1
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 June 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 July 31, 2001
- ------------------------------------- --------------------------------
Common Stock, $1 par value 485,008,984 Shares
2
The Williams Companies, Inc.
Index
<Table>
<Caption>
Part I. Financial Information Page
----
Item 1. Financial Statements
Consolidated Statement of Income--Three and Six Months Ended June 30, 2001 and 2000 2
Consolidated Balance Sheet--June 30, 2001 and December 31, 2000 3
Consolidated Statement of Cash Flows--Six Months Ended June 30, 2001 and 2000 4
Notes to Consolidated Financial Statements 5
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operation 18
Item 3. Quantitative and Qualitative Disclosures about Market Risk 28
Part II. Other Information 29
Item 4. Submission of Matters to a Vote of Security Holders
Item 6. Exhibits and Reports on Form 8-K
Exhibit 10.1 --Form of Limited Waiver and Second Amendment to Credit
Agreement dated as of July 25, 2000 with the financial
institutions from time to time party thereto, The Chase
Manhattan Bank and Commerzbank AG, as Co-Syndication
Agents, Credit Lyonnais New York Branch, as
Documentation Agent, and Citibank, N.A., as Agent, which
Credit Agreement has been amended by a Waiver and First
Amendment to Credit Agreement dated as of January 31,
2001.
Exhibit 12 --Computation of Ratio of Earnings to Fixed Charges
</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
3
The Williams Companies, Inc.
Consolidated Statement of Income
(Unaudited)
<Table>
<Caption>
Three months Six months
(Dollars in millions, except per-share amounts) ended June 30, ended June 30,
---------------------------- ----------------------------
2001 2000* 2001 2000*
------------ ------------ ------------ ------------
Revenues:
Gas Pipeline $ 415.5 $ 492.0 $ 884.1 $ 973.3
Energy Services 2,591.0 1,959.8 5,434.9 3,499.0
Other 20.6 17.0 39.1 33.3
Intercompany eliminations (206.5) (119.1) (449.5) (256.6)
------------ ------------ ------------ ------------
Total revenues 2,820.6 2,349.7 5,908.6 4,249.0
------------ ------------ ------------ ------------
Segment costs and expenses:
Costs and operating expenses 1,977.5 1,489.4 4,018.9 2,799.4
Selling, general and administrative expenses 196.2 213.4 422.3 393.3
Other (income) expense-net (89.0) 14.8 (77.8) 15.7
------------ ------------ ------------ ------------
Total segment costs and expenses 2,084.7 1,717.6 4,363.4 3,208.4
------------ ------------ ------------ ------------
General corporate expenses 27.0 23.7 56.4 47.1
------------ ------------ ------------ ------------
Operating income:
Gas Pipeline 207.0 215.2 411.0 412.5
Energy Services 524.8 413.5 1,125.3 621.8
Other 4.1 3.4 8.9 6.3
General corporate expenses (27.0) (23.7) (56.4) (47.1)
------------ ------------ ------------ ------------
Total operating income 708.9 608.4 1,488.8 993.5
Interest accrued (171.0) (157.2) (361.0) (325.8)
Interest capitalized 11.2 14.6 20.9 23.8
Investing income 21.7 16.0 58.8 38.1
Minority interest in income and preferred returns
of consolidated subsidiaries (20.4) (13.9) (44.6) (27.0)
Other income-net 6.1 1.1 11.5 5.6
------------ ------------ ------------ ------------
Income from continuing operations before income taxes 556.5 469.0 1,174.4 708.2
Provision for income taxes 217.0 182.6 456.6 282.9
------------ ------------ ------------ ------------
Income from continuing operations 339.5 286.4 717.8 425.3
Income (loss) from discontinued operations -- 65.4 (179.1) 26.2
------------ ------------ ------------ ------------
Net income $ 339.5 $ 351.8 $ 538.7 $ 451.5
============ ============ ============ ============
Basic earnings per common share:
Income from continuing operations $ .70 $ .64 $ 1.48 $ .96
Income (loss) from discontinued operations -- .15 (.37) .06
------------ ------------ ------------ ------------
Net income $ .70 $ .79 $ 1.11 $ 1.02
============ ============ ============ ============
Average shares (thousands) 487,211 443,778 483,173 443,331
Diluted earnings per common share:
Income from continuing operations $ .69 $ .63 $ 1.47 $ .95
Income (loss) from discontinued operations -- .15 (.37) .06
------------ ------------ ------------ ------------
Net income $ .69 $ .78 $ 1.10 $ 1.01
============ ============ ============ ============
Average shares (thousands) 491,698 448,617 487,527 448,361
Cash dividends per common share $ .15 $ .15 $ .30 $ .30
</Table>
*Certain amounts have been restated or reclassified as described in Note 2 of
Notes to Consolidated Financial Statements.
See accompanying notes.
2
4
The Williams Companies, Inc.
Consolidated Balance Sheet
(Unaudited)
<Table>
<Caption>
(Dollars in millions, except per-share amounts) June 30, December 31,
2001 2000
----------- -----------
ASSETS
Current assets:
Cash and cash equivalents $ 1,014.6 $ 996.8
Accounts and notes receivable less allowance of $23.4 ($9.8 in 2000) 3,855.6 3,357.3
Inventories 751.3 848.4
Energy trading assets 4,914.9 7,879.8
Deferred income taxes 26.6 64.9
Margin deposits 217.5 730.9
Other 462.5 319.3
----------- -----------
Total current assets 11,243.0 14,197.4
Net assets of discontinued operations -- 2,290.2
Investments 2,769.6 1,368.6
Property, plant and equipment, at cost 19,684.7 19,028.8
Less accumulated depreciation and depletion (4,871.5) (4,589.5)
----------- -----------
14,813.2 14,439.3
Energy trading assets 3,810.4 1,831.1
Other assets and deferred charges 989.5 789.0
----------- -----------
Total assets $ 33,625.7 $ 34,915.6
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Notes payable $ 1,515.0 $ 2,036.7
Accounts payable 3,714.1 3,088.0
Accrued liabilities 1,640.8 1,560.4
Energy trading liabilities 4,513.8 7,597.3
Long-term debt due within one year 1,623.2 1,634.1
----------- -----------
Total current liabilities 13,006.9 15,916.5
Long-term debt 6,983.2 6,830.5
Deferred income taxes 3,101.3 2,863.9
Energy trading liabilities 2,606.3 1,302.8
Other liabilities and deferred income 952.0 944.0
Contingent liabilities and commitments (Note 11)
Minority and preferred interests in consolidated subsidiaries 1,074.4 976.0
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, 488.1 million
issued in 2001, 447.9 million issued in 2000 488.1 447.9
Capital in excess of par value 3,674.0 2,473.9
Retained earnings 1,635.2 3,065.7
Accumulated other comprehensive income 210.5 28.2
Other (66.5) (81.2)
----------- -----------
5,941.3 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 5,901.6 5,892.0
----------- -----------
Total liabilities and stockholders' equity $ 33,625.7 $ 34,915.6
=========== ===========
</Table>
See accompanying notes.
3
5
The Williams Companies, Inc.
Consolidated Statement of Cash Flows
(Unaudited)
<Table>
<Caption>
(Millions) Six months ended June 30,
---------------------------
2001 2000*
---------- ----------
OPERATING ACTIVITIES:
Income from continuing operations $ 717.8 $ 425.3
Adjustments to reconcile to cash provided by operations:
Depreciation, depletion and amortization 358.1 313.9
Provision for deferred income taxes 221.2 170.2
Provision for loss on property and other assets 25.1 4.2
Gain on dispositions of assets (101.5) (16.3)
Minority interest in income and preferred returns of
consolidated subsidiaries 44.6 27.0
Tax benefit of stock-based awards 21.4 13.2
Cash provided (used) by changes in assets and liabilities:
Accounts and notes receivable (553.5) (315.5)
Inventories 97.2 (180.7)
Margin deposits 513.4 (38.6)
Other current assets (104.8) (95.4)
Accounts payable 561.1 402.5
Accrued liabilities (46.5) (59.9)
Changes in current energy trading assets and liabilities (118.7) (263.6)
Changes in non-current energy trading assets and liabilities (675.8) (195.6)
Other, including changes in non-current assets and liabilities 64.3 59.7
---------- ----------
Net cash provided by operating activities 1,023.4 250.4
---------- ----------
FINANCING ACTIVITIES:
Proceeds from notes payable 1,430.0 314.0
Payments of notes payable (2,751.0) (445.1)
Proceeds from long-term debt 1,695.6 900.0
Payments of long-term debt (731.7) (553.2)
Proceeds from issuance of common stock 1,380.8 34.2
Dividends paid (145.3) (132.6)
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 (50.4) (.6)
---------- ----------
Net cash provided by financing activities 726.5 116.7
---------- ----------
INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures (750.3) (673.0)
Proceeds from dispositions 21.2 20.4
Changes in accounts payable and accrued liabilities 27.1 (14.2)
Purchase of investment in Barrett Resources (1,241.4) --
Acquisition of business, net of cash acquired -- (147.7)
Purchases of investments/advances to affiliates (232.0) (90.9)
Proceeds from disposition of investments and other assets 391.4 .9
Other--net 32.2 15.4
---------- ----------
Net cash used by investing activities (1,751.8) (889.1)
---------- ----------
DISCONTINUED OPERATIONS:
Net cash provided (used) by operating activities 7.6 (112.7)
Net cash provided by financing activities 1,343.4 1.4
Net cash used by investing activities (1,448.7) (28.5)
Cash of discontinued operations at spinoff (96.5) --
---------- ----------
Net cash used by discontinued operations (194.2) (139.8)
---------- ----------
Decrease in cash and cash equivalents (196.1) (661.8)
Cash and cash equivalents at beginning of period** 1,210.7 1,081.6
---------- ----------
Cash and cash equivalents at end of period** $ 1,014.6 $ 419.8
========== ==========
</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 $287.7 million at December 31, 2000 and 1999 and
June 30, 2000, respectively.
See accompanying notes.
4
6
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 June 30, 2001, its results of operations for
the three and six months ended June 30, 2001 and 2000, and cash flows for the
six months ended June 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
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 6).
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 under Energy Services. Prior
year segment information has been reclassified to conform to this presentation.
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.
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 three and six months
ended June 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 three and six months ended
June 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 three and six
months ended June 30, 2000, is a $25.9 million guarantee loss accrual. The
accrual results from the decision to discontinue mezzanine lending services and
represents the estimated liability associated with guarantees of third-party
lending activities.
5
7
Notes (Continued)
4. Barrett acquisition
Through a series of transactions, Williams acquired all of the
outstanding stock of Barrett Resources Corporation, 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. 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. 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.
At June 30, 2001, Williams' 50 percent ownership in Barrett is recorded
as an equity method investment and is included in investments in Williams'
Consolidated Balance Sheet. Williams' 50 percent share of Barrett's results of
operations beginning June 11, 2001, as well as amortization of Williams'
investment that is in excess of Williams' underlying equity in Barrett's net
assets, is included in equity earnings within Exploration & Production's
revenues and segment profit in Williams' Consolidated Statement of Income.
Subsequent to the August 2, 2001 acquisition of the remaining 50
percent of Barrett's common stock, Williams' acquisition of Barrett will be
accounted for as a purchase business combination.
5. Provision for income taxes
The provision (benefit) for income taxes includes:
<Table>
<Caption>
Three months ended Six months ended
(Millions) June 30, June 30,
------------------- ------------------
2001 2000 2001 2000
------- ------- ------- -------
Current:
Federal $ 104.7 $ 20.2 $ 194.0 $ 95.1
State 20.8 5.0 35.1 18.5
Foreign -- (4.2) 6.3 (.9)
------- ------- ------- -------
125.5 21.0 235.4 112.7
Deferred:
Federal 84.4 155.3 203.1 141.1
State 4.2 17.7 15.9 41.7
Foreign 2.9 (11.4) 2.2 (12.6)
------- ------- ------- -------
91.5 161.6 221.2 170.2
------- ------- ------- -------
Total provision $217.0 $182.6 $ 456.6 $ 282.9
======= ======= ======= =======
</Table>
The effective income tax rate for the three and six months ended June
30, 2001 and 2000, is greater than the federal statutory rate due primarily to
the effect of state income taxes.
6. 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 and had a carrying value of approximately $96 million
and an estimated fair value of $63 million at June 30, 2001. Additionally,
receivables include amounts due from WCG of approximately $109 million at June
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 issue Williams' equity in the event of
WCG's default, or 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. WCG however, is obligated to reimburse Williams for any
payment Williams is required to make in connection with these notes. Williams is
also considering the purchase from WCG of its headquarters building currently
under construction, and would enter into a long-term lease arrangement with WCG
being the sole occupant of the building.
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 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>
Six
Period Three months
ending months ended ended
(Millions) April 23, June 30, June 30,
2001 2000 2000
--------- --------- ---------
Revenues $ 329.5 $ 175.3 $ 335.6
Income (loss) from operations:
Income (loss) before income
taxes (271.3) 120.1 76.4
(Provision) benefit for
income taxes 92.2 (54.7) (28.6)
Cumulative effect of
change in accounting
principle -- -- (21.6)
--------- --------- ---------
Total income (loss)
from discontinued
operations $ (179.1) $ 65.4 $ 26.2
========= ========= =========
</Table>
6
8
Notes (Continued)
7. Earnings per share
Basic and diluted earnings per common share are computed as follows:
<Table>
<Caption>
(Dollars in millions, except Three Six
per-share amounts; shares months ended months ended
in thousands) June 30, June 30,
--------------------------- ---------------------------
2001 2000 2001 2000
------------ ------------ ------------ ------------
Income from continuing
operations for basic
and diluted earnings
per share $ 339.5 $ 286.4 $ 717.8 $ 425.3
============ ============ ============ ============
Basic weighted-average
shares 487,211 443,778 483,173 443,331
Effect of dilutive securities:
Stock options 4,487 4,839 4,354 5,030
------------ ------------ ------------ ------------
Diluted weighted-average
shares 491,698 448,617 487,527 448,361
============ ============ ============ ============
Earnings per common share
from continuing
operations:
Basic $ .70 $ .64 $ 1.48 $ .96
Diluted $ .69 $ .63 $ 1.47 $ .95
============ ============ ============ ============
</Table>
8. Inventories
<Table>
<Caption>
June 30, December 31,
(Millions) 2001 2000
------------- -------------
Raw materials:
Crude oil $ 103.9 $ 70.0
Other 1.4 1.6
------------- -------------
105.3 71.6
Finished goods:
Refined products 217.7 269.6
Natural gas liquids 100.6 200.2
General merchandise 7.2 12.5
------------- -------------
325.5 482.3
Materials and supplies 127.2 122.9
Natural gas in underground storage 191.8 169.0
Other 1.5 2.6
------------- -------------
$ 751.3 $ 848.4
============= =============
</Table>
9. Debt and banking arrangements
Notes payable
Williams has a $1.7 billion commercial paper program backed by a
short-term bank-credit facility. At June 30, 2001, $35 million of commercial
paper was outstanding under the program. Interest rates vary with current market
conditions. Subsequent to June 30, 2001, the commercial paper program and
related short-term bank-credit facility were increased to $2.2 billion.
In June 2001, Williams entered into a $200 million short-term debt
obligation expiring June 2002. The interest rate varies with current market
conditions and was 4.6 percent at June 30, 2001.
In connection with the cash portion of the Barrett acquisition,
Williams entered into a $1.5 billion short-term credit agreement expiring
November 2001 (Note 4). At June 30, 2001, $1.2 billion was borrowed under this
agreement. The interest rate varies with current market conditions and was 4.9
percent at June 30, 2001. Williams expects to replace this credit agreement with
long-term financing before the end of 2001.
7
9
Notes (Continued)
Debt
<Table>
<Caption>
Weighted-
average
interest June 30, December 31,
(Millions) rate* 2001 2000
---------- ---------- ----------
Revolving credit loans 5.0% $ 29.6 $ 350.0
Debentures, 6.25% -10.25%,
payable 2003 - 2031 (1) 7.1 1,759.3 1,103.5
Notes, 5.1% - 9.45%,
payable through 2031 (2) 7.1 5,395.2 4,856.8
Notes, adjustable rate,
payable through 2004 4.9 1,355.9 2,080.4
Other, payable through 2009 6.6 66.4 73.9
---------- ---------- ----------
8,606.4 8,464.6
Current portion of long-term debt (1,623.2) (1,634.1)
---------- ----------
$ 6,983.2 $ 6,830.5
========== ==========
</Table>
* At June 30, 2001, including the effects of interest-rate swaps.
(1) $200 million, 7.08% debentures, payable 2026, are subject to redemption at
par at the option of the debtholder in 2001. $192.5 million was redeemed in
July 2001.
(2) $240 million, 6.125% notes, payable 2012, are subject to redemption at par
at the option of the debtholder in 2002.
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.
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.
In June 2001, Williams issued $480 million of 7.75 percent notes due
2031.
10. 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
$17 million and $66 million of net after-tax losses reclassified for the three
and six months ended June 30, 2001, respectively) offsetting net gains expected
to be realized in earnings from favorable market movements associated with the
underlying transactions being hedged.
11. Contingent liabilities and commitments
Rate and regulatory matters and related litigation
Williams' interstate pipeline subsidiaries have various regulatory
proceedings pending. As a result of rulings in certain of these proceedings, a
portion of the revenues of these subsidiaries has been collected subject to
refund. The natural gas pipeline subsidiaries have accrued approximately $50
million for potential refund as of June 30, 2001.
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
8
10
Notes (Continued)
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 in 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 multiparty 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 Commission that, with
some variations, recommends applying the methodology of the June 19 order to
determine refunds for prior periods.
On July 25, 2001, the Commission 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
9
11
Notes (Continued)
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.
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 June 30,
2001, these subsidiaries had accrued liabilities totaling approximately $35
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 June 30, 2001, Central had
accrued a liability for approximately $10 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 $35 million liability
mentioned above. Actual costs incurred will depend on the actual number of
contaminated sites identified, the actual amount and extent of contamination
discovered, the final cleanup standards mandated by the EPA and other
governmental authorities and other factors. 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 and Transcontinental Gas Pipe
Line are discussing a settlement. While no specific amount was proposed, the DOJ
stated that any settlement must include an appropriate civil penalty for the
alleged violations. Transcontinental Gas Pipe Line cannot reasonably estimate
the amount of its potential liability, if any, at this time. 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 June 30, 2001, WES and its subsidiaries had
accrued liabilities totaling approximately $40 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 June 30, 2001, WES and its
subsidiaries had accrued receivables totaling $3 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
10
12
Notes (Continued)
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 June 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.
Other legal matters
In connection with agreements to resolve take-or-pay and other contract
claims and to amend gas purchase contracts, Transcontinental Gas Pipe Line and
Texas Gas each entered into certain settlements with producers which may require
the indemnification of certain claims for additional royalties which the
producers may be required to pay as a result of such settlements. As a result of
such settlements, Transcontinental Gas Pipe Line is currently defending two
lawsuits brought by producers. In 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 June 30,
2001, post judgement interest was approximately $9.0 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 case, a producer has
asserted damages, including interest calculated through June 30, 2001, of $9.2
million. In August 2000, a producer asserted a claim for approximately $6.7
million against Transcontinental Gas Pipe Line. 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 other defendants in filing at least
two dispositive motions, along with contesting class certification in the next
several months.
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 Williams Gas Pipelines
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,
11
13
Notes (Continued)
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. Neither
Williams Energy Marketing & Trading nor the named individuals has been served.
This case has been consolidated with the class actions.
On May 17, 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 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 June 30, 2001, annual estimated committed
payments under these contracts range from approximately $20 million to $424
million, resulting in total committed payments over the next 21 years of
approximately $7 billion.
12
14
Notes (Continued)
12. 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.
13. 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. Comprehensive income
Comprehensive income is as follows:
<Table>
<Caption>
Three Six
months ended months ended
(Millions) June 30, June 30,
---------------------- ----------------------
2001 2000 2001 2000
--------- --------- --------- ---------
Net income $ 339.5 $ 351.8 $ 538.7 $ 451.5
Other comprehensive income (loss):
Unrealized gains (losses)
on securities 33.5 222.9 (53.2) 363.5
Realized gains on securities
in net income (.1) (251.3) (20.7) (282.8)
Cumulative effect of a
change in accounting for
derivative instruments -- -- (153.4) --
Unrealized gains on derivative
instruments 442.4 -- 457.1 --
Net reclassification into
earnings of derivative
instrument losses 36.5 -- 45.7 --
Foreign currency
translation adjustments 7.4 (10.4) (24.4) (15.5)
--------- --------- --------- ---------
Other comprehensive
income (loss) before taxes
and minority interest 519.7 (38.8) 251.1 65.2
Income tax benefit (provision)
on other comprehensive
income (loss) (191.4) 11.2 (100.1) (31.2)
Minority interest in other
comprehensive income
(loss) (2.5) 6.1 10.0 (2.9)
--------- --------- --------- ---------
Other comprehensive income
(loss) 325.8 (21.5) 161.0 31.1
--------- --------- --------- ---------
Comprehensive income $ 665.3 $ 330.3 $ 699.7 $ 482.6
========= ========= ========= =========
</Table>
Components of other comprehensive income (loss) before minority
interest and taxes related to discontinued operations are as follows:
<Table>
<Caption>
Three Six
months ended months ended
(Millions) June 30, June 30,
---------------------- ----------------------
2001 2000 2001 2000
--------- --------- --------- ---------
Unrealized gains (losses) on $ 34.5 $ 199.3 $ (56.2) $ 339.9
securities
Realized gains on securities in (.1) (251.3) (20.7) (282.8)
net income
Foreign currency translation
adjustments (2.7) (9.6) (22.1) (14.9)
--------- --------- --------- ---------
Other comprehensive income
(loss) before minority interest
and taxes related to discontinued
operations $ 31.7 $ (61.6) $ (99.0) $ 42.2
========= ========= ========= =========
</Table>
13
15
Notes (Continued)
15. 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 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 15 and 16:
<Table>
<Caption>
Three months ended Six months ended
(Millions) June 30, June 30,
---------------------- -----------------------
2001 2000 2001 2000
--------- --------- --------- ---------
Segment profit:
Gas Pipeline $ 207.0 $ 215.2 $ 411.0 $ 412.5
Energy Services 524.8 413.5 1,125.3 621.8
Other 4.1 3.4 8.9 6.3
--------- --------- --------- ---------
Total 735.9 632.1 1,545.2 1,040.6
--------- --------- --------- ---------
General corporate
expenses (27.0) (23.7) (56.4) (47.1)
--------- --------- --------- ---------
Operating income $ 708.9 $ 608.4 $ 1,488.8 $ 993.5
========= ========= ========= =========
</Table>
14
16
Notes (Continued)
15. Segment disclosures (continued)
<Table>
<Caption>
Revenues
-------------------------------------------------------- -------------
External Inter- Equity Earnings Segment
(Millions) Customers segment (Losses) Total Profit (Loss)
----------- ----------- --------------- ----------- -------------
FOR THE THREE MONTHS ENDED JUNE 30, 2001
GAS PIPELINE $ 394.7 $ 10.7 $ 10.1 $ 415.5 $ 207.0
ENERGY SERVICES
Energy Marketing & Trading 539.5 (135.8)* (.9) 402.8 273.2
Exploration & Production 10.2 86.5 5.9 102.6 40.3
International 27.9 -- 4.0 31.9 3.5
Midstream Gas & Liquids 331.9 153.3 (5.4) 479.8 40.8
Petroleum Services 1,474.0 78.0 .2 1,552.2 160.2
Williams Energy Partners 18.1 3.6 -- 21.7 6.9
Merger-related costs and
non-compete amortization -- -- -- -- (.1)
----------- ----------- ----------- ----------- -----------
TOTAL ENERGY SERVICES 2,401.6 185.6 3.8 2,591.0 524.8
----------- ----------- ----------- ----------- -----------
OTHER 10.8 10.2 (.4) 20.6 4.1
ELIMINATIONS -- (206.5) -- (206.5) --
----------- ----------- ----------- ----------- -----------
TOTAL $ 2,807.1 $ -- $ 13.5 $ 2,820.6 $ 735.9
=========== =========== =========== =========== ===========
FOR THE THREE MONTHS ENDED JUNE 30, 2000
GAS PIPELINE $ 471.3 $ 14.3 $ 6.4 $ 492.0 $ 215.2
ENERGY SERVICES
Energy Marketing & Trading 611.7 (158.2)* .1 453.6 272.6
Exploration & Production 16.5 55.2 -- 71.7 10.0
International 16.4 -- .1 16.5 1.7
Midstream Gas & Liquids 164.8 157.7 (.8) 321.7 71.1
Petroleum Services 1,043.3 35.6 (.2) 1,078.7 57.0
Williams Energy Partners 12.7 4.9 -- 17.6 2.6
Merger-related costs and
non-compete amortization -- -- -- -- (1.5)
----------- ----------- ----------- ----------- -----------
TOTAL ENERGY SERVICES 1,865.4 95.2 (.8) 1,959.8 413.5
----------- ----------- ----------- ----------- -----------
OTHER 7.4 9.6 -- 17.0 3.4
ELIMINATIONS -- (119.1) -- (119.1) --
----------- ----------- ----------- ----------- -----------
TOTAL $ 2,344.1 $ -- $ 5.6 $ 2,349.7 $ 632.1
=========== =========== =========== =========== ===========
</Table>
*Energy Marketing & Trading intercompany cost of sales, which are netted in
revenues consistent with fair-value accounting, exceed intercompany revenue.
15
17
Notes (Continued)
15. Segment disclosures (continued)
<Table>
<Caption>
Revenues
------------------------------------------------------------
External Inter- Equity Earnings Segment
(Millions) Customers segment (Losses) Total Profit (Loss)
- ---------- --------- --------- -------------- --------- -------------
FOR THE SIX MONTHS ENDED JUNE 30, 2001
GAS PIPELINE $ 848.5 $ 17.4 $ 18.2 $ 884.1 $ 411.0
ENERGY SERVICES
Energy Marketing & Trading 1,360.7 (300.0)* 1.7 1,062.4 757.7
Exploration & Production 19.1 211.8 5.9 236.8 90.9
International 51.1 -- (1.1) 50.0 (5.0)
Midstream Gas & Liquids 770.0 320.5 (12.7) 1,077.8 78.6
Petroleum Services 2,793.6 172.2 .1 2,965.9 192.3
Williams Energy Partners 34.3 7.7 -- 42.0 12.3
Merger-related costs and
non-compete amortization -- -- -- -- (1.5)
-------- -------- -------- -------- --------
TOTAL ENERGY SERVICES 5,028.8 412.2 (6.1) 5,434.9 1,125.3
-------- -------- -------- -------- --------
OTHER 19.6 19.9 (.4) 39.1 8.9
ELIMINATIONS -- (449.5) -- (449.5) --
-------- -------- -------- -------- --------
TOTAL $5,896.9 $ -- $ 11.7 $5,908.6 $1,545.2
======== ======== ======== ======== ========
FOR THE SIX MONTHS ENDED JUNE 30, 2000
GAS PIPELINE $ 932.1 $ 28.9 $ 12.3 $ 973.3 $ 412.5
ENERGY SERVICES
Energy Marketing & Trading 903.4 (293.5)* .1 610.0 350.4
Exploration & Production 24.4 103.1 -- 127.5 21.4
International 33.0 -- .5 33.5 5.0
Midstream Gas & Liquids 333.5 312.4 .2 646.1 153.6
Petroleum Services 1,969.6 77.2 (.2) 2,046.6 85.9
Williams Energy Partners 25.9 9.4 -- 35.3 9.7
Merger-related costs and
non-compete amortization -- -- -- -- (4.2)
-------- -------- -------- -------- --------
TOTAL ENERGY SERVICES 3,289.8 208.6 .6 3,499.0 621.8
-------- -------- -------- -------- --------
OTHER 14.2 19.1 -- 33.3 6.3
ELIMINATIONS -- (256.6) -- (256.6) --
-------- -------- -------- -------- --------
TOTAL $4,236.1 $ -- $ 12.9 $4,249.0 $1,040.6
======== ======== ======== ======== ========
</Table>
<Table>
<Caption>
TOTAL ASSETS
-------------------------------
(Millions) June 30, 2001 December 31, 2000
- ---------- ------------- -----------------
GAS PIPELINE $ 8,985.4 $ 8,956.2
ENERGY SERVICES
Energy Marketing & Trading 13,541.9 14,609.7
Exploration & Production 2,133.4 671.5
International 2,263.3 2,214.4
Midstream Gas & Liquids 4,303.4 4,293.5
Petroleum Services 2,912.2 2,666.5
Williams Energy Partners 404.3 349.8
---------- ----------
TOTAL ENERGY SERVICES 25,558.5 24,805.4
---------- ----------
OTHER 5,830.3 7,019.9
ELIMINATIONS (6,748.5) (8,156.1)
---------- ----------
33,625.7 32,625.4
NET ASSETS OF DISCONTINUED OPERATIONS -- 2,290.2
---------- ----------
TOTAL $ 33,625.7 $ 34,915.6
========== ==========
</Table>
*Energy Marketing & Trading intercompany cost of sales, which are netted in
revenues consistent with fair-value accounting, exceed intercompany revenue.
16
18
Notes (Continued)
16. 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,
intangible assets with indefinite useful lives and goodwill 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. The effect of
these standards on Williams' results of operations and financial position is
being evaluated.
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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 6 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
SECOND QUARTER 2001 VS. SECOND QUARTER 2000
Williams' revenues increased $470.9 million, or 20 percent, due primarily to
higher petroleum products and natural gas sales prices and volumes, revenues
from Canadian operations acquired in fourth-quarter 2000 and the $163 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 the effect of a $64 million
reduction of Gas Pipeline's rate refund liabilities in 2000.
Segment costs and expenses increased $367.1 million, or 21 percent, due
primarily to higher costs related to increased petroleum products average per
unit costs and higher related volumes, costs associated with Canadian operations
acquired in fourth-quarter 2000 and the impact of reporting certain sales
activity costs net with related revenues in 2000.
Operating income increased $100.5 million, or 17 percent, due primarily to
the $72.1 million pre-tax gain on the sale of the convenience stores in May
2001, higher margins at refining and marketing operations, higher realized
average natural gas sales prices from production and marketing activities, $27.5
million gain on sale of limited partnership interests at Gas Pipeline and the
$25.9 million effect in 2000 of the guarantee loss accrual at Energy Marketing &
Trading. These increases were partially offset by the $64 million effect in 2000
of rate refund liability reductions, lower per unit natural gas liquids margins
and volumes and a $10.9 million impairment charge at Midstream Gas & Liquids.
Income from continuing operations before income taxes increased $87.5
million from $469.0 million in 2000 to $556.5 million in 2001, due primarily to
$100.5 million higher operating income. Partially offsetting the higher
operating income is $17.2 million higher net interest expense reflecting
increased debt in support of continued expansion and new projects.
GAS PIPELINES
GAS PIPELINE'S revenues decreased $76.5 million, or 16 percent, due
primarily to the effect of a $64 million reduction of rate refund liabilities in
2000 following the settlement of prior rate proceedings and $21 million lower
gas exchange imbalance settlements (offset in costs and operating expenses).
Partially offsetting these decreases were $4 million higher revenues from a
liquefied natural gas storage facility acquired in June 2000 and $4 million
higher equity investment earnings from pipeline joint venture projects.
Costs and expenses decreased $37.9 million, or 17 percent, due primarily to
the $21 million lower gas exchange imbalance settlements and $15 million
resulting from the FERC's approval for recovery from customers of fuel costs
incurred in prior periods by Transco.
Other (income) expense-net for the three months ended June 30, 2001, within
segment costs and expenses includes a $27.5 million pre-tax gain from the sale
of Williams' limited partnership interest in Northern Border Partners, L.P.
Segment profit decreased $8.2 million, or 4 percent, due primarily to the
lower revenues discussed previously, partially offset by the lower segment costs
and expenses and the $27.5 million pre-tax gain.
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
ENERGY MARKETING & TRADING'S revenues decreased $50.8 million, or 11
percent, due to a $26 million decrease in trading revenues and a $25 million
decrease in non-trading revenues. The $26 million decrease in trading revenues
is due primarily
18
20
Management's Discussion & Analysis (Continued)
to $25 million lower gas and electric power services margins and $11 million
lower crude and refined trading margins partially offset by $10 million higher
natural gas liquids margins. The lower gas and electric power services margins
reflect net unfavorable changes in the overall fair value of the gas and
electric power portfolio resulting from lower margins on additional price risk
management services as compared to last year, partially offset by favorable
results from proprietary trading activities around existing portfolio positions.
Approximately 1,100 megawatts of notional volumes in the southeast and western
regions of the United States were added in 2001 to Energy Marketing & Trading
through price risk management services offered through structured transactions.
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 lower crude and refined margins and higher natural
gas liquids margins result from price movements in relation to current trading
positions.
The $25 million decrease in non-trading revenues is due primarily to $31
million lower natural gas liquids revenues from lower sales prices.
Costs and operating expenses decreased $24 million, or 28 percent, due
primarily to $22 million lower natural gas liquids costs. This variance is
associated with the corresponding change in non-trading revenues discussed
above.
Other (income) expense - net in 2000 includes a $25.9 million guarantee loss
accrual (see Note 3) and a $12.4 million gain on the sale of certain natural gas
liquids contracts.
Segment profit of $273.2 million in 2001 is comparable to the $272.6 million
of segment profit in 2000. Decreases attributable to $26 million lower trading
revenues discussed above and $9 million lower margins from non-trading natural
gas liquids operations were partially offset by a $14 million decrease in
selling, general and administrative expenses and the impact in 2000 of the $25.9
million guarantee loss accrual and the $12.4 million gain on sale of certain
natural gas liquids contracts. The lower selling, general and administrative
costs reflect lower variable compensation levels associated with the decrease in
operating profit for the quarter.
CALIFORNIA
At June 30, 2001, Energy Marketing & Trading had net accounts receivable of
approximately $302 million for power sales to the California Independent Service
Operator (ISO) and the California Power Exchange Corporation (CPEC). While the
amount recorded reflects management's best estimate of collectibility, future
events or circumstances could change those estimates. 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. In addition,
Southern California Edison (SCE) has engaged in talks with the State of
California regarding various arrangements that could prevent its bankruptcy.
Williams does not believe its credit exposure to these bankruptcies and
potential bankruptcy will result in a material adverse effect on its results of
operations or financial condition.
The prices that Williams charges for power 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 this period 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 parties 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
19
21
Management's Discussion & Analysis (Continued)
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 regarding refunds for past periods that concluded without
resolution of the issues. Absent settlement, the presiding administrative law
judge issued a report to the Commission that, with some variations, recommends
applying the methodology of the June 19 order to determine refunds for prior
periods. On July 25, 2001, the Commission 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, 2000. 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 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 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 Note 11). 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. 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.
EXPLORATION & PRODUCTION'S revenues increased $30.9 million, or 43 percent,
due primarily to $18 million from increased realized average natural gas sales
prices (including the effect of hedge positions) and $5 million associated with
an increase in volumes from production and marketing activities. Approximately
66 percent of production in second-quarter 2001 was hedged. In addition,
revenues increased $5.9 million from equity earnings from the 50 percent
investment in Barrett Resources Corporation acquired in June 2001 (see Note 4
for further discussion of the Barrett acquisition).
Segment profit increased $30.3 million, to $40.3 million in 2001 from $10
million in 2000, due primarily to the higher revenues discussed previously.
INTERNATIONAL'S revenues increased $15.4 million, from $16.5 million in
2000. The increase is attributable to $7.3 million of revenue from Colorado soda
ash production which began in October 2000, $2.6 million higher Venezuelan gas
compression revenues, and $1.1 million from increased operating fees due to
increased volumes at a Venezuelan crude oil storage and shiploading terminal.
Equity earnings from the Lithuanian refinery, pipeline and terminal investment
increased $4.1 million, from an equity loss of $2.7 million in 2000, due to
higher volumes and better product mix and purchase costs.
20
22
Management's Discussion & Analysis (Continued)
Operating costs increased $14.8 million primarily due to soda ash production
which began operation in October 2000.
Segment profit increased $1.8 million, from $1.7 million in 2000, due
primarily to the higher revenues discussed above and $1.1 million lower general
and administrative costs offset by the $14.8 million increase in operating
costs.
MIDSTREAM GAS & LIQUIDS' revenues increased $158.1 million, or 49 percent,
due primarily to $182 million in revenues from Canadian operations acquired in
October 2000. The $182 million of revenues from Canadian operations consist
primarily of $84 million of natural gas liquids sales from processing
activities, $61 million of natural gas liquids sales from fractionation
activities and $35 million of processing revenues. Domestic natural gas liquids
revenues decreased $29 million, reflecting a $33 million decrease from 27
percent decrease in domestic liquids volumes sold, partially offset by $4
million increase due to higher average domestic natural gas liquids sales
prices.
Costs and operating expenses increased $181 million to $400 million in
second-quarter 2001, due primarily to $182 million of costs and operating
expenses related to the Canadian operations. Higher domestic maintenance,
depreciation and power costs were offset by lower product costs related to
natural gas liquids sales and lower operating costs.
General and administrative expenses decreased $5 million, or 16 percent, due
primarily to lower compensation expense and the absence of costs related to last
year's reorganization.
Included in other (income) expense-net within segment costs and expenses for
2001 is a $10.9 million impairment loss related to management's second-quarter
2001 decision and commitment to sell certain south Texas non-regulated gathering
and processing assets. The $10.9 million charge represents the impairment of the
assets to fair value based on expected proceeds from the sale.
Segment profit decreased $30.3 million, or 43 percent due primarily to $10
million from decreased domestic natural gas liquids volumes sold, $9 million
from lower average domestic per-unit natural gas liquids margins and the $10.9
million impairment loss discussed above.
PETROLEUM SERVICES' revenues increased $473.5 million, or 44 percent, due
primarily to $322 million higher refining and marketing revenues (excluding a
$26 million increase to revenues due to lower intra-segment sales to the travel
center/convenience stores which are eliminated) and $71 million higher 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 is 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 and
Trading's revenue for the three months ended June 30, 2000 includes
approximately $163 million for both the sales and cost of sales related to this
activity. The $322 million increase in refining and marketing revenues includes
the $163 million impact previously discussed, $125 million from a 14 percent
increase in refined product volumes sold and $34 million from three percent
higher average refined product sales prices. The $71 million increase in travel
center/convenience store sales reflects $78 million from a 55 percent increase
in diesel sales volumes, $11 million from four percent higher average gasoline
and diesel sales prices, partially offset by $16 million from 13 percent
decrease in gasoline sales volumes and $2 million lower merchandise sales. The
increase in diesel sales volumes is partly due to a higher number of travel
centers in 2001. In addition, revenues increased due to $40 million higher
bio-energy sales reflecting an increase in ethanol volumes sold and average
ethanol sales prices and $11 million higher revenues from Williams' 3.1 percent
undivided interest in Trans Alaska Pipeline System (TAPS) acquired in late June
2000. Partially offsetting these increases were $7 million lower fleet
management revenues.
Costs and operating expenses increased $445.4 million, or 45 percent, due
primarily to $295 million higher refining costs and $79 million higher travel
center/convenience store costs (excluding a $26 million increase due to lower
intra-segment purchases from the refineries which are eliminated). The $295
million increase in refining and marketing costs includes the $163 million
impact of the transfer of management from Energy Marketing & Trading to
Petroleum Services discussed above, $113 million associated with increased
volumes sold through refining and marketing operations, $10 million from higher
crude supply costs and other related per-unit cost of sales, and $9 million
higher other operating costs at the refinery. The $79 million increase in travel
center/convenience store costs is primarily from $75 million increased diesel
sales volumes, $12 million higher average diesel and gasoline purchase prices,
$5 million higher store operating costs and $2 million higher merchandise costs,
partially offset by $15 million due to decreased gasoline volumes sold. In
addition, costs and operating expenses increased due to $29 million higher
bio-energy product and operating costs and $5 million higher costs from
Williams' 3.1 percent undivided interest in TAPS.
21
23
Management's Discussion & Analysis (Continued)
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 of Memphis and Nashville.
Revenues related to the stores which were sold approximated $77 million and $121
million for 2001 and 2000, respectively.
Segment profit increased $103.2 million, to $160.2 million in 2001 from
$57.0 million in 2000 due primarily to the $72.1 million gain on the sale of
convenience stores and $27 million from refining and marketing operations. The
refining and marketing operations increase was due primarily to $24 million
higher margins and $12 million due to higher refining and marketing volumes
sold, partially offset by $9 million higher other operating costs at the
refineries. In addition, segment profit increased due to $6 million from
Williams' interest in TAPS acquired in late June 2000.
WILLIAMS ENERGY PARTNERS' revenue increased $4.1 million from $17.6 million
to $21.7 million and segment profit increased $4.3 million from $2.6 million to
$6.9 million, due primarily to acquisition of the Wyatt terminal facilities
acquired in September 2000 and additional ammonia pipeline revenues.
CONSOLIDATED
INTEREST ACCRUED increased $13.8 million, or 9 percent, due primarily to a
$9 million increase in interest expense on rate refunds reflecting the effect in
2000 of an $11.2 million reduction to interest accruals related to Gas
Pipeline's rate refund liabilities reductions in 2000 and a $4 million increase
related to interest on deposits received from customers relating to energy
trading and hedging activities. Slightly higher borrowing levels resulted in a
$5 million increase to interest expense, however, the increase was largely
offset by the effect of lower average interest rates. Investing income increased
$5.7 million, or 36 percent, due primarily to interest income on margin deposits
of $8 million, partially offset by a decrease in dividend income of $4 million
due to the sale of Ferrellgas Senior common units in second-quarter 2001.
Minority interest in income and preferred returns of consolidated subsidiaries
increased $6.5 million, or 47 percent, due primarily to preferred returns of
Snow Goose LLC, formed in December 2000 offset by a $3 million decrease related
to Williams obligated mandatorily redeemable preferred securities of Trust which
were redeemed by Williams in second-quarter 2001.
The provision for income taxes increased $34.4 million, or 19 percent,
primarily as a result of higher pre-tax income. The effective income tax rates
for 2001 and 2000 are greater than the federal statutory rate due primarily to
the effects of state income taxes.
SIX MONTHS ENDED JUNE 30, 2001 VS. SIX MONTHS ENDED JUNE 30, 2000
CONSOLIDATED OVERVIEW
Williams' revenues increased $1,659.6 million, or 39 percent, due primarily
to higher gas and electric power services, revenues from Canadian operations
acquired in fourth-quarter 2000, higher petroleum products and natural gas sales
prices and volumes and the $316 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 the effect in 2000 of a $71 million reduction of Gas Pipeline's
rate refund liabilities.
Segment costs and expenses increased $1,155 million, or 36 percent, due
primarily to higher costs related to increased petroleum products average prices
and volumes, costs associated with Canadian operations acquired in
fourth-quarter 2000 and the impact of reporting certain sales activity costs net
with related revenues in 2000 (discussed above). Partially offsetting these
increases was a $72.1 million gain on the sale of certain convenience stores.
Operating income increased $495.3 million, or 50 percent, due primarily to
higher gas and electric power services 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, $27.5
million pre-tax gain on sale of limited partnership interests at Gas Pipeline
and the effect in 2000 of a $25.9 million guarantee loss accrual at Energy
Marketing & Trading. Partially offsetting these increases was lower per-unit
natural gas liquids margins and the $71 million effect in 2000 of rate refund
liabilities and approximately $22 million of impairment charges within Energy
Services.
Income from continuing operations before income taxes increased $466.2
million from $708.2 million in 2000 to $1,174.4 million in 2001, due primarily
to $495.3 million higher operating income and $21 million higher investing
income primarily from interest on margin deposits. Partially offsetting the
increases are $38.1 million higher net interest expense reflecting increased
debt in support of continued expansion and new projects and $17.6 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.
22
24
Management's Discussion & Analysis (Continued)
GAS PIPELINE
GAS PIPELINE'S revenues decreased $89.2 million, or 9 percent, due primarily
to the effect of a $71 million reduction of rate refund liabilities in 2000
following the settlement of prior rate proceedings and $39 million lower gas
exchange imbalance settlements (offset in costs and operating expenses).
Partially offsetting these decreases were $8 million higher revenues from a
liquefied natural gas storage facility acquired in June 2000, $6 million higher
equity investment earnings from pipeline joint venture projects and $4 million
higher transportation demand revenues at Transco.
Costs and expenses decreased $47 million, or 11 percent, due primarily to
the $39 million lower gas exchange imbalance settlements (offset in revenues)
and $15 million resulting from the FERC's approval for recovery from customers
of fuel costs incurred in prior periods by Transco. Offsetting these decreases
to cost and expenses was $12 million in higher depreciation expense due to
increased property, plant & equipment.
Other (income) expense-net for the six months ended June 30, 2001, within
segment costs and expenses 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 gain from an insurance settlement in 2001 for storage gas losses.
Segment profit decreased $1.5 million, due primarily to the lower revenues
discussed previously, partially offset by lower costs and expenses, the $27.5
million pre-tax gain on the sale of limited partner interests and $12 million
lower general and administrative expenses. The lower general and administrative
costs result primarily from the 2000 headquarters consolidation of two of the
gas pipelines, lower tracked costs which are passed through to customers and
lower employee benefits costs.
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
ENERGY MARKETING & TRADING'S revenues increased $452.4 million, or 74
percent, due to a $461 million increase in trading revenues offset by a $9
million decrease in non-trading revenues. The $461 million increase in trading
revenues is due primarily to $481 million higher gas and electric power services
margins and $14 million increased natural gas liquids margins slightly offset by
$34 million lower crude and refined trading margins. The higher gas and electric
power 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. In addition, the
increased gas and electric power 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 $9 million decrease in non-trading revenues is due primarily to $21
million lower natural gas liquids revenues resulting from lower sales prices
partially offset by $10 million higher non-trading power services revenues.
Costs and operating expenses increased $8 million, or 6 percent, due
primarily to 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 a $25.9 million guarantee loss
accrual (see Note 3) and a $12.4 million gain on the sale of certain natural gas
liquids contracts.
Segment profit increased $407.3 million, from $350.4 million in 2000 to
$757.7 million in 2001, due primarily to the $481 million higher gas and
electric power services margins and the effect of the $25.9 million guarantee
loss accrual in 2000. Partially offsetting the increases were $51 million higher
selling, general and administrative costs, $34 million lower crude and refined
trading margins and $20 million lower margins from non-trading natural gas
liquids operations and the $12.4 million effect of the 2000 gain on sale of
certain natural 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, and start-up of a London trading location.
EXPLORATION & PRODUCTION'S revenues increased $109.3 million, or 86 percent,
due primarily to $83 million from increased realized average natural gas sales
prices (including the effect of hedge positions)
23
25
Management's Discussion & Analysis (Continued)
and $15 million associated with an increase in volumes from production and
marketing activities. Approximately 63 percent of production through
second-quarter 2001 was hedged. Exploration & Production has entered into
contracts that hedge approximately 78 percent of estimated production for the
remainder of the year. At June 30, 2001, the contracted future hedge prices are
in excess of the spot market, resulting in an unrealized gain reflected in other
comprehensive income. In addition, revenues increased $5.9 million from equity
earnings from the 50 percent investment in Barrett Resources Corporation
acquired in June 2001 (see Note 4 for further discussion of Barrett
acquisition).
Segment profit increased $69.5 million, to $90.9 million in 2001 from $21.4
in 2000, due primarily to the higher revenues discussed previously, partially
offset by $21 million higher gas purchase costs related to the marketing of
natural gas from the Williams Coal Seam Royalty Trust and royalty interest
owners, $8 million higher production-related taxes and $8 million higher
operating and maintenance expenses.
INTERNATIONAL'S revenues increased $16.5 million, or 49 percent, from $33.5
million in 2000. The increase is attributable to $11.2 million of revenue from
Colorado soda ash production which began in October 2000, $3.5 million higher
Venezuelan gas compression revenues, and $2.9 million from increased operating
fees due to increased volumes at a Venezuelan crude oil storage and shiploading
terminal. These increases were partially offset by $1.2 million higher equity
losses from the Lithuanian refinery.
Operating costs increased $29.8 million primarily due to soda ash production
which began operation in October 2000.
Segment profit decreased $10 million from segment profit of $5 million in
2000 to a segment loss of $5 million in 2001. The soda ash project had a segment
loss of $16.4 million reflecting initial operations start-up costs. Partially
offsetting the loss from soda ash production were the effects of the higher
Venezuelan revenues discussed above and lower general and administrative costs.
MIDSTREAM GAS & LIQUIDS' revenues increased $431.7 million, or 67 percent,
due primarily to $465 million in revenues from Canadian operations acquired in
October 2000. The $465 million of revenues from Canadian operations consist
primarily of $208 million of natural gas liquids sales from processing
activities, $166 million of natural gas liquids sales from fractionation, and
$87 million of processing revenues. Domestic natural gas liquids revenues
decreased $26 million reflecting a $64 million decrease from a 27 percent
decrease in volumes sold, partially offset by a $38 million increase due to
higher average domestic natural gas liquids sales prices. In addition, equity
method investments had $12.7 million in equity losses during 2001 compared to
equity earnings of $.2 million in 2000.
Costs and operating expenses increased $507 million to $935 million, due
primarily to $465 million of costs and operating expenses related to the
Canadian operations, $44 million higher liquids fuel and replacement gas
purchases, and $10 million higher power costs related to the natural gas liquids
pipeline, partially offset by the effect in 2000 of $12 million of losses
associated with certain propane storage transactions in first-quarter 2000.
General and administrative expenses decreased $16 million, or 24 percent,
due primarily to $12 million of reorganization and early retirement costs
occurring in 2000 and $2 million lower compensation expense.
Included in other (income) expense-net within segment costs and expenses for
2001 is a $10.9 million impairment loss related to management's second-quarter
2001 decision and commitment to sell certain south Texas non-regulated gathering
and processing assets. The $10.9 million charge represents the impairment of the
assets to fair value based on expected proceeds from the sale.
Segment profit decreased $75 million, or 49 percent, due primarily to $43
million from lower average per-unit domestic natural gas liquids margins, $23
million from decreased domestic natural gas liquids volumes sold, $17 million
decrease from natural gas liquids pipeline operations, $13 million from higher
equity investment losses, and $10.9 million due to an impairment loss discussed
above. Partially offsetting these decreases to segment profit were $16 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 $919.3 million, or 45 percent, due
primarily to $636 million higher refining and marketing revenues (excluding a
$61 million increase to revenues due to lower intra-segment sales to the travel
centers/convenience stores which are eliminated) and $145 million higher travel
center/convenience store sales. The $636 million increase in refining and
marketing revenues includes the $316 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,
$157 million from nine percent higher average refined product sales prices and
$163 million resulting from a 10 percent increase in refined product volumes
sold. The $145 million increase in travel center/convenience store sales
reflects $133 million from a 47 percent increase in diesel sales
24
26
Management's Discussion & Analysis (Continued)
volumes, $14 million from two percent higher average gasoline and diesel sales
prices and $6 million higher merchandise sales, partially offset by $8 million
due to a four percent decrease in gasoline volumes sold. In addition, revenues
increased due to $62 million higher bio-energy sales reflecting increases in
ethanol volumes sold and average ethanol sales prices, $22 million higher
revenues from Williams' 3.1 percent undivided interest in TAPS acquired in late
June 2000 and $8 million higher commodity sales from transportation activities.
Slightly offsetting these increases were $8 million lower revenues related to
the petrochemical plant due to a plant turnaround in first quarter 2001.
Costs and operating expenses increased $876 million, or 46 percent, due
primarily to $579 million higher refining costs and $160 million higher travel
center/convenience store costs (excluding a $61 million increase to costs due to
lower intra-segment purchases from the refineries which are eliminated). The
$579 million increase in refining and marketing costs includes the $316 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) and the remaining increase
reflects $105 million from higher crude supply costs and other related per-unit
cost of sales and $148 million associated with increased volumes sold through
refining and marketing operations and $10 million increase in other operating
costs at the refineries. The $160 million increase in travel center/convenience
store costs is primarily from $127 million increased diesel sales volumes, $15
million higher average diesel and gasoline purchase prices, $10 million higher
merchandise costs and $16 million higher store operating costs, partially offset
by $8 million due to decreased gasoline sales volumes. In addition, costs and
operating expenses increased due to $55 million higher bio-energy product and
operating costs, $11 million higher cost of commodity sales from transportation
activities and $10 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 of Memphis and Nashville. Revenues
related to the stores which were sold approximated $182 million and $234 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 $106.4 million, to $192.3 million in 2001 from
$85.9 million in 2000. An increase of $57 million from refining and marketing
operations resulted from $52 million higher refinery gross margins and $15
million higher refinery volumes, partially offset by $10 million higher other
operating costs at the refineries. In addition, segment profit increased $72.1
million from the gain on the sale of convenience stores and $13 million from
Williams' interest in TAPS acquired in late June 2000. Partially offsetting
these increases were an $11 million impairment charge related to an end-to-end
mobile computing systems business, $16 million higher operating costs from the
travel centers/convenience stores and $8 million lower revenues from activities
at the petrochemical plant.
WILLIAMS ENERGY PARTNERS' revenue increased $6.7 million from $35.3 million
to $42 million and segment profit increased $2.6 million from $9.7 million to
$12.3 million, due primarily to acquisition of the Wyatt terminal facilities
acquired in September 2000.
CONSOLIDATED
GENERAL CORPORATE EXPENSES increased $9.3 million, or 20 percent, primarily
due to an increase in outside legal costs and higher compensation levels.
Interest accrued increased $35.2 million, or 11 percent, due primarily to the
$15 million effect of higher borrowing levels combined with the $5 million
effect of higher average interest rates, a $10 million increase in interest
expense related to deposits received from customers relating to energy trading
and hedging activities and a $7 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 senior unsecured
debt securities issued in January 2001. Notes payable includes $1.2 million
borrowed under a $1.5 million short-term credit agreement originated June 2001
which expires November 2001. Investing income increased $20.7 million, or 54
percent, due primarily to interest income on margin deposits. Minority interest
in income and preferred returns of consolidated subsidiaries increased $17.6
million, or 65 percent, due primarily to preferred returns of Snow Goose LLC,
formed in December 2000.
The provision for income taxes increased $173.7 million, or 61 percent,
primarily as a result of higher pre-tax income offset slightly by a decrease in
the effective tax rate. The effective income tax rates for 2001 and 2000 are
greater than the federal statutory rate due primarily to the effects of state
income taxes.
Loss from discontinued operations for the six months ended June 30, 2001,
includes $179.1 million after-tax loss from operations of WCG (see Note 6). The
$26.2 income from operations for the six months ended June 30, 2000 represents
the after-tax income from the operations of WCG.
25
27
Management's Discussion & Analysis (Continued)
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 $830 million at June 30, 2001, as
compared to $854 million at December 31, 2000.
o $700 million available under Williams' $700 million bank-credit facility at
June 30, 2001, as compared to $350 million at December 31, 2000.
o $1.67 billion available under Williams' $1.7 billion commercial paper
program at June 30, 2001, as compared to $4 million at December 31, 2000.
Subsequent to June 30, 2001, the commercial paper program and related
short-term bank-credit facility were increased to $2.2 billion.
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. 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 August 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.
In 2001, capital expenditures and investments, excluding the Barrett
Resources acquisition, are estimated to total approximately $2.3 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,
(6) sale or disposal of existing businesses and/or (7) debt or equity public
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 will retain, 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 6.
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
WCG's default, or 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. WCG, however, is obligated to reimburse Williams for any payment
Williams is required to make in connection with these notes. Additionally,
receivables include amounts due from WCG of approximately $109 million at June
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. Williams is also
considering the purchase from WCG of its
26
28
Management's Discussion & Analysis (Continued)
headquarters building currently under construction, and would enter into a
long-term lease arrangement with WCG being the sole occupant of the building.
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 short-term debt obligation
expiring June 2002. Interest rates are based on the adjusted Eurodollar rate.
The proceeds from these issuances will be used for general corporate purposes.
Additionally, Williams, in advance of the cash tender of Barrett Resource
Corporation, entered into a $1.5 billion short-term credit agreement expiring in
November 2001. At June 30, 2001, approximately $1.2 billion was borrowed under
this agreement at an initial rate of approximately 4.9 percent, based on the
adjusted Eurodollar rate. For further discussion of the Barrett Resources
Corporation, see Note 4.
The long term debt to debt-plus-equity ratio was 54.1 percent at June 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
63.1 percent at June 30, 2001 and 63.9 percent at December 31, 2000 (70.5
percent at December 31, 2000 if WCG debt is 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. At June 30, 2001, this investment was recorded as an
equity method investment and is included in investments in the Consolidated
Balance Sheet. 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.
27
29
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. Additionally,
Williams, in advance of the cash tender of Barrett Resources Corporation,
entered into a $1.5 billion short-term credit agreement expiring in November
2001. At June 30, 2001, approximately $1.2 billion was borrowed under this
agreement at an initial rate of approximately 4.9 percent, based on the adjusted
Eurodollar rate.
COMMODITY PRICE RISK
At June 30, 2001, the value at risk for the trading operations was $74
million compared to $90 million at December 31, 2000. This decrease of
approximately 18 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, 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 June 30, 2001 and December 31, 2000. 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 12 percent and 11 percent of
Williams' net assets at June 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
$137 million at June 30, 2001.
EQUITY PRICE RISK
Williams' exposure to equity price risk was primarily from investments held
by WCG. As a result of the spinoff of WCG, Williams' exposure to equity price
risk as it existed prior to the distribution date was significantly reduced,
however, following the distribution date, Williams will be exposed to potential
impairment valuations with respect to the WCG common stock retained. As of June
30, 2001, the WCG shares retained by Williams had a carrying value of
approximately $96 million and an estimated fair value of $63 million.
28
30
PART II. OTHER INFORMATION
Item 4. Submission of Matters to a Vote of Security Holders
The Annual Meeting of Stockholders of the Company was held on May 17, 2001. At
the Annual Meeting, six individuals were elected as directors of the Company and
eight individuals continue to serve as directors pursuant to their prior
election. In addition, the appointment of Ernst & Young LLP as the independent
auditor of the Company for 2001 was ratified.
A tabulation of the voting at the Annual Meeting with respect to the matters
indicated is as follows:
Election of Directors
<Table>
<Caption>
Name For Withheld
- ---- --- --------
Glenn A. Cox 408,025,196 5,618,349
Thomas H. Cruikshank 405,797,674 7,845,871
Charles M. Lillis 408,104,384 5,539,161
George A. Lorch 407,956,854 5,686,691
Gordon R. Parker 408,094,142 5,549,403
Joseph H. Williams 397,195,772 16,447,773
</Table>
Ratification of Appointment of Independent Auditors
<Table>
<Caption>
For Against Abstain
--- ------- -------
407,843,860 3,577,975 2,221,710
</Table>
Item 6. Exhibits and Reports on Form 8-K
(a) The exhibits listed below are filed as part of this report:
Exhibit 10.1--Form of Limited Waiver and Second Amendment to
Credit Agreement dated as of July 25, 2000 with the
financial institutions from time to time party
thereto, The Chase Manhattan Bank and Commerzbank
AG, as Co-Syndication Agents, Credit Lyonnais New
York Branch, as Documentation Agent, and Citibank,
N.A., as Agent which Credit Agreement has been
amended by a Waiver and First Amendment to Credit
Agreement dated as of January 31, 2001.
Exhibit 12 --Computation of Ratio of Earnings to Fixed Charges
(b) During second-quarter 2001, the Company filed a Form 8-K on April
2, 2001; April 12, 2001; April 27, 2001; May 1, 2001; May 3,
2001; May 7, 2001; May 22, 2001; and June 13, 2001, which
reported significant events under Item 5 of the Form and included
the Exhibits required by Item 7 of the Form.
29
31
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)
Gary R. Belitz
---------------------------------------
Gary R. Belitz
Controller
(Duly Authorized Officer and
Principal Accounting Officer)
August 10, 2001
32
INDEX TO EXHIBITS
<Table>
<Caption>
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
10.1 Form of Limited Waiver and Second Amendment to Credit
Agreement dated as of July 25, 2000 with the financial
institutions from time to time party thereto, The Chase
Manhattan Bank and Commerzbank AG, as Co-Syndication
Agents, Credit Lyonnais New York Branch, as Documentation
Agent, and Citibank, N.A., as Agent which Credit
Agreement has been amended by a Waiver and First
Amendment to Credit Agreement dated as of January 31,
2001.
12 Computation of Ratio of Earnings to Fixed Charges
</Table>