Eclipse Resources Corporation (NYSE:ECR) (the “Company” or
“Eclipse Resources”) today announced its third quarter 2016
financial and operational results.
Third Quarter 2016 Highlights:
- Average net daily production was 221.6
MMcfe per day, exceeding the high end of the Company’s previously
issued guidance.
- Realized an average natural gas price,
before the impact of cash settled derivatives and firm
transportation expenses, of $2.28 per Mcf, a $0.60 discount to the
average NYMEX natural gas prices during the quarter.
- Realized an average oil price, before
the impact of cash settled derivatives of $39.67 per barrel, a
$5.22 per barrel discount to the average WTI oil price during the
quarter.
- Realized an average natural gas liquids
price, before the impact of cash settled derivatives of $13.41 per
barrel, or approximately 30% of the average WTI oil price during
the quarter.
- Per unit cash production costs
(includes lease operating, transportation, gathering and
compression, production and ad valorem taxes) were $1.53 per Mcfe
and includes $0.39 per Mcfe of firm transportation expenses.
- Net loss for the third quarter of 2016
was $26.8 million; Adjusted EBITDAX1 for the third quarter of 2016
was $21.7 million.
- Completed 12 wells utilizing Eclipse’s
“Generation 3” completion design which incorporates increased
proppant loading, tighter spacing and 100% slickwater. The Company
turned 11 gross (9.6 net) wells to sales during the third quarter
of 2016 and was very encouraged with the initial results of the
wells as compared to the Company’s previous completion
designs.
- The Company’s first “Super-Lateral”
well continued to outperform the Company’s “type well”
expectations, producing a cumulative amount of 2.4 Bcfe (38% gas,
38% condensate and 24% natural gas liquids) during the first 185
days of production while exhibiting significantly shallower
pressure declines than the Company anticipated. Based on the well’s
performance to date, the Company currently estimates the well will
outperform the Company’s “type well” reserve expectations by 28% to
50%.
Subsequent to the end of the Third Quarter:
- Commenced transporting natural gas as
the only user on the 205,000 MMBtu per day Utica Access Project
into the Columbia Gas Transmission “TCO” pool.
- The Company completed its borrowing
base redetermination of its revolving credit facility which
resulted in no change to its $125 million borrowing base. 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 hedges of 90,000 MMBtu per
day.
- The Company has 198,333 MMBtu per day
of 2017 natural gas production hedged, or approximately 80% of its
expected natural gas production, at an average floor price2 of
$2.86 and an average ceiling price of $3.28.
- The Company has an average of 3,500
barrels per day of 2017 oil production hedged, or approximately 80%
of its expected oil production, at an average floor price2 of
$46.00 and an average ceiling price of $59.81.
- The Company has 140,000 MMBtu per day
of 2018 natural gas production hedged at an average floor price2 of
$2.86 and an average ceiling price of $3.29.
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 third quarter 2016 results, “The team’s continuously
outstanding execution and innovation has allowed us to yet again
exceed the high end of our production guidance while delivering
unit operating costs below our previously estimated guidance range
for the quarter. During the third quarter, a team of Eclipse
Resources and Halliburton personnel set a Halliburton record for
the number of stages completed in a month by a single crew in the
Northeast region. This record was set and then broken by the same
crew in two consecutive months. Additionally, this week we learned
we set their record for the total amount of proppant pumped in a
month by a single crew in the Northeast, pumping over 82 million
pounds of proppant in October. We have transferred some lessons
learned from our ground breaking Purple Hayes “Super-Lateral” well
which continues to exceed our type well expectations to date.
During the quarter, we completed 12 of our DUC wells using what we
refer to as our “Generation 3” completion design that incorporates
tighter spacing, increased proppant loading and 100% slickwater.
Due to record setting efficiencies in our completion operations, we
have been able to effectively neutralize well cost inflation
keeping our well costs within budget and maintaining leading edge
cost metrics.
To date, our wells turned to sales using the “Generation 3”
completion design have exhibited higher initial flowing tubing
pressures as compared to Generation 1 and 2 completions employed
previously. These wells are being produced using our managed
pressure drawdown method and have demonstrated flat production with
very encouraging pressure declines similar to what we’ve seen on
our Purple-Hayes well.
We are continuing to drill on our Utica Shale dry gas acreage in
eastern Monroe County, Ohio where we are currently drilling a 7
well pad. Additionally, we are currently completing our first
“Generation 3” completion in the dry gas window on a five well pad
with average lateral extensions of 10,891 feet in which we are
successfully placing proppant concentrations of 2,600 to 3,000
pounds per foot using 100% slickwater. We expect to begin putting
these exciting test wells to sales starting late in the fourth
quarter.
With the commencement of our Utica Access capacity in
mid-October, we can now transport up to 205,000 MMBtu per day of
our gas to the “TCO” pool. With this capacity now in place, we have
seen an immediate uplift to our realized natural gas prices and
expect to realize a differential of ($0.30) to ($0.35) per Mcf on
natural gas sales during the fourth quarter of 2016. Based on
forward basis pricing, this capacity could allow for an estimated
basis uplift of approximately $1.08 per MMBtu3 for 2017 relative to
selling natural gas at Dominion South Point. This valuable natural
gas firm transport capacity coupled with our recently added ability
to access capacity on the Mariner East I pipeline for a portion of
our ethane should enable us to achieve a higher overall realized
price per unit moving forward.
We have taken advantage of the recent price improvement in
natural gas markets to finish out our 2017 gas hedging program,
which now covers approximately 80% of our currently expected
natural gas production of 2017, and to commence our 2018 natural
gas hedging program which now totals 140,000 MMBtu per day. We
expect to continue to opportunistically add to our 2018 hedge
portfolio as prices allow, while attempting to retain upside
participation if the natural gas price increases.”
3
Based on the full year 2017 calendar
spread between Dominion South Point and the TCO pool
Operational Discussion
The Company’s production for the three months ended
September 30, 2016 and 2015 is set forth in the following
table:
Three Months Ended
September 30,
2016 2015 Production:
Natural gas (MMcf) 15,372.2 13,412.4 NGL sales (Mbbls) 525.5
663.2 Oil sales (Mbbls) 310.0 554.6 Total (MMcfe) 20,385.2 20,719.2
Average daily production volume: Natural gas (Mcf/d)
167,089 145,787 NGL sales (Bbls/d) 5,712 7,209 Oil sales (Bbls/d)
3,370 6,028 Total (Mcfe/d) 221,575 225,209
The table below summarizes year to date activity as of September
30, 2016 and the number of wells expected to be turned to sales for
the remainder of 2016:
Area Wells Spud YTD Wells
Completed YTD Wells to Sales YTD
Planned Wells to Salesin Q4
2016
Condensate/Rich Gas 2 — — — Dry Gas
East 5 2 — 5 Lean Condensate 1 15 14 3
Financial Discussion
GAAP Revenues for the third quarter of 2016 totaled $54.5
million, compared to $71.2 million for the third quarter of 2015.
Adjusted Revenues4, which includes the impact of cash settled
derivatives and excludes brokered natural gas and marketing
revenue, totaled $59.0 million for the third quarter of 2016
compared to $71.3 million for the third quarter of 2015. Net loss
for the third quarter of 2016 was $26.8 million, or ($0.10) per
share. Adjusted Net Loss4 for the third quarter of 2016 was $21.4
million, or ($0.08) per share. Adjusted EBITDAX4 was $21.7 million
for the third quarter of 2016.
4
Adjusted Revenue, Adjusted Net Loss and
Adjusted EBITDAX are non-GAAP financial measures. Tables
reconciling Adjusted Revenue, Adjusted Net Loss and Adjusted
EBITDAX to the most directly comparable GAAP measures can be found
at the end of the financial statements included in this press
release.
Average realized price calculations are set forth in the table
below:
Three Months Ended
September 30,
Nine Months Ended
September 30,
2016 2015 2016
2015 Average Sales Price (excluding cash settled
derivatives) Natural gas ($/Mcf) $ 2.28 $ 2.86 $ 1.96 $ 2.76
NGLs ($/Bbl) 13.41 4.16 13.28 11.42 Oil ($/Bbl) 39.67 37.52 33.95
40.25 Total average prices ($/Mcfe) 2.67 2.99 2.34 3.26
Average Sales Price (including cash settled derivatives)
Natural gas ($/Mcf) $ 2.50 $ 3.50 $ 2.57 $ 3.42 NGLs ($/Bbl) 13.21
4.16 13.36 11.42 Oil ($/Bbl) 43.60 38.98 43.56 41.24 Total average
prices ($/Mcfe) 2.89 3.44 2.94 3.71
Average Sales Price
(including firm transportation) Natural gas ($/Mcf) $ 1.77 $
2.56 $ 1.49 $ 2.49 NGLs ($/Bbl) 13.41 4.16 13.28 11.42 Oil ($/Bbl)
39.67 37.52 33.95 40.25 Total average prices ($/Mcfe) 2.28 2.80
1.99 3.09
Average Sales Price (including cash settled
derivatives and firm transportation) Natural gas ($/Mcf) $ 2.00
$ 3.20 $ 2.10 $ 3.15 NGLs ($/Bbl) 13.21 4.16 13.36 11.42 Oil
($/Bbl) 43.60 38.98 43.56 41.24 Total average prices ($/Mcfe) 2.51
3.25 2.59 3.54
The Company’s primary operating expenses decreased by 38%
compared to the prior year’s quarter and are shown below. Per unit
cash production costs (includes lease operating, transportation,
gathering and compression, production and ad valorem taxes) were
$1.53 per Mcfe for the third quarter 2016.
Three Months Ended
September 30,
Nine Months Ended
September 30,
2016 2015 2016
2015 Operating expenses (in thousands): Lease
operating $ 2,186 $ 3,212 $ 7,111 $ 10,147 Transportation,
gathering and compression 26,888 22,811 78,279 57,896 Production
and ad valorem taxes 1,980 3,175 1,747 8,353 Depreciation,
depletion and amortization 28,225 67,172 64,287 170,245 General and
administrative 8,036 13,710 29,712 38,370
Operating expenses per
Mcfe: Lease operating $ 0.11 $ 0.16 $ 0.12 $ 0.19
Transportation, gathering and compression 1.32 1.10 1.30 1.09
Production, severance and ad valorem taxes 0.10 0.15 0.03 0.16
Depreciation, depletion and amortization 1.38 3.24 1.07 3.20
General and administrative 0.39 0.66 0.49 0.72
Capital Expenditures
Third quarter 2016 capital expenditures were $76.6 million.
These expenditures included $67.3 million for drilling and
completions (operated drilling and completions of $65.3 million and
non-operated drilling and completions of $2.0 million), ($0.1)
million for midstream expenditures, $9.3 million for land related
expenditures, and $0.1 million for corporate related
expenditures.
Financial Position and
Liquidity
As of September 30, 2016, the Company’s liquidity was $272
million consisting of $178 million in cash and cash equivalents and
available borrowing capacity under the Company’s revolving credit
facility of $94 million (after giving effect to outstanding letters
of credit issued by the Company of $31 million).
Subsequent to the end of the third 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 remain at $125 million. The next borrowing base
redetermination under the revolving credit facility is scheduled to
occur in the spring of 2017 under the terms of the Company’s credit
agreement.
Matthew R. DeNezza, Executive Vice President and Chief Financial
Officer, commented, “With the closing of our equity offering early
in the quarter and the recent completion of our borrowing base
redetermination, we continue to maintain a strong liquidity
position based on a sizable, quarter end cash position of $178
million and an undrawn revolver with availability of over $90
million after giving effect to our currently outstanding letters of
credit. We believe this liquidity position as well as our continued
cash flow outperformance will create the foundation used to
generate a robust growth profile as we move out of this year and
into next.”
Commodity Derivatives
The Company engages in a number of different commodity trading
program strategies as a risk management tool to attempt to mitigate
the potential negative impact on cash flows caused by price
fluctuations in natural gas, natural gas liquids and oil prices.
Below is a table that illustrates the Company’s current hedging
activities:
Description Volume
(MMBtu/d)
Production Period Weighted
Average
Price ($/MMBtu)
Natural Gas Swaps: 65,000 September 2016 – December
2016 $ 3.28 10,000 January 2017 – December 2017 $ 2.98
Natural
Gas Collars: Floor purchase price (put) 30,000 September 2016 –
December 2017 $ 3.00 Ceiling sold price (call) 30,000 September
2016 – December 2017 $ 3.50 Floor purchase price (put) 100,000
January 2017 – December 2017 $ 2.80 Ceiling sold price (call)
100,000 January 2017 – December 2017 $ 3.17 Floor purchase price
(put) 20,000 January 2017 – December 2018 $ 2.90 Ceiling sold price
(call) 20,000 January 2017 – December 2018 $ 3.25 Floor purchase
price (put) 40,000 January 2018 – December 2018 $ 2.75 Ceiling sold
price (call) 40,000 January 2018 – December 2018 $ 3.28
Natural
Gas Three-way Collars: Floor purchase price (put) 40,000
September 2016 – December 2016 $ 2.90 Ceiling sold price (call)
40,000 September 2016 – December 2016 $ 3.24 Floor sold price (put)
40,000 September 2016 – December 2016 $ 2.35 Floor purchase price
(put) 30,000 January 2017 – December 2017 $ 2.75 Ceiling sold price
(call) 30,000 January 2017 – December 2017 $ 3.57 Floor sold price
(put) 30,000 January 2017 – December 2017 $ 2.25
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
Oil Derivatives
Description Volume
(Bbls/d)
Production Period Weighted
Average
Price ($/Bbl)
Oil Swaps: 850
September 2016 – December 2016
$ 45.55
Oil Three-way Collars: Floor purchase price (put)
1,000 September 2016 – December 2016 $ 60.00 Ceiling sold price
(call) 1,000 September 2016 – December 2016 $ 70.10 Floor sold
price (put) 1,000 September 2016 – December 2016 $ 45.00 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: 42,000 September 2016 – December 2016
$ 0.46 10,500 September 2016 $ 0.46
Subsequent to September 30, 2016, the Company entered into
the following derivative instruments:
Description Volume
(MMbtu/d)
Production Period Weighted
Average
Price ($/MMbtu)
Natural Gas Swaps: 10,000 March 2017 – December 2017
$ 3.21
Natural Gas Three-way Collars: 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 $ 2.13
Guidance
The Company issued the following fourth quarter and amended full
year 2016 guidance in the table below:
Q4 2016 FY 2016 Production
MMcfe/d 245 - 250 225 - 230 % Gas 70% - 75% 70% - 75% % NGL 15% -
17% 16% - 18% % Oil 10% - 12% 9% - 11% Gas Price Differential
($/Mcf)1 $(0.30) - $(0.35) $(0.35) - $(0.40) Oil Differential
($/Bbl)1 $(7.00) - $(9.00) $(8.00) - $(9.00) NGL Prices (% of WTI)1
35% - 40% 30% - 33% Cash Production Costs ($/Mcfe)2 $1.66 - $1.71
$1.51 - $1.56 Cash G&A ($mm)3 $6.0 - $7.0 $30 CAPEX ($mm) $196
1.
Excludes impact of hedges and cost of firm
transportation
2.
Includes lease operating, transportation,
gathering and compression, production and ad valorem taxes. FT
expense of $0.45-$0.50 per Mcfe for the fourth quarter and
$0.35-$0.40 per Mcfe for the full year is reflected in this
amount.
3.
Includes approximately $0.9 million of
severance costs in the FY 2016 guidance estimate
Conference Call
A conference call to review the Company’s financial and
operational results for the third quarter of 2016 is scheduled for
Friday, November 4, 2016 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 Third Quarter
2016 Earnings Call. A replay of the call will be available through
January 4, 2017. To access the phone replay dial 877-660-6853 or
201-612-7415 for international callers. The conference ID is
13647741. 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. Additionally, Eclipse
Resources has updated its investor presentation with third quarter
2016 financial and operational results. Please see the Investor
Center of the Company’s website at www.EclipseResources.com for the
presentation entitled “Company Presentation – November 2016”.
ECLIPSE RESOURCES
CORPORATIONCONDENSED CONSOLIDATED BALANCE SHEETS(In
thousands, except share and per share amounts)(Unaudited)
September 30,
2016
December 31,
2015
ASSETS CURRENT ASSETS Cash and cash equivalents $
177,669 $ 184,405 Accounts receivable 25,638 27,476 Assets held for
sale 184 21,971 Other current assets 5,289 35,532
Total current assets 208,780 269,384
PROPERTY AND
EQUIPMENT AT COST Oil and natural gas properties, successful
efforts method: Unproved properties 578,212 720,159 Proved oil and
gas properties, net 407,129 265,838 Other property and equipment,
net 6,933 7,971 Total property and equipment, net
992,274 993,968
OTHER NONCURRENT ASSETS Other assets
1,937 2,520 Deferred taxes — 540
TOTAL ASSETS
$ 1,202,991 $ 1,266,412
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable $ 38,741 $ 34,717 Accrued capital expenditures
20,324 10,956 Accrued liabilities 21,229 25,462 Accrued interest
payable 9,690 23,809 Liabilities held for sale —
18,898 Total current liabilities 89,984 113,842
NONCURRENT LIABILITIES Debt, net of unamortized discount and
debt issuance costs 491,593 527,248 Asset retirement obligations
4,599 3,401 Other liabilities 7,480 1,367 Total
liabilities 593,656 645,858
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 1,958,043 1,829,082 Treasury
stock, shares at cost; 72,704 at September 30, 2016 (61 ) —
Accumulated deficit (1,351,254 ) (1,210,755 ) Total
stockholders' equity 609,335 620,554
TOTAL
LIABILITIES AND STOCKHOLDERS' EQUITY $ 1,202,991
$ 1,266,412
ECLIPSE RESOURCES
CORPORATIONCONDENSED CONSOLIDATED STATEMENTS OF
OPERATIONS(In thousands, except per share data)(Unaudited)
For the Three Months
EndedSeptember 30,
For the Nine Months
EndedSeptember 30,
2016 2015 2016 2015
REVENUES Natural gas, oil and natural gas liquids sales $
54,351 $ 61,928 $ 140,740 $ 173,526 Brokered natural gas and
marketing revenue 128 9,244 10,411
15,913 Total revenues 54,479 71,172 151,151 189,439
OPERATING EXPENSES Lease operating 2,186 3,212 7,111 10,147
Transportation, gathering and compression 26,888 22,811 78,279
57,896 Production and ad valorem taxes 1,980 3,175 1,747 8,353
Brokered natural gas and marketing expense 42 9,262 11,604 20,057
Depreciation, depletion and amortization 28,225 67,172 64,287
170,245 Exploration 12,083 3,244 45,183 22,940 General and
administrative 8,036 13,710 29,712 38,370 Rig termination and
standby (112 ) 174 3,843 7,597 Impairment of proved oil and gas
properties — — 17,665 — Accretion of asset retirement obligations
100 412 275 1,197 (Gain) loss on sale of assets 102
290 (944 ) (5,183 ) Total operating expenses
79,530 123,462 258,762 331,619
OPERATING
LOSS (25,051 ) (52,290 )
(107,611 ) (142,180 ) OTHER INCOME
(EXPENSE) Gain (loss) on derivative instruments 10,639 23,679
(8,407 ) 31,527 Interest expense, net (12,393 ) (11,774 ) (38,293 )
(40,196 ) Gain (loss) on early extinguishment of debt — (59,392 )
14,489 (59,392 ) Other income (expense) 4 —
(137 ) 400 Total other expense, net (1,750 )
(47,487 ) (32,348 ) (67,661 )
LOSS BEFORE INCOME
TAXES (26,801 ) (99,777 )
(139,959 ) (209,841 ) INCOME TAX
BENEFIT (EXPENSE) — 18,309 (540 )
52,300
NET LOSS $ (26,801 ) $
(81,468 ) $ (140,499 ) $
(157,541 ) NET LOSS PER COMMON SHARE
Basic and diluted
$ (0.10 ) $
(0.37 ) $ (0.60 ) $
(0.73 ) WEIGHTED AVERAGE COMMON SHARES
OUTSTANDING Basic and diluted
258,812 222,537
234,933 216,332
Adjusted Revenue
Adjusted Revenue is a non-GAAP financial measure. The Company
defines Adjusted Revenue as follows: total revenues plus cash
settled derivatives 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
September 30,
2016 2015 Total revenues $ 54,479 $ 71,172
Net cash receipts (payments) on derivative
instruments
4,612 9,332 Brokered natural gas and marketing (128 )
(9,244 )
Adjusted revenue $ 58,963 $
71,260
Adjusted Net Loss
Adjusted net income or loss represents income or loss before
income taxes adjusted for certain non-cash items less income taxes.
We believe adjusted net income or 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 EndedSeptember
30,
Nine Months EndedSeptember
30,
2016 2015 2016 2015 Loss
before income taxes, as reported $ (26,801 ) $ (99,777 ) $ (139,959
) $ (209,841 ) (Gain) loss on derivative instruments (10,639 )
(23,679 ) 8,407 (31,527 ) Net cash receipts (payments) on
derivative instruments 4,612 9,332 35,870 23,754 Rig termination
and standby (112 ) 174 3,843 7,597 Impairment of proved oil and gas
properties - - 17,665 - Dry hole and other 325 8 872 38 Stock based
compensation 1,764 1,237 5,464 3,394 Impairment of unproved
properties 9,360 1,037 28,080 7,080 Other (income) expense (4 ) -
137 (400 ) Gain on early extinguishment of debt - 59,392 (14,489 )
59,392 Gain on sale of assets 102 290 (944 )
(5,183 ) Loss before income taxes, as adjusted (21,393 )
(51,986 ) (55,054 ) (145,696 ) Income tax benefit (expense)
- 18,309 (540 ) 52,300
Adjusted net
loss $ (21,393 ) $ (33,677
) $ (55,594 ) $ (93,396
) Adjusted net loss per Common Share $
(0.08 ) $ (0.15 ) $
(0.24 ) $ (0.43 )
Weighted Average Common Shares Outstanding 258,812
222,537 234,933 216,332
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 (loss) before interest
expense or interest income; income taxes; write-down of abandoned
leases; impairments; depreciation, depletion and amortization
(“DD&A”); amortization of deferred financing costs; 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. 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
September 30,
Nine Months Ended
September 30,
2016 2015 2016
2015 Net loss $ (26,801 ) $ (81,468 ) $ (140,499 ) $
(157,541 ) Depreciation, depletion and amortization 28,225 67,172
64,287 170,245 Exploration expense 12,083 3,244 45,183 22,940 Rig
termination and standby (112 ) 174 3,843 7,597 Impairment of proved
oil and gas properties — — 17,665 — Stock-based compensation 1,764
1,237 5,464 3,394 Accretion of asset retirement obligations 100 412
275 1,197 (Gain) loss on derivative instruments (10,639 ) (23,679 )
8,407 (31,527 ) Net cash receipts (payments) on settled derivatives
4,612 9,332 35,870 23,754 Interest expense, net 12,393 11,774
38,293 40,196 (Gain) loss on sale of assets 102 290 (944 ) (5,183 )
Gain on early extinguishment of debt — 59,392 (14,489 ) 59,392
Other (income) expense (4 ) - 137 (400 ) Income tax (benefit)
expense — (18,309 ) 540 (52,300 )
Adjusted EBITDAX $ 21,723 $
29,571 $ 64,032 $ 81,764
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 ThreeMonths
EndedSeptember 30,2016
For the ThreeMonths
EndingDecember 31,2016
For the
YearEndingDecember 31, 2016
General and administrative expenses, as reported $ 8,036 $7 - $8
million $36 - $37 million Stock-based compensation expense
(1,764 ) (1) - (2) million (6) - (7) million Cash general and
administrative expenses $ 6,272 $6 - $7 million $30 million
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.
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version on businesswire.com: http://www.businesswire.com/news/home/20161103006794/en/
Eclipse Resources CorporationDouglas Kris, Investor Relations,
814-325-2059dkris@eclipseresources.com
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