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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q/A
AMENDMENT NO. 1
[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934.
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 1999
or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934.
For the transition period from to
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Commission File Number 1-12480
[LOGO] LOUIS DREYFUS NATURAL GAS CORP.
(Exact name of registrant as specified in its charter)
OKLAHOMA 73-1098614
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
14000 QUAIL SPRINGS PARKWAY, SUITE 600
OKLAHOMA CITY, OKLAHOMA 73134
(Address of principal executive office) (Zip code)
Registrant's telephone number, including area code: (405) 749-1300
NONE
(Former name, former address and former fiscal
year, if changed since last report.)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. YES X NO .
--- ---
40,143,008 shares of common stock, $.01 par value, issued and outstanding at
August 12, 1999.
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LOUIS DREYFUS NATURAL GAS CORP.
TABLE OF CONTENTS
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PART I. FINANCIAL INFORMATION PAGE
----
Item 1 -- CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
Consolidated Balance Sheets:
June 30, 1999 and December 31, 1998.................................... 3
Consolidated Statements of Operations:
Three months and six months ended June 30, 1999 and 1998............... 4
Consolidated Statements of Stockholders' Equity
June 30, 1999 and December 31, 1998.................................... 5
Consolidated Statements of Cash Flows:
Six months ended June 30, 1999 and 1998................................ 6
Condensed Notes to Consolidated Financial Statements......................... 7
Item 2 -- MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS.................................... 10
Item 3 -- QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK.......... 19
PART II. OTHER INFORMATION................................................ 22
Page 2 of 23
LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED BALANCE SHEETS (RESTATED)
(DOLLARS IN THOUSANDS)
A S S E T S
JUNE 30, DECEMBER 31,
1999 1998
---------- -----------
(UNAUDITED)
CURRENT ASSETS
Cash and cash equivalents......................................................... $ 7,983 $ 2,539
Receivables:
Oil and gas sales.............................................................. 43,989 37,381
Joint interest and other, net.................................................. 8,056 11,725
Costs reimbursable by insurance................................................ -- 7,200
Fixed-price contracts and other derivatives....................................... 12,313 23,338
Prepaids and other................................................................ 2,283 4,572
---------- ----------
Total current assets........................................................... 74,624 86,755
---------- ----------
PROPERTY AND EQUIPMENT, at cost, based on successful efforts
accounting..................................................................... 1,583,721 1,519,296
Less accumulated depreciation, depletion and amortization......................... (475,175) (434,693)
---------- ----------
1,108,546 1,084,603
---------- ----------
OTHER ASSETS
Fixed-price contracts and other derivatives....................................... 79,529 107,302
Other, net........................................................................ 4,364 5,148
---------- ----------
83,893 112,450
---------- ----------
$1,267,063 $1,283,808
---------- ----------
---------- ----------
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
CURRENT LIABILITIES
Accounts payable.................................................................. $ 24,707 $ 38,222
Accrued liabilities............................................................... 10,824 10,696
Revenues payable.................................................................. 11,109 10,940
Fixed-price contracts and other derivatives....................................... 13,552 2,292
---------- ----------
Total current liabilities...................................................... 60,192 62,150
---------- ----------
LONG-TERM DEBT.................................................................... 629,637 596,844
---------- ----------
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred revenue.................................................................. 14,571 15,551
Deferred income taxes............................................................. 42,886 65,116
Fixed-price contracts and other derivatives....................................... 15,882 5,350
Other............................................................................. 20,604 19,336
---------- ----------
93,943 105,353
---------- ----------
STOCKHOLDERS' EQUITY
Preferred stock, par value $.01; 10 million shares authorized; no shares
outstanding.................................................................... -- --
Common stock, par value $.01; 100 million shares authorized; issued and
outstanding, 40,138,508 and 40,109,758 shares, respectively.................... 401 401
Additional paid-in capital........................................................ 419,490 419,075
Retained earnings................................................................. 9,741 6,735
Accumulated other comprehensive income ........................................... 53,659 93,250
---------- ----------
483,291 519,461
---------- ----------
$1,267,063 $1,283,808
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---------- ----------
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
Page 3 of 23
LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
(IN THOUSANDS, EXCEPT PER SHARE DATA)
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
-------------------- ---------------------
1999 1998 1999 1998
------- -------- -------- --------
(RESTATED) (RESTATED)
REVENUES
Oil and gas sales............................................ $70,306 $ 69,481 $128,461 $137,395
Change in derivative fair value.............................. (2,488) -- 1,197 --
Other income................................................. 251 870 2,194 2,552
------- -------- -------- --------
68,069 70,351 131,852 139,947
------- -------- -------- --------
EXPENSES
Operating costs.............................................. 15,860 17,044 31,453 34,065
General and administrative................................... 5,803 6,336 11,618 12,539
Exploration costs............................................ 2,213 9,360 6,152 16,940
Depreciation, depletion and amortization 29,070 34,250 57,200 66,291
Impairment................................................... -- 9,864 -- 9,864
Interest..................................................... 10,233 10,372 20,247 20,418
------- -------- -------- --------
63,179 87,226 126,670 160,117
------- -------- -------- --------
Income (loss) before income taxes............................ 4,890 (16,875) 5,182 (20,170)
Income tax provision (benefit)............................... 2,042 (6,484) 2,176 (7,736)
------- -------- -------- --------
NET INCOME (LOSS)............................................ $ 2,848 $(10,391) $ 3,006 $(12,434)
------- -------- -------- --------
------- -------- -------- --------
Net income (loss) per share - basic and diluted.............. $ .07 $ (.26) $ .07 $ (.31)
------- -------- -------- --------
------- -------- -------- --------
Weighted average diluted common shares....................... 40,414 40,110 40,268 40,104
------- -------- -------- --------
------- -------- -------- --------
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
Page 4 of 23
LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (UNAUDITED) (RESTATED)
(IN THOUSANDS)
ACCUMULATED
ADDITIONAL OTHER TOTAL
COMMON PAID-IN RETAINED COMPREHENSIVE STOCKHOLDERS'
STOCK CAPITAL EARNINGS INCOME EQUITY
------ ---------- -------- ------------- -------------
BALANCE AT DECEMBER 31, 1998 ............. $ 401 $419,075 $ 6,735 $ 93,250 $519,461
Exercise of stock options ................ -- 415 -- -- 415
--------
Sub-total ............................. -- -- -- -- 519,876
--------
Comprehensive loss:
Net income ............................... -- -- 3,006 -- 3,006
Other comprehensive loss, net of tax:
Reclassification adjustments - contract
settlements ......................... -- -- -- (5,030) (5,030)
Change in fixed-price contract and
other derivative fair value ......... -- -- -- (34,561) (34,561)
--------
Total comprehensive loss ................. -- -- -- -- (36,585)
------ -------- ------- -------- --------
BALANCE AT JUNE 30, 1999 ................. $ 401 $419,490 $ 9,741 $ 53,659 $483,291
------ -------- ------- -------- --------
------ -------- ------- -------- --------
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
Page 5 of 23
LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(IN THOUSANDS)
SIX MONTHS ENDED
JUNE 30,
-----------------------
1999 1998
--------- ---------
(RESTATED)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)........................................ $ 3,006 $ (12,434)
Items not affecting cash flows:
Depreciation, depletion and amortization.............. 57,200 66,291
Impairment............................................ -- 9,864
Deferred income taxes................................. 2,036 (8,286)
Exploration costs..................................... 6,152 16,940
Change in derivative fair value....................... (1,197) --
Other................................................. (111) 242
Net change in operating assets and liabilities:
Accounts receivable................................... 4,261 26,442
Prepaids and other.................................... 2,289 5,973
Accounts payable...................................... (13,515) (12,196)
Accrued liabilities................................... 128 (5,615)
Revenues payable...................................... 169 (2,135)
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60,418 85,086
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CASH FLOWS FROM INVESTING ACTIVITIES
Exploration and development expenditures................. (59,457) (138,333)
Acquisition of oil and gas properties.................... (30,409) (4,575)
Additions to other property and equipment................ (976) (1,658)
Proceeds from sale of property and equipment............. 7,034 565
Change in other assets................................... (143) (241)
--------- ---------
(83,951) (144,242)
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CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from bank borrowings............................ 240,369 329,514
Repayments of bank borrowings............................ (207,569) (306,014)
Proceeds from stock options exercised.................... 415 324
Change in deferred revenue............................... (980) (888)
Change in gains from price-risk management activities.... (2,249) 39,549
Change in other long-term liabilities.................... (1,009) (2,717)
--------- ---------
28,977 59,768
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Change in cash and cash equivalents...................... 5,444 612
Cash and cash equivalents, beginning of period........... 2,539 5,538
--------- ---------
Cash and cash equivalents, end of period................. $ 7,983 $ 6,150
--------- ---------
--------- ---------
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Interest paid, net of capitalized interest............... $ 19,479 $ 17,904
Income taxes paid........................................ 285 250
--------- ---------
$ 19,764 $ 18,154
--------- ---------
--------- ---------
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
Page 6 of 23
LOUIS DREYFUS NATURAL GAS CORP.
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
JUNE 30, 1999
NOTE 1 -- ACCOUNTING PRINCIPLES AND BASIS OF PRESENTATION
The accompanying unaudited consolidated financial statements have been
prepared in accordance with the instructions to Form 10-Q as prescribed by
the Securities and Exchange Commission. All material adjustments, consisting
of only normal and recurring adjustments, which, in the opinion of
Management, were necessary for a fair presentation of the results for the
interim periods have been reflected. The results of operations for the
three-month and six-month periods ended June 30, 1999 are not necessarily
indicative of the results to be expected for the full year. Certain
reclassifications have been made to the prior year statements to conform with
the current year presentation. Reference is made to the Company's Annual
Report on Form 10-K, as amended, for the year ended December 31, 1998 for an
expanded discussion of the Company's financial disclosures and accounting
policies.
NOTE 2 -- RESTATED FINANCIAL STATEMENTS
Pursuant to the provisions of SFAS 133, all hedging designations and the
methodology for determining hedge ineffectiveness must be documented at the
inception of the hedge, and, upon the initial adoption of the standard,
hedging relationships must be designated anew. The documentation must also
indicate the risk management intent for entering into the hedging
arrangement. The Company believed that it complied with the spirit and intent
of the provisions of the standard with respect to documentation. However, in
connection with the review of the Company's public filings by the Staff of
the Securities and Exchange Commission in September 1999, the Company's
documentation was found to be insufficient as of the October 1, 1998 date of
adoption of SFAS 133. Therefore, the Company was precluded from being able to
utilize the special provisions of hedge accounting for the fourth quarter of
1998, and the period from January 1, 1999 to January 13, 1999, the date the
Company's documentation was sufficient in relation to the formal
documentation requirements of the standard. As a result, the changes in fair
value of all of the Company's derivatives during these periods were required
to be reported in results of operations, rather than in other comprehensive
income. The accompanying financial statements as of June 30, 1999, and for
the three-month and six-month periods then ended, have been restated to
reflect this change in accounting. The effect of the restatement is provided
below.
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, 1999 JUNE 30, 1999
------------------------ -----------------------
AS AS
AS PREVIOUSLY AS PREVIOUSLY
RESTATED REPORTED RESTATED REPORTED
-------- ---------- -------- ----------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
STATEMENT OF OPERATIONS DATA:
Change in derivative fair value ............... $ (2,488) $ (2,488) $ 1,197 $ (5,038)
Total revenues ................................ 68,069 68,069 131,852 125,617
Interest expense .............................. 10,233 10,267 20,247 20,315
Total expenses ................................ 63,179 63,213 126,670 126,738
Income (loss) before income taxes ............. 4,890 4,856 5,182 (1,121)
Income tax provision (benefit) ................ 2,042 1,322 2,176 (471)
Net income (loss) ............................. 2,848 3,534 3,006 (650)
Net income (loss) per share - basic and
diluted...................................... .07 .09 .07 (.02)
AS OF JUNE 30, 1999
-----------------------
AS
AS PREVIOUSLY
RESTATED REPORTED
-------- ----------
(IN THOUSANDS)
BALANCE SHEET DATA:
Long-term debt............................................................. $629,637 $628,964
Deferred income taxes...................................................... 42,886 42,890
Total deferred credits and other
liabilities.............................................................. 93,943 93,947
Retained earnings (deficit)................................................ 9,741 (3,185)
Accumulated other comprehensive income..................................... 53,659 67,254
Total stockholders' equity................................................. 483,291 483,960
Page 7 of 23
LOUIS DREYFUS NATURAL GAS CORP.
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (CONTINUED)
JUNE 30, 1999
NOTE 3 -- HEDGING
In October 1998, the Company adopted Statement of Financial Accounting
Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities" ("SFAS 133") which establishes new accounting and reporting
guidelines for derivative instruments and hedging activities. It requires
that all derivative instruments be recognized as assets or liabilities in the
statement of financial position, measured at fair value. The accounting for
changes in the fair value of a derivative depends on the intended use of the
derivative and the resulting designation. Designation is established at the
inception of a derivative, but redesignation is permitted. For derivatives
designated as cash flow hedges, changes in fair value are recognized in other
comprehensive income until the hedged item is recognized in earnings. Hedge
effectiveness is measured at least quarterly based on the relative changes in
fair value between the derivative contract and the hedged item over time. Any
change in fair value resulting from ineffectiveness, as defined by SFAS 133,
is recognized immediately in earnings. Effective January 13, 1999,
substantially all of the Company's Fixed-Price Contracts and interest rate
swaps are designated as cash flow hedges. See Note 2 -- Restated Financial
Statements. Changes in the fair value of derivative instruments which are not
designated as hedges, do not qualify as cash flow hedges due to
ineffectiveness, or are defined by SFAS 133 as being "fair value hedges," are
recorded in earnings as the changes occur. Earnings for the three-months and
six-months ended June 30, 1999 included net charges of $2.1 million and $3.6
million, respectively, relating to changes in fair value for Fixed-Price
Contracts not qualifying as cash flow hedges and $.4 million and $1.4
million, respectively of net charges relating to Fixed-Price Contract hedge
ineffectiveness. In addition, earnings include a $6.2 million gain
attributable to an increase in derivative fair value from January 1, 1999
through January 13, 1999.
NOTE 4 -- ACQUISITIONS
In late March 1999, the Company acquired additional working interests in
three offshore platforms for $20.5 million. The acquired interests included
21.4 Bcfe of proved reserves, approximately 90% of which were natural gas
reserves. Oil and gas production from the acquired properties at March 31,
1999 was approximately 17 MMcfe per day. In May 1999, the Company acquired
interests in six producing Lower Wilcox wells located in Lavaca County,
Texas, for $9 million. The acquired properties currently produce 3.5 MMcfe
per day of oil and natural gas with estimated proved reserves of 12 Bcfe. The
purchase method was used to account for both acquisitions.
NOTE 5 -- CONTINGENCIES
LITIGATION. On December 22, 1995, the United States District Court for
the Western District of Oklahoma entered a $10.8 million judgment in favor of
the Company against Midcon Offshore, Inc. ("Midcon") in connection with
non-performance by Midcon under an agreement to purchase a certain offshore
oil and gas property. In January 1996, Midcon delivered a $10.8 million
promissory note to the Company secured by first and second liens on assets of
Midcon, payable in full on or before December 15, 1996 in settlement of
disputes in connection with this litigation. On December 16, 1996, Midcon
filed for protection from its creditors under Chapter 11 of the United States
Bankruptcy Code in the United States Bankruptcy Court, Southern District of
Texas, Corpus Christi Division. On January 27, 1997, Midcon filed an action
in the bankruptcy court alleging that Midcon's action in connection with the
settlement constituted fraudulent transfers or avoidable preferences and
seeking a return of $1.7 million paid under the note and also seeking a
release of the liens securing the payment obligation under the note. The
complaint filed in the action also alleged certain affirmative claims against
the Company including injury to reputation and loss of business opportunity.
On July 23, 1999, an agreement was reached between the Company and certain
parties in interest to the Midcon bankruptcy case, including the Trustee and
the Official Unsecured Creditors Committee. The terms of the agreement
provide for the payment of $8.6 million to the Company in satisfaction of its
claims against the estate. The settlement amount is subject to approval of
the bankruptcy court, which has set a hearing date for this matter on August
18, 1999. If approved by the court, the Company would be entitled to receive
these funds ten days after the related order is entered. This potential
receipt of funds would be reflected in earnings and operating cash flows in
the quarter when receipt of the funds is no longer uncertain. No amounts have
been recorded with respect thereto in the accompanying financial statements
as of June 30, 1999.
Page 8 of 23
LOUIS DREYFUS NATURAL GAS CORP.
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (CONTINUED)
JUNE 30, 1999
In February 1995, a lawsuit was filed in the United States District
Court in Denver, Colorado, by KN Gas Supply Services, Inc. ("KNGSS"),
requesting declaratory judgment that KNGSS had the right to reduce the
contract price for gas produced from the Bowdoin Field, a property acquired
by the Company in 1997, to market levels from October 1, 1993 forward. KNGSS
alleged that it was entitled to a refund of approximately $7.7 million for
the period through September 1996. KNGSS has not updated its refund claim
through the present date. A motion for summary judgment was filed by a
predecessor to the Company in July 1996 and in February 1998, the court ruled
in favor of the Company and against KNGSS. KNGSS subsequently filed an appeal
which is scheduled to be heard in September 1999. Although the Company cannot
predict the ultimate outcome of this proceeding, it will continue to
vigorously defend its interests in this case and does not expect the outcome
of the case to have a material adverse impact on its financial position or
results of operations.
The Company was also a party to other litigation as of June 30, 1999.
The more significant of such legal claims was an alleged underpayment of
royalty of $5.5 million plus interest, and preliminary and final royalty
underpayment determinations from the Minerals Management Service aggregating
approximately $2.1 million plus interest. The Company is a defendant in
additional pending legal proceedings which are routine and incidental to its
business. While the ultimate results of all these proceedings and
determinations cannot be predicted with certainty, the Company will
vigorously defend its interests and does not believe that the outcome of
these matters will have a material adverse effect on the Company.
FIXED-PRICE CONTRACTS. The Company is a party to a long-term natural gas
physical delivery contract with an independent power producer ("IPP") which
sells electrical power under a firm, fixed-price contract to Niagra Mohawk
Corporation ("NIMO"), a New York state utility. The ability of this IPP to
perform its obligations to the Company is dependent on the continued
performance by NIMO of its power purchase obligations to the IPP. NIMO has
taken aggressive regulatory, judicial and contractual actions to curtail
power purchase obligations from IPPs generally, and in July 1997, NIMO
entered into a Master Restructuring Agreement (the "MRA") with a number of
similarly situated IPPs to settle or restructure obligations with them. As a
result, the Company terminated a Fixed-Price Contract with one of these
settling parties and received a termination payment of $40.1 million in June
1998. This termination amount has been recorded in accumulated other
comprehensive income, net of tax effect. However, the IPP with whom the
Company still has a contract did not participate in the MRA. This contract
which hedges 51 Bcf of natural gas as of June 30, 1999 remains in force and
is reflected in the Company's balance sheet at a fair value of $62.0 million.
The Company continues to deliver natural gas pursuant to the terms of this
contract which expires in 2007. NIMO has continued to seek relief from its
contractual obligations under its contract with the IPP in the court system,
most recently in a trial in a United States District court. A decision from
this trial is expected in the fall of 1999. If NIMO is successful in these
efforts, it could have an adverse effect on the ability of the IPP to
continue to perform its obligations to the Company and could materially
impair the value of the Company's natural gas contract. Although there can be
no assurance, Management does not expect that NIMO will ultimately succeed in
these efforts.
Page 9 of 23
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
OVERVIEW
GENERAL. The Company's business strategy is to generate strong and
consistent growth in reserves, production, operating cash flows and earnings
through a balanced program of exploration and development drilling and
strategic acquisitions of oil and gas properties. The Company's activities
are geographically concentrated in its core areas: the Permian Region of West
Texas, Southeast New Mexico and the San Juan Basin; the Mid-Continent Region
of Oklahoma, Kansas and the Panhandle of Texas; and the Gulf Coast Region,
which includes South Texas, Offshore Gulf of Mexico, East Texas, Southwest
Arkansas and Northern Louisiana (collectively "Core Areas"), where the
Company has significant expertise and where the Company benefits from
operational synergies. The Company's capital expenditure plans for 1999
include the investment of approximately $170 million in these Core Areas. See
"-- Commitments and Capital Expenditures."
The Company has a portfolio of fixed-price contracts comprised of
long-term physical delivery contracts, energy swaps, collars, futures
contracts, basis swaps and option agreements (collectively "Fixed-Price
Contracts"). As of June 30, 1999, the Company's Fixed-Price Contracts hedged
243 Bcf of future gas production representing 20% of its estimated proved
natural gas reserves at December 31, 1998, at escalating fixed prices. These
average fixed prices are presently significantly higher than the forward
market prices for natural gas. See "Quantitative and Qualitative Disclosures
About Market Risk."
FORWARD-LOOKING STATEMENTS. All statements in this document concerning
the Company other than purely historical information (collectively
"Forward-Looking Statements") reflect the current expectations of management
and are based on the Company's historical operating trends, its proved
reserve and Fixed-Price Contract positions and other information currently
available to management. Such Forward-Looking Statements include, among
others, statements regarding the Company's future drilling plans and
objectives and related exploration and development budgets, and number and
location of planned wells, and statements regarding the quality of the
Company's properties and potential reserve and production levels. These
statements assume, among other things, that no significant changes will occur
in the operating environment for the Company's oil and gas properties and
that there will be no material acquisitions or divestitures except as
disclosed herein. The Company cautions that the Forward-Looking Statements
are subject to all the risks and uncertainties incident to the acquisition,
development and marketing of, and exploration for, oil and gas reserves.
These risks include, but are not limited to, commodity price risks,
counterparty risks, environmental risks, drilling risks, reserve risks, and
operations and production risks. Certain of these risks are described herein
and in the Company's Annual Report on Form 10-K, as amended, for the year
ended December 31, 1998. Moreover, the Company may make material acquisitions
or divestitures, modify its Fixed-Price Contract positions by entering into
new contracts or terminating existing contracts, or entering into financing
transactions. None of these can be predicted with certainty and, accordingly,
are not taken into consideration in the Forward-Looking Statements made
herein. Statements concerning Fixed-Price Contract, interest rate swap and
other financial instrument fair values and their estimated contribution to
future results of operations are based upon market information as of a
specific date. Such market information in certain cases is a function of
significant judgment and estimation. For all of the foregoing reasons, actual
results may vary materially from the Forward-Looking Statements and there is
no assurance that the assumptions used are necessarily the most likely. The
Company expressly disclaims any obligation or undertaking to release publicly
any updates regarding any changes in the Company's expectations with regard
to the subject matter of any Forward-Looking Statements or any changes in
events, conditions or circumstances on which any Forward-Looking Statements
are based.
CERTAIN DEFINITIONS. As used herein, the abbreviations listed below are
defined as follows:
BBL. One stock tank barrel, or 42 U.S. gallons liquid volume, used
herein in reference to oil or other liquid hydrocarbons.
BCF. Billion cubic feet.
BCFE. Billion cubic feet of natural gas equivalent, determined using the
ratio of one Bbl of oil or condensate to six Mcf of natural gas.
BBTU. Billion Btus.
BTU. British thermal unit, which is the heat required to raise the
temperature of a one-pound mass of water from 58.5 to 59.5 degrees
Fahrenheit.
MBBLS. Thousand barrels.
MCF. Thousand cubic feet.
MCFE. Thousand cubic feet of natural gas equivalent, determined using the
ratio of one Bbl of oil or condensate to six Mcf
Page 10 of 23
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (CONTINUED)
of natural gas.
MMBBLS. Million barrels.
MMBTU. Million Btus.
MMCF. Volume of one million cubic feet.
MMCFE. Million cubic feet of natural gas equivalent, determined using the
ratio of one Bbl of oil or condensate to six Mcf of natural gas.
TBTU. One trillion Btus.
SELECTED OPERATING DATA. The following table provides certain operating
data relating to the Company's operations.
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
--------------------- --------------------
1999 1998 1999 1998
-------- -------- -------- -------
OIL AND GAS SALES: (M$)
Wellhead oil sales .......................................... $ 11,800 $ 11,541 $ 20,028 $ 23,026
Effect of Fixed-Price Contract settlements (1) .............. -- -- -- 496
-------- -------- -------- --------
Total oil sales ............................................. $ 11,800 $ 11,541 $ 20,028 $ 23,522
-------- -------- -------- --------
-------- -------- -------- --------
Wellhead natural gas sales .................................. $ 55,801 $ 54,211 $ 98,317 $106,546
Effect of Fixed-Price Contract settlements (1) .............. 2,705 3,729 10,116 7,327
-------- -------- -------- --------
Total natural gas sales ..................................... $ 58,506 $ 57,940 $108,433 $113,873
-------- -------- -------- --------
-------- -------- -------- --------
PRODUCTION:
Oil production (MBbls) ...................................... 760 913 1,502 1,738
Natural gas production (MMcf) ............................... 26,625 24,989 52,093 49,943
Net equivalent production (MMcfe) ........................... 31,183 30,468 61,105 60,371
Percent of oil production hedged by Fixed-Price
Contracts (%).............................................. 0% 0% 0% 5%
Percent of gas production hedged by Fixed-Price
Contracts (%).............................................. 72% 46% 54% 46%
AVERAGE SALES PRICE:
Oil price (per Bbl):
Wellhead price ............................................ $ 15.53 $ 12.64 $ 13.33 $ 13.25
Effect of Fixed-Price Contract settlements (1) ............ -- -- -- .28
-------- -------- -------- --------
Total ..................................................... $ 15.53 $ 12.64 $ 13.33 $ 13.53
-------- -------- -------- --------
-------- -------- -------- --------
Natural gas price (per Mcf):
Wellhead price ............................................ $ 2.10 $ 2.17 $ 1.89 $ 2.13
Effect of Fixed-Price Contract settlements (1) ............ .10 .15 .19 .15
-------- -------- -------- --------
Total ..................................................... $ 2.20 $ 2.32 $ 2.08 $ 2.28
-------- -------- -------- --------
-------- -------- -------- --------
Average sales price (per Mcfe) .............................. $ 2.25 $ 2.28 $ 2.10 $ 2.28
OPERATING AND OVERHEAD COSTS: (per Mcfe)
Lease operating expenses .................................... $ .40 $ .45 $ .41 $ .45
Production taxes ............................................ .11 .11 .10 .11
General and administrative .................................. .19 .21 .19 .21
-------- -------- -------- --------
Total ....................................................... $ .70 $ .77 $ .70 $ .77
-------- -------- -------- --------
-------- -------- -------- --------
CASH OPERATING MARGIN (per Mcfe) ............................ $ 1.55 $ 1.51 $ 1.40 $ 1.51
DEPRECIATION, DEPLETION AND AMORTIZATION - OIL AND GAS ...... $ .89 $ 1.08 $ .89 $ 1.05
- -------------------------
(1) - Represents the hedging results from the Company's Fixed-Price Contracts.
See "Quantitative and Qualitative Disclosures About Market Risk -
Fixed-Price Contracts." These amounts do not include any change in
derivative fair value included in results of operations for the respective
period.
Page 11 of 23
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (CONTINUED)
RESULTS OF OPERATIONS -- THREE MONTHS ENDED JUNE 30, 1999 COMPARED TO THREE
MONTHS ENDED JUNE 30, 1998
NET INCOME AND CASH FLOWS FROM OPERATING ACTIVITIES. For the quarter
ended June 30, 1999, the Company realized net income of $2.8 million, or $.07
per share, on total revenue of $68.1 million. This compares to a net loss of
$10.4 million, or $.26 per share, on total revenue of $70.4 million for the
second quarter of 1998. Cash flows from operating activities (before working
capital changes) for the second quarter of 1999 grew 5% to $38.5 million
compared to $36.5 million for the second quarter of 1998. Growth in total
production and lower cash expenses were the principal reasons for the
increase in operating cash flows, more than offsetting the effects of lower
average oil and gas prices for the current year period. Results of operations
for the quarter ended June 30, 1999 were enhanced by improved lease operating
and overhead costs on a unit of production basis and lower exploration costs
and oil and gas depletion. Cash flows provided by operating activities after
consideration of the net change in working capital decreased to $27.5 million
from the $55.8 million reported for the second quarter of 1998, primarily due
to an increase in accounts receivable and a decrease in accounts payable.
PRODUCTION. The Company produced 31.2 Bcfe for the second quarter of
1999 compared to 30.5 Bcfe for the prior year second quarter, an increase of
2%. Gas production increased to 26.6 Bcf compared to 25.0 Bcf for the second
quarter of 1998, an increase of 7%. Oil production for the second quarter of
1999 decreased 17% to 760 MBbls compared to 913 MBbls for the prior-year
second quarter.
OIL AND GAS PRICES. On a natural gas equivalent basis, the Company
received an average price of $2.25 per Mcfe for the quarter ended June 30,
1999, a decrease of 1% from the $2.28 per Mcfe received for the second
quarter of 1998. The Company's gas production yielded an average price of
$2.20 per Mcf, a decrease of 5% compared to $2.32 per Mcf for the prior-year
second quarter. The Company's average gas price for the 1999 second quarter
was enhanced $.10 per Mcf as a result of the Company's hedging activities.
The average gas price for the second quarter of 1998 increased $.15 per Mcf
as a result of the Fixed-Price Contracts in effect for that period. The
average oil price for the second quarter of 1999 was $15.53 per Bbl an
increase of 23% from the $12.64 per Bbl received for the prior-year second
quarter. No fixed-price oil contracts were in effect during the second
quarter of 1999 or 1998.
The net effect of higher gas production and lower gas prices increased
gas sales to $58.5 million for the second quarter of 1999 compared to $57.9
million for the second quarter of 1998. The net effect of higher oil prices
and lower oil production increased oil sales to $11.8 million compared to
$11.5 million reported for the prior-year quarter. The impact of the
Company's Fixed-Price Contract settlements for each period was to increase
gas sales by $2.7 million for the quarter ended June 30, 1999 and to increase
gas sales by $3.7 million for the quarter ended June 30, 1998. See
"Quantitative and Qualitative Disclosures About Market Risk."
CHANGE IN DERIVATIVE FAIR VALUE. The Company adopted SFAS 133 in October
1998. Pursuant to this standard, the changes in fair value of certain of the
Company's derivative contracts and the ineffective portion of any cash flow
hedge are reflected in earnings as the changes occur. These changes in fair
value resulted in a $2.5 million non-cash charge for the second quarter of
1999. Results of operations will continue to be affected by changes in fair
value for these contracts, the amount and timing of which cannot be
predicted. See "Quantitative and Qualitative Disclosures About Market Risk."
OTHER INCOME. Other income for the second quarter of 1999 was $.3
million, a modest decline compared to $.9 million for the second quarter of
1998.
OPERATING COSTS. Operating costs for the second quarter of 1999 were
comprised of $12.3 million of lease operating expenses and $3.5 million of
production taxes. This compares to $13.8 million of lease operating expenses
and $3.3 million of production taxes for the second quarter of 1998. The
decrease in lease operating expenses is principally attributable to improved
operating efficiencies in the field and to a reduction in costs for services
and materials. Lease operating expenses on a natural gas equivalent unit of
production basis decreased to $.40 per Mcfe for the three months ended June
30, 1999 compared to $.45 for the three months ended June 30, 1998.
GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative expense
("G&A") for the second quarter of 1999 was $5.8 million, a decrease of 8%
from the prior-year second quarter amount of $6.3 million. This decrease is
Page 12 of 23
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (CONTINUED)
primarily attributable to cost reduction measures implemented by the Company
in the first quarter of 1999. On a natural gas equivalent unit of production
basis, G&A decreased to $.19 per Mcfe for the 1999 second quarter compared to
$.21 per Mcfe for the 1998 second quarter.
EXPLORATION COSTS. Exploration costs, comprised of geological and
geophysical costs, exploratory dry holes and leasehold impairment costs, were
$2.2 million for the quarter ended June 30, 1999, compared to $9.4 million
for the second quarter of 1998. The 1999 amount consists of $.6 million of
dry hole costs, $.5 million of seismic acquisition and other geological and
geophysical costs and $1.1 million of leasehold costs. The 1998 amount
consists of $5.0 million of dry hole costs, $2.4 million of seismic
acquisition costs and other geological and geophysical costs and $2.0 million
of leasehold costs.
DEPRECIATION, DEPLETION AND AMORTIZATION. Depreciation, depletion and
amortization ("DD&A") for the second quarter of 1999 was $29.1 million
compared to $34.3 million for the prior-year second quarter. This decrease in
DD&A is attributable to a decrease in the oil and gas DD&A rate. The oil and
gas DD&A rate per equivalent unit of production was $.89 for the 1999 second
quarter compared to $1.08 for the second quarter of 1998. This decrease was
primarily the result of 1998 reserve additions added at favorable finding and
development costs and to a $42.7 million impairment charge taken in the
fourth quarter of 1998.
IMPAIRMENT. There was no impairment charge recorded for the second
quarter of 1999. For the quarter ended June 30, 1998, the Company recorded an
impairment charge of $9.9 million in connection with an impairment review
conducted in response to a significant decline in oil prices. This review
identified one offshore field which had a net book value in excess of
estimated future net revenues for the field, which resulted in the impairment
charge.
INTEREST EXPENSE. Interest expense for the second quarter of 1999 was
$10.2 million compared to $10.4 million for the second quarter of 1998. The
net impact of interest rate swaps in effect for the second quarter of 1999
and 1998 was not material. See "Capital Resources and Liquidity - Credit
Facility."
INCOME TAXES. For the second quarter of 1999, the Company recorded a tax
provision of $2.0 million on pretax income of $4.9 million, an effective rate
of 42%. This compares to a tax benefit of $6.5 million on pretax loss of
$16.9 million, an effective rate of 38%, for the second quarter of 1998.
RESULTS OF OPERATIONS -- SIX MONTHS ENDED JUNE 30, 1999 COMPARED TO SIX
MONTHS ENDED JUNE 30, 1998
NET INCOME AND CASH FLOWS FROM OPERATING ACTIVITIES. The Company
realized net income of $3.0 million, or $.07 per share, on total revenue of
$131.9 million for the six months ended June 30, 1999. This compares with a
net loss of $12.4 million, or $.31 per share, on total revenue of $139.9
million for the six months ended June 30, 1998. Cash flows from operating
activities (before working capital changes) for the first six months of 1999
were $67.1 million, compared to $72.6 million for the first six months of
1998, a decrease of 8%. The decline in operating cash flows for the current
year six-month period was primarily the result of lower oil and gas prices in
relation to those received for the first six months of 1998. This price
decline was partially offset by a 9% improvement in lease operating and
overhead costs on a unit of production basis. Reductions in exploration
costs, oil and gas depletion and impairment expense were the principal
reasons for the improvement in current period operating results. Cash flows
provided by operating activities after consideration of the net change in
working capital decreased to $60.4 million from the $85.1 million reported
for the second quarter of 1998, primarily due to lower oil and gas prices
discussed above and a smaller decrease in accounts receivable relative to the
comparable period of 1998.
PRODUCTION. The Company's total production was 61.1 Bcfe for the first
six months of 1999 compared to 60.4 Bcfe for the comparable prior-year
period, an increase of 1%. Gas production increased to 52.1 Bcf compared to
49.9 Bcf for the first half of 1998, an increase of 4%. Oil production for
the first six months of 1999 decreased 14% to 1.5 MMBbls compared to 1.7
MMBbls for the first six months of 1998.
OIL AND GAS PRICES. On a natural gas equivalent basis, the Company
received an average price of $2.10 per Mcfe for the first six months of 1999,
a decrease of 8% from the $2.28 per Mcfe received for the first six months of
1998.
Page 13 of 23
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (CONTINUED)
The Company's gas production yielded an average price of $2.08 per Mcf, a
decrease of 9% compared to $2.28 per Mcf for the prior-year six-month period.
The Company's average gas price for the first six months of 1999 was enhanced
$.19 per Mcf as a result of the Company's hedging activities. The average gas
price for the first six months of 1998 was enhanced $.15 per Mcf as a result
of the Fixed-Price Contracts in effect for that period. The average oil price
for the first half of 1999 was $13.33 per Bbl compared to $13.53 per Bbl for
the first half of 1998, a decline of 1%. No fixed-price oil contracts were in
effect during the current year six-month period. Fixed-Price Contracts in
effect during the prior-year six-month period increased the average oil price
by $.28 per Bbl.
The net effect of higher gas production and lower gas prices decreased
gas sales to $108.4 million for the first six months of 1999 compared to
$113.9 million for the first six months of 1998. The combination of lower oil
production and lower oil prices decreased oil sales to $20.0 million compared
to $23.5 million reported for the prior-year six-month period. The impact of
the Company's Fixed-Price Contract settlements for each period was to
increase oil and gas sales by $10.1 million for the six months ended June 30,
1999 and to increase oil and gas sales by $7.8 million for the six months
ended June 30, 1998. See "Quantitative and Qualitative Disclosures About
Market Risk."
CHANGE IN DERIVATIVE FAIR VALUE. Pursuant to the provisions of SFAS 133,
all hedging designations and the methodology for determining hedge
ineffectiveness must be documented at the inception of the hedge, and, upon
the initial adoption of the standard, hedging relationships must be
designated anew. The documentation must also indicate the risk management
intent for entering into the hedging arrangement. The Company believed that
it complied with the spirit and intent of the provisions of the standard with
respect to documentation. However, in connection with the review of the
Company's public filings by the Staff of the Securities and Exchange
Commission in September 1999, the Company's documentation was found to be
insufficient as of the October 1, 1998 date of adoption of SFAS 133.
Therefore, the Company was precluded from being able to utilize the special
provisions of hedge accounting for the fourth quarter of 1998, and the period
from January 1, 1999 to January 13, 1999, the date the Company's
documentation was sufficient in relation to the formal documentation
requirements of the standard. As a result, the changes in fair value of all
of the Company's derivatives during these periods were required to be
reported in results of operations, rather than in other comprehensive income.
The accompanying financial statements as of June 30, 1999, and for the
three-month and the six-month periods then ended, have been restated to
reflect this change in accounting. The effect of the restatement was to
decrease reported results of operations by $.7 million for the three months
ended June 30, 1999 and to increase reported results of operations by $3.7
million for the six months ended June 30, 1999. Change in derivative fair
value for the six months ended June 30, 1999 reflected a $6.2 million pretax
gain attributable to the change in contract fair value occurring between
January 1, 1999 and January 13, 1999.
Pursuant to this standard, the changes in fair value of certain of the
Company's derivative contracts and the ineffective portion of any cash flow
hedge are reflected in earnings as the changes occur. These changes in fair
value resulted in a $5.0 million non-cash charge for the six months ended
June 30, 1999, partially offsetting the $6.2 million gain described above.
Results of operations will continue to be affected by changes in fair value
for these contracts, the amount and timing of which cannot be predicted. See
"Quantitative and Qualitative Disclosures About Market Risk."
OTHER INCOME. Other income for the first six months of 1999 was $2.2
million, a modest decline compared to $2.6 million for the first six months
of 1998.
OPERATING COSTS. Operating costs for the first six months of 1999 were
comprised of $25.3 million of lease operating expenses and $6.1 million of
production taxes. This compares to $27.2 million of lease operating expenses
and $6.9 million of production taxes for the first six months of 1998. The
decrease in lease operating expenses is principally attributable to improved
operating efficiencies in the field and to a reduction in costs for services
and materials. Lease operating expenses on a natural gas equivalent unit of
production basis improved to $.41 per Mcfe compared to $.45 per Mcfe for the
six months ended June 30, 1998. The decrease in production taxes is primarily
the result of lower oil and gas prices in the first six months of 1999.
GENERAL AND ADMINISTRATIVE EXPENSE. G&A for the first six months of 1999
was $11.6 million compared to $12.5 million for the comparable prior-year
period. This decrease is primarily attributable to cost reduction measures
Page 14 of 23
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (CONTINUED)
implemented by the Company in the first quarter of 1999. On a natural gas
equivalent unit of production basis, G&A decreased to $.19 per Mcfe for the
first six months of 1999 compared to $.21 per Mcfe for the first six months
of 1998.
EXPLORATION COSTS. Exploration costs, comprised of geological and
geophysical costs, exploratory dry holes and leasehold impairment costs, were
$6.2 million for the six months ended June 30, 1999, compared to $16.9
million for the six months ended June 30, 1998. The 1999 amount consists of
$1.1 million of dry hole costs, $1.3 million of seismic acquisition and other
geological and geophysical costs and $3.8 million of leasehold costs. The
1998 amount consists of $8.4 million of dry hole costs, $6.2 million of
seismic acquisition and other geological and geophysical costs and $2.3
million of leasehold costs.
DEPRECIATION, DEPLETION AND AMORTIZATION. DD&A for the first half of
1999 was $57.2 million compared to $66.3 million for the first half of 1998.
This decrease in DD&A is attributable to a decrease in the oil and gas DD&A
rate. The oil and gas DD&A rate per equivalent unit of production was $.89
for the first six months of 1999 compared to $1.05 for the first six months
of 1998. This decrease was primarily the result of 1998 reserve additions
added at favorable finding and development costs and to a $42.7 million
impairment charge taken in the fourth quarter of 1998.
IMPAIRMENT. There was no impairment charge recorded for the first six
months of 1999. For the six month period ended June 30, 1998, the Company
recorded an impairment charge of $9.9 million as a result of an impairment
review conducted in response to a significant decline in oil prices for such
period. This review identified one offshore field which had a net book value
in excess of estimated future net revenues for the field, which resulted in
the impairment charge.
INTEREST EXPENSE. Interest expense for the six months ended June 30,
1999 was $20.2 million compared to $20.4 million for the six months ended
June 30, 1998. The net impact of interest rate swaps in effect for the first
six months of 1999 and 1998 was immaterial. See "Capital Resources and
Liquidity - Credit Facility."
INCOME TAXES. For the first half of 1999 the Company recorded a tax
provision of $2.2 million on pretax income of $5.2 million, an effective rate
of 42%. This compares to a tax benefit of $7.7 million provided on a pretax
loss of $20.2 million, an effective rate of 38%, for the first half of 1998.
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 six months ended June 30, 1999 and
1998, the Company expended $89.9 million and $142.9 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 six-month periods. See "Commitments and Capital Expenditures."
Certain of these investments include expenditures which under successful
efforts accounting are expensed as incurred or if unsuccessful in discovering
new reserves. Investing activities for the six months ended June 30, 1999 and
1998 included $2.5 million and $15.1 million respectively of costs which have
been expensed as exploration costs in the statement of operations for the
corresponding periods. Cash flows from operating activities before changes in
working capital for the six months ended June 30, 1999 and 1998 were $67.1
million and $72.6 million, representing 75% and 51%, 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 "Quantitative and Qualitative Disclosures About
Market Risk - Fixed-Price Contracts."
Cash flows from financing activities for the first six months of 1999
reflected a net source of cash of $29.0 million compared to a $59.8 million
source of cash for the first six months of 1998. Included in the amount for
1998 is $40.1 million of proceeds received in connection with the termination
of a Fixed-Price Contract. See Note 5 of the Condensed Notes to Consolidated
Financial Statements appearing elsewhere herein. Historically, the Company
has relied upon
Page 15 of 23
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (CONTINUED)
availability under various revolving bank credit facilities and proceeds from
the issuance of senior and subordinated notes to fund its investing
activities.
The Company's EBITDAX decreased to $87.6 million for the first six
months of 1999 from $93.3 million for the first six months of 1998. EBITDAX
is defined herein as income (loss) before interest, income taxes, DD&A,
impairments, exploration costs and change in derivative fair value. EBITDAX
decreased primarily as a result of lower oil and gas prices in relation to
those received for the first six months of 1998. The Company believes that
EBITDAX is a financial measure commonly used in the oil and gas industry as
an indicator of a company's ability to service and incur debt. However,
EBITDAX should not be considered in isolation or as a substitute for net
income, cash flows provided by operating activities or other data prepared in
accordance with generally accepted accounting principles, or as a measure of
a company's profitability or liquidity. EBITDAX measures as presented may not
be comparable to other similarly titled measures of other companies.
CREDIT FACILITY. The Company has a revolving credit facility (the
"Credit Facility") with a syndicate of banks which provides up to $450
million in borrowings (the "Commitment"). Letters of credit are limited to
$75 million of such availability. The Credit Facility allows the Company to
draw on the full $450 million credit line without restrictions tied to
periodic revaluations of its oil and gas reserves provided the Company
continues to maintain an investment grade credit rating from either Standard
& Poor's Ratings Service or Moody's Investors Service. A borrowing base can
be required only upon the vote by a majority in interest of the lenders after
the loss of an investment grade credit rating. No principal payments are
required under the Credit Facility prior to termination on October 14, 2002.
The Company has relied upon the Credit Facility to provide funds for
acquisitions and drilling activities, and to provide letters of credit to
meet the Company's margin requirements under Fixed-Price Contracts. As of
June 30, 1999, the Company had $330.0 million of principal and $17.8 million
of letters of credit outstanding under the Credit Facility.
The Company has the option of borrowing at a LIBOR-based interest rate
or the Base Rate (approximating the prime rate). The LIBOR interest rate
margin and the facility fee payable under the Credit Facility are subject to
a sliding scale based on the Company's senior debt credit rating. At June 30,
1999, the applicable interest rate was LIBOR plus 30 basis points. The Credit
Facility also requires the payment of a facility fee equal to 15 basis points
of the Commitment. The average interest rate for borrowings under the Credit
Facility was 5.7% as of June 30, 1999. Including the effect of interest rate
swaps which hedge a portion of the interest rate exposure attributable to
this facility, the effective interest rate was 5.6%. See the Notes to
Consolidated Financial Statements included in the Company's Annual Report on
Form 10-K, as amended, for the year ended December 31, 1998 for an expanded
discussion of the Company's interest rate swaps. The Credit Facility contains
various affirmative and restrictive covenants which, among other things,
limit total indebtedness to $700 million ($625 million of senior
indebtedness) and require the Company to meet certain financial tests.
Borrowings under the Credit Facility are unsecured.
OTHER LINES OF CREDIT. The Company has certain other unsecured lines of
credit available to it which aggregated $30.1 million as of June 30, 1999.
Such short-term lines of credit are unsecured and primarily used to meet
margin requirements under Fixed-Price Contracts and for working capital
purposes. As of June 30, 1999, the Company had no indebtedness and $.1
million of letters of credit outstanding under such credit lines. Repayment
of indebtedness thereunder is expected to be made through Credit Facility
availability.
6 7/8% SENIOR NOTES DUE 2007. In December 1997, the Company issued $200
million principal amount, $198.8 million net of discount, of 6 7/8% Senior
Notes due 2007. Interest is payable semi-annually on June 1 and December 1.
The associated indenture agreement contains restrictive covenants which place
limitations on the amount of liens and the Company's ability to enter into
sale and leaseback transactions.
9 1/4% SUBORDINATED NOTES DUE 2004. In June 1994, the Company issued
$100 million principal amount, $98.5 million net of discount, of 9 1/4%
Senior Subordinated Notes due 2004 (the "Subordinated Notes"). Interest is
payable semi-annually on June 15 and December 15. The associated indenture
agreement contains certain restrictive covenants which limit, among other
things, the prepayment of the Subordinated Notes, the incurrence of
additional indebtedness, the payment of dividends and the disposition of
assets.
Page 16 of 23
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (CONTINUED)
The Company believes that the borrowing capacity available under the
Credit Facility, combined with the Company's internal cash flows, will be
adequate to finance the capital expenditure program planned for the balance
of 1999, and to meet the Company's margin requirements under its Fixed-Price
Contracts. See "Commitments and Capital Expenditures" and "Quantitative and
Qualitative Disclosures About Market Risk." At June 30, 1999, the Company had
working capital of $14.4 million and a current ratio of 1.2 to 1. Total
long-term debt outstanding at June 30, 1999 was $629.6 million. The Company's
long-term debt as a percentage of its total capitalization was 57%.
COMMITMENTS AND CAPITAL EXPENDITURES
The Company's primary business strategy is to generate strong and
consistent growth in reserves, production, operating cash flows and earnings
through a balanced program of exploration and development drilling and
strategic acquisitions of oil and gas properties. For the six months ended
June 30, 1999, the Company expended $50.2 million on development activities
and $9.3 million on exploration activities. This expenditure level resulted
in the drilling of 78 development wells and 7 exploratory wells. Of these
wells, 73 development wells and three exploratory wells were successfully
completed as producers, for a completion success rate of 94% and 43%,
respectively (an overall success rate of 89%). In addition, the Company
invested $32.5 million in proved oil and gas property acquisitions during the
first six months of 1999. For the balance of 1999, the Company currently
plans to invest an additional $78 million in connection with its drilling
program focused principally in its Core Areas. Actual levels of drilling and
acquisition expenditures may vary due to many factors, including drilling
results, new drilling opportunities, oil and natural gas prices and
acquisition opportunities.
The Company continues to actively search for additional attractive oil
and gas property acquisitions, but is not able to predict the timing or
amount of additional capital expenditures which may ultimately be employed in
acquisitions during 1999.
OUTLOOK FOR FISCAL 1999
Reference is made to "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Outlook for Fiscal Year 1999" included
in the Company's Annual Report on Form 10-K, as amended, for the year ended
December 31, 1998 for an expanded discussion of 1999 estimates. Subject to
the uncertainties identified in "Forward-Looking Statements", no material
modifications to previously disclosed estimates are deemed necessary.
YEAR 2000 COMPLIANCE
GENERAL. The Company continues to address the business issues surrounding
the ability of computer software and hardware and other business systems to
appropriately consider periods and dates after December 31, 1999, both in its
offices and field locations ("Year 2000 Issue"). Non-compliant information
technology ("IT") systems and non-IT systems could result in system failures
or miscalculations causing disruptions of business operations or a temporary
inability to engage in normal business activities. Both IT and non-IT systems
may contain embedded technology, which complicates the Company's efforts to
identify, assess and remediate the Year 2000 Issue.
The Company has formed a task force to develop and implement a
comprehensive plan to resolve the Year 2000 Issue and to oversee the
assessment, remediation, testing and implementation phases of the plan. The
plan encompasses a study of significant operational exposures that would be
reasonably likely to result from the failure by the Company or significant
third parties to be Year 2000 compliant on a timely basis. These exposures
include the Company's ability to produce its oil and gas reserves, to
maintain environmental compliance and to meet contractual obligations. It
also includes the ability of its purchasers, transporters, outside operators
and other customers to buy, take delivery of, transport and pay for natural
gas and crude oil produced. Other risks relate to continued performance of
suppliers, vendors and service companies that the Company relies upon to
conduct its operations, as well as the financial institutions utilized in
connection with its borrowing and cash management activities. The mandate of
the task force includes monitoring the progress of third parties as deemed
appropriate, to the extent information can be obtained.
STATUS.
IT SYSTEMS. The Company has completed the assessment phase of all
significant IT systems, including its accounting, land, production and
engineering software and its computer hardware. The Company believes that the
Page 17 of 23
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (CONTINUED)
remediation, testing and implementation phases are also complete for these
systems. Upgrades of certain PC-based systems will continue throughout 1999,
however, non-compliance in these systems is not estimated to represent a
material exposure. While the Company believes that all significant IT systems
are Year 2000 compliant, it will continue to monitor such systems for
previously unidentified exposures.
NON-IT SYSTEMS. The Company has completed the assessment phase of all
significant non-IT systems, which includes operating equipment with embedded
chips or software. The Company believes that the remediation, testing and
implementation phases are also complete. The existence of embedded technology
is by nature more difficult to identify. While the Company believes that all
significant non-IT systems are Year 2000 compliant, the task force will
continue to search for previously unidentified exposures.
THIRD PARTIES. The Company has completed the assessment phase of its
exposure to Year 2000 compliance by material third parties. The responses
received to date from third parties have not identified a material
non-compliance issue that would require action by the Company. The Company
will continue to monitor its exposure to new and existing material third
parties to the extent information is made available throughout the balance of
1999. The Company has a limited number of systems which interface directly
with third parties. Such systems, although believed to be compliant, are not
significant to its business operations.
The Company cannot be assured that the various phases of its Year 2000
plan will successfully identify and mitigate all material exposures to the
Year 2000 Issue.
COSTS. The Company has, and will continue to use, primarily internal
resources to reprogram, or replace, test and implement the software, hardware
and operating equipment for Year 2000 modifications. Because the majority of
the software employed by the Company was purchased from third parties subject
to ongoing maintenance agreements, Year 2000 upgrades did not result in
significant cash outlays. Total costs incurred to date in connection with
Year 2000 compliance have been immaterial. The estimated cost attributable to
remaining compliance issues in the aggregate is expected to be less than
$100,000 including hardware, software, internal and external labor costs,
which will be funded through operating cash flows.
RISK FACTORS. The Company believes it has an effective program in place
to resolve the Year 2000 Issue in a timely manner and does not expect to
incur significant operational problems due to Year 2000 non-compliance. As
noted above, the Company has substantially completed all phases of its Year
2000 plan, but certain plan activities will be ongoing through the end of
1999. No assurance can be given that all material issues have been or will be
identified, or that all material third parties will be compliant by the year
2000. If all significant Year 2000 issues are not properly and timely
identified, assessed, remediated, tested and implemented, the Company's
results of operations may be materially adversely affected. Additionally,
non-compliance by third parties may have a material adverse effect on the
Company's systems or results of operations.
The Company has not identified a "worst case scenario" that is reasonably
likely to cause a material interruption of its business activities, to cause
a material environmental event, to cause it not to meet a material
contractual obligation, or to otherwise have a material adverse effect on its
operations. Accordingly, the Company has not formalized a contingency plan to
address Year 2000 non-compliance. The Company plans to continue to evaluate
the status of its Year 2000 plan throughout 1999 and to evaluate whether such
a contingency plan is advisable.
Page 18 of 23
LOUIS DREYFUS NATURAL GAS CORP.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
GENERAL
The Company's results of operations and operating cash flows are impacted
by changes in market prices for oil and gas and changes in market interest
rates. To mitigate a portion of its exposure to adverse market changes, the
Company has entered into Fixed-Price Contracts and interest rate swaps. All
of the Company's Fixed-Price Contracts and interest rate swaps have been
entered into as hedges of oil and gas price risk or interest rate risk and
not for trading purposes. Information regarding the Company's market
exposures, Fixed-Price Contracts, interest rate swaps and certain other
financial instruments is provided below. All information is presented in U.S.
Dollars.
FIXED-PRICE CONTRACTS
DESCRIPTION OF CONTRACTS. The Company's Fixed-Price Contracts are
comprised of long-term physical delivery contracts, energy swaps, collars,
futures contracts and basis swaps. These contracts allow the Company to
predict with greater certainty the effective oil and gas prices to be
received for its hedged production and benefit the Company when market prices
are less than the fixed prices provided in its Fixed-Price Contracts.
However, the Company will not benefit from market prices that are higher than
the fixed prices in such contracts for its hedged production. For the years
ended December 31, 1998, 1997 and 1996, Fixed-Price Contracts hedged 50%, 60%
and 51%, respectively, of the Company's gas production and 16%, 33% and 67%,
respectively, of its oil production. For the six months ended June 30, 1999,
Fixed-Price Contracts hedged 54% of the Company's natural gas production. As
of June 30, 1999, Fixed-Price Contracts are in place to hedge 243 Bcf of the
Company's estimated future gas production, representing 20% of its proved
natural gas reserves as of December 31, 1998.
Reference is made to the Company's Annual Report on Form 10-K, as
amended, for the year ended December 31, 1998 for a more detailed discussion
of the Company's Fixed-Price Contracts.
In July 1999, the Company entered into an oil swap for the last 5 months
of 1999 which hedges 330 MBbls of oil production at $20.37 per Bbl.
Page 19 of 23
LOUIS DREYFUS NATURAL GAS CORP.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK (CONTINUED)
The following table summarizes the estimated volumes, fixed prices,
fixed-price sales, fixed-price purchases and future net revenues attributable
to the Company's Fixed-Price Contracts as of June 30, 1999. The Company
expects the prices to be realized for its hedged production to vary from the
prices shown in the following table, due to basis, which is the differential
between the floating price paid under each energy swap contract, or the cost
of gas to supply physical delivery contracts and the price received at the
wellhead for the Company's production. Basis differentials are caused by
differences in location, quality, contract terms, timing and other variables.
Future net revenues for any period are determined as the differential between
the fixed prices provided by Fixed-Price Contracts and forward market prices
as of June 30, 1999, as adjusted for basis. Future net revenues change with
changes in market prices and basis.
SIX
MONTHS
ENDING YEARS ENDING DECEMBER 31, BALANCE
DECEMBER 31, ------------------------------------------- THROUGH
1999 2000 2001 2002 2003 2017 TOTAL
------------ ------- ------- ------- ------- -------- --------
(DOLLARS IN THOUSANDS, EXCEPT PRICE DATA)
NATURAL GAS SWAPS:
SALES CONTRACTS
Contract volumes (BBtu) ................... 9,353 9,830 7,475 6,405 5,650 17,783 56,496
Weighted-average fixed price
per MMBtu (1) ........................... $ 2.36 $ 2.46 $ 2.47 $ 2.67 $ 2.92 $ 3.29 $ 2.77
Future fixed-price sales .................. $ 22,112 $24,164 $18,446 $17,098 $16,492 $ 58,430 $156,742
Future net revenues (2) ................... $ (835) $ 179 $ 59 $ 1,085 $ 2,086 $ 10,784 $ 13,358
PURCHASE CONTRACTS
Contract volumes (BBtu) ................... (5,520) -- -- -- -- -- (5,520)
Weighted-average fixed price
per MMBtu (1) ........................... $ 2.18 $ -- $ -- $ -- $ -- $ -- $ 2.18
Future fixed-price purchases .............. $ (12,038) $ -- $ -- $ -- $ -- $ -- $(12,038)
Future net revenues (2) ................... $ 1,589 $ -- $ -- $ -- $ -- $ -- $ 1,589
NATURAL GAS PHYSICAL DELIVERY
CONTRACTS:
Contract volumes (BBtu) ................... 12,143 22,678 23,240 23,115 20,245 71,483 172,904
Weighted-average fixed price
per MMBtu (1) ........................... $ 2.81 $ 2.94 $ 3.06 $ 3.21 $ 3.47 $ 4.32 $ 3.61
Future fixed-price sales .................. $ 34,137 $66,675 $71,109 $74,150 $70,292 $308,529 $624,892
Future net revenues (2) ................... $ 2,549 $ 7,749 $ 9,699 $10,973 $11,157 $ 40,406 $ 82,533
NATURAL GAS COLLARS:
Contract volumes (BBtu):
Floor ................................... 12,052 -- -- -- -- -- 12,052
Ceiling ................................. 19,320 -- -- -- -- -- 19,320
Weighted-average fixed price
per MMBtu (1):
Floor ................................... $ 2.01 $ -- $ -- $ -- $ -- $ -- $ 2.01
Ceiling ................................. $ 2.10 $ -- $ -- $ -- $ -- $ -- $ 2.10
Future fixed-price sales .................. $ 40,572 $ -- $ -- $ -- $ -- $ -- $ 40,572
Future net revenues (2) ................... $ (6,610) $ -- $ -- $ -- $ -- $ -- $ (6,610)
TOTAL NATURAL GAS CONTRACTS (3):
Contract volumes (BBtu) ................... 35,296 32,508 30,715 29,520 25,895 89,266 243,200
Weighted-average fixed price
per MMBtu (1) ........................... $ 2.40 $ 2.79 $ 2.92 $ 3.09 $ 3.35 $ 4.11 $ 3.33
Future fixed-price sales .................. $ 84,783 $90,839 $89,555 $91,248 $86,784 $366,959 $810,168
Future net revenues (2) ................... $ (3,307) $ 7,928 $ 9,758 $12,058 $13,243 $ 51,190 $ 90,870
- -----------------------
(1) - The Company expects the prices to be realized for its hedged production
to vary from the prices shown due to basis.
(2) - Future net revenues as presented above are undiscounted and have not been
adjusted for contract performance risk or counterparty credit risk.
(3) - Does not include basis swaps with notional volumes by year, as follows:
1999 - 9.6 TBtu; 2000 - 21.3 TBtu; 2001 - 9.4 TBtu; and 2002 - 5.5 TBtu.
Page 20 of 23
LOUIS DREYFUS NATURAL GAS CORP.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK (CONTINUED)
The estimates of future net revenues from the Company's Fixed-Price
Contracts are computed based on the difference between the prices provided by
the Fixed-Price Contracts and forward market prices as of the specified date.
The market for natural gas beyond a five year horizon is illiquid and
published market quotations are not available. The Company has relied upon
near-term market quotations, longer-term over-the-counter market quotations
and other market information to determine its future net revenue estimates.
Forward market prices for natural gas are dependent upon supply and demand
factors in such forward market and are subject to significant volatility. The
future net revenue estimates shown above are subject to change as forward
market prices change.
The estimated fair value of the Company's Fixed-Price Contracts and
interest rate swaps and the associated carrying value as of June 30, 1999 are
identical. Such amounts are provided below.
ESTIMATED
FAIR VALUE
------------
(IN THOUSANDS)
Derivative assets:
Fixed-price natural gas swaps:
Sales contracts..................................... $ 15,357
Purchase contracts.................................. 1,558
Fixed-price natural gas collars....................... 455
Fixed-price natural gas delivery contracts............ 70,195
Interest rate swaps - fixed........................... 4,277
Derivative liabilities:
Fixed-price natural gas swaps - sales contracts....... (5,813)
Fixed-price natural gas collars....................... (7,065)
Fixed-price natural gas delivery contracts............ (12,518)
Natural gas basis swaps............................... (3,943)
Interest rate swaps - fixed........................... (95)
---------
Total................................................. $ 62,408
---------
---------
The fair value of Fixed-Price Contracts as of June 30, 1999 was
estimated based on market prices of natural gas and crude oil for the periods
covered by the contracts. The net differential between the prices in each
contract and market prices for future periods, as adjusted for estimated
basis, has been applied to the volumes stipulated in each contract to arrive
at an estimated future value. This estimated future value was discounted on a
contract-by-contract basis at rates commensurate with the Company's
estimation of contract performance risk and counterparty credit risk. The
terms and conditions of the Company's fixed-price physical delivery contracts
and certain financial swaps are uniquely tailored to the Company's
circumstances. In addition, the determination of market prices for natural
gas beyond a five year horizon is subject to significant judgment and
estimation. As a result, the Fixed-Price Contract fair value as reflected in
the balance sheet as of June 30, 1999 does not necessarily represent the
value a third party would pay to assume the Company's positions. See "Note 5
- -- Contingencies" of the Condensed Notes to Consolidated Financial Statements
appearing elsewhere in this document.
INTEREST RATE SENSITIVITY
The Company has entered into interest rate swaps to hedge the interest
rate exposure associated with borrowings under the Credit Facility. As of
June 30, 1999, the Company had fixed the interest rate on average notional
amounts of $155 million for the balance of 1999, and $125 million, $125
million and $94 million for the years ending December 31, 2000, 2001 and
2002, respectively. Under the interest rate swaps, the Company receives the
LIBOR three-month rate (5.4% at June 30, 1999) and pays an average rate of
5.3% for the balance of 1999 and 5.0%, 5.0% and 5.0% for 2000, 2001 and 2002,
respectively. The notional amounts are less than the maximum amount
anticipated to be outstanding under the Credit Facility in such years.
Reference is made to the Company's Annual Report on Form 10-K, as
amended, for the year ended December 31, 1998 for an expanded discussion of
the Company's interest rate swaps.
Page 21 of 23
LOUIS DREYFUS NATURAL GAS CORP.
PART II. OTHER INFORMATION
ITEM 1 -- NONE
ITEM 2 -- NONE
ITEM 3 -- NONE
ITEM 4 -- SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The 1999 Annual Meeting of Shareholders was held on May 18, 1999. The
following were submitted to a vote of the Company's shareholders:
1. The election of twelve directors for the ensuing year and until their
successors are duly elected and qualified. The results of the election
for each director are as follows:
Gerard Louis-Dreyfus 35,260,510 votes for; 995,294 votes withheld; 0 votes abstaining
Simon B. Rich, Jr. 36,243,703 votes for; 12,101 votes withheld; 0 votes abstaining
Mark Andrews 36,223,733 votes for; 32,071 votes withheld; 0 votes abstaining
Mark E. Monroe 36,243,848 votes for; 11,956 votes withheld; 0 votes abstaining
Richard E. Bross 36,225,024 votes for; 30,780 votes withheld; 0 votes abstaining
Daniel R. Finn, Jr. 36,243,827 votes for; 11,977 votes withheld; 0 votes abstaining
Peter G. Gerry 36,243,448 votes for; 12,356 votes withheld; 0 votes abstaining
John H. Moore 36,242,098 votes for; 13,706 votes withheld; 0 votes abstaining
James R. Paul 36,243,823 votes for; 11,981 votes withheld; 0 votes abstaining
Ernest F. Steiner 35,261,313 votes for; 994,491 votes withheld; 0 votes abstaining
Nancy K. Quinn 36,242,811 votes for; 12,993 votes withheld; 0 votes abstaining
E. William Barnett 36,224,456 votes for; 31,348 votes withheld; 0 votes abstaining
2. The approval of amendments to the Company's Stock Option Plan. The
results of the shareholder vote included 32,213,770 votes for;
4,031,436 votes against; and 10,598 abstaining.
3. Ratification of the selection of Ernst & Young as independent auditors
of the Company for the year ending December 31, 1998. The results of
the shareholder vote included 36,223,627 votes for; 28,997 votes
against; and 3,180 votes abstaining.
ITEM 5 -- NONE
ITEM 6 -- EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:
27.1 -- Financial Data Schedule
(b) Reports on Form 8-K:
None
Page 22 of 23
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: October 7, 1999 /s/ Jeffrey A. Bonney
------------------------------
Jeffrey A. Bonney
Executive Vice President and
Chief Financial Officer
Page 23 of 23