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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, 2000
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,
2000: 42,277,405
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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
--------------------------------- -------------------------------
2000 1999 2000 1999
-------------- -------------- -------------- ------------
(In thousands, except per share amounts)
Revenues:
Natural gas........................................... $ 44,021 $ 24,349 $ 122,216 $ 69,637
Oil, condensate and natural gas liquids............... 19,940 24,141 59,420 57,949
Cogeneration operations............................... 1,664 1,545 5,915 6,486
Other................................................. 358 52 1,579 (447)
-------------- -------------- -------------- -------------
Total.............................................. 65,983 50,087 189,130 133,625
-------------- -------------- -------------- -------------
Costs and Expenses:
Production and operating.............................. 10,076 9,352 29,402 28,809
Exploration........................................... 7,880 9,537 22,134 55,022
Depletion, depreciation and amortization.............. 24,608 16,428 70,857 54,719
Impairment of producing oil and gas properties........ --- --- 12,200 ---
Loss (Gain) on sales of property, plant and equipment. 1,389 (747) 3,678 (1,258)
Cogeneration operations............................... 1,405 1,566 4,793 6,105
General, administrative and other..................... 4,638 7,104 15,554 20,398
Taxes, other than income.............................. 3,412 1,424 7,403 3,399
-------------- -------------- -------------- -------------
Total.............................................. 53,408 44,664 166,021 167,194
-------------- -------------- -------------- -------------
Operating Income (Loss)................................. 12,575 5,423 23,109 (33,569)
Other Income--Net....................................... 47 221 168 57
Interest Income......................................... 384 1,324 725 4,384
Interest and Other Financing Costs...................... (8,861) (4,442) (24,819) (12,707)
-------------- -------------- -------------- -------------
Income (Loss) Before Income Taxes....................... 4,145 2,526 (817) (41,835)
Income Taxes............................................ 800 1,067 3,100 2,287
Minority Interest Third Party........................... 1,674 --- 3,062 ---
-------------- -------------- -------------- -------------
Net Income (Loss)....................................... 1,671 1,459 (6,979) (44,122)
Preferred Stock Dividends............................... 3,373 3,116 9,923 8,938
-------------- -------------- -------------- -------------
Net (Loss) Applicable to Common Shareholders............ $ (1,702) $ (1,657) $ (16,902) $ (53,060)
============== ============== ============== =============
Net (Loss) Per Share Available to Common Shareholders:
Basic................................................. $ (0.04) $ (0.04) $ (0.40) $ (1.26)
============== ============== ============== =============
Diluted............................................... $ (0.04) $ (0.04) $ (0.40) $ (1.26)
============== ============== ============== =============
Weighted Average Shares Outstanding:
Basic..................................................... 41,929 42,200 42,110 42,200
============== ============== ============== =============
Diluted................................................... 41,929 42,200 42,110 42,200
============== ============== ============== =============
See accompanying notes.
2
EEX CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEET
(UNAUDITED)
September 30 December 31
2000 1999
------------- -----------
(In thousands)
ASSETS
------
Current Assets:
Cash and cash equivalents.................................................... $ 7,111 $ 15,053
Restricted cash.............................................................. --- 5,000
Accounts receivable--trade (net of allowance of $2,329 and $1,791)........... 46,741 28,248
Other........................................................................ 14,505 12,737
------------- -----------
Total current assets..................................................... 68,357 61,038
------------- -----------
Property, Plant and Equipment (at cost):
Oil and gas properties (successful efforts method)........................... 1,246,245 1,259,364
Other........................................................................ 8,598 8,047
------------- -----------
Total.................................................................... 1,254,843 1,267,411
Less accumulated depletion, depreciation and amortization.................... 550,007 576,914
------------- -----------
Net property, plant and equipment........................................ 704,836 690,497
------------- -----------
Deferred Income Tax Assets...................................................... 19,709 22,809
Other Assets.................................................................... 2,894 6,440
------------- -----------
Total.................................................................... $ 795,796 $ 780,784
============= ===========
LIABILITIES AND SHAREHOLDERS' EQUITY
------------------------------------
Current Liabilities:
Accounts payable--trade...................................................... $ 48,426 $ 72,518
Current portion of capital lease obligations................................. 13,351 16,810
Other........................................................................ 5,804 2,580
------------- -----------
Total current liabilities................................................ 67,581 91,908
------------- -----------
Bank Revolving Credit Agreement................................................. 114,000 ---
Capital Lease Obligations....................................................... 192,283 205,634
Gas Sales Obligation............................................................ 88,953 105,000
Other Liabilities............................................................... 47,331 80,329
Minority Interest Third Party................................................... 6,112 3,050
Shareholders' Equity:
Preferred stock (10,000 shares authorized; 1,720 and 1,621 shares issued;
Liquidation preference of $172,040 and $162,117)......................... 17 16
Common stock ($0.01 par value; 150,000 shares authorized; 43,083 and
42,483 shares issued).................................................... 430 424
Paid in capital.............................................................. 741,574 729,925
Retained (deficit)........................................................... (451,650) (434,748)
Unamortized restricted stock compensation.................................... (1,410) (443)
Unearned compensation........................................................ (391) ---
Treasury stock, at cost (805 and 14 shares).................................. (9,034) (311)
------------- -----------
Total shareholders' equity............................................... 279,536 294,863
------------- -----------
Total.................................................................... $ 795,796 $ 780,784
============= ===========
See accompanying notes.
3
EEX CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
(UNAUDITED)
Nine Months Ended
September 30
-----------------------------------
2000 1999
--------------- --------------
(In thousands)
OPERATING ACTIVITIES
Net (Loss)............................................................... $ (6,979) $ (44,122)
Dry hole cost............................................................ (328) 27,625
Depletion, depreciation and amortization................................. 70,857 54,719
Impairment of producing oil and gas properties........................... 12,200 ---
Impairment of undeveloped leasehold...................................... 4,793 2,907
Deferred income taxes.................................................... 3,100 2,384
Loss (Gain) on sales of property, plant and equipment.................... 3,678 (1,258)
Other.................................................................... (18,954) (4,309)
Changes in current operating assets and liabilities:
Accounts receivable..................................................... (18,493) 16,658
Other current assets.................................................... (1,768) (249)
Accounts payable........................................................ (6,155) (12,987)
Other current liabilities............................................... 3,224 (2,692)
--------------- --------------
Net cash flows provided by operating activities....................... 45,175 38,676
--------------- --------------
INVESTING ACTIVITIES
Additions of property, plant and equipment............................... (127,422) (106,554)
Proceeds from dispositions of property, plant and equipment.............. 11,760 ---
Other (changes in accruals).............................................. (17,937) 10,309
--------------- --------------
Net cash flows used in investing activities........................... (133,599) (96,245)
--------------- --------------
FINANCING ACTIVITIES
Issuance of preferred stock and common stock warrants.................... --- 150,000
Borrowings under bank revolving credit agreement......................... 200,000 80,000
Repayment of borrowings under bank revolving credit agreement............ (86,000) (80,000)
Borrowings under short-term financing agreement.......................... 45,000 2,000
Repayment of borrowings under short-term financing agreement............. (45,000) (2,000)
Deliveries under the gas sales obligation................................ (16,047) ---
Minority interest third party............................................ 3,062 ---
Purchase of treasury stock............................................... (3,723) ---
Payments of capital lease obligations.................................... (16,810) (10,436)
--------------- --------------
Net cash flows provided by financing activities....................... 80,482 139,564
--------------- --------------
Net Increase (Decrease) in Cash and Cash Equivalents....................... (7,942) 81,995
Cash and Cash Equivalents at Beginning of Period........................... 15,053 15,588
--------------- --------------
Cash and Cash Equivalents at End of Period................................. $ 7,111 $ 97,583
=============== ==============
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.
In 2000, EEX paid dividends in-kind on the preferred stock as follows:
Amount of Dividends Number of Preferred
Date (In millions) Shares Issued
--------------------- ----------------------- ----------------------
September 30, 2000 $3.4 33,734
June 30, 2000 $3.3 33,071
March 31, 2000 $3.2 32,423
3. Early in 1998, EEX entered into two forward purchase facilities to
repurchase shares of its common stock. EEX initiated several transactions
under these facilities, which allowed for settlement, at EEX's option, by
paying cash in exchange for physical delivery of the shares to EEX, or on a
net basis in either shares of EEX common stock or in cash. As of the end of
August 2000, EEX settled these two facilities by paying $8.7 million (of
which $7.6 million was previously deposited and classified as restricted
cash) for physical delivery of 796,532 shares to EEX. These shares are
recorded as treasury shares in the Condensed Consolidated Balance Sheet.
Under the terms of the facilities, EEX had previously deposited $7.6
million in cash collateral accounts, $5 million deposited in 1999 and the
remaining $2.6 million deposited in 2000. The $5 million deposited in 1999
is shown as a non-cash transaction in the Condensed Consolidated Statement
of Cash Flows for the nine months ended September 30, 2000.
4. Payments under the gas sales obligation are amortized using the interest
method through final pay out. Payments made during the first three quarters
of 2000 related to this obligation were $4.7 million, $6.0 million and $5.4
million, respectively.
5. 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.
In Gracy Fund, et al. v. EEX Corporation, et al., EEX, its insurers and co-
defendants reached an agreement with counsel for plaintiffs to settle the
case for a total amount of $25 million, of which EEX contributes $1.25
million. Under a Memorandum of Understanding dated as of June 22, 2000, the
settlement is subject to certain terms and conditions, including, but not
limited to, notifying the class members, defendants' right to cancel the
settlement agreement if greater than a specified number of class members
opt out of the settlement, and the court's final approval. EEX paid the
settlement amount into an escrow account on July 21, 2000. On October 16,
2000, the parties filed a motion with the court with the definitive terms
of the settlement agreement. The parties asked the court to approve
preliminarily the settlement, authorize notice to the class of plaintiffs,
and set a date for a hearing on final approval. EEX entered into the
settlement to avoid the uncertainty and expense of litigation. EEX and the
individual defendants continue to deny all the allegations of the suit.
5
EEX CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
On July 31, 2000, EEX filed EEX Corporation v. Cal Dive International,
Inc., et al. in the 11th District Court, Harris County, Texas. The suit
claims a breach of fiduciary duty by a former employee involving, and
damages from, a series of transactions with the defendants. Certain of the
defendants in the above suit filed on August 1, 2000, Cal Dive
International, Inc., et al. v. EEX Corporation in Federal District Court,
Southern District of Texas, alleging breach of purchase and sale and other
agreements and seeking a declaratory judgment that Cal Dive is not liable
to EEX in the transactions that are the subject of EEX's suit. Because of
the stage of the litigation, no estimate of the claim or liability can be
made at this time.
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 of such occurrences and their overall
effect 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.
6. On December 17, 1999, EEX closed a stock purchase of certain affiliates of
Tesoro Petroleum Corporation that indirectly own oil and gas properties and
pipeline assets. The purchase price was allocated to the assets purchased
and liabilities assumed based upon preliminary estimates of fair value on
the date of acquisition.
7. Segment information has been prepared in accordance with Statement of
Financial Accounting Standards 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.
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 1999 Annual Report on Form 10-K). EEX's
reportable segments are consistent with its business strategy. 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, 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
Impairment of producing oil and gas
properties............................. --- --- --- --- --- ---
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
============ ============== =============== ============= ========== =========
Three months ended September 30, 1999:
- -----------------------------------------
Total Revenues........................... $ --- $ --- $ 32,630 $ 17,429 $ 28 $ 50,087
Production and operating costs........... --- --- 5,257 4,095 --- 9,352
Exploration costs........................ 7,488 --- 1,326 723 --- 9,537
Depletion, depreciation and amortization. --- 900 12,511 2,715 302 16,428
Other costs.............................. --- --- 782 (b) --- 8,565 9,347
------------ -------------- --------------- ------------- ---------- ---------
Operating Income (Loss).................. (7,488) (900) 12,754 9,896 (8,839) 5,423
Interest Income and other................ --- --- --- --- 1,545 1,545
Interest and other financing costs....... --- (3,788) (183) --- (471) (4,442)
------------ -------------- --------------- ------------- ---------- --------
Income (Loss) before income taxes........ $ (7,488) $ (4,688) $ 12,571 $ 9,896 $ (7,765) $ 2,526
============ ============== =============== ============= ========== =========
Long-Lived Assets........................ $ 60,495 $ 135,762 $ 213,054 $ 57,285 $ 5,822 $ 472,418
============ ============== =============== ============= ========== =========
Additions to Long-Lived Assets........... $ 23,529 $ 4,135 $ 22,049 $ 2,764 $ 549 $ 53,026
============ ============== =============== ============= ========== =========
6
EEX CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Deepwater
----------------------------
Operations FPS/Pipelines Onshore/Shelf International Other(a) Total
------------ -------------- --------------- ------------- ---------- ---------
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
============ ============== =============== ============= ========== =========
Nine months ended September 30, 1999:
- -----------------------------------------
Total Revenues........................... $ --- $ --- $ 87,117 $ 42,229 $ 4,279 $ 133,625
Production and operating costs........... --- --- 17,564 11,245 --- 28,809
Exploration costs........................ 43,507 --- 8,377 3,138 --- 55,022
Depletion, depreciation and amortization. --- 4,500 40,703 8,494 1,022 54,719
Other costs.............................. --- --- 3,577 (b) --- 25,067 28,644
------------ -------------- --------------- ------------- ---------- ---------
Operating Income (Loss).................. (43,507) (4,500) 16,896 19,352 (21,810) (33,569)
Interest Income and other................ --- --- --- --- 4,441 4,441
Interest and other financing costs....... --- (10,745) (591) --- (1,371) (12,707)
------------ -------------- --------------- ------------- ---------- ---------
Income (Loss) before income taxes........ $ (43,507) $ (15,245) $ 16,305 $ 19,352 $ (18,740) $ (41,835)
============ ============== =============== ============= ========== =========
Long-Lived Assets........................ $ 60,495 $ 135,762 $ 213,054 $ 57,285 $ 5,822 $ 472,418
============ ============== =============== ============= ========== =========
Additions to Long-Lived Assets........... $ 44,827 $ 5,165 $ 46,240 $ 9,966 $ 1,316 $ 107,514
============ ============== =============== ============= ========== =========
__________________
(a) Includes primarily Cogeneration Plant Operations, General and
Administrative and gains/losses on hedging and sale of assets.
(b) Includes taxes other than income.
8. In March 2000, the Financial Accounting Standards Board issued FASB
Interpretation No. 44, "Accounting for Certain Transactions involving Stock
Compensation, an interpretation of APB Opinion No. 25." EEX adopted the
Interpretation prospectively as of July 1, 2000. As a result of adopting
the Interpretation, EEX is required to apply variable accounting to certain
options issued on February 15, 2000 until the options are exercised,
forfeited or expire unexercised. The effect of adopting the Interpretation
resulted in additional compensation expense of $0.1 million and a decrease
in stockholders' equity of $0.4 million.
7
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."
UPDATE AND RECENT EVENTS
Llano Well No. 3 and Deepwater* Gulf of Mexico Exploration
The Llano No. 3 located at Garden Banks Block 386 was drilled to its planned
total depth of approximately 25,500 feet in July 2000, encountering hydrocarbons
in the Lower Pliocene and Miocene-age sands. Based upon log analysis, the well
encountered approximately 340 feet of hydrocarbon-bearing sands. This compares
to approximately 200 feet of hydrocarbon-bearing sands encountered in the
discovery well. This second appraisal well is located approximately one mile to
the northwest of the discovery well. EEX believes the field should be commercial
with potential gross reserves estimated to be in the range of 200 to 250 million
barrels of oil equivalent. These estimates do not constitute proved reserves at
this time.
EEX and the other participants in the Llano leases are in discussions on a plan
of development for Llano, as well as on further exploration in the Llano area. A
plan of development would normally include additional wells, production and
transportation facilities, and will require regulatory approvals. EEX has
recommended using the Pipelines (defined below) as part of a plan of
development. No assurances can be given that an agreement will be reached among
the parties regarding a plan of development or further actions in the Llano
area.
EEX entered into an agreement with Murphy Oil Corporation to farmout its 40%
working interest in the Mason Prospect in return for a carried 18% working
interest (up to 110% of the approved estimated cost of the well or to the
objective depth, whichever comes first) in the initial exploration well on the
prospect. The Mason Prospect on Garden Banks Block 562 is located approximately
ten miles south of the Llano area. The well, operated by Murphy Oil Corporation,
began drilling in mid-August and has been temporarily abandoned while a side-
track operation is being evaluated.
The Arctic I semi-submersible drilling rig is currently drilling a well to test
the Jason Prospect. This well is located approximately six miles northeast of
Llano and will test the sands correlative to, but shallower than, those
encountered in the Llano discovery. This prospect targets Lower Pliocene and
Miocene-age sands up to a depth of approximately 18,000 feet and is expected to
reach total depth in the fourth quarter. EEX is the operator with a 100% working
interest in the prospect and will pay 70% of the total cost as a result of the
Enterprise joint venture agreement.
The Arctic I semi-submersible drilling rig is under contract with EEX and
expires in July 2002. After the rig completes its work on the Jason Prospect,
the Company expects to sublease the rig to another operator for a period less
than the remaining lease term, or drill another Llano area well. Depending on
the willingness of certain Llano area partners to participate in subsequent
wells, EEX may seek the participation of new joint venture partners to share in
the expense of subsequent well(s), elect to bear 100% of the costs or decide to
"stack" the rig and take it out of operation at a rate of approximately $130,000
per day.
Gulf of Mexico Shelf
In March 2000, EEX completed a sale of certain properties on the Gulf of Mexico
Continental Shelf ("Shelf"). Primarily as the result of a decision to shift
capital spending from the Shelf to higher potential onshore programs, the
remaining Shelf properties are continuing to experience production declines.
EEX previously announced it is considering the sale of its remaining Shelf
properties. EEX has received bids and is actively negotiating a purchase and
sale agreement. If a purchase and sale agreement is concluded, management
intends to close the transaction by December 31, 2000.
___________________
* "Deepwater" means areas of the Gulf of Mexico where water depths are greater
than 600 feet.
8
Cooper Floating Production System ("FPS") and Pipelines
The FPS and Pipelines (two pipelines and associated facilities from the Cooper
project) have a carrying value of approximately $148 million net to EEX at
September 30, 2000, generally reflecting the highest valued use of the assets.
EEX has continued its efforts to place into service the FPS that completed
refurbishment and became ready for service in the first half of 2000. Previously
reported discussions with an operator for a disposition of the FPS have
terminated. EEX recently completed a new marketing evaluation that indicated a
number of potential uses for the FPS. The study indicated that the highest value
use of the FPS is as a production facility in a project that requires such
capability in the near term (as opposed to experiencing delays associated with
design and fabrication). Because of the uniqueness of the FPS and the
characteristics of its markets, it is difficult to assess its ultimate market
value. The 40% co-owner and EEX have entered into an agreement with a company to
market the FPS and associated facilities. Management believes that a disposition
of the FPS is not likely in 2000 and therefore, will not appreciably affect this
year's cash flows. To the extent marketing efforts do not result in a
satisfactory transaction, the FPS may be used as an early production option
should the Jason well result in a commercial discovery.
The Pipelines are also not in use. Recent internal engineering estimates
indicate that the daily capacity for pipeline quality products is approximately
70,000 barrels of oil and 140 million cubic feet of gas. EEX continues to
believe that the Pipelines have utility as support infrastructure for
anticipated development at Llano and the greater Llano area, including the Jason
Prospect. EEX currently estimates potential gross Llano reserves in the range of
200 to 250 million barrels of oil equivalent, however, it has yet to record
proved reserves at Llano or in the Llano area.
While management believes that it can realize the value of the FPS and
Pipelines, there can be no assurance that this can be accomplished in the near
term, or on favorable financial terms.
International Exploration and Development
As previously reported, production from the Mudi Field in Indonesia has declined
to a level below that forecast at year-end 1999. After a preliminary evaluation
of the field and its production, in the second quarter of 2000, the carrying
value of the asset was reduced by $12 million. EEX is continuing studies of the
reservoir and is participating in drilling and other operations intended to
improve production rates. During the third quarter, the Mudi 16 development well
was drilled and is currently producing at a controlled rate of approximately
1,500 barrels per day. The depreciation, depletion and amortization rate
("DD&A") was increased in the second and third quarters. Higher oil prices and
the mechanism of the production sharing agreement contributed to these changes
by lowering the number of barrels necessary to recover costs. EEX continues to
consider the sale of this asset but no final determination has been made
concerning a sale. If the property is sold, there can be no assurances that the
purchase price will be equal to or greater than the carrying value of the asset.
Two wells were drilled by another operator resulting in the Pohokura Field
discovery, offsetting EEX's North Taranaki block in New Zealand. EEX is
currently considering a proposal by the other operator for a joint 3-D seismic
project over the area to determine the extent of the field and better define
area prospectivity.
Onshore U.S. Business
EEX has continued its strategy to grow its U.S. onshore business. A recently
completed review of the Company's onshore oil and gas reserves that was audited
by an outside engineering firm estimated the proved reserves for the onshore
business unit to be 360 billion cubic feet of gas equivalent ("Bcfe") at June
30, 2000. Of these reserves, 310 Bcfe were proved developed and 50 Bcfe were
proved undeveloped. This represents a 10% increase since year-end 1999,
including the effects of production and asset sales.
9
RESULTS OF OPERATIONS
For the third quarter of 2000, EEX reported a net loss applicable to common
shareholders of approximately $2 million ($0.04 per share), versus a net loss
applicable to common shareholders of $2 million ($0.04 per share) for the same
period in 1999.
Quarters Ended September 30, 2000 and 1999
For the third quarter of 2000, total revenues were $66 million, 32% higher than
total revenues in the third quarter of 1999. Natural gas revenues for the third
quarter of 2000 were 81% higher than the same quarter of 1999. This increase was
due to a 33% increase in average prices and a 36% increase in production. The
increase in production is primarily a result of the Tesoro acquisition,
partially offset by asset sales and production declines on other properties. The
average natural gas sales price per thousand cubic feet ("Mcf") was $3.25 in the
third quarter of 2000, compared with $2.44 in the same period of 1999. Natural
gas production for the third quarter of 2000 was 14 billion cubic feet ("Bcf"),
compared with 10 Bcf in the same period of 1999. Oil revenues decreased 18% from
the same period in 1999 due to a 47% decrease in production, primarily as a
result of production decline associated with the offshore shelf properties and
Mudi Field, offset by an increase in the average price to $31.33 from $20.07.
Costs and expenses for the third quarter of 2000 were $53 million, compared with
$45 million in 1999. Operating expenses (production and operating, general and
administrative and taxes other than income) were $18 million in the current
quarter, unchanged from the same period of 1999. Increased production and
operating expense and taxes other than income were offset by lower general and
administrative and other costs. Exploration expenses for the third quarter of
2000 decreased to $8 million, compared to $10 million for the same period of
1999. The current quarter includes $2.1 million of exploration expenses
associated with impairment of undeveloped leases. The third quarter of 1999
includes $4.7 million of exploration expenses associated with the George
Prospect dry hole in Mississippi Canyon Block 442. Depletion, depreciation and
amortization for the third quarter of 2000 was $25 million, $8 million higher
than the same period of 1999, primarily due to an increased rate on the Mudi
Field due to higher oil prices and the mechanism of the production sharing
agreement, and the addition of properties from the Tesoro acquisition, which
were offset somewhat by property sales and production declines.
Total interest and other financing costs for the third quarter of 2000,
including interest income, preferred stock dividends and other income, were $12
million, a $6 million increase from the same period of 1999. This increase was
primarily due to increased interest expense associated with borrowings under the
revolving credit agreement, the gas sales obligation and carrying cost
associated with terminating the forward purchase facilities. Interest income
decreased during the current quarter due to a lower cash balance.
Nine Months Ended September 30, 2000 and 1999
For the nine months ended September 30, 2000, total revenues were $189 million,
42% higher than total revenues for the nine months ended September 30, 1999.
Natural gas revenues for the first nine months of 2000 were 76% higher than the
first nine months of 1999. This increase was due to a 30% increase in production
and a 35% increase in average prices. The average natural gas sales price per
thousand cubic feet ("Mcf") was $2.91 for the first nine months of 2000,
compared with $2.16 in the same period of 1999. Natural gas production for the
first nine months of 2000 was 42 billion cubic feet ("Bcf"), compared with 32
Bcf in the same period of 1999. The increase in production is primarily due to
the Tesoro acquisition, which was offset by property sales and production
declines. Oil revenues increased 2%, primarily due to increased average prices,
offset by a 46% decrease in production, primarily due to production declines
associated with offshore shelf properties and the Mudi Field. The average oil
price during the first nine months of 2000 increased to $28.61 from $15.25.
Production from the Mudi Field in Indonesia during the first nine months of 2000
was lower than forecast at year-end 1999. EEX reevaluated this asset at the end
of the second quarter and reduced the carrying value by $12 million per SFAS
121.
10
Costs and expenses for the first nine months of 2000 were $166 million, compared
with $167 million in 1999. Operating expenses (production and operating, general
and administrative and taxes other than income) remained flat from period to
period. Exploration expenses for the first nine months of 2000 decreased to $22
million, compared to $55 million for the same period of 1999. The current period
includes $4.8 million of exploration expenses associated with the impairment of
undeveloped leases. The first nine months of 1999 included $24 million of
exploration expenses associated with the George Prospect dry hole in Mississippi
Canyon Block 442. Depletion, depreciation and amortization for the first nine
months of 2000 was $71 million, $16 million higher than the same period of 1999,
primarily due to an increased rate on the Mudi Field due to higher oil prices
and the mechanism of the production sharing agreement, and the addition of
properties from the Tesoro acquisition, which were offset somewhat by property
sales and production declines.
Total interest and other financing costs for the first nine months of 2000,
including interest income, preferred stock dividends and other income, were $34
million, a $17 million increase from the same period of 1999. This increase was
primarily due to increased interest expense associated with borrowings under the
revolving credit agreement, the gas sales obligation and carrying cost
associated with terminating the forward purchase facilities. Interest income
also decreased during the first nine months of 2000 due to a lower cash balance.
EEX CORPORATION
SUMMARY OF SELECTED OPERATING DATA
FOR OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30 September 30
------------------------------- -------------------------------
2000 1999 2000 1999
-------------- -------------- -------------- --------------
Sales volume
Natural gas (Bcf) (a).................................. 13.5 10.0 42.0 32.2
Oil, condensate and natural gas liquids (MMBbls) (d)... 0.6 1.2 2.1 3.8
Total volumes (Bcfe) (a)............................. 17.4 17.2 54.6 55.1
Average sales price (b)
Natural gas (per Mcf) (c).............................. $ 3.25 $ 2.44 $ 2.91 $ 2.16
Oil, condensate and natural gas liquids (per Bbl)...... 31.01 19.93 28.35 15.22
Total (per Mcfe) (c)................................. 3.68 2.81 3.33 2.32
Average costs and expenses (per Mcfe) (c)
Production and operating (b)........................... $ 0.58 $ 0.54 $ 0.54 $ 0.52
Exploration............................................ 0.45 0.55 0.41 1.00
Depletion, depreciation and amortization............... 1.41 0.95 1.30 0.99
General, administrative and other...................... 0.27 0.41 0.29 0.37
Taxes, other than income............................... 0.20 0.08 0.14 0.06
_________________
(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.
11
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows
Net cash flows provided by operating activities for the nine months ended
September 30, 2000 were $45 million, an increase of $6 million over the same
period of 1999. Higher revenues were largely offset by increased receivables and
decreased advances from partners. Net cash flows used in investing activities
for the nine months ended September 30, 2000 were $134 million, a $37 million
increase from cash flows used in investing activities for the same period of
1999. The increase in investing activities is primarily due to increased capital
spending related to onshore operations, offset by decreased spending related to
the Gulf of Mexico Shelf properties. Net cash flows provided by financing
activities for the nine months ended September 30, 2000 were $80 million,
compared to $140 million for the same period of 1999. As of September 30, 2000,
EEX had $114 million outstanding under the revolving credit agreement. During
the first quarter of 1999, EEX received $150 million from the issuance of
preferred stock and warrants.
Capital Budget
Currently forecasted 2000 capital expenditures are approximately $170 million,
compared with actual expenditures of $388 million in 1999 (including $215
million for the acquisition of Tesoro oil and gas properties and pipelines).
Capital expenditures for the third quarter of 2000 were $44 million and for the
first nine months of 2000 were $127 million. EEX expects to fund these capital
expenditures by operating cash flows, proceeds from property sales, investment
costs carried under joint venture arrangements and increased borrowings under
the revolving credit agreement. In order to continue its anticipated capital
program, including Llano area development, EEX will require additional capital
resources. EEX may seek additional funds from public and private equity markets,
debt markets and/or sell additional assets beyond the Gulf of Mexico Shelf sale
currently being negotiated.
EEX's access to public or private equity or debt markets may be limited by
general 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
secure funds when required for its activities, its liquidity and ability to make
capital investments would become impaired.
Liquidity
EEX has a $350 million revolving credit line with a group of banks that matures
on June 27, 2002, of which $114 million was outstanding at September 30, 2000.
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
described in EEX's 1999 Annual Report on Form 10-K, 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. As of September 30,
2000, the debt to capital ratio under the revolving credit agreement was 54% and
unused available credit was approximately $95 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.
Under the Enterprise joint venture agreement, the remaining exploration carry of
approximately $14 million at September 30, 2000, reduced by the amount paid for
the 30% carry in the Jason well, is due from Enterprise on December 31, 2000.
EEX's ability to fund its capital budget and its liquidity can be affected by
any of the following:
. The value of EEX's investment in the Llano area, the Pipelines and a portion
of its plan to realize the value of its deferred tax asset is dependent upon
development of its Llano discovery or other exploration success on its Llano
area leases. A reduction in value of these assets due to adverse drilling
results, limited development plans or delays in development, 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.
. Sale of the FPS and/or Pipelines would result in a significant change in
EEX's debt structure due to the termination of the capital lease obligation
associated with those assets. EEX would also incur substantial early
termination costs that would adversely affect net income and reduce borrowing
capacity. A disposition of the capital lease would reduce the debt used in
computing the debt to capital ratio and increase the amount of funds
available to EEX to borrow under its revolving credit agreement. However,
there can be no assurance that such a potential sale and related changes can
be accomplished on favorable terms.
12
. The majority of the commitment associated with the Arctic I rig (See Note 19
to the Consolidated Financial Statements in Item 8 of EEX's 1999 Annual
Report on Form 10-K and the discussion above under "Update and Recent
Events-Llano Well No. 3 and Deepwater Gulf of Mexico Exploration") has been
assumed, for planning purposes, to be funded by EEX's joint venture partners
in its Llano development and Llano area exploration program. If the joint
venture partners elect not to participate in these projects, and EEX cannot
find other participants to share the costs of drilling, EEX would incur
expenditures greater than forecast and be exposed to potentially higher dry
hole cost. If the rig were stacked, the daily cost would increase exploration
expense adversely affecting net income or loss. EEX currently has no
commitment from joint venture partners for the use of the rig.
. 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. If
EEX is unable to secure additional equity and capital expenditures continue
at currently planned levels, available borrowings under the revolving credit
agreement may become severely limited or unavailable.
. In July 2001, EEX's letters of credit for $70 million expire under the terms
of the agreement under which they were issued. These letters of credit are
credit support required for the equity portion (approximately $68 million) in
the capital lease obligation for the FPS and Pipelines. If the FPS and/or
Pipelines are not sold, or the letter of credit facility renewed or replaced
by a similar arrangement, EEX will be required by the capital lease
agreements to terminate the lease and pay $68 million to the lessor. EEX
would assume the direct responsibility for the secured notes (approximately
$138 million) representing the financed portion of the lease. This would
result in total debt increasing by approximately $14 million and total
capitalization decreasing by approximately $14 million resulting in a
decrease of available credit under the revolving credit agreement.
. If a significant adverse financial impact results from the occurrence of any
or all of the above-mentioned factors prior to EEX obtaining additional
equity, EEX's liquidity would be severely impacted.
NEW ACCOUNTING STANDARD
In June 1999, the Financial Accounting Standards Board issued SFAS No. 137,
"Accounting for Derivative Instruments and Hedging Activities--Deferral of the
Effective Date of FASB Statement No. 133," which is effective for fiscal years
beginning after June 15, 2000, with earlier adoption encouraged. FASB Statement
No. 133, "Accounting for Derivative Instruments and Hedging Activities,"
requires companies to record derivatives on the balance sheet as assets and
liabilities, measured at fair value. Gains or losses resulting from changes in
the values of those derivatives would be accounted for depending on the use of
the derivative and whether it qualifies for hedge accounting. EEX has not yet
determined what the effect, if any, of SFAS No. 133 will be on results of
operations and financial position. EEX will adopt this accounting standard as
required by January 1, 2001.
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--See the discussion above under "Liquidity
and Capital Resources - Capital Budget."
FPS and Pipeline Marketing Risk--See the discussion above under "Update and
Recent Events - Cooper Floating Production System ("FPS") and Pipelines."
13
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 offshore and international areas that
will increase associated exploration risk. 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.
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 reserves and exploration
prospects include properties located in water depths of 20 to greater than 7,000
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.
Volatility of Oil and Gas Markets--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 oil and 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.
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 adjustment in reserve estimates could adversely affect EEX. Also, any
substantial decline in projected net revenues resulting from production of
reserves 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, 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.
14
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Hedging activity for the third quarter ended September 30, 2000, resulted in a
loss of $3.8 million for natural gas and break-even for crude oil which totals
to a combined loss of $3.8 million. The total net hedging loss for natural gas
includes a gain of $3.0 million related to hedging activities associated with
the contractual requirement to purchase gas for delivery to a co-generation
plant in Texas. This gain is recorded as oil and gas properties. For the nine
months ended September 30, 2000, the combined hedging activity has resulted in a
loss of $3.8 million. The tables below provide information about EEX's hedging
instruments as of September 30, 2000. Since essentially all of the hedging done
by EEX utilized either "swap" or "collar" instruments, the tables have been
separated to show the volumes hedged utilizing each instrument. The Notional
Amount is equal to the volumetric hedge position of EEX during the periods. The
fair values of the hedging instruments are based on the difference between the
applicable strike price and the New York Mercantile Exchange future prices for
the applicable trading months. EEX follows hedge accounting for these positions
and accordingly, the fair values presented below, which represent unrealized
gains (losses), have not been recognized in the financial statements.
Notional Average Fair Value at
Amount Strike Price September 30, 2000
(BBtu) (1) (Per MMBtu) (2) (In thousands)
----------- ----------------- ------------------
Natural Gas Swaps:
October 2000 - December 2000............................ 2,060 (3) $2.68 $(2,114)
January 2001 - March 2001............................... 383 2.75 (756)
April 2001 - June 2001.................................. 398 2.48 (765)
July 2001 - September 2001.............................. 414 2.49 (785)
October 2001 - December 2001............................ 391 2.69 (740)
January 2002 - March 2002............................... 439 2.74 (645)
April 2002 - June 2002.................................. 445 2.51 (625)
July 2002 - September 2002.............................. 455 2.51 (655)
October 2002 - December 2002............................ 426 2.69 (590)
January 2003 - March 2003............................... 290 2.76 (284)
April 2003 - June 2003.................................. 315 2.54 (306)
July 2003 - September 2003.............................. 311 2.54 (311)
October 2003 - December 2003............................ 303 2.72 (203)
January 2004 - March 2004............................... 315 2.80 (138)
April 2004 - June 2004.................................. 310 2.58 (206)
July 2004 - September 2004.............................. 335 2.57 (224)
October 2004 - December 2004............................ 319 2.76 (155)
-------- -----------
Total................................................ 7,909 $(9,502)
======== ==========
_______________________
(1) Billions of British Thermal Units.
(2) Millions of British Thermal Units.
(3) The notional amount represents the total volumetric hedge position during
the period October through December 2000, which includes "Buy" swaps to
offset and manage existing hedge positions. The notional amount of the "Buy"
swaps for October through December 2000 is 1,075 BBtu's. EEX is a net
purchaser of 90 BBtu's for the October through December 2000 period.
Notional Average Fair Value at
Amount Strike Price September 30, 2000
(BBtu) (1) (Per MMBtu) (2) (In thousands)
--------------- ----------------------------- ------------------
Floor Ceiling
----------- ------------
Natural Gas Collars:
October 2000 - December 2000........................ 3,680 $2.509 $2.838 $ (8,968)
January 2001 - March 2001........................... 3,150 2.532 3.719 (3,188)
April 2001 - June 2001.............................. 3,185 2.456 3.107 (4,079)
July 2001 - September 2001.......................... 3,220 2.454 3.110 (4,115)
October 2001 - December 2001 3,220 2.506 3.378 (3,880)
--------------- -----------
Total............................................ 16,455 $(24,230)
=============== ============
Note: Includes the cost of "puts" which was included in the averages calculated
for this table.
_______________
(1) Billions of British Thermal Units.
(2) Millions of British Thermal Units.
15
EEX has a contractual requirement to deliver gas to a co-generation plant in
Texas. EEX has been meeting the requirements for gas delivery by purchasing gas
in the open market and has entered into the following hedge transactions. These
volumes are not included in the above natural gas hedging table. The Notional
Amount is equal to the volumetric position of EEX during the period. The fair
values of the hedging instruments are based on the difference between the strike
price and the New York Mercantile Exchange future prices for the applicable
trading month. EEX follows hedge accounting for these positions and accordingly,
the fair values presented below, which represent unrealized gains (losses), have
not been recognized in the financial statements.
Notional Average Fair Value at
Amount Strike Price September 30, 2000
(BBtu) (1) (Per MMBtu) (2) (In thousands)
--------------------- ----------------------- --------------------
Natural Gas:
October 2000 - December 2000........................ 1,380 $2.32 $4,052
______________________
(1) Billions of British Thermal Units.
(2) Millions of British Thermal Units.
16
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
In Gracy Fund, et al. v. EEX Corporation, et al., previously reported in the
1999 Annual Report on Form 10-K and Quarterly Report on Form 10-Q for the
quarter ended June 30, 2000, EEX, its insurers and co-defendants reached an
agreement with counsel for plaintiffs to settle the case for a total amount of
$25 million, of which EEX contributes $1.25 million. Under a Memorandum of
Understanding dated as of June 22, 2000, the settlement is subject to certain
terms and conditions, including, but not limited to, notifying the class
members, defendants' right to cancel the settlement agreement if greater than a
specified number of class members opt out of the settlement, and the court's
final approval. EEX paid the settlement amount into an escrow account on July
21, 2000. On October 16, 2000, the parties filed a motion with the court with
the definitive terms of the settlement agreement. The parties asked the court to
approve preliminarily the settlement, authorize notice to the class of
plaintiffs, and set a date for a hearing on final approval. EEX entered into the
settlement to avoid the uncertainty and expense of litigation. EEX and the
individual defendants continue to deny all the allegations of the suit.
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
Exhibit 27 Financial Data Schedule
(b) Reports on Form 8-K
None
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 7, 2000 By: /s/ R. S. Langdon
------------------------------
R. S. Langdon
Executive Vice President,
Finance and Administration,
and Chief Financial Officer
18