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Eclipse Resources Corporation Announces Fourth Quarter 2016 and Full Year 2016 Financial and Operational Results
Eclipse Resources Corporation (NYSE:ECR) (the “Company” or “Eclipse
Resources”) today announced its fourth quarter and full year 2016
financial and operational results, as well as issued updated guidance
for the first quarter of 2017 and full year 2017.
Fourth Quarter 2016 Highlights:
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Average net daily production was 255.3 MMcfe per day, exceeding the
high end of the Company’s previously issued production guidance.
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Realized an average natural gas price, before the impact of cash
settled derivatives and firm transportation expenses, of $2.88 per
Mcf, a $0.16 discount to the average NYMEX natural gas prices during
the quarter, exceeding the Company’s previously issued natural gas
differential guidance.
-
Realized an average oil price, before the impact of cash settled
derivatives, of $44.51 per barrel, a $4.63 per barrel discount to the
average WTI oil price during the quarter, exceeding the Company’s
previously issued oil differential guidance.
-
Realized an average natural gas liquids (“NGL”) price, before the
impact of cash settled derivatives, of $21.22 per barrel, or
approximately 43% of the average WTI oil price during the quarter,
beating the Company’s previously issued NGL price differential
guidance.
-
Per unit cash production costs (including lease operating,
transportation, gathering and compression, production and ad valorem
taxes) were $1.54 per Mcfe and includes $0.41 per Mcfe of
firm transportation expenses, which was below the Company’s previously
issued operating expense guidance.
-
Net loss for the fourth quarter of 2016 was $63.3 million; Adjusted
EBITDAX1 for the fourth quarter of 2016 was $41.3 million.
-
Capital expenditures were $57.8 million. These expenditures included
$49.6 million for drilling and completions, $1.7 million for midstream
expenditures, $6.0 million for land-related expenditures, and $0.5
million for corporate-level expenditures.
Full Year 2016 Highlights:
-
Average net daily production was 228.6 MMcfe per day, exceeding the
midpoint of the Company’s previously issued production guidance.
-
Realized an average natural gas price, before the impact of cash
settled derivatives and firm transportation expenses, of $2.21 per
Mcf, a $0.31 discount to the average NYMEX natural gas prices during
the year, exceeding the Company’s previously issued natural gas
differential guidance.
-
Realized an average oil price, before the impact of cash settled
derivatives, of $37.35 per barrel, a $5.94 per barrel discount to the
average WTI oil price during the year, beating the Company’s
previously issued oil differential guidance.
-
Realized an average natural gas liquids price, before the impact of
cash settled derivatives, of $15.62 per barrel, or approximately 36%
approximately of the average WTI oil price during the year, exceeding
the Company’s previously issued NGL differential guidance.
-
Per unit cash production costs (including lease operating,
transportation, gathering and compression, production and ad valorem
taxes) were $1.48 per Mcfe and includes $0.36 per Mcfe of
firm transportation expenses, which was below the Company’s previously
issued operating expense guidance.
-
Net loss for the year was $203.8; Adjusted EBITDAX1 for the
year was $105.0 million
-
Capital expenditures were $176.9 million. These expenditures included
$150.5 million for drilling and completions, $3.9 million for
midstream expenditures, $21.5 million for land-related expenditures,
and $1.0 million for corporate-related expenditures
-
Proved Reserves grew 35% over the previous year to approximately 469
Bcfe at SEC pricing and 108% over the previous year to approximately
1.22 Tcfe at forward NYMEX strip pricing; Finding and Development
costs for the year fell to $0.70 per Mcfe, utilizing drilling and
completion costs, and to $0.91 per Mcfe including all capital uses.
Subsequent to the end of the Fourth Quarter:
-
The Company completed its borrowing base redetermination of its
revolving credit facility, which resulted in an increase in its
borrowing base from $125 million to $175 million, and extended the
maturity of its revolving credit facility from January 2018 to January
2020. The Company remains undrawn on its revolving credit facility,
other than for letters of credit.
-
The Company added to its natural gas hedge portfolio by executing
incremental basis hedges of 60,000 MMBtu per day.
-
The Company has approximately 226,000 MMBtu per day of 2017
natural gas production hedged at an average floor price2
of $2.87 and an average ceiling price of $3.35.
-
The Company has an average of approximately 3,500 barrels per day
of 2017 oil production hedged, or approximately 75% of its
expected oil production for 2017, at an average floor price2
of $46.00 and an average ceiling price of $59.79.
-
The Company has 190,000 MMBtu per day of 2018 natural gas
production hedged at an average floor price2 of $2.88
and an average ceiling price of $3.37.
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1
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Non-GAAP measure. See reconciliation for details
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2
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For the purposes of calculating three-way floor price, the
higher valued put is used
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Benjamin W. Hulburt, Chairman, President and CEO, commented on the
Company’s fourth quarter and full year 2016 results, “During the fourth
quarter, we were able to once again set record production levels for the
Company while keeping our per unit operating expenses below our
previously announced guidance range. This now marks the ninth
consecutive reporting period in which the Company has met or exceeded
its production and operating expense guidance, representing every
reporting period the Company had since our initial public offering in
June of 2014.
As we highlighted in our analyst day, we recently increased our type
curve expectations in our Utica Shale Condensate and Rich Gas areas as a
result of the outperformance we have seen to date on the wells which
were completed with our “Gen3” completion design in these areas.
Although we have not yet increased our Utica Shale Dry Gas type curve,
our first “Gen3” pad in the Utica Shale Dry Gas area continues to
produce at an average rate of approximately 30% above our Utica Dry Gas
type curve using our managed pressure drawdown methodology. Largely as a
result of the performance of our “Gen3” producing wells, we have
increased our first quarter 2017 production guidance to between 275 and
280 MMcfe per day.
As 2017 continues to unfold, we will again endeavor to lower our cost
structure and build on our accomplishments. During 2017, we plan to
drill 24 wells with an average lateral length of approximately 13,300,
eleven of which are expected to be “Super-Laterals” with lateral
extensions exceeding 15,000 feet. While leading the industry on lateral
lengths should allow us to continue to lower our cost per foot of
lateral, we have also taken significant steps to manage our well costs
by negotiating lower day rates on our drilling rigs and locking in
flat-to-modest increases on our pressure pumping and proppant costs for
the next two years.
Despite a significant amount of volatility during the quarter in natural
gas prices, we have again been able to deliver a strong natural gas
realized price, exceeding our guidance for both the fourth quarter 2016
and the full year 2016. We have also taken advantage of this volatility
by adding to our 2018 hedge portfolio as prices allowed, with the goal
of retaining upside participation if the natural gas price increases.
Lastly, I’m very happy to announce we have negotiated a new condensate
marketing contract which fixes our discount to the West Texas
Intermediate price for the period beginning in April of this year
through the end of 2018, and as a consequence, we have updated our
annual oil price differential guidance resulting in an estimated
improvement on our oil differentials of approximately 15%.”
Operational Discussion
The Company’s production for the three months and years ended
December 31, 2016 and 2015 is set forth in the following table:
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Three Months Ended
December 31,
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Year Ended
December 31,
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2016
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2015
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2016
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2015
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Production:
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Natural gas (MMcf)
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16,563.9
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15,814.0
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60,921.9
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49,477.6
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NGL sales (Mbbls)
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721.1
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709.9
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2,446.2
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2,450.3
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Oil sales (Mbbls)
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433.4
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442.3
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1,343.8
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1,950.5
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Total (MMcfe)
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23,490.9
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22,727.2
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83,661.9
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75,882.4
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Average daily production volume:
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Natural gas (Mcf/d)
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180,042
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171,891
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166,453
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135,555
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NGL sales (Bbls/d)
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7,838
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7,716
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6,684
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6,713
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Oil sales (Bbls/d)
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4,711
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4,808
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3,672
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5,344
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Total (Mcfe/d)
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255,336
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247,035
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228,589
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207,897
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Financial Discussion
Revenues for the fourth quarter of 2016 totaled $83.9 million, compared
to $65.9 million for the fourth quarter of 2015. Adjusted Revenues4,
which includes the impact of cash settled derivatives and excludes
brokered natural gas and marketing revenue, totaled $85.1 million for
the fourth quarter of 2016 compared to $74.4 million for the fourth
quarter of 2015. Net loss for the fourth quarter of 2016 was $63.3
million, or $(0.23) per share. Adjusted Net Loss4 for the
fourth quarter of 2016 was $5.7 million, or $(0.02) per share. Adjusted
EBITDAX4 was $41.3 million for the fourth quarter of 2016.
Revenues for the full year 2016 totaled $235.0 million, compared to
$255.3 million for the full year 2015. Adjusted Revenues4,
which includes the impact of cash settled derivatives and excludes
brokered natural gas and marketing revenue, totaled $261.7 million for
the full year 2016 compared to $271.7 million for the full year 2015.
Net loss for the full year 2016 was $203.8 million, or $(0.84) per
share. Adjusted Net Loss4 for the full year 2016 was $61.6
million, or $(0.26) per share. Adjusted EBITDAX4 was $105.0
million for the full year 2016.
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4
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Adjusted Revenue, Adjusted Net Loss and Adjusted EBITDAX are
non-GAAP financial measures. Tables reconciling Adjusted Revenue,
Adjusted Net Loss and Adjusted EBITDAX to the most directly
comparable GAAP measures can be found at the end of the financial
statements included in this press release.
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Average realized price calculations for the three months and years ended
December 31, 2016 and 2015 are set forth in the table below:
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Three Months Ended
December 31,
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Year Ended
December 31,
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2016
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2015
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2016
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2015
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Average Sales Price (excluding cash settled derivatives)
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Natural gas ($/Mcf)
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$
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2.88
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$
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2.32
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$
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2.21
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$
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2.62
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NGLs ($/Bbl)
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21.22
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14.50
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15.62
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12.32
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Oil ($/Bbl)
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44.51
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32.03
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37.35
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38.38
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Total average prices ($/Mcfe)
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3.50
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2.69
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2.67
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3.09
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Average Sales Price (including cash settled derivatives)
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Natural gas ($/Mcf)
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$
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3.00
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$
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2.98
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$
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2.69
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$
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3.27
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NGLs ($/Bbl)
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20.78
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14.50
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15.55
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12.32
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Oil ($/Bbl)
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46.97
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38.25
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44.66
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40.92
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Total average prices ($/Mcfe)
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3.62
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3.27
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3.13
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3.58
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Average Sales Price (including firm transportation)
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Natural gas ($/Mcf)
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$
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2.29
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$
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1.99
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$
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1.71
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$
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2.31
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NGLs ($/Bbl)
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21.22
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14.50
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15.62
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12.32
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Oil ($/Bbl)
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44.51
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32.03
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37.35
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38.38
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Total average prices ($/Mcfe)
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3.09
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2.46
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2.30
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2.89
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Average Sales Price (including cash settled derivatives and firm
transportation)
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Natural gas ($/Mcf)
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$
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2.42
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$
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2.65
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$
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2.19
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$
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2.95
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NGLs ($/Bbl)
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20.78
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14.50
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15.55
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12.32
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Oil ($/Bbl)
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46.97
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38.25
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44.66
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38.38
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Total average prices ($/Mcfe)
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3.21
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3.04
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2.76
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3.38
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The Company’s primary operating expenses per Mcfe for the fourth quarter
of 2016 decreased by 39% compared to the prior year’s quarter and are
shown in the table below. Per unit cash production costs (includes lease
operating, transportation, gathering and compression, production and ad
valorem taxes) were $1.54 per Mcfe for the fourth quarter 2016 and
includes $0.41 per Mcfe of firm transportation expenses.
The Company’s primary operating expenses per Mcfe for the year ended
December 31, 2016 decreased by 42% compared to the prior year’s and are
shown below. Per unit cash production costs (includes lease operating,
transportation, gathering and compression, production and ad valorem
taxes) were $1.48 per Mcfe for the full year 2016 and includes $0.36 per
Mcfe of firm transportation expenses.
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Three Months Ended
December 31,
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Year Ended
December 31,
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2016
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2015
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2016
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2015
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Operating expenses (in thousands):
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Lease operating
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$
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1,912
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$
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3,757
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$
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9,023
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$
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13,904
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Transportation, gathering and compression
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30,947
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27,950
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109,226
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85,846
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Production and ad valorem taxes
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3,251
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3,268
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4,998
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11,621
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Depreciation, depletion and amortization
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28,661
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74,505
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92,948
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244,750
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General and administrative
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9,719
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8,039
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39,431
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46,409
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Operating expenses per Mcfe:
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Lease operating
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$
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0.08
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$
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0.17
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$
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0.11
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$
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0.18
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Transportation, gathering and compression
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1.32
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1.23
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1.31
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1.13
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Production, severance and ad valorem taxes
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0.14
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0.14
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0.06
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0.15
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Depreciation, depletion and amortization
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1.22
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3.28
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1.11
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3.23
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General and administrative
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0.41
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0.35
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0.47
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0.61
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Capital Expenditures
Fourth quarter 2016 capital expenditures were $57.8 million. These
expenditures included $49.6 million for drilling and completions, $1.7
million for midstream expenditures, $6.0 million for land-related
expenditures, and $0.5 million for corporate-related expenditures.
Full Year 2016 capital expenditures were $176.9 million. These
expenditures included $150.5 million for drilling and completions, $3.9
million for midstream expenditures, $21.5 million for land-related
expenditures, and $1.0 million for corporate-related expenditures.
Financial Position and Liquidity
Subsequent to the end of the fourth quarter of 2016, the Company
completed its semi-annual borrowing base redetermination process with
the lending group under its revolving credit facility. Through that
process, the lending group determined that the Company’s borrowing base
will increase from $125 million to $175 million, and extended the
maturity of the Company’s revolving credit facility to January of 2020.
As of December 31, 2016, the Company’s pro forma liquidity was $341.7
million consisting of $201.2 million in cash and cash equivalents and
available borrowing capacity under the Company’s revolving credit
facility of $140.5 million (after giving effect to outstanding letters
of credit issued by the Company of $34.5 million and pro forma the
borrowing base redetermination).
Matthew R. DeNezza, Executive Vice President and Chief Financial
Officer, commented, “With the closing of the asset divestiture late in
the fourth quarter and our recent borrowing base redetermination, which
resulted in a 40% borrowing base increase, we continue to maintain a
strong liquidity position. At year end and pro forma for this recent
redetermination, our liquidity was approximately $342 million, and
included a cash position of approximately $201 million and undrawn
revolver availability of approximately $141 million, after giving effect
to outstanding letters of credit. We believe this liquidity position, as
well as our internally generated cash flows, will allow us to fund our
2017 drilling program, which we anticipate will provide the groundwork
for a 25% compound annual growth rate in production over the next three
years.”
Commodity Derivatives
The Company engages in a number of different commodity trading program
strategies as a risk management tool to attempt to mitigate the
potential negative impact on cash flows caused by price fluctuations in
natural gas, NGL and oil prices. Below is a table that illustrates the
Company’s hedging activities as of December 31, 2016:
Natural Gas Derivatives
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Description
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Volume
(MMBtu/d)
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Production Period
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Weighted Average
Price ($/MMBtu)
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Natural Gas Swaps:
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10,000
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January 2017 – December 2017
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$
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2.98
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10,000
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March 2017 – December 2017
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$
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3.21
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Natural Gas Collars:
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Floor purchase price (put)
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130,000
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January 2017 – December 2017
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$
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2.85
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Ceiling sold price (call)
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130,000
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January 2017 – December 2017
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$
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3.24
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Floor purchase price (put)
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20,000
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January 2017 – December 2018
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$
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2.90
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Ceiling sold price (call)
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20,000
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January 2017 – December 2018
|
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$
|
3.25
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Floor purchase price (put)
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40,000
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January 2018 – December 2018
|
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$
|
2.75
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Ceiling sold price (call)
|
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40,000
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January 2018 – December 2018
|
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$
|
3.27
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Natural Gas Three-way Collars:
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Floor purchase price (put)
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30,000
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January 2017 – December 2017
|
|
$
|
2.75
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Ceiling sold price (call)
|
|
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30,000
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January 2017 – December 2017
|
|
$
|
3.57
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Floor sold price (put)
|
|
|
30,000
|
|
|
January 2017 – December 2017
|
|
$
|
2.25
|
|
|
Floor purchase price (put)
|
|
|
30,000
|
|
|
April 2017 – March 2019
|
|
$
|
3.00
|
|
|
Ceiling sold price (call)
|
|
|
30,000
|
|
|
April 2017 – March 2019
|
|
$
|
3.40
|
|
|
Floor sold price (put)
|
|
|
30,000
|
|
|
April 2017 – March 2019
|
|
$
|
2.20
|
|
|
Floor purchase price (put)
|
|
|
80,000
|
|
|
January 2018 – December 2018
|
|
$
|
2.90
|
|
|
Ceiling sold price (call)
|
|
|
80,000
|
|
|
January 2018 – December 2018
|
|
$
|
3.31
|
|
|
Floor sold price (put)
|
|
|
80,000
|
|
|
January 2018 – December 2018
|
|
$
|
2.12
|
|
|
Floor purchase price (put)
|
|
|
20,000
|
|
|
October 2017 – December 2018
|
|
$
|
2.90
|
|
|
Ceiling sold price (call)
|
|
|
20,000
|
|
|
October 2017 – December 2018
|
|
$
|
3.50
|
|
|
Floor sold price (put)
|
|
|
20,000
|
|
|
October 2017 – December 2018
|
|
$
|
2.20
|
|
|
Natural Gas Call/Put Options:
|
|
|
|
|
|
|
|
|
|
|
|
Call sold
|
|
|
40,000
|
|
|
January 2018 – December 2018
|
|
$
|
3.75
|
|
|
Call sold
|
|
|
10,000
|
|
|
January 2019 – December 2019
|
|
$
|
4.75
|
|
|
Basis Swaps:
|
|
|
|
|
|
|
|
|
|
|
|
TCO - Columbia
|
|
|
20,000
|
|
|
January 2017 – December 2017
|
|
$
|
(0.19
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Derivatives
|
Description
|
|
Volume
(Bbls/d)
|
|
|
Production Period
|
|
Weighted Average
Price ($/Bbl)
|
|
Oil Swaps:
|
|
|
|
|
|
|
|
|
|
|
Floor purchase price (put)
|
|
|
2,000
|
|
|
January 2017 – September 2017
|
|
$
|
46.00
|
|
Ceiling sold price (call)
|
|
|
2,000
|
|
|
January 2017 – September 2017
|
|
$
|
59.50
|
|
Floor sold price (put)
|
|
|
2,000
|
|
|
January 2017 – September 2017
|
|
$
|
38.00
|
|
Floor purchase price (put)
|
|
|
2,000
|
|
|
January 2017 – December 2017
|
|
$
|
46.00
|
|
Ceiling sold price (call)
|
|
|
2,000
|
|
|
January 2017 – December 2017
|
|
$
|
60.00
|
|
Floor sold price (put)
|
|
|
2,000
|
|
|
January 2017 – December 2017
|
|
$
|
38.00
|
|
Oil Call/Put Options:
|
|
|
|
|
|
|
|
|
|
|
Call sold
|
|
|
1,000
|
|
|
January 2018 – December 2018
|
|
$
|
50.00
|
|
|
|
|
|
|
|
|
|
|
|
NGL Derivatives
|
Description
|
|
Volume
(Gal/d)
|
|
|
Production Period
|
|
Weighted Average
Price ($/Gal)
|
|
Propane Swaps:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
84,000
|
|
|
January 2017 – December 2017
|
|
$
|
0.60
|
|
|
|
|
|
|
|
|
|
|
|
Subsequent to December 31, 2016, the Company entered into the following
derivative instruments:
|
Description
|
|
Volume
(MMbtu/d)
|
|
|
Production Period
|
|
Weighted Average
Price ($/MMbtu)
|
|
|
Natural Gas Call/Put Options:
|
|
|
|
|
|
|
|
|
|
|
|
Call sold
|
|
|
60,000
|
|
|
January 2018 – March 2018
|
|
$
|
3.75
|
|
|
Call purchased
|
|
|
60,000
|
|
|
January 2018 – March 2018
|
|
$
|
3.25
|
|
|
Put sold
|
|
|
60,000
|
|
|
January 2018 – December 2018
|
|
$
|
2.40
|
|
|
Put purchased
|
|
|
60,000
|
|
|
January 2018 – December 2018
|
|
$
|
2.10
|
|
|
Call sold
|
|
|
50,000
|
|
|
April 2017 - December 2018
|
|
$
|
3.40
|
|
|
Call purchased
|
|
|
50,000
|
|
|
April 2017 - December 2018
|
|
$
|
3.20
|
|
|
Put sold
|
|
|
70,000
|
|
|
April 2017 - December 2018
|
|
$
|
2.25
|
|
|
Basis Swaps:
|
|
|
|
|
|
|
|
|
|
|
|
Appalachia - Dominion
|
|
|
20,000
|
|
|
May 2017 – November 2017
|
|
$
|
(1.04
|
)
|
|
Appalachia - Dominion
|
|
|
40,000
|
|
|
June 2017 – November 2017
|
|
$
|
(1.01
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Guidance
The Company issued the following first quarter and full year 2017
guidance in the table below:
|
|
|
Q1 2017
|
|
FY 2017
|
|
Production MMcfe/d
|
|
275 - 280
|
|
305 - 315
|
|
% Gas
|
|
72% - 76%
|
|
77% - 82%
|
|
% NGL
|
|
14% - 16%
|
|
9% - 14%
|
|
% Oil
|
|
10% - 12%
|
|
7% - 11%
|
|
Gas Price Differential ($/Mcf)1,2
|
|
$0.05 - $(0.05)
|
|
$(0.25) - $(0.35)
|
|
Oil Differential ($/Bbl)1
|
|
$(7.50) - $(8.50)
|
|
$(6.50) - $(7.50)
|
|
NGL Prices (% of WTI)1
|
|
42% - 46%
|
|
33% - 38%
|
|
Cash Production Costs ($/Mcfe)3
|
|
$1.65 - $1.70
|
|
$1.45 - $1.55
|
|
Cash G&A ($mm)4
|
|
$8.5 - $9.5
|
|
$35 - $37
|
|
CAPEX ($mm)5
|
|
|
|
~$300
|
|
|
|
|
|
|
|
1.
|
|
|
Excludes impact of hedges.
|
|
2.
|
|
|
Excludes the cost of firm transportation.
|
|
3.
|
|
|
Includes lease operating, transportation, gathering and
compression, production and ad valorem taxes.
|
|
4.
|
|
|
Non-GAAP measure which excludes non-cash compensation, see
reconciliation.
|
|
5.
|
|
|
Excludes potential acquisitions and payments of approximately
$17 million for land leased in 2016 and expected to be paid in
2017.
|
|
|
|
|
|
Conference Call
A conference call to review the Company’s financial fourth quarter 2016
and full-year 2016 earnings is scheduled for Wednesday, March 1, 2017,
at 9:00 a.m. (Eastern). To participate in the call, please dial
877-709-8150, or 201-689-8354 for international callers, and reference
Eclipse Resources Fourth Quarter and Full Year 2016 Earnings Call. A
replay of the call will be available through May 3, 2017. To access the
phone replay dial 877-660-6853 or 201-612-7415 for international
callers. The conference ID is 13653954. A live webcast of the call may
be accessed through the “Investors” section of the Company’s website at www.eclipseresources.com.
|
ECLIPSE RESOURCES CORPORATION
CONDENSED
CONSOLIDATED BALANCE SHEETS
(In thousands, except share
and per share amounts)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
2016
|
|
|
December 31,
2015
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
CURRENT ASSETS
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
201,229
|
|
|
$
|
184,405
|
|
|
Accounts receivable
|
|
|
43,638
|
|
|
|
27,476
|
|
|
Assets held for sale
|
|
|
468
|
|
|
|
21,971
|
|
|
Other current assets
|
|
|
4,295
|
|
|
|
35,532
|
|
|
Total current assets
|
|
|
249,630
|
|
|
|
269,384
|
|
|
|
|
|
|
|
|
|
|
|
|
PROPERTY AND EQUIPMENT AT COST
|
|
|
|
|
|
|
|
|
|
Oil and natural gas properties, successful efforts method:
|
|
|
|
|
|
|
|
|
|
Unproved properties
|
|
|
526,270
|
|
|
|
720,159
|
|
|
Proved oil and gas properties, net
|
|
|
414,482
|
|
|
|
265,838
|
|
|
Other property and equipment, net
|
|
|
6,748
|
|
|
|
7,971
|
|
|
Total property and equipment, net
|
|
|
947,500
|
|
|
|
993,968
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER NONCURRENT ASSETS
|
|
|
|
|
|
|
|
|
|
Other assets
|
|
|
729
|
|
|
|
2,520
|
|
|
Deferred taxes
|
|
|
—
|
|
|
|
540
|
|
|
TOTAL ASSETS
|
|
$
|
1,197,859
|
|
|
$
|
1,266,412
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
44,049
|
|
|
$
|
34,717
|
|
|
Accrued capital expenditures
|
|
|
11,083
|
|
|
|
10,956
|
|
|
Accrued liabilities
|
|
|
64,150
|
|
|
|
25,462
|
|
|
Accrued interest payable
|
|
|
21,098
|
|
|
|
23,809
|
|
|
Liabilities held for sale
|
|
|
245
|
|
|
|
18,898
|
|
|
Total current liabilities
|
|
|
140,625
|
|
|
|
113,842
|
|
|
|
|
|
|
|
|
|
|
|
|
NONCURRENT LIABILITIES
|
|
|
|
|
|
|
|
|
|
Debt, net of unamortized discount and debt issuance costs
|
|
|
492,278
|
|
|
|
527,248
|
|
|
Asset retirement obligations
|
|
|
4,806
|
|
|
|
3,401
|
|
|
Other liabilities
|
|
|
13,434
|
|
|
|
1,367
|
|
|
Total liabilities
|
|
|
651,143
|
|
|
|
645,858
|
|
|
COMMITMENTS AND CONTINGENCIES
|
|
|
|
|
|
|
|
|
|
STOCKHOLDERS' EQUITY
|
|
|
|
|
|
|
|
|
|
Preferred stock, 50,000,000 authorized, no shares issued and
outstanding
|
|
|
—
|
|
|
|
—
|
|
|
Common stock, $0.01 par value, 1,000,000,000 authorized,
260,591,893 and 222,674,270 shares issued and outstanding,
respectively
|
|
|
2,607
|
|
|
|
2,227
|
|
|
Additional paid in capital
|
|
|
1,958,731
|
|
|
|
1,829,082
|
|
|
Treasury stock, shares at cost; 72,704 shares at December 31, 2016
|
|
|
(61
|
)
|
|
|
—
|
|
|
Accumulated deficit
|
|
|
(1,414,561
|
)
|
|
|
(1,210,755
|
)
|
|
Total stockholders' equity
|
|
|
546,716
|
|
|
|
620,554
|
|
|
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY
|
|
$
|
1,197,859
|
|
|
$
|
1,266,412
|
|
|
|
|
|
|
|
|
|
|
|
|
ECLIPSE RESOURCES CORPORATION
CONDENSED
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands,
except per share data)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months
Ended December 31,
|
|
|
For the Year
Ended December 31,
|
|
|
|
|
2016
|
|
|
2015
|
|
|
2016
|
|
|
2015
|
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, oil and natural gas liquids sales
|
|
$
|
82,275
|
|
|
$
|
61,075
|
|
|
$
|
223,015
|
|
|
$
|
234,601
|
|
|
Brokered natural gas and marketing revenue
|
|
|
1,608
|
|
|
|
4,807
|
|
|
|
12,019
|
|
|
|
20,720
|
|
|
Total revenues
|
|
|
83,883
|
|
|
|
65,882
|
|
|
|
235,034
|
|
|
|
255,321
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
|
1,912
|
|
|
|
3,757
|
|
|
|
9,023
|
|
|
|
13,904
|
|
|
Transportation, gathering and compression
|
|
|
30,947
|
|
|
|
27,950
|
|
|
|
109,226
|
|
|
|
85,846
|
|
|
Production and ad valorem taxes
|
|
|
3,251
|
|
|
|
3,268
|
|
|
|
4,998
|
|
|
|
11,621
|
|
|
Brokered natural gas and marketing expense
|
|
|
664
|
|
|
|
6,116
|
|
|
|
12,268
|
|
|
|
26,173
|
|
|
Depreciation, depletion and amortization
|
|
|
28,661
|
|
|
|
74,505
|
|
|
|
92,948
|
|
|
|
244,750
|
|
|
Exploration
|
|
|
7,592
|
|
|
|
93,271
|
|
|
|
52,775
|
|
|
|
116,211
|
|
|
General and administrative
|
|
|
9,719
|
|
|
|
8,039
|
|
|
|
39,431
|
|
|
|
46,409
|
|
|
Rig termination and standby
|
|
|
3
|
|
|
|
2,075
|
|
|
|
3,846
|
|
|
|
9,672
|
|
|
Impairment of proved oil and gas properties
|
|
|
—
|
|
|
|
691,334
|
|
|
|
17,665
|
|
|
|
691,334
|
|
|
Accretion of asset retirement obligations
|
|
|
116
|
|
|
|
426
|
|
|
|
391
|
|
|
|
1,623
|
|
|
(Gain) loss on sale of assets
|
|
|
7,880
|
|
|
|
446
|
|
|
|
6,936
|
|
|
|
(4,737
|
)
|
|
Gain on reduction of pension obligations
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
Total operating expenses
|
|
|
90,745
|
|
|
|
911,187
|
|
|
|
349,507
|
|
|
|
1,242,806
|
|
|
OPERATING LOSS
|
|
|
(6,862
|
)
|
|
|
(845,305
|
)
|
|
|
(114,473
|
)
|
|
|
(987,485
|
)
|
|
OTHER INCOME (EXPENSE)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) on derivative instruments
|
|
|
(43,931
|
)
|
|
|
24,494
|
|
|
|
(52,338
|
)
|
|
|
56,021
|
|
|
Interest expense, net
|
|
|
(12,496
|
)
|
|
|
(13,204
|
)
|
|
|
(50,789
|
)
|
|
|
(53,400
|
)
|
|
Gain (loss) on early extinguishment of debt
|
|
|
—
|
|
|
|
—
|
|
|
|
14,489
|
|
|
|
(59,392
|
)
|
|
Other income (expense)
|
|
|
(12
|
)
|
|
|
—
|
|
|
|
(149
|
)
|
|
|
400
|
|
|
Total other expense, net
|
|
|
(56,439
|
)
|
|
|
11,290
|
|
|
|
(88,787
|
)
|
|
|
(56,371
|
)
|
|
LOSS BEFORE INCOME TAXES
|
|
|
(63,301
|
)
|
|
|
(834,015
|
)
|
|
|
(203,260
|
)
|
|
|
(1,043,856
|
)
|
|
INCOME TAX BENEFIT (EXPENSE)
|
|
|
(6
|
)
|
|
|
20,146
|
|
|
|
(546
|
)
|
|
|
72,446
|
|
|
NET LOSS
|
|
$
|
(63,307
|
)
|
|
$
|
(813,869
|
)
|
|
$
|
(203,806
|
)
|
|
$
|
(971,410
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET LOSS PER COMMON SHARE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted
|
|
$
|
(0.23
|
)
|
|
$
|
(3.66
|
)
|
|
$
|
(0.84
|
)
|
|
$
|
(4.46
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted
|
|
|
258,812
|
|
|
|
222,534
|
|
|
|
241,434
|
|
|
|
217,897
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted Revenue
Adjusted Revenue is a non-GAAP financial measure. The Company defines
Adjusted Revenue as follows: total revenues plus net cash receipts
settled derivative instruments less brokered gas and marketing revenue.
The Company believes Adjusted Revenue provides investors with helpful
information with respect to the performance of the Company's operations
and management uses Adjusted Revenue to evaluate its ongoing operations
and for internal planning and forecasting purposes. See the table below
which reconciles Adjusted Revenue and total revenues.
|
|
|
For the Three Months Ended
December 31,
|
|
|
For the Year Ended
December 31,
|
|
|
|
|
2016
|
|
|
2015
|
|
|
2016
|
|
|
2015
|
|
|
Total revenues
|
|
$
|
83,883
|
|
|
$
|
65,882
|
|
|
$
|
235,034
|
|
|
$
|
255,321
|
|
|
Net cash receipts (payments) on derivative instruments
|
|
|
2,826
|
|
|
|
13,320
|
|
|
|
38,696
|
|
|
|
37,074
|
|
|
Brokered natural gas and marketing revenue
|
|
|
(1,608
|
)
|
|
|
(4,807
|
)
|
|
|
(12,019
|
)
|
|
|
(20,720
|
)
|
|
Adjusted revenue
|
|
$
|
85,101
|
|
|
$
|
74,395
|
|
|
$
|
261,711
|
|
|
$
|
271,675
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted Net Loss
Adjusted net loss represents loss before income taxes adjusted for
certain non-cash items as set forth in the table below less income
taxes. We believe adjusted net loss is used by many investors and
published research in making investment decisions and evaluating
operational trends of the Company and its performance relative to other
oil and gas producing companies. Adjusted net loss is not a measure of
net income as determined by GAAP. See the table below for a
reconciliation of adjusted net loss and net loss.
|
|
|
Three Months Ended
December 31,
|
|
|
Year Ended
December 31,
|
|
|
|
|
2016
|
|
|
2015
|
|
|
2016
|
|
|
2015
|
|
|
Loss before income taxes, as reported
|
|
$
|
(63,301
|
)
|
|
$
|
(834,015
|
)
|
|
$
|
(203,260
|
)
|
|
$
|
(1,043,856
|
)
|
|
(Gain) loss on derivative instruments
|
|
|
43,931
|
|
|
|
(24,494
|
)
|
|
|
52,338
|
|
|
|
(56,021
|
)
|
|
Net cash receipts (payments) on derivative instruments
|
|
|
2,826
|
|
|
|
13,320
|
|
|
|
38,696
|
|
|
|
37,074
|
|
|
Rig termination and standby
|
|
|
3
|
|
|
|
2,075
|
|
|
|
3,846
|
|
|
|
9,672
|
|
|
Impairment of proved oil and gas properties
|
|
|
-
|
|
|
|
691,334
|
|
|
|
17,665
|
|
|
|
691,334
|
|
|
Dry hole and other
|
|
|
156
|
|
|
|
365
|
|
|
|
1,029
|
|
|
|
511
|
|
|
Stock based compensation
|
|
|
1,049
|
|
|
|
1,241
|
|
|
|
6,216
|
|
|
|
4,635
|
|
|
Impairment of unproved properties
|
|
|
1,744
|
|
|
|
88,492
|
|
|
|
29,824
|
|
|
|
95,573
|
|
|
Other (income) expense
|
|
|
12
|
|
|
|
-
|
|
|
|
149
|
|
|
|
(400
|
)
|
|
Gain on early extinguishment of debt
|
|
|
-
|
|
|
|
-
|
|
|
|
(14,489
|
)
|
|
|
59,392
|
|
|
(Gain) loss on sale of assets
|
|
|
7,880
|
|
|
|
446
|
|
|
|
6,936
|
|
|
|
(4,737
|
)
|
|
Loss before income taxes, as adjusted
|
|
|
(5,700
|
)
|
|
|
(61,236
|
)
|
|
|
(61,050
|
)
|
|
|
(206,823
|
)
|
|
Income tax benefit (expense)
|
|
|
(6
|
)
|
|
|
20,146
|
|
|
|
(546
|
)
|
|
|
72,446
|
|
|
Adjusted net loss
|
|
$
|
(5,706
|
)
|
|
$
|
(41,090
|
)
|
|
$
|
(61,596
|
)
|
|
$
|
(134,377
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss per Common Share
|
|
$
|
(0.23
|
)
|
|
$
|
(3.66
|
)
|
|
$
|
(0.84
|
)
|
|
$
|
(4.46
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted net loss per Common Share
|
|
$
|
(0.02
|
)
|
|
$
|
(0.18
|
)
|
|
$
|
(0.26
|
)
|
|
$
|
(0.62
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Common Shares Outstanding
|
|
|
258,812
|
|
|
|
222,534
|
|
|
|
241,434
|
|
|
|
217,897
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDAX
Adjusted EBITDAX is a supplemental non-GAAP measure that is used by the
Company to evaluate its financial results. The Company defines Adjusted
EBITDAX as net loss before interest expense; income taxes; impairments;
depreciation, depletion and amortization (“DD&A”); gain (loss) on
derivative instruments, net cash receipts (payments on settled
derivative instruments, and premiums (paid) received on options that
settled during the period); non-cash compensation expense; gain or loss
from sale of interest in gas properties; exploration expenses; and other
unusual or infrequent items set forth in the table below. Adjusted
EBITDAX is not a measure of net income as determined by GAAP. See the
table below for a reconciliation of Adjusted EBITDAX to net loss.
|
|
|
Three Months Ended
December 31,
|
|
|
Year Ended
December 31,
|
|
|
|
|
2016
|
|
|
2015
|
|
|
|
2016
|
|
|
2015
|
|
|
Net loss
|
|
$
|
(63,307
|
)
|
|
$
|
(813,869
|
)
|
|
$
|
(203,806
|
)
|
|
$
|
(971,410
|
)
|
|
Depreciation, depletion and amortization
|
|
|
28,661
|
|
|
|
74,505
|
|
|
|
92,948
|
|
|
|
244,750
|
|
|
Exploration expense
|
|
|
7,592
|
|
|
|
93,271
|
|
|
|
52,775
|
|
|
|
116,211
|
|
|
Rig termination and standby
|
|
|
3
|
|
|
|
2,075
|
|
|
|
3,846
|
|
|
|
9,672
|
|
|
Impairment of proved oil and gas properties
|
|
|
—
|
|
|
|
691,334
|
|
|
|
17,665
|
|
|
|
691,334
|
|
|
Stock-based compensation
|
|
|
1,049
|
|
|
|
1,241
|
|
|
|
6,216
|
|
|
|
4,635
|
|
|
Accretion of asset retirement obligations
|
|
|
116
|
|
|
|
426
|
|
|
|
391
|
|
|
|
1,623
|
|
|
(Gain) loss on derivative instruments
|
|
|
43,931
|
|
|
|
(24,494
|
)
|
|
|
52,338
|
|
|
|
(56,021
|
)
|
|
Net cash receipts (payments) on settled derivatives
|
|
|
2,826
|
|
|
|
13,320
|
|
|
|
38,696
|
|
|
|
37,074
|
|
|
Interest expense, net
|
|
|
12,496
|
|
|
|
13,204
|
|
|
|
50,789
|
|
|
|
53,400
|
|
|
(Gain) loss on sale of assets
|
|
|
7,880
|
|
|
|
446
|
|
|
|
6,936
|
|
|
|
(4,737
|
)
|
|
Gain (loss) on early extinguishment of debt
|
|
|
—
|
|
|
|
—
|
|
|
|
(14,489
|
)
|
|
|
59,392
|
|
|
Other (income) expense
|
|
|
12
|
|
|
|
-
|
|
|
|
149
|
|
|
|
(400
|
)
|
|
Income tax (benefit) expense
|
|
|
6
|
|
|
|
(20,146
|
)
|
|
|
546
|
|
|
|
(72,446
|
)
|
|
Adjusted EBITDAX
|
|
$
|
41,265
|
|
|
$
|
31,313
|
|
|
$
|
105,000
|
|
|
$
|
113,077
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash General and Administrative Expenses
Cash General and Administrative Expenses is a non-GAAP financial measure
used by the Company in the Guidance Table to provide a measure of
Administrative expenses used by many investors and published research in
making investment decisions and evaluating operational trends of the
Company. See the table below for a reconciliation of Cash General and
Administrative Expenses and General and Administrative Expenses.
|
|
|
For the Three
Months Ending
December
31, 2016
|
|
|
For the Year Ending
December 31, 2016
|
|
|
General and administrative expenses, estimated to be reported
|
|
$
|
9,719
|
|
|
$
|
39,431
|
|
|
Stock-based compensation expense
|
|
|
(1,049
|
)
|
|
|
(6,216
|
)
|
|
Cash general and administrative expenses
|
|
$
|
8,670
|
|
|
$
|
33,215
|
|
|
|
|
|
|
|
|
|
|
|
About Eclipse Resources
Eclipse Resources is an independent exploration and production company
engaged in the acquisition and development of oil and natural gas
properties in the Appalachian Basin, including the Utica and Marcellus
Shales. For more information, please visit the Company’s website at www.eclipseresources.com.
Forward-Looking Statements
This press release contains “forward-looking statements” within the
meaning of Section 27A of the Securities Act of 1933, as amended (the
“Securities Act”) and Section 21E of the Securities Exchange Act of
1934, as amended (the “Exchange Act”). All statements, other than
statements of historical fact included in this press release, regarding
Eclipse Resources’ strategy, future operations, financial position,
estimated revenues and income/losses, projected costs and capital
expenditures, prospects, plans and objectives of management are
forward-looking statements. When used in this press release, the words
“plan,” “endeavor,” “will,” “would,” “could,” “believe,” “anticipate,”
“intend,” “estimate,” “expect,” “project” and similar expressions are
intended to identify forward-looking statements, although not all
forward-looking statements contain such identifying words. These
forward-looking statements are based on Eclipse Resources’ current
expectations and assumptions about future events and are based on
currently available information as to the outcome and timing of future
events. When considering forward-looking statements, you should keep in
mind the risk factors and other cautionary statements described under
the heading “Risk Factors” in Eclipse Resources’ Annual Report on Form
10-K filed with the Securities Exchange Commission on March 4, 2016 (the
“2015 Annual Report”), and in “Item 1A. Risk Factors” of Eclipse
Resources’ Quarterly Reports on Form 10-Q.
Forward-looking statements may include statements about Eclipse
Resources’ business strategy; reserves; general economic conditions;
financial strategy, liquidity and capital required for developing its
properties and timing related thereto; realized natural gas, NGLs and
oil prices; timing and amount of future production of natural gas, NGLs
and oil; its hedging strategy and results; future drilling plans;
competition and government regulations, including those related to
hydraulic fracturing; the anticipated benefits under its commercial
agreements; pending legal matters relating to its leases; marketing of
natural gas, NGLs and oil; leasehold and business acquisitions; the
costs, terms and availability of gathering, processing, fractionation
and other midstream services; general economic conditions; credit
markets; uncertainty regarding its future operating results, including
initial production rates and liquid yields in its type curve areas; and
plans, objectives, expectations and intentions contained in this press
release that are not historical.
Eclipse Resources cautions you that these forward-looking statements
are subject to all of the risks and uncertainties, most of which are
difficult to predict and many of which are beyond its control, incident
to the exploration for and development, production, gathering and sale
of natural gas, NGLs and oil. These risks include, but are not limited
to; legal and environmental risks, drilling and other operating risks,
regulatory changes, commodity price volatility and the recent
significant decline of the price of natural gas, NGLs, and oil,
inflation, lack of availability of drilling, production and processing
equipment and services, counterparty credit risk, the uncertainty
inherent in estimating natural gas, NGLs and oil reserves and in
projecting future rates of production, cash flow and access to capital,
the timing of development expenditures, and the other risks described
under the heading “Risk Factors” in the 2015 Annual Report and in “Item
1A. Risk Factors” of Eclipse Resources’ Quarterly Reports on Form 10-Q.
All forward-looking statements, expressed or implied, included in
this press release are expressly qualified in their entirety by this
cautionary statement. This cautionary statement should also be
considered in connection with any subsequent written or oral
forward-looking statements that Eclipse Resources or persons acting on
the Company’s behalf may issue.
View source version on businesswire.com: http://www.businesswire.com/news/home/20170228006894/en/ Copyright Business Wire 2017
Source: Business Wire
(February 28, 2017 - 5:24 PM EST)
News by QuoteMedia
www.quotemedia.com
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