.
.
.
EXHIBIT 99.3
THE WILLIAMS COMPANIES, INC.
CONSOLIDATED STATEMENT OF OPERATIONS
(UNAUDITED)
THREE MONTHS
ENDED MARCH 31,
-------------------------
(DOLLARS IN MILLIONS, EXCEPT PER-SHARE AMOUNTS) 2004 2003*
------------------------------------------------------------------------------ ------------ ------------
Revenues:
Power....................................................................... $ 2,296.4 $ 3,781.5
Gas Pipeline................................................................ 359.0 339.6
Exploration & Production.................................................... 165.2 243.9
Midstream Gas & Liquids..................................................... 627.3 865.4
Other....................................................................... 12.6 28.0
Intercompany eliminations................................................... (395.0) (482.3)
----------- -----------
Total revenues............................................................. 3,065.5 4,776.1
----------- -----------
Segment costs and expenses:
Costs and operating expenses................................................ 2,689.9 4,423.6
Selling, general and administrative expenses................................ 84.4 105.6
Other expense - net......................................................... 8.4 .7
----------- -----------
Total segment costs and expenses........................................... 2,782.7 4,529.9
----------- -----------
General corporate expenses.................................................... 32.0 22.9
----------- -----------
Operating income (loss):
Power....................................................................... (11.1) (130.5)
Gas Pipeline................................................................ 143.9 148.5
Exploration & Production.................................................... 48.6 111.7
Midstream Gas & Liquids..................................................... 103.6 115.4
Other....................................................................... (2.2) 1.1
General corporate expenses.................................................. (32.0) (22.9)
----------- -----------
Total operating income..................................................... 250.8 223.3
Interest accrued.............................................................. (243.3) (352.8)
Interest capitalized.......................................................... 4.0 11.9
Interest rate swap loss....................................................... (8.1) (2.8)
Investing income.............................................................. 10.3 46.3
Minority interest in income of consolidated subsidiaries...................... (4.8) (3.5)
Other income - net............................................................ .9 22.1
----------- -----------
Income (loss) from continuing operations before income taxes and
cumulative effect of change in accounting principles........................ 9.8 (55.5)
Provision (benefit) for income taxes.......................................... 11.3 (12.4)
----------- -----------
Loss from continuing operations............................................... (1.5) (43.1)
Income (loss) from discontinued operations.................................... 11.4 (10.1)
----------- -----------
Income (loss) before cumulative effect of change in accounting principles..... 9.9 (53.2)
Cumulative effect of change in accounting principles.......................... - (761.3)
----------- -----------
Net income (loss)............................................................. 9.9 (814.5)
Preferred stock dividends..................................................... - 6.8
----------- -----------
Income (loss) applicable to common stock...................................... $ 9.9 $ (821.3)
=========== ===========
Basic and diluted earnings (loss) per common share:
Loss from continuing operations............................................. $ - $ (.10)
Income (loss) from discontinued operations.................................. .02 (.02)
----------- -----------
Income (loss) before cumulative effect of change in accounting
principles................................................................. .02 (.12)
Cumulative effect of change in accounting principles........................ - (1.47)
----------- -----------
Net income (loss).......................................................... $ .02 $ (1.59)
=========== ===========
Weighted-average shares (thousands)......................................... 519,485 517,652
Cash dividends per common share............................................... $ .01 $ .01
* Certain amounts have been reclassified as described in Note 2 of Notes to
Consolidated Financial Statements.
See accompanying notes.
99.3-1
THE WILLIAMS COMPANIES, INC.
CONSOLIDATED BALANCE SHEET
(UNAUDITED)
MARCH 31, DECEMBER 31,
(DOLLARS IN MILLIONS, EXCEPT PER-SHARE AMOUNTS) 2004 2003*
--------------------------------------------------------------------------------- ------------ ------------
ASSETS
Current assets:
Cash and cash equivalents...................................................... $ 1,997.8 $ 2,315.7
Restricted cash................................................................ 55.7 47.1
Restricted investments......................................................... 283.6 93.2
Accounts and notes receivable less allowance of $102.8 ($112.2 in 2003)........ 1,483.8 1,613.2
Inventories.................................................................... 204.0 242.9
Derivative assets.............................................................. 4,037.1 3,166.8
Margin deposits................................................................ 639.0 553.9
Assets of discontinued operations.............................................. 172.7 441.3
Deferred income taxes.......................................................... 104.2 106.6
Other current assets and deferred charges...................................... 146.1 214.3
------------ ------------
Total current assets........................................................ 9,124.0 8,795.0
Restricted cash.................................................................. 142.3 159.8
Restricted investments........................................................... - 288.1
Investments...................................................................... 1,390.0 1,463.6
Property, plant and equipment, at cost........................................... 15,846.4 15,752.3
Less accumulated depreciation and depletion...................................... (4,149.2) (4,018.3)
------------ ------------
11,697.2 11,734.0
Derivative assets................................................................ 3,386.8 2,495.6
Goodwill......................................................................... 1,014.5 1,014.5
Assets of discontinued operations................................................ 336.5 345.1
Other assets and deferred charges................................................ 698.9 726.1
------------ ------------
Total assets................................................................ $ 27,790.2 $ 27,021.8
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Notes payable.................................................................. $ - $ 3.3
Accounts payable............................................................... 983.0 1,228.0
Accrued liabilities............................................................ 830.5 944.4
Liabilities of discontinued operations......................................... 42.7 95.7
Derivative liabilities......................................................... 4,083.4 3,064.2
Long-term debt due within one year............................................. 442.9 935.2
------------ ------------
Total current liabilities................................................... 6,382.5 6,270.8
Long-term debt................................................................... 10,824.8 11,039.8
Deferred income taxes............................................................ 2,405.0 2,453.4
Derivative liabilities........................................................... 3,130.5 2,124.1
Other liabilities and deferred income............................................ 925.6 947.5
Contingent liabilities and commitments (Note 11)
Minority interests in consolidated subsidiaries.................................. 87.7 84.1
Stockholders' equity:
Common stock, $1 per share par value, 960 million shares authorized, 523
million issued in 2004, 521.4 million issued in 2003.......................... 523.0 521.4
Capital in excess of par value................................................. 5,205.8 5,195.1
Accumulated deficit............................................................ (1,422.0) (1,426.8)
Accumulated other comprehensive loss........................................... (209.1) (121.0)
Other.......................................................................... (25.0) (28.0)
------------ ------------
4,072.7 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.................................................. 4,034.1 4,102.1
------------ ------------
Total liabilities and stockholders' equity.................................. $ 27,790.2 $ 27,021.8
============ ============
* Certain amounts have been reclassified as described in Note 2 to Consolidated
Financial Statements.
See accompanying notes.
99.3-2
THE WILLIAMS COMPANIES, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
(UNAUDITED)
THREE MONTHS ENDED MARCH 31,
-------------------------------
2004 2003*
----------- -----------
(MILLIONS)
OPERATING ACTIVITIES:
Loss from continuing operations.......................................... $ (1.5) $ (43.1)
Adjustments to reconcile to cash provided (used) by operations:
Depreciation, depletion and amortization............................... 160.4 164.5
Provision (benefit) for deferred income taxes.......................... 3.8 (23.4)
Provision for loss on investments, property and other assets........... 7.4 12.0
Net (gain) loss on disposition of assets............................... 1.3 (.6)
Provision for uncollectible accounts................................... (3.8) (2.0)
Minority interest in income of consolidated subsidiaries............... 4.8 3.5
Amortization of stock-based awards..................................... 4.1 17.2
Accrual for fixed rate interest included in the RMT note payable....... - 33.0
Amortization of deferred set-up fee and fixed rate interest on RMT
note payable.......................................................... - 64.3
Cash provided (used) by changes in current assets and liabilities:
Restricted cash...................................................... 2.8 2.5
Accounts and notes receivable........................................ 161.2 (37.7)
Inventories.......................................................... 38.9 39.6
Margin deposits...................................................... (85.4) (48.7)
Other current assets and deferred charges............................ 66.9 (69.6)
Accounts payable..................................................... (214.0) (83.4)
Accrued liabilities.................................................. (114.5) (178.9)
Changes in current and noncurrent derivative assets and liabilities.... 114.5 (10.9)
Changes in noncurrent restricted cash.................................. (.1) (.5)
Other, including changes in noncurrent assets and liabilities.......... 3.1 (20.8)
---------- ----------
Net cash provided (used) by operating activities of continuing
operations.......................................................... 149.9 (183.0)
Net cash provided (used) by operating activities of discontinued
operations.......................................................... (47.1) 86.3
---------- ----------
Net cash provided (used) by operating activities..................... 102.8 (96.7)
---------- ----------
FINANCING ACTIVITIES:
Payments of notes payable................................................ (3.3) (.1)
Proceeds from long-term debt............................................. - 176.5
Payments of long-term debt............................................... (707.7) (360.0)
Proceeds from issuance of common stock................................... 4.8 -
Dividends paid........................................................... (5.2) (12.0)
Payments of debt issuance costs.......................................... - (6.9)
Payments/dividends to minority interests................................. (1.2) (.4)
Changes in restricted cash............................................... 6.3 (250.6)
Changes in cash overdrafts............................................... (27.4) (31.9)
Other - net.............................................................. (.5) .1
---------- ----------
Net cash used by financing activities of continuing operations....... (734.2) (485.3)
Net cash used by financing activities of discontinued operations..... (.6) (81.0)
---------- ----------
Net cash used by financing activities................................ (734.8) (566.3)
---------- ----------
INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures................................................... (127.8) (235.1)
Proceeds from dispositions............................................. .9 43.4
Purchases of investments/advances to affiliates.......................... (.4) (5.7)
Purchases of restricted investments...................................... (235.9) -
Proceeds from sales of businesses........................................ 279.9 636.2
Proceeds from sale of restricted investments............................. 331.2 -
Proceeds from dispositions of investments and other assets............... 74.8 .1
Other - net.............................................................. (9.3) 4.0
---------- ----------
Net cash provided by investing activities of continuing operations... 313.4 442.9
Net cash used by investing activities of discontinued operations..... (.9) (14.3)
---------- ----------
Net cash provided by investing activities............................ 312.5 428.6
---------- ----------
Decrease in cash and cash equivalents...................................... (319.5) (234.4)
Cash and cash equivalents at beginning of period**......................... 2,318.2 1,736.0
---------- ----------
Cash and cash equivalents at end of period**............................... $ 1,998.7 $ 1,501.6
========== ==========
* 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 $.9
million, $2.5 million, $98.4 million and $85.6 million at March 31, 2004,
December 31, 2003, March 31, 2003 and December 31, 2002, respectively.
See accompanying notes.
99.3-3
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 include 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. Projected asset sales
are expected to generate proceeds of approximately $800 million in 2004 and
include the Alaska refinery and certain Midstream Gas & Liquids (Midstream)
assets including the straddle plants in western Canada. On March 31, 2004, we
completed the sale of our Alaska refinery and related assets for approximately
$304 million (see Note 5).
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 10). 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
10).
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.
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.
99.3-4
Notes (Continued)
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 notes in 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 March 31, 2004, and results of operations and
cash flows for the three months ended March 31, 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 for
first-quarter 2003 include $13.7 million of revenue attributable to the 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 the following components as discontinued operations
(see Note 5):
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;
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;
o Gulf Liquids New River Project LLC, previously part of the Midstream
segment; and
o our straddle plants in western Canada, previously part of the
Midstream segment.
99.3-5
Notes (Continued)
Unless indicated otherwise, the information in the Notes to the Consolidated
Financial Statements relates to our continuing operations. We expect that 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 period presented to reflect the discontinued
operations noted above, consistent with the presentation in our 2003 Form 10-K,
as restated and amended. 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.
4. PROVISION (BENEFIT) FOR INCOME TAXES
The provision (benefit) for income taxes from continuing operations
includes:
THREE MONTHS ENDED
MARCH 31,
---------------------
2004 2003
(MILLIONS)
Current:
Federal................................................ $ 3.2 $ 6.3
State.................................................. 1.8 4.7
Foreign................................................ 2.5 -
------- --------
7.5 11.0
Deferred:
Federal................................................ (.6) (16.6)
State.................................................. 2.1 (3.0)
Foreign................................................ 2.3 (3.8)
------- --------
3.8 (23.4)
------- --------
Total provision (benefit).................................. $ 11.3 $ (12.4)
======= ========
The effective income tax rate for the three months ended March 31, 2004, is
greater than the federal statutory rate due primarily to an accrual for income
tax contingencies, net foreign operations, and state income taxes.
The effective income tax rate for the three months ended March 31, 2003, is
less than the federal statutory rate (less tax benefit) due primarily to an
accrual for income tax contingencies and state income taxes.
99.3-6
Notes (Continued)
5. 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 March
31, 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.
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. 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. Consequently, the results of operations of the straddle
plants have been reclassified to discontinued operations in the consolidated
financial statements and in the tables below. All prior periods reflect this
classification.
SUMMARIZED RESULTS OF DISCONTINUED OPERATIONS
The following table presents the summarized results of discontinued
operations for the three months ended March 31, 2004 and March 31, 2003. Income
from discontinued operations before income taxes for the first quarter of 2004
includes a charge of $17.4 million to adjust our accrued liability associated
with certain Quality Bank litigation matters (see Note 11).
THREE MONTHS ENDED
MARCH 31,
-----------------------
2004 2003
-------- -----------
(MILLIONS)
Revenues......................................................... $ 294.3 $ 1,217.9
======== ==========
Income from discontinued operations before
income taxes................................................... 11.1 96.8
(Impairments) and gain (loss) on sales - net..................... 6.9 (117.3)
Benefit (provision) for income taxes............................. (6.6) 10.4
-------- ----------
Income (loss) from discontinued operations....................... $ 11.4 $ (10.1)
======== ==========
SUMMARIZED ASSETS AND LIABILITIES OF DISCONTINUED OPERATIONS
The following table presents the summarized assets and liabilities of
discontinued operations as of March 31, 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 March 31, 2004 balances include
the Canadian straddle plants, Gulf Liquids and the 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.
MARCH 31, DECEMBER 31,
2004 2003
---------- ------------
(MILLIONS)
Total current assets.......................................... $ 112.6 $ 175.4
-------- --------
Property, plant and equipment -- net............................ 395.2 609.0
Other non-current assets........................................ 1.4 2.0
-------- --------
Total non-current assets...................................... 396.6 611.0
-------- --------
Total assets.................................................. $ 509.2 $ 786.4
======== ========
Long-term debt due within one year.............................. $ .6 $ 1.2
Other current liabilities....................................... 40.4 81.5
-------- --------
Total current liabilities..................................... 41.0 82.7
-------- --------
Long-term debt.................................................. - .3
Other non-current liabilities................................... 1.7 12.7
-------- --------
Total non-current liabilities................................. 1.7 13.0
-------- --------
Total liabilities............................................. $ 42.7 $ 95.7
======== ========
99.3-7
Notes (Continued)
HELD FOR SALE AT MARCH 31, 2004
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 previously written down to their estimated
fair value less cost to sell at December 31, 2003. 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 mid-2004. These operations were part of the Midstream
segment.
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 (consisting of $279
million in cash and a $25 million short-term receivable), subject to closing
adjustments for items such as the value of petroleum inventories. 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.
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.
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. A first-quarter
2003 impairment charge of $5 million is 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.
Bio-energy facilities
On May 30, 2003, we completed the sale of our bio-energy operations for
approximately $59 million in cash. 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. These properties were part of the Exploration & Production
segment.
99.3-8
Notes (Continued)
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. 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. The gain on sale is included in (impairments) and gain
(loss) on sale in the preceding table of summarized results of discontinued
operations. These operations were part of the previously reported Petroleum
Services segment.
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.
6. EARNINGS (LOSS) PER SHARE
Basic and diluted earnings (loss) per common share are computed as follows:
THREE MONTHS ENDED
MARCH 31,
--------------------------
2004 2003
----------- -------------
(DOLLARS IN MILLIONS,
EXCEPT PER-SHARE
AMOUNTS; SHARES IN
THOUSANDS)
Loss from continuing operations........................................ $ (1.5) $ (43.1)
Convertible preferred stock dividends.................................. - (6.8)
----------- -----------
Loss from continuing operations available to common
stockholders for basic and diluted earnings per share................ (1.5) (49.9)
=========== ===========
Basic and diluted weighted-average shares.............................. 519,485 517,652
Loss per share from continuing operations:
Basic and diluted.................................................... $ - $ (.10)
For the periods ended March 31, 2004 and 2003, diluted earnings (loss) per
share is the same as the basic calculation as each period presented has a loss
from continuing operations. Shares, which would otherwise have been included in
the diluted earnings (loss) per share, have been excluded from the computation.
Inclusion of these shares, which are discussed below, would be antidilutive.
For the three months ended March 31, 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. In addition, approximately 3.8 million weighted-average stock
options and approximately 2.4 million weighted-average unvested deferred shares
have been excluded from the computation of diluted earnings per common share as
their inclusion would be antidilutive.
For the three months ended March 31, 2003, approximately 1.7 million
weighted-average stock options, approximately 14.7 million weighted-average
shares related to the assumed conversion of 9 7/8 percent cumulative convertible
preferred stock and approximately 3.2 million weighted-average unvested deferred
shares, that otherwise would have been included, have been excluded from the
computation of diluted earnings per common share as their inclusion would be
antidilutive.
99.3-9
Notes (Continued)
7. EMPLOYEE BENEFIT PLANS
Net pension and other postretirement benefit expense for the three months
ended March 31, 2004 and 2003 is as follows:
OTHER POSTRETIREMENT
PENSION BENEFITS BENEFITS
---------------------- -----------------------
THREE MONTHS THREE MONTHS
ENDED MARCH 31, ENDED MARCH 31,
---------------------- -----------------------
2004 2003 2004 2003
---------- --------- -------- --------
(MILLIONS)
Service cost............................................... $ 7.0 $ 6.5 $ 1.5 $ 1.7
Interest cost.............................................. 14.5 13.4 5.7 6.4
Expected return on plan assets............................. (14.9) (13.8) (3.1) (3.5)
Amortization of transition obligation...................... - - .6 .7
Amortization of prior service cost (credit) ............... (.7) (.6) .2 .2
Recognized net actuarial loss.............................. 3.7 3.4 - -
Regulatory asset amortization (deferral) .................. 1.1 .1 1.6 2.7
Settlement/ curtailment expense............................ - 1.5 - -
-------- -------- ------- -------
Net periodic pension and postretirement benefit expense.... $ 10.7 $ 10.5 $ 6.5 $ 8.2
======== ======== ======= =======
As previously disclosed in our Annual Report on Form 10-K for the year ended
December 31, 2003, we expect to contribute approximately $60 million to our
pension plans and approximately $15 million to our other postretirement benefit
plans in 2004. As of March 31, 2004, $.7 million has been contributed to our
pension plans and $2.5 million has been contributed to our other postretirement
benefit plans. We presently anticipate contributing approximately an additional
$59 million to fund our pension plans in 2004 for a total of approximately $60
million. We presently anticipate contributing approximately an additional $12
million to our other postretirement benefit plans in 2004 for a total of
approximately $15 million.
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. Management is evaluating the
impact of the Act on the future obligations of the plan. In accordance with FASB
Staff Position 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. Authoritative guidance on the accounting for a federal
subsidy is pending. That guidance, as currently drafted would require any change
in obligation attributable to prior service be deferred and recognized over
future periods if the plan is deemed to be actuarially equivalent and eligible
for the subsidy. As proposed, this guidance would be effective for us beginning
July 1, 2004.
99.3-10
Notes (Continued)
8. 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
MARCH 31,
----------------------
2004 2003
---- ----
(MILLIONS)
Net income (loss), as reported.................................................. $ 9.9 $ (814.5)
Add: Stock-based employee compensation included in the Consolidated
Statement of Operations, net of related tax effects........................... 4.4 10.6
Deduct: Stock-based employee compensation expense determined under fair
value based method for all awards, net of related tax effects................. (7.4) (14.7)
------- ---------
Pro forma net income (loss) .................................................... $ 6.9 $ (818.6)
======= =========
Earnings (loss) per share:
Basic-as reported............................................................. $ .02 $ (1.59)
Basic-pro forma............................................................... $ .01 $ (1.59)
Diluted-as reported........................................................... $ .02 $ (1.59)
Diluted-pro forma............................................................. $ .01 $ (1.59)
======= =========
Pro forma amounts for 2004 include compensation expense from awards of our
company stock made in 2004, 2003, 2002 and 2001. Also included in the 2004 pro
forma expense is $1 million 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. The
remaining expense on the cancelled options will be amortized through year-end
2004.
9. INVENTORIES
Inventories at March 31, 2004 and December 31, 2003 are as follows:
MARCH 31, DECEMBER 31,
2004 2003
--------- ------------
(MILLIONS)
Finished goods:
Refined products.......................................... $ 19.1 $ 8.0
Natural gas liquids....................................... 50.7 40.4
--------- ---------
69.8 48.4
Natural gas in underground storage.......................... 74.4 132.5
Materials, supplies and other............................... 59.8 62.0
--------- ---------
$ 204.0 $ 242.9
========= =========
99.3-11
Notes (Continued)
10. DEBT AND BANKING ARRANGEMENTS
NOTES PAYABLE AND LONG-TERM DEBT
Notes payable and long-term debt at March 31, 2004 and December 31, 2003,
are as follows:
WEIGHTED-
AVERAGE
INTEREST MARCH 31, 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% $ 234.7 $ 243.7
Notes, adjustable rate, payable through 2016......... 3.3% 596.2 602.5
Unsecured long-term debt
Debentures, 5.5%-10.25%, payable through 2033...... 7.0% 1,645.6 1,645.2
Notes, 6.125%-9.25%, payable through 2032 (2) ...... 7.5% 8,712.0 9,404.3
Other, payable through 2007.......................... 4.0% 79.2 79.3
------------ ------------
11,267.7 11,975.0
Long-term debt due within one year....................... (442.9) (935.2)
------------ ------------
Total long-term debt..................................... $ 10,824.8 $ 11,039.8
============ ============
(1) At March 31, 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 2004. These FELINE PACS include equity
forward contracts that require the holder to purchase shares of our common stock
in 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.
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.
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
The interest rate on our current $800 million secured revolving and letter
of credit facility is variable at LIBOR plus .75 percent, or 1.84 percent at
March 31, 2004. As of March 31, 2004, letters of credit totaling $268 million
have been issued by the participating financial institutions under this facility
and remain outstanding. No revolving credit loans were outstanding. At March 31,
2004, the amount of restricted investments securing this facility was $283.6
million, which collateralized the facility at approximately 106 percent.
99.3-12
Notes (Continued)
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 will be used primarily for issuing letters of
credit. 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 bank syndicated its associated credit risk into the institutional investor
market via a 144A offering. Upon the occurrence of certain credit events,
outstanding letters of credit become cash collateralized creating a borrowing
under the facilities, and 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:
o the fixed facility fee at a weighted average rate of 3.19 percent to
the investors,
o interest on borrowings under the $400 million facility equal to a
fixed rate of 3.57 percent, and
o interest on borrowings under the $100 million facility at a
fluctuating LIBOR interest rate.
The bank established trusts funded by the institutional investors, whereby
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. We have
no asset securitization or collateral requirements under the new facilities.
During April 2004, use of these new facilities released approximately $500
million of restricted cash, restricted investments and margin deposits.
Significant covenants under these facilities include the following:
o 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);
o limitations on asset sales;
o limitations on the use of proceeds from permitted asset sales;
o limitations on transactions with affiliates; and
o 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.
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. Northwest Pipeline Corporation (Northwest Pipeline) 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:
o 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;
o ratio of Debt to Capitalization no greater than 55 percent for
Northwest Pipeline and Transco;
o 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 period 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.
99.3-13
Notes (Continued)
Issuances and 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.
A summary of significant retirements, payments and prepayments of long-term
debt for the quarter ended March 31, 2004 is as follows:
PRINCIPAL
DUE DATE AMOUNT
-------- ------
(MILLIONS)
ISSUE/TERMS
-----------
Retirements/payments/prepayments of long-term debt in 2004:
9.25% senior unsecured notes.................................... 2004 $ 678.5
Various notes, 6.62% - 9.45%.................................... 2004 22.7
Various notes, adjustable rate.................................. 2004 6.3
11. 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 $5 million for
potential refund as of March 31, 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 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 is expected to resolve 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 $31.7 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 $8 million through March 31, 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 early summer, 2004. Although we have
entered into a global settlement with the State of California and various other
parties that resolves the refund issues among the settling parties for the
period of January 17, 2001 to June 19, 2001, we have potential refund exposure
to non-settling parties (e.g., various California electric utilities).
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.
99.3-14
Notes (Continued)
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"). The Utility Settlement was filed with the FERC on April 27, 2004.
Comments and approval are pending. While only these two utilities were
originally parties to the Utility Settlement with us, additional parties,
including San Diego Gas & Electric, 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 opt out of 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. If this settlement is
approved, our outstanding receivables for the period of approximately $261
million will be partially offset by our settlement obligation of approximately
$136 million. We will receive $108 million of our net $125 million receivable on
an expedited basis. These funds will be largely used to repurchase PG&E
receivables previously sold to Bear Stearns. The remainder of the receivable, in
addition to accrued interest, is expected to be received within a year of the
settlement. To be effective, the Utility Settlement must be approved by the FERC
and the California Public Utilities Commission. Approval by the FERC will also
resolve FERC investigations into physical and economic withholding. The Utility
Settlement, if approved, will also resolve any claims by the settling parties
regarding these issues. We recorded a charge of approximately $33 million in the
fourth quarter of 2003 associated with the terms of this settlement.
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. The Utility Settlement, if
approved, will resolve this issue and we will maintain all existing authorities.
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. We believe the vast
majority of fines are not justified and have challenged them pursuant to the
FERC-approved dispute resolution process contained in the ISO tariff.
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.
99.3-15
Notes (Continued)
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 are in the process of completing 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.
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
will be resolved pursuant to the Utility Settlement that is discussed above in
Refund proceedings if that settlement is approved by the FERC.
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 on 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. On October 24, 2003, the court granted a motion for
preliminary approval of the settlement. The final approval hearing is currently
scheduled for June 4, 2004. Upon approval, the majority of civil litigation
involving us and California markets will be resolved. Some litigation by
non-California plaintiffs, or relating to reporting of natural gas information
to trade publications, as discussed below, will continue. As of March 31, 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.
99.3-16
Notes (Continued)
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 are in the process of completing 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 and state court in California and in Federal court in New
York.
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. Had the FERC 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 $46 million, excluding interest, through
March 31, 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, Transco 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 March 31, 2004, Transco had accrued liabilities of $28
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 March 31, 2004, we had accrued liabilities totaling
approximately $11 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.
99.3-17
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 March 31, 2004, we had accrued liabilities of
approximately $10 million for such excess costs.
WILLIAMS ENERGY PARTNERS
As part of our June 17, 2003 sale of Williams Energy Partners (see Note 5),
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.
At March 31, 2004, we had accrued liabilities totaling approximately $9
million for these costs. In addition, we deferred approximately $113 million of
the gain associated with our indemnifications, including environmental
indemnifications, of the purchaser under the sales agreement. At March 31, 2004,
we had a remaining deferred gain relating to this sale of approximately $95
million. When claims for performance under the indemnity for environmental
matters are submitted by the purchaser and accepted by us, indemnification
amounts for accepted claims are reclassified from the deferred gain to accrued
liabilities. We anticipate ongoing performance under the indemnity provisions
for environmental claims, and therefore, the amount of ultimate gain cannot be
determined.
During the first quarter of 2004, we have been engaged in discussions with
the purchaser regarding a potential buyout of these indemnities in the form of a
structured cash settlement. At the time of this filing, the discussions are in
the advanced stages and it is reasonably possible that an agreement as to terms
will be reached during the second quarter. If the agreement is completed as
being discussed, we would reclassify a significant portion of the deferred gain
to accrued liabilities in the second quarter.
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. We have
indemnity obligations to Magellan related to this matter.
OTHER
At March 31, 2004, we had accrued environmental liabilities totaling
approximately $13 million related to our:
o potential indemnification obligations to purchasers of our former
retail petroleum and refining operations;
o former propane marketing operations, petroleum products and natural
gas pipelines, natural gas liquids fractionation;
o a discontinued petroleum refining facility;
o exploration and production and mining operations; and
o the discontinued Canadian straddle plants.
99.3-18
Notes (Continued)
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's 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.
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 March 31, 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.
99.3-19
Notes (Continued)
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.
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. 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 December 15, 2003, the court
substantially denied the defendants' motion to dismiss in the shareholder suits.
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. 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 was approved.
99.3-20
Notes (Continued)
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. (WGP), 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, WGP, WGCGC and WFS believe their actions were reasonable and lawful and
each have filed petitions for review of the FERC's orders with the U.S. Court of
Appeals for the District of Columbia.
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 $180 million. Due to the sale of WAPI's
interests on March 31, 2004, no future Quality Bank liability will accrue.
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.
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 March 31, 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.
99.3-21
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 March 31, 2004, Power's estimated committed payments under
these contracts are approximately $307 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
$6.6 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
members' ability to meet certain performance criteria. As of March 31, 2004, the
total outstanding project financing is $32.4 million. Our maximum potential
liability is the full amount of the financing, but based on the current status
of the project, it is likely that any obligation would be limited to 50 percent
of the outstanding financing. As additional borrowings are made under the
project financing facility, our potential exposure will increase. This guarantee
expires in March 2005, and we have not accrued any amounts at March 31, 2004.
We have guaranteed commercial letters of credit totaling $17 million on
behalf of Accroven. These expire in January 2005, have no carrying value and are
fully collateralized with cash.
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 $51 million at March 31, 2004. Our exposure declines
systematically throughout the remaining term of WilTel's obligations. The
carrying value of these guarantees is approximately $46 million at March 31,
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 March 31, 2004.
12. COMPREHENSIVE INCOME (LOSS)
Comprehensive income (loss) from both continuing and discontinued operations
is as follows:
THREE MONTHS ENDED
MARCH 31,
------------------------
2004 2003
--------- ----------
(MILLIONS)
Net income (loss) ...................................................... $ 9.9 $ (814.5)
Other comprehensive income (loss):
Unrealized losses on securities..................................... - (4.2)
Net realized losses on securities................................... 3.0 -
Unrealized losses on derivative instruments......................... (184.6) (184.1)
Net reclassification into earnings of derivative instrument losses.. 46.7 15.3
Foreign currency translation adjustments............................ (5.3) 24.7
Minimum pension liability adjustment................................ .7 -
--------- ---------
Other comprehensive loss before taxes............................... (139.5) (148.3)
Income tax benefit on other comprehensive loss...................... 51.4 66.2
--------- ---------
Other comprehensive loss................................................ (88.1) (82.1)
--------- ---------
Comprehensive loss...................................................... $ (78.2) $ (896.6)
========= =========
99.3-22
Notes (Continued)
13. 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.
Since May 1995, an entity within our Midstream segment has operated
production area facilities owned by entities within our Gas Pipeline segment.
These regulated gas gathering assets have been operated pursuant to the terms of
an operating agreement. Effective June 1, 2004, and due in part to FERC Order
2004, the operating agreement was terminated and management and decision-making
control transferred to the 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.
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).
99.3-23
Notes (Continued)
13. SEGMENT DISCLOSURES (CONTINUED)
EXPLORATION MIDSTREAM
GAS & GAS &
POWER PIPELINE PRODUCTION LIQUIDS OTHER ELIMINATIONS TOTAL
----- -------- ---------- ------- ----- ------------ -----
(MILLIONS)
THREE MONTHS ENDED MARCH 31, 2004
Segment revenues:
External $ 2,103.9 $ 355.3 $ (14.8) $ 618.3 $ 2.8 $ - $ 3,065.5
Internal 170.9 3.7 180.0 9.0 9.8 (373.4) -
---------- ------- -------- ------- ------- --------- ----------
Total segment revenues 2,274.8 359.0 165.2 627.3 12.6 (373.4) 3,065.5
---------- ------- -------- ------- ------- --------- ----------
Less intercompany interest rate
swap loss (21.6) - - - - 21.6 -
---------- ------- -------- ------- ------- --------- ----------
Total revenues $ 2,296.4 $ 359.0 $ 165.2 $ 627.3 $ 12.6 $ (395.0) $ 3,065.5
========== ======= ======== ======= ======= ========= ==========
Segment profit (loss) $ (32.0) $ 147.4 $ 51.5 $ 107.6 $ (8.7) $ - $ 265.8
Less:
Equity earnings .7 3.8 2.9 4.2 - - 11.6
Loss from investments - (.3) - (.2) (6.5) - (7.0)
Intercompany interest rate swap
loss (21.6) - - - - - (21.6)
---------- ------- -------- ------- ------- -------- ----------
Segment operating income (loss) $ (11.1) $ 143.9 $ 48.6 $ 103.6 $ (2.2) $ - 282.8
---------- ------- -------- ------- ------- -------- ----------
General corporate expenses (32.0)
----------
Consolidated operating income $ 250.8
==========
THREE MONTHS ENDED MARCH 31, 2003
Segment revenues:
External $ 3,588.0 $ 332.8 $ (7.1) $ 847.9 $ 14.5 $ - $ 4,776.1
Internal 187.6 6.8 251.0 17.5 13.5 (476.4) -
---------- ------- -------- ------- ------- --------- ----------
Total segment revenues 3,775.6 339.6 243.9 865.4 28.0 (476.4) 4,776.1
---------- ------- -------- ------- ------- --------- ----------
Less intercompany interest rate
swap loss (5.9) - - - - 5.9 -
---------- ------- -------- ------- ------- --------- ----------
Total revenues $ 3,781.5 $ 339.6 $ 243.9 $ 865.4 $ 28.0 $ (482.3) $ 4,776.1
========== ======= ======== ======= ======= ========= ==========
Segment profit (loss) $ (137.0) $ 150.3 $ 113.8 $ 112.8 $ 4.8 $ - $ 244.7
Less:
Equity earnings (loss) (.6) 1.8 2.1 (2.6) 3.7 - 4.4
Intercompany interest rate swap
loss (5.9) - - - - - (5.9)
---------- ------- -------- ------- ------- -------- ----------
Segment operating income (loss) $ (130.5) $ 148.5 $ 111.7 $ 115.4 $ 1.1 $ - 246.2
---------- ------- -------- ------- ------- -------- ----------
General corporate expenses (22.9)
----------
Consolidated operating income $ 223.3
==========
TOTAL ASSETS
-----------------------------------
MARCH 31, 2004 DECEMBER 31, 2003
-------------- -----------------
(MILLIONS)
Power.............................................................. $ 10,197.7 $ 8,732.9
Gas Pipeline....................................................... 7,312.6 7,314.3
Exploration & Production........................................... 5,372.5 5,347.4
Midstream Gas & Liquids............................................ 4,021.1 3,990.3
Other.............................................................. 5,700.2 6,928.7
Eliminations....................................................... (5,323.1) (6,078.2)
----------- -----------
27,281.0 26,235.4
Discontinued operations............................................ 509.2 786.4
----------- -----------
Total $ 27,790.2 $ 27,021.8
=========== ===========
14. 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.
99.3-24
Notes (Continued)
15. SUBSEQUENT EVENTS
NOTES PAYABLE AND LONG-TERM DEBT
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. 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.
In August 2004, we expanded our three-year, $1 billion secured revolving
credit facility by an additional $275 million.
Upon entering into the new $1 billion secured revolving credit facility on
May 3, 2004 (see Note 10), we terminated the $800 million revolving and letter
of credit facility which we entered into in June 2003.
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.
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.
ENVIRONMENTAL MATTERS
As part of our June 17, 2003 sale of Williams Energy Partners (see Note 2),
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.
ASSET SALES
On July 28, 2004, we closed the sale of the Canadian straddle plants for
approximately $544 million in U.S. funds, including amounts paid to our
subsidiaries for amounts previously due from the straddle plants. We expect to
recognize a pre-tax gain of approximately $190 million on the sale in
third-quarter 2004.
OTHER LEGAL MATTERS
As discussed in Note 11, 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.
99.3-25
Notes (Continued)
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.
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. 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.
99.3-26