HOUSTON, Feb. 28, 2018 /PRNewswire/ -- EP Energy
Corporation (NYSE:EPE) today reported fourth quarter and year-end
2017 financial and operational results for the company.
Key highlights include:
2017 Full Year Results
- New leadership team in place
- 82.3 thousand barrels of oil equivalent per day (MBoe/d),
including 46.1 thousand barrels of oil production per day
(MBbls/d)
- $587 million of oil and gas
expenditures, including acquisitions of $29
million
- 149 completed wells
- $194 million net loss /
$691 million Adjusted EBITDAX
- Entered into Eagle Ford acquisition and Altamont acreage
divestiture - closed 1Q'18
- Improved financial flexibility with extended debt maturity
profile
2017 Proved Reserves
- Proved reserves of 392.1 million barrels of oil equivalent
(MMBoe) - down nine percent from 2016
- Pro-forma for divestitures and ownership changes, total proved
reserves essentially flat to 2016
- 52 percent oil and 72 percent liquids
- Proved developed reserves of 218.3 MMBoe - up seven percent
from 2016
- 13 year reserve to production ratio (based on 2017 annual
production)
"We have been making meaningful progress on multiple fronts
since coming on board in November last year," said Russell Parker, president and chief executive
officer of EP Energy Corporation. "The organization has been
restructured to increase the speed of execution and decision
making. In each operating area we are blending in new
concepts to improve asset performance, increase capital efficiency
and reduce operating costs. So far in 2018, we have improved
our financial flexibility by extending $1.2
billion of near term maturities, and we enhanced our
portfolio of capital efficient projects with the completion of two
successful A&D transactions. We are pleased with our
progress so far, but we are even more excited about executing on
the opportunities ahead that will drive us toward cash flow
neutrality and reduced leverage."
2017 Financial Results
Fourth Quarter 2017
For the quarter ended December 31, 2017, EP Energy reported
a $0.29 diluted net loss per share
and $0.07 adjusted loss per share.
The reported net loss for the fourth quarter of 2017 was
$72 million, versus a $140 million net loss in the same 2016 period,
due to higher realized pricing on oil and NGL volumes and lower
reported general and administrative costs. Adjusted EBITDAX
for the fourth quarter 2017 was $181
million, down from $255
million in the fourth quarter of 2016, due to $118 million less of hedge settlements and lower
total equivalent and oil volumes in 2017 versus 2016, partially
offset by higher realized pricing on physical sales.
The company ended the year with fourth quarter operating
expenses of $217 million, down from
$247 million in the fourth quarter of
2016 due to lower reported general and administrative costs.
Adjusted cash operating costs were $101
million for the fourth quarter 2017, down from $111 million in the same 2016 period. Adjusted
cash operating costs were $13.65 per
barrel of oil equivalent (Boe) for the fourth quarter 2017, down
from $14.80 per Boe in the same 2016
period mainly due to lower adjusted general and administrative
costs, partially offset by higher production taxes from higher
pricing in 2017.
Capital expenditures in the fourth quarter 2017 were
$145 million, up from $116 million in the same period 2016, due to
increased drilling activity in the Eagle Ford in 2017. The
company spent $92 million in the
Eagle Ford, $28 million in the
Permian and $25 million in the
Altamont. In the fourth quarter 2017, the company completed
30 gross wells, 14 of which were in the Eagle Ford, seven in the
Permian as part of the company's drilling joint venture and nine in
the Altamont drilling joint venture.
Full Year 2017
For the year ended December 31, 2017, EP Energy reported
$0.79 diluted net loss per share and
$0.39 adjusted loss per share.
Reported net loss was $194 million
for the year 2017, compared to a $27
million net loss in the same 2016 period, which included
approximately $450 million of gains
on extinguishment of debt and asset sales in 2016. Adjusted
EBITDAX for the year 2017 was $691
million, down from $1,039
million in 2016 due primarily to $546
million in lower hedge settlements offset by higher realized
pricing on oil and NGL volumes in 2017.
Total operating expenses for the year ended December 31,
2017 were $927 million, up from
$865 million in the same 2016
period. The difference was driven by a $78 million gain on the sale of the Haynesville
assets in 2016. Adjusted cash operating costs were
$427 million for the year 2017, down
from $440 million in the same 2016
period. Adjusted cash operating costs per unit were $14.23 per Boe for the year 2017, up slightly
from $13.77 per Boe in the same 2016
period due to lower volumes and higher production taxes resulting
from higher pricing in 2017.
Capital expenditures in 2017 were $587
million, up from $488 million
in the same period 2016. In 2017, the company spent
$227 million in the Eagle Ford,
$267 million in the Permian
(including $29 million of
acquisitions) and $93 million in the
Altamont. In 2017, the company completed 149 gross wells,
which was approximately 50 more than EP Energy completed in
2016. In 2017, the company completed 53 wells in the Eagle
Ford, 71 wells in the Permian, including 58 wells in the drilling
joint venture and 25 wells in the Altamont.
Note: See Disclosure of Non-GAAP Financial Measures section
of this release for applicable definitions and reconciliations to
GAAP terms.
Financial Position and Liquidity
At December 31, 2017, EP Energy's balance sheet included
$4.1 billion of total debt and
approximately $27 million of cash and
cash equivalents.
In January 2018, EP Energy
successfully exchanged and extended the maturity on approximately
$1.1 billion of senior unsecured
notes maturing in 2020, 2022 and 2023 for new senior secured notes
maturing in 2024. The company has no significant near-term
debt maturities with the Reserve-Based Loan Facility (RBL Facility)
maturing in May 2019 and a manageable
level of approximately $275 million
in maturities over the next four years. The company plans to
address the extension of the RBL Facility by the end of the second
quarter 2018.
As of December 31, 2017, the
company had approximately $800
million of total liquidity. Pro-forma for the
January 2018 debt exchange, the
company had approximately $700
million of liquidity at year-end 2017. The company
remains focused on balance sheet improvement and maintaining strong
financial flexibility. The company expects to reduce its net
debt to adjusted EBITDAX ratio in 2018.
Operations
For the year ended December 31, 2017, average daily
production was 82.3 MBoe/d, including 46.1 MBbls/d of oil.
Fourth quarter 2017 average daily production was 80.6 MBoe/d,
including 43.6 MBbls/d of oil. The decrease in the third and
fourth quarter production is due to the timing of Eagle Ford
activity that was focused early in 2017.
Eagle Ford Program
In 2017, the company completed 53 wells in its Eagle Ford
program and production was 35.7 MBoe/d, an 18 percent decrease from
2016 due to reduced capital spending since 2015. During the
fourth quarter of 2017, the company completed 14 wells and produced
30.6 MBoe/d, a 19 percent decrease from the fourth quarter of
2016. In 2018, the company expects to significantly increase
year over year annual production for the first time since 2015.
EP Energy expanded its Eagle Ford horizontal shale inventory by
approximately 200 future drilling locations with the acquisition of
producing properties and undeveloped acreage from Carrizo Oil &
Gas, Inc., which closed in January
2018.
In the Eagle Ford, the company has increased the current oil
field production rate by 20 percent compared with the fourth
quarter 2017 average. Half of the increase was driven by
performance from new wells and half of the increase was due to the
acquisition. Included in these results are four Ritchie Farms
in-fill pad child wells that have been on-line for 25 days with
cumulative production six percent higher than the parent
well. The company also completed four new Volatile Oil wells
in December and January that had a 60-day oil rate 30 percent
higher than the company's type curve.
EP Energy continues to test initiatives for optimal field
development and well design to increase production rates, cash flow
and asset value.
Permian Program
In 2017, the company completed 71 wells in its Permian program
and produced 28.7 MBoe/d, a 34 percent increase from 2016. In
the fourth quarter of 2017, the company completed seven wells, down
from 21 completed wells in the same 2016 period, and produced 32.1
MBoe/d, a 17 percent increase from the fourth quarter of
2016.
Also in 2017, EP Energy completed several bolt-on acquisitions
in Upton County which added
current production and future drilling locations. These
acquisitions totaled approximately $29
million and included approximately 3,600 net acres in
Upton County with gross oil
production of 300 Bbls/d. The transactions added
approximately 60 future drilling locations and enabled the company
to extend approximately 20 short lateral locations to long lateral
locations.
In the Permian, the company is focused on reducing operating
costs with enhanced water handling facilities, further optimizing
its development program and maintaining its drilling commitments
for 2018.
Altamont Program
The company continued to efficiently develop its Altamont
program, with the highest returns achieved in its recompletion
program. In 2017, the company
completed 25 wells and performed 59 recompletions. The
company benefits from a significant inventory of recompletion
opportunities, which generate some of the highest project returns
in the portfolio.
Full year production was 17.9 MBoe/d, eight percent higher than
2016 driven by improved performance and higher activity levels of
the company's drilling and recompletion programs. In the
fourth quarter 2017, the company completed nine wells and had
production volumes of 17.9 MBoe/d.
During the year, the company benefited from improved realized
pricing relative to WTI oil prices and higher returns with its
drilling joint venture.
Hedge Program Update
In 2017, EP Energy realized $93
million from settlements on financial derivatives. At
year-end 2017, the mark-to-market value of the company's hedge
positions was approximately $5
million. For 2018, EP Energy has effectively hedged
approximately 89 percent of its expected oil production at an
average price of $58.47 per barrel,
and hedged approximately 56 percent of its expected natural gas
production at an average price of $3.04 per MMBtu. Importantly, the company
also has the ability to participate in upside pricing movements on
two-thirds of its anticipated 2018 production as a result of having
a collar structure on a portion of its derivatives.
A summary of the company's 2018 and 2019 hedge positions is
listed below:
|
2018
|
|
2019
|
Total Fixed Price
Hedges
|
|
|
|
Oil volumes
(MMBbls)
|
14.9
|
|
|
1.8
|
|
Average floor price
($/Bbl)
|
$
|
58.47
|
|
|
$
|
55.35
|
|
|
|
|
|
Natural gas volumes
(TBtu)
|
25.6
|
|
|
7.3
|
|
Average floor prices
($/MMBtu)
|
$
|
3.04
|
|
|
$
|
2.97
|
|
|
Note: Positions
are as of January 31, 2018 (Contract months: January 2018 -
Forward) and the table includes WTI three-way collars of 8.9 MMBbls
and 1.1 MMBbls in 2018 and 2019, respectively, and WTI collars of
1.0 MMBbls in 2018.
|
2017 Proved Reserves
EP Energy's proved oil and natural gas reserves were 392.1 MMBoe
as of December 31, 2017, a nine percent decrease compared
to proved reserves at December 31,
2016 of 432.4 MMBoe. Proved developed reserves
increased seven percent from 204.6 MMBoe in 2016 to 218.3 MMBoe in
2017. In 2017, proved developed reserves were 56 percent of
total proved reserves and 52 percent oil.
2017 proved reserves were lower than 2016 primarily due to
divestitures relating to the company's two drilling joint ventures
and ownership changes, resulting from higher WTI prices under the
variable royalty rates agreement with University Lands.
Excluding the impact of the divestitures and ownership changes 2017
proved reserves were essentially flat to 2016. Importantly,
proved developed reserves increased to 56 percent of the company's
total reserves, up from 47 percent in 2016.
The SEC first-day-of-the-month 12-month average prices for
reserves as of December 31, 2017 were
$51.34 per Bbl for oil and
$2.98 per MMBtu for natural gas, up
from $42.75 per Bbl for oil and
$2.48 per MMBtu for natural gas in
the prior 12-month period.
2018 Outlook
EP Energy is reaffirming its previously provided operational and
financial guidance for full year 2018. In addition, the
company is providing production and capital guidance for the first
quarter of 2018.
|
|
1Q'18
|
2018
|
|
|
|
|
Oil production
(MBbls/d)
|
|
43 - 44
|
46 - 50
|
Total production
(MBoe/d)
|
|
77 - 79
|
81 - 87
|
|
|
|
|
Oil & Gas
Expenditures ($ million)1,2
|
|
$210 -
$220
|
$600 -
$650
|
Eagle
Ford
|
|
|
~50%
|
Permian
|
|
|
~30%
|
Altamont
|
|
|
~20%
|
|
|
|
|
Average gross
drilling rigs
|
|
|
|
Eagle
Ford
|
|
|
1 - 2
|
Permian
|
|
|
1
|
Altamont
|
|
|
2
|
|
|
|
|
Operating
Costs
|
|
|
|
Lease operating
expense ($/Boe)
|
|
|
$5.00 -
$5.70
|
G&A expense
($/Boe)
|
|
|
$2.90 -
$3.25
|
Adjusted G&A
expense ($/Boe)3
|
|
|
$2.30 -
$2.60
|
Transportation and
commodity purchases ($/Boe)
|
|
|
$3.15 -
$3.45
|
Taxes, other than
income ($/Boe)4
|
|
|
$2.50 -
$2.60
|
DD&A
($/Boe)
|
|
|
$16.50 -
$17.50
|
|
|
|
|
1 Includes
~$135 million non-drill capital including; ~$55 million for general
equipment, ~$30 million for capitalized G&A and interest, ~$25
million for enhanced facility projects, ~$10 million for enhanced
oil recovery projects, and ~$15 million for leasing and seismic,
and excludes net acquisition costs and divestiture proceeds of ~$57
million.
|
|
2 Altamont
capital includes ~100 recompletions for $50 million.
|
|
3 Adjusted
G&A represents G&A expense less approximately $0.60 - $0.65
per Boe of non-cash compensation expense.
|
|
4
Severance taxes are based on $55/Bbl WTI.
|
Webcast Information
EP Energy has scheduled a webcast at 10 a.m. Eastern Time,
9 a.m. Central Time, on March 1,
to discuss its fourth quarter and full year financial and
operational results. The webcast may be accessed online
through the company's website at epenergy.com in the Investor
Center. Materials to be discussed during the webcast will be
available in the Investor Center one hour prior to the
webcast. A limited number of telephone lines will be
available to participants by dialing 888-317-6003 (conference ID#
1387932) 10 minutes prior to the start of the webcast. A
replay of the webcast will be available through April 5, 2018 on the company's website in the
Investor Center or by dialing 877-344-7529 (conference ID#
10117505).
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.
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
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, fees paid to the Sponsors, gains and losses on
extinguishment of debt, gains and/or losses on sale of assets and
impairment charges. Adjusted EBITDAX Per Unit is calculated
using Adjusted EBITDAX divided by equivalent volumes.
Below is a reconciliation of our consolidated net loss to
EBITDAX and Adjusted EBITDAX:
|
Quarter ended
December 31,
|
|
Year ended
December 31,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
($ in millions, except equivalent volumes and per unit)
|
Net loss
|
$
|
(72)
|
|
|
$
|
(140)
|
|
|
$
|
(194)
|
|
|
$
|
(27)
|
|
Income tax (benefit)
expense
|
(2)
|
|
|
—
|
|
|
(9)
|
|
|
1
|
|
Interest expense, net
of capitalized interest
|
81
|
|
|
81
|
|
|
326
|
|
|
312
|
|
Depreciation,
depletion and amortization
|
119
|
|
|
120
|
|
|
487
|
|
|
462
|
|
Exploration
expense
|
2
|
|
|
2
|
|
|
9
|
|
|
5
|
|
EBITDAX
|
128
|
|
|
63
|
|
|
619
|
|
|
753
|
|
Mark-to-market on
financial derivatives(1)
|
51
|
|
|
53
|
|
|
(41)
|
|
|
73
|
|
Cash settlements and
cash premiums on financial derivatives(2)
|
7
|
|
|
125
|
|
|
93
|
|
|
639
|
|
Non-cash portion of
compensation expense(3)
|
(29)
|
|
|
7
|
|
|
(22)
|
|
|
19
|
|
Transition, severance
and other costs(4)
|
19
|
|
|
5
|
|
|
19
|
|
|
15
|
|
Fees paid to
Sponsors(5)
|
5
|
|
|
—
|
|
|
5
|
|
|
—
|
|
Gain on sale of
assets
|
—
|
|
|
—
|
|
|
—
|
|
|
(78)
|
|
Loss (gain) on
extinguishment of debt
|
—
|
|
|
—
|
|
|
16
|
|
|
(384)
|
|
Impairment
charges
|
—
|
|
|
2
|
|
|
2
|
|
|
2
|
|
Adjusted
EBITDAX
|
$
|
181
|
|
|
$
|
255
|
|
|
$
|
691
|
|
|
$
|
1,039
|
|
|
|
|
|
|
|
|
|
Total equivalent
volumes (MBoe)
|
7,412
|
|
|
7,594
|
|
|
30,024
|
|
|
32,077
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDAX Per
Unit (MBoe)(6)
|
$
|
24.43
|
|
|
$
|
33.53
|
|
|
$
|
23.03
|
|
|
$
|
32.39
|
|
|
|
|
|
|
|
|
|
|
(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 our long-term incentive programs adjusted for
cash payments made under these plans.
|
|
|
(4)
|
Reflects transition
and severance costs related to workforce reductions.
|
|
|
(5)
|
Represents fees paid
in connection with the release of members of the new leadership
team from a portfolio company of funds managed by Apollo Global
Management LLC and payment of certain legal expenses.
|
|
|
(6)
|
Adjusted EBITDAX Per
Unit is based on actual amounts rather than the rounded totals
presented.
|
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 of debt,
gains and/or losses on sale of assets, impairment charges, other
costs that affect comparability, including transition, severance and other costs and associated LTI
forfeitures, fees paid to the Sponsors and changes in the
valuation allowance on deferred tax assets.
Below is a reconciliation of consolidated diluted net loss per
share to Adjusted EPS:
|
Quarter ended December 31, 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)
|
$
|
58
|
|
|
$
|
37
|
|
|
$
|
0.15
|
|
Transition, severance
and other costs
|
|
|
|
|
|
Severance and
other costs(4)
|
19
|
|
|
12
|
|
|
$
|
0.05
|
|
Fees paid to
Sponsors(5)
|
5
|
|
|
3
|
|
|
$
|
0.01
|
|
Long-term
incentive forfeitures
|
(33)
|
|
|
(31)
|
|
|
$
|
(0.13)
|
|
Valuation allowance
on deferred tax assets
|
|
|
33
|
|
|
0.14
|
|
Total
adjustments
|
$
|
49
|
|
|
$
|
54
|
|
|
$
|
0.22
|
|
|
|
|
|
|
|
Adjusted
EPS
|
|
|
|
|
$
|
(0.07)
|
|
|
|
|
|
|
|
Diluted weighted
average shares(6)
|
|
|
|
|
246
|
|
|
Year ended December 31, 2017
|
|
Pre-Tax
|
|
After-Tax
|
|
Diluted EPS(1)
|
|
($ in millions, except earnings per share amounts)
|
Net loss
|
|
|
$
|
(194)
|
|
|
$
|
(0.79)
|
|
|
|
|
|
|
|
Adjustments(2)
|
|
|
|
|
|
Impact of
financial derivatives(3)
|
$
|
52
|
|
|
$
|
33
|
|
|
$
|
0.14
|
|
Transition, severance
and other costs
|
|
|
|
|
|
Severance and
other costs(4)
|
19
|
|
|
12
|
|
|
0.05
|
|
Fees paid to
Sponsors(5)
|
5
|
|
|
3
|
|
|
0.01
|
|
Long-term
incentive forfeitures
|
(33)
|
|
|
(31)
|
|
|
(0.13)
|
|
Loss on
extinguishment/modification of debt
|
16
|
|
|
11
|
|
|
0.04
|
|
Impairment
charges
|
2
|
|
|
—
|
|
|
—
|
|
Valuation allowance
on deferred tax assets
|
|
|
69
|
|
|
$
|
0.29
|
|
Total
adjustments
|
$
|
61
|
|
|
$
|
97
|
|
|
$
|
0.40
|
|
|
|
|
|
|
|
Adjusted
EPS
|
|
|
|
|
$
|
(0.39)
|
|
|
|
|
|
|
|
Diluted weighted
average shares(6)
|
|
|
|
|
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 of approximately 36%, as well as any
other income tax effects specifically attributable to that item.
Taxes associated with certain LTI forfeitures related to the change
in management are generally not deductible for tax
purposes.
|
|
|
(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.
|
|
|
(4)
|
Reflects transition
and severance costs related to workforce reductions.
|
|
|
(5)
|
Represents fees paid
in connection with the release of members of the new leadership
team from a portfolio company of funds managed by Apollo Global
Management LLC and payment of certain legal expenses.
|
|
|
(6)
|
Diluted shares
include certain restricted stock and performance unit
awards.
|
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, transition, severance and other
costs and fees paid to the Sponsors.
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 and/or losses on sales 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), transition, severance and other
costs that affect comparability and fees paid to the Sponsors. 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 the operation of our assets.
We exclude the non-cash portion of compensation expense as well as
transition, severance and other costs that affect
comparability and fees paid to the Sponsors, as we believe such
adjustments allow investors to evaluate our costs against others in
our industry and these items 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
December 31,
|
|
|
2017
|
|
2016
|
|
|
Total
($MM)
|
|
Per Unit
($/Boe)(1)
|
|
Total
($MM)
|
|
Per Unit
($/Boe)(1)
|
Oil and natural gas
purchases
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1
|
|
|
$
|
0.17
|
|
Transportation
costs
|
|
29
|
|
|
3.92
|
|
|
28
|
|
|
3.71
|
|
Lease operating
expense
|
|
42
|
|
|
5.60
|
|
|
42
|
|
|
5.59
|
|
General and
administrative
|
|
10
|
|
|
1.35
|
|
|
45
|
|
|
5.85
|
|
Depreciation,
depletion and amortization
|
|
119
|
|
|
16.01
|
|
|
120
|
|
|
15.78
|
|
Impairment
charges
|
|
—
|
|
|
—
|
|
|
2
|
|
|
0.21
|
|
Exploration and other
expense
|
|
2
|
|
|
0.20
|
|
|
2
|
|
|
0.23
|
|
Taxes, other than
income taxes
|
|
15
|
|
|
2.08
|
|
|
7
|
|
|
1.08
|
|
Total operating
expenses
|
|
$
|
217
|
|
|
$
|
29.16
|
|
|
$
|
247
|
|
|
$
|
32.62
|
|
Adjustments:
|
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
$
|
(119)
|
|
|
$
|
(16.01)
|
|
|
$
|
(120)
|
|
|
$
|
(15.78)
|
|
Impairment
charges
|
|
—
|
|
|
—
|
|
|
(2)
|
|
|
(0.21)
|
|
Exploration
expense
|
|
(2)
|
|
|
(0.20)
|
|
|
(2)
|
|
|
(0.23)
|
|
Non-cash portion of
compensation expense(2)
|
|
29
|
|
|
3.95
|
|
|
(7)
|
|
|
(0.89)
|
|
Transition, severance
and other costs(2)
|
|
(19)
|
|
|
(2.56)
|
|
|
(5)
|
|
|
(0.71)
|
|
Fees paid to
Sponsors(2)
|
|
(5)
|
|
|
(0.69)
|
|
|
—
|
|
|
—
|
|
Adjusted cash
operating costs and per unit adjusted cash costs
|
|
$
|
101
|
|
|
$
|
13.65
|
|
|
$
|
111
|
|
|
$
|
14.80
|
|
|
|
|
|
|
|
|
|
|
Total consolidated
equivalent volumes (MBoe)
|
|
|
|
7,412
|
|
|
|
|
7,594
|
|
|
|
Year Ended
December 31,
|
|
|
2017
|
|
2016
|
|
|
Total
($MM)
|
|
Per-Unit
($/Boe)(1)
|
|
Total
($MM)
|
|
Per-Unit
($/Boe)(1)
|
Oil and natural gas
purchases
|
|
$
|
2
|
|
|
$
|
0.07
|
|
|
$
|
10
|
|
|
$
|
0.32
|
|
Transportation
costs
|
|
115
|
|
|
3.83
|
|
|
109
|
|
|
3.41
|
|
Lease operating
expense
|
|
163
|
|
|
5.42
|
|
|
159
|
|
|
4.97
|
|
General and
administrative
|
|
81
|
|
|
2.69
|
|
|
146
|
|
|
4.54
|
|
Depreciation,
depletion and amortization
|
|
487
|
|
|
16.22
|
|
|
462
|
|
|
14.40
|
|
Gain on sale of
assets
|
|
—
|
|
|
—
|
|
|
(78)
|
|
|
(2.44)
|
|
Impairment
charges
|
|
2
|
|
|
0.04
|
|
|
2
|
|
|
0.05
|
|
Exploration and other
expense
|
|
12
|
|
|
0.40
|
|
|
5
|
|
|
0.16
|
|
Taxes, other than
income taxes
|
|
65
|
|
|
2.19
|
|
|
50
|
|
|
1.58
|
|
Total operating
expenses
|
|
$
|
927
|
|
|
$
|
30.86
|
|
|
$
|
865
|
|
|
$
|
26.99
|
|
Adjustments:
|
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
$
|
(487)
|
|
|
$
|
(16.22)
|
|
|
$
|
(462)
|
|
|
$
|
(14.40)
|
|
Impairment
charges
|
|
(2)
|
|
|
(0.04)
|
|
|
(2)
|
|
|
(0.05)
|
|
Gain on sale of
assets
|
|
—
|
|
|
—
|
|
|
78
|
|
|
2.44
|
|
Exploration
expense
|
|
(9)
|
|
|
(0.30)
|
|
|
(5)
|
|
|
(0.16)
|
|
Non-cash portion of
compensation expense(2)
|
|
22
|
|
|
0.75
|
|
|
(19)
|
|
|
(0.58)
|
|
Transition,
restructuring and other costs(2)
|
|
(19)
|
|
|
(0.64)
|
|
|
(15)
|
|
|
(0.47)
|
|
Fees paid to
Sponsors(2)
|
|
(5)
|
|
|
(0.18)
|
|
|
—
|
|
|
—
|
|
Adjusted cash
operating costs and per-unit adjusted cash costs
|
|
$
|
427
|
|
|
$
|
14.23
|
|
|
$
|
440
|
|
|
$
|
13.77
|
|
|
|
|
|
|
|
|
|
|
Total consolidated
equivalent volumes (MBoe)
|
|
|
|
30,024
|
|
|
|
|
32,077
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Per unit costs are
based on actual amounts rather than the rounded totals
presented.
|
|
|
(2)
|
Amounts are excluded
in the calculation of adjusted general and administrative
expense.
|
EBITDAX, Adjusted EBITDAX and Adjusted EBITDAX Per Unit 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. Adjusted EPS is used by
management and we believe is a valuable measure of operating
performance. Adjusted Cash Operating Costs per unit is 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 is used
by management and investors as additional information. 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 EBITDAX Per
Unit, Adjusted General and Administrative Expense and Adjusted Cash
Operating Costs 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, Adjusted EBITDAX, Adjusted EBITDAX Per Unit
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 General and Administrative Expense should not
be used as an alternative to GAAP general and administrative
expense. Adjusted Cash Operating Costs 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. Our presentation of Adjusted EPS,
EBITDAX, Adjusted EBITDAX, Adjusted EBITDAX Per Unit, Adjusted
General and Administrative Expense and Adjusted Cash Operating
Costs 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 EBITDAX Per Unit,
Adjusted General and Administrative Expense and Adjusted Cash
Operating Costs 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 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 service 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
Bill Baerg
713-997-2906
bill.baerg@epenergy.com
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SOURCE EP Energy Corporation