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Company Curtails September 2007 Natural Gas Production and
Decreases Drilling Activity in Response to Lower Natural Gas Prices;
However, Reaffirms Previous Production Guidance for Full-Years 2007
and 2008
OKLAHOMA CITY--(BUSINESS WIRE)--Sept. 4, 2007--Chesapeake Energy
Corporation (NYSE:CHK) today announced an enhanced financial plan for
2008-2009 and its initial production and budget forecasts for 2009.
Key elements of the financial plan include taking advantage of the
favorable master limited partnership (MLP) and financial markets that
exist for low decline-rate producing natural gas assets and for
midstream gas assets in order to capture latent balance sheet value
and to fully fund its planned capital expenditures.
During the next four months, the company anticipates completing
its first two transactions associated with the new plan. For the first
transaction, Chesapeake has retained Jefferies Randall & Dewey to
assist in selling a non-operated minority interest in certain
Chesapeake-operated producing assets in Kentucky and West Virginia
representing approximately 145 bcfe of proved reserves and 30 mmcfe
net per day of production, or approximately 1.5% of the company's
current proved reserves and net production. Chesapeake believes these
assets will be attractive to both the MLP and financial markets due to
the low-risk, long reserve-life and low decline-rate profiles of the
properties. The company intends to retain drilling rights on the
properties below currently producing intervals and outside of existing
producing wellbores. Chesapeake expects to receive proceeds of
approximately $550 million from the Appalachian asset sale, which is
anticipated to close by year-end 2007. Additionally, Chesapeake plans
to pursue the sale of four similar packages of mature properties
approximately every six months in 2008 and 2009 for further proceeds
of approximately $2 billion.
For the second transaction, Chesapeake has retained UBS Investment
Bank to assist in forming a private MLP or an alternative financial
structure to own a non-operating majority interest in its midstream
natural gas assets, which consist primarily of gas gathering systems
and processing assets. These assets, which are expected to grow
substantially in future years, currently generate annualized cash flow
from operating activities of approximately $100 million. The company
believes this transaction will be valued in excess of $1 billion.
As a result of these planned transactions during the next nine
quarters, Chesapeake believes the MLP and financial markets will allow
it to monetize approximately $3.5 billion of assets that, in
management's opinion, are not adequately reflected in Chesapeake's
current market valuation.
Chesapeake Elects to Curtail Production and Defer Drilling
Activity in Response to Lower Natural Gas Prices; However, Reaffirms
Previous Production Growth Forecasts for 2007 and 2008 and Projects
Further Production Growth in 2009
In response to currently low natural gas prices, Chesapeake has
elected to temporarily reduce its gross daily natural gas production
by approximately 200 million cubic feet (mmcf) through a combination
of production curtailments and deferred pipeline hook-ups. This
production reduction will amount to roughly 125 mmcf per day net to
Chesapeake, or about 6% of the company's current net production, and
will be focused in the Fort Worth Barnett Shale, South Texas, Deep
Haley and the Anadarko Basin areas where many of the company's most
prolific wells are located. Similar to its voluntary natural gas
production curtailments in October 2006, the company plans to continue
monitoring the natural gas markets and adjust production rates
accordingly as market conditions dictate.
Chesapeake has also elected to reduce its operated drilling rig
count from current levels of 155-160 rigs to 140-145 rigs by the end
of 2007. This reduction in drilling activity will lower the company's
previously budgeted capital expenditures by approximately 10% in each
of 2008 and 2009, or a combined $1 billion.
However, because Chesapeake's production growth during most of
2007 has exceeded internal projections, the company expects to meet
its previously released production guidance of August 2, 2007, which
projected an 18-22% production increase for the full-year 2007 and a
14-18% production increase for full-year 2008, despite the asset
sales, production curtailments and reduced drilling activity described
above. Further, the company's initial projection for 2009 production
growth is 12-16%.
The company's updated forecasts for 2007, 2008 and 2009 are
attached to this release in an Outlook dated September 4, 2007,
labeled as Schedule "A," which begins on page 6. This Outlook has been
changed from the Outlook dated August 2, 2007, (attached as Schedule
"B," which begins on page 10) to reflect various updated information.
Management Comments
Aubrey K. McClendon, Chesapeake's Chief Executive Officer,
commented, "Our announcement addresses two important topics in our
industry today: low natural gas prices and attractive asset values for
sellers of natural gas assets into the MLP and financial markets.
First, we believe that current low natural gas prices are temporary
and result from a modest oversupply of natural gas in the U.S. This
oversupply has largely been caused by two consecutive mild winters in
the U.S., increases in imports of liquefied natural gas resulting from
an exceptionally warm European winter last season and increased
production from domestic producers through higher drilling activity
levels.
Chesapeake has been the leading contributor to these domestic
natural gas production increases. Over the past year, the U.S. rig
count has increased by approximately 70 rigs to around 1,800 rigs
while Chesapeake's operated rig count has increased by approximately
50 rigs, representing about 70% of the nation's overall increase in
drilling activity. As a consequence of Chesapeake's drilling success,
the company's gross natural gas production has grown by approximately
550 mmcf per day during the past year, accounting for approximately
50% of the total increase in U.S. natural gas production while using
only about 9% of the nation's rigs.
To protect the company's long-term shareholder value, we believe
Chesapeake needs to respond to the current oversupply of natural gas
and defer natural gas production and drilling activity until natural
gas supply and demand come into better balance. We will continue
monitoring the natural gas markets and adjust our production volumes
and drilling activity as market conditions dictate.
We would also like to highlight Chesapeake's proactive approach to
revenue management. So far this year, we have realized approximately
$630 million in gains from our natural gas hedges and, as of the
middle of last week, the mark-to-market gain on our remaining 2007
through 2009 natural gas hedges was approximately $1.5 billion. We
have hedged approximately 60% of our 2007 second half natural gas
production through swaps at a weighted average price of $8.47 per mcf,
approximately 70% of our 2008 natural gas production at an average
price of $9.18 per mcf and approximately 27% of our 2009 natural gas
production at an average price of $8.98 per mcf. Additionally, we have
hedged approximately 12% of our 2007 second half natural gas
production through collars at a weighted average floor of $6.94 per
mcf, approximately 4% of our 2008 natural gas production at a weighted
average floor of $7.41 per mcf and approximately 2% of our 2009
natural gas production at a weighted average floor of $7.50 per mcf.
The swap amounts above include certain knockout swaps that may or may
not be effective hedges at contract settlement dates depending on
future natural gas prices.
Secondly, we are excited to announce our enhanced financial plan
for 2008-2009. This plan will enable us to realize approximately $3.5
billion in cash from the MLP and financial markets for assets that we
believe are not adequately reflected in the company's current market
valuation. Furthermore, we have lowered our planned total capital
expenditures for 2008 and 2009 by approximately $1 billion. In
combination with the $3.5 billion in planned asset monetizations, we
believe that our shareholders and debtholders will be pleased that
Chesapeake will be cash self-sufficient for the foreseeable future and
yet can still meet its previously announced production and reserve
growth forecasts. Importantly, we believe that by year-end 2009, the
company's production will be nearly 40% higher than at June 30, 2007,
and its proved reserves will be nearly 30% higher. We believe the
market will recognize the substantial value creation potential of this
enhanced financial plan."
Conference Call Information
A conference call to discuss this release has been scheduled for
Wednesday morning, September 5, 2007, at 9:00 a.m. EDT. The telephone
number to access the conference call is 913-312-1271 and the
confirmation code is 1929342. We encourage those who would like to
participate in the call to dial the access number between 8:50 and
8:55 a.m. EDT. For those unable to participate in the conference call,
a replay will be available for audio playback from noon EDT, September
5, 2007, through midnight EDT on September 19, 2007. The number to
access the conference call replay is 719-457-0820 and the passcode for
the replay is 1929342. The conference call will also be webcast live
on the Internet and can be accessed by going to Chesapeake's website
at www.chkenergy.com and selecting the "News & Events" section. The
webcast of the conference call will be available on our website for
one year.
This press release and the accompanying Outlooks 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 give our current expectations or
forecasts of future events. They include estimates of oil and natural
gas reserves, expected oil and natural gas production and future
expenses, projections of future oil and natural gas prices, planned
capital expenditures for drilling, leasehold acquisitions and seismic
data, and statements concerning anticipated cash flow and liquidity,
business strategy and other plans and objectives for future
operations. Disclosures concerning the fair value of derivative
contracts and their estimated contribution to our future results of
operations are based upon market information as of a specific date.
These market prices are subject to significant volatility. We caution
you not to place undue reliance on our forward-looking statements,
which speak only as of the date of this press release, and we
undertake no obligation to update this information.
Factors that could cause actual results to differ materially from
expected results are described in "Risks Related to our Business"
under "Risk Factors" in the prospectus supplement we filed with the
Securities and Exchange Commission on August 9, 2007. These risk
factors include the volatility of oil and natural gas prices; the
limitations our level of indebtedness may have on our financial
flexibility; our ability to compete effectively against strong
independent oil and natural gas companies and majors; the availability
of capital on an economic basis to fund reserve replacement costs; our
ability to replace reserves and sustain production; uncertainties
inherent in estimating quantities of oil and natural gas reserves and
projecting future rates of production and the amount and timing of
development expenditures; uncertainties in evaluating oil and natural
gas reserves of acquired properties and associated potential
liabilities; our ability to effectively consolidate and integrate
acquired properties and operations; unsuccessful exploration and
development drilling; declines in the values of our oil and natural
gas properties resulting in ceiling test write-downs; lower prices
realized on oil and natural gas sales and collateral required to
secure hedging liabilities resulting from our commodity price risk
management activities; the negative impact lower oil and natural gas
prices could have on our ability to borrow; drilling and operating
risks, including potential environmental liabilities; production
interruptions that could adversely affect our cash flow; and pending
or future litigation.
Our production forecasts are dependent upon many assumptions,
including estimates of production decline rates from existing wells
and the outcome of future drilling activity. Although we believe the
expectations and forecasts reflected in these and other
forward-looking statements are reasonable, we can give no assurance
they will prove to have been correct. They can be affected by
inaccurate assumptions or by known or unknown risks and uncertainties.
Chesapeake Energy Corporation is the largest independent producer
and third-largest overall producer of natural gas in the United
States. Headquartered in Oklahoma City, the company's operations are
focused on exploratory and developmental drilling and corporate and
property acquisitions in the Mid-Continent, Fort Worth Barnett Shale,
Fayetteville Shale, Permian Basin, Delaware Basin, South Texas, Texas
Gulf Coast, Ark-La-Tex and Appalachian Basin regions of the United
States.
SCHEDULE "A"
CHESAPEAKE'S OUTLOOK AS OF SEPTEMBER 4, 2007
Quarters Ending September 30, 2007 and December 31, 2007; Years
Ending December 31, 2007, 2008 and 2009.
We have adopted a policy of periodically providing guidance on
certain factors that affect our future financial performance. As of
September 4, 2007, we are using the following key assumptions in our
projections for the third quarter of 2007, the fourth quarter of 2007
and the full-years 2007, 2008 and 2009.
The primary changes from our August 2, 2007 Outlook are in
italicized bold and are explained as follows:
1) We are increasing our prior production guidance for the quarter
ending September 30, 2007;
2) Guidance for the quarter ending December 31, 2007 has been
provided for the first time;
3) Guidance for the year ending December 31, 2009 has been
provided for the first time;
4) Production assumptions have been updated, including assumed
assets sales with production losses of 30 mmcf/d in 2007 and 60 mmcf/d
in 2008 and 2009;
5) Certain cost assumptions have been updated;
6) Projected effects of changes in our hedging positions have been
updated; and
7) Budgeted capital expenditure assumptions have been updated.
Quarter Ending Quarter Ending
9/30/2007 12/31/2007
-------------- ---------------
Estimated Production
Oil - mbbls 2,500 2,500
Natural gas - bcf 165.5 - 167.5 171.5 - 173.5
Natural gas equivalent - bcfe 180.5 - 182.5 186.5 - 188.5
Daily natural gas equivalent
midpoint - in mmcfe 1,975 2,040
NYMEX Prices (a) (for calculation of realized hedging effects only):
Oil - $/bbl $69.72 $67.50
Natural gas - $/mcf $6.17 $7.50
Estimated Realized Hedging Effects (based on assumed NYMEX prices
above):
Oil - $/bbl $2.07 $3.50
Natural gas - $/mcf $1.81 $1.85
Estimated Differentials to NYMEX
Prices:
Oil - $/bbl 7 - 9% 7 - 9%
Natural gas - $/mcf 10 - 14% 10 - 14%
Operating Costs per Mcfe of Projected Production:
Production expense $0.90 - 1.00 $0.90 - 1.00
Production taxes (generally 5.5% of
O&G revenues) (b) $0.35 - 0.40 $0.35 - 0.40
General and administrative $0.25 - 0.30 $0.25 - 0.30
Stock-based compensation (non-cash) $0.09 - 0.11 $0.08 - 0.10
DD&A of oil and natural gas assets $2.55 - 2.65 $2.60 - 2.70
Depreciation of other assets $0.24 - 0.28 $0.20 - 0.25
Interest expense(c) $0.55 - 0.60 $0.55 - 0.60
Other Income per Mcfe:
Oil and natural gas marketing income $0.08 - 0.10 $0.08 - 0.10
Service operations income $0.06 - 0.08 $0.04 - 0.06
Book Tax Rate (About Equals 97%
deferred) 38% 38%
Equivalent Shares Outstanding - in
millions:
Basic 454 454
Diluted 520 520
Budgeted Capital Expenditures - in
millions:
Drilling $1,050 - 1,150 $1,000 - 1,100
Leasehold acquisition costs $100 - 200 $100 - 200
Geological and geophysical costs $50 - 75 $50 - 75
-------------- ---------------
Total budgeted capital
expenditures $1,200 - 1,425 $1,150 - 1,375
Year Ending Year Ending Year Ending
12/31/2007 12/31/2008 12/31/2009
-------------- --------------- ---------------
Estimated Production
Oil - mbbls 9,500 10,800 11,300
Natural gas - bcf 632 - 640 729.5 - 739.5 830 - 840
Natural gas
equivalent - bcfe 688 - 698 794.5 - 804.5 898 - 908
Daily natural gas
equivalent midpoint
- in mmcfe 1,900 2,185 2,475
NYMEX Prices (a) (for calculation of realized hedging effects only):
Oil - $/bbl $65.10 $67.50 $67.50
Natural gas - $/mcf $7.00 $7.50 $7.50
Estimated Realized Hedging Effects (based on assumed NYMEX prices
above):
Oil - $/bbl $4.64 $4.66 $4.04
Natural gas - $/mcf $1.92 $1.53 $0.56
Estimated
Differentials to
NYMEX Prices:
Oil - $/bbl 7 - 9% 7 - 9% 7 - 9%
Natural gas - $/mcf 10 - 14% 10 - 14% 10 - 14%
Operating Costs per Mcfe of Projected Production:
Production expense $0.90 - 1.00 $0.90 - 1.00 $0.90 - 1.00
Production taxes
(generally 5.5% of
O&G revenues) (b) $0.35 - 0.40 $0.35 - 0.40 $0.35 - 0.40
General and
administrative $0.25 - 0.30 $0.25 - 0.30 $0.25 - 0.30
Stock-based
compensation (non-
cash) $0.08 - 0.10 $0.10 - 0.12 $0.10 - 0.12
DD&A of oil and
natural gas assets $2.50 - 2.70 $2.50 - 2.70 $2.50 - 2.70
Depreciation of
other assets $0.24 - 0.28 $0.24 - 0.28 $0.24 - 0.28
Interest expense(c) $0.55 - 0.60 $0.55 - 0.60 $0.55 - 0.60
Other Income per Mcfe:
Oil and natural gas
marketing income $0.08 - 0.10 $0.02 - 0.04 $0.02 - 0.04
Service operations
income $0.05 - 0.07 $0.05 - 0.07 $0.05 - 0.07
Book Tax Rate (About
Equals 97% deferred) 38% 38% 38%
Equivalent Shares
Outstanding - in
millions:
Basic 453 458 463
Diluted 519 524 529
Budgeted Capital
Expenditures - in
millions:
Drilling $4,250 - 4,450 $4,000 - 4,200 $4,000 - 4,200
Leasehold
acquisition costs $600 - 800 $500 - 600 $500 - 600
Geological and
geophysical costs $250 - 300 $200 $200
-------------- --------------- ---------------
Total budgeted
capital
expenditures $5,100 - 5,550 $4,700 - $5,000 $4,700 - $5,000
(a) Oil NYMEX prices have been updated for actual contract prices
through July 2007 and natural gas NYMEX prices have been updated for
actual contract prices through September 2007.
(b) Severance tax per mcfe is based on NYMEX prices of: $69.72 per
bbl of oil and $6.80 to $7.95 per mcf of natural gas during Q3 2007;
$67.50 per bbl of oil and $6.85 to $7.95 per mcf of natural gas during
Q4 2007; $65.10 per bbl of oil and $6.85 to $8.00 per mcf of natural
gas during calendar 2007; and $67.50 per bbl of oil and $6.85 to $8.00
per mcf of natural gas during calendar 2008 and 2009.
(c) Does not include gains or losses on interest rate derivatives
(SFAS 133).
Commodity Hedging Activities
The company utilizes hedging strategies to hedge the price of a
portion of its future oil and natural gas production. These strategies
include:
(i) For swap instruments, Chesapeake receives a fixed price and
pays a floating market price, as defined in each instrument, to the
counterparty. The fixed-price payment and the floating-price payment
are netted, resulting in a net amount due to or from the counterparty.
(ii) For cap-swaps, Chesapeake receives a fixed price and pays a
floating market price. The fixed price received by Chesapeake includes
a premium in exchange for a "cap" limiting the counterparty's
exposure. In other words, there is no limit to Chesapeake's exposure
but there is a limit to the downside exposure of the counterparty.
(iii) For knockout swaps, Chesapeake receives a fixed price and
pays a floating market price. The fixed price received by Chesapeake
includes a premium in exchange for the possibility to reduce the
counterparty's exposure to zero, in any given month, if the floating
market price is lower than certain pre-determined knockout prices.
(iv) For written call options, Chesapeake receives a premium from
the counterparty in exchange for the sale of a call option. If the
market price exceeds the fixed price of the call option, Chesapeake
pays the counterparty such excess. If the market price settles below
the fixed price of the call option, no payment is due from Chesapeake.
(v) Collars contain a fixed floor price (put) and ceiling price
(call). If the market price exceeds the call strike price or falls
below the put strike price, Chesapeake receives the fixed price and
pays the market price. If the market price is between the call and the
put strike price, no payments are due from either party.
(vi) A three-way collar contract consists of a standard collar
contract plus a written put option with a strike price below the floor
price of the collar. In addition to the settlement of the collar, the
put option requires Chesapeake to make a payment to the counterparty
equal to the difference between the put option price and the
settlement price if the settlement price for any settlement period is
below the put option strike price.
(vii) Basis protection swaps are arrangements that guarantee a
price differential of oil or natural gas from a specified delivery
point. Chesapeake receives a payment from the counterparty if the
price differential is greater than the stated terms of the contract
and pays the counterparty if the price differential is less than the
stated terms of the contract.
Commodity markets are volatile, and as a result, Chesapeake's
hedging activity is dynamic. As market conditions warrant, the company
may elect to settle a hedging transaction prior to its scheduled
maturity date and lock in the gain or loss on the transaction.
Chesapeake enters into oil and natural gas derivative transactions
in order to mitigate a portion of its exposure to adverse market
changes in oil and natural gas prices. Accordingly, associated gains
or loses from the derivative transactions are reflected as adjustments
to oil and natural gas sales. All realized gains and losses from oil
and natural gas derivatives are included in oil and natural gas sales
in the month of related production. Pursuant to SFAS 133, certain
derivatives do not qualify for designation as cash flow hedges.
Changes in the fair value of these non-qualifying derivatives that
occur prior to their maturity (i.e., because of temporary fluctuations
in value) are reported currently in the consolidated statement of
operations as unrealized gains (losses) within oil and natural gas
sales.
Following provisions of SFAS 133, changes in the fair value of
derivative instruments designated as cash flow hedges, to the extent
effective in offsetting cash flows attributable to hedged risk, are
recorded in other comprehensive income until the hedged item is
recognized in earnings. Any change in fair value resulting from
ineffectiveness is recognized currently in oil and natural gas sales.
Excluding the swaps assumed in connection with the acquisition of
CNR which are described below, the company currently has the following
open natural gas swaps in place and also has the following gains from
lifted natural gas swaps:
Open Swap
Positions
as a Total Total Lifted
Avg. Assuming % of Gains Gain
NYMEX Natural Estimated from per Mcf of
Open Strike Gas Total Lifted Estimated
Swaps Price Production Natural Swaps Total
in of Open in Bcf's Gas ($ Natural Gas
Bcf's Swaps of: Production millions) Production
======================================================================
2007:
--------
Q3 72.6 $7.87 166.5 44% $113.8 $0.68
Q4 110.9 $8.82 172.5 64% $116.8 $0.68
======================================================================
Q3-Q4
2007(1) 183.5 $8.44 339.0 54% $230.6 $0.68
======================================================================
======================================================================
Total
2008(1) 475.3 $9.27 734.5 65% $105.0 $0.14
======================================================================
======================================================================
Total
2009(1) 208.0 $9.12 835.0 25% $3.9 $0.01
======================================================================
(1) Certain hedging arrangements include cap-swaps and knockout
swaps with provisions limiting the counterparty's exposure below
prices ranging from $5.75 to $6.50 covering 88 bcf in Q3-Q4 2007,
$5.25 to $6.50 covering 225 bcf in 2008 and $5.90 to $6.50 covering
152 bcf in 2009.
The company currently has the following open natural gas collars
in place:
Open Collars
as a % of
Avg. Avg. Assuming Estimated
Open NYMEX NYMEX Natural Gas Total
Collars Floor Ceiling Production Natural Gas
in Bcf's Price Price in Bcf's of: Production
======================================================================
2007:
-------------
Q3 22.1 $6.76 $8.20 166.5 13%
Q4 19.6 $7.13 $8.88 172.5 11%
======================================================================
Q3-Q4 2007(1) 41.7 $6.94 $8.52 339.0 12%
======================================================================
======================================================================
Total 2008(1) 26.8 $7.41 $9.40 734.5 4%
======================================================================
======================================================================
Total 2009(1) 18.3 $7.50 $10.72 835.0 2%
======================================================================
(1) Certain collar arrangements include three-way collars that
include written put options with strike prices ranging from $5.00 to
$6.00 covering 33 bcf in Q3-Q4 2007, $5.00 to $6.00 covering 11 bcf in
2008 and $6.00 covering 18 bcf in 2009.
Note: Not shown above are written call options covering 46 bcf of
production in Q3-Q4 2007 at a weighted average price of $10.49 for a
weighted average premium of $0.61, 110 bcf of production in 2008 at a
weighed average price of $10.41 for a weighted average premium of
$0.67 and 119 bcf of production in 2009 at a weighed average price of
$11.12 for a weighted average premium of $0.61.
The company has the following natural gas basis protection swaps
in place:
Mid-Continent Appalachia
----------------------- ---------------------------
Volume in NYMEX Volume in NYMEX
Bcf's less(1): Bcf's plus(1):
----------- ----------- ------------- -------------
Q3-Q4 2007 74.6 0.34 18.4 0.35
2008 118.6 0.27 43.9 0.35
2009 86.6 0.29 36.5 0.31
2010 -- -- 29.2 0.31
2011 -- -- 29.2 0.32
2012 10.7 0.34 -- --
----------- ----------- ------------- -------------
Totals 290.5 $ 0.30 157.2 $ 0.33
=========== =========== ============= =============
(1) weighted average
We assumed certain liabilities related to open derivative
positions in connection with the CNR acquisition in November 2005. In
accordance with SFAS 141, these derivative positions were recorded at
fair value in the purchase price allocation as a liability of $592
million ($255 million as of June 30, 2007). The recognition of the
derivative liability and other assumed liabilities resulted in an
increase in the total purchase price which was allocated to the assets
acquired. Because of this accounting treatment, only cash settlements
for changes in fair value subsequent to the acquisition date for the
derivative positions assumed result in adjustments to our oil and
natural gas revenues upon settlement. For example, if the fair value
of the derivative positions assumed does not change, then upon the
sale of the underlying production and corresponding settlement of the
derivative positions, cash would be paid to the counterparties and
there would be no adjustment to oil and natural gas revenues related
to the derivative positions. If, however, the actual sales price is
different from the price assumed in the original fair value
calculation, the difference would be reflected as either a decrease or
increase in oil and natural gas revenues, depending upon whether the
sales price was higher or lower, respectively, than the prices assumed
in the original fair value calculation. For accounting purposes, the
net effect of these acquired hedges is that we hedged the production
volumes listed below at their fair values on the date of our
acquisition of CNR.
Pursuant to SFAS 149 "Amendment of SFAS 133 on Derivative
Instruments and Hedging Activities", the assumed CNR derivative
instruments are deemed to contain a significant financing element and
all cash flows associated with these positions are reported as
financing activity in the statement of cash flows.
The following details the CNR derivatives (natural gas swaps) we
have assumed:
Open Swap
Avg. Positions
NYMEX Avg. Fair as a %
Strike Value Upon Assuming of
Open Price Acquisition Initial Natural Gas Estimated
Swaps Of Open of Liability Production Total
in Swaps Open Swaps Acquired in Bcf's Natural Gas
Bcf's (per Mcf) (per Mcf) (per Mcf) of: Production
======================================================================
2007:
Q3 10.6 $4.82 $8.45 ($3.63) 166.5 6%
Q4 10.6 $4.82 $8.87 ($4.05) 172.5 6%
======================================================================
Q3-Q4
2007 21.2 $4.82 $8.66 ($3.84) 339.0 6%
======================================================================
======================================================================
Total
2008 38.4 $4.68 $8.02 ($3.34) 734.5 5%
======================================================================
======================================================================
Total
2009 18.3 $5.18 $7.28 ($2.10) 835.0 2%
======================================================================
Note: Not shown above are collars covering 3.7 bcf of production
in 2009 at an average floor and ceiling of $4.50 and $6.00.
The company also has the following crude oil swaps in place:
Total
Open Swap Total Lifted
Positions as Gains Gain per
a % from bbl
Open Avg. Assuming Oil of Estimated Lifted of
Swaps NYMEX Production Total Swaps Estimated
in Strike in Oil ($ Total Oil
mbbls Price mbbls of: Production millions) Production
======================================================================
2007:
Q3 1,656 $71.61 2,500 66% $2.1 $0.84
Q4 1,656 $71.57 2,500 66% $2.1 $0.84
======================================================================
Q3-Q4
2007(1) 3,312 $71.59 5,000 66% $4.2 $0.84
======================================================================
======================================================================
Total
2008(1) 7,502 $72.77 10,800 69% $4.8 $0.45
======================================================================
======================================================================
Total
2009(1) 3,650 $76.75 11,300 32% -- --
======================================================================
(1) Certain hedging arrangements include cap-swaps and knockout
swaps with provisions limiting the counterparty's exposure below
prices ranging from $45.00 to $60.00 covering 1,472 mbbls in Q3-Q4
2007 and 3,478 mbbls in 2008 and from $52.50 to $60.00 covering 3,103
mbbls in 2009.
Note: Not shown above are written call options covering 1,282
mbbls of production in 2008 at a weighted average price of $75.00 for
a weighted average premium of $4.72 and 2,190 mbbls of production in
2009 at a weighed average price of $75.00 for a weighted average
premium of $5.47.
SCHEDULE "B"
CHESAPEAKE'S PREVIOUS OUTLOOK AS OF AUGUST 2, 2007
(PROVIDED FOR REFERENCE ONLY)
NOW SUPERSEDED BY OUTLOOK AS OF SEPTEMBER 4, 2007
Quarter Ending September 30, 2007; Year Ending December 31, 2007;
and Year Ending December 31, 2008.
We have adopted a policy of periodically providing investors with
guidance on certain factors that affect our future financial
performance. As of August 2, 2007, we are using the following key
assumptions in our projections for the third quarter of 2007, the
full-year 2007 and the full-year 2008.
The primary changes from our May 3, 2007 Outlook are in italicized
bold in the table and are explained as follows:
1) We have provided our first guidance for the quarter ending
September 30, 2007;
2) We have updated the projected effect of changes in our hedging
positions;
3) Production and certain cost assumptions have been updated; and
4) Capital expenditure assumptions have been updated and specific
detail has been provided by type of budgeted capital expenditure.
Quarter Ending Year Ending Year Ending
9/30/2007 12/31/2007 12/31/2008
-------------- -------------- ---------------
Estimated Production
Oil - mbbls 2,200 9,000 9,000
Natural gas - bcf 166.5 - 170.5 634 - 644 740.5 - 750.5
Natural gas equivalent
- bcfe 179.5 - 183.5 688 - 698 794.5 - 804.5
Daily natural gas
equivalent midpoint -
in mmcfe 1,975 1,900 2,185
NYMEX Prices (a) (for
calculation of realized
hedging effects only):
Oil - $/bbl $65.00 $63.30 $65.00
Natural gas - $/mcf $7.31 $7.28 $7.50
Estimated Realized
Hedging Effects (based
on assumed NYMEX prices
above):
Oil - $/bbl $5.85 $6.24 $6.81
Natural gas - $/mcf $1.42 $1.81 $1.46
Estimated Differentials
to NYMEX Prices:
Oil - $/bbl 7 - 9% 7 - 9% 7 - 9%
Natural gas - $/mcf 10 - 14% 10 - 14% 10 - 14%
Operating Costs per Mcfe
of Projected
Production:
Production expense $0.90 - 1.00 $0.90 - 1.00 $0.90 - 1.00
Production taxes
(generally 5.5% of
O&G revenues) (b) $0.35 - 0.40 $0.35 - 0.40 $0.35 - 0.40
General and
administrative $0.25 - 0.30 $0.25 - 0.30 $0.25 - 0.30
Stock-based
compensation (non-
cash) $0.09 - 0.11 $0.08 - 0.10 $0.10 - 0.12
DD&A of oil and
natural gas assets $2.55 - 2.65 $2.40 - 2.60 $2.50 - 2.70
Depreciation of other
assets $0.24 - 0.28 $0.24 - 0.28 $0.24 - 0.28
Interest expense(c) $0.55 - 0.60 $0.60 - 0.65 $0.55 - 0.60
Other Income per Mcfe:
Oil and natural gas
marketing income $0.08 - 0.10 $0.08 - 0.10 $0.08 - 0.10
Service operations
income $0.06 - 0.08 $0.07 - 0.10 $0.07 - 0.10
Book Tax Rate (About
Equals 97% deferred) 38% 38% 38%
Equivalent Shares
Outstanding - in
millions:
Basic 454 453 458
Diluted 520 519 524
Budgeted Capital
Expenditures - in
millions:
Drilling $1,050 - 1,150 $4,300 - 4,500 $4,300 - 4,500
Leasehold acquisition
costs $100 - 200 $600 - 800 $600 - 800
Geological and
geophysical costs $50 - 75 $200 - 300 $200 - 300
-------------- -------------- ---------------
Total budgeted
capital
expenditures $1,200 - 1,425 $5,100 - 5,600 $5,100 - $5,600
(a) Oil NYMEX prices have been updated for actual contract prices
through June 2007 and natural gas NYMEX prices have been updated for
actual contract prices through July 2007.
(b) Severance tax per mcfe is based on NYMEX prices of $65.00 per
bbl of oil and $6.90 to $8.00 per mcf of natural gas during Q3 2007,
$63.30 per bbl of oil and $6.90 to $8.00 per mcf of natural gas during
calendar 2007 and $65.00 per bbl of oil and $6.90 to $8.00 per mcf of
natural gas during calendar 2008.
(c) Does not include gains or losses on interest rate derivatives
(SFAS 133).
Commodity Hedging Activities
The company utilizes hedging strategies to hedge the price of a
portion of its future oil and natural gas production. These strategies
include:
(i) For swap instruments, Chesapeake receives a fixed price and
pays a floating market price, as defined in each instrument, to the
counterparty. The fixed-price payment and the floating-price payment
are netted, resulting in a net amount due to or from the counterparty.
(ii) For cap-swaps, Chesapeake receives a fixed price and pays a
floating market price. The fixed price received by Chesapeake includes
a premium in exchange for a "cap" limiting the counterparty's
exposure. In other words, there is no limit to Chesapeake's exposure
but there is a limit to the downside exposure of the counterparty.
(iii) For knockout swaps, Chesapeake receives a fixed price and
pays a floating market price. The fixed price received by Chesapeake
includes a premium in exchange for the possibility to reduce the
counterparty's exposure to zero, in any given month, if the floating
market price is lower than certain pre-determined knockout prices.
(iv) For written call options, Chesapeake receives a premium from
the counterparty in exchange for the sale of a call option. If the
market price settles below the fixed price of the call option, no
payment is due from Chesapeake.
(v) Collars contain a fixed floor price (put) and ceiling price
(call). If the market price exceeds the call strike price or falls
below the put strike price, Chesapeake receives the fixed price and
pays the market price. If the market price is between the call and the
put strike price, no payments are due from either party.
(vi) A three-way collar contract consists of a standard collar
contract plus a written put option with a strike price below the floor
price of the collar. In addition to the settlement of the collar, the
put option requires Chesapeake to make a payment to the counterparty
equal to the difference between the put option price and the
settlement price if the settlement price for any settlement period is
below the put option strike price.
(vii) Basis protection swaps are arrangements that guarantee a
price differential of oil or natural gas from a specified delivery
point. Chesapeake receives a payment from the counterparty if the
price differential is greater than the stated terms of the contract
and pays the counterparty if the price differential is less than the
stated terms of the contract.
Commodity markets are volatile, and as a result, Chesapeake's
hedging activity is dynamic. As market conditions warrant, the company
may elect to settle a hedging transaction prior to its scheduled
maturity date and lock in the gain or loss on the transaction.
Chesapeake enters into oil and natural gas derivative transactions
in order to mitigate a portion of its exposure to adverse market
changes in oil and natural gas prices. Accordingly, associated gains
or loses from the derivative transactions are reflected as adjustments
to oil and natural gas sales. All realized gains and losses from oil
and natural gas derivatives are included in oil and natural gas sales
in the month of related production. Pursuant to SFAS 133, certain
derivatives do not qualify for designation as cash flow hedges.
Changes in the fair value of these non-qualifying derivatives that
occur prior to their maturity (i.e., because of temporary fluctuations
in value) are reported currently in the consolidated statement of
operations as unrealized gains (losses) within oil and natural gas
sales.
Following provisions of SFAS 133, changes in the fair value of
derivative instruments designated as cash flow hedges, to the extent
effective in offsetting cash flows attributable to hedged risk, are
recorded in other comprehensive income until the hedged item is
recognized in earnings. Any change in fair value resulting from
ineffectiveness is recognized currently in oil and natural gas sales.
Excluding the swaps assumed in connection with the acquisition of
CNR which are described below, the company currently has the following
open natural gas swaps in place and also has the following gains from
lifted natural gas swaps:
Open Swap Total
Positions Lifted
as a Total Gain
Avg. % of Gains per Mcf of
NYMEX Assuming Estimated from Estimated
Open Strike Natural Gas Total Lifted Total
Swaps Price Production Natural Swaps Natural
in of Open in Bcf's Gas ($ Gas
Bcf's Swaps of: Production millions) Production
======================================================================
2007:
--------
Q3 85.9 $8.27 168.5 51% $111.2 $0.66
Q4 95.2 $9.01 173.5 55% $116.8 $0.67
======================================================================
Q3-Q4
2007(1) 181.1 $8.66 342.0 53% $228.0 $0.67
======================================================================
======================================================================
Total
2008(1) 441.7 $9.33 745.5 59% $105.0 $0.14
======================================================================
======================================================================
Total
2009(1) 115.9 $9.37 816.0 14% $3.9 $0.01
======================================================================
(1) Certain hedging arrangements include knockout swaps with
knockout provisions at prices ranging from $5.25 to $6.50 covering 116
bcf in Q3-Q4 2007, $5.75 to $6.50 covering 222 bcf in 2008 and $5.90
to $6.50 covering 116 bcf in 2009.
The company currently has the following open natural gas collars
in place:
Open Collars
as a % of
Avg. Avg. Assuming Estimated
Open NYMEX NYMEX Natural Gas Total
Collars Floor Ceiling Production Natural Gas
in Bcf's Price Price in Bcf's of: Production
======================================================================
2007:
-------------
Q3 22.1 $6.76 $8.20 168.5 13%
Q4 19.6 $7.13 $8.88 173.5 11%
======================================================================
Q3-Q4 2007(1) 41.7 $6.94 $8.52 342.0 12%
======================================================================
======================================================================
Total 2008(1) 26.8 $7.41 $9.40 745.5 4%
======================================================================
======================================================================
Total 2009(1) 18.3 $7.50 $10.72 816.0 2%
======================================================================
(1) Certain collar arrangements include three-way collars that
include written put options with strike prices ranging from $5.00 to
$6.00 covering 33 bcf in Q3-Q4 2007, $5.00 to $6.00 covering 11 bcf in
2008 and $6.00 covering 18 bcf in 2009.
Note: Not shown above are written call options covering 51 bcf of
production in Q3-Q4 2007 at a weighted average price of $9.45 for a
weighted average premium of $0.55, 104 bcf of production in 2008 at a
weighed average price of $10.39 for a weighted average premium of
$0.68 and 72 bcf of production in 2009 at a weighed average price of
$11.38 for a weighted average premium of $0.54.
The company has the following natural gas basis protection swaps
in place:
Mid-Continent Appalachia
---------------------------- ----------------------------
Volume in Volume in
Bcf's NYMEX less(1): Bcf's NYMEX plus(1):
------------- -------------- ------------- --------------
Q3-Q4 2007 78.5 0.37 18.4 0.35
2008 118.6 0.27 43.9 0.35
2009 86.6 0.29 36.5 0.31
2010 -- -- 29.2 0.31
2011 -- -- 29.2 0.32
2012 10.7 0.34 -- --
------------- -------------- ------------- --------------
Totals 294.4 $ 0.31 157.2 $ 0.33
============= ============== ============= ==============
(1) weighted average
We assumed certain liabilities related to open derivative
positions in connection with the CNR acquisition in November 2005. In
accordance with SFAS 141, these derivative positions were recorded at
fair value in the purchase price allocation as a liability of $592
million ($255 million as of June 30, 2007). The recognition of the
derivative liability and other assumed liabilities resulted in an
increase in the total purchase price which was allocated to the assets
acquired. Because of this accounting treatment, only cash settlements
for changes in fair value subsequent to the acquisition date for the
derivative positions assumed result in adjustments to our oil and
natural gas revenues upon settlement. For example, if the fair value
of the derivative positions assumed does not change, then upon the
sale of the underlying production and corresponding settlement of the
derivative positions, cash would be paid to the counterparties and
there would be no adjustment to oil and natural gas revenues related
to the derivative positions. If, however, the actual sales price is
different from the price assumed in the original fair value
calculation, the difference would be reflected as either a decrease or
increase in oil and natural gas revenues, depending upon whether the
sales price was higher or lower, respectively, than the prices assumed
in the original fair value calculation. For accounting purposes, the
net effect of these acquired hedges is that we hedged the production
volumes listed below at their fair values on the date of our
acquisition of CNR.
Pursuant to SFAS 149 "Amendment of SFAS 133 on Derivative
Instruments and Hedging Activities", the assumed CNR derivative
instruments are deemed to contain a significant financing element and
all cash flows associated with these positions are reported as
financing activity in the statement of cash flows.
The following details the CNR derivatives (natural gas swaps) we
have assumed:
Open Swap
Positions
Avg. NYMEX Avg. Fair Assuming as a %
Strike Value Upon Natural of
Open Price Acquisition Initial Gas Estimated
Swaps Of Open of Liability Production Total
in Swaps Open Swaps Acquired in Bcf's Natural Gas
Bcf's (per Mcf) (per Mcf) (per Mcf) of: Production
======================================================================
2007:
Q3 10.6 $4.82 $8.45 ($3.63) 168.5 6%
Q4 10.6 $4.82 $8.87 ($4.05) 173.5 6%
======================================================================
Q3-Q4
2007 21.2 $4.82 $8.66 ($3.84) 342.0 6%
======================================================================
======================================================================
Total
2008 38.4 $4.68 $8.02 ($3.34) 745.5 5%
======================================================================
======================================================================
Total
2009 18.3 $5.18 $7.28 ($2.10) 816.0 2%
======================================================================
Note: Not shown above are collars covering 3.7 bcf of production
in 2009 at an average floor and ceiling of $4.50 and $6.00.
The company also has the following crude oil swaps in place:
Total
Open Swap Total Lifted
Positions as Gains Gain per
Assuming a % from bbl
Open Avg. Oil of Estimated Lifted of
Swaps NYMEX Production Total Swaps Estimated
in Strike in Oil ($ Total Oil
mbbls Price mbbls of: Production millions) Production
======================================================================
2007:
Q3 1,656 $71.61 2,230 74% $2.1 $0.95
Q4 1,656 $71.57 2,300 72% $2.1 $0.91
======================================================================
Q3-Q4
2007(1) 3,312 $71.59 4,530 73% $4.2 $0.93
======================================================================
======================================================================
Total
2008(1) 6,680 $72.77 9,000 74% $4.8 $0.54
======================================================================
======================================================================
Total
2009(1) 2,920 $77.58 9,000 32% -- --
======================================================================
(1) Certain hedging arrangements include cap-swaps and knockout
swaps with provisions limiting the counterparty's exposure below
prices ranging from $45.00 to $60.00 covering 1,472 mbbls in Q3-Q4
2007 and 3,112 mbbls in 2008 and from $52.50 to $60.00 covering 2,738
mbbls in 2009.
Note: Not shown above are written call options covering 916 mbbls
of production in 2008 at a weighted average price of $75.00 for a
weighted average premium of $5.03 and 1,460 mbbls of production in
2009 at a weighed average price of $75.00 for a weighted average
premium of $5.96.
CONTACT: Chesapeake Energy Corporation
Jeffrey L. Mobley, CFA,
405-767-4763
Senior Vice President - Investor Relations and Research
jmobley@chkenergy.com
or
Marc Rowland
405-879-9232
Executive Vice President
and Chief Financial Officer
mrowland@chkenergy.com
SOURCE: Chesapeake Energy Corporation