Announces 2015 Total Planned Capital
Expenditures
Chesapeake Energy Corporation (NYSE:CHK) today reported
financial and operational results for the 2014 full year and fourth
quarter and announced details of its 2015 Outlook and capital
expenditure program. Highlights include:
- 2014 adjusted net income of $1.49
per fully diluted share and 2014 adjusted ebitda of $4.945
billion
- Average 2014 production of
approximately 706,000 boe per day, an increase of 9% year over
year, adjusted for asset sales
- Planned 2015 total capital
expenditures ranging from $4.0 to $4.5 billion
- Projected 2015 production growth of
3 – 5%, adjusted for asset sales
Doug Lawler, Chesapeake’s Chief Executive Officer, said, “2014
was a year of accomplishments for Chesapeake. Because of these
accomplishments and the progress we have made as a company in 2014,
Chesapeake is well positioned to remain strong and flexible in
2015. We have taken and continue to take appropriate steps not only
to weather the current difficult commodity price environment we
face today, but to thrive in it. Chesapeake became a much stronger
company in 2014, and we are looking forward to becoming even
stronger in 2015.”
2015 Capital Program and Production Outlook
Chesapeake is budgeting total capital expenditures (including
capitalized interest) of $4.0 – $4.5 billion for 2015. Using the
midpoint of the range, this represents a 26% reduction from the
company's 2014 capital expenditures before acquisitions of $5.8
billion, and a 37% reduction from the company’s 2014 total capital
expenditures of approximately $6.7 billion (reconciled in the
"Capital Spending and Cost Overview" section below). The company is
targeting 2015 production of 235 – 240 million barrels of oil
equivalent (mmboe), or average daily production of 645 – 655
thousand barrels of oil equivalent (mboe), which represents 3 – 5%
production growth after adjusting for 2014 asset sales. Of the 2015
projected production, approximately 39 – 40 mmboe is estimated to
be crude oil, 1,035 – 1,055 billion cubic feet (bcf) natural gas
and 23 – 24 mmboe natural gas liquids (NGL).
Chesapeake plans to operate 35 – 45 rigs in 2015, which
represents the company's lowest operated rig activity level since
2004 and a decrease of approximately 38% (using the midpoint of the
range) from an average of 64 rigs in 2014. The company intends to
spud approximately 790 gross operated wells and connect to sales
approximately 800 gross operated wells in 2015, a decrease from
approximately 1,175 and 1,150 wells, respectively, in 2014. The
table below compares the capital and rig counts allocated to the
company’s operating areas for 2015 and 2014:
2015E D&C 2014 D&C 2015E Avg.
2014 Avg. Capex Capex Operated Operated Allocation
Allocation Rigs Rigs Eagle Ford 35% 40% 12 –
14 20 Utica 25% 10% 3 – 5 8 Haynesville 13% 8% 7 – 8 8 Powder River
Basin: Niobrara & Upper Cretaceous 10% 5% 3 – 4 4 Mid-Continent
North: Mississippian Lime 5% 7% 7 – 8 9 Mid-Continent South 5% 8% 1
– 2 5 Marcellus 5% 11% 1 – 2 5 Other(a) 2% 11%
1 – 2 5 Totals 100% 100% 35 – 45 64
(a) For 2014, includes Marcellus South,
Barnett Shale and exploration wells.
2014 Full-Year Results
For the 2014 full year, Chesapeake reported net income available
to common stockholders of $1.273 billion, or $1.87 per fully
diluted share. Items typically excluded by securities analysts in
their earnings estimates increased net income available to common
stockholders for the 2014 full year by approximately $316 million
and are presented on Page 14 of this release. The primary component
of this increase was unrealized gains on the company's oil and
natural gas commodity derivatives, partially offset by the
redemption of all the outstanding preferred shares of a subsidiary.
Adjusting for these items, 2014 full-year adjusted net income
available to common stockholders was $957 million, or $1.49 per
fully diluted share, compared to adjusted net income available to
common stockholders of $965 million, or $1.50 per fully diluted
share, in the 2013 full year.
Adjusted ebitda was $4.945 billion for the 2014 full year,
compared to $5.016 billion for the 2013 full year. Operating cash
flow, which is defined as cash flow provided by operating
activities before changes in assets and liabilities, was $5.026
billion for the 2014 full year, compared to $4.958 billion for the
2013 full year.
Adjusted net income available to common stockholders, operating
cash flow, ebitda and adjusted ebitda are non-GAAP financial
measures. Reconciliations of these measures to comparable financial
measures calculated in accordance with generally accepted
accounting principles are provided on pages 13 – 17 of this
release.
Chesapeake’s daily production for the 2014 full year averaged
706,300 barrels of oil equivalent (boe), a year-over-year increase
of 9%, adjusted for asset sales. Average daily production consisted
of approximately 115,800 barrels (bbls) of oil, 3.0 bcf of natural
gas and 90,500 bbls of NGL. Adjusted for asset sales, 2014
full-year average daily oil production increased 7%, average daily
natural gas production increased 6% and average daily NGL
production increased 42%.
2014 Fourth Quarter Results
For the 2014 fourth quarter, Chesapeake reported net income
available to common stockholders of $586 million, or $0.81 per
fully diluted share. Items typically excluded by securities
analysts in their earnings estimates increased 2014 fourth quarter
net income by approximately $552 million on an after-tax basis. The
primary component of this increase was unrealized gains on oil and
natural gas commodity derivatives. Adjusting for these items, 2014
fourth quarter net income available to common stockholders was $34
million, or $0.11 per fully diluted share, which compares to
adjusted net income available to common stockholders of $161
million, or $0.27 per fully diluted share, in the 2013 fourth
quarter.
For the 2014 fourth quarter, Chesapeake reported adjusted ebitda
of $916 million, compared to $1.132 billion in the 2013 fourth
quarter. Operating cash flow was $873 million in the 2014 fourth
quarter, compared to $995 million in the 2013 fourth quarter. The
quarter-over-quarter decreases in adjusted ebitda and operating
cash flow were primarily the result of lower realized oil, natural
gas and NGL prices, partially offset by higher production
volumes.
Chesapeake’s daily production for the 2014 fourth quarter
averaged approximately 729,000 boe, a year-over-year increase of
12%, adjusted for asset sales. Average daily production in the 2014
fourth quarter consisted of approximately 121,200 bbls of oil, 3.1
bcf of natural gas and 97,600 bbls of NGL, which represent
year-over-year increases of 7%, 9% and 40% respectively, adjusted
for asset sales.
Strategic Transactions and Asset Sales Update
In the 2014 fourth quarter, the company received approximately
$5.1 billion of net proceeds from asset sales, most of which was
from the sale of certain assets in the southern Marcellus Shale and
a portion of the eastern Utica Shale assets that closed in December
2014. Also in the 2014 fourth quarter, the company entered into a
new five-year $4.0 billion senior unsecured syndicated revolving
credit facility. The new unsecured facility has investment
grade-like terms and allowed Chesapeake to release nearly $6.0
billion of proved reserve-based collateral.
Capital Spending and Cost Overview
Chesapeake’s drilling and completion capital expenditures during
the 2014 full year were approximately $4.5 billion, and capital
expenditures for the acquisition of unproved properties, geological
and geophysical costs, and other property, plant and equipment were
approximately $669 million, for a total of approximately $5.1
billion, compared to the company’s forecasted range of $5.0 – $5.4
billion. In addition, during 2014 the company invested
approximately $499 million to repurchase leased rigs and
compressors as part of its strategic initiative to reduce
complexity and future commitments, as well as to facilitate asset
sales and the spin-off of its oilfield services business. The
company also invested approximately $450 million as part of an
exchange of properties in the Powder River Basin. Total capital
investments, including capitalized interest of $637 million, were
approximately $6.7 billion in 2014, compared to approximately $7.8
billion in 2013, and is reconciled below. Chesapeake’s total
capital expenditures were approximately $1.8 billion in the 2014
fourth quarter compared to approximately $2.1 billion in the 2013
fourth quarter.
$ in millions 2013 2014
2015 Type of Cost Q4 FY
Q4 FY Outlook Drilling
and completion costs $ 1,151 $ 5,466 $ 1,370
$ 4,470 Other exploration and development costs and
PP&E 478 1,231 252
669
Subtotal planned capital
spending $ 1,629 $ 6,697 $
1,622 $ 5,139 $3,500 – 4,000
Capitalized interest 182 815 134 637 500 PRB property exchange — —
— 450 Sale leasebacks 262 266
25 499
Total capital
spending $ 2,073 $ 7,778 $
1,781 $ 6,725 $4,000 – 4,500
Chesapeake spud a total of 308 gross wells and connected 311
gross wells to sales during the 2014 fourth quarter, compared to
239 gross wells spud and 260 gross wells connected to sales during
the 2014 third quarter.
Chesapeake's focus on cost discipline continued to generate
reductions in costs associated with production and general and
administrative (G&A) expenses. Average production expenses
during the 2014 full year were $4.69 per boe, a decrease of 1% year
over year. G&A expenses (including stock-based compensation)
during the 2014 full year were $1.25 per boe, a decrease of 33%
year over year.
Average production expenses during the 2014 fourth quarter were
$5.07, an increase of 10% from the 2013 fourth quarter. G&A
expenses (including stock-based compensation) during the 2014
fourth quarter were $1.38 per boe, a decrease of 30% from the 2013
fourth quarter.
A summary of the company’s guidance for 2015 is provided in the
Outlook dated February 25, 2015, attached to this release as
Schedule "A” beginning on Page 18.
Total Proved Reserves
The company's December 31, 2014, proved reserves were 2.469
billion boe, an increase of 5% compared to year-end 2013 before
acquisitions and divestitures. In 2014, Chesapeake increased its
proved reserves by 448 mmboe for extensions and discoveries and 14
mmboe from acquisitions. The additions were offset by 362 mmboe as
the result of divestitures, 51 mmboe of net negative reserve
revisions and production of 258 mmboe. Chesapeake's proved
developed reserves as a percentage of total proved reserves
increased to 75% as of December 31, 2014, compared to 68% as of
December 31, 2013. Additional information on reserves changes can
be found on Page 10.
Operations Update
As described below, Chesapeake continues to improve on its
capital efficiency, cycle times and well cost reductions.
Southern Division
Eagle Ford Shale (South
Texas): Eagle Ford net production averaged
approximately 106 mboe per day (230 gross operated mboe per day)
during the 2014 fourth quarter, an increase of 4% sequentially. The
2014 average completed well cost (January – October) was
approximately $6.1 million with an average completed lateral length
of 5,900 feet and 19 frac stages, compared to an average completed
well cost of $6.9 million in 2013 with an average completed lateral
length of 5,850 feet and 18 frac stages. Wells in various stages of
completion or waiting on pipeline in the area have increased to 158
as of December 31, 2014, compared to 109 wells at December 31,
2013. The average peak production rate of the 123 wells that
commenced first production in the Eagle Ford during the 2014 fourth
quarter was approximately 850 boe per day.
Haynesville Shale (Northwest
Louisiana): Haynesville Shale net production
averaged approximately 592 million cubic feet of natural gas
equivalent (mmcfe) per day (910 gross operated mmcfe per day)
during the 2014 fourth quarter, an increase of 5% sequentially. The
2014 average completed well cost (January – October) was
approximately $8.4 million with an average completed lateral length
of 4,900 feet and 13 frac stages, compared to an average completed
well cost of $8.9 million in 2013 with an average completed lateral
length of 4,400 feet and 18 frac stages. The average peak
production rate of the 18 wells that commenced first production in
the Haynesville during the 2014 fourth quarter was approximately
13.4 mmcfe per day.
Mid-Continent North: Mississippian Lime
(Northern Oklahoma): Mississippian Lime net
production averaged approximately 28 mboe per day (72 gross
operated mboe per day) during the 2014 fourth quarter, an increase
of 4% sequentially. The 2014 average completed well cost (January –
October) was approximately $3.1 million with an average completed
lateral length of 4,500 feet, compared to an average completed well
cost of $3.5 million in 2013 with an average completed lateral
length of 4,500 feet. The average peak production rate of the 42
wells that commenced first production in the Mississippian Lime
during the 2014 fourth quarter was approximately 730 boe per
day.
Northern Division
Utica Shale (Eastern
Ohio): Utica net production averaged
approximately 100 mboe per day (180 gross operated mboe per day)
during the 2014 fourth quarter, an increase of 17% sequentially.
The 2014 average completed well cost (January – October) was
approximately $6.6 million with an average completed lateral length
of 6,000 feet and 27 frac stages, compared to an average completed
well cost of $6.7 million in 2013 with an average completed lateral
length of 5,150 feet and 17 frac stages. Wells in various stages of
completion or waiting on pipeline in the area decreased to 166 as
of December 31, 2014, compared to 195 at December 31, 2013. The
average peak production rate of the 51 wells that commenced first
production in the Utica during the 2014 fourth quarter was
approximately 1,280 boe per day.
Marcellus Shale (Northern
Pennsylvania): Northern Marcellus net production
averaged approximately 817 mmcfe per day (2.07 gross operated bcfe
per day) during the 2014 fourth quarter, a decrease of 7%
sequentially. The 2014 average completed well cost (January –
October) was approximately $7.3 million with an average completed
lateral length of 5,900 feet and 27 frac stages, compared to an
average completed well cost of $7.9 million in 2013 with an average
completed lateral length of 5,400 feet and 13 frac stages. Wells in
various stages of completion or waiting on pipeline in the area
increased to 117 as of December 31, 2014, compared to 112 at
December 31, 2013. The average peak production rate of the 25 wells
that commenced first production in the northern Marcellus during
the 2014 fourth quarter was approximately 15.2 mmcfe per day.
Powder River Basin (PRB): Niobrara and
Upper Cretaceous (Wyoming): PRB net production
averaged approximately 18 mboe per day (27 gross operated mboe per
day) during the 2014 fourth quarter, an increase of 20%
sequentially, and, adjusted on an absolute basis to include the
property exchange transaction with RKI Exploration &
Production, an increase of 29% sequentially. The 2014 average
completed well cost (January – October) was approximately $9.1
million per well with an average completed lateral length of 5,100
feet and 18 frac stages, compared to an average completed well cost
of $10.1 million per well in 2013 with an average completed lateral
length of 5,050 feet and 15 frac stages. Wells in various stages of
completion or waiting on pipeline in the area decreased to 38 as of
December 31, 2014, compared to 57 wells at December 31, 2013. The
average peak production rate of the 13 wells that commenced first
production in the Powder River Basin during the 2014 fourth quarter
was approximately 1,670 boe per day.
Key Financial and Operational Results
The table below summarizes Chesapeake’s key financial and
operational results during the 2014 fourth quarter and 2014 full
year and compares them to results in prior periods.
Three Months Ended Full Year Ended
12/31/14 09/30/14 12/31/13
12/31/14 12/31/13 Oil equivalent production
(in mmboe) 67.1 66.8 61.2 257.8 244.4 Oil production (in mmbbls)
11.2 10.9 10.2 42.3 41.1 Average realized oil price ($/bbl)(a)
76.40 84.81 89.58 82.76 92.53 Oil as % of total production 17 16 17
16 17 NGL production (in mmbbls) 9.0 8.8 5.9 33.1 20.9 Average
realized NGL price ($/bbl)(a) 13.11 22.95 31.76 21.27 27.87 NGL as
% of total production 13 13 9 13 8 Natural gas production (in bcf)
281.6 282.0 270.5 1,095.0 1,094.6 Average realized natural gas
price ($/mcf)(a) 1.72 2.09 1.90 2.36 2.23 Natural gas as % of total
production 70 71 74 71 75 Production expenses ($/boe) (5.07 ) (4.47
) (4.62 ) (4.69 ) (4.74 ) Production taxes ($/boe) (0.70 ) (0.94 )
(0.91 ) (0.90 ) (0.94 ) General and administrative costs ($/boe)(b)
(1.23 ) (0.72 ) (1.79 ) (1.07 ) (1.62 ) Stock-based compensation
($/boe) (0.15 ) (0.18 ) (0.19 ) (0.18 ) (0.24 ) DD&A of natural
gas and liquids properties ($/boe) (10.53 ) (10.31 ) (10.53 )
(10.41 ) (10.59 ) DD&A of other assets ($/boe) (0.56 ) (0.55 )
(1.32 ) (0.90 ) (1.28 ) Interest expense ($/boe)(a) (0.56 ) (0.16 )
(0.86 ) (0.63 ) (0.65 ) Marketing, gathering and compression net
margin ($ in millions)(c) (39 ) (7 ) 9 (11 ) 98 Oilfield services
net margin ($ in millions)(c) — — 52 115 159 Operating cash flow ($
in millions)(d) 873 1,293 995 5,026 4,958 Operating cash flow
($/boe) 13.01 19.37 16.27 19.50 20.26 Adjusted ebitda ($ in
millions)(e) 916 1,236 1,132 4,945 5,016 Adjusted ebitda ($/boe)
13.66 18.52 18.51 19.18 20.52 Net income available to common
stockholders ($ in millions) 586 169 (159 ) 1,273 474 Earnings per
share – diluted ($) 0.81 0.26 (0.24 ) 1.87 0.73 Adjusted net income
available to common stockholders ($ in millions)(f) 34 251 161 957
965 Adjusted earnings per share – diluted ($) 0.11 0.38 0.27 1.49
1.50
(a) Includes the effects of realized gains
(losses) from hedging, but excludes the effects of unrealized gains
(losses) from hedging.
(b) Excludes expenses associated with
stock-based compensation and restructuring and other termination
costs.
(c) Includes revenue and operating
expenses and excludes depreciation and amortization of other
assets.
(d) Defined as cash flow provided by operating activities before
changes in assets and liabilities. (e) Defined as net income before
interest expense, income taxes and depreciation, depletion and
amortization expense, as adjusted to remove the effects of certain
items detailed on Page 17. (f) Defined as net income available to
common stockholders, as adjusted to remove the effects of certain
items detailed on Page 14.
2014 Full-Year and Fourth Quarter Financial and Operational
Results Conference Call Information
A conference call to discuss this release has been scheduled for
Wednesday, February 25, 2015, at 9:00 am EST. The telephone number
to access the conference call is 913-312-1469 or toll-free
888-601-3877. The passcode for the call is 2873261.
We encourage those who would like to participate in the call to
place calls between 8:50 and 9:00 am EST. For those unable to
participate in the live conference call, a replay will be available
for audio playback at 2:00 pm EST on Wednesday, February 25, 2015,
and will run through 2:00 pm EST on Wednesday, March 11, 2015. The
number to access the conference call replay is 719-457-0820
or toll-free 888-203-1112. The passcode for the replay is
2873261. The conference call will also be webcast live on
Chesapeake’s website at www.chk.com and a replay will be available
following the call.
Chesapeake Energy Corporation (NYSE:CHK) is the
second-largest producer of natural gas and the 11th largest
producer of oil and natural gas liquids in the U.S.
Headquartered in Oklahoma City, the company's operations are
focused on discovering and developing its large and geographically
diverse resource base of unconventional oil and natural gas assets
onshore in the U.S. The company also owns substantial
marketing and compression businesses. Further information is
available at www.chk.com where Chesapeake routinely
posts announcements, updates, events, investor information,
presentations and news releases.
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, production growth and well connection
forecasts, estimates of operating costs, planned development
drilling and expected drilling cost reductions, capital
expenditures, expected efficiency gains, anticipated asset sales
and proceeds to be received therefrom, projected cash flow and
liquidity, business strategy and other plans and objectives for
future operations, 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;
write-downs of our oil and natural gas carrying values due to
declines in prices; the availability of operating cash flow and
other funds to finance reserve replacement costs; 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;
the limitations our level of indebtedness may have on our financial
flexibility; charges incurred in response to market conditions and
in connection with 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; federal and state tax proposals affecting our industry;
potential OTC derivatives regulation limiting our ability to hedge
against commodity price fluctuations; impacts of potential
legislative and regulatory actions addressing climate change;
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; cyber
attacks adversely impacting our operations; and interruption in
operations at our headquarters due to a catastrophic event.
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 CONDENSED
CONSOLIDATED STATEMENTS OF OPERATIONS ($ in millions, except
per share data) (unaudited)
Three Months Ended Year Ended
December 31, December 31, 2014
2013 2014 2013 REVENUES:
Oil, natural gas and NGL $ 2,369 $ 1,608 $ 8,180 $ 7,052 Marketing,
gathering and compression 2,681 2,689 12,225 9,559 Oilfield
services — 244 546
895 Total Revenues 5,050 4,541
20,951 17,506
OPERATING
EXPENSES: Oil, natural gas and NGL production 340 282 1,208
1,159 Production taxes 47 56 232 229 Marketing, gathering and
compression 2,720 2,680 12,236 9,461 Oilfield services — 193 431
736 General and administrative 93 121 322 457 Restructuring and
other termination costs (5 ) 45 7 248 Provision for legal
contingencies 134 — 234 —
Oil, natural gas and NGL depreciation,
depletion and amortization
706 644 2,683 2,589 Depreciation and amortization of other assets
38 80 232 314 Impairments of fixed assets and other 14 203 88 546
Net (gains) losses on sales of fixed assets 3
(12 ) (199 ) (302 ) Total Operating Expenses
4,090 4,292 17,474 15,437
INCOME FROM OPERATIONS 960 249
3,477 2,069
OTHER INCOME
(EXPENSE): Interest expense (7 ) (63 ) (89 ) (227 ) Losses on
investments (7 ) (189 ) (80 ) (226 ) Net gain (loss) on sales of
investments — — 67 (7 ) Losses on purchases of debt (2 ) (123 )
(197 ) (193 ) Other income 10 7
22 26 Total Other Expense (6 )
(368 ) (277 ) (627 )
INCOME (LOSS) BEFORE INCOME
TAXES 954 (119 ) 3,200
1,442
INCOME TAX EXPENSE (BENEFIT): Current
income taxes 13 13 47 22 Deferred income taxes 273
(58 )
1,097
526 Total Income Tax Expense (Benefit)
286 (45 ) 1,144 548
NET INCOME (LOSS) 668 (74 ) 2,056 894 Net income
attributable to noncontrolling interests (29 ) (42 )
(139 ) (170 )
NET INCOME (LOSS) ATTRIBUTABLE TO
CHESAPEAKE 639 (116 ) 1,917
724 Preferred stock dividends (43 ) (43 ) (171 ) (171
) Redemption of preferred shares of a subsidiary — — (447 ) (69 )
Earnings allocated to participating securities (10 )
— (26 ) (10 )
NET INCOME (LOSS) AVAILABLE
TO COMMON STOCKHOLDERS $ 586 $ (159 ) $ 1,273 $
474
EARNINGS (LOSS) PER COMMON SHARE: Basic $ 0.89
$ (0.24 ) $ 1.93 $ 0.73 Diluted $ 0.81
$ (0.24 ) $ 1.87 $ 0.73
WEIGHTED AVERAGE COMMON
AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions): Basic
660 656 659 653
Diluted 773 656 772
653
CHESAPEAKE ENERGY
CORPORATION CONDENSED CONSOLIDATED BALANCE SHEETS ($
in millions) (unaudited)
December 31, December 31,
2014 2013 Cash and cash
equivalents $ 4,108 $ 837 Other current assets 3,360
2,819 Total Current Assets 7,468 3,656
Property and equipment, (net) 32,515 37,134 Other assets 768
992 Total Assets $ 40,751 $ 41,782 Current
liabilities $ 5,863 $ 5,515 Long-term debt, net of discounts 11,154
12,886 Other long-term liabilities 1,344 1,834 Deferred income tax
liabilities 4,185 3,407 Total Liabilities
22,546 23,642 Preferred stock 3,062 3,062
Noncontrolling interests 1,302 2,145 Common stock and other
stockholders’ equity 13,841 12,933 Total Equity
18,205 18,140 Total Liabilities and Equity $
40,751 $ 41,782 Common Shares Outstanding (in millions)
663 664
CHESAPEAKE ENERGY
CORPORATION CAPITALIZATION ($ in millions)
(unaudited)
December 31, December 31,
2014 2013 Total debt, net of
unrestricted cash $ 7,427 $ 12,049 Preferred stock 3,062 3,062
Noncontrolling interests(a) 1,302 2,145 Common stock and other
stockholders’ equity 13,841 12,933
Total $ 25,632 $ 30,189 Total net debt to
capitalization ratio 29 % 40 %
(a) Includes third-party ownership as
follows:
CHK Cleveland Tonkawa, L.L.C. $ 1,015 $ 1,015 Chesapeake
Granite Wash Trust 287 314 CHK Utica, L.L.C. — 807 Other —
9 Total $ 1,302 $ 2,145
CHESAPEAKE ENERGY CORPORATION ROLL-FORWARD OF
PROVED RESERVES 12 MONTHS ENDED DECEMBER 31, 2014
(unaudited)
Mmboe(a) Beginning balance, December 31, 2013
2,678 Production (258 ) Acquisitions 14 Divestitures (362 )
Revisions - changes to previous estimates (78 ) Revisions - price
27 Extensions and discoveries 448 Ending balance,
December 31, 2014 2,469 Proved reserves growth
rate before acquisitions and divestitures 5 % Proved reserves
growth rate after acquisitions and divestitures (8 )% Proved
developed reserves 1,864 Proved developed reserves percentage 75 %
PV-10 ($ in millions)(a) $ 22,012
(a) Reserve volumes and PV-10 value estimated using SEC reserve
recognition standards and pricing assumptions based on the trailing
12-month average first-day-of-the-month prices as of December 31,
2014, of $4.35 per mcf of natural gas and $94.98 per bbl of oil,
before field differential adjustments.
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF PV-10 ($ in millions)
(unaudited)
December 31, December 31, 2014
2013 Standardized measure of discounted future
net cash flows $ 17,133 $ 17,390 Discounted future cash flows for
income taxes 4,879 4,286 Discounted future net cash
flows before income taxes (PV-10) $ 22,012 $ 21,676
PV-10 is discounted (at 10%) future net cash flows before income
taxes. The standardized measure of discounted future net cash flows
includes the effects of estimated future income tax expenses and is
calculated in accordance with Accounting Standards Codification
Topic 932. Management uses PV-10 as one measure of the value of the
company's current proved reserves and to compare relative values
among peer companies without regard to income taxes. We also
understand that securities analysts and rating agencies use this
measure in similar ways. While PV-10 is based on prices, costs and
discount factors which are consistent from company to company, the
standardized measure is dependent on the unique tax situation of
each individual company.
The company’s PV-10 and standardized measure were calculated
using the following prices, before field differentials: $4.35 per
mcf of natural gas and $94.98 per bbl of oil as of December 31,
2014, and $3.67 per mcf of natural gas and $96.82 per bbl of oil as
of December 31, 2013, before field differential adjustments.
CHESAPEAKE ENERGY CORPORATION
SUPPLEMENTAL DATA - OIL, NATURAL GAS AND NGL PRODUCTION, SALES
AND INTEREST EXPENSE (unaudited)
Three Months Ended
Twelve Months Ended December 31,
December 31, 2014 2013 2014 2013
Net Production: Oil (mmbbl) 11.2 10.2 42.3 41.1 Natural gas
(bcf) 281.6 270.5 1,095.0 1,094.6 NGL (mmbbl) 9.0 5.9 33.1 20.9 Oil
equivalent (mmboe) 67.1 61.2 257.8 244.4
Oil, natural gas
and NGL Sales ($ in millions): Oil sales $ 749 $ 937 $ 3,682 $
3,911 Oil derivatives – realized gains (losses)(a) 103 (19 ) (185 )
(108 ) Oil derivatives – unrealized gains (losses)(a) 505
116 859 280 Total
Oil Sales 1,357 1,034 4,356
4,083 Natural gas sales 453 498 2,777
2,430 Natural gas derivatives – realized gains (losses)(a) 30 17
(191 ) 9 Natural gas derivatives – unrealized gains (losses)(a)
411 (127 ) 535 (52 )
Total Natural Gas Sales 894 388
3,121 2,387 NGL sales 118
186 703 582 Total NGL
Sales 118 186 703
582 Total Oil, Natural Gas and NGL Sales $ 2,369 $
1,608 $ 8,180 $ 7,052
Average Sales
Price – excluding gains (losses) on derivatives: Oil ($ per
bbl) $ 67.16 $ 91.46 $ 87.13 $ 95.17 Natural gas ($ per mcf) $ 1.61
$ 1.84 $ 2.54 $ 2.22 NGL ($ per bbl) $ 13.11 $ 31.76 $ 21.27 $
27.87 Oil equivalent ($ per boe) $ 19.68 $ 26.49 $ 27.78 $ 28.33
Average Sales Price – including realized gains (losses)
on derivatives: Oil ($ per bbl) $ 76.40 $ 89.58 $ 82.76 $ 92.53
Natural gas ($ per mcf) $ 1.72 $ 1.90 $ 2.36 $ 2.23 NGL ($ per bbl)
$ 13.11 $ 31.76 $ 21.27 $ 27.87 Oil equivalent ($ per boe) $ 21.67
$ 26.44 $ 26.32 $ 27.92
Interest Expense ($ in
millions): Interest(b) $ 40 $ 56 $ 173 $ 169 Derivatives –
realized (gains) losses(c) (2 ) (3 ) (12 ) (9 ) Derivatives –
unrealized (gains) losses(c) (31 ) 10
(72 ) 67 Total Interest Expense $ 7 $ 63
$ 89 $ 227
(a) Realized gains and losses include the
following items: (i) settlements of nondesignated derivatives
related to current period production revenues, (ii) prior period
settlements for option premiums and for early-terminated
derivatives originally scheduled to settle against current period
production revenues, and (iii) gains and losses related to de-
designated cash flow hedges originally designated to settle against
current period production revenues. Unrealized gains and losses
include the change in fair value of open derivatives scheduled to
settle against future period production revenues offset by amounts
reclassified as realized gains and losses during the period.
Although we no longer designate our derivatives as cash flow hedges
for accounting purposes, we believe these definitions are useful to
management and investors in determining the effectiveness of our
price risk management program.
(b) Net of amounts capitalized.
(c) Realized (gains) losses include
settlements related to the current period interest accrual and the
effect of (gains) losses on early termination trades. Unrealized
(gains) losses include changes in the fair value of open interest
rate derivatives offset by amounts reclassified to realized (gains)
losses during the period.
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED CASH FLOW DATA ($ in millions)
(unaudited)
December 31, December 31, THREE
MONTHS ENDED: 2014 2013
Beginning cash $ 90 $ 987
Cash
provided by operating activities 829 1,028
Cash flows from investing activities: Drilling
and completion costs on proved and unproved properties(a) (1,367 )
(1,117 ) Acquisition of proved and unproved properties(b) (280 )
(211 ) Sales of proved and unproved properties 5,082 668 Geological
and geophysical costs (29 ) (17 ) Cash paid to purchase leased rigs
and compressors (25 ) (262 ) Additions to other property and
equipment (26 ) (71 ) Proceeds from sales of other assets 39 126
Additions to investments (3 ) (36 ) Other 1 —
Total cash provided by (used in) investing activities
3,392 (920 )
Cash used in financing
activities (203 ) (258 )
Change in cash and
cash equivalents 4,018 (150 )
Ending
cash $ 4,108 $ 837
(a) Includes capitalized interest of $9
million and $15 million for the three months ended December 31,
2014 and 2013, respectively.
(b) Includes capitalized interest of $120
million and $163 million for the three months ended December 31,
2014 and 2013, respectively.
December 31, December 31,
TWELVE MONTHS ENDED: 2014 2013
Beginning cash $ 837 $ 287
Cash provided by operating activities 4,634
4,614
Cash flows from investing
activities: Drilling and completion costs on proved and
unproved properties(a) (4,534 ) (5,552 ) Acquisition of proved and
unproved properties(b) (1,279 ) (974 ) Sales of proved and unproved
properties 5,781 3,409 Geological and geophysical costs (47 ) (52 )
Cash paid to purchase leased rigs and compressors (499 ) (266 )
Additions to other property and equipment (227 ) (706 ) Proceeds
from sales of other assets 1,003 922 Additions to investments (17 )
— Proceeds from sales of investments 239 71 Decrease in restricted
cash 37 — Other (3 ) 181
Total cash
provided by (used in) investing activities 454
(2,967 )
Cash used in financing activities
(1,817 ) (1,097 )
Change in cash and cash
equivalents 3,271 550
Ending
cash $ 4,108 $ 837
(a) Includes capitalized interest of $39
million and $62 million for the twelve months ended December 31,
2014 and 2013, respectively.
(b) Includes capitalized interest of $553
million and $734 million for the twelve months ended December 31,
2014 and 2013, respectively.
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON
STOCKHOLDERS ($ in millions, except per share data)
(unaudited)
December 31,
September 30, December 31, THREE MONTHS ENDED:
2014 2014 2013
Net income available to common stockholders $ 586 $ 169 $
(159 )
Adjustments, net of tax(a):
Unrealized (gains) losses on derivatives (663 ) (378 ) 13
Restructuring and other termination costs (3 ) (9 ) 28 Impairments
of fixed assets and other 10 9 126 Net (gains) losses on sales of
fixed assets 2 (53 ) (7 ) Losses on purchases of debt and
extinguishment of other financing 2 — 76 Losses on investments — —
84 Provision for legal contingencies 94 61 — Other 6 5 — Redemption
of preferred shares of a subsidiary(a) — 447
—
Adjusted net income available to common
stockholders(b) $ 34 $ 251 $ 161 Preferred stock
dividends 43 43 43 Earnings allocated to participating securities
10 3 —
Total adjusted net income attributable to Chesapeake
$ 87 $ 297 $ 204
Weighted average
fully diluted shares outstanding
(in millions)(c)
775 776 767
Adjusted earnings per share assuming
dilution(b) $ 0.11 $ 0.38 $ 0.27
(a) All adjustments to net income available to common
stockholders reflected net of tax other than the redemption of
preferred shares of a subsidiary.
(b) Adjusted net income and adjusted earnings per share assuming
dilution are not measures of financial performance under GAAP, and
should not be considered as an alternative to net income available
to common stockholders or diluted earnings per share. Adjusted net
income available to common stockholders and adjusted earnings per
share assuming dilution exclude certain items that management
believes affect the comparability of operating results. The company
believes these adjusted financial measures are a useful adjunct to
earnings calculated in accordance with accounting principles
generally accepted in the United States (GAAP) because:
(i) Management uses adjusted net income
available to common stockholders to evaluate the company's
operational trends and performance relative to other oil and
natural gas producing companies.
(ii) Adjusted net income available to common
stockholders is more comparable to earnings estimates provided by
securities analysts.
(iii) Items excluded generally are one-time
items or items whose timing or amount cannot be reasonably
estimated. Accordingly, any guidance provided by the company
generally excludes information regarding these types of items.
(c) Weighted average fully diluted shares outstanding include
shares that were considered antidilutive for calculating earnings
per share in accordance with GAAP.
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON
STOCKHOLDERS ($ in millions, except per share data)
(unaudited)
December 31, December 31, TWELVE
MONTHS ENDED: 2014 2013
Net income available to common stockholders $ 1,273 $ 474
Adjustments, net of tax(a): Unrealized
gains on derivatives (941 ) (100 ) Restructuring and other
termination costs 4 154 Impairments of fixed assets and other 57
341 Net gains on sales of fixed assets (128 ) (187 ) Impairments of
investments 3 6 Net (gain) loss on sales of investments (43 ) 5
Losses on purchases of debt and extinguishment of other financing
126 120 Losses on investments — 84 Provision for legal
contingencies 150 — Other 9 (1 ) Redemption of preferred shares of
a subsidiary(a) 447 69
Adjusted net
income available to common stockholders(b) $ 957
$ 965 Preferred stock dividends 171 171 Earnings
allocated to participating securities 26 10
Total adjusted net income attributable to
Chesapeake $ 1,154 $ 1,146
Weighted
average fully diluted shares outstanding (in
millions)(c) 776 765
Adjusted earnings per
share assuming dilution(b) $ 1.49 $ 1.50
(a) All adjustments to net income available to common
stockholders reflected net of tax other than the redemption of
preferred shares of a subsidiary.
(b) Adjusted net income available to common stockholders and
adjusted earnings per share assuming dilution exclude certain items
that management believes affect the comparability of operating
results. The company believes these adjusted financial measures are
a useful adjunct to earnings calculated in accordance with
accounting principles generally accepted in the United States
(GAAP) because:
(i) Management uses adjusted net income
available to common stockholders to evaluate the company's
operational trends and performance relative to other oil and
natural gas producing companies.
(ii) Adjusted net income available to common
stockholders is more comparable to earnings estimates provided by
securities analysts.
(iii) Items excluded generally are one-time
items or items whose timing or amount cannot be reasonably
estimated. Accordingly, any guidance provided by the company
generally excludes information regarding these types of items.
(c) Weighted average fully diluted shares outstanding include
shares that were considered antidilutive for calculating earnings
per share in accordance with GAAP.
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF OPERATING CASH FLOW AND EBITDA ($ in
millions) (unaudited)
December
31, September 30, December 31, THREE MONTHS
ENDED: 2014 2014 2013
CASH PROVIDED BY OPERATING ACTIVITIES $ 829 $ 1,184 $
1,028 Changes in assets and liabilities 44 109
(33 )
OPERATING CASH FLOW(a) $ 873
$ 1,293 $ 995
December 31, September 30, December 31,
THREE MONTHS ENDED: 2014 2014
2013 NET INCOME $ 668 $ 692 $ (74 )
Interest expense 7 17 63 Income tax expense (benefit) 286 437 (45 )
Depreciation and amortization of other assets 38 37 80 Oil, natural
gas and NGL depreciation, depletion and amortization 706
688 644
EBITDA(b)
$ 1,705 $ 1,871 $ 668
December 31, September 30, December
31, THREE MONTHS ENDED: 2014
2014 2013 CASH PROVIDED BY OPERATING
ACTIVITIES $ 829 $ 1,184 $ 1,028 Changes in assets and
liabilities 44 109 (33 ) Interest expense, net of unrealized gains
(losses) on derivatives 38 11 53 Oil, natural gas and NGL
derivative gains (losses), net 1,049 564 (13 ) Cash receipts
(payments) on oil, natural gas and NGL derivative settlements, net
(88 ) 34 30 Stock-based compensation — (19 ) (20 ) Restructuring
and other termination costs (3 ) 42 (11 ) Impairments of fixed
assets and other (14 ) (15 ) (166 ) Net gains (losses) on sales of
fixed assets (2 ) 86 12 Losses on investments (7 ) (27 ) (189 )
Provision for legal contingencies (134 ) (100 ) — Losses on
purchases of debt and extinguishment of other financing (2 ) — (3 )
Other items (5 ) 2 (20 )
EBITDA(b) $ 1,705 $ 1,871 $ 668
(a) Operating cash flow represents net cash provided by
operating activities before changes in assets and liabilities.
Operating cash flow is presented because management believes it is
a useful adjunct to net cash provided by operating activities under
GAAP. Operating cash flow is widely accepted as a financial
indicator of an oil and natural gas company's ability to generate
cash that is used to internally fund exploration and development
activities and to service debt. This measure is widely used by
investors and rating agencies in the valuation, comparison, rating
and investment recommendations of companies within the oil and
natural gas exploration and production industry. Operating cash
flow is not a measure of financial performance under GAAP and
should not be considered as an alternative to cash flows from
operating, investing or financing activities as an indicator of
cash flows, or as a measure of liquidity.
(b) Ebitda represents net income before interest expense, income
taxes, and depreciation, depletion and amortization expense. Ebitda
is presented as a supplemental financial measurement in the
evaluation of our business. We believe that it provides additional
information regarding our ability to meet our future debt service,
capital expenditures and working capital requirements. This measure
is widely used by investors and rating agencies in the valuation,
comparison, rating and investment recommendations of companies.
Ebitda is also a financial measurement that, with certain
negotiated adjustments, is reported to our lenders pursuant to our
bank credit agreements and is used in the financial covenants in
our bank credit agreements. Ebitda is not a measure of financial
performance under GAAP. Accordingly, it should not be considered as
a substitute for net income, income from operations or cash flow
provided by operating activities prepared in accordance with
GAAP.
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF OPERATING CASH FLOW AND EBITDA ($ in
millions) (unaudited)
December 31, December 31,
TWELVE MONTHS ENDED: 2014 2013
CASH PROVIDED BY OPERATING ACTIVITIES $ 4,634 $ 4,614
Changes in assets and liabilities 392 344
OPERATING CASH FLOW(a) $ 5,026 $ 4,958
December 31, December 31, TWELVE
MONTHS ENDED: 2014 2013
NET INCOME $ 2,056 $ 894 Interest expense 89 227 Income tax
expense 1,144 548 Depreciation and amortization of other assets 232
314 Oil, natural gas and NGL depreciation, depletion and
amortization 2,683 2,589
EBITDA(b) $ 6,204 $ 4,572
December
31, December 31, TWELVE MONTHS ENDED:
2014 2013 CASH PROVIDED BY OPERATING
ACTIVITIES $ 4,634 $ 4,614 Changes in assets and liabilities
392 344 Interest expense, net of unrealized gains (losses) on
derivatives 161 159 Oil, natural gas and NGL derivative gains
(losses), net 1,018 129 Cash receipts on oil, natural gas and NGL
derivative settlements, net 264 91 Stock-based compensation (59 )
(98 ) Restructuring and other termination costs 15 (175 )
Impairments of fixed assets and other (58 ) (483 ) Net gains on
sales of fixed assets 199 302 Provision for legal contingencies
(234 ) — Losses on investments (80 ) (229 ) Net gain (loss) on
sales of investments 67 (7 ) Losses on purchases of debt and
extinguishment of other financing (63 ) (40 ) Other items
(52 ) (35 )
EBITDA(b) $ 6,204 $ 4,572
(a) Operating cash flow represents net cash provided by
operating activities before changes in assets and liabilities.
Operating cash flow is presented because management believes it is
a useful adjunct to net cash provided by operating activities under
GAAP. Operating cash flow is widely accepted as a financial
indicator of an oil and natural gas company's ability to generate
cash which is used to internally fund exploration and development
activities and to service debt. This measure is widely used by
investors and rating agencies in the valuation, comparison, rating
and investment recommendations of companies within the oil and
natural gas exploration and production industry. Operating cash
flow is not a measure of financial performance under GAAP and
should not be considered as an alternative to cash flows from
operating, investing or financing activities as an indicator of
cash flows, or as a measure of liquidity.
(b) Ebitda represents net income before interest expense, income
taxes, and depreciation, depletion and amortization expense. Ebitda
is presented as a supplemental financial measurement in the
evaluation of our business. We believe that it provides additional
information regarding our ability to meet our future debt service,
capital expenditures and working capital requirements. This measure
is widely used by investors and rating agencies in the valuation,
comparison, rating and investment recommendations of companies.
Ebitda is also a financial measurement that, with certain
negotiated adjustments, is reported to our lenders pursuant to our
bank credit agreements and is used in the financial covenants in
our bank credit agreements. Ebitda is not a measure of financial
performance under GAAP. Accordingly, it should not be considered as
a substitute for net income, income from operations or cash flow
provided by operating activities prepared in accordance with
GAAP.
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED EBITDA ($ in millions)
(unaudited)
December 31,
September 30, December 31, THREE MONTHS ENDED:
2014 2014 2013
EBITDA $ 1,705 $ 1,871 $ 668
Adjustments:
Unrealized (gains) losses on oil, natural gas and NGL derivatives
(916 ) (622 ) 11 Restructuring and other termination costs (5 ) (14
) 45 Impairments of fixed assets and other 14 15 203 Net (gains)
losses on sales of fixed assets 3 (86 ) (12 ) Net loss on sales of
investments — — 136 Losses on purchases of debt and extinguishment
of other financing 2 — 123 Provision for legal contingencies 134
100 — Net income attributable to noncontrolling interests (29 ) (30
) (42 ) Other 8 2 —
Adjusted EBITDA(a) $ 916 $ 1,236
$ 1,132
December
31, December 31, TWELVE MONTHS ENDED:
2014 2013 EBITDA $ 6,204 $ 4,572
Adjustments: Unrealized gains on oil, natural gas and
NGL derivatives (1,394 ) (228 ) Restructuring and other termination
costs 7 248 Impairments of fixed assets and other 88 550 Net gains
on sales of fixed assets (199 ) (302 ) Losses on investments 5 146
Net (gain) loss on sales of investments (67 ) 7 Losses on purchases
of debt and extinguishment of other financing 197 193 Provision for
legal contingencies 234 — Net income attributable to noncontrolling
interests (139 ) (170 ) Other 9 —
Adjusted EBITDA(a) $ 4,945 $ 5,016
(a) Adjusted ebitda excludes certain items that management
believes affect the comparability of operating results. The company
believes these non-GAAP financial measures are a useful adjunct to
ebitda because:
(i) Management uses adjusted ebitda to
evaluate the company's operational trends and performance relative
to other oil and natural gas producing companies.
(ii) Adjusted ebitda is more comparable to
estimates provided by securities analysts.
(iii) Items excluded generally are one-time
items or items whose timing or amount cannot be reasonably
estimated. Accordingly, any guidance provided by the company
generally excludes information regarding these types of items.
Accordingly, adjusted EBITDA should not be
considered as a substitute for net income, income from operations
or cash flow provided by operating activities prepared in
accordance with GAAP.
SCHEDULE "A” CHESAPEAKE ENERGY CORPORATION
MANAGEMENT’S OUTLOOK AS OF FEBRUARY 25, 2015
Chesapeake periodically provides
management guidance on certain factors that affect the company’s
future financial performance.
Year Ending 12/31/2015 Adjusted Production Growth(a) 3% - 5%
Absolute Production Liquids - mbbls 62 – 64 Oil - mbbls 39 – 40
NGL(b) - mbbls 23 – 24 Natural gas - bcf 1,035 – 1,055 Total
absolute production - mmboe 235 – 240 Absolute daily rate - mboe
645 – 655 Estimated Realized Hedging Effects(c) (based on 2/23/15
strip prices): Oil - $/bbl $19.94 Natural gas - $/mcf $0.31
Estimated Basis/Gathering/Marketing/Transportation Differentials to
NYMEX Prices: Oil - $/bbl $7.00 – 9.00 NGL - $/bbl $48.00 – 52.00
Natural gas - $/mcf $1.70 – 1.90 Fourth quarter MVC estimate ($ in
millions) ($180) – (200) Operating Costs per Boe of Projected
Production: Production expense $4.50 – 5.00 Production taxes $0.45
– 0.55 General and administrative(d) $1.45 – 1.55 Stock-based
compensation (noncash) $0.20 – 0.25 DD&A of natural gas and
liquids assets $10.50 – 11.50 Depreciation of other assets $0.60 –
0.70 Interest expense(e) $1.00 – 1.10 Other ($ millions):
Marketing, gathering and compression net margin(f) ($40 – 60) Net
income attributable to noncontrolling interests and other(g) ($30 –
50) Book Tax Rate 37% Capital Expenditures ($ in millions)(h)
$3,500 – 4,000 Capitalized Interest ($ in millions) $500 Total
Capital Expenditures ($ in millions) $4,000 – 4,500
(a) Based on 2014 production of 622 mboe/day adjusted for 2014
sales and the potential sale of Cleveland Tonkawa assets in
2015.
(b) Assumes ethane recovery in the Utica to fulfill Chesapeake’s
pipeline commitments, no ethane recovery in the Powder River Basin
and partial ethane recovery in the Mid-Continent and Eagle
Ford.
(c) Includes expected settlements for commodity derivatives
adjusted for option premiums. For derivatives closed early,
settlements are reflected in the period of original contract
expiration.
(d) Excludes expenses associated with stock-based
compensation.
(e) Excludes unrealized gains (losses) on interest rate
derivatives.
(f) Includes revenue and operating expenses and excludes
depreciation and amortization of other assets
(g) Net income attributable to noncontrolling interests of
Chesapeake Granite Wash Trust and CHK Cleveland Tonkawa L.L.C.
(h) Includes capital expenditures for drilling and completion,
acquisition of unproved properties, geological and geophysical
costs and other property and plant and equipment
Oil, Natural Gas and NGL Hedging Activities
Chesapeake enters into oil, natural gas and NGL derivative
transactions in order to mitigate a portion of its exposure to
adverse changes in market prices. Please see the quarterly reports
on Form 10-Q and annual reports on Form 10-K filed by Chesapeake
with the SEC for detailed information about derivative instruments
the company uses, its quarter-end and year-end derivative positions
and accounting for oil, natural gas and NGL derivatives.
As of January 31, 2015, the company had downside protection on
approximately 43% of its projected 2015 oil production at an
average price of $93.39 per bbl of which 11% is hedged under collar
arrangements with upside to an average NYMEX price of $90/bbl and
exposure below an average NYMEX price of $80/bbl. Approximately 43%
of the company's projected 2015 natural gas production had downside
protection at an average price of $4.21 per thousand cubic feet of
natural gas, of which 20% is hedged under collar arrangements with
upside to an average NYMEX price of $4.29/mcf and exposure below an
average NYMEX price of $3.37/mcf.
The company’s crude oil hedging positions as of January 31,
2015, were as follows:
Open Crude Oil Swaps; Gains (Losses) from Closed Crude
Oil Trades and Call Option Premiums
Total Gains from Closed Trades Avg.
NYMEX and Premiums for Open Swaps Price of Call Options
(mbbls) Open Swaps ($ in millions) Q1 2015 3,834 $
94.07 $ 50 Q2 2015 3,041 94.49 61 Q3 2015 2,868 94.82 62 Q4 2015
2,714 95.15 63 Total 2015 12,457
$ 94.58 $ 236 Total 2016 – 2022 — — $
117
Crude Oil Three-Way Collars
Open
Avg. NYMEX Avg. NYMEX Avg. NYMEX Collars Sold Put Bought Put
Sold Call (mbbls) Price Price
Price Q1 2015 1,080 $ 80.00 $ 90.00 $ 98.94 Q2 2015 1,092 80.00
90.00 98.94 Q3 2015 1,104 80.00 90.00 98.94 Q4 2015 1,104
80.00 90.00 98.94 Total
2015 4,380 $ 80.00 $ 90.00 $ 98.94
Crude Oil Net Written Call Options
Call Options Avg. NYMEX
(mbbls) Strike Price Q1 2015 1,485 $ 100.00 Q2
2015 3,349 91.89 Q3 2015 3,386 91.89 Q4 2015 3,386
91.89 Total 2015 11,606 $ 92.93 Total 2016 –
2017 24,220 $ 100.07
The company’s natural gas hedging positions as of January 31,
2015, were as follows:
Open Natural Gas Swaps; Gains (Losses) from Closed
Natural Gas Trades and Call Option Premiums
Total Gains (Losses) from Closed
Trades Avg. NYMEX and Premiums for Open Swaps Price of Call Options
(bcf) Open Swaps ($ in millions) Q1 2015 81 $
4.53 $ (39 ) Q2 2015 53 3.95 (30 ) Q3 2015 52 3.94 (31 ) Q4 2015 52
3.94 (31 ) Total 2015 238 $ 4.14
$ (131 ) Total 2016 – 2022 37 $ 3.95 $ (187 )
Natural Gas Three-Way Collars
Avg. NYMEX Avg. NYMEX Avg. NYMEX Open Collars Sold Bought
Sold Call (bcf) Put Price Put Price
Price Q1 2015 100 $ 3.36 $ 4.42 $ 4.65 Q2 2015 35 3.38 4.17
4.37 Q3 2015 36 3.38 4.17 4.37 Q4 2015 36 3.38
4.17 4.37 Total 2015 207
$ 3.37 $ 4.29 $ 4.51
Natural Gas Net
Written Call Options
Call Options Avg. NYMEX (bcf)
Strike Price Total 2016 – 2020 193 $ 9.92
Natural Gas Basis Protection Swaps
Volume Avg. NYMEX
(bcf) plus/(minus) Q1 2015 28 $ 1.28 Q2 2015 8 (0.34 ) Q3
2015 8 (0.33 ) Q4 2015 8 (0.33 ) Total 2015
52 $ 0.55 Total 2016 - 2022 8 $
(1.02 )
Chesapeake Energy CorporationInvestor Relations:Brad Sylvester,
CFA, 405-935-8870ir@chk.comorMedia Relations:Gordon Pennoyer,
405-935-8878media@chk.com
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