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 June 30, 2001
or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934.
For the transition period from to
--------- ---------
Commission File Number 1-12480
Louis Dreyfus Natural Gas Corp.
(Exact name of registrant as specified in its charter)
Oklahoma 73-1098614
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
14000 QUAIL SPRINGS PARKWAY, SUITE 600
OKLAHOMA CITY, OKLAHOMA 73134
(Address of principal executive office) (Zip code)
Registrant's telephone number, including area code: (405) 749-1300
NONE
(Former name, former address and former fiscal year, if changed since last
report.)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. YES X NO .
----- -----
43,762,027 shares of common stock, $.01 par value, issued and outstanding, net
of treasury shares, at August 9, 2001.
2
LOUIS DREYFUS NATURAL GAS CORP.
Table of Contents
PART I. FINANCIAL INFORMATION Page
Item 1 -- CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
Consolidated Balance Sheets:
June 30, 2001 and December 31, 2000. . . . . . . . . . . . . . . . . 3
Consolidated Statements of Income:
Three months and six months ended June 30, 2001 and 2000 . . . . . . 5
Consolidated Statements of Cash Flows:
Six months ended June 30, 2001 and 2000. . . . . . . . . . . . . . . 6
Condensed Notes to Consolidated Financial Statements . . . . . . . . . 7
Item 2 -- MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS. . . . . . . . . . . . . . . . . . . . . . 11
Item 3 -- QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK. . 22
PART II. OTHER INFORMATION . . . . . . . . . . . . . . . . . . . . . . 26
3
LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED BALANCE SHEETS
(dollars in thousands)
A S S E T S
June 30, December 31,
2001 2000
------------- -------------
(unaudited)
CURRENT ASSETS
Cash and cash equivalents. . . . . . . . . . . . $ 1,730 $ 2,799
Receivables:
Oil and gas sales. . . . . . . . . . . . . . . 88,669 109,488
Joint interest and other, net. . . . . . . . . 14,823 9,098
Income taxes . . . . . . . . . . . . . . . . . -- 9,276
Fixed-price contracts and other derivatives. . . 67,531 1,004
Prepaids and other . . . . . . . . . . . . . . . 3,993 4,623
------------- -------------
Total current assets . . . . . . . . . . . . . 176,746 136,288
------------- -------------
PROPERTY AND EQUIPMENT, at cost, based on
successful efforts accounting. . . . . . . . . 2,096,688 1,951,520
Less accumulated depreciation, depletion
and amortization . . . . . . . . . . . . . . . (641,615) (591,305)
------------- -------------
1,455,073 1,360,215
------------- -------------
OTHER ASSETS
Fixed-price contracts and other derivatives. . . 59,789 752
Other, net . . . . . . . . . . . . . . . . . . . 4,463 4,710
------------- -------------
64,252 5,462
------------- -------------
$ 1,696,071 $ 1,501,965
============= =============
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
June 30, December 31,
2001 2000
------------- -------------
(unaudited)
CURRENT LIABILITIES
Accounts payable . . . . . . . . . . . . . . . . $ 80,478 $ 46,065
Revenues payable . . . . . . . . . . . . . . . . 21,691 19,794
Accrued liabilities. . . . . . . . . . . . . . . 13,708 14,984
Fixed-price contracts and other derivatives. . . 25,684 126,255
------------- -------------
Total current liabilities. . . . . . . . . . . 141,561 207,098
------------- -------------
LONG-TERM DEBT 523,032 606,909
------------- -------------
DEFERRED CREDITS AND OTHER LONG-TERM LIABILITIES
Deferred revenue . . . . . . . . . . . . . . . . 10,081 11,277
Fixed-price contracts and other derivatives. . . 64,554 103,447
Deferred income taxes. . . . . . . . . . . . . . 146,212 19,222
Other. . . . . . . . . . . . . . . . . . . . . . 20,364 21,193
------------- -------------
241,211 155,139
------------- -------------
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,
44,114,117 and 43,689,774 shares,
respectively . . . . . . . . . . . . . . . . . 441 437
Paid-in capital. . . . . . . . . . . . . . . . . 509,338 504,989
Retained earnings. . . . . . . . . . . . . . . . 247,623 126,409
Accumulated other comprehensive income (loss) . 34,883 (99,005)
Treasury stock, at cost, 58,415 and 589 common
shares, respectively . . . . . . . . . . . . . (2,018) (11)
------------- -------------
790,267 532,819
------------- -------------
$ 1,696,071 $ 1,501,965
============= =============
See accompanying notes to consolidated financial statements.
5
LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED STATEMENTS OF INCOME (unaudited)
(in thousands, except per share data)
Three Months Ended Six Months Ended
June 30, June 30,
------------------ ------------------
2001 2000 2001 2000
-------- -------- -------- --------
REVENUES
Oil and gas sales. . . . . . . . . . $156,586 $ 99,121 $365,080 $186,484
Change in derivative fair value. . . (112) (11,945) 3,038 (20,108)
Other income . . . . . . . . . . . . 936 828 1,278 2,082
-------- -------- -------- --------
157,410 88,004 369,396 168,458
-------- -------- -------- --------
EXPENSES
Operating costs. . . . . . . . . . . 26,158 19,457 56,576 36,611
General and administrative . . . . . 6,793 5,609 13,604 11,701
Exploration costs. . . . . . . . . . 4,290 4,028 18,606 7,271
Depreciation, depletion and
amortization . . . . . . . . . . . 32,288 29,827 65,094 60,085
Impairment . . . . . . . . . . . . . 2,606 4,569 2,606 4,569
Interest . . . . . . . . . . . . . . 7,850 9,882 16,778 19,308
-------- -------- -------- --------
79,985 73,372 173,264 139,545
-------- -------- -------- --------
Income before income taxes . . . . . 77,425 14,632 196,132 28,913
Income tax provision . . . . . . . . 29,614 5,560 74,918 10,986
-------- -------- -------- --------
NET INCOME . . . . . . . . . . . . . $ 47,811 $ 9,072 $121,214 $ 17,927
======== ======== ======== ========
Net income per share:
Basic. . . . . . . . . . . . . . . . $ 1.09 $ .22 $ 2.76 $ .44
======== ======== ======== ========
Diluted. . . . . . . . . . . . . . . $ 1.07 $ .22 $ 2.71 $ .43
======== ======== ======== ========
Weighted average number of common
shares:
Basic. . . . . . . . . . . . . . . . 43,990 40,649 43,915 40,442
Diluted. . . . . . . . . . . . . . . 44,751 41,827 44,718 41,315
See accompanying notes to consolidated financial statements.
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LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
(in thousands)
Six Months Ended
June 30,
------------------
2001 2000
-------- --------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $121,214 $ 17,927
Items not affecting cash flows:
Depreciation, depletion and amortization. . . . . . . . . . . . . . . . 65,094 60,085
Impairment. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,606 4,569
Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . 44,929 10,408
Exploration costs . . . . . . . . . . . . . . . . . . . . . . . . . . . 18,606 7,271
Change in derivative fair value . . . . . . . . . . . . . . . . . . . . (3,038) 20,108
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 859 (365)
Net change in operating assets and liabilities:
Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . 24,176 (31,504)
Prepaids and other. . . . . . . . . . . . . . . . . . . . . . . . . . . 630 (703)
Accounts payable. . . . . . . . . . . . . . . . . . . . . . . . . . . . 34,413 25,146
Accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . (863) (692)
Income taxes payable. . . . . . . . . . . . . . . . . . . . . . . . . . 566 (570)
Revenues payable. . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,897 4,709
-------- --------
311,089 116,389
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Exploration and development expenditures. . . . . . . . . . . . . . . . . (173,725) (125,828)
Acquisition of proved oil and gas properties. . . . . . . . . . . . . . . (5,611) (131,891)
Additions to other property and equipment . . . . . . . . . . . . . . . . (2,218) (1,581)
Proceeds from sale of property and equipment. . . . . . . . . . . . . . . 1,107 10,857
Payment of option premiums. . . . . . . . . . . . . . . . . . . . . . . . (39,489) --
Change in other assets. . . . . . . . . . . . . . . . . . . . . . . . . . (77) 470
-------- --------
(220,013) (247,973)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from bank borrowings . . . . . . . . . . . . . . . . . . . . . . 256,300 277,350
Repayments of bank borrowings . . . . . . . . . . . . . . . . . . . . . . (340,200) (144,350)
Repayments of subordinated notes. . . . . . . . . . . . . . . . . . . . . -- (6,549)
Proceeds from stock option exercises and other. . . . . . . . . . . . . . 3,790 8,755
Sale (purchase) of treasury shares. . . . . . . . . . . . . . . . . . . . (2,904) 49
Change in deferred revenue. . . . . . . . . . . . . . . . . . . . . . . . (1,196) (1,089)
Change in gains from price-risk management activities . . . . . . . . . . (6,735) (6,340)
Change in other long-term liabilities . . . . . . . . . . . . . . . . . . (1,200) (1,046)
-------- --------
(92,145) 126,780
-------- --------
Change in cash and cash equivalents . . . . . . . . . . . . . . . . . . . (1,069) (4,804)
Cash and cash equivalents, beginning of period. . . . . . . . . . . . . . 2,799 9,660
-------- --------
Cash and cash equivalents, end of period. . . . . . . . . . . . . . . . . $ 1,730 $ 4,856
======== ========
See accompanying notes to consolidated financial statements.
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LOUIS DREYFUS NATURAL GAS CORP.
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
JUNE 30, 2001
NOTE 1 -- ACCOUNTING PRINCIPLES AND BASIS OF PRESENTATION
The accompanying unaudited consolidated financial statements have been
prepared in accordance with the instructions to Form 10-Q as prescribed by the
Securities and Exchange Commission. All material adjustments, consisting of
normal and recurring adjustments and a $2.6 million impairment charge
discussed below, 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, 2001 are not necessarily indicative of the results to be expected for the
full year. Reference is made to our Annual Report on Form 10-K for the year
ended December 31, 2000 for an expanded discussion of our financial
disclosures and accounting policies.
In the second quarter of 2001, an impairment charge of $2.6 million was
recorded which primarily relates to a downward reserve revision for one
single-well offshore field drilled in 1998. We are unaware of any other
fields which may be impaired because of performance or other reasons.
However, future impairments may be recognized as a result of numerous factors,
all of which are beyond our ability to control or predict.
NOTE 2 -- HEDGING
We reduce our exposure to unfavorable changes in oil and natural gas prices
by utilizing fixed-price physical delivery contracts, energy swaps, collars,
options and basis swaps. We also enter into interest rate swap contracts to
reduce our exposure to adverse interest rate fluctuations. These derivative
instruments are accounted for pursuant to Statement of Financial Accounting
Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities" (SFAS 133). All of our fixed-price contracts and interest rate
swaps are designated as cash flow hedges. Change in derivative fair value in
the statements of income for the three-month and the six-month periods ended
June 30, 2001 and 2000 is comprised of the following:
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LOUIS DREYFUS NATURAL GAS CORP.
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued)
JUNE 30, 2001
Three Months Ended Six Months Ended
June 30, June 30,
------------------ ------------------
2001 2000 2001 2000
-------- -------- -------- --------
CHANGE IN DERIVATIVE FAIR VALUE
Change in fair value of derivatives
not qualifying for hedge accounting. $ 1,955 $ (9,308) $ 2,869 $(16,235)
Amortization of derivative fair value
gains and losses recognized in
earnings prior to actual cash
settlements. . . . . . . . . . . . . (3,748) (2,070) (5,344) (4,346)
Ineffective portion of derivatives
qualifying for hedge accounting . . 1,681 (567) 5,513 473
-------- -------- -------- --------
$ (112) $(11,945) $ 3,038 $(20,108)
======== ======== ======== ========
Despite certain fixed-price contracts failing the effectiveness guidelines
of SFAS 133 from time to time, fixed-price contracts continue to be highly
effective in achieving the risk management objectives for which they were
intended.
The change in carrying value of fixed-price contracts and interest rate
swaps in the balance sheet since December 31, 2000 resulted from a decrease in
market prices for natural gas and crude oil and a decrease in interest rates.
The majority of this change in fair value was reflected in accumulated other
comprehensive income, net of deferred tax effects. Derivative assets and
liabilities reflected as current in the June 30, 2001 balance sheet represent
the estimated fair value of fixed-price contract settlements scheduled to
occur over the subsequent twelve-month period based on market prices for oil
and gas as of the balance sheet date. The offsetting change in value of
hedged future production has not been reflected in the accompanying balance
sheet. The contract settlement amounts are not receivable or payable until
the monthly period that the related underlying hedged transaction occurs.
9
LOUIS DREYFUS NATURAL GAS CORP.
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued)
JUNE 30, 2001
The estimated fair values of fixed-price contracts as of June 30, 2001 and
December 31, 2000 are provided below. The associated carrying values of these
contracts are equal to the estimated fair values for each period presented.
June 30, December 31,
2001 2000
------------- -------------
(in thousands)
Derivative assets:
Fixed-price natural gas swaps. . . . . . . . $ 31,025 $ --
Fixed-price natural gas collars. . . . . . . 90,411 --
Fixed-price natural gas delivery contracts . 986 --
Natural gas basis swaps. . . . . . . . . . . 4,898 --
Interest rate swaps. . . . . . . . . . . . . -- 1,756
Derivative liabilities:
Fixed-price natural gas swaps. . . . . . . . (17,097) (55,923)
Fixed-price natural gas collars. . . . . . . (1,529) (26,054)
Fixed-price natural gas delivery contracts . (70,217) (146,234)
Natural gas basis swaps. . . . . . . . . . . (421) (1,491)
Interest rate swaps. . . . . . . . . . . . . (974) --
------------- -------------
$ 37,082 $ (227,946)
============= =============
The fair value of fixed-price contracts as of June 30, 2001 and December 31,
2000 was estimated based on market prices of natural gas and crude oil for the
periods covered by the contracts. The net differential between the prices in
each contract and market prices for future periods, as adjusted for estimated
basis, has been applied to the volumes stipulated in each contract to arrive
at an estimated future value. This estimated future value was discounted on a
contract-by-contract basis at rates commensurate with our estimation of
contract performance risk and counterparty credit risk. The fair value of
options and other derivative instruments which contain options (such as collar
structures) has been estimated based on remaining term, volatility and other
factors. The terms and conditions of our fixed-price physical delivery
contracts and certain financial swaps are uniquely tailored to our
circumstances. In addition, certain fixed-price contracts hedge gas
production for periods beyond five years into the future. The market for
natural gas beyond the five-year horizon is illiquid and published market
quotations are not available. We have relied upon near-term market
quotations, longer-term over-the-counter market quotations and other market
information to determine fair value estimates. The fair value of the interest
rate swaps was based on market interest rates as of each respective date.
NOTE 3 -- LITIGATION
Louis Dreyfus Natural Gas Corp. is one of numerous defendants in several
lawsuits originally filed in 1995, subsequently consolidated with related
litigation, and now pending in the Texas 93rd Judicial District Court in
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LOUIS DREYFUS NATURAL GAS CORP.
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued)
JUNE 30, 2001
Hildago County, Texas. The lawsuit alleges that the plaintiffs, a group of
local landowners and businesses, have suffered damages including, but not
limited to, property damage and lost profits of approximately $60 million as
the result of an underground hydrocarbon plume within the city of McAllen,
Texas. The lawsuit alleges that gas wells and related pipeline facilities
operated by us, and other facilities operated by other defendants, caused the
plume. In August 1999, the plaintiff's experts produced reports that
suggested we might be considered a significant contributor to the plume. Our
investigation into this matter has not found any leaks or discharges from our
facilities. In addition, our investigation has revealed the plume to be
unrelated to our gas wells and facilities. Trial is not anticipated to
commence during 2001. We will vigorously defend our interests in this case.
We do not presently expect the ultimate outcome of the case to have a material
adverse impact on our financial position or results of operations; however,
results of litigation are inherently unpredictable.
We were a defendant in various other legal proceedings as of June 30, 2001,
which are routine and incidental to our business. We will vigorously defend
our interests in these proceedings. While the ultimate results of all these
proceedings cannot be predicted with certainty, we do not believe that the
outcome of these matters will have a material adverse effect on our financial
position or results of operations.
NOTE 4 -- COMPREHENSIVE INCOME (LOSS)
Components of comprehensive income (loss) for the three-month and the
six-month periods ended June 30, 2001 and 2000, are as follows:
Three Months Ended Six Months Ended
June 30, June 30,
------------------ ------------------
2001 2000 2001 2000
-------- -------- -------- --------
Net income . . . . . . . . . . . . . $ 47,811 $ 9,072 $121,214 $ 17,927
Other comprehensive income (loss),
net of tax:
Reclassification adjustments -
contract settlements. . . . . . . 1,529 8,628 16,478 10,841
Change in fixed-price contract and
other derivative fair value . . . 111,142 (37,453) 117,410 (65,163)
-------- -------- -------- --------
Comprehensive income (loss). . . . . $160,482 $(19,753) $255,102 $(36,395)
======== ======== ======== ========
NOTE 5 -- STOCK REPURCHASE PROGRAM
On April 25, 2001, our Board of Directors authorized up to $40 million for
the purchase of our common stock in the open market from time to time. As of
June 30, 2001, we had repurchased 34,100 common shares for a total of $1.2
million under this program.
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LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
OVERVIEW
General. Our business strategy is to generate strong and consistent growth
in reserves, production, operating cash flows and earnings through a program
of exploration and development drilling and strategic acquisitions of oil and
gas properties. Our drilling, acquisition and operating activities are
geographically concentrated in three core areas: the Permian Region which
includes west Texas, southeast New Mexico and the San Juan Basin; the
Mid-Continent Region which includes Oklahoma, Kansas, the panhandle of Texas,
east Texas, southwest Arkansas and north Louisiana; and the Gulf Coast Region,
which includes south Texas, and offshore Gulf of Mexico. Our 2001 capital
expenditure budget includes the investment of approximately $320 million in
drilling activities in these core areas. See "-- Commitments and Capital
Expenditures."
We have a portfolio of fixed-price contracts comprised of long-term physical
delivery contracts, energy swaps, collars, options and basis swaps. As of
June 30, 2001, our fixed-price contracts hedged 219 Bcf of future natural gas
production representing 12% of our estimated December 31, 2000 proved
reserves. Of this total volume, 41 Bcf of natural gas is hedged for the
remainder of 2001. See "Quantitative and Qualitative Disclosures About Market
Risk."
Forward-Looking Statements. All statements made in this document other than
purely historical information are forward-looking statements within the
meaning of the federal securities laws. These statements reflect our current
expectations and are based on our historical operating trends, our proved
reserve and fixed-price contract positions as of June 30, 2001 and other
information currently available to us. Forward-looking statements include
statements regarding our future drilling plans and objectives, and related
exploration and development budgets, and number and location of planned wells,
and statements regarding the quality of our properties and potential reserve
and production levels. These statements may be preceded by, or followed by or
otherwise include the words "believes", "expects", "anticipates", "intends",
"plans", "estimates", "projects", or similar expressions or statements that
certain events "will" or "may" occur. These statements assume, among other
things, that no significant changes will occur in the operating environment
for our oil and gas properties and that there will be no material acquisitions
or divestitures except as disclosed in this document.
We caution that the forward-looking statements are subject to all the risks
and uncertainties incident to the acquisition, exploration, development and
marketing of oil and natural gas reserves. These risks include, but are not
limited to, commodity price, counterparty, environmental, drilling, reserves,
operations and production risks. Certain of these risks are described in this
document and in our Annual Report filed on Form 10-K for the year ended
December 31, 2000. We may make material acquisitions or divestitures, modify
our fixed-price contract positions by entering into new contracts or
terminating existing contracts, or enter into financing transactions. None of
these events can be predicted with certainty and are not taken into
consideration in the forward-looking statements made in this document.
Statements concerning fixed-price contract, interest rate swap and other
financial instrument fair values and their estimated contribution to our
12
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
future results of operations are based upon market information as of a
specific date. This market information is often a function of significant
judgment and estimation. Further, market prices for oil and gas and market
interest rates are subject to significant volatility.
For all of these reasons, actual results may vary materially from the
forward-looking statements and there is no assurance that the assumptions used
are necessarily the most likely. We expressly disclaim any obligation or
undertaking to release publicly any updates regarding any changes in our
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 in this document, the abbreviations listed
below are defined as follows:
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in this
document in reference to oil or other liquid hydrocarbons.
Bcf. Billion cubic feet.
Bcfe. Billion cubic feet of natural gas equivalent, determined using the
ratio of one Bbl of oil or condensate to six Mcf of natural gas.
BBtu. Billion Btus.
Btu. British thermal unit, which is the heat required to raise the
temperature of a one-pound mass of water from 58.5 to 59.5 degrees
Fahrenheit.
EBITDAX. EBITDAX is defined in this document as income before interest, income
taxes, depreciation, depletion and amortization, impairment,
exploration costs and change in derivative fair value. We believe
that EBITDAX is a financial measure commonly used in the oil and gas
industry as an indicator of a company's ability to service and incur
debt. However, EBITDAX should not be considered in isolation or as a
substitute for net income, cash flows provided by operating
activities or other data prepared in accordance with generally
accepted accounting principles, or as a measure of a company's
profitability or liquidity. EBITDAX measures as presented may not be
comparable to other similarly titled measures of other companies.
MBbls. Thousand barrels.
Mcf. Thousand cubic feet.
Mcfe. Thousand cubic feet of natural gas equivalent, determined using the
ratio of one Bbl of oil or condensate to six Mcf of natural gas.
MMBbls. Million barrels.
MMBtu. Million Btus.
MMcf. 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. Trillion Btus.
Selected Operating Data. The following table provides certain operating
data relating to our results of operations.
13
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
Three Months Ended Six Months Ended
June 30, June 30,
------------------ ------------------
2001 2000 2001 2000
-------- -------- -------- --------
OIL AND GAS SALES: (in thousands)
Wellhead oil sales . . . . . . . . . . . . . . . . . $ 19,671 $ 18,947 $ 39,974 $ 37,890
Effect of fixed-price contract settlements (1) . . . -- (2,616) -- (5,280)
-------- -------- -------- --------
Total oil sales. . . . . . . . . . . . . . . . . . . $ 19,671 $ 16,331 $ 39,974 $ 32,610
======== ======== ======== ========
Wellhead natural gas sales . . . . . . . . . . . . . $136,048 $ 96,775 $345,505 $166,294
Effect of fixed-price contract settlements (1) . . . 867 (13,985) (20,399) (12,420)
-------- -------- -------- --------
Total natural gas sales. . . . . . . . . . . . . . . $136,915 $ 82,790 $325,106 $153,874
======== ======== ======== ========
PRODUCTION:
Oil production (MBbls) . . . . . . . . . . . . . . . 762 690 1,513 1,389
Natural gas production (MMcf). . . . . . . . . . . . 29,606 28,373 59,596 55,961
Net equivalent production (MMcfe). . . . . . . . . . 34,180 32,513 68,677 64,295
Percent of oil production hedged by fixed-price
contracts . . . . . . . . . . . . . . . . . . . . . -- 73% -- 72%
Percent of gas production hedged by fixed-price
contracts . . . . . . . . . . . . . . . . . . . . . 88% 68% 68% 49%
AVERAGE SALES PRICE:
Oil price (per Bbl):
Wellhead price. . . . . . . . . . . . . . . . . . . $ 25.80 $ 27.46 $ 26.41 $ 27.28
Effect of fixed-price contract settlements (1). . . -- (3.79) -- (3.80)
-------- -------- -------- --------
Total. . . . . . . . . . . . . . . . . . . . . . . . $ 25.80 $ 23.67 $ 26.41 $ 23.48
======== ======== ======== ========
Natural gas price (per Mcf):
Wellhead price. . . . . . . . . . . . . . . . . . . $ 4.59 $ 3.41 $ 5.80 $ 2.97
Effect of fixed-price contract settlements (1). . . .03 (.49) (.34) (.22)
-------- -------- -------- --------
Total . . . . . . . . . . . . . . . . . . . . . . . $ 4.62 $ 2.92 $ 5.46 $ 2.75
======== ======== ======== ========
Average sales price (per Mcfe) . . . . . . . . . . . $ 4.58 $ 3.05 $ 5.32 $ 2.90
OPERATING AND OVERHEAD COSTS: (per Mcfe)
Lease operating expenses . . . . . . . . . . . . . . $ .50 $ .40 $ .50 $ .40
Production taxes . . . . . . . . . . . . . . . . . . .27 .20 .33 .17
General and administrative . . . . . . . . . . . . . .20 .17 .20 .18
-------- -------- -------- --------
Total. . . . . . . . . . . . . . . . . . . . . . . . $ .97 $ .77 $ 1.03 $ .75
======== ======== ======== ========
Cash operating margin (per Mcfe) (2) . . . . . . . . $ 3.61 $ 2.28 $ 4.29 $ 2.15
Depreciation, Depletion and Amortization - Oil and
Gas (per Mcfe). . . . . . . . . . . . . . . . . . . $ .91 $ .88 $ .92 $ .90
<FN>
(1) - Represents the realized hedging results from our fixed-price contracts. See
"Quantitative and Qualitative Disclosures About Market Risk - Fixed-Price Contracts."
These amounts do not include any change in derivative fair value included in results of
operations for the respective period.
(2) - Cash operating margin is defined as oil and gas sales less lease operating expenses,
production taxes and general and administrative costs.
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 JUNE 30, 2001 COMPARED TO THREE
MONTHS ENDED JUNE 30, 2000
Net Income and Cash Flows from Operating Activities. For the quarter ended
June 30, 2001, we realized net income of $47.8 million, or $1.07 per diluted
share, on total revenue of $157.4 million. This compares to net income of
$9.1 million, or $.22 per diluted share, on total revenue of $88.0 million for
the second quarter of 2000. Net income excluding the non-cash impact of SFAS
133 derivative accounting was $47.9 million, or $1.07 per diluted share, for
the second quarter of 2001 and $16.5 million or $.39 per diluted share, for
the second quarter of 2000.
Cash flows from operating activities (before working capital changes) for
the second quarter of 2001 grew 72% to $111.9 million compared to $64.9
million for the second quarter of 2000. EBITDAX for the quarter ended June
30, 2001 improved 66% to $124.6 million. This compares to EBITDAX of $74.9
million for the prior year quarter. The increases in earnings, operating cash
flows and EBITDAX for the current year quarter were primarily the result of
higher crude oil and natural gas prices and higher production. Cash flows
provided by operating activities after consideration of the net change in
working capital increased to $114.2 million from the $64.6 million reported
for the second quarter of 2000, primarily for these same reasons.
Production. Total production for the second quarter grew 5% to 34.2 Bcfe
compared to 32.5 Bcfe produced during the second quarter of 2000. Gas
production increased to 29.6 Bcf compared to 28.4 Bcf for the second quarter
of 2000, an increase of 4%. Oil production for the second quarter of 2001
increased 10% to 762 MBbls compared to 690 MBbls for the prior-year second
quarter.
Oil and Gas Prices. Our natural gas production yielded an average price of
$4.62 per Mcf, an increase of 58% compared to $2.92 per Mcf for the prior-year
second quarter. Our average gas price for the second quarter of 2001 was
enhanced $.03 per Mcf as a result of our hedging activities. The average gas
price for the second quarter of 2000 was reduced $.49 per Mcf as a result of
the fixed-price contracts in effect for that period. The average oil price
for the second quarter of 2001 was $25.80 per Bbl compared to $23.67 per Bbl
for the prior-year second quarter, an increase of 9%. The 2000 second quarter
average oil price was reduced $3.79 per Bbl as a result of our hedging
activities. No fixed-price oil contracts were in effect during the second
quarter of 2001. On a natural gas equivalent basis, we received an average
price of $4.58 per Mcfe for the second quarter of 2001, an increase of 50%
from the $3.05 per Mcfe received for the second quarter of 2000.
The combination of higher gas prices and higher production increased gas
sales to $136.9 million for the second quarter of 2001 compared to $82.8
million for the second quarter of 2000. The combined effect of higher oil
prices and higher production increased oil sales to $19.7 million compared to
$16.3 million reported for the prior-year quarter. The impact of fixed-price
contract settlements for each period was to increase oil and gas sales by $.9
million for the quarter ended June 30, 2001 and to decrease oil and gas sales
by $16.6 million for the quarter ended June 30, 2000. See "Quantitative and
Qualitative Disclosures About Market Risk."
15
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
Change in Derivative Fair Value. Amounts recorded in this caption represent
non-cash gains and losses created by valuation changes in derivatives or
portions of derivatives which are not entitled to receive hedge accounting.
All amounts recorded in this caption are ultimately reversed in this caption
over the respective contract term. Change in derivative fair value for the
second quarter of 2001 was a net loss of $.1 million, which included a $1.9
million gain attributable to the change in fair value for certain cash flow
hedges which did not meet the effectiveness guidelines of SFAS 133 for the
quarter, a $3.7 million net loss attributable to the reversal of contract fair
value gains and losses recognized in earnings prior to actual settlement, and
a gain of $1.7 million relating to hedge ineffectiveness. Change in
derivative fair value for the second quarter of 2000 was a net loss of $11.9
million, which included $9.3 million of losses attributable to the change in
fair value for certain cash flow hedges which did not meet the effectiveness
guidelines of SFAS 133, $.5 million of net losses relating to hedge
ineffectiveness, and $2.1 million of losses relating to the reversal of
contract fair value gains and losses recognized in earnings prior to actual
settlement. Despite failing the effectiveness guidelines of SFAS 133 from
time to time, our fixed-price contracts continue to be highly effective in
achieving the risk management objectives for which they were intended.
Other Income. Other income for the second quarter of 2001 was $.9 million
compared to $.8 million reported for the second quarter of 2000.
Operating Costs. Operating costs for the second quarter of 2001 were
comprised of $17.1 million of lease operating expenses and $9.1 million of
production taxes. This compares to $13.1 million of lease operating expenses
and $6.4 million of production taxes for the second quarter of 2000. The
increase in production taxes is primarily the result of higher oil and gas
prices in the second quarter of 2001. The increase in lease operating
expenses is due primarily to increases in service industry costs, higher ad
valorem taxes and the costs attributable to properties acquired and drilled
over the previous twelve-month period. Lease operating expenses on a natural
gas equivalent unit of production basis increased to $.50 per Mcfe for the
three months ended June 30, 2001 compared to $.40 for the three months ended
June 30, 2000.
General and Administrative Expense. General and administrative expense, or
G&A, for the second quarter of 2001 was $6.8 million, an increase of 21% from
the prior-year second quarter amount of $5.6 million. The net change between
the periods is primarily attributable to higher personnel costs incurred in
the current year quarter. On a natural gas equivalent unit of production
basis, G&A increased to $.20 per Mcfe for the second quarter of 2001 compared
to $.17 per Mcfe for the second quarter of 2000.
Exploration Costs. Exploration costs, comprised of geological and
geophysical costs, or G&G costs, exploratory dry holes and leasehold
impairment costs, were $4.3 million for the quarter ended June 30, 2001,
compared to $4.0 million for the second quarter of 2000. The 2001 amount
consists of $2.9 million of dry hole costs, $1.2 million of seismic
acquisition and other G&G costs and $.2 million of leasehold costs. The 2000
amount consists of $1.0 million of dry hole costs, $2.5 million of seismic
16
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
acquisition costs and other G&G costs and $.5 million of leasehold costs.
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization, or DD&A, for the second quarter of 2001 was $32.3 million
compared to $29.8 million for the prior-year second quarter. This increase in
DD&A is attributable to an increase in the oil and gas DD&A rate and higher
production. The oil and gas DD&A rate per equivalent unit of production was
$.91 for the 2001 second quarter compared to $.88 for the second quarter of
2000. This increase in rate is attributable to an increase in production from
certain higher cost properties.
Impairment. For the quarter ended June 30, 2001, an impairment charge of
$2.6 million was recorded which primarily relates to a downward reserve
revision for a single-well offshore field drilled in 1998. For the quarter
ended June 30, 2000, an impairment charge of $4.6 million was recorded related
to two single-well offshore fields. We are unaware of any other fields which
may be impaired because of performance or other reasons. However, future
impairments may be recognized as a result of numerous factors, all of which
are beyond our ability to control or predict.
Interest Expense. Interest expense for the second quarter of 2001 was $7.9
million compared to $9.9 million for the second quarter of 2000. This
decrease is primarily attributable to lower average outstanding debt during
the current year quarter. The net impact of interest rate swaps in effect for
each period was immaterial. See "Capital Resources and Liquidity -- Credit
Facility."
Income Taxes. For the second quarter of 2001, a tax provision of $29.6
million was recorded on pretax income of $77.4 million, an effective rate of
38%. This compares to a tax provision of $5.6 million on pretax income of
$14.6 million, an effective rate of 38%, for the second quarter of 2000.
RESULTS OF OPERATIONS -- SIX MONTHS ENDED JUNE 30, 2001 COMPARED TO SIX MONTHS
ENDED JUNE 30, 2000
Net Income and Cash Flows from Operating Activities. We realized net income
of $121.2 million, or $2.71 per diluted share, on total revenue of $369.4
million for the six months ended June 30, 2001. This compares with net income
of $17.9 million, or $.43 per diluted share, on total revenue of $168.5
million for the six months ended June 30, 2001. Net income excluding the
non-cash impact of SFAS 133 derivative accounting was $119.3 million, or $2.67
per diluted share, for the six months ended June 30, 2001, and $30.4 million,
or $.73 per diluted share, for the six months ended June 30, 2000.
Cash flows from operating activities (before working capital changes) for
the first six months of 2001 grew 109% to $250.3 million, compared to $120.0
million for the first six months of 2000. EBITDAX for the first six months of
2001 improved 111% to $296.2 million, compared to EBITDAX of $140.3 million
for the six months ended June 30, 2000. The increase in earnings, operating
cash flows and EBITDAX for the current year six-month period was primarily the
result of higher oil and gas prices and higher production in relation to the
first six months of 2000. Cash flows provided by operating activities after
consideration of the net change in working capital increased to $311.1 million
compared to $116.4 million reported for the comparable period of 2000,
17
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
primarily for these same reasons.
Production. Total production for the first six months of 2001 was 68.7 Bcfe
compared to 64.3 Bcfe for the comparable prior-year period, an increase of 7%.
Gas production increased to 59.6 Bcf compared to 56.0 Bcf for the first half
of 2000, an increase of 6%. Oil production for the first six months of 2001
increased 9% to 1.5 MMBbls compared to 1.4 MMBbls for the first six months of
2000.
Oil and Gas Prices. Gas production yielded an average price of $5.46 per
Mcf, an increase of 99% compared to $2.75 per Mcf for the prior-year six-month
period. The average gas price for the first six months of 2001 was reduced
$.34 per Mcf as a result of fixed-price contracts. The average gas price for
the first six months of 2000 was reduced $.22 per Mcf as a result of the
fixed-price contracts in effect for that period. The average oil price for
the first half of 2001 was $26.41 per Bbl compared to $23.48 per Bbl for the
first half of 2000, an increase of 12%. Fixed-price contracts in effect
during the first six months of 2000 decreased the average oil price by $3.80
per Bbl. No fixed-price oil contracts were in effect during the first six
months of 2001. On a natural gas equivalent basis, we received an average
price of $5.32 per Mcfe for the first six months of 2001, an increase of 83%
from the $2.90 per Mcfe received for the first six months of 2000.
The combined effect of higher gas prices and higher production increased gas
sales to $325.1 million for the first six months of 2001 compared to $153.9
million for the first six months of 2000. The combined effect of higher oil
prices and higher production increased oil sales to $40.0 million compared to
$32.6 million reported for the prior-year six-month period. The impact of
fixed-price contract settlements for each period was to decrease oil and gas
sales by $20.4 million for the six months ended June 30, 2001 and to decrease
oil and gas sales by $17.7 million for the six months ended June 30, 2000.
See "Quantitative and Qualitative Disclosures About Market Risk -- Fixed-Price
Contracts."
Change in Derivative Fair Value. Amounts recorded in this caption represent
non-cash gains and losses created by valuation changes in derivatives or
portions of derivatives which are not entitled to receive hedge accounting.
All amounts recorded in this caption are ultimately reversed in this caption
over the respective contract term. Change in derivative fair value for the six
months ended June 30, 2001 was a net gain of $3.0 million, which included a
$2.8 million gain attributable to the change in fair value for certain cash
flow hedges which did not meet the effectiveness guidelines of SFAS 133 for
the period, a $5.3 million net loss attributable to the reversal of contract
fair value gains and losses recognized in earnings prior to actual settlement,
and a gain of $5.5 million relating to hedge ineffectiveness. Change in
derivative fair value for the six months ended June 30, 2000 was a net loss of
$20.1 million which included $16.2 million of losses attributable to the
change in fair value of certain cash flow hedges which did not meet the
effectiveness guidelines of SFAS 133, $.5 million of net gains relating to
hedge ineffectiveness, and $4.4 million of losses relating to the reversal of
contract fair value gains and losses recognized in earnings prior to actual
settlement. Despite certain fixed-price contracts failing the effectiveness
guidelines of SFAS 133 from time to time, our fixed-price contracts continue
to be highly effective in achieving the risk management objectives for which
18
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
they were intended.
Other Income. Other income for the first six months of 2001 and 2000 was
$1.3 million and $2.1 million, respectively.
Operating Costs. Operating costs for the first six months of 2001 were
comprised of $34.1 million of lease operating expenses and $22.5 million of
production taxes. This compares to $25.8 million of lease operating expenses
and $10.8 million of production taxes for the first six months of 2000. The
increase in production taxes is principally attributable to higher oil and gas
prices. The increase in lease operating expenses is due primarily to
increases in service industry costs, higher ad valorem taxes and the costs
attributable to properties acquired and drilled over the previous twelve-month
period. Lease operating expenses on a natural gas equivalent unit of
production basis increased to $.50 per Mcfe compared to $.40 per Mcfe for the
six months ended June 30, 2000.
General and Administrative Expense. G&A for the first six months of 2001
was $13.6 million, compared to $11.7 million for the first six months of 2000.
The net change between the two periods is primarily attributable to an
increase in personnel costs. On a natural gas equivalent unit of production
basis, G&A increased to $.20 per Mcfe for the first six months of 2001
compared to $.18 per Mcfe for the first six months of 2000.
Exploration Costs. Exploration costs, comprised of G&G costs, exploratory
dry holes and leasehold impairment costs, were $18.6 million for the six
months ended June 30, 2001, compared to $7.3 million for the six months ended
June 30, 2000. The 2001 amount consists of $8.1 million of dry hole costs,
$3.0 million of seismic acquisition and other G&G costs and $7.5 million of
leasehold costs. The 2000 amount consists of $1.1 million of dry hole costs,
$3.4 million of seismic acquisition and other G&G costs and $2.8 million of
leasehold costs.
Depreciation, Depletion and Amortization. DD&A for the first half of 2001
was $65.1 million compared to $60.1 million for the first half of 2000. This
increase in DD&A is attributable to an increase in the oil and gas DD&A rate
and higher production. The oil and gas DD&A rate per equivalent unit of
production was $.92 for the first six months of 2001 compared to $.90 for the
first six months of 2000. This increase was primarily the result of an
increase in production from certain higher cost properties.
Impairment. For the six month period ended June 30, 2001, an impairment
charge of $2.6 million was recorded which primarily relates to a downward
reserve revision for a single-well offshore field drilled in 1998. For the
six months ended June 30, 2000, an impairment charge of $4.6 million was
recorded relating to two single-well offshore fields. We are unaware of any
other fields which may be impaired because of performance or other reasons.
However, future impairments may be recognized as a result of numerous factors,
all of which are beyond our ability to control or predict.
Interest Expense. Interest expense for the six months ended June 30, 2001
was $16.8 million compared to $19.3 million for the six months ended June 30,
2000. This decrease is primarily attributable to lower average outstanding
debt during the current-year period. The net impact of interest rate swaps in
19
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
effect for the first six months of 2001 and 2000 was to decrease interest
expense by $.4 million and by $.8 million, respectively. See "Capital
Resources and Liquidity -- Credit Facility."
Income Taxes. For the first half of 2001, a tax provision of $74.9 million
was recorded on pretax income of $196.1 million, an effective rate of 38%.
This compares to a tax provision of $11.0 million provided on pretax income of
$28.9 million, an effective rate of 38%, for the first half of 2000.
CAPITAL RESOURCES AND LIQUIDITY
Cash Flows. Our business of acquiring, exploring and developing oil and gas
properties is capital intensive. Our ability to grow our reserve base is
contingent, in part, upon the ability to generate cash flows from operating
activities and to access outside sources of capital to fund our investing
activities. For the six months ended June 30, 2001 and 2000, we expended
$179.3 million and $257.7 million, respectively, in oil and gas property
acquisition, exploration and development activities, representing
substantially all of the cash flow we invested during each six-month period.
See "-- Commitments and Capital Expenditures." Cash flows from operating
activities before changes in working capital for the six months ended June 30,
2001 and 2000 were $250.3 million and $120.0 million, representing 140% and
47%, respectively, of the oil and gas property investments made for each
period. Substantially all of the cash flows from operating activities are
generated from oil and gas sales which are highly dependent upon oil and gas
prices. Significant decreases in the market prices of oil and gas could
result in reduction of cash flows from operating activities, which in turn
could impact the amount of capital investment.
Cash flows from financing activities for the first six months of 2001
reflected a net use of cash of $92.1 million compared to a $126.8 million
source of cash for the first six months of 2000. This decrease in borrowings
during the current year period was principally the result of the application
of excess operating cash flows for the period. Historically, we have relied
upon availability under various credit facilities and proceeds from equity
offerings to fund our investing activities.
Credit Facility. We have a revolving credit facility with a syndicate of
banks which provides up to $450 million in borrowings. Letters of credit are
limited to $75 million of this availability. The credit facility allows us to
draw on the full $450 million credit line without restrictions tied to
periodic revaluations of our oil and gas reserves provided we continue to
maintain an investment grade credit rating from either Standard & Poor's
Ratings Service or Moody's Investors Service. We presently have senior
unsecured credit ratings of BBB and Baa3 from Standard & Poor's and Moody's,
respectively. A borrowing base can be required only upon the vote by a
majority in interest of the lenders after the loss of an investment grade
credit rating. No principal payments are required under the credit facility
prior to termination on October 14, 2002. We have relied upon the credit
facility to provide funds for acquisitions, drilling activities and to provide
letters of credit to meet margin requirements under fixed-price contracts. As
of June 30, 2001, there was $218.0 million of principal and $12.8 million of
letters of credit outstanding under the credit facility.
20
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
We have the option of borrowing at a LIBOR-based interest rate or the Base
Rate (approximating the prime rate). The LIBOR interest rate margin and the
facility fee payable under the credit facility are subject to a sliding scale
based on our senior debt credit rating. At June 30, 2001, the applicable
interest rate was LIBOR plus 23 basis points and the facility fee was 12 basis
points of the total commitment. The average interest rate for borrowings
under the credit facility was 4.1% as of June 30, 2001. The effective
interest rate including the effect of interest rate swaps was 4.7%. See the
Notes to Consolidated Financial Statements included in our Annual Report on
Form 10-K for the year ended December 31, 2000 for an expanded discussion of
our interest rate swaps. The credit facility contains various affirmative and
restrictive covenants which, among other things, limit total indebtedness to
$700 million ($625 million of senior indebtedness) and require us to meet
certain financial tests. Borrowings under the credit facility are unsecured.
Other Lines of Credit. We have certain other unsecured lines of credit
which aggregated $55.1 million as of June 30, 2001. These short-term lines of
credit are primarily used for working capital purposes. As of June 30, 2001,
we had $11.9 million of indebtedness borrowed under these credit lines.
Outstanding letters of credit were immaterial. Repayment of this indebtedness
is expected to be made through credit facility availability.
6 7/8% Senior Notes due 2007. In December 1997, we issued $200 million
principal amount, $198.8 million net of discount, of 6 7/8% Senior Notes due
2007. Interest is payable semi-annually on June 1 and December 1. The
associated indenture agreement contains restrictive covenants which place
limitations on the amount of liens and our ability to enter into sale and
leaseback transactions.
9 1/4% Subordinated Notes due 2004. In June 1994, we issued $100 million
principal amount, $98.5 million net of discount, of 9 1/4% Senior Subordinated
Notes due 2004. 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. The outstanding principal balance as of June 30, 2001
was $93.7 million.
We believe that the borrowing capacity available under the credit facility,
combined with our internally generated operating cash flows, will be adequate
to finance the capital expenditure program planned for the balance of 2001,
and to meet margin requirements under fixed-price contracts. See "Commitments
and Capital Expenditures" and "Quantitative and Qualitative Disclosures About
Market Risk." At June 30, 2001, we had working capital of $35.2 million and a
current ratio of 1.25 to 1. The working capital amount includes short-term
derivative assets and liabilities which represent the estimated fair value of
contract settlements occurring over the next twelve months. The offsetting
working capital impact of the underlying cash flow transactions hedged by the
contracts for the corresponding periods is not reflected in the balance sheet.
Working capital without the impact of SFAS 133 accounting would decrease by
$41.8 million. Settlement amounts are not received or paid until the monthly
period that the related underlying hedged transaction occurs. Total long-term
debt outstanding at June 30, 2001 was $523.0 million. Long-term debt as a
percentage of total capitalization was 40%.
21
LOUIS DREYFUS NATURAL GAS CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (continued)
COMMITMENTS AND CAPITAL EXPENDITURES
Our business strategy is to generate strong and consistent growth in
reserves, production, operating cash flows and earnings through a balanced
program of exploration and development drilling and strategic acquisitions of
oil and gas properties. For the six months ended June 30, 2001, we invested
$158.7 million in development activities and $15.2 million in exploration
activities. This expenditure level resulted in the drilling of 236
development wells and one exploratory well. Of these wells, 230 development
wells and zero exploratory wells were successfully completed as producers, for
a completion success rate of 97% and 0%, respectively (an overall success rate
of 97%). In addition, $5.6 million was invested in proved reserve
acquisitions. For the balance of the year, we have budgeted an additional
$146 million to be invested in connection with our 2001 drilling program
focused in our core operating areas. See "Outlook for Fiscal 2001".
We continue to actively search for additional attractive oil and gas
property acquisitions, but are not able to predict the timing or amount of
additional capital expenditures which may ultimately be employed in
acquisitions during 2001.
OUTLOOK FOR FISCAL 2001
The following represents revisions to previously disclosed estimates and
have been prepared based on current expectations as of August 9, 2001.
Revenues. The drilling budget for 2001 has been increased to $320 million,
compensating for service industry cost increases since the first of the year.
This amount is subject to further revision. Based on this level of
expenditure, we now expect total production for 2001 to be approximately 5%
higher than 2000's production results. This revision is principally
attributable to delays experienced early in the year in commencing our
drilling program, higher production declines than anticipated in certain Gulf
Coast properties, and production results through June 30, 2001.
We expect that natural gas prices at the wellhead for the balance of 2001
will average $.14 to $.18 per Mcf less than the average of the last three
trading days for the NYMEX Henry Hub index (NYMEX L3D). Crude oil prices are
expected to average $1.80 to $2.20 per Bbl less than the average NYMEX West
Texas Intermediate price (WTI). See "Quantitative and Qualitative Disclosures
About Market Risk" for a discussion of hedges and fixed-prices in effect for
the balance of the year. The impact of contract basis is expected to increase
the average contract price by $.05 to $.10 per Mcf for hedged production.
Expenses. The current tax provision in 2001, which is particularly
susceptible to change with fluctuating commodity prices, is expected to
represent between 35% and 45% of the total tax provision. This change in
guidance is primarily the result of a decline in market prices for oil and gas
for the last six months of 2001.
22
LOUIS DREYFUS NATURAL GAS CORP.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
GENERAL
Our results of operations and operating cash flows are impacted by changes
in market prices for oil and gas and changes in market interest rates. To
mitigate a portion of our exposure to adverse market changes, we entered into
fixed- price contracts and interest rate swaps. Each fixed-price contract and
interest rate swap has been entered into as a hedge of oil and gas price risk
or interest rate risk and not for trading purposes. Information regarding our
market exposures, fixed-price contracts, interest rate swaps and certain other
financial instruments is provided below. All information is presented in U.S.
Dollars.
FIXED-PRICE CONTRACTS
Description of Contracts. Our fixed-price contracts are comprised of
long-term physical delivery contracts, energy swaps, collars, options and
basis swaps. These contracts allow us to predict with greater certainty the
effective oil and gas prices to be received for our hedged production and
benefit us when market prices are less than the fixed prices provided in the
fixed-price contracts. However, we will not benefit from market prices that
are higher than the fixed prices for our hedged production. Collar structures
provide for participation in price increases to the extent of the ceiling
prices provided in those contracts. Purchased put options provide unlimited
participation in price increases. For the years ended December 31, 2000, 1999
and 1998, fixed-price contracts hedged 44%, 55% and 50%, respectively, of our
gas production and 40%, 19% and 16%, respectively, of our oil production. For
the six months ended June 30, 2001, fixed-price contracts hedged 68% of our
natural gas production. As of June 30, 2001, fixed-price contracts are in
place to hedge 219 Bcf of our estimated future natural gas production. Of this
total volume, 41 Bcf are hedged for the remainder of fiscal 2001. Reference is
made to our Annual Report on Form 10-K for the year ended December 31, 2000
for a more detailed discussion of the fixed-price contracts.
The following table summarizes the estimated volumes, fixed prices,
fixed-price sales and future net revenues (as defined below) attributable to
the fixed-price contracts as of June 30, 2001. We expect the prices to be
realized for hedged production to vary from the prices shown in the following
table due to basis, which is the differential between the floating price paid
under each energy swap contract, or the cost of gas to supply physical
delivery contracts and the price received at the wellhead for our hedged
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,
2001, as adjusted for basis. Future net revenues change with changes in
market prices and basis.
23
LOUIS DREYFUS NATURAL GAS CORP.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK(continued)
FIXED-PRICE CONTRACTS
Six
Months
Ending
December Years Ending December 31, Balance
31, -------------------------------------- through
2001 2002 2003 2004 2005 2017 Total
-------- -------- -------- -------- -------- -------- ---------
(dollars in thousands, except price data)
NATURAL GAS SWAPS:
Contract volumes (BBtu). . 16,244 6,697 5,650 5,650 5,650 6,483 46,374
Weighted-average fixed
price per MMBtu (1). . . $ 4.90 $ 2.65 $ 2.92 $ 3.12 $ 3.32 $ 3.41 $ 3.72
Future fixed-price sales . $ 79,635 $ 17,766 $ 16,492 $ 17,608 $ 18,740 $ 22,082 $ 172,323
Future net revenues
(losses) (2). . . . . . . $ 27,498 $ (6,230) $ (3,630) $ (2,484) $ (1,519)$ (1,423) $ 12,212
NATURAL GAS PHYSICAL
DELIVERY CONTRACTS:
Contract volumes (BBtu). . 8,995 17,689 14,819 6,634 5,314 37,512 90,963
Weighted-average fixed
price per MMBtu (1). . . $ 2.39 $ 2.46 $ 2.53 $ 2.53 $ 2.63 $ 3.00 $ 2.70
Future fixed-price sales . $ 21,522 $ 43,461 $ 37,428 $ 16,802 $ 13,978 $112,520 $ 245,711
Future net revenues
(losses) (2) . . . . . . $ (8,141) $(18,530) $(14,069) $ (6,477) $ (4,854)$(26,573) $ (78,644)
NATURAL GAS COLLARS AND
OPTIONS:
Contract volumes (BBtu):
Floor. . . . . . . . . . 15,980 32,850 32,850 -- -- -- 81,680
Ceiling. . . . . . . . . 15,980 20,110 16,470 -- -- -- 52,560
Weighted-average fixed
price per MMBtu (1):
Floor. . . . . . . . . . $ 4.20 $ 4.37 $ 4.36 $ -- $ -- $ -- $ 4.33
Ceiling. . . . . . . . . $ 5.90 $ 5.89 $ 7.00 $ -- $ -- $ -- $ 6.24
Future fixed-price sales
(3). . . . . . . . . . . $ 68,051 $149,004 $143,244 $ -- $ -- $ -- $ 360,299
Future net revenues
(losses) (2) . . . . . . $ 16,655 $ 34,590 $ 37,638 $ -- $ -- $ -- $ 88,883
TOTAL NATURAL GAS
CONTRACTS (4):
Contract volumes (BBtu)
(at floor) . . . . . . . 4 1,219 57,236 53,319 12,284 10,964 43,995 219,017
Weighted-average fixed
price per MMBtu (1). . . $ 4.11 $ 3.67 $ 3.70 $ 2.80 $ 2.98 $ 3.06 $ 3.55
Future fixed-price sales
(3). . . . . . . . . . . $169,208 $210,231 $197,164 $ 34,410 $ 32,718 $134,602 $ 778,333
Future net revenues
(losses) (2) . . . . . . $ 36,012 $ 9,830 $ 19,939 $ (8,961) $ (6,373)$(27,996) $ 22,451
<FN>
(1) - We expect the prices to be realized for our hedged production to vary from the prices
shown due to basis.
(2) - Future net revenues as presented above are undiscounted and have not been adjusted for
contract performance risk or counterparty credit risk. Bracketed amounts represent
decreases to future natural gas sales based on forward market pricing at June 30, 2001.
(3) - Future fixed-price sales for production hedged by collars and options as presented are
calculated based on the floor price if forward market prices at June 30, 2001 were below
the floor price or on the ceiling price if the forward market prices were above the
ceiling price. Otherwise, future fixed-price sales are based on forward market prices.
(4) - Does not include basis swaps with notional volumes by year, as follows: 2001 - 14.7 Tbtu;
2002 - 28.1 TBtu; and 2003 - 11.5 TBtu.
24
LOUIS DREYFUS NATURAL GAS CORP.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK (continued)
The estimates of future net revenues (losses) from fixed-price contracts are
computed based on the difference between the prices provided by the
fixed-price contracts and forward market prices as of the specified date. The
market for natural gas beyond a five year horizon is illiquid and published
market quotations are not available. We have relied upon near-term market
quotations, longer-term over-the-counter market quotations and other market
information to determine future net revenue estimates. Forward market prices
for natural gas are dependent upon supply and demand factors in the forward
market and are subject to significant volatility. The future net revenue
estimates shown above are subject to change as forward market prices change.
The estimated fair values of our fixed-price contracts as of June 30, 2001
and December 31, 2000 are provided below. The associated carrying values of
these contracts are equal to the estimated fair values for each period
presented.
June 30, December 31,
2001 2000
------------- -------------
(in thousands)
Derivative assets:
Fixed-price natural gas swaps. . . . . . . . $ 31,025 $ --
Fixed-price natural gas collars. . . . . . . 90,411 --
Fixed-price natural gas delivery contracts . 986 --
Natural gas basis swaps. . . . . . . . . . . 4,898 --
Interest rate swaps. . . . . . . . . . . . . -- 1,756
Derivative liabilities:
Fixed-price natural gas swaps. . . . . . . . (17,097) (55,923)
Fixed-price natural gas collars. . . . . . . (1,529) (26,054)
Fixed-price natural gas delivery contracts . (70,217) (146,234)
Natural gas basis swaps. . . . . . . . . . . (421) (1,491)
Interest rate swaps. . . . . . . . . . . . . (974) --
------------- -------------
$ 37,082 $ (227,946)
============= =============
The fair value of fixed-price contracts as of June 30, 2001 and December 31,
2000 was estimated based on market prices of natural gas and crude oil for the
periods covered by the contracts. The net differential between the prices in
each contract and market prices for future periods, as adjusted for estimated
basis, has been applied to the volumes stipulated in each contract to arrive
at an estimated future value. This estimated future value was discounted on a
contract-by-contract basis at rates commensurate with our estimation of
contract performance risk and counterparty credit risk. The fair value of
derivative instruments which contain options (such as collar structures) has
been estimated based on remaining term, volatility and other factors. The
terms and conditions of our fixed-price physical delivery contracts and
certain financial swaps are uniquely tailored to our circumstances. In
addition, certain of the contracts hedge gas production for periods beyond
five years into the future. The market for natural gas beyond the five-year
horizon is illiquid and published market quotations are not available. We
have relied upon near-term market quotations, longer-term over-the-counter
market quotations and other market information to determine fair value
25
LOUIS DREYFUS NATURAL GAS CORP.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK (continued)
estimates. The fair value of the interest rate swaps was based on market
interest rates as of each respective date.
INTEREST RATE SENSITIVITY
We have entered into interest rate swaps to hedge the interest rate exposure
associated with borrowings under the bank credit facility. As of June 30,
2001, an average notional amount of $125 million has been hedged for the
balance of 2001, and an average notional amount of $94 million has been hedged
for the year ending December 31, 2002. Under the interest rate swaps, we
receive the LIBOR three-month rate ( 3.8% at June 30, 2001) and pay an average
rate of 5.0% for each period covered by the swaps. The notional amounts are
less than the amount anticipated to be outstanding under the bank credit
facility for the respective periods.
Reference is made to our Annual Report on Form 10-K for the year ended
December 31,2000 for an expanded discussion of the interest rate swaps.
26
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 2001 Annual Meeting of Shareholders was held on May 15, 2001. The
following were submitted to a vote of 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 33,514,419 votes for; 7,465,796 votes withheld;
0 votes abstaining
Simon B. Rich, Jr. 36,860,423 votes for; 4,119,792 votes withheld;
0 votes abstaining
Mark Andrews 38,815,600 votes for; 2,164,615 votes withheld;
0 votes abstaining
Mark E. Monroe 34,973,496 votes for; 6,006,719 votes withheld;
0 votes abstaining
Richard E. Bross 34,970,311 votes for; 6,009,904 votes withheld;
0 votes abstaining
Daniel R. Finn, Jr. 33,397,860 votes for; 7,582,355 votes withheld;
0 votes abstaining
Peter G. Gerry 38,816,693 votes for; 2,163,522 votes withheld;
0 votes abstaining
John H. Moore 38,812,666 votes for; 2,167,549 votes withheld;
0 votes abstaining
James R. Paul 34,927,213 votes for; 6,053,002 votes withheld;
0 votes abstaining
Ernest F. Steiner 36,984,452 votes for; 3,995,763 votes withheld;
0 votes abstaining
Nancy K. Quinn 38,439,690 votes for; 2,540,525 votes withheld;
0 votes abstaining
E. William Barnett 38,816,422 votes for; 2,163,793 votes withheld;
0 votes abstaining
2. The approval of the Louis Dreyfus Natural Gas Corp. 2001 Employee Stock
Purchase Plan. The results of the shareholder vote included 34,466,554
votes for; 6,488,843 votes against; and 24,818 votes abstaining.
3. Ratification of the selection of Ernst & Young as independent auditors
for the year ending December 31, 2001. The results of the shareholder
vote included 40,890,942 votes for; 84,882 votes against; and 4,391
votes abstaining.
Item 5 -- None
Item 6 -- None
27
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: August 13, 2001 /s/ Jeffrey A. Bonney
-----------------------------------
Jeffrey A. Bonney
Executive Vice President and Chief
Financial Officer