<PAGE> 1
FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
(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, 1998
-------------------------------------------------
OR
[ ]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from _____________________ to _______________________
Commission file number 1-4174
---------------------------------------------------------
THE WILLIAMS COMPANIES, INC.
- --------------------------------------------------------------------------------
(Exact name of registrant as specified in its charter)
DELAWARE 73-0569878
- ------------------------ ------------------------------------
(State of Incorporation) (IRS Employer Identification Number)
ONE WILLIAMS CENTER
TULSA, OKLAHOMA 74172
- --------------------------------------- ----------
(Address of principal executive office) (Zip Code)
Registrant's telephone number: (918)573-2000
-------------
NO CHANGE
- --------------------------------------------------------------------------------
Former name, former address and former fiscal year,
if changed since last report.
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes X No
--- ---
Indicate the number of shares outstanding of each of the issuer's classes of
common stock as of the latest practicable date.
Class Outstanding at October 31, 1998
- -------------------------- -------------------------------
Common Stock, $1 par value 427,771,866 Shares
<PAGE> 2
The Williams Companies, Inc.
Index
<TABLE>
<CAPTION>
Page
----
<S> <C>
Part I. Financial Information
Item 1. Financial Statements
Consolidated Statement of Income--Three and Nine Months
Ended September 30, 1998 and 1997 2
Consolidated Balance Sheet--September 30, 1998 and December 31, 1997 3
Consolidated Statement of Cash Flows--Nine Months
Ended September 30, 1998 and 1997 4
Notes to Consolidated Financial Statements 5
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 15
Item 3. Quantitative and Qualitative Disclosures about
Market Risk 22
Part II. Other Information
Item 6. Exhibits and Reports on Form 8-K 23
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 Current Report on Form 8-K dated May 18, 1998 and the Year
2000 disclosures contained in this document.
1
<PAGE> 3
The Williams Companies, Inc.
Consolidated Statement of Income
(Unaudited)
<TABLE>
<CAPTION>
(Millions, except per-share amounts)
---------------------------------------------
Three months ended Nine months ended
September 30, September 30,
---------------------------------------------
1998 1997* 1998 1997*
-------- -------- -------- ---------
<S> <C> <C> <C> <C>
Revenues:
Gas Pipelines (Note 3) $ 400.6 $ 398.3 $1,243.9 $1,237.4
Energy Services (Note 3) 1,240.7 1,517.0 3,741.5 4,386.3
Communications (Note 2) 418.5 413.7 1,219.6 989.4
Other 14.5 8.9 40.0 28.0
Intercompany eliminations (173.3) (238.9) (603.6) (742.6)
-------- -------- -------- --------
Total revenues 1,901.0 2,099.0 5,641.4 5,898.5
-------- -------- -------- --------
Profit-center costs and expenses:
Costs and operating expenses 1,377.2 1,609.5 4,059.4 4,454.3
Selling, general and administrative expenses 275.0 220.3 754.4 593.1
Other (income) expense--net (Notes 3 and 4) 13.3 (6.6) 68.3 (16.3)
-------- -------- -------- --------
Total profit-center costs and expenses 1,665.5 1,823.2 4,882.1 5,031.1
-------- -------- -------- --------
Operating profit:
Gas Pipelines (Note 3) 141.7 141.7 489.7 453.9
Energy Services (Note 3) 116.6 137.3 315.7 413.2
Communications (Note 2) (25.6) (5.2) (56.2) (3.9)
Other 2.8 2.0 10.1 4.2
-------- -------- -------- --------
Total operating profit 235.5 275.8 759.3 867.4
General corporate expenses (Note 4) (17.2) (17.9) (76.1) (57.0)
Interest accrued (131.5) (118.5) (376.0) (344.7)
Interest capitalized 12.6 8.1 28.6 15.5
Investing income (loss) (Note 5) (33.7) 4.1 (30.7) 13.5
Gain on sale of interest in subsidiary (Note 6) -- -- -- 44.5
Gain on sale of assets (Note 7) -- -- -- 66.0
Minority interest in (income) loss of
consolidated subsidiaries .1 (5.2) (5.5) (12.6)
Other expense--net (10.0) (1.9) (22.4) (4.7)
-------- -------- -------- --------
Income before income taxes 55.8 144.5 277.2 587.9
Provision for income taxes (Note 8) 23.7 57.1 111.5 203.4
-------- -------- -------- --------
Income before extraordinary loss 32.1 87.4 165.7 384.5
Extraordinary loss (Note 9) -- (73.7) (4.8) (73.7)
-------- -------- -------- --------
Net income 32.1 13.7 160.9 310.8
Preferred stock dividends 1.9 2.4 5.7 7.6
-------- -------- -------- --------
Income applicable to common stock $ 30.2 $ 11.3 $ 155.2 $ 303.2
-------- -------- -------- --------
Basic earnings per common share (Note 10):
Income before extraordinary loss $ .07 $ .21 $ .38 $ .92
Extraordinary loss (Note 9) -- (.18) (.01) (.18)
-------- -------- -------- --------
Net income $ .07 $ .03 $ .37 $ .74
-------- -------- -------- --------
Average shares (thousands) 428,594 411,821 424,076 411,677
Diluted earnings per common share (Note 10):
Income before extraordinary loss $ .07 $ .20 $ .38 $ .89
Extraordinary loss (Note 9) -- (.17) (.01) (.17)
-------- -------- -------- --------
Net income $ .07 $ .03 $ .37 $ .72
======== ======== ======== ========
Average shares (thousands) 442,080 429,155 440,874 428,980
Cash dividends per common share $ .15 $ .13 $ .45 $ .39
</TABLE>
* Amounts have been restated to reflect the acquisition of MAPCO Inc., which
has been accounted for as a pooling of interests, and certain revenue amounts
have been reclassified to conform to current year classifications (see Note
2 for additional information).
See accompanying notes.
2
<PAGE> 4
The Williams Companies, Inc.
Consolidated Balance Sheet
(Unaudited)
<TABLE>
<CAPTION>
(Millions)
----------------------------
September 30, December 31,
1998 1997*
------------- ------------
<S> <C> <C>
ASSETS
- ------
Current assets:
Cash and cash equivalents $ 91.6 $ 122.1
Receivables 1,650.7 1,584.5
Transportation and exchange gas receivable 105.2 130.4
Inventories (Note 11) 434.9 433.9
Commodity trading assets 275.3 180.3
Deferred income taxes 227.6 236.6
Other 188.5 176.2
----------- -----------
Total current assets 2,973.8 2,864.0
Investments 690.7 388.1
Property, plant and equipment, at cost 15,829.9 14,605.1
Less accumulated depreciation and depletion (3,441.9) (3,068.3)
----------- -----------
12,388.0 11,536.8
Goodwill and other intangible assets--net 588.8 600.6
Other assets and deferred charges 1,092.6 888.1
----------- -----------
Total assets $ 17,733.9 $ 16,277.6
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
- ------------------------------------
Current liabilities:
Notes payable (Note 12) $ 797.8 $ 693.0
Accounts payable 1,051.3 1,288.5
Accrued liabilities 1,437.1 1,349.3
Commodity trading liabilities 273.7 182.0
Long-term debt due within one year (Note 12) 144.9 80.3
----------- -----------
Total current liabilities 3,704.8 3,593.1
Long-term debt (Note 12) 6,323.4 5,351.5
Deferred income taxes 2,072.2 2,009.1
Other liabilities 1,027.3 946.5
Minority interest in consolidated subsidiaries 284.6 144.8
Contingent liabilities and commitments (Note 13)
Stockholders' equity:
Preferred stock, $1 par value, 30 million shares authorized, 1.8 million shares
issued in 1998 and 2.5 million shares issued in 1997 102.2 142.2
Common stock, $1 par value, 960 million shares authorized, 431.7 million
shares issued in 1998 and 431.5 million shares issued in 1997 431.7 431.5
Capital in excess of par value 973.2 1,041.6
Retained earnings 2,948.4 2,983.3
Other (85.7) (54.1)
----------- -----------
4,369.8 4,544.5
Less treasury stock (at cost), 4 million shares of common stock in 1998
and 18.9 million shares of common stock in 1997 (Note 4) (48.2) (311.9)
----------- -----------
Total stockholders' equity 4,321.6 4,232.6
----------- -----------
Total liabilities and stockholders' equity $ 17,733.9 $ 16,277.6
=========== ===========
</TABLE>
* Amounts have been restated to reflect the acquisition of MAPCO Inc., which
has been accounted for as a pooling of interests (see Note 2 for additional
information).
See accompanying notes.
3
<PAGE> 5
The Williams Companies, Inc.
Consolidated Statement of Cash Flows
(Unaudited)
<TABLE>
<CAPTION>
(Millions)
-------------------------------
Nine months ended September 30,
-------------------------------
1998 1997*
-------------------------------
<S> <C> <C>
OPERATING ACTIVITIES:
Net income $ 160.9 $ 310.8
Adjustments to reconcile to cash provided from operations:
Extraordinary loss 4.8 73.7
Premium on early extinguishment of debt (7.1) (154.2)
Depreciation, depletion and amortization 471.8 432.8
Provision for deferred income taxes 67.1 59.0
Provision for loss on property and other assets 29.8 2.5
(Gain) loss on dispositions of property and interest in subsidiary .6 (119.9)
Minority interest in income of consolidated subsidiaries 5.5 12.6
Cash provided (used) by changes in assets and liabilities:
Receivables sold (55.9) 138.9
Receivables 24.0 164.1
Inventories (.7) (103.6)
Other current assets (31.8) 25.7
Accounts payable (227.2) (55.8)
Accrued liabilities 64.8 (142.1)
Current commodity trading assets and liabilities (3.3) 11.4
Non-current commodity trading assets and liabilities (36.7) (15.8)
Other, including changes in non-current assets and liabilities (22.0) 40.2
---------- ----------
Net cash provided by operating activities 444.6 680.3
---------- ----------
FINANCING ACTIVITIES:
Proceeds from notes payable 708.9 1,439.1
Payments of notes payable (1,096.7) (282.1)
Proceeds from long-term debt 2,623.4 1,329.1
Payments of long-term debt (1,089.7) (1,918.1)
Proceeds from issuance of common stock 67.2 37.7
Purchases of treasury stock - (50.2)
Dividends paid (195.8) (156.5)
Contributions from minority interest owners 141.5 11.9
Other--net (16.1) (35.0)
---------- ----------
Net cash provided by financing activities 1,142.7 375.9
---------- ----------
INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures (1,344.5) (931.4)
Proceeds from dispositions 71.2 89.3
Changes in accounts payable and accrued liabilities (3.3) (17.3)
Acquisition of businesses, net of cash acquired - (135.7)
Proceeds from sale of assets - 66.0
Purchase of investments/advances to affiliates (347.9) (229.2)
Other--net 6.7 20.5
---------- ----------
Net cash used by investing activities (1,617.8) (1,137.8)
---------- ----------
Decrease in cash and cash equivalents (30.5) (81.6)
Cash and cash equivalents at beginning of period 122.1 220.1
---------- ----------
Cash and cash equivalents at end of period $ 91.6 $ 138.5
========== ==========
</TABLE>
* Amounts have been restated to reflect the acquisition of MAPCO Inc., which has
been accounted for as a pooling of interests (see Note 2 for additional
information).
See accompanying notes.
4
<PAGE> 6
The Williams Companies, Inc.
Notes to Consolidated Financial Statements
(Unaudited)
1. General
- -------------------------------------------------------------------------------
The accompanying interim consolidated financial statements of The Williams
Companies, Inc. (Williams) do not include all notes in annual financial
statements and therefore should be read in conjunction with the consolidated
financial statements and notes thereto in Williams' Current Report on Form 8-K
dated May 18, 1998. 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, 1998, results of operations for
the three and nine months ended September 30, 1998 and 1997, and cash flows for
the nine months ended September 30, 1998 and 1997.
Operating profit of operating companies may vary by quarter. Based on
current rate structures and/or historical maintenance schedules,
Transcontinental Gas Pipe Line and Texas Gas Transmission experience lower
operating profits in the second and third quarters as compared to the first and
fourth quarters. As a result of its power services activity, Energy Marketing &
Trading experiences higher operating profit in the second and third quarters as
compared to the first and fourth quarters.
2. Basis of presentation
- -------------------------------------------------------------------------------
On March 28, 1998, Williams completed the acquisition of MAPCO Inc. by
exchanging shares of Williams common stock for outstanding MAPCO common stock
and employee stock options (see Note 4). The transaction has been accounted for
as a pooling of interests and, accordingly, the consolidated financial
statements and notes have been restated to reflect the results of operations,
financial position and cash flows as if the companies had been combined
throughout the periods presented. MAPCO is engaged in the NGL pipeline,
petroleum refining and marketing and propane marketing businesses, and has
become part of the Energy Services business unit.
Effective April 1, 1998, certain marketing activities of natural gas
liquids (previously reported in Midstream Gas & Liquids) and petroleum refining
products (previously reported in Petroleum Services) were transferred to Energy
Marketing & Trading and combined with its commodity risk trading operations. As
a result, revenues and operating profit amounts for the three and nine months
ended September 30, 1997, have been reclassified consistent with the
activities. These marketing activities are reported through first quarter 1998
on a "gross" basis in the Consolidated Statement of Income as revenues and
profit-center costs within Energy Marketing & Trading. Concurrent with
completing the combination of such activities with the commodity risk trading
operations of Energy Marketing & Trading, the related contract rights and
obligations of certain of these operations were recorded in the Consolidated
Balance Sheet on a market-value basis consistent with Energy Marketing &
Trading's accounting policy, and the income statement presentation relating to
these operations was changed effective April 1, 1998, to reflect these revenues
net of the related costs to purchase such items.
On April 30, 1997, Williams and Northern Telecom (Nortel) combined their
customer-premise equipment sales and service operations into a limited
liability company, Williams Communications Solutions, LLC (LLC).
Communications' revenues and operating profit amounts include the operating
results of the LLC beginning May 1, 1997 (see Note 6).
3. Revenues and operating profit
- -------------------------------------------------------------------------------
Revenues and operating profit of Gas Pipelines and Energy Services for the
three and nine months ended September 30, 1998 and 1997, are as follows:
<TABLE>
<CAPTION>
Three months ended September 30,
-----------------------------------------
(Millions) Revenues Operating Profit
1998 1997 1998 1997
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Gas Pipelines:
Central $ 42.3 $ 49.4 $ 12.3 $ 19.1
Kern River Gas
Transmission 40.3 43.1 27.3 30.6
Northwest Pipeline 73.9 71.2 35.7 35.3
Texas Gas
Transmission 50.0 53.2 7.9 3.7
Transcontinental Gas
Pipe Line 194.1 181.4 58.5 53.0
-------- -------- -------- --------
$ 400.6 $ 398.3 $ 141.7 $ 141.7
======== ======== ======== ========
</TABLE>
5
<PAGE> 7
Notes (continued)
<TABLE>
<CAPTION>
Three months ended September 30,
-----------------------------------------
(Millions) Revenues Operating Profit
1998 1997 1998 1997
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Energy Services:
Energy Marketing
& Trading $ 298.3 $ 524.4* $ 14.6 $ (2.5)*
Exploration &
Production 28.7 32.1 4.9 5.4
Midstream Gas &
Liquids 208.5 260.3* 56.2 72.1*
Petroleum Services 705.2 700.2* 44.8 62.3*
Merger-related costs - - (3.9) -
--------- -------- -------- --------
$ 1,240.7 $1,517.0* $ 116.6 $ 137.3*
========= ======== ======== ========
<CAPTION>
Nine months ended September 30,
-----------------------------------------------------
(Millions) Revenues Operating Profit
1998 1997 1998 1997
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
Gas Pipelines:
Central $ 128.2 $ 137.2 $ 41.7 $ 51.4
Kern River Gas
Transmission 121.8 125.1 83.8 90.6
Northwest Pipeline 215.4 204.5 105.1 94.5
Texas Gas
Transmission 193.8 210.4 61.2 55.5
Transcontinental
Gas Pipe Line 584.7 560.2 197.9 161.9
---------- ---------- ---------- ----------
$ 1,243.9 $ 1,237.4 $ 489.7 $ 453.9
========== ========== ========== ==========
Energy Services:
Energy Marketing
& Trading $ 953.5 $ 1,511.6* $ 35.3 $ 9.7*
Exploration &
Production 106.8 94.5 25.2 20.1
Midstream Gas &
Liquids 650.4 782.9* 177.3 226.4*
Petroleum Services 2,030.8 1,997.3* 123.8 157.0*
Merger-related costs -- -- (45.9) --
---------- ---------- ---------- ----------
$ 3,741.5 $ 4,386.3* $ 315.7 $ 413.2*
========== ========== ========== ==========
</TABLE>
* Amounts have been restated as described in Note 2.
Included in the third quarter 1998 operating profit for Energy Marketing &
Trading are credit loss accruals of $26.4 million for certain energy capital and
retail energy activities.
Included in the nine months ended September 30, 1998 other (income)
expense-net and in operating profit for Petroleum Services is a $15.5 million
loss provision for potential refunds to customers from a recent order from the
Federal Energy Regulatory Commission (see Note 13 for additional information).
4. MAPCO acquisition
- -------------------------------------------------------------------------------
On November 24, 1997, Williams and MAPCO Inc. announced that they had
entered into a definitive merger agreement whereby Williams would acquire MAPCO
by exchanging 1.665 shares of Williams common stock for each outstanding share
of MAPCO common stock. In addition, outstanding MAPCO employee stock options
would be converted into Williams common stock. The merger was consummated on
March 28, 1998, with the issuance of 98.8 million shares of Williams common
stock valued at $3.1 billion based on the closing price of Williams common
stock on March 27, 1998. In connection with the merger, 8.4 million shares of
MAPCO $1 par value common stock previously held in treasury were retired. These
shares had a carrying value of $253.8 million.
The merger constituted a tax-free reorganization and has been accounted for
as a pooling of interests. Intercompany transactions between Williams and MAPCO
prior to the merger have been eliminated, and no material adjustments were
necessary to conform MAPCO's accounting policies.
In connection with the merger, Williams has recognized approximately $74
million in merger-related costs comprised primarily of outside professional
fees and early retirement and severance costs. Approximately $46 million of
these merger-related costs are included in other (income) expense-net as a
component of Energy Services' operating profit for the nine months ended
September 30, 1998 (see Note 3), and approximately $28 million is included in
general corporate expenses. During 1997, payments of $32.6 million were made
for non-compete agreements. These costs are being amortized over one to three
years from the merger completion date.
6
<PAGE> 8
Notes (continued)
The results of operations for each company and the combined amounts
presented in the Williams' Consolidated Statement of Income are as follows:
<TABLE>
<CAPTION>
Three months Three months Nine months
ended ended ended
(Millions) March 31, September 30, September 30,
------------------------------------------------
1998 1997 1997
---------- ---------- ----------
<S> <C> <C> <C>
Revenues:
Williams $ 1,137.3 $ 1,121.0 $ 3,143.0
MAPCO 823.8 982.1 2,767.6
Intercompany
eliminations (1.3) (4.1) (12.1)
---------- ---------- ----------
Combined $ 1,959.8 $ 2,099.0 $ 5,898.5
========== ========== ==========
Net income:
Williams $ 59.7 $ (8.4) $ 205.3
MAPCO 8.4 22.1 105.5
---------- ---------- ----------
Combined $ 68.1 $ 13.7 $ 310.8
========== ========== ==========
</TABLE>
5. Investing income (loss)
- -------------------------------------------------------------------------------
Third-quarter 1998 investing loss includes a $23.2 million write-down
related to a Communications network applications venture that was re-evaluated
in the third quarter.
6. Sale of interest in subsidiary
- -------------------------------------------------------------------------------
On April 30, 1997, Williams and Nortel combined their customer-premise
equipment sales and service operations into a limited liability company,
Williams Communications Solutions, LLC (LLC). In addition, Williams paid $68
million to Nortel. Williams has accounted for its 70 percent interest in the
operations that Nortel contributed to the LLC as a purchase business
combination, and beginning May 1, 1997, has included the results of operations
of the acquired company in Williams' Consolidated Statement of Income.
Williams recorded the 30 percent reduction in its operations contributed to
the LLC as a sale to the minority shareholders of the LLC. Williams recognized
a gain of $44.5 million based on the fair value of its operations contributed
to the LLC. Income taxes were not provided on the gain, because the transaction
did not effect the differences between the financial and tax bases of
identifiable assets and liabilities.
If the transaction had occurred on January 1, 1997, Williams' unaudited pro
forma revenues for the nine months ended September 30, 1997, would have been
approximately $6.1 billion. The pro forma effect of the transaction on
Williams' net income is not significant. Pro forma financial information is not
necessarily indicative of results of operations that would have occurred if the
transaction had occurred on January 1, 1997, or of future results of operations
of the combined companies.
7. Sale of assets
- -------------------------------------------------------------------------------
In January 1997, Williams sold its interest in the natural gas liquids and
condensate reserves in the West Panhandle field of Texas for $66 million in
cash. The sale resulted in a $66 million pre-tax gain on the transaction,
because the related reserves had no book value.
8. Provision for income taxes
- -------------------------------------------------------------------------------
The provision for income taxes includes:
<TABLE>
<CAPTION>
Three months ended Nine months ended
(Millions) September 30, September 30,
---------------------------------------------
1998 1997 1998 1997
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
Current:
Federal $ 16.0 $ 34.5 $ 40.8 $ 122.3
State .1 9.7 2.1 22.1
Foreign .5 -- 1.5 --
--------- --------- --------- ---------
16.6 44.2 44.4 144.4
Deferred:
Federal 4.1 11.8 54.6 48.7
State 3.0 1.1 12.5 10.3
--------- --------- --------- ---------
7.1 12.9 67.1 59.0
--------- --------- --------- ---------
Total provision $ 23.7 $ 57.1 $ 111.5 $ 203.4
========= ========= ========= =========
</TABLE>
The effective income tax rate for 1998 is greater than the federal
statutory rate due primarily to the effects of state income taxes.
The effective income tax rate for the three months ended September 30,
1997, is greater than the federal statutory rate due primarily to the effects
of state income taxes, partially offset by the effects of income tax credits
from coal-seam gas production.
The effective income tax rate for the nine months ended September 30, 1997,
is less than the federal statutory rate due primarily to the effect of the
non-taxable gain recognized in the second quarter (see Note 6) and income tax
credits from coal-seam gas production, partially offset by the effects of state
income taxes.
9. Extraordinary loss
- -------------------------------------------------------------------------------
The extraordinary loss in 1998 resulted from the early extinguishment of
debt. 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).
During the third quarter of 1997, Williams initiated a restructuring of its
debt portfolio. At September 30, 1997, Williams had paid approximately $1.2
million to redeem higher interest rate debt for a $73.7 million net loss (net
of a $46.9 million benefit for income taxes).
8
<PAGE> 9
Notes (continued)
10. Earnings per share
- -------------------------------------------------------------------------------
Basic earnings per common share are computed for the three and nine months
ended September 30, 1998 and 1997, as follows:
<TABLE>
<CAPTION>
(Millions, except Three months ended Nine months ended
per-share amounts) September 30, September 30,
--------------------------------------------
1998 1997* 1998 1997*
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Basic earnings:
Income before
extraordinary loss $ 32.1 $ 87.4 $ 165.7 $ 384.5
Extraordinary loss -- (73.7) (4.8) (73.7)
-------- -------- -------- --------
Net income 32.1 13.7 160.9 310.8
Preferred stock dividends:
$2.21 cumulative
preferred stock -- .2 -- 1.0
$3.50 cumulative
convertible
preferred stock 1.9 2.2 5.7 6.6
-------- -------- -------- --------
Income applicable to
common stock $ 30.2 $ 11.3 $ 155.2 $ 303.2
-------- -------- -------- --------
Basic shares:
Average number of
common shares
outstanding during
the period 426,021 408,591 421,719 408,068
Shares attributable to
deferred stock 2,573 3,230 2,357 3,609
-------- -------- -------- --------
Total basic weighted-
average shares 428,594 411,821 424,076 411,677
-------- -------- -------- --------
Basic earnings per common share:
Income before
extraordinary loss $ .07 $ .21 $ .38 $ .92
Extraordinary loss -- (.18) (.01) (.18)
-------- -------- -------- --------
Net income $ .07 $ .03 $ .37 $ .74
======== ======== ======== ========
</TABLE>
Diluted earnings per common share are computed for the three and nine months
ended September 30, 1998 and 1997, as follows:
<TABLE>
<CAPTION>
(Millions, except Three months ended Nine months ended
per-share amounts) September 30, September 30,
-------------------------------------------------------
1998 1997* 1998 1997*
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
Diluted earnings:
Income before
extraordinary loss $ 32.1 $ 87.4 $ 165.7 $ 384.5
Extraordinary loss -- (73.7) (4.8) (73.7)
----------- ----------- ----------- -----------
Net income 32.1 13.7 160.9 310.8
Preferred stock dividends:
$2.21 cumulative
preferred stock -- .2 -- 1.0
----------- ----------- ----------- -----------
Income applicable
to common stock $ 32.1 $ 13.5 $ 160.9 $ 309.8
=========== =========== =========== ===========
Diluted shares:
Average number of
common shares
outstanding during
the period 426,021 408,591 421,719 408,068
Shares attributable
to options and
deferred stock 7,029 8,848 9,222 9,195
Dilutive preferred
shares 9,030 11,716 9,933 11,717
----------- ----------- ----------- -----------
Total diluted weighted-
average shares 442,080 429,155 440,874 428,980
=========== =========== =========== ===========
Diluted earnings per common share:
Income before
extraordinary loss $ .07 $ .20 $ .38 $ .89
Extraordinary loss -- (.17) (.01) (.17)
----------- ----------- ----------- -----------
Net income $ .07 $ .03 $ .37 $ .72
=========== =========== =========== ===========
</TABLE>
* Share and per-share amounts for 1997 have been restated to reflect the effect
of the December 29, 1997, two-for-one common stock split and the acquisition
of MAPCO Inc., which has been accounted for as a pooling of interests.
8
<PAGE> 10
Notes (continued)
11. Inventories
- -------------------------------------------------------------------------------
<TABLE>
<CAPTION>
September 30, December 31,
(Millions) 1998 1997
--------------------------
<S> <C> <C>
Raw materials:
Crude oil $ 45.7 $ 30.5
Other 1.2 5.2
--------- ---------
46.9 35.7
Finished goods:
Refined products 79.6 122.3
Natural gas liquids 68.4 43.8
General merchandise &
communications equipment 78.8 90.0
--------- ---------
226.8 256.1
Materials and supplies 87.3 82.5
Natural gas in underground storage 71.4 57.8
Other 2.5 1.8
--------- ---------
$ 434.9 $ 433.9
========= =========
</TABLE>
12. Debt and banking arrangements
- -------------------------------------------------------------------------------
Notes payable
During 1998, Williams Holdings of Delaware, Inc. (Williams Holdings)
increased its commercial paper program to $1 billion. The commercial paper
program is backed by short-term bank-credit facilities totaling $1 billion. At
September 30, 1998, $593 million of commercial paper was outstanding under the
program. Interest rates vary with current market conditions.
Debt
Williams also has a $1 billion credit agreement under which Northwest
Pipeline, Transcontinental Gas Pipe Line, Texas Gas Transmission, and Williams
Communications Solutions, LLC have access to varying amounts of the facility
while Williams and Williams Holdings have access to all unborrowed amounts.
Interest rates vary with current market conditions.
For financial statement reporting purposes at September 30, 1998, $250
million in current debt obligations have been classified as non-current
obligations based on Williams' intent and ability to refinance on a long-term
basis. At September 30, 1998, the amount available on the $1 billion credit
agreement of $318 million is sufficient to complete these refinancings.
9
<PAGE> 11
Notes (continued)
Debt
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Weighted-
average
interest September 30, December 31,
(Millions) rate* 1998 1997
---------------------------------------
<S> <C> <C> <C>
The Williams Companies, Inc.
Revolving credit loans 5.9% $ 682.0 $ 383.0
Debentures, 8.875% - 10.25%,
payable 2012, 2020
and 2021 8.3 136.9 137.0
Notes, 5.1% - 9.625%, pay-
able through 2012** 6.4 2,275.1 1,042.1
Williams Gas Pipelines Central
Variable rate notes,
payable 1999 8.2 130.0 130.0
Kern River Gas Transmission
Notes, 6.42% and 6.72%,
payable through 2001 6.6 549.8 586.4
Northwest Pipeline
Debentures, 7.125% - 10.65%,
payable through 2025 8.3 151.4 151.6
Notes, 6.625%, payable 2007 6.6 250.0 250.0
Adjustable rate notes,
payable through 2002 9.0 6.7 8.3
Texas Gas Transmission
Debentures, 7.25%, payable
2027 7.3 99.1 99.0
Notes, 8.625%, payable 2004 8.6 152.1 152.4
Transcontinental Gas Pipe Line
Revolving credit loans -- -- 160.0
Debentures, 7.08% and 7.25%,
payable 2026** 7.2 399.7 399.7
Notes, 6.125% - 8.875%, payable
2002 through 2008 7.0 426.2 128.2
Adjustable rate note, payable
2002 5.7 150.0 150.0
Williams Holdings of Delaware
Revolving credit loans -- -- 200.0
Debentures, 6.25% and 7.7%,
payable 2006 and 2027 5.6 351.9 351.8
Notes, 6.365% - 8.87%, payable
through 2022 7.6 536.6 625.3
MAPCO Inc.
Commercial paper and
bank money market lines -- -- 135.8
MAPCO Natural Gas Liquids, Inc.
Notes, 6.67% - 8.95%,
payable through 2022 7.8 165.0 165.0
Williams Communications Solutions
Revolving credit loans -- -- 125.0
Other, payable through 2005 7.4 5.8 51.2
--------- ---------
6,468.3 5,431.8
Current portion of long-term debt (144.9) (80.3)
--------- ---------
$ 6,323.4 $ 5,351.5
========= =========
</TABLE>
* At September 30, 1998, including the effects of interest-rate swaps.
** $300 million, 5.95% notes, payable 2010; $200 million, 7.08% debentures,
payable 2026; and $240 million, 6.125% notes, payable 2012 are subject to
redemption at par at the option of the debtholder in 2000, 2001 and 2002,
respectively.
13. 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 reserved
$416 million for potential refund as of September 30, 1998.
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. In October 1997, the FERC voted not to reconsider an
order issued in one of the three pipeline proceedings, but convened a conference
on January 30, 1998, to consider, on an industry-wide basis, issues with respect
to pipeline rates of return. In July 1998, the FERC issued orders in the other
two pipeline rate cases, again modifying its rate of return methodology by
adopting a formula that gives less weight to the long-term growth component.
This most recent formula modification results in somewhat higher rates of return
compared to the rates of return calculated under the FERC's prior formula.
Neither pipeline has made any changes to its accounting reserves pending
resolution of the issues discussed above.
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 recently ruled on by the U.S. Court of Appeals for the D.C. Circuit,
require interstate gas pipeline companies to change the manner in which they
provide services. Williams' gas pipelines subsidiaries implemented
restructurings in 1993. Certain aspects of two of its pipeline companies'
restructurings are under appeal.
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. On February 27, 1997, the
FERC issued Order No. 636-C which dealt with the six issues remanded by the D.C.
Circuit. In that order, the FERC reaffirmed that pipelines should be exempt from
sharing gas supply realignment costs. Requests for rehearing have been filed for
the order.
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. The deadline
for comments on the NOPR and NOI has been extended until the first quarter of
1999.
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 the second
quarter of 1998, for potential refunds to customers for the issues described
above. Since May 1, 1992, WPL has collected and recognized as revenues $141
million in noncompetitive markets that are in excess of tariff rates previously
approved by the FERC and that are subject to refund with interest. WPL believes
that the tariff rates collected in these markets during this period will be
justified in accordance with the FERC's cost-basis guidelines and will be making
the appropriate filings with the FERC to support this position.
As a result of FERC Order 636, which requires interstate gas pipelines to
change the way they do business, 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.
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. Order 636-D has been appealed.
10
<PAGE> 12
Notes (continued)
Pursuant to a stipulation and agreement approved by the FERC, Williams Gas
Pipelines Central (Central) has made 13 filings to direct bill take-or-pay and
gas supply realignment costs. The total amount approved for direct billing, net
of certain amounts collected subject to refunds, is $73.1 million. An intervenor
has 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 has filed for rehearing, and
management plans to vigorously defend 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, which in
turn must be acted upon by the FERC. If the FERC's final ruling on eligibility
is unfavorable, Central will appeal these orders to the courts. On May 29, 1998,
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. The Order also denied, without prejudice to a later refiling, an
indefinite extension of Central's recovery mechanism for non-settlement costs
associated with these contracts. No party bid less than the fixed maximum
reserve price in the approved auction and, as a result, the contracts were not
assigned. In accordance with FERC's Orders, on September 30, 1998, Central filed
a request for authority to conduct a second reverse auction of the contracts.
Under the proposed reverse auction, which FERC has now approved, effective
February 1, 1999, Central will assign the contracts to bidders at or below an
aggregate reserve price of $112.6 million. If no unaffiliated bidders are
willing to accept assignment on those terms, Central will be 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.
Because of the uncertainties pertaining to the outcome of these issues
currently pending at the FERC and the status of settlement negotiation and
various other factors, Central cannot reasonably estimate the ultimate costs
that may be incurred. Central is actively pursuing negotiations with the
producers and others to resolve all outstanding obligations under the contracts.
Based on the terms of what Central believes would be a reasonable settlement,
$113 million has been accrued as a liability at September 30, 1998. Central also
has a $111 million regulatory asset at September 30, 1998, for estimated
recovery of future costs from customers. Central cannot predict the final
outcome of the FERC's rulings on contract prudency and cost recovery under Order
No. 636 and is unable to determine the ultimate liability and loss, if any, at
this time. If Central does not prevail in these FERC proceedings or any
subsequent appeals, and if Central is able to reach a settlement with the
producers and others consistent with the $113 million accrued liability, the
loss could be the total of the regulatory asset and the $40 million of protested
costs. Central continues to believe that it entered into the gas purchase
contracts in a prudent manner under FERC rules in place at the time. Central
also believes that these costs will be found eligible for recovery under Order
No. 636.
In September 1995, Texas Gas received FERC approval of a settlement
regarding Texas Gas' recovery of gas supply realignment costs. Through
September 30, 1998, 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.
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 FERC policy. While Williams believes that these accruals are
adequate and the associated regulatory assets are appropriate, costs actually
incurred and amounts actually recovered from customers will depend upon the
outcome of various court and FERC proceedings, the success of settlement
negotiations and various other factors, not all of which are presently
foreseeable.
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, 1998, these subsidiaries had reserves totaling approximately $26
million for these costs.
11
<PAGE> 13
Notes (continued)
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, 1998, Central had recorded a liability for
approximately $16 million, representing the current estimate of future
environmental cleanup costs to be incurred over the next six to ten years. The
Midstream Gas & Liquids unit of Energy Services (WES) has recorded an aggregate
liability of approximately $11 million, representing the current estimate of its
future environmental and remediation costs, including approximately $5 million
relating to former Central facilities. Texas Gas and Transcontinental Gas Pipe
Line likewise had recorded 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.
WES also accrues environmental remediation costs for its petroleum products
pipelines, retail petroleum, refining and propane marketing operations primarily
related to soil and groundwater contamination. At September 30, 1998, WES and
its subsidiaries had reserves, in addition to the reserves listed above,
totaling approximately $30 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, 1998, WES and its subsidiaries had
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. Such costs have exceeded this amount. At
September 30, 1998, Williams had approximately $12 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 has 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 have been filed against Northwest Pipeline and others in U.S. district
court in Colorado, making essentially the same claims. The district court has
stayed all of the cases involving Northwest Pipeline until the plaintiffs
exhaust 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.
Other legal matters
In 1988, certain royalty owners in a producing field in Cameron Parish,
Louisiana, brought suit against a Williams subsidiary and other working interest
owners seeking additional royalties or lease cancellation. An amended petition
later added a second Williams subsidiary, Williams and additional working
interest owners. All other defendants have been dismissed or have settled with
plaintiffs. In their recently amended damage claim, the plaintiffs asserted
royalty underpayments plus interest of approximately $12 million. The claimed
damages are attributable to all working interests for a period of about 15
years. One of the two Williams subsidiaries sued owned a one-half interest in
the field and served as operator for approximately eight years. The other
subsidiary purchased produced gas from the field. Plaintiffs also request
punitive damages equal to double the alleged damages and attorneys' fees.
Williams believes all royalties due from its subsidiaries were properly paid,
that the field was properly operated, and that it is not responsible for any
amounts due from any other working interests or for the period after its
subsidiary had sold its interest and terminated its status as operator of the
field. The litigation pending in Cameron Parish, Louisiana, has recently been
settled for payments of aggregating approximately $9 million, for which reserves
have been fully accrued.
12
<PAGE> 14
Notes (continued)
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. The only lawsuit remaining is 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. The defendants seek to have the judgment
modified in many respects, including the elimination of punitive damages as well
as a portion of the actual damages awarded. If the defendants prevail on appeal,
it will result in an award significantly less than the judgment. The plaintiffs
have cross-appealed and seek to modify the judgment to increase the total award
plus interest to exceed $155 million. 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
decision, Williams believes will provide for aggregate payments of approximately
$13 million, the full amount of which has been previously accrued.
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 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. The
defendants are considering an appeal to the Supreme Court. The Supreme Court has
granted an extension of time in which to file a writ of certiorari to November
18, 1998.
Williams Communications, Inc. filed suit on March 20, 1998, against
WorldCom Network Services, Inc. (WorldCom) in district court in Tulsa County in
order to prevent WorldCom from disconnecting any of Williams' equipment on the
WorldCom network. This suit sought a declaratory judgment that the single fiber
retained by Williams on the WorldCom network could be used for specified
multimedia uses, and that WorldCom was required to permit Williams to purchase
additional fiber either acquired or constructed by WorldCom. WorldCom had denied
Williams' claim and had asserted various counterclaims for monetary damages,
rescission and injunctive relief. This lawsuit was settled on July 9, 1998. The
settlement resolves all claims for monetary damages, permitted uses of Williams'
fiber on the WorldCom network and Williams' right to purchase additional fiber
on WorldCom fiber builds. There was no significant financial impact to Williams
as a result 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
13
<PAGE> 15
Notes (continued)
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 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, in a prior
year, a liability representing an estimate of amounts it expects to incur in
satisfaction of this indemnity.
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
During the second quarter of 1998, Energy Marketing & Trading entered into
a 15 year contract giving Williams the right to receive fuel conversion services
for purposes of generating electricity. This contract also gives Williams the
right to receive installed capacity and certain ancillary services. Annual
committed payments under the contract range from $140 million to $165 million,
resulting in total committed payments of approximately $2.3 billion.
14. Adoption of accounting standards
- -------------------------------------------------------------------------------
The Financial Accounting Standards Board issued three new accounting
standards, Statement on Financial Accounting Standard (SFAS) No. 131,
"Disclosures about Segments of an Enterprise and Related Information," SFAS No.
132, "Employers' Disclosures about Pensions and Other Postretirement Benefits"
and SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities." SFAS No. 131 and No. 132, effective for fiscal years beginning
after December 15, 1997, are disclosure-oriented standards. Therefore, neither
standard will affect Williams' reported consolidated net income or cash flows.
SFAS No. 133 is effective for fiscal years beginning after June 15, 1999. This
standard 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 has yet to be determined.
The American Institute of Certified Public Accountants (AICPA) issued
Statement of Position (SOP) 98-5, "Reporting on the Costs of Start-Up
Activities," effective for fiscal years beginning after December 15, 1998. The
SOP requires that all start-up costs be expensed and that the effect of adopting
the SOP be reported as the cumulative effect of a change in accounting
principle. The effect of this SOP on Williams' results of operations and
financial position has yet to be determined.
15. Comprehensive income
- -------------------------------------------------------------------------------
Comprehensive income for the three and nine months ended September 30 is
as follows:
<TABLE>
<CAPTION>
Three months ended Nine months ended
(Millions) September 30, September 30,
-------------------- --------------------
1998 1997 1998 1997
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Net income $ 32.1 $ 13.7 $ 160.9 $ 310.8
Other comprehensive
income (loss):
Unrealized gains
(losses) on
securities (16.0) -- 10.8 --
Foreign currency
translation
adjustments (2.0) -- (4.5) --
-------- -------- -------- --------
Comprehensive
income before
taxes 14.1 13.7 167.2 310.8
Income taxes (6.2) -- 4.2 --
-------- -------- -------- --------
Comprehensive
Income $ 20.3 $ 13.7 $ 163.0 $ 310.8
======== ======== ======== ========
</TABLE>
14
<PAGE> 16
ITEM 2.
Management's Discussion and Analysis of
Financial condition and Results of Operations
MAPCO Acquisition
On November 24, 1997, Williams and MAPCO Inc. announced that they had
entered into a definitive merger agreement whereby Williams would acquire MAPCO
by exchanging 1.665 shares of Williams common stock for each outstanding share
of MAPCO common stock. In addition, outstanding MAPCO employee stock options
would be converted into Williams common stock. The merger was consummated on
March 28, 1998, with the issuance of 98.8 million shares of Williams common
stock. MAPCO is engaged in the NGL pipeline, petroleum refining and marketing
and propane marketing businesses, and became part of the Energy Services
business unit.
The merger constituted a tax-free reorganization and has been
accounted for as a pooling of interests. Accordingly, all prior period
financial information presented has been restated to include the combined
results of operations and financial condition of MAPCO as though it had always
been a part of Williams.
Results of Operations
Third Quarter 1998 vs. Third Quarter 1997
GAS PIPELINES
CENTRAL'S revenues and operating profit decreased $7.1 million, or 14
percent, and $6.8 million, or 35 percent, respectively, due primarily to the
net effect of favorable adjustments to certain accruals in 1997 and lower
transportation revenues. Total throughput increased 8.2 TBtu, or 13 percent,
due to higher firm and interruptible transportation volumes.
KERN RIVER GAS TRANSMISSION'S (KERN RIVER) revenues and operating
profit decreased $2.8 million, or 6 percent, and $3.3 million, or 11 percent,
respectively, due primarily to the impact of its rate design and lower average
commodity transportation rates. Additionally, operating profit decreased due to
higher general and administrative expenses. Total throughput decreased less
than 1 percent.
NORTHWEST PIPELINE'S revenues increased $2.7 million, or 4 percent,
due primarily to $2.9 million of favorable 1998 adjustments to rate refund
accruals and demand charge reserves. Total throughput increased 15.5 TBtu, or
11 percent. Operating profit increased $.4 million, or 1 percent, due primarily
to the rate refund accrual adjustment, substantially offset by higher general
and administrative expenses.
TEXAS GAS TRANSMISSION'S revenues decreased $3.2 million, or 6
percent, due primarily to lower cost of service recovery in the third quarter
1998 rates, partially offset by the impact of new services being offered. Total
throughput decreased less than 1 percent. Operating profit increased $4.2
million, or 114 percent, due primarily to lower operating and maintenance
expenses and the impact of new services being offered. Because of its rate
structure, Texas Gas typically experiences lower operating profit in the second
and third quarters as compared to the first and fourth quarters.
TRANSCONTINENTAL GAS PIPE LINE'S (TRANSCO) revenues increased $12.7
million, or 7 percent, due primarily to expansion projects placed in service in
1998 and the fourth quarter of 1997. Total throughput increased 2.8 TBtu, or 1
percent. Operating profit increased $5.5 million, or 10 percent, due primarily
to expansion projects, partially offset by the effect of a $5.4 million
settlement received in 1997 related to a prior rate proceeding. Because of its
rate structure and historical maintenance schedule, Transco typically
experiences lower operating profit in the second and third quarter as compared
to the first and fourth quarters.
ENERGY SERVICES
ENERGY MARKETING & TRADING'S revenues decreased $226.1 million, or 43
percent, due primarily to the $347 million impact in 1998 of reporting revenues
on a net margin basis for certain crude oil, refined products and natural gas
liquids trading operations previously reported on a "gross basis" (see Note 2 of
the Notes to Consolidated Financial Statements). In addition, revenues
associated with natural gas physical trading decreased $20 million due primarily
to the adverse market and supply conditions experienced as a result of Hurricane
Georges; crude oil and refined products revenues decreased $27 million including
the impact of decreased average prices associated with the marketing of refined
products from the Alaska refinery; and energy capital revenues were unfavorably
impacted by $9.8 million of credit loss accruals. Partially offsetting these
decreases were increased power services revenue of $178 million from power
generation under a new contract and a $9.5 million favorable long-term natural
gas transportation contract settlement. Costs and operating expenses decreased
$279 million, or 54 percent, due primarily to the impact in 1998 of reporting
revenues on a net margin basis for certain crude oil, refined products and
natural gas liquids trading operations previously reported on a "gross basis"
and
15
<PAGE> 17
lower average prices associated with refined product purchases from the Alaska
refinery, partially offset by electric power generation costs under the new
power services contract. Selling, general and administrative expenses increased
$29 million due primarily to a $16.6 million retail energy credit loss accrual
and increased staffing and other costs associated with an expanded business
base. Operating profit increased $17.1 million, from a $2.5 million operating
loss in 1997, due primarily to $57 million from the new power services activity,
and the favorable contract settlement. Partially offsetting these increases were
lower natural gas physical trading revenues, total credit loss accruals of $26.4
million in 1998 for certain energy capital and retail energy activities and the
effect of a $6 million recovery in 1997 of an account previously considered a
bad debt. The new power services activity is associated with a power generation
plant that is normally operational during the summer peak cooling season;
therefore, operating profit from this activity will typically be higher in the
second and third quarters as compared to the first and fourth quarters.
EXPLORATION & PRODUCTION'S revenues decreased $3.4 million, or 11
percent, due primarily to a decrease in sales volumes from company-owned
production and marketing volumes from Williams Coal Seam Gas Royalty Trust
(Royalty Trust) combined with lower average natural gas sales prices. Partially
offsetting these decreases is an additional $3 million in deferred income
resulting from a transaction that transferred certain tax credits to a third
party. Operating profit decreased $.5 million, or 9 percent, due primarily to
higher depreciation, depletion and amortization, decreased company-owned
production volumes and lower average natural gas sales prices, partially offset
by increased recognition of deferred income.
MIDSTREAM GAS & LIQUIDS' revenues decreased $51.8 million, or 20
percent, due primarily to the $17 million impact from the shutdown of the
Canadian marketing operations, $16 million lower natural gas liquids sales from
processing activities, $5 million lower gathering revenues and $4 million lower
natural gas liquids pipeline transportation revenues resulting from decreased
shipments. The lower liquids sales reflect lower average sales prices combined
with a 7 percent decrease in volumes sold. Costs and operating expenses
decreased $30 million, or 18 percent, due primarily to the shutdown of the
Canadian marketing operations and lower fuel and replacement gas purchases.
Operating profit decreased $15.9 million, or 22 percent, due primarily to $11
million lower per-unit liquids margins, lower gathering revenues and a decline
in pipeline transportation revenues, partially offset by a 1998 gain of $6
million on settlement of product imbalances.
PETROLEUM SERVICES' revenues increased $5 million, or 1 percent, due
primarily to $44 million of pipeline construction revenues, $21 million higher
convenience store sales, a 17 percent increase in ethanol sales volumes and $5
million higher revenues from fleet management and mobile computer technology
operations. Substantially offsetting these increases were a $70 million decrease
in revenues from refining operations due to lower average sales prices and lower
average ethanol sales prices. The $21 million increase in convenience store
sales reflects $13 million higher merchandise sales due to increased store count
and higher average sales per store and $32 million from a 27 percent increase in
gasoline and diesel sales volumes, partially offset by the $24 million impact of
lower average gasoline and diesel sales prices. Costs and operating expenses
increased $9 million, or 1 percent, due primarily to $42 million of pipeline
construction costs, $17 million of increased convenience store product purchases
and operating costs resulting primarily from increased store count and higher
average sales per store, and $8 million higher costs from fleet management and
mobile computer technology operations, partially offset by a $60 million
decrease from refining operations due mainly to lower average crude oil purchase
prices. Selling, general and administrative expenses increased $13 million due
in part to increased activities in human resources development,
investor/media/customer relations and business development. Operating profit
decreased $17.5 million, or 28 percent, due primarily to lower per-unit refinery
margins and $13 million higher selling, general and administrative expenses,
partially offset by higher average transportation rates.
COMMUNICATIONS
COMMUNICATIONS' revenues increased $4.8 million, or 1 percent, due
primarily to higher network services revenues, partially offset by lower
customer premise equipment sales and services revenues. Sales order backlog at
September 30, 1998 increased $17.3 million from September 30, 1997. Selling,
general, and administrative expenses increased $19.9 million, or 19 percent, due
primarily to expansion and enhancement of the infrastructure primarily in
support of the solutions business and the development of a new national digital
fiber-optic network. The construction of the network continues ahead of schedule
and on budget. Operating profit decreased $20.4 million to a $25.6 million
operating loss in 1998, due primarily to $6 million of charges by the solutions
business for asset write-downs, and higher selling, information services and
other costs associated with substantially expanding the solutions and network
infrastructure, partially offset by improved results in the network applications
businesses.
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<PAGE> 18
CONSOLIDATED
INTEREST ACCRUED increased $13 million, or 11 percent, due primarily to higher
borrowing levels including Williams Holdings' commercial paper program,
partially offset by lower average interest rates following the late 1997 debt
restructuring. Interest capitalized increased $4.5 million, or 56 percent, due
primarily to international investment activities. Investing income decreased
$37.8 million to a $33.7 million loss, as a result of a $23 million write-down
related to a network applications venture (see Note 5) and a $16 million
decrease in equity earnings primarily from international investments, slightly
offset by $4 million higher interest income on long-term notes receivable.
Minority interest in (income) loss of consolidated subsidiaries is $5.3 million
favorable to 1997 due primarily to lower earnings experienced by Williams
Communications Solutions, LLC and allocated to the 30 percent interest held by
minority shareholders. Other expense - net is $8.1 million unfavorable as
compared to 1997 due primarily to a litigation accrual and other reserve
adjustments in 1998 totaling $5 million related to assets previously sold and
the effect of a 1997 gain on the sale of an airplane.
The $33.4 million, or 58 percent, decrease in the provision for income
taxes is primarily a result of lower pre-tax income. The effective income tax
rate in 1998 exceeds the federal statutory rate due primarily to the effects of
state income taxes. The effective income tax rate in 1997 exceeds the federal
statutory rate due primarily to the effects of state income taxes, partially
offset by income tax credits from coal-seam gas production.
Nine Months Ended September 30, 1998 vs. Nine Months Ended September 30, 1997
GAS PIPELINES
OTHER
In July 1998, the Federal Energy Regulatory Commission issued orders in
two gas pipelines' rate cases that modified its rate of return methodology (see
Note 13).
CENTRAL'S revenues decreased $9 million, or 7 percent, due primarily to
the net effect of favorable adjustments to certain accruals in 1997 and lower
transportation revenues. Total throughput increased 6 TBtu, or 3 percent, due
primarily to higher interruptible transportation volumes. Other (income)
expense - net for 1998 and 1997 includes gains from the sale-in-place of
natural gas from a decommissioned storage field of $3 million and $7 million,
respectively. Operating profit decreased $9.7 million, or 19 percent, due
primarily to the net effect of adjustments to certain accruals in 1997, a lower
gain in 1998 compared to 1997 from the sale-in-place of natural gas and lower
transportation revenues, partially offset by lower general and administrative
expenses and operating and maintenance expenses.
KERN RIVER'S revenues decreased $3.3 million, or 3 percent, due
primarily to the impact of its rate design. Total throughput increased 9.2
TBtu, or 4 percent, primarily due to higher short-term firm and interruptible
transportation volumes. Operating profit decreased $6.8 million, or 8 percent,
due primarily to lower revenue, increased general and administrative expenses
and higher ad valorem taxes.
NORTHWEST PIPELINE'S revenues increased $10.9 million, or 5 percent,
due primarily to a new rate design effective March 1, 1997 that enables greater
short-term firm and interruptible transportation volumes, the $4.4 million net
favorable effect of adjustments to rate refund accruals and demand charge
reserves in 1998 and the impact of an unfavorable adjustment to rate refund
accruals in 1997. Total throughput increased 24.7 TBtu, or 5 percent. Operating
profit increased $10.6 million, or 11 percent, due primarily to the new rate
design and the net favorable rate refund accrual adjustments.
TEXAS GAS TRANSMISSION'S revenues decreased $16.6 million, or 8
percent, due primarily to $15 million lower reimbursable costs passed through
to customers as provided in Texas Gas' rates and the $4 million impact of the
favorable resolution of certain contractual issues in 1997, partially offset by
higher revenues related to new services and increased cost recovery in the
current rate structure. Total throughput decreased 12.7 TBtu, or 2 percent.
Costs and operating expenses decreased $16.6 million, or 15 percent, due
primarily to the lower reimbursable costs which are passed through to customers
and lower operating, maintenance, general and administrative expenses.
Operating profit increased $5.7 million, or 10 percent, due primarily to lower
operating, maintenance, general and administrative expenses and the higher
revenues related to new services and increased cost recovery, partially offset
by the impact of the favorable resolution in 1997 of certain contractual
issues. Because of its rate structure, Texas Gas typically experiences lower
operating profit in the second and third quarters as compared to the first and
fourth quarters.
TRANSCO'S revenues increased $24.5 million, or 4 percent, due
primarily to new rates placed into effect May 1, 1997 to recover costs
associated with increased capital expenditures and expansion projects placed
into service in 1998 and late 1997. Revenues were also favorably impacted by
new services initiated in the last half of 1997 and a 1998 adjustment of $10
million related to the new rates placed into effect in 1997, partially offset
by $12 million lower reimbursable costs passed through to customers as provided
in Transco's rates. Total throughput decreased 10.3 TBtu, or 1 percent.
Operating profit increased $36 million, or 22 percent, due primarily to the
revenue increases described above and $5 million lower operating and
maintenance expenses, partially offset by the effect of a $5.4 million
settlement received in 1997 related to a prior rate proceeding. Because of its
rate structure and historical maintenance schedule, Transco typically
experiences lower operating profit in the second and third quarters as compared
to the first and fourth quarters.
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<PAGE> 19
ENERGY SERVICES
ENERGY MARKETING & TRADING'S revenues decreased $558.1 million, or 37
percent, due primarily to the $676 million impact in 1998 of reporting revenues
on a net basis for certain crude oil, refined products and natural gas liquids
trading operations previously reported on a "gross" basis (see Note 2). In
addition, revenues associated with natural gas origination, price-risk
management and physical trading decreased $41 million due primarily to
unfavorable market movement against the natural gas portfolio and the adverse
market and supply conditions which resulted from Hurricane Georges in September
1998; crude oil and refined products revenues decreased $25 million including
the impact of decreased average prices associated with the marketing of refined
products from the Alaska and Memphis refineries; and energy capital revenues
were unfavorably impacted by $9.8 million of credit loss accruals. Partially
offsetting these decreases were increased power services revenue of $185 million
from power generation under a new contract, $16 million of long-term natural gas
transportation contract settlements and increased physical and notional trading
volumes. Costs and operating expenses decreased $642 million, or 44 percent, due
primarily to the impact in 1998 of reporting revenues on a net margin basis for
certain crude oil, refined products and natural gas liquids trading operations
previously reported on a "gross basis" and lower average prices associated with
refined product purchases from the Memphis and Alaska refineries, partially
offset by electric power generation costs under the new power services contract.
Selling, general and administrative expenses increased $52 million due primarily
to a $16.6 million retail energy credit loss accrual and increased staffing and
other costs associated with an expanded business base. Operating profit
increased $25.6 million, to $35.3 million in 1998, due primarily to $58 million
from power services, improved crude oil, refined products and liquids trading,
favorable long-term transportation contract settlements, and lower retail
propane operating costs. Partially offsetting these increases were a decrease in
revenues from natural gas origination, price-risk management and physical
trading activities, total 1998 credit loss accruals of $26.4 million for certain
energy capital and retail energy activities and the effect of a $6 million
recovery in 1997 of an account previously considered a bad debt. The new power
services activity is associated with a power generation plant that is normally
operational during the summer peak cooling season; therefore, operating profit
from this activity will typically be higher in the second and third quarters as
compared to the first and fourth quarters.
EXPLORATION & PRODUCTION'S revenues increased $12.3 million, or 13
percent, due primarily to the recognition of additional deferred income
resulting from a transaction that transferred certain tax credits to a third
party, partially offset by lower average natural gas sales prices for both
company-owned production and marketing of Royalty Trust volumes. Operating
profit increased $5.1 million, or 26 percent, due primarily to increased
recognition of deferred income, partially offset by $9 million higher
depreciation, depletion and amortization resulting from downward adjustments to
natural gas reserves, $5 million higher leasehold impairment expense and $3
million higher general and administrative expenses.
MIDSTREAM GAS & LIQUIDS' revenues decreased $132.5 million, or 17
percent, due primarily to the $43 million impact from the shutdown of the
Canadian marketing operations and $43 million lower natural gas liquids sales
from processing activities resulting from a decline in average liquids sales
prices. Revenues also declined due to $13 million lower natural gas liquids
pipeline transportation revenues resulting from decreased shipments, the
passthrough of $10 million lower operating costs to customers and adjustments
of $12 million related to new rates placed into effect in 1997 for Midstream's
regulated gathering activities (offset in costs and operating expenses),
slightly offset by $7 million higher gathering revenues. Costs and operating
expenses decreased $90 million, or 18 percent, due primarily to the shutdown of
the Canadian marketing operations, the rate adjustments related to Midstream's
regulated gathering activities, lower costs passed through to customers and
lower fuel and replacement gas purchases. Operating profit decreased $49.1
million, or 22 percent, due primarily to $35 million from lower per-unit
liquids margins, decreased pipeline transportation shipments, higher operating,
maintenance and depreciation expenses and $6 million of unfavorable litigation
loss provisions in 1998, partially offset by higher gathering revenues and a
gain of $6 million on the settlement of product imbalances.
PETROLEUM SERVICES' revenues increased $33.5 million, or 2 percent,
due primarily to $74 million in pipeline construction revenue and $36 million
higher convenience store merchandise sales resulting from the May 1997 EZ-Serve
acquisition and increased per store sales. In addition, revenues increased due
to $24 million higher revenues from fleet management and mobile computer
technology operations begun in mid-1997, $14 million higher ethanol sales and
$8 million higher product transportation revenues resulting primarily from an
increased average transportation rate per barrel. Partially offsetting these
increases were a $110 million decrease in revenues from refining operations and
$9 million lower product sales from transportation activities. The $14 million
higher ethanol sales reflects a 27 percent increase in sales volumes, partially
offset by a decrease in average sales prices. The $110 million decline in
refining revenues reflects $279 million from lower average sales prices,
partially offset by $169 million from a 16 percent increase in barrels sold. A
$64 million revenue increase from higher convenience store gasoline and diesel
sales volumes was offset by
18
<PAGE> 20
lower average gasoline and diesel sales prices. Costs and operating expenses
increased $34 million, or 2 percent, due primarily to $70 million of pipeline
construction costs and $24 million higher convenience store merchandise cost of
sales resulting from the EZ-Serve acquisition and increased per store sales. In
addition, costs and operating expenses increased due to $28 million higher costs
from fleet management and mobile computer technology operations, $15 million
higher convenience store operating costs resulting from the EZ-Serve acquisition
and $13 million of increased ethanol cost of sales. Largely offsetting these
increases were a $94 million decrease from refining operations, $8 million lower
cost of product sales from transportation activities and a $6 million decrease
in the cost of gasoline and diesel sales. The $94 million decrease from refining
operations reflects a $240 million decrease due to lower average crude oil
purchase prices, partially offset by $139 million due to increased processed
volumes and higher operating costs at the Memphis refinery. Selling, general and
administrative expenses increased $17 million due in part to increased
activities in human resources development, investor/media/customer relations and
business development. Other (income) expense - net in 1998 includes a $15.5
million accrual for potential transportation rate refunds to customers (see Note
3). Operating profit decreased $33.2 million, or 21 percent, due primarily to
the $15.5 million accrual for potential refunds to transportation customers, $17
million higher selling, general and administrative expenses and lower refinery
operating profit, partially offset by higher average transportation rates.
Refinery operating profit decreased due to lower per-unit refinery margins and
$6 million increased operating costs at the Memphis refinery due to higher
production levels, partially offset by 8 percent higher refinery volumes
processed.
COMMUNICATIONS
COMMUNICATIONS' revenues increased $230.2 million, or 23 percent, due
primarily to the April 30, 1997 combination of the Nortel customer premise
equipment sales and services operations which contributed an additional $196
million of revenue in 1998. In addition, revenues increased as a result of
providing off-net services to new long-term customers associated with the
fiber-optic network currently under construction. Sales order backlog at
September 30, 1998 increased $17.3 million from September 30, 1997. Costs and
operating expenses increased $170.4 million, or 23 percent, including $121
million associated with the combination with Nortel and higher costs in both the
network and network applications businesses including off-net leased capacity
costs associated with providing customer services prior to completion of the new
network. Selling, general, and administrative expenses increased $102.9 million,
or 41 percent, of which $90 million is attributable to the solutions business
which includes the combination with Nortel. Included in the overall increase are
$23 million of increased information systems costs associated with expansion and
enhancement of the infrastructure and continued costs of maintaining multiple
systems while common systems are being developed, and the expansion of the sales
infrastructure to support the new national digital fiber-optic network including
$6 million for a new national advertising campaign. The construction of the
network continues ahead of schedule and on budget. Operating profit decreased
$52.3 million to a $56.2 million operating loss in 1998, due primarily to the
increase in selling, general and administrative expenses as a percentage of
revenue resulting from the items discussed above, and $6 million of charges for
asset write-downs by the solutions business.
CONSOLIDATED
GENERAL CORPORATE EXPENSE increased $19.1 million, or 34 percent, due
primarily to MAPCO merger-related costs of $28 million, partially offset by
expense savings realized following the MAPCO merger. An additional $45.9 million
of merger-related costs are included in other (income) expense - net as a
component of Energy Services' operating profit (see Note 3). Interest accrued
increased $31.3 million, or 9 percent, due primarily to higher borrowing levels
including Williams Holdings' commercial paper program, partially offset by lower
average interest rates following the late 1997 debt restructuring. Interest
capitalized increased $13.1 million to $28.6 million, due primarily to increased
capital expenditures for the fiber-optic network, the Venezuelan gas injection
plant and international investment activities. Investing income decreased $44.2
million to a $30.7 million loss, as a result of a $23.2 million write-down
related to a network applications venture (see Note 5) and a $28 million
decrease in equity earnings primarily from international investments, slightly
offset by higher interest income on long-term notes receivable. For information
concerning the $44.5 million 1997 gain on sale of interest in subsidiary, see
Note 6. The $66 million 1997 gain on sale of assets results from the sale of
Williams' interest in the liquids and condensate reserves in the West Panhandle
field of Texas (see Note 7). Minority interest in (income) loss of consolidated
subsidiaries is $7.1 million favorable as compared to 1997 due primarily to
lower earnings experienced by Williams Communications Solutions, LLC and
allocated to the 30 percent interest held by minority shareholders. Other
expense - net is $17.7 million unfavorable as compared to 1997 due primarily to
1998 litigation loss accruals and other reserve adjustments totaling $11 million
related to assets previously sold and the impact of a 1997 gain of $4 million on
the termination of interest rate swap agreements.
The $91.9 million, or 45 percent, decrease in the provision for income
taxes is primarily a result of lower pre-tax income, partially offset by a
higher effective income tax rate in
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<PAGE> 21
1998. The effective income tax rate in 1998 exceeds the federal statutory rate
due primarily to the effects of state income taxes. The effective income tax
rate for 1997 is less than the federal statutory rate due primarily to the
effect of the non-taxable gain recognized in 1997 (see Note 6) and income tax
credits from coal-seam gas production, partially offset by the effects of state
income taxes.
The $4.8 million 1998 extraordinary loss results from the early
extinguishment of debt (see Note 9).
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
Williams Holdings' commercial paper program, which can be utilized without
limitation under existing loan covenants. At September 30, 1998, Williams had
access to $717 million of liquidity representing $318 million available under
its $1 billion bank-credit facility, $372 million of commercial paper
availability, and cash-equivalent investments. This compares with liquidity of
$166 million at December 31, 1997, and $585 million at September 30, 1997. The
lower level at December 31, 1997 reflected the use of the $1 billion
bank-credit facility to provide interim financing related to the debt
restructuring program. This restructuring program was completed during the
first quarter of 1998 and a significant portion of the $1 billion bank-credit
facility was repaid. In addition, Williams Holdings' commercial paper program,
begun in mid-1997, was expanded to $1 billion in March 1998. At September 30,
1998, $250 million of current debt obligations have been classified as
non-current obligations based on Williams' intent and ability to refinance them
on a long-term basis.
In 1998, capital expenditures and investments are estimated to be
approximately $2.3 billion. During 1998, Williams expects to finance capital
expenditures, investments, working-capital requirements and expenditures for the
year 2000 compliance project through cash generated from operations and the use
of the available portion of its $1 billion bank-credit facility, its commercial
paper program, short-term uncommitted bank lines and public debt offerings.
Financing Activities
In January 1998, Williams issued $300 million of 6.125 percent notes
due 2001 and $100 million of floating rate notes due 2000. In February 1998,
Williams issued $240 million of 6.125 percent debt remarketable in 2002 and
$300 million of 5.95 percent debt remarketable in 2000. In January 1998,
Transcontinental Gas Pipe Line issued $200 million of 6.125 percent notes and
$100 million of 6.25 percent notes due in 2005 and 2008, respectively. In July
1998, Williams issued $350 million of 6.2 percent notes due 2002 and $275
million of 6.5 percent notes due 2006. The proceeds were used for general
corporate purposes, including the repayment of outstanding debt.
The consolidated long-term debt to debt-plus-equity ratio was 59.4
percent at September 30, 1998, compared to 55.8 percent at December 31, 1997.
If short-term notes payable and long-term debt due within one year are included
in the calculations, these ratios would be 62.7 percent at September 30, 1998
and 59.1 percent at December 31, 1997.
Investing Activities
During the second quarter of 1998, Williams made a $150 million
investment in and a $100 million advance to a foreign telecommunications
business.
Other
Other Commitments
During the second quarter, Energy Marketing & Trading entered into a
15-year contract giving Williams the right to receive fuel conversion services
for purposes of generating electricity. This contract also gives Williams the
right to receive installed capacity as well as certain ancillary services.
Annual committed payments under the contract range from $140 million to $165
million, resulting in total committed payments of approximately $2.3 billion.
Williams' intent is to resell power generated as a result of this service into
markets in the western region of the United States. Williams also intends to
resell capacity and ancillary services into such markets as the opportunities
arise.
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
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<PAGE> 22
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, and testing and validation. The awareness and inventory/assessment
phases of this project as they relate to both traditional and non-traditional
information technology areas have been substantially completed except with
respect to international investments. 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
desireable but not required, and 5) unnecessary. Categories 1 - 3 were
designated as critical and are the major focus of this project.
Renovation/replacement and testing/validation of critical systems is expected to
be completed by June 30, 1999, except for replacement of certain critical
systems scheduled for completion by September 1, 1999. Certain non-critical
systems may not be compliant by January 1, 2000.
Testing and validation activities have begun and will continue
throughout the process. Year 2000 test labs are in place and operational. As
expected, few problems have been detected during testing for items believed to
be compliant. The following table indicates the approximate project status for
traditional information technology and non-traditional areas by business unit.
The tested category indicates the percentage that has been fully tested or
otherwise validated as compliant. The untested category includes items that are
believed to be compliant but which have not yet been validated. The not
compliant category includes items which have been identified as not year 2000
compliant. The unknown category includes items identified during the assessment
phase which require additional follow-up to determine whether they are
compliant.
<TABLE>
<CAPTION>
Not
Business Unit Tested Untested Compliant Unknown
- ------------- ------ -------- --------- -------
<S> <C> <C> <C> <C>
Traditional Information
Technology:
Gas Pipelines 14% 66% 20% --%
Energy Services 12 46 18 24
Communications 8 62 27 3
Corporate/Other 45 43 11 1
Non-Traditional Infor-
mation Technology:
Gas Pipelines 37 38 25 --
Energy Services 27 73 -- --
Communications 15 64 16 5
Corporate/Other 73 11 1 15
</TABLE>
Williams has initiated a formal communications process with other
companies to determine the extent to which those companies are addressing their
year 2000 compliance. In connection with this process, Williams has sent over
11,000 letters and questionnaires to third parties including customers,
vendors, service providers, etc. Additional communications are being mailed
during the fourth quarter of 1998. Williams is evaluating responses as they are
received or otherwise investigating the status of these companies' year 2000
compliance efforts. As of September 30, 1998, approximately 22 percent of the
companies contacted have responded and virtually all have indicated that they
are already compliant or will be compliant on a timely basis. Where necessary,
Williams will be working 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 expects to utilize both internal resources and external
contractors to complete the year 2000 compliance project. Existing resources
will be redeployed, and several previously planned system implementations
currently in process are scheduled for completion on or before September 1,
1999, which are expected to lessen possible year 2000 impacts. For example, a
new year 2000 compliant payroll/human resources system, scheduled to be online
January 1, 1999, will replace multiple human resources administration and
payroll processing systems currently in place. The Communications business unit
has a major service information management system implementation and other
system implementations currently in process necessary to integrate the
operations of its many components acquired in past acquisitions. These systems
will address 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. The Gas Pipelines
recently completed implementation of a new telephone system and a new common
financial system is scheduled for completion July 1, 1999. In situations where
planned system implementations will not be in service timely, alternative steps
are being taken to make existing systems compliant.
Although all critical systems over which Williams has control are
planned to be compliant and tested before the year 2000, there is a possibility
of service interruptions due to non-compliance by third parties. For example,
power failures along the communications network or transportation systems would
cause service interruptions. This risk should be minimized by the
enterprise-wide effort to communicate with and evaluate third-party compliance
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.
Contingency plans
21
<PAGE> 23
are being developed for critical business processes, critical business
partners, suppliers and system replacements that experience significant delays.
These plans are expected to be defined by August 31, 1999 and implemented where
appropriate.
Costs incurred for new software and hardware purchases are being
capitalized and other costs are being expensed as incurred. While estimates of
the total cost of Williams' enterprise-wide project continue to be refined,
Williams estimates that future costs, including any accelerated system
replacements, necessary to complete the project within the schedule described
will total approximately $50 million. Of this total, approximately $45 million
will be expensed and the remainder capitalized. 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. Approximately $7 million of costs has been expensed to date and
approximately $3 million has been capitalized. The costs of the project and the
completion dates 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 year 2000 compliance
modification plans and other factors. There can be no guarantee that these
estimates will be achieved, and actual results could differ materially from
these estimates.
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.
ITEM 3.
Quantitative and Qualitative
Disclosures About Market Risk
During the nine months ended September 30, 1998, the percent of
Williams' fixed rate debt approached targeted levels as Williams completed
issuing long-term debt under the restructuring program and reduced its variable
rate interim financings. Williams issued $1.8 billion of fixed rate debt at a
weighted average interest rate of approximately 6.2 percent (see Financing
Activities above). The debt matures $300 million in 2000, $300 million in 2001,
$900 million in 2002 and $300 million thereafter. Williams also entered into an
interest rate swap of $240 million converting fixed rate debt into variable
rate debt. The interest rate swap matures in 2002. Williams has $400 million of
interest rate locks, expiring primarily in 1998, at an average locked-in rate
of 5.4 percent referenced to underlying treasury securities having a
weighted-average maturity of 9 years.
22
<PAGE> 24
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
(b) During the third quarter of 1998, the Company filed a Form
8-K on July 22, 1998, which reported a significant event
under Item 5 of the Form and included the exhibits required
by Item 7 of the Form.
23
<PAGE> 25
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on its behalf by
the undersigned thereunto duly authorized.
THE WILLIAMS COMPANIES, INC.
-----------------------------------
(Registrant)
/s/ GARY R. BELITZ
-----------------------------------
Gary R. Belitz
Controller
(Duly Authorized Officer and
Principal Accounting Officer)
November 13, 1998
<PAGE> 26
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
Exhibit No. Description
- ---------- -----------
<S> <C>
Exhibit 12 -- Computation of Ratio of Earnings to Combined Fixed Charges
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, 1998
------------------
<S> <C>
Earnings:
Income before income taxes $277.2
Add:
Interest expense - net 347.4
Rental expense representative of interest factor 31.7
Minority interest in income of consolidated subsidiaries 5.5
Other 23.0
------
Total earnings as adjusted plus fixed charges $684.8
======
Fixed charges and preferred stock dividend requirements:
Interest expense - net $347.4
Capitalized interest 28.6
Rental expense representative of interest factor 31.7
Pretax effect of dividends on preferred stock of
the Company 9.5
------
Combined fixed charges and preferred stock dividend
requirements $417.2
======
Ratio of earnings to combined fixed charges and
preferred stock dividend requirements 1.64
======
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> SEP-30-1998
<CASH> 91,629
<SECURITIES> 0
<RECEIVABLES> 1,796,198
<ALLOWANCES> 40,231
<INVENTORY> 434,899
<CURRENT-ASSETS> 2,973,768
<PP&E> 15,829,860
<DEPRECIATION> 3,441,879
<TOTAL-ASSETS> 17,733,867
<CURRENT-LIABILITIES> 3,704,761
<BONDS> 6,323,396
0
102,164
<COMMON> 431,712
<OTHER-SE> 3,787,770
<TOTAL-LIABILITY-AND-EQUITY> 17,733,867
<SALES> 0
<TOTAL-REVENUES> 5,641,402
<CGS> 0
<TOTAL-COSTS> 4,882,221
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 23,415
<INTEREST-EXPENSE> 375,999
<INCOME-PRETAX> 277,179
<INCOME-TAX> 111,469
<INCOME-CONTINUING> 165,710
<DISCONTINUED> 0
<EXTRAORDINARY> (4,762)
<CHANGES> 0
<NET-INCOME> 160,948
<EPS-PRIMARY> .37
<EPS-DILUTED> .37
</TABLE>
