Chesapeake Energy Corporation (NYSE:CHK) today reported
financial and operational results for the 2015 first quarter.
Highlights include:
- Average production of approximately
686,000 boe per day, an increase of 14% year over year, adjusted
for asset sales
- Adjusted net income of $0.11 per
fully diluted share and adjusted ebitda of $928 million
- 2015 total production guidance
increased to 640 – 650 mboe per day
- 2015 capital guidance of
approximately $3.5 – $4.0 billion reiterated
- Additional 600 – 700 new Eagle Ford
locations added following successful down spacing test
results
Doug Lawler, Chesapeake’s Chief Executive Officer, commented,
“Chesapeake is meeting the challenge of low commodity prices
head-on and delivered a very strong first quarter. Adjusted for
asset sales, our production in the 2015 first quarter grew by 14%
compared to the 2014 first quarter. Our cash costs remain at
industry-low levels and we expect our assets to continue delivering
greater efficiencies even as we reduce our activity levels
throughout 2015. We remain on target to balance our capital
spending and our cash flow by year-end, and the capital
efficiencies that we are seeing in each of our operating areas are
helping to strengthen that cash flow. During this challenging
commodity price environment, our talented employees and
high-quality assets are delivering competitive, differential
performance.”
2015 First Quarter Financial Results
For the 2015 first quarter, Chesapeake reported a net loss
available to common stockholders of $3.782 billion, or ($5.72) per
fully diluted share, which compares to net income available to
common stockholders of $374 million, or $0.54 per fully diluted
share in the 2014 first quarter. Items typically excluded by
securities analysts in their earnings estimates reduced 2015 first
quarter net income by approximately $3.824 billion on an after-tax
basis and are presented on Page 11 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 March 31,
2015, compared to December 31, 2014. Adjusting for this and other
items, 2015 first quarter net income available to common
stockholders was $42 million, or $0.11 per fully diluted share,
which compares to adjusted net income available to common
stockholders of $405 million, or $0.59 per fully diluted share, in
the 2014 first quarter.
Adjusted ebitda was $928 million in the 2015 first quarter,
compared to $1.515 billion in the 2014 first quarter. Operating
cash flow was $910 million in the 2015 first quarter, compared to
$1.614 billion in the 2014 first 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.
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 11 – 13 of this
release.
2015 First Quarter Average Daily Production of 686,000 Boe
Increased 14% Year Over Year and 2% Sequentially, Adjusted for
Asset Sales
Chesapeake’s daily production for the 2015 first quarter
averaged approximately 686,000 barrels of oil equivalent (boe), a
year-over-year increase of 14%, adjusted for asset sales. Average
daily production in the 2015 first quarter consisted of
approximately 121,900 barrels (bbls) of oil, 2.9 billion cubic feet
(bcf) of natural gas and 75,800 bbls of NGL, which represent
year-over-year increases of 17%, 12% and 19%, respectively,
adjusted for asset sales.
Capital Spending and Cost Overview
Chesapeake’s drilling and completion capital expenditures during
the 2015 first quarter were approximately $1.3 billion, and capital
expenditures for leasehold, geological and geophysical costs and
other property, plant and equipment were approximately $63 million,
for a total of approximately $1.4 billion. Total capital
expenditures, including capitalized interest of $123 million, were
approximately $1.5 billion in the 2015 first quarter, compared to
approximately $1.8 billion in the 2014 fourth quarter and $1.4
billion in the 2014 first quarter and are reconciled below.
2015 2014 2014
Activity Comparison Q1 Q4
Q1 Average operated rig count 54 67 60 Gross wells completed
261 341 225 Gross wells spud 244 308 268 Gross wells connected
262 311 249
Type of Cost ($ in millions) Drilling and completion costs $
1,300 $ 1,370 $ 729 Leasehold, G&G and other PP&E
63 252 121
Subtotal capital
spending $ 1,363 $ 1,622 $
850 Capitalized interest 123 134 178 Purchases of previously
leased equipment — 25 340
Total capital spending $ 1,486
$ 1,781 $ 1,368
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 2015 first quarter were $4.84 per boe, a decrease of 5%
from the 2014 fourth quarter and an increase of 2% year over year.
G&A expenses (including stock-based compensation) during the
2015 first quarter were $0.91 per boe, a decrease of 34% from the
2014 fourth quarter and 30% year over year.
A summary of the company’s guidance for 2015 is provided in the
Outlook dated May 6, 2015, attached to this release as Schedule "A”
beginning on Page 14.
Operational Results – Southern Division
Eagle Ford Shale (South
Texas): Eagle Ford net production averaged
approximately 113 thousand barrels of oil equivalent (mboe) per day
(242 gross operated mboe per day) during the 2015 first quarter, an
increase of 7% sequentially. The full-year 2014 average completed
well cost was $5.9 million with an average completed lateral length
of 5,850 feet and 18 frac stages, compared to the full-year 2013
average completed well cost of $6.9 million with an average
completed lateral length of 5,850 feet and 18 frac stages. Well
cost-reduction efforts continue and the company anticipates
completed well costs of $5.5 million by year-end 2015. The company
has successfully drilled five wells with laterals in excess of
10,000 feet. This technical achievement will heavily influence
future development in the field as the company prioritizes
front-loading its drill schedule with this well design. Chesapeake
has successfully completed down spacing tests in various sections
of its acreage, adding 600 – 700 incremental locations to
its undrilled inventory. The company plans to test its first Upper
Eagle Ford well in the 2015 fourth quarter. The average peak
production rate of the 105 wells that commenced first production in
the Eagle Ford during the 2015 first quarter was approximately 763
boe per day.
Haynesville Shale and Bossier Shale
(Northwest Louisiana): Haynesville net production
averaged approximately 616 million cubic feet of natural gas
equivalent (mmcf) per day (996 gross operated mmcf per day) during
the 2015 first quarter, an increase of 4% sequentially. The
full-year 2014 average completed well cost was $8.4 million with an
average completed lateral length of 4,900 feet and 14 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. In April 2015, the company placed its initial two modern
extended lateral (7,500 feet) Haynesville wells on line, the Nguyen
8-15-14 1H ALT and the Nguyen 5-15-14 2H ALT at peak 24-hour rates
of 18.5 mmcf per day and 16.7 mmcf per day, respectively, with
flowing surface pressures of approximately 600 PSI per foot greater
than surrounding in-unit wells. The average peak production rate of
the 19 wells that commenced first production in the Haynesville
during the 2015 first quarter was approximately 15.4 mmcf per day.
Chesapeake also recently turned in line two successful tests in the
Bossier Shale utilizing enhanced stimulation techniques. These
wells are producing at a restricted rate of 12.0 mmcf per day
paving the way for future Bossier development of 200 – 400 wells
that can utilize both enhanced stimulation and extended
laterals.
Mid-Continent North: Mississippian Lime
(Northern Oklahoma): Mississippian Lime net
production averaged approximately 32 mboe per day (75 gross
operated mboe per day) during the 2015 first quarter, an increase
of 11% sequentially. The full-year 2014 average completed well cost
was $3.0 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
company anticipates completed well costs of $2.5 million in 2015,
resulting in a 45% capital reduction in three years. The average
peak production rate of the 48 wells that commenced first
production in the Mississippian Lime during the 2015 first quarter
was approximately 733 boe per day.
Operational Results – Northern Division
Utica Shale (Eastern
Ohio): Utica net production averaged
approximately 110 mboe per day (190 gross operated mboe per day)
during the 2015 first quarter, an increase of 10% sequentially. The
full-year 2014 average completed well cost was $7.2 million with an
average completed lateral length of 6,200 feet and 29 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. Chesapeake anticipates average completed well costs of $8.2
million in 2015 while extending laterals to 7,900 feet with 41 frac
stages. The average peak production rate of the 38 wells that
commenced first production in the Utica during the 2015 first
quarter was approximately 1,272 boe per day.
Marcellus Shale (Northern
Pennsylvania): Marcellus net production averaged
approximately 832 mmcf per day (1.932 gross operated bcf per day)
during the 2015 first quarter, an increase of 2% sequentially. The
2014 full-year average completed well cost was $7.5 million with an
average completed lateral length of 5,950 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. With ample existing drilled inventory and significant
curtailed volumes, Chesapeake expects to maintain production at
current levels throughout 2015 in the Marcellus. The average peak
production rate of the 16 wells that commenced first production in
the northern Marcellus during the 2015 first quarter was
approximately 15.8 mmcf per day.
Powder River Basin (PRB): Niobrara and
Upper Cretaceous (Wyoming): PRB net production
averaged approximately 20 mboe per day (30 gross operated mboe per
day) during the 2015 first quarter, an increase of 10%
sequentially. The 2014 full-year average completed well cost
(including multiple exploratory wells) was $10.6 million per well
with an average completed lateral length of 5,425 feet and 20 frac
stages, compared to an average completed well cost of $10.1 million
per well in 2013 with an average completed lateral length of 5,050
feet and 15 frac stages. Chesapeake continues to improve
operational efficiency and has successfully tested multiple Upper
Cretaceous test wells. The average peak production rate of the 11
wells that commenced first production in the PRB during the 2015
first quarter was approximately 1,594 boe per day.
Key Financial and Operational Results
The table below summarizes Chesapeake’s key financial and
operational results during the 2015 first quarter, as compared to
results in prior periods.
Three Months Ended 03/31/15
12/31/14 03/31/14 Oil equivalent production
(in mmboe) 61.8 67.1 60.8 Oil production (in mmbbls) 11.0 11.2 9.9
Average realized oil price ($/bbl)(a) 62.57 76.40 85.08 Oil as % of
total production 18 17 16 Natural gas production (in bcf) 263.8
281.6 260.0 Average realized natural gas price ($/mcf)(a) 2.37 1.72
3.27 Natural gas as % of total production 71 70 71 NGL production
(in mmbbls) 6.8 9.0 7.6 Average realized NGL price ($/bbl)(a) 6.99
13.11 29.23 NGL as % of total production 11 13 13 Production
expenses ($/boe) (4.84 ) (5.07 ) (4.73 ) Production taxes ($/boe)
(0.45 ) (0.70 ) (0.83 ) General and administrative costs ($/boe)(b)
(0.72 ) (1.23 ) (1.09 ) Stock-based compensation ($/boe) (0.19 )
(0.15 ) (0.21 ) DD&A of natural gas and liquids properties
($/boe) (11.08 ) (10.53 ) (10.33 ) DD&A of other assets ($/boe)
(0.57 ) (0.56 ) (1.29 ) Interest expense ($/boe)(a) (0.98 ) (0.56 )
(0.90 ) Marketing, gathering and compression net margin ($ in
millions)(c) (25 ) (39 ) 35 Oilfield services net margin ($ in
millions)(c) — — 45 Operating cash flow ($ in millions)(d) 910 873
1,614 Operating cash flow ($/boe) 14.73 13.01 26.55 Adjusted ebitda
($ in millions)(e) 928 916 1,515 Adjusted ebitda ($/boe) 15.02
13.66 24.94 Net income (loss) available to common stockholders ($
in millions) (3,782 ) 586 374 Earnings (loss) per share – diluted
($) (5.72 ) 0.81 0.54 Adjusted net income available to common
stockholders ($ in millions)(f) 42 34 405 Adjusted earnings per
share – diluted ($) 0.11 0.11 0.59 (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 13.
(f) Defined as net income available to common stockholders, as
adjusted to remove the effects of certain items detailed on Page
11.
2015 First Quarter Financial and Operational Results
Conference Call Information
A conference call to discuss this release has been scheduled for
Wednesday, May 6, 2015, at 9:00 am EDT. The telephone number to
access the conference call is 913-312-1393 or toll-free
888-797-2983. The passcode for the call is 3887326.
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, May 6, 2015, and
will run through 2:00 pm EDT on Wednesday, May 20, 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
3887326. 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. An investor presentation has been posted on the
company's website at www.chk.com/investors/presentations. The
latest investor presentation that will be referenced during the
call provides additional financial and operational disclosure and
will be available in the Investor Relations section of the
company's website.
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 assets 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 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
March 31, 2015 2014 REVENUES:
Oil, natural gas and NGL $ 1,085 $ 1,766 Marketing, gathering and
compression 1,675 3,015 Oilfield services —
265 Total Revenues 2,760 5,046
OPERATING EXPENSES: Oil, natural gas and NGL production 299
288 Production taxes 28 50 Marketing, gathering and compression
1,700 2,980 Oilfield services — 220 General and administrative 56
79 Restructuring and other termination costs (10 ) (7 ) Provision
for legal contingencies 25 — Oil, natural gas and NGL depreciation,
depletion and amortization 684 628 Depreciation and amortization of
other assets 35 78 Impairment of oil and natural gas properties
4,976 — Impairments of fixed assets and other 4 20 Net (gains)
losses on sales of fixed assets 3 (23 ) Total
Operating Expenses 7,800 4,313
INCOME (LOSS) FROM OPERATIONS (5,040 ) 733
OTHER INCOME (EXPENSE): Interest expense (51 ) (39 )
Losses on investments (7 ) (21 ) Net gain on sales of investments —
67 Other income 6 6 Total Other Income
(Expense) (52 ) 13
INCOME (LOSS) BEFORE
INCOME TAXES (5,092 ) 746
INCOME TAX
EXPENSE (BENEFIT): Current income taxes — 3 Deferred income
taxes (1,372 ) 277 Total Income Tax Expense
(Benefit) (1,372 ) 280
NET INCOME
(LOSS) (3,720 ) 466 Net income attributable to noncontrolling
interests (19 ) (41 )
NET INCOME (LOSS)
ATTRIBUTABLE TO CHESAPEAKE (3,739 ) 425
Preferred stock dividends (43 ) (43 ) Earnings allocated to
participating securities — (8 )
NET INCOME
(LOSS) AVAILABLE TO COMMON STOCKHOLDERS $ (3,782 ) $ 374
EARNINGS (LOSS) PER COMMON SHARE: Basic $ (5.72 ) $ 0.57
Diluted $ (5.72 ) $ 0.54
WEIGHTED AVERAGE COMMON
AND COMMON
EQUIVALENT SHARES OUTSTANDING (in
millions):
Basic 661 658 Diluted 661
765
CHESAPEAKE ENERGY
CORPORATION CONDENSED CONSOLIDATED BALANCE SHEETS ($
in millions) (unaudited) March 31,
December 31, 2015 2014
Cash and cash equivalents $ 2,907 $ 4,108 Other current
assets 2,491 3,360 Total Current Assets 5,398
7,468 Property and equipment, (net) 28,385 32,515
Other assets 590 768 Total Assets $ 34,373 $ 40,751
Current liabilities $ 5,366 $ 5,863 Long-term debt, net of
discounts 10,623 11,154 Other long-term liabilities 1,194 1,344
Deferred income tax liabilities 2,817 4,185 Total
Liabilities 20,000 22,546 Preferred stock
3,062 3,062 Noncontrolling interests 1,295 1,302 Common stock and
other stockholders’ equity 10,016 13,841 Total Equity
14,373 18,205 Total Liabilities and Equity $
34,373 $ 40,751 Common Shares Outstanding (in millions)
664 663
CHESAPEAKE ENERGY
CORPORATION CAPITALIZATION ($ in millions)
(unaudited) March 31, 2015
December 31, 2014 Total debt, net of
unrestricted cash $ 8,601 $ 7,427 Preferred stock 3,062 3,062
Noncontrolling interests(a) 1,295 1,302 Common stock and other
stockholders’ equity 10,016 13,841
Total $ 22,974 $ 25,632 Total net debt to
capitalization ratio 37 % 29 %
(a) Includes third-party ownership as
follows:
CHK Cleveland Tonkawa, L.L.C. $ 1,015 $ 1,015 Chesapeake
Granite Wash Trust 280 287 Total
$ 1,295 $ 1,302
CHESAPEAKE ENERGY CORPORATION SUPPLEMENTAL DATA –
OIL, NATURAL GAS AND NGL PRODUCTION, SALES AND INTEREST
EXPENSE (unaudited) Three Months Ended
March 31, 2015 2014 Net
Production: Oil (mmbbl) 11.0 9.9 Natural gas (bcf) 263.8 260.0
NGL (mmbbl) 6.8 7.6 Oil equivalent (mmboe) 61.8 60.8
Oil,
natural gas and NGL Sales ($ in millions): Oil sales $ 451 $
922 Oil derivatives – realized gains (losses)(a) 235 (84 ) Oil
derivatives – unrealized gains (losses)(a) (110 ) 10
Total Oil Sales 576 848
Natural gas sales 425 1,005 Natural gas derivatives – realized
gains (losses)(a) 200 (154 ) Natural gas derivatives – unrealized
gains (losses)(a) (164 ) (154 ) Total Natural Gas
Sales 461 697 NGL sales
48 221 Total NGL Sales 48
221 Total Oil, Natural Gas and NGL Sales $ 1,085 $
1,766
Average Sales Price – excluding gains
(losses) on derivatives: Oil ($ per bbl) $ 41.16 $ 93.60
Natural gas ($ per mcf) $ 1.61 $ 3.86 NGL ($ per bbl) $ 6.99 $
29.23 Oil equivalent ($ per boe) $ 14.96 $ 35.35
Average
Sales Price – including realized gains (losses) on derivatives:
Oil ($ per bbl) $ 62.57 $ 85.08 Natural gas ($ per mcf) $ 2.37 $
3.27 NGL ($ per bbl) $ 6.99 $ 29.23 Oil equivalent ($ per boe) $
22.00 $ 31.44
Interest Expense ($ in millions):
Interest(b) $ 62 $ 58 Derivatives – realized (gains) losses(c) (1 )
(3 ) Derivatives – unrealized (gains) losses(c) (10 )
(16 ) Total Interest Expense $ 51 $ 39
(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) March 31, March 31,
THREE MONTHS ENDED: 2015 2014
Beginning cash $ 4,108 $ 837
Cash provided by operating activities 423
1,291
Cash flows from investing
activities: Drilling and completion costs(a) (1,306 ) (897 )
Acquisition of proved and unproved properties(b) (128 ) (187 )
Proceeds from divestitures of proved and unproved properties 21 49
Additions to other property and equipment (58 ) (97 ) Cash paid to
purchase leased rigs and compressors — (340 ) Proceeds from sales
of other property and equipment 2 239 Additions to investments (3 )
(3 ) Proceeds from sales of investments — 239 Other —
(2 )
Total cash used in investing activities
(1,472 ) (999 )
Cash used in financing
activities (152 ) (125 )
Change in cash and
cash equivalents (1,201 ) 167
Ending
cash $ 2,907 $ 1,004 (a) Includes
capitalized interest of $11 million and $16 million for the three
months ended March 31, 2015 and 2014, respectively. (b) Includes
capitalized interest of $109 million and $158 million for the three
months ended March 31, 2015 and 2014, respectively.
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON
STOCKHOLDERS ($ in millions, except per share data)
(unaudited) March 31, December 31,
March 31, THREE MONTHS ENDED: 2015
2014 2014 Net income (loss)
available to common stockholders $ (3,782 ) $ 586 $ 374
Adjustments, net of tax: Unrealized (gains) losses on
derivatives 192 (663 ) 80 Restructuring and other termination costs
(7 ) (3 ) (4 ) Provision for legal contingencies 18 94 — Impairment
of oil and natural gas properties 3,635 — — Impairments of fixed
assets and other 3 10 12 Net (gains) losses on sales of fixed
assets 2 2 (14 ) Net gain on sales of investments — — (42 ) Losses
on purchases of debt and extinguishment of other financing — 2 —
Tax rate adjustment (17 ) — — Other (2 ) 6
(1 )
Adjusted net income available to common
stockholders(a) $ 42 $ 34 $ 405
Preferred stock dividends 43 43 43 Earnings allocated to
participating securities — 10 8
Total adjusted net income
attributable to Chesapeake $ 85 $ 87 $ 456
Weighted average fully diluted shares outstanding
(in millions)(b)
776 775 767
Adjusted earnings per share assuming
dilution(a) $ 0.11 $ 0.11 $ 0.59 (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)
March 31, December 31, March 31, THREE
MONTHS ENDED: 2015 2014
2014 CASH PROVIDED BY OPERATING ACTIVITIES $
423 $ 829 $ 1,291 Changes in assets and liabilities 487
44 323
OPERATING CASH
FLOW(a) $ 910 $ 873 $ 1,614
March 31, December 31,
March 31, THREE MONTHS ENDED: 2015
2014 2014 NET INCOME
(LOSS) $ (3,720 ) $ 668 $ 466 Interest expense 51 7 39 Income
tax expense (benefit) (1,372 ) 286 280 Depreciation and
amortization of other assets 35 38 78 Oil, natural gas and NGL
depreciation, depletion and amortization 684
706 628
EBITDA(b) $ (4,322 ) $
1,705 $ 1,491
March 31, December 31, March 31, THREE
MONTHS ENDED: 2015 2014
2014 CASH PROVIDED BY OPERATING ACTIVITIES $
423 $ 829 $ 1,291 Changes in assets and liabilities 487 44 323
Interest expense, net of unrealized gains (losses) on derivatives
61 38 55 Oil, natural gas and NGL derivative gains (losses), net
161 1,049 (382 ) Cash (receipts) payments on oil, natural gas and
NGL derivative settlements, net (413 ) (88 ) 168 Stock-based
compensation (23 ) — (20 ) Restructuring and other termination
costs 10 (3 ) 9 Provision for legal contingencies (25 ) (134 ) —
Impairment of oil and natural gas properties (4,976 ) — —
Impairments of fixed assets and other (2 ) (14 ) (12 ) Net gains
(losses) on sales of fixed assets (3 ) (2 ) 23 Losses on
investments (7 ) (7 ) (21 ) Net gain on sales of investments — — 67
Losses on purchases of debt and extinguishment of other financing —
(2 ) — Other items (15 ) (5 ) (10 )
EBITDA(b) $ (4,322 ) $ 1,705 $ 1,491
(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) March 31, December 31,
March 31, THREE MONTHS ENDED: 2015
2014 2014 EBITDA $ (4,322
) $ 1,705 $ 1,491
Adjustments: Unrealized (gains)
losses on oil, natural gas and NGL derivatives 274 (916 ) 144
Restructuring and other termination costs (10 ) (5 ) (7 ) Provision
for legal contingencies 25 134 — Impairment of oil and natural gas
properties 4,976 — — Impairments of fixed assets and other 4 14 20
Net (gains) losses on sales of fixed assets 3 3 (23 ) Net gains on
sales of investments — — (67 ) Losses on purchases of debt and
extinguishment of other financing — 2 — Net income attributable to
noncontrolling interests (19 ) (29 ) (41 ) Other (3 )
8 (2 )
Adjusted EBITDA(a) $ 928
$ 916 $ 1,515 (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
MAY 6, 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) 1% – 3%
Absolute Production Liquids - mbbls 62 – 64 Oil - mbbls 38.5 – 39.5
NGL(b) - mbbls 23.5 – 24.5 Natural gas - bcf 1,025 – 1,040 Total
absolute production - mmboe 233 – 237 Absolute daily rate - mboe
640 – 650 Estimated Realized Hedging Effects(c) (based on 4/30/15
strip prices): Oil - $/bbl $19.33 Natural gas - $/mcf $0.32
Estimated Basis/Gathering/Marketing/Transportation Differentials to
NYMEX Prices: Oil - $/bbl $7.00 – 9.00 Natural gas - $/mcf $1.70 –
1.90 NGL - $/bbl $49.00 – 51.00 Fourth quarter minimum volume
commitment (MVC) estimate ($ 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 $9.50 – 10.50
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) ($30 – 50) Book Tax Rate 25% – 30% Capital
Expenditures ($ 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/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, leasehold,
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 derivative positions and
accounting for oil, natural gas and NGL derivatives.
As of April 30, 2015, the company had downside protection on
approximately 43% of its remaining projected 2015 oil production at
an average price of $93.48 per bbl of which 12% 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 40% of the company's remaining
projected 2015 natural gas production has downside protection at an
average price of $3.85 per one thousand cubic feet of natural gas
(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 $3.38 per
mcf.
The company’s crude oil hedging positions as of April 30, 2015,
were as follows:
Open Crude Oil Swaps; Gains (Losses) from
Closed Crude Oil Trades and Call Option Premiums
Total Gains
from Closed Trades Avg. NYMEX and Premiums for Open Swaps Price of
Call Options (mbbls) Open Swaps ($ in
millions) Q2 2015 3,041 $ 94.49 $ 61 Q3 2015 2,868 94.82 62 Q4 2015
2,714 95.15 63 Total Q2 - Q4
2015 8,623 $ 94.81 $ 186 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 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 Q2 - Q4 2015 3,300 $ 80.00
$ 90.00 $ 98.94
Crude Oil Net
Written Call Options Call Options Avg. NYMEX (mbbls)
Strike Price Q2 2015 3,349 $ 91.89 Q3 2015 3,386 91.89 Q4 2015
3,386 91.89 Total Q2 - Q4 2015 10,121
$ 91.89 Total 2016 – 2017 24,220 $ 100.07
Crude Oil Basis Protection Swaps
Volume Avg. NYMEX (mbbls) plus Q2 2015 1,740 $ 5.04 Q3 2015 2,392
3.14 Q4 2015 2,361 3.14 Total Q2 - Q4 2015
6,493 $ 3.65
The company’s natural gas hedging positions as of April 30, 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) Q2 2015 70 $ 3.64 $ (30 )
Q3 2015 78 3.54 (31 ) Q4 2015 52 3.94
(31 ) Total Q2 - Q4 2015 200 $ 3.68 $
(92 ) Total 2016 – 2022 37 $ 3.95 $ (187 )
Natural Gas Three-Way Collars
Avg. NYMEX Avg. NYMEX Avg. NYMEX Open Collars Sold
Bought
Sold
(bcf) Put Price Put Price Call
Price 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 Q2 - Q4 2015 107 $ 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) Q2 2015 22 $ (0.70 ) Q3 2015 37 (0.82 ) Q4 2015
10 (0.34 ) Total Q2 - Q4 2015 69 $
(0.71 ) Total 2016 - 2022 27 $ (0.56 )
Chesapeake Energy CorporationInvestor Relations:Brad Sylvester,
CFA, 405-935-8870ir@chk.comorMedia Relations:Gordon Pennoyer,
405-935-8878media@chk.com
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