<PAGE> 1
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 1999
------------------------------------------------
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
-------------------- -------------------------
Commission file number 1-4174
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THE WILLIAMS COMPANIES, INC.
- --------------------------------------------------------------------------------
(Exact name of registrant as specified in its charter)
DELAWARE 73-0569878
- -------------------------------- -------------------------------------------
(State of Incorporation) (IRS Employer Identification Number)
ONE WILLIAMS CENTER
TULSA, OKLAHOMA 74172
- ----------------------------------------- -----------------------------------
(Address of principal executive office) (Zip Code)
Registrant's telephone number: (918) 573-2000
-----------------------------------
NO CHANGE
- --------------------------------------------------------------------------------
Former name, former address and former fiscal year,
if changed since last report.
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes X No
----- -----
Indicate the number of shares outstanding of each of the issuer's classes of
common stock as of the latest practicable date.
<TABLE>
<CAPTION>
Class Outstanding at October 29, 1999
- -------------------------------- -------------------------------------------
<S> <C>
Common Stock, $1 par value 434,733,977 Shares
</TABLE>
<PAGE> 2
The Williams Companies, Inc.
Index
<TABLE>
<CAPTION>
Part I. Financial Information Page
----
<S> <C>
Item 1. Financial Statements
Consolidated Statement of Income--Three and Nine Months
Ended September 30, 1999 and 1998 2
Consolidated Balance Sheet--September 30, 1999 and December 31, 1998 3
Consolidated Statement of Cash Flows--Nine Months
Ended September 30, 1999 and 1998 4
Notes to Consolidated Financial Statements 5
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 17
Item 3. Quantitative and Qualitative Disclosures about
Market Risk 31
Part II. Other Information 32
Item 6. Exhibits and Reports on Form 8-K
Exhibit 12--Computation of Ratio of Earnings to Combined
Fixed Charges and Preferred Stock Dividend
Requirements
Exhibit 27--Financial Data Schedule
</TABLE>
Certain matters discussed in this report, excluding historical information,
include forward-looking statements. Although The Williams Companies, Inc.
believes such forward-looking statements are based on reasonable assumptions, no
assurance can be given that every objective will be achieved. Such statements
are made in reliance on the safe harbor protections provided under the Private
Securities Litigation Reform Act of 1995. Additional information about issues
that could lead to material changes in performance is contained in The Williams
Companies, Inc.'s 1998 Form 10-K.
1
<PAGE> 3
The Williams Companies, Inc.
Consolidated Statement of Income
(Unaudited)
<TABLE>
<CAPTION>
Three months Nine months
(Dollars in millions, except per-share amounts) ended September 30, ended September 30,
--------------------------- ----------------------
1999 1998* 1999 1998*
---------- ---------- --------- ---------
<S> <C> <C> <C> <C>
Revenues (Note 15):
Gas Pipeline (Note 3) $ 409.5 $ 399.5 $ 1,300.9 $ 1,240.9
Energy Services (Note 2) 1,788.7 1,326.4 4,511.5 4,060.3
Communications 504.4 425.9 1,514.9 1,249.3
Other 40.7 9.6 70.7 33.1
Intercompany eliminations (530.6) (274.6) (1,215.0) (963.7)
---------- ---------- --------- ---------
Total revenues 2,212.7 1,886.8 6,183.0 5,619.9
---------- ---------- --------- ---------
Segment costs and expenses:
Costs and operating expenses 1,692.4 1,377.2 4,566.0 4,059.4
Selling, general and administrative expenses 311.2 279.8 939.7 764.3
Other (income) expense--net (Notes 4 and 5) (6.2) 39.0 24.4 97.2
---------- ---------- --------- ---------
Total segment costs and expenses 1,997.4 1,696.0 5,530.1 4,920.9
---------- ---------- --------- ---------
General corporate expenses 12.7 17.2 46.2 76.1
---------- ---------- --------- ---------
Operating income (loss) (Note 15):
Gas Pipeline (Note 3) 142.7 141.7 504.9 489.9
Energy Services (Notes 4 and 5) 135.2 112.4 360.2 308.8
Communications (Note 4) (81.7) (54.0) (209.3) (87.4)
Other 19.1 (9.3) (2.9) (12.3)
General corporate expenses (Note 5) (12.7) (17.2) (46.2) (76.1)
---------- ---------- --------- ---------
Total operating income 202.6 173.6 606.7 622.9
Interest accrued (Note 3) (168.6) (131.5) (446.5) (376.0)
Interest capitalized 10.6 12.6 37.5 28.6
Investing income 7.2 6.2 19.5 19.6
Minority interest in (income) loss of consolidated subsidiaries (2.9) .1 (6.9) (5.5)
Other expense--net (.4) (5.2) (.2) (12.4)
---------- ---------- --------- ---------
Income before income taxes, extraordinary loss and
change in accounting principle 48.5 55.8 210.1 277.2
Provision for income taxes (Notes 4 and 6) 32.8 23.7 121.5 111.5
---------- ---------- --------- ---------
Income before extraordinary loss and change in
accounting principle 15.7 32.1 88.6 165.7
Extraordinary loss (Note 7) -- -- -- (4.8)
---------- ---------- --------- ---------
Income before change in accounting principle 15.7 32.1 88.6 160.9
Change in accounting principle (Note 8) -- -- (5.6) --
---------- ---------- --------- ---------
Net income 15.7 32.1 83.0 160.9
Preferred stock dividends 1.1 1.9 3.6 5.7
---------- ---------- --------- ---------
Income applicable to common stock $ 14.6 $ 30.2 $ 79.4 $ 155.2
========== ========== ========= =========
Basic and diluted earnings per common share (Note 9):
Income before extraordinary loss
and change in accounting principle $ .03 $ .07 $ .19 $ .38
Extraordinary loss (Note 7) -- -- -- (.01)
Change in accounting principle (Note 8) -- -- (.01) --
---------- ---------- --------- ---------
Net income $ .03 $ .07 $ .18 $ .37
========== ========== ========= =========
Basic average shares (thousands) 436,546 428,594 434,579 424,076
Diluted average shares (thousands) 442,244 442,080 440,347 440,874
Cash dividends per common share $ .15 $ .15 $ .45 $ .45
</TABLE>
* Certain amounts have been reclassified as described in Note 2 of Notes to
Consolidated Financial Statements.
See accompanying notes.
2
<PAGE> 4
The Williams Companies, Inc.
Consolidated Balance Sheet
(Unaudited)
<TABLE>
<CAPTION>
(Dollars in millions, except per-share amounts) September 30, December 31,
1999 1998*
------------- ------------
<S> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents $ 287.9 $ 503.3
Receivables 2,344.1 1,628.2
Transportation and exchange gas receivable 55.9 96.4
Inventories (Note 10) 655.7 497.5
Energy trading assets 431.9 354.5
Deferred income taxes 235.4 239.9
Other 246.0 166.1
------------- ------------
Total current assets 4,256.9 3,485.9
Investments 1,280.7 866.1
Property, plant and equipment, at cost 18,074.5 16,206.3
Less accumulated depreciation and depletion (3,971.7) (3,621.0)
------------- ------------
14,102.8 12,585.3
Goodwill and other intangible assets--net 548.9 583.6
Other assets and deferred charges 1,178.3 1,126.4
------------- ------------
Total assets $ 21,367.6 $ 18,647.3
============= ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Notes payable (Note 11) $ 1,355.2 $ 1,052.7
Accounts payable 1,664.8 1,158.2
Accrued rate refund liabilities 211.6 358.7
Other accrued liabilities 1,250.6 1,188.9
Energy trading liabilities 346.8 290.1
Long-term debt due within one year (Note 11) 473.0 390.6
------------- ------------
Total current liabilities 5,302.0 4,439.2
Long-term debt (Note 11) 7,772.8 6,366.4
Deferred income taxes 2,468.4 2,060.8
Other liabilities and deferred income 1,061.6 1,015.2
Minority interest in consolidated subsidiaries 532.4 508.3
Contingent liabilities and commitments (Note 12)
Stockholders' equity:
Preferred stock, $1 par value, 30 million shares authorized, 1.2 million
issued in 1999, 1.8 million in 1998 (Note 17) 69.0 102.2
Common stock, $1 par value, 960 million shares authorized, 438.5 million
issued in 1999, 432.3 million in 1998 438.5 432.3
Capital in excess of par value 1,103.9 982.4
Retained earnings 2,734.1 2,849.5
Accumulated other comprehensive income 16.6 16.7
Other (86.6) (78.5)
------------- ------------
4,275.5 4,304.6
Less treasury stock (at cost) 3.8 million shares of common stock in 1999
and 4.0 million in 1998 (45.1) (47.2)
------------- ------------
Total stockholders' equity 4,230.4 4,257.4
------------- ------------
Total liabilities and stockholders' equity $ 21,367.6 $ 18,647.3
============= ============
</TABLE>
*Certain amounts have been reclassified as discussed in Note 2 of Notes to
Consolidated Financial Statements.
See accompanying notes.
3
<PAGE> 5
The Williams Companies, Inc.
Consolidated Statement of Cash Flows
(Unaudited)
<TABLE>
<CAPTION>
(Millions) Nine months ended September 30,
-------------------------------
1999 1998*
---------- ----------
<S> <C> <C>
OPERATING ACTIVITIES:
Net income $ 83.0 $ 160.9
Adjustments to reconcile to cash provided from operations:
Extraordinary loss -- 4.8
Change in accounting principle 5.6 --
Depreciation, depletion and amortization 545.1 471.8
Provision for deferred income taxes 403.8 67.1
Provision for loss on property and other assets 34.1 29.8
Minority interest in income of consolidated subsidiaries 6.9 5.5
Cash provided (used) by changes in assets and liabilities:
Receivables sold 21.0 (55.9)
Receivables (746.2) 24.0
Inventories (140.4) (.7)
Other current assets (69.4) (31.8)
Accounts payable 577.0 (227.2)
Accrued rate refund liabilities (147.0) 93.7
Other accrued liabilities 18.7 .3
Changes in current energy trading assets and liabilities (20.6) (3.3)
Changes in non-current energy trading assets and liabilities (23.9) (36.7)
Changes in non-current deferred income 131.3 13.9
Other, including changes in non-current assets and liabilities 22.8 (42.3)
---------- ----------
Net cash provided by operating activities 701.8 473.9
---------- ----------
FINANCING ACTIVITIES:
Proceeds from notes payable 2,338.0 708.9
Payments of notes payable (1,418.0) (1,096.7)
Proceeds from long-term debt 2,195.7 2,623.4
Payments of long-term debt (1,327.0) (1,089.7)
Proceeds from issuance of common stock 132.9 67.2
Dividends paid (198.4) (195.8)
Proceeds from sale of LLC member interests -- 100.0
Other--net (5.3) 25.4
---------- ----------
Net cash provided by financing activities 1,717.9 1,142.7
---------- ----------
INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures (2,071.2) (1,334.5)
Proceeds from dispositions and excess fiber capacity transactions 62.7 32.0
Changes in accounts payable and accrued liabilities (63.5) (3.3)
Acquisition of business, net of cash acquired (162.9) --
Proceeds from sale of assets 59.4 1.3
Purchase of investments/advances to affiliates (458.4) (347.9)
Other--net (1.2) 5.3
---------- ----------
Net cash used by investing activities (2,635.1) (1,647.1)
---------- ----------
Decrease in cash and cash equivalents (215.4) (30.5)
Cash and cash equivalents at beginning of period 503.3 122.1
---------- ----------
Cash and cash equivalents at end of period $ 287.9 $ 91.6
========== ==========
</TABLE>
* Certain amounts have been reclassified as discussed in Note 2 of Notes to
Consolidated Financial Statements.
See accompanying notes.
4
<PAGE> 6
The Williams Companies, Inc.
Notes to Consolidated Financial Statements
(Unaudited)
1. General
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The accompanying interim consolidated financial statements of The Williams
Companies, Inc. (Williams) do not include all notes in annual financial
statements and therefore should be read in conjunction with the consolidated
financial statements and notes thereto in Williams' Annual Report on Form 10-K.
The accompanying financial statements have not been audited by independent
auditors but include all adjustments, both normal recurring and others, which,
in the opinion of Williams' management, are necessary to present fairly its
financial position at September 30, 1999, results of operations for the three
and nine months ended September 30, 1999 and 1998, and cash flows for the nine
months ended September 30, 1999 and 1998.
Segment profit of operating companies may vary by quarter. Based on current
rate structures and/or historical maintenance schedules of certain of its
pipelines, Gas Pipeline experiences lower segment profits in the second and
third quarters as compared to the first and fourth quarters.
2. Basis of presentation
- --------------------------------------------------------------------------------
In fourth-quarter 1998, Williams adopted Statement of Financial Accounting
Standards (SFAS) No. 131, "Disclosures about Segments of an Enterprise and
Related Information." Beginning January 1, 1999, Communications' 1998 segment
results have been restated to include the results of investments in certain
Brazilian and Australian telecommunications projects, which had previously been
reported in Other segment revenues and profit (loss). These investments, along
with businesses previously reported as Network Applications and certain
cost-basis investments previously reported in Network Services, are now
collectively managed and reported as Strategic Investments.
Effective April 1, 1998, certain marketing activities were transferred from
other Energy Services segments to Energy Marketing & Trading and combined with
its energy risk trading operations. The income statement presentation relating
to certain of these operations was changed effective April 1, 1998, on a
prospective basis, to reflect these revenues net of the related costs to
purchase such items. Activity prior to this date is reflected on a "gross" basis
in the Consolidated Statement of Income. Concurrent with completing the
combination of such activities with the energy risk trading operations of Energy
Marketing & Trading, the related contract rights and obligations of certain of
these operations are recorded in the Consolidated Balance Sheet at fair value
consistent with Energy Marketing & Trading's accounting policy.
Certain other income statement, balance sheet, cash flow and segment asset
amounts have been reclassified to conform to the current classifications.
3. Rate refund liability reductions
- --------------------------------------------------------------------------------
Based on second-quarter 1999 regulatory proceedings involving rate-of-return
methodology, three of the gas pipelines made reductions to certain rate refund
liabilities and related interest accruals totaling approximately $51 million, of
which $38.2 million is included in Gas Pipeline's segment revenues and segment
profit for the nine months ended September 30, 1999. In addition, $2.7 million
is included in Midstream Gas & Liquids segment revenues and segment profit for
the nine months ended September 30, 1999, as a result of its management of
certain regulated gathering facilities. The balance of $10.6 million is included
as a reduction of interest accrued for the nine months ended September 30, 1999.
4. Asset sales and impairments and other accruals
- --------------------------------------------------------------------------------
Included in other (income) expense-net within segment costs and expenses and
Strategic Investments' segment loss for the nine months ended September 30,
1999, are pre-tax charges totaling $26.7 million relating to management's
second-quarter 1999 decision and commitment to sell certain network application
businesses. The $26.7 million charge consists of a $22.8 million impairment of
the assets to fair value based on the expected net sales proceeds and $3.9
million in exit costs consisting of contractual obligations and employee-related
costs. This transaction resulted in an income tax provision of approximately
$7.9 million, which reflects the impact of goodwill not deductible for tax
purposes. Segment losses for the operations related to these assets for the
three and nine months ended September 30, 1999, are $.9 million and $10 million,
respectively. Segment losses for the operations related to these assets for the
corresponding periods in 1998 were $4.8 million and $14.3 million, respectively.
The sales of these businesses were completed during third-quarter 1999, with no
significant change required to second-quarter 1999 charges noted above. The
proceeds from these sales were approximately $50 million.
Included in other (income) expense-net within segment costs and expenses and
segment profit for Petroleum Services for the nine months ended September 30,
1998, is a $15.5 million loss provision, including interest, for potential
refunds to customers as a result of an order from the Federal Energy Regulatory
Commission (FERC) to Williams Pipe Line (see Note 12 for additional
information). Based on a favorable settlement agreement
5
<PAGE> 7
and FERC approval received October 13, 1999, $6.5 million of the original loss
provision was reversed in third-quarter 1999 and is included in other (income)
expense-net within segment costs and expenses and Petroleum Services' segment
profit for the three and nine months ended September 30, 1999.
Also included in other (income) expense-net within segment costs and expenses
and Strategic Investments' segment loss for the three and nine months ended
September 30, 1998, is a $23.2 million loss related to a venture involved in the
technology and transmission of business information for news and educational
purposes. The loss occurred as a result of Williams' re-evaluation and decision
to exit the venture as Williams decided against making further investment in the
venture. Williams abandoned the venture during fourth-quarter 1998. The loss
primarily consisted of $17 million from the impairment of the total carrying
amount of the investment and $5 million from recognition of contractual
obligations that continued after abandonment.
5. Merger-related costs
- --------------------------------------------------------------------------------
In connection with the 1998 acquisition of MAPCO Inc., Williams recognized
approximately $74 million during the nine months ended September 30, 1998, in
merger-related costs comprised primarily of outside professional fees and early
retirement and severance costs. Approximately $46 million of these
merger-related costs is included in other (income) expense-net within segment
costs and expenses and as a component of Energy Services' segment profit, and
$28 million, unrelated to the segments, is included in general corporate
expenses.
6. Provision for income taxes
- --------------------------------------------------------------------------------
The provision (benefit) for income taxes includes:
<TABLE>
<CAPTION>
Three months ended Nine months ended
(Millions) September 30, September 30,
------------------- -----------------
1999 1998 1999 1998
-------- ------- ------- -------
<S> <C> <C> <C> <C>
Current:
Federal $ .2 $ 16.0 $(299.3) $ 40.8
State 6.3 .1 14.0 2.1
Foreign 1.1 .5 3.0 1.5
-------- ------- ------- -------
7.6 16.6 (282.3) 44.4
Deferred:
Federal 20.7 4.1 389.7 54.6
State 4.5 3.0 14.1 12.5
-------- ------- ------- -------
25.2 7.1 403.8 67.1
-------- ------- ------- -------
Total provision $ 32.8 $ 23.7 $ 121.5 $ 111.5
======== ======= ======= =======
</TABLE>
A federal tax refund of $321 million received in second-quarter 1999 is
reflected for the nine months ended September 30, 1999, as a current federal
benefit with an offsetting deferred federal provision attributable to temporary
differences between the book and tax basis of certain assets.
The effective income tax rate for the three months ended September 30, 1999,
is greater than the federal statutory rate due primarily to the effects of state
income taxes and the losses of foreign entities which are not deductible for
U.S. tax purposes.
The effective income tax rate for the nine months ended September 30, 1999,
is greater than the federal statutory rate due primarily to the effects of state
income taxes, losses of foreign entities not deductible for U.S. tax purposes,
and the impact of goodwill not deductible for tax purposes related to assets
impaired during the second quarter (see Note 4).
The effective income tax rate for 1998 is greater than the federal statutory
rate due primarily to the effects of state income taxes.
7. Extraordinary loss
- -------------------------------------------------------------------------------
In 1998, Williams paid $54.4 million to redeem higher interest rate debt for
a $4.8 million net loss (net of a $2.6 million benefit for income taxes).
8. Change in accounting principles
- -------------------------------------------------------------------------------
Effective January 1, 1999, Williams adopted Statement of Position (SOP) 98-5,
"Reporting on the Costs of Start-Up Activities." The SOP requires that all
start-up costs be expensed as incurred, and the expense related to the initial
application of this SOP of $5.6 million (net of a $3.6 million benefit for
income taxes) is reported as the cumulative effect of a change in accounting
principle.
Additionally, the Emerging Issues Task Force (EITF) reached a consensus on
Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk
Management Activities" which was adopted first-quarter 1999. The effect of
initially applying the consensus at January 1, 1999, is immaterial to Williams'
results of operations and financial position.
In June 1999, the Financial Accounting Standards Board (FASB) issued
interpretation No. 43, "Real Estate Sales, an interpretation of FASB Statement
No. 66," which is effective for sales of real estate with property improvements
or integral equipment entered into after June 30, 1999. Under this
interpretation, dark fiber is considered integral equipment and accordingly
title must transfer to a lessee in order for a lease transaction to be accounted
for as a sales-type lease. After June 30, 1999, the effective date of FASB
Interpretation No. 43, sales-type lease accounting is no longer appropriate for
dark fiber leases and therefore these transactions will be accounted for as
operating leases unless title to the fibers under lease transfers to the lessee
or the agreement was entered into prior to June 30, 1999.
6
<PAGE> 8
9. Earnings per share
- --------------------------------------------------------------------------------
Basic and diluted earnings per common share are computed for the three and
nine months ended September 30, 1999 and 1998, as follows:
<TABLE>
<CAPTION>
(Dollars in millions, except Three Nine
per-share amounts; shares in months ended months ended
thousands) September 30, September 30,
------------------ -------------------
1999 1998 1999 1998
-------- -------- -------- ---------
<S> <C> <C> <C> <C>
Income before extraordinary
loss and change in
accounting principle $ 15.7 $ 32.1 $ 88.6 $ 165.7
Preferred stock dividends 1.1 1.9 3.6 5.7
-------- -------- -------- ---------
Income before extraordinary
loss and change in
accounting principle
available to common
stockholders for basic
earnings per share 14.6 30.2 85.0 160.0
Effect of dilutive securities:
Convertible preferred
stock dividends -- 1.9 -- 5.7
-------- -------- -------- ---------
Income before extraordinary
loss and change in
accounting principle
available to common
stockholders for diluted
earnings per share $ 14.6 $ 32.1 $ 85.0 $ 165.7
======== ======== ======== =========
Basic weighted-average
shares 436,546 428,594 434,579 424,076
Effect of dilutive securities:
Convertible preferred
stock -- 9,030 -- 9,933
Stock options 5,698 4,456 5,768 6,865
-------- -------- -------- ---------
5,698 13,486 5,768 16,798
-------- -------- -------- ---------
Diluted weighted-average
shares 442,244 442,080 440,347 440,874
======== ======== ======== =========
Basic and diluted earnings per
common share before extraordinary
loss and change in accounting
principle $ .03 $ .07 $ .19 $ .38
======== ======== ======== =========
</TABLE>
For the three and nine months ended September 30, 1999, approximately 5.8
million shares and 6.6 million shares, respectively, related to the assumed
conversion of $3.50 convertible preferred stock have been excluded from the
computation of diluted earnings per common share. Inclusion of these shares
would be antidilutive.
10. Inventories
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
September 30, December 31,
(Millions) 1999 1998
------------- ------------
<S> <C> <C>
Raw materials:
Crude oil $ 48.8 $ 43.2
Other 1.6 2.0
------------- ------------
50.4 45.2
Finished goods:
Refined products 210.1 104.0
Natural gas liquids 51.8 58.6
General merchandise and
communications equipment 154.7 92.8
------------- ------------
416.6 255.4
Materials and supplies 93.5 93.4
Natural gas in underground storage 93.1 95.7
Other 2.1 7.8
------------- ------------
$ 655.7 $ 497.5
============= ============
</TABLE>
11. Debt and banking arrangements
- --------------------------------------------------------------------------------
NOTES PAYABLE
In September 1999, Williams' communications business, Williams Communications
Group, Inc. ("WCG"), entered into a $750 million temporary short-term credit
facility, guaranteed by Williams. At September 30, 1999, $625 million was
outstanding under this facility. Interest rates vary with current market
conditions.
During 1999, Williams increased its commercial paper program to $1.4 billion,
backed by a short-term bank-credit facility. At September 30, 1999,
approximately $1.1 billion of commercial paper was outstanding under the
program. Interest rates vary with current market conditions.
DEBT
In September 1999, WCG entered into a $1.05 billion long-term credit
agreement, guaranteed by Williams. Williams is expected to be released from the
guarantee in fourth-quarter 1999. Terms of the credit agreement contain
restrictive covenants limiting the transfer of funds to Williams (parent),
including the payment of dividends and repayment of intercompany borrowings by
WCG to Williams (parent). At September 30, 1999, $500 million was outstanding
under this facility. Interest rates vary with current market conditions.
Williams also has a $1 billion credit agreement under which Northwest
Pipeline, Transcontinental Gas Pipe Line and Texas Gas Transmission have access
to varying amounts of the facility, while Williams has access to all unborrowed
amounts. Interest rates vary with current market conditions.
7
<PAGE> 9
<TABLE>
<CAPTION>
Debt
- --------------------------------------------------------------------------------
Weighted-
average
interest September 30, December 31,
(Millions) rate* 1999 1998
--------- ------------- ------------
<S> <C> <C> <C>
Revolving credit loans 7.0% $ 900.0 $ 694.0
Notes-WCG, 7.63% - 9.5%,
payable 1999 8.0 625.0 --
Debentures, 6.25% - 7.7%,
payable 2006 - 2027 (1) 6.5 935.4 935.4
Debentures, 8.875% - 10.25%,
payable 2003 - 2022 8.5 169.7 169.7
Notes, 5.1% - 7.625%,
payable through 2012 (2) 6.5 4,349.5 3,871.6
Notes, 8.2% - 9.625%,
payable through 2022 8.8 673.7 691.0
Notes, adjustable rate,
payable through 2004 6.2 585.0 386.7
Other, payable through 2009 7.3 7.5 8.6
------------- ------------
8,245.8 6,757.0
Current portion of long-term debt (473.0) (390.6)
------------- ------------
$ 7,772.8 $ 6,366.4
============= ============
</TABLE>
* At September 30, 1999, including the effects of interest-rate swaps.
(1) $200 million, 7.08% debentures, payable 2026, are subject to redemption at
par at the option of the debtholder in 2001.
(2) $300 million, 5.95% notes, payable 2010, and $240 million, 6.125% notes,
payable 2012, are subject to redemption at par at the option of the
debtholder in 2000 and 2002, respectively.
Subsequent to September 30, 1999 and in conjunction with its equity offering
(see Note 16), WCG issued $1.5 billion of 10.875 percent notes due 2009 and $500
million of 10.7 percent notes due 2007. Proceeds from the issuance of the notes
were used to repay the $625 million borrowing under WCG's short-term facility
and the $500 million borrowing under WCG's long-term credit facility. As a
result, these borrowings are classified as noncurrent obligations for financial
reporting purposes.
Also for financial reporting purposes at September 30, 1999, an additional
$230 million in current debt obligations has been classified as non-current
based on Williams' intent and ability to refinance on a long-term basis. At
September 30, 1999, the amount available under the $1 billion credit agreement
of $600 million and the subsequent issuance of $175 million of 7.375 percent
notes due 2006 by Williams Gas Pipeline Central are sufficient to complete the
refinancing of these obligations.
12. Contingent liabilities and commitments
- --------------------------------------------------------------------------------
Rate and regulatory matters and related litigation
Williams' interstate pipeline subsidiaries, including Williams Pipe Line,
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 $203 million for potential refund as of September 30, 1999.
In 1997, the Federal Energy Regulatory Commission (FERC) issued orders
addressing, among other things, the authorized rates of return for three of the
Williams interstate natural gas pipeline subsidiaries. All of the orders involve
rate cases that became effective between 1993 and 1995 and, in each instance,
these cases have been superseded by more recently filed rate cases. In the three
orders, the FERC continued its practice of utilizing a methodology for
calculating rates of return that incorporates a long-term growth rate component.
However, the long-term growth rate component used by the FERC is now a
projection of U.S. gross domestic product growth rates. Generally, calculating
rates of return utilizing a methodology which includes a long-term growth rate
component results in rates of return that are lower than they would be if the
long-term growth rate component were not included in the methodology. Each of
the three pipeline subsidiaries challenged its respective FERC order in an
effort to have the FERC change its rate-of-return methodology with respect to
these and other rate cases. On January 30, 1998, the FERC convened a public
conference to consider, on an industry-wide basis, issues with respect to
pipeline rates of return. In July 1998, the FERC issued orders in two of the
three pipeline subsidiary rate cases, again modifying its rate-of-return
methodology by adopting a formula that gives less weight to the long-term growth
component. Certain parties are appealing the FERC's action, because the most
recent formula modification results in somewhat higher rates of return compared
to the rates of return calculated under the FERC's prior formula. In June and
July 1999, the FERC applied the new methodology in the third pipeline subsidiary
rate case, as well as in a fourth case involving the same pipeline subsidiary.
As a result of these orders and developments in certain other regulatory
proceedings in the second quarter, each of the three gas pipeline subsidiaries
made reductions to its accrued liability for rate refunds to reflect application
of the new rate-of-return methodology (see Note 3).
In 1992, the FERC issued Order 636, Order 636-A and Order 636-B. These
orders, which were challenged in various respects by various parties in
proceedings ruled on by the U.S. Court of Appeals for the D.C. Circuit, required
interstate gas pipeline companies to change the manner in which they provide
services. Williams' gas pipelines subsidiaries implemented restructurings in
1993.
The only appeal challenging Northwest Pipeline's restructuring has been
dismissed. On April 14, 1998, all appeals concerning Transcontinental Gas Pipe
Line's restructuring were denied by the D.C. Circuit. Williams Gas Pipelines
Central's restructuring appeal was remanded to the FERC. The appeal of Texas
Gas' restructuring remains pending. On February 27, 1997, the FERC issued Order
No. 636-C in response to the D.C. Circuit's partial remand of the three previous
636 orders. In that order, the FERC reaffirmed that pipelines should be exempt
from sharing gas supply realignment costs. Rehearing of Order 636-C was denied
in Order 636-D.
8
<PAGE> 10
Orders 636-C and 636 -D have been appealed.
Recently, the FERC issued a Notice of Proposed Rulemaking (NOPR) and a Notice
of Inquiry (NOI), proposing revisions to regulatory policies for interstate
natural gas transportation service. In the NOPR, the FERC proposes to eliminate
the rate cap on short-term transportation services and implement regulatory
policies that are intended to maximize competition in the short-term
transportation market, mitigate the ability of firms to exercise residual
monopoly power and provide opportunities for greater flexibility in the
provision of pipeline services and to revise certain other rate and certificate
policies. In the NOI, the FERC seeks comments on its pricing policies in the
existing long-term market and pricing policies for new capacity. Williams filed
comments on the NOPR and NOI in the second quarter of 1999.
As a result of the Order 636 decisions described, each of the natural gas
pipeline subsidiaries has undertaken the reformation or termination of its
respective gas supply contracts. None of the pipelines has any significant
pending supplier take-or-pay, ratable take or minimum take claims. During
second-quarter 1999, Williams Gas Pipelines Central (Central) reached an
agreement with its customers, state commissions and FERC staff concerning
recovery of certain gas supply realignment costs which arose from supplier
take-or-pay contracts.
Current FERC policy associated with Orders 436 and 500 requires interstate
gas pipelines to absorb some of the cost of reforming gas supply contracts
before allowing any recovery through direct bill or surcharges to transportation
as well as sales commodity rates. Under Orders 636, 636-A, 636-B, 636-C and
636-D, costs incurred to comply with these rules are permitted to be recovered
in full, although a percentage of such costs must be allocated to interruptible
transportation service.
Pursuant to a stipulation and agreement approved by the FERC, Central has
made 17 filings to recover take-or-pay and gas supply realignment costs of
$201.3 million from its customers. An intervenor filed a protest seeking to have
the FERC review the prudence of certain of the costs covered by these filings.
On July 31, 1996, the administrative law judge issued an initial decision
rejecting the intervenor's prudency challenge. On September 30, 1997, the FERC,
by a two-to-one vote, reversed the administrative law judge's decision and
determined that three contracts were imprudently entered into in 1982. Central
filed for rehearing, and management has vigorously defended the prudency of
these contracts. An intervenor also filed a protest seeking to have the FERC
decide whether non-settlement costs are eligible for recovery under Order No.
636. In January 1997, the FERC held that none of the non-settlement costs and
only 75 percent of settlement costs could be recovered by Central if the costs
were not eligible for recovery under Order No. 636. This order was affirmed on
rehearing in April 1997. On June 16, 1998, a FERC administrative law judge
issued an initial decision finding that Central had not met all the tests
necessary to show that these costs were eligible for recovery under Order No.
636. On July 20, 1998, Central filed exceptions to the administrative law
judge's decision. On May 29, 1998, the FERC approved an Order which permitted
Central to conduct a reverse auction of the gas purchase contracts which are the
subject of the prudence challenges outlined above. No party bid less than the
fixed maximum price in the approved auction and, as a result, the contracts were
not assigned. In accordance with the FERC's Orders, on September 30, 1998,
Central filed a request for authority to conduct a second reverse auction of the
contracts. Under the approved reverse auction, Central was granted authority to
assign the contracts to bidders at or below an aggregate reserve price of $112.6
million. If no unaffiliated bidders were willing to accept assignment on those
terms, Central was authorized to assign the contracts to an affiliate or a third
party and recover $112.6 million from its customers subject to the outcome of
the prudence and eligibility cases described above. The FERC also approved an
extension of the recovery mechanism for non-settlement costs through February 1,
1999.
On January 21, 1999, Central assigned its obligations under the largest of
the three contracts to an unaffiliated third party and paid the third party $100
million. Central also agreed to pay the third party a total of $18 million in
installments over the next five years. Central received indemnities from the
third party and a release of its obligations under the contract. No parties
submitted bids at the second reverse auction, and in accordance with the tariff
provisions for the reverse auction, Central assigned the two smaller contracts
to an affiliate effective February 1, 1999. As a result of these assignments,
Central has no remaining above-market price gas contracts. Central has filed
with the FERC to recover all costs related to the three contracts.
Central has been negotiating with the FERC and state regulators to resolve
the amount of costs which are recoverable from its customers. As a result of
these negotiations, Central expensed $58 million in 1998 of costs previously
expected to be recovered and capitalized as a regulatory asset in 1998. At
September 30, 1999, Central had a $50 million regulatory asset representing an
estimate of costs to be recovered in the future. On April 21, 1999, Central
reached an agreement in principle with the FERC staff, the state commissions,
and its customers on all issues related to recovery of Central's remaining
take-or-pay and gas supply realignment costs. The settlement resolves all
prudence, eligibility and absorption issues at a level consistent with Central's
established accruals and provides that Central would be allowed to recover the
costs allocated to its customers by means of a direct bill to be paid, in some
instances, over time. On June 18, 1999, Central filed a proposed stipulation and
agreement with the FERC which documents the April 21 settlement. One interested
party objected to the settlement, which is subject to FERC approval. The chief
administrative law judge dismissed the objection and certified the settlement as
"uncontested" to the FERC on July 28, 1999. On August 29, 1999, the FERC
approved the stipulation and agreement as an
9
<PAGE> 11
uncontested settlement and rejected all objections. No party filed a request for
rehearing and the FERC's approval is final. The settlement was effective
November 1, 1999.
In September 1995, Texas Gas received FERC approval of a settlement regarding
Texas Gas' recovery of gas supply realignment costs. Through September 30, 1999,
Texas Gas has paid approximately $76 million and expects to pay no more than $80
million for gas supply realignment costs, primarily as a result of contract
terminations. Texas Gas has recovered approximately $66 million, plus interest,
in gas supply realignment costs. On June 1, 1999, Texas Gas filed with the FERC
under the provisions of Order No. 528 to recover 75 percent of approximately
$1.8 million in costs it has been required to pay pursuant to indemnifications
for royalties. Texas Gas began collecting these costs subject to refund
effective July 1, 1999, pursuant to a FERC order. On October 7, 1999, Texas Gas
received a letter order from the Commission approving the collection of these
costs.
The foregoing accruals are in accordance with Williams' accounting policies
regarding the establishment of such accruals which take into consideration
estimated total exposure, as discounted and risk-weighted, as well as costs and
other risks associated with the difference between the time costs are incurred
and the time such costs are recovered from customers. The estimated portion of
such costs recoverable from customers is deferred or recorded as a regulatory
asset based on an estimate of expected recovery of the amounts allowed by the
FERC policy. Costs to be incurred are fixed. Cost recovery is subject only to
collection risk for which reserves have been provided.
On July 15, 1998, Williams Pipe Line (WPL) received an Order from the FERC
which affirmed an administrative law judge's 1996 initial decision regarding
rate-making proceedings for the period September 15, 1990, through May 1, 1992.
The FERC has ruled that WPL did not meet its burden of establishing that its
transportation rates in its 12 noncompetitive markets were just and reasonable
for the period and has ordered refunds. WPL continues to believe it should
prevail upon appeal regarding collected rates for that period. However, due to
this FERC decision, WPL accrued $15.5 million, including interest, in
second-quarter 1998, for potential refunds to customers for the issues described
above. On May 20, 1999, WPL submitted an uncontested offer of settlement to the
presiding administrative law judge that would resolve all outstanding rate
issues on WPL from September 1, 1990 to the present. This settlement was
certified to the FERC as uncontested on June 23, 1999. On October 13, 1999, the
FERC approved the settlement without conditions. Based on this favorable
settlement and FERC approval, $6.5 million of the original $15.5 million loss
provision was reversed in third-quarter 1999. The settlement will become final
on December 13, 1999, if no appeals are filed.
Environmental matters
Since 1989, Texas Gas and Transcontinental Gas Pipe Line have had studies
under way to test certain of their facilities for the presence of toxic and
hazardous substances to determine to what extent, if any, remediation may be
necessary. Transcontinental Gas Pipe Line has responded to data requests
regarding such potential contamination of certain of its sites. The costs of any
such remediation will depend upon the scope of the remediation. At September 30,
1999, these subsidiaries had reserves totaling approximately $26 million for
these costs.
Certain Williams subsidiaries, including Texas Gas and Transcontinental Gas
Pipe Line, have been identified as potentially responsible parties (PRP) at
various Superfund and state waste disposal sites. In addition, these
subsidiaries have incurred, or are alleged to have incurred, various other
hazardous materials removal or remediation obligations under environmental laws.
Although no assurances can be given, Williams does not believe that these
obligations or the PRP status of these subsidiaries will have a material adverse
effect on its financial position, results of operations or net cash flows.
Transcontinental Gas Pipe Line, Texas Gas and Central have identified
polychlorinated biphenyl (PCB) contamination in air compressor systems, soils
and related properties at certain compressor station sites. Transcontinental Gas
Pipe Line, Texas Gas and Central have also been involved in negotiations with
the U.S. Environmental Protection Agency (EPA) and state agencies to develop
screening, sampling and cleanup programs. In addition, negotiations with certain
environmental authorities and other programs concerning investigative and
remedial actions relative to potential mercury contamination at certain gas
metering sites have been commenced by Central, Texas Gas and Transcontinental
Gas Pipe Line. As of September 30, 1999, Central had accrued a liability for
approximately $11 million, representing the current estimate of future
environmental cleanup costs to be incurred over the next six to ten years. Texas
Gas and Transcontinental Gas Pipe Line likewise had accrued liabilities for
these costs which are included in the $26 million reserve mentioned above.
Actual costs incurred will depend on the actual number of contaminated sites
identified, the actual amount and extent of contamination discovered, the final
cleanup standards mandated by the EPA and other governmental authorities and
other factors. Texas Gas, Transcontinental Gas Pipe Line and Central have
deferred these costs as incurred pending recovery through future rates and other
means.
Transcontinental Gas Pipe Line received a letter stating that the U.S.
Department of Justice (DOJ), at the request of the EPA, intends to file a civil
action against Transcontinental Gas Pipe Line arising from its waste management
practices at Transcontinental Gas Pipe Line's compressor stations and metering
stations in
10
<PAGE> 12
eleven states from Texas to New Jersey. DOJ stated in the letter that its
complaint will seek civil penalties and injunctive relief under federal
environmental laws. DOJ and Transcontinental Gas Pipe Line are discussing a
settlement. While no specific amount was proposed, DOJ stated that any
settlement must include an appropriate civil penalty for the alleged violations.
Transcontinental Gas Pipe Line cannot reasonably estimate the amount of its
potential liability, if any, at this time. However, Transcontinental Gas Pipe
Line believes it has substantially addressed environmental concerns on its
system through ongoing voluntary remediation and management programs.
Energy Services (WES) also accrues environmental remediation costs for its
natural gas gathering and processing facilities, petroleum products pipelines,
retail petroleum, refining and propane marketing operations primarily related to
soil and groundwater contamination. At September 30, 1999, WES and its
subsidiaries had accrued liabilities totaling approximately $43 million. WES
recognizes receivables related to environmental remediation costs from state
funds as a result of laws permitting states to reimburse certain expenses
associated with underground storage tank problems and repairs. At September 30,
1999, WES and its subsidiaries had accrued receivables totaling $19 million.
In connection with the 1987 sale of the assets of Agrico Chemical Company,
Williams agreed to indemnify the purchaser for environmental cleanup costs
resulting from certain conditions at specified locations, to the extent such
costs exceed a specified amount. At September 30, 1999, Williams had
approximately $13 million accrued for such excess costs. The actual costs
incurred will depend on the actual amount and extent of contamination
discovered, the final cleanup standards mandated by the EPA or other
governmental authorities, and other factors.
A lawsuit was filed in May 1993, in a state court in Colorado in which
certain claims have been made against various defendants, including Northwest
Pipeline, contending that gas exploration and development activities in portions
of the San Juan Basin have caused air, water and other contamination. The
plaintiffs in the case sought certification of a plaintiff class. In June 1994,
the lawsuit was dismissed for failure to join an indispensable party over which
the state court had no jurisdiction. The Colorado court of appeals affirmed the
dismissal and remanded the case to Colorado district court for action consistent
with the appeals court's decision. Since June 1994, eight individual lawsuits
were filed against Northwest Pipeline and others in U.S. district court in
Colorado, making essentially the same claims. The district court stayed all of
the cases involving Northwest Pipeline until the plaintiffs exhausted their
remedies before the Southern Ute Indian Tribal Court. Some plaintiffs filed
cases in the Tribal Court, but none named Northwest Pipeline as a defendant. The
parties have now executed a settlement agreement which settles all Federal and
Tribal cases.
Other legal matters
On April 7, 1992, a liquefied petroleum gas explosion occurred near an
underground salt dome storage facility located near Brenham, Texas and owned by
an affiliate of MAPCO Inc., Seminole Pipeline Company ("Seminole"). MAPCO Inc.,
as well as Seminole, Mid-America Pipeline Company, MAPCO Natural Gas Liquids
Inc., and other non-MAPCO entities were named as defendants in civil action
lawsuits filed in state district courts located in four Texas counties. Seminole
and the above-mentioned subsidiaries of MAPCO Inc. have settled in excess of
1,600 claims in these lawsuits. As of January 1999, the only lawsuit not fully
resolved was the Dallmeyer case which was tried before a jury in Harris County.
In Dallmeyer, the judgment rendered in March 1996 against defendants Seminole
and MAPCO Inc. and its subsidiaries totaled approximately $72 million, which
included nearly $65 million of punitive damages awarded to the 21 plaintiffs.
Both plaintiffs and defendants have appealed the Dallmeyer judgment to the Court
of Appeals for the Fourteenth District of Texas in Harris County. In February
and March 1998, the defendants entered into settlement agreements involving 17
of the 21 plaintiffs to finally resolve their claims against all defendants for
an aggregate payment of approximately $10 million. These settlements have
satisfied and reduced the judgment on appeal by approximately $42 million as to
the remaining four plaintiffs. The Court of Appeals issued its decision on
October 15, 1998, which, while denying all of the plaintiffs' cross-appeal
issues, affirmed in part and reversed in part the trial court's judgment. The
defendants had entered into settlement agreements with the remaining plaintiffs
which, in light of the decisions, provided for aggregate payments of
approximately $13.6 million, the full amount of which has been previously
accrued. The releases from the last remaining plaintiffs were received in
February 1999.
In 1991, the Southern Ute Indian Tribe (the Tribe) filed a lawsuit against
Williams Production Company (Williams Production), a wholly owned subsidiary of
Williams, and other gas producers in the San Juan Basin area, alleging that
certain coal strata were reserved by the United States for the benefit of the
Tribe and that the extraction of coal-seam gas from the coal strata was
wrongful. The Tribe seeks compensation for the value of the coal-seam gas. The
Tribe also seeks an order transferring to the Tribe ownership of all of the
defendants' equipment and facilities utilized in the extraction of the coal-seam
gas. In September 1994, the court granted summary judgment in favor of the
defendants, and the Tribe lodged an interlocutory appeal with the U.S. Court of
Appeals for the Tenth Circuit. Williams Production agreed to indemnify the
Williams Coal Seam Gas Royalty Trust (Trust) against any losses that may arise
in respect of certain properties subject to the lawsuit. On July 16, 1997, the
U.S. Court of Appeals for the Tenth Circuit reversed the decision of the
district court, held that the Tribe owns the coal-seam gas produced from certain
coal strata on fee lands within the
11
<PAGE> 13
exterior boundaries of the Tribe's reservation, and remanded the case to the
district court for further proceedings. On September 16, 1997, Amoco Production
Company, the class representative for the defendant class (of which Williams
Production is a part), filed its motion for rehearing En Banc before the court
of Appeals. On July 20, 1998, the Court of Appeals sitting En Banc affirmed the
panel's decision. After the Court of Appeals decision, Williams Production
entered into an agreement in principle to settle the Tribe's claims against it.
Final settlement documents have now been executed by Williams Production and the
Tribe. Under the agreement, Williams has agreed to pay certain costs associated
with production and transfer a portion of its interest to the Tribe. The Tribe
released Williams Production from the claims asserted in the lawsuit. The
settlement has been submitted to the U.S. District Court for final approval and
will become final if no objections are filed by November 8, 1999. The Supreme
Court granted a Writ of Certiorari in respect of the Court of Appeals
affirmation of the decision en banc, and on June 7, 1999, the Supreme Court
reversed the decision of the Court of Appeals and held that the Tribe did not
own the coal-seam gas produced from certain coal strata on fee lands within the
exterior boundaries of the Tribe's reservation. The Supreme Court decision does
not impact the terms of the settlement.
In connection with agreements to resolve take-or-pay and other contract
claims and to amend gas purchase contracts, Transcontinental Gas Pipe Line and
Texas Gas each entered into certain settlements with producers which may require
the indemnification of certain claims for additional royalties which the
producers may be required to pay as a result of such settlements. As a result of
such settlements, Transcontinental Gas Pipe Line is currently defending two
lawsuits brought by producers. In one of the cases, a jury verdict found that
Transcontinental Gas Pipe Line was required to pay a producer damages of $23.3
million including $3.8 million in attorneys' fees. Transcontinental Gas Pipe
Line is pursuing an appeal. In the other case, a producer has asserted damages,
including interest calculated through December 31, 1997, of approximately $6
million. Producers have received and may receive other demands, which could
result in additional claims. Indemnification for royalties will depend on, among
other things, the specific lease provisions between the producer and the lessor
and the terms of the settlement between the producer and either Transcontinental
Gas Pipe Line or Texas Gas. Texas Gas may file to recover 75 percent of any such
additional amounts it may be required to pay pursuant to indemnities for
royalties under the provisions of Order 528.
In connection with the sale of certain coal assets in 1996, MAPCO entered
into a Letter Agreement with the buyer providing for indemnification by MAPCO
for reductions in the price or tonnage of coal delivered under a certain
pre-existing Coal Sales Agreement dated December 1, 1986. The Letter Agreement
is effective for reductions during the period July 1, 1996, through December 31,
2002, and provides for indemnification for such reductions as incurred on a
quarterly basis. The buyer has stated it is entitled to indemnification from
MAPCO for amounts of $7.8 million through June 30, 1998, and may claim
indemnification for additional amounts in the future. MAPCO has filed for
declaratory relief as to certain aspects of the buyer's claims. MAPCO also
believes it would be entitled to substantial set-offs and credits against any
amounts determined to be due and has accrued a liability representing an
estimate of amounts it expects to incur in satisfaction of this indemnity. The
parties have entered into settlement agreements which provided for the payment
of approximately $35 million to settle this and certain other minor unrelated
claims, most of which had been previously accrued. As a result of the
settlement, the declaratory relief litigation will be dismissed.
In 1998, the United States Department of Justice informed Williams that Jack
Grynberg, an individual, had filed claims in the United States District Court
for the District of Colorado under the False Claims Act against Williams and
certain of its wholly owned subsidiaries including Williams Gas Pipelines
Central, Kern River Gas Transmission, Northwest Pipeline, Williams Gas Pipeline
Company, Transcontinental Gas Pipe Line Corporation, Texas Gas, Williams Field
Services Company and Williams Production Company. Mr. Grynberg has also filed
claims against approximately 300 other energy companies and alleges that the
defendants violated the False Claims Act in connection with the measurement and
purchase of hydrocarbons. The relief sought is an unspecified amount of
royalties allegedly not paid to the federal government, treble damages, a civil
penalty, attorneys' fees, and costs. On April 9, 1999, the United States
Department of Justice announced that it was declining to intervene in any of the
Grynberg QUI TAM cases, including the action filed against the Williams entities
in the United States District Court for the District of Colorado. On October 21,
1999, the Panel on Multi- District Litigation transferred all of the Grynberg
qui tam cases, including the ones filed against Williams, to the United States
District Court for the District of Wyoming for pre-trial purposes.
Shrier v. Williams was filed on August 4, 1999, in the U.S. District Court
for the Northern District of Oklahoma. Oxford v. Williams was filed on September
3, 1999, in state court in Jefferson County, Texas. The Oxford complaint was
amended to add an additional plaintiff on September 24, 1999. On October 1,
1999, the case was removed to the U.S. District Court for the Eastern District
of Texas, Beaumont Division. In each lawsuit, the plaintiff seeks to bring a
nationwide class action on behalf of all landowners on whose property the
plaintiffs allege WCG has installed fiber-optic cable without the permission of
the landowner. The plaintiffs are seeking a declaratory ruling that WCG is
trespassing, damages resulting from the alleged trespass, damages based on our
profits from use of the property and damages from alleged fraud. Relief
requested by the plaintiff includes injunction against further trespass, actual
and punitive damages, and attorneys' fees.
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<PAGE> 14
Williams believes that installation of the cable containing the single-fiber
network that crosses over or near the named plaintiffs' land does not infringe
on the plaintiffs' property rights. Williams also does not believe that the
plaintiffs in these lawsuits have sufficient basis for certification of a class
action. The proposed composition of the class in the Oxford lawsuit appears to
include only landowners who would also be included in the class proposed in the
Shrier suit.
Class actions have been filed by the plaintiffs in Shrier and Oxford against
certain communications carriers which challenge the carriers' rights to install
and operate fiber-optic systems along railroad rights of way. Approximately 15
percent of WCG's network is installed on railroad rights of way. WCG is a party
to litigation challenging its right to use railroad rights of way over which it
has installed approximately 28 miles of its network. The plaintiffs in this
action are seeking to have this matter certified as a class action. WCG cannot
quantify the impact of such claims at this time.
In addition to the foregoing, various other proceedings are pending against
Williams or its subsidiaries which are incidental to their operations.
Summary
While no assurances may be given, Williams does not believe that the ultimate
resolution of the foregoing matters, taken as a whole and after consideration of
amounts accrued, insurance coverage, recovery from customers or other
indemnification arrangements, will have a materially adverse effect upon
Williams' future financial position, results of operations or cash flow
requirements.
Other matters
Energy Marketing & Trading has entered into certain contracts giving Williams
the right to receive fuel conversion and certain other services for purposes of
generating electricity. At September 30, 1999, annual estimated committed
payments under these contracts range from $62.7 million to $344.8 million,
resulting in total committed payments over the next 22 years of approximately
$6.5 billion.
13. Adoption of accounting standards
- --------------------------------------------------------------------------------
The FASB has issued SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities." This standard as amended, effective for fiscal years
beginning after June 15, 2000, requires that all derivatives be recognized as
assets or liabilities in the balance sheet and that those instruments be
measured at fair value. The effect of this standard on Williams' results of
operations and financial position is being evaluated.
14. Comprehensive income (loss)
- --------------------------------------------------------------------------------
Comprehensive income (loss) for the three months and nine months ended
September 30 is as follows:
<TABLE>
<CAPTION>
Three Nine
months ended months ended
(Millions) September 30, September 30,
---------------------- ----------------------
1999 1998 1999 1998
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
Net income $ 15.7 $ 32.1 $ 83.0 $ 160.9
Other comprehensive
income (loss):
Unrealized gains
(losses) on securities (102.5) (16.0) 29.1 10.8
Foreign currency
translation adjust-
ments 3.0 (2.0) (17.9) (4.5)
--------- --------- --------- ---------
Other comprehensive
income (loss) before
taxes (99.5) (18.0) 11.2 6.3
Income taxes (benefit) on
other comprehensive
income (loss) (39.9) (6.2) 11.3 4.2
--------- --------- --------- ---------
Comprehensive
income (loss) $ (43.9) $ 20.3 $ 82.9 $ 163.0
========= ========= ========= =========
</TABLE>
13
<PAGE> 15
15. Segment disclosures
- --------------------------------------------------------------------------------
Williams evaluates performance based upon segment profit or loss from
operations which includes revenues from external and internal customers, equity
earnings, operating costs and expenses, and depreciation, depletion and
amortization. Intersegment sales are generally accounted for as if the sales
were to unaffiliated third parties, that is, at current market prices.
Williams' reportable segments are strategic business units that offer
different products and services. The segments are managed separately because
each segment requires different technology, marketing strategies and industry
knowledge. Other includes investments in international energy and certain
communications-related ventures, as well as corporate operations.
The following table reflects the reconciliation of segment profit, per the
tables on pages 15 and 16, to operating income as reported in the Consolidated
Statement of Income for the three and nine months ended September 30:
<TABLE>
<CAPTION>
Three Nine
months ended months ended
(Millions) September 30, September 30,
---------------------- ----------------------
1999 1998 1999 1998
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
Segment profit $ 215.3 $ 190.8 $ 652.9 $ 699.0
General corporate
expenses (12.7) (17.2) (46.2) (76.1)
--------- --------- --------- ---------
Operating income $ 202.6 $ 173.6 $ 606.7 $ 622.9
========= ========= ========= =========
</TABLE>
The increase in Energy Marketing & Trading's total assets, as noted on page
16, is due primarily to increased electric power services activity.
The increase in Network Services' total assets, also noted on page 16, is
due primarily to the construction of its fiber-optic network.
The increase in Strategic Investments' total assets, also noted on page 16
and the investment balance in the Consolidated Balance Sheet is due primarily to
the additional investments in a Brazilian telecommunications project.
14
<PAGE> 16
15. Segment disclosures (continued)
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Revenues
---------------------------------------------------
External Inter- Equity Earnings Segment
(Millions) Customers segment (Losses) Total Profit (Loss)
--------- -------- --------------- ---------- -------------
<S> <C> <C> <C> <C> <C>
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 1999
GAS PIPELINE $ 392.3 $ 16.0 $ 1.2 $ 409.5 $ 142.7
ENERGY SERVICES
Energy Marketing & Trading 648.8 (16.1)* -- 632.7 16.0
Exploration & Production 20.3 36.9 -- 57.2 8.1
Midstream Gas & Liquids 184.5 94.7 (2.5) 276.7 68.2
Petroleum Services 444.7 377.1 .3 822.1 46.1
Merger-related costs and
non-compete amortization -- -- -- -- (3.2)
--------- -------- --------------- ---------- -------------
1,298.3 492.6 (2.2) 1,788.7 135.2
--------- -------- --------------- ---------- -------------
COMMUNICATIONS
Communications Solutions 359.0 -- -- 359.0 (11.0)
Network Services 74.4 11.7 .1 86.2 (48.8)
Strategic Investments 64.0 -- (4.8) 59.2 (21.9)
--------- -------- --------------- ---------- -------------
497.4 11.7 (4.7) 504.4 (81.7)
--------- -------- --------------- ---------- -------------
OTHER 22.7 10.3 7.7 40.7 19.1
ELIMINATIONS -- (530.6) -- (530.6) --
--------- -------- --------------- ---------- -------------
TOTAL $ 2,210.7 $ -- $ 2.0 $ 2,212.7 $ 215.3
========= ======== =============== ========== =============
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 1998
GAS PIPELINE $ 386.1 $ 13.4 $ -- $ 399.5 $ 141.7
ENERGY SERVICES
Energy Marketing & Trading 490.5 (40.8)* (4.3) 445.4 10.3
Exploration & Production 5.5 23.2 -- 28.7 4.9
Midstream Gas & Liquids 193.2 15.6 (.3) 208.5 56.2
Petroleum Services 388.9 254.8 .1 643.8 44.9
Merger-related costs and
non-compete amortization -- -- -- -- (3.9)
--------- -------- --------------- ---------- -------------
1,078.1 252.8 (4.5) 1,326.4 112.4
--------- -------- --------------- ---------- -------------
COMMUNICATIONS
Communications Solutions 344.9 -- -- 344.9 (1.2)
Network Services 21.0 12.5 -- 33.5 (11.0)
Strategic Investments 51.6 1.2 (5.3) 47.5 (41.8)
--------- -------- --------------- ---------- -------------
417.5 13.7 (5.3) 425.9 (54.0)
--------- -------- --------------- ---------- -------------
OTHER 19.7 (5.3) (4.8) 9.6 (9.3)
ELIMINATIONS -- (274.6) -- (274.6) --
--------- -------- --------------- ---------- -------------
TOTAL $ 1,901.4 $ -- $ (14.6) $ 1,886.8 $ 190.8
========= ======== =============== ========== =============
</TABLE>
* Energy Marketing & Trading intercompany cost of sales, which are netted in
revenues consistent with fair value accounting, exceed intercompany revenue.
15
<PAGE> 17
15. Segment disclosures (continued)
<TABLE>
<CAPTION>
Revenues
---------------------------------------------------
External Inter- Equity Earnings Segment
(Millions) Customers segment (Losses) Total Profit (Loss)
--------- -------- --------------- ---------- -------------
<S> <C> <C> <C> <C> <C>
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 1999
GAS PIPELINE $ 1,257.2 $ 41.8 $ 1.9 $ 1,300.9 $ 504.9
ENERGY SERVICES
Energy Marketing & Trading 1,695.2 (87.7)* (.3) 1,607.2 72.2
Exploration & Production 32.4 95.3 -- 127.7 19.8
Midstream Gas & Liquids 514.7 227.4 (10.4) 731.7 168.4
Petroleum Services 1,172.1 872.2 .6 2,044.9 109.8
Merger-related costs and
non-compete amortization -- -- -- -- (10.0)
--------- -------- --------------- ---------- -------------
3,414.4 1,107.2 (10.1) 4,511.5 360.2
--------- -------- --------------- ---------- -------------
COMMUNICATIONS
Communications Solutions 1,051.5 -- -- 1,051.5 (27.8)
Network Services 247.7 35.8 .1 283.6 (86.3)
Strategic Investments 197.3 .3 (17.8) 179.8 (95.2)
--------- -------- --------------- ---------- -------------
1,496.5 36.1 (17.7) 1,514.9 (209.3)
--------- -------- --------------- ---------- -------------
OTHER 53.5 29.9 (12.7) 70.7 (2.9)
ELIMINATIONS -- (1,215.0) -- (1,215.0) --
--------- -------- --------------- ---------- -------------
TOTAL $ 6,221.6 $ -- $ (38.6) $ 6,183.0 $ 652.9
========= ======== =============== ========== =============
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 1998
GAS PIPELINE $ 1,203.5 $ 37.2 $ .2 $ 1,240.9 $ 489.9
ENERGY SERVICES
Energy Marketing & Trading 1,531.1 (68.2)* (7.2) 1,455.7 28.1
Exploration & Production 28.6 78.2 -- 106.8 25.2
Midstream Gas & Liquids 601.2 47.6 1.6 650.4 177.3
Petroleum Services 1,034.4 812.7 .3 1,847.4 124.1
Merger-related costs and
non-compete amortization -- -- -- -- (45.9)
--------- -------- --------------- ---------- -------------
3,195.3 870.3 (5.3) 4,060.3 308.8
--------- -------- --------------- ---------- -------------
COMMUNICATIONS
Communications Solutions 1,016.4 -- -- 1,016.4 13.1
Network Services 48.2 37.3 -- 85.5 (25.4)
Strategic Investments 151.8 3.6 (8.0) 147.4 (75.1)
--------- -------- --------------- ---------- -------------
1,216.4 40.9 (8.0) 1,249.3 (87.4)
--------- -------- --------------- ---------- -------------
OTHER 24.6 15.3 (6.8) 33.1 (12.3)
ELIMINATIONS -- (963.7) -- (963.7) --
--------- -------- --------------- ---------- -------------
TOTAL $ 5,639.8 $ -- $ (19.9) $ 5,619.9 $ 699.0
========= ======== =============== ========== =============
</TABLE>
<TABLE>
<CAPTION>
TOTAL ASSETS
-------------------------------------
(Millions) September 30, 1999 December 31, 1998
------------------ -----------------
<S> <C> <C>
GAS PIPELINE $ 8,390.0 $ 8,386.2
ENERGY SERVICES
Energy Marketing & Trading 3,381.8 2,596.8
Exploration & Production 594.1 484.1
Midstream Gas & Liquids 3,442.1 3,201.8
Petroleum Services 2,676.5 2,525.2
------------------ -----------------
10,094.5 8,807.9
------------------ -----------------
COMMUNICATIONS
Communications Solutions 1,054.1 946.4
Network Services 1,565.1 712.9
Strategic Investments 1,041.4 638.4
------------------ -----------------
3,660.6 2,297.7
------------------ -----------------
OTHER 5,735.2 4,782.4
ELIMINATIONS (6,512.7) (5,626.9)
------------------ -----------------
TOTAL $ 21,367.6 $ 18,647.3
================== =================
</TABLE>
* Energy Marketing & Trading intercompany cost of sales, which are netted in
revenues consistent with fair-value accounting, exceed intercompany revenues.
16
<PAGE> 18
16. Communications' initial public offering
- --------------------------------------------------------------------------------
On October 1, 1999, Williams' communications business, WCG, completed an
initial public offering of approximately 34 million shares of its common stock
at $23 per share for net proceeds of approximately $738 million. In addition,
approximately 34 million shares of common stock were privately sold in
concurrent investments by SBC Communications Inc., Intel Corporation, and
Telefonos de Mexico for proceeds of $738.5 million. These transactions resulted
in a reduction of the Williams' ownership interest in WCG from 100 percent to
85.3 percent. The sale of the subsidiary's stock will result in an approximate
$1.2 billion increase to Williams' stockholders' equity and an initial increase
in excess of $300 million to Williams' minority interest liability. In
conjunction with the public equity offering, WCG issued $2 billion of high-yield
public debt (see Note 11).
17. Preferred stock
- --------------------------------------------------------------------------------
On October 4, 1999, Williams called for the redemption at the close of
business November 1, 1999 of all outstanding shares of its $3.50 cumulative
convertible preferred stock. All outstanding shares were convertible to Williams
common stock at the option of the holder and were so converted by the redemption
date.
18. Sale of retail propane business
- --------------------------------------------------------------------------------
On November 8, 1999, Williams announced it had reached an agreement, after
receiving an unsolicited offer from Ferrellgas Partners L.P. ("Ferrellgas"), to
sell Williams' retail propane business, Thermogas Company, to Ferrellgas for
$432.5 million including $175 million in senior common units of Ferrellgas. This
transaction is subject to certain conditions, including review under federal
anti-trust laws and is expected to close before the end of 1999. Thermogas's
operations are reported within the Energy Marketing & Trading segment.
ITEM 2
Management's Discussion and Analysis of
Financial Condition and Results of Operations
RESULTS OF OPERATIONS
Third Quarter 1999 vs. Third Quarter 1998
CONSOLIDATED OVERVIEW
Williams' revenues increased $326 million, or 17 percent, due primarily to
higher revenues at Energy Services from increased petroleum products and natural
gas liquids sales volumes and average sales prices and Communications' new
business growth. Partially offsetting these increases were lower electric power
services and pipeline construction revenues.
Segment costs and expenses increased $301 million, or 18 percent, due
primarily to increased costs at Energy Services related to increased petroleum
products and natural gas liquids volumes purchased and average purchase prices
and higher costs and expenses from Communications' new business growth. These
increases were partially offset by lower costs from electric power services
activities, lower pipeline construction costs, the effect of Communications'
1998 asset write-downs of $29 million and the effect of Energy Services' 1998
credit loss accruals of $26 million.
Operating income increased $29 million, or 17 percent, due primarily to a
$29 million improvement from International activities (included in Other segment
profit (loss)) and a $23 million increase from Energy Services, partially offset
by a $28 million decrease at Communications. The Energy Services improvement
reflects higher trading margins from natural gas services and natural gas
liquids, increased per-unit natural gas liquids sales margins and the effect of
1998 credit loss accruals totaling $26 million. These increases were largely
offset by $73 million lower electric power services margins from recording
revenue in accordance with EITF 98-10 "Accounting for Contracts Involved in
Energy Trading and Risk Management Activities" which was adopted first-quarter
1999 and lower demand for electricity in southern California in 1999 compared to
1998 due to cooler summer temperatures in 1999. The decrease at Communications
is due primarily to costs associated with infrastructure growth and improvement
and losses experienced from providing customer services prior to completion of
the new network, partially offset by the effect of 1998 asset write-downs
totaling $29 million.
Income before income taxes, extraordinary loss and change in accounting
principle decreased $7 million, or 13 percent, due primarily to $39 million
higher net interest expense reflecting increased debt in support of continued
expansion and new projects, largely offset by the higher operating income.
17
<PAGE> 19
GAS PIPELINE
GAS PIPELINE'S revenues increased $10 million, or 2 percent, due primarily
to $21 million higher historical gas exchange imbalance settlements (offset in
costs and operating expenses), a $4 million reduction to rate refund
liabilities, and $3 million from expansion projects. These increases were
largely offset by $10 million lower reimbursable costs passed through to
customers (offset in costs and operating expenses), $6 million lower
transportation and other revenues (mainly from transportation rate discounting,
rate design and decreased interruptible transportation volumes) and the effect
of favorable 1998 adjustments of $3 million from the settlement of rate case
issues.
Segment profit increased $1 million, or 1 percent, due primarily to the $7
million effect of 1999 regulatory and rate adjustments (including $3 million of
reductions to costs and operating expenses), $3 million lower operating and
maintenance expenses and $3 million higher revenues from expansion projects,
partially offset by $6 million lower transportation and other revenues, the
effect of the favorable 1998 rate reserve adjustments of $3 million and $2
million higher depreciation and amortization.
Based on current rate structures and/or historical maintenance schedules of
certain of its pipelines, Gas Pipeline experiences lower segment profits in the
second and third quarters as compared to the first and fourth quarters.
ENERGY SERVICES
ENERGY MARKETING & TRADING'S operating results can be significantly impacted
by energy commodity price volatility. In addition, trading sales revenues are
reported net of the related purchase costs while non-trading activities are
reported gross. As a result, net revenues (revenues less cost of sales) is used
to analyze Energy Marketing & Trading's operating results as shown below:
18
<PAGE> 20
<TABLE>
<CAPTION>
1999 1998
------- -------
<S> <C> <C>
Revenues $632.7 $ 445.4
Cost of sales 556.7 361.7
------- -------
Net Revenues $ 76.0 $ 83.7
======= =======
</TABLE>
Revenues increased $187.3 million, or 42 percent, due primarily to $229
million higher crude and refined products revenues which reflects higher average
sales prices and increased sales volumes associated primarily with crude sales
to the Memphis refinery. In addition, revenues increased due to $45 million
higher natural gas services revenues, $37 million higher natural gas liquids
trading revenues and $27 million higher retail gas and electric revenues,
partially offset by $147 million lower electric power services revenues. The
higher natural gas services revenues includes $36 million of favorable contract
settlements during third-quarter 1999 and the effects of more favorable market
and supply conditions, partially offset by the effect of a $9.5 million
favorable long-term natural gas transportation contract settlement in 1998.
Retail gas and electric increased revenues resulted from the fourth-quarter 1998
acquisition of Volunteer Energy. The lower electric power services revenues
reflects the effect of recording revenue in accordance with EITF 98-10
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities" which was adopted first-quarter 1999 and lower demand for
electricity in southern California in 1999 compared to 1998 due to cooler summer
temperatures in 1999.
Cost of sales increased $194.9 million, or 54 percent, due primarily to
higher costs for crude and refined products, natural gas liquids and retail gas
and electric operations of $228 million, $23 million and $22 million,
respectively, partially offset by $74 million lower costs for electric power
services. These variances are associated with the corresponding changes in
revenues discussed above.
Net revenues decreased $7.7 million, or 9 percent, due primarily to $73
million lower electric power services margins resulting from the adoption of
EITF 98-10 discussed above and cooler summer temperatures in southern California
in 1999 and $6 million of lower retail propane margins. Substantially offsetting
these decreases were $45 million higher natural gas services revenues discussed
above, $14 million from improved natural gas liquids margins and increased
volumes, the effect of a $9.8 energy capital credit loss accrual in 1998 and $5
million higher margins from retail gas and electric activities. The improved
margins from retail gas and electric activities reflects, in part, the effect of
general and administrative expenses included in equity losses in 1998 from
partially owned companies that are now consolidated.
Segment profit increased $5.7 million, or 55 percent, due primarily to the
effect of a 1998 retail energy credit loss accrual of $16.6 million, partially
offset by the $7.7 million decrease in net revenues and $4 million higher
selling, general and administrative expenses.
EXPLORATION & PRODUCTION'S revenues increased $28.5 million, from $28.7
million in 1998, due primarily to $8 million associated with increases in both
company-owned production volumes and marketing volumes from Williams Coal Seam
Gas Royalty Trust (Royalty Trust) and royalty interest owners, $14 million
associated with increased average natural gas sales prices and $5 million from
the April 1999 acquisition of oil and gas producing properties. Company-owned
production has increased due mainly to a drilling program initiated in the San
Juan Basin in 1998.
Segment profit increased $3.2 million, from $4.9 million in 1998, due
primarily to a $3 million favorable effect of higher average natural gas sales
prices for company-owned production, $3 million higher revenues from increased
company-owned production volumes and $6 million of gains on the sales of assets.
Partially offsetting were $4 million lower margins on natural gas marketing
activities, $4 million higher nonproducing leasehold amortization and $2 million
higher dry hole costs.
MIDSTREAM GAS & LIQUIDS' revenues increased $68.2 million, or 33 percent,
due primarily to $51 million higher natural gas liquids sales from processing
activities, $8 million higher transportation revenues associated with increased
shipments and $6 million from higher average gathering rates. The $51 million
higher natural gas liquids sales reflects $28 million from a 51 percent increase
in average natural gas liquids sales prices and $23 million from a 68 percent
increase in volumes sold.
Costs and operating expenses increased $41 million due primarily to $27
million higher liquids fuel and replacement gas purchases and higher operating
and maintenance expenses, including $2 million associated with an early
retirement incentive program.
Segment profit increased $12 million, or 21 percent, due primarily to $22
million from higher per-unit natural gas liquids margins, $8 million higher
transportation revenues and $6 million from higher average gathering rates.
Largely offsetting were higher operating and maintenance expenses, $6 million
higher general and administrative expenses, the effect of a 1998 gain of $6
million on settlement of product imbalances and $2 million of costs associated
with a cancelled pipeline construction project.
19
<PAGE> 21
PETROLEUM SERVICES' revenues increased $178.3 million, or 28 percent, due
primarily to $159 million higher refinery revenues (including $28 million higher
intra-segment sales to the convenience stores), $41 million higher convenience
store sales, $31 million higher revenues from growth in fleet management and
mobile computer technology operations and $9 million in revenues from a
petrochemical plant acquired in March 1999. Partially offsetting these increases
was a $42 million decrease in pipeline construction revenues following
substantial completion of the project. The $159 million increase in refinery
revenues reflects $99 million from a 28 percent increase in average sales
prices, $56 million from a 19 percent increase in refined product volumes sold
and $4 million of storage fee revenues. The $41 million increase in convenience
store sales reflects $25 million from higher average gasoline and diesel sales
prices, $10 million primarily from a 30 percent increase in diesel sales volumes
and $6 million higher merchandise sales. Both the average number of convenience
stores and per-store sales in third-quarter 1999 have increased as compared to
1998.
Costs and operating expenses increased $179 million, or 31 percent, due
primarily to $165 million higher refining costs, $31 million higher costs from
growth in the fleet management and mobile computer technology operations and $45
million higher convenience store cost of sales (including $28 million higher
intra-segment purchases from the refineries), partially offset by $40 million
lower pipeline construction costs. The $165 million increase in refining costs
reflects $109 million from a higher average per-unit cost of sales, $46 million
associated with increased volumes sold and $10 million higher operating costs
mainly at the Mid-South refinery. The $45 million increase in convenience store
cost of sales reflects $10 million from increased diesel volumes sold, $27
million from higher average gasoline and diesel purchase prices and an $8
million increase in merchandise cost of sales.
Segment profit increased $1.2 million, or 3 percent, due primarily to $11
million from the increase in refined product volumes sold, a $6.5 million
favorable adjustment to rate refund accruals following the third-quarter 1999
approved settlement of rate case issues, $4 million of margins from the recently
acquired petrochemical plant and $3 million of margins from growth in
terminalling activities. Substantially offsetting were $10 million higher
refinery operating costs, $11 million from lower per-unit refinery margins and
$5 million higher selling, general and administrative expenses.
COMMUNICATIONS
COMMUNICATION SOLUTIONS' revenues increased $14.1 million, or 4 percent, due
primarily to $5 million higher sales from new systems and upgrades, $5 million
higher maintenance and customer service orders and $3 million in professional
services.
Segment loss increased $9.8 million, from a $1.2 million loss in 1998 to an
$11 million loss in 1999, due primarily to $11 million of higher selling,
general and administrative expenses and a decrease in the overall gross margin
from 28.8 percent to 26.5 percent, partially offset by the effect of $6 million
of charges in 1998 for asset write-downs. Selling, general and administrative
expenses increased primarily as a result of costs necessary to improve managing
and integrating complex business operations and systems in addition to $2
million higher depreciation and amortization and a $2 million increase in the
provision for uncollectible trade receivables.
NETWORK SERVICES' revenues increased $52.7 million, from $33.5 million in
1998, due primarily to $36 million from business growth from data and switched
voice services, $9 million of revenue in 1999 from dark fiber capacity leases
accounted for as sales-type leases on the newly constructed digital fiber-optic
network and $7 million higher consulting and outsourcing revenues.
Costs and operating expenses increased $73 million, from $33 million in
1998, due primarily to $23 million higher leased capacity costs associated with
providing customer services prior to completion of the new network, $16 million
higher operations and maintenance expenses on the newly completed portions of
the network, $10 million higher depreciation expense, $8 million of construction
costs associated with the dark fiber capacity leases, $7 million higher local
access connection costs and $6 million higher costs of consulting and
outsourcing services.
Segment loss increased $37.8 million, from an $11 million loss in 1998 to a
$48.8 million loss in 1999, due primarily to a $17 million increase in selling,
general and administrative expenses primarily associated with expanding the
infrastructure in support of the network expansion, losses experienced from
providing customer services prior to completion of the new network and $10
million higher depreciation expense.
20
<PAGE> 22
STRATEGIC INVESTMENTS' revenues increased $11.7 million, or 25 percent, due
primarily to $13 million of revenues contributed by an Australian
telecommunications company acquired in August 1998 and $6 million of revenues
from a Mexican telecommunications company acquired in October 1998, partially
offset by the $7 million effect of the July 1999 sale of the audio and video
conferencing and closed circuit video broadcasting businesses.
Costs and operating expenses increased $18 million, or 39 percent, due
primarily to the Australian and Mexican acquisitions.
Other (income) expense - net in 1998 includes a $23.2 million write-down
related to the abandonment of a venture involved in the technology and
transmission of business information for news and educational purposes (see Note
4 of Notes to Consolidated Financial Statements).
Segment loss decreased $19.9 million, from a $41.8 million loss in 1998 to a
$21.9 million loss in 1999, due primarily to the effect of the $23.2 million
1998 write-down, partially offset by $4 million of losses from start-up
activities of the Australian communications operations.
OTHER
OTHER revenues increased $31.1 million, from $9.6 million in 1998, and
segment profit increased $28.4 million, from a $9.3 million segment loss in 1998
to a $19.1 million segment profit in 1999, due primarily to international
activities. International revenues increased $25 million and segment profit
increased $29 million due primarily to $7 million higher Venezuelan gas
compression revenues and $16 million higher equity investment earnings. The $7
million higher gas compression revenues reflects the effect of a high pressure
unit which became operational in September 1998. The $16 million improvement in
equity investment earnings is due primarily to $12 million from investing
activities in another Brazilian communications company.
CONSOLIDATED
GENERAL CORPORATE EXPENSES decreased $4.5 million, or 26 percent, due in
part to MAPCO merger-related costs of $2 million included in 1998 general
corporate expenses. Interest accrued increased $37.1 million, or 28 percent, due
primarily to higher borrowing levels including the commercial paper program,
Communications' short-term and long-term credit facilities and the July 1999
issuance of additional public debt. Other expense - net is $4.8 million
favorable as compared to 1998 due primarily to a 1998 litigation loss accrual
and other reserve adjustments totaling $5 million related to assets previously
sold.
The $9.1 million, or 38 percent, increase in the provision for income taxes
is primarily a result of a higher effective income tax rate, partially offset by
lower pre-tax income. The effective income tax rate in 1999 is significantly
higher than the federal statutory rate due primarily to the effects of state
income taxes and the losses of foreign entities which are not deductible for
U.S. tax purposes. The effective income tax rate in 1998 exceeds the federal
statutory rate due primarily to the effects of state income taxes.
Nine Months Ended September 30, 1999 vs. Nine Months Ended September 30, 1998
CONSOLIDATED OVERVIEW
Williams' revenues increased $563 million, or 10 percent, due primarily to
higher revenues from increased petroleum products and natural gas liquids sales
volumes and average sales prices, increased revenues from retail natural gas and
electric activities following a late 1998 acquisition, Communications' dark
fiber capacity lease revenues and new business growth, fleet management and
mobile computer technology operations and reductions to rate refund liabilities
at Gas Pipeline. Partially offsetting these increases were the effects in 1999
of reporting certain revenues net of costs within Energy Services (see Note 2)
and lower electric power services and pipeline construction revenues.
Segment costs and expenses increased $609 million, or 12 percent, due
primarily to higher costs related to increased petroleum products and natural
gas liquids volumes purchased and average purchase prices, higher retail natural
gas and electric costs following a late 1998 acquisition, higher costs and
expenses from Communications including $26.7 million of 1999 asset impairment
charges and exit costs, increased fleet management and mobile computer
technology operations and higher selling, general and administrative expenses.
In addition, 1999 includes $10.5 million of expense associated with a
Williams-wide incentive program. Partially offsetting these increases were the
effects in 1999 of reporting certain costs net in revenues within Energy
Services (see Note 2) and lower electric power services and pipeline
construction costs. In addition, 1998 included $74 million of MAPCO
merger-related costs (including $28 million within general corporate expenses)
(see Note 5), $29 million of asset write-downs at Communications and $26 million
of credit loss accruals at Energy Services.
Operating income decreased $16 million, or 3 percent, due primarily to a
$122 million decrease at
21
<PAGE> 23
Communications and a $9 million decrease from International activities (included
in Other segment loss), largely offset by the effect in 1998 of MAPCO
merger-related costs totaling $74 million, a $16 million improvement at Energy
Services and $15 million from Gas Pipeline. The additional losses at
Communications reflect higher selling, general and administrative expenses,
including costs associated with infrastructure growth and improvement, and $29
million of losses from start-up activities of Australian and Brazilian
communications operations. Energy Services' improvement reflects improved
natural gas and natural gas liquids trading margins, the effect in 1998 of $26
million of credit loss accruals, and the combined effect of a $15.5 million
accrual for potential refunds in 1998 and a $6.5 million reduction of that
accrual in 1999, partially offset by higher selling, general and administrative
expenses and lower refinery margins. The Gas Pipeline increase reflects the
effect of 1998 and 1999 adjustments associated with regulatory and rate issues.
Income before income taxes, extraordinary loss and change in accounting
principle decreased $67 million, or 24 percent, due primarily to $62 million
higher net interest expense reflecting increased debt in support of continued
expansion and new projects and $16 million lower operating income, slightly
offset by the effect of 1998 litigation loss accruals and other reserve
adjustments totaling $11 million.
GAS PIPELINE
GAS PIPELINE'S revenues increased $60 million, or 5 percent, due primarily
to a total of $46 million of reductions to rate refund liabilities, resulting
primarily from second-quarter 1999 regulatory proceedings involving
rate-of-return methodology for three of the gas pipelines. Revenues also
increased due to $48 million higher historical gas exchange imbalance
settlements (offset in costs and operating expenses) and $15 million from
expansion projects and new services. These increases were partially offset by
$12 million lower reimbursable costs passed through to customers (offset in
costs and operating expenses), $22 million lower transportation and other
revenues (primarily from transportation rate discounting, rate design and
decreased interruptible transportation volumes) and $13 million of favorable
1998 adjustments from the settlement of rate case issues.
Segment costs and expenses increased $45 million, or 6 percent, due
primarily to the higher gas exchange imbalance settlements net of reimbursable
costs which are passed through to customers, $9 million higher general and
administrative expenses, $7 million higher depreciation and amortization and a
$3.4 million gain in 1998 from the sale-in-place of natural gas from a
decommissioned storage field, partially offset by $10 million lower
transportation expenses. General and administrative expenses increased primarily
from information systems initiatives, higher labor and benefits costs, a $2.3
million accrual for damages associated with two pipeline ruptures in the
northwest and the $2 million write-off of previously capitalized software
development costs.
Segment profit increased $15 million, or 3 percent, due primarily to the $33
million net effect of the regulatory and rate issues discussed above, $15
million of revenues from expansion projects and new services and $10 million in
lower transportation expenses. These segment profit increases were partially
offset by $22 million lower transportation and other revenues, $9 million higher
general and administrative expenses, $7 million higher depreciation and
amortization and a $3.4 million gain in 1998 from the sale-in-place of natural
gas from a decommissioned storage field.
Based on current rate structures and/or historical maintenance schedules of
certain of its pipelines, Gas Pipeline experiences lower segment profits in the
second and third quarters as compared to the first and fourth quarters.
ENERGY SERVICES
ENERGY MARKETING & TRADING'S operations results can be significantly
impacted by energy commodity price volatility. In addition, trading sales
revenues are reported net of the related purchase costs while non-trading
activities are reported gross. As a result, net revenues (revenues less cost of
sales) is used to analyze Energy Marketing & Trading's operating results as
shown below:
<TABLE>
<CAPTION>
1999 1998
--------- ---------
<S> <C> <C>
Revenues $1,607.2 $1,455.7
Cost of sales 1,344.9 1,245.8
--------- ---------
Net Revenues $ 262.3 $ 209.9
========= =========
</TABLE>
Revenues increased $151.5 million, or 10 percent, due primarily to a $140
million increase of retail gas and electric revenues resulting from the late
1998 acquisition of Volunteer Energy. In addition, revenues increased due to $85
million higher crude and refined products revenues and $48 million higher
natural gas services revenues. Partially offsetting were lower natural gas
liquids revenues of $69 million resulting primarily from the $84 million effect
in the first quarter of 1999 of reporting revenues on a net basis for certain
operations previously reported on a "gross" basis (see Note 2)
22
<PAGE> 24
and $53 million lower electric power services revenues. Crude and refined
product revenues increased due to higher average sales prices and increased
sales volumes associated primarily with crude sales to the Memphis refinery. The
higher natural gas services revenues includes $36 million of favorable contract
settlements during third-quarter 1999 and the effects of more favorable market
and supply conditions, partially offset by the effect of a $9.5 million
favorable long-term natural gas transportation contract settlement in 1998. The
lower electric power services revenues reflects the effect of recording revenue
in accordance with EITF 98-10 "Accounting for Contracts Involved in Energy
Trading and Risk Management Activities" which was adopted first-quarter 1999 and
lower demand for electricity in southern California in 1999 compared to 1998 due
to cooler summer temperatures in 1999.
Costs of sales increased $99.1 million, or 8 percent, due primarily to
higher costs for retail gas and electric operations and crude and refined
products of $129 million and $83 million, respectively, partially offset by $101
million lower natural gas liquids costs and $13 million lower costs for electric
power services. These variances are associated with the corresponding changes in
revenues discussed above.
Net revenues increased $52.4 million, or 25 percent, due primarily to $48
million higher natural gas services revenues discussed above, $32 million higher
natural gas liquids margins and $11 million higher margins from retail gas and
electric activities. The natural gas liquids margins increase reflects improved
per-unit margins on all natural gas liquids products and $11 million associated
with the acquisition of a petrochemical plant in early 1999. The improved
margins from retail gas and electric activities reflects, in part, the effect of
general and administrative expenses included in equity losses in 1998 from
partially owned companies that are now consolidated. Partially offsetting these
increases were $40 million lower electric power services margins resulting from
cooler summer temperatures in southern California in 1999 and the adoption of
EITF 98-10 discussed above.
Segment profit increased $44.1 million, from $28.1 million in 1998, due
primarily to the $52.4 million increase in net revenues, the effect of a $16.6
million retail energy credit loss accrual in 1998 and a $6.5 million gain on the
sale of certain retail gas and electric assets in 1999, partially offset by $31
million higher selling, general and administrative expenses and $4 million
higher retail propane operating expenses. The increase in selling, general and
administrative expenses reflects higher compensation levels associated with
improved operating performance, growth in electric power services operations,
the Volunteer Energy acquisition and increased activities in human resources
development, investor/media/customer relations and business development.
In October 1999, the ongoing business of Volunteer Energy was sold to a
third party resulting in an estimated pre-tax gain of $10 million to $15
million. Volunteer Energy revenues and costs and expenses, which are included
within Energy, Marketing & Trading, were $131.6 million and $135.4 million,
respectively, for the nine months ended September 30, 1999.
On November 8, 1999, Williams announced it had reached an agreement to sell
the retail propane business for $432.5 million. The transaction is subject to
certain conditions and is expected to close before the end of 1999. Retail
propane revenues and costs and expenses, which are included within Energy
Marketing & Trading, were $178.3 million and $167.8 million, respectively, for
the nine months ended September 30, 1999 (see Note 18).
EXPLORATION & PRODUCTION'S revenues increased $20.9 million, or 20 percent,
due primarily to $18 million associated with increases in both company-owned
production volumes and marketing volumes from the Royalty Trust and royalty
interest owners, $10 million from the April 1999 acquisition of oil and gas
producing properties and $2 million associated with increased average natural
gas sales prices, partially offset by a $10 million decrease in the recognition
of income previously deferred from a 1997 transaction that transferred certain
nonoperating economic benefits to a third party. Company-owned production has
increased due mainly to a drilling program initiated in the San Juan basin in
1998.
Segment profit decreased $5.4 million, or 21 percent, due primarily to $10
million decreased recognition of deferred income, $7 million higher operating
and maintenance expenses, a $4 million unfavorable effect of lower average
natural gas sales prices for company-owned production and $4 million higher
nonproducing leasehold amortization. Partially offsetting were $10 million
higher revenue from increased company-owned production volumes, $6 million of
gains on the sales of assets and a $5 million favorable effect of the April 1999
acquisition.
MIDSTREAM GAS & LIQUIDS' revenues increased $81.3 million, or 13 percent,
due primarily to $56 million higher natural gas liquids sales from processing
activities and favorable adjustments in 1998 of $12 million related to rates
placed into effect in 1997 for Midstream's regulated gathering activities
(offset in costs and operating expenses). In
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addition, revenues increased due to $8 million higher natural gas liquids
storage revenues following the acquisition of a Kansas storage facility during
the second quarter of 1999, $7 million higher transportation revenues associated
with increased shipments, $6 million from higher average gathering rates and a
$3 million favorable rate adjustment in 1999. The $56 million higher natural gas
liquids sales reflects $38 million from a 36 percent increase in volumes sold
and $18 million from a 13 percent increase in average natural gas liquids sales
prices. Partially offsetting these increases were $12 million lower equity
earnings including a $4 million reclassification on the Discovery pipeline
project related to a prior year (offset in capitalized interest) and $9 million
lower condensate revenues related to a shift in the revenue mix from sales of
condensate for customers to providing gathering and transportation services
under fee-based contracts.
Costs and operating expenses increased $62 million due primarily to $30
million higher liquids fuel and replacement gas purchases, the 1998 rate
adjustments related to Midstream's regulated gathering activities and higher
operating and maintenance expenses.
Segment profit decreased $8.9 million, or 5 percent, due primarily to higher
operating and maintenance expenses, $12 million lower equity earnings, $12
million higher general and administrative expenses, $7 million of costs
associated with cancelled pipeline construction projects and the effect of a
1998 gain of $6 million on settlement of product imbalances. Largely offsetting
were $13 million from higher per-unit natural gas liquids margins, higher
gathering, storage and transportation revenues of $8 million, $8 million and $7
million, respectively, and $6 million from the increase in natural gas liquids
volumes sold.
PETROLEUM SERVICES' revenues increased $197.5 million, or 11 percent, due
primarily to $92 million higher convenience store sales, $124 million higher
refinery revenues (including $41 million higher intra-segment sales to the
convenience stores), $68 million higher revenues from growth in fleet management
and mobile computer technology operations and $17 million in revenues from a
petrochemical plant acquired in March 1999. Partially offsetting these increases
was a $58 million decrease in pipeline construction revenues following
substantial completion of the project. The $92 million increase in convenience
store sales reflects $56 million from a 16 percent increase in gasoline and
diesel sales volumes, $26 million higher merchandise sales and $10 million from
slightly higher average gasoline and diesel sales prices. Both the average
number of convenience stores and per-store sales in 1999 have increased as
compared to 1998. The $124 million increase in refinery revenues reflects $75
million from an 8 percent increase in refined product volumes sold, $45 million
from a 5 percent increase in average sales prices and $4 million of storage fee
revenues.
Costs and operating expenses increased $219 million, or 13 percent, due
primarily to $149 million higher refining costs, $66 million higher costs from
growth in the fleet management and mobile computer technology operations, $87
million higher convenience store cost of sales (including $41 million higher
intra-segment purchases from the refineries) and $16 million higher convenience
store operating costs, partially offset by $56 million lower pipeline
construction costs. The $149 million increase in refining costs reflects $70
million from a higher average per-unit cost of sales, $61 million associated
with increased volumes sold and $18 million higher operating costs at the
refineries. The $87 million increase in convenience store cost of sales reflects
$22 million higher merchandise cost of sales, $50 million from a 16 percent
increase in gasoline and diesel sales volumes and $15 million from increased
average gasoline and diesel purchase prices.
Selling, general and administrative expenses increased $22 million due, in
part, to increased activities in human resources development,
investor/media/customer relations and business development.
Segment profit decreased $14.3 million, or 12 percent, due primarily to $25
million lower per-unit refinery margins, $22 million higher selling, general and
administrative expenses, $18 million higher operating costs at the refineries
and $5 million lower ethanol profits. Largely offsetting were $14 million from
increased refined product volumes sold, the effect of a $15.5 million accrual in
1998 for potential refunds to transportation customers, a $6.5 million favorable
adjustment in 1999 to that 1998 rate refund accrual following the third-quarter
1999 approved settlement of rate case issues, $9 million of margins from the
recently acquired petrochemical plant, $7 million from increased terminalling
activities, $4 million higher margins on convenience store merchandise sales and
the recovery of $4 million of environmental expenses previously incurred.
COMMUNICATIONS
COMMUNICATION SOLUTIONS' revenues increased $35.1 million, or 3 percent, due
primarily to $29 million higher sales from new systems and upgrades, $8 million
of professional services revenues following an October 1998 acquisition and $10
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million higher other revenue including $6 million in 1999 associated with the
sale of rights to future cash flows from equipment lease renewals, partially
offset by $13 million lower maintenance and customer service orders resulting,
in part, from competitive pressures.
Segment profit decreased $40.9 million, from a $13.1 million profit in 1998
to a $27.8 million loss in 1999, due primarily to $47 million of higher selling,
general and administrative expenses, partially offset by the effect of $6
million of charges in 1998 for asset write-downs and $4 million realized on the
sale of rights to future cash flows from equipment lease renewals. Selling,
general and administrative expenses increased primarily as a result of costs
necessary to improve managing and integrating complex business operations and
systems including $13 million higher information technology costs and $3 million
of process-related consulting fees. Also contributing to the selling, general
and administrative expense increase are a $12 million increase in the provision
for uncollectible trade receivables, $6 million higher depreciation and
amortization, $3 million of expense associated with a Williams-wide incentive
program and $2 million of severance costs.
NETWORK SERVICES' revenues increased $198.1 million, from $85.5 million in
1998, due primarily to $104 million from business growth from data and switched
voice services, $81 million of revenue in 1999 from dark fiber capacity leases
accounted for as sales-type leases on the newly constructed digital fiber-optic
network and $13 million higher consulting and outsourcing revenues.
Costs and operating expenses increased $220 million, from $78 million in
1998, due primarily to $70 million higher leased capacity costs associated with
providing customer services prior to completion of the new network, $57 million
of construction costs associated with the dark fiber capacity leases, $32
million higher operations and maintenance expenses on the newly completed
portions of the network, $18 million higher depreciation expense, $15 million
higher local access connection costs and $12 million higher costs of consulting
and outsourcing services.
Segment loss increased $60.9 million, from a $25.4 million loss in 1998 to
an $86.3 million loss in 1999, due primarily to a $39 million increase in
selling, general and administrative expenses primarily associated with expanding
the infrastructure in support of the network expansion, losses experienced from
providing customer services prior to completion of the new network and $18
million higher depreciation expense.
STRATEGIC INVESTMENTS' revenues increased $32.4 million, or 22 percent, due
primarily to $33 million of revenues contributed by an Australian
telecommunications company acquired in August 1998 and $14 million of revenues
from a Mexican telecommunications company acquired in October 1998, partially
offset by equity investment losses of $14 million from ATL-Algar Telecom Leste
S.A., a Brazilian telecommunications business in initial operations.
Costs and operating expenses increased $37 million, or 26 percent, and
selling, general and administrative expenses increased $12 million, or 21
percent, due primarily to the Australian and Mexican acquisitions.
Other (income) expense - net in 1999 includes $26.7 million of asset
impairment charges and exit costs relating to management's decision and
commitment to sell the audio and video conferencing and closed-circuit video
broadcasting businesses (see Note 4). Other (income) expense - net in 1998
includes a $23.2 million write-down related to the abandonment of a venture
involved in the technology and transmission of business information for news and
educational purposes (see Note 4).
Segment loss increased $20.1 million, from a $75.1 million loss in 1998 to a
$95.2 million loss in 1999, due primarily to the $26.7 million of asset
impairment charges and exit costs in 1999 and $29 million of losses from the
start-up activities of the Australian and Brazilian communications operations,
partially offset by the $23.2 million asset write-down in 1998 and an $8 million
effect of businesses that were generating losses that have been sold or
otherwise exited.
OTHER
OTHER revenues increased $37.6 million, from $33.1 million in 1998, due
primarily to $20 million higher Venezuelan gas compression revenues and $19
million of rental income from one of the gas pipelines for office space,
partially offset by $5 million higher equity investment losses. The $20 million
higher gas compression revenues reflects the effect of a high pressure unit
which became operational in September 1998, partially offset by the effect of
operational problems experienced in early 1999.
Segment loss decreased $9.4 million, or 76 percent, due primarily to a $10
million improvement at the Venezuelan gas compression plant and the effect of
$5.6 million of international investment fund write-downs in 1998, partially
offset by $5 million higher equity investment losses and $3 million higher
general and administrative expenses.
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CONSOLIDATED
GENERAL CORPORATE EXPENSES decreased $29.9 million, or 39 percent, due
primarily to MAPCO merger-related costs of $28 million included in 1998 general
corporate expenses. An additional $46 million of merger-related costs are
included in 1998 as a component of Energy Services' segment profit (see Note 5).
Interest accrued increased $70.5 million, or 19 percent, due primarily to the
$91 million effect of higher borrowing levels including the commercial paper
program, Communications' short-term and long-term credit facilities and the July
1999 issuance of additional public debt, slightly offset by a $10.6 million
favorable adjustment related to the reduction of certain rate refund liabilities
in second-quarter 1999 (see Note 3) and lower average interest rates. Interest
capitalized increased $8.9 million, or 31 percent, due primarily to increased
capital expenditures for the fiber-optic network and pipeline construction
projects and adjustments totaling $7 million related to Williams' equity
investments in pipelines under construction, partially offset by lower capital
expenditures for international investments. Other expense - net is $12.2 million
favorable as compared to 1998 due primarily to 1998 litigation loss accruals and
other reserve adjustments totaling $11 million related to assets previously
sold.
The $10 million, or 9 percent, increase in the provision for income taxes is
primarily a result of a higher effective income tax rate, substantially offset
by lower pre-tax income. The effective income tax rate in 1999 is significantly
higher than the federal statutory rate due primarily to the effects of state
income taxes, losses of foreign entities not deductible for U.S. tax purposes,
and the impact of goodwill not deductible for tax purposes related to assets
impaired during the second quarter of 1999 (see Note 4). The effective income
tax rate in 1998 exceeds the federal statutory rate due primarily to the effects
of state income taxes.
The $4.8 million 1998 extraordinary loss results from the early
extinguishment of debt (see Note 7).
The $5.6 million 1999 change in accounting principle relates to the adoption
of Statement of Position 98-5, "Reporting on the Costs of Start-Up Activities"
(see Note 8).
FINANCIAL CONDITION AND LIQUIDITY
Liquidity
Williams considers its liquidity to come from two sources: internal
liquidity, consisting of available cash investments, and external liquidity,
consisting of borrowing capacity from available bank-credit facilities and the
commercial paper program, which can be utilized without limitation under
existing loan covenants. At September 30, 1999, Williams had access to $1.01
billion of liquidity including $600 million available under its $1 billion
bank-credit facility, $328 million of commercial paper availability, and
cash-equivalent investments. This compares with liquidity of $738 million at
December 31, 1998, and $717 million at September 30, 1998. In addition,
Communications had access to an additional $583 million at September 30, 1999,
including $550 million under a new $1.05 billion bank-credit facility and
cash-equivalent investments. Communications' liquidity has not been included in
the Williams' liquidity amount discussed above due to restrictions on funds
transfers and dividend payments to Williams.
Registration statements have been filed with the Securities and Exchange
Commission by Williams and Northwest Pipeline, Texas Gas Transmission and
Transcontinental Gas Pipeline (each a wholly owned subsidiary of Williams).
Approximately $755 million of shelf availability remains under these outstanding
registration statements and may be used to issue a variety of debt or equity
securities. Williams believes additional financing arrangements can be obtained
on reasonable terms if required.
In September 1999, Williams Communications Group, Inc.'s (WCG) $1.4 billion
interim short-term bank-credit facility expired. Borrowings under this agreement
were repaid with borrowings under a new $750 million temporary short-term credit
facility and a new $1.05 billion long-term credit agreement (both entered into
in September 1999) (see Note 11). Amounts available under the short-term and
long-term agreements at September 30, 1999, were $125 million and $550 million,
respectively.
In October 1999, WCG completed an initial public equity offering which
yielded net proceeds of approximately $738 million (see Note 16). Additional
shares of common stock were privately sold in concurrent investments by SBC
Communications Inc., Intel Corporation, and Telefonos de Mexico for proceeds of
$738.5 million. Concurrent with these equity transactions, WCG issued high-yield
public debt of approximately $2 billion in October 1999 (see Note 11). Proceeds
from these equity and debt transactions were used to repay the borrowings under
the $750 million short-term facility and the $1.05 billion long-term credit
agreement and will also be used to fund Communications' operating losses and
working capital and for continued construction of Communications' national
fiber-optic network and other expansion opportunities.
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During 1998, Communications entered into an operating lease agreement
covering a portion of its fiber-optic network designed to fund up to $750
million of capital expenditures for the fiber-optic network. As of September 30,
1999 $547 million of costs have been incurred and the remaining capacity under
the program is $203 million.
During fourth-quarter 1999 and the year 2000, Williams' capital expenditures
and investments are estimated to total approximately $2 billion and $6
billion, respectively. Williams expects to finance capital expenditures,
investments and working-capital requirements through (1) cash generated from
operations, (2) Communications' initial equity and high-yield debt offerings,
(3) the use of the available portion of the $1 billion bank-credit facility,
Communications' $1.05 billion long-term credit facility and the fiber-optic
lease program, (4) commercial paper, (5) short-term uncommitted bank lines, (6)
private borrowings and (7) debt or equity public offerings.
Financing Activities
In January 1999, the commercial paper program increased to $1.4 billion from
$1 billion. The commercial paper program is backed by a $1.4 billion short-term
bank-credit facility. At September 30, 1999, $1.1 billion of commercial paper
was outstanding under the program. In January 1999, Williams entered into a $200
million adjustable rate term loan due 2004, and in July 1999, Williams issued
$700 million of 7.625 percent notes due 2019. During third-quarter 1999, $625
million of borrowings were made under the Communications' $750 million interim
short-term credit facility and $500 million of borrowings were made under
Communications' $1.05 billion long-term credit agreement. Proceeds were used for
general corporate purposes, including the repayment of outstanding debt.
In November 1999, Williams Gas Pipelines Central issued $175 million of
7.375 percent notes due 2006. Proceeds were used for general corporate purposes,
including the repayment of outstanding debt.
The consolidated long-term debt to debt-plus-equity ratio was 64.8 percent
at September 30, 1999, compared to 59.9 percent at December 31, 1998. If
short-term notes payable and long-term debt due within one year are included in
the calculations, these ratios would be 69.4 percent at September 30, 1999 and
64.7 percent at December 31, 1998.
Investing Activities
During first-quarter 1999, Williams exercised an option to increase its
investment in ATL, a Brazilian telecommunications business, by an additional 35
percent equity interest for $265 million. This investment was funded through
borrowings under the $1 billion bank-credit facility. Also in first-quarter
1999, Williams purchased a company with a petrochemical plant and natural gas
liquids transportation, storage and other facilities for $163 million in cash.
Operating Activities
The increase in receivables and accounts payable reflects increased electric
power services activity at Energy Marketing & Trading. The change in accounts
payable also reflects an $84 million payment pursuant to a wireless fiber
capacity agreement. The change in inventories represents increases in the
refined product and crude oil inventories at Energy Marketing & Trading. The
decrease in accrued rate refund liabilities reflects the payment in 1999 of $149
million of rate refunds to natural gas customers and the second-quarter 1999
reductions to rate refund liabilities (see Note 3). The increase in accrued
liabilities is due primarily to increases in accrued payroll, income taxes
payable and Communications' deferred revenue, substantially offset by the
payment in first-quarter 1999 of $100 million in connection with the assignment
of Williams' obligations under a gas purchase contract to an unaffiliated third
party (see Note 12). In addition, during 1999 Williams has received federal
income tax refunds totaling $380 million (see Note 6).
OTHER
Other Commitments
Energy Marketing & Trading entered into certain contracts during 1998 and
1999 giving Williams the right to receive fuel conversion and certain other
services for purposes of generating electricity. At September 30, 1999, annual
estimated committed payments under these contracts range from $62.7 million to
$344.8 million, resulting in total committed payments over the next 22 years of
approximately $6.5 billion.
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Environmental
Transcontinental Gas Pipe Line (Transco) received a letter stating that the
U.S. Department of Justice (DOJ), at the request of the U.S. Environmental
Protection Agency, intends to file a civil action against Transco arising from
its waste management practices at Transco's compressor stations and metering
stations in eleven states from Texas to New Jersey. DOJ stated in the letter
that its complaint will seek civil penalties and injunctive relief under federal
environmental laws. DOJ and Transco are discussing a settlement. While no
specific amount was proposed, DOJ stated that any settlement must include an
appropriate civil penalty for the alleged violations. Transco cannot reasonably
estimate the amount of its potential liability, if any, at this time. However,
Transco believes it has substantially addressed environmental concerns on its
system through ongoing voluntary remediation and management programs.
Year 2000 Compliance
Williams initiated an enterprise-wide project in 1997 to address the year
2000 compliance issue for both traditional information technology areas and
non-traditional areas, including embedded technology which is prevalent
throughout the company. This project focuses on all technology hardware and
software, external interfaces with customers and suppliers, operations process
control, automation and instrumentation systems, and facility items. The phases
of the project are awareness, inventory and assessment, renovation and
replacement, testing and validation and contingency planning. The awareness and
inventory/assessment phases of this project as they relate to both traditional
and non-traditional information technology areas have been completed. During the
inventory and assessment phase, all systems with possible year 2000 implications
were inventoried and classified into five categories: 1) highest, business
critical, 2) high, compliance necessary within a short period of time following
January 1, 2000, 3) medium, compliance necessary within 30 days from January 1,
2000, 4) low, compliance desirable but not required, and 5) unnecessary.
Categories 1 through 3 were designated as critical and are the major focus of
this project. Some non-critical systems may not be compliant by January 1, 2000.
Renovation/replacement and testing/validation of critical systems has been
substantially completed, except for replacement of certain critical systems
scheduled for completion later in 1999. These systems include an accounting
system at Exploration & Production, gas flow control systems at Midstream Gas &
Liquids and a couple of plant or station control systems at Midstream Gas &
Liquids. Testing and validation activities will continue throughout the process
as replacement systems come online and as remediation of systems pursuant to an
implemented contingency plan are completed. As of September 30, 1999, virtually
all traditional information technology and non-traditional areas have been fully
tested or otherwise validated as compliant.
Williams initiated a formal communications process with other companies in
1998 to determine the extent to which those companies are addressing year 2000
compliance. In connection with this process, Williams has sent approximately
18,200 letters and questionnaires to third parties including customers, vendors
and service providers. Williams is evaluating responses as they are received or
otherwise investigating the status of these companies' year 2000 compliance
efforts. Because only approximately 44 percent of the companies contacted have
responded to this inquiry (all of these have indicated that they are already
compliant or will be compliant on a timely basis), Williams has also been
working directly with key business partners to reduce the risk of a break in
service or supply and with non-compliant companies to mitigate any material
adverse effect on Williams.
Williams has utilized both internal resources and external contractors to
complete the year 2000 compliance project. Williams has a core group of 318
people involved in this enterprise-wide project. This includes 28 individuals
responsible for coordinating, organizing, managing, communicating, and
monitoring the project and another 290 staff members responsible for completing
the project. Depending on which phase the project is in and what area is being
focused on at any given point in time, there can be an additional 500 to 1,200
employees who have also contributed a portion of their time to the completion of
this project. The Communications business unit has contracted with an external
contractor at a cost of approximately $3.5 million to assist in all phases and
various areas of the project. Gas Pipeline has contracted with an external
contractor for a cost of up to $6 million for the remediation of the customer
service software. Within Energy Services, two external contractors are being
utilized at a total cost of approximately $3 million.
Several previously planned system implementations have been or are scheduled
for completion during 1999, which will lessen possible year 2000 impacts. For
example, a new year 2000 compliant payroll/human resources system was
implemented January 1, 1999. It replaced multiple human resources administration
and payroll
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processing systems previously in place. The Communications business unit
completed implementation of a major service information management system in
mid-1999 which integrates the operations of its many components acquired in past
acquisitions. This system addresses the year 2000 compliance issues in certain
areas. Within the Energy Services business unit, major applications had been
replaced or were being replaced by MAPCO prior to its acquisition by Williams in
early 1998. Those applications were incorporated into the enterprise-wide
project. In addition, the Petroleum Services business unit of Energy Services is
replacing its current ATLAS and revenue billing systems. The new ATLAS system
will be used to manage refined product pipeline transportation, manage customer
product inventories, authorize supplier and customer terminal loading and track
loading balances. The new revenue billing system will interface with ATLAS to
appropriately bill customers and account for the transactions. Current plans are
to implement these new systems late in 1999. The Midstream Gas & Liquids
business unit of Energy Services plans to implement a new Gas Management and
Gathering & Processing Accounting System (GasKit). Gas Pipeline completed
implementation of a new telephone system in 1998, and a new common financial
system was implemented July 1, 1999 at one of the pipelines.
Although all critical systems over which Williams has control are planned to
be compliant and tested before the year 2000, Williams has identified two areas
that would equate to a most reasonably likely worst case scenario. First is the
possibility of service interruptions due to non-compliance by third parties. For
example, power failures along the communications network or transportation
systems could cause service interruptions. This risk should be minimized by the
enterprise-wide communications effort with and evaluation of third-party
compliance plans and by the development of contingency plans. Another area of
risk for non-compliance is the delay of system replacements scheduled for
completion during 1999. The status of these systems is being closely monitored
to reduce the chance of delays in completion dates. In situations where planned
system implementations will not be in service timely or have been delayed past
an implementation date of September 1, 1999, alternative steps are being taken
to make existing systems compliant or to develop manual back-up plans. It is not
possible to quantify the possible financial impact if this most reasonably
likely worst case scenario were to come to fruition.
Significant focus on the contingency plan phase of the project has been
taking place in 1999. Guidelines for the contingency planning process were
issued in January 1999. Contingency plans have been developed for critical
business processes, critical business partners, suppliers and system
replacements that experience significant delays. The following is a discussion
of contingency plans by business unit.
Gas Pipeline's contingency plans include manning operational stations
twenty-four hours a day, putting extra security measures into place and stocking
up on supplies. In addition, most of Gas Pipeline's compressor stations are
capable of independently generating electricity in the event of a loss of
electricity, and operation of the pipelines can be done manually in case there
is a loss of telecommunications capability.
Energy Services' contingency plans include accelerating into 1999 some
processes that would normally be done in early January 2000, manual back-up
systems in case of automated system failures, use of prior nominations if
communications are down, and increased staffing levels including twenty-four
hour manning of critical locations. Back-up power sources are in place for
operation of critical locations and strategically located convenience stores in
the event of loss of electrical power with the exception of the refinery
operations. Back-up generators were not deemed practical for operation of the
refineries; therefore, Williams has worked closely with local utilities in those
areas to ensure that the plans of those utilities are adequate. In the event of
failure of any of the external bulletin boards, which are relied upon by Energy
Marketing & Trading for nominating gas on pipelines, nominations will be faxed
directly to the pipelines. Because of the delays in the implementation date of
the new ATLAS and revenue billing systems at Petroleum Services, the contingency
plan for those systems has been implemented. That plan includes the modification
and testing of the existing ATLAS and revenue billing systems to ensure that
compliant systems are in place in case the new systems' implementation date is
delayed past December 31, 1999. Modifications to these systems have been
completed; the revenue billing system has been tested and validated as
compliant; and testing and validation of the ATLAS system is targeted for
completion by November 30, 1999. Due to the delay in the implementation of the
GasKit system at Midstream Gas & Liquids from June 1999 to first-quarter 2000,
the current system is currently being modified and is targeted to be year 2000
compliant by November 15, 1999.
Communications engaged an outside consultant to assist in identifying
potential impacts to its business areas and processes. That information was used
to enhance the development of contingency plans. Communications' normal
contingency plans include back-up battery or generator systems along the
fiber-optic network and manning of critical operational areas, field locations
and control centers twenty-four hours a day, seven days a week. At the end of
1999 and into 2000, these locations will be manned with extra staff, a
heightened on-call status will be in effect for other areas, information
technology staff will be on-site to monitor system performance and teams will be
organized to address any critical issues that may arise.
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Contingency plans for the corporate headquarters' data centers include
onsite or on-call personnel to monitor systems and resolve problems, backup
generators in the event of loss of electric power, and backup chiller
systems/trailer mounted chillers in case of the loss of chiller capability from
the third-party supplier.
Costs incurred for new software and hardware purchases are being capitalized
and other costs are being expensed as incurred. Williams currently estimates the
total cost of the enterprise-wide project, including any accelerated system
replacements, to be approximately $47 million. This $47 million has been or is
expected to be spent as follows:
o Prior to 1998 and during the first quarter of 1998, Williams was conducting
the project awareness and inventory/assessment phases of the project and
incurred costs totaling $3 million.
o During the second quarter of 1998, $2 million was spent on the
renovation/replacement and testing/validation phases and completion of the
inventory/assessment phase.
o The third and fourth quarters of 1998 focused on the renovation/replacement
and testing/validation phases, and $10 million was incurred.
o During the first quarter of 1999, renovation/replacement and
testing/validation continued, contingency planning began and $9 million was
incurred.
o During the second quarter of 1999, the primary focus shifted to
testing/validation and contingency planning, and $10 million was spent.
o The primary focus during third-quarter 1999 was contingency planning and
final testing and $8 million was incurred.
o The fourth quarter of 1999 will continue to focus mainly on contingency
planning and final testing with $4 million expected to be spent.
o Approximately $1 million is estimated to be spent during the first two
quarters of 2000 for monitoring and problem resolution.
Of the $42 million incurred to date, approximately $38 million has been
expensed and approximately $4 million has been capitalized. The $5 million of
future costs necessary to complete the project within the schedule described are
expected to be expensed. This estimate does not include Williams' potential
share of year 2000 costs that may be incurred by partnerships and joint ventures
in which the company participates but is not the operator. The costs of
previously planned system replacements are not considered to be year 2000 costs
and are, therefore, excluded from the amounts discussed above.
The preceding discussion contains forward-looking statements including,
without limitation, statements relating to the company's plans, strategies,
objectives, expectations, intentions, and adequate resources, that are made
pursuant to the "safe harbor" provisions of the Private Securities Litigation
Reform Act of 1995. Readers are cautioned that such forward-looking statements
contained in the year 2000 update are based on certain assumptions which may
vary from actual results. Specifically, the dates on which the company believes
the year 2000 project will be completed and computer systems will be implemented
are based on management's best estimates, which were derived utilizing numerous
assumptions of future events, including the continued availability of certain
resources, third-party modification plans and other factors. However, there can
be no guarantee that these estimates will be achieved, or that there will not be
a delay in, or increased costs associated with, the implementation of the year
2000 project. Other specific factors that might cause differences between the
estimates and actual results include, but are not limited to, the availability
and cost of personnel trained in these areas, the ability to locate and correct
all relevant computer code, timely responses to and corrections by third parties
and suppliers, the ability to implement interfaces between the new systems and
the systems not being replaced, and similar uncertainties. Due to the general
uncertainty inherent in the year 2000 problem, resulting in large part from the
uncertainty of the year 2000 readiness of third parties, the company cannot
ensure its ability to timely and cost effectively resolve problems associated
with the year 2000 issue that may affect its operations and business, or expose
it to third-party liability.
30
<PAGE> 32
ITEM 3
Quantitative and Qualitative Disclosures About Market Risk
During the first quarter of 1999, Williams issued $200 million in adjustable
rate debt due in 2004 at an initial rate of approximately 5.3 percent.
During second quarter of 1999, Williams issued $700 million in 7.625 percent
fixed rate notes due 2019.
Subsequent to September 30, 1999, Williams' communications business,
Williams Communications Group, Inc. issued $2 billion in notes consisting of
$500 million in 10.7 percent notes due 2007 and $1.5 billion in 10.875 percent
notes due 2009.
Also subsequent to September 30, 1999, Williams Gas Pipelines Central issued
$175 million in 7.375 percent fixed rate notes due 2006.
At September 30, 1999, Williams has preferred stock interests in certain
Brazilian ventures totaling $370 million. Estimating cash flows from these
investments is not practical given that the cash flows from or liquidation of
these investments are uncertain. The Brazilian economy has experienced
significant volatility in 1999 resulting in an approximate 37 percent reduction
in the Brazilian Real against the U.S. dollar. However, Williams believes the
fair value of these investments approximates the carrying value. An additional
20 percent reduction in the value of the Brazilian Real against the U.S. dollar
could result in up to a $74 million reduction in the fair value of these
investments. This analysis assumes a direct correlation in the fluctuation of
the Brazilian Real against the value of our investments. The ultimate duration
and severity of the conditions in Brazil remains uncertain, as does the
long-term impact on our interests in the ventures. Williams does not presently
utilize derivative or other financial instruments to hedge the risk associated
with the movement in foreign currencies. However, Williams continues to monitor
currency fluctuations in this region and will consider the use of derivative
financial instruments or employment of other investment alternatives if cash
flows or investment returns so warrant.
31
<PAGE> 33
PART II. OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K
(a) The exhibits listed below are filed as part of this report:
Exhibit 12--Computation of Ratio of Earnings to Combined Fixed
Charges and Preferred Dividend Requirements
Exhibit 27--Financial Data Schedule
(b) During the third quarter of 1999, the Company did not file a
Form 8-K.
32
<PAGE> 34
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on its behalf by
the undersigned thereunto duly authorized.
THE WILLIAMS COMPANIES, INC.
------------------------------------
(Registrant)
/s/ Gary R. Belitz
------------------------------------
Gary R. Belitz
Controller
(Duly Authorized Officer and
Principal Accounting Officer)
November 12, 1999
<PAGE> 35
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
<S> <C>
Exhibit 12 -- Computation of Ratio of Earnings to Combined Fixed
Charges and Preferred Dividend Requirements
Exhibit 27 -- Financial Data Schedule
</TABLE>
<PAGE> 1
Exhibit 12
The Williams Companies, Inc. and Subsidiaries
Computation of Ratio of Earnings to Combined Fixed Charges
and Preferred Stock Dividend Requirements
(Dollars in millions)
<TABLE>
<CAPTION>
Nine months ended
September 30, 1999
------------------
<S> <C>
Earnings:
Income before income taxes, extraordinary loss
and change in accounting principle $ 210.1
Add:
Interest expense - net 409.0
Rental expense representative of interest factor 59.6
Minority interest in income of consolidated subsidiaries 6.9
Interest accrued - 50% owned company 5.3
Equity losses in less than 50% owned companies 23.7
Other 7.7
---------
Total earnings as adjusted plus fixed charges $ 722.3
=========
Fixed charges and preferred stock dividend requirements:
Interest expense - net $ 409.0
Capitalized interest 37.5
Rental expense representative of interest factor 59.6
Pretax effect of dividends on preferred stock of
the Company 7.8
Interest accrued - 50% owned company 5.3
---------
Combined fixed charges and preferred stock dividend
requirements $ 519.2
=========
Ratio of earnings to combined fixed charges and
preferred stock dividend requirements 1.39
=========
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> SEP-30-1999
<CASH> 287,935
<SECURITIES> 0
<RECEIVABLES> 2,442,460
<ALLOWANCES> 42,518
<INVENTORY> 655,672
<CURRENT-ASSETS> 4,256,909
<PP&E> 18,074,490
<DEPRECIATION> 3,971,703
<TOTAL-ASSETS> 21,367,627
<CURRENT-LIABILITIES> 5,301,984
<BONDS> 7,772,843
0
69,002
<COMMON> 438,482
<OTHER-SE> 3,722,945
<TOTAL-LIABILITY-AND-EQUITY> 21,367,627
<SALES> 0
<TOTAL-REVENUES> 6,182,983
<CGS> 0
<TOTAL-COSTS> 4,565,957
<OTHER-EXPENSES> 24,516
<LOSS-PROVISION> 19,116
<INTEREST-EXPENSE> 446,539
<INCOME-PRETAX> 210,115
<INCOME-TAX> 121,497
<INCOME-CONTINUING> 88,618
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> (5,600)
<NET-INCOME> 83,018
<EPS-BASIC> .18
<EPS-DILUTED> .18
</TABLE>
