Transaction Will Include Production of 30 Mmcfe per Day and 500 Bcfe of
Internally Estimated Reserves, Consisting of 223 Bcfe of Proved Reserves and
277 Bcfe of Probable and Possible Reserves
Acquisition Will Boost Chesapeake's Production Forecast by 2.8% for 2005 and
4.3% for 2006 as Estimated Average Daily Production Should Increase by
35 Mmcfe Per Day in 2005 and 55 Mmcfe Per Day in 2006
OKLAHOMA CITY, Dec. 27 /PRNewswire-FirstCall/ -- Chesapeake Energy
Corporation (NYSE: CHK) today announced that it has entered into an agreement
to acquire Tulsa-based privately-held BRG Petroleum Corporation and related
partnerships for $325 million in cash. In this transaction, Chesapeake
anticipates acquiring an internally estimated 223 billion cubic feet of
natural gas equivalent proved reserves (bcfe), 277 bcfe of probable and
possible reserves and net production of approximately 30 million cubic feet of
natural gas equivalent production (mmcfe) per day from 477 existing wells.
After allocating $71 million of the $325 million purchase price to BRG's
estimated 120,000 net acres of undeveloped leasehold (and related probable and
possible reserves) and $5 million to mid-stream assets, Chesapeake's
acquisition cost for the 223 bcfe of internally estimated proved reserves will
be $1.12 per thousand cubic feet of natural gas equivalent (mcfe). Including
$492 million of anticipated future costs to fully develop the proved, probable
and possible (3P) reserves, the company estimates that its all-in acquisition
cost for acquiring and developing the 500 bcfe of 3P reserves should be
$1.62 per mcfe based on the company's projected development plan and
anticipated future drilling costs. The BRG proved reserves have a
reserves-to-production index of 20.3 years (9.7 years excluding proved
undeveloped reserves), are 93% gas, are 48% proved developed, have current
lease operating expenses of $0.53 per mcfe and will be 96% Chesapeake-operated
(by value).
BRG's properties are concentrated in the Mid-Continent and Ark-La-Tex
regions. In these areas, Chesapeake has identified 213 proved undeveloped and
420 probable and possible locations on BRG's leasehold. The drilling
locations are concentrated in the Sahara gas resource play in Northwest
Oklahoma and in the East Texas Cotton Valley gas resource play in Nacogdoches
County, Texas. Current well economics in Sahara involve investing $550,000 to
develop an estimated ultimate recovery (EUR) of 0.6 bcfe and current Cotton
Valley economics in Nacogdoches County involve investing $900,000 to develop
an estimated EUR of 0.9 bcfe. Pro forma for this acquisition, Chesapeake
expects that its proved oil and natural gas reserves will increase to an
internally estimated 4.8 trillion cubic feet of natural gas equivalent (tcfe)
as of December 31, 2004.
Through the use of two rigs in 2005 and four rigs in 2006, the company
believes it can increase gas production on the acquired properties from
30 mmcfe per day at closing in February 2005 to 40 mmcfe per day in December
2005 and to 70 mmcfe per day in December 2006. If these production increases
are achieved, Chesapeake estimates that its total average daily production in
2005 and 2006 will increase by 35 and 55 mmcfe per day, respectively (see
Chesapeake's updated Outlook as of December 27, 2004 attached as Exhibit "A").
The company has hedged 67% of BRG's current gas production at NYMEX gas prices
of $7.42 per mmbtu and $7.45 per mmbtu for 2005 and 2006, respectively, well
above the gas prices used to evaluate the property.
The BRG acquisition is expected to close on February 1, 2005 and is
subject to customary closing conditions and purchase price adjustments. The
company intends to finance the acquisition from cash on hand and by using its
bank credit facility. Chesapeake expects to expand its bank credit facility
to $1 billion and to extend the maturity of the facility to 2010. BRG was
advised in the sale by Randall & Dewey of Houston, Texas.
Management Comment
Aubrey K. McClendon, Chesapeake's Chief Executive Officer, commented, "We
are pleased to announce today's proposed acquisition of BRG for several
reasons. First, BRG will add to our very strong presence in the
Mid-Continent, especially in the Sahara region of Northwest Oklahoma. Since
establishing our initial Sahara position by acquiring 50,000 net leasehold
acres through our acquisitions of DLB Oil & Gas, Inc. and Hugoton Energy
Corporation in 1998, we now control more than 500,000 net acres in Sahara. To
date, we have drilled more than 600 wells in this area and believe we can
drill approximately 2,500 additional wells in the next 5-10 years, providing
more than 1 tcfe of potential gas resource upside to Chesapeake's existing
approximate five tcfe of proved reserves. We believe Sahara is one of the
great gas resources plays in the U.S. and fortunately from a competitive
standpoint, one of the least recognized by the industry.
In addition, through BRG we will be building on Chesapeake's Ark-La-Tex
position that was initially established through our Greystone Petroleum LLC
transaction in June 2004. In that transaction, we acquired a significant
interest in the Sligo Field in North Louisiana's Bossier Parish. In just
seven months, we have increased our net production on the property from
45 mmcfe per day to today's rate of approximately 60 mmcfe per day. In
addition, from an estimated proved reserve base of 214 bcfe at the date of
acquisition, we have already been able to increase Greystone's proved reserves
by approximately 10%.
In this latest Ark-La-Tex acquisition, Chesapeake will be acquiring
42,000 gross (37,000 net) leasehold acres in the Naconiche Creek area of
Nacogdoches County, Texas from BRG. During the past few years, BRG has
drilled more than 75 wells in this area to prove the commerciality of this
promising gas resource play. We now intend to accelerate further development
of the field by drilling over 600 additional wells that should develop an
average estimated EUR of 0.9 bcfe per well for a per well investment of
$900,000. After royalties, our finding costs should be approximately
$1.25 per mcfe with virtually no dry-hole risk.
In the BRG transaction, as with all of our acquisitions, we are hopeful
that over time our reserve estimates will increase and that our well spacing
will decrease, leading to significantly higher recoverable reserves than
originally projected at the time of acquisition. We look forward to adding
further value to the attractive gas resource plays acquired from BRG in the
years to come."
Hallwood Transaction Closes as Scheduled
On December 15, 2004, Chesapeake closed its $292 million acquisition of
Barnett Shale properties from Dallas-based Hallwood Energy Corporation. In
the Hallwood acquisition, Chesapeake acquired Hallwood's 18,000 acre North
Block assets in Johnson County, Texas. Through this transaction, Chesapeake
acquired 135 bcfe of proved reserves, 145 bcfe of probable and possible
reserves and net production of approximately 25 mcfe per day. Chesapeake is
currently utilizing two rigs to further develop the North Block assets and is
participating as non-operator in two rigs operated by Hallwood that are
operating on Hallwood's South Block, in which Chesapeake owns a 44% working
interest.
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 exchange offer prospectus
dated November 30, 2004 (as amended on December 16, 2004) we filed with the
Securities and Exchange Commission on December 20, 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 undertaking
and outcome of future drilling activity, which may be affected by significant
commodity price declines or drilling cost increases. Also, our internal
estimates of reserves, particularly those in the properties 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 or ultimately 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.
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 DECEMBER 27, 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
December 27, 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.
We expect to record non-operating losses in Q4 2004 in connection with our
pending cash tender offer for our $209.8 million of 8.375% senior notes due
2008 and our pending offer to exchange our 6.0% convertible preferred stock
for our common stock. If we purchase all of our 8.375% senior notes pursuant
to the tender offer, we estimate that an after-tax loss on the early
redemption of the notes of $12 million will be recorded in Q4 2004 as an
adjustment to net earnings. If all our 6.0% preferred stock is exchanged for
common stock, we estimate that a loss on the early conversion of the preferred
stock of approximately $37 million will be reflected as an adjustment to net
income available to common shareholders for the purpose of calculating basic
earnings per share in Q4 2004.
The primary changes from our November 30, 2004 Outlook are explained as
follows:
(1) We have updated our previous production forecasts for 2005 and 2006
to reflect increases in production of 35 mmcfe per day in 2005
(excluding January) and 55 mmcfe per day in 2006 as a result of the
announced acquisition of BRG Petroleum Corporation. This increases
our full-year 2005 production forecast by 2.8% to a mid-point of
1,190 mmcfe per day and our 2006 production forecast by 4.3% to a
mid-point of 1,325 mmcfe per day.
(2) We have increased capital expenditures by $50 million in 2005 and
$100 million in 2006 to reflect planned increased drilling activity
planned on the BRG and other company properties.
(3) We have updated the projected effects from changes in our hedging
positions since our November 30, 2004 Outlook.
(4) We have included our expectations for future NYMEX oil and gas
prices to illustrate hedging effects only.
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 - 319 391 - 399 438 - 448
Gas
Equivalent
- Bcfe 98 - 99 356 - 358 430 - 438 478 - 488
Daily gas
equivalent
midpoint
- in Mmcfe 1,069 975 1,190 1,325
NYMEX Prices
(for
calculation
of realized
hedging
effects only):
Oil - $/Bo $46.67 $41.00 $40.00 $40.00
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 $1.75 - 1.80 $1.80 - 1.90
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 - $1,100 - $1,300 - $1,450 -
$325 mm $1,150 mm $1,400 mm $1,550 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 62.4 $6.91 -$0.11 $6.80 93.4 67%
2nd Qtr 38.5 $6.05 -$0.27 $5.78 97.5 39%
3rd Qtr 34.5 $6.06 -$0.31 $5.75 100.8 34%
4th Qtr 23.5 $6.20 -$0.46 $5.74 103.0 23%
Total 2005(1) 158.9 $6.41 -$0.24 $6.17 394.7 40%
Total 2006(1) 39.3 $6.77 -$0.62 $6.15 443.0 9%
Total 2007(2) -- -- -- -- 470.0 --
TOTALS
2005-2007 198.2 $6.48 -$0.31 $6.17 1,307.7 15%
(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
$5.50 covering 60.2 bcf in 2005 and $3.75 to $5.50 covering 28.4 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.
Note: 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 188.6 0.26 394.7 48%
2006 130.1 0.32 443.0 29%
2007 126.5 0.28 470.0 27%
2008 118.6 0.27 495.0 24%
2009 86.6 0.29 520.0 17%
Totals 807.8 $0.26 2,641.5 31%
* 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 30, 2004
(PROVIDED FOR REFERENCE ONLY)
NOW SUPERSEDED BY OUTLOOK AS OF DECEMBER 27, 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 - $1,100 - $1,250 - $1,350 -
$325 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.
Note: 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.
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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