HOUSTON, Nov. 7, 2018 /PRNewswire/ -- EP Energy
Corporation (NYSE:EPE) today reported third quarter 2018 financial
and operational results.
3Q'18 Updates - Continuing to Execute Strategy with Focus on
Value Creation and De-levering the Business
- Drilled and completed most productive oil well in company
history in Northeastern Utah
(NEU), formerly Altamont
- Drilled most productive Eagle Ford oil well and second most
productive Permian oil well in company history
- Improved capital efficiency in all three assets
- Operating cash flows $163MM, investing cash flows ($205MM), and
financing cash flows of ($1MM)
- Free cash flow positive of $4MM (excluding hedges) for the
first quarter in company history
- Initiated third Eagle Ford enhanced oil recovery (EOR) pilot
project in October
- Drilled and completed two horizontal wells in NEU and currently
have 57 horizontal permits in process
- Equivalent production of 80.4 MBoe/d
- Oil production of 46.4 MBbls/d
- Net loss of $44MM
- Adjusted EBITDAX of $214MM
- Oil and gas expenditures of $201MM including $46MM acquisition
capital
- Adjusted oil and gas expenditures of $133MM
- Completed (based on wells fracture stimulated or frac'd) 31
gross wells
- G&A expense of $2.91 per Boe,
Adjusted G&A expense of $2.05 per
Boe
- Reaffirmed the RBL Facility borrowing base in November and
ended the quarter with $666MM of liquidity- $56MM of cash and 100%
undrawn RBL Facility capacity
- Net debt to annualized adjusted EBITDAX improved one full turn
from 3Q'17 to 3Q'18
3Q'18 Demonstrating Capital Discipline and Improvement in
Leverage Metrics
The third quarter of 2018 was the first quarter in the company's
history to be free cash flow positive excluding hedging
settlements. This was driven by a combination of improved capital
efficiency, reduced costs, and higher oil prices.
3Q'18 Operating and Financial Performance Demonstrate Strong
Execution
Below is a summary of third quarter 2018 results compared to the
third quarter 2017:
|
3Q'17
|
3Q'18
|
3Q'18
vs.
3Q'17
|
Oil Production
(MBbls/d)
|
45.1
|
46.4
|
+ 3%
|
Equivalent Production
(MBoe/d)
|
81.0
|
80.4
|
- 1%
|
Percent Oil
(%)
|
55.7
|
57.7
|
+ 4%
|
Produced Volumes
(MBoe/d)1
|
81.0
|
81.7
|
+ 1%
|
LOE per Unit
($/Boe)
|
5.66
|
6.16
|
+ 9%
|
Adjusted LOE per Unit
($/Boe)2,3
|
5.66
|
5.88
|
+ 4%
|
Lease Operating
Expense ($MM)
|
42.2
|
45.6
|
+ 8%
|
Adjusted Lease
Operating Expense ($MM)2,3
|
42.2
|
43.5
|
+ 3%
|
Adjusted G&A
expense per Unit ($/Boe)2
|
2.63
|
2.05
|
- 22%
|
Net (Loss)
($MM)
|
(72)
|
(44)
|
+ 39%
|
Adjusted EBITDAX
($MM)2
|
159
|
214
|
+ 35%
|
Oil and Gas
Expenditures ($MM)
|
162
|
201
|
+ 24%
|
Adjusted Oil and Gas
Expenditures (excl. Acquisitions and Other )
($MM)2
|
133
|
133
|
0%
|
|
|
1
|
Produced volumes
include 8 MMcf/d of reinjected gas volumes used in operations
during the 3Q'18.
|
2
|
See Disclosure of
Non-GAAP Financial Measures for applicable definitions and
reconciliations to GAAP terms.
|
3
|
Does not include
approximately $2 million or $0.28 per Boe for the quarter ended
September 30, 2018 of adjustments under a joint venture
agreement.
|
Unlocking Value in Utah -
First Horizontal Well Delivers Most Productive Well in Company
History
The company has renamed its position in the Uinta Basin to
Northeastern Utah or NEU. In
the third quarter of 2018, the company produced 17.5 MBoe/d,
including 12.0 MBbls/d of oil, a four percent decrease from the
third quarter of 2017, respectively. EP Energy operated two
joint venture drilling rigs and completed (frac'd) six gross wells
and two net wells in the third quarter of 2018. Total capital
invested in NEU in the third quarter of 2018 was $35 million excluding acquisitions.
In the third quarter of 2018, the company completed its first
two horizontal wells in NEU. The Duchesne City 1-25-26-C5-2H well was drilled
to a lateral length of approximately 9,800 feet and has produced
110,000 barrels of oil after 78 days, making it the most productive
oil well completed in the company's history. The second well,
Duchesne City 1-25-26-C5-1H, was
drilled to a lateral length of 7,900 feet and has produced 60,000
barrels of oil after 78 days and is in the top 6% of oil producing
wells for the company.
In the fourth quarter of 2018, the company plans to take core
samples to assess the potential of horizontal development over the
company's entire 159,000 net acres across multiple benches.
Additionally, the company has 57 horizontal permits in process and
will focus on NEU horizontal wells in 2019 due to their strong
productivity.
Eagle Ford: Significant Oil Growth and Progress on Capital
Efficiency Initiatives
The company produced 35.8 MBoe/d, including 25.6 MBbls/d of oil
in the third quarter of 2018, a nine percent and 28% increase from
the third quarter of 2017, respectively. EP Energy averaged
approximately three drilling rigs, invested $92 million excluding acquisition capital and
completed (frac'd) 22 gross and 10 net wells in the third quarter
of 2018.
EP Energy continued to increase the scale of EOR operations in
the third quarter and into the fourth quarter of 2018. In our first
EOR pilot, we completed two injection cycles and expect to complete
2-3 more cycles across the three pilot areas by year-end. In
August, the company operationalized its second pilot in the north
end of its La Salle acreage. In
October, the third EOR pilot became operational in the retrograde
condensate window in the southern end of its acreage
position. In total, the company recycled approximately 8
MMcfe/d of gas in the third quarter of 2018. The goal for the EOR
projects is to significantly increase recoverable reserves and
lower finding and development (F&D) costs.
Wells drilled in 2018 with new completion designs have exceeded
pre-2018 offset wells by eight percent on net revenue per
investment (RPI) as of 160 days. This group of wells are expected
to outperform their offsets by 20% based on RPI. In addition, the
company completed its two longest Eagle Ford laterals in company
history. Both wells are currently in flow back, and we expect to
provide a performance update in 4Q'18. The company continues to
modify completion designs, lateral lengths and spacing for each pad
to maximize returns and minimize F&D costs.
In the fourth quarter of 2018, the company plans to run three
rigs and complete 21 wells focused on development in the southern
and eastern portion of the La
Salle acreage.
Permian: Optimizations Lead to Second Most Productive Well
Since Program Inception
In the third quarter of 2018, the company produced 27.1 MBoe/d,
including 8.8 MBbls/d of oil, a nine percent and 30% decrease from
the third quarter of 2017, respectively. In the third quarter of
2018, the company invested $7 million
(excluding drilling JV adjustments) and completed (frac'd) three
gross and two net wells.
In 2018, the company applied a new completion design that
resulted in the second most productive oil well in program history.
Two additional wells with the enhanced design, which came online in
September, are currently performing in-line with the
improvement.
The company maintains ample take-away capacity out of the basin
through contractual agreements with third-party processors and
marketing companies. In addition, the company has 100% of its
Midland to Cushing basis exposure hedged in 2018 at
-$1.02 per barrel and approximately
one-third of its Midland to
Cushing basis exposure hedged in
2019 at -$6.47 per barrel.
Multi-year Commodity Hedge Program: Well Positioned in 2018
and ~60 Percent Hedged in 20191
EP Energy maintains a solid hedge program, which provides
continued commodity price protection. A summary of the
company's current open hedge positions is listed below:
|
|
2018
|
|
2019
|
Total Fixed Price
Hedges
|
|
|
|
|
Oil volumes
(MMBbls)2
|
|
3.8
|
|
|
9.7
|
|
Average ceiling price
($/Bbl)
|
|
$
|
63.96
|
|
|
$
|
67.82
|
|
Average floor price
($/Bbl)
|
|
$
|
58.45
|
|
|
$
|
58.09
|
|
|
|
|
|
|
Natural Gas volumes
(TBtu)
|
|
7.0
|
|
|
7.0
|
|
Average price
($/MMBtu)
|
|
$
|
3.04
|
|
|
$
|
2.97
|
|
|
Note: Positions are as of October 22, 2018
(Contract months: September 1, 2018 - Forward)
|
|
1
|
Percentage based
on mid-point of 2018 production guidance
|
2
|
2018 and 2019
positions include WTI three way collars of 2.2 MMBbls and 7.3
MMBbls, respectively, and WTI collars of 0.3 MMBbls in 2018 and 1.6
MMBbls in 2019.
|
Liquidity - Financial Flexibility Continues to Improve with
Successful Redetermination of RBL Facility
The company ended the quarter with $56
million in cash and zero borrowings on the RBL Facility,
resulting in $666 million of
available liquidity and $4.3 billion
of net debt (total debt of $4.4
billion less cash of $56
million). In November 2018,
the banks reaffirmed the current borrowing base of $1.4 billion and commitments of $629 million.
2018 Outlook Maintained
The table below summarizes the company's current operational and
financial guidance for the full year 2018.
|
|
3Q'18 YTD
Actuals
|
|
FY
2018
Estimate
|
|
|
|
|
|
|
|
|
|
|
Production
Volumes
|
|
|
|
|
Oil production
(MBbls/d)
|
|
46.4
|
|
45 – 47
|
Total production
(MBoe/d)
|
|
81.0
|
|
79 – 82
|
|
|
|
|
|
Oil & Gas
Expenditures ($ million)
|
|
$545
|
|
$630 –
$6701
|
Eagle Ford
|
|
$349
|
|
~65%
|
Permian
|
|
$98
|
|
~15%
|
NEU
|
|
$98
|
|
~20%2
|
|
|
|
|
|
Average Gross
Drilling Rigs
|
|
|
|
|
Eagle Ford
|
|
2.8
|
|
3
|
Permian
|
|
0.4
|
|
-
|
NEU
|
|
2.0
|
|
2
|
|
|
|
|
|
Operating
Costs
|
|
|
|
|
Lease operating
expense ($/Boe)
|
|
$5.53
|
|
$5.00 –
$5.70
|
Reported G&A
expense ($/Boe)
|
|
$3.09
|
|
$2.90 –
$3.25
|
Adjusted G&A
expense ($/Boe)3,5
|
|
$2.33
|
|
$2.30 –
$2.60
|
Transportation
($/Boe)
|
|
$3.44
|
|
$3.15 –
$3.45
|
Taxes, other than
income ($/Boe)4
|
|
$2.86
|
|
$2.75 –
$2.85
|
DD&A
($/Boe)
|
|
$17.00
|
|
$17.00 –
$17.50
|
|
|
1
|
Full year 2018
includes ~$120 million non-drill capital including: ~$55 million
for general equipment, ~$20 million for capitalized G&A and
interest, ~$20 million for enhanced facility projects, ~$15 million
for EOR projects, and ~$10 million for leasing and seismic, and
does not include acquisition costs or $22 million drilling joint
venture adjustment
|
2
|
Full year 2018 NEU
capital includes ~81 recompletions for $47 million.
|
3
|
Adjusted G&A
represents G&A expense less approximately $0.44 per Boe of
non-cash compensation expense and $0.32 per Boe in transition,
severance and other costs in YTD 3Q'18 reported G&A and $0.60 -
$0.65 per Boe of non-cash compensation expense in FY 2018
Estimate.
|
4
|
Severance taxes
estimates are based on current WTI prices.
|
5
|
See Disclosure of
Non-GAAP Financial Measures for applicable definitions and
reconciliations to GAAP terms.
|
Webcast Information
EP Energy has scheduled a webcast at 10:00 a.m. Eastern Time, 9:00 a.m. Central
Time, on November 8, 2018, to discuss
its third quarter financial and operational results. The
webcast may be accessed online through the company's website at
epenergy.com in the Investor Center. Materials relating to
the webcast will be available in the Investor Center. A
limited number of telephone lines will be available to participants
by dialing 888-317-6003 (conference ID#8791565) 10 minutes prior to
the start of the webcast. A replay of the webcast will be
available through December 15, 2018
on the company's website in the Investor Center or by dialing
877-344-7529 (conference ID#10124370).
About EP Energy
The EP Energy team is driven to deliver superior returns for our
investors by developing the oil and natural gas that feeds
America's growing energy needs. The company focuses on enhancing
the value of its high quality asset portfolio, increasing capital
efficiency, maintaining financial flexibility, and pursuing
accretive acquisitions and divestitures. EP Energy is working to
set the standard for efficient development of hydrocarbons in the
U.S. Learn more at epenergy.com.
The following table provides the company's production results,
average realized prices, results of operations and certain non-GAAP
financial measures for the periods presented. See Disclosure
of Non-GAAP Financial Measures for applicable definitions and
reconciliations to GAAP terms.
|
Quarter ended
September 30,
|
|
2018
|
|
2017
|
Oil Sales Volumes
(MBbls/d)
|
|
|
|
Eagle Ford
|
25.6
|
|
|
20.0
|
|
Permian
|
8.8
|
|
|
12.6
|
|
NEU
|
12.0
|
|
|
12.5
|
|
Total Oil Sales
Volumes
|
46.4
|
|
|
45.1
|
|
Natural Gas Sales
Volumes (MMcf/d)
|
|
|
|
Eagle Ford
|
30
|
|
|
37
|
|
Permian
|
58
|
|
|
55
|
|
NEU
|
33
|
|
|
34
|
|
Total Natural Gas
Sales Volumes
|
121
|
|
|
126
|
|
NGLs Sales Volumes
(MBbls/d)
|
|
|
|
Eagle Ford
|
5.2
|
|
|
6.7
|
|
Permian
|
8.7
|
|
|
8.2
|
|
NEU
|
—
|
|
|
—
|
|
Total NGLs Sales
Volumes
|
13.9
|
|
|
14.9
|
|
Equivalent Sales
Volumes (MBoe/d)
|
|
|
|
Eagle Ford
|
35.8
|
|
|
32.9
|
|
Permian
|
27.1
|
|
|
29.9
|
|
NEU
|
17.5
|
|
|
18.2
|
|
Total Equivalent Sales
Volumes
|
80.4
|
|
|
81.0
|
|
|
|
|
|
Net loss ($ in
millions)
|
(44)
|
|
|
(72)
|
|
Adjusted EBITDAX ($
in millions)
|
214
|
|
|
159
|
|
Basic and diluted net
loss per common share ($)
|
(0.18)
|
|
|
(0.29)
|
|
Adjusted EPS
($)
|
(0.04)
|
|
|
(0.12)
|
|
Capital Expenditures
($ in millions)(1)
|
201
|
|
|
162
|
|
Adjusted Capital
Expenditures ($ in millions)
|
133
|
|
|
133
|
|
Total Operating
Expenses ($/Boe)
|
33.13
|
|
|
31.79
|
|
Adjusted Cash
Operating Costs ($/Boe)
|
15.20
|
|
|
14.73
|
|
Depreciation,
depletion and amortization rate ($/Boe)
|
17.11
|
|
|
15.92
|
|
Average realized
prices(2)
|
|
|
|
Oil price on physical
sales ($/Bbl)
|
66.61
|
|
|
45.49
|
|
Oil, including
financial derivatives ($/Bbl)(3)
|
63.37
|
|
|
51.75
|
|
Natural gas price on
physical sales ($/Mcf)
|
1.34
|
|
|
2.26
|
|
Natural gas, including
financial derivatives ($/Mcf)(3)
|
1.69
|
|
|
2.49
|
|
NGLs price on physical
sales ($/Bbl)
|
27.74
|
|
|
18.98
|
|
NGLs, including
financial derivatives ($Bbl)(3)
|
24.79
|
|
|
18.45
|
|
|
|
|
|
|
|
|
|
(1)
|
The quarter ended
September 30, 2018 includes $46 million and $22 million,
respectively, of acquisition capital and capital adjustments under
a joint venture agreement. The quarter ended September 30, 2017
includes $29 million of acquisition capital.
|
(2)
|
Oil and natural gas
prices on physical sales reflect operating revenues for oil and
natural gas reduced by oil and natural gas purchases
associated with managing our physical sales.
|
(3)
|
Prices per unit are
calculated using total financial derivative cash
settlements.
|
EP ENERGY
CORPORATION
CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
(In
millions)
(Unaudited)
|
|
|
Quarter ended
September 30,
|
|
2018
|
|
2017
|
Operating
revenues
|
|
|
|
Oil
|
$
|
287
|
|
|
$
|
189
|
|
Natural
gas
|
15
|
|
|
27
|
|
NGLs
|
36
|
|
|
26
|
|
Financial
derivatives
|
(44)
|
|
|
(23)
|
|
Total operating
revenues
|
294
|
|
|
219
|
|
|
|
|
|
Operating
expenses
|
|
|
|
Oil and natural gas
purchases
|
3
|
|
|
—
|
|
Transportation
costs
|
25
|
|
|
29
|
|
Lease operating
expense
|
46
|
|
|
42
|
|
General and
administrative
|
21
|
|
|
25
|
|
Depreciation,
depletion and amortization
|
127
|
|
|
118
|
|
Gain on sale of
assets
|
(1)
|
|
|
—
|
|
Impairment
charges
|
—
|
|
|
1
|
|
Exploration and other
expense
|
2
|
|
|
6
|
|
Taxes, other than
income taxes
|
22
|
|
|
16
|
|
Total operating
expenses
|
245
|
|
|
237
|
|
|
|
|
|
Operating income
(loss)
|
49
|
|
|
(18)
|
|
|
|
|
|
Other
income
|
2
|
|
|
—
|
|
Gain on
extinguishment/modification of debt
|
—
|
|
|
24
|
|
Interest
expense
|
(95)
|
|
|
(80)
|
|
Loss before income
taxes
|
(44)
|
|
|
(74)
|
|
Income tax
benefit
|
—
|
|
|
2
|
|
Net loss
|
$
|
(44)
|
|
|
$
|
(72)
|
|
EP ENERGY
CORPORATION
CONDENSED
CONSOLIDATED BALANCE SHEETS
(In
millions)
(Unaudited)
|
|
|
September 30,
2018
|
|
|
December 31,
2017
|
ASSETS
|
|
|
|
|
Current
assets(1)
|
$
|
315
|
|
|
|
$
|
466
|
|
Property, plant and
equipment, net(2)
|
|
4,913
|
|
|
|
|
4,422
|
|
Other non-current
assets
|
|
11
|
|
|
|
|
12
|
|
Total
assets
|
$
|
5,239
|
|
|
|
$
|
4,900
|
|
|
|
|
|
|
LIABILITIES AND EQUITY
|
|
|
|
|
Current
liabilities
|
$
|
563
|
|
|
|
$
|
448
|
|
Long-term debt, net
of debt issue costs
|
4,295
|
|
|
|
4,022
|
|
Other non-current
liabilities
|
64
|
|
|
|
38
|
|
Total stockholders'
equity
|
317
|
|
|
|
392
|
|
Total liabilities and
equity
|
$
|
5,239
|
|
|
|
$
|
4,900
|
|
|
|
|
|
|
|
|
|
(1)
|
Balance as of
December 31, 2017 includes $172 million of assets held for
sale.
|
(2)
|
Balance is net of
accumulated depreciation, depletion and amortization of $3,554
million and $3,179 million as of September 30, 2018 and
December 31, 2017, respectively.
|
EP ENERGY
CORPORATION
CONDENSED
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In
millions)
(Unaudited)
|
|
|
Nine months
ended September 30,
|
|
2018
|
|
2017
|
Net loss
|
$
|
(84)
|
|
|
$
|
(122)
|
|
Adjustments to
reconcile net loss to net cash provided by operating
activities
|
|
|
|
Non-cash
expenses
|
349
|
|
|
410
|
|
Asset and liability
changes
|
115
|
|
|
10
|
|
Net cash provided by
operating activities
|
380
|
|
|
298
|
|
Net cash used in
investing activities
|
(659)
|
|
|
(434)
|
|
Net cash provided by
financing activities
|
290
|
|
|
137
|
|
|
|
|
|
|
|
Change in cash, cash
equivalents and restricted cash
|
11
|
|
|
1
|
|
|
|
|
|
Cash, cash
equivalents and restricted cash - beginning of period
|
45
|
|
|
20
|
|
Cash, cash
equivalents and restricted cash - end of period
|
$
|
56
|
|
|
$
|
21
|
|
Disclosure of Non-GAAP Financial Measures
The Securities and Exchange Commission's Regulation G applies to
any public disclosure or release of material information that
includes a non-GAAP financial measure. In the event of such a
disclosure or release, Regulation G requires (i) the
presentation of the most directly comparable financial measure
calculated and presented in accordance with GAAP and (ii) a
reconciliation of the differences between the non-GAAP financial
measure presented and the most directly comparable financial
measure calculated and presented in accordance with GAAP.
Non-GAAP Terms
Adjusted EPS is defined as diluted earnings per share adjusted
for certain items that EP Energy considers to be significant to
understanding our underlying performance for a given period.
Adjusted EPS is useful in analyzing the company's ongoing earnings
potential and understanding certain significant items impacting the
comparability of EP Energy's results. Adjusted EPS is
calculated as net income (loss) per common share adjusted for the
impact of financial derivatives (mark-to-market effects of
financial derivatives, net of cash settlements and cash premiums
related to these derivatives), gains and losses on
extinguishment/modification of debt, impairment charges, other
costs that affect comparability, including transition, severance
and other costs and changes in the valuation allowance on deferred
tax assets.
Below is a reconciliation of consolidated diluted net income
(loss) per share to Adjusted EPS:
|
Quarter ended
September 30, 2018
|
|
Pre
Tax
|
|
After
Tax
|
|
Diluted
EPS(1)
|
|
($ in millions,
except earnings per share amounts)
|
Net loss
|
|
|
$
|
(44)
|
|
|
$
|
(0.18)
|
|
|
|
|
|
|
|
Adjustments(2)
|
|
|
|
|
|
Impact of financial
derivatives(3)
|
$
|
30
|
|
|
$
|
23
|
|
|
$
|
0.09
|
|
Transition, severance
and other costs
|
1
|
|
|
1
|
|
|
0.01
|
|
Valuation allowance
on deferred tax assets
|
|
|
10
|
|
|
0.04
|
|
Total
adjustments
|
$
|
31
|
|
|
$
|
34
|
|
|
$
|
0.14
|
|
|
|
|
|
|
|
Adjusted
EPS
|
|
|
|
|
$
|
(0.04)
|
|
|
|
|
|
|
|
Diluted weighted
average shares
|
|
|
|
|
248
|
|
|
|
|
Quarter ended
September 30, 2017
|
|
Pre
Tax
|
|
After
Tax
|
|
Diluted
EPS(1)
|
|
($ in millions,
except earnings per share amounts)
|
Net loss
|
|
|
$
|
(72)
|
|
|
$
|
(0.29)
|
|
|
|
|
|
|
|
Adjustments(2)
|
|
|
|
|
|
Impact of financial
derivatives(3)
|
$
|
50
|
|
|
$
|
32
|
|
|
$
|
0.13
|
|
Gain on
extinguishment of debt
|
(24)
|
|
|
(15)
|
|
|
(0.06)
|
|
Impairment
charges
|
1
|
|
|
—
|
|
|
—
|
|
Valuation allowance
on deferred tax assets
|
|
|
24
|
|
|
0.10
|
|
Total
adjustments
|
$
|
27
|
|
|
$
|
41
|
|
|
$
|
0.17
|
|
|
|
|
|
|
|
Adjusted
EPS
|
|
|
|
|
$
|
(0.12)
|
|
|
|
|
|
|
|
Diluted weighted
average shares
|
|
|
|
|
246
|
|
|
|
|
|
|
|
|
|
(1)
|
Diluted per share
amounts are based on actual amounts rather than the rounded totals
presented.
|
(2)
|
All individual
adjustments for all periods presented assume a statutory federal
and blended state tax rate, as well as any other income tax effects
specifically attributable to that item.
|
(3)
|
Represents
mark-to-market impact net of cash settlements and cash premiums
related to financial derivatives. There were no cash premiums
received or paid for the periods presented.
|
Free Cash Flow is defined as Adjusted EBITDAX less hedge
settlements, adjusted oil and gas expenditures, and cash interest
calculated on an annualized basis. Below is a reconciliation of our
net cash provided by operating activities to Free Cash Flow:
|
|
Quarter
ended September 30,
2018
|
|
|
($ in
millions)
|
Net cash provided by
operating activities(1)
|
|
$
|
163
|
Interest expense,
net
|
|
95
|
Working capital and
other
|
|
(44)
|
Adjusted
EBITDAX
|
|
$
|
214
|
Less: Hedge
settlements
|
|
14
|
Less: Adjusted
oil and gas expenditures(2)
|
|
(133)
|
Less: One
quarter of annualized cash interest
|
|
(91)
|
Free Cash
Flow
|
|
$
|
4
|
|
|
|
Net cash used in
investing activities(1)
|
|
$
|
(205)
|
Net cash used in
financing activities(1)
|
|
$
|
(1)
|
|
|
|
|
|
|
|
|
(1)
|
Calculated as the
difference between YTD September 30, 2018 and YTD June 30, 2018
GAAP Statement of Cash Flow amounts.
|
(2)
|
Adjusted oil and gas
expenditures excludes $46 million of acquisition capital and $22
million of capital adjustments under a joint venture
agreement.
|
EBITDAX is defined as net income (loss) plus interest and debt
expense, income taxes, depreciation, depletion and amortization and
exploration expense. Adjusted EBITDAX is defined as EBITDAX,
adjusted as applicable in the relevant period for the net change in
the fair value of derivatives (mark-to-market effects of financial
derivatives, net of cash settlements and cash premiums related to
these derivatives), the non-cash portion of compensation expense
(which represents non-cash compensation expense under our long-term
incentive programs adjusted for cash payments made under these
plans), transition, severance and other costs that affect
comparability, gains and losses on extinguishment/modification of
debt, gains and/or losses on sale of assets and impairment
charges.
Below is a reconciliation of our consolidated net income (loss)
to EBITDAX and Adjusted EBITDAX:
|
|
Quarter ended
September 30,
|
|
|
2018
|
|
2017
|
|
|
($ in millions)
|
Net loss
|
|
$
|
(44)
|
|
|
$
|
(72)
|
|
Income tax
benefit
|
|
—
|
|
|
(2)
|
|
Interest expense, net
of capitalized interest
|
|
95
|
|
|
80
|
|
Depreciation,
depletion and amortization
|
|
127
|
|
|
118
|
|
Exploration
expense
|
|
1
|
|
|
3
|
|
EBITDAX
|
|
179
|
|
|
127
|
|
Mark-to-market on
financial derivatives(1)
|
|
44
|
|
|
23
|
|
Cash settlements and
cash premiums on financial derivatives(2)
|
|
(14)
|
|
|
27
|
|
Non-cash portion of
compensation expense(3)
|
|
5
|
|
|
5
|
|
Transition, severance
and other costs(4)
|
|
1
|
|
|
—
|
|
Gain on sale of
assets
|
|
(1)
|
|
|
—
|
|
Gain on
extinguishment/modification of debt
|
|
—
|
|
|
(24)
|
|
Impairment
charges
|
|
—
|
|
|
1
|
|
Adjusted
EBITDAX
|
|
$
|
214
|
|
|
$
|
159
|
|
|
|
|
|
|
|
|
|
(1)
|
Represents the income
statement impact of financial derivatives.
|
(2)
|
Represents actual
cash settlements related to financial derivatives. There were no
cash premiums received or paid for the periods
presented.
|
(3)
|
Non-cash portion of
compensation expense represents compensation expense (net of
forfeitures) under long-term incentive programs adjusted for cash
payments made under these plans.
|
(4)
|
Reflects transition
and severance costs related to workforce reductions.
|
Adjusted cash operating costs is a non-GAAP measure that is
defined as total operating expenses, excluding depreciation,
depletion and amortization expense, exploration expense, impairment
charges, gains/losses on sale of assets, the non-cash portion of
compensation expense (which represents compensation expense under
our long-term incentive programs adjusted for cash payments made
under these plans) and transition, severance and other costs that
affect comparability. We use this measure to describe the
costs required to directly or indirectly operate our existing
assets and produce and sell our oil and natural gas, including the
costs associated with the delivery and purchases and sales of
produced commodities. Accordingly, we exclude depreciation,
depletion, and amortization and impairment charges as such costs
are non-cash in nature. We exclude exploration expense from our
measure as it is substantially non-cash in nature and is not
related to the costs to operate our existing assets. Similarly,
gains and losses on the sale of assets are excluded as they are
unrelated to our existing assets. We exclude the non-cash portion
of compensation expense as well as transition, severance and other
costs that affect comparability, as we believe such adjustments
allow investors to evaluate our costs against others in our
industry and this item can vary across companies due to different
ownership structures, compensation objectives or the occurrence of
transactions.
Below is a reconciliation of our GAAP operating expenses to
non-GAAP adjusted cash operating costs:
|
|
Quarter ended
September 30,
|
|
|
2018
|
|
2017
|
|
|
Total
|
|
Per-Unit(1)
|
|
Total
|
|
Per-Unit(1)
|
|
|
($ in millions,
except per unit costs)
|
Oil and natural gas
purchases
|
|
$
|
3
|
|
|
$
|
0.36
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Transportation
costs
|
|
25
|
|
|
3.41
|
|
|
29
|
|
|
3.91
|
|
Lease operating
expense
|
|
46
|
|
|
6.16
|
|
|
42
|
|
|
5.66
|
|
General and
administrative
|
|
21
|
|
|
2.91
|
|
|
25
|
|
|
3.28
|
|
Depreciation,
depletion and amortization
|
|
127
|
|
|
17.11
|
|
|
118
|
|
|
15.92
|
|
Impairment
charges
|
|
—
|
|
|
—
|
|
|
1
|
|
|
0.09
|
|
Gain on sale of
assets
|
|
(1)
|
|
|
(0.13)
|
|
|
—
|
|
|
—
|
|
Exploration and other
expense
|
|
2
|
|
|
0.29
|
|
|
6
|
|
|
0.83
|
|
Taxes, other
than income taxes
|
|
22
|
|
|
3.02
|
|
|
16
|
|
|
2.10
|
|
Total operating
expenses
|
|
$
|
245
|
|
|
$
|
33.13
|
|
|
$
|
237
|
|
|
$
|
31.79
|
|
Adjustments:
|
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
$
|
(127)
|
|
|
$
|
(17.11)
|
|
|
$
|
(118)
|
|
|
$
|
(15.92)
|
|
Impairment
charges
|
|
—
|
|
|
—
|
|
|
(1)
|
|
|
(0.09)
|
|
Exploration
expense
|
|
(1)
|
|
|
(0.09)
|
|
|
(3)
|
|
|
(0.40)
|
|
Gain on sale of
assets
|
|
1
|
|
|
0.13
|
|
|
—
|
|
|
—
|
|
Non-cash portion of
compensation expense(2)
|
|
(5)
|
|
|
(0.70)
|
|
|
(5)
|
|
|
(0.65)
|
|
Transition, severance
and other costs(2)
|
|
(1)
|
|
|
(0.16)
|
|
|
—
|
|
|
—
|
|
Adjusted cash
operating costs and per-unit adjusted cash costs
|
|
$
|
112
|
|
|
$
|
15.20
|
|
|
$
|
110
|
|
|
$
|
14.73
|
|
|
|
|
|
|
|
|
|
|
Total consolidated
equivalent volumes (MBoe)
|
|
|
|
7,401
|
|
|
|
|
7,456
|
|
|
|
|
|
|
|
|
|
(1)
|
Per unit costs are
based on actual total amounts rather than the rounded totals
presented.
|
(2)
|
Amounts are excluded
in the calculation of adjusted general and administrative
expense.
|
Adjusted general and administrative expenses are defined as
general and administrative expenses excluding the non-cash portion
of compensation expense which represents compensation expense (net
of forfeitures) under our long-term incentive programs adjusted for
cash payments under these plans and transition, severance and other
costs. Adjusted cash general and administrative expense are defined
as Adjusted general and administrative expenses including
capitalized labor.
Below is a reconciliation of our GAAP general and administrative
expense to non-GAAP adjusted general and administrative expense and
non-GAAP adjusted cash general and administrative expense:
|
Actuals
|
|
FY 2018
Estimate
|
|
|
Quarter ended
September 30,
|
|
|
2018
|
|
2017
|
|
Low
|
|
High
|
|
Total
|
|
($/Boe)
|
|
Total
|
|
($/Boe)
|
|
($/Boe)
|
|
($/Boe)
|
|
($ in millions,
except per Boe costs)
|
GAAP general and
administrative expense
|
$
|
21
|
|
|
$
|
2.91
|
|
|
$
|
25
|
|
|
$
|
3.28
|
|
|
$
|
2.90
|
|
|
$
|
3.25
|
|
Less non-cash
compensation expense
|
5
|
|
|
0.70
|
|
|
5
|
|
|
0.65
|
|
|
0.60
|
|
|
0.65
|
|
Less transition,
severance and other costs
|
1
|
|
|
0.16
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Adjusted general and
administrative expense
|
$
|
15
|
|
|
$
|
2.05
|
|
|
$
|
20
|
|
|
$
|
2.63
|
|
|
$
|
2.30
|
|
|
$
|
2.60
|
|
Capitalized
labor
|
4
|
|
|
0.47
|
|
|
6
|
|
|
0.79
|
|
|
|
|
|
Adjusted cash general
and administrative expense
|
$
|
19
|
|
|
$
|
2.52
|
|
|
$
|
26
|
|
|
$
|
3.42
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Per unit costs are
based on actual total amounts rather than the rounded totals
presented.
|
Net Debt is a non-GAAP measure defined as long-term debt less
cash and cash equivalents.
EBITDAX and Adjusted EBITDAX are used by management and we
believe provide investors with additional information (i) to
evaluate our ability to service debt adjusting for items required
or permitted in calculating covenant compliance under our debt
agreements, (ii) to provide an important supplemental
indicator of the operational performance of our business without
regard to financing methods and capital structure, (iii) for
evaluating our performance relative to our peers, (iv) to
measure our liquidity (before cash capital requirements and working
capital needs) and (v) to provide supplemental information
about certain material non-cash and/or other items that may not
continue at the same level in the future. Free Cash Flow is used by
management and we believe provides investors with useful
information for analysis of the company's ability to internally
fund capital expenditure and to service or incur additional debt.
Adjusted Cash Operating Costs ($ and per unit) and Adjusted Lease
Operating Expense ($ and per unit) are used by management as a
performance measure, and we believe provides investors valuable
information related to our operating performance and our operating
efficiency relative to other industry participants and
comparatively over time across our historical results.
Adjusted General and Administrative expense, Adjusted Cash General
and Administrative expense and related per unit measures as well as
Adjusted Oil and Gas Expenditures are used by management and
investors as additional information as noted above. Net Debt is
used by management for analysis of the company's financial position
and/or liquidity. In addition, the company believes that these
measures are widely used by professional research analysts and
others in the valuation, comparison and investment recommendations
of companies in the oil and gas exploration and production
industry.
Adjusted EPS, EBITDAX, Adjusted EBITDAX, Adjusted Cash Operating
Costs, Adjusted Oil and Gas Expenditures, Adjusted Lease Operating
Expense, Free Cash Flow, Adjusted General and Administrative
expense, Adjusted Cash General and Administrative expense and Net
Debt have limitations as analytical tools and should not be
considered in isolation or as a substitute for analysis of our
results as reported under U.S. GAAP. Adjusted EPS should not
be used as an alternative to earnings (loss) per share or other
measure of financial performance presented in accordance with GAAP.
EBITDAX and Adjusted EBITDAX should not be used as an alternative
to net income (loss), operating income (loss), operating cash flows
or other measures of financial performance or liquidity presented
in accordance with GAAP. Adjusted Cash Operating Costs and Adjusted
Lease Operating Expense should not be used as an alternative to
operating expenses, operating cash flows or other measures of
financial performance or liquidity presented in accordance with
GAAP. Adjusted General and Administrative expense and Adjusted Cash
General and Administrative expense should not be used as an
alternative to GAAP general and administrative expense. Free Cash
Flow and Adjusted Oil and Gas Expenditures should not be used as an
alternative to operating, investing and/or financing cash flows,
oil and gas capital expenditures or other measures of liquidity
presented in accordance with GAAP. Our presentation of Adjusted
EPS, EBITDAX, Adjusted EBITDAX, Adjusted Cash Operating Costs,
Adjusted Lease Operating Expense, Adjusted Oil and Gas
Expenditures, Adjusted General and Administrative expense, Adjusted
Cash General and Administrative expense, Free Cash Flow and Net
Debt may not be comparable to similarly titled measures used by
other companies in our industry. Furthermore, our presentation of
Adjusted EPS, EBITDAX, Adjusted EBITDAX, Adjusted Cash Operating
Costs, Adjusted Lease Operating Expense, Adjusted Oil and Gas
Expenditures, Adjusted General and Administrative expense, Adjusted
Cash General and Administrative expense, Free Cash Flow and Net
Debt should not be construed as an inference that our future
results will be unaffected by the items noted above or what we
believe to be other unusual items, or that in the future we may not
incur expenses that are the same as or similar to some of the
adjustments in this presentation.
Cautionary Statement Regarding Forward-Looking
Statements
This release includes certain forward-looking statements and
projections of EP Energy. We have made every reasonable effort to
ensure that the information and assumptions on which these
statements and projections are based are current, reasonable, and
complete. However, a variety of factors could cause actual results
to differ materially from the projections, anticipated results or
other expectations expressed, including, without limitation, the
volatility of and potential for sustained low oil, natural gas and
NGL prices; the supply and demand for oil, natural gas and
NGLs; the company's ability to meet production volume
targets; changes in commodity prices and basis differentials for
oil and natural gas; the uncertainty of estimating proved reserves
and unproved resources; the future level of operating and capital
costs; the availability and cost of financing to fund future
exploration and production operations; the success of drilling
programs with regard to proved undeveloped reserves and unproved
resources; the company's ability to comply with the covenants in
various financing documents; the company's ability to obtain
necessary governmental approvals for proposed E&P projects and
to successfully construct and operate such projects; actions by the
credit rating agencies; credit and performance risk of our lenders,
trading counterparties, customers, vendors, suppliers and third
party operators; general economic and weather conditions in
geographic regions or markets served by the company, or where
operations of the company are located, including the risk of a
global recession and negative impact on oil and natural gas demand;
the uncertainties associated with governmental regulation,
including any potential changes in federal and state tax laws and
regulations; competition; and other factors described in the
company's Securities and Exchange Commission filings. While the
company makes these statements and projections in good faith,
neither the company nor its management can guarantee that
anticipated future results will be achieved. Reference must be made
to those filings for additional important factors that may affect
actual results. EP Energy assumes no obligation to publicly update
or revise any forward-looking statements made herein or any other
forward-looking statements made by EP Energy, whether as a result
of new information, future events, or otherwise.
Contact
Investor and Media
Relations
Jordan Strauss
713-997-6791
jordan.strauss@epenergy.com
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SOURCE EP Energy Corporation