Press Releases
Chesapeake Energy Corporation
After allocating $255.2 million of the $686.4 million purchase price to the 98,000 net acres of leasehold (and related probable and possible reserves) being acquired from the sellers, Chesapeake's acquisition cost for the 289 bcfe of internally estimated proved reserves will be $1.49 per thousand cubic feet of natural gas equivalent (mcfe). Based on the company's projected development plan which includes $683 million of anticipated future drilling and development costs, Chesapeake estimates that its all-in cost of acquiring and developing the 566 bcfe of 3P reserves will be $2.42 per mcfe.
The proved reserves associated with these acquisitions have a reserves-to- production index estimated at 13.0 years, are 89% natural gas, are 36% proved developed and have current lease operating expenses of $0.32 per mcfe. The properties are located in areas where Chesapeake already has extensive drilling and producing operations.
On the acquired properties, Chesapeake has identified 276 proved undeveloped and 375 probable and possible drilling locations. Pro forma for these acquisitions, Chesapeake believes that it will own an internally estimated 5.4 trillion cubic feet of natural gas equivalent (tcfe) of proved oil and natural gas reserves and more than 4.0 tcfe of unproven reserves as of December 31, 2004.
Chesapeake has hedged 100% of the 1,200 barrels of current oil production from the acquired properties at NYMEX oil prices of $58.44 per barrel for 2005 and $57.98 per barrel for 2006. In addition, the company has hedged 100% of the 54,000 mmcf of current gas production from the acquired properties at NYMEX gas prices of $7.65 per mmbtu for 2005 and $7.53 mmbtu for 2006, levels well above the prices used to value the acquisitions.
Chesapeake has recently closed one of the transactions for approximately $228 million in cash and expects to close the remaining acquisitions by May 31, 2005. The pending acquisitions are subject to customary closing conditions and purchase price adjustments but are not conditioned on the closing of any of the other transactions. Chesapeake intends to finance the acquisitions by issuing a combination of senior notes and preferred stock. As a result of these acquisitions and the financings contemplated herein, the company has updated its Outlook, which is attached to this release as Exhibit "A". The company's previous Outlook, dated February 22, 2005, is attached as Exhibit "B" for comparative purposes.
The sellers include Houston-based Laredo Energy II, L.L.C. and its partners; Houston-based Pecos Production Company; Midland-based Rubicon Oil & Gas I, L.P. and a Dallas-based independent oil and gas company. Laredo was advised by Petrie Parkman & Co. of Houston and Pecos was advised by Waterous & Co. of Houston.
Management Comment
Aubrey K. McClendon, Chesapeake's Chief Executive Officer, commented, "We are pleased to announce these acquisitions for several reasons. First, they will add to our growing presence in South Texas, East Texas and the Permian Basin, all areas of increasing importance to Chesapeake. Second, these acquisitions have all of the attributes of successful previous Chesapeake transactions -- acquisitions from private companies of low-cost, high-margin proved producing natural gas reserves, exploitation potential of proved undeveloped, probable and possible reserves and finally, exploration potential for new reserves. In addition, the acquisitions are heavily-weighted to natural gas and the properties have attractive operating and future development costs. We are confident that Chesapeake can deliver significant shareholder value from the acquired properties for years to come."
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 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 1 of our 2004 Annual Report on Form 10-K filed with the Securities and Exchange Commission on March 9, 2005. They include the volatility of oil and gas prices; adverse effects our level of indebtedness could have on our operations and future growth; our ability to compete effectively against strong independent oil and gas companies and majors; the availability of capital on an economic basis to fund reserve replacement costs; uncertainties inherent in estimating quantities of oil and gas reserves; projecting future rates of production and the timing of development expenditures; our ability to replace reserves and sustain production; uncertainties in evaluating oil and gas reserves of acquired properties and associated potential liabilities; unsuccessful exploration and development drilling; declines in the values of our oil and gas properties resulting in ceiling test write-downs; lower prices realized on oil and gas sales and collateral required to secure hedging liabilities resulting from our commodity price risk management activities; 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 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 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 proposed financings through the issuance of senior notes and preferred stock in this press release shall not constitute an offer to sell or a solicitation of an offer to buy the securities. The terms of any such offerings have not been decided. The securities will 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 fourth 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 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 APRIL 12, 2005
Quarter Ending June 30, 2005; 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 April 12, 2005, we are using the following key assumptions in our projections for the second quarter of 2005, the full-year 2005 and the full-year 2006.
The primary changes from our February 22, 2005 Outlook are in the table and are explained as follows:
1) We have shown the operational and financial effects of the
acquisitions and anticipated financing of them as described in our
press release dated April 12, 2005.
2) We have shown our projections for the quarter ending June 30, 2005
for the first time.
3) We have updated the projected effects from changes in our hedging
positions since our February 22, 2005 Outlook.
4) We have updated certain of our cost and oil and natural gas price
differentials to reflect changing market conditions.
5) We have included our expectations for future NYMEX oil and gas prices
to illustrate hedging effects only.
Quarter Ending Year Ending Year Ending
June 30, 2005 Dec. 31, 2005 Dec. 31, 2006
Estimated Production:
Oil - Mbo 1,770 7,000 7,300
Gas - Bcf 98-100 403 - 411 457 - 467
Gas Equivalent - Bcfe 108.5 - 110.5 445 - 453 501 - 511
Daily gas equivalent
midpoint -in Mmcfe 1,203 1,230 1,386
NYMEX Prices (for calculation
of realized hedging
effects only):
Oil - $/Bo $45.00 $46.21 $45.00
Gas - $/Mcf $6.78 $6.51 $6.50
Estimated Differentials to
NYMEX Prices:
Oil - $/Bo -$4.00 -$4.00 -$4.00
Gas - $/Mcf -$0.80 -$0.80 -$0.80
Estimated Realized Hedging
Effects (based on expected
NYMEX prices above):
Oil - $/Bo -$0.78 -$0.87 $1.12
Gas - $/Mcf -$0.26 $0.13 $0.10
Operating Costs per Mcfe of
Projected Production:
Production expense $0.68-0.72 $0.68-0.72 $0.72-0.77
Production taxes (generally
7% of O&G revenues) (A) $0.40-0.45 $0.40-0.45 $0.40-0.45
General and administrative $0.10-0.12 $0.10-0.12 $0.11-0.13
Stock-based compensation
(non-cash) $0.03-0.05 $0.03-0.05 $0.04-0.06
DD&A - oil and gas $1.75-1.85 $1.75-1.85 $1.85-1.95
Depreciation of other assets $0.09-0.11 $0.09-0.11 $0.10-0.12
Interest expense (B) $0.43-0.47 $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
Book Tax Rate (approx.
95% deferred) 36.5% 36.5% 36.5%
Equivalent Shares Outstanding:
Basic 312 mm 315 mm 318 mm
Diluted 367 mm 364 mm 370 mm
Capital Expenditures:
Drilling, leasehold and
seismic $400- $1,600- $1,800-
$450mm $1,800mm $2,000mm
(A) Severance tax per mcfe is based on NYMEX prices of $45.00 per barrel
of oil and natural gas prices ranging from $6.00-$7.20 during Q2
2005, $6.50-$7.50 during calendar 2005, and $6.35-$7.25 during
calendar 2006.
(B) 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. NYMEX Open Swap
Avg. NYMEX Gain Price Assuming Positions
Strike (Loss) Including Gas as a % of
Open Price from Open Production Estimated
Swaps Of Open Locked & Locked in Total Gas
in Bcf's Swaps Swaps Positions Bcf's of: Production
2005:
1st Qtr 62.2 $7.00 -$0.18 $6.82 91.5 68%
2nd Qtr 63.1 $6.29 -$0.17 $6.12 99.0 64%
3rd Qtr 57.0 $6.41 -$0.19 $6.22 105.5 54%
4th Qtr 38.1 $6.64 -$0.28 $6.36 111.0 34%
Total 2005 (A) 220.4 $6.58 -$0.19 $6.39 407.0 54%
Total 2006 (A) 79.4 $7.10 -$0.31 $6.79 462.0 17%
TOTALS
2005-2006 299.8 $6.72 -$0.22 $6.50 869.0 34%
(A) Certain hedging arrangements include swaps with knockout prices
ranging from $3.75 to $5.50 covering 79.5 bcf in 2005 and $3.75 to
$5.50 covering 35.7 bcf in 2006.
Note: Not shown above are collars covering 4.4 bcf of production in 2005 at a weighted average floor and ceiling of $3.10 and $4.44 and call options covering 7.3 bcf of production in 2005 at a weighted average price of $6.00.
The company has also entered into the following natural gas basis protection swaps:
Assuming Gas
Volume NYMEX Production in
in Bcf's less:* Bcf's of: % Hedged
2005 188.6 $0.26 407.0 46%
2006 130.1 0.32 462.0 28%
2007 126.5 0.28 490.0 26%
2008 118.6 0.27 515.0 23%
2009 86.6 0.29 540.0 16%
Totals 650.4 $0.28 2,414.0 27%
* 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 - 2005 870.5 $41.87 1,650 53%
Q2 - 2005 1,107.0 $43.76 1,770 63%
Q3 - 2005 522.0 $47.59 1,790 29%
Q4 - 2005 429.5 $47.32 1,790 24%
Total 2005 (A) 2,929.0 $44.40 7,000 42%
Total 2006 (A) 835.0 $55.68 7,300 11%
(A) Certain hedging arrangements include swaps with knockout prices
ranging from $26.00 to $42.00 covering 2,317 mbo in 2005 and $40.00
to $42.00 covering 501.5 mbo in 2006.
SCHEDULE "B"
CHESAPEAKE'S PREVIOUS OUTLOOK AS OF FEBRUARY 22, 2005
(PROVIDED FOR REFERENCE ONLY)
NOW SUPERSEDED BY OUTLOOK AS OF APRIL 12, 2005
Quarter Ending March 31, 2005; 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 February 22, 2005, we are using the following key assumptions in our projections for the first quarter of 2005, the full-year 2005 and the full- year 2006.
The primary changes from our December 27, 2004 Outlook are in the table and are explained as follows:
1) We have provided our first production forecast for the first quarter
of 2005.
2) We have increased capital expenditures by $100 million in 2005 and
$50 million in 2006 to reflect a planned increase in drilling
activity on various company properties.
3) We have updated the projected effects from changes in our hedging
positions since our December 27, 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
March 31, 2005 Dec. 31, 2005 Dec. 31, 2006
Estimated Production:
Oil - Mbo 1,650 6,600 6,600
Gas - Bcf 91 - 92 391 - 399 438 - 448
Gas Equivalent - Bcfe 101 - 102 430 - 438 478 - 488
Daily gas equivalent midpoint
-in Mmcfe 1,128 1,190 1,325
NYMEX Prices (for calculation
of realized hedging effects
only):
Oil - $/Bo $42.28 $40.57 $40.00
Gas - $/Mcf $6.17 $6.04 $6.00
Estimated Differentials to
NYMEX Prices:
Oil - $/Bo -$2.75 -$2.75 -$2.75
Gas - $/Mcf -$0.75 -$0.70 -$0.70
Estimated Realized Hedging
Effects (based on expected
NYMEX prices above):
Oil - $/Bo -$0.23 $0.04 $0.00
Gas - $/Mcf $0.56 $0.07 $0.00
Operating Costs per Mcfe of
Projected Production:
Production expense $0.62 - 0.67 $0.62 - 0.67 $0.68 - 0.72
Production taxes (generally
7% of O&G revenues) $0.38 - 0.40 $0.38 - 0.40 $0.38 - 0.40
General and administrative $0.10 - 0.11 $0.10 - 0.11 $0.11 - 0.12
Stock-based compensation
(non-cash) $0.02 - 0.04 $0.04 - 0.06 $0.09 - 0.10
DD&A - oil and gas $1.70 - 1.75 $1.75 - 1.80 $1.80 - 1.90
Depreciation of other assets $0.09 - 0.11 $0.09 - 0.11 $0.10 - 0.12
Interest expense (A) $0.43 - 0.47 $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
Book Tax Rate 36.5% 36.5% 36.5%
Equivalent Shares Outstanding:
Basic 314 mm 315 mm 318 mm
Diluted 352 mm 352 mm 355 mm
Capital Expenditures:
Drilling, leasehold
and seismic $350- $1,400- $1,500-
$375 mm $1,500 mm $1,600mm
(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. NYMEX Open Swap
Avg. NYMEX Gain Price Assuming Positions
Strike (Loss) Including Gas as a % of
Open Price from Open Production Estimated
Swaps Of Open Locked & Locked in Total Gas
in Bcf's Swaps Swaps Positions Bcf's of: Production
2005:
1st Qtr 62.2 $7.00 -$0.18 $6.82 91.5 68%
2nd Qtr 52.2 $6.17 -$0.19 $5.98 97.0 54%
3rd Qtr 46.4 $6.19 -$0.23 $5.96 101.5 46%
4th Qtr 27.5 $6.26 -$0.39 $5.87 105.0 26%
Total 2005 (A) 188.3 $6.46 -$0.22 $6.24 395.0 48%
Total 2006 (A) 39.3 $6.77 -$0.62 $6.15 443.0 9%
Total 2007 (B) --- --- --- --- 470.0 ---
TOTALS
2005-2007 227.6 $6.51 -$0.29 $6.22 1,308.0 17%
(A) Certain hedging arrangements include swaps with knockout prices
ranging from $3.75 to $5.50 covering 70.0 bcf in 2005 and $3.75 to
$5.50 covering 28.4 bcf in 2006.
(B) 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 4.4 bcf of production in 2005 at a weighted average floor and ceiling of $3.10 and $4.44. and call options covering 7.3 bcf of production in 2005 at a weighted average price of $6.00.
The company has also entered into the following natural gas basis protection swaps:
Assuming Gas
Volume NYMEX Production in
in Bcf's less:* Bcf's of: % Hedged
2005 188.6 0.26 392.0 48%
2006 130.1 0.32 440.0 30%
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 650.4 $0.28 2,317.0 28%
* 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 - 2005 870.5 $41.87 1,650 53%
Q2 - 2005 1,001.0 $42.39 1,650 61%
Q3 - 2005 246.0 $38.00 1,650 15%
Q4 - 2005 153.5 $32.15 1,650 9%
Total 2005 (A) 2,271.0 $41.02 6,600 34%
(A) Certain hedging arrangements include swaps with 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/
