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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, 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 October 31,
2002: 42,556,914
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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
----------------------------- ----------------------------
2002 2001 2002 2001
--------------- ------------- ------------- --------------
(In thousands, except per share amounts)
Revenues:
Natural gas ................................................ $ 31,421 $ 32,580 $ 102,852 $ 105,117
Oil, condensate and natural gas liquids .................... 2,259 2,595 6,711 8,791
Cogeneration operations .................................... 684 1,306 2,650 5,194
Other ...................................................... 347 365 1,651 1,392
--------------- ------------- ------------- --------------
Total ................................................. 34,711 36,846 113,864 120,494
--------------- ------------- ------------- --------------
Costs and Expenses:
Production and operating ................................... 5,413 5,285 17,379 15,672
Exploration ................................................ 4,840 8,318 19,504 36,089
Depletion, depreciation and amortization ................... 11,053 13,209 35,139 36,197
(Gain) on sales of property, plant and equipment ........... (685) (29,176) (858) (28,841)
Cogeneration operations .................................... 526 992 2,368 4,460
General, administrative and other .......................... 3,728 2,956 13,017 9,456
Taxes, other than income ................................... 2,507 2,300 8,153 11,966
--------------- ------------- ------------- --------------
Total ................................................. 27,382 3,884 94,702 84,999
--------------- ------------- ------------- --------------
Operating Income from Continuing Operations .................... 7,329 32,962 19,162 35,495
Other Income--Net .............................................. 22 11 115 62
Interest Income ................................................ 29 183 896 784
Interest and Other Financing Costs ............................. (7,379) (7,519) (20,190) (23,096)
--------------- ------------- ------------- --------------
Income (Loss) from Continuing Operations Before Income Taxes ... 1 25,637 (17) 13,245
Income Taxes ................................................... 389 9,281 389 9,281
--------------- ------------- ------------- --------------
Income (Loss) from Continuing Operations ....................... (388) 16,356 (406) 3,964
Discontinued Operations:
Income from Discontinued Operations,
Net of Income Taxes ........................................ 261 3,622 2,721 14,147
--------------- ------------- ------------- --------------
Net Income (Loss) .............................................. (127) 19,978 2,315 18,111
Preferred Stock Dividends ...................................... 3,952 3,652 11,626 10,741
--------------- ------------- ------------- --------------
Net Income (Loss) Applicable to Common Shareholders ............ $ (4,079) $ 16,326 $ (9,311) $ 7,370
=============== ============= ============= ==============
Basic Earnings Per Share:
Net Income (Loss) from Continuing Operations ............... $ (0.10) $ 0.30 $ (0.29) $ (0.16)
Net Income from Discontinued Operations .................... -- 0.09 0.07 0.34
--------------- ------------- ------------- --------------
Net Income (Loss) Applicable to Common Shareholders ........ $ (0.10) $ 0.39 $ (0.22) $ 0.18
=============== ============= ============= ==============
Diluted Earnings Per Share:
Net Income (Loss) from Continuing Operations ............... $ (0.10) $ 0.24 $ (0.29) $ (0.16)
Net Income from Discontinued Operations .................... -- 0.05 0.07 0.34
--------------- ------------- ------------- --------------
Net Income (Loss) Applicable to Common Shareholders ........ $ (0.10) $ 0.29 $ (0.22) $ 0.18
=============== ============= ============= ==============
Weighted Average Shares Outstanding:
Basic ...................................................... 41,939 41,723 41,901 41,695
Diluted .................................................... 41,939 69,863 41,901 41,798
See accompanying notes.
2
EEX CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEET
(UNAUDITED)
September 30 December 31
2002 2001
--------------- ---------------
(In thousands)
ASSETS
------
Current Assets:
Cash and cash equivalents ................................................ $ 22,956 $ 136,618
Accounts receivable--trade (net of allowance of $2,837 and $2,780) ....... 15,967 29,651
Natural gas hedging derivatives .......................................... -- 23,203
Assets held for sale (net of allowance of $0 and $1,650) ................. -- 13,174
Other .................................................................... 3,981 1,871
--------------- ---------------
Total current assets ................................................ 42,904 204,517
--------------- ---------------
Property, Plant and Equipment (at cost):
Oil and gas properties (successful efforts method) ....................... 912,764 873,008
Other .................................................................... 8,609 8,668
--------------- ---------------
Total ............................................................... 921,373 881,676
Less accumulated depletion, depreciation and amortization ................ 399,280 362,128
--------------- ---------------
Net property, plant and equipment ................................... 522,093 519,548
--------------- ---------------
Net property, plant and equipment held for sale .............................. -- 18,107
Other Assets ................................................................. 3,035 7,946
--------------- ---------------
Total ............................................................... $ 568,032 $ 750,118
=============== ===============
LIABILITIES AND SHAREHOLDERS' EQUITY
------------------------------------
Current Liabilities:
Accounts payable--trade .................................................. $ 39,798 $ 42,443
Bank revolving credit agreement .......................................... 223,000 325,000
Secured notes payable .................................................... 14,642 13,579
Liabilities held for sale ................................................ -- 6,132
Other .................................................................... 5,929 7,118
--------------- ---------------
Total current liabilities ........................................... 283,369 394,272
--------------- ---------------
Secured Notes Payable ........................................................ 86,122 100,764
Gas Sales Obligation ......................................................... 41,914 59,937
Other Liabilities ............................................................ 12,281 9,357
Minority Interest Third Party ................................................ 5,000 5,000
Shareholders' Equity:
Preferred stock (10,000 shares authorized; 2,016 and 1,899 shares issued;
Liquidation preference of $201,572 and $189,946) .................... 20 19
Common stock ($0.01 par value; 150,000 shares authorized; 42,557 and
42,496 shares issued) ............................................... 433 432
Paid in capital .......................................................... 772,281 760,484
Retained (deficit) ....................................................... (614,923) (605,612)
Unamortized restricted stock compensation ................................ (957) (1,403)
Other comprehensive income ............................................... (8,391) 35,954
Treasury stock, at cost (843 and 817 shares) ............................. (9,117) (9,086)
--------------- ---------------
Total shareholders' equity .......................................... 139,346 180,788
--------------- ---------------
Total ............................................................... $ 568,032 $ 750,118
=============== ===============
See accompanying notes.
3
EEX CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
(UNAUDITED)
Nine Months Ended
September 30
-------------------------------
2002 2001
-------------- --------------
(In thousands)
OPERATING ACTIVITIES
Net Income ............................................................... $ 2,315 $ 18,111
Less: Income from discontinued operations ................................ 2,721 14,147
-------------- --------------
Income (Loss) from continuing operations ........................... (406) 3,964
Adjustments to reconcile net income to net cash
provided by operating activities:
Dry hole cost ............................................................ (189) 2,945
Depletion, depreciation and amortization ................................. 35,139 36,197
Impairment of undeveloped leasehold ...................................... 7,324 5,896
Deferred income taxes .................................................... -- 9,281
(Gain) on sales of property, plant and equipment ......................... (858) (28,841)
Other .................................................................... (2,552) (13,828)
Changes in current operating assets and liabilities:
Accounts receivable ................................................... 3,920 17,522
Other current assets .................................................. (2,110) 5,352
Accounts payable ...................................................... (4,911) (21,536)
Other current liabilities ............................................. (1,189) 405
-------------- --------------
Net cash flows provided by operating activities .................... 34,168 17,357
-------------- --------------
INVESTING ACTIVITIES
Additions of property, plant and equipment ............................... (44,834) (130,367)
Proceeds from dispositions of property, plant and equipment .............. 11,616 59,470
Other (changes in accruals) .............................................. (8,700) 556
-------------- --------------
Net cash flows used in investing activities ........................ (41,918) (70,341)
-------------- --------------
FINANCING ACTIVITIES
Borrowings under bank revolving credit agreement ......................... 227,000 185,000
Repayment of borrowings under bank revolving credit agreement ............ (329,000) (80,000)
Deliveries under the gas sales obligation ................................ (18,023) (20,299)
Proceeds from hedge settlements .......................................... 96 --
Purchase of treasury stock ............................................... (31) (25)
Purchase of lessor's equity interest in capital lease .................... -- (54,416)
Payments of secured notes payable ........................................ (13,579) (6,340)
Payments of capital lease obligations .................................... -- (7,805)
-------------- --------------
Net cash flows (used in) provided by financing activities .......... (133,537) 16,115
-------------- --------------
Cash Provided By Discontinued Operations ..................................... 27,605 23,043
Net Decrease in Cash and Cash Equivalents .................................... (113,682) (13,826)
Cash and Cash Equivalents at Beginning of Period ............................. 136,638 19,791
-------------- --------------
Cash and Cash Equivalents at End of Period ................................... 22,956 5,965
Less: Cash and Cash Equivalents of Discontinued Operations .................. -- 20
-------------- --------------
Cash and Cash Equivalents from Continuing Operations ......................... $ 22,956 $ 5,945
============== ==============
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
September 30, 2002 and December 31, 2001, and the results of operations and
cash flows for the nine months ended September 30, 2002 and 2001. Operating
results for the nine months ended September 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 ("PT
Medco"). During the third quarter of 2002, the Company closed the sale of
all of the shares of a subsidiary that owns a 15% interest in the Asahan
Concession to Medco International Ventures.
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
September 30, 2002, the outstanding balance was $223 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. The interest rates for the third quarter of 2002 were prime
plus 3.25% or LIBOR plus 4.5%. A loan restructuring fee of $2.5 million and
an arrangement fee of $0.8 million are payable if the merger with Newfield
is not completed by November 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. In the fourth quarter of 2001, the Company began marketing all of its
Indonesian assets. On January 1, 2002, the Company adopted SFAS No. 144.
Consequently, the Indonesian operations were 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 were recorded at their estimated fair market values
and the effect of any adjustments were reflected in the net income from
discontinued operations.
In March 2002, the Company negotiated and signed two stock purchase
agreements. 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 and received approximately $26 million. The sale
of this subsidiary was recorded during the second quarter of 2002.
On September 30, 2002, the Company closed the sale of all of the shares of
a subsidiary that owns a 15% interest in the Asahan Concession to Medco
International Ventures and received approximately $0.7 million. The sale of
this subsidiary was recorded during the third quarter of 2002.
Refer to Note 9 for results of the international segment's discontinued
operations for the quarter ended and the nine months ended September 30,
2002 compared to September 30, 2001. As of September 30, 2002, all
international operations have been sold.
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. Dividends on the preferred stock have been paid in-kind since
issuance.
The following table shows the dividends in-kind paid on, and the aggregate
liquidation preference of, the preferred stock as of the dates shown:
Aggregate Liquidation
Amount of Dividends Number of Preferred Preference
Date (In millions) Shares Issued (In millions)
------------------------ ----------------------- ------------------------- ------------------------
September 30, 2002 $4.0 39,524 $201.6
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 third quarter of 2002 were $5
million, during the second quarter of 2002 were $6 million, and during the
first quarter of 2002 were $7 million.
7. The Statement of Cash Flows for the nine months ended September 30, 2002
reflects $4 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 $40 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 three reportable segments, which are primarily in the
business of natural gas and crude oil exploration and production: Onshore,
Deepwater Operations, and Deepwater FPS/Pipelines. 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
of 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. During the
third quarter of 2002, the Company closed and recorded the sale of all of
the shares of the subsidiary that owns a 15% interest in the Asahan
Concession. As of September 30, 2002, the Company has sold all of its
international operations.
Financial information by operating segment is presented below (in
thousands):
Continuing Discontinued
Deepwater Operations Operations -
----------------------------
Onshore Operations FPS/Pipelines Other(a) Total International
---------- ---------- ------------- ---------- ----------- -------------
Three months ended September 30, 2002:
-------------------------------------
Total revenues ...................... $ 31,824 $ -- $ -- $ 2,887 $ 34,711 $ --
Production and operating costs ...... 5,013 24 376 -- 5,413 --
Exploration costs ................... 3,961 885 -- (6) 4,840 --
Depletion, depreciation and
amortization ....................... 9,727 -- 1,059 267 11,053 --
Other costs ......................... 2,671 (b) -- -- 3,405 6,076 (261)
---------- ---------- ------------- ---------- ----------- -------------
Operating Income (Loss) ............. 10,452 (909) (1,435) (779) 7,329 261
Interest Income ..................... -- -- -- 51 51 --
Interest and other financing costs .. (1,108) -- (1,927) (4,344) (7,379) --
---------- ---------- ------------- ---------- ----------- -------------
Income (Loss) before income taxes ... $ 9,344 $ (909) $ (3,362) $ (5,072) $ 1 $ 261
========== ========== ============= ========== =========== =============
Long-Lived Assets ................... $ 376,260 $ 76,871 $ 67,034 $ 1,928 $ 522,093 $ --
========== ========== ============= ========== =========== =============
Additions to Long-Lived Assets ...... $ 9,152 $ 951 $ -- $ 28 $ 10,131 $ --
========== ========== ============= ========== =========== =============
Three months ended September 30, 2001:
-------------------------------------
Total revenues ...................... $ 32,015 $ -- $ -- $ 4,831 $ 36,846 $ 11,643
Production and operating costs ...... 4,980 -- 306 (1) 5,285 3,261
Exploration costs ................... 7,236 940 -- 142 8,318 344
Depletion, depreciation and
amortization ....................... 10,473 -- 2,271 465 13,209 4,424
Other costs ......................... 2,297 (b) -- -- (25,225) (22,928) --
---------- ---------- ------------- ---------- ----------- -------------
Operating Income (Loss) ............. 7,029 (940) (2,577) 29,450 32,962 3,614
Interest Income ..................... -- -- -- 194 194 8
Interest and other financing costs .. (1,662) -- (2,628) (3,229) (7,519) --
---------- ---------- ------------- ---------- ----------- -------------
Income (Loss) before income taxes ... $ 5,367 $ (940) $ (5,205) $ 26,415 $ 25,637 $ 3,622
========== ========== ============= ========== =========== =============
Long-Lived Assets ................... $ 431,080 $ 69,341 $ 154,802 $ 3,689 $ 658,912 $ 27,774
========== ========== ============= ========== =========== =============
Additions to Long-Lived Assets ...... $ 36,174 $ (1,615) $ (18) $ 97 $ 34,638 $ 1,239
========== ========== ============= ========== =========== =============
7
EEX CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Continuing Discontinued
Deepwater Operations Operations -
----------------------------
Onshore Operations FPS/Pipelines Other(a) Total International
----------- ------------ --------------- ------------ ----------- ---------------
Nine months ended September 30, 2002:
-------------------------------------
Total revenues ............................... $ 96,002 $ -- $ -- $ 17,862 $ 113,864 $ 10,408
Production and operating costs ............... 15,536 777 1,066 -- 17,379 3,734
Exploration costs ............................ 9,786 9,724 -- (6) 19,504 380
Depletion, depreciation and amortization ..... 30,829 -- 3,177 1,133 35,139 --
Impairment of oil and gas properties as
required per SFAS 144 ..................... -- -- -- -- -- 4,051
Other costs .................................. 8,121 (b) -- -- 14,559 22,680 (506)
---------- ---------- ---------- ---------- ---------- ----------
Operating Income (Loss) ...................... 31,730 (10,501) (4,243) 2,176 19,162 2,749
Interest Income .............................. -- -- -- 1,011 1,011 7
Interest and other financing costs ........... (3,588) -- (3,852) (12,750) (20,190) --
---------- ---------- ---------- ---------- ---------- ----------
Income (Loss) before income taxes ............ $ 28,142 $ (10,501) $ (8,095) $ (9,563) $ (17) $ 2,756
========== ========== ========== ========== ========== ==========
Long-Lived Assets ............................ $ 376,260 $ 76,871 $ 67,034 $ 1,928 $ 522,093 $ --
========== ========== ========== ========== ========== ==========
Additions to Long-Lived Assets ............... $ 29,457 $ 15,085 $ 211 $ 81 $ 44,834 $ 2,028
========== ========== ========== ========== ========== ==========
Nine months ended September 30, 2001:
-------------------------------------
Total revenues ............................... $ 121,937 $ -- $ -- $ (1,443) $ 120,494 $ 39,415
Production and operating costs ............... 15,062 -- 610 -- 15,672 10,286
Exploration costs ............................ 17,321 18,131 -- 637 36,089 979
Depletion, depreciation and amortization ..... 29,916 -- 4,899 1,382 36,197 14,030
Other costs .................................. 12,063 (b) -- 3 (15,025) (2,959) --
---------- ---------- ---------- ---------- ---------- ----------
Operating Income (Loss) ...................... 47,575 (18,131) (5,512) 11,563 35,495 14,120
Interest Income .............................. -- -- -- 846 846 27
Interest and other financing costs ........... (5,474) -- (9,427) (8,195) (23,096) --
---------- ---------- ---------- ---------- ---------- ----------
Income (Loss) before income taxes ............ $ 42,101 $ (18,131) $ (14,939) $ 4,214 $ 13,245 $ 14,147
========== ========== ========== ========== ========== ==========
Long-Lived Assets ............................ $ 431,080 $ 69,341 $ 154,802 $ 3,689 $ 658,912 $ 27,774
========== ========== ========== ========== ========== ==========
Additions to Long-Lived Assets ............... $ 111,877 $ 4,529 $ 13,499 $ 462 $ 130,367 $ 6,290
========== ========== ========== ========== ========== ==========
------------------------------------
(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 $2 million for the quarter ended September 30, 2002, compared
to a gain of $4 million for the same period of 2001.
8
EEX CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
At September 30, 2002, EEX had outstanding natural gas swaps that were
entered into as hedges extending through December 31, 2003, to exchange
payments on 24,230 billion British thermal units of natural gas ("BBtu").
At September 30, 2002, the weighted average strike price and market price
per million British thermal units ("MMBtu") of natural gas were $3.48 and
$4.06, respectively. At September 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 $10.4 million, a net noncurrent liability of $2.2
million and accumulated other comprehensive loss of approximately $12.6
million. The Company realized no hedge ineffectiveness in the third quarter
of 2002.
At September 30, 2002, EEX had outstanding natural gas collars that were
entered into as hedges for the month of October 2002 to exchange payments
on approximately 155 BBtu of natural gas. At September 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 $3.64, respectively. At
September 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 $0.1 million and accumulated other comprehensive loss of $0.1 million.
The Company recognized no hedge ineffectiveness in the third 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. or its subsidiaries and affiliates in
December 2001 due to Enron's bankruptcy filing. During the third quarter of
2002, the Company reclassified approximately $1.3 million from accumulated
other comprehensive income to revenues related to these transactions. As of
September 30, 2002, $1.2 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.
11. In June 2001, the Financial Accounting Standards Board issued SFAS No. 143,
"Accounting for Asset Retirement Obligations" ("SFAS No. 143"). SFAS No.
143 requires entities to record the fair value of a liability for an asset
retirement obligation in the period in which it is incurred and a
corresponding increase in the carrying amount of the related long-lived
asset. SFAS No. 143 is effective for fiscal years beginning after June 15,
2002. EEX plans to implement this standard on January 1, 2003. EEX is
currently assessing the impact of this standard.
9
EEX CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
12. Earnings Per Share - The reconciliation between basic and diluted earnings
per common share is as follows:
Three Months Ended Nine Months Ended
September 30 September 30
--------------------- ---------------------
2002 2001 2002 2001
-------- -------- -------- --------
(In thousands, except per share amounts)
Net income (loss) from continuing operations .................... $ (4,340) $ 12,704 $(12,032) $ (6,777)
Effect of dilutive securities:
Preferred stock dividends .................................... -- 3,652 -- --
Stock options ................................................ -- 44 -- --
-------- -------- -------- --------
Net income (loss) from continuing operations for diluted
earnings per share ........................................... $ (4,340) $ 16,400 $(12,032) $ (6,777)
======== ======== ======== ========
Net income from discontinued operations ......................... $ 261 $ 3,622 $ 2,721 $ 14,147
Effect of dilutive securities:
Preferred stock dividends .................................... -- -- -- --
Stock options ................................................ -- -- -- --
-------- -------- -------- --------
Net income from discontinued operations for diluted earnings per
share ........................................................ $ 261 $ 3,622 $ 2,721 $ 14,147
======== ======== ======== ========
Net income (loss) from continuing operations applicable to
common shareholders .......................................... $ (4,079) $ 16,326 $ (9,311) $ 7,370
Effect of dilutive securities:
Preferred stock dividends .................................... -- 3,652 -- --
Stock options ................................................ -- 44 -- --
-------- -------- -------- --------
Net income (loss) from continuing operations applicable to
common shareholders for diluted earnings per share ........... $ (4,079) $ 20,022 $ (9,311) $ 7,370
======== ======== ======== ========
Basic weighted average shares outstanding ....................... 41,939 41,723 41,901 41,695
Effect of dilutive securities:
Preferred stock .............................................. -- 27,907 -- --
Stock options ................................................ -- 233 -- 103
-------- -------- -------- --------
Diluted weighted average shares outstanding ..................... 41,939 69,863 41,901 41,798
======== ======== ======== ========
Basic earnings per share:
Net income (loss) from continuing operations.................. $ (0.10) $ 0.30 $ (0.29) $ (0.16)
Net income from discontinued operations....................... -- 0.09 0.07 0.34
-------- -------- -------- --------
Net income (loss) applicable to common shareholders........... $ (0.10) $ 0.39 $ (0.22) $ 0.18
======== ======== ======== ========
Diluted earnings per share:
Net income (loss) from continuing operations.................. $ (0.10) $ 0.24 $ (0.29) $ (0.16)
Net income from discontinued operations....................... -- 0.05 0.07 0.34
-------- -------- -------- --------
Net income (loss) applicable to common shareholders........... $ (0.10) $ 0.29 $ (0.22) $ 0.18
======== ======== ======== ========
10
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, Treasure Island Royalty Trust, in lieu of
Newfield stock. Approximately 42.5 million trust units will be available. For
each unit that an EEX shareholder is allocated, the number of shares of Newfield
common stock that the shareholder would otherwise receive will be reduced by
0.00054 of one share. 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.
Treasure Island Royalty Trust is a trust created by Newfield under Texas law to
hold non-expense bearing overriding royalty interests in future production
attributable to subject leasehold interests in an area referred to as Treasure
Island. Treasure Island is located within 116 Gulf of Mexico lease blocks and
consists of all horizons below depths agreed to by EEX and Newfield for each of
the blocks. The agreed depths generally correspond to the base of a salt weld
typically found at 18,000 feet, but sometimes as deep as 22,200 feet, true
vertical depth. To be subject to an overriding royalty interest held by the
trust, a leasehold interest in Treasure Island must be held by EEX at the
effective time of the merger or acquired by EEX or Newfield within five years
after the effective time of the merger. EEX currently holds an interest in 27
Treasure Island lease blocks. The overriding royalty interests will be granted
to the trust pursuant to a master conveyance of overriding royalty interest from
EEX.
At this time, the Treasure Island project is only an exploration concept. An
"exploration concept" is a series of untested prospects with geological
characteristics thought to be conducive to the accumulation and entrapment of
significant quantities of oil and gas and that are analogous to producing fields
elsewhere. There is no production, and there are no proved reserves, currently
associated with Treasure Island or the royalty interests. The trust will have no
ability to influence the exploration or development of Treasure Island. In
addition, Newfield will be under no obligation to fund or to commit any other
resources to the exploration or development of Treasure Island.
EEX and BP Exploration and Production Inc. ("BP") have entered into an agreement
pursuant to which BP acquired 75% of the interests held by EEX in leases that
include Treasure Island horizons. BP may elect, but has no obligation, to drill
up to three wells to the Treasure Island horizons pursuant to the agreement. BP
will retain its interest in certain leases with each well it drills. If BP
drills all three wells, it retains all the interests acquired under the
agreement. If it does not drill one or more of the three wells, BP must reassign
certain interests to EEX for nominal consideration. If BP does not drill any of
the wells, EEX will need to fund the exploration of the leases with its own
capital or find another company willing to do so. If BP meets its obligations
under the agreement, BP will operate the project and will control the timing of
exploration and other expenditures.
11
The merger is subject to the approval of EEX's shareholders and other conditions
which must be met or waived. The special meeting of shareholders to vote on the
approval of the merger agreement is scheduled for November 26, 2002. EEX has
agreed to terminate the gas sales obligation between EEX E&P and an affiliate of
Enron North America Corp. before the merger closes. Because Enron North America
has filed for bankruptcy, the completion of these actions requires the approval
of the bankruptcy court. The timing of court approval is difficult to predict
and may not be obtained prior to the EEX special meeting. If approval has not
been obtained prior to the special meeting, the completion of the merger will be
delayed until approval is obtained or other arrangements satisfactory to
Newfield are made. The merger agreement requires that the merger be completed on
or before December 31, 2002. Newfield has filed a registration statement on Form
S-4 and other relevant documents with the Securities and Exchange Commission
concerning the merger, and EEX has mailed the proxy statement/prospectus
contained therein to its shareholders in connection with the merger. A complete
description of the merger can be found in the proxy statement/prospectus.
Floating Production System and Pipelines
EEX continued its marketing efforts for the Floating Production System ("FPS")
and the Pipelines during the third quarter of 2002. 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. The Llano owners have decided to use
facilities other than the Pipelines for the development of the Llano field
production; thus the potential market for use of the Pipelines has narrowed. EEX
is working with others to develop proposals for the use of the FPS and 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, Amerada Hess
Corporation. 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. 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 third quarter 2002 net loss of $4 million, or ($0.10)
per share, compared to net income of $16 million, or $0.39 per share for the
third 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 third quarter, the
Company closed and recorded the sale of the other Indonesian subsidiary that
owns a 15% interest in the Asahan Concession.
A discussion of results of continuing operations for the three and nine months
ended September 30, 2002, compared to the same period of 2001 follows.
RESULTS OF CONTINUING OPERATIONS
Quarters Ended September 30, 2002 and 2001
For the third quarter of 2002, EEX reported a loss from continuing operations of
$4 million or ($0.10) per share, versus income from continuing operations of $13
million or $0.30 per share for the same period in 2001.
For the third quarter of 2002, total revenues were $35 million, 6% lower than
the third quarter of 2001. Natural gas revenues for the third quarter of 2002
were 4% lower than the same quarter of 2001. This decrease was due to a 7%
decrease in production offset by a 3% increase in the average natural gas sales
price. Natural gas production for the third quarter of 2002 was 11 billion cubic
feet ("Bcf"), slightly lower than the same period of 2001. The average natural
gas sales price per thousand cubic feet ("Mcf") was $2.99 in the third quarter
of 2002, compared with $2.89 in the same period of 2001. The average natural gas
sales price for the third quarter 2002 includes hedging gains of $2 million and
2,485 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 $2.89 per Mcf for the third
quarter 2001 includes hedging losses of approximately $4 million and 4,325 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 third quarter of 2002
decreased 12% from the same quarter of 2001. This decrease was primarily due to
an 18% decrease in production offset by a 7% increase in the average oil sales
price. The average oil price per barrel during the third quarter of 2002 was
$26.15 compared to $24.55 for the same period of 2001.
12
Costs and expenses for the third quarter of 2002 were $27 million, compared with
$4 million in the same period of 2001. The increase for the third quarter of
2002 was primarily due to the gain of $27 million recorded in the third quarter
of 2001 related to the sale of the Llano Field. Operating expenses (production
and operating, general, administrative and other, and taxes other than income)
were $12 million in the current quarter, 11% higher than the third quarter of
2001. This increase was primarily due to increased general, administrative and
other resulting from an increase in D&O liability insurance premiums and
increased employee benefit cost. Exploration expenses for the third quarter of
2002 were $5 million, compared to $8 million for the same period of 2001. The
decrease is primarily due to no dry hole costs or geological and geophysical
expenditures during the third quarter 2002 compared to $2 million in dry hole
costs and $1 million in geological and geophysical expenditures during the same
period of 2001. Depletion, depreciation and amortization for the third quarter
of 2002 was $11 million, 16% lower than the third quarter of 2001. This decrease
was due primarily to lower production volumes during the third quarter of 2002.
Total interest and other financing costs for the third quarter of 2002,
including interest income, preferred stock dividends and other income, were $11
million, unchanged from the same period of 2001.
Nine Months Ended September 30, 2002 and 2001
For the nine months ended September 30, 2002, total revenues were $114 million,
6% lower than total revenues for the nine months ended September 30, 2001.
Natural gas revenues for the first nine months of 2002 were 2% lower than the
first nine months of 2001. This decrease was due to a 3% decrease in average
natural gas sales prices offset by a 1% increase in production. The average
natural gas sales price per Mcf was $3.19 for the first nine months of 2002,
compared with $3.28 in the same period of 2001. The average natural gas sales
price of $3.19 per Mcf for the first nine months of 2002 includes hedging gains
of $14 million and 7,941 BBtu delivered under the gas sales obligation at an
average price of $2.44 per MMBtu. The average natural gas sales price of $3.28
per Mcf for the first nine months of 2001 includes hedging losses of $6 million
and 15,555 BBtu delivered under fixed-price delivery contracts and the gas sales
obligation at an average price of $2.66 per MMBtu. Natural gas production for
the first nine months of 2002 was 32 Bcf, relatively unchanged from the same
period of 2001. Oil revenues decreased 23% primarily due to a 12% decline in
average oil sales prices and a 12% decrease in production for the nine months
ended September 30, 2002. The average oil price during the first nine months of
2002 decreased to $23.03 from $26.09.
Costs and expenses for the first nine months of 2002 were $95 million, compared
with $85 million for the same period of 2001. Operating expenses (production and
operating, general, administrative and other, and taxes, other than income) were
$39 million, 4% higher than the third quarter of 2001. 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 with Newfield and
exploration of other strategic alternatives. Taxes, other than income were lower
for the nine months ended September 30, 2002 primarily due to lower average
natural gas sales prices. Exploration expenses for the first nine months of 2002
were $20 million, compared to $36 million for the same period of 2001.
Exploration expense for the first nine 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 nine months of 2001. The
contract for the Arctic I rig expired on July 3, 2002. In addition, the first
nine months of 2001 includes dry hole costs of $3 million and an increase of $2
million in geological and geophysical costs compared to the same period of 2002.
Depletion, depreciation and amortization for the first nine months of 2002 was
$35 million, 3% lower than the first nine months of 2001.
Total interest and other financing costs for the first nine months of 2002,
including interest income, preferred stock dividends and other income, were $31
million, a $2 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.
13
EEX CORPORATION
SUMMARY OF SELECTED OPERATING DATA
FOR OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30 September 30
---------------------------- ---------------------------
2002 2001 2002 2001
------------ -------------- ------------ -------------
Sales volume
Natural gas (Bcf) (a) ................................. 10.5 11.3 32.2 32.0
Oil, condensate and natural gas liquids (MMBbls) (d) .. 0.1 0.1 0.3 0.4
Total volumes (Bcfe) (a) ........................... 11.0 12.0 34.0 34.2
Average sales price (b)
Natural gas (per Mcf) (c) ............................. $ 2.99 $ 2.89 $ 3.19 $ 3.28
Oil, condensate and natural gas liquids (per Bbl) ..... 25.38 22.37 22.00 24.02
Total (per Mcfe) (c) ............................... 3.05 2.94 3.22 3.33
Average costs and expenses (per Mcfe) (c)
Production and operating (b) .......................... $ 0.49 $ 0.44 $ 0.51 $ 0.46
Exploration ........................................... 0.44 0.70 0.57 1.06
Depletion, depreciation and amortization .............. 1.00 1.10 1.03 1.06
General, administrative and other ..................... 0.34 0.25 0.38 0.28
Taxes, other than income .............................. 0.23 0.19 0.24 0.35
-------------------------
(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 third quarter of 2002, EEX closed and recorded the sale of the
Indonesian subsidiary that owns a 15% interest in the Asahan Concession for
approximately $0.7 million.
For the nine months ended September 30, 2002, EEX reported net income from
discontinued Indonesian operations (International segment), net of tax, of
approximately $3 million, or $0.07 per share, versus net income of approximately
$14 million, or $0.34 per share, for the same period of 2001.
For the nine months ended September 30, 2002, oil revenues were $10 million, 74%
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 nine months of 2002 was $20.57
compared to $25.28 for the same period of 2001, a decrease of approximately 19%.
Oil production for the first nine months of 2002 decreased 68% 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 nine months of 2001 was approximately $14 million.
Net cash flows provided by discontinued operations were $28 million for the nine
months ended September 30, 2002, compared to net cash flows provided by
discontinued operations of $23 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 two Indonesian subsidiaries during the second and third quarters
of 2002. The 2001 cash flow is primarily attributable to operations.
14
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):
Nine Months Ended
September 30
----------------------------------
2002 2001
-------------- ---------------
Net cash provided by operating activities ..................... $ 34 $ 17
Net cash (used in) investing activities ....................... (42) (70)
Net cash (used in) provided by financing activities ........... (134) 16
As of September 30, 2002, the cash and cash equivalents balance was
approximately $23 million.
Net cash flows provided by operating activities for continuing operations for
the nine months ended September 30, 2002 were approximately $34 million, an
increase of approximately $17 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
nine months ended September 30, 2002 were approximately $42 million, a $28
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 in 2002 offset by a decrease in proceeds received from
dispositions of property, plant and equipment compared to 2001. 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. The
proceeds from dispositions of property, plant and equipment received in the
third quarter of 2001 were primarily related to the sale of the Llano Field.
Net cash flows used in financing activities for continuing operations for the
nine months ended September 30, 2002 were approximately $134 million, compared
to net cash flows provided by financing activities of $16 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. As of the end of the third
quarter of 2002, a net repayment of approximately $102 million has been made.
The Company's net borrowings during the first nine months of 2001 were $105
million. During the second quarter of 2001, the Company purchased the lessor's
equity interest and terminated the capital lease associated with the FPS and
Pipelines.
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
LIBOR Rate plus 4.0%, each rate increasing 0.5% per
quarter beginning June 30, 2002.
Fees: EEX paid a loan restructuring fee of $2,500,000 into an
account subject to escrow instructions in October 2002.
If the merger has been consummated by November 30,
2002, the restructuring fee will be returned to EEX. If
the merger is not completed by November 30, 2002, the
restructuring fee will be paid to participant banks.
EEX Operating will also be obligated to pay $750,000 as
an arrangement fee if the merger is not completed by
November 30, 2002.
Guaranties: Loans are guaranteed by all of EEX's domestic
subsidiaries other than EEX Reserves Funding LLC and
its subsidiaries.
15
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 October 31, 2002, the outstanding borrowings were
$223 million, outstanding letters of credit were $1 million, and available
credit was $16 million under the new credit agreement. As of September 30, 2002,
EEX met the required financial covenant ratios of the Total Debt to EBITDAX and
EBITDAX to Fixed Charges. As of September 30, 2002, EEX met the reserve
maintenance test requirement to maintain at least 375 Bcfe of proved reserves
with at least 70% of the present value attributed to proved developed producing.
Future Capital Requirements
Capital expenditures from continuing operations for the nine months ended
September 30, 2002 were approximately $45 million, compared to approximately
$130 million for the nine months ended September 30, 2001. This decrease in
capital spending during the first nine months of 2002 is primarily due to the
completion of the Encogen obligation during the first half 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 $10 million. Substantially all of these capital expenditures
will be made on drilling development wells on the Onshore segment.
Sources of Capital and Liquidity
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.
Except for temporary inter-company balances, 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.
16
EEX estimates, based upon its current budget forecast, that it will have drawn
all or substantially 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 $18 million net payment on its Secured Notes due January 2, 2003.
There can be no assurance that EEX will be able to meet the financial covenants
for the new credit agreement as of the end of the fourth calendar quarter of
this year, 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. The occurrence of one or more of these events, if not timely cured,
may have a material adverse effect (as defined in the merger agreement) on EEX,
which would give Newfield the right to terminate the merger agreement pursuant
to its terms.
EEX is not currently pursuing additional sources of financing because of the
proposed merger and restrictions in the 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 in developing 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.
OTHER MATTERS
Accounting Pronouncements
In June 2001, the Financial Accounting Standards Board issued SFAS No. 143,
"Accounting for Asset Retirement Obligations" ("SFAS No. 143"). SFAS No. 143
requires entities to record the fair value of a liability for an asset
retirement obligation in the period in which it is incurred and a corresponding
increase in the carrying amount of the related long-lived asset. SFAS No. 143 is
effective for fiscal years beginning after June 15, 2002. EEX plans to implement
this standard on January 1, 2003. EEX is currently assessing the impact of this
standard.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Hedging activity for the nine months ended September 30, 2002 resulted in a gain
of approximately $14 million for natural gas. The table below provides
information about EEX's hedging instruments as of September 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.
Fair Value at
Notional Average September 30,
Amount Strike Price 2002
(BBtu)(1) (Per MMBtu)(2) (In thousands)
--------------- ---------------------- ------------------
Floor Ceiling
--------- ---------
Natural Gas Collars:
October 2002 ................................ 155 $2.40 $2.73 $ (141)
--------------- ------------------
Total .................................. 155 $ (141)
=============== ==================
Fair Value at
Notional Average September 30,
Amount Swap Price 2002
(BBtu)(1) (Per MMBtu)(2) (In thousands)
--------------- ------------------- ------------------
Natural Gas Swaps:
October 2002 - December 2002 ................ 5,060 $3.63 $ (2,015)
January 2003 - March 2003 ................... 4,500 3.55 (3,269)
April 2003 - June 2003 ...................... 4,550 3.29 (2,830)
July 2003 - September 2003 .................. 5,060 3.36 (2,269)
October 2003 - December 2003 ................ 5,060 3.55 (2,234)
--------------- ------------------
Total .................................. 24,230 $(12,617)
=============== ==================
--------------------
(1) Billions of British Thermal Units.
(2) Millions of British Thermal Units.
17
Item 4. Disclosure Controls And Procedures
As of October 31, 2002, under the supervision and with the participation of
EEX's Chief Executive Officer (CEO) and Chief Financial Officer (CFO),
management has evaluated the effectiveness of the design and operation of EEX's
disclosure controls and procedures. Based on that evaluation, the CEO and CFO
concluded that, as of October 31, 2002, EEX's disclosure controls and procedures
were effective to ensure that information required to be disclosed by EEX in the
reports filed or submitted by EEX under the Securities and Exchange Act of 1934
is recorded, processed, summarized and reported within the time periods
specified in the SEC's rules and forms, and include controls and procedures
designed to ensure that information required to be disclosed by EEX in such
reports is accumulated and communicated to EEX's management, including the CEO
and CFO, as appropriate, to allow timely decisions regarding required
disclosure.
There were no significant changes in EEX's internal controls or in other factors
that could significantly affect those controls subsequent to the date of the
evaluation.
18
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 6. Exhibits and Reports on Form 8-K
(a) Exhibits
10.1* Amendatory Letter dated July 16, 2002, by and
between EEX Corporation and BP Exploration and
Production Inc. amending the Asset Purchase, Farmout
& Joint Exploration Agreement dated March 1, 2002,
and the Offshore Operating Agreement attached
thereto, previously filed as Exhibits 10.1 to 10.4
to the Registrant's Quarterly Report on Form 10-Q
for the quarter ended June 30, 2002, incorporated by
reference to Exhibit 10.1 to Registrant's Current
Report on Form 8-K with report date of July 16,
2002, filed on September 27, 2002.
10.2* Second Amendatory Agreement dated as of September
27, 2002 and effective as of May 29, 2002, to the
Agreement and Plan of Merger by and among Newfield
Exploration Company, Newfield Operating Company, and
EEX incorporated by reference to Exhibit 2.1.2 and
Annex A to the proxy statement/prospectus in
Amendment No. 3 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 September 27, 2002.
23.1 Consent of Richard L. Edmonson, General Counsel of
EEX Corporation
99.1 Certificates of Thomas M Hamilton, Chief Executive
Officer, and Richard S. Langdon, Chief Financial
Officer, pursuant to 18 U.S.C. Section 1350, as
adopted 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 September 27, 2002 and dated
July 16, 2002 (Amendatory Letter with BP Exploration).
19
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 14, 2002 By: /s/ Richard S. Langdon
----------------------------------
Richard S. Langdon
Executive Vice President,
Finance and Administration,
and Chief Financial Officer
CERTIFICATIONS
I, Thomas M Hamilton, certify that:
1. I have reviewed this quarterly report on Form 10-Q of EEX Corporation;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: November 14, 2002
/s/ Thomas M Hamilton
----------------------------
Thomas M Hamilton
Chairman, President and Chief
Executive Officer
20
CERTIFICATIONS
I, Richard S. Langdon, certify that:
1. I have reviewed this quarterly report on Form 10-Q of EEX Corporation;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: November 14, 2002
/s/ Richard S. Langdon
---------------------------
Richard S. Langdon
Executive Vice President and
Chief Financial Officer
21