Company Posts Second Quarter Recurring Net Income of $48 Million, Cash Flow of $122 Million and Ebitda of $145 Million on Revenue Of $276 Million and Production of 39 Bcfe
Company Announces Hedging Positions Have Approximate Value of $150 Million -
293 Bcf Hedged at an Average NYMEX Price of $4.15 Per Mcf
During Next 30 Months
Anticipating Sale of Canadian Subsidiary and Lower Service Costs in 2001 And
In 2002, Company Reduces Cap-Ex Budget and Production Forecasts - Continues Focus on Profitability and Return on Capital
OKLAHOMA CITY, July 26 /PRNewswire/ -- Chesapeake Energy Corporation
The company's recurring net income of $48.0 million excludes a $46.0 million after-tax extraordinary charge resulting from the early retirement of debt and a $37.5 million after-tax non-cash gain resulting from the effects of SFAS 133 on the company's fixed price commodity contracts.
Production for the second quarter of 2001 was 39.1 billion cubic feet of natural gas equivalent (bcfe), comprised of 35.0 billion cubic feet of natural gas (bcf) and 682 thousand barrels of oil (mbo). The company's gas production increased 19% from the second quarter of 2000. Average prices realized during the second quarter of 2001 were $27.70 per barrel of oil and $4.46 per thousand cubic feet (mcf) of natural gas, for a gas equivalent price of $4.48 per mcfe. Hedging activities during the second quarter increased oil revenue by $1.27 per barrel and increased gas revenue by $0.18 per mcf, for a total revenue increase from hedging of $7.2 million ($0.18 per mcfe).
The table below summarizes Chesapeake's key statistics during the quarter and compares them to the first quarter of 2001 and the second quarter of 2000:
Three Months Ended 6/30/01 3/31/01 6/30/00 Average daily production (in mmcfe) 430 446 375 Gas as a % of total production 90 90 86 Natural gas production (in bcf) 35.0 36.0 29.3 Average gas sales price ($/mcf) 4.46 5.59 2.76 Oil production (in mbbls) 682 686 791 Average oil sales price ($/bbl) 27.70 29.01 24.46 Natural gas equivalent production (in bcfe) 39.1 40.2 34.1 Gas equivalent sales price ($/mcfe) 4.48 5.51 2.94 General and administrative costs ($/mcfe) .07 .10 .09 Production taxes ($/mcfe) .26 .36 .17 Lease operating expenses ($/mcfe) .48 .44 .37 Interest expense ($/mcfe) .59 .64 .64 DD&A of oil and gas properties ($/mcfe) 1.02 .95 .73 Operating cash flow ($ in millions) 122.3 161.5 59.7 Operating cash flow ($/mcfe) 3.13 4.02 1.75 Ebitda ($ in millions) 145.3 187.4 81.5 Ebitda ($/mcfe) 3.71 4.67 2.39 Recurring net income ($ in millions) 48.0 70.3 31.6 Anticipating Lower Gas Prices, Company Hedges 293 Bcf Of 2001-03 Production, Reduces 2001-02 Cap-Ex by $125 Million And Decides to Sell Canadian Subsidiary
Last winter, Chesapeake's management became increasingly concerned that higher natural gas prices were significantly reducing demand and that gas futures prices did not reflect weakening market fundamentals. In response, the company began hedging its 2001-03 natural gas production and has continued to add hedges during the past six months as gas storage reports have confirmed an ongoing supply/demand imbalance. Today, Chesapeake's hedges cover 293 bcf of projected natural gas production during the next 30 months at an average NYMEX price of $4.15 per mcf. By year, Chesapeake has hedged 66 bcf of remaining 2001 gas production at an average NYMEX price of $4.69 per mcf, 135 bcf of 2002 gas production at $4.12 per mcf and 92 bcf of 2003 gas production at $3.78 per mcf.
Chesapeake's hedges enable the company to accomplish several important goals. Most importantly, the company has locked in historically high forward gas prices that will enable it to generate more than $1.2 billion of cash flow and $350 million of net income during the next three years. By eliminating its exposure to highly volatile natural gas prices, Chesapeake believes that investors should appreciate the predictability of the company's financial results, recognize the strength of its debt service coverage and more easily differentiate the company from other E&P companies.
In addition, the company's hedges allow it to more aggressively protect its focus on generating strong rates of return. Consistent with that focus, Chesapeake is concerned that the industry's finding costs and operating margins have been adversely impacted during the past few months by much higher service costs and much lower gas prices. As a consequence, the company has elected to reduce its drilling cap-ex during the next 12-18 months by $125 million and expects other E&P companies to make cap-ex reductions as well. Chesapeake anticipates that a decrease in cap-ex across the industry will lead to lower service costs and more attractive finding costs.
One transaction that will contribute substantially to the cap-ex reduction and lowered production guidance is the anticipated sale of the company's Canadian assets, which are located in the Helmet Field of northeastern British Columbia. Chesapeake acquired these assets in 1997-98 and has substantially increased their value as a result of four successful winter drilling programs. The company has recently received several attractive offers for its Helmet properties and anticipates closing a sale late in the third quarter. Chesapeake expects to report a sizable gain from this transaction and intends to re-deploy the sales proceeds into debt reduction and/or further investment in its core U.S. operating areas, where it receives much higher gas prices, possesses greater operating efficiencies and achieves higher rates of return.
Chesapeake Updates 2001 and 2002 Forecasts
With each earnings announcement, the company updates its forecasts and estimates. The following forecasts and estimates revise and replace in their entirety previous projections last updated on April 26, 2001 and further assume Chesapeake sells its Canadian subsidiary at the end of the third quarter and reduces its cap-ex budget by $125 million over the next 12-18 months. The company's forecasts and estimates are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Actual results may differ materially due to the risks and uncertainties identified at the end of this release. Furthermore, these projections do not reflect the potential impact of unforeseen events that may occur subsequent to the issuance of this release.
Chesapeake's current 2001 guidance is based on projected production of 154-158 bcfe (89% gas) and projected per mcfe lease operating expenses of $0.50-$0.55, production taxes of $0.23-$0.27, interest expense of $0.60-$0.65, general and administrative costs of $0.10-$0.11 and DD&A of oil and gas properties of $1.05-$1.15. In addition, Chesapeake expects its tax rate to average 40%, of which 95% should be deferred.
If the mid-points of the forecasted ranges described above are achieved and if NYMEX oil and gas prices average $24.33 per bo and $3.00 per mcf in the second half of 2001, Chesapeake expects to realize oil and gas revenue for the year of $4.61 per mcfe and to generate ebitda of $575-600 million, operating cash flow of $475-500 million and recurring net income of $175-200 million. If these assumptions are accurate, the company's 2001 cash flow and earnings per fully diluted share should range between $2.75-2.95 and $1.00-1.10, respectively.
Chesapeake's current 2002 guidance is based on a drilling cap-ex budget of $200 million (reduced $125 million from previous guidance), projected production of 154-160 bcfe (87% gas and excluding Canadian production) and projected per mcfe lease operating expenses of $0.45-0.50, production taxes of $0.18-0.22, interest expense of $0.55-0.60, general and administrative costs of $0.10-0.11 and DD&A of oil and gas properties of $1.10-1.20. The company expects its 2002 tax rate to average 40%, of which virtually all should be deferred.
If the mid-points of the forecasted ranges described above are achieved and if NYMEX prices average $3.00 per mcf and $22.00 per barrel in 2002, Chesapeake expects to realize oil and gas revenue for the year of $3.72 per mcfe and to generate ebitda of $450-475 million, operating cash flow of $365-390 million and net income of $100-125 million. If these assumptions are accurate, the company's 2002 cash flow and earnings per fully diluted share should range between $2.05-2.25 and $0.60-0.70, respectively.
Chesapeake Announces Several Opportunistic Investments: 100% of K. Stewart Petroleum Corporation, 49.9% of RAM Energy, Inc., And a $22.5 Million Loan to Seven Seas Petroleum Corporation
Continuing its ongoing Mid-Continent asset consolidation program, Chesapeake has recently acquired an interest in two privately held Oklahoma- based natural gas producers -- 49.9% of RAM Energy, Inc. ("RAM") and 100% of K. Stewart Petroleum Corp. ("KSP"). RAM is a Mid-Continent-focused gas producer with 23,000 mcfe of current daily production and over 100 bcfe of proved reserves. Many of RAM's assets are located in areas of close proximity to Chesapeake's existing operations in Oklahoma. The purchase price for the company's interest in RAM was $10 million in Chesapeake common stock.
KSP is an exploration company previously owned 40% by ONEOK, Inc.
Chesapeake's acquisition cost was $22 million for KSP's 20 bcfe of proved reserves and more than 100 bcfe of probable and possible reserves. Industry estimates for Comanche Lodge's reserves range from 200-400 bcfe. Analogous fields to Comanche Lodge are West Mayfield, discovered by Conoco in 1976 and located nine miles to the west, and Northeast Mayfield, discovered by Unocal in 1970 and located five miles to the northwest. To date these prolific fields have produced more than 600 bcfe from various formations between 15,000-25,000'. More than 25 years after their discovery, Mayfield and Northeast Mayfield are still two of the most actively drilled fields in Oklahoma today.
In addition, Chesapeake has recently negotiated an investment in Seven Seas Petroleum Corporation
Proceeds from the debt issuance will be used by Seven Seas to complete development of its previously discovered Guaduas Field in Colombia and to drill the 18,000' Escuela #2 well, which will test the Subthrust Dindal structure underneath the Guaduas Field, and other corporate purposes. The Guaduas Field is located 60 miles northwest of Bogota in the Magdelena Valley of central Colombia. Seven Seas' independent reservoir engineers, Ryder Scott Company Petroleum Consultants, have estimated that the Guaduas Field's existing proved recoverable reserves are 48 million barrels net to Seven Seas (156 million barrels gross). The Subthrust Dindal structure covers more than 50,000 acres and has reserve potential of up to 3.5 billion barrels of oil, making it perhaps the largest undrilled prospect in the western hemisphere. The Escuela #2 well is scheduled to begin drilling in the fourth quarter of this year and will require an estimated 150 days to drill and test the targeted Subthrust Hoyon and Cimarrona formations.
Aubrey K. McClendon, Chesapeake's Chairman and Chief Executive Officer, commented, "We are very pleased with our strong performance during the second quarter of 2001. During the quarter, we increased our reserves to a record level of 1,750 bcfe, executed a well-timed hedging program that virtually ensures our company will generate more than $1.2 billion of cash flow and $350 million of net income during 2001-03, strengthened our balance sheet by lengthening the maturity and lowering the interest rate on $800 million of long-term debt and made several investments that we believe have considerable upside potential. In addition, we have recently received several attractive offers to purchase our Canadian assets that will generate a sizable gain if sold.
"We will continue to focus on per unit of production profitability and return on investment rather than pursuing high rates of production growth during periods when service costs cause unacceptably high finding costs. With strong levels of cash flow protected by our hedges during what we believe will be a period of lower gas prices in the second half of 2001 and in 2002, Chesapeake is very well positioned to reduce debt, grow assets and generate significant increases in shareholder value during what may be an extended period of extreme gas price volatility and compressed pricing cycles."
Conference Call Information
Chesapeake's management invites your participation in a conference call tomorrow morning, Friday, July 27 at 9:00 a.m. EDT to discuss the contents of this release and respond to questions. Please call 913-981-4901 between 8:50 and 9:00 am EDT tomorrow if you would like to participate in the call. For those unable to participate, the call will also be available over the Internet by visiting our home page at http://www.chkenergy.com/ and clicking on the link under Shareholder Information or by going directly to http://www.vcall.com/ . A replay of the call will also be available by calling 719-457-0820 between 12:00 p.m. EDT Friday, July 27 through midnight Friday, August 10, 2001. The passcode for this call is 402673.
The information in this release includes certain forward-looking statements that are based on assumptions that in the future may prove not to have been accurate. Those statements, and Chesapeake Energy Corporation's business and prospects, are subject to a number of risks, including production variances from expectations, uncertainties about estimates of reserves, volatility of oil and gas prices, the need to develop and replace reserves, the substantial capital expenditures required to fund operations, environmental risks, drilling and operating risks, risks related to exploratory and developmental drilling, competition, government regulation, and the ability of the company to implement its business strategy. These and other risks are described in the company's documents and reports that are available from the United States Securities and Exchange Commission, including those discussed under Risk Factors in the report filed on Form 10-Q for the quarter ended March 31, 2001.
Chesapeake Energy Corporation is among the 10 largest independent natural gas producers 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 region of the United States. The company's Internet address is http://www.chkenergy.com/ .
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS ($ in 000's, except per share data) (unaudited) THREE MONTHS ENDED: June 30, 2001 June 30, 2000 $ $/mcfe $ $/mcfe REVENUES: Oil and gas sales 175,225 4.48 100,221 2.94 Risk management income 62,455 1.60 --- --- Oil and gas marketing sales 38,001 0.97 34,242 1.01 Total revenues 275,681 7.05 134,463 3.95 OPERATING COSTS: Production expenses 18,842 0.48 12,581 0.37 Production taxes 9,991 0.26 5,717 0.17 General and administrative 2,873 0.07 3,188 0.09 Oil and gas marketing expenses 36,913 0.94 33,122 0.97 Depreciation, depletion, and amortization of oil and gas properties 39,910 1.02 24,877 0.73 Depreciation and amortization of other assets 1,837 0.05 1,836 0.06 Total operating costs 110,366 2.82 81,321 2.39 INCOME FROM OPERATIONS 165,315 4.23 53,142 1.56 OTHER INCOME (EXPENSE): Interest and other income 683 0.02 1,667 0.05 Interest expense (22,984) (0.59) (21,813) (0.64) (22,301) (0.57) (20,146) (0.59) Income Before Income Taxes and Extraordinary Item 143,014 3.66 32,996 0.97 Income Tax Expense 57,529 1.47 1,362 0.04 INCOME BEFORE EXTRAORDINARY ITEM 85,485 2.19 31,634 0.93 EXTRAORDINARY ITEM: Loss on early extinguishment of debt, net of applicable income tax (46,000) (1.18) --- --- NET INCOME 39,485 1.01 31,634 0.93 Preferred Stock Dividends (182) --- (2,907) (0.08) Gain on Redemption of Preferred Stock --- --- 1,481 0.04 Net Income Available to Common Shareholders 39,303 1.01 30,208 0.89 Earnings Per Common Share - Basic Income Before Extraordinary Item and Risk Management Income (D) 0.29 --- 0.26 --- Risk Management Income (D) 0.23 --- --- --- Extraordinary Item (0.28) --- --- --- Net Income 0.24 --- 0.26 --- Earnings Per Common Share - Assuming Dilution Income Before Extraordinary Item and Risk Management Income (D) 0.28 --- 0.22 --- Risk Management Income (D) 0.22 --- --- --- Extraordinary Item (0.27) --- --- --- Net Income 0.23 --- 0.22 --- Average Common Shares and Common Equivalent Shares Outstanding Basic 162,588 --- 116,466 --- Diluted (A) 171,321 --- 146,113 --- Operating Cash Flow (B) 122,306 3.13 59,709 1.75 EBITDA (C) 145,290 3.71 81,522 2.39 Thousands of barrels of oil (mbbl) 682 -14% 791 Millions of cubic feet of gas (mmcf) 35,045 19% 29,339 Millions of cubic feet of gas equivalents (mmcfe) 39,137 15% 34,085 MMcfe per day 430 15% 375 Average price/barrel $ 27.70 13% $ 24.46 Average price/mcf $ 4.46 62% $ 2.76 Average gas equivalent price/mcfe $ 4.48 52% $ 2.94 A. Earnings per share assuming dilution for the three months ended June 30, 2001 and 2000, includes the effect of dilutive stock options, and includes the effect of the assumed conversion of all preferred stock as of the beginning of the period. B. Income before income taxes and extraordinary item, depreciation, depletion and amortization and risk management income. C. Earnings before income taxes and extraordinary item, interest expense, depreciation, depletion and amortization and risk management income. D. Risk management income is shown on an after-tax basis. CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS ($ in 000's, except per share data) (unaudited) SIX MONTHS ENDED: June 30, 2001 June 30, 2000 $ $/mcfe $ $/mcfe REVENUES: Oil and gas sales 396,444 5.00 187,514 2.76 Risk management income 62,455 0.79 --- --- Oil and gas marketing sales 94,166 1.19 61,610 0.90 Total revenues 553,065 6.98 249,124 3.66 OPERATING COSTS: Production expenses 36,630 0.46 25,126 0.37 Production taxes 24,286 0.31 10,933 0.16 General and administrative 6,874 0.09 6,220 0.09 Oil and gas marketing expenses 91,391 1.15 59,666 0.88 Depreciation, depletion, and amortization of oil and gas properties 78,083 0.98 49,360 0.73 Depreciation and amortization of other assets 3,790 0.05 3,702 0.05 Total operating costs 241,054 3.04 155,007 2.28 INCOME FROM OPERATIONS 312,011 3.94 94,117 1.38 OTHER INCOME (EXPENSE): Interest and other income 1,252 0.02 2,859 0.04 Interest expense (48,873) (0.62) (42,677) (0.63) Gothic standby credit facility costs (3,392) (0.04) --- --- (51,013) (0.64) (39,818) (0.59) Income Before Income Taxes and Extraordinary Item 260,998 3.30 54,299 0.79 Income Tax Expense 105,225 1.33 1,463 0.02 INCOME BEFORE EXTRAORDINARY ITEM 155,773 1.97 52,836 0.77 EXTRAORDINARY ITEM: Loss on early extinguishment of debt, net of applicable income tax (46,000) (0.58) --- --- NET INCOME 109,773 1.39 52,836 0.77 Preferred Stock Dividends (728) (0.01) (6,949) (0.10) Gain on Redemption of Preferred Stock --- --- 11,895 0.17 Net Income Available to Common Shareholders 109,045 1.38 57,782 0.84 Earnings Per Common Share - Basic Income Before Extraordinary Item and Risk Management Income (D) 0.74 --- 0.53 --- Risk Management Income (D) 0.23 --- --- --- Extraordinary Item (0.29) --- --- --- Net Income 0.68 --- 0.53 --- Earnings Per Common Share - Assuming Dilution Income Before Extraordinary Item and Risk Management Income (D) 0.69 --- 0.36 --- Risk Management Income (D) 0.22 --- --- --- Extraordinary Item (0.27) --- --- --- Net Income 0.64 --- 0.36 --- Average Common Shares and Common Equivalent Shares Outstanding Basic 160,161 --- 108,196 --- Diluted (A) 170,835 --- 146,285 --- Operating Cash Flow (B) 283,808 3.58 107,361 1.58 EBITDA (C) 332,681 4.20 150,038 2.21 Thousands of barrels of oil (mbbl) 1,368 -17% 1,655 Millions of cubic feet of gas (mmcf) 71,085 22% 58,086 Millions of cubic feet of gas equivalents (mmcfe) 79,293 17% 68,016 MMcfe per day 438 17% 374 Average price/barrel $ 28.36 16% $ 24.52 Average price/mcf $ 5.03 99% $ 2.53 Average gas equivalent price/mcfe $ 5.00 81% $ 2.76 A. Earnings per share assuming dilution for the six months ended June 30, 2001 and 2000, includes the effect of dilutive stock options, and includes the effect of the assumed conversion of all preferred stock as of the beginning of the period. B. Income before income taxes and extraordinary item, Gothic standby credit facility costs, depreciation, depletion and amortization, and risk management income. C. Earnings before income taxes and extraordinary item, Gothic standby credit facility costs, interest expense, depreciation, depletion and amortization and risk management income. D. Risk management income is shown on an after-tax basis.
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, Corporate
Development, +1-405-879-9257, both of Chesapeake Energy Corporation
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