<PAGE> 1
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934.
For the quarterly period ended September 30, 2000
or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934.
For the transition period from to
--------- ---------
Commission File Number 1-12480
LOUIS DREYFUS NATURAL GAS CORP.
(Exact name of registrant as specified in its charter)
Oklahoma 73-1098614
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
14000 QUAIL SPRINGS PARKWAY, SUITE 600
OKLAHOMA CITY, OKLAHOMA 73134
(Address of principal executive office) (Zip code)
Registrant's telephone number, including area code: (405) 749-1300
NONE
(Former name, former address and former fiscal year, if changed since last
report.)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. YES X NO .
----- -----
43,228,013 shares of common stock, $.01 par value, issued and outstanding at
November 6, 2000.
<PAGE>
<PAGE> 2
LOUIS DREYFUS NATURAL GAS CORP.
Table of Contents
PART I. FINANCIAL INFORMATION Page
Item 1 -- CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
Consolidated Balance Sheets:
September 30, 2000 and December 31, 1999 . . . . . . . . . . . . . . . 3
Consolidated Statements of Income:
Three months and nine months ended September 30, 2000 and 1999 . . . . 4
Consolidated Statements of Cash Flows:
Nine months ended September 30, 2000 and 1999. . . . . . . . . . . . . 5
Condensed Notes to Consolidated Financial Statements . . . . . . . . . . 6
Item 2 -- MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS. . . . . . . . . . . . . . . . . . 9
Item 3 -- QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK. . .19
PART II. OTHER INFORMATION . . . . . . . . . . . . . . . . . . . . .22
<PAGE>
<PAGE> 3
LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED BALANCE SHEETS
(dollars in thousands)
<TABLE>
<CAPTION>
A S S E T S
September 30, December 31,
2000 1999
------------- -------------
(unaudited)
<S> <C> <C>
CURRENT ASSETS
Cash and cash equivalents. . . . . . . . . . . . $ 2,639 $ 9,660
Receivables:
Oil and gas sales. . . . . . . . . . . . . . . 90,469 43,782
Joint interest and other, net. . . . . . . . . 12,610 8,923
Income taxes . . . . . . . . . . . . . . . . . 8,049 --
Fixed-price contracts and other derivatives. . . 1,924 7,204
Prepaids and other . . . . . . . . . . . . . . . 6,607 4,928
------------- -------------
Total current assets . . . . . . . . . . . . . 122,298 74,497
------------- -------------
PROPERTY AND EQUIPMENT, at cost, based on
successful efforts accounting. . . . . . . . . 1,919,960 1,636,854
Less accumulated depreciation, depletion
and amortization . . . . . . . . . . . . . . . (565,204) (513,715)
------------- -------------
1,354,756 1,123,139
------------- -------------
OTHER ASSETS
Fixed-price contracts and other derivatives. . . 2,868 24,493
Other, net . . . . . . . . . . . . . . . . . . . 5,176 4,958
------------- -------------
8,044 29,451
------------- -------------
$ 1,485,098 $ 1,227,087
============= =============
</TABLE>
<PAGE> 4
LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED BALANCE SHEETS(continued)
(dollars in thousands)
<TABLE>
<CAPTION>
L I A B I L I T I E S A N D S T O C K H O L D E R S ' E Q U I T Y
September 30, December 31,
2000 1999
------------- -------------
(unaudited)
<S> <C> <C>
CURRENT LIABILITIES
Accounts payable . . . . . . . . . . . . . . . . $ 48,557 $ 41,216
Accrued liabilities. . . . . . . . . . . . . . . 20,702 12,413
Revenues payable . . . . . . . . . . . . . . . . 20,534 14,413
Fixed-price contracts and other derivatives. . . 63,937 4,673
------------- -------------
Total current liabilities. . . . . . . . . . . 153,730 72,715
------------- -------------
LONG-TERM DEBT . . . . . . . . . . . . . . . . . 660,696 555,222
------------- -------------
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred revenue . . . . . . . . . . . . . . . . 11,863 13,524
Fixed-price contracts and other derivatives. . . 87,415 12,008
Deferred income taxes. . . . . . . . . . . . . . 19,574 52,341
Other. . . . . . . . . . . . . . . . . . . . . . 21,929 22,495
------------- -------------
140,781 100,368
------------- -------------
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,
43,223,927 and 40,230,880 shares, respectively. 432 402
Additional paid-in capital. . . . . . . . . . . . 501,568 420,859
Retained earnings . . . . . . . . . . . . . . . . 75,501 28,149
Accumulated other comprehensive income (loss) . . (47,599) 49,981
Treasury stock at cost, 589 and 32,139 shares,
respectively. . . . . . . . . . . . . . . . . . (11) (609)
------------- -------------
529,891 498,782
------------- -------------
$ 1,485,098 $ 1,227,087
============= =============
</TABLE>
See accompanying notes to consolidated financial statements.
<PAGE> 5
LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED STATEMENTS OF INCOME (unaudited)
(in thousands, except per share data)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ ------------------
2000 1999 2000 1999
-------- -------- -------- --------
<S> <C> <C> <C> <C>
REVENUES
Oil and gas sales. . . . . . . . . . $127,330 $ 77,780 $313,814 $206,241
Change in derivative fair value. . . 6,645 2,868 (13,463) (8,242)
Other income . . . . . . . . . . . . 486 9,298 2,568 11,492
-------- -------- -------- --------
134,461 89,946 302,919 209,491
-------- -------- -------- --------
EXPENSES
Operating costs. . . . . . . . . . . 23,601 17,348 60,212 48,801
General and administrative . . . . . 5,720 6,050 17,421 17,668
Exploration costs. . . . . . . . . . 12,115 4,979 19,386 11,131
Depreciation, depletion and
amortization . . . . . . . . . . . 34,058 29,423 94,143 86,623
Impairment . . . . . . . . . . . . . -- -- 4,569 --
Interest . . . . . . . . . . . . . . 11,018 10,400 30,326 30,647
-------- -------- -------- --------
86,512 68,200 226,057 194,870
-------- -------- -------- --------
Income before income taxes . . . . . 47,949 21,746 76,862 14,621
Income tax provision . . . . . . . . 18,524 8,698 29,510 5,848
-------- -------- -------- --------
NET INCOME . . . . . . . . . . . . . $ 29,425 $ 13,048 $ 47,352 $ 8,773
======== ======== ======== ========
Net income per share:
Basic. . . . . . . . . . . . . . . . $ .68 $ .32 $ 1.15 $ .22
======== ======== ======== ========
Diluted. . . . . . . . . . . . . . . $ .66 $ .32 $ 1.12 $ .22
======== ======== ======== ========
Weighted average number of common
shares:
Basic. . . . . . . . . . . . . . . . 43,065 40,161 41,323 40,131
Diluted. . . . . . . . . . . . . . . 44,331 40,590 42,327 40,360
</TABLE>
See accompanying notes to consolidated financial statements.
<PAGE> 6
LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
(in thousands)
<TABLE>
<CAPTION>
Nine Months Ended
September 30,
------------------
2000 1999
-------- --------
<S>
<C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
47,352 $ 8,773
Items not affecting cash flows:
Depreciation, depletion and amortization. . . . . . . . . . . . . . . .
94,143 86,623
Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . .
27,039 5,628
Exploration costs . . . . . . . . . . . . . . . . . . . . . . . . . . .
19,386 11,131
Change in derivative fair value . . . . . . . . . . . . . . . . . . . .
13,463 8,242
Impairment. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4,569 --
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(262) 46
Net change in operating assets and liabilities:
Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . .
(57,977) 571
Prepaids and other. . . . . . . . . . . . . . . . . . . . . . . . . . .
(1,679) 1,515
Accounts payable. . . . . . . . . . . . . . . . . . . . . . . . . . . .
7,341 (5,261)
Accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . .
8,660 5,437
Revenues payable. . . . . . . . . . . . . . . . . . . . . . . . . . . .
6,121 301
-------- --------
168,156 123,006
CASH FLOWS FROM INVESTING ACTIVITIES
Exploration and development expenditures. . . . . . . . . . . . . . . . .
(195,718) (94,347)
Acquisition of proved oil and gas properties. . . . . . . . . . . . . . .
(158,419) (34,287)
Additions to other property and equipment . . . . . . . . . . . . . . . .
(4,291) (1,537)
Proceeds from sale of property and equipment. . . . . . . . . . . . . . .
10,986 7,048
Change in other assets. . . . . . . . . . . . . . . . . . . . . . . . . .
344 (353)
-------- --------
(347,098) (123,476)
======== ========
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from bank borrowings . . . . . . . . . . . . . . . . . . . . . .
479,350 328,469
Repayments of bank borrowings . . . . . . . . . . . . . . . . . . . . . .
(367,350) (320,969)
Repayments of subordinated notes. . . . . . . . . . . . . . . . . . . . .
(6,549) --
Proceeds from issuance of common stock. . . . . . . . . . . . . . . . . .
70,934 --
Proceeds from stock option exercises and other. . . . . . . . . . . . . .
9,701 1,601
Change in deferred revenue. . . . . . . . . . . . . . . . . . . . . . . .
(1,661) (1,497)
Change in gains from price-risk management activities . . . . . . . . . .
(9,544) (3,343)
Change in other long-term liabilities . . . . . . . . . . . . . . . . . .
(2,960) (275)
-------- --------
171,921 3,986
-------- --------
Change in cash and cash equivalents . . . . . . . . . . . . . . . . . . .
(7,021) 3,516
Cash and cash equivalents, beginning of period. . . . . . . . . . . . . .
9,660 2,539
-------- --------
Cash and cash equivalents, end of period. . . . . . . . . . . . . . . . . $
2,639 $ 6,055
======== ========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Interest paid, net of capitalized interest. . . . . . . . . . . . . . . . $
22,652 $ 24,230
Income taxes paid . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10,565 753
-------- --------
$
33,217 $ 24,983
</TABLE>
See accompanying notes to consolidated financial
statements.
<PAGE> 7
LOUIS DREYFUS NATURAL GAS CORP.
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
SEPTEMBER 30, 2000
NOTE 1 -- ACCOUNTING PRINCIPLES AND BASIS OF PRESENTATION
The accompanying unaudited consolidated financial statements have been
prepared in accordance with the instructions to Form 10-Q as prescribed by the
Securities and Exchange Commission. All material adjustments, consisting of
normal and recurring adjustments which, in the opinion of Management, were
necessary for a fair presentation of the results for the interim periods have
been reflected. The results of operations for the three-month and nine-month
periods ended September 30, 2000 are not necessarily indicative of the results
to be expected for the full year. Reference is made to the Company's Annual
Report on Form 10-K for the year ended December 31, 1999 for an expanded
discussion of the Company's financial disclosures and accounting policies.
NOTE 2 -- HEDGING
The Company reduces its exposure to unfavorable changes in oil and natural
gas prices by utilizing fixed-price physical delivery contracts, energy swaps,
collars, futures contracts, basis swaps and options (collectively "Fixed-Price
Contracts"). The Company also enters into interest rate swap contracts to
reduce its exposure to adverse interest rate fluctuations. In October 1998,
the Company adopted Statement of Financial Accounting Standards No. 133,
"Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133")
which establishes new accounting and reporting guidelines for derivative
instruments and hedging activities. Substantially all of the Company's
Fixed-Price Contracts (other than three costless natural gas collars which
matured in September 2000) and interest rate swaps are designated as cash flow
hedges. Change in derivative fair value in the statements of operations for
the three-month and the nine-month periods ended September 30, 2000 and 1999
is comprised of the following:
<PAGE> 8
LOUIS DREYFUS NATURAL GAS CORP.
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued)
SEPTEMBER 30, 2000
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ ------------------
2000 1999 2000 1999
-------- -------- -------- --------
<S> <C> <C> <C> <C>
CHANGE IN DERIVATIVE FAIR VALUE
Change in fair value for derivatives
not qualifying for hedge accounting. $ 9,359 $ 2,240 $ (6,876) $ (4,391)
Amortization of derivative fair value
gains and losses recognized in
earnings prior to actual cash
settlements. . . . . . . . . . . . . (2,051) (677) (6,397) (6,422)
The ineffective portion of
derivatives qualifying for hedge
accounting . . . . . . . . . . . . . (663) 1,305 (190) 2,571
-------- -------- -------- --------
$ 6,645 $ 2,868 $(13,463) $ (8,242)
======== ======== ======== ========
</TABLE>
Despite certain Fixed-Price Contracts failing the effectiveness guidelines
of SFAS 133 from time to time, Fixed-Price Contracts continue to be highly
effective in achieving the risk management objectives for which they were
intended.
The change in carrying value of Fixed-Price Contracts and interest rate
swaps in the Company's balance sheet since December 31, 1999 resulted from a
significant increase in market prices for natural gas and crude oil and an
increase in interest rates. The majority of this change in fair value was
reflected in accumulated other comprehensive income, net of deferred tax
effects. Derivative liabilities reflected as current in the September 30,
2000 balance sheet represent the estimated fair value of Fixed-Price Contract
settlements scheduled to occur over the subsequent twelve-month period based
on market prices for oil and gas as of the balance sheet date. Because
present accounting rules do not provide for the accrual of the future cash
flow transactions the contracts were designed to hedge, an apparent working
capital deficit is created which does not, in Management's opinion, accurately
depict the Company's true working capital position or its liquidity. These
settlement amounts are not due and payable until the monthly period that the
related underlying hedged transaction occurs. In some cases the recorded
liability for certain contracts significantly exceeds the total settlement
amounts that would be paid to a counterparty based on prices in effect at the
balance sheet date due to option time value. For derivatives which are held
to maturity, this time value has no direct relationship to actual future
contract settlements and consequently does not represent a liability which
will be settled in cash.
<PAGE> 9
LOUIS DREYFUS NATURAL GAS CORP.
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued)
SEPTEMBER 30, 2000
The estimated fair values of Fixed-Price Contracts and interest rate swaps
as of September 30, 2000 and December 31, 1999 are provided below. The
associated carrying values of these contracts are equal to the estimated fair
values for each period presented.
<TABLE>
September 30, December 31,
2000 1999
------------ ------------
(in thousands)
<S> <C> <C>
Derivative assets:
Fixed-price natural gas swaps. . . . . . . . $ -- $ 16,433
Fixed-price natural gas collars. . . . . . . -- 1,323
Fixed-price natural gas delivery contracts . 945 7,921
Fixed-price crude oil swaps. . . . . . . . . -- 360
Interest rate swaps. . . . . . . . . . . . . 3,847 5,660
Derivative liabilities:
Fixed-price natural gas swaps. . . . . . . . (35,950) (4,329)
Fixed-price natural gas collars. . . . . . . (9,376) --
Fixed-price natural gas delivery contracts . (104,652) (9,081)
Natural gas basis swaps. . . . . . . . . . . (1,374) (3,271)
------------ ------------
$ (146,560) $ 15,016
============ ============
</TABLE>
The fair value of Fixed-Price Contracts as of September 30, 2000 and
December 31, 1999 was estimated based on market prices of natural gas and
crude oil for the periods covered by the contracts. The net differential
between the prices in each contract and market prices for future periods, as
adjusted for estimated basis, has been applied to the volumes stipulated in
each contract to arrive at an estimated future value. This estimated future
value was discounted on a contract-by-contract basis at rates commensurate
with the Company's estimation of contract performance risk and counterparty
credit risk. The fair value of derivative instruments which contain options
(e.g. collar structures) has been estimated based on remaining life,
volatility and other factors. The terms and conditions of the Company's
fixed-price physical delivery contracts and certain financial swaps are
uniquely tailored to the Company's circumstances. In addition, the
determination of market prices for natural gas beyond a five year horizon is
subject to significant judgment and estimation. As a result, the Fixed-Price
Contract fair value does not necessarily represent the value a third party
would pay to assume the Company's contract positions.
<PAGE> 10
LOUIS DREYFUS NATURAL GAS CORP.
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued)
SEPTEMBER 30, 2000
NOTE 3 -- ACQUISITION OF PROPERTIES FROM COSTILLA ENERGY, INC.
On June 15, 2000, the Company acquired substantially all of the oil and gas
properties of Costilla Energy, Inc. for approximately $126 million in cash,
net of estimated purchase price adjustments. The acquired properties were
comprised of 135 Bcfe of net proved reserves included in 1,011 gross (607 net)
producing wells at closing. The Costilla properties are primarily located
within the Company's three core operating areas. A substantial portion of the
total identified value is contained within a field in which the Company has a
significant ownership position, the SW Speaks field in Lavaca County, Texas.
The purchase price for the Costilla acquisition was initially funded through
availability under the Company's revolving bank credit facility. See Note 4
-- Common Stock Offering. The acquisition has been accounted for using the
purchase method of accounting.
In connection with the acquisition, the Company entered into two costless
collars to hedge a portion of the future production from the properties. The
first collar hedges 20 MMcf per day for 2001 at a floor price of $3.13 per
MMBtu and a ceiling price of $4.25 per MMBtu. The second collar hedges 20
MMcf per day in 2002 at a floor price of $2.84 per MMBtu and a ceiling price
of $3.94 per MMBtu.
NOTE 4 -- COMMON STOCK OFFERING
On June 28, 2000, the Company sold 2.4 million shares of its common stock at
$31.00 per share ($29.53 per share net of underwriting discount) in a public
offering. Proceeds from the offering of $70.9 million received in July 2000
were applied to reduce a majority of the indebtedness incurred in connection
with the acquisition of properties from Costilla Energy, Inc. In addition, an
indirect wholly-owned subsidiary of S.A. Louis Dreyfus et Cie sold 1.6 million
shares of the Company's common stock in the offering. Subsequent to the
offering, S.A. Louis Dreyfus et Cie through its subsidiaries owned 19.2
million common shares, or approximately 44% of the total issued and
outstanding common shares of the Company.
NOTE 5 -- LITIGATION
The Company is one of numerous defendants in several lawsuits originally
filed in 1995, subsequently consolidated with related litigation, and now
pending in the 93rd Judicial District Court in Hildago County, Texas. The
lawsuit alleges that the plaintiffs, a group of local landowners and
businesses, have suffered damages including, but not limited to, property
damage and lost profits of approximately $60 million as the result of an
underground hydrocarbon plume within the city of McAllen, Texas. The lawsuit
alleges that gas wells and related pipeline facilities operated by the
Company, and other facilities operated by other defendants, caused the plume.
In August 1999, the plaintiff's experts produced reports that suggested the
Company might be considered a significant contributor to the plume. The
<PAGE> 11
LOUIS DREYFUS NATURAL GAS CORP.
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued)
SEPTEMBER 30, 2000
Company's investigation into this matter has not found any leaks or discharges
from its facilities. In addition, the Company's investigation has revealed
the plume to be unrelated to the Company's production of natural gas from its
facilities. Trial is not anticipated to commence until the second half of
2001. The Company will vigorously defend its interests in this case. Results
of litigation are inherently unpredictable; however, the Company does not
presently expect the ultimate outcome of the case to have a material adverse
impact on its financial position or results of operations.
The Company was a defendant in various other legal proceedings as of
September 30, 2000, which are routine and incidental to its business. While
the ultimate results of all these proceedings and determinations cannot be
predicted with certainty, the Company will vigorously defend its interests and
does not presently believe that the outcome of these matters will have a
material adverse effect on the Company.
NOTE 6 -- COMPREHENSIVE LOSS
Components of comprehensive loss for the three-month and the nine-month
periods ended September 30, 2000 and 1999, are as follows:
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ ------------------
2000 1999 2000 1999
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Net income . . . . . . . . . . . . . $ 29,425 $ 13,048 $ 47,352 $ 8,773
Other comprehensive loss, net of tax:
Reclassification adjustments -
contract settlements. . . . . . . 12,877 641 23,718 (4,389)
Change in fixed-price contract and
other derivative fair value . . . (56,135) (23,112) (121,298) (50,043)
-------- -------- -------- --------
Comprehensive loss . . . . . . . . . $(13,833) $ (9,423) $(50,228) $(45,659)
======== ======== ======== ========
</TABLE>
<PAGE> 12
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
OVERVIEW
General. Our business strategy is to generate strong and consistent growth
in reserves, production, operating cash flows and earnings through a balanced
program of exploration and development drilling and strategic acquisitions of
oil and gas properties. Our drilling, acquisition and operating activities
are geographically concentrated in three core areas: the Permian Region of
West Texas, Southeast New Mexico and the San Juan Basin; the Mid-Continent
Region of Oklahoma, Kansas and the Panhandle of Texas; and the Gulf Coast
Region, which includes South Texas, Offshore Gulf of Mexico, East Texas,
Southwest Arkansas and Northern Louisiana (collectively our "Core Areas"). We
have significant experience and expertise in our Core Areas and we benefit
from operational synergies due to the concentration of our properties within
these areas. Our capital expenditure plans for 2000 include the investment of
approximately $220 million in drilling activities, the vast majority of which
will be expended in these Core Areas. See "-- Commitments and Capital
Expenditures."
We reduce exposure to unfavorable changes in oil and gas prices by utilizing
long-term physical delivery contracts, energy swaps, collars, futures
contracts, basis swaps and option agreements (collectively "Fixed-Price
Contracts"). As of September 30, 2000, our Fixed-Price Contracts hedged 157
Bcf of future production, representing 11% of our estimated total proved
reserves at December 31, 1999, at escalating fixed prices. Approximately 6
Bcf is hedged for the remainder of fiscal 2000. See "Quantitative and
Qualitative Disclosures About Market Risk."
Forward-Looking Statements. All statements made in this document other than
purely historical information are "forward-looking statements" within the
meaning of the federal securities laws. These statements reflect our current
expectations and are based on our historical operating trends, proved reserve
and Fixed-Price Contract positions and other currently available information.
Forward-looking statements include statements regarding our future drilling
plans and objectives and related exploration and development budgets and
number and location of planned wells and statements regarding the quality of
our properties and potential reserve and production levels. These statements
may be preceded by or followed by or otherwise include the words "believes",
"expects", "anticipates", "intends", "plans", "estimates", "projects", or
similar expressions or statements that certain events "will" or "may" occur.
These statements assume that no significant changes will occur in the
operating environment for our oil and gas properties and that there will be no
material acquisitions or divestitures except as otherwise described.
The forward-looking statements are subject to all the risks and
uncertainties incident to the acquisition, exploration, development and
marketing of oil and natural gas reserves, including the risks described in
this document and in our Annual Report filed on Form 10-K for the year ended
December 31, 1999. These risks include, but are not limited to, commodity
<PAGE> 13
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
price, counterparty, environmental, drilling, reserves, operations and
production risks. We may also make material acquisitions or divestitures,
modify our Fixed-Price Contract positions or enter into financing
transactions. None of these events can be predicted with certainty and are
not taken into consideration in the forward-looking statements.
Statements concerning Fixed-Price Contract, interest rate swap and other
financial instrument fair values and their estimated contribution to our
future results of operations are based upon market information as of a
specific date. This market information is often a function of significant
judgment and estimation. Further, market prices for oil and gas and market
interest rates are subject to significant volatility.
For all of these reasons, our actual results may vary materially from the
forward-looking statements and there is no assurance that the assumptions we
have used are necessarily the most likely. We will not update any
forward-looking statements to reflect events or circumstances occurring after
the date the statement is made.
Certain Definitions. As used herein, the abbreviations listed below are
defined as follows:
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein
in reference to oil or other liquid hydrocarbons.
Bcf. Billion cubic feet.
Bcfe. Billion cubic feet of natural gas equivalent, determined using the
ratio of one Bbl of oil or condensate to six Mcf of natural gas.
BBtu. Billion Btus.
Btu. British thermal unit, which is the heat required to raise the
temperature of a one-pound mass of water from 58.5 to 59.5 degrees
Fahrenheit.
EBITDAX. EBITDAX is defined in this document as income before interest
expense, income taxes, depreciation, depletion and amortization,
impairment, exploration costs and change in derivative fair value.
We believe that EBITDAX is a financial measure commonly used in the
oil and gas industry as an indicator of a company's ability to
service and incur debt. However, EBITDAX should not be considered in
isolation or as a substitute for net income, cash flows provided by
operating activities or other data prepared in accordance with
generally accepted accounting principles, or as a measure of a
company's profitability or liquidity. EBITDAX measures as presented
may not be comparable to other similarly titled measures of other
companies.
MBbls. Thousand barrels.
Mcf. Thousand cubic feet.
Mcfe. Thousand cubic feet of natural gas equivalent, determined using the
ratio of one Bbl of oil or condensate to six Mcf of natural gas.
MMBbls. Million barrels.
<PAGE> 14
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
MMBtu. Million Btus.
MMcf. Volume of one million cubic feet.
MMcfe. Million cubic feet of natural gas equivalent, determined using the
ratio of one Bbl of oil or condensate to six Mcf of natural gas.
TBtu. One Trillion Btus.
Selected Operating Data. The following table provides certain operating
data relating to our results of operations.
<PAGE> 15
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
<TABLE>
<CAPTION>
Three Months Ended Nine
Months Ended
September 30,
September 30,
------------------
------------------
2000 1999
2000 1999
-------- --------
-------- --------
<S> <C> <C> <C>
<C>
OIL AND GAS SALES: (M$)
Wellhead oil sales . . . . . . . . . . . . . . . . . $ 23,290 $ 14,487 $
61,180 $ 34,515
Effect of Fixed-Price Contract settlements (1) . . . 125 (259)
(5,155) (259)
-------- --------
-------- --------
Total oil sales. . . . . . . . . . . . . . . . . . . $ 23,415 $ 14,228 $
56,025 $ 34,256
======== ========
======== ========
Wellhead natural gas sales . . . . . . . . . . . . . $134,822 $ 69,663
$301,116 $167,980
Effect of Fixed-Price Contract settlements (1) . . . (30,907) (6,111)
(43,327) 4,005
-------- --------
-------- --------
Total natural gas sales. . . . . . . . . . . . . . . $103,915 $ 63,552
$257,789 $171,985
======== ========
======== ========
PRODUCTION:
Oil production (MBbls) . . . . . . . . . . . . . . . 762 730
2,151 2,232
Natural gas production (MMcf). . . . . . . . . . . . 31,932 27,611
87,893 79,704
Net equivalent production (MMcfe). . . . . . . . . . 36,506 31,989
100,801 93,094
Percent of oil production hedged by Fixed-Price
Contracts . . . . . . . . . . . . . . . . . . . . . 20% 20%
54% 7%
Percent of gas production hedged by Fixed-Price
Contracts . . . . . . . . . . . . . . . . . . . . . 62% 77%
53% 62%
AVERAGE SALES PRICE:
Oil price (per Bbl):
Wellhead price. . . . . . . . . . . . . . . . . . . $ 30.55 $ 19.85 $
28.44 $ 15.47
Effect of Fixed-Price Contract settlements (1). . . .16 (.35)
(2.40) (.12)
-------- --------
-------- --------
Total . . . . . . . . . . . . . . . . . . . . . . . $ 30.71 $ 19.50 $
26.04 $ 15.35
======== ========
======== ========
Natural gas price (per Mcf):
Wellhead price. . . . . . . . . . . . . . . . . . . $ 4.22 $ 2.52 $
3.42 $ 2.11
Effect of Fixed-Price Contract settlements (1). . . (.97) (.22)
(.49) .05
-------- --------
-------- --------
Total . . . . . . . . . . . . . . . . . . . . . . . $ 3.25 $ 2.30 $
2.93 $ 2.16
======== ========
======== ========
Average sales price (per Mcfe) . . . . . . . . . . . $ 3.49 $ 2.43 $
3.11 $ 2.22
OPERATING AND OVERHEAD COSTS: (per Mcfe)
Lease operating expenses . . . . . . . . . . . . . . $ .41 $ .40 $
.40 $ .41
Production taxes . . . . . . . . . . . . . . . . . . .24 .14
.20 .11
General and administrative . . . . . . . . . . . . . .16 .19
.17 .19
-------- --------
-------- --------
Total. . . . . . . . . . . . . . . . . . . . . . . . $ .81 $ .73 $
.77 $ .71
======== ========
======== ========
Cash operating margin (per Mcfe) (2) . . . . . . . . $ 2.68 $ 1.70 $
2.34 $ 1.51
Depreciation, depletion and amortization - oil and
gas (per Mcfe) . . . . . . . . . . . . . . . . . . $ .90 $ .89 $
.90 $ .89
<FN>
(1) - Represents the realized hedging results from our 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) - Cash operating margin is defined as oil and gas sales less lease
operating expenses,
production taxes and general and administrative costs.
</TABLE>
<PAGE> 16
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
RESULTS OF OPERATIONS -- THREE MONTHS ENDED SEPTEMBER 30, 2000 COMPARED TO
THREE MONTHS ENDED SEPTEMBER 30, 1999
Net Income and Cash Flows from Operating Activities. For the quarter ended
September 30, 2000, we realized net income of $29.4 million, or $.66 per
share, on revenues of $134.5 million. This compares to net income of $13.0
million, or $.32 per share, on revenues of $89.9 million for the third quarter
of 1999. Earnings results for the third quarter of 2000 exceeded the level of
earnings previously realized for any full fiscal year in our history. Net
income excluding the non-cash impact of SFAS 133 derivative accounting was
$25.3 million, or $.57 per share, for the third quarter of 2000 and $11.3
million or $.28 per share, for the third quarter of 1999.
Cash flows from operating activities (before working capital changes) for
the third quarter of 2000 grew 61% to a record $85.7 million compared to $53.4
million for the third quarter of 1999. EBITDAX for the quarter ended
September 30, 2000 improved 55% to $98.5 million, also a record. This
compares to EBITDAX of $63.7 million for the prior year quarter. The
increases in operating cash flows and EBITDAX for the current year quarter
were principally the result of higher oil and gas prices and higher gas
production. Cash flows provided by operating activities after consideration
of the net change in working capital decreased to $51.8 million from the $62.6
million reported for the third quarter of 1999, primarily due to an increase
in accounts receivable and a decrease in accounts payable in the current year
period.
Production. We produced 36.5 Bcfe for the third quarter of 2000 compared to
32.0 Bcfe for the prior year third quarter, an increase of 14%. Gas
production increased to 31.9 Bcf compared to 27.6 Bcf for the third quarter of
1999, an increase of 16%. Oil production for the third quarter of 2000
increased 4% to 762 MBbls compared to 730 MBbls for the prior-year third
quarter.
Oil and Gas Prices. On a natural gas equivalent basis, we received an
average price of $3.49 per Mcfe for the quarter ended September 30, 2000, an
increase of 44% from the $2.43 per Mcfe received for the third quarter of
1999. Our gas production yielded an average price of $3.25 per Mcf, an
increase of 41% compared to $2.30 per Mcf for the prior-year third quarter.
Our average gas price for the 2000 third quarter was reduced $.97 per Mcf as a
result of our price risk management activities. The average gas price for the
third quarter of 1999 was reduced $.22 per Mcf as a result of the Fixed-Price
Contracts in effect for that period. The average oil price for the third
quarter of 2000 was $30.71 per Bbl, an increase of 57% from the $19.50 per Bbl
received for the prior-year third quarter. The average oil price for the
third quarter of 2000 increased $.16 per Bbl as a result of our hedging
activities. The average oil price for the third quarter of 1999 was reduced
$.35 per Bbl as a result of our hedging activities.
<PAGE> 17
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
The combination of higher gas production and higher gas prices increased gas
sales to $103.9 million for the third quarter of 2000 compared to $63.6
million for the third quarter of 1999. The combination of higher oil prices
and higher oil production increased oil sales to $23.4 million compared to
$14.2 million reported for the prior-year quarter. The impact of Fixed-Price
Contract settlements was to decrease oil and gas sales by $30.8 million for
the quarter ended September 30, 2000 and to decrease oil and gas sales by $6.4
million for the quarter ended September 30, 1999. See "Quantitative and
Qualitative Disclosures About Market Risk."
Change in Derivative Fair Value. Change in derivative fair value for the
third quarter of 2000 was a net gain of $6.6 million, which included a $9.4
million gain associated with certain derivatives not qualifying for hedge
accounting, $.7 million of net losses relating to the ineffective portion of
derivatives which qualified for hedge accounting, and a $2.1 million loss
relating to the reversal of contract fair value gains and losses recognized in
earnings prior to actual cash settlement. Change in derivative fair value for
the third quarter of 1999 was a net gain of $2.9 million, which included a
$2.3 million gain associated with certain derivatives not qualifying for hedge
accounting, $1.3 million of net gains relating to the ineffective portion of
derivatives which qualified for hedge accounting, and $.7 million of losses
relating to the reversal of contract fair value gains and losses recognized in
earnings prior to actual cash settlement. Despite certain contracts failing
the effectiveness guidelines of SFAS 133 from time to time, our Fixed-Price
Contracts continue to be highly effective in achieving the risk management
objectives for which they were intended.
Other Income. Other income for the third quarters of 2000 and 1999 was $.5
million and $9.3 million, respectively. The decrease was primarily the result
of a nonrecurring pretax gain of $8.6 million recognized in the third quarter
of 1999.
Operating Costs. Operating costs for the third quarter of 2000 were
comprised of $14.8 million of lease operating expenses and $8.8 million of
production taxes. This compares to $12.9 million of lease operating expenses
and $4.5 million of production taxes for the third quarter of 1999. The
increase in production taxes is primarily the result of higher oil and gas
prices in the third quarter of 2000. Lease operating expenses on a natural
gas equivalent unit of production basis were $.41 per Mcfe for the three
months ended September 30, 2000 as compared to $.40 per Mcfe for the three
months ended September 30, 1999. The increase is primarily attributable to
the higher operating costs of the properties acquired from Costilla Energy,
Inc.
General and Administrative Expense. General and administrative expense
("G&A") for the third quarter of 2000 was $5.7 million, a decrease of 5% from
the prior-year third quarter amount of $6.1 million. This decrease is
primarily attributable to an increase in overhead recoveries, due in part to
<PAGE> 18
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
the Costilla acquisition. On a natural gas equivalent unit of production
basis, G&A decreased to $.16 per Mcfe for the 2000 third quarter compared to
$.19 per Mcfe for the 1999 third quarter, due to growth in production without
corresponding increases in G&A costs.
Exploration Costs. Exploration costs, comprised of geological and
geophysical costs, exploratory dry holes and leasehold impairment costs,
increased to $12.1 million for the quarter ended September 30, 2000, compared
to $5.0 million for the third quarter of 1999. The 2000 amount consists of
$8.0 million of dry hole costs, $.9 million of seismic acquisition and other
geological and geophysical costs and $3.2 million of leasehold costs. The
1999 amount consists of $.1 million of dry hole costs, $1.6 million of seismic
acquisition and other geological and geophysical costs and $3.3 million of
leasehold costs.
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization ("DD&A") for the third quarter of 2000 was $34.1 million compared
to $29.4 million for the prior-year third quarter. This increase in DD&A is
attributable to an increase in production. The oil and gas DD&A rate per
equivalent unit of production was $.90 per Mcfe for the 2000 third quarter
compared to $.89 per Mcfe for the third quarter of 1999. This increase was
due, in part, to the cost of the Costilla acquisition.
Interest Expense. Interest expense for the third quarter of 2000 was $11.0
million compared to $10.4 million for the third quarter of 1999. The net
impact of interest rate swaps in effect for the third quarter of 2000 was to
decrease interest expense by $.6 million. The impact of interest rate swaps
in the third quarter of 1999 was not material. See "Capital Resources and
Liquidity - Credit Facility."
Income Taxes. For the third quarter of 2000, a tax provision of $18.5
million was recorded on pretax income of $47.9 million, an effective rate of
39%. This compares to a tax provision of $8.7 million on pretax income of
$21.7 million, an effective rate of 40%, for the third quarter of 1999.
RESULTS OF OPERATIONS -- NINE MONTHS ENDED SEPTEMBER 30, 2000 COMPARED TO NINE
MONTHS ENDED SEPTEMBER 30, 1999
Net Income and Cash Flows from Operating Activities. We realized net income
of $47.4 million, or $1.12 per share, on revenues of $302.9 million for the
nine months ended September 30, 2000. This compares with net income of $8.8
million, or $.22 per share, on revenues of $209.5 million for the nine months
ended September 30, 1999. Net income excluding the non-cash impact of SFAS
133 derivative accounting was $55.6 million, or $1.31 per share, for the first
nine months of 2000, and $13.7 million, or $.34 per share, for the nine months
ended September 30, 1999. Cash flows from operating activities (before
working capital changes) for the first nine months of 2000 were $205.7
million, compared to $120.4 million for the first nine months of 1999, an
increase of 71%. The increase in operating cash flows for the current year
<PAGE> 19
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
nine-month period was primarily the result of higher oil and gas prices and
higher gas production in relation to the first nine months of 1999. Cash
flows provided by operating activities after consideration of the net change
in working capital increased to $168.2 million from the $123.0 million
reported for the third quarter of 1999, primarily for the same reasons.
EBITDAX for the first nine months of 2000 was $238.7 million, compared to
$151.3 million for the comparable period of 1999, an increase of 58%.
Production. Total production for the first nine months of 2000 was 100.8
Bcfe compared to 93.1 Bcfe for the comparable prior-year period, an increase
of 8%. Gas production increased to 87.9 Bcf compared to 79.7 Bcf for the
comparable prior-year period, an increase of 10%. Oil production for the
first nine months of 2000 decreased 4% to 2.15 MMBbls compared to 2.23 MMBbls
for the first nine months of 1999.
Oil and Gas Prices. On a natural gas equivalent basis, we received an
average price of $3.11 per Mcfe for the first nine months of 2000, an increase
of 40% from the $2.22 per Mcfe received for the first nine months of 1999.
Gas production yielded an average price of $2.93 per Mcf, an increase of 36%
compared to $2.16 per Mcf for the prior-year nine-month period. The average
gas price for the first nine months of 2000 was reduced $.49 per Mcf as a
result of Fixed-Price Contracts. The average gas price for the first nine
months of 1999 was enhanced $.05 per Mcf as a result of the Fixed-Price
Contracts in effect for that period. The average oil price for the first nine
months of 2000 was $26.04 per Bbl compared to $15.35 per Bbl for the first
nine months of 1999, an increase of 70%. Fixed-Price Contracts in effect
during the first nine months of 2000 decreased the average oil price by $2.40
per Bbl. Fixed-Price Contracts in effect during the first nine months of 1999
decreased the average oil price by $.12 per Bbl.
The combined effect of higher gas production and higher gas prices increased
gas sales to $257.8 million for the first nine months of 2000 compared to
$172.0 million for the first nine months of 1999. The net effect of lower oil
production and higher oil prices increased oil sales to $56.0 million compared
to $34.3 million reported for the prior-year nine-month period. The impact of
Fixed-Price Contract settlements was to decrease oil and gas sales by $48.5
million for the nine months ended September 30, 2000 and to increase oil and
gas sales by $3.7 million for the nine months ended September 30, 1999. See
"Quantitative and Qualitative Disclosures About Market Risk."
Change in Derivative Fair Value. Change in derivative fair value for the
nine months ended September 30, 2000 was a net loss of $13.5 million which was
comprised of a $6.9 million loss associated with certain derivatives not
qualifying for hedge accounting, $.2 million of net losses relating to the
ineffective portion of derivatives which qualified for hedge accounting, and
$6.4 million of losses relating to the reversal of contract fair value gains
and losses recognized in earnings prior to actual cash settlement. Change in
derivative fair value for the nine months ended September 30, 1999 was a net
<PAGE> 20
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
loss of $8.2 million which included a $4.4 million loss associated with
certain derivatives not qualifying for hedge accounting, $2.6 million of net
gains relating to the ineffective portion of derivatives which qualified for
hedge accounting, and $6.4 million of losses relating to the reversal of
contract fair value gains and losses recognized in earnings prior to actual
cash settlement. Despite certain Fixed-Price Contracts failing the
effectiveness guidelines of SFAS 133 from time to time, our Fixed-Price
Contracts continue to be highly effective in achieving the risk management
objectives for which they were intended.
Other Income. Other income for the first nine months of 2000 was $2.6
million compared to $11.5 million for the first nine months of 1999. This
decrease was primarily the result of a nonrecurring pretax gain of $8.6
million recognized in 1999.
Operating Costs. Operating costs for the first nine months of 2000 were
comprised of $40.6 million of lease operating expenses and $19.6 million of
production taxes. This compares to $38.2 million of lease operating expenses
and $10.6 million of production taxes for the first nine months of 1999. The
increase in production taxes is principally attributable to higher oil and gas
prices. Lease operating expenses on a natural gas equivalent unit of
production basis improved to $.40 per Mcfe compared to $.41 per Mcfe for the
nine months ended September 30, 1999.
General and Administrative Expense. G&A for the first nine months of 2000
was $17.4 million, compared to $17.7 million reported for the first nine
months of 1999. On a natural gas equivalent unit of production basis, G&A
decreased to $.17 per Mcfe for the first nine months of 2000 compared to $.19
per Mcfe for the first nine months of 1999, due to growth in production
without corresponding increases in G&A costs.
Exploration Costs. Exploration costs, comprised of geological and
geophysical costs, exploratory dry holes and leasehold impairment costs,
increased to $19.4 million for the nine months ended September 30, 2000,
compared to $11.1 million for the nine months ended September 30, 1999. The
2000 amount consists of $9.1 million of dry hole costs, $4.3 million of
seismic acquisition and other geological and geophysical costs and $6.0
million of leasehold costs. The 1999 amount consists of $1.1 million of dry
hole costs, $2.9 million of seismic acquisition and other geological and
geophysical costs and $7.1 million of leasehold costs.
Depreciation, Depletion and Amortization. DD&A for the first nine months of
2000 was $94.1 million compared to $86.6 million for the first nine months of
1999. This increase in DD&A is attributable to an increase in the oil and gas
DD&A rate and higher gas production. The oil and gas DD&A rate per equivalent
unit of production was $.90 per Mcfe for the first nine months of 2000
compared to $.89 per Mcfe for the first nine months of 1999. This increase
was primarily the result of an increase in production from certain higher cost
<PAGE> 21
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
properties and the impact of the Costilla acquisition.
Impairment. For the nine month period ended September 30, 2000, an
impairment charge of $4.6 million was recorded due to downward reserve
revisions for two single-well offshore fields drilled in 1998. There was no
impairment charge recorded for the first nine months of 1999. We are unaware
of any other fields which may be impaired because of performance or other
reasons. However, future impairments may be recognized as a result of
numerous factors, all of which are beyond our ability to control or predict.
Interest Expense. Interest expense for the nine months ended September 30,
2000 was $30.3 million compared to $30.6 million for the nine months ended
September 30, 1999. The net impact of interest rate swaps in effect for the
first nine months of 2000 and 1999 was to decrease interest expense by $1.4
million and increase interest expense by $.2 million, respectively. See
"Capital Resources and Liquidity - Credit Facility."
Income Taxes. For the first nine months of 2000, a tax provision of $29.5
million was recorded on pretax income of $76.9 million, an effective rate of
38%. This compares to a tax provision of $5.8 million provided on pretax
income of $14.6 million, an effective rate of 40%, for the first nine months
of 1999. The effective rate for the first nine months of 1999 was higher than
the statutory rate primarily due to the effect of permanent differences
created by differences in the book and tax bases of acquired assets.
CAPITAL RESOURCES AND LIQUIDITY
Cash Flows. Our business of acquiring, exploring and developing oil and gas
properties is capital intensive. Our ability to grow our reserve base is
contingent, in part, upon the ability to generate cash flows from operating
activities and to access outside sources of capital to fund our investing
activities. For the nine months ended September 30, 2000 and 1999, we
expended $354.1 million and $128.6 million, respectively, in oil and gas
property acquisition, exploration and development activities, representing
substantially all of the cash flow we invested during each nine-month period.
See "Commitments and Capital Expenditures." Cash flows from operating
activities before changes in working capital for the nine months ended
September 30, 2000 and 1999 were $205.7 million and $120.4 million,
representing 58% and 94%, respectively, of the oil and gas property
investments made for each period. Substantially all of the cash flows from
operating activities are generated from oil and gas sales which are highly
dependent upon oil and gas prices. Significant decreases in the market prices
of oil and gas could result in reduction of cash flows from operating
activities, which in turn could impact the amount of capital investment.
Cash flows from financing activities for the first nine months of 2000
reflected a net source of cash of $171.9 million compared to a $4.0 million
source of cash for the first nine months of 1999. This increase is related to
borrowings made during the period to fund proved reserve acquisitions closed
<PAGE> 22
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
during the year, including the acquisition of properties from Costilla Energy,
Inc., discussed below. Financing cash flows also include the proceeds from
the issuance of common stock in July 2000, as discussed below. Historically,
we have relied upon availability under various revolving bank credit
facilities and proceeds from the issuance of senior and subordinated notes to
fund our investing activities.
Credit Facility. We have a revolving credit facility (the "Credit
Facility") with a syndicate of banks which provides up to $450 million in
borrowings (the "Commitment"). Letters of credit are limited to $75 million
of this availability. The Credit Facility allows us to draw on the full $450
million credit line without restrictions tied to periodic revaluations of our
oil and gas reserves provided we continue to maintain an investment grade
credit rating from either Standard & Poor's Ratings Service or Moody's
Investors Service. We presently have unsecured senior credit ratings of BBB
and Baa3 from Standard & Poor's and Moody's, respectively. A borrowing base
can be required only upon the vote by a majority in interest of the lenders
after the loss of an investment grade credit rating. No principal payments
are required under the Credit Facility prior to termination on October 14,
2002. We have relied upon the Credit Facility to provide funds for
acquisitions and drilling activities, and to provide letters of credit to meet
margin requirements under Fixed-Price Contracts. As of September 30, 2000,
there was $350.6 million of principal and $34.8 million of letters of credit
outstanding under the Credit Facility. See "-- Common Stock Offering."
We have the option of borrowing at a LIBOR-based interest rate or the Base
Rate (approximating the prime rate). The LIBOR interest rate margin and the
facility fee payable under the Credit Facility are subject to a sliding scale
based on our senior debt credit rating. At September 30, 2000, the applicable
interest rate was LIBOR plus 30 basis points. The Credit Facility also
requires the payment of a facility fee equal to 15 basis points of the
Commitment. The average interest rate for borrowings under the Credit
Facility was 7.0% as of September 30, 2000. Including the effect of interest
rate swaps which hedge a portion of the interest rate exposure attributable to
this facility, the effective interest rate was 6.4%. See the Notes to
Consolidated Financial Statements included in our Annual Report on Form 10-K
for the year ended December 31, 1999 for an expanded discussion of our
interest rate swaps. The Credit Facility contains various affirmative and
restrictive covenants which, among other things, limit total indebtedness to
$700 million ($625 million of senior indebtedness) and require us to meet
certain financial tests. Borrowings under the Credit Facility are unsecured.
Other Lines of Credit. We have certain other uncommitted lines of credit
which aggregated $50.1 million as of September 30, 2000. These short-term
lines of credit are unsecured and primarily used to meet margin requirements
under Fixed-Price Contracts and for working capital purposes. As of September
30, 2000, there was $17.0 million of indebtedness and $.1 million of letters
of credit outstanding under these credit lines. Repayment of this
<PAGE> 23
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
indebtedness is expected to be made through Credit Facility availability.
6 7/8% Senior Notes due 2007. In December 1997, we issued $200 million
principal amount, $198.8 million net of discount, of 6 7/8% Senior Notes due
2007. Interest is payable semi-annually on June 1 and December 1. The
associated indenture agreement contains restrictive covenants which place
limitations on the amount of liens and our ability to enter into sale and
leaseback transactions.
9 1/4% Subordinated Notes due 2004. In June 1994, we issued $100 million
principal amount, $98.5 million net of discount, of 9 1/4% Senior Subordinated
Notes due 2004 (the "Subordinated Notes"). Interest is payable semi-annually
on June 15 and December 15. The associated indenture agreement contains
certain restrictive covenants which limit, among other things, the prepayment
of the Subordinated Notes, the incurrence of additional indebtedness, the
payment of dividends and the disposition of assets. In the second quarter of
2000, we purchased $6.3 million face amount of the Subordinated Notes in the
open market, leaving $93.7 million of principal outstanding at September 30,
2000.
Common Stock Offering. On June 28, 2000, we sold 2.4 million shares of our
common stock at $31.00 per share ($29.53 per share net of underwriting
discount) in a public offering. Proceeds from the offering of $70.9 million
received in July 2000 were applied to reduce a majority of the indebtedness
incurred in connection with the acquisition of properties from Costilla
Energy, Inc. described below. In addition, an indirect wholly-owned
subsidiary of S.A. Louis Dreyfus et Cie sold 1.6 million shares of our common
stock in the offering. Subsequent to the offering, S.A. Louis Dreyfus et Cie
through its subsidiaries owned 19.2 million of our common shares, or
approximately 44% of the total issued and outstanding common shares.
We believe that the borrowing capacity available under the Credit Facility,
combined with our internally generated operating cash flows, will be adequate
to finance the capital expenditure program planned for the balance of 2000,
and to meet margin requirements under Fixed-Price Contracts. See "Commitments
and Capital Expenditures" and "Quantitative and Qualitative Disclosures About
Market Risk."
At September 30, 2000, we had negative working capital of $31.4 million and
a current ratio of .8 to 1. This working capital deficit is the result of
recording the fair value of Fixed-Price Contract settlements scheduled to
occur over the subsequent twelve-month period based on market prices for oil
and gas as of the balance sheet date and option valuations. Because present
accounting rules do not provide for the accrual of the future cash flow
transactions the contracts were designed to hedge, an apparent working capital
deficit is created which does not, in our opinion, accurately depict our true
working capital position or liquidity. These settlement amounts are not due
and payable until the monthly period that the related underlying hedged
<PAGE> 24
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
transaction occurs. In some cases, the recorded liability for certain
contracts significantly exceeds the total settlement amounts that would be
paid to a counterparty based on prices in effect at the balance sheet date due
to option time value. For derivatives which are held to maturity, this time
value has no direct relationship to actual future contract settlements and
consequently does not represent a liability which will be settled in cash.
Short-term liquidity has actually improved as a result of the increase in oil
and gas prices. Excluding the current portion of Fixed-Price Contracts from
current assets and liabilities, working capital was $30.6 million and the
current ratio was 1.3 to 1. Total long-term debt outstanding at September 30,
2000 was $660.7 million. Long-term debt as a percentage of total
capitalization was 55%.
COMMITMENTS AND CAPITAL EXPENDITURES
Our primary business strategy is to generate strong and consistent growth in
reserves, production, operating cash flows and earnings through a balanced
program of exploration and development drilling and strategic acquisitions of
oil and gas properties. For the nine months ended September 30, 2000, we
invested $158.6 million in development activities and $37.1 million on
exploration activities. This expenditure level resulted in the drilling of
362 development wells and nine exploratory wells. Of these wells, 347
development wells and five exploratory wells were successfully completed as
producers, for a completion success rate of 96% and 56%, respectively (an
overall success rate of 95%). In addition, we invested $158.4 million in
proved oil and gas property acquisitions during the first nine months of 2000.
The more significant transaction involved the acquisition of proved and
unproved oil and gas properties from Costilla Energy, Inc. in June 2000. The
Costilla properties consisted of 135 Bcfe of net proved reserves contained
within 1,011 gross (607 net) producing wells. The acquired properties are
primarily located within our Core Areas. The $126 million purchase price, net
of estimated purchase price adjustments, was initially funded through
availability under the Credit Facility. See "Capital Resources and Liquidity
-- Common Stock Offering." The acquisition has been accounted for using the
purchase method of accounting. For the balance of 2000, we currently plan to
invest an additional $24 million in connection with our drilling program
focused principally in our Core Areas. Actual levels of drilling and
acquisition expenditures may vary due to many factors, including drilling
results, new drilling opportunities, oil and natural gas prices and
acquisition opportunities.
We continue to actively search for additional attractive oil and gas
property acquisitions, but are not able to predict the timing or amount of
additional capital expenditures which may ultimately be employed in
acquisitions during 2000.
<PAGE> 25
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
FOURTH QUARTER 2000 OUTLOOK
The following fourth quarter estimates have been prepared based on current
expectations for production, revenue and expenses from investment activity
planned under our 2000 capital program.
Revenues. Natural gas and crude oil production are each expected to
increase between 2% and 6% from levels realized for the third quarter of 2000.
Based on current market prices for oil and gas, we expect that natural gas
prices at the wellhead will average $.08 to $.12 per Mcf less than the average
of the last three trading days for the NYMEX Henry Hub index (NYMEX L3D). The
NYMEX L3D price for October 2000 was $5.30 per MMBtu and for November 2000 was
$4.62 per MMBtu. Crude oil prices are expected to average $1.30 to $1.50 per
Bbl less than the average NYMEX West Texas Intermediate price (WTI). The WTI
price for October 2000 was $32.94.
Approximately 6 Bcf of natural gas in the fourth quarter is hedged by
fixed-price contracts. The weighted average contract price, including the
amortization of deferred gains, is expected to be approximately $2.96 per Mcf,
before the impact of basis. Contract basis is expected to have the effect of
reducing the average contract price by $.02 to $.06 per Mcf. The amount of
change in derivative fair value to be reported in revenues for the fourth
quarter cannot be predicted due to contract valuations and effectiveness
testing which are performed as of the end of the year.
Expenses. Lease operating expenses for the fourth quarter are expected to
average approximately $.42 per Mcfe. Production taxes are expected to average
about 5.8% of wellhead sales. DD&A for the fourth quarter will be dependent
upon the results of the Company's year-end reserve study. However, the fourth
quarter DD&A rate is not expected to change materially from the average rate
for the first nine months of 2000.
General and administrative costs are expected to be approximately $6.5
million in the fourth quarter of 2000. Exploration costs could range between
$5.0 million and $13.5 million, depending upon the level of success
experienced with fourth quarter exploration drilling. We do not expect to
recognize an impairment charge in the fourth quarter of 2000; however,
impairments cannot be predicted with any certainty. The potential for a
fourth quarter impairment charge will be largely dependent upon the results of
the year-end reserve study and year-end prices. Interest expense is expected
to be approximately $10.5 million for the fourth quarter of 2000.
We expect that the effective income tax rate for the fourth quarter will
approximate 39%. The current tax provision in the fourth quarter of 2000 is
expected to represent between 5% and 13% of the total tax provision primarily
as a result of the deduction of intangible drilling costs and utilization of
acquired tax carryforwards.
<PAGE> 26
LOUIS DREYFUS NATURAL GAS CORP.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
GENERAL
Our results of operations and operating cash flows are impacted by changes
in market prices for oil and gas and changes in market interest rates. To
mitigate a portion of our exposure to adverse market changes, we have entered
into Fixed-Price Contracts and interest rate swaps. Each Fixed-Price Contract
and interest rate swap has been entered into as a hedge of oil and gas price
risk or interest rate risk and not for trading purposes. Information
regarding our market exposures, Fixed-Price Contracts, interest rate swaps and
certain other financial instruments is provided below. All information is
presented in U.S. Dollars.
FIXED-PRICE CONTRACTS
Description of Contracts. Our Fixed-Price Contracts are comprised of
long-term physical delivery contracts, energy swaps, collars, futures
contracts and basis swaps. These contracts allow us to predict with greater
certainty the effective oil and gas prices to be received for our hedged
production and benefit us when market prices are less than the fixed prices
provided in the Fixed-Price Contracts. However, we will not benefit from
market prices that are higher than the fixed prices in these contracts for our
hedged production. For the years ended December 31, 1999, 1998 and 1997,
Fixed-Price Contracts hedged 55%, 50% and 60%, respectively, of our natural
gas production and 19%, 16% and 33%, respectively, of our oil production. For
the nine months ended September 30, 2000, Fixed-Price Contracts hedged 53% of
our natural gas production and 54% of our oil production. As of September
30, 2000, Fixed-Price Contracts are in place to hedge 157 Bcf of our estimated
future natural gas production; 6 Bcf are hedged for the remainder of fiscal
2000.
Reference is made to our Annual Report on Form 10-K for the year ended
December 31, 1999 for a more detailed discussion of the Fixed-Price Contracts.
The following table summarizes the estimated volumes, fixed prices,
fixed-price sales and future net revenues attributable to the Fixed-Price
Contracts as of September 30, 2000. We expect the prices to be realized for
our hedged production to vary from the prices shown in the following table due
to basis, which is the differential between the floating price paid under each
energy swap contract, or the cost of gas to supply physical delivery contracts
and the price received at the wellhead for our production. Basis
differentials are caused by differences in location, quality, contract terms,
timing and other variables. Future net revenues for any period are determined
as the differential between the fixed prices provided by Fixed-Price Contracts
and forward market prices as of September 30, 2000, as adjusted for basis.
Future net revenues change with changes in market prices and basis.
<PAGE> 27
LOUIS DREYFUS NATURAL GAS CORP.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
(continued)
<TABLE>
<CAPTION>
FIXED-PRICE CONTRACTS
Three
Months
Ending
December Years Ending December 31,
Balance
31, --------------------------------------
through
2000 2001 2002 2003 2004
2017 Total
-------- -------- -------- -------- --------
-------- ---------
(dollars in thousands, except price
data)
<S> <C> <C> <C> <C> <C>
<C> <C>
NATURAL GAS SWAPS:
Contract volumes (BBtu) . . 2,580 7,840 6,697 5,650 5,650
12,133 40,550
Weighted-average fixed
price per MMBtu (1). . . $ 2.45 $ 2.46 $ 2.65 $ 2.92 $ 3.12 $
3.36 $ 2.92
Future fixed-price sales . $ 6,320 $ 19,281 $ 17,766 $ 16,492 $ 17,608 $
40,822 $ 118,289
Future net
revenues (losses) (2). . $ (7,239) $(16,882) $ (9,694) $ (4,077) $ (1,831)$
314 $ (39,409)
NATURAL GAS PHYSICAL
DELIVERY CONTRACTS:
Contract volumes (BBtu). . 3,790 17,814 17,689 14,819 6,634
41,321 102,067
Weighted-average fixed
price per MMBtu (1). . . $ 2.33 $ 2.38 $ 2.46 $ 2.53 $ 2.53 $
2.93 $ 2.65
Future fixed-price sales . $ 8,834 $ 42,464 $ 43,461 $ 37,428 $ 16,802
$121,209 $ 270,198
Future net losses (2). . . $(11,492) $(37,210) $(27,005) $(15,110) $
(5,679)$(20,004) $(116,500)
NATURAL GAS COLLARS:
Contract volumes (BBtu):
Floor. . . . . . . . . . -- 7,300 7,300 -- --
-- 14,600
Ceiling. . . . . . . . . -- 7,300 7,300 -- --
-- 14,600
Weighted-average fixed
price per MMBtu (1):
Floor. . . . . . . . . . $ -- $ 3.13 $ 2.84 $ -- $ -- $
-- $ 2.99
Ceiling. . . . . . . . . $ -- $ 4.25 $ 3.94 $ -- $ -- $
-- $ 4.10
Future fixed-price sales
(at ceiling). . . . . . . $ -- $ 31,025 $ 28,762 $ -- $ -- $
-- $ 59,787
Future net losses (2). . . $ -- $ (5,237) $ (4,139) $ -- $ -- $
-- $ (9,376)
TOTAL NATURAL GAS
CONTRACTS (3):
Contract volumes (BBtu). . 6,370 32,954 31,686 20,469 12,284
53,454 157,217
Weighted-average fixed
price per MMBtu (1). . . $ 2.38 $ 2.82 $ 2.84 $ 2.63 $ 2.80 $
3.03 $ 2.85
Future fixed-price sales . $ 15,154 $ 92,770 $ 89,989 $ 53,920 $ 34,410
$162,031 $ 448,274
Future net losses (2). . . $(18,731) $(59,329) $(40,838) $(19,187) $
(7,510)$(19,690) $(165,285)
<FN>
(1) - We expect the prices to be realized for our hedged production to vary
from the prices
shown due to basis.
(2) - Future net revenues (losses) as presented above are undiscounted and
have not been
adjusted for contract performance risk or counterparty credit risk.
(3) - Does not include basis swaps with notional volumes by year, as
follows: 2000 - 5.2 Tbtu;
2001 - 9.4 TBtu; and 2002 - 5.5 TBtu.
</TABLE>
<PAGE> 28
LOUIS DREYFUS NATURAL GAS CORP.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK (continued)
The estimates of future net revenues (losses) from Fixed-Price Contracts are
computed based on the difference between the prices provided by the
Fixed-Price Contracts and forward market prices as of the specified date. The
market for natural gas beyond a five year horizon is illiquid and published
market quotations are not available. We have relied upon near-term market
quotations, longer-term over-the-counter market quotations and other market
information to determine future net revenue estimates. Forward market prices
for natural gas are dependent upon supply and demand factors in the forward
market and are subject to significant volatility. The future net revenue
estimates shown above are subject to change as forward market prices change.
The estimated fair values of our Fixed-Price Contracts as of September 30,
2000 and December 31, 1999 are provided below. The associated carrying values
of these contracts are equal to the estimated fair values for each period
presented.
<TABLE>
<CAPTION>
September 30, December 31,
2000 1999
------------ ------------
(in thousands)
<S> <C> <C>
Derivative assets:
Fixed-price natural gas swaps. . . . . . . . $ -- $ 16,433
Fixed-price natural gas collars. . . . . . . -- 1,323
Fixed-price natural gas delivery contracts . 945 7,921
Fixed-price crude oil swaps. . . . . . . . . -- 360
Interest rate swaps. . . . . . . . . . . . . 3,847 5,660
Derivative liabilities:
Fixed-price natural gas swaps. . . . . . . . (35,950) (4,329)
Fixed-price natural gas collars. . . . . . . (9,376) --
Fixed-price natural gas delivery contracts . (104,652) (9,081)
Natural gas basis swaps. . . . . . . . . . . (1,374) (3,271)
------------ -------------
Total. . . . . . . . . . . . . . . . . . . . $ (146,560) $ 15,016
============ =============
</TABLE>
The fair value of Fixed-Price Contracts as of September 30, 2000 and
December 31, 1999 was estimated based on market prices of natural gas and
crude oil for the periods covered by the contracts. The net differential
between the prices in each contract and market prices for future periods, as
adjusted for estimated basis, has been applied to the volumes stipulated in
each contract to arrive at an estimated future value. This estimated future
value was discounted on a contract-by-contract basis at rates commensurate
with our estimation of contract performance risk and counterparty credit risk.
The fair value of derivative instruments which contain options (e.g. collar
structures) has been estimated based on remaining life, volatility and other
factors. For collars which are held to maturity, the option time value has no
direct relationship to actual future contract settlements and consequently
<PAGE> 29
LOUIS DREYFUS NATURAL GAS CORP.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK (continued)
does not represent a liability which will be settled in cash. The terms and
conditions of fixed-price physical delivery contracts and certain financial
swaps are uniquely tailored to our circumstances. In addition, the
determination of market prices for natural gas beyond a five year horizon is
subject to significant judgment and estimation. As a result, the Fixed-Price
Contract fair value does not necessarily represent the value a third party
would pay to assume our contract positions.
INTEREST RATE SENSITIVITY
We have entered into interest rate swaps to hedge the interest rate exposure
associated with borrowings under the Credit Facility. As of September 30,
2000, the interest rate has been hedged for average notional amounts of $125
million for the balance of 2000, and $125 million and $94 million for the
years ending December 31, 2001 and 2002, respectively. Under the interest
rate swaps, we receive the LIBOR three-month rate (6.8% at September 30, 2000)
and pay an average rate of 5.0% for the balance of 2000 and all of 2001 and
2002. The notional amounts are less than the maximum amount anticipated to be
outstanding under the Credit Facility in these years.
Reference is made to our Annual Report on Form 10-K for the year ended
December 31, 1999 for an expanded discussion of the interest rate swaps.
<PAGE> 30
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> 31
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: November 10, 2000 /s/ Jeffrey A. Bonney
-----------------------------------
Jeffrey A. Bonney
Executive Vice President and Chief
Financial Officer
