<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 March 31, 1999
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OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
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Commission file number 1-4174
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THE WILLIAMS COMPANIES, INC.
- --------------------------------------------------------------------------------
(Exact name of registrant as specified in its charter)
DELAWARE 73-0569878
- ------------------------------- -------------------------------------
(State of Incorporation) (IRS Employer Identification Number)
ONE WILLIAMS CENTER
TULSA, OKLAHOMA 74172
- --------------------------------------- -------------------------------------
(Address of principal executive office) (Zip Code)
Registrant's telephone number: (918) 573-2000
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NO CHANGE
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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 April 30, 1999
- -------------------------- -----------------------------
Common Stock, $1 par value 432,385,894 Shares
<PAGE> 2
The Williams Companies, Inc.
Index
<TABLE>
<CAPTION>
Part I. Financial Information Page
<S> <C>
Item 1. Financial Statements
Consolidated Statement of Income--Three Months
Ended March 31, 1999 and 1998 2
Consolidated Balance Sheet--March 31, 1999 and December 31, 1998 3
Consolidated Statement of Cash Flows--Three Months
Ended March 31, 1999 and 1998 4
Notes to Consolidated Financial Statements 5
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 14
Item 3. Quantitative and Qualitative Disclosures about
Market Risk 20
Part II. Other Information
Item 6. Exhibits and Reports on Form 8-K 21
Exhibit 12--Computation of Ratio of Earnings to Combined
Fixed Charges and Preferred Stock Dividend
Requirements
</TABLE>
Certain matters discussed in this report, excluding historical information,
include forward-looking statements. Although The Williams Companies, Inc.
believes such forward-looking statements are based on reasonable assumptions, no
assurance can be given that every objective will be achieved. Such statements
are made in reliance on the safe harbor protections provided under the Private
Securities Litigation Reform Act of 1995. Additional information about issues
that could lead to material changes in performance is contained in The
Williams Companies, Inc.'s 1998 Form 10-K.
1
<PAGE> 3
The Williams Companies, Inc.
Consolidated Statement of Income
(Unaudited)
<TABLE>
<CAPTION>
(Dollars in millions, except per-share amounts) Three months ended March 31,
--------------------------------------------- ---------------------------
1999 1998*
----------- -----------
<S> <C> <C>
Revenues (Note 14):
Gas Pipeline $ 466.9 $ 442.2
Energy Services (Note 2) 1,253.1 1,304.2
Communications 506.0 398.4
Other 6.2 13.7
Intercompany eliminations (248.2) (199.7)
----------- -----------
Total revenues 1,984.0 1,958.8
----------- -----------
Segment costs and expenses:
Costs and operating expenses 1,442.6 1,423.1
Selling, general and administrative expenses 304.7 235.6
Other (income) expense--net (Note 3) (2.5) 31.9
----------- -----------
Total segment costs and expenses 1,744.8 1,690.6
----------- -----------
General corporate expenses 16.9 40.8
----------- -----------
Operating income (loss) (Note 14):
Gas Pipeline 186.8 195.0
Energy Services (Note 3) 120.9 91.8
Communications (51.5) (21.6)
Other (17.0) 3.0
General corporate expenses (Note 3) (16.9) (40.8)
----------- -----------
Total operating income 222.3 227.4
Interest accrued (143.3) (118.0)
Interest capitalized 9.4 8.2
Investing income 6.7 3.7
Minority interest in income of consolidated subsidiaries (.6) (2.3)
Other income (expense)--net 1.3 (.6)
----------- -----------
Income before income taxes, extraordinary loss and
change in accounting principle 95.8 118.4
Provision for income taxes (Note 4) 39.9 45.5
----------- -----------
Income before extraordinary loss and change in
accounting principle 55.9 72.9
Extraordinary loss (Note 5) -- (4.8)
----------- -----------
Income before change in accounting principle 55.9 68.1
Change in accounting principle (Note 6) (5.6) --
----------- -----------
Net income 50.3 68.1
Preferred stock dividends 1.6 2.2
----------- -----------
Income applicable to common stock $ 48.7 $ 65.9
=========== ===========
Basic and diluted earnings per common share (Note 7):
Income before extraordinary loss and change in
accounting principle $ .12 $ .17
Extraordinary loss (Note 5) -- (.01)
----------- -----------
Income before change in accounting principle .12 .16
Change in accounting principle (Note 6) (.01) --
----------- -----------
Net income $ .11 $ .16
=========== ===========
Basic average shares (thousands) 432,091 417,347
Diluted average shares (thousands) 437,000 439,031
Cash dividends per common share $ .15 $ .15
</TABLE>
* Certain amounts have been reclassified as described in Note 2 of Notes to
Consolidated Financial Statements.
See accompanying notes.
2
<PAGE> 4
The Williams Companies, Inc.
Consolidated Balance Sheet
(Unaudited)
<TABLE>
<CAPTION>
(Dollars in millions, except per-share amounts) March 31, December 31,
--------------------------------------------- 1999 1998
------------ ------------
<S> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents $ 330.1 $ 503.3
Receivables 1,579.9 1,628.2
Transportation and exchange gas receivable 74.5 96.4
Inventories (Note 8) 533.9 497.5
Energy trading assets 323.6 354.5
Deferred income taxes 235.6 239.9
Other 228.2 212.3
------------ ------------
Total current assets 3,305.8 3,532.1
Investments 1,284.2 866.1
Property, plant and equipment, at cost 16,614.7 16,225.6
Less accumulated depreciation and depletion (3,704.2) (3,621.0)
------------ ------------
12,910.5 12,604.6
Goodwill and other intangible assets--net 635.0 583.6
Other assets and deferred charges 1,036.7 1,060.9
------------ ------------
Total assets $ 19,172.2 $ 18,647.3
============ ============
LIABILITIES AND STOCKHOLDERS EQUITY
Current liabilities:
Notes payable (Note 10) $ 1,683.8 $ 1,052.7
Accounts payable 978.3 1,158.2
Accrued liabilities 1,335.8 1,547.6
Energy trading liabilities 243.0 290.1
Long-term debt due within one year (Note 10) 691.8 390.6
------------ ------------
Total current liabilities 4,932.7 4,439.2
Long-term debt (Note 10) 6,192.4 6,366.4
Deferred income taxes 2,132.1 2,060.8
Other liabilities and deferred income 1,080.0 1,015.2
Minority interest in consolidated subsidiaries 504.5 508.3
Contingent liabilities and commitments (Note 11)
Stockholders' equity:
Preferred stock, $1 par value, 30 million shares authorized, 1.4 million
issued in 1999, 1.8 million in 1998 79.7 102.2
Common stock, $1 par value, 960 million shares authorized, 435.7 million
issued in 1999, 432.3 million in 1998 435.7 432.3
Capital in excess of par value 1,037.8 982.4
Retained earnings 2,833.5 2,849.5
Accumulated other comprehensive income 68.4 16.7
Other (79.5) (78.5)
------------ ------------
4,375.6 4,304.6
Less treasury stock (at cost), 3.8 million shares of common stock in 1999
and 4.0 million in 1998 (45.1) (47.2)
------------ ------------
Total stockholders' equity 4,330.5 4,257.4
------------ ------------
Total liabilities and stockholders' equity $ 19,172.2 $ 18,647.3
============ ============
</TABLE>
See accompanying notes.
3
<PAGE> 5
The Williams Companies, Inc.
Consolidated Statement of Cash Flows
(Unaudited)
<TABLE>
<CAPTION>
(Millions) Three months ended March 31,
--------- ----------------------------
1999 1998
------------ ------------
<S> <C> <C>
OPERATING ACTIVITIES:
Net income $ 50.3 $ 68.1
Adjustments to reconcile to cash provided from operations:
Extraordinary loss -- 4.8
Change in accounting principle 5.6 --
Depreciation, depletion and amortization 172.9 155.3
Provision for deferred income taxes 27.9 37.8
Minority interest in income of consolidated subsidiaries .6 2.3
Cash provided (used) by changes in assets and liabilities:
Receivables sold 16.0 (17.2)
Receivables 16.0 280.8
Inventories (19.4) 12.6
Other current assets (29.6) 6.1
Accounts payable (104.8) (275.6)
Accrued liabilities (226.5) (53.7)
Changes in current energy trading assets and liabilities (16.0) (.4)
Changes in non-current energy trading assets and liabilities 4.2 (2.4)
Changes in non-current deferred income 116.5 5.2
Other, including changes in non-current assets and liabilities 22.9 (12.5)
------------ ------------
Net cash provided by operating activities 36.6 211.2
------------ ------------
FINANCING ACTIVITIES:
Proceeds from notes payable 681.6 354.7
Payments of notes payable (54.8) (646.2)
Proceeds from long-term debt 727.8 1,450.1
Payments of long-term debt (598.9) (926.7)
Proceeds from issuance of common stock 82.1 41.6
Dividends paid (66.3) (64.6)
Other--net 4.8 20.0
------------ ------------
Net cash provided by financing activities 776.3 228.9
------------ ------------
INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures (376.5) (374.9)
Changes in accounts payable and accrued liabilities (92.4) (7.0)
Acquisition of business, net of cash acquired (162.9) --
Purchase of investments/advances to affiliates (353.2) (14.8)
Other--net (1.1) 7.7
------------ ------------
Net cash used by investing activities (986.1) (389.0)
------------ ------------
Increase (decrease) in cash and cash equivalents (173.2) 51.1
Cash and cash equivalents at beginning of period 503.3 122.1
------------ ------------
Cash and cash equivalents at end of period $ 330.1 $ 173.2
============ ============
</TABLE>
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' Annual Report on Form 10-K.
The accompanying financial statements have not been audited by independent
auditors, but include all adjustments both normal recurring and others which, in
the opinion of Williams' management, are necessary to present fairly its
financial position at March 31, 1999, and its results of operations and cash
flows for the three months ended March 31, 1999 and 1998.
Segment profit of operating companies may vary by quarter. Based on current
rate structures and/or historical maintenance schedules of certain of its
pipelines, Gas Pipeline experiences higher segment profits in the first and
fourth quarters as compared to the second and third quarters.
2. Basis of presentation
In the fourth-quarter 1998, Williams adopted Statement
of Financial Accounting Standards No. 131, "Disclosures about Segments of an
Enterprise and Related Information." Beginning January 1, 1999, Communications'
Network Applications 1998 segment results have been restated to include the
results of investments in certain Brazilian and Australian telecommunications
projects, which had previously been reported in Other segment revenues and
profit(loss). These investments, along with businesses previously reported as
Network Applications and certain cost-basis investments previously reported in
Network Services, are now collectively managed and reported under the name of
Strategic Investments.
Effective April 1, 1998, certain marketing activities were transferred from
other Energy Services segments to Energy Marketing & Trading and combined with
its energy risk trading operations. As a result, revenues and segment profit
amounts prior to April 1, 1998, have been reclassified and reported within
Energy Marketing & Trading. The income statement presentation relating to
certain of these operations was changed effective April 1, 1998, on a
prospective basis, to reflect these revenues net of the related costs to
purchase such items. Activity prior to this date is reflected on a "gross" basis
in the Consolidated Statement of Income. Concurrent with completing the
combination of such activities with the energy risk trading operations of Energy
Marketing & Trading, the related contract rights and obligations of certain of
these operations are recorded in the Consolidated Balance Sheet at fair value
consistent with Energy Marketing & Trading's accounting policy.
Certain other income statement and segment asset amounts have been
reclassified to conform to the current classifications.
3. Merger-related costs
In connection with the March 28, 1998, acquisition of MAPCO Inc., Williams
recognized approximately $59 million in merger-related costs comprised primarily
of outside professional fees and early retirement and severance costs in the
first quarter of 1998. Approximately $36 million of these merger-related costs
is included in other (income) expense-net within segment costs and expenses and
as a component of Energy Services' segment profit, and $23 million, unrelated to
the segments, is included in general corporate expenses.
4. Provision for income taxes
The provision for income taxes includes:
<TABLE>
<CAPTION>
Three months ended
(Millions) March 31,
-----------------------------
1999 1998
------------ ------------
<S> <C> <C>
Current:
Federal $ 7.8 $ 5.6
State 3.3 1.5
Foreign .9 .6
------------ ------------
12.0 7.7
Deferred:
Federal 23.1 32.9
State 4.8 4.9
------------ ------------
27.9 37.8
------------ ------------
Total provision $ 39.9 $ 45.5
============ ============
</TABLE>
The effective income tax rate for 1999 and 1998 is greater than the federal
statutory rate due primarily to the effects of state income taxes.
5. Extraordinary loss
In 1998, Williams paid $54.4 million to redeem higher interest rate debt for
a $4.8 million net loss (net of a $2.6 million benefit for income taxes).
5
<PAGE> 7
Notes (Continued)
6. Change in accounting principle
Effective January 1, 1999, Williams adopted Statement of Position (SOP) 98-5,
"Reporting on the Costs of Start-Up Activities." The SOP requires that all
start-up costs be expensed as incurred and the expense related to the initial
application of this SOP of $5.6 million (net of a $3.6 million benefit for
income taxes) is reported as the cumulative effect of a change in accounting
principle.
Additionally, the Emerging Issues Task Force (EITF) reached a consensus on
Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk
Management Activities" which was adopted first-quarter 1999. The effect of
initially applying the consensus at January 1, 1999, is immaterial to Williams'
results of operations and financial position.
7. Earnings per share
Basic and diluted earnings per common share are computed for the three months
ended March 31, 1999 and 1998, as follows:
<TABLE>
<CAPTION>
(Dollars in millions, except per-share Three months ended
amounts; shares in thousands) March 31,
-------------------------
1999 1998
----------- -----------
<S> <C> <C>
Income before extraordinary loss
and change in accounting principle $ 55.9 $ 72.9
Preferred stock dividends 1.6 2.2
----------- -----------
Income before extraordinary loss and
change in accounting principle
available to common stockholders
for basic earnings per share 54.3 70.7
Effect of dilutive securities:
Convertible preferred stock dividends -- 2.2
----------- -----------
Income before extraordinary loss and
change in accounting principle
available to common stockholders
for diluted earnings per share $ 54.3 $ 72.9
=========== ===========
Basic weighted-average shares 432,091 417,347
Effect of dilutive securities:
Convertible preferred stock -- 11,147
Stock options 4,909 10,537
----------- -----------
4,909 21,684
----------- -----------
Diluted weighted-average shares 437,000 439,031
=========== ===========
Earnings per common share before
extraordinary loss and change
in accounting principle:
Basic and diluted $ .12 $ .17
----------- -----------
</TABLE>
For 1999, approximately 7.7 million shares related to the assumed conversion
of $3.50 convertible preferred stock have been excluded from the computation of
diluted earnings per common share. Inclusion of these shares would be
antidilutive.
8. Inventories
<TABLE>
<CAPTION>
March 31, December 31,
(Millions) 1999 1998
------------ ------------
<S> <C> <C>
Raw materials:
Crude oil $ 56.5 $ 43.2
Other 1.7 2.0
------------ ------------
58.2 45.2
Finished goods:
Refined products 187.6 104.0
Natural gas liquids 17.5 58.6
General merchandise and
communications equipment 99.1 92.8
------------ ------------
304.2 255.4
Materials and supplies 96.2 93.4
Natural gas in underground storage 65.1 95.7
Other 10.2 7.8
------------ ------------
$ 533.9 $ 497.5
============ ============
</TABLE>
9. Investments
At December 31, 1998, Williams had investments in certain Brazilian
telecommunication ventures totaling approximately $211 million of which
approximately $150 million were preferred stock interests. Effective January 1,
1999, Williams adopted the provisions of the consensus of Emerging Issues Task
Force (EITF) Issue No. 98-13, "Accounting by an Equity Method Investor for
Investee Losses When the Investor has Loans to and Investments in Other
Securities of the Investee." Williams currently applies the equity method to
investments in common stock and certain other investments in which Williams
exercises significant influence. Previously, Williams also applied the equity
method to investments in certain other equity securities of the investee when
Williams also had an investment in the common stock of the investee.
The impact of the change for the three months ended March 31, 1999, was to
increase both income before extraordinary loss and change in accounting
principle and net income by approximately $26 million, or $.06 per share.
10. Debt and banking arrangements
NOTES PAYABLE
During 1999, Williams Holdings of Delaware, Inc. (Williams Holdings)
increased its commercial paper program to $1.4 billion, backed by a short-term
bank-credit facility. At March 31, 1999, $1.4 billion 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, Williams
Communications Solutions, LLC and Williams Communications Group, Inc. 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.
6
<PAGE> 8
NOTES (CONTINUED)
Debt
<TABLE>
<CAPTION>
Weighted-
average
interest March 31, December 31,
(Millions) rate* 1999 1998
------------ ------------ ------------
<S> <C> <C> <C>
Revolving credit loans 6.7% $ 645.0 $ 694.0
Debentures, 6.25% - 7.7%,
payable 2001 - 2027 (1) 6.4 935.4 935.4
Debentures, 8.875% - 10.25%,
payable 2003 - 2022 8.3 169.7 169.7
Notes, 5.1% - 7.6%,
payable through 2012 (2) 6.3 3,850.1 3,871.6
Notes, 8.2% - 9.625%,
payable through 2022 8.8 690.1 691.0
Notes, adjustable rate,
payable through 2004 6.1 585.0 386.7
Other, payable through 2005 8.5 8.9 8.6
------------ ------------ ------------
6,884.2 6,757.0
Current portion of long-term debt (691.8) (390.6)
------------ ------------
$ 6,192.4 $ 6,366.4
============ ============
</TABLE>
* At March 31, 1999, including the effects of interest-rate swaps.
(1) $200 million, 7.08% debentures, payable 2026, are subject to redemption at
par at the option of the debtholder in 2001.
(2) $300 million, 5.95% notes, payable 2010, and $240 million, 6.125% notes,
payable 2012, are subject to redemption at par at the option of the
debtholder in 2000 and 2002, respectively.
In April 1999, Williams' communications business entered into a $1.4 billion
temporary short-term bank-credit facility, guaranteed by Williams.
Communications expects to replace this facility with a permanent bank-credit
facility in the second quarter of 1999.
11. 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
$249 million for potential refund as of March 31, 1999.
In 1997, the Federal Energy Regulatory Commission (FERC) issued orders
addressing, among other things, the authorized rates of return for three of the
Williams interstate natural gas pipeline subsidiaries. All of the orders involve
rate cases that became effective between 1993 and 1995 and, in each instance,
these cases have been superseded by more recently filed rate cases. In the three
orders, the FERC continued its practice of utilizing a methodology for
calculating rates of return that incorporates a long-term growth rate component.
However, the long-term growth rate component used by the FERC is now a
projection of U.S. gross domestic product growth rates. Generally, calculating
rates of return utilizing a methodology which includes a long-term growth rate
component results in rates of return that are lower than they would be if the
long-term growth rate component were not included in the methodology. Each of
the three pipeline subsidiaries challenged its respective FERC order in an
effort to have the FERC change its rate of return methodology with respect to
these and other rate cases. In October 1997, the FERC voted not to reconsider an
order issued in the first of the three pipeline proceedings, and the pipeline
appealed the FERC's decision. On January 30, 1998, the FERC convened a public
conference to consider, on an industry-wide basis, issues with respect to
pipeline rates of return. In July 1998, the FERC issued orders in 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. Certain
parties are appealing the FERC's action, because the most recent formula
modification results in somewhat higher rates of return compared to the rates of
return calculated under the FERC's prior formula. In March 1999, the FERC was
granted a remand to reconsider whether the new methodology should be applied in
the first proceeding. None of the three pipelines 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 ruled on by the U.S. Court of Appeals for the D.C. Circuit, required
interstate gas pipeline companies to change the manner in which they provide
services. Williams' gas pipelines subsidiaries implemented restructurings in
1993.
The only appeal challenging Northwest Pipeline's restructuring has been
dismissed. On April 14, 1998, all appeals concerning Transcontinental Gas Pipe
Line's restructuring were denied by the D.C. Circuit. Williams Gas Pipelines
Central's restructuring appeal was remanded to the FERC. The appeal of Texas
Gas' restructuring remains pending. On February 27, 1997, the FERC issued Order
No. 636-C in response to the D.C. Circuit's partial remand of the three previous
636 orders. In that order, the FERC reaffirmed that pipelines should be exempt
from sharing gas supply realignment costs. Rehearing of Order 636-C was denied
in Order 636-D. Orders 636-C and 636-D have been appealed.
Recently, the FERC issued a Notice of Proposed Rulemaking (NOPR) and a Notice
of Inquiry (NOI), proposing revisions to regulatory policies for interstate
natural gas transportation service. In the NOPR, the FERC proposes to eliminate
the rate cap on short-term transportation services and implement regulatory
policies that are intended to maximize competition in the short-term
transportation market, mitigate the ability of firms to exercise residual
monopoly power and provide opportunities for greater flexibility in the
provision of pipeline services and to revise certain other rate and certificate
policies. In the NOI, the FERC seeks comments on its pricing policies in the
existing long-term market and pricing policies for new capacity. The deadline
for comments on the NOPR and NOI has been extended until the second quarter of
1999.
7
<PAGE> 9
Notes (Continued)
As a result of the Order 636 decisions described, each of the natural gas
pipeline subsidiaries has undertaken the reformation or termination of its
respective gas supply contracts. None of the pipelines has any significant
pending supplier take-or-pay, ratable take or minimum take claims. Central is
continuing efforts to recover certain gas supply realignment costs which arose
from supplier take-or-pay contracts.
Current FERC policy associated with Orders 436 and 500 requires interstate
gas pipelines to absorb some of the cost of reforming gas supply contracts
before allowing any recovery through direct bill or surcharges to transportation
as well as sales commodity rates. Under Orders 636, 636-A, 636-B, 636-C and
636-D, costs incurred to comply with these rules are permitted to be recovered
in full, although a percentage of such costs must be allocated to interruptible
transportation service.
Pursuant to a stipulation and agreement approved by the FERC, Williams Gas
Pipelines Central (Central) has made 17 filings to recover take-or-pay and gas
supply realignment costs of $201.3 million from its customers. An intervenor
filed a protest seeking to have the FERC review the prudence of certain of the
costs covered by these filings. On July 31, 1996, the administrative law judge
issued an initial decision rejecting the intervenor's prudency challenge. On
September 30, 1997, the FERC, by a two-to-one vote, reversed the administrative
law judge's decision and determined that three contracts were imprudently
entered into in 1982. Central filed for rehearing, and management has vigorously
defended the prudency of these contracts. An intervenor also filed a protest
seeking to have the FERC decide whether non-settlement costs are eligible for
recovery under Order No. 636. In January 1997, the FERC held that none of the
non-settlement costs and only 75 percent of settlement costs could be recovered
by Central if the costs were not eligible for recovery under Order No. 636. This
order was affirmed on rehearing in April 1997. On June 16, 1998, a FERC
administrative law judge issued an initial decision finding that Central had not
met all the tests necessary to show that these costs were eligible for recovery
under Order No. 636. On July 20, 1998, Central filed exceptions to the
administrative law judge's decision. On May 29, 1998, the FERC approved an Order
which permitted Central to conduct a reverse auction of the gas purchase
contracts which are the subject of the prudence challenges outlined above. No
party bid less than the fixed maximum price in the approved auction and, as a
result, the contracts were not assigned. In accordance with the FERC's Orders,
on September 30, 1998, Central filed a request for authority to conduct a second
reverse auction of the contracts. Under the approved reverse auction, Central
was granted authority to assign the contracts to bidders at or below an
aggregate reserve price of $112.6 million. If no unaffiliated bidders were
willing to accept assignment on those terms, Central was authorized to assign
the contracts to an affiliate or a third party and recover $112.6 million from
its customers subject to the outcome of the prudence and eligibility cases
described above. The FERC also approved an extension of the recovery mechanism
for non-settlement costs through February 1, 1999.
On January 21, 1999, Central assigned its obligations under the largest of
the three contracts to an unaffiliated third party and paid the third party $100
million. Central also agreed to pay the third party a total of $18 million in
installments over the next five years. Central received indemnities from the
third party and a release of its obligations under the contract. No parties
submitted bids at the second reverse auction, and in accordance with the tariff
provisions for the reverse auction, Central assigned the two smaller contracts
to an affiliate effective February 1, 1999. As a result of these assignments,
Central has no remaining above-market price gas contracts. Central has filed
with the FERC to recover all costs related to the three contracts.
Central has been negotiating with the FERC and state regulators to resolve
the amount of costs which are recoverable from its customers. As a result of
these negotiations, Central expensed $58 million of costs previously expected to
be recovered and capitalized as a regulatory asset in 1998. At March 31, 1999,
Central had a $57.7 million regulatory asset representing an estimate of costs
to be recovered in the future. On April 21, 1999, Central reached an agreement
in principle with the FERC staff, the state commissions, and its customers on
all issues related to recovery of Central's remaining take-or-pay and gas supply
realignment costs. The settlement resolves all prudence, eligibility and
absorption issues at a level materially consistent with Central's established
reserves at March 31, 1999, and provides that Central would be allowed to
recover the costs allocated to its customers by means of a direct bill to be
paid, in some instances, over time. The agreement in principle is subject to
complete documentation and FERC approval.
In September 1995, Texas Gas received FERC approval of a settlement regarding
Texas Gas' recovery of gas supply realignment costs. Through March 31, 1999,
Texas Gas has paid approximately $76 million and expects to pay no more than $80
million for gas supply realignment costs, primarily as a result of contract
terminations. Texas Gas has recovered approximately $66 million, plus interest,
in gas supply realignment costs.
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
8
<PAGE> 10
Notes (Continued)
the 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.
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 $160
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.
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 March 31,
1999, these subsidiaries had reserves totaling approximately $27 million for
these costs.
Certain Williams subsidiaries, including Texas Gas and Transcontinental Gas
Pipe Line, have been identified as potentially responsible parties (PRP) at
various Superfund and state waste disposal sites. In addition, these
subsidiaries have incurred, or are alleged to have incurred, various other
hazardous materials removal or remediation obligations under environmental laws.
Although no assurances can be given, Williams does not believe that these
obligations or the PRP status of these subsidiaries will have a material adverse
effect on its financial position, results of operations or net cash flows.
Transcontinental Gas Pipe Line, Texas Gas and Central have identified
polychlorinated biphenyl (PCB) contamination in air compressor systems, soils
and related properties at certain compressor station sites. Transcontinental Gas
Pipe Line, Texas Gas and Central have also been involved in negotiations with
the U.S. Environmental Protection Agency (EPA) and state agencies to develop
screening, sampling and cleanup programs. In addition, negotiations with certain
environmental authorities and other programs concerning investigative and
remedial actions relative to potential mercury contamination at certain gas
metering sites have been commenced by Central, Texas Gas and Transcontinental
Gas Pipe Line. As of March 31, 1999, Central had recorded a liability for
approximately $12 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 $10 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
$27 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 March 31, 1999, WES and its
subsidiaries had reserves, in addition to the reserves listed above, totaling
approximately $31 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 March 31, 1999, WES and its subsidiaries had receivables totaling
$14 million.
In connection with the 1987 sale of the assets of Agrico Chemical Company,
Williams agreed to indemnify the purchaser for environmental cleanup costs
resulting from certain conditions at specified locations, to the extent such
costs exceed a specified amount. At March 31, 1999, 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 affirmed the
9
<PAGE> 11
Notes (Continued)
dismissal and remanded the case to Colorado district court for action consistent
with the appeals court's decision. Since June 1994, eight individual lawsuits
were filed against Northwest Pipeline and others in U.S. district court in
Colorado, making essentially the same claims. The district court stayed all of
the cases involving Northwest Pipeline until the plaintiffs exhausted their
remedies before the Southern Ute Indian Tribal Court. Some plaintiffs filed
cases in the Tribal Court, but none named Northwest Pipeline as a defendant. The
parties have now executed a settlement agreement which settles all Federal and
Tribal cases.
Other legal matters
On April 7, 1992, a liquefied petroleum gas explosion occurred near an
underground salt dome storage facility located near Brenham, Texas and owned by
an affiliate of MAPCO Inc., Seminole Pipeline Company ("Seminole"). MAPCO Inc.,
as well as Seminole, Mid-America Pipeline Company, MAPCO Natural Gas Liquids
Inc., and other non-MAPCO entities were named as defendants in civil action
lawsuits filed in state district courts located in four Texas counties. Seminole
and the above-mentioned subsidiaries of MAPCO Inc. have settled in excess of
1,600 claims in these lawsuits. As of January 1999, the only lawsuit not fully
resolved was the Dallmeyer case which was tried before a jury in Harris County.
In Dallmeyer, the judgment rendered in March 1996 against defendants Seminole
and MAPCO Inc. and its subsidiaries totaled approximately $72 million which
included nearly $65 million of punitive damages awarded to the 21 plaintiffs.
Both plaintiffs and defendants have appealed the Dallmeyer judgment to the Court
of Appeals for the Fourteenth District of Texas in Harris County. In February
and March 1998, the defendants entered into settlement agreements involving 17
of the 21 plaintiffs to finally resolve their claims against all defendants for
an aggregate payment of approximately $10 million. These settlements have
satisfied and reduced the judgment on appeal by approximately $42 million as to
the remaining four plaintiffs. The Court of Appeals issued its decision on
October 15, 1998, which, while denying all of the plaintiffs' cross-appeal
issues, affirmed in part and reversed in part the trial court's judgment. The
defendants had entered into settlement agreements with the remaining plaintiffs
which, in light of the decisions, provided for aggregate payments of
approximately $13.6 million, the full amount of which has been previously
accrued. The releases from the last remaining plaintiffs were received in
February 1999.
In 1991, the Southern Ute Indian Tribe (the Tribe) filed a lawsuit against
Williams Production Company (Williams Production), a wholly owned subsidiary of
Williams, and other gas producers in the San Juan Basin area, alleging that
certain coal strata were reserved by the United States for the benefit of the
Tribe and that the extraction of coal-seam gas from the coal strata was
wrongful. The Tribe seeks compensation for the value of the coal-seam gas. The
Tribe also seeks an order transferring to the Tribe ownership of all of the
defendants' equipment and facilities utilized in the extraction of the coal-seam
gas. In September 1994, the court granted summary judgment in favor of the
defendants, and the Tribe lodged an interlocutory appeal with the U.S. Court of
Appeals for the Tenth Circuit. Williams Production agreed to indemnify the
Williams Coal Seam Gas Royalty Trust (Trust) against any losses that may arise
in respect of certain properties subject to the lawsuit. On July 16, 1997, the
U.S. Court of Appeals for the Tenth Circuit reversed the decision of the
district court, held that the Tribe owns the coal-seam gas produced from certain
coal strata on fee lands within the 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
Supreme Court granted a writ of certiorari in respect of this decision and heard
oral arguments on April 19, 1999. Williams Production has entered into an
agreement in principle to settle the Tribe's claims against Williams Production.
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
10
<PAGE> 12
Notes (Continued)
currently defending two lawsuits brought by producers. In one of the cases, a
jury verdict found that Transcontinental Gas Pipe Line was required to pay a
producer damages of $23.3 million including $3.8 million in attorneys' fees.
Transcontinental Gas Pipe Line is pursuing an appeal. In the other case, a
producer has asserted damages, including interest calculated through December
31, 1997, of approximately $6 million. Producers have received and may receive
other demands, which could result in additional claims. Indemnification for
royalties will depend on, among other things, the specific lease provisions
between the producer and the lessor and the terms of the settlement between the
producer and either Transcontinental Gas Pipe Line or Texas Gas. Texas Gas may
file to recover 75 percent of any such additional amounts it may be required to
pay pursuant to indemnities for royalties under the provisions of Order 528.
In connection with the sale of certain coal assets in 1996, MAPCO entered
into a Letter Agreement with the buyer providing for indemnification by MAPCO
for reductions in the price or tonnage of coal delivered under a certain
pre-existing Coal Sales Agreement dated December 1, 1986. The Letter Agreement
is effective for reductions during the period July 1, 1996, through December 31,
2002, and provides for indemnification for such reductions as incurred on a
quarterly basis. The buyer has stated it is entitled to indemnification from
MAPCO for amounts of $7.8 million through June 30, 1998, and may claim
indemnification for additional amounts in the future. MAPCO has filed for
declaratory relief as to certain aspects of the buyer's claims. MAPCO also
believes it would be entitled to substantial set-offs and credits against any
amounts determined to be due and has accrued a liability representing an
estimate of amounts it expects to incur in satisfaction of this indemnity. The
parties are currently pursuing settlement negotiations as a part of a mediation.
In 1998, the United States Department of Justice informed Williams that Jack
Grynberg, an individual, had filed claims in the United States District Court
for the District of Colorado under the False Claims Act against Williams and
certain of its wholly owned subsidiaries including Williams Gas Pipelines
Central, Kern River Gas Transmission, Northwest Pipeline, Williams Gas Pipeline
Company, Transcontinental Gas Pipe Line Corporation, Texas Gas, Williams Field
Services Company and Williams Production Company. Mr. Grynberg has also filed
claims against approximately 300 other energy companies and alleges that the
defendants violated the False Claims Act in connection with the measurement and
purchase of hydrocarbons. The relief sought is an unspecified amount of
royalties allegedly not paid to the federal government, treble damages, a civil
penalty, attorneys' fees, and costs. On April 9, 1999, the United States
Department of Justice announced that it was declining to intervene in any of the
Grynberg qui tam cases, including the action filed against the Williams entities
in the United States District Court for the District of Colorado.
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 1998, Energy Marketing & Trading entered into a 15-year contract
giving Williams the right to receive fuel conversion and certain other services
for purposes of generating electricity. Annual committed payments under this
contract range from $140 million to $165 million, resulting in total committed
payments of approximately $2.3 billion.
During the first quarter of 1999, Energy Marketing & Trading entered into a
similar contract with a 20 year term. Annual committed payments under this
contract, which is scheduled to commence in mid-2001, range from $39 million to
$55 million resulting in additional committed payments of approximately $950
million.
12. Adoption of accounting standards
The Financial Accounting Standards Board has issued Statement on Financial
Accounting Standard (SFAS) No. 133, "Accounting for Derivative Instruments and
Hedging Activities." This standard, effective for fiscal years beginning after
June 15, 1999, requires that all derivatives be recognized as assets or
liabilities in the balance sheet and that those instruments be measured at fair
value. The effect of this standard on Williams' results of operations and
financial position is still being evaluated.
13. Comprehensive income
Comprehensive income for the three months ended March 31 is as follows:
<TABLE>
<CAPTION>
Three months ended
(Millions) March 31,
1999 1998
------------ ------------
<S> <C> <C>
Net income $ 50.3 $ 68.1
Other comprehensive income (loss):
Unrealized gains on securities 120.6 13.3
Foreign currency translation
adjustments (22.0) (2.1)
------------ ------------
Other comprehensive income
before taxes 98.6 11.2
Income taxes on other
comprehensive income 46.9 5.2
------------ ------------
Comprehensive income $ 102.0 $ 74.1
============ ============
</TABLE>
11
<PAGE> 13
Notes (Continued)
14. Segment disclosures
Williams evaluates performance based upon segment profit or loss from
operations which includes revenues from external and internal customers, equity
earnings, operating costs and expenses, and depreciation, depletion and
amortization. Intersegment sales are generally accounted for as if the sales
were to unaffiliated third parties, that is, at current market prices.
Williams' reportable segments are strategic business units that offer
different products and services. The segments are managed separately because
each segment requires different technology, marketing strategies and industry
knowledge. Other includes investments in international energy and
communications-related ventures, as well as corporate operations.
The following table reflects the reconciliation of segment profit, per the
table on page 13, to operating income as reported in the Consolidated Statement
of Income for the three months ended March 31:
<TABLE>
<CAPTION>
(Millions) 1999 1998
---------- ----------
<S> <C> <C>
Segment profit $ 239.2 $ 268.2
General corporate expenses (16.9) (40.8)
---------- ----------
Operating income $ 222.3 $ 227.4
========== ==========
</TABLE>
The increase in Strategic Investments' total assets, as noted on the
following page, is due primarily to the additional investments in a Brazilian
telecommunications project and the increase in the carrying value of a
marketable equity security.
12
<PAGE> 14
Notes (Continued)
14. Segment disclosures (continued)
<TABLE>
<CAPTION>
Revenues
-------------------------------------------------------------
External Inter- Equity Earnings Segment
(Millions) Customers segment (Losses) Total Profit (Loss)
------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
FOR THE THREE MONTHS ENDED MARCH 31, 1999
GAS PIPELINE $ 452.3 $ 14.5 $ .1 $ 466.9 $ 186.8
ENERGY SERVICES
Energy Marketing & Trading 515.6 (43.5)* (.1) 472.0 40.7
Exploration & Production 1.2 26.3 -- 27.5 4.7
Midstream Gas & Liquids 193.1 26.9 (2.3) 217.7 46.6
Petroleum Services 334.4 201.3 .2 535.9 33.0
Merger-related costs and
non-compete amortization -- -- -- -- (4.1)
------------ ------------ ------------ ------------ ------------
1,044.3 211.0 (2.2) 1,253.1 120.9
------------ ------------ ------------ ------------ ------------
COMMUNICATIONS
Communications Solutions 337.3 -- -- 337.3 (8.8)
Network Services 95.8 12.7 -- 108.5 (17.2)
Strategic Investments 68.1 .2 (8.1) 60.2 (25.5)
------------ ------------ ------------ ------------ ------------
501.2 12.9 (8.1) 506.0 (51.5)
------------ ------------ ------------ ------------ ------------
OTHER 12.8 9.8 (16.4) 6.2 (17.0)
ELIMINATIONS -- (248.2) -- (248.2) --
------------ ------------ ------------ ------------ ------------
TOTAL $ 2,010.6 $ -- $ (26.6) $ 1,984.0 $ 239.2
============ ============ ============ ============ ============
FOR THE THREE MONTHS ENDED MARCH 31, 1998
GAS PIPELINE $ 430.3 $ 11.9 $ -- $ 442.2 $ 195.0
ENERGY SERVICES
Energy Marketing & Trading 408.7 71.9 (1.1) 479.5 15.5
Exploration & Production 11.8 28.8 -- 40.6 12.3
Midstream Gas & Liquids 219.4 18.5 1.5 239.4 66.3
Petroleum Services 505.8 38.8 .1 544.7 33.6
Merger-related costs and
non-compete amortization -- -- -- -- (35.9)
------------ ------------ ------------ ------------ ------------
1,145.7 158.0 .5 1,304.2 91.8
------------ ------------ ------------ ------------ ------------
COMMUNICATIONS
Communications Solutions 327.4 -- -- 327.4 3.3
Network Services 9.1 12.1 -- 21.2 (7.9)
Strategic Investments 50.2 1.1 (1.5) 49.8 (17.0)
------------ ------------ ------------ ------------ ------------
386.7 13.2 (1.5) 398.4 (21.6)
------------ ------------ ------------ ------------ ------------
OTHER (4.4) 16.6 1.5 13.7 3.0
ELIMINATIONS -- (199.7) -- (199.7) --
------------ ------------ ------------ ------------ ------------
TOTAL $ 1,958.3 $ -- $ .5 $ 1,958.8 $ 268.2
============ ============ ============ ============ ============
</TABLE>
<TABLE>
<CAPTION>
TOTAL ASSETS
-----------------------------------
(Millions) March 31, 1999 December 31, 1998
-------------- -----------------
<S> <C> <C>
GAS PIPELINE $ 8,261.8 $ 8,386.2
ENERGY SERVICES
Energy Marketing & Trading 2,599.2 2,596.8
Exploration & Production 451.9 484.1
Midstream Gas & Liquids 3,343.6 3,201.8
Petroleum Services 2,511.6 2,525.2
-------------- --------------
8,906.3 8,807.9
-------------- --------------
COMMUNICATIONS
Communications Solutions 944.8 946.4
Network Services 780.8 712.9
Strategic Investments 1,102.8 638.4
-------------- --------------
2,828.4 2,297.7
-------------- --------------
OTHER 5,393.3 4,782.4
ELIMINATIONS (6,217.6) (5,626.9)
-------------- --------------
TOTAL $ 19,172.2 $ 18,647.3
============== ==============
</TABLE>
* Energy Marketing & Trading intercompany cost of sales, which are netted in
revenues consistent with fair-value accounting, exceed intercompany revenues.
13
<PAGE> 15
15. Subsequent event
On April 9, 1999, Williams' communications business filed a registration
statement for an initial public equity offering which is expected to yield
proceeds of $500 million to $750 million, representing a minority interest in
its communications business. During the first quarter of 1999, Williams
announced that simultaneously with the public equity offering, SBC
Communications plans to acquire up to a 10 percent interest in Williams'
communications business for an investment up to $500 million. In addition,
Communications is expected to issue high-yield public debt of $1.3 billion in
1999. Proceeds will be reinvested in the continued construction of Williams'
national fiber-optic network and other expansion opportunities.
ITEM 2
Management's Discussion and Analysis of
Financial Condition and Results of Operations
Results of Operations
First Quarter 1999 vs. First Quarter 1998
CONSOLIDATED OVERVIEW
Williams' revenues increased $25 million, or 1 percent, due primarily to
Communications' sales of excess fiber capacity and new business growth on the
fiber-optic network, increased revenues from retail natural gas and electric
activities following a late 1998 acquisition and higher power services revenues.
Partially offsetting these increases were the $84 million effect in 1999 of
reporting certain revenues net of costs within Energy Services (see Note 2 of
the Notes to the Consolidated Financial Statements) and continued lower
petroleum products and natural gas liquids sales prices.
Segment costs and expenses increased $54 million, or 3 percent, due
primarily to higher costs and expenses within Communications, higher costs from
retail natural gas and electric activities following a late 1998 acquisition and
higher power services costs. Partially offsetting these increases were the $84
million impact in 1999 of reporting certain costs net in revenues within Energy
Services (see Note 2), lower purchase prices for petroleum products and the
effect in 1998 of Mapco merger-related costs totaling $59 million (including $23
million within general corporate expenses).
Operating income decreased $5 million, or 2 percent, comprised primarily of a
$30 million decrease at Communications, reflecting losses from international
ventures in initial operations and infrastructure growth and improvement, and a
$21 million decrease from International activities, reflecting losses from
start-up operations. Partially offsetting these decreases was the effect in 1998
of MAPCO merger-related costs totaling $59 million. Income before income taxes,
extraordinary loss and change in accounting principle decreased $23 million due
primarily to $24 million higher net interest expense reflecting continued
expansion and new projects.
GAS PIPELINES
GAS PIPELINE'S revenues increased $24.7 million, or 6 percent, and costs and
operating expenses increased $20 million, or 11 percent, due primarily to the
settlement of an historical gas exchange imbalance.
Segment profit decreased $8.2 million, or 4 percent, due primarily to the
effect of a $3.4 million gain in 1998 from the sale-in-place of natural gas from
a decommissioned storage field and $6 million higher general and administrative
expenses in 1999, including expenses related to information system initiatives
and a $2.3 million accrual for damages associated with two pipeline ruptures in
the northwest.
Based on current rate structures and/or historical maintenance schedules of
certain of its pipelines, Gas Pipeline experiences higher segment profits in the
first and fourth quarters as compared with the second and third quarters.
During 1998, the Federal Energy Regulatory Commission (FERC) issued several
rulings that could result in higher tariff rates in future periods for Gas
Pipeline. These FERC rulings are subject to appeal (see Note 11).
14
<PAGE> 16
ENERGY SERVICES
ENERGY MARKETING & TRADING'S revenues decreased $7.5 million, or 2 percent,
due primarily to the $84 million impact in 1999 of reporting revenues on a net
basis for certain natural gas liquids trading operations previously reported on
a "gross" basis (see Note 2). Excluding this decrease, revenues increased $77
million due primarily to $68 million higher revenues from retail natural gas and
electric activities following the late 1998 acquisition of Volunteer Energy and
$53 million higher electric power services revenues from new activity in
southern California, partially offset by a $45 million decrease in revenues
associated with crude and refined products marketing and trading. The $45
million decrease from crude and refined products activities reflects $79 million
from lower average sales prices from crude and refined products marketing
activities, partially offset by $19 million from increased volumes sold and $15
million higher net revenues associated with crude and refined products trading
activities.
Costs and operating expenses decreased $49 million, or 11 percent, due
primarily to the $84 million impact in 1999 of reporting revenues on a net basis
for certain natural gas liquids trading operations previously reported on a
"gross" basis (see Note 2). In addition, costs associated with crude and refined
products marketing activities decreased $59 million reflecting lower average
product purchase prices, partially offset by increased volumes purchased.
Partially offsetting these decreases were $62 million of higher costs following
the late 1998 acquisition of Volunteer Energy and $40 million of costs related
to new electric power activity in southern California. Selling, general and
administrative expenses increased $16 million reflecting growth in electric
power services operations, the Volunteer Energy acquisition and higher
compensation levels associated with improved operating performance.
Segment profit increased $25.2 million, to $40.7 million in 1999 from $15.5
million in 1998, due primarily to $8 million higher electric power marketing
and trading profits and $12 million higher profits from crude and refined
products marketing and trading. In addition, retail propane profits increased $7
million reflecting a 13 percent increase in propane volumes combined with
improved per-unit propane margins resulting from favorable weather conditions.
EXPLORATION & PRODUCTION'S revenues decreased $13.1 million, or 32 percent,
due primarily to lower average natural gas sales prices for both company-owned
production and sales of volumes from the Williams Coal Seam Gas Royalty Trust
and royalty interest owners. In addition, revenues decreased due to a $4 million
reduction in deferred income recognized from a 1997 transaction that transferred
certain nonoperating economic benefits to a third party, partially offset by a
$2 million increase resulting from 13 percent higher company-owned production
volumes.
Segment profit decreased $7.6 million, or 62 percent, due primarily to the
$4 million reduction in deferred income recognition, a $5 million unfavorable
effect of lower average natural gas sales prices for company-owned production
and $2 million higher leasehold impairment expense, partially offset by $3
million lower dry hole costs and the 13 percent increase in company-owned
production volumes.
MIDSTREAM GAS & LIQUIDS' revenues decreased $21.7 million, or 9 percent, due
primarily to $8 million lower natural gas liquids sales from processing
activities, $3 million lower natural gas liquids pipeline transportation
revenues resulting from decreased shipments, $4 million lower condensate
revenues following processing plant shutdowns during 1999 and $4 million lower
equity earnings primarily from the Discovery pipeline project. The $8 million
lower natural gas liquids sales reflects $14 million from lower average liquids
sales prices, partially offset by $6 million from a 14 percent increase in
liquids volumes sold.
Segment profit decreased $19.7 million, or 30 percent, due primarily to $9
million lower per-unit liquids margins, lower pipeline transportation revenues
and equity earnings and increased costs and expenses, partially offset by the
effect of a $3 million litigation accrual in 1998.
PETROLEUM SERVICES' revenue decreased $8.8 million, or 2 percent, due
primarily to $41 million lower revenues from refining operations and $8 million
lower ethanol sales, largely offset by $18 million higher convenience store
revenues, $12 million higher revenues from fleet management and mobile computer
technology operations and $7 million higher transportation and terminalling
revenues. The $41 million decline in refining revenues reflects $65 million from
lower average sales prices because of lower crude costs, partially offset by $24
million from a 9 percent increase in refined product volumes sold. The $18
million increase in convenience store sales reflects $25 million from increased
gasoline and diesel sales volumes and $11 million higher merchandise sales due
to additional stores, partially offset by the $18 million effect of lower
average retail gasoline and diesel sales prices.
Costs and operating expenses decreased $9 million, or 2 percent, due
primarily to $43 million lower refinery crude oil purchases, partially offset by
$10 million higher costs from the fleet management and mobile computer
technology operations,
15
<PAGE> 17
$13 million higher convenience store cost of sales, $8 million higher
convenience store operating costs and $4 million higher refinery operating
costs. The $43 million lower crude oil purchase costs reflects $62 million from
lower average crude oil prices, partially offset by $19 million related to an
increase in processed barrels sold. The $13 million higher convenience store
cost of sales reflects $23 million from increased gasoline and diesel sales
volumes and $6 million of higher merchandise cost of sales, partially offset by
$16 million from lower average gasoline and diesel prices.
Segment profit decreased $.6 million, or 2 percent, due primarily to $5
million lower profits from the refining and retail operations and $6 million
higher general and administrative expenses, substantially offset by $6 million
higher profits from the transportation and terminalling operations and the
recovery of $4 million of environmental expenses previously incurred.
COMMUNICATIONS
COMMUNICATIONS SOLUTIONS' revenues increased by $9.9 million, or 3 percent,
due primarily to $14 million higher new system sales and upgrades, partially
offset by $9 million lower customer service orders resulting, in part, from
competitive pressures.
Segment profit decreased $12.1 million, from a $3.3 million segment profit
in 1998 to an $8.8 million segment loss in 1999, due primarily to $16 million
higher selling, general and administrative expenses including $7 million
increased provision for uncollectible trade receivables and higher costs
necessary to improve managing and integrating complex business operations and
systems.
NETWORK SERVICES' revenues increased $87.3 million, from $21.2 million in
1998, due primarily to $51 million of revenue in 1999 from the sale of excess
dark fiber capacity on the newly constructed digital fiber-optic network and $32
million from business growth.
Costs and operating expenses increased $90 million, from $18 million in
1998, due primarily to $41 million of construction costs associated with the
sale of dark fiber, $29 million higher leased capacity costs associated with
providing customer services prior to completion of the new network and $6
million higher operations and maintenance expenses.
Segment loss increased $9.3 million, from a $7.9 million loss in 1998 to a
$17.2 million loss in 1999, due primarily to losses experienced from providing
customer services prior to completion of the new network and the cost of
expanding the infrastructure in support of the network expansion, partially
offset by $10.5 million of profit from selling excess fiber capacity.
As each phase of the on-going construction of the planned 32,000 mile
full-services wholesale communications network goes into service, revenues and
costs are expected to increase. During 1998, 9,000 miles of new network were
added increasing the network to 19,000 cable miles at December 31, 1998. At
March 31, 1999, the network had increased to 20,000 cable miles. The remaining
12,000 miles are planned to come online during the rest of 1999 and 2000. The
February 8, 1999, announcement by Williams of a 20-year agreement with SBC
Communications, under which Network Services will become the preferred provider
of nationwide long-distance voice and data services for SBC Communications, will
contribute to the expected network revenue increase in 2000. Additional sales of
excess dark fiber capacity along the new network are expected to generate
increasing revenues and serve as a funding source for continued infrastructure
growth and construction.
STRATEGIC INVESTMENTS' revenues increased $10.4 million, or 21 percent, due
primarily to $15 million of revenue contributed by the August 1998 acquisition
of an Australian telecommunications company, partially offset by equity
investment losses of $8 million from ATL - Algar Telecom Leste S.A. (ATL), a
Brazilian telecommunications business in initial operations.
Costs and operating expenses increased $13 million, or 27 percent, and
selling, general and administrative expenses increased $6 million, or 30
percent, due primarily to the Australian acquisition.
Segment loss increased $8.5 million, or 50 percent, due primarily to
start-up activities in the Australian and Brazilian telecommunications
businesses, partially offset by a $6 million decrease in losses from video
transmission services. Management is currently assessing some of its business
activities within this segment which may ultimately result in the impairment of
or the sale of some of these businesses. Preliminary estimates are that such
impairment charges or losses for the activities under review approximate $30
million. No definitive agreements or formal plans have been reached relating to
the businesses under review.
OTHER
OTHER segment loss of $17 million in 1999 compares to a segment profit of
$3 million in 1998, due primarily to $18 million higher international equity
investment losses, including $14 million from investing activities in another
Brazilian communications company in which Williams has approximately a 5 percent
common equity interest. The equity losses result primarily from start-up
operations of certain communications ventures within this company.
16
<PAGE> 18
CONSOLIDATED
GENERAL CORPORATE EXPENSES decreased $23.9 million, or 59 percent, due
primarily to $23 million of MAPCO merger-related costs included in first-quarter
1998 general corporate expenses. An additional $36 million of merger-related
costs are included in 1998 as a component of Energy Services' segment profit
(see Note 3). Interest accrued increased $25.3 million, or 21 percent, due
primarily to higher borrowing levels including Williams Holdings' commercial
paper program and the issuance of additional public debt. Investing income
increased $3 million, to $6.7 million, due primarily to higher interest income
on advances to affiliates.
The $5.6 million, or 12 percent, decrease in the provision for income taxes
is primarily a result of lower pre-tax income. The effective tax rate in 1999
and 1998 exceeds the federal statutory rate due primarily to the effects of
state income taxes.
The $4.8 million 1998 extraordinary loss results from the early
extinguishment of debt (see Note 5).
The $5.6 million 1999 change in accounting principle relates to the adoption
of Statement of Position 98-5, "Reporting on the Costs of Start-Up Activities"
(see Note 6).
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 March 31, 1999, Williams had access
to $512 million of liquidity including $355 million available under its $1
billion bank-credit facility and $149 million of cash-equivalent investments.
This compares with liquidity of $738 million at December 31, 1998, and $1.2
billion at March 31, 1998.
Registration statements have been filed with the Securities and Exchange
Commission by Williams and Williams Holdings of Delaware, Northwest Pipeline,
Texas Gas Transmission and Transcontinental Gas Pipeline (each a wholly owned
subsidiary of Williams). Approximately $2.1 billion of shelf availability,
including the registration of $975 million effective in April 1999, remains
under these outstanding registration statements and may be used to issue a
variety of debt or equity securities. Williams believes any additional financing
arrangements can be obtained on reasonable terms if required.
On April 9, 1999, Williams' communications business filed a registration
statement for an initial public equity offering which is expected to yield
proceeds of $500 million to $750 million, representing a minority interest in
its communications business. During first-quarter 1999, Williams announced that
simultaneously with the public equity offering, SBC Communications plans to
acquire up to a 10 percent interest in Williams' communications business for an
investment up to $500 million. In addition, Communications is expected to issue
high-yield public debt of $1.3 billion in 1999 under a registration statement
currently in process. Proceeds from these equity and debt transactions will be
reinvested in the continued construction of Williams' national fiber-optic
network and other expansion opportunities. Also in April, Williams'
communications business entered into a $1.4 billion interim short-term
bank-credit facility expected to be replaced with a permanent bank-credit
facility in the second quarter of 1999.
In addition, a total of $419 million remains available under Williams'
securitized asset lease program designed to fund up to $750 million of capital
expenditures for the fiber-optic network.
In 1999, capital expenditures and investments are estimated to be
approximately $5 billion. Williams expects to finance capital expenditures,
investments and working-capital requirements through cash generated from
operations, Communications' initial equity and high-yield debt offerings, and
the use of the available portion of its $1 billion bank-credit facility and
asset lease program, commercial paper, short-term uncommitted bank lines,
private borrowings and debt or equity public offerings.
Financing Activities
In January 1999, Williams Holdings increased its commercial paper program to
$1.4 billion from $1 billion. The commercial paper program is backed by a $1.4
billion short-term bank-credit facility. At March 31, 1999, $1.4 billion of
commercial paper was outstanding under the program. Also in January 1999,
Williams entered into a $200 million adjustable rate term loan due 2004. 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 58.8 percent
at March 31, 1999, compared to 59.9 percent at December 31, 1998. If short-term
notes payable and long-term debt due within one year are included in the
calculations, these ratios would be 66.4 percent at March 31, 1999 and 64.7
percent at December 31, 1998.
17
<PAGE> 19
Investing Activities
During first-quarter 1999, Williams exercised an option to increase its
investment in ATL, a Brazilian telecommunications business, by an additional 35
percent equity interest for $265 million. This investment was funded through
borrowings under the $1 billion bank-credit facility. Also in first-quarter
1999, Williams purchased a company with an ethylene plant and natural gas
liquids transportation, storage and other facilities for $163 million in cash.
Operating Activities
The decrease in accounts payable and accrued liabilities is due primarily to
the payment in 1999 of $113 million of rate refunds to natural gas
transportation customers, $100 million in connection with the assignment of
Williams' obligations under a gas purchase contract to an unaffiliated third
party (see Note 11), and $84 million pursuant to a wireless fiber capacity
agreement.
Year 2000 Compliance
Williams initiated an enterprise-wide project in 1997 to address the year
2000 compliance issue for both traditional information technology areas and
non-traditional areas, including embedded technology which is prevalent
throughout the company. This project focuses on all technology hardware and
software, external interfaces with customers and suppliers, operations process
control, automation and instrumentation systems, and facility items. The phases
of the project are awareness, inventory and assessment, renovation and
replacement, testing and validation. 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. During the
inventory and assessment phase, all systems with possible year 2000 implications
were inventoried and classified into five categories: 1) highest, business
critical, 2) high, compliance necessary within a short period of time following
January 1, 2000, 3) medium, compliance necessary within 30 days from January 1,
2000, 4) low, compliance desirable but not required, and 5) unnecessary.
Categories 1 through 3 were designated as critical and are the major focus of
this project. 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 later in 1999. Some 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 project status as of March 31, 1999, 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.
<TABLE>
<CAPTION>
Not
Business Unit Tested Untested Compliant
------------- ---------- ---------- ----------
<S> <C> <C> <C>
Traditional Information
Technology:
Gas Pipeline 80% 7% 13%
Energy Services 74 23 3
Communications 58 24 18
Corporate/Other 86 11 3
Non-Traditional
Information Technology:
Gas Pipeline 79 10 11
Energy Services 68 28 4
Communications 74 20 6
Corporate/Other 93 7 0
</TABLE>
Williams initiated a formal communications process with other companies in
1998 to determine the extent to which those companies are addressing year 2000
compliance. In connection with this process, Williams has sent approximately
15,600 letters and questionnaires to third parties including customers, vendors
and service providers. Williams is evaluating responses as they are received or
otherwise investigating the status of these companies' year 2000 compliance
efforts. As of March 31, 1999, approximately 40 percent of the companies
contacted have responded and virtually all of these 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. Williams has a core group of 279
people involved in this enterprise-wide project. This includes 16 individuals
responsible for coordinating, organizing, managing, communicating, and
monitoring the project and another 263 staff members responsible for completing
the project. Depending on which phase the project is in and what area is being
focused on at any given point in time, there can be an additional 500 to 1,200
employees who are also contributing a portion of their time to the completion of
this project. The Communications business unit has contracted with an external
contractor at a cost of approximately $3 million to assist in all phases and
various areas of the project. Gas Pipeline has contracted with an external
contractor for a cost of up to $6 million for the remediation of its customer
service software. Within Energy Services, two external contractors are being
utilized at a total cost of approximately $2 million.
18
<PAGE> 20
Several previously planned system implementations are scheduled for
completion during 1999, which will lessen possible year 2000 impacts. For
example, a new year 2000 compliant payroll/human resources system was
implemented January 1, 1999. It replaced multiple human resources administration
and payroll processing systems previously 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
are coming online in stages and 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. Those applications have been incorporated into the enterprise-wide
project and remaining system replacements are proceeding on schedule. In
addition, the Petroleum Services business unit of Energy Services is replacing
its ATLAS and revenue billing systems. The planned implementation date for this
has been delayed from the summer of 1999, to October 1, 1999. Gas Pipeline
completed implementation of a new telephone system in 1998, and a new common
financial system is scheduled for completion July 1, 1999 at one of the
pipelines. In situations where planned system implementations will not be in
service timely or are delayed past an implementation date of September 1, 1999,
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, Williams has identified two areas
that would equate to a most reasonably likely worst case scenario. First is the
possibility of service interruptions due to non-compliance by third parties. For
example, power failures along the communications network or transportation
systems would cause service interruptions. This risk should be minimized by the
enterprise-wide communications effort and evaluation of 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.
It is not possible to quantify the possible financial impact if this most
reasonably likely worst case scenario were to come to fruition.
Initial contingency planning began during 1998. Significant focus on that
phase of the project is taking place in 1999. Guidelines for that process were
issued in January 1999. Contingency plans are being developed for critical
business processes, critical business partners, suppliers and system
replacements that experience significant delays. Communications has engaged an
outside consultant to assist in this process. These plans are expected to be
defined by August 31, 1999, and implemented where appropriate. Because of the
delay in the implementation date of the new ATLAS and revenue billing systems at
Petroleum Services to October 1, 1999, the contingency plan for those systems
has been implemented. That plan includes the modification and testing of the
existing ATLAS and revenue billing systems by September 1, 1999 to ensure that a
compliant system is in place in case the new systems' implementation date is
delayed further.
Costs incurred for new software and hardware purchases are being capitalized
and other costs are being expensed as incurred. Williams currently estimates the
total cost of the enterprise-wide project, including any accelerated system
replacements, to be approximately $50 million. This $50 million has been or is
expected to be spent as follows:
o Prior to 1998 and during the first quarter of 1998, Williams was conducting
the project awareness and inventory/assessment phases of the project and
incurred costs totaling $3 million.
o During the second quarter of 1998, $2 million was spent on the
renovation/replacement and testing/validation phases and completion of the
inventory/assessment phase.
o The third and fourth quarters of 1998 focused on the renovation/replacement
and testing/validation phases, and $10 million was incurred.
o During the first-quarter 1999, renovation/replacement and
testing/validation continued, contingency planning began and $9 million was
incurred.
o During the second quarter of 1999, the primary focus is expected to shift
to testing/validation and contingency planning, and $15 million is expected
to be spent.
o The third and fourth quarters of 1999 will focus mainly on contingency
planning and final testing with $11 million expected to be spent.
Of the $24 million incurred to date, approximately $21 million has been
expensed, and approximately $3 million has been capitalized. Of the $26 million
of future costs necessary to complete the project within the schedule described,
approximately $23 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. The costs of previously planned system replacements are
not considered to be year 2000 costs and are, therefore, excluded from the
amounts discussed above.
The preceding discussion contains forward-looking statements including,
without limitation,
19
<PAGE> 21
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 first quarter of 1999, Williams issued $200 million in adjustable
rate debt due in 2004 at an initial rate of approximately 5.3 percent.
At March 31, 1999, Williams has preferred stock interests in certain South
American ventures totaling $367 million for which the fair value of these
investments is deemed to approximate the carrying value. Williams' financial
results could be affected if these investments incur a permanent decline in
value as a result of changes in foreign currency exchange rates and the local
economic conditions. These ventures are in a country that has experienced
significant devaluation and volatility. The ultimate duration and severity of
the conditions in this country remain uncertain as does the long-term impact on
Williams' interest in these ventures.
20
<PAGE> 22
PART II. OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K
(a) The exhibits listed below are filed as part of this report:
Exhibit 12 -- Computation of Ratio of Earnings to Combined Fixed
Charges and Preferred Dividend Requirements
Exhibit 27 -- Financial Data Schedule
(b) During the first quarter of 1999, the Company filed a Form 8-K on
January 26, 1999; March 3, 1999; and March 24, 1999, which
reported significant events under Item 5 of the Form and included
the exhibits required by Item 7 of the Form.
21
<PAGE> 23
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)
May 14, 1999
<PAGE> 24
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NO. DESCRIPTION
------- -----------
<S> <C>
Exhibit 12 -- Computation of Ratio of Earnings to Combined Fixed Charges and
Preferred Dividend Requirements
Exhibit 27 -- Financial Data Schedule
</TABLE>
<PAGE> 1
Exhibit 12
The Williams Companies, Inc. and Subsidiaries
Computation of Ratio of Earnings to Combined Fixed Charges
and Preferred Stock Dividend Requirements
(Dollars in millions)
<TABLE>
<CAPTION>
Three months ended
March 31, 1999
---------------
<S> <C>
Earnings:
Income before income taxes, extraordinary loss
and change in accounting principle $ 95.8
Add:
Interest expense - net 133.9
Rental expense representative of interest factor 19.2
Minority interest in (income) loss of consolidated subsidiaries .6
Interest accrued - 50% owned company 1.8
Equity losses in less than 50% owned companies 20.3
Other 2.1
---------------
Total earnings as adjusted plus fixed charges $ 273.7
===============
Fixed charges and preferred stock dividend requirements:
Interest expense - net $ 133.9
Capitalized interest 9.4
Rental expense representative of interest factor 19.2
Pretax effect of dividends on preferred stock of
the Company 2.7
Interest accrued - 50% owned company 1.8
---------------
Combined fixed charges and preferred stock dividend requirements $ 167.0
===============
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> 3-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> MAR-31-1999
<CASH> 330,077
<SECURITIES> 0
<RECEIVABLES> 1,694,303
<ALLOWANCES> 39,865
<INVENTORY> 533,883
<CURRENT-ASSETS> 3,305,839
<PP&E> 16,614,721
<DEPRECIATION> 3,704,236
<TOTAL-ASSETS> 19,172,166
<CURRENT-LIABILITIES> 4,932,718
<BONDS> 6,192,394
0
79,710
<COMMON> 435,663
<OTHER-SE> 3,815,101
<TOTAL-LIABILITY-AND-EQUITY> 19,172,166
<SALES> 0
<TOTAL-REVENUES> 1,984,011
<CGS> 0
<TOTAL-COSTS> 1,744,796
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 9,587
<INTEREST-EXPENSE> 143,336
<INCOME-PRETAX> 95,837
<INCOME-TAX> 39,945
<INCOME-CONTINUING> 55,892
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> (5,600)
<NET-INCOME> 50,292
<EPS-PRIMARY> .11
<EPS-DILUTED> .11
</TABLE>
