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 June 30, 2002
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 July 31, 2002:
42,556,914
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
EEX CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
(UNAUDITED)
Three Months Ended Six Months Ended
June 30 June 30
---------------------------- ----------------------------
2002 2001 2002 2001
------------- ------------- -------------- -------------
(In thousands, except per share amounts)
Revenues:
Natural gas $ 35,100 $ 33,051 $ 71,431 $ 72,537
Oil, condensate and natural gas liquids 2,369 2,931 4,452 6,196
Cogeneration operations 827 1,843 1,966 3,888
Other 346 223 1,304 1,027
--------- --------- --------- ---------
Total 38,642 38,048 79,153 83,648
--------- --------- --------- ---------
Costs and Expenses:
Production and operating 5,728 5,445 11,966 10,387
Exploration 8,940 8,060 14,664 27,771
Depletion, depreciation and amortization 11,956 11,548 24,086 22,988
(Gain) Loss on sales of property, plant and equipment (156) 33 (173) 335
Cogeneration operations 1,041 1,593 1,842 3,468
General, administrative and other 4,906 3,187 9,289 6,500
Taxes, other than income 3,789 4,121 5,646 9,666
--------- --------- --------- ---------
Total 36,204 33,987 67,320 81,115
--------- --------- --------- ---------
Operating Income from Continuing Operations 2,438 4,061 11,833 2,533
Other Income--Net 65 49 93 51
Interest Income 338 205 867 601
Interest and Other Financing Costs (6,649) (7,765) (12,811) (15,577)
--------- --------- --------- ---------
Income (Loss) from Continuing Operations Before Income Taxes (3,808) (3,450) (18) (12,392)
Income Taxes -- -- -- --
--------- --------- --------- ---------
Income (Loss) from Continuing Operations (3,808) (3,450) (18) (12,392)
Discontinued Operations:
Income (Loss) from Discontinued Operations,
Net of Income Taxes (241) 5,832 2,460 10,525
--------- --------- --------- ---------
Net Income (Loss) (4,049) 2,382 2,442 (1,867)
Preferred Stock Dividends 3,875 3,579 7,674 7,089
--------- --------- --------- ---------
Net (Loss) Applicable to Common Shareholders $ (7,924) $ (1,197) $ (5,232) $ (8,956)
========= ========= ========= =========
Basic and Diluted Earnings Per Share:
Net (Loss) from Continuing Operations $ (0.18) $ (0.17) $ (0.18) $ (0.47)
========= ========= ========= ==========
Net Income (Loss) from Discontinued Operations $ (0.01) $ 0.14 $ 0.06 $ 0.26
========= ========= ========= =========
Net (Loss) Applicable to Common Shareholders $ (0.19) $ (0.03) $ (0.12) $ (0.21)
========= ========= ========= =========
Weighted Average Shares Outstanding:
Basic and Diluted 41,903 41,664 41,881 41,656
See accompanying notes.
2
EEX CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEET
(UNAUDITED)
June 30 December 31
2002 2001
--------------- ---------------
(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents $ 17,441 $ 136,618
Accounts receivable--trade (net of allowance of $2,781 and $2,780) 23,100 29,651
Natural gas hedging derivatives -- 23,203
Assets held for sale (net of allowance of $0 and $1,650) -- 13,174
Other 3,472 1,871
----------- -----------
Total current assets 44,013 204,517
----------- -----------
Property, Plant and Equipment (at cost):
Oil and gas properties (successful efforts method) 903,101 873,008
Other 8,582 8,668
----------- -----------
Total 911,683 881,676
Less accumulated depletion, depreciation and amortization 386,238 362,128
----------- -----------
Net property, plant and equipment 525,445 519,548
----------- -----------
Net property, plant and equipment held for sale -- 18,107
Other Assets 4,528 7,946
----------- -----------
Total $ 573,986 $ 750,118
=========== ===========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Accounts payable--trade $ 36,048 $ 42,443
Bank revolving credit agreement 221,000 325,000
Secured notes payable 14,642 13,579
Liabilities held for sale 75 6,132
Other 4,174 7,118
----------- -----------
Total current liabilities 275,939 394,272
----------- -----------
Secured Notes Payable 86,122 100,764
Gas Sales Obligation 46,957 59,937
Other Liabilities 13,457 9,357
Minority Interest Third Party 5,000 5,000
Shareholders' Equity:
Preferred stock (10,000 shares authorized; 1,976 and 1,899 shares issued;
Liquidation preference of $197,620 and $189,946) 20 19
Common stock ($0.01 par value; 150,000 shares authorized; 42,558 and
42,496 shares issued) 433 432
Paid in capital 768,331 760,484
Retained (deficit) (610,844) (605,612)
Unamortized restricted stock compensation (1,124) (1,403)
Other comprehensive income (1,188) 35,954
Treasury stock, at cost (843 and 817 shares) (9,117) (9,086)
----------- -----------
Total shareholders' equity 146,511 180,788
----------- -----------
Total $ 573,986 $ 750,118
=========== ===========
See accompanying notes.
3
EEX CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
(UNAUDITED)
Six Months Ended
June 30
-------------------------------
2002 2001
-------------- --------------
(In thousands)
OPERATING ACTIVITIES
Net Income (Loss) $ 2,442 $ (1,867)
Less: Income from discontinued operations 2,460 10,525
---------- ----------
Income (Loss) from continuing operations (18) (12,392)
Adjustments to reconcile net income to net cash
provided by operating activities:
Dry hole cost 23 853
Depletion, depreciation and amortization 24,086 22,988
Impairment of undeveloped leasehold 4,852 3,900
(Gain) Loss on sales of property, plant and equipment (173) 335
Other (3,739) (11,119)
Changes in current operating assets and liabilities:
Accounts receivable (3,213) 8,075
Other current assets (1,601) 5,523
Accounts payable (1,876) (14,128)
Other current liabilities (2,944) (1,483)
---------- ----------
Net cash flows provided by operating activities 15,397 2,552
---------- ----------
INVESTING ACTIVITIES
Additions of property, plant and equipment (34,703) (95,729)
Proceeds from dispositions of property, plant and equipment 10,866 184
Other (changes in accruals) (7,682) 3,332
---------- ----------
Net cash flows used in investing activities (31,519) (92,213)
---------- ----------
FINANCING ACTIVITIES
Borrowings under bank revolving credit agreement 225,000 145,000
Repayment of borrowings under bank revolving credit agreement (329,000) (13,000)
Deliveries under the gas sales obligation (12,980) (14,084)
Proceeds from hedge settlements 96 --
Purchase of treasury stock (31) (6)
Purchase of lessor's equity interest in capital lease -- (54,416)
Payments of secured notes payable (13,579) --
Payments of capital lease obligations -- (7,805)
---------- ----------
Net cash flows (used in) provided by financing activities (130,494) 55,689
---------- ----------
Cash Provided By Discontinued Operations 27,419 16,383
Net Decrease in Cash and Cash Equivalents (119,197) (17,589)
Cash and Cash Equivalents at Beginning of Period 136,638 19,791
---------- ----------
Cash and Cash Equivalents at End of Period 17,441 2,202
Less: Cash and Cash Equivalents of Discontinued Operations -- 20
---------- ----------
Cash and Cash Equivalents from Continuing Operations $ 17,441 $ 2,182
========== ==========
See accompanying notes.
4
EEX CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. The accompanying unaudited consolidated financial statements present the
financial position, results of operations and cash flows of EEX Corporation
and its subsidiaries ("EEX" or the "Company"). These consolidated financial
statements have been prepared pursuant to the rules and regulations of the
Securities and Exchange Commission governing interim financial disclosures.
These consolidated financial statements reflect all adjustments (consisting
of only normal recurring adjustments) that, in the opinion of management,
are necessary to fairly present the Company's financial position as of June
30, 2002 and December 31, 2001, and the results of operations and cash
flows for the six months ended June 30, 2002 and 2001. Operating results
for the six months ended June 30, 2002 are not necessarily indicative of
the results that may be expected for the year ending December 31, 2002.
Up to the end of 2001, EEX reported its business operations in four
segments: Onshore, Deepwater Operations, Deepwater FPS and Pipelines and
International. See Note 23 to the Consolidated Financial Statements in Item
8 of EEX's Annual Report on Form 10-K and Note 9, below. In the fourth
quarter of 2001, the Company began marketing all of its Indonesian assets.
As a result, the results of operations of the Indonesian subsidiaries
(International segment) are presented as a discontinued operation in
accordance with Statement of Financial Accounting Standards No. 144,
"Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS No.
144"). The historical financial statements have been restated to give
effect to this treatment. During the second quarter of 2002, the Company
closed the sale of all of the shares of a subsidiary that owns a 25%
interest in the Tuban Concession to PT Medco Energi Internasional. The sale
of the other Indonesian subsidiary has not closed.
These consolidated financial statements should be read in conjunction with
the audited consolidated financial statements and accompanying notes
included in the Company's Annual Report on Form 10-K for the year ended
December 31, 2001.
2. The Company's consolidated financial statements have been presented on the
basis that it is a going concern, which contemplates the realization of
assets and satisfaction of liabilities in the normal course of business.
The Company has incurred recurring net losses and there are uncertainties
relating to the Company's ability to meet future expenditures and cash flow
requirements. These conditions raise substantial doubt about the Company's
ability to continue as a going concern. The financial statements do not
include any adjustments to reflect the possible future effects on the
recoverability and classification of assets or the amounts and
classification of liabilities that may result from the outcome of these
uncertainties.
3. On May 28, 2002, EEX Operating, L.P. ("EEX Operating") and EEX entered into
a new revolving credit facility with a group of banks. The maximum credit
amount under the new credit agreement is $240 million, with a $10 million
sublimit for letters of credit, and an additional $10 million available
only for letters of credit to support surety bond obligations of EEX. As of
June 30, 2002, the outstanding balance is $221 million and is classified as
a current liability on the balance sheet. The new credit agreement matures
March 31, 2003, unless earlier terminated upon the occurrence of certain
specified events. The interest rate for (i) base rate loans is the higher
of the federal funds rate plus 1/2 of 1% or the Administrative Agent's
prime rate plus 2.75% and (ii) Eurodollar loans, is LIBOR plus 4.0%. The
interest rates increase 0.5% per quarter beginning June 30, 2002. Loans are
guaranteed by all of EEX's domestic subsidiaries other than EEX Reserves
Funding LLC and its subsidiaries and secured by security interests in the
equity and ownership interests of EEX's domestic subsidiaries (other than
the subsidiaries of EEX Reserves Funding LLC); other material tangible and
intangible assets of EEX Operating, EEX and its subsidiaries; and mortgages
on substantially all of the oil and gas properties of EEX Operating and
EEX.
Covenants of the new credit agreement limit additional borrowings,
repayment of existing debt, capital expenditures, dividends, distributions
and redemptions, investments, loans and advances, liens, gas imbalances,
take-or-pay obligations, mergers, property transfers and the sale of oil
and gas properties; restrict the restructuring of the gas sales obligation
and hedging agreements; and include other customary negative covenants. EEX
may not use borrowed funds to pay the scheduled principal and interest
payment due January 2, 2003 on the secured notes. The new credit agreement
requires, on a quarterly basis, that: (i) EEX's ratio of total debt (as
defined) to EBITDAX (as defined) for the four most recent quarters may not
be greater than 4.0 to 1.0; (ii) commencing April 1, 2002, EEX's ratio of
EBITDAX to fixed charges (as defined) may not be less than 1.0 to 1.0; and
(iii) EEX's proved oil and natural gas reserves must be at least 375
billion cubic feet equivalent, and the present value, using the lenders'
price deck and discount rate (currently 9%), of EEX's proved developed
producing reserves must be at least 70% of the present value of EEX's total
proved reserves.
5
EEX CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
4. On January 1, 2002, the Company adopted SFAS No. 144. Consequently, the
Indonesian operations are held for sale and presented as discontinued
operations. The assets and liabilities specifically related to this segment
are classified as held for sale in the accompanying consolidated balance
sheets, which include working capital and fixed assets. These assets have
been recorded at their estimated fair market values and the effect of any
adjustments have been reflected in the net income from discontinued
operations.
In the fourth quarter of 2001, the Company began marketing all of its
Indonesian assets. In March 2002, the Company negotiated and signed two
stock purchase agreements subject to certain conditions to closing. On
April 26, 2002, the Company closed the sale of all of the shares of a
subsidiary that owns a 25% interest in the Tuban Concession, onshore Java,
to PT Medco Energi Internasional and received approximately $26 million.
The sale of this subsidiary was recorded during the second quarter 2002.
The sale of the other Indonesian subsidiary that owns a 15% interest in the
Asahan Concession, offshore Sumatra, has not closed. An impairment of
approximately $0.5 million was recorded in the second quarter of 2002 to
reflect the impact of a disputed drilling cost overrun.
Refer to Note 9 - Segment Information - International segment for results
of operations for the quarter ended and the six months ended June 30, 2002
compared to June 30, 2001.
5. 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.
The following table shows the dividends in-kind paid on, and the
liquidation preference of, the preferred stock as of the dates shown:
Amount of Dividends Number of Preferred Liquidation Preference
Date (In millions) Shares Issued (In millions)
--------------- ------------------- ------------------- ----------------------
June 30, 2002 $3.9 38,749 $197.6
March 31, 2002 $3.8 37,990 $193.7
6. Payments under the gas sales obligation are amortized using the interest
method through final pay out using an interest rate of 9.5%. Payments
related to this obligation made during the second quarter of 2002 were $6
million, and during the first quarter of 2002, $7 million.
7. The Statement of Cash Flows for the six months ended June 30, 2002 reflects
$3 million related to the early settlement of several hedges as a non-cash
transaction. This amount was reclassified from other comprehensive income
and recognized as revenues to match the underlying sales transaction being
hedged. In addition, the Statement of Cash Flows also reflects the net
change in the fair value of derivative financial instruments which results
in a non-cash decrease of $34 million to shareholders' equity.
8. 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.
6
EEX CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
9. 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 the Company'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: Onshore,
Deepwater Operations, Deepwater FPS/Pipelines, and International. The
accounting policies of the segments are the same as those described in the
summary of significant accounting policies (See Note 3 to the Consolidated
Financial Statements in Item 8 of EEX's 2001 Annual Report on Form 10-K).
EEX's reportable segments are managed separately because of their
geographic locations.
In the fourth quarter of 2001, the Company began marketing all of its
Indonesian assets. In accordance with SFAS No. 144, the results of
operations of the Indonesian subsidiaries (International segment) are
presented as a discontinued operation. Historical segment information has
been restated to give effect to this treatment. During the second quarter
2002, the Company closed and recorded the sale of all of the shares of the
subsidiary that owns a 25% interest in the Tuban Concession. The sale of
the other Indonesian subsidiary has not closed.
Financial information by operating segment is presented below (in
thousands):
Deepwater Continuing Discontinued
------------------------------ Operations Operations -
Onshore Operations FPS/Pipelines Other(a) Total International
--------- ------------- -------------- ---------- ------------- -------------
Three months ended June 30, 2002:
Total revenues $ 36,184 $ -- $ -- $ 2,458 $ 38,642 $ --
Production and operating costs 4,934 400 394 -- 5,728 --
Exploration costs 2,947 5,993 -- -- 8,940 --
Depletion, depreciation and
amortization 10,522 -- 1,059 375 11,956 --
Impairment of oil and gas properties
as required per SFAS 144 -- -- -- -- -- 451
Other costs 3,552 (b) -- -- 6,028 9,580 (245)
-------- ------- --------- -------- --------- --------
Operating Income (Loss) 14,229 (6,393) (1,453) (3,945) 2,438 (206)
Interest Income -- -- -- 403 403 --
Interest and other financing costs (1,115) -- (5,534) (6,649) --
-------- ------- --------- -------- --------- --------
Income (Loss) before income taxes $ 13,114 $(6,393) $ (1,453) $ (9,076) $ (3,808) $ (206)
======== ======= ========= ======== ========= ========
Long-Lived Assets $377,554 $77,581 $ 68,093 $ 2,217 $ 525,445 $ --
======== ======= ========= ======== ========= ========
Additions to Long-Lived Assets $ 9,429 $ 7,610 $ 96 $ 8 $ 17,143 $ 193
======== ======= ========= ======== ========= ========
Three months ended June 30, 2001:
Total revenues $ 38,399 $ -- $ -- $ (351) $ 38,048 $ 14,110
Production and operating costs 5,289 -- 155 1 5,445 3,467
Exploration costs 5,761 1,921 -- 378 8,060 199
Depletion, depreciation and
amortization 9,769 -- 1,314 465 11,548 4,620
Other costs 4,104 (b) -- -- 4,830 8,934 --
-------- ------- --------- -------- --------- --------
Operating Income (Loss) 13,476 (1,921) (1,469) (6,025) 4,061 5,824
Interest Income -- -- -- 254 254 9
Interest and other financing costs (1,820) -- (3,401) (2,544) (7,765) --
-------- ------- --------- -------- --------- --------
Income (Loss) before income taxes $ 11,656 $(1,921) $ (4,870) $ (8,315) $ (3,450) $ 5,833
======== ======= ========= ======== ========= ========
Long-Lived Assets $415,233 $95,196 $ 157,091 $ 4,090 $ 671,610 $ 30,932
======== ======= ========= ======== ========= ========
Additions to Long-Lived Assets $ 41,733 $ 2,411 $ 13,517 $ 342 $ 58,003 $ 2,411
======== ======= ========= ======== ========= ========
7
EEX CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Deepwater Continuing Discontinued
------------------------------ Operations Operations -
Onshore Operations FPS/Pipelines Other(a) Total International
----------- ------------ -------------- ------------ ------------- -------------
Six months ended June 30, 2002:
Total revenues $ 64,178 $ -- $ -- $ 14,975 $ 79,153 $ 10,408
Production and operating costs 10,523 753 690 -- 11,966 3,734
Exploration costs 5,825 8,839 -- -- 14,664 380
Depletion, depreciation and
amortization 21,102 -- 2,118 866 24,086 --
Impairment of oil and gas properties
as required per SFAS 144 -- -- -- -- -- 4,051
Other costs 5,450 (b) -- -- 11,154 16,604 (245)
-------- -------- --------- ------- --------- --------
Operating Income (Loss) 21,278 (9,592) (2,808) 2,955 11,833 2,488
Interest Income -- -- -- 960 960 7
Interest and other financing costs (2,479) -- (1,926) (8,406) (12,811) --
-------- -------- --------- ------- --------- --------
Income (Loss) before income taxes $ 18,799 $ (9,592) $ (4,734) $ (4,491) $ (18) $ 2,495
======== ======== ========= ======== ========= ========
Long-Lived Assets $377,554 $77,581 $ 68,093 $ 2,217 $ 525,445 $ --
======== ======== ========= ======== ========= ========
Additions to Long-Lived Assets $ 20,305 $14,134 $ 211 $ 53 $ 34,703 $ 2,028
======== ======== ========= ======== ========= ========
Six months ended June 30, 2001:
Total revenues $ 89,922 $ -- $ -- $ (6,274) $ 83,648 $ 27,772
Production and operating costs 10,082 -- 304 1 10,387 7,025
Exploration costs 10,085 17,191 -- 495 27,771 635
Depletion, depreciation and
amortization 19,443 -- 2,628 917 22,988 9,606
Other costs 9,766 (b) -- 3 10,200 19,969 --
-------- -------- --------- ------- --------- --------
Operating Income (Loss) 40,546 (17,191) (2,935) (17,887) 2,533 10,506
Interest Income -- -- -- 652 652 20
Interest and other financing costs (3,812) -- (6,799) (4,966) (15,577) --
-------- -------- --------- ------- --------- --------
Income (Loss) before income taxes $ 36,734 $(17,191) $ (9,734) $(22,201) $ (12,392) $ 10,526
======== ======== ========= ======== ========= ========
Long-Lived Assets $415,233 $ 95,196 $ 157,091 $ 4,090 $ 671,610 $ 30,932
======== ======== ========= ======== ========= ========
Additions to Long-Lived Assets $ 75,703 $ 6,144 $ 13,517 $ 365 $ 95,729 $ 5,051
======== ======== ========= ======== ========= ========
(a) Includes primarily cogeneration plant operations, general and
administrative, gains/loss on hedging and sale of assets.
(b) Includes taxes other than income.
10. The Company addresses market risk by selecting instruments whose value
fluctuations correlate strongly with the underlying commodity being hedged.
The Company enters into swaps, options, collars and other derivative
contracts to hedge the price risks associated with a portion of anticipated
future oil and gas production. While the use of hedging arrangements limits
the downside risk of adverse price movements, it may also limit future
gains from favorable movements. Under these agreements, payments are
received or made based on the differential between a fixed and a variable
product price. These agreements are settled in cash at expiration or
exchanged for physical delivery contracts. The Company enters into the
majority of its hedging transactions with one counterparty and a netting
agreement is in place with that counterparty. The Company does not obtain
collateral to support the agreements but monitors the financial viability
of counter-parties and believes its credit risk is minimal on these
transactions. In the event of nonperformance, the Company would be exposed
to price risk. The Company has some risk of accounting loss since the price
received for the product at the actual physical delivery point may differ
from the prevailing price at the delivery point required for settlement of
the hedging transaction.
The net gain related to financial hedging activities that was reclassified
to revenues to match the underlying sales transaction being hedged was
approximately $1 million for the quarter ended June 30, 2002, compared to a
loss of $2 million for the same period of 2001.
8
EEX CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
At June 30, 2002, EEX had outstanding natural gas swaps that were entered
into as hedges extending through December 31, 2003, to exchange payments on
29,290 billion British Thermal Units of natural gas. At June 30, 2002, the
weighted average strike price and market price per million British Thermal
Units ("MMBtu") of natural gas were $3.47 and $3.73, respectively. At June
30, 2002, the Company estimated, using a NYMEX price strip as of that date,
that the fair market value represented a net current liability of
approximately $2.8 million, a net noncurrent liability of $3.7 million and
accumulated other comprehensive loss of approximately $6.5 million. The
Company realized no hedge ineffectiveness in the second quarter of 2002.
At June 30, 2002, EEX had outstanding natural gas collars that were entered
into as hedges extending through October 2002 to exchange payments on
approximately 1 Bcf of natural gas. At June 30, 2002, the weighted average
floor and ceiling strike prices and the market price per MMBtu of natural
gas were $2.40, $2.73 and $3.30, respectively. At June 30, 2002, the
Company estimated, using a NYMEX price strip as of that date, that the fair
market value represented a net current liability of approximately $0.4
million and accumulated other comprehensive loss of approximately $0.4
million. The Company recognized no hedge ineffectiveness in the second
quarter of 2002.
The Company may from time to time settle early derivative transactions.
Gains or losses are included in accumulated other comprehensive income
until they are recognized in revenues to match the underlying sales
transaction being hedged. The Company also terminated several financial
hedges with Enron North America Corp. in December 2001 due to Enron's
bankruptcy filing. During the second quarter of 2002, the Company
reclassified approximately $1.3 million from accumulated other
comprehensive income to revenues related to these transactions. As of June
30, 2002, approximately $2.5 million remains to be reclassified from other
comprehensive income to revenues in 2002 and approximately $3.2 million
remains to be reclassified from other comprehensive income to revenues in
2003.
9
Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations
Management's Discussion and Analysis of Financial Condition and Results of
Operations and all accompanying information should be read in conjunction with
the consolidated financial statements, accompanying notes and other financial
information included in this Quarterly Report on Form 10-Q and in the Company's
most recent Annual Report on Form 10-K for the year ended December 31, 2001.
Certain statements in this report, including statements of EEX 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. 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, the risks, uncertainties and critical accounting
policies and estimates described in the Company's Annual Report on Form 10-K for
the year ended December 31, 2001, and described from time to time in EEX's other
documents and reports filed with the Securities and Exchange Commission. The
following discussion should be read in conjunction with Item 7, "Management's
Discussion and Analysis of Financial Condition and Results of Operations--Risks,
Uncertainties and Critical Accounting Policies and Estimates," in the Company's
Annual Report on Form 10-K for the year ended December 31, 2001.
Newfield Merger
On May 29, 2002, EEX entered into a definitive merger agreement with Newfield
Exploration Company ("Newfield"). In the aggregate, the outstanding shares of
EEX common stock would be converted into approximately 2.4 million shares of
Newfield common stock, or 0.05703 shares of Newfield common stock per share of
EEX common stock. EEX's common shareholders will also have the option to elect
to receive units in a new trust in lieu of Newfield stock. Approximately 42.5
million trust units will be available. For each unit that an EEX shareholder
elects to receive, the number of shares of Newfield common stock that the
shareholder would otherwise receive will be reduced by 0.00054 of one share. The
trust will own overriding royalty interests in future production from defined
intervals generally below 20,000 feet from Gulf of Mexico lease blocks in which
EEX owns or may acquire an interest. Those leases are the subject of the Asset
Purchase, Farmout and Joint Exploration Agreement effective as of March 1, 2002,
with BP Exploration & Production Inc. ("BP") described below.
The holders of EEX's preferred stock, each of whom has signed a voting agreement
to vote its shares in favor of the merger, will receive a total of 4.7 million
shares of Newfield common stock in the merger.
The merger is subject to the approval of EEX's shareholders, certain regulatory
approvals and other conditions.
Gulf of Mexico Deep Shelf
In May 2002, EEX entered into an Asset Purchase, Farmout and Joint Exploration
Agreement effective as of March 1, 2002, with BP. BP acquired 75% of EEX's
current interest in 22 outer continental shelf ("OCS") leases. As part of this
agreement, BP will conduct further leasing and geophysical activities with a
minimum cost of $4.7 million in an area encompassing 140 OCS blocks. At the end
of the initial evaluation period, BP may, at its option, commit to the drilling
of up to three wells. The first election must be made on or before June 1, 2003,
and the well must be commenced not later than December 31, 2003. BP may elect to
drill a second well within 180 days of the completion of the first well and a
third well within 120 days of the completion of the second well. EEX will be
carried for its 25% interest of the costs of the initial evaluation period and
the drilling of the first three exploration wells. There is no production
currently associated with the interests that are the subject of the agreement.
In addition to the acquired blocks, EEX and BP were successful bidders on six
federal offshore blocks at OCS Lease Sale No. 182 held March 20, 2002, that are
included in the agreement. All the blocks have been awarded by the Minerals
Management Service.
10
Other Gulf of Mexico Activities
The Devil's Island well completed operations on June 12, 2002. The original well
bore encountered approximately 100 feet of pay and the updip sidetrack, the
second of two sidetracks, encountered approximately 30 feet of pay in a zone
separate from that encountered in the original well bore. EEX has a 20% working
interest in the Devil's Island project. The Glomar Arctic I rig was demobilized
from the Devil's Island well location to a stack location effective June 14,
2002. The rig contract expired on July 3, 2002 and the rig was released. The
Devil's Island operator plans further study to determine future operations. EEX
is preparing possible development options for consideration by the operator that
would combine the Devil's Island discovery and EEX's Jason discovery.
EEX continued its marketing efforts for the Floating Production System ("FPS")
and the Pipelines during the second quarter. EEX owns 60% of the FPS and
Pipelines; a subsidiary of Exxon Mobil Corp. owns 40%. EEX has received market
inquiries for use of the FPS as a drilling rig. EEX is continuing to market the
asset for use as a floating production system which use management believes is
higher valued than use as a drilling rig. No assurance can be given that EEX
will be successful in selling this asset at the higher valued use or that any
sale will recover the carrying value of the asset. The value of the Pipelines
depends on their use to transport production from the greater Llano area or
other areas in proximity to the Pipelines. EEX is now developing a proposal for
the Pipelines to transport production from the Jason and Devil's Island
discoveries. While EEX currently holds controlling interest in the Jason
discovery, the Devil's Island development plan will be decided by the operator.
EEX is also awaiting notification from the Llano operator to determine the
utility of the Pipelines for Llano field production. There can be no assurance
that these efforts will be successful or that the value received from
transportation of production from such discoveries would recover the carrying
value of the asset. If the Llano owners decide to use other pipelines for the
Llano field's development, the potential markets for use of the Pipelines will
be narrower. When the proposed merger with Newfield is completed, new management
may employ a different strategy to realize value from these assets, which may
impact their value.
RESULTS OF OPERATIONS
EEX Corporation reported a second quarter 2002 net loss of $8 million, or
($0.19) per share, compared to a net loss of $1 million, or ($0.03) per share
for the second quarter of 2001. The Indonesian subsidiaries (the International
segment) are reported as a discontinued operation under Statement of Financial
Accounting Standards No. 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets," ("SFAS No. 144"). The financial statements have been
restated in accordance with SFAS No. 144 to eliminate the impact of the
discontinued Indonesian operations from continuing operations. During the second
quarter, the Company closed and recorded the sale of all of the shares of the
subsidiary that owns a 25% interest in the Tuban Concession. The sale of the
other Indonesian subsidiary that owns a 15% interest in the Asahan Concession
has not closed.
A discussion of results of continuing operations for the three and six months
ended June 30, 2002, compared to the same period of 2001 follows.
RESULTS OF CONTINUING OPERATIONS
Quarters Ended June 30, 2002 and 2001
For the second quarter of 2002, EEX reported a loss from continuing operations
of $8 million ($0.18 per share), versus a net loss of $7 million ($0.17 per
share) for the same period in 2001.
For the second quarter of 2002, total revenues were $39 million, 2% higher than
the first quarter of 2001. Natural gas revenues for the second quarter of 2002
were 6% higher than the same quarter of 2001. This increase was due to a 2%
increase in the average natural gas sales price and a 4% increase in production.
Natural gas production for the second quarter of 2002 was 11 billion cubic feet
("Bcf"), slightly higher than the same period of 2001. The average natural gas
sales price per thousand cubic feet ("Mcf") was $3.18 in the second quarter of
2002, compared with $3.13 in the same period of 2001. The average natural gas
sales price for the second quarter 2002 includes hedging gains of $1 million and
2,645 billion British thermal units ("BBtu") delivered under the gas sales
obligation at an average price of $2.36 per million British thermal units
("MMBtu"). The average natural gas sales price of $3.13 per Mcf for the second
quarter 2001 includes hedging losses of approximately $2 million and 5,730 BBtu
delivered under fixed-price delivery contracts and the gas sales obligation at
an average price of $2.54 per MMBtu. Oil revenues for the second quarter of 2002
decreased 17% from the same quarter of 2001. This decrease was primarily due to
a 5% decrease in the average oil sales price and a 13% decrease in production.
The average oil price per barrel during the second quarter of 2002 was $24.65
compared to $25.85 for the same period of 2001.
11
Costs and expenses for the second quarter of 2002 were $36 million, compared
with $34 million in the same period of 2001. Operating expenses (production and
operating, general, administrative and other, and taxes other than income) were
$14 million in the current quarter, 13% higher than the second quarter of 2001.
This increase was primarily due to increased general, administrative and other
primarily due to approximately $1 million of fees incurred in the second quarter
of 2002 related to the Company's planned merger and exploration of strategic
alternatives. Exploration expenses for the second quarter of 2002 were $9
million, compared to $8 million for the same period of 2001. The second quarter
of 2002 includes approximately $3 million in costs associated with stacking of
the Arctic I rig compared to $0.6 million for the same period of 2001.
"Stacking" means maintaining the rig inactive, in this case, at an offshore
location. Depletion, depreciation and amortization for the second quarter of
2002 was $12 million, unchanged from the same period of 2001.
Total interest and other financing costs for the second quarter of 2002,
including interest income, preferred stock dividends and other income, were $10
million, a $1 million decrease from the same period of 2001. This decrease is
primarily due to lower interest expense related to the debt associated with the
FPS and Pipelines and the gas sales obligation offset by higher interest expense
associated with increased borrowings under the revolving credit agreement.
Six Months Ended June 30, 2002 and 2001
For the six months ended June 30, 2002, total revenues were $79 million, 5%
lower than total revenues for the six months ended June 30, 2001. Natural gas
revenues for the first six months of 2002 were 2% lower than the first six
months of 2001. This decrease was due to a 6% decrease in average natural gas
sales prices offset by a 5% increase in production. The average natural gas
sales price per Mcf was $3.30 for the first six months of 2002, compared with
$3.50 in the same period of 2001. The average natural gas sales price of $3.30
per Mcf for the first six months of 2002 includes hedging gains of $12 million
and 5,456 BBtu delivered under the gas sales obligation at an average price of
$2.47 per MMBtu. The average natural gas sales price of $3.50 per Mcf for the
first six months of 2001 includes hedging losses of approximately $10 million
and 10,847 BBtu delivered under fixed-price delivery contracts and the gas sales
obligation at an average price of $2.67 per MMBtu. Natural gas production for
the first six months of 2002 was 22 Bcf, compared with 21 Bcf in the same period
of 2001. Oil revenues decreased 27% primarily due to a 19% decline in average
oil sales prices for the six months ended June 30, 2002. The average oil price
during the first six months of 2002 decreased to $21.70 from $26.80, a decrease
of 19%.
Costs and expenses for the first six months of 2002 were $67 million, compared
with $81 million for the same period of 2001. Operating expenses (production and
operating, general and administrative and taxes other than income) remained flat
from period to period. General, administrative and other costs and production
and operating costs were higher, offset by lower taxes, other than income.
General, administrative and other costs were higher primarily due to fees
related to the Company's planned merger and exploration of strategic
alternatives. Taxes, other than income were lower for the six months ended June
30, 2002 primarily due to lower average natural gas sales prices. Exploration
expenses for the first six months of 2002 were $15 million, compared to $28
million for the same period of 2001. Exploration expense for the first six
months of 2002 includes approximately $3 million in costs associated with the
stacking of the Arctic I rig compared to $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 included in the first
six months of 2001. Depletion, depreciation and amortization for the first six
months of 2002 was $24 million, $1 million higher than the same period of 2001.
Total interest and other financing costs for the first six months of 2002,
including interest income, preferred stock dividends and other income, were $20
million, a $3 million decrease from the same period of 2001. This decrease is
primarily due to lower interest expense related to the debt associated with the
FPS and Pipelines and the gas sales obligation offset by higher interest expense
associated with increased borrowings under the revolving credit agreement.
12
EEX CORPORATION
SUMMARY OF SELECTED OPERATING DATA
FOR OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED)
Three Months Ended Six Months Ended
June 30 June 30
---------------------------- ---------------------------
2002 2001 2002 2001
------------- -------------- ------------- -------------
Sales volume
Natural gas (Bcf) (a) 11.1 10.6 21.7 20.7
Oil, condensate and natural gas liquids (MMBbls) (d) 0.1 0.1 0.2 0.3
Total volumes (Bcfe) (a) 11.7 11.3 23.0 22.2
Average sales price (b)
Natural gas (per Mcf) (c) $ 3.18 $ 3.13 $ 3.30 $ 3.50
Oil, condensate and natural gas liquids (per Bbl) 23.93 23.83 20.61 24.78
Total (per Mcfe) (c) 3.21 3.18 3.30 3.54
Average costs and expenses (per Mcfe) (c)
Production and operating (b) $ 0.49 $ 0.48 $ 0.52 $ 0.47
Exploration 0.77 0.71 0.64 1.25
Depletion, depreciation and amortization 1.03 1.02 1.05 1.03
General, administrative and other 0.42 0.28 0.40 0.29
Taxes, other than income 0.32 0.36 0.25 0.44
------------------
(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.
RESULTS OF DISCONTINUED OPERATIONS
During the second quarter of 2002, EEX closed and recorded the sale of all of
the shares of the subsidiary that owns a 25% interest in the Tuban Concession.
The sale of the other Indonesian subsidiary that owns a 15% interest in the
Asahan Concession has not closed.
For the six months ended June 30, 2002, EEX reported net income from
discontinued Indonesian operations (International segment), net of tax, of
approximately $3 million, $0.06 per share, versus net income of approximately
$11 million, $0.26 per share, for the same period of 2001.
For the six months ended June 30, 2002, oil revenues were $10 million, 63% lower
than oil revenues in the same period of 2001 primarily due to recording revenues
for only the first quarter of 2002 due to the sale of the Mudi Field. The
average oil price per barrel during the first six months of 2002 was $20.57
compared to $26.03 for the same period of 2001, a decrease of approximately 21%.
Oil production for the first six months of 2002 decreased 53% compared to the
same period in 2001. In accordance with SFAS No. 144, an impairment of
approximately $4 million, net of tax, was recorded in the first quarter of 2002,
which represented the Company's estimate at that time of the difference between
the book value and the fair value of the assets held for sale. In accordance
with SFAS No. 144, depletion was suspended in the first quarter of 2002.
Depletion for the first six months of 2001 was approximately $10 million.
Net cash flows provided by discontinued operations were $27 million for the six
months ended June 30, 2002, compared to net cash flows provided by discontinued
operations of $16 million for the same period 2001. The 2002 cash flow is
primarily due to the proceeds received from the sale of all of the shares of the
subsidiary that owns a 25% interest in the Tuban Concession during the second
quarter of 2002. The 2001 cash flow is primarily attributable to operations.
13
LIQUIDITY AND CAPITAL RESOURCES
Cash and Cash Equivalents and Cash Flows from Continuing Operations
The following summary table reflects the Company's cash flows from continuing
operations (in millions):
Six Months Ended
June 30
------------------
2002 2001
-------- ---------
Net cash provided by operating activities $ 15 $ 3
Net cash (used in) investing activities (32) (92)
Net cash (used in) provided by financing activities (130) 56
As of June 30, 2002, the cash and cash equivalents balance was approximately $17
million.
Net cash flows provided by operating activities from continuing operations for
the six months ended June 30, 2002 were approximately $15 million, an increase
of approximately $13 million over the same period of 2001. This increase was
primarily due to full utilization of the Arctic I rig through mid June 2002.
Net cash flows used in investing activities for continuing operations for the
six months ended June 30, 2002 were approximately $32 million, a $61 million
decrease from cash flows used in investing activities for the same period of
2001. The decrease in investing activities is primarily due to lower capital
expenditures and proceeds received from dispositions of property, plant and
equipment in 2002. The Encogen obligation was completed in the first half of
2001 and onshore spending was reduced in 2002 due to capital constraints offset
by capital spent on the Devil's Island well. In addition, the Company received
$11 million from the sale of a part of the production payment associated with
the Encogen obligation.
Net cash flows used in financing activities for continuing operations for the
six months ended June 30, 2002 were approximately $130 million, compared to net
cash flows provided by financing activities of $56 million for the same period
of 2001. During the second quarter of 2002, the Company entered into a new
credit facility and paid down the old facility resulting in a net repayment of
approximately $104 million. During the second quarter of 2001, the Company
borrowed $132 million.
Financing Activities
Effective May 28, 2002, EEX Operating, L.P. ("EEX Operating"), as Borrower and
an Obligor and EEX, as an additional Obligor, entered into a new revolving
credit facility with a group of banks and JPMorgan Chase Bank, as Administrative
Agent. A copy of the new credit agreement and related documents were filed as
exhibits to EEX's Current Report on Form 8-K filed on June 6, 2002. Unless
indicated otherwise, capitalized terms used in this section are defined in the
new credit agreement.
Maximum credit amount: $240 million, with a $10 million sublimit for
letters of credit, and an additional $10 million
available only for letters of credit
to support surety bond obligations of EEX.
Maturity: March 31, 2003, unless earlier terminated upon the
occurrence of certain specified events.
Interest rate: (i) For Base Rate Loans, the higher of Federal
Funds Rate plus 1/2 of 1% or Administrative Agent's
prime rate plus 2.75% and (ii) for Eurodollar Loans,
the Eurodollar Rate plus 4.0%, each rate increasing
0.5% per quarter beginning June 30, 2002.
Fees: A loan restructuring fee of $2,500,000 and an
arrangement fee of $750,000 are payable by September
30, 2002; provided, that in the event that EEX has
received all governmental approvals for its proposed
merger and has distributed all proxy and related
voting materials to its shareholders by such date,
then payment of the fees shall be delayed until
November 30, 2002; and provided further, that if the
merger has been consummated by November 30, 2002,
then EEX Operating shall have no obligation to pay
the fees.
Guaranties: Loans are guaranteed by all of EEX's domestic
subsidiaries other than EEX Reserves Funding LLC and
its subsidiaries.
14
Security: Security interests in the equity and ownership
interests of EEX's domestic subsidiaries (other than
the subsidiaries of EEX Reserves Funding LLC); other
material tangible and intangible assets of EEX
Operating, EEX and its subsidiaries; and mortgages
on substantially all of the oil and gas properties
of EEX Operating and EEX. EEX and EEX Operating are
required to maintain liens on oil and gas properties
of not less than 100% of the total value of their
oil and gas properties and 100% of the proved and
probable reserves (other than $500,000 of properties
outside of Texas and Louisiana).
Mandatory Prepayment: The proceeds from sales of assets and equity
offerings must be used to prepay loans outstanding;
mandatory prepayments reduce the maximum credit
amount.
Negative Covenants: Limits on additional borrowings, repayment of
existing debt, capital expenditures, dividends,
distributions and redemptions, investments, loans
and advances, liens, gas imbalances, take-or-pay
obligations, other prepayments, mergers, property
transfers and the sale of oil and gas properties and
hedging agreements; restrictions on the
restructuring of the gas sales obligation with Bob
West Treasure L.L.C., an Enron affiliate; and other
customary negative covenants. EEX may not use
borrowed funds to pay the scheduled principal and
interest payment due January 2, 2003 on its Secured
Notes.
Financial Covenants: The ratio of Total Debt to EBITDAX for the four most
recent quarters may not be greater than 4.0 to 1.0.
Commencing April 1, 2002, the ratio of EBITDAX to
Fixed Charges may not be less than 1.0 to 1.0.
EEX is required to maintain at least 375 Bcfe of
proved oil and natural gas reserves. The present
value, using JPMorgan's price deck and discount
rate (currently 9%), of EEX's proved developed
producing reserves must be at least 70% of the
present value of EEX's total proved reserves.
Events of Default: Nonpayment of principal when due; nonpayment of
interest, fees or other amounts after an agreed upon
grace period; material inaccuracy of representations
and warranties; violation of covenants;
cross-default; bankruptcy events; material
judgments; change in control; and other defaults
customary for oil and gas industry borrowers.
EEX Operating borrowed $225 million under the new credit agreement upon
execution and advanced that amount to EEX, and EEX used that amount, together
with $100 million in cash it had on hand, to repay and terminate its existing
revolving credit agreement. On July 31, 2002, the outstanding amount under the
new credit agreement was $223 million and the available credit was $17 million.
As of June 30, 2002, EEX met the required financial covenant ratios of the Total
Debt to EBITDAX and EBITDAX to Fixed Charges. Based upon preliminary
information, EEX expects to meet the requirement to maintain at least 375 Bcfe
of proved reserves with at least 70% of the present value attributed to proved
developed producing.
There can be no assurances that EEX will be able to meet the financial covenants
of the new credit agreement as of the end of the third fiscal quarter, and, if
it does not, it will be in default. There can be no assurances that EEX will be
able to cure such default, or any other covenant default that may occur.
Future Capital Requirements
Capital expenditures from continuing operations for the six months ended June
30, 2002 were approximately $35 million, compared to approximately $96 million
for the six months ended June 30, 2001. This decrease in capital spending during
the first half of 2002 is primarily due to the completion of the Encogen
obligation in the same period of 2001 and reduced onshore spending due to
capital constraints offset by capital spent on the Devil's Island Well. Capital
expenditures for the remainder of 2002 are expected to be approximately $20
million. Substantially all of these capital expenditures will be made on
drilling development wells on the Onshore segement.
Sources of Capital and Liquidity
During April 2002, the Company received approximately $26 million from the sale
of the shares of a subsidiary that owns a 25% interest in the Tuban Concession.
During the remainder of the year, EEX's sources of liquidity will be operating
cash flows from EEX Operating and borrowings under the new credit agreement. The
operating cash flows from EEX E&P Company, L.P. will not be available to EEX
because of restrictions in the agreement related to the gas sales obligation.
EEX estimates, based upon its current budget forecast, that it will have drawn
all of its available credit under the new credit agreement at or before December
31, 2002. EEX has no current source of funds to make the approximately $15
million payment on its Secured Notes due January 2, 2003.
15
EEX is not currently pursuing additional sources of financing because of the
pending merger and merger agreement with Newfield. If the merger does not take
place, there can be no assurances that EEX will be able to obtain additional
financing before it uses all of its available credit under the new credit
agreement. EEX will also require additional financing to make the January 2,
2003 payment on the Secured Notes if the merger does not take place.
No assurances can be given that EEX will be successful in completing the merger
with Newfield or an acceptable financing plan should the merger not occur. In
the event of default under the new credit agreement, EEX's lenders may attempt
to enforce their security interest in EEX's oil and gas properties and other
assets. EEX may then have to seek protection from its creditors and
reorganization under Federal bankruptcy laws.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Hedging activity for the six months ended June 30, 2002 resulted in a gain of
approximately $12 million for natural gas. The table below provides information
about EEX's hedging instruments as of June 30, 2002. 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 June 30, 2002
(BBtu) (1) (Per MMBtu) (2) (In thousands)
--------------- ---------------------- ------------------
Floor Ceiling
--------- ---------
Natural Gas Collars:
July 2002 - September 2002 460 $2.40 $2.73 $ (263)
October 2002 155 2.40 2.73 (89)
------ --------
Total 615 $ (352)
======= ========
Notional Average Fair Value at
Amount Swap Price June 30, 2002
(BBtu) (1) (Per MMBtu) (2) (In thousands)
------------------- ------------------- ------------------
Natural Gas Swaps:
July 2002 - September 2002 5,060 $3.42 $ 586
October 2002 - December 2002 5,060 3.63 198
January 2003 - March 2003 4,500 3.55 (1,612)
April 2003 - June 2003 4,550 3.29 (1,984)
July 2003 - September 2003 5,060 3.36 (1,724)
October 2003 - December 2003 5,060 3.55 (1,971)
------- --------
Total 29,290 $ (6,507)
======= ========
----------
(1) Billions of British Thermal Units.
(2) Millions of British Thermal Units.
16
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
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 EEX's General Counsel, Richard L. Edmonson, individual litigation
counsel, and current assessments, 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.
Item 2. Changes in Securities and Use of Proceeds
(a) On May 29, 2002, EEX amended it Rights Agreement by the Third Amendment
to Rights Agreement. The amendment provides that the execution of the
merger agreement with Newfield and of certain voting agreements entered
into in connection with the merger agreement, the performance of the
merger agreement and consummation of the transactions contemplated in
the merger agreement and voting agreements (see Part I, Item 2,
"Management's Discussion and Analysis of Financial Condition and
Results of Operation - Newfield Merger," above) will not be considered
events that trigger the distribution of Rights under the Rights
Agreement. A copy of the Third Amendment to Rights Agreement is an
exhibit to EEX's Current Report on Form 8-K, filed June 6, 2002 with
the Securities and Exchange Commission.
Item 4. Submission of Matters to a Vote of Security Holders
At the annual meeting of shareholders held on May 30, 2002, the shareholders
elected two directors for terms expiring at the annual meeting in 2005, and
ratified the appointment of Ernst & Young LLP as Independent Auditors for fiscal
year 2002. In addition to the two directors elected at the meeting, Thomas M
Hamilton, B. A. Bridgewater, Frederick M. Lowther, and M. P. Mallardi continued
their respective terms of office after the meeting. Below is the result of the
vote.
Election of Directors:
Abstentions and Broker
Name Votes for Withheld Non-Votes
---- ---------- ----------------- ---------
F. S. Addy 45,081,714 671,016 --
H. H. Newman 45,086,142 666,588 --
Appointment of Ernst & Young LLP as Independent Auditors:
Abstentions and
For Against Broker Non-Votes
----- ------- ----------------
45,382,675 272,987 97,068
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
2.1* Amended and Restated Agreement and Plan of Merger dated as
of May 29, 2002 by and among Newfield Exploration Company,
Newfield Operating Company and EEX Corporation, incorporated
by reference to Annex A to the proxy statement/prospectus in
Amendment No. 1 to the Registration Statement on Form S-4,
No. 333-91014, of Newfield Exploration Company and Treasure
Island Royalty Trust, filed under CIK 0000912750 on July 3,
2002.
4.1* Second Amendment to Rights Agreement, dated May 13, 2002,
among EEX Corporation, Harris Trust Company of New York and
Computershare Investor Services, LLC, incorporated by
reference to Exhibit 4.1 to Registrant's Current Report on
Form 8-K with report date of May 29, 2002, filed on June 6,
2002.
4.2* Third Amendment to Rights Agreement, dated May 29, 2002 by
and between EEX Corporation and Computershare Investor
Services, LLC, incorporated by reference to Exhibit 4.2 to
Registrant's Current Report on Form 8-K with report date of
May 29, 2002, filed on June 6, 2002.
10.1 Asset Purchase, Farmout and Joint Exploration Agreement
dated as of March 1, 2002, between BP Exploration &
Production Inc. and EEX
10.2 Offshore Operating Agreement effective March 1, 2002,
between BP Exploration & Production Inc. and EEX (Exhibit D
to the Asset Purchase, Farmout and Joint Exploration
Agreement)
10.3 Letter Agreement dated May 8, 2002, between BP Exploration
& Production Inc. and EEX
10.4 Amendatory Letter dated July 17, 2002, between BP Exploration
& Production Inc. and EEX
10.5* Credit Agreement, dated as of May 28, 2002 among EEX
Operating L.P., as Borrower and an Obligor, EEX Corporation,
as an additional Obligor, JPMorgan Chase Bank, as
Administrative Agent, Canadian Imperial Bank of Commerce, as
Syndication Agent, J.P. Morgan Securities Inc., as Lead
Arranger and Sole Bookrunner, CIBC World Markets Corp., as
Co-Arranger, and the Lenders signatory thereto, incorporated
by reference to Exhibit 10.2 to Registrant's Current Report
on Form 8-K with report date of May 29, 2002, filed on June
6, 2002.
10.6* Guarantee and Collateral Agreement, dated as of May 28, 2002
made by each of the Grantors defined therein in favor of
JPMorgan Chase Bank, as Administrative Agent, incorporated
by reference to Exhibit 10.3 to Registrant's Current Report
on Form 8-K with report date of May 29, 2002, filed on June
6, 2002.
10.7* Form of Mortgage, Assignment of Production, Security
Agreement and Financing Statement executed by EEX Operating
L.P. and EEX Corporation to JPMorgan Chase Bank, as
Administrative Agent, incorporated by reference to Exhibit
10.4 to Registrant's Current Report on Form 8-K with report
date of May 29, 2002, filed on June 6, 2002.
10.8* Form of Mortgage, Deed of Trust, Assignment of Production,
Security Agreement and Financing Statement executed by EEX
Operating L.P. and EEX Corporation to Robert C. Mertensotto,
as Trustee for the benefit of JPMorgan Chase Bank, as
Administrative Agent, incorporated by reference to Exhibit
10.5 to Registrant's Current Report on Form 8-K with report
date of May 29, 2002, filed on June 6, 2002.
23.1 Consent of Richard L. Edmonson
99.1 Certifications of Registrant's Chief Executive Officer and
Chief Financial Officer pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002
-------------
* incorporated by reference
(b) Reports on Form 8-K
Current Report on Form 8-K filed June 6, 2002 and dated May 29,
2002 (news release -- merger with Newfield Exploration Company)
Current Report on Form 8-K filed June 17, 2002 and dated May 28,
2002 (new credit agreement, liquidity and capital resources and
Devil's Island well results)
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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: August 13, 2002 By: /s/ R. S. Langdon
------------------------------
R. S. Langdon
Executive Vice President,
Finance and Administration,
and Chief Financial Officer
18