OKLAHOMA CITY, Feb. 14, 2017 /PRNewswire/ -- Chesapeake
Energy Corporation (NYSE:CHK) today announced additional details of
its 2017 guidance outlook. Highlights include:
- Projected total capital expenditures guidance of
$1.9 –
$2.5 billion, including
capitalized interest
- Projected total company production guidance ranging from
a decline of 3% to growth of 2%, adjusted for asset
sales
- Exit rate oil production projected to grow by 10% in
2017, while exit rate gas production projected to remain relatively
flat, adjusted for asset sales
- Plan to operate an average of approximately 17 drilling
rigs, compared to 10 rigs in 2016
Doug Lawler, Chesapeake's Chief Executive Officer,
commented, "The execution of our 2017 capital program will position
Chesapeake for significant
production and earnings growth and cash flow neutrality in 2018. As
noted during our October 2016 Analyst
Day, our 2017 capital program is driven by improved capital
efficiencies and profitability from our significant portfolio of
high rate of return drilling opportunities. We will maintain our
financial and operational flexibility with a relentless focus on
driving differential performance. We look forward to building
on our progress, both financially and operationally, in 2017 and
beyond."
2017 Capital Program and Production Outlook
Chesapeake is budgeting planned
total capital expenditures (including capitalized interest) in the
range of $1.9 – $2.5 billion in 2017, compared to total capital
expenditures of approximately $1.65 –
$1.75 billion in 2016, excluding 2016
proved property acquisitions and the repurchase of volumetric
production payment (VPP) transactions. The company is narrowing its
range of projected capital as it gains confidence in market
conditions supporting a return to projected production growth in
the second half of the year. The company is targeting total
production of 194 – 205 million barrels of oil equivalent (mmboe)
in 2017, or average daily production of 532 – 562 thousand barrels
of oil equivalent (mboe), representing a decline of 3% to modest
growth of 2% compared to 2016, after adjusting for asset sales. Of
the 2017 projected total production, approximately 33 – 35 mmboe is
estimated to be crude oil, 18 – 20 mmboe is estimated to be natural
gas liquids and 860 – 900 billion cubic feet is estimated to be
natural gas.
Chesapeake plans to operate an
average of approximately 17 rigs in 2017, an increase from an
average of 10 rigs in 2016. The company intends to spud and place
on production approximately 400 and 450 gross operated wells in
2017, respectively, compared to 213 and 428 wells in 2016,
respectively. A complete summary of the company's guidance for 2017
is attached to this release.
Operations Update
Lawler continued, "We have a number of operational
results we are looking forward to in 2017, including our
return to the Powder River Basin (PRB) and our first results from
the Turner formation in the 2017 second quarter, along with
additional results from the Sussex and Niobrara and a Mowry test
later in the year. In total, we plan to place approximately 30
wells on production in the PRB in 2017. In the Mid-Continent area,
we plan to place approximately 100 wells on production during 2017,
with roughly 60 of those wells planned from the Oswego formation.
The Mid-Continent is expected to provide oil growth in 2017 through
development drilling in the Oswego and our exploitation of 'the
Wedge play.' Finally, we plan to operate approximately six rigs and
place approximately 165 wells on production in the Eagle Ford Shale
in South Texas. Several new tests
are planned in the Eagle Ford, which include more than 10
extra-long lateral wells reaching approximately 15,000 feet and we
also plan to test the Upper Eagle Ford and Austin Chalk formations. Our increased activity
in the Eagle Ford, Oklahoma and
the PRB is expected to result in oil growth of approximately 10%
from year-end 2016 to year-end 2017, with continued growth in our
oil volumes projected to be over 20% by year-end 2018.
"In our natural gas plays, our progress in the Haynesville Shale
in Louisiana continues to improve
with recent wells placed on production reaching approximately 30 –
45 million cubic feet (mmcf) of gas per day. Our plans for 2017 in
the Haynesville include utilizing
three rigs and placing approximately 35 wells on production. In
Northeast Appalachia, our activities in the Marcellus Shale in
Pennsylvania and the Utica Shale
in Ohio will be more focused on
completing inventory wells compared to drilling and completing new
wells. We also plan to begin applying more aggressive fracture
stimulation procedures to wells in both the Marcellus and our dry
gas Utica areas during the year.
We are projecting that natural gas production growth will be
relatively flat from year-end 2016 to year-end 2017, but expect
that our gas volumes will return to growing again from year-end
2017 to year-end 2018. Nonetheless, we are projecting that these
world-class gas producing areas will generate significant free cash
flow for us compared to the capital invested during both 2017 and
2018."
Doug Lawler will be making a
company presentation at the 2017 Credit Suisse Energy
Summit on Tuesday, February 14,
2017 at 1:30 PM EST. The event
will be available to the public via internet webcast. A link
to the webcast will be accessible at www.chk.com/investors on
the date of the event.
Headquartered in Oklahoma
City, Chesapeake Energy Corporation's (NYSE: CHK) operations
are focused on discovering and developing its large and
geographically diverse resource base of unconventional oil and
natural gas assets onshore in the United
States. The company also owns oil and natural gas marketing
and natural gas gathering and compression businesses.
This news release and the accompanying Outlook include
"forward-looking statements" within the meaning of Section 27A of
the Securities Act of 1933 and Section 21E of the Securities
Exchange Act of 1934. Forward-looking statements are statements
other than statements of historical fact. They include statements
that give our current expectations or forecasts of future events,
production and well connection forecasts, estimates of operating
costs, anticipated capital and operational efficiencies, planned
development drilling and expected drilling cost reductions, general
and administrative expenses, capital expenditures, the timing of
anticipated noncore asset sales and proceeds to be received
therefrom, projected cash flow and liquidity, our
ability to enhance our cash flow and financial flexibility, plans
and objectives for future operations (including our ability to
optimize base production and execute gas gathering agreements), the
ability of our employees, portfolio strength and operational
leadership to create long-term value, and the assumptions on which
such statements are based. Although we believe the expectations and
forecasts reflected in the forward-looking statements are
reasonable, we can give no assurance they will prove to have been
correct. They can be affected by inaccurate or changed assumptions
or by known or unknown risks and uncertainties.
Factors that could cause actual results to differ materially
from expected results include those described under "Risk Factors"
in Item 1A of our annual report on Form 10-K and any updates to
those factors set forth in Chesapeake's subsequent quarterly reports on
Form 10-Q or current reports on Form 8-K (available at
http://www.chk.com/investors/sec-filings). These risk factors
include the volatility of oil, natural gas and NGL prices; the
limitations our level of indebtedness may have on our financial
flexibility; our inability to access the capital markets on
favorable terms or at all; the availability of cash flows from
operations and other funds to finance reserve replacement costs or
satisfy our debt obligations; a further downgrade in our credit
rating requiring us to post more collateral under certain
commercial arrangements; write-downs of our oil and natural gas
asset carrying values due to low commodity prices; our ability to
replace reserves and sustain production; uncertainties inherent in
estimating quantities of oil, natural gas and NGL reserves and
projecting future rates of production and the amount and timing of
development expenditures; our ability to generate profits or
achieve targeted results in drilling and well operations; leasehold
terms expiring before production can be established; commodity
derivative activities resulting in lower prices realized on oil,
natural gas and NGL sales; the need to secure derivative
liabilities and the inability of counterparties to satisfy their
obligations; adverse developments or losses from pending or future
litigation and regulatory proceedings, including royalty claims;
charges incurred in response to market conditions and in connection
with our ongoing actions to reduce financial leverage and
complexity; drilling and operating risks and resulting liabilities;
effects of environmental protection laws and regulation on our
business; legislative and regulatory initiatives further regulating
hydraulic fracturing; our need to secure adequate supplies of water
for our drilling operations and to dispose of or recycle the water
used; impacts of potential legislative and regulatory actions
addressing climate change; federal and state tax proposals
affecting our industry; potential OTC derivatives regulation
limiting our ability to hedge against commodity price fluctuations;
competition in the oil and gas exploration and production industry;
a deterioration in general economic, business or industry
conditions; negative public perceptions of our industry; limited
control over properties we do not operate; pipeline and gathering
system capacity constraints and transportation interruptions;
terrorist activities and cyber-attacks adversely impacting our
operations; an interruption in operations at our headquarters due
to a catastrophic event; the continuation of suspended dividend
payments on our common stock and preferred stock; certain
anti-takeover provisions that affect shareholder rights; and our
inability to increase or maintain our liquidity through debt
repurchases, capital exchanges, asset sales, joint ventures,
farmouts or other means.
In addition, disclosures concerning the estimated
contribution of derivative contracts to our future results of
operations are based upon market information as of a specific
date. These market prices are subject to significant
volatility. Our production forecasts are also dependent upon
many assumptions, including estimates of production decline rates
from existing wells and the outcome of future drilling
activity. Expected asset sales may not be completed in the
time frame anticipated or at all. We caution you not to place
undue reliance on our forward-looking statements, which speak only
as of the date of this news release, and we undertake no obligation
to update any of the information provided in this release or the
accompanying Outlook, except as required by applicable law.
CHESAPEAKE
ENERGY CORPORATION OUTLOOK FOR 2017
Chesapeake periodically
provides guidance on certain factors that affect the company's
future financial performance. New information or changes from the
company's November 3, 2016
preliminary Outlook are italicized bold below.
|
Year Ending
12/31/2017
|
|
|
Adjusted
Production Growth(a)
|
(3%) to
2%
|
Absolute
Production
|
|
Liquids -
mmbbls
|
51 - 55
|
Oil -
mmbbls
|
33 - 35
|
NGL -
mmbbls
|
18 - 20
|
Natural gas -
bcf
|
860 - 900
|
Total absolute
production - mmboe
|
194 - 205
|
Absolute daily rate -
mboe
|
532 - 562
|
Estimated
Realized Hedging Effects(b) (based on 2/9/17 strip
prices):
|
|
Oil -
$/bbl
|
($0.15)
|
Natural gas -
$/mcf
|
($0.24)
|
NGL -
$/bbl
|
$0.06
|
Estimated Basis
to NYMEX Prices:
|
|
Oil -
$/bbl
|
$1.55 -
$1.75
|
Natural gas -
$/mcf
|
$0.35 -
$0.45
|
NGL -
$/bbl
|
$4.00 -
$4.40
|
Operating Costs per
Boe of Projected Production:
|
|
Production
expense
|
$2.50 -
$2.70
|
Gathering, processing
and transportation expenses
|
$7.00 -
$7.50
|
Oil -
$/bbl
|
$4.25 -
$4.45
|
Natural Gas -
$/mcf
|
$1.25 -
$1.35
|
NGL -
$/bbl
|
$8.10 -
$8.50
|
Production
taxes
|
$0.40 -
$0.50
|
General and
administrative(c)
|
$1.20 -
$1.30
|
Stock-based
compensation (noncash)
|
$0.10 -
$0.20
|
DD&A of
natural gas and liquids assets
|
$4.00 -
$5.00
|
Depreciation of
other assets
|
$0.40 -
$0.50
|
Interest
expense(d)
|
$1.85 -
$1.95
|
Marketing, gathering
and compression net margin(e)
|
($80) –
($60)
|
Book Tax
Rate
|
0%
|
Capital
Expenditures ($ in millions)(f)
|
$1,700 -
$2,300
|
Capitalized Interest
($ in millions)
|
$200
|
Total Capital
Expenditures ($ in millions)
|
$1,900 -
$2,500
|
|
|
(a)
|
Based on 2016
production of 547 mboe per day, adjusted for 2016 sales.
|
(b)
|
Includes expected
settlements for commodity derivatives adjusted for option
premiums. For derivatives closed early, settlements are
reflected in the period of original contract expiration.
|
(c)
|
Excludes expenses
associated with stock-based compensation.
|
(d)
|
Excludes unrealized
gains (losses) on interest rate derivatives.
|
(e)
|
Includes revenue and
operating expenses. Excludes depreciation and amortization of other
assets.
|
(f)
|
Includes capital
expenditures for drilling and completion, leasehold, geological and
geophysical costs, rig termination payments and other property and
plant and equipment. Excludes any additional proved property
acquisitions.
|
INVESTOR
CONTACT:
|
MEDIA
CONTACT:
|
Brad Sylvester,
CFA
|
Gordon
Pennoyer
|
405-935-8870
|
405-935-8878
|
ir@chk.com
|
media@chk.com
|
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visit:http://www.prnewswire.com/news-releases/chesapeake-energy-corporation-provides-2017-guidance-and-operational-update-300406427.html
SOURCE Chesapeake Energy Corporation