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, 2001
--------------------------------------------------
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, 2001
- --------------------------------------- ------------------------------------
Common Stock, $1 par value 515,362,257 Shares
The Williams Companies, Inc.
Index
<Table>
<Caption>
Page
----
Part I. Financial Information
Item 1. Financial Statements
Consolidated Statement of Income--Three and Nine Months Ended September 30, 2001 and 2000 2
Consolidated Balance Sheet--September 30, 2001 and December 31, 2000 3
Consolidated Statement of Cash Flows--Nine Months Ended September 30, 2001 and 2000 4
Notes to Consolidated Financial Statements 5
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations 20
Item 3. Quantitative and Qualitative Disclosures about Market Risk 31
Part II. Other Information 32
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 2000 Form
8-K dated May 22, 2001.
1
The Williams Companies, Inc.
Consolidated Statement of Income
(Unaudited)
<Table>
<Caption>
Three months Nine months
(Dollars in millions, except per-share amounts) ended September 30, ended September 30,
----------------------------- -----------------------------
2001 2000* 2001 2000*
------------ ------------ ------------ ------------
Revenues:
Energy Marketing & Trading $ 524.2 $ 288.5 $ 1,586.6 $ 898.5
Gas Pipeline 432.8 437.4 1,316.9 1,410.7
Energy Services 1,992.6 1,696.1 6,365.1 4,585.1
Other 17.9 17.0 57.0 50.3
Intercompany eliminations (157.1) (109.6) (606.6) (366.2)
------------ ------------ ------------ ------------
Total revenues 2,810.4 2,329.4 8,719.0 6,578.4
------------ ------------ ------------ ------------
Segment costs and expenses:
Costs and operating expenses 1,807.9 1,667.3 5,826.8 4,466.7
Selling, general and administrative expenses 243.7 178.6 666.0 571.9
Other (income) expense-net 23.1 11.3 (54.7) 27.0
------------ ------------ ------------ ------------
Total segment costs and expenses 2,074.7 1,857.2 6,438.1 5,065.6
------------ ------------ ------------ ------------
General corporate expenses 32.4 18.7 88.8 65.8
------------ ------------ ------------ ------------
Operating income:
Energy Marketing & Trading 380.5 147.1 1,138.2 497.5
Gas Pipeline 137.7 153.4 548.7 565.9
Energy Services 215.9 168.4 583.5 439.8
Other 1.6 3.3 10.5 9.6
General corporate expenses (32.4) (18.7) (88.8) (65.8)
------------ ------------ ------------ ------------
Total operating income 703.3 453.5 2,192.1 1,447.0
Interest accrued (194.1) (182.3) (555.1) (508.1)
Interest capitalized 12.4 15.2 33.3 39.0
Investing income (loss) (84.2) 21.0 (25.4) 59.1
Minority interest in income and preferred returns
of consolidated subsidiaries (20.4) (13.5) (65.0) (40.5)
Other income (expense)-net 2.0 (5.0) 13.5 .6
------------ ------------ ------------ ------------
Income from continuing operations before income taxes 419.0 288.9 1,593.4 997.1
Provision for income taxes 197.7 112.4 654.3 395.3
------------ ------------ ------------ ------------
Income from continuing operations 221.3 176.5 939.1 601.8
Loss from discontinued operations -- (55.4) (179.1) (29.2)
------------ ------------ ------------ ------------
Net income $ 221.3 $ 121.1 $ 760.0 $ 572.6
============ ============ ============ ============
Basic earnings per common share:
Income from continuing operations $ .44 $ .39 $ 1.92 $ 1.36
Loss from discontinued operations -- (.12) (.37) (.07)
------------ ------------ ------------ ------------
Net income $ .44 $ .27 $ 1.55 $ 1.29
============ ============ ============ ============
Average shares (thousands) 502,877 445,066 489,813 443,914
Diluted earnings per common share:
Income from continuing operations $ .44 $ .39 $ 1.91 $ 1.35
Loss from discontinued operations -- (.12) (.37) (.07)
------------ ------------ ------------ ------------
Net income $ .44 $ .27 $ 1.54 $ 1.28
============ ============ ============ ============
Average shares (thousands) 506,165 450,294 493,812 449,010
Cash dividends per common share $ .18 $ .15 $ .48 $ .45
</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,
2001 2000
-------------- --------------
ASSETS
Current assets:
Cash and cash equivalents $ 413.9 $ 996.8
Accounts and notes receivable less allowance of $25.3 ($9.8 in 2000) 4,189.6 3,357.3
Inventories 861.6 848.4
Energy trading assets 6,259.4 7,879.8
Deferred income taxes -- 64.9
Margin deposits 307.9 730.9
Other 544.3 319.3
-------------- --------------
Total current assets 12,576.7 14,197.4
Net assets of discontinued operations -- 2,290.2
Investments 1,586.3 1,368.6
Property, plant and equipment, at cost 22,754.7 19,028.8
Less accumulated depreciation and depletion (5,057.5) (4,589.5)
-------------- --------------
17,697.2 14,439.3
Goodwill and other intangible assets, net 1,142.4 42.5
Energy trading assets 3,808.9 1,831.1
Other assets and deferred charges 1,401.6 746.5
-------------- --------------
Total assets $ 38,213.1 $ 34,915.6
============== ==============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Notes payable $ 719.9 $ 2,036.7
Accounts payable 3,371.4 3,088.0
Accrued liabilities 2,249.1 1,560.4
Deferred income taxes 162.7 --
Energy trading liabilities 5,258.7 7,597.3
Long-term debt due within one year 1,736.5 1,634.1
-------------- --------------
Total current liabilities 13,498.3 15,916.5
Long-term debt 8,821.4 6,830.5
Deferred income taxes 3,826.8 2,863.9
Energy trading liabilities 2,569.6 1,302.8
Other liabilities and deferred income 967.0 944.0
Contingent liabilities and commitments (Note 12)
Minority and preferred interests in consolidated subsidiaries 1,075.0 976.0
Williams obligated mandatorily redeemable preferred securities of
Trust holding only Williams indentures -- 189.9
Stockholders' equity:
Preferred stock, $1 per share par value, 30 million shares authorized -- --
Common stock, $1 per share par value, 960 million shares authorized, 518.4 million
issued in 2001, 447.9 million issued in 2000 518.4 447.9
Capital in excess of par value 4,901.1 2,473.9
Retained earnings 1,763.8 3,065.7
Accumulated other comprehensive income 377.2 28.2
Other (65.8) (81.2)
-------------- --------------
7,494.7 5,934.5
Less treasury stock (at cost), 3.4 million shares of common stock in 2001
and 3.6 million in 2000 (39.7) (42.5)
-------------- --------------
Total stockholders' equity 7,455.0 5,892.0
-------------- --------------
Total liabilities and stockholders' equity $ 38,213.1 $ 34,915.6
============== ==============
</Table>
See accompanying notes.
3
The Williams Companies, Inc.
Consolidated Statement of Cash Flows
(Unaudited)
<Table>
<Caption>
(Millions) Nine months ended September 30,
-------------------------------
2001 2000*
------------ ------------
OPERATING ACTIVITIES:
Income from continuing operations $ 939.1 $ 601.8
Adjustments to reconcile to cash provided by operations:
Depreciation, depletion and amortization 562.2 475.5
Provision for deferred income taxes 389.9 245.4
Provision for loss on property and other assets 117.8 16.4
Net gain on dispositions of assets (88.9) (15.6)
Minority interest in income and preferred returns of
consolidated subsidiaries 65.0 40.5
Tax benefit of stock-based awards 26.3 22.4
Cash provided (used) by changes in assets and liabilities:
Accounts and notes receivable (785.7) (430.6)
Inventories (8.2) (312.0)
Margin deposits 423.0 (58.9)
Other current assets (31.4) (48.1)
Accounts payable 165.9 510.9
Accrued liabilities 509.0 (20.1)
Changes in current energy trading assets and liabilities (783.2) (342.8)
Changes in non-current energy trading assets and liabilities (711.1) (291.2)
Other, including changes in non-current assets and liabilities 52.3 93.3
------------ ------------
Net cash provided by operating activities 842.0 486.9
------------ ------------
FINANCING ACTIVITIES:
Proceeds from notes payable 1,830.0 1,126.0
Payments of notes payable (3,925.7) (150.6)
Proceeds from long-term debt 4,013.8 900.0
Payments of long-term debt (1,440.2) (732.0)
Proceeds from issuance of common stock 1,397.2 65.4
Dividends paid (237.9) (199.1)
Proceeds from sale of limited partner units of consolidated partnership 92.5 --
Payment of Williams obligated mandatorily redeemable preferred
securities of Trust holding only Williams indentures (194.0) --
Other--net (134.5) (2.3)
------------ ------------
Net cash provided by financing activities 1,401.2 1,007.4
------------ ------------
INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures (1,307.4) (1,102.4)
Proceeds from dispositions 30.6 25.0
Changes in accounts payable and accrued liabilities 8.3 (14.1)
Acquisition of business, net of cash acquired (1,321.8) (147.8)
Purchases of investments/advances to affiliates (417.8) (129.7)
Proceeds from disposition of investments and other assets 406.1 20.2
Purchase of assets subsequently leased to seller (276.0) --
Other--net 32.2 17.1
------------ ------------
Net cash used by investing activities (2,845.8) (1,331.7)
------------ ------------
DISCONTINUED OPERATIONS:
Net cash provided by operating activities 7.6 23.6
Net cash provided by financing activities 1,343.4 1,775.0
Net cash used by investing activities (1,448.7) (2,027.7)
Cash of discontinued operations at spinoff (96.5) --
------------ ------------
Net cash used by discontinued operations (194.2) (229.1)
------------ ------------
Decrease in cash and cash equivalents (796.8) (66.5)
Cash and cash equivalents at beginning of period** 1,210.7 1,081.6
------------ ------------
Cash and cash equivalents at end of period** $ 413.9 $ 1,015.1
============ ============
</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 $213.9
million, $483.9 million and $162.5 million at December 31, 2000 and 1999
and September 30, 2000, respectively.
See accompanying notes.
4
The Williams Companies, Inc.
Notes to Consolidated Financial Statements
(Unaudited)
1. General
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 22, 2001. The accompanying financial statements have not been audited
by independent auditors, but include all normal recurring adjustments and
others, which, in the opinion of Williams' management, are necessary to present
fairly its financial position at September 30, 2001, its results of operations
for the three and nine months ended September 30, 2001 and 2000, and cash flows
for the nine months ended September 30, 2001 and 2000.
Segment profit of operating companies may vary by quarter. Based on current
rate structures and/or historical maintenance schedules of certain of its
pipelines, Gas Pipeline generally experiences lower segment profits in the
second and third quarters as compared to the first and fourth quarters.
While the amounts recorded in the Consolidated Balance Sheet related to
certain receivables from California power sales reflect management's best
estimate of collectibility, future events or circumstances could change those
estimates either positively or negatively.
2. Basis of presentation
Effective September 2001, the Energy Marketing & Trading segment is
presented as Williams' third industry group joining Gas Pipeline and Energy
Services. Energy Marketing & Trading was previously reported as an operating
segment within the Energy Services industry group.
As a result of the April 23, 2001, tax-free spinoff of Williams
Communications Group, Inc. (WCG), WCG has been accounted for as discontinued
operations and, accordingly, the accompanying consolidated financial statements
and notes have been restated to reflect the results of operations, net assets
and cash flows of WCG as discontinued operations. Unless indicated otherwise,
the information in the Notes to Consolidated Financial Statements relates to the
continuing operations of Williams (see Note 7).
During first-quarter 2001, Williams Energy Partners L.P. (WEP) completed an
initial public offering. WEP, including Williams' general partnership interest,
is now reported as a separate segment within Energy Services and consists
primarily of certain terminals and an ammonia pipeline previously reported
within Petroleum Services and Midstream Gas & Liquids, respectively. Also during
first-quarter 2001, management of international activities, previously reported
in Other, was transferred and the international activities are now reported as a
separate segment within Energy Services.
Effective February 2001, management of certain operations, previously
conducted by Energy Marketing & Trading, was transferred to Petroleum Services.
These operations included the procurement of crude oil and marketing of refined
products produced from the Memphis refinery for which prior year segment
information has been restated to reflect the transfer. Additionally, the refined
product sales activities surrounding certain terminals located throughout the
United States were transferred. This sales activity was previously included in
the trading portfolio of Energy Marketing & Trading and was therefore reported
net of related costs of sales. Following the transfer, these sales are reported
on a "gross" basis.
Prior year segment information has been restated to reflect the above
mentioned changes.
Certain other income statement, balance sheet and cash flow amounts have
been reclassified to conform to the current classifications.
3. Asset sales, impairments and other accruals
Included in other (income) expense-net within segment costs and expenses and
Petroleum Services' segment profit for the nine months ended September 30, 2001,
is a pre-tax gain of $72.1 million from the sale of certain convenience stores.
Included in other (income) expense-net within segment costs and expenses and
Gas Pipeline's segment profit for the nine months ended September 30, 2001, is a
pre-tax gain of $27.5 million for the sale of Williams' limited partnership
interest in Northern Border Partners, L.P. Williams retained a general
partnership interest.
Included in other (income) expense-net within segment costs and expenses and
Energy Marketing & Trading's segment profit for the nine months ended September
30, 2000, are guarantee loss accruals and impairments of $30.3 million. The
impairment charges result from the decision to discontinue mezzanine lending
services, and the accruals represent the estimated liabilities associated with
guarantees of third-party lending activities.
5
Notes (Continued)
4. Investing income (loss)
In accordance with certain accounting guidelines governing the valuation of
investments, including publicly traded marketable equity securities, Williams
recognized a $94.2 million charge in third-quarter 2001. This charge represents
declines in the value of certain investments, including $70.9 million related to
Williams' investment in WCG, which were determined to be other than temporary.
This determination was primarily based on the continued depressed market values
of these investments and the overall market value decline experienced by related
industry sectors. The $94.2 million charge is included in investing income
(loss) and is reflected in net income with no associated tax benefit.
Approximately $23.3 million of the write-down is also included in Energy
Marketing & Trading's segment profit for the three and nine months ended
September 30, 2001.
5. Barrett acquisition
Through a series of transactions, Williams acquired all of the outstanding
stock of Barrett Resources Corporation (Barrett). On June 11, 2001, Williams
acquired 50 percent of Barrett's outstanding common stock in a cash tender offer
of $73 per share for a total of approximately $1.2 billion. Williams acquired
the remaining 50 percent of Barrett's outstanding common stock on August 2,
2001, through a merger by exchanging each remaining share of Barrett common
stock for 1.767 shares of Williams common stock for a total of approximately 30
million shares of Williams common stock valued at $1.2 billion. The value of the
30 million shares of Williams common stock was based on the average market price
of Williams common stock for the 2 days before and after the May 7, 2001
announcement of the terms of the acquisition. This acquisition has been
accounted for as a purchase business combination with a purchase price,
including transaction fees and other related costs, of approximately $2.5
billion, excluding $312 million of debt obligations of Barrett. The allocation
of the purchase price is preliminary; however, it is not expected to materially
change.
Williams' 50 percent share of Barrett's results of operations for the period
June 11, 2001 to August 1, 2001, as well as amortization of the excess of
Williams' investment over the underlying equity in Barrett's net assets for that
period, is included in equity earnings within Exploration & Production's
revenues and segment profit in the Consolidated Statement of Income. Beginning
August 2, 2001, 100 percent of Barrett's results of operations are included in
Exploration & Production's revenues and segment profit in the Consolidated
Statement of Income.
Barrett is an independent natural gas and oil exploration and production
company with producing properties located principally in the Rocky Mountain and
Mid-Continent regions of the United States. As of August 2, 2001, Barrett's
estimated proved gas and oil reserves were 1.9 trillion cubic feet of gas
equivalents. Barrett's assets include long-lived reserves that offer opportunity
for long-term and steady growth and align strategically with Williams' other
assets in those regions. Williams is a major gatherer and processor in the
Rockies and has natural gas pipelines and gas liquids pipelines that move
product out of the Rockies. In addition, these new gas reserves help to balance
the risk profile of Williams' growing power portfolio by providing a physical
and natural hedge against a short natural gas position.
The following unaudited pro forma information combines the results of
operations of Williams and Barrett as if the purchase of 100 percent of Barrett
occurred January 1, 2000.
<Table>
<Caption>
Three Nine
(Millions, except per-share months ended months ended
amounts) September 30, September 30,
----------------------- -----------------------
2001 2000 2001 2000
---------- ---------- ---------- ----------
Unaudited
Revenues $ 2,853.0 $ 2,424.3 $ 9,085.0 $ 6,792.5
Income from continuing
operations $ 228.6 $ 179.5 $ 1,020.8 $ 573.2
Net income $ 228.6 $ 124.1 $ 841.7 $ 544.0
Basic earnings per common share:
Income from continuing
operations $ .44 $ .38 $ 1.98 $ 1.21
Net income $ .44 $ .26 $ 1.64 $ 1.15
Diluted earnings per common share:
Income from continuing
operations $ .44 $ .37 $ 1.97 $ 1.20
Net income $ .44 $ .26 $ 1.62 $ 1.14
========== ========== ========== ==========
</Table>
Pro forma financial information is not necessarily indicative of results of
operations that would have occurred if the acquisition had occurred on January
1, 2000, or of future results of operations of the combined companies.
6
Notes (Continued)
6. Provision for income taxes
The provision (benefit) for income taxes includes:
<Table>
<Caption>
Three months ended Nine months ended
(Millions) September 30, September 30,
----------------------- -----------------------
2001 2000 2001 2000
---------- ---------- ---------- ----------
Current:
Federal $ 25.4 $ 23.6 $ 219.4 $ 118.7
State .8 10.2 35.9 28.7
Foreign 2.8 3.4 9.1 2.5
---------- ---------- ---------- ----------
29.0 37.2 264.4 149.9
Deferred:
Federal 142.2 77.6 345.3 218.7
State 20.7 6.1 36.6 47.8
Foreign 5.8 (8.5) 8.0 (21.1)
---------- ---------- ---------- ----------
168.7 75.2 389.9 245.4
---------- ---------- ---------- ----------
Total provision $ 197.7 $ 112.4 $ 654.3 $ 395.3
========== ========== ========== ==========
</Table>
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.
The effective income tax rate for the three and nine months ended September
30, 2000, is greater than the federal statutory rate due primarily to the effect
of state income taxes.
7. Discontinued operations
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, to holders of
record on April 9 of Williams common stock. Distribution of .822399 of a share
of WCG common stock for each share of Williams common stock occurred on April
23, 2001. The distribution was recorded as a dividend and resulted in a decrease
to stockholders' equity of approximately $1.8 billion, which included an
increase to accumulated other comprehensive income of approximately $21.3
million. The WCG shares retained by Williams are included in investments in the
Consolidated Balance Sheet. In third-quarter 2001, Williams recognized a $70.9
million loss related to the write-down of this investment due to the decline in
value which was determined to be other than temporary (see Note 4).
Additionally, receivables include amounts due from WCG of approximately $120
million at September 30, 2001. Williams has extended the payment term of up to
$100 million of the outstanding balance which was due March 31, 2001 to March
15, 2002.
Williams is providing indirect credit support for $1.4 billion of WCG's
structured notes through a commitment to make available proceeds of a Williams
equity issuance in the event any one of the following were to occur: (1) a WCG
default; (2) downgrading of Williams' senior unsecured debt to Ba1 or below by
Moody's, BB or below by S&P, or BB+ or below by Fitch, if Williams' common stock
closing price is below $30.22 for ten consecutive trading days while such
downgrade is in effect; or (3) to the extent proceeds from WCG's refinancing or
remarketing of certain structured notes prior to March 2004 produces proceeds of
less than $1.4 billion. The ability of WCG to make payments on the notes is
dependent on its ability to raise additional capital and its subsidiaries'
ability to dividend cash to WCG. Williams' current senior unsecured debt ratings
are as follows: Moody's-Baa2, S&P-BBB and Fitch-BBB. WCG is obligated to
reimburse Williams for any payment Williams is required to make in connection
with these notes.
Williams has provided a guarantee of WCG's obligations under a 1998
transaction in which WCG entered into an operating lease agreement covering a
portion of its fiber-optic network. The total cost of the network assets covered
by the lease agreement is $750 million. The lease terms initially totaled five
years and, if renewed, could extend to seven years. WCG has an option to
purchase the covered network assets during the lease term at an amount
approximating lessor's cost. As a result of an agreement between Williams and
WCG's revolving credit facility lenders, if Williams gains control of the
network assets covered by the lease, Williams is obligated to return the assets
to WCG and the liability of WCG to compensate Williams for such property must be
subordinated to the interests of WCG's revolving credit facility lenders and
may not mature any earlier than one year after the maturity of WCG's revolving
credit facility.
In third-quarter 2001, Williams purchased the WCG headquarters building and
other ancillary assets from WCG for $276 million. Williams then entered into a
long-term lease arrangement under which WCG is the sole lessee of these assets.
As a result of this transaction, Williams' Consolidated Balance Sheet includes
$28 million in accounts and notes receivable and $248 million in other assets
and deferred charges relating to amounts due from WCG.
Williams has received an initial private letter ruling from the Internal
Revenue Service (IRS) stating that the distribution of WCG common stock would be
tax-free to Williams and its stockholders. Although private letter rulings are
generally binding on the IRS, Williams' will not be able to rely on this ruling
if any of the factual representations or assumptions that were made to obtain
the ruling are, or become, incorrect or untrue in any material respect. However,
Williams is not aware of any facts or circumstances that would cause any of the
7
Notes (Continued)
representations or assumptions to be incorrect or untrue in any material
respect. The distribution could also become taxable to Williams, but not
Williams shareholders, under the Internal Revenue Code (IRC) in the event that
Williams' or WCG's business combinations were deemed to be part of a plan
contemplated at the time of distribution and would constitute a total cumulative
change of more than 50 percent of the equity interest in either company.
Williams, with respect to shares of WCG's common stock that Williams
retained, has committed to the IRS to dispose of all of the WCG common stock
that it retains as soon as market conditions allow, but in any event not longer
than five years after the spinoff. As part of a separation agreement, and
subject to an additional favorable ruling by the IRS that such a limitation is
not inconsistent with any ruling issued to Williams regarding the tax-free
treatment of the spinoff, Williams has agreed not to dispose of the retained WCG
shares for three years from the date of distribution and must notify WCG of an
intent to dispose of such shares.
Summarized results of discontinued operations are as follows:
<Table>
<Caption>
Nine
Period Three months
ending months ended ended
(Millions) April 23, September 30, September 30,
-------------- -------------- --------------
2001 2000 2000
-------------- -------------- --------------
Revenues $ 329.5 $ 206.7 $ 542.3
Loss from operations:
Loss before
income taxes (271.3) (104.9) (28.5)
Benefit for
income taxes 92.2 49.5 20.9
Cumulative effect of
change in accounting
principle -- -- (21.6)
-------------- -------------- --------------
Total loss from
discontinued
operations $ (179.1) $ (55.4) $ (29.2)
============== ============== ==============
</Table>
8. Earnings per share
Basic and diluted earnings per common share are computed as follows:
<Table>
<Caption>
(Dollars in millions, except Three Nine
per-share amounts; shares months ended months ended
in thousands) September 30, September 30,
--------------------------- ---------------------------
2001 2000 2001 2000
------------ ------------ ------------ ------------
Income from continuing
operations for basic
and diluted earnings
per share $ 221.3 $ 176.5 $ 939.1 $ 601.8
============ ============ ============ ============
Basic weighted-average
shares 502,877 445,066 489,813 443,914
Effect of dilutive securities:
Stock options 3,288 5,228 3,999 5,096
------------ ------------ ------------ ------------
Diluted weighted-average
shares 506,165 450,294 493,812 449,010
============ ============ ============ ============
Earnings per common share
from continuing
operations:
Basic $ .44 $ .39 $ 1.92 $ 1.36
Diluted $ .44 $ .39 $ 1.91 $ 1.35
============ ============ ============ ============
</Table>
9. Inventories
<Table>
<Caption>
September 30, December 31,
(Millions) 2001 2000
-------------- --------------
Raw materials:
Crude oil $ 104.3 $ 70.0
Other 1.5 1.6
-------------- --------------
105.8 71.6
Finished goods:
Refined products 265.6 269.6
Natural gas liquids 194.3 200.2
General merchandise 10.8 12.5
-------------- --------------
470.7 482.3
Materials and supplies 136.1 122.9
Natural gas in underground storage 147.4 169.0
Other 1.6 2.6
-------------- --------------
$ 861.6 $ 848.4
============== ==============
</Table>
10. Debt and banking arrangements
Notes payable
During 2001, Williams increased its commercial paper program to $2.2
billion, backed by a short-term bank-credit facility. At September 30, 2001, $70
million of commercial paper was outstanding under the program. Interest rates
vary with current market conditions.
In June 2001, Williams entered into a $200 million (amended in July to $300
million) short-term debt obligation expiring January 2002. The interest rate
varies based on LIBOR plus .875 percent and was 3.5 percent at September 30,
2001.
In July 2001, Williams issued $300 million in floating rate notes due July
2002. The interest rate varies based on LIBOR plus .875 percent and was 4.6
percent at September 30, 2001.
8
Notes (Continued)
Debt
<Table>
<Caption>
Weighted-
average
interest September 30, December 31,
(Millions) rate* 2001 2000
-------------- -------------- --------------
Revolving credit loans 4.7% $ 187.4 $ 350.0
Debentures, 6.25%-10.25%,
payable 2003-2031 7.4 1,591.2 1,103.5
Notes, 5.1%-9.45%,
payable through 2031(1) 7.2 7,358.8 4,856.8
Notes, adjustable rate,
payable through 2004 4.3 1,355.3 2,080.4
Other, payable through 2016 7.3 65.2 73.9
-------------- --------------
10,557.9 8,464.6
Current portion of long-term debt (1,736.5) (1,634.1)
-------------- --------------
$ 8,821.4 $ 6,830.5
============== ==============
</Table>
* At September 30, 2001.
(1) $240 million, 6.125% notes, payable 2012, are subject to redemption at par
at the option of the debtholder in 2002 and $400 million of 6.75% notes,
payable 2016, putable/callable in 2006.
Under the terms of Williams' $700 million revolving credit agreement,
Northwest Pipeline, Transcontinental Gas Pipe Line and Texas Gas Transmission
have access to varying amounts of the facility, while Williams (parent) has
access to all unborrowed amounts. Interest rates vary with current market
conditions. Additionally, certain Williams subsidiaries have revolving credit
facilities with a total capacity of $102 million at September 30, 2001.
In January 2001, Williams issued $1.1 billion in debt obligations consisting
of $700 million of 7.5 percent debentures due 2031 and $400 million of 6.75
percent Putable Asset Term Securities due 2016, putable/callable in 2006.
In June 2001, Williams issued $480 million of 7.75 percent notes due 2031.
In August 2001, Williams issued $1.5 billion in debt obligations consisting
of $750 million of 7.125 percent notes due 2011 and $750 million of 7.875
percent notes due 2021. A portion of the proceeds was used to repay $1.2 billion
outstanding under a short-term credit agreement entered into for the cash
portion of the Barrett acquisition (see Note 5).
In August 2001, Transcontinental Gas Pipe Line issued $300 million of 7
percent notes due 2011, and Kern River Gas Transmission issued $510 million of
6.676 percent senior notes due 2016.
In connection with the Barrett acquisition (see Note 5), Williams' September
30, 2001 Consolidated Balance Sheet includes $310 million of debt obligations of
Barrett. Barrett's debt obligations include $150 million of 7.55 percent notes
due 2007, which are guaranteed by Williams, and $155 million of debt obligations
under Barrett's revolving credit agreement maturing December 2001. Interest
rates on the revolving credit agreement vary with market conditions.
11. Derivative instruments and hedging activities
On January 1, 2001, Williams adopted Statement of Financial Accounting
Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging
Activities," as amended by SFAS No. 138, "Accounting for Certain Derivative
Instruments and Certain Hedging Activities."
This standard requires that all derivative financial instruments be recorded
on the balance sheet at their fair value. Changes in the fair value of
derivatives will be recorded each period in earnings if the derivative is not a
hedge. If a derivative is a hedge, changes in the fair value of the derivative
will either be recognized in earnings, along with the change in the fair value
of the hedged asset, liability or firm commitment also recognized in earnings,
or recognized in other comprehensive income until the hedged item is recognized
in earnings. For a derivative recognized in other comprehensive income, the
ineffective portion of the derivative's change in fair value will be recognized
immediately in earnings.
At adoption, Williams recorded a cumulative effect of an accounting change
associated with the adoption of SFAS No. 133 to record all derivatives at fair
value. The cumulative effect of the accounting change was not material to net
income, but resulted in a $95 million reduction of other comprehensive income
(net of income tax benefits of $59 million) related to derivatives which hedge
the variable cash flows of certain forecasted commodity transactions. Of the
transition adjustment recorded in other comprehensive income at January 1, 2001,
net losses of approximately $90 million (net of income tax benefits of $56
million) will be reclassified into earnings during 2001 (including approximately
$12 million and $78 million of net after-tax losses reclassified for the three
and nine months ended September 30, 2001, respectively) offsetting net gains
expected to be realized in earnings from favorable market movements associated
with the underlying transactions being hedged.
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 $50
million for potential refund as of September 30, 2001.
9
Notes (Continued)
In 1997, the Federal Energy Regulatory Commission (FERC) issued orders
addressing, among other things, the authorized rates of return for three of
Williams' interstate natural gas pipeline subsidiaries. All of the orders
involve rate cases that became effective between 1993 and 1995 and, in each
instance, these cases were superseded by more recently filed rate cases. In the
three orders, the FERC continued its practice of utilizing a methodology for
calculating rates of return that incorporates a long-term growth rate component.
However, the long-term growth rate component used by the FERC is now a
projection of U.S. gross domestic product growth rates. Generally, calculating
rates of return utilizing a methodology which includes a long-term growth rate
component results in rates of return that are lower than they would be if the
long-term growth rate component were not included in the methodology. Each of
the three pipeline subsidiaries challenged its respective FERC order in an
effort to have the FERC change its rate-of-return methodology with respect to
these and other rate cases. On January 30, 1998, the FERC convened a public
conference to consider, on an industry-wide basis, issues with respect to
pipeline rates of return. In July 1998, the FERC issued orders in two of the
three pipeline subsidiary rate cases, again modifying its rate-of-return
methodology by adopting a formula that gives less weight to the long-term growth
component. Certain parties appealed the FERC's action, because the most recent
formula modification results in somewhat higher rates of return compared to the
rates of return calculated under the FERC's prior formula. The appeals have been
denied. Similarly, in July 2001, the Court of Appeals denied a petition for
review, attaching the application of the weighting of the growth factors to a
still pending rate proceeding involving a Williams interstate pipeline. In June
and July 1999, the FERC applied the new methodology in the third pipeline
subsidiary rate case, as well as in a fourth case involving the same pipeline
subsidiary. In March 2000, the FERC applied the new methodology in a fifth case
involving a Williams interstate pipeline subsidiary, and certain parties sought
rehearing before the FERC in this proceeding. In January 2001, the FERC denied
the rehearing requests in this proceeding.
As a result of FERC Order 636 decisions in prior years, each of the natural
gas pipeline subsidiaries has undertaken the reformation or termination of its
respective gas supply contracts. None of the pipelines has any significant
pending supplier take-or-pay, ratable take or minimum take claims.
Williams 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, it 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
the FERC, 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.
However, in its FERC filings, Williams continues its objections to refunds in
any amount.
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, back to May 1, 2000, and possibly
earlier. Although Williams believes these requests are ill-founded and will be
rejected by the FERC, there can be no assurance of such action.
In an order issued June 19, 2001, the FERC has 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 will be in effect from June
20, 2001 through September 30, 2002, establishes a market clearing price for
spot sales in all hours of the day that is based on the bid of the highest-cost
gas-fired California generating unit that is needed to serve the California
Independent System Operator's load. When generation operating reserves fall
below 7 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 is the market clearing price. When generation
operating reserves rise to 7 percent or above in California, absent cost-based
justification for a higher price, Williams' maximum price will be limited to 85
percent of the highest hourly price that was in effect during the most recent
reserve deficiency period. The June 19 order also implemented multi-party
settlement talks
10
Notes (Continued)
regarding refunds for past periods that concluded without resolution of the
issues. Absent settlement, the presiding administrative law judge issued a
report to the FERC that, with some variations, recommends applying the
methodology of the June 19 order to determine refunds for prior periods. On July
25, 2001, the FERC issued an order adopting, to a significant extent, the
Judge's recommendation and establishing an expedited hearing to establish the
facts necessary to determine refunds under the approved methodology. Refunds
under this order 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.
On March 14, 2001, the FERC issued a Show Cause Order directing Williams
Energy Marketing & Trading Company 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 California
Independent System Operator 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
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. If adopted, these new standards would require the adoption
of new compliance measures by certain Williams subsidiaries.
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,
2001, these subsidiaries had accrued liabilities totaling approximately $33
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 (PCB) 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, 2001, Central
had accrued a liability for approximately $9 million, representing 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 $33 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
11
Notes (Continued)
factors. Texas Gas, Transcontinental Gas Pipe Line and Central have deferred
these costs as incurred pending recovery through future rates and other means.
In July 1999, Transcontinental Gas Pipe Line received a letter stating that
the U.S. Department of Justice (DOJ), at the request of the EPA, intends to file
a civil action against Transcontinental Gas Pipe Line arising from its waste
management practices at Transcontinental Gas Pipe Line's compressor stations and
metering stations in 11 states from Texas to New Jersey. The DOJ stated in the
letter that its complaint will seek civil penalties and injunctive relief under
federal environmental laws. The DOJ offered to discuss settlement of the claims,
and discussions began in September 1999 and have continued throughout 2000 and
into 2001. However, Transcontinental Gas Pipe Line believes it has substantially
addressed environmental concerns on its system through ongoing voluntary
remediation and management programs.
Williams Energy Services (WES) 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,
WES owns a discontinued petroleum refining facility that is being evaluated for
potential remediation efforts. At September 30, 2001, WES and its subsidiaries
had accrued liabilities totaling approximately $42 million. WES accrues
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, 2001, WES
and its subsidiaries had accrued receivables totaling $2 million.
Williams Field Services (WFS), a WES subsidiary, received a Notice of
Violation (NOV) from the EPA in February 2000. WFS received a contemporaneous
letter from the DOJ indicating that the DOJ will also be involved in the matter.
The NOV alleged violations of the Clean Air Act at a gas processing plant. WFS,
the EPA and the DOJ agreed to settle this matter for a penalty of $850,000. In
the course of investigating this matter, WFS discovered a similar potential
violation at the plant and disclosed it to the EPA and the DOJ. The EPA is
currently evaluating the violation and is expected to propose a monetary
penalty.
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, 2001, Williams had
approximately $11 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 July 1, 1998 through July 2, 2001.
Williams is in the process of responding to the request.
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 three
lawsuits brought by producers. In one of the cases, 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
September 30, 2001, post-judgement interest was approximately $9.7 million.
Transcontinental Gas Pipe Line's appeals have been 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 which is pending. In the other cases,
producers have asserted damages, including interest calculated through September
30, 2001, of $9.5 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 Order 528.
On June 8, 2001, 14 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. The Williams entities will join
12
Notes (Continued)
other defendants in filing at least two dispositive motions, along with
contesting class certification in the next several months. In September 2001,
the plaintiffs voluntarily dismissed two of the 14 Williams entities named as
defendants in the lawsuit.
In 1998, the United States Department of Justice 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 including Central, Kern River Gas
Transmission, Northwest Pipeline, Williams Gas Pipeline Company,
Transcontinental Gas Pipe Line Corporation, Texas Gas, Williams Field Services
Company and Williams Production Company. Mr. 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 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 United States Department of Justice
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 the ones filed against Williams, to the United States District
Court for the District of Wyoming for pre-trial purposes. Motions to dismiss the
complaints filed by various defendants, including Williams, were denied on May
18, 2001.
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 believes that WCG's installation of the
cable containing the single fiber network that crosses over or near the putative
class members' land does not infringe on their property rights. Williams also
does not believe that the plaintiffs have sufficient basis for certification of
a class action. It is likely that Williams will be subject to other putative
class action suits challenging WCG's railroad or pipeline rights of way.
However, Williams has a claim for indemnity from WCG for damages resulting from
or arising out of the businesses or operations conducted or formerly conducted
or assets owned or formerly owned by any subsidiary of WCG.
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 Williams Energy Marketing & Trading Company, 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.
The defendants removed these cases to federal district courts. The
multi-district litigation panel consolidated the cases in the Southern District
of California before Judge Whaley. Judge Whaley subsequently ruled in favor of
the plaintiffs in their petitions to remand and the cases are now pending in San
Diego and San Francisco Superior Courts.
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 including Williams
Energy Marketing & Trading and fourteen executive officers, including 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.
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. 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.
13
Notes (Continued)
On October 5, 2001, 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.
On October 19, 2001, Williams settled a $42 million claim for coal royalty
payments relating to a discontinued activity by agreeing to pay $9.5 million.
In addition to the foregoing, various other proceedings are pending against
Williams or its subsidiaries which are incidental to their operations.
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
Williams the right to receive fuel conversion services as well as certain other
services associated with electric generation facilities that are either
currently in operation or are to be constructed at various locations throughout
the continental United States. At September 30, 2001, annual estimated committed
payments under these contracts range from approximately $20 million to $462
million, resulting in total committed payments over the next 21 years of
approximately $8 billion.
13. Williams obligated mandatorily redeemable preferred securities
On April 6, 2001, an affiliate of Ferrellgas Partners, L.P. (Ferrellgas)
purchased the Ferrellgas Partners L.P. senior common units from Williams for
$199.1 million. Williams recognized no gain or loss associated with this
transaction as the purchase price of the units sold approximated their carrying
value. The proceeds of this sale were used primarily to redeem the Williams
obligated mandatorily redeemable preferred securities of Trust holding only
Williams indentures.
14. Equity offering
In January 2001, Williams issued approximately 38 million shares of common
stock in a public offering at $36.125 per share. The impact of this issuance
resulted in increases of approximately $38 million to common stock and $1.3
billion to capital in excess of par value.
14
Notes (Continued)
15. Comprehensive income
Comprehensive income is as follows:
<Table>
<Caption>
Three Nine
months ended months ended
(Millions) September 30, September 30,
------------------------ ------------------------
2001 2000 2001 2000
---------- ---------- ---------- ----------
Net income $ 221.3 $ 121.1 $ 760.0 $ 572.6
Other comprehensive
income:
Unrealized gains (losses)
on securities (18.1) 272.3 (71.3) 635.8
Realized (gains) losses on
securities in net income 20.3 (40.2) (.4) (323.0)
Cumulative effect of a
change in accounting for
derivative instruments -- -- (153.4) --
Unrealized gains on derivative
instruments 408.5 -- 865.6 --
Net reclassification into
earnings of derivative
instrument gains (120.3) -- (74.6) --
Foreign currency
translation adjustments (11.6) (14.9) (36.0) (30.4)
---------- ---------- ---------- ----------
Other comprehensive
income before taxes
and minority interest 278.8 217.2 529.9 282.4
Income tax provision on
other comprehensive
income (112.1) (90.2) (212.2) (121.4)
Minority interest in other
comprehensive income -- (19.0) 10.0 (21.9)
---------- ---------- ---------- ----------
Other comprehensive income 166.7 108.0 327.7 139.1
---------- ---------- ---------- ----------
Comprehensive income $ 388.0 $ 229.1 $ 1,087.7 $ 711.7
========== ========== ========== ==========
</Table>
Components of other comprehensive income (loss) before minority interest and
taxes related to discontinued operations are as follows:
<Table>
<Caption>
Three Nine
months ended months ended
(Millions) September 30, September 30,
----------------------- ------------------------
2001 2000 2001 2000
---------- ---------- ---------- ----------
Unrealized gains (losses) on
securities $ -- $ 275.0 $ (56.2) $ 614.9
Realized gains on securities in
net income -- (40.2) (20.7) (323.0)
Foreign currency translation
adjustments -- (14.2) (22.1) (29.1)
---------- ---------- ---------- ----------
Other comprehensive income
(loss) before minority interest
and taxes related to discontinued
operations $ -- $ 220.6 $ (99.0) $ 262.8
========== ========== ========== ==========
</Table>
15
Notes (Continued)
16. Segment disclosures
Williams evaluates performance based upon segment profit (loss) from
operations which includes revenues from external and internal customers, equity
earnings (losses), operating costs and expenses, depreciation, depletion and
amortization and income (loss) from investments. Intersegment sales are
generally accounted for as if the sales were to unaffiliated third parties, that
is, at current market prices.
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.
The increase in Exploration & Production's total assets, as noted on page
18, is due primarily to the assets and preliminary purchase price allocation
related to the Barrett acquisition (see Note 5) and to the increased value of
hedge contracts on natural gas production.
The following table reflects the reconciliation of operating income as
reported in the Consolidated Statement of Income to segment profit (loss), per
the tables on pages 17 and 18:
<Table>
<Caption>
Three months ended September 30, 2001 Three months ended September 30, 2000
----------------------------------------- ---------------------------------------
Operating Loss from Segment Operating Loss from Segment
(Millions) Income Investments Profit Income Investments Profit
----------- ----------- ----------- ----------- ----------- -----------
Energy Marketing & Trading $ 380.5 $ (23.3) $ 357.2 $ 147.1 $ -- $ 147.1
Gas Pipeline 137.7 -- 137.7 153.4 -- 153.4
Energy Services 215.9 -- 215.9 168.4 -- 168.4
Other 1.6 -- 1.6 3.3 -- 3.3
----------- ----------- ----------- ----------- ----------- -----------
Total segments 735.7 $ (23.3) $ 712.4 472.2 $ -- $ 472.2
----------- ----------- ----------- ----------- ----------- -----------
General corporate
expenses (32.4) (18.7)
----------- -----------
Total operating
income $ 703.3 $ 453.5
=========== ===========
</Table>
<Table>
<Caption>
Nine months ended September 30, 2001 Nine months ended September 30, 2000
----------------------------------------- ---------------------------------------
Operating Loss from Segment Operating Loss from Segment
(Millions) Income Investments Profit Income Investments Profit
----------- ----------- ----------- ----------- ----------- -----------
Energy Marketing & Trading $ 1,138.2 $ (23.3) $ 1,114.9 $ 497.5 $ -- $ 497.5
Gas Pipeline 548.7 -- 548.7 565.9 -- 565.9
Energy Services 583.5 -- 583.5 439.8 -- 439.8
Other 10.5 -- 10.5 9.6 -- 9.6
----------- ----------- ----------- ----------- ----------- -----------
Total segments 2,280.9 $ (23.3) $ 2,257.6 1,512.8 $ -- $ 1,512.8
----------- ----------- ----------- ----------- ----------- -----------
General corporate
expenses (88.8) (65.8)
----------- -----------
Total operating
income $ 2,192.1 $ 1,447.0
=========== ===========
</Table>
16
Notes (Continued)
16. Segment disclosures (continued)
<Table>
<Caption>
Revenues
------------------------------------------------------------------
External Inter- Equity Earnings Segment
(Millions) Customers segment (Losses) Total Profit (Loss)
------------- ------------- --------------- ------------- -------------
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2001
ENERGY MARKETING & TRADING $ 705.1 $ (180.6)* $ (.3) $ 524.2 $ 357.2
GAS PIPELINE 408.5 12.4 11.9 432.8 137.7
ENERGY SERVICES
Exploration & Production 46.6 104.7 2.6 153.9 56.9
International 36.0 -- -- 36.0 7.8
Midstream Gas & Liquids 257.9 147.1 (1.6) 403.4 81.1
Petroleum Services 1,317.9 59.6 -- 1,377.5 66.1
Williams Energy Partners 17.6 4.2 -- 21.8 4.0
Merger-related costs and
non-compete amortization -- -- -- -- --
------------- ------------- --------------- ------------- -------------
TOTAL ENERGY SERVICES 1,676.0 315.6 1.0 1,992.6 215.9
------------- ------------- --------------- ------------- -------------
OTHER 8.2 9.7 -- 17.9 1.6
ELIMINATIONS -- (157.1) -- (157.1) --
------------- ------------- --------------- ------------- -------------
TOTAL $ 2,797.8 $ -- $ 12.6 $ 2,810.4 $ 712.4
============= ============= =============== ============= =============
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2000
ENERGY MARKETING & TRADING $ 475.2 $ (186.8)* $ .1 $ 288.5 $ 147.1
GAS PIPELINE 413.2 17.0 7.2 437.4 153.4
ENERGY SERVICES
Exploration & Production 4.9 62.1 -- 67.0 18.0
International 18.1 -- .6 18.7 4.2
Midstream Gas & Liquids 170.7 173.4 (1.0) 343.1 83.2
Petroleum Services 1,219.9 30.2 (.1) 1,250.0 60.2
Williams Energy Partners 13.0 4.3 -- 17.3 4.2
Merger-related costs and
non-compete amortization -- -- -- -- (1.4)
------------- ------------- --------------- ------------- -------------
TOTAL ENERGY SERVICES 1,426.6 270.0 (.5) 1,696.1 168.4
------------- ------------- --------------- ------------- -------------
OTHER 7.6 9.4 -- 17.0 3.3
ELIMINATIONS -- (109.6) -- (109.6) --
------------- ------------- --------------- ------------- -------------
TOTAL $ 2,322.6 $ -- $ 6.8 $ 2,329.4 $ 472.2
============= ============= =============== ============= =============
</Table>
* Energy Marketing & Trading intercompany cost of sales, which are netted in
revenues consistent with fair-value accounting, exceed intercompany revenue.
17
Notes (Continued)
16. Segment disclosures (continued)
<Table>
<Caption>
Revenues
-----------------------------------------------------------------------------
External Inter- Equity Earnings Segment
(Millions) Customers segment (Losses) Total Profit (Loss)
--------------- --------------- --------------- --------------- ---------------
FOR THE NINE MONTHS ENDED
SEPTEMBER 30, 2001
ENERGY MARKETING & TRADING $ 2,065.8 $ (480.6)* $ 1.4 $ 1,586.6 $ 1,114.9
GAS PIPELINE 1,257.0 29.8 30.1 1,316.9 548.7
ENERGY SERVICES
Exploration & Production 65.7 316.5 8.5 390.7 147.8
International 87.1 -- (1.1) 86.0 2.8
Midstream Gas & Liquids 1,027.9 467.6 (14.3) 1,481.2 159.7
Petroleum Services 4,111.5 231.8 .1 4,343.4 258.4
Williams Energy Partners 51.9 11.9 -- 63.8 16.3
Merger-related costs and
non-compete amortization -- -- -- -- (1.5)
--------------- --------------- --------------- --------------- ---------------
TOTAL ENERGY SERVICES 5,344.1 1,027.8 (6.8) 6,365.1 583.5
--------------- --------------- --------------- --------------- ---------------
OTHER 27.8 29.6 (.4) 57.0 10.5
ELIMINATIONS -- (606.6) -- (606.6) --
--------------- --------------- --------------- --------------- ---------------
TOTAL $ 8,694.7 $ -- $ 24.3 $ 8,719.0 $ 2,257.6
=============== =============== =============== =============== ===============
FOR THE NINE MONTHS ENDED
SEPTEMBER 30, 2000
ENERGY MARKETING & TRADING $ 1,378.6 $ (480.3)* $ .2 $ 898.5 $ 497.5
GAS PIPELINE 1,345.3 45.9 19.5 1,410.7 565.9
ENERGY SERVICES
Exploration & Production 29.3 165.2 - 194.5 39.4
International 51.1 - 1.1 52.2 9.2
Midstream Gas & Liquids 504.2 485.8 (.8) 989.2 236.8
Petroleum Services 3,189.5 107.4 (.3) 3,296.6 146.1
Williams Energy Partners 38.9 13.7 -- 52.6 13.9
Merger-related costs and
non-compete amortization -- -- -- -- (5.6)
--------------- --------------- --------------- --------------- ---------------
TOTAL ENERGY SERVICES 3,813.0 772.1 -- 4,585.1 439.8
--------------- --------------- --------------- --------------- ---------------
OTHER 21.8 28.5 -- 50.3 9.6
ELIMINATIONS -- (366.2) -- (366.2) --
--------------- --------------- --------------- --------------- ---------------
TOTAL $ 6,558.7 $ -- $ 19.7 $ 6,578.4 $ 1,512.8
=============== =============== =============== =============== ===============
</Table>
<Table>
<Caption>
TOTAL ASSETS
-------------------------------------
(Millions) September 30, 2001 December 31, 2000
------------------ -----------------
ENERGY MARKETING & TRADING $ 15,728.1 $ 14,609.7
GAS PIPELINE 9,199.7 8,956.2
ENERGY SERVICES
Exploration & Production 4,970.5 671.5
International 2,209.1 2,214.4
Midstream Gas & Liquids 4,425.5 4,293.5
Petroleum Services 2,974.2 2,666.5
Williams Energy Partners 366.4 349.8
--------------- ---------------
TOTAL ENERGY SERVICES 14,945.7 10,195.7
--------------- ---------------
OTHER 6,281.3 7,019.9
ELIMINATIONS (7,941.7) (8,156.1)
---------------- ----------------
38,213.1 32,625.4
NET ASSETS OF DISCONTINUED OPERATIONS -- 2,290.2
---------------- ----------------
TOTAL $ 38,213.1 $ 34,915.6
================ ================
</Table>
* Energy Marketing & Trading intercompany cost of sales, which are netted in
revenues consistent with fair-value accounting, exceed intercompany revenue.
18
Notes (Continued)
17. Recent accounting standards
In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No.
141, "Business Combinations" and SFAS No. 142, "Goodwill and Other Intangible
Assets." SFAS No. 141 establishes accounting and reporting standards for
business combinations and requires all business combinations to be accounted for
by the purchase method. The Statement is effective for all business combinations
initiated after June 30, 2001, and any business combinations accounted for using
the purchase method for which the date of acquisition is July 1, 2001, or later.
SFAS No. 142 addresses accounting and reporting standards for goodwill and other
intangible assets. Under this Statement, goodwill and intangible assets with
indefinite useful lives will no longer be amortized, but will be tested annually
for impairment. The Statement becomes effective for all fiscal years beginning
after December 15, 2001.
Williams will apply the new rules on accounting for goodwill and other
intangible assets beginning January 1, 2002. Application of the nonamortization
provisions of the Statement will not be material. During first-quarter 2002,
Williams will perform an initial impairment test of goodwill as of January 1,
2002. The effect of this test on the results of operations and financial
position of Williams has not been determined. The acquisition of Barrett
Resources was completed on August 2, 2001 (see Note 5). Approximately $1 billion
of goodwill recorded as a result of this acquisition is not being amortized.
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations." This Statement addresses financial accounting and reporting for
obligations associated with the retirement of tangible long-lived assets and the
associated asset retirement costs and amends FASB Statement No. 19, "Financial
Accounting and Reporting by Oil and Gas Producing Companies." The Statement
requires that the fair value of a liability for an asset retirement obligation
be recognized in the period in which it is incurred if a reasonable estimate of
fair value can be made, and that the associated asset retirement costs be
capitalized as part of the carrying amount of the long-lived asset. The
Statement is effective for financial statements issued for fiscal years
beginning after June 15, 2002. The effect of this standard on Williams' results
of operations and financial position is being evaluated.
In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment
or Disposal of Long-Lived Assets." This Statement supersedes SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed of" and amends 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 Statement retains the basic framework of SFAS No.
121, resolves certain implementation issues of SFAS No. 121, extends
applicability to discontinued operations, and broadens the presentation of
discontinued operations to include a component of an entity. The Statement will
be applied prospectively and is effective for financial statements issued for
fiscal years beginning after December 15, 2001. Adoption of the Statement is not
expected to have any initial impact on Williams' results of operations or
financial position.
19
ITEM 2
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATION
In March 2001, the board of directors of Williams approved a tax-free
spinoff of Williams' communications business, Williams Communications Group,
Inc. (WCG), to Williams' shareholders. On April 23, 2001, Williams distributed
398.5 million shares, or approximately 95 percent of the WCG common stock held
by Williams, to holders of record of Williams common stock. As a result, the
consolidated financial statements have been restated to present WCG as
discontinued operations (see Note 7 of Notes to Consolidated Financial
Statements). Unless otherwise indicated, 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.
RESULTS OF OPERATIONS
THIRD QUARTER 2001 VS. THIRD QUARTER 2000
OVERVIEW
Williams' revenues increased $481 million, or 21 percent, due primarily to
higher gas and electric power trading and services revenues, the $126 million
impact of reporting certain revenues net of the related costs in 2000 related to
sales activity surrounding certain terminals (see Note 2), revenues from
Canadian operations acquired in fourth-quarter 2000, higher petroleum products
revenues and the revenues of Barrett Resources Corporation (Barrett) acquired in
August 2001, partially offset by $122 million decrease in revenues related to
the convenience stores sold in May 2001.
Segment costs and expenses increased $217.5 million, or 12 percent, due
primarily to the impact of reporting certain sales activity costs net with
related revenues in 2000, higher costs associated with Canadian operations
acquired in fourth-quarter 2000, higher petroleum product costs, costs
associated with Barrett acquired in August 2001 and higher charitable
contribution commitments. These increases were partially offset by a $119
million decrease in costs related to the convenience stores sold in May 2001.
Operating income increased $249.8 million, or 55 percent, due primarily to
higher gas and electric power trading and services margins (including $164
million from the recognition of power sales made in previous 2001 quarters --
see Energy Marketing & Trading's third quarter discussion) and the impact of
Barrett, partially offset by charitable contribution commitments.
Income from continuing operations before income taxes increased $130.1
million from $288.9 million in 2000 to $419 million in 2001, due primarily to
$249.8 million higher operating income. These increases were partially offset by
a $105.2 million decrease in investing income (loss) primarily from write-downs
of certain investments and $14.6 million higher net interest expense reflecting
increased debt in support of continued expansion and new projects.
ENERGY MARKETING & TRADING
ENERGY MARKETING & TRADING'S revenues increased $235.7 million, or 82
percent, due to a $287 million increase in trading revenues and a $52 million
decrease in non-trading revenues. The $287 million increase in trading revenues
is due primarily to $249 million higher gas and electric power trading and
services margins and $23 million higher crude and refined trading margins as
well as $15 million higher natural gas liquids margins. The higher gas and
electric power trading and services margins primarily reflect favorable results
from proprietary trading activities in natural gas, partially offset by net
unfavorable changes in existing power portfolios. In addition, the increased gas
and electric power trading and services margins include $180 million from the
recognition of power sales, $164 million of which related to previous quarters
in 2001, due to additional guidance regarding California's credit responsibility
for power sales to major utilities. The higher crude and refined trading margins
and higher natural gas liquids margins result from favorable price movements in
relation to current trading positions.
The $52 million decrease in non-trading revenues is due primarily to $51
million lower natural gas liquids revenues resulting from lower sales prices.
Costs and operating expenses decreased $34 million, or 47 percent, due
primarily to $39 million lower natural gas liquids costs. This variance is
associated with the corresponding change in non-trading revenues discussed
above.
Segment profit increased $210.1 million to $357.2 million in 2001 as
compared to $147.1 million of segment profit in 2000. The increase is due
primarily to $287 million higher trading revenues discussed above partially
offset by $12 million lower margins from non-trading natural gas liquids
operations, $42 million increase in selling, general and administrative
expenses, and a $23.3 million loss from the write-downs of marketable equity
securities and a cost-based investment (see Note 4). The higher selling, general
and administrative costs reflect higher variable compensation levels associated
with the increased operating performance as well as charitable contribution
commitments to state universities.
20
Management's Discussion & Analysis (Continued)
CALIFORNIA
At September 30, 2001, Energy Marketing & Trading had net accounts
receivable recorded of approximately $477 million for power sales to the
California Independent System Operator (ISO) and the California Power Exchange
Corporation (CPEC). The increase from June 30, 2001 in the net accounts
receivable is due to $180 million revenues recognized primarily for previous
2001 quarter power sales as discussed above. While the amount recorded reflects
management's best estimate of collectibility, future events or circumstances
could change those estimates. In March and April of 2001, two California power
related entities, the CPEC and Pacific Gas and Electric Company (PG&E), filed
for bankruptcy under Chapter 11. On September 20, 2001, PG&E filed a
reorganization plan as part of its Chapter 11 bankruptcy proceeding that seeks
to pay all of its creditors in full. California utility regulators agreed on
October 2, 2001, to a settlement in which Edison International (EIX) unit
Southern California Edison will repay its back debt out of existing rates by
2005. The agreement settles a federal-court lawsuit in which the utility sought
to force the California Public Utilities Commission to raise rates and allows
the utility to recover an estimated $3 billion in back debt. Both the
reorganization plan and the settlement agreement are subject to current
challenges, further legal proceedings and regulatory approvals. Williams does
not believe its credit exposure to these utilities will result in a materially
adverse effect on its results of operations or financial condition.
The prices charged for power by Williams and other traders and generators
in California and other western markets have been challenged in various
proceedings, including those before the Federal Energy Regulatory Commission
(FERC). In December 2000, the FERC issued an order which provided that for the
period between October 2, 2000 and December 31, 2002, it 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
the FERC, 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.
However, in its FERC filings, Williams continues its objections to refunds in
any amount.
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. Although Williams believes these requests are ill-founded and
will be rejected by the FERC, there can be no assurance of such action.
In an order issued June 19, 2001, the FERC has 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 will be in effect from June
20, 2001 through September 30, 2002, establishes a market clearing price for
spot sales in all hours of the day that is based on the bid of the highest-cost
gas-fired California generating unit that is needed to serve the California
ISO's load. When generation operating reserves fall below 7 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 is the market clearing price. When generation operating
reserves rise to 7 percent or above in California, absent cost-based
justification for a higher price, Williams' maximum price will be limited to 85
percent of the highest hourly price that was in effect during the most recent
reserve deficiency period. The June 19 order also implemented multi-party
settlement talks regarding refunds for past periods that concluded without
resolution of the issues. Absent settlement, the presiding administrative law
judge issued a report to the FERC that, with some variations, recommends
applying the methodology of the June 19 order to determine refunds for prior
periods. On July 25, 2001, the FERC issued an order adopting, to a significant
extent, the Judge's recommendation and establishing an expedited hearing to
establish the facts necessary to determine refunds under the approved
methodology. Refunds under this order 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.
In March 2001, FERC issued a Show Cause Order directing Williams 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, 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
21
Management's Discussion & Analysis (Continued)
the California 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.
In May 2001, the Department of Justice 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. In
connection with that investigation, the Department of Justice issued a Civil
Investigative Demand to Williams requesting answers to certain interrogatories
and the production of documents. Williams is cooperating with the investigation.
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
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 (see "Other Legal Matters" in Note 12). Most
of these initiatives, investigations and proceedings are in their preliminary
stages and their likely outcome cannot be estimated. There can be no assurance
that these initiatives, investigations and proceedings will not have an adverse
effect on Williams' results of operations or financial condition.
GAS PIPELINE
GAS PIPELINE'S revenues decreased $4.6 million, or 1 percent, due primarily
to $13 million lower gas exchange imbalance settlements (offset in costs and
operating expenses), $4 million lower transportation revenues at Texas Gas due
primarily to discounting and $3 million reduction of rate refund liabilities in
2000 following the settlement of a prior rate proceeding. Partially offsetting
these decreases were $14 million higher transportation demand revenues at
Transco and Kern River and $5 million higher equity investment earnings from
pipeline joint venture projects.
Costs and operating expenses decreased $5.2 million, or 2 percent. The
decrease reflects $13 million lower gas exchange imbalance settlements (offset
in revenues), partially offset by $12 million in higher depreciation expense due
to increased property, plant and equipment placed into service.
Other (income) expense-net includes $14 million of charitable contribution
commitments primarily related to the Williams 2001 United Way campaign held
during the quarter. Last year's Williams United Way campaign commitments were
made in the fourth quarter.
Segment profit decreased $15.7 million, or 10 percent, due primarily to the
$14 million charitable contribution commitments.
Based on current rate structures and/or historical maintenance schedules of
certain of its pipelines, Gas Pipeline generally experiences lower segment
profits in the second and the third quarters as compared with the first and
fourth quarters.
ENERGY SERVICES
EXPLORATION & PRODUCTION'S revenues increased $86.9 million, to $153.9
million in 2001 from $67 million in 2000, due primarily to $69 million of
revenues related to Barrett, which became a consolidated entity on August 2,
2001 (see Note 5 for further discussion of Barrett). Included in the $69 million
is the favorable impact of hedge contracts placed on Barrett production by
Williams. Revenues also increased $11 million from increased average realized
natural gas sales prices (including the effect of hedge positions).
Approximately 80 percent of production in third-quarter 2001 was hedged.
Segment profit increased $38.9 million, to $56.9 million in 2001 from $18.0
million in 2000, due primarily to the higher revenues discussed above, partially
offset by $41 million of segment costs and expenses related to Barrett and $7
million higher general and administrative expenses.
INTERNATIONAL'S revenues increased $17.3 million, from $18.7 million in
2000. The increase is attributable to $10.2 million of revenue from a new gas
compression facility in Venezuela which began operations in August 2001, $6.6
million of revenue from Colorado soda ash production which began in October
2000, and $1.3 million increase in revenues from the existing Venezuelan gas
compression facility. Equity earnings of $2.9 million from a new NGL extraction
and processing joint venture in Venezuela were offset by $2.8 million higher
equity losses from the Lithuanian refinery, pipeline and terminal investment.
22
Management's Discussion & Analysis (Continued)
Costs and operating expenses increased $13.3 million, due primarily to
$11.7 million related to soda ash production which began in October 2000 and
$2.5 million related to the new gas compression facility in Venezuela which
began operations in 2001.
Segment profit increased $3.6 million from $4.2 million in 2000. The
increase in segment profit is primarily related to $7.8 million from the new gas
compression facility in Venezuela partially offset by $5.1 million higher
segment loss related to the soda ash project.
MIDSTREAM GAS & LIQUIDS' revenues increased $60.3 million, or 18 percent,
due primarily to $99 million in revenues from Canadian operations acquired in
October 2000. Domestic natural gas liquids revenues decreased $44 million
reflecting a $25 million decrease from 20 percent lower average domestic natural
gas liquids sales prices and a $19 million decrease due to a 13 percent decrease
in domestic liquids volumes sold.
Costs and operating expenses increased $55 million to $291 million in the
third-quarter 2001, due primarily to $85 million of costs and operating expenses
related to the Canadian operations and increased domestic operating and
maintenance costs. Substantially offsetting those increased costs were $41
million lower product costs related to domestic natural gas liquids sales.
Included in other (income) expense-net within segment costs and expenses
for 2001 is a $4.2 million impairment loss related to management's third-quarter
2001 decision to sell certain south Texas non-regulated gathering assets. The
$4.2 million charge represents the impairment of the assets to fair value based
on expected proceeds from a sale.
Segment profit decreased $2.1 million, or 2.5 percent due primarily to the
$4.2 million impairment loss discussed above, a $3 million decrease from
domestic natural gas liquids sales activities and an increase in domestic
operating and maintenance costs. These decreases were partially offset by a $10
million segment profit from the Canadian operations.
PETROLEUM SERVICES' revenues increased $127.5 million, or 10 percent, due
primarily to $118 million higher refining and marketing revenues (excluding an
increase of $59 million as a result of lower intra-segment sales to the travel
center/convenience stores which are eliminated), partially offset by $80 million
lower travel center/convenience store sales. Effective February 2001, management
of refined product sales activities surrounding certain terminals throughout the
United States was transferred to Petroleum Services from Energy Marketing &
Trading (see Note 2). The sales activity was previously included in the trading
portfolio of Energy Marketing & Trading and was therefore reported net of
related cost of sales along with other refined product trading gains and losses
within Energy Marketing & Trading prior to February 2001. After the transfer of
management of these activities to Petroleum Services, these sales activities are
reported "gross" within the Petroleum Services segment. Energy Marketing &
Trading's revenue for the three months ended September 30, 2000 includes
approximately $126 million for both the sales and cost of sales related to this
activity. The $118 million increase in refining and marketing revenues includes
the $126 million impact previously discussed and $128 million from a 13 percent
increase in refined product volumes sold, partially offset by $137 million
resulting from 13 percent lower average refined product sales prices. The $80
million decrease in travel center/convenience store sales reflects $122 million
of revenues in 2000 related to the 198 convenience stores sold in May 2001,
partially offset by a $42 million increase in revenues related to travel centers
and Alaska convenience stores. The $42 million increase in the travel
centers/convenience stores retained reflects $49 million from a 25 percent
increase in gasoline and diesel sales volumes and $11 million higher merchandise
sales, partially offset by $18 million lower average gasoline and diesel sales
prices. In addition, revenues increased due to $29 million higher bio-energy
sales reflecting an increase in ethanol volumes sold and average ethanol sales
prices.
Costs and operating expenses increased $120.5 million, or 10 percent, due
primarily to $111 million higher refining and marketing costs and $74 million
lower travel center/convenience store costs (excluding a $59 million increase
due to lower intra-segment purchases from the refineries which are eliminated).
The $111 million increase in refining and marketing costs includes the $126
million impact of the transfer of management from Energy Marketing & Trading to
Petroleum Services discussed above and a $66 million increase in the costs
related to refined product purchased for resale and a $10 million increase in
other operating costs at the refineries, offset by a $91 million decrease from
lower crude supply cost and other per unit cost of sales from the refineries.
The refining and marketing costs include the impact of price risk management
activities that are used to manage the economic exposure of fluctuations in
commodity prices of crude oil and refined products. The $74 million decrease in
travel center/convenience store costs reflects $119 million of costs in 2000
related to the 198 convenience stores sold in May 2001, partially offset by a
$45 million increase in costs related to travel centers and Alaska convenience
stores. The $45 million increase in costs for the travel centers/convenience
stores retained reflect $47 million from increased diesel and gasoline sales
volumes, $13 million from higher store operating costs and $6 million higher
merchandise costs, partially offset by $21 million lower gasoline and diesel
sale prices. In
23
Management's Discussion & Analysis (Continued)
addition, costs and operating expenses increased due to $21 million higher
bio-energy operating costs.
Segment profit increased $5.9 million, to $66.1 million in 2001 from $60.2
million in 2000, due primarily to $7 million from refining and marketing
operations and $6 million higher operating profit from bio-energy operations,
partially offset by $5 million higher operating losses for the travel
center/convenience stores retained.
WILLIAMS ENERGY PARTNERS' revenue increased $4.5 million from $17.3 million
to $21.8 million, due primarily to acquisition of a marine terminal facility
acquired in September 2000 and additional ammonia revenues. Segment profit
decreased $.2 million from $4.2 million to $4 million, due primarily to
increased revenues being substantially offset by increased selling, general and
administrative costs.
CONSOLIDATED
GENERAL CORPORATE EXPENSES increased $13.7 million, or 73 percent,
primarily due to an increase in advertising costs (which includes a branding
campaign of $8 million) and charitable contribution commitments of $5 million.
Interest accrued increased $11.8 million, or 6 percent, due primarily to the $25
million effect of higher borrowing levels slightly offset by the $15 million
effect of lower interest rates. The increased borrowing levels reflect an
increase in long-term debt levels partially offset by a decrease in commercial
paper levels as compared to 2000. Long-term debt includes $1.1 billion long-term
senior unsecured debt securities issued in January 2001 and $1.5 billion of
long-term debt securities issued in August 2001 primarily for the replacement of
$1.2 billion borrowed under a $1.5 billion short-term credit agreement
originated in June 2001 related to the cash portion of the Barrett acquisition.
Investing income (loss) decreased $105.2 million, from $21 million of investing
income in 2000 to an investing loss of $84.2 million in 2001, due primarily to
write-downs of investments in certain publicly traded and marketable equity
securities and a cost based investment totaling $94.2 million including $70.9
million related to the write-down of Williams' investment in WCG (see Note 4).
In addition, the decrease in investing income (loss) reflects a $5 million
decrease in dividend income due to the sale of the Ferrellgas Senior common
units in second-quarter 2001 and $5 million resulting from a settlement of a
note receivable from a foreign investee for less than the carrying amount.
Minority interest in income and preferred returns of consolidated subsidiaries
increased $6.9 million, or 51 percent, due primarily to preferred returns of
Snow Goose LLC, formed in December 2000 and minority interest in income of
Williams Energy Partners L.P. and certain of International's consolidated
subsidiaries partially offset by a $4 million decrease related to the preferred
returns of Williams obligated mandatorily redeemable preferred securities of
Trust which were redeemed by Williams in second-quarter 2001.
The provision for income taxes increased $85.3 million, or 76 percent,
primarily as a result of higher pre-tax income and the valuation allowances
associated with the tax benefits for investment write-downs for which ultimate
realization is uncertain. The effective tax rate for 2001 is greater than the
federal statutory rate due primarily to the valuation allowances discussed above
and the effect of state income taxes. The effective income tax rate for 2000 is
greater than the federal statutory rate due primarily to the effects of state
income taxes.
NINE MONTHS ENDED SEPTEMBER 30, 2001 VS.
NINE MONTHS ENDED SEPTEMBER 30, 2000
CONSOLIDATED OVERVIEW
Williams' revenues increased $2,140.6 million, or 33 percent, due primarily
to higher gas and electric power trading and services margins, revenues from
Canadian operations acquired in fourth-quarter 2000, higher petroleum products
revenues, higher natural gas sales prices, revenues from Barrett and the $442
million impact of reporting certain revenues net of the related costs in 2000
related to sales activity surrounding certain terminals. These revenues are
reported "gross" subsequent to the transfer of management over the sales
activity from Energy Marketing & Trading to Petroleum Services effective
February 2001 (see Note 2). Partially offsetting these increases was a decrease
of $185 million in revenues related to convenience stores sold in May 2001 and
the effect in 2000 of a $74 million reduction of Gas Pipeline's rate refund
liabilities.
Segment costs and expenses increased $1,372.5 million, or 27 percent, due
primarily to higher petroleum product costs, costs associated with Canadian
operations acquired in fourth-quarter 2000, costs associated with Barrett
acquired in August 2001 and the impact of reporting certain sales activity costs
net with related revenues in 2000 (discussed above). These increases were
partially offset by a $178 million decrease in costs as a result of the sale of
198 convenience stores in May 2001 and the $72.1 million gain on the sale of
these convenience stores.
Operating income increased $745.1 million, or 51 percent, due primarily to
higher gas and electric power service margins, the $72.1 million pre-tax gain on
the sale of the convenience stores in May 2001, higher margins at refining and
marketing operations, increased realized natural gas sales prices, the impact of
Barrett and the effect in 2000 of $30.3 million in guarantee loss accruals and
impairment charges at Energy Marketing & Trading. Partially offsetting these
increases were lower per-unit natural gas liquids margins and the
24
$74 million effect in 2000 of rate refund liabilities and approximately $26
million of impairment charges within Energy Services.
Income from continuing operations before income taxes increased $596.3
million from $997.1 million in 2000 to $1,593.4 million in 2001, due primarily
to $745.1 million higher operating income, partially offset by $85 million
decrease in investing income (loss) primarily from write-downs of investments,
$52.7 million higher net interest expense reflecting increased debt in support
of continued expansion and new projects and $24.5 million higher minority
interest in income and preferred returns of subsidiaries related primarily to
the preferred returns of Snow Goose LLC, formed in December 2000.
ENERGY MARKETING & TRADING
ENERGY MARKETING & TRADING'S revenues increased $688.1 million, or 77
percent, due to a $748 million increase in trading revenues offset by a $60
million decrease in non-trading revenues. The $748 million increase in trading
revenues is due primarily to $731 million higher gas and electric power trading
and services margins and $29 million increased natural gas liquids margins
slightly offset by $11 million lower crude and refined trading margins. The
higher gas and electric power trading and services margins primarily result from
a net favorable change in the overall fair value of the gas and electric
portfolio resulting from proprietary trading activities around existing
portfolio positions, including power sales in California. In addition, the
increased gas and electric power trading and services margins reflect the
benefit of additional price risk management services offered through structured
transactions. These new structured transactions included the addition of
approximately 3,710 megawatts of notional volumes to Energy Marketing & Trading
in the mid-continent, northeast and southeast regions of the United States.
These contracts include agreements to market capacity of electricity generation
facilities, as well as agreements to provide load following and/or full
requirements services.
The $60 million decrease in non-trading revenues is due primarily to $72
million lower natural gas liquids revenues primarily from lower sales prices
partially offset by $11 million higher non-trading power services revenues.
Costs and operating expenses decreased $26 million, or 13 percent, due
primarily to lower natural gas liquids costs, partially offset by higher
cogeneration costs of sales and increased operating expenses. These variances
are associated with the corresponding changes in non-trading revenues discussed
above.
Other (income) expense-net in 2000 includes $30.3 million in guarantee loss
accruals and impairment charges (see Note 3) and a $12.4 million gain on the
sale of certain natural gas liquids contracts.
Segment profit increased $617.4 million, from $497.5 million in 2000 to
$1,114.9 million in 2001, due primarily to the $748 million higher trading
revenues discussed above and the effect of the $30.3 million guarantee loss
accruals and impairment charges in 2000. Partially offsetting these increases
were $93 million higher selling, general and administrative costs, $32 million
lower margins from non-trading natural gas liquids operations, a $23.3 million
loss from the write-downs of marketable equity securities and a cost-based
investment (see Note 4), and the $12.4 million effect of the 2000 gain on sale
of certain natural gas liquids contracts. The higher selling, general and
administrative costs primarily reflect higher variable compensation levels
associated with improved operating performance, $10 million of bad debt expense
related to California electric power sales to a customer that had unexpectedly
filed for bankruptcy, increased outside service costs, as well as increased
charitable contribution commitments to state universities.
GAS PIPELINE
GAS PIPELINE'S revenues decreased $93.8 million, or 7 percent, due
primarily to the effect of a $74 million reduction of rate refund liabilities in
2000 following the settlement of prior rate proceedings and $51 million lower
gas exchange imbalance settlements (offset in costs and operating expenses).
Partially offsetting these decreases were $17 million higher transportation
demand revenues at Transco and Kern River, $11 million higher equity investment
earnings from pipeline joint venture projects and $8 million higher revenues
from a liquefied natural gas storage facility acquired in June 2000.
Costs and operating expenses decreased $52.2 million, or 8 percent, due
primarily to the $51 million lower gas exchange imbalance settlements (offset in
revenues) and $15 million resulting from the FERC's approval for recovery of
fuel costs incurred in prior periods by Transco. Partially offsetting these
decreases was $24 million in higher depreciation expense due to increased
property, plant and equipment placed into service.
Other (income) expense-net includes a $27.5 million pre-tax gain from the
sale of Williams' limited partnership interest in Northern Border Partners L.P.
and a $3 million insurance settlement in 2001 for storage gas losses, partially
offset by charitable contribution commitments of $14 million related to the
Williams
25
Management's Discussion & Analysis (Continued)
2001 United Way campaign. Last year's Williams United Way campaign commitments
were made during the fourth quarter.
Segment profit decreased $17.2 million, or 3 percent, due primarily to the
lower revenues discussed previously, partially offset by the lower costs and
expenses, the items discussed previously in other (income) expense-net, and $11
million lower general and administrative expenses. The lower general and
administrative costs result primarily from lower tracked costs which are passed
through to customers and costs in 2000 related to the headquarters consolidation
of two of the gas pipelines.
Based on current rate structures and/or historical maintenance schedules of
certain of its pipelines, Gas Pipeline generally experiences lower segment
profits in the second and third quarters as compared to the first and fourth
quarters.
ENERGY SERVICES
EXPLORATION & PRODUCTION'S revenues increased $196.2 million from $194.5
million in 2000, due primarily to $94 million from increased realized average
natural gas sales prices (including the effect of hedge positions) and $15
million associated with an increase in volumes from production and marketing
activities. Revenues also include $77 million related to Barrett which became a
consolidated entity on August 2, 2001 (see Note 5 for further discussion of
Barrett). Included in the $77 million is the impact of hedge contracts placed on
Barrett production by Williams and $8.5 million in equity earnings from the 50
percent investment in Barrett held by Williams for the period from June 11, 2001
through August 1, 2001. Approximately 74 percent of production through
third-quarter 2001, including Barrett production during August 2, 2001 to
September 30, 2001, was hedged. Exploration & Production has entered into
contracts that hedge approximately 81 percent of estimated production for the
remainder of the year. At September 30, 2001, the contracted future hedges are
at prices that averaged above the spot market, resulting in an unrealized gain
reflected in other comprehensive income. In addition, revenues in 2001 included
$22 million related to recognition of income from transactions which transferred
certain non-operating economic benefits to a third party, compared to $9 million
in 2000.
Segment costs and operating expenses increased $88 million, including an $8
million increase in selling, general and administrative expenses. Gas purchase
costs related to the marketing of natural gas from the Williams Coal Seam
Royalty Trust and royalty interest owners increased $22 million. Segment costs
and operating expenses related to Barrett operations were approximately $41
million and were comprised primarily of depletion, depreciation and amortization
and operating and maintenance costs. In addition, the increase in costs and
operating expenses related to existing Williams properties included $8 million
higher production-related taxes, $8 million higher operating and maintenance
expenses and $7 million higher depreciation and amortization expenses, slightly
offset by $9 million lower unproved lease amortization expense.
Segment profit increased $108.4 million, to $147.8 million in 2001 from
$39.4 million in 2000, due primarily to the higher revenues in excess of costs
discussed previously, including segment profit related to Barrett of $28.2
million for the period from August 2, 2001 to September 30, 2001.
INTERNATIONAL'S revenues increased $33.8 million, or 65 percent, from $52.2
million in 2000. The increase is attributable to $17.8 million of revenue from
Colorado soda ash production which began in October 2000, $10.2 million of
revenue from a new gas compression facility in Venezuela which began operations
in 2001, and $4.8 million in revenues from an existing Venezuelan gas
compression facility. Equity earnings decreased $2.2 million from income of $1.1
million in 2000 to a loss of $1.1 million in 2001. The decrease is due primarily
to a $4 million increase in equity losses from the Lithuanian refinery, pipeline
and terminal investment, slightly offset by equity earnings of $2.8 million from
a NGL extraction and processing joint venture acquired in 2001.
Costs and operating expenses increased $43.1 million due primarily to $39.3
million related to soda ash production which began in October 2000 and $3.7
million related to the new gas compression facility in Venezuela which began
operations in 2001.
Segment profit decreased $6.4 million, or 70 percent, from $9.2 million in
2000. The soda ash project had a higher segment loss of $21.5 million reflecting
initial operations start up costs, and operational complications. Partially
offsetting the loss from soda ash production was an $11.7 million increase from
Venezuelan gas compression facilities, including the new gas compression
facility, and lower general and administrative costs.
MIDSTREAM GAS & LIQUIDS' revenues increased $492 million, or 50 percent,
due primarily to $564 million in revenues from Canadian operations acquired in
October 2000. The $564 million of revenues from Canadian operations consist
primarily of $270 million of natural gas liquids sales from processing
activities, $205 million of natural gas liquids sales from fractionation
activities, and $81 million of processing revenues. Domestic natural gas liquids
revenues decreased $70 million reflecting a $85 million decrease from a 22
percent decrease in volumes sold, partially offset by a $15 million
26
Management's Discussion & Analysis (Continued)
increase due to higher average natural gas liquids sales prices. In addition,
equity method investments had $13.5 million higher equity losses in 2001,
primarily from the Discovery pipeline project.
Costs and operating expenses increased $563 million to $1.2 billion, due
primarily to $549 million of costs and operating expenses related to the
Canadian operations, $16 million higher general operating and maintenance costs,
and $8 million higher power costs related to the natural gas liquids pipelines,
partially offset by the effect in 2000 of $12 million of losses associated with
certain propane storage transactions.
General and administrative expenses decreased $11 million, or 13 percent,
due primarily to $12 million of reorganization and early retirement costs
occurring in 2000 and a $12 million reduction in overall expenses, partially
offset by $11 million of general and administrative expenses related to the
Canadian operations.
Included in other (income) expense-net within segment costs and expenses
for 2001 is $15 million of impairment charges related to management's 2001
decisions and commitments to sell certain south Texas non-regulated gathering
and processing assets. The $15.1 million in impairment charges represent the
impairment of the assets to fair value based on expected proceeds from the
sales.
Segment profit decreased $77.1 million, or 33 percent, due primarily to $35
million from lower average per-unit domestic natural gas liquids margins, $25
million from decreased domestic natural gas liquids volumes sold, $8 million
decrease associated with higher power costs of the natural gas liquids pipeline
system, $13.5 million from higher equity investment losses, and $15 million due
to the impairment charges discussed above. Partially offsetting these decreases
to segment profit were $11 million lower general and administrative expenses and
$12 million of losses associated with certain propane storage transactions in
first-quarter 2000.
PETROLEUM SERVICES' revenues increased $1,046.8 million, or 32 percent, due
primarily to $754 million higher refining and marketing revenues (excluding an
increase of $120 million as a result of lower intra-segment sales to the travel
centers/convenience stores which are eliminated) and $66 million higher travel
center/convenience store sales. The $754 million increase in refining and
marketing revenues includes the $442 million impact of the transfer of
management from Energy Marketing & Trading to Petroleum Services effective
February 2001 of refined product sales activities surrounding certain terminals,
$289 million resulting from an 11 percent increase in refined product volumes
sold and $23 million from higher average refined product sales prices. The $66
million increase in travel center/convenience store sales reflects $251 million
increase in revenues related to travel centers and Alaska convenience stores
offset by a $185 million decrease in revenues related to the 198 convenience
stores sold in May 2001. The $251 million increase in revenues of the travel
centers/convenience stores retained reflects $215 million from a 38 percent
increase in gasoline and diesel sales volumes, $5 million from higher average
gasoline sales prices and $37 million higher merchandise sales, partially offset
by $6 million from lower average diesel sales prices. In addition, revenues
increased due to $90 million higher bio-energy sales reflecting increases in
ethanol volumes sold and average ethanol sales prices, $25 million higher
revenues from Williams' 3.1 percent undivided interest in TAPS acquired in late
June 2000 and $9 million higher commodity sales from transportation activities.
Slightly offsetting these increases were $12 million lower revenues related to
the petrochemical plant due to a plant turnaround in first-quarter 2001.
Costs and operating expenses increased $996.3 million, or 33 percent, due
primarily to $691 million higher refining and marketing costs and $86 million
higher travel center/convenience store costs (excluding a $120 million increase
in costs due to lower intra-segment purchases from the refineries which are
eliminated). The $691 million increase in refining and marketing costs includes
the $442 million impact of the transfer of management from Energy Marketing &
Trading to Petroleum Services effective February 2001 of refined product sales
activities surrounding certain terminals (see discussion above) while the
remaining increase reflects a $277 million increase in the cost of refined
product purchased for resale and $19 million increase in other operating costs
at the refineries, partially offset by a $47 million decrease from lower crude
supply cost and other per unit cost of sales from the refineries. The refining
and marketing costs include the impact of price risk management activities that
are used to manage the economic exposure of fluctuations in commodity prices of
crude oil and refined products. The $86 million increase in travel
center/convenience store costs reflects a $264 million increase in costs related
to the travel centers and Alaska convenience stores, partially offset by a $178
million decrease in costs related to the 198 convenience stores sold in May
2001. The $264 million increase in costs for the travel centers/convenience
stores retained reflect $204 million from increased diesel and gasoline sales
volumes, $26 million higher merchandise costs, $37 million from higher store
operating costs and $4 million higher gasoline sales prices, partially offset by
$7 million lower diesel sales prices. In addition, costs and operating expenses
increased due to $76 million higher bio-energy raw product and operating costs,
$10 million higher commodity sales from transportation activities and $8 million
of cost related to Williams' 3.1 percent undivided interest in TAPS.
Included in other (income) expense-net within segment costs and expenses
for 2001, is a $72.1 million pre-tax gain from the sale of 198 convenience
stores, primarily in the Tennessee metropolitan areas
27
Management's Discussion & Analysis (Continued)
of Memphis and Nashville. Revenues related to the stores which were sold
approximated $183 million and $368 million for 2001 and 2000. Also included in
other (income) expense-net within segment costs and expenses is an $11 million
impairment charge related to an end-to-end mobile computing systems business.
Segment profit increased $112.3 million, or 77 percent, due primarily to an
increase of $64 million from refining and marketing operations and $15 million
from Williams interest in TAPS acquired in late June 2000. In addition, segment
profit increased due to a $72.1 million gain on the sale of convenience stores
in May 2001. Partially offsetting these increases were an $11 million impairment
charge related to an end-to-end mobile computing systems business, a $23 million
increase in operating losses from the travel centers/convenience stores retained
and $13 million lower revenues from activities at the petrochemical plant.
WILLIAMS ENERGY PARTNERS' revenue increased $11.2 million to $63.8 million
and segment profit increased $2.4 million from $13.9 million to $16.3 million,
due primarily to acquisition of a marine terminal facility acquired in September
2000.
CONSOLIDATED
GENERAL CORPORATE EXPENSES increased $23 million, or 35 percent, primarily
due to an increase in advertising costs (which includes a branding campaign of
$9 million), charitable contribution commitments of $7 million, an increase in
outside legal costs and higher compensation levels. Interest accrued increased
$47 million, or 9 percent, due primarily to the $38 million effect of higher
borrowing levels slightly offset by the $9 million effect of lower average
interest rates. Interest accrued also increased due to a $12 million increase in
interest expense related to deposits received from customers relating to energy
trading and hedging activities, a $6 million increase in amortization of debt
expense, and a $4 million increase in interest expense on rate refund
liabilities. The increased borrowing levels reflect an increase in long-term
debt levels partially offset by a decrease in commercial paper levels as
compared to 2000. Long-term debt includes $1.1 billion of long-term debt
securities issued in January 2001 and $1.5 billion of long-term debt securities
issued in August 2001 primarily to replace $1.2 billion borrowed under a $1.5
billion short-term agreement originated in June 2001 related to the cash portion
of the Barrett acquisition. Investing income (loss) decreased $84.5 million,
from investing income of $59.1 million in 2000 to an investing loss of $25.4
million in 2001, due primarily to write-downs of investments in certain publicly
traded marketable equity securities of $94.2 million including $70.9 million
related to the write-down of Williams' investment in WCG (see Note 4). In
addition, the decrease in investing income (loss) reflects a decrease in
dividend income of $8 million due to the sale of Ferrellgas Senior common units
in second-quarter 2001. The decreases to investing income (loss) were slightly
offset by interest income on margin deposits of $20 million. Minority interest
in income and preferred returns of consolidated subsidiaries increased $24.5
million, or 60 percent, due primarily to preferred returns of Snow Goose LLC,
formed in December 2000 and minority interest in income of Williams Energy
Partners L.P., partially offset by a $6 million decrease related to the
preferred returns of Williams obligated mandatorily redeemable preferred
securities of Trust which were redeemed by Williams in second-quarter 2001.
The provision for income taxes increased $259 million, or 66 percent,
primarily as a result of higher pre-tax income and the valuation allowances
associated with the tax benefits for investment write-downs for which ultimate
realization is uncertain. The effective tax rate for 2001 is greater than the
federal statutory rate due primarily to the valuation allowances discussed above
and the effect of state income taxes. The effective income tax rate for 2000 is
greater than the federal statutory rate due primarily to the effects of state
income taxes.
Loss from discontinued operations for the nine months ended September 30,
2001, includes $179.1 million after-tax loss from operations of WCG (see Note
7). The $29.2 income from operations for the nine months ended September 30,
2000, represents the after-tax income from the operations of WCG.
FINANCIAL CONDITION AND LIQUIDITY
Liquidity
Williams considers its liquidity to come from both internal and external
sources. Certain of those sources are available to Williams (parent) and certain
of its subsidiaries. Williams' unrestricted sources of liquidity, which can be
utilized without limitation under existing loan covenants, consist primarily of
the following:
o Available cash-equivalent investments of $240 million at September 30,
2001, as compared to $854 million at December 31, 2000.
o $700 million available under Williams' $700 million bank-credit facility at
September 30, 2001, as compared to $350 million at December 31, 2000.
28
Management's Discussion & Analysis (Continued)
o $2.1 billion available under Williams' $2.2 billion commercial paper
program at September 30, 2001, as compared to $4 million at December 31,
2000 under a $1.7 billion commercial paper program.
o Cash generated from operations.
o Short-term uncommitted bank lines of credit can also be used in managing
liquidity.
In June 2001, Williams filed a $1.9 billion shelf registration statement
with the Securities and Exchange Commission to issue a variety of debt and
equity securities. This registration statement became effective in July 2001. At
November 1, 2001, approximately $400 million of shelf availability remains under
this registration statement. 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). At November 1, 2001, 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
and market conditions will affect amounts borrowed, if any, under these
arrangements. Williams believes additional financing arrangements, if required,
can be obtained on reasonable terms.
Capital and investment expenditures for the fourth quarter of 2001 are
estimated to be approximately $1 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' $700 million bank-credit facility, (3) commercial paper, (4)
short-term uncommitted bank lines, (5) private borrowings and/or (6) public debt
offerings.
WCG Separation
Currently, Williams does not believe that the separation of WCG and
Williams will negatively impact liquidity or the financial condition of
Williams. Since the initial equity offering by WCG in October 1999, the sources
of liquidity for WCG had been separate from Williams' sources of liquidity. The
reduction to Williams' stockholders' equity as a result of the separation in
April 2001 was approximately $1.8 billion. Williams, with respect to shares of
WCG's common stock that Williams retained, has committed to the Internal Revenue
Service (IRS) to dispose of all of the WCG shares that it retains as soon as
market conditions allow, but in any event not longer than five years after the
spinoff. As part of a separation agreement and subject to a favorable ruling by
the IRS that such a limitation is not inconsistent with any ruling issued to
Williams regarding the tax-free treatment of the spinoff, Williams has agreed
not to dispose of the retained WCG shares for three years from the date of
distribution and must notify WCG of an intent to dispose of such shares. For
further discussion of separation agreements and potential tax exposure as a
result of the WCG separation, see Note 7.
Additionally, Williams, prior to the spinoff and in an effort to strengthen
WCG's capital structure, entered into an agreement under which Williams
contributed an outstanding promissory note from WCG of approximately $975
million and certain other assets, including a building under construction. In
return, Williams received 24.3 million newly issued common shares of WCG.
Williams is providing indirect credit support for $1.4 billion of WCG's
structured notes through a commitment to issue Williams' equity in the event of
any one of the following: (1) WCG's default; (2) downgrading of Williams' senior
unsecured debt to Ba1 or below by Moody's, BB or below by S&P, or BB+ or below
by Fitch if Williams' common stock closing price is below $30.22 for ten
consecutive trading days while such downgrade is in effect; or (3) to the extent
proceeds from WCG's refinancing or remarketing of certain structured notes prior
to March 2004 produces proceeds of less than $1.4 billion. The ability of WCG to
make payments on the notes is dependent on its ability to raise additional
capital and its subsidiaries' ability to dividend cash to WCG. Williams' current
senior unsecured debt ratings are as follows: Moody's-Baa2, S&P-BBB and
Fitch-BBB. WCG is obligated to reimburse Williams for any payment Williams is
required to make in connection with these notes.
Williams has provided a guarantee of WCG's obligations under a 1998
transaction in which WCG entered into an operating lease agreement covering a
portion of its fiber-optic network. The total cost of the network assets covered
by the lease agreement is $750 million. The lease terms initially totaled five
years and, if renewed, could extend to seven years. WCG has an option to
purchase the covered network assets during the lease term at an amount
approximating lessor's cost. As a result of an agreement between Williams and
WCG's revolving credit facility lenders, if Williams gains control of the
network assets covered by the lease, Williams is obligated to return the assets
to WCG and the liability of WCG to compensate Williams for such property must be
subordinated to the interests of WCG's revolving credit facility lenders and may
not mature any earlier than one year after the maturity of WCG's revolving
credit facility.
In third-quarter 2001, Williams purchased the WCG headquarters building and
other ancillary assets from WCG for $276 million. Williams then entered into a
long-term lease arrangement under which WCG is the sole lessee of these assets.
As a result of this transaction, Williams' Consolidated
29
Management's Discussion & Analysis (Continued)
Balance Sheet includes $28 million in accounts and notes receivable and $248
million in other assets and deferred charges relating to amounts due from WCG.
Additionally, receivables include amounts due from WCG of approximately $120
million at September 30, 2001. Williams has extended the payment term of up to
$100 million of the outstanding balance due March 31, 2001 to March 15, 2002.
Financing Activities
In January 2001, Williams issued $1.1 billion of senior unsecured debt
securities, of which $500 million in proceeds was used to retire temporary
financing obtained in September 2000. Also in January 2001, Williams issued
approximately 38 million shares of common stock in a public offering at $36.125
per share. Net proceeds were $1.33 billion. Williams has and will continue to
use the remaining proceeds that were received from the debt offering and equity
offerings to expand Williams' capacity for funding of the energy-related capital
program, repay commercial paper, repay debt, including a portion of floating
rate notes due December 15, 2001, and other general corporate purposes.
Williams Energy Partners L.P. (WEP) owns and operates a diversified
portfolio of energy assets. The partnership is principally engaged in the
storage, transportation and distributions of refined petroleum products and
ammonia. On February 9, 2001, WEP completed an initial public offering of
approximately 4.6 million common units at $21.50 per unit for net proceeds of
approximately $92 million. The initial public offering represents 40 percent of
the units, and Williams retained a 60 percent interest in the partnership,
including its general partner interest.
In April 2001, Williams redeemed the Williams obligated mandatorily
redeemable preferred securities of Trust holding only Williams indentures for
$194 million. Proceeds from the sale of the Ferrellgas Partners L.P. senior
common units held by Williams were used for this redemption.
In June 2001, Williams issued $480 million of 7.75 percent notes due 2031.
Also in June 2001, Williams issued a $200 million (amended in July to $300
million) short-term debt obligation expiring January 2002. Interest rates are
based on LIBOR plus .875 percent. The proceeds from these issuances will be used
for general corporate purposes.
In July 2001, Williams entered into a $300 million short-term debt
obligation expiring July 2002. Interest rates are based on LIBOR plus .875
percent. The proceeds from this issuance are being used for general corporate
purposes.
In August 2001, Williams issued $750 million of 7.125 percent notes due
2011 and $750 million of 7.875 percent notes due 2021. A portion of the proceeds
were used to repay $1.2 billion outstanding under a short-term credit agreement
entered into for the cash portion of the Barrett acquisition (see Note 5). Also
in connection with the Barrett acquisition, Williams' Consolidated Balance Sheet
includes $310 million of debt obligations of Barrett. Barrett's debt obligations
include $150 million of 7.55 percent notes due 2007, which is guaranteed by
Williams, and $155 million of debt obligations under Barrett's revolving credit
agreement maturing December 2001. Interest rates on the revolving credit
agreement vary with market conditions. For further discussion of the Barrett
Resources Corporation acquisition, see Note 5.
In August 2001, Transcontinental Gas Pipe Line issued $300 million of 7
percent notes due 2011. Also in August 2001, Kern River Gas Transmission issued
$510 million of 6.676 percent senior notes due 2016. The proceeds from the Kern
River notes were primarily used to repay $435 million of notes which matured
September 2001.
The long term debt to debt-plus-equity ratio was 54.2 percent at September
30, 2001, compared to 53.5 percent at December 31, 2000 (63.7 percent at
December 31, 2000 if WCG debt is included). If short-term notes payable and
long-term debt due within one year are included in the calculations, these
ratios would be 60.2 percent at September 30, 2001 and 63.9 percent at December
31, 2000 (70.5 percent at December 31, 2000 if WCG debt had been included).
Investing Activities
On June 11, 2001, Williams acquired 50 percent of Barrett Resources'
outstanding common stock in a cash tender offer of $73 per share for a total of
approximately $1.2 billion. On August 2, 2001, Williams completed the
acquisition of Barrett Resources by exchanging each remaining share of Barrett
Resources for 1.767 shares of Williams common stock.
Recent Accounting Standards
For a discussion of recent accounting standards issued and any potential
impact to Williams, See Note 17.
30
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-quarter 2001. In January 2001,
Williams issued $1.1 billion in debt obligations consisting of $700 million of
7.5 percent debentures due 2031 and $400 million of 6.75 percent Putable Asset
Term Securities, putable/callable in 2006. A portion of the proceeds was used to
retire $500 million of temporary financing obtained in September 2000. In June
2001, Williams issued $480 million of 7.75 percent notes due 2031. Also in June
2001, Williams issued a $200 million short-term debt obligation expiring June
2002. Interest rates are based on the adjusted Eurodollar rate. During July
2001, Williams issued a $300 million floating rate short-term debt obligation
expiring July 2002. The interest rate is based on LIBOR plus spread. During
August 2001, Williams issued $750 million of 7.125 percent notes due 2011 and
$750 million 7.875 percent notes due 2021. Proceeds from the August issuance
were used to retire $1.2 billion outstanding under a $1.5 billion short-term
credit agreement entered into second quarter 2001 in advance of the cash tender
of Barrett.
COMMODITY PRICE RISK
At September 30, 2001, the value at risk for the trading operations was $56
million compared to $90 million at December 31, 2000. This decrease of
approximately 38 percent reflects the impact of the additional price risk
management services offered in 2001 through structured transactions. These
structured transactions decrease risk on an aggregated portfolio basis. 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. Energy Marketing & Trading's 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 and market
interest rates, there is a 95 percent probability that the one-day loss in the
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 our
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.
FOREIGN CURRENCY RISK
As it relates to the continuing operations of Williams, international
investments accounted for under the cost method totaled approximately $146
million and $144 million at September 30, 2001 and December 31, 2000,
respectively. These international investments could affect the financial results
if the investments incur a permanent decline in value as a result of changes in
foreign currency exchange rates and the economic conditions in foreign
countries.
In addition, the net assets of continuing consolidated foreign operations,
located primarily in Canada, are approximately 10 percent and 11 percent of
Williams' net assets at September 30, 2001 and December 31, 2000, respectively.
These foreign operations, whose functional currency is the local currency, do
not have significant transactions or financial instruments denominated in other
currencies. However, these investments do have the potential to impact Williams'
financial position, due to fluctuations in these local currencies arising from
the process of re-measuring the local functional currency into the U.S. dollar.
As an example, a 20 percent change in the respective functional currencies
against the U.S. dollar could have changed stockholders' equity by approximately
$145 million at September 30, 2001.
EQUITY PRICE RISK
Equity price risk primarily arises from investments in WCG and energy-
related companies. The investments in energy-related companies are carried at
fair value and approximated $7 million at September 30, 2001. Williams'
remaining basis in WCG after the third quarter write-down of $70.9 million was
approximately $25 million at September 30, 2001.
31
PART II. OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K
(a) The exhibits listed below are filed as part of this report:
Exhibit 4.1 Form of Limited Waiver and Second Amendment to Credit
Agreement dated as of July 23, 2001, among Williams, as Borrower,
the Banks, the Co-Syndication Agents, the Co-Documentation Agents
and Citibank, N.A., as Agent for the Banks.
*Exhibit 4.2 Revised Form of Indenture between Barrett Resources
Corporation, as Issuer, and Bankers Trust Company, as Trustee,
with respect to Senior Notes including specimen of 7.55% Senior
Notes (filed as Exhibit 4.1 to Barrett Resources Corporation's
Amendment No. 2 to Registration Statement on Form S-3 filed
February 10, 1997).
Exhibit 4.3 First Supplemental Indenture dated 2001, between
Barrett Resources Corporation, as Issuer, and Bankers Trust
Company, as Trustee.
Exhibit 4.4 Second Supplemental Indenture dated as of August 2,
2001, among Barrett Resources Corporation, as Issuer, Resources
Acquisition Corp., The Williams Companies, Inc. and Bankers Trust
Company, as Trustee.
Exhibit 10.1 Form of Membership Interest Purchase Agreement dated
as of September 11, 2001, between Williams Communications, LLC and
Williams Aircraft, Inc.
Exhibit 10.2 Form of Aircraft Dry Lease, N352WC, dated as of
September 13, 2001, between Williams Communications Aircraft, LLC
and Williams Communications, LLC.
Exhibit 10.3 Form of Aircraft Dry Lease, N358WC, dated as of
September 13, 2001, between Williams Communications Aircraft, LLC
and Williams Communications, LLC.
Exhibit 10.4 Form of Aircraft Dry Lease, N359WC, dated as of
September 13, 2001, between Williams Communications Aircraft, LLC
and Williams Communications, LLC.
Exhibit 10.5 Form of Agreement of Purchase and Sale dated as of
September 13, 2001, among Williams Technology Center, LLC,
Williams Headquarters Building Company and Williams
Communications, LLC.
Exhibit 10.6 Form of Master Lease dated as of September 13, 2001,
among Williams Technology Center, LLC, Williams Headquarters
Building Company and Williams Communications, LLC.
Exhibit 10.7 Intercreditor Agreement dated as of September 8,
1999, among Williams, Williams Communications Group, Inc, Williams
Communications, LLC and Bank of America N.A.
Exhibit 10.8 Indenture dated as of March 28, 2001, among WCG Note
Trust, Issuer, WCG Note Trust, Issuer, WCG Note Corp., Inc.,
Co-Issuer, and United States Trust Company of New York, Indenture
Trustee and Securities Intermediary.
Exhibit 12 Computation of Ratio of Earnings to Fixed Charges
(b) During third-quarter 2001, the Company filed a Form 8-K on July
30, 2001; August 2, 2001; September 17, 2001 and September 25,
2001, which reported significant events under Item 5 of the Form
and included the Exhibits required by Item 7 of the Form.
* Exhibit has heretofore been filed with the Securities and Exchange Commission
as part of the filing indicated and is incorporated herein by reference.
32
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 13, 2001
INDEX TO EXHIBITS
<Table>
<Caption>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
4.1 Form of Limited Waiver and Second Amendment to Credit
Agreement dated as of July 23, 2001, among Williams, as
Borrower, the Banks, the Co-Syndication Agents, the
Co-Documentation Agents and Citibank, N.A., as Agent for the
Banks.
*4.2 Revised Form of Indenture between Barrett Resources
Corporation, as Issuer, and Bankers Trust Company, as Trustee,
with respect to Senior Notes including specimen of 7.55%
Senior Notes (filed as Exhibit 4.1 to Barrett Resources
Corporation's Amendment No. 2 to Registration Statement on
Form S-3 filed February 10, 1997).
4.3 First Supplemental Indenture dated 2001, between Barrett
Resources Corporation, as Issuer, and Bankers Trust Company,
as Trustee.
4.4 Second Supplemental Indenture dated as of August 2, 2001,
among Barrett Resources Corporation, as Issuer, Resources
Acquisition Corp., The Williams Companies, Inc. and Bankers
Trust Company, as Trustee.
10.1 Form of Membership Interest Purchase Agreement dated as of
September 11, 2001, between Williams Communications, LLC and
Williams Aircraft, Inc.
10.2 Form of Aircraft Dry Lease, N352WC, dated as of September 13,
2001, between Williams Communications Aircraft, LLC and
Williams Communications, LLC.
10.3 Form of Aircraft Dry Lease, N358WC, dated as of September 13,
2001, between Williams Communications Aircraft, LLC and
Williams Communications, LLC.
10.4 Form of Aircraft Dry Lease, N359WC, dated as of September 13,
2001, between Williams Communications Aircraft, LLC and
Williams Communications, LLC.
10.5 Form of Agreement of Purchase and Sale dated as of September
13, 2001, among Williams Technology Center, LLC, Williams
Headquarters Building Company and Williams Communications,
LLC.
10.6 Form of Master Lease dated as of September 13, 2001, among
Williams Technology Center, LLC, Williams Headquarters
Building Company and Williams Communications, LLC.
10.7 Intercreditor Agreement dated as of September 8, 1999, among
Williams, Williams Communications Group, Inc, Williams
Communications, LLC and Bank of America N.A.
10.8 Indenture dated as of March 28, 2001, among WCG Note Trust,
Issuer, WCG Note Trust, Issuer, WCG Note Corp., Inc.,
Co-Issuer, and United States Trust Company of New York,
Indenture Trustee and Securities Intermediary.
12 Computation of Ratio of Earnings to Fixed Charges
</Table>
- ----------
* Exhibit has heretofore been filed with the Securities and Exchange Commission
as part of the filing indicated and is incorporated herein by reference.