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 MARCH 31, 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
[LOGO] 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 / /.
40,115,758 shares of common stock, $.01 par value, issued and outstanding at
May 11, 1999.
LOUIS DREYFUS NATURAL GAS CORP.
TABLE OF CONTENTS
- -------------------------------------------------------------------------------
PART I. FINANCIAL INFORMATION PAGE
Item 1 -- CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
Consolidated Balance Sheets:
March 31, 1999 and December 31, 1998.................................................................... 3
Consolidated Statements of Operations:
Three months ended March 31, 1999 and 1998.............................................................. 4
Consolidated Statements of Stockholders' Equity
March 31, 1999 and December 31, 1998.................................................................... 5
Consolidated Statements of Cash Flows:
Three months ended March 31, 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............................................................................... 10
Item 3 -- QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.......................................... 17
PART II. OTHER INFORMATION................................................................................ 20
Page 2 of 21
LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED BALANCE SHEETS (RESTATED)
(DOLLARS IN THOUSANDS)
A S S E T S
MARCH 31, DECEMBER 31,
1999 1998
------------ ------------
(UNAUDITED)
CURRENT ASSETS
Cash and cash equivalents......................................................... $ 840 $ 2,539
Receivables:
Oil and gas sales.............................................................. 32,411 37,381
Joint interest and other, net.................................................. 11,117 11,725
Costs reimbursable by insurance................................................ -- 7,200
Fixed-price contracts and other derivatives....................................... 17,359 23,338
Prepaids and other................................................................ 3,086 4,572
------------ -------------
Total current assets........................................................... 64,813 86,755
------------ -------------
PROPERTY AND EQUIPMENT, at cost, based on successful efforts
accounting................................................................... 1,566,145 1,519,296
Less accumulated depreciation, depletion and amortization ........................ (456,700) (434,693)
------------ -------------
1,109,445 1,084,603
------------ -------------
OTHER ASSETS
Fixed-price contracts and other derivatives....................................... 91,128 107,302
Other, net........................................................................ 4,556 5,148
------------ -------------
95,684 112,450
------------ -------------
$ 1,269,942 $ 1,283,808
============ =============
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
CURRENT LIABILITIES
Accounts payable.................................................................. $ 27,936 $ 38,222
Accrued liabilities............................................................... 20,000 12,988
Revenues payable.................................................................. 8,633 10,940
------------ -------------
Total current liabilities...................................................... 56,569 62,150
------------ -------------
LONG-TERM DEBT.................................................................... 618,440 596,844
------------ -------------
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred revenue.................................................................. 15,070 15,551
Deferred income taxes............................................................. 51,159 65,116
Other............................................................................. 31,977 24,686
------------ -------------
98,206 105,353
------------ -------------
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, 40,109,758 shares................................................. 401 401
Additional paid-in capital........................................................ 419,075 419,075
Retained earnings................................................................. 6,893 6,735
Accumulated other comprehensive income ........................................... 70,358 93,250
------------ -------------
496,727 519,461
------------ -------------
$ 1,269,942 $ 1,283,808
============ =============
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
Page 3 of 21
LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
(IN THOUSANDS, EXCEPT PER SHARE DATA)
THREE MONTHS ENDED
MARCH 31,
------------------------
1999 1998
---------- ----------
(RESTATED)
REVENUES
Oil and gas sales.................................................................... $ 58,155 $ 67,914
Change in derivative fair value...................................................... 3,685 --
Other income......................................................................... 1,943 1,682
---------- ----------
63,783 69,596
---------- ----------
EXPENSES
Operating costs...................................................................... 15,593 17,021
General and administrative........................................................... 5,815 6,203
Exploration costs.................................................................... 3,939 7,580
Depreciation, depletion and amortization............................................. 28,130 32,041
Interest............................................................................. 10,014 10,046
---------- ----------
63,491 72,891
---------- ----------
Income (loss) before income taxes.................................................... 292 (3,295)
Income tax provision (benefit)....................................................... 134 (1,252)
---------- ----------
NET INCOME (LOSS).................................................................... $ 158 $ (2,043)
========== ==========
Net income (loss) per share - basic and diluted...................................... $ .00 $ (.05)
========== ==========
Weighted average diluted common shares............................................... 40,129 40,099
========== ==========
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
Page 4 of 21
LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (UNAUDITED) (RESTATED)
(IN THOUSANDS)
ACCUMULATED
ADDITIONAL OTHER TOTAL
COMMON PAID-IN RETAINED COMPREHENSIVE STOCKHOLDERS'
STOCK CAPITAL EARNINGS INCOME EQUITY
----------- ----------- ------------ ------------- -------------
BALANCE AT DECEMBER 31, 1998............ $ 401 $ 419,075 $ 6,735 $ 93,250 $ 519,461
-----------
Comprehensive loss:
Net income.............................. -- -- 158 -- 158
Other comprehensive loss, net of tax:
Reclassification adjustments - contract
settlements........................ -- -- -- (4,283) (4,283)
Change in fixed-price contract and
other derivative fair value........ -- -- -- (18,609) (18,609)
-----------
Total comprehensive loss................ -- -- -- -- (22,734)
----------- ----------- ----------- ----------- -----------
BALANCE AT MARCH 31, 1999............... $ 401 $ 419,075 $ 6,893 $ 70,358 $ 496,727
=========== =========== =========== =========== ===========
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
Page 5 of 21
LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(IN THOUSANDS)
THREE MONTHS ENDED
MARCH 31,
------------------------
1999 1998
---------- ----------
(RESTATED)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)....................................................................... $ 158 $ (2,043)
Items not affecting cash flows:
Depreciation, depletion and amortization............................................. 28,130 32,041
Deferred income taxes................................................................ 74 (1,527)
Exploration costs.................................................................... 3,939 7,580
Change in derivative fair value...................................................... (3,685) --
Other................................................................................ 7 94
Net change in operating assets and liabilities:
Accounts receivable.................................................................. 12,778 7,911
Prepaids and other................................................................... 1,486 3,683
Accounts payable..................................................................... (10,286) (17,967)
Accrued liabilities.................................................................. 2,664 1,404
Revenues payable..................................................................... (2,307) (1,879)
---------- ----------
32,958 29,297
---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES
Exploration and development expenditures................................................ (31,659) (58,622)
Acquisition of oil and gas properties................................................... (21,983) (3,551)
Additions to other property and equipment............................................... (441) (721)
Proceeds from sale of property and equipment............................................ 22 88
Change in other assets.................................................................. (8) (173)
---------- ----------
(54,069) (62,979)
---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from bank borrowings........................................................... 113,869 155,075
Repayments of bank borrowings........................................................... (92,269) (120,575)
Proceeds from stock options exercised................................................... -- 223
Change in deferred revenue.............................................................. (481) (436)
Change in gains from price-risk management activities................................... (1,077) (222)
Change in other long-term liabilities................................................... (630) (378)
---------- ----------
19,412 33,687
---------- ----------
Change in cash and cash equivalents..................................................... (1,699) 5
Cash and cash equivalents, beginning of period.......................................... 2,539 5,538
---------- ----------
Cash and cash equivalents, end of period................................................ $ 840 $ 5,543
========== ==========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Interest paid, net of capitalized interest.............................................. $ 4,721 $ 4,393
Income taxes paid....................................................................... 125 --
---------- ----------
$ 4,846 $ 4,393
========== ==========
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
Page 6 of 21
LOUIS DREYFUS NATURAL GAS CORP.
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
MARCH 31, 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 period ended March 31, 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
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 found to be insufficient as of the October 1, 1998 date of
adoption of SFAS 133. Therefore, the Company is precluded from being able to
utilize the special provisions of hedge accounting for the fourth quarter of
1998, and the period from January 1, 1999 to January 13, 1999, the date the
Company's documentation was sufficient in relation to the formal
documentation requirements of the standard. As a result, the changes in fair
value of all of the Company's derivatives during these periods were required
to be reported in results of operations, rather than in other comprehensive
income. The accompanying financial statements as of March 31, 1999, and for
the quarter then ended, have been restated to reflect this change in
accounting. The effect of the restatement is provided below.
AS
AS PREVIOUSLY
RESTATED REPORTED
---------- ----------
(IN THOUSANDS, EXCEPT
PER SHARE DATA)
STATEMENT OF OPERATIONS DATA FOR THE QUARTER ENDED MARCH 31, 1999:
Change in derivative fair value................................................ $ 3,685 $ --
Other income................................................................... 1,943 (607)
Total revenues................................................................. 63,783 57,548
Interest expense............................................................... 10,014 10,048
Total expenses................................................................. 63,491 63,525
Income (loss) before income taxes.............................................. 292 (5,977)
Income tax provision (benefit)................................................. 134 (1,793)
Net income (loss).............................................................. 158 (4,184)
Net income (loss) per share - basic and diluted................................ .00 (.10)
BALANCE SHEET DATA AS OF MARCH 31, 1999:
Long-term debt................................................................. 618,440 617,733
Deferred income taxes.......................................................... 51,159 51,883
Total deferred credits and other liabilities................................... 98,206 98,930
Retained earnings (deficit).................................................... 6,893 (6,719)
Accumulated other comprehensive income......................................... 70,358 83,953
Total stockholders' equity..................................................... 496,727 496,710
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
Page 7 of 21
LOUIS DREYFUS NATURAL GAS CORP.
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (CONTINUED)
MARCH 31, 1999
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. See Note 2 -- Restated Financial Statements. Changes in the
fair value of derivative instruments which are not designated as hedges or
are defined by SFAS 133 as being "fair value hedges" are recorded in earnings
as the changes occur. Earnings for the quarter ended March 31, 1999 included
a net gain of $3.7 million, which is comprised of an increase in derivative
fair value through January 13, 1999 of $6.2 million, a $1.0 million loss
attributable to hedge ineffectiveness, and a $1.5 million loss relating to
changes in fair value for Fixed-Price Contracts not qualifying as cash flow
hedges through March 31, 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. The purchase method was used to
account for this acquisition.
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
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 amounts 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. The
complaint also seeks subordination of the Company's claim. The court denied
the Company's motion to dismiss the complaint. The Company considers the
allegations in the complaint to be without merit and will vigorously defend
against this action. Collection of unpaid interest and principal on the
Midcon note is uncertain and no amounts have been recorded with respect
thereto in the accompanying financial statements as of March 31, 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 not been heard. 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 March 31, 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
Page 8 of 21
LOUIS DREYFUS NATURAL GAS CORP.
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (CONTINUED)
MARCH 31, 1999
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.
NOTE 6 -- FIXED-PRICE CONTRACTS
The Company was a party to two Fixed-Price Contracts, both long-term
physical delivery contracts, with independent power producers ("IPPs") which
sold electrical power under firm, fixed-price contracts to Niagra Mohawk
Corporation ("NIMO"), a New York state utility ("NIMO Contracts"). The
ability of these IPPs to perform their obligations to the Company was
dependent on the continued performance by NIMO of its power purchase
obligations to the counterparties. NIMO has taken aggressive regulatory,
judicial and contractual actions in recent years seeking to curtail power
purchase obligations, including its obligations to the NIMO Contract
counterparties, and had further stated that its future financial prospects
were dependent on its ability to resolve these obligations, along with other
matters. In July 1997, NIMO entered into a Master Restructuring Agreement
(the "MRA") with 16 IPPs, including the NIMO Contract counterparties.
Subsequently, one of the NIMO Contract counterparties withdrew from the MRA.
The power purchase agreement between NIMO and the other counterparty was
terminated. In connection therewith, the Company agreed to terminate its
fixed-price contract to the counterparty in exchange for $40.1 million. This
termination amount was received in June 1998 and has been recorded in
accumulated other comprehensive income, net of tax effect. The remaining NIMO
Contract which hedges 53 Bcf of natural gas as of March 31, 1999 remains in
force and is reflected in the Company's balance sheet at a fair value of
$67.5 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 this contract in the court
system. Although there can be no assurance, Management does not expect that
NIMO will ultimately succeed in these efforts.
Page 9 of 21
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 majority of the
Company's growth has been the result of proved reserve acquisitions
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 March 31, 1999, the Company's Fixed-Price Contracts hedged
252 Bcfe of future production representing 19% of its estimated proved
reserves, 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
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.
Page 10 of 21
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (CONTINUED)
MMBTU. Million Btus.
MMCF. Volume of one million cubic feet.
MMcfe. Million cubic feet of natural gas equivalent, determined using the
ratio of one Bbl of oil or condensate to six Mcf of natural gas.
TBTU. One Trillion Btus.
SELECTED OPERATING DATA. The following table provides certain operating
data relating to the Company's operations.
THREE MONTHS ENDED
MARCH 31,
--------------------
1999 1998
-------- --------
OIL AND GAS SALES: (M$)
Wellhead oil sales............................................................... $ 8,228 $ 11,485
Effect of Fixed-Price Contract settlements (1)................................... -- 496
-------- --------
Total oil sales.................................................................. $ 8,228 $ 11,981
======== ========
Wellhead natural gas sales ...................................................... $ 42,516 $ 52,335
Effect of Fixed-Price Contract settlements (1)................................... 7,411 3,598
-------- --------
Total natural gas sales.......................................................... $ 49,927 $ 55,933
======== ========
PRODUCTION:
Oil production (MBbls)........................................................... 742 825
Natural gas production (MMcf).................................................... 25,468 24,954
Net equivalent production (MMcfe)................................................ 29,922 29,903
Oil production hedged by Fixed-Price Contracts (MBbls)........................... -- 79
Gas production hedged by Fixed-Price Contracts (BBtu)............................ 8,790 11,330
AVERAGE SALES PRICE:
Oil (per Bbl):
Wellhead price................................................................. $ 11.09 $ 13.93
Effect of Fixed-Price Contract settlements (1)................................. -- .60
-------- --------
Total.......................................................................... $ 11.09 $ 14.53
======== ========
Average fixed price received under Fixed-Price Contracts....................... $ n/a $ 22.20
Net effective realization (2).................................................. n/a 92%
Natural gas (per Mcf):
Wellhead price................................................................. $ 1.67 $ 2.10
Effect of Fixed-Price Contract settlements (1)................................. .29 .14
-------- --------
Total.......................................................................... $ 1.96 $ 2.24
======== ========
Average fixed price received under Fixed-Price Contracts....................... $ 2.75 $ 2.62
Net effective realization (2).................................................. 92% 92%
Equivalent price (per Mcfe)...................................................... $ 1.94 $ 2.27
EXPENSES: (per Mcfe)
Operating costs:
Lease operating................................................................ $ .43 $ .45
Production taxes............................................................... .09 .12
General and administrative....................................................... .19 .21
Depreciation, depletion and amortization - oil and gas........................... .89 1.03
------------------------------------
(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.
(2) - Represents the net effective price realized for the Company's hedged
production (after consideration for basis results) as a percentage of
the fixed prices in the Company's Fixed-Price Contracts. See
"Quantitative and Qualitative Disclosures About Market Risk -
Fixed-Price Contracts."
Page 11 of 21
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (CONTINUED)
RESULTS OF OPERATIONS -- THREE MONTHS ENDED MARCH 31, 1999 COMPARED TO THREE
MONTHS ENDED MARCH 31, 1998
NET INCOME AND CASH FLOWS FROM OPERATING ACTIVITIES. For the quarter
ended March 31, 1999, the Company realized net income of $.2 million, or $.00
per share, on total revenue of $63.8 million. This compares with a net loss
of $2.0 million, or $0.05 per share, on total revenue of $69.6 million for
the first quarter of 1998. Cash flows from operating activities (before
working capital changes) for the first quarter of 1999 declined 21% to $28.6
million compared to $36.1 million for the first quarter of 1998. The increase
in earnings for the first quarter of 1999 was principally attributable to a
significant improvement in cash and non-cash expenses for the period. The
decline in operating cash flows was largely due to lower oil and gas prices.
Cash flows provided by operating activities after consideration of the net
change in working capital increased to $33.0 million from the $29.3 million
reported for the first quarter of 1998, primarily due to a greater decrease
in accounts receivable and a smaller decrease in accounts payable for the
first quarter of 1999 in relation to the prior year quarter.
PRODUCTION. The Company's total production for the first quarter of 1999
remained relatively constant in relation to the prior-year first quarter at
29.9 Bcfe. Gas production increased to 25.5 Bcf compared to 25.0 Bcf for the
first quarter of 1998, an increase of 2%. Oil production for the first
quarter of 1999 decreased 10% to 742 MBbls compared to 825 MBbls for the
prior-year first quarter.
OIL AND GAS PRICES. On a natural gas equivalent basis, the Company
received an average price of $1.94 per Mcfe for the quarter ended March 31,
1999, a decrease of 15% from the $2.27 received for the first quarter of
1998. The Company's gas production yielded an average price of $1.96 per Mcf,
a decrease of 13% compared to $2.24 per Mcf for the prior-year first quarter.
The Company's average gas price for the first quarter of 1999 was enhanced
$.29 per Mcf as a result of the Company's hedging activities. The average gas
price for the first quarter of 1998 was enhanced $.14 as a result of the
Fixed-Price Contracts in effect for that period. The average oil price for
the first quarter of 1999 was $11.09 per Bbl compared to $14.53 per Bbl for
the prior-year first quarter, a decrease of 24%. No fixed-price oil contracts
were in effect during the 1999 first quarter. The 1998 first quarter average
oil price was enhanced $.60 per Bbl as a result of the Company's hedging
activities.
The net effect of lower gas prices and higher gas production was to
decrease gas sales to $49.9 million for the first quarter of 1999 compared to
$55.9 million for the first quarter of 1998. The combination of lower oil
production and lower oil prices decreased oil sales to $8.2 million compared
to $12.0 million reported for the prior-year quarter. The impact of the
Company's Fixed-Price Contract settlements for each period was to increase
oil and gas sales by $7.4 million for the quarter ended March 31, 1999 and to
increase oil and gas sales by $4.1 million for the quarter ended March 31,
1998. See "Quantitative and Qualitative Disclosures About Market Risk -
Fixed-Price Contracts."
CHANGE IN DERIVATIVE FAIR VALUE. 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 found to be
insufficient as of the October 1, 1998 date of adoption of SFAS 133.
Therefore, the Company is precluded from being able to utilize the special
provisions of hedge accounting for the fourth quarter of 1998, and the period
from January 1, 1999 to January 13, 1999, the date the Company's
documentation was sufficient in relation to the formal documentation
requirements of the standard. As a result, the changes in fair value of all
of the Company's derivatives during these periods were required to be
reported in results of operations, rather than in other comprehensive income.
The accompanying financial statements as of March 31, 1999, and for the
quarter then ended, have been restated to reflect this change in accounting.
The effect of the restatement was to increase reported results of operations
by $6.3 million ($4.3 million after tax) for the quarter ended March 31,
1999. The pretax change in derivative fair value through January 13, 1999 of
$6.2 million was partially reduced by a $2.5 million non-cash change in
derivative fair value attributable to ineffectiveness and other fair value
changes for certain derivatives not qualifying as cash flow hedges pursuant
to SFAS 133.
OTHER INCOME. Other income for the first quarter of 1999 was $1.9
million, approximating the $1.7 million reported
Page 12 of 21
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (CONTINUED)
for the first quarter of 1998.
OPERATING COSTS. Operating costs for the first quarter of 1999 were
comprised of $13.0 million of lease operating expenses and $2.6 million of
production taxes. This compares to $13.4 million of lease operating expenses
and $3.6 million of production taxes for the first 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. The decrease in production taxes is primarily the result of
lower oil and gas prices in the first quarter of 1999. Lease operating
expenses on a natural gas equivalent unit of production basis improved to
$.43 per Mcfe compared to $.45 per Mcfe for the three months ended March 31,
1998.
GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative expense
("G&A") for the first quarter of 1999 was $5.8 million, a decrease of 6% from
the prior-year first quarter amount of $6.2 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 10% to $.19 per Mcfe for the 1999 first quarter compared
to $.21 per Mcfe for the first quarter of 1998.
EXPLORATION COSTS. Exploration costs, comprised of geological and
geophysical costs, exploratory dry holes and leasehold impairment costs, were
$3.9 million for the quarter ended March 31, 1999, compared to $7.6 million
for the first quarter of 1998. The 1999 amount consists of $.7 million of
seismic acquisition and other geological and geophysical costs, $2.7 million
of leasehold costs and $.5 million of dry hole costs. The 1998 amount
consists of $4.1 million of seismic acquisition and other geological and
geophysical costs and $3.5 million of dry hole costs.
DEPRECIATION, DEPLETION AND AMORTIZATION. Depreciation, depletion and
amortization ("DD&A") for the first quarter of 1999 was $28.1 million
compared to $32.0 million for the prior-year first quarter. This decrease in
DD&A is attributable to a decrease in the oil and gas DD&A rate, improving to
$.89 per Mcfe for the first quarter of 1999 compared to $1.03 per Mcfe for
the first 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.
INTEREST EXPENSE. Interest expense for the first quarter of 1999 and
1998 was $10.0 million. The net impact of interest rate swaps in effect for
the first quarter of 1999 and 1998 was not material. See "Capital Resources
and Liquidity -- Credit Facility."
INCOME TAXES. For the first quarter of 1999, the Company recorded a tax
provision of $.1 million on pretax income of $.3 million, an effective rate
of 46%. This compares to a tax benefit of $1.3 million provided on a pretax
loss of $3.3 million, an effective rate of 38%, for the first quarter of
1998. The effective rate for the first quarter of 1999 was higher than the
statutory rate primarily due to the effect of permanent differences created
by differences in the tax bases of acquired assets.
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 quarters ended March 31, 1999 and
1998, the Company expended $53.6 million and $62.2 million, respectively, in
oil and gas property acquisition, exploration and development activities,
representing substantially all of the cash flows invested by the Company
during the three-month periods. See "Commitments and Capital Expenditures."
Cash flows from operating activities before changes in working capital for
the quarters ended March 31, 1999 and 1998 were $28.6 million and $36.1
million, representing 53% and 58%, respectively, of the oil and gas property
investments made for each quarter. 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 or gas could result in reduction of cash flows from operating
activities, which in turn could impact the amount of capital investment. See
"Quantitative and Qualitative Disclosures About Market Risk - Fixed-Price
Contracts."
Page 13 of 21
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (CONTINUED)
Cash flows from financing activities for the first quarter of 1999
reflected a source of cash of $19.4 million, compared to a $33.7 million
source of cash for the first quarter of 1998. 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 from $46.4 million in the first quarter
of 1998 to $38.7 million in the first quarter of 1999 primarily as a result
of lower oil and gas prices. EBITDAX is defined herein as income (loss)
before interest, income taxes, DD&A, impairments, exploration costs and
change in derivative fair value. LDNG 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 maturity on October 14, 2002. The
Company has relied upon the Credit Facility to provide funds for
acquisitions, drilling activities and to provide letters of credit to meet
the Company's margin requirements under Fixed-Price Contracts. As of March
31, 1999, the Company had $290.0 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 March
31, 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. At March 31, 1999, the effective interest rate for
borrowings under the Credit Facility was 5.6%, including the effect of
interest rate swaps. 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 $45.0 million as of March 31, 1999.
Such short-term lines of credit are primarily used to meet margin
requirements under Fixed-Price Contracts and for working capital purposes. As
of March 31, 1999, the Company had $28.8 million of indebtedness and $.1
million of letters of credit outstanding under these 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.
Page 14 of 21
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." At March 31, 1999, the
Company had working capital of $8.2 million and a current ratio of 1.1 to 1.
Total long-term debt outstanding at March 31, 1999 was $618.4 million. The
Company's long-term debt as a percentage of its total capitalization was 55%.
COMMITMENTS AND CAPITAL EXPENDITURES
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. For the quarter ended March 31, 1999,
the Company expended $25.8 million on development activities and $5.9 million
on exploration activities. This expenditure level resulted in the drilling of
41 development wells and 7 exploratory wells. Of these wells, 39 development
wells and 5 exploratory wells were successfully completed as producers, for a
completion success rate of 95% and 71%, respectively (an overall success rate
of 92%). In addition, the Company invested $24.1 million in proved oil and
gas property acquisitions during the first quarter of 1999. For the balance
of the year, the Company currently plans to invest an additional $114 million
in connection with its drilling and proved reserve acquisition programs
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 entered into a purchase and sale
agreement with a third party for a $9 million acquisition of proved reserves
in April 1999. This acquisition is expected to close in May 1999.
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 expenditure 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 ability of the Company to produce its oil and gas reserves, to
maintain environmental compliance and to meet contractual obligations. It
also includes the ability of the Company's 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 the Company's 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
Page 15 of 21
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (CONTINUED)
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
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 estimates that it is 90% complete with the
assessment phase of its exposure to Year 2000 compliance by material third
parties (identified above). The assessment phase is expected to be completed
in May 1999. 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 material third
parties to the extent information is available. 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 the Company's
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. See Risk Factors below.
COSTS. The Company has used, 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 has been immaterial. The estimated cost
attributable to remaining compliance issues in the aggregate is expected to
be less than $200,000 including hardware, software, internal and external
labor costs, which will be funded through operating cash flows.
RISK FACTORS. Management 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 not fully completed all phases of its Year 2000
plan. Further, no assurance can be given that all material issues 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, there can be no
assurance that the Company's results of operations will not be materially
affected. Additionally, there can be no assurance that non-compliance by
third parties will not 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 as of this date. Accordingly, the Company currently does
not have a contingency plan in place to address Year 2000 non-compliance. The
Company plans to evaluate the status of its Year 2000 plan in June 1999 and
will determine at that date whether such a plan is advisable.
Page 16 of 21
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 has entered into Fixed-Price
Contracts to reduce its exposure to unfavorable changes in oil and gas prices
which are subject to significant and often volatile fluctuation. 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
quarter ended March 31, 1999, Fixed-Price Contracts hedged 35% of the
Company's natural gas production. As of March 31, 1999, Fixed-Price Contracts
are in place to hedge 252 Bcf of the Company's estimated future gas
production.
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.
During the quarter ended March 31, 1999, the Company entered into a
number of fixed-price collars for various periods of 1999 which hedge 14 TBtu
of gas production at an average floor price of $1.83 per MMBtu and 31 TBtu at
an average ceiling price of $2.09 per MMBtu. In addition, the Company entered
into a 1999 fixed-price swap which hedges 3 TBtu at $1.94 per MMBtu.
Page 17 of 21
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 (as defined
below) attributable to the Company's Fixed-Price Contracts as of March 31,
1999.
NINE
MONTHS
ENDING YEARS ENDING DECEMBER 31, BALANCE
DECEMBER 31, ----------------------------------------- THROUGH
1999 2000 2001 2002 2003 2017 TOTAL
------ -------- -------- -------- -------- -------- ---------
(DOLLARS IN THOUSANDS, EXCEPT PRICE DATA)
NATURAL GAS SWAPS:
SALES CONTRACTS
Contract volumes (BBtu)..... 14,670 9,830 7,475 6,405 5,650 17,783 61,813
Weighted-average fixed price
per MMBtu (1)............. $ 2.34 $ 2.46 $ 2.47 $ 2.67 $ 2.92 $ 3.29 $ 2.73
Future fixed-price sales.... $ 34,276 $ 24,164 $ 18,446 $ 17,098 $ 16,492 $ 58,429 $ 168,905
Future net revenues (2)..... $ 3,666 $ 1,746 $ 1,101 $ 1,886 $ 2,683 $ 12,715 $ 23,797
PURCHASE CONTRACTS
Contract volumes (BBtu)..... (8,250) -- -- -- -- -- (8,250)
Weighted-average fixed price
per MMBtu (1)............. $ 2.18 $ -- $ -- $ -- $ -- $ -- $ 2.18
Future fixed-price purchases $(17,992) $ -- $ -- $ -- $ -- $ -- $ (17,992)
Future net revenues (2)..... $ (577) $ -- $ -- $ -- $ -- $ -- $ (577)
NATURAL GAS PHYSICAL DELIVERY
CONTRACTS:
Contract volumes (BBtu)..... 18,187 22,678 23,240 23,115 20,245 71,483 178,948
Weighted-average fixed price
per MMBtu (1)............. $ 2.78 $ 2.94 $ 3.06 $ 3.21 $ 3.47 $ 4.32 $ 3.58
Future fixed-price sales.... $ 50,472 $ 66,675 $ 71,109 $ 74,150 $ 70,292 $ 308,529 $ 641,227
Future net revenues (2)..... $ 10,344 $ 12,311 $ 14,578 $ 16,560 $ 17,724 $ 89,216 $ 160,733
NATURAL GAS COLLARS:
Contract volumes (BBtu):
Floor..................... 19,150 -- -- -- -- -- 19,150
Ceiling................... 31,150 -- -- -- -- -- 31,150
Weighted-average fixed price
per MMBtu (1):
Floor..................... $ 1.99 $ -- $ -- $ -- $ -- $ -- $ 1.99
Ceiling................... $ 2.09 $ -- $ -- $ -- $ -- $ -- $ 2.09
Future fixed-price sales.... $ 38,114 $ -- $ -- $ -- $ -- $ -- $ 38,114
Future net revenues (2)..... $ (2,689) $ -- $ -- $ -- $ -- $ -- $ (2,689)
TOTAL NATURAL GAS CONTRACTS (3):
Contract volumes (BBtu)..... 43,757 32,508 30,715 29,520 25,895 89,266 251,661
Weighted-average fixed price
per MMBtu (1)............. $ 2.40 $ 2.79 $ 2.92 $ 3.09 $ 3.35 $ 4.11 $ 3.30
Future fixed-price sales.... $104,870 $ 90,839 $ 89,555 $ 91,248 $ 86,784 $ 366,958 $ 830,254
Future net revenues (2)..... $ 10,744 $ 14,057 $ 15,679 $ 18,446 $ 20,407 $ 101,931 $ 181,264
- ------------------------------------
(1) - The Company expects the prices to be realized for its hedged production
will vary from the prices shown due to location, quality and other
factors which create a differential between wellhead prices and the
floating prices under its Fixed-Price Contracts.
(2) - 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 March 31, 1999, as adjusted for basis. Future net
revenues change with changes in market prices and basis. Future net
revenues as presented herein 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 - 14.3 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
Page 18 of 21
LOUIS DREYFUS NATURAL GAS CORP.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK (CONTINUED)
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 the
associated carrying value as of March 31, 1999 are provided below.
ESTIMATED CARRYING
FAIR VALUE VALUE
---------- ----------
(IN THOUSANDS)
FIXED-PRICE CONTRACTS AS OF MARCH 31, 1999:
Natural Gas Swaps:
Sales Contracts.............................................................. $ 18,555 $ 18,555
Purchase Contracts........................................................... (583) (583)
Natural Gas Physical Delivery Contracts........................................ 77,686 77,686
Natural Gas Collars............................................................ (2,689) (2,689)
Natural Gas Basis Swaps........................................................ (4,330) (4,330)
---------- ----------
Total.......................................................................... $ 88,639 $ 88,639
========== ==========
The fair value of Fixed-Price Contracts as of March 31, 1999 was
estimated based on market prices of natural gas and crude oil for the periods
covered by the contracts. The net differential between the prices in each
contract and market prices for future periods, as adjusted for estimated
basis, has been applied to the volumes stipulated in each contract to arrive
at an estimated future value. In connection with the adoption of SFAS 133,
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 March 31, 1999
does not necessarily represent the value a third party would pay to assume
the Company's positions. See "Note 6 -- Fixed- Price Contracts" 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
March 31, 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 (5.0% at March 31, 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.
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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
Page 20 of 21
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: October 7, 1999 /s/ Jeffrey A. Bonney
----------------------------------------------------
Jeffrey A. Bonney
Executive Vice President and Chief Financial Officer
Page 21 of 21