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Company Reduces Drilling Capital Expenditure Budget through 2010 by Approximately $3 Billion and Expects Approximately $2 Billion of Excess Cash Generation in 2009 and 2010 to Be Directed Primarily to Debt Reduction Lower Capex and Asset and VPP Sales Lead to Lower Production Growth Forecasts for 2008 of 18% from 21% and for 2009 and 2010 of 16% from 19% Company Closes Fayetteville Shale Joint Venture Transaction with BP America; Discussions Progress on Marcellus Shale Joint Venture; Company Resumes Plans to Sell a $1 Billion Minority Interest in its Midstream Business Company Provides Hedging Update; Substantial Decline in Natural Gas and Oil Prices Has Led to an Approximate $6 Billion Favorable Mark-to-Market Change in the Company's Hedging Positions Since June 30, 2008 Company Completes Three New Haynesville Shale Wells in September with Average per Well Initial Production Rates Exceeding 10 MMcfe per Day
OKLAHOMA CITY, Sep 22, 2008 (BUSINESS WIRE) -- Chesapeake Energy Corporation (NYSE:CHK) today announced plans to reduce
its drilling capital expenditure (capex) budget during the second half
of 2008 through year-end 2010 by approximately $3.2 billion, or 17%, in
response to an approximate 50% decrease in natural gas prices since June
30, 2008 and concerns about the possibility of an emerging U.S. natural
gas surplus in advance of increased demand from the U.S. transportation
sector. Of the $3.2 billion drilling capex reduction, $0.8 billion is
attributable to the drilling capex carry associated with the company's
recently closed Fayetteville Shale joint venture with BP America
(NYSE:BP), $0.5 billion is attributable to the drilling capex carry
anticipated in a Marcellus Shale joint venture and $1.9 billion is
attributable to reduced drilling activity. The company plans to reduce
its current operated drilling rig count of 157 rigs to approximately 140
rigs by year-end 2008 and expects to keep its rig count relatively flat
through 2009 and 2010.
Chesapeake Elects to Temporarily Curtail a Portion of its Current
Natural Gas Production and Lowers its Longer-Term Production Growth
Forecasts; Company Successfully Completes Three Additional Horizontal
Haynesville Shale Wells
In addition to reducing drilling capex, Chesapeake has elected to
temporarily curtail a portion of its unhedged natural gas production in
the Mid-Continent region due to unusually weak wellhead natural gas
prices that are substantially below industry breakeven costs. The
company has curtailed approximately 100 million cubic feet (mmcf) per
day of net natural gas production (approximately 125-150 mmcf per day
gross) and plans to restore this production once natural gas prices
recover from recently depressed wellhead price levels of $3.00 - 5.00
per thousand cubic feet (mcf). This curtailment represents approximately
4% of the company's current net natural gas and oil production capacity
of over 2.3 billion cubic feet of natural gas equivalent per day (92%
natural gas).
The company has also reduced its full-year 2008 production growth
estimate to 18% from 21% to account for the temporary curtailment
discussed above, the sale of 45 million cubic feet of natural gas
equivalent (mmcfe) per day of production associated with its
Fayetteville Shale joint venture with BP, the anticipated sale of 60
mmcfe per day of production in the 2008 fourth quarter associated with
the company's fourth volumetric production
payment (VPP) and shut-ins in the 2008 third quarter of onshore
production associated with natural gas processing plant limitations as a
result of damage by Hurricane Ike.
Additionally, as a result of reduced drilling activity levels announced
today, the company has lowered its anticipated production growth
forecasts in 2009 and 2010 to 16% per year from 19% per year. At these
levels, Chesapeake believes its production growth will still remain at
or near the top of its large-cap peer group, particularly in light of
continued strong drilling results from its shale plays. Notably, during
the month of September, Chesapeake completed three additional horizontal
Haynesville Shale wells with average per well initial production rates
exceeding 10 mmcfe per day bringing its total horizontal Haynesville
Shale wells on production to 14.
Chesapeake Closes $1.9 Billion Fayetteville Shale 25% Joint Venture
Transaction with BP and Continues Negotiations on Marcellus Shale 25%
Joint Venture; Company Resumes Plans to Sell a Minority Interest in its
Midstream Business for Approximately $1 Billion to Help Fund Haynesville
Midstream Capex
On September 19, 2008, Chesapeake closed its Fayetteville Shale 25%
joint venture transaction with BP. In this transaction, the company
received $1.1 billion in cash and will receive a further $800 million
during the remainder of 2008 and in 2009 through the funding of 100% of
Chesapeake's 75% share of drilling and
completion expenditures. In addition, Chesapeake continues to make
progress in its discussions with multiple parties regarding a Marcellus
Shale 25% joint venture that is anticipated to be similar in structure
to the Plains Exploration & Production (NYSE:PXP) Haynesville Shale and
BP Fayetteville Shale transactions. The company anticipates completing a
Marcellus Shale joint venture transaction by year-end 2008.
In addition, Chesapeake has recently resumed plans to sell a minority
interest in its midstream natural gas business to institutional
investors. Projected proceeds of approximately $1 billion will be used
to fund a portion of the costs associated with building the midstream
infrastructure in various shale plays, primarily in the Haynesville
Shale. In preparation for this transaction, the company is in the
process of transferring all of its midstream natural gas assets outside
of Appalachia, which consist primarily of gas gathering systems and
processing assets, into new partnership entities managed by Chesapeake
Midstream Partners, L.P. (CMP). CMP is in the process of finalizing a
secured revolving credit facility for its operations with an initial
borrowing capacity of $500 million. The assets managed by CMP, which are
expected to continue growing substantially in future years, should
generate annualized cash flow from operating activities of approximately
$300 - 350 million in 2009 and $400 - 450 million in 2010. Chesapeake
anticipates that in the next few years, CMP will become the largest
producer-operated midstream natural gas business in the U.S.
Including planned asset sales and as a result of reduced drilling capex,
Chesapeake anticipates generating excess cash of approximately $2
billion in 2009 and 2010 that will be primarily directed to debt
reduction.
Natural Gas and Oil Hedging Update
As of June 30, 2008, Chesapeake's natural gas
and oil hedging positions had a negative mark-to-market value of
approximately $6.5 billion. Subsequent to June 30, the prices of natural
gas and oil have significantly declined and Chesapeake's
hedging positions had a negative mark-to-market value of approximately
$500 million (including settlements for the 2008 third quarter) as of
September 18, 2008, or a favorable change of approximately $6.0 billion.
For the second half of 2008 and for the full years 2009 and 2010,
Chesapeake has hedged through swaps and collars approximately 83%, 72%
and 46% of its expected natural gas and oil production at average prices
of $9.30, $9.63 and $9.89 per thousand cubic feet of natural gas
equivalent (mcfe), respectively. In addition, Chesapeake has collected
approximately $400 million in premiums for written calls with strike
prices above current market prices for its natural gas and oil
production in the second half of 2008 and for the full years 2009 and
2010.
The company's updated forecasts for 2008
through 2010 are attached to this release in an Outlook dated September
22, 2008, labeled as Schedule "A,"
which begins on page 6. This Outlook has been changed from the Outlook
dated July 31, 2008 (attached as Schedule "B,"
which begins on page 11) to reflect various updated information.
Management Comments
Aubrey K. McClendon, Chesapeake's Chief
Executive Officer, commented, "During the
past ten years, Chesapeake has led the E&P industry in production
growth, and through our efforts and those of other leading independent
producers, there are now abundant supplies of natural gas in the U.S.
market. In fact, we believe there is now sufficient domestic natural gas
supply growth to satisfy a growing percentage of the U.S. transportation
fuel market through the use of CNG-fueled vehicles. However, until the
market has sufficient incentives for service station owners to build out
CNG infrastructure, for auto manufacturers to offer new CNG vehicles in
large quantities and for consumers to install home refueling devices,
retrofit existing vehicles and purchase new CNG vehicles, insufficient
natural gas demand exists to prevent periodic declines in wellhead
natural gas prices below the industry's
breakeven profitability levels.
"Therefore, we believe it is in the best
interests of Chesapeake's shareholders to
temporarily curtail a portion of our natural gas production, reduce the
company's drilling capex and lower our
production growth to provide time for rising natural gas demand to catch
up with increasing natural gas supply. We have made these decisions even
though Chesapeake is well hedged, has one of the lowest cost structures
in the large-cap E&P industry and has a substantial portion of its capex
budget during the next few years carried by other companies. We will
monitor market conditions and bring curtailed natural gas production
volumes back on stream as prices improve. We remain confident that
natural gas is the single best solution to meeting America's energy,
transportation and environmental challenges in the years ahead and we
will continue our industry-leading efforts to increase both supply and
demand for clean, affordable and abundant American natural gas.
"We are hopeful that many of Chesapeake's
shareholders, employees and royalty owners, along with public officials
and natural gas consumers across the country, have seen and appreciated
the company's new advertising campaign, CNG
Now. We strongly believe that natural gas is the cleanest and most
affordable alternative to expensive imported oil, has a very large and
important role to play in rejuvenating the U.S. auto manufacturing
industry, can help lower greenhouse gas emissions and can help reduce
the financial burden of high gasoline prices on Americans. We intend to
continue our advertising campaign and encourage producers and consumers
alike to indicate their support to federal, state and local officials.
"Further, we are pleased that our
Fayetteville Shale joint venture transaction with BP is now in place and
look forward to completing a similar joint venture in the Marcellus
Shale. We are also happy to report that we have resumed efforts to sell
a $1 billion minority interest in our midstream natural gas business.
Our midstream business has grown substantially over the past three years
and is well positioned for further growth as it builds additional
gathering infrastructure in the Barnett, Fayetteville and Haynesville
Shale plays to support the company's rapid
production growth in these areas. Now that the Haynesville Shale's
success is more visible to potential midstream equity partners, we
believe it is the right time to initiate a new process to bring in an
equity partner interested in helping fund anticipated growth in our
midstream business.
"Finally, I am also pleased to announce that
Chesapeake completed three new horizontal Haynesville Shale wells in
September with average initial production rates exceeding 10 mmcfe per
day on restricted chokes with high flowing casing pressure. We look
forward to initial production commencing from our first PXP joint
venture Haynesville Shale well in October and will provide a full update
on the Haynesville Shale and other important plays at our Investor and
Analyst Meeting in Oklahoma City on October 15 and 16, 2008. This
meeting will be webcast so that all investors will be able to learn more
about our operations and prospects for future growth."
Conference Call Information
A conference call to discuss this release has been scheduled for Tuesday
morning, September 23, 2008, at 9:00 a.m. EDT. The telephone number to
access the conference call is 913-312-4374 or toll-free 888-221-9584.
The passcode for the call is 5132124. We encourage those who
would like to participate in the call to dial the access number between
8:50 and 9:00 a.m. EDT. For those unable to participate in the
conference call, a replay will be available for audio playback from noon
EDT on September 23, 2008 through midnight EDT on Tuesday, October 7,
2008. The number to access the conference call replay is 719-457-0820
or toll-free 888-203-1112. The passcode for the replay is 5132124.
The conference call will also be webcast live on the Internet and can be
accessed by going to Chesapeake's website at www.chk.com
and selecting the "News & Events"
section. The webcast of the conference call will be available on our
website for one year.
Chesapeake Energy Corporation is the largest producer of natural gas
in the U.S. Headquartered in Oklahoma City, the company's
operations are focused on exploratory and developmental drilling and
corporate and property acquisitions in the Fort Worth Barnett Shale,
Haynesville Shale, Fayetteville Shale, Anadarko Basin, Arkoma Basin,
Appalachian Basin, Permian Basin, Delaware Basin, South Texas, Texas
Gulf Coast and Ark-La-Tex regions of the United States. Further
information is available at www.chk.com.
This press release includes "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 planned
capital expenditures for drilling and other anticipated cash outflows
(including amounts budgeted for leasehold and property acquisitions,
geophysical costs, compression and other PP&E, midstream assets,
dividends, interest and income taxes), expected natural gas and oil
production and future expenses, projections of future natural gas and
oil prices, and planned asset sales, as well as statements concerning
anticipated cash flow and liquidity, expected uses of future excess cash
flow, 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 "Risk
Factors" in the Prospectus Supplement we
filed with the U.S. Securities and Exchange Commission on July 10, 2008.
These risk factors include the volatility of natural gas and oil prices;
the limitations our level of indebtedness may have on our financial
flexibility; our ability to compete effectively against strong
independent natural gas and oil companies and majors; the availability
of capital on an economic basis, including planned asset monetization
transactions, to fund reserve replacement costs; our ability to replace
reserves and sustain production; uncertainties inherent in
estimating quantities of natural gas and oil reserves and projecting
future rates of production and the amount and timing of development
expenditures; uncertainties in evaluating natural gas and oil 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 natural gas and oil properties resulting in ceiling
test write-downs; risks associated with our natural gas and oil hedging
program, including realizations on hedged natural gas and oil sales that
are lower than market prices, collateral required to secure hedging
liabilities and losses resulting from counterparty failure; the negative
impact lower natural gas and oil 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.
SCHEDULE "A"
CHESAPEAKE'S OUTLOOK AS OF September 22,
2008
Quarters Ending September 30, 2008 and December 31, 2008 and Years
Ending December 31, 2008, 2009 and 2010.
We have adopted a policy of periodically providing guidance on certain
factors that affect our future financial performance. As of September
22, 2008, we are using the following key assumptions in our projections
for the third and fourth quarters of 2008 and the full years 2008, 2009
and 2010.
The primary changes from our July 31, 2008 Outlook are in italicized
bold and are explained as follows:
1) Our first guidance for the 2008 fourth quarter has been provided;
2) Projected production volumes have been updated to reflect reduction
in rig count and anticipated divestitures;
3) Projected effects of changes in our hedging positions have been
updated;
4) Certain cost assumptions and budgeted capital expenditure assumptions
have been updated; and
5) Our NYMEX natural gas and oil price assumptions for estimating future
operating cash flow have been reduced.
Quarter Ending Quarter Ending Year Ending 12/31/2008 Year Ending 12/31/2009 Year Ending 12/31/2010
9/30/2008 12/31/2008
Estimated Production(a)
Natural gas -- bcf 196 -- 199 197 -- 201 777 -- 781 893 -- 913 1,032 -- 1,072
Oil -- mbbls 2,825 2,825 11,200 12,000 13,000
Natural gas equivalent -- bcfe 213 -- 216 214 -- 218 844 -- 848 965 -- 985 1,110 --1,150
Daily natural gas equivalent midpoint -- 2,330 2,350 2,310 2,670 3,095
mmcfe
Year-over-year production increase 15.0% 5.9% 18.0% 15.6% 15.9%
NYMEX Prices(b) (for
calculation of realized hedging effects only):
Natural gas - $/mcf $10.24 $7.50 $9.18 $8.00 $8.00
Oil - $/bbl $120.06 $110.00 $112.99 $110.00 $120.00
Estimated Realized Hedging Effects (based on assumed NYMEX prices
above):
Natural gas - $/mcf ($0.82) $1.94 $0.24 $1.04 $0.85
Oil - $/bbl ($39.97) ($28.38) ($32.74) ($44.74) ($28.90)
Estimated Differentials to NYMEX Prices:
Natural gas - $/mcf 10 -- 14% 10 -- 14% 10 -- 14% 10 -- 14% 10 -- 14%
Oil - $/bbl 5 -- 7% 5 -- 7% 5 -- 7% 5 -- 7% 5 -- 7%
Operating Costs per Mcfe of Projected Production:
Production expense $1.00 -- 1.10 $1.00 -- 1.10 $1.00 -- 1.10 $1.10 -- 1.20 $1.15 -- 1.25
Production taxes (~ 5% of O&G revenues)(c) $0.45 -- 0.50 $0.35 -- 0.40 $0.40 -- 0.45 $0.35 -- 0.40 $0.35 -- 0.40
General and administrative(d) $0.33 -- 0.37 $0.33 -- 0.37 $0.33 -- 0.37 $0.33 -- 0.37 $0.33 -- 0.37
Stock-based compensation (non-cash) $0.10 -- 0.12 $0.10 -- 0.12 $0.10 -- 0.12 $0.10 -- 0.12 $0.10 -- 0.12
DD&A of natural gas and oil assets $2.35 -- 2.40 $2.30 -- 2.35 $2.30 -- 2.40 $2.20 -- 2.30 $2.15 -- 2.25
Depreciation of other assets $0.20 -- 0.24 $0.20 -- 0.24 $0.20 -- 0.24 $0.20 -- 0.24 $0.20 -- 0.24
Interest expense(e) $0.35 -- 0.40 $0.30 -- 0.35 $0.35 -- 0.40 $0.40 -- 0.45 $0.35 -- 0.40
Other Income per Mcfe:
Natural gas and oil marketing income $0.09 -- 0.11 $0.09 -- 0.11 $0.09 -- 0.11 $0.09 -- 0.11 $0.09 -- 0.11
Service operations income $0.04 -- 0.06 $0.04 -- 0.06 $0.04 -- 0.06 $0.04 -- 0.06 $0.04 -- 0.06
Book Tax Rate 38.5% 38.5% 38.5% 38.5% 38.5%
Cash Income Taxes -- in millions -- $350 - 450 $350 -- 450 $200 -- 300 $200 -- 300
Equivalent Shares Outstanding -- in
millions:
Basic 553 -- 557 560 -- 565 530 - 535 565 - 570 575 - 580
Diluted 593 -- 598 595 -- 600 565 - 570 600 - 605 610 - 615
Cash Flow Projections -- in millions Quarter Ending 9/30/2008 Quarter Ending 12/31/2008 Year Ending 12/31/2008 Year Ending 12/31/2009 Year Ending 12/31/2010
Inflows:
Operating cash flow before changes in assets and liabilities(f)(g) $1,250 -- 1,350 $1,350 -- 1,450 $5,550 -- 5,750 $5,650 -- 6,250 $6,500 -- 7,100
Sale of leasehold and producing properties(a) $4,650 -- 4,750 $1,650 -- 1,850 $6,550 -- 6,850 $1,750 -- 2,250 $750 -- 1,250
Sale of producing properties via VPP's(a) $600 $550 -- 650 $1,775 -- 1,875 $1,100 -- 1,300 $1,100 -- 1,300
Debt and equity offerings $1,585 -- $4,730 -- --
Midstream financings $200 -- 250 $650 -- 850 $850 -- 1,100 $650 -- 850 $650 -- 850
Proceeds from investments and other $100 -- 150 -- $275 -- 325 $775 -- 825 $150 -- 250
Total Cash Inflows $8,385 -- 8,685 $4,200 -- 4,800 $19,730 -- 20,630 $9,925 -- 11,475 $9,150 -- 10,750
Outflows:
Drilling $1,450 -- 1,550 $1,200 -- 1,300 $5,500 -- 5,700 $4,500 -- 5,000 $5,000 -- 5,500
Acquisition of leasehold and producing properties $4,750 -- 5,250 $1,000 -- 1,500 $8,500 -- 9,500 $2,000 -- 2,250 $1,250 -- 1,750
Geophysical costs $75 $75 $300 $225 -- 275 $225 -- 275
Compression and other PP&E $225 -- 250 $100 -- 125 $1,000 -- 1,050 $500 -- 550 $250 -- 300
Midstream infrastructure $275 -- 300 $375 -- 400 $1,200 -- 1,250 $1,350 -- 1,500 $750 -- 950
Dividends, senior notes redemption, capitalized interest, etc. $550 -- 600 $150 -- 200 $1,150 -- 1,250 $575 -- 600 $500 -- 550
Cash income taxes -- $350 -- 450 $350 -- 450 $200 -- 300 $200 -- $300
Total Cash Outflows $7,325 -- 8,025 $3,250 -- 4,050 $18,000 -- 19,500 $9,350 -- 10,475 $8,175 -- 9,625
Net Cash Change $660 -- 1,060 $750 -- 950 $1,130 -- 1,730 $575 --1,000 $975 -- 1,125
(a) The 2008 production and cash flow forecasts reflect sales completed
in the 2008 first half and both completed and anticipated sales by the
company of: 1) producing properties for $600 million in the 2008 third
quarter and approximately $600 million in the 2008 fourth quarter in two
volumetric production payment (VPP) transactions; 2) Haynesville Shale
undeveloped leasehold for $1.85 billion to PXP in the 2008 third
quarter; 3) Arkoma Basin Woodford Shale properties for $1.75 billion to
BP in the 2008 third quarter; 4) Arkoma Basin Fayetteville Shale
properties for $1.1 billion to BP in the 2008 third quarter and 5)
undeveloped leasehold in the Marcellus Shale and other areas for
approximately $1.75 billion in the 2008 fourth quarter. The 2009 and
2010 production and cash flow forecasts reflect sales by the company of
producing properties for approximately $1.2 billion each year in VPP
transactions and undeveloped leasehold for approximately $2.0 billion in
2009 and approximately $1.0 billion in 2010.
(b) NYMEX oil prices have been updated for actual contract prices
through August 2008 and NYMEX natural gas prices have been updated for
actual contract prices through September 2008.
(c) Severance tax per mcfe is based on NYMEX prices of $120.06 per bbl
of oil and $9.50 to $10.50 per mcf of natural gas during Q3 2008;
$110.00 per bbl of oil and $7.00 to $8.00 per mcf of natural gas during
Q4 2008; $112.99 per bbl of oil and $8.25 to $9.50 per mcf of natural
gas during calendar 2008; $110.00 per bbl of oil and $7.00 to $8.50 per
mcf of natural gas during 2009; and $120.00 per bbl of oil and $7.00 to
$8.50 per mcf of natural gas during 2010.
(d) Excludes expenses associated with noncash stock compensation.
(e) Does not include gains or losses on interest rate derivatives (SFAS
133).
(f) A non-GAAP financial measure. We are unable to provide a
reconciliation to projected cash provided by operating activities, the
most comparable GAAP measure, because of uncertainties associated with
projecting future changes in assets and liabilities.
(g) Assumes NYMEX natural gas of $7.50 to $8.50 per mcf and NYMEX oil
prices of $110.00 per bbl.
Commodity Hedging Activities
The company utilizes hedging strategies to hedge the price of a portion
of its future natural gas and oil production. These strategies include:
(i) For swap instruments, Chesapeake receives a fixed price and pays a
floating market price 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) Basis protection swaps are arrangements that guarantee a price
differential for oil or natural gas from a specified delivery point. For
Mid-Continent basis protection swaps, which have negative differentials
to NYMEX, 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. For Appalachian basis protection swaps, which
have positive differentials to NYMEX, Chesapeake receives a payment from
the counterparty if the price differential is less than the stated terms
of the contract and pays the counterparty if the price differential is
greater than the stated terms of the contract.
(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 predetermined knockout prices.
(iv) 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
(v) 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.
(vi) 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.
(vii) 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.
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 natural gas and oil derivative transactions in
order to mitigate a portion of its exposure to adverse market changes in
natural gas and oil prices. Accordingly, associated gains or losses from
the derivative transactions are reflected as adjustments to natural gas
and oil sales. All realized gains and losses from natural gas and oil
derivatives are included in natural gas and oil 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 nonqualifying 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 natural gas and oil 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 natural gas and oil 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 (losses) from lifted
natural gas swaps:
Open Swaps Avg. NYMEX Assuming Open Swap Total Gains Total Lifted Gain
in Bcf's Strike Price Natural Gas Positions as a (Losses) from (Loss) per Mcf of
of Open Swaps Production % of Estimated Lifted Swaps Estimated
in Bcf's of: Total Natural ($ millions) Total Natural Gas
Gas Production Production
Q3 2008 154.5 $8.99 198 78% $38.8 $0.20
Q4 2008 147.5 $9.43 199 74% $53.4 $0.27
Q3-Q4 2008(1) 302.0 $9.21 397 76% $92.2 $0.23
Total 2009(1) 570.1 $9.54 903 63% ($135.9) ($0.15)
Total 2010(1) 470.0 $9.70 1,052 45% ($68.9) ($0.07)
(1) Certain hedging arrangements include knockout swaps with
provisions limiting the counterparty's
exposure below prices ranging from $5.45 to $7.50 covering 138 bcf in
2008, $5.45 to $7.50 covering 356 bcf in 2009 and $5.45 to $7.50
covering 318 bcf in 2010.
The company currently has the following open natural gas collars
in place:
Open Collars Avg. NYMEX Avg. NYMEX Assuming Open Collars
in Bcf's Floor Price Ceiling Price Natural Gas as a % of
Production Estimated Total
in Bcf's of: Natural Gas
Production
Q3 2008 8.3 $8.17 $10.26 198 4%
Q4 2008 6.5 $8.04 $10.33 199 3%
Q3-Q4 2008 14.8 $8.11 $10.29 397 4%
Total 2009(1) 63.9 $8.05 $11.18 903 7%
Total 2010(1) 25.6 $7.71 $11.46 1,052 2%
(1) Certain collar arrangements include three-way collars that
include written put options with strike prices ranging from $5.50 to
$6.00 covering 38 bcf in 2009 and at $6.00 to $6.50 covering 4 bcf in
2010.
The company currently has the following natural gas written call
options in place:
Call Options Avg. NYMEX Avg. Premium Assuming Call Options
in Bcf's Call Price per mcf Natural Gas as a % of
Production Estimated Total
in Bcf's of: Natural Gas
Production
Q3 2008 25.2 $10.25 $0.86 198 13%
Q4 2008 34.0 $10.39 $0.70 199 17%
Q3-Q4 2008 59.2 $10.32 $0.78 397 15%
Total 2009 225.5 $11.37 $0.61 903 25%
Total 2010 231.8 $10.77 $0.72 1,052 22%
The company has the following natural gas basis protection swaps
in place:
Mid-Continent Appalachia
Volume in Bcf's NYMEX less(1): Volume in Bcf's NYMEX plus(1):
2008 65.7 $ 0.47 11.6 $ 0.33
2009 77.1 0.35 16.9 0.28
2010 -- -- 10.2 0.26
2011 32.2 0.68 12.1 0.25
2012 30.4 0.49 -- --
Totals 205.4 $ 0.46 50.8 $ 0.28
(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 ($102 million
as of June 30, 2008). 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 natural gas and oil 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 natural
gas and oil 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 natural gas and oil 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 Avg. NYMEX Avg. Fair Initial Assuming Open Swap
Swaps Strike Price Value Upon Liability Natural Gas Positions as a %
in Bcf's Of Open Acquisition of Acquired Production of Estimated Total
Swaps Open Swaps (per Mcf) in Bcf's of: Natural Gas
(per Mcf) (per Mcf) Production
Q3 2008 9.7 $4.68 $7.41 ($2.74) 198 5%
Q4 2008 9.7 $4.66 $7.84 ($3.17) 199 5%
Q3-Q4 2008 19.4 $4.67 $7.62 ($2.95) 397 5%
Total 2009 18.3 $5.18 $7.28 ($2.10) 903 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 $6.00.
The company also has the following crude oil swaps in place:
Open Avg. NYMEX Assuming Open Swap Total Losses Total Lifted
Swaps Strike Price Oil Positions as a % from Lifted Losses per
in mbbls Production of Estimated Swaps bbl of
in mbbls of: Total Oil Production ($ millions) Estimated
Total Oil
Production
Q3 2008 1,979 $76.45 2,825 70% ($4.6) ($1.63)
Q4 2008 1,702 $77.57 2,825 60% ($4.7) ($1.68)
Q3-Q4 2008(1) 3,681 $76.97 5,650 65% ($9.3) ($1.66)
Total 2009(1) 8,395 $82.33 12,000 70% -- --
Total 2010(1) 4,745 $90.25 13,000 37% -- --
(1) Certain hedging arrangements include cap-swaps and
knockout swaps with provisions limiting the counterparty's
exposure below prices ranging from $45.00 to $65.00 covering 2,148 mbbls
in 2008, from $52.50 to $60.00 covering 7,848 mbbls in 2009 and $60.00
covering 4,745 mbbls in 2010.
Note: Not shown above are written call options covering 1,534 mbbls
of production in 2008 at a weighted average price of $85.23 for a
weighted average premium of $3.34, 3,285 mbbls of production in 2009 at
a weighed average price of $122.22 for a weighted average premium of
$6.07 and 3,285 mbbls of production in 2010 at a weighed average price
of $131.67 for a weighted average premium of $6.94.
SCHEDULE "B"
CHESAPEAKE'S PREVIOUS OUTLOOK AS OF JULY
31, 2008
(PROVIDED FOR REFERENCE ONLY)
NOW SUPERSEDED BY OUTLOOK AS OF SEPTEMBER 22, 2008
Quarter Ending September 30, 2008 and Years Ending December 31, 2008,
2009 and 2010.
We have adopted a policy of periodically providing guidance on certain
factors that affect our future financial performance. As of July 31,
2008, we are using the following key assumptions in our projections for
the third quarter of 2008 and the full years 2008, 2009 and 2010.
The primary changes from our July 16, 2008 Outlook are in italicized
bold and are explained as follows:
1) Our first guidance for the 2008 third quarter has been provided;
2) Projected effects of changes in our hedging positions have been
updated;
3) Certain cost assumptions and budgeted capital expenditure assumptions
have been updated; and
4) Our NYMEX natural gas and oil price assumptions for estimating future
operating cash flow have been reduced.
Quarter Ending Year Ending Year Ending Year Ending
9/30/2008 12/31/2008 12/31/2009 12/31/2010
Estimated Production(a)
Natural gas -- bcf 198 -- 204 791 -- 801 943 -- 963 1,122 -- 1,162
Oil -- mbbls 2,730 11,000 12,000 13,000
Natural gas equivalent -- bcfe 214 -- 220 857 -- 867 1,015 -- 1,035 1,200 --1,240
Daily natural gas equivalent midpoint -- 2,360 2,360 2,810 3,340
mmcfe
Year-over-year production increase 16% 21% 19% 19%
NYMEX Prices(b) (for
calculation of realized hedging effects only):
Natural gas - $/mcf $11.04 $10.00 $10.00 $10.00
Oil - $/bbl $110.00 $110.47 $110.00 $110.00
Estimated Realized Hedging Effects (based on assumed NYMEX prices
above):
Natural gas - $/mcf ($1.51) ($0.42) ($0.02) $0.13
Oil - $/bbl $(31.94) ($31.02) ($33.91) ($19.80)
Estimated Differentials to NYMEX Prices:
Natural gas - $/mcf 10 -- 14% 10 -- 14% 10 -- 14% 10 -- 14%
Oil - $/bbl 5 -- 7% 5 -- 7% 5 -- 7% 5 -- 7%
Operating Costs per Mcfe of Projected Production:
Production expense $0.95 -- 1.05 $0.95 -- 1.05 $1.00 -- 1.10 $1.05 -- 1.15
Production taxes (~ 5% of O&G revenues)(c) $0.45 -- 0.50 $0.45 -- 0.50 $0.45 -- 0.50 $0.45 -- 0.50
General and administrative(d) $0.33 -- 0.37 $0.33 -- 0.37 $0.33 -- 0.37 $0.33 -- 0.37
Stock-based compensation (non-cash) $0.10 -- 0.12 $0.10 -- 0.12 $0.10 -- 0.12 $0.10 -- 0.12
DD&A of natural gas and oil assets $2.35 -- 2.40 $2.30 -- 2.40 $2.25 -- 2.35 $2.20 -- 2.30
Depreciation of other assets $0.20 -- 0.24 $0.20 -- 0.24 $0.20 -- 0.24 $0.20 -- 0.24
Interest expense(e) $0.45 -- 0.50 $0.45 -- 0.50 $0.45 -- 0.50 $0.45 -- 0.50
Other Income per Mcfe:
Natural gas and oil marketing income $0.09 -- 0.11 $0.09 -- 0.11 $0.09 -- 0.11 $0.09 -- 0.11
Service operations income $0.04 -- 0.06 $0.04 -- 0.06 $0.04 -- 0.06 $0.04 -- 0.06
Book Tax Rate 38.5% 38.5% 38.5% 38.5%
Cash Income Taxes -- in millions -- $100 -- 250 -- --
Equivalent Shares Outstanding -- in
millions:
Basic 553 - 557 530 - 535 565 - 570 575 - 580
Diluted 593 - 598 565 - 570 600 - 605 610 - 615
Quarter Ending 9/30/2008 Year Ending 12/31/2008 Year Ending 12/31/2009 Year Ending 12/31/2010
Cash Flow Projections -- in millions
Inflows:
Operating cash flow before changes in assets and liabilities(f)(g) $1,200 -- 1,300 $5,600 -- 5,700 $6,400 -- 7,000 $7,600 -- 8,900
Sale of leasehold and producing properties(a) $6,750 -- 7,250 $8,250 -- 8,750 $2,500 -- 3,500 $2,500 -- 3,500
Debt and equity offerings $1,575 $4,725 -- --
Proceeds from investments and other $75 -- 100 $425 -- 450 $550 -- 650 $550 -- 650
Total Cash Inflows $9,600 -- 10,225 $19,000 -- 19,625 $9,450 -- 11,150 $10,650 -- 13,050
Outflows:
Drilling $1,550 -- 1,650 $5,750 -- 6,250 $6,000 -- 6,500 $6,250 -- 6,750
Acquisition of leasehold and producing properties $5,000 -- 5,500 $8,250 -- 8,750 $2,000 -- 2,250 $2,000 -- 2,250
Geophysical costs $75 $300 $250 -- 275 $250 -- 275
Midstream, compression and other PP&E $400 -- 450 $2,000 -- 2,250 $1,000 -- 1,250 $1,000 -- 1,250
Dividends, Sr. Notes redemption, capitalized interest, etc. $550 -- 600 $1,150 -- 1,250 $575 -- 600 $575 -- 600
Cash income taxes -- $100 -- 250 -- --
Total Cash Outflows $7,575 -- 8,275 $17,550 -- 19,050 $9,825 -- 10,875 $10,075 -- 11,125
Net Cash Change $1,950 -- 2,025 $575 -- 1,450 ($375) -- 275 $575 -- 1,925
(a) The 2008 forecast reflects sales completed in the 2008 first half
and both completed and anticipated sales by the company of: 1) producing
properties for $605 million in the 2008 third quarter in a volumetric
production payment (VPP) transaction; 2) Haynesville undeveloped
leasehold for $1.650 billion in the 2008 third quarter; 3) Arkoma Basin
properties for $1.75 billion in the 2008 third quarter; and 4)
undeveloped leasehold or producing properties for $3.5 - 4.5 billion in
the 2008 second half. The 2009 and 2010 forecasts assume that the
company sells undeveloped leasehold or producing properties for $3.0 -
4.0 billion in each year.
(b) NYMEX oil prices have been updated for actual contract prices
through June 2008 and NYMEX natural gas prices have been updated for
actual contract prices through July 2008.
(c) Severance tax per mcfe is based on NYMEX prices of $100.00 per bbl
of oil and $9.50 to $10.50 per mcf of natural gas during Q3 2008;
$105.47 per bbl of oil and $9.50 to $10.50 per mcf of natural gas during
calendar 2008; and $110.00 per bbl of oil and $9.50 to $10.50 per mcf of
natural gas during 2009 and 2010.
(d) Excludes expenses associated with noncash stock compensation.
(e) Does not include gains or losses on interest rate derivatives (SFAS
133).
(f) A non-GAAP financial measure. We are unable to provide a
reconciliation to projected cash provided by operating activities, the
most comparable GAAP measure, because of uncertainties associated with
projecting future changes in assets and liabilities.
(g) Assumes NYMEX natural gas of $9.00 to $11.00 per mcf and NYMEX oil
prices of $110.00 per bbl.
Commodity Hedging Activities
The company utilizes hedging strategies to hedge the price of a portion
of its future natural gas and oil production. These strategies include:
(i) For swap instruments, Chesapeake receives a fixed price and pays a
floating market price 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) Basis protection swaps are arrangements that guarantee a price
differential for oil or natural gas from a specified delivery point. For
Mid-Continent basis protection swaps, which have negative differentials
to NYMEX, 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. For Appalachian basis protection swaps, which
have positive differentials to NYMEX, Chesapeake receives a payment from
the counterparty if the price differential is less than the stated terms
of the contract and pays the counterparty if the price differential is
greater than the stated terms of the contract.
(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 predetermined knockout prices.
(iv) 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
(v) 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.
(vi) 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.
(vii) 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.
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 natural gas and oil derivative transactions in
order to mitigate a portion of its exposure to adverse market changes in
natural gas and oil prices. Accordingly, associated gains or losses from
the derivative transactions are reflected as adjustments to natural gas
and oil sales. All realized gains and losses from natural gas and oil
derivatives are included in natural gas and oil 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 nonqualifying 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 natural gas and oil 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 natural gas and oil 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 (losses) from lifted
natural gas swaps:
Open Swaps Avg. NYMEX Assuming Open Swap Total Gains Total Lifted Gain
in Bcf's Strike Price Natural Gas Positions as a (Losses) from (Loss) per Mcf of
of Open Swaps Production % of Estimated Lifted Swaps Estimated
in Bcf's of: Total Natural ($ millions) Total Natural Gas
Gas Production Production
Q3 2008 154.5 $8.99 201 77% $38.8 $0.19
Q4 2008 144.8 $9.56 213 68% $50.4 $0.24
Q3-Q4 2008(1) 299.3 $9.26 414 72% $89.2 $0.22
Total 2009(1) 494.1 $9.88 953 52% ($154.7) ($0.16)
Total 2010(1) 269.3 $10.02 1,142 24% ($66.3) ($0.06)
(1) Certain hedging arrangements include knockout swaps with
provisions limiting the counterparty's
exposure below prices ranging from $5.45 to $7.50 covering 138 bcf in
2008, 5.45 to $7.50 covering 343 bcf in 2009 and $5.45 to $7.50 covering
172 bcf in 2010.
The company currently has the following open natural gas collars
in place:
Open Collars Avg. NYMEX Avg. NYMEX Assuming Open Collars
in Bcf's Floor Price Ceiling Price Natural Gas as a % of
Production Estimated Total
in Bcf's of: Natural Gas
Production
Q3 2008 8.3 $8.17 $10.26 201 4%
Q4 2008 6.5 $8.04 $10.33 213 3%
Q3-Q4 2008 14.8 $8.11 $10.29 414 4%
Total 2009(1) 63.9 $8.05 $11.18 953 7%
Total 2010(1) 25.6 $7.71 $11.46 1,142 2%
(1) Certain collar arrangements include three-way collars that
include written put options with strike prices ranging from $5.50 to
$6.00 covering 38 bcf in 2009 and at $6.00 covering 4 bcf in 2010.
The company currently has the following natural gas written call
options in place:
Call Options Avg. NYMEX Avg. Premium Assuming Call Options
in Bcf's Call Price per mcf Natural Gas as a % of
Production Estimated Total
in Bcf's of: Natural Gas
Production
Q3 2008 28.2 $10.25 $0.86 201 14%
Q4 2008 34.0 $10.39 $0.91 213 16%
Q3-Q4 2008 62.2 $10.32 $0.89 414 16%
Total 2009 225.5 $11.37 $0.71 953 24%
Total 2010 308.4 $10.74 $0.71 1,142 27%
The company has the following natural gas basis protection swaps
in place:
Mid-Continent Appalachia
Volume in Bcf's NYMEX less(1): Volume in Bcf's NYMEX plus(1):
2008 72.4 0.44 11.6 0.33
2009 91.1 0.33 16.9 0.28
2010 -- -- 10.2 0.26
2011 34.2 0.68 12.1 0.25
2012 32.1 0.49 -- --
Totals 229.8 $ 0.44 50.8 $ 0.28
(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 ($102 million
as of June 30, 2008). 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 natural gas and oil 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 natural
gas and oil 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 natural gas and oil 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 Avg. NYMEX Avg. Fair Initial Assuming Open Swap
Swaps Strike Price Value Upon Liability Natural Gas Positions as a %
in Bcf's Of Open Acquisition of Acquired Production of Estimated Total
Swaps Open Swaps (per Mcf) in Bcf's of: Natural Gas
(per Mcf) (per Mcf) Production
Q3 2008 9.7 $4.68 $7.41 ($2.74) 201 5%
Q4 2008 9.7 $4.66 $7.84 ($3.17) 213 5%
Q3-Q4 2008 19.4 $4.67 $7.62 ($2.95) 414 5%
Total 2009 18.3 $5.18 $7.28 ($2.10) 953 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 $6.00.
The company also has the following crude oil swaps in place:
Open Avg. NYMEX Assuming Open Swap Total Losses Total Lifted
Swaps Strike Price Oil Positions as a % from Lifted Losses per
in mbbls Production of Estimated Swaps bbl of
in mbbls of: Total Oil Production ($ millions) Estimated
Total Oil
Production
Q3 2008 2,039 76.92 2,730 75% $(4.6) $(1.69)
Q4 2008 1,886 79.01 2,710 70% $(4.7) $(1.75)
Q3-Q4 2008(1) 3,925 $77.93 5,440 72% $(9.3) $(1.72)
Total 2009(1) 8,395 $82.33 12,000 70% -- --
Total 2010(1) 4,745 $90.25 13,000 37% -- --
(1) Certain hedging arrangements include cap-swaps and
knockout swaps with provisions limiting the counterparty's
exposure below prices ranging from $45.00 to $65.00 covering 2,392 mbbls
in 2008, from $52.50 to $60.00 covering 7,848 mbbls in 2009 and $60.00
covering 4,745 mbbls in 2010.
Note: Not shown above are written call options covering 1,472 mbbls
of production in 2008 at a weighted average price of $82.50 for a
weighted average premium of $3.27, 2,555 mbbls of production in 2009 at
a weighed average price of $146.43 for a weighted average premium of
$4.98 and 2,555 mbbls of production in 2010 at a weighed average price
of $160.71 for a weighted average premium of $3.79.
SOURCE: Chesapeake Energy Corporation
Chesapeake Energy Corporation
Jeffrey L. Mobley, CFA, 405-767-4763
Senior Vice President --
Investor Relations and Research
jeff.mobley@chk.com
or
Marc Rowland, 405-879-9232
Executive Vice President
and Chief Financial Officer
marc.rowland@chk.com