UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
( X ) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2003
------------------------------------------------
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
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Commission file number 1-4174
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THE WILLIAMS COMPANIES, INC.
- --------------------------------------------------------------------------------
(Exact name of registrant as specified in its charter)
DELAWARE 73-0569878
------------------------ -----------------------------------
(State of Incorporation) (IRS Employer Identification Number)
ONE WILLIAMS CENTER
TULSA, OKLAHOMA 74172
--------------------------------------- --------------
(Address of principal executive office) (Zip Code)
Registrant's telephone number: (918)573-2000
------------------------
NO CHANGE
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Former name, former address and former fiscal year, if changed
since last report.
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes X No
----- -----
Indicate by check mark whether the registrant is an accelerated filer
(as defined in Rule 12b-2 of the Exchange Act). Yes X No
---- -----
Indicate the number of shares outstanding of each of the issuer's
classes of common stock as of the latest practicable date.
Class Outstanding at April 30, 2003
------------------------------ --------------------------------
Common Stock, $1 par value 517,719,805 Shares
The Williams Companies, Inc.
Index
<Table>
<Caption>
Part I. Financial Information Page
----
Item 1. Financial Statements
Consolidated Statement of Operations--Three Months Ended March 31, 2003 and 2002 2
Consolidated Balance Sheet--March 31, 2003 and December 31, 2002 3
Consolidated Statement of Cash Flows--Three Months Ended March 31, 2003 and 2002 4
Notes to Consolidated Financial Statements 5
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations 30
Item 3. Quantitative and Qualitative Disclosures about Market Risk 46
Item 4. Controls and Procedures 47
Part II. Other Information 48
Item 1. Legal Proceedings
Item 6. Exhibits and Reports on Form 8-K
</Table>
Certain matters discussed in this report, excluding historical information,
include forward-looking statements - statements that discuss Williams' expected
future results based on current and pending business operations. Williams makes
these forward-looking statements in reliance on the safe harbor protections
provided under the Private Securities Litigation Reform Act of 1995.
Forward-looking statements can be identified by words such as
"anticipates," "believes," "expects," "planned," "scheduled," "could,"
"continues," "estimates," "forecasts," "might," "potential," "projects" or
similar expressions. Although Williams believes these forward-looking statements
are based on reasonable assumptions, statements made regarding future results
are subject to a number of assumptions, uncertainties and risks that may cause
future results to be materially different from the results stated or implied in
this document. Additional information about issues that could lead to material
changes in performance is contained in The Williams Companies, Inc.'s 2002 Form
10-K.
The Williams Companies, Inc.
Consolidated Statement of Operations
(Unaudited)
<Table>
<Caption>
Three months
(Dollars in millions, except per-share amounts) ended March 31,
- ----------------------------------------------- ----------------------------
2003 2002*
------------ ------------
Revenues:
Energy Marketing & Trading $ 3,781.5 $ 340.9
Gas Pipeline 406.4 384.0
Exploration & Production 266.4 227.7
Midstream Gas & Liquids 1,133.2 400.0
Williams Energy Partners 116.7 92.1
Petroleum Services 239.7 187.5
Other 14.0 16.9
Intercompany eliminations (597.7) (27.1)
------------ ------------
Total revenues 5,360.2 1,622.0
------------ ------------
Segment costs and expenses:
Costs and operating expenses 4,847.7 816.7
Selling, general and administrative expenses 149.4 166.1
Other (income) expense - net 113.1 (1.0)
------------ ------------
Total segment costs and expenses 5,110.2 981.8
------------ ------------
General corporate expenses 22.9 38.2
------------ ------------
Operating income (loss):
Energy Marketing & Trading (130.5) 273.0
Gas Pipeline 92.9 159.8
Exploration & Production 124.0 106.7
Midstream Gas & Liquids 110.1 52.7
Williams Energy Partners 35.4 26.9
Petroleum Services 18.5 22.6
Other (0.4) (1.5)
General corporate expenses (22.9) (38.2)
------------ ------------
Total operating income 227.1 602.0
Interest accrued (372.8) (210.8)
Interest capitalized 12.1 5.4
Interest rate swap income (loss) (2.8) 10.2
Investing income (loss) 48.0 (215.8)
Minority interest in income and preferred returns
of consolidated subsidiaries (16.1) (15.1)
Other income (expense) - net 22.5 (4.5)
------------ ------------
Income (loss) from continuing operations before income taxes and
cumulative effect of change in accounting principles (82.0) 171.4
Provision (benefit) for income taxes (24.3) 73.0
------------ ------------
Income (loss) from continuing operations (57.7) 98.4
Income from discontinued operations 4.5 9.3
------------ ------------
Income (loss) before cumulative effect of change in accounting principles (53.2) 107.7
Cumulative effect of change in accounting principles (761.3) --
------------ ------------
Net income (loss) (814.5) 107.7
Preferred stock dividends 6.8 69.7
------------ ------------
Income (loss) applicable to common stock $ (821.3) $ 38.0
============ ============
Basic and diluted earnings (loss) per common share:
Income (loss) from continuing operations $ (.13) $ .05
Income from discontinued operations .01 .02
------------ ------------
Income (loss) before cumulative effect of change in accounting principles (.12) .07
Cumulative effect of change in accounting principles (1.47) --
------------ ------------
Net income (loss) $ (1.59) $ .07
============ ============
Basic weighted-average shares (thousands) 517,652 519,224
Diluted weighted-average shares (thousands) 517,652 521,240
Cash dividends per common share $ .01 $ .20
</Table>
*Certain amounts have been reclassified as described in Note 2 of Notes to
Consolidated Financial Statements.
See accompanying notes.
2
The Williams Companies, Inc.
Consolidated Balance Sheet
(Unaudited)
<Table>
<Caption>
(Dollars in millions, except per-share amounts) March 31, December 31,
- ---------------------------------------------- 2003 2002
------------ ------------
ASSETS
Current assets:
Cash and cash equivalents $ 1,501.1 $ 1,728.3
Restricted cash 323.1 102.8
Accounts and notes receivable less allowance of $115.6 ($113.2 in 2002) 2,589.4 2,524.4
Inventories 383.4 443.1
Energy risk management and trading assets -- 296.7
Derivative assets 7,772.8 5,024.3
Margin deposits 853.5 804.8
Assets of discontinued operations 205.9 981.3
Deferred income taxes 572.9 569.2
Other current assets and deferred charges 410.3 411.2
------------ ------------
Total current assets 14,612.4 12,886.1
Restricted cash 216.5 188.3
Investments 1,511.0 1,475.6
Property, plant and equipment, at cost 19,036.6 19,039.7
Less accumulated depreciation and depletion (4,359.5) (4,322.0)
------------ ------------
14,677.1 14,717.7
Energy risk management and trading assets -- 1,821.6
Derivative assets 2,415.2 1,865.1
Goodwill 1,082.5 1,082.5
Other assets and deferred charges 927.6 951.6
------------ ------------
Total assets $ 35,442.3 $ 34,988.5
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Notes payable $ 967.6 $ 934.8
Accounts payable 1,927.3 2,027.5
Accrued liabilities 1,377.3 1,546.6
Liabilities of discontinued operations 124.4 304.1
Energy risk management and trading liabilities -- 244.4
Derivative liabilities 7,807.5 5,168.3
Long-term debt due within one year 2,304.5 1,082.8
------------ ------------
Total current liabilities 14,508.6 11,308.5
Long-term debt 10,491.1 11,896.4
Deferred income taxes 2,799.5 3,353.6
Energy risk management and trading liabilities -- 680.9
Derivative liabilities 2,023.0 1,209.8
Other liabilities and deferred income 1,036.9 1,066.6
Contingent liabilities and commitments (Note 11)
Minority interests in consolidated subsidiaries 430.3 423.7
Stockholders' equity:
Preferred stock, $1 per share par value, 30 million shares authorized, 1.5
million issued in 2003 and 2002 271.3 271.3
Common stock, $1 per share par value, 960 million shares authorized,
520.8 million issued in 2003, 519.9 million issued in 2002 520.8 519.9
Capital in excess of par value 5,186.6 5,177.2
Accumulated deficit (1,710.8) (884.3)
Accumulated other comprehensive income (loss) (48.3) 33.8
Other (28.1) (30.3)
------------ ------------
4,191.5 5,087.6
Less treasury stock (at cost), 3.2 million shares of common stock in
2003 and 2002 (38.6) (38.6)
------------ ------------
Total stockholders' equity 4,152.9 5,049.0
------------ ------------
Total liabilities and stockholders' equity $ 35,442.3 $ 34,988.5
============ ============
</Table>
See accompanying notes.
3
The Williams Companies, Inc.
Consolidated Statement of Cash Flows
(Unaudited)
<Table>
<Caption>
(Millions) Three months ended March 31,
----------------------------
2003 2002*
------------ ------------
OPERATING ACTIVITIES:
Income (loss) from continuing operations $ (57.7) $ 98.4
Adjustments to reconcile to cash provided (used) by operations:
Depreciation, depletion and amortization 198.4 178.8
Provision (benefit) for deferred income taxes (35.2) 59.2
Payments of guarantees and payment obligations related to WilTel -- (753.9)
Provision for loss on property and other assets 129.5 9.3
Provision for uncollectible accounts:
WilTel -- 232.0
Other 6.0 1.7
Minority interest in income and preferred returns of consolidated subsidiaries 16.1 15.1
Amortization and taxes associated with stock-based awards 11.1 8.0
Accrual for fixed rate interest included in RMT note payable 33.0 --
Amortization of deferred set-up fee and fixed rate interest on the RMT note payable 64.3 --
Cash provided (used) by changes in current assets and liabilities:
Restricted cash 2.5 --
Accounts and notes receivable (101.6) (132.3)
Inventories 18.8 (75.5)
Margin deposits (48.7) (43.1)
Other current assets and deferred charges (65.1) (103.3)
Accounts payable (61.8) 114.8
Accrued liabilities (168.2) (300.1)
Changes in current derivative and energy risk management and trading 1,083.3 58.3
assets and liabilities
Changes in noncurrent derivative and energy risk management and trading assets
and liabilities (1,094.2) (347.0)
Other, including changes in noncurrent assets and liabilities (33.2) (38.0)
------------ ------------
Net cash used by operating activities of continuing operations (102.7) (1,017.6)
Net cash provided by operating activities of discontinued operations 6.0 19.7
------------ ------------
Net cash used by operating activities (96.7) (997.9)
------------ ------------
FINANCING ACTIVITIES:
Payments of notes payable (.1) (1,337.5)
Proceeds from long-term debt 176.5 3,083.7
Payments of long-term debt (360.5) (277.1)
Proceeds from issuance of common stock -- 13.1
Dividends paid (12.0) (103.5)
Proceeds from sale of limited partner units of consolidated partnership -- 272.3
Payments of debt issuance costs (6.9) (95.4)
Payments/dividends to minority and preferred interests (9.5) (12.8)
Changes in restricted cash (250.6) --
Changes in cash overdrafts (31.6) (6.2)
Other--net -- (.4)
------------ ------------
Net cash provided (used) by financing activities of continuing operations (494.7) 1,536.2
Net cash used by financing activities of discontinued operations (71.6) (6.8)
------------ ------------
Net cash provided (used) by financing activities (566.3) 1,529.4
------------ ------------
INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures (244.4) (386.4)
Proceeds from dispositions 43.6 85.5
Purchases of investments/advances to affiliates (5.7) (150.0)
Proceeds from sales of businesses 636.2 423.2
Other--net 4.1 (8.4)
------------ ------------
Net cash provided (used) by investing activities of continuing operations 433.8 (36.1)
Net cash used by investing activities of discontinued operations (5.2) (93.5)
------------ ------------
Net cash provided (used) by investing activities 428.6 (129.6)
------------ ------------
Increase (decrease) in cash and cash equivalents (234.4) 401.9
Cash and cash equivalents at beginning of period** 1,736.0 1,301.1
------------ ------------
Cash and cash equivalents at end of period** $ 1,501.6 $ 1,703.0
============ ============
</Table>
* Amounts have been restated or reclassified as described in Note 2 of Notes
to Consolidated Financial Statements.
** Includes cash and cash equivalents of discontinued operations of $.5
million, $7.7 million, $23.2 million and $42.6 million at March 31, 2003,
December 31, 2002, March 31, 2002 and December 31, 2001, respectively.
See accompanying notes.
4
The Williams Companies, Inc.
Notes to Consolidated Financial Statements
(Unaudited)
1. General
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Company outlook
As discussed in The Williams Companies, Inc.'s (Williams or the Company)
Form 10-K for the year ended December 31, 2002, events in 2002 and the last half
of 2001 significantly impacted the Company's operations, both past and future.
On February 20, 2003, Williams outlined its planned business strategy for the
next several years which management believes to be a comprehensive response to
the events which have impacted the energy sector and Williams during 2002. The
plan focuses on retaining a strong, but smaller, portfolio of natural gas
businesses and bolstering Williams' liquidity through more asset sales, limited
levels of financing at the Williams and subsidiary levels and additional
reductions in its operating costs. The plan is designed to provide Williams with
a clear strategy to address near-term and medium-term liquidity issues and
further de-leverage the company with the objective of returning to investment
grade status by 2005, while retaining businesses with favorable returns and
opportunities for growth in the future. As part of this plan, Williams expects
to generate proceeds, net of related debt, of nearly $4 billion from asset sales
during 2003 and first-quarter 2004. During first-quarter 2003, Williams had
received $679.8 million in net proceeds from the sales of assets and businesses,
including the retail travel centers and the Midsouth refinery. In April 2003,
Williams announced that it had signed definitive agreements for the sales of the
Texas Gas pipeline system, Williams' general partnership interest and limited
partner investment in Williams Energy Partners, and certain natural gas
exploration and production properties in Kansas, Colorado, New Mexico and Utah
(see Note 14). All of these newly announced sales are expected to close in the
second quarter. Sales anticipated to close in the second quarter are expected to
generate net proceeds of approximately $2 billion. As previously announced, the
Company intends to reduce its commitment to the Energy Marketing & Trading
business, which could be realized by entering into a joint venture with a third
party or through the sale of a portion or all of the marketing and trading
portfolio. Through March 31, 2003, Energy Marketing & Trading has sold or
announced sales of contracts totaling approximately $215 million.
As of March 31, 2003, the Company has maturing notes payable and long-term
debt through first-quarter 2004 totaling approximately $3.5 billion, which
includes certain contractual fees and deferred interest associated with an
underlying debt. The Company anticipates the cash on hand, the asset sales
mentioned above, additional asset sales, and refinancing of a portion of these
obligations will enable the Company to meet its liquidity needs over that
period.
Other
The accompanying interim consolidated financial statements of Williams 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 Williams' Annual Report on Form 10-K. 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 Williams' management, are necessary to present fairly its
financial position at March 31, 2003, and its results of operations and cash
flows for the three months ended March 31, 2003 and 2002.
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.
5
Notes (Continued)
2. Basis of presentation
- --------------------------------------------------------------------------------
In accordance with the provisions related to discontinued operations within
Statement of Financial Accounting Standard (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 6):
o The Colorado soda ash mining operations, previously part of the
International segment
o Bio-energy operations, previously part of the Petroleum Services segment
o Refining and marketing operations in the Midsouth, including the Midsouth
refinery, previously part of the Petroleum Services segment
o Retail travel centers concentrated in the Midsouth, previously part of the
Petroleum Services segment
o Kern River Gas Transmission (Kern River), previously one of Gas Pipeline's
segments
o Central natural gas pipeline, previously one of Gas Pipeline's segments
o Two natural gas liquids pipeline systems, Mid-American Pipeline and
Seminole Pipeline, previously part of the Midstream Gas & Liquids segment
Unless indicated otherwise, the information in the Notes to the
Consolidated Financial Statements relates to the continuing operations of
Williams. Williams expects that other components of its business will be
classified as discontinued operations in the future as those operations are sold
or classified as held-for-sale.
Certain other statement of operations, balance sheet and cash flow amounts
have been reclassified to conform to the current classifications.
3. Changes in accounting policies and cumulative effect of change in accounting
principles
- --------------------------------------------------------------------------------
Energy commodity risk management and trading activities and revenues
Effective January 1, 2003, Williams adopted Emerging Issues Task Force
(EITF) Issue No. 02-3, "Issues Related to Accounting for Contracts Involved in
Energy Trading and Risk Management Activities." The Issue rescinded EITF Issue
No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk
Management Activities." Issue No. 02-3 precludes fair value accounting for
energy trading contracts that are not derivatives pursuant to Statement of
Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative
Instruments and Hedging Activities," and for commodity trading inventories. As a
result of initial application of this Issue, Williams reduced energy risk
management and trading assets (including inventories) by $2,159.2 million,
energy risk management and trading liabilities by $925.3 million and net income
by $762.5 million (net of a $471.4 million benefit for income taxes). Of this
amount, approximately $755 million relates to Energy Marketing & Trading's
portion with the remainder relating to Midstream Gas & Liquids. The
reduction of net income is reported as a cumulative effect of a change in
accounting principle. The change results 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.
The power tolling, load serving, transportation and storage contracts are
now accounted for on an accrual basis. Under this model, revenues for sales of
products are recognized in the period of delivery. Revenues and costs associated
with these non-derivative energy contracts and other non-derivative activities
are reflected gross in revenues and costs and operating expenses in the
Consolidated Statement of Operations beginning January 1, 2003. This change
significantly impacts the presentation of revenues and costs and operating
expenses. Physical commodity inventories previously reflected at fair value are
now stated at average cost, not in excess of market. Derivative energy contracts
utilized for trading purposes continue to be reflected at fair value, and gains
and losses due to changes in fair value of these derivatives are reflected net
in revenues.
6
Notes (Continued)
Asset retirement obligations
Additionally, effective January 1, 2003, Williams adopted SFAS No. 143,
"Accounting for Asset Retirement Obligations." This Statement requires that the
fair value of a liability for an asset retirement obligation be recognized in
the period in which it is incurred if a reasonable estimate of fair value can be
made, and that the associated asset retirement costs be capitalized as part of
the carrying amount of the long-lived asset. The Statement also amends SFAS No.
19, "Financial Accounting and Reporting by Oil and Gas Producing Companies." As
required by the new standard, Williams recorded liabilities equal to the present
value of expected future asset retirement obligations at January 1, 2003. The
obligations relate to producing wells, offshore platforms, underground storage
caverns and gas gathering well connections. At the end of the useful life of
each respective asset, Williams is legally obligated to plug both producing
wells and storage caverns and remove any related surface equipment, to dismantle
offshore platforms, and to cap certain gathering pipelines at the wellhead
connection and remove any related surface equipment. The liabilities are
partially offset by increases in property, plant and equipment, net of
accumulated depreciation, recorded as if the provisions of the Statement had
been in effect at the date the obligation was incurred. As a result of the
adoption of SFAS No. 143, Williams recorded a long-term liability of $33.4
million; property, plant and equipment, net of accumulated depreciation, of
$24.8 million and a credit to earnings of $1.2 million (net of a $.1 million
benefit for income taxes) reflected as a cumulative effect of a change in
accounting principle. Williams also recorded a $9.7 million regulatory asset for
retirement costs of dismantling offshore platforms expected to be recovered
through regulated rates. In connection with adoption of SFAS No. 143, Williams
changed its 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 amounts discussed above. Williams has not recorded
liabilities for pipeline transmission assets, processing and refining assets,
and gas gathering systems pipelines. A reasonable estimate of the fair value of
the retirement obligations for these assets cannot be made as the remaining life
of these assets is not currently determinable.
Had the Statement been adopted at the beginning of 2002, the impact to
Williams' income from continuing operations and net income would have been
immaterial. There would have been no impact on earnings per share.
4. Asset impairments and other loss accruals
- --------------------------------------------------------------------------------
In February 2003, Williams announced its intentions to sell its Texas Gas
pipeline system as part of the company's ongoing strategy to improve its
financial position (see Note 1). A reserve auction process was initiated for the
sale of the Texas Gas pipeline system during first-quarter 2003. This business
did not meet the criteria to be classified as held for sale at March 31, 2003,
and was evaluated for recoverability on a held-for-use basis pursuant to SFAS
No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." A
$109 million impairment charge was recorded in first-quarter 2003 reflecting the
excess of the carrying cost of the long-lived assets over management's estimate
of fair value, and is reported in other (income) expense - net within segment
costs and expenses as part of the Gas Pipeline segment. Fair value was based on
management's assessment of the expected sales price pursuant to an agreement to
sell the pipeline system for $795 million in cash, which was announced April 14,
2003.
The company is currently engaged in negotiations to sell its Alaska
refinery and related assets. During first-quarter 2003, management revised its
assessment of the estimated fair value of these assets, reflective of recent
information obtained through continuing sales negotiations using a probability
weighted approach. As a result, an additional impairment charge of $8 million
was recognized in first-quarter 2003 in other (income) expense - net within
segment costs and expenses as part of the Petroleum Services segment.
Investing income (loss) for 2003 includes a $12 million impairment of the
investment in Algar Telecom S.A. Negotiations for the sale of this investment
have resulted in a determination that fair value is less than carrying value,
representing an other than temporary decline in value. Fair value was based on
management's assessment of the expected sales price pursuant to terms of a
completed memorandum of understanding for the sale of the investment.
Investing income (loss) for 2002 includes a $232 million loss provision
related to the estimated recoverability of receivables from Wiltel
Communications Group, Inc. (formerly Williams Communications Group, Inc.).
7
Notes (Continued)
5. Provision (benefit) for income taxes
- --------------------------------------------------------------------------------
The provision (benefit) for income taxes from continuing operations
includes:
Three months ended
March 31,
--------------------
(Millions) 2003 2002
-------- --------
Current:
Federal $ 6.2 $ 7.6
State 4.7 2.6
Foreign -- 3.6
-------- --------
10.9 13.8
Deferred:
Federal (26.6) 43.7
State (6.4) 8.8
Foreign (2.2) 6.7
-------- --------
(35.2) 59.2
-------- --------
Total provision (benefit) $ (24.3) $ 73.0
======== ========
The effective income tax rate for the three months ended March 31, 2003, is
less than the federal statutory rate (less tax benefit) largely due to the
effect of state income taxes associated primarily with jurisdictions in which
Williams files separate returns.
The effective income tax rate for the three months ended March 31, 2002, is
greater than the federal statutory rate due primarily to the effect of state
income taxes.
6. Discontinued operations
- --------------------------------------------------------------------------------
During 2002, Williams began the process of selling assets and/or businesses
to address liquidity issues. The businesses discussed below represent components
of Williams that have been sold or approved for sale by the board of directors
as of March 31, 2003; therefore, their results of operations (including any
impairments, gains or losses), financial position and cash flows have been
reflected in the consolidated financial statements and notes as discontinued
operations.
Summarized results of discontinued operations for the three months ended
March 31, 2003 and 2002 are as follows:
<Table>
<Caption>
Three months ended
March 31,
--------------------
(Millions) 2003 2002
-------- --------
Revenues $ 612.9 $ 896.1
Income from discontinued operations
before income taxes and cumulative
effect of change in accounting
principle $ 6.3 $ 52.5
(Impairments) and gain (loss) on
sales - net (.3) (38.1)
Provision for income taxes (1.5) (5.1)
-------- --------
Total income from discontinued
operations $ 4.5 $ 9.3
======== ========
</Table>
8
Notes (Continued)
Summarized assets and liabilities of discontinued operations reflected as
current assets and current liabilities in the Consolidated Balance Sheet as of
March 31, 2003 and December 31, 2002, are as follows:
<Table>
<Caption>
March 31, December 31,
(Millions) 2003 2002
------------ ------------
Total current assets $ 156.9 $ 441.6
------------ ------------
Property, plant and equipment - net 39.3 520.5
Other non-current assets 9.7 19.2
------------ ------------
Total non-current assets 49.0 539.7
------------ ------------
Total assets $ 205.9 $ 981.3
------------ ------------
Long-term debt due within one year $ .1 $ 68.6
Other current liabilities 111.0 217.3
------------ ------------
Total current liabilities 111.1 285.9
------------ ------------
Long-term debt -- 8.5
Other non-current liabilities 13.3 9.7
------------ ------------
Total non-current liabilities 13.3 18.2
------------ ------------
Total liabilities $ 124.4 $ 304.1
============ ============
</Table>
HELD FOR SALE AT MARCH 31, 2003
Soda ash operations
In March 2002, Williams announced its intentions to sell its soda ash
mining facility located in Colorado. During third-quarter 2002, Williams' board
of directors approved a plan authorizing management to negotiate and facilitate
a sale of its interest in the soda ash operations pursuant to terms of a
proposed sales agreement. The soda ash facility was previously written-down to
its estimated fair value less cost to sell at December 31, 2002. This estimate
was reflective of terms of the negotiations to sell the operations. During 2003,
further sale negotiations provided new information regarding estimated fair
value. As a result, an additional impairment charge of $5 million was recognized
in first-quarter 2003 and is included in (impairments) and gain (loss) on sales
in the preceding table. The soda ash operations were part of the previously
reported International segment.
Bio-energy facilities
Williams' bio-energy operations have been identified as assets not related
to the new more narrowly focused business. During fourth-quarter 2002, Williams'
board of directors approved a plan authorizing management to negotiate and
facilitate a sale pursuant to terms of a proposed sales agreement. The December
31, 2002 carrying value reflected the estimated fair value less cost to sell. On
February 20, 2003, Williams announced it had signed a definitive agreement to
sell these operations to a new company formed by Morgan Stanley Capital
Partners. This sale is expected to close during second-quarter 2003. These
operations were part of the Petroleum Services segment.
2003 COMPLETED TRANSACTIONS
Midsouth refinery and related assets
On March 4, 2003, Williams completed the sale of its refinery and other
related operations located in Memphis, Tennessee to Premcor, Inc. for
approximately $455 million in cash. A gain on sale of $4.7 million was
recognized when the asset was sold and is included in (impairments) and gain
(loss) on sales in the preceding table. These assets were previously
written-down by $240.8 million to their estimated fair value less cost to sell
at December 31, 2002. These operations were part of the Petroleum Services
segment.
9
Notes (Continued)
Williams travel centers
On February 27, 2003, Williams completed the sale of the travel centers to
Pilot Travel Centers LLC for approximately $189 million in cash. The December
31, 2002 carrying value reflected the estimated fair value less cost to sell. No
significant gain or loss was recognized on the sale. These operations were part
of the Petroleum Services segment.
2002 COMPLETED TRANSACTIONS
Kern River
On March 27, 2002, Williams completed the sale of its Kern River pipeline
for $450 million in cash and the assumption by the purchaser of $510 million in
debt. As part of the agreement, $32.5 million of the purchase price was
contingent upon Kern River receiving a certificate from the FERC to construct
and operate a future expansion. This certificate was received in July 2002, and
the contingent payment plus interest was recognized as income from discontinued
operations in third-quarter 2002. Included as a component of (impairments) and
gain (loss) on sales in the preceding table is a pre-tax loss of $38.1 million
for the three months ended March 31, 2002. Kern River was a segment within Gas
Pipeline.
Central
On November 15, 2002, Williams completed the sale of its Central natural
gas pipeline, for $380 million in cash and the assumption by the purchaser of
$175 million in debt. Central was a segment within Gas Pipeline.
Mid-America and Seminole Pipelines
On August 1, 2002, Williams completed the sale of its 98 percent interest
in Mid-America Pipeline and 98 percent of its 80 percent ownership interest in
Seminole Pipeline for $1.2 billion. The sale generated net cash proceeds of
$1.15 billion. These assets were part of the Midstream Gas & Liquids segment.
10
Notes (Continued)
7. Earnings (loss) per share
- --------------------------------------------------------------------------------
Basic and diluted earnings (loss) per common share are computed as follows:
<Table>
<Caption>
(Dollars in millions, except per-share Three months ended
amounts; shares in thousands) March 31,
- --------------------------------------------- ----------------------------
2003 2002
------------ ------------
Income (loss) from continuing operations $ (57.7) $ 98.4
Convertible preferred stock dividends (6.8) (69.7)
------------ ------------
Income (loss) from continuing operations
available to common stockholders
for basic and diluted earnings per share $ (64.5) $ 28.7
------------ ------------
Basic weighted-average shares
Effect of dilutive securities: 517,652 519,224
Stock options -- 2,016
------------ ------------
Diluted weighted-average shares 517,652 521,240
------------ ------------
Earnings (loss) per share from continuing operations:
Basic $ (.13) $ .05
Diluted $ (.13) $ .05
============ ============
</Table>
For the three months ended March 31, 2003, diluted earnings (loss) per
share is the same as the basic calculation. The inclusion of any stock options,
convertible preferred stock and unvested deferred stock would be antidilutive as
Williams reported a loss from continuing operations for this period. As a
result, 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 for the three months ended March 31, 2003.
For the three months ended March 31, 2002, approximately .8 million
weighted-average shares related to the assumed conversion of 9 7/8 percent
cumulative convertible preferred stock have been excluded from the computation
of diluted earnings per common share. Inclusion of these shares would be
antidilutive.
11
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" 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 and earnings per share if the company had
applied the fair value recognition provisions of SFAS No. 123 "Accounting for
Stock-Based Compensation."
<Table>
<Caption>
Three months ended March 31,
(Millions) 2003 2002
------------ ------------
Net income (loss), as reported $ (814.5) $ 107.7
Add: Stock-based employee compensation included
in the Consolidated Statement of Operations, net
of related tax effects 10.6 3.8
Deduct: Stock-based employee compensation expense
determined under fair value based method for all
awards, net of related tax effects (14.7) (7.3)
------------ ------------
Pro forma net income (loss) $ (818.6) $ 104.2
============ ============
Earnings (loss) per share:
Basic-as reported $ (1.59) $ .07
Basic-pro forma $ (1.59) $ .07
Diluted-as reported $ (1.59) $ .07
Diluted-pro forma $ (1.59) $ .07
============ ============
</Table>
Pro forma amounts for 2003 include compensation expense from Williams
awards made in 2002 and 2001. Pro forma amounts for 2002 include compensation
expense from certain Williams awards made in 1999 and compensation expense from
Williams' awards made in 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.
12
Notes (Continued)
9. Inventories
- --------------------------------------------------------------------------------
Inventories at March 31, 2003 and December 31, 2002 are as follows:
<Table>
<Caption>
March 31, December 31,
(Millions) 2003 2002
------------ ------------
Raw materials:
Crude oil $ 31.1 $ 18.3
------------ ------------
31.1 18.3
Finished goods:
Refined products 68.3 73.6
Natural gas liquids 99.6 115.6
General merchandise 4.4 4.4
------------ ------------
172.3 193.6
Materials and supplies 104.6 105.8
Natural gas in underground
storage 75.4 125.4
------------ ------------
$ 383.4 $ 443.1
============ ============
</Table>
Effective January 1, 2003, Williams adopted EITF Issue No. 02-3, "Issues
Related to Accounting for Contracts Involved in Energy Trading and Risk
Management Activities" (see Note 3). As a result of initial application of this
Issue, Williams reduced natural gas in underground storage by $37 million,
refined products by $2.9 million and natural gas liquids by $1 million.
13
Notes (Continued)
10. Debt and banking arrangements
- --------------------------------------------------------------------------------
NOTES PAYABLE AND LONG-TERM DEBT
Notes payable and long-term debt at March 31, 2003 and December 31, 2002,
is as follows:
<Table>
<Caption>
Weighted-
Average
Interest March 31, December 31,
(Millions) Rate (1) 2003 2002
------------ ------------ ------------
Secured notes payable (2) 5.4% $ 967.6 $ 934.8
------------ ------------
Long-term debt:
Secured long-term debt
Revolving credit loans --% $ -- $ 81.0
Debentures, 9.9%, payable 2020 9.9 28.7 28.7
Notes, 7.725%-9.45%, payable through 2022 8.3 545.9 558.8
Notes, adjustable rate, payable through 2007 7.1 264.6 183.2
Other, payable 2003 6.7 15.1 20.9
Unsecured long-term debt
Debentures, 6.25%-10.25%, payable through 2031 7.4 1,548.6 1,548.2
Notes, 6.125%-9.25%, payable through 2032 (3) 7.8 9,675.2 9,500.5
Notes, adjustable rate, payable through 2004 5.3 494.7 759.9
Other, payable through 2006 5.6 130.9 158.1
Capital leases, payable through 2005 6.1 91.9 139.9
------------ ------------
12,795.6 12,979.2
Long-term debt due within one year (2,304.5) (1,082.8)
------------ ------------
Total long-term debt $ 10,491.1 $ 11,896.4
============ ============
</Table>
(1) At March 31, 2003.
(2) Interest rate for $954.6 million (RMT note payable) is based on the
Eurodollar rate plus 4 percent per annum. The principal balance includes
interest accruing to the note at a fixed rate of 14 percent compounded
quarterly.
(3) Includes $1.1 billion of 6.5 percent notes, payable 2007 subject to
remarketing in 2004 (FELINE PACS). If a remarketing is unsuccessful in 2004
and a second remarketing in February 2005 is unsuccessful as defined in the
offering document of the FELINE PACS, then Williams could exercise its
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
Williams common stock.
14
Notes (Continued)
REVOLVING CREDIT FACILITIES
Under the terms of Williams' revolving credit agreement (amended in July
2002, restated in October 2002, and amended in March 2003), Northwest Pipeline
and Transco have access to $400 million and Texas Gas Transmission has access to
$200 million, while Williams (Parent) has access to all unborrowed amounts.
Interest rates vary based on LIBOR plus an applicable margin (which varies with
Williams' senior unsecured credit ratings). During first-quarter 2003, Williams
completed asset sales which reduced the commitments from participating banks in
the revolving credit facility to $400 million. After 1) certain pre-existing
debt with a balance of $294.2 million at March 31, 2003, is paid off and
pre-existing letters of credit totaling $94.5 million at March 31, 2003, are
cash collateralized ($67.3 million is cash collateralized at March 31, 2003) and
2) in certain circumstances, the letter of credit facility (discussed below) is
collateralized, the commitments may be further reduced to zero as a result of
additional asset sales. No amounts were outstanding under this agreement at
March 31, 2003.
Changes to the revolving credit facility under the terms of the March 2003
amendment include: (i) a modified consolidated debt to consolidated net worth
plus consolidated debt financial covenant to maintain the threshold at 68
percent from March 30, 2003 through June 30, 2003 and 65 percent after June 30,
2003, (rather than reducing from 68 percent to 65 percent at March 30, 2003),
(ii) approval of additional asset sales, including the sales of Williams'
investments in Williams Energy Partners L.P., Texas Gas pipeline system,
Midstream Gas & Liquids' investments in four liquids pipelines and other
miscellaneous assets and (iii) exclusion of the convenience stores and terminals
from the Alaska assets pledged as collateral. At March 31, 2003, Williams' ratio
of consolidated debt to consolidated net worth plus consolidated debt as defined
in Williams' amended revolving credit facility was 65.1 percent. The ratio of
interest expense plus cash flow to interest expense, as defined in the
agreements, for the twelve months ended March 31, 2003, was 2.2. Failure to meet
the required covenants of the revolving credit facility could become an event of
default and could result in acceleration of amounts due under this facility and
other company debt obligations with similar covenants, or for which there are
certain provisions for cross-default in place.
In addition to the revolving credit facility discussed above, Williams
Energy Partners L.P. has an $85 million unsecured revolving credit facility with
no amounts outstanding at March 31, 2003.
LETTER OF CREDIT FACILITY -- $400 MILLION
Williams has a $400 million letter of credit facility that expires July
2003. Letters of credit totaling $383 million have been issued by the
participating financial institutions under this facility at March 31, 2003. As
of March 31, 2003, a total of $9.3 million letters of credit under this
agreement have been cash collateralized.
ISSUANCES AND RETIREMENTS
Significant long-term debt, including capital leases, issuances and
retirements, other than amounts under revolving credit agreements, for the three
months ended March 31, 2003 are as follows:
<Table>
<Caption>
Principal
Issue/Terms Due Date Amount
- ----------- ------------ ------------
(Millions)
Issuances of long-term debt in 2003:
8.125% senior notes 2010 $ 175.0
(Northwest Pipeline)
Retirements/prepayments of long-term debt in 2003:
Preferred interests 2003-2006 $ 139.0
Various capital leases 2005 48.0
Various notes, 8.55% - 9.45% 2003 13.0
Various notes, adjustable rate 2003-2004 154.1
</Table>
15
Notes (Continued)
11. Contingent liabilities and commitments
- --------------------------------------------------------------------------------
RATE AND REGULATORY MATTERS AND RELATED LITIGATION
Williams' 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 $11
million for potential refund as of March 31, 2003.
Williams Energy Marketing & Trading Company (Energy Marketing & Trading)
subsidiaries are engaged in power marketing in various geographic areas,
including California. Prices charged for power by Williams and other traders and
generators in California and other western states have been challenged in
various proceedings including those before the FERC. In December 2002, the FERC
issued an order which provided that, for the period between October 2, 2000 and
December 31, 2002, the FERC may order refunds from Williams and other similarly
situated companies if the FERC finds that the wholesale markets in California
are unable to produce competitive, just and reasonable prices or that market
power or other individual seller conduct is exercised to produce an unjust and
unreasonable rate. The judge issued his findings in the refund case on December
12, 2002. Under these findings, Williams' refund obligation to the California
Independent System Operator (ISO) is $192 million, excluding emissions costs and
interest. The judge found that Williams' refund obligation to the California
Power Exchange (PX) is $21.5 million, excluding interest. However, the judge
found that the ISO owes Williams $246.8 million, excluding interest, and that
the PX owes Williams $31.7 million, excluding interest, and $2.9 million in
charge backs. The judge's findings do not include the $18 million in emissions
costs that the judge found Williams is entitled to use as an offset to refund
liability, and the judge's refund amounts 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, Energy Marketing & Trading recorded a charge for refund
obligations of $37 million and recorded interest income related to amounts due
from the counterparties of $33 million. Pursuant to an order from the 9th
Circuit, FERC permitted the 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. Williams and other sellers submitted comments
to the additional evidence on March 20, 2003. The FERC is considering this
evidence and is expected to issue further guidance later this year.
In an order issued June 19, 2001, the FERC implemented a revised price
mitigation and market monitoring plan for wholesale power sales by all suppliers
of electricity, including Williams, in spot markets for a region that includes
California and ten other western states (the "Western Systems Coordinating
Council," or "WSCC"). In general, the plan, which was in effect from June 20,
2001 through September 30, 2002, established a market clearing price for spot
sales in all hours of the day that was based on the bid of the highest-cost
gas-fired California generating unit that was needed to serve the ISO's load.
When generation operating reserves fell below seven percent in California (a
"reserve deficiency period"), absent cost-based justification for a higher
price, the maximum price that Williams could charge for wholesale spot sales in
the WSCC was the market clearing price. When generation operating reserves rose
to seven percent or above in California, absent cost-based justification for a
higher price, Williams' maximum price was limited to 85 percent of the highest
hourly price that was in effect during the most recent reserve deficiency
period. This methodology initially resulted in a maximum price of $92 per
megawatt hour during non-emergency periods and $108 per megawatt hour during
emergency periods. These maximum prices remained unchanged throughout summer and
fall 2001. Revisions to the plan for the post-September 30, 2002, period were
provided on July 17, 2002, as discussed below.
On December 19, 2001, the FERC reaffirmed its June 19 order with certain
clarifications and modifications. It also altered the price mitigation
methodology for spot market transactions for the WSCC market for the winter 2001
season and set the period maximum price at $108 per megawatt hour through April
30, 2002. Under the order, this price would be subject to being recalculated
when the average gas price rises by a minimum factor of ten percent effective
for the following trading day, but in no event would the maximum price drop
below $108 per megawatt hour. The FERC also upheld a ten percent addition to the
price applicable to sales into California to reflect credit risk. On July 9,
2002, the ISO's operating reserve levels dropped below seven percent for a full
operating hour, during which the ISO declared a Stage 1 System Emergency
resulting in a new Market Clearing Price cap of $57.14/MWh under the FERC's
rules. On July 11, 2002, the FERC issued an order that the existing price
mitigation formula be replaced with a hard price cap of $91.87/MWh for spot
markets operated in the West (which is the level of price mitigation that
existed prior to the July 9, 2002 events that reduced the cap), to be effective
July 12, 2002. The cap expired September 30, 2002, but the cap was later
extended by FERC to October 30, 2002.
16
Notes (Continued)
On July 17, 2002, the FERC issued its first order on the California ISO's
proposed market redesign. Key elements of the order include (1) maintaining
indefinitely the current must-offer obligation across the West; (2) the adoption
of Automatic Mitigation Procedures (AMP) to identify and limit excessive bids
and local market power within California, (bids less than $91.87/MWh will not be
subject to AMP); (3) a West-wide spot market bid cap of $250/MWh, beginning
October 1, 2002, and continuing indefinitely; (4) a requirement that the ISO
expedite the following market design elements and requiring them to be filed by
October 21, 2002: (a) creation of an integrated day-ahead market; (b) ancillary
services market reforms; and (c) hour-ahead and real-time market reforms; and
(5) the development of locational marginal pricing (LMP). The FERC reaffirmed
these elements in an order issued October 9, 2002, with the following
clarification: (a) generators may bid above the ISO cap, but their bids cannot
set the market clearing price and they will be subject to justification and
refund, (b) if the market clearing price is projected to be above $91.87 per MWh
in any zone, automatic mitigation will be triggered in all zones, (c) the 10
percent creditworthiness adder will be removed effective October 31, 2002. On
January 17, 2003, FERC clarified that bids below $91.87 per MWh are not entitled
to a safe harbor from mitigation, and where a seller is subject to the
must-offer obligation but fails to submit a bid, the ISO may impose a proxy bid.
On October 31, 2002, FERC found that the ISO has not explained how it will treat
generators that are running at minimum load and dispatched for instructed
energy. On December 2, 2002, the ISO proposed to pay for energy at minimum load
the uninstructed energy price even when a unit is dispatched for instructed
energy. Williams protested on January 2, 2003, arguing that the ISO's proposal
fails to keep sellers whole.
In a separate but related proceeding, certain entities have also asked the
FERC to revoke Williams' authority to sell power from California-based
generating units at market-based rates, to limit Williams 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 California Public Utilities Commission (CPUC) filed a complaint with
the FERC on February 25, 2002, seeking to void or, alternatively, reform a
number of the long-term power purchase contracts entered into between the State
of California and several suppliers in 2001, including Energy Marketing &
Trading. The CPUC alleges that the contracts are tainted with the exercise of
market power and significantly exceed "just and reasonable" prices. The
California Electricity Oversight Board (CEOB) made a similar filing on February
27, 2002. The FERC set the complaint for hearing on April 25, 2002, but held the
hearing in abeyance pending settlement discussions before a FERC judge. The FERC
also ordered that the higher public interest test will apply to the contracts.
The FERC commented that the state has a very heavy burden to carry in proving
its case. On July 17, 2002, the FERC denied rehearing of the April 25, 2002,
order that set for hearing California's challenges to the long-term contracts
entered into between the state and several suppliers, including Energy Marketing
& Trading. The settlement discussions noted above have resulted in Williams
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 original contract contained only block energy sales. The
settlement does not extend to criminal matters or matters of willful fraud, but
will resolve civil complaints brought by the California Attorney General against
Williams that are discussed below and the State of California's refund claims
that are discussed above. Pursuant to the settlement, Williams also will provide
consideration of $147 million over eight years and six gas powered electric
turbines. In addition, the settlement is intended to resolve 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
Williams' motion for partial dismissal from the refund proceedings. The
dismissal affects Williams' refund obligations to the settling parties, but not
to other parties, such as investor-owned utilities. Pursuant to the settlement,
the CPUC and CEOB filed on January 13, 2003, a motion to withdraw their
complaints against Williams regarding the original block energy sales contract.
Private class action plaintiffs also executed the settlement. Various court
filings and approvals are necessary to make the settlement effective as to
plaintiffs and to terminate the class actions as to Williams.
On May 2, 2002, PacifiCorp filed a complaint against Energy Marketing &
Trading seeking relief from rates contained in three separate confirmation
agreements between PacifiCorp and Energy Marketing & Trading (known as the
Summer 2002 90-Day Contracts). PacifiCorp filed similar complaints against three
other suppliers. PacifiCorp alleges that the rates contained in the contracts
are unjust and unreasonable. Energy Marking & Trading filed its answer on
May 22, 2002, requesting that the FERC reject the complaint and deny the relief
sought. On June 28, 2002, the FERC set PacifiCorp's complaints for hearing, but
held the hearing in abeyance pending the outcome of settlement judge
proceedings. If the case goes to hearing, the FERC stated that PacifiCorp will
bear a heavy burden of proving that the extraordinary remedy of contract
modification is justified. The FERC set a refund effective date of July 1, 2002.
The hearing was conducted December 13 through December 20, 2002, at FERC. The
judge issued an initial decision on February 27, 2003 dismissing the complaints.
This decision has been appealed to the FERC and requests have been made to
re-open the record.
17
Notes (Continued)
On March 14, 2001, the FERC issued a Show Cause Order directing Energy
Marketing & Trading and AES Southland, Inc. to show cause why they should not be
found to have engaged in violations of the Federal Power Act and various
agreements, and they were directed to make refunds in the aggregate of
approximately $10.8 million and have certain conditions placed on Williams'
market-based rate authority for sales from specific generating facilities in
California for a limited period. On April 30, 2001, the FERC issued an Order
approving a settlement of this proceeding. The settlement terminated the
proceeding without making any findings of wrongdoing by Williams. Pursuant to
the settlement, Williams agreed to refund $8 million to the ISO by crediting
such amount against outstanding invoices. Williams also agreed to prospective
conditions on its authority to make bulk power sales at market-based rates for
certain limited facilities under which it has call rights for a one-year period.
Williams also has been informed that the facts underlying this proceeding have
been investigated by a California Grand Jury, and the investigation has been
closed without the Grand Jury taking any action. As a result of federal court
orders, FERC released the data it obtained from Williams that gave rise to the
show cause order.
On December 11, 2002, the FERC staff informed Transcontinental Gas Pipe
Line Corporation (Transco) of a number of issues the FERC staff identified
during the course of a formal, nonpublic investigation into the relationship
between Transco and its marketing affiliate, Energy Marketing & Trading. The
FERC staff asserted that Energy Marketing & Trading personnel had access to
Transco data bases and other information, and that Transco had failed to
accurately post certain information on its electronic bulletin board. Williams,
Transco and Energy Marketing & Trading did not agree with all of the FERC
staff's allegations and furthermore believe that Energy Marketing & Trading did
not profit from the alleged activities. Nevertheless, in order to avoid
protracted litigation, on March 13, 2003, Williams, Transco and Energy Marketing
& Trading executed a settlement of this matter with the FERC staff. An Order
approving the settlement was issued by the FERC on March 17, 2003. No requests
for rehearing of the March 17, 2003 order were filed; therefore, the order
became final on April 16, 2003. Pursuant to the terms of the settlement
agreement, Transco will pay a civil penalty in the amount of $20 million,
beginning with a payment of $4 million within thirty (30) days of the date the
FERC Order approving the settlement becomes final. The first payment is due by
May 16, 2003, and the subsequent $4 million payments are due on or before the
first, second, third and fourth anniversaries of the first payment. Transco
recorded a charge to income and established a liability of $17 million in 2002
on a discounted basis to reflect the future payments to be made over the next
four years. In addition, Transco has provided notice to its merchant sales
service customers that it will be terminating such services when it is able to
do so under the terms of any applicable contracts and FERC certificates
authorizing such services. Most of these sales are made through a Firm Sales
(FS) program, and under this program Transco must provide two-year advance
notice of termination. Therefore, Transco notified the FS customers of its
intention to terminate the FS service effective April 1, 2005. As part of the
settlement, Energy Marketing & Trading has agreed, subject to certain
exceptions, that it will not enter into new transportation agreements that would
increase the transportation capacity it holds on certain affiliated interstate
gas pipelines, including Transco. Finally, Transco and certain affiliates have
agreed to the terms of a compliance plan designed to ensure future compliance
with the provisions of the settlement agreement and the FERC's rules governing
the relationship of Transco and Energy Marketing & Trading.
On August 1, 2002, the FERC issued a Notice of Proposed Rulemaking (NOPR)
that proposes restrictions on various types of cash management programs employed
by companies in the energy industry, such as Williams and its subsidiaries. In
addition to stricter guidelines regarding the accounting for and documentation
of cash management or cash pooling programs, the FERC proposal, if made final,
would preclude public utilities, natural gas companies and oil pipeline
companies from participating in such programs unless the parent company and its
FERC-regulated affiliate maintain investment-grade credit ratings and that the
FERC-regulated affiliate maintains stockholders equity of at least 30 percent of
total capitalization. Williams' and its regulated gas pipelines' current credit
ratings are not investment grade. Williams participated in comments in this
proceeding on August 28, 2002, by the Interstate Natural Gas Association of
America. On September 25, 2002, the FERC convened a technical conference to
discuss the issues raised in the comments filed by parties in this proceeding,
and a final rule is expected to be promulgated by FERC in the next several
months.
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. 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." This investigation does not constitute a Federal Power Act complaint;
rather, the results of the investigation will be used by the FERC in any
existing or subsequent Federal Power Act or Natural Gas Act complaint. The FERC
Staff is directed to complete the investigation as soon as "is practicable."
Williams, through many of its subsidiaries, is a
18
Notes (Continued)
major supplier of natural gas and power in the West and, as such, anticipates
being the subject of certain aspects of the investigation. Williams is
cooperating with all data requests received in this proceeding. On May 8, 2002,
Williams received an additional set of 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.
Williams 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 Williams to show cause
why its market-based rate authority should not be revoked as the FERC found that
certain of Williams' responses related to the Enron trading practices
constituted a failure to cooperate with the staff's investigation. Williams
subsequently supplemented its responses to address the show cause order. On July
26, 2002, Williams received a letter from the FERC informing Williams that it
had reviewed all of Williams' supplemental responses and concluded that Williams
responded to the initial May 8, 2002 request.
In response to an article appearing in the New York Times on June 2, 2002,
containing allegations by a former Williams employee that it had attempted to
"corner" the natural gas market in California, and at Williams' invitation, the
FERC is conducting an investigation into these allegations. Also, the Commodity
Futures Trading Commission (CFTC) and the U.S. Department of Justice (DOJ) are
conducting an investigation regarding gas and power trading and have requested
information from Williams in connection with this investigation.
Williams disclosed on October 25, 2002, that certain of its gas traders had
reported inaccurate information to a trade publication that published gas price
indices. On November 8, 2002, Williams received a subpoena from a federal grand
jury in Northern California seeking documents related to Williams' involvement
in California markets, including its reporting to trade publications for both
gas and power transactions. Williams is in the process of completing its
response to the subpoena. The CFTC's and the DOJ's investigations into this
matter are continuing.
On March 26, 2003, FERC issued an order addressing Enron trading practices,
the allegation of cornering the gas market, and the gas price index issue. The
March 26, 2003 order cleared Williams on the issue of cornering the market and
contemplated or established further proceedings on the other two as to Williams
and numerous other market participants.
On May 31, 2002, Williams received a request from the Securities and
Exchange Commission (SEC) to voluntarily produce documents and information
regarding "round-trip" trades for gas or power from January 1, 2000, to the
present in the United States. On June 24, 2002, the SEC made an additional
request for information including a request that Williams address the amount of
Williams' credit, prudency and/or other reserves associated with its energy
trading activities and the methods used to determine or calculate these
reserves. The June 24, 2002, request also requested Williams' volumes, revenues,
and earnings from its energy trading activities in the Western U.S. market.
Williams has responded to the SEC's requests.
On July 3, 2002, the ISO announced fines against several energy producers
including Williams, for failure to deliver electricity in 2001 as required. The
ISO fined Williams $25.5 million, which will be offset against Williams' claims
for payment from the ISO. Williams believes the vast majority of fines are not
justified and has challenged the fines pursuant to the FERC approved process
contained in the ISO tariff.
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,
rejects the recovery of the costs of Transco's Mobile Bay expansion project from
its shippers on a "rolled-in" basis and finds that incremental pricing for the
Mobile Bay expansion project is just and reasonable. The initial decision does
not address the issue of the effective date for the change to incremental
pricing, although Transco's rates reflecting recovery of the Mobile Bay
expansion project costs on a "rolled-in" basis have been in effect since
September 1, 2001. The administrative law judge's initial decision is subject to
review by the FERC. Energy Marketing & Trading holds long-term transportation
capacity on the Mobile Bay expansion project. If the FERC adopts the decision of
the administrative law judge on the pricing of the Mobile Bay expansion project
and also requires that the decision be implemented effective September 1, 2001,
Energy Marketing & Trading could be subject to surcharges of approximately $22
million, including interest, for prior periods, in addition to increased costs
going forward.
19
Notes (Continued)
ENVIRONMENTAL MATTERS
Since 1989, Texas Gas Transmission Corporation (Texas Gas) and Transco have
had studies under way to test certain of their 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. The costs of any such
remediation will depend upon the scope of the remediation. At March 31, 2003,
these subsidiaries had accrued liabilities totaling approximately $31 million
for these costs.
Certain Williams' subsidiaries, including Texas Gas and Transco, 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. Although no assurances can be
given, Williams does not believe that these obligations or the PRP status of
these subsidiaries will have a material adverse effect on its financial
position, results of operations or net cash flows. In the event the sale of
Texas Gas to Loews Corporation is completed, Texas Gas' liability for clean-up
at these sites will remain with Texas Gas.
Transco and Texas Gas have identified polychlorinated biphenyl
contamination (PCB) in air compressor systems, soils and related properties at
certain compressor station sites. Transco and Texas Gas have 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,
negotiations with certain environmental authorities and other programs
concerning investigative and remedial actions relative to potential mercury
contamination at certain gas metering sites have been commenced by Texas Gas and
Transco. Texas Gas and Transco likewise had accrued liabilities for these costs
which are included in the $31 million liability mentioned above. Actual costs
incurred will depend 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. Liability for PCB contamination will remain with Texas Gas after the
closing of its sale to Loews Corporation.
In addition to its Gas Pipelines, Williams and its subsidiaries, including
those reported in discontinued operations, also accrue environmental remediation
costs for its natural gas gathering and processing facilities, petroleum
products pipelines, retail petroleum and refining operations and for certain
facilities related to former propane marketing operations primarily related to
soil and groundwater contamination. In addition, Williams owns a discontinued
petroleum refining facility that is being evaluated for potential remediation
efforts. At March 31, 2003, Williams and its subsidiaries, including those
reported in discontinued operations, had accrued liabilities totaling
approximately $47 million for these costs. Williams and its subsidiaries,
including those reported in discontinued operations, accrue receivables related
to environmental remediation costs based upon an estimate of amounts that will
be reimbursed from state funds for certain expenses associated with underground
storage tank problems and repairs. At March 31, 2003, Williams and its
subsidiaries, including those reported in discontinued operations, had accrued
receivables totaling $1 million.
In connection with the 1987 sale of the assets of Agrico Chemical Company,
Williams 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, 2003, Williams had approximately
$9 million accrued for such excess costs. The actual costs incurred will depend
on the actual amount and extent of contamination discovered, the final cleanup
standards mandated by the EPA or other governmental authorities, and other
factors.
On July 2, 2001, the EPA issued an information request asking for
information on oil releases and discharges in any amount from Williams'
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, Williams furnished its response.
In 2002, Williams Refining & Marketing, LLC (Williams Refining) submitted
to the EPA a self-disclosure letter indicating noncompliance with the EPA's
benzene waste "NESHAP" regulations. This unintentional noncompliance had
occurred due to a regulatory interpretation that resulted in under-counting the
total annual benzene level at the 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 mid-2003. 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. On March 4, 2003, Williams completed
the sale of the Memphis refinery. Williams is obligated to indemnify the
purchaser for any such penalty and accrued $2 million in connection with the
sale for this obligation.
20
Notes (Continued)
OTHER LEGAL MATTERS
In connection with agreements to resolve take-or-pay and other contract
claims and to amend gas purchase contracts, Transco and Texas Gas each 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 Energy Marketing
& Trading, 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 which 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 either Transco or Texas Gas. 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 defending
two lawsuits in which producers have asserted damages, including interest
calculated through March 31, 2003, of approximately $18 million.
On June 8, 2001, fourteen Williams 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 the Williams defendants, 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. In September 2001, the plaintiffs voluntarily dismissed two of the
fourteen Williams entities named as defendants in the lawsuit. In January 2002,
most of the Williams defendants, along with a group of Coordinating Defendants,
filed a motion to dismiss for lack of personal jurisdiction and other grounds.
On August 19, 2002, the defendants' motion to dismiss on nonjurisdictional
grounds was denied. On September 17, 2002, the plaintiffs filed a motion for
class certification. The Williams entities joined with other defendants in
contesting certification of the class. On April 10, 2003 the court denied the
plaintiffs' motion for class certification. The motion to dismiss for lack of
personal jurisdiction remains pending.
In 1998, the DOJ informed Williams that Jack Grynberg, an individual, had
filed claims in the United States District Court for the District of Colorado
under the False Claims Act against Williams and certain of its wholly owned
subsidiaries. In connection with its sale of Kern River, the Company agreed to
indemnify the purchaser for any liability relating to this claim, including
legal fees. The maximum amount of future payments that Williams could
potentially be required to pay under this indemnification depends upon the
ultimate resolution of the claim and cannot currently be determined. No amounts
have been accrued for this indemnification. Grynberg has also filed claims
against approximately 300 other energy companies and alleged that the defendants
violated the False Claims Act in connection with the measurement, royalty
valuation and purchase of hydrocarbons. The relief sought was an unspecified
amount of royalties allegedly not paid to the federal government, treble
damages, a civil penalty, attorneys' fees, and costs. 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 against the Williams entities in the United
States District Court for the District of Colorado. On October 21, 1999, the
Panel on Multi-District Litigation transferred all of the Grynberg qui tam
cases, including those filed against Williams, to the United States District
Court for the District of Wyoming for pre-trial purposes. On October 9, 2002,
the court granted a motion to dismiss Grynberg's royalty valuation claims.
Grynberg's measurement claims remain pending against Williams and the other
defendants.
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 The Williams Companies and Williams Production RMT Company with a
complaint in the District Court in and for the City of Denver, State of
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. On October 7, 2002, the Williams defendants filed a motion
to stay the proceedings in this case based on the pendency of the False Claims
Act litigation discussed in the preceding paragraph.
21
Notes (Continued)
Williams and certain of its subsidiaries are named as defendants in various
putative, nationwide class actions brought on behalf of all landowners on whose
property the plaintiffs have alleged WilTel Communications Group, Inc. (WilTel)
installed fiber-optic cable without the permission of the landowners. Williams
and its subsidiaries have been dismissed from all of the cases.
In November 2000, class actions were filed in San Diego, California
Superior Court by Pamela Gordon and Ruth Hendricks on behalf of San Diego rate
payers against California power generators and traders including Williams Energy
Services Company and Energy Marketing & Trading, subsidiaries of Williams. Three
municipal water districts also filed a similar action on their own behalf. Other
class actions have been filed on behalf of the people of California and on
behalf of commercial restaurants in San Francisco Superior Court. These lawsuits
result from the increase in wholesale power prices in California that began in
the summer of 2000. Williams is also a defendant in other litigation arising out
of California energy issues. The suits claim that the defendants acted to
manipulate prices in violation of the California antitrust and unfair business
practices statutes and other state and federal laws. Plaintiffs are seeking
injunctive relief as well as restitution, disgorgement, appointment of a
receiver, and damages, including treble damages. These cases have all been
administratively consolidated in San Diego County Superior Court. As part of a
comprehensive settlement with the State of California and other parties,
Williams and the lead plaintiffs in these suits have resolved the claims. While
the settlement is final as to the State of California, the San Diego Superior
Court must still approve it as to the plaintiff ratepayers.
On May 2, 2001, the Lieutenant Governor of the State of California and
Assemblywoman Barbara Matthews, acting in their individual capacities as members
of the general public, filed suit against five companies and fourteen executive
officers, including Energy Marketing & Trading and Williams' then current
officers Keith Bailey, Chairman and CEO of Williams, Steve Malcolm, President
and CEO of Williams Energy Services and an Executive Vice President of Williams,
and Bill Hobbs, Senior Vice President of Williams Energy Marketing & Trading, in
Los Angeles Superior State Court alleging State Antitrust and Fraudulent and
Unfair Business Act Violations and seeking injunctive and declaratory relief,
civil fines, treble damages and other relief, all in an unspecified amount. This
case is being administratively consolidated with the other class actions in San
Diego Superior Court. As part of a comprehensive settlement with the State of
California and other parties, Williams and the lead plaintiffs in these suits
have resolved the claims. While the settlement is final as to the State of
California, the San Diego Superior Court must still approve it as to the
plaintiffs in this suit.
On October 5, 2001, a suit was filed on behalf of California taxpayers and
electric ratepayers in the Superior Court for the County of San Francisco
against the Governor of California and 22 other defendants consisting of other
state officials, utilities and generators, including Energy Marketing & Trading.
The suit alleges that the long-term power contracts entered into by the state
with generators are illegal and unenforceable on the basis of fraud, mistake,
breach of duty, conflict of interest, failure to comply with law, commercial
impossibility and change in circumstances. Remedies sought include rescission,
reformation, injunction, and recovery of funds. Private plaintiffs have also
brought five similar cases against Williams and others on similar grounds. These
suits have all been removed to federal court, and plaintiffs are seeking to
remand the cases to state court. In January, 2003, the federal district court
granted the plaintiffs' motion to remand the case to San Diego Superior Court,
but on February 20, 2003, the United States Court of Appeals for the Ninth
Circuit, on its own motion, stayed the remand order pending its review of an
appeal of the remand order by certain defendants. As part of a comprehensive
settlement with the State of California and other parties, Williams and the lead
plaintiffs in these suits have resolved the claims. While the settlement is
final as to the State of California, once the jurisdictional issue is resolved,
either the San Diego Superior Court or the United States District Court for the
Southern District of California must still approve the settlement as to the
plaintiff ratepayers and taxpayers.
Numerous shareholder class action suits have been filed against Williams in
the United States District Court for the Northern District of Oklahoma. The
majority of the suits allege that Williams and co-defendants, WilTel 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 Williams, certain corporate officers, all members of
the Williams 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 Williams and WilTel equity holders. The
amended complaint of the WilTel securities holders was filed on September 27,
2002, and the amended complaint of the WMB securities holders was filed on
October 7, 2002. This amendment added numerous claims related to Energy
Marketing & Trading. In addition, four class action complaints have been filed
against Williams and the members of its board of directors under the Employee
Retirement Income Security Act by participants in Williams' 401(k) plan. A
motion to consolidate these suits has been approved. Williams and other
defendants have filed motions to dismiss each of these suits. Oral arguments on
the motions were held in April 2003 and decisions are pending. 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 suits pending action by the federal court in the shareholder suits
was approved.
22
Notes (Continued)
On April 26, 2002, the Oklahoma Department of Securities issued an order
initiating an investigation of Williams and WilTel regarding issues associated
with the spin-off of WilTel and regarding the WilTel bankruptcy. Williams has
committed to cooperate fully in the investigation.
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 recently spundown and 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 have sought rehearing of the FERC's order.
On October 23, 2002, Western Gas Resources, Inc. and its subsidiary, Lance
Oil and Gas Company, Inc. filed suit against Williams Production RMT Company in
District Court for Sheridan, Wyoming, claiming that the merger of Barrett
Resources Corporation and Williams triggered a preferential right to purchase a
portion of the coal bed methane development properties owned by Barrett in the
Powder River Basin of northeastern Wyoming. In addition, Western claims that the
merger triggered certain rights of Western to replace Barrett as operator of
those properties. Mediation efforts are continuing and a trial date has been set
for July 2004. The Company believes that the claims have no merit.
Williams Alaska Petroleum, Inc. (WAPI) is actively engaged in administrative
litigation being conducted jointly by the FERC and the Regulatory Commission of
Alaska 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 from WAPI in the range of $150 million to $200 million aggregate.
Because of the complexity of the issues involved, however, the outcome cannot be
predicted with certainty nor can the likely result be quantified.
Energy Marketing & Trading has paid and received various settlement amounts
in conjunction with the liquidation of trading positions during 2002 and the
first quarter of 2003. Additionally, one counterparty has disputed a settlement
amount related to the liquidation of a trading position with Energy Marketing &
Trading, and the amount is in excess of $100 million payable to Energy Marketing
& Trading. The matter is being arbitrated. This counterparty, American Electric
Power Company, Inc. (AEP), is a related party as a result of a director who
serves on both Williams' and AEP's board of directors. Energy Marketing &
Trading's net revenues from AEP were $264.6 million in 2002. At December 31,
2002, amounts due from and due to AEP were $215.1 million and $106.4 million,
respectively. This information for 2002 corrects information previously
disclosed by the Company. For the first quarter of 2003, there were no revenues.
In addition to the foregoing, various other proceedings are pending against
Williams or its subsidiaries which are incidental to their 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 net income of 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 Williams' future financial position.
COMMITMENTS
Energy Marketing & Trading 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, 2003, annual estimated
committed payments under these contracts range from approximately $333 million
to $462 million through 2018 and decline over the remaining four years to $60
million in 2022, resulting in total committed payments over the next 20 years of
approximately $8 billion.
23
Notes (Continued)
GUARANTEES
In 2001, Williams sold its investment in Ferrellgas Partners L.P. senior
common units (Ferrellgas units). As part of the sale, Williams became party to a
put agreement whereby the purchaser's lenders can unilaterally require Williams
to repurchase the units upon nonpayment by the purchaser of its term loan due to
its lender or failure or default by Williams under any of its debt obligations
greater than $60 million. The maximum potential obligation under the put
agreement at March 31, 2003, was $87.9 million. Williams' contingent obligation
decreases as purchaser's payments are made to the lender. Collateral and other
recourse provisions include the outstanding Ferrellgas units and a guarantee
from Ferrellgas Partners L.P. to cover any shortfall from the sale of the
Ferrellgas units at less than face value. The proceeds from the liquidation of
the Ferrellgas units combined with the Ferrellgas Partners' guarantee should be
sufficient to cover any required payment by Williams. The put agreement expires
December 30, 2005. There have been no events of default and the purchaser has
performed as required under payment terms with the lender. No amounts have been
accrued for this contingent obligation as management believes it is not probable
that Williams would be required to perform under this obligation.
In connection with the 1993 public offering of units in the Williams Coal
Seam Gas Royalty Trust (Royalty Trust), Exploration & Production entered a gas
purchase contract for the purchase of natural gas in which the Royalty Trust
holds a net profits interest. Under this agreement, Exploration & Production
guarantees a minimum purchase price that the Royalty Trust will realize in the
calculation of its net profits interest. Exploration & Production has 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 1987 sale of certain real estate assets associated
with its Tulsa headquarters, Williams guaranteed 70 percent of the principal and
interest payments through 2007 on revenue bonds issued by the purchaser to
finance those assets. In the event that future operating results from these
assets are not sufficient to make the principal and interest payments, Williams
is required to fund that short-fall. The maximum potential future payments under
this guarantee are $8.6 million, all of which is accrued at March 31, 2003.
In connection with the construction of a joint venture pipeline project,
Williams guaranteed 50 percent of the joint venture's project financing in the
event of nonpayment by the joint venture. Williams' maximum potential liability
under this guarantee, based on the outstanding project financing at March 31,
2003, is $13.7 million. As additional borrowings are made under the $191.4
million project financing facility, Williams' maximum potential exposure will
increase. This guarantee expires in March 2005, and no amounts have been accrued
at March 31, 2003.
Williams Gas Pipeline Company, L.L.C. (WGP) has guaranteed commercial letters
of credit totaling $16.9 million on behalf of ACCROVEN, an equity investee of
Midstream Gas & Liquids. In the event that the financial institution is required
to provide funding pursuant to the letters of credit, WGP would be required to
reimburse the financial institution. These expire in January 2004, have no
carrying value and are fully collateralized with cash.
Discovery Pipeline (Discovery) is a joint venture gas gathering and
processing system. Williams has provided a guarantee in the event of
nonperformance on 50 percent of Discovery's debt obligation, or approximately
$126.9 million at March 31, 2003. Performance under the guarantee generally
would occur upon a failure of payment by the financed entity or certain events
of default related to the guarantor. These events of default primarily relate to
bankruptcy and/or insolvency of the guarantor. The guarantee expires upon the
maturity of the debt obligation at the end of 2003, and no amounts have been
accrued as of March 31, 2003.
Williams has provided guarantees in the event of nonpayment by WilTel on
certain lease performance obligations of WilTel that extend through 2042 and
have a maximum potential exposure of approximately $53 million. Williams'
exposure declines systematically throughout the remaining term of WilTel's
obligations. At March 31, 2003, Williams has an accrued liability of $47.3
million for this guarantee.
24
Notes (Continued)
12. Comprehensive income (loss)
- --------------------------------------------------------------------------------
Comprehensive loss is as follows:
<Table>
<Caption>
Three months ended
March 31,
------------------------
(Millions) 2003 2002
---------- ----------
Net income (loss) $ (814.5) $ 107.7
Other comprehensive loss:
Unrealized gains (losses)
on securities (4.2) 1.1
Unrealized losses on derivative
instruments (184.1) (201.3)
Net reclassification into
earnings of derivative
instrument (gains) losses 15.3 (154.3)
Foreign currency
translation adjustments 24.7 (1.4)
---------- ----------
Other comprehensive loss before
taxes and minority interest (148.3) (355.9)
Income tax benefit on other
comprehensive loss 66.2 135.0
---------- ----------
Other comprehensive loss (82.1) (220.9)
---------- ----------
Comprehensive loss $ (896.6) $ (113.2)
========== ==========
</Table>
Components of other comprehensive income (loss) before taxes related to
discontinued operations are as follows:
<Table>
<Caption>
Three months ended
March 31,
--------------------
(Millions) 2003 2002
-------- --------
Unrealized losses on derivative instruments $ (.4) $ (2.7)
Net reclassification into earnings of
derivative instruments (gains) losses .5 (1.6)
-------- --------
Other comprehensive income (loss)
before taxes related to discontinued
operations $ .1 $ (4.3)
======== ========
</Table>
25
Notes (Continued)
13. Segment disclosures
- --------------------------------------------------------------------------------
Segments
Williams' 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 includes corporate operations.
Segments - Performance measurement
Williams currently evaluates 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 as if the sales were to
unaffiliated third parties, that is, at current market prices.
Energy Marketing & Trading has entered into intercompany interest rate swaps
with the corporate parent, the effect of which is included in Energy Marketing &
Trading'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 loss in the
Consolidated Statement of Operations below operating income (loss).
The majority of energy commodity hedging by certain Williams' business units
is done through intercompany derivatives with Energy Marketing & Trading which,
in turn, enters into offsetting derivative contracts with unrelated third
parties. Energy Marketing & Trading bears the counterparty performance risks
associated with unrelated third parties.
The following tables reflect the reconciliation of revenues and operating
income as reported in the Consolidated Statement of Operations to segment
revenues and segment profit (loss).
26
Notes (Continued)
13. Segment disclosures (continued)
<Table>
<Caption>
Energy Exploration Midstream Williams
Marketing Gas & Gas & Energy Petroleum
& Trading Pipeline Production Liquids Partners Services
------------ ------------ ------------ ------------ ------------ ------------
(MILLIONS)
THREE MONTHS ENDED MARCH 31, 2003
Segment revenues:
External $ 3,511.4 $ 399.3 $ (7.1) $ 1,115.7 $ 113.1 $ 227.4
Internal 264.2 7.1 273.5 17.5 3.6 12.3
------------ ------------ ------------ ------------ ------------ ------------
Total segment revenues 3,775.6 406.4 266.4 1,133.2 116.7 239.7
------------ ------------ ------------ ------------ ------------ ------------
Less intercompany interest
rate swap gain (loss) (5.9) -- -- -- -- --
------------ ------------ ------------ ------------ ------------ ------------
Total revenues $ 3,781.5 $ 406.4 $ 266.4 $ 1,133.2 $ 116.7 $ 239.7
------------ ------------ ------------ ------------ ------------ ------------
Segment profit (loss) $ (136.4) $ 94.6 $ 126.1 $ 106.9 $ 35.4 $ 22.1
Less:
Equity earnings (loss) -- 1.7 2.1 (3.2) -- 3.6
Intercompany interest
rate swap gain (loss) (5.9) -- -- -- -- --
------------ ------------ ------------ ------------ ------------ ------------
Segment operating
income (loss) $ (130.5) $ 92.9 $ 124.0 $ 110.1 $ 35.4 $ 18.5
------------ ------------ ------------ ------------ ------------ ------------
General corporate expenses
Consolidated operating
income
THREE MONTHS ENDED MARCH 31, 2002
Segment revenues:
External $ 583.9 $ 367.5 $ 17.6 $ 386.3 $ 78.3 $ 181.3
Internal (228.9)* 16.5 210.1 13.7 13.8 6.2
------------ ------------ ------------ ------------ ------------ ------------
Total segment revenues 355.0 384.0 227.7 400.0 92.1 187.5
------------ ------------ ------------ ------------ ------------ ------------
Less intercompany interest
rate swap gain (loss) 14.1 -- -- -- -- --
------------ ------------ ------------ ------------ ------------ ------------
Total revenues $ 340.9 $ 384.0 $ 227.7 $ 400.0 $ 92.1 $ 187.5
------------ ------------ ------------ ------------ ------------ ------------
Segment profit (loss) $ 283.1 $ 179.3 $ 106.3 $ 54.3 $ 26.9 $ 22.6
Less:
Equity earnings (loss) (4.0) 19.5 (.4) 1.6 -- --
Intercompany interest
rate swap gain (loss) 14.1 -- -- -- -- --
------------ ------------ ------------ ------------ ------------ ------------
Segment operating
income (loss) $ 273.0 $ 159.8 $ 106.7 $ 52.7 $ 26.9 $ 22.6
------------ ------------ ------------ ------------ ------------ ------------
General corporate expenses
Consolidated operating
income
</Table>
<Table>
<Caption>
Other Eliminations Total
------------ ------------ ------------
THREE MONTHS ENDED MARCH 31, 2003
Segment revenues:
External $ 0.4 $ -- $ 5,360.2
Internal 13.6 (591.8) --
------------ ------------ ------------
Total segment revenues 14.0 (591.8) 5,360.2
------------ ------------ ------------
Less intercompany interest
rate swap gain (loss) -- 5.9 --
------------ ------------ ------------
Total revenues $ 14.0 $ (597.7) $ 5,360.2
------------ ------------ ------------
Segment profit (loss) $ (0.3) $ -- $ 248.4
Less:
Equity earnings (loss) 0.1 -- 4.3
Intercompany interest
rate swap gain (loss) -- -- (5.9)
------------ ------------ ------------
Segment operating
income (loss) $ (0.4) $ -- $ 250.0
------------ ------------ ------------
General corporate expenses (22.9)
------------
Consolidated operating
income $ 227.1
============
THREE MONTHS ENDED MARCH 31, 2002
Segment revenues:
External $ 7.1 $ -- $ 1,622.0
Internal 9.8 (41.2) --
------------ ------------ ------------
Total segment revenues 16.9 (41.2) 1,622.0
------------ ------------ ------------
Less intercompany interest
rate swap gain (loss) -- (14.1) --
------------ ------------ ------------
Total revenues $ 16.9 $ (27.1) $ 1,622.0
============ ============ ============
Segment profit (loss) $ (10.7) $ -- $ 661.8
Less:
Equity earnings (loss) (9.2) -- 7.5
Intercompany interest
rate swap gain (loss) -- -- 14.1
------------ ------------ ------------
Segment operating
income (loss) $ (1.5) $ -- 640.2
------------ ------------ ------------
General corporate expenses (38.2)
------------
Consolidated operating
income $ 602.0
============
</Table>
* Prior to January 1, 2003, Energy Marketing & Trading intercompany cost of
sales, which were netted in revenues consistent with fair-value accounting,
exceeded intercompany revenue. Beginning January 1, 2003, EM&T intercompany
cost of sales are no longer netted in revenues due to adoption of EITF 02-3
(see Note 3).
27
Notes (Continued)
13. Segment disclosures (continued)
<Table>
<Caption>
Total Assets
-------------------------------------
(Millions) March 31, 2003 December 31, 2002
---------------- -----------------
Energy Marketing & Trading $ 14,054.3 $ 12,533.2
Gas Pipeline 8,285.5 8,196.5
Exploration & Production 5,652.0 5,816.4
Midstream Gas & Liquids 5,129.6 5,027.0
Williams Energy Partners 1,117.1 1,110.2
Petroleum Services 1,147.2 1,189.6
Other 6,691.3 6,829.1
Eliminations (6,840.6) (6,694.8)
---------------- -----------------
35,236.4 34,007.2
Discontinued operations 205.9 981.3
---------------- -----------------
Total $ 35,442.3 $ 34,988.5
================ =================
</Table>
28
Notes (Continued)
14. Subsequent events
- --------------------------------------------------------------------------------
In April 2003, Williams' board of directors approved plans authorizing
management to negotiate and facilitate the sales pursuant to terms of proposed
sales agreements of Texas Gas Transmission Corporation, Williams' general
partner interest and limited partner equity interest in Williams Energy
Partners, and certain natural gas exploration and production properties.
Beginning in April 2003, the assets and liabilities of these operations will be
classified as held for sale and Texas Gas and Williams Energy Partners will be
reflected as discontinued operations.
On April 9, 2003, Williams announced it had signed a definitive agreement
to sell certain natural gas exploration and production properties in Kansas,
Colorado and New Mexico to XTO Energy Inc. for $400 million in cash. On April
24, 2003, Williams announced it had signed a definitive agreement to sell
additional natural gas exploration and production properties in Utah for $48.6
million in cash to Berry Petroleum. These transactions are expected to close in
second-quarter 2003 and are expected to result in estimated pre-tax gains
totaling between $135 million to $145 million.
On April 14, 2003, Williams announced it had signed a definitive agreement
to sell Texas Gas Transmission Corporation to Loews Pipeline Holding Corp. for
$1.045 billion, which includes $795 million in cash to be paid to Williams and
$250 million in debt that will remain at Texas Gas. The sale is expected to
close in May 2003.
On April 21, 2003, Williams announced it had signed a definitive agreement
to sell its general partner interest and limited partner equity interest in
Williams Energy Partners to a newly formed entity owned by Madison Dearborn
Partners, LLC, Carlyle/Riverstone Global Energy and Power Fund II, L.P. for $512
million in cash. In addition, this sale will result in the removal of $570
million of partnership debt from Williams' consolidated balance sheet. The sale
is expected to close in June 2003 and is expected to result in a pre-tax gain of
at least $285 million to $300 million.
The summarized assets and liabilities of these disposal groups reflected in
the consolidated balance sheet at March 31, 2003, are as follows:
<Table>
<Caption>
(Millions)
----------
Total current assets $ 229.5
Property, plant and equipment 2,164.7
Other non-current assets 188.2
----------
Total non-current assets 2,352.9
----------
Total assets $ 2,582.4
==========
Long-term debt due within one year $ 90.0
Other current liabilities 124.3
----------
Total current liabilities 214.3
Long-term debt 729.7
Other non-current liabilities 464.7
----------
Total liabilities $ 1,408.7
==========
</Table>
29
ITEM 2
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATION
RECENT EVENTS AND COMPANY OUTLOOK
On February 20, 2003, Williams outlined its planned business strategy for
the next few years. Williams believes it to be a comprehensive response to the
events that have impacted the energy sector and Williams during 2002. The plan
focuses on retaining a strong, but smaller, portfolio of natural gas businesses
and bolstering Williams' liquidity through more asset sales, limited levels of
financing at the Williams and subsidiary levels and additional reductions in its
operating costs. The plan is designed to provide Williams with a clear strategy
to address near-term and medium-term liquidity issues and further de-leverage
the company with the objective of returning to investment grade status by 2005,
while retaining businesses with favorable returns and opportunities for growth
in the future.
Williams, at March 31, 2003, has maturing notes payable and long-term debt
totaling approximately $3.5 billion (which includes certain contractual fees and
deferred interest associated with an underlying debt) through the first quarter
of 2004. Of that amount, approximately $1.15 billion is due in July associated
with the RMT note payable. Williams expects to refinance a substantial portion
of this obligation and use other financing or cash on hand to fund the payoff of
the RMT note payable and related contractual fees. The remaining maturing notes
and long-term debt are expected to be repaid with cash on hand and proceeds from
asset sales. Long-term debt, excluding the current portion, at March 31, 2003
was approximately $10.5 billion, which includes $437 million of debt that is
required to be repaid as assets sales are completed. See the Liquidity section
for a maturity schedule of the long-term debt.
As part of the asset sales portion of the plan, Williams expects to
generate proceeds, net of related debt, of nearly $4 billion from asset sales
during 2003 and first-quarter 2004. Through March 31, 2003, Williams had
received approximately $680 million in net proceeds from the sales of assets and
businesses, including the retail travel centers and the Midsouth refinery. In
April 2003, Williams announced that it had signed definitive agreements for the
sales of the Texas Gas pipeline system, Williams' general partnership interest
and limited partner investment in Williams Energy Partners, and certain natural
gas exploration and production properties in Kansas, Colorado, New Mexico and
Utah. All of these newly announced sales are expected to close in the second
quarter. The sales anticipated to close in the second quarter 2003, including
the bio-energy operations, are expected to generate net proceeds of
approximately $2 billion. The additional assets and or businesses expected to be
sold in 2003 include the Alaska refinery and related assets, certain assets
within Midstream Gas & Liquids, the soda ash mining operations and various other
non-core assets. The specific assets and the timing of such sales are dependent
on various factors, including negotiations with prospective buyers, regulatory
approvals, industry conditions, lender consents to sales of collateral and the
short-and long-term liquidity requirements of Williams. While management
believes it has considered all relevant information in assessing for potential
impairments, the ultimate sales price for assets that may be sold and the final
decisions in the future may result in additional impairments or losses and/or
gains.
Williams continues its efforts to reduce its commitment to the Energy
Marketing & Trading business. As part of these efforts, Energy Marketing &
Trading has focused on managing its existing contractual commitments, while
pursuing potential dispositions and restructuring of certain of its long-term
contracts. Although management currently believes that the Company has the
financial resources and liquidity to meet the expected cash requirements of
Energy Marketing & Trading, the Company continues to pursue several specific
transactions with interested parties involving the sales of portions of Energy
Marketing & Trading's portfolio and would consider the sale or joint venture of
all of the portfolio. It is possible that Williams, in order to generate levels
of liquidity that are needed in the future, would be willing to accept amounts
for all or a portion of its entire portfolio that are less than its carrying
value at March 31, 2003.
The Company's available liquidity to meet maturing debt requirements and
fund a reduced level of capital expenditures will be dependent on several
factors, including the cash flows of retained businesses, the amount of proceeds
raised from the sale of assets previously mentioned, the price of natural gas
and capital spending. Future cash flows from operations may also be affected by
the timing and nature of the sale of assets. Because of recent asset sales,
anticipated asset sales, potential external financings, and available secured
credit facilities, Williams currently believes that it has, or has access to,
the financial resources and liquidity to meet future cash requirements through
the first quarter of 2004.
The secured credit facilities require Williams to meet certain covenants and
limitations as well as maintain certain financial ratios (see Note 10). Included
in these covenants are provisions that limit the ability to incur future
indebtedness, pledge assets and pay dividends on common stock. In addition, debt
and related commitments must be reduced from the proceeds of asset sales and
minimum levels of current and future liquidity must be maintained.
30
Management's Discussion & Analysis (Continued)
GENERAL
In accordance with the provisions related to discontinued operations within
Statement of Financial Accounting Standard (SFAS) No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets," the consolidated financial
statements and notes in Item 1 reflect the results of operations, financial
position and cash flows, through the date of sale as applicable, of the
following components as discontinued operations (see Note 6):
o Kern River Gas Transmission (Kern River), previously one of Gas
Pipeline's segments
o Central natural gas pipeline, previously one of Gas Pipeline's
segments
o Colorado soda ash mining operations, part of the previously reported
International segment
o Two natural gas liquids pipeline systems, Mid-American Pipeline and
Seminole Pipeline, previously part of the Midstream Gas & Liquids
segment
o Refining and marketing operations in the Midsouth, including the
Midsouth refinery, previously part of the Petroleum Services segment
o Retail travel centers concentrated in the Midsouth, previously part of
the Petroleum Services segment
o Bio-energy operations, previously part of the Petroleum Services
segment
Unless indicated otherwise, the following discussion and analysis of results
of operations, financial condition and liquidity relates to the current
continuing operations of Williams and should be read in conjunction with the
consolidated financial statements and notes thereto included in Item 1 of this
document and Williams' Annual Report on Form 10-K. The operations of Texas Gas
and Williams Energy Partners will be reported as discontinued operations in the
second quarter 2003.
CRITICAL ACCOUNTING POLICIES & ESTIMATES
As noted in the 2002 Annual Report on Form 10-K, Williams' financial
statements reflect the selection and application of accounting policies that
require management to make significant estimates and assumptions. One of the
critical judgment areas in the application of our accounting policies noted in
the Form 10-K is the revenue recognition of energy risk management and trading
operations. As a result of the application of the conclusions reached by the
Emerging Issues Task Force in Issue No. 02-3, "Issues related to Accounting for
Contracts Involved in Energy Trading and Risk Management Activities," the
methodology for revenue recognition related to energy risk management and
trading activities changed January 1, 2003. Williams initially applied the
consensus effective January 1,2003 and reported the initial application as a
cumulative effect of a change in accounting principle. See Note 3 for a
discussion of the impacts to Williams financial statements as a result of
applying this consensus.
31
Management's Discussion & Analysis (Continued)
RESULTS OF OPERATIONS
Consolidated Overview
The following table and discussion is a summary of Williams' consolidated
results of operations. The results of operations by segment are discussed in
further detail following this consolidated overview discussion.
<Table>
<Caption>
THREE
MONTHS ENDED
MARCH 31,
------------------------
2003 2002
---------- ----------
(MILLIONS)
Revenues $ 5,360.2 $ 1,622.0
Costs and expenses:
Costs and operating expenses 4,847.7 816.7
Selling, general and
administrative expenses 149.4 166.1
Other (income) expense-net 113.1 (1.0)
General corporate expenses 22.9 38.2
---------- ----------
Total costs and expenses 5,133.1 1,020.0
Operating income 227.1 602.0
Interest accrued-net (360.7) (205.4)
Interest rate swap income (loss) (2.8) 10.2
Investing income (loss) 48.0 (215.8)
Minority interest in income and preferred
returns of consolidated subsidiaries (16.1) (15.1)
Other income (expense)-net 22.5 (4.5)
---------- ----------
Income (loss) from continuing operations before
income taxes and cumulative effect of change
in accounting principles (82.0) 171.4
(Provision) benefit for income taxes 24.3 (73.0)
---------- ----------
Income (loss) from continuing operations (57.7) 98.4
Income (loss) from discontinued operations 4.5 9.3
---------- ----------
Income (loss) before cumulative effect of change
in accounting principles (53.2) 107.7
Cumulative effect of change in accounting principles (761.3) --
---------- ----------
Net income (loss) (814.5) 107.7
Preferred stock dividends 6.8 69.7
---------- ----------
Income (loss) applicable to common stock $ (821.3) $ 38.0
========== ==========
</Table>
Three Months Ended March 31, 2003 vs. Three Months Ended March 31, 2002
Williams' revenue increased $3,738.2 million due primarily to increased
revenues at Energy Marketing & Trading and Midstream Gas & Liquids as a result
of the adoption of Emerging Issues Task Force (EITF) Issue 02-3, "Issues Related
to Accounting for Contracts Involved in Energy Trading & Risk Management
Activities", which requires that revenues and cost of sales from non-derivative
contracts and certain physically settled derivative contracts to be reported on
a gross basis. Prior to the adoption of EITF 02-3 on January 1, 2003, revenues
related to non-derivative contracts were reported on a net basis. Revenues at
Midstream Gas & Liquids also increased due to a $154 million increase in
Canadian revenues and a $111 million increase from domestic gathering and
processing activities, with both increases reflecting higher liquids sales
prices.
Costs and operating expenses increased $4,031 million due primarily to the
impact of reporting certain costs gross at Energy Marketing & Trading and
Midstream Gas & Liquids, as discussed above. Costs and operating expenses at
Midstream Gas & Liquids also increased $179 million due to higher fuel & shrink
costs as a result of higher prices as well as $52 million of higher costs
resulting from the consolidation of Gulf Liquids in mid-2002.
32
Management's Discussion & Analysis (Continued)
Selling, general and administrative expenses decreased $16.7 million due
primarily to the impact of staff reductions at Energy Marketing & Trading and a
$7 million favorable adjustment at Gas Pipeline for reductions to
employee-related benefits accruals. These decreases are slightly offset by $11.8
million of expense at Energy Marketing & Trading related to the accelerated
recognition of deferred compensation as a result of staff reductions and $8
million of bad debt expense at Midstream Gas & Liquids.
Other (income) expense - net in 2003 includes a $109 million impairment
related to the Texas Gas pipeline system and an $8 million impairment of Alaska
assets (see Note 4).
General corporate expenses decreased $15.3 million, or 40 percent, due
primarily to lower advertising expenses and lower charitable contributions.
Operating income decreased $374.9 million, or 62 percent, due primarily to
a $404 million decrease at Energy Marketing & Trading due to decreased gross
margins from power, natural gas, petroleum products, and emerging products and a
$67 million decrease at Gas Pipeline which is primarily due to the impairment
for Texas Gas. These decreases to operating income are slightly offset by a $57
million increase at Midstream Gas & Liquids which is primarily attributable to
increased operating profit from domestic gathering and processing operations.
Interest accrued - net increased $155.3 million, or 76 percent, due
primarily to $89 million related to interest expense, including amortization of
fees, on the RMT note payable, the $39 million effect of higher average interest
rates, the $12 million effect of higher average borrowing levels and $15 million
higher debt amortization expense.
The 2003 investing income increased $263.8 million as compared to the 2002
investing loss. Investing income (loss) for 2003 and 2002 consisted of the
following components:
<Table>
<Caption>
Three months
ended March 31,
2003 2002
---------- ----------
Equity earnings* $ 4.3 $ 7.5
Loss provision for WilTel receivables -- (232.0)
Impairment of cost based investment (12.0) --
Interest income and other 55.7 8.7
---------- ----------
Investing income (loss) $ 48.0 $ (215.8)
========== ==========
</Table>
* This item is also included in the measure of segment profit (loss).
Equity earnings for 2002 includes a net equity loss of $3.3 million related
to equity method investments which were sold during 2002. The $232.0 million
loss provision is related to the estimated recoverability of receivables from
Wiltel Communications Group, Inc. (formerly Williams Communications Group,
Inc.). The $12.0 million impairment of cost based investment relates to Algar
Telecom S.A. (see Note 4). Interest income and other increased $47 million due
primarily to a $41.4 million increase at Energy Marketing & Trading comprised
primarily of interest income (substantial portion is related to prior periods)
recorded as a result of recent FERC proceedings as well as a $2.0 million
increase in interest income from margin deposits.
In 2002, Williams entered into interest rate swaps with external counter
parties primarily in support of the energy trading portfolio (see Note 13).
Williams has significantly reduced this activity.
Minority interest in income and preferred returns of consolidated
subsidiaries in 2003 includes higher minority interest expense of $9.5 million
related to Williams Energy Partners, LP which is offset by the absence of
preferred returns totaling $7.5 million related to the preferred interests in
Castle Associates L.P., Arctic Fox, L.L.C., Piceance Production Holdings LLC and
Williams' Risk Holdings L.L.C.
Other income (expense) - net increased $27.0 million due primarily to a
$12.5 million foreign currency transaction gain on a Canadian dollar denominated
note receivable. Other income (expense) - net in 2002 included an $8 million
loss related to early retirement of remarketable notes.
The provision (benefit) for income taxes was favorable by $97.3 million
due primarily to a pre-tax loss in 2003 as compared to pre-tax income for 2002.
The effective income tax rate for the three months ended March 31,
33
Management's Discussion & Analysis (Continued)
2003, is less than the federal statutory rate (less tax benefit) due largely to
the effect of state income taxes associated with jurisdictions in which Williams
files separate returns. The effective income tax rate for the three months ended
March 31, 2002, is greater than the federal statutory rate due primarily to the
effect of state income taxes.
Cumulative effect of change in accounting principles is an unfavorable
amount in 2003 of $761.3 million which is comprised of a $762.5 million charge
related to the adoption of EITF Issue No. 02-3 (see Note 3) offset by $1.2
million related to the adoption of SFAS No. 143 (see Note 3).
Income (loss) applicable to common stock in 2002 reflects the impact of
$69.4 million associated with accounting for a preferred security that contains
a conversion option that was beneficial to the purchaser at the time the
security was issued.
RESULTS OF OPERATIONS-SEGMENTS
Williams is currently organized into the following segments: Energy Marketing
& Trading, Gas Pipeline, Exploration & Production, Midstream Gas & Liquids,
Williams Energy Partners and Petroleum Services. Williams currently evaluates
performance based upon several measures including segment profit (loss) from
operations (see Note 13). Segment profit of the operating companies may vary by
quarter. The following discussions relate to the results of operations of
Williams' segments.
ENERGY MARKETING & TRADING
<Table>
<Caption>
THREE
MONTHS ENDED
MARCH 31,
2003 2002
---------- ----------
(MILLIONS)
Segment revenues $ 3,775.6 $ 355.0
========== ==========
Segment profit (loss) $ (136.4) $ 283.1
========== ==========
</Table>
Three Months Ended March 31, 2003 vs. Three Months Ended March 31, 2002
ENERGY MARKETING & TRADING'S revenues and cost of sales increased by
$3,420.6 million and $3,858.5 million respectively, which equates to a decrease
in gross margin of $437.9 million. This significant increase in revenues and
cost of sales is primarily a result of the adoption of Emerging Issues Task
Force (EITF) Issue 02-3, "Issues Related to Accounting for Contracts Involved in
Energy Trading & Risk Management Activities", which requires that revenues and
cost of sales from non-derivative energy contracts and certain physically
settled derivative contracts to be reported on a gross basis. Prior to the
adoption of EITF 02-3 on January 1, 2003, revenues related to non-derivative
energy contracts were reported on a net basis in trading revenues. As permitted
by EITF 02-3, prior year amounts have not been restated.
On October 25, 2002, the Emerging Issues Task Force concluded on Issue No.
02-3, which rescinded Issue No. 98-10, "Accounting for Contracts Involved in
Energy Trading and Risk Management Activities" under which all energy trading
contracts, derivative and non-derivative, were required to be valued at fair
value with the net change in fair value of these contracts representing
unrealized gains and losses reported in income currently and recorded as
revenues in the Consolidated Statement of Operations. Energy contracts include
forward contracts, futures contracts, options contracts, swap agreements,
commodity inventories, short- and long-term purchase and sale commitments, which
involve physical delivery of an energy commodity and energy-related contracts,
such as transportation, storage, full requirements, load serving and power
tolling contracts. Energy-related contracts that are not considered to be
derivatives under SFAS 133 are no longer presented on the balance sheet at fair
value. These contracts will now be reported under the accrual method of
accounting. In addition, trading inventories will no longer be marked to market
but will be reported on a lower of cost or market basis. Upon adoption of this
new standard on January 1, 2003 Energy Marketing & Trading recorded an
adjustment as a cumulative effect of change in accounting principle to remove
the previously reported fair value of non-derivative energy contracts from the
balance sheet. Energy Marketing & Trading's portion of this change in accounting
principle was approximately $755 million on an after-tax basis (see Note 3).
Prior year amounts, however, have not been restated as permitted by EITF 02-3.
34
Management's Discussion & Analysis (Continued)
In general, Energy Marketing & Trading's results were adversely impacted in
the first quarter by the absence of significant origination activities to date
in 2003 as compared to 2002, seasonality in power tolling results, and certain
adjustments and market movements against the portfolio as discussed below.
Energy Marketing & Trading's ability to manage or hedge its portfolio against
adverse market movements was limited by a lack of market liquidity as well as
Williams' limited ability to provide adequate credit & liquidity support.
Energy Marketing & Trading's revenues increased by $3,420.6 million
primarily as a result of a $3,670.2 million increase in non-trading revenues as
a result of new gross reporting requirements as discussed above, partially
offset by a $249.6 million decrease in trading revenues. Energy Marketing &
Trading's gross margin decreased $437.9 million due to a $278.6 million decrease
in power and natural gas gross margin, a $117.7 million decrease in petroleum
products gross margin, a $28.8 million decrease in emerging products gross
margin, and a $12.8 million decrease in European gross margin. The $278.6
million decrease in power and natural gas gross margin was primarily
attributable to a $62.5 million decrease in power and gas origination revenue
from first quarter 2002, unfavorable gross margins on tolling contracts from the
seasonality related to months that traditionally have lower weather-related
power demands, and a $37 million adjustment to increase the liability for rate
refunds associated with recent FERC rulings related to California power and
natural gas markets. The $117.7 million decrease in petroleum products gross
margin is primarily attributable to a $118.8 million decrease in petroleum
products origination activities from the first quarter 2002. The $28.8 million
decrease in emerging products gross margin is primarily attributable to falling
interest rates on forward interest rate positions that are marked to market. The
$12.8 million decrease in European revenues is primarily related to winding down
the European trading operations.
Energy Marketing & Trading's future results will continue to be affected by
the reduction in liquidity available from its parent, the willingness of
counterparties to enter into transactions with Energy Marketing & Trading, the
liquidity of markets in which Energy Marketing & Trading transacts, and the
creditworthiness of other counterparties in the industry and their ability to
perform under contractual obligations. Since Williams is not currently rated
investment grade by credit rating agencies Williams is required, in certain
instances, to provide additional adequate assurances in the form of cash or
credit support to enter into and maintain existing transactions. The financial
and credit constraints of Williams will likely continue to result in Energy
Marketing & Trading having exposure to market movements, which could result in
additional operating losses. In addition, other companies in the energy trading
and marketing sector are experiencing financial difficulties which will affect
Energy Marketing & Trading's credit and default assessment related to the future
value of its forward positions and the ability of such counterparties to perform
under contractual obligations. The ultimate outcome of these items could result
in future operating losses for Energy Marketing & Trading or limit Energy
Marketing & Trading's ability to achieve profitable operations.
Selling, general, and administrative expenses decreased by $14.6 million,
or 29 percent. This cost reduction is primarily due to the impact of staff
reductions in the Energy Marketing & Trading business segment. Selling, general,
and administrative costs for first quarter 2003 include approximately $13
million in costs associated with Energy Marketing & Trading's continued
reductions in workforce. At March 31, 2003, Energy Marketing & Trading employed
approximately 327 employees, compared with approximately 1,000 employees at
March 31, 2002. As of May 1, 2003, the number of Energy Marketing & Trading
employees was approximately 287. Additional staffing reductions are expected
during 2003.
Segment profit (loss) decreased $419.5 million, or 148 percent, due
primarily to decreased power, natural gas, petroleum products, and emerging
products gross margins as discussed above, partially offset by the $14.6 million
decrease in selling, general, and administrative expenses.
In the future, Energy Marketing & Trading's gross margins will be measured
in three distinct categories: accrual, hedge, and mark to market. The accrual
category will include revenues associated with non-derivative energy contracts,
owned generation assets, and transactions with affiliate entities. The hedge
category will include revenues associated with contracts that have been
designated as SFAS 133 hedges. The mark to market category will include revenues
associated with derivative contracts that have not been designated as or do not
qualify for SFAS 133 hedge accounting treatment for which the change in fair
value is recognized in the income statement.
35
Management's Discussion & Analysis (Continued)
GAS PIPELINE
<Table>
<Caption>
THREE
MONTHS ENDED
MARCH 31,
2003 2002
---------- ----------
(MILLIONS)
Segment revenues $ 406.4 $ 384.0
========== ==========
Segment profit $ 94.6 $ 179.3
========== ==========
</Table>
On April 14, 2003, Williams announced that it has signed a definitive
agreement to sell Texas Gas Transmission Corporation (Texas Gas) to Loews
Pipeline Holding Corp., a unit of Loews Corporation, for $1.045 billion, which
includes $795 million in cash to be paid to Williams and $250 million in debt
that will remain at Texas Gas and will be assumed by the buyer. The sale is
expected to close in May 2003. As a result of the sale agreement, Williams Gas
Pipeline recorded a pre-tax impairment charge of $109 million in the first
quarter 2003. Pursuant to current accounting guidance, Texas Gas will be
reclassified to discontinued operations beginning in the second quarter of 2003.
Segment revenues of Texas Gas were $84.1 million and $80.1 million for the three
months ended March 31, 2003 and 2002, respectively. Segment profit of Texas Gas
was $52.5 million and $44.6 million for the three months ended March 31, 2003
and 2002, respectively.
For the purposes of first quarter 2003 reporting, Gas Pipeline's continuing
operations include Northwest Pipeline Corporation, Texas Gas, Transcontinental
Gas Pipe Line Corporation, a 50 percent interest in the Gulfstream Natural Gas
System, L.L.C. and other joint venture interstate and intrastate natural gas
pipeline systems. Certain assets sold during 2002 are included in the 2002
results. These assets include Cove Point, general partner interest in Northern
Border, and our 14.6 percent interest in the Alliance Pipeline. These assets
represented $3.6 million of revenues and $7.5 million of segment profit in 2002.
Financial results related to Kern River Pipeline and the Central Pipeline, both
of which were sold during 2002, are included in discontinued operations.
Three Months Ended March 31, 2003 vs. Three Months Ended March 31, 2002
GAS PIPELINE'S revenues increased $22.4 million, or 6 percent, due primarily
to $16 million higher demand revenues on the Transco system resulting from new
expansion projects (MarketLink and Sundance) and higher rates in connection with
rate proceedings that became effective in late 2002, $9 million on the Northwest
Pipeline system resulting from new projects (Gray's Harbor, Centralia and
Chehalis) and higher transportation revenues, $6 million higher recovery of
tracked costs which are passed through to customers (offset in costs and
operating expenses) and $4 million higher transportation revenues on the Texas
Gas system. Partially offsetting these increases were $8 million lower gas
exchange imbalance settlements (offset in costs and operating expenses) and $7
million lower storage revenues. Storage revenues decreased $3 million as a
result of the September 2002 sale of the Cove Point facility.
Costs and operating expenses decreased $15 million, or 9 percent, due
primarily to $8 million lower gas exchange imbalance settlements (offset in
revenues) and $10 million lower fuel expense on Transco due primarily to pricing
differentials related to the volumes of gas used in operation. These decreases
were partially offset by $6 million higher tracked costs which are passed
through to customers (offset in revenues).
General and administrative costs decreased $7 million, or 15 percent, due
primarily to reductions to employee-related benefits accruals.
Other (income) expense - net in 2003 includes a $109 million impairment
charge related to Texas Gas. The $109 million charge represents the excess
carrying cost of the related long-lived assets over fair value pursuant to the
terms of the sales agreement. Estimated costs to sell of approximately $7
million will be recognized in the second quarter 2003 when the operations become
held for sale.
Segment profit, which includes equity earnings (included in investing
income), decreased $84.7 million, or 47 percent, due primarily to the effect of
the $109 million impairment charge in 2003 discussed previously in other
(income) expense - net and $17.8 million lower equity earnings. The decrease in
equity earnings is due to $12 million lower earnings for Gulfstream Natural
36
Management's Discussion & Analysis (Continued)
Gas System and the absence of $6 million of equity earnings following the
October 2002 sale of Gas Pipeline's 14.6 percent ownership in Alliance Pipeline.
The lower earnings for Gulfstream Natural Gas System were primarily due to the
absence in 2003 of interest capitalized on internally generated funds as allowed
by the FERC during construction. The pipeline was placed into service during
second-quarter 2002. These decreases were partially offset by the higher demand
revenues, lower fuel costs and the $7 million decrease in general and
administrative costs discussed above.
EXPLORATION & PRODUCTION
<Table>
<Caption>
THREE
MONTHS ENDED
MARCH 31,
2003 2002
---------- ----------
(MILLIONS)
Segment revenues $ 266.4 $ 227.7
========== ==========
Segment profit $ 126.1 $ 106.3
========== ==========
</Table>
On February 20, 2003, Williams announced that it was evaluating the sale of
additional assets including Exploration & Production properties. On April 9,
2003, Williams announced that it had agreed to sell certain natural gas
properties in Kansas, Colorado and New Mexico for $400 million. Also on April
24, 2003, Williams announced the sale of its Brundage Canyon properties in Utah
for $49 million. The sales are expected to close in the second quarter and are
expected to result in an estimated pre-tax gain between $135 million and $145
million. The properties being sold represented approximately 13 percent of
Williams' proved domestic gas equivalent reserves at December 31, 2002. This
transaction represents a substantial portion of the Exploration & Production
assets targeted by Williams for sale in 2003. Due to these sales and potential
remaining sales, future operating results could be impacted.
Three Months Ended March 31, 2003 vs. Three Months Ended March 31, 2002
EXPLORATION & PRODUCTION'S revenues increased $38.7 million, or 17 percent,
due primarily to $33 million higher domestic production revenues and $8 million
higher domestic gas management revenues. The $33 million increase in production
revenues includes $45 million from higher net realized average prices for
production (including the effect of hedge positions) partially offset by $12
million due to a six percent decrease in net domestic production volumes
following the sale of certain properties in 2002. Approximately 80 percent of
domestic production in the first quarter 2003 was hedged. Exploration &
Production has contracts that hedge approximately 90 percent of estimated
production for the remainder of the year at prices that average $3.73 per mcfe.
These contracts are entered into with Energy Marketing & Trading which in turn,
enters into offsetting derivative contracts with unrelated third parties.
Generally, Energy Marketing & Trading bears the counterparty performance risks
associated with unrelated third parties. Exploration & Production also has
derivative contracts with EM&T that no longer qualify or were never designated
as hedges. The changes in fair value of these contracts are recognized in
revenues. The total impact, realized and unrealized, of these instruments on
2003 revenues was $.8 million loss. These contracts include basis differential
derivatives not designated with underlying production and certain de-designated
derivatives in connection with the anticipated asset sales announced in February
2003, whereby the forecasted gas sales were no longer probable of occurring.
Domestic gas management revenues consist primarily of marketing activities
within the Exploration & Production segment that are not a direct part of the
results of operations for producing activities. These non-producing activities
include acquisition and disposition of other working interest and royalty
interest gas and the movement of gas from the wellhead to the tailgate of the
respective plants for sale to Energy Marketing & Trading or third parties.
Costs and expenses, including selling, general and administrative expenses,
increased $21 million due primarily to $9 million higher operating taxes, $8
million higher domestic gas management expenses and $7 million higher
depreciation, depletion and amortization expense, partially offset by $6 million
lower exploration expenses. The higher operating taxes corresponds with the
higher domestic production revenues for first quarter 2003 over first quarter
2002. The higher depreciation, depletion and amortization is due to increased
depletion rates as a result of changes in the reserve estimates based on year
end reserve reports. The lower exploration expenses reflect the current focus of
the company on developing proved properties while reducing exploratory
activities.
Segment profit increased $19.8 million due primarily to higher net realized
average prices on production and lower exploration expenses as well as an
increase in International equity earnings of $2 million.
37
Management's Discussion & Analysis (Continued)
MIDSTREAM GAS & LIQUIDS
<Table>
<Caption>
THREE
MONTHS ENDED
MARCH 31,
2003 2002
---------- ----------
(MILLIONS)
Segment revenues $ 1,133.2 $ 400.0
========== ==========
Segment profit $ 106.9 $ 54.3
========== ==========
</Table>
Midstream Gas & Liquids has announced the intention to sell certain assets,
including certain operations in Canada. Future assets sales would have the
effect of lowering revenues in periods following their sale. Increasing profits
from deepwater operations are expected to reduce the impact on segment profit
resulting from these sales.
Three Months Ended March 31, 2003 vs. Three Months Ended March 31, 2002
MIDSTREAM GAS & LIQUIDS' revenues increased $733 million, or 183 percent,
due primarily to a $427 million effect of a change in the reporting of natural
gas liquids trading activities for which costs are no longer netted in revenues
as a result of the application of EITF Issue No. 02-3, combined with a $154
million increase in Canadian revenues and a $111 million increase in domestic
gathering and processing revenues. The increase in Canadian revenues is due
primarily to a $141 million increase in liquids sales from processing and
fractionation facilities resulting from higher liquids sales prices and liquids
sales resulting from the new olefin fractionation facility which was not fully
operational in the first quarter of 2002. The increase in domestic gathering and
processing revenues is due primarily to a $90 million increase in liquids sales
resulting from a 100 percent increase in liquid sales prices. Also contributing
to the increase in revenues was a $46 million increase in liquids and
petrochemical sales from Gulf Coast olefin facilities due to the consolidation
of Gulf Liquids operations, which was not a consolidated entity in the first
quarter of 2002. Offsetting the increase in revenues was a $12 million decline
in Venezuelan revenues due largely to curtailed operations resulting from a fire
at one of the high-pressure gas compression facilities during February.
Costs and expenses increased $667 million, or 212 percent, due primarily to
the $427 million effect of the change in reporting certain costs of natural gas
liquids trading activities discussed above. Costs and expenses were also
impacted by higher fuel and shrink costs at domestic and Canadian processing
facilities of $54 million and $125 million, respectively, due primarily to
higher natural gas prices. Also impacting costs and expenses were $52 million of
product costs, depreciation and other operating and maintenance costs associated
with the consolidation of Gulf Liquids operations, combined with a $14 million
increase in Canadian depreciation and operations and maintenance costs due
primarily to a full period of operations at the new olefins fractionation
facility. Offsetting these increases is an $11 million decline in operation and
maintenance costs from gathering and processing facilities within remaining
domestic operations.
Selling, general and administrative expenses increased $8 million,
reflecting an $8 million bad debt expense associated with a single customer
within the Canadian operations and a $7 million increase due to Gulf Liquids and
the Canadian olefins facility, partially offset by a decline in general and
administrative costs in remaining Midstream Gas & Liquids operations.
Segment profit increased $52.6 million due primarily to a $69 million
increase in operating profit from domestic gathering and processing operations,
partially offset by a $6 million decline in Canadian operating results, a $6
million decline in Venezuela operating profit, and a $4 million decline in Gulf
Coast olefin operating profit. The increase in domestic gathering and processing
profits is due primarily to a $32 million increase in liquid sales margins from
domestic processing plants within the western United States as a result of
higher natural gas liquids sales prices and a favorable basis differential for
natural gas within Wyoming which had the effect of lower fuel and shrink prices
at processing facilities in this region. Management expects this favorable basis
differential to tighten as additional transportation capacity for natural gas
out of this region enters service during the second quarter of 2003. Also
contributing to the increase in domestic gathering and processing profits was a
$19 million increase associated with new deepwater operations, combined with
lower operations, maintenance and selling, general and administrative costs.
Offsetting the increases in domestic gathering and processing operating profit
is a $6 million decline in equity earnings from Discovery pipeline which
reflects an $8 million charge associated with an adjustment recorded by
Discovery to expense certain amounts previously capitalized during periods prior
to Williams becoming the operator. The
38
Management's Discussion & Analysis (Continued)
decline in Gulf Coast olefin operating profit was due primarily to $11 million
of losses at Gulf Liquids resulting from unfavorable margins and ongoing startup
and operational issues, partially offset by a $7 million increase in
petrochemical trading margins resulting from higher product prices. The $6
million decline in Canadian operating results includes the $8 million bad debt
expense.
The $6 million decline in Venezuelan segment profit is due primarily to
curtailed operations resulting from a fire at one of the high-pressure gas
compression facilities, partially offset by an improvement in equity earnings
from Accroven and lower foreign currency exchange losses as a result of currency
exchange controls in place within Venezuela. The economic and political
situation within Venezuela remains fluid and volatile but has not significantly
impacted the operations or cash flow at our owned facilities. Contracts with
PDVSA at these facilities provide for payment in U.S. dollars and contain
provisions that provide for adjustments for inflation and minimum volume
guarantees if the plants are operational.
WILLIAMS ENERGY PARTNERS
<Table>
<Caption>
THREE
MONTHS ENDED
MARCH 31,
2003 2002
---------- ----------
(MILLIONS)
Segment revenues $ 116.7 $ 92.1
========== ==========
Segment profit $ 35.4 $ 26.9
========== ==========
</Table>
On April 21, 2003, Williams announced it had signed a definitive agreement
to sell its 54.6 percent ownership interest in Williams Energy Partners L.P. in
a $1.1 billion transaction, which includes $512 million in cash to Williams and
the removal of $570 million in debt from Williams' consolidated balance sheet.
The buyer is a newly formed entity owned equally by Madison Dearborn Partners,
LLC and Carlyle/Riverstone Global Energy and Power Fund II, L.P. The sale is
scheduled to close in June 2003. Williams expects to recognize a pre-tax gain of
at least $285 million to $300 million. This gain and the operations of Williams
Energy Partners will be reported as discontinued operations beginning in
second-quarter.
Three Months Ended March 31, 2003 vs. Three Months Ended March 31, 2002
WILLIAMS ENERGY PARTNERS' revenues increased $24.6 million, or 27
percent, due primarily to higher petroleum products sales revenues reflecting
higher average sales prices and higher transportation revenues as a result of
increased average transportation rates and volumes within the Williams Pipe Line
system.
Costs and operating expenses increased $21 million, or 41 percent, due
primarily to increased costs associated with petroleum products purchases.
Segment profit increased $8.5 million, or 32 percent, due primarily to the
increased Williams Pipe Line system rates and volumes, higher petroleum products
margins and lower general and administrative costs due primarily to decreased
costs allocated from Williams.
PETROLEUM SERVICES
<Table>
<Caption>
THREE
MONTHS ENDED
MARCH 31,
2003 2002
---------- ----------
(MILLIONS)
Segment revenues $ 239.7 $ 187.5
========== ==========
Segment profit $ 22.1 $ 22.6
========== ==========
</Table>
Petroleum Services' continuing operations include North Pole, Alaska
refining operations, retail operations from the 29 Williams Express convenience
stores in Alaska, a 3.0845 percent undivided interest in the Trans-Alaska
Pipeline System (TAPS) and transportation operations. Transportation operations
include Williams' 32.1 percent interest in Longhorn Partners Pipeline LP (which
is not yet operational) and gas liquids blending activities for the Williams
Energy Partners segment. Williams has announced that it is pursuing the sale of
its
39
Management's Discussion & Analysis (Continued)
operations in Alaska. If a sale is approved and other conditions are met, these
operations would be reported as discontinued operations in the future.
Three Months Ended March 31, 2003 vs. Three Months Ended March 31, 2002
PETROLEUM SERVICES' revenues increased $52.2 million, or 28 percent, due
primarily to $56 million higher Alaska refining revenues resulting from 19
percent higher volumes sold and a significant increase in average refined
product sales prices.
Costs and operating expenses increased $48 million, or 30 percent, due
primarily to $50 million higher crude oil costs for the Alaska refinery
reflecting the higher volumes and prices.
Other (income) expense-net in 2003 includes an $8 million impairment of the
Alaska assets for which Williams intends to sell in 2003 (see Note 4).
Segment profit decreased $.5 million and reflects the $8 million impairment
of Alaska assets, offset by higher operating profit from Alaska refining
operations and a $3.8 million income adjustment for Longhorn's equity earnings
resulting from a favorable adjustment to a 2002 estimate of Longhorn's 2002
results.
FAIR VALUE OF ENERGY RISK MANAGEMENT AND TRADING ACTIVITIES
The charts below reflect the fair value of energy derivatives for Energy
Marketing & Trading and Midstream Gas & Liquids that have not been designated or
do not qualify as SFAS 133 hedges, separated by the year in which the recorded
fair value is expected to be realized. As of December 31, 2002, Energy Marketing
& Trading reported a net asset of approximately $1,632 million related to the
fair value of energy risk management and trading contracts. With the adoption of
EITF 02-3 on January 1, 2003, approximately $1,193 million of that pre-tax fair
value pertained to non-derivative energy contracts, and this amount was reported
as a cumulative effect of a change in accounting principle.
(In millions)
<Table>
<Caption>
TO BE REALIZED TO BE REALIZED TO BE REALIZED TO BE REALIZED TO BE REALIZED
IN 1-12 MONTHS IN MONTHS 13-36 IN MONTHS 37-60 IN MONTHS 61-120 IN MONTHS 121+ TOTAL FAIR
(YEAR 1) (YEARS 2-3) (YEARS 4-5) (YEARS 6-10) (YEARS 11+) VALUE
- ---------------- ---------------- ---------------- ---------------- ---------------- ----------------
$ 89.5 $ 209.0 $ 172.7 $ 81.6 $ (77.8) $ 475.0
- ---------------- ---------------- ---------------- ---------------- ---------------- ----------------
</Table>
The $475 million net asset related to the fair value of derivative
contracts that have not been designated as or do not qualify as SFAS 133 hedges
at March 31, 2003 represents an approximate increase of 8 percent compared to a
comparable carrying value at December 31, 2002.
Energy Marketing & Trading holds other derivatives designated as SFAS 133
cash flow hedges on behalf of other business units. As of March 31, 2003 the
fair value of these derivatives was a net liability of approximately $126.8
million. Various other business units within Williams also possess certain SFAS
133 hedge assets of approximately $9.3 million. In addition, the table above
does not reflect the fair value of non-derivative energy contracts that were
reversed through the adjustment on January 1, 2003 reported as a cumulative
effect of change in accounting principle.
Estimates and assumptions regarding counterparty performance and credit
considerations
Energy Marketing & Trading and Midstream Gas & Liquids include in their
estimate of fair value for all derivative contracts an assessment of the risk of
counterparty non-performance. Such assessment considers the credit rating of
each counterparty as represented by public rating agencies such as Standard &
Poor's
40
Management's Discussion & Analysis (Continued)
and Moody's Investor's Service, the inherent default probabilities within these
ratings, the regulatory environment that the contract is subject to, as well as
the terms of each individual contract.
Risks surrounding counterparty performance and credit could ultimately
impact the amount and timing of the cash flows expected to be realized. Energy
Marketing & Trading and Midstream Gas & Liquids continually assess this risk and
have credit protection within various agreements to call on additional
collateral support in the event of changes in the creditworthiness of the
counterparty. Additional collateral support could include letters of credit,
payment under margin agreements, guarantees of payment by creditworthy parties,
or in some instances, transfers of the ownership interest in natural gas
reserves or power generation assets. In addition, Energy Marketing & Trading and
Midstream Gas & Liquids enter into netting agreements to mitigate counterparty
performance and credit risk.
The gross forward credit exposure from Energy Marketing & Trading and
Midstream Gas & Liquids' derivative contracts as of March 31, 2003 is summarized
as below.
<Table>
<Caption>
INVESTMENT
COUNTERPARTY TYPE GRADE (a) TOTAL
---------- ----------
(MILLIONS)
Gas and electric utilities $ 1,107.0 $ 1,149.9
Energy marketers and traders 2,842.5 5,694.2
Financial Institutions 1,358.6 1,358.6
Other 1,978.6 1,997.0
---------- ----------
$ 7,286.7 10,199.7
==========
Credit reserves (52.6)
----------
Gross credit exposure from derivative contracts (b) $ 10,147.1
==========
</Table>
In addition to the gross Energy Marketing & Trading and Midstream Gas &
Liquids' derivative exposure discussed above, other business units within
Williams have an additional $40.9 million in gross derivative asset exposure.
Energy Marketing & Trading and Midstream Gas & Liquids assess their credit
exposure on a net basis when appropriate and contractually allowed. The net
forward credit exposure from Energy Marketing & Trading and Midstream Gas &
Liquids' derivative contracts as of March 31, 2003 is summarized below.
<Table>
<Caption>
INVESTMENT
COUNTERPARTY TYPE GRADE (a) TOTAL
---------- ----------
(MILLIONS)
Gas and electric utilities $ 656.2 $ 698.8
Energy marketers and traders 154.2 274.3
Financial Institutions 53.3 53.3
Other 23.1 36.3
---------- ----------
$ 886.8 1,062.7
==========
Credit reserves (52.6)
----------
Net credit exposure from derivative contracts (b) $ 1,010.1
==========
</Table>
- ---------------
(a) "Investment Grade" is primarily determined using publicly available
credit ratings along with consideration of cash, standby letters of
credit, parent company guarantees, and property interests, including
oil and gas reserves. Included in "Investment Grade" are
counterparties with a minimum Standard & Poor's and Moody's Investor's
Service rating of BBB- or Baa3, respectively.
(b) One counterparty within the California power market represents greater
than ten percent of derivative assets and is included in "Investment
Grade." Standard & Poor's and Moody's Investor's Service do not
currently rate this counterparty. This counterparty has been included
in the "Investment Grade" column based upon contractual credit
requirements in the event of assignment or novation.
41
Management's Discussion & Analysis (Continued)
The overall net credit exposure from derivative contracts of $1,010.1 at
March 31, 2003 represents an overall decline in derivative credit exposure of
approximately 18 percent on a comparable basis from December 31, 2002.
Certain of Energy Marketing & Trading's counterparties have experienced
significant declines in their financial stability and creditworthiness which may
adversely impact their ability to perform under contracts with Energy Marketing
& Trading. In 2002 and 2003, Energy Marketing & Trading closed out certain
trading positions with counterparties and has disputes associated with certain
of these terminations. Credit constraints, declines in market liquidity, and
financial instability of market participants, are expected to continue and
potentially grow in 2003. Continued liquidity and credit constraints of Williams
may also significantly impact Energy Marketing & Trading's ability to manage
market risk and meet contractual obligations.
Electricity and natural gas markets, in California and elsewhere, continue
to be subject to numerous and wide-ranging federal and state regulatory
proceedings and investigations, as well as civil actions, regarding among other
things, market structure, behavior of market participants, market prices, and
reporting to trade publications. Energy Marketing & Trading may be liable for
refunds and other damages and penalties as a part of these actions. Each of
these matters as well as other regulatory and legal matters related to Energy
Marketing & Trading are discussed in more detail in Note 11 to the Consolidated
Financial Statements. The outcome of these matters could affect the
creditworthiness and ability to perform contractual obligations of Energy
Marketing & Trading as well as the creditworthiness and ability to perform
contractual obligations of other market participants.
42
Management's Discussion & Analysis (Continued)
FINANCIAL CONDITION AND LIQUIDITY
LIQUIDITY
Williams' liquidity comes from both internal and external sources. Certain
of those sources are available to Williams (the parent) and others are available
to certain of its subsidiaries. Williams' sources of liquidity consist of the
following:
o Cash-equivalent investments at the corporate level of $894 million at
March 31, 2003, as compared to $1.3 billion at December 31, 2002. This
does not include $228 million of restricted cash at March 31, 2003
that was returned to Williams in early April. This cash was part of
the proceeds from the sale of the Midsouth refinery.
o Cash and cash-equivalent investments of various international and
domestic entities other than Williams Energy Partners of $512 million
at March 31, 2003 as compared to $354 million at December 31, 2002.
o Cash generated from sales of assets
o Cash generated from operations.
o $400 million available under Williams' revolving credit facility at
March 31, 2003, as compared to $463 million at December 31, 2002. This
decrease results from the reduction of commitments as a result of
asset sales as provided in the agreement. This credit facility is
available to the extent that it is not used to satisfy the financial
ratios and other covenants under certain credit agreements. As
discussed in Note 10 of Notes to Consolidated Financial Statements,
the borrowing capacity under this facility will reduce as assets are
sold.
o $17 million remaining at March 31, 2003, under a $400 million secured
short-term letter of credit facility obtained in third-quarter 2002
and expiring in July 2003. The company is currently in negotiations to
renew or replace this facility.
Williams has an effective shelf registration statement with the Securities
and Exchange Commission that enables it to issue up to $3 billion of a variety
of debt and equity securities. Since the filing of Williams' Form 10-K in March
2003, the debt capital markets have improved and Williams is evaluating the
feasibility of utilizing this shelf availability.
In addition, there are outstanding registration statements filed with the
Securities and Exchange Commission for Williams' wholly owned subsidiaries:
Northwest Pipeline and Transcontinental Gas Pipe Line. As of May 12, 2003,
approximately $350 million of shelf availability remains under these outstanding
registration statements and may be used to issue a variety of debt securities.
Interest rates, market conditions, and industry conditions will affect amounts
raised, if any, in the capital markets. On March 4, 2003, Northwest Pipeline
Corporation, a subsidiary of Williams, completed an offering of $175 million of
8.125 percent senior notes due 2010. The $350 million of shelf availability
mentioned above is not affected by this offering.
Capital and investment expenditures for 2003 are estimated to total
approximately $1 billion. Williams expects to fund capital and investment
expenditures, debt payments and working-capital requirements through (1) cash on
hand, (2) cash generated from operations, (3) the sale of assets, (4) issuance
of debt by Williams or certain subsidiaries and/or (5) amounts available under
Williams' revolving credit facility.
Outlook
Williams expects to generate proceeds, net of related debt, of nearly $4
billion from asset sales during 2003 and first-quarter 2004. On April 14, 2003,
Williams announced that it signed a definitive agreement to sell its Texas Gas
pipeline system to Loews Pipeline Holding Corporation for $1.045 billion, which
includes $795 million in cash to be paid to Williams and $250 million in debt
that will remain at Texas Gas. The sale is expected to close in May 2003. On
April 21, 2003, Williams announced it had signed a definitive agreement to sell
its 54.6 percent ownership interest in Williams Energy Partners L.P. in a $1.1
billion transaction, which includes $512 million in cash to Williams and
43
Management's Discussion & Analysis (Continued)
$570 million in debt that will remain at Williams Energy Partners. The buyer is
a newly formed entity owned equally by Madison Dearborn Partners, LLC and
Carlyle/Riverstone Global Energy and Power Fund II, L.P. The sale is scheduled
to close in June, subject to standard closing conditions.
In addition to Texas Gas and Williams Energy Partners, Williams has also
reached agreements to sell the following assets or energy-related contracts: 1)
Certain natural gas exploration and production properties in Kansas, Colorado
and New Mexico for $400 million to XTO Energy, Inc., 2) a full-requirements
power agreement with Jackson Electric Membership Corporation for $188 million to
Progress Energy, 3) equity interest in Williams Bio-Energy L.L.C. for
approximately $75 million to a new company formed by Morgan Stanley Capital
Partners, and 4) certain natural gas exploration and production properties in
Utah for $49 million. The sales are all expected to close in second quarter
2003.
Based on the Company's forecast of cash flows and liquidity, Williams
believes that it has, or has access to, the financial resources and liquidity to
meet future cash requirements and satisfy current lending covenants through the
first quarter of 2004. Included in this forecast are the expected proceeds, net
of related debt, of nearly $4 billion from asset sales discussed above. For the
remainder of 2003 and including periods through first-quarter 2004, the Company
has scheduled debt retirements (which include certain contractual fees and
deferred interest associated with an underlying debt) of approximately $3.5
billion. Realization of the proceeds from forecasted assets sales is a
significant factor for the Company to satisfy its loan covenant which requires
minimum levels of parent liquidity and to satisfy current scheduled debt
maturities.
OPERATING ACTIVITIES
During first-quarter 2003, Williams recorded approximately $130 million in
provisions for losses on property and other assets consisting primarily of the
$109 million impairment of Texas Gas, the $12 million impairment of Algar
Telecom S.A. and the $8 million impairment of the Alaska assets (see Note 4).
The accrual for fixed rate interest included in the RMT note payable
represents the quarterly noncash reclassification of the deferred fixed rate
interest from an accrued liability to the RMT note payable. The amortization of
deferred set-up fee and fixed rate interest on the RMT note payable relates to
amounts recognized in the income statement as interest expense, but generally
will not be paid until maturity.
FINANCING ACTIVITIES
For a discussion of borrowings and repayments in 2003, see Note 10 of Notes
to Consolidated Financial Statements.
Dividends paid on common stock are currently $.01 per common share.
Additionally, one of the covenants within the current credit agreements limits
the common stock dividends paid by Williams in any quarter to not more than
$6.25 million.
Williams' long-term debt to debt-plus-equity ratio (excluding debt of
discontinued operations) was 71.6 percent at March 31, 2003, compared to 70.2
percent at December 31, 2002. If short-term notes payable and long-term debt due
within one year are included in the calculations, these ratios would be 76.9
percent at March 31 2003, and 73.4 percent at December 31, 2002. Additionally,
the long-term debt to debt-plus-equity ratio as calculated for covenants under
certain debt agreements was 65.1 percent at March 31, 2003, and 65.2 percent at
December 31, 2002. See Note 10 for a discussion of changes to the credit
agreement during March 2003.
Included in restricted cash is approximately $228 million that was required
to be held by a collateral trustee following the sale of the Midsouth refinery.
This cash was returned to Williams in April 2003.
INVESTING ACTIVITIES
For 2003, net cash proceeds from asset dispositions and the sales of
businesses include the following:
o $453 million related to the sale of the Memphis refinery.
o $188 million related to the sale of the Williams travel centers.
o $40 million related to the sale of the Worthington facility
44
Management's Discussion & Analysis (Continued)
COMMITMENTS
The table below summarizes some of the more significant contractual
obligations and commitments by period. These amounts do not reflect debt
reductions contingent upon asset sales (see Note 10).
<Table>
<Caption>
APRIL 1-
DEC. 31,
2003 2004 2005 2006 2007 THEREAFTER TOTAL
---------- ---------- ---------- ---------- ---------- ---------- ----------
(Millions)
Notes payable .................. $ 968(1) $ -- $ -- $ -- $ -- $ -- $ 968
Long-term debt, including
current portion ........... 800 1,832 1,364(2) 1,030 855 6,823 12,704
Capital leases ................. -- -- 92 -- -- -- 92
Operating leases ............... 40 29 18 11 9 26 133
Fuel conversion and other
service contracts(3) ...... 333 443 446 449 452 5,517 7,640
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total .......................... $ 2,141 $ 2,304 $ 1,920 $ 1,490 $ 1,316 $ 12,366 $ 21,537
========== ========== ========== ========== ========== ========== ==========
</Table>
(1) An additional $197 million will be paid at maturity of the RMT note
payable related to a deferred set up fee and deferred interest.
(2) Includes $1.1 billion of 6.5 percent notes, payable 2007 subject to
remarketing in 2004 (FELINE PACS). If the remarketing is unsuccessful in
2004 and a second remarketing in February 2005 is unsuccessful as defined
in the offering document of the FELINE PACS, then Williams could exercise
its 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 Williams common stock.
(3) Energy Marketing & Trading has entered into certain contracts giving
Williams the right to receive fuel conversion services as well as certain
other services associated with electric generation facilities that are
either currently in operation or are to be constructed at various
locations throughout the continental United States.
45
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
INTEREST RATE RISK
Williams' interest rate risk exposure associated with the debt portfolio was
impacted by debt payments and by a new debt issuance in March 2003. During the
first quarter of 2003, Williams paid down approximately $360 million of debt
including $112 million on the debt of Snow Goose LLC, and $200 million in other
various notes. In March 2003, Northwest Pipeline Corporation, a subsidiary of
Williams, through a private debt placement, issued $175 million of 8.125 percent
notes payable 2010 (see Note 10).
COMMODITY PRICE RISK
Trading
Energy Marketing & Trading and Midstream Gas & Liquids have operations that
incur commodity price risk as a consequence of providing price risk management
services to third-party customers. This includes exposure to commodity
price-risk associated with the natural gas, electricity, crude oil, refined
products, and natural gas liquids markets in the United States and Canada.
Derivative contracts that are not designated or do not qualify as hedges under
SFAS 133 are valued at fair value and unrealized gains and losses from changes
in fair value are recognized in income. Such derivative contracts are subject to
risk from changes in energy commodity market prices, volatility and correlation
of those commodity prices, the portfolio position of its contracts, the
liquidity of the market in which the contract is transacted and changes in
interest rates.
Energy Marketing & Trading and Midstream Gas & Liquids measure the market
risk in their portfolio utilizing a value-at-risk methodology to estimate the
potential one-day loss from adverse changes in the fair value of their
portfolios. At March 31, 2003 and December 31, 2002, the value at risk for the
derivative contracts that have not been designated or did not qualify as SFAS
133 hedges was approximately $29 million and $50 million, respectively. The
adoption of EITF 02-3 resulted in non-derivative energy contracts no longer
being accounted for and reported at fair value, therefore such contracts have
not been included in the March 31, 2003 trading value at risk. Value at risk
requires a number of key assumptions and is not necessarily representative of
actual losses in fair value that could be incurred from the portfolio. The
value-at-risk model assumes that as a result of changes in commodity prices,
there is a 95 percent probability that the one-day loss in fair value of the
portfolio will not exceed the value at risk. The value-at-risk model uses
historical simulations to estimate hypothetical movements in future market
prices assuming normal market conditions based upon historical market prices.
Value at risk does not consider that changing the portfolio in response to
market conditions could affect market prices and could take longer to execute
than the one-day holding period assumed in the value-at-risk model. While a
one-day holding period has historically been the industry standard, a longer
holding period could more accurately represent the true market risk in an
environment where market illiquidity and credit and liquidity constraints of the
company may result in further inability to mitigate risk in a timely manner in
response to changes in market conditions.
Nontrading
Williams is also exposed to market risks from changes in energy commodity
prices within Exploration & Production and Petroleum Services. Exploration &
Production has commodity price risk associated with the sales prices of the
natural gas and crude oil it produces. Petroleum Services' refinery is exposed
to commodity price risk for crude oil purchases and refined product sales.
Williams manages its exposure to certain of these commodity price risks through
the use of derivative commodity instruments.
Williams' non-trading derivative commodity instruments primarily consist
of natural gas price and basis swaps in its Exploration & Production business.
46
A value-at-risk methodology was used to measure the market risk of these
derivative commodity instruments in the non-trading portfolio. It estimates the
potential one-day loss from adverse changes in the fair value of these
instruments. The value-at-risk model did not consider the underlying commodity
positions to which these derivative commodity instruments relate; therefore, it
is not representative of actual losses that could occur on a total non-trading
portfolio basis that includes the underlying commodity positions. At March 31,
2003 and December 31, 2002, the value at risk for the non-trading derivative
commodity instruments was approximately $27 million and $45 million,
respectively. Value at risk requires a number of key assumptions and is not
necessarily representative of actual losses in fair value that could be incurred
from the non-trading derivative commodity instruments. The value-at-risk model
assumes that as a result of changes in commodity prices there is a 95 percent
probability that the one-day loss in fair value of the non-trading derivative
commodity instruments will not exceed the value at risk. The value-at-risk model
uses historical simulations to estimate hypothetical movements in future market
prices assuming normal market conditions based upon historical market prices.
Gains and losses on these derivative commodity instruments would be
substantially offset by corresponding gains and losses on the hedged commodity
positions.
ITEM 4. CONTROLS AND PROCEDURES
An evaluation of the effectiveness of the design and operation of Williams'
disclosure controls and procedures (as defined in Rule 13a-14(c) and 15d-14(c)
of the Securities Exchange Act) was performed within the 90 days prior to the
filing date of this report. This evaluation was performed under the supervision
and with the participation of Williams' management, including Williams' Chief
Executive Officer and Chief Financial Officer. Based upon that evaluation,
Williams' Chief Executive Officer and Chief Financial Officer concluded that
these disclosure controls and procedures are effective.
There have been no significant changes in Williams' internal controls or
other factors that could significantly affect internal controls since the
certifying officers' most recent evaluation of those controls.
47
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
The information called for by this item is provided in Note 11 Contingent
liabilities and commitments included in the Notes to Consolidated Financial
Statements included under Part I, Item 1. Financial Statements of this report,
which information is incorporated by reference into this item.
Item 6. Exhibits and Reports on Form 8-K
(a) The exhibits listed below are filed as part of this report:
Exhibit 4.1 - Indenture dated March 4, 2003, between Northwest
Pipeline Corporation and JP Morgan Chase Bank, as Trustee.
Exhibit 10.1--Purchase Agreement by and among Williams Gas
Pipeline Company, LLC as Seller, The Williams Companies, Inc.
and Loews Pipeline Holding Corp., as Buyer, for the purchase
and sale of all the capital stock of Texas Gas Transmission
Corporation, a Delaware Corporation, dated as of April 11,
2003.
Exhibit 10.2--Purchase and Sale Agreement between Williams
Production RMT Company and Williams Production Company,
L.L.C., as Seller, and XTO Energy Inc., as Buyer dated
April 9, 2003.
Exhibit 10.3--Consent and Waiver dated January 22, 2003, under
the Amended and Restated Credit Agreement dated as of October
31, 2002 among The Williams Companies, Inc., Citicorp USA,
Inc., as agent and collateral agent, Bank of America N.A. as
syndication agent, Citibank, N.A., Bank of America N.A. and
The Bank of Nova Scotia as issuing banks and the various
lenders and other Persons from time to time party thereto, and
the Collateral Trust Agreement dated as of July 31, 2002,
among The Williams Companies, Inc. and certain of its
subsidiaries in favor of Citibank, N.A., as collateral trustee
for the benefit of the holders of the secured obligations, as
amended by the First Amendment to Collateral Trust Agreement
dated October 31, 2002.
Exhibit 10.4--Consent and Waiver dated January 22, 2003, under
the First Amended and Restated Credit Agreement dated October
31, 2002 among The Williams Companies, Inc. Northwest Pipeline
Corporation, Transcontinental Gas Pipe Line Corporation, and
Texas Gas Transmission Corporation, the financial institutions
and other Persons from time to time party thereto, JPMorgan
Chase Bank (f/k/a The Chase Manhattan Bank) and Commerzbank
AG, as Co-Syndication Agents, Credit Lyonnais New York Branch,
as Documentation Agent, and Citicorp USA, Inc., as agent, and
the Collateral Trust Agreement, dated as of July 31, 2002,
among The Williams Companies, Inc. and certain of its
subsidiaries in favor of Citibank, N.A., as collateral trustee
for the benefit of the holders of the secured obligations, as
amended by that First Amendment to Collateral Trust Agreement
dated October 31, 2002.
Exhibit 10.5--Amendment dated March 28, 2003 to the Amended
and Restated Credit Agreement dated as of October 31, 2002, as
modified by the Consent and Waiver dated as of January 22,
2003, among The Williams Companies, Inc., Citicorp USA, Inc.,
as agent and collateral agent, Bank of America N.A. as
syndication agent, Citibank, N.A., Bank of America N.A. and
The Bank of Nova Scotia as issuing banks and the various
lenders and other Persons from time to time party thereto.
Exhibit 10.6--Amendment dated March 28, 2003 to the First
Amended and Restated Credit Agreement dated October 31, 2002,
as modified by the Consent and Waiver dated as of January 22,
2003, among The Williams Companies, Inc., Northwest Pipeline
Corporation, Transcontinental Gas Pipe Line Corporation, and
Texas Gas Transmission Corporation, the financial institutions
and other Persons from time to time party thereto, JPMorgan
Chase Bank (f/k/a The Chase Manhattan Bank) and Commerzbank
AG, as Co-Syndication Agents, Credit Lyonnais New York Branch,
as Documentation Agent, and Citicorp USA, Inc., as agent.
48
Exhibit 12--Computation of Ratio of Earnings to Combined Fixed
Charges and Preferred Stock Dividend Requirements.
Exhibit 99.1--Certification pursuant to 18 U.S.C. Section
1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002 by Steven J. Malcolm, Chief Executive Officer of
The Williams Companies, Inc.
Exhibit 99.2--Certification pursuant to 18 U.S.C. Section
1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002 by Donald R. Chappel, Chief Financial Officer of
The Williams Companies, Inc.
(b) During first-quarter 2003, Williams filed a Form 8-K on the
following dates reporting events under the specified items:
January 2, 2003 Item 9; January 9, 2003 Item 9; January 17,
2003 Item 5; January 24, 2003 Item 9; February 19, 2003 Item
9; February 21, 2003 Items 5, 7 and 9; March 6, 2003 Item 9;
March 12, 2003 Item 9; March 19, 2003 Item 9; and March 21,
2003 Item 9.
49
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
THE WILLIAMS COMPANIES, INC.
--------------------------------------
(Registrant)
/s/ Gary R. Belitz
--------------------------------------
Gary R. Belitz
Controller
(Duly Authorized Officer and
Principal Accounting Officer)
May 13, 2003
Certifications
I, Steven J. Malcolm, President and Chief Executive Officer of The Williams
Companies, Inc. ("registrant"), certify that:
1. I have reviewed this quarterly report on Form 10-Q of the
registrant;
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect
to the period covered by this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented
in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant
and we have:
a. Designed such disclosure controls and procedures to ensure
that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us
by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b. Evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to
the filing date of this quarterly report (the "Evaluation
Date"); and
c. Presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based
on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors
and the audit committee of registrant's board of directors (or
persons performing the equivalent function):
a. All significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrant's ability to record, process, summarize and report
financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b. Any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in
this quarterly report whether or not there were significant changes
in internal controls or in other factors that could significantly
affect internal controls subsequent to the date of our most recent
evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.
Date: May 13, 2003 /s/ Steven J. Malcolm
-------------------------------------
Steven J. Malcolm
President and Chief Executive Officer
Certifications
I, Donald R. Chappel, Senior Vice President - Finance and Chief Financial
Officer of The Williams Companies, Inc. ("registrant"), certify that:
1. I have reviewed this quarterly report on Form 10-Q of registrant;
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect
to the period covered by this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented
in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant
and we have:
a. Designed such disclosure controls and procedures to ensure
that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us
by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b. Evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to
the filing date of this quarterly report (the "Evaluation
Date"); and
c. Presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based
on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors
and the audit committee of registrant's board of directors (or
persons performing the equivalent function):
a. All significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrant's ability to record, process, summarize and report
financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b. Any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in
this quarterly report whether or not there were significant changes
in internal controls or in other factors that could significantly
affect internal controls subsequent to the date of our most recent
evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.
Date: May 13, 2003 /s/ Donald R. Chappel
--------------------------------------
Donald R. Chappel
Senior Vice President - Finance
and Chief Financial Officer
INDEX TO EXHIBITS
Exhibit 4.1 - Indenture dated March 4, 2003, between Northwest
Pipeline Corporation and JP Morgan Chase Bank, as Trustee.
Exhibit 10.1--Purchase Agreement by and among Williams Gas
Pipeline Company, LLC as Seller, The Williams Companies, Inc.
and Loews Pipeline Holding Corp., as Buyer, for the purchase
and sale of all the capital stock of Texas Gas Transmission
Corporation, a Delaware Corporation, dated as of April 11,
2003.
Exhibit 10.2--Purchase and Sale Agreement between Williams
Production RMT Company and Williams Production Company,
L.L.C., as Seller, and XTO Energy Inc., as Buyer dated April
9. 2003.
Exhibit 10.3--Consent and Waiver dated January 22, 2003, under
the Amended and Restated Credit Agreement dated as of October
31, 2002 among The Williams Companies, Inc., Citicorp USA,
Inc., as agent and collateral agent, Bank of America N.A. as
syndication agent, Citibank, N.A., Bank of America N.A. and
The Bank of Nova Scotia as issuing banks and the various
lenders and other Persons from time to time party thereto, and
the Collateral Trust Agreement dated as of July 31, 2002,
among The Williams Companies, Inc. and certain of its
subsidiaries in favor of Citibank, N.A., as collateral trustee
for the benefit of the holders of the secured obligations, as
amended by the First Amendment to Collateral Trust Agreement
dated October 31, 2002.
Exhibit 10.4--Consent and Waiver dated January 22, 2003, under
the First Amended and Restated Credit Agreement dated October
31, 2002 among The Williams Companies, Inc. Northwest Pipeline
Corporation, Transcontinental Gas Pipe Line Corporation, and
Texas Gas Transmission Corporation, the financial institutions
and other Persons from time to time party thereto, JPMorgan
Chase Bank (f/k/a The Chase Manhattan Bank) and Commerzbank
AG, as Co-Syndication Agents, Credit Lyonnais New York Branch,
as Documentation Agent, and Citicorp USA, Inc., as agent, and
the Collateral Trust Agreement, dated as of July 31, 2002,
among The Williams Companies, Inc. and certain of its
subsidiaries in favor of Citibank, N.A., as collateral trustee
for the benefit of the holders of the secured obligations, as
amended by that First Amendment to Collateral Trust Agreement
dated October 31, 2002.
Exhibit 10.5--Amendment dated March 28, 2003 to the Amended
and Restated Credit Agreement dated as of October 31, 2002, as
modified by the Consent and Waiver dated as of January 22,
2003, among The Williams Companies, Inc., Citicorp USA, Inc.,
as agent and collateral agent, Bank of America N.A. as
syndication agent, Citibank, N.A., Bank of America N.A. and
The Bank of Nova Scotia as issuing banks and the various
lenders and other Persons from time to time party thereto.
Exhibit 10.6--Amendment dated March 28, 2003 to the First
Amended and Restated Credit Agreement dated October 31, 2002,
as modified by the Consent and Waiver dated as of January 22,
2003, among The Williams Companies, Inc. Northwest Pipeline
Corporation, Transcontinental Gas Pipe Line Corporation, and
Texas Gas Transmission Corporation, the financial institutions
and other Persons from time to time party thereto, JPMorgan
Chase Bank (f/k/a The Chase Manhattan Bank) and Commerzbank
AG, as Co-Syndication Agents, Credit Lyonnais New York Branch,
as Documentation Agent, and Citicorp USA, Inc., as agent.
Exhibit 12--Computation of Ratio of Earnings to Combined Fixed
Charges and Preferred Stock Dividend Requirements.
Exhibit 99.1--Certification pursuant to 18 U.S.C. Section
1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002 by Steven J. Malcolm, Chief Executive Officer of
The Williams Companies, Inc.
Exhibit 99.2--Certification pursuant to 18 U.S.C. Section
1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002 by Donald R. Chappel, Chief Financial Officer of
The Williams Companies, Inc.
(b) During first-quarter 2003, Williams filed a Form 8-K on the
following dates reporting events under the specified items:
January 2, 2003 Item 9; January 9, 2003 Item 9; January 17,
2003 Item 5; January 24, 2003 Item 9; February 19, 2003 Item
9; February 21, 2003 Items 5, 7 and 9; March 6, 2003 Item 9;
March 12, 2003 Item 9; March 19, 2003 Item 9; and March 21,
2003 Item 9.