AUSTIN, Texas–(BUSINESS WIRE)–Jones Energy, Inc. (NYSE: JONE) (“Jones Energy” or “the Company”) today provided its 2015 year-end reserves, an operations update, estimated financial results for the fourth quarter and full year 2015, and its initial 2016 capital budget plan and guidance.

Highlights

• Proved reserves at year-end 2015 were 101.7 MMBoe based on SEC pricing¹; proved oil reserves were 25.4 MMBbl
• Cleveland proved reserves were 80.6 MMBoe at year-end 2015
• PV-10 value of proved reserves was $470 million at SEC prices¹
• Mark-to-market hedge value of $264 million incorporating strip pricing as of February 10, 2016
• Liquidity of approximately $420 million as of December 31, 2015
• Initial 2016 capital budget of $25 million, primarily for workovers
• Estimated full year 2015 production of approximately 25.1 MBoe/d (above top end of guidance); estimated oil production for the full year of approximately 7.1 MBoe/d (top end of guidance)
• Estimated production for the fourth quarter of 2015 of approximately 23.6 MBoe/d (above top end of guidance); estimated oil production for the fourth quarter of 2015 of approximately 6.0 MBoe/d (in-line with guidance)
• Estimated Cleveland production for the fourth quarter of 2015 of approximately 17.7 MBoe/d

Jones Energy Founder, Chairman, and CEO, Jonny Jones stated, “2015 was a year that saw our company meet or beat every goal we laid out for ourselves resulting in estimated production growth approaching 10% while simultaneously dropping capital spending by roughly 60%. Despite the incredible cost savings we created this past year, the commodity price environment has become even more challenging during the past few months. As a team, we believe the responsible decision as capital allocators is to hold off on drilling new wells at this time. Our valuable hedge position has continued to afford us the luxury of allowing service costs and commodity prices to rebalance before deploying additional drilling and completion capital. We will be patient in an effort to make sure that our capital investments create an acceptable return for our shareholders.” Mr. Jones went on to say, “Our year-end proved reserves reflect the strength of our Cleveland well economics as we maintained high levels of proved reserves despite the significant drop in prices. We continue to believe that our multi-year hedge book and significant liquidity have Jones Energy well prepared to weather current market conditions and positioned to seize opportunities to create shareholder value.”

¹ SEC prices for 2015 year-end proved reserves were $50.25 per barrel for oil and $2.59 per MMBtu for natural gas based on the average of such prices for 2015.

2015 Year-End Proved Reserves

Jones Energy’s year-end 2015 proved reserves based on SEC pricing and definitions were 101.7 MMBoe, of which 58% were classified as proved developed reserves. Total proved oil reserves at year-end 2015 were 25.4 MMBbl compared to year-end 2014 proved oil reserves of 27.7 MMBbl. The SEC PV-10² value of proved reserves for year-end 2015 was $470 million, with a corresponding standardized measure value of approximately $465 million³.

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 2015 WTI oil price of $50.25 per barrel and an average 2015 Henry Hub spot market natural gas price of $2.59 per MMBtu.

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 production figures are estimates pending final audit results by the Company’s outside auditor.

Assuming strip pricing as of February 10, 2016 through 2020 and keeping pricing flat thereafter, instead of 2015 SEC pricing, while leaving all other parameters unchanged, the Company’s proved reserves would have been 102.3 MMBoe and the PV-10 value of proved reserves would have been $364 million.

As of December 31, 2015, the Company had identified 2,103 gross drilling locations. These include 711 gross drilling locations in the Cleveland play and 277 gross locations in the Arkoma Woodford shale. The Company acquired more than 90 drilling locations through leasing during 2015 and 8 of these locations were included in proved reserves.

The Company currently does not anticipate drilling new wells on its Arkoma Woodford acreage in the near term. As a result, the Company will not spud the required number of additional wells per the joint development agreement between Jones Energy and Vanguard Natural Resources within the prescribed time period to maintain rights to the additional future drilling locations. The loss of these drilling locations, along with other near term lease expirations in the Arkoma, have contributed to a reduction in the Company’s Woodford proved undeveloped reserve figures and total drilling location count. The total number of Arkoma drilling locations removed from the Company’s inventory totaled 496 gross locations and 40 net locations, including 42 gross (8 net) locations associated with proved undeveloped reserves. These Arkoma drilling locations had no associated PV-10 value in the Company’s year-end 2015 proved reserves based on SEC pricing and definitions.

2016 Capital Budget and Operating Plan

The Company has established an initial capital budget of $25 million for 2016, with the majority dedicated to capital workovers and field optimization activities. The Company will continue to monitor market conditions and may determine at a later date to spend additional capital which may include redeploying rigs to resume drilling activities or leasing. At present, the Company continues to negotiate with vendors regarding service costs and does not plan on resuming drilling activities until well costs create acceptable rates of return at strip prices.

Operations Update

Production Update for the Fourth Quarter and Full Year 2015

The Company produced an estimated 2.2 MMBoe (approximately 23,600 Boe/d) in the fourth quarter of 2015 and an estimated 9.2 MMBoe (approximately 25,100 Boe/d) for the full year. Oil volumes comprised 25% of production for the fourth quarter and 28% for the full year. NGL volumes accounted for 31% of the fourth quarter production and 29% of the full year volumes. During the fourth quarter, liquids accounted for 56% of total production.

Revenues and EBITDAX for the Fourth Quarter of 2015

The Company estimates revenues including current period settlements of matured derivative contracts for the fourth quarter of 2015 of between $78.5 million and $81.5 million based upon internally projected production figures and estimated realized commodity prices. The Company estimates EBITDAX⁵ for the fourth quarter of 2015 of between $63.6 million and $66.6 million.

2015 Capital Expenditures

During the fourth quarter of 2015, the Company spent $14.1 million on capital expenditures, of which $8.0 million was related to drilling and completing wells, representing 57% of the total capital expenditures in the quarter. The remaining $6.1 million was primarily related to field maintenance and leasing.

For the full year 2015, the Company spent $200.1 million on capital expenditures, of which $173.2 million was related to drilling and completing wells, representing 87% of the total capital expenditures in the year. This compares to revised 2015 capital expenditure guidance of $210 million.

2016 Guidance

Based upon the current 2016 capital budget and operating plan, we are projecting 2016 average daily production of 15,500 to 17,000 Boe per day. A table has been provided below with full year and first quarter 2016 guidance by category. The Company’s average production for the fourth quarter of 2016 is expected to be between 13.0 MBoe/d and 14.4 MBoe/d, which is approximately 40% below the estimated average production rate of 23.6 MBoe/d for the fourth quarter of 2015. All guidance figures are reflective of the initial 2016 capital expenditure budget and current activity levels and do not account for any potential changes based upon evolving market conditions.

⁵ EBITDAX is a non-GAAP financial measure.

*Production and ad valorem taxes are included as one line item on the Company’s Consolidated Statements of Operations.

Liquidity and Hedging

As of December 31, 2015, the Company had undrawn credit facility availability of $400 million and approximately $22 million in cash.

The estimated mark-to-market value of the Company’s commodity price hedges in 2016 and beyond was $264 million incorporating strip pricing as of February 10, 2016. The following table summarizes the Company’s commodity derivative contracts outstanding:

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.

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 potential redeployment of rigs, the initial 2016 capital budget, the potential for drilling and completion cost savings and the resultant impact on the initial 2016 capital budget, the ability to fund the Company’s initial 2016 capital expenditure budget largely with free cash, and projections regarding total production, average daily production, percentage liquids, operating expenses, production and ad valorem taxes as a percentage of revenue, cash G&A expenses and capital expenditure levels for 2016. These statements are based on certain assumptions made by the Company based on management’s experience and perception of historical trends, current economic and market 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 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, 2015 contained herein are based on SEC mandated first-day-of-the-month unweighted average prices for 2015 and costs as of December 31, 2015. 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 year-end 2015.

Non-GAAP Financial Measures

PV-10 is derived from the Standardized Measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the Standardized Measure of discounted future net cash flows on a pre-tax basis. 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 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 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 and natural gas properties. PV-10, however, is not a substitute for the Standardized Measure of discounted future net cash flows. Our 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.

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. EBITDAX is not a measure of net income as determined by 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 and should not be viewed as a substitute for GAAP. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies. The Company expects to release its December 31, 2015 net income with year-end earnings results.