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 September 30, 2002
-------------------------------------------------
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
---------------------- -----------------------
Commission file number 1-4174
---------------------------------------------------------
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
- --------------------------------------------------------------------------------
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 the number of shares outstanding of each of the issuer's classes of
common stock as of the latest practicable date.
Class Outstanding at October 31, 2002
- --------------------------------------- ------------------------------------
Common Stock, $1 par value 516,666,268 Shares
The Williams Companies, Inc.
Index
<Table>
<Caption>
Part I. Financial Information Page
------
Item 1. Financial Statements
Consolidated Statement of Operations--Three and Nine Months Ended September 30, 2002 and 2001 2
Consolidated Balance Sheet--September 30, 2002 and December 31, 2001 3
Consolidated Statement of Cash Flows--Nine Months Ended September 30, 2002 and 2001 4
Notes to Consolidated Financial Statements 5
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations 32
Item 3. Quantitative and Qualitative Disclosures about Market Risk 55
Item 4. Controls and Procedures 55
Part II. Other Information 56
Item 1. Legal Proceedings
Item 2. Changes in Securities and Use of Proceeds
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" 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 2001 Form
10-K.
1
The Williams Companies, Inc.
Consolidated Statement of Operations
(Unaudited)
<Table>
<Caption>
Three months Nine months
(Dollars in millions, except per-share amounts) ended September 30, ended September 30,
- ----------------------------------------------- ----------------------------- -----------------------------
2002 2001* 2002 2001*
------------ ------------ ------------ ------------
Revenues:
Energy Marketing & Trading $ (219.2) $ 493.1 $ (73.9) $ 1,429.0
Gas Pipeline 381.4 335.1 1,106.4 1,048.5
Exploration & Production 219.3 160.6 677.8 410.2
Midstream Gas & Liquids 501.8 414.9 1,339.8 1,506.8
Williams Energy Partners 107.5 110.8 303.6 310.7
Petroleum Services 1,170.9 1,281.9 3,266.7 4,077.6
International .7 1.1 3.1 2.6
Other 14.8 17.9 47.1 57.4
Intercompany eliminations (73.3) (88.1) (152.4) (184.4)
------------ ------------ ------------ ------------
Total revenues 2,103.9 2,727.3 6,518.2 8,658.4
------------ ------------ ------------ ------------
Segment costs and expenses:
Costs and operating expenses 1,792.7 1,814.8 5,145.6 6,005.8
Selling, general and administrative expenses 218.7 238.4 614.0 625.7
Other (income) expense - net 318.1 7.7 486.8 (42.7)
------------ ------------ ------------ ------------
Total segment costs and expenses 2,329.5 2,060.9 6,246.4 6,588.8
------------ ------------ ------------ ------------
General corporate expenses 44.1 32.4 116.4 88.8
------------ ------------ ------------ ------------
Operating income (loss):
Energy Marketing & Trading (316.6) 380.5 (458.1) 1,130.5
Gas Pipeline 163.7 89.9 438.2 378.4
Exploration & Production 230.3 60.1 431.4 149.6
Midstream Gas & Liquids 96.7 68.2 197.5 137.9
Williams Energy Partners 13.4 27.1 69.8 83.6
Petroleum Services (405.4) 42.4 (395.4) 189.4
International (4.0) (3.4) (11.0) (9.2)
Other (3.7) 1.6 (.6) 9.4
General corporate expenses (44.1) (32.4) (116.4) (88.8)
------------ ------------ ------------ ------------
Total operating income (loss) (269.7) 634.0 155.4 1,980.8
Interest accrued (366.3) (179.5) (848.8) (507.1)
Interest capitalized 7.8 12.1 20.0 32.6
Interest rate swap loss (52.2) -- (125.2) --
Investing income (loss):
Estimated loss on realization of amounts due from
Williams Communications Group, Inc. (22.9) -- (269.9) --
Other 85.3 (69.6) 161.5 39.9
Minority interest in income and preferred returns
of consolidated subsidiaries (23.7) (22.2) (60.6) (70.4)
Other income - net 1.2 1.9 20.6 12.2
------------ ------------ ------------ ------------
Income (loss) from continuing operations before income taxes (640.5) 376.7 (947.0) 1,488.0
Provision (benefit) for income taxes (231.8) 182.8 (313.0) 615.2
------------ ------------ ------------ ------------
Income (loss) from continuing operations (408.7) 193.9 (634.0) 872.8
Income (loss) from discontinued operations 114.6 27.4 98.5 (112.8)
------------ ------------ ------------ ------------
Net income (loss) (294.1) 221.3 (535.5) 760.0
Preferred stock dividends 6.8 -- 83.3 --
------------ ------------ ------------ ------------
Income (loss) applicable to common stock $ (300.9) $ 221.3 $ (618.8) $ 760.0
============ ============ ============ ============
Basic earnings (loss) per common share:
Income (loss) from continuing operations $ (.80) $ .39 $ (1.39) $ 1.78
Income (loss) from discontinued operations .22 .05 .19 (.23)
------------ ------------ ------------ ------------
Net income (loss) $ (.58) $ .44 $ (1.20) $ 1.55
============ ============ ============ ============
Average shares (thousands) 516,901 502,877 516,688 489,813
Diluted earnings (loss) per common share:
Income (loss) from continuing operations $ (.80) $ .39 $ (1.39) $ 1.77
Income (loss) from discontinued operations .22 .05 .19 (.23)
------------ ------------ ------------ ------------
Net income (loss) $ (.58) $ .44 $ (1.20) $ 1.54
============ ============ ============ ============
Average shares (thousands) 516,901 506,165 516,688 493,812
Cash dividends per common share $ .01 $ .18 $ .41 $ .48
</Table>
* Certain amounts have been restated or 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) September 30, December 31,
- ----------------------------------------------- 2002 2001*
------------- ------------
ASSETS
Current assets:
Cash and cash equivalents $ 1,292.7 $ 1,274.9
Restricted cash 324.0 --
Accounts and notes receivable less allowance of $223.7 ($252.2 in 2001) 3,437.5 3,005.2
Inventories 820.2 804.2
Energy risk management and trading assets 4,410.8 6,514.1
Margin deposits 660.8 213.8
Assets of discontinued operations 779.6 214.6
Deferred income taxes 253.6 440.6
Other 780.7 470.6
------------ ------------
Total current assets 12,759.9 12,938.0
Restricted cash 136.2 --
Investments 1,641.6 1,562.9
Property, plant and equipment, at cost 20,443.6 19,633.6
Less accumulated depreciation and depletion (5,056.7) (4,377.6)
------------ ------------
15,386.9 15,256.0
Energy risk management and trading assets 3,583.0 4,209.4
Goodwill, net 1,087.3 1,164.3
Assets of discontinued operations -- 2,658.9
Receivables from Williams Communications Group, Inc. less allowance of
$2,084.9 ($103.2 in 2001) 277.0 137.2
Other assets and deferred charges 995.8 979.5
------------ ------------
Total assets $ 35,867.7 $ 38,906.2
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Notes payable $ 929.0 $ 1,424.5
Accounts payable 2,745.5 2,861.5
Accrued liabilities 1,884.2 1,825.8
Liabilities of discontinued operations 340.7 211.6
Energy risk management and trading liabilities 4,330.8 5,525.7
Guarantees and payment obligations related to Williams Communications Group, Inc. 51.2 645.6
Long-term debt due within one year 1,393.0 999.8
------------ ------------
Total current liabilities 11,674.4 13,494.5
Long-term debt 12,293.6 8,702.8
Deferred income taxes 3,188.9 3,689.9
Liabilities of discontinued operations -- 864.3
Energy risk management and trading liabilities 1,994.7 2,936.6
Guarantees and payment obligations related to Williams Communications Group, Inc. -- 1,120.0
Other liabilities and deferred income 927.6 905.9
Contingent liabilities and commitments (Note 12)
Minority interests in consolidated subsidiaries 419.5 171.8
Preferred interests in consolidated subsidiaries -- 976.4
Stockholders' equity:
Preferred stock, $1 per share par value, 30 million shares authorized,
1.5 million issued in 2002, none in 2001 271.3 --
Common stock, $1 per share par value, 960 million shares authorized,
519.7 million issued in 2002, 518.9 million issued in 2001 519.7 518.9
Capital in excess of par value 5,169.0 5,085.1
Retained earnings (deficit) (653.2) 199.6
Accumulated other comprehensive income 131.2 345.1
Other (30.4) (65.0)
------------ ------------
5,407.6 6,083.7
Less treasury stock (at cost), 3.2 million shares of common stock in 2002
and 3.4 million in 2001 (38.6) (39.7)
------------ ------------
Total stockholders' equity 5,369.0 6,044.0
------------ ------------
Total liabilities and stockholders' equity $ 35,867.7 $ 38,906.2
============ ============
</Table>
* Certain amounts have been restated or reclassified as described in Note 2 of
Notes to Consolidated Financial Statements.
See accompanying notes.
3
The Williams Companies, Inc.
Consolidated Statement of Cash Flows
(Unaudited)
<Table>
<Caption>
(Millions) Nine months ended September 30,
- ---------- -------------------------------
2002 2001*
------------ ------------
OPERATING ACTIVITIES:
Income (loss) from continuing operations $ (634.0) $ 872.8
Adjustments to reconcile to cash provided (used) by operations:
Depreciation, depletion and amortization 607.8 479.2
Provision (benefit) for deferred income taxes (270.1) 385.2
Payments of guarantees and payment obligations related to Williams Communications
Group, Inc. (753.9) --
Estimated loss on realization of amounts due from Williams Communications Group, Inc. 269.9 --
Provision for loss on property and other assets 573.7 117.8
Net gain on dispositions of assets (204.6) (88.9)
Minority interest in income and preferred returns of consolidated subsidiaries 60.6 70.4
Tax benefit of stock-based awards 2.6 26.3
Accrual for interest in note payable 21.0 --
Cash provided (used) by changes in current assets and liabilities:
Restricted cash (151.9) --
Accounts and notes receivable (447.5) (776.4)
Inventories (28.1) (10.4)
Margin deposits (447.0) 423.0
Other current assets (454.2) (20.1)
Accounts payable (163.2) 175.0
Accrued liabilities (5.9) 482.2
Changes in current energy risk management and trading assets and liabilities 908.3 (783.2)
Changes in noncurrent energy risk management and trading assets and liabilities (315.5) (711.1)
Changes in noncurrent restricted cash (103.8) --
Other, including changes in noncurrent assets and liabilities 10.1 19.4
------------ ------------
Net cash provided (used) by operating activities of continuing operations (1,525.7) 661.2
Net cash provided by operating activities of discontinued operations 190.5 146.0
------------ ------------
Net cash provided (used) by operating activities (1,335.2) 807.2
------------ ------------
FINANCING ACTIVITIES:
Proceeds from notes payable 1,608.0 1,830.0
Payments of notes payable (2,303.0) (3,925.7)
Proceeds from long-term debt 3,490.0 3,503.8
Payments of long-term debt (1,948.7) (979.7)
Proceeds from issuance of common stock 25.1 1,397.2
Proceeds from issuance of preferred stock 271.3 --
Dividends paid (218.8) (237.9)
Proceeds from sale of limited partner units of consolidated partnership 279.3 92.5
Payment of Williams obligated mandatorily redeemable preferred securities of Trust
holding only Williams indentures -- (194.0)
Payments of debt issuance costs (186.9) (44.0)
Retirement of preferred interest in consolidated subsidiary (135.0) --
Payments/dividends to preferred and minority interests (58.0) (41.8)
Changes in restricted cash (203.8) --
Other--net (23.7) (.2)
------------ ------------
Net cash provided by financing activities of continuing operations 595.8 1,400.2
Net cash provided (used) by financing activities of discontinued operations (97.0) 1,386.8
------------ ------------
Net cash provided by financing activities 498.8 2,787.0
------------ ------------
INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures (1,383.5) (1,151.1)
Proceeds from dispositions 456.1 23.6
Changes in accounts payable and accrued liabilities 21.6 4.4
Acquisition of business (primarily property, plant & equipment), net of cash acquired -- (1,321.8)
Purchases of investments/advances to affiliates (284.3) (417.8)
Proceeds from sales of businesses 1,920.2 164.4
Proceeds from dispositions of investments and other assets 98.1 241.7
Proceeds received on advances to affiliates 75.0 20.0
Purchase of assets subsequently leased to seller (8.9) (276.0)
Other--net 28.8 12.1
------------ ------------
Net cash provided (used) by investing activities of continuing operations 923.1 (2,700.5)
Net cash used by investing activities of discontinued operations (95.1) (1,594.0)
------------ ------------
Net cash provided (used) by investing activities 828.0 (4,294.5)
------------ ------------
Cash of discontinued operations at spinoff -- (96.5)
------------ ------------
Decrease in cash and cash equivalents (8.4) (796.8)
Cash and cash equivalents at beginning of period** 1,301.1 1,210.7
------------ ------------
Cash and cash equivalents at end of period** $ 1,292.7 $ 413.9
============ ============
</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 $26.2
million, $37.3 million and $235.3 million at December 31, 2001,
September 30, 2001 and December 31, 2000, respectively.
See accompanying notes.
4
The Williams Companies, Inc.
Notes to Consolidated Financial Statements
(Unaudited)
1. General
- --------------------------------------------------------------------------------
Recent Developments
Recent events have significantly impacted the Company's operations and will
have a continuing impact on the Company's operations in the future. In the first
quarter of 2002, as a result of credit issues facing the Company and the
assumption of payment obligations and performance on guarantees associated with
Williams Communications Group, Inc. (WCG), Williams announced plans to
strengthen its balance sheet. During the second quarter, the results of the
Energy Marketing & Trading business were not profitable reflecting market
movements against its portfolio and an absence of origination activities. These
unfavorable conditions were in large part a result of market concerns about
Williams' credit and liquidity situation and limited Energy Marketing &
Trading's ability to manage market risk and exercise hedging strategies as
market liquidity deteriorated. During third-quarter 2002, Williams' credit
ratings were lowered below investment grade. Williams was also unable to
complete a renewal of its unsecured short-term bank credit facility. Following
these events, Williams sold assets in July 2002 receiving net proceeds of
approximately $1.5 billion, obtained secured credit facilities totaling $1.3
billion and amended its revolving credit facility to make it secured. Also
during the third quarter, Williams completed additional asset sales resulting in
net cash proceeds of approximately $466 million. Losses continued in the third
quarter from the Energy Marketing & Trading business reflecting the continued
negative market movements against the portfolio, the absence of origination
activities and the adverse affects of Williams' overall liquidity and credit
ratings issues, which impact Energy Marketing & Trading's ability to enter into
price risk management and hedging activities.
The Company has scheduled debt retirements due through first quarter 2004
of approximately $4.1 billion and anticipates significant additional asset sales
to meet its liquidity needs over that period. The Company has also reduced
projected levels of capital expenditures and the board of directors reduced the
quarterly dividend on common stock for the third quarter from the prior level of
$.20 per share to $.01 per share. The Company has also announced its intentions
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.
While the Company believes that these actions will significantly address
liquidity and credit concerns, the resulting downsizing of the Company will have
a significant impact on the Company's future financial position and results of
operations. The Company's ability to maintain liquidity and future operations
could be significantly impacted by other events, including the possibility that
the asset sales and reduction of the Company's commitment to its Energy
Marketing & Trading business will not be accomplished as currently anticipated.
The timing and amount of proceeds to be realized from the sale of assets is
subject to several variables, including negotiations with prospective buyers,
industry conditions, lender consents to the sale of collateral, regulatory
approvals and Williams' assessment of its short and long-term liquidity
requirements. The reduction of the Company's commitment to Energy Marketing &
Trading activities could be affected by the willingness of buyers and/or
potential partners to enter into transactions with Williams, giving
consideration to the current condition of the energy trading sector and
liquidity and credit constraints of Williams. As a result of these factors, the
proceeds that may be realized from the sales of assets, including the trading
portfolio, may be less than the carrying values at September 30, 2002, and could
result in additional impairments and losses. Additional information on these
events is discussed in the accompanying notes and in Management's Discussion and
Analysis.
Other
The accompanying interim consolidated financial statements of The Williams
Companies, Inc. (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' Current Report on Form 8-K
dated May 28, 2002. The accompanying unaudited financial statements include all
normal recurring adjustments and others, including asset impairments and loss
accruals, which, in the opinion of Williams' management, are necessary to
present fairly its financial position at September 30, 2002, its results of
operations for the three and nine months ended September 30, 2002 and 2001, and
its cash flows for the nine months ended September 30, 2002 and 2001.
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires management to make
estimates and assumptions that affect the amounts reported in the consolidated
financial statements and accompanying notes. Actual results could differ from
those estimates.
2. Basis of presentation
- --------------------------------------------------------------------------------
In accordance with the provisions related to discontinued operations within
Statement of Financial Accounting 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 7):
o Central natural gas pipeline, previously one of Gas Pipeline's
segments
o The Colorado soda ash mining operations, previously part of the
International segment
o Two natural gas liquids pipeline systems, Mid-American Pipeline and
Seminole Pipeline, previously part of the Midstream Gas & Liquids
segment
o Kern River Gas Transmission (Kern River), previously one of Gas
Pipeline's segments
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 the sales of those assets
occur.
Certain other statement of operations, balance sheet and cash flow amounts
have been reclassified to conform to the current classifications.
5
Notes (Continued)
3. Asset sales, impairments and other accruals
- --------------------------------------------------------------------------------
In first-quarter 2002, Williams offered an enhanced-benefit early
retirement option to certain employee groups. The deadline for electing the
early retirement option was April 26, 2002. The nine months ended September 30,
2002, reflects $30 million of expense associated with the early retirement
option, of which $24 million is recorded in selling, general and administrative
expenses and the remaining in general corporate expenses.
In a Form 8-K filed on May 28, 2002, Williams announced a plan that was
designed to further improve the company's financial position and more narrowly
focus its business strategy within its major business units. Part of this plan
included the generation of $1.5 billion to $3 billion of proceeds from the sale
of assets and/or businesses. Williams is continuing to evaluate the assets
and/or businesses that fit within its more narrowly focused business strategy,
and has identified certain assets and/or businesses, that are
more-likely-than-not to be disposed of before the end of their previously
estimated useful lives. The assets and/or businesses that did not meet the
criteria to be classified as held for sale at September 30, 2002, (see Note 2)
were evaluated for recoverability on a held-for-use basis pursuant to Statement
of Financial Accounting Standards (SFAS) No. 144, "Accounting for the Impairment
or Disposal of Long-Lived Assets." A probability-weighted approach was used to
consider the likelihood of possible outcomes including sale in the near term and
hold for the remaining estimated useful life. Key variables, including
management's estimate of fair value, probability of sale and selection of those
assets to be marketed for sale continued to be updated in third-quarter 2002.
For those assets and/or businesses that were not recoverable based on
undiscounted cash flows, an impairment loss was recognized in third-quarter 2002
based on management's estimate of fair value.
During second-quarter 2002, Williams identified the travel centers as a
business that does not fit within the new business strategy and began actively
marketing that business for sale. Probability-weighted undiscounted cash flows
for asset recoverability were estimated on a facility-by-facility basis. Fair
value estimates for the travel centers with an indicated impairment were based
on management's estimate of discounted cash flows using a probability-weighted
approach which considered the likelihood of sale and related sale proceeds and
the possibility of holding the asset for its remaining estimated useful life.
The $27 million loss recognized in second-quarter 2002 by Petroleum Services
includes both impairment charges related to stores owned by Williams and
liability accruals associated with a residual value guarantee of certain travel
centers under an operating lease. This operating lease is now considered a
capitalized lease due to changes in July 2002. During third quarter 2002,
management revised its assessment regarding the likelihood of sale and estimated
fair value of these facilities, reflective of information from the reserve
auction process and revision to the company's mix and timing of specific asset
sales. Petroleum Services recorded a $112.1 million impairment charge in
third-quarter 2002, to reflect the impact of these changed assumptions upon the
September 30, 2002 impairment valuation. Fair value was based on the expected
sales price pursuant to an agreement to sell the travel centers for $190 million
in cash, which was announced October 30, 2002.
During the second quarter of 2002, Williams announced its intention to sell
its refining operations as part of the strategy to improve the company's
financial position. These assets were part of a reserve auction process, for
which bids were received during third-quarter 2002. An impairment evaluation
performed for each of the refining operations resulted in a third quarter
impairment charge of $176.2 million associated with the Midsouth refining
long-lived assets, which was recorded in Petroleum Services. Fair value was
based on management's assessment of the expected sales price pursuant to
information from the reserve auction process using a probability-weighted
approach.
The Company is currently engaged in a reserve auction process for its
bio-energy facilities, which are primarily engaged in the production and
marketing of ethanol. During third-quarter 2002, management revised its
assessment of the likelihood of sale and estimated fair value of these
facilities, also reflective of the maturation of the reserve auction process and
revisions to the company's mix and timing of specific asset sales. As a result,
the September 30, 2002 measure of probability-weighted undiscounted cash flows
were below the carrying cost of the long-lived assets, resulting in a
third-quarter impairment charge of $144.3 million, including $21.6 million
related to goodwill, recorded by Petroleum Services. Fair value was based upon
management's estimate of undiscounted cash flows using a probability-weighted
approach considering the current information from the reserve auction process.
Additionally, as Williams has more narrowly focused its business strategy
and reduced planned capital spending, certain projects will not be further
developed. As a result, Williams has written-off capitalized costs and accrued
for estimated costs associated with termination of these projects. For the three
and nine months ended September 30, 2002, Energy Marketing & Trading recorded
charges totalling $11.5 million and $95.2 million, respectively, including
write-offs associated with a terminated power plant project and accruals for
commitments for certain assets that were previously planned to be used in power
projects.
6
Notes (Continued)
Energy Marketing & Trading recognized a $57.5 million goodwill impairment
loss in second-quarter 2002 reflecting deteriorating market conditions in the
merchant energy sector in which it operates and Energy Marketing & Trading's
resulting announcement in June 2002 to scale back its own energy marketing and
risk management business. The fair value of Energy Marketing & Trading used to
calculate the goodwill impairment loss was based on the estimated fair value of
the trading portfolio inclusive of the fair value of contracts with affiliates,
which are not reflected at fair value in the financial statements. The fair
value of these contracts was estimated using a discounted cash flow model with
natural gas pricing assumptions based on current market information. The
remaining goodwill was evaluated for impairment in third-quarter 2002 and no
impairment was required based on management's estimate of the fair value of
Energy Marketing & Trading at September 30, 2002.
Significant gains or losses from asset sales, impairments and other
accruals included in other (income) expense - net within segment costs and
expenses are included in the following table.
<Table>
<Caption>
Three months ended Nine months ended
September 30, September 30,
------------------------------ ------------------------------
(Millions) 2002 2001 2002 2001
---------- ------------ ------------ ------------ ------------
ENERGY MARKETING & TRADING
Net loss accruals and write-offs $ 11.5 $ -- $ 95.2 $ --
Impairment of goodwill -- -- 57.5 --
EXPLORATION & PRODUCTION
Gain on sale of natural gas
production properties in
Wyoming (122.3) -- (122.3) --
Gain on sale of natural gas
production properties in
Anadarko basin (21.6) -- (21.6) --
MIDSTREAM GAS & LIQUIDS
Impairment of south Texas
assets -- 4.2 -- 15.1
PETROLEUM SERVICES
Impairment of Midsouth refinery 176.2 -- 176.2 --
Impairment of bio-energy
facilities, including
goodwill impairment 144.3 -- 144.3 --
Gain on sale of certain
convenience stores -- -- -- (72.1)
Impairment of end-to-end
mobile computing systems
business -- -- -- 11.2
Impairment and other loss
accruals for travel centers 112.1 -- 139.1 --
</Table>
4. Receivables from Williams Communications Group, Inc. and other related
information
- --------------------------------------------------------------------------------
Background
At December 31, 2001, Williams had financial exposure from WCG of $375
million of receivables and $2.21 billion of guarantees and payment obligations.
Williams determined it was probable it would not fully realize the $375 million
of receivables, and it would be required to perform under its $2.21 billion of
guarantees and payment obligations. Williams developed an estimated range of
loss related to its total WCG exposure and management believed that no loss
within that range was more probable than another. For 2001, Williams recorded
the $2.05 billion minimum amount of the range of loss from its financial
exposure to WCG, which was reported in the Consolidated Statement of Operations
as a $1.84 billion pre-tax charge to discontinued operations and a $213 million
pre-tax charge to continuing operations. The charge to discontinued operations
of $1.84 billion included a $1.77 billion minimum amount of the estimated range
of loss from performance on $2.21 billion of guarantees and payment obligations.
The charge to continuing operations of $213 million included estimated losses
from an assessment of the recoverability of the carrying amounts of the $375
million of receivables and a remaining $25 million investment in WCG common
stock.
7
Notes (Continued)
Williams, prior to the spinoff of WCG, provided indirect credit support for
$1.4 billion of WCG's Note Trust Notes. On March 5, 2002, Williams received the
requisite approvals on its consent solicitation to amend the terms of the WCG
Note Trust Notes. The amendment, among other things, eliminated acceleration of
the WCG Note Trust Notes due to a WCG bankruptcy or from a Williams credit
rating downgrade. The amendment also affirmed Williams' obligation for all
payments due with respect to the WCG Note Trust Notes, which mature in March
2004, and allows Williams to fund such payments from any available sources. In
July 2002, Williams acquired substantially all of the WCG Note Trust Notes by
exchanging $1.4 billion of Williams Senior Unsecured 9.25 percent Notes due
March 2004. In November 2002, Williams acquired the remaining outstanding
WCG Note Trust Notes.
Williams also provided a guarantee of WCG's obligations under a 1998
transaction in which WCG entered into a lease agreement covering a portion of
its fiber-optic network. WCG had an option to purchase the covered network
assets during the lease term at an amount approximating the lessor's cost of
$750 million. On March 8, 2002, WCG exercised its option to purchase the covered
network assets. On March 29, 2002, Williams funded the purchase price of $754
million and became entitled to an unsecured note from WCG for the same amount.
Williams has also provided guarantees on certain other performance
obligations of WCG totaling approximately $57 million.
2002 Evaluation
At September 30, 2002, Williams had receivables and claims from WCG of
$2.15 billion arising from Williams affirming its payment obligation on the $1.4
billion of WCG Note Trust Notes and Williams paying $754 million under the WCG
lease agreement. At September 30, 2002, Williams also had $334 million of
previously existing receivables. In third-quarter 2002, Williams recorded in
continuing operations a pre-tax charge of $22.9 million related to WCG,
including an assessment of the recoverability of its receivables and claims from
WCG. For the nine months ended September 30, 2002, Williams has recorded in
continuing operations pre-tax charges of $269.9 million related to the recovery
of these receivables and claims. At September 30, 2002, Williams estimates that
approximately $2.2 billion of the $2.5 billion of receivables from WCG are not
recoverable.
On April 22, 2002, WCG filed for bankruptcy protection under Chapter 11 of
the U.S. Bankruptcy Code. On October 15, 2002, WCG consummated its Chapter 11
Plan of Reorganization (Plan). The Plan was confirmed by the United States
Bankruptcy Court for the Southern District of New York (Court) on September 30,
2002.
The Plan includes (1) mutual releases, effective October 15, 2002, between
WCG (and all of its affiliates and each of their present and former directors,
officers, employees and agents), the Official Creditors Committee and Williams
(and all of its affiliates and each of their present and former directors,
officers, employees and agents), which forever bar causes of action against
Williams that are based in whole or in part on any act, omission, event,
condition or thing in existence or that occurred in whole or in part prior to
October 15, 2002, and arising out of or relating in any way to WCG or its
present or former assets; (2) a channeling injunction, effective October 15,
2002, which enjoins the holders of unsecured claims against WCG from taking any
action to assert, seek or obtain a recovery from Williams; (3) the sale of
certain of Williams' claims against WCG to Leucadia National Corporation
(Leucadia) for $180 million; and (4) the sale by Williams to WCG of the Williams
Technology Center and certain related assets for (a) a seven and one-half year
promissory note in the principal amount of $100 million with interest at 7
percent (Long Term Note) secured by a mortgage on the Williams Technology Center
and certain other collateral, and (b) a four year promissory note (which may be
pre-paid without penalty) with face amount of $74.4 million and an original
principal amount of $44.8 million (Short Term Note) secured by a mortgage on the
Williams Technology Center and certain other collateral. Interest on the
principal amount of the Short Term Note is capitalized on December 31 of each
year beginning in 2003 and accrues at the following rates: 10 percent interest
from October 15, 2002 to December 31, 2003; 12 percent interest from January 1,
2004 to December 31, 2004; 14 percent interest from January 1, 2005 to December
31, 2005; and 16 percent interest from January 1, 2006 to December 29, 2006. The
Plan does not extinguish or eliminate claims that WCG shareholders have made
against Williams and its directors and officers.
Because of the timing of applications made by WilTel Communications Group,
Inc. formerly WCG (WilTel), to the Federal Communication Commission (FCC) for
the transfer by WCG to WilTel of certain telecommunications licenses, pursuant
to the Plan and the Court's order confirming the Plan, certain components of the
Plan (including the following) were placed into escrow pending the issuance of
certain permanent licenses to WilTel by the FCC: (1) a cash collateralized
letter of credit that expires on March 14, 2003 in the amount of $181 million
issued by Fleet National Bank for the account of Leucadia in respect of
Leucadia's obligation to pay for the claims it purchased from Williams; and (2)
documents related to the sale of the Williams Technology Center and certain
related assets including the Short Term Note and the Long Term Note. The
escrowed items will be released upon the issuance of specified permanent
licenses from the FCC provided that no objections are filed by any third party.
If the FCC has not granted the permanent licenses by February 28, 2003, or if
objections are pending (which have not been resolved to Leucadia's reasonable
satisfaction), the escrow unwinds. In the event the escrow unwinds, then (i) the
letter of
8
Notes (Continued)
credit will either expire by its terms on March 14, 2003, or will be returned to
Leucadia, and (ii) 11,775,000 common shares of WilTel will be returned by
Leucadia to the escrow agent for distribution to Williams in accordance with the
terms of the escrow agreement. Should that distribution to Williams occur, it is
anticipated that Williams would own approximately 30 percent of the outstanding
common stock of WilTel and the right to designate two board seats on WilTel's
board of directors. During the escrow period, WilTel is obligated to pay
Williams monthly lease payments in accordance with the September 2001
sale-leaseback transaction with respect to the Williams Technology Center and
certain related assets. When the escrowed items are released, Williams will
credit WilTel by reducing the Long Term Note by the difference between the
sale-leaseback payments and the note payments. In the event the escrow unwinds,
the sale-leaseback transaction will continue unaffected.
At September 30, 2002, Williams estimated recoveries of its receivables and
claims against WilTel based on the agreements included in the Plan. Williams'
net receivable at September 30, 2002 includes $180 million related to the sale
of its claim to Leucadia and $122 million as the fair value of its notes from
WilTel. The fair value of the notes from WilTel was based on an estimated
discount rate considering the creditworthiness of WilTel, the amount and timing
of the cash flows and Williams' security in the Williams Technology Center and
certain other collateral. Williams believes the transactions contemplated by
these agreements provide the most relevant information available to estimate the
recovery of its receivables and claims, as they represent third party
transactions that Williams' management has executed pending the outcome of the
escrow.
Prior to second-quarter 2002, Williams had estimated the recovery of its
receivables from WCG by performing a financial analysis and utilizing the
assistance of external legal counsel and an external financial and restructuring
advisor. In preparing its financial analysis, Williams and its external
financial and restructuring advisor considered the overall market condition of
the telecommunications industry, financial projections provided by WCG, the
potential impact of a bankruptcy on WCG's financial performance, the nature of
the proposed restructuring as detailed in WCG's bankruptcy filing and various
issues discussed in negotiations prior to WCG's bankruptcy filing.
Actual recoveries may ultimately differ from currently estimated recoveries
if the escrow unwinds causing Williams to receive common stock equity in WilTel
and the existing sale - leaseback transaction to remain in place.
5. Investing income (loss)
- --------------------------------------------------------------------------------
Estimated loss on realization of amounts due from Williams Communications Group,
Inc.
For the three and nine months ended September 30, 2002, Williams has
recorded in continuing operations pre-tax charges of $22.9 million and $269.9
million, respectively, related to the recoverability of these receivables and
claims (see Note 4).
Other
Other investing income (loss) for the three and nine months ended September
30, 2002 and 2001, is as follows:
<Table>
<Caption>
Three months ended Nine months ended
September 30, September 30,
----------------------------- -----------------------------
(Millions) 2002 2001 2002 2001
---------- ------------ ------------ ------------ ------------
Equity earnings* $ 19.1 $ 10.3 $ 79.7 $ 21.8
Income (loss) from investments* 55.1 (23.3) 42.8 4.2
Write-down of WCG common stock investment -- (70.9) -- (70.9)
Interest income and other 11.1 14.3 39.0 84.8
------------ ------------ ------------ ------------
Total other investing income (loss) $ 85.3 $ (69.6) $ 161.5 $ 39.9
============ ============ ============ ============
</Table>
* Items also included in segment profit (loss).
Equity earnings for the nine months ended September 30, 2002, include a
benefit of $27.4 million, reflecting a contractual construction completion fee
received by an equity affiliate of Williams whose operations are accounted for
under the equity method of accounting. This equity affiliate served as the
general contractor on the Gulfstream pipeline project for Gulfstream Pipeline
Natural Gas System (Gulfstream), an interstate natural gas pipeline subject to
Federal Energy Regulatory Commission (FERC) regulations and an equity affiliate
of Williams. The fee paid by Gulfstream, associated with the early completion
during second-quarter of the construction of Gulfstream's pipeline, was
capitalized by Gulfstream as property, plant and equipment and is included in
Gulfstream's rate base to be recovered in future revenues.
9
Notes (Continued)
Included in income (loss) from investments for the three and nine months
ended September 30, 2002, are the following:
o $58.5 million gain on sale of Williams' investment in a Lithuanian oil
refinery, pipeline and terminal complex, which was included in the
International segment
o $8.7 million gain on sale of Williams' general partner equity interest
in Northern Border Partners, L.P., which was included in the Gas
Pipeline segment
o $11.6 million net write-down pursuant to terms of an announced sale of
Williams' equity interest in a Canadian and U.S. gas pipeline, which
was included in the Gas Pipeline segment
o $12.3 million write-down of Gas Pipeline's investment in a pipeline
project which was cancelled in the second-quarter 2002 (included in
the nine months only)
Included in income (loss) from investments for the three and nine months
ended September 30, 2001, are the following:
o $23.3 million write-downs of certain other investments, which were
included in the Energy Marketing & Trading segment
o $27.5 million gain on the sale of Williams' limited partnership
interest in Northern Border Partners, L. P., which was included in the
Gas Pipeline segment (included in nine months only)
The $70.9 million write-down of the WCG investment included in the three
and nine months ended September 30, 2001, resulted from a decline in the value
of the WCG common stock which was determined to be other than temporary.
6. Provision (benefit) for income taxes
- --------------------------------------------------------------------------------
The provision (benefit) for income taxes from continuing operations
includes:
<Table>
<Caption>
Three months ended Nine months ended
September 30, September 30,
------------------------------ ------------------------------
(Millions) 2002 2001 2002 2001
---------- ------------ ------------ ------------ ------------
Current:
Federal $ (100.3) $ 17.3 $ (63.7) $ 189.3
State 10.0 (1.1) 10.0 31.6
Foreign 10.8 2.8 10.8 9.1
------------ ------------ ------------ ------------
(79.5) 19.0 (42.9) 230.0
Deferred:
Federal (103.8) 138.2 (211.6) 342.5
State (60.2) 19.8 (70.2) 34.7
Foreign 11.7 5.8 11.7 8.0
------------ ------------ ------------ ------------
(152.3) 163.8 (270.1) 385.2
------------ ------------ ------------ ------------
Total provision (benefit) $ (231.8) $ 182.8 $ (313.0) $ 615.2
============ ============ ============ ============
</Table>
The effective income tax rate for the three months ended September 30,
2002, is greater than the federal statutory rate due primarily to the effect of
state income taxes, offset by the effects of taxes on foreign operations.
The effective income tax rate for the nine months ended
September 30, 2002, is less than the federal statutory rate due primarily to the
effect of taxes on foreign operations and the impairment of goodwill, which is
not deductible for income tax purposes, and reduces the tax benefit of the
pre-tax loss, offset by the effect of state income taxes.
The effective income tax rate for the three and nine months ended September
30, 2001, is greater than the federal statutory rate due primarily to valuation
allowances associated with the tax benefits for investment write-downs for which
ultimate realization is uncertain and the effect of state income taxes.
10
Notes (Continued)
7. Discontinued operations
- --------------------------------------------------------------------------------
2002 Transactions
In accordance with the provisions related to discontinued operations within
SFAS No. 144, the results of operations for the following asset and/or business
sales have been reflected in the consolidated financial statements as
discontinued operations:
Central
During third-quarter 2002, Williams' board of directors approved an agreement
to sell one of its Gas Pipeline segments, Central natural gas pipeline, for $380
million in cash and the assumption by the purchaser of $175 million in debt. As
a result of the board of directors' approval, Central met the criteria within
SFAS No. 144 to be considered "held for sale" at September 30, 2002. The sale is
expected to close in fourth-quarter 2002. The sale agreement results from
efforts to market this asset through a reserve price auction process that was
initiated during second-quarter 2002. A third-quarter 2002 impairment charge of
$86.9 million is recorded as a component of impairments and gain (loss) on sales
from discontinued operations (included in the following table) reflecting the
excess of the September 30, 2002, carrying cost of the long-lived assets over
management's estimate of fair value less costs to sell Central. Fair value was
based upon terms of the sales agreement, with the final bid level reflecting a
decline from initial offers received in the earlier stages of the reserve
auction process.
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
$1.16 billion and a pre-tax gain of $304.6 million which is recorded in
third-quarter 2002 as a component of impairments and gain (loss) on sales from
discontinued operations (included in the following table). Mid-America Pipeline
is a 7,726-mile natural gas liquids pipeline system. Seminole Pipeline is a
1,281-mile natural gas liquids pipeline system. These assets were part of the
Midstream Gas & Liquids segment.
Soda ash operations
In March 2002, Williams announced its intentions to sell its soda ash mining
facility located in Colorado, which was previously written-down to estimated
fair value at December 31, 2001, and in April 2002, Williams initiated a
reserve-auction process. As this process and negotiations with interested
parties progressed, new information regarding estimated fair value became
available. As a result, an additional impairment loss of $44.1 million was
recognized in second-quarter 2002 by the International segment. Management's
estimate of fair value used to calculate the impairment loss was based on
discounted cash flows assuming sale of the facility in 2002. 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. As a result of the
board of directors' approval and management's expectation of consummation of a
sale, these operations met the criteria within SFAS No. 144 to be held for sale
at September 30, 2002. An additional pre-tax impairment of $48.2 million was
recorded in third-quarter 2002 and is recorded as a component of impairments and
gain (loss) on sales from discontinued operations (included in the following
table), reflective of management's estimate of fair value associated with
revised terms of its negotiations to sell the operations.
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 from discontinued operations (included in the following
table) is a pre-tax gain of $31.7 million and a pre-tax loss of $6.4 million for
the three and nine months ended September 30, 2002, respectively.
11
Notes (Continued)
2001 Transactions
On March 30, 2001, Williams' board of directors approved a tax-free spinoff
of WCG to Williams' shareholders. Williams distributed 398.5 million shares, or
approximately 95 percent of the WCG common stock held by Williams on April 23,
2001. In accordance with Accounting Principles Board Opinion No. 30, "Reporting
the Results of Operations - Reporting the Effects of Disposal of a Segment of a
Business, and Extraordinary, Unusual, and Infrequently Occurring Events and
Transactions," the results of operations and cash flows for WCG have been
reflected in the accompanying Consolidated Statement of Operations and
Consolidated Statement of Cash Flows and notes as discontinued operations. See
Note 4 for information regarding events in 2002 related to WCG.
Summarized results of discontinued operations
Summarized results of discontinued operations for the three and nine months
ended September 30, 2002 and 2001, are as follows:
<Table>
<Caption>
Three months ended Nine months ended
September 30, September 30,
------------------------ ------------------------
(Millions) 2002 2001 2002 2001
- ---------- ---------- ---------- ---------- ----------
2002 Transactions:
Revenues $ 66.4 $ 155.0 $ 326.0 $ 429.8
Income from operations before
income taxes $ 8.3 $ 42.3 $ 69.1 $ 105.4
Impairments and gain (loss) on sales 201.2 -- 119.0 --
Provision for income taxes (94.9) (14.9) (89.6) (39.1)
---------- ---------- ---------- ----------
$ 114.6 $ 27.4 $ 98.5 $ 66.3
---------- ---------- ---------- ----------
2001 Transactions:
Revenues $ -- $ -- $ -- $ 329.5
Loss from operations before
income taxes $ -- $ -- $ -- $ (271.3)
Benefit for income taxes -- -- -- 92.2
---------- ---------- ---------- ----------
$ -- $ -- $ -- $ (179.1)
---------- ---------- ---------- ----------
Total income (loss) from discontinued
operations $ 114.6 $ 27.4 $ 98.5 $ (112.8)
========== ========== ========== ==========
</Table>
12
Notes (Continued)
Summarized assets and liabilities of discontinued operations
Summarized assets and liabilities of discontinued operations as of September
30, 2002 and December 31, 2001, are as follows:
<Table>
<Caption>
September 30, December 31,
(Millions) 2002 2001
- ---------- ------------- ------------
Total current assets $ 779.6 $ 214.6
------------ ------------
Property, plant and equipment -- 2,463.2
Other non-current assets -- 195.7
------------ ------------
Total non-current assets -- 2,658.9
------------ ------------
Total assets $ 779.6 $ 2,873.5
------------ ------------
Long-term debt due within one year -- 37.0
Other current liabilities 340.7 174.6
------------ ------------
Total current liabilities 340.7 211.6
------------ ------------
Long-term debt -- 797.9
Other non-current liabilities -- 66.4
------------ ------------
Total non-current liabilities -- 864.3
------------ ------------
Total liabilities $ 340.7 $ 1,075.9
============ ============
</Table>
At September 30, 2002, Central and the soda ash operations had been approved
for sale by Williams' board of directors. Because the sales are expected to
close within 12 months, the discontinued assets and liabilities have been
reclassified to the current section of the balance sheet as assets and
liabilities held for sale for September 30, 2002. December 31, 2001 has been
restated to include Central and the soda ash operations as discontinued
operations, but the assets and liabilities for Central and the soda ash
operations were not reclassified to current assets and liabilities.
8. 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 Nine months ended
amounts; shares in thousands) September 30, September 30,
- -------------------------------------- ---------------------------- ----------------------------
2002 2001 2002 2001
------------ ------------ ------------ ------------
Income (loss) from continuing operations $ (408.7) $ 193.9 $ (634.0) $ 872.8
Preferred stock dividends (see Note 14) (6.8) -- (83.3) --
------------ ------------ ------------ ------------
Income (loss) from continuing operations
available to common stockholders
for basic and diluted earnings per share $ (415.5) $ 193.9 $ (717.3) $ 872.8
============ ============ ============ ============
Basic weighted-average shares 516,901 502,877 516,688 489,813
Effect of dilutive securities:
Stock options -- 3,288 -- 3,999
------------ ------------ ------------ ------------
Diluted weighted-average shares 516,901 506,165 516,688 493,812
------------ ------------ ------------ ------------
Earnings (loss) per share from continuing operations:
Basic $ (.80) $ .39 $ (1.39) $ 1.78
Diluted $ (.80) $ .39 $ (1.39) $ 1.77
============ ============ ============ ============
</Table>
13
Notes (Continued)
For the three and nine months ended September 30, 2002, 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 these
periods. As a result, approximately 7.6 thousand and 880 thousand
weighted-average stock options for the three and nine months ended September 30,
2002, respectively, that otherwise would have been included, were excluded from
the computation of diluted earnings per common share. Additionally,
approximately 14.7 million and 10.1 million weighted-average shares for the
three and nine months ended September 30, 2002, respectively, related to the
assumed conversion of 9 7/8 percent cumulative convertible preferred stock and
approximately 4.1 million and 3.5 million weighted average unvested deferred
shares for the three and nine months ended September 30, 2002, respectively,
have been excluded from the computation of diluted earnings per common share.
9. Restricted cash
- --------------------------------------------------------------------------------
Restricted cash within current assets consists primarily of cash collateral
as required under the $900 million short-term Credit Agreement (see Note 11),
collateral in support of a financial guarantee and letters of credit. Restricted
cash within noncurrent assets consists primarily of collateral in support of
surety bonds underwritten by an insurance company and letters of credit.
Williams does not expect this cash to be released within the next twelve months.
The current and noncurrent restricted cash is primarily invested in
short-term money market accounts with financial institutions and an insurance
company as well as treasury securities. The classification of restricted cash is
determined based on the expected term of the collateral requirement and not
necessarily the maturity date of the underlying securities.
10. Inventories
- --------------------------------------------------------------------------------
Inventories at September 30, 2002 and December 31, 2001 are as follows:
<Table>
<Caption>
September 30, December 31,
(Millions) 2002 2001
------------- ------------
Raw materials:
Crude oil $ 158.4 $ 117.7
Other 1.3 1.3
---------- ----------
159.7 119.0
Finished goods:
Refined products 170.2 265.0
Natural gas liquids 201.8 142.6
General merchandise 19.0 14.5
---------- ----------
391.0 422.1
Materials and supplies 138.7 124.9
Natural gas in underground storage 128.0 136.4
Other 2.8 1.8
---------- ----------
$ 820.2 $ 804.2
========== ==========
</Table>
11. Debt and banking arrangements
- --------------------------------------------------------------------------------
Secured credit facilities
In third-quarter 2002, Williams obtained a $400 million letter of credit
facility, a $900 million short-term loan (discussed below) and amended its
existing revolving credit facility. The $400 million letter of credit facility,
which expires July 2003, and the revolving credit facility which expires July
2005, are secured by substantially all of Williams' Midstream Gas & Liquids
assets and the equity of substantially all of the Midstream Gas & Liquids
subsidiaries and the subsidiaries which own the refinery assets. These
facilities are also guaranteed by most of Williams' subsidiaries, except for
Transcontinental Gas Pipe Line, Texas Gas and Northwest Pipeline. As of
September 30, 2002, Williams has $660 million of additional secured borrowing
capacity available under its revolving credit facility.
14
Notes (Continued)
Additionally, the company is no longer required to make a "no material
adverse change" representation prior to borrowings under the revolving credit
facility. An additional $159 million of public securities were also ratably
secured with the same assets in accordance with the indentures covering those
securities. Additionally, as Williams completes asset sales, the commitments
from participating banks in the revolving credit facility will be reduced and
various other preexisting debt will be paid down. As of September 30, 2002, the
revolving credit facility commitment had been reduced to $660 million.
Transcontinental Gas Pipe Line, Texas Gas and Northwest Pipeline continue as
participating borrowers in this facility. Significant new covenants under these
agreements include: (i) restrictions on the creation of new subsidiaries, (ii)
additional restrictions on pledging assets to other creditors, (iii) a covenant
that the ratio of interest expense plus cash flow to interest expense be greater
than 1.5 to 1, (iv) a limit on dividends on common stock paid by Williams in any
quarter of $6.25 million, (v) certain restrictions on declaration or payment of
dividends on preferred stock issued after July 30, 2002, (vi) a limit on
investments in others of $50 million annually, (vii) a $50 million limit on
additional debt incurred by subsidiaries other than Transcontinental Gas Pipe
Line, Texas Gas, Northwest Pipeline or Williams Energy Partners L.P. and (viii)
modified the net debt to consolidated net worth plus net debt financial covenant
to increase the threshold to 70 percent through December 30, 2002, and then
after December 30, 2002 but on or before March 30, 2003 not to exceed 68 percent
and after March 30, 2003 the ratio shall not exceed 65 percent.
Williams Production RMT Company (RMT), a wholly owned subsidiary, entered
into a $900 million short-term Credit Agreement dated July 31, 2002, with
certain lenders including a subsidiary of Lehman Brothers, Inc., a related party
to Williams. The loan, reported in Notes Payable in the Consolidated Balance
Sheet, is guaranteed by Williams, Williams Production Holdings LLC (Holdings)
and certain RMT subsidiaries. It is also secured by the capital stock and assets
of Holdings and certain of RMT's subsidiaries. The assets of RMT are comprised
primarily of the assets of the former Barrett Resources Corporation acquired in
2001, which were primarily natural gas properties in the Rocky Mountain region.
The loan matures on July 25, 2003, and bears interest payable quarterly at the
Eurodollar rate plus 4 percent per annum (5.810 percent at September 30, 2002),
plus additional interest of 14 percent per annum, which is accrued and added to
the principal balance. The principal balance at September 30, 2002, was $921
million.
RMT must also pay a deferred set-up fee. The amount of the fee is dependant
upon whether a majority of the fair market value of RMT's assets or a majority
of its capital stock is sold (company sale) on or before the maturity date,
regardless of whether the loan obligations have been repaid. If a company sale
has occurred, the amount of such fee would be the greater of (x) 15 percent of
the loan principal amount, and (y) 15 percent to 21 percent, depending on the
timing of the company sale, of the difference between (A) the purchase price of
such company sale, including the amount of any liabilities assumed by the
purchaser, up to $2.5 billion, and (B) the sum of (1) the principal amount of
the outstanding loans, plus (2) outstanding debt of RMT and its subsidiaries,
plus (3) accrued and unpaid interest on the loans to the date of repayment. If a
company sale has not occurred, the fee would be 15 percent of the loan amount.
However, if a company sale occurs within three months after the maturity date,
then RMT must also pay the positive difference, if any, between the fee that
would have been paid had such company sale occurred prior to the maturity date
and the actual fee paid on the maturity date.
Significant covenants on Holdings, RMT and certain RMT subsidiaries under the
loan agreement include: (i) an interest coverage ratio of greater than 1.5 to 1,
(ii) a fixed charge coverage ratio of greater than 1.15 to 1, (iii) a limitation
on restricted payments, (iv) a limitation on capital expenditures in excess of
$300 million and (v) a limitation on intercompany indebtedness.
Under the RMT Credit Agreements, Williams must maintain actual and
projected parent liquidity (a) at any time from the closing date through the
180th day thereafter, of $600 million; (b) at any time thereafter through and
including the maturity date, of $750 million; and (c) only projected liquidity
for twelve months after the maturity date, of $200 million. If a default were to
occur with respect to parent liquidity, RMT must be sold within 75 days.
Liquidity projections must be provided weekly until the maturity date. Each
projection covers a period extending 12 months from the report date. The loan is
also required to be prepaid with the net cash proceeds of any sales of RMT's
assets, and, in the event of a company sale, the loan is required to be prepaid
in full. A prepayment or acceleration of the loan requires RMT to pay to lenders
(i) a make-whole amount, and (ii) the deferred set up fee set forth above. A
partial prepayment of the loan requires RMT to pay a pro rata portion of the
make-whole amount and deferred set up fee.
Additionally, Williams amended certain other financing facilities and
agreements totaling $1.9 billion which provided the lenders thereunder with
guarantees from Williams Gas Pipeline Company, L.L.C. and Williams Production
Holdings LLC and certain lenders with a ratable share of proceeds from future
asset sales to reduce certain of these facilities. These facilities and
agreements include the preferred interest in Castle Associates LP (Castle), $600
million of term loans, certain letters of credit, two operating lease agreements
with special purpose entities, the preferred interest in Piceance Production
Holdings LLC (Piceance) and the preferred interest in Snow Goose Associates,
L.L.C., which is currently classified as debt. As a result of the changes to the
two operating lease agreements, these leases are now reported as a capitalized
leases as of September 30, 2002. Additionally, the preferred interests in Castle
and Piceance are now reported as debt.
15
Notes (Continued)
Notes payable
In addition to the $921 million RMT note payable discussed previously,
Williams has entered into various short-term credit agreements with amounts
outstanding totaling $8 million at September 30, 2002. The weighted-average
interest rate on these notes at September 30, 2002 was 4.65 percent. At
September 30, 2002, a $411 million note payable by Williams Energy Partners L.P.
(WEP) a partially owned and consolidated entity of Williams, has been
reclassified to long-term debt as discussed below.
Debt
Long-term debt at September 30, 2002 and December 31, 2001, is as follows:
<Table>
<Caption>
Weighted-
average
interest September 30, December 31,
(Millions) rate 2002 2001
- ---------- ------------ ------------- ------------
Secured Debt
- ------------
Revolving credit loans 7.0% $ 81.3 $ --
Debentures, 9.9% payable 2020 9.9 28.7 --
Notes, 8.2% - 9.45%, payable 2002-2022 9.0 265.8 --
Notes, adjustable rate, payable through 2004 3.3 13.6 --
Other 6.8 306.7 --
Unsecured Debt
- --------------
Revolving credit loans 3.3% 58.0 53.7
Commercial paper -- -- 300.0
Debentures, 6.25% - 10.25%, payable 2003 - 2031 7.4 1,547.9 1,585.4
Notes, 6.125% - 9.25%, payable through 2032(1) 7.7 9,650.8 6,510.7
Notes, adjustable rate, payable through 2004 5.3 1,381.7 1,192.9
Other 6.3 352.1 59.9
------------ ------------
$ 13,686.6 $ 9,702.6
Current portion of long-term debt (1,393.0) (999.8)
------------ ------------
$ 12,293.6 $ 8,702.8
============ ============
</Table>
(1) $400 million of 6.75% notes, payable 2016, putable/callable in 2006 and $1.1
billion of 6.5% notes payable 2007, subject to remarketing in 2004.
Williams' December 31, 2001, long-term debt included $300 million of
commercial paper, $300 million of short-term debt obligations and $244 million
of long-term debt obligations due within one year, which would have otherwise
been classified as current, but were classified as noncurrent based on Williams'
intent and ability to refinance on a long-term basis. At September 30, 2002, a
$411 million note payable by WEP has been reclassified to long-term debt based
on WEP's new debt agreement entered into October 2002. On October 31, 2002,
Williams Pipe Line LLC, a subsidiary of WEP, and WEP, entered into a private
placement debt agreement, effective October 1, 2002, with a group of financial
institutions providing for the issuance of up to $200 million aggregate
principal amount of Floating Rate Series A Senior Secured Notes and up to $340
million aggregate principal amount of Fixed Rate Series B Senior Secured Notes,
upon satisfaction of certain conditions precedent, which will be used to
refinance the note payable by WEP. As part of this agreement, WEP agreed not to
redeem or retire the Class B Units held by the general partner except with
equity issuance proceeds. WEP and its subsidiaries are legally separate entities
from Williams and its subsidiaries, and the assets owned by WEP are generally
not available for the payment of debts owed to the creditors of Williams and
its subsidiaries.
Pursuant to completion of a consent solicitation during first-quarter 2002
with WCG Note Trust Note holders, Williams recorded $1.4 billion of long-term
debt obligations. In July 2002, Williams acquired substantially all of the WCG
Note Trust Notes by exchanging $1.4 billion of Williams Senior Unsecured 9.25
percent notes due March 2004. In November 2002, Williams acquired the remaining
outstanding WCG Note Trust Notes (see Note 4).
Under the terms of Williams' revolving credit agreement (which as of
September 30, 2002 had reduced to $660 million, as discussed previously),
Northwest Pipeline and Transcontinental Gas Pipe Line 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 with current
market conditions. At September 30, 2002, there were no amounts outstanding
under this agreement. Additionally, certain Williams subsidiaries have revolving
credit facilities with an available capacity of $35 million at September 30,
2002.
In March 2002, the terms of a Williams $560 million priority return
structure, previously classified as preferred interest in consolidated
subsidiaries, were amended. The amendment provided for the outside investor's
preferred interest to be redeemed in equal quarterly installments through April
2003 (see Note 13). The interest rate varies based on LIBOR plus an applicable
margin and was 2.803 percent at September 30, 2002. Through September 30, 2002,
$224 million has been redeemed. Based on the new payment terms, the remaining
outstanding preferred interest of $336 million is classified as long-term debt
due within one year at September 30, 2002.
In May 2002, Energy Marketing & Trading entered into an agreement which
transferred the rights to certain receivables in exchange for cash. Due to the
structure of the agreement, Energy Marketing & Trading accounted for this
transaction as debt collateralized by the claims. The $78.7 million of debt is
classified as current.
16
Notes (Continued)
In July 2002, as discussed above, the terms of the $200 million preferred
interest in Castle and the $100 million preferred interest in Piceance were
amended, and the preferred interests are now reported as debt. At September 30,
2002, the Castle and Piceance notes had principal balances of $182 million and
$91 million, respectively. In addition, the terms of two operating leases were
amended, resulting in an increase to capitalized leases of $270 million.
In addition to the items discussed above, significant long-term debt,
including capitalized leases, issuances and retirements, other than amounts
under revolving credit agreements, for the nine months ended September 30, 2002
are as follows:
<Table>
<Caption>
Principal
Issue/Terms Due Date Amount
- ----------- -------- ----------
(Millions)
Issuances of long-term debt in 2002:
6.5% notes (see Note 14) 2007 $ 1,100.0
8.125% notes 2012 650.0
8.75% notes 2032 850.0
8.875% notes (Transcontinental Gas Pipe Line) 2012 325.0
Retirements/prepayments of long-term
debt in 2002:
6.125% notes(1) 2012 $ 240.0
6.2% notes 2002 350.0
8.875% notes (Transcontinental Gas Pipe Line) 2002 125.0
Adjustable rate note (Transcontinental Gas
Pipe Line) 2002 150.0
Various notes, 5.1% - 9.45% 2002 193.2
Various notes, adjustable rate 2002 93.9
</Table>
(1) Subject to redemption at par in 2002.
Williams' ratio of net debt to consolidated net worth plus net debt, as
defined in Williams' amended revolving credit facility, was 65.8 percent at
September 30, 2002.
12. 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 $151
million, including $2.2 million related to discontinued operations, for
potential refund as of September 30, 2002.
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 2000, 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. Beginning on March 9, 2001, the FERC issued a series of
orders directing Williams and other similarly situated companies to provide
refunds for any prices charged in excess of FERC-established proxy prices in
January, February, March, April and May 2001, or to provide justification for
the prices charged during those months. According to these orders, Williams'
total potential refund liability for January through May 2001 is approximately
$30 million. Williams has filed justification for its prices with the FERC and
calculated its refund liability under the methodology used by the FERC to
compute refund amounts at approximately $11 million. On July 25, 2001, the FERC
issued an order establishing a hearing to establish the facts necessary to
determine refunds under the approved
17
Notes (Continued)
methodology. On August 13, 2002, the FERC issued its preliminary findings as to
its investigation into Western markets (discussed below), which call into
question the gas price methodology established in the July 25, 2001 order. Any
change from the July 25, 2001 methodology would likely result in increased
refund liability for Energy Marketing & Trading. Refunds will cover the period
of October 2, 2000 through June 20, 2001. They will be paid as offsets against
outstanding bills and are inclusive of any amounts previously noticed for refund
for that period. Absent a change in the gas price methodology, the judge
presiding over the refund proceedings is expected to issue his findings in
November 2002. The FERC will subsequently issue a refund order based on these
findings.
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 Independent
System Operator's (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 may charge for
wholesale spot sales in the WSCC was the market clearing price. When generation
operating reserves rise 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, and 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 and July 25 orders 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 will 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 will
expire when the currently effective West-wide mitigation plan expires on
September 30, 2002.
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) required the ISO to 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 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 Electricity
Oversight Board 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. Energy
Marketing & Trading will appeal the order. The settlement discussions noted
above have resulted in Williams reaching a global settlement entering into a
settlement agreement with the State of California that includes a renegotiated
long-term energy contract. This contract is made up of a combination of block
energy sales, dispatchable products and a gas contract. The original contract
contained only block energy sales. The settlement will also resolve 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 terms are scheduled to become
effective on December 31, 2002, subject to approval by various courts and the
FERC at the completion of due diligence by the California Attorney General. If
this due diligence uncovers previously unknown and illegal acts, the Attorney
General may terminate the agreement.
18
Notes (Continued)
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.
Should the matter go to hearing, a final decision should be issued by May 31,
2003.
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.
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 are
also under investigation by a California Grand Jury.
On September 27, 2001, the FERC issued a Notice of Proposed Rulemaking (NOPR)
proposing to adopt uniform standards of conduct for transmission providers. The
proposed rules define transmission providers as interstate natural gas pipelines
and public utilities that own, operate or control electric transmission
facilities. The proposed standards would regulate the conduct of transmission
providers with their energy affiliates. The FERC proposes to define energy
affiliates broadly to include any transmission provider affiliate that engages
in or is involved in transmission (gas or electric) transactions, or manages or
controls transmission capacity, or buys, sells, trades or administers natural
gas or electric energy or engages in financial transactions relating to the sale
or transmission of natural gas or electricity. Current rules affecting Williams
regulate the conduct of Williams' natural gas pipelines and their natural gas
marketing affiliates. The FERC invited interested parties to comment on the
NOPR. On April 25, 2002, the FERC issued its staff analysis of the NOPR and the
comments received. The staff analysis proposes redefining the definition of
energy affiliates to exclude affiliated transmission providers. On May 21, 2002,
the FERC held a public conference concerning the NOPR and the FERC invited the
submission of additional comments. If adopted, these new standards would require
the adoption of new compliance measures by certain Williams subsidiaries.
On July 17, 2002, the FERC issued a Notice of Inquiry to seek comments on its
negotiated rate policies and practices. The FERC states that it is undertaking a
review of the recourse rate as a viable alternative and safeguard against the
exercise of market power of interstate gas pipelines, as well as the entire
spectrum of issues related to its negotiated rate program. The FERC requested
that interested parties respond to various questions related to the FERC's
negotiated rate policies and practices. Williams' Gas Pipeline companies have
negotiated rates under the FERC's existing negotiated rate programs and
participated in comments filed in this proceeding by Williams in support of the
FERC's existing negotiated rate program.
On August 1, 2002, the FERC issued a NOPR that proposes restrictions on the
type of cash management program employed by 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 maintain 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.
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."
19
Notes (Continued)
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 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 recent 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) is conducting an investigation regarding gas
and power trading in Western markets and has requested information from Williams
in connection with this investigation. In conjunction 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. Williams' and the CFTC's investigation into this matter is continuing.
On May 31, 2002, Williams received a request from the Securities and Exchange
Commission (SEC) to voluntarily produce documents and information regarding any
prearranged or contemporaneous buy and sell ("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 March 20, 2002, the California Attorney General filed a complaint with the
FERC alleging that Williams and all other sellers of power in California have
failed to comply with federal law requiring the filing of rates and charges for
power. While the FERC rejected the complaint that the market-based rate filing
requirements violate the Federal Power Act, it directed the refiling of
quarterly reports for periods after October 2000 to include transaction specific
information.
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.
Environmental Matters
Since 1989, Texas Gas and Transcontinental Gas Pipe Line 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. Transcontinental Gas Pipe Line 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 September 30,
2002, these subsidiaries had accrued liabilities totaling approximately $32
million for these costs.
Certain Williams' subsidiaries, including Texas Gas and Transcontinental Gas
Pipe Line, 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.
Transcontinental Gas Pipe Line, Texas Gas and Williams Gas Pipelines Central
(Central) have identified polychlorinated biphenyl contamination in air
compressor systems, soils and related properties at certain compressor station
sites. Transcontinental Gas Pipe Line, Texas Gas and Central 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 Central,
Texas Gas and Transcontinental Gas Pipe Line. As of September 30, 2002, Central
had
20
Notes (Continued)
accrued a liability for approximately $8 million, which is included in
discontinued operations and represents the current estimate of future
environmental cleanup costs to be incurred over the next six to ten years. Texas
Gas and Transcontinental Gas Pipe Line likewise had accrued liabilities for
these costs which are included in the $32 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.
In addition to its Gas Pipelines, Williams and its subsidiaries 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 September 30, 2002, Williams and its
subsidiaries had accrued liabilities totaling approximately $43 million for
these costs. Williams and its subsidiaries 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 September 30, 2002, Williams and its
subsidiaries 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 September 30, 2002, Williams had
approximately $10 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.
Other legal matters
In connection with agreements to resolve take-or-pay and other contract
claims and to amend gas purchase contracts, Transcontinental Gas Pipe Line 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. As a result of
such settlements, Transcontinental Gas Pipe Line is currently defending two
lawsuits brought by producers. In another case, a jury verdict found that
Transcontinental Gas Pipe Line was required to pay a producer damages of $23.3
million including $3.8 million in attorneys' fees. In addition, through December
31, 2001, post-judgment interest was approximately $10.5 million.
Transcontinental Gas Pipe Line's appeals were denied by the Texas Court of
Appeals for the First District of Texas, and on April 2, 2001, the company filed
an appeal to the Texas Supreme Court. On February 21, 2002, the Texas Supreme
Court denied Transcontinental Gas Pipe Line's petition for review. As a result,
Transcontinental Gas Pipe Line recorded a fourth-quarter 2001 pre-tax charge to
income (loss) for the year ended December 31, 2001, in the amount of $37 million
($18 million was included in Gas Pipeline's segment profit and $19 million in
interest accrued) representing management's estimate of the effect of this
ruling. Transcontinental Gas Pipe Line filed a motion for rehearing which was
denied, thereby concluding this matter. In May 2002, Transcontinental Gas Pipe
Line paid Texaco the amount of the judgment plus accrued interest. In the two
remaining cases, producers have asserted damages, including interest calculated
through December 31, 2001, of $16.3 million. Producers have received and may
receive other demands, which could result in additional claims. Indemnification
for royalties will depend on, among other things, the specific lease provisions
between the producer and the lessor and the terms of the settlement between the
producer and either Transcontinental Gas Pipe Line or Texas Gas. Texas Gas may
file to recover 75 percent of any such additional amounts it may be required to
pay pursuant to indemnities for royalties under the provisions of the FERC
Order 528.
On June 8, 2001, fourteen Williams entities were named as defendants in a
nationwide class action lawsuit which has 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 November 2001,
Williams, along with other "Coordinating Defendants", filed a motion to dismiss
on nonjurisdictional grounds. In January 2002, most of the Williams defendants,
along with a group of Coordinating Defendants, filed a motion to dismiss for
lack of personal
21
Notes (Continued)
jurisdiction. 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. In the next several months, the Williams
entities will join with other defendants in contesting certification of the
plaintiff class.
In 1998, the United States Department of Justice (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 liability relating
to this claim. Grynberg has also filed claims against approximately 300 other
energy companies and alleges that the defendants violated the False Claims Act
in connection with the measurement, royalty valuation and purchase of
hydrocarbons. The relief sought is 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.
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 WCG installed fiber-optic cable without the
permission of the landowners. Williams and its subsidiaries were dismissed from
all of the cases, except one. The parties in the only remaining case in which
Williams or its subsidiaries are named as defendants have reached a settlement
in principle and are in the process of drafting the settlement documents. The
settlement does not obligate Williams or its subsidiaries to pay any monies to
the remaining plaintiff.
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
coordinated in San Diego County Superior Court.
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 coordinated with the other class actions in San Diego Superior
Court.
22
Notes (Continued)
On May 17, 2001, the DOJ advised Williams that it had commenced an antitrust
investigation relating to an agreement between a subsidiary of Williams and AES
Southland alleging that the agreement limits the expansion of electric
generating capacity at or near the AES Southland plants that are subject to a
long-term tolling agreement between Williams and AES Southland. In connection
with that investigation, the DOJ has issued two Civil Investigative Demands to
Williams requesting answers to certain interrogatories and the production of
documents. Williams is cooperating with the investigation. On November 13, 2002,
the DOJ formally notified Williams that it had terminated this investigation
without any recommended action against Williams or AES.
On November 8, 2002, Williams received a subpoena from a federal grand jury
in northern California seeking documents related to Williams' involvement in
California power markets. The subpoena also questions Williams' reporting to
trade publications for both gas and power.
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.
On March 11, 2002, the California Attorney General filed a civil complaint in
San Francisco Superior Court against Williams and three other sellers of
electricity alleging unfair competition relating to sales of ancillary power
services between 1998 and 2000. The complaint seeks restitution, disgorgement
and civil penalties of approximately $150 million in total. This case has been
removed to federal court. On April 9, 2002, the California Attorney General
filed a civil complaint in San Francisco Superior Court against Williams and
three other sellers of electricity alleging unfair and unlawful business
practices related to charges for electricity during and after 2000. The maximum
penalty for each violation is $2,500 and the complaint seeks a total fine in
excess of $1 billion. These cases have been removed to federal court. Motions to
remand have been denied. Finally, the California Attorney General has indicated
he may file a Clayton Act complaint against AES Southland and Williams relating
to AES Southland's acquisition of Southern California generation facilities in
1998, tolled by Williams. Williams believes the complaints against it are
without merit.
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, WCG 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 Williams Communications equity
holders. The amended complaint of the WCG securities holders was filed on
September 27, 2002, and the amended complaint of the WMB securities holders was
filed on October 7, 2002. Williams will be filing separate responsive pleadings
in each proceeding. 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. 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.
The U.S. Trustee selected Williams to serve on the Official Committee of
Unsecured Creditors in the WCG bankruptcy. At its initial meeting, the committee
formed a subcommittee of the creditors committee, which excludes Williams, to
investigate what rights and remedies, if any, the creditors may have against
Williams relating to its dealings with WCG. Williams has entered into an
agreement with WCG in which Williams agreed not to object to a plan of
reorganization submitted by WCG in its bankruptcy if that plan provides (i) for
WCG to assume its obligations under certain service agreements and the sale
leaseback transaction with Williams and (ii) for Williams' other claims to be
treated as general unsecured claims with treatment substantially identical to
the treatment of claims by WCG's bondholders. This matter is discussed more
fully in Note 4.
On April 26, 2002, the Oklahoma Department of Securities issued an order
initiating an investigation of Williams and WCG regarding issues associated with
the spin-off of WCG and regarding the WCG 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 Field
Services Company (WFS) and Transcontinental Gas Pipe Line Corporation (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 offshore
pipeline system, the North Padre Island gathering system. By order of the FERC,
the matter was heard before an administrative law judge in April 2002. On June
4, 2002, the administrative law judge
23
Notes (Continued)
issued an initial decision finding that the affiliates acted in concert to
frustrate the FERC's regulation of Transco and recommending that the FERC
reassert jurisdiction over the North Padre Island gathering system. Transco, WGP
and WFS believe their actions were reasonable and lawful and submitted briefs
taking exceptions to the initial decision. 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 and WFS 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 were not successful in revolving the
dispute. The Company believes that the claims have no merit.
In addition to the foregoing, various other proceedings are pending against
Williams or its subsidiaries which are incidental to their operations.
Enron and certain of its subsidiaries, with whom Energy Marketing & Trading and
other Williams subsidiaries have had commercial relations, filed a voluntary
petition for Chapter 11 reorganization under the U.S. Bankruptcy Code in the
Federal District Court for the Southern District of New York on December 2,
2001. Additional Enron subsidiaries have subsequently filed for Chapter 11
protection. Williams has filed its proofs of claim prior to the court-ordered
October 15, 2002, bar date. During fourth-quarter 2001, Energy Marketing &
Trading recorded a total decrease to revenues of approximately $130 million as a
part of its valuation of energy commodity and derivative trading contracts with
Enron entities, approximately $91 million of which was recorded pursuant to
events immediately preceding and following the announced bankruptcy of Enron.
Other Williams subsidiaries recorded approximately $5 million of bad debt
expense related to amounts receivable from Enron entities in fourth-quarter
2001, reflected in selling, general and administrative expenses. At December 31,
2001, Williams has reduced its recorded exposure to accounts receivable from
Enron entities, net of margin deposits, to expected recoverable amounts. During
first-quarter 2002, Energy Marketing & Trading sold rights to certain Enron
receivables to a third party in exchange for $24.5 million in cash. The $24.5
million was recorded within the trading revenues in first-quarter 2002.
Summary
While no assurances may be given, Williams, based on advice of counsel, does
not believe 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 have a materially
adverse effect upon Williams' future financial position, results of operations
or cash flow requirements.
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 either currently in
operation or are to be constructed at various locations throughout the
continental United States. At September 30, 2002, annual estimated committed
payments under these contracts range from approximately $60 million to $462
million, resulting in total committed payments over the next 20 years of
approximately $8 billion.
13. Preferred interests in consolidated subsidiaries
- --------------------------------------------------------------------------------
In December 2000, Williams formed two separate legal entities, Snow Goose
Associates, L.L.C. (Snow Goose) and Arctic Fox Assets, L.L.C. (Arctic Fox) for
the purpose of generating funds to invest in certain Canadian energy-related
assets. An outside investor contributed $560 million in exchange for the
non-controlling preferred interest in Snow Goose. The investor in Snow Goose is
entitled to quarterly priority distributions. The initial priority return
structure was originally scheduled to expire in December 2005.
During first-quarter 2002, the terms of the priority return were amended.
Significant terms of the amendment include elimination of covenants regarding
Williams' credit ratings, modifications of certain Canadian interest coverage
covenants and a requirement to amortize the outside investor's preferred
interest with equal principal payments due each quarter and the final payment in
April 2003. In addition, Williams provided a financial
24
Notes (Continued)
guarantee of the Arctic Fox note payable to Snow Goose which, in turn, is the
source of the priority returns. Based on the terms of the amendment, the
remaining balance due is classified as long-term debt due within one year on
Williams' Consolidated Balance Sheet at September 30, 2002. Priority returns
prior to this amendment are included in preferred returns and minority interest
in income of consolidated subsidiaries on the Consolidated Statement of
Operations.
Following the downgrades in Williams' credit ratings in July 2002, the $135
million preferred interest in Williams Risk Holdings L.L.C. was redeemed.
Additionally, terms of the $200 million preferred interest in Castle Associates
L.P. and the $100 million preferred interest in Piceance Production Holdings LLC
were amended and as a result the $200 million and $100 million, respectively,
are classified as debt at September 30, 2002.
14. Stockholders' equity
- --------------------------------------------------------------------------------
Concurrent with the sale of Kern River to MidAmerican Energy Holdings Company
(MEHC), Williams issued approximately 1.5 million shares of 9 7/8 percent
cumulative convertible preferred stock to MEHC for $275 million. The terms of
the preferred stock allow the holder to convert, at any time, one share of
preferred stock into 10 shares of Williams common stock at $18.75 per share.
Preferred shares have a liquidation preference equal to the stated value of
$187.50 per share plus any dividends accumulated and unpaid. Dividends on the
preferred stock are payable quarterly.
Preferred dividends for the nine months ended September 30, 2002, include
$69.4 million associated with the accounting for a preferred security that
contains a conversion option that is beneficial to the purchaser at the time the
security was issued. This is accounted for as a noncash dividend (reduction to
retained earnings) and results from the conversion price being less than the
market price of Williams common stock on the date the preferred stock was
issued. The reduction in retained earnings was offset by an increase in capital
in excess of par value.
In January 2002, Williams issued $1.1 billion of 6.5 percent notes payable
2007 which are subject to remarketing in 2004. Attached to these notes is an
equity forward contract requiring the holder to purchase Williams common stock
at the end of three years. The note and equity forward contract are bundled as
units, called FELINE PACS, and were sold in a public offering for $25 per unit.
At the end of three years, the holder is required to purchase for $25, one share
of Williams common stock provided the average price of Williams common stock
does not exceed $41.25 per share for a 20 trading day period prior to
settlement. If the average price over that period exceeds $41.25 per share, the
number of shares issued in exchange for $25 will be equal to one share
multiplied by the quotient of $41.25 divided by the average price over that
period.
25
Notes (Continued)
15. Comprehensive income (loss)
- --------------------------------------------------------------------------------
Comprehensive income (loss) is as follows:
<Table>
<Caption>
Three months ended Nine months ended
September 30, September 30,
------------------------ ------------------------
(Millions) 2002 2001 2002 2001
- ---------- ---------- ---------- ---------- ----------
Net income (loss) $ (294.1) $ 221.3 $ (535.5) $ 760.0
Other comprehensive
income (loss):
Unrealized gains (losses)
on securities (.9) (18.1) (.1) (71.3)
Realized (gains) losses on
securities reclassified
to net income -- 20.3 -- (.4)
Cumulative effect of a
change in accounting for
derivative instruments -- -- -- (153.4)
Unrealized gains (losses) on
derivative instruments 106.6 408.5 (82.3) 865.6
Net reclassification into
earnings of derivative
instrument (gains) losses (62.9) (120.3) (263.7) (74.6)
Foreign currency
translation adjustments (19.5) (11.6) .2 (36.0)
---------- ---------- ---------- ----------
Other comprehensive income
(loss) before taxes and
minority interest 23.3 278.8 (345.9) 529.9
Income tax benefit (provision)
on other comprehensive
income (loss) (16.0) (112.1) 132.0 (212.2)
Minority interest in other
comprehensive income (loss) -- -- -- 10.0
---------- ---------- ---------- ----------
Other comprehensive income (loss) 7.3 166.7 (213.9) 327.7
---------- ---------- ---------- ----------
Comprehensive income (loss) $ (286.8) $ 388.0 $ (749.4) $ 1,087.7
========== ========== ========== ==========
</Table>
Components of other comprehensive income (loss) before minority interest and
taxes related to discontinued operations are as follows:
<Table>
<Caption>
Three months ended Nine months ended
September 30, September 30,
--------------------------- ---------------------------
(Millions) 2002 2001 2002 2001
- ---------- ------------ ------------ ------------ ------------
Unrealized gains (losses) on securities $ -- $ -- $ -- $ (56.2)
Realized gains on securities
reclassified to net income -- -- -- (20.7)
Foreign currency translation
adjustments -- -- -- (22.1)
------------ ------------ ------------ ------------
Other comprehensive income (loss)
before minority interest and taxes
related to discontinued operations $ -- $ -- $ -- $ (99.0)
============ ============ ============ ============
</Table>
26
Notes (Continued)
16. Segment disclosures
- --------------------------------------------------------------------------------
Segments and reclassification of operations
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.
Effective July 1, 2002, management of certain operations previously conducted
by Energy Marketing & Trading, International and Petroleum Services was
transferred to Midstream Gas & Liquids. These operations included natural gas
liquids trading, activities in Venezuela and a petrochemical plant,
respectively. Segment amounts have been restated to reflect these changes.
On April 11, 2002, Williams Energy Partners L.P., a partially owned and
consolidated entity of Williams, acquired Williams Pipe Line, an operation
previously included within Petroleum Services. Accordingly, Williams Pipe Line's
operations have been transferred from the Petroleum Services segment to the
Williams Energy Partners segment for which segment information has been restated
for all prior periods presented.
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.
In first-quarter 2002, Williams began managing its interest rate risk on an
enterprise basis by the corporate parent. The more significant of these risks
relate to its debt instruments and its energy risk management and trading
portfolio. To facilitate the management of the risk, entities within Williams
may enter into derivative instruments (usually swaps) with the corporate parent.
The level, term and nature of derivative instruments entered into with external
parties are determined by the corporate parent. 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 parties.
The decrease in Energy Marketing & Trading's total assets, as reflected on
page 30, is due primarily to a decline in the fair value of the energy risk
management and trading portfolio.
The following tables reflect the reconciliation of revenues and operating
income (loss) as reported in the Consolidated Statement of Operations to segment
revenues and segment profit (loss).
27
Notes (Continued)
16. Segment disclosures (continued)
- --------------------------------------------------------------------------------
<Table>
<Caption>
Energy Exploration Midstream Williams
Marketing Gas & Gas & Energy Petroleum
& Trading Pipeline Production Liquids Partners Services
---------- ---------- ----------- ---------- ---------- ----------
THREE MONTHS ENDED SEPTEMBER 30, 2002
Segment revenues:
External $ (.4) $ 362.7 $ 16.5 $ 469.2 $ 92.8 $ 1,157.3
Internal (289.8)* 18.7 202.8 32.6 14.7 13.6
---------- ---------- ---------- ---------- ---------- ----------
Total segment revenues (290.2) 381.4 219.3 501.8 107.5 1,170.9
---------- ---------- ---------- ---------- ---------- ----------
Less intercompany interest
rate swap gain (loss) (71.0) -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ----------
Total revenues $ (219.2) $ 381.4 $ 219.3 $ 501.8 $ 107.5 $ 1,170.9
========== ========== ========== ========== ========== ==========
Segment profit (loss) $ (387.6) $ 172.6 $ 231.8 $ 104.0 $ 13.4 $ (406.2)
Less:
Equity earnings (loss) -- 11.6 1.5 7.3 -- (.1)
Income (loss) from
investments -- (2.7) -- -- -- (.7)
Intercompany interest
rate swap gain (loss) (71.0) -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ----------
Segment operating
income (loss) $ (316.6) $ 163.7 $ 230.3 $ 96.7 $ 13.4 $ (405.4)
---------- ---------- ---------- ---------- ---------- ----------
General corporate expenses
Consolidated operating
income (loss)
THREE MONTHS ENDED SEPTEMBER 30, 2001
Segment revenues:
External $ 618.4 $ 324.3 $ 55.9 $ 361.1 $ 90.5 $ 1,267.8
Internal (125.3)* 10.8 104.7 53.8 20.3 14.1
---------- ---------- ---------- ---------- ---------- ----------
Total segment revenues 493.1 335.1 160.6 414.9 110.8 1,281.9
---------- ---------- ---------- ---------- ---------- ----------
Less intercompany interest
rate swap gain (loss) -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ----------
Total revenues $ 493.1 $ 335.1 $ 160.6 $ 414.9 $ 110.8 $ 1,281.9
========== ========== ========== ========== ========== ==========
Segment profit (loss) $ 356.9 $ 101.8 $ 65.0 $ 69.5 $ 27.1 $ 42.4
Less:
Equity earnings (loss) (.3) 11.9 4.9 1.3 -- --
Income (loss) from
investments (23.3) -- -- -- -- --
Intercompany interest
rate swap gain (loss) -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ----------
Segment operating
income (loss) $ 380.5 $ 89.9 $ 60.1 $ 68.2 $ 27.1 $ 42.4
---------- ---------- ---------- ---------- ---------- ----------
General corporate expenses
Consolidated operating
income (loss)
</Table>
<Table>
<Caption>
Inter-
national Other Eliminations Total
---------- ---------- ------------ ----------
THREE MONTHS ENDED SEPTEMBER 30, 2002
Segment revenues:
External $ .7 $ 5.1 $ -- $ 2,103.9
Internal -- 9.7 (2.3) --
---------- ---------- ---------- ----------
Total segment revenues .7 14.8 (2.3) 2,103.9
---------- ---------- ---------- ----------
Less intercompany interest
rate swap gain (loss) -- -- 71.0 --
---------- ---------- ---------- ----------
Total revenues $ .7 $ 14.8 $ (73.3) $ 2,103.9
========== ========== ========== ==========
Segment profit (loss) $ 53.1 $ (3.5) $ -- $ (222.4)
Less:
Equity earnings (loss) (1.4) .2 -- 19.1
Income (loss) from
investments 58.5 -- -- 55.1
Intercompany interest
rate swap gain (loss) -- -- -- (71.0)
---------- ---------- ---------- ----------
Segment operating
income (loss) $ (4.0) $ (3.7) $ -- $ (225.6)
---------- ---------- ---------- ----------
General corporate expenses (44.1)
----------
Consolidated operating
income (loss) $ (269.7)
==========
THREE MONTHS ENDED SEPTEMBER 30, 2001
Segment revenues:
External $ 1.1 $ 8.2 $ -- $ 2,727.3
Internal -- 9.7 (88.1) --
---------- ---------- ---------- ----------
Total segment revenues 1.1 17.9 (88.1) 2,727.3
---------- ---------- ---------- ----------
Less intercompany interest
rate swap gain (loss) -- -- -- --
---------- ---------- ---------- ----------
Total revenues $ 1.1 $ 17.9 $ (88.1) $ 2,727.3
========== ========== ========== ==========
Segment profit (loss) $ (10.9) $ 1.6 $ -- $ 653.4
Less:
Equity earnings (loss) (7.5) -- -- 10.3
Income (loss) from
investments -- -- -- (23.3)
Intercompany interest
rate swap gain (loss) -- -- -- --
---------- ---------- ---------- ----------
Segment operating
income (loss) $ (3.4) $ 1.6 $ -- $ 666.4
---------- ---------- ---------- ----------
General corporate expenses (32.4)
----------
Consolidated operating
income (loss) $ 634.0
==========
</Table>
* Energy Marketing & Trading intercompany cost of sales, which are netted in
revenues consistent with fair-value accounting, exceed intercompany revenue.
28
Notes (Continued)
16. Segment disclosures (continued)
- --------------------------------------------------------------------------------
<Table>
<Caption>
Energy Exploration Midstream Williams
Marketing Gas & Gas & Energy Petroleum
& Trading Pipeline Production Liquids Partners Services
---------- ---------- ----------- ---------- ---------- ----------
NINE MONTHS ENDED SEPTEMBER 30, 2002
Segment revenues:
External $ 649.8 $ 1,055.7 $ 58.4 $ 1,273.1 $ 262.9 $ 3,197.5
Internal (863.6)* 50.7 619.4 66.7 40.7 69.2
---------- ---------- ---------- ---------- ---------- ----------
Total segment revenues (213.8) 1,106.4 677.8 1,339.8 303.6 3,266.7
---------- ---------- ---------- ---------- ---------- ----------
Less intercompany interest
rate swap gain (loss) (139.9) -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ----------
Total revenues $ ( 73.9) $ 1,106.4 $ 677.8 $ 1,339.8 $ 303.6 $ 3,266.7
========== ========== ========== ========== ========== ==========
Segment profit (loss) $ (602.0) $ 506.0 $ 433.5 $ 210.0 $ 69.8 $ (396.5)
Less:
Equity earnings (loss) (4.0) 82.8 2.1 12.5 -- (.4)
Income (loss) from
investments -- (15.0) -- -- -- (.7)
Intercompany interest
rate swap gain (loss) (139.9) -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ----------
Segment operating
income (loss) $ (458.1) $ 438.2 $ 431.4 $ 197.5 $ 69.8 $ (395.4)
---------- ---------- ---------- ---------- ---------- ----------
General corporate expenses
Consolidated operating
income (loss)
NINE MONTHS ENDED SEPTEMBER 30, 2001
Segment revenues:
External $ 1,851.8 $ 1,023.9 $ 93.7 $ 1,416.3 $ 265.5 $ 3,976.7
Internal (422.8)* 24.6 316.5 90.5 45.2 100.9
---------- ---------- ---------- ---------- ---------- ----------
Total segment revenues 1,429.0 1,048.5 410.2 1,506.8 310.7 4,077.6
---------- ---------- ---------- ---------- ---------- ----------
Less intercompany interest
rate swap gain (loss) -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ----------
Total revenues $ 1,429.0 $ 1,048.5 $ 410.2 $ 1,506.8 $ 310.7 $ 4,077.6
========== ========== ========== ========== ========== ==========
Segment profit (loss) $ 1,108.6 $ 436.0 $ 165.4 $ 126.4 $ 83.6 $ 189.5
Less:
Equity earnings (loss) 1.4 30.1 15.8 (11.5) -- .1
Income (loss) from
investments (23.3) 27.5 -- -- -- --
Intercompany interest
rate swap gain (loss) -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ----------
Segment operating
income (loss) $ 1,130.5 $ 378.4 $ 149.6 $ 137.9 $ 83.6 $ 189.4
---------- ---------- ---------- ---------- ---------- ----------
General corporate expenses
Consolidated operating
income (loss)
</Table>
<Table>
<Caption>
Inter-
national Other Eliminations Total
---------- ---------- ------------ ----------
NINE MONTHS ENDED SEPTEMBER 30, 2002
Segment revenues:
External $ 3.1 $ 17.7 $ -- $ 6,518.2
Internal -- 29.4 (12.5) --
---------- ---------- ---------- ----------
Total segment revenues 3.1 47.1 (12.5) 6,518.2
---------- ---------- ---------- ----------
Less intercompany interest
rate swap gain (loss) -- -- 139.9 --
---------- ---------- ---------- ----------
Total revenues $ 3.1 $ 47.1 $ (152.4) $ 6,518.2
========== ========== ========== ==========
Segment profit (loss) $ 34.8 $ (1.2) $ -- $ 254.4
Less:
Equity earnings (loss) (12.7) (.6) -- 79.7
Income (loss) from
investments 58.5 -- -- 42.8
Intercompany interest
rate swap gain (loss) -- -- -- (139.9)
---------- ---------- ---------- ----------
Segment operating
income (loss) $ (11.0) $ (.6) $ -- $ 271.8
---------- ---------- ---------- ----------
General corporate expenses (116.4)
----------
Consolidated operating
income (loss) $ 155.4
==========
NINE MONTHS ENDED SEPTEMBER 30, 2001
Segment revenues:
External $ 2.6 $ 27.9 $ -- $ 8,658.4
Internal -- 29.5 (184.4) --
---------- ---------- ---------- ----------
Total segment revenues 2.6 57.4 (184.4) 8,658.4
---------- ---------- ---------- ----------
Less intercompany interest
rate swap gain (loss) -- -- -- --
---------- ---------- ---------- ----------
Total revenues $ 2.6 $ 57.4 $ (184.4) $ 8,658.4
========== ========== ========== ==========
Segment profit (loss) $ (22.9) $ 9.0 $ -- $ 2,095.6
Less:
Equity earnings (loss) (13.7) (.4) -- 21.8
Income (loss) from
investments -- -- -- 4.2
Intercompany interest
rate swap gain (loss) -- -- -- --
---------- ---------- ---------- ----------
Segment operating
income (loss) $ (9.2) $ 9.4 $ -- $ 2,069.6
---------- ---------- ---------- ----------
General corporate expenses (88.8)
----------
Consolidated operating
income (loss) $ 1,980.8
==========
</Table>
* Energy Marketing & Trading intercompany cost of sales, which are netted in
revenues consistent with fair-value accounting, exceed intercompany revenue.
29
16. Segment disclosures (continued)
- --------------------------------------------------------------------------------
<Table>
<Caption>
Total Assets
---------------------------------------
(Millions) September 30, 2002 December 31, 2001
- ---------- ------------------ -----------------
Energy Marketing & Trading $12,734.9 $15,045.3
Gas Pipeline 8,110.6 7,506.5
Exploration & Production 5,844.9 5,045.6
Midstream Gas & Liquids 5,154.8 4,750.7
Williams Energy Partners 1,201.9 1,033.6
Petroleum Services 1,909.1 2,147.9
International 668.5 1,124.8
Other 6,234.5 6,852.1
Eliminations (6,771.1) (7,473.8)
--------- ---------
35,088.1 36,032.7
Discontinued operations 779.6 2,873.5
--------- ---------
Total $35,867.7 $38,906.2
========= =========
</Table>
30
Notes (Continued)
17. Recent accounting standards
- --------------------------------------------------------------------------------
In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No.
142, "Goodwill and Other Intangible Assets." Williams adopted this Statement
effective January 1, 2002. This Statement addresses accounting and reporting
standards for goodwill and other intangible assets. Under the provisions of this
Statement, goodwill and intangible assets with indefinite useful lives are no
longer amortized, but will be tested annually for impairment. Based on
management's estimate of the fair value of the operating unit's goodwill there
was no impairment upon adoption of this Standard at January 1, 2002.
In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement
Obligations," which is effective for fiscal years beginning after June 15, 2002.
The Statement requires legal obligations associated with the retirement of
long-lived assets to be recognized at their fair value at the time that the
obligations are incurred. Upon initial recognition of a liability, that cost
should be capitalized as part of the related long-lived asset and allocated to
expense over the useful life of the asset. Williams will adopt the new rules on
asset retirement obligations on January 1, 2003. The impact of adoption is to be
reported as a cumulative effect of change in accounting principle. Application
of the new rules is expected to result in estimated retirement obligations
related to exploration and production assets, offshore transmission platforms,
and certain international assets. The estimated obligations will consider
current factors such as expected future inflation rates, current costs of
borrowing, estimated retirement dates and estimated expected costs of required
retirement activities. Retirement obligations have not been estimated for assets
for which the remaining life is not currently determinable, including pipeline
transmission assets, processing and refining assets, and gas gathering systems.
In second-quarter 2002, the FASB issued SFAS No. 145, "Rescission of FASB
Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical
Corrections." The rescission of SFAS No. 4, "Reporting Gains and Losses from
Extinguishment of Debt," and SFAS No. 64, "Extinguishments of Debt Made to
Satisfy Sinking-Fund Requirements," requires that gains and losses from
extinguishment of debt only be classified as extraordinary items in the event
that they meet the criteria of APB Opinion No. 30. SFAS No. 44, "Accounting for
Intangible Assets of Motor Carriers," established accounting requirements for
the effects of transition to the Motor Carriers Act of 1980 and is no longer
required now that the transitions have been completed. Finally, the amendments
to SFAS No. 13 require certain lease modifications that have economic effects
which are similar to sale-leaseback transactions be accounted for as
sale-leaseback transactions. The provisions of this Statement related to the
rescission of SFAS No. 4 are to be applied in fiscal years beginning after May
15, 2002, while the provisions related to SFAS No. 13 are effective for
transactions occurring after May 15, 2002. All other provisions of the Statement
are effective for financial statements issued on or after May 15, 2002. There
was no initial impact of SFAS No. 145 on Williams' results of operations and
financial position. However, in subsequent reporting periods, gains and losses
from debt extinguishments will not be accounted for as extraordinary items.
Also in second-quarter 2002, the FASB issued SFAS No. 146, "Accounting for
Costs Associated with Exit or Disposal Activities." This Statement addresses
financial accounting and reporting for costs associated with exit or disposal
activities and nullifies Emerging Issues Task Force Issue No. 94-3, "Liability
Recognition for Certain Employee Termination Benefits and Other Costs to Exit an
Activity (including Certain Costs Incurred in a Restructuring)." This Statement
requires that a liability for a cost associated with an exit or disposal
activity be recognized and measured initially at fair value only when the
liability is incurred. The provisions of the Statement are effective for exit or
disposal activities that are initiated after December 31, 2002. The effect of
this standard on Williams is being evaluated.
On October 25, 2002, the Emerging Issues Task Force (EITF) reached a
consensus on Issue No. 02-3, "Issues Related to Accounting for Contracts
Involved in Energy Trading and Risk Management Activities." This Issue rescinds
EITF Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and
Risk Management Activities," the impact of which is to preclude fair value
accounting for all energy trading contracts not within the scope of SFAS No.
133, "Accounting for Derivative Instruments and Hedging Activities" and trading
inventories. The EITF also reached a consensus that gains and losses on
derivative instruments within the scope of SFAS No. 133 should be shown net in
the income statement if the derivative instruments are held for trading
purposes. The consensus regarding the rescission of Issue 98-10 is applicable
for fiscal periods beginning after December 15, 2002, and earlier application is
permitted. Williams is evaluating whether it will adopt the consensus in 2002
or January 1, 2003. Adoption of the consensus will be reported as a cumulative
effect of a change in accounting principle. Energy trading contracts not within
the scope of SFAS No. 133 executed after October 25, 2002, but prior to the
implementation of the consensus are not permitted to apply fair value
accounting. The effect of initially applying the consensus, which could be
significant, is being evaluated, as Williams must review its energy trading
contracts to identify those contracts within the scope of SFAS No. 133.
31
ITEM 2
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATION
RECENT EVENTS
As a result of credit issues facing the Company and the assumption of payment
obligations and performance on guarantees associated with WCG, Williams
announced plans during first-quarter 2002 to strengthen its balance sheet and
support retention of its investment grade ratings. The plan included reducing
capital expenditures during the balance of 2002, future sales of assets to
generate proceeds to be used to reduce outstanding debt and the lowering of
expenses, in part through an enhanced-benefit early retirement program which
concluded during the second quarter. In addition, the plan included the
elimination of "ratings triggers" giving rise to options to put or accelerate
debt or cause redemption of preferred interests. Exposure to ratings triggers
was substantially reduced to $182 million in first-quarter 2002. In
third-quarter 2002, the remaining $182 million was redeemed or extinguished.
During the second quarter, Williams experienced liquidity issues, the effect
of which limited Energy Marketing & Trading's ability to manage market risk and
exercise hedging strategies as market liquidity deteriorated. During May 2002,
major rating agencies lowered their credit ratings on Williams' unsecured
long-term debt; however, the ratings remained investment grade for the balance
of the quarter. In June, Williams announced a $500 million reduction in its
working capital and liquidity commitments to its Energy Marketing & Trading
business and reduced its work force accordingly. Later in June, Williams
announced its intentions to offer for sale its two refineries and related
assets, with the expectation of closing such sales by the end of 2002.
Williams experienced a substantial net loss for the second quarter. The loss
primarily resulted from a decline in Energy Marketing & Trading's results and
reflected a significant decline in the forward mark-to-market value of its
portfolio, the costs associated with terminated power projects, and the partial
impairment of goodwill from deteriorating energy trading market conditions in
the second quarter. Williams also recognized asset impairments and cost
write-offs, in part a result of asset sale considerations and terminated
projects reflecting a reduced capital expenditure program. In addition, the
board of directors reduced the common stock dividend for the third quarter from
the prior level of $.20 per share to $.01 per share. The major rating agencies
downgraded Williams' unsecured long-term debt credit ratings to below investment
grade, reflecting the uncertainty associated with the trading business,
short-term cash requirements facing the Company and the increased level of debt
the company had incurred to meet the WCG payment obligations and guarantees.
Concurrent with these events, Williams was unable to complete a renewal of its
unsecured short-term bank facility which expired on July 24, 2002. Subsequently,
Williams and a subsidiary obtained two secured facilities totaling $1.3 billion,
including a letter of credit facility for $400 million, and amended its existing
revolving credit facility, which expires July 2005, to make it secured. These
facilities include pledges of certain assets and contain financial ratios and
other covenants that must be maintained (see Note 11). If such provisions of the
agreements are not maintained, then amounts outstanding can become due and
payable immediately.
Following the credit rating downgrade in July, Williams sold certain
exploration and production properties and substantially all of its natural gas
liquids pipeline systems, receiving net cash proceeds of approximately $1.5
billion. Williams also sold certain liquified natural gas assets for
approximately $217 million, its 27 percent ownership interest in a Lithuanian
refinery, pipeline and terminal investment for $85 million and its $75 million
note receivable from the Lithuanian investment for face value. These
transactions closed in September. During the second quarter, a review for
impairment was performed on certain assets that were being considered for
possible sale, including an assessment of the more likely than not probabilities
of sale for each asset. Impairments were recorded in the second quarter totaling
approximately $71 million reflecting management's estimate of the fair value of
these assets based on information available at the time. During third-quarter,
Williams' board of directors approved for sale the Central natural gas pipeline
unit and the soda ash mining operations, both of which are reported as
discontinued operations. Williams currently has a definitive agreement for the
sale of Central. Also, during the third quarter, the impairment reviews were
updated to incorporate new information obtained through the maturation of the
assets sales process. As a result, Williams recorded $568 million of pre-tax
impairment charges (including those recorded in discontinued operations) in the
third quarter (see Notes 3 and 7).
In addition, Williams is pursuing the sale of other assets to enhance
liquidity. The sales are anticipated to close during the remainder of 2002 and
the first half of 2003. Williams has numerous assets that could be sold which
have values in excess of the previously announced target of $1.5 billion to $3
billion to be generated from asset sales. The specific assets that will be sold
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 the Company. While management believes it has considered all
relevant information in assessing for potential impairments, the ultimate sales
price for assets that may be sold in the future may result in additional
impairments or losses, and/or gains.
32
Management's Discussion & Analysis (Continued)
The operating results of Energy Marketing & Trading are adversely affected by
several factors, including Williams' overall liquidity and credit ratings which
impact Energy Marketing & Trading's ability to enter into price risk management
and hedging activities. The credit rating downgrades have also triggered certain
Energy Marketing & Trading contractual provisions, including providing
counterparties with adequate assurance, margin, credit enhancement, or credit
replacement. Successful completion of the agreement announced on November 11,
2002 regarding the global settlement with the State of California and other
parties will eliminate certain outstanding complaints and litigation and resolve
the State of California's claims for refunds to the FERC filed in connection
with its power activities in California (see Note 12). This agreement provides
for a new long-term power sales contract with the state in addition to other
settlement provisions. For further discussions regarding Energy Marketing &
Trading's business and its fair value of energy contracts, see the "Fair Value
of Energy Risk Management and Trading activities." The energy trading sector has
experienced deteriorating conditions because of credit and regulatory concerns,
and these have significantly reduced Energy Marketing & Trading's ability to
attract new business. During third-quarter, several companies in the energy
trading sector have announced that they are either reducing commitments to or
exiting altogether, the energy trading business. These market conditions plus
the unwillingness of counterparties to enter into new business with Energy
Marketing & Trading will affect results in the future and could result in
additional operating losses. On August 1, 2002, Williams announced its intention
to further reduce its commitment and exposure to its energy marketing and risk
management business. This reduction could be realized by entering into a joint
venture arrangement with a third party or a sale of a portion or all of the
marketing and trading portfolio. It is possible that Williams, in order to
generate levels of liquidity it needs in the future, would be willing to accept
amounts for a portion or its entire portfolio that are less than its carrying
value at September 30, 2002. Additionally, on October 25, 2002, the Emerging
Issues Task Force concluded in Issue No. 02-3 to rescind Issue No. 98-10, under
which non-derivative energy trading contracts are currently marked-to-market. In
addition, trading inventories will also no longer be marked-to-market but will
be reported on a lower of cost or market basis. Upon adoption of this new
standard, Energy Marketing & Trading will record an adjustment for the
cumulative effect of this change in accounting principle. The impact of this
change in accounting principle could be significant. Energy Marketing & Trading
is currently evaluating the potential impact of the change but is unable at this
time to provide an estimate.
At September 30, 2002, Williams has maturing notes payable and long-term debt
totaling $685 million for the remainder of the current year and $2 billion
during 2003. The Company's available liquidity to meet these requirements and
fund a reduced level of capital expenditures will be dependent on several items,
including the cash flows of retained businesses, the amount of proceeds raised
from the sale of assets and the price of natural gas. 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 in the future and
available secured credit facilities, Williams currently believes that it has the
financial resources and liquidity to meet future cash requirements for the
balance of the year.
The new secured credit facilities require Williams to meet certain covenants
and limitations as well as maintain certain financial ratios (see Note 11).
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 have been
established.
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 of the following components as discontinued operations
(see Note 7):
o Central natural gas pipeline, previously one of Gas Pipeline's segments
o The Colorado soda ash mining operations, previously part of the
International segment
o Two natural gas liquids pipeline systems, Mid-American Pipeline and
Seminole Pipeline, previously part of the Midstream Gas & Liquids
segment
o Kern River Gas Transmission (Kern River), previously one of Gas
Pipeline's segments
Unless indicated otherwise, the following discussion and analysis of results
of operations, financial condition and liquidity relates to the 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
Exhibit 99(b) of Williams' Current Report on Form 8-K dated May 28, 2002, which
includes financial statements that reflect Kern River as discontinued
operations.
33
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 beginning on page 37.
<Table>
<Caption>
THREE NINE
MONTHS ENDED MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------ ------------------------
2002 2001 2002 2001
---------- ---------- ---------- ----------
(MILLIONS) (MILLIONS)
Revenues $ 2,103.9 $ 2,727.3 $ 6,518.2 $ 8,658.4
========== ========== ========== ==========
Operating income (loss) $ (269.7) $ 634.0 155.4 1,980.8
Interest accrued-net (358.5) (167.4) (828.8) (474.5)
Interest rate swap loss (52.2) -- (125.2) --
Investing income (loss):
Estimated loss on realization
of amounts due from WCG (22.9) -- (269.9) --
Other 85.3 (69.6) 161.5 39.9
Preferred returns and
minority interest in income
of consolidated subsidiaries (23.7) (22.2) (60.6) (70.4)
Other income - net 1.2 1.9 20.6 12.2
---------- ---------- ---------- ----------
Income (loss) from continuing
operations before income taxes (640.5) 376.7 (947.0) 1,488.0
Provision (benefit) for income
taxes (231.8) 182.8 (313.0) 615.2
---------- ---------- ---------- ----------
Income (loss) from continuing
operations (408.7) 193.9 (634.0) 872.8
Income (loss) from discontinued
operations 114.6 27.4 98.5 (112.8)
---------- ---------- ---------- ----------
Net income (loss) (294.1) 221.3 (535.5) 760.0
Preferred stock dividends (6.8) -- (83.3) --
---------- ---------- ---------- ----------
Income (loss) applicable to
common stock $ (300.9) $ 221.3 $ (618.8) $ 760.0
========== ========== ========== ==========
</Table>
Three Months Ended September 30, 2002 vs. Three Months Ended September 30, 2001
Williams' revenues decreased $623.4 million, or 23 percent, due primarily to
lower revenues associated with energy risk management and trading activities at
Energy Marketing & Trading and lower refined product sales volumes within
Petroleum Services. Partially offsetting these decreases were increased natural
gas production revenues as a result of higher net production volumes and net
realized average prices within Exploration & Production, increased revenues
associated with higher natural gas liquids sales prices from domestic processing
activities as well as an increase in natural gas liquids sales from Canadian
fractionation activities within Midstream Gas & Liquids and an increase to
revenues as a result of reductions in rate refund liabilities associated with
rate case settlements within Gas Pipeline.
Cost and operating expenses decreased $22.1 million due primarily to lower
refining and marketing costs at Petroleum Services and lower gas exchange
imbalance settlements (offset in revenues) at Gas Pipeline. Partially
offsetting these decreases were higher natural gas liquids purchases related to
Canadian fractionation activities, higher depreciation expense at Midstream Gas
& Liquids and increased depletion, depreciation and amortization and lease
operating expenses at Exploration & Production due primarily to the acquisition
of the former Barrett operations.
Selling, general and administrative expenses decreased $19.7 million, or 8
percent, due primarily to lower variable compensation levels associated with
reduced segment profit and reduced staffing levels at Energy Marketing & Trading
slightly offset by $6 million of expenses related to the Company contributions
to an employee stock ownership plan resulting from retirement of related
external debt, as well as approximately $5 million of employee-related severance
costs.
Other (income) expense - net in 2002 includes $432.6 million of impairment
charges within Petroleum Services comprised of a $176.2 million impairment of
the Midsouth refinery and related assets, $112.1 million impairment of the
travel centers and a $144.3 million impairment of the bio-energy business (see
Note 3). Partially offsetting these impairment charges were $143.9 million of
gains on sales of natural gas production properties in Wyoming and the Anadarko
Basin within Exploration & Production.
General corporate expenses increased $11.7 million, or 36 percent, due
primarily to approximately $19 million of costs related to consulting services
and legal fees associated with the liquidity and business issues addressed
during third-quarter 2002.
Operating income (loss) decreased $903.7 million to an operating loss of
$269.7 million, due primarily to lower
34
Management's Discussion & Analysis (Continued)
net revenues associated with energy risk management and trading activities at
Energy Marketing & Trading, and the $432.6 million of impairment charges as
previously mentioned. Partially offsetting these decreases were the gains on
sales of natural gas properties and increased production at Exploration &
Production discussed above and the effect of the rate refund liability
reductions related to rate case settlements at Gas Pipeline.
Interest accrued - net increased $191.1 million, or 114 percent, due
primarily to $53 million related to interest on the RMT note payable entered
into during third-quarter 2002 (see Note 11), the $66 million effect of higher
borrowing levels and the $45 million effect of higher average interest rates as
well as $27 million of higher debt amortization expense.
In 2002, Williams entered into interest rate swaps with external
counterparties resulting in losses of $52.2 million in third-quarter 2002 (see
Note 16).
Investing income (loss) increased $132 million due primarily to the $58.5
million gain on the sale of Williams' investment in a Lithuanian oil refinery
pipeline and terminal complex, which was included in the International operating
segment, an $8.7 million gain on the sale of Williams' general partner equity
interest in Northern Border Partners, L.P., $8.8 million in higher earnings on
equity investments, the absence in third-quarter 2002 of a $70.9 million
write-down of Williams' investment in WCG common stock and a $23.3 million loss
related to the 2001 loss from other investments included in the Energy Marketing
& Trading operating segment, which were determined to be other than temporary.
Partially offsetting is an $11.6 million net write-down of Williams' equity
interest in a Canadian and U.S. gas pipeline and $22.9 million estimated loss on
realization of amounts due from WCG (see Note 4).
The provision (benefit) for income taxes was favorable by $414.6 million due
primarily to a pre-tax loss in 2002 as compared to pre-tax income in 2001. The
effective income tax rate for the three months ended September 30, 2002, is
greater than the federal statutory rate due primarily to the effect of state
income taxes offset by the effect of taxes on foreign operations. The effective
income tax rate for the three months ended September 30, 2001, is greater than
the federal statutory rate due primarily to valuation allowances associated with
the tax benefits for investment write-downs for which ultimate realization is
uncertain and the effect of state income taxes.
Income (loss) from discontinued operations increased $87.2 million ($167.3
million pre-tax) due primarily to the $304.6 million before tax gain on the sale
of Mid-America and Seminole Pipelines, partially offset by the $86.9 million
impairment at Central natural gas pipeline system and an additional impairment
of $48.2 million of the soda ash operations (see Note 7).
Nine Months Ended September 30, 2002 vs. Nine Months Ended September 30, 2001
Williams' revenue decreased $2,140.2 million, or 25 percent, due primarily to
lower revenues associated with energy risk management and trading activities at
Energy Marketing & Trading, lower refined product sales prices and decreased
volumes sold at the refineries, lower travel center and Alaska convenience store
sales and the absence of $183 million of revenue related to the 198 convenience
stores sold in May 2001 within Petroleum Services and lower natural gas liquids
sales prices within Midstream Gas & Liquids. Partially offsetting these
decreases was an increase in net production volumes within Exploration &
Production and an increase in revenues due to the rate refund liability
reductions associated with the rate case settlements within Gas Pipeline.
Costs and operating expenses decreased $860.2 million, or 14 percent, due
primarily to lower refining and marketing costs, lower travel center/convenience
store costs reflecting the absence of the 198 convenience stores sold in May
2001 and lower diesel sales volumes and average gasoline and diesel purchase
prices at Petroleum Services and lower shrink, fuel and replacement gas
purchases related to processing activities at Midstream Gas & Liquids. Slightly
offsetting these decreases are increased depletion, depreciation and
amortization and lease operating expenses at Exploration & Production due
primarily to the addition of the former Barrett operations.
Selling, general and administrative expenses for 2002 include approximately
$6 million of expenses related to the company contributions to an employee stock
ownership plan resulting from retirement of related external debt, as well as
approximately $8 million of employee-related severance costs.
Other (income) expense - net in 2002 includes $459.6 million of impairment
charges within Petroleum Services comprised of a $176.2 million impairment of
the Midsouth refinery and related assets, $139.1 million impairment of the
travel centers and a $144.3 million impairment of the bio-energy business (see
Note 3). Also included in other (income) expense - net in 2002 are $152.7
million of impairment charges and loss accruals within Energy Marketing &
Trading comprised of $95.2 million associated with a terminated power plant
project and accruals for commitments for certain power assets and a $57.5
million goodwill impairment. Partially offsetting these impairment charges and
accruals were $143.9 million of gains on sales of natural gas production
properties at Exploration & Production in 2002 and the absence of 2001
impairment charges of $15.1 million and $11.2 million within Midstream Gas &
Liquids and Petroleum Services, respectively (see Note 3).
General corporate expenses increased $27.6 million, or 31 percent, due
primarily to $19 million of costs related to consulting services and legal fees
associated with the liquidity and business issues addressed during third-quarter
2002, and $6 million of expense related to the enhanced-benefit early retirement
options offered to certain employee groups as well as $4 million of expense
related to employee severance costs.
Operating income (loss) decreased $1,825.4 million, or 92 percent, due
primarily to lower net revenues associated with energy risk management and
trading activities at Energy Marketing & Trading, decreased profit from refining
and marketing operations within Petroleum Services and the impairment charges
and loss accruals noted above. Partially offsetting these decreases are the
gains from the sale of natural gas production properties and increased net
production volumes at Exploration & Production, the effect of the reductions in
rate refund liabilities associated with rate case settlements at Gas Pipeline
and higher natural gas liquids margins at Midstream Gas & Liquids.
Interest accrued - net increased $354.3 million, or 75 percent, due
primarily to $53 million related to interest on the RMT note payable, the $137
million effect of higher average interest rates, the $103 million effect of
higher borrowing levels and $45 million higher debt amortization expense. Also
contributing to these increases is a $10 million decrease in interest
capitalized related to a gas compression facility which began operations in
August 2001.
In 2002, Williams entered into interest rate swaps with external counter
parties resulting in losses of $125.2 million (see Note 16).
35
Management's Discussion & Analysis (Continued)
Investing income (loss) decreased $148.3 million due primarily to the $269.9
million estimated loss on realization of amounts due from WCG (see Note 4), the
impact of a $27.5 million gain in 2001 on the sale of Williams' limited partner
equity interest in Northern Border Partners, L.P., a $12.3 million write-down of
an investment in a pipeline project which was canceled and an $11.6 million net
impairment of Williams' equity interest in a Canadian and U.S. gas pipeline.
Partially offsetting these decreases was a $58.5 million gain on the sale of
Williams' equity interest in a Lithuanian oil refinery, pipeline and terminal
complex, which was included in the International segment, $57.9 million in
higher earnings on equity investments and the absence in 2002 of a $70.9 million
write-down of Williams' investment in WCG common stock and a 2001 $23.3 million
loss from other investments, which were determined to be other than temporary,
and an $8.7 million gain in 2002 on the sale of Williams' general partner
interest in Northern Border Partners, L.P. In addition, interest income related
to margin deposits decreased $22 million, dividend income decreased $5 million
due to the second-quarter 2001 sale of Ferrellgas Partners L.P. senior common
units and interest income from foreign investments decreased, while losses on
foreign investments increased for a combined negative impact of $12 million.
Other income - net increased $8.4 million due primarily to an $11 million
gain in second-quarter 2002 at Gas Pipeline associated with the disposition of
securities received through a mutual insurance company reorganization, a $10
million decrease in losses from the sales of receivables to special purpose
entities and the absence in 2002 of a 2001 $10 million payment to settle a claim
for coal royalty payments relating to a discontinued activity. Partially
offsetting these increases was an $8 million loss related to early retirement of
remarketable notes in first-quarter 2002.
The provision (benefit) for income taxes was favorable by $928.2 million due
primarily to a pre-tax loss as compared to pre-tax income in 2002. The
effective income tax rate for the nine months ended September 30, 2002, is less
than the federal statutory rate due primarily to the effect of taxes on foreign
operations and the impairment of goodwill, which is not deductible for tax
purposes and reduces the tax benefit of the pre-tax loss, offset by the effect
of state income taxes. The effective income tax rate for the nine months ended
September 30, 2001, is greater than the federal statutory rate due primarily to
valuation allowances associated with the tax benefits for investment write-downs
for which ultimate realization is uncertain and the effect of state income
taxes.
Income (loss) from discontinued operations increased $211.3 million ($354
million pre-tax) due primarily to the $304.6 million before tax gain on the sale
of Mid-America and Seminole Pipelines and the 2001 after-tax loss from the WCG
operations, partially offset by the $86.9 million impairment at Central natural
gas pipeline system and an additional impairment of $48.2 million related to the
soda ash operations (see Note 7).
Income (loss) applicable to common stock in 2002 reflects the impact of the
$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. The average number of shares in 2002 for the diluted
calculation (which is the same as the basic calculation due to Williams
reporting a loss from continuing operations - see Note 8) increased
approximately 23 million from September 30, 2001. The increase is due primarily
to the 29.6 million shares issued in the Barrett acquisition in August 2001.
The increased shares had a dilutive effect on earnings per share in 2002 of
approximately $.06 per share.
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, Petroleum Services, and International. Williams
currently evaluates performance based upon segment profit (loss) from operations
(see Note 16). Segment profit of the operating companies may vary by quarter.
Energy Marketing & Trading's results can vary quarter to quarter based on the
timing of origination activities and market movements of commodity prices,
interest rates and counterparty creditworthiness impacting the determination of
fair value of contracts.
In addition to the impact to the segments as a result of discontinued
operations previously discussed, the following changes occurred in 2002:
o Effective July 1, 2002, management of certain operations previously
conducted by Energy Marketing & Trading, International and Petroleum
Services was transferred to Midstream Gas & Liquids. These operations
included natural gas liquids trading, activities in Venezuela and a
petrochemical plant, respectively.
o On April 11, 2002, Williams Energy Partners L.P., a partially owned and
consolidated entity of Williams, acquired Williams Pipe Line, an
operation previously included within the Petroleum Services segment.
Accordingly, Williams Pipe Line's results of operations have been
transferred from the Petroleum Services segment to the Williams Energy
Partners segment.
o Management of an investment in an Argentine oil and gas exploration
company was transferred from the International segment to the
Exploration & Production segment to align exploration and production
activities.
Prior period amounts have been restated to reflect these changes. The
following discussions relate to the results of operations of Williams' segments.
36
Management's Discussion & Analysis (Continued)
ENERGY MARKETING & TRADING
<Table>
<Caption>
THREE NINE
MONTHS ENDED MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------ ------------------------
2002 2001 2002 2001
---------- ---------- ---------- ----------
(MILLIONS) (MILLIONS)
Segment revenues $ (290.2) $ 493.1 $ (213.8) $ 1,429.0
========== ========== ========== ==========
Segment profit (loss) $ (387.6) $ 356.9 $ (602.0) $ 1,108.6
========== ========== ========== ==========
</Table>
Three Months Ended September 30, 2002 vs. Three Months Ended September 30, 2001
ENERGY MARKETING & TRADING'S revenues decreased $783.3 million, or 159
percent, due primarily to a $782.1 million decrease in risk management and
trading revenues. During third-quarter 2002, Energy Marketing & Trading's
results were adversely affected by the impact of market movements against its
portfolio and an absence of new origination activities. 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 market concerns
regarding Williams' credit and liquidity situation.
The $782.1 million decrease from third-quarter 2001 in risk management and
trading revenues is due primarily to a decrease of $787.5 million in the natural
gas and power revenues and a $59.5 million decrease in the petroleum products
revenues, partially offset by a $63.6 million increase in revenues from the
emerging products portfolio. The $782.1 million decrease includes a $22.7
million decrease in revenues from new transactions originated as compared to
third-quarter 2001, resulting from Energy Marketing & Trading's inability to
enter into new origination transactions in the third quarter of 2002 as a result
of reduced market liquidity and Williams' limited credit capacity. Of the $787.5
million decline in natural gas and power revenues, $327.3 million is
attributable to a decline in natural gas revenues, caused primarily by
increasing prices on short natural gas positions. The remaining $460.2 million
decline relates to lower revenues from the power portfolio caused primarily by
significantly narrower spark spreads compared with third-quarter 2001 as well as
the net impact of portfolio valuation adjustments associated with portfolio
sales activities. The $59.5 million decrease in petroleum products revenues is
primarily due to lower volatility in the crude option and refined products
transportation portfolios. The $63.6 million increase in emerging products
revenues is primarily related to intercompany and external interest rate hedging
activities. Additionally, the natural gas, power and the petroleum products
portfolios were impacted by the general market deterioration and credit
degradation in the energy trading sector which had the effect of reducing
contract valuations as market liquidity declined and corporate bond spreads
deteriorated.
As a result of Williams' current liquidity constraints and previously
announced strategies, Energy Marketing & Trading continued efforts in the third
quarter to sell all or portions of its portfolio. Energy Marketing & Trading
continues to evaluate its potential alternatives which includes potential sale
of all or part of the portfolio, joint venture or other business combination
opportunities. As a result of information obtained through the negotiation
activities with potential buyers, the estimated fair value of certain portions
of the portfolio was reduced by $74.8 million reflecting management's estimate
of fair value at September 30, 2002. For those portions of the portfolio for
which no viable market information was received through negotiation efforts,
fair value has been estimated using other market-based information and valuation
techniques consistent with existing methodologies. Given the condition of the
energy trading sector and liquidity constraints of Williams, however, amounts
ultimately realized in any future portfolio sales, joint ventures or business
combination opportunities may be significantly less than fair value estimates
presented in the financial statements.
Selling, general, and administrative expenses decreased by $32 million, or 33
percent. This cost reduction is primarily due to lower variable compensation
levels associated with reduced segment profit and reduced staffing levels in the
energy marketing and trading operations.
Segment profit decreased $744.5 million or 209 percent, due primarily to the
$782.1 million reduction of risk management and trading revenues and a $11.5
million third-quarter 2002 loss accrual (see Note 3), partially offset by
reduced selling, general and administrative expenses and the absence of a $23.3
million 2001 loss on write-downs of investments (see Note 5).
Energy Marketing & Trading's future results will 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. 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 price risk management transactions. With the
decision to continue to reduce Williams' financial commitment and
37
Management's Discussion & Analysis (Continued)
exposure to the trading business, it is likely that Energy Marketing & Trading
will have greater 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 assessment related to the future value of
its forward positions. The effect of these items on Energy Marketing & Trading's
results could limit the ability of this segment to achieve profitable
operations.
A third party, from which Williams has the right to receive fuel
conversion services, disclosed in their third quarter 10-Q filed on November
12, 2002 that they were evaluating the future effect of certain subsidiaries
currently in default under outstanding project indebtedness. It is not possible
at this time to determine whether this situation or future actions by the third
party will negatively affect our results or financial position. Williams will
evaluate the implications, if any, of this situation and the future events that
occur during the fourth quarter.
On October 25, 2002, the Emerging Issues Task Force concluded in Issue No.
02-3 to rescind Issue No. 98-10, under which non-derivative energy trading
contracts are currently marked-to-market. In addition, trading inventories will
also no longer be marked-to-market but will be reported on a lower of cost or
market basis. Upon adoption of this new standard, Energy Marketing & Trading
will record an adjustment for the cumulative effect of this change in accounting
principle. The impact of this change in accounting principle could be
significant. Energy Marketing & Trading is currently evaluating the potential
impact of the change but is unable at this time to provide an estimate.
Issues in the Western Marketplace
At September 30, 2002, Energy Marketing & Trading had net accounts receivable
recorded of approximately $242 million for power sales to the California
Independent System Operator and the California Power Exchange Corporation
(CPEC). While the amount recorded reflects management's best estimate of
collectibility, future events or circumstances could change those estimates.
As discussed in Rate and Regulatory Matters and Related Litigation in Note 12
of the Notes to Consolidated Financial Statements, the FERC and the DOJ have
issued orders or initiated actions which involve the activities of Energy
Marketing & Trading in California and the western states. In addition to these
federal agency actions, a number of federal and state initiatives addressing the
issues of the California electric power industry are also ongoing and may result
in restructuring of various markets in California and elsewhere. Discussions in
California and other states have ranged from threats of re-regulation to
suspension of plans to move forward with deregulation. Allegations have also
been made that the wholesale price increases experienced in 2000 and 2001
resulted from the exercise of market power and collusion of the power generators
and sellers, such as Williams. These allegations have resulted in multiple state
and federal investigations as well as the filing of class-action lawsuits in
which Williams is a named defendant. Williams' long-term power contract with the
State of California has also been challenged both at the FERC and in civil
suits. Most of these initiatives, investigations and proceedings are in their
preliminary stages and their likely outcome cannot be estimated. However,
Williams executed a settlement agreement on November 11, 2002, that is intended
to resolve many of these disputes with the State of California on a global basis
that includes a renegotiated long-term energy contract. The settlement is also
intended to resolve complaints brought by the California Attorney General
against Williams and the State of California's refund claims. In addition, the
settlement is intended to resolve ongoing investigations by the States of
California, Oregon, and Washington. The settlement is subject to various court
and agency approvals and due diligence by the California Attorney General (see
other legal matters in Note 12). There can be no assurance that these
initiatives, investigations and proceedings will not have a material adverse
effect on Williams' results of operations or financial condition.
Nine Months Ended September 30, 2002 vs. Nine Months Ended September 30, 2001
ENERGY MARKETING & TRADING'S revenues decreased $1,642.8 million, or 115
percent, due primarily to a $1,642.6 million decrease in risk management and
trading revenues. As noted previously, Energy Marketing & Trading's results were
in general adversely affected by its limited ability to manage or hedge its
portfolio against adverse market movements due to a lack of market liquidity,
the market's concerns regarding Williams' credit and liquidity situation, and
internal efforts to preserve liquidity.
The $1,642.6 million decrease in risk management and trading revenues is due
primarily to a decrease of $1,747.8 million in natural gas and power revenues,
partially offset by a $12.1 million increase in petroleum product revenues and
$85.3 million increase in emerging products revenues. The $1,646.5 million
decrease in revenues includes a $127.3 million decrease due to the absence of
any significant new transactions originating during the second and third
quarters of 2002. Declines in natural gas revenues are primarily due to rising
gas prices on short natural gas positions. Decreases in power revenues are
due primarily to lower market volatility and narrower spark spreads than were
present during 2001 and valuation adjustments resulting from 2002 third quarter
efforts to sell portions of Energy Marketing & Trading's portfolio. The $12.1
million increase in petroleum products revenues is due to $118.8 million
resulting from the origination of transactions during the first quarter of 2002
offset by a decrease in revenues resulting from lower volatility in the crude
option and refined products transportation portfolios. The $85.3 million
increase in revenues from the emerging products portfolio relates primarily to
intercompany and external interest rate hedging activities. Additionally, the
natural gas and power and the petroleum products portfolio were also impacted by
the general market deterioration and credit degradation in the energy trading
sector which had the effect of reducing contract valuations as market liquidity
declined and corporate bond spreads deteriorated.
38
Management's Discussion & Analysis (Continued)
Selling, general, and administrative costs decreased by $74 million, or 29
percent. This cost reduction is primarily due to lower variable compensation
levels associated with reduced segment profit and reduced staffing levels in the
energy marketing and trading operations.
Other (income) expense - net in 2002 includes $95.2 million of net loss
accruals and write-offs primarily associated with commitments for certain
terminated power projects (see Note 3). Of this amount, $61.5 million was
associated with a reduction to fair value of certain power equipment which
management made the decision to sell rather than utilize in power development
projects. The balance for the second quarter primarily represents an accrual for
costs associated with leased power generation equipment. Also included in other
(income) expense in 2002 is a $57.5 million partial goodwill impairment recorded
during second- quarter resulting from deteriorating market conditions. The
remaining goodwill was evaluated for impairment in third-quarter 2002 and no
additional impairment was required based on management's estimate of the fair
value of Energy Marketing & Trading at September 30, 2002.
Segment profit decreased $1,710.6 million, or 154 percent, due primarily to
the $1,646.5 million reduction in risk management and trading revenues and the
non-recurring items discussed in other income (expense) above, partially offset
by the decrease in selling, general, and administrative expense.
GAS PIPELINE
<Table>
<Caption>
THREE NINE
MONTHS ENDED MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
--------------------------- ---------------------------
2002 2001 2002 2001
------------ ------------ ------------ ------------
(MILLIONS) (MILLIONS)
Segment revenues $ 381.4 $ 335.1 $ 1,106.4 $ 1,048.5
============ ============ ============ ============
Segment profit $ 172.6 $ 101.8 $ 506.0 $ 436.0
============ ============ ============ ============
</Table>
Three Months Ended September 30, 2002 vs. Three Months Ended September 30, 2001
GAS PIPELINE'S revenues increased $46.3 million, or 14 percent, due primarily
to the effect of $36.5 million in reductions in the rate refund liabilities and
other adjustments associated with rate case settlements on the Transcontinental
Gas Pipe Line (Transco) and Texas Gas systems, $16 million higher demand
revenues on the Transco system resulting from new expansion projects and new
rate case settlement rates effective September 1, 2001, and $6 million higher
transportation revenues on the Texas Gas system resulting from the new rate case
settlement rates. Partially offsetting these increases was $19 million in lower
gas exchange imbalance settlements (offset in costs and operating expenses).
Costs and operating expenses decreased $27.9 million, or 15 percent, due
primarily to $19 million lower gas exchange imbalance settlements (offset in
revenues), $7.6 million lower depreciation expense due to adjustments related to
lower depreciation rates approved in the rate case settlements and $3 million
lower operations and maintenance expense primarily due to lower professional and
other contractual services.
General and administrative costs reflect $13 million lower charitable
contributions due to significantly reduced levels of company commitments to the
2002 United Way campaign from record levels in 2001. This decline was partially
offset by $10 million higher expense primarily associated with employee-related
benefits in third-quarter 2002 including approximately $4 million related to
expense recognized as a result of accelerated company contributions to an
employee stock ownership plan resulting from the early retirement of related
third party debt.
Other income (expense) - net in 2002 includes a $3.7 million loss from the
sale of the Cove Point facility. The sale closed in September 2002 for proceeds
of $217 million.
Segment profit, which includes equity earnings and income (loss) from
investments, increased $70.8 million, or 70 percent, due primarily to the $44.1
million effect of rate refund liability reductions and other adjustments related
to the final settlement of Transco and Texas Gas rate cases during third-quarter
2002, the higher revenues and lower overall expenses discussed above, and an
$8.7 million gain on the sale of the general partnership interest in Northern
Border Partners, L.P. which was sold for $12 million. Partially offsetting these
increases to segment profit were the $3.7 million loss on the sale of the Cove
Point facility and an $11.6 million net impairment charge on Gas Pipeline's 14.6
percent ownership interest in Alliance Pipeline which was sold in October 2002
for approximately $173 million.
39
Management's Discussion & Analysis (Continued)
Nine Months Ended September 30, 2002 vs. Nine Months Ended September 30, 2001
GAS PIPELINE'S revenues increased $57.9 million, or 6 percent, due primarily
to the $36.5 million effect of reductions in the rate refund liabilities and
other adjustments associated with rate case settlements on the Transco and Texas
Gas systems ($17.4 million is applicable to the first six months of 2002), $35
million higher demand revenues on the Transco system resulting from new
expansion projects and new settlement rates effective September 1, 2001, and $9
million from environmental mitigation credit sales and services. Partially
offsetting these increases were $19 million lower gas exchange imbalance
settlements (offset in costs and operating expenses), $9 million lower revenues
associated with the recovery of tracked costs which are passed through to
customers (offset in costs and operating expenses and general and administrative
expenses) and $7 million lower storage revenues primarily due to lower rates on
Cove Point's short-term storage contracts.
Costs and operating expenses decreased $12.8 million, or 3 percent, due
primarily to $19 million lower gas exchange imbalance settlements (offset in
revenues), $7 million lower other tracked costs which are passed through to
customers (offset in revenues) and $5 million lower operations and maintenance
expense due primarily to lower professional and other contractual services and
telecommunications expenses. These decreases were partially offset by the $15
million effect in 2001 of a regulatory reserve reversal resulting from the
FERC's approval for recovery of fuel costs incurred in prior periods by Transco,
as well as $5 million higher depreciation expense. The $5 million higher
depreciation expense reflects a $12 million increase due to increased property,
plant and equipment placed into service (including depletion of property held
for the environmental mitigation credit sales), partially offset by a $7.6
million adjustment related to the 2002 rate case settlements resulting in lower
depreciation rates applied retrospectively ($3.1 million is applicable to the
first six months of 2002).
General and administrative costs increased $13.1 million, or 8 percent, due
primarily to $11 million in costs associated with an early retirement option
offered during the first half of 2002 and $15 million higher expenses primarily
related to employee-related benefits expense, including approximately $4 million
related to expense recognized as a result of accelerated company contributions
to an employee stock ownership plan resulting from the early retirement of
related third party debt. These increases were partially offset by $13 million
lower charitable contributions in 2002 and $3 million lower tracked costs
(offset in revenues).
Other income (expense) - net in 2002 includes a $3.7 million loss on the sale
of the Cove Point facility.
Segment profit, which includes equity earnings and income (loss) from
investments (both included in investing income), increased $70 million, or 16
percent, due primarily to $52.7 million higher equity earnings, the $44.1
million effect of rate refund liability reductions and other adjustments related
to the final settlement of rate cases during third-quarter 2002, the higher
demand revenues discussed above, lower costs and operating expenses also
discussed above, and an $8.7 million gain in 2002 on the sale of the general
partnership interest in Northern Border Partners, L.P. These increases were
partially offset by an $11.6 million impairment charge in 2002 on Gas Pipeline's
14.6 percent ownership interest in Alliance Pipeline, a $12.3 million write-down
in 2002 of Gas Pipeline's investment in a pipeline project that has been
cancelled and the impact of a $27.5 million gain in 2001 from the sale of the
limited partnership interest in Northern Border Partners, L.P, the $13.1 million
increase in general and administrative costs discussed above and the $3.7
million loss on the sale of the Cove Point facility. The increase in equity
earnings includes a $27.4 million benefit in 2002 related to the contractual
construction completion fee received by an equity affiliate. This equity
affiliate served as the general contractor on the Gulfstream pipeline project
for Gulfstream Natural Gas System (Gulfstream), an interstate natural gas
pipeline subject to FERC regulation and also an equity affiliate. The fee, paid
by Gulfstream and associated with the completion during the second quarter of
2002 of the construction of Gulfstream's pipeline, was capitalized by Gulfstream
as property, plant and equipment and is included in Gulfstream's rate base to be
recovered in future revenues. Additionally, the equity earnings increase
reflects a $25 million increase from Gulfstream primarily related to interest
capitalized on the Gulfstream pipeline project in accordance with FERC
regulations.
40
Management's Discussion & Analysis (Continued)
EXPLORATION & PRODUCTION
<Table>
<Caption>
THREE NINE
MONTHS ENDED MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
----------------------- -----------------------
2002 2001 2002 2001
---------- ---------- ---------- ----------
(MILLIONS) (MILLIONS)
Segment revenues $ 219.3 $ 160.6 $ 677.8 $ 410.2
========== ========== ========== ==========
Segment profit $ 231.8 $ 65.0 $ 433.5 $ 165.4
========== ========== ========== ==========
</Table>
Three Months Ended September 30, 2002 vs. Three Months Ended September 30, 2001
EXPLORATION & PRODUCTION'S revenues increased $58.7 million, or 37 percent,
due primarily to $67 million higher production revenues and $7 million in
unrealized gains from the mark-to-market financial instruments related to basis
differentials on natural gas production, partially offset by $16 million lower
gas management, international and other miscellaneous revenues. The $67 million
increase in production revenues includes $37 million associated with an increase
in net production volumes as well as $30 million from increased net realized
average prices for production (including the effect of hedge positions). The
increase in net production volumes mainly results from the acquisition at the
beginning of August 2001 of Barrett Resources Corporation (Barrett).
Approximately 78 percent of domestic production in the third quarter of 2002 was
hedged. Exploration & Production has contracts that hedge approximately 87
percent of estimated production for the remainder of the year. These hedges are
entered into 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. During 2001, a portion of the external derivative contracts was with
Enron, which filed for bankruptcy in December 2001. As a result, the contracts
were effectively liquidated due to contractual terms concerning bankruptcy and
Energy Marketing & Trading recorded estimated charges for the credit exposure.
During the third quarter of 2002, Energy Marketing & Trading had additional
contracts not related to Enron that were terminated. Under accounting guidance,
the other comprehensive income related to a terminated contract remains in
accumulated other comprehensive income and is recognized as the underlying
volumes are produced. During the third quarter of 2002, approximately $10
million related to the terminated contracts was recognized as revenues while $52
million remains in accumulated other comprehensive income at September 30, 2002.
Costs and operating expenses, including selling, general and administrative
expenses, increased $26 million, due primarily to increased depletion,
depreciation and amortization and lease operating expenses as a result of the
addition of the former Barrett operations.
Included in other (income) expense-net are $143.9 million in net gains from
the sales of natural gas production properties. As previously reported,
Exploration & Production completed during the third quarter of 2002, the sales
of natural gas production properties in the Jonah field (Wyoming) and in the
Anadarko Basin. The sales resulted in gains of approximately $122.3 million and
$21.6 million, respectively, and generated approximately $326 million in net
cash proceeds. The Jonah field properties represented approximately 11 percent
of total reserves at December 31, 2001, the absence of which could impact future
revenue levels.
Segment profit increased $166.8 million due primarily to the gains from asset
sales mentioned above, increased production volumes and higher net realized
average prices.
Nine Months Ended September 30, 2002 vs. Nine Months Ended September 30, 2001
EXPLORATION & PRODUCTION'S revenues increased $267.6 million, or 65 percent,
due primarily to $277 million higher production revenues, $14 million in
unrealized gains from the mark-to-market financial instruments related to basis
differentials on natural gas production, partially offset by $23 million lower
gas management revenues. The $277 million increase in production revenues
includes $276 million associated with an increase in net production volumes. The
increase in net production volumes results mainly from the acquisition in third
quarter 2001 of the former Barrett operations. Approximately 81 percent of
domestic production through the third quarter of 2002 was hedged. Through the
third quarter of 2002, approximately $28 million related to the terminated
contracts discussed above was recognized as revenues. At September 30, 2002, the
contracted future hedge contracts are at prices that averaged above the spot
market, resulting in an unrealized gain of $130 million (including $52 million
related to the terminated contracts as discussed previously) reflected in
accumulated other comprehensive income within stockholders' equity. This is a
decrease from the unrealized gain at December 31, 2001, due to an increase in
natural gas prices.
Gas management revenues consist primarily of marketing activities within the
Exploration & Production segment
41
Management's Discussion & Analysis (Continued)
that are not a direct part of the results of operations for producing
activities. These marketing 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 operating expenses, including selling, general and administrative
expenses, increased $129 million due primarily to $127 million increase in
depletion, depreciation and amortization and lease operating expenses resulting
from the addition of the former Barrett operations, $23 million higher selling
general and administrative expenses and $9 million higher production related
taxes, partially offset by $23 million lower gas management costs, and $10
million lower costs from International activities.
Included in other (income) expense-net are $147.4 million in net gains from
the sales of natural gas production properties during 2002.
Segment profit increased $268.1 million due primarily to the gains from asset
sales and increased production volumes, partially offset by a $5 million
decrease in earnings from equity investments and $8.5 million of equity earnings
in 2001 related to the 50 percent investment in Barrett held by Williams for the
period from June 11, 2001 through August 1, 2001.
MIDSTREAM GAS & LIQUIDS
<Table>
<Caption>
THREE NINE
MONTHS ENDED MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
----------------------- -----------------------
2002 2001 2002 2001
---------- ---------- ---------- ----------
(MILLIONS) (MILLIONS)
Segment revenues $ 501.8 $ 414.9 $ 1,339.8 $ 1,506.8
========== ========== ========== ==========
Segment profit $ 104.0 $ 69.5 $ 210.0 $ 126.4
========== ========== ========== ==========
</Table>
Three Months Ended September 30, 2002 vs. Three Months Ended September 30, 2001
MIDSTREAM GAS & LIQUIDS' revenues increased $86.9 million, or 21 percent, due
primarily to a $47 million increase from domestic operations, a $42 million
increase from Canadian operations and $10 million higher revenues from
Venezuelan activities due primarily to a gas compression facility which began
operations in August 2001. The increase in domestic operations reflects $23
million higher natural gas liquids sales from domestic processing activities,
$21 million of revenues from Gulf Liquids, a domestic processing and
fractionation company which became a consolidated entity in 2002 and $4 million
higher domestic processing revenues. The $23 million higher liquids sales from
domestic processing activities reflects $25 million from a 24 percent increase
in volumes sold, partially offset by $2 million from lower average natural gas
liquids sales prices. The increase in the domestic liquids volumes sold is due
primarily to expansion of an existing natural gas liquids plant and the impact
of another natural gas liquids plant placed in service in fourth-quarter 2001.
The increase in the Canadian operations includes $34 million higher natural gas
liquids sales from Canadian fractionation activities due primarily to higher
propane sales from an extraction facility which began operations in 2002 and
higher product sales as a result of improvements made at a parafins facility and
$7 million higher liquids sales from Canadian activities reflecting $15 million
from a 29 percent increase in average natural gas liquids sales prices,
partially offset by $8 million from a 14 percent decrease in volumes sold.
Costs and operating expenses increased $50 million, or 16 percent, due
primarily to $21 million higher natural gas liquids purchases related to
Canadian fractionation activities, $16 million higher depreciation expense for
both foreign and domestic operations due primarily to additional property, plant
and equipment placed into service, $15 million related to the domestic
fractionation activities of Gulf Liquids, $10 million higher transportation,
fractionation and marketing costs related to natural gas liquids sales from
processing activities ($6 million related to Canadian activities and $4 million
related to domestic activities) and $6 million higher operations and maintenance
expense due primarily to the inclusion of the Gulf Liquids operating and
maintenance expenses of $10 million combined with $5 million higher expenses
related to the Venezuelan gas compression facility, largely offset by a $12
million decrease resulting from operational efficiencies.
Selling, general and administrative costs increased $9 million due primarily
to the consolidation of the Gulf Liquids operations.
Included in 2001 other (income) expense - net are impairment charges of $4.2
million related to certain South Texas non-regulated gathering and processing
assets.
42
Management's Discussion & Analysis (Continued)
Segment profit increased $34.5 million, or 50 percent, due primarily to a
$27.5 million increase from domestic operations and a $7 million increase from
Canadian operations. The domestic operations, which represent 65 percent of 2002
segment profit, increased due to higher natural gas liquids margins of $8
million primarily resulting from favorable shrink prices at the Wyoming plants,
$7 million lower other operating costs due primarily to reduced condensate
costs, $6 million favorable products margin from Gulf Liquids, $5 million lower
operating taxes, $4 million higher domestic processing margins and $3 million in
equity earnings in 2002 versus $3 million of equity losses in 2001 reflecting
improved results from the Discovery pipeline project. These favorable variances
of the domestic operations were partially offset by $12 million higher selling,
general and administrative costs and $5 million higher depreciation expense due
primarily to the inclusion of Gulf Liquids. The Canadian operations were higher
due to improved liquids margins from processing ($8 million) and fractionation
($13 million) due to favorable inventory positions, partially offset by $8
million higher depreciation expense and $5 million higher liquids transportation
expense.
Williams is currently evaluating the sale of its Canadian processing,
fractionation and olefins businesses. The Canadian business contributed $459
million, or 34 percent, to revenues and $24 million, or 12 percent, to segment
profit for the nine months ended September 30, 2002.
Midstream Gas & Liquid's deepwater natural gas and crude infrastructure
expansion projects in the Gulf of Mexico are expected to increase both revenues
and operating profit in the future. The first major deepwater project, East
Breaks, went into service in late 2001.
Nine Months Ended September 30, 2002 vs. Nine Months Ended September 30, 2001
MIDSTREAM GAS & LIQUIDS' revenues decreased $167 million, or 11 percent, due
primarily to $88 million lower revenues related to natural gas liquids trading,
$83 million lower natural gas liquids sales from Canadian processing activities
due primarily to a 30 percent decrease in average natural gas liquids sales
prices, $31 million higher intrasegment sales, which are eliminated and
primarily relate to sales from trading operations, $30 million lower revenues
from Canadian processing activities due primarily to lower processing rates
which are based on the recovery of certain costs which were lower in 2002 and
$16 million lower domestic gathering revenues due primarily to decreased
volumes. These decreases were partially offset by $49 million higher revenues
from Venezuelan activities primarily due to a gas compression facility which
began operations in August 2001, as well as $21 million higher sales from Gulf
Liquids, a domestic processing and fractionation facility which became a
consolidated entity during 2002, and $6 million higher domestic revenues from
transportation activities.
Costs and operating expenses decreased $243 million, or 19 percent. Costs
were down due primarily to $169 million lower shrink, fuel and replacement gas
purchases relating to processing activities ($127 million related to Canada and
$42 million related to domestic activities), $69 million lower costs relating to
natural gas liquids trading, $31 million lower external costs due to increased
intrasegment purchases discussed above, which are eliminated, $17 million lower
natural gas liquids purchases related to Canadian fractionation activities and a
$7 million decrease in domestic power expense. Partially offsetting these
decreases were $21 million increased depreciation expense for both foreign and
domestic operations due primarily to additional property, plant and equipment
placed into service, $15 million in higher costs related to the domestic
fractionation activities from Gulf Liquids and $13 million higher domestic
transportation, fractionation and marketing costs related to natural gas liquids
sales from processing activities.
Selling, general and administrative costs increased $17 million due primarily
to the addition of the Gulf Liquids assets.
Included in other (income) expense - net within segment costs and expenses
for 2001 is $15.1 million of impairment charges related to certain South Texas
non-regulated gathering and processing assets. Included in 2002 other (income)
expense - net, is a $5.9 million charge representing the impairment of assets to
fair value associated with the third-quarter 2002 sale of the Kansas-Hugoton
natural gas gathering system.
Segment profit increased $83.6 million, or 66 percent, due primarily to a $62
million increase from domestic operations, a $21 million increase from Canadian
operations and an $18 million increase from Venezuelan activities, partially
offset by an $18 million decrease from natural gas liquids trading activities.
The domestic operations, which represent 67 percent of 2002 segment profit,
increased due to higher natural gas liquids margins of $29 million primarily
resulting from favorable shrink prices at the Wyoming plants, $14 million lower
other operating costs due primarily to reduced condensate costs, the $9 million
favorable variance in other (income) expense - net discussed above, decreased
power costs due to lower gas prices of $8 million, $6 million increased
transportation revenues due primarily to the start up of the deepwater oil and
natural gas gathering system in late 2001 and equity earnings in 2002 of $9
million versus $14 million of equity losses in 2001. The equity earnings
improvement is due primarily to the Discovery pipeline project. Partially
offsetting these favorable variances are the $17 million higher selling, general
and administrative costs discussed above and lower gathering revenues of $16
million due primarily to lower volumes. Canadian segment profit was higher due
to $22 million improved liquids margins from processing as a result of higher
average natural gas liquids prices and $23 million higher fractionation margins
due to favorable inventory positions and higher volumes, partially offset by $15
million higher liquids transportation expense and $6 million higher depreciation
expense.
43
Management's Discussion & Analysis (Continued)
WILLIAMS ENERGY PARTNERS
<Table>
<Caption>
THREE NINE
MONTHS ENDED MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
----------------------- -----------------------
2002 2001 2002 2001
---------- ---------- ---------- ----------
(MILLIONS) (MILLIONS)
Segment revenues $ 107.5 $ 110.8 $ 303.6 $ 310.7
========== ========== ========== ==========
Segment profit $ 13.4 $ 27.1 $ 69.8 $ 83.6
========== ========== ========== ==========
</Table>
Three Months Ended September 30, 2002 vs. Three Months Ended September 30, 2001
WILLIAMS ENERGY PARTNERS' segment profit decreased $13.7 million, or 51
percent, due primarily to $9 million higher environmental expense primarily
related to the petroleum products pipeline as a result of internal environmental
studies completed during third-quarter 2002.
Nine Months Ended September 30, 2002 vs. Nine Months Ended September 30, 2001
WILLIAMS ENERGY PARTNERS' revenue decreased $7.1 million, or 2 percent due
primarily to $12 million lower commodity sales from transportation activities
and reduced ammonia volumes, partially offset by higher revenue from a marine
facility acquired in October 2001 and two inland terminals acquired in
June 2001.
Costs and operating expenses were relatively unchanged with the effect of
$12 million lower commodity purchases offset by $7 million higher environmental
expense and higher operating expenses. The increased operating expenses include
third-party pipeline lease expenses and additional operating costs from the
newly acquired marine and inland terminals.
Segment profit decreased $13.8 million or 17 percent due to the decrease
in revenue discussed above, and higher selling, general and administrative
expenses.
PETROLEUM SERVICES
<Table>
<Caption>
THREE NINE
MONTHS ENDED MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------ ------------------------
2002 2001 2002 2001
---------- ---------- ---------- ----------
(MILLIONS) (MILLIONS)
Segment revenues $ 1,170.9 $ 1,281.9 $ 3,266.7 $ 4,077.6
========== ========== ========== ==========
Segment profit (loss) $ (406.2) $ 42.4 $ (396.5) $ 189.5
========== ========== ========== ==========
</Table>
Three Months Ended September 30, 2002 vs. Three Months Ended September 30, 2001
PETROLEUM SERVICES' revenues decreased $111 million, or 9 percent, due
primarily to $100 million lower refining and marketing revenues and $16 million
lower revenues from the travel centers and Alaska convenience stores, partially
offset by $6 million higher bio-energy sales. The $100 million decrease in
refining and marketing revenues includes $93 million resulting from 10 percent
lower refined product volumes sold and $7 million from a decrease in average
refined product sales prices. Volumes at the Midsouth refinery declined due to
lower crude throughput resulting from the restrictions on obtaining crude
supplies due to Williams' credit situation and management's decision to fulfill
only firm commitments for diesel fuel as a result of narrowing crack spreads.
Volumes at Alaska increased over the prior year's third-quarter. The $16 million
decrease in revenues of the travel centers and Alaska convenience stores
primarily reflects $19 million from an 11 percent decrease in diesel sales
volumes and $9 million from a 4 percent decrease in average diesel and gasoline
sales prices and $3 million from a decrease in merchandise sales, partially
offset by a $16 million increase in gasoline sales volumes. The decrease in
travel center diesel sales volumes includes the impact of renegotiated fleet
programs. Travel center gasoline volumes in third-quarter 2001 were lower than
normal reflecting the environment after September 11, 2001. The $6 million
increase in bio-energy sales primarily reflects a $27 million increase from
higher ethanol sales volumes resulting from new marketing agreements, partially
offset by a $23 million decrease from lower average ethanol sales prices.
Costs and operating expenses decreased $92 million, or 8 percent, due
primarily to $91 million lower refining
44
Management's Discussion & Analysis (Continued)
and marketing costs and $12 million lower costs for the travel centers and
Alaska convenience stores, partially offset by $13 million higher bio-energy
costs. The $91 million decrease in refining and marketing costs includes a $75
million decrease from lower crude supply costs and other cost of sales from the
refineries related to lower overall volumes and a $16 million decrease in the
total cost of refined product purchased for resale, also resulting from lower
volumes. The $12 million decrease in costs for the travel centers and the Alaska
convenience stores reflects $18 million from lower diesel sales volumes, $5
million from lower average gasoline and diesel purchase prices and $3 million
lower store operating and merchandise costs, partially offset by a $14 million
increase in gasoline purchase volumes.
Other (income) expense - net in third-quarter 2002 includes a $176.2
million impairment charge related to Williams Midsouth refinery, a $112.1
million impairment charge related to the travel centers and a $144.3 million
impairment charge related to bio-energy operations (see Note 3).
Segment profit decreased $448.6 million to a $406.2 million segment loss
due primarily to the $432.6 million in impairment charges discussed above in
other (income) expense - net, $9 million lower operating profit from refining
and marketing operations due primarily to narrowing crack spreads and
curtailment of business due to credit capacity limitations, and $7 million lower
operating profit from bio-energy operations due primarily to higher product and
feedstock costs.
Williams has been in discussions regarding the sale of its refining and
marketing operations, and its Alaska convenience stores. In October 2002,
Williams' board of directors approved the sale of the travel centers with the
closing of the sale anticipated in late fourth-quarter 2002 or early first
quarter 2003. In addition, the bio-energy operation is also a business that may
be sold in the future and has been the subject of a reserve auction process.
Depending of the terms of prospective sales and timing of liquidity needs,
Williams may accept amounts that are less than the respective business' carrying
value at September 30, 2002.
Nine Months Ended September 30, 2002 vs. Nine Months Ended September 30, 2001
PETROLEUM SERVICES' revenues decreased $810.9 million, or 20 percent, due
primarily to $544 million lower refining and marketing revenues, $352 million
lower travel center/convenience store sales and $16 million lower bio-energy
sales, partially offset by $107 million lower intrasegment sales, which are
eliminated and primarily relate to sales from refining and marketing to travel
center/convenience stores. The $544 million decrease in refining and marketing
revenues primarily includes $413 million resulting from 15 percent lower average
refined product sales prices and $131 million from a decrease in refined product
volumes sold. The decrease in volumes is due primarily to the curtailment of
business in second and third-quarter 2002 due to limitations of Williams' credit
support capacity. The $352 million decrease in travel center/convenience store
costs reflects a $169 million decrease in revenues related to travel centers and
Alaska convenience stores and the absence of $183 million in revenues related to
the 198 convenience stores sold in May 2001. The $169 million decrease in
revenues of the travel centers and Alaska convenience stores primarily reflects
$113 million from a 19 percent decrease in diesel sales volumes and $73 million
from an 11 percent decrease in average diesel and gasoline sales prices and $6
million from a decrease in merchandise sales, partially offset by a $24 million
increase in gasoline sales volumes. The $16 million decrease in bio-energy sales
primarily reflects $68 million lower average ethanol sales prices, partially
offset by $47 million higher ethanol sales volumes resulting from new marketing
agreements.
Costs and operating expenses decreased $737 million, or 19 percent, due
primarily to $489 million lower refining and marketing costs and $354 million
lower travel center/convenience store costs, partially offset by a $107 million
increase in external costs due to decreased intrasegment purchases discussed
above, which are eliminated. The $489 million decrease in refining and marketing
costs includes a $425 million decrease from lower crude supply costs and other
cost of sales from the refineries related to lower overall volumes and a $64
million decrease in the total cost of refined product purchased for resale. The
$354 million decrease in travel center and Alaska convenience store costs
primarily reflects the absence of $183 million in costs related to the 198
convenience stores sold in May 2001 and a $171 million decrease in costs for the
travel centers and Alaska convenience stores. The $171 million decrease in costs
for the travel centers and Alaska convenience stores reflects $108 million from
decreased diesel sales volumes, $70 million from lower average gasoline and
diesel purchase prices and $14 million lower store operating and merchandise
costs, partially offset by $22 million in increased gasoline purchase volumes.
Other (income) expense - net in 2002 includes a $176.2 million impairment
charge related to Williams Midsouth refinery, $139.1 million in loss accruals
and impairment charges related to the travel centers and a $144.3 million
impairment charge related to bio-energy operations (see Note 3). Other (income)
expense - net in 2001 includes a $72.1 million pre-tax gain from the sale of
convenience stores sold in May 2001 and an $11.2 million impairment charge
related to an end-to-end mobile computing systems business.
Segment profit decreased $586 million to a $396.5 million segment loss
due primarily to the $520.5 million net unfavorable effect related to the
impairment charges and other items noted above in other (income) expense - net,
the $55 million lower operating profit from refining and marketing operations
due primarily to narrowing crack spreads and curtailment of business due to
credit issues and $20 million lower operating profit from bio-energy operations
due primarily to higher product and feedstock costs.
45
Management's Discussion & Analysis (Continued)
INTERNATIONAL
<Table>
<Caption>
THREE NINE
MONTHS ENDED MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
----------------------- -----------------------
2002 2001 2002 2001
---------- ---------- ---------- ----------
(MILLIONS) (MILLIONS)
Segment revenues $ .7 $ 1.1 $ 3.1 $ 2.6
========== ========== ========== ==========
Segment profit (loss) $ 53.1 $ (10.9) $ 34.8 $ (22.9)
========== ========== ========== ==========
</Table>
Three Months Ended September 30, 2002 vs. Three Months Ended September 30, 2001
INTERNATIONAL'S segment profit increased $64 million, due primarily to a $58.5
million gain from the September 2002 sale of Williams' 27 percent ownership
interest in the Lithuanian refinery, pipeline and terminal complex and a $6
million decrease in equity losses from the Lithuanian operations for the period.
Williams received approximately $85 million from the sale of this investment. In
addition, Williams sold its $75 million note receivable from the Lithuanian
operations at face value. As a result of the sale of its interest in the
Lithuanian operations and the anticipated sale of the soda ash operations
(previously reported as continuing operations within International), it is
anticipated that the International segment will be included in the Other segment
category in future reporting periods.
Results of the soda ash operations previously included in the International
segment have been reclassified to discontinued operations (see Note 7) following
the board of director's authorization in third-quarter 2002 to sell this
business.
Nine Months Ended September 30, 2002 vs. Nine Months Ended September 30, 2001
INTERNATIONAL'S segment profit increased $57.7 million, due primarily to a $58.5
million gain on the sale of Williams' remaining 27 percent ownership interest in
the Lithuanian refinery.
46
Management's Discussion & Analysis (Continued)
FAIR VALUE OF ENERGY RISK MANAGEMENT AND TRADING ACTIVITIES
The fair value of energy risk management and trading contracts for Energy
Marketing & Trading and the natural gas liquids trading operations (reported in
the Midstream Gas & Liquids segment) decreased $509 million during third-quarter
2002 and $593 million year-to-date. The following table reflects the changes in
fair value between December 31, 2001 and September 30, 2002.
<Table>
<Caption>
(Millions)
----------
FAIR VALUE OF CONTRACTS OUTSTANDING AT DECEMBER 31, 2001
$ 2,261
Recognized losses included in the fair value of contracts
outstanding at December 31, 2001
expected to be realized during the period 173
Initial recorded value of new contracts entered into during
the period 181
Net options premiums received during the period(1) (271)
Changes attributable to market movements of contracts outstanding
at March 31, 2002 176
----------
FAIR VALUE OF CONTRACTS OUTSTANDING AT MARCH 31, 2002 $ 2,520
Recognized Gains included in the fair value of contracts
outstanding at March 31, 2002
expected to be realized during the period (243)
Initial recorded value of new contracts entered into during
the period 22
Net options premiums paid during the period(1) 23
Changes attributable to market movements of contracts outstanding
at June 30, 2002 (145)
----------
FAIR VALUE OF CONTRACTS OUTSTANDING AT JUNE 30, 2002 $ 2,177
Recognized Gains included in the fair value of contracts
outstanding at June 30, 2002
expected to be realized during the period (169)
Initial recorded value of new contracts entered into during
the period 1
Changes in fair value attributable to changes in valuation
Techniques (20)
Net option premiums received during the period(1) (173)
Change attributable to market movements of contracts
Outstanding at September 30, 2002 (148)
----------
FAIR VALUE OF CONTRACTS OUTSTANDING AT SEPTEMBER 30, 2002 $ 1,668
</Table>
(1) Option premiums paid and received are included in the fair value of
contracts outstanding during any given period as they are a portion of the
overall energy trading portfolio. Option premiums paid result in an initial
increase in the fair value of contracts outstanding and a decrease in cash;
premiums received result in an initial decrease in the fair value of
contracts outstanding and an increase in cash. The underlying value of the
options associated with the premium payments are also included in the fair
value of contracts outstanding.
47
Management's Discussion & Analysis (Continued)
48
Management's Discussion & Analysis (Continued)
The charts below reflect the fair value of energy risk management and trading
contracts for Energy Marketing & Trading and the Natural Gas Liquids trading
operations (reported in the Midstream Gas & Liquids segment) by valuation
methodology and the year in which the recorded fair value is expected to be
realized. It should be noted that EITF Issue No. 02-03, which must be adopted no
later than periods beginning after December 15, 2002, may have a significant
impact on fair values as reported below.
<Table>
<Caption>
TO BE TO BE TO BE TO BE TO BE
REALIZED IN REALIZED IN REALIZED IN REALIZED IN REALIZED IN
1-12 MONTHS IN 13-36 MONTHS MONTHS 37-60 MONTHS 61-120 121+ MONTHS TOTAL FAIR
VALUATION TECHNIQUE (YEAR 1) (YEARS 2-3) (YEARS 4-5) (YEARS 6-10) (YEARS 11+) VALUE
- ------------------- ----------- --------------- ------------ ------------- ----------- ----------
BASED UPON QUOTED 12/31/2001 $ 757 $ 316 $ 345 $ 363 $ 18 $ 1,799
PRICES IN ACTIVE
MARKETS AND QUOTED 3/31/2002 $ 875 $ 337 $ 379 $ 435 $ (5) $ 2,021
PRICES & OTHER
EXTERNAL FACTORS 6/30/2002 $ 625 $ 396 $ 383 $ 391 $ 4 $ 1,799
IN LESS LIQUID
MARKETS(1) 9/30/2002 $ 195 $ 345 $ 276 $ 269 $ (1) $ 1,084
---------- ---------- ---------- ---------- ---------- ----------
BASED UPON MODELS 12/31/2001 $ 231 $ 12 $ (19) $ 50 $ 188 $ 462
& OTHER VALUATION
TECHNIQUES(2) 3/31/2002 $ 53 $ 30 $ -- $ 125 $ 291 $ 499
6/30/2002 $ 143 $ (111) $ (33) $ 112 $ 267 $ 378
9/30/2002 $ (97) $ (58) $ 50 $ 295 $ 394 $ 584
---------- ---------- ---------- ---------- ---------- ----------
12/31/2001 $ 988 $ 328 $ 326 $ 413 $ 206 $ 2,261
3/31/2002 $ 928 $ 367 $ 379 $ 560 $ 286 $ 2,520
6/30/2002 $ 768 $ 285 $ 350 $ 503 $ 271 $ 2,177
9/30/2002 $ 98 $ 287 $ 327 $ 564 $ 392 $ 1,668
---------- ---------- ---------- ---------- ---------- ----------
TOTAL
1Q CHANGE $ (60) $ 39 $ 53 $ 147 $ 80 $ 259
2Q CHANGE $ (160) $ (82) $ (29) $ (57) $ (15) $ (343)
3Q CHANGE $ (670) $ 2 $ (23) $ 61 $ 121 $ (509)
YTD CHANGE $ (890) $ (41) $ 1 $ 151 $ 186 $ (593)
---------- ---------- ---------- ---------- ---------- ----------
</Table>
(1) A significant portion of the value expected to be realized relates to a
contract within the California power market. The original terms of this
agreement provide for the sale of power at prices ranging from $62.50 to
$87.00 per megawatt hour over a ten-year period at variable volumes up
to 1,400 megawatts per hour. On November 11, 2002, Williams executed a
Settlement Agreement with California. The Settlement includes a
renegotiated long-term energy contract with the State of California. The
renegotiated contract provides for the sale of power at prices ranging
from $62.50 to $87.00 per megawatt hour through 2010 at varying volumes
up to 1,875 megawatts per hour. The value to be realized set forth above
does not reflect the revised terms of the contract with the State of
California.
(2) Quoted market prices of the underlying commodities are significant
factors in estimating the fair value.
Energy Marketing & Trading manages the risk assumed from providing energy
risk management services to its customers. This risk resulted from exposure to
energy commodity prices, volatility and correlation of commodity prices, the
portfolio position of the contracts, liquidity of the market in which the
contract is transacted, interest rates, and counterparty performance and credit.
Energy Marketing & Trading seeks to diversify its portfolio in managing the
commodity price risk in the transactions that it executes in various markets and
regions by executing offsetting contracts to manage the commodity price risk in
accordance with parameters established in its trading policy. As noted
previously, during the third quarter of 2002, Energy Marketing & Trading was
significantly constrained in its ability to manage or hedge its portfolio
against adverse market movements according to the aforementioned methodology due
49
Management's Discussion & Analysis (Continued)
to a lack of market liquidity, the market's concerns regarding Williams credit
and liquidity, and internal efforts to preserve liquidity.
In response to factors such as recent downgrades by credit rating agencies to
below-investment grade and difficulties in obtaining financing facilities, the
Company announced a significant reduction in its financial commitment to the
Energy Marketing & Trading segment. As a result the Company is evaluating
opportunities to sell or liquidate Energy Marketing & Trading's trading
portfolio or to form a joint venture around the Energy Marketing & Trading unit
with another party. As a result of this decision, the ultimate realization of
the estimated fair value of Energy Marketing & Trading's portfolio under this
strategy may vary from the amount of the Company's estimate at September 30,
2002.
FINANCIAL CONDITION AND LIQUIDITY
LIQUIDITY
Williams' liquidity comes from both internal and external sources. Certain of
those sources are available to Williams (parent) and others are available to
certain of its subsidiaries. Williams' sources of liquidity consist primarily of
the following:
o Available cash-equivalent investments of $980.5 million at September
30, 2002, as compared to $1.1 billion at December 31, 2001.
o $660 million available under Williams' revolving bank-credit
facility at September 30, 2002, as compared to $700 million at
December 31, 2001. As discussed in Note 11, the borrowing capacity
under this facility will reduce as assets are sold.
o $61 million at September 30, 2002 under a new $400 million secured
short-term letter of credit facility obtained in the third-quarter
2002.
o Cash generated from operations and the future sales of certain
assets.
In April 2002, Williams filed a shelf registration statement with the
Securities and Exchange Commission to enable it to issue up to $3 billion of a
variety of debt and equity securities. This registration statement was declared
effective June 26, 2002. Because of Williams' debt rating and loan covenants, it
is unlikely that Williams would be able to issue securities under the shelf
registration statement in the near term.
In addition, there are outstanding registration statements filed with the
Securities and Exchange Commission for Northwest Pipeline, Texas Gas
Transmission and Transcontinental Gas Pipe Line (each a wholly owned subsidiary
of Williams). As of November 13, 2002 approximately $450 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.
Capital and investment expenditures for 2002 are estimated to total
approximately $2.2 billion. Williams expects to fund capital and investment
expenditures, debt payments and working-capital requirements through (1) cash
generated from operations, (2) the use of the available portion of Williams'
$660 million, and/or (3) the sale or disposal of assets.
As discussed in Note 11, Williams Production RMT Company (RMT), a wholly
owned subsidiary, entered into a $900 million Credit Agreement dated as of July
31, 2002, with certain lenders including a subsidiary of Lehman Brothers, Inc.,
a related party to Williams. The loan is guaranteed by Williams, Williams
Production Holdings LLC (Holdings) and certain RMT subsidiaries. It is also
secured by the capital stock and assets of Holdings and certain of RMT's
subsidiaries. The assets of RMT are comprised primarily of the assets of the
former Barrett Resources Corporation acquired in 2001, which were primarily
natural gas properties in the Rocky Mountain region. The loan matures on July
25, 2003. RMT must be sold within 75 days of a parent liquidity event which will
arise if Williams fails to maintain actual and projected liquidity (a) at any
time from the closing date through the 180th day thereafter (January 27, 2003),
of $600 million; (b) at any time thereafter through and including the maturity
date, of $750 million; and (c) only projected liquidity for twelve months after
the maturity date, of $200 million. Liquidity projections must be provided
weekly until the maturity date.
Outlook
Based on the Company's forecast of cash flows and liquidity, Williams
believes that it has the financial resources and liquidity to meet future cash
requirements and satisfy current lending covenants for the balance of the year.
Included in this forecast are expected proceeds totaling approximately $780
million from the sale of assets, approximately $550 million is expected to close
in the fourth-quarter pursuant to definitive agreements and the remainder is
expected to close in the fourth quarter upon further negotiations.
Including periods through first-quarter 2004, the Company has scheduled debt
retirements of approximately $4.1 billion and anticipates significant additional
asset sales to meet its liquidity needs over that period. Realization of the
proceeds from forecasted asset sales is a significant factor for the Company to
satisfy its loan covenant regarding minimum levels of parent liquidity.
50
Management's Discussion & Analysis (Continued)
Credit Ratings
At December 31, 2001, Williams maintained certain preferred interest and debt
obligations that contained provisions requiring payment of the related
obligation or liquidation of the related assets in the event of specified
declines in Williams' senior unsecured long-term credit ratings given by Moody's
Investor's Service, Standard & Poor's and Fitch Ratings (rating agencies).
Obligations subject to these "ratings triggers" totaled $816 million at December
31, 2001. During the first quarter of 2002, Williams negotiated changes to
certain of the agreements, which eliminated the exposure to the "ratings
trigger" clauses incorporated in the agreements. Negotiations for one of the
agreements resulted in Williams agreeing to redeem a $560 million preferred
interest over the next year in equal quarterly installments (see Note 13). The
obligations subject to "ratings triggers" were reduced to $182 million at March
31, 2002. As a result of the credit rating downgrades in July 2002, Williams
redeemed $135 million of preferred interests on August 1, 2002 and repaid a $47
million loan in August 2002.
Williams' energy risk management and trading business also relied upon the
investment-grade rating of Williams' senior unsecured long-term debt to satisfy
credit support requirements of many counterparties. As a result of the credit
rating downgrades to below investment grade levels, Energy Marketing & Trading's
participation in energy risk management and trading activities requires
alternate credit support under certain existing agreements. In addition,
Williams is required to fund margin requirements pursuant to industry standard
derivative agreements with cash, letters of credit or other negotiable
instruments. For October 1, 2002 through November 11, 2002, Williams has
provided approximately $341 million in cash to various counterparties, including
prepayments for crude oil for the refineries and margin requirements. Williams
continues to negotiate with various counterparties on the types and amounts of
credit support that may be required pursuant to adequate assurance and similar
provisions in existing agreements. The amount of credit support ultimately
required under these agreements may be significant.
Off-Balance Sheet Financing Arrangements and Guarantees of Debt or Other
Commitments to Third Parties
As disclosed in Williams' Current Report on Form 8-K dated May 28, 2002,
Williams had operating lease agreements with special purpose entities (SPE's).
The lease agreements relate to certain Williams travel center stores, offshore
oil and gas pipelines and an onshore gas processing plant. As a result of
changes to the agreements in conjunction with the secured financing facilities
completed in July 2002, the agreements no longer qualify for operating lease
treatment. These operating leases were recorded as a capitalized lease beginning
in July 2002.
Williams had agreements to sell, on an ongoing basis, certain of its accounts
receivable to qualified special-purpose entities. On July 25, 2002, these
agreements expired and were not renewed.
WCG and significant events since December 31, 2001 regarding WCG
At December 31, 2001, Williams had financial exposure from WCG of $375
million of receivables and $2.21 billion of guarantees and payment obligations.
Williams determined it was probable it would not fully realize the $375 million
of receivables, and it would be required to perform under its $2.21 billion of
guarantees and payment obligations. Williams developed an estimated range of
loss related to its total WCG exposure and management believed that no loss
within that range was more probable than another. For 2001, Williams recorded
the $2.05 billion minimum amount of the range of loss from its financial
exposure to WCG, which was reported in the Consolidated Statement of Operations
as a $1.84 billion pre-tax charge to discontinued operations and a $213 million
pre-tax charge to continuing operations. The charge to discontinued operations
of $1.84 billion included a $1.77 billion minimum amount of the estimated range
of loss from performance on $2.21 billion of guarantees and payment obligations.
The charge to continuing operations of $213 million included estimated losses
from an assessment of the recoverability of the carrying amounts of the $375
million of receivables and a remaining $25 million investment in WCG common
stock.
Williams, prior to the spinoff of WCG, provided indirect credit support for
$1.4 billion of WCG's Note Trust Notes. On March 5, 2002, Williams received the
requisite approvals on its consent solicitation to amend the terms of the WCG
Note Trust Notes. The amendment, among other things, eliminated provisions that
would have caused acceleration of the WCG Note Trust Notes as a result of a WCG
bankruptcy or a Williams credit rating downgrade. The amendment also affirmed
51
Management's Discussion & Analysis (Continued)
Williams' obligation for all payments due with respect to the WCG Note Trust
Notes, which mature in March 2004, and allows Williams to fund such payments
from any available sources. In July 2002, Williams acquired substantially all of
the WCG Note Trust Notes by exchanging $1.4 billion of Williams Senior Unsecured
9.25 percent Notes due March 2004. In November 2002, Williams acquired the
remaining WCG Note Trust Notes.
Williams also provided a guarantee of WCG's obligations under a 1998
transaction in which WCG entered into a lease agreement covering a portion of
its fiber-optic network. WCG had an option to purchase the covered network
assets during the lease term at an amount approximating the lessor's cost of
$750 million. On March 8, 2002, WCG exercised its option to purchase the covered
network assets. On March 29, 2002, Williams funded the purchase price of $754
million and became entitled to an unsecured note from WCG for the same amount.
Williams has also provided guarantees on certain other performance
obligations of WCG totaling approximately $57 million.
2002 Evaluation
At September 30, 2002, Williams had receivables and claims from WCG of $2.15
billion arising from Williams affirming its payment obligation on the $1.4
billion of WCG Note Trust Notes and Williams paying $754 million under the WCG
lease agreement. At September 30, 2002, Williams also had $334 million of
previously existing receivables. In third-quarter 2002, Williams recorded in
continuing operations a pre-tax charge of $22.9 million related to WCG,
including an assessment of the recoverability of its receivables and claims from
WCG. For the nine months ended September 30, 2002, Williams has recorded in
continuing operations pre-tax charges of $269.9 million related to the recovery
of these receivables and claims. At September 30, 2002, Williams estimates that
approximately $2.2 billion of the $2.5 billion of receivables from WCG are not
recoverable.
See Note 4 for further discussion of Williams' estimate of recoverability
including terms of the Settlement Agreement between Williams, WCG, the Official
Committee of Unsecured Creditors and Leucadia National Corporation.
OPERATING ACTIVITIES
In March 2002, WCG exercised its option to purchase certain network assets
under an operating lease agreement for which Williams provided a guarantee of
WCG's obligations. On March 29, 2002, Williams, as guarantor under the
agreement, paid $754 million related to WCG's purchase of these network assets.
In return, Williams became entitled to receive an instrument of unsecured debt
from WCG in the same amount. Williams recorded an additional pre-tax charge of
$232 million, $15 million, and $22.9 million in first, second, and third-quarter
2002, respectively, related to its assessment of the recoverability of certain
receivables from WCG (see Note 4).
During 2002, Williams was required to provide cash collateral in support of
surety bonds underwritten by an insurance company and provide cash collateral in
support of letters of credit due to downgrades by credit rating agencies.
During 2002, Williams has recorded a total of approximately $574 million in
provisions for losses on property and other assets. Those provisions consisted
primarily of the impairments at Petroleum Services, a partial impairment of
goodwill at Energy Marketing & Trading and writedowns of investments.
During second-quarter 2002, Williams made a $55 million contribution to its
pension plan. Due to the decline of the stock market in 2002, the plan assets
have decreased from the values at year end. See the Other section.
FINANCING ACTIVITIES
On January 14, 2002, Williams completed the sale of 44 million publicly
traded units, more commonly known as FELINE PACS, that each include a senior
debt security and an equity purchase contract. The $1.1 billion of debt has a
term of five years, and the equity purchase contract will require the Company to
deliver Williams common stock to holders after three years based on a previously
agreed rate. Net proceeds from this issuance were approximately $1.1 billion.
The FELINE PACS were issued as part of Williams' plan to strengthen its balance
sheet and maintain its investment-grade rating.
On March 19, 2002, Williams issued $850 million of 30-year notes with an
interest rate of 8.75 percent and $650 million of 10-year notes with an interest
rate of 8.125 percent. The proceeds were used to repay outstanding
52
Management's Discussion & Analysis (Continued)
commercial paper, provide working capital and for general corporate purposes.
In April 2002, Williams Energy Partners L.P., a partially owned and
consolidated entity of Williams, borrowed $700 million from a group of
institutions. These proceeds were primarily used to acquire Williams Pipe Line,
a formerly wholly owned subsidiary of Williams. In May 2002, Williams Energy
Partners L.P. issued approximately 8 million common units at $37.15 per unit
resulting in approximately $283 million of net proceeds that were used to reduce
the $700 million loan. Williams Energy Partners L.P. will refinance the
September 30, 2002 balance of $411 million in short-term debt with long-term
debt financing (see Note 11).
In May 2002, Energy Marketing & Trading entered into an agreement which
transferred the rights to certain receivables, along with risks associated with
that collection, in exchange for cash. Due to the structure of the agreement,
Energy Marketing & Trading accounted for this transaction as debt collateralized
by the claims. The $79 million of debt is classified as current.
As discussed in Note 11 and under the "Liquidity" heading of management's
discussion and analysis, RMT entered into a $900 million credit agreement dated
as of July 31, 2002.
On March 27, 2002, concurrent with its sale of Kern River to MEHC, Williams
issued approximately 1.5 million shares of 9.875 percent cumulative convertible
preferred stock for $275 million. Dividends on the preferred stock are payable
quarterly (see Note 14).
In July 2002, Williams reduced the quarterly dividend on common stock from
$.20 per share to $.01 per share. Additionally, one of the new covenants within
the 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 was 69.6 percent at
September 30, 2002 (excluding Central debt), compared to 59.0 percent at
December 31, 2001 (excluding Kern River, Central, Mid America Pipeline, and
Seminole Pipeline debt). If short-term notes payable and long-term debt due
within one year are included in the calculations, these ratios would be 73.1
percent at September 30, 2002 and 64.8 percent at December 31, 2001.
Additionally, the long-term debt to debt-plus-equity ratio as calculated for
covenants under certain debt agreements, as amended, was 65.8 percent at
September 30, 2002.
INVESTING ACTIVITIES
Williams has contributed approximately $215 million towards the development
of the Gulfstream joint venture project, a Williams equity investment, during
2002.
Net cash proceeds from asset dispositions, the sales of businesses and
investments include the following:
o $1.16 billion related to the sale of Mid-American and Seminole
Pipeline on August 1, 2002.
o $464 million related to the sale of Kern River on March 27, 2002.
o $326 million from the sale of Jonah Field and Anadarko Basin
properties on August 1, 2002.
o $217 million related to the sale of the Cove Point LNG Facility on
September 5, 2002.
o $85 million related to the sale of Williams' 27 percent interest in
the Lithuanian refinery, pipeline and terminal complex on September
19, 2002.
o $75 million related to the sale of a note receivable from the
Lithuanian refinery, pipeline and terminal complex.
o $77 million related to the sale of Kansas Hugoton on August 2, 2002.
o $12 million from the sale of Williams' interest in Northern Border
Partners on August 16, 2002.
COMMITMENTS
The table below summarizes the maturity or redemption by year of the notes
payable, long-term debt and preferred interests in consolidated subsidiaries
outstanding at September 30, 2002 by period. These amounts do not reflect debt
reductions contingent upon asset sales (see Note 11)
<Table>
<Caption>
October 1 -
December 31
2002 2003 2004 2005 2006 Thereafter Total
----------- -------- -------- -------- -------- -------- --------
Notes payable $ -- $ 929(1) $ -- $ -- $ -- $ -- $ 929
Long-term debt,
including current portion 685 1,075 2,991(2) 402 1,042(3) 7,492 13,687
</Table>
(1) An additional $240 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% notes, payable 2007, subject to
remarketing in 2004.
(3) Includes $400 million of 6.75% notes, payable 2016, putable/callable in
2006.
53
Management's Discussion & Analysis (Continued)
OTHER
If lump sum payments made during 2002 from the pension plan reach the
settlement accounting threshold, Williams would be required to recognize certain
unrecognized net losses that would increase pension expense. Williams
anticipates that the threshold will be reached in the fourth quarter of 2002
resulting in an additional expense charge of $25 million to $35 million. In
addition, on January 1, 2002, the market value of plan assets exceeded the
accumulated benefit obligation (calculated using a discount rate of 7.5
percent). Through September 30, 2002, the assets in the defined benefit pension
plans have experienced negative returns. If, at December 31, 2002, the market
value of each plan's assets are less than the respective plan's accumulated
benefit obligation, Williams may be required to make additional cash
contributions to the plan during the fourth quarter such that the market value
of plan assets would exceed the accumulated benefit obligation at December 31,
2002, in order to avoid recording an additional charge to stockholders' equity.
54
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 new debt issuances in first and third-quarter 2002. In January 2002,
Williams issued $1.1 billion of 6.5 percent notes payable 2007 (see Note 11). In
February 2002, $240 million of 6.125 percent notes were retired. In March 2002,
Williams issued $850 million of 8.75 percent notes due 2032 and $650 million of
8.125 percent notes due 2012. Also in March 2002, the terms of a $560 million
priority return structure classified as preferred interest in consolidated
subsidiaries were amended. Based on the new payment terms of the amendment, the
remaining balance due has been reclassified from preferred interests in
consolidated subsidiaries to long-term debt due within one year (see Note 13).
The interest rate varies based on LIBOR plus an applicable margin and was 2.803
percent at September 30, 2002. Through September 30, 2002, $224 million has been
redeemed.
Pursuant to the completion of a consent solicitation during first-quarter
2002 with WCG Note Trust holders, Williams recorded $1.4 billion of long-term
debt obligations. In July 2002, Williams acquired substantially all of the WCG
Note Trust notes by exchanging $1.4 billion of Williams Senior Unsecured 9.25
percent notes due March 2004 (see Note 4). In November 2002, Williams acquired
the remaining WCG Note Trust Notes. In July 2002, Transcontinental Gas Pipe Line
issued $325 million of 8.875 percent long-term debt obligations due 2012 and
Williams obtained a $900 million secured short-term loan. The $900 million
borrowing accrues interest at a 14 percent interest rate plus a variable rate,
which is currently 5.81 percent.
COMMODITY PRICE RISK
At September 30, 2002, the value at risk for the Energy Marketing & Trading
operations and the natural gas liquids trading operations (now reported in the
Midstream Gas & Liquids segment) was $48.9 million compared to $74.5 million at
June 30, 2002. This decline in value at risk is primarily a result of the $509
million decline in overall portfolio value outlined in previous sections. 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
trading portfolio. The value-at-risk model includes all financial instruments
and physical positions and commitments in its trading portfolio and assumes that
as a result of changes in commodity prices, there is a 95 percent probability,
but not certainty, that the one-day loss in fair value of the trading 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 energy risk management and trading 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 is 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.
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 and 15d-14 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.
55
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
The information called for by this item is provided in Note 12 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 2. Changes in Securities and Use of Proceeds
Pursuant to the terms of the new credit facilities entered into on July 31,
2002, Williams is restricted from declaring and paying dividends in any quarter
the aggregate amount of which would be greater than $6.25 million. This
restriction does not limit Williams' ability to declare and pay dividends on
preferred stock issued prior to July 31, 2002, nor does it limit the ability of
Williams Energy Partners L.P. to make distributions to its unit holders
pursuant to the terms of its partnership agreement.
The terms of the 9.875 percent cumulative convertible preferred stock issued to
MEHC (see Note 14) prohibit Williams from declaring and paying dividends on its
common stock or any other parity preferred stock if dividends on the 9.875
percent cumulative convertible preferred stock are in arrears. Dividends on all
parity preferred stock not paid in full must be paid pro rata.
Item 6. Exhibits and Reports on Form 8-K
(a) The exhibits listed below are filed as part of this report:
Exhibit 10.1 -- Amendment No. 1 dated as of October 31, 2002 to
Credit Agreement dated as of July 31, 2002 among The Williams
Companies, Inc., Williams Production Holdings LLC, Williams
Production RMT Company, as Borrower, the Several Lenders from time
to time parties thereto, Lehman Brothers Inc., as Lead Arranger
and Book Manager, and Lehman Commercial Paper Inc., as Syndication
Agent and Administrative Agent, and Guarantee and Collateral
Agreement made by The Williams Companies, Inc., Williams
Production Holdings LLC, Williams Production RMT Company and
certain of its Subsidiaries in favor of Lehman Commercial Paper
Inc., as Administrative Agent, dated as of July 31, 2002.
Exhibit 10.2 -- First Amended and Restated Credit Agreement dated
as of October 31, 2002 among The Williams Companies, Inc.,
Northwest Pipeline Corporation, Transcontinental Gas Pipe Line
Corporation and Texas Gas Transmission Corporation, as Borrowers,
the Banks named therein, JPMorgan Chase Bank and Commerzbank AG,
as Co-Syndication Agents, Credit Lyonnais New York Branch, as
Documentation Agent, Citicorp USA, Inc., as Agent, and Salomon
Smith Barney Inc., as Arranger.
Exhibit 10.3 -- Amended and Restated Credit Agreement dated as of
October 31, 2002 among The Williams Companies, Inc., as Borrower,
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, the Banks named
therein, as Banks, and Salomon Smith Barney Inc., as Arranger.
Exhibit 10.4 -- First Amendment dated as of October 31, 2002 to
Security Agreement dated as of July 31, 2002 among The Williams
Companies, Inc. and each of the Subsidiaries which is or
subsequently becomes a party to the Security Agreement in favor of
Citibank, N.A., as collateral trustee for the benefit of the
holders of the Secured Obligations.
Exhibit 10.5 -- First Amendment dated as of October 31, 2002 to
Pledge Agreement dated as of July 31, 2002 among The Williams
Companies, Inc. and each of the Subsidiaries which is or
subsequently becomes a party to the Pledge Agreement in favor of
Citibank, N.A., as collateral trustee for the benefit of the
holders of the Secured Obligations.
Exhibit 10.6 -- First Amendment dated as of October 31, 2002 to
Guaranty dated as of July 31, 2002 by Williams Gas Pipeline
Company, L.L.C. in favor of the Financial Institutions as defined
therein.
Exhibit 10.7 -- First Amendment dated as of October 31, 2002 to
Collateral Trust Agreement dated as of July 31, 2002 among The
Williams Companies, Inc. and certain of its Subsidiaries, as
Debtors, and Citibank, N.A., as Collateral Trustee.
Exhibit 10.8 -- First Amendment to Guaranty by Midstream Entities
dated as of October 31, 2002 to Guaranty dated as of July 31, 2002
by certain Midstream Subsidiaries, as defined therein, in favor of
Citibank, N.A., as surety administrative agent for the holders of
the Secured Obligations.
56
Part II. Other Information (continued)
Exhibit 10.9 -- Amended and Restated Subordinated Guaranty dated
as of October 31, 2002 by Williams Production Holdings LLC in
favor of the Financial Institutions as defined therein.
Exhibit 10.10 -- First Amended and Restated Term Loan Agreement
dated as of October 31, 2002 among The Williams Companies, Inc.,
as Borrower, Credit Lyonnais New York Branch, as Administrative
Agent, Commerzbank AG New York and Grand Cayman Branches, as
Syndication Agent, The Bank of Nova Scotia, as Documentation
Agent, and the Lenders named therein.
Exhibit 10.11 -- Settlement and Retention Agreement dated August
7, 2002, between The Williams Companies, Inc. and William G. von
Glahn
Exhibit 10.12 -- Form of Change in Control Severance Agreement
between the Company and certain executive officers.
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 Jack D. McCarthy, Chief Financial Officer of The Williams
Companies, Inc.
(b) During third-quarter 2002, Williams filed a Form 8-K on the
following dates reporting events under the specified items: July
3, 2002 Items 5 and 7; July 12, 2002 Items 5 and 7; July 23, 2002
Item 9; July 26, 2002 Item 9; July 29, 2002 Item 9; July 31, 2002
Item 9; August 6, 2002 Item 9; August 14, 2002 Item 9; August 15,
2002 Item 9; August 21, 2002 Item 9; September 6, 2002 Item 9;
September 17, 2002 Item 9; and September 24, 2002 Item 9 (filed
two Form 8-K's on this date).
57
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)
November 14, 2002
CERTIFICATION
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.
/s/ STEVEN J. MALCOLM
Date: November 14, 2002 -------------------------------------
Steven J. Malcolm
President and Chief Executive Officer
I, Jack D. McCarthy, 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: November 14, 2002 /s/ JACK D. MCCARTHY
-------------------------------
Jack D. McCarthy
Senior Vice President - Finance
and Chief Financial Officer
EXHIBIT INDEX
<Table>
<Caption>
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
Exhibit 10.1 -- Amendment No. 1 dated as of October 31, 2002 to Credit
Agreement dated as of July 31, 2002 among The Williams
Companies, Inc., Williams Production Holdings LLC, Williams
Production RMT Company, as Borrower, the Several Lenders from
time to time parties thereto, Lehman Brothers Inc., as Lead
Arranger and Book Manager, and Lehman Commercial Paper Inc., as
Syndication Agent and Administrative Agent, and Guarantee and
Collateral Agreement made by The Williams Companies, Inc.,
Williams Production Holdings LLC, Williams Production RMT
Company and certain of its Subsidiaries in favor of Lehman
Commercial Paper Inc., as Administrative Agent, dated as of
July 31, 2002.
Exhibit 10.2 -- First Amended and Restated Credit Agreement dated as of October
31, 2002 among The Williams Companies, Inc., Northwest Pipeline
Corporation, Transcontinental Gas Pipe Line Corporation and
Texas Gas Transmission Corporation, as Borrowers, the Banks
named therein, JPMorgan Chase Bank and Commerzbank AG, as
Co-Syndication Agents, Credit Lyonnais New York Branch, as
Documentation Agent, Citicorp USA, Inc., as Agent, and Salomon
Smith Barney Inc., as Arranger.
Exhibit 10.3 -- Amended and Restated Credit Agreement dated as of October 31,
2002 among The Williams Companies, Inc., as Borrower, 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, the Banks named
therein, as Banks, and Salomon Smith Barney Inc., as Arranger.
Exhibit 10.4 -- First Amendment dated as of October 31, 2002 to Security
Agreement dated as of July 31, 2002 among The Williams
Companies, Inc. and each of the Subsidiaries which is or
subsequently becomes a party to the Security Agreement in favor
of Citibank, N.A., as collateral trustee for the benefit of the
holders of the Secured Obligations.
Exhibit 10.5 -- First Amendment dated as of October 31, 2002 to Pledge
Agreement dated as of July 31, 2002 among The Williams
Companies, Inc. and each of the Subsidiaries which is or
subsequently becomes a party to the Pledge Agreement in favor
of Citibank, N.A., as collateral trustee for the benefit of the
holders of the Secured Obligations.
Exhibit 10.6 -- First Amendment dated as of October 31, 2002 to Guaranty dated
as of July 31, 2002 by Williams Gas Pipeline Company, L.L.C. in
favor of the Financial Institutions as defined therein.
Exhibit 10.7 -- First Amendment dated as of October 31, 2002 to Collateral
Trust Agreement dated as of July 31, 2002 among The Williams
Companies, Inc. and certain of its Subsidiaries, as Debtors,
and Citibank, N.A., as Collateral Trustee.
Exhibit 10.8 -- First Amendment to Guaranty by Midstream Entities dated as of
October 31, 2002 to Guaranty dated as of July 31, 2002 by
certain Midstream Subsidiaries, as defined therein, in favor of
Citibank, N.A., as surety administrative agent for the holders
of the Secured Obligations.
Exhibit 10.9 -- Amended and Restated Subordinated Guaranty dated as of October
31, 2002 by Williams Production Holdings LLC in favor of the
Financial Institutions as defined therein.
Exhibit 10.10 -- First Amended and Restated Term Loan Agreement dated as of
October 31, 2002 among The Williams Companies, Inc., as
Borrower, Credit Lyonnais New York Branch, as Administrative
Agent, Commerzbank AG New York and Grand Cayman Branches, as
Syndication Agent, The Bank of Nova Scotia, as Documentation
Agent, and the Lenders named therein.
Exhibit 10.11 -- Settlement and Retention Agreement dated August 7, 2002,
between The Williams Companies, Inc. and William G. von Glahn
Exhibit 10.12 -- Form of Change in Control Severance Agreement between the
Company and certain executive officers.
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
Jack D. McCarthy, Chief Financial Officer of The Williams
Companies, Inc.
</Table>