<PAGE> 1
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q/A
Amendment No. 2
[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934.
For the quarterly period ended June 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 .
---- ----
40,143,008 shares of common stock, $.01 par value, issued and outstanding at
August 12, 1999.
<PAGE>
<PAGE> 2
LOUIS DREYFUS NATURAL GAS CORP.
Table of Contents
PART I. FINANCIAL INFORMATION Page
Item 1 -- CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
Consolidated Balance Sheets:
June 30, 1999 and December 31, 1998. . . . . . . . . . . . . . . . . . 3
Consolidated Statements of Operations:
Three months and six months ended June 30, 1999 and 1998 . . . . . . . 5
Consolidated Statements of Cash Flows:
Six months ended June 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 DISCLOSURE ABOUT MARKET RISK. . .27
PART II. OTHER INFORMATION . . . . . . . . . . . . . . . . . . . . .32
<PAGE>
<PAGE> 3
LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED BALANCE SHEETS
(dollars in thousands)
<TABLE>
<CAPTION>
A S S E T S
June 30, December 31,
1999 1998
----------- -----------
(restated,
unaudited)
<S> <C> <C>
CURRENT ASSETS
Cash and cash equivalents. . . . . . . . . . . . . $ 7,983 $ 2,539
Receivables:
Oil and gas sales . . . . . . . . . . . . . . . . 43,989 37,381
Joint interest and other, net . . . . . . . . . . 8,056 11,725
Costs reimbursable by insurance . . . . . . . . . -- 7,200
Fixed-price contracts and other derivatives. . . . 12,313 23,338
Prepaids and other . . . . . . . . . . . . . . . . 2,283 4,572
----------- -----------
Total current assets. . . . . . . . . . . . . . . 74,624 86,755
----------- -----------
PROPERTY AND EQUIPMENT, at cost, based on
successful efforts accounting. . . . . . . . . . 1,583,721 1,519,296
Less accumulated depreciation, depletion
and amortization. . . . . . . . . . . . . . . . (475,175) (434,693)
----------- -----------
1,108,546 1,084,603
----------- -----------
OTHER ASSETS
Fixed-price contracts and other derivatives. . . . 79,529 107,302
Other, net . . . . . . . . . . . . . . . . . . . . 4,364 5,148
----------- -----------
83,893 112,450
----------- -----------
$ 1,267,063 $ 1,283,808
=========== ===========
</TABLE>
<PAGE> 4
LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED BALANCE SHEETS (continued)
(dollars in thousands)
<TABLE>
<CAPTION>
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
June 30, December 31,
1999 1998
----------- -----------
(restated
unaudited)
<S> <C> <C>
CURRENT LIABILITIES
Accounts payable . . . . . . . . . . . . . . . . . $ 24,707 $ 38,222
Accrued liabilities. . . . . . . . . . . . . . . . 10,824 10,696
Revenues payable . . . . . . . . . . . . . . . . . 11,109 10,940
Fixed-price contracts and other derivatives. . . . 13,552 2,292
----------- -----------
Total current liabilities . . . . . . . . . . . . 60,192 62,150
----------- -----------
LONG-TERM DEBT . . . . . . . . . . . . . . . . . . 629,637 596,844
----------- -----------
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred revenue . . . . . . . . . . . . . . . . . 14,571 15,551
Deferred income taxes. . . . . . . . . . . . . . . 42,537 65,116
Fixed-price contracts and other derivatives. . . . 15,882 5,350
Other. . . . . . . . . . . . . . . . . . . . . . . 20,604 19,336
----------- -----------
93,594 105,353
----------- -----------
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,
40,138,508 and 40,109,758 shares, respectively . 401 401
Additional paid-in capital . . . . . . . . . . . . 419,490 419,075
Retained earnings. . . . . . . . . . . . . . . . . 2,460 6,735
Accumulated other comprehensive income . . . . . . 61,289 93,250
----------- -----------
483,640 519,461
----------- -----------
$ 1,267,063 $ 1,283,808
=========== ===========
</TABLE>
See accompanying notes to consolidated financial statements.
<PAGE> 5
LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)
(in thousands, except per share data)
<TABLE>
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
------------------ ------------------
1999 1998 1999 1998
-------- -------- -------- --------
(restated) (restated)
<S> <C> <C> <C> <C>
REVENUES
Oil and gas sales. . . . . . . . . . $ 70,306 $ 69,481 $128,461 $137,395
Change in derivative fair value. . . (8,135) -- (11,110) --
Other income . . . . . . . . . . . . 251 870 2,194 2,552
-------- -------- -------- --------
62,422 70,351 119,545 139,947
-------- -------- -------- --------
EXPENSES
Operating costs. . . . . . . . . . . 15,860 17,044 31,453 34,065
General and administrative . . . . . 5,803 6,336 11,618 12,539
Exploration costs. . . . . . . . . . 2,213 9,360 6,152 16,940
Depreciation, depletion
and amortization . . . . . . . . . 29,070 34,250 57,200 66,291
Impairment . . . . . . . . . . . . . -- 9,864 -- 9,864
Interest . . . . . . . . . . . . . . 10,233 10,372 20,247 20,418
-------- -------- -------- --------
63,179 87,226 126,670 160,117
-------- -------- -------- --------
Loss before income taxes . . . . . . (757) (16,875) (7,125) (20,170)
Income tax benefit . . . . . . . . . (303) (6,484) (2,850) (7,736)
-------- -------- -------- --------
NET LOSS . . . . . . . . . . . . . . $ (454) $(10,391) $ (4,275) $(12,434)
======== ======== ======== ========
Net loss per share -
basic and diluted. . . . . . . . . $ (.01) $ (.26) $ (.11) $ (.31)
======== ======== ======== ========
Weighted average diluted common
shares . . . . . . . . . . . . . . 40,123 40,110 40,116 40,104
======== ======== ======== ========
</TABLE>
See accompanying notes to consolidated financial statements.
<PAGE> 6
LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
(in thousands)
<TABLE>
<CAPTION>
Six Months Ended
June 30,
------------------
1999 1998
-------- --------
(restated)
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (4,275) $(12,434)
Items not affecting cash flows:
Depreciation, depletion and amortization. . . . . . . . . . . . . . . 57,200 66,291
Impairment. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -- 9,864
Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . (2,990) (8,286)
Exploration costs . . . . . . . . . . . . . . . . . . . . . . . . . . 6,152 16,940
Change in derivative fair value . . . . . . . . . . . . . . . . . . . 11,110 --
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (111) 242
Net change in operating assets and liabilities:
Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . 4,261 26,442
Prepaids and other. . . . . . . . . . . . . . . . . . . . . . . . . . 2,289 5,973
Accounts payable. . . . . . . . . . . . . . . . . . . . . . . . . . . (13,515) (12,196)
Accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . 128 (5,615)
Revenues payable. . . . . . . . . . . . . . . . . . . . . . . . . . . 169 (2,135)
-------- --------
60,418 85,086
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Exploration and development expenditures . . . . . . . . . . . . . . . (59,457) (138,333)
Acquisition of oil and gas properties. . . . . . . . . . . . . . . . . (30,409) (4,575)
Additions to other property and equipment. . . . . . . . . . . . . . . (976) (1,658)
Proceeds from sale of property and equipment . . . . . . . . . . . . . 7,034 565
Change in other assets . . . . . . . . . . . . . . . . . . . . . . . . (143) (241)
-------- --------
(83,951) (144,242)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from bank borrowings. . . . . . . . . . . . . . . . . . . . . 240,369 329,514
Repayments of bank borrowings. . . . . . . . . . . . . . . . . . . . . (207,569) (306,014)
Proceeds from stock options exercised. . . . . . . . . . . . . . . . . 415 324
Change in deferred revenue . . . . . . . . . . . . . . . . . . . . . . (980) (888)
Change in gains from price-risk management activities. . . . . . . . . (2,249) 39,549
Change in other long-term liabilities. . . . . . . . . . . . . . . . . (1,009) (2,717)
-------- --------
28,977 59,768
-------- --------
Change in cash and cash equivalents. . . . . . . . . . . . . . . . . . 5,444 612
Cash and cash equivalents, beginning of period . . . . . . . . . . . . 2,539 5,538
-------- --------
Cash and cash equivalents, end of period . . . . . . . . . . . . . . . $ 7,983 $ 6,150
======== ========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Interest paid, net of capitalized interest . . . . . . . . . . . . . . $ 19,479 $ 17,904
Income taxes paid. . . . . . . . . . . . . . . . . . . . . . . . . . . 285 250
-------- --------
$ 19,764 $ 18,154
======== ========
</TABLE>
See accompanying notes to consolidated financial statements.
<PAGE> 7
LOUIS DREYFUS NATURAL GAS CORP.
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
June 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
six-month periods ended June 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 six
months ended June 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 for
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 June 30, 1999,
and for the three months and six months then ended, have been restated to
reflect this change. The effect of the restatement is provided below.
<TABLE>
<CAPTION>
Three Months Ended Six Months Ended
June 30, 1999 June 30, 1999
----------------------- -----------------------
As As
As Previously As Previously
Restated Reported Restated Reported
---------- ---------- ---------- ----------
(in thousands, except per share data)
<S> <C> <C> <C> <C>
Statement of Operations Data:
Change in derivative fair value. . . . . . . . $ (8,135) $ (2,488) $ (11,110) $ 1,197
Total revenues . . . . . . . . . . . . . . . . 62,422 68,069 119,545 131,852
Income (loss) before income taxes. . . . . . . (757) 4,890 (7,125) 5,182
Income tax provision (benefit) . . . . . . . . (303) 2,042 (2,850) 2,176
Net income (loss). . . . . . . . . . . . . . . (454) 2,848 (4,275) 3,006
Net income (loss) per share -
basic and diluted . . . . . . . . . . . . . . (.01) .07 (.11) .07
Weighted average diluted common shares . . . . 40,123 40,414 40,116 40,268
</TABLE>
<PAGE> 8
LOUIS DREYFUS NATURAL GAS CORP.
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued)
JUNE 30, 1999
<TABLE>
<CAPTION>
As of June 30, 1999
-----------------------
As
As Previously
Restated Reported
---------- ----------
(in thousands)
<S> <C> <C>
Balance Sheet Data:
Deferred income taxes. . . . . . . . . . . . . . . . . . . . . . . $ 42,537 $ 42,886
Total deferred credits and other liabilities . . . . . . . . . . . 93,594 93,943
Retained earnings. . . . . . . . . . . . . . . . . . . . . . . . . 2,460 9,741
Accumulated other comprehensive income . . . . . . . . . . . . . . 61,289 53,659
Total stockholders' equity . . . . . . . . . . . . . . . . . . . . 483,640 483,291
</TABLE>
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
change in fair value resulting from ineffectiveness, as defined by SFAS 133,
is recognized immediately in earnings. Effective January 13, 1999,
substantially all of the Company's Fixed-Price Contracts and interest rate
swaps are 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 six-months ended June 30, 1999 included net charges of $8.1
million and $11.1 million, respectively, which are comprised of losses of $.5
million and $1.3 million, respectively, of changes in fair value for
Fixed-Price Contracts not designated as cash flow hedges, $1.0 million and
$1.3 million, respectively, of net gains relating to Fixed-Price Contract
hedge ineffectiveness, $8.3 million and $11.5 million, respectively, of losses
attributable to a loss of effectiveness for certain derivative contracts, and
losses of $.3 million and $5.8 million 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, change in
derivative fair value includes a $6.2 million gain attributable to an increase
in derivative fair value from January 1, 1999 through January 13, 1999 (see
discussion below).
<PAGE> 9
LOUIS DREYFUS NATURAL GAS CORP.
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued)
JUNE 30, 1999
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 June 30, 1999, and for the six-month
periods then ended, reflect this accounting. Change in derivative fair value
for the six months ended June 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.
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,
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. The acquired properties currently produce 3.5 MMcfe per day
of oil and natural gas with estimated proved reserves of 12 Bcfe. The
purchase method was used to account for both acquisitions.
NOTE 5 -- CONTINGENCIES
Litigation. On December 22, 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 first and second liens on assets of
Midcon, payable in full on or before December 15, 1996 in settlement of
disputes in connection with this litigation. On December 16, 1996, Midcon
filed for protection from its creditors under Chapter 11 of the United States
Bankruptcy Code in the United States Bankruptcy Court, Southern District of
<PAGE> 10
LOUIS DREYFUS NATURAL GAS CORP.
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued)
JUNE 30, 1999
Texas, Corpus Christi Division. On January 27, 1997, Midcon filed an action
in the bankruptcy court alleging that Midcon's action in connection with the
settlement constituted fraudulent transfers or avoidable preferences and
seeking a return of $1.7 million paid under the note and also seeking a
release of the liens securing the payment obligation under the note. The
complaint filed in the action also alleged certain affirmative claims against
the Company including injury to reputation and loss of business opportunity.
On July 23, 1999, an agreement was reached between the Company and certain
parties in interest to the Midcon bankruptcy case, including the Trustee and
the Official Unsecured Creditors Committee. The terms of the agreement
provide for the payment of $8.6 million to the Company in satisfaction of its
claims against the estate. The settlement amount is subject to approval of
the bankruptcy court, which has set a hearing date for this matter on August
18, 1999. If approved by the court, the Company would be entitled to receive
these funds ten days after the related order is entered. This potential
receipt of funds would be reflected in earnings and operating cash flows in
the quarter when receipt of the funds is no longer uncertain. No amounts have
been recorded with respect thereto in the accompanying financial statements as
of June 30, 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 is scheduled to be
heard in September 1999. 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 June 30, 1999. The
more significant of such legal claims was an alleged underpayment of royalty
of $5.5 million plus interest, and preliminary and final royalty underpayment
determinations from the Minerals Management Service aggregating approximately
$2.1 million plus interest. 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.
Fixed-Price Contracts. The Company is a party to a long-term natural gas
<PAGE> 11
LOUIS DREYFUS NATURAL GAS CORP.
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued)
JUNE 30, 1999
physical delivery contract with an independent power producer ("IPP") which
sells electrical power under a firm, fixed-price contract to Niagra Mohawk
Corporation ("NIMO"), a New York state utility. The ability of this IPP to
perform its obligations to the Company is dependent on the continued
performance by NIMO of its power purchase obligations to the IPP. NIMO has
taken aggressive regulatory, judicial and contractual actions to curtail power
purchase obligations from IPPs generally, and in July 1997, NIMO entered into
a Master Restructuring Agreement (the "MRA") with a number of similarly
situated IPPs to settle or restructure obligations with them. As a result,
the Company terminated a Fixed-Price Contract with one of these settling
parties and received a termination payment of $40.1 million in June 1998.
This termination amount has been recorded in accumulated other comprehensive
income, net of tax effect. However, the IPP with whom the Company still has a
contract did not participate in the MRA. This contract which hedges 51 Bcf of
natural gas as of June 30, 1999 remains in force and is reflected in the
Company's balance sheet at a fair value of $62.0 million. The Company
continues to deliver natural gas pursuant to the terms of this contract which
expires in 2007. NIMO has continued to seek relief from its contractual
obligations under its contract with the IPP in the court system, most recently
in a trial in a United States District court. A decision from this trial is
expected in the fall of 1999. If NIMO is successful in these efforts, it
could have an adverse effect on the ability of the IPP to continue to perform
its obligations to the Company and could materially impair the value of the
Company's natural gas contract. Although there can be no assurance,
Management does not expect that NIMO will ultimately succeed in these efforts.
NOTE 6 -- COMPREHENSIVE LOSS
Components of comprehensive loss for the three-month and the six-month
periods ended June 30, 1999 and 1998, are as follows:
<TABLE>
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
------------------ ------------------
1999 1998 1999 1998
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Net loss . . . . . . . . . . . . . . $ (454) $(10,391) $ (4,275) $(12,434)
Other comprehensive loss, net of tax:
Reclassification adjustments -
contract settlements . . . . . . . (747) -- (5,030) --
Change in fixed-price contract
and other derivative fair value. . (12,451) -- (26,931) --
-------- -------- -------- --------
Comprehensive loss . . . . . . . . . $(13,652) $(10,391) $(36,236) $(12,434)
======== ======== ======== ========
</TABLE>
<PAGE> 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, futures contracts, basis
swaps and option agreements (collectively "Fixed-Price Contracts"). As of
June 30, 1999, the Company's Fixed-Price Contracts hedged 243 Bcf of future
gas production representing 20% of its estimated proved natural gas reserves
at December 31, 1998, at escalating fixed prices. These average fixed prices
are presently significantly higher than the forward market prices for natural
gas. 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 entering into financing
<PAGE> 13
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
transactions. None of these can be predicted with certainty and, accordingly,
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.
<PAGE> 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.
<TABLE>
<CAPTION> Three Months Ended Six Months Ended
June 30, June 30,
------------------ ------------------
1999 1998 1999 1998
-------- -------- -------- --------
<S> <C> <C> <C> <C>
OIL AND GAS SALES: (M$)
Wellhead oil sales . . . . . . . . . . . . $ 11,800 $ 11,541 $ 20,028 $ 23,026
Effect of Fixed-Price Contracts (1). . . . -- -- -- 496
-------- -------- -------- --------
Total oil sales. . . . . . . . . . . . . . $ 11,800 $ 11,541 $ 20,028 $ 23,522
======== ======== ======== ========
Wellhead natural gas sales . . . . . . . . $ 55,801 $ 54,211 $ 98,317 $106,546
Effect of Fixed-Price Contracts (1). . . . 2,705 3,729 10,116 7,327
-------- -------- -------- --------
Total natural gas sales. . . . . . . . . . $ 58,506 $ 57,940 $108,433 $113,873
======== ======== ======== ========
PRODUCTION:
Oil production (MBbls) . . . . . . . . . . 760 913 1,502 1,738
Natural gas production (MMcf). . . . . . . 26,625 24,989 52,093 49,943
Net equivalent production (MMcfe). . . . . 31,183 30,468 61,105 60,371
Percent of oil production hedged by
Fixed-Price Contracts (%). . . . . . . . 0% 0% 0% 5%
Percent of gas production hedged by
Fixed-Price Contracts (%). . . . . . . . 72% 46% 54% 46%
AVERAGE SALES PRICE:
Oil price (per Bbl):
Wellhead price . . . . . . . . . . . . . $ 15.53 $ 12.64 $ 13.33 $ 13.25
Effect of Fixed-Price Contracts (1). . . -- -- -- .28
-------- -------- -------- --------
Total. . . . . . . . . . . . . . . . . . $ 15.53 $ 12.64 $ 13.33 $ 13.53
Natural gas price (per Mcf):
Wellhead price . . . . . . . . . . . . . $ 2.10 $ 2.17 $ 1.89 $ 2.13
Effect of Fixed-Price Contracts (1). . . .10 .15 .19 .15
-------- -------- -------- --------
Total. . . . . . . . . . . . . . . . . . $ 2.20 $ 2.32 $ 2.08 $ 2.28
======== ======== ======== ========
Average sales price (per Mcfe) . . . . . . $ 2.25 $ 2.28 $ 2.10 $ 2.28
OPERATING AND OVERHEAD COSTS: (per Mcfe)
Lease operating expenses . . . . . . . . . $ .40 $ .45 $ .41 $ .45
Production taxes . . . . . . . . . . . . . .11 .11 .10 .11
General and administrative . . . . . . . . .19 .21 .19 .21
-------- -------- -------- --------
Total. . . . . . . . . . . . . . . . . . . $ .70 $ .77 $ .70 $ .77
======== ======== ======== ========
CASH OPERATING MARGIN: (per Mcfe). . . . . $ 1.55 $ 1.51 $ 1.40 $ 1.51
DEPRECIATION, DEPLETION AND AMORTIZATION -
OIL AND GAS . . . . . . . . . . . . . . . $ .89 $ 1.08 $ .89 $ 1.05
<FN>
(1) - Represents the hedging results from the Company's Fixed-Price Contracts. See
"Quantitative and Qualitative Disclosures About Market Risk - Fixed-Price Contracts."
</TABLE>
<PAGE> 15
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
RESULTS OF OPERATIONS -- THREE MONTHS ENDED JUNE 30, 1999 COMPARED TO THREE
MONTHS ENDED JUNE 30, 1998
Net Loss and Cash Flows from Operating Activities. For the quarter ended
June 30, 1999, the Company realized a net loss of $.5 million, or $.01 per
share, on total revenue of $62.4 million. This compares to a net loss of
$10.4 million, or $.26 per share, on total revenue of $70.4 million for the
second quarter of 1998. Cash flows from operating activities (before working
capital changes) for the second quarter of 1999 grew 5% to $38.5 million
compared to $36.5 million for the second quarter of 1998. Growth in total
production and lower cash expenses were the principal reasons for the increase
in operating cash flows, more than offsetting the effects of lower average oil
and gas prices for the current year period. Results of operations for the
quarter ended June 30, 1999 were enhanced by improved lease operating and
overhead costs on a unit of production basis and lower exploration costs and
oil and gas depletion and impairment expense. Cash flows provided by
operating activities after consideration of the net change in working capital
decreased to $27.5 million from the $55.8 million reported for the second
quarter of 1998, primarily due to an increase in accounts receivable and a
decrease in accounts payable.
Production. The Company produced 31.2 Bcfe for the second quarter of 1999
compared to 30.5 Bcfe for the prior year second quarter, an increase of 2%.
Gas production increased to 26.6 Bcf compared to 25.0 Bcf for the second
quarter of 1998, an increase of 7%. Oil production for the second quarter of
1999 decreased 17% to 760 Mbbls compared to 913 MBbls for the prior-year
second quarter.
Oil and Gas Prices. On a natural gas equivalent basis, the Company received
an average price of $2.25 per Mcfe for the quarter ended June 30, 1999, a
decrease of 1% from the $2.28 per Mcfe received for the second quarter of
1998. The Company's gas production yielded an average price of $2.20 per Mcf,
a decrease of 5% compared to $2.32 per Mcf for the prior-year second quarter.
The Company's average gas price for the 1999 second quarter was enhanced $.10
per Mcf as a result of the Company's hedging activities. The average gas
price for the second quarter of 1998 increased $.15 per Mcf as a result of the
Fixed-Price Contracts in effect for that period. The average oil price for
the second quarter of 1999 was $15.53 per Bbl, an increase of 23% from the
$12.64 per Bbl received for the prior-year second quarter. No fixed-price oil
contracts were in effect during the second quarter of 1999 or 1998.
The net effect of higher gas production and lower gas prices increased gas
sales to $58.5 million for the second quarter of 1999 compared to $57.9
million for the second quarter of 1998. The net effect of higher oil prices
and lower oil production increased oil sales to $11.8 million compared to
$11.5 million reported for the prior-year quarter. The impact of the
Company's Fixed-Price Contract settlements for each period was to increase gas
sales by $2.7 million for the quarter ended June 30, 1999 and to increase gas
sales by $3.7 million for the quarter ended June 30, 1998. See "Quantitative
<PAGE> 16
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
and Qualitative Disclosures About Market Risk."
Change in Derivative Fair Value. The Company restated its financial results
for the three months ended June 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 June 30, 1999 have been restated to
reflect this change. The effect of the restatement was to decrease reported
results of operations by $5.6 million ($3.3 million, net of tax) for the
quarter ended June 30, 1999. Change in derivative fair value for the second
quarter of 1999 included $.5 million of losses associated with certain
derivatives not designated as cash flow hedges, $1.0 million of net gains
relating to Fixed-Price Contract hedge ineffectiveness, $8.3 million of losses
attributable to a loss of effectiveness for certain cash flow hedges, and $.3
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 $.3 million,
a modest decline compared to $.9 million for the second quarter of 1998.
Operating Costs. Operating costs for the second quarter of 1999 were
comprised of $12.3 million of lease operating expenses and $3.5 million of
production taxes. This compares to $13.8 million of lease operating expenses
and $3.3 million of production taxes for the second 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 June
30, 1999 compared to $.45 for the three months ended June 30, 1998.
General and Administrative Expense. General and administrative expense
("G&A") for the second quarter of 1999 was $5.8 million, a decrease of 8% from
the prior-year second quarter amount of $6.3 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 second quarter compared to
$.21 per Mcfe for the 1998 second quarter.
Exploration Costs. Exploration costs, comprised of geological and
geophysical costs, exploratory dry holes and leasehold impairment costs, were
$2.2 million for the quarter ended June 30,1999, compared to $9.4 million for
the second quarter of 1998. The 1999 amount consists of $.6 million of dry
<PAGE> 17
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
hole costs, $.5 million of seismic acquisition and other geological and
geophysical costs and $1.1 million of leasehold costs. The 1998 amount
consists of $5.0 million of dry hole costs, $2.4 million of seismic
acquisition costs and other geological and geophysical costs and $2.0 million
of leasehold costs.
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization ("DD&A") for the second quarter of 1999 was $29.1 million
compared to $34.3 million for the prior-year second 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 second
quarter compared to $1.08 for the second quarter of 1998. This decrease was
primarily the result of 1998 reserve additions added at favorable finding and
development costs and to a $42.7 million impairment charge taken in the fourth
quarter of 1998.
Impairment. There was no impairment charge recorded for the second quarter
of 1999. For the quarter ended June 30, 1998, the Company recorded an
impairment charge of $9.9 million in connection with an impairment review
conducted in response to a significant decline in oil prices. This review
identified one offshore field which had a net book value in excess of
estimated future net revenues for the field, which resulted in the impairment
charge.
Interest Expense. Interest expense for the second quarter of 1999 was $10.2
million compared to $10.4 million for the second quarter of 1998. The net
impact of interest rate swaps in effect for the second quarter of 1999 and
1998 was not material. See "Capital Resources and Liquidity - Credit
Facility."
Income Taxes. For the second quarter of 1999, the Company recorded a tax
benefit of $.3 million on pretax loss of $.8 million, an effective rate of
40%. This compares to a tax benefit of $6.5 million on pretax loss of $16.9
million, an effective rate of 38%, for the second quarter of 1998.
RESULTS OF OPERATIONS -- SIX MONTHS ENDED JUNE 30, 1999 COMPARED TO SIX MONTHS
ENDED JUNE 30, 1998
Net Loss and Cash Flows from Operating Activities. The Company realized a
net loss of $4.3 million, or $.11 per share, on total revenue of $119.5
million for the six months ended June 30, 1999. This compares with a net loss
of $12.4 million, or $.31 per share, on total revenue of $139.9 million for
the six months ended June 30, 1998. Cash flows from operating activities
(before working capital changes) for the first six months of 1999 were $67.1
million, compared to $72.6 million for the first six months of 1998, a
decrease of 8%. The decline in operating cash flows for the current year
six-month period was primarily the result of lower oil and gas prices in
relation to those received for the first six months of 1998. This price
decline was partially offset by a 9% improvement in lease operating and
<PAGE> 18
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
overhead costs on a unit of production basis. Reductions in exploration
costs, oil and gas depletion and impairment expense were the principal reasons
for the improvement in current period operating results. Cash flows provided
by operating activities after consideration of the net change in working
capital decreased to $60.4 million from the $85.1 million reported for the
second quarter of 1998, primarily due to lower oil and gas prices discussed
above and a smaller decrease in accounts receivable relative to the comparable
period of 1998.
Production. The Company's total production was 61.1 Bcfe for the first six
months of 1999 compared to 60.4 Bcfe for the comparable prior-year period, an
increase of 1%. Gas production increased to 52.1 Bcf compared to 49.9 Bcf for
the first half of 1998, an increase of 4%. Oil production for the first six
months of 1999 decreased 14% to 1.5 MMBbls compared to 1.7 MMBbls for the
first six months of 1998.
Oil and Gas Prices. On a natural gas equivalent basis, the Company received
an average price of $2.10 per Mcfe for the first six months of 1999, a
decrease of 8% from the $2.28 per Mcfe received for the first six months of
1998. The Company's gas production yielded an average price of $2.08 per Mcf,
a decrease of 9% compared to $2.28 per Mcf for the prior-year six-month
period. The Company's average gas price for the first six months of 1999 was
enhanced $.19 per Mcf as a result of the Company's hedging activities. The
average gas price for the first six months of 1998 was enhanced $.15 per Mcf
as a result of the Fixed-Price Contracts in effect for that period. The
average oil price for the first half of 1999 was $13.33 per Bbl compared to
$13.53 per Bbl for the first half of 1998, a decline of 1%. No fixed-price
oil contracts were in effect during the current year six-month period.
Fixed-Price Contracts in effect during the prior-year six-month period
increased the average oil price by $.28 per Bbl.
The net effect of higher gas production and lower gas prices decreased gas
sales to $108.4 million for the first six months of 1999 compared to $113.9
million for the first six months of 1998. The combination of lower oil
production and lower oil prices decreased oil sales to $20.0 million compared
to $23.5 million reported for the prior-year six-month period. The impact of
the Company's Fixed-Price Contract settlements for each period was to increase
oil and gas sales by $10.1 million for the six months ended June 30, 1999 and
to increase oil and gas sales by $7.8 million for the six months ended June
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 six months ended June 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 for the contracts occur. This change was made based
<PAGE> 19
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
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 June 30, 1999,
and for the six months then ended, have been restated to reflect this change.
The effect of the restatement was to decrease reported results of operations
by $12.3 million for the six months ended June 30, 1999. Change in derivative
fair value for the six months ended June 30, 1999 included $1.3 million of
losses associated with certain derivatives not designated as cash flow hedges,
$1.3 million of net gains relating to Fixed-Price Contract hedge
ineffectiveness, $11.5 million of losses attributable to a loss of
effectiveness for certain cash flow hedges, and $5.8 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 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,
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 June 30, 1999, and for the six-month
period then ended, reflect this accounting. Change in derivative fair value
for the six months ended June 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 six months of 1999 was $2.2
million, a modest decline compared to $2.6 million for the first six months of
1998.
Operating Costs. Operating costs for the first six months of 1999 were
comprised of $25.3 million of lease operating expenses and $6.1 million of
production taxes. This compares to $27.2 million of lease operating expenses
and $6.9 million of production taxes for the first six months of 1998. The
<PAGE> 20
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
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
six months ended June 30, 1998. The decrease in production taxes is primarily
the result of lower oil and gas prices in the first six months of 1999.
General and Administrative Expense. G&A for the first six months of 1999
was $11.6 million compared to $12.5 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 six months of 1999 compared to $.21 per Mcfe for the first six months of
1998.
Exploration Costs. Exploration costs, comprised of geological and
geophysical costs, exploratory dry holes and leasehold impairment costs, were
$6.2 million for the six months ended June 30, 1999, compared to $16.9 million
for the six months ended June 30, 1998. The 1999 amount consists of $1.1
million of dry hole costs, $1.3 million of seismic acquisition and other
geological and geophysical costs and $3.8 million of leasehold costs. The
1998 amount consists of $8.4 million of dry hole costs, $6.2 million of
seismic acquisition and other geological and geophysical costs and $2.3
million of leasehold costs.
Depreciation, Depletion and Amortization. DD&A for the first half of 1999
was $57.2 million compared to $66.3 million for the first half 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 six months of 1999 compared to $1.05 for the first six months of 1998.
This decrease was primarily the result of 1998 reserve additions added at
favorable finding and development costs and to a $42.7 million impairment
charge taken in the fourth quarter of 1998.
Impairment. There was no impairment charge recorded for the first six
months of 1999. For the six month period ended June 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 oil prices for such
period. This review identified one offshore field which had a net book value
in excess of estimated future net revenues for the field, which resulted in
the impairment charge.
Interest Expense. Interest expense for the six months ended June 30, 1999
was $20.2 million compared to $20.4 million for the six months ended June 30,
1998. The net impact of interest rate swaps in effect for the first six
months of 1999 and 1998 was immaterial. See "Capital Resources and Liquidity
- - Credit Facility."
<PAGE> 21
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
Income Taxes. For the first half of 1999 the Company recorded a tax benefit
of $2.9 million on pretax loss of $7.1 million, an effective rate of 40%.
This compares to a tax benefit of $7.7 million provided on a pretax loss of
$20.2 million, an effective rate of 38%, for the first half 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 six months ended June 30, 1999 and
1998, the Company expended $89.9 million and $142.9 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 six-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 six months ended June 30, 1999 and
1998 included $2.5 million and $15.1 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 six months ended June 30, 1999 and 1998 were $67.1
million and $72.6 million, representing 75% and 51%, 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 six months of 1999
reflected a net source of cash of $29.0 million compared to a $59.8 million
source of cash for the first six 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. See Note 5 of the Condensed Notes to Consolidated
Financial Statements appearing elsewhere herein. 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 decreased to $87.6 million for the first six months of
1999 from $93.3 million for the first six 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 decreased
primarily as a result of lower oil and gas prices in relation to those
received for the first six months of 1998. The Company believes that EBITDAX
is a financial measure commonly used in the oil and gas industry as an
<PAGE> 22
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
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
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 June 30,
1999, the Company had $330.0 million of principal and $17.8 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 June 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 5.7% as of June 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 5.6%. 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 June 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 June 30, 1999, the Company had no indebtedness and $.1
million of letters of credit outstanding under such credit lines. Repayment
<PAGE> 23
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
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.
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 June 30, 1999, the Company had working
capital of $14.4 million and a current ratio of 1.2 to 1. Total long-term
debt outstanding at June 30, 1999 was $629.6 million. The Company's long-term
debt as a percentage of its total capitalization was 57%.
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 six months ended June 30,
1999, the Company expended $50.2 million on development activities and $9.3
million on exploration activities. This expenditure level resulted in the
drilling of 78 development wells and 7 exploratory wells. Of these wells, 73
development wells and three exploratory wells were successfully completed as
producers, for a completion success rate of 94% and 43%, respectively (an
overall success rate of 89%). In addition, the Company invested $32.5 million
in proved oil and gas property acquisitions during the first six months of
1999. For the balance of 1999, the Company currently plans to invest an
additional $78 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
<PAGE> 24
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
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
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 estimated to represent a
material exposure. While the Company believes that all significant IT systems
<PAGE> 25
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
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
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, and will continue to use, primarily 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
<PAGE> 26
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
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.
<PAGE>
<PAGE> 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 six months ended June 30, 1999, Fixed-Price Contracts
hedged 54% of the Company's natural gas production. As of June 30, 1999,
Fixed-Price Contracts are in place to hedge 243 Bcf of the Company's estimated
future gas production, representing 20% of its proved natural gas reserves as
of December 31, 1998.
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.
In July 1999, the Company entered into an oil swap for the last 5 months of
1999 which hedges 330 MBbls of oil production at $20.37 per Bbl.
<PAGE>
<PAGE> 28
LOUIS DREYFUS NATURAL GAS CORP.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK (continued)
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 June 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 June 30, 1999, as adjusted for basis. Future net revenues change with
changes in market prices and basis.
<TABLE>
<CAPTION>
FIXED-PRICE CONTRACTS
Six
Months
Ending
December Years Ending December 31, Balance
31, -------------------------------------- through
1999 2000 2001 2002 2003 2017 Total
-------- -------- -------- -------- -------- -------- ---------
(dollars in thousands, except price
data)
<S> <C> <C> <C> <C> <C> <C> <C>
NATURAL GAS SWAPS
Sales Contracts:
Contract volumes
(BBtu) . . . . . . . . . 9,353 9,830 7,475 6,405 5,650 17,783 56,496
Weighted average fixed
price per MMBtu (1). . . $ 2.36 $ 2.46 $ 2.47 $ 2.67 $ 2.92 $ 3.29 $ 2.77
Future fixed-price sales . $ 22,112 $ 24,164 $ 18,446 $ 17,098 $ 16,492 $ 58,430 $ 156,742
Future net revenues (2). . $ (835) $ 179 $ 59 $ 1,085 $ 2,086 $ 10,784 $ 13,358
Purchase Contracts:
Contract volumes (BBtu). . (5,520) -- -- -- -- -- (5,520)
Weighted average fixed
price per MMBtu (1). . . $ 2.18 $ -- $ -- $ -- $ -- $ -- $ 2.18
Future fixed-price
purchases. . . . . . . . $(12,038) $ -- $ -- $ -- $ -- $ -- $ (12,038)
Future net revenues(2) . . $ 1,589 $ -- $ -- $ -- $ -- $ -- $ 1,589
NATURAL GAS PHYSICAL
DELIVERY CONTRACTS
Contract volumes (BBtu). . 12,143 22,678 23,240 23,115 20,245 71,483 172,904
Weighted average fixed
price per MMBtu (1). . . $ 2.81 $ 2.94 $ 3.06 $ 3.21 $ 3.47 $ 4.32 $ 3.61
Future fixed-price sales . $ 34,137 $ 66,675 $ 71,109 $ 74,150 $ 70,292 $308,529 $ 624,892
Future net revenues (2). . $ 2,549 $ 7,749 $ 9,699 $ 10,973 $ 11,157 $ 40,406 $ 82,533
NATURAL GAS COLLARS
Contract volumes (BBtu):
Floor. . . . . . . . . . 12,052 -- -- -- -- -- 12,052
Ceiling. . . . . . . . . 19,320 -- -- -- -- -- 19,320
</TABLE>
<PAGE> 29
LOUIS DREYFUS NATURAL GAS CORP.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK (continued)
<TABLE>
<CAPTION>
FIXED-PRICE CONTRACTS (continued)
Six
Months
Ending
December Years Ending December 31, Balance
31, -------------------------------------- through
1999 2000 2001 2002 2003 2017 Total
-------- -------- -------- -------- -------- -------- ---------
(dollars in thousands, except price data)
<S> <C> <C> <C> <C> <C> <C> <C>
Weighted average fixed
price per MMBtu (1):
Floor. . . . . . . . . . $ 2.01 $ -- $ -- $ -- $ -- $ -- $ 2.01
Ceiling. . . . . . . . . $ 2.10 $ -- $ -- $ -- $ -- $ -- $ 2.10
Future fixed-price sales . $ 40,572 $ -- $ -- $ -- $ -- $ -- $ 40,572
Future net revenues (2). . $ (6,610) $ -- $ -- $ -- $ -- $ -- $ (6,610)
TOTAL NATURAL GAS
CONTRACTS (3):
Contract volumes (MBbls) . 35,296 32,508 30,715 29,520 25,895 89,266 243,200
Weighted average fixed
price per MMBtu (1). . . $ 2.40 $ 2.79 $ 2.92 $ 3.09 $ 3.35 $ 4.11 $ 3.33
Future fixed-price sales . $ 84,783 $ 90,839 $ 89,555 $ 91,248 $ 86,784 $366,959 $ 810,168
Future net revenues (2). . $ (3,307) $ 7,928 $ 9,758 $ 12,058 $ 13,243 $ 51,190 $ 90,870
<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) - Does not include basis swaps with notional volumes by year, as follows: 1999 - 9.6 Tbtu;
2000 - 21.3 TBtu; 2001 - 9.4 TBtu; and 2002 - 5.5 TBtu.
</TABLE>
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
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 June 30, 1999 are
identical. Such amounts are provided below.
<PAGE> 30
LOUIS DREYFUS NATURAL GAS CORP.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK (continued)
<TABLE>
<CAPTION>
Estimated
Fair Value
------------
(in thousands)
<S> <C>
Derivative assets:
Fixed-price natural gas swaps:
Sales contracts. . . . . . . . . . . . . . . . . . . . . . $ 15,357
Purchase contracts . . . . . . . . . . . . . . . . . . . . 1,558
Fixed-price natural gas collars . . . . . . . . . . . . . . 455
Fixed-price natural gas delivery contracts. . . . . . . . . 70,195
Interest rate swaps - fixed . . . . . . . . . . . . . . . . 4,277
Derivative liabilities:
Fixed-price natural gas swaps - sales contracts . . . . . . (5,813)
Fixed-price natural gas collars . . . . . . . . . . . . . . (7,065)
Fixed-price natural gas delivery contracts. . . . . . . . . (12,518)
Natural gas basis swaps . . . . . . . . . . . . . . . . . . (3,943)
Interest rate swaps - fixed . . . . . . . . . . . . . . . . (95)
------------
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 62,408
============
</TABLE>
The fair value of Fixed-Price Contracts as of June 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.
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
June 30, 1999 does not necessarily represent the value a third party would pay
to assume the Company's positions. See "Note 5 -- Contingencies" of the
Condensed Notes to Consolidated Financial Statements appearing elsewhere in
this document.
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 June 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.
<PAGE> 31
LOUIS DREYFUS NATURAL GAS CORP.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK (continued)
Under the interest rate swaps, the Company receives the LIBOR three-month rate
(5.4% at June 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.
<PAGE>
<PAGE> 32
LOUIS DREYFUS NATURAL GAS CORP.
PART II. OTHER INFORMATION
ITEM 1 -- NONE
ITEM 2 -- NONE
ITEM 3 -- NONE
ITEM 4 -- SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The 1999 Annual Meeting of Shareholders was held on May 18, 1999. The
following were submitted to a vote of the Company's shareholders:
1. The election of twelve directors for the ensuing year and until their
successors are duly elected and qualified. The results of the election
for each director are as follows:
Gerard Louis-Dreyfus 35,260,510 votes for; 995,294 votes withheld; 0
votes abstaining
Simon B. Rich, Jr. 36,243,703 votes for; 12,101 votes withheld; 0
votes abstaining
Mark Andrews 36,223,733 votes for; 32,071 votes withheld; 0
votes abstaining
Mark E. Monroe 36,243,848 votes for; 11,956 votes withheld; 0
votes abstaining
Richard E. Bross 36,225,024 votes for; 30,780 votes withheld; 0
votes abstaining
Daniel R. Finn, Jr. 36,243,827 votes for; 11,977 votes withheld; 0
votes abstaining
Peter G. Gerry 36,243,448 votes for; 12,356 votes withheld; 0
votes abstaining
John H. Moore 36,242,098 votes for; 13,706 votes withheld; 0
votes abstaining
James R. Paul 36,243,823 votes for; 11,981 votes withheld; 0
votes abstaining
Ernest F. Steiner 35,261,313 votes for; 994,491 votes withheld; 0
votes abstaining
Nancy K. Quinn 36,242,811 votes for; 12,993 votes withheld; 0
votes abstaining
E. William Barnett 36,224,456 votes for; 31,348 votes withheld; 0
votes abstaining
2. The approval of amendments to the Company's Stock Option Plan. The
results of the shareholder vote included 32,213,770 votes for; 4,031,436
votes against; and 10,598 abstaining.
3. Ratification of the selection of Ernst & Young as independent auditors of
the Company for the year ending December 31, 1998. The results of the
shareholder vote included 36,223,627 votes for; 28,997 votes against;
and 3,180 votes abstaining.
<PAGE> 33
LOUIS DREYFUS NATURAL GAS CORP.
PART II. OTHER INFORMATION (continued)
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
<PAGE>
<PAGE> 34
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
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
This schedule contains summary financial information extracted from the
unaudited consolidated balance sheet at June 30, 1999 and the unaudited
consolidated statement of operations for the six months ended June 30, 1999
and is qualified in its entirety by reference to such financial statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> JUN-30-1999
<CASH> 7,983
<SECURITIES> 0
<RECEIVABLES> 53,360
<ALLOWANCES> (1,315)
<INVENTORY> 184
<CURRENT-ASSETS> 74,624
<PP&E> 1,583,721
<DEPRECIATION> (475,175)
<TOTAL-ASSETS> 1,267,063
<CURRENT-LIABILITIES> 60,192
<BONDS> 629,637
0
0
<COMMON> 401
<OTHER-SE> 483,239
<TOTAL-LIABILITY-AND-EQUITY> 1,267,063
<SALES> 128,461
<TOTAL-REVENUES> 119,545
<CGS> 31,453
<TOTAL-COSTS> 126,670
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 20,247
<INCOME-PRETAX> (7,125)
<INCOME-TAX> (2,850)
<INCOME-CONTINUING> (4,275)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (4,275)
<EPS-BASIC> (.11)
<EPS-DILUTED> (.11)
</TABLE>
