Press Releases
Chesapeake Energy Corporation
The company's 2004 third quarter net income available to common shareholders includes an unrealized after-tax mark-to-market loss of $24.8 million ($0.08 per fully diluted common share) resulting from the company's oil and natural gas and interest rate hedging programs. This item is typically excluded from analysts' estimates.
If this item had been excluded, Chesapeake's net income to common shareholders would have been $110.3 million ($0.37 per fully diluted common share) and ebitda would have been $393.8 million. This item does not affect the calculation of operating cash flow.
Oil and Natural Gas Production and Proved Reserves Again Set Records; Reserve Replacement Rate of 789% Achieved at Attractive Cost of $1.02 Per Mcfe
Production for the 2004 third quarter was 94.2 billion cubic feet of natural gas equivalent (bcfe), an increase of 23.2 bcfe, or 33%, over the 71.0 bcfe produced in the 2003 third quarter and an increase of 7.7 bcfe, or 9%, over the 86.5 bcfe produced in the 2004 second quarter. The 23.2 bcfe increase in this year's third quarter production over 2003 third quarter production consisted of approximately 9.3 bcfe (40%) generated from organic drillbit growth and approximately 13.9 bcfe (60%) generated from acquisitions. The company's 2004 third quarter production exceeded its July 26, 2004 forecasted 2004 third quarter production by 2.2 bcfe, or 2.4%, because of stronger than forecasted drilling results in 2004.
Chesapeake's annualized organic growth rate during the first three quarters of 2004 has been 13%, well above the company's previously forecasted organic growth rate of 5% and among the best organic growth performances reported by public mid- and large-cap E&P companies this year. In addition, the balance between Chesapeake's growth through the drillbit and growth through acquisitions reflects the continued successful execution of the company's successful growth strategy. The company is projecting annual organic growth rates of 13% in 2004, 10% in 2005 and 8% in 2006. Total projected company production growth rates are 33% in 2004, 14% in 2005 and 8% in 2006.
Production in the 2004 third quarter of 94.2 bcfe was comprised of 83.2 billion cubic feet of natural gas (bcf) (88% on a natural gas equivalent basis) and 1.83 million barrels of oil and natural gas liquids (mmbo) (12% on a natural gas equivalent basis). Chesapeake's average daily production rate for the quarter was 1,024 million cubic feet of natural gas equivalent production (mmcfe), consisting of 905 mmcf of gas and 19,935 barrels of oil and natural gas liquids. The 2004 third quarter was Chesapeake's 13th consecutive quarter of sequential production growth. During these 13 quarters, Chesapeake's production has increased 141%, for an average compounded quarterly growth rate of 7% and an average compounded annual growth rate of 31%.
During the 2004 third quarter, the company replaced its 94.2 bcfe of production with an internally estimated 744 bcfe of new proved reserves, for a reserve replacement rate of 789% at a drilling and acquisition cost of $1.02 per mcfe. Reserve replacement through the drillbit was 364 bcfe (including 91 bcfe from performance revisions and 18 bcfe from oil and natural gas price increases), or 49% of the total increase, and reserve replacement through acquisitions was 380 bcfe, or 51% of the total increase. At the end of the third quarter, Chesapeake's estimated proved reserves were 4.45 trillion cubic feet of natural gas equivalent (tcfe). The company anticipates that its year- end 2004 proved reserves will be approximately 4.6 tcfe and that its year-end 2005 and 2006 proved reserves should be approximately 5.0 tcfe and 5.4 tcfe, respectively, excluding any potential proved reserves added through future acquisitions.
Average prices realized during the 2004 third quarter (including realized gains or losses from oil and gas derivatives, but excluding unrealized gains or losses on such derivatives) were $29.15 per barrel of oil (bo) and $5.17 per thousand cubic feet of natural gas (mcf), for a realized gas equivalent price of $5.13 per thousand cubic feet of natural gas equivalent (mcfe). Chesapeake's average realized pricing differentials to NYMEX during the quarter were a negative $2.98 per bo and a negative $0.56 per mcf. Realized gains or losses from oil and natural gas hedging activities generated an $11.16 loss per bo and a $0.21 loss per mcf, for a 2004 third quarter realized hedging loss of $38.0 million, or $0.40 per mcfe.
Key Operational and Financial Statistics for the 2004 Third Quarter
The table below summarizes Chesapeake's key results during the 2004 third quarter and compares them to the 2004 second quarter and the 2003 third quarter:
Three Months Ended:
9/30/04 6/30/04 9/30/03
Average daily production (in mmcfe) 1,024 951 772
Gas as % of total production 88 88 90
Natural gas production (in bcf) 83.2 76.5 63.7
Average realized gas price ($/mcf)(a) 5.17 4.87 4.92
Oil production (in mbbls) 1,834 1,673 1,216
Average realized oil price ($/bo)(a) 29.15 28.12 26.20
Natural gas equivalent production
(in bcfe) 94.2 86.5 71.0
Gas equivalent realized price ($/mcfe) (a) 5.13 4.85 4.86
General and administrative costs
($/mcfe) (b) .09 .09 .07
Production taxes ($/mcfe) .33 .26 .30
Production expenses ($/mcfe) .57 .57 .51
Interest expense ($/mcfe) (a) .45 .44 .53
DD&A of oil and gas properties ($/mcfe) 1.63 1.58 1.38
Operating cash flow ($ in millions) (c) 353.4 308.2 247.7
Operating cash flow ($/mcfe) 3.75 3.56 3.49
Ebitda ($ in millions) (d) 361.3 324.1 285.3
Ebitda ($/mcfe) 3.83 3.74 4.02
Net income to common shareholders
($ in millions) 85.6 85.8 81.9
(a) includes the effects of realized gains or (losses) from hedging, but
does not include the effects of unrealized gains or (losses) from
hedging
(b) excludes expenses associated with non-cash stock based compensation
(c) defined as cash flow provided by operating activities before changes
in assets and liabilities
(d) defined as income before income taxes, interest expense, and
depreciation, depletion and amortization expense
Strong Drilling Results and Significant Leasehold Additions Lead to Increased Production Estimates; Leasehold and 3-D Seismic Inventories Reach 3.5 Million
and 9.0 Million Net Acres and Identified Probable
and Possible Reserves Exceed 4.0 Tcfe
Chesapeake's exploratory and development drilling programs and production enhancement operations on its properties continue to produce operational results that exceed the company's forecasts and distinguish the company among its peers. During the 2004 third quarter, Chesapeake drilled 182 gross (143 net) operated wells and participated in another 292 gross (38 net) wells operated by other companies. The company's drilling success rate was 98% for company-operated wells and 96% for non-operated wells. During the quarter, Chesapeake invested $224 million in operated wells, $68 million in non- operated wells and $66 million in acquiring new leasehold and 3-D seismic data.
In addition to adding significant leasehold to its existing leasehold positions in Bray, Cement, Cordell, Mayfield, Sahara, Texoma, Watonga- Chickasha, Anadarko Shelf and other existing core Anadarko and Arkoma Basin projects, Chesapeake also has been aggressively building industry-leading leasehold positions in the Granite Wash and Cherokee/Atoka Wash gas resource plays in the Anadarko Basin (approximately 200,000 prospective net acres acquired to date), in the Hartshorne Coal and Caney Shale gas resource plays of the Arkoma Basin (approximately 200,000 prospective acres acquired to date) and in the Barnett Shale gas resource play in North Texas (approximately 15,000 prospective net acres acquired to date, mainly in our Hallwood JV in Johnson County).
Chesapeake believes it has built the largest onshore U.S. inventories of leasehold and 3-D seismic in the industry (more than 3.5 million and 9.0 million net acres, respectively) and believes it has identified more than a seven-year drilling backlog of 5,000 locations on which the company expects to develop more than 4.0 tcfe of internally estimated probable and possible reserves.
Strong Operational Results Lead to Another Increase in 2004 and 2005 Production Forecasts and to a Strong Initial 2006 Production Forecast
For the 12th consecutive quarter, Chesapeake is increasing its production forecasts. Chesapeake now estimates that its 2004 fourth quarter production will range from 98 to 99 bcfe (1,069 mmcfe per day at the midpoint), up 2.1% from its previous forecast of 96 to 97 bcfe (1,049 mmcfe per day at the midpoint) issued on July 26, 2004. Production in the 2004 fourth quarter should exceed 2003 fourth quarter production by approximately 25 bcfe, or 34%.
For the full-year 2004, the company has increased its mid-point production forecast by 3.0 bcfe (0.8%) to a range of 356 to 358 bcfe (975 mmcfe per day at the mid-point) from its previous forecast of 353 to 355 bcfe (967 mmcfe per day at the mid-point) issued on July 26, 2004. Production for the full-year 2004 should exceed full-year 2003 production by approximately 89 bcfe, or 33%, 40% of which is projected organic growth.
For the full-year 2005, the company has increased its mid-point production forecast by 12.0 bcfe (3.0%) to a range of 403 to 411 bcfe (1,115 mmcfe per day at the mid-point) from its previous forecast of 390 to 400 bcfe (1,082 mmcfe per day at the mid-point) issued on July 26, 2004. Production for the full-year 2005 should exceed full-year 2004 production by approximately 50 bcfe, or 14%, 70% of which is projected organic growth.
For the full-year 2006, the company has released its initial mid-point production forecast of a range of 433 to 443 bcfe (1,200 mmcfe per day at the mid-point). Production for the full-year 2006 should exceed full-year 2005 production by approximately 31 bcfe, or 8%, all of which is projected organic growth.
Chesapeake Takes Advantage of Recent Natural Gas and Oil Price
Strength and Adds to its Natural Gas and Oil Price Hedges
Chesapeake has taken advantage of recent natural gas and oil price strength and has added to its hedge positions in 2004, 2005 and 2006. In addition, by taking advantage of natural gas price weakness during the 2004 second quarter and lifting all of its hedges for 2006 and 2007 natural gas production and then reinstating hedges for 3% of its projected 2006 natural gas production in the third quarter, the company has saved approximately $25 million to date in potential hedging losses. The following tables compare Chesapeake's projected 2004-2007 oil and natural gas production volumes that have been hedged as of November 1, 2004 to what had been previously hedged as of July 26, 2004.
Hedged Positions as of November 1, 2004
Oil Natural Gas
Quarter or Year % Hedged $ NYMEX % Hedged $ NYMEX
2004 1Q 87 % $28.58 99 % $5.97
2004 2Q 92 % $30.00 81 % $5.15
2004 3Q 83 % $30.32 85 % $5.40
2004 4Q 96 % $30.10 86 % $5.77
2004 Total 89 % $29.80 88 % $5.58
2005 1Q 52 % $41.76 64 % $6.70
2005 2Q 52 % $41.63 34 % $5.51
2005 3Q 8 % $31.16 28 % $5.41
2005 4Q 8 % $30.62 18 % $5.22
2005 Total 30 % $40.20 35 % $5.96
2006 --- --- 3 % $4.87
Hedged Positions as of July 26, 2004
Oil Natural Gas
Quarter or Year % Hedged $ NYMEX % Hedged $ NYMEX
2004 1Q 87 % $28.58 99 % $5.97
2004 2Q 92 % $30.00 81 % $5.15
2004 3Q 95 % $30.32 68 % $5.25
2004 4Q 95 % $30.10 40 % $5.12
2004 Total 92 % $29.80 71 % $5.41
2005 9 % $31.56 17 % $4.74
2006 --- --- --- ---
Depending on changes in oil and natural gas futures markets and management's view of underlying oil and natural gas supply and demand trends, Chesapeake may either increase or decrease its hedging positions at any time in the future without notice.
The company's updated 2004 and 2005 forecasts and initial 2006 forecast are attached to this release in an Outlook dated November 1, 2004 labeled as Schedule "A". This Outlook has been changed from the Outlook dated July 26, 2004 (attached as Schedule "B" for investors' convenience) to reflect today's increased production forecasts and the projected effects from hedging position changes.
Balance Sheet Continues to Strengthen
As of September 30, 2004, Chesapeake's long-term debt was $2.76 billion and its stockholders' equity was $2.82 billion, for a debt-to-total capitalization ratio of 49%. The company's proved reserves were 4.45 tcfe, for long-term debt per mcfe of proved reserves of $0.62. One year ago, the company's debt-to-total capitalization ratio was 56% and its long-term debt per mcfe of proved reserves was $0.68, reflecting improvements of 13% and 9%, respectively. Given Chesapeake's strong reserve replacement record through the drillbit, low operating costs and high returns on invested capital, the company believes that its balance sheet will continue to strengthen in the years ahead. During November 2004, the company expects to cause conversion of its $135.7 million of 6.75% perpetual preferred stock into 17,624,658 shares of common stock.
Management Comments
Aubrey K. McClendon, Chesapeake's Chief Executive Officer, commented, "Today's announcement of very strong operational and financial results for the 2004 third quarter and increased production forecasts for the 2004 fourth quarter and the full-years of 2004, 2005 and 2006 provide compelling evidence that Chesapeake's business strategy continues to create significant shareholder value. Key measures reflecting this increase in shareholder value are:
* a record level of proved reserves, production, net income to common
shareholders, cash flow and ebitda;
* a 9% increase in sequential quarterly production from the 2004 second
quarter to the 2004 third quarter;
* a 33% increase in year-over-year quarterly production;
* a 33% increase in estimated 2004 production over 2003 production;
* a 14% increase in estimated 2005 production over estimated 2004
production;
* an 8% increase in estimated 2006 production over estimated 2005
production;
* reserve replacement for the quarter of 789% at an estimated drilling
and acquisition cost of $1.02 per mcfe;
* excellent operating cost control and high returns on equity and total
capital;
* a seven-year inventory of drilling projects with development potential
of at least 4.0 tcfe of estimated probable and possible reserves in
the years ahead.
The company's business strategy has worked very well for our shareholders since our IPO on February 4, 1993, generating a 1,150% increase in our common stock price during the past 11 years. Our business strategy features delivering growth through a balance of acquisitions and organic drilling, focusing on natural gas to take advantage of strong long-term natural gas supply/demand fundamentals and building dominant regional scale to achieve low operating costs and high returns on capital. We believe Chesapeake's management team can continue the successful execution of the company's distinctive business strategy and continue to deliver significant shareholder value for years to come."
November 2004 Investor Conference Information
Chesapeake has scheduled three management conferences with qualified institutional investors on the following dates and places: Tuesday, November 16, 2004 from 12:00 p.m. - 5:00 p.m. EST at the Four Seasons Hotel in New York; Wednesday, November 17, 2004 from 7:30 a.m. - 12:30 p.m. EST at the Ritz Carlton Boston Common in Boston; and Thursday, November 18, 2004 from 7:30 a.m. - 12:30 p.m. PST at the Peninsula Hotel, Los Angeles. Representing the company will be Aubrey McClendon (CEO), Tom Ward (COO), Marc Rowland (CFO), Tom Price (SVP - IR) and Mark Lester (SVP - Exploration). Seating space is limited and those investors wishing to attend must communicate interest in attending by emailing Robin Evans at
Conference Call Information
A conference call has been scheduled for Tuesday morning, November 2, 2004 at 9:00 a.m. EST to discuss this earnings release. The telephone number to access the conference call is 913.981.5520. For those unable to participate in the conference call, a replay will be available from 12:00 p.m. EST, November 2, 2004 through midnight EST on November 15, 2004. The number to access the conference call replay is 719.457.0820 and the passcode is 840912. The conference call will also be simulcast live on the Internet and can be accessed at http://www.chkenergy.com/ by selecting "Conference Calls" under the "Investor Relations" section. The webcast of the conference call will be available on the website for one year.
This press release and the accompanying Outlooks include "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements give our current expectations or forecasts of future events. They include estimates of oil and gas reserves, expected oil and gas production and future expenses, projections of future oil and gas prices, planned capital expenditures for drilling, leasehold acquisitions and seismic data, and statements concerning anticipated cash flow and liquidity, business strategy and other plans and objectives for future operations. Disclosures concerning derivative contracts and their estimated contribution to our future results of operations are based upon market information as of a specific date. These market prices are subject to significant volatility.
Factors that could cause actual results to differ materially from expected results are described under "Risk Factors" in our prospectus dated September 10, 2004 filed with the Securities and Exchange Commission on September 10, 2004. They include the volatility of oil and gas prices; adverse effects our substantial indebtedness and preferred stock obligations could have on our operations and future growth; our ability to compete effectively against strong independent oil and gas companies and majors; possible financial losses and significant collateral requirements as a result of our commodity price and interest rate risk management activities; uncertainties inherent in estimating quantities of oil and gas reserves, including reserves we acquire; projecting future rates of production and the timing of development expenditures; exposure to potential liabilities of acquired properties and companies; our ability to replace reserves; the availability of capital; writedowns of oil and gas carrying values if commodity prices decline; environmental and other claims in excess of insured amounts resulting from drilling and production operations; and the loss of key personnel. We caution you not to place undue reliance on these forward- looking statements, which speak only as of the date of this press release, and we undertake no obligation to update this information.
Our production forecasts are dependent upon many assumptions, including estimates of production decline rates from existing wells and the outcome of future drilling activity. 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.
Chesapeake Energy Corporation is the fifth largest independent producer of natural gas in the U.S. Headquartered in Oklahoma City, the company's operations are focused on exploratory and developmental drilling and producing property acquisitions in the Mid-Continent, Permian Basin, South Texas, Texas Gulf Coast and Ark-La-Tex regions of the United States. The company's Internet address is http://www.chkenergy.com/ .
CHESAPEAKE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
($ in 000's, except per share data)
(unaudited)
THREE MONTHS ENDED: September 30, September 30,
2004 2003
$ $/mcfe $ $/mcfe
REVENUES:
Oil and gas sales 450,936 4.79 345,587 4.87
Oil and gas marketing sales 178,860 1.90 108,962 1.53
Total Revenues 629,796 6.69 454,549 6.40
OPERATING COSTS:
Production expenses 54,102 0.57 35,944 0.51
Production taxes 30,872 0.33 21,638 0.30
General and administrative expenses:
General and administrative
(excluding stock based
compensation) 8,361 0.09 4,726 0.07
Stock based compensation 584 0.01 147 ---
Provisions for legal settlements --- --- 716 0.01
Oil and gas marketing expenses 175,426 1.86 105,849 1.49
Oil and gas depreciation,
depletion, and amortization 153,586 1.63 97,947 1.38
Depreciation and amortization
of other assets 7,700 0.08 4,841 0.07
Total Operating Costs 430,631 4.57 271,808 3.83
INCOME FROM OPERATIONS 199,165 2.12 182,741 2.57
OTHER INCOME (EXPENSE):
Interest and other income 885 0.01 (188) ---
Interest expense (48,689) (0.52)(40,851) (0.57)
Total Other Income (Expense) (47,804) (0.51)(41,039) (0.57)
Income Before Income Taxes 151,361 1.61 141,702 2.00
Income Tax Expense:
Current --- --- 330 ---
Deferred 54,489 0.58 53,513 0.76
Total Income Tax Expense 54,489 0.58 53,843 0.76
NET INCOME 96,872 1.03 87,859 1.24
Preferred Stock Dividends (11,287) (0.12) (5,979) (0.09)
NET INCOME AVAILABLE TO COMMON
SHAREHOLDERS 85,585 0.91 81,880 1.15
EARNINGS PER COMMON SHARE:
Basic $0.33 $0.38
Assuming dilution $0.29 $0.33
WEIGHTED AVERAGE COMMON AND
COMMON EQUIVALENT SHARES OUTSTANDING
(in 000's):
Basic 257,096 216,080
Assuming dilution 319,473 265,545
CHESAPEAKE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
($ in 000's, except per share data)
(unaudited)
NINE MONTHS ENDED: September 30, September 30,
2004 2003
$ $/mcfe $ $/mcfe
REVENUES:
Oil and gas sales 1,270,394 4.89 951,125 4.87
Oil and gas marketing sales 496,823 1.91 309,566 1.59
Total Revenues 1,767,217 6.80 1,260,691 6.46
OPERATING COSTS:
Production expenses 148,500 0.57 101,664 0.52
Production taxes 68,559 0.26 57,336 0.29
General and administrative expenses:
General and administrative
(excluding stock based
compensation) 23,947 0.09 15,740 0.08
Stock based compensation 3,125 0.01 512 ---
Provision for legal settlements --- --- 1,002 0.01
Oil and gas marketing expenses 486,205 1.88 302,064 1.55
Oil and gas depreciation, depletion,
and amortization 410,237 1.58 266,131 1.36
Depreciation and amortization
of other assets 20,155 0.08 12,647 0.07
Total Operating Costs 1,160,728 4.47 757,096 3.88
INCOME FROM OPERATIONS 606,489 2.33 503,595 2.58
OTHER INCOME (EXPENSE):
Interest and other income 3,563 0.01 1,356 0.01
Interest expense (124,040) (0.47) (115,891) (0.59)
Loss on repurchases or exchanges
of Chesapeake debt (6,925) (0.03) --- ---
Total Other Income (Expense) (127,402) (0.49) (114,535) (0.58)
Income Before Income Taxes
and Cumulative Effect
of Accounting Change 479,087 1.84 389,060 2.00
Income Tax Expense:
Current --- --- 330 ---
Deferred 172,470 0.66 147,511 0.76
Total Income Tax Expense 172,470 0.66 147,841 0.76
NET INCOME BEFORE CUMULATIVE EFFECT OF
ACCOUNTING CHANGE, NET OF TAX 306,617 1.18 241,219 1.24
Cumulative Effect of Accounting Change,
Net of Income Tax of $1,464,000 --- --- 2,389 0.01
NET INCOME 306,617 1.18 243,608 1.25
Preferred Stock Dividends (30,799) (0.12) (15,484) (0.08)
NET INCOME AVAILABLE TO COMMON
SHAREHOLDERS 275,818 1.06 228,124 1.17
EARNINGS PER COMMON SHARE:
Basic
Income Before Cumulative
Effect of Accounting Change $1.13 $1.08
Cumulative Effect of --- 0.01
Accounting Change
Net Income $1.13 $1.09
Assuming dilution
Income Before Cumulative
Effect of Accounting Change $0.98 $0.95
Cumulative Effect of --- 0.01
Accounting Change
Net Income $0.98 $0.96
WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING
(in 000's):
Basic 245,087 209,394
Assuming dilution 307,438 253,567
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(in 000's)
(unaudited)
September 30, December 31,
2004 2003
Cash $49,073 $40,581
Other current assets 471,445 301,823
TOTAL CURRENT ASSETS 520,518 342,404
Property and equipment (net) 6,792,727 4,133,117
Other assets 113,046 96,770
TOTAL ASSETS $7,426,291 $4,572,291
Current liabilities $973,010 $513,156
Long term debt 2,762,425 2,057,713
Asset retirement obligation 68,166 48,812
Long term liabilities 58,480 28,774
Deferred tax liability 740,895 191,026
TOTAL LIABILITIES 4,602,976 2,839,481
STOCKHOLDERS' EQUITY 2,823,315 1,732,810
TOTAL LIABILITIES & STOCKHOLDERS' EQUITY $7,426,291 $4,572,291
COMMON SHARES OUTSTANDING 269,718 216,784
CHESAPEAKE ENERGY CORPORATION
SUPPLEMENTAL DATA - OIL & GAS SALES AND INTEREST EXPENSE
Three Months Ended Nine Months Ended
September 30, September 30,
2004 2003 2004 2003
Oil and Gas Sales
($ in thousands):
Oil sales $ 73,921 $ 33,908 $181,882 $101,811
Oil derivatives -
realized gains (losses) (20,464) (2,045) (41,672) (8,924)
Oil derivatives - unrealized
gains (losses) (14,436) 185 (21,925) (993)
Total oil sales 39,021 32,048 118,285 91,894
Gas sales 447,466 293,309 1,222,783 889,598
Gas derivatives - realized
gains (losses) (17,514) 19,781 (25,976) (65,028)
Gas derivatives - unrealized
gains (losses) (18,037) 449 (44,698) 34,661
Total gas sales 411,915 313,539 1,152,109 859,231
Total oil
and gas sales $450,936 $345,587 $1,270,394 $951,125
Average Sales Price
(excluding gains (losses)
on derivatives):
Oil ($ per bbl) $ 40.31 $ 27.88 $ 36.58 $ 29.09
Gas ($ per mcf) $ 5.38 $ 4.61 $ 5.32 $ 5.11
Gas equivalent ($ per mcfe) $ 5.53 $ 4.61 $ 5.41 $ 5.08
Average Sales Price (excluding
unrealized gains (losses) on
derivatives):
Oil ($ per bbl) $ 29.15 $ 26.20 $ 28.20 $ 26.54
Gas ($ per mcf) $ 5.17 $ 4.92 $ 5.21 $ 4.74
Gas equivalent ($ per mcfe) $ 5.13 $ 4.86 $ 5.15 $ 4.70
Interest Expense
($ in thousands):
Interest $ 42,258 $ 38,855 $ 118,335 $113,011
Derivatives - realized
(gains) losses 221 (1,097) (184) (2,453)
Derivatives - unrealized
(gains) losses 6,210 3,093 5,889 5,333
Total Interest Expense $ 48,689 $ 40,851 $ 124,040 $115,891
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED CASH FLOW DATA
(in 000's)
(unaudited)
THREE MONTHS ENDED: September 30, September 30,
2004 2003
Cash provided by operating activities $367,649 $276,884
Cash (used in) investing activities $(1,068,791) $(284,994)
Cash provided by financing activities $673,978 $10,679
NINE MONTHS ENDED: September 30, September 30,
2004 2003
Cash provided by operating activities $1,038,206 $653,517
Cash (used in) investing activities $(2,668,241) $(1,600,768)
Cash provided by financing activities $ 1,638,527 $738,092
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF CERTAIN FINANCIAL MEASURES
(in 000's)
(unaudited)
THREE MONTHS ENDED: September 30, September 30,
2004 2003
CASH PROVIDED BY OPERATING ACTIVITIES $367,649 $276,884
Adjustments:
Changes in assets and liabilities (14,252) (29,175)
OPERATING CASH FLOW* $353,397 $247,709
NINE MONTHS ENDED: September 30, September 30,
2004 2003
CASH PROVIDED BY OPERATING ACTIVITIES $1,038,206 $653,517
Adjustments:
Changes in assets and liabilities (43,082) (12,026)
OPERATING CASH FLOW* $995,124 $641,491
* 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 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
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.
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF CERTAIN FINANCIAL MEASURES
(in 000's)
(unaudited)
THREE MONTHS ENDED: September 30, September 30,
2004 2003
NET INCOME $96,872 $87,859
Income tax expense 54,489 53,843
Interest expense 48,689 40,851
Depreciation and amortization of other assets 7,700 4,841
Oil and gas depreciation, depletion
and amortization 153,586 97,947
EBITDA** $361,336 $285,341
NINE MONTHS ENDED: September 30, September 30,
2004 2003
NET INCOME BEFORE CUMULATIVE EFFECT
OF ACCOUNTING CHANGE $306,617 $241,219
Income tax expense 172,470 147,841
Interest expense 124,040 115,891
Depreciation and amortization of other assets 20,155 12,647
Oil and gas depreciation, depletion
and amortization 410,237 266,131
EBITDA** $1,033,519 $783,729
** Ebitda represents net income (loss) before cumulative effect of
accounting change, income tax expense (benefit), 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: September 30, September 30,
2004 2003
CASH PROVIDED BY OPERATING $367,649 $276,884
ACTIVITIES
Changes in assets and liabilities (14,252) (29,175)
Interest expense, realized 42,479 37,758
Unrealized gains (losses) on oil (32,473) 634
and gas derivatives
Other non-cash items (2,067) (760)
EBITDA $361,336 $285,341
NINE MONTHS ENDED: September 30, September 30,
2004 2003
CASH PROVIDED BY OPERATING ACTIVITIES $1,038,206 $653,517
Changes in assets and liabilities (43,082) (12,026)
Interest expense, realized 118,151 110,558
Unrealized gains (losses) on oil (66,623) 33,668
and gas derivatives
Other non-cash items (13,133) (1,988)
EBITDA $1,033,519 $783,729
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED EARNINGS & ADJUSTED EBITDA
($ In 000's, except per share amounts)
Three Nine
Months Months
Ended Ended
September 30, September 30,
2004 2004
Net income available to common shareholders $85,585 $275,818
Adjustments, net of tax:
Unrealized (gains)
losses on derivatives 24,757 46,408
Loss on repurchases or exchanges of debt --- 4,432
Adjusted earnings* $110,342 $326,658
Adjusted earnings per share
assuming dilution $0.37 $1.14
EBITDA $361,336 $1,033,519
Adjustments, before tax:
Unrealized (gains) losses
on oil and gas derivatives 32,473 66,623
Loss on repurchases or
exchanges of debt --- 6,925
Adjusted EBITDA* $393,809 $1,107,067
* Adjusted earnings, adjusted earnings per share assuming dilution and
adjusted EBITDA, both non-GAAP financial measures, 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 and EBITDA because:
a. Management uses adjusted earnings and adjusted EBITDA to evaluate
the Company's operational trends and performance relative to other
oil and gas producing companies.
b. Adjusted earnings and adjusted EBITDA are more comparable to
earnings and EBITDA 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 NOVEMBER 1, 2004
Quarter Ending December 31, 2004; Year Ending December 31, 2004; Year Ending December 31, 2005; Year Ending December 31, 2006.
We have adopted a policy of periodically providing investors with guidance on certain factors that affect our future financial performance. As of November 1, 2004, we are using the following key assumptions in our projections for the fourth quarter of 2004, the full-year 2004, the full-year 2005 and the full-year 2006.
The primary changes from our July 26, 2004 Outlook are in the table and are explained as follows:
1) We have deleted our 2004 third quarter forecast and have updated our
forecasts for the 2004 fourth quarter, the full-year 2004 and full-
year 2005 forecasts and have provided our initial 2006 forecast.
2) We have updated our previous production forecast for the full-year
2004 to reflect actual third quarter 2004 production, which exceeded
the mid-point of our guidance by 24 mmcfe per day, or 2.4%. In
addition, we have revised upward our fourth quarter 2004 production
forecast by 20 mmcfe per day, or 2.0%, from the mid-point of our
previous guidance, ii) our full-year 2004 production forecast by
8 mmcfe per day, or 0.8%, from the mid-point of our previous
guidance, iii) our full-year 2005 forecast by 33 mmcfe per day, or
3.0%, from the mid-point of our previous guidance, all to account for
better than expected 2004 drilling results. The mid-point of our
initial 2006 production forecast is 438 bcfe, or 1,200 mmcfe per day,
a projected increase of 7.6% over the midpoint of our revised 2005
forecast and 23.1% above the mid-point of our revised 2004 production
forecast.
3) We have updated the projected effects from changes in our hedging
positions since our July 26, 2004 Outlook.
4) We have included our expectations for future NYMEX oil and gas prices
to illustrate hedging effects only.
5) For ease of reconciliation, please note that our first quarter 2004
production was 78.9 bcfe, our second quarter 2004 production was
86.5 bcfe, our third quarter production was 94.2 bcfe and our first
nine months 2004 production was 259.7 bcfe. Our July 26, 2004
Outlook forecasted a third quarter 2004 production range of 91.5 to
92.5 bcfe and a full-year 2004 production range of 353 to 355 bcfe.
The differences are attributable to better than expected 2004
drilling results.
Quarter Year Year Year
Ending Ending Ending Ending
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
2004 2004 2005 2006
Estimated Production:
Oil - Mbo 1,588 6,560 6,600 6,600
Gas - Bcf 88.5-89.5 317-319 364-372 393-403
Gas Equivalent - Bcfe 98-99 356-358 403-411 433-443
Daily gas equivalent
midpoint - in Mmcfe 1,069 975 1,115 1,200
NYMEX Prices (for calculation
of realized hedging effects
only):
Oil - $/Bo $46.67 $41.00 $40.00 $36.00
Gas - $/Mcf $6.60 $6.01 $6.00 $6.00
Estimated Differentials to
NYMEX Prices:
Oil - $/Bo -$2.75 -$2.65 -$2.75 -$2.75
Gas - $/Mcf -$0.75 -$0.70 -$0.70 -$0.70
Estimated Realized Hedging
Effects (based on expected
NYMEX prices above):
Oil - $/Bo -$15.85 -$10.19 $0.06 $0.00
Gas - $/Mcf -$0.53 -$0.23 $0.00 -$0.04
Operating Costs per Mcfe of
Projected Production:
Production expense $0.57-0.62 $0.57-0.62 $0.62-0.67 $0.68-0.72
Production taxes
(generally 7%
of O&G revenues) $0.40-0.44 $0.28-0.33 $0.38-0.40 $0.38-0.40
General and
administrative $0.10-0.11 $0.10-0.11 $0.10-0.11 $0.11-0.12
Stock based compensation
(non-cash) $0.02-0.04 $0.02-0.04 $0.04-0.06 $0.09-0.10
DD&A - oil and gas $1.65-1.70 $1.60-1.65 $1.65-1.75 $1.75-1.85
Depreciation
of other assets $0.08-0.10 $0.08-0.10 $0.09-0.11 $0.10-0.12
Interest expense(a) $0.45-0.49 $0.45-0.49 $0.43-0.47 $0.43-0.47
Other Income and
Expense per Mcfe:
Marketing
and other income $0.02-0.04 $0.02-0.04 $0.02-0.04 $0.02-0.04
Book Tax Rate 36% 36% 36% 36%
Equivalent Shares Outstanding:
Basic 279 mm 254 mm 288 mm 290 mm
Diluted 347 mm 317 mm 349 mm 352 mm
Capital Expenditures:
Drilling, leasehold and
seismic $300-$325 mm $1,100 - $1,200 - $1,300 -
$1,150 mm $1,300 mm $1,400 mm
(a) Does not include gains or losses on interest rate derivatives (SFAS
133).
Commodity Hedging Activities
The company utilizes hedging strategies to hedge the price of a portion of its future oil and gas production. These strategies include:
(i) For swap instruments, we receive a fixed price for the hedged
commodity and pay a floating market price, as defined in each
instrument, to the counterparty. The fixed-price payment and the
floating-price payment are netted, resulting in a net amount due to
or from the counterparty.
(ii) For cap-swaps, Chesapeake receives a fixed price and pays a
floating market price. The fixed price received by Chesapeake
includes a premium in exchange for a "cap" limiting the
counterparty's exposure. In other words, there is no limit to
Chesapeake's exposure but there is a limit to the downside exposure
of the counterparty.
(iii) Basis protection swaps are arrangements that guarantee a price
differential of oil or gas from a specified delivery point.
Chesapeake receives a payment from the counterparty if the price
differential is greater than the stated terms of the contract
and pays the counterparty if the price differential is less than
the stated terms of the contract.
Commodity markets are volatile, and as a result, Chesapeake's hedging activity is dynamic. As market conditions warrant, the company may elect to settle a hedging transaction prior to its scheduled maturity date and, as a result, lock in the gain or loss on the transaction.
Chesapeake enters into oil and natural gas derivative transactions in order to mitigate a portion of its exposure to adverse market changes in oil and natural gas prices. Accordingly, associated gains or loses from the derivative transactions are reflected as adjustments to oil and gas sales. All realized gains and losses from oil and natural gas derivatives are included in oil and gas sales in the month of related production. Pursuant to SFAS 133, certain derivatives do not qualify for designation as cash flow hedges. Changes in the fair value of these non-qualifying derivatives that occur prior to their maturity (i.e. because of temporary fluctuations in value) are reported currently in the consolidated statement of operations as unrealized gains (losses) within oil and gas sales.
Following provisions of SFAS 133, changes in the fair value of derivative instruments designated as cash flow hedges, to the extent effective in offsetting cash flows attributable to hedged risk, are recorded in other comprehensive income until the hedged item is recognized in earnings. Any change in fair value resulting from ineffectiveness is recognized currently in oil and natural gas sales.
The company currently has in place the following natural gas swaps:
% Hedged
Avg.
Avg. NYMEX Assuming Open Swap
NYMEX Gain Price Gas Positions
Open Strike (Loss) Including Production as a % of
Swaps Price from Open & in Estimated
in Of Open Locked Locked Bcf's Total Gas
Bcf's Swaps Swaps Positions of: Production
2004:
1st Qtr 69.5 $5.94 $0.03 $5.97 70.1 99 %
2nd Qtr 62.2 $5.15 $0.00 $5.15 76.5 81 %
3rd Qtr(1) 70.7 $5.49 -$0.09 $5.40 83.2 85 %
4th Qtr(1) 76.5 $5.88 -$0.11 $5.77 89.0 86 %
Total 278.9 $5.63 -$0.05 $5.58 318.8 88 %
2004
2005:
1st Qtr 56.1 $6.82 -$0.12 $6.70 87.7 64 %
2nd Qtr 30.4 $5.86 -$0.35 $5.51 90.7 34 %
3rd Qtr 26.2 $5.77 -$0.36 $5.41 93.8 28 %
4th Qtr 17.0 $5.85 -$0.63 $5.22 95.8 18 %
Total
2005(1) 129.7 $6.26 -$0.30 $5.96 368.0 35 %
Total
2006(1) 13.8 $6.64 -$1.77 $4.87 398.0 3 %
Total
2007(2) --- --- --- --- 430.0 ---
TOTALS
2005-2007 143.5 $6.30 -$0.44 $5.86 1,196.0 12 %
(1) Certain hedging arrangements include swaps with knockout prices
ranging from $3.50 to $5.25 covering 25.4 bcf in 2004, $3.75 to
$5.00 covering 52.9 bcf in 2005 and $3.75 to $5.25 covering 21.1 bcf
in 2006.
(2) Swaps covering 25.6 bcf have been locked for 2007. This will result
in the recognition of $11.6 million of losses in 2007 when the
hedging arrangements settle.
(3) Not shown above are collars covering 1.1 bcf and 4.4 bcf of
production in Q4 2004 and in 2005, respectively, at a weighted
average floor and ceiling of $3.10 and $4.44. In addition, call
options covering 10.2 bcf and 7.3 bcf of production in Q4 2004 and
in 2005 at a weighted average price of $6.31 and $6.00 are not
included in the table above.
The company has also entered into the following natural gas basis protection swaps:
Assuming
Gas
Production
Volume in NYMEX in Bcf's
Bcf's less: of: % Hedged
2004 157.4 0.17 318.8 49 %
2005 175.2 0.25 368.0 48 %
2006 113.1 0.30 398.0 28 %
2007 107.7 0.26 430.0 25 %
2008 108.0 0.25 460.0 23 %
2009 80.3 0.28 490.0 16 %
Totals 741.7 $0.26 * 2,464.8 30 % *
* weighted average
The company has entered into the following crude oil hedging arrangements:
% Hedged
Open Avg. Open Swap Positions
Swaps NYMEX Assuming Oil as %
in Strike Production in of Total Estimated
mbo's Price mbo's of: Production
Q1 - 2004 1,270 $28.58 1,465 87 %
Q2 - 2004 1,540 $30.00 1,673 92 %
Q3 - 2004(1) 1,519 $30.32 1,834 83 %
Q4 - 2004(1) 1,518 $30.10 1,588 96 %
Total 2004(1) 5,847 $29.80 6,560 89 %
Q1 - 2005 855 $41.76 1,650 52 %
Q2 - 2005 865 $41.63 1,650 52 %
Q3 - 2005 138 $31.16 1,650 8 %
Q4 - 2005 138 $30.62 1,650 8 %
Total 2005(1) 1,996 $40.20 6,600 30 %
(1) Certain hedging arrangements include swaps with knockout prices
ranging from $21.00 to $26.00 covering 2,240 mbo in 2004 and knockout
prices ranging from $26.00 to $34.00 covering 1,996 mbo in 2005.
SCHEDULE "B"
CHESAPEAKE'S PREVIOUS OUTLOOK AS OF JULY 26, 2004
(PROVIDED FOR REFERENCE ONLY)
NOW SUPERSEDED BY OUTLOOK AS OF NOVEMBER 1, 2004
Quarter Ending September 30, 2004; Quarter Ending December 31, 2004; Year Ending December 31, 2004; Year Ending December 31, 2005.
We have adopted a policy of periodically providing investors with guidance on certain factors that affect our future financial performance. As of July 26, 2004, we are using the following key assumptions in our projections for the third and fourth quarters of 2004, the full-year 2004 and the full-year 2005.
The primary changes from our May 11, 2004 guidance are explained as follows:
1) We have replaced our 2004 second quarter forecast with our initial
forecasts for the 2004 third and fourth quarters, have revised our
full year 2004 forecast and have provided our initial 2005 forecast.
2) We have updated our previous production forecasts for the full year
2004 to include today's announced acquisitions and the results of
recent drilling activities. These include 30 mmcfe per day of
production beginning August 2, 2004 and an additional 30 mmcfe per
day beginning September 1, 2004 for the acquisitions and an
additional 6.5 mmcfe per day beginning July 1, 2004 for better than
expected drilling results during the second quarter.
3) We have updated the projected effects from the reductions in our
hedging positions.
4) We have included our expectations for future NYMEX oil and gas prices
to illustrate hedging effects only. For ease of reconciliation,
please note that our first quarter 2004 production was 78.9 bcfe, our
second quarter 2004 production was 86.5 bcfe and our first half 2004
production was 165.4 bcfe. Our May 11, 2004 Outlook forecasted a
second quarter 2004 production range of 83-84 bcfe and a full year
2004 production range of 341-347 bcfe.
5) Solely for the purposes of this Schedule "A" we have included the
projected effects of financing the recently announced acquisitions
with the issuance of $300 million of long-term debt securities and
23 million shares of common stock (including a 3 million share over-
allotment option). There is no assurance we will make or complete
such offerings.
Quarter Quarter Year Year
Ending Ending Ending Ending
Sept. 30, Dec. 31, Dec. 31, Dec. 31,
2004 2004 2004 2005
Estimated Production:
Oil - Mbo 1,600 1,600 6,340 6,360
Gas - Bcf 82-83 86.5-87.5 315-317 352-362
Gas Equivalent - Bcfe 91.5-92.5 96-97 353-355 390-400
Daily gas equivalent midpoint 1,000 1,049 967 1,082
- in Mmcfe
NYMEX Prices (for calculation
of realized hedging effects
only):
Oil - $/Bo $34.00 $32.00 $34.87 $30.00
Gas - $/Mcf $5.71 $5.50 $5.73 $5.00
Estimated Differentials to
NYMEX Prices:
Oil - $/Bo -$2.75 -$2.75 -$2.75 -$2.75
Gas - $/Mcf -$0.75 -$0.75 -$0.75 -$0.75
Estimated Realized Hedging
Effects (based on expected
NYMEX prices above):
Oil - $/Bo -$3.52 -$1.82 -$4.70 $0.13
Gas - $/Mcf -$0.23 $0.01 -$0.09 $0.11
Operating Costs per Mcfe of
Projected Production:
Production expense $0.57-0.62 $0.57-0.62 $0.57-0.62 $0.60-0.65
Production taxes
(generally 7%
of O&G revenues) $0.34-0.38 $0.34-0.38 $0.28-0.33 $0.30-0.35
General and administrative $0.10-0.11 $0.10-0.11 $0.10-0.11 $0.10-0.11
Stock based compensation
(non-cash) $0.02-0.04 $0.02-0.04 $0.02-0.04 $0.06-0.07
DD&A - oil and gas $1.60-1.65 $1.60-1.65 $1.60-1.65 $1.65-1.70
Depreciation
of other assets $0.08-0.10 $0.08-0.10 $0.08-0.10 $0.08-0.10
Interest expense(a) $0.46-0.50 $0.46-0.50 $0.45-0.49 $0.44-0.48
Other Income and Expense
per Mcfe:
Marketing and other income $0.02-0.04 $0.02-0.04 $0.02-0.04 $0.02-0.04
Book Tax Rate 36 % 36 % 36 % 36 %
Equivalent Shares Outstanding:
Basic 256 mm 278 mm 253 mm 285 mm
Diluted(b) 319 mm 328 mm 312 mm 328 mm
Capital Expenditures:
Drilling, leasehold and
seismic $260-$290 $260-$290 $1,000- $1,000 -
mm mm $1,100 mm $1,100 mm
(a) Does not include gains or losses on interest rate derivatives
(SFAS 133).
(b) Does not include the potential conversion of the company's 4.125%
convertible preferred stock because the common stock price does
not exceed the conversion price of the preferred.
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
Avg. Price Assuming Open Swap
NYMEX Gain Including Gas Positions
Open Strike (Loss) Open & Production as a % of
Swaps Price from Locked in Estimated
in Of Open Locked Positions Bcf's Total Gas
Bcf's Swaps Swaps of: Production
2004:
1st Qtr 69.5 $5.94 $0.03 $5.97 70.1 99 %
2nd Qtr 62.2 $5.15 $0.00 $5.15 76.5 81 %
3rd Qtr(1) 56.3 $5.34 -$0.09 $5.25 82.5 68 %
4th Qtr(1) 35.0 $5.39 -$0.27 $5.12 87.0 40 %
Total 2004 223.0 $5.48 -$0.07 $5.41 316.1 71 %
Total
2005(1) 61.3 $5.24 -$0.50 $4.74 357.0 17 %
Total 2006
(1)(2) --- --- --- --- 375.0 ---
Total
2007(2) --- --- --- --- 395.0 ---
TOTALS
2004-2007 284.3 $5.43 -$0.29 $5.14 1,443.1 24 %
(1) Certain hedging arrangements include swaps with knockout price
ranging from $3.75 to $4.75 covering 4.6 bcf in 2004, $3.75 to $4.75
covering 9.1 bcf in 2005 and $3.75 covering 7.3 bcf in 2006.
(2) Swaps covering 32.9 bcf and 25.6 bcf have been locked for 2006 and
2007. This will result in the recognition of $22.6 million and
$11.6 million of losses in 2006 and 2007, respectively, when the
hedging arrangements settle.
(3) Not shown above are collars covering 1.5 bcf and 4.4 bcf of
production in 2004 and 2005, respectively, at a weighted average
floor and ceiling of $3.10 and $4.44. In addition, call options
covering 27.4 bcf and 7.3 bcf of production in 2004 and 2005 at
weighted average price of $6.19 and $6.00 are not included in the
table above.
The company has also entered into the following natural gas basis protection swaps:
Assuming
Gas
Production
Volume in NYMEX in Bcf's
Bcf's less: of: % Hedged
2004 157.4 0.173 316.1 50 %
2005 109.5 0.156 357.0 31 %
2006 47.5 0.155 375.0 13 %
2007 63.9 0.166 395.0 16 %
2008 64.0 0.166 415.0 15 %
2009 37.0 0.160 435.0 9 %
Totals 479.3 $0.164* 2,293.1 21 %
* weighted average
The company has entered into the following crude oil hedging arrangements:
% Hedged
Open Avg. Open Swap
Swaps NYMEX Assuming Oil Positions as %
in Strike Production in of Total Estimated
mbo's Price mbo's of: Production
Q1 - 2004 1,270 $28.58 1,465 87 %
Q2 - 2004 1,540 $30.00 1,673 92 %
Q3 - 2004(1) 1,519 $30.32 1,600 95 %
Q4 - 2004(1) 1,518 $30.10 1,600 95 %
Total 2004(1) 5,847 $29.80 6,338 92 %
Total 2005(1) 548 $31.56 6,360 9 %
(1) Certain hedging arrangements include swaps with a knockout price
ranging from $21.00 to $26.00 covering 2,240 mbo in 2004 and a
knockout price of $26.00 covering 548 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/
Company News On-Call: http://www.prnewswire.com/comp/138877.html
