Press Releases
Chesapeake Energy Corporation
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 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
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
Web site: http://www.chkenergy.com/
