Eclipse Resources Corporation Announces Fourth Quarter and Full Year 2017 Results and an Increase in First Quarter 2018 Production Guidance

STATE COLLEGE, Pa.–(BUSINESS WIRE)–Eclipse Resources Corporation (NYSE:ECR) (the “Company” or “Eclipse
Resources”) today announced its fourth quarter 2017 and full year 2017
financial and operational results, along with an increase in first
quarter 2018 production guidance. In conjunction with this release, the
Company has posted an updated investor presentation to its website at www.eclipseresources.com.

Fourth Quarter 2017 Highlights:

• Average net daily production was 311.7 MMcfe per day, consisting of
  74% natural gas and 26% liquids.
• Realized an average natural gas price, before the impact of cash
  settled derivatives and firm transportation expenses, of $2.55 per
  Mcf, a $0.38 per Mcf discount to the average monthly NYMEX settled
  natural gas price during the quarter.
• Realized an average oil price, before the impact of cash settled
  derivatives, of $49.61 per barrel, a $5.66 per barrel discount to the
  average WTI oil price during the quarter.
• Realized an average natural gas liquids (“NGL”) price, before the
  impact of cash settled derivatives, of $31.16 per barrel, or
  approximately 56% of the average WTI oil price during the quarter.
• Per unit cash production costs (including lease operating,
  transportation, gathering and compression, production and ad valorem
  taxes)were $1.49 per Mcfe, including $0.34 per Mcfe in
  firm transportation expenses.
• Net loss for the fourth quarter of 2017 was $13.1 million; and
  Adjusted EBITDAX1 for the fourth quarter of 2017 was $53.5
  million.

Full Year 2017 Highlights:

• Average net daily production was 310.7 MMcfe per day, consisting of
  77% natural gas and 23% liquids.
• Realized an average natural gas price, before the impact of cash
  settled derivatives and firm transportation expenses, of $2.76 per
  Mcf, a $0.35 per Mcf discount to the average monthly NYMEX settled
  natural gas price during the year.
• Realized an average oil price, before the impact of cash settled
  derivatives, of $46.04 per barrel, a $4.76 per barrel discount to the
  average WTI oil price during the year.
• Realized an average natural gas liquids price, before the impact of
  cash settled derivatives, of $23.62 per barrel, or approximately 46%
  of the average WTI oil price during the year.
• Per unit cash production costs (including lease operating,
  transportation, gathering and compression, production and ad valorem
  taxes)were $1.35 per Mcfe, including $0.34 per Mcfe in
  firm transportation expenses.
• Net income for the year was $8.5 million; and Adjusted EBITDAX1
  for the year was $189.1 million.
• Capital expenditures for fiscal 2017 were $314.1 million, including
  $246.4 million for drilling and completions, $10.5 million for
  midstream expenditures, $55.9 million for land-related expenditures,
  and $1.3 million for corporate-related expenditures
• Proved reserves grew 211% over the previous year to approximately 1.46
  Tcfe at SEC pricing and by 19% to approximately 1.46 Tcfe based on
  forward NYMEX strip pricing; Finding and Development costs, including
  revisions, for fiscal 2017 decreased to $0.26 per Mcfe, utilizing
  drilling and completion costs, and $0.31 per Mcfe including all
  capital uses.

1Non-GAAP measure. See reconciliation for details

Benjamin W. Hulburt, Chairman, President and CEO, commented on the
Company’s fourth quarter and full year 2017 results, “During 2017,
Eclipse Resources had substantial operational and strategic success
leading to an expansion in our asset base, a substantial increase in
cash flow and the addition of a strategic joint venture partner. Through
these actions, we increased our acreage footprint by 57%, generated 85%
year over year growth in EBITDAX, to a company record of approximately
$189 million and commenced a $290 million joint venture process.

As we highlighted during our analyst day, the strategic shift toward
increasing activity in our liquids area has allowed us to capture the
benefit of the recovery in oil prices and to exceed our full year 2017
guidance for both oil and NGL production. In 2018, the Company plans to
turn 13 gross (9 net) Utica Condensate wells with an average lateral
length of 16,325 feet to sales, resulting in over 40% oil production
growth year over year. The first of which was very recently put to sales
with an initial production rate of approximately 2,000 BOE per day
consisting of 60% in total liquids, including approximately 735 barrels
of oil, from a well with a completed lateral length of 15,600 feet. As
the well is continuing to unload water and undergoing our managed
flowback procedure we expect the well’s production to continue to
increase by approximately 15-20% before hitting peak production over the
next two weeks. We expect to put the two remaining wells on the pad with
similar lateral lengths to sales over the course of the coming week. In
addition, the Company has recently turned to sales two Marcellus
Condensate wells with initial production characteristics exceeding
expectations on Mcfe basis, and we will continue to evaluate the
performance of these wells.

As 2018 continues to unfold, we will focus on corporate level returns
and seek to improve these returns by focusing on optimization of our
drilling and completions approach on a pad by pad and well by well
basis. This approach will seek to vary items including proppant
concentrations, stage spacing, cluster spacing, lateral length,
intra-lateral spacing, wells per pad, first well spud to pad turn to
sales cycle time, and most importantly the interrelationship between
each of these variables as a means of maximizing returns on each well we
drill rather than trying to maximize production or EURs at any cost. At
the corporate level we then focus on full cycle returns which
incorporate land, G&A, and hedges to ensure we are exceeding our
weighted average cost of capital. We have tied our compensation
structure to this approach as well which requires a frequent “lookback”
on actual results to calculate our full cycle internal rate of return on
every well using actual timing of capital and turn to sales, drilling
and completion costs, cash flows and incorporating our best estimate of
forward cash flows at current forward strip prices. We will also
continue to produce our wells in a way that maximizes rate while
maintaining the fracture network to accelerate cash flows up to the
point where we believe we would begin to impact well performance.

During 2018, we plan to drill 33 gross wells with an average lateral
length of approximately 16,800 feet, 73% of which are expected to be
“Super-Laterals” with lateral extensions exceeding 15,000 feet. This
represents a 24% increase in average lateral footage per well over 2017
and remains well above any of our peers. 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 through innovation, including reduced plug drill out times,
expanding the use of a bi-fuel fleet, the continued evolution of
engineered completions and the optimization of proppant loading.

Despite a significant amount of volatility during the fourth quarter of
2017 in natural gas prices, we have again been able to deliver a strong
natural gas realized price, as recent firm transportation projects have
created incremental unutilized capacity and new buyers needing to fill
this capacity. We have also taken advantage of this volatility by adding
to our hedge portfolio, with the goal of retaining upside participation
if the natural gas price increases. Lastly, I am extremely pleased with
our team’s continued ability to find creative solutions to build our
business, from the execution of our previously-announced joint venture
agreement with Sequel Energy to our accretive acquisition of the Flat
Castle acreage, which marks another year of accomplishments that we
believe have put us on a path for a successful future.”

Operational Discussion

The Company’s production for the three and twelve months ended
December 31, 2017 and 2016 is set forth in the following table:

Market Conditions

Prices for various quantities of natural gas, NGLs and oil that we
produce significantly impact our revenues and cash flows. Prices for
commodities, such as hydrocarbons, are inherently volatile. The
following table lists average daily, high, low and average monthly
settled NYMEX Henry Hub prices for natural gas and average daily, high
and low NYMEX WTI prices for oil for the three and twelve months ended
December 31, 2017 and 2016:

Financial Discussion

Revenue for the fourth quarter of 2017 totaled $104.1 million, compared
to $83.9 million for the fourth quarter of 2016. Adjusted Revenue2,
which includes the impact of cash settled derivatives and excludes
brokered natural gas and marketing revenue, totaled $105.8 million for
the fourth quarter of 2017 compared to $85.1 million for the fourth
quarter of 2016. Net Loss for the fourth quarter of 2017 was $13.1
million, or $0.05 per share compared to $62.1 million or $0.24 per share
for the fourth quarter of 2016. Adjusted Net Income2 for the
fourth quarter of 2017 was $5.2 million, or $0.02 per share, compared to
an Adjusted Net Loss $4.8 million, or $0.02 per share for the fourth
quarter of 2016. Adjusted EBITDAX2 was $53.5 million for the
fourth quarter of 2017 compared to $42.2 million for the fourth quarter
of 2016.

Revenue for the year ended December 31, 2017 totaled $383.7 million,
compared to $235.0 million for the year ended December 31, 2016.
Adjusted Revenue2, which includes the impact of cash settled
derivatives and excludes brokered natural gas and marketing revenue,
totaled $378.0 million for the year ended December 31, 2017 compared to
$261.7 million for the year ended December 31, 2016. Net Income for the
year ended December 31, 2017 was $8.5 million, or $0.03 per share
compared to a Net Loss of $206.7 million or $0.86 per share for the year
ended December 31, 2016. Adjusted Net Income2 for the
year ended December 31, 2017 was $1.5 million, or $0.01 per share,
compared to an Adjusted Net Loss $64.5 million, or $0.27 per share for
the year ended December 31, 2016. Adjusted EBITDAX2 was
$189.1 million for the year ended December 31, 2017 compared to $102.1
million for the year ended December 31, 2016.

Average realized price calculations for the three months and years ended
December 31, 2017 and 2016 are set forth in the table below:

Per unit cash production costs, which include $0.34 per Mcfe of firm
transportation expense, were $1.49 per Mcfe for the fourth quarter 2017
and increased by 1% compared to the fourth quarter of 2016. The
Company’s cash production costs (includes lease operating,
transportation, gathering and compression, production and ad valorem
taxes) are shown in the table below.

Per unit cash production costs, which include $0.34 per Mcfe of firm
transportation expense, were $1.35 per Mcfe for the year ended
December 31, 2017 and decreased by 10% compared to the year ended
December 31, 2016. The Company’s cash production costs (includes lease
operating, transportation, gathering and compression, production and ad
valorem taxes) are shown in the table below.

General and administrative expense was $44.6 million for the year ended
December 31, 2017 compared to $39.4 million for the year ended
December 31, 2016 and are shown in the table below. General and
administrative expense per Mcfe was $0.39 in the year ended December 31,
2017 compared to $0.47 in the year ended December 31, 2016. General and
administrative expense includes $9.3 million and $6.2 million of
stock-based compensation expense for the years ended December 31, 2017
and 2016, respectively.

Capital Expenditures

Fourth quarter 2017 capital expenditures were $32.3 million, including
$21.8 million for drilling and completions, $4.6 million for midstream
expenditures, $5.7 million for land-related expenditures, and $0.2
million for corporate-related expenditures.

For the year ended December 31, 2017 capital expenditures were $314.1
million, including $246.4 million for drilling and completions, $10.5
million for midstream expenditures, $55.9 million for land-related
expenditures, and $1.3 million for corporate-related expenditures.

During the fourth quarter of 2017, the Company commenced drilling 6
gross (3.3 net) operated Utica Shale wells, commenced completions of 5
gross (3.7 net) operated wells and turned to sales 8 gross (6.6 net)
operated wells.

During the year ended December 31, 2017, the Company commended drilling
29 gross (21.6 net) operated Utica and Marcellus Shale wells, commenced
completions of 24 gross (21.3 net) operated wells and turned to sales 24
gross (22.2 net) operated wells.

Financial Position and Liquidity

As of December 31, 2017, the Company’s liquidity was $208.6 million,
consisting of $17.2 million in cash and cash equivalents and $191.4
million in available borrowing capacity under the Company’s revolving
credit facility (after giving effect to outstanding letters of credit
issued by the Company of $33.6 million).

Matthew R. DeNezza, Executive Vice President and Chief Financial
Officer, commented, “The closing of the joint venture agreement with
Sequel Energy late in the fourth quarter, our year end cash position,
undrawn revolver availability of approximately $191 million, along with
internally generated cash flows, provide us with the ability to fund our
2018 drilling program. In addition, we will continue to monitor
commodity prices as we maintain the flexibility to adjust capital
expenditures during the second half of 2018 as commodity prices dictate.
”

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, 2017:

Natural Gas Derivatives

Oil Derivatives

Subsequent to the End of the Fourth Quarter:

• The Company added to its natural gas hedge portfolio by executing
  incremental natural gas swap hedges of 30,000 MMBtu per day at $2.90.
• The Company added to its oil hedge portfolio by executing incremental
  oil swap hedges of 1,000 Bbl per day at $61.00 as well as incremental
  three way collars of 2,000 Bbl per day at an average floor price of
  $50.00 and an average ceiling price of $60.56.
• The Company added to its oil hedge portfolio by executing incremental
  oil call options of 1,000 Bbl per day at an average ceiling sold price
  of $57.12 and purchased price of $52.25.

Below are tables that illustrates the Company’s hedging activities
subsequent to the end of the fourth quarter:

Natural Gas:

Oil:

Guidance

The Company has also reaffirmed its previously issued first quarter and
full year 2018 guidance as set forth in the table below:

Conference Call

A conference call to review the Company’s financial and operational
results is scheduled for Thursday, March 1, 2018 at 10:00 a.m. Eastern
Time. 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 2017 Earnings Call. A replay of the call
will be available through May 1, 2018. To access the phone replay dial
877-660-6853 or 201-612-7415 for international callers. The conference
ID is 13676633. A live webcast of the call may be accessed through the
Investor Center on the Company’s website at www.eclipseresources.com.
The webcast will be archived for replay on the Company’s website for six
months.

Contacts

Eclipse Resources Corporation
Douglas Kris, 814-325-2059
Investor
Relations
[email protected]

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