Press Releases
Chesapeake
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
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/
