.
.
.
EXHIBIT 99.5
The Williams Companies, Inc.
Consolidated Statement of Operations
(Unaudited)
THREE MONTHS SIX MONTHS
ENDED JUNE 30, ENDED JUNE 30,
------------------------ ------------------------
(DOLLARS IN MILLIONS, EXCEPT PER-SHARE AMOUNTS) 2004 2003* 2004 2003*
----------------------------------------------- ----------- ----------- ----------- -----------
Revenues:
Power $ 2,333.2 $ 2,940.2 $ 4,629.6 $ 6,721.7
Gas Pipeline 331.0 330.7 690.0 670.3
Exploration & Production 189.0 200.2 354.2 444.1
Midstream Gas & Liquids 630.5 502.2 1,257.8 1,367.6
Other 7.0 20.1 19.6 48.1
Intercompany eliminations (442.0) (381.1) (837.0) (863.4)
----------- ----------- ----------- -----------
Total revenues 3,048.7 3,612.3 6,114.2 8,388.4
----------- ----------- ----------- -----------
Segment costs and expenses:
Costs and operating expenses 2,658.3 3,024.8 5,348.2 7,448.4
Selling, general and administrative expenses 81.9 115.4 166.3 221.0
Other (income) expense - net 23.0 (225.3) 31.4 (224.6)
----------- ----------- ----------- -----------
Total segment costs and expenses 2,763.2 2,914.9 5,545.9 7,444.8
----------- ----------- ----------- -----------
General corporate expenses 28.3 21.8 60.3 44.7
----------- ----------- ----------- -----------
Operating income (loss):
Power 24.2 364.7 13.1 234.2
Gas Pipeline 128.3 113.4 272.2 261.9
Exploration & Production 40.1 176.2 88.7 287.9
Midstream Gas & Liquids 96.1 51.6 199.7 167.0
Other (3.2) (8.5) (5.4) (7.4)
General corporate expenses (28.3) (21.8) (60.3) (44.7)
----------- ----------- ----------- -----------
Total operating income 257.2 675.6 508.0 898.9
Interest accrued (222.3) (405.9) (465.6) (758.7)
Interest capitalized .7 11.3 4.7 23.2
Interest rate swap income (loss) 6.8 (6.1) (1.3) (8.9)
Investing income (loss) 11.7 (43.2) 22.0 3.1
Early debt retirement costs (96.8) -- (97.3) --
Minority interest in income of consolidated subsidiaries (6.0) (6.0) (10.8) (9.5)
Other income (expense) - net 13.4 13.9 14.8 36.0
----------- ----------- ----------- -----------
Income (loss) from continuing operations before income taxes and cumulative (35.3) 239.6 (25.5) 184.1
effect of change in accounting principles
Provision (benefit) for income taxes (17.3) 125.9 (6.0) 113.5
----------- ----------- ----------- -----------
Income (loss) from continuing operations (18.0) 113.7 (19.5) 70.6
Income (loss) from discontinued operations (.2) 156.0 11.2 145.9
----------- ----------- ----------- -----------
Income (loss) before cumulative effect of change in accounting principles (18.2) 269.7 (8.3) 216.5
Cumulative effect of change in accounting principles -- -- -- (761.3)
----------- ----------- ----------- -----------
Net income (loss) (18.2) 269.7 (8.3) (544.8)
Preferred stock dividends -- 22.7 -- 29.5
----------- ----------- ----------- -----------
Income (loss) applicable to common stock $ (18.2) $ 247.0 $ (8.3) $ (574.3)
=========== =========== =========== ===========
Basic earnings (loss) per common share:
Income (loss) from continuing operations $ (.03) $ .18 $ (.04) $ .08
Income (loss) from discontinued operations -- .30 .02 .28
----------- ----------- ----------- -----------
Income (loss) before cumulative effect of change in accounting principles (.03) .48 (.02) .36
Cumulative effect of change in accounting principles -- -- -- (1.47)
----------- ----------- ----------- -----------
Net income (loss) $ (.03) $ .48 $ (.02) $ (1.11)
=========== =========== =========== ===========
Weighted-average shares (thousands) 521,698 518,090 520,592 517,872
Diluted earnings (loss) per common share:
Income (loss) from continuing operations $ (.03) $ .17 $ (.04) $ .07
Income (loss) from discontinued operations -- .29 .02 .28
----------- ----------- ----------- -----------
Income (loss) before cumulative effect of change in accounting principles (.03) .46 (.02) .35
Cumulative effect of change in accounting principles -- -- -- (1.45)
----------- ----------- ----------- -----------
Net income (loss) $ (.03) $ .46 $ (.02) $ (1.10)
=========== =========== =========== ===========
Weighted-average shares (thousands) 521,698 534,839 520,592 523,553
Cash dividends per common share $ .01 $ .01 $ .02 $ .02
* Certain amounts have been reclassified as described in Note 2 of Notes to
Consolidated Financial Statements.
See accompanying notes.
99.5-1
The Williams Companies, Inc.
Consolidated Balance Sheet
(Unaudited)
JUNE 30, DECEMBER 31,
(DOLLARS IN MILLIONS, EXCEPT PER-SHARE AMOUNTS) 2004 2003*
----------------------------------------------- ------------ -----------
ASSETS
Current assets:
Cash and cash equivalents $ 1,030.3 $ 2,315.7
Restricted cash 45.2 47.1
Restricted investments -- 93.2
Accounts and notes receivable less allowance of $102.8 ($112.2 in 2003) 1,461.0 1,613.2
Inventories 255.3 242.9
Derivative assets 3,936.1 3,166.8
Margin deposits 423.7 553.9
Assets of discontinued operations 434.8 441.3
Deferred income taxes 68.2 106.6
Other current assets and deferred charges 107.4 214.3
------------ -----------
Total current assets 7,762.0 8,795.0
Restricted cash 131.0 159.8
Restricted investments -- 288.1
Investments 1,363.0 1,463.6
Property, plant and equipment, at cost 16,043.4 15,752.3
Less accumulated depreciation and depletion (4,273.3) (4,018.3)
------------ -----------
11,770.1 11,734.0
Derivative assets 3,435.8 2,495.6
Goodwill 1,014.5 1,014.5
Assets of discontinued operations -- 345.1
Other assets and deferred charges 692.0 726.1
------------ -----------
Total assets $ 26,168.4 $ 27,021.8
============ ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Notes payable $ -- $ 3.3
Accounts payable 1,044.8 1,228.0
Accrued liabilities 859.9 944.4
Liabilities of discontinued operations 24.3 95.7
Derivative liabilities 3,979.2 3,064.2
Long-term debt due within one year 276.6 935.2
------------ -----------
Total current liabilities 6,184.8 6,270.8
Long-term debt 9,483.0 11,039.8
Deferred income taxes 2,326.3 2,453.4
Derivative liabilities 3,179.4 2,124.1
Other liabilities and deferred income 906.3 947.5
Contingent liabilities and commitments (Note 13)
Minority interests in consolidated subsidiaries 89.7 84.1
Stockholders' equity:
Common stock, $1 per share par value, 960 million shares authorized, 525.6 million issued in 2004, 525.6 521.4
521.4 million issued in 2003
Capital in excess of par value 5,217.0 5,195.1
Accumulated deficit (1,445.5) (1,426.8)
Accumulated other comprehensive loss (235.5) (121.0)
Other (24.1) (28.0)
------------ -----------
4,037.5 4,140.7
Less treasury stock (at cost), 3.2 million shares of common stock in 2004 and 2003 (38.6) (38.6)
------------ -----------
Total stockholders' equity 3,998.9 4,102.1
------------ -----------
Total liabilities and stockholders' equity $ 26,168.4 $ 27,021.8
============ ===========
* Certain amounts have been reclassified as described in Note 2 to Consolidated
Financial Statements.
See accompanying notes.
99.5-2
The Williams Companies, Inc.
Consolidated Statement of Cash Flows
(Unaudited)
SIX MONTHS ENDED JUNE 30,
-------------------------
2004 2003*
----------- -----------
(MILLIONS)
OPERATING ACTIVITIES:
Income (loss) from continuing operations $ (19.5) $ 70.6
Adjustments to reconcile to cash provided (used) by operations:
Depreciation, depletion and amortization 328.5 329.8
Provision (benefit) for deferred income taxes (19.5) 79.6
Provision for loss on investments, property and other assets 30.0 120.8
Net gain on disposition of assets (2.0) (100.6)
Provision for uncollectible accounts (4.8) 6.0
Minority interest in income of consolidated subsidiaries 10.8 9.5
Amortization of stock-based awards 7.5 21.4
Payment of deferred set-up fee and fixed rate interest on RMT note payable -- (265.0)
Accrual for fixed rate interest included in the RMT note payable -- 99.3
Amortization of deferred set-up fee and fixed rate interest on RMT note payable -- 154.5
Cash provided (used) by changes in current assets and liabilities:
Restricted cash 2.8 (.5)
Accounts and notes receivable 150.0 682.3
Inventories (12.5) 42.0
Margin deposits 130.2 195.2
Other current assets and deferred charges 105.0 (61.0)
Accounts payable (144.8) (462.8)
Accrued liabilities (142.7) (205.7)
Changes in current and noncurrent derivative assets and liabilities 77.7 (356.8)
Changes in noncurrent restricted cash 11.0 (2.4)
Other, including changes in noncurrent assets and liabilities 95.9 47.9
----------- -----------
Net cash provided by operating activities of continuing operations 603.6 404.1
Net cash provided by operating activities of discontinued operations 11.5 64.8
----------- -----------
Net cash provided by operating activities 615.1 468.9
----------- -----------
FINANCING ACTIVITIES:
Payments of notes payable (3.3) (892.8)
Proceeds from long-term debt -- 1,776.5
Payments of long-term debt (2,217.0) (919.3)
Proceeds from issuance of common stock 11.9 .1
Dividends paid (10.4) (42.9)
Repurchase of preferred stock -- (275.0)
Payments of debt issuance costs (20.4) (54.9)
Premiums paid on tender offer and early debt retirement (79.5) --
Payments/dividends to minority interests (5.2) (.7)
Changes in restricted cash 16.9 62.2
Changes in cash overdrafts (27.4) (25.9)
Other - net (3.1) (.1)
----------- -----------
Net cash used by financing activities of continuing operations (2,337.5) (372.8)
Net cash used by financing activities of discontinued operations (1.2) (93.1)
----------- -----------
Net cash used by financing activities (2,338.7) (465.9)
----------- -----------
INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures (329.0) (449.8)
Proceeds from dispositions 3.0 467.9
Purchases of investments/advances to affiliates (1.6) (13.3)
Purchases of restricted investments (471.8) (463.3)
Proceeds from sales of businesses 306.0 1,943.6
Proceeds from sale of restricted investments 851.4 --
Proceeds from dispositions of investments and other assets 85.2 33.3
Other - net (6.7) (3.5)
----------- -----------
Net cash provided by investing activities of continuing operations 436.5 1,514.9
Net cash used by investing activities of discontinued operations (.8) (24.2)
----------- -----------
Net cash provided by investing activities 435.7 1,490.7
----------- -----------
Increase (decrease) in cash and cash equivalents (1,287.9) 1,493.7
Cash and cash equivalents at beginning of period** 2,318.2 1,736.0
----------- -----------
Cash and cash equivalents at end of period** $ 1,030.3 $ 3,229.7
=========== ===========
* Certain amounts have been reclassified as described in Note 2 of Notes to
Consolidated Financial Statements.
** Includes cash and cash equivalents of discontinued operations of $2.5
million, $2.6 million and $85.6 million at December 31, 2003, June 30, 2003
and December 31, 2002, respectively.
See accompanying notes.
99.5-3
The Williams Companies, Inc.
Notes to Consolidated Financial Statements
(Unaudited)
1. GENERAL
Company overview and outlook
In February 2003, we outlined our planned business strategy in response to
the events that significantly impacted the energy sector and our company during
late 2001 and much of 2002, including the collapse of Enron and the severe
decline of the telecommunications industry. The plan focused on migrating to an
integrated natural gas business comprised of a strong, but smaller, portfolio of
natural gas businesses; reducing debt; and increasing our liquidity through
asset sales, strategic levels of financing and reductions in operating costs.
The plan was designed to address near-term and medium-term debt and liquidity
issues, to de-leverage the company with the objective of returning to investment
grade status and to develop a balance sheet and cash flows capable of supporting
and ultimately growing our remaining businesses.
As discussed in our Annual Report on Form 10-K for the year ended December
31, 2003, we successfully executed certain critical components of our plan
during 2003. Key execution steps for 2004 and beyond included the completion of
planned asset sales; additional reductions of our selling, general and
administrative (SG&A) costs; the replacement of our cash-collateralized letter
of credit and revolver facility with facilities that do not encumber cash; and
continuation of efforts to exit from the Power business (see below).
Asset sales during 2004 were initially expected to generate proceeds of
approximately $800 million. In first-quarter 2004, we completed the sale of our
Alaska refinery and related assets for approximately $304 million. On July 28,
2004, we completed the sale of three straddle plants in western Canada for
approximately $536 million (see Note 6). In addition to these transactions, we
currently expect to generate additional proceeds from the sale of assets of
approximately $50 to $100 million.
In April 2004, we entered into two new unsecured credit facilities totaling
$500 million, which will be used primarily for issuing letters of credit. During
April 2004, use of these new facilities released approximately $500 million of
restricted cash, restricted investments and margin deposits (see Note 12). Also,
on May 3, 2004, we entered into a new three-year $1 billion secured revolving
credit facility. The revolving credit facility is secured by certain Midstream
assets and a guarantee from Williams Gas Pipeline Company, LLC. (WGP) (see Note
12).
In May 2004, we made cash tender offers for approximately $1.34 billion
aggregate principal amount of a specified series of our outstanding notes and
debentures. As of the June 8, 2004, tender offer expiration date, we had
accepted for purchase $1.17 billion of the notes for purchase (see Note 12). In
May 2004, we also repurchased debt of approximately $255 million of various
maturities on the open market. Our repurchase of these notes served to decrease
debt and will result in reduced annual interest expense.
Power Business Status
Since mid-2002, we have been pursuing a strategy of exiting the Power
business and have worked with financial advisors to assist with this effort. To
date, several factors have contributed to the difficulty of achieving a complete
exit from this business, including the following with respect to the wholesale
power industry:
o oversupply position in most markets expected through the balance of
the decade;
o slow North American gas supply response to high gas prices; and
o expectations of hybrid regulated/deregulated market structure for
several years.
As a result of these factors and the size of our Power business, the number
of financially viable parties expressing an interest in purchasing the entire
business has been limited. Additionally, the current and near term view of the
wholesale power market, which we interpret as depressed, has strongly influenced
these parties' view of value and related risk associated with this business.
99.5-4
Notes (Continued)
Because market conditions may change, and we cannot determine the impact of
this on a buyer's point of view, amounts ultimately received in any portfolio
sale, contract liquidation or realization may be significantly different from
the estimated economic value or carrying values reflected in the Consolidated
Balance Sheet. In addition, our tolling agreements are not derivatives and thus
have no carrying value in the Consolidated Balance Sheet pursuant to the
application of Emerging Issues Task Force (EITF) Issue No. 02-3, "Issues Related
to Accounting for Contracts Involved in Energy Trading and Risk Management
Activities" (EITF 02-3). Based on current market conditions, certain of these
agreements are forecasted to realize significant future losses. It is possible
that we may sell contracts for less than their carrying value or enter into
agreements to terminate certain obligations, either of which could result in
significant future loss recognition or reductions of future cash flows.
We continue to evaluate alternatives and discuss our plans and operating
strategy for the Power business with our Board of Directors. As an alternative
to continuing a plan of pursuing a complete exit from the Power business, we are
evaluating whether the benefits of realizing the positive cash flows expected to
be generated by this business through continued ownership exceed the benefits of
a sale at a depressed price. If we pursue this alternative, we expect to
continue our current program of managing this business to minimize financial
risk, generate cash and manage existing contractual commitments.
Other
Our accompanying interim consolidated financial statements do not include
all the notes in our annual financial statements and, therefore, should be read
in conjunction with the consolidated financial statements and notes thereto in
our Annual Report on Form 10-K, as restated and amended. The accompanying
unaudited financial statements include all normal recurring adjustments and
others, including asset impairments, loss accruals, and the change in accounting
principles which, in the opinion of our management, are necessary to present
fairly our financial position at June 30, 2004, and results of operations for
the three and six months ended June 30, 2004 and 2003 and cash flows for the six
months ended June 30, 2004 and 2003.
During the second quarter of 2003, we corrected the accounting treatment
previously applied to certain third-party derivative contracts during 2002 and
2001. We previously disclosed this in our Form 10-Q for the second quarter of
2003 and in our Form 10-K for the year ended December 31, 2003. Results through
June 30, 2003, include $106.8 million of revenue attributable to prior periods.
Our management, after consultation with our independent auditor, concluded that
the effect of the previous accounting treatment was not material to 2003 and
earlier periods and the trend of earnings.
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires management to make
estimates and assumptions that affect the amounts reported in the consolidated
financial statements and accompanying notes. Actual results could differ from
those estimates.
2. BASIS OF PRESENTATION
In accordance with the provisions related to discontinued operations within
Statement of Financial Accounting Standards (SFAS) No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets," the accompanying consolidated
financial statements and notes reflect the results of operations, financial
position and cash flows of certain components as discontinued operations (see
Note 6).
During second-quarter 2004, our Board of Directors approved a plan
authorizing management to negotiate and facilitate a sale of our straddle plants
in western Canada, which were part of the Midstream segment. As a result, these
assets and their related income and cash flows are now reported as discontinued
operations. In addition, the following components are included as discontinued
operations:
o retail travel centers concentrated in the Midsouth, part of the
previously reported Petroleum Services segment;
o refining and marketing operations in the Midsouth, including the
Midsouth refinery, part of the previously reported Petroleum Services
segment;
o Texas Gas Transmission Corporation, previously one of Gas Pipeline's
segments;
o natural gas properties in the Hugoton and Raton basins, previously
part of the Exploration & Production segment;
99.5-5
Notes (Continued)
o bio-energy operations, part of the previously reported Petroleum
Services segment;
o our general partnership interest and limited partner investment in
Williams Energy Partners, previously the Williams Energy Partners
segment;
o the Colorado soda ash mining operations, part of the previously
reported International segment;
o certain gas processing, natural gas liquids fractionation, storage
and distribution operations in western Canada and at a plant in
Redwater, Alberta, previously part of the Midstream segment;
o refining, retail and pipeline operations in Alaska, part of the
previously reported Petroleum Services segment; and
o Gulf Liquids New River Project LLC, previously part of the Midstream
segment.
Unless indicated otherwise, the information in the Notes to the Consolidated
Financial Statements relates to our continuing operations. Other components of
our business may be classified as discontinued operations in the future as those
operations are sold or classified as held-for-sale.
We have restated all segment information in the Notes to Consolidated
Financial Statements for the prior periods presented to reflect the discontinued
operations noted above. Certain other statement of operations, balance sheet and
cash flow amounts have been reclassified to conform to the current
classifications.
3. CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLES
Energy commodity risk management and trading activities and revenues
Effective January 1, 2003, we adopted EITF 02-3. As a result of initial
application of this Issue, we reduced net income by $762.5 million (net of a
$471.4 million benefit for income taxes) in first-quarter 2003. Approximately
$755 million of the reduction in net income relates to Power, with the remainder
relating to Midstream. The reduction of net income is reported as a cumulative
effect of a change in accounting principle. The change resulted primarily from
power tolling, load serving, transportation and storage contracts not meeting
the definition of a derivative and no longer being reported at fair value.
Asset retirement obligations
Effective January 1, 2003, we also adopted SFAS No. 143, "Accounting for
Asset Retirement Obligations." As required by the new standard, we recorded
liabilities equal to the present value of expected future asset retirement
obligations at January 1, 2003. As a result of the adoption of SFAS No. 143, we
recorded a credit to earnings of $1.2 million (net of a $.1 million provision
for income taxes) reflected as a cumulative effect of a change in accounting
principle. In connection with adoption of SFAS No. 143, we changed our method of
accounting to include salvage value of equipment related to producing wells in
the calculation of depreciation. The impact of this change is included in the
effect of adoption.
99.5-6
Notes (Continued)
4. ASSET SALES, IMPAIRMENTS AND OTHER ACCRUALS
Significant gains or losses from asset sales, impairments and other accruals
included in other (income) expense - net within segment costs and expenses and
investing income (loss) are included in the following tables.
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
-------------------------- -----------------------
2004 2003 2004 2003
---------- ---------- ---------- ---------
(MILLIONS) (MILLIONS)
OTHER (INCOME) EXPENSE-NET:
POWER
Gain on sale of Jackson power contract................................... $ -- $ (175.0) $ -- $ (175.0)
Commodity Futures Trading Commission settlement (see Note 13) ........... -- 20.0 -- 20.0
GAS PIPELINE
Write-off of software development costs due to cancelled implementation.. -- 25.5 -- 25.5
Write-off of previously-capitalized costs................................ 9.0 -- 9.0 --
EXPLORATION & PRODUCTION
Net gain on sale of natural gas properties............................... -- (91.5) -- (91.5)
Loss provision related to an ownership dispute........................... 11.3 -- 11.3 --
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
-------------------------- -----------------------
2004 2003 2004 2003
---------- ---------- ---------- ---------
(MILLIONS) (MILLIONS)
INVESTING INCOME (LOSS):
POWER
Impairment of Aux Sable investment........................................ $ -- $ (8.5) $ -- $ (8.5)
OTHER
Impairment of cost-based investment....................................... -- (13.5) -- (13.5)
Longhorn Partners Pipeline, L.P.
Impairment of investment................................................ (10.8) (42.4) (10.8) (42.4)
Net unreimbursed Longhorn recapitalization advisory fees................ -- -- (6.5) --
Impairment of Algar Telecom S.A. investment............................... (1.1) -- (1.1) (12.0)
5. PROVISION (BENEFIT) FOR INCOME TAXES
The provision (benefit) for income taxes from continuing operations
includes:
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
---------------------- ---------------------
2004 2003 2004 2003
-------- -------- -------- --------
(MILLIONS) (MILLIONS)
Current:
Federal....................................... $ .1 $ 6.2 $ 3.3 $ 12.5
State......................................... 2.6 8.5 4.4 13.2
Foreign....................................... 3.3 8.2 5.8 8.2
-------- -------- -------- --------
6.0 22.9 13.5 33.9
Deferred:
Federal....................................... (13.0) 103.2 (13.6) 86.6
State......................................... (12.6) (2.1) (10.5) (5.1)
Foreign....................................... 2.3 1.9 4.6 (1.9)
-------- -------- -------- --------
(23.3) 103.0 (19.5) 79.6
-------- -------- -------- --------
Total provision (benefit) ...................... $ (17.3) $ 125.9 $ (6.0) $ 113.5
======== ======== ======== ========
99.5-7
Notes (Continued)
The effective income tax rate benefit for the three months ended June 30,
2004, is greater than the federal statutory rate due primarily to the effect of
state income taxes partially offset by net foreign operations and an accrual for
income tax contingencies.
The effective income tax rate benefit for the six months ended June 30,
2004, is less than the federal statutory rate due primarily to net foreign
operations and an accrual for income tax contingencies partially offset by the
effect of state income taxes.
The effective income tax rate for the three and six months ended June 30,
2003, is greater than the federal statutory rate due primarily to the financial
impairment of certain investments, capital losses generated for which valuation
allowances were established, nondeductible expenses and an accrual for income
tax contingencies.
6. DISCONTINUED OPERATIONS
During 2002, we began the process of selling assets and/or businesses to
address liquidity issues. The businesses discussed below represent components
that have been sold or approved for sale by our Board of Directors as of June
30, 2004; therefore, their results of operations (including any impairments,
gains or losses), financial position and cash flows have been reflected in the
consolidated financial statements and notes as discontinued operations.
SUMMARIZED RESULTS OF DISCONTINUED OPERATIONS
The following table presents the summarized results of discontinued
operations for the three and six months ended June 30, 2004 and June 30, 2003.
Income from discontinued operations before income taxes for the six months ended
June 30, 2004 includes a first-quarter charge of $17.4 million to increase our
accrued liability associated with certain Quality Bank litigation matters (see
Note 13).
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
--------------------- -----------------------
2004 2003 2004 2003
------- -------- -------- ----------
(MILLIONS) (MILLIONS)
Revenues......................................................... $ 45.3 $ 628.4 $ 339.6 $ 1,846.3
======= ======== ======== ==========
Income (loss) from discontinued operations before income taxes... (2.9) 22.6 8.2 119.4
(Impairments) and gain (loss) on sales - net..................... .1 232.9 7.0 115.6
Benefit (provision) for income taxes............................. 2.6 (99.5) (4.0) (89.1)
------- -------- -------- ----------
Income (loss) from discontinued operations....................... $ (.2) $ 156.0 $ 11.2 $ 145.9
======= ======== ======== ==========
SUMMARIZED ASSETS AND LIABILITIES OF DISCONTINUED OPERATIONS
The following table presents the summarized assets and liabilities of
discontinued operations as of June 30, 2004 and December 31, 2003. The December
31, 2003 balances include the assets and liabilities of the Canadian straddle
plants, the Gulf Liquids New River Project LLC (Gulf Liquids) and the Alaska
refining, retail and pipeline operations. The June 30, 2004 balances include the
Canadian straddle plants, Gulf Liquids and certain remaining working capital
amounts of the Alaska refining, retail and pipeline operations. The assets and
liabilities from discontinued operations are reflected on the Consolidated
Balance Sheet as current beginning in the period they are both approved for sale
and expected to be sold within twelve months.
JUNE 30, DECEMBER 31,
2004 2003
-------- ---------
(MILLIONS)
Total current assets.................................. $ 46.6 $ 175.4
-------- ---------
Property, plant and equipment - net..................... 386.6 609.0
Other non-current assets................................ 1.6 2.0
-------- ---------
Total non-current assets.............................. 388.2 611.0
-------- ---------
Total assets......................................... $ 434.8 $ 786.4
======== =========
Long-term debt due within one year...................... -- 1.2
Other current liabilities............................... 23.4 81.5
-------- ---------
Total current liabilities............................. $ 23.4 $ 82.7
-------- ---------
Long-term debt.......................................... -- .3
Other non-current liabilities........................... .9 12.7
-------- ---------
Total non-current liabilities......................... .9 13.0
-------- ---------
Total liabilities.................................... $ 24.3 $ 95.7
======== =========
99.5-8
Notes (Continued)
HELD FOR SALE AT JUNE 30, 2004
Canadian straddle plants
During second-quarter 2004, our Board of Directors approved a plan to
negotiate and facilitate the sale of our three natural gas liquid extraction
plants (straddle plants) in western Canada. On July 28, 2004, we closed the sale
of these facilities for approximately $536 million in U.S. funds. We expect to
recognize a pre-tax gain of approximately $190 million on the sale in
third-quarter 2004. These assets were previously written down to estimated fair
value, resulting in a $36.8 million impairment in fourth-quarter 2002 and an
additional $41.7 million impairment in fourth-quarter 2003. In 2004, the fair
value of the assets increased substantially due primarily to renegotiation of
certain customer contracts and a general improvement in the market for
processing assets. These operations were part of the Midstream segment.
Gulf Liquids New River Project LLC
During second-quarter 2003, our Board of Directors approved a plan
authorizing management to negotiate and facilitate a sale of the assets of Gulf
Liquids. The Gulf Liquids assets were written down to their estimated fair value
less cost to sell resulting in a second-quarter 2003 impairment charge of $92.6
million, which is included in (impairments) and gain (loss) on sales in the
preceding table of summarized results of discontinued operations. We estimated
fair value based on a probability-weighted analysis of various scenarios,
including expected sales prices, discounted cash flows and salvage valuations.
During first-quarter 2004, we initiated a second bid process and expect the sale
of these operations to be completed in the second half of 2004. These operations
were part of the Midstream segment.
Winterthur International Insurance Company (Winterthur) issued policies to
Gulf Liquids providing financial assurance related to construction contracts
among Gulf Liquids, Gulsby Engineering, Inc. and Gulsby-Bay. After disputes
arose regarding obligations under the construction contracts, Winterthur
disputed coverage resulting in arbitration between Winterthur and Gulf Liquids.
In July 2004, the arbitration panel awarded Gulf Liquids $93.6 million, offset
by $18 million previously paid to Gulf Liquids, plus interest of $7.7 million,
for a total award to Gulf Liquids of approximately $83.3 million. Winterthur has
filed a Petition to Vacate the Arbitration Award in the New York State court.
Because the final outcome of the arbitration is uncertain, we have not
recognized the award in the consolidated financial statements.
2004 COMPLETED TRANSACTIONS
Alaska refining, retail and pipeline operations
On March 31, 2004, we completed the sale of our Alaska refinery, retail and
pipeline and related assets for approximately $304 million, subject to closing
adjustments for items such as the value of petroleum inventories. We received
$279 million in cash at the time of sale and $25 million in cash during the
second quarter of 2004. Throughout the sales negotiation process, we regularly
reassessed the estimated fair value of these assets based on information
obtained from the sales negotiations using a probability-weighted approach. We
recognized a $3.6 million gain on the sale during first-quarter 2004. The gain
and an $8 million first-quarter 2003 impairment charge are included in
(impairments) and gain (loss) on sales in the preceding table of summarized
results of discontinued operations. These operations were part of the previously
reported Petroleum Services segment.
2003 COMPLETED TRANSACTIONS
Canadian liquids operations
During the third quarter of 2003, we completed the sale of certain gas
processing, natural gas liquids fractionation, storage and distribution
operations in western Canada and at our Redwater, Alberta plant for total
proceeds of $246 million in cash. These operations were part of the Midstream
segment.
99.5-9
Notes (Continued)
Soda ash operations
On September 9, 2003, we completed the sale of our soda ash mining facility
located in Colorado. During 2003, ongoing sale negotiations continued to provide
new information regarding estimated fair value, and, as a result, the carrying
value of these assets was adjusted periodically as necessary. We recognized
impairment charges of $5 million and $11.1 million during the first and second
quarters of 2003, respectively. These impairments are included in (impairments)
and gain (loss) on sales in the preceding table of summarized results of
discontinued operations. The soda ash operations were part of the previously
reported International segment.
Williams Energy Partners
On June 17, 2003, we completed the sale of our 100 percent general
partnership interest and 54.6 percent limited partner investment in Williams
Energy Partners for approximately $512 million in cash and assumption by the
purchasers of $570 million in debt. In December 2003, we received additional
cash proceeds of $20 million following the occurrence of a contingent event. In
second-quarter 2003 we recognized a gain on sale of $275.6 million which is
included in (impairments) and gain (loss) on sales in the preceding table of
summarized results of discontinued operations and deferred an additional $113
million associated with certain environmental indemnifications we provided to
the purchasers under the sales agreement. In second-quarter 2004, we settled
these indemnifications with an agreement to pay $117.5 million over a four-year
period (see Note 11).
Bio-energy facilities
On May 30, 2003, we completed the sale of our bio-energy operations for
approximately $59 million in cash. During second-quarter 2003, we recognized a
loss on sale of $6.4 million, which is included in (impairments) and gain (loss)
on sales in the preceding table of summarized results of discontinued
operations. These operations were part of the previously reported Petroleum
Services segment.
Natural gas properties
On May 30, 2003, we completed the sale of natural gas exploration and
production properties in the Raton Basin in southern Colorado and the Hugoton
Embayment in southwestern Kansas. This sale included all of our interests within
these basins. During second-quarter 2003, we recognized a gain on sale of $39.9
million which is included in (impairments) and gain (loss) on sales in the
preceding table of summarized results of discontinued operations. These
properties were part of the Exploration & Production segment.
Texas Gas
On May 16, 2003, we completed the sale of Texas Gas Transmission Corporation
for $795 million in cash and the assumption by the purchaser of $250 million in
existing Texas Gas debt. There was no significant gain or loss recognized on the
sale. We recorded a $109 million impairment charge in first-quarter 2003
reflecting the excess of the carrying cost of the long-lived assets over our
estimate of fair value based on our assessment of the expected sales price
pursuant to the purchase and sale agreement. The impairment charge is included
in (impairments) and gain (loss) on sales in the preceding table of summarized
results of discontinued operations. Texas Gas was a segment within Gas Pipeline.
Midsouth refinery and related assets
On March 4, 2003, we completed the sale of our refinery and other related
operations located in Memphis, Tennessee for $455 million in cash. These assets
were previously written down to their estimated fair value less cost to sell at
December 31, 2002. We recognized a pre-tax gain on sale of $4.7 million in the
first quarter of 2003. During the second quarter of 2003, we recognized a $24.7
million gain on the sale of an earn-out agreement we retained in the sale of the
refinery. These gains are included in (impairments) and gain (loss) on sales in
the preceding table of summarized results of discontinued operations. These
operations were part of the previously reported Petroleum Services segment.
99.5-10
Notes (Continued)
Williams travel centers
On February 27, 2003, we completed the sale of our travel centers for
approximately $189 million in cash. We had previously written these assets down
to their estimated fair value to sell at December 31, 2002, and did not
recognize a significant gain or loss on the sale. These operations were part of
the previously reported Petroleum Services segment.
7. EARNINGS (LOSS) PER SHARE
Basic and diluted earnings (loss) per common share are computed as follows:
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------------- -------------------------
2004 2003 2004 2003
---------- ---------- ---------- ----------
(DOLLARS IN MILLIONS, (DOLLARS IN MILLIONS,
EXCEPT PER-SHARE EXCEPT PER-SHARE
AMOUNTS; SHARES IN AMOUNTS; SHARES IN
THOUSANDS) THOUSANDS)
Income (loss) from continuing operations ....................... $ (18.0) $ 113.7 $ (19.5) $ 70.6
Convertible preferred stock dividends .......................... -- (22.7) -- (29.5)
---------- ---------- ---------- ----------
Income (loss) from continuing operations available to common
stockholders for basic and diluted earnings per share ........ $ (18.0) $ 91.0 $ (19.5) $ 41.1
========== ========== ========== ==========
Basic weighted-average shares .................................. 521,698 518,090 520,592 517,872
Effect of dilutive securities:
Stock options ................................................ -- 3,889 -- 2,814
Deferred shares unvested ..................................... -- 2,567 -- 2,867
Convertible debentures ....................................... -- 10,293 -- --
---------- ---------- ---------- ----------
Diluted weighted-average shares ................................ 521,698 534,839 520,592 523,553
---------- ---------- ---------- ----------
Earnings (loss) per share from continuing operations:
Basic ........................................................ $ (.03) $ .18 $ (.04) $ .08
Diluted ...................................................... $ (.03) $ .17 $ (.04) $ .07
========== ========== ========== ==========
For the three and six months ended June 30, 2004, approximately 3.5 million
and 3.7 million weighted-average stock options, respectively, and approximately
2.8 million and 2.6 million weighted-average unvested deferred shares,
respectively, that otherwise would have been included, have been excluded from
the computation of diluted earnings per common share as their inclusion would be
antidilutive. The unvested deferred shares will vest over the period from July
2004 to January 2008.
In addition, for the three and six months ended June 30, 2004,
approximately 27.5 million weighted-average shares related to the assumed
conversion of convertible debentures, as well as the related interest, have been
excluded from the computation of diluted earnings per common share as their
inclusion would be antidilutive. If no other components used to calculate
diluted earnings per share (EPS) change, we estimate the assumed conversion of
the convertible debentures would become dilutive and therefore be included in
diluted EPS at an Income from continuing operations amount of $48.8 million and
$97.4 million for the three and six months ended June 30, 2004, respectively.
Approximately 9.4 million options to purchase shares of common stock with a
weighted-average exercise price of $27.43 were outstanding at June 30, 2004, but
have been excluded from the computation of diluted earnings per share. Inclusion
of these shares would have been antidilutive, as the exercise prices of the
options exceeded the second-quarter weighted average market price of the common
shares of $11.03 for the three months ended June 30, 2004.
For the three and six months ended June 30, 2003, approximately 11.3
million and 13 million weighted-average shares, respectively, related to the
assumed conversion of 9 7/8 percent cumulative convertible preferred stock have
been excluded from the computation of diluted earnings per common share as their
inclusion would be antidilutive. The preferred stock was redeemed in June 2003.
99.5-11
Notes (Continued)
For the six months ended June 30, 2003, approximately 5.2 million
weighted-average shares related to the assumed conversion of convertible
debentures, as well as the related interest, were excluded from the computation
of diluted earnings per common share as their inclusion would be antidilutive.
If no other components used to calculate diluted EPS change, we estimate the
assumed conversion of the convertible debentures would become dilutive and
therefore be included in diluted EPS at an Income from continuing operations
amount of $148.4 million.
8. EMPLOYEE BENEFIT PLANS
Net periodic pension and other postretirement benefit (income) expense for
the three and six months ended June 30, 2004 and 2003 is as follows:
PENSION BENEFITS
---------------------------------------------------
THREE MONTHS SIX MONTHS
ENDED JUNE 30, ENDED JUNE 30,
----------------------- -----------------------
2004 2003 2004 2003
--------- --------- --------- ---------
(MILLIONS) (MILLIONS)
Components of net periodic pension (income) expense:
Service cost ........................................... $ 5.1 $ 6.4 $ 12.1 $ 12.9
Interest cost .......................................... 10.7 13.2 25.2 26.6
Expected return on plan assets ......................... (17.5) (13.6) (32.4) (27.4)
Amortization of prior service credit ................... (.1) (.6) (.8) (1.2)
Recognized net actuarial loss .......................... .9 3.4 4.6 6.8
Regulatory asset amortization (deferral) ............... (.1) .1 1.0 .2
Settlement/curtailment (income) expense ................ .1 (.9) .1 .6
--------- --------- --------- ---------
Net periodic pension (income) expense .................. $ (.9) $ 8.0 $ 9.8 $ 18.5
========= ========= ========= =========
OTHER POSTRETIREMENT BENEFITS
---------------------------------------------------
THREE MONTHS SIX MONTHS
ENDED JUNE 30, ENDED JUNE 30,
----------------------- -----------------------
2004 2003 2004 2003
--------- --------- --------- ---------
(MILLIONS) (MILLIONS)
Components of net periodic postretirement benefit
(income) expense:
Service cost ........................................... $ .3 $ 1.5 $ 1.8 $ 3.2
Interest cost .......................................... 5.1 6.3 10.8 12.7
Expected return on plan assets ......................... (3.1) (3.3) (6.2) (6.8)
Amortization of transition obligation .................. .7 .7 1.3 1.4
Amortization of prior service cost ..................... .1 .1 .3 .3
Regulatory asset amortization .......................... 1.9 2.0 3.5 4.7
Settlement/curtailment (income) expense ................ -- (29.0) -- (29.0)
--------- --------- --------- ---------
Net periodic postretirement benefit (income) expense ... $ 5.0 $ (21.7) $ 11.5 $ (13.5)
========= ========= ========= =========
The $29 million settlement/curtailment income included in net periodic
postretirement (income) expense for the three and six months ended June 30,
2003, is included in income (loss) from discontinued operations in the
Consolidated Statement of Operations due to the settlement/curtailment directly
resulting from the sale of the operations included within discontinued
operations.
As previously disclosed in our Annual Report on Form 10-K for the year ended
December 31, 2003, we expected to contribute approximately $60 million to our
pension plans and approximately $15 million to our other postretirement benefit
plans in 2004. For the six months ended June 30, 2004, we contributed $16.5
million to our pension plans and $5.8 million to our other postretirement
benefit plans. We presently anticipate contributing approximately an additional
$44 million to fund our pension plans in 2004 for a total of approximately $61
million. We presently anticipate contributing approximately an additional $9
million to our other postretirement benefit plans in 2004 for a total of
approximately $15 million.
Net periodic pension income for the three months ended June 30, 2004
includes a favorable adjustment to reflect revised 2004 actuarial information.
The improvement results largely from a reduction in the number of employees and
higher than expected asset performance.
99.5-12
Notes (Continued)
In December 2003, the Medicare Prescription Drug, Improvement and
Modernization Act of 2003 (the Act) was signed into law. The Act introduces a
prescription drug benefit under Medicare (Medicare Part D) as well as a federal
subsidy to sponsors of retiree health care benefit plans that provide a benefit
that is at least actuarially equivalent to Medicare Part D. Our health care plan
for retirees includes prescription drug coverage. In accordance with FASB Staff
Position (FSP) No. FAS 106-1, "Accounting and Disclosure Requirements Related to
the Medicare Prescription Drug, Improvement and Modernization Act of 2003," the
provisions of the Act are not reflected in any measures of benefit obligations
or other postretirement benefit expense in the financial statements or
accompanying notes. In May 2004, the FASB issued FSP No. FAS 106-2, "Accounting
and Disclosure Requirements Related to the Medicare Prescription Drug,
Improvement and Modernization Act of 2003." This guidance is effective for us
beginning in third quarter 2004 and supersedes FSP No. FAS 106-1. We are
evaluating the impact of the Act on future obligations of the plan. If the plan
is determined to be actuarially equivalent and eligible for the subsidy, the
change in the obligation attributable to prior service will be deferred and
recognized over future periods beginning in third quarter 2004.
9. STOCK-BASED COMPENSATION
Employee stock-based awards are accounted for under Accounting
Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" (APB
25) and related interpretations. Fixed-plan common stock options generally do
not result in compensation expense because the exercise price of the stock
options equals the market price of the underlying stock on the date of grant.
The following table illustrates the effect on net income (loss) and earnings
(loss) per share if we had applied the fair value recognition provisions of SFAS
No. 123 "Accounting for Stock-Based Compensation."
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------------ ------------------------
2004 2003 2004 2003
---------- ---------- ---------- ----------
(MILLIONS) (MILLIONS)
Net income (loss), as reported ................................. $ (18.2) $ 269.7 $ (8.3) $ (544.8)
Add: Stock-based employee compensation included in the
Consolidated Statement of Operations, net of related tax
effects..................................................... 1.3 3.3 5.8 13.9
Deduct: Stock-based employee compensation expense determined
under fair value based method for all awards, net of related
tax effects .................................................. (3.2) (6.3) (10.7) (21.0)
---------- ---------- --------- ---------
Pro forma net income (loss) .................................... $ (20.1) $ 266.7 $ (13.2) $ (551.9)
========== ========== ========= =========
Earnings (loss) per share:
Basic-as reported ............................................ $ (.03) $ .48 $ (.02) $ (1.11)
Basic-pro forma .............................................. $ (.04) $ .47 $ (.03) $ (1.12)
Diluted-as reported .......................................... $ (.03) $ .46 $ (.02) $ (1.10)
Diluted-pro forma ............................................ $ (.04) $ .46 $ (.03) $ (1.11)
========== ========== ========== =========
Pro forma amounts for 2004 include compensation expense from awards of
our company stock made in 2004, 2003, 2002 and 2001. Also included in pro forma
expense for the three and six months ended June 30, 2004, is $700,000 and $1.7
million, respectively, of incremental expense associated with the stock option
exchange program described below. Pro forma amounts for 2003 include
compensation expense from awards made in 2003, 2002 and 2001.
Since compensation expense for stock options is recognized over the
future years' vesting period for pro forma disclosure purposes and additional
awards are generally made each year, pro forma amounts may not be representative
of future years' amounts.
On May 15, 2003, our shareholders approved a stock option exchange
program. Under this exchange program, eligible employees were given a one-time
opportunity to exchange certain outstanding options for a proportionately lesser
number of options at an exercise price to be determined at the grant date of the
new options. Surrendered options were cancelled June 26, 2003, and replacement
options were granted on December 29, 2003. We did not recognize any expense
pursuant to the stock option exchange. However, for purposes of pro forma
disclosures, we recognized additional expense related to these new options and
will amortize the remaining expense on the cancelled options through year-end
2004.
99.5-13
Notes (Continued)
10. INVENTORIES
Inventories at June 30, 2004 and December 31, 2003 are as follows:
JUNE 30, DECEMBER 31,
2004 2003
-------- -----------
(MILLIONS)
Finished goods:
Refined products............................. $ 15.8 $ 8.0
Natural gas liquids.......................... 60.1 40.4
-------- ---------
75.9 48.4
Natural gas in underground storage............. 116.8 132.5
Materials, supplies and other.................. 62.6 62.0
-------- ---------
$ 255.3 $ 242.9
======== =========
11. ACCRUED LIABILITIES AND OTHER LIABILITIES AND DEFERRED INCOME
On May 26, 2004, we were released from certain historical indemnities,
primarily related to environmental remediation, for an agreement to pay $117.5
million (see Note 13). We had previously deferred $113 million of a gain on sale
related to these indemnities. At the date of sale, the deferred revenue and
identified obligations related to the indemnities totaled $102 million. At June
30, 2004, the net present value of this settlement is $107.5 million. Of this
amount, $35 million is classified as current and was subsequently paid on July
1, 2004. The remaining amount will be paid in three installments of $27.5
million, $20 million, and $35 million in 2005, 2006, and 2007, respectively.
99.5-14
Notes (Continued)
12. DEBT AND BANKING ARRANGEMENTS
NOTES PAYABLE AND LONG-TERM DEBT
Notes payable and long-term debt at June 30, 2004 and December 31, 2003,
are as follows:
WEIGHTED-
AVERAGE
INTEREST JUNE 30, DECEMBER 31,
RATE (1) 2004 2003
----------- ----------- -----------
(MILLIONS)
Secured notes payable................................... --% $ -- $ 3.3
=========== ===========
Long-term debt:
Secured long-term debt
Notes, 6.62%-9.45%, payable through 2016............. 8.0% $ 231.7 $ 243.7
Notes, adjustable rate, payable through 2016......... 3.4% 594.9 602.5
Unsecured long-term debt
Debentures, 5.5%-10.25%, payable through 2033........ 7.1% 1,415.5 1,645.2
Notes, 6.125%-9.25%, payable through 2032 (2) ....... 7.7% 7,517.1 9,404.3
Other, payable through 2007........................... 6.0% .4 79.3
----------- -----------
9,759.6 11,975.0
Long-term debt due within one year...................... (276.6) (935.2)
----------- -----------
Total long-term debt.................................... $ 9,483.0 $ 11,039.8
=========== ===========
(1) At June 30, 2004.
(2) Includes $1.1 billion of 6.5 percent notes payable 2007, subject to
remarketing in November 2004, discussed below.
Long-term debt includes $1.1 billion of 6.5 percent notes, payable in 2007,
which are subject to remarketing in November 2004. These FELINE PACS include
equity forward contracts that require the holder to purchase shares of our
common stock in February 2005. If a remarketing is unsuccessful in 2004 and a
second remarketing in February 2005 is unsuccessful as defined in the offering
document for the FELINE PACS, then we could exercise our right to foreclose on
the notes in order to satisfy the obligation of the holders of the equity
forward contracts requiring the holder to purchase our common stock. This would
be a non-cash transaction. If either remarketing of the notes is successful, we
will receive the proceeds from the remarketing in February 2005 and issue stock
to the holders of the forward contracts.
On February 25, 2004, our Exploration & Production segment amended its $500
million secured variable rate note. The amendment reduced the floating interest
rate from the London InterBank Offered Rate (LIBOR) plus 3.75 percent to LIBOR
plus 2.5 percent. The amendment also extended the maturity date from May 30,
2007 to May 30, 2008. The amendment provides for an additional reduction in the
interest rate by 25 basis points, or 0.25 percent, if we meet certain
credit-rating requirements. The significant covenants were not altered by the
amendment.
In May 2004, we made cash tender offers for approximately $1.34 billion
aggregate principal amount of a specified series of our outstanding notes and
debentures. As of the June 8, 2004, tender offer expiration date, we had
accepted for purchase tenders of notes and debentures with an aggregate
principal amount of approximately $1.17 billion. Holders of notes and debentures
tendered by the early tender expiration date received an early tender payment
premium of $30.00 per $1,000.00 principal amount of notes and debentures. In May
2004, we also repurchased approximately $255 million of various notes with
maturity dates ranging from 2006 to 2011. In conjunction with these tendered
notes and debentures and related consents, and early retirements, we paid
premiums of approximately $79 million. The premiums, as well as related fees and
expenses, together totaling approximately $96.8 million, were recorded in
second-quarter 2004 as early debt retirement costs.
99.5-15
Notes (Continued)
On July 20, 2004, Wilpro Energy Services (PIGAP II) Limited, one of our
subsidiaries, received a notice of default from the Venezuelan state oil
company, PDVSA, relating to certain operational issues alleging that our
subsidiary is not in compliance under a services agreement. We do not believe a
basis exists for such notice and are contesting the giving of this notice.
Although this notice of default could result in an event of default with respect
to project loans totaling approximately $219 million and could result in an
adverse effect with respect to other of our debt instruments, we believe that we
will be able to resolve any issues arising from the alleged notice of default
without any such results occurring with respect to our other debt instruments.
The lenders under the project loan agreement have confirmed to us in writing
that based on the facts they currently know, they have no intention of
exercising any rights or remedies under the project loan agreement until the
issues raised in the notice and our response are clarified.
We are required by certain foreign lenders to ensure that the interest
rates received by them under various loan agreements are not reduced by taxes by
providing for the reimbursement of any domestic taxes required to be paid by the
foreign lender. The maximum potential amount of future payments under these
indemnifications is based on the related borrowings, generally continue
indefinitely unless limited by the underlying tax regulations, and have no
carrying value. We have never been called upon to perform under these
indemnifications.
Revolving credit and letter of credit facilities
In April 2004, we entered into two unsecured bank revolving credit
facilities totaling $500 million. These facilities provide for both borrowings
and issuing letters of credit, but are used primarily for issuing letters of
credit. At June 30, 2004, letters of credit totaling $489 million have been
issued by the participating financial institution under this facility and no
revolving credit loans were outstanding. We are required to pay to the bank
fixed fees at a weighted-average rate of 3.64 percent on the total committed
amount of the facilities. In addition, we pay interest on any borrowings at a
fluctuating rate comprised of either a base rate or LIBOR. We were able to
obtain the unsecured credit facilities because the funding bank syndicated its
associated credit risk into the institutional investor market via a 144A
offering, which allows for the resale of certain restricted securities to
qualified institutional buyers. Upon the occurrence of certain credit events,
letters of credit outstanding under the agreement become cash collateralized
creating a borrowing under the facilities. Concurrently the bank can deliver the
facilities to the institutional investors, whereby the investors replace the
bank as lender under the facilities. Upon such occurrence, we will pay:
- a fixed facility fee at a weighted average rate of 3.19
percent to the investors,
- interest on borrowings under the $400 million facility equal
to a fixed rate of 3.57 percent, and
- interest on borrowings under the $100 million facility at a
fluctuating LIBOR interest rate.
To facilitate the syndication of these facilities, the bank established
trusts funded by the institutional investors. The assets of the trusts serve as
collateral to reimburse the bank for our borrowings in the event the facilities
are delivered to the investors. Thus, we have no asset securitization or
collateral requirements under the new facilities. During second-quarter 2004,
use of these new facilities replaced existing facilities and released
approximately $500 million of restricted cash, restricted investments and margin
deposits which secured our previous $800 million revolving and letter of credit
facility. Significant covenants under these new facilities include the
following:
- limitations on certain payments, including a limitation on the
payment of quarterly dividends to no greater than $.05 per
common share (however, we are limited to $.02 per common share
under a more restrictive covenant contained in our $800
million 8.625 percent senior unsecured notes);
- limitations on asset sales;
- limitations on the use of proceeds from permitted asset sales;
- limitations on transactions with affiliates; and
- limitations on the incurrence of additional indebtedness and
issuance of disqualified stock, unless the fixed charge
coverage ratio for our most recently ended four full fiscal
quarters is at least 2 to 1, determined on a proforma basis.
99.5-16
Notes (Continued)
On May 3, 2004, we entered into a new three-year, $1 billion secured
revolving credit facility which is available for borrowings and letters of
credit. At June 30, 2004, letters of credit totaling $181 million have been
issued by the participating institutions under this facility and no revolving
credit loans were outstanding. We also have a commitment from our agent bank to
expand our credit facility by an additional $275 million. Northwest Pipeline
Corporation (Northwest) and Transcontinental Gas Pipeline Corporation (Transco)
have access to $400 million each under the facility. The new facility is secured
by certain Midstream assets, including substantially all of our southwest
Wyoming, Wamsutter, San Juan Conventional, Manzanares and Torre Alta systems.
Additionally, the facility is guaranteed by WGP. Interest is calculated based on
a choice of two methods: a fluctuating rate equal to the facilitating bank's
base rate plus an applicable margin or a periodic fixed rate equal to LIBOR plus
an applicable margin. We are also required to pay a commitment fee based on the
unused portion of the facility, currently .375 percent. The applicable margins
and commitment fee are based on the relevant borrower's senior unsecured
long-term debt ratings. Significant financial covenants under the credit
agreement include:
- ratio of debt to capitalization no greater than (i) 75 percent for
the period June 30, 2004 through December 31, 2004, (ii) 70 percent
for the period after December 31, 2004 through December 31, 2005,
and (iii) 65 percent for the remaining term of the agreement;
- ratio of debt to capitalization no greater than 55 percent for
Northwest and Transco; and
- ratio of EBITDA to Interest, on a rolling four quarter basis (or, in
the first year, building up to a rolling four quarter basis), no
less than (i) 1.5 for the periods ending September 30, 2004 through
March 31, 2005, (ii) 2.0 for any period after March 31, 2005 through
December 31, 2005, and (iii) 2.5 for the remaining term of the
agreement.
Upon entering into the new $1 billion secured revolving credit facility on
May 3, 2004, we terminated the $800 million revolving and letter of credit
facility which we entered into in June 2003. Termination of the facility
resulted in a $3.8 million charge which is recorded in Interest accrued in the
Consolidated Statement of Operations.
Retirements
On March 15, 2004, we retired $679 million of senior, unsecured 9.25 percent
notes. The amount represented the outstanding balance subsequent to the
fourth-quarter 2003 tender which retired $721 million of the original $1.4
billion balance.
As previously discussed, in May 2004, we made cash tender offers for
approximately $1.34 billion aggregate principal amount of our specified series
of outstanding notes. We accepted for purchase tenders of notes and debentures
with an aggregate principal amount of approximately $1.17 billion. In May 2004,
we also repurchased approximately $255 million of various notes with maturity
dates ranging from 2006 to 2011.
A summary of significant retirements, payments, prepayments and tenders of
long-term debt for the six months ended June 30, 2004 is as follows:
PRINCIPAL
DUE DATE AMOUNT
---------- ----------
Issue/Terms
(MILLIONS)
9.25% senior unsecured notes 2004 $ 678.5
6.75% PATS 2006 370.3
6.5% unsecured notes 2006 251.4
6.25% unsecured debentures 2006 231.0
6.5% unsecured notes 2008 221.9
7.55% unsecured notes 2007 118.8
6.625% unsecured notes 2004 101.6
7.25% unsecured notes 2009 85.0
Long-term debt collateralized by certain receivables N/A 78.7
7.125% unsecured notes 2011 60.0
Various notes, 6.62% - 9.45% 2013-2016 12.0
Various notes, adjustable rate 2004-2016 7.6
99.5-17
Notes (Continued)
13. CONTINGENT LIABILITIES AND COMMITMENTS
RATE AND REGULATORY MATTERS AND RELATED LITIGATION
Our interstate pipeline subsidiaries have various regulatory
proceedings pending. As a result of rulings in certain of these proceedings, a
portion of the revenues of these subsidiaries has been collected subject to
refund. The natural gas pipeline subsidiaries have accrued approximately $7
million for potential refund as of June 30, 2004.
ISSUES RESULTING FROM CALIFORNIA ENERGY CRISIS
Power subsidiaries are engaged in power marketing in various geographic
areas, including California. Prices charged for power by us and other traders
and generators in California and other western states in 2000 and 2001 have been
challenged in various proceedings including those before the Federal Energy
Regulatory Commission (FERC). These challenges include refund proceedings,
California Independent System Operator (ISO) fines, summer 2002 90-day
contracts, investigations of alleged market manipulation including withholding,
gas indices and other gaming of the market, new long-term power sales to the
state of California that were subsequently challenged and civil litigation
relating to certain of these issues. We have entered into a settlement with the
State of California and others that has resolved each of these issues as to the
State, and in February 2004 we announced a settlement with certain California
utilities that resolves these issues as to such utilities. However, certain of
these issues remain open as to the FERC and other non-settling parties.
Refund proceedings
We and other suppliers of electricity in the California market are the
subject of refund proceedings before the FERC. In December 2000, the FERC issued
an order initiating the proceeding, which ultimately (by order dated June 19,
2001) established a refund methodology and set a refund period of October 2,
2000 to June 19, 2001. As a result of a hearing to determine refund liability
for the market participants, a FERC administrative law judge issued findings on
December 12, 2002, that estimated our refund obligation to the ISO at $192
million, excluding emissions costs and interest. The judge estimated that our
refund obligation to the California Power Exchange (PX) was $21.5 million,
excluding interest. However, the judge estimated that the ISO owes us $246.8
million, excluding interest, and that the PX owes us $17.4 million, excluding
interest, and $2.9 million in charge backs. The estimates did not include $17
million in emissions costs that the judge found we are entitled to use as an
offset to the refund liability, and the judge's refund estimates are not based
on final mitigated market clearing prices. On March 26, 2003, the FERC acted to
largely adopt the judge's order with a change to the gas methodology used to set
the clearing price. As a result, Power recorded a first-quarter 2003 charge for
refund obligations of $37 million. Net interest income related to amounts due
from the counterparties is approximately $31 million through June 30, 2004. On
October 16, 2003, the FERC issued an additional refund order granting rehearing
in part and denying rehearing in part. This order is not expected to have a
material effect on the refund calculation for us. However, pursuant to the
October 16 order, the ISO has been ordered to calculate refunds for the market.
This study is expected to be complete in 2004.
On February 25, 2004, we announced a settlement agreement with
California utilities, Southern California Edison and Pacific Gas & Electric
(PG&E), to resolve our refund liability to the utilities as well as all other
known disputes related to the California energy crisis of 2000 and 2001 (the
"Utility Settlement"). We recorded a charge of approximately $33 million in the
fourth quarter of 2003 associated with the terms of this settlement. San Diego
Gas and Electric also joined in the settlement as a party. The Utility
Settlement was filed with the FERC on April 27, 2004 and was approved by the
FERC on July 2, 2004 to be effective on July 12, 2004. While only these three
utilities were originally parties to the Utility Settlement with us, additional
parties have now opted in and the Utility Settlement includes funding for
refunds to all buyers in equal kind in the FERC refund period. Should any buyer
not opt into the Utility Settlement, the refund amount in the Utility Settlement
would be reduced and we would continue to litigate with that buyer regarding the
refund issue and amount. Pursuant to this settlement our outstanding receivables
for the period of approximately $261 million will be partially offset by our
settlement obligation of approximately $136 million. We have received $2 million
of our net receivable in the second quarter. During July, we received
approximately $104 million of our remaining net $123 million receivable.
Approximately the same amount of funds ($109 million) was used on June 24, 2004
to repurchase PG&E receivables previously sold to Bear Stearns. As for the $19
million receivable that remains at the end of July, $16 million is being held in
escrow until released by the FERC and $3 million is being held by the PX.
Approval by the FERC also resolved FERC investigations into physical and
economic withholding. The Utility Settlement also resolved any claims by the
settling parties regarding these issues.
99.5-18
Notes (Continued)
In a separate but related proceeding, certain entities have also asked
the FERC to revoke our authority to sell power from California-based generating
units at market-based rates, to limit us to cost-based rates for future sales
from such units and to order refunds of excessive rates, with interest,
retroactive to May 1, 2000, and possibly earlier. As a result of the Utility
Settlement, this issue is resolved and we will maintain all existing
authorities.
Although we have entered into a global settlement with the State of
California, certain California utilities, and various other parties that resolve
the refund issues among the settling parties, we have potential refund exposure
to non-settling parties (e.g., various California end users that have not agreed
to opt into the utility settlement). Therefore, we continue to participate in
the FERC refund case and related proceedings. Challenges to virtually every
aspect of the refund proceeding, including the refund period, are now pending at
the Ninth Circuit Court of Appeals. No schedule has yet been established for
hearing the appeals.
ISO fines
On July 3, 2002, the ISO announced fines against several energy
producers including us, for failure to deliver electricity during the period
December 2000 through May 2001. The ISO fined us $25.5 million during this
period, which was offset against our claims for payment from the ISO. These
amounts will be adjusted as part of the refund proceeding described above. As
the result of a settlement reached with the ISO pursuant to a FERC-approved
dispute resolution process contained in the ISO tariff, these fines will be
significantly reduced through the re-run of the market that takes place in the
refund proceeding.
Summer 2002 90-day contracts
On May 2, 2002, PacifiCorp filed a complaint with the FERC against
Power seeking relief from rates contained in three separate confirmation
agreements between PacifiCorp and Power (known as the Summer 2002 90-Day
Contracts). PacifiCorp filed similar complaints against three other suppliers.
PacifiCorp alleged that the rates contained in the contracts are unjust and
unreasonable. On June 26, 2003, the FERC affirmed the administrative law judge's
initial decision dismissing the complaints. PacifiCorp has appealed the FERC's
order to the United States Court of Appeals for the DC Circuit after the FERC
denied rehearing of its order on November 10, 2003.
Investigations of alleged market manipulation
As a result of various allegations and FERC Orders, in 2002 the FERC
initiated investigations of manipulation of the California gas and power
markets. As they related to us, these investigations included economic and
physical withholding, so-called "Enron Gaming Practices" and gas index
manipulation.
On February 13, 2002, the FERC issued an Order Directing Staff
Investigation commencing a proceeding titled Fact-Finding Investigation of
Potential Manipulation of Electric and Natural Gas Prices prior to the
California parties (who include the California Attorney General, the Electricity
Oversight Board, the Public Utilities Commission and two investor-owned
utilities) filing of their report. Through the investigation, the FERC intends
to determine whether "any entity, including Enron Corporation (Enron) (through
any of its affiliates or subsidiaries), manipulated short-term prices for
electric energy or natural gas in the West or otherwise exercised undue
influence over wholesale electric prices in the West since January 1, 2000,
resulting in potentially unjust and unreasonable rates in long-term power sales
contracts subsequently entered into by sellers in the West." On May 8, 2002, we
received data requests from the FERC related to a disclosure by Enron of certain
trading practices in which it may have been engaged in the California market. On
May 21, and May 22, 2002, the FERC supplemented the request inquiring as to
"wash" or "round-trip" transactions. We responded on May 22, 2002, May 31, 2002,
and June 5, 2002, to the data requests. On June 4, 2002, the FERC issued an
order to us to show cause why our market-based rate authority should not be
revoked as the FERC found that certain of our responses related to the Enron
trading practices constituted a failure to cooperate with the staff's
investigation. We subsequently supplemented our responses to address the show
cause order. On July 26, 2002, we received a letter from the FERC informing us
that it had reviewed all of our supplemental responses and concluded that we
responded to the initial May 8, 2002 request.
As also discussed below in REPORTING OF NATURAL GAS-RELATED INFORMATION
TO TRADE PUBLICATIONS, on November 8, 2002, we received a subpoena from a
federal grand jury in Northern California seeking documents related to our
involvement in California markets. We have completed our response to the
subpoena. This subpoena is a part of the broad United States Department of
Justice (DOJ) investigation regarding gas and power trading.
99.5-19
Notes (Continued)
Pursuant to an order from the Ninth Circuit, the FERC permitted certain
California parties to conduct additional discovery into market manipulation by
sellers in the California markets. The California parties sought this discovery
in order to potentially expand the scope of the refunds. On March 3, 2003, the
California parties submitted evidence from this discovery on market manipulation
("March 3rd Report"). We and other sellers submitted comments regarding the
additional evidence on March 20, 2003.
On March 26, 2003, the FERC issued a Staff Report addressing: (1) Enron
trading practices, (2) an allegation in a June 2, 2002 New York Times article
that we had attempted to corner the gas market, and (3) the allegations of gas
price index manipulation which are discussed in more detail below in REPORTING
OF NATURAL GAS-RELATED INFORMATION TO TRADE PUBLICATIONS. The Staff Report
cleared us on the issue of cornering the market and contemplated or established
further proceedings on the other two issues as to us and numerous other market
participants. On June 25, 2003, the FERC issued a series of orders in response
to the California parties' March 3rd Report and the Staff Report. These orders
resulted in further investigations regarding potential allegations of physical
withholding, economic withholding, and a show cause order alleging that various
companies engaged in Enron trading practices. On August 29, 2003, we entered
into a settlement with the FERC trial staff of all Enron trading practices for
approximately $45,000. The settlement was approved by the FERC on January 22,
2004. The investigations of physical and economic withholding are also
continuing. Each of these FERC investigations of alleged market manipulation are
resolved pursuant to the Utility Settlement that is discussed above in Refund
proceedings.
Long-term contracts
In February 2001, during the height of the California energy crisis, we
entered into a long-term power contract with the State of California to assist
in stabilizing its market. This contract was later challenged by the State of
California. This challenge resulted in settlement discussions being held between
the State and us on the contract issue as well as other state initiated
proceedings and allegations of market manipulation. A settlement was reached
that resulted in us entering into a settlement agreement with the State of
California and other non-Federal parties that includes renegotiated long-term
energy contracts. These contracts are made up of block energy sales,
dispatchable products and a gas contract. The settlement does not extend to
criminal matters or matters of willful fraud, but also resolved civil complaints
brought by the California Attorney General against us and the State of
California's refund claims that are discussed above. In addition, the settlement
resolved ongoing investigations by the States of California, Oregon and
Washington. The settlement was reduced to writing and executed on November 11,
2002. The settlement closed on December 31, 2002, after FERC issued an order
granting our motion for partial dismissal from the refund proceedings. The
dismissal affects our refund obligations to the settling parties, but not to
other parties, such as investor-owned utilities. Pursuant to the settlement, the
California Public Utilities Commission (CPUC) and California Electricity
Oversight Board (CEOB) filed a motion on January 13, 2003 to withdraw their
complaints against us regarding the original block energy sales contract. On
June 26, 2003, the FERC granted the CPUC and CEOB joint motion to withdraw their
respective complaints against us. Certain private class action and other civil
plaintiffs who have initiated class action litigation against us and others in
California based on allegations against us with respect to the California energy
crisis also executed the settlement. Final approval by the court is needed to
make the settlement effective as to plaintiffs and to terminate the class
actions as to us. The Court granted approval on June 29, 2004. Some litigation
by non-California plaintiffs, or relating to reporting of natural gas
information to trade publications, as discussed below, will continue. As of June
30, 2004, pursuant to the terms of the settlement, we have transferred ownership
of six LM6000 gas powered electric turbines, have made two payments totaling $72
million to the California Attorney General, and have funded a $15 million fee
and expense fund associated with civil actions that are subject to the
settlement. An additional $75 million remains to be paid to the California
Attorney General (or his designee) over the next six years, with the final
payment of $15 million due on January 1, 2010.
REPORTING OF NATURAL GAS-RELATED INFORMATION TO TRADE PUBLICATIONS
We disclosed on October 25, 2002, that certain of our natural gas
traders had reported inaccurate information to a trade publication that
published gas price indices. As noted above, on November 8, 2002, we received a
subpoena from a federal grand jury in Northern California seeking documents
related to our involvement in California markets, including our reporting to
trade publications for both gas and power transactions. We completed our
response to the subpoena. The DOJ's investigation into this matter is
continuing. In addition, the Commodity Futures Trading Commission (CFTC) has
conducted an investigation of us regarding this issue. On July 29, 2003, we
reached a settlement with the CFTC where in exchange for $20 million, the CFTC
closed its investigation and we did not admit or deny allegations that we had
engaged in false reporting or attempted manipulation. Civil suits based on
allegations of manipulating the gas indices have been brought against us and
others in Federal court in New York, Washington, Oregon and California and in
state court in California.
99.5-20
Notes (Continued)
Investigations related to natural gas storage inventory
We responded to a subpoena from the CFTC and inquiries from the FERC
related to natural gas storage inventory issues. We believe that these inquiries
are a part of an ongoing general industry-wide investigation. The inquiries
relate to the formal reporting of inventory levels, the sharing of non-public
data concerning inventory levels, and the potential uses of such data in natural
gas trading. Through some of our subsidiaries, we own and operate natural gas
storage facilities.
MOBILE BAY EXPANSION
On December 3, 2002, an administrative law judge at the FERC issued an
initial decision in Transco's general rate case which, among other things,
rejected the recovery of the costs of Transco's Mobile Bay expansion project
from its shippers on a "rolled-in" basis and found that incremental pricing for
the Mobile Bay expansion project is just and reasonable. The administrative law
judge's initial decision is subject to review by the FERC. On March 26, 2004,
the FERC issued an Order on Initial Decision in which it reversed the
administrative law judge's holding and accepted Transco's proposal for rolled in
rates. Power holds long-term transportation capacity on the Mobile Bay expansion
project. If the FERC had adopted the decision of the administrative law judge on
the pricing of the Mobile Bay expansion project and also required that the
decision be implemented effective September 1, 2001, Power could have been
subject to surcharges of approximately $50 million, excluding interest, through
June 30, 2004, in addition to increased costs going forward. On April 26, 2004,
several parties, including Transco filed requests for rehearing of the FERC's
March 26, 2004 order.
ENRON BANKRUPTCY
We have outstanding claims against Enron Corp. and various of its
subsidiaries (collectively "Enron") related to Enron's bankruptcy filed in
December 2001. In March 2002, we sold $100 million of our claims against Enron
to a third party for $24.5 million. On December 23, 2003, Enron filed objections
to these claims. Under the sales agreement, the purchaser of the claims may
demand repayment of the purchase price, plus interest assessed at 7.5 percent
per annum, for that portion of the claims still subject to objections 90 days
following the initial objection. To date, the purchaser has not demanded
repayment.
ENVIRONMENTAL MATTERS
Continuing operations
Since 1989, our Transco subsidiary has had studies under way to test
certain of its facilities for the presence of toxic and hazardous substances to
determine to what extent, if any, remediation may be necessary. Transco has
responded to data requests regarding such potential contamination of certain of
its sites. Transco has identified polychlorinated biphenyl (PCB) contamination
in compressor systems, soils and related properties at certain compressor
station sites. Transco has also been involved in negotiations with the U.S.
Environmental Protection Agency (EPA) and state agencies to develop screening,
sampling and cleanup programs. In addition, Transco commenced negotiations with
certain environmental authorities and other programs concerning investigative
and remedial actions relative to potential mercury contamination at certain gas
metering sites. The costs of any such remediation will depend upon the scope of
the remediation. At June 30, 2004, Transco had accrued liabilities of $27
million related to PCB contamination, potential mercury contamination, and other
toxic and hazardous substances.
We also accrued environmental remediation costs for our natural gas
gathering and processing facilities, primarily related to soil and groundwater
contamination. At June 30, 2004, we had accrued liabilities totaling
approximately $8 million for these costs.
Actual costs incurred for these matters will depend on the actual
number of contaminated sites identified, the amount and extent of contamination
discovered, the final cleanup standards mandated by the EPA and other
governmental authorities and other factors.
Former operations, including operations classified as discontinued
In connection with the sale of certain assets and businesses, we have
retained responsibility, through indemnification of the purchasers, for
environmental and other liabilities existing at the time the sale was
consummated.
99.5-21
Notes (Continued)
AGRICO
In connection with the 1987 sale of the assets of Agrico Chemical
Company, we agreed to indemnify the purchaser for environmental cleanup costs
resulting from certain conditions at specified locations; to the extent such
costs exceed a specified amount. At June 30, 2004, we had accrued liabilities of
approximately $10 million for such excess costs.
We are also in discussions with defendants involved in two class action
damages lawsuits involving this former chemical fertilizer business. We are not
a named defendant in the lawsuits, but have contractual obligations to
participate with the named defendants in the ongoing remediation. One named
defendant has filed a motion to compel us to participate in arbitration over the
contractual obligations.
WILLIAMS ENERGY PARTNERS
As part of our June 17, 2003 sale of Williams Energy Partners (see Note
6), we indemnified the purchaser for:
(1) environmental cleanup costs resulting from certain
conditions, primarily soil and groundwater contamination, at specified
locations, to the extent such costs exceed a specified amount and
(2) currently unidentified environmental contamination
relating to operations prior to April 2002 and identified prior to
April 2008.
On May 26, 2004, the parties reached an agreement for buyout of certain
indemnities in the form of a structured cash settlement totaling $117.5 million.
Yearly payments will be made through 2007. The agreement releases Williams from
all environmental indemnity obligations under the June 2003 Sale of Williams
Energy Partners and two related agreements. Williams is now indemnified by the
purchaser for third party environmental claims made against Williams for claims
covered under the June 2003 purchase and sale agreement (PSA) and related
agreements as well as all environmental occurrences before the closing date of
the PSA. The agreement also transferred most third party litigation matters
related to Williams Energy Partners' assets to the purchaser.
On July 2, 2001, the EPA issued an information request asking for
information on oil releases and discharges in any amount from our pipelines,
pipeline systems, and pipeline facilities used in the movement of oil or
petroleum products, during the period from July 1, 1998 through July 2, 2001. In
November 2001, we furnished our response. This matter has not become an
enforcement proceeding. On March 11, 2004, the Department of Justice (DOJ)
invited the new owner of the Williams Pipe Line, Magellan Midstream Partners,
L.P. (Magellan), to enter into negotiations regarding alleged violations of the
Clean Water Act and to sign a tolling agreement. No penalty has been assessed by
the EPA; however, the DOJ stated in its letter that the maximum possible
penalties were approximately $22 million for the alleged violations. It is
anticipated that by providing additional clarification and through negotiations
with the EPA and DOJ, that any proposed penalty will be reduced. All
environmental indemnity obligations to Magellan were released in the May 26,
2004 buyout agreement described above. Williams will participate in the EPA/DOJ
negotiations and respond to requests for information related to three release
events not related to Magellan-owned assets.
OTHER
At June 30, 2004, we had accrued environmental liabilities totaling
approximately $16 million related primarily to our:
- potential indemnification obligations to purchasers of our
former retail petroleum and refining operations;
- former propane marketing operations, petroleum products and
natural gas pipelines;
- a discontinued petroleum refining facility; and
- exploration and production and mining operations.
These costs include (1) certain conditions at specified locations
related primarily to soil and groundwater contamination and (2) any penalty
assessed on Williams Refining & Marketing, LLC (Williams Refining) associated
with noncompliance with EPA's benzene waste "NESHAP" regulations. In 2002,
Williams Refining submitted to the EPA a self-disclosure letter indicating
noncompliance with those regulations. This unintentional noncompliance had
occurred due to a regulatory interpretation that resulted in under-counting the
total annual benzene level at Williams Refining Memphis refinery. Also in 2002,
the EPA conducted an all-media audit of the Memphis refinery. The EPA
anticipates releasing a report of its audit findings in 2004. The EPA will
likely assess a penalty on Williams Refining due to the benzene waste NESHAP
issue, but the amount of any such penalty is not known. In connection with the
sale of the Memphis refinery in March 2003, we indemnified the purchaser for any
such penalty.
99.5-22
Notes (Continued)
We are a plaintiff in litigation involving the environmental
investigation and subsequent cleanup of our former retail petroleum and refining
operations. In April we received a court order to participate in mediation
before the end of June with the defendant to attempt to reach a settlement prior
to going to trial. Mediation occurred in June and discussions are ongoing.
Certain of our subsidiaries have been identified as potentially
responsible parties (PRP) at various Superfund and state waste disposal sites.
In addition, these subsidiaries have incurred, or are alleged to have incurred,
various other hazardous materials removal or remediation obligations under
environmental laws.
Summary of environmental matters
Actual costs incurred for these matters could be substantially greater
than amounts accrued depending on the actual number of contaminated sites
identified, the actual amount and extent of contamination discovered, the final
cleanup standards mandated by the EPA and other governmental authorities and
other factors.
OTHER LEGAL MATTERS
Royalty indemnifications
In connection with agreements to resolve take-or-pay and other contract
claims and to amend gas purchase contracts, Transco entered into certain
settlements with producers which may require the indemnification of certain
claims for additional royalties which the producers may be required to pay as a
result of such settlements. Transco, through its agent, Power, continues to
purchase gas under contracts which extend, in some cases, through the life of
the associated gas reserves. Certain of these contracts contain royalty
indemnification provisions that have no carrying value. Producers have received
and may receive other demands, which could result in claims pursuant to royalty
indemnification provisions. Indemnification for royalties will depend on, among
other things, the specific lease provisions between the producer and the lessor
and the terms of the agreement between the producer and Transco. Consequently,
the potential maximum future payments under such indemnification provisions
cannot be determined.
As a result of these settlements, Transco has been sued by certain
producers seeking indemnification from Transco. Transco is currently a defendant
in one lawsuit in which a producer has asserted damages, including interest
calculated through June 30, 2004, of approximately $10 million. On July 11,
2003, at the conclusion of the trial, the judge ruled in Transco's favor and
subsequently entered a formal judgment. The plaintiff is seeking an appeal.
Will Price (formerly Quinque)
On June 8, 2001, fourteen of our entities were named as defendants in a
nationwide class action lawsuit which had been pending against other defendants,
generally pipeline and gathering companies, for more than one year. The
plaintiffs allege that the defendants, including us, have engaged in
mismeasurement techniques that distort the heating content of natural gas,
resulting in an alleged underpayment of royalties to the class of producer
plaintiffs. After the court denied class action certification and while motions
to dismiss for lack of personal jurisdiction were pending, the court granted the
plaintiffs' motion to amend their petition on July 29, 2003. The fourth amended
petition, which was filed on July 29, 2003, deletes all of our defendants except
two Midstream subsidiaries. All defendants intend to continue their opposition
to class certification.
Grynberg
In 1998, the DOJ informed us that Jack Grynberg, an individual, had
filed claims on behalf of himself and the federal government, in the United
States District Court for the District of Colorado under the False Claims Act
against us and certain of our wholly owned subsidiaries. The claims sought an
unspecified amount of royalties allegedly not paid to the federal government,
treble damages, a civil penalty, attorneys' fees, and costs. In connection with
our sale of Kern River and Texas Gas, we agreed to indemnify the purchasers for
any liability relating to this claim, including legal fees. The maximum amount
of future payments that we could potentially be required to pay under these
indemnifications depends upon the ultimate resolution of the claim and cannot
currently be determined. The amounts accrued for these indemnifications are
insignificant. Grynberg has also filed claims against approximately 300 other
energy companies alleging that the defendants violated the False Claims Act in
connection with the measurement, royalty valuation and purchase of hydrocarbons.
On April 9, 1999, the DOJ announced that it was declining to intervene in any of
the Grynberg qui tam cases, including the action filed in federal court in
Colorado against us. On October 21, 1999, the Panel on Multi-District Litigation
transferred all of the Grynberg qui tam cases, including those filed against us,
to the federal court in Wyoming for pre-trial purposes. Grynberg's measurement
claims remain pending against us and the other defendants; the court previously
dismissed Grynberg's royalty valuation claims.
99.5-23
Notes (Continued)
On August 6, 2002, Jack J. Grynberg, and Celeste C. Grynberg, Trustee
on Behalf of the Rachel Susan Grynberg Trust, and the Stephen Mark Grynberg
Trust, served us and Williams Production RMT Company with a complaint in the
state court in Denver, Colorado. The complaint alleges that the defendants have
used mismeasurement techniques that distort the BTU heating content of natural
gas, resulting in the alleged underpayment of royalties to Grynberg and other
independent natural gas producers. The complaint also alleges that defendants
inappropriately took deductions from the gross value of their natural gas and
made other royalty valuation errors. Theories for relief include breach of
contract, breach of implied covenant of good faith and fair dealing,
anticipatory repudiation, declaratory relief, equitable accounting, civil theft,
deceptive trade practices, negligent misrepresentation, deceit based on fraud,
conversion, breach of fiduciary duty, and violations of the state racketeering
statute. Plaintiff is seeking actual damages of between $2 million and $20
million based on interest rate variations, and punitive damages in the amount of
approximately $1.4 million dollars. Our motion to stay the proceedings in this
case based on the pendency of the False Claims Act litigation discussed in the
preceding paragraph was granted on January 15, 2003.
Securities class actions
Numerous shareholder class action suits have been filed against us in
the United States District Court for the Northern District of Oklahoma. The
majority of the suits allege that we and co-defendants, WilTel Communications
(WilTel), previously an owned subsidiary known as Williams Communications, and
certain corporate officers, have acted jointly and separately to inflate the
stock price of both companies. Other suits allege similar causes of action
related to a public offering in early January 2002, known as the FELINE PACS
offering. These cases were filed against us, certain corporate officers, all
members of our Board of Directors and all of the offerings' underwriters. These
cases have all been consolidated and an order has been issued requiring separate
amended consolidated complaints by our equity holders and WilTel equity holders.
The underwriters of this offering have requested indemnification from these
cases. If granted, costs incurred as a result of these indemnifications will not
be covered by our insurance policies. The amended complaint of the WilTel
securities holders was filed on September 27, 2002, and the amended complaint of
our securities holders was filed on October 7, 2002. This amendment added
numerous claims related to Power. On April 2, 2004, the purported class of our
securities holders filed a partial motion for summary judgment with respect to
certain disclosures made in connection with our public offerings during the
class period.
In addition, four class action complaints have been filed against us,
the members of our Board of Directors and members of our Benefits and Investment
Committees under the Employee Retirement Income Security Act (ERISA) by
participants in our 401(k) plan. A motion to consolidate these suits has been
approved. On July 14, 2003, the Court dismissed us and our Board from the ERISA
suits, but not the members of the Benefits and Investment Committees to whom we
might have an indemnity obligation. If it is determined that we have an
indemnity obligation, we expect that any costs incurred will be covered by our
insurance policies. The Department of Labor is also independently investigating
our employee benefit plans. On May 3, 2004, plaintiffs requested permission to
amend their complaint to add additional Investment Committee members and to
again name the Board of Directors. That permission was granted June 7, 2004, and
a motion to dismiss was filed on behalf of the Board on July 15, 2004.
Derivative shareholder suits have been filed in state court in Oklahoma, all
based on similar allegations. On August 1, 2002, a motion to consolidate and a
motion to stay these Oklahoma suits pending action by the federal court in the
shareholder suits were approved.
Oklahoma securities investigation
On April 26, 2002, the Oklahoma Department of Securities issued an
order initiating an investigation of us and WilTel regarding issues associated
with the spin-off of WilTel and regarding the WilTel bankruptcy. We have no
pending inquiries in this investigation, but are committed to cooperate fully in
the investigation.
Shell offshore litigation
On November 30, 2001, Shell Offshore, Inc. filed a complaint at the
FERC against Williams Gas Processing - Gulf Coast Company, L.P. (WGPGCC),
Williams Gulf Coast Gathering Company (WGCGC), Williams Field Services Company
(WFS) and Transco, alleging concerted actions by the affiliates frustrating the
FERC's regulation of Transco. The alleged actions are related to offers of
gathering service by WFS and its subsidiaries on the deregulated North Padre
Island offshore gathering system. On September 5, 2002, the FERC issued an order
reasserting jurisdiction over that portion of the North Padre Island facilities
previously transferred to WFS. The FERC also determined an unbundled gathering
rate for service on these facilities which is to be collected by Transco.
Transco, WGPGCC, WGCGC and WFS believe their actions were reasonable and lawful
and each has filed petitions for review of the FERC's orders with the U.S. Court
of Appeals for the District of Columbia. On July 13, 2004, the Court of Appeals
reversed the FERC's decision, ruling that FERC's attempt to impose regulated
rates was without legal basis.
99.5-24
Notes (Continued)
TAPS Quality Bank
Williams Alaska Petroleum, Inc. (WAPI) is actively engaged in
administrative litigation being conducted jointly by the FERC and the Regulatory
Commission of Alaska (RCA) concerning the Trans-Alaska Pipeline System (TAPS)
Quality Bank. Primary issues being litigated include the appropriate valuation
of the naphtha, heavy distillate, vacuum gas oil and residual product cuts
within the TAPS Quality Bank as well as the appropriate retroactive effects of
the determinations. WAPI's interest in these proceedings is material as the
matter involves claims by crude producers and the State of Alaska for
retroactive payments plus interest of up to $181 million. Due to the sale of
WAPI's interests on March 31, 2004, no future Quality Bank liability will accrue
but any liability that existed as of the date of the sale will remain a
Williams's liability. Because of the complexity of the issues involved, however,
the outcome cannot be predicted with certainty nor can the likely result be
quantified. Certain periodic discussions have been held and continue among some
of the litigants. Because of the number of parties involved and the diversity of
positions, no comprehensive terms have been identified that could be considered
probable to achieve final settlement among all parties. The FERC and RCA
presiding administrative law judges are expected to render their joint and/or
individual initial decision(s) sometime during the third quarter of 2004.
Although we sold WAPI, we retained potential liability for any retroactive
payments that may be awarded in these proceedings for the period ending on March
31, 2004.
Deepwater Construction Litigation
On February 12, 2004, Technip Offshore Contractors, Inc. (TOCI) served
WFS, as agent for Williams Fields Services Company - Gulf Coast Company, L.P.
and Williams Oil Gathering, L.L.C., with a lawsuit brought in federal court in
Houston, Texas. TOCI alleges breach of its contract with us for the construction
of export pipelines connected to the Devils Tower SPAR in the Gulf of Mexico.
TOCI seeks (1) acceleration of our obligation to pay amounts held as retention
and (2) payment of almost $10 million for the value of disputed change orders.
We have filed counterclaims seeking almost $7 million arising from damages
suffered due to TOCI's breaches of the contract, including liquidated delay
damages. The litigation is in the early stages of discovery.
Colorado Royalty Litigation
On June 27, 2002, a royalty owner in the Piceance basin of Colorado
filed suit against Williams Production RMT Company alleging that we breached our
lease agreements and violated the Colorado Deceptive Trade Practices Act by
making various deductions from his royalty payments from 1996 to date. On August
2, 2004, the jury returned its verdict in the amount of $4.1 million for the
plaintiff. The verdict included a finding of bad faith which could potentially
triple the damage award. The verdict is not yet final pending post-trial
motions, but we expect to appeal the verdict if it is not set aside by the
court.
Other divestiture indemnifications
Pursuant to various purchase and sale agreements relating to divested
businesses and assets, we have indemnified certain purchasers against
liabilities that they may incur with respect to the businesses and assets
acquired from us. The indemnities provided to the purchasers are customary in
sale transactions and are contingent upon the purchasers incurring liabilities
that are not otherwise recoverable from third parties. The indemnities generally
relate to breach of warranties, tax, historic litigation, personal injury,
environmental matters, right of way and other representations that we have
provided. At June 30, 2004, we do not expect any of the indemnities provided
pursuant to the sales agreements to have a material impact on our future
financial position. However, if a claim for indemnity is brought against us in
the future, it may have a material adverse effect on results of operations in
the period in which the claim is made.
In addition to the foregoing, various other proceedings are pending
against us which are incidental to our operations.
SUMMARY
Litigation, arbitration, regulatory matters and environmental matters
are subject to inherent uncertainties. Were an unfavorable ruling to occur,
there exists the possibility of a material adverse impact on the results of
operations in the period in which the ruling occurs. Management, including
internal counsel, currently believes that the ultimate resolution of the
foregoing matters, taken as a whole and after consideration of amounts accrued,
insurance coverage, recovery from customers or other indemnification
arrangements, will not have a materially adverse effect upon our future
financial position.
99.5-25
Notes (Continued)
COMMITMENTS
Power has entered into certain contracts giving it the right to receive
fuel conversion services as well as certain other services associated with
electric generation facilities that are currently in operation throughout the
continental United States. At June 30, 2004, Power's estimated committed
payments under these contracts are approximately $210 million for the remainder
of 2004, range from approximately $397 million to $423 million annually through
2017 and decline over the remaining five years to $58 million in 2022. Total
committed payments under these contracts over the next eighteen years are
approximately $6.5 billion.
GUARANTEES
In connection with the 1993 public offering of units in the Williams
Coal Seam Gas Royalty Trust (Royalty Trust), our Exploration & Production
segment entered into a gas purchase contract for the purchase of natural gas in
which the Royalty Trust holds a net profits interest. Under this agreement, we
guarantee a minimum purchase price that the Royalty Trust will realize in the
calculation of its net profits interest. We have an annual option to discontinue
this minimum purchase price guarantee and pay solely based on an index price.
The maximum potential future exposure associated with this guarantee is not
determinable because it is dependent upon natural gas prices and production
volumes. No amounts have been accrued for this contingent obligation as the
index price continues to exceed the minimum purchase price.
In connection with the construction of a joint venture pipeline
project, we guaranteed, through a put agreement, certain portions of the joint
venture's project financing in the event of nonpayment by the joint venture. Our
potential liability under this guarantee ranges from zero percent to 100 percent
of the outstanding project financing, depending on our ability and the other
project member's ability to meet certain performance criteria. As of June 30,
2004, the total outstanding project financing is $32.8 million. While our
maximum potential liability is the full amount of the financing, based on a
recently executed Memorandum of Agreement (MOA), our exposure has been
significantly reduced. On March 8, 2004, we entered into the MOA, in which the
partner in the joint venture assumed 100 percent of project development costs to
date as well as responsibility for any ongoing additional costs, pending a final
determination of whether the project will go forward. Based on the MOA and the
current status of the project, it is highly unlikely that any obligation would
be incurred with respect to the project. The put agreement expires in March
2005. We have not accrued any amounts related to the guarantee at June 30, 2004.
We have guaranteed commercial letters of credit totaling $17 million on
behalf of an equity method investee. These expire in January 2005, and have no
carrying value.
We have provided guarantees in the event of nonpayment by our
previously owned communications subsidiary, WilTel, on certain lease performance
obligations that extend through 2042 and have a maximum potential exposure of
approximately $50 million at June 30, 2004. Our exposure declines systematically
throughout the remaining term of WilTel's obligations. The carrying value of
these guarantees is approximately $45 million at June 30, 2004 and is recorded
as a non-current liability.
We have provided guarantees on behalf of certain partnerships in which
we have an equity ownership interest. These generally guarantee operating
performance measures and the maximum potential future exposure cannot be
determined. These guarantees continue until we withdraw from the partnerships.
No amounts have been accrued at June 30, 2004.
99.5-26
Notes (Continued)
14. COMPREHENSIVE INCOME (LOSS)
Comprehensive income (loss) from both continuing and discontinued
operations is as follows:
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
----------------------- -----------------------
2004 2003 2004 2003
--------- --------- --------- ---------
(MILLIONS) (MILLIONS)
Net income (loss) ................................. $ (18.2) $ 269.7 $ (8.3) $ (544.8)
Other comprehensive income (loss):
Unrealized gains on securities .................. -- 4.4 -- .2
Net realized losses on securities ............... -- -- 3.0 --
Unrealized losses on derivative instruments ..... (83.8) (266.1) (268.4) (450.2)
Net reclassification into earnings of derivative
instrument losses .............................. 51.3 8.5 98.0 23.8
Foreign currency translation adjustments ........ (6.2) 28.9 (11.5) 53.6
Minimum pension liability adjustment ............ -- 1.6 .7 1.6
--------- --------- --------- ---------
Other comprehensive loss before taxes ........... (38.7) (222.7) (178.2) (371.0)
Income tax benefit on other comprehensive loss .. 12.3 96.2 63.7 162.4
--------- --------- --------- ---------
Other comprehensive loss .......................... (26.4) (126.5) (114.5) (208.6)
--------- --------- --------- ---------
Comprehensive income (loss) ....................... $ (44.6) $ 143.2 $ (122.8) $ (753.4)
========= ========= ========= =========
15. SEGMENT DISCLOSURES
Segments and reclassification of operations
Our reportable segments are strategic business units that offer
different products and services. The segments are managed separately because
each segment requires different technology, marketing strategies and industry
knowledge. Other primarily consists of corporate operations and certain
continuing operations previously reported within the International and Petroleum
Services segments.
Effective June 1, 2004, and due in part to FERC Order 2004, management
and decision-making control of certain regulated gas gathering assets was
transferred from our Midstream segment to our Gas Pipeline segment.
Consequently, the results of operations were similarly reclassified. All prior
periods reflect these classifications.
Effective September 21, 2004, and due in large part to FERC Order 2004,
management and decision-making control of our equity method investment in the
Aux Sable gas processing plant and related business was transferred from our
Midstream segment to our Power segment. Consequently, the results of operations
were similarly reclassified. All prior periods reflect these classifications.
Segments - performance measurement
We currently evaluate performance based upon segment profit (loss) from
operations which, includes revenues from external and internal customers,
operating costs and expenses, depreciation, depletion and amortization, equity
earnings (losses) and income (loss) from investments including gains/losses on
impairments related to investments accounted for under the equity method.
Intersegment sales are generally accounted for at current market prices as if
the sales were to unaffiliated third parties.
Power has entered into intercompany interest rate swaps with the
corporate parent, the effect of which is included in Power's segment revenues
and segment profit (loss) as shown in the reconciliation within the following
tables. The results of interest rate swaps with external counterparties are
shown as interest rate swap income (loss) in the Consolidated Statement of
Operations below operating income.
The majority of energy commodity hedging by certain of our business
units is done through intercompany derivatives with Power which, in turn, enters
into offsetting derivative contracts with unrelated third parties. Power bears
the counterparty performance risks associated with unrelated third parties.
99.5-27
Notes (Continued)
15. SEGMENT DISCLOSURES (CONTINUED)
The following tables reflect the reconciliation of revenues and operating
income (loss) as reported in the Consolidated Statement of Operations to segment
revenues and segment profit (loss).
EXPLORATION MIDSTREAM
GAS & GAS &
POWER PIPELINE PRODUCTION LIQUIDS OTHER ELIMINATIONS TOTAL
---------- -------- ---------- -------- ------- ------------ ----------
(MILLIONS)
THREE MONTHS ENDED JUNE 30, 2004
Segment revenues:
External $ 2,118.7 $ 325.9 $ (19.3) $ 621.3 $ 2.1 $ -- $ 3,048.7
Internal 235.0 5.1 208.3 9.2 4.9 (462.5) --
---------- -------- -------- -------- ------- -------- ----------
Total segment revenues 2,353.7 331.0 189.0 630.5 7.0 (462.5) 3,048.7
---------- -------- -------- -------- ------- -------- ----------
Less intercompany interest rate swap income
(loss) 20.5 -- -- -- -- (20.5) --
---------- -------- -------- -------- ------- -------- ----------
Total revenues $ 2,333.2 $ 331.0 $ 189.0 $ 630.5 $ 7.0 $ (442.0) $ 3,048.7
========== ======== ======== ======== ======= ======== ==========
Segment profit (loss) $ 43.8 $ 132.8 $ 43.3 $ 99.5 $ (14.3) $ -- $ 305.1
Less:
Equity earnings (losses) (.9) 5.2 3.2 3.5 (.3) -- 10.7
Loss from investments -- (.7) -- (.1) (10.8) -- (11.6)
Intercompany interest rate swap income
(loss) 20.5 -- -- -- -- -- 20.5
---------- -------- -------- -------- ------- -------- ----------
Segment operating income (loss) $ 24.2 $ 128.3 $ 40.1 $ 96.1 $ (3.2) $ -- 285.5
---------- -------- -------- -------- ------- -------- ----------
General corporate expenses (28.3)
----------
Consolidated operating income $ 257.2
==========
THREE MONTHS ENDED JUNE 30, 2003
Segment revenues:
External $ 2,797.8 $ 320.5 $ (5.8) $ 488.2 $ 11.6 $ -- $ 3,612.3
Internal 125.7 10.2 206.0 14.0 8.5 (364.4) --
---------- -------- -------- -------- ------- -------- ----------
Total segment revenues 2,923.5 330.7 200.2 502.2 20.1 (364.4) 3,612.3
---------- -------- -------- -------- ------- -------- ----------
Less intercompany interest rate swap loss (16.7) -- -- -- -- 16.7 --
---------- -------- -------- -------- ------- -------- ----------
Total revenues $ 2,940.2 $ 330.7 $ 200.2 $ 502.2 $ 20.1 $ (381.1) $ 3,612.3
========== ======== ======== ======== ======= ======== ==========
Segment profit (loss) $ 335.9 $ 115.5 $ 178.7 $ 57.2 $ (51.7) $ -- $ 635.6
Less:
Equity earnings (losses) (3.6) 2.0 2.5 .8 (.7) -- 1.0
Income (loss) from investments (8.5) .1 -- 4.8 (42.5) -- (46.1)
Intercompany interest rate swap loss (16.7) -- -- -- -- -- (16.7)
---------- -------- -------- -------- ------- -------- ----------
Segment operating income (loss) $ 364.7 $ 113.4 $ 176.2 $ 51.6 $ (8.5) $ -- 697.4
---------- -------- -------- -------- ------- -------- ----------
General corporate expenses (21.8)
----------
Consolidated operating income $ 675.6
==========
EXPLORATION MIDSTREAM
GAS & GAS &
POWER PIPELINE PRODUCTION LIQUIDS OTHER ELIMINATIONS TOTAL
---------- -------- ---------- -------- ------- ------------ ----------
(MILLIONS)
SIX MONTHS ENDED JUNE 30, 2004
Segment revenues:
External $ 4,222.6 $ 681.2 $ (34.1) $ 1,239.6 $ 4.9 $ -- $ 6,114.2
Internal 405.9 8.8 388.3 18.2 14.7 (835.9) --
---------- -------- -------- ---------- ------- -------- ----------
Total segment revenues 4,628.5 690.0 354.2 1,257.8 19.6 (835.9) 6,114.2
---------- -------- -------- ---------- ------- -------- ----------
Less intercompany interest rate swap loss (1.1) -- -- -- -- 1.1 --
---------- -------- -------- ---------- ------- -------- ----------
Total revenues $ 4,629.6 $ 690.0 $ 354.2 $ 1,257.8 $ 19.6 $ (837.0) $ 6,114.2
========== ======== ======== ========== ======= ======== ==========
Segment profit (loss) $ 11.8 $ 280.2 $ 94.8 $ 207.1 $ (23.0) $ -- $ 570.9
Less:
Equity earnings (losses) (.2) 9.0 6.1 7.7 (.3) -- 22.3
Loss from investments -- (1.0) -- (.3) (17.3) -- (18.6)
Intercompany interest rate swap loss (1.1) -- -- -- -- -- (1.1)
---------- -------- -------- ---------- ------- -------- ----------
Segment operating income (loss) $ 13.1 $ 272.2 $ 88.7 $ 199.7 $ (5.4) $ -- 568.3
---------- -------- -------- ---------- ------- -------- ----------
General corporate expenses (60.3)
----------
Consolidated operating income $ 508.0
==========
SIX MONTHS ENDED JUNE 30, 2003
Segment revenues:
External $ 6,385.8 $ 653.3 $ (12.9) $ 1,336.1 $ 26.1 $ -- $ 8,388.4
Internal 313.3 17.0 457.0 31.5 22.0 (840.8) --
---------- -------- -------- ---------- ------- -------- ----------
Total segment revenues 6,699.1 670.3 444.1 1,367.6 48.1 (840.8) 8,388.4
---------- -------- -------- ---------- ------- -------- ----------
Less intercompany interest rate swap loss (22.6) -- -- -- -- 22.6 --
---------- -------- -------- ---------- ------- -------- ----------
Total revenues $ 6,721.7 $ 670.3 $ 444.1 $ 1,367.6 $ 48.1 $ (863.4) $ 8,388.4
========== ======== ======== ========== ======= ======== ==========
Segment profit (loss) $ 198.9 $ 265.8 $ 292.5 $ 170.0 $ (46.9) $ -- $ 880.3
Less:
Equity earnings (losses) (4.2) 3.8 4.6 (1.8) 3.0 -- 5.4
Income (loss) from investments (8.5) .1 -- 4.8 (42.5) -- (46.1)
Intercompany interest rate swap loss (22.6) -- -- -- -- -- (22.6)
---------- -------- -------- ---------- ------- -------- ----------
Segment operating income (loss) $ 234.2 $ 261.9 $ 287.9 $ 167.0 $ (7.4) $ -- 943.6
---------- -------- -------- ---------- ------- -------- ----------
General corporate expenses (44.7)
----------
Consolidated operating income $ 898.9
==========
99.5-28
Notes (Continued)
15. SEGMENT DISCLOSURES (CONTINUED)
TOTAL ASSETS
--------------------------------------
JUNE 30, 2004 DECEMBER 31, 2003*
------------- ------------------
(MILLIONS)
Power $ 9,984.9 $ 8,732.9
Gas Pipeline 7,361.9 7,314.3
Exploration & Production 5,316.0 5,347.4
Midstream Gas & Liquids 4,020.2 3,990.3
Other 4,159.9 6,928.7
Eliminations (5,109.3) (6,078.2)
------------ -----------
25,733.6 26,235.4
Discontinued operations 434.8 786.4
------------ -----------
Total $ 26,168.4 $ 27,021.8
============ ===========
* Certain amounts have been reclassified as described in Note 2.
16. RECENT ACCOUNTING STANDARDS
As discussed in our Annual Report on Form 10-K for the year ended
December 31, 2003, the SEC staff, in a letter to the EITF Chairman, questioned
whether leased mineral rights should be presented as intangible assets rather
than property, plant and equipment. In March 2004, the EITF reached a consensus
that all mineral rights should be considered tangible assets for accounting
purposes. Therefore, no reclassification will be required.
In May 2004, the FASB issued FSP No. FAS 106-2, "Accounting and
Disclosure Requirements Related to the Medicare Prescription Drug, Improvement
and Modernization Act of 2003." This guidance is effective for us beginning in
third quarter 2004 and supersedes FSP No. FAS 106-1. We are evaluating the
impact of the Act on future obligations of the plan. If the plan is determined
to be actuarially equivalent and thus eligible for the subsidy, the change in
the obligation attributable to prior service will be deferred and recognized
over future periods beginning in third-quarter 2004 (see Note 8).
EITF Issue No. 03-1, "The Meaning of Other Than Temporary Impairment
and Its Application to Certain Investments," contains recognition and
measurement guidance that must be applied to investment impairment evaluations
in interim reporting periods beginning after June 15, 2004. This Issue is
required to be adopted on a prospective basis. Specifically, the Issue provides
guidance to determine whether an investment is impaired and whether that
impairment is other than temporary. The Issue applies to debt and equity
securities, except equity securities accounted for under the equity method. We
are reviewing this Issue and have yet to determine the impact to our
Consolidated Balance Sheet and Consolidated Statement of Operations.
17. SUBSEQUENT EVENTS
NOTES PAYABLE AND LONG-TERM DEBT
In August 2004, we made cash tender offers and consent solicitations
for all of our 8.625 percent senior notes due 2010. Approximately $792.8
million, or approximately 99 percent, aggregate principal amount of notes were
accepted for purchase. In conjunction with this purchase, we paid premiums of
approximately $135 million.
99.5-29
Notes (Continued)
On September 17, 2004, we initiated an offer to exchange up to 43.9
million FELINE PACS units for one share of our common stock plus $1.47 in cash
for each unit. The offer expired October 18, 2004 and resulted in approximately
33.1 million of the 44 million issued and outstanding units being tendered and
accepted for exchange. The exchange offer reduced our overall debt by
approximately $827 million and increased our common stock outstanding by 33.1
million shares. The effect of the exchange, including a pre-tax charge for
related expenses of approximately $25 million, will be reflected in the fourth
quarter.
OTHER LEGAL MATTERS
As discussed in Note 13, Williams Alaska Petroleum, Inc. (WAPI) is
actively engaged in administrative litigation being conducted jointly by the
FERC and the Regulatory Commission of Alaska (RCA) concerning the Trans-Alaska
Pipeline System (TAPS) Quality Bank. Primary issues being litigated include the
appropriate valuation of the naptha, heavy distillate, vacuum gas oil and
residual product cuts within the TAPS Quality Bank as well as the appropriate
retroactive effects of the determinations.
The FERC and RCA presiding administrative law judges rendered their
joint and individual initial decisions during the third quarter of 2004. The
initial decisions set forth methodologies for determining the valuations of the
product cuts under review and also approved the retroactive application of the
approved methodologies for the heavy distillate and residual product cuts. Based
on our computation and assessment of ultimate ruling terms that would be
considered probable, we recorded an accrual of approximately $134 million in the
third quarter of 2004. Because the application of certain aspects of the initial
decisions are subject to interpretation, we have calculated the reasonably
possible impact of the decisions, if fully adopted by the FERC and RCA, to
result in additional exposure to us of approximately $32 million more than we
have accrued at September 30, 2004. We will be filing a brief on exceptions to
the initial decisions to both the FERC and RCA on November 16, 2004, and reply
briefs are due on February 1, 2005. Decisions from the Commissions will then be
issued likely before the end of 2005. It is unlikely that we will be required to
make any payments with respect to this matter until sometime after the
Commission decisions.
As discussed in Note 6, in July 2004, an arbitration panel awarded Gulf
Liquids approximately $83.3 million related to obligations under construction
contracts. On November 1, 2004, Winterthur remitted approximately $85 million to
us in the settlement of certain disputes regarding obligations under
construction contracts. As a result of the payment, we will recognize pre-tax
income of approximately $95 to $100 million within Income from discontinued
operations in the fourth quarter.
99.5-30