<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, 1997
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 .
----- -----
39,146,504 shares of common stock, $.01 par value, issued and outstanding at
October 28, 1997.
<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:
December 31, 1996 and September 30, 1997 . . . . . . . . . . . . . . 3
Consolidated Statements of Income:
Three months and nine months ended September 30, 1996 and 1997 . . . 5
Consolidated Statements of Cash Flows:
Nine months ended September 30, 1996 and 1997. . . . . . . . . . . . 6
Condensed Notes to Consolidated Financial Statements . . . . . . . . . 7
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS. . . . . . . . . . . . . . . . . . . . . . 12
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. . 32
PART II. OTHER INFORMATION . . . . . . . . . . . . . . . . . . . . 33
<PAGE>
<PAGE> 3
LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED BALANCE SHEETS
(dollars in thousands)
<TABLE>
<CAPTION>
A S S E T S
December 31, September 30,
1996 1997
------------- -------------
(unaudited)
<S> <C> <C>
CURRENT ASSETS
Cash and cash equivalents. . . . . . . . . . $ 7,749 $ 10,551
Receivables:
Oil and gas sales . . . . . . . . . . . . . 33,579 29,737
Joint interest and other. . . . . . . . . . 5,358 7,485
Deposits . . . . . . . . . . . . . . . . . . 5,592 2,986
Inventory and other. . . . . . . . . . . . . 3,147 4,855
------------- -------------
Total current assets . . . . . . . . . . . . 55,425 55,614
------------- -------------
PROPERTY AND EQUIPMENT, at cost, based on
successful efforts accounting . . . . . . . 907,027 987,345
Less accumulated depreciation, depletion
and amortization. . . . . . . . . . . . . . (235,162) (276,174)
------------- -------------
671,865 711,171
------------- -------------
OTHER ASSETS, net. . . . . . . . . . . . . . 6,323 4,985
------------- -------------
$ 733,613 $ 771,770
============= =============
</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
December 31, September 30,
1996 1997
------------- -------------
(unaudited)
<S> <C> <C>
CURRENT LIABILITIES
Accounts payable . . . . . . . . . . . . . . $ 36,415 $ 30,593
Accrued liabilities. . . . . . . . . . . . . 7,251 11,069
Revenues payable . . . . . . . . . . . . . . 7,419 6,981
------------- -------------
Total current liabilities . . . . . . . . . 51,085 48,643
------------- -------------
LONG-TERM DEBT . . . . . . . . . . . . . . . 343,907 356,017
------------- -------------
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred revenue . . . . . . . . . . . . . . 19,049 17,821
Deferred gains from price-risk
management activities . . . . . . . . . . . 26,226 23,684
Deferred income taxes. . . . . . . . . . . . 22,692 33,944
Other. . . . . . . . . . . . . . . . . . . . 6,961 4,847
------------- -------------
74,928 80,296
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,
27,800,750 and 27,830,000 shares,
respectively. . . . . . . . . . . . . . . . 278 278
Additional paid-in capital . . . . . . . . . 197,301 197,780
Retained earnings. . . . . . . . . . . . . . 66,114 88,756
------------- -------------
263,693 286,814
------------- -------------
$ 733,613 $ 771,770
============= =============
See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE> 5
LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED STATEMENTS OF INCOME (unaudited)
(in thousands, except per share data)
<TABLE>
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ ------------------
1996 1997 1996 1997
-------- -------- -------- --------
<S> <C> <C> <C> <C>
REVENUES
Oil and gas sales. . . . . . . . . . . $ 48,074 $ 46,091 $131,713 $142,193
Gain (loss) on sales of property
and equipment . . . . . . . . . . . . 29 66 (37) 8,683
Other income . . . . . . . . . . . . . 885 636 2,978 1,919
-------- -------- -------- --------
48,988 46,793 134,654 152,795
-------- -------- -------- --------
EXPENSES
Operating costs. . . . . . . . . . . . 11,161 10,624 32,705 32,489
General and administrative . . . . . . 3,975 4,008 12,346 11,899
Exploration costs. . . . . . . . . . . 549 1,886 791 5,300
Depreciation, depletion and
amortization. . . . . . . . . . . . . 17,042 16,990 48,766 49,241
Interest . . . . . . . . . . . . . . . 6,545 6,512 20,202 19,031
-------- -------- -------- --------
39,272 40,020 114,810 117,960
-------- -------- -------- --------
Income before income taxes . . . . . . 9,716 6,773 19,844 34,835
Income taxes . . . . . . . . . . . . . 3,206 2,371 6,548 12,193
-------- -------- -------- --------
NET INCOME . . . . . . . . . . . . . . $ 6,510 $ 4,402 $ 13,296 $ 22,642
======== ======== ======== ========
Net income per share . . . . . . . . . $ .23 $ .16 $ .48 $ .81
======== ======== ======== ========
Weighted average common shares
outstanding . . . . . . . . . . . . . 27,800 27,812 27,800 27,805
======== ======== ======== ========
See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE> 6
LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
(in thousands)
<TABLE>
<CAPTION>
Nine Months Ended
September 30,
------------------
1996 1997
-------- --------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 13,296 $ 22,642
Items not affecting cash flows:
Depreciation, depletion and amortization . . . . . . . . . . . . . . . . 48,766 49,241
Deferred income taxes. . . . . . . . . . . . . . . . . . . . . . . . . . 5,134 11,252
Exploration costs. . . . . . . . . . . . . . . . . . . . . . . . . . . . 791 5,300
(Gain) loss on sales of property and equipment . . . . . . . . . . . . . 37 (8,683)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 339 536
Net change in operating assets and liabilities:
Accounts receivable. . . . . . . . . . . . . . . . . . . . . . . . . . . 2,560 1,715
Deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 395 2,606
Inventory and other. . . . . . . . . . . . . . . . . . . . . . . . . . . 1,359 (1,708)
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,583) (5,822)
Accrued liabilities. . . . . . . . . . . . . . . . . . . . . . . . . . . (136) 3,818
Revenues payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,449 (438)
Deferred revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . (4,310) --
-------- --------
69,097 80,459
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Oil and gas property expenditures . . . . . . . . . . . . . . . . . . . . (99,963) (109,417)
Additions to other property and equipment . . . . . . . . . . . . . . . . (1,976) (1,899)
Proceeds from sale of property and equipment. . . . . . . . . . . . . . . 326 27,448
Expenditures for other assets . . . . . . . . . . . . . . . . . . . . . . (78) --
-------- --------
(101,691) (83,868)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term bank borrowings . . . . . . . . . . . . . . . . . 196,140 225,601
Repayments of long-term bank borrowings . . . . . . . . . . . . . . . . . (183,140) (213,601)
Proceeds from stock options exercised . . . . . . . . . . . . . . . . . . -- 479
Change in deferred revenue. . . . . . . . . . . . . . . . . . . . . . . . (1,686) (1,228)
Change in deferred gains from price-risk management activities. . . . . . 27,376 (2,542)
Change in other long-term liabilities . . . . . . . . . . . . . . . . . . (334) (2,498)
-------- --------
38,356 6,211
-------- --------
Change in cash and cash equivalents . . . . . . . . . . . . . . . . . . . 5,762 2,802
Cash and cash equivalents, beginning of period. . . . . . . . . . . . . . 1,584 7,749
-------- --------
Cash and cash equivalents, end of period. . . . . . . . . . . . . . . . . $ 7,346 $ 10,551
======== ========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Interest paid, net of capitalized interest. . . . . . . . . . . . . . . . $ 17,361 $ 15,161
Income taxes paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,179 667
-------- --------
$ 18,540 $ 15,828
======== ========
</TABLE>
See accompanying notes to consolidated financial statements.
<PAGE> 7
LOUIS DREYFUS NATURAL GAS CORP.
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
September 30, 1997
NOTE 1 -- ACCOUNTING PRINCIPLES AND BASIS OF PRESENTATION
The accompanying unaudited consolidated financial statements of Louis
Dreyfus Natural Gas Corp. (the "Company" or "LDNG") 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, 1997 are not necessarily indicative of the results
to be expected for the full year. Certain reclassifications have been made to
the prior year statements to conform with the current year presentation.
Reference is made to the Company's Annual Report on Form 10-K, as amended, for
the year ended December 31, 1996 for an expanded discussion of the Company's
financial disclosures and accounting policies.
NOTE 2 -- EARNINGS PER SHARE
In February 1997, the Financial Accounting Standards Board issued Statement
No. 128, "Earnings per Share"("SFAS 128"), which is required to be adopted by
the Company on December 31, 1997. At that time, the Company will be required
to change the method currently used to compute earnings per share and to
restate all prior periods. Under the new requirements, both basic earnings
per share and diluted earnings per share will be presented. Basic and diluted
earnings per share as determined under SFAS 128 for the three-month and
nine-month periods ended September 30, 1996 and 1997, approximated the
respective net income per share amounts shown on the accompanying Consolidated
Statements of Income.
NOTE 3 -- MERGER WITH AMERICAN EXPLORATION COMPANY
On October 14, 1997, the Company completed the acquisition (the "American
Acquisition") of American Exploration Company ("American"), a 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 acquisition
consideration paid to the shareholders of American consisted of 11.3 million
shares of LDNG common stock and $47.2 million of cash. In addition, holders
of American's $20 million convertible preferred stock received LDNG preferred
shares. Shares of preferred stock are convertible at the option of the
holders, unless earlier redeemed by the Company, into a total of 960,000
shares of LDNG common stock plus $4 million cash.
As of December 31, 1996, American had proved reserves of 254 Bcfe with a
present value discounted at 10% of $370.8 million. American operated
approximately 58% of its reserves, of which 66% was natural gas and 80% was
proved developed. American also held approximately 370,000 net undeveloped
acres. The acquisition will be accounted for as a purchase; accordingly, the
<PAGE> 8
LOUIS DREYFUS NATURAL GAS CORP.
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued)
September 30, 1997
results of operations relating to this acquisition will be included in the
Company's financial results for the periods subsequent to October 14, 1997.
Presented below is certain unaudited pro forma information for the
nine-month periods ended September 30, 1996 and 1997, giving effect to the
American Acquisition as if the transaction had been consummated as of January
1, 1996. Such unaudited pro forma information has been prepared pursuant to
regulations prescribed by the Securities and Exchanged Commission and does not
purport to be indicative of the results of operations which actually would
have been obtained if the transaction had occurred as presented or which may
be obtained in the future. It does not consider the effects of the cost
reduction and financing plans of management expected to be implemented after
closing, nor does it include the effects of certain purchase accounting
adjustments expected to be recorded at closing. The financial impact of such
plans and purchase accounting adjustments is expected to be material. Also,
the pro forma information does not include the impairment charge expected to
be recorded in the fourth quarter of 1997. See footnote (1) to the pro forma
information that follows. Future results may also vary significantly from the
results reflected in the unaudited pro forma information due to oil and gas
production increases or declines, new Fixed-Price Contracts, changes in
product prices, future acquisitions and divestitures, future development and
exploration activities, and other factors.
Nine Months Ended
September 30,
---------------------
1996 1997
-------- --------
(in thousands, except
per share data)
Unaudited pro forma information (1):
Revenues . . . . . . . . . . . . . . . . . . . . . . $187,766 $219,676
Net income . . . . . . . . . . . . . . . . . . . . . $ 931 $ 11,619
Net income (loss) per common share . . . . . . . . . $ (.01) $ .26
Weighted average common shares outstanding . . . . . 39,107 39,112
(1) - The pro forma information shown above does not consider the effects of
the cost reduction and financing plans of management expected to be
implemented after closing, nor does it include the effects of certain
purchase accounting adjustments expected to be recorded at closing.
The estimated combined financial impact of such plans and purchase
accounting adjustments if included in the pro forma income statements
would be an increase in pro forma net income of $7.7 million and $7.5
million for the nine months ended September 30, 1996 and 1997,
respectively.
In addition, the pro forma information shown above does not include an
impairment charge expected to be recorded in the fourth
<PAGE> 9
LOUIS DREYFUS NATURAL GAS CORP.
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued)
September 30, 1997
quarter of 1997 in connection with the acquisition. Based on
preliminary estimates of the total purchase price to be allocated to
the oil and gas properties of American (the "American Properties") as
of June 30, 1997, the Company reported an estimated pro forma
impairment charge of $73 million ($45 million, after tax). The
determination of the actual purchase price amount to be allocated to
the American Properties and the resultant calculation of the
impairment charge are in preliminary stages. The Company
presently is not aware of any information that would lead it to
believe that a substantially different impairment amount will
ultimately be recorded; however, the actual amount may differ
materially from the preliminary estimate.
NOTE 4 -- CONTINGENCIES
LITIGATION. On December 22, 1995, the United States District Court for the
Western District of Oklahoma entered a $10.8 million judgment in favor of the
Company against Midcon Offshore, Inc. ("Midcon") in connection with
non-performance by Midcon under an agreement to purchase a certain offshore
oil and gas property. The judgment amount was in addition to a $1.3 million
deposit previously paid by Midcon to the Company. 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. During
1996, the Company received principal and interest payments on the promissory
note totaling $1.7 million. 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 24, 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. The Company considers the allegations of Midcon to be without merit and
will vigorously defend against this action. Collection of the remaining
unpaid interest and principal on the Midcon note is uncertain and no amounts
have been recorded with respect thereto in the accompanying financial
statements as of September 30, 1997. The Company will recognize income as any
payments are received.
FIXED-PRICE CONTRACTS. Two fixed-price contracts which hedge an aggregate
98.5 Bcf of natural gas as of September 30, 1997 are with independent power
producers ("IPPs") which sell electric power under firm fixed-price contracts
to Niagara Mohawk Corporation ("NIMO"), a New York state utility. As of
September 30, 1997, the present value at a discount rate of 10% of the
differential between the fixed prices provided by these contracts and forward
market prices, as adjusted for estimated basis, was approximately $123
million. This premium in the fixed prices is not reflected in the Company's
financial statements until realized. For the years ended December 31, 1994,
1995 and 1996, these contracts contributed $5.1 million, $9.6 million and $.9
million, respectively, to natural gas sales. The ability of these IPPs to
<PAGE> 10
LOUIS DREYFUS NATURAL GAS CORP.
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued)
September 30, 1997
perform their obligations to the Company is largely dependent on the continued
performance by NIMO of its power purchase obligations to the IPPs. In recent
years, NIMO has taken aggressive regulatory, judicial and contractual actions
seeking to curtail power purchase obligations, including its obligations to
the IPPs that are counterparties to the Company's fixed-price contracts.
These actions have not been successful. Further, NIMO has stated that its
future financial prospects are dependent on its ability to resolve these
obligations, along with other matters.
On July 9, 1997, NIMO entered into a Master Restructuring Agreement (the
"MRA") with 16 IPPs, including the Company's counterparties. Pursuant to the
MRA, the power purchase agreements between NIMO and the IPPs would be
terminated, restated or amended, in exchange for an aggregate of $3.6 billion
in cash, $50 million in notes or cash, 46 million shares of NIMO common stock
and certain fixed-price swap contracts. The allocation of the consideration
among the IPPs has not been disclosed. The closing of the MRA is conditioned
upon, among other things, NIMO and the IPPs negotiating their individual
restated and amended contracts, the receipt of all regulatory approvals, the
receipt of all consents by third parties necessary for the transactions
contemplated by the MRA (including the termination of the existing power
purchase contracts and the termination or amendment of all related third party
agreements), the IPPs entering into new third party arrangements which will
enable each IPP to restructure its projects on a reasonably satisfactory
economic basis, NIMO having completed all necessary financing arrangements and
NIMO and the IPPs having received all necessary approvals from their
respective boards of directors, shareholders and partners.
Preliminary discussions between the Company and the IPP counterparties have
commenced. If the Company consents to the MRA, it will receive a portion of
the NIMO settlement proceeds in exchange for the cancellation of the affected
fixed-price contracts. Such proceeds would be used to repay indebtedness
outstanding under the bank credit facility and would be reflected in the
Company's balance sheet as deferred hedging gains to be amortized into oil and
gas revenues over the original life of the underlying contracts. However, the
amount of such proceeds to be received by the Company, if any, cannot be
estimated at this time. Cancellation of the contracts would subject a greater
portion of the Company's oil and gas production to market prices, which in a
low oil and gas price environment could adversely affect the carrying value of
the Company's oil and gas properties and could otherwise have an adverse
effect on the Company.
NOTE 5 -- NEW BANK CREDIT FACILITY
On October 14, 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"). The Credit
Facility allows LDNG to draw on the full $550 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
<PAGE> 11
LOUIS DREYFUS NATURAL GAS CORP.
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued)
September 30, 1997
from either Standard & Poor's Ratings Service or Moody's Investors Service. A
borrowing base can be required only upon the loss of an investment grade
credit rating and the election by a majority in interest of the lenders. No
principal payments are required under the Credit Facility prior to termination
on October 14, 2002.
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 October
14, 1997, the applicable interest rate was LIBOR plus 30 basis points and the
facility fee was 15 basis points. This pricing is an improvement of 5 basis
points compared to the prior facility.
The Credit Facility agreement contains certain affirmative and restrictive
covenants which generally provide greater flexibility than those contained in
the prior facility. These covenants, among other things, limit total
outstanding 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. In connection with the termination of the $300
million borrowing-base credit facility, the Company will recognize a charge in
the fourth quarter of 1997 of approximately $1.7 million representing the
unamortized loan origination fees associated with the facility.
The Company previously had entered into interest rate swaps to hedge the
interest rate exposure associated with borrowings under the $300 million
borrowing-base credit facility. As of September 30, 1997, the Company had
fixed the interest rate on average notional amounts of $143 million for the
balance of 1997, and $99 million and $33 million for the years ending December
31, 1998 and 1999, respectively. Under the interest rate swaps, the Company
receives the LIBOR three-month rate (5.8% at September 30, 1997) and pays an
average rate of 6.1% for the balance of 1997, 6.3% for 1998 and 6.5% for 1999.
In October 30, 1997, the Company entered into three additional interest rate
swaps which hedge an aggregate notional amount of $150 million for a period of
five years. The effective average fixed rate of the new interest rate swaps
is 6.5%.<PAGE>
<PAGE> 12
LOUIS DREYFUS NATURAL GAS CORP.
ITEM 2. 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, earnings and operating cash flows
through a balanced program of exploration and development drilling and
strategic acquisitions of oil and gas properties. Since its acquisition by
S.A. Louis Dreyfus et Cie in 1990, the Company's oil and gas reserves and
production have grown significantly as the result of a number of proved
reserve acquisitions and its active drilling program.
Over the three-year period ended December 31, 1996, the Company acquired 322
Bcfe of proved reserves through various acquisitions for a total consideration
of $191.4 million, or $.59 per Mcfe. Such acquisitions have been
geographically concentrated in regions where the Company has significant
expertise and where the Company benefits from operational synergies. In 1997,
the Company continued this acquisition strategy. Of particular significance,
was the acquisition of American Exploration Company ("American") which was
completed on October 14, 1997 (the "American Acquisition"). See related
discussion under "Commitments and Capital Expenditures."
The Company's drilling program over the three-year period ended December 31,
1996 resulted in the drilling of 745 gross wells (450 net wells), with an
overall drilling success rate of 95%. This program added 251 Bcfe of proved
reserves (including revisions of previous estimates) during this period.
Total finding costs (total costs incurred to acquire, explore and develop oil
and gas properties divided by the increase in proved reserves through
acquisitions of proved properties, extensions and discoveries, and revisions
of previous estimates) over this three-year period averaged $.75 per Mcfe.
Recently, exploratory drilling has become an integral component of the
Company's operating strategy. During 1996, the Company invested $15 million in
connection with exploration prospects, including drilling, seismic data
collection and leasehold acquisition activities. The Company has allocated
$31 million, or 23%, of its current capital budget for exploratory activities
in 1997.
The Company has a portfolio of long-term physical delivery contracts, energy
swaps, collars, futures contracts, basis swaps and option agreements
(collectively "Fixed-Price Contracts") designed to reduce the risk associated
with fluctuations in natural gas and oil prices. For the years ended December
31, 1994, 1995 and 1996, Fixed-Price Contracts hedged 98%, 84% and 51% of the
Company's natural gas production not otherwise subject to fixed prices and
91%, 86% and 67% of its oil production, respectively. Over the past few
years, competition in Fixed-Price Contracts has increased, the opportunities
for attractive Fixed-Price Contracts have diminished and spot prices for
natural gas are presently higher than nearby forward market prices. In
response to these changes, a smaller share of the Company's production and
reserve growth has been hedged under long-term Fixed-Price Contracts due to
Management's reluctance to sell into a forward market where prices trend down
<PAGE> 13
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
or are essentially flat over the next several years. Management believes that
the current relationship between cash flow protection and exposure to oil and
gas prices is an appropriate balance for the Company. However, the Company
may decide to hedge a greater or smaller share of production in the future,
depending upon market conditions, capital investment considerations and other
factors. See "Fixed-Price Contracts."
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. 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. The Company cautions that the Forward-Looking Statements are
subject to all the risks and uncertainties incident to the acquisition,
development and marketing of, and exploration for, oil and gas reserves.
These risks include, but are not limited to, commodity price risks,
counterparty risks, environmental risks, drilling risks, reserve, operations
and production risks, and risks attributable to the American Acquisition.
Many of these risks are described elsewhere herein. Moreover, the Company may
make material acquisitions, modify its Fixed-Price Contract position by
entering into new contracts or terminating existing contracts, or enter 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
expressly disclaims any obligation or undertaking to release publicly any
updates regarding any change 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:
CERTAIN DEFINITIONS
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.
<PAGE> 14
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
CERTAIN DEFINITIONS (continued)
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.
Selected Operating Data. The following table provides certain operating data
relating to the Company's operations.
<TABLE>
<CAPTION>
SELECTED OPERATING DATA
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ ------------------
1996 1997 1996 1997
-------- -------- -------- --------
<S> <C> <C> <C> <C>
OIL AND GAS SALES: (M$)
Wellhead oil sales . . . . . . . . . . $ 9,888 $ 7,390 $ 27,879 $ 24,915
Effect of Fixed-Price Contracts (1). . (834) -- (1,939) 322
-------- -------- -------- --------
Total oil sales. . . . . . . . . . . . $ 9,054 $ 7,390 $ 25,940 $ 25,237
======== ======== ======== ========
Wellhead natural gas sales . . . . . . $ 36,699 $ 38,007 $101,707 $117,515
Effect of Fixed-Price Contracts (1). . 2,321 694 4,066 (559)
-------- -------- -------- --------
Total natural gas sales. . . . . . . . $ 39,020 $ 38,701 $105,773 $116,956
======== ======== ======== ========
TOTAL PRODUCTION:
Oil production (MBbls) . . . . . . . . 454 403 1,369 1,240
Natural gas production (MMcf). . . . . 16,606 16,774 47,576 48,379
Equivalent production (MMcfe). . . . . 19,332 19,193 55,792 55,819
PRODUCTION HEDGED BY FIXED-PRICE
CONTRACTS:
Oil production (MBbls) . . . . . . . . 304 -- 949 362
Natural gas production (MMcf). . . . . 8,591 11,673 24,185 29,241
Equivalent production (MMcfe). . . . . 10,415 11,673 29,879 31,413
</TABLE>
<PAGE> 15
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
<TABLE>
<CAPTION>
SELECTED OPERATING DATA, continued
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ ------------------
1996 1997 1996 1997
-------- -------- -------- --------
<S> <C> <C> <C> <C>
AVERAGE SALES PRICE:
Oil (per Bbl):
Wellhead price . . . . . . . . . . . $ 21.77 $ 18.32 $ 20.36 $ 20.09
Effect of Fixed-Price Contracts (1). (1.84) -- (1.42) .26
-------- -------- -------- --------
Total. . . . . . . . . . . . . . . . $ 19.93 $ 18.32 $ 18.94 $ 20.35
======== ======== ======== ========
Average fixed price received under
Fixed-Price Contracts. . . . . . . $ 19.53 n/a $ 19.33 $ 22.32
Net effective realization (2). . . . 97% n/a 96% 98%
Natural gas (per Mcf):
Wellhead price . . . . . . . . . . . $ 2.21 $ 2.27 $ 2.14 $ 2.43
Effect of Fixed-Price Contracts (1). .14 .04 .08 (0.01)
-------- -------- -------- --------
Total. . . . . . . . . . . . . . . . $ 2.35 $ 2.31 $ 2.22 $ 2.42
======== ========= ======== ========
Average fixed price received under
Fixed-Price Contracts. . . . . . . $ 2.43 $ 2.41 $ 2.37 $ 2.45
Net effective cash realization (2) . 102% 97% 97% 99%
Equivalent price (per Mcfe). . . . . . $ 2.49 $ 2.40 $ 2.36 $ 2.55
EXPENSES: (per Mcfe)
Operating costs:
Lease operating. . . . . . . . . . . $ .45 $ .43 $ .47 $ .45
Production taxes . . . . . . . . . . $ .12 $ .12 $ .12 $ .13
General and administrative . . . . . . $ .21 $ .21 $ .22 $ .21
Depreciation, depletion and
amortization - oil & gas. . . . . $ .83 $ .82 $ .82 $ .82
(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 --
Market Risk."
<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, 1997 COMPARED TO
THREE MONTHS ENDED SEPTEMBER 30, 1996
Net Income and Cash Flows from Operating Activities. For the quarter ended
September 30, 1997, the Company realized net income of $4.4 million, or $.16
per share, on total revenue of $46.8 million. This compares with net income
of $6.5 million, or $.23 per share, on total revenue of $49.0 million for the
third quarter of 1996. Cash flows from operating activities (before working
capital changes) for the third quarter of 1997 decreased to $25.8 million from
the $26.7 million reported for the third quarter of 1996. The decline in
third quarter 1997 earnings and operating cash flows was principally the
result of lower oil and gas prices. Earnings were also reduced in the 1997
third quarter by an increase in exploration costs. Cash flows provided by
operating activities after consideration for the net change in working capital
decreased to $26.5 million compared to $33.0 million for the third quarter of
1996. This decrease is due to lower oil and gas prices and to an increase in
receivables for the third quarter of 1997.
Production. The Company produced 19.2 Bcfe for the third quarter of 1997
compared to 19.3 Bcfe for the prior year third quarter, a decrease of 1%.
Natural gas production increased to 16.8 Bcf, up 1% from the 16.6 Bcf produced
in the third quarter of 1996. Oil production for the third quarter of 1997
decreased 11% to 403 MBbls compared to 454 MBbls for the third quarter of
1996. The decrease in oil production was primarily the result of the sale of
a non-core waterflood property in January 1997.
Oil and Gas Prices. On a natural gas equivalent basis, the Company received
an average price of $2.40 per Mcfe for the quarter ended September 30, 1997, a
4% decrease from the $2.49 per Mcfe received for the third quarter of 1996.
The Company's gas production yielded an average price of $2.31 per Mcf
compared to $2.35 per Mcf for the prior year third quarter. The average gas
price for the third quarter of 1997 was enhanced $.04 per Mcf as a result of
the Company's hedging activities. The average gas price for the third quarter
of 1996 increased $.14 per Mcf as a result of Fixed-Price Contracts in effect
for that period. The average oil price received for the third quarter of 1997
was $18.32 per Bbl, a decrease of 8% compared to $19.93 per Bbl for the
prior-year third quarter. The Company's third quarter 1997 oil production was
not hedged. Fixed-Price Contracts hedging the Company's crude oil production
during the third quarter of 1996 decreased the average price by $1.84 per Bbl.
The net effect of higher gas production and lower average price decreased
gas sales to $38.7 million for the third quarter of 1997 compared to $39.0
million for the third quarter of 1996. The combined effect of lower oil
production and lower prices was to decrease oil sales by 18% to $7.4 million
from the $9.1 million reported for the third quarter of 1996. See additional
discussion under "Fixed-Price Contracts."
Other Income. Other income for the third quarter of 1997 was $.6 million
compared to $.9 million for the third quarter of 1996. The 1996 third quarter
<PAGE> 17
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
amount is higher primarily due to the receipt of a $.5 million installment
payment from Midcon Offshore, Inc. in connection with a $10.8 million judgment
in the Company's favor. See Note 4 of the Condensed Notes to Consolidated
Financial Statements, "Contingencies -- Litigation," appearing elsewhere in
this document.
Operating Costs. Operating costs, which include direct lease operating
expenses and production taxes, decreased to $10.6 million for the third
quarter of 1997 compared to $11.2 million for third quarter of 1996. This
improvement is due, in part, to the sale of a non-core waterflood property in
January 1997. On an equivalent unit of production basis, total operating
costs decreased to $.55 per Mcfe for the third quarter of 1997 compared to
$.58 per Mcfe for the prior-year third quarter.
General and Administrative Expense. General and administrative expense
("G&A") for the third quarter of 1997 remained constant at $4.0 million
compared to the prior-year third quarter. On an equivalent unit of production
basis, G&A remained constant at $.21 per Mcfe for the 1997 third quarter in
relation to the prior-year third quarter.
Exploration Costs. Exploration costs, comprised of geological and
geophysical costs, exploratory dry holes and leasehold impairment costs were
$1.9 million for the quarter ended September 30, 1997 compared to $.5 million
for the third quarter of 1996. This increase is primarily due to an increase
in dry hole costs expensed during the third quarter of 1997 in connection with
the Company's exploratory drilling program.
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization ("DD&A") for the third quarter of 1997 remained constant at $17.0
million compared to the prior-year third quarter. The oil and gas DD&A rate
per equivalent unit of production (including leasehold impairment) decreased
to $.82 per Mcfe for the third quarter of 1997 compared to $.83 per Mcfe for
the third quarter of 1996.
Interest Expense. Interest expense for the third quarter of 1997 remained
constant at $6.5 million compared to the third quarter of 1996. The net
impact of interest rate swaps in effect for the third quarter of 1997 was not
material. The net impact of interest rate swaps in effect during the third
quarter of 1996 was to increase interest expense by $.2 million. See "Capital
Resources and Liquidity -- Credit Facility."
Income Taxes. For the third quarter of 1997, the Company recorded an income
tax provision of $2.4 million on pretax income of $6.8 million, an effective
rate of 35%. This compares to an income tax provision of $3.2 million on
pretax income of $9.7 million, an effective rate of 33%, for the third quarter
of 1996. The effective rate for both quarters was lower than the statutory
rate primarily due to the availability of Section 29 credits.
<PAGE>
<PAGE> 18
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
RESULTS OF OPERATIONS -- NINE MONTHS ENDED SEPTEMBER 30, 1997 COMPARED TO NINE
MONTHS ENDED SEPTEMBER 30, 1996
Net Income and Cash Flows from Operating Activities. The Company realized
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. This compares with net
income of $13.3 million, or $.48 per share, on total revenue of $134.7 million
for the first nine months of 1996. Cash flows from operating activities
(before working capital changes) for the first nine months of 1997 increased
17% to $80.3 million from the $68.4 million reported for the first nine months
of 1996. The increase in earnings and cash flows for the first nine months of
1997 was primarily the result of higher oil and gas prices. In addition, net
income for the 1997 nine-month period included a $5.5 million after-tax gain
on the sale of a non-core waterflood property in January 1997. Cash flows
provided by operating activities after consideration for the net change in
working capital increased to $80.5 million compared to $69.1 million for the
nine-months ended September 30, 1996. This increase is attributable to higher
oil and gas prices in the 1997 nine-month period and a reduction in deferred
revenue during the first nine months of 1996.
Production. The Company produced 55.8 Bcfe for the first nine months of
1997 and 1996. Natural gas production for the nine months ended September 30,
1997 was 48.4 Bcf, a 2% increase over the 47.6 Bcf produced in the first nine
months of 1996. Oil production for the first nine months of 1997 decreased 9%
to 1.2 MMBbls compared to 1.4 MMBbls for the first nine months of 1996. The
decrease in oil production was primarily the result of the sale of a non-core
waterflood property in January 1997.
Oil and Gas Prices. On a natural gas equivalent basis, the Company received
an average price of $2.55 per Mcfe for the first nine months of 1997, an
increase of 8% compared to $2.36 per Mcfe for the first nine months of 1996.
The average gas price for the first nine months of 1997 was $2.42 per Mcf, an
increase of 9% compared to $2.22 per Mcf for the nine months ended September
30, 1996. The Company's average gas price for the first nine months of 1997
decreased $.01 per Mcf as a result of the Company's hedging activities. The
average gas price for the first nine months of 1996 was enhanced $.08 per Mcf
as a result of Fixed-Price Contracts in effect for that period. The average
oil price for the first nine months of 1997 was $20.35 per Bbl compared to
$18.94 per Bbl for the first nine months of 1996, an increase of 7%. The
average oil price for the current year nine-month period increased $.26 per
Bbl as a result of Fixed-Price Contracts in effect for the period. The effect
of Fixed-Price Contracts hedging the Company's crude oil production during the
first nine months of 1996 was to decrease the average price by $1.42 per Bbl.
The combination of higher gas production and higher average price increased
natural gas sales to $117.0 million for the first nine months of 1997, an
increase of 11% from the $105.8 million reported for the first nine months of
1996. The net effect of lower oil production and higher average price was to
decrease oil sales by 3% to $25.2 million compared to $25.9 million for the
<PAGE> 19
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
prior-year nine-month period.
Gain (Loss) on Sales of Property and Equipment. During the first nine
months of 1997, the Company recognized a net gain on sales of property and
equipment of $8.7 million. The comparable amount for the first nine months of
1996 was not material. Substantially all of the 1997 balance is attributable
to the gain realized upon the sale of a non-core waterflood property in
January 1997.
Other Income. Other income for the first nine months of 1997 was $1.9
million compared to $3.0 million for the first nine months of 1996. The 1996
third quarter amount is higher primarily due to the receipt of $1.7 million
from Midcon Offshore, Inc. in connection with a $10.8 million judgment in the
Company's favor. See Note 4 of the Condensed Notes to Consolidated Financial
Statements, "Contingencies -- Litigation," appearing elsewhere in this
document.
Operating Costs. Operating costs, which include direct lease operating
expenses and production taxes, decreased to $32.5 million for the first nine
months of 1997 compared to $32.7 million for the first nine months of 1996.
This improvement is due, in part, to the sale of a non-core waterflood
property in January 1997. On an equivalent unit of production basis, total
operating costs remained relatively constant at $.58 per Mcfe for the first
nine months of 1997 compared to $.59 per Mcfe for the comparable prior-year
period.
General and Administrative Expense. G&A for the first nine months of 1997
was $11.9 million compared to $12.3 million for the comparable prior-year
period. On an equivalent unit of production basis, G&A decreased to $.21 per
Mcfe for the first nine months of 1997 compared to $.22 per Mcfe for the first
nine months of 1996. This improvement is primarily attributable to an
increase in overhead recoveries from third parties.
Exploration Costs. Exploration costs, comprised of geological and
geophysical costs, exploratory dry holes and leasehold impairment costs were
$5.3 million for the nine months ended September 30, 1997 compared to $.8
million for the nine months ended September 30, 1996. This increase is
consistent with the increase in exploration activity conducted by the Company
for the first nine months of 1997 relative to the comparable period of 1996.
The 1997 amount consists of $2.2 million of seismic acquisition and other
geological and geophysical costs, $2.5 million of dry hole costs and $.6
million of leasehold impairment.
Depreciation, Depletion and Amortization. DD&A for the first nine months of
1997 was $49.2 million compared to $48.8 million for the first nine months of
1996. This increase in DD&A is attributable to an increase in amortization
and depreciation of non-oil and gas assets. The oil and gas DD&A rate per
equivalent unit of production remained constant at $.82 per Mcfe for the first
nine months of 1997 compared to the first nine months of 1996.
<PAGE> 20
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
Interest Expense. For the nine months ended September 30, 1997, interest
expense was $19.0 million compared to $20.2 million for the first nine months
of 1996. This decrease is primarily attributable to lower effective interest
rates for the first nine months of 1997. The net impact of interest rate
swaps in effect during the first nine months of 1997 was to increase interest
expense by $.2 million. Interest rate swaps in effect for the first nine
months of 1996 increased interest expense by $.7 million. See "Capital
Resources and Liquidity -- Credit Facility."
Income Taxes. For the first nine months of 1997, the Company recorded a tax
provision of $12.2 million on pretax income of $34.8 million, an effective
rate of 35%. This compares to a tax provision of $6.5 million provided on
pretax income of $19.8 million for the first nine months of 1996, an effective
rate of 33%. The effective rate for both periods 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, 1997
and 1996, the Company expended $109.4 million and $100.0 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, 1997 and 1996 were $80.3
million and $68.4 million, representing 73% and 68%, 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 $26.4 million in connection with the
January 1997 sale of a non-core waterflood property. Such proceeds were
applied 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 a $38.4 million source of cash for the
first nine months of 1996. Historically, the Company has relied upon
availability under its revolving bank credit facility and proceeds from the
issuance of subordinated notes to fund its investing activities.
The Company's EBITDAX increased to $108.4 million for the first nine months
of 1997 compared to $89.6 million for the first nine months of 1996. EBITDAX
is defined herein as income before interest, income taxes, DD&A, impairments
and exploration costs. Increases in EBITDAX have occurred primarily as a
<PAGE> 21
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
result of increases in the Company's oil and gas sales. LDNG believes that
EBITDAX is a financial measure commonly used in the oil and gas industry as an
indicator of a company's ability to service and incur debt. However, EBITDAX
should not be considered in isolation or as a substitute for net income, cash
flows provided by operating activities or other data prepared in accordance
with generally accepted accounting principles, or as a measure of a company's
profitability or liquidity. EBITDAX measures as presented may not be
comparable to other similarly titled measures of other companies.
Credit Facility. On October 14, 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"). The Credit Facility allows LDNG to draw on the full $550 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 loss of an
investment grade credit rating and the election by a majority in interest of
the lenders. No principal amounts are required under the Credit Facility
prior to termination on October 14, 2002.
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 October
14, 1997, the applicable interest rate was LIBOR plus 30 basis points and the
facility fee was 15 basis points. This pricing is an improvement of 5 basis
points compared to the prior facility.
The Credit Facility agreement contains certain affirmative and restrictive
covenants which generally provide greater flexibility than those contained in
the prior facility. These covenants, among other things, limit total
outstanding 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.
The Company previously had entered into interest rate swaps to hedge the
interest rate exposure associated with borrowings under the $300 million
borrowing-base credit facility. As of September 30, 1997, the Company had
fixed the interest rate on average notional amounts of $143 million for the
balance of 1997, and $99 million and $33 million for the years ending December
31, 1998 and 1999, respectively. Under the interest rate swaps, the Company
receives the LIBOR three-month rate (5.8% at September 30, 1997) and pays an
average rate of 6.1% for the balance of 1997, 6.3% for 1998 and 6.5% for 1999.
The Company has an additional interest rate swap under which the Company pays
the LIBOR three-month rate and receives 7.1% on a notional amount of $25
million. This interest rate swap matures June 2004. In October 1997, the
Company entered into three additional interest rate swaps which hedge an
aggregate notional amount of $150 million for a period of five years. The
<PAGE> 22
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
effective average fixed rate of the new interest rate swaps is 6.5%.
For each interest rate swap, the differential between the fixed rate and the
floating rate multiplied by the notional amount is the swap gain or loss.
Such gain or loss is included in interest expense in the period for which the
interest rate exposure was hedged. If an interest rate swap is liquidated or
sold prior to maturity, the gain or loss is deferred and amortized as interest
expense over the original contract term. At September 30, 1997, the amount of
such deferrals was not material.
As of September 30, 1997, the Company had $245.0 million of principal and
$1.8 million of letters of credit outstanding under its $300 million
borrowing-base credit facility.
Subordinated Notes. In June 1994, the Company completed the sale of $100
million of 9-1/4% Senior Subordinated Notes due 2004 (the "Notes") in a public
offering. The Notes were sold at 98.534% of face value to yield 9.48% to
maturity. 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 Notes, the incurrence of
additional indebtedness, the payment of dividends and the disposition of
assets.
Other. The Company has certain other unsecured lines of credit available to
it which aggregated $60 million as of September 30, 1997. Such short-term
lines of credit are primarily used to meet margining requirements under
Fixed-Price Contracts and for working capital purposes. As of September 30,
1997, the Company had $12.0 million of indebtedness and $17.9 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 1997 and
for 1998, and to meet the Company's margin requirements under its Fixed-Price
Contracts. See "Commitments and Capital Expenditures" and "Fixed-Price
Contracts -- Margining." At September 30, 1997, the Company had working
capital of $7.0 million and a current ratio of 1.1 to 1. Total long-term debt
outstanding at September 30, 1997 was $356.0 million. The Company's long-term
debt as a percentage of its total capitalization was 55%.
COMMITMENTS AND CAPITAL EXPENDITURES
The Company's primary business strategy is to increase production and
reserves through acquisition, development and exploration activities. For the
nine months ended September 30, 1997, the Company expended $109.4 million in
connection with this strategy, including $86.0 million for development
activities, $9.4 million for proved reserve acquisitions and $14.0 million for
exploration activities, the majority of which was leasehold and seismic costs.
<PAGE> 23
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
For the balance of 1997, the Company currently plans to spend approximately
$56 million in connection with its drilling program, focused principally in
its core regions of Sonora, the Mid-Continent, the Gulf Coast, Permian and
Arklatex. Such planned expenditure levels include approximately $17 million
of additional exploration drilling and other exploration costs. 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. As of September 30, 1997, the Company
had drilled 239 wells, 221 of which were successfully completed as producers.
The Company plans to drill approximately 135 additional wells by year-end
1997.
For 1998, the Company's Board of Directors has approved an exploration and
development budget of $200 million. This expenditure level is expected to
result in the drilling of over 500 wells in the Company's core regions.
Approximately 40% of this budget is expected to be directed toward exploration
opportunities, including $27 million for the acquisition of undeveloped
acreage and seismic surveys.
On October 14, 1997, the Company completed the acquisition of American, a
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 acquisition consideration paid to the shareholders of American consisted
of 11.3 million shares of LDNG common stock and $47.2 million of cash. Such
cash consideration was funded through bank credit facility availability. In
addition, holders of American's $20 million convertible preferred stock
received LDNG preferred shares. Shares of preferred stock are convertible at
the option of the holders, unless earlier redeemed, into a total of 960,000
shares of LDNG common stock plus $4 million cash.
As of December 31, 1996, American had proved reserves of 254 Bcfe with a
present value discounted at 10% of $370.8 million. American operated
approximately 58% of its reserves, of which 66% was natural gas and 80% was
proved developed. American also held approximately 370,000 net undeveloped
acres. The acquisition will be accounted for as a purchase; accordingly, the
results of operations relating to this acquisition will be included in the
Company's financial results for the periods subsequent to October 14, 1997.
On October 16, 1997, the Company gave notice of prepayment to the holders of
the 11% Senior Subordinated Notes of American (the "American Notes") assumed
in the American Acquisition. Prepayment of the $35 million principal amount
of the American Notes is subject to a Make Whole Premium as defined in the
underlying indenture agreement. As of November 10, 1997, the estimated Make
Whole Premium was approximately $7.6 million. The American Notes are expected
to be prepaid on November 17, 1997 with availability under the Credit
Facility.
<PAGE> 24
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
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, 1994,
1995 and 1996, Fixed-Price Contracts hedged 98%, 84% and 51% of the Company's
natural gas production not otherwise subject to fixed prices and 91%, 86% and
67% of its oil production, respectively. For the nine months ended September
30, 1997, Fixed-Price Contracts hedged 60% of the Company's natural gas
production and 29% of its oil production. As of September 30, 1997,
Fixed-Price Contracts are in place to hedge 322 Bcf of the Company's estimated
future production from proved gas reserves and 169 MBbls of the Company's
estimated future production from proved oil reserves. See Note 4 of the
Condensed Notes to Consolidated Financial Statements, "Contingencies --
Fixed-Price Contracts," appearing elsewhere in this document.
For energy swap sales contracts, the Company receives a fixed price for the
commodity being hedged and pays a floating market price, as defined in each
contract (generally NYMEX futures prices or a regional spot market index), to
the counterparty. For physical delivery contracts, the Company purchases gas
in the spot market at floating market prices and delivers such gas to the
contract counterparty at a fixed price. Under energy swap purchase contracts,
the Company pays a fixed price for the commodity and receives a floating
market price.
<PAGE> 25
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
The following table summarizes the estimated volumes, fixed prices,
fixed-price sales, fixed-price purchases and future net revenues (as defined
below) attributable to the Company's Fixed-Price Contracts as of September 30,
1997.
</TABLE>
<TABLE>
<CAPTION>
FIXED-PRICE CONTRACTS
Three
Months
Ending Years Ending December 31, Balance
December -------------------------------------- through
31, 1997 1998 1999 2000 2001 2017 Total
-------- -------- -------- -------- -------- -------- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
NATURAL GAS SWAPS
Sales Contracts
Contract volumes (BBtu). . 1,920 13,825 15,825 9,830 7,475 29,838 78,713
Weighted average fixed
price per MMBtu (1). . . . $ 2.23 $ 2.33 $ 2.44 $ 2.46 $ 2.47 $ 3.08 $ 2.67
Future fixed price
sales (M$) . . . . . . . . $ 4,290 $ 32,243 $ 38,629 $ 24,164 $ 18,446 $ 92,019 $ 209,791
Future net
revenues (M$) (2). . . . . $ (1,712)$ (937) $ 2,232 $ 1,850 $ 1,403 $ 21,566 $ 24,402
Purchase Contracts
Contract volumes (BBtu). . (460) (9,125) (10,950) -- -- -- (20,535)
Weighted average
fixed price per MMBtu (1). $ 2.01 $ 2.09 $ 2.18 $ -- $ -- $ -- $ 2.14
Future fixed price
purchases (M$) . . . . . . $ (925)$(19,108) $(23,879) $ -- $ -- $ -- $ (43,912)
Future net
revenues (M$) (2). . . . . $ 513 $ 2,793 $ 1,305 $ -- $ -- $ -- $ 4611
NATURAL GAS PHYSICAL
DELIVERY CONTRACTS
Contract volumes (BBtu). . 8,985 36,060 28,204 26,749 27,300 134,096 261,394
Weighted average fixed
price per MMBtu (1). . . . $ 2.56 $ 2.64 $ 2.84 $ 3.04 $ 3.19 $ 4.11 $ 3.51
Future fixed price
sales (M$) . . . . . . . . $ 23,031 $ 95,130 $ 80,125 $ 81,403 $ 86,963 $551,455 $ 918,107
Future net
revenues (M$) (2). . . . . $ (5,089)$ 8,384 $ 14,874 $ 19,949 $ 24,090 $204,820 $ 267,028
TOTAL NATURAL GAS
CONTRACTS (3) (4)
Contract volumes (BBtu). . 10,445 40,760 33,079 36,579 34,775 163,934 319,572
Weighted average fixed
price per MMBtu (1). . . . $ 2.53 $ 2.66 $ 2.87 $ 2.89 $ 3.03 $ 3.93 $ 3.39
Future fixed price
sales (M$) . . . . . . . . $ 26,396 $108,265 $ 94,874 $105,567 $105,409 $643,475 $1,083,986
Future net
revenues (M$) (2). . . . . $ (6,288)$ 10,240 $ 18,411 $ 21,799 $ 25,493 $226,386 $ 296,041
</TABLE>
<PAGE> 26
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
<TABLE>
<CAPTION>
FIXED-PRICE CONTRACTS (continued)
Three
Months
Ending Years Ending December 31, Balance
December -------------------------------------- through
31, 1997 1998 1999 2000 2001 2017 Total
-------- -------- -------- -------- -------- -------- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
CRUDE OIL SWAPS
Contract volumes (MBbls) . 90 79 -- -- -- -- 169
Weighted average fixed
price per Bbl (1). . . . . $ 22.20 $ 22.20 $ -- $ -- $ -- $ -- $ 22.20
Future fixed price
sales (M$) . . . . . . . . $ 1,998 $ 1,754 $ -- $ -- $ -- $ -- $ 3,752
Future net
revenues (M$) (2). . . . . $ 97 $ 105 $ -- $ -- $ -- $ -- $ 202
<FN>
(1) - The Company expects the prices to be realized for its hedged production will vary from the
prices shown due to location, quality and other factors which create a differential between
wellhead prices and the floating prices under its Fixed-Price Contracts. See "--Market
Risk."
(2) - Future net revenues for any period are determined as the differential between the fixed
prices provided by Fixed-Price Contracts and forward market prices as of September 30,
1997, as adjusted for estimated basis. Future net revenues change as market prices and
basis fluctuate. See "-- Market Risk."
(3) - Does not include basis swaps with notional volumes by year, as follows: 1997 - 5.7 TBtu;
1998 - 24.5 TBtu; 1999 - 19.0 TBtu; 2000 - 21.3 TBtu; 2001 - 9.4 TBtu; and 2002 - 5.5 TBtu.
(4) - Does not include 1.4 TBtu for 1997 and 1.4 TBtu for 1998 of natural gas hedged by a
fixed-price collar with a floor price of $2.34 per MMBtu and a ceiling price of $2.55 per
MMBtu.
</TABLE>
The estimates of the future net revenues from the Company's Fixed-Price
Contracts contained herein are computed based on the difference between the
prices provided by the Fixed-Price Contracts and forward market prices as of
the specified date. Such estimates do not necessarily represent the fair
market value of the Company's Fixed-Price Contracts or the actual future net
revenues that will be received. The forward market prices for natural gas and
oil are highly volatile, are dependent upon supply and demand factors in such
forward market and may not correspond to the actual market prices at the
settlement dates of the Company's Fixed-Price Contracts. Forward market
prices are available in a limited over-the-counter market and are obtained
from sources the Company believes to be reliable.
Accounting. The differential between the fixed price and the floating price
for each contract settlement period multiplied by the associated contract
volumes is the contract profit or loss. The realized contract profit or loss
is included in oil and gas sales in the period for which the underlying
commodity was hedged. All of the Company's Fixed-Price Contracts have been
executed in connection with its natural gas and crude oil hedging program and
not for trading purposes. Consequently, no amounts are reflected in the
Company's balance sheet or income statement related to changes in market value
<PAGE> 27
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
of the contracts. If a Fixed-Price Contract is settled prior to maturity, the
gain or loss is deferred and amortized into oil and gas sales over the
original life of the contract. At September 30, 1997, the Company had $23.7
million of unamortized deferred hedging gains recorded on its balance sheet.
Prepayments received under Fixed-Price Contracts with continuing performance
obligations are recorded as deferred revenue and amortized into oil and gas
sales as obligations under the contracts are fulfilled. At September 30,
1997, the Company had $17.8 million of deferred revenue recorded on its
balance sheet.
Credit Risk. The terms of the Company's Fixed-Price Contracts generally
provide for monthly settlements and energy swap contracts provide for the
netting of payments. The counterparties to the contracts are comprised of
independent power producers, pipeline marketing affiliates, financial
institutions, a municipality and S.A. Louis Dreyfus et Cie, among others. In
some cases, the Company requires letters of credit or corporate guarantees to
secure the performance obligations of the contract counterparty. Should a
counterparty to a contract default on a contract, there can be no assurance
that the Company would be able to enter into a new contract with a third party
on terms comparable to the original contract. The loss of a contract would
subject a greater portion of the Company's oil and gas production to market
prices, which in a low oil and gas price environment could adversely affect
the carrying value of the Company's oil and gas properties and could otherwise
have an adverse effect on the Company. The Company has not experienced
non-performance by any counterparty. See Note 4 of the Condensed Notes to
Consolidated Financial Statements, "Contingencies -- Fixed-Price Contracts,"
appearing elsewhere in this document.
Market Risk. The Company's Fixed-Price Contracts at September 30, 1997
hedge 322 Bcf of proved natural gas reserves and 169 MBbls of oil at fixed
prices. If the Company's proved reserves are produced at rates significantly
less than anticipated, the volumes specified under the Fixed-Price Contracts
could exceed production volumes. In such case, the Company would be required
to satisfy its contractual commitments at market prices in effect for each
settlement period, which may be above the contract price, without a
corresponding offset in wellhead revenue for such volumes. The Company
expects future production volumes to be greater than the volumes provided for
in its contracts.
The differential between the floating price paid under each swap contract,
or the cost of gas to supply physical delivery contracts, and the price
received at the wellhead for the Company's production is termed "basis" and is
the result of differences in location, quality, contract terms, timing and
other variables. The effective price realizations which result from the
Company's Fixed-Price Contracts are affected by movements in basis. For the
years ended December 31, 1994, 1995 and 1996, the Company received on an Mcf
basis approximately 11%, 3% and 3% less than the prices specified in its
natural gas Fixed-Price Contracts, respectively due to basis. For its oil
production hedged by Fixed-Price Contracts, the Company realized approximately
<PAGE> 28
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
8%, 7% and 4% less than the specified contract prices for such years,
respectively. For the nine months ended September 30, 1997, the Company
received prices which were 1% less and 2% less than the prices specified in
its natural gas contracts and crude oil contracts, respectively. Basis
results for the first nine months of 1997 are not necessarily indicative of
the results to be expected for the full year. Basis movements can result from
a number of variables, including regional supply and demand factors, changes
in the Company's portfolio of Fixed-Price Contracts and the composition of the
Company's producing property base. Basis movements are generally considerably
less than the price movements affecting the underlying commodity, but their
effect can be significant. A 1% change in price realization for hedged
natural gas production for the balance of 1997 would represent a $299,000
change in gas sales. A 1% change in price realization for hedged oil
production for the balance of 1997 would represent a $20,000 change in oil
sales. The Company actively manages its exposure to basis movements and from
time to time will enter into contracts designed to reduce such exposure.
Margining. The Company is required to post margin in the form of bank
letters of credit or treasury bills under certain of its Fixed-Price
Contracts. In some cases, the amount of such margin is fixed; in others, the
amount changes as the market value of the respective contract changes, or if
certain financial tests are not met. For the years ended December 31, 1994,
1995 and 1996, the maximum aggregate amount of margin posted by the Company
was $41.0 million, $23.4 million and $28.4 million, respectively. For the
nine months ended September 30, 1997, the highest amount of posted margin was
$26.8 million. If natural gas prices were to rise, or if the Company fails to
meet the financial tests contained in certain of its Fixed-Price Contracts,
margin requirements could increase significantly. The Company believes that
it will be able to meet such requirements through the Credit Facility and such
other credit lines that it has or may obtain in the future. If the Company is
unable to meet its margin requirements, a contract could be terminated and the
Company could be required to pay damages to the counterparty which generally
approximate the cost to the counterparty of replacing the contract. At
September 30, 1997, the Company had issued margin in the form of letters of
credit and treasury bills totaling $18.8 million and $3.0 million,
respectively. In addition, approximately 30 Bcf of the Company's proved gas
reserves are mortgaged to a Fixed-Price Contract counterparty, securing the
Company's performance under the associated contract.
OUTLOOK FOR FISCAL YEAR 1997
Reference is made to the discussion under the caption "Forward-Looking
Statements" appearing elsewhere herein which describes the risks and
uncertainties inherent in estimating future results and the important factors
that could cause actual results to differ materially from the Forward-Looking
Statements discussed below. Such Forward-Looking Statements consider the
expected impact of the American Acquisition which closed on October 14, 1997,
and which will be accounted for under purchase accounting rules. The
following comments should be read in conjunction with the consolidated
financial statements, including the notes thereto, and Management's Discussion
<PAGE> 29
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
and Analysis of Financial Condition and Results of Operations contained herein
and in the following reports incorporated herein by reference: LDNG's Annual
Report on Form 10-K for the year ended December 31, 1996, as amended,
American's Annual Report on Form 10-K for the year ended December 31, 1996 and
American's Quarterly Report on Form 10-Q for the quarter ended June 30, 1997.
The following comments should also be read in conjunction with the unaudited
pro forma financial statements, including the notes thereto, included in
LDNG's Registration Statement on Form S-4 as filed on September 3, 1997
incorporated herein by reference.
Production. LDNG expects a significant increase in both oil and natural gas
production for the periods subsequent to the Merger, as production from the
properties acquired in the American Acquisition (the "American Properties") is
included with LDNG's production results. For the month of September 1997,
LDNG's and American's daily production results were 216 MMcfe and 106 MMcfe,
respectively.
Oil and Gas Prices. As of September 30, 1997, LDNG's Fixed-Price Contracts
for the balance of 1997 provide average fixed prices of $2.53 per Mcf for its
hedged natural gas and $22.20 per Bbl for its hedged oil production before
consideration of basis. Based on October 28, 1997 quotations for regional
natural gas prices for the balance of 1997 and giving effect to LDNG's
portfolio of basis swaps, LDNG anticipates price realization percentages for
the balance of 1997 to be comparable to historical averages. LDNG's
Fixed-Price Contracts hedge 15 Bcf of natural gas production (including 2.2
Bcf of fixed-price collars) and 324 MBbls of oil for the fourth quarter of
1997. These totals include the hedging arrangements assumed in the American
Acquisition. No plans currently exist to increase or decrease the amount of
hedged production volumes for the remainder of 1997; however, LDNG may decide
to hedge a greater or smaller share of production in the future.
LDNG is unable to predict the market prices that will be received for its
unhedged production for the balance of 1997. For the first nine months of
1997, average monthly wellhead prices for its natural gas ranged from $1.85
per Mcf to $4.11 per Mcf and its oil prices varied from $18.23 per Bbl to
$24.94 per Bbl. Approximately 60% of LDNG's estimated production for the
balance of 1997 is hedged by Fixed-Price Contracts.
Other Income. LDNG does not anticipate a material change in its well
services or gas gathering income for the balance of 1997 in relation to the
results achieved for the first nine months of 1997. Other miscellaneous
sources of income, such as gains or losses on property dispositions, cannot be
estimated, but are not expected to be material, nor are American's sources of
other income subsequent to the Merger expected to be material.
Operating Costs. Lifting costs are expected to increase significantly
subsequent to closing as a result of the costs attributable to the American
Properties. However, lifting costs on an equivalent unit of production basis
for the balance of 1997 are not expected to rise significantly on a combined
<PAGE> 30
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
basis in relation to LDNG's results for the first nine months of 1997.
Production taxes are expected to be incurred at an average rate of 5% to 6% of
wellhead oil and gas sales.
General and Administrative Expense. LDNG expects a significant increase in
general and administrative costs for the fourth quarter of 1997 resulting
from the G&A attributable to American. G&A costs are also expected to
increase on an equivalent unit of production basis. LDNG anticipates that
ultimately meaningful savings in G&A will be realized in relation to that
incurred by both companies independently, primarily through the elimination of
redundant positions and activities, which is scheduled to occur during the
fourth quarter of 1997. However, the benefit of such cost reduction measures
is not anticipated to be realized until the first quarter of 1998.
Exploration Costs. Capital expenditures for exploration drilling,
leasehold, seismic and other geological and geophysical costs for the balance
of 1997 are expected to be $17 million. Under the successful efforts method
of accounting, the costs associated with unsuccessful exploration wells are
expensed. All exploratory geological and geophysical costs (estimated at $1
million for the balance of 1997) are expensed as incurred, regardless of
ultimate success in the discovery of new reserves. Remaining exploration
costs to be expensed during the fourth quarter of 1997 will depend on
exploratory drilling results.
Depreciation, Depletion and Amortization. Based on the carrying value
expected to be assigned to the American Properties at closing pursuant to
purchase accounting rules and after consideration for the impairment charge
discussed below, LDNG's depreciation, depletion and amortization expense is
expected to significantly increase in the aggregate and on an equivalent unit
of production basis for the balance of 1997.
Impairment of Oil and Gas Properties. Based on the expected purchase price
allocation to be assigned to the American Properties, it is anticipated that
an impairment charge will be recorded in the fourth quarter of 1997. See
footnote (1) to the unaudited pro forma information contained in the Condensed
Notes to Consolidated Financial Statements under "Note 3 -- Merger with
American Exploration Company," appearing elsewhere in this document.
Additional future impairments of oil and gas properties may occur due to
changes in oil and gas prices, revisions to proved reserves, drilling results,
changes in drilling plans, changes in Fixed-Price Contracts or other factors.
The amount or timing of any future impairment cannot be estimated or
predicted, but may be material.
Interest Expense. LDNG expects interest expense to increase significantly
as a result of funding the cash portion of the merger consideration ($47.2
million), refinancing the bank credit facility of American ($81 million), and
assuming the subordinated notes of American ($35 million). However, the ratio
of EBITDAX to interest of the combined entities is expected to show
improvement in relation to LDNG's stand alone results. Further, the ratio of
<PAGE> 31
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
long-term debt to book capitalization is also expected to be lower than LDNG's
current leverage position.
Income Taxes. LDNG expects that income taxes will be provided at effective
rates approximating corporate statutory rates for the balance of 1997.
<PAGE> 32
LOUIS DREYFUS NATURAL GAS CORP.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See "Management's Discussion and Analysis of Financial Condition and Results
of Operations -- Fixed-Price Contracts."
<PAGE>
<PAGE> 33
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 -- EXHIBIT AND REPORTS ON FORM 8-K
(a) Exhibits:
27.1 -- Financial Data Schedule
(b) Reports on Form 8-K.
None
<PAGE>
<PAGE> 34
LOUIS DREYFUS NATURAL GAS CORP.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
LOUIS DREYFUS NATURAL GAS CORP.
-----------------------------------
(Registrant)
Date: November 13, 1997 /s/ Jeffrey A. Bonney
-----------------------------------
Jeffrey A. Bonney
Chief Financial Officer and Treasurer
<PAGE>
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
This schedule contains summary financial information extracted from the
unaudited consolidated balance sheet at September 30, 1997 and the unaudited
consolidated statement of income for the nine months ended September 30, 1997
and is qualified in its entirety by reference to such financial statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> SEP-30-1997
<CASH> 10,551
<SECURITIES> 0
<RECEIVABLES> 38,307
<ALLOWANCES> (1,085)
<INVENTORY> 2,509
<CURRENT-ASSETS> 55,614
<PP&E> 987,345
<DEPRECIATION> (276,174)
<TOTAL-ASSETS> 771,770
<CURRENT-LIABILITIES> 48,643
<BONDS> 356,017
0
0
<COMMON> 278
<OTHER-SE> 286,536
<TOTAL-LIABILITY-AND-EQUITY> 771,770
<SALES> 142,193
<TOTAL-REVENUES> 152,795
<CGS> 32,489
<TOTAL-COSTS> 117,960
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 19,031
<INCOME-PRETAX> 34,835
<INCOME-TAX> 12,193
<INCOME-CONTINUING> 22,642
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 22,642
<EPS-PRIMARY> .81
<EPS-DILUTED> .81
</TABLE>
