Jones Energy, Inc. Provides 2015 Year-End Reserves, Operations and Financial Update, and 2016 Guidance
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
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Proved reserves at year-end 2015 were 101.7 MMBoe based on SEC pricing1;
proved oil reserves were 25.4 MMBbl
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Cleveland proved reserves were 80.6 MMBoe at year-end 2015
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PV-10 value of proved reserves was $470 million at SEC prices1
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Mark-to-market hedge value of $264 million incorporating strip pricing
as of February 10, 2016
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Liquidity of approximately $420 million as of December 31, 2015
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Initial 2016 capital budget of $25 million, primarily for workovers
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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)
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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)
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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.
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Proved Reserves as of December 31, 2015
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Oil
(MMBbl)
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Gas
(Bcf)
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NGLs
(MMBbl)
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Total
(MMBoe)
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% Liquids
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Cleveland
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24.8
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179.2
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25.9
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80.6
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62.9%
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Woodford
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0.1
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66.0
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5.1
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16.3
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32.2%
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Other
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0.5
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16.4
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1.6
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4.8
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43.5%
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Total Proved
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25.4
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261.6
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32.6
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101.7
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57.1%
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Proved Developed
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11.0
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169.7
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19.7
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59.0
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52.1%
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Changes in Proved Reserves (MMBoe)
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Proved reserves as of December 31, 2014
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115.3
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Extensions and discoveries
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5.5
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Production4
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(9.2
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Revisions of previous estimates
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(9.9
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Proved reserves as of December 31, 2015
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101.7
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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
$210 million.
2016 Guidance
Based upon the current 2016 capital budget and operating plan, we are
projecting 2016 average daily production of 15,500 to 17,000 Boe per
day. A table has been provided below with full year and first quarter
2016 guidance by category. The Company’s average production for the
fourth quarter of 2016 is expected to be between 13.0 MBoe/d and 14.4
MBoe/d, which is approximately 40% below the estimated average
production rate of 23.6 MBoe/d for the fourth quarter of 2015. All
guidance figures are reflective of the initial 2016 capital expenditure
budget and current activity levels and do not account for any potential
changes based upon evolving market conditions.
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2016 Guidance
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2016E
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1Q16E
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Total Production (MMBoe)
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5.6 – 6.2
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1.75 – 1.85
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Average Daily Production (MBoe/d)
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15.5 – 17.0
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19.3 – 20.3
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Crude Oil (MBbl/d)
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3.6 – 3.9
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4.6 – 4.9
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Natural Gas (MMcf/d)
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41.7 – 45.9
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51.7 – 54.1
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NGLs (MBbl/d)
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4.9 – 5.4
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6.1 – 6.4
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Lease Operating Expense ($mm)
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$35.0 – $38.0
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Production Taxes (% of Unhedged Revenue)*
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4.5% – 5.5%
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Ad Valorem Taxes ($mm)*
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$1.5 – $1.7
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Cash G&A Expense ($mm)
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$18.0 – $20.0
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Total Capital Expenditures ($mm)
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$25.0
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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:
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Current Hedge Positions
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Fiscal Year Ending December 31,
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2016
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2017
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2018
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1H19
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Oil, Natural Gas and NGL Swaps
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Oil (MBbl)
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1,849
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1,040
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803
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339
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Natural Gas (MMcf)
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16,730
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12,300
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10,240
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4,410
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Ethane (MBbl)
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53
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-
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-
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-
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Propane (MBbl)
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627
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-
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-
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Iso Butane (MBbl)
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76
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7
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-
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-
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Butane (MBbl)
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218
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17
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-
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-
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Natural Gasoline (MBbl)
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227
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18
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-
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Total NGLs (MBbl)
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1,201
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42
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-
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-
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Weighted Average Prices
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Oil ($ / Bbl)
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$
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84.09
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$
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78.69
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$
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77.47
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$
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64.65
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Natural Gas ($ / Mcf)
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4.46
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4.29
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4.19
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3.53
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Ethane ($ / Gal)
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0.21
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-
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-
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Propane ($ / Gal)
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0.55
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-
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-
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Iso Butane ($ / Gal)
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0.75
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1.42
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-
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Butane ($ / Gal)
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0.72
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1.37
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-
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Natural Gasoline ($ / Gal)
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1.46
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1.73
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-
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-
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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.
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.
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SEC PV-10 and Standardized Measure as of December 31, 2015 ($mm)
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PV-10
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$470
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Present value of future income taxes discounted at 10%
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(5)
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Standardized measure
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465
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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.
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