1
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934.
For the quarterly period ended 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
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.
2
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 . . . . . . . . . . . . . 5
Consolidated Statements of Stockholders' Equity:
March 31, 1999 and December 31, 1998 . . . . . . . . . . . . . . . . 6
Consolidated Statements of Cash Flows:
Three months ended March 31, 1999 and 1998 . . . . . . . . . . . . . 7
Condensed Notes to Consolidated Financial Statements . . . . . . . . . 8
Item 2 -- MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS. . . . . . . . . . . . . . . . . . . . . . 11
Item 3 -- QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK . 21
PART II. OTHER INFORMATION . . . . . . . . . . . . . . . . . . . . 25
3
LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED BALANCE SHEETS
(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
=========== ===========
4
LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED BALANCE SHEETS (continued)
(dollars in thousands)
L I A B I L I T I E S A N D S T O C K H O L D E R S ' E Q U I T Y
March 31, December 31,
1999 1998
----------- -----------
(unaudited)
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 . . . . . . . . . . . . . . . . . . 617,733 596,103
----------- -----------
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred revenue . . . . . . . . . . . . . . . . . 15,070 15,551
Deferred income taxes. . . . . . . . . . . . . . . 51,883 65,398
Other. . . . . . . . . . . . . . . . . . . . . . . 31,977 24,686
----------- -----------
98,930 105,635
----------- -----------
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
Accumulated deficit. . . . . . . . . . . . . . . . (6,719) (2,535)
Accumulated other comprehensive income . . . . . . 83,953 102,979
----------- -----------
496,710 519,920
----------- -----------
$ 1,269,942 $ 1,283,808
=========== ===========
See accompanying notes to consolidated financial statements.
5
LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)
(in thousands, except per share data)
Three Months Ended
March 31,
------------------
1999 1998
-------- --------
REVENUES
Oil and gas sales . . . . . . . . . . . . . . . . . . . $ 58,155 $ 67,914
Other income. . . . . . . . . . . . . . . . . . . . . . (607) 1,682
-------- --------
57,548 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. . . . . . . . . . . . . . . . . . . . . . . . 10,048 10,046
-------- --------
63,525 72,891
-------- --------
Loss before income taxes. . . . . . . . . . . . . . . . (5,977) (3,295)
Income taxes. . . . . . . . . . . . . . . . . . . . . . (1,793) (1,252)
-------- --------
NET LOSS. . . . . . . . . . . . . . . . . . . . . . . . $ (4,184) $ (2,043)
======== ========
Net loss per share - basic and diluted. . . . . . . . . $ (.10) $ (.05)
======== ========
Weighted average diluted common shares. . . . . . . . . 40,110 40,099
======== ========
</TABLE)
See accompanying notes to consolidated financial statements.
6
LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (unaudited)
(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 $ (2,535) $ 102,979 $ 519,920
-----------
Comprehensive loss:
Net loss. . . . . . . . . . . -- -- (4,184) -- (4,184)
Other comprehensive loss,
net of tax:
Reclassification
adjustments. . . . . . . . -- -- -- (4,283) (4,283)
Change in fixed-price
contract and other
derivative effectiveness. . -- -- -- 636 636
Change in fixed-price
contract and other
derivative fair value . . . -- -- -- (15,379) (15,379)
-----------
Total comprehensive loss. . . -- -- -- -- (23,210)
-------- ---------- --------- ----------- -----------
BALANCE AT MARCH 31, 1999 . . $ 401 $ 419,075 $ (6,719) $ 83,953 $ 496,710
======== ========== ========= =========== ===========
See accompanying notes to consolidated financial statements.
7
LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
(in thousands)
Three Months Ended
March 31,
------------------
1999 1998
-------- --------
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (4,184) $ (2,043)
Items not affecting cash flows:.
Depreciation, depletion and amortization . . . . . . . . . . . . . . . . . 28,130 32,041
Deferred income taxes. . . . . . . . . . . . . . . . . . . . . . . . . . . (1,853) (1,527)
Exploration costs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,939 7,580
Change in contract fair value. . . . . . . . . . . . . . . . . . . . . . . 2,550 --
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41 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.
8
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 for the year
ended December 31, 1998 for an expanded discussion of the Company's financial
disclosures and accounting policies.
NOTE 2 -- 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. 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 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 charge of $1.5 million relating to changes in
fair value for Fixed-Price Contracts not qualifying as cash flow hedges and
$1.1 million of charges relating to Fixed-Price Contract hedge
ineffectiveness.
NOTE 3 -- 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.
9
LOUIS DREYFUS NATURAL GAS CORP.
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued)
March 31, 1999
The purchase method was used to account for this acquisition.
NOTE 4 -- 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 the
10
LOUIS DREYFUS NATURAL GAS CORP.
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued)
March 31, 1999
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 5 -- 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.
11
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 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
12
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
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.
13
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
Selected Operating Data. The following table provides certain operating
data relating to the Company's operations.
Three Months Ended
March 31,
--------------------
1999 1998
-------- --------
OIL AND GAS SALES: (M$)
Wellhead oil sales. . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 8,228 $ 11,485
Effect of Fixed-Price Contracts (1) . . . . . . . . . . . . . . . . . . . -- 496
-------- --------
Total oil sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 8,228 $ 11,981
======== ========
Wellhead natural gas sales. . . . . . . . . . . . . . . . . . . . . . . . $ 42,516 $ 52,335
Effect of Fixed-Price Contracts (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 Contracts (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 Contracts (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
<FN>
(1) - Represents the hedging results from the Company's Fixed-Price Contracts. See
"Quantitative and Qualitative Disclosures About Market Risk - Fixed-Price Contracts."
(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."
14
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 Loss and Cash Flows from Operating Activities. For the quarter ended
March 31, 1999, the Company realized a net loss of $4.2 million, or $0.10 per
share, on total revenue of $57.5 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 declines in
earnings and cash flows for the first quarter of 1999 were principally
attributable to lower oil and gas prices, the impact of which was partially
offset by a significant improvement in cash and non-cash expenses for the
period. 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 aggregate impact of
the Company's oil and gas hedging activities 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
15
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
Contracts."
Other Income. Other income for the first quarter of 1999 was a charge of
$.6 million compared to income of $1.7 million for the first quarter of 1998.
The 1999 amount included a $2.6 million non-cash charge attributable to
derivative contract ineffectiveness and the fair value change for certain
derivatives not qualifying as cash flow hedges under SFAS 133.
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. On a natural gas equivalent unit of production basis,
interest costs remained constant at $.34 per Mcfe compared to the first
quarter of 1998. The net impact of interest rate swaps in effect for the
16
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
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
benefit of $1.8 million on a pre-tax loss of $6.0 million, an effective rate
of 30%. This compares to a tax benefit of $1.3 million provided on a pre-tax
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 lower 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."
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 $36.1 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 and exploration costs. 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
17
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
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 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 margining
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
18
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
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." 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 $617.7 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 for the year ended December 31,
19
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
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
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
20
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
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.
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 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.
22
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.
FIXED-PRICE CONTRACTS
Nine
Months
Ending
December Years Ending December 31, Balance
31, -------------------------------------- through
1999 2000 2001 2002 2003 2017 Total
-------- -------- -------- -------- -------- -------- ---------
(dollars in thousands, except price data)
NATURAL GAS SWAPS
Sales Contracts:
Contract volumes
(BBtu) . . . . . . . . . 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 (MBbls) . 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
23
LOUIS DREYFUS NATURAL GAS CORP.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK (continued)
<FN>
(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 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
24
LOUIS DREYFUS NATURAL GAS CORP.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK (continued)
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 5 -- 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 for the year
ended December 31, 1998 for an expanded discussion of the Company's interest
rate swaps.
25
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
26
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: May 12, 1999 /s/ Jeffrey A. Bonney
---------------------------------------
Jeffrey A. Bonney
Executive Vice President and
Chief Financial Officer