Company to Acquire 18,000 Acre North Block Property in Johnson County, Texas,
Located Just North of Chesapeake's Existing 44%-Owned 30,000 Acre South Block
Joint Venture With Hallwood
Transaction Includes Production of 25 Mmcfe Per Day and 280 Bcfe of Internally
Estimated Reserves, Consisting of 135 Bcfe of Proved Reserves and 145 Bcfe of
Probable and Possible Reserves
Acquisition Boosts Chesapeake's Production Forecast By 3.6% for 2005 and 5.8%
for 2006 as Estimated Production on Acquired Property Increases to 40 Mmcfe
per Day in 2005 and 70 Mmcfe per Day in 2006
OKLAHOMA CITY, Nov. 30 /PRNewswire-FirstCall/ -- Chesapeake (NYSE: CHK)
today announced that it has entered into an agreement with Hallwood Energy
Corporation to acquire Hallwood's 18,000 acre North Block property in Johnson
County, Texas for $277 million in cash. This property is located immediately
north of Hallwood's 30,000 acre South Block property, in which Chesapeake
acquired a 44% working interest through its June 2002 acquisition of Canaan
Energy Corporation.
In this transaction, Chesapeake anticipates acquiring an internally
estimated 135 billion cubic feet of natural gas equivalent proved reserves
(bcfe), 145 bcfe of probable and possible reserves and net production of
approximately 25 million cubic feet of natural gas equivalent production
(mmcfe) per day from 31 vertical wells and 11 horizontal wells. Chesapeake
has identified approximately 70 proved undeveloped and 90 probable and
possible horizontal drilling locations on the 18,000 acre North Block that it
believes can be drilled at an average cost of approximately $2.2 million per
well to develop estimated ultimate reserves (EUR) of 2.5 bcfe per well. Pro
forma for this acquisition, Chesapeake's proved oil and natural gas reserves
will increase to an internally estimated 4.6 trillion cubic feet of natural
gas equivalent (tcfe) as of September 30, 2004.
After allocating $98 million of the $277 million purchase price to
undeveloped leasehold, Chesapeake's acquisition cost for the 135 bcfe of
internally estimated proved reserves will be $1.33 per thousand cubic feet of
natural gas equivalent (mcfe). Including $303 million of anticipated future
drilling costs to fully develop the proved, probable and possible (3P)
reserves, the company estimates that its all-in acquisition cost for the
280 bcfe of 3P reserves will be $2.07 per mcfe. In addition, Chesapeake has
agreed to purchase Hallwood's North Block gas gathering, compression and water
disposal assets for $15 million.
The North Block proved reserves have a reserves-to-production index of
14.8 years, are 100% gas, are 15% proved developed, have current lease
operating expenses of $0.22 per mcfe, have severance taxes of 1.3% of the
wellhead revenue value and will be 100% Chesapeake-operated. The property's
very low lease operating expenses (approximately $0.53 per mcfe below the
industry average) and unusually low severance taxes (approximately $0.37 below
the standard 7.5% Texas severance tax rate at $6.00 per mcf because of
severance tax reductions applicable to certain types of newly drilled wells in
Texas) create an approximate $0.90 per mcfe economic advantage over typical
Mid-Continent natural gas properties.
Through the use of a three-rig drilling program, the company believes it
can increase gas production on the acquired property from 25 mmcfe per day in
December 2004 to at least 55 mmcfe per day by December 2005 and to at least
85 mmcfe per day by December 2006. If these production increases are
achieved, Chesapeake estimates that its average daily production in 2005 and
2006 will increase by 40 and 70 mmcfe per day, respectively (see Chesapeake's
updated Outlook as of November 30, 2004 attached as Exhibit "A"). The company
has hedged the current 25 mmcfe per day of acquired production at NYMEX gas
prices of $7.15 per mmbtu and $6.63 per mmbtu for 2005 and 2006, respectively,
well above the gas prices used to evaluate the property.
The acquisition is expected to close on December 15, 2004 and is subject
to customary closing conditions. The company intends to finance the
acquisition using a portion of the proceeds from a new $600 million private
issue of senior notes.
Hallwood is a private company and was advised in the sale by Albrecht &
Associates, Inc. of Houston, Texas.
Management Comment
Aubrey K. McClendon, Chesapeake's Chief Executive Officer, commented, "We
are pleased to announce today's acquisition of the Hallwood North Block
acreage for several reasons. First, we are building our Barnett Shale
ownership and creating economies of scale by leveraging off our acquisition of
Canaan Energy Corporation in June 2002. In that $120 million transaction we
inherited an initial Barnett Shale leasehold position in Johnson County,
Texas, to which we initially gave no value. Today it appears that
Chesapeake's South Block Barnett Shale position may be worth more than what we
paid for the entire Canaan transaction.
"Second, Chesapeake is well positioned to continue Hallwood's successful
production ramp-up currently underway, having worked closely with Hallwood for
two years in the South Block and because of our extensive experience with
horizontal drilling (more than 285 horizontal wells drilled in Texas since
1990) and 3-D seismic (more than 9.0 million acres owned). Hallwood's use of
horizontal drilling, innovative completion techniques and 3-D seismic
information during the past few years has been very effective on both the
18,000 North Block property and the 30,000 acre South Block property.
"Finally, we believe we have been conservative in our reserve estimates
for the acquired property, both with regard to our estimated EUR's of 2.5 bcfe
per horizontal well and to our planned PUD drilling pattern of 140 acres and
2,000' standoffs for horizontal wellbores. Over time, we are hopeful that our
reserve estimates can increase and that our well spacing can decrease, leading
to significantly higher recoverable proved reserves than currently projected.
We look forward to adding further value to this prolific gas-producing area of
the Mid-Continent region in the years to come."
Conference Call Information
A conference call has been scheduled for Wednesday morning,
December 1, 2004 at 9:00 a.m. EST to discuss this release. The telephone
number to access the conference call is 913.981.5592. For those unable to
participate in the conference call, a replay will be available from 12:00 p.m.
EST, December 1, 2004 through midnight EST on December 14, 2004. The number
to access the conference call replay is 719.457.0820 and the passcode is
915998. The conference call will also be simulcast live on the Internet and
can be accessed at http://www.chkenergy.com by selecting "Conference Calls"
under the "Investor Relations" section. The webcast of the conference call
will be available on the 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 gas reserves, expected oil and gas production and
future expenses, projections of future oil and 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
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.
Factors that could cause actual results to differ materially from expected
results are described under "Risk Factors" in our prospectus dated
September 10, 2004 filed with the Securities and Exchange Commission on
September 10, 2004. They include the volatility of oil and gas prices;
adverse effects our substantial indebtedness and preferred stock obligations
could have on our operations and future growth; our ability to compete
effectively against strong independent oil and gas companies and majors;
possible financial losses and significant collateral requirements as a result
of our commodity price and interest rate risk management activities;
uncertainties inherent in estimating quantities of oil and gas reserves,
including reserves we acquire; projecting future rates of production and the
timing of development expenditures; exposure to potential liabilities of
acquired properties and companies; our ability to replace reserves; the
availability of capital; writedowns of oil and gas carrying values if
commodity prices decline; environmental and other claims in excess of insured
amounts resulting from drilling and production operations; and the loss of key
personnel. We caution you not to place undue reliance on these forward-
looking statements, which speak only as of the date of this press release, and
we undertake no obligation to update this information.
Our production forecasts are dependent upon many assumptions, including
estimates of production decline rates from existing wells and the outcome of
future drilling activity. Also, our internal estimates of reserves,
particularly those in the property proposed to be acquired where we may have
limited review of data or experience with the reserves, may be subject to
revision and may be different from estimates by our external reservoir
engineers at year-end. Although we believe the expectations, estimates 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 and data or by known or unknown
risks and uncertainties.
The SEC has generally permitted oil and gas companies, in filings made
with the SEC, to disclose only proved reserves that a company has demonstrated
by actual production or conclusive formation tests to be economically and
legally producible under existing economic and operating conditions. We use
the terms "probable" and "possible" reserves or other descriptions of volumes
of reserves potentially recoverable through additional drilling or recovery
techniques that the SEC's guidelines may prohibit us from including in filings
with the SEC. These estimates are by their nature more speculative than
estimates of proved reserves and accordingly are subject to substantially
greater risk of being actually realized by the company.
The announcement of a proposed debt financing in this press release shall
not constitute an offer to sell or a solicitation of an offer to buy any
securities. The debt securities will likely not be registered under the
Securities Act of 1933 or any state securities laws, and may not be offered or
sold in the United States absent registration or an applicable exemption from
the registration requirements of the Securities Act and state laws.
Chesapeake Energy Corporation is the sixth largest independent producer of
natural gas in the U.S. Headquartered in Oklahoma City, the company's
operations are focused on exploratory and developmental drilling and producing
property acquisitions in the Mid-Continent, Permian Basin, South Texas, Texas
Gulf Coast and Ark-La-Tex regions of the United States. The company's
Internet address is http://www.chkenergy.com .
SCHEDULE "A"
CHESAPEAKE'S OUTLOOK AS OF NOVEMBER 30, 2004
Quarter Ending December 31, 2004; Year Ending December 31, 2004; Year
Ending December 31, 2005; Year Ending December 31, 2006.
We have adopted a policy of periodically providing investors with guidance
on certain factors that affect our future financial performance. As of
November 30, 2004, we are using the following key assumptions in our
projections for the fourth quarter of 2004, the full-year 2004, the full-year
2005 and the full-year 2006.
The primary changes from our November 1, 2004 Outlook are explained as
follows:
1) We have updated our previous production forecasts for 2005 and 2006
to reflect increases in production of 40 mmcfe per day in 2005 and
70 mmcfe per day in 2006 as a result of the announced acquisition of
Hallwood Energy Corporation. This increases our full-year 2005
production forecast by 3.6% to a mid-point of 1,155 mmcfe per day and
our 2006 production forecast by 5.8% to a mid-point of 1,270 mmcfe
per day.
2) We have increased capital expenditures by $50 million in each of 2005
and 2006 to reflect increased drilling activity planned on the
Hallwood North Block property.
3) We have updated the projected effects from changes in our hedging
positions since our November 1, 2004 Outlook.
4) We have included our expectations for future NYMEX oil and gas prices
to illustrate hedging effects only.
5) We have adjusted equivalent shares outstanding to reflect i) the
conversion of our 6.75% preferred stock into common shares on
November 22, 2004, ii) a recent private exchange of 600,000 shares of
our 6.0% preferred stock for 3.225 million of our common shares, and
iii) our pending tender offer to exchange our remaining 6.0%
preferred stock for an estimated 21.2 million common shares.
Quarter Ending Year Ending Year Ending Year Ending
December 31, December 31, December 31, December 31,
2004 2004 2005 2006
Estimated
Production:
Oil - Mbo 1,588 6,560 6,600 6,600
Gas - Bcf 88.5 - 89.5 317 - 319 379 - 387 418 - 428
Gas Equivalent
- Bcfe 98 - 99 356 - 358 418 - 426 458 - 468
Daily gas
equivalent
midpoint - in
Mmcfe 1,069 975 1,155 1,270
NYMEX Prices (for
calculation of
realized hedging
effects only):
Oil - $/Bo $46.67 $41.00 $40.00 $36.00
Gas - $/Mcf $6.60 $6.01 $6.00 $6.00
Estimated
Differentials to
NYMEX Prices:
Oil - $/Bo -$2.75 -$2.65 -$2.75 -$2.75
Gas - $/Mcf -$0.75 -$0.70 -$0.70 -$0.70
Estimated
Realized Hedging
Effects (based
on expected NYMEX
prices above):
Oil - $/Bo -$15.85 -$10.19 $0.06 $0.00
Gas - $/Mcf -$0.53 -$0.23 $0.05 -$0.01
Operating Costs
per Mcfe of
Projected
Production:
Production
expense $0.57 - 0.62 $0.57 - 0.62 $0.62 - 0.67 $0.68 - 0.72
Production taxes
(generally
7% of O&G
revenues) $0.40 - 0.44 $0.28 - 0.33 $0.38 - 0.40 $0.38 - 0.40
General and
administrative $0.10 - 0.11 $0.10 - 0.11 $0.10 - 0.11 $0.11 - 0.12
Stock based
compensation
(non-cash) $0.02 - 0.04 $0.02 - 0.04 $0.04 - 0.06 $0.09 - 0.10
DD&A - oil
and gas $1.65 - 1.70 $1.60 - 1.65 $1.65 - 1.75 $1.75 - 1.85
Depreciation of
other assets $0.08 - 0.10 $0.08 - 0.10 $0.09 - 0.11 $0.10 - 0.12
Interest
expense(a) $0.45 - 0.49 $0.45 - 0.49 $0.43 - 0.47 $0.43 - 0.47
Other Income and
Expense per Mcfe:
Marketing and
other income $0.02 - 0.04 $0.02 - 0.04 $0.02 - 0.04 $0.02 - 0.04
Book Tax Rate 36% 36% 36% 36%
Equivalent Shares
Outstanding:
Basic 279 mm 254 mm 313 mm 316 mm
Diluted 347 mm 327 mm 351 mm 354 mm
Capital
Expenditures:
Drilling,
leasehold and
seismic $300 - $325 $1,100 - $1,250 - $1,350 -
mm $1,150 mm $1,350 mm $1,450 mm
(a) 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 gas production. These strategies include:
(i) For swap instruments, we receive a fixed price for the hedged
commodity and pay 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) Basis protection swaps are arrangements that guarantee a price
differential of oil or 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, as a
result, 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 gas sales.
All realized gains and losses from oil and natural gas derivatives are
included in oil and 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 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.
The company currently has in place the following natural gas swaps:
% Hedged
Avg. Avg. NYMEX Open Swap
NYMEX Gain Price Assuming Positions
Strike (Loss) Including Gas as a % of
Price from Open Production Estimated
Open Swaps Of Open Locked & Locked in Total Gas
in Bcf's Swaps Swaps Positions Bcf's of: Production
2004:
1st Qtr 69.5 $5.94 $0.03 $5.97 70.1 99%
2nd Qtr 62.2 $5.15 $0.00 $5.15 76.5 81%
3rd Qtr(1) 70.7 $5.49 -$0.09 $5.40 83.2 85%
4th Qtr(1) 76.5 $5.88 -$0.11 $5.77 89.0 86%
Total 2004 278.9 $5.63 -$0.05 $5.58 318.8 88%
2005:
1st Qtr 60.6 $6.89 -$0.11 $6.78 91.5 66%
2nd Qtr 34.9 $5.97 -$0.30 $5.67 94.5 37%
3rd Qtr 30.8 $5.96 -$0.35 $5.61 97.5 32%
4th Qtr 21.6 $6.10 -$0.50 $5.60 99.5 22%
Total 2005(1) 147.9 $6.36 -$0.26 $6.10 383.0 39%
Total 2006(1)(2) 32.0 $6.62 -$0.76 $5.86 423.0 8%
Total 2007(2) --- --- --- --- 450.0 ---
TOTALS
2005-2007 179.9 $6.41 -$0.35 $6.06 1,256.0 14%
(1) Certain hedging arrangements include swaps with knockout prices
ranging from $3.50 to $5.25 covering 25.4 bcf in 2004, $3.75 to
$5.00 covering 52.9 bcf in 2005 and $3.75 to $5.25 covering 21.1 bcf
in 2006.
(2) Swaps covering 25.6 bcf have been locked for 2007. This will result
in the recognition of $11.6 million of losses in 2007 when the
hedging arrangements settle.
(3) Not shown above are collars covering 1.1 bcf and 4.4 bcf of
production in Q4 2004 and in 2005, respectively, at a weighted
average floor and ceiling of $3.10 and $4.44. In addition, call
options covering 10.2 bcf and 7.3 bcf of production in Q4 2004 and
in 2005 at a weighted average price of $6.31 and $6.00 are not
included in the table above.
The company has also entered into the following natural gas basis
protection swaps:
Assuming Gas
Volume Production
in Bcf's NYMEX less: in Bcf's of: % Hedged
2004 157.4 0.17 318.8 49%
2005 186.1 0.26 383.0 49%
2006 124.1 0.31 423.0 29%
2007 118.7 0.27 450.0 26%
2008 108.0 0.25 475.0 23%
2009 80.3 0.28 500.0 16%
Totals 774.6 $0.25 2,549.8 30%
* weighted average
The company has entered into the following crude oil hedging arrangements:
% Hedged
Open Swap
Positions as %
Assuming Oil of Total
Open Swaps Avg. NYMEX Production Estimated
in mbo's Strike Price in mbo's of: Production
Q1 - 2004 1,270 $28.58 1,465 87%
Q2 - 2004 1,540 $30.00 1,673 92%
Q3 - 2004(1) 1,519 $30.32 1,834 83%
Q4 - 2004(1) 1,518 $30.10 1,588 96%
Total 2004(1) 5,847 $29.80 6,560 89%
Q1 - 2005 855 $41.76 1,650 52%
Q2 - 2005 865 $41.63 1,650 52%
Q3 - 2005 138 $31.16 1,650 8%
Q4 - 2005 138 $30.62 1,650 8%
Total 2005(1) 1,996 $40.20 6,600 30%
(1) Certain hedging arrangements include swaps with knockout prices
ranging from $21.00 to $26.00 covering 2,240 mbo in 2004 and
knockout prices ranging from $26.00 to $34.00 covering 1,996 mbo in
2005.
SCHEDULE "B"
CHESAPEAKE'S PREVIOUS OUTLOOK AS OF NOVEMBER 1, 2004
(PROVIDED FOR REFERENCE ONLY)
NOW SUPERSEDED BY OUTLOOK AS OF NOVEMBER 30, 2004
Quarter Ending December 31, 2004; Year Ending December 31, 2004; Year
Ending December 31, 2005; Year Ending December 31, 2006.
We have adopted a policy of periodically providing investors with guidance
on certain factors that affect our future financial performance. As of
November 1, 2004, we are using the following key assumptions in our
projections for the fourth quarter of 2004, the full-year 2004, the full-year
2005 and the full-year 2006.
The primary changes from our July 26, 2004 Outlook are explained as
follows:
1) We have deleted our 2004 third quarter forecast and have updated our
forecasts for the 2004 fourth quarter, the full-year 2004 and full-
year 2005 forecasts and have provided our initial 2006 forecast.
2) We have updated our previous production forecast for the full-year
2004 to reflect actual third quarter 2004 production, which exceeded
the mid-point of our guidance by 24 mmcfe per day, or 2.4%. In
addition, we have revised upward our fourth quarter 2004 production
forecast by 20 mmcfe per day, or 2.0%, from the mid-point of our
previous guidance, ii) our full-year 2004 production forecast by
8 mmcfe per day, or 0.8%, from the mid-point of our previous
guidance, iii) our full-year 2005 forecast by 33 mmcfe per day, or
3.0%, from the mid-point of our previous guidance, all to account for
better than expected 2004 drilling results. The mid-point of our
initial 2006 production forecast is 438 bcfe, or 1,200 mmcfe per day,
a projected increase of 7.6% over the midpoint of our revised 2005
forecast and 23.1% above the mid-point of our revised 2004 production
forecast.
3) We have updated the projected effects from changes in our hedging
positions since our July 26, 2004 Outlook.
4) We have included our expectations for future NYMEX oil and gas prices
to illustrate hedging effects only.
5) For ease of reconciliation, please note that our first quarter 2004
production was 78.9 bcfe, our second quarter 2004 production was
86.5 bcfe, our third quarter production was 94.2 bcfe and our first
nine months 2004 production was 259.7 bcfe. Our July 26, 2004
Outlook forecasted a third quarter 2004 production range of 91.5 to
92.5 bcfe and a full-year 2004 production range of 353 to 355 bcfe.
The differences are attributable to better than expected 2004
drilling results.
Quarter Ending Year Ending Year Ending Year Ending
December 31, December 31, December 31, December 31,
2004 2004 2005 2006
Estimated
Production:
Oil - Mbo 1,588 6,560 6,600 6,600
Gas - Bcf 88.5 - 89.5 317 - 319 364 - 372 393 - 403
Gas Equivalent
- Bcfe 98 - 99 356 - 358 403 - 411 433 - 443
Daily gas
equivalent
midpoint -
in Mmcfe 1,069 975 1,115 1,200
NYMEX Prices
(for calculation
of realized
hedging effects
only):
Oil - $/Bo $46.67 $41.00 $40.00 $36.00
Gas - $/Mcf $6.60 $6.01 $6.00 $6.00
Estimated
Differentials to
NYMEX Prices:
Oil - $/Bo -$2.75 -$2.65 -$2.75 -$2.75
Gas - $/Mcf -$0.75 -$0.70 -$0.70 -$0.70
Estimated Realized
Hedging Effects
(based on expected
NYMEX prices
above):
Oil - $/Bo -$15.85 -$10.19 $0.06 $0.00
Gas - $/Mcf -$0.53 -$0.23 $0.00 -$0.04
Operating Costs
per Mcfe of
Projected
Production:
Production
expense $0.57 - 0.62 $0.57 - 0.62 $0.62 - 0.67 $0.68 - 0.72
Production
taxes
(generally
7% of O&G
revenues) $0.40 - 0.44 $0.28 - 0.33 $0.38 - 0.40 $0.38 - 0.40
General and
administrative $0.10 - 0.11 $0.10 - 0.11 $0.10 - 0.11 $0.11 - 0.12
Stock based
compensation
(non-cash) $0.02 - 0.04 $0.02 - 0.04 $0.04 - 0.0 $0.09 - 0.10
DD&A - oil
and gas $1.65 - 1.70 $1.60 - 1.65 $1.65 - 1.75 $1.75 - 1.85
Depreciation of
other assets $0.08 - 0.10 $0.08 - 0.10 $0.09 - 0.11 $0.10 - 0.12
Interest
expense(a) $0.45 - 0.49 $0.45 - 0.49 $0.43 - 0.47 $0.43 - 0.47
Other Income and
Expense per Mcfe:
Marketing and
other income $0.02 - 0.04 $0.02 - 0.04 $0.02 - 0.04 $0.02 - 0.04
Book Tax Rate 36% 36% 36% 36%
Equivalent Shares
Outstanding:
Basic 279 mm 254 mm 288 mm 290 mm
Diluted 347 mm 317 mm 349 mm 352 mm
Capital Expenditures:
Drilling,
leasehold and
seismic $300 - $325 $1,100 - $1,200 - $1,300 -
mm $1,150 mm $1,300 mm $1,400 mm
(a) 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 gas production. These strategies include:
(i) For swap instruments, we receive a fixed price for the hedged
commodity and pay 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) Basis protection swaps are arrangements that guarantee a price
differential of oil or 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, as a
result, 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 gas sales.
All realized gains and losses from oil and natural gas derivatives are
included in oil and 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 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.
The company currently has in place the following natural gas swaps:
% Hedged
Avg. Avg. NYMEX Open Swap
NYMEX Gain Price Assuming Positions
Strike (Loss) Including Gas as a % of
Price from Open Production Estimated
Open Swaps Of Open Locked & Locked in Total Gas
in Bcf's Swaps Swaps Positions Bcf's of: Production
2004:
1st Qtr 69.5 $5.94 $0.03 $5.97 70.1 99%
2nd Qtr 62.2 $5.15 $0.00 $5.15 76.5 81%
3rd Qtr(1) 70.7 $5.49 -$0.09 $5.40 83.2 85%
4th Qtr(1) 76.5 $5.88 -$0.11 $5.77 89.0 86%
Total 2004 278.9 $5.63 -$0.05 $5.58 318.8 88%
2005:
1st Qtr 56.1 $6.82 -$0.17 $6.65 92.0 61%
2nd Qtr 30.4 $5.86 -$0.35 $5.51 92.0 33%
3rd Qtr 26.2 $5.77 -$0.41 $5.36 92.0 28%
4th Qtr 17.0 $5.85 -$0.63 $5.22 92.0 18%
Total 2005(1) 129.7 $6.26 -$0.30 $5.96 368.0 35%
Total 2006(1)(2) 13.8 $6.64 -$1.77 $4.87 398.0 3%
Total 2007(2) --- --- --- --- 430.0 ---
TOTALS
2005-2007 143.5 $6.30 -$0.44 $5.86 1,196.0 12%
(1) Certain hedging arrangements include swaps with knockout prices
ranging from $3.50 to $5.25 covering 25.4 bcf in 2004, $3.75 to
$5.00 covering 52.9 bcf in 2005 and $3.75 to $5.25 covering 21.1 bcf
in 2006.
(2) Swaps covering 25.6 bcf have been locked for 2007. This will result
in the recognition of $11.6 million of losses in 2007 when the
hedging arrangements settle.
(3) Not shown above are collars covering 1.1 bcf and 4.4 bcf of
production in Q4 2004 and in 2005, respectively, at a weighted
average floor and ceiling of $3.10 and $4.44. In addition, call
options covering 10.2 bcf and 7.3 bcf of production in Q4 2004 and
in 2005 at a weighted average price of $6.31 and $6.00 are not
included in the table above.
The company has also entered into the following natural gas basis
protection swaps:
Assuming Gas
Volume Production
in Bcf's NYMEX less: in Bcf's of: % Hedged
2004 157.4 0.17 318.8 49%
2005 175.2 0.25 368.0 48%
2006 113.1 0.30 398.0 28%
2007 107.7 0.26 430.0 25%
2008 108.0 0.25 460.0 23%
2009 80.3 0.28 490.0 16%
Totals 741.7 $0.26 2,464.8 30%
* weighted average
The company has entered into the following crude oil hedging arrangements:
% Hedged
Open Swap
Positions as %
Assuming Oil of Total
Open Swaps Avg. NYMEX Production Estimated
in mbo's Strike Price in mbo's of: Production
Q1 - 2004 1,270 $28.58 1,465 87%
Q2 - 2004 1,540 $30.00 1,673 92%
Q3 - 2004(1) 1,519 $30.32 1,834 83%
Q4 - 2004(1) 1,518 $30.10 1,588 96%
Total 2004(1) 5,847 $29.80 6,560 89%
Q1 - 2005 855 $41.76 1,650 52%
Q2 - 2005 865 $41.63 1,650 52%
Q3 - 2005 138 $31.16 1,650 8%
Q4 - 2005 138 $30.62 1,650 8%
Total 2005(1) 1,996 $40.20 6,600 30%
(1) Certain hedging arrangements include swaps with knockout prices
ranging from $21.00 to $26.00 covering 2,240 mbo in 2004 and
knockout prices ranging from $26.00 to $34.00 covering 1,996 mbo in
2005.
SOURCE Chesapeake Energy Corporation
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Related links:
http://www.chkenergy.com
CONTACT:
Marc Rowland, Executive Vice President and
Chief Financial Officer, +1-405-879-9232, or Tom Price, Jr.,
Senior Vice President-Investor Relations, +1-405-879-9257, both
of Chesapeake Energy Corporation
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