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, 1996
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 .
----- -----
27,800,000 shares of common stock, $.01 par value, issued and outstanding at
October 31, 1996.
2
LOUIS DREYFUS NATURAL GAS CORP.
Table of Contents
PART I. FINANCIAL INFORMATION Page
CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
Consolidated Balance Sheets:
December 31, 1995 and September 30, 1996 . . . . . . . . . . . . . . 3
Consolidated Statements of Income:
Three months and nine months ended September 30, 1995 and 1996 . . . 5
Consolidated Statements of Cash Flows:
Nine months ended September 30, 1995 and 1996. . . . . . . . . . . . 6
Condensed Notes to Consolidated Financial Statements . . . . . . . . . 8
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS. . . . . . . . . . . . . . . . . . . . . . 10
PART II. OTHER INFORMATION . . . . . . . . . . . . . . . . . . . . 28
3
LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED BALANCE SHEETS
(dollars in thousands)
A S S E T S
December 31, September 30,
1995 1996
------------- -------------
(unaudited)
CURRENT ASSETS
Cash and cash equivalents. . . . . . . . . . $ 1,584 $ 7,346
Receivables:
Oil and gas sales. . . . . . . . . . . . . 23,443 23,233
Joint interest and other, net. . . . . . . 5,300 2,950
Deposits . . . . . . . . . . . . . . . . . . 3,900 3,505
Inventory and other. . . . . . . . . . . . . 3,095 1,736
------------- -------------
Total current assets . . . . . . . . . . . 37,322 38,770
------------- -------------
PROPERTY AND EQUIPMENT, at cost, based on
successful efforts accounting. . . . . . . 778,348 877,853
Less accumulated depreciation, depletion,
amortization and impairment. . . . . . . . (188,495) (235,029)
------------- -------------
589,853 642,824
------------- -------------
OTHER ASSETS, net. . . . . . . . . . . . . . 7,762 6,806
------------- -------------
$ 634,937 $ 688,400
============= =============
4
LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED BALANCE SHEETS (continued)
(dollars in thousands)
L I A B I L I T I E S A N D S T O C K H O L D E R S ' E Q U I T Y
December 31, September 30,
1995 1996
------------- -------------
(unaudited)
CURRENT LIABILITIES
Accounts payable . . . . . . . . . . . . . . $ 21,458 $ 19,875
Accrued liabilities. . . . . . . . . . . . . 7,912 7,776
Revenues payable . . . . . . . . . . . . . . 4,687 7,136
------------- -------------
Total current liabilities. . . . . . . . . 34,057 34,787
BANK DEBT. . . . . . . . . . . . . . . . . . 216,000 229,000
SUBORDINATED DEBT. . . . . . . . . . . . . . 98,760 98,870
DEFERRED REVENUE . . . . . . . . . . . . . . 20,557 19,442
DEFERRED HEDGING GAINS . . . . . . . . . . . 5,070 27,565
OTHER LONG-TERM LIABILITIES. . . . . . . . . 4,285 4,098
DEFERRED INCOME TAXES. . . . . . . . . . . . 13,627 18,761
------------- -------------
392,356 432,523
------------- -------------
STOCKHOLDERS' EQUITY
Preferred stock, par value $.01; 10 million
shares authorized; no shares outstanding . -- --
Common stock, par value $.01; 100 million
shares authorized; 27,800,000 shares
issued and outstanding . . . . . . . . . . 278 278
Additional paid-in capital . . . . . . . . . 197,291 197,291
Retained earnings. . . . . . . . . . . . . . 45,012 58,308
------------- -------------
242,581 255,877
------------- -------------
$ 634,937 $ 688,400
============= =============
See accompanying notes to consolidated financial statements.
/TABLE
5
LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED STATEMENTS OF INCOME (unaudited)
(in thousands, except per share data)
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ ------------------
1995 1996 1995 1996
-------- -------- -------- --------
REVENUES
Oil and gas sales. . . . . . . . . . . $ 43,054 $ 48,074 $119,118 $131,713
Interest and other . . . . . . . . . . 500 914 2,019 2,941
-------- -------- -------- --------
43,554 48,988 121,137 134,654
-------- -------- -------- --------
EXPENSES
Operating costs. . . . . . . . . . . . 9,384 11,161 25,362 32,705
General and administrative . . . . . . 3,952 3,975 12,206 12,346
Exploration costs. . . . . . . . . . . -- 549 -- 791
Depreciation, depletion, amortization
and impairment . . . . . . . . . . . 15,931 17,042 42,579 48,766
Interest . . . . . . . . . . . . . . . 5,944 6,545 15,428 20,202
-------- -------- -------- --------
35,211 39,272 95,575 114,810
-------- -------- -------- --------
Income before income taxes . . . . . . 8,343 9,716 25,562 19,844
Income taxes . . . . . . . . . . . . . 2,752 3,206 8,435 6,548
-------- -------- -------- --------
NET INCOME . . . . . . . . . . . . . . $ 5,591 $ 6,510 $ 17,127 $ 13,296
======== ======== ======== ========
Net income per share . . . . . . . . . $ .20 $ .23 $ .62 $ .48
======== ======== ======== ========
Weighted average common shares
outstanding. . . . . . . . . . . . . 27,800 27,800 27,800 27,800
======== ======== ======== ========
See accompanying notes to consolidated financial statements.
/TABLE
6
LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
(in thousands)
Nine Months Ended
September 30,
---------------------
1995 1996
-------- --------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income . . . . . . . . . . . . . . . . . . . . . . $ 17,127 $ 13,296
Items not affecting cash flows:
Depreciation, depletion, amortization
and impairment . . . . . . . . . . . . . . . . . . . 43,186 48,766
Deferred income taxes. . . . . . . . . . . . . . . . 7,285 5,134
Exploration costs. . . . . . . . . . . . . . . . . . -- 791
Other. . . . . . . . . . . . . . . . . . . . . . . . 375 376
-------- --------
67,973 68,363
Net change in operating assets and liabilities:
Accounts receivable. . . . . . . . . . . . . . . . . (3,335) 2,560
Deposits . . . . . . . . . . . . . . . . . . . . . . 972 395
Inventory and other. . . . . . . . . . . . . . . . . (693) 1,359
Accounts payable . . . . . . . . . . . . . . . . . . (4,219) (1,583)
Accrued liabilities. . . . . . . . . . . . . . . . . 5,358 (136)
Revenues payable . . . . . . . . . . . . . . . . . . (551) 2,449
Deferred revenue . . . . . . . . . . . . . . . . . . -- (4,310)
-------- --------
65,505 69,097
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property and equipment. . . . . . . . (159,027) (101,939)
Proceeds from sale of property and equipment . . . . . 15,104 326
Expenditures for other assets. . . . . . . . . . . . . -- (78)
-------- --------
(143,923) (101,691)
-------- --------
/TABLE
7
LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited) (continued)
(in thousands)
Nine Months Ended
September 30,
---------------------
1995 1996
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term bank borrowings. . . . . . . . 201,250 196,140
Repayments of long-term bank borrowings. . . . . . . . (109,647) (183,140)
Change in deferred hedging gains . . . . . . . . . . . -- 26,805
Change in deferred revenue . . . . . . . . . . . . . . (9,455) (1,115)
Change in other long-term liabilities. . . . . . . . . (294) (334)
-------- --------
81,854 38,356
-------- --------
Change in cash and cash equivalents. . . . . . . . . . 3,436 5,762
Cash and cash equivalents, beginning of period . . . . 2,980 1,584
-------- --------
Cash and cash equivalents, end of period . . . . . . . $ 6,416 $ 7,346
======== ========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Interest paid. . . . . . . . . . . . . . . . . . . . . $ 10,667 $ 17,361
Income taxes paid. . . . . . . . . . . . . . . . . . . 3,222 1,179
-------- --------
$ 13,889 $ 18,540
======== ========
See accompanying notes to consolidated financial statements.
/TABLE
8
LOUIS DREYFUS NATURAL GAS CORP.
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
September 30, 1996
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, 1996 are not necessarily indicative of
the results to be expected for the full year. Certain reclassifications have
been made to the prior year statements to conform with the current year
presentation. Reference is made to the Company's Annual Report on Form 10-K
for the year ended December 31, 1995 for an expanded discussion of the
Company's financial disclosures and accounting policies.
NOTE 2 -- GAIN CONTINGENCY
On December 22, 1995, the United States District Court for the Western
District of Oklahoma entered a 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, the Company and Midcon settled remaining disputes in connection with
this litigation, and Midcon delivered a $10.8 million promissory note to the
Company. The note is secured by first and second liens on assets of Midcon
and is payable in full on or before December 15, 1996. For the nine months
ended September 30, 1996, Midcon made principal and interest payments on the
note totaling $1.7 million which have been recorded as other income. As of
September 30, 1996, $9.6 million of the judgment plus accrued interest
remained unpaid. Collectibility of this balance is uncertain, accordingly, no
amounts have been recorded with respect to the balance of the note in the
accompanying financial statements as of September 30, 1996. The Company will
recognize income as future payments are received.
NOTE 3 -- ACQUISITIONS AND DIVESTITURES
In November 1996, the Company purchased a 75-mile pipeline located in its
Sonora Field for $15.1 million, including the associated compression
facilities and transportation contracts, from an unrelated party.
Substantially all of the gas transported by this pipeline is produced from
properties owned by the Company.
In October 1996, the Company entered into an agreement with Santa Fe Energy
Resources to sell 100% of its ownership in the Levelland Field, an oil
property located in West Texas. The agreement provides for a sales price of
$27.1 million, effective December 1, 1996, and a closing date in January 1997.
As of December 31, 1995, the Levelland Field had remaining proved reserves of
5.0 million barrels of oil and 1.6 billion cubic feet of natural gas net to
the interest to be sold. The disposition of this property, when consummated,
9
LOUIS DREYFUS NATURAL GAS CORP.
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued)
September 30, 1996
is expected to result in an estimated pretax gain of approximately $9 million
in 1997. The operating results of the Levelland Field will be included in the
Company's financial statements through the date of closing.
10
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
OVERVIEW
General. Formed in 1979, Louis Dreyfus Natural Gas Corp. (the "Company")
was acquired by S.A. Louis Dreyfus et Cie on July 18, 1990 to conduct oil and
gas acquisition, development, production and marketing activities in North
America. Since that date, the Company's oil and gas reserves and production
have grown significantly as the result of numerous proved reserve acquisitions
and its active drilling program. In November 1993, the Company completed an
initial public offering of 7.8 million shares of common stock. At September
30, 1996, S.A. Louis Dreyfus et Cie's ownership in the Company was
approximately 74%.
The Company has a portfolio of fixed-price contracts, which include
long-term physical delivery contracts, energy swaps, basis swaps, futures
contracts and option agreements (collectively, "Fixed-Price Contracts")
designed to reduce the risk associated with fluctuations in natural gas and
oil prices. For the nine-month periods ended September 30, 1995 and 1996,
Fixed-Price Contracts hedged 84% and 51%, respectively, of the Company's
natural gas production not otherwise subject to fixed prices and 88% and 69%,
respectively, of the Company's oil production for such periods. Moreover, as
of September 30, 1996, the Company's Fixed-Price Contracts hedge 353 Bcf of
natural gas and 292 MBbls of oil to be produced in future periods. See
"Fixed-Price Contracts."
Forward-Looking Statements. Forward-looking statements for 1996 and for
later periods, which include all statements other than purely historical
information, are made in various places in this discussion. Such statements
represent the estimates of Management based on the Company's historical
operating trends, its proved reserves as of December 31, 1995, its Fixed-Price
Contract position as of September 30, 1996 and other information available to
Management. See "Estimates for Fiscal Year 1996" for a discussion of the
risks, uncertainties and other important factors which could cause actual
results to differ materially from those projected in such statements.
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. One billion Btus, equivalent to one MMcf of dry gas.
11
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
CERTAIN DEFINITIONS (continued)
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. One million Btus, equivalent to one Mcf of dry gas.
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. One trillion Btus, equivalent to one Bcf of dry gas.
12
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,
------------------ ------------------
1995 1996 1995 1996
-------- -------- -------- --------
OIL AND GAS SALES: (M$)
Wellhead oil sales . . . . . . . . . . $ 6,818 $ 9,888 $ 21,294 $ 27,879
Effect of Fixed-Price Contracts. . . . 401 (834) 805 (1,939)
-------- -------- -------- --------
Total oil sales. . . . . . . . . . . . $ 7,219 $ 9,054 $ 22,099 $ 25,940
======== ======== ======== ========
Wellhead natural gas sales:
Sales under Sonora Gas Contract. . . $ 12,977 $ -- $ 36,085 $ --
Other sales. . . . . . . . . . . . . 16,941 36,699 41,100 101,707
-------- -------- -------- --------
Total 29,918 36,699 77,185 101,707
Effect of Fixed-Price Contracts (1). . 5,917 2,321 19,834 4,066
-------- -------- -------- --------
Total natural gas sales. . . . . . . . $ 35,835 $ 39,020 $ 97,019 $105,773
======== ======== ======== ========
PRODUCTION:
Oil production (MBbls) . . . . . . . . 411 454 1,242 1,369
Natural gas production (MMcf):
Sold under Sonora Gas Contract . . . 3,365 -- 9,267 --
Other production . . . . . . . . . . 11,040 16,606 27,491 47,576
-------- -------- -------- --------
Total. . . . . . . . . . . . . . . . 14,405 16,606 36,758 47,576
======== ======== ======== ========
Net equivalent production (MMcfe). . . 16,872 19,332 44,211 55,792
/TABLE
13
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,
------------------ ------------------
1995 1996 1995 1996
-------- -------- -------- --------
AVERAGE SALES PRICE:
Oil (per Bbl):
Wellhead price . . . . . . . . . . . $ 16.58 $ 21.77 $ 17.14 $ 20.36
Effect of Fixed-Price Contracts. . . .98 (1.84) .65 (1.42)
-------- -------- -------- --------
Total. . . . . . . . . . . . . . . . $ 17.56 $ 19.93 $ 17.79 $ 18.94
======== ======== ======== ========
Average fixed price received under
Fixed-Price Contracts. . . $ 18.99 $ 19.53 $ 19.21 $ 19.33
Net effective cash realization (2) . 94% 97% 93% 96%
Natural gas (per Mcf):
Sales under Sonora Gas Contract. . . $ 3.86 $ -- $ 3.89 $ --
Other wellhead sales . . . . . . . . 1.53 2.21 1.50 2.14
-------- -------- -------- --------
Average price. . . . . . . . . . . . 2.08 2.21 2.10 2.14
Effect of Fixed-Price Contracts (1). .41 .14 .54 .08
-------- -------- -------- --------
Total. . . . . . . . . . . . . . . . $ 2.49 $ 2.35 $ 2.64 $ 2.22
======== ======== ======== ========
Average fixed price received under
Fixed-Price Contracts. . . . . . . . $ 2.35 $ 2.43 $ 2.46 $ 2.37
Net effective cash realization (2) . 99% 102% 97% 97%
Equivalent price (per Mcfe). . . . . . $ 2.55 $ 2.49 $ 2.69 $ 2.36
EXPENSES (per Mcfe):
Operating costs. . . . . . . . . . . . $ .56 $ .58 $ .57 $ .59
General and administrative . . . . . . $ .23 $ .21 $ .28 $ .22
Depreciation, depletion, amortization
& impairment - oil & gas . . . . . . . $ .89 $ .83 $ .91 $ .82
<FN>
(1) - Includes basis swap results and amortization of deferred hedging gains
and losses. See "Fixed-Price Contracts -- Market Risk."
(2) - Represents the net effective cash price realized for the Company's
hedged production (after consideration for basis 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."
/TABLE
14
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
RESULTS OF OPERATIONS -- THREE MONTHS ENDED SEPTEMBER 30, 1996 COMPARED TO
THREE MONTHS ENDED SEPTEMBER 30, 1995
Net Income and Cash Flows from Operating Activities. For the quarter ended
September 30, 1996, the Company realized net income of $6.5 million, or $.23
per share, on total revenue of $49.0 million. This compares with net income
of $5.6 million, or $.20 per share, on total revenue of $43.6 million for the
third quarter of 1995. Cash flows from operating activities (before working
capital changes) for the third quarter of 1996 increased 11% to $26.7 million
from the $24.1 million reported for the third quarter of 1995. The increase
in third quarter 1996 earnings and operating cash flows was principally the
result of a significant increase in production for the quarter.
Production. The Company produced 19.3 Bcfe for the third quarter of 1996
compared to 16.9 Bcfe for the prior year third quarter, an increase of 15%.
Natural gas production increased to 16.6 Bcf, up 15% over the 14.4 Bcf
produced in the third quarter of 1995. Oil production for the third quarter
of 1996 increased 10% to 454 MBbls compared to 411 MBbls for the third quarter
of 1995. The increase in oil and gas production was primarily the result of
acquisitions closed during the previous twelve months and the results of the
Company's drilling program. Over this period, the Company expended $35.0
million and $92.3 million in connection with its acquisition and drilling
programs, respectively.
Oil and Gas Prices. On a natural gas equivalent basis, the Company received
an average price of $2.49 per Mcfe for the quarter ended September 30, 1996, a
decrease of 2% from the $2.55 per Mcfe received for the third quarter of 1995.
The Company's gas production yielded an average price of $2.35 per Mcf, a
decrease of 6% from the $2.49 per Mcf for the prior year third quarter, due
primarily to the expiration in December 1995 of a wellhead contract for
certain Sonora Field production with Lone Star Gas Company ("Sonora Gas
Contract"). This contract paid $3.86 per Mcf for approximately 3.4 Bcf of
natural gas in the third quarter of 1995. The average gas price for the third
quarter of 1996 was enhanced $.14 per Mcf as a result of the Company's hedging
activities. The average gas price for the third quarter of 1995 was enhanced
$.41 per Mcf as a result of Fixed-Price Contracts in effect for that period.
The average oil price received for the third quarter of 1996 was $19.93 per
Bbl, an increase of 13% compared to $17.56 per Bbl for the prior-year third
quarter. The 1996 third quarter average oil price was reduced $1.84 per Bbl
as a result of the Company's hedging activities. Fixed-Price Contracts
hedging the Company's crude oil production during the third quarter of 1995
increased the average price by $.98 per Bbl.
The combination of higher gas production and lower average gas prices
increased gas sales to $39.0 million for the third quarter of 1996 compared to
$35.8 million for the third quarter of 1995, an increase of 9%. The combined
effect of higher oil production and higher average oil prices was to increase
oil sales by 25% to $9.1 million from the $7.2 million reported for the third
quarter of 1995. See additional discussion under "Fixed-Price Contracts."
15
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
Other Income. Other income for the third quarter of 1996 was $914,000
compared to $500,000 for the third quarter of 1995. The 1996 third quarter
amount is higher primarily due to the receipt of $503,000 from Midcon
Offshore, Inc. in connection with a $10.8 million judgment in the Company's
favor. As of September 30, 1996, $9.6 million of the judgment plus accrued
interest remained unpaid. Collectibility of this balance is uncertain;
accordingly, no amounts have been recorded with respect to the balance of the
judgment in the accompanying financial statements as of September 30, 1996.
The Company will recognize income as future payments are received.
Operating Costs. Operating costs, which include direct lease operating
expenses and production taxes, increased to $11.2 million for the third
quarter of 1996 compared to $9.4 million for third quarter of 1995. This
increase is principally attributable to producing properties acquired and
wells drilled during the previous twelve months. On an equivalent unit of
production basis, total operating costs remained relatively constant at $.58
per Mcfe for the third quarter of 1996 compared to $.56 per Mcfe for the
prior-year third quarter. The increase per Mcfe for the 1996 third quarter is
attributable to higher production taxes associated with higher wellhead
prices.
General and Administrative Expense. General and administrative expense
("G&A") for the third quarter of 1996 was $4.0 million compared to $4.0
million for the prior-year third quarter. On an equivalent unit of production
basis, G&A decreased to $.21 per Mcfe for the 1996 third quarter compared to
$.23 per Mcfe for the third quarter of 1995, a decrease of 9%. This decrease
is primarily attributable to a significant growth in oil and gas production
without corresponding increases in personnel and associated costs.
Exploration Costs. Exploration costs, comprised primarily of dry hole and
geological and geophysical costs, were $549,000 for the quarter ended
September 30, 1996. No exploration costs were incurred for the prior year
quarter.
Depreciation, Depletion, Amortization and Impairment. Depreciation,
depletion, amortization and impairment ("DD&A") for the third quarter of 1996
was $17.0 million compared to $15.9 million for the prior-year third quarter.
This increase in DD&A is attributable to the increase in production volumes
previously discussed. The oil and gas DD&A rate per equivalent unit of
production (including leasehold impairment) was $.83 per Mcfe for the third
quarter of 1996 compared to $.89 per Mcfe for the third quarter of 1995. This
decrease in rate is due principally to favorable finding cost results
attributable to the Company's acquisition and drilling programs during the
previous twelve-month period and to an impairment charge taken in the fourth
quarter of 1995 upon the adoption of SFAS 121.
Interest Expense. Interest expense for the third quarter of 1996 was $6.5
million compared to $5.9 million for the third quarter of 1995. This increase
is primarily attributable to a higher level of outstanding indebtedness for
16
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
the 1996 third quarter as a result of acquisitions funded with availability
under the Company's $300 million bank credit facility. The net impact of
interest rate swaps in effect for the third quarter of 1996 was to increase
interest expense by $186,000. The net impact of interest rate swaps in effect
during the third quarter of 1995 was to decrease interest expense by $63,000.
See "Capital Resources and Liquidity -- Credit Facility."
Income Taxes. For the third quarter of 1996, the Company recorded an income
tax provision of $3.2 million on pretax income of $9.7 million, an effective
rate of 33%. This compares to an income tax provision of $2.8 million on
pretax income of $8.3 million, an effective rate of 33%, for the third quarter
of 1995. The effective rate for both quarters was lower than the statutory
rate primarily due to the availability of Section 29 credits.
RESULTS OF OPERATIONS -- NINE MONTHS ENDED SEPTEMBER 30, 1996 COMPARED TO
NINE MONTHS ENDED SEPTEMBER 30, 1995
Net Income and Cash Flows from Operating Activities. The Company realized
net income of $13.3 million, or $.48 per share, on total revenue of $134.7
million for the nine months ended September 30, 1996. This compares with net
income of $17.1 million, or $.62 per share, on total revenue of $121.1 million
for the first nine months of 1995. Cash flows from operating activities
(before working capital changes) for the first nine months of 1996 were
essentially unchanged at $68.4 million compared to $68.0 million for the first
nine months of 1995. The results for the 1995 nine-month period reflect the
positive impact of the Sonora Gas Contract which paid $3.89 per Mcf for
approximately 9.3 Bcf of production. This contract expired in December 1995.
Production. The Company produced 55.8 Bcfe for the first nine months of
1996 compared to 44.2 Bcfe for the comparable prior-year period. This
increase in overall production is principally attributable to the results of
the Company's drilling program and producing property acquisitions made during
the previous twelve months. Natural gas production for the nine months ended
September 30, 1996 was 47.6 Bcf, a 29% increase over the 36.8 Bcf produced
during the first nine months of 1995. Oil production for the first nine
months of 1996 increased 10% to 1,369 MBbls compared to 1,242 MBbls for the
first nine months of 1995.
Oil and Gas Prices. On a natural gas equivalent basis, the Company received
an average price of $2.36 per Mcfe for the first nine months of 1996, a
decrease of 12% compared to $2.69 per Mcfe for the first nine months of 1995.
The average gas price for the first nine months of 1996 was $2.22 per Mcf, a
decrease of 16% compared to $2.64 per Mcf for the nine months ended September
30, 1995. These declines were primarily the result of the expiration of the
Sonora Gas Contract. The Company's average gas price for the first nine
months of 1996 was enhanced $.08 per Mcf as a result of the Company's hedging
activities. The average gas price for the first nine months of 1995 was
enhanced $.54 per Mcf as a result of Fixed-Price Contracts in effect for that
period. The average oil price for the first nine months of 1996 was $18.94
per Bbl compared to $17.79 per Bbl for the first nine months of 1995. The
17
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
average oil price for the current year nine-month period was reduced $1.42 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 1995 was to increase the average price by $.65 per Bbl.
The combination of higher gas production and lower average gas prices
increased gas sales to $105.8 million for the first nine months of 1996, an
increase of 9% from the $97.0 million reported for the first nine months of
1995. The combined effect of higher oil production and higher average oil
prices was to increase oil sales by 17% to $25.9 million compared to $22.1
million for the prior-year nine-month period.
Other Income. Other income for the first nine months of 1996 was $2.9
million compared to $2.0 million for the first nine months of 1995. This
increase is 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. As
of September 30, 1996, $9.6 million of the judgment plus accrued interest
remained unpaid. Collectibility of this balance is uncertain; accordingly, no
amounts have been recorded with respect to the balance of the judgment in the
accompanying financial statements as of September 30, 1996. The Company will
recognize income as future payments are received.
Operating Costs. Operating costs, which include direct lease operating
expenses and production taxes, increased to $32.7 million for the first nine
months of 1996 compared to $25.4 million for the first nine months of 1995.
This increase is principally attributable to producing properties acquired and
wells drilled during the previous twelve months. On a natural gas equivalent
basis, total operating costs remained relatively constant at $.59 per Mcfe for
the first nine months of 1996 compared to $.57 per Mcfe for the comparable
prior-year period. The increase per Mcfe for the 1996 period is attributable
to higher production taxes associated with higher wellhead prices.
General and Administrative Expense. G&A for the first nine months of 1996
was $12.3 million compared to $12.2 million for the comparable prior-year
period. On a natural gas equivalent basis, G&A decreased to $.22 per Mcfe for
the first nine months of 1996 compared to $.28 per Mcfe for the first nine
months of 1995, a decrease of 21%. This decrease is primarily attributable to
significant growth in oil and gas production without corresponding increases
in personnel and related costs.
Exploration Costs. Exploration costs, comprised primarily of dry hole and
geological and geophysical costs, were $791,000 for the nine months ended
September 30, 1996. Through the first nine months of 1996, the Company had
drilled eleven exploratory wells, nine of which were successfully completed.
Depreciation, Depletion, Amortization and Impairment. DD&A for the first
nine months of 1996 was $48.8 million compared to $42.6 million for the first
nine months of 1995. This increase in DD&A is attributable to the increase in
production volumes previously discussed. The oil and gas DD&A rate per
18
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
equivalent unit of production (including leasehold impairment) was $.82 per
Mcfe for the first nine months of 1996 and $.91 per Mcfe for the first nine
months of 1995. This decrease in rate is due principally to favorable finding
cost results attributable to the Company's acquisition and drilling programs
during the previous twelve-month period and to an impairment charge taken in
the fourth quarter of 1995 upon the adoption of SFAS 121.
Interest Expense. For the nine months ended September 30, 1996, interest
expense was $20.2 million compared to $15.4 million for the first nine months
of 1995. This increase is primarily attributable to a higher level of
outstanding indebtedness for the first nine months of 1996 as a result of
acquisitions funded with availability under the Company's $300 million bank
credit facility. The net impact of interest rate swaps in effect during the
first nine months of 1996 was to increase interest expense by $718,000.
Interest rate swaps in effect for the first nine months of 1995 decreased
interest costs by $351,000. See "Capital Resources and Liquidity -- Credit
Facility."
Income Taxes. For the first nine months of 1996, the Company recorded a tax
provision of $6.5 million on pretax income of $19.8 million, an effective rate
of 33%. This compares to a tax provision of $8.4 million provided on pretax
income of $25.6 million for the first nine months of 1995, 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
General. For the nine-month period ended September 30, 1996, the Company
funded its investing activities primarily through cash provided by operating
activities, bank borrowings and other financing activities. The Company's
income (excluding gains and losses on sales and retirements of assets and
non-cash charges and writedowns) before deduction for interest, income taxes,
and DD&A ("EBITDA") increased from $84.6 million for the first nine months of
1995 to $89.8 million for the first nine months of 1996. This increase in
EBITDA has occurred primarily as a result of the increase in the Company's oil
and gas sales between the two periods. The Company's $300 million bank credit
facility and the indenture agreement for the 9-1/4% Senior Subordinated Notes
due 2004 include certain covenants based in part on EBITDA. However, EBITDA
should not be considered an alternative to net income as an indicator of
Company operating performance or an alternative to cash flows as a measure of
liquidity.
Credit Facility. The Company has a revolving credit facility with a
syndicate of banks (the "Credit Facility"), as most recently amended July 31,
1996 to reduce the pricing and extend the maturity, which provides for
borrowings and letters of credit up to the lesser of the Commitment or the Oil
and Gas Reserves Loan Value as defined by the agreement. The maximum amount
of letters of credit available for issuance thereunder is further limited to
$75 million. The Oil and Gas Reserves Loan Value is based on a periodic
valuation of the Company's oil and gas reserves and Fixed-Price Contracts,
19
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
subject to certain adjustments, and was most recently reset to be $315 million
in June 1996. The Commitment is $300 million and reduces at the rate of
$18.75 million per quarter commencing October 31, 1999 through July 31, 2003.
The Company has relied upon the Credit Facility to provide funds for
acquisitions and to provide letters of credit to meet the Company's margin
requirements under Fixed-Price Contracts. See "Fixed-Price Contracts
- -- Margining." As of September 30, 1996, the Company had $226.0 million of
principal and $1.9 million of letters of credit outstanding under the Credit
Facility.
The Company has the option of either borrowing at a LIBOR-based interest
rate or the Base Rate (approximating the prime rate). The agreement also
provides for a competitive bid option for borrowings under the facility. The
LIBOR interest rate margin under the facility is subject to a sliding scale
based on the relationship of outstanding indebtedness to the discounted
present value of the Company's oil and gas reserves and Fixed-Price Contracts.
The LIBOR interest rate margin varies from .25% to .55% per annum. At
September 30, 1996, the applicable interest rate was LIBOR plus .30%. The
amended Credit Facility also requires the payment of a facility fee equal to
.20% of the Commitment.
The Credit Facility contains various affirmative and restrictive covenants.
These covenants, among other things, limit additional indebtedness, the extent
to which volumes under Fixed-Price Contracts can exceed proved reserves in any
year and in the aggregate, the sale of assets and the payment of dividends,
and require the Company to meet certain financial tests. Borrowings under the
Credit Facility are unsecured.
The Company has entered into interest rate swaps to hedge the interest rate
exposure associated with the Credit Facility. As of September 30, 1996, the
Company had fixed the interest rate on average notional amounts of $186
million for the balance of 1996, and $153 million, $99 million and $33 million
for the years ending December 31, 1997, 1998 and 1999, respectively. Under
the interest rate swaps, the Company receives the LIBOR three-month rate (5.7%
at September 30, 1996) and pays an average rate of 6.1% for the balance of
1996, and 6.1%, 6.3% and 6.5% for the years ending December 31, 1997, 1998 and
1999, respectively. The notional amounts are less than the maximum amount
anticipated to be available under the Credit Facility in such years. As of
September 30, 1996, the effective interest rate for borrowings under the
Credit Facility, including the effect of interest rate swaps, was 6.3%. On
June 28, 1996, the Company entered into 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 is in effect through
June 28, 2004.
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.
20
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
Proceeds from the offering were used to retire outstanding indebtedness under
the Credit Facility and for general working capital purposes. 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 $53 million as of September 30, 1996. Such short-term
lines of credit are primarily used to meet letter of credit obligations under
Fixed-Price Contracts and for working capital purposes. At September 30,
1996, the Company had $3.0 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 currently 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
1996 and to meet the Company's obligations under its Fixed-Price Contracts.
See "Commitments and Capital Expenditures" and "Fixed-Price Contracts --
Margining." At September 30, 1996, the Company had working capital of $4.0
million and a current ratio of 1.1 to 1. Total long-term debt outstanding at
September 30, 1996 was $327.9 million. The Company's long-term debt as a
percentage of its total capitalization was 56%.
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, 1996, the Company expended $100.0 million in
connection with this strategy, including $11.0 million for exploration
projects, funded principally through internally generated cash flows, bank
borrowings and other investing activities. For the balance of 1996, the
Company currently plans to spend approximately $25 million in connection with
its drilling program, the vast majority of which is development drilling,
focused principally in its core operating areas of Sonora, the Mid-Continent,
the Permian Region and the Gulf Coast. Such planned expenditure levels
include approximately $7 million of additional exploration drilling and other
exploration costs. Actual capital expenditure levels may vary due to many
factors, including drilling results, new drilling opportunities, oil and
natural gas prices and acquisition opportunities. As of October 31, 1996, the
Company had drilled 240 wells, 231 of which were successfully completed as
producers, and an additional 17 wells were in progress.
On April 4, 1996, the Company purchased certain producing oil and gas
properties and associated leasehold acreage from Coastal Oil and Gas
Corporation and affiliates for $29.9 million. The properties, which are
located primarily in Oklahoma, consist of approximately 60 Bcfe of proved
reserves attributable to approximately 800 wells. The Company continues to
actively search for attractive proved reserve acquisitions but is not able to
21
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
predict the timing or amount of any capital expenditure which may be employed
in acquisitions.
In November 1996, the Company purchased a 75-mile pipeline located in its
Sonora Field for $15.1 million, including the associated compression
facilities and transportation contracts, from an unrelated party.
Substantially all of the gas transported by this pipeline is produced from
properties owned by the Company.
In October 1996, the Company entered into an agreement with Santa Fe Energy
Resources to sell 100% of its ownership in the Levelland Field, an oil
property located in West Texas. The agreement provides for a sales price of
$27.1 million, effective December 1, 1996, and a closing date in January 1997.
As of December 31, 1995, the Levelland Field had remaining proved reserves of
5.0 million barrels of oil and 1.6 billion cubic feet of natural gas net to
the interest to be sold. The disposition of this property, when consummated,
is expected to result in an estimated pretax gain of approximately $9 million
in 1997. The operating results of the Levelland Field will be included in the
Company's financial statements through the date of closing.
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, basis swaps, futures contracts 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, for its hedged production, the Company
will not benefit from market prices that are higher than the fixed prices in
such contracts. During the first nine months of 1996, Fixed-Price Contracts
hedged 51% of the Company's gas production and 69% of its oil production.
Moreover, as of September 30, 1996, Fixed-Price Contracts are in place to
hedge approximately 59% of the Company's estimated future production from
proved gas reserves through the year 2000 and 292 MBbls of oil for the balance
of 1996.
Under its energy swap sales contracts, the Company receives a fixed price
for the respective commodity and pays a floating market price (generally a
NYMEX-based or regional spot market index), as defined in each contract, to
the counterparty. For its physical delivery contracts, the Company purchases
gas in the spot market at floating market prices and delivers such gas to the
contract counterparty for a fixed price. Under its energy swap purchase
contracts, the Company pays a fixed price for the commodity and receives a
floating market price.
The following table summarizes the volumes, fixed prices and future amounts
to be received (or paid) under the Company's Fixed-Price Contracts as of
22
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
September 30, 1996. Such amounts do not reflect the future floating price
payments (in the case of energy swaps) or the future cost of supplying gas (in
the case of physical delivery contracts) pursuant to these contracts.
23
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
FIXED-PRICE CONTRACTS (1)
Three
Months
Ending
December Years Ending December 31, Balance
31, -------------------------------------- through
1996 1997 1998 1999 2000 2017 Total
-------- -------- -------- -------- -------- -------- ----------
NATURAL GAS SWAPS, OPTIONS
AND FUTURES
Sales Contracts
Contract volumes
(BBtu) (2) . . . . . . . 2,007 4,843 13,825 15,825 9,830 37,307 83,637
Weighted average fixed
price per MMBtu. . . . . $ 2.85 $ 2.16 $ 2.33 $ 2.44 $ 2.46 $ 2.96 $ 2.65
Future receipts (M$) . . . $ 5,718 $ 10,443 $ 32,243 $ 38,629 $ 24,164 $110,450 $ 221,647
Purchase Contracts
Contract volumes (BBtu). . (300) (2,425) (9,125) (10,950) -- -- (22,800)
Weighted average fixed
price per MMBtu. . . . . $ 2.30 $ 2.02 $ 2.09 $ 2.18 $ -- $ -- $ 2.13
Future payments (M$) . . . $ (689)$ (4,904) $(19,108) $(23,880) $ -- $ -- $ (48,581)
NATURAL GAS PHYSICAL
DELIVERY CONTRACTS
Contract volumes (BBtu). . 7,335 32,511 36,060 28,204 26,749 161,396 292,255
Weighted average fixed
price per MMBtu. . . . . $ 2.42 $ 2.50 $ 2.64 $ 2.84 $ 3.04 $ 3.96 $ 3.40
Future receipts (M$) . . . $ 17,739 $ 81,276 $ 95,130 $ 80,125 $ 81,403 $638,418 $ 994,091
TOTAL NATURAL GAS
CONTRACTS (3)
Contract volumes (BBtu). . 9,042 34,929 40,760 33,079 36,579 198,703 353,092
Weighted average fixed
price per MMBtu. . . . . $ 2.52 $ 2.49 $ 2.66 $ 2.87 $ 2.89 $ 3.77 $ 3.31
Future receipts (M$) . . . $ 22,768 $ 86,815 $108,265 $ 94,874 $105,567 $748,868 $1,167,157
CRUDE OIL SWAPS AND
FUTURES (4)
Contract volumes (MBbls) . 292 -- -- -- -- -- 292
Weighted average fixed
price per Bbl. . . . . . $ 20.16 $ -- $ -- $ -- $ -- $ -- $ 20.16
Future receipts (M$) . . . $ 5,888 $ -- $ -- $ -- $ -- $ -- $ 5,888
<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
"Fixed-Price Contracts -- Market Risk."
(2)- Includes 20,000 BBtu attributable to a natural gas swap entered into with an affiliate in
April 1996. See "Significant New Contracts."
(3)- Does not include basis swaps with notional volumes by year, as follows: 1996 - 4.3 TBtu;
1997 - 19.6 TBtu; 1998 - 22.6 TBtu; 1999 - 17.2 TBtu; 2000 - 20.9 TBtu; and thereafter -
14.9 TBtu.
(4)- Does not include oil futures contracts entered into after September 30, 1996 which hedge
362 MBbls of oil at $22.32 per Bbl in 1997.
24
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
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
of the contracts. If a Fixed-Price Contract is liquidated, sold or monetized
prior to maturity, the gain or loss is deferred and amortized into oil and gas
sales over the original life of the contract.
In June 1996, the Company and an unaffiliated counterparty to one of its
fixed-price contracts amended the terms of a fixed-price natural gas contract
to monetize the premium in the fixed prices provided by the contract.
Pursuant to the amendment, the Company received a non-refundable payment in
the amount of $25.0 million. As consideration for this payment, the weighted
average fixed price over the remaining 17 years of the contract was reduced
from $3.20 per MMBtu to $2.37 per MMBtu, approximating the forward market
prices for natural gas at the time. The payment has been reflected in the
Company's balance sheet as a deferred hedging gain and will be amortized into
earnings over the life of the underlying contract. As of September 30, 1996,
the balance of deferred hedging gains was $27.6 million; the amount of
deferred hedging losses was not material.
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 or cancel 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 and could adversely affect the carrying value of
the Company's oil and gas properties and the amount of borrowing capacity
available under the Credit Facility. See "Capital Resources and Liquidity."
Two Fixed-Price Contracts which hedge an aggregate 109 Bcf of natural gas as
of September 30, 1996 are with independent power producers who sell electrical
power under firm fixed-price contracts to Niagara Mohawk Corporation ("NIMO"),
a New York state utility. As of September 30, 1996, the fixed prices provided
by these contracts were "in the money" in relation to quoted forward market
prices for natural gas by approximately $131 million (discounted at 10%).
This premium in the fixed prices is not reflected in the Company's financial
statements until realized. The ability of these independent power producers
to perform their obligations to the Company is largely dependent on the
25
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
continued performance by NIMO of its power purchase obligations. NIMO in
recent years has initiated judicial and regulatory proceedings designed to
curtail power purchase obligations under its contracts with non-regulated
power generators. As of September 30, 1996, NIMO had not been successful in
these proceedings. In April 1996, the Federal Energy Regulatory Commission
issued Order No. 888 which, among other things, affirmed the ability of public
utilities to recover stranded investment costs when open-access transmission
rules become effective. The implications of Order No. 888 are far reaching
and its ultimate impact to NIMO is unknown; however, the order is anticipated
to allow NIMO to recover costs, such as power purchase obligations with
non-regulated power generators which have become "stranded" as the result of
customers having access to electricity from other generators through NIMO's
transmission system, subject to state regulatory approval. On August 1, 1996,
NIMO announced an offer to terminate 44 independent power contracts, including
those to the Company's counterparties, in exchange for a combination of cash
and debt securities from a newly restructured NIMO. The terms of the offer
have not been made public. At this time, the likelihood of NIMO's proposal
being accepted cannot be predicted, nor can any potential impact on future
counterparty performance if the proposal is accepted. The Company has not
experienced non-performance by any counterparty.
Market Risk. The Company's Fixed-Price Contracts hedge 353 Bcf of proved
natural gas reserves, substantially all of which are proved developed
reserves, and 292 MBbls of oil at fixed prices. If the Company's proved
reserves are produced at rates less than anticipated, the volumes specified
under the Fixed-Price Contracts may 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 any excess
volumes. The Company expects future production volumes to be equal to or
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 factors. The effective price realizations which result from the
Company's Fixed-Price Contracts are affected by movements in basis. For its
gas production in 1994 and 1995, the Company realized approximately 11% and 3%
less than the prices specified in its natural gas fixed-price contracts due to
basis, respectively. For its oil production hedged by Fixed-Price Contracts
in 1994 and 1995, the Company realized approximately 8% and 7% less than the
prices specified in such contracts, respectively. For the nine months ended
September 30, 1996, the Company received approximately 3% and 4% less than the
prices specified in its natural gas contracts and crude oil contracts,
respectively. Such results do not include a $4.3 million basis charge
recognized in the fourth quarter of 1995, discussed below. Basis results for
the first nine months of 1996 are not necessarily indicative of the results to
be expected for the full year. Basis movements can result from a number of
26
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
variables, including temporary regional market aberrations, 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 remaining three months of 1996 would represent
a $228,000 change in gas sales. A 1% change in price realization for hedged
oil production for the remaining three months of 1996 would represent a
$59,000 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.
In the first quarter of 1996, the Company experienced an unprecedented
widening of basis for certain of its Fixed-Price Contracts. These particular
contracts have floating indices tied to the NYMEX natural gas contract or
involve the purchase of gas in the spot market priced at or near the Henry Hub
delivery point in Louisiana. The Henry Hub price has historically had high
correlation to the market prices received by the Company for its gas
production, making such contracts effective natural gas price hedges. This
effectiveness, however, was lost for the first quarter 1996 settlement
periods. As a result, the Company recognized a $4.3 million charge in the
fourth quarter of 1995 (when the anomaly was identified) to reflect the
estimated basis loss incurred. To reduce exposure to Henry Hub basis
volatility, the Company canceled a 20-Bcf contract with S.A. Louis Dreyfus et
Cie in January 1996, receiving $1.6 million in proceeds. These proceeds are
being amortized into oil and gas sales over the original 19-month contract
term which commenced January 1996. The Company has also entered into several
basis swaps with third parties which are designed to substantially reduce
the Company's exposure to Henry Hub basis volatility over the next five years.
Margining. The Company is required to post margin in the form of bank
letters of credit 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. During 1994 and 1995, the maximum aggregate amount of margin
posted by the Company was $41.0 million and $23.4 million, respectively. 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, 1996,
the Company had issued margin in the form of letters of credit and treasury
bills totaling $18.9 million and $3.5 million, respectively.
Significant New Contracts. The Company entered into two long-term,
Fixed-Price Contracts to hedge a portion of the production acquired from
27
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
Coastal Oil and Gas Corporation. The first contract is a ten-year, 20-Bcf
natural gas swap with Duke/Louis Dreyfus L.L.C., an affiliate, which commences
June 1997. The fixed prices in this contract range from $2.05 to $2.51 per
MMBtu. The second contract, which was entered into with an unrelated party,
is a five-year, 9-Bcf natural gas swap that provides an average fixed price of
$2.10 per MMBtu. This contract also commences June 1997.
ESTIMATES FOR FISCAL YEAR 1996
General. The fiscal year 1996 estimates provided under this caption and
other statements in this document other than purely historical information
(collectively "Forward-Looking Statements") are based on the Company's
historical operating trends, its proved reserves as of December 31, 1995, its
Fixed-Price Contract position as of September 30, 1996 and other information
available to Management. These statements assume that market conditions for
the Company's oil and gas production are comparable to those experienced in
1995 as modified for changes in oil and gas prices through October 1996.
These statements also assume that no significant changes occur in the
operating environment for the Company's oil and gas properties. And finally,
the Forward-Looking Statements assume no material changes in the composition
of the Company's property base as the result of material acquisitions or
divestitures except as disclosed herein. THE COMPANY CAUTIONS THAT THE
FORWARD-LOOKING STATEMENTS PROVIDED HEREIN ARE SUBJECT TO ALL THE RISK 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 RISK, ENVIRONMENTAL RISK, DRILLING RISK, RESERVE
RISK, OPERATIONS AND PRODUCTION RISK, AND COUNTERPARTY RISK. CERTAIN OF THESE
RISKS ARE DESCRIBED ELSEWHERE HEREIN. MOREOVER, THE COMPANY MAY MAKE MATERIAL
ACQUISITIONS OR DIVESTITURES, 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
DIFFER MATERIALLY FROM THE FORWARD-LOOKING STATEMENTS AND THERE IS NO
ASSURANCE THAT THE ASSUMPTIONS USED ARE NECESSARILY THE MOST LIKELY.
Reference is made to "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Estimates for Fiscal Year 1996"
included in the Company's Annual Report on Form 10-K for the year ended
December 31, 1995 and in the Company's Form 10-Q for the quarter ended March
31, 1996. Subject to the uncertainties identified in the preceding paragraph,
no material modifications to previously disclosed estimates are deemed
necessary.
28
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
Exhibits:
27.1 -- Financial Data Schedule
No reports on Form 8-K.
29
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 8, 1996 /s/ Jeffrey A. Bonney
-----------------------------------
Jeffrey A. Bonney
Vice President and Chief Accounting Officer