10-Q 1 sep0010q.txt TEXT 1 SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 Form 10-Q [ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934. For the quarterly period ended September 30, 2000 or [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934. For the transition period from to --------- --------- Commission File Number 1-12480 LOUIS DREYFUS NATURAL GAS CORP. (Exact name of registrant as specified in its charter) Oklahoma 73-1098614 (State or other jurisdiction of (IRS Employer incorporation or organization) Identification No.) 14000 QUAIL SPRINGS PARKWAY, SUITE 600 OKLAHOMA CITY, OKLAHOMA 73134 (Address of principal executive office) (Zip code) Registrant's telephone number, including area code: (405) 749-1300 NONE (Former name, former address and former fiscal year, if changed since last report.) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES X NO . ----- ----- 43,228,013 shares of common stock, $.01 par value, issued and outstanding at November 6, 2000. 2 LOUIS DREYFUS NATURAL GAS CORP. Table of Contents PART I. FINANCIAL INFORMATION Page Item 1 -- CONSOLIDATED FINANCIAL STATEMENTS (unaudited) Consolidated Balance Sheets: September 30, 2000 and December 31, 1999 . . . . . . . . . . . . . . . 3 Consolidated Statements of Income: Three months and nine months ended September 30, 2000 and 1999 . . . . 4 Consolidated Statements of Cash Flows: Nine months ended September 30, 2000 and 1999. . . . . . . . . . . . . 5 Condensed Notes to Consolidated Financial Statements . . . . . . . . . . 6 Item 2 -- MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. . . . . . . . . . . . . . . . . . 9 Item 3 -- QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK. . .19 PART II. OTHER INFORMATION . . . . . . . . . . . . . . . . . . . . .22 3 LOUIS DREYFUS NATURAL GAS CORP. CONSOLIDATED BALANCE SHEETS (dollars in thousands)

4 LOUIS DREYFUS NATURAL GAS CORP. CONSOLIDATED BALANCE SHEETS(continued) (dollars in thousands)

See accompanying notes to consolidated financial statements. 5 LOUIS DREYFUS NATURAL GAS CORP. CONSOLIDATED STATEMENTS OF INCOME (unaudited) (in thousands, except per share data)

See accompanying notes to consolidated financial statements. 6 LOUIS DREYFUS NATURAL GAS CORP. CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited) (in thousands)

See accompanying notes to consolidated financial statements. 7 LOUIS DREYFUS NATURAL GAS CORP. CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) SEPTEMBER 30, 2000 NOTE 1 -- ACCOUNTING PRINCIPLES AND BASIS OF PRESENTATION The accompanying unaudited consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q as prescribed by the Securities and Exchange Commission. All material adjustments, consisting of normal and recurring adjustments which, in the opinion of Management, were necessary for a fair presentation of the results for the interim periods have been reflected. The results of operations for the three-month and nine-month periods ended September 30, 2000 are not necessarily indicative of the results to be expected for the full year. Reference is made to the Company's Annual Report on Form 10-K for the year ended December 31, 1999 for an expanded discussion of the Company's financial disclosures and accounting policies. NOTE 2 -- HEDGING The Company reduces its exposure to unfavorable changes in oil and natural gas prices by utilizing fixed-price physical delivery contracts, energy swaps, collars, futures contracts, basis swaps and options (collectively "Fixed-Price Contracts"). The Company also enters into interest rate swap contracts to reduce its exposure to adverse interest rate fluctuations. In October 1998, the Company adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133") which establishes new accounting and reporting guidelines for derivative instruments and hedging activities. Substantially all of the Company's Fixed-Price Contracts (other than three costless natural gas collars which matured in September 2000) and interest rate swaps are designated as cash flow hedges. Change in derivative fair value in the statements of operations for the three-month and the nine-month periods ended September 30, 2000 and 1999 is comprised of the following: 8 LOUIS DREYFUS NATURAL GAS CORP. CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued) SEPTEMBER 30, 2000

Despite certain Fixed-Price Contracts failing the effectiveness guidelines of SFAS 133 from time to time, Fixed-Price Contracts continue to be highly effective in achieving the risk management objectives for which they were intended. The change in carrying value of Fixed-Price Contracts and interest rate swaps in the Company's balance sheet since December 31, 1999 resulted from a significant increase in market prices for natural gas and crude oil and an increase in interest rates. The majority of this change in fair value was reflected in accumulated other comprehensive income, net of deferred tax effects. Derivative liabilities reflected as current in the September 30, 2000 balance sheet represent the estimated fair value of Fixed-Price Contract settlements scheduled to occur over the subsequent twelve-month period based on market prices for oil and gas as of the balance sheet date. Because present accounting rules do not provide for the accrual of the future cash flow transactions the contracts were designed to hedge, an apparent working capital deficit is created which does not, in Management's opinion, accurately depict the Company's true working capital position or its liquidity. These settlement amounts are not due and payable until the monthly period that the related underlying hedged transaction occurs. In some cases the recorded liability for certain contracts significantly exceeds the total settlement amounts that would be paid to a counterparty based on prices in effect at the balance sheet date due to option time value. For derivatives which are held to maturity, this time value has no direct relationship to actual future contract settlements and consequently does not represent a liability which will be settled in cash. 9 LOUIS DREYFUS NATURAL GAS CORP. CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued) SEPTEMBER 30, 2000 The estimated fair values of Fixed-Price Contracts and interest rate swaps as of September 30, 2000 and December 31, 1999 are provided below. The associated carrying values of these contracts are equal to the estimated fair values for each period presented. September 30, December 31, 2000 1999 ------------ ------------ (in thousands) Derivative assets: Fixed-price natural gas swaps. . . . . . . . $ -- $ 16,433 Fixed-price natural gas collars. . . . . . . -- 1,323 Fixed-price natural gas delivery contracts . 945 7,921 Fixed-price crude oil swaps. . . . . . . . . -- 360 Interest rate swaps. . . . . . . . . . . . . 3,847 5,660 Derivative liabilities: Fixed-price natural gas swaps. . . . . . . . (35,950) (4,329) Fixed-price natural gas collars. . . . . . . (9,376) -- Fixed-price natural gas delivery contracts . (104,652) (9,081) Natural gas basis swaps. . . . . . . . . . . (1,374) (3,271) ------------ ------------ $ (146,560) $ 15,016 ============ ============

The fair value of Fixed-Price Contracts as of September 30, 2000 and December 31, 1999 was estimated based on market prices of natural gas and crude oil for the periods covered by the contracts. The net differential between the prices in each contract and market prices for future periods, as adjusted for estimated basis, has been applied to the volumes stipulated in each contract to arrive at an estimated future value. This estimated future value was discounted on a contract-by-contract basis at rates commensurate with the Company's estimation of contract performance risk and counterparty credit risk. The fair value of derivative instruments which contain options (e.g. collar structures) has been estimated based on remaining life, volatility and other factors. The terms and conditions of the Company's fixed-price physical delivery contracts and certain financial swaps are uniquely tailored to the Company's circumstances. In addition, the determination of market prices for natural gas beyond a five year horizon is subject to significant judgment and estimation. As a result, the Fixed-Price Contract fair value does not necessarily represent the value a third party would pay to assume the Company's contract positions. 10 LOUIS DREYFUS NATURAL GAS CORP. CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued) SEPTEMBER 30, 2000 NOTE 3 -- ACQUISITION OF PROPERTIES FROM COSTILLA ENERGY, INC. On June 15, 2000, the Company acquired substantially all of the oil and gas properties of Costilla Energy, Inc. for approximately $126 million in cash, net of estimated purchase price adjustments. The acquired properties were comprised of 135 Bcfe of net proved reserves included in 1,011 gross (607 net) producing wells at closing. The Costilla properties are primarily located within the Company's three core operating areas. A substantial portion of the total identified value is contained within a field in which the Company has a significant ownership position, the SW Speaks field in Lavaca County, Texas. The purchase price for the Costilla acquisition was initially funded through availability under the Company's revolving bank credit facility. See Note 4 -- Common Stock Offering. The acquisition has been accounted for using the purchase method of accounting. In connection with the acquisition, the Company entered into two costless collars to hedge a portion of the future production from the properties. The first collar hedges 20 MMcf per day for 2001 at a floor price of $3.13 per MMBtu and a ceiling price of $4.25 per MMBtu. The second collar hedges 20 MMcf per day in 2002 at a floor price of $2.84 per MMBtu and a ceiling price of $3.94 per MMBtu. NOTE 4 -- COMMON STOCK OFFERING On June 28, 2000, the Company sold 2.4 million shares of its common stock at $31.00 per share ($29.53 per share net of underwriting discount) in a public offering. Proceeds from the offering of $70.9 million received in July 2000 were applied to reduce a majority of the indebtedness incurred in connection with the acquisition of properties from Costilla Energy, Inc. In addition, an indirect wholly-owned subsidiary of S.A. Louis Dreyfus et Cie sold 1.6 million shares of the Company's common stock in the offering. Subsequent to the offering, S.A. Louis Dreyfus et Cie through its subsidiaries owned 19.2 million common shares, or approximately 44% of the total issued and outstanding common shares of the Company. NOTE 5 -- LITIGATION The Company is one of numerous defendants in several lawsuits originally filed in 1995, subsequently consolidated with related litigation, and now pending in the 93rd Judicial District Court in Hildago County, Texas. The lawsuit alleges that the plaintiffs, a group of local landowners and businesses, have suffered damages including, but not limited to, property damage and lost profits of approximately $60 million as the result of an underground hydrocarbon plume within the city of McAllen, Texas. The lawsuit alleges that gas wells and related pipeline facilities operated by the Company, and other facilities operated by other defendants, caused the plume. In August 1999, the plaintiff's experts produced reports that suggested the Company might be considered a significant contributor to the plume. The 11 LOUIS DREYFUS NATURAL GAS CORP. CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued) SEPTEMBER 30, 2000 Company's investigation into this matter has not found any leaks or discharges from its facilities. In addition, the Company's investigation has revealed the plume to be unrelated to the Company's production of natural gas from its facilities. Trial is not anticipated to commence until the second half of 2001. The Company will vigorously defend its interests in this case. Results of litigation are inherently unpredictable; however, the Company does not presently expect the ultimate outcome of the case to have a material adverse impact on its financial position or results of operations. The Company was a defendant in various other legal proceedings as of September 30, 2000, which are routine and incidental to its business. While the ultimate results of all these proceedings and determinations cannot be predicted with certainty, the Company will vigorously defend its interests and does not presently believe that the outcome of these matters will have a material adverse effect on the Company. NOTE 6 -- COMPREHENSIVE LOSS Components of comprehensive loss for the three-month and the nine-month periods ended September 30, 2000 and 1999, are as follows:

12 LOUIS DREYFUS NATURAL GAS CORP. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OVERVIEW General. Our business strategy is to generate strong and consistent growth in reserves, production, operating cash flows and earnings through a balanced program of exploration and development drilling and strategic acquisitions of oil and gas properties. Our drilling, acquisition and operating activities are geographically concentrated in three core areas: the Permian Region of West Texas, Southeast New Mexico and the San Juan Basin; the Mid-Continent Region of Oklahoma, Kansas and the Panhandle of Texas; and the Gulf Coast Region, which includes South Texas, Offshore Gulf of Mexico, East Texas, Southwest Arkansas and Northern Louisiana (collectively our "Core Areas"). We have significant experience and expertise in our Core Areas and we benefit from operational synergies due to the concentration of our properties within these areas. Our capital expenditure plans for 2000 include the investment of approximately $220 million in drilling activities, the vast majority of which will be expended in these Core Areas. See "-- Commitments and Capital Expenditures." We reduce exposure to unfavorable changes in oil and gas prices by utilizing long-term physical delivery contracts, energy swaps, collars, futures contracts, basis swaps and option agreements (collectively "Fixed-Price Contracts"). As of September 30, 2000, our Fixed-Price Contracts hedged 157 Bcf of future production, representing 11% of our estimated total proved reserves at December 31, 1999, at escalating fixed prices. Approximately 6 Bcf is hedged for the remainder of fiscal 2000. See "Quantitative and Qualitative Disclosures About Market Risk." Forward-Looking Statements. All statements made in this document other than purely historical information are "forward-looking statements" within the meaning of the federal securities laws. These statements reflect our current expectations and are based on our historical operating trends, proved reserve and Fixed-Price Contract positions and other currently available information. Forward-looking statements include statements regarding our future drilling plans and objectives and related exploration and development budgets and number and location of planned wells and statements regarding the quality of our properties and potential reserve and production levels. These statements may be preceded by or followed by or otherwise include the words "believes", "expects", "anticipates", "intends", "plans", "estimates", "projects", or similar expressions or statements that certain events "will" or "may" occur. These statements assume that no significant changes will occur in the operating environment for our oil and gas properties and that there will be no material acquisitions or divestitures except as otherwise described. The forward-looking statements are subject to all the risks and uncertainties incident to the acquisition, exploration, development and marketing of oil and natural gas reserves, including the risks described in this document and in our Annual Report filed on Form 10-K for the year ended December 31, 1999. These risks include, but are not limited to, commodity 13 LOUIS DREYFUS NATURAL GAS CORP. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) price, counterparty, environmental, drilling, reserves, operations and production risks. We may also make material acquisitions or divestitures, modify our Fixed-Price Contract positions or enter into financing transactions. None of these events can be predicted with certainty and are not taken into consideration in the forward-looking statements. Statements concerning Fixed-Price Contract, interest rate swap and other financial instrument fair values and their estimated contribution to our future results of operations are based upon market information as of a specific date. This market information is often a function of significant judgment and estimation. Further, market prices for oil and gas and market interest rates are subject to significant volatility. For all of these reasons, our actual results may vary materially from the forward-looking statements and there is no assurance that the assumptions we have used are necessarily the most likely. We will not update any forward-looking statements to reflect events or circumstances occurring after the date the statement is made. Certain Definitions. As used herein, the abbreviations listed below are defined as follows: Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to oil or other liquid hydrocarbons. Bcf. Billion cubic feet. Bcfe. Billion cubic feet of natural gas equivalent, determined using the ratio of one Bbl of oil or condensate to six Mcf of natural gas. BBtu. Billion Btus. Btu. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit. EBITDAX. EBITDAX is defined in this document as income before interest expense, income taxes, depreciation, depletion and amortization, impairment, exploration costs and change in derivative fair value. We believe that EBITDAX is a financial measure commonly used in the oil and gas industry as an indicator of a company's ability to service and incur debt. However, EBITDAX should not be considered in isolation or as a substitute for net income, cash flows provided by operating activities or other data prepared in accordance with generally accepted accounting principles, or as a measure of a company's profitability or liquidity. EBITDAX measures as presented may not be comparable to other similarly titled measures of other companies. MBbls. Thousand barrels. Mcf. Thousand cubic feet. Mcfe. Thousand cubic feet of natural gas equivalent, determined using the ratio of one Bbl of oil or condensate to six Mcf of natural gas. MMBbls. Million barrels. 14 LOUIS DREYFUS NATURAL GAS CORP. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) MMBtu. Million Btus. MMcf. Volume of one million cubic feet. MMcfe. Million cubic feet of natural gas equivalent, determined using the ratio of one Bbl of oil or condensate to six Mcf of natural gas. TBtu. One Trillion Btus. Selected Operating Data. The following table provides certain operating data relating to our results of operations. 15 LOUIS DREYFUS NATURAL GAS CORP. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

16 LOUIS DREYFUS NATURAL GAS CORP. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) RESULTS OF OPERATIONS -- THREE MONTHS ENDED SEPTEMBER 30, 2000 COMPARED TO THREE MONTHS ENDED SEPTEMBER 30, 1999 Net Income and Cash Flows from Operating Activities. For the quarter ended September 30, 2000, we realized net income of $29.4 million, or $.66 per share, on revenues of $134.5 million. This compares to net income of $13.0 million, or $.32 per share, on revenues of $89.9 million for the third quarter of 1999. Earnings results for the third quarter of 2000 exceeded the level of earnings previously realized for any full fiscal year in our history. Net income excluding the non-cash impact of SFAS 133 derivative accounting was $25.3 million, or $.57 per share, for the third quarter of 2000 and $11.3 million or $.28 per share, for the third quarter of 1999. Cash flows from operating activities (before working capital changes) for the third quarter of 2000 grew 61% to a record $85.7 million compared to $53.4 million for the third quarter of 1999. EBITDAX for the quarter ended September 30, 2000 improved 55% to $98.5 million, also a record. This compares to EBITDAX of $63.7 million for the prior year quarter. The increases in operating cash flows and EBITDAX for the current year quarter were principally the result of higher oil and gas prices and higher gas production. Cash flows provided by operating activities after consideration of the net change in working capital decreased to $51.8 million from the $62.6 million reported for the third quarter of 1999, primarily due to an increase in accounts receivable and a decrease in accounts payable in the current year period. Production. We produced 36.5 Bcfe for the third quarter of 2000 compared to 32.0 Bcfe for the prior year third quarter, an increase of 14%. Gas production increased to 31.9 Bcf compared to 27.6 Bcf for the third quarter of 1999, an increase of 16%. Oil production for the third quarter of 2000 increased 4% to 762 MBbls compared to 730 MBbls for the prior-year third quarter. Oil and Gas Prices. On a natural gas equivalent basis, we received an average price of $3.49 per Mcfe for the quarter ended September 30, 2000, an increase of 44% from the $2.43 per Mcfe received for the third quarter of 1999. Our gas production yielded an average price of $3.25 per Mcf, an increase of 41% compared to $2.30 per Mcf for the prior-year third quarter. Our average gas price for the 2000 third quarter was reduced $.97 per Mcf as a result of our price risk management activities. The average gas price for the third quarter of 1999 was reduced $.22 per Mcf as a result of the Fixed-Price Contracts in effect for that period. The average oil price for the third quarter of 2000 was $30.71 per Bbl, an increase of 57% from the $19.50 per Bbl received for the prior-year third quarter. The average oil price for the third quarter of 2000 increased $.16 per Bbl as a result of our hedging activities. The average oil price for the third quarter of 1999 was reduced $.35 per Bbl as a result of our hedging activities. 17 LOUIS DREYFUS NATURAL GAS CORP. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) The combination of higher gas production and higher gas prices increased gas sales to $103.9 million for the third quarter of 2000 compared to $63.6 million for the third quarter of 1999. The combination of higher oil prices and higher oil production increased oil sales to $23.4 million compared to $14.2 million reported for the prior-year quarter. The impact of Fixed-Price Contract settlements was to decrease oil and gas sales by $30.8 million for the quarter ended September 30, 2000 and to decrease oil and gas sales by $6.4 million for the quarter ended September 30, 1999. See "Quantitative and Qualitative Disclosures About Market Risk." Change in Derivative Fair Value. Change in derivative fair value for the third quarter of 2000 was a net gain of $6.6 million, which included a $9.4 million gain associated with certain derivatives not qualifying for hedge accounting, $.7 million of net losses relating to the ineffective portion of derivatives which qualified for hedge accounting, and a $2.1 million loss relating to the reversal of contract fair value gains and losses recognized in earnings prior to actual cash settlement. Change in derivative fair value for the third quarter of 1999 was a net gain of $2.9 million, which included a $2.3 million gain associated with certain derivatives not qualifying for hedge accounting, $1.3 million of net gains relating to the ineffective portion of derivatives which qualified for hedge accounting, and $.7 million of losses relating to the reversal of contract fair value gains and losses recognized in earnings prior to actual cash settlement. Despite certain contracts failing the effectiveness guidelines of SFAS 133 from time to time, our Fixed-Price Contracts continue to be highly effective in achieving the risk management objectives for which they were intended. Other Income. Other income for the third quarters of 2000 and 1999 was $.5 million and $9.3 million, respectively. The decrease was primarily the result of a nonrecurring pretax gain of $8.6 million recognized in the third quarter of 1999. Operating Costs. Operating costs for the third quarter of 2000 were comprised of $14.8 million of lease operating expenses and $8.8 million of production taxes. This compares to $12.9 million of lease operating expenses and $4.5 million of production taxes for the third quarter of 1999. The increase in production taxes is primarily the result of higher oil and gas prices in the third quarter of 2000. Lease operating expenses on a natural gas equivalent unit of production basis were $.41 per Mcfe for the three months ended September 30, 2000 as compared to $.40 per Mcfe for the three months ended September 30, 1999. The increase is primarily attributable to the higher operating costs of the properties acquired from Costilla Energy, Inc. General and Administrative Expense. General and administrative expense ("G&A") for the third quarter of 2000 was $5.7 million, a decrease of 5% from the prior-year third quarter amount of $6.1 million. This decrease is primarily attributable to an increase in overhead recoveries, due in part to 18 LOUIS DREYFUS NATURAL GAS CORP. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) the Costilla acquisition. On a natural gas equivalent unit of production basis, G&A decreased to $.16 per Mcfe for the 2000 third quarter compared to $.19 per Mcfe for the 1999 third quarter, due to growth in production without corresponding increases in G&A costs. Exploration Costs. Exploration costs, comprised of geological and geophysical costs, exploratory dry holes and leasehold impairment costs, increased to $12.1 million for the quarter ended September 30, 2000, compared to $5.0 million for the third quarter of 1999. The 2000 amount consists of $8.0 million of dry hole costs, $.9 million of seismic acquisition and other geological and geophysical costs and $3.2 million of leasehold costs. The 1999 amount consists of $.1 million of dry hole costs, $1.6 million of seismic acquisition and other geological and geophysical costs and $3.3 million of leasehold costs. Depreciation, Depletion and Amortization. Depreciation, depletion and amortization ("DD&A") for the third quarter of 2000 was $34.1 million compared to $29.4 million for the prior-year third quarter. This increase in DD&A is attributable to an increase in production. The oil and gas DD&A rate per equivalent unit of production was $.90 per Mcfe for the 2000 third quarter compared to $.89 per Mcfe for the third quarter of 1999. This increase was due, in part, to the cost of the Costilla acquisition. Interest Expense. Interest expense for the third quarter of 2000 was $11.0 million compared to $10.4 million for the third quarter of 1999. The net impact of interest rate swaps in effect for the third quarter of 2000 was to decrease interest expense by $.6 million. The impact of interest rate swaps in the third quarter of 1999 was not material. See "Capital Resources and Liquidity - Credit Facility." Income Taxes. For the third quarter of 2000, a tax provision of $18.5 million was recorded on pretax income of $47.9 million, an effective rate of 39%. This compares to a tax provision of $8.7 million on pretax income of $21.7 million, an effective rate of 40%, for the third quarter of 1999. RESULTS OF OPERATIONS -- NINE MONTHS ENDED SEPTEMBER 30, 2000 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30, 1999 Net Income and Cash Flows from Operating Activities. We realized net income of $47.4 million, or $1.12 per share, on revenues of $302.9 million for the nine months ended September 30, 2000. This compares with net income of $8.8 million, or $.22 per share, on revenues of $209.5 million for the nine months ended September 30, 1999. Net income excluding the non-cash impact of SFAS 133 derivative accounting was $55.6 million, or $1.31 per share, for the first nine months of 2000, and $13.7 million, or $.34 per share, for the nine months ended September 30, 1999. Cash flows from operating activities (before working capital changes) for the first nine months of 2000 were $205.7 million, compared to $120.4 million for the first nine months of 1999, an increase of 71%. The increase in operating cash flows for the current year 19 LOUIS DREYFUS NATURAL GAS CORP. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) nine-month period was primarily the result of higher oil and gas prices and higher gas production in relation to the first nine months of 1999. Cash flows provided by operating activities after consideration of the net change in working capital increased to $168.2 million from the $123.0 million reported for the third quarter of 1999, primarily for the same reasons. EBITDAX for the first nine months of 2000 was $238.7 million, compared to $151.3 million for the comparable period of 1999, an increase of 58%. Production. Total production for the first nine months of 2000 was 100.8 Bcfe compared to 93.1 Bcfe for the comparable prior-year period, an increase of 8%. Gas production increased to 87.9 Bcf compared to 79.7 Bcf for the comparable prior-year period, an increase of 10%. Oil production for the first nine months of 2000 decreased 4% to 2.15 MMBbls compared to 2.23 MMBbls for the first nine months of 1999. Oil and Gas Prices. On a natural gas equivalent basis, we received an average price of $3.11 per Mcfe for the first nine months of 2000, an increase of 40% from the $2.22 per Mcfe received for the first nine months of 1999. Gas production yielded an average price of $2.93 per Mcf, an increase of 36% compared to $2.16 per Mcf for the prior-year nine-month period. The average gas price for the first nine months of 2000 was reduced $.49 per Mcf as a result of Fixed-Price Contracts. The average gas price for the first nine months of 1999 was enhanced $.05 per Mcf as a result of the Fixed-Price Contracts in effect for that period. The average oil price for the first nine months of 2000 was $26.04 per Bbl compared to $15.35 per Bbl for the first nine months of 1999, an increase of 70%. Fixed-Price Contracts in effect during the first nine months of 2000 decreased the average oil price by $2.40 per Bbl. Fixed-Price Contracts in effect during the first nine months of 1999 decreased the average oil price by $.12 per Bbl. The combined effect of higher gas production and higher gas prices increased gas sales to $257.8 million for the first nine months of 2000 compared to $172.0 million for the first nine months of 1999. The net effect of lower oil production and higher oil prices increased oil sales to $56.0 million compared to $34.3 million reported for the prior-year nine-month period. The impact of Fixed-Price Contract settlements was to decrease oil and gas sales by $48.5 million for the nine months ended September 30, 2000 and to increase oil and gas sales by $3.7 million for the nine months ended September 30, 1999. See "Quantitative and Qualitative Disclosures About Market Risk." Change in Derivative Fair Value. Change in derivative fair value for the nine months ended September 30, 2000 was a net loss of $13.5 million which was comprised of a $6.9 million loss associated with certain derivatives not qualifying for hedge accounting, $.2 million of net losses relating to the ineffective portion of derivatives which qualified for hedge accounting, and $6.4 million of losses relating to the reversal of contract fair value gains and losses recognized in earnings prior to actual cash settlement. Change in derivative fair value for the nine months ended September 30, 1999 was a net 20 LOUIS DREYFUS NATURAL GAS CORP. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) loss of $8.2 million which included a $4.4 million loss associated with certain derivatives not qualifying for hedge accounting, $2.6 million of net gains relating to the ineffective portion of derivatives which qualified for hedge accounting, and $6.4 million of losses relating to the reversal of contract fair value gains and losses recognized in earnings prior to actual cash settlement. Despite certain Fixed-Price Contracts failing the effectiveness guidelines of SFAS 133 from time to time, our Fixed-Price Contracts continue to be highly effective in achieving the risk management objectives for which they were intended. Other Income. Other income for the first nine months of 2000 was $2.6 million compared to $11.5 million for the first nine months of 1999. This decrease was primarily the result of a nonrecurring pretax gain of $8.6 million recognized in 1999. Operating Costs. Operating costs for the first nine months of 2000 were comprised of $40.6 million of lease operating expenses and $19.6 million of production taxes. This compares to $38.2 million of lease operating expenses and $10.6 million of production taxes for the first nine months of 1999. The increase in production taxes is principally attributable to higher oil and gas prices. Lease operating expenses on a natural gas equivalent unit of production basis improved to $.40 per Mcfe compared to $.41 per Mcfe for the nine months ended September 30, 1999. General and Administrative Expense. G&A for the first nine months of 2000 was $17.4 million, compared to $17.7 million reported for the first nine months of 1999. On a natural gas equivalent unit of production basis, G&A decreased to $.17 per Mcfe for the first nine months of 2000 compared to $.19 per Mcfe for the first nine months of 1999, due to growth in production without corresponding increases in G&A costs. Exploration Costs. Exploration costs, comprised of geological and geophysical costs, exploratory dry holes and leasehold impairment costs, increased to $19.4 million for the nine months ended September 30, 2000, compared to $11.1 million for the nine months ended September 30, 1999. The 2000 amount consists of $9.1 million of dry hole costs, $4.3 million of seismic acquisition and other geological and geophysical costs and $6.0 million of leasehold costs. The 1999 amount consists of $1.1 million of dry hole costs, $2.9 million of seismic acquisition and other geological and geophysical costs and $7.1 million of leasehold costs. Depreciation, Depletion and Amortization. DD&A for the first nine months of 2000 was $94.1 million compared to $86.6 million for the first nine months of 1999. This increase in DD&A is attributable to an increase in the oil and gas DD&A rate and higher gas production. The oil and gas DD&A rate per equivalent unit of production was $.90 per Mcfe for the first nine months of 2000 compared to $.89 per Mcfe for the first nine months of 1999. This increase was primarily the result of an increase in production from certain higher cost 21 LOUIS DREYFUS NATURAL GAS CORP. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) properties and the impact of the Costilla acquisition. Impairment. For the nine month period ended September 30, 2000, an impairment charge of $4.6 million was recorded due to downward reserve revisions for two single-well offshore fields drilled in 1998. There was no impairment charge recorded for the first nine months of 1999. We are unaware of any other fields which may be impaired because of performance or other reasons. However, future impairments may be recognized as a result of numerous factors, all of which are beyond our ability to control or predict. Interest Expense. Interest expense for the nine months ended September 30, 2000 was $30.3 million compared to $30.6 million for the nine months ended September 30, 1999. The net impact of interest rate swaps in effect for the first nine months of 2000 and 1999 was to decrease interest expense by $1.4 million and increase interest expense by $.2 million, respectively. See "Capital Resources and Liquidity - Credit Facility." Income Taxes. For the first nine months of 2000, a tax provision of $29.5 million was recorded on pretax income of $76.9 million, an effective rate of 38%. This compares to a tax provision of $5.8 million provided on pretax income of $14.6 million, an effective rate of 40%, for the first nine months of 1999. The effective rate for the first nine months of 1999 was higher than the statutory rate primarily due to the effect of permanent differences created by differences in the book and tax bases of acquired assets. CAPITAL RESOURCES AND LIQUIDITY Cash Flows. Our business of acquiring, exploring and developing oil and gas properties is capital intensive. Our ability to grow our reserve base is contingent, in part, upon the ability to generate cash flows from operating activities and to access outside sources of capital to fund our investing activities. For the nine months ended September 30, 2000 and 1999, we expended $354.1 million and $128.6 million, respectively, in oil and gas property acquisition, exploration and development activities, representing substantially all of the cash flow we invested during each nine-month period. See "Commitments and Capital Expenditures." Cash flows from operating activities before changes in working capital for the nine months ended September 30, 2000 and 1999 were $205.7 million and $120.4 million, representing 58% and 94%, respectively, of the oil and gas property investments made for each period. Substantially all of the cash flows from operating activities are generated from oil and gas sales which are highly dependent upon oil and gas prices. Significant decreases in the market prices of oil and gas could result in reduction of cash flows from operating activities, which in turn could impact the amount of capital investment. Cash flows from financing activities for the first nine months of 2000 reflected a net source of cash of $171.9 million compared to a $4.0 million source of cash for the first nine months of 1999. This increase is related to borrowings made during the period to fund proved reserve acquisitions closed 22 LOUIS DREYFUS NATURAL GAS CORP. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) during the year, including the acquisition of properties from Costilla Energy, Inc., discussed below. Financing cash flows also include the proceeds from the issuance of common stock in July 2000, as discussed below. Historically, we have relied upon availability under various revolving bank credit facilities and proceeds from the issuance of senior and subordinated notes to fund our investing activities. Credit Facility. We have a revolving credit facility (the "Credit Facility") with a syndicate of banks which provides up to $450 million in borrowings (the "Commitment"). Letters of credit are limited to $75 million of this availability. The Credit Facility allows us to draw on the full $450 million credit line without restrictions tied to periodic revaluations of our oil and gas reserves provided we continue to maintain an investment grade credit rating from either Standard & Poor's Ratings Service or Moody's Investors Service. We presently have unsecured senior credit ratings of BBB and Baa3 from Standard & Poor's and Moody's, respectively. A borrowing base can be required only upon the vote by a majority in interest of the lenders after the loss of an investment grade credit rating. No principal payments are required under the Credit Facility prior to termination on October 14, 2002. We have relied upon the Credit Facility to provide funds for acquisitions and drilling activities, and to provide letters of credit to meet margin requirements under Fixed-Price Contracts. As of September 30, 2000, there was $350.6 million of principal and $34.8 million of letters of credit outstanding under the Credit Facility. See "-- Common Stock Offering." We have the option of borrowing at a LIBOR-based interest rate or the Base Rate (approximating the prime rate). The LIBOR interest rate margin and the facility fee payable under the Credit Facility are subject to a sliding scale based on our senior debt credit rating. At September 30, 2000, the applicable interest rate was LIBOR plus 30 basis points. The Credit Facility also requires the payment of a facility fee equal to 15 basis points of the Commitment. The average interest rate for borrowings under the Credit Facility was 7.0% as of September 30, 2000. Including the effect of interest rate swaps which hedge a portion of the interest rate exposure attributable to this facility, the effective interest rate was 6.4%. See the Notes to Consolidated Financial Statements included in our Annual Report on Form 10-K for the year ended December 31, 1999 for an expanded discussion of our interest rate swaps. The Credit Facility contains various affirmative and restrictive covenants which, among other things, limit total indebtedness to $700 million ($625 million of senior indebtedness) and require us to meet certain financial tests. Borrowings under the Credit Facility are unsecured. Other Lines of Credit. We have certain other uncommitted lines of credit which aggregated $50.1 million as of September 30, 2000. These short-term lines of credit are unsecured and primarily used to meet margin requirements under Fixed-Price Contracts and for working capital purposes. As of September 30, 2000, there was $17.0 million of indebtedness and $.1 million of letters of credit outstanding under these credit lines. Repayment of this 23 LOUIS DREYFUS NATURAL GAS CORP. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) indebtedness is expected to be made through Credit Facility availability. 6 7/8% Senior Notes due 2007. In December 1997, we issued $200 million principal amount, $198.8 million net of discount, of 6 7/8% Senior Notes due 2007. Interest is payable semi-annually on June 1 and December 1. The associated indenture agreement contains restrictive covenants which place limitations on the amount of liens and our ability to enter into sale and leaseback transactions. 9 1/4% Subordinated Notes due 2004. In June 1994, we issued $100 million principal amount, $98.5 million net of discount, of 9 1/4% Senior Subordinated Notes due 2004 (the "Subordinated Notes"). Interest is payable semi-annually on June 15 and December 15. The associated indenture agreement contains certain restrictive covenants which limit, among other things, the prepayment of the Subordinated Notes, the incurrence of additional indebtedness, the payment of dividends and the disposition of assets. In the second quarter of 2000, we purchased $6.3 million face amount of the Subordinated Notes in the open market, leaving $93.7 million of principal outstanding at September 30, 2000. Common Stock Offering. On June 28, 2000, we sold 2.4 million shares of our common stock at $31.00 per share ($29.53 per share net of underwriting discount) in a public offering. Proceeds from the offering of $70.9 million received in July 2000 were applied to reduce a majority of the indebtedness incurred in connection with the acquisition of properties from Costilla Energy, Inc. described below. In addition, an indirect wholly-owned subsidiary of S.A. Louis Dreyfus et Cie sold 1.6 million shares of our common stock in the offering. Subsequent to the offering, S.A. Louis Dreyfus et Cie through its subsidiaries owned 19.2 million of our common shares, or approximately 44% of the total issued and outstanding common shares. We believe that the borrowing capacity available under the Credit Facility, combined with our internally generated operating cash flows, will be adequate to finance the capital expenditure program planned for the balance of 2000, and to meet margin requirements under Fixed-Price Contracts. See "Commitments and Capital Expenditures" and "Quantitative and Qualitative Disclosures About Market Risk." At September 30, 2000, we had negative working capital of $31.4 million and a current ratio of .8 to 1. This working capital deficit is the result of recording the fair value of Fixed-Price Contract settlements scheduled to occur over the subsequent twelve-month period based on market prices for oil and gas as of the balance sheet date and option valuations. Because present accounting rules do not provide for the accrual of the future cash flow transactions the contracts were designed to hedge, an apparent working capital deficit is created which does not, in our opinion, accurately depict our true working capital position or liquidity. These settlement amounts are not due and payable until the monthly period that the related underlying hedged 24 LOUIS DREYFUS NATURAL GAS CORP. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) transaction occurs. In some cases, the recorded liability for certain contracts significantly exceeds the total settlement amounts that would be paid to a counterparty based on prices in effect at the balance sheet date due to option time value. For derivatives which are held to maturity, this time value has no direct relationship to actual future contract settlements and consequently does not represent a liability which will be settled in cash. Short-term liquidity has actually improved as a result of the increase in oil and gas prices. Excluding the current portion of Fixed-Price Contracts from current assets and liabilities, working capital was $30.6 million and the current ratio was 1.3 to 1. Total long-term debt outstanding at September 30, 2000 was $660.7 million. Long-term debt as a percentage of total capitalization was 55%. COMMITMENTS AND CAPITAL EXPENDITURES Our primary business strategy is to generate strong and consistent growth in reserves, production, operating cash flows and earnings through a balanced program of exploration and development drilling and strategic acquisitions of oil and gas properties. For the nine months ended September 30, 2000, we invested $158.6 million in development activities and $37.1 million on exploration activities. This expenditure level resulted in the drilling of 362 development wells and nine exploratory wells. Of these wells, 347 development wells and five exploratory wells were successfully completed as producers, for a completion success rate of 96% and 56%, respectively (an overall success rate of 95%). In addition, we invested $158.4 million in proved oil and gas property acquisitions during the first nine months of 2000. The more significant transaction involved the acquisition of proved and unproved oil and gas properties from Costilla Energy, Inc. in June 2000. The Costilla properties consisted of 135 Bcfe of net proved reserves contained within 1,011 gross (607 net) producing wells. The acquired properties are primarily located within our Core Areas. The $126 million purchase price, net of estimated purchase price adjustments, was initially funded through availability under the Credit Facility. See "Capital Resources and Liquidity -- Common Stock Offering." The acquisition has been accounted for using the purchase method of accounting. For the balance of 2000, we currently plan to invest an additional $24 million in connection with our drilling program focused principally in our Core Areas. Actual levels of drilling and acquisition expenditures may vary due to many factors, including drilling results, new drilling opportunities, oil and natural gas prices and acquisition opportunities. We continue to actively search for additional attractive oil and gas property acquisitions, but are not able to predict the timing or amount of additional capital expenditures which may ultimately be employed in acquisitions during 2000. 25 LOUIS DREYFUS NATURAL GAS CORP. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) FOURTH QUARTER 2000 OUTLOOK The following fourth quarter estimates have been prepared based on current expectations for production, revenue and expenses from investment activity planned under our 2000 capital program. Revenues. Natural gas and crude oil production are each expected to increase between 2% and 6% from levels realized for the third quarter of 2000. Based on current market prices for oil and gas, we expect that natural gas prices at the wellhead will average $.08 to $.12 per Mcf less than the average of the last three trading days for the NYMEX Henry Hub index (NYMEX L3D). The NYMEX L3D price for October 2000 was $5.30 per MMBtu and for November 2000 was $4.62 per MMBtu. Crude oil prices are expected to average $1.30 to $1.50 per Bbl less than the average NYMEX West Texas Intermediate price (WTI). The WTI price for October 2000 was $32.94. Approximately 6 Bcf of natural gas in the fourth quarter is hedged by fixed-price contracts. The weighted average contract price, including the amortization of deferred gains, is expected to be approximately $2.96 per Mcf, before the impact of basis. Contract basis is expected to have the effect of reducing the average contract price by $.02 to $.06 per Mcf. The amount of change in derivative fair value to be reported in revenues for the fourth quarter cannot be predicted due to contract valuations and effectiveness testing which are performed as of the end of the year. Expenses. Lease operating expenses for the fourth quarter are expected to average approximately $.42 per Mcfe. Production taxes are expected to average about 5.8% of wellhead sales. DD&A for the fourth quarter will be dependent upon the results of the Company's year-end reserve study. However, the fourth quarter DD&A rate is not expected to change materially from the average rate for the first nine months of 2000. General and administrative costs are expected to be approximately $6.5 million in the fourth quarter of 2000. Exploration costs could range between $5.0 million and $13.5 million, depending upon the level of success experienced with fourth quarter exploration drilling. We do not expect to recognize an impairment charge in the fourth quarter of 2000; however, impairments cannot be predicted with any certainty. The potential for a fourth quarter impairment charge will be largely dependent upon the results of the year-end reserve study and year-end prices. Interest expense is expected to be approximately $10.5 million for the fourth quarter of 2000. We expect that the effective income tax rate for the fourth quarter will approximate 39%. The current tax provision in the fourth quarter of 2000 is expected to represent between 5% and 13% of the total tax provision primarily as a result of the deduction of intangible drilling costs and utilization of acquired tax carryforwards. 26 LOUIS DREYFUS NATURAL GAS CORP. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK GENERAL Our results of operations and operating cash flows are impacted by changes in market prices for oil and gas and changes in market interest rates. To mitigate a portion of our exposure to adverse market changes, we have entered into Fixed-Price Contracts and interest rate swaps. Each Fixed-Price Contract and interest rate swap has been entered into as a hedge of oil and gas price risk or interest rate risk and not for trading purposes. Information regarding our market exposures, Fixed-Price Contracts, interest rate swaps and certain other financial instruments is provided below. All information is presented in U.S. Dollars. FIXED-PRICE CONTRACTS Description of Contracts. Our Fixed-Price Contracts are comprised of long-term physical delivery contracts, energy swaps, collars, futures contracts and basis swaps. These contracts allow us to predict with greater certainty the effective oil and gas prices to be received for our hedged production and benefit us when market prices are less than the fixed prices provided in the Fixed-Price Contracts. However, we will not benefit from market prices that are higher than the fixed prices in these contracts for our hedged production. For the years ended December 31, 1999, 1998 and 1997, Fixed-Price Contracts hedged 55%, 50% and 60%, respectively, of our natural gas production and 19%, 16% and 33%, respectively, of our oil production. For the nine months ended September 30, 2000, Fixed-Price Contracts hedged 53% of our natural gas production and 54% of our oil production. As of September 30, 2000, Fixed-Price Contracts are in place to hedge 157 Bcf of our estimated future natural gas production; 6 Bcf are hedged for the remainder of fiscal 2000. Reference is made to our Annual Report on Form 10-K for the year ended December 31, 1999 for a more detailed discussion of the Fixed-Price Contracts. The following table summarizes the estimated volumes, fixed prices, fixed-price sales and future net revenues attributable to the Fixed-Price Contracts as of September 30, 2000. We expect the prices to be realized for our hedged production to vary from the prices shown in the following table due to basis, which is the differential between the floating price paid under each energy swap contract, or the cost of gas to supply physical delivery contracts and the price received at the wellhead for our production. Basis differentials are caused by differences in location, quality, contract terms, timing and other variables. Future net revenues for any period are determined as the differential between the fixed prices provided by Fixed-Price Contracts and forward market prices as of September 30, 2000, as adjusted for basis. Future net revenues change with changes in market prices and basis. 27 LOUIS DREYFUS NATURAL GAS CORP. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK (continued)

28 LOUIS DREYFUS NATURAL GAS CORP. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK (continued) The estimates of future net revenues (losses) from Fixed-Price Contracts are computed based on the difference between the prices provided by the Fixed-Price Contracts and forward market prices as of the specified date. The market for natural gas beyond a five year horizon is illiquid and published market quotations are not available. We have relied upon near-term market quotations, longer-term over-the-counter market quotations and other market information to determine future net revenue estimates. Forward market prices for natural gas are dependent upon supply and demand factors in the forward market and are subject to significant volatility. The future net revenue estimates shown above are subject to change as forward market prices change. The estimated fair values of our Fixed-Price Contracts as of September 30, 2000 and December 31, 1999 are provided below. The associated carrying values of these contracts are equal to the estimated fair values for each period presented.

LOUIS DREYFUS NATURAL GAS CORP 10-Q