Press Releases
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.
PRNewswire -- July 27
END FIRST AND FINAL ADD
SOURCE: Chesapeake Energy Corporation
Web site: http://www.chkenergy.com/
