EXHIBIT 99.4
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Stockholders of The Williams Companies, Inc.
We have audited the accompanying consolidated balance sheet of The Williams
Companies, Inc. as of December 31, 2003 and 2002, and the related consolidated
statements of operations, stockholders' equity, and cash flows for each of the
three years in the period ended December 31, 2003. Our audits also included the
financial statement schedule listed in the table of contents at Exhibit 99.4.
These financial statements and schedule are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements and schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the consolidated financial position of The
Williams Companies, Inc. at December 31, 2003 and 2002, and the consolidated
results of its operations and its cash flows for each of the three years in the
period ended December 31, 2003, in conformity with U.S. generally accepted
accounting principles. Also, in our opinion, the related financial statement
schedule, when considered in relation to the basic financial statements taken as
a whole, presents fairly in all material respects, the information set forth
therein.
As explained in Note 1 to the consolidated financial statements, effective
January 1, 2003, the Company adopted Emerging Issues Task Force Issue No. 02-3,
"Issues Related to Accounting for Contracts Involved in Energy Trading and Risk
Management Activities" (see third paragraph of "Energy commodity risk management
and trading activities and revenues" section in Note 1) and Statement of
Financial Accounting Standards No. 143, "Accounting for Asset Retirement
Obligations" (see last paragraph of "Property, plant and equipment" section in
Note 1).
/s/ ERNST & YOUNG LLP
Tulsa, Oklahoma
February 18, 2004, except for the matters described
in the third paragraph of the "Basis of presentation"
section in Note 1 and the second paragraph in Note 2,
as to which the date is September 14, 2004
99.4-1
THE WILLIAMS COMPANIES, INC.
CONSOLIDATED STATEMENT OF OPERATIONS
YEARS ENDED DECEMBER 31,
----------------------------------------------
2003 2002 2001
------------ ----------- -----------
(MILLIONS, EXCEPT PER-SHARE AMOUNTS)
Revenues:
Power ......................................................... $ 13,195.5 $ 56.2 $ 1,705.6
Gas Pipeline .................................................. 1,368.3 1,301.2 1,243.1
Exploration & Production ...................................... 779.7 860.4 603.9
Midstream Gas & Liquids ....................................... 2,778.5 1,143.1 1,155.2
Other ......................................................... 72.0 124.1 319.3
Intercompany eliminations ..................................... (1,549.3) (91.1) (127.6)
------------ ----------- -----------
Total revenues ............................................... 16,644.7 3,393.9 4,899.5
------------ ----------- -----------
Segment costs and expenses:
Costs and operating expenses .................................. 14,989.7 1,934.3 2,111.2
Selling, general and administrative expenses .................. 407.1 564.0 655.5
Other (income) expense -- net ................................. (130.2) 240.1 (12.4)
------------ ----------- -----------
Total segment costs and expenses ............................. 15,266.6 2,738.4 2,754.3
------------ ----------- -----------
General corporate expenses ...................................... 87.0 142.8 124.3
------------ ----------- -----------
Operating income (loss):
Power ......................................................... 145.3 (471.7) 1,294.6
Gas Pipeline .................................................. 539.6 461.3 390.0
Exploration & Production ...................................... 392.5 504.9 217.2
Midstream Gas & Liquids ....................................... 309.4 177.9 183.0
Other ......................................................... (8.7) (16.9) 60.4
General corporate expenses .................................... (87.0) (142.8) (124.3)
------------ ----------- -----------
Total operating income ....................................... 1,291.1 512.7 2,020.9
------------ ----------- -----------
Interest accrued ................................................ (1,286.1) (1,159.4) (691.8)
Interest capitalized ............................................ 45.5 27.3 36.9
Interest rate swap loss ......................................... (2.2) (124.2) -
Investing income (loss) ......................................... 73.1 (113.2) (172.6)
Minority interest in income and preferred returns of consolidated
subsidiaries .................................................. (19.4) (41.8) (71.7)
Other income (expense) -- net ................................... (26.1) 24.3 26.4
------------ ----------- -----------
Income (loss) from continuing operations before income taxes and
cumulative effect of change in accounting principles .......... 75.9 (874.3) 1,148.1
Provision (benefit) for income taxes ............................ 47.7 (277.2) 507.6
------------ ----------- -----------
Income (loss) from continuing operations ........................ 28.2 (597.1) 640.5
Income (loss) from discontinued operations ...................... 240.9 (157.6) (1,118.2)
------------ ----------- -----------
Income (loss) before cumulative effect of change in accounting
principles .................................................... 269.1 (754.7) (477.7)
Cumulative effect of change in accounting principles ............ (761.3) - -
------------ ----------- -----------
Net loss ........................................................ (492.2) (754.7) (477.7)
Preferred stock dividends ....................................... 29.5 90.1 -
------------ ----------- -----------
Loss applicable to common stock ................................. $ (521.7) $ (844.8) $ (477.7)
============ =========== ===========
Basic earnings (loss) per common share:
Income (loss) from continuing operations ...................... $ - $ (1.33) $ 1.29
Income (loss) from discontinued operations .................... .46 (.30) (2.25)
------------ ----------- -----------
Income (loss) before cumulative effect of change in accounting
principles ................................................... .46 (1.63) (.96)
Cumulative effect of change in accounting principles .......... (1.47) - -
------------ ----------- -----------
Net loss ..................................................... $ (1.01) $ (1.63) $ (.96)
============ =========== ===========
Diluted earnings (loss) per common share:
Income (loss) from continuing operations ...................... $ - $ (1.33) $ 1.28
Income (loss) from discontinued operations .................... .46 (.30) (2.23)
------------ ----------- -----------
Income (loss) before cumulative effect of change in accounting
principles ................................................... .46 (1.63) (.95)
Cumulative effect of change in accounting principles .......... (1.47) - -
------------ ----------- -----------
Net loss ..................................................... $ (1.01) $ (1.63) $ (.95)
============ =========== ===========
See accompanying notes.
99.4-2
THE WILLIAMS COMPANIES, INC.
CONSOLIDATED BALANCE SHEET
DECEMBER 31,
------------------------
2003 2002
----------- -----------
(DOLLARS IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
ASSETS
Current assets:
Cash and cash equivalents ........................................................................ $ 2,315.7 $ 1,650.4
Restricted cash .................................................................................. 47.1 102.8
Restricted investments ........................................................................... 93.2 -
Accounts and notes receivable less allowance of $112.2 ($111.8 in 2002) .......................... 1,613.2 2,387.1
Inventories ...................................................................................... 242.9 365.7
Energy risk management and trading assets ........................................................ - 296.7
Derivative assets ................................................................................ 3,166.8 5,024.3
Margin deposits .................................................................................. 553.9 804.8
Assets of discontinued operations ................................................................ 441.3 1,297.3
Deferred income taxes ............................................................................ 106.6 569.2
Other current assets and deferred charges ........................................................ 214.3 387.8
----------- -----------
Total current assets ........................................................................... 8,795.0 12,886.1
Restricted cash .................................................................................... 159.8 188.1
Restricted investments ............................................................................. 288.1 -
Investments ........................................................................................ 1,463.6 1,468.6
Property, plant and equipment -- net ............................................................... 11,734.0 11,698.2
Energy risk management and trading assets .......................................................... - 1,821.6
Derivative assets .................................................................................. 2,495.6 1,865.1
Goodwill ........................................................................................... 1,014.5 1,059.5
Assets of discontinued operations .................................................................. 345.1 3,268.8
Other assets and deferred charges .................................................................. 726.1 732.5
----------- -----------
Total assets ................................................................................... $ 27,021.8 $ 34,988.5
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Notes payable .................................................................................... $ 3.3 $ 996.3
Accounts payable ................................................................................. 1,228.0 1,864.0
Accrued liabilities .............................................................................. 944.4 1,404.5
Liabilities of discontinued operations ........................................................... 95.7 550.2
Energy risk management and trading liabilities ................................................... - 244.4
Derivative liabilities ........................................................................... 3,064.2 5,168.3
Long-term debt due within one year ............................................................... 935.2 1,080.8
--------- -----------
Total current liabilities ...................................................................... 6,270.8 11,308.5
Long-term debt ..................................................................................... 11,039.8 11,075.7
Deferred income taxes .............................................................................. 2,453.4 3,353.6
Liabilities and minority interests of discontinued operations ...................................... - 1,264.5
Energy risk management and trading liabilities ..................................................... - 680.9
Derivative liabilities ............................................................................. 2,124.1 1,209.8
Other liabilities and deferred income .............................................................. 947.5 962.8
Contingent liabilities and commitments (Note 16)
Minority interests in consolidated subsidiaries .................................................... 84.1 83.7
Stockholders' equity:
Preferred stock, $1 per share par value, 30 million shares authorized,
1.5 million issued in 2002 ...................................................................... - 271.3
Common stock, $1 per share par value, 960 million shares authorized,
521.4 million issued in 2003, 519.9 million issued in 2002 ...................................... 521.4 519.9
Capital in excess of par value ................................................................... 5,195.1 5,177.2
Accumulated deficit .............................................................................. (1,426.8) (884.3)
Accumulated other comprehensive income (loss) .................................................... (121.0) 33.8
Other ............................................................................................ (28.0) (30.3)
----------- -----------
4,140.7 5,087.6
Less treasury stock (at cost), 3.2 million shares of common stock in 2003
and 2002 ........................................................................................ (38.6) (38.6)
----------- -----------
Total stockholders' equity ..................................................................... 4,102.1 5,049.0
----------- -----------
Total liabilities and stockholders' equity ..................................................... $ 27,021.8 $ 34,988.5
=========== ===========
See accompanying notes.
99.4-3
THE WILLIAMS COMPANIES, INC.
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
ACCUMULATED
CAPITAL IN OTHER
EXCESS OF RETAINED COMPREHENSIVE
PREFERRED COMMON PAR EARNINGS INCOME TREASURY
STOCK STOCK VALUE (DEFICIT) (LOSS) OTHER STOCK TOTAL
--------- ------ ---------- --------- ------------- ------ -------- ---------
(DOLLARS IN MILLIONS, EXCEPT PER-SHARE AMOUNTS)
BALANCE, DECEMBER 31, 2000..................... $ -- $447.9 $ 2,473.9 $ 3,065.7 $ 28.2 $(81.2) $ (42.5) $5,892.0
Comprehensive loss:
Net loss -- 2001.............................. -- -- -- (477.7) -- -- -- (477.7)
Other comprehensive income:
Net unrealized gains on cash flow hedges, net
of reclassification adjustments............. -- -- -- -- 370.2 -- -- 370.2
Net unrealized depreciation on marketable
equity securities, net of reclassification
adjustments................................. -- -- -- -- (35.3) -- -- (35.3)
Foreign currency translation adjustments..... -- -- -- -- (37.1) -- -- (37.1)
Minimum pension liability adjustment......... -- -- -- -- (2.2) -- -- (2.2)
--------
Total other comprehensive income.............. 295.6
--------
Total comprehensive loss....................... (182.1)
Issuance of common stock (38 million shares)... -- 38.0 1,295.4 -- -- -- -- 1,333.4
Issuance of common stock for acquisition of
business (29.6 million shares)................ -- 29.6 1,206.1 -- -- -- -- 1,235.7
Cash dividends -- Common stock
($.68 per share).............................. -- -- -- (341.0) -- -- -- (341.0)
Stockholders' notes issued..................... -- -- -- -- -- (8.8) -- (8.8)
Stockholders' notes repaid..................... -- -- -- -- -- 6.3 -- 6.3
Stock award transactions, including tax benefit
(including 3.6 million common shares)......... -- 3.4 98.6 -- -- .7 2.8 105.5
Distribution of WilTel's common stock.......... -- -- -- (2,047.4) 21.3 18.0 -- (2,008.1)
Other.......................................... -- -- 11.1 -- -- -- -- 11.1
--------- ------ ---------- --------- ------------- ------ -------- --------
BALANCE, DECEMBER 31, 2001..................... -- 518.9 5,085.1 199.6 345.1 (65.0) (39.7) 6,044.0
Comprehensive loss:
Net loss -- 2002.............................. -- -- -- (754.7) -- -- -- (754.7)
Other comprehensive loss:
Net unrealized losses on cash flow hedges,
net of reclassification adjustments......... -- -- -- -- (298.9) -- -- (298.9)
Net unrealized appreciation on marketable
equity securities, net of reclassification
adjustments................................. -- -- -- -- 4.6 -- -- 4.6
Foreign currency translation adjustments..... -- -- -- -- (.1) -- -- (.1)
Minimum pension liability adjustment......... -- -- -- -- (16.9) -- -- (16.9)
--------
Total other comprehensive loss................ (311.3)
--------
Total comprehensive loss....................... (1,066.0)
Issuance of 9.875 percent cumulative
convertible preferred stock (1.5 million
shares)....................................... 271.3 -- -- -- -- -- -- 271.3
Cash dividends -- Common stock
($.42 per share).............................. -- -- -- (216.8) -- -- -- (216.8)
Preferred stock($14.14 per share)............. -- -- -- (20.8) -- -- -- (20.8)
Issuance of equity of consolidated limited
partnership................................... -- -- 44.6 -- -- -- -- 44.6
Beneficial conversion option on issuance of
convertible preferred stock (Note 13)......... -- -- 69.4 (69.4) -- -- -- --
FELINE PACS equity contract adjustment
(Note 13)..................................... -- -- (76.7) -- -- -- -- (76.7)
Allowance for and repayments of stockholders'
notes......................................... -- -- -- -- -- 7.8 (1.3) 6.5
Stock award transactions, including tax benefit
(including 1.2 million common shares)......... -- 1.0 33.1 -- -- .4 2.4 36.9
ESOP loan repayment............................ -- -- -- -- -- 26.5 -- 26.5
Other.......................................... -- -- 21.7 (22.2) -- -- -- (.5)
--------- ------ ---------- --------- ------------- ------ -------- --------
BALANCE, DECEMBER 31, 2002..................... 271.3 519.9 5,177.2 (884.3) 33.8 (30.3) (38.6) 5,049.0
Comprehensive loss:
Net loss -- 2003.............................. -- -- -- (492.2) -- -- -- (492.2)
Other comprehensive loss:
Net unrealized losses on cash flow hedges,
net of reclassification adjustments......... -- -- -- -- (236.9) -- -- (236.9)
Net unrealized depreciation on marketable
equity securities, net of reclassification
adjustments................................. -- -- -- -- (7.4) -- -- (7.4)
Foreign currency translation adjustments..... -- -- -- -- 77.0 -- -- 77.0
Minimum pension liability adjustment......... -- -- -- -- 12.5 -- -- 12.5
--------
Total other comprehensive loss................ (154.8)
--------
Total comprehensive loss....................... (647.0)
Redemption of 9.875 percent cumulative
convertible preferred stock (1.5 million
shares)....................................... (271.3) -- -- -- -- -- -- (271.3)
Cash dividends -- Common stock
($.04 per share).............................. -- -- -- (20.8) -- -- -- (20.8)
Preferred stock($20.14 per share)............. -- -- -- (29.5) -- -- -- (29.5)
Repayments of stockholders' notes.............. -- -- -- -- -- 2.3 -- 2.3
Stock award transactions, including tax benefit
(including 1.5 million common shares)......... -- 1.5 17.9 -- -- -- -- 19.4
--------- ------ ---------- --------- ------------- ------ -------- --------
BALANCE, DECEMBER 31, 2003..................... $ -- $521.4 $ 5,195.1 $(1,426.8) $ (121.0) $(28.0) $ (38.6) $4,102.1
========= ====== ========== ========= ============= ====== ======== ========
See accompanying notes.
99.4-4
THE WILLIAMS COMPANIES, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
YEARS ENDED DECEMBER 31,
-------------------------------------
2003 2002 2001
-------- -------- ----------
(MILLIONS)
OPERATING ACTIVITIES:
Income (loss) from continuing operations......................... $ 28.2 $ (597.1) $ 640.5
Adjustments to reconcile to cash provided (used) by operations:
Depreciation, depletion and amortization........................ 657.4 648.8 515.4
Provision (benefit) for deferred income taxes................... 65.3 (199.4) 322.3
Payments of guarantees and payment obligations related to WilTel -- (753.9) --
Provision for loss on investments, property and other assets.... 231.9 399.1 157.4
Net gain on dispositions of assets.............................. (142.8) (190.4) (91.2)
Provision for uncollectible accounts:
WilTel......................................................... -- 268.7 188.0
Other.......................................................... 7.3 9.7 13.6
Minority interest in income and preferred returns of
consolidated subsidiaries..................................... 19.4 41.8 71.7
Amortization and taxes associated with stock-based awards....... 27.1 31.2 22.4
Payment of deferred set-up fee and fixed rate interest on RMT
note payable.................................................. (265.0) -- --
Accrual for fixed rate interest included in RMT note payable.... 99.3 32.2 --
Amortization of deferred set-up fee and fixed rate interest on
RMT note payable.............................................. 154.5 110.9 --
Cash provided (used) by changes in current assets and
liabilities:
Restricted cash................................................ (1.4) (4.0) --
Accounts and notes receivable.................................. 668.7 243.7 344.3
Inventories.................................................... 88.6 85.6 254.9
Margin deposits................................................ 252.2 (633.4) 559.5
Other current assets and deferred charges...................... 10.3 (262.7) (2.3)
Accounts payable............................................... (608.0) (573.0) (420.5)
Accrued liabilities............................................ (387.1) (261.2) 248.4
Changes in current and noncurrent derivative and energy risk
management and trading assets and liabilities................... (350.0) 579.5 (1,419.2)
Changes in noncurrent restricted cash............................ 17.6 (104.1) --
Other, including changes in noncurrent assets and liabilities.... 34.4 29.5 (37.8)
-------- -------- ----------
Net cash provided (used) by operating activities of continuing
operations................................................... 607.9 (1,098.5) 1,367.4
Net cash provided by operating activities of discontinued
operations................................................... 162.2 583.2 461.2
-------- -------- ----------
Net cash provided (used) by operating activities............... 770.1 (515.3) 1,828.6
-------- -------- ----------
FINANCING ACTIVITIES:
Proceeds from notes payable...................................... -- 913.4 1,852.4
Payments of notes payable........................................ (960.8) (2,051.7) (2,631.4)
Proceeds from long-term debt..................................... 2,006.5 3,481.5 3,377.1
Payments of long-term debt....................................... (2,187.1) (2,536.2) (1,654.7)
Proceeds from issuance of common stock........................... 1.2 5.2 1,388.5
Dividends paid................................................... (53.3) (230.8) (341.0)
Proceeds from issuance of preferred stock........................ -- 271.3 --
Repurchase of preferred stock.................................... (275.0) (135.0) --
Net proceeds from issuance of preferred interests of
consolidated subsidiaries....................................... -- -- 95.3
Redemption of our obligated mandatorily preferred securities of
Trust holding only our indentures............................... -- -- (194.0)
Payments for debt issuance costs................................. (78.6) (186.3) (44.8)
Premiums paid on tender offer and early debt retirements......... (57.7) -- --
Payments/dividends to minority and preferred interests........... (19.8) (48.0) (50.3)
Changes in restricted cash....................................... 67.9 (182.1) --
Changes in cash overdrafts....................................... (29.7) 28.4 (28.8)
Other -- net..................................................... (2.8) (8.4) (.1)
-------- -------- ----------
Net cash provided (used) by financing activities of continuing
operations................................................... (1,589.2) (678.7) 1,768.2
Net cash provided (used) by financing activities of
discontinued operations...................................... (94.8) 524.7 1,584.2
-------- -------- ----------
Net cash provided (used) by financing activities............... (1,684.0) (154.0) 3,352.4
-------- -------- ----------
INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures............................................ (956.0) (1,662.0) (1,457.1)
Proceeds from dispositions...................................... 603.9 549.1 28.4
Acquisitions of businesses (primarily property, plant and
equipment), net of cash acquired................................ -- -- (1,291.6)
Purchases of investments/advances to affiliates.................. (150.4) (308.7) (568.3)
Purchases of restricted investments.............................. (739.9) -- --
Proceeds from sales of businesses................................ 2,250.5 2,300.4 163.7
Proceeds from sale of restricted investments..................... 351.8 -- --
Proceeds from dispositions of investments and other assets....... 128.6 273.0 243.9
Proceeds received on advances to affiliates...................... -- 75.0 95.0
Proceeds received on sale of receivables from WilTel............. -- 180.0 --
Purchase of assets subsequently leased to seller................. -- -- (276.0)
Other -- net..................................................... 33.6 35.0 24.7
-------- -------- ----------
Net cash provided (used) by investing activities of continuing
operations................................................... 1,522.1 1,441.8 (3,037.3)
Net cash used by investing activities of discontinued
operations................................................... (26.0) (337.6) (1,956.8)
-------- -------- ----------
Net cash provided (used) by investing activities............... 1,496.1 1,104.2 (4,994.1)
-------- -------- ----------
Cash of discontinued operations at spinoff........................ -- -- (96.5)
-------- -------- ----------
Increase in cash and cash equivalents............................. 582.2 434.9 90.4
Cash and cash equivalents at beginning of year.................... 1,736.0 1,301.1 1,210.7
-------- -------- ----------
Cash and cash equivalents at end of year*......................... $2,318.2 $1,736.0 $ 1,301.1
======== ======== ==========
- ----------
* Includes cash and cash equivalents of discontinued operations of $2.5
million, $85.6 million and $60.7 million for 2003, 2002 and 2001,
respectively.
See accompanying notes.
99.4-5
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. DESCRIPTION OF BUSINESS, BASIS OF PRESENTATION AND SUMMARY OF
SIGNIFICANT ACCOUNTING POLICIES
DESCRIPTION OF BUSINESS
Operations of our company are located principally in the United States and
are organized into the following reporting segments: Gas Pipeline, Exploration &
Production, Midstream Gas & Liquids, and Power (formerly named Williams Energy
Marketing & Trading Company).
Gas Pipeline is comprised primarily of two interstate natural gas
pipelines as well as investments in natural gas pipeline-related companies. The
Gas Pipeline operating segments have been aggregated for reporting purposes and
include Northwest Pipeline, which extends from the San Juan Basin in
northwestern New Mexico and southwestern Colorado to Oregon and Washington, and
Transcontinental Gas Pipe Line (Transco), which extends from the Gulf of Mexico
region to the northeastern United States.
Exploration & Production includes natural gas exploration, production and
gas management activities primarily in the Rocky Mountain and Mid-Continent
regions of the United States and in Argentina.
Midstream Gas & Liquids (Midstream) is comprised of natural gas gathering
and processing and treating facilities in the Rocky Mountain and Gulf Coast
regions of the United States, majority-owned natural gas compression and
transportation facilities in Venezuela; and assets in Canada including a natural
gas liquids extraction facility and a fractionation plant.
Power is an energy services provider that buys, sells, stores, and
transports a full suite of energy-related commodities, including power, natural
gas, crude oil, refined products and emission credits, primarily on a wholesale
level. In June 2002, we announced our intent to exit the energy merchant
business and reduce our financial commitment to the Power segment. As a result,
Power initiated efforts to sell all or portions of its power, natural gas and
crude and refined products portfolios and reduced its involvement in trading
activities as defined in Statement of Financial Accounting Standard (SFAS) No.
115 "Accounting for Certain Investments in Debt and Equity Securities." However,
Power still conducts limited trading activities and maintains contracts entered
into for trading purposes. As the process to sell the portfolio continues, Power
manages its activities to reduce risk, to generate cash and to fulfill
contractual commitments.
OVERVIEW
In February 2003, we outlined our planned business strategy in response to
the events that significantly impacted the energy sector and our company during
late 2001 and much of 2002, including the collapse of Enron and the severe
decline of the telecommunications industry. The plan focused on migrating to an
integrated natural gas business comprised of a strong, but smaller, portfolio of
natural gas businesses; reducing debt; and increasing our liquidity through
asset sales, strategic levels of financing and reductions in operating costs.
The plan was designed to address near-term and medium-term debt and liquidity
issues, to de-leverage the company with the objective of returning to investment
grade status, and to develop a balance sheet and cash flows capable of
supporting and ultimately growing our remaining businesses. A component of our
plan was to reduce risk and liquidity requirements of the Power segment while
realizing the value of Power's portfolio. Another component of the plan
consisted of selling all or parts of the Power business.
During 2003, we successfully executed the following critical components of
our plan:
- Generated cash proceeds of approximately $3 billion from the
sales of assets.
- Repaid $3.2 billion of debt through scheduled maturities and
early extinguishment of debt and accessed the public debt
markets available to us primarily to refinance $2 billion of
higher cost debt.
- Sustained core business earnings capacity through completed
system expansions at Gas Pipeline, continued drilling activity
at Exploration & Production and continued investment in
deepwater activities within Midstream.
- Continued rationalization of our cost structure, including a
28 percent reduction in selling, general and administrative
costs of continuing operations and a 39 percent reduction in
general corporate expenses.
99.4-6
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Through these efforts, we satisfied key liquidity issues facing us in
2003, including the early repayment of the Williams Production RMT Company (RMT)
note payable of approximately $1.15 billion (including certain contractual fees
and deferred interest). Additionally, we completed tender offers that prepaid
approximately $721 million of the $1.4 billion of our senior unsecured 9.25
percent notes that mature in first-quarter 2004.
We are pursuing a strategy of exiting the Power business. However, market
conditions have contributed to the difficulty of, and could delay, full,
immediate exit from this business. In 2003, we generated in excess of $600
million from the sale, termination or liquidation of Power contracts and assets.
During the year, we continued to manage our portfolio to reduce risk, to
generate cash and to fulfill contractual commitments. We are also pursuing our
goal to resolve the remaining legal and regulatory issues associated with the
business.
During 2003, we engaged financial advisors to assist and advise with
efforts to exit the Power business. Because market conditions may change and we
cannot determine the impact of this on a buyer's point of view, amounts
ultimately received in any portfolio sale, contract liquidation or realization
may be significantly different from the estimated economic value or carrying
values reflected in the Consolidated Balance Sheet. In addition, tolling
agreements are not derivatives and thus have no carrying value in the
Consolidated Balance Sheet pursuant to the application of Emerging Issues Task
Force (EITF) Issue No. 02-3, "Issues Related to Accounting for Contracts
Involved in Energy Trading and Risk Management Activities," (EITF 02-3). Based
on current market conditions certain of these agreements are forecasted to
realize significant future losses. It is possible that we may sell contracts for
less than their carrying value or enter into agreements to terminate certain
obligations, either of which could result in significant future loss recognition
or reductions of future cash flows.
Results for 2003 include approximately $117 million of revenue related to
the correction of the accounting treatment previously applied to certain third
party derivative contracts during 2002 and 2001. This matter was initially
disclosed in our Form 10-Q for the second quarter of 2003. Income from
continuing operations before income taxes and cumulative effect of change in
accounting principles in 2003 was $51.6 million. Absent the corrections, we
would have reported a pretax loss from continuing operations in 2003.
Approximately $83 million of this revenue relates to a correction of net energy
trading assets for certain derivative contract terminations occurring in 2001.
The remaining $34 million relates to net gains on certain other derivative
contracts entered into in 2002 and 2001 that we now believe should not have been
deferred as a component of other comprehensive income due to the incorrect
designation of these contracts as cash flow hedges. Our management, after
consultation with our independent auditor, concluded that the effect of the
previous accounting treatment was not material to 2003 and prior periods and the
trend of earnings.
Entering 2004, our plan is to focus on the following objectives:
- sustain solid core business performance, including increased
capital allocation to Exploration & Production activities;
- continue reduction of debt, including scheduled maturities and
early retirements, and selective refinancing of certain
instruments; and
- maintain investment discipline.
Key execution steps include the completion of planned asset sales, which
are estimated to generate proceeds of approximately $800 million in 2004,
additional reductions of our SG&A costs, the replacement of our
cash-collateralized letter of credit and revolver facility with facilities that
do not encumber cash and continuing efforts to exit from the power business.
99.4-7
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
BASIS OF PRESENTATION
In accordance with the provisions related to discontinued operations
within SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived
Assets," the accompanying consolidated financial statements and notes reflect
the results of operations, financial position and cash flows of the following
components as discontinued operations (see Note 2):
- Kern River Gas Transmission (Kern River), previously one of
Gas Pipeline's segments;
- two natural gas liquids pipeline systems, Mid-American
Pipeline and Seminole Pipeline, previously part of the
Midstream segment;
- Central natural gas pipeline, previously one of Gas Pipeline's
segments;
- retail travel centers concentrated in the Midsouth, part of
the previously reported Petroleum Services segment;
- refining and marketing operations in the Midsouth, including
the Midsouth refinery, part of the previously reported
Petroleum Services segment;
- Texas Gas Transmission Corporation, previously one of Gas
Pipeline's segments;
- natural gas properties in the Hugoton and Raton basins,
previously part of the Exploration & Production segment;
- bio-energy operations, part of the previously reported
Petroleum Services segment;
- our general partnership interest and limited partner
investment in Williams Energy Partners, previously the
Williams Energy Partners segment;
- the Colorado soda ash mining operations, part of the
previously reported International segment;
- certain gas processing, natural gas liquids fractionation,
storage and distribution operations in western Canada and at a
plant in Redwater, Alberta, previously part of the Midstream
segment;
- refining, retail and pipeline operations in Alaska, part of
the previously reported Petroleum Services segment;
- Gulf Liquids New River Project LLC, previously part of the
Midstream segment; and
- our straddle plants in western Canada, previously part of the
Midstream segment.
Additionally, the results of operations and cash flows of WilTel
Communications (WilTel), formerly Williams Communications, are reflected in
discontinued operations in the accompanying financial statements.
Since May 1995, an entity within our Midstream segment has operated
production area facilities owned by entities within our Gas Pipeline segment.
These regulated gas gathering assets have been operated pursuant to the terms of
an operating agreement. Effective June 1, 2004, and due in part to FERC Order
2004, the operating agreement was terminated and management and decision-making
control transferred to the Gas Pipeline segment. Consequently, the results of
operations were similarly reclassified. All prior periods reflect these
classifications.
Unless otherwise indicated, the information in the Notes to the
Consolidated Financial Statements relates to our continuing operations. We
expect that other components of our business may be classified as discontinued
operations in the future as the sales of those assets occur.
We have restated all segment information in the Notes to the Consolidated
Financial Statements for all prior periods presented to reflect the changes
noted above.
We have also reclassified certain prior year amounts to conform to current
year classifications.
99.4-8
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
In 2001, through two transactions, we acquired all of the outstanding
stock of Barrett Resources Corporation (Barrett). On June 11, 2001, we acquired
50 percent of Barrett's outstanding common stock in a cash tender offer totaling
approximately $1.2 billion. We 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 our common stock for
a total of approximately 30 million shares of our common stock valued at $1.2
billion.
The unaudited pro forma net loss for 2001, if the purchase of 100 percent
of Barrett occurred at the beginning of that year, was $396 million, or $.76
loss per diluted share. Pro forma financial information is not necessarily
indicative of results of operations that would have occurred if the acquisition
had occurred at the beginning of that year or of future results of operations of
the combined companies.
The estimated fair values of the significant assets acquired and liabilities
assumed at August 2, 2001, the date of acquisition, were:
- Current assets -- $127.6 million
- Property, plant and equipment -- $2,520.4 million
- Goodwill and other assets -- $1,114.5 million
- Current liabilities -- $171.6 million
- Long-term debt -- $312.1 million
- Deferred income taxes -- $634.7 million
- Other non-current liabilities -- $127.1 million
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of consolidation
The consolidated financial statements include the accounts of our
corporate parent and our majority-owned subsidiaries and investments. We account
for companies in which we and our subsidiaries own 20 percent to 50 percent of
the voting common stock, or otherwise exercise significant influence over
operating and financial policies of the company, under the equity method.
Use of estimates
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires management to make
estimates and assumptions that affect the amounts reported in the consolidated
financial statements and accompanying notes. Actual results could differ from
those estimates.
99.4-9
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Estimates and assumptions which, in the opinion of management, are
significant to the underlying amounts included in the financial statements and
for which it would be reasonably possible that future events or information
could change those estimates include:
- impairment assessments of long-lived assets and goodwill;
- litigation-related contingencies;
- valuations of energy contracts, including energy-related
contracts;
- environmental remediation obligations;
- realization of deferred income tax assets;
- Gas Pipeline and Power revenues subject to refund; and
- valuation of Exploration & Production's reserves.
These estimates are discussed further throughout the accompanying notes.
Cash and cash equivalents
Cash and cash equivalents include demand and time deposits, certificates
of deposit and other marketable securities with maturities of three months or
less when acquired.
Restricted cash and investments
Restricted cash within current assets consists primarily of collateral as
required by certain borrowings by our Venezuelan operations and letters of
credit. Restricted cash within noncurrent assets consists primarily of
collateral in support of surety bonds underwritten by an insurance company, the
RMT term loan B (see Note 11), certain borrowings by our Venezuelan operations
and letters of credit. We do not expect this cash to be released within the next
twelve months. The current and noncurrent restricted cash is primarily invested
in short-term money market accounts with financial institutions and an insurance
company as well as treasury securities.
Both short-term and long-term restricted investments consist of short-term
U.S. Treasury securities as required under the $800 million revolving and letter
of credit facility (see Note 11). These securities are purchased and sold based
on the balance required in the collateral account. Therefore, these securities
are accounted for as "available-for-sale." These securities are marked to market
with the unrealized holding gains and losses included in Other Comprehensive
Income, until realized (see Note 18). Realized gains or losses are reclassified
into earnings and based on specific identification of the securities sold.
The classification of restricted cash and investments is determined based
on the expected term of the collateral requirement and not necessarily the
maturity date of the underlying securities.
Accounts receivable
Accounts receivable are carried on a gross basis, with no discounting,
less the allowance for doubtful accounts. No allowance for doubtful accounts is
recognized at the time the revenue, which generates the accounts receivable, is
recognized. We estimate the allowance for doubtful accounts based on existing
economic conditions, the financial conditions of the customers and the amount
and age of past due accounts. Receivables are considered past due if full
payment is not received by the contractual due date. Interest income related to
past due accounts receivable is recognized at the time full payment is received
or collectibility is assured. Past due accounts are generally written off
against the allowance for doubtful accounts only after all collection attempts
have been exhausted.
99.4-10
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Inventory valuation
Prior to the EITF reaching a consensus on EITF 02-3 on October 25, 2003
(see Energy commodity risk management and trading activities and revenues), we
stated inventories at cost, which were not in excess of market, except for
certain assets held for energy risk management by Power and Midstream which were
stated at fair value. We stated all inventories purchased after October 25, 2003
at cost in accordance with Issue 02-3. For inventories held for energy risk
management purposes purchased on or before October 25, 2002, we included the
amount by which fair value exceeded cost in a cumulative effect of a change in
accounting principle. Beginning on January 1, 2003, we stated all inventories at
cost, which is not in excess of market. We determined the cost of certain
natural gas inventories held by Transco using the last-in, first-out (LIFO) cost
method; and we determined the cost of the remaining inventories primarily using
the average-cost method or market, if lower.
Property, plant and equipment
Property, plant and equipment is recorded at cost. We base the carrying
value of these assets on estimates, assumptions and judgments relative to
capitalized costs, useful lives and salvage values. As regulated entities,
Northwest Pipeline and Transco provide for depreciation using the straight-line
method at FERC prescribed rates. Depreciation of general plant is provided on a
group basis at straight-line rates. Depreciation rates used for major regulated
gas plant facilities at December 31, 2003, 2002, and 2001 are as follows:
CATEGORY OF PROPERTY 2003 2002 2001
- ---------------------------------------------------- ------------- ------------ ------------
Gathering facilities................................. 0% - 3.80% 0% - 3.80% 2.60% - 3.80%
Storage facilities................................... 1.05% - 2.50% 1.05% - 2.50% 1.05% - 2.50%
Onshore transmission facilities...................... 2.35% - 5.00% 2.35% - 5.00% 2.35% - 5.00%
Offshore transmission facilities..................... 0.85% - 1.50% 0.85% - 1.50% 1.50%
Depreciation for non-regulated entities is provided primarily on the
straight-line method over estimated useful lives except as noted below regarding
oil and gas exploration and production activities. The estimated useful lives
are as follows.
ESTIMATED
CATEGORY OF PROPERTY USEFUL LIVES
- --------------------------------------------------- -------------
(IN YEARS)
Natural Gas Gathering and Processing Facilities.... 10 to 40
Power Generation Facilities........................ 15 to 30
Transportation Equipment........................... 3 to 30
Building and Improvements.......................... 10 to 45
Right of Way....................................... 4 to 40
Office Furnishings & Computers..................... 3 to 20
Gains or losses from the ordinary sale or retirement of property, plant
and equipment for regulated pipelines are credited or charged to accumulated
depreciation; other gains or losses are recorded in net income (loss).
Oil and gas exploration and production activities are accounted for under
the successful efforts method of accounting. Costs incurred in connection with
the drilling and equipping of exploratory wells are capitalized as incurred. If
proved reserves are not found, such costs are charged to expense. Other
exploration costs, including lease rentals, are expensed as incurred. All costs
related to development wells, including related production equipment and lease
acquisition costs, are capitalized when incurred. Unproved properties are
evaluated annually, or as conditions warrant, to determine any impairment in
carrying value. Depreciation, depletion and amortization are provided under the
units of production method on a field basis.
Proved properties, including developed and undeveloped, and costs
associated with probable reserves, are assessed for impairment using estimated
future cash flows on a field basis. Estimating future cash flows involves the
use of complex judgments such as estimation of the proved and probable oil and
gas reserve quantities, risk associated with the different categories of oil and
gas reserves, timing of development and production, expected future commodity
prices, capital expenditures and production costs.
Effective January 1, 2003, we adopted SFAS No. 143, "Accounting for Asset
Retirement Obligations." This Statement requires that the fair value of a
liability for an asset retirement obligation be recognized in the period in
which it is incurred if a reasonable estimate of fair value can be made, and
that the associated asset retirement costs be capitalized as part of the
carrying amount of the long-lived asset. As required by the new standard, we
recorded liabilities equal to the present value of expected future asset
retirement
99.4-11
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
obligations at January 1, 2003. The obligations relate to producing wells,
offshore platforms, underground storage caverns and gas gathering well
connections. At the end of the useful life of each respective asset, we are
legally obligated to plug both producing wells and storage caverns and remove
any related surface equipment, to dismantle offshore platforms, and to cap
certain gathering pipelines at the wellhead connection and remove any related
surface equipment. The liabilities are partially offset by increases in
property, plant and equipment, net of accumulated depreciation, recorded as if
the provisions of the Statement had been in effect at the date the obligation
was incurred. As a result of the adoption of SFAS No. 143, we recorded a
long-term liability of $33.4 million; property, plant and equipment, net of
accumulated depreciation, of $24.8 million and a credit to earnings of $1.2
million (net of a $.1 million provision for income taxes) reflected as a
cumulative effect of a change in accounting principle. We also recorded a $9.7
million regulatory asset for retirement costs of dismantling offshore platforms
expected to be recovered through regulated rates. In connection with adoption of
SFAS No. 143, we changed our method of accounting to include salvage value of
equipment related to producing wells in the calculation of depreciation. The
impact of this change is included in the amounts discussed above. We have not
recorded liabilities for pipeline transmission assets, processing and refining
assets, and gas gathering systems pipelines. A reasonable estimate of the fair
value of the retirement obligations for these assets cannot be made as the
remaining life of these assets is not currently determinable. If the Statement
had been adopted at the beginning of 2002, the impact to our income from
continuing operations and net income would have been immaterial. There would
have been no impact on earnings per share.
Goodwill
Goodwill represents the excess of cost over fair value of assets of
businesses acquired. Beginning January 1, 2002, the impairment of goodwill and
other intangible assets is measured pursuant to the guidelines of SFAS No. 142,
"Goodwill and Other Intangible Assets". Goodwill is evaluated for impairment by
first comparing our management's estimate of the fair value of a reporting unit
with its carrying value, including goodwill. If the carrying value exceeds its
fair value, a computation of the implied fair value of the goodwill is compared
with its related carrying value. If the carrying value of the reporting unit
goodwill exceeds the implied fair value of that goodwill, an impairment loss is
recognized in the amount of the excess.
When a reporting unit is sold or classified as held for sale, any goodwill
of that reporting unit is included in its carrying value for purposes of
determining any impairment or gain/loss on sale. If a portion of a reporting
unit with goodwill is sold or classified as held for sale and that asset group
represents a business, a portion of the reporting unit's goodwill is allocated
to and included in the carrying value of that asset group. Except for
Bio-energy, Alaska Retail, Williams Energy Partners and the Travel Centers, none
of the operations sold during 2003 or classified as held for sale at December
31, 2003 represented reporting units with goodwill or businesses within
reporting units to which goodwill was required to be allocated.
Judgments and assumptions are inherent in our management's estimate of
undiscounted future cash flows used to determine the estimate of the reporting
unit's fair value. The use of alternate judgments and/or assumptions could
result in the recognition of different levels of impairment charges in the
financial statements.
In accordance with SFAS No. 142, approximately $1 billion of goodwill
acquired subsequent to June 30, 2001, in the acquisition of Barrett, was not
amortized in 2001. Beginning January 1, 2002, all goodwill is no longer
amortized, but is tested annually for impairment. Application of the
nonamortization provisions of SFAS No. 142 did not materially impact the
comparability of the Consolidated Statement of Operations. Exploration &
Production's goodwill was approximately $1 billion at December 31, 2003 and
2002.
Treasury stock
Treasury stock purchases are accounted for under the cost method whereby
the entire cost of the acquired stock is recorded as treasury stock. Gains and
losses on the subsequent reissuance of shares are credited or charged to capital
in excess of par value using the average-cost method.
99.4-12
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Energy commodity risk management and trading activities and revenues
Prior to 2003, we, through Power and the natural gas liquids trading
operations (reported within the Midstream segment), had energy commodity risk
management and trading operations that entered into energy and energy-related
contracts to provide price-risk management services to our third-party
customers. These contracts involved power, natural gas, refined products,
natural gas liquids and crude oil. Prior to the adoption of EITF 02-3, we valued
all energy and energy-related contracts used in energy commodity risk management
and trading activities at fair value in accordance with SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities," and Issue No.
98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management
Activities." Energy contracts included the following:
- forward contracts,
- futures contracts,
- option contracts,
- swap agreements,
- certain physical commodity inventories, and
- short-and long-term purchase and sale commitments, which involve
physical delivery of an energy commodity.
Energy-related contracts included the following:
- power tolling contracts,
- full requirements contracts,
- load serving contracts,
- storage contracts,
- transportation contracts, and
- transmission contracts.
In addition, we entered into interest rate swap agreements and credit
default swaps to manage the interest rate and credit risk in our energy trading
portfolio. Prior to 2003, we recorded these energy and energy-related contracts
and credit default swap agreements, with the exception of physical trading
commodity inventories, in current and noncurrent energy risk management and
trading assets and energy risk management and trading liabilities in the
Consolidated Balance Sheet. We based the classification of current versus
noncurrent on the timing of expected future cash flows. In accordance with SFAS
No. 133 and Issue No. 98-10, we recognized the net change in fair value of these
contracts representing unrealized gains and losses in income currently. We also
recorded the net change in fair value as revenues in the Consolidated Statement
of Operations. Power and the natural gas liquids trading operations, reported
their trading operations' physical sales transactions net of the related
purchase costs, consistent with fair value accounting for such trading
activities. The accounting for energy-related contracts required us to assess
whether certain of these contracts were executory service arrangements or leases
pursuant to SFAS No. 13, "Accounting for Leases." As a result, we assessed each
of our energy-related contracts and made the determination based on the
substance of each contract focusing on factors such as 1) physical and
operational control of the related asset, 2) risks and rewards of owning,
operating and maintaining the related asset and 3) other contractual terms. See
Recent accounting standards section within this Note for recent developments
regarding guidance determining whether an arrangement contains a lease.
As discussed in the Inventory valuation section of this note, the EITF
reached a consensus on Issue No. 02-3 on October 25, 2002. This Issue rescinded
EITF Issue No. 98-10. As a result of the rescission, in 2003, we no longer
account for 1) energy trading contracts that are not derivatives as defined in
SFAS No. 133 and 2) commodity trading inventories at fair value. The consensus
was applicable
99.4-13
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
for fiscal periods beginning after December 15, 2002, except for physical
trading commodity inventories purchased after October 25, 2002. Issue No. 02-3
prohibited us from reporting physical trading commodity inventories purchased
after October 25, 2002 at fair value. We applied the consensus effective January
1, 2003 and reported the initial application as a cumulative effect of a change
in accounting principle. The effect of initially applying the consensus reduced
net income by $762.5 million, net of a $471.4 million benefit for income taxes.
The charge primarily consisted of the fair value of power tolling, load serving,
transportation and storage contracts. These contracts did not meet the
definition of a derivative and thus are no longer reported at fair value. After
January 1, 2003, these contracts were accounted for under the accrual basis of
accounting. The charge also included the amount by which the December 31, 2002
fair value of physical trading commodity inventories exceeded cost. We continued
to carry derivatives at fair value in 2003. See further discussion on derivative
assets and liabilities in the Derivative instruments and hedging activities,
including interest rate swaps section within this Note.
Prior to 2003, we determined the fair value of energy and energy-related
contracts based on the nature of the transaction and the market in which
transactions were executed. We executed certain transactions in exchange-traded
or over-the-counter markets for which quoted prices in active periods existed.
We executed other transactions in markets or periods in which quoted prices were
not available. Quoted market prices for varying periods in active markets were
readily available for valuing forward contracts, futures contracts, swap
agreements and purchase and sales transactions in the commodity markets in which
Power and the natural gas liquids trading operations transacted. Market data in
active periods was also available for interest rate transactions, which affected
the trading portfolio. For contracts or transactions that extended into periods
for which actively quoted prices were not available, Power and the natural gas
liquids trading operations estimated energy commodity prices in the illiquid
periods by incorporating information obtained from commodity prices in actively
quoted markets, prices in less active markets, prices reflected in current
transactions and market fundamental analysis. For contracts where quoted market
prices were not available, primarily transportation, storage, full requirements,
load serving, transmission and power tolling contracts (energy-related
contracts), Power estimated fair value using proprietary models and other
valuation techniques that reflected the best information available under the
circumstances. In situations where Power had received current information from
negotiation activities with potential buyers of these contracts, Power
considered this information in the determination of the fair value of the
contract. The valuation techniques used when estimating fair value for
energy-related contracts incorporated the following:
- option pricing theory,
- statistical and simulation analysis,
- present value concepts incorporating risk from uncertainty of the
timing and amount of estimated cash flows, and
- specific contractual terms.
In estimating fair value, Power also assumed liquidation of the positions
in an orderly manner over a reasonable period of time in a transaction between a
willing buyer and seller.
These valuation techniques for tolling contracts, full requirements
contracts and other non-derivative energy-related contracts utilized factors
such as the following:
- quoted energy commodity market prices,
- estimates of energy commodity market prices in the absence of quoted
market prices,
- volatility factors underlying the positions,
- estimated correlation of energy commodity prices, contractual
volumes, and estimated volumes under option and other arrangements,
- liquidity of the market in which the contract was transacted, and
- a risk-free market discount rate.
99.4-14
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Fair value also reflected a risk premium that market participants would
consider in their determination of fair value. Regardless of the method for
which fair value was determined, we considered the risk of non-performance and
credit considerations of the counterparty in estimating the fair value of all
contracts. We adjusted the estimates of fair value as assumptions changed or as
transactions became closer to settlement and enhanced estimates become
available.
The fair value of our trading portfolio was continually subject to change
due to changing market conditions and changing trading portfolio positions. In
2002, determining fair value for these contracts also involved complex
assumptions including estimating natural gas and power market prices in illiquid
periods and markets, estimating market volatility and liquidity and correlation
of natural gas and power prices, evaluating risk arising from uncertainty
inherent in estimating cash flows and estimates regarding counterparty
performance and credit considerations. Changes in valuation methodologies or the
underlying assumptions could result in significantly different fair values.
Derivative instruments and hedging activities, including interest rate swaps
In 2002, we presented Power and Midstream's derivative and non-derivative
trading assets on the Consolidated Balance Sheet in energy commodity risk
management and trading activities. All other derivatives were presented in
current assets, other assets and deferred charges, accrued liabilities and other
liabilities and deferred income in the Consolidated Balance Sheet as of December
31, 2002. After the adoption of EITF 02-3 on January 1, 2003, we recorded all
derivatives in current and noncurrent derivative assets and current and
noncurrent derivative liabilities. We based the classification of current versus
noncurrent on the timing of expected future cash flows.
Derivative instruments held by us consist primarily of futures contracts,
swap agreements, forward contracts and option contracts. We execute most of
these transactions in exchange-traded or over-the-counter markets for which
quoted prices in active periods exist. For contracts with lives exceeding the
time period for which quoted prices were available, we determine fair value by
estimating commodity prices during the illiquid periods. We estimate commodity
prices during illiquid periods by incorporating information obtained from
commodity prices in actively quoted markets, prices reflected in current
transactions and market fundamental analysis.
In first-quarter 2002, we began managing a portion of our interest rate
risk on an enterprise basis by the corporate parent. The more significant of
these risks relates to Power's trading and non-trading portfolio. To facilitate
the management of the risk, our entities enter into derivative instruments
(usually swaps) with the corporate parent. The level, term and nature of
derivative instruments entered into with external parties are determined by the
corporate parent. Power enters into intercompany interest rate swaps with the
corporate parent, the effect of which is included in Power's segment revenues
and segment profit (loss) as shown in the reconciliation within the segment
disclosures (see Note 19). The results of interest rate swaps with external
counterparties are shown as interest rate swap loss in the Consolidated
Statement of Operations below operating income (loss).
The accounting for changes in the fair value of all derivatives depends
upon whether we have designated them in a hedging relationship and, further, on
the type of hedging relationship. To qualify for designation in a hedging
relationship, specific criteria have to be met and the appropriate documentation
maintained. We establish hedging relationships pursuant to our risk management
policies. We initially and regularly evaluate the hedging relationships to
determine whether they were expected to be, and remain, highly effective hedges.
If a derivative ceases to be a highly effective hedge, hedge accounting is
discontinued prospectively, and future changes in the fair value of the
derivative are recognized in earnings each period.
For derivatives designated as a hedge of a recognized asset or liability
or an unrecognized firm commitment (fair value hedges), we recognize the changes
in the fair value of the derivative as well as changes in the fair value of the
hedged item attributable to the hedged risk each period in earnings. If we
terminate a firm commitment designated as the hedged item in a fair value hedge
or it otherwise no longer qualifies as the hedged item, we recognize any asset
or liability previously recorded as part of the hedged item currently in
earnings.
For derivatives designated as a hedge of a forecasted transaction or of
the variability of cash flows related to a recognized asset or liability (cash
flow hedges), the effective portion of the change in fair value of the
derivative is reported in other comprehensive income and reclassified into
earnings in the period in which the hedged item affects earnings. Amounts
excluded from the effectiveness calculation and any ineffective portion of the
change in fair value of the derivative are recognized currently in earnings.
Gains or losses deferred in accumulated other comprehensive income associated
with terminated derivatives, derivatives that cease to be highly effective
hedges and cash flow hedges that have been otherwise discontinued remain in
accumulated other comprehensive
99.4-15
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
income until the hedged item affects earnings or it is probable that the hedged
item will not occur by the end of the originally specified time period or within
two months thereafter. Forecasted transactions designated as the hedged item in
a cash flow hedge are regularly evaluated to assess whether they continue to be
probable of occurring. When it is probable the forecasted transaction will not
occur, any gain or loss deferred in accumulated other comprehensive income is
recognized in earnings at that time.
For derivatives held for trading and non-trading purposes not designated
as a hedge, we reported changes in fair value currently in earnings. As
discussed in the Description of business section of this Note, in 2003, we are
no longer significantly engaged in trading activities. We now primarily enter
into derivative contracts to reduce risk associated with our assets and
non-derivative energy-related contracts, such as tolling, full requirements,
storage and transportation contracts. However, we still maintain certain
derivatives entered into for trading purposes. In Issue No. 02-3, the EITF
reached a consensus that gains and losses on derivative instruments within the
scope of SFAS No. 133 should be shown net in the income statement if the
derivative instruments are held for trading purposes. On July 31, 2003, the EITF
reached a consensus on Issue No. 03-11, "Reporting Realized Gains and Losses on
Derivative Instruments That Are Subject to FASB Statement No. 133, Accounting
for Derivative Instruments and Hedging Activities, and Not Held for Trading
Purposes as Defined in Issue No. 02-3 Issues Involved in Accounting for
Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy
Trading and Risk Management Activities." In this issue, the EITF concluded that
determining whether realized gains and losses on physically settled derivative
contracts not held for trading purposes should be reported in the income
statement on a gross or net basis is a matter of judgment that depended on the
relevant facts and circumstances. Applying these two consensuses, we report
unrealized gains and losses on all derivative contracts not designated as hedges
on a net basis in the Consolidated Statement of Operations. We also report
realized gains and losses on all derivative contracts not designated as hedges
that settled financially on a net basis. We apply the indicators provided in
Issue No. 99-19, "Reporting Revenue Gross as a Principal versus Net as an Agent"
to determine the proper treatment for derivative and non-derivative contracts
not designated as hedges that resulted in physical delivery. In accordance with
Issue No. 99-19, we account for realized revenues and purchase costs for all
contracts that result in physical delivery on a gross basis in the Consolidated
Statement of Operations. EITF 02-3 and Issue No. 03-11 did not require
restatement of prior year amounts.
In the second quarter of 2003, we elected the normal purchases and normal
sales exception available under SFAS No. 133 on certain derivative contracts
held by our Power segment. We reflected these contracts in current and
noncurrent derivative assets and liabilities at their fair value on the date of
the election less the portion of that fair value allocable to previous
settlement periods.
On January 1, 2001, we recorded a cumulative effect of an accounting
change associated with the adoption of SFAS No. 133, as amended, to record all
derivatives at fair value. The cumulative effect of the accounting change was
not material to net income (loss), 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 energy
commodity transactions.
Gas pipeline revenues
Revenues for sales of products are recognized in the period of delivery,
and revenues from the transportation of gas are recognized in the period the
service is provided. Gas Pipeline is subject to Federal Energy Regulatory
Commission (FERC) regulations and, accordingly, certain revenues collected may
be subject to possible refunds upon final orders in pending rate cases. Gas
Pipeline records estimates of rate refund liabilities considering Gas Pipeline
and other third-party regulatory proceedings, advice of counsel and estimated
total exposure, as discounted and risk weighted, as well as collection and other
risks.
Revenues, other than gas pipeline and energy commodity risk management and
trading activities
Revenues generally are recorded when services are performed or products
have been delivered.
Additionally, revenues from the domestic production of natural gas in
properties for which Exploration & Production has an interest with other
producers are recognized based on the actual volumes sold during the period. Any
differences between volumes sold and entitlement volumes, based on Exploration &
Production's net working interest, which are determined to be non-recoverable
through remaining production, are recognized as accounts receivable or accounts
payable, as appropriate. Cumulative differences between volumes sold and
entitlement volumes are not significant.
99.4-16
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Impairment of long-lived assets and investments
We evaluate the long-lived assets of identifiable business activities for
impairment when events or changes in circumstances indicate, in our management's
judgment, that the carrying value of such assets may not be recoverable.
Beginning January 1, 2002, the impairment evaluation of tangible long-lived
assets is measured pursuant to the guidelines of SFAS No. 144. When an indicator
of impairment has occurred, we compare our management's estimate of undiscounted
future cash flows attributable to the assets to the carrying value of the assets
to determine whether an impairment has occurred. We apply a probability-weighted
approach to consider the likelihood of different cash flow assumptions and
possible outcomes including selling in the near term or holding for the
remaining estimated useful life. If an impairment of the carrying value has
occurred, we determine the amount of the impairment recognized in the financial
statements by estimating the fair value of the assets and recording a loss for
the amount that the carrying value exceeds the estimated fair value.
For assets identified to be disposed of in the future and considered held
for sale in accordance with SFAS No. 144, we compare the carrying value to the
estimated fair value less the cost to sell to determine if recognition of an
impairment is required. Until the assets are disposed of, the estimated fair
value, which includes estimated cash flows from operations until the assumed
date of sale, is redetermined when related events or circumstances change.
We evaluate our investments for impairment when events or changes in
circumstances indicate, in our management's judgement, that the carrying value
of such investments may have experienced an other-than-temporary decline in
value. When evidence of loss in value has occurred, we compare our estimate of
fair value of the investment to the carrying value of the investment to
determine whether an impairment has occurred. If the estimated fair value is
less than the carrying value and we consider the decline in value to be other
than temporary, the excess of the carrying value over the fair value is
recognized in the financial statements as an impairment.
Judgments and assumptions are inherent in our management's estimate of
undiscounted future cash flows used to determine recoverability of an asset and
the estimate of an asset's fair value used to calculate the amount of impairment
to recognize. Additionally, our management's judgment is used to determine the
probability of sale with respect to assets considered for disposal pursuant to
our announced strategy of selling assets as a significant source of liquidity.
The use of alternate judgments and/or assumptions could result in the
recognition of different levels of impairment charges in the financial
statements.
Capitalization of interest
We capitalize interest on major projects during construction. Interest is
capitalized on borrowed funds and, where regulation by the FERC exists, on
internally generated funds. The rates used by regulated companies are calculated
in accordance with FERC rules. Rates used by unregulated companies are based on
the average interest rate on debt. Interest capitalized on internally generated
funds, as permitted by FERC rules, is included in non-operating other income
(expense) -- net.
99.4-17
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Employee stock-based awards
Employee stock-based awards are accounted for under Accounting Principles
Board Opinion (APB) No. 25, "Accounting for Stock Issued to Employees" and
related interpretations. Fixed-plan common stock options generally do not result
in compensation expense because the exercise price of the stock options equals
the market price of the underlying stock on the date of grant. The plans are
described more fully in Note 14. The following table illustrates the effect on
net loss and loss per share if we had applied the fair value recognition
provisions of SFAS No. 123, "Accounting for Stock-Based Compensation."
YEARS ENDED DECEMBER 31,
--------------------------------------
2003 2002 2001
---------- ---------- ----------
(DOLLARS IN MILLIONS)
Net loss, as reported .................................................... $ (492.2) $ (754.7) $ (477.7)
Add: Stock-based employee compensation expense included in the
Consolidated Statement of Operations, net of related tax effects ....... 18.7 19.1 13.6
Deduct: Total stock based employee compensation expense determined
under fair value based method for all awards, net of related tax effects (31.6) (34.5) (24.7)
---------- ---------- ----------
Pro forma net loss ....................................................... $ (505.1) $ (770.1) $ (488.8)
========== ========== ==========
Loss per share:
Basic -- as reported ................................................... $ (1.01) $ (1.63) $ (.96)
========== ========== ==========
Basic -- pro forma ..................................................... $ (1.03) $ (1.66) $ (.98)
========== ========== ==========
Diluted -- as reported ................................................. $ (1.01) $ (1.63) $ (.95)
========== ========== ==========
Diluted -- pro forma ................................................... $ (1.03) $ (1.66) $ (.98)
========== ========== ==========
Pro forma amounts for 2003 include compensation expense from awards of our
company stock made in 2003, 2002 and 2001. Also included in the 2003 pro forma
expense is $2 million of incremental expense associated with a stock option
exchange program (see Note 14). Pro forma amounts for 2002 include compensation
expense from awards made in 2002 and 2001 and from certain awards made in 1999.
Pro forma amounts for 2001 include compensation expense from awards made in 2001
and from certain awards made in 1999.
Since compensation expense from stock options is recognized over the
future years' vesting period for pro forma disclosure purposes and additional
awards are generally made each year, pro forma amounts may not be representative
of future years' amounts.
Income taxes
We include the operations of our subsidiaries in our consolidated tax
return. Deferred income taxes are computed using the liability method and are
provided on all temporary differences between the financial basis and the tax
basis of our assets and liabilities. Our management's judgment and income tax
assumptions are used to determine the levels, if any, of valuation allowances
associated with deferred tax assets.
Earnings (loss) per share
Basic earnings (loss) per share is based on the sum of the weighted
average number of common shares outstanding and issuable restricted and vested
deferred shares. Diluted earnings (loss) per share includes any dilutive effect
of stock options, unvested deferred shares and, for applicable periods
presented, convertible preferred stock and convertible debt, unless otherwise
noted.
Foreign currency translation
Certain of our foreign subsidiaries and equity method investees use their
local currency as their functional currency. These foreign currencies include
the Canadian dollar, British pound and Euro. Assets and liabilities of certain
foreign subsidiaries and equity investees are translated at the spot rate in
effect at the applicable reporting date, and the combined statements of
operations and our share of the results of operations of our equity affiliates
are translated into the U.S. dollar at the average exchange rates in effect
during the applicable period. The resulting cumulative translation adjustment is
recorded as a separate component of other comprehensive income (loss).
Transactions denominated in currencies other than the functional currency
are recorded based on exchange rates at the time such transactions arise.
Subsequent changes in exchange rates result in transactions gains and losses
which are reflected in the Consolidated Statement of Operations.
99.4-18
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Issuance of equity of consolidated subsidiary
Sales of common stock by a consolidated subsidiary are accounted for as
capital transactions with the adjustment to capital in excess of par value. No
gain or loss is recognized on these transactions.
Securitizations and transfers of financial instruments
Through July 2002, we had agreements to sell, on an ongoing basis, certain
of our trade accounts receivable through revolving securitization structures
under which we retained servicing responsibilities as well as a subordinate
interest in the transferred receivables. These agreements expired in July 2002
and were not renewed. We accounted for the securitization of trade accounts
receivable in accordance with SFAS No. 140, "Accounting for Transfers and
Servicing of Financial Assets and Extinguishments of Liabilities." As a result,
the related receivables were removed from the Consolidated Balance Sheet and a
retained interest was recorded for the amount of receivables sold in excess of
cash received.
We determined the fair value of our retained interests based on the
present value of future expected cash flows using our management's best estimate
of various factors, including credit loss experience and discount rates
commensurate with the risks involved. These assumptions were updated
periodically based on actual results, thus the estimated credit loss and
discount rates utilized were materially consistent with historical performance.
The fair value of the servicing responsibility was estimated based on internal
costs, which approximate market. Costs associated with the sale of receivables
are included in nonoperating other income (expense) -- net in the Consolidated
Statement of Operations.
RECENT ACCOUNTING STANDARDS
The FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit
or Disposal Activities." This Statement addresses financial accounting and
reporting for costs associated with exit or disposal activities and nullifies
EITF Issue No. 94-3, "Liability Recognition for Certain Employee Termination
Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred
in a Restructuring)." Under this Statement, a liability for a cost associated
with an exit or disposal activity is recognized at fair value when the liability
is incurred rather than at the date of an entity's commitment to an exit plan.
The provisions of this Statement are effective for exit or disposal activities
that are initiated after December 31, 2002; hence, initial adoption of this
Statement on January 1, 2003, did not have any impact on our results of
operations or financial position.
The FASB issued SFAS No. 148, "Accounting for Stock-Based Compensation --
Transition and Disclosure," which is effective for fiscal years ending after
December 15, 2002. SFAS No. 148 amends SFAS No. 123 to permit two additional
transition methods for a voluntary change to the fair value based method of
accounting for stock-based employee compensation from the intrinsic method under
APB No. 25. The prospective method of transition under SFAS No. 123 is an option
to the entities that adopt the recognition provisions under this statement in a
fiscal year beginning before December 15, 2003. In addition, this statement
amends the disclosure requirements of SFAS No. 123 to require prominent
disclosures in both annual and interim financial statements concerning the
method of accounting used for stock-based employee compensation and the effects
of that method on reported results of operations. Under this statement, pro
forma disclosures are required in a specific tabular format in the "Summary of
Significant Accounting Policies." We have applied the disclosure requirements of
this statement effective December 31, 2002. The adoption had no effect on our
consolidated financial position or results of operations. We continue to account
for our stock-based compensation plans under APB Opinion No. 25. See Employee
stock-based awards. FASB has announced it will be issuing an Exposure Draft on
equity-based compensation. In deliberations on this matter, the FASB has
concluded that equity-based compensation awards to employees results in an
expense to the employer that should be recognized in the income statement.
The FASB issued FASB Interpretation No. 45, "Guarantor's Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others." This Interpretation requires the fair value of
guarantees issued or modified after December 31, 2002, be initially recognized
by the guarantor at the inception of the guarantee, and expands the disclosure
requirements for guarantees. Initial adoption of this Interpretation did not
have any impact on our results of operations or financial position. The expanded
disclosure requirements have been presented in the Notes to Consolidated
Financial Statements.
99.4-19
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
In January 2003, the FASB issued Interpretation No. 46, "Consolidation of
Variable Interest Entities." The Interpretation defines a variable interest
entity (VIE) as an entity in which equity investors do not have the
characteristics of a controlling financial interest or do not have sufficient
equity at risk for the entity to finance its activities without additional
subordinated financial support from other parties. The investments or other
interests that will absorb portions of the VIE's expected losses if they occur
or receive portions of the VIE's expected residual returns if they occur are
called variable interests. Variable interests may include, but are not limited
to, equity interests, debt instruments, beneficial interests, derivative
instruments and guarantees. The Interpretation requires an entity to consolidate
a VIE if that entity will absorb a majority of the VIE's expected losses if they
occur, receive a majority of the VIE's expected residual returns if they occur,
or both. If no party will absorb a majority of the expected losses or expected
residual returns, no party will consolidate the VIE. The Interpretation also
requires disclosure of significant variable interests in unconsolidated VIE's.
The Interpretation is effective for all new variable interest entities created
or acquired after January 31, 2003. For variable interest entities created or
acquired prior to February 1, 2003, the provisions of the Interpretation were
initially to be effective for the first interim or annual period ending after
June 15, 2003. However, in October 2003, the FASB delayed the required effective
date of the Interpretation on those entities to the first period beginning after
December 15, 2003. Additionally, in December 2003, the FASB issued a revision to
the Interpretation to clarify certain provisions and to exempt certain entities
from its requirements. The revised Interpretation will require full
implementation in the first quarter of 2004. We adopted the original
Interpretation in 2003 with no material effect to the consolidated financial
statements. The effect of the adoption of the revised Interpretation is not
expected to be material to the consolidated financial statements.
The FASB issued revised SFAS No. 132, "Employers' Disclosures about
Pensions and Other Postretirement Benefits." This Statement addresses disclosure
requirements for pensions and other postretirement benefits. The provisions of
this Statement retain the disclosure requirements of the previously issued SFAS
No. 132 and expand the disclosure requirements to include information describing
types of plan assets, investment strategy, measurement date, plan obligations
and cash flows. Additionally, the Statement requires disclosure of the
components of net periodic benefit cost recognized during interim periods. This
Statement is effective for financial statements with fiscal years and interim
periods ending after December 15, 2003, except for the disclosure of estimated
future benefit payments, which is effective for fiscal years ending after June
15, 2004.
EITF Issue No. 01-8, "Determining Whether An Arrangement Contains a
Lease," became effective on July 1, 2003, and provides guidance for determining
whether certain contracts such as transportation, storage, load serving, and
tolling agreements are executory service arrangements or leases pursuant to SFAS
No. 13. A prospective transition is provided for whereby the consensus is to be
applied to arrangements consummated or modified after July 1, 2003. Our review
indicates that certain of Power's tolling agreements could be considered leases
under the consensus if the tolling agreements are modified after July 1, 2003.
If such tolling agreements are deemed to be capital leases, the net present
value of the demand payments would be reported on the balance sheet consistent
with debt as an obligation under capital lease, and as an asset in property,
plant and equipment.
The SEC staff, in a letter to the EITF Chairman, raised the issue of
classification of leased mineral rights, for companies subject to SFAS No. 19
"Financial Accounting and Reporting by Oil and Gas Producing Companies" that
acquire leased mineral rights. Specifically, the SEC staff has stated its view
that leased mineral rights meet the definition of an intangible asset under SFAS
No. 141 "Business Combinations" and are thus subject to the disclosure
requirements of SFAS No. 142 "Goodwill and Other Intangible Assets." At December
31, 2003 and 2002, our Exploration & Production segment had net leased mineral
rights of $1.9 billion and $2.1 billion, respectively. The leased mineral rights
would continue to be amortized over their remaining useful life, where
appropriate. The effect of such a reclassification, if required, is not expected
to affect our Statement of Operations or Statement of Cash Flows.
99.4-20
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
NOTE 2. DISCONTINUED OPERATIONS
During 2002, we began the process of selling certain assets and/or
businesses to address liquidity issues. The businesses discussed below represent
components that have been sold or approved for sale by our Board of Directors as
of December 31, 2003. Therefore, their results of operations (including any
impairments, gains or losses), financial position and cash flows have been
reflected in the consolidated financial statements and notes as discontinued
operations.
During second-quarter 2004, our Board of Directors approved a plan to
negotiate and facilitate the sale of our three natural gas liquid extraction
plants (straddle plants) in western Canada. We expect to complete the sale in
the third quarter of 2004. These assets were previously written down to
estimated fair value, resulting in a $36.8 million impairment in fourth-quarter
2002 and an additional $41.7 million impairment in fourth-quarter 2003. In 2004,
the fair value of the assets increased substantially due primarily to
renegotiation of certain customer contracts and a general improvement in the
market for processing assets. These operations were part of the Midstream
segment. Consequently, the results of operations of the straddle plants have
been reclassified to discontinued operations in the consolidated financial
statements and in the tables below. All prior periods reflect this
classification.
SUMMARIZED RESULTS OF DISCONTINUED OPERATIONS
Summarized results of discontinued operations for the years ended December
31, 2003, 2002, and 2001 are as follows:
2003 2002 2001
---------- ---------- ----------
(MILLIONS)
Revenues ............................................. $ 2,620.9 $ 6,007.7 $ 7,006.5
========== ========== ==========
Income from discontinued operations before income
taxes .............................................. $ 167.6 $ 348.0 $ 231.0
(Impairments) and gain (loss) on sales-net ........... 169.0 (567.8) (184.8)
Losses associated with performance on WilTel guarantee
obligations ........................................ - - (1,839.2)
Benefit (provision) for income taxes ................. (95.7) 62.2 674.8
---------- ---------- ----------
Income (loss) from discontinued operations ...... $ 240.9 $ (157.6) $ (1,118.2)
========== ========== ==========
SUMMARIZED ASSETS AND LIABILITIES OF DISCONTINUED OPERATIONS
Summarized assets and liabilities of discontinued operations as of
December 31, 2003 and 2002, are as follows:
2003 2002
---------- ----------
(MILLIONS)
Total current assets ................... $ 175.4 $ 757.6
---------- ----------
Property, plant and equipment -- net ... 609.0 3,540.0
Other non-current assets ............... 2.0 268.5
---------- ----------
Total non-current assets ............. 611.0 3,808.5
---------- ----------
Total assets ......................... $ 786.4 $ 4,566.1
========== ==========
Reflected on balance sheet as:
Current assets ....................... $ 441.3 $ 1,297.3
Non-current assets ................... 345.1 3,268.8
---------- ----------
Total assets ......................... $ 786.4 $ 4,566.1
========== ==========
Long-term debt due within one year ..... $ 1.2 $ 70.6
Other current liabilities .............. 81.5 461.3
---------- ----------
Total current liabilities ............ 82.7 531.9
---------- ----------
Long-term debt ......................... .3 829.3
Minority interests ..................... -- 340.0
Other non-current liabilities .......... 12.7 113.5
---------- ----------
Total non-current liabilities ........ 13.0 1,282.8
---------- ----------
Total liabilities .................... $ 95.7 $ 1,814.7
========== ==========
Reflected on balance sheet as:
Current liabilities .................. $ 95.7 $ 550.2
Non-current liabilities .............. -- 1,264.5
---------- ----------
Total liabilities .................... $ 95.7 $ 1,814.7
========== ==========
HELD FOR SALE AT DECEMBER 31, 2003
99.4-21
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Alaska refining, retail and pipeline operations
On November 17, 2003, we entered into agreements to sell our Alaska
refinery, retail and pipeline assets for approximately $265 million in cash,
subject to various closing adjustments. The transactions are expected to close
in the first quarter of 2004 following the completion of various closing
conditions.
Throughout the sales negotiation process, we regularly reassessed the
estimated fair value of these assets based on information obtained from the
sales negotiations using a probability-weighted approach. As a result,
impairment charges of $8 million and $18.4 million were recorded during 2003 and
2002, respectively. These impairments are included in (impairments) and gain
(loss) on sales in the preceding table of summarized results of discontinued
operations. These operations were part of the previously reported Petroleum
Services segment.
Gulf Liquids New River Project LLC
During second-quarter 2003, our Board of Directors approved a plan
authorizing management to negotiate and facilitate a sale of the assets of Gulf
Liquids New River Project LLC (Gulf Liquids). We recognized impairment charges
totaling $108.7 million during 2003 to reduce the carrying cost of the long-
lived assets to estimated fair value less costs to sell the assets. These
charges are included in (impairments) and gain (loss) on sales in the preceding
table of summarized results of discontinued operations. We estimated fair value
based on a probability-weighted analysis of various scenarios including expected
sales prices, salvage valuations and discounted cash-flows. We expect to
complete the sale of these operations within one year of the Board's approval.
These operations were part of our Midstream segment.
2003 COMPLETED TRANSACTIONS
Canadian liquids operations
During 2003, we completed the sales of certain gas processing, natural gas
liquids fractionation, storage and distribution operations in western Canada and
at our Redwater, Alberta plant for total proceeds of $246 million in cash. We
recognized pre-tax gains totaling $92.1 million in 2003 on the sales which are
included in (impairments) and gain (loss) on sales in the preceding table of
summarized results of discontinued operations. These operations were part of our
Midstream segment.
Soda ash operations
On September 9, 2003, we completed the sale of our soda ash mining
facility located in Colorado. The December 31, 2002 carrying value reflected the
then estimated fair value less cost to sell. During 2003, ongoing sale
negotiations continued to provide new information regarding estimated fair
value, and, as a result, we recognized additional impairment charges of $17.4
million in 2003. We also recognized a loss on the sale in 2003 of $4.2 million.
These impairments, the loss on the sale and previous impairments of $133.5
million in 2002 and $170 million in 2001 are included in (impairments) and gain
(loss) on sales in the preceding table of summarized results of discontinued
operations. The soda ash operations were part of the previously reported
International segment.
Williams Energy Partners
On June 17, 2003, we completed the sale of our 100 percent general
partnership interest and 54.6 percent limited partner investment in Williams
Energy Partners for $512 million in cash and assumption by the purchasers of
$570 million in debt. In December 2003, we received additional cash proceeds of
$20 million following the occurrence of a contingent event. We recognized a
total pre-tax gain of $310.8 million on the sale during 2003, including the $20
million of additional proceeds, all of which is included in (impairments) and
gain (loss) on sales in the preceding table of summarized results of
discontinued operations. We deferred an additional $113 million associated with
our indemnifications of the purchasers for a variety of matters, including
obligations that may arise associated with existing environmental contamination
relating to operations prior to April 2002 and identified prior to April 2008
(see Note 16).
99.4-22
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Bio-energy facilities
On May 30, 2003, we completed the sale of our bio-energy operations for
$59 million in cash. During 2003, we recognized an additional pre-tax loss on
the sale of $5.4 million. We recorded impairment charges totaling $195.7
million, including $23 million related to goodwill, during 2002, to reduce the
carrying cost to our estimate of fair value, less cost to sell, at that time.
Both the additional loss and impairment charges are included in (impairments)
and gain (loss) on sales in the preceding table of summarized results of
discontinued operations. These operations were part of the previously reported
Petroleum Services segment.
Natural gas properties
On May 30, 2003, we completed the sale of natural gas exploration and
production properties in the Raton Basin in southern Colorado and the Hugoton
Embayment in southwestern Kansas. This sale included all of our interests within
these basins. We recognized a $39.7 million gain on the sale during 2003. The
gain is included in (impairments) and gain (loss) on sales in the preceding
table of summarized results of discontinued operations. These properties were
part of the Exploration & Production segment.
Texas Gas
On May 16, 2003, we completed the sale of Texas Gas Transmission
Corporation for $795 million in cash and the assumption by the purchaser of $250
million in existing Texas Gas debt. We recorded a $109 million impairment charge
in first-quarter 2003 reflecting the excess of the carrying cost of the
long-lived assets over our estimate of fair value based on our assessment of the
expected sales price pursuant to the purchase and sale agreement. The impairment
charge is included in (impairments) and gain (loss) on sales in the preceding
table of summarized results of discontinued operations. No significant gain or
loss was recognized on the subsequent sale. Texas Gas was a segment within Gas
Pipeline.
Midsouth Refinery and related assets
On March 4, 2003, we completed the sale of our refinery and other related
operations located in Memphis, Tennessee for $455 million in cash. We had
previously written these assets down by $240.8 million to their estimated fair
value less cost to sell at December 31, 2002. We recognized a pre-tax gain on
sale of $4.7 million in the first quarter of 2003. During the second quarter of
2003, we recognized a $24.7 million pre-tax gain on the sale of an earn-out
agreement that we retained in the sale of the refinery. The 2002 impairment
charge and subsequent gains are included in (impairments) and gain (loss) on
sales in the preceding table of summarized results of discontinued operations.
These operations were part of the previously reported Petroleum Services
segment.
Williams travel centers
On February 27, 2003, we completed the sale of our travel centers for
approximately $189 million in cash. We had previously written these assets down
by $146.6 million in 2002 and $14.7 million in 2001 to their estimated fair
value less cost to sell at December 31, 2002. These impairments are included in
(impairments) and gain (loss) on sales in the preceding table of summarized
results of discontinued operations. We did not recognize a significant gain or
loss on the sale. These operations were part of the previously reported
Petroleum Services segment.
2002 COMPLETED TRANSACTIONS
Central
On November 15, 2002, we completed the sale of our Central natural gas
pipeline for $380 million in cash and the assumption by the purchaser of $175
million in debt. Impairment charges totaling $91.3 million during 2002 are
reflected in (impairments) and gain (loss) on sales in the preceding table of
summarized results of discontinued operations. Central was a segment within Gas
Pipeline.
Mid-America and Seminole Pipelines
On August 1, 2002, we completed the sale of our 98 percent interest in
Mid-America Pipeline and 98 percent of our 80 percent ownership interest in
Seminole Pipeline for $1.2 billion. The sale generated net cash proceeds of
$1.15 billion. The preceding table of summarized results of discontinued
operations, (impairments) and gain (loss) on sales includes a pre-tax gain of
$301.7 million during 2002 and an $11.4 million reduction of the gain during
2003. These assets were part of the Midstream segment.
99.4-23
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Kern River
On March 27, 2002, we completed the sale of our Kern River pipeline for
$450 million in cash and the assumption by the purchaser of $510 million in
debt. As part of the agreement, $32.5 million of the purchase price was
contingent upon Kern River receiving a certificate from the FERC to construct
and operate a future expansion. We received the certificate in July 2002, and
recognized the contingent payment plus interest as income from discontinued
operations in third-quarter 2002. Included as a component of (impairments) and
gain (loss) on sales in the preceding table of summarized results of
discontinued operations is a pre-tax loss of $6.4 million for the year ended
December 31, 2002. Kern River was a segment within Gas Pipeline.
WILTEL
Spinoff and related information
On March 30, 2001, our Board of Directors approved a tax-free spinoff of
WilTel to our shareholders. On April 23, 2001, we distributed 398.5 million
shares, or approximately 95 percent of our WilTel common stock, to holders of
our common stock. Accordingly, the results of operations, financial position and
cash flows for WilTel have been reflected in the accompanying consolidated
financial statements and notes as discontinued operations.
In an effort to strengthen WilTel's capital structure, prior to the
spinoff we took the following steps:
- We contributed an outstanding promissory note from WilTel of
approximately $975 million.
- We contributed certain other assets, including the Williams
Technology Center (Technology Center) and other ancillary
assets under construction. We also committed to complete
construction of the Technology Center. Later in 2001, we
repurchased the Technology Center and three corporate aircraft
from WilTel for $276 million. We then leased these assets back
to WilTel.
- We provided indirect credit support for $1.4 billion of the
WCG Note Trust Notes.
- We provided a guarantee of WilTel's obligations under a 1998
asset defeasance program (ADP) transaction in which WilTel
entered into a lease agreement covering a portion of its
fiber-optic network. WilTel had an option to purchase the
covered network assets during the lease term at an amount
approximating lessor's cost of $750 million.
2001 post spinoff and accounting
Prior to filing our 2001 Annual Report on Form 10-K, WilTel announced that
it might seek to reorganize under the U.S. Bankruptcy Code. As a result, we
determined that it was probable we would be unable to fully recover certain
receivables and our investment in WilTel. We also concluded that it was probable
that we would be required to perform under certain guarantees and payment
obligations. Using the information available prior to March 7, 2002 and under
the circumstances, we developed an estimated range of loss related to our total
WilTel exposure. As part of this evaluation, we considered our position as an
unsecured creditor, the fair value of the leased assets securing the Technology
Center lease, likely recoveries from a successful reorganization process under
Chapter 11 of the U.S. Bankruptcy Code, and the enterprise value of WilTel. We
also received assistance from external legal counsel and an external financial
and restructuring advisor. At that time, we believed that no loss within the
range was more probable than another. Accordingly, we recorded the $2.05 billion
minimum amount of the range of loss. This is reported in the 2001 Consolidated
Statement of Operations as a $1.84 billion pre-tax charge to discontinued
operations and a $213 million pre-tax charge to continuing operations.
The $1.84 billion pre-tax charge to discontinued operations includes
portions of the following items:
- Indirect credit support for $1.4 billion of WCG Note Trust
Notes and related interest.
- Guarantee of the ADP transaction.
99.4-24
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The $213 million pre-tax charge to continuing operations includes portions
of the following items:
- $106 million of receivables from services prior to the spinoff
- $269 million receivable for the Technology Center lease
- the remaining investment in WilTel common stock, which had
previously been written down by $70.9 million earlier in 2001
2002 developments and accounting
In 2002, we acquired all of the WCG Note Trust Notes by exchanging $1.4
billion of our Senior Unsecured 9.25 percent Notes due March 2004. WilTel was
indirectly obligated to reimburse us for any payments we were required to make
in connection with the WCG Note Trust Notes.
On March 29, 2002, we funded the $754 million purchase price related to
WilTel's March 8, 2002 exercise of its option to purchase the covered network
assets under the ADP transaction. The payment entitled us to an unsecured note
from WilTel for the same amount.
On April 22, 2002, WilTel filed for bankruptcy protection under Chapter 11
of the U.S. Bankruptcy Code. On October 15, 2002, WilTel consummated its
reorganization plan. Under this plan:
- our common stock ownership in WilTel was cancelled,
- we recovered $180 million of claims against WilTel through the
sale of those claims to WilTel's new parent organization, and
- we sold the Technology Center back to WilTel in exchange for
two promissory notes due in seven and one-half years and four
years and secured by a mortgage on the Technology Center.
During 2002, we recognized additional pre-tax charges of $268.7 million in
continuing operations related to the recovery and settlement of our receivables
and claims against WilTel.
Status at December 31, 2003
At December 31, 2003, we have a $110.8 million receivable from WilTel for
the promissory notes relating to the sale of the Technology Center pursuant to
the WilTel reorganization plan. The receivable is included in other assets and
deferred charges.
We have provided guarantees in the event of nonpayment by WilTel on
certain lease performance obligations of WilTel that extend through 2042 and
have a maximum potential exposure of approximately $51 million at December 31,
2003. Our exposure declines systematically throughout the remaining term of
WilTel's obligations. The carrying value of these guarantees is approximately
$46 million at December 31, 2003 and is recorded as a non-current liability.
99.4-25
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
NOTE 3. INVESTING ACTIVITIES
INVESTING INCOME (LOSS)
Investing income (loss) for the years ended December 31, 2003, 2002 and
2001, is as follows:
2003 2002 2001
-------- -------- --------
(MILLIONS)
Equity earnings (losses)* ................................ $ 20.3 $ 73.0 $ 22.7
Income (loss) from investments* .......................... (25.3) 42.1 4.2
Impairments of cost based investments .................... (35.0) (12.1) (5.6)
Write-down of investment in WilTel stock (see Note 2) .... -- -- (95.9)
Loss provision for WilTel receivables (see Note 2) ....... -- (268.7) (188.0)
Interest income and other ................................ 113.1 52.5 90.0
-------- -------- --------
Total ................................................ $ 73.1 $ (113.2) $ (172.6)
======== ======== ========
* Items also included in segment profit.
Equity earnings for the year ended December 31, 2002, includes a benefit
of $27.4 million for a contractual construction completion fee received by one
of our equity affiliates whose operations are accounted for under the equity
method of accounting. This equity affiliate served as the general contractor on
the Gulfstream pipeline project for Gulfstream Natural Gas System (Gulfstream),
an interstate natural gas pipeline subject to FERC regulations and an equity
affiliate of ours. The fee paid by Gulfstream was for the early completion
during second-quarter 2002 of the construction of Gulfstream's pipeline. It was
capitalized by Gulfstream as property, plant and equipment and is included in
Gulfstream's rate base to be recovered in future revenues.
Income (loss) from investments for the year ended December 31, 2003,
includes:
- a $43.1 million impairment of our investment in equity and
debt securities of Longhorn Partners Pipeline L.P., which is
included in the Other segment;
- a $14.1 million impairment of our equity interest in Aux
Sable, which is included in the Midstream segment;
- a $13.5 million gain on the sale of stock in eSpeed Inc.,
which is included in the Power segment; and
- an $11.1 million gain on sale of our equity interest in West
Texas LPG Pipeline, L.P. which is included in the Midstream
segment.
Income (loss) from investments for the year ended December 31, 2002,
includes:
- a $58.5 million gain on sale of our investment in AB Mazeikiu
Nafta, a Lithuanian oil refinery, pipeline and terminal
complex, which is included in the Other segment;
- a $12.3 million write-off of Gas Pipeline's investment in a
pipeline project which was cancelled in 2002;
- a $10.4 million net write-down pursuant to the sale of our
equity interest in Alliance Pipeline, a Canadian and U.S. gas
pipeline, which is included in the Gas Pipeline segment; and
- an $8.7 million gain on sale of our general partner equity
interest in Northern Border Partners, L.P., which is included
in the Gas Pipeline segment.
99.4-26
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Income (loss) from investments for the year ended December 31, 2001,
includes:
- a $27.5 million gain on the sale of our limited partnership
interest in Northern Border Partners, L.P., which is included
in the Gas Pipeline segment; and
- $23.3 million of write-downs of certain investments which are
included in the Power segment.
Impairments of cost based investments for the year ended December 31,
2003, includes:
- a $13.5 million impairment of investment in ReserveCo, a
company holding phosphate reserves, and
- a $13.2 million impairment of investment in Algar Telecom S.A.
The 2002 and 2001 impairments of cost based investments relate primarily to
various international investments.
Interest income for the year ended December 31, 2003, includes
approximately $34 million of interest income at Power as the result of certain
recent FERC proceedings.
INVESTMENTS
Investments at December 31, 2003 and 2002, are as follows:
2003 2002
---------- ----------
(MILLIONS)
Equity method:
Gulfstream Natural Gas System, LLC -- 50% ......... $ 730.8 $ 734.4
Discovery Pipeline -- 50% ......................... 194.6 75.3
Longhorn Partners Pipeline, L.P. -- 32.7% ......... 85.1 89.3
ACCROVEN -- 49.3% ................................. 67.1 60.4
Alliance Aux Sable -- 14.6% ....................... 42.8 54.8
Petrolera Entre Lomas S.A. -- 40.8% ............... 41.5 35.8
Other ............................................. 71.8 140.1
---------- ----------
1,233.7 1,190.1
Cost method:
Algar Telecom S.A. -- common and preferred stock .. 15.3 52.8
Various international funds ....................... 48.9 53.9
Indonesian toll road .............................. 23.7 23.7
Other ............................................. 24.8 33.5
---------- ----------
112.7 163.9
Advances to Longhorn Partners Pipeline, L.P. ........ 117.2 100.9
Other ............................................... -- 13.7
---------- ----------
$ 1,463.6 $ 1,468.6
========== ==========
In December 2003, our Midstream subsidiary made an additional $127 million
investment in Discovery Pipeline which was subsequently used by Discovery
Pipeline to repay maturing debt. All owners contributed amounts equal to their
ownership percentage so our 50 percent ownership in Discovery remained
unchanged. Also during 2003, Midstream sold its investments in four pipelines
that had a combined book value of approximately $63 million at December 31,
2002.
During February 2004, we were a party to a recapitalization plan completed
by Longhorn Partners Pipeline, L.P. (Longhorn). As a result of this plan, we
sold a portion of our equity investment in Longhorn for $11.4 million, received
$58 million in repayment of a portion of our advances to Longhorn and converted
the remaining advances, including accrued interest, into preferred equity
interests in Longhorn. These preferred equity interests are subordinate to the
preferred interests held by the new investors. No gain or loss was recognized on
this transaction.
99.4-27
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Dividends and distributions received from companies carried on the equity
basis were $21 million, $81 million and $51 million in 2003, 2002 and 2001,
respectively. The $27.4 million Gulfstream construction completion fee described
previously is included in the 2002 distributions.
GUARANTEES ON BEHALF OF INVESTEES
We have guaranteed commercial letters of credit totaling $17 million on
behalf of ACCROVEN. These expire in January 2005, have no carrying value and are
fully collateralized with cash.
In connection with the construction of a joint venture pipeline project,
we guaranteed, through a put agreement, certain portions of the joint venture's
project financing in the event of nonpayment by the joint venture. Our potential
liability under this guarantee ranges from zero percent to 100 percent of the
outstanding project financing, depending on our ability and the other project
members' ability to meet certain performance criteria. As of December 31, 2003,
the total outstanding project financing is $31.7 million. Our maximum potential
liability is the full amount of the financing, but based on the current status
of the project, it is likely that any obligation would be limited to 50 percent
of the outstanding financing. As additional borrowings are made under the
project financing facility, our potential exposure will increase. This guarantee
expires in March 2005, and we have not accrued any amounts at December 31, 2003.
We have provided guarantees on behalf of certain partnerships in which we
have an equity ownership interest. These generally guarantee operating
performance measures and the maximum potential future exposure cannot be
determined. These guarantees continue until we withdraw from the partnerships.
No amounts have been accrued at December 31, 2003.
NOTE 4. ASSET SALES, IMPAIRMENTS AND OTHER ACCRUALS
Significant gains or losses from asset sales, impairments and other
accruals included in other (income) expense - net within segment costs and
expenses for the years ended December 31, 2003, 2002 and 2001, are as follows:
(INCOME) EXPENSE
----------------------------------
2003 2002 2001
-------- -------- --------
(MILLIONS)
POWER
Gain on sale of full requirements contract .................................. $ (188.0) $ -- $ --
Commodity Futures Trading Commission settlement ............................. 20.0 -- --
California rate refund and other accrual adjustments ........................ 19.5 -- --
Impairment of goodwill ...................................................... 45.0 61.1 --
Impairment of generation facilities ......................................... 44.1 44.7 --
Loss accruals and impairment of other power related assets .................. -- 82.6 --
Guarantee loss accruals and write-offs ...................................... -- 56.2 --
Impairment of plant for terminated expansion ................................ -- -- 13.3
GAS PIPELINE
Write-off of software development costs due to cancelled implementation ..... 25.6 -- --
Loss accrual for litigation and claims ...................................... -- -- 18.3
EXPLORATION & PRODUCTION
Net gain on sales of certain natural gas properties ......................... (96.7) (141.7) --
MIDSTREAM GAS & LIQUIDS
Gain on sale of the wholesale propane business .............................. (16.2) -- --
Impairment of Canadian olefin assets ........................................ -- 78.2 --
Impairment of south Texas assets ............................................ -- -- 13.8
OTHER
Gain on sale of certain convenience stores .................................. -- -- (75.3)
Impairment of end-to-end mobile computing systems business .................. -- -- 12.1
99.4-28
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
POWER
In June 2002, we announced our intent to exit the Power business. As a
result, Power pursued efforts to sell all or portions of our power, natural gas,
and crude and refined products portfolios in the latter half of 2002 and in
2003. Based on bids received in these sales efforts, we impaired certain assets
and projects in 2002. During 2003, we continued our focus on exiting the Power
business and, as a result, impaired certain assets.
California Rate Refund and Other Accrual Adjustments. In addition to the
$19.5 million charge included in other (income) expense -- net within segment
costs and expenses for 2003, a $13.8 million charge is recorded within costs and
operating expenses. These two amounts, totaling $33.3 million, are for
California rate refund liability and other accrual adjustments and relate to
power marketing activities in California during 2000 and 2001. See Note 16 for
further discussion.
Goodwill. The fair value of the Power reporting unit used to calculate the
goodwill impairment loss in 2002 was based on the estimated fair value of the
trading portfolio inclusive of the fair value of contracts with affiliates. In
2002, the trading portfolio was reflected at fair value in the financial
statements and the affiliate contracts were not. The fair value of the affiliate
contracts was estimated using a discounted cash flow model with natural gas
pricing assumptions based on current market information.
During 2003, we continued to focus on exiting the Power business. Because
of this and current market conditions in which this business operates, we
evaluated Power's remaining goodwill for impairment. In estimating the fair
value of the Power reporting unit, we considered our derivative portfolio which
is carried at fair value on the balance sheet and our non-derivative portfolio
which is no longer carried at fair value on the balance sheet. Because of the
significant negative fair value of certain of our non-derivative contracts, we
may be unable to realize our carrying value of this reporting unit. As a result,
we recognized a $45 million impairment of the remaining goodwill within Power
during 2003.
Generation Facilities. The 2003 impairment relates to the Hazelton
generation facility. Fair value was estimated using future cash flows based on
current market information and discounted at a risk adjusted rate. The 2002
impairment was related to the Worthington generation facility. Fair value was
estimated based on expected proceeds from the sale of the facility, which closed
in first-quarter 2003.
Loss Accruals and Impairment of Other Power Related Assets. The 2002 loss
accruals and impairments of other power related assets were recorded pursuant to
reducing activities associated with the distributive power generation business.
Guarantee Loss Accruals and Write-Offs. The 2002 guarantee loss accruals
and write-offs within Power of $56.2 million includes accruals for commitments
for certain assets that were previously planned to be used in power projects,
write-offs associated with a terminated power plant project and a $13.2 million
reversal of loss accruals related to the wind-down of our mezzanine lending
business.
MIDSTREAM GAS & LIQUIDS
Canadian Olefin Assets. The 2002 impairment is associated with an olefin
fractionation facility and reflects a reduction of carrying cost to management's
estimate of fair market value, determined primarily from information available
from efforts to sell these assets.
99.4-29
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
NOTE 5. PROVISION (BENEFIT) FOR INCOME TAXES
The provision (benefit) for income taxes from continuing operations
includes:
2003 2002 2001
-------- -------- --------
(MILLIONS)
Current:
Federal ........................ $ (8.8) $ (126.7) $ 167.9
State .......................... (17.6) 27.5 9.7
Foreign ........................ 8.8 21.4 7.7
-------- -------- --------
(17.6) (77.8) 185.3
Deferred:
Federal ........................ 29.1 (150.6) 265.6
State .......................... 51.3 (56.6) 37.0
Foreign ........................ (15.1) 7.8 19.7
-------- -------- --------
65.3 (199.4) 322.3
-------- -------- --------
Total provision (benefit) .... $ 47.7 $ (277.2) $ 507.6
======== ======== ========
Reconciliations from the provision (benefit) for income taxes from
continuing operations at the federal statutory rate to the provision (benefit)
for income taxes are as follows:
2003 2002 2001
-------- -------- --------
(MILLIONS)
Provision (benefit) at statutory rate ................. $ 26.6 $ (306.0) $ 401.8
Increases (reductions) in taxes resulting from:
State income taxes (net of federal benefit) ......... 5.0 (19.0) 30.4
Foreign operations - net ............................ 3.5 81.6 12.6
Capital losses ...................................... (39.6) (121.2) 44.5
Non-deductible impairment of goodwill ............... 15.8 21.7 --
Income tax (credits) recapture ...................... -- 26.8 --
Other - net ......................................... 36.4 38.9 18.3
-------- -------- --------
Provision (benefit) for income taxes .................. $ 47.7 $ (277.2) $ 507.6
======== ======== ========
Significant components of deferred tax liabilities and assets as of
December 31, 2003 and 2002, are as follows:
2003 2002
---------- ----------
(MILLIONS)
Deferred tax liabilities:
Property, plant and equipment ................ $ 2,118.8 $ 2,183.1
Derivatives - net ............................ 149.9 642.7
Investments .................................. 514.8 568.0
Other ........................................ 195.8 168.9
---------- ----------
Total deferred tax liabilities ............. 2,979.3 3,562.7
---------- ----------
Deferred tax assets:
Minimum tax credits .......................... 151.5 151.7
Accrued liabilities .......................... 208.7 314.5
Receivables .................................. 52.5 68.2
Federal carryovers ........................... 115.7 216.2
Foreign carryovers ........................... 46.2 72.9
Other ........................................ 125.7 111.3
---------- ----------
Total deferred tax assets .................. 700.3 934.8
---------- ----------
Valuation allowance .......................... 67.8 156.5
---------- ----------
Net deferred tax assets .................... 632.5 778.3
---------- ----------
Overall net deferred tax liabilities ......... $ 2,346.8 $ 2,784.4
========== ==========
99.4-30
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Valuation allowances at December 31, 2003 serve to reduce the recognized
tax benefit associated with foreign asset impairments and foreign carryovers to
an amount that will, more likely than not, be realized. Valuation allowances at
December 31, 2002 serve to reduce the recognized tax benefit associated with
federal capital loss carryovers, foreign asset impairments and foreign
carryovers to an amount that will, more likely than not, be realized. The
valuation allowance decreased $89 million and $23 million in 2003 and 2002,
respectively.
Utilization of foreign operating loss carryovers reduced the provision for
income taxes during 2003 by $19 million.
Undistributed earnings of certain consolidated foreign subsidiaries at
December 31, 2003, amounted to approximately $45 million. No provision for
deferred U.S. income taxes has been made for these subsidiaries because we
intend to permanently reinvest such earnings in those foreign operations.
The impact of foreign operations on the effective tax rate increased
during 2002 due to the recognition of U.S. tax on foreign dividend distributions
and recording of a financial impairment on certain foreign assets for which a
valuation allowance was established.
Federal net operating loss carryovers, charitable contribution carryovers,
and capital loss carryovers of $204 million, $58 million and $68 million,
respectively, at the end of 2003 are expected to be utilized prior to expiration
in 2007 through 2022.
Cash refunds for income taxes (net of payments) were $88 million in 2003.
Cash payments for income taxes (net of refunds) were $36 million and $87 million
in 2002 and 2001, respectively.
During the course of audits of our business by domestic and foreign tax
authorities, we frequently face challenges regarding the amount of taxes due.
These challenges include questions regarding the timing and amount of deductions
and the allocation of income among various tax jurisdictions. In evaluating the
liability associated with our various filing positions, we record a liability
for probable tax contingencies. In association with this liability, we record an
estimate of related interest as a component of our current tax provision. The
impact of this accrual is included within Other - net in our reconciliation of
the tax provision to the federal statutory rate.
NOTE 6. EARNINGS (LOSS) PER SHARE
Basic and diluted earnings (loss) per common share for the years ended
December 31, 2003, 2002 and 2001, are as follows:
2003 2002 2001
----------- ----------- -----------
(DOLLARS IN MILLIONS, EXCEPT PER-
SHARE AMOUNTS; SHARES IN THOUSANDS)
Income (loss) from continuing operations ...................................... $ 28.2 $ (597.1) $ 640.5
Convertible preferred stock dividends (see Note 13) ........................... 29.5 90.1 -
----------- ----------- -----------
Income (loss) from continuing operations available to common stockholders
for basic and diluted earnings per share .................................... $ (1.3) $ (687.2) $ 640.5
=========== =========== ===========
Basic weighted-average shares ................................................. 518,137 516,793 496,935
Effect of dilutive securities:
Stock options ............................................................... - - 3,632
----------- ----------- -----------
Diluted weighted-average shares ............................................... 518,137 516,793 500,567
=========== =========== ===========
Earnings (loss) per share from continuing operations:
Basic ....................................................................... $ - $ (1.33) $ 1.29
=========== =========== ===========
Diluted ..................................................................... $ - $ (1.33) $ 1.28
=========== =========== ===========
For the year ended December 31, 2003, approximately 3.6 million
weighted-average stock options, approximately 6.4 million weighted average
shares related to the assumed conversion of 9.875 percent cumulative convertible
preferred stock, approximately 2.5 million weighted-average unvested deferred
shares and approximately 16.5 million weighted-average shares related to the
assumed conversion of convertible debentures, as well as the related interest,
that otherwise would have been included, have been excluded from the computation
of diluted earnings per common share as their inclusion would be antidilutive.
The preferred stock was redeemed in June 2003.
99.4-31
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
For the year ended December 31, 2002, approximately 666 thousand
weighted-average stock options, approximately 11.3 million weighted-average
shares related to the assumed conversion of the 9.875 percent cumulative
convertible preferred stock and approximately 3.6 million weighted-average
unvested deferred shares, that otherwise would have been included, have been
excluded from the computation of diluted earnings per common share as their
inclusion would be antidilutive.
Additionally, approximately 15.0 million, 38.7 million and 15.3 million
options to purchase shares of common stock with weighted-average exercise prices
of $22.77, $19.90 and $36.12, respectively, were outstanding on December 31,
2003, 2002 and 2001, respectively, but have been excluded from the computation
of diluted earnings per share. Inclusion of these shares would have been
antidilutive, as the exercise prices of the options exceeded the average market
prices of the common shares for the respective years.
99.4-32
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
NOTE 7. EMPLOYEE BENEFIT PLANS
The following table presents the changes in benefit obligations and plan
assets for pension benefits and other postretirement benefits for the years
indicated. It also presents a reconciliation of the funded status of these
benefits to the amount recorded in the Consolidated Balance Sheet at December 31
of each year indicated. The annual measurement date for our plans is December
31. Prior year amounts have been restated to exclude those benefit plans where
we will no longer serve as sponsor related to those operations reported as
discontinued operations (see Note 1). Changes in the obligations or assets of
continuing plans associated with the transfer of such obligations or assets in a
sale or planned sale reflected as discontinued operations have been reflected as
divestitures in the following tables.
OTHER POSTRETIREMENT
PENSION BENEFITS BENEFITS
--------------------- ---------------------
2003 2002 2003 2002
-------- -------- -------- --------
(MILLIONS)
Change in benefit obligation:
Benefit obligations at beginning of year ............ $ 788.9 $ 870.2 $ 410.5 $ 489.0
Service cost ........................................ 25.5 32.5 6.2 7.1
Interest cost ....................................... 52.7 59.3 24.1 31.8
Plan participants' contributions .................... -- -- 3.3 3.9
Curtailment ......................................... -- (.8) -- --
Settlement benefits paid ............................ (6.1) (18.7) -- --
Benefits paid ....................................... (87.1) (116.0) (24.6) (26.3)
Divestiture ......................................... (.8) (3.3) (118.3) (27.0)
Special termination benefit cost .................... -- 29.5 -- 1.5
Actuarial (gain) loss ............................... 2.8 (63.8) 61.2 (69.5)
-------- -------- -------- --------
Benefit obligation at end of year ................... 775.9 788.9 362.4 410.5
-------- -------- -------- --------
Change in plan assets:
Fair value of plan assets at beginning of year ...... 592.9 725.0 193.9 247.6
Actual return on plan assets ........................ 155.8 (94.7) 36.1 (34.9)
Divestiture ......................................... -- -- (70.2) (20.2)
Employer contributions .............................. 50.8 97.3 14.2 23.8
Plan participants' contributions .................... -- -- 3.3 3.9
Benefits paid ....................................... (87.1) (116.0) (24.6) (26.3)
Settlement benefits paid ............................ (6.1) (18.7) -- --
-------- -------- -------- --------
Fair value of plan assets at end of year ............ 706.3 592.9 152.7 193.9
-------- -------- -------- --------
Funded status ......................................... (69.6) (196.0) (209.7) (216.6)
Unrecognized net actuarial loss ....................... 195.5 309.5 44.5 14.3
Unrecognized prior service cost (credit) .............. (4.6) (7.2) 1.5 (1.5)
Unrecognized transition obligation .................... -- -- 23.6 28.2
-------- -------- -------- --------
Prepaid (accrued) benefit cost ........................ $ 121.3 $ 106.3 $ (140.1) $ (175.6)
======== ======== ======== ========
Amounts recognized in the Consolidated Balance Sheet consist of:
Prepaid benefit cost........................................ $ 164.4 $ 169.1 $ -- $ --
Accrued benefit cost........................................ (53.7) (91.6) (140.1) (175.6)
Accumulated other comprehensive income (before tax)......... 10.6 28.8 -- --
--------- --------- --------- ---------
Prepaid (accrued) benefit cost.............................. $ 121.3 $ 106.3 $ (140.1) $ (175.6)
========= ========= ========= =========
The accumulated benefit obligation for pension benefit plans was $720.2
million and $680.5 million at December 31, 2003 and 2002, respectively.
Information for pension plans with projected benefit obligation and
accumulated benefit obligation in excess of plan assets as of December 31, 2003
and 2002 is as follows:
DECEMBER 31,
------------------
2003 2002
------- -------
Projected benefit obligation.......................... $ 335.0 $ 368.8
Accumulated benefit obligation........................ 279.2 260.3
Fair value of plan assets............................. 225.5 169.9
99.4-33
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Net pension and other postretirement benefit expense for the years ended
December 31, 2003, 2002 and 2001, consists of the following:
PENSION BENEFITS
----------------------------------
2003 2002 2001
-------- -------- --------
(MILLIONS)
Components of net periodic pension expense:
Service cost ............................................................ $ 25.5 $ 32.5 $ 30.8
Interest cost ........................................................... 52.7 59.3 60.9
Expected return on plan assets .......................................... (54.2) (65.3) (80.0)
Amortization of transition asset ........................................ -- -- (1.0)
Amortization of prior service credit .................................... (2.5) (1.6) (1.4)
Recognized net actuarial loss ........................................... 13.7 4.0 .8
Regulatory asset amortization (deferral) ................................ 3.9 (1.2) 1.2
Settlement/curtailment expense .......................................... .6 4.8 --
Special termination benefit cost ........................................ -- 29.5 --
-------- -------- --------
Net periodic pension expense .............................................. $ 39.7 $ 62.0 $ 11.3
======== ======== ========
OTHER POSTRETIREMENT BENEFITS
----------------------------------
2003 2002 2001
-------- -------- --------
(MILLIONS)
Components of net periodic postretirement benefit expense (credit):
Service cost ............................................................ $ 6.2 $ 7.1 $ 6.9
Interest cost ........................................................... 24.1 31.8 29.5
Expected return on plan assets .......................................... (13.0) (18.9) (22.6)
Amortization of transition obligation ................................... 2.7 4.1 4.1
Amortization of prior service cost ...................................... .6 .2 .1
Recognized net actuarial gain ........................................... -- -- (2.6)
Regulatory asset amortization ........................................... 8.6 3.7 14.7
Settlement/curtailment expense (credit) ................................. (41.9) 13.5 --
Special termination benefit cost ........................................ -- 1.5 --
-------- -------- --------
Net periodic postretirement benefit expense (credit) ...................... $ (12.7) $ 43.0 $ 30.1
======== ======== ========
The $(41.9) million and $13.5 million settlement/curtailment expense
(credit) included in net periodic postretirement benefit expense in 2003 and
2002, respectively, is included in income (loss) from discontinued operations in
the Consolidated Statement of Operations due to the settlement/curtailment
directly resulting from the sale of the operations included within discontinued
operations.
The weighted-average assumptions utilized to determine benefit obligations
as of December 31, 2003 and 2002 are as follows:
OTHER
POSTRETIREMENT
PENSION BENEFITS BENEFITS
---------------- --------------
2003 2002 2003 2002
---- ---- ---- ----
Discount rate.............................................................. 6.25% 7% 6.25% 7%
Rate of compensation increase.............................................. 5 5 N/A N/A
The weighted-average assumptions utilized to determine net pension and
other postretirement benefit expense for the years ended December 31, 2003, 2002
and 2001, are as follows:
OTHER
PENSION BENEFITS POSTRETIREMENT BENEFITS
------------------------ -----------------------
2003 2002 2001 2003 2002 2001
---- ---- ---- ---- --- ----
Discount rate........................................................ 7% 7.5% 7.5% 7% 7% 7.5%
Expected return on plan assets....................................... 8.5 8.5 10 8.5 8.5 10
Expected return on plan assets (net of effective tax rate)........... N/A N/A N/A 7 7 8.2
Rate of compensation increase........................................ 5 5 5 N/A N/A N/A
99.4-34
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The expected rate of return was determined by our Investment Committee by
combining a review of the historical returns realized within the portfolio, the
investment strategy included in the Plans' Investment Policy Statements, and the
capital market projections provided by our independent investment consultants
for the asset classifications in which the portfolio is invested and the target
weightings of each asset classification.
The annual assumed rate of increase in the health care cost trend rate for
2004 is 11.8 percent, and systematically decreases to 5 percent by 2015.
The nonpension postretirement benefit plans which we sponsor provide for
retiree contributions and contain other cost-sharing features such as
deductibles and coinsurance. The accounting for these plans anticipates future
cost-sharing that is consistent with our expressed intent to increase the
retiree contribution rate generally in line with health care cost increases.
In December 2003, the Medicare Prescription Drug, Improvement and
Modernization Act of 2003 (the Act) was signed into law. The Act introduces a
prescription drug benefit under Medicare (Medicare Part D) as well as a federal
subsidy to sponsors of retiree health care benefit plans that provide a benefit
that is at least actuarially equivalent to Medicare Part D. Our health care plan
for retirees includes prescription drug coverage. Management is evaluating the
impact of the Act on the future obligations of the plan. In accordance with FASB
Staff Position No. FAS 106-1, the provisions of the Act are not reflected in any
measures of benefit obligations or other postretirement benefit expense in the
financial statements or accompanying notes. Authoritative guidance on the
accounting for a federal subsidy is pending and that guidance, when issued,
could require us to change previously reported information.
The health care cost trend rate assumption has a significant effect on the
amounts reported. A one-percentage-point change in assumed health care cost
trend rates would have the following effects:
POINT INCREASE POINT DECREASE
-------------- --------------
(MILLIONS)
Effect on total of service and interest cost components........ $ 5.1 $ (4.1)
Effect on postretirement benefit obligation.................... 50.9 (46.2)
The amount of postretirement benefit costs deferred as a net regulatory
asset at December 31, 2003 and 2002, is $24 million and $57.5 million,
respectively, and is expected to be recovered through rates over approximately 8
years.
Our pension plans' weighted-average asset allocations at December 31, 2003
and 2002, by asset category are as follows:
PLAN ASSETS
AT
DECEMBER 31,
------------
2003 2002
---- ----
Equity securities.............................................. 82% 78%
Debt securities................................................ 13 16
Other.......................................................... 5 6
---- ----
100% 100%
==== ====
Included in equity securities are investments in commingled funds that
invest entirely in equity securities and comprise 38 percent of the pension
plans' weighted-average assets at December 31, 2003 and 2002. Other assets are
comprised primarily of cash and cash equivalents.
Our investment strategy for the assets within the pension plans is to
maximize investment returns with prudent levels of risk to meet current and
projected financial requirements of the pension plans. These risks are
evaluated, in part, from an asset-only standpoint as to investment allocation,
investment style and manager selection. Additional risk perspectives are
reviewed considering the allocation of assets and the structure of the plan
liabilities and the combined effects on the plans. Our investment policy for the
pension plan assets includes a target asset allocation. The target for equity
securities is 84 percent and debt securities and other is 16 percent at December
31, 2003.
99.4-35
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Our other postretirement benefits plan weighted-average asset allocations
at December 31, 2003 and 2002, by asset category are as follows:
PLAN ASSETS
AT
DECEMBER 31,
------------
2003 2002
---- ----
Equity securities........................................ 74% 69%
Debt securities.......................................... 14 19
Other.................................................... 12 12
---- ----
100% 100%
==== ====
Included in equity securities are investments in commingled funds that
invest entirely in equity securities and comprise 22 percent and 17 percent of
the other postretirement benefit plans' weighted-average assets at December 31,
2003 and 2002, respectively. Other assets are comprised primarily of cash and
cash equivalents, and insurance contracts assets.
Our investment strategy for the assets within the other postretirement
benefit plans is to maximize investment returns with prudent levels of risk in a
tax efficient manner to meet current and projected financial requirements of the
other postretirement benefit plans. These risks are evaluated, in part, from an
asset-only standpoint as to investment allocation, investment style and manager
selection. Additional risk perspectives are reviewed considering the allocation
of assets and the structure of the plan liabilities and the combined effects on
the plans. Our investment policy for the other postretirement benefit plan
assets includes a target asset allocation. The target for equity securities is
80 percent and debt securities and other is 20 percent at December 31, 2003.
We expect to contribute approximately $60 million to our pension plans and
approximately $15 million to our other postretirement benefit plans in 2004.
We maintain defined-contribution plans. Costs related to continuing
operations of $18 million, $39 million and $24 million were recognized for these
plans in 2003, 2002 and 2001, respectively. In 2002, these costs included the
cost related to additional contributions to an employee stock ownership plan
resulting from the retirement of related external debt.
NOTE 8. INVENTORIES
Inventories at December 31, 2003 and 2002, are as follows:
2003 2002
-------- --------
(MILLIONS)
Raw materials:
Crude oil .......................... $ 2.1 $ 3.8
Finished goods:
Refined products ................... 8.0 47.7
Natural gas liquids ................ 40.4 102.8
-------- --------
48.4 150.5
-------- --------
Materials and supplies ............... 59.9 86.0
Natural gas in underground storage ... 132.5 125.4
-------- --------
$ 242.9 $ 365.7
======== ========
Effective January 1, 2003, we adopted EITF 02-3 (see Note 1). As a result,
we reduced the recorded value of natural gas in underground storage by $37.0
million, refined products by $2.9 million and natural gas liquids by $1.0
million. Prior to the adoption of EITF 02-3, we reported inventories related to
energy risk management and trading activities at fair value. Subsequent to the
adoption, these inventories are reported using the average-cost method.
As of December 31, 2003 less than one percent of inventories were stated
at fair value compared with 52 percent at December 31, 2002. Inventories,
primarily related to energy risk management and trading activities, stated at
fair value at December 31, 2002, included refined products of $23.1 million,
natural gas in underground storage of $76.2 million, and natural gas liquids of
$90.7 million. Inventories determined using the LIFO cost method were
approximately ten percent and seven percent of inventories at December 31, 2003
and 2002, respectively. The remaining inventories were primarily determined
using the average-cost method.
Lower-of-cost or market reductions of approximately $1.1 million and $18.2
million were recognized in 2003 and 2002, respectively, related to certain
power-related inventories primarily included in materials and supplies.
99.4-36
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
NOTE 9. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment at December 31, 2003 and 2002, is as
follows:
2003 2002
----------- -----------
(MILLIONS)
Cost:
Power ............................................ $ 190.7 $ 420.9
Gas Pipeline ..................................... 7,949.1 7,527.5
Exploration & Production ......................... 3,235.7 3,174.1
Midstream Gas & Liquids .......................... 4,126.7 3,920.2
Other ............................................ 250.2 319.2
----------- -----------
15,752.4 15,361.9
Accumulated depreciation, depletion and amortization (4,018.4) (3,663.7)
----------- -----------
$ 11,734.0 $ 11,698.2
=========== ===========
Depreciation, depletion and amortization expense for property, plant and
equipment was $655.6 million in 2003, $644.8 million in 2002 and $510.0 million
in 2001.
Gross property, plant and equipment includes approximately $676 million at
December 31, 2003 and $984 million at December 31, 2002 of construction in
progress which is not yet subject to depreciation. In addition, property of
Exploration & Production includes approximately $675 million at December 31,
2003 and $774 million at December 31, 2002 of capitalized costs from the Barrett
acquisition related to properties with probable reserves not yet subject to
depletion.
Commitments for construction and acquisition of property, plant and
equipment are approximately $60 million at December 31, 2003.
Net property, plant and equipment includes approximately $1.2 billion at
December 31, 2003 and 2002, related to amounts in excess of the original cost of
the regulated facilities within Gas Pipeline as a result of our prior
acquisitions. This amount is being amortized over the estimated remaining useful
lives of these assets at the date of acquisition. Current FERC policy does not
permit recovery through rates for amounts in excess of original cost of
construction.
We adopted SFAS No. 143, "Accounting for Asset Retirement Obligations" on
January 1, 2003 (see Note 1). As a result, we recorded a liability of $33.4
million representing the present value of expected future asset retirement
obligations at January 1, 2003. The asset retirement obligation at December 31,
2003 is $38.7 million (see Note 1).
99.4-37
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
NOTE 10. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
Under our cash-management system, certain subsidiaries' cash accounts
reflect credit balances to the extent checks written have not been presented for
payment. Accounts payable includes approximately $27 million of these credit
balances at December 31, 2003 and $57 million at December 31, 2002.
Accrued liabilities at December 31, 2003 and 2002, are as follows:
2003 2002
--------- ---------
(MILLIONS)
Interest................................................................................................ $ 261.2 $ 301.2
Employee costs.......................................................................................... 153.6 178.8
Taxes other than income taxes........................................................................... 101.2 99.7
Net lease obligation.................................................................................... 65.3 58.5
Guarantees and payment obligations related to WilTel.................................................... 46.1 47.7
Deposits received from customers relating to energy risk management and trading and hedging activities.. 25.8 141.2
Income taxes............................................................................................ 6.2 63.3
Accrued liabilities related to the RMT note payable..................................................... -- 237.0
Other................................................................................................... 285.0 277.1
--------- ---------
$ 944.4 $ 1,404.5
========= =========
NOTE 11. DEBT, LEASES AND BANKING ARRANGEMENTS
NOTES PAYABLE AND LONG-TERM DEBT
Notes payable and long-term debt at December 31, 2003 and 2002, are as
follows:
WEIGHTED-
AVERAGE DECEMBER 31,
INTEREST ---------------------------
RATE(1) 2003 2002
--------- ----------- ----------
(MILLIONS)
Secured notes payable............................................... 6.57% $ 3.3 $ 996.3
=========== ==========
Long-term debt:
Secured long-term debt
Revolving credit loans.......................................... $ -- $ 81.0
Debentures...................................................... -- 28.7
Notes, 6.62%-9.45%, payable through 2016........................ 8.0% 243.7 256.8
Notes, adjustable rate, payable through 2016.................... 4.4% 602.5 2.3
Other, payable 2003............................................. --- -- 20.9
Unsecured long-term debt
Debentures, 5.5%-10.25%, payable through 2033................... 7.0% 1,645.2 1,449.0
Notes, 6.125%-9.25%, payable through 2032(2).................... 7.7% 9,404.3 9,349.9
Notes, adjustable rate.......................................... --- -- 669.9
Other, payable through 2005..................................... 4.3% 79.3 158.1
Capital leases...................................................... --- -- 139.9
----------- ----------
Total long-term debt, including current............................. 11,975.0 12,156.5
Current portion of long-term debt................................. (935.2) (1,080.8)
----------- ----------
Total long-term debt................................................ $ 11,039.8 $ 11,075.7
=========== ==========
- -------------
(1) At December 31, 2003
(2) Includes $1.1 billion of 6.5% notes payable 2007, subject to remarketing
in 2004, discussed below.
99.4-38
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Notes payable at December 31, 2002, included a $921.8 million secured note
(the RMT note payable), which was repaid in May 2003 with proceeds from asset
sales and from a new $500 million long-term debt obligation (described below
under "Issuances and Retirements").
Long-term debt includes $1.1 billion of 6.5 percent notes, payable in
2007, that are subject to remarketing in 2004. These FELINE PACS include equity
forward contracts which require the holder to purchase shares of our common
stock in 2005. If the 2004 remarketing is unsuccessful and a second remarketing
in February 2005 is unsuccessful, we could exercise our right to foreclose on
the notes in order to satisfy the obligation of the holders of the equity
forward contracts requiring the holder to purchase our common stock (see Note
13). This would be a non-cash transaction.
In September 2003, our Board of Directors authorized us to retire or
otherwise prepay up to $1.8 billion of debt, including $1.4 billion designated
for our senior, unsecured 9.25 percent notes due March 15, 2004. On October 8,
2003, we announced a cash tender offer for any and all of our $1.4 billion
senior, unsecured 9.25 percent notes as well as cash tender offers and consent
solicitations for approximately $241 million of other outstanding notes and
debentures. As of the November 6, 2003, tender offer expiration date, we had
accepted $721 million of the senior, unsecured 9.25 percent notes for purchase.
Additionally, we received tenders of notes and deliveries of related consents
from holders of $230 million of the other notes and debentures. In conjunction
with the tendered notes and related consents, we paid premiums of approximately
$58 million. The premiums, as well as related fees and expenses, together
totaling $66.8 million, were recorded in fourth-quarter 2003 as a pre-tax charge
to earnings.
We are required by certain foreign lenders to ensure that the interest
rates received by them under various loan agreements are not reduced by taxes by
providing for the reimbursement of any domestic taxes required to be paid by the
foreign lender. The maximum potential amount of future payments under these
indemnifications is based on the related borrowings, generally continue
indefinitely unless limited by the underlying tax regulations, and have no
carrying value. We have never been called upon to perform under these
indemnifications.
Revolving credit and letter of credit facilities
On June 6, 2003, we entered into a two-year $800 million revolving and
letter of credit facility, primarily for the purpose of issuing letters of
credit. Northwest Pipeline and Transco also have access to all unborrowed
amounts under the facility. The facility must be secured by cash and/or
acceptable government securities with a market value of at least 105 percent of
the then outstanding aggregate amount available for drawing under all letters of
credit, plus the aggregate amount of all loans then outstanding. The restricted
cash and investments used as collateral are classified on our balance sheet as
current or non-current based on the expected ultimate termination date of the
underlying debt or letters of credit. The new credit facility replaced a $1.1
billion credit line entered into in July 2002 that was comprised of a $700
million revolving credit facility and a $400 million letter of credit facility
secured by substantially all of our Midstream assets. The lenders released these
assets as collateral upon termination of the old credit facilities, and they
were not pledged in support of the new facility. The interest rate on the new
facility is variable at the London InterBank Offered Rate (LIBOR) plus .75
percent, or 1.87 percent at December 31, 2003. As of December 31, 2003, letters
of credit totaling $353 million have been issued by the participating financial
institutions under this facility and remain outstanding. No revolving credit
loans were outstanding. At December 31, 2003, the amount of restricted
investments securing this facility was $381 million, which collateralized the
facility at approximately 108 percent.
Issuances and retirements
On May 28, 2003, we issued $300 million of 5.5 percent junior subordinated
convertible debentures due 2033. These notes, which are callable after seven
years, are convertible at the option of the holder into our common stock at a
conversion price of approximately $10.89 per share. The proceeds were used to
redeem all of the outstanding 9.875 percent cumulative-convertible preferred
shares (see Note 13).
99.4-39
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
On May 30, 2003, our Exploration & Production subsidiary entered into a
$500 million secured note due May 30, 2007, at a floating interest rate of LIBOR
plus 3.75 percent (totaling 4.92 percent at December 31, 2003). This loan
refinances a portion of the RMT note discussed above. Certain of our Exploration
& Production interests in the U.S. Rocky Mountains had secured the RMT note
payable and now serve as security on the current loan. Significant covenants on
the borrower, RMT and its parent Williams Production Holdings LLC (Holdings),
include:
- interest coverage ratio computed on a consolidated RMT basis
of greater than 3 to 1;
- ratio of the present value of future cash flows of proved
reserves, discounted at ten percent, based on the most recent
engineering report to total senior secured debt, computed on a
consolidated RMT basis, of greater than 1.75 to 1;
- limitation on restricted payments; and
- limitation on intercompany indebtedness.
On February 25, 2004, this loan facility was amended. The maturity date was
extended to May 30, 2008, and the interest rate was lowered to LIBOR plus 2.5
percent.
On June 10, 2003, we issued $800 million of 8.625 percent senior unsecured
notes due 2010. The notes were issued under our $3 billion shelf registration
statement. Significant covenants include:
- limitation on certain payments, including a limitation on the
payment of quarterly dividends to no greater than $.02 per
common share;
- limitation on asset sales, unless the consideration is at
least equal to fair market value and at least 75 percent of
the consideration received is in the form of cash or cash
equivalents;
- limitation on the use of proceeds from permitted asset sales;
- limitation on transactions with affiliates; and
- limitation on additional indebtedness and issuance of
preferred stock unless the Fixed Charge Coverage Ratio for our
most recently ended four full fiscal quarters is at least 2 to
1, determined on a proforma basis.
While we do not expect to exceed the fixed charge covenant ratio until the end
of 2005, the covenant includes a provision that allows us to refinance our
existing revolver and letter of credit facility. These restrictions may be
lifted if certain conditions, including our attaining an investment grade rating
from both Moody's Investors Service and Standard and Poor's are met.
99.4-40
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
A summary of significant issuances and retirements of long-term debt,
including capital leases, as well as the items listed above, for the year ended
December 31, 2003, is as follows:
PRINCIPAL
ISSUE/TERMS DUE DATE AMOUNT
----------- -------- --------
(MILLIONS)
Issuances of long-term debt in 2003:
8.125% senior notes (Northwest Pipeline)............................ 2010 $ 175.0
RMT term B loan (Exploration & Production).......................... 2007 500.0
5.5% junior subordinated convertible debentures..................... 2033 300.0
8.625% senior unsecured notes....................................... 2010 800.0
1.97% Midstream Venezuela Project Financing -- SACE................. 2016 105.0
6.62% Midstream Venezuela Project Financing -- OPIC................. 2016 125.0
Retirements/prepayments of long-term debt in 2003:
Preferred interests................................................. 2003-2006 $ 302.5
Various capital leases.............................................. 2005 139.8
Various notes, 6.125%-9.45%......................................... 2003-2004 247.4
Various notes, adjustable rate...................................... 2003-2004 531.2
Various debentures.................................................. 2003 7.5
Debt tender offers/consent solicitations accepted for purchase...... 2003-2022 951.4
Terms of certain of our subsidiaries' borrowing arrangements with lenders
limit the transfer of funds to the corporate parent. At December 31, 2003,
approximately $105 million of net assets of consolidated subsidiaries was
restricted. Of this amount, $91 million is reported as restricted cash on our
Consolidated Balance Sheet. In addition, certain equity method investees'
borrowing arrangements and foreign government regulations limit the amount of
dividends or distributions to the corporate parent. Restricted net assets of
equity method investees was approximately $86 million at December 31, 2003.
Aggregate minimum maturities of long-term debt for each of the next five
years are as follows:
(MILLIONS)
----------
2004......................................... $ 932.3
2005......................................... 246.8
2006......................................... 971.7
2007......................................... 2,019.6
2008......................................... 384.9
As noted above, the FELINE PACS are subject to remaketing in 2004. If the
2004 remarketing is unsuccessful, a second remarketing will occur in February of
2005. If this attempt at remarketing is unsuccessful, we could exercise our
right to foreclose on the notes in order to satisfy the obligation of the
holders of the equity forward contracts requiring the holder to purchase our
common stock (see Note 13). This would be a non-cash transaction. Otherwise, the
notes are not subject to early retirement.
Cash payments for interest (net of amounts capitalized) and other fees
recorded as interest expense were as follows: 2003 -- $1.3 billion; 2002 -- $856
million; and 2001 -- $548 million.
LEASES-LESSEE
Future minimum annual rentals under noncancelable operating leases as of
December 31, 2003, are payable as follows:
(MILLIONS)
----------
2004......................................... $ 41.8
2005......................................... 36.3
2006......................................... 25.8
2007......................................... 20.1
2008......................................... 19.4
Thereafter................................... 54.9
----------
Total........................................ $ 198.3
==========
99.4-41
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Total rent expense was $110 million in 2003, $93 million in 2002, and $89
million in 2001. In 2003, sublease income from third parties was $16.5 million.
In July 2002, we amended the terms of an operating lease with a
special-purpose entity owned by third parties through which we leased offshore
oil and gas pipelines and an onshore gas processing plant. The amended terms
caused the lease to be reclassified as a capital lease. The capital lease
obligation, which was $139.9 million at December 31, 2002, was paid off in
second-quarter 2003.
NOTE 12. PREFERRED INTERESTS IN CONSOLIDATED SUBSIDIARIES
Prior to 2003, we transferred certain of our assets into newly created
consolidated entities and then sold a non-controlling preferred interest in
those entities to outside investors. The outside investors in three of the
entities were unconsolidated special purpose entities formed solely for the
purpose of purchasing the preferred ownership interest in the respective entity.
The special purpose entities were capitalized with no less than three-percent
equity from an independent third party. The outside investor in the fourth
entity was not a special purpose entity. In each case, the outside investor was
entitled to priority distributions from the consolidated entity. The assets and
liabilities of these entities are included in the Consolidated Balance Sheet,
with the obligations to the outside investors reflected as debt. In 2002 and
2003, we paid the remaining obligations to the outside investors in these
entities, as further described below.
SNOW GOOSE ASSOCIATES, L.L.C.
In December 2000, we formed two separate legal entities, Snow Goose
Associates, L.L.C. (Snow Goose) and Arctic Fox Assets, L.L.C. (Arctic Fox) for
the purpose of generating funds to invest in certain Canadian energy-related
assets. An outside investor contributed $560 million in exchange for the
non-controlling preferred interest in Snow Goose. The investor in Snow Goose was
entitled to quarterly priority distributions, representing an adjustable rate
structure. The initial priority return period was scheduled to expire in
December 2005.
During first-quarter 2002, the terms of the priority return were amended.
Significant terms of the amendment included elimination of covenants regarding
our credit ratings, modifications of certain Canadian interest coverage
covenants and a requirement to amortize the outside investor's preferred
interest with equal principal payments due each quarter and the final payment in
April 2003. In addition, we provided a financial guarantee of the Arctic Fox
note payable to Snow Goose which, in turn, is the source of the priority
returns. Based on the terms of the amendment, the remaining balance due of $224
million was classified as long-term debt due within one year on our Consolidated
Balance Sheet at December 31, 2002. Priority returns prior to this amendment are
included in preferred returns and minority interest in income of consolidated
subsidiaries on the Consolidated Statement of Operations. Subsequent priority
return payments are included in interest accrued on the Consolidated Statement
of Operations.
In April 2003, we purchased the remaining outside investors' interest in
Snow Goose.
PICEANCE PRODUCTION HOLDINGS LLC
In December 2001, we formed Piceance Production Holdings LLC (Piceance)
and Rulison Production Company LLC (Rulison) in a series of transactions that
resulted in the sale of a non-controlling preferred interest in Piceance to an
outside investor for $100 million. We used the proceeds of the sale for general
corporate purposes. The assets of Piceance included fixed-price overriding
royalty interests in certain oil and gas properties owned by a subsidiary of
ours as well as a $135 million note from Rulison. The outside investor was
entitled to quarterly priority distributions beginning in January 2002, based
upon an adjustable rate structure in addition to participation in a portion of
the operating results of Piceance. At December 31, 2002, the obligation to the
outside investor was $78.5 million and in May 2003, we purchased the remaining
outside investors' interest in Piceance.
CASTLE ASSOCIATES L.P.
In December 1998, we formed Castle Associates L.P. (Castle) through a
series of transactions that resulted in the sale of a non-controlling preferred
interest in Castle to an outside investor for $200 million. We used the proceeds
of the sale for general corporate purposes. The outside investor was entitled to
quarterly priority distributions based upon an adjustable rate structure, in
addition to a portion of the participation in the operating results of Castle.
We purchased the outside investors' interest in December 2002.
99.4-42
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
WILLIAMS RISK HOLDINGS L.L.C.
During 1998, we formed Williams Risk Holdings L.L.C. (Holdings) in a
series of transactions that resulted in the sale of a non-controlling preferred
interest in Holdings to an outside investor for $135 million. We used the
proceeds from the sale for general corporate purposes. The outside investor in
Holdings was not a special purpose entity. The outside investor was entitled to
monthly preferred distributions based upon an adjustable rate structure, in
addition to participation in a portion of the operating results of Holdings. The
initial priority return structure of Holdings was scheduled to expire in
September 2003. In July 2002, following the downgrade of our senior unsecured
rating we purchased the outside investor's ownership interest.
NOTE 13. STOCKHOLDERS' EQUITY
Concurrent with the sale of Kern River to MidAmerican Energy Holdings
Company (MEHC) on March 27, 2002, we issued approximately 1.5 million shares of
9.875 percent cumulative convertible preferred stock to MEHC for $275 million.
The terms of the preferred stock allowed the holder to convert, at any time, one
share of preferred stock into 10 shares of our common stock at $18.75 per share.
The preferred shares carried no voting rights and had a liquidation preference
equal to the stated value of $187.50 per share plus any dividends accumulated
and unpaid. Dividends on the preferred stock were payable quarterly. At the time
the preferred stock was issued, the conversion price was less than the market
price of our common stock and thus deemed beneficial to the purchaser. The
benefit was recorded as a noncash dividend of $69.4 million, which was a
reduction to our retained earnings with an offsetting amount recorded as an
increase to capital in excess of par value.
On June 10, 2003, we redeemed all of the outstanding 9.875 percent
cumulative-convertible preferred shares for approximately $289 million, plus
$5.3 million for accrued dividends. The $13.8 million payments in excess of
carrying value of the shares was also recorded as a dividend. These shares were
repurchased with proceeds from a private placement of 5.5 percent junior
subordinated convertible debentures due 2033 (see Note 11).
In January 2002, we issued $1.1 billion of 6.5 percent notes payable in
2007 which are subject to remarketing in 2004. Each note was bundled with an
equity forward contract (together, the FELINE PACS units) and sold in a public
offering for $25 per unit. The equity forward contract requires the holder of
each note to purchase one share of our common stock for $25 three years from
issuance of the contract, provided that the average price of our common stock
does not exceed $41.25 per share for the 20 trading day period prior to
settlement. If the average price over that period exceeds $41.25 per share, the
number of shares issued in exchange for $25 will be equal to one share
multiplied by the quotient of $41.25 divided by the average price over that
period. For example, if the average price at settlement is $45 per share, the
holder will be required to purchase .9166 of a share for $25. The holder of the
equity forward contract can settle the contract early in the event we are
involved in a merger in which at least 30 percent of the proceeds received by
our shareholders is cash. In this event, the holder will be entitled to pay the
purchase price and receive the kind and amount of securities they would have
received had they settled the equity forward contract immediately prior to the
acquisition. In addition to the 6.5 percent interest payment on the notes, we
also make a 2.5 percent annual contract adjustment payment for the term of the
equity forward contract. The present value of the total of the contract
adjustment payments at the date the FELINE PACS were issued was $76.7 million
and was recorded as a liability and a reduction to capital in excess of par at
that time. A periodic charge is recognized in income to increase the value of
the related liability as the date of the common stock issuance approaches.
We maintain a Stockholder Rights Plan under which each outstanding share
of our common stock has one-third of a preferred stock purchase right attached.
Under certain conditions, each right may be exercised to purchase, at an
exercise price of $140 (subject to adjustment), one two-hundredth of a share of
Series A Junior Participating Preferred Stock. The rights may be exercised only
if an Acquiring Person acquires (or obtains the right to acquire) 15 percent or
more of our common stock; or commences an offer for 15 percent or more of our
common stock; or the Board of Directors determines an Adverse Person has become
the owner of a substantial amount of our common stock. The rights, which until
exercised do not have voting rights, expire in 2006 and may be redeemed at a
price of $.01 per right prior to their expiration, or within a specified period
of time after the occurrence of certain events. In the event a person becomes
the owner of more than 15 percent of our common stock or the Board of Directors
determines that a person is an Adverse Person, each holder of a right (except an
Acquiring Person or an Adverse Person) shall have the right to receive, upon
exercise, our common stock having a value equal to two times the exercise price
of the right. In the event we are engaged in a merger, business combination or
50 percent or more of our assets, cash flow or earnings power is sold or
transferred, each holder of a right (except an Acquiring Person or an Adverse
Person) shall have the right to receive, upon exercise, common stock of the
acquiring company having a value equal to two times the exercise price of the
right.
99.4-43
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
NOTE 14. STOCK-BASED COMPENSATION
PLAN INFORMATION
On May 16, 2002, our stockholders approved The Williams Companies, Inc.
2002 Incentive Plan (the "Plan"). The Plan provides for common-stock-based
awards to both employees and non-management directors. Upon approval by the
stockholders, all prior stock plans were terminated resulting in no further
grants being made from those plans. However, options outstanding in those prior
plans remain in those plans with their respective terms and provisions.
The Plan permits the granting of various types of awards including, but
not limited to, stock options, restricted stock and deferred stock. Awards may
be granted for no consideration other than prior and future services or based on
certain financial performance targets being achieved. At December 31, 2003, 56.2
million shares of our common stock were reserved for issuance pursuant to
existing and future stock awards, of which 28.3 million shares were available
for future grants (14.8 million at December 31, 2002).
LOANS
Several of our prior stock plans allowed us to loan money to participants
to exercise stock options using stock certificates as collateral. Effective
November 14, 2001, we no longer issue loans under the stock option loan
programs. Loan holders were offered a one-time opportunity in January 2002 to
refinance outstanding loans at a market rate of interest commensurate with the
borrower's credit standing. The refinancing was in the form of a full recourse
note, with interest payable annually in cash and a loan maturity date of
December 31, 2005. We continue to hold the collateral shares and may review the
borrower's financial position at any time. The variable rate of interest on the
loans was determined at the signing of the promissory note to be 1.75 percent
plus the current three-month London Interbank Offered Rate (LIBOR). The rate is
subject to change every three months beginning with the first three-month
anniversary of the note. The amount of loans outstanding at December 31, 2003
and 2002, totaled approximately $28 million (net of a $5 million allowance) and
$30.3 million (net of a $5 million allowance), respectively.
DEFERRED SHARES
We granted deferred shares of approximately 158,000 in 2003, 2,738,000 in
2002 and 1,423,000 in 2001. Deferred shares are valued at the date of award, and
the weighted-average grant date fair value of the shares granted was $4.68 in
2003, $12.26 in 2002 and $40.84 in 2001. We recognized approximately $30
million, $31 million and $22 million of expense for deferred shares, net of the
reduction of expense from forfeited shares, in 2003, 2002 and 2001,
respectively. Expense related to deferred shares granted is recognized in the
performance year or over the vesting period, depending on the terms of the
awards. The reduction of expense related to the deferred shares forfeited is
recognized in the year of the forfeiture. We issued approximately 1,329,000 in
2003, 499,000 in 2002 and 260,000 in 2001, of the deferred shares previously
granted.
OPTIONS
The purchase price per share for stock options may not be less than the
market price of the underlying stock on the date of grant. Stock options
generally become exercisable after three years from the date of grant and
generally expire ten years after grant.
On May 15, 2003, our shareholders approved a stock option exchange
program. Under this program, eligible employees were given a one-time
opportunity to exchange certain outstanding options for a proportionately lesser
number of options at an exercise price to be determined at the grant date of the
new options. Surrendered options were cancelled June 26, 2003, and replacement
options were granted on December 29, 2003. We did not recognize any expense
pursuant to the stock option exchange. However, for purposes of pro forma
disclosures, we recognized additional expense related to these new options. The
remaining expense on the cancelled options will be amortized through year-end
2004.
99.4-44
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The following summary reflects stock option activity for our common stock
and related information for 2003, 2002 and 2001:
2003 2002 2001
----------------------- --------------------- -------------------------
WEIGHTED- WEIGHTED- WEIGHTED-
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
OPTIONS PRICE OPTIONS PRICE OPTIONS PRICE
------- --------- ------- --------- ------- ---------
(MILLIONS) (MILLIONS) (MILLIONS)
Outstanding -- beginning of year ..... 38.8 $ 19.85 25.6 $ 28.23 23.1 $ 28.63
Granted .............................. 4.1* 9.76 15.8 6.64 4.8 37.45
Exercised ............................ (.2) 5.86 (.5) 11.77 (3.3) 18.47
Barrett option conversions ........... -- -- -- -- 2.0 21.57
Adjustment for WilTel spinoff(1) ..... -- -- -- -- 2.1 --
Canceled ............................. (17.0)** 25.60 (2.1) 26.31 (3.1) 32.35
----- ---- ----
Outstanding -- end of year ........... 25.7 $ 14.63 38.8 $ 19.85 25.6 $ 28.23
===== ==== ====
Exercisable -- end of year ........... 12.3 $ 24.23 21.7 $ 27.42 20.0 $ 26.41
===== ==== ====
* Includes 3.9 million shares that were granted December 29, 2003,
under the stock option exchange program, described above.
** Includes 10.4 million shares that were cancelled on June 26, 2003
under the stock option exchange program, described above.
(1) Effective with the spinoff of WilTel on April 23, 2001, the number and
exercise price of unexercised stock options were adjusted to preserve the
intrinsic value of the stock options that existed prior to the spinoff.
The following summary provides information about options for our common
stock that are outstanding and exercisable at December 31, 2003:
STOCK OPTIONS OUTSTANDING STOCK OPTIONS EXERCISABLE
---------------------------------------- -------------------------
WEIGHTED-
WEIGHTED- AVERAGE WEIGHTED-
AVERAGE REMAINING AVERAGE
EXERCISE CONTRACTUAL EXERCISE
RANGE OF EXERCISE PRICES OPTIONS PRICE LIFE OPTIONS PRICE
------------------------ ------- --------- ----------- ------- ---------
(MILLIONS) (MILLIONS)
$1.35 to $5.40.............................. 10.0 $ 2.82 8.7 years 1.2 $ 4.28
$6.96 to $9.70.............................. .8 8.68 1.1 years .8 8.68
$10.00 to $12.22............................ 4.5 10.21 5.2 years .7 11.40
$12.59 to $31.56............................ 5.8 20.39 3.4 years 5.2 20.86
$33.51 to $42.52............................ 4.6 37.74 3.8 years 4.4 37.87
---- ----
Total..................................... 25.7 $ 14.63 5.8 years 12.3 $ 24.23
==== ====
99.4-45
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The estimated fair value at date of grant of options for our common stock
granted in 2003, 2002 and 2001, using the Black-Scholes option pricing model, is
as follows:
2003* 2002 2001
------- -------- ------
Weighted-average grant date fair value of options for our common stock granted during the year.. $ 2.95 $ 2.77 $10.93
======= ======== ======
Assumptions:
Dividend yield................................................................................ 1% 1% 1.9%
Volatility.................................................................................... 50% 56% 35%
Risk-free interest rate....................................................................... 3.1% 3.6% 4.8%
Expected life (years)......................................................................... 5.0 5.0 5.0
* The 2003 weighted average fair value and assumptions do not reflect
options that were granted December 29, 2003, as part of the stock option
exchange program which is described above. The fair value of these options
is $1.58, which is the difference in the fair value of the new options
granted and the fair value of the exchanged options. The assumptions used
in the fair value calculation of the new options granted were: 1) dividend
yield of .40 percent; 2) volatility of 50 percent; 3) weighted average
expected remaining life of 3.4 years; and 4) weighted average risk free
interest rate of 1.99 percent.
Pro forma net income (loss) and earnings per share, assuming we had
applied the fair-value method of SFAS No. 123, "Accounting for Stock-Based
Compensation" in measuring compensation cost beginning with 1997 employee
stock-based awards is disclosed under Employee stock-based awards in Note 1.
NOTE 15. FINANCIAL INSTRUMENTS, DERIVATIVES, GUARANTEES AND CONCENTRATION OF
CREDIT RISK
FINANCIAL INSTRUMENTS FAIR VALUE
Fair-value methods
We used the following methods and assumptions in estimating our fair-value
disclosures for financial instruments:
Cash and Cash Equivalents and Restricted Cash: The carrying amounts
reported in the balance sheet approximate fair value due to the short-term
maturity of these instruments.
Notes and Other Non-current Receivables, Margin Deposits and Deposits
Received from Customers Relating to Energy Trading and Hedging Activities: The
carrying amounts reported in the balance sheet approximate fair value as these
instruments have interest rates approximating market or maturities of less than
three years.
Restricted Investments and Marketable Equity Securities: The restricted
investments consist of short-term U.S. Treasury securities. Fair value is
determined using indicative year-end traded prices.
Advances to Affiliates: The 2003 carrying amounts reported in the balance
sheet approximate fair value as these instruments were written down to estimated
fair value based on terms of a recapitalization plan (see Note 3). The 2002
carrying amounts, reported in the balance sheet in Investments approximate fair
value as these instruments have interest rates approximating market.
Notes Payable: Fair value of the RMT note payable in 2002 was determined
using the expertise of outside investment banking firms. The carrying amounts of
other notes payable approximate fair value due to the short-term maturity of
these instruments.
Long-Term Debt: The fair value of our publicly traded long-term debt is
valued using indicative year-end traded bond market prices. Private debt is
valued based on the prices of similar securities with similar terms and credit
ratings. At December 31, 2003 and 2002, 77 percent and 76 percent, respectively,
of our long-term debt was publicly traded. We used the expertise of outside
investment banking firms to assist with the estimate of the fair value of
long-term debt.
99.4-46
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Energy Derivatives: Energy derivatives include:
- futures contracts,
- forward purchase and sale contracts,
- swap agreements,
- option contracts,
- interest-rate swap agreements and futures contracts, and
- credit default swaps.
Fair value of energy derivatives is determined based on the nature of the
transaction and the market in which transactions are executed. Most of these
transactions are executed in exchange-traded or over-the-counter markets for
which quoted prices in active periods exist. For contracts with lives exceeding
the time period for which quoted prices are available, we determined fair value
by estimating commodity prices during the illiquid periods. We estimated
commodity prices during illiquid periods by incorporating information obtained
from commodity prices in actively quoted markets, prices reflected in current
transactions and market fundamental analysis.
Foreign Currency Derivatives: Fair value is determined by discounting
estimated future cash flows using forward foreign exchange rates derived from
the year-end forward exchange curve. Fair value was calculated by the financial
institution that is counterparty to the agreement.
Interest-Rate Swaps: Fair value is determined by discounting estimated
future cash flows using forward-interest rates derived from the year-end yield
curve. The financial institutions that are the counterparties to the swaps
calculated the fair value.
99.4-47
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Carrying Amounts and Fair Values of Our Financial Instruments
2003 2002
------------------------------ ----------------------------
CARRYING FAIR CARRYING FAIR
ASSET (LIABILITY) AMOUNT VALUE AMOUNT VALUE
----------------- ------------ ------------ ------------ ------------
(MILLIONS)
Cash and cash equivalents ................................. $ 2,315.7 $ 2,315.7 $ 1,650.4 $ 1,650.4
Restricted cash (current and noncurrent) .................. 206.9 206.9 290.9 290.9
Notes and other noncurrent receivables .................... 140.0 140.0 164.9 164.9
Investments:
Cost based investments .................................. 112.7 (a) 163.9 (a)
Restricted investments (current and noncurrent) ......... 381.3 381.3 -- --
Marketable equity securities ............................ -- -- 13. 7 13.7
Advances to affiliates .................................. 117.2 117.2 100.9 100.9
Notes payable ............................................. (3.3) (3.3) (996.3) (1,063.1)
Long-term debt, including current portion ................. (11,975.0) (12,281.5) (12,016.7) (8,505.5)
Margin deposits ........................................... 553.9 553.9 804.8 804.8
Deposits received from customers relating to energy risk
management and trading and hedging activities ........... (25.8) (25.8) (141.2) (141.2)
Guarantees ................................................ 46.8 (b) 65.7 (b)
Energy derivatives:
Energy trading and non-trading derivatives .............. 845.9 845.9 465.9 465.9
Energy commodity cash flow and fair-value hedges ........ (296.4) (296.4) 49.3 49.3
Foreign currency derivatives .............................. (55.2) (55.2) 24.0 24.0
Interest-rate swaps ....................................... (20.2) (20.2) (27.9) (27.9)
(a) These investments are primarily in non-publicly traded companies for which
it is not practicable to estimate fair value.
(b) It is not practicable to estimate the fair value of these financial
instruments because of their unusual nature and unique characteristics.
ENERGY DERIVATIVES
Energy trading and non-trading derivatives
We have energy trading and non-trading derivatives that have not been
designated as or do not qualify as SFAS No. 133 hedges. As such, the net change
in their fair value is recognized in earnings. Our Power segment has trading
derivatives that provide risk management services to our third-party customers
and non-trading derivatives that hedge or could possibly hedge our long-term
structured contract positions on an economic basis. In addition, our Exploration
& Production segment enters into natural gas basis swap agreements and the
Alaska operations (within discontinued operations) enters into crude oil and
refined product contracts.
We also hold significant non-derivative energy-related contracts in our
Power trading and non-trading portfolios. These have not been included in the
financial instruments table above because they do not qualify as financial
instruments. See Note 1 regarding Energy commodity risk management and trading
activities and revenues for further discussion of the non-derivative
energy-related contracts.
99.4-48
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
POWER SEGMENT
Futures Contracts: Futures contracts are commitments to either purchase or
sell a commodity at a future date for a specified price and are generally
settled in cash, but may be settled through delivery of the underlying
commodity. Exchange-traded or over-the-counter markets providing quoted prices
in active periods are available. Where quoted prices are not available, other
market indicators exist for the futures contracts we enter into. The fair value
of these contracts is based on quoted prices.
Swap Agreements and Forward Purchase and Sale Contracts: Swap agreements
require us to make payments to (or receive payments from) counterparties based
upon the differential between a fixed and variable price or variable prices of
energy commodities for different locations. Forward contracts which involve
physical delivery of energy commodities contain both fixed and variable pricing
terms. Swap agreements and forward contracts are valued based on prices of the
underlying energy commodities over the contract life and contractual or notional
volumes with the resulting expected future cash flows discounted to a present
value using a risk-free market interest rate.
Options: Physical and financial option contracts give the buyer the right
to exercise the option and receive the difference between a predetermined strike
price and a market price at the date of exercise. These contracts are valued
based on option pricing models considering prices of the underlying energy
commodities over the contract life, volatility of the commodity prices,
contractual volumes, estimated volumes under option and other arrangements and a
risk-free market interest rate.
Interest-Rate and Credit Derivatives: Interest-rate swap and futures
agreements, including those with the parent, are used to manage the interest
rate risk in Power's energy trading and non-trading portfolio. Under swap
agreements, Power pays a fixed rate and receives a variable rate on the notional
amount of the agreements. Financial futures contracts are commitments to either
purchase or sell a financial instrument, such as a Eurodollar deposit, U.S.
Treasury bond or U.S. Treasury note, at a future date for a specified price.
These are generally settled in cash, but may be settled through delivery of the
underlying instrument. The fair value of these contracts is determined by
discounting estimated future cash flows using forward interest rates derived
from interest rate yield curves. Credit default swaps are used to manage
counterparty credit exposure in the energy trading and non-trading portfolio.
Under these agreements, Power pays a fixed rate premium for a notional amount of
risk coverage associated with certain credit events. The covered credit events
are bankruptcy, obligation acceleration, failure to pay and restructuring. The
fair value of these agreements is based on current pricing received from the
counterparties.
The valuation of all the contracts discussed above also considers factors
such as the liquidity of the market in which the contract is transacted,
uncertainty regarding the ability to liquidate the position considering market
factors applicable at the date of such valuation and risk of non-performance and
credit considerations of the counterparty. For contracts or transactions that
extend into periods for which actively quoted prices are not available, we
estimate energy commodity prices in the illiquid periods by incorporating
information obtained from commodity prices in actively quoted markets, prices
reflected in current transactions and market fundamental analysis.
EXPLORATION & PRODUCTION SEGMENT
Our operations associated with the production of natural gas enter into
basis swap agreements fixing the price differential between the Rocky Mountain
natural gas prices and Gulf Coast natural gas prices as part of their overall
natural gas price risk management program to reduce risk of declining natural
gas prices in basins with limited pipeline capacity to other markets. Certain of
these basis swaps do not qualify for hedge accounting treatment under SFAS No.
133; hence, the net change in fair value of these derivatives representing
unrealized gains and losses is recognized in earnings currently as revenues in
the Consolidated Statement of Operations.
DISCONTINUED OPERATIONS
During 2002 and early 2003, our operations associated with crude oil
refining and refined products marketing in the Midsouth entered into derivative
transactions (primarily forward contracts, futures contracts, swap agreements
and option contracts) which were not designated as hedges. The forward contracts
were for the procurement of crude oil and refined products supply for
operational purposes, while the other derivatives manage certain risks
associated with market fluctuations in crude oil and refined product prices
related to refined products marketing. The net change in fair value of these
derivatives, representing unrealized gains and losses, was recognized in
earnings currently as revenues or costs and operating expenses in the
Consolidated Statement of Operations. As a result of the completion of the sale
of the Midsouth refinery during first-quarter 2003, these derivatives were
discontinued.
99.4-49
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Energy commodity cash flow hedges
We are also exposed to market risk from changes in energy commodity prices
within other areas of our operations. We utilize derivatives to manage our
exposure to the variability in expected future cash flows attributable to
commodity price risk associated with forecasted purchases and sales of natural
gas, refined products and crude oil. These derivatives have been designated as
cash flow hedges.
We produce, buy and sell natural gas and crude oil at different locations
throughout the United States. To reduce exposure to a decrease in revenues or an
increase in costs from fluctuations in natural gas and crude oil market prices,
we enter into natural gas and crude oil futures contracts and swap agreements to
fix the price of anticipated sales and purchases of natural gas and sales of
crude oil. During 2003, we discontinued hedge accounting for anticipated sales
of crude oil due to the sale of those producing properties.
Our refinery operations purchase crude oil for processing and sell the
refined products. These operations are exposed to increasing costs of crude oil
and/or decreasing refined product sales prices due to changes in market prices.
We enter into crude oil and refined products futures contracts and swap
agreements to lock in the prices of anticipated purchases of crude oil and sales
of refined products. During 2002, these derivatives were accounted for as cash
flow hedges. Hedge accounting was discontinued during 2002 for forecasted
transactions no longer probable of occurring because of the anticipated sales of
the refineries (see Note 2).
Our electric generation facilities utilize natural gas in the production
of electricity. To reduce the exposure to increasing costs of natural gas due to
changes in market prices, we enter into natural gas futures contracts and swap
agreements to fix the prices of anticipated purchases of natural gas. In
addition, during 2002 we entered into fixed-price forward physical contracts to
fix the prices of anticipated sales of electric production. During 2002, we
discontinued hedge accounting for one of the electric generation facilities due
to the sale of the facility in 2003.
Derivative gains or losses from these cash flow hedges are deferred in
other comprehensive income and reclassified into earnings in the same period or
periods during which the hedged forecasted purchases or sales affect earnings.
To match the underlying transaction being hedged, derivative gains or losses
associated with anticipated purchases are recognized in costs and operating
expenses and amounts associated with anticipated sales are recognized in
revenues in the Consolidated Statement of Operations. Approximately $.6 million
of gains from hedge ineffectiveness are included in costs and operating expenses
in the Consolidated Statement of Operations during 2003. Approximately $.5
million of losses and $.7 million of gains from hedge ineffectiveness are
included in revenues and costs and operating expenses, respectively, in the
Consolidated Statement of Operations during 2002. We discontinued hedge
accounting in 2003 and 2002 for certain contracts when it became probable that
the related forecasted transactions would not occur. As a result, we
reclassified net losses of $5 million and net gains of $43 million from
accumulated other comprehensive income and into earnings in the Consolidated
Statement of Operations in 2003 and 2002, respectively. For 2003 and 2002, there
were no derivative gains or losses excluded from the assessment of hedge
effectiveness. As of December 31, 2003, we had hedged future cash flows
associated with anticipated energy commodity purchases and sales for up to 12
years. Based on recorded values at December 31, 2003, approximately $104 million
of net losses (net of income tax benefits of $65 million) will be reclassified
into earnings within the next year. These losses will offset net gains that will
be realized in earnings from previous favorable market movements associated with
underlying hedged transactions.
Energy commodity fair-value hedges
Our refineries carry inventories of crude oil and refined products. During
2002, we entered into crude oil and refined products futures contracts and swap
agreements to reduce the market exposure of these inventories from changing
energy commodity prices. These derivatives were designated as fair-value hedges.
Derivative gains and losses from these fair-value hedges were recognized in
earnings currently along with the change in fair value of the hedged item
attributable to the risk being hedged. Gains and losses related to hedges of
inventory were recognized in costs and operating expenses in the Consolidated
Statement of Operations. Approximately $8 million of net gains from hedge
ineffectiveness was recognized in costs and operating expenses in the
Consolidated Statement of Operations during 2002. There were no derivative gains
or losses excluded from the assessment of hedge effectiveness. During
third-quarter 2002, we discontinued the use of fair value hedges related to
refined products and crude oil in early 2003 due to the sale of the Midsouth
refinery.
99.4-50
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
FOREIGN CURRENCY DERIVATIVES
We have an intercompany Canadian-dollar-denominated note receivable that
is exposed to foreign-currency risk. To protect against variability in the cash
flows from the repayment of the note receivable associated with changes in
foreign currency exchange rates, we entered into a forward contract to fix the
U.S. dollar principal cash flows from this note. This derivative was designated
as a cash flow hedge and was expected to be highly effective over the period of
the hedge. Hedge accounting was discontinued effective October 1, 2002 because
the hedge is no longer expected to be highly effective. All gains or losses
subsequent to October 1, 2002, are recognized currently in other income
(expense) -- net below operating income. Gains and losses from the change in
fair value of the derivatives prior to October 1, 2002, were deferred in other
comprehensive income (loss) and reclassified to other income (expense) -- net
below operating income as the Canadian-dollar-denominated note receivable
impacted earnings as it was translated into U.S. dollars. The $2.4 million of
net losses (net of income tax benefits of $1.5 million) deferred in other
comprehensive income (loss) at December 31, 2002, was reclassified into earnings
during 2003. In 2002, there were no derivative gains or losses recorded in the
Consolidated Statement of Operations from hedge ineffectiveness or from amounts
excluded from the assessment of hedge effectiveness, and no foreign currency
hedges were discontinued as a result of it becoming probable that the forecasted
transaction would not occur.
INTEREST-RATE SWAPS
We managed our interest rate risk on an enterprise basis through the
corporate parent. A significant component of this risk relates to our Power
segment's trading and non-trading portfolios. To facilitate the management of
the risk, Power may enter into derivative instruments (usually swaps) with the
corporate parent. The corporate parent determines the level, term and nature of
derivative instruments entered into with external parties. These external
derivative instruments do not qualify for hedge accounting per SFAS No. 133;
therefore, changes in their fair value are reflected in earnings, the effect of
which is shown as interest rate swap loss in the Consolidated Statement of
Operations below operating income.
GUARANTEES
In addition to the guarantees and payment obligations discussed elsewhere
in these footnotes (see Notes 2, 3, 11 and 16), we have issued guarantees and
other similar arrangements with off-balance sheet risk as discussed below.
In connection with the 1993 public offering of units in the Williams Coal
Seam Gas Royalty Trust (Royalty Trust), our Exploration & Production segment
entered into a gas purchase contract for the purchase of natural gas in which
the Royalty Trust holds a net profits interest. Under this agreement, we
guarantee a minimum purchase price that the Royalty Trust will realize in the
calculation of its net profits interest. We have an annual option to discontinue
this minimum purchase price guarantee and pay solely based on an index price.
The maximum potential future exposure associated with this guarantee is not
determinable because it is dependent upon natural gas prices and production
volumes. No amounts have been accrued for this contingent obligation as the
index price continues to exceed the minimum purchase price.
SALE OF RECEIVABLES
Through July 25, 2002 we sold certain trade accounts receivable to special
purpose entities (SPEs) in a securitization structure. We acted as the servicing
agent for the sold receivables and received a servicing fee approximating the
fair value of such services. During 2002 and 2001, we received cash proceeds
from the SPEs of approximately $4.5 billion and $12.5 billion, respectively. The
sales of these receivables resulted in charges to results of operations of
approximately $3 million and $16 million in 2002 and 2001, respectively.
CONCENTRATION OF CREDIT RISK
Cash equivalents and restricted investments
Our cash equivalents consist of high-quality securities placed with
various major financial institutions with credit ratings at or above BBB by
Standard & Poor's or Baa1 by Moody's Investors Service. Restricted investments
consist of short-term U.S. Treasury Securities.
99.4-51
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Accounts and notes receivable
The following table summarizes concentration of receivables, net of
allowances, by product or service at December 31, 2003 and 2002:
2003 2002
---- ----
(MILLIONS)
Receivables by product or service:
Sale or transportation of natural gas and related products.......... $ 793.9 $ 910.0
Power sales and related services.................................... 704.9 1,009.1
Sale or transportation of petroleum products........................ 29.2 276.9
Income taxes receivable............................................. 17.5 152.0
Other............................................................... 67.7 39.1
--------- ---------
Total............................................................ $ 1,613.2 $ 2,387.1
========= =========
Natural gas customers include pipelines, distribution companies,
producers, gas marketers and industrial users primarily located in the eastern
and northwestern United States, Rocky Mountains, Gulf Coast, Venezuela and
Canada. Power customers include the California Independent System Operator
(ISO), the California Department of Water Resources, other power marketers and
utilities located throughout the majority of the United States. Petroleum
products customers include wholesale, commercial, industrial and independent
dealers located primarily in the Mid-Continent region. As a general policy,
collateral is not required for receivables, but customers' financial condition
and credit worthiness are evaluated regularly.
As of December 31, 2003, approximately $177 million of certain power
receivables net of related allowances from the ISO and the California Power
Exchange have not been paid (compared to $230 million at December 31, 2002). We
believe that we have appropriately reflected the collection and credit risk
associated with receivables and derivative assets in our Consolidated Balance
Sheet and Statement of Operations at December 31, 2003. In 2002, we borrowed
approximately $79 million which was collateralized by certain of these
receivables.
Derivative assets and liabilities
We have a risk of loss as a result of counterparties not performing
pursuant to the terms of their contractual obligations. Risk of loss can result
from credit considerations and the regulatory environment of the counterparty.
We attempt to minimize credit-risk exposure to derivative counterparties and
brokers through formal credit policies, consideration of credit ratings from
public ratings agencies, monitoring procedures, master netting agreements and
collateral support under certain circumstances.
The concentration of counterparties within the energy and energy trading
industry impacts our overall exposure to credit risk in that these
counterparties are similarly influenced by changes in the economy and regulatory
issues. Additional collateral support could include the following:
- letters of credit,
- payment under margin agreements,
- guarantees of payment by credit worthy parties, and
- transfers of ownership interests in natural gas reserves or power
generation assets.
We also enter into netting agreements to mitigate counterparty performance and
credit risk.
99.4-52
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The gross credit exposure from our derivative contracts as of December 31,
2003 is summarized below.
INVESTMENT
COUNTERPARTY TYPE GRADE(a) TOTAL
- --------------------------------------------------- ---------- --------
(MILLIONS)
Gas and electric utilities......................... $ 988.2 $1,045.9
Energy marketers and traders....................... 1,317.2 3,118.5
Financial Institutions............................. 918.5 918.5
Other.............................................. 609.8 619.3
---------- --------
$ 3,833.7 5,702.2
==========
Credit reserves.................................... (39.8)
--------
Gross credit exposure from derivatives(b).......... $5,662.4
========
We assess our credit exposure on a net basis. The net credit exposure from
our derivatives as of December 31, 2003 is summarized below.
INVESTMENT
COUNTERPARTY TYPE GRADE(a) TOTAL
- --------------------------------------------------- ---------- --------
(MILLIONS)
Gas and electric utilities......................... $ 606.1 $ 629.4
Energy marketers and traders..................... 52.1 376.3
Financial Institutions........................... 160.4 160.4
Other............................................ -- .2
---------- --------
$ 818.6 1,166.3
==========
Credit reserves.................................. (39.8)
--------
Net credit exposure from derivatives(b).......... $1,126.5
========
- ----------
(a) We determine investment grade primarily using publicly available credit
ratings. We included counterparties with a minimum Standard & Poor's of
BBB -- or Moody's Investors Service rating of Baa3 in investment grade. We
also classify counterparties that have provided sufficient collateral,
such as cash, standby letters of credit, parent company guarantees, and
property interests, as investment grade.
(b) One counterparty within the California power market represents more than
ten percent of the derivative assets and is included in investment grade.
Standard & Poor's and Moody's Investors Service do not currently rate this
counterparty. We included this counterparty in the investment grade column
based upon contractual credit requirements in the event of assignment or
substitution of a new obligation for the existing one.
Revenues
In 2003, there were no customers that exceeded 10 percent of our revenues.
In 2002, eight of Power's customers exceeded 10 percent of our revenues with
sales from each customer of $516.9 million, $505.5 million, $482.5 million,
$474.8 million, $408.7 million, $379.2 million, $377.5 million and $358.9
million, respectively. The revenues from these customers in 2002 are net of cost
of sales with the same customer consistent with fair-value accounting (see Note
1). The sum of these net revenues exceeds our total revenues because there are
additional customers with whom we have negative net revenues (due to the costs
from these customers exceeding the revenues) which offset this sum. In 2001,
three of Power's customers exceeded 10 percent of our revenues with sales of
$937.7 million, $597.9 million and $501 million, respectively.
Certain of our counterparties have experienced significant declines in
their financial stability and creditworthiness, which may adversely impact their
ability to perform under contracts. Revenues from two counterparties, which have
credit ratings below investment grade, constitute approximately 12 percent of
Power's gross revenues. Our exposure to these counterparties may be mitigated by
the existence of netting arrangements.
99.4-53
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
NOTE 16. CONTINGENT LIABILITIES AND COMMITMENTS
RATE AND REGULATORY MATTERS AND RELATED LITIGATION
Our interstate pipeline subsidiaries have various regulatory proceedings
pending. As a result of rulings in certain of these proceedings, a portion of
the revenues of these subsidiaries has been collected subject to refund. The
natural gas pipeline subsidiaries have accrued approximately $11 million for
potential refund as of December 31, 2003.
ISSUES RESULTING FROM CALIFORNIA ENERGY CRISIS
Power subsidiaries are engaged in power marketing in various geographic
areas, including California. Prices charged for power by us and other traders
and generators in California and other western states in 2000 and 2001 have been
challenged in various proceedings including those before the FERC. These
challenges include refund proceedings, California Independent System Operator
(ISO) fines, summer 2002 90-day contracts, investigations of alleged market
manipulation including withholding gas indices and other gaming of the market,
new long-term power sales to the State of California that were subsequently
challenged and civil litigation relating to certain of these issues. We have
entered into a settlement with the State of California and others that has
resolved each of these issues as to the State. However, certain of these issues
remain open as to the FERC and other non-settling parties.
Refund proceedings
We and other suppliers of electricity in the California market are the
subject of refund proceedings before the FERC. In December 2000, the FERC issued
an order initiating the proceeding, which ultimately (by order dated June 19,
2001) established a refund methodology and set a refund period of October 2,
2000 to June 19, 2001. As a result of a hearing to determine refund liability
for the market participants, a FERC Administrative Law Judge issued findings on
December 12, 2002, that estimated our refund obligation to the ISO at $192
million, excluding emissions costs and interest. The judge estimated that our
refund obligation to the California Power Exchange (PX) was $21.5 million,
excluding interest. However, the judge estimated that the ISO owes us $246.8
million, excluding interest, and that the PX owes us $31.7 million, excluding
interest, and $2.9 million in charge backs. The estimates did not include $17
million in emissions costs that the judge found we are entitled to use as an
offset to the refund liability, and the judge's refund estimates are not based
on final mitigated market clearing prices. On March 26, 2003, the FERC acted to
largely adopt the judge's order with a change to the gas methodology used to set
the clearing price. As a result, Power recorded a first-quarter 2003 charge for
refund obligations of $37 million. Net interest income related to amounts due
from the counterparties is approximately $19 million through December 31, 2003.
On October 16, 2003, the FERC issued an additional refund order granting
rehearing in part and denying rehearing in part. This order is not expected to
have a material effect on the refund calculation for us. However, pursuant to
the October 16 Order, the ISO has been ordered to calculate refunds for the
market. This study is expected to be complete in early summer, 2004. Although we
have entered into a global settlement with the State of California and various
other parties that resolves the refund issues among the settling parties for the
period of January 17, 2001 to June 19, 2001, we have potential refund exposure
to non-settling parties (e.g., various California electric utilities).
Therefore, we continue to participate in the FERC refund case and related
proceedings. Challenges to virtually every aspect of the refund proceeding,
including the refund period, are now pending at the Ninth Circuit Court of
Appeals. No schedule has yet been established for hearing the appeals.
On February 25, 2004, we announced a settlement agreement with California
utilities, Southern California Edison and Pacific Gas & Electric (PG&E), to
resolve our refund liability to the utilities as well as all other known
disputes related to the California energy crisis of 2000 and 2001. While only
these two utilities are parties to the settlement with us, the settlement
provides funding for refunds to all buyers in equal kind in the FERC refund
period. Should any buyer opt out of the settlement, the refund amount in the
settlement would be reduced and we would continue to litigate with that buyer
regarding the refund issue and amount. To be effective, this settlement must be
approved by the FERC, the California Public Utilities Commission, and the U.S.
Bankruptcy Court for PG&E. Approval by the FERC will also resolve FERC
investigations into physical and economic withholding. We recorded a charge of
approximately $33 million in the fourth quarter of 2003 associated with the
terms of this settlement.
In a separate but related proceeding, certain entities have also asked the
FERC to revoke our authority to sell power from California-based generating
units at market-based rates, to limit us to cost-based rates for future sales
from such units and to order refunds of excessive rates, with interest,
retroactive to May 1, 2000, and possibly earlier.
99.4-54
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
ISO fines
On July 3, 2002, the ISO announced fines against several energy producers
including us, for failure to deliver electricity during the period December 2000
through May 2001. The ISO fined us $25.5 million during this period, which was
offset against our claims for payment from the ISO. These amounts will be
adjusted as part of the refund proceeding described above. We believe the vast
majority of fines are not justified and have challenged them pursuant to the
FERC-approved dispute resolution process contained in the ISO tariff.
Summer 2002 90-day contracts
On May 2, 2002, PacifiCorp filed a complaint with the FERC against Power
seeking relief from rates contained in three separate confirmation agreements
between PacifiCorp and Power (known as the Summer 2002 90-Day Contracts).
PacifiCorp filed similar complaints against three other suppliers. PacifiCorp
alleged that the rates contained in the contracts are unjust and unreasonable.
On June 26, 2003, the FERC affirmed the Administrative Law Judge's initial
decision dismissing the complaints. PacifiCorp has appealed the FERC's order
after the FERC denied rehearing of its order on November 10, 2003.
Investigations of alleged market manipulation
As a result of various allegations and FERC Orders, the FERC initiated
investigations of manipulation of the California gas and power markets in 2002.
As they related to us, these investigations included economic and physical
withholding, so-called "Enron Gaming Practices" and gas index manipulation.
On February 13, 2002, the FERC issued an Order Directing Staff
Investigation commencing a proceeding titled Fact-Finding Investigation of
Potential Manipulation of Electric and Natural Gas Prices prior to the
California parties (who include the California Attorney General, the Electricity
Oversight Board, the Public Utilities Commission and two investor-owned
utilities) filing of their report. Through the investigation, the FERC intends
to determine whether "any entity, including Enron Corporation (Enron) (through
any of its affiliates or subsidiaries), manipulated short-term prices for
electric energy or natural gas in the West or otherwise exercised undue
influence over wholesale electric prices in the West since January 1, 2000,
resulting in potentially unjust and unreasonable rates in long-term power sales
contracts subsequently entered into by sellers in the West." On May 8, 2002, we
received data requests from the FERC related to a disclosure by Enron of certain
trading practices in which it may have been engaged in the California market. On
May 21, and May 22, 2002, the FERC supplemented the request inquiring as to
"wash" or "round-trip" transactions. We responded on May 22, 2002, May 31, 2002,
and June 5, 2002, to the data requests. On June 4, 2002, the FERC issued an
order to us to show cause why our market-based rate authority should not be
revoked as the FERC found that certain of our responses related to the Enron
trading practices constituted a failure to cooperate with the staff's
investigation. We subsequently supplemented our responses to address the show
cause order. On July 26, 2002, we received a letter from the FERC informing us
that it had reviewed all of our supplemental responses and concluded that we
responded to the initial May 8, 2002 request.
As also discussed below in REPORTING OF NATURAL GAS-RELATED INFORMATION TO
TRADE PUBLICATIONS, on November 8, 2002, we received a subpoena from a federal
grand jury in Northern California seeking documents related to our involvement
in California markets. We are in the process of completing our response to the
subpoena. This subpoena is a part of the broad United States Department of
Justice (DOJ) investigation regarding gas and power trading.
Pursuant to an order from the Ninth Circuit, the FERC permitted certain
California parties to conduct additional discovery into market manipulation by
sellers in the California markets. The California parties sought this discovery
in order to potentially expand the scope of the refunds. On March 3, 2003, the
California parties submitted evidence from this discovery on market manipulation
("March 3rd Report"). We and other sellers submitted comments regarding the
additional evidence on March 20, 2003.
On March 26, 2003, the FERC issued a Staff Report addressing: (1) Enron
trading practices, (2) an allegation in a June 2, 2002 New York Times article
that we had attempted to corner the gas market, and (3) the allegations of gas
price index manipulation which are discussed in more detail below in REPORTING
OF NATURAL GAS-RELATED INFORMATION TO TRADE PUBLICATIONS. The Staff Report
cleared us on the issue of cornering the market and contemplated or established
further proceedings on the other two issues as to us and numerous other market
participants. On June 25, 2003, the FERC issued a series of orders in response
to the California parties' March 3rd Report and the Staff Report. These orders
resulted in further investigations regarding potential allegations of physical
withholding,
99.4-55
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
economic withholding, and a show cause order alleging that various companies
engaged in Enron trading practices. On August 29, 2003, we entered into a
settlement with the FERC trial staff of all Enron trading practices for
approximately $45,000. The settlement was approved by the FERC on January 22,
2004. The investigations of physical and economic withholding are also
continuing. Each of these FERC investigations of alleged market manipulation
will be resolved pursuant to the February 25 settlement that is discussed above
in Refund proceedings.
Long-term contracts
In February 2001, during the height of the California Energy Crisis, we
entered into a long-term power contract with the State of California to assist
in stabilizing its market. This contract was later challenged by the State of
California. This challenge resulted in settlement discussions being held between
the State and us on the contract issue as well as other state initiated
proceedings and allegations on market manipulation. A settlement was reached
that resulted in us entering into a settlement agreement with the State of
California and other non-Federal parties that includes renegotiated long-term
energy contracts. These contracts are made up of block energy sales,
dispatchable products and a gas contract. The settlement does not extend to
criminal matters or matters of willful fraud, but also resolved civil complaints
brought by the California Attorney General against us and the State of
California's refund claims that are discussed above. In addition, the settlement
resolved ongoing investigations by the States of California, Oregon and
Washington. The settlement was reduced to writing and executed on November 11,
2002. The settlement closed on December 31, 2002, after FERC issued an order
granting our motion for partial dismissal from the refund proceedings. The
dismissal affects our refund obligations to the settling parties, but not to
other parties, such as investor-owned utilities. Pursuant to the settlement, the
California Public Utilities Commission (CPUC) and California Electricity
Oversight Board (CEOB) filed a motion on January 13, 2003 to withdraw their
complaints against us regarding the original block energy sales contract. On
June 26, 2003, the FERC granted the CPUC and CEOB joint motion to withdraw their
respective complaints against us. Certain private class action and other civil
plaintiffs who have initiated class action litigation against us and others in
California based on allegations against us with respect to the California energy
crisis also executed the settlement. Final approval by the court is needed to
make the settlement effective as to plaintiffs and to terminate the class
actions as to us. On October 24, 2003, the court granted a motion for
preliminary approval of the settlement. The final approval hearing is currently
scheduled for June 4, 2004. Upon approval, the majority of civil litigation
involving Williams and California markets will be resolved. Some litigation by
non-California plaintiffs, or relating to reporting of natural gas information
to trade publications, as discussed below, will continue. As of December 31,
2003, pursuant to the terms of the settlement, we have transferred ownership of
six LM6000 gas powered electric turbines, have made two payments totaling $72
million to the California Attorney General, and have funded a $15 million fee
and expense fund associated with civil actions that are subject to the
settlement. An additional $75 million remains to be paid to the California
Attorney General (or his designee) over the next six years, with the final
payment of $15 million due on January 1, 2010.
MARKETING AFFILIATE INVESTIGATION
By order dated March 17, 2003, the FERC approved a settlement between the
FERC staff and us, Transco, and Power which resolved the FERC staff's
allegations during a formal, nonpublic investigation that Power personnel had
access to Transco data bases and other information, and that Transco had failed
to accurately post certain information on its electronic bulletin board.
Pursuant to the terms of the settlement agreement, Transco will pay a civil
penalty in the amount of $20 million in five equal installments. The first
payment was made on May 16, 2003, and the subsequent payments are due on or
before the first, second, third and fourth anniversaries of the first payment.
Transco recorded a charge to income and established a liability of $17 million
in 2002 representing the net present value of the future payments. Transco
notified its Firm Sales (FS) customers of its intention to terminate the FS
service effective April 1, 2005 under the terms of any applicable contracts and
FERC certificates authorizing such services. As part of the settlement, Power
has agreed, subject to certain exceptions, that it will not enter into new
transportation agreements that would increase the transportation capacity it
holds on certain affiliated interstate gas pipelines, including Transco.
Finally, Transco and certain affiliates have agreed to the terms of a compliance
plan designed to ensure future compliance with the provisions of the settlement
agreement and the FERC's rules governing the relationship of Transco and Power.
INVESTIGATION OF "ROUND-TRIP" TRADING AND RESERVES FOR ENERGY TRADING ACTIVITIES
On May 31, 2002, we received a request from the Enforcement Division of
the Securities and Exchange Commission (SEC) to voluntarily produce documents
and information regarding "round-trip" trades for gas or power from January 1,
2000, to the present in the United States. On June 24, 2002, the SEC made an
additional request for information including a request that we address the
amount of our credit, prudency and/or other reserves associated, with our energy
trading activities and the methods used to determine
99.4-56
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
or calculate these reserves. The June 24, 2002, request also requested our
volumes, revenues, and earnings from our energy trading activities in the
Western U.S. market. We have responded to the SEC's requests and have received
no further related requests from them to date.
REPORTING OF NATURAL GAS-RELATED INFORMATION TO TRADE PUBLICATIONS
We disclosed on October 25, 2002, that certain of our natural gas traders
had reported inaccurate information to a trade publication that published gas
price indices. As noted above, on November 8, 2002, we received a subpoena from
a federal grand jury in Northern California seeking documents related to our
involvement in California markets, including our reporting to trade publications
for both gas and power transactions. We are in the process of completing our
response to the subpoena. The DOJ's investigation into this matter is
continuing. In addition, the Commodity Futures Trading Commission (CFTC) has
conducted an investigation of us regarding this issue. On July 29, 2003, we
reached a settlement with the CFTC where in exchange for $20 million, the CFTC
closed its investigation and we did not admit or deny allegations that we had
engaged in false reporting or attempted manipulation. Civil suits based on
allegations of manipulating the gas indices have been brought against us and
others in federal and state court in California and in Federal court in New
York.
MOBILE BAY EXPANSION
On December 3, 2002, an administrative law judge at the FERC issued an
initial decision in Transco's general rate case which, among other things,
rejects the recovery of the costs of Transco's Mobile Bay expansion project from
its shippers on a "rolled-in" basis and finds that incremental pricing for the
Mobile Bay expansion project is just and reasonable. The initial decision does
not address the issue of the effective date for the change to incremental
pricing, although Transco's rates reflecting recovery of the Mobile Bay
expansion project costs on a "rolled-in" basis have been in effect since
September 1, 2001. The administrative law judge's initial decision is subject to
review by the FERC. Power holds long-term transportation capacity on the Mobile
Bay expansion project. If the FERC adopts the decision of the administrative law
judge on the pricing of the Mobile Bay expansion project and also requires that
the decision be implemented effective September 1, 2001, Power could be subject
to surcharges of approximately $41 million, excluding interest, through December
31, 2003, in addition to increased costs going forward.
ENRON BANKRUPTCY
We have outstanding claims against Enron Corp. and various of its
subsidiaries (collectively "Enron") related to Enron's bankruptcy filed in
December 2001. In March 2002, we sold $100 million of our claims against Enron
to a third party for $24.5 million. On December 23, 2003, Enron filed objections
to these claims. Under the sales agreement, the purchaser of the claims may
demand repayment of the purchase price, plus interest assessed at 7.5 percent
per annum, for that portion of the claims still subject to objections 90 days
following the initial objection.
ENVIRONMENTAL MATTERS
Continuing operations
Since 1989, Transco has had studies under way to test certain of its
facilities for the presence of toxic and hazardous substances to determine to
what extent, if any, remediation may be necessary. Transco has responded to data
requests regarding such potential contamination of certain of its sites. Transco
has identified polychlorinated biphenyl (PCB) contamination in compressor
systems, soils and related properties at certain compressor station sites.
Transco has also been involved in negotiations with the U.S. Environmental
Protection Agency (EPA) and state agencies to develop screening, sampling and
cleanup programs. In addition, Transco commenced negotiations with certain
environmental authorities and other programs concerning investigative and
remedial actions relative to potential mercury contamination at certain gas
metering sites. The costs of any such remediation will depend upon the scope of
the remediation. At December 31, 2003, Transco had accrued liabilities of $28
million related to PCB contamination, potential mercury contamination, and other
toxic and hazardous substances.
We also accrue environmental remediation costs for our natural gas
gathering and processing facilities, primarily related to soil and groundwater
contamination. At December 31, 2003, we had accrued liabilities totaling
approximately $11 million for these costs.
Actual costs incurred for these matters will depend on the actual number
of contaminated sites identified, the amount and extent of contamination
discovered, the final cleanup standards mandated by the EPA and other
governmental authorities and other factors.
99.4-57
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Former operations, including operations classified as discontinued
In connection with the sale of certain assets and businesses, we have
retained responsibility, through indemnification of the purchasers, for
environmental and other liabilities existing at the time the sale was
consummated.
AGRICO
In connection with the 1987 sale of the assets of Agrico Chemical Company,
we agreed to indemnify the purchaser for environmental cleanup costs resulting
from certain conditions at specified locations, to the extent such costs exceed
a specified amount. At December 31, 2003, we had accrued liabilities of
approximately $9 million for such excess costs.
WILLIAMS ENERGY PARTNERS
As part of our June 17, 2003 sale of Williams Energy Partners (see Note
2), we indemnified the purchaser for:
(1) environmental cleanup costs resulting from certain conditions,
primarily soil and groundwater contamination, at specified
locations, to the extent such costs exceed a specified amount
and
(2) currently unidentified environmental contamination relating to
operations prior to April 2002 and identified prior to April
2008.
At December 31, 2003, we had accrued liabilities totaling approximately $9
million for these costs. In addition, we deferred a portion of the gain
associated with our indemnifications, including environmental indemnifications,
of the purchaser under the sales agreement. At December 31, 2003, we had a
remaining deferred gain relating to this sale of approximately $96 million.
On July 2, 2001, the EPA issued an information request asking for
information on oil releases and discharges in any amount from our pipelines,
pipeline systems, and pipeline facilities used in the movement of oil or
petroleum products, during the period from July 1, 1998 through July 2, 2001. In
November 2001, we furnished our response. This matter has not become an
enforcement proceeding. On March 11, 2004, the Department of Justice (DOJ)
invited the new owner of the pipeline to enter into negotiations regarding
alleged violations of the Clean Water Act and to sign a tolling agreement. No
penalty has been assessed by the EPA; however, the DOJ stated in its letter that
the maximum possible penalties were approximately $22 million for the alleged
violations. It is anticipated that by providing additional clarification and
through negotiations with the EPA and DOJ, that any proposed penalty will be
reduced. We have indemnity obligations to the new owner related to this matter.
OTHER
At December 31, 2003, we had accrued environmental liabilities totaling
approximately $17 million related to our:
- Alaska refining, retail and pipeline operations and the
Canadian straddle plants currently classified as held for
sale;
- potential indemnification obligations to purchasers of our
former retail petroleum and refining operations;
- former propane marketing operations, petroleum products and
natural gas pipelines, natural gas liquids fractionation;
- a discontinued petroleum refining facility; and
- exploration and production and mining operations.
99.4-58
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
These costs include (1) certain conditions at specified locations related
primarily to soil and groundwater contamination and (2) any penalty assessed on
Williams Refining & Marketing, LLC (Williams Refining) associated with
noncompliance with EPA's benzene waste "NESHAP" regulations. In 2002, Williams
Refining submitted to the EPA a self-disclosure letter indicating noncompliance
with those regulations. This unintentional noncompliance had occurred due to a
regulatory interpretation that resulted in under-counting the total annual
benzene level at Williams Refinery's Memphis refinery. Also in 2002, the EPA
conducted an all-media audit of the Memphis refinery. The EPA anticipates
releasing a report of its audit findings in 2004. The EPA will likely assess a
penalty on Williams Refining due to the benzene waste NESHAP issue, but the
amount of any such penalty is not known. In connection with the sale of the
Memphis refinery in March 2003, we indemnified the purchaser for any such
penalty.
Certain of our subsidiaries have been identified as potentially
responsible parties (PRP) at various Superfund and state waste disposal sites.
In addition, these subsidiaries have incurred, or are alleged to have incurred,
various other hazardous materials removal or remediation obligations under
environmental laws.
Summary of environmental matters
Actual costs incurred for these matters could be substantially greater
than amounts accrued depending on the actual number of contaminated sites
identified, the actual amount and extent of contamination discovered, the final
cleanup standards mandated by the EPA and other governmental authorities and
other factors.
OTHER LEGAL MATTERS
Royalty indemnifications
In connection with agreements to resolve take-or-pay and other contract
claims and to amend gas purchase contracts, Transco entered into certain
settlements with producers which may require the indemnification of certain
claims for additional royalties which the producers may be required to pay as a
result of such settlements. Transco, through its agent, Power, continues to
purchase gas under contracts which extend, in some cases, through the life of
the associated gas reserves. Certain of these contracts contain royalty
indemnification provisions which have no carrying value. Producers have received
and may receive other demands, which could result in claims pursuant to royalty
indemnification provisions. Indemnification for royalties will depend on, among
other things, the specific lease provisions between the producer and the lessor
and the terms of the agreement between the producer and Transco. Consequently,
the potential maximum future payments under such indemnification provisions
cannot be determined.
As a result of these settlements, Transco has been sued by certain
producers seeking indemnification from Transco. Transco is currently a defendant
in one lawsuit in which a producer has asserted damages, including interest
calculated through December 31, 2003, of approximately $10 million. On July 11,
2003, at the conclusion of the trial, the judge ruled in Transco's favor and
subsequently entered a formal judgment. The plaintiff is seeking an appeal. On
November 25, 2003, Transco and another producer settled a separate lawsuit in
which the producer had asserted damages, including interest, of approximately $8
million.
Western gas resources
On October 24, 2003, we settled the claims by Western Gas Resources, Inc.
and its subsidiary that our merger with Barrett Resources Corporation triggered
a preferential right to purchase and a right to operate certain Barrett coal bed
methane development properties in the Powder River Basin in Wyoming. As a
result, terms in a long-term gathering agreement with Western were amended and a
subsidiary of Western received operating rights to approximately one-half of the
properties jointly owned with us.
Will Price (formerly Quinque)
On June 8, 2001, fourteen of our entities were named as defendants in a
nationwide class action lawsuit which had been pending against other defendants,
generally pipeline and gathering companies, for more than one year. The
plaintiffs allege that the defendants, including us, have engaged in
mismeasurement techniques that distort the heating content of natural gas,
resulting in an alleged underpayment of royalties to the class of producer
plaintiffs. After the court denied class action certification and while motions
to dismiss for lack of personal jurisdiction were pending, the court granted the
plaintiffs' motion to amend their petition on July 29, 2003. The fourth amended
petition, which was filed on July 29, 2003, deletes all of our defendants except
two Midstream subsidiaries. All defendants intend to continue their opposition
to class certification.
99.4-59
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Grynberg
In 1998, the DOJ informed us that Jack Grynberg, an individual, had filed
claims on behalf of himself and the federal government, in the United States
District Court for the District of Colorado under the False Claims Act against
us and certain of our wholly owned subsidiaries. The claims sought an
unspecified amount of royalties allegedly not paid to the federal government,
treble damages, a civil penalty, attorneys' fees, and costs. In connection with
our sale of Kern River and Texas Gas, we agreed to indemnify the purchasers for
any liability relating to this claim, including legal fees. The maximum amount
of future payments that we could potentially be required to pay under these
indemnifications depends upon the ultimate resolution of the claim and cannot
currently be determined. The amounts accrued for these indemnifications are
insignificant. Grynberg has also filed claims against approximately 300 other
energy companies alleging that the defendants violated the False Claims Act in
connection with the measurement, royalty valuation and purchase of hydrocarbons.
On April 9, 1999, the DOJ announced that it was declining to intervene in any of
the Grynberg qui tam cases, including the action filed in federal court in
Colorado against us. On October 21, 1999, the Panel on Multi-District Litigation
transferred all of the Grynberg qui tam cases, including those filed against us,
to the federal court in Wyoming forpre-trial purposes. Grynberg's measurement
claims remain pending against us and the other defendants; the court previously
dismissed Grynberg's royalty valuation claims.
On August 6, 2002, Jack J. Grynberg, and Celeste C. Grynberg, Trustee on
Behalf of the Rachel Susan Grynberg Trust, and the Stephen Mark Grynberg Trust,
served us and Williams Production RMT Company with a complaint in the state
court in Denver, Colorado. The complaint alleges that the defendants have used
mismeasurement techniques that distort the BTU heating content of natural gas,
resulting in the alleged underpayment of royalties to Grynberg and other
independent natural gas producers. The complaint also alleges that defendants
inappropriately took deductions from the gross value of their natural gas and
made other royalty valuation errors. Theories for relief include breach of
contract, breach of implied covenant of good faith and fair dealing,
anticipatory repudiation, declaratory relief, equitable accounting, civil theft,
deceptive trade practices, negligent misrepresentation, deceit based on fraud,
conversion, breach of fiduciary duty, and violations of the state racketeering
statute. Plaintiff is seeking actual damages of between $2 million and $20
million based on interest rate variations, and punitive damages in the amount of
approximately $1.4 million dollars. Our motion to stay the proceedings in this
case based on the pendency of the False Claims Act litigation discussed in the
preceding paragraph was granted on January 15, 2003.
Securities class actions
Numerous shareholder class action suits have been filed against us in the
United States District Court for the Northern District of Oklahoma. The majority
of the suits allege that we and co-defendants, WilTel and certain corporate
officers, have acted jointly and separately to inflate the stock price of both
companies. Other suits allege similar causes of action related to a public
offering in early January 2002, known as the FELINE PACS offering. These cases
were filed against us, certain corporate officers, all members of our Board of
Directors and all of the offerings' underwriters. These cases have all been
consolidated and an order has been issued requiring separate amended
consolidated complaints by our equity holders and WilTel equity holders. The
amended complaint of the WilTel securities holders was filed on September 27,
2002, and the amended complaint of our securities holders was filed on October
7, 2002. This amendment added numerous claims related to Power. In addition,
four class action complaints have been filed against us, the members of our
Board of Directors and members of our Benefits and Investment Committees under
the Employee Retirement Income Security Act (ERISA) by participants in our
401(k) plan. A motion to consolidate these suits has been approved. On July 14,
2003, the Court dismissed us and our Board from the ERISA suits, but not the
members of the Benefits and Investment Committees to whom we might have an
indemnity obligation. The Department of Labor is also independently
investigating our employee benefit plans. On December 15, 2003, the court
substantially denied the defendants' motion to dismiss in the shareholder suits.
Derivative shareholder suits have been filed in state court in Oklahoma, all
based on similar allegations. On August 1, 2002, a motion to consolidate and a
motion to stay these Oklahoma suits pending action by the federal court in the
shareholder suits was approved.
Oklahoma securities investigation
On April 26, 2002, the Oklahoma Department of Securities issued an order
initiating an investigation of us and WilTel regarding issues associated with
the spin-off of WilTel and regarding the WilTel bankruptcy. We have no pending
inquiries in this investigation, but are committed to cooperate fully in the
investigation. Shell offshore litigation
99.4-60
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
On November 30, 2001, Shell Offshore, Inc. filed a complaint at the FERC
against Williams Gas Processing -- Gulf Coast Company, L.P. (WGP), Williams Gulf
Coast Gathering Company (WGCGC), Williams Field Services Company (WFS) and
Transco, alleging concerted actions by the affiliates frustrating the FERC's
regulation of Transco. The alleged actions are related to offers of gathering
service by WFS and its subsidiaries on the deregulated North Padre Island
offshore gathering system. On September 5, 2002, the FERC issued an order
reasserting jurisdiction over that portion of the North Padre Island facilities
previously transferred to WFS. The FERC also determined an unbundled gathering
rate for service on these facilities which is to be collected by Transco.
Transco, WGP, WGCGC and WFS believe their actions were reasonable and lawful and
each have filed petitions for review of the FERC's orders with the U.S. Court of
Appeals for the District of Columbia.
TAPS Quality Bank
Williams Alaska Petroleum, Inc. (WAPI) is actively engaged in
administrative litigation being conducted jointly by the FERC and the Regulatory
Commission of Alaska (RCA) concerning the Trans-Alaska Pipeline System (TAPS)
Quality Bank. Primary issues being litigated include the appropriate valuation
of the naphtha, heavy distillate, vacuum gas oil and residual product cuts
within the TAPS Quality Bank as well as the appropriate retroactive effects of
the determinations. WAPI's interest in these proceedings is material as the
matter involves claims by crude producers and the State of Alaska for
retroactive payments plus interest of up to $180 million. Because of the
complexity of the issues involved, however, the outcome cannot be predicted with
certainty nor can the likely result be quantified. Certain periodic discussions
have been held and continue among some of the litigants. Because of the number
of parties involved and the diversity of positions, no comprehensive terms have
been identified that could be considered probable to achieve final settlement
among all parties. The FERC and RCA presiding administrative law judges are
expected to render their joint and/or individual initial decision(s) sometime
during the second quarter of 2004.
Other divestiture indemnifications
Pursuant to various purchase and sale agreements relating to divested
businesses and assets, we have indemnified certain purchasers against
liabilities that they may incur with respect to the businesses and assets
acquired from us. The indemnities provided to the purchasers are customary in
sale transactions and are contingent upon the purchasers incurring liabilities
that are not otherwise recoverable from third parties. The indemnities generally
relate to breach of warranties, tax, historic litigation, personal injury,
environmental matters, right of way and other representations that we have
provided. At December 31, 2003, we do not expect any of the indemnities provided
pursuant to the sales agreements to have a material impact on our future
financial position. However, if a claim for indemnity is brought against us in
the future, it may have a material adverse effect on results of operations in
the period in which the claim is made.
In addition to the foregoing, various other proceedings are pending
against us which are incidental to our operations.
SUMMARY
Litigation, arbitration, regulatory matters and environmental matters are
subject to inherent uncertainties. Were an unfavorable ruling to occur, there
exists the possibility of a material adverse impact on the results of operations
in the period in which the ruling occurs. Management, including internal
counsel, currently believes that the ultimate resolution of the foregoing
matters, taken as a whole and after consideration of amounts accrued, insurance
coverage, recovery from customers or other indemnification arrangements, will
not have a materially adverse effect upon our future financial position.
COMMITMENTS
Power has entered into certain contracts giving it the right to receive
fuel conversion services as well as certain other services associated with
electric generation facilities that are currently in operation throughout the
continental United States. At December 31, 2003, Power's estimated committed
payments under these contracts range from approximately $391 million to $422
million annually through 2017 and decline over the remaining five years to $57
million in 2022. Total committed payments under these contracts over the next 19
years are approximately $6.7 billion.
99.4-61
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
NOTE 17. RELATED PARTY TRANSACTIONS
LEHMAN BROTHERS HOLDINGS, INC.
Lehman Brothers Inc. is a related party as a result of a director that
serves on our Board of Directors and Lehman Brothers Holdings, Inc.'s Board of
Directors. In third-quarter 2002, RMT, a wholly owned subsidiary, entered into a
$900 million short-term Credit Agreement dated July 31, 2002, with certain
lenders including a subsidiary of Lehman Brothers Inc. This debt obligation was
paid in second-quarter 2003 (see Note 11). Included in interest accrued on the
Consolidated Statement of Operations for 2003 and 2002, are $199.4 million and
$154.1 million, respectively, of interest expense, including amortization of
deferred set up fees related to the RMT note. As of December 31, 2003, the
amount due to Lehman Brothers, Inc., related primarily to advisory fees was $1.8
million. At December 31, 2002, the amount payable related to the RMT note and
related interest was approximately $1 billion. In addition, we paid $37.2
million, $39.6 million and $27 million to Lehman Brothers Inc. in 2003, 2002,
and 2001, respectively, primarily for underwriting fees related to debt and
equity issuances as well as strategic advisory and restructuring success fees.
AMERICAN ELECTRIC POWER COMPANY, INC.
American Electric Power Company, Inc. (AEP) is a related party as a result
of a director that serves on both our Board of Directors and AEP's Board of
Directors. Our Power segment engaged in forward and physical power and gas
trading activities with AEP. Net revenues from AEP were $264.6 million in 2002.
There were no trading activities with AEP in 2003. Amounts due to AEP were
$106.4 million as of December 31, 2002. Amounts receivable from AEP were $215.1
million as of December 31, 2002. During 2002, AEP disputed a settlement amount
related to the liquidation of a trading position with Power. Arbitration was
initiated and in 2003 AEP paid Power $90 million to resolve the dispute.
EXXONMOBIL CORPORATION
ExxonMobil Corporation is a related party as a result of a director that
serves on both our Board of Directors and ExxonMobil Corporation's Board of
Directors. Transactions with ExxonMobil Corporation result primarily from the
purchase and sale of crude oil, refined products and natural gas liquids in
support of crude oil, refined products and natural gas liquids trading
activities and strategies as well as revenues generated from gathering and
processing activities. Aggregate revenues from this customer, including those
reported on a net basis in 2002 and 2001, were $121.8 million, $217.6 million
and $38.9 million in 2003, 2002 and 2001, respectively. Aggregate purchases from
this customer were $30.4 million, $15.6 million and $6.4 million in 2003, 2002
and 2001, respectively. Amounts due from ExxonMobil were $40.0 million and $22.1
million as of December 31, 2003 and 2002, respectively. Amounts due to
ExxonMobil were $8.7 million and $66.9 million as of December 31, 2003 and 2002,
respectively.
99.4-62
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
NOTE 18. ACCUMULATED OTHER COMPREHENSIVE INCOME
The table below presents changes in the components of accumulated other
comprehensive income.
INCOME (LOSS)
--------------------------------------------------------------
UNREALIZED
APPRECIATION FOREIGN MINIMUM
CASH FLOW (DEPRECIATION) CURRENCY PENSION
HEDGES ON SECURITIES TRANSLATION LIABILITY TOTAL
--------- -------------- ----------- --------- --------
(MILLIONS)
Balance at December 31, 2000 .................................... $ -- $ 72.7 $ (44.5) $ -- $ 28.2
-------- -------- -------- -------- --------
2001 CHANGE:
Cumulative effect of change in accounting for derivative
instruments (net of $58.9 million income tax) ................. (94.5) -- -- -- (94.5)
Pre-income tax amount ........................................... 896.8 (69.7) (39.9) (3.6) 783.6
Income tax benefit (provision) .................................. (343.3) 27.5 - 1.4 (314.4)
Minority interest in other comprehensive loss ................... -- 5.4 2.8 -- 8.2
Net realized gains in net income (net of $.1 income tax and
$1.8 minority interest) ....................................... -- 1.5 - -- 1.5
Net reclassification into earnings of derivative instrument-
gains (net of a $55.7 million income tax) ..................... (88.8) -- - -- (88.8)
-------- -------- -------- -------- --------
370.2 (35.3) (37.1) (2.2) 295.6
Adjustment due to spinoff of WilTel ............................. -- (36.5) 57.8 -- 21.3
-------- -------- -------- -------- --------
Balance at December 31, 2001 .................................... 370.2 .9 (23.8) (2.2) 345.1
-------- -------- -------- -------- --------
2002 CHANGE:
Pre-income tax amount ........................................... (170.7) 5.3 (.1) (27.3) (192.8)
Income tax benefit (provision) .................................. 65.0 (1.9) -- 10.4 73.5
Minority interest in other comprehensive loss ................... .4 -- -- -- .4
Net realized loss in net loss (net of $.7 income tax) ........... -- 1.2 -- -- 1.2
Net reclassification into earnings of derivative instrument
gains (net of a $119.2 million income tax) .................... (193.6) -- -- -- (193.6)
-------- -------- -------- -------- --------
(298.9) 4.6 (.1) (16.9) (311.3)
-------- -------- -------- -------- --------
Balance at December 31, 2002 .................................... 71.3 5.5 (23.9) (19.1) 33.8
-------- -------- -------- -------- --------
2003 CHANGE:
Pre-income tax amount ........................................... (408.8) 2.6 77.0 18.2 (311.0)
Income tax benefit (provision) .................................. 156.3 (1.0) (6.9) 148.4
Net reclassification into earnings of derivative instrument
losses (net of a $9.7 million income tax benefit) ............. 15.6 -- -- -- 15.6
Realized gains on securities reclassified into earnings (net
of $5.3 income tax) ........................................... -- (9.0) -- -- (9.0)
Reclassification into earnings due to sale of Bio-energy
facilities .................................................... -- -- -- 1.2 1.2
-------- -------- -------- -------- --------
(236.9) (7.4) 77.0 12.5 (154.8)
-------- -------- -------- -------- --------
Balance at December 31, 2003 .................................... $ (165.6) $ (1.9) $ 53.1 $ (6.6) $ (121.0)
======== ======== ======== ======== ========
The 2001 adjustment due to the spin-off of WilTel includes unrealized
appreciation (depreciation) on securities and foreign currency translation
balances that relate to WilTel (see Note 2).
AVAILABLE FOR SALE SECURITIES
At December 31, 2003, we held U.S. Treasury securities with a fair value
of $381.3 million. These securities mature within three to six months. Gross
unrealized losses of $3 million on these securities are included in Accumulated
Other Comprehensive Income at December 31, 2003.
During 2003 we received proceeds totaling $370.5 million from the sale and
maturity of available for sale securities. We realized gross gains and losses of
$14.4 million and $0.1 million, respectively, from these transactions.
At December 31, 2002, we held marketable equity securities for which gross
unrealized gains of $8.7 million were included in Accumulated Other
Comprehensive Income.
99.4-63
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
NOTE 19. SEGMENT DISCLOSURES
SEGMENTS AND RECLASSIFICATION OF OPERATIONS
Our reportable segments are strategic business units that offer different
products and services. The segments are managed separately because each segment
requires different technology, marketing strategies and industry knowledge. The
segment formerly named Energy Marketing & Trading is now named Power. The
Petroleum Services segment is now reported within Other as the result of a
significant portion of its assets being reflected as discontinued operations.
Segment amounts have been restated to reflect this change. Other primarily
consists of corporate operations and certain continuing operations previously
reported within the International and Petroleum Services segments.
Segment amounts for 2002 and 2001 reflect the reclassification of the
Petroleum Services segment to Other.
SEGMENTS -- PERFORMANCE MEASUREMENT
We currently evaluate performance based on segment profit (loss) from
operations, which includes revenues from external and internal customers,
operating costs and expenses, depreciation, depletion and amortization, equity
earnings (losses) and income (loss) from investments including gains/losses on
impairments related to investments accounted for under the equity method. The
accounting policies of the segments are the same as those described in Note 1,
Summary of significant accounting policies. Intersegment sales are generally
accounted for at current market prices as if the sales were to unaffiliated
third parties.
Power has entered into intercompany interest rate swaps with the corporate
parent, the effect of which is included in Power's segment revenues and segment
profit (loss) as shown in the reconciliation within the following tables. The
results of interest rate swaps with external counterparties are shown as
interest rate swap income (loss) in the Consolidated Statement of Operations
below operating income.
The majority of energy commodity hedging by certain of our business units
is done through intercompany derivatives with Power which, in turn, enters into
offsetting derivative contracts with unrelated third parties. Power bears the
counterparty performance risks associated with unrelated third parties.
The following geographic area data includes revenues from external
customers based on product shipment origin and long-lived assets based upon
physical location.
UNITED STATES OTHER TOTAL
------------- --------- ---------
(MILLIONS)
Revenues from external customers:
2003 .......................... $15,749.5 $ 895.2 $16,644.7
2002 .......................... 3,167.3 226.6 3,393.9
2001 .......................... 4,738.4 161.1 4,899.5
Long-lived assets:
2003 .......................... $11,982.0 $ 776.9 $12,758.9
2002 .......................... 11,996.7 772.2 12,768.9
99.4-64
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The increase in revenues in 2003 is due primarily to the adoption of EITF
02-3 in 2003, which requires that revenues and costs of sale from non-derivative
contracts and certain physically settled derivative contracts be reported on a
gross basis. Prior to the adoption, these revenues were presented net of costs.
As permitted by EITF 02-3, prior year amounts have not been restated. Results
for 2003 include approximately $117 million of revenue related to the correction
of the accounting treatment previously applied to certain third party derivative
contracts during 2002 and 2001.
Long-lived assets are comprised of property, plant and equipment, goodwill
and other intangible assets.
MIDSTREAM
GAS EXPLORATION & GAS &
POWER PIPELINE PRODUCTION LIQUIDS OTHER ELIMINATIONS TOTAL
--------- -------- ------------- --------- ------- ------------ ---------
(MILLIONS)
2003
Segment revenues:
External .................................. $12,570.5 $1,344.3 $ (36.3) $2,733.9 $ 32.3 $ -- $16,644.7
Internal .................................. 622.1 24.0 816.0 44.6 39.7 (1,546.4) --
--------- -------- -------- -------- ------- ----------- ---------
Total segment revenues ...................... 13,192.6 1,368.3 779.7 2,778.5 72.0 (1,546.4) 16,644.7
Less intercompany interest rate swap loss ... (2.9) -- -- -- -- 2.9 --
--------- -------- -------- -------- ------- ----------- ---------
Total revenues .............................. $13,195.5 $1,368.3 $ 779.7 $2,778.5 $ 72.0 $ (1,549.3) $16,644.7
========= ======== ======== ======== ======= =========== =========
Segment profit (loss) ....................... $ 154.1 $ 555.5 $ 401.4 $ 309.7 $ (50.5) $ -- $ 1,370.2
Less:
Equity earnings (losses) .................. - 15.8 8.9 (5.7) 1.3 -- 20.3
Income (loss) from investments ............ 11.7 0.1 -- 6.0 (43.1) -- (25.3)
Intercompany interest rate swap loss ...... (2.9) -- -- -- -- -- (2.9)
--------- -------- -------- -------- ------- ----------- ---------
Segment operating income (loss) ............. $ 145.3 $ 539.6 $ 392.5 $ 309.4 $ (8.7) $ -- 1,378.1
========= ======== ======== ======== ======= ===========
General corporate expenses .................. (87.0)
---------
Consolidated operating income ............... $ 1,291.1
=========
Other financial information:
Additions to long-lived assets .............. $ 1.0 $ 517.4 $ 241.5 $ 255.0 $ 2.5 $ -- $ 1,017.4
Depreciation, depletion & amortization ...... $ 31.5 $ 274.6 $ 173.9 $ 157.7 $ 19.7 $ -- $ 657.4
2002
Segment revenues:
External .................................. $ 909.6 $1,244.1 $ 62.6 $1,110.7 $ 66.9 $ -- $ 3,393.9
Internal .................................. (994.8)* 57.1 797.8 32.4 57.2 50.3 --
--------- -------- -------- -------- ------- ----------- ---------
Total segment revenues ...................... (85.2) 1,301.2 860.4 1,143.1 124.1 50.3 3,393.9
Less intercompany interest rate swap loss ... (141.4) -- -- -- -- 141.4 --
--------- -------- -------- -------- ------- ----------- ---------
Total revenues .............................. $ 56.2 $1,301.2 $ 860.4 $1,143.1 $ 124.1 $ (91.1) $ 3,393.9
========= ======== ======== ======== ======= =========== =========
Segment profit (loss) ....................... $ (624.8) $ 535.8 $ 508.6 $ 195.5 $ 14.1 $ -- $ 629.2
Less:
Equity earnings (losses) .................. (9.7) 88.4 3.7 17.6 (27.0) -- 73.0
Income (loss) from investments ............ (2.0) (13.9) -- -- 58.0 -- 42.1
Intercompany interest rate swap loss ...... (141.4) -- -- -- -- -- (141.4)
--------- -------- -------- -------- ------- ----------- ---------
Segment operating income (loss) ............. $ (471.7) $ 461.3 $ 504.9 $ 177.9 $ (16.9) $ -- 655.5
========= ======== ======== ======== ======= ===========
General corporate expenses .................. (142.8)
---------
Consolidated operating income ............... $ 512.7
=========
Other financial information:
Additions to long-lived assets .............. $ 135.8 $ 705.0 $ 382.8 $ 616.4 $ 51.7 $ -- $ 1,891.7
Depreciation, depletion & amortization ...... $ 33.1 $ 253.0 $ 184.6 $ 149.9 $ 28.2 $ -- $ 648.8
2001
Segment revenues:
External .................................. $ 2,249.6 $1,204.5 $ 121.6 $1,075.5 $ 248.3 $ -- $ 4,899.5
Internal .................................. (544.0)* 38.6 482.3 79.7 71.0 (127.6) --
--------- -------- -------- -------- ------- ----------- ---------
Total revenues and segment revenues ......... $ 1,705.6 $1,243.1 $ 603.9 $1,155.2 $ 319.3 $ (127.6) $ 4,899.5
========= ======== ======== ======== ======= =========== =========
Segment profit .............................. $ 1,270.0 $ 463.8 $ 231.8 $ 169.0 $ 37.5 $ -- $ 2,172.1
Less:
Equity earnings (losses) .................. (1.3) 46.3 14.6 (14.0) (22.9) -- 22.7
Income (loss) from investments ............ (23.3) 27.5 -- -- -- -- 4.2
--------- -------- -------- -------- ------- ----------- ---------
Segment operating income .................... $ 1,294.6 $ 390.0 $ 217.2 $ 183.0 $ 60.4 $ -- 2,145.2
========= ======== ======== ======== ======= ===========
General corporate expenses .................. (124.3)
---------
Consolidated operating income ............... $ 2,020.9
=========
Other financial information:
Additions to long-lived assets .............. $ 209.2 $ 559.2 $3,561.1 $ 560.7 $ 53.5 $ -- $ 4,943.7
Depreciation, depletion & amortization ...... $ 20.0 $ 247.8 $ 97.1 $ 123.9 $ 26.6 $ -- $ 515.4
- --------------
* Prior to January 1, 2003, Power intercompany cost of sales, which
are netted in revenues consistent with fair-value accounting, exceed
intercompany revenues. Beginning January 1, 2003, Power intercompany
cost of sales are no longer netted in revenues due to the adoption
of EITF Issue No. 02-3 (see Note 1). Segment revenues and profit for
Power include net realized and unrealized mark-to market gains of
$401 million from derivative contracts accounted for on a fair value
basis for the year ended December 31, 2003.
99.4-65
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
TOTAL ASSETS EQUITY METHOD INVESTMENTS
------------------------------- ------------------------------
DECEMBER 31, DECEMBER 31, DECEMBER 31, DECEMBER 31,
2003 2002 2003 2002
-------------- -------------- -------------- --------------
(MILLIONS)
Power(1) .................................... $ 8,690.1 $ 12,532.9 $ -- $ --
Gas Pipeline ................................ 7,314.3 7,290.2 774.4 778.4
Exploration & Production .................... 5,347.4 5,595.1 41.5 35.8
Midstream Gas & Liquids ..................... 4,033.1 3,976.8 332.7 282.0
Other ....................................... 6,928.7 7,664.3 85.1 93.9
Eliminations ................................ (6,078.2) (6,636.9) -- --
-------------- -------------- -------------- --------------
26,235.4 30,422.4 1,233.7 1,190.1
-------------- -------------- -------------- --------------
Net assets of discontinued operations ....... 786.4 4,566.1 -- --
-------------- -------------- -------------- --------------
Total assets ................................ $ 27,021.8 $ 34,988.5 $ 1,233.7 $ 1,190.1
============== ============== ============== ==============
- ----------
(1) The decrease in Power's total assets is largely due to the decrease in
energy risk management and trading assets as a result of the adoption of
EITF 02-3 (see Note 1).
20. EVENTS (UNAUDITED) SUBSEQUENT TO THE DATE OF INDEPENDENT REGISTERED PUBLIC
ACCOUNTING FIRM'S REPORT
NOTES PAYABLE AND LONG-TERM DEBT
In May 2004, we made cash tender offers for approximately $1.34 billion
aggregate principal amount of a specified series of our outstanding notes and
debentures. As of the June 8, 2004, tender offer expiration date, we had
accepted for purchase tenders of notes and debentures with an aggregate
principal amount of approximately $1.17 billion. In May 2004, we also
repurchased approximately $255 million of various notes with maturity dates
ranging from 2006 to 2011. In conjunction with these tendered notes and
debentures and related consents, and early retirements, we paid premiums of
approximately $79 million.
Revolving credit and letter of credit facilities
In April 2004, we entered into two unsecured bank revolving credit
facilities totaling $500 million. These facilities provide for both borrowings
and issuing letters of credit, but are used primarily for issuing letters of
credit. We are required to pay to the bank fixed fees at a weighted-average rate
of 3.64 percent on the total committed amount of the facilities. In addition, we
pay interest on any borrowings at a fluctuating rate comprised of either a base
rate or LIBOR. We were able to obtain the unsecured credit facilities because
the funding bank syndicated its associated credit risk into the institutional
investor market via a 144A offering, which allows for the resale of certain
restricted securities to qualified institutional buyers. Upon the occurrence of
certain credit events, letters of credit outstanding under the agreement become
cash collateralized creating a borrowing under the facilities. Concurrently the
bank can deliver the facilities to the institutional investors, whereby the
investors replace the bank as lender under the facilities. Upon such occurrence,
we will pay:
- a fixed facility fee at a weighted average rate of 3.19 percent to
the investors,
- interest on borrowings under the $400 million facility equal to a
fixed rate of 3.57 percent, and
- interest on borrowings under the $100 million facility at a
fluctuating LIBOR interest rate.
99.4-66
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
To facilitate the syndication of these facilities, the bank established
trusts funded by the institutional investors. The assets of the trusts serve as
collateral to reimburse the bank for our borrowings in the event the facilities
are delivered to the investors. Thus, we have no asset securitization or
collateral requirements under the new facilities. During second-quarter 2004,
use of these new facilities replaced existing facilities and released
approximately $500 million of restricted cash, restricted investments and margin
deposits which secured our previous $800 million revolving and letter of credit
facility. Significant covenants under these new facilities include the
following:
- limitations on certain payments, including a limitation on the
payment of quarterly dividends to no greater than $.05 per
common share;
- limitations on asset sales;
- limitations on the use of proceeds from permitted asset sales;
- limitations on transactions with affiliates; and
- limitations on the incurrence of additional indebtedness and
issuance of disqualified stock, unless the fixed charge
coverage ratio for our most recently ended four full fiscal
quarters is at least 2 to 1, determined on a proforma basis.
On May 3, 2004, we entered into a new three-year, $1 billion secured
revolving credit facility which is available for borrowings and letters of
credit. In August, 2004, we expanded the credit facility by an additional $275
million. Northwest Pipeline Corporation (Northwest) and Transcontinental Gas
Pipeline Corporation (Transco) have access to $400 million each under the
facility. The new facility is secured by certain Midstream assets, including
substantially all of our southwest Wyoming, Wamsutter, San Juan Conventional,
Manzanares and Torre Alta systems. Additionally, the facility is guaranteed by
WGP. Interest is calculated based on a choice of two methods: a fluctuating rate
equal to the facilitating bank's base rate plus an applicable margin or a
periodic fixed rate equal to LIBOR plus an applicable margin. We are also
required to pay a commitment fee based on the unused portion of the facility,
currently .375 percent. The applicable margins and commitment fee are based on
the relevant borrower's senior unsecured long-term debt ratings. Significant
financial covenants under the credit agreement include:
- ratio of debt to capitalization no greater than (i) 75 percent
for the period June 30, 2004 through December 31, 2004, (ii)
70 percent for the period after December 31, 2004 through
December 31, 2005, and (iii) 65 percent for the remaining term
of the agreement;
- ratio of debt to capitalization no greater than 55 percent for
Northwest and Transco; and
- ratio of EBITDA to Interest, on a rolling four quarter basis
(or, in the first year, building up to a rolling four quarter
basis), no less than (i) 1.5 for the periods ending September
30, 2004 through March 31, 2005, (ii) 2.0 for any period after
March 31, 2005 through December 31, 2005, and (iii) 2.5 for
the remaining term of the agreement.
Upon entering into the new $1 billion secured revolving credit facility on
May 3, 2004, we terminated the $800 million revolving and letter of credit
facility which we entered into in June 2003.
In August 2004, we made tender offers for all of our 8.625 percent senior
notes due 2010. Approximately $792.8 million, or approximately 99 percent,
aggregate principal amount of notes were accepted for purchase. In conjunction
with this purchase, we paid premiums of approximately $135 million.
ENVIRONMENTAL MATTERS
As part of our June 17, 2003 sale of Williams Energy Partners (see Note
2), we indemnified the purchaser for:
(1) environmental cleanup costs resulting from certain conditions,
primarily soil and groundwater contamination, at specified
locations, to the extent such costs exceed a specified amount
and
(2) currently unidentified environmental contamination relating to
operations prior to April 2002 and identified prior to April
2008.
99.4-67
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
On May 26, 2004, the parties reached an agreement for buyout of certain
indemnities in the form of a structured cash settlement totaling $117.5 million.
Yearly payments will be made through 2007. The agreement releases Williams from
all environmental indemnity obligations under the June 2003 Sale of Williams
Energy Partners and two related agreements. Williams is now indemnified by the
purchaser for third party environmental claims made against Williams for claims
covered under the June 2003 purchase and sale agreement (PSA) and related
agreements as well as all environmental occurrences before the closing date of
the PSA. The agreement also transferred most third party litigation matters
related to Williams Energy Partners' assets to the purchaser.
ASSET SALES
On July 28, 2004, we closed the sale of the Canadian straddle plants for
approximately $536 million in U.S. funds. We expect to recognize a pre-tax gain
of approximately $190 million on the sale in third-quarter 2004.
OTHER LEGAL MATTERS
As discussed in Note 16, Williams Alaska Petroleum, Inc. (WAPI) is actively
engaged in administrative litigation being conducted jointly by the FERC and the
Regulatory Commission of Alaska (RCA) concerning the Trans-Alaska Pipeline
System (TAPS) Quality Bank. Primary issues being litigated include the
appropriate valuation of the naptha, heavy distillate, vacuum gas oil and
residual product cuts within the TAPS Quality Bank as well as the appropriate
retroactive effects of the determinations.
On August 31, 2004, the FERC administrative law judge (ALJ) issued a ruling on
the matter. On September 3, 2004, the RCA administrative law judge adopted the
FERC judge's ruling. The ruling is unfavorable and, if upheld as issued, would
result in additional payments by Williams into the Quality Bank of approximately
$185 million to $235 million and an additional expense accrual of approximately
$150 million to $200 million. We are currently analyzing the impact of the ALJ's
ruling, but due to the length and complexity of the written ruling, including
the number of years potentially retroactively affected, we are unable at this
time to determine the ultimate impact on WAPI if this ruling is upheld as
issued. No immediate or certain cash payments result from the ruling. We believe
any FERC or RCA order resulting in a required cash payment in this proceeding
will likely be issued in the last half of 2005 or later. After we complete a
more thorough review of the ruling and evaluate the merits of our position,
including appeals, we will determine the additional expense accrual that is
necessary in the third quarter. That accrual may be material to our consolidated
statement of operations. However, we do not expect the ultimate payments, if
any, of amounts related to these proceedings to have a material adverse effect
upon our financial position.
99.4-68
THE WILLIAMS COMPANIES, INC
QUARTERLY FINANCIAL DATA
(UNAUDITED)
Summarized quarterly financial data are as follows (millions, except
per-share amounts). Certain amounts have been restated or reclassified as
described in Note 1 of Notes to Consolidated Financial Statements.
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
--------- --------- --------- ---------
2003
Revenues .............................................. $ 4,776.1 $ 3,612.3 $ 4,743.4 $ 3,512.9
Costs and operating expenses .......................... 4,423.6 3,024.8 4,387.6 3,153.7
Income (loss) from continuing operations .............. (43.1) 113.7 20.0 (62.4)
Net income (loss) ..................................... (814.5) 269.7 106.3 (53.7)
Basic earnings (loss) per common share:
Income (loss) from continuing operations ............ (.10) .18 .04 (.12)
Net income (loss) ................................... (1.59) .48 .21 (.10)
Diluted earnings (loss) per common share:
Income (loss) from continuing operations ............ (.10) .17 .04 (.12)
Net income (loss) ................................... (1.59) .46 .20 (.10)
2002
Revenues .............................................. $ 1,140.1 $ 596.1 $ 643.8 $ 1,013.9
Costs and operating expenses .......................... 468.5 473.5 466.3 526.0
Income (loss) from continuing operations .............. 42.4 (338.9) (179.6) (121.0)
Net income (loss) ..................................... 107.7 (349.1) (294.1) (219.2)
Basic and diluted earnings (loss) per common share:
Loss from continuing operations ..................... (.06) (.66) (.36) (.25)
Net income (loss) ................................... .07 (.68) (.58) (.44)
The sum of earnings per share for the four quarters may not equal the
total earnings per share for the year due to changes in the average number of
common shares outstanding and rounding.
Net loss for fourth-quarter 2003 includes the following items which are
pre-tax:
- $45.0 million impairment of goodwill at Power (see Note 4),
- $44.1 million impairment of the Hazelton generation facility
at Power (see Note 4),
- $33.3 million California rate refund and other accrual
adjustments at Power (see Note 4),
- $19.9 million in unrealized gains on certain derivative
contracts that had previously not been recognized in 2003,
including approximately $10 million of revenue related to the
accounting treatment applied to certain derivative contracts
terminated in prior periods at Power (see Note 1),
- $16.2 million gain on sale of the wholesale propane business
at Midstream (see Note 4),
- $66.8 million of costs for the early retirement of debt (see
Note 10),
- $31.5 million income from discontinued operations (see Note
2), and
- $18.9 million loss from discontinued operations for
impairments and net gains on sales (see Note 2).
99.4-69
THE WILLIAMS COMPANIES, INC
QUARTERLY FINANCIAL DATA - (CONTINUED)
(UNAUDITED)
Net income for third-quarter 2003 includes the following items which are
pre-tax:
- $13.0 million gain on sale of a full requirements contract at
Power (see Note 4),
- $126.8 million positive valuation adjustment on a terminated
derivative contract at Power,
- $13.5 million gain on sale of marketable equity securities at
Power (see Note 3),
- $11.0 million gain on sale of equity interest in West Texas
LPG Pipeline, L.P. investment at Midstream (see Note 3),
- $16.7 million income from discontinued operations (see Note
2), and
- $72.3 million gain from discontinued operations for
impairments and net gains on sales (see Note 2).
Net income for second-quarter 2003 includes the following items which are
pre-tax:
- $20 million Commodity Futures Trading Commission settlement at
Power (see Note 4),
- $175 million gain on sale of a full requirements contract at
Power (see Note 4),
- $25.5 million write-off of software development costs at Gas
Pipelines (see Note 4),
- $80.7 million correction, attributable to prior periods
relating to the accounting treatment previously applied to
certain third party derivative contracts during 2002 and 2001
at Power (see Note 1),
- $12.4 million of revenue attributable to prior periods
relating to the accounting treatment previously applied to
certain third party derivative contracts during 2002 and 2001
and recorded prior to the $80.7 million correction in
second-quarter at Power (see Note 1),
- $94.1 million gain on the sale of certain natural gas
properties at Exploration & Production (see Note 4),
- $42.4 million impairment of an investment in equity and debt
securities of Longhorn Partners Pipeline L.P. at Other (see
Note 4),
- $14.5 million in accelerated amortization of costs related to
the termination of the revolving credit agreement,
- $13.5 million impairment of cost based investment in
ReserveCo, a company holding phosphate reserves (see Note 3),
- $22.6 million income from discontinued operations (see Note
2), and
- $232.9 million gain from discontinued operations for
impairments and net gains on sales (see Note 2).
Net loss for first-quarter 2003 includes the following items which are
pre-tax:
- $13.7 million of revenue attributable to prior periods
relating to the accounting treatment previously applied to
certain third party derivative contracts during 2002 and 2001
and recorded prior to the $80.7 million correction in
second-quarter at Power (see Note 1),
- $12.0 million impairment of a cost based investment in Algar
Telecom S.A. at Other (see Note 3),
- $761.3 million cumulative effect of change in accounting
principles related to the adoption of EITF Issue No. 02-3 and
SFAS No. 143 (see Note 1),
- $96.8 million income from discontinued operations (see Note
2), and
- $117.3 million loss from discontinued operations for
impairments and net losses on sales (see Note 2).
99.4-70
THE WILLIAMS COMPANIES, INC
QUARTERLY FINANCIAL DATA - (CONTINUED)
(UNAUDITED)
Net loss for fourth-quarter 2002 includes the following items which are
pre-tax:
- $85.0 million net revenue impact related to the settlement and
valuation of Power contracts with the State of California,
- $44.7 million impairment of the Worthington generation
facility at Power (see Note 4),
- $50.8 million loss accruals and impairments of other power
related assets at Power (see Note 4),
- $17.0 million charge associated with a FERC settlement at Gas
Pipeline (see Note 16),
- $78.2 million impairment of Canadian assets at Midstream (see
Note 4),
- $89.4 million income from discontinued operations (see Note
2), and
- $227.2 million loss from discontinued operations for
impairments and net losses on sales (see Note 2).
Net loss for third-quarter 2002 includes the following items which are
pre-tax:
- $10.5 million loss accruals related to commitments for certain
assets previously planned to be used in power projects at
Power (see Note 4),
- $11.6 million net write-down pursuant to the sale of our
equity interest in a Canadian and U.S. gas pipeline, at Gas
Pipeline (see Note 3),
- $143.9 million gain related to the sale of certain natural gas
production properties at Exploration & Production (see Note
4),
- $58.5 million gain on sale of our investment in a Lithuanian
oil refinery, pipeline and terminal complex, included at Other
(see Note 3),
- $22.9 million charge, included in continuing operations,
related to estimated losses from an assessment of the
recoverability of WilTel related receivables (see Note 2),
- $57.2 million income from discontinued operations (see Note
2), and
- $231.4 million loss from discontinued operations for
impairments and net losses on sales (see Note 2).
99.4-71
THE WILLIAMS COMPANIES, INC
QUARTERLY FINANCIAL DATA - (CONTINUED)
(UNAUDITED)
Net loss for second-quarter 2002 includes the following items which are
pre-tax:
- $57.5 million impairment of goodwill at Power due to
deteriorating market conditions in the merchant energy sector
(see Note 4),
- $58.9 million of loss accruals related to commitments for
certain assets previously planned to be used in power projects
and write-offs associated with a terminated power plant
project at Power (see Note 4),
- $31.8 million impairment of other power related assets at
Power (see Note 4),
- $12.3 million write-down of Gas Pipeline's investment in a
pipeline project which was cancelled in 2002 (see Note 3),
- $27.4 million benefit which reflects a contractual
construction completion fee received by one of our equity
affiliates at Gas Pipeline whose operations are accounted for
under the equity method of accounting (see Note 3),
- $15.0 million charge, included in continuing operations,
related to estimated losses from an assessment of the
recoverability of WilTel related receivables (see Note 2),
- $28.8 million of expense was recorded for our early retirement
option,
- $56.9 million income from discontinued operations (see Note
2), and
- $71.1 million loss from discontinued operations for
impairments and net losses on sales (see Note 2).
Net income for first-quarter 2002 includes the following items which are
pre-tax:
- $232.0 million charge, included in continuing operations,
related to estimated losses from an assessment of the
recoverability of WilTel related receivables (see Note 2),
- $144.5 million income from discontinued operations (see Note
2), and
- $38.1 million loss from discontinued operations for
impairments and net losses on sales (see Note 2).
99.4-72
THE WILLIAMS COMPANIES, INC.
SUPPLEMENTAL OIL AND GAS DISCLOSURES
(UNAUDITED)
The following information pertains to our oil and gas producing
activities and is presented in accordance with SFAS No. 69, "Disclosures About
Oil and Gas Producing Activities." The information is required to be disclosed
by geographic region. We have significant oil and gas producing activities
primarily in the Rocky Mountain and Mid-continent areas of the United States.
Additionally, we have oil and gas producing activities in Argentina and
Venezuela. However, proved reserves and revenues related to these activities are
approximately 7.3 percent and 4.2 percent, respectively, of our total
international and domestic oil and gas producing activities. The following
information relates only to the oil and gas activities in the United States and
includes the activities of those properties that qualified for reporting as
discontinued operations in the Consolidated Statement of Operations.
CAPITALIZED COSTS
AS OF DECEMBER 31,
---------------------------
2003 2002
---------- ----------
(MILLIONS)
Proved properties .......................................... $ 2,464.4 $ 2,544.8
Unproved properties ........................................ 682.5 784.5
---------- ----------
3,146.9 3,329.3
Accumulated depreciation, depletion, and amortization,
and valuation provisions ................................... (511.1) (417.7)
---------- ----------
Net capitalized costs ...................................... $ 2,635.8 $ 2,911.6
========== ==========
- Capitalized costs include the cost of equipment and facilities
for oil and gas producing activities. These amounts for 2003
and 2002 do not include approximately $1 billion of goodwill
related to the purchase of Barrett Resources Corp. (Barrett)
in 2001.
- Proved properties include capitalized costs for oil and gas
leaseholds holding proved reserves; development wells and
related equipment and facilities (including uncompleted
development well costs); successful exploratory wells and
related equipment and facilities (and uncompleted exploratory
well costs) and support equipment.
- Unproved properties consist primarily of acreage related to
probable reserves acquired through the Barrett acquisition in
addition to a small portion of unproved exploratory acreage.
COSTS INCURRED
FOR THE YEAR ENDED DECEMBER 31,
-----------------------------------------
2003 2002 2001
--------- ---------- ----------
(MILLIONS)
Acquisition .................... $ 11.3 $ -- $ 2,557.0
Exploration .................... 7.1 15.5 35.6
Development .................... 186.8 374.3 198.9
--------- ---------- ----------
$ 205.2 $ 389.8 $ 2,791.5
========= ========== ==========
- Costs incurred include capitalized and expensed items.
- Acquisition costs include costs incurred to purchase, lease,
or otherwise acquire a property, the majority of the 2001
costs relates to the Barrett acquisition during 2001.
- Exploration costs include the costs of geological and
geophysical activity, dry holes, drilling and equipping
exploratory wells, and the cost of retaining undeveloped
leaseholds.
- Development costs include costs incurred to gain access to and
prepare development well locations for drilling and to drill
and equip development wells.
99.4-73
THE WILLIAMS COMPANIES, INC.
SUPPLEMENTAL OIL AND GAS DISCLOSURES -- (CONTINUED)
RESULTS OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31,
2003 2002* 2001*
--------- --------- ---------
(MILLIONS)
Revenues:
Oil and gas revenues ......................................... $ 611.9 $ 683.0 $ 408.4
Other revenues ............................................... 168.8 189.0 171.2
--------- --------- ---------
Total revenues ............................................... 780.7 872.0 579.6
--------- --------- ---------
Costs:
Production costs ............................................. 138.3 119.5 79.3
General & administrative ..................................... 54.4 62.9 40.1
Exploration expenses ......................................... 7.1 13.9 10.1
Depreciation, depletion & amortization ....................... 170.2 191.0 94.0
Property impairments ......................................... -- 8.4 7.2
Gains on sales of interests in oil and gas properties ........ (134.8) (141.7) --
Other expenses ............................................... 102.1 109.2 138.7
--------- --------- ---------
Total costs ................................................ 337.3 363.2 369.4
--------- --------- ---------
Results of operations ........................................ 443.4 508.8 210.2
Equity earnings .............................................. -- -- 8.5
Provision for income taxes ................................... (169.6) (186.9) (80.4)
--------- --------- ---------
Exploration and production net income ........................ $ 273.8 $ 321.9 $ 138.3
========= ========= =========
- ----------
* Certain amounts have been reclassified to conform to current presentation.
- Results of operations for producing activities consist of all
related domestic activities within the Exploration &
Production reporting unit, including those operations that
qualified for presentation as discontinued operations within
our Consolidated Statement of Operations. Included above are
the pretax results of operations and gains on sales of assets,
reported as discontinued operations, of $60.2 million in 2003,
$11.9 million in 2002 and $2.3 million in 2001.
- Oil and gas revenues consist primarily of natural gas
production sold to the Power subsidiary and includes the
impact of intercompany hedges.
- Other revenues and other expenses consist of activities within
the Exploration & Production segment that are not a direct
part of the producing activities. These non-producing
activities include acquisition and disposition of other
working interest and royalty interest gas and the movement of
gas from the wellhead to the tailgate of the respective plants
for sale to the Power subsidiary or third party purchasers. In
addition, other revenues include recognition of income from
transactions which transferred certain non-operating benefits
to a third party.
- Production costs consist of costs incurred to operate and
maintain wells and related equipment and facilities used in
the production of petroleum liquids and natural gas. These
costs also include production related taxes other than income
taxes, and administrative expenses related to the production
activity. Excluded are depreciation, depletion and
amortization of capitalized acquisition, exploration and
development costs.
- Exploration expenses include unsuccessful exploratory dry hole
costs, leasehold impairment, geological and geophysical
expenses and the cost of retaining undeveloped leaseholds.
- Depreciation, depletion and amortization includes depreciation
of support equipment.
99.4-74
THE WILLIAMS COMPANIES, INC.
SUPPLEMENTAL OIL AND GAS DISCLOSURES - (Continued)
PROVED RESERVES
2003 2002 2001
------ ------ ------
(BCFE)
Proved reserves at beginning of period ........... 2,834 3,178 1,202
Revisions ........................................ (5) (87) (69)
Purchases ........................................ 38 -- 1,949
Extensions and discoveries ....................... 412 385 239
Production ....................................... (186) (211) (131)
Sale of minerals in place ........................ (390) (431) (12)
------ ------ ------
Proved reserves at end of period ................. 2,703 2,834 3,178
====== ====== ======
Proved developed reserves at end of period ....... 1,165 1,368 1,599
====== ====== ======
- The SEC defines proved oil and gas reserves (Rule 4-10(a) of
Regulation S-X) as the estimated quantities of crude oil,
natural gas, and natural gas liquids which geological and
engineering data demonstrate with reasonable certainty are
recoverable in future years from known reservoirs under
existing economic and operating conditions. Our proved
reserves consist of two categories, proved developed reserves
and proved undeveloped reserves. Proved developed reserves are
currently producing wells and wells awaiting minor sales
connection expenditure, recompletion, additional perforations
or borehole stimulation treatments. Proved undeveloped
reserves are those reserves which are expected to be recovered
from new wells on undrilled acreage or from existing wells
where a relatively major expenditure is required for
recompletion. Proved reserves on undrilled acreage are limited
to those drilling units offsetting productive units that are
reasonably certain of production when drilled or where it can
be demonstrated with certainty that there is continuity of
production from the existing productive formation.
- Natural gas reserves are computed at 14.73 pounds per square
inch absolute and 60 degrees Fahrenheit. Crude oil reserves
are insignificant and have been included in the proved
reserves on a basis of billion cubic feet equivalents (Bcfe).
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL
AND GAS RESERVES
The following is based on the estimated quantities of proved reserves
and the year-end prices and costs. The average year end natural gas prices used
in the following estimates were $5.28, $3.85, and $2.31 per mmcfe at December
31, 2003, 2002 and 2001, respectively. Future income tax expenses have been
computed considering available carryforwards and credits and the appropriate
statutory tax rates. The discount rate of 10 percent is as prescribed by SFAS
No. 69. Continuation of year-end economic conditions also is assumed. The
calculation is based on estimates of proved reserves, which are revised over
time as new data becomes available. Probable or possible reserves, which may
become proved in the future, are not considered. The calculation also requires
assumptions as to the timing of future production of proved reserves, and the
timing and amount of future development and production costs. Of the $1,303
million of future development costs, $192 million, $277 million and $186 million
are estimated to be spent in 2004, 2005 and 2006, respectively.
Numerous uncertainties are inherent in estimating volumes and the value
of proved reserves and in projecting future production rates and timing of
development expenditures. Such reserve estimates are subject to change as
additional information becomes available. The reserves actually recovered and
the timing of production may be substantially different from the reserve
estimates.
99.4-75
THE WILLIAMS COMPANIES, INC.
SUPPLEMENTAL OIL AND GAS DISCLOSURES -- (CONTINUED)
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
AT DECEMBER 31,
----------------------
2003 2002
------- -------
(MILLIONS)
Future cash inflows ............................................................ $14,268 $10,904
Less:
Future production costs ....................................................... 2,434 2,828
Future development costs ...................................................... 1,303 1,215
Future income tax provisions .................................................. 3,858 2,346
------- -------
Future net cash flows .......................................................... 6,673 4,515
Less 10 percent annual discount for estimated timing of cash flows ............. 3,324 2,243
------- -------
Standardized measure of discounted future net cash flows ...................... $ 3,349 $ 2,272
======= =======
SOURCES OF CHANGE IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
2003 2002 2001
------- ------- -------
(MILLIONS)
Standardized measure of discounted future net cash flows beginning of period ... $ 2,272 $ 1,432 $ 2,720
Changes during the year:
Sales of oil and gas produced, net of operating costs ........................ (567) (322) (270)
Net change in prices and production costs .................................... 2,001 1,602 (3,945)
Extensions, discoveries and improved recovery, less estimated future costs ... 901 546 153
Development costs incurred during year ....................................... 187 374 199
Changes in estimated future development costs ................................ (159) (326) (41)
Purchase of reserves in place, less estimated future costs ................... 78 -- 1,069
Sales of reserves in place, less estimated future costs ...................... (855) (611) (8)
Revisions of previous quantity estimates ..................................... (11) (123) (43)
Accretion of discount ........................................................ 341 203 426
Net change in income taxes ................................................... (773) (537) 1,077
Other ........................................................................ (66) 34 95
------- ------- -------
Net changes .................................................................. 1,077 840 (1,288)
------- ------- -------
Standardized measure of discounted future net cash flows end of period ......... $ 3,349 $ 2,272 $ 1,432
======= ======= =======
99.4-76
THE WILLIAMS COMPANIES, INC.
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
ADDITIONS
-------------------------
CHARGED TO
BEGINNING COSTS AND ENDING
BALANCE EXPENSES OTHER DEDUCTIONS BALANCE
--------- ---------- --------- ---------- ---------
(MILLIONS)
Year ended December 31, 2003:
Allowance for doubtful accounts -- Accounts and notes
receivables(a) .............................................. $ 111.8 $ 7.3 $ 7.9(j) $ 14.8(c) $ 112.2
Price-risk management credit reserves(a) ..................... 250.4 2.6(f) -- 213.2(i) 39.8
Refining and processing plant major maintenance accrual(b) ... 2.7 1.4 -- -- 4.1
Year ended December 31, 2002:
Allowance for doubtful accounts -- Accounts and notes
receivables(a) .............................................. 251.8 22.4 -- 162.4(c) 111.8
Other noncurrent assets(a) .................................. 103.2 256.0 1,720.0(e) 2,079.2(c) --
Price-risk management credit reserves(a) ..................... 648.2 (397.8)(f) -- -- 250.4
Refining and processing plant major maintenance accrual(b) ... 1.2 1.5 -- -- 2.7
Year ended December 31, 2001:
Allowance for doubtful accounts -- Accounts and notes
receivables(a) .............................................. 6.9 98.4 145.6(g) (.9)(c) 251.8
Other noncurrent assets(a) ................................... -- 103.2 -- -- 103.2
Price-risk management credit reserves(a) ..................... 60.9 728.5(f) (141.2)(h) -- 648.2
Refining and processing plant major maintenance accrual(b) ... 6.0 1.2 -- 6.0(d) 1.2
- ----------
(a) Deducted from related assets.
(b) Included in liabilities.
(c) Represents balances written off, net of recoveries and
reclassifications.
(d) Represents payments made.
(e) Reflects a reclassification of amounts included in the liability for
Guarantees and payment obligations related to WilTel at December 31,
2002 (see Note 2 of Notes to Consolidated Financial Statements).
(f) Included in revenue.
(g) Reflects a reclassification of the reserve related to Enron from
Price-risk management credit reserves to Allowance for doubtful
accounts -- Accounts and notes receivable and amounts related to
acquisitions of businesses.
(h) Reflects a reclassification of the reserve related to Enron from
Price-risk management credit reserves to Allowance for doubtful
accounts -- Accounts and notes receivable.
(i) Reflects cumulative effect of change in accounting principle related to
EITF 02-3 (see Note 1 of Notes to Consolidated Financial Statements).
(j) Reflects allowances for accounts receivable charged to costs and
expenses for a discontinued operation whose receivables were not held
for sale.
99.4-77