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, 1998
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 .
----- -----
40,109,758 shares of common stock, $.01 par value, issued and outstanding at
November 6, 1998.
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LOUIS DREYFUS NATURAL GAS CORP.
Table of Contents
PART I. FINANCIAL INFORMATION Page
CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
Consolidated Balance Sheets:
December 31, 1997 and September 30, 1998 . . . . . . . . . . . . . . 3
Consolidated Statements of Operations:
Three months and nine months ended September 30, 1997 and 1998 . . . 5
Consolidated Statements of Cash Flows:
Nine months ended September 30, 1997 and 1998. . . . . . . . . . . . 6
Condensed Notes to Consolidated Financial Statements . . . . . . . . . 7
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS. . . . . . . . . . . . . . . . . . . . . . 12
PART II. OTHER INFORMATION . . . . . . . . . . . . . . . . . . . . 27
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LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED BALANCE SHEETS
(dollars in thousands)
A S S E T S
December 31, September 30,
1997 1998
------------- -------------
(unaudited)
CURRENT ASSETS
Cash and cash equivalents. . . . . . . . . . $ 5,538 $ 5,209
Receivables:
Oil and gas sales . . . . . . . . . . . . . 46,192 33,241
Joint interest and other. . . . . . . . . . 14,311 13,693
Costs reimbursable by insurance . . . . . . 22,406 7,200
Deposits . . . . . . . . . . . . . . . . . . 4,467 3,053
Inventory and other. . . . . . . . . . . . . 9,883 3,979
------------- -------------
Total current assets . . . . . . . . . . . . 102,797 66,375
------------- -------------
PROPERTY AND EQUIPMENT, at cost, based on
successful efforts accounting . . . . . . . 1,404,784 1,564,022
Less accumulated depreciation, depletion
and amortization. . . . . . . . . . . . . . (305,769) (405,105)
------------- -------------
1,099,015 1,158,917
------------- -------------
OTHER ASSETS, net. . . . . . . . . . . . . . 9,142 8,759
------------- -------------
$ 1,210,954 $ 1,234,051
============= =============
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LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED BALANCE SHEETS (continued)
(dollars in thousands)
L I A B I L I T I E S A N D S T O C K H O L D E R S ' E Q U I T Y
December 31, September 30,
1997 1998
------------- -------------
(unaudited)
CURRENT LIABILITIES
Accounts payable . . . . . . . . . . . . . . $ 61,197 $ 41,385
Accrued liabilities. . . . . . . . . . . . . 22,258 19,540
Revenues payable . . . . . . . . . . . . . . 16,111 11,056
------------- -------------
Total current liabilities. . . . . . . . . . 99,566 71,981
------------- -------------
LONG-TERM DEBT . . . . . . . . . . . . . . . 563,344 592,645
------------- -------------
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred revenue . . . . . . . . . . . . . . 17,387 26,780
Deferred gains from price-risk management
activities. . . . . . . . . . . . . . . . . 23,453 62,223
Deferred income taxes. . . . . . . . . . . . 21,896 10,117
Other. . . . . . . . . . . . . . . . . . . . 16,104 18,650
------------- -------------
78,840 117,770
------------- -------------
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,
40,088,258 and 40,109,758 shares,
respectively. . . . . . . . . . . . . . . . 401 401
Additional paid-in capital . . . . . . . . . 418,751 419,075
Retained earnings. . . . . . . . . . . . . . 50,052 32,179
------------- -------------
469,204 451,655
------------- -------------
$ 1,210,954 $ 1,234,051
============= =============
See accompanying notes to consolidated financial statements.
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LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)
(in thousands, except per share data)
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ ------------------
1997 1998 1997 1998
-------- -------- -------- --------
REVENUES
Oil and gas sales. . . . . . . . . . . $ 46,091 $ 67,472 $142,193 $204,867
Other income . . . . . . . . . . . . . 702 1,362 10,602 3,914
-------- -------- -------- --------
46,793 68,834 152,795 208,781
-------- -------- -------- --------
EXPENSES
Operating costs. . . . . . . . . . . . 10,624 16,495 32,489 50,560
General and administrative . . . . . . 4,008 6,439 11,899 18,978
Exploration costs. . . . . . . . . . . 1,886 9,707 5,300 26,647
Depreciation, depletion and
amortization. . . . . . . . . . . . . 16,990 34,718 49,241 101,009
Impairment . . . . . . . . . . . . . . -- -- -- 9,864
Interest . . . . . . . . . . . . . . . 6,512 10,132 19,031 30,550
-------- -------- -------- --------
40,020 77,491 117,960 237,608
-------- -------- -------- --------
Income (loss) before income taxes. . . 6,773 (8,657) 34,835 (28,827)
Income taxes . . . . . . . . . . . . . 2,371 (3,218) 12,193 (10,954)
-------- -------- -------- --------
NET INCOME (LOSS). . . . . . . . . . . $ 4,402 $ (5,439) $ 22,642 $(17,873)
======== ======== ======== ========
Net income (loss) per share:
Basic. . . . . . . . . . . . . . . . . $ .16 $ (.14) $ .81 $ (.45)
======== ======== ======== ========
Diluted. . . . . . . . . . . . . . . . $ .16 $ (.14) $ .81 $ (.45)
======== ======== ======== ========
Weighted average number of common
shares outstanding:
Basic. . . . . . . . . . . . . . . . . 27,813 40,110 27,805 40,106
======== ======== ======== ========
Diluted. . . . . . . . . . . . . . . . 27,931 40,110 27,890 40,106
======== ======== ======== ========
See accompanying notes to consolidated financial statements.
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LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
(in thousands)
Nine Months Ended
September 30,
------------------
1997 1998
-------- --------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss). . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 22,642 $(17,873)
Items not affecting cash flows:
Depreciation, depletion and amortization . . . . . . . . . . . . . . . . 49,241 101,009
Impairment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -- 9,864
Deferred income taxes. . . . . . . . . . . . . . . . . . . . . . . . . . 11,252 (11,779)
Exploration costs. . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,300 26,647
Gain on sale of property . . . . . . . . . . . . . . . . . . . . . . . . (8,683) (113)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 536 472
Net change in operating assets and liabilities:
Accounts receivable. . . . . . . . . . . . . . . . . . . . . . . . . . . 1,715 30,369
Deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,606 1,414
Inventory and other. . . . . . . . . . . . . . . . . . . . . . . . . . . (1,708) 5,904
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5,822) (19,812)
Accrued liabilities. . . . . . . . . . . . . . . . . . . . . . . . . . . 3,818 (3,617)
Revenues payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . (438) (5,055)
-------- --------
80,459 117,430
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Exploration and development expenditures. . . . . . . . . . . . . . . . . (99,980) (191,455)
Acquisition of oil and gas properties . . . . . . . . . . . . . . . . . . (9,437) (5,197)
Additions to other property and equipment . . . . . . . . . . . . . . . . (1,899) (2,528)
Proceeds from sale of property and equipment. . . . . . . . . . . . . . . 27,448 1,733
Change in other assets. . . . . . . . . . . . . . . . . . . . . . . . . . -- (893)
-------- --------
(83,868) (198,340)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from bank borrowings . . . . . . . . . . . . . . . . . . . . . . 225,601 416,614
Repayments of bank borrowings . . . . . . . . . . . . . . . . . . . . . . (213,601) (387,514)
Proceeds from stock options exercised . . . . . . . . . . . . . . . . . . 479 324
Change in deferred revenue. . . . . . . . . . . . . . . . . . . . . . . . (1,228) 9,393
Change in gains from price-risk management activities . . . . . . . . . . (2,542) 38,770
Change in other long-term liabilities . . . . . . . . . . . . . . . . . . (2,498) 2,994
-------- --------
6,211 80,581
-------- --------
Change in cash and cash equivalents . . . . . . . . . . . . . . . . . . . 2,802 (329)
Cash and cash equivalents, beginning of period. . . . . . . . . . . . . . 7,749 5,538
-------- --------
Cash and cash equivalents, end of period. . . . . . . . . . . . . . . . . $ 10,551 $ 5,209
======== ========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Interest paid, net of capitalized interest. . . . . . . . . . . . . . . . $ 15,161 $ 21,518
Income taxes paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . 667 255
-------- --------
$ 15,828 $ 21,773
======== ========
See accompanying notes to consolidated financial statements.
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LOUIS DREYFUS NATURAL GAS CORP.
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
September 30, 1998
NOTE 1 -- ACCOUNTING PRINCIPLES AND BASIS OF PRESENTATION
The accompanying unaudited consolidated financial statements have been
prepared in accordance with the instructions to Form 10-Q as prescribed by the
Securities and Exchange Commission. All material adjustments, consisting of
only normal and recurring adjustments, which, in the opinion of Management,
were necessary for a fair presentation of the results for the interim periods
have been reflected. The results of operations for the three-month and
nine-month periods ended September 30, 1998 are not necessarily indicative of
the results to be expected for the full year. Certain reclassifications have
been made to the prior year financial 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, 1997 for an expanded discussion of the
Company's financial disclosures and accounting policies.
NOTE 2 -- EARNINGS PER SHARE
In December 1997, the Company adopted Statement of Financial Accounting
Standards No. 128, "Earnings per Share" ("SFAS 128"), which changes the method
used to compute earnings per share and requires the restatement of all prior
periods to conform with the new calculation method. The restatement of
earnings per share information for the 1997 periods pursuant to SFAS 128 did
not result in a change to amounts previously reported. Weighted average
diluted common shares outstanding for the three months and nine months ended
September 30, 1997 include the effect of dilutive stock options. All stock
options were anti-dilutive in 1998. Reference is made to the Notes to
Consolidated Financial Statements included in the Company's Annual Report on
Form 10-K for the year ended December 31, 1997 for a description of
potentially dilutive securities of the Company.
NOTE 3 -- COMPREHENSIVE INCOME
The Company adopted Statement of Financial Accounting Standards No. 130,
"Reporting Comprehensive Income" ("SFAS 130") on January 1, 1998, which is
effective for fiscal years beginning after December 15, 1997. The provisions
of SFAS 130 require the Company to classify items of other comprehensive
income in the financial statements and display the accumulated balance of
other comprehensive income separately from retained earnings and additional
paid-in capital in the equity section of the statement of financial position.
Reclassification of financial statements for all prior periods is required for
comparative purposes. For the three months and nine months ended September
30, 1997 and 1998, the effects of the provisions of SFAS 130 were immaterial.
NOTE 4 -- ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
In June 1998, the Financial Accounting Standards Board issued Statement No.
133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS
133"), which is effective for all fiscal quarters of fiscal years beginning
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LOUIS DREYFUS NATURAL GAS CORP.
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued)
September 30, 1998
after June 15, 1999. Earlier application is permitted only as of the
beginning of any fiscal quarter that begins after issuance of the statement.
SFAS 133 establishes new accounting and reporting guidelines for derivative
instruments and for 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. 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. Any change in fair value resulting
from ineffectiveness, as defined by SFAS 133, is recognized immediately in
earnings. The Company believes that substantially all derivatives in its
portfolio of contracts qualify as cash flow hedges. Changes in the fair value
of derivative instruments which are not hedges are recorded in earnings as the
changes occur.
SFAS 133 does not specifically address a number of issues that are unique to
the oil and gas industry. In addition, certain provisions are complex and
their application to the Company's set of circumstances must be inferred. The
Company believes that adoption of the standard will result in the
reclassification, net of deferred income tax effect, of the balance of
deferred gains from price-risk management activities to stockholders' equity.
In addition, the fair value of its energy swaps, collars, futures contracts,
basis swaps and interest rate swaps will be recorded as assets
and liabilities. The net step-up in value will be reflected as a component of
stockholders' equity net of deferred income tax effect. The term "derivative"
is defined broadly in the new pronouncement. The Company believes, though it
is uncertain at this time, that its long-term physical delivery contracts meet
the definition of a derivative and, consequently, are subject to the
provisions of this statement. This issue is one of many presented to an
implementation task force created by the Financial Accounting Standards Board
for consideration. Certain fixed-price contracts in the Company's portfolio
contain provisions or have other characteristics that are unique to such
contracts. An established market does not exist for determining fair value
for these contracts; consequently, assessing fair value will require the
evaluation of many subjective factors, such as performance, basis and credit
risks. The Company has not completed a fair value determination for its
contract portfolio. However, the Company's preliminary estimate suggests that
adoption of SFAS 133 would have resulted in an increase to stockholders'
equity of approximately $100 million as of September 30, 1998. This increase
is based on the fixed prices provided by each contract, commodity market
prices for future periods, the balance of deferred gains and losses from
price-risk management activities, market interest rates and corresponding
deferred income tax effects. This valuation is subject to change based on the
completion of the Company's valuation analysis, changes in market prices and
rates, future contract settlements and other factors.
There are other provisions which could have a material effect on the
Company's financial statements. One such provision precludes the
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LOUIS DREYFUS NATURAL GAS CORP.
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued)
September 30, 1998
consideration of future cash flows of derivative instruments in asset
impairment determinations irrespective of any risk management intent for
entering into such instruments. At this time, the Company is not able to
predict the amount of impairment, if any, that may be recognized due to the
adoption of SFAS 133. Any resultant charge is expected to be more than offset
by the net step-up in value of the Company's fixed-price contracts. The
Company expects to adopt SFAS 133 by December 31, 1998.
NOTE 5 -- ACQUISITION OF AMERICAN EXPLORATION COMPANY
In October 1997, the Company acquired 100% of the outstanding common stock
of American Exploration Company ("American"), a Houston-based, publicly-held
independent energy company with exploration and development activities focused
primarily in South Texas, the Texas State Waters, the Cotton Valley Reef Trend
in East Texas and the Smackover Trend in Arkansas (the "American
Acquisition"). The acquisition consideration paid consisted of approximately
11.3 million shares of LDNG Common Stock valued at $17.15 per share and $47.2
million of cash. In addition, LDNG assumed $116 million of American long-term
debt, $20 million liquidation value of American preferred stock, and warrants
and options valued at $10.3 million. The acquisition consisted of 217 Bcfe of
proved reserves, approximately 3,500 producing wells, 1.0 million gross acres
of developed leasehold, 2.0 million gross acres of undeveloped leasehold and
other assets and liabilities. The purchase method was used to account for
this acquisition.
NOTE 6 -- 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
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LOUIS DREYFUS NATURAL GAS CORP.
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued)
September 30, 1998
thereto in the accompanying financial statements during 1998. The Company
will recognize income as any payments are received.
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 obtained in the American
Acquisition, to market levels from October 1, 1993 forward. KNGSS alleges
that it has overpaid American and seeks 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
American in July 1996 and was argued before the court in February 1997. The
Company assumed responsibility for this lawsuit in connection with the
American Acquisition. In February 1998, the court ruled in favor of the
Company's motion. 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.
American was a defendant in various other legal proceedings for which the
Company also assumed responsibility in the American Acquisition. The largest
of such legal claims was for an alleged underpayment of royalty of $3.2
million plus interest. In addition, American had received preliminary and
final royalty underpayment determinations from the Minerals Management Service
aggregating approximately $2.8 million plus interest in connection with
certain gas contract settlements made in prior years. The Company is a
defendant in additional pending legal proceedings which are routine and
incidental to its business. While the ultimate results of all these
proceedings and determinations cannot be predicted with certainty, the Company
will vigorously defend its interests and does not believe that the outcome of
these matters will have a material adverse effect on the Company.
NOTE 7 -- FIXED-PRICE CONTRACTS
The Company had two fixed-price contracts with independent power producers
("IPPs") which sold electrical power under firm fixed-price contracts to
Niagara Mohawk Corporation ("NIMO"), a New York state utility ("NIMO
Contracts"). In July 1997, NIMO entered into a Master Restructuring Agreement
(the "MRA") with 16 IPPs, including the counterparties to the NIMO Contracts.
Subsequently, one of the 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, the receipt of which has
been recorded as a deferred gain from price-risk management activities in the
Company's balance sheet to be amortized over the remaining contract term (see
Note 4). The remaining NIMO Contract which hedges 56 Bcf of natural gas as of
September 30, 1998 remains in force. Accordingly, the Company plans to
continue to deliver natural gas pursuant to the terms of this contract which
11
LOUIS DREYFUS NATURAL GAS CORP.
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued)
September 30, 1998
expires in 2007.
NOTE 8 -- SECTION 29 CREDIT TRANSACTION
Effective May 1, 1998, the Company entered into an agreement with a third
party to convey certain oil and gas properties which have production
qualifying for Section 29 tax credits. The agreement provides for the
conveyance of qualifying properties in two separate tranches, the first of
which was funded in July 1998 resulting in the receipt of $12.7 million. The
second tranche which pertains to a smaller number of properties is expected to
close later in 1998. As of September 30, 1998, the Company's balance sheet
reflects deferred revenue of $10.7 million associated with the first tranche
which is being recognized in earnings as production occurs.
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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 come from proved reserve acquisitions geographically
concentrated in six core areas: the Sonora area of West Texas; the
Mid-Continent area of Oklahoma, Kansas and the Panhandle of Texas; the Western
area of West Texas and Southeast New Mexico; the Gulf Coast area of South
Texas; the Offshore area in the Gulf of Mexico; and the Arklatex area of East
Texas, Southwest Arkansas and Northern Louisiana (collectively "Core Areas"),
where the Company has significant expertise and where the Company benefits
from operational synergies. For 1998, the Company plans to spend
approximately $215 million for oil and gas exploration and development
activities in these Core Areas. These plans include approximately $80
million targeted for exploration projects.
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
September 30, 1998, the Company's Fixed-Price Contracts hedged 279 Bcfe of
future production, representing 23% of its estimated proved reserves, at
escalating fixed prices. These fixed prices are presently significantly
higher than the forward market prices for natural gas. Recent hedging
activity has been for shorter periods of time, generally less than 12 months,
when market conditions have been viewed as favorable.
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, drilling risks,
reserves, operations or 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, 1997. Moreover, the Company may make material acquisitions
and modify its Fixed-Price Contract positions by entering into new contracts
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LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
or terminating existing contracts or entering into financing transactions.
None of these can be predicted with certainty and, accordingly, are not taken
into consideration in the Forward-Looking Statements made herein. 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 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. 42 U.S. gallons, the basic unit for measuring crude oil and natural
gas condensate.
Bcf. Volume of one billion cubic feet.
Bcfe. Bcf 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 quantity of heat required to raise
the temperature of a one-pound mass of water from 58.5 to 59.5
degrees Fahrenheit.
MBbls. Volume of one thousand barrels.
Mcf. Volume of one thousand cubic feet, the basic unit for measuring
natural gas.
Mcfe. Mcf equivalent, determined using the ratio of one Bbl of oil or
condensate to six Mcf of natural gas.
MMBbls. Volume of one million barrels.
MMBtu. Million Btus.
MMcf. Volume of one million cubic feet.
MMcfe. MMcf equivalent, determined using the ratio of one Bbl of oil or
condensate to six Mcf of natural gas.
TBtu. Trillion Btus.
14
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
Selected Operating Data. The following table provides certain operating
data relating to the Company's operations.
SELECTED OPERATING DATA
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ ------------------
1997 1998 1997 1998
-------- -------- -------- --------
OIL AND GAS SALES: (M$)
Wellhead oil sales . . . . . . . . . . $ 7,390 $ 10,436 $ 24,915 $ 33,462
Effect of Fixed-Price Contracts (1). . -- -- 322 496
-------- -------- -------- --------
Total oil sales. . . . . . . . . . . . $ 7,390 $ 10,436 $ 25,237 $ 33,958
======== ======== ======== ========
Wellhead natural gas sales . . . . . . $ 38,007 $ 49,410 $117,515 $155,956
Effect of Fixed-Price Contracts (1). . 694 7,626 (559) 14,953
-------- -------- -------- --------
Total natural gas sales. . . . . . . . $ 38,701 $ 57,036 $116,956 $170,909
======== ======== ======== ========
PRODUCTION:
Oil production (MBbls) . . . . . . . . 403 877 1,240 2,615
Natural gas production (MMcf). . . . . 16,774 25,279 48,379 75,222
Net equivalent production (MMcfe). . . 19,193 30,543 55,819 90,914
Oil production hedged by Fixed-Price
Contracts (MBbls) . . . . . . . . . . -- -- 362 79
Gas production hedged by Fixed-Price
Contracts (BBtu). . . . . . . . . . . 11,673 13,975 29,241 36,862
15
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
SELECTED OPERATING DATA, continued
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ ------------------
1997 1998 1997 1998
-------- -------- -------- --------
AVERAGE SALES PRICE:
Oil (per Bbl):
Wellhead price . . . . . . . . . . . $ 18.32 $ 11.90 $ 20.09 $ 12.79
Effect of Fixed-Price Contracts (1). -- -- .26 .19
-------- -------- -------- --------
Total. . . . . . . . . . . . . . . . $ 18.32 $ 11.90 $ 20.35 $ 12.98
======== ======== ======== ========
Average fixed price received under
Fixed-Price Contracts . . . . . . . $ n/a $ n/a $ 22.32 $ 22.20
Net effective realization (2). . . . n/a n/a 98% 92%
Natural gas (per Mcf):
Wellhead price . . . . . . . . . . . $ 2.27 $ 1.96 $ 2.43 $ 2.07
Effect of Fixed-Price Contracts (1). .04 .30 (.01) .20
-------- -------- -------- --------
Total. . . . . . . . . . . . . . . . $ 2.31 $ 2.26 $ 2.42 $ 2.27
======== ======== ======== ========
Average fixed price received under
Fixed-Price Contracts . . . . . . . $ 2.41 $ 2.60 $ 2.45 $ 2.60
Net effective cash realization (2) . 97% 96% 99% 95%
Equivalent price (per Mcfe). . . . . . $ 2.40 $ 2.21 $ 2.55 $ 2.25
EXPENSES: (per Mcfe)
Operating costs:
Lease operating. . . . . . . . . . . $ .43 $ .43 $ .45 $ .45
Production taxes . . . . . . . . . . $ .12 $ .11 $ .13 $ .11
General and administrative . . . . . . $ .21 $ .21 $ .21 $ .21
Depreciation, depletion and
amortization - oil & gas . . . . . $ .82 $ 1.09 $ .82 $ 1.07
(1) - Represents the hedging results from the Company's Fixed-Price Contracts.
See "Fixed-Price Contracts."
(2) - Represents the net effective price realized for the Company's hedged
production (after consideration for basis results and amortization of
deferred hedging gains and losses) as a percentage of the fixed prices
in the Company's Fixed-Price Contracts. See "Fixed-Price Contracts."
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, 1998 COMPARED TO
THREE MONTHS ENDED SEPTEMBER 30, 1997
Net Income (Loss) and Cash Flows from Operating Activities. For the quarter
ended September 30, 1998, the Company realized a net loss of $5.4 million, or
$.14 per share, on total revenue of $68.8 million. This compares to net
income of $4.4 million, or $.16 per share, on total revenue of $46.8 million
for the third quarter of 1997. Cash flows from operating activities (before
working capital changes) for the third quarter of 1998 grew significantly,
increasing 38% to $35.6 million compared to $25.8 million for the third
quarter of 1997. Significant production growth was the principal driver
behind the increase in operating cash flows, more than offsetting the effects
of lower oil and gas prices. Increases in non-cash expenses (oil and gas
depletion and exploration costs) adversely affected results of operations for
the quarter ended September 30, 1998. Cash flows provided by operating
activities after consideration of the net change in working capital increased
to $44.6 million from the $26.5 million reported for the third quarter of
1997, primarily due to the increase in production previously discussed and a
decrease in accounts receivable.
Production. The Company produced 30.5 Bcfe for the third quarter of 1998
compared to 19.2 Bcfe for the prior year third quarter, an increase of 59%.
Gas production increased to 25.3 Bcf compared to 16.8 Bcf for the third
quarter of 1997, an increase of 51%. Oil production for the third quarter of
1998 increased 118% to 877 MBbls compared to 403 MBbls for the prior-year
third quarter. These increases in production are primarily attributable to
the American Acquisition and the results of the Company's oil and gas drilling
program.
Oil and Gas Prices. On a natural gas equivalent basis, the Company received
an average price of $2.21 per Mcfe for the quarter ended September 30, 1998, a
decrease of 8% from the $2.40 per Mcfe received for the third quarter of 1997.
The Company's gas production yielded an average price of $2.26 per Mcf, a
decrease of 2% compared to $2.31 per Mcf for the prior-year third quarter.
The Company's average gas price for the 1998 third quarter was enhanced $.30
per Mcf as a result of the Company's hedging activities. The average gas
price for the third quarter of 1997 increased $.04 per Mcf as a result of the
Fixed-Price Contracts in effect for that period. The average oil price for
the third quarter of 1998 was $11.90 per Bbl a decrease of 35% from the $18.32
per Bbl received for the prior-year third quarter. No fixed-price oil
contracts were in effect during the 1998 or 1997 third quarters.
The net effect of higher gas production and lower gas prices was to increase
gas sales to $57.0 million for the third quarter of 1998 compared to $38.7
million for the third quarter of 1997. The net effect of higher oil production
and lower oil prices increased oil sales to $10.4 million compared to $7.4
million reported for the prior-year quarter. The impact of the Company's gas
hedging activities was to increase gas sales by $7.6 million for the quarter
ended September 30, 1998 and to increase gas sales by $.7 million for the
17
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
quarter ended September 30, 1997. See "Fixed-Price Contracts."
Operating Costs. Operating costs for the third quarter of 1998 were
comprised of $13.3 million of lease operating expenses and $3.2 million of
production taxes. This compares to $8.2 million of lease operating expenses
and $2.4 million of production taxes for the third quarter of 1997. These
increases are principally attributable to producing properties acquired in the
American Acquisition and wells drilled during the previous twelve months.
Lease operating expenses on a natural gas equivalent unit of production basis
remained constant at $.43 per Mcfe for the three months ended September 30,
1998 compared to the three months ended September 30, 1997.
General and Administrative Expense. General and administrative
expense("G&A") for the third quarter of 1998 was $6.4 million, an increase of
61% from the prior-year third quarter amount of $4.0 million. This increase is
primarily attributable to increases in personnel and related costs as a result
of the American Acquisition. On a natural gas equivalent unit of production
basis, G&A remained constant at $.21 per Mcfe for the 1998 and 1997 third
quarters.
Exploration Costs. Exploration costs, comprised of geological and
geophysical costs, exploratory dry holes and leasehold impairment costs, were
$9.7 million for the quarter ended September 30, 1998, compared to $1.9
million for the third quarter of 1997. The 1998 amount consists of $7.6
million of dry hole costs, $1.3 million of seismic acquisition and other
geological and geophysical costs and $.8 million of leasehold costs. The 1997
amount consists of $1.7 million of dry hole costs and $.2 million of seismic
acquisition and other geological and geophysical costs.
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization ("DD&A") for the third quarter of 1998 was $34.7 million compared
to $17.0 million for the prior-year third quarter. This increase in DD&A is
attributable to higher production levels and an increase in the oil and gas
DD&A rate. The oil and gas DD&A rate per equivalent unit of production was
$1.09 for the 1998 third quarter compared to $.82 for the third quarter of
1997. This increase was due primarily to the American Acquisition purchase
price allocated to proved reserves using the purchase method of accounting.
Interest Expense. Interest expense for the third quarter of 1998 was $10.1
million compared to $6.5 million for the third quarter of 1997. This increase
is primarily attributable to a higher level of outstanding indebtedness for
the 1998 third quarter as a result of the American Acquisition. On a natural
gas equivalent unit of production basis, interest costs decreased to $.33 per
Mcfe for the third quarter of 1998 compared to $.34 per Mcfe for the
prior-year third quarter. The net impact of interest rate swaps in effect for
the third quarter of 1998 and 1997 was not material.
Income Taxes. For the third quarter of 1998, the Company recorded a tax
benefit of $3.2 million on a pre-tax loss of $8.7 million, an effective rate
18
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
of 37%. This compares to an income tax provision of $2.4 million provided on
pre-tax income of $6.8 million, an effective rate of 35%, for the third
quarter of 1997. The effective rate for the third quarter of 1997 was lower
than the statutory rate primarily due to the availability of Section 29
credits.
RESULTS OF OPERATIONS -- NINE MONTHS ENDED SEPTEMBER 30, 1998 COMPARED TO NINE
MONTHS ENDED SEPTEMBER 30, 1997
Net Income (Loss) and Cash Flows from Operating Activities. The Company
realized a net loss of $17.9 million, or $.45 per share, on total revenue of
$208.8 million for the nine months ended September 30, 1998. This compares
with net income of $22.6 million, or $.81 per share, on total revenue of
$152.8 million for the nine months ended September 30, 1997. Cash flows from
operating activities (before working capital changes) for the first nine
months of 1998 were notably higher at $108.2 million, compared to $80.3
million for the first nine months of 1997, an increase of 35%. The decrease
in 1998 earnings was primarily the result of lower oil and gas prices, higher
DD&A, and increased exploration costs. The increase in cash flows provided by
operating activities (before working capital changes) was primarily driven by
significant production growth as described below. Cash flows provided by
operating activities after consideration of the net change in working capital
increased to $117.4 million from the $80.5 million reported for the third
quarter of 1997, primarily due to the increase in production previously
discussed and a decrease in accounts receivable.
Production. The Company produced 90.9 Bcfe for the first nine months of
1998 compared to 55.8 Bcfe for the comparable prior-year period, an increase
of 63%. Gas production increased to 75.2 Bcf compared to 48.4 Bcf for the
first nine months of 1997, an increase of 55%. Oil production for the first
nine months of 1998 increased 111% to 2,615 MBbls compared to 1,240 MBbls for
the first nine months of 1997. These increases are primarily attributable to
the American Acquisition and the results of the Company's exploration and
development drilling activities.
Oil and Gas Prices. On a natural gas equivalent basis, the Company received
an average price of $2.25 per Mcfe for the first nine months of 1998, a
decrease of 12% from the $2.55 per Mcfe received for the first nine months of
1997. The Company's gas production yielded an average price of $2.27 per Mcf,
a decrease of 6% compared to $2.42 per Mcf for the prior-year period. The
Company's average gas price for the first nine months of 1998 was enhanced
$.20 per Mcf as a result of the Company's hedging activities. The average gas
price for the first nine months of 1997 decreased $.01 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 1998 was $12.98 per Bbl compared to $20.35 per
Bbl for the first half of 1997, a decline of 36%. The average oil price for
the current year nine-month period was enhanced $.19 per Bbl as a result of
the Company's hedging activities. Fixed-Price Contracts in effect during the
prior-year nine-month period increased the average oil price by $.26 per Bbl.
19
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 lower gas prices increased gas
sales to $170.9 million for the first nine months of 1998 compared to $117.0
million for the first nine months of 1997. The net effect of higher oil
production and lower oil prices increased oil sales to $34.0 million compared
to $25.2 million reported for the prior-year period. The aggregate impact of
the Company's oil and gas hedging activities was to increase oil and gas sales
by $15.4 million for the nine months ended September 30, 1998 and to decrease
oil and gas sales by $.2 million for the nine months ended September 30, 1997.
See "Fixed-Price Contracts."
Other Income. Other income for the first nine months of 1998 was $3.9
million compared to $10.6 million for the first nine months of 1997. The 1997
amount included a net gain of $8.5 million realized upon the sale of a
non-core waterflood property.
Operating Costs. Operating costs for the first nine months of 1998 were
comprised of $40.5 million of lease operating expenses and $10.1 million of
production taxes. This compares to $25.1 million of lease operating expenses
and $7.4 million of production taxes for the first nine months of 1997. These
increases are principally attributable to producing properties acquired in the
American Acquisition and wells drilled during the previous twelve months.
Lease operating expenses on a natural gas equivalent unit of production basis
remained constant at $.45 per Mcfe for the nine months ended September 30,
1998 compared to the nine months ended September 30, 1997.
General and Administrative Expense. G&A for the first nine months of 1998
was $19.0 million compared to $11.9 million for the comparable prior-year
period. This increase is primarily attributable to increases in personnel and
related costs as a result of the American Acquisition. On a natural gas
equivalent unit of production basis, G&A remained constant at $.21 per Mcfe
for the first nine months of 1998 compared to the first nine months of 1997.
Exploration Costs. Exploration costs were $26.6 million for the nine months
ended September 30, 1998, compared to $5.3 million for the nine months ended
September 30, 1997. The 1998 amount consists of $16.0 million of dry hole
costs, $7.6 million of seismic acquisition and other geological and
geophysical costs and $3.0 million of leasehold costs. The 1997 amount
consists of $2.5 million of dry hole costs, $2.2 million of seismic
acquisition and other geological and geophysical costs and $.6 million of
leasehold costs. The Company invested $70.4 million and $14.0 million,
respectively, in its exploration program during the nine months ended
September 30, 1998 and 1997.
Depreciation, Depletion and Amortization. DD&A for the first nine months of
1998 was $101.0 million compared to $49.2 million for the first half of 1997.
This increase in DD&A is attributable to higher production levels and an
increase in the oil and gas DD&A rate. The oil and gas DD&A rate per
equivalent unit of production was $1.07 for the first nine months of 1998
compared to $.82 for the first nine months of 1997. This increase was due
20
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
primarily to the American Acquisition purchase price allocated to proved
reserves using the purchase method of accounting.
Impairment. In the second quarter of 1998, the Company recorded an
impairment charge of $9.9 million as the result of an impairment review
conducted in response to the significant decline in oil prices. This review
identified one field which had a net book value in excess of estimated future
net revenues for the field, which resulted in the impairment charge. There
was no impairment charge recorded for the first nine months of 1997.
Interest Expense. Interest expense for the nine months ended September 30,
1998 was $30.6 million compared to $19.0 million for the nine months ended
September 30, 1997. This increase is primarily attributable to a higher level
of outstanding indebtedness for the first nine months of 1998 as a result of
the American Acquisition. On a natural gas equivalent unit of production
basis, interest costs remained constant at $.34 per Mcfe for the first nine
months of 1998 and 1997. The net impact of interest rate swaps in effect for
the first nine months of 1998 and 1997 was immaterial.
Income Taxes. For the first nine months of 1998, the Company recorded a tax
benefit of $11.0 million on a pre-tax loss of $28.8 million, an effective rate
of 38%. This compares to an income tax provision of $12.2 million provided on
pre-tax income of $34.8 million, an effective rate of 35%, for the first nine
months of 1997. The effective rate for the first nine months of 1997 was
lower than the statutory rate primarily due to the availability of Section 29
credits.
CAPITAL RESOURCES AND LIQUIDITY
Cash Flows. The Company's business of acquiring, exploring and developing
oil and gas properties is capital intensive. The Company's ability to grow
its reserve base is contingent, in part, upon its ability to generate cash
flows from operating activities and to access outside sources of capital to
fund its investing activities. For the nine months ended September 30,
1998 and 1997, the Company expended $196.7 million and $109.4 million,
respectively, in oil and gas property acquisition, exploration and development
activities, representing substantially all of the cash flow invested by the
Company during the nine-month periods. See "Commitments and Capital
Expenditures." Cash flows from operating activities before changes in working
capital for the nine months ended September 30, 1998 and 1997 were $108.2
million and $80.3 million, representing 55% and 73%, respectively, of the oil
and gas property investments made for each period. Substantially all of the
cash flows from operating activities are generated from oil and gas sales
which are highly dependent upon oil and gas prices. Significant decreases in
the market prices of oil and gas could result in lower cash flows from
operating activities, which could, in turn, impact the amount of capital
invested by the Company. See "Fixed-Price Contracts."
The Company received net proceeds of $26.2 million in connection with the
January 1997 sale of a non-core waterflood property. The proceeds were used
21
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
to reduce outstanding indebtedness. As a result, cash flows from financing
activities for the first nine months of 1997 reflected a net source of cash of
$6.2 million, compared to an $80.6 million source of cash for the first nine
months of 1998. Included in the amount for 1998 is $40.1 million of proceeds
received in connection with the termination of a Fixed-Price Contract. See
Note 7 of the Condensed Notes to Consolidated Financial Statements appearing
elsewhere herein. Historically, the Company has relied upon availability
under various revolving bank credit facilities and proceeds from the issuance
of senior and subordinated notes to fund its investing activities.
The Company's EBITDAX increased from $108.4 million for the first nine
months of 1997 to $139.2 million for the first nine months of 1998. EBITDAX
is defined herein as income (loss) before interest, income taxes, DD&A,
impairments and exploration costs. Increases in EBITDAX have occurred
primarily as a result of increases in the Company's oil and gas sales. The
Company believes that EBITDAX is a financial measure commonly used in the oil
and gas industry as an indicator of a company's ability to service and incur
debt. However, EBITDAX should not be considered in isolation or as a
substitute for net income, cash flows provided by operating activities or
other data prepared in accordance with generally accepted accounting
principles, or as a measure of a company's profitability or liquidity.
EBITDAX measures as presented may not be comparable to other similarly titled
measures of other companies.
Credit Facility. In October 1997, in connection with the American
Acquisition, the Company replaced its $300 million borrowing base credit
facility with a new $550 million revolving credit facility (the "Credit
Facility"). Upon the issuance of senior notes in December 1997, the Company
reduced the aggregate commitment under the Credit Facility to $450 million
(the "Commitment"). 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. Letters of credit are limited to
$75 million of such availability. No principal payments are required under
the Credit Facility prior to termination on October 14, 2002. The Company has
relied upon the Credit Facility and the predecessor bank 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, 1998, the Company had $290.0 million of principal and $5.0
million of letters of credit outstanding under the Credit Facility.
The Company has the option of borrowing at a LIBOR-based interest rate or
the Base Rate (approximating the prime rate). The LIBOR interest rate margin
and the facility fee payable under the Credit Facility are subject to a
sliding scale based on the Company's senior debt credit rating. At September
30, 1998, the applicable interest rate was LIBOR plus 30 basis points. The
22
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
Credit Facility also requires the payment of a facility fee equal to 15 basis
points of the Commitment. At September 30, 1998, the effective interest rate
for borrowings under the Credit Facility was 6.2%, 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, 1997 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.
6 7/8% Senior Notes due 2007. In December 1997, the Company issued $200
million principal amount, $198.8 million net of discount, of 6 7/8% Senior
Notes due 2007. Interest is payable semi-annually on June 1 and December 1.
The associated indenture agreement contains restrictive covenants which place
limitations on the amount of liens and the Company's ability to enter into
sale and leaseback transactions.
9 1/4% Subordinated Notes due 2004. In June 1994, the Company issued $100
million principal amount, $98.5 million net of discount, of 9 1/4% Senior
Subordinated Notes due 2004 (the "Subordinated Notes"). Interest is payable
semi-annually on June 15 and December 15. The associated indenture agreement
contains certain restrictive covenants which limit, among other things, the
prepayment of the Subordinated Notes, the incurrence of additional
indebtedness, the payment of dividends and the disposition of assets.
Other Lines of Credit. The Company has certain other lines of credit
available to it which aggregated $45.1 million as of September 30, 1998. Such
short-term lines of credit are uncommitted, unsecured and used primarily to
meet margin requirements under Fixed-Price Contracts and for working capital
purposes. As of September 30, 1998, the Company had $4.6 million of
borrowings and $15.1 million of letters of credit outstanding under such
credit lines. Repayment of indebtedness thereunder is expected to be made
through Credit Facility availability.
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 1998, and
to meet the Company's margin requirements under its Fixed-Price Contracts.
See "Commitments and Capital Expenditures" and "Fixed-Price Contracts." At
September 30, 1998, the Company had a working capital deficit of $5.6 million
and a current ratio of .9 to 1. Total long-term debt outstanding at September
30, 1998 was $592.6 million. The Company's long-term debt as a percentage of
its total capitalization was 57%. This ratio is expected to decrease upon the
adoption of SFAS 133. See Note 4 of the Condensed Notes to Consolidated
Financial Statements appearing elsewhere herein.
23
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
COMMITMENTS AND CAPITAL EXPENDITURES
The Company's primary business strategy is to increase oil and gas
production and reserves through acquisition, development and exploration
activities. For the nine months ended September 30, 1998, the Company
expended $196.7 million in connection with this strategy, including $121.0
million for development activities and $70.4 million for exploration
activities which includes $16.6 million of unproved property costs expected to
benefit future periods. This expenditure level resulted in the drilling of
270 development wells and 22 exploratory wells. Of these wells, 250
development wells and 11 exploratory wells were successfully completed as
producers, for a completion success rate of 93% and 50%, respectively (an
overall success rate of 89%). In connection with the Company's fourth quarter
drilling plans, the board of directors recently approved a $15 million
increase, bringing the total 1998 drilling budget to $215 million. Actual
levels of development and exploration expenditures may vary due to many
factors, including drilling results, new drilling opportunities, oil and
natural gas prices and acquisition opportunities.
Certain significant exploratory successes have just recently begun
contributing to the Company's production growth. During October, the Company
brought two offshore discoveries on production at a combined rate of 22 MMcf
of natural gas per day. The Company owns a 100% working interest in these
wells. In the Gulf Coast region, four new Lower Wilcox tests recently came on
production at a combined rate of 16 MMcf of natural gas per day. The combined
production rate is expected to increase to 25 MMcf per day when
associated pipeline capacity is increased, scheduled to occur by year-end
1998. The Company owns an average 36% working interest in these four wells.
Further, casing has been set on four additional Lower Wilcox discoveries which
are presently undergoing completion. The Company also has an average 36%
working interest in these four wells. Five additional Lower Wilcox wells are
expected to reach total depth by year-end 1998.
The Company continues to actively search for attractive proved reserve
acquisitions but is not able to predict the timing or amount of capital
expenditure which may be employed in acquisitions during 1998 and is not
currently obligated to make any material acquisitions.
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, basis swaps and option
agreements. 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, 1995,
24
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
1996 and 1997, Fixed-Price Contracts hedged 84%, 51%, and 60% of the Company's
natural gas production not otherwise subject to fixed prices and 86%, 67% and
33% of its oil production, respectively. For the nine months ended September
30, 1998, Fixed-Price Contracts hedged 49% of the Company's natural gas
production and 3% of its oil production. As of September 30, 1998,
Fixed-Price Contracts are in place to hedge 275 Bcf of the Company's estimated
future production from proved gas reserves and 690 MBbls of its future
oil production.
During 1998, the Company entered into ten natural gas fixed-price collars
which had floors hedging an aggregate of 17.2 TBtu of natural gas, 9.9 TBtu
for 1998 and 7.3 TBtu for 1999, and ceilings covering 33.2 TBtu of natural
gas, 18.6 TBtu for 1998 and 14.6 TBtu for 1999. The Company additionally
entered into one crude oil fixed-price collar, the floor of which hedges 230
MBbls of oil and the ceiling covers 460 MBbls of oil for the fourth quarter of
1998. The natural gas collars contain floor prices ranging from $2.10 per
MMBtu to $2.68 per MMBtu and ceiling prices ranging from $2.41 per MMBtu to
$3.08 per MMBtu. The weighted average ceiling and floor prices are $2.74 per
MMBtu and $2.40 per MMBtu, respectively. The Company entered into a gas swap
which hedges 600 MMcf in the fourth quarter of 1998 at an average fixed-price
of $2.46 per Mcf. The oil collar contains a floor price of $16.55 per Bbl and
a ceiling price of $18.10 per Bbl. The Company also entered into an oil swap
which hedges 230 MBbls in the fourth quarter of 1998 at an average fixed-price
of $16.52 per Bbl. For an expanded discussion of the Company's Fixed-Price
Contracts, see the Notes to Consolidated Financial Statements included in the
Company's Annual Report on Form 10-K for the year ended December 31, 1997.
During the second quarter, the Company received $40.1 million in connection
with the early termination of a gas contract. See Note 7 of the Condensed
Notes to Consolidated Financial Statements appearing elsewhere herein for a
further discussion. Also see Note 4 of the Condensed Notes to Consolidated
Financial Statements for a discussion of the new financial accounting
standard, which upon adoption, will change the accounting for the Company's
hedging activities.
OUTLOOK FOR FISCAL 1998
Reference is made to "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Outlook for Fiscal Year 1998" included
in the Company's Annual Report on Form 10-K for the year ended December 31,
1997 for an expanded discussion of 1998 estimates. Subject to the
uncertainties identified in "Forward-Looking Statements" and other information
provided elsewhere in this document and in the Company's Form 10-Q for the
quarter ended June 30, 1998, 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 dated after December 31, 1999, both in its
25
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
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 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 remediation phase is
estimated to be 90% complete and is expected to be fully completed in December
1998. The testing phase is presently estimated to be 60% complete, and is
expected to be fully completed in February 1999. The implementation phase is
estimated to be 50% complete with upgraded IT systems fully operational in
March 1999.
Non-IT Systems. The Company has completed the assessment phase of all
significant non-IT systems, which included operating equipment with embedded
chips or software. The Company believes that the remediation, testing and
implementation phases are also complete. The existence of embedded technology
is by nature more difficult to identify. While the Company believes that all
significant non-IT systems are Year 2000 compliant, the task force will
continue to search for previously unidentified exposures.
Third Parties. The Company estimates that it is 90% complete with the
assessment phase of its exposure to Year 2000 compliance by material third
parties. The assessment phase is expected to be completed in December 1998.
The responses received to date from third parties have not identified a
material non-compliance issue that would require remediation by the Company.
However, the Company does not have the ability to substantiate actual Year
2000 compliance by third parties and there can be no assurance that all
26
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
material third parties will be compliant on a timely basis. 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 costs attributable to
remaining compliance issues in the aggregate is expected to be less than
$250,000 including hardware, software, internal and external labor costs.
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 yet completed all necessary phases of its Year 2000
plan. In the unlikely event that the Company did not complete any additional
phases, the Company would be unable to accurately account for its business
activities, process vendor payments, distribute revenues or bill third
parties. In addition, the Company would be forced to change its engineering
software supplier or rely upon third party consultants for its engineering
needs.
No assurance can be given that all material Year 2000 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. Finally, major disruptions in the economy resulting
from the Year 2000 issues could also materially adversely effect the Company.
The Company currently does not have a contingency plan in place in the event
of Year 2000 non-compliance. The Company plans to evaluate the status of its
Year 2000 plan in March 1999 and will determine at that date whether such a
plan is necessary.
27
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
28
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, 1998 /s/ Jeffrey A. Bonney
-----------------------------------
Jeffrey A. Bonney
Executive Vice President and Chief Financial
Officer