1
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q/A
Amendment No. 1
[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934.
For the quarterly period ended September 30, 1999
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 .
----- -----
40,225,651 shares of common stock, $.01 par value, issued and outstanding at
November 10, 1999.
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LOUIS DREYFUS NATURAL GAS CORP.
Table of Contents
PART I. FINANCIAL INFORMATION Page
Item 1 -- CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
Consolidated Balance Sheets:
September 30, 1999 and December 31, 1998 . . . . . . . . . . . . . . . 3
Consolidated Statements of Operations:
Three months and nine months ended September 30, 1999 and 1998 . . . . 5
Consolidated Statements of Cash Flows:
Nine months ended September 30, 1999 and 1998. . . . . . . . . . . . . 6
Condensed Notes to Consolidated Financial Statements . . . . . . . . . . 7
Item 2 -- MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS. . . . . . . . . . . . . . . . . . . . . . .12
Item 3 -- QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK . .27
PART II. OTHER INFORMATION . . . . . . . . . . . . . . . . . . . . .32
3
LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED BALANCE SHEETS
(dollars in thousands)
A S S E T S
September 30, December 31,
1999 1998
------------- -------------
(restated,
unaudited)
CURRENT ASSETS
Cash and cash equivalents. . . . . . . . . . . . $ 6,055 $ 2,539
Receivables:
Oil and gas sales . . . . . . . . . . . . . . . 47,033 37,381
Joint interest and other, net . . . . . . . . . 8,702 11,725
Costs reimbursable by insurance . . . . . . . . -- 7,200
Fixed-price contracts and other derivatives. . . 48,352 23,338
Prepaids and other . . . . . . . . . . . . . . . 3,057 4,572
------------- -------------
Total current assets. . . . . . . . . . . . . . 113,199 86,755
------------- -------------
PROPERTY AND EQUIPMENT, at cost, based on
successful efforts accounting. . . . . . . . . 1,606,324 1,519,296
Less accumulated depreciation, depletion
and amortization . . . . . . . . . . . . . . . (492,530) (434,693)
------------- -------------
1,113,794 1,084,603
------------- -------------
OTHER ASSETS
Fixed-price contracts and other derivatives. . . 19,345 107,302
Other, net . . . . . . . . . . . . . . . . . . . 4,374 5,148
------------- -------------
23,719 112,450
------------- -------------
$ 1,250,712 $ 1,283,808
============= =============
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LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED BALANCE SHEETS (continued)
(dollars in thousands)
L I A B I L I T I E S A N D S T O C K H O L D E R S ' E Q U I T Y
September 30, December 31,
1999 1998
------------- -------------
(unaudited)
CURRENT LIABILITIES
Accounts payable . . . . . . . . . . . . . . . . $ 32,961 $ 38,222
Accrued liabilities. . . . . . . . . . . . . . . 17,133 10,696
Revenues payable . . . . . . . . . . . . . . . . 11,241 10,940
Fixed-price contracts and other derivatives. . . 15,229 2,292
------------- -------------
Total current liabilities . . . . . . . . . . . 76,564 62,150
------------- -------------
LONG-TERM DEBT . . . . . . . . . . . . . . . . . 604,334 596,844
------------- -------------
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred revenue . . . . . . . . . . . . . . . . 14,054 15,551
Deferred income taxes. . . . . . . . . . . . . . 37,383 65,116
Fixed-price contracts and other derivatives. . . 21,430 5,350
Other. . . . . . . . . . . . . . . . . . . . . . 21,469 19,336
------------- -------------
94,336 105,353
------------- -------------
STOCKHOLDERS' EQUITY
Preferred stock, par value $.01; 10 million
shares authorized; no shares outstanding. . . . -- --
Common stock, par value $.01; 100 million
shares authorized; issued and outstanding,
40,223,401 and 40,109,758 shares, respectively. 402 401
Additional paid-in capital . . . . . . . . . . . 420,750 419,075
Retained earnings. . . . . . . . . . . . . . . . 15,508 6,735
Accumulated other comprehensive income . . . . . 38,818 93,250
------------- -------------
475,478 519,461
------------- -------------
$ 1,250,712 $ 1,283,808
============= =============
See accompanying notes to consolidated financial statements.
5
LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)
(in thousands, except per share data)
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ ------------------
1999 1998 1999 1998
-------- -------- -------- --------
(restated) (restated)
REVENUES
Oil and gas sales. . . . . . . . . . $ 77,780 $ 67,472 $206,241 $204,867
Change in derivative fair value. . . 2,868 -- (8,242) --
Other income . . . . . . . . . . . . 9,298 1,362 11,492 3,914
--------- -------- -------- --------
89,946 68,834 209,491 208,781
--------- -------- -------- --------
EXPENSES
Operating costs. . . . . . . . . . . 17,348 16,495 48,801 50,560
General and administrative . . . . . 6,050 6,439 17,668 18,978
Exploration costs. . . . . . . . . . 4,979 9,707 11,131 26,647
Depreciation, depletion and
amortization . . . . . . . . . . . 29,423 34,718 86,623 101,009
Impairment . . . . . . . . . . . . . -- -- -- 9,864
Interest . . . . . . . . . . . . . . 10,400 10,132 30,647 30,550
--------- -------- -------- --------
68,200 77,491 194,870 237,608
--------- -------- -------- --------
Income (loss) before income taxes. . 21,746 (8,657) 14,621 (28,827)
Income tax provision (benefit) . . . 8,698 (3,218) 5,848 (10,954)
NET INCOME (LOSS). . . . . . . . . . $ 13,048 $ (5,439) $ 8,773 $(17,873)
========= ======== ======== ========
Net income (loss) per share -
basic and diluted . . . . . . . . . $ .32 $ (.14) $ .22 $ (.45)
========= ======== ======== ========
Weighted average number of common
shares:
Basic. . . . . . . . . . . . . . . . 40,161 40,110 40,131 40,106
========= ======== ======== ========
Diluted. . . . . . . . . . . . . . . 40,590 40,110 40,360 40,106
========= ======== ======== ========
See accompanying notes to consolidated financial statements.
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LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
(in thousands)
Nine Months Ended
September 30,
------------------
1999 1998
-------- --------
(restated)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 8,773 $(17,873)
Items not affecting cash flows:
Depreciation, depletion and amortization . . . . . . . . . . . . . . . . 86,623 101,009
Impairment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -- 9,864
Deferred income taxes. . . . . . . . . . . . . . . . . . . . . . . . . . 5,628 (11,779)
Exploration costs. . . . . . . . . . . . . . . . . . . . . . . . . . . . 11,131 26,647
Change in derivative fair value. . . . . . . . . . . . . . . . . . . . . 8,242 --
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46 359
Net change in operating assets and liabilities:
Accounts receivable. . . . . . . . . . . . . . . . . . . . . . . . . . . 571 30,369
Prepaids and other . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,515 7,318
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5,261) (19,812)
Accrued liabilities. . . . . . . . . . . . . . . . . . . . . . . . . . . 5,437 (3,617)
Revenues payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . 301 (5,055)
-------- --------
123,006 117,430
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Exploration and development expenditures. . . . . . . . . . . . . . . . . (94,347) (191,455)
Acquisition of oil and gas properties . . . . . . . . . . . . . . . . . . (34,287) (5,197)
Additions to other property and equipment . . . . . . . . . . . . . . . . (1,537) (2,528)
Proceeds from sale of property and equipment. . . . . . . . . . . . . . . 7,048 1,733
Change in other assets. . . . . . . . . . . . . . . . . . . . . . . . . . (353) (893)
-------- --------
(123,476) (198,340)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from bank borrowings . . . . . . . . . . . . . . . . . . . . . . 328,469 416,614
Repayments of bank borrowings . . . . . . . . . . . . . . . . . . . . . . (320,969) (387,514)
Proceeds from stock options exercised . . . . . . . . . . . . . . . . . . 1,601 324
Change in deferred revenue. . . . . . . . . . . . . . . . . . . . . . . . (1,497) 9,393
Change in gains from price-risk management activities . . . . . . . . . . (3,343) 38,770
Change in other long-term liabilities . . . . . . . . . . . . . . . . . . (275) 2,994
-------- --------
3,986 80,581
-------- --------
Change in cash and cash equivalents . . . . . . . . . . . . . . . . . . . 3,516 (329)
Cash and cash equivalents, beginning of period. . . . . . . . . . . . . . 2,539 5,538
-------- --------
Cash and cash equivalents, end of period. . . . . . . . . . . . . . . . . $ 6,055 $ 5,209
======== ========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Interest paid, net of capitalized interest. . . . . . . . . . . . . . . . $ 24,230 $ 21,518
Income taxes paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . 753 255
-------- --------
$ 24,983 $ 21,773
======== ========
See accompanying notes to consolidated financial statements.
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LOUIS DREYFUS NATURAL GAS CORP.
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
SEPTEMBER 30, 1999
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
only 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, 1999 are not necessarily indicative of
the results to be expected for the full year. Certain reclassifications have
been made to the prior year statements to conform with the current year
presentation. Reference is made to the Company's Annual Report on Form 10-K,
as amended, for the year ended December 31, 1998 for an expanded discussion of
the Company's financial disclosures and accounting policies.
NOTE 2 -- RESTATED FINANCIAL STATEMENTS
The Company restated its financial results for the three months and nine
months ended September 30, 1999 to adjust amounts previously reported in
"change in derivative fair value" in the respective statements of operations.
The adjustment is primarily the result of a change in the calculation for
reversing contract fair value gains and losses recognized in "change in
derivative fair value" in periods prior to when actual cash settlements under
the contracts occur. This change was made based on new implementation
guidance relating to SFAS 133, as hereinafter defined, received from the
Company's independent auditors. The Company believes the revised calculation
results in a better allocation of the reversals of those gains and losses to
future periods. The accompanying financial statements as of September 30,
1999, and for the three months and nine months then ended, have been restated
to reflect this change. The effect of the restatement is provided below.
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LOUIS DREYFUS NATURAL GAS CORP.
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued)
SEPTEMBER 30, 1999
Three Months Ended Nine Months Ended
September 30, 1999 September 30, 1999
----------------------- -----------------------
As As
As Previously As Previously
Restated Reported Restated Reported
---------- ---------- ---------- ----------
(in thousands, except per share data)
Statement of Operations Data:
Change in derivative fair value. . . . . . . . $ 2,868 $ (2,510) $ (8,242) $ (1,313)
Total revenues . . . . . . . . . . . . . . . . 89,946 84,568 209,491 216,420
Income before income taxes . . . . . . . . . . 21,746 16,368 14,621 21,550
Income tax provision . . . . . . . . . . . . . 8,698 6,444 5,848 8,620
Net income . . . . . . . . . . . . . . . . . . 13,048 9,924 8,773 12,930
Net income per share - basic . . . . . . . . . .32 .25 .22 .32
Net income per share - diluted . . . . . . . . .32 .24 .22 .32
As of September 30, 1999
------------------------
As
As Previously
Restated Reported
---------- ----------
(in thousands)
Balance Sheet Data:
Deferred income taxes. . . . . . . . . . . . . . . . . . . . . . . . $ 37,383 $ 37,522
Total deferred credits and other liabilities . . . . . . . . . . . . 94,336 94,475
Retained earnings. . . . . . . . . . . . . . . . . . . . . . . . . . 15,508 19,665
Accumulated other comprehensive income . . . . . . . . . . . . . . . 38,818 34,522
Total stockholders' equity . . . . . . . . . . . . . . . . . . . . . 475,478 475,339
NOTE 3 -- HEDGING
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. It requires
that all derivative instruments be recognized as assets or liabilities in the
statement of financial position, measured at fair value. The accounting for
changes in the fair value of a derivative depends on the intended use of the
derivative and the resulting designation. Designation is established at the
inception of a derivative, but redesignation is permitted. For derivatives
designated as cash flow hedges, changes in fair value are recognized in other
comprehensive income until the hedged item is recognized in earnings. Hedge
effectiveness is measured at least quarterly based on the relative changes in
fair value between the derivative contract and the hedged item over time. Any
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LOUIS DREYFUS NATURAL GAS CORP.
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued)
SEPTEMBER 30, 1999
change in fair value resulting from ineffectiveness, as defined by SFAS 133,
is recognized immediately in earnings. Substantially all of the Company's
Fixed-Price Contracts and interest rate swaps were designated as cash flow
hedges. Changes in the fair value of derivative instruments which are not
designated as cash flow hedges, or are ineffective, are recorded in earnings
as the changes occur. Earnings for the three-months and nine-months ended
September 30, 1999 included net gains of $2.9 million and net charges of $8.2
million, respectively, which are comprised of gains of $2.1 million and $.7
million, respectively, of changes in fair value for Fixed-Price Contracts not
designated as cash flow hedges, $1.3 million and $2.6 million, respectively,
of net gains relating to Fixed-Price Contract hedge ineffectiveness, $.2
million of gains and $11.3 million of losses, respectively, attributable to a
loss of effectiveness for certain cash flow hedges, and losses of $.7 million
and $6.4 million, respectively, related to the reversal of contract fair value
gains and losses recognized in earnings prior to actual settlement (see Note 2
- -- Restated Financial Statements). In addition, earnings include a $6.2
million pretax gain attributable to an increase in derivative fair value from
January 1, 1999 to January 13, 1999 (see discussion below).
Pursuant to the provisions of SFAS 133, all hedging designations and the
methodology for determining hedge ineffectiveness must be documented at the
inception of the hedge, and, upon the initial adoption of the standard,
hedging relationships must be designated anew. The documentation must also
indicate the risk management intent for entering into the hedging arrangement.
The Company believed that it complied with the spirit and intent of the
provisions of the standard with respect to documentation. However, in
connection with the review of the Company's public filings by the Staff of the
Securities and Exchange Commission in September 1999, the Company's
documentation was determined to be insufficient as of the October 1, 1998 date
of adoption of SFAS 133. Therefore, the Company was precluded from being able
to utilize the special provisions of hedge accounting for the period from
January 1, 1999 to January 13, 1999, the date the Company's documentation was
determined to be sufficient in relation to the formal documentation
requirements of the standard. As a result, the change in fair value of all
the Company's derivatives during this period was required to be reported in
results of operations, rather than in other comprehensive income. The
accompanying financial statements as of September 30, 1999, and for the
nine-month period then ended, reflect this accounting. Change in derivative
fair value for the nine months ended September 30, 1999 includes a $6.2
million pretax gain ($3.7 million, net of tax) attributable to the change in
contract fair value occurring between January 1, 1999 and January 13, 1999.
NOTE 4 -- ACQUISITIONS
In late March 1999, the Company acquired additional working interests in
three offshore platforms for $20.5 million. The acquired interests included
21.4 Bcfe of proved reserves, approximately 90% of which were natural gas
reserves. Oil and gas production from the acquired properties at March 31,
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LOUIS DREYFUS NATURAL GAS CORP.
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued)
SEPTEMBER 30, 1999
1999 was approximately 17 MMcfe per day. In May 1999, the Company acquired
interests in six producing Lower Wilcox wells located in Lavaca County, Texas,
for $9 million. These acquired properties produced 3.5 MMcfe of oil and
natural gas per day with estimated proved reserves of 12 Bcfe at the date of
acquisition. The purchase method was used to account for both acquisitions.
NOTE 5 -- CONTINGENCIES
Litigation. In December 1995, the United States District Court for the
Western District of Oklahoma entered a $10.8 million judgment in favor of the
Company against Midcon Offshore, Inc. ("Midcon") in connection with non-
performance by Midcon under an agreement to purchase a certain offshore oil
and gas property. In January 1996, Midcon delivered a $10.8 million
promissory note to the Company secured by liens on assets of Midcon, in
settlement of disputes in connection with this litigation. Midcon paid $3.0
million to the Company prior to its filing for bankruptcy in December 1996.
In July 1999, an agreement was reached between the Company and the Trustee to
the Midcon bankruptcy case, which provided for the payment of $8.6 million to
the Company in satisfaction of its claims against the estate. The settlement
was approved by the Bankruptcy Court in August 1999 and payment was made to
the Company. Receipt of the settlement proceeds has been reflected in
earnings and operating cash flows in the third quarter of 1999.
In February 1995, a lawsuit was filed in the United States District Court in
Denver, Colorado, by KN Gas Supply Services, Inc. ("KNGSS"), requesting
declaratory judgment that KNGSS had the right to reduce the contract price for
gas produced from the Bowdoin Field, a property acquired by the Company in
1997, to market levels from October 1, 1993 forward. KNGSS alleged that it
was entitled to a refund of approximately $7.7 million for the period through
September 1996. KNGSS has not updated its refund claim through the present
date. A motion for summary judgment was filed by a predecessor to the Company
in July 1996, and in February 1998 the court ruled in favor of the Company and
against KNGSS. KNGSS subsequently filed an appeal which has been heard and is
under advisement by the Court. Although the Company cannot predict the
ultimate outcome of this proceeding, it will continue to vigorously defend its
interests in this case and does not expect the outcome of the case to have a
material adverse impact on its financial position or results of operations.
The Company was also a party to other litigation as of September 30, 1999.
One of the more significant of such legal claims was an alleged underpayment
of royalty of $2.8 million, plus damages. The Company is a defendant in
additional pending legal proceedings 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 believe that the outcome of these matters
will have a material adverse effect on the Company.
11
LOUIS DREYFUS NATURAL GAS CORP.
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued)
SEPTEMBER 30, 1999
NOTE 6 -- SUBSEQUENT EVENT
The Company was a party to a long-term natural gas physical delivery
contract with an independent power producer ("IPP") which sold electrical
power under a firm, fixed-price contract to Niagara Mohawk Corporation
("NIMO"), a New York state utility. As of September 30, 1999, this contract
hedged 50 Bcf of future natural gas production. The ability of the IPP to
perform its obligations to the Company was dependent on the continued
performance by NIMO of its power purchase obligations to the IPP. NIMO had
taken aggressive regulatory, judicial and contractual actions to curtail power
purchase obligations from IPPs generally, including the IPP counterparty to
the Company's gas contract. In settlement of litigation initiated by NIMO
against this IPP, an agreement was reached in late October 1999 between the
respective parties to terminate the power contract in exchange for a cash
payment from NIMO. In connection with this agreement, the Company agreed to
the termination of its gas contract with the IPP in exchange for a cash
payment to the Company of approximately $44 million. The carrying value of
this contract as of September 30, 1999 has been adjusted to reflect the
termination settlement amount provided in the agreement. The after-tax value
of the termination payment will remain in accumulated other comprehensive
income to be amortized into earnings over the original contract term. Closing
is anticipated to occur in November 1999. The termination payment proceeds
will be applied to reduce outstanding indebtedness.
NOTE 7 -- COMPREHENSIVE LOSS
Components of comprehensive loss for the three-month and the nine-month
periods ended September 30, 1999 and 1998, are as follows:
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ ------------------
1999 1998 1999 1998
-------- -------- -------- --------
Net income (loss). . . . . . . . . . $ 13,048 $ (5,439) $ 8,773 $(17,873)
Other comprehensive loss, net of tax:
Reclassification adjustments -
contract settlements. . . . . . . 641 -- (4,389) --
Change in fixed-price contract
and other derivative fair value. . (23,112) -- (50,043) --
-------- -------- -------- --------
Comprehensive loss . . . . . . . . . $ (9,423) $ (5,439) $(45,659) $(17,873)
======== ======== ======== ========
12
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
Overview
General. The Company's 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. The Company's activities
are geographically concentrated in its 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 "Core Areas"), where the Company
has significant expertise and where the Company benefits from operational
synergies. The Company's capital expenditure plans for 1999 include the
investment of approximately $170 million in these Core Areas. See "--
Commitments and Capital Expenditures."
The Company has a portfolio of fixed-price contracts comprised of long-term
physical delivery contracts, energy swaps, collars, basis swaps (collectively
"Fixed-Price Contracts"). As of September 30, 1999, the Company's Fixed-
Price Contracts hedged 223 Bcfe of future oil and gas production representing
17% of its estimated proved oil and gas reserves at December 31, 1998, at
escalating fixed prices. See "Quantitative and Qualitative Disclosures About
Market Risk."
Forward-Looking Statements. All statements in this document concerning the
Company other than purely historical information (collectively
"Forward-Looking Statements") reflect the current expectations of management
and are based on the Company's historical operating trends, its proved reserve
and Fixed-Price Contract positions and other information currently available
to management. Such Forward-Looking Statements include, among others,
statements regarding the Company's future drilling plans and objectives and
related exploration and development budgets, and number and location of
planned wells, and statements regarding the quality of the Company's
properties and potential reserve and production levels. These statements
assume, among other things, that no significant changes will occur in the
operating environment for the Company's oil and gas properties and that there
will be no material acquisitions or divestitures except as disclosed herein.
The Company cautions that the Forward-Looking Statements are subject to all
the risks and uncertainties incident to the acquisition, development and
marketing of, and exploration for, oil and gas reserves. These risks include,
but are not limited to, commodity price risks, counterparty risks,
environmental risks, drilling risks, reserve risks, and operations and
production risks. Certain of these risks are described herein and in the
Company's Annual Report on Form 10-K, as amended, for the year ended December
31, 1998. Moreover, the Company may make material acquisitions or
divestitures, modify its Fixed-Price Contract positions by entering into new
contracts or terminating existing contracts, or enter into financing
transactions. None of these can be predicted with certainty and, accordingly,
13
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
are not taken into consideration in the Forward-Looking Statements made
herein. Statements concerning Fixed-Price Contract, interest rate swap and
other financial instrument fair values and their estimated contribution to
future results of operations are based upon market information as of a
specific date. Such market information in certain cases is a function of
significant judgment and estimation. For all of the foregoing reasons, actual
results may vary materially from the Forward-Looking Statements and there is
no assurance that the assumptions used are necessarily the most likely. The
Company expressly disclaims any obligation or undertaking to release publicly
any updates regarding any changes in the Company's expectations with regard to
the subject matter of any Forward-Looking Statements or any changes in events,
conditions or circumstances on which any Forward-Looking Statements are based.
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.
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.
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.
14
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
Selected Operating Data. The following table provides certain operating
data relating to the Company's operations.
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ ------------------
1999 1998 1999 1998
-------- -------- -------- --------
OIL AND GAS SALES: (M$)
Wellhead oil sales . . . . . . . . . . $ 14,487 $ 10,436 $ 34,515 $ 33,462
Effect of Fixed-Price Contract
settlements (1). . . . . . . . . . . (259) -- (259) 496
-------- -------- -------- --------
Total oil sales. . . . . . . . . . . . $ 14,228 $ 10,436 $ 34,256 $ 33,958
======== ======== ======== ========
Wellhead natural gas sales . . . . . . $ 69,663 $ 49,410 $167,980 $155,956
Effect of Fixed-Price Contract
settlements (1). . . . . . . . . . . (6,111) 7,626 4,005 14,953
-------- -------- -------- --------
Total natural gas sales. . . . . . . . $ 63,552 $ 57,036 $171,985 $170,909
======== ======== ======== ========
PRODUCTION:
Oil production (MBbls) . . . . . . . . 730 877 2,232 2,615
Natural gas production (MMcf). . . . . 27,611 25,279 79,704 75,222
Net equivalent production (MMcfe). . . 31,989 30,543 93,094 90,914
Percent of oil production hedged by
Fixed-Price Contracts (%). . . . . . 20% 0% 7% 3%
Percent of gas production hedged by
Fixed-Price Contracts (%). . . . . . 77% 55% 62% 49%
AVERAGE SALES PRICE:
Oil price (per Bbl):
Wellhead price . . . . . . . . . . . $ 19.85 $ 11.90 $ 15.47 $ 12.79
Effect of Fixed-Price Contract
settlements (1). . . . . . . . . . (.35) -- (.12) .19
-------- -------- -------- --------
Total. . . . . . . . . . . . . . . . $ 19.50 $ 11.90 $ 15.35 $ 12.98
======== ======== ======== ========
Natural gas price (per Mcf):
Wellhead price . . . . . . . . . . . $ 2.52 $ 1.96 $ 2.11 $ 2.07
Effect of Fixed-Price Contract
settlements (1) . . . . . . . . . . (.22) .30 .05 .20
-------- -------- -------- --------
Total. . . . . . . . . . . . . . . . $ 2.30 $ 2.26 $ 2.16 $ 2.27
======== ======== ======== ========
Average sales price (per Mcfe) . . . . $ 2.43 $ 2.21 $ 2.22 $ 2.25
15
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
SELECTED OPERATING DATA, continued
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ ------------------
1999 1998 1999 1998
-------- -------- -------- --------
OPERATING AND OVERHEAD COSTS: (per Mcfe)
Lease operating expenses . . . . . . . $ .40 $ .43 $ .41 $ .45
Production taxes . . . . . . . . . . . .14 .11 .11 .11
General and administrative . . . . . . .19 .21 .19 .21
-------- -------- -------- --------
Total. . . . . . . . . . . . . . . . . $ .73 $ .75 $ .71 $ .77
======== ======== ======== ========
CASH OPERATING MARGIN (per Mcfe) . . . $ 1.70 $ 1.46 $ 1.51 $ 1.48
DEPRECIATION, DEPLETION AND
AMORTIZATION - OIL AND GAS. . . . . . $ .89 $ 1.09 $ .89 $ 1.07
- -----------------------
<FN>
(1) - Represents the hedging results from the Company's Fixed-Price
Contracts. See "Quantitative and Qualitative Disclosures About Market
Risk - Fixed-Price Contracts." These amounts do not include any
change in derivative fair value included in results of operations for
the respective period.
RESULTS OF OPERATIONS -- THREE MONTHS ENDED SEPTEMBER 30, 1999 COMPARED TO
THREE MONTHS ENDED SEPTEMBER 30, 1998
Net Income and Cash Flows from Operating Activities. For the quarter ended
September 30, 1999, the Company realized net income of $13.0 million, or $.32
per share, on total revenue of $89.9 million. This compares to a net loss of
$5.4 million, or $.14 per share, on total revenue of $68.8 million for the
third quarter of 1998. Cash flows from operating activities (before working
capital changes) for the third quarter of 1999 grew 50% to $53.4 million
compared to $35.6 million for the third quarter of 1998. The increase in
earnings and operating cash flows for the quarter was primarily the result of
higher oil and gas prices and natural gas production, and a nonrecurring
pretax gain of $8.6 million recognized upon the settlement of certain
litigation. Earnings for the quarter ended September 30, 1999 also benefitted
from lower exploration costs and oil and gas depletion. Cash flows provided
by operating activities after consideration of the net change in working
capital increased to $62.6 million from the $32.3 million reported for the
third quarter of 1998, primarily due to the reasons identified above. In
addition, operating cash flows for the third quarter benefitted from an
increase in accounts payable.
16
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
Production. The Company produced 32.0 Bcfe for the third quarter of 1999
compared to 30.5 Bcfe for the prior year third quarter, an increase of 5%.
Gas production increased to 27.6 Bcf compared to 25.3 Bcf for the third
quarter of 1998, an increase of 9%. Oil production for the third quarter of
1999 decreased 17% to 730 MBbls compared to 877 MBbls for the prior-year third
quarter.
Oil and Gas Prices. On a natural gas equivalent basis, the Company received
an average price of $2.43 per Mcfe for the quarter ended September 30, 1999,
an increase of 10% from the $2.21 per Mcfe received for the third quarter of
1998. The Company's gas production yielded an average price of $2.30 per Mcf,
an increase of 2% compared to $2.26 per Mcf for the prior-year third quarter.
The Company's average gas price for the 1999 third quarter decreased $.22 per
Mcf as a result of the Company's hedging activities. The average gas price
for the third quarter of 1998 was enhanced $.30 per Mcf as a result of the
Fixed-Price Contracts in effect for that period. The average oil price for
the third quarter of 1999 was $19.50 per Bbl, an increase of 64% from the
$11.90 per Bbl received for the prior-year third quarter. The average oil
price for the third quarter of 1999 decreased $.35 per Bbl as a result of the
Fixed-Price Contracts in effect for that period. No fixed-price oil contracts
were in effect during the third quarter of 1998.
The net effect of higher gas production and higher gas prices increased gas
sales to $63.6 million for the third quarter of 1999 compared to $57.0 million
for the third quarter of 1998. The net effect of higher oil prices and lower
oil production increased oil sales to $14.2 million compared to $10.4 million
reported for the prior-year quarter. The aggregate impact of the Company's
Fixed-Price Contract settlements for each period was to decrease oil and gas
sales by $6.4 million for the quarter ended September 30, 1999 and to increase
gas sales by $7.6 million for the quarter ended September 30, 1998. See
"Quantitative and Qualitative Disclosures About Market Risk."
Change in Derivative Fair Value. The Company restated its financial results
for the three months ended September 30, 1999 to adjust amounts previously
reported in "change in derivative fair value" in the statement of operations.
The adjustment is primarily the result of a change in the calculation for
reversing contract fair value gains and losses recognized in "change in
derivative fair value" in periods prior to when actual cash settlements for
the contracts occur. This change was made based on new implementation guidance
relating to SFAS 133 received from the Company's independent auditors. The
Company believes the revised calculation results in a better allocation of the
reversals of those gains and losses to future periods. The accompanying
financial statements as of September 30, 1999 have been restated to reflect
this change. The effect of the restatement was to increase reported results
of operations by $5.4 million ($3.1 million, net of tax) for the quarter ended
September 30, 1999. Change in derivative fair value for the third quarter of
1999 included $2.1 million of gains associated with certain derivatives not
designated as cash flow hedges, $1.3 million of net gains relating to
17
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
Fixed-Price Contract hedge ineffectiveness, $.2 million
of gains attributable to a loss of effectiveness for certain cash flow hedges,
and $.7 million of losses related to the reversal of contract fair value gains
and losses recognized in earnings prior to actual settlement.
Other Income. Other income for the second quarter of 1999 was $9.3 million,
an increase of $7.9 million compared to $1.4 million for the third quarter of
1998. This increase was primarily the result of a nonrecurring pretax gain of
$8.6 million recognized upon the settlement of certain litigation.
Operating Costs. Operating costs for the third quarter of 1999 were
comprised of $12.9 million of lease operating expenses and $4.4 million of
production taxes. This compares to $13.3 million of lease operating expenses
and $3.2 million of production taxes for the third quarter of 1998. The
decrease in lease operating expenses is principally attributable to improved
operating efficiencies in the field and to a reduction in costs for services
and materials. Lease operating expenses on a natural gas equivalent unit of
production basis decreased to $.40 per Mcfe for the three months ended
September 30, 1999 compared to $.43 for the three months ended September 30,
1998. The increase in production taxes is primarily the result of higher oil
and gas prices for the third quarter of 1999 compared to the third quarter of
1998.
General and Administrative Expense. General and administrative expense
("G&A") for the third quarter of 1999 was $6.1 million, a decrease of 6% from
the prior-year third quarter amount of $6.4 million. This decrease is
primarily attributable to cost reduction measures implemented by the Company
in the first quarter of 1999. On a natural gas equivalent unit of production
basis, G&A decreased to $.19 per Mcfe for the 1999 third quarter compared to
$.21 per Mcfe for the 1998 third quarter.
Exploration Costs. Exploration costs, comprised of geological and
geophysical costs, exploratory dry holes and leasehold impairment costs, were
$5.0 million for the quarter ended September 30, 1999, compared to $9.7
million for the third quarter of 1998. The 1999 amount consists of $3.3
million of leasehold impairments, $1.6 million of seismic acquisition and
other geological and geophysical costs and $.1 million of dry hole costs. The
1998 amount consists of $.8 million of leasehold impairments, $1.3 million of
seismic acquisition costs and other geological and geophysical costs and $7.6
million of dry hole costs.
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization ("DD&A") for the third quarter of 1999 was $29.4 million compared
to $34.7 million for the prior-year third quarter. This decrease in DD&A is
attributable to a decrease in the oil and gas DD&A rate. The oil and gas DD&A
rate per equivalent unit of production was $.89 for the 1999 third quarter
compared to $1.09 for the third quarter of 1998. This decrease was primarily
the result of 1998 reserve additions added at favorable finding and
18
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
development costs and to an impairment charge recognized in the fourth quarter
of 1998.
Interest Expense. Interest expense for the third quarter of 1999 was $10.4
million compared to $10.1 million for the third quarter of 1998. The net
impact of interest rate swaps in effect for the third quarter of 1999 and 1998
was not material. See "Capital Resources and Liquidity Credit Facility."
Income Taxes. For the third quarter of 1999, the Company recorded a tax
provision of $8.7 million on pretax income of $21.7 million, an effective rate
of 40%. This compares to a tax benefit of $3.2 million on pretax loss of $8.7
million, an effective rate of 37%, for the third quarter of 1998.
RESULTS OF OPERATIONS -- NINE MONTHS ENDED SEPTEMBER 30, 1999 COMPARED TO NINE
MONTHS ENDED SEPTEMBER 30, 1998
Net Income and Cash Flows from Operating Activities. The Company realized
net income of $8.8 million, or $.22 per share, on total revenue of $209.5
million for the nine months ended September 30, 1999. This compares with a
net loss of $17.9 million, or $.45 per share, on total revenue of $208.8
million for the nine months ended September 30, 1998. Cash flows from
operating activities (before working capital changes) for the first nine
months of 1999 were $120.4 million, compared to $108.2 million for the first
nine months of 1998, an increase of 11%. The increase in earnings and
operating cash flows for the current nine-month period was primarily the
result of higher oil prices and natural gas production, and a nonrecurring
pretax gain of $8.6 million recognized upon the settlement of certain
litigation. Reductions in exploration costs and oil and gas depletion also
benefitted current period operating results. Cash flows provided by operating
activities after consideration of the net change in working capital increased
to $123.0 million from the $117.4 million reported for the third quarter of
1998, primarily due to the reasons identified above. In addition, operating
cash flows for the 1998 nine-month period benefitted from the collection of an
insurance claim receivable.
Production. The Company's total production was 93.1 Bcfe for the first nine
months of 1999 compared to 90.9 Bcfe for the comparable prior-year period, an
increase of 2%. Gas production increased to 79.7 Bcf compared to 75.2 Bcf for
the first nine months of 1998, an increase of 6%. Oil production for the
first nine months of 1999 decreased 15% to 2.2 MMBbls compared to 2.6 MMBbls
for the first nine months of 1998.
Oil and Gas Prices. On a natural gas equivalent basis, the Company received
an average price of $2.22 per Mcfe for the first nine months of 1999, a
decrease of 1% from the $2.25 per Mcfe received for the first nine months of
1998. The Company's gas production yielded an average price of $2.16 per Mcf,
a decrease of 5% compared to $2.27 per Mcf for the prior-year nine-month
period. The Company's average gas price for the first nine months of 1999 was
enhanced $.05 per Mcf as a result of the Company's hedging activities. The
19
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
average gas price for the first nine months of 1998 was enhanced $.20 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 1999 was $15.35 per Bbl
compared to $12.98 per Bbl for the first nine months of 1998, an increase of
18%. Fixed-Price Contracts in effect during the current year nine-month
period decreased the average oil price by $.12 per Bbl. Fixed-Price Contracts
in effect during the prior-year nine-month period increased the average oil
price by $.19 per Bbl.
The net effect of higher gas production and lower gas prices increased gas
sales to $172.0 million for the first nine months of 1999 compared to $170.9
million for the first nine months of 1998. The combination of lower oil
production and higher oil prices increased oil sales to $34.3 million compared
to $34.0 million reported for the prior-year nine-month period. The impact
of the Company's Fixed-Price Contract settlements was to increase oil and gas
sales by $3.7 million for the nine months ended September 30, 1999 and to
increase oil and gas sales by $15.4 million for the nine months ended
September 30, 1998. See "Quantitative and Qualitative Disclosures About
Market Risk."
Change in Derivative Fair Value. The Company restated its financial results
for the three months and nine months ended September 30, 1999 to adjust
amounts previously reported in "change in derivative fair value" in the
respective statements of operations. The adjustment is primarily the result
of a change in the calculation for reversing contract fair value gains and
losses recognized in "change in derivative fair value" in periods prior to
when actual cash settlements under the contracts occur. This change was made
based on new implementation guidance relating to SFAS 133 received from the
Company's independent auditors. The Company believes the revised calculation
results in a better allocation of the reversals of those gains and losses to
future periods. The accompanying financial statements as of September 30,
1999, and for the nine months then ended, have been restated to reflect this
change. The effect of restatement was to decrease reported results of
operations by $6.9 million ($4.2 million after tax) for the nine months ended
September 30, 1999. Change in derivative fair value for the nine months ended
September 30, 1999 included $.7 million of net gains associated with certain
derivatives not designated as cash flow hedges, $2.6 million of net gains
relating to Fixed-Price Contract hedge ineffectiveness, $11.3 million of
losses attributable to a loss of effectiveness for certain cash flow hedges,
and $6.4 million of losses related to the reversal of contract fair value
gains and losses recognized in earnings prior to actual settlement.
In addition, earnings include a $6.2 million pretax gain attributable to an
increase in derivative fair value from January 1, 1999 through January 13,
1999 (see discussion below).
Pursuant to the provisions of SFAS 133, all hedging designations and the
methodology for determining hedge ineffectiveness must be documented at the
inception of the hedge, and, upon the initial adoption of the standard,
20
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
hedging relationships must be designated anew. The documentation must also
indicate the risk management intent for entering into the hedging arrangement.
The Company believed that it complied with the spirit and intent of the
provisions of the standard with respect to documentation. However, in
connection with the review of the Company's public filings by the Staff of the
Securities and Exchange Commission in September 1999, the Company's
documentation was determined to be insufficient as of the October 1, 1998 date
of adoption of SFAS 133. Therefore, the Company was precluded from being able
to utilize the special provisions of hedge accounting for the period from
January 1, 1999 to January 13, 1999, the date the Company's documentation was
determined to be sufficient in relation to the formal documentation
requirements of the standard. As a result, the change in fair value of all
the Company's derivatives during these periods was required to be reported in
results of operations, rather than in other comprehensive income. The
accompanying financial statements as of September 30, 1999, and for the
nine-month period then ended, reflect this accounting. Change in derivative
fair value for the nine months ended September 30, 1999 reflected a $6.2
million pretax gain ($3.7 million, net of tax) attributable to the change in
contract fair value occurring between January 1, 1999 and January 13, 1999.
Other Income. Other income for the first nine months of 1999 was $11.5
million, an increase of $7.6 million compared to $3.9 million for the first
nine months of 1998. This increase was primarily the result of a nonrecurring
pretax gain of $8.6 million recognized upon the settlement of certain
litigation.
Operating Costs. Operating costs for the first nine months of 1999 were
comprised of $38.2 million of lease operating expenses and $10.6 million of
production taxes. This compares to $40.5 million of lease operating expenses
and $10.1 million of production taxes for the first nine months of 1998. The
decrease in lease operating expenses is principally attributable to improved
operating efficiencies in the field and to a reduction in costs for services
and materials. Lease operating expenses on a natural gas equivalent unit of
production basis improved to $.41 per Mcfe compared to $.45 per Mcfe for the
nine months ended September 30, 1998.
General and Administrative Expense. G&A for the first nine months of 1999
was $17.7 million compared to $19.0 million for the comparable prior-year
period. This decrease is primarily attributable to cost reduction measures
implemented by the Company in the first quarter of 1999. On a natural gas
equivalent unit of production basis, G&A decreased to $.19 per Mcfe for the
first nine months of 1999 compared to $.21 per Mcfe for the first nine months
of 1998.
Exploration Costs. Exploration costs, comprised of geological and
geophysical costs, exploratory dry holes and leasehold impairment costs, were
$11.1 million for the nine months ended September 30, 1999, compared to $26.6
million for the nine months ended September 30, 1998. The 1999 amount
21
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
consists of $7.1 million of leasehold impairments, $2.9 million of seismic
acquisition and other geological and geophysical costs and $1.1 million of dry
hole costs. The 1998 amount consists of $3.0 million of leasehold
impairments, $7.6 million of seismic acquisition and other geological and
geophysical costs and $16.0 million of dry hole costs.
Depreciation, Depletion and Amortization. DD&A for the first nine months of
1999 was $86.6 million compared to $101.0 million for the first nine months of
1998. This decrease in DD&A is attributable to a decrease in the oil and gas
DD&A rate. The oil and gas DD&A rate per equivalent unit of production was
$.89 for the first nine months of 1999 compared to $1.07 for the first nine
months of 1998. This decrease was primarily the result of 1998 reserve
additions added at favorable finding and development costs and to an
impairment charge taken in the fourth quarter of 1998.
Impairment. There was no impairment charge recorded for the first nine
months of 1999. For the nine month period ended September 30, 1998, the
Company recorded an impairment charge of $9.9 million as a result of an
impairment review conducted in response to a significant decline in market
prices for crude oil. This review identified one offshore field which had a
net book value in excess of estimated future net revenues resulting in the
impairment charge.
Interest Expense. Interest expense for the nine months ended September 30,
1999 of $30.6 million approximated the amount for the nine months ended
September 30, 1998. The net impact of interest rate swaps in effect for the
first nine months of 1999 and 1998 was immaterial. See "Capital Resources and
Liquidity Credit Facility."
Income Taxes. For the nine months ended September 30, 1999, the Company
recorded a tax provision of $5.8 million on pretax income of $14.6 million, an
effective rate of 40%. This compares to a tax benefit of $11.0 million
provided on a pretax loss of $28.8 million, an effective rate of 38%, for the
first nine months of 1998.
CAPITAL RESOURCES AND LIQUIDITY
Cash Flows. The Company's business of acquiring, exploring and developing
oil and gas properties is capital intensive. The Company's ability to grow
its reserve base is contingent, in part, upon its ability to generate cash
flows from operating activities and to access outside sources of capital to
fund its investing activities. For the nine months ended September 30, 1999
and 1998, the Company expended $128.6 million and $196.7 million,
respectively, in oil and gas property acquisition, exploration and development
activities, representing substantially all of the cash flow invested by the
Company during the nine-month periods. See "Commitments and Capital
Expenditures." Certain of these investments include expenditures which under
successful efforts accounting are expensed as incurred or if unsuccessful in
discovering new reserves. Investing activities for the nine months ended
22
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
September 30, 1999 and 1998 included $4.3 million and $24.4 million
respectively of costs which have been expensed as exploration costs in the
statement of operations for the corresponding periods. Cash flows from
operating activities before changes in working capital for the nine months
ended September 30, 1999 and 1998 were $120.4 million and $108.2 million,
representing 94% and 55%, 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 lower cash flows from operating activities,
which could, in turn, impact the amount of capital invested by the Company.
See "Quantitative and Qualitative Disclosures About Market Risk -- Fixed-Price
Contracts."
Cash flows from financing activities for the first nine months of 1999
reflected a net source of cash of $4.0 million compared to an $80.6 million
source of cash for the first nine months of 1998. Included in the amount for
1998 is $40.1 million of proceeds received in connection with the termination
of a Fixed-Price Contract. Historically, the Company has relied upon
availability under various revolving bank credit facilities and proceeds from
the issuance of senior and subordinated notes to fund its investing
activities.
The Company's EBITDAX increased to $151.3 million for the first nine months
of 1999 from $139.2 million for the first nine months of 1998. EBITDAX is
defined herein as income (loss) before interest, income taxes, DD&A,
impairments, exploration costs and change in derivative fair value. EBITDAX
increased primarily as a result of the receipt of an $8.6 million litigation
settlement and higher natural gas production. The Company believes 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.
Credit Facility. The Company has 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 such availability. The Credit Facility allows the Company to draw on the
full $450 million credit line without restrictions tied to periodic
revaluations of its oil and gas reserves provided the Company continues to
maintain an investment grade credit rating from either Standard & Poor's
Ratings Service or Moody's Investors Service. 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. The
23
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
Company has relied upon the Credit Facility to provide funds for acquisitions
and drilling activities, and to provide letters of credit to meet the
Company's margin requirements under Fixed-Price Contracts. As of September
30, 1999, the Company had $300.0 million of principal and $21.3 million of
letters of credit outstanding under the Credit Facility.
The Company has 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 the Company's senior debt credit rating. At September
30, 1999, 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 5.8% as of September 30, 1999. 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 5.7%. See the
Notes to Consolidated Financial Statements included in the Company's Annual
Report on Form 10-K, as amended, for the year ended December 31, 1998 for an
expanded discussion of the Company's 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 the Company to meet certain financial tests.
Borrowings under the Credit Facility are unsecured.
Other Lines of Credit. The Company has certain other unsecured lines of
credit available to it which aggregated $30.1 million as of September 30,
1999. Such 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, 1999, the Company had $4.7 million of
indebtedness and $.1 million of letters of credit outstanding under such
credit lines. Repayment of indebtedness thereunder is expected to be made
through Credit Facility availability.
6 7/8% Senior Notes due 2007. In December 1997, the Company 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 the Company's ability to enter into
sale and leaseback transactions.
9 1/4% Subordinated Notes due 2004. In June 1994, the Company 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.
24
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
The Company believes that the borrowing capacity available under the Credit
Facility, combined with the Company's internal cash flows, will be adequate to
finance the capital expenditure program planned for the balance of 1999, and
to meet the Company's margin requirements under its Fixed-Price Contracts.
See "Commitments and Capital Expenditures" and "Quantitative and Qualitative
Disclosures About Market Risk." At September 30, 1999, the Company had
working capital of $36.6 million and a current ratio of 1.5 to 1. Total
long-term debt outstanding at September 30, 1999 was $604.3 million. The
Company's long-term debt as a percentage of its total capitalization was 56%.
COMMITMENTS AND CAPITAL EXPENDITURES
The Company's 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, 1999, the Company expended $80.6 million on development activities and
$13.7 million on exploration activities. This expenditure level resulted in
the drilling of 119 development wells and 14 exploratory wells. Of these
wells, 110 development wells and 10 exploratory wells were successfully
completed as producers, for a completion success rate of 92% and 71%,
respectively (an overall success rate of 90%). In addition, the Company
invested $34.3 million in proved oil and gas property acquisitions during the
first nine months of 1999. For the balance of 1999, the Company currently
plans to invest an additional $40 million in connection with its drilling
program focused principally in its 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.
The Company continues to actively search for additional attractive oil and
gas property acquisitions, but is not able to predict the timing or amount of
additional capital expenditures which may ultimately be employed in
acquisitions during 1999.
OUTLOOK FOR FISCAL 1999
Reference is made to "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Outlook for Fiscal Year 1999" included
in the Company's Annual Report on Form 10-K, as amended, for the year ended
December 31, 1998 for an expanded discussion of 1999 estimates. Subject to
the uncertainties identified in "Forward-Looking Statements", no material
modifications to previously disclosed estimates are deemed necessary.
YEAR 2000 COMPLIANCE
General. The Company continues to address the business issues surrounding
the ability of computer software and hardware and other business systems to
appropriately consider periods and dates after December 31, 1999, both in its
offices and field locations ("Year 2000 Issue"). Non-compliant information
technology ("IT") systems and non-IT systems could result in system failures
25
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
or miscalculations causing disruptions of business operations or a temporary
inability to engage in normal business activities. Both IT and non-IT systems
may contain embedded technology, which complicates the Company's efforts to
identify, assess and remediate the Year 2000 Issue.
The Company has formed a task force to develop and implement a comprehensive
plan to resolve the Year 2000 Issue and to oversee the assessment,
remediation, testing and implementation phases of the plan. The plan
encompasses a study of significant operational exposures that would be
reasonably likely to result from the failure by the Company or significant
third parties to be Year 2000 compliant on a timely basis. These exposures
include the Company's ability to produce its oil and gas reserves, to maintain
environmental compliance and to meet contractual obligations. It also
includes the ability of its purchasers, transporters, outside operators and
other customers to buy, take delivery of, transport and pay for natural gas
and crude oil produced. Other risks relate to continued performance of
suppliers, vendors and service companies that the Company relies upon to
conduct its operations, as well as the financial institutions utilized in
connection with its borrowing and cash management activities. The mandate of
the task force includes monitoring the progress of third parties as deemed
appropriate, to the extent information can be obtained.
Status.
IT Systems. The Company has completed the assessment phase of all
significant IT systems, including its accounting, land, production and
engineering software and its computer hardware. The Company believes that the
remediation, testing and implementation phases are also complete for these
systems. Upgrades of certain PC-based systems will continue throughout 1999,
however, non-compliance in these systems is not believed to represent a
material exposure. While the Company believes that all significant IT systems
are Year 2000 compliant, it will continue to monitor such systems for
previously unidentified exposures.
Non-IT Systems. The Company has completed the assessment phase of all
significant non-IT systems, which includes operating equipment with embedded
chips or software. The Company believes that the remediation, testing and
implementation phases are also complete. The existence of embedded technology
is by nature more difficult to identify. While the Company believes that all
significant non-IT systems are Year 2000 compliant, the task force will
continue to search for previously unidentified exposures.
Third Parties. The Company has completed the assessment phase of its
exposure to Year 2000 compliance by material third parties. The responses
received to date from third parties have not identified a material
non-compliance issue that would require action by the Company. The Company
will continue to monitor its exposure to new and existing material third
parties to the extent information is made available throughout the balance of
1999. The Company has a limited number of systems which interface directly
26
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
with third parties. Such systems, although believed to be compliant, are not
significant to its business operations.
The Company cannot be assured that the various phases of its Year 2000 plan
will successfully identify and mitigate all material exposures to the Year
2000 Issue.
Costs. The Company has primarily used internal resources to reprogram, or
replace, test and implement the software, hardware and operating equipment for
Year 2000 modifications. Because the majority of the software employed by the
Company was purchased from third parties subject to ongoing maintenance
agreements, Year 2000 upgrades did not result in significant cash outlays.
Total costs incurred to date in connection with Year 2000 compliance have been
immaterial. The estimated cost attributable to remaining compliance issues in
the aggregate is expected to be less than $100,000 including hardware,
software, internal and external labor costs, which will be funded through
operating cash flows.
Risk Factors. The Company believes it has an effective program in place to
resolve the Year 2000 Issue in a timely manner and does not expect to incur
significant operational problems due to Year 2000 non-compliance. As noted
above, the Company has substantially completed all phases of its Year 2000
plan, but certain plan activities will be ongoing through the end of 1999. No
assurance can be given that all material issues have been or will be
identified, or that all material third parties will be compliant by the year
2000. If all significant Year 2000 issues are not properly and timely
identified, assessed, remediated, tested and implemented, the Company's
results of operations may be materially adversely affected. Additionally,
non-compliance by third parties may have a material adverse effect on the
Company's systems or results of operations.
The Company has not identified a "worst case scenario" that is reasonably
likely to cause a material interruption of its business activities, to cause a
material environmental event, to cause it not to meet a material contractual
obligation, or to otherwise have a material adverse effect on its operations.
Accordingly, the Company has not formalized a contingency plan to address Year
2000 non-compliance. The Company plans to continue to evaluate the status of
its Year 2000 plan throughout 1999 and to evaluate whether such a contingency
plan is advisable.
27
LOUIS DREYFUS NATURAL GAS CORP.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
GENERAL
The Company's 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 its exposure to adverse market changes, the Company
has entered into Fixed-Price Contracts and interest rate swaps. All of the
Company's Fixed-Price Contracts and interest rate swaps have been entered into
as hedges of oil and gas price risk or interest rate risk and not for trading
purposes. Information regarding the Company's 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. The Company's Fixed-Price Contracts are comprised
of long-term physical delivery contracts, energy swaps, collars, futures
contracts and basis swaps. These contracts allow the Company to predict with
greater certainty the effective oil and gas prices to be received for its
hedged production and benefit the Company when market prices are less than the
fixed prices provided in its Fixed-Price Contracts. However, the Company will
not benefit from market prices that are higher than the fixed prices in such
contracts for its hedged production. For the years ended December 31, 1998,
1997 and 1996, Fixed-Price Contracts hedged 50%, 60% and 51%, respectively, of
the Company's gas production and 16%, 33% and 67%, respectively, of its oil
production. For the nine months ended September 30, 1999, Fixed-Price
Contracts hedged 54% of the Company's oil and gas production. As of September
30, 1999, and prior to the termination of the gas contract discussed below,
Fixed-Price Contracts are in place to hedge 223 Bcfe of the Company's
estimated future oil and gas production, representing 17% of its proved oil
and gas reserves as of December 31, 1998.
The Company was a party to a long-term natural gas physical delivery
contract with an independent power producer ("IPP") which sold electrical
power under a firm, fixed-price contract to Niagara Mohawk Corporation
("NIMO"), a New York state utility. As of September 30, 1999 this contract
hedged 50 Bcf of future natural gas production. The ability of the IPP to
perform its obligations to the Company was dependent on the continued
performance by NIMO of its power purchase obligations to the IPP. NIMO had
taken aggressive regulatory, judicial and contractual actions to curtail power
purchase obligations from IPPs generally, including the IPP counterparty to
the Company's gas contract. In settlement of litigation initiated by NIMO
against this IPP, an agreement was reached in late October 1999 between the
respective parties to terminate the power contract in exchange for a cash
payment from NIMO. In connection with this agreement, the Company agreed to
the termination of its gas contract with the IPP in exchange for a cash
payment to the Company of approximately $44 million. The carrying value of
this contract as of September 30, 1999 has been adjusted to reflect the
termination settlement amount provided in the agreement. The after-tax value
of the termination payment will remain in accumulated other comprehensive
income to be amortized into earnings over the original contract term. Closing
is anticipated to occur in November 1999. The termination payment proceeds
28
LOUIS DREYFUS NATURAL GAS CORP.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK (continued)
will be applied to reduce outstanding indebtedness.
Reference is made to the Company's Annual Report on Form 10-K, as amended,
for the year ended December 31, 1998 for a more detailed discussion of the
Company's Fixed-Price Contracts.
The following table summarizes the estimated volumes, fixed prices,
fixed-price sales, fixed-price purchases and future net revenues attributable
to the Company's Fixed-Price Contracts as of September 30, 1999. The Company
expects the prices to be realized for its 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 the Company's 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, 1999, as adjusted for basis. Future net revenues change
with changes in market prices and basis.
Three
Months
Ending
December Years Ending December 31, Balance
31, -------------------------------------- through
1999 2000 2001 2002 2003 2017 Total
-------- -------- -------- -------- -------- -------- ---------
(dollars in thousands, except price data)
NATURAL GAS SWAPS:
Sales Contracts
Contract volumes
(BBtu) . . . . . . . . . 4,116 9,830 7,475 6,405 5,650 17,783 51,259
Weighted-average fixed
price per MMBtu (1). . . $ 2.44 $ 2.46 $ 2.47 $ 2.67 $ 2.92 $ 3.29 $ 2.82
Future fixed-price sales . $ 10,025 $ 24,164 $ 18,446 $ 17,098 $ 16,492 $ 58,430 $ 144,655
Future net revenues (2). . $ (1,343) $ (2,186) $ (1,138) $ 186 $ 1,493 $ 9,741 $ 6,753
Purchase Contracts
Contract volumes (BBtu). . (2,760) -- -- -- -- -- (2,760)
Weighted-average fixed
price per MMBtu (1). . . $ 2.18 $ -- $ -- $ -- $ -- $ -- $ 2.18
Future fixed-price
purchases. . . . . . . . $ (6,019) $ -- $ -- $ -- $ -- $ -- $ (6,019)
Future net revenues(2) . . $ 1,609 $ -- $ -- $ -- $ -- $ -- $ 1,609
NATURAL GAS PHYSICAL
DELIVERY CONTRACTS:
Contract volumes (BBtu). . 4,970 22,678 23,240 23,115 20,245 71,483 165,731
Weighted-average fixed
price per MMBtu (1). . . $ 2.92 $ 2.88 $ 3.00 $ 3.14 $ 3.40 $ 4.10 $ 3.53
Future fixed-price sales . $ 14,493 $ 65,332 $ 69,712 $ 72,684 $ 68,775 $293,225 $ 584,221
Future net
revenues (2) (3) . . . . $ 426 $ 2,760 $ 5,001 $ 5,221 $ 5,169 $ 13,521 $ 32,098
29
LOUIS DREYFUS NATURAL GAS CORP.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK (continued)
Three
Months
Ending
December Years Ending December 31, Balance
31, -------------------------------------- through
1999 2000 2001 2002 2003 2017 Total
-------- -------- -------- -------- -------- -------- ---------
(dollars in thousands, except price data)
NATURAL GAS COLLARS:
Contract volumes (BBtu):
Floor. . . . . . . . . . 4,876 -- -- -- -- -- 4,876
Ceiling. . . . . . . . . 7,360 -- -- -- -- -- 7,360
Weighted-average fixed
price per MMBtu (1):
Floor. . . . . . . . . . $ 2.07 $ -- $ -- $ -- $ -- $ -- $ 2.07
Ceiling. . . . . . . . . $ 2.17 $ -- $ -- $ -- $ -- $ -- $ 2.17
Future fixed-price sales . $ 15,971 $ -- $ -- $ -- $ -- $ -- $ 15,971
Future net revenues (2). . $ (4,172) $ -- $ -- $ -- $ -- $ -- $ (4,172)
TOTAL NATURAL GAS
CONTRACTS (4):
Contract volumes (BBtu) . 13,686 32,508 30,715 29,520 25,895 89,266 221,590
Weighted-average fixed
price per MMBtu (1). . . $ 2.52 $ 2.75 $ 2.87 $ 3.04 $ 3.29 $ 3.94 $ 3.33
Future fixed-price sales . $ 34,470 $ 89,496 $ 88,158 $ 89,782 $ 85,267 $351,655 $ 738,828
Future net revenues (2). . $ (3,480) $ 574 $ 3,863 $ 5,407 $ 6,662 $ 23,262 $ 36,288
CRUDE OIL SWAPS:
Contract volumes (MBbls) . 184 -- -- -- -- -- 184
Weighted-average fixed
price per Bbl (1) . . . . $ 20.37 $ -- $ -- $ -- $ -- $ -- $ 20.37
Future fixed-price sales . $ 3,748 $ -- $ -- $ -- $ -- $ -- $ 3,748
Future net revenues (2). . $ (686) $ -- $ -- $ -- $ -- $ -- $ (686)
<FN>
(1) - The Company expects the prices to be realized for its hedged production to vary from the
prices shown due to basis.
(2) - Future net revenues as presented above are undiscounted and have not been adjusted for
contract performance risk or counterparty credit risk.
(3) - Includes the future net revenues of a Fixed-Price Contract that was terminated in
November 1999 in exchange for a payment of approximately $44 million to be received at
closing. See related discussion under this heading.
(4) - Does not include basis swaps with notional volumes by year, as follows: 1999 - 4.8 Tbtu;
2000 - 21.3 TBtu; 2001 - 9.4 TBtu; and 2002 - 5.5 TBtu.
The estimates of future net revenues from the Company's 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. The Company has relied upon
near-term market quotations, longer-term over-the-counter market quotations
and other market information to determine its future net revenue estimates.
Forward market prices for natural gas are dependent upon supply and demand
30
LOUIS DREYFUS NATURAL GAS CORP.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK (continued)
factors in such 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 value of the Company's Fixed-Price Contracts and interest
rate swaps and the associated carrying value as of September 30, 1999 are
identical. Such amounts are provided below.
Estimated
Fair Value
--------------
(in thousands)
Derivative assets:
Fixed-price natural gas swaps:
Sales contracts . . . . . . . . . . . . . . . . . . . . $ 11,558
Purchase contracts. . . . . . . . . . . . . . . . . . . 1,593
Fixed-price natural gas collars . . . . . . . . . . . . . 83
Fixed-price natural gas delivery contracts (1). . . . . . 49,992
Interest rate swaps - fixed . . . . . . . . . . . . . . . 4,471
Derivative liabilities:
Fixed-price natural gas swaps - sales contracts . . . . . (8,026)
Fixed-price oil swaps - sales contracts . . . . . . . . . (678)
Fixed-price natural gas collars . . . . . . . . . . . . . (4,255)
Fixed-price natural gas delivery contracts. . . . . . . . (20,245)
Natural gas basis swaps . . . . . . . . . . . . . . . . . (3,443)
Interest rate swaps - fixed . . . . . . . . . . . . . . . (12)
--------------
Total . . . . . . . . . . . . . . . . . . . . . . . . . . $ 31,038
==============
- ------------------------------
<FN>
(1) Includes the fair value of a Fixed-Price Contract that was terminated in
November 1999 in exchange for a payment of approximately $44 million to
be received at closing. See related discussion under this heading.
The fair value of Fixed-Price Contracts as of September 30, 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 terms and
conditions of the Company's fixed-price physical delivery contracts and
certain financial swaps are uniquely tailored to the Company's circumstances.
31
LOUIS DREYFUS NATURAL GAS CORP.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK (continued)
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 as reflected in the balance sheet as of
September 30, 1999 does not necessarily represent the value a third party
would pay to assume the Company's positions.
Interest rate sensitivity
The Company has entered into interest rate swaps to hedge the interest rate
exposure associated with borrowings under the Credit Facility. As of
September 30, 1999, the Company had fixed the interest rate on average
notional amounts of $155 million for the balance of 1999, and $125 million,
$125 million and $94 million for the years ending December 31, 2000, 2001 and
2002, respectively. Under the interest rate swaps, the Company receives the
LIBOR three- month rate (6.1% at September 30, 1999) and pays an average rate
of 5.3% for the balance of 1999 and 5.0%, 5.0% and 5.0% for 2000, 2001 and
2002, respectively. The notional amounts are less than the maximum amount
anticipated to be outstanding under the Credit Facility in such years.
Reference is made to the Company's Annual Report on Form 10-K, as amended,
for the year ended December 31, 1998 for an expanded discussion of the
Company's interest rate swaps.
32
LOUIS DREYFUS NATURAL GAS CORP.
PART II. OTHER INFORMATION
ITEM 1 -- NONE
ITEM 2 -- NONE
ITEM 3 -- NONE
ITEM 4 -- NONE
ITEM 5 -- NONE
ITEM 6 -- EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:
27.1 -- Financial Data Schedule
(b) Reports on Form 8-K:
None
33
LOUIS DREYFUS NATURAL GAS CORP.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
LOUIS DREYFUS NATURAL GAS CORP.
-----------------------------------
(Registrant)
Date: March 6, 2000 /s/ Jeffrey A. Bonney
-----------------------------------
Jeffrey A. Bonney
Executive Vice President and Chief Financial
Officer