CHESAPEAKE ENERGY CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS
($ in 000's, except per share data) (unaudited) THREE MONTHS ENDED:
June 30, June 30, 2006 2005 $ $/mcfe $ $/mcfe REVENUES: Oil and
natural gas sales 1,186,383 8.32 772,401 6.83 Marketing sales
367,610 2.57 275,617 2.43 Service operations revenue 30,023 0.21
--- --- Total Revenues 1,584,016 11.10 1,048,018 9.26 OPERATING
COSTS: Production expenses 120,697 0.85 72,333 0.64 Production
taxes 33,923 0.24 47,253 0.42 General and administrative expenses
33,555 0.24 11,788 0.10 Marketing expenses 355,688 2.48 270,003
2.39 Service operations expense 15,667 0.11 --- --- Oil and natural
gas depreciation, depletion and amortization 328,159 2.30 209,371
1.85 Depreciation and amortization of other assets 23,163 0.16
11,807 0.10 Total Operating Costs 910,852 6.38 622,555 5.50 INCOME
FROM OPERATIONS 673,164 4.72 425,463 3.76 OTHER INCOME (EXPENSE):
Interest and other income 4,974 0.03 2,005 0.02 Interest expense
(73,456) (0.51) (53,902) (0.48) Loss on repurchases or exchanges of
Chesapeake debt --- --- (68,400) (0.60) Total Other Income
(Expense) (68,482) (0.48) (120,297) (1.06) Income Before Income
Taxes 604,682 4.24 305,166 2.70 Income Tax Expense: Current --- ---
--- --- Deferred 244,779 1.72 111,387 0.99 Total Income Tax Expense
244,779 1.72 111,387 0.99 NET INCOME 359,903 2.52 193,779 1.71
Preferred stock dividends (18,228) (0.12) (9,859) (0.09) Loss on
exchange/conversion of preferred stock (9,547) (0.07) (4,743)
(0.04) NET INCOME AVAILABLE TO COMMON SHAREHOLDERS 332,128 2.33
179,177 1.58 EARNINGS PER COMMON SHARE: Basic $0.87 $0.58 Assuming
dilution $0.82 $0.52 WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT
SHARES OUTSTANDING (in 000's) Basic 380,675 311,181 Assuming
dilution 428,169 364,063 CHESAPEAKE ENERGY CORPORATION CONSOLIDATED
STATEMENTS OF OPERATIONS ($ in 000's, except per share data)
(unaudited) SIX MONTHS ENDED: June 30, June 30, 2006 2005 $ $/mcfe
$ $/mcfe REVENUES: Oil and natural gas sales 2,697,204 9.66
1,311,343 6.01 Marketing sales 771,977 2.76 520,125 2.39 Service
operations revenue 59,402 0.21 --- --- Total Revenues 3,528,583
12.63 1,831,468 8.40 OPERATING COSTS: Production expenses 240,089
0.86 141,895 0.65 Production taxes 89,296 0.32 83,211 0.38 General
and administrative expenses 62,346 0.22 23,855 0.11 Marketing
expenses 747,048 2.67 507,279 2.33 Service operations expense
30,104 0.11 --- --- Oil and natural gas depreciation, depletion and
amortization 633,116 2.27 390,339 1.79 Depreciation and
amortization of other assets 47,035 0.17 21,889 0.10 Employee
retirement expense 54,753 0.20 --- --- Total Operating Costs
1,903,787 6.82 1,168,468 5.36 INCOME FROM OPERATIONS 1,624,796 5.81
663,000 3.04 OTHER INCOME (EXPENSE): Interest and other income
14,610 0.05 5,362 0.02 Interest expense (146,114) (0.52) (97,030)
(0.44) Gain on sale of investment 117,396 0.42 --- --- Loss on
repurchases or exchanges of Chesapeake debt --- --- (69,300) (0.32)
Total Other Income (Expense) (14,108) (0.05) (160,968) (0.74)
Income Before Income Taxes 1,610,688 5.76 502,032 2.30 Income Tax
Expense: Current --- --- --- --- Deferred 627,062 2.24 183,243 0.84
Total Income Tax Expense 627,062 2.24 183,243 0.84 NET INCOME
983,626 3.52 318,789 1.46 Preferred stock dividends (37,040) (0.13)
(15,322) (0.07) Loss on exchange/conversion of preferred stock
(10,556) (0.04) (4,743) (0.02) NET INCOME AVAILABLE TO COMMON
SHAREHOLDERS 936,030 3.35 298,724 1.37 EARNINGS PER COMMON SHARE:
Basic $2.50 $0.96 Assuming dilution $2.27 $0.88 WEIGHTED AVERAGE
COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in 000's) Basic
374,683 310,523 Assuming dilution 433,414 356,478 CHESAPEAKE ENERGY
CORPORATION CONSOLIDATED BALANCE SHEETS (in 000's) (unaudited) June
30, December 31, 2006 2005 Cash $366,270 $60,027 Other current
assets 1,289,467 1,123,370 Total Current Assets 1,655,737 1,183,397
Property and equipment (net) 17,775,369 14,411,887 Other assets
629,945 523,178 Total Assets $20,061,051 $16,118,462 Current
liabilities $1,776,469 $1,964,088 Long term debt 6,330,115
5,489,742 Asset retirement obligation 171,430 156,593 Other long
term liabilities 357,120 528,738 Deferred tax liability 2,435,731
1,804,978 Total Liabilities 11,070,865 9,944,139 STOCKHOLDERS'
EQUITY 8,990,186 6,174,323 TOTAL LIABILITIES & STOCKHOLDERS'
EQUITY $20,061,051 $16,118,462 COMMON SHARES OUTSTANDING 418,876
370,190 CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF SIX MONTHS
ENDED JUNE 30, 2006 ADDITIONS TO OIL AND NATURAL GAS PROPERTIES ($
in 000's, except per unit amounts) (unaudited) Reserves Cost (in
mmcfe) $/mcfe Exploration and development costs $1,338,205
786,027(A) $1.70 Acquisition of proved properties 494,278 269,239
$1.84 Subtotal 1,832,483 1,055,266 $1.74 Divestitures (73) (89) ---
Geological and geophysical costs 71,675 --- --- Adjusted subtotal
1,904,085 1,055,177 $1.80 Revisions - price --- (195,541) ---
Acquisition of unproved properties 1,256,132 --- --- Leasehold
acquisition costs 323,856 --- --- Adjusted subtotal 3,484,073
859,636 $4.05 Tax basis step-up 81,373 --- Asset retirement
obligation and other 11,774 --- Total $3,577,220 859,636 $4.16 (A)
Includes positive performance revisions of 352 bcfe and excludes
downward revisions of 196 bcfe resulting from natural gas price
declines between December 31, 2005 and June 30, 2006. CHESAPEAKE
ENERGY CORPORATION ROLL-FORWARD OF PROVED RESERVES (unaudited)
Mmcfe Beginning balance, 12/31/05 7,520,690 Extensions and
discoveries 434,414 Acquisitions 269,239 Divestitures (89)
Revisions - performance 351,613 Revisions - price (195,541)
Production (279,428) Ending balance, 6/30/06 8,100,898 Reserve
replacement 859,636 Reserve replacement rate 308% CHESAPEAKE ENERGY
CORPORATION SUPPLEMENTAL DATA - OIL AND NATURAL GAS SALES AND
INTEREST EXPENSE (in 000's) (unaudited) THREE MONTHS ENDED SIX
MONTHS ENDED June 30, June 30, 2006 2005 2006 2005 Oil and Natural
Gas Sales ($ in thousands): Oil sales $138,241 $96,798 $262,908
$176,742 Oil derivatives - realized gains (losses) (12,227)
(10,650) (16,035) (17,717) Oil derivatives - unrealized gains
(losses) (2,564) 10,900 (3,899) (1,942) Total Oil Sales 123,450
97,048 242,974 157,083 Natural gas sales 774,259 635,901 1,714,577
1,171,678 Natural gas derivatives - realized gains (losses) 269,650
(33,702) 521,679 13,713 Natural gas derivatives - unrealized gains
(losses) 19,024 73,154 217,974 (31,131) Total Natural Gas Sales
1,062,933 675,353 2,454,230 1,154,260 Total Oil and Natural Gas
Sales $1,186,383 $772,401 $2,697,204 $1,311,343 Average Sales Price
(excluding gains (losses) on derivatives): Oil ($ per bbl) $64.51
$48.11 $61.73 $47.03 Natural gas ($ per mcf) $5.96 $6.29 $6.75
$6.00 Natural gas equivalent ($ per mcfe) $6.40 $6.47 $7.08 $6.19
Average Sales Price (excluding unrealized gains (losses) on
derivatives): Oil ($ per bbl) $58.80 $42.82 $57.97 $42.32 Natural
gas ($ per mcf) $8.04 $5.95 $8.81 $6.07 Natural gas equivalent ($
per mcfe) $8.20 $6.08 $8.89 $6.17 Interest Expense ($ in thousands)
Interest $73,834 $54,710 $146,732 $102,003 Derivatives - realized
(gains) losses (1,163) (675) (2,407) (1,796) Derivatives -
unrealized (gains) losses 785 (133) 1,789 (3,177) Total Interest
Expense $73,456 $53,902 $146,114 $97,030 CHESAPEAKE ENERGY
CORPORATION CONDENSED CONSOLIDATED CASH FLOW DATA (in 000's)
(unaudited) THREE MONTHS ENDED: June 30, June 30, 2006 2005 Cash
provided by operating activities $ 1,077,686 $ 507,232 Cash (used
in) investing activities (1,823,996) (1,365,941) Cash provided by
financing activities 1,074,294 858,709 SIX MONTHS ENDED: June 30,
June 30, 2006 2005 Cash provided by operating activities $
2,045,144 $ 1,019,917 Cash (used in) investing activities
(3,784,057) (2,539,878) Cash provided by financing activities
2,045,156 1,513,065 CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF
OPERATING CASH FLOW AND EBITDA (in 000's) (unaudited) THREE MONTHS
ENDED: June 30, March 31, June 30, 2006 2006 2005 CASH PROVIDED BY
OPERATING ACTIVITIES $1,077,686 $ 967,458 $507,232 Adjustments:
Changes in assets and liabilities (163,520) 79,405 (53,498)
OPERATING CASH FLOW* $ 914,166 $1,046,863 $453,734 * Operating cash
flow represents net cash provided by operating activities before
changes in assets and liabilities. Operating cash flow is presented
because management believes it is a useful adjunct to net cash
provided by operating activities under accounting principles
generally accepted in the United States (GAAP). Operating cash flow
is widely accepted as a financial indicator of an oil and natural
gas company's ability to generate cash which is used to internally
fund exploration and development activities and to service debt.
This measure is widely used by investors and rating agencies in the
valuation, comparison, rating and investment recommendations of
companies within the oil and natural gas exploration and production
industry. Operating cash flow is not a measure of financial
performance under GAAP and should not be considered as an
alternative to cash flows from operating, investing, or financing
activities as an indicator of cash flows, or as a measure of
liquidity. THREE MONTHS ENDED: June 30, March 31, June 30, 2006
2006 2005 NET INCOME $ 359,903 $ 623,723 $193,779 Income tax
expense 244,779 382,283 111,387 Interest expense 73,456 72,658
53,902 Depreciation and amortization of other assets 23,163 23,872
11,807 Oil and natural gas depreciation, depletion and amortization
328,159 304,957 209,371 EBITDA** $1,029,460 $1,407,493 $580,246 **
Ebitda represents net income before income tax expense, interest
expense, and depreciation, depletion and amortization expense.
Ebitda is presented as a supplemental financial measurement in the
evaluation of our business. We believe that it provides additional
information regarding our ability to meet our future debt service,
capital expenditures and working capital requirements. This measure
is widely used by investors and rating agencies in the valuation,
comparison, rating and investment recommendations of companies.
Ebitda is also a financial measurement that, with certain
negotiated adjustments, is reported to our lenders pursuant to our
bank credit agreement and is used in the financial covenants in our
bank credit agreement and our senior note indentures. Ebitda is not
a measure of financial performance under GAAP. Accordingly, it
should not be considered as a substitute for net income, income
from operations, or cash flow provided by operating activities
prepared in accordance with GAAP. Ebitda is reconciled to cash
provided by operating activities as follows: THREE MONTHS ENDED:
June 30, March 31, June 30, 2006 2006 2005 CASH PROVIDED BY
OPERATING ACTIVITIES $1,077,686 $967,458 $507,232 Changes in assets
and liabilities (163,520) 79,405 (53,498) Interest expense 73,456
72,658 53,902 Unrealized gains (losses) on oil and natural gas
derivatives 16,460 197,615 84,054 Other non-cash items 25,378
90,357 (11,444) EBITDA $1,029,460 $1,407,493 $580,246 CHESAPEAKE
ENERGY CORPORATION RECONCILIATION OF OPERATING CASH FLOW AND EBITDA
(in 000's) (unaudited) SIX MONTHS ENDED: June 30, June 30, 2006
2005 CASH PROVIDED BY OPERATING ACTIVITIES $2,045,144 $1,019,917
Adjustments: Changes in assets and liabilities (84,115) (61,561)
OPERATING CASH FLOW* $1,961,029 $958,356 * Operating cash flow
represents net cash provided by operating activities before changes
in assets and liabilities. Operating cash flow is presented because
management believes it is a useful adjunct to net cash provided by
operating activities under accounting principles generally accepted
in the United States (GAAP). Operating cash flow is widely accepted
as a financial indicator of an oil and natural gas company's
ability to generate cash which is used to internally fund
exploration and development activities and to service debt. This
measure is widely used by investors and rating agencies in the
valuation, comparison, rating and investment recommendations of
companies within the oil and natural gas exploration and production
industry. Operating cash flow is not a measure of financial
performance under GAAP and should not be considered as an
alternative to cash flows from operating, investing, or financing
activities as an indicator of cash flows, or as a measure of
liquidity. SIX MONTHS ENDED: June 30, June 30, 2006 2005 NET INCOME
$983,626 $318,789 Income tax expense 627,062 183,243 Interest
expense 146,114 97,030 Depreciation and amortization of other
assets 47,035 21,889 Oil and natural gas depreciation, depletion
and amortization 633,116 390,339 EBITDA** $2,436,953 $1,011,290 **
Ebitda represents net income before income tax expense, interest
expense, and depreciation, depletion and amortization expense.
Ebitda is presented as a supplemental financial measurement in the
evaluation of our business. We believe that it provides additional
information regarding our ability to meet our future debt service,
capital expenditures and working capital requirements. This measure
is widely used by investors and rating agencies in the valuation,
comparison, rating and investment recommendations of companies.
Ebitda is also a financial measurement that, with certain
negotiated adjustments, is reported to our lenders pursuant to our
bank credit agreement and is used in the financial covenants in our
bank credit agreement and our senior note indentures. Ebitda is not
a measure of financial performance under GAAP. Accordingly, it
should not be considered as a substitute for net income, income
from operations, or cash flow provided by operating activities
prepared in accordance with GAAP. Ebitda is reconciled to cash
provided by operating activities as follows: SIX MONTHS ENDED: June
30, June 30, 2006 2005 CASH PROVIDED BY OPERATING ACTIVITIES
$2,045,144 $1,019,917 Changes in assets and liabilities (84,115)
(61,561) Interest expense 146,114 97,030 Unrealized gains (losses)
on oil and natural gas derivatives 214,075 (33,073) Other non-cash
items 115,735 (11,023) EBITDA $2,436,953 $1,011,290 CHESAPEAKE
ENERGY CORPORATION RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE
TO COMMON ($ in 000's, except per share amounts) (unaudited) June
30, March 31, June 30, THREE MONTHS ENDED: 2006 2006 2005 Net
income available to common shareholders $ 332,128 $ 603,902 $
179,177 Adjustments: Loss on conversion/exchange of preferred stock
9,547 1,009 4,743 Unrealized (gains) losses on derivatives, net of
tax (9,720) (121,899) (53,458) Cumulative impact of new Texas
margin tax 15,000 --- --- Reversal of severance tax accrual, net of
tax (7,192) --- --- Gain on sale of investment, net of tax ---
(72,786) --- Employee retirement expense, net of tax --- 33,947 ---
Loss on repurchases or exchanges of debt, net of tax --- --- 43,434
Adjusted net income available to common shareholders* 339,763
444,173 173,896 Preferred dividends 18,228 18,812 9,859 Total
adjusted net income $ 357,991 $ 462,985 $ 183,755 Weighted average
fully diluted shares outstanding** 434,915 431,723 366,677 Adjusted
earnings per share assuming dilution $ 0.82 $ 1.07 $ 0.50 *
Adjusted net income available to common and adjusted earnings per
share assuming dilution exclude certain items that management
believes affect the comparability of operating results. The company
discloses these non-GAAP financial measures as a useful adjunct to
GAAP earnings because: a. Management uses adjusted net income
available to common to evaluate the company's operational trends
and performance relative to other oil and natural gas producing
companies. b. Adjusted net income available to common is more
comparable to earnings estimates provided by securities analysts.
c. Items excluded generally are one-time items, or items whose
timing or amount cannot be reasonably estimated. Accordingly, any
guidance provided by the company generally excludes information
regarding these types of items. ** Weighted average fully diluted
shares outstanding includes shares that were considered
antidilutive for calculating earnings per share in accordance with
GAAP. CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF ADJUSTED
EBITDA ($ in 000's) (unaudited) June 30, March 31, June 30, THREE
MONTHS ENDED: 2006 2006 2005 EBITDA $ 1,029,460 $ 1,407,493 $
580,246 Adjustments, before tax: Unrealized (gains) losses on oil
and natural gas derivatives (16,460) (197,615) (84,054) Reversal of
severance tax accrual (11,600) --- --- Gain on sale of investment
--- (117,396) --- Employee retirement expense --- 54,753 --- Loss
on repurchases or exchanges of debt --- --- 68,400 Adjusted EBITDA*
$ 1,001,400 $ 1,147,235 $ 564,592 * Adjusted EBITDA excludes
certain items that management believes affect the comparability of
operating results. The company discloses these non-GAAP financial
measures as a useful adjunct to EBITDA because: a. Management uses
adjusted EBITDA to evaluate the company's operational trends and
performance relative to other oil and natural gas producing
companies. b. Adjusted EBITDA is more comparable to earnings
estimates provided by securities analysts. c. Items excluded
generally are one-time items, or items whose timing or amount
cannot be reasonably estimated. Accordingly, any guidance provided
by the company generally excludes information regarding these types
of items. CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF ADJUSTED
NET INCOME AVAILABLE TO COMMON ($ in 000's, except per share
amounts) (unaudited) June 30, June 30, SIX MONTHS ENDED: 2006 2005
Net income available to common shareholders $ 936,030 $ 298,724
Adjustments: Loss on conversion/exchange of preferred stock 10,556
4,743 Unrealized (gains) losses on derivatives, net of tax
(131,619) 18,985 Cumulative impact of new Texas margin tax 15,000
--- Reversal of severance tax accrual, net of tax (7,192) --- Gain
on sale of investment, net of tax (72,786) --- Employee retirement
expense, net of tax 33,947 --- Loss on repurchases or exchanges of
debt, net of tax --- 44,006 Adjusted net income available to common
shareholders* 783,936 366,458 Preferred dividends 37,040 15,322
Total adjusted net income $ 820,976 $ 381,780 Weighted average
fully diluted shares outstanding** 433,414 359,136 Adjusted
earnings per share assuming dilution $ 1.89 $ 1.06 * Adjusted net
income available to common and adjusted earnings per share assuming
dilution exclude certain items that management believes affect the
comparability of operating results. The company discloses these
non-GAAP financial measures as a useful adjunct to GAAP earnings
because: a. Management uses adjusted net income available to common
to evaluate the company's operational trends and performance
relative to other oil and natural gas producing companies. b.
Adjusted net income available to common is more comparable to
earnings estimates provided by securities analysts. c. Items
excluded generally are one-time items, or items whose timing or
amount cannot be reasonably estimated. Accordingly, any guidance
provided by the company generally excludes information regarding
these types of items. ** Weighted average fully diluted shares
outstanding includes shares that were considered antidilutive for
calculating earnings per share in accordance with GAAP. CHESAPEAKE
ENERGY CORPORATION RECONCILIATION OF ADJUSTED EBITDA ($ in 000's)
(unaudited) June 30, June 30, SIX MONTHS ENDED: 2006 2005 EBITDA $
2,436,953 $ 1,011,290 Adjustments, before tax: Unrealized (gains)
losses on oil and natural gas derivatives (214,075) 33,073 Reversal
of severance tax accrual (11,600) --- Gain on sale of investment
(117,396) --- Employee retirement expense 54,753 --- Loss on
repurchases or exchanges of debt --- 69,300 Adjusted EBITDA* $
2,148,635 $ 1,113,663 *Adjusted EBITDA excludes certain items that
management believes affect the comparability of operating results.
The company discloses these non-GAAP financial measures as a useful
adjunct to EBITDA because: a. Management uses adjusted EBITDA to
evaluate the company's operational trends and performance relative
to other oil and natural gas producing companies. b. Adjusted
EBITDA is more comparable to earnings estimates provided by
securities analysts. c. Items excluded generally are one-time
items, or items whose timing or amount cannot be reasonably
estimated. Accordingly, any guidance provided by the company
generally excludes information regarding these types of items.
SCHEDULE "A" CHESAPEAKE'S OUTLOOK AS OF JULY 27, 2006 Quarter
Ending September 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 July 27, 2006, we are using
the following key assumptions in our projections for the third
quarter of 2006, the full-year 2006 and the full-year 2007. The
primary changes from our June 5, 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 expenditure assumptions have
been updated; 3) We have shown our projections for the quarter
ending September 30, 2006 for the first time. Quarter Ending Year
Ending Year Ending 9/30/2006 12/31/2006 12/31/2007 Estimated
Production (A): Oil - mbbls 2,000 8,400 8,400 Natural gas - bcf 136
- 140 531 - 541 595 - 605 Natural gas equivalent - bcfe 148 - 152
581 - 591 645 - 655 Daily natural gas equivalent midpoint - in
mmcfe 1,630 1,605 1,781 NYMEX Prices (B) (for calculation of
realized hedging effects only): Oil - $/bbl $56.25 $61.67 $56.25
Natural gas - $/mcf $6.96 $7.57 $7.50 Estimated Realized Hedging
Effects (based on assumed NYMEX prices above): Oil - $/bbl $7.26
$1.92 $11.43 Natural gas - $/mcf $1.89 $1.99 $1.89 Estimated
Differentials to NYMEX Prices: Oil - $/bbl 6 - 8% 7 - 9% 6 - 8%
Natural gas - $/mcf 8 - 12% 10 - 15% 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) (C) $0.38-0.42 $0.41-0.46 $0.41-0.46 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 $2.35-2.40 $2.30-2.40 $2.40-2.50
Depreciation of other assets $0.18-0.22 $0.18-0.22 $0.24-0.28
Interest expense (D) $0.55-0.59 $0.54-0.58 $0.60-0.65 Other Income
per Mcfe: Marketing and other income $0.02-0.04 $0.04-0.06
$0.04-0.06 Service operations income $0.10-0.12 $0.08-0.12
$0.10-0.15 Book Tax Rate (approximately equal to 95% deferred) 38%
38% 38% Equivalent Shares Outstanding: Basic 418 mm 397 mm 423 mm
Diluted 484 mm 459 mm 488 mm Capital Expenditures: Drilling,
leasehold and seismic $900-1,100 mm $3,700-4,000 mm $3,800-4,100 mm
(A) Production forecast for Q3 2006 and calendar 2006 excludes
provisions for possible production curtailments that the industry
and Chesapeake may experience as a result of high pipeline
pressures and/or early filling of U.S. natural gas storage
facilities. (B) Oil NYMEX prices have been updated for actual
contract prices through June 2006 and natural gas NYMEX prices have
been updated for actual contract prices through July 2006. (C)
Severance tax per mcfe is based on NYMEX prices of $56.25 per bbl
of oil and $6.80 to $7.60 per mcf of natural gas during Q3 2006,
$57.35 per bbl of oil and $7.50 to $8.50 per mcf of natural gas
during calendar 2006 and $56.25 per bbl of oil and $7.50 to $8.50
per mcf of natural gas during calendar 2007. (D) 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 Positions Avg. NYMEX as a %
of Price Estimated Avg. NYMEX Including Assuming Total Strike Price
Gain (Loss) Open & Natural Gas Natural Open Swaps Of Open from
Locked Locked Production Gas in Bcf's Swaps Swaps Positions in
Bcf's of: Production 2006: Q1 93.8 $10.81 -$0.09 $10.72 124.1 76%
Q2 101.4 $8.82 -$0.05 $8.77 129.8 78% Q3 117.9 $8.80 -$0.05 $8.75
138.0 85% Q4 114.9 $9.46 -$0.04 $9.42 144.1 80% Total 2006(A) 428.0
$9.42 -$0.05 $9.37 536.0 80% Total 2007 392.1 $9.99 -$0.03 $9.96
600.0 65% Total 2008 329.4 $9.53 --- $9.53 642.0 51% Total 2009 3.7
$9.02 --- $9.02 687.0 1% (A) 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 53.9 bcf in 2007 and
$5.75 to $6.50 covering 69.5 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 in Bcf's NYMEX less*: Volume 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 November 2005. In accordance with SFAS 141, these
derivative positions were recorded at fair value in the purchase
price allocation as a liability of $592 million ($469 million as of
June 30, 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 Open Swap Avg. NYMEX Avg. Fair Positions Strike
Value Upon as a % Price Acquisition Initial Assuming of Estimated
Of Open of Open Liability Natural Gas Total Open Swaps Swaps Swaps
Acquired Production Natural Gas in Bcf's (per Mcf) (per Mcf) (per
Mcf) in 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) 129.8 8% Q3 10.6 $4.86 $9.95
($5.09) 138.0 8% Q4 10.6 $4.86 $10.38 ($5.52) 144.1 7% Total 2006
39.6 $4.87 $10.51 ($5.64) 536.0 7% Total 2007 42.0 $4.82 $9.18
($4.36) 600.0 7% Total 2008 38.4 $4.67 $8.01 ($3.34) 642.0 6% Total
2009 18.3 $5.18 $7.28 ($2.10) 687.0 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 Avg. Assuming Oil as % of Total Open Swaps 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 2,143 64% Q3
1,747.0 $64.83 2,000 87% Q4 1,840.0 $65.64 2,141 86% Total 2006(A)
6,076.0 $63.52 8,400 72% Total 2007 6,110.0 $71.42 8,400 73% Total
2008 5,032.0 $71.45 8,000 63% Total 2009 182.5 $66.10 8,000 2% (A)
Certain hedging arrangements include swaps with knockout prices
ranging from $40.00 to $60.00 covering 654.5 mbbls in 2006, $45.00
to $60.00 covering 1,460.0 mbbls in 2007 and $45.00 to $60.00
covering 1,098.0 mbbls in 2008, respectively. SCHEDULE "B"
CHESAPEAKE'S PREVIOUS OUTLOOK AS OF JUNE 5, 2006 (PROVIDED FOR
REFERENCE ONLY) NOW SUPERSEDED BY OUTLOOK AS OF JULY 27, 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 losses 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
Positions Avg. NYMEX as a % of Price Estimated Avg. NYMEX Including
Assuming Total Strike Price Gain (Loss) Open & Natural Gas
Natural Open Swaps Of Open from Locked Locked Production Gas in
Bcf's Swaps Swaps Positions in 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(A) 428.0 $9.42 -$0.05 $9.37 538.0 80%
Total 2007(A) 370.2 $9.98 -$0.04 $9.94 597.0 62% Total 2008(A)
311.1 $9.50 --- $9.50 637.0 49% Total 2009 3.7 $9.02 --- $9.02
682.0 1% (A) 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 in
Bcf's NYMEX less*: Volume 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 Open Swap
Avg. NYMEX Avg. Fair Positions Strike Value Upon as a % Price
Acquisition Initial Assuming of Estimated Of Open of Open Liability
Natural Gas Total Open Swaps Swaps Swaps Acquired Production
Natural Gas in Bcf's (per Mcf) (per Mcf) (per Mcf) in 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 Avg. Assuming Oil as %
of Total Open Swaps 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(A) 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% (A) 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. DATASOURCE: Chesapeake
Energy Corporation Web site: http://www.chkenergy.com/
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