Eclipse Resources Corporation (NYSE:ECR) (the “Company” or
“Eclipse Resources”) today announced its second quarter 2017
financial and operational results, along with updated guidance for
the third quarter of 2017 and full year 2017. As discussed further
below the Company has also entered into a commitment agreement with
Sequel Energy Group LLC (“Sequel”) (an affiliate of GSO Capital
Partners, or “GSO”) to establish a proposed drilling joint venture
and has received an increase to its borrowing base on its senior
secured revolving line of credit from its bank-lending group. In
conjunction with this release, the Company has posted an updated
investor presentation to its website at
www.eclipseresources.com.
Second Quarter 2017 Highlights:
- Average net daily production was 287.8
MMcfe per day, exceeding the high end of the Company’s previously
issued production guidance range of 265 to 275 MMcfe per day.
- Realized an average natural gas price,
before the impact of cash settled derivatives and firm
transportation expenses, of $2.98 per Mcf, a $0.20 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 $43.57 per barrel, a
$4.53 per barrel discount to the average WTI oil price during the
quarter, exceeding the Company’s previously issued oil differential
guidance range of $7.50 to $8.50 per barrel.
- Realized an average natural gas liquids
(“NGL”) price, before the impact of cash settled derivatives, of
$16.84 per barrel, or approximately 35% 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 $1.36 per Mcfe
and include $0.35 per Mcfe in firm transportation expenses, which
was below the Company’s previously issued per unit cash production
cost guidance range of $1.45 to $1.50 per Mcfe.
- Net income for the second quarter of
2017 was $11.5 million; and Adjusted EBITDAX1 for the second
quarter of 2017 was $39.6 million.
Subsequent to the end of the Second Quarter:
- The Company has entered into a
commitment agreement with Sequel to establish a drilling joint
venture on the Company’s Utica Shale acreage in southeast Ohio.
Eclipse and Sequel expect to enter into definitive documents
relating to the proposed transaction by the end of the current
quarter.
- The commitment agreement sets forth the
proposed terms for the drilling joint venture, including:
- Committed funding from Sequel of up to
$325 million to fund its proportionate share of two drilling
programs comprising 34 gross wells in aggregate, commencing with
wells currently in progress and extending through wells expected to
be commenced through the end 2018.
- A mutual option for an additional third
well program of similar size, which would increase the committed
funding.
- Eclipse Resources shall be the operator
of all wells drilled within each well program.
- Eclipse Resources shall have the right
to adjust its pre-carry working interest in the first program up
until the fourth quarter of 2017 to between 30% to 50%, and its
pre-carry working interest in the second program to between 30% to
70% until such program is commenced.
- A 15% carried interest on drilling and
completion capital expenditures incurred in each well program,
proportionately reduced to Eclipse Resources retained pre-carry
working interest.
- A significant portion of Sequel’s
working interest in each well program will revert to Eclipse
Resources once a certain return is realized by Sequel in each
program.
The Company’s proposed drilling joint venture with Sequel is
subject to further negotiation, completion and execution of
definitive agreements and other customary conditions. The
commitment agreement provides that Eclipse and Sequel will
negotiate in good faith for a period of time and use their
commercially reasonable efforts to enter into mutually agreeable
definitive documents relating to the proposed transaction, which
the parties expect to complete by the end of the current quarter.
Accordingly, there can be no assurance that the proposed
transaction will be completed in the anticipated timeframe, if at
all, and if consummated, what will be the final terms of such
definitive agreement.
- The Company has recently completed its
semi-annual borrowing base redetermination of its revolving credit
facility, which resulted in an increase in its borrowing base from
$175 million to $225 million. The Company remains undrawn under its
revolving credit facility, other than letters of credit associated
with its firm natural gas transportation agreements.
- The Company added to its 2018 oil hedge
portfolio by executing incremental three way collars of 4,000
barrels per day at an average floor price2 of $45.00 and an average
ceiling price of $52.26.
1 Non-GAAP measure. See reconciliation for
details.
2 For the purposes of calculating three-way
floor price, the higher valued put is used.
Benjamin W. Hulburt, Chairman, President and CEO, commented on
the Company’s second quarter 2017 results, “Our continued focus on
execution, innovation and efficiency resulted in the Company
delivering another tremendous quarter with production above the top
end of our guidance, operating expenses below the low end of our
guidance and continued strong well performance in both the dry gas
and condensate areas of our acreage. This now marks the eleventh
consecutive reporting period in which the Company has met or
exceeded its production and operating expense guidance, which
represents every single reporting period since our initial public
offering in June of 2014.
We continue to strive to be a leader in innovation, not only in
our region, but nationwide, with a significant amount of work we
are doing today focused on new technology applications to improve
productivity, reduce costs and maintain high returning wells as we
develop our substantial drilling inventory. This culture of
innovation powers our well performance and we have seen that
illustrated in our most recent set of Dry Gas wells. These wells
have incorporated a series of trials on numerous new techniques
that will help us develop our “Gen4” well design. Our seven well
Moser pad, located in the Company’s Dry Gas acreage in eastern
Monroe County, Ohio, was turned to sales in June and has produced
at an average rate of approximately 19% above our recently
increased Dry Gas type well expectation. We are continuing to
evaluate which of the new techniques may be the most impactful on
future operations, but we are very encouraged with the results we
are seeing on certain of the techniques we’ve tested.
We have continued our relentless pursuit for industry leading
drilling innovation, and have set a new internal record on our most
recent “super-lateral”, which we drilled to a total measured depth
of 24,600 with a 15,600 foot completable lateral in our Utica
Condensate area in 12 days from spud to TD. Additionally, we are
currently completing what we believe to be the longest onshore
laterals ever drilled, the Great Scott 3H (19,100’ completable
lateral) and Outlaw C11H (19,500’ completable lateral), located in
our Utica Condensate area. We are approximately 70% done completing
these laterals, which have treated as designed thus far. We have
two additional wells to complete on this pad before we will turn
all four wells to sales, which we expect to occur in the fourth
quarter of 2017.
We believe that the drilling joint venture commitment agreement
we have recently entered into with Sequel, an affiliate of GSO,
speaks to both the quality of our assets and our industry leading
operational performance. At today’s forward strip prices, Eclipse
calculates that the present value of the carried interest and
significant working interest reversion as outlined in the
commitment agreement will equate to a meaningful valuation premium
to both where we trade and where recent Utica asset transactions
have taken place. Perhaps most importantly, as we see a significant
amount of commodity volatility looking into 2018, the terms of this
drilling joint venture will allow us to maintain, or even
accelerate our current drilling pace, while scaling our company
level capital expenditures based on the economic environment.
Additionally, prior to commencing each well program, under the
terms proposed in the commitment agreement, Eclipse will have the
ability to choose its working interest for such program within
agreed upon bands. We believe this structure allows us to maintain
an efficient, two-rig operating program while providing flexibility
to manage capital spending to a level that is appropriate depending
on the strength of forward commodity curves. We are extremely
pleased with the proposed terms and structure as outlined by the
commitment agreement with Sequel and the high degree of confidence
that our partner has in our assets and operational capabilities. We
believe that the industry experience of the Sequel team combined
with the scale and structuring capabilities of GSO make them the
ideal drilling joint venture partners for Eclipse.
We believe that our proven operational performance, continued
gain in efficiency and financial flexibility leave us well
positioned to deliver upon the production guidance that we have
provided. We remain highly focused on returns and excited for
continued operational improvement. We believe that these attributes
will drive significant value enhancements from our assets and
generate long-term shareholder value.”
Operational Discussion
The Company’s production for the three and six months ended
June 30, 2017 and 2016 is set forth in the following
table:
Three Months Ended Six Months
Ended June 30, June 30, 2017
2016 2017 2016
Production: Natural gas (MMcf)
20,127.8 15,298.5 39,509.4 28,985.8 NGL sales (Mbbls) 662.1 685.9
1,327.1 1,199.6 Oil sales (Mbbls) 347.8 345.2 801.9 600.5 Total
(MMcfe) 26,187.2 21,485.1 52,283.4 39,786.4
Average daily
production volume: Natural gas (Mcf/d) 221,185 168,115 218,284
159,263 NGL sales (Bbls/d) 7,276 7,537 7,332 6,591 Oil sales
(Bbls/d) 3,822 3,793 4,430 3,299 Total (Mcfe/d) 287,771 236,095
288,859 218,603
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 NYMEX WTI prices
for oil for the three and six months ended June 30, 2017 and
2016:
Three Months Ended Six Months
Ended June 30, June 30, 2017
2016 2017 2016 NYMEX Henry Hub
High ($/MMBtu) $ 3.27 $ 2.94 $ 3.71 $ 2.94 NYMEX Henry Hub Low
($/MMBtu) 2.85 1.71 2.44 1.49 Average Daily NYMEX Henry Hub
($/MMBtu) 3.08 2.16 3.05 2.09 Average Monthly NYMEX Settled Henry
Hub ($/MMBtu) 3.18 1.95 3.25 2.02 NYMEX WTI High ($/Bbl) $
53.38 $ 51.23 $ 54.48 $ 51.23 NYMEX WTI Low ($/Bbl) 42.48 34.30
42.48 26.19 Average NYMEX WTI ($/Bbl) 48.10 46.21 49.85 40.88
Financial Discussion
Revenue for the second quarter of 2017 totaled $86.2 million,
compared to $47.1 million for the second quarter of 2016. Adjusted
Revenue3, which includes the impact of cash settled derivatives and
excludes brokered natural gas and marketing revenue, totaled $83.6
million for the second quarter of 2017 compared to $58.8 million
for the second quarter of 2016. Net Income (Loss) for the second
quarter of 2017 was $11.5 million, or $0.04 per share compared to
$(73.2) million or $(0.33) per share for the second quarter of
2016. Adjusted Net Income (Loss) 3 for the second quarter of 2017
was $(2.8) million, or $(0.01) per share, compared to $(24.1)
million, or $(0.11) per share for the second quarter of 2016.
Adjusted EBITDAX3 was $39.6 million for the second quarter of 2017,
compared to $16.9 million for the second quarter of 2016.
Revenue for the six months ended June 30, 2017 totaled $188.1
million, compared to $96.7 million for the six months ended June
30, 2016. Adjusted Revenue3, which includes the impact of cash
settled derivatives and excludes brokered natural gas and marketing
revenue, totaled $179.0 million for the six months ended June 30,
2017 compared to $117.6 million for the six months ended June 30,
2016. Net Income (Loss) for the six months ended June 30, 2017 was
$38.3 million, or $0.15 per share compared to $(118.7) million or
$(0.53) per share for the six months ended June 30, 2016. Adjusted
Net Income (Loss)3 for the six months ended June 30, 2017 was $2.1
million, or $0.01 per share, compared to $(39.2) million, or
$(0.18) per share for the six months ended June 30, 2016. Adjusted
EBITDAX3 was $89.8 million for the six months ended June 30, 2017,
compared to $37.3 million for the six months ended June 30,
2016.
3 Adjusted Revenue, Adjusted Net Income
(Loss) and Adjusted EBITDAX are non-GAAP financial measures. Tables
reconciling Adjusted Revenue, Adjusted Net Income (Loss) and
Adjusted EBITDAX to the most directly comparable GAAP measures can
be found at the end of the financial statements included in this
press release.
Average realized price calculations for the three and six months
ended June 30, 2017 and 2016 are set forth in the table below:
Three Months Ended Six Months
Ended June 30, June 30, 2017
2016 2017 2016 Average Sales
Price (excluding cash settled derivatives
and firm transportation)
Natural gas ($/Mcf) $ 2.98 $ 1.56 $ 3.07 $ 1.79 NGLs ($/Bbl) 16.84
13.60 21.26 13.22 Oil ($/Bbl) 43.57 36.74 45.02 30.99 Total average
prices ($/Mcfe) 3.29 2.14 3.55 2.17
Average Sales Price
(including cash settled derivatives,
excluding firm transportation)
Natural gas ($/Mcf) $ 2.86 $ 2.31 $ 2.94 $ 2.60 NGLs ($/Bbl) 16.38
13.43 20.23 13.43 Oil ($/Bbl) 43.57 41.38 45.11 43.52 Total average
prices ($/Mcfe) 3.19 2.74 3.42 2.96
Average Sales Price
(including firm transportation,
excluding cash settled
derivatives)
Natural gas ($/Mcf) $ 2.52 $ 1.12 $ 2.56 $ 1.35 NGLs ($/Bbl) 16.84
13.60 21.26 13.22 Oil ($/Bbl) 43.57 36.74 45.02 30.99 Total average
prices ($/Mcfe) 2.94 1.82 3.16 1.85
Average Sales Price
(including cash settled derivatives
and firm transportation)
Natural gas ($/Mcf) $ 2.41 $ 1.86 $ 2.43 $ 2.16 NGLs ($/Bbl) 16.38
13.43 20.23 13.43 Oil ($/Bbl) 43.57 41.38 45.11 43.52 Total average
prices ($/Mcfe) 2.84 2.42 3.04 2.63
The Company’s operating expenses per Mcfe for the second quarter
of 2017 decreased by 8% 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 $1.36 per Mcfe
for the second quarter 2017 and includes $0.35 per Mcfe of firm
transportation expenses.
Three Months Ended Six Months
Ended June 30, June 30, 2017
2016 2017 2016 Operating
expenses (in thousands): Lease operating $ 4,568 $ 2,248 $
6,911 $ 4,925 Transportation, gathering and compression 28,969
28,254 61,846 51,391 Production and ad valorem taxes 2,033 2,203
3,964 4,766 Depreciation, depletion and amortization 25,152 20,949
51,341 36,062 General and administrative 10,730 10,402 20,862
21,676
Operating expenses per Mcfe: Lease operating $ 0.17 $
0.10 $ 0.13 $ 0.12 Transportation, gathering and compression 1.11
1.32 1.19 1.29 Production, severance and ad valorem taxes 0.08 0.10
0.08 0.12 Depreciation, depletion and amortization 0.96 0.98 0.98
0.91 General and administrative 0.41 0.48 0.40 0.54
Capital Expenditures
Second quarter 2017 capital expenditures were $98.5 million.
These expenditures included $80.2 million for drilling and
completions, $0.7 million for midstream expenditures, $17.3 million
for land-related expenditures, and $0.3 million for
corporate-related expenditures.
During the second quarter of 2017, the Company drilled 9 gross
(8.6 net) operated Utica Shale wells. In addition, the Company
completed 6 gross (5.8 net) operated wells and turned to sales 9
gross (9.0 net) operated wells.
Financial Position and
Liquidity
As of June 30, 2017, the Company’s liquidity was $238.5
million, consisting of $97.1 million in cash and cash equivalents
and $141.4 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).
Subsequent to the end of the second quarter, 2017, the Company
completed its semi-annual borrowing base redetermination of its
revolving credit facility, which resulted in an increase in its
borrowing base from $175 million to $225 million. The Company
remains undrawn on its revolving credit facility, other than for
letters of credit.
Matthew R. DeNezza, Executive Vice President and Chief Financial
Officer, commented, “At quarter end and pro-forma for the recent
borrowing base redetermination, which resulted in a borrowing base
increase of approximately 29%, our liquidity would have been
approximately $288 million. We remain highly focused on the
strength of our balance sheet with the objective of keeping our
leverage ratios low. We believe this strong liquidity position
coupled with our proposed drilling joint venture will allow us the
flexibility to navigate the current commodity price volatility with
a focus on the future. Finally, we believe we possess a
well-balanced hedge book through the end of the fiscal year 2018,
which will provide additional certainty of cash flows as we look
toward the future.”
Commodity Derivatives
The Company engages in a number of different commodity trading
program strategies as a risk management tool to attempt to mitigate
the potential negative impact on cash flows caused by price
fluctuations in natural gas, NGL and oil prices. Below is a table
that illustrates the Company’s hedging activities as of
June 30, 2017:
Natural Gas Derivatives
Volume
Weighted Average
Description (MMBtu/d) Production Period
Price ($/MMBtu) Natural Gas Swaps: 10,000 July
2017 – December 2017 $ 2.98 10,000 July 2017 – December 2017 $ 3.21
30,000 October 2017 – March 2018 $ 3.46
Natural Gas Three-way
Collars: Floor purchase price (put) 160,000 July 2017 –
December 2017 $ 2.83 Ceiling sold price (call) 160,000 July 2017 –
December 2017 $ 3.37 Floor sold price (put) 160,000 July 2017 –
December 2017 $ 2.31 Floor purchase price (put) 30,000 July 2017 –
March 2019 $ 3.00 Ceiling sold price (call) 30,000 July 2017 –
March 2019 $ 3.40 Floor sold price (put) 20,000
July 2017 – March 2019
$ 2.40 Floor sold price (put) 10,000 July 2017 – March 2019 $ 2.20
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 Floor purchase price (put) 60,000 January 2018 – March 2018 $
2.90 Ceiling sold price (call) 60,000 January 2018 – March 2018 $
3.75 Floor sold price (put) 60,000 January 2018 – March 2018 $ 2.40
Floor purchase price (put) 60,000 April 2018 – December 2018 $ 2.90
Ceiling sold price (call) 60,000 April 2018 – December 2018 $ 3.25
Floor sold price (put) 60,000 April 2018 – December 2018 $ 2.40
Floor purchase price (put) 60,000 January 2018 – December 2018 $
2.80 Ceiling sold price (call) 60,000 January 2018 – December 2018
$ 3.35 Floor sold price (put) 60,000 January 2018 – December 2018 $
2.33 Floor purchase price (put) 20,000 July 2017 – December 2018 $
2.90 Ceiling sold price (call) 20,000 July 2017 – December 2018 $
3.25 Floor sold price (put) 20,000 July 2017 – December 2018 $ 2.40
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 July 2017 –
December 2017 $ (0.19 ) Appalachia - Dominion 40,000 July 2017 –
November 2017 $ (1.01 ) Appalachia - Dominion 40,000 July 2017 –
November 2017 $ (1.04 )
Oil Derivatives
Volume Weighted Average
Description (Bbls/d) Production Period
Price ($/Bbl) Oil Three-way Collars: Floor
purchase price (put) 2,000 July 2017 – September 2017 $ 46.00
Ceiling sold price (call) 2,000 July 2017 – September 2017 $ 59.50
Floor sold price (put) 2,000 July 2017 – September 2017 $ 38.00
Floor purchase price (put) 2,000 July 2017 – December 2017 $ 46.00
Ceiling sold price (call) 2,000 July 2017 – December 2017 $ 60.00
Floor sold price (put)
2,000 July 2017 – December 2017 $ 38.00
NGL Derivatives
Volume Weighted Average
Description (Gal/d) Production Period Price
($/Gal) Propane Swaps: 84,000 July 2017 –
December 2017 $ 0.60
Subsequent to June 30, 2017, the Company entered into the
following derivative instruments:
Volume Production
Weighted Average Description (Bbls/d)
Period Price ($/Bbl) Oil Three-way Collars:
Floor purchase price (put) 4,000 January 2018 – December
2018 $ 45.00 Ceiling sold price (call) 4,000 January 2018 –
December 2018 $ 52.26 Floor sold price (put) 4,000 January 2018 –
December 2018 $ 35.00
Guidance
The Company issued the following third quarter and full year
2017 guidance in the table below:
Q3 2017 FY 2017 Production MMcfe/d 350
- 355 315 - 320 % Gas 80% - 85% 77% - 81% % NGL 10% - 12% 11% - 15%
% Oil 5% - 7% 7% - 9% Gas Price Differential ($/Mcf)1,2 $(0.60) -
$(0.70) $(0.25) - $(0.35) Oil Differential ($/Bbl)1 $(6.50) -
$(7.00) $(6.00) - $(7.00) NGL Prices (% of WTI)1 30% - 35% 35% -
40% Cash Production Costs ($/Mcfe)3 $1.20 - $1.25 $1.40 - $1.45
Cash G&A ($mm)4 $9.0 - $10.0 $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 to the most comparable GAAP
measure at the end of the financial statements included in this
press release.
5.
Excludes potential acquisitions and
payments of approximately $17 million for land leased in 2016 which
are expected to be paid in 2017.
Conference Call
A conference call to review the Company’s financial second
quarter 2017 earnings is scheduled for Thursday, August 3, 2017, at
10:00 a.m. (Eastern). To participate in the call, please dial
877-709-8150, or 201-689-8354 for international callers, and
reference Eclipse Resources Second Quarter Earnings Call. A replay
of the call will be available through October 4, 2017. To access
the phone replay dial 877-660-6853 or 201-612-7415 for
international callers. The conference ID is 13667027. 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)
June 30, December 31, 2017 2016
ASSETS CURRENT ASSETS Cash and cash equivalents $
97,075 $ 201,229 Accounts receivable 40,438 44,423 Assets held for
sale 404 468 Other current assets 4,426 4,295 Total
current assets 142,343 250,415
PROPERTY AND EQUIPMENT AT
COST Oil and natural gas properties, successful efforts method:
Unproved properties 492,058 526,270 Proved oil and gas properties,
net 567,724 414,482 Other property and equipment, net 6,271
6,748 Total property and equipment, net 1,066,053 947,500
OTHER NONCURRENT ASSETS Other assets 3,861
729
TOTAL ASSETS $ 1,212,257 $
1,198,644 LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES Accounts payable $ 56,623 $ 44,049
Accrued capital expenditures 15,329 11,083 Accrued liabilities
20,174 55,044 Accrued interest payable 21,239 21,098 Liabilities
held for sale 189 245 Total current liabilities
113,554 131,519
NONCURRENT LIABILITIES Debt, net of
unamortized discount and debt issuance costs 493,644 492,278 Asset
retirement obligations 5,598 4,806 Other liabilities 2,156
13,434 Total liabilities 614,952 642,037
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, 262,738,442
and 260,591,893 shares issued and
outstanding, respectively
2,637 2,607 Additional paid in capital 1,963,090 1,958,731 Treasury
stock, shares at cost; 991,247 and 72,704 shares, respectively
(2,093 ) (61 ) Accumulated deficit (1,366,329 )
(1,404,670 ) Total stockholders' equity 597,305
556,607
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $
1,212,257 $ 1,198,644 ECLIPSE
RESOURCES CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF
OPERATIONS
(In thousands, except per share data)
(Unaudited)
For the Three Months Ended
For the Six Months Ended June 30, June 30,
2017 2016 2017 2016
REVENUES Natural gas, oil and natural gas liquids sales $
86,194 $ 45,901 $ 185,625 $ 86,389 Brokered natural gas and
marketing revenue (3 ) 1,165 2,428
10,283 Total revenues 86,191 47,066 188,053 96,672
OPERATING EXPENSES Lease operating 4,568 2,248 6,911 4,925
Transportation, gathering and compression 28,969 28,254 61,846
51,391 Production and ad valorem taxes 2,033 2,203 3,964 4,766
Brokered natural gas and marketing expense 6 2,160 2,466 11,562
Depreciation, depletion and amortization 25,152 20,949 51,341
36,062 Exploration 8,997 17,444 20,577 33,100 General and
administrative 10,730 10,402 20,862 21,676 Rig termination and
standby — 1,292 — 3,955 Impairment of proved oil and gas properties
— — — 17,665 Accretion of asset retirement obligations 128 89 252
175 (Gain) loss on sale of assets 6 (1,024 ) 1
(1,046 ) Total operating expenses 80,589
84,017 168,220 184,231
OPERATING INCOME (LOSS)
5,602 (36,951 ) 19,833 (87,559
) OTHER INCOME (EXPENSE) Gain (loss) on derivative
instruments 18,177 (29,596 ) 43,274 (19,046 ) Interest expense, net
(12,285 ) (12,439 ) (24,747 ) (25,900 ) Gain (loss) on early
extinguishment of debt — 5,825 — 14,489 Other income (expense)
— (2 ) (19 ) (141 ) Total other
expense, net 5,892 (36,212 ) 18,508
(30,598 )
INCOME (LOSS) BEFORE INCOME TAXES 11,494
(73,163 ) 38,341 (118,157 )
INCOME TAX BENEFIT (EXPENSE) — — —
(540 )
NET INCOME (LOSS) $ 11,494
$ (73,163 ) $ 38,341 $
(118,697 ) NET INCOME (LOSS) PER COMMON
SHARE Basic
$ 0.04 $ (0.33 )
$ 0.15 $ (0.53 ) Diluted
$ 0.04 $ (0.33 ) $
0.15 $ (0.53 ) WEIGHTED
AVERAGE COMMON SHARES OUTSTANDING Basic
262,423
223,013 261,768 222,898 Diluted
264,420
223,013 264,321 222,898
Adjusted Revenue
Adjusted revenue is a non-GAAP financial measure. The Company
defines Adjusted revenue as follows: total revenues plus net cash
receipts or payments on settled derivative instruments less
brokered natural 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
For the Six Months Ended
June 30, June 30, $ thousands
2017
2016 2017 2016 Total revenues $ 86,191
$ 47,066 $ 188,053 $ 96,672 Net cash receipts (payments) on
derivative
instruments
(2,644 ) 12,880 (6,633 ) 31,258 Brokered natural gas and marketing
revenue 3 (1,165 ) (2,428 ) (10,283 )
Adjusted revenue $ 83,550 $
58,781 $ 178,992 $ 117,647
Adjusted Net Income
(Loss)
Adjusted net income (loss) represents income (loss) before
income taxes adjusted for certain non-cash items as set forth in
the table below. We believe Adjusted net income (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 income (loss) is not a measure of net income (loss) as
determined by GAAP. See the table below for a reconciliation of
Adjusted net income (loss) and net income (loss).
Three Months Ended Six Months Ended
June June 30, 30, $ thousands
2017
2016 2017 2016 Income (loss) before
income taxes, as reported $ 11,494 $ (73,163 ) $ 38,341 $ (118,157
) (Gain) loss on derivative instruments (18,177 ) 29,596 (43,274 )
19,046 Net cash receipts (payments) on derivative instruments
(2,644 ) 12,880 (6,633 ) 31,258 Rig termination and standby — 1,292
— 3,955 Impairment of proved oil and gas properties — — — 17,665
Dry hole and other 79
511
942 548 Stock-based compensation 2,348 2,226 4,429 3,701 Impairment
of unproved properties 4,125 9,360 8,250 18,720 Other (income)
expense — 2 19 141 Gain on early extinguishment of debt — (5,825 )
— (14,489 ) (Gain) loss on sale of assets 6 (1,024 )
1 (1,046 ) Loss before income taxes, as adjusted
(2,769 ) (24,145 ) 2,075 (38,658 ) Income tax benefit (expense)
— — — (540 )
Adjusted net income
(loss) $ (2,769 ) $ (24,145
) $ 2,075 $ (39,198 )
Net income (loss) per Common Share Basic
$
0.04 $ (0.33 ) $ 0.15
$ (0.53 ) Diluted
$ 0.04
$ (0.33 ) $ 0.15 $
(0.53 ) Adjusted net income (loss) per
Common Share Basic
$ (0.01 ) $
(0.11 ) $ 0.01 $ (0.18
) Diluted
$ (0.01 ) $
(0.11 ) $ 0.01 $ (0.18
) Weighted Average Common Shares Outstanding
Basic
262,423 223,013 261,768 222,898
Diluted
264,420 223,013 264,321 222,898
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 income or 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 or loss as determined by GAAP. See
the table below for a reconciliation of Adjusted EBITDAX to net
income or net loss.
Three Months Ended Six Months Ended
June 30, June 30, $ thousands
2017
2016 2017 2016 Net income (loss)
$ 11,494 $ (73,163 ) $ 38,341 $ (118,697 ) Depreciation, depletion
and amortization 25,152 20,949 51,341 36,062 Exploration expense
8,997 17,444 20,577 33,100 Rig termination and standby — 1,292 —
3,955 Impairment of proved oil and gas properties — — — 17,665
Stock-based compensation 2,348 2,226 4,429 3,701 Accretion of asset
retirement obligations 128 89 252 175 (Gain) loss on derivative
instruments (18,177 ) 29,596 (43,274 ) 19,046 Net cash receipts
(payments) on settled derivatives (2,644 ) 12,880 (6,633 ) 31,258
Interest expense, net 12,285 12,439 24,747 25,900 (Gain) loss on
sale of assets 6 (1,024 ) 1 (1,046 ) (Gain) loss on early
extinguishment of debt — (5,825 ) — (14,489 ) Other (income)
expense — 2 19 141 Income tax (benefit) expense — —
— 540
Adjusted EBITDAX $ 39,589
$ 16,905 $ 89,800 $
37,311
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.
Guidance For the Three
For the Three
Months Ended
Months Ending
For the Year Ending
$ thousands
June 30, 2017
September 30, 2017
December 31, 2017
General and administrative expenses, estimated to be
reported
$ 10,730 $ 11,000-$13,000 $ 44,500-$47,500 Stock-based compensation
expense (2,348 ) (2,000-3,000 ) (9,500-10,500
)
Cash general and administrative
expenses
$ 8,382 $ 9,000-$10,000 $ 35,000-$37,000
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 3, 2017 (the “2016 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; our proposed drilling joint
venture with Sequel; 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, our inability to successfully negotiate or enter into
definitive agreements and satisfy other conditions precedent for
our proposed joint venture drilling transaction with Sequel, and to
effectively implement that transaction, 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
2016 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/20170802006527/en/
Eclipse Resources CorporationDouglas Kris, Investor
Relations814-325-2059dkris@eclipseresources.com
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