Press Releases
Chesapeake Energy Corporation
Chesapeake has also recently acquired or agreed to acquire an additional 28,000 net acres of leasehold, primarily in Johnson and Tarrant Counties, from various additional sellers for $87 million. On this acreage, Chesapeake anticipates drilling 400 net wells to develop 650 bcfe of unproved reserves. Including an estimated $1.1 billion of capital needed to fully develop the 650 bcfe of unproved reserves, Chesapeake's all-in acquisition cost for the additional acreage will be $1.80 per mcfe.
Through these transactions, Chesapeake anticipates acquiring an internally estimated 1.5 trillion cubic feet of natural gas equivalent (tcfe) of proved and unproved reserves, comprised of 0.16 tcfe of proved reserves and 1.36 tcfe of unproved reserves. Including an estimated $2.3 billion of capital needed to fully develop the 1.5 tcfe of proved and unproved reserves, Chesapeake's all-in acquisition cost for the Four Sevens/Sinclair properties and the additional acreage will be $2.10 per mcfe.
Chesapeake anticipates increasing the 30 mmcfe of net daily production from the Four Sevens/Sinclair assets to at least 45-50 mmcfe by year-end 2006 and 80-100 mmcfe by year-end 2007. The company has not yet estimated a production ramp-up from the other Barnett Shale acquisitions, but believes it will also be significant. Chesapeake plans to close all of today's announced Barnett Shale transactions by July 31, 2006 and anticipates permanently financing the acquisitions by issuing a balance of senior notes and preferred equity in the near future.
Today's announcements increase Chesapeake's total leasehold in the Barnett Shale to approximately 153,000 net acres, including 110,000 net acres in Johnson and Tarrant Counties, which are in the heart of the most prolific portion of the horizontally developed Barnett Shale play. The company has pro forma current net production of 140 mmcfe per day (200 mmcfe gross) and believes it can drill an additional 2,100 net Barnett Shale wells to potentially develop 3.4 tcfe of unproved reserves compared to 1.1 tcfe of unproved reserves estimated as of March 31, 2006. To develop this significant backlog of value, Chesapeake plans to increase its current Barnett Shale drilling rig count from 12 (including 4 from Four Sevens/Sinclair) to 24 by year-end 2006. At that rig count, Chesapeake believes that it can drill 350- 400 Barnett Shale gross wells per year.
Chesapeake's current overall development plan for its 110,000 net acres of Johnson and Tarrant County leasehold is to drill 14-18 horizontal Barnett Shale wells per 640 acres using an average horizontal lateral length of 3,000 feet and an average spacing between wells of 500 feet. Using these parameters, Chesapeake believes its Johnson and Tarrant County horizontal drilling will develop an average of 2.2 bcfe of reserves per well at an average cost of $2.7 million, resulting in finding costs of approximately $1.64 per mcfe before leasehold or acquisition costs and after an approximate 25% average royalty burden.
To ensure strong returns on the acquisitions, the company has hedged 100% of the projected full-year 2007 and 2008 natural gas production volumes from the Four Sevens/Sinclair properties at an average NYMEX natural gas price of $10.50 per mmbtu, well above the gas price used to value the properties. Furthermore, Chesapeake has entered or will enter into multiple firm capacity pipeline transportation agreements that should help expand Barnett Shale takeaway capacity, reduce the company's basis differentials and enhance overall returns on its invested capital.
Company Expects Existing Barnett Shale Proved Reserves to be Revised
Upward by 22% in the 2006 Second Quarter
As of March 31, 2006, the company's Barnett Shale proved reserves were 464 bcfe of the company's total proved reserves of 7.8 tcfe. Following a review of Chesapeake's Barnett Shale drilling results over the past 18 months and a comprehensive study of industry production data, the company has raised its estimate of average recoverable reserves on its existing proved Barnett Shale assets by approximately 100 bcfe, or an increase of 22%. Pro forma for the announced Barnett Shale acquisitions, its increased estimate of recoverable reserves and its anticipated development plan, Chesapeake estimates its total proved and unproved Barnett Shale reserve potential on its 153,000 net acres to be approximately 4.0 tcfe as of June 30, 2006.
With the anticipated growth in the company's proved reserves base and pro forma for the acquisitions announced today, Chesapeake expects to report 8.2 - 8.4 tcfe of proved reserves (based on March 31, 2006 oil and natural gas prices) and total proved and unproved reserves of approximately 20 tcfe as of June 30, 2006. To calculate its unproved reserves, Chesapeake uses a probability-weighted statistical approach to estimate the potential number of drillsites and potential unproved reserves associated with such drillsites.
Today's developments follow a consistent path of achievement for Chesapeake in the Barnett Shale. In the 18 months prior to today's announcements, Chesapeake invested approximately $800 million to acquire approximately 55,000 net acres in three significant transactions with Hallwood Energy Corporation and a private independent producer. In those acquisitions, the company acquired 49 mmcfe of initial net daily production and approximately 250 bcfe of proved reserves. After investing an additional $212 million to drill 91 wells in Johnson and Tarrant Counties, Chesapeake's Barnett Shale net production now exceeds 110 mmcfe per day and development costs to date have averaged only $1.47 per mcfe.
The keys to success for Chesapeake in the Barnett Shale play have been threefold:
-- focus on acquiring leasehold in the Johnson and Tarrant County "sweet
spot" where the Barnett Shale is greater than 250 feet thick, where
the frac barrier is non-water bearing and where the shale is thermally
mature and in the dry gas window;
-- utilize the company's horizontal drilling expertise to generate better
production and lower costs. Since 1990, Chesapeake has drilled almost
800 horizontal wells in the U.S. and has been a leader in improving
horizontal drilling and completion technologies; and
-- leverage the company's industry-leading shale expertise. Chesapeake
is the only company in the U.S. active in shale plays in West Texas,
North Texas, southeastern Oklahoma, Arkansas and throughout the
Appalachian Basin.
Company Enters West Texas Barnett and Woodford Shale Plays Through Acquisition
of 150,000 Net Acres and Announces its First Commercial Production from the
Barnett Shale in West Texas and from the Fayetteville Shale in Arkansas
Chesapeake has acquired or agreed to acquire approximately 150,000 net acres in Brewster, Pecos and Reeves Counties in West Texas in two separate transactions. In these transactions, Chesapeake has assumed operation of one producing vertical Barnett Shale well and is drilling one vertical Barnett and Woodford Shale well and one horizontal Barnett Shale well. In addition, Chesapeake has assumed completion operations on two vertical Barnett and Woodford Shale wells, one horizontal Barnett Shale well and one horizontal Woodford Shale well. Chesapeake intends to commence an aggressive 3-D seismic and drilling program to determine the potential of these assets. In this area in West Texas, the Barnett Shale is 400-950 feet thick (compared to 100-400 feet in the Fort Worth Basin) and the deeper Woodford Shale is 400-500 feet thick (compared to approximately 150-250 feet thick in southeastern Oklahoma). Chesapeake's first vertical well is producing natural gas in commercial quantities from the Barnett Shale in Reeves County, Texas.
In addition, Chesapeake has recently completed several wells in the Fayetteville Shale play in Arkansas. Results to date cause the company to believe that at least 300,000 of its 1.1 million net acre leasehold position in the Fayetteville Shale will be commercially productive. Based on its analysis of its own wells and those drilled by others in the play, Chesapeake has concluded that per-well reserves of 1.2-1.5 bcfe may be achievable over a broad area of the play using a spacing pattern of approximately 10 wells per 640 acres. If so, Chesapeake believes its 300,000 net acres of potentially productive leasehold could support the drilling of up to 4,600 net wells on an unrisked basis. Efforts remain underway to determine the commercial potential of Chesapeake's other 800,000 net acres.
Drilling, completing and operating costs in the Fayetteville Shale remain high and current economics in the area do not yet rank the play among Chesapeake's 15 best plays. Nevertheless, the company remains hopeful that it can achieve further engineering and operational breakthroughs that will make the play more economically attractive than it is today.
Chesapeake Significantly Increases its Oil and Natural Gas Hedging Positions
In addition to the hedges associated with the Four Sevens/Sinclair acquisition, Chesapeake has also significantly added to its 2007 and 2008 oil and natural gas hedging positions on its existing production over the past month to secure exceptional margins and profitability. The following tables compare Chesapeake's hedged production volumes (including only swaps and also including the hedges assumed in the CNR acquisition) as of June 5, 2006 to those as of May 1, 2006.
Swap Positions as of June 5, 2006
Natural Gas Oil
Quarter or Year % Hedged $ NYMEX % Hedged $ NYMEX
2006 2Q 86% $8.88 69% $61.85
2006 3Q 93% $8.85 84% $63.90
2006 4Q 86% $9.50 85% $63.76
2006 Total Remaining 88% $9.08 79% $63.24
2007 Total 69% $9.86 56% $68.79
2008 Total 55% $9.34 48% $69.50
2009 Total 3% $7.57 2% $66.26
Swap Positions as of May 1, 2006
Natural Gas Oil
Quarter or Year % Hedged $ NYMEX % Hedged $ NYMEX
2006 2Q 86% $8.88 69% $61.85
2006 3Q 94% $8.85 84% $63.90
2006 4Q 88% $9.50 85% $63.76
2006 Total Remaining 89% $9.08 79% $63.24
2007 Total 65% $9.82 44% $67.07
2008 Total 48% $9.06 37% $68.20
2009 Total 3% $7.57 2% $66.26
Depending on changes in oil and natural gas futures markets and management's view of underlying oil and natural gas supply and demand trends, Chesapeake may either increase or decrease its hedging positions at any time in the future without notice.
The company has updated its 2006 and 2007 forecasts to reflect the acquisitions announced today, the anticipated acquisition financing and additional hedges. This update is attached to this release in an Outlook dated June 5, 2006 and labeled as Schedule "A", beginning on page 8. This Outlook has been changed from the Outlook dated May 1, 2006 (attached as Schedule "B", beginning on page 12) to reflect various updated information.
Management Comments
Aubrey K. McClendon, Chesapeake's Chief Executive Officer, commented, "We are excited to announce the acquisition of 26,000 net acres of high-quality Barnett Shale properties in Johnson and Tarrant Counties from Four Sevens/Sinclair, the additional 28,000 net acres of other high-quality Barnett Shale leasehold, our acquisition of 150,000 net acres in the Barnett and Woodford Shale play in West Texas and our initial commercial production success in the Barnett Shale in West Texas and in the Fayetteville Shale in Arkansas. Each of these announcements is based on our considerable expertise in drilling and completing horizontal wells in shale, tight sands and other unconventional formations. We believe that Chesapeake has industry-leading expertise in these areas and further believe these new acquisitions and successes in the Barnett, Woodford and Fayetteville shale plays will accelerate the company's already ambitious growth plans".
Conference Call Information
A conference call has been scheduled for Monday morning, June 5, 2006 at 9:00 a.m. EDT to discuss this release. The telephone number to access the conference call is 913.981.5543 and the confirmation code is 9463648. We encourage those who would like to participate in the call to dial the access number between 8:50 and 8:55 am EDT. For those unable to participate in the conference call, a replay will be available from 12:00 p.m. EDT, June 5, 2006 through midnight EDT on June 19, 2006. The number to access the conference call replay is 719.457.0820 and the passcode for the replay is 9463648. The conference call will also be webcast live on the Internet and can be accessed on our recently enhanced website at http://www.chkenergy.com/ by selecting "Events Calendar" under the "News & Events" section. The webcast of the conference call will be available on our website indefinitely. Additionally, a slide show presentation discussing the release is accessible on our website by selecting "Presentations" under the "Investor Relations" section.
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 natural gas reserves, expected oil and natural gas production and future expenses, projections of future oil and natural 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 the fair value of derivative contracts and their estimated contribution to our future results of operations are based upon market information as of a specific date. These market prices are subject to significant volatility.
Factors that could cause actual results to differ materially from expected results are described under "Risk Factors" in Item 1A of our 2005 Form 10-K filed with the Securities and Exchange Commission on March 14, 2006. They include the volatility of oil and natural gas prices; the limitations our level of indebtedness may have on our financial flexibility; our ability to compete effectively against strong independent oil and natural gas companies and majors; the availability of capital on an economic basis to fund reserve replacement costs; our ability to replace reserves and sustain production; uncertainties inherent in estimating quantities of oil and natural gas reserves and projecting future rates of production and the timing of development expenditures; uncertainties in evaluating oil and natural gas reserves of acquired properties and associated potential liabilities; our ability to effectively consolidate and integrate acquired properties and operations; unsuccessful exploration and development drilling; declines in the values of our oil and natural gas properties resulting in ceiling test write- downs; lower prices realized on oil and natural gas sales and collateral required to secure hedging liabilities resulting from our commodity price risk management activities; the negative impact lower oil and natural gas prices could have on our ability to borrow; and drilling and operating risks. 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 properties recently acquired or 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 and forecasts reflected in these and other forward-looking statements are reasonable, we can give no assurance they will prove to have been correct. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties.
The SEC has generally permitted oil and natural 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", "possible" or "unproved" to describe 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. While we believe our calculations of unproved drillsites and estimation of unproved reserves have been appropriately risked and are reasonable, such calculations and estimates have not been reviewed by third party engineers or appraisers.
Chesapeake Energy Corporation is the second 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 corporate and property acquisitions in the Mid-Continent, Permian Basin, South Texas, Texas Gulf Coast, Barnett Shale, Ark-La-Tex and Appalachian Basin regions of the United States. The company's Internet address is http://www.chkenergy.com/.
SCHEDULE "A"
CHESAPEAKE'S OUTLOOK AS OF JUNE 5, 2006
Quarter Ending June 30, 2006; Year Ending December 31, 2006; Year Ending December 31, 2007.
We have adopted a policy of periodically providing investors with guidance on certain factors that affect our future financial performance. As of June 5, 2006, we are using the following key assumptions in our projections for the second quarter of 2006, the full-year 2006 and the full-year 2007.
The primary changes from our May 1, 2006 Outlook are in italicized bold in the table and are explained as follows:
1) We have updated the projected effect of changes in our hedging
positions;
2) Production, certain costs and capital expenditures have increased as a
result of the acquisitions announced today; and
3) Share count has been adjusted to reflect our tender offer to convert
our 4.125% preferred stock and 5.0% preferred stock to common stock,
recent repurchases of common stock and an expected preferred equity
offering in the near future.
Quarter Ending Year Ending Year Ending
6/30/2006 12/31/2006 12/31/2007
Estimated Production:
Oil - mbbls 2,000 8,000 8,000
Natural gas - bcf 127 - 132 533 - 543 592 - 602
Natural gas equivalent - bcfe 139 - 144 581 - 591 640 - 650
Daily natural gas equivalent
midpoint - in mmcfe 1,555 1,605 1,767
NYMEX Prices (a) (for calculation
of realized hedging effects only):
Oil - $/bbl $58.39 $56.72 $52.50
Natural gas - $/mcf $7.16 $7.54 $7.00
Estimated Realized Hedging Effects
(based on assumed NYMEX prices
above):
Oil - $/bbl $2.62 $4.83 $9.39
Natural gas - $/mcf $1.68 $2.00 $2.19
Estimated Differentials to NYMEX
Prices:
Oil - $/bbl 6 - 8% 6 - 8% 6 - 8%
Natural gas - $/mcf 8 - 12% 9 - 13% 9 - 13%
Operating Costs per Mcfe of
Projected Production:
Production expense $0.85 - 0.95 $0.85 - 0.95 $0.90 - 1.00
Production taxes (generally
6.0% of O&G revenues) (b) $0.40 - 0.45 $0.41 - 0.46 $0.36 - 0.41
General and administrative $0.15 - 0.20 $0.15 - 0.20 $0.15 - 0.20
Stock-based compensation
(non-cash) $0.05 - 0.07 $0.06 - 0.08 $0.08 - 0.10
DD&A of oil and natural gas
assets $2.25 - 2.35 $2.30 - 2.40 $2.40 - 2.50
Depreciation of other assets $0.16 - 0.20 $0.18 - 0.22 $0.24 - 0.28
Interest expense (c) $0.52 - 0.57 $0.52 - 0.57 $0.53 - 0.58
Other Income per Mcfe:
Marketing and other income $0.02 - 0.04 $0.04 - 0.06 $0.04 - 0.06
Service operations income $0.10 - 0.15 $0.10 - 0.15 $0.10 - 0.15
Book Tax Rate (approximately
95% deferred) 37.5% 37.5% 37.5%
Equivalent Shares Outstanding:
Basic 379 mm 380 mm 389 mm
Diluted 434 mm 441 mm 452 mm
Capital Expenditures:
Drilling, leasehold and
seismic $900 - 1,000 $3,500 - 3,800 $3,500 - 3,800
mm mm mm
(a) Oil NYMEX prices have been updated for actual contract prices through
April 2006 and natural gas NYMEX prices have been updated for actual
contract prices through May 2006.
(b) Severance tax per mcfe is based on NYMEX prices of $58.39 per bbl of
oil and $7.20 to $8.20 per mcf of natural gas during Q2 2006, $56.72
per bbl of oil and $7.35 to $8.35 per mcf of natural gas during
calendar 2006, and $52.50 per bbl of oil and $6.50 to $7.50 per mcf of
natural gas during calendar 2007.
(c) 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 natural 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 natural 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 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 natural gas sales. All realized gains and losses from oil and natural gas derivatives are included in oil and natural 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 natural 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.
Excluding the swaps assumed in connection with the acquisition of CNR which are described below, the company currently has the following natural gas swaps in place:
% Hedged
Open Swap
Avg. Avg. NYMEX Assuming Positions
NYMEX Gain Price Natural as a % of
Open Strike (Loss) Including Gas Estimated
Swaps Price from Open & Production Total
in Of Open Locked Locked in Natural Gas
Bcf's Swaps Swaps Positions Bcf's of: Production
2006:
Q1 93.8 $10.81 -$0.09 $10.72 124.1 76%
Q2 101.4 $8.82 -$0.05 $8.77 129.5 78%
Q3 117.9 $8.80 -$0.05 $8.75 138.5 85%
Q4 114.9 $9.46 -$0.04 $9.42 145.9 79%
Total 2006(1) 428.0 $9.42 -$0.05 $9.37 538.0 80%
Total 2007(1) 370.2 $9.98 -$0.04 $9.94 597.0 62%
Total 2008(1) 311.1 $9.50 - $9.50 637.0 49%
Total 2009 3.7 $9.02 - $9.02 682.0 1%
(1) Certain hedging arrangements include swaps with knockout prices
ranging from $3.75 to $5.50 covering 43.0 bcf in 2006, $5.75 to $6.50
covering 32.0 bcf in 2007 and $5.75 to $6.50 covering 51.2 bcf in
2008, respectively.
Note: Not shown above are collars covering 0.2 bcf of production in 2006 at a weighted average floor and ceiling of $6.00 and $9.70 and call options covering 7.3 bcf of production in 2006 at a weighted average price of $12.50, 25.6 bcf of production in 2007 at a weighted average price of $10.53 and 7.3 bcf of production in 2008 at a weighed average price of $12.50.
The company has the following natural gas basis protection swaps in place:
Mid-Continent Appalachia
Volume
Volume in Bcf's NYMEX less*: in Bcf's NYMEX plus*:
2006 130.1 $0.32 - $-
2007 137.2 0.33 36.5 0.35
2008 118.6 0.27 36.6 0.35
2009 86.6 0.29 18.2 0.31
Totals 472.5 $0.30 91.3 $0.34
* weighted average
We assumed certain liabilities related to open derivative positions in connection with the CNR acquisition. In accordance with SFAS 141, these derivative positions were recorded at fair value in the purchase price allocation as a liability of $592 million ($523 million as of March 31, 2006). The recognition of the derivative liability and other assumed liabilities resulted in an increase in the total purchase price which was allocated to the assets acquired. Because of this accounting treatment, only cash settlements for changes in fair value subsequent to the acquisition date for the derivative positions assumed result in adjustments to our oil and natural gas revenues upon settlement. For example, if the fair value of the derivative positions assumed does not change, then upon the sale of the underlying production and corresponding settlement of the derivative positions, cash would be paid to the counterparties and there would be no adjustment to oil and natural gas revenues related to the derivative positions. If, however, the actual sales price is different from the price assumed in the original fair value calculation, the difference would be reflected as either a decrease or increase in oil and natural gas revenues, depending upon whether the sales price was higher or lower, respectively, than the prices assumed in the original fair value calculation. For accounting purposes, the net effect of these acquired hedges is that we hedged the production volumes listed below at their fair values on the date of our acquisition of CNR.
Pursuant to SFAS 149 "Amendment of SFAS 133 on Derivative Instruments and Hedging Activities", the derivative instruments assumed in connection with the CNR acquisition are deemed to contain a significant financing element and all cash flows associated with these positions are reported as financing activity in the statement of cash flows.
The following details the CNR derivatives (natural gas swaps) we have assumed:
% Hedged
Avg. Open Swap
NYMEX Avg. Fair Assuming Positions
Strike Value Upon Natural as a % of
Open Price Acquisition Initial Gas Estimated
Swaps Of Open of Open Liability Production Total
in Swaps Swaps Acquired in Natural Gas
Bcf's (per Mcf) (per Mcf) (per Mcf) Bcf's of: Production
2006:
Q1 7.9 $4.91 $12.14 ($7.23) 124.1 6%
Q2 10.5 $4.86 $9.97 ($5.11) 129.5 8%
Q3 10.6 $4.86 $9.95 ($5.09) 138.5 8%
Q4 10.6 $4.86 $10.38 ($5.52) 145.9 7%
Total 2006 39.6 $4.87 $10.51 ($5.64) 538.0 7%
Total 2007 42.0 $4.82 $9.18 ($4.36) 597.0 7%
Total 2008 38.4 $4.67 $8.01 ($3.34) 637.0 6%
Total 2009 18.3 $5.18 $7.28 ($2.10) 682.0 3%
Note: Not shown above are collars covering 3.7 bcf of production in 2009 at an average floor and ceiling of $4.50 and $6.00, respectively.
The company also has the following crude oil swaps in place:
% Hedged
Open Swap
Positions as %
Assuming Oil of Total
Open Swaps Avg. NYMEX Production Estimated
in mbbls Strike Price in mbbls of: Production
2006:
Q1 1,109.5 $60.03 2,116 52%
Q2 1,379.5 $61.85 2,000 69%
Q3 1,625.0 $63.90 1,942 84%
Q4 1,656.0 $63.76 1,942 85%
Total 2006(1) 5,770.0 $62.63 8,000 72%
Total 2007 4,452.0 $68.79 8,000 56%
Total 2008 3,843.0 $69.50 8,000 48%
Total 2009 182.5 $66.26 8,000 2%
(1) Certain hedging arrangements include swaps with knockout prices
ranging from $40.00 to $42.00 covering 501.5 mbbls in 2006, $45.00
covering 182.5 mbbls in 2007 and $45.00 covering 183.0 mbbls in 2008,
respectively.
SCHEDULE "B"
CHESAPEAKE'S PREVIOUS OUTLOOK AS OF MAY 1, 2006
(PROVIDED FOR REFERENCE ONLY)
NOW SUPERSEDED BY OUTLOOK AS OF JUNE 5, 2006
Quarter Ending June 30, 2006; Year Ending December 31, 2006; Year Ending December 31, 2007.
We have adopted a policy of periodically providing investors with guidance on certain factors that affect our future financial performance. As of May 1, 2006, we are using the following key assumptions in our projections for the second quarter of 2006, the full-year 2006 and the full-year 2007.
The primary changes from our February 23, 2006 Outlook are in italicized bold in the table and are explained as follows:
1) We have updated the projected effect of changes in our hedging
positions since our February 23, 2006 Outlook.
2) We have updated our expectations for future NYMEX oil and natural gas
prices based on current market conditions in order to illustrate
hedging effects only.
3) We have updated certain of our cost assumptions.
4) We have shown our projections for the quarter ending June 30, 2006
for the first time.
Quarter Ending Year Ending Year Ending
6/30/2006 12/31/2006 12/31/2007
Estimated Production:
Oil - mbbls 2,000 8,000 8,000
Natural gas - bcf 127 - 132 528 - 538 571 - 581
Natural gas equivalent - bcfe 139 - 144 576 - 586 619 - 629
Daily natural gas equivalent
midpoint - in mmcfe 1,555 1,592 1,710
NYMEX Prices (a) (for
calculation of realized hedging
effects only):
Oil - $/bbl $60.00 $60.87 $50.00
Natural gas - $/mcf $7.08 $7.52 $7.00
Estimated Realized Hedging
Effects (based on assumed NYMEX
prices above):
Oil - $/bbl $1.33 $1.43 $7.83
Natural gas - $/mcf $1.67 $2.02 $2.00
Estimated Differentials to NYMEX
Prices:
Oil - $/bbl 6 - 8% 6 - 8% 6 - 8%
Natural gas - $/mcf 8 - 12% 8 - 12% 8 - 12%
Operating Costs per Mcfe of
Projected Production:
Production expense $0.85 - 0.95 $0.85 - 0.95 $0.90 - 1.00
Production taxes (generally
6.0% of O&G revenues) (b) $0.48 - 0.53 $0.41 - 0.46 $0.36 - 0.41
General and administrative $0.15 - 0.20 $0.15 - 0.20 $0.15 - 0.20
Stock-based compensation
(non-cash) $0.05 - 0.07 $0.06 - 0.08 $0.08 - 0.10
DD&A of oil and natural gas
assets $2.25 - 2.35 $2.30 - 2.35 $2.35 - 2.45
Depreciation of other
assets $0.16 - 0.20 $0.16 - 0.20 $0.20 - 0.25
Interest expense (c) $0.52 - 0.57 $0.52 - 0.57 $0.53 - 0.58
Other Income per Mcfe:
Marketing and other income $0.02 - 0.04 $0.02 - 0.04 $0.02 - 0.04
Service operations income $0.10 - 0.15 $0.10 - 0.15 $0.10 - 0.15
Book Tax Rate (approximately
95% deferred) 38% 38% 38%
Equivalent Shares Outstanding:
Basic 377 mm 376 mm 387 mm
Diluted 436 mm 436 mm 441 mm
Capital Expenditures:
Drilling, leasehold and
seismic $700 - 750 $3,200 - 3,500 $3,400 - 3,600
mm mm mm
(a) Oil NYMEX prices have been updated for actual contract prices through
March 2006 and natural gas NYMEX prices have been updated for
actual contract prices through April 2006.
(b) Severance tax per mcfe is based on NYMEX prices of $60.00 per bbl and
natural gas prices ranging from $8.75 to $9.75 per mcf during Q2 2006,
$7.35 to $8.35 per mcf during calendar 2006 and $50.00 per bbl and
$6.50 to $7.50 per mcf during calendar 2007.
(c) 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 natural 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 natural 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 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 natural gas sales. All realized gains and losses from oil and natural gas derivatives are included in oil and natural 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 natural 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.
Excluding the swaps assumed in connection with the acquisition of CNR which are described below, the company currently has the following natural gas swaps in place:
% Hedged
Open Swap
Avg. Avg. NYMEX Assuming Positions
NYMEX Gain Price Natural as a % of
Open Strike (Loss) Including Gas Estimated
Swaps Price from Open & Production Total
in Of Open Locked Locked in Natural Gas
Bcf's Swaps Swaps Positions Bcf's of: Production
2006:
Q1 93.8 $10.81 -$0.09 $10.72 124.1 76%
Q2 101.4 $8.82 -$0.05 $8.77 129.5 78%
Q3 117.9 $8.80 -$0.05 $8.75 137.0 86%
Q4 114.9 $9.46 -$0.04 $9.42 142.4 81%
Total 2006(1) 428.0 $9.42 -$0.05 $9.37 533.0 80%
Total 2007 330.0 $9.94 -$0.04 $9.90 576.0 57%
Total 2008 248.9 $9.22 - $9.22 604.0 41%
Total 2009 3.7 $9.02 - $9.02 634.0 1%
(1) Certain hedging arrangements include swaps with knockout prices
ranging from $3.75 to $5.50 covering 43.0 bcf in 2006.
Note: Not shown above are collars covering 0.2 bcf of production in 2006 at a weighted average floor and ceiling of $6.00 and $9.70 and call options covering 7.3 bcf of production in 2006 at a weighted average price of $12.50, 25.6 bcf of production in 2007 at a weighted average price of $10.53 and 7.3 bcf of production in 2008 at a weighed average price of $12.50.
The company has the following natural gas basis protection swaps in place:
Mid-Continent Appalachia
Volume
Volume in Bcf's NYMEX less*: in Bcf's NYMEX plus*:
2006 130.1 $0.32 - $-
2007 137.2 0.33 32.9 0.34
2008 118.6 0.27 25.6 0.34
2009 86.6 0.29 18.2 0.31
Totals 472.5 $0.30 76.7 $0.33
* weighted average
We assumed certain liabilities related to open derivative positions in connection with the CNR acquisition. In accordance with SFAS 141, these derivative positions were recorded at fair value in the purchase price allocation as a liability of $592 million ($523 million as of March 31, 2006). The recognition of the derivative liability and other assumed liabilities resulted in an increase in the total purchase price which was allocated to the assets acquired. Because of this accounting treatment, only cash settlements for changes in fair value subsequent to the acquisition date for the derivative positions assumed result in adjustments to our oil and natural gas revenues upon settlement. For example, if the fair value of the derivative positions assumed does not change, then upon the sale of the underlying production and corresponding settlement of the derivative positions, cash would be paid to the counterparties and there would be no adjustment to oil and natural gas revenues related to the derivative positions. If, however, the actual sales price is different from the price assumed in the original fair value calculation, the difference would be reflected as either a decrease or increase in oil and natural gas revenues, depending upon whether the sales price was higher or lower, respectively, than the prices assumed in the original fair value calculation. For accounting purposes, the net effect of these acquired hedges is that we hedged the production volumes listed below at their fair values on the date of our acquisition of CNR.
Pursuant to SFAS 149 "Amendment of SFAS 133 on Derivative Instruments and Hedging Activities", the derivative instruments assumed in connection with the CNR acquisition are deemed to contain a significant financing element and all cash flows associated with these positions are reported as financing activity in the statement of cash flows.
The following details the CNR derivatives (natural gas swaps) we have assumed:
% Hedged
Avg. Open Swap
NYMEX Avg. Fair Assuming Positions
Strike Value Upon Natural as a % of
Open Price Acquisition Initial Gas Estimated
Swaps Of Open of Open Liability Production Total
in Swaps Swaps Acquired in Natural Gas
Bcf's (per Mcf) (per Mcf) (per Mcf) Bcf's of: Production
2006:
Q1 7.9 $4.91 $12.14 ($7.23) 124.1 6%
Q2 10.5 $4.86 $9.97 ($5.11) 129.5 8%
Q3 10.6 $4.86 $9.95 ($5.09) 137.0 8%
Q4 10.6 $4.86 $10.38 ($5.52) 142.4 7%
Total 2006 39.6 $4.87 $10.51 ($5.64) 533.0 7%
Total 2007 42.0 $4.82 $9.18 ($4.36) 576.0 7%
Total 2008 38.4 $4.67 $8.01 ($3.34) 604.0 6%
Total 2009 18.3 $5.18 $7.28 ($2.10) 634.0 3%
Note: Not shown above are collars covering 3.7 bcf of production in 2009 at an average floor and ceiling of $4.50 and $6.00, respectively.
The company also has the following crude oil swaps in place:
% Hedged
Open Swap
Positions as %
Assuming Oil of Total
Open Swaps Avg. NYMEX Production Estimated
in mbbls Strike Price in mbbls of: Production
2006:
Q1 1,109.5 $60.03 2,116 52%
Q2 1,379.5 $61.85 2,000 69%
Q3 1,625.0 $63.90 1,942 84%
Q4 1,656.0 $63.76 1,942 85%
Total 2006(1) 5,770.0 $62.63 8,000 72%
Total 2007 3,555.0 $67.07 8,000 44%
Total 2008 2,928.0 $68.20 8,000 37%
Total 2009 182.5 $66.26 8,000 2%
(1) Certain hedging arrangements include swaps with knockout prices ranging from $40.00 to $42.00 covering 501.5 mbbls in 2006.
SOURCE: Chesapeake Energy Corporation
CONTACT: Investor Contact: Jeffrey L. Mobley, CFA, Senior Vice President
- Investor Relations And Research, +1-405-767-4763,
Media Contact: Thomas S. Price, Jr., Senior Vice President - Corporate
Development, +1-405-879-9257,
Web site: http://www.chkenergy.com/
