Press Releases
OKLAHOMA CITY, Feb. 23 /PRNewswire-FirstCall/ -- Chesapeake Energy Corporation (NYSE: CHK) today reported its financial and operating results for the fourth quarter of 2003 and for the full-year 2003. For the fourth quarter, Chesapeake generated net income available to common shareholders of $62.4 million ($0.25 per fully diluted common share), operating cash flow of $262.4 million (defined as cash flow from operating activities before changes in assets and liabilities) and ebitda of $257.8 million (defined as income before income taxes, interest expense, and depreciation, depletion and amortization expense) on revenue of $456.7 million.
For the full-year 2003, Chesapeake generated net income available to common shareholders of $290.5 million ($1.21 per fully diluted common share), operating cash flow of $903.9 million (defined as cash flow from operating activities before changes in assets and liabilities) and ebitda of $1,041.6 million (defined as income before income taxes and cumulative effect of accounting change, interest expense, and depreciation, depletion and amortization expense) on revenue of $1,717.4 million.
The company's fourth quarter and full-year 2003 net income available to common shareholders and ebitda include various items that are typically not included in published estimates of the company's financial results by certain securities analysts. Such items and their after-tax effects on fourth quarter and full-year reported results are described as follows:
-- an unrealized mark-to-market loss of $15.1 million for the fourth
quarter and a $2.5 million gain for the full-year resulting from the
company's oil and natural gas and interest rate hedging programs,
-- a $12.9 million loss from the early extinguishment of certain
Chesapeake debt securities,
-- a $3.3 million loss for the fourth quarter and $4.0 million loss for
the full-year related to the settlement of certain royalty owner
litigation, and
-- a $1.2 million loss from the final impairment of the company's
investment in the securities of Seven Seas Petroleum Inc.
Without these items, Chesapeake's net income to common shareholders in the fourth quarter of 2003 would have been $94.9 million ($0.37 per fully diluted common share) and ebitda would have been $309.1 million. Without these items, Chesapeake's net income to common shareholders for the full year 2003 would have been $306.1 million ($1.27 per fully diluted common share) and ebitda would have been $1,060.2 million. The foregoing items do not affect the calculation of operating cash flow.
Production and Revenue Realizations Rise to Record Levels
Production for the fourth quarter of 2003 was 73.3 billion cubic feet of natural gas equivalent (bcfe), an increase of 23.8 bcfe, or 48%, over the 49.5 bcfe produced in the 2002 fourth quarter and an increase of 2.3 bcfe, or 3.3%, over the 71.0 produced in the 2003 third quarter. The 2003 fourth quarter's 73.3 bcfe of production was comprised of 66.3 billion cubic feet of natural gas (bcf) (90% on a natural gas equivalent basis) and 1.2 million barrels of oil and natural gas liquids (mmbo) (10% on a natural gas equivalent basis). Chesapeake's average daily production rate for the quarter was 797 million cubic feet of natural gas equivalent production (mmcfe), consisting of 721 mmcf of gas and 12,663 barrels of oil and natural gas liquids.
Oil and natural gas production for the full-year 2003 was 268 bcfe, an increase of 87 bcfe, or 48%, over the 181 bcfe produced in 2002. Of this 87 bcfe in year-over-year production growth, 36 bcfe was generated from internally generated organic drillbit growth while 51 bcfe was generated from acquisitions. This makes the company's organic growth rate during 2003 20%, well above the company's forecasted organic growth rate of 5% and among the top 3 organic growth performances reported by public mid- and large-cap E&P companies.
Chesapeake has increased its production for 14 consecutive years, one of the best track records in the industry. In addition, the 2003 fourth quarter was Chesapeake's tenth consecutive quarter of sequential production growth. During the past ten quarters, Chesapeake's production has increased 87%, for an average sequential quarterly growth rate of 6.5% and an annualized growth rate of 28.1%.
Average prices realized during the 2003 fourth quarter (including realized gains or losses from oil and gas derivatives, but excluding unrealized gains or losses on such derivatives) were $23.76 per barrel of oil (bo) and $5.15 per thousand cubic feet of natural gas (mcf), for a realized gas equivalent price of $5.03 per thousand cubic feet of natural gas equivalent (mcfe). Chesapeake's realized pricing differentials to NYMEX during the quarter averaged a negative $2.42 per bo and a negative $0.47 per mcf. Realized gains or losses from hedging activities generated a $2.69 loss per bo and a $0.90 gain per mcf, for a 2003 fourth quarter realized hedging gain of $56.6 million.
Average prices realized during the full-year 2003 (including realized gains or losses from oil and gas derivatives, but excluding unrealized gains or losses on such derivatives) were $25.85 per bo and $4.85 per mcf, for a realized gas equivalent price of $4.79 per mcfe. Chesapeake's realized pricing differentials to NYMEX during the year averaged a negative $2.25 per bo and a negative $0.54 per mcf. Realized losses from hedging activities generated a $2.58 loss per bo and a $0.02 loss per mcf, for a 2003 full-year realized hedging loss of $17.4 million.
Key Operational and Financial Statistics for the 2003 Fourth Quarter and for
the Full-Year 2003
The table below summarizes Chesapeake's key statistics during the 2003 fourth quarter and compares them to the 2003 third quarter and the 2002 fourth quarter:
Three Months Ended:
12/31/03 9/30/03 12/31/02
Average daily production (in mmcfe) 797 772 538
Gas as % of total production 90 90 89
Natural gas production (in bcf) 66.3 63.7 43.9
Average realized gas price ($/mcf) (A) 5.15 4.92 4.00
Oil production (in mbbls) 1,165 1,216 941
Average realized oil price ($/bo) (A) 23.76 26.20 24.67
Natural gas equivalent production
(in bcfe) 73.3 71.0 49.5
Gas equivalent realized price
($/mcfe) (A) 5.03 4.86 4.01
General and administrative costs
($/mcfe) .10 .07 .11
Production taxes ($/mcfe) .28 .30 .21
Lease operating expenses ($/mcfe) .49 .51 .54
Interest expense ($/mcfe) (A) .51 .53 .63
DD&A of oil and gas properties ($/mcfe) 1.41 1.38 1.28
Operating cash flow ($ in millions) (B) 262.4 247.7 128.2
Operating cash flow ($/mcfe) 3.58 3.49 2.59
Ebitda ($ in millions) (C) 257.8 285.3 145.0
Ebitda ($/mcfe) 3.52 4.02 2.93
Net income to common shareholders
($ in millions) 62.4 81.9 23.7
(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) defined as cash flow provided by operating activities before changes
in assets and liabilities
(C) defined as income before income taxes, interest expense, and
depreciation, depletion and amortization expense
In addition, the table below summarizes Chesapeake's key statistics during 2003 and compares them to the prior two years' results:
Year Ended:
12/31/03 12/31/02 12/31/01
Average daily production (in mmcfe) 735 497 442
Gas as % of total production 90 89 89
Natural gas production (in bcf) 240.4 160.7 144.2
Average realized gas price ($/mcf) (A) 4.85 3.54 4.56
Oil production (in mbbls) 4,665 3,466 2,880
Average realized oil price ($/bbl) (A) 25.85 25.22 26.92
Natural gas equivalent production
(in bcfe) 268.4 181.5 161.5
Gas equivalent realized price
($/mcfe) (A) 4.79 3.61 4.56
General and administrative costs
($/mcfe) .09 .10 .09
Production taxes ($/mcfe) .29 .17 .20
Lease operating expenses ($/mcfe) .51 .54 .47
Interest expense ($/mcfe) (A) .55 .61 .61
DD&A of oil and gas properties ($/mcfe) 1.38 1.22 1.07
Operating cash flow ($ in millions) (B) 903.9 412.5 518.6
Operating cash flow ($/mcfe) 3.37 2.27 3.21
Ebitda ($ in millions) (C) 1,041.6 414.4 641.6
Ebitda ($/mcfe) 3.88 2.28 3.97
Net income to common shareholders
($ in millions) 290.5 30.2 215.4
(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) defined as cash flow provided by operating activities before changes
in assets and liabilities
(C) defined as income before income taxes and cumulative effect of
accounting change, interest expense, and depreciation, depletion and
amortization expense
Chesapeake Reports Excellent 2003 Reserve Replacement and Finding Costs;
Proved Reserves Reach Record Level of 3.5 Tcfe (Pro Forma for January 2004
Transactions)
Chesapeake began 2003 with estimated proved reserves of 2,205 bcfe and ended the year with 3,169 bcfe, an increase of 964 bcfe, or 44%. Taking into account production of 268 bcfe, reserve replacement during the year was 1,232 bcfe, or 459%, at a finding and acquisition cost of $1.36 per mcfe.
Of the 1,232 bcfe of proved reserve additions, acquisitions added 805 bcfe at a cost of $1.38 per mcfe and drilling, including positive revisions to previous estimates, added 438 bcfe for a reserve replacement rate from drilling of 167% at a cost of $1.32 per mcfe. Proved reserves sold during the year totaled 11 bcfe at a price of $2.07 per mcfe. A complete reconciliation of finding and acquisition cost information and a roll forward of proved reserves is presented in the tables following this release.
During 2003, the company drilled 442 gross operated wells (352 net) and participated in another 641 gross wells (104 net) operated by other companies. Chesapeake's drilling costs were $438 million for operated wells and $140 million for non-operated wells. The company's success rate was 96% for operated wells and 95% for non-operated wells.
Of the company's estimated proved reserves at year-end 2003, 74% were proved developed compared to 74% in 2002 and 71% in 2001. In addition, 74% of this year's estimated proved reserves were prepared by independent third-party reservoir engineers (primarily Ryder Scott Company Petroleum Consultants and Netherland, Sewell & Associates, Inc.) compared to 73% in 2002 and 71% in 2001.
As of December 31, 2003, the company's estimated future net cash flows discounted at 10% before taxes (PV-10) were $7.3 billion using field differential adjusted prices of $30.22 per bo (based on a NYMEX year-end price of $32.47 per bo) and $5.68 per mcf (based on a NYMEX year-end price of $5.97 per mcf). Last year's PV-10 was $3.72 billion using field differential adjusted prices of $30.18 per bo (based on a NYMEX year-end price of $31.25 per bo) and $4.28 per mcf (based on a NYMEX year-end price of $4.60 per mcf).
The foregoing year-end amounts do not include the effects of several acquisitions closed in January 2004. Pro forma for these acquisitions, the company's proved reserves at year-end 2003 were 3,474 bcfe and had a PV-10 value of $7.9 billion.
Significant Balance Sheet Improvement Continued in 2003
During the year, Chesapeake continued its consistent focus on improving the strength of its balance sheet. At the beginning of the year, the company's debt as a percentage of total capitalization was 65% and debt per proved mcfe was $0.75 per mcfe. By year-end 2003 (pro forma for the reserves acquired in January 2004 and the related financings and debt exchanges completed in January 2004), the company's debt as a percentage of total capitalization had decreased to 53% and debt per proved mcfe had decreased to $0.65 per mcfe, reductions of 18% and 13%, respectively. Key goals of management are to reduce debt to below 50% of total capitalization and debt per mcfe of proved reserves to below $0.60.
Additionally, through a series of recently completed debt exchanges, Chesapeake has extended the average maturity of its long-term debt to over nine years and reduced its average interest rate to 7.7%. The company's secured credit facility is currently rated as investment grade by at least one rating agency and the company believes its present business strategy will lead to an investment grade credit rating for its unsecured debt in the years ahead.
Chesapeake Updates 2004 Production Forecasts and Hedging Information
Chesapeake's updated 2004 first quarter and full-year 2004 forecasts are attached to this release in an Outlook dated February 23, 2004 labeled Schedule "A". This Outlook has been changed from the Outlook dated December 22, 2003 (attached as Schedule "B" for investors' convenience) to reflect minor changes from the Outlook dated December 22. In addition, investors should note that 75 mmcfe per day of production acquired in January 2004 will not be recognized until February 1, 2004 rather than on the previously assumed effective date of January 1, 2004. As a consequence, Chesapeake expects that its production for the first quarter of 2004 will be at the lower end of the December 22 forecast of 78-79 bcfe.
Chesapeake's average daily production in 2004 is expected to exceed 2003's production by approximately 155 mmcfe, or 21%, first quarter 2004 average daily production is expected to exceed 2003's first quarter production by approximately 232 mmcfe, or 37%, and first quarter 2004 average daily production is expected to exceed 2003's fourth quarter production by approximately 66 mmcfe, or 8%.
The following table details Chesapeake's current hedging positions. These hedging positions have not changed from the company's Outlook dated December 22, 2003:
Hedged Positions as of February 23, 2004
Oil Natural Gas
Quarter or Year % Hedged $ NYMEX % Hedged $ NYMEX
2004 1Q 88% $28.58 100% $5.97
2004 2Q 88% $28.86 73% $4.97
2004 3Q 72% $28.75 58% $4.89
2004 4Q 63% $28.46 47% $5.08
2004 Total 78% $28.68 69% $5.32
2005 --- --- 27% $5.04
2006 --- --- 11% $4.88
2007 --- --- 8% $4.76
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.
Management Summary
Aubrey K. McClendon, Chesapeake's Chief Executive Officer, commented, "By all measures, Chesapeake generated exceptionally strong results for its shareholders in 2003. Our success in 2003 resulted from a series of key management decisions made during the past six years that have positioned the company to be a prime beneficiary of today's strong natural gas markets. These decisions included favoring gas over oil, establishing regional dominance in its operating areas, delivering value-added growth through a balance of drilling and acquisitions and managing risk through opportunistic oil and natural gas hedging.
"During these six years of exceptional achievement, Chesapeake has become the largest producer of natural gas in the Mid-Continent, among the six largest independent producers of natural gas in the U.S. and one of the most profitable producers of natural gas in the industry per unit of production. We believe the combination of our product and geographic strategies, our value-added risk management strategy, our balanced acquisition and drilling programs, our high quality assets and our low operating costs will enable Chesapeake to continue delivering one of the industry's best track records of value creation in the years to come."
Conference Call Information
A conference call has been scheduled for Tuesday morning, February 24, 2004 at 9:00 a.m. EST to discuss this earnings release. The telephone number to access the conference call is 913.981.5533. For those unable to participate in the conference call, a replay will be available from 12:00 p.m. EST on Tuesday, February 24, 2004 through midnight EST on Friday, March 12, 2004. The number to access the conference call replay is 719.457.0820 and the passcode is 593812. The conference call will also be simulcast live on the Internet and can be accessed at 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. 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. Factors that could cause actual results to differ materially from expected results are described in the risk factors appearing in our Prospectus Supplement and Prospectus filed together under Rule 424(b)(2) of the Securities Act of 1933 on January 9, 2004 and subsequent filings with the Securities and Exchange Commission. They include the volatility of oil and gas prices; adverse effects our substantial indebtedness could have on our operations and future growth; our ability to compete effectively against strong independent oil and gas companies and majors; the cost and availability of drilling and production services; possible financial losses 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; our ability to replace reserves; the availability of capital; changes in interest rates; and drilling and operating risks. We caution you not to place undue reliance on these forward-looking statements, which speak only as of the date of this press release, and we undertake no obligation to update this information.
Chesapeake Energy Corporation is one of the six largest independent U.S. natural gas producers. 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 and onshore Texas Gulf Coast regions of the United States. The company's Internet address is www.chkenergy.com .
CHESAPEAKE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
($ in 000's, except per share data)
(unaudited)
THREE MONTHS ENDED: December 31, 2003 December 31, 2002
$ $/mcfe $ $/mcfe
REVENUES:
Oil and gas sales 345,697 4.72 200,377 4.05
Oil and gas marketing
sales 111,044 1.51 57,981 1.17
Total Revenues 456,741 6.23 258,358 5.22
OPERATING COSTS:
Production expenses 35,919 0.49 26,939 0.55
Production taxes 20,557 0.28 10,167 0.21
General and
administrative 7,501 0.10 5,688 0.11
Provision for legal
settlements 5,400 0.07 --- ---
Oil and gas marketing
expenses 108,224 1.48 56,900 1.15
Oil and gas
depreciation, depletion,
and amortization 103,334 1.41 63,458 1.28
Depreciation and
amortization of other
assets 4,146 0.06 3,520 0.07
Total Operating Costs 285,081 3.89 166,672 3.37
INCOME FROM OPERATIONS 171,660 2.34 91,686 1.85
OTHER INCOME (EXPENSE):
Interest and other
income 1,471 0.02 (3) ---
Interest expense (38,465) (0.52) (34,252) (0.69)
Loss on investment
in Seven Seas (2,015) (0.03) (12,431) (0.25)
Loss on repurchases
of Chesapeake debt (20,759) (0.28) (1,273) (0.03)
Total Other Income
(Expense) (59,768) (0.81) (47,959) (0.97)
Income Before Income
Taxes 111,892 1.53 43,727 0.88
Income Tax Expense:
Current 4,670 0.06 --- ---
Deferred 37,849 0.52 17,488 0.35
Total Income Tax
Expense 42,519 0.58 17,488 0.35
NET INCOME 69,373 0.95 26,239 0.53
Preferred Stock
Dividends (6,985) (0.10) (2,529) (0.05)
NET INCOME AVAILABLE
TO COMMON SHAREHOLDERS 62,388 0.85 23,710 0.48
EARNINGS PER COMMON SHARE:
Basic $0.29 $0.14
Assuming dilution $0.25 $0.13
WEIGHTED AVERAGE COMMON
AND COMMON EQUIVALENT
SHARES OUTSTANDING
(in 000's)
Basic 216,571 170,118
Assuming dilution 273,169 195,733
CHESAPEAKE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
($ in 000's, except per share data)
(unaudited)
TWELVE MONTHS ENDED: December 31, 2003 December 31, 2002
$ $/mcfe $ $/mcfe
REVENUES:
Oil and gas sales 1,296,822 4.83 568,187 3.13
Oil and gas marketing
sales 420,610 1.57 170,315 0.94
Total Revenues 1,717,432 6.40 738,502 4.07
OPERATING COSTS:
Production expenses 137,583 0.51 98,191 0.54
Production taxes 77,893 0.29 30,101 0.17
General and
administrative 23,753 0.09 17,618 0.10
Provision for legal
settlements 6,402 0.02 --- ---
Oil and gas marketing
expenses 410,288 1.53 165,736 0.91
Oil and gas
depreciation, depletion,
and amortization 369,465 1.38 221,189 1.22
Depreciation and
amortization of
other assets 16,793 0.06 14,009 0.07
Total Operating
Costs 1,042,177 3.88 546,844 3.01
INCOME FROM OPERATIONS 675,255 2.52 191,658 1.06
OTHER INCOME (EXPENSE):
Interest and other
income 2,827 0.01 7,340 0.04
Interest expense (154,356) (0.57) (112,031) (0.62)
Loss on investment
in Seven Seas (2,015) (0.01) (17,201) (0.10)
Loss on repurchases
of Chesapeake debt (20,759) (0.08) (2,626) (0.01)
Total Other Income
(Expense) (174,303) (0.65) (124,518) (0.69)
Income Before Income
Taxes and Cumulative
Effect of Accounting
Change 500,952 1.87 67,140 0.37
Income Tax Expense:
Current 5,000 0.02 --- ---
Deferred 185,360 0.69 26,854 0.15
Total Income Tax
Expense 190,360 0.71 26,854 0.15
NET INCOME BEFORE
CUMULATIVE EFFECT
OF ACCOUNTING CHANGE 310,592 1.16 40,286 0.22
Cumulative Effect of
Accounting Change,
Net of Tax 2,389 0.01 --- ---
NET INCOME 312,981 1.17 40,286 0.22
Preferred Stock
Dividends (22,469) (0.09) (10,117) (0.05)
NET INCOME AVAILABLE
TO COMMON SHAREHOLDERS 290,512 1.08 30,169 0.17
EARNINGS PER COMMON SHARE:
Basic
Income Before
Cumulative Effect of
Accounting Change $1.36 $0.18
Cumulative Effect of
Accounting Change 0.02 ---
Net Income $1.38 $0.18
Assuming dilution
Income Before
Cumulative Effect of
Accounting Change $1.20 $0.17
Cumulative Effect of
Accounting Change 0.01 ---
Net Income $1.21 $0.17
WEIGHTED AVERAGE COMMON
AND COMMON EQUIVALENT
SHARES OUTSTANDING
(in 000's):
Basic 211,203 166,910
Assuming dilution 258,567 172,714
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(in 000's)
(unaudited)
December 31, December 31,
2003 2002
Cash $ 40,581 $ 247,637
Other current assets 301,823 187,680
TOTAL CURRENT ASSETS 342,404 435,317
Property and equipment (net) 4,133,117 2,389,884
Deferred tax asset --- 2,071
Other assets 96,770 48,336
TOTAL ASSETS $ 4,572,291 $ 2,875,608
Current liabilities $ 513,156 $ 265,552
Long term debt 2,057,713 1,651,198
Long term liabilities 77,586 50,983
Deferred tax liability 191,026 ---
TOTAL LIABILITIES 2,839,481 1,967,733
STOCKHOLDERS' EQUITY 1,732,810 907,875
TOTAL LIABILITIES & STOCKHOLDERS' EQUITY $ 4,572,291 $ 2,875,608
COMMON SHARES OUTSTANDING 216,784 190,144
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF 2003 FINDING COSTS
($ in 000's, except per unit amounts)
(unaudited)
Reserves
Cost (in mmcfe) Per Unit
Exploration and development costs (A) $577,779 437,488 $ 1.32
Acquisition of proved properties 1,110,077 805,041 1.38
Subtotal $1,687,856 1,242,529 $ 1.36
Acquisition of unproved properties $ 198,394 --- ---
Divestitures (22,156) (10,723) 2.07
Leasehold acquisition costs 84,984 --- ---
Geological and geophysical costs 42,736 --- ---
Asset retirement obligation and other 62,731 --- ---
Total $2,054,545 1,231,806 $ 1.67
(A) Reserves include revisions to previous estimates
CHESAPEAKE ENERGY CORPORATION
ROLLFORWARD OF RESERVES
(unaudited)
Mmcfe
Beginning balance, 12/31/02 2,205,125
Production (268,356)
Acquisitions 805,041
Divestitures (10,723)
Revisions 56,354
Extensions and discoveries 381,134
Ending balance, 12/31/03 3,168,575
Reserve replacement 1,231,806
Reserve replacement rate 459%
CHESAPEAKE ENERGY CORPORATION
SUPPLEMENTAL DATA - OIL & GAS SALES AND INTEREST EXPENSE
Three Months Ended Twelve Months Ended
December 31, December 31,
2003 2002 2003 2002
Oil and Gas Sales
($ in thousands):
Oil sales $ 30,819 $ 25,478 $ 132,630 $ 88,495
Oil derivatives
- realized gains
(losses) (3,134) (2,268) (12,058) (1,092)
Oil derivatives
- unrealized gains
(losses) (8,447) 811 (9,440) (7,369)
Total oil sales $ 19,238 $ 24,021 $ 111,132 $ 80,034
Gas sales $281,452 $161,086 $1,171,050 $ 470,913
Gas derivatives
- realized gains
(losses) 59,697 14,165 (5,331) 97,138
Gas derivatives
- unrealized gains
(losses) (14,690) 1,105 19,971 (79,898)
Total gas sales $326,459 $176,356 $1,185,690 $ 488,153
Total oil and gas
sales $345,697 $200,377 $1,296,822 $ 568,187
Average Sales Price
(excluding gains
(losses) on derivatives):
Oil ($ per bbl) $ 26.45 $ 27.08 $ 28.43 $ 25.53
Gas ($ per mcf) $ 4.25 $ 3.67 $ 4.87 $ 2.93
Gas equivalent
($ per mcfe) $ 4.26 $ 3.77 $ 4.86 $ 3.08
Average Sales Price
(excluding unrealized
gains (losses) on
derivatives):
Oil ($ per bbl) $ 23.76 $ 24.67 $ 25.85 $ 25.22
Gas ($ per mcf) $ 5.15 $ 4.00 $ 4.85 $ 3.54
Gas equivalent
($ per mcfe) $ 5.03 $ 4.01 $ 4.79 $ 3.61
Interest Expense
($ in thousands):
Interest $(38,665) $(32,079) $ (151,676) $(114,695)
Derivatives
- realized gains
(losses) 1,406 765 3,859 3,415
Derivatives
- unrealized gains
(losses) (1,206) (2,938) (6,539) (751)
Total Interest
Expense $(38,465) $(34,252) $ (154,356) $(112,031)
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED CASH FLOW DATA
(in 000's)
(unaudited)
THREE MONTHS ENDED: December 31, December 31,
2003 2002
Cash provided by operating activities $ 292,085 $ 78,873
Cash (used in) investing activities $(476,449) $(162,562)
Cash provided by financing activities $ 186,467 $ 305,948
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED CASH FLOW DATA
(in 000's)
(unaudited)
TWELVE MONTHS ENDED: December 31, December 31,
2003 2002
Cash provided by operating activities $ 945,602 $ 432,531
Cash (used in) investing activities $(2,077,217) $(779,745)
Cash provided by financing activities $ 924,559 $ 477,257
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF CERTAIN FINANCIAL MEASURES
(in 000's)
(unaudited)
THREE MONTHS ENDED: December 31, December 31,
2003 2002
CASH PROVIDED BY OPERATING ACTIVITIES $292,085 $ 78,873
Adjustments:
Changes in assets and liabilities (29,647) 49,345
OPERATING CASH FLOW* $262,438 $128,218
* 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.
THREE MONTHS ENDED: December 31, December 31,
2003 2002
Net income $ 69,373 $ 26,239
Deferred income tax expense 42,519 17,488
Interest expense 38,465 34,252
Depreciation and amortization of other assets 4,146 3,520
Oil and gas depreciation, depletion and
amortization 103,334 63,458
EBITDA** $257,837 $144,957
** 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 banks under our bank credit facilities and is used in our financial covenants under our bank credit facilities and our indentures governing our senior notes. 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: December 31, December 31,
2003 2002
CASH PROVIDED BY OPERATING ACTIVITIES $292,085 $ 78,873
Changes in assets and liabilities (29,647) 49,345
Interest expense 38,465 34,252
Unrealized gains (losses) on oil and gas
derivatives (23,137) 1,916
Other non-cash items (19,929) (19,429)
EBITDA $257,837 $144,957
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF CERTAIN FINANCIAL MEASURES
(in 000's)
(unaudited)
TWELVE MONTHS ENDED: December 31, December 31,
2003 2002
CASH PROVIDED BY OPERATING ACTIVITIES $945,602 $432,531
Adjustments:
Changes in assets and liabilities (41,673) (20,014)
OPERATING CASH FLOW* $903,929 $412,517
* 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.
TWELVE MONTHS ENDED: December 31, December 31,
2003 2002
Net income before cumulative effect of
accounting change $ 310,592 $ 40,286
Deferred income tax expense 190,360 26,854
Interest expense 154,356 112,031
Depreciation and amortization of other assets 16,793 14,009
Oil and gas depreciation, depletion and
amortization 369,465 221,189
EBITDA** $1,041,566 $414,369
** 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 banks under our bank credit facilities and is used in our financial covenants under our bank credit facilities and our indentures governing our senior notes. 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:
TWELVE MONTHS ENDED: December 31, December 31,
2003 2002
CASH PROVIDED BY OPERATING ACTIVITIES $945,602 $432,531
Changes in assets and liabilities (41,673) (20,014)
Interest expense 154,356 112,031
Unrealized gains (losses) on oil and gas
derivatives 10,531 (87,267)
Other non-cash items (27,250) (22,912)
EBITDA $1,041,566 $414,369
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED EARNINGS & ADJUSTED EBITDA
($ In 000'S, except per share amounts)
Three Months Twelve Months
Ended Ended
December 31, December 31,
2003 2003
Net income to common shareholders $ 62,388 $ 290,512
Adjustments, net of tax:
Unrealized (gains) losses from hedging 15,092 (2,475)
Loss on repurchases of debt 12,871 12,871
Provision for legal settlements 3,348 3,969
Loss on investment in Seven Seas 1,249 1,249
Adjusted earnings* $ 94,948 $ 306,126
Adjusted earnings per share assuming dilution $0.37 $1.27
EBITDA $257,837 $1,041,566
Adjustments, before tax:
Unrealized (gains) losses from hedging 23,137 (10,531)
Loss on repurchases of debt 20,759 20,759
Provision for legal settlements 5,400 6,402
Loss on investment in Seven Seas 2,015 2,015
Adjusted EBITDA* $309,148 $1,060,211
*Adjusted earnings 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 February 23, 2004
Quarter Ending March 31, 2004; Year Ending December 31, 2004.
We have adopted a policy of periodically providing investors with guidance on certain factors that affect our future financial performance. As of February 23, 2004, we are using the following key assumptions in our projections for the first quarter of 2004 and the full-year 2004.
The primary changes from our December 22, 2003 guidance are explained as
follows. We have included our expectations for future NYMEX oil and gas
prices to illustrate hedging effects only. They are not a forecast of 2004
oil and natural gas prices.
Quarter Ending Year Ending
March 31, December 31
2004 2004
Estimated Production:
Oil - Mbo 1,450 5,800
Gas - Bcf 69 - 70 288 - 294
Gas Equivalent - Bcfe 78 - 79 323 - 329
Daily gas equivalent midpoint - in Mmcfe 863 890
NYMEX Prices (for calculation of realized
hedging effects only):
Oil - $/Bo $28.08 $25.77
Gas - $/Mcf $5.47 $4.74
Estimated Differentials to NYMEX Prices:
Oil - $/Bo -$2.50 -$2.50
Gas - $/Mcf -$0.60 -$0.60
Estimated Realized Hedging Effects
(based on expected NYMEX prices above):
Oil - $/Bo +$0.50 +$2.23
Gas - $/Mcf +$0.66 +$0.44
Operating Costs per Mcfe of Projected
Production:
Production expense $0.55 - 0.60 $0.55 - 0.60
Production taxes (generally 7%
of O&G revenues) $0.32 - 0.34 $0.28 - 0.32
General and administrative $0.10 - 0.11 $0.10 - 0.11
DD&A - oil and gas $1.48 - 1.52 $1.50 - 1.55
Depreciation of other assets $0.07 - 0.09 $0.07 - 0.09
Interest expense (A) $0.49 - 0.53 $0.45 - 0.50
Other Income and Expense per Mcfe:
Marketing and other income $0.02 - 0.04 $0.02 - 0.04
Book Tax Rate 38% 38%
Equivalent Shares Outstanding:
Basic 240,000 m 247,000 m
Diluted 302,000 m 304,000 m
Capital Expenditures:
Drilling, Land and Seismic $175 - $200 mm $750-800 mm
(A) Does not include gains or losses on interest rate derivatives
(SFAS 133)
Commodity Hedging Activities
Periodically the Company utilizes hedging strategies to hedge the price of a portion of its future oil and gas production. These strategies include:
(i) For swap instruments, we receive a fixed price for the hedged
commodity and pay a floating market price, as defined in each
instrument, to the counterparty. The fixed-price payment and the
floating-price payment are netted, resulting in a net amount due to
or from the counterparty.
(ii) For cap-swaps, Chesapeake receives a fixed price and pays a
floating market price. The fixed price received by Chesapeake
includes a premium in exchange for a "cap" limiting the
counterparty's exposure. In other words, there is no limit to
Chesapeake's exposure but there is a limit to the downside exposure
of the counterparty.
(iii) Basis protection swaps are arrangements that guarantee a price
differential of oil or gas from a specified delivery point.
Chesapeake receives a payment from the counterparty if the price
differential is greater than the stated terms of the contract and
pays the counterparty if the price differential is less than the
stated terms of the contract.
Commodity markets are volatile, and as a result, Chesapeake's hedging activity is dynamic. As market conditions warrant, the Company may elect to settle a hedging transaction prior to its scheduled maturity date and, as a result, lock in the gain or loss on the transaction.
Chesapeake enters into oil and natural gas derivative transactions in order to mitigate a portion of its exposure to adverse market changes in oil and natural gas prices. Accordingly, associated gains or loses from the derivative transactions are reflected as adjustments to oil and gas sales. All realized gains and losses from oil and natural gas derivatives are included in oil and gas sales in the month of related production. Pursuant to SFAS 133, certain derivatives do not qualify for designation as cash flow hedges. Changes in the fair value of these non-qualifying derivatives that occur prior to their maturity (i.e. because of temporary fluctuations in value) are reported currently in the consolidated statement of operations as unrealized gains (losses) within oil and gas sales.
Following provisions of SFAS 133, changes in the fair value of derivative instruments designated as cash flow hedges, to the extent effective in offsetting cash flows attributable to hedged risk, are recorded in other comprehensive income until the hedged item is recognized in earnings. Any change in fair value resulting from ineffectiveness is recognized currently in oil and natural gas sales.
The Company currently has in place the following natural gas swaps:
% Hedged
Avg. NYMEX Open Swap
Avg. NYMEX Price Assuming Positions
Strike Including Gas as a % of
Price Gain from Open & Production Estimated
Open Swaps Of Open Locked Locked in Bcf's Total Gas
in Bcf's Swaps Swaps Positions of: Production
2004:
1st Qtr 69.5 $5.94 $0.03 $5.97 69.5 100%
2nd Qtr 52.8 $4.97 $0.00 $4.97 72.0 73%
3rd Qtr 43.2 $4.89 $0.00 $4.89 74.0 58%
4th Qtr 35.0 $5.08 $0.00 $5.08 75.0 47%
Total 2004 200.5 $5.31 $0.01 $5.32 290.5 69%
Total 2005 82.1 $5.04 $0.00 $5.04 300.0 27%
Total 2006 32.9 $4.88 $0.00 $4.88 310.0 11%
Total 2007 25.6 $4.76 $0.00 $4.76 320.0 8%
TOTALS
2004-2007 341.1 $5.16 $0.01 $5.17 1,220.5 28%
Chesapeake has also entered into the following natural gas basis
protection swaps:
Assuming Gas
Annual Production
Volume in Bcf's NYMEX less: in Bcf's
of: % Hedged
2004 157.4 0.173 290.5 54%
2005 109.5 0.156 300.0 37%
2006 47.5 0.155 310.0 15%
2007 63.9 0.166 320.0 20%
2008 64.0 0.166 330.0 19%
2009 37.0 0.160 340.0 11%
Totals 479.3 $0.164* 1,890.5 25%
* weighted average
The Company has entered into the following crude oil hedging arrangements:
% Hedged
Open Swap
Assuming Oil Positions as %
Avg. Production of Total
Open Swaps NYMEX in Mmbo's Estimated
in Mmbo's Strike Price of: Production
Q1 - 2004* 1,270 $28.58 1,450 88%
Q2 - 2004* 1,282 $28.86 1,450 88%
Q3 - 2004* 1,044 $28.75 1,450 72%
Q4 - 2004* 920 $28.46 1,450 63%
Total 2004 4,516 $28.68 5,800 78%
*Swaps with a knockout price of $21.00, with the exception of 2,000 bopd in 2004 with a knockout price of $24.00, with an additional 1,000 bopd in Q2 2004 at $24, 1,000 bopd in Q3 and Q4 2004 with a knockout price of $23.00, 2,000 bopd for 1/04 and 3-8/04 at a knockout price of $22.00, and 3,000 bopd in 2/04 at a knockout price of $22.00.
SCHEDULE "B"
CHESAPEAKE'S PREVIOUS OUTLOOK AS OF DECEMBER 22, 2003
(PROVIDED FOR REFERENCE ONLY)
NOW SUPERSEDED BY OUTLOOK AS OF FEBRUARY 23, 2004
Quarter Ending March 31, 2004; Year Ending December 31, 2004.
We have adopted a policy of periodically providing investors with guidance on certain factors that affect our future financial performance. As of December 22, 2003, we are using the following key assumptions in our projections for the first quarter of 2004 and the full-year 2004.
The primary changes from our November 12, 2003 guidance are explained as follows:
1) We have increased our production forecasts to reflect the three
acquisitions announced today.
2) We have updated the projected effects from changes in our hedging
positions.
3) We have included our expectations for future NYMEX oil and gas prices
to illustrate hedging effects only. They are not a forecast of 2004
oil and natural gas prices.
4) We have included the pro forma effects of additional equity and debt
issuance to fund the acquisitions announced today.
Quarter Ending Year Ending
March 31, December 31,
2004 2004
Estimated Production:
Oil - Mbo 1,450 5,800
Gas - Bcf 69 - 70 288 - 294
Gas Equivalent - Bcfe 78 - 79 323 - 329
Daily gas equivalent midpoint - in Mmcfe 863 890
NYMEX Prices (for calculation of realized
hedging effects only):
Oil - $/Bo $25.00 $25.00
Gas - $/Mcf $4.50 $4.50
Estimated Differentials to NYMEX Prices:
Oil - $/Bo -$2.50 -$2.50
Gas - $/Mcf -$0.60 -$0.60
Estimated Realized Hedging Effects
(based on expected NYMEX prices above):
Oil - $/Bo +$3.13 +$2.72
Gas - $/Mcf +$1.48 +$0.68
Operating Costs per Mcfe of Projected
Production:
Production expense $0.55 - 0.60 $0.55 - 0.60
Production taxes (generally 7% of
O&G revenues) $0.25 - 0.29 $0.25 - 0.29
General and administrative $0.10 - 0.11 $0.10 - 0.11
DD&A - oil and gas $1.42 - 1.46 $1.42 - 1.46
Depreciation of other assets $0.07 - 0.09 $0.07 - 0.09
Interest expense (A) $0.49 - 0.53 $0.49 - 0.53
Other Income and Expense per Mcfe: (B)
Marketing and other income $0.02 - 0.04 $0.02 - 0.04
Book Tax Rate 38% 38%
Equivalent Shares Outstanding:
Basic 240,000 m 244,000 m
Diluted 300,000 m 302,000 m
Capital Expenditures:
Drilling, Land and Seismic $175 - $195 mm $725 - $775 mm
(A) Does not include gains or losses on interest rate derivatives
(SFAS 133).
(B) Does not include the cumulative effect of the adoption of SFAS 143 as
of January 1, 2003.
Commodity Hedging Activities
Periodically the Company utilizes hedging strategies to hedge the price of a portion of its future oil and gas production. These strategies include:
(i) For swap instruments, we receive a fixed price for the hedged
commodity and pay a floating market price, as defined in each
instrument, to the counterparty. The fixed-price payment and the
floating-price payment are netted, resulting in a net amount due
to or from the counterparty.
(ii) For cap-swaps, Chesapeake receives a fixed price and pays a
floating market price. The fixed price received by Chesapeake
includes a premium in exchange for a "cap" limiting the
counterparty's exposure. In other words, there is no limit to
Chesapeake's exposure but there is a limit to the downside
exposure of the counterparty.
(iii) Basis protection swaps are arrangements that guarantee a price
differential of oil or gas from a specified delivery point.
Chesapeake receives a payment from the counterparty if the price
differential is greater than the stated terms of the contract and
pays the counterparty if the price differential is less than the
stated terms of the contract.
Commodity markets are volatile, and as a result, Chesapeake's hedging activity is dynamic. As market conditions warrant, the Company may elect to settle a hedging transaction prior to its scheduled maturity date and, as a result, lock in the gain or loss on the transaction.
Chesapeake enters into oil and natural gas derivative transactions in order to mitigate a portion of its exposure to adverse market changes in oil and natural gas prices. Accordingly, associated gains or loses from the derivative transactions are reflected as adjustments to oil and gas sales. All realized gains and losses from oil and natural gas derivatives are included in oil and gas sales in the month of related production. Pursuant to SFAS 133, certain derivatives do not qualify for designation as cash flow hedges. Changes in the fair value of these non-qualifying derivatives that occur prior to their maturity (i.e. because of temporary fluctuations in value) are reported currently in the consolidated statement of operations as unrealized gains (losses) within oil and gas sales.
Following provisions of SFAS 133, changes in the fair value of derivative instruments designated as cash flow hedges, to the extent effective in offsetting cash flows attributable to hedged risk, are recorded in other comprehensive income until the hedged item is recognized in earnings. Any change in fair value resulting from ineffectiveness is recognized currently in oil and natural gas sales.
The Company currently has in place the following natural gas swaps:
% Hedged
Avg. NYMEX Open Swap
Avg. NYMEX Price Assuming Positions
Strike Including Gas as a % of
Price Gain from Open & Production Estimated
Open Swaps Of Open Locked Locked in Bcf's Total Gas
in Bcf's Swaps Swaps Positions of: Production
2004:
1st Qtr 69.5 $5.94 $0.03 $5.97 70.9 98%
2nd Qtr 52.8 $4.97 $0.00 $4.97 71.9 74%
3rd Qtr 43.2 $4.89 $0.00 $4.89 73.6 59%
4th Qtr 35.0 $5.08 $0.00 $5.08 74.6 47%
Total 2004 200.5 $5.31 $0.01 $5.32 291.0 69%
Total 2005 82.1 $5.04 $0.00 $5.04 300.0 27%
Total 2006 32.9 $4.88 $0.00 $4.88 310.0 11%
Total 2007 25.6 $4.76 $0.00 $4.76 320.0 8%
TOTALS
2004-2007 341.1 $5.16 $0.01 $5.17 1,220.0 28%
NOW SUPERSEDED BY OUTLOOK AS OF FEBRUARY 23, 2004
Chesapeake has also entered into the following natural gas basis
protection swaps:
Assuming Gas
Annual Production
Volume in Bcf's NYMEX less: in Bcf's
of: % Hedged
2004 157.4 0.173 291.0 54%
2005 109.5 0.156 300.0 37%
2006 47.5 0.155 310.0 15%
2007 63.9 0.166 320.0 20%
2008 64.0 0.166 330.0 19%
2009 37.0 0.160 340.0 11%
Totals 479.3 $0.164* 1,891.0 25%
* weighted average
The Company has entered into the following crude oil hedging arrangements:
% Hedged
Open Swap
Assuming Oil Positions as %
Avg. Production of Total
Open Swaps NYMEX in Mmbo's Estimated
in Mmbo's Strike Price of: Production
Q1 - 2004* 1,270 $28.58 1,450 88%
Q2 - 2004* 1,282 $28.86 1,450 88%
Q3 - 2004* 1,044 $28.75 1,450 72%
Q4 - 2004* 920 $28.46 1,450 63%
Total 2004 4,516 $28.68 5,800 78%
*Swaps with a knockout price of $21.00, with the exception of 2,000 bopd in 2004 with a knockout price of $24.00, with an additional 1,000 bopd in Q2 2004 at $24, 1,000 bopd in Q3 and Q4 2004 with a knockout price of $23.00, 2,000 bopd for 1/04 and 3-8/04 at a knockout price of $22.00, and 3,000 bopd in 2/04 at a knockout price of $22.00.
NOW SUPERSEDED BY OUTLOOK AS OF FEBRUARY 23, 2004
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
