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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT UNDER SECTION 13 OR 15 (d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended September 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 No. 1-12905
EEX CORPORATION
(Exact name of Registrant as specified in its charter)
Texas 75-2421863
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
2500 CityWest Blvd.
Suite 1400
Houston, Texas 77042
(Address of principal executive office) (Zip Code)
(713) 243-3100
(Registrant's telephone number, including Area Code)
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 twelve 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 ___
---
Number of shares of Common Stock of Registrant outstanding as of October 31,
2001: 42,491,924
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PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
EEX CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30 September 30
--------------------------------- -------------------------------
2001 2000 2001 2000
-------------- -------------- -------------- ------------
(In thousands, except per share amounts)
Revenues:
Natural gas............................................. $ 32,580 $44,021 $105,117 $122,216
Oil, condensate and natural gas liquids................. 14,239 19,940 48,206 59,420
Cogeneration operations................................. 1,306 1,664 5,194 5,915
Other................................................... 365 358 1,392 1,579
-------------- -------------- -------------- ------------
Total................................................ 48,490 65,983 159,909 189,130
-------------- -------------- -------------- ------------
Costs and Expenses:
Production and operating................................ 8,547 10,076 25,958 29,402
Exploration............................................. 8,662 7,880 37,068 22,134
Depletion, depreciation and amortization................ 17,633 24,608 50,227 70,857
Impairment of producing oil and gas properties.......... -- -- -- 12,200
(Gain) Loss on sales of property, plant and equipment... (29,176) 1,389 (28,841) 3,678
Cogeneration operations................................. 992 1,405 4,460 4,793
General, administrative and other....................... 2,956 4,638 9,457 15,554
Taxes, other than income................................ 2,300 3,412 11,966 7,403
-------------- -------------- -------------- ------------
Total................................................ 11,914 53,408 110,295 166,021
-------------- -------------- -------------- ------------
Operating Income.......................................... 36,576 12,575 49,614 23,109
Other Income--Net......................................... 19 47 90 168
Interest Income........................................... 183 384 784 725
Interest and Other Financing Costs........................ (7,519) (8,861) (23,096) (24,819)
-------------- -------------- -------------- ------------
Income (Loss) Before Income Taxes......................... 29,259 4,145 27,392 (817)
Income Taxes.............................................. 9,281 800 9,281 3,100
Minority Interest Third Party............................. -- 1,674 -- 3,062
-------------- -------------- -------------- ------------
Net Income (Loss)......................................... 19,978 1,671 18,111 (6,979)
Preferred Stock Dividends................................. 3,652 3,373 10,741 9,923
-------------- -------------- -------------- ------------
Net Income (Loss) Applicable to Common Shareholders....... $ 16,326 $(1,702) $ 7,370 $(16,902)
============== ============== ============== ============
Net Income (Loss) Per Share Available to
Common Shareholders:
Basic................................................... $ 0.39 $ (0.04) $ 0.18 $ (0.40)
============== ============== ============== ============
Diluted................................................. $ 0.29 $ (0.04) $ 0.18 $ (0.40)
============== ============== ============== ============
Weighted Average Shares Outstanding:
Basic................................................... 41,723 41,929 41,695 42,110
============== ============== ============== ============
Diluted................................................. 69,863 41,929 41,798 42,110
============== ============== ============== ============
See accompanying notes.
2
EEX CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEET
(UNAUDITED)
September 30 December 31
2001 2000
--------------- ---------------
(In thousands)
ASSETS
------
Current Assets:
Cash and cash equivalents.................................................... $ 5,965 $ 19,791
Accounts receivable--trade (net of allowance of $2,329 and $2,270)........... 62,222 57,539
Other........................................................................ 20,924 22,478
------------ ------------
Total current assets..................................................... 89,111 99,808
------------ ------------
Property, Plant and Equipment (at cost):
Oil and gas properties (successful efforts method)........................... 1,013,523 955,263
Other........................................................................ 8,617 8,160
------------ ------------
Total.................................................................... 1,022,140 963,423
Less accumulated depletion, depreciation and amortization.................... 335,454 323,875
------------ ------------
Net property, plant and equipment........................................ 686,686 639,548
------------ ------------
Deferred Income Tax Assets...................................................... 10,565 19,846
Other Assets.................................................................... 18,200 4,866
------------ ------------
Total.................................................................... $ 804,562 $ 764,068
============ ============
LIABILITIES AND SHAREHOLDERS' EQUITY
------------------------------------
Current Liabilities:
Accounts payable--trade...................................................... $ 55,902 $ 76,999
Bank revolving credit agreement.............................................. 180,000 --
Capital lease obligations.................................................... -- 13,351
Secured notes payable........................................................ 16,278 --
Other........................................................................ 6,398 5,993
------------ ------------
Total current liabilities................................................ 258,578 96,343
------------ ------------
Bank Revolving Credit Agreement................................................. -- 75,000
Capital Lease Obligations....................................................... -- 192,283
Secured Notes Payable........................................................... 120,795 --
Gas Sales Obligation............................................................ 63,191 83,490
Other Liabilities............................................................... 10,336 22,351
Minority Interest Third Party................................................... 5,000 5,000
Shareholders' Equity:
Preferred stock (10,000 shares authorized; 1,862 and 1,755 shares issued;
Liquidation preference of $186,222 and $175,481)......................... 19 18
Common stock ($0.01 par value; 150,000 shares authorized; 42,497 and
42,256 shares issued).................................................... 432 429
Paid in capital.............................................................. 756,761 744,782
Retained (deficit)........................................................... (437,796) (445,166)
Unamortized restricted stock compensation.................................... (1,712) (1,067)
Unearned compensation........................................................ -- (349)
Other comprehensive income................................................... 38,029 --
Treasury stock, at cost (817 and 808 shares)................................. (9,071) (9,046)
------------ ------------
Total shareholders' equity............................................... 346,662 289,601
------------ ------------
Total.................................................................... $ 804,562 $ 764,068
============ ============
See accompanying notes.
3
EEX CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
(UNAUDITED)
Nine Months Ended
September 30
------------------------------------
2001 2000
--------------- ---------------
(In thousands)
OPERATING ACTIVITIES
Net Income (Loss)......................................................... $ 18,111 $ (6,979)
Dry hole cost............................................................. 2,945 (328)
Depletion, depreciation and amortization.................................. 50,227 70,857
Impairment of producing oil and gas properties............................ -- 12,200
Impairment of undeveloped leasehold....................................... 5,896 4,793
Deferred income taxes..................................................... 9,281 3,100
(Gain) Loss on sales of property, plant and equipment..................... (28,841) 3,678
Other..................................................................... (13,826) (18,954)
Changes in current operating assets and liabilities:
Accounts receivable...................................................... 22,591 (18,493)
Other current assets..................................................... 1,554 (1,768)
Accounts payable......................................................... (21,820) (6,155)
Other current liabilities................................................ 405 3,224
--------------- ---------------
Net cash flows provided by operating activities........................ 46,523 45,175
--------------- ---------------
INVESTING ACTIVITIES
Additions of property, plant and equipment................................ (136,657) (127,422)
Proceeds from dispositions of property, plant and equipment............... 59,470 11,760
Other (changes in accruals)............................................... 723 (17,937)
--------------- ---------------
Net cash flows used in investing activities............................ (76,464) (133,599)
--------------- ---------------
FINANCING ACTIVITIES
Borrowings under bank revolving credit agreement.......................... 185,000 200,000
Repayment of borrowings under bank revolving credit agreement............. (80,000) (86,000)
Borrowings under short-term financing agreement........................... -- 45,000
Repayment of borrowings under short-term financing agreement.............. -- (45,000)
Deliveries under the gas sales obligation................................. (20,299) (16,047)
Purchase of treasury stock................................................ (25) (3,723)
Purchase of lessor's equity interest in capital lease..................... (54,416) --
Minority interest third party............................................. -- 3,062
Payments of secured notes payable......................................... (6,340) --
Payments of capital lease obligations..................................... (7,805) (16,810)
--------------- ---------------
Net cash flows provided by financing activities........................ 16,115 80,482
--------------- ---------------
Net Decrease in Cash and Cash Equivalents................................... (13,826) (7,942)
Cash and Cash Equivalents at Beginning of Period............................ 19,791 15,053
--------------- ---------------
Cash and Cash Equivalents at End of Period.................................. $ 5,965 $ 7,111
=============== ===============
Non-Cash Items:
Conversion of forward purchase facilities to treasury stock............... $ -- $ 5,000
See accompanying notes.
4
EEX CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. In the opinion of management, all adjustments (consisting only of normal
recurring accruals) necessary for a fair presentation of the financial
position, results of operations and cash flows for the interim periods
included herein have been made.
2. The preferred stock has a stated value of $100 and a current dividend rate
of 8% per year, payable quarterly. The 8% dividend rate will be adjusted to
a market rate, not to exceed 18%, in January 2006 or upon the earlier
occurrence of certain events, including a change of control. Prior to any
such adjustment of the dividend rate, EEX may, at its option, accrue
dividends or pay them in cash, shares of preferred stock or shares of
common stock. After any adjustment of the dividend rate, dividends must be
paid in cash.
EEX paid dividends in-kind on the preferred stock as follows:
Amount of Dividends Number of Preferred
Date (In millions) Shares Issued
----------------------- ------------------------ ----------------------
September 30, 2001 $3.7 36,514
June 30, 2001 $3.6 35,798
March 31, 2001 $3.5 35,096
3. Payments under the gas sales obligation are amortized using the interest
method through final pay out. Payments made during the third quarter of
2001 related to this obligation were $6 million. Payments made for the nine
months ended September 30, 2001 were $20 million.
4. During the second quarter 2001, EEX terminated its capital lease obligation
and assumed directly notes payable secured by the FPS and Pipelines when it
elected not to replace expiring letters of credit supporting the capital
lease obligation and to purchase the lessor's equity interest in the
capital lease. The annual interest rate on the assumed secured notes is
7.54%. The principal payments under the secured notes are payable in annual
installments due January 2 of each year (except 2006) with the final
installment due in 2009. Prepayment of the notes prior to 2006 may require
EEX to pay make-whole premiums.
Principal payments as of September 30, 2001 under the secured notes are as
follows (in thousands):
2002........................................... $ 16,278
2003........................................... 17,553
2004........................................... 18,928
2005........................................... 17,790
Thereafter..................................... 66,524
------------
Total..................................... $ 137,073
============
5. The termination of the capital lease and assumption of the notes described
in note 4, above, is reflected as a non-cash transaction in the Statement
of Cash Flows for the nine months ended September 30, 2001.
The Statement of Cash Flows for the nine months ended September 30, 2001
also reflects the impact of the adoption of SFAS No. 133, which resulted in
a $38 million non-cash increase in shareholders' equity.
6. EEX is involved in a number of legal and administrative proceedings
incident to the ordinary course of its business. In the opinion of
management, based on the advice of counsel and current assessment, any
liability to EEX relative to these ordinary course proceedings will not
have a material adverse effect on EEX's operations or financial condition.
The operations and financial position of EEX continue to be affected from
time to time in varying degrees by domestic and foreign political
developments as well as legislation and regulations pertaining to
restrictions on oil and gas production, imports and exports, natural gas
regulation, tax increases, environmental regulations and cancellation of
contract rights. Both the likelihood and overall effect of such occurrences
on EEX vary greatly and are not predictable.
EEX has taken and will continue to take into account uncertainties and
potential exposures in legal and administrative proceedings in periodically
establishing accounting reserves.
5
EEX CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
7. Earnings Per Share - The reconciliation between basic and diluted earnings
per common share is as follows:
Three Months Ended Nine Months Ended
September 30 September 30
-------------------------------- --------------------------------
2001 2000 2001 2000
-------------- -------------- -------------- --------------
(In thousands, except per share amounts)
Net income (loss) from continuing operations............... $ 16,326 $(1,702) $ 7,370 $(16,902)
Effect of dilutive securities:
Preferred stock dividends................................ 3,652 -- -- --
Stock options............................................ 44 -- -- --
------------- -------------- -------------- --------------
Net income (loss) from continuing operations applicable
to common shareholders for diluted earnings per share.... $ 20,022 $(1,702) $ 7,370 $(16,902)
============= ============== ============== ==============
Basic weighted average shares outstanding.................. 41,723 41,929 41,695 42,110
Effect of dilutive securities:
Preferred stock.......................................... 27,907 -- -- --
Stock options............................................ 233 -- 103 --
------------- -------------- -------------- --------------
Diluted weighted average shares outstanding................ 69,863 41,929 41,798 42,110
============= ============== ============== ==============
Net income (loss) per share available to common shareholders:
Basic.................................................... $ 0.39 $ (0.04) $ 0.18 $ (0.40)
============== ============== ============== ==============
Diluted.................................................. $ 0.29 $ (0.04) $ 0.18 $ (0.40)
============== ============== ============== ==============
6
EEX CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
8. Segment information has been prepared in accordance with Statement of
Financial Accounting Standards ("SFAS") No. 131, "Disclosures About Segments
of an Enterprise and Related Information." EEX has determined that its
reportable segments are those that are based on EEX's method of internal
reporting and are consistent with its business strategy. EEX has four
reportable segments, which are primarily in the business of natural gas and
crude oil exploration and production: Deepwater Operations, Deepwater
FPS/Pipelines, Onshore/Shelf and International. The accounting policies of
the segments are the same as those described in the summary of significant
accounting policies (See Note 2 to the Consolidated Financial Statements in
Item 8 of EEX's 2000 Annual Report on Form 10-K). Financial information by
operating segment is presented below (in thousands):
Deepwater
--------------------------
Operations FPS/Pipelines Onshore/Shelf International Other(a) Total
---------- ------------- ------------- ------------- -------- -----
Three months ended September 30, 2001:
-------------------------------------
Total Revenues............................. $ -- $ -- $ 32,015 $ 11,643 $ 4,832 $ 48,490
Production and operating costs............. -- 306 4,980 3,261 -- 8,547
Exploration costs.......................... 940 -- 7,236 486 -- 8,662
Depletion, depreciation and amortization... -- 2,271 10,473 4,424 465 17,633
Other costs................................ -- -- 2,297 (b) -- (25,225) (22,928)
---------- ------------- ------------- ------------- --------- --------
Operating Income (Loss).................... (940) (2,577) 7,029 3,472 29,592 36,576
Interest Income and other.................. -- -- -- -- 202 202
Interest and other financing costs......... -- (2,628) (1,662) -- (3,229) (7,519)
---------- ------------- ------------- ------------- --------- --------
Income (Loss) before income taxes.......... $ (940) $ (5,205) $ 5,367 $ 3,472 $ 26,565 $ 29,259
========== ============= ============= ============= ========= ========
Long-Lived Assets.......................... $ 69,341 $ 154,802 $ 431,080 $ 27,948 $ 3,515 $686,686
========== ============= ============= ============= ========= ========
Additions to Long-Lived Assets............. $ (1,615) $ (18) $ 36,174 $ 1,248 $ 88 $ 35,877
========== ============= ============= ============= ========= ========
Three months ended September 30, 2000:
-------------------------------------
Total Revenues............................. $ -- $ -- $ 57,150 $ 14,019 $ (5,186) $ 65,983
Production and operating costs............. -- 364 6,502 3,210 -- 10,076
Exploration costs.......................... 2,354 -- 4,892 634 -- 7,880
Depletion, depreciation and amortization... -- 1,232 14,178 8,771 427 24,608
Other costs................................ -- -- 3,423 (b) -- 7,421 10,844
---------- ------------- ------------- ------------- --------- --------
Operating Income (Loss).................... (2,354) (1,596) 28,155 1,404 (13,034) 12,575
Interest Income and other.................. -- -- -- -- 431 431
Interest and other financing costs......... -- (3,543) (2,309) -- (3,009) (8,861)
---------- ------------- ------------- ------------- --------- --------
Income (Loss) before income taxes.......... $ (2,354) $ (5,139) $ 25,846 $ 1,404 $ (15,612) $ 4,145
========== ============= ============= ============= ========= ========
Long-Lived Assets.......................... $ 75,645 $ 147,584 $ 437,187 $ 39,573 $ 4,847 $704,836
========== ============= ============= ============= ========= ========
Additions to Long-Lived Assets............. $ 11,999 $ (497) $ 26,213 $ 6,747 $ 222 $ 44,684
========== ============= ============= ============= ========= ========
7
EEX CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Deepwater
--------------------------
Operations FPS/Pipelines Onshore/Shelf International Other(a) Total
---------- ------------- ------------- ------------- -------- -----
Nine months ended September 30, 2001:
------------------------------------
Total Revenues............................. $ -- $ -- $ 121,937 $ 39,415 $ (1,443) $ 159,909
Production and operating costs............. -- 610 15,062 10,286 -- 25,958
Exploration costs.......................... 18,131 -- 17,321 1,616 -- 37,068
Depletion, depreciation and amortization... -- 4,899 29,916 14,030 1,382 50,227
Other costs................................ -- 3 12,063 (b) -- (15,024) (2,958)
---------- ------------- ------------- ------------- --------- -------
Operating Income (Loss).................... (18,131) (5,512) 47,575 13,483 12,199 49,614
Interest Income and other.................. -- -- -- -- 874 874
Interest and other financing costs......... -- (9,427) (5,474) -- (8,195) (23,096)
---------- ------------- ------------- ------------- --------- -------
Income (Loss) before income taxes.......... $ (18,131) $ (14,939) $ 42,101 $ 13,483 $ 4,878 $ 27,392
========== ============= ============= ============= ========= =========
Long-Lived Assets.......................... $ 69,341 $ 154,802 $ 431,080 $ 27,948 $ 3,515 $ 686,686
========== ============= ============= ============= ========= =========
Additions to Long-Lived Assets............. $ 4,529 $ 13,499 $ 111,877 $ 6,287 $ 465 $ 136,657
========== ============= ============= ============= ========= =========
Nine months ended September 30, 2000:
------------------------------------
Total Revenues............................. $ -- $ -- $ 150,837 $ 41,178 $ (2,885) $ 189,130
Production and operating costs............. -- 613 17,708 11,081 -- 29,402
Exploration costs.......................... 6,520 -- 13,761 1,853 -- 22,134
Depletion, depreciation and amortization... -- 3,278 46,325 19,971 1,283 70,857
Impairment of producing oil and gas
properties............................... -- -- 200 12,000 -- 12,200
Other costs................................ -- -- 7,997 (b) -- 23,431 31,428
---------- ------------- ------------- ------------- --------- -------
Operating Income (Loss).................... (6,520) (3,891) 64,846 (3,727) (27,599) 23,109
Interest Income and other.................. -- -- -- -- 893 893
Interest and other financing costs......... -- (10,571) (7,553) -- (6,695) (24,819)
---------- ------------- ------------- ------------- --------- -------
Income (Loss) before income taxes.......... $ (6,520) $ (14,462) $ 57,293 $ (3,727) $ (33,401) $ (817)
========== ============= ============= ============= ========= =========
Long-Lived Assets.......................... $ 75,645 $ 147,584 $ 437,187 $ 39,573 $ 4,847 $ 704,836
========== ============= ============= ============= ========= =========
Additions to Long-Lived Assets............. $ 26,531 $ 6,711 $ 75,821 $ 10,981 $ 1,027 $ 121,071
========== ============= ============= ============= ========= =========
____________________
(a) Includes primarily Cogeneration Plant Operations, General and
Administrative, gains/loss on hedging and sale of assets.
(b) Includes taxes other than income.
9. SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities," was adopted January 1, 2001. This statement requires companies
to record derivatives on the balance sheet as assets and liabilities,
measured at fair value. The manner of accounting for gains or losses
resulting from changes in the values of derivatives is determined by the use
of the derivative and whether it qualifies for hedge accounting. The effect
of adoption on January 1, 2001 was a decrease to shareholders' equity of
approximately $20 million. As of September 30, 2001, shareholders' equity
increased by $38 million in accordance with the statement.
8
Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations
Certain statements in this report, including statements of EEX's and
management's expectations, intentions, plans and beliefs, are "forward-looking
statements," within the meaning of Section 21E of the Securities Exchange Act of
1934, as amended, that are subject to certain events, risks and uncertainties
that may be outside EEX's control. See "Forward-Looking Statements--
Uncertainties and Risks."
RESULTS OF OPERATIONS
Quarters Ended September 30, 2001 and 2000
For the third quarter of 2001, EEX reported net income applicable to common
shareholders of $16 million ($0.39 per share), versus a net loss applicable to
common shareholders of $2 million ($0.04 per share) for the same period in 2000.
The current quarter's net income includes net after-tax gains from the sale of
assets of $20 million, primarily arising from the sale of the Llano Field in
September 2001 for $50 million in cash and an overriding royalty interest of up
to 1% of future production. Excluding these gains on asset sales, the third
quarter of 2001 resulted in a net loss of $4 million or ($0.09) per share.
For the third quarter of 2001, total revenues were $48 million, 27% lower than
total revenues in the third quarter of 2000. Natural gas revenues for the third
quarter of 2001 were 26% lower than the same quarter of 2000. This decrease was
due to a 17% decrease in production and an 11% decrease in the average natural
gas sales price. Natural gas production for the third quarter of 2001 was 11
billion cubic feet ("Bcf"), compared with 14 Bcf in the same period of 2000.
The decrease in production is primarily a result of the sale of the offshore
shelf properties in December 2000. The average natural gas sales price per
thousand cubic feet ("Mcf") was $2.89 in the third quarter of 2001, compared
with $3.25 in the same period of 2000. The average natural gas sales price for
the third quarter 2001 includes hedging gains of $4 million and 5,520 billion
British thermal units ("BBtu") delivered under fixed-price physical delivery
contracts and the gas sales obligation at an average price of $2.49 per million
British thermal units ("MMBtu"). The average natural gas sales price of $3.25
per Mcf for the third quarter 2000 includes hedging losses of $7 million and
3,099 BBtu delivered under the gas sales obligation at an average price of $2.41
per MMBtu. Oil revenues for the third quarter of 2001 decreased 29% from the
same quarter of 2000. This decrease was due to a 24% decrease in the average oil
sales price and a 6% decrease in production. Production declined primarily due
to the sale of the offshore shelf properties in December 2000. The average oil
price per barrel during the third quarter of 2001 was $23.81 compared to $31.33
for the same period of 2000.
Costs and expenses for the third quarter of 2001 were $12 million, compared with
$53 million in 2000. Expenses for the third quarter of 2001 were $41 million,
compared to $52 million for the same period of 2000, excluding the impact of
asset sales in each period. Operating expenses (production and operating,
general, administrative and other, and taxes other than income) were $14 million
in the current quarter, 24% lower than the third quarter of 2000. Production
and operating, general, administrative and other and taxes, other than income
decreased primarily due to the sale of the offshore shelf properties.
Exploration expenses for the third quarter of 2001 were $9 million, compared to
$8 million for the same period of 2000. This increase was primarily due to
approximately $2 million in onshore dry hole costs offset by lower geological
and geophysical expenses. Depletion, depreciation and amortization for the
third quarter of 2001 was $18 million, $7 million lower than the same period of
2000, primarily due to the sale of the offshore shelf properties. Gain on
sales of property, plant and equipment for the third quarter 2001 was $29
million, compared to a loss on sales of property, plant and equipment of $1
million in 2000. The gain is associated primarily with the sale of the Llano
Field.
Total interest and other financing costs for the third quarter of 2001,
including interest income, preferred stock dividends and other income, were $11
million, a $1 million decrease from the same period of 2000.
Nine Months Ended September 30, 2001 and 2000
For the nine months ended September 30, 2001, EEX reported net income applicable
to common shareholders of $7 million ($0.18 per share), versus a net loss
applicable to common shareholders of $17 million ($0.40 per share) for the same
period in 2000. The current year's net income includes net after-tax gains from
the sale of assets of $20 million, primarily arising from the sale of the Llano
Field in September 2001. Excluding the gains on asset sales, the nine months
ended September 30, 2001 resulted in a net loss of $12 million or ($0.29) per
share.
9
For the nine months ended September 30, 2001, total revenues were $160 million,
15% lower than total revenues for the nine months ended September 30, 2000.
Natural gas revenues for the first nine months of 2001 were 14% lower than the
first nine months of 2000. This decrease was due to a 24% decrease in
production, offset by a 13% increase in average natural gas sales prices. The
average natural gas sales price per Mcf was $3.28 for the first nine months of
2001, compared with $2.91 in the same period of 2000. The average natural gas
sales price for the nine months ended September 30, 2001 includes hedging losses
of $6 million and 16,367 BBtu delivered under fixed-price physical delivery
contracts and the gas sales obligation at an average price of $2.61 per MMBtu.
The average natural gas sales price of $2.91 per Mcf for the nine months ended
September 30, 2000 includes hedging losses of $9 million and 9,849 BBtu
delivered under the gas sales obligation at an average price of $2.51 per MMBtu.
Natural gas production for the first nine months of 2001 was 32 Bcf, compared
with 42 Bcf in the same period of 2000. The decrease in production is primarily
due to the sale of the offshore shelf properties. Oil revenues decreased 19%,
due to decreased production, primarily due to the sale of the offshore shelf
properties and a decline in average prices. The average oil price during the
first nine months of 2001 decreased to $25.41 from $28.61.
Costs and expenses for the first nine months of 2001 were $110 million, compared
with $166 million for the same period of 2000. Year-to-date expenses were $139
million, compared to $162 million for the same period last year, excluding the
impact of asset sales in each period. Operating expenses (production and
operating, general, administrative and other, and taxes other than income) were
$47 million for the nine months ended September 30, 2001 compared with $52
million for the same period of 2000. Production and operating and general,
administrative and other costs were lower, offset by increased taxes, other than
income. Production and operating costs decreased primarily as a result of the
sale of the offshore shelf properties, offset by an increase in workover
expense. Exploration expenses for the first nine months of 2001 increased to $37
million, compared to $22 million for the same period of 2000. Exploration
expense includes approximately $14 million in costs associated with the stacking
of the Arctic I rig and recognition of the net cost associated with the
assignment of the Arctic I contract through May 2001. Since early June 2001, the
Arctic I contract was fully assumed by third parties for the drilling of one
well expected to be completed in the fourth quarter 2001. Depletion,
depreciation and amortization for the first nine months of 2001 was $50 million,
$21 million lower than the same period of 2000, primarily due to the sale of the
offshore shelf properties. A $12 million charge from the reduction of the
carrying value of the Mudi Field per SFAS 121 was recorded during the second
quarter of 2000. Gain on sales of property, plant and equipment for the nine
months ended 2001 was $29 million compared to a loss of $4 million for the same
period of 2000. The gain is associated primarily with the sale of the Llano
Field during the third quarter of 2001.
Total interest and other financing costs for the first nine months of 2001,
including interest income, preferred stock dividends and other income, were $33
million, a $1 million decrease from the same period of 2000.
10
EEX CORPORATION
SUMMARY OF SELECTED OPERATING DATA
FOR OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30 September 30
------------------------------- -------------------------------
2001 2000 2001 2000
-------------- -------------- -------------- --------------
Sales volume
Natural gas (Bcf) (a).................................. 11.3 13.5 32.0 42.0
Oil, condensate and natural gas liquids (MMBbls) (d)... 0.6 0.6 1.9 2.1
Total volumes (Bcfe) (a)............................. 14.9 17.4 43.5 54.6
Average sales price (b)
Natural gas (per Mcf) (c).............................. $ 2.89 $ 3.25 $ 3.28 $ 2.91
Oil, condensate and natural gas liquids (per Bbl)...... 23.42 31.01 25.04 28.35
Total (per Mcfe) (c)................................. 3.14 3.68 3.52 3.33
Average costs and expenses (per Mcfe) (c)
Production and operating (b)........................... $ 0.57 $ 0.58 $ 0.60 $ 0.54
Exploration............................................ 0.58 0.45 0.85 0.41
Depletion, depreciation and amortization............... 1.18 1.41 1.15 1.30
General, administrative and other...................... 0.20 0.27 0.22 0.29
Taxes, other than income............................... 0.15 0.20 0.27 0.14
_______________________
(a) Billion cubic feet or billion cubic feet equivalent, as applicable. Ratio
of six Mcf of natural gas to one barrel of crude oil, condensate or natural
gas liquids.
(b) Before related production, severance and ad valorem taxes.
(c) One thousand cubic feet or one thousand cubic feet equivalent, as
applicable. Ratio of six Mcf of natural gas to one barrel of crude oil,
condensate or natural gas liquids.
(d) One million barrels of crude oil or other liquid hydrocarbons.
Recent Developments - Onshore
EEX's Onshore U.S. operations achieved a 93% success rate in the 28 wells
drilled in the third quarter. In the development drilling program, 25 of 26
wells resulted in productive completions and all were flowing to sales at the
end of the third quarter. One of the two exploration wells drilled is productive
and is waiting on a pipeline connection.
For the year to date, the Onshore program has achieved an 86% success rate in a
59 well program. The development well success rate is 89% in 55 wells drilled,
and the exploration well success rate is 50% in 4 wells drilled. At the end of
the third quarter, an additional 5 wells are in process of completion and 6
wells are drilling. The Company anticipates drilling 72 onshore wells this year.
During the quarter, eight wells were completed at the Langtry Field, Val Verde
Basin, Texas, (EEX 50% working interest) and tied to sales with a combined gross
initial flow rate of 20 million cubic feet of gas ("MMcf") per day. At the end
of the quarter, gross field production was 44 MMcf per day (16.5 MMcf per day
net to EEX after royalties). At the Vaquillas Ranch Field (EEX 100% working
interest), six wells were completed and tied to sales in the quarter with a
combined gross initial flow rate of 14.5 million cubic feet of gas equivalent
("MMcfe") per day. Field production rates at the end of the quarter were 21
MMcfe per day gross (16 MMcfe per day net to EEX after royalties).
Effective September 1, 2001, EEX sold its non-operating interest in the Sheridan
Field in South Texas for $8.7 million. At the time of the sale EEX's share of
production from the field was approximately 1.6 MMcfe per day.
11
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows
Net cash flows provided by operating activities for the nine months ended
September 30, 2001 were $47 million, an increase of $1 million over the same
period of 2000. This increase was due to a $22 million decrease in receivables
for the nine months ended 2001 compared to an increase of $18 million in
receivables for the comparative period of 2000. This was offset by a decrease
in payables primarily related to funding of the pension plan during the year and
expenses associated with stacking the Arctic I rig and the assignment of the
Arctic I contract during the first quarter 2001. Net cash flows used in
investing activities for the nine months ended September 30, 2001 were $76
million, a $57 million decrease from cash flows used in investing activities for
the same period of 2000. The decrease in investing activities is primarily due
to an increase in proceeds from dispositions of property, plant and equipment of
$48 million, primarily related to the sale of the Llano Field in the third
quarter of 2001. This increase was offset by increased capital spending of $9
million and a favorable change in accruals of $19 million. Net cash flows
provided by financing activities for the nine months ended September 30, 2001
were $16 million, compared to $80 million for the same period of 2000. This
was primarily due to purchasing the lessor's equity interest and terminating the
capital lease during the second quarter of 2001 and decreased net borrowings
during the nine months ended September 30, 2001 compared to the same period of
2000.
Capital Budget
Capital expenditures during the first nine months of 2001 were $137 million. The
Onshore/Shelf segment invested $112 million in capital, including $25 million to
satisfy the remainder of the gas delivery obligation to Encogen One Partners,
Ltd. Capital expenditures during the first nine months of 2001 also include $14
million associated with the purchase of the lessor's equity interest in the
capital lease associated with the FPS and Pipelines. Capital expenditures for
the last quarter of 2001 are expected to be approximately $13 million, for an
estimated total of $150 million in 2001, compared to $181 million in 2000. The
Onshore/Shelf segment is estimated to spend 75-80% of the remaining 2001 capital
budget. Estimated capital expenditures for 2001 will exceed EEX's estimated
operating cash flows by approximately $90 million. EEX intends to fund its
remaining 2001 capital expenditures from operating cash flows, proceeds from
asset sales, and borrowings under the revolving credit agreement. The 2002
capital budget has not been finalized but is not expected to exceed EEX's
operating cash flows. See "Liquidity" and "Forward-Looking Statements
--Uncertainties and Risks" below.
Liquidity
EEX has a $350 million revolving credit line with a group of banks that matures
on June 27, 2002, of which $180 million was outstanding at September 30, 2001,
all of which is classified in current liabilities. The revolving credit
agreement limits, at all times, total debt, as defined in the credit agreement,
to the lesser of 60% of capitalization, as defined, or $1 billion, and prohibits
liens on property except under certain circumstances. As of September 30, 2001,
the debt to capital ratio under the revolving credit agreement was 48% and
unused available credit was approximately $170 million. The interest rate
ranges from the London Inter-Bank Offered Rate (LIBOR) plus 0.55% to 1.30% per
annum, plus a facility fee of 0.20% to 0.45% per annum, depending upon the debt
to capital ratio. As of October 31, 2001, EEX had approximately $210 million
outstanding under the revolving credit agreement.
During the second quarter of 2001, EEX elected to not replace the expiring
letters of credit supporting the capital lease obligation associated with the
FPS and Pipelines and to purchase the lessor's equity interest, terminate the
capital lease and assume directly the debt secured by the FPS and Pipelines, as
provided in the agreements. EEX assumed the remainder of the capital lease
obligation, debt of approximately $137 million, of which $16 million is
classified in current liabilities, at September 30, 2001.
During the third quarter, EEX sold its interest in the Llano Field for $50
million cash plus an overriding royalty interest of 1/2 of 1% for the first 100
million barrels of oil equivalent total production from the Llano Field and 1%
on all production thereafter. The proceeds were used to pay down debt. The
Company intends to sell all of its interests in Indonesia, including its
interest in the Tuban Block, before the end of 2001. The book value of the
properties is approximately $27 million and the proceeds from the anticipated
sale will be used to reduce debt.
12
In December 1999, EEX E&P L.P., a limited partnership indirectly half-owned by
EEX ("E&P L.P."), entered into a prepaid forward sale agreement, the gas sales
obligation, for approximately 50 Bcfe of production from E&P L.P. to be
delivered from January 2000 through December 2004. The gas sales obligation is
secured by the oil and gas properties of E&P L.P. The gas sales obligation may
be prepaid by paying a predetermined amount of approximately $63 million at
September 30, 2001 plus a make-whole for the hedges assumed by the purchaser.
Because of the structure of the transaction, the gas sales obligation is not
included in the definition of debt for purposes of determining the debt to
capital ratio under the bank revolving credit agreement.
In September 2001, EEX began a private offering of $350 million of senior notes
as a part of its plan to simplify its capital structure and restructure its
debt. The offering was deferred because of disruptions in the bond market
following the events of September 11. Consequently, EEX has begun discussions
with the agent banks under the revolving credit agreement to replace that
facility. EEX is seeking a new borrowing base facility that will extend the
maturity of its principal credit facility. The new facility would be secured by
oil and gas properties with borrowings limited to a borrowing base determined by
the amount of reserves. The restructuring may include prepayment of the gas
sales obligation (including related make-whole amounts). See the discussion in
Item 7, "Management's Discussion and Analysis of Financial Condition and Results
of Operations--Liquidity and Capital Resources--Liquidity" and Notes 6 and 10 to
Consolidated Financial Statements in Item 8 of EEX's 2000 Annual Report on Form
10-K. There can be no assurances that EEX will be able to successfully negotiate
an acceptable credit facility. If the Company is unable to negotiate a new
credit facility, it may be unable to maintain certain of its covenants under its
revolving credit agreement which could restrict its ability to draw additional
funds and/or accelerate the maturity of the outstanding indebtedness under the
revolving credit agreement. In such event, EEX may be required to reduce capital
spending and/or sell assets sufficient to meet its current obligations. EEX will
continue to evaluate the bond market with the intent of recommencing its debt
offering when market conditions are favorable. There can be no assurances that
market conditions will improve to permit EEX to access the bond market. Risks
concerning EEX's liquidity are further discussed in "Capital Liquidity and
Funding Risk" below.
As described above and in EEX's 2000 Annual Report on Form 10-K, preserving
liquidity under EEX's current revolving credit agreement and restructuring its
debt involve many risks and uncertainties. These risks and uncertainties are
described in "Forward-Looking Statements--Uncertainties and Risks" below. A
significant adverse financial impact resulting from the occurrence of one or
more of these risks and uncertainties prior to achieving debt restructuring
would significantly impact EEX's liquidity and its ability to carry out its
planned activities.
Forward-Looking Statements--Uncertainties and Risks
Certain statements in this report, including statements of EEX's and
management's expectations, intentions, plans and beliefs, are "forward-looking
statements," within the meaning of Section 21E of the Securities Exchange Act of
1934, as amended, and are subject to certain events, risks and uncertainties
that may be outside EEX's control. These forward-looking statements include
statements of management's plans and objectives for EEX's future operations and
statements of future economic performance; information regarding drilling
schedules, expected or planned production, future production levels of
international and domestic fields, EEX's capital budget and future capital
requirements, EEX's meeting its future capital needs, the level of future
expenditures for environmental costs and the outcome of regulatory and
litigation matters; and the assumptions underlying such forward-looking
statements. Actual results and developments could differ materially from those
expressed in or implied by such statements due to a number of factors,
including, without limitation, those described in the context of such forward-
looking statements and the risk factors set forth below and described from time
to time in EEX's other documents and reports filed with the Securities and
Exchange Commission.
Capital Liquidity and Funding Risk--EEX is exposed to many risks in preserving
liquidity under its existing revolving credit agreement, executing debt
restructure and funding its investment plans (see the discussion above and in
Item 7, "Liquidity and Capital Resources--Capital Budget" in EEX's 2000 Annual
Report on Form 10-K). The amount available under the revolving credit agreement
is limited by a debt to capital ratio; therefore, any event that decreases
equity will reduce liquidity. The principal risks to liquidity are described
below. Any decreases in capitalization through losses incurred from dry hole
expense, asset write-downs, loss on sales or other reasons, or increases in
borrowings or debt (as defined in the revolving credit agreement) will increase
the debt to capital ratio and further limit available borrowings.
EEX's access to financial markets may be limited by general market conditions in
or volatility of the markets, general conditions affecting the oil and gas
industry, or by EEX's financial condition. No assurances can be given that EEX
will be able to secure funds in these markets when necessary, or that such funds
will be obtained on terms favorable to it. If EEX were unable to restructure its
debt or renegotiate the terms of its existing revolving credit agreement, it may
be required to curtail capital spending and/or sell assets sufficient to repay
borrowings under the revolving credit agreement and meet its current
obligations.
13
FPS and Pipeline Valuation--See the discussion under Item 1, "Strategy--Realize
Value from the Cooper Floating Production System ("FPS") and Pipelines" and
"U.S. Exploration and Development--Offshore--Cooper Floating Production System
("FPS") and Pipelines" and Note 11 to Consolidated Financial Statements in Item
8 of EEX's 2000 Annual Report on Form 10-K. The current carrying value of the
FPS and Pipelines of approximately $155 million is based upon a development
scenario in the greater Llano complex that utilizes these assets. The Llano
Field operator has requested a proposal from EEX to evaluate the potential use
of the FPS and Pipelines for a Llano development scenario. EEX and its co-owner
are preparing a bid for submittal to the operator. If the Llano Field owners do
not accept the bid, then valuing these assets based solely upon the potential
development of prospects in the greater Llano complex other than the Llano Field
may no longer be appropriate. An alternate method of valuing the assets may
result in a lower carrying value resulting in an asset impairment charge and a
reduction in equity. A sale of the FPS and/or Pipelines would result in a
required prepayment of the debt associated with the FPS and Pipelines.
Prepayment of the notes prior to 2006 may require EEX to pay make-whole
premiums. While management believes that it can realize the value of the FPS and
Pipelines in a development in the greater Llano complex, there can be no
assurance that this can be accomplished in the near term, or on favorable
financial terms.
Valuation of Greater Llano Complex--The value of EEX's investment in the greater
Llano complex is dependent upon market conditions for the sale of assets in the
deepwater Gulf of Mexico, development of its Jason discovery or other
exploration and appraisal success on its remaining Llano complex leases. A
reduction in value of these assets due to adverse drilling results, limited
development plans or delays in development, reductions in estimated reserve
quantities, or adverse economic conditions, would reduce the capitalization used
in computing the debt to capital ratio which would decrease the amount of funds
available to EEX to borrow under its revolving credit agreement.
Arctic I - Rig Commitment--The majority of the commitment associated with the
Arctic I rig (See Note 17 to Consolidated Financial Statements in Item 8 and the
discussion under "U.S. Exploration and Development--Offshore, Deepwater Gulf of
Mexico Exploration" in EEX's 2000 Annual Report on Form 10-K) has been assumed,
for budget and planning purposes, to be funded by EEX's prospective participants
in its Llano complex exploration and appraisal program. When the Arctic I is
returned to EEX after the drilling of its current well, EEX intends to continue
drilling in the greater Llano complex if it is able to obtain participation of
other industry participants. EEX currently has no firm commitment from co-
owners or other potential participants for the use of the rig. EEX may also
pursue subsidized contract assignments or stack the rig. If EEX cannot find
other participants to share the costs of drilling, EEX would incur expenditures
greater than forecast that could negatively impact equity.
Effect of Adoption of SFAS No. 133--In January 2001, EEX adopted SFAS No. 133
(see the discussion in Item 7, "Management's Discussion and Analysis of
Financial Condition and Results of Operations--Other Matters--New Accounting
Standard" in EEX's 2000 Annual Report on Form 10-K). This accounting standard
requires that EEX mark to market its hedge positions and report the result as an
adjustment to shareholders' equity as other comprehensive income. If future gas
prices are generally higher than EEX's contractual hedge prices, the resulting
decrease to shareholders' equity would decrease available credit under the
revolving credit agreement.
Volatility of Oil and Gas Markets and Commodity Prices--EEX's operations are
highly dependent upon the prices of, and demand for, oil and gas. These prices
have been, and are likely to continue to be, volatile. Prices are subject to
fluctuations in response to a variety of factors that are beyond the control of
EEX, such as worldwide economic and political conditions as they affect actions
of OPEC and Middle East and other producing countries, and the price and
availability of alternative fuels. EEX's hedging activities with respect to
some of its projected gas production, which are designed to protect against
price declines, may prevent EEX from realizing the benefits of price increases
above the levels of the hedges.
Encogen Obligation--In January 2002, the obligor of a production payment due to
EEX may elect to purchase a portion of the obligation (See the discussion in
Item 7, "Management's Discussion and Analysis of Financial Condition and Results
of Operations--Impairment of Assets" in EEX's 2000 Annual Report on Form 10-K).
If the obligor purchases this portion of the asset, or such purchase becomes
probable, in the opinion of management, then the Company would realize a loss on
the sale of approximately $18 million. Based upon available information,
management cannot predict at this time the likelihood that the obligor will
elect to purchase the additional volumes.
Exploration Risk--Exploration for oil and gas in the Deepwater Gulf of Mexico
and unexplored frontier areas has inherent and historically high risk. EEX is
focusing on exploration opportunities in onshore, offshore and international
areas. Future reserve increases and production will be dependent on EEX's
success in these exploration efforts and no assurances can be given of such
success. Exploration may involve unprofitable efforts, not only with respect to
dry wells, but also with respect to wells that are productive but do not produce
sufficient net revenues to return a profit after drilling, operating and other
costs.
14
Operational Risks and Hazards--EEX's operations are subject to the risks and
uncertainties associated with finding, acquiring and developing oil and gas
properties, and producing, transporting and selling oil and gas. Operations may
be materially curtailed, delayed or canceled as a result of numerous factors,
such as accidents, weather conditions, compliance with governmental requirements
and shortages or delays in the delivery of equipment. Operating hazards such as
fires, explosions, blow-outs, equipment failures, abnormally pressured
formations and environmental accidents may have a material adverse effect on
EEX's operations or financial condition. EEX's ability to sell its oil and gas
production is dependent on the availability and capacity of gathering systems,
pipelines and other forms of transportation.
Offshore Risks--EEX's Gulf of Mexico oil and gas prospects include properties
located in water depths greater than 2,000 feet where operations are by their
nature more difficult than drilling operations conducted on land in established
producing areas. Deepwater drilling and operations require the application of
more advanced technologies that involve a higher risk of mechanical failure and
can result in significantly higher drilling and operating costs which, in turn,
can require greater capital investment than anticipated and materially change
the expected future value of offshore development projects. The size of oil and
gas reserves determined through exploration and confirmation drilling operations
must ultimately be significant enough to justify the additional capital required
to construct and install production and transportation systems and drill
development wells. Development of any discoveries made pursuant to EEX's
Deepwater exploration program may not return any profit to it and could result
in an economic loss. Furthermore, offshore operations require a significant
amount of time between the discovery and the time the gas or oil is actually
marketed, increasing the market risk involved with such operations.
Estimating Reserves and Future Net Cash Flows--Uncertainties are inherent in
estimating quantities and values of reserves and in projecting rates of
production, net revenues and the timing of development expenditures. Reserve
data represent estimates only of the recovery of hydrocarbons from underground
accumulations and are often different from the quantities ultimately recovered.
Downward adjustments in reserve estimates could adversely affect EEX. Also, any
substantial decline in projected net revenues resulting from production of
reserves, whether due to lower volumes or prices, could have a material adverse
effect on EEX's financial position and results of operations.
Government Regulation--EEX's business is subject to certain federal, state and
local laws and regulations relating to the drilling for and the production of
oil and gas, as well as environmental and safety matters. Enforcement of or
changes to these regulations could have a material impact on EEX's operations,
financial condition and results of operations.
International Operations--EEX's interests in properties in countries outside the
United States are subject to the various risks inherent in foreign operations.
These risks may include, among other things, loss of property and equipment as a
result of expropriation, nationalization, war, insurrection and other political
risks, risks of increases in taxes and governmental royalties, renegotiations of
contracts with governmental entities, changes in laws and policies governing
operations of foreign-based companies and other uncertainties arising out of
foreign government sovereignty over EEX's international operations. EEX's
international operations may also be adversely affected by laws and policies of
the United States affecting foreign trade, taxation and investment. In addition,
in the event of a dispute arising from foreign operations, EEX may be subject to
the exclusive jurisdiction of foreign courts or may not be successful in
subjecting foreign persons to the jurisdiction of the courts of the United
States.
15
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Hedging activity for the third quarter ended September 30, 2001 resulted in a
gain of approximately $4 million for natural gas. For the nine months ended
September 30, 2001, the hedging loss was approximately $6 million. The table
below provides information about EEX's hedging instruments as of September 30,
2001. The Notional Amount is equal to the volumetric hedge position of EEX
during the periods. The fair values of the hedging instruments, which have been
recorded in other comprehensive income, are based on the difference between the
applicable strike price and the New York Mercantile Exchange future prices for
the applicable trading months.
Notional Average Fair Value at
Amount Strike Price September 30, 2001
(BBtu) (1) (Per MMBtu) (2) (In thousands)
------------------- ------------------------------- -----------------------
Floor Ceiling
------------- -------------
Natural Gas Collars:
October 2001 - December 2001........ 2,760 $3.242 $4.962 $2,783
January 2002 - March 2002........... 1,350 3.854 6.137 1,393
April 2002 - June 2002.............. 1,365 3.374 5.658 813
------------------- -----------------------
Total............................ 5,475 $4,989
=================== =======================
Notional Average Fair Value at
Amount Swap Price September 30, 2001
(BBtu) (1) (Per MMBtu) (2) (In thousands)
----------------------- ----------------------- -----------------------
Natural Gas Swaps:
October 2001 - December 2001........ 2,150 $4.24 $ 4,380
January 2002 - March 2002........... 4,500 4.38 7,026
April 2002 - June 2002.............. 4,550 3.95 5,308
July 2002 - September 2002.......... 4,600 4.03 5,209
October 2002 - December 2002........ 4,600 4.20 5,015
January 2003 - March 2003........... 2,700 3.93 1,708
April 2003 - June 2003.............. 2,730 3.59 1,451
July 2003 - September 2003.......... 2,760 3.67 1,485
October 2003 - December 2003........ 2,760 3.84 1,458
----------------------- -----------------------
Total............................ 31,350 $33,040
======================= =======================
______________________
(1) Billions of British Thermal Units.
(2) Millions of British Thermal Units.
16
PART II. OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
10.1 Purchase and Sale Agreement dated August 30, 2001, between
EEX and Amerada Hess Corporation, without exhibits and
schedules.
(b) Reports on Form 8-K
Current Report on Form 8-K filed August 1, 2001 and dated July 27,
2001 (news release --- second quarter results conference call).
Current Report on Form 8-K filed September 10, 2001 and dated
September 4, 2001 (news releases --- onshore performance, Sheridan
Field sale and Llano Field sale).
17
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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.
EEX CORPORATION
(Registrant)
Dated: November 2, 2001 By: /s/ R. S. Langdon
---------------------------------
R. S. Langdon
Executive Vice President,
Finance and Administration,
and Chief Financial Officer
18
EXHIBIT INDEX
Exhibit
Number Description
------- -----------
10.1 Purchase and Sale Agreement dated August 30, 2001, between
EEX and Amerada Hess Corporation, without exhibits and
schedules.