Chesapeake Energy Corporation (NYSE:CHK) today reported
financial and operational results for the 2015 second quarter.
Highlights include:
• Production averaged approximately 703,000 boe per
day, an increase of 13% year over year, adjusted for asset
sales
• Adjusted net loss of $0.11 per fully diluted share
and adjusted ebitda of $600 million
• 2015 total production guidance increased to 667 –
677 mboe per day, up 4% from midpoint of prior guidance
• 2015 production and general and administrative
expense guidance lowered
• 2015 capital guidance maintained at $3.5 – $4.0
billion
• Strategic asset sales, joint ventures and
participation agreements being pursued in multiple operating
areas
Doug Lawler, Chesapeake’s Chief Executive Officer, commented,
“The downturn in commodity prices has presented a severe test to
our industry. Despite the challenges, we remain focused on lowering
costs and improving operational efficiencies in our portfolio of
high-quality assets. Production for the quarter was very strong,
growing by 13% over last year and 2% sequentially when adjusting
for asset sales, primarily driven by base optimization and
increased well productivity from larger completions. We are
currently expecting a stronger production trajectory as we enter
2016 and, as a result, we have raised our 2015 production guidance
by 4%. We currently expect our 2015 exit rate to be approximately
660,000 barrels of oil equivalent per day, despite our voluntary
curtailment of 50,000 net boe per day and the sharply reduced 2015
drilling activity. Our 2015 second quarter drilling and completion
capital program was executed as planned, and we expect to stay
within our annual capex guidance of $3.5 – $4.0 billion. While we
strive to remain flexible in the face of lower commodity prices, we
continue to focus on driving our costs lower. We have reduced our
guidance for production and general and administrative expenses due
to the outstanding job our employees have done in managing our
controllable costs.”
Lawler continued, “The improvements in our capital efficiency
over the last two years have served to increase the unrecognized
value of our assets. Further, I believe the strength and
optionality of our portfolio provides meaningful opportunities to
increase our liquidity and future cash flow. As a result, we are
reviewing opportunities in multiple operating areas to create
additional value through strategic asset sales, joint venture
agreements and participation, or farmout agreements. Options for
potential transaction proceeds include additional drilling in 2016
and enhancing our capital structure. We are not finished with the
transformation of Chesapeake into a top-tier E&P company, and
we look forward to the opportunities that lie ahead.”
2015 Second Quarter Financial Results
For the 2015 second quarter, Chesapeake reported a net loss
available to common stockholders of $4.151 billion, or $6.27 per
fully diluted share, which compares to net income available to
common stockholders of $145 million, or $0.22 per fully diluted
share, in the 2014 second quarter. Items typically excluded by
securities analysts in their earnings estimates reduced 2015 second
quarter net income by approximately $4.025 billion on an after-tax
basis and are presented on Page 12 of this release. The primary
source of this reduction was an impairment in the carrying value of
Chesapeake's oil and natural gas properties largely resulting from
significant decreases in the trailing 12-month average
first-day-of-the-month oil and natural gas prices as of June 30,
2015, compared to March 31, 2015. Adjusting for this and other
items, the 2015 second quarter net loss available to common
stockholders was $126 million, or $0.11 per fully diluted share,
which compares to adjusted net income available to common
stockholders of $235 million, or $0.36 per fully diluted share, in
the 2014 second quarter.
Adjusted ebitda was $600 million in the 2015 second quarter,
compared to $1.277 billion in the 2014 second quarter. Operating
cash flow was $606 million in the 2015 second quarter, compared to
$1.269 billion in the 2014 second quarter. The year-over-year
decreases in adjusted ebitda and operating cash flow were primarily
the result of lower realized oil, natural gas and natural gas
liquid (NGL) prices, partially offset by increases in realized
hedging gains and lower production and general and administrative
(G&A) costs.
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 12 – 16 of this
release.
2015 Second Quarter Average Daily Production of 703,000 Boe
Increased 13% Year Over Year and 2% Sequentially, Adjusted for
Asset Sales
Chesapeake’s daily production for the 2015 second quarter
averaged approximately 703,000 barrels of oil equivalent (boe), a
year-over-year increase of 13%, adjusted for asset sales. Average
daily production in the 2015 second quarter consisted of
approximately 119,500 barrels (bbls) of oil, 3.0 billion cubic feet
(bcf) of natural gas and 79,200 bbls of NGL, which represent
year-over-year increases of 11%, 11% and 24%, respectively,
adjusted for asset sales.
Capital Spending and Cost Overview
Chesapeake’s 2015 second quarter drilling and completion capital
expenditures decreased 39% sequentially to approximately $787
million, and capital expenditures for leasehold, geological and
geophysical costs and other property, plant and equipment decreased
11% sequentially to approximately $56 million, for a total of
approximately $843 million. Total capital expenditures, including
capitalized interest of $114 million, decreased 36% and 38% to
approximately $957 million in the 2015 second quarter, compared to
approximately $1.5 billion in the 2015 first quarter and $1.6
billion in the 2014 second quarter, respectively, and are detailed
below.
2015 2015 2014
Activity Comparison Q2 Q1
Q2 Average operated rig count 26 54 65 Gross wells completed
121 261 294 Gross wells spud 109 244 286 Gross wells connected
173 262 275
Type of Cost ($ in millions)
Drilling and completion costs
$787
$1,300
$1,131
Leasehold, G&G and other PP&E 56 63
184
Subtotal capital spending $843 $1,363
$1,315 Capitalized interest 114 123 155 Purchases of
previously leased equipment — — 82
Total
capital spending $957 $1,486
$1,552
Chesapeake's focus on cost discipline continued to generate
reductions in production and G&A expenses. Production expenses
during the 2015 second quarter were $4.32 per boe. G&A expenses
(including stock-based compensation) during the 2015 second quarter
were $1.08 per boe. Combined production expenses and G&A
expenses (including stock-based compensation) during the 2015
second quarter were $5.40 per boe, a decrease of 8% year over
year.
A summary of the company’s guidance for 2015 is provided in the
Outlook dated August 5, 2015, beginning on Page 17.
Operational Results – Southern Division
Eagle Ford Shale (South Texas): Eagle Ford net production
averaged approximately 105 thousand barrels of oil equivalent
(mboe) per day (223 gross operated mboe per day) during the 2015
second quarter, a decrease of 7% sequentially. The sequential
decrease in Eagle Ford production was due to gathering and
treatment facility downtime for more than 60 days in May and June
which reduced total net production volume over that period by
approximately 14 mboe per day. The facility has since been repaired
and was placed back in service July 1, 2015. The 2015 first quarter
average completed well cost was $5.2 million with an average
completed lateral length of 5,700 feet and 20 frac stages, compared
to the full-year 2014 average completed well cost of $5.9 million
with an average completed lateral length of 5,850 feet and 18 frac
stages. Chesapeake continues to realize significant cost reductions
on both a drilling capital per foot and on a completion capital
per-foot basis. That trend is expected to continue in subsequent
quarters while overall completed well costs will increase as the
company invests in longer laterals and larger completions in the
area. The company has drilled six wells with more than 9,000 foot
laterals, is currently drilling a 13,000 foot lateral and intends
to spud its first upper Eagle Ford well in the 2015 third quarter.
Operated rig count in the Eagle Ford averaged six rigs in the 2015
second quarter, down from 20 a year ago, and the company
anticipates maintaining three operated rigs for the second half of
the year.
Haynesville Shale and Bossier Shales (Northwest
Louisiana): Haynesville net production averaged approximately
669 million cubic feet of natural gas (mmcf) per day (1.08 gross
operated bcf per day) during the 2015 second quarter, an increase
of 32% year over year and 9% sequentially. The sequential increase
in Haynesville production was due to outstanding well performance
from 15 new wells turned in line and minimal base decline seen from
wells turned in line in the 2015 first quarter. Significant
production growth realized to date in the Barnett and Haynesville
combined with the anticipated volumes to come online in the second
half of 2015, has allowed the company to decrease the midpoint of
the estimated total midstream volume commitment shortfall payment
in 2015 by $20 million as seen in the Outlook, beginning on Page
17. The 2015 first quarter average completed well cost was $7.9
million with an average completed lateral length of 4,900 feet and
13 frac stages, compared to the full-year 2014 average completed
well cost of $8.4 million with an average completed lateral length
of 4,900 feet and 14 frac stages. Chesapeake's unique continuous
blocks of leasehold provide a competitive advantage and the ability
to extend laterals from two units to four units. In combination
with further enhancement of completions in the Haynesville, this is
significantly improving well performance and profitability in a low
natural gas price environment. Operated rig count in the
Haynesville averaged six rigs in the 2015 second quarter, down from
eight a year ago, and the company anticipates increasing to seven
operated rigs for the second half of the year.
Mid-Continent:
Mississippian Lime (Northern Oklahoma): Mississippian Lime net
production averaged approximately 32 mboe per day (77 gross
operated mboe per day) during the 2015 second quarter, an increase
of 1% sequentially. The 2015 first quarter average completed well
cost was $2.8 million with an average completed lateral length of
4,450 feet and 10 frac stages, compared to the full-year 2014
average completed well cost of $3.0 million with an average
completed lateral length of 4,450 feet and nine frac stages. The
company continues to realize efficiencies, and recent completed
well costs are under $2.7 million. Chesapeake's outstanding
leasehold position and efficient operations continue to deliver
strong returns even in the current oil price environment. Operated
rig count in the Mississippian Lime averaged four rigs in the 2015
second quarter, down from eight a year ago, and the company
anticipates maintaining two operated rigs for the second half of
the year.
Oklahoma STACK (Northwest and Central Oklahoma): The company has
identified multiple stacked and staggered liquids-rich
opportunities on its extensive Oklahoma STACK leasehold position
that is essentially all held by production. Two wells Chesapeake
recently turned in line from the Oswego and Hoxbar formations
delivered peak 24-hour oil rates of 1,955 and 1,515 bbls of oil per
day. Completed costs for the aforementioned wells were $5.9 million
and $7.1 million, respectively. The company believes well costs for
both formations can be driven lower by more than 30% and
anticipates greater efficiencies over time. The company intends to
move a rig into the STACK in the 2015 third quarter which will
focus on the Meramec and other formations.
Operational Results – Northern Division
Utica Shale (Eastern Ohio): Utica net production averaged
approximately 124 mboe per day (222 gross operated mboe per day)
during the 2015 second quarter, an increase of 13% sequentially.
Chesapeake voluntarily curtailed an average of approximately 100
gross mmcf per day of Utica production in July 2015 and is
currently curtailing 275 gross mmcf per day as a result of weak
in-basin natural gas prices and the deterioration of propane
prices. The company anticipates maintaining curtailment until a new
regional pipeline is placed in-service in November 2015. The
pipeline will allow the company to move approximately 350 gross
mmcf per day out of the basin providing a very competitive basin
transportation rate. Chesapeake anticipates a significant pricing
uplift on these volumes due to access to the Gulf Coast market. The
company continues to utilize ethane rejection in order to maximize
its natural gas price realizations. The 2015 first quarter average
completed well cost was $8.5 million with an average completed
lateral length of 8,000 feet and 43 frac stages, compared to the
full-year 2014 average completed well cost of $7.2 million with an
average completed lateral length of 6,200 feet and 29 frac stages.
The company anticipates overall Utica completed well costs will
increase as the company invests in longer laterals and larger
completions in the area. Operated rig count in the Utica averaged
four rigs in the 2015 second quarter, down from eight a year ago,
and the company anticipates maintaining two operated rigs for the
second half of the year.
Marcellus Shale (Northern Pennsylvania): Marcellus net
production averaged approximately 820 mmcf per day (1.84 gross
operated bcf per day) during the 2015 second quarter, a decrease of
1% sequentially. Chesapeake began voluntarily curtailing 300 gross
mmcf per day of Marcellus production in the 2015 first quarter, and
has since increased to 500 gross mmcfe per day in the 2015 second
quarter as result of weak in-basin pricing due to pipeline
constraints. The company anticipates maintaining Marcellus
curtailments for the remainder of the year. The 2015 first quarter
average completed well cost was $7.5 million with an average
completed lateral length of 6,900 feet and 28 frac stages, compared
to the full-year 2014 average completed well cost of $7.5 million
with an average completed lateral length of 6,000 feet and 27 frac
stages. The company continues to realize efficiencies and recent
completed well costs are under $6.7 million. Operated rig count in
the Marcellus averaged one rig in the 2015 second quarter, down
from six a year ago, and the company anticipates maintaining one
operated rig for the second half of the year.
Powder River Basin (PRB) (Wyoming): PRB net production
averaged approximately 20 mboe per day (32 gross operated mboe per
day) during the 2015 second quarter, an increase of 1%
sequentially. The 2015 first quarter average completed well cost
was $11.0 million with an average completed lateral length of 6,000
feet and 22 frac stages, compared to the full-year 2014 average
completed well cost of $10.6 million with an average completed
lateral length of 5,400 feet and 20 frac stages. The company
continues to realize efficiencies and recent completed well costs
are under $8.7 million. Chesapeake continues to optimize its
completions and test various cluster spacing in the Sussex
formation as it has drilled 20 wells to date with 12 of those
currently producing. The company anticipates exclusively drilling
Sussex wells for the remainder of the year with the exception of
two test wells expected to be drilled in the Teapot formation and
the Parkman E formation in the 2015 third and fourth quarters,
respectively. Operated rig count in the PRB averaged one rig in the
2015 second quarter, down from three a year ago, and the company
anticipates maintaining one operated rig for the second half of the
year.
Key Financial and Operational Results
The table below summarizes Chesapeake’s key financial and
operational results during the 2015 second quarter, as compared to
results in prior periods.
Three Months Ended
06/30/15
03/31/15
06/30/14
Oil equivalent production (in mmboe) 63.9 61.8 63.2 Oil production
(in mmbbls) 10.8 11.0 10.3 Average realized oil price ($/bbl)(a)
67.91 62.57 85.23 Oil as % of total production 17 18 16 Natural gas
production (in bcf) 275.4 263.8 271.3 Average realized natural gas
price ($/mcf)(a) 1.01 2.37 2.45 Natural gas as % of total
production 72 71 72 NGL production (in mmbbls) 7.2 6.8 7.7 Average
realized NGL price ($/bbl)(a) 1.90 6.99 21.03 NGL as % of total
production 11 11 12 Production expenses ($/boe) (4.32 ) (4.84 )
(4.46 ) Production taxes ($/boe) (0.52 ) (0.45 ) (1.14 ) General
and administrative costs ($/boe)(b) (0.89 ) (0.72 ) (1.25 )
Stock-based compensation ($/boe) (0.19 ) (0.19 ) (0.18 ) DD&A
of natural gas and liquids properties ($/boe) (9.39 ) (11.08 )
(10.45 ) DD&A of other assets ($/boe) (0.52 ) (0.57 ) (1.25 )
Interest expense ($/boe)(a) (1.12 ) (0.98 ) (0.92 ) Marketing,
gathering and compression net margin ($ in millions)(c) 209 (25 ) 1
Oilfield services net margin ($ in millions)(d) — — 69 Operating
cash flow ($ in millions)(e) 606 910 1,269 Operating cash flow
($/boe) 9.49 14.73 20.07 Adjusted ebitda ($ in millions)(f) 600 928
1,277 Adjusted ebitda ($/boe) 9.37 15.02 20.20 Net income (loss)
available to common stockholders ($ in millions) (4,151 ) (3,782 )
145 Earnings (loss) per share – diluted ($) (6.27 ) (5.72 ) 0.22
Adjusted net income (loss) available to
common stockholders ($ in millions)(g)
(126 ) 42 235 Adjusted earnings (loss) per share – diluted ($)
(0.11 ) 0.11 0.36
(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,
operating expenses and $220 million of unrealized gains on supply
contract derivatives. Excludes depreciation and amortization of
other assets.
(d) Includes revenue,
operating expenses and excludes depreciation and amortization of
other assets.
(e) Defined as cash flow
provided by operating activities before changes in assets and
liabilities.
(f) 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 16.
(g) Defined as net income
available to common stockholders, as adjusted to remove the effects
of certain items detailed on Page 12.
2015 Second Quarter Financial and Operational Results
Conference Call Information
A conference call to discuss this release has been scheduled for
Wednesday, August 5, 2015 at 9:00 am EDT. The telephone number to
access the conference call is 913-312-0648 or toll-free
800-930-1344. The passcode for the call is 8058511.
We encourage those who would like to participate in the call to
place calls between 8:50 and 9:00 am EDT. For those unable to
participate in the live conference call, a replay will be available
for audio playback at 2:00 pm EDT on Wednesday, August 5, 2015, and
will run through 2:00 pm EDT on Wednesday, August 19, 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
8058511. The conference call will also be webcast live at
www.chk.com in the “Investors” section of the company’s website.
The webcast of the conference will be available on the website for
one year.
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 and the effect on the unrecognized value of our
assets, anticipated assets sales and proceeds to be received
therefrom, projected cash flow and liquidity, business strategy and
other opportunities, plans and objectives for future operations
(including joint venture and participation agreements), 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 June
30, 2015 2014 REVENUES: Oil,
natural gas and NGL $ 728 $ 1,704 Marketing, gathering and
compression 2,305 3,167 Oilfield services — 281 Total
Revenues 3,033 5,152
OPERATING EXPENSES: Oil,
natural gas and NGL production 276 282 Production taxes 34 72
Marketing, gathering and compression 2,096 3,166 Oilfield services
— 212 General and administrative 69 90 Restructuring and other
termination costs (4 ) 33 Provision for legal contingencies 334 —
Oil, natural gas and NGL depreciation, depletion and amortization
601 661 Depreciation and amortization of other assets 34 79
Impairment of oil and natural gas properties 5,015 — Impairments of
fixed assets and other 84 40 Net (gains) losses on sales of fixed
assets 1 (93 ) Total Operating Expenses 8,540 4,542
INCOME (LOSS) FROM OPERATIONS (5,507 ) 610
OTHER INCOME (EXPENSE): Interest expense (71 ) (27 ) Losses
on investments (17 ) (24 ) Losses on purchases of debt — (195 )
Other income (expense) (1 ) 7 Total Other Expense (89 ) (239
)
INCOME (LOSS) BEFORE INCOME TAXES (5,596 ) 371
INCOME TAX EXPENSE (BENEFIT): Current income taxes (6 ) 5
Deferred income taxes (1,500 ) 136 Total Income Tax Expense
(Benefit) (1,506 ) 141
NET INCOME (LOSS) (4,090 ) 230
Net income attributable to noncontrolling interests (18 ) (39 )
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE (4,108 ) 191
Preferred stock dividends (43 ) (43 ) Earnings allocated to
participating securities — (3 )
NET INCOME (LOSS)
AVAILABLE TO COMMON STOCKHOLDERS $ (4,151 ) $ 145
EARNINGS (LOSS) PER COMMON SHARE: Basic $ (6.27 ) $ 0.22
Diluted $ (6.27 ) $ 0.22
WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in millions):
Basic 662 659 Diluted 662 659
CHESAPEAKE ENERGY CORPORATION CONDENSED
CONSOLIDATED STATEMENTS OF OPERATIONS ($ in millions, except
per share data) (unaudited)
Six Months Ended June 30,
2015 2014 REVENUES: Oil, natural gas
and NGL $ 1,813 $ 3,471 Marketing, gathering and compression 3,980
6,182 Oilfield services — 545 Total Revenues 5,793
10,198
OPERATING EXPENSES: Oil, natural gas
and NGL production 575 570 Production taxes 62 122 Marketing,
gathering and compression 3,796 6,147 Oilfield services — 431
General and administrative 125 169 Restructuring and other
termination costs (14 ) 26 Provision for legal contingencies 359 —
Oil, natural gas and NGL depreciation, depletion and amortization
1,285 1,288 Depreciation and amortization of other assets 69 157
Impairment of oil and natural gas properties 9,991 — Impairments of
fixed assets and other 88 60 Net (gains) losses on sales of fixed
assets 4 (115 ) Total Operating Expenses 16,340 8,855
INCOME (LOSS) FROM OPERATIONS (10,547 ) 1,343
OTHER INCOME (EXPENSE): Interest expense (122 ) (66 ) Losses
on investments (24 ) (45 ) Net gain on sales of investments — 67
Losses on purchases of debt — (195 ) Other income 5 13
Total Other Expense (141 ) (226 )
INCOME (LOSS) BEFORE
INCOME TAXES (10,688 ) 1,117
INCOME TAX EXPENSE
(BENEFIT): Current income taxes (6 ) 8 Deferred income taxes
(2,872 ) 413 Total Income Tax Expense (Benefit) (2,878 ) 421
NET INCOME (LOSS) (7,810 ) 696 Net income
attributable to noncontrolling interests (37 ) (80 )
NET INCOME
(LOSS) ATTRIBUTABLE TO CHESAPEAKE (7,847 ) 616 Preferred
stock dividends (86 ) (86 ) Earnings allocated to participating
securities — (12 )
NET INCOME (LOSS) AVAILABLE TO COMMON
STOCKHOLDERS $ (7,933 ) $ 518
EARNINGS (LOSS) PER
COMMON SHARE: Basic $ (11.99 ) $ 0.79 Diluted $ (11.99 )
$ 0.78
WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in millions):
Basic 662 658 Diluted 662 760
CHESAPEAKE ENERGY CORPORATION CONDENSED CONSOLIDATED
BALANCE SHEETS ($ in millions) (unaudited)
June 30,
December 31,
2015
2014 Cash and cash equivalents $ 2,051 $ 4,108
Other current assets 2,180 3,360 Total Current Assets 4,231
7,468 Property and equipment, (net) 23,615 32,515
Other assets 752 768 Total Assets $ 28,598 $ 40,751
Current liabilities $ 5,128 $ 5,863 Long-term debt, net of
discounts 10,655 11,154 Other long-term liabilities 1,164 1,344
Deferred income tax liabilities 1,408 4,185 Total
Liabilities 18,355 22,546 Preferred stock 3,062 3,062
Noncontrolling interests 1,285 1,302 Common stock and other
stockholders’ equity 5,896 13,841 Total Equity 10,243
18,205 Total Liabilities and Equity $ 28,598 $ 40,751
Common Shares Outstanding (in millions) 663 663
CHESAPEAKE ENERGY CORPORATION
CAPITALIZATION ($ in millions) (unaudited)
June 30, December
31, 2015 2014 Total
debt, net of unrestricted cash $ 9,493 $ 7,427 Preferred stock
3,062 3,062 Noncontrolling interests(a) 1,285 1,302 Common stock
and other stockholders’ equity 5,896 13,841 Total $
19,736
$ 25,632 Total net debt to capitalization
ratio 48 % 29 %
(a) Includes third-party
ownership as follows:
CHK Cleveland Tonkawa, L.L.C
$
1,015
$
1,015
Chesapeake Granite Wash Trust
270
287
Total
$
1,285
$
1,302
CHESAPEAKE ENERGY CORPORATION SUPPLEMENTAL
DATA –
OIL, NATURAL GAS AND NGL PRODUCTION, SALES AND
INTEREST EXPENSE (unaudited)
Three Months Ended
Six Months Ended June 30,
June 30, 2015 2014 2015
2014 Net Production: Oil (mmbbl) 10.8 10.3 21.8 20.2
Natural gas (bcf) 275.4 271.3 539.2 531.4 NGL (mmbbl) 7.2 7.7 14.0
15.2 Oil equivalent (mmboe) 63.9 63.2 125.7 124.0
Oil, natural gas and NGL Sales ($ in
millions):
Oil sales $ 557 $ 1,006 $ 1,008 $ 1,928 Oil derivatives – realized
gains (losses)(a) 182 (127 ) 417 (210 ) Oil derivatives –
unrealized gains (losses)(a) (234 ) (113 ) (344 ) (103 ) Total Oil
Sales 505 766 1,081 1,615
Natural gas sales 206 750 631 1,754 Natural gas derivatives –
realized gains (losses)(a) 71 (86 ) 271 (240 ) Natural gas
derivatives – unrealized gains (losses)(a) (67 ) 113 (231 )
(41 ) Total Natural Gas Sales 210 777 671
1,473 NGL sales 13 161 61 383
Total NGL Sales 13 161 61 383
Total Oil, Natural Gas and NGL Sales $ 728 $ 1,704 $
1,813 $ 3,471
Average Sales Price –
excluding gains (losses) on derivatives: Oil ($ per bbl) $
51.21 $ 97.49 $ 46.16 $ 95.59 Natural gas ($ per mcf) $ 0.75 $ 2.76
$ 1.17 $ 3.30 NGL ($ per bbl) $ 1.90 $ 21.03 $ 4.37 $ 25.10 Oil
equivalent ($ per boe) $ 12.13 $ 30.32 $ 13.52 $ 32.79
Average Sales Price – including realized gains (losses) on
derivatives: Oil ($ per bbl) $ 67.91 $ 85.23 $ 65.22 $ 85.16
Natural gas ($ per mcf) $ 1.01 $ 2.45 $ 1.67 $ 2.85 NGL ($ per bbl)
$ 1.90 $ 21.03 $ 4.37 $ 25.10 Oil equivalent ($ per boe) $ 16.08 $
26.97 $ 18.99 $ 29.16
Interest Expense ($ in
millions): Interest(b) $ 72 $ 61 $ 134 $ 119 Derivatives –
realized (gains) losses(c) (1 ) (3 ) (2 ) (6 ) Derivatives –
unrealized (gains) losses(c) — (31 ) (10 ) (47 ) Total
Interest Expense $ 71 $ 27 $ 122 $ 66
(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)
June 30, June 30, THREE MONTHS ENDED:
2015 2014 Beginning cash
$ 2,907 $ 1,004
Net cash provided by
operating activities 314 1,352
Cash
flows from investing activities: Drilling and completion
costs(a) (862 ) (1,099 ) Acquisitions of proved and unproved
properties(b) (138 ) (169 ) Divestitures of proved and unproved
properties (7 ) 199 Additions to other property and equipment (35 )
(101 ) Cash paid to purchase leased rigs and compressors — (82 )
Proceeds from sales of other property and equipment 5 474 Additions
to investments (3 ) (2 ) Proceeds from sales of investments — —
Other — (1 )
Net cash used in investing activities
(1,040 ) (781 )
Net cash used in financing activities
(130 ) (113 )
Change in cash and cash equivalents (856 ) 458
Ending cash $ 2,051 $ 1,462
(a) Includes capitalized interest of $7
million and $12 million for the three months ended June 30,
2015 and 2014, respectively.
(b) Includes capitalized interest of $104
million and $140 million for the three months ended June 30,
2015 and 2014, respectively.
CHESAPEAKE ENERGY CORPORATION CONDENSED
CONSOLIDATED CASH FLOW DATA ($ in millions)
(unaudited)
June 30, June 30, SIX MONTHS ENDED:
2015 2014 Beginning cash
$ 4,108 $ 837
Net cash provided by
operating activities 737 2,643
Cash
flows from investing activities: Drilling and completion
costs(a) (2,168 ) (1,996 ) Acquisitions of proved and unproved
properties(b) (266 ) (356 ) Divestitures of proved and unproved
properties 14 248 Additions to other property and equipment (93 )
(198 ) Cash paid to purchase leased rigs and compressors — (422 )
Proceeds from sales of other property and equipment 7 713 Additions
to investments (6 ) (5 ) Proceeds from sales of investments — 239
Other — (3 )
Net cash used in investing activities
(2,512 ) (1,780 )
Net cash used in financing
activities (282 ) (238 )
Change in cash and cash
equivalents (2,057 ) 625
Ending cash $ 2,051
$ 1,462
(a) Includes capitalized interest of $18
million and $28 million for the six months ended June 30, 2015
and 2014, respectively.
(b) Includes capitalized interest of $212
million and $298 million for the six months ended June 30,
2015 and 2014, respectively.
CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF
ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS ($ in
millions, except per share data) (unaudited)
June 30,
March 31, June 30, THREE MONTHS
ENDED: 2015 2015 2014
Net income (loss) available to common stockholders $
(4,151 ) $ (3,782 ) $ 145
Adjustments, net of tax:
Unrealized (gains) losses on commodity derivatives 220 192 (19 )
Unrealized gains on supply contract derivatives (161 ) — —
Restructuring and other termination costs (3 ) (7 ) 20 Provision
for legal contingencies 244 18 — Impairment of oil and natural gas
properties 3,666 3,635 — Impairments of fixed assets and other 61 3
25 Net (gains) losses on sales of fixed assets 1 2 (57 )
Impairments of investments — — 3 Losses on purchases of debt — —
120 Tax rate adjustment — (17 ) — Other (3 ) (2 ) (2 )
Adjusted
net income (loss) available to common stockholders(a) $
(126 ) $ 42 $ 235 Preferred stock dividends 43
43 43 Earnings allocated to participating securities — —
3
Total adjusted net income (loss) attributable to
Chesapeake $ (83 ) $ 85 $ 281
Weighted
average fully diluted shares outstanding
(in millions)(b)
777 776 776
Adjusted earnings (loss) per share assuming
dilution(a) $ (0.11 ) $ 0.11 $ 0.36
(a) Adjusted net income and adjusted
earnings per share assuming dilution are not measures of financial
performance under accounting principles generally accepted in the
United States (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 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.
(b) 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)
June 30, June
30, SIX MONTHS ENDED: 2015
2014 Net income (loss) available to common
stockholders $ (7,933 ) $ 518
Adjustments, net of
tax: Unrealized losses on commodity derivatives 412 61
Unrealized gains on supply contract derivatives (161 ) —
Restructuring and other termination costs (10 ) 16 Provision for
legal contingencies 262 — Impairment of oil and natural gas
properties 7,301 — Impairments of fixed assets and other 64 37 Net
(gains) losses on sales of fixed assets 3 (72 ) Impairments of
investments — 3 Net gain on sales of investments — (42 ) Losses on
purchases of debt — 121 Tax rate adjustment (17 ) — Other (5 ) (3 )
Adjusted net income (loss) available to common
stockholders(a) $ (84 ) $ 639 Preferred
stock dividends 86 86 Earnings allocated to participating
securities — 12
Total adjusted net income
attributable to Chesapeake $ 2 $ 737
Weighted average fully diluted shares outstanding (in
millions)(b) 777 776
Adjusted earnings per
share assuming dilution(a) $ 0.00 $ 0.95
(a) Adjusted net income and adjusted
earnings per share assuming dilution are not measures of financial
performance under accounting principles generally accepted in the
United States (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 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.
(b) 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)
June 30, March 31,
June 30, THREE MONTHS ENDED: 2015
2015 2014 CASH PROVIDED BY
OPERATING ACTIVITIES $ 314 $ 423 $ 1,352 Changes in assets and
liabilities 292 487 (83 )
OPERATING CASH
FLOW(a) $ 606 $ 910 $ 1,269
June 30,
March 31, June 30, THREE MONTHS
ENDED: 2015 2015 2014
NET INCOME (LOSS) $ (4,090 ) $ (3,720 ) $ 230
Interest expense 71 51 27 Income tax expense (benefit) (1,506 )
(1,372 ) 141 Depreciation and amortization of other assets 34 35 79
Oil, natural gas and NGL depreciation, depletion and amortization
601 684 661
EBITDA(b) $ (4,890 )
$ (4,322 ) $ 1,138
June 30, March 31, June 30, THREE
MONTHS ENDED: 2015 2015
2014 CASH PROVIDED BY OPERATING ACTIVITIES $
314 $ 423 $ 1,352 Changes in assets and liabilities 292 487 (83 )
Interest expense, net of unrealized gains (losses) on derivatives
71 61 58 Gains (losses) on commodity derivatives, net (48 ) 161
(213 ) Gains on supply contract derivatives, net 220 — — Cash
(receipts) payments on oil, natural gas and NGL derivative
settlements, net (223 ) (413 ) 150 Stock-based compensation (20 )
(23 ) (20 ) Restructuring and other termination costs 4 10 (33 )
Provision for legal contingencies (334 ) (25 ) — Impairment of oil
and natural gas properties (5,015 ) (4,976 ) — Impairments of fixed
assets and other (79 ) (2 ) (39 ) Net gains (losses) on sales of
fixed assets (1 ) (3 ) 93 Losses on investments (17 ) (7 ) (24 )
Losses on purchases of debt — — (61 ) Other items (54 ) (15 ) (42 )
EBITDA(b) $ (4,890 ) $ (4,322 ) $ 1,138 (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)
June 30, June 30, SIX MONTHS
ENDED: 2015 2014 CASH
PROVIDED BY OPERATING ACTIVITIES $ 737 $ 2,643 Changes in
assets and liabilities 779 240
OPERATING CASH
FLOW(a) $ 1,516 $ 2,883
June 30, June 30, SIX
MONTHS ENDED: 2015 2014
NET INCOME (LOSS) $ (7,810 ) $ 696 Interest expense 122 66
Income tax expense (benefit) (2,878 ) 421 Depreciation and
amortization of other assets 69 157 Oil, natural gas and NGL
depreciation, depletion and amortization 1,285 1,288
EBITDA(b) $ (9,212 ) $ 2,628
June 30, June 30, SIX
MONTHS ENDED: 2015 2014
CASH PROVIDED BY OPERATING ACTIVITIES $ 737 $ 2,643 Changes
in assets and liabilities 779 240 Interest expense, net of
unrealized gains (losses) on derivatives 132 113 Gains (losses) on
commodity derivatives, net 113 (595 ) Gains on supply contract
derivatives, net 220 — Cash (receipts) payments on oil, natural gas
and NGL derivative settlements, net (636 ) 318 Stock-based
compensation (43 ) (40 ) Restructuring and other termination costs
14 (24 ) Provision for legal contingencies (359 ) — Impairment of
oil and natural gas properties (9,991 ) — Impairments of fixed
assets and other (81 ) (51 ) Net gains (losses) on sales of fixed
assets (4 ) 115 Losses on investments (24 ) (45 ) Net gain on sales
of investments — 67 Losses on purchases of debt — (61 ) Other items
(69 ) (52 )
EBITDA(b) $ (9,212 ) $ 2,628 (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
ADJUSTED EBITDA ($ in millions) (unaudited)
June
30, March 31, June 30, THREE
MONTHS ENDED: 2015 2015
2014 EBITDA $ (4,890 ) $ (4,322 ) $ 1,138
Adjustments: Unrealized losses on oil, natural gas
and NGL derivatives 301 274 — Unrealized gains on supply contract
derivatives (220 ) — — Restructuring and other termination costs (4
) (10 ) 33 Provision for legal contingencies 334 25 — Impairment of
oil and natural gas properties 5,015 4,976 — Impairments of fixed
assets and other 84 4 40 Net (gains) losses on sales of fixed
assets 1 3 (93 ) Impairments of investments — — 5 Losses on
purchases of debt — — 195 Net income attributable to noncontrolling
interests (18 ) (19 ) (39 ) Other (3 ) (3 ) (2 )
Adjusted
EBITDA(a) $ 600 $ 928 $ 1,277
CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF
ADJUSTED EBITDA ($ in millions) (unaudited)
June 30, June 30,
SIX MONTHS ENDED: 2015 2014
EBITDA $ (9,212 ) $ 2,628
Adjustments:
Unrealized losses on oil, natural gas and NGL derivatives 575 144
Unrealized gains on supply contract derivatives (220 ) —
Restructuring and other termination costs (14 ) 26 Provision for
legal contingencies 359 — Impairment of oil and natural gas
properties 9,991 — Impairments of fixed assets and other 88 60 Net
(gains) losses on sales of fixed assets 4 (115 ) Impairments of
investments — 5 Net gains on sales of investments — (67 ) Losses on
purchases of debt — 195 Net income attributable to noncontrolling
interests (37 ) (80 ) Other (6 ) (4 )
Adjusted
EBITDA(a) $ 1,528 $ 2,792 (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.
CHESAPEAKE ENERGY CORPORATION MANAGEMENT’S OUTLOOK
AS OF AUGUST 5, 2015
Chesapeake periodically provides
management guidance on certain factors that affect the company’s
future financial performance. Changes from the company's May 6,
2015 Outlook are italicized bold below.
Year Ending 12/31/2015 Adjusted Production Growth(a)
5% –
7% Absolute Production Liquids - mbbls
67 – 69 Oil -
mbbls
41.5 – 42.5 NGL(b) - mbbls
25.5 – 26.5 Natural
gas - bcf
1,055 – 1,070 Total absolute production - mmboe
243 – 247 Absolute daily rate - mboe
667 – 677
Estimated Realized Hedging Effects(c) (based on 7/31/15 strip
prices): Oil - $/bbl
$20.01 Natural gas - $/mcf
$0.37
Estimated Basis/Gathering/Marketing/Transportation Differentials to
NYMEX Prices: Oil - $/bbl $7.00 – 9.00 Natural gas - $/mcf
$1.65
– 1.85 NGL - $/bbl $49.00 – 51.00 Fourth quarter minimum volume
commitment (MVC) estimate ($ in millions)
($160) – (180)
Operating Costs per Boe of Projected Production: Production expense
$4.40 – 4.90 Production taxes $0.45 – 0.55 General and
administrative(d)
$1.25 – 1.35 Stock-based compensation
(noncash) $0.20 – 0.25 DD&A of natural gas and liquids assets
$8.50 – 9.50 Depreciation of other assets $0.60 – 0.70
Interest expense(e) $1.10 – 1.20 Other ($ millions): Marketing,
gathering and compression net margin(f) ($40 – 60) Net income
attributable to noncontrolling interests and other(g)
($60 –
65) Book Tax Rate 25% – 30% Capital Expenditures ($ in
millions)(h) $3,000 – 3,500 Capitalized Interest ($ in millions)
$475 Total Capital Expenditures ($ in millions) $3,475 – 3,975
(a) Based on 2014 production of 622 mboe
per day adjusted for 2014 sales and the potential sale of Cleveland
Tonkawa asset 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. Excludes depreciation and amortization of other assets
and unrealized gains (losses) on supply contract derivatives.
(g) Net income attributable to
noncontrolling interests of Chesapeake Granite Wash Trust and,
prior to its anticipated sale in the 2015 third quarter, CHK
Cleveland Tonkawa, L.L.C.
(h) Includes capital expenditures for
drilling and completion, leasehold, geological and geophysical
costs and other property and plant and equipment.
Oil and Natural Gas Hedging Activities
Chesapeake enters into oil and natural gas 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 derivative positions and
accounting for oil and natural gas derivatives.
As of July 31, 2015, the company had downside protection on
approximately 48% of its remaining projected 2015 oil production at
an average price of $87.64 per bbl of which 11% is hedged under
three-way collar arrangements based on an average bought put NYMEX
price of $90 per bbl and exposure below an average sold put NYMEX
price of $80 per bbl. Approximately 39% of the company's remaining
projected 2015 natural gas production has downside protection at an
average price of $3.87 per mcf, of which 14% is hedged under
three-way collar arrangements based on an average bought put NYMEX
price of $4.17 per mcf and exposure below an average sold put NYMEX
price of $3.38 per mcf.
The company’s crude oil hedging positions as of July 31, 2015
were as follows:
Open Crude Oil Swaps; Gains (Losses) from Closed
Crude Oil Trades and Call Option Premiums
Total Gains from
Closed Trades
Avg. NYMEX and Premiums for Open Swaps Price of Call Options
(mbbls) Open Swaps ($ in millions) Q3 2015
3,788 $ 86.98 $ 62 Q4 2015 3,634 86.89
63 Total Q3 - Q4 2015 7,422 $ 86.94 $
125 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 Q3 2015 1,104 $ 80.00 $ 90.00 $ 98.94 Q4 2015
1,104 80.00 90.00 98.94 Total Q3
- Q4 2015 2,208 $ 80.00 $ 90.00
$ 98.94
Crude Oil Net Written Call Options
Call Options Avg.
NYMEX (mbbls) Strike Price Q3 2015 1,868 $ 85.31 Q4 2015
1,868 85.31 Total Q3 - Q4 2015 3,736 $ 85.31
Total 2016 – 2017 24,220 $ 100.07
Crude Oil
Basis Protection Swaps
Volume
Avg. NYMEX
(mbbls)
plus
Q3 2015 3,405 $ 3.52 Q4 2015 2,361 3.14 Total Q3 - Q4
2015 5,766 $ 3.36
The company’s natural gas hedging positions as of July 31, 2015
were as follows:
Open Natural Gas Swaps; Gains (Losses) from Closed
Natural Gas Trades and Call Option Premiums
Total Losses from
Closed Trades and
Avg. NYMEX
Premiums for
Open Swaps Price of Call Options (bcf) Open
Swaps ($ in millions) Q3 2015 78 $ 3.54 $ (31 ) Q4 2015
53 3.94 (31 ) Total Q3 - Q4 2015
131 $ 3.70 $ (62 ) Total 2016 – 2022
169 $ 3.36 $ (187 )
Natural Gas
Three-Way Collars
Avg. NYMEX Avg. NYMEX
Open Collars Sold Bought Avg. NYMEX (bcf)
Put Price Put Price Sold Call Price Q3 2015 36
$ 3.38 $ 4.17 $ 4.37 Q4 2015 35 3.38
4.17 4.37 Total Q3 - Q4 2015 71 $ 3.38
$ 4.17 $ 4.37
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) Q3 2015 37 $ (0.82 ) Q4 2015 15 0.17
Total Q3 - Q4 2015 52 $ (0.54 ) Total 2016 -
2022 48 $ (0.23 )
View source
version on businesswire.com: http://www.businesswire.com/news/home/20150805005512/en/
Chesapeake Energy CorporationINVESTOR CONTACT:Brad
Sylvester, CFA, 405-935-8870ir@chk.comorMEDIA CONTACT:Gordon
Pennoyer 405-935-8878media@chk.com
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