<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, 1997
------------------------------------------------
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) 588-2000
-------------------------------------
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, 1997
- -------------------------------------- -------------------------------------
Common Stock, $1 par value 159,808,502 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 and Nine
Months Ended September 30, 1997 and 1996 2
Consolidated Balance Sheet--September 30, 1997 and
December 31, 1996 3
Consolidated Statement of Cash Flows--Nine Months
Ended September 30, 1997 and 1996 4
Notes to Consolidated Financial Statements 5
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 11
Part II. Other Information
Item 6. Exhibits and Reports on Form 8-K 16
Exhibit 11--Computation of Earnings Per Common and Common-
equivalent Share
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 Reform Act of 1995. Additional information about issues that could
lead to material changes in performance is contained in The Williams Companies,
Inc.'s Annual Report on Form 10-K.
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,
----------------------------- -----------------------------
1997 1996 1997 1996
------------ ------------ ------------ ------------
<S> <C> <C> <C> <C>
Revenues:
Williams Interstate Natural Gas Systems (Note 3) $ 398.3 $ 390.9 $ 1,237.4 $ 1,249.3
Williams Energy Group (Note 3) 357.7 336.9 1,083.7 1,044.6
Williams Communications Group (Note 4) 413.7 189.0 989.4 491.1
Other 8.9 12.1 28.0 37.3
Intercompany eliminations (57.6) (86.7) (195.5) (248.9)
------------ ------------ ------------ ------------
Total revenues 1,121.0 842.2 3,143.0 2,573.4
------------ ------------ ------------ ------------
Profit-center costs and expenses:
Costs and operating expenses 705.3 509.3 1,911.7 1,502.6
Selling, general and administrative expenses 204.1 138.0 551.1 415.4
Other income--net (5.9) (2.9) (15.3) (3.9)
------------ ------------ ------------ ------------
Total profit-center costs and expenses 903.5 644.4 2,447.5 1,914.1
------------ ------------ ------------ ------------
Operating profit:
Williams Interstate Natural Gas Systems (Note 3) 141.7 121.8 453.9 409.9
Williams Energy Group (Note 3) 79.0 73.4 241.3 240.4
Williams Communications Group (Note 4) (5.2) 2.1 (3.9) 6.0
Other 2.0 .5 4.2 3.0
------------ ------------ ------------ ------------
Total operating profit 217.5 197.8 695.5 659.3
General corporate expenses (12.5) (11.6) (32.2) (29.8)
Interest accrued (103.4) (93.5) (301.6) (265.6)
Interest capitalized 4.3 2.1 10.4 4.5
Investing income 4.0 6.6 11.8 14.7
Gain on sale of interest in subsidiary (Note 4) -- -- 44.5 --
Minority interest in income of consolidated
subsidiaries (Note 4) (4.4) -- (9.5) --
Other income (expense)--net 1.2 2.2 (6.3) (4.1)
------------ ------------ ------------ ------------
Income before income taxes 106.7 103.6 412.6 379.0
Provision for income taxes (Notes 4 and 5) 41.4 32.6 133.6 122.7
------------ ------------ ------------ ------------
Income before extraordinary loss 65.3 71.0 279.0 256.3
Extraordinary loss (Note 6) (73.7) -- (73.7) --
------------ ------------ ------------ ------------
Net income (loss) (8.4) 71.0 205.3 256.3
Preferred stock dividends 2.4 2.6 7.6 7.8
------------ ------------ ------------ ------------
Income (loss) applicable to common stock $ (10.8) $ 68.4 $ 197.7 $ 248.5
============ ============ ============ ============
Primary earnings per common and common-equivalent
share (Note 11):
Income before extraordinary loss $ .39 $ .42 $ 1.67 $ 1.53
Extraordinary loss (Note 6) (.45) -- (.45) --
------------ ------------ ------------ ------------
Net income (loss) $ (.06) $ .42 $ 1.22 $ 1.53
============ ============ ============ ============
Average shares (thousands) 162,959 162,412 162,574 162,142
Fully diluted earnings per common and common-equivalent
share (Note 11):
Income before extraordinary loss $ .39 $ .42 $ 1.65 $ 1.52
Extraordinary loss (Note 6) (.44) -- (.44) --
------------ ------------ ------------ ------------
Net income (loss) $ (.05) $ .42 $ 1.21 $ 1.52
============ ============ ============ ============
Average shares (thousands) 169,002 168,467 168,663 168,189
Cash dividends per common share $ .26 $ .227 $ .78 $ .68
</TABLE>
See accompanying notes.
2
<PAGE> 4
The Williams Companies, Inc.
Consolidated Balance Sheet
(Unaudited)
<TABLE>
<CAPTION>
(Millions)
--------------------------
September 30, December 31,
1997 1996
------------ ------------
<S> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents $ 94.0 $ 115.3
Receivables (Note 7) 884.5 952.9
Transportation and exchange gas receivable 116.2 117.7
Inventories 285.8 204.6
Commodity trading assets 165.3 147.2
Deferred income taxes 209.2 199.5
Other 134.9 152.9
--------- ---------
Total current assets 1,889.9 1,890.1
Investments 274.4 190.6
Property, plant and equipment, at cost 12,009.6 11,212.3
Less accumulated depreciation and depletion (2,149.0) (1,826.0)
--------- ---------
9,860.6 9,386.3
Goodwill and other intangible assets--net (Note 4) 437.0 198.1
Other assets and deferred charges 791.8 753.7
--------- ---------
Total assets $13,253.7 $12,418.8
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Notes payable (Note 8) $ 1,082.9 $ 269.5
Accounts payable 675.0 683.3
Transportation and exchange gas payable 67.4 73.7
Accrued liabilities 950.7 975.3
Commodity trading liabilities 167.4 137.9
Long-term debt due within one year (Note 8) 114.5 59.6
--------- ---------
Total current liabilities 3,057.9 2,199.3
Long-term debt (Note 8) 4,043.6 4,376.9
Deferred income taxes 1,659.7 1,626.6
Other liabilities 858.1 787.5
Minority interest in consolidated subsidiaries (Note 4) 105.9 7.5
Contingent liabilities and commitments (Note 10)
Stockholders' equity:
Preferred stock, $1 par value, 30,000,000 shares authorized, 2,499,372 shares
issued in 1997 and 3,241,552 shares issued in 1996 (Note 9) 142.5 161.0
Common stock, $1 par value, 480,000,000 shares authorized, 161,669,428
shares issued in 1997 and 160,214,163 shares issued in 1996 161.7 160.2
Capital in excess of par value 1,091.8 1,047.7
Retained earnings 2,193.5 2,119.5
Unamortized deferred compensation (2.4) (2.2)
--------- ---------
3,587.1 3,486.2
Less treasury stock (at cost), 2,459,729 shares of common stock in 1997
and 2,737,337 shares of common stock in 1996 (58.6) (65.2)
--------- ---------
Total stockholders' equity 3,528.5 3,421.0
--------- ---------
Total liabilities and stockholders' equity $13,253.7 $12,418.8
========= =========
</TABLE>
See accompanying notes.
3
<PAGE> 5
The Williams Companies, Inc.
Consolidated Statement of Cash Flows
(Unaudited)
<TABLE>
<CAPTION>
(Millions)
---------------------
Nine months ended
September 30,
---------------------
1997 1996
-------- --------
<S> <C> <C>
OPERATING ACTIVITIES:
Net income $ 205.3 $ 256.3
Adjustments to reconcile to cash provided from operations:
Extraordinary loss 73.7 --
Depreciation, depletion and amortization 369.6 332.7
Provision for deferred income taxes 45.5 10.5
Minority interest in income of consolidated subsidiaries 9.5 --
Gain on sale of interest in subsidiary (44.5) --
Changes in receivables sold 138.9 (49.3)
Changes in receivables 104.3 100.7
Changes in inventories (56.2) (14.3)
Changes in other current assets 21.7 14.1
Changes in accounts payable (2.5) (49.4)
Changes in accrued liabilities (126.1) (59.0)
Changes in current commodity trading assets and liabilities 11.4 (20.5)
Changes in non-current commodity trading assets and liabilities (15.8) (35.9)
Premium on early extinguishment of debt (154.2) --
Other, including changes in non-current assets and liabilities 33.9 25.9
-------- --------
Net cash provided by operating activities 614.5 511.8
-------- --------
FINANCING ACTIVITIES:
Proceeds from notes payable 1,439.1 356.8
Payments of notes payable (259.3) (56.5)
Proceeds from long-term debt 1,119.7 1,549.0
Payments of long-term debt (1,903.2) (1,187.1)
Proceeds from issuance of common stock 33.6 42.7
Purchases of treasury stock -- (33.8)
Preferred stock redemption (18.5) --
Dividends paid (131.3) (114.8)
Other--net .1 (3.3)
-------- --------
Net cash provided by financing activities 280.2 553.0
-------- --------
INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures (811.3) (528.2)
Proceeds from dispositions 87.5 24.3
Changes in accounts payable and accrued liabilities (17.3) (10.9)
Acquisition of businesses, net of cash acquired (80.8) (295.5)
Income tax and other payments related to discontinued operations (8.9) (255.2)
Purchase of investments/advances to affiliate (114.6) (57.3)
Other--net 29.4 8.1
-------- --------
Net cash used by investing activities (916.0) (1,114.7)
-------- --------
Decrease in cash and cash equivalents (21.3) (49.9)
Cash and cash equivalents at beginning of period 115.3 90.4
-------- --------
Cash and cash equivalents at end of period $ 94.0 $ 40.5
======== ========
</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 financial
statements and notes thereto in Williams' 1996 Annual Report on Form 10-K. The
accompanying financial statements have not been audited by independent auditors,
but include all adjustments both normal recurring and others which, in the
opinion of Williams' management, are necessary to present fairly its financial
position at September 30, 1997, results of operations for the three and nine
months ended September 30, 1997 and 1996, and cash flows for the nine months
ended September 30, 1997 and 1996.
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.
2. Basis of presentation
On April 30, 1997, Williams and Northern Telecom (Nortel) combined their
customer premise operations into a limited liability company, WilTel
Communications, LLC (LLC) (see Note 4). Williams Communications Group's revenues
and operating profit amounts for 1997 include the operating results of the LLC
beginning May 1, 1997.
Williams Energy Group is comprised of four units. Field Services includes
Williams' natural gas gathering and processing activities previously reported in
Williams Field Services Group. Merchant Services includes Williams' energy
commodity trading and price-risk management activities previously reported in
Williams Energy Services. Certain natural gas and natural gas liquids marketing
operations formerly reported in Williams Field Services Group are also included
in Merchant Services. Petroleum Services includes Williams' interstate petroleum
products pipeline, ethanol-producing facilities and petroleum terminals
previously reported in Williams Pipe Line. Exploration & Production includes
exploration for and production of hydrocarbons previously reported as a
component of Williams Field Services Group. Certain revenues and operating
profit amounts for the three and nine months ended September 30, 1996, and cash
flow amounts for the nine months ended September 30, 1996, have been
reclassified to conform to current-year classifications for these
reorganizations and certain other matters.
Revenues and operating profit amounts for 1996 include the operating
results of Kern River Gas Transmission Company since its January 16, 1996,
acquisition by Williams of the remaining interest.
3. Revenues and operating profit
Revenues and operating profit of Williams Interstate Natural Gas Systems and
Williams Energy Group for the three and nine months ended September 30, 1997 and
1996, are as follows:
<TABLE>
<CAPTION>
Three months ended September 30,
- ------------------------------------------------------------------------------
(Millions) Revenues Operating Profit
- ------------------------------------------------------ --------------------
1997 1996 1997 1996
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Williams Interstate Natural
Gas Systems:
Northwest Pipeline $ 71.2 $ 69.1 $ 35.3 $ 36.1
Williams Natural Gas 49.4 43.4 19.1 11.9
Transcontinental Gas
Pipe Line 181.4 180.6 53.0 40.5
Texas Gas Transmission 53.2 55.0 3.7 2.7
Kern River Gas
Transmission 43.1 42.8 30.6 30.6
-------- -------- -------- --------
$ 398.3 $ 390.9 $ 141.7 $ 121.8
======== ======== ======== ========
Williams Energy Group:
Field Services $ 170.6 $ 146.0 $ 39.6 $ 44.6
Merchant Services 15.5 57.0 6.8 15.1
Petroleum Services 139.5 114.4 27.2 14.4
Exploration & Production 32.1 19.5 5.4 (.7)
-------- -------- -------- --------
$ 357.7 $ 336.9 $ 79.0 $ 73.4
======== ======== ======== ========
</TABLE>
<TABLE>
<CAPTION>
Nine months ended September 30,
--------------------------------------------
(Millions) Revenues Operating Profit
- ------------------------------------------------------ --------------------
1997 1996 1997 1996
- ------------------------------------------ -------- -------- --------
<S> <C> <C> <C> <C>
Williams Interstate Natural
Gas Systems:
Northwest Pipeline $ 204.5 $ 205.6 $ 94.5 $ 103.1
Williams Natural Gas 137.2 131.8 51.4 33.9
Transcontinental Gas
Pipe Line 560.2 572.8 161.9 133.6
Texas Gas Transmission 210.4 220.6 55.5 55.6
Kern River Gas
Transmission 125.1 118.5 90.6 83.7
-------- -------- -------- --------
$1,237.4 $1,249.3 $ 453.9 $ 409.9
======== ======== ======== ========
Williams Energy Group:
Field Services $ 518.2 $ 454.0 $ 129.5 $ 131.1
Merchant Services 73.9 181.3 28.6 52.8
Petroleum Services 397.1 356.4 63.1 57.4
Exploration & Production 94.5 52.9 20.1 (.9)
-------- -------- -------- --------
$1,083.7 $1,044.6 $ 241.3 $ 240.4
======== ======== ======== ========
</TABLE>
4. Acquisition
On April 30, 1997, Williams and Nortel combined their customer premise
equipment sales and service operations into a limited liability company, WilTel
Communications, 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
5
<PAGE> 7
Notes (continued)
Income. Accordingly, the acquired assets and liabilities, including $150 million
in debt obligations, have been recorded based on an allocation of the purchase
price, with substantially all of the cost in excess of historical carrying
values allocated to goodwill. The goodwill will be amortized using the straight
line method over approximately 25 years.
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 affect the differences between the financial and tax bases of identifiable
assets and liabilities.
If the transaction occurred on January 1, 1996, Williams' unaudited pro
forma revenues for the nine months ended September 30, 1997 and 1996, would have
been $3,391.1 million and $3,113.6 million, respectively. 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, 1996, or
of future results of operations of the combined companies.
5. Provision for income taxes
<TABLE>
<CAPTION>
Three months ended Nine months ended
(Millions) September 30, September 30,
- ------------------------------------------------- --------------------
1997 1996 1997 1996
- ------------------------------------- -------- -------- --------
<S> <C> <C> <C> <C>
Current:
Federal $ 29.2 $ 28.4 $ 73.3 $ 101.3
State 6.5 (4.0) 14.8 10.9
-------- -------- -------- --------
35.7 24.4 88.1 112.2
Deferred:
Federal 5.5 7.8 37.6 8.6
State .2 .4 7.9 1.9
-------- -------- -------- --------
5.7 8.2 45.5 10.5
-------- -------- -------- --------
Total provision $ 41.4 $ 32.6 $ 133.6 $ 122.7
======== ======== ======== ========
</TABLE>
The effective income tax 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 4) and income tax
credits from coal-seam gas production, partially offset by the effects of state
income taxes.
The effective income tax rate in 1996 is less than the federal statutory
rate due primarily to income tax credits from coal-seam gas production,
partially offset by the effects of state income taxes. Both 1996 periods include
approximately $6 million, net of federal income tax effect, from the effects of
state income tax adjustments related to 1995. In addition, the nine months ended
September 30, 1996, includes second quarter recognition of favorable adjustments
totaling $10 million related to research credits and previously provided
deferred income taxes on certain regulated capital projects.
Cash payments, net of refunds, for income taxes for the nine months ended
September 30, 1997 and 1996, were $60 million and $352 million, respectively.
6. Extraordinary loss
In September 1997, Williams initiated a restructuring of its debt portfolio
(see Note 8). As of September 30, 1997, Williams has paid approximately $1.2
billion to redeem approximately $1 billion of higher interest rate debt,
resulting in an extraordinary loss of $73.7 million (net of a $46.9 million
benefit for income taxes). In addition, $22.7 million has been deferred for rate
recovery as a regulatory asset.
7. Sale of receivables
In January 1997, Williams expanded its revolving receivables facilities by
$200 million. As of September 30, 1997, Williams has sold $166.9 million of
receivables under this facility. The Financial Accounting Standards Board has
issued a new accounting standard, FAS No. 125, "Accounting for Transfers and
Servicing of Financial Assets and Extinguishments of Liabilities," effective for
transactions occurring after December 31, 1996. The adoption of this standard
has not had a material impact on Williams' consolidated results of operations,
financial position or cash flows.
8. Debt and banking arrangements
Notes Payable
In July 1997, Williams Holdings entered into a commercial paper program
backed by a new $500 million short-term bank-credit facility. At September 30,
1997, $414 million of commercial paper was outstanding under the program.
Interest rates vary with current market conditions.
6
<PAGE> 8
Debt
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------
Weighted
average
interest September 30, December 31,
(Millions) rate* 1997 1996
- ---------------------------------------------- ------- -------- --------
<S> <C> <C> <C>
The Williams Companies, Inc.
Debentures, 8.875% -
10.25%, payable 2012,
2020, 2021 and 2025 9.5% $137.1 $587.5
Notes, 7.5% - 9.625%, pay-
able 1998 through 2001 6.9 963.1 817.5
Northwest Pipeline
Revolving credit loans 6.0 207.0 --
Debentures, 7.125% - 10.65%,
payable through 2025 8.4 170.2 360.0
Adjustable rate notes,
payable through 2002 9.0 8.3 10.0
Williams Natural Gas
Variable rate notes,
payable 1999 8.2 130.0 130.0
Transcontinental Gas Pipe Line
Debentures, 7.25% and
9.125%, payable 1998
through 2026 8.1 352.2 352.4
Debentures, 7.08%, payable
2026 (subject to debt-
holder redemption in
2001) 7.1 200.0 200.0
Notes, 8.125% and 8.875%,
payable 1997 and 2002 8.9 128.3 227.7
Adjustable rate note, payable
2002 5.7 150.0 --
Texas Gas Transmission
Debentures, 7.25%, payable
2027 7.3 99.0 --
Notes, 9.625% and 8.625%,
payable 1997 and 2004 8.6 152.5 253.6
Kern River Gas Transmission
Notes, 6.42% and 6.72%,
payable through 2001 6.6 586.4 617.7
Williams Holdings of Delaware
Revolving credit loans 6.3 200.0 500.0
Debentures, 6.25%,
payable 2006 4.8 248.9 248.8
Notes, 6.4% - 6.91%, payable
1998 through 2002 6.7 205.6 --
Williams Pipe Line
Notes, 8.95% and 9.78%,
payable through 2001 9.4 90.0 100.0
Williams Energy Ventures
Adjustable rate notes,
payable through 2002 -- -- 25.6
WilTel Communications, LLC
Revolving credit loans 6.0 125.0 --
Other, payable through 1999 7.9 4.5 5.7
-------- --------
4,158.1 4,436.5
Current portion of long-term debt (114.5) (59.6)
-------- --------
$4,043.6 $4,376.9
======== ========
</TABLE>
*At September 30, 1997, including the effects of interest-rate swaps.
In September 1997, Williams initiated a restructuring of its debt
portfolio. As of September 30, 1997, Williams has redeemed approximately $1
billion of higher interest rate debt. Subsequent to September 30, 1997, Williams
will redeem approximately $300 million of additional debt obligations. The
restructuring has been temporarily financed with the combination of short-term
bank agreements and Williams' existing revolving credit agreement, until new
long-term debt securities are issued in the fourth quarter of 1997 and first
quarter of 1998.
In July 1997, Williams entered into a new $1 billion bank-credit agreement,
replacing the previous agreement. Under the new agreement, Northwest Pipeline,
Transcontinental Gas Pipe Line, Texas Gas Transmission, Williams Pipe Line, and
WilTel Communications, LLC will have access to varying amounts of the facility
while Williams (parent) and Williams Holdings of Delaware, Inc. (Williams
Holdings) have access to all unborrowed amounts. Interest rates vary with
current market conditions. Subsequent to September 30, 1997, Williams Pipe Line
elected to withdraw as a borrower under the agreement. Amounts available to the
remaining parties did not change.
For financial statement reporting purposes at September 30, 1997, $768
million in notes payable and current debt obligations, primarily related to the
restructuring noted above, have been classified as non-current obligations based
on Williams' intent and ability to refinance on a long-term basis. At September
30, 1997, the amount available on the $1 billion credit agreement of $468
million and Williams' subsequent issuance of $300 million in long-term debt
obligations are sufficient to complete these refinancings. The remaining amounts
borrowed for the restructuring under the short-term credit agreements of $429
million have been classified as notes payable.
Cash payments for interest (net of amounts capitalized) for the nine months
ended September 30, 1997 and 1996, are $325 million and $279 million,
respectively.
9. Preferred stock redemption
In September 1997, Williams redeemed the remaining shares of its $2.21
cumulative preferred stock at par value for approximately $19 million.
10. 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. As to Williams Pipe Line, revenues collected
subject to refund were $307 million at September 30, 1997; it is not expected
that the amount of any refunds ordered would be significant. Accordingly, no
portion of these revenues has been reserved for refund. As to the other
pipelines, $281 million of revenues has been reserved for potential refund as of
September 30, 1997.
The Federal Energy Regulatory Commission (FERC) recently 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
7
<PAGE> 9
Notes (continued)
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. At a recent public FERC meeting, the FERC voted not
to reconsider an order issued in one of the three pipeline proceedings, but
announced plans to convene a conference early in 1998 to consider, on an
industry-wide basis, issues with respect to pipeline rates of return.
In 1992, 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. Kern River Gas Transmission implemented its restructuring on August 1,
1993, Williams Natural Gas implemented its restructuring on October 1, 1993, and
Northwest Pipeline, Texas Gas and Transcontinental Gas Pipe Line implemented
their restructurings on November 1, 1993. Certain aspects of four pipeline
companies' restructurings are under appeal.
On July 16, 1996, the U.S. Court of Appeals for the D.C. Circuit issued an
order which in part affirmed and in part remanded Order 636. However, the court
stated that Order 636 would remain in effect until FERC issued a final order on
remand after considering the remanded issues. With the issuance of this
decision, the stay on the appeals of individual pipeline's restructuring cases
will be lifted. The only appeal challenging Northwest Pipeline's restructuring
has been dismissed. 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.
Contract reformations and gas purchase deficiencies
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 and 636-C 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
Natural Gas (WNG) has made eight filings to direct bill take-or-pay and gas
supply realignment costs. The first provided for the offset of certain amounts
collected subject to refund against previous take-or-pay direct-billed amounts
and, in addition, covered $24 million in new costs. This filing was approved,
and the final direct-billed amount, taking into consideration the offset, was
$15 million. The second filing covered $18 million in gas supply realignment
costs, and provided for an offset of $3 million. The third filing covered $6.5
million in gas supply realignment costs. The remaining filings covered
additional costs of approximately $18 million, which are similar in nature to
the costs in the second filing. 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. As of September 30,
1997, WNG had an accrual of $94 million for its then-estimated remaining
contract-reformation and gas supply realignment costs. An intervenor has filed a
protest seeking to have the FERC decide whether non-settlement costs covered by
certain of WNG's recent filings were eligible for recovery pursuant to Order No.
636. In January 1997, the FERC held that 100 percent of such prudent non-settled
costs would be recovered by WNG if such costs were eligible for recovery under
Order No. 636. The FERC also held that none of the non-settled costs could be
recovered by WNG if these costs were not eligible for recovery under Order No.
636. This Order was affirmed on rehearing in April 1997. WNG has appealed these
FERC orders. WNG will make additional filings under the applicable FERC orders
to recover such further costs as may be incurred in the future. WNG has recorded
a regulatory asset of approximately $94 million for estimated future recovery of
the foregoing costs. On September 30, 1997, the FERC, by a two-to-one vote,
reversed the administrative law judge and determined that three contracts were
imprudently entered into in 1982. WNG has filed for rehearing. The outcome of
the FERC orders on rehearing or appeal is uncertain. WNG is actively pursuing
settlement of the gas purchase contracts. WNG believes that the accrued
liability of $94 million is adequate through September 30, 1997, and that any
ultimate additional exposure will not be material.
In September 1995, Texas Gas received FERC approval of a settlement
regarding Texas Gas' recovery of gas supply realignment costs. The settlement
provides that Texas Gas will recover 100 percent of such costs up to $50
million, will share in costs incurred between $50 million and $80 million, and
will absorb any such costs above $80 million. Through September 30, 1997, 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
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$66 million, plus interest, in gas supply realignment costs and has recorded a
regulatory asset of approximately $1 million for the estimated future recovery
of such costs, most of which will be collected from customers prior to December
31, 1997. Ninety percent of the cost recovery is collected through demand
surcharges on Texas Gas' firm transportation rates; the remaining 10 percent
should be recoverable from interruptible transportation service.
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,
1997, these subsidiaries had reserves totaling approximately $26 million for
these costs.
Certain Williams subsidiaries, including Texas Gas and Transcontinental Gas
Pipe Line, have been identified as potentially responsible parties (PRP) at
various Superfund and state waste disposal sites. In addition, these
subsidiaries have incurred or are alleged to have incurred various other
hazardous materials removal or remediation obligations under environmental laws.
Although no assurances can be given, Williams does not believe that the PRP
status of these subsidiaries will have a material adverse effect on its
financial position, results of operations or net cash flows.
Transcontinental Gas Pipe Line, Texas Gas and Williams Natural Gas 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 Williams Natural Gas 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 Williams
Natural Gas, Texas Gas and Transcontinental Gas Pipe Line. As of September 30,
1997, Williams Natural Gas had recorded a liability for approximately $17
million, representing the current estimate of future environmental cleanup costs
to be incurred over the next six to ten years. The Field Services unit of
Williams Energy Group has recorded an aggregate liability of approximately $13
million, representing the current estimate of their future environmental and
remediation costs, including approximately $5 million relating to former
Williams Natural Gas 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 Williams Natural Gas have deferred these costs pending
recovery as incurred through future rates and other means.
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, 1997, Williams had approximately $11 million accrued for such
excess costs. The actual costs incurred will depend on the actual amount and
extent of contamination discovered, the final cleanup standards mandated by the
EPA or other governmental authorities, and other factors.
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. Northwest Pipeline is
vigorously defending these lawsuits.
Other legal matters
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
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Notes (continued)
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. In addition, if the Tribe is successful in showing that Williams
Production has no rights in the coal-seam gas, Williams Production has agreed to
pay to the Trust for distribution to then-current unitholders, an amount
representing a return of a portion of the original purchase price paid for the
units. While Williams believes that such a payment is not probable, it has
reserved a portion of the proceeds from the sale of the units in the Trust. 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. In the event
that further review is denied, the district court will be in the position to
hear the defendants' affirmative defenses against the Tribe's claims.
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 and Texas Gas were named as
defendants in, respectively, six and two lawsuits. Six of the eight lawsuits
have been settled for cash payments aggregating approximately $9 million, all of
which have previously been accrued, and of which approximately $3 million is
recoverable as transition costs under Order 636. In one of the two remaining
cases, a jury verdict found that Transcontinental Gas Pipe Line was required to
pay to a producer damages of $14.5 million plus $3.8 million in attorneys'
fees. The trial judge deferred entering judgement pending mediation. In the
other remaining case, a producer has asserted damages, including interest
calculated through December 31, 1996, 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 November 1994, Continental Energy Associates Limited Partnership (the
Partnership) filed a voluntary petition under Chapter 11 of the Bankruptcy Code
with the U.S. Bankruptcy Court, Middle District of Pennsylvania. The Partnership
owns a cogeneration facility in Hazelton, Pennsylvania (the Facility). Hazelton
Fuel Management Company (HFMC), a subsidiary of Transco Energy, formerly
supplied natural gas and fuel oil to the Facility. Pursuant to a court approved
Plan of Reorganization, all litigation involving HFMC has been fully settled and
HFMC received $6.3 million from the bankruptcy estate, leaving it with
approximately $14 million of outstanding receivables, all of which have been
fully reserved.
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.
11. Adoption of accounting standards
The Financial Accounting Standards Board has issued two new accounting
standards, FAS No. 130, "Reporting Comprehensive Income," and FAS No. 131,
"Disclosures about Segments of an Enterprise and Related Information," effective
for fiscal years beginning after December 15, 1997. While Williams has certain
comprehensive income items, adopting these pronouncements will not materially
change Williams financial reporting and disclosures. Williams has not yet
determined if it will adopt either standard early.
The Financial Accounting Standards Board has issued FAS No. 128, "Earnings
per Share," effective for fiscal years ending after December 15, 1997. Earnings
per share calculated under this standard would not differ significantly from
amounts reported in the Consolidated Statement of Income.
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ITEM 2.
Management's Discussion and Analysis of
Financial Condition and Results of Operations
Third Quarter 1997 vs. Third Quarter 1996
NORTHWEST PIPELINE'S revenues increased $2.1 million, or 3 percent, due
primarily to new transportation rates effective March 1, 1997, partially offset
by the $3 million effect of a favorable regulatory decision in 1996. Total
throughput decreased 44.6 TBtu, or 23 percent, as a result of the 1996 sale of
the south-end facilities. Operating profit decreased $800,000, or 2 percent,
due primarily to the 1996 favorable regulatory decision, partially offset by
lower operating and maintenance expenses and general and administrative
expenses.
WILLIAMS NATURAL GAS' revenues increased $6 million, or 14 percent, due
primarily to the net effect of adjustments to certain accruals in 1997 and
higher transportation revenues. Total throughput increased 5.3 TBtu, or 9
percent. Operating profit increased $7.2 million, or 59 percent, due primarily
to the net effect of adjustments to certain accruals in 1997, lower operating
and maintenance expenses and higher transportation revenues.
TRANSCONTINENTAL GAS PIPE LINE'S revenues increased slightly as the
effects of a mainline expansion placed in service in late 1996 and new rates
effective May 1, 1997, were substantially offset by the effect of having passed
through to ratepayers a $3 million lower level of reimbursable costs. Total
throughput increased 15 TBtu, or 4 percent, due primarily to higher firm and
interruptible long-haul transportation volumes. Costs and operating expenses
decreased $13 million, or 12 percent, due primarily to a $5.4 million
settlement related to a prior rate proceeding, lower costs charged to Transco
by others and passed through to customers as provided in Transco's rates and
$10 million lower operating and maintenance expenses, slightly offset by higher
depreciation related to recent capital projects placed into service. Operating
profit increased $12.5 million, or 31 percent, due primarily to the $5.4
million settlement, lower operating and maintenance expenses, the effects of
the mainline expansion and the new rates effective May 1, 1997, partially
offset by higher general and administrative expenses and depreciation. 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.
TEXAS GAS TRANSMISSION'S revenues decreased $1.8 million, or 3 percent,
due primarily to lower costs passed through to customers as provided in Texas
Gas' rates. Total throughput decreased 3.6 TBtu, or 2 percent. Operating
profit increased $1 million, or 36 percent, due primarily to lower operating
and maintenance expenses associated with the timing of maintenance projects.
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.
KERN RIVER GAS TRANSMISSION'S (KERN RIVER) revenues increased $300,000
and operating profit remained unchanged as compared to the third quarter of
1996. Total throughput increased 4.2 TBtu, or 6 percent, due primarily to
higher firm transportation volumes.
FIELD SERVICES' revenues increased $24.6 million, or 17 percent, due
primarily to higher natural gas liquids sales of $21 million resulting from a
90 percent increase in volumes. In addition, gathering and processing volumes
increased 9 percent and 11 percent, respectively. Costs and operating expenses
increased $25 million, or 28 percent, due primarily to higher fuel and
replacement gas purchases and increased operating and maintenance expenses.
Other income--net for 1996 includes a $3 million gain from the sale of a small
gathering system in the Texas panhandle. Operating profit decreased $5
million, or 11 percent, due primarily to $14 million from lower per-unit
liquids margins, increased operating and maintenance expenses, lower average
gathering rates and the effect of the 1996 gain on sale of a small gathering
system, partially offset by the increases in gathering, processing and natural
gas liquids volumes.
MERCHANT SERVICES' revenues decreased $41.5 million, or 73 percent, and
costs and operating expenses decreased $31 million, or 100 percent, due
primarily to the 1997 reporting on a net margin basis of certain natural gas and
gas liquids marketing operations previously reported in Field Services (see Note
2). In addition, revenues decreased an additional $11 million, due primarily to
lower price-risk management revenues and physical trading margins as a result of
decreased price volatility. A 39 percent increase in both physical trading and
notional natural gas volumes and increased petroleum products trading volumes
partially offset this decrease. Operating profit decreased $8.3 million, or 54
percent, due primarily to the decrease in net revenues and the expenses
associated with expansion of business growth platforms, partially offset by a
$6.3 million recovery of an account previously considered a bad debt.
PETROLEUM SERVICES' revenues increased $25.1 million, or 22 percent, due
primarily to a $16 million increase in ethanol sales and a $7 million increase
in product sales associated with transportation activities. Ethanol sales
increased as a result of 52 percent higher sales volumes, partially offset by
lower average sales prices. Ethanol production was reduced during the
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second half of 1996 due to unfavorable market conditions. Pipeline shipments
were comparable to 1996. Costs and operating expenses increased $13 million, or
15 percent, due primarily to the increase in ethanol production and product
sales. Operating profit increased $12.8 million, or 89 percent, due primarily
to $9 million from increased ethanol sales volumes and per-unit margins, in
addition to lower general and administrative expenses and higher product sales
margins.
EXPLORATION & PRODUCTION'S revenues increased $12.6 million, or 64
percent, due primarily to higher average natural gas sales prices for company-
owned production and from the marketing of Williams Coal Seam Gas Royalty Trust
(Royalty Trust) natural gas and a 47 percent increase in company-owned
production volumes. Costs and operating expenses increased $7 million, or 27
percent, as a result of increased production activities. Operating profit
increased $6.1 million, from a $700,000 operating loss in 1996 to a $5.4
million operating profit in 1997, due primarily to the increase in average
natural gas prices and company-owned production volumes, partially offset by
higher expenses associated with increased activity levels.
WILLIAMS COMMUNICATIONS GROUP'S revenues increased $224.7 million, or
119 percent, to $413.7 million due primarily to acquisitions which contributed
revenues of approximately $210 million, including approximately $186 million
from the acquisition of the customer premise equipment sales and services
operations of Northern Telecom (Nortel). The number of ports in service at
September 30, 1997, more than doubled as compared to September 30, 1996, due
primarily to the Nortel acquisition. Fiber billable minutes from occasional
service increased 33 percent. Dedicated service voice-grade equivalent miles
at September 30, 1997, increased 36 percent as compared with September 30,
1996. Costs and operating expenses increased $168 million, or 115 percent, due
primarily to acquired operations, the overall increase in business activity,
higher expenses for developing advanced network applications and increased
depreciation associated with added capacity. Selling, general and
administrative expenses increased $63 million, or 154 percent, due primarily to
acquired operations, the overall increase in business activity, higher expenses
for developing advanced network applications and expanding the infrastructure
of this business for future growth. Operating profit decreased $7.3 million
from a $2.1 million operating profit in 1996 to a $5.2 million operating loss
in 1997 due primarily to the expense of developing the infrastructure along
with integrating the most recent acquisitions, partially offset by improved
earnings from enterprise network solutions including the impact of the Nortel
acquisition.
INTEREST ACCRUED increased $9.9 million, or 11 percent, due primarily
to higher borrowing levels including additional borrowings under the $1 billion
bank-credit facility and the issuance of commercial paper by Williams Holdings
of Delaware, Inc. (Williams Holdings), a wholly-owned subsidiary of Williams.
The average interest rate on new 1997 borrowings is lower than on previously
outstanding borrowings. Interest capitalized increased $2.2 million, or 108
percent, due primarily to capital expenditures for Williams Communications
Group's fiber-optic network. The minority interest in income of consolidated
subsidiaries is related primarily to the 30 percent interest held by WilTel
Communications, LLC's minority shareholders (see Note 4). The effective income
tax rate in 1997 is higher than the federal statutory rate due primarily to the
effects of state income taxes, partially offset by income tax credits from
coal-seam gas production. The effective income tax rate in 1996 is less than
the federal statutory rate due primarily to income tax credits from coal-seam
gas production and approximately $6 million, net of federal income tax effect,
from the effects of state income tax adjustments related to 1995. Partially
offsetting these were the effects of state income taxes.
The 1997 extraordinary loss results from the early extinguishment of
debt (see Note 6 for additional information).
Nine Months Ended September 30, 1997 vs. Nine Months Ended September 30, 1996
NORTHWEST PIPELINE'S revenues decreased $1.1 million, or 1 percent, due
primarily to the effect of a $2.6 million increase to rate reserve accruals in
1997 and recognition of $8 million of revenues in 1996 from favorable
regulatory decisions, largely offset by new transportation rates that became
effective March 1, 1997. Total throughput decreased 109.5 TBtu, or 17 percent,
as a result of the 1996 sale of the south-end facilities. Operating profit
decreased $8.6 million, or 8 percent, primarily due to the effect of an
increase to rate reserve accruals in 1997 and recognition in 1996 of favorable
regulatory decisions, partially offset by lower operating and maintenance
expenses.
WILLIAMS NATURAL GAS' revenues increased $5.4 million, or 4 percent, due
primarily to the net effect of adjustments to certain accruals in 1997. Total
throughput decreased 9.1 TBtu, or 4 percent, due primarily to lower
interruptible volumes. Other income--net includes a $7 million gain from the
sale-in-place of natural gas from a decommissioned storage field. Operating
profit increased $17.5 million, or 51 percent, due primarily to the gain on
sale-in-place of natural gas, the net effect of adjustments to certain accruals
in 1997, lower operating and maintenance expenses, an increase in firm reserved
capacity and lower general and administrative expenses.
TRANSCONTINENTAL GAS PIPE LINE'S revenues decreased $12.6 million, or 2
percent, due primarily to the effect of having passed through to ratepayers a
$22 million lower level of reimbursable costs, partially offset by the effects
of a mainline expansion placed into service
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in late 1996 and new rates effective May 1, 1997. Total throughput decreased
13.9 TBtu, or 1 percent, due primarily to milder weather during 1997 as
compared to 1996 which lowered firm long-haul and production area interruptible
transportation volumes. Costs and operating expenses decreased $36.3 million,
or 10 percent, due primarily to lower costs charged to Transco by others and
passed through to customers as provided in Transco's rates, $15 million lower
operating and maintenance expenses and a $5.4 million settlement related to a
prior rate proceeding. Operating profit increased $28.3 million, or 21
percent, due primarily to lower operating and maintenance expenses, the
effects of the mainline expansion and the new rates effective May 1, 1997, and
the $5.4 million settlement. 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.
TEXAS GAS TRANSMISSION'S revenues decreased $10.2 million, or 5 percent,
and costs and operating expenses decreased $8 million, or 7 percent, due
primarily to lower costs passed through to customers as provided in Texas Gas'
rates. Total throughput decreased 15.4 TBtu, or 3 percent. Operating profit
was comparable to 1996 as favorable 1996 adjustments to rate refund accruals
and a change in mix of transportation volumes under different rate structures
were substantially offset by the favorable resolution in 1997 of certain
contractual issues and lower operating and maintenance expenses. 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.
KERN RIVER'S revenues increased $6.6 million, or 6 percent, due
primarily to a full nine months of operations in 1997 compared to a partial
nine months in 1996 and higher transportation revenues during 1997. Results
for 1996 reflect operations from January 16, 1996, when Williams acquired the
remaining interest in Kern River. Total throughput increased 12.4 TBtu, or 6
percent, primarily as a result of the full nine months of operations in 1997
and higher firm transportation volumes during the third quarter. Operating
profit increased $6.9 million, or 8 percent, due primarily to the full nine
months of operations in 1997 and higher transportation revenues during 1997.
FIELD SERVICES' revenues increased $64.2 million, or 14 percent, due
primarily to higher natural gas liquids sales of $52 million, the pass through
of $11 million higher operating costs to customers, higher condensate revenues
of $9 million and $5 million higher processing revenues, partially offset by
lower average gathering rates in the Gulf-coast region. Natural gas liquids
sales increased due to a 47 percent increase in volumes combined with an
increase in average natural gas liquids prices. Costs and operating expenses
increased $64 million, or 23 percent, due primarily to higher fuel and
replacement gas purchases and $11 million higher operating costs passed through
to customers. Other income--net in 1996 includes a $3 million environmental
remediation accrual offset by a $3 million gain from the sale of a small
gathering system in the Texas panhandle. Operating profit decreased $1.6
million, or 1 percent, due primarily to $16 million from lower per-unit liquids
margins, $8 million from lower average gathering rates, higher gathering fuel
and replacement gas purchase costs and increased operating and maintenance
expenses. Substantially offsetting these were $21 million from increased
natural gas liquids volumes, higher processing revenues and lower depreciation
and amortization.
MERCHANT SERVICES' revenues decreased $107.4 million, or 59 percent, and
costs and operating expenses decreased $87 million, or 90 percent, due
primarily to the 1997 reporting on a net margin basis of certain natural gas
and gas liquids marketing operations previously reported in Field Services (see
Note 2). In addition, revenues decreased an additional $20 million, due
primarily to lower price-risk management revenues and physical trading margins
as a result of decreased price volatility. Increases in both physical trading
and notional natural gas volumes of 12 percent and 52 percent, respectively,
and increased petroleum products trading volumes partially offset this decrease.
Operating profit decreased $24.2 million, or 46 percent, due primarily to the
decrease in net revenues and the expenses associated with expansion of business
growth platforms, partially offset by a $6.3 million recovery of an account
previously considered a bad debt.
PETROLEUM SERVICES' revenues increased $40.7 million, or 11 percent, due
primarily to a $27 million increase in product sales from transportation
activities and a $15 million increase in ethanol sales, slightly offset by a
decrease in average transportation rates. Ethanol sales increased as a result
of 15 percent higher sales volumes, partially offset by lower average sales
prices. Ethanol production was reduced during the second half of 1996 due to
unfavorable market conditions. Costs and operating expenses increased $32
million, or 12 percent, due primarily to the increase in ethanol production and
product sales. Operating profit increased $5.7 million, or 10 percent, due
primarily to $11 million from increased ethanol sales volumes and per-unit
margins, in addition to improved product terminalling operations resulting from
the August 1996 acquisition of eight petroleum products terminals. These
increases were partially offset by lower average transportation rates and the
impact of favorable insurance settlements of $3 million in 1996.
EXPLORATION & PRODUCTION'S revenues increased $41.6 million, or 79
percent, due primarily to higher average natural gas sales prices for company-
owned production and from the marketing of Royalty Trust natural gas and a 24
percent increase in company-owned production volumes. Costs and operating
expenses increased $23 million, or 45 percent, due primarily to higher Royalty
Trust natural gas purchase prices and increased production activities.
Operating profit
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increased $21 million from a $900,000 loss in 1996 to a $20.1 million operating
profit in 1997, due primarily to the increase in average natural gas prices and
company-owned production volumes, partially offset by higher expenses
associated with increased activity levels.
WILLIAMS COMMUNICATIONS GROUP'S revenues increased $498.3 million, or
101 percent, to $989.4 million due primarily to acquisitions which contributed
revenues of approximately $400 million, including approximately $300 million
from the acquisition of the customer premise equipment sales and services
operations of Northern Telecom (Nortel). Additionally, increased business
activity in enterprise network solutions resulted in a $47 million revenue
increase in new system sales and a $27 million increase in existing system
enhancement revenues. The number of ports in service at September 30, 1997,
more than doubled as compared to September 30, 1996, due primarily to the
Nortel acquisition. Fiber billable minutes from occasional service increased
63 percent. Dedicated service voice-grade equivalent miles at September 30,
1997, increased 36 percent as compared with September 30, 1996. Costs and
operating expenses increased $371 million, or 99 percent, due primarily to
acquired operations, the overall increase in business activity, higher expenses
for developing advanced network applications and increased depreciation
associated with added capacity. Selling, general and administrative expenses
increased $139 million, or 127 percent, due primarily to acquired operations,
the overall increase in business activity, higher expenses for developing
advanced network applications and expanding the infrastructure of this business
for future growth. Operating profit decreased $9.9 million from a $6 million
operating profit in 1996 to a $3.9 million operating loss in 1997, due primarily
to the expense of developing the infrastructure along with integrating the most
recent acquisitions, partially offset by improved earnings from enterprise
network solutions including the impact of the Nortel acquisition.
INTEREST ACCRUED increased $36 million, or 14 percent, due primarily to
higher borrowing levels including increased borrowing under the $1 billion
bank-credit facility. The average interest rate on new 1997 borrowings is
lower than on previously outstanding borrowings. Interest capitalized
increased $5.9 million, or 133 percent, due primarily to capital expenditures
for Williams Communications Group's fiber-optic network. For information
concerning the 1997 gain on sale of interest in subsidiary see Note 4. The
minority interest in income of consolidated subsidiaries is related primarily
to the 30 percent interest held by WilTel Communications, LLC's minority
shareholders (see Note 4). The effective income tax rate in 1997 is less than
the federal statutory rate due primarily to the effect of the non-taxable gain
recognized in 1997 (see Note 4) and income tax credits from coal-seam gas
production, partially offset by the effects of state income taxes. The
effective tax rate in 1996 is less than the federal statutory rate due
primarily to income tax credits from coal-seam gas production and recognition
of favorable adjustments totaling $16 million related to research credits,
previously provided deferred income taxes on certain regulated capital projects
and state income tax adjustments related to 1995. Partially offsetting these
were the effects of state income taxes.
The 1997 extraordinary loss results from the early extinguishment of
debt (see Note 6 for additional information).
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, 1997, Williams had
access to $566 million of liquidity representing $468 million available under
its $1 billion bank-credit facility, $85 million available under the commercial
paper program, and cash-equivalent investments. This compares with liquidity
of $550 million at December 31, 1996, and $499 million at September 30, 1996.
At September 30, 1997, $468 million of notes payable and current debt
obligations have been classified as non-current obligations based on Williams'
intent and ability to refinance them on a long-term basis with the remaining
amount available under the $1 billion bank-credit facility.
In July 1997, Williams Holdings finalized a commercial paper program
backed by a new $500 million short-term bank-credit facility. At September 30,
1997, $414 million of commercial paper was outstanding under the program.
In 1997, capital expenditures are estimated to be approximately $1.5
billion. During 1997, Williams expects to finance capital expenditures,
investments and working-capital requirements through cash generated from
operations, the use of the available portion of its $1 billion bank-credit
facility, commercial paper, short-term uncommitted bank lines and/or public
debt/equity offerings.
Financing Activities
In September 1997, Williams initiated a restructuring of its debt
portfolio (see Note 8). As of September 30, 1997, Williams has paid
approximately $1.2 billion to redeem approximately $1 billion of its higher
interest rate debt, resulting in an extraordinary loss of
14
<PAGE> 16
$73.7 million (see Note 6). A total of approximately $300 million of
additional debt is expected to be redeemed in the fourth quarter of 1997,
resulting in an additional extraordinary loss of approximately $6 million in
the fourth quarter of 1997. The restructuring has been temporarily financed
with the combination of its $1 billion bank-credit facility and $957 million of
borrowings under short-term bank agreements with commitments totaling $1.2
billion. Registration statements were filed with the Securities and Exchange
Commission in September 1997 by Williams, Williams Holdings, Northwest Pipeline
and Transcontinental Gas Pipe Line (wholly-owned subsidiaries of Williams)
bringing the total financing filed for by these companies under outstanding
shelf registration statements to $900 million, $820 million, $400 million and
$500 million, respectively. No securities had been issued under these
registration statements at September 30, 1997.
In November 1997, $300 million of 6.5 - 6.625 percent notes due 2002-
2004 were issued by Williams under its registration statement. These proceeds
were used to repay temporary financing. Additional securities are expected to
be issued under these registration statements in the fourth quarter of 1997 and
first quarter of 1998 with proceeds to be used to repay temporary financing.
Also in September 1997, Williams redeemed the remaining shares of its
$2.21 cumulative preferred stock for $18.5 million in cash.
In July 1997, Transcontinental Gas Pipe Line entered into a $150 million
five-year bank term loan agreement. The proceeds were used for general
corporate purposes.
In July 1997, Texas Gas Transmission Corporation, a wholly-owned
subsidiary of Williams, issued $100 million of 7.25 percent debentures due
2027, under a $200 million shelf registration filed with the Securities and
Exchange Commission in May 1997. The proceeds were used to repay $100 million
of 9.625 percent notes which matured in July 1997.
In June 1997, Williams Holdings issued $180 million of medium terms
notes under a previously outstanding registration statement. The proceeds were
used for general corporate purposes.
In January 1997, Williams expanded its revolving receivables facility
and sold $200 million of receivables. The proceeds were used primarily for the
repayment of long-term debt.
The consolidated long-term debt to debt-plus-equity ratio decreased to
53.4 percent at September 30, 1997, from 56.1 percent at December 31, 1996, due
primarily to short-term borrowings of $429 million during the quarter for
temporary financing for the debt restructuring.
Investing Activities
On April 30, 1997, Williams and Northern Telecom (Nortel) combined their
customer premise equipment sales and services operations into a limited
liability company, WilTel Communications, LLC (LLC). In addition, Williams
paid $68 million to Nortel. Williams has accounted for its 70 percent in the
operations that Nortel contributed to the LLC as a purchase business
combination. Williams recorded the 30 percent reduction in its operations
contributed to the LLC as a sale to the minority shareholders of the LLC (see
Note 4).
During the second quarter of 1997, Williams sold interests in certain
coal-seam natural gas properties for $56 million in cash.
During the first quarter of 1997, Williams purchased a 20 percent
interest in a foreign telecommunications business for $65 million in cash.
15
<PAGE> 17
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 11--Computation of Earnings Per Common and Common-
equivalent Share
Exhibit 12--Computation of Ratio of Earnings to Combined
Fixed Charges and Preferred Stock Dividend
Requirements
(b) During the third quarter of 1997, the Company filed a Form
8-K on September 8, 1997, which reported a significant event
under Item 5 of the Form and included the exhibits required
by Item 7 of the Form.
<PAGE> 18
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
THE WILLIAMS COMPANIES, INC.
-----------------------------------------
(Registrant)
Gary R. Belitz
-----------------------------------------
Gary R. Belitz
Controller
(Duly Authorized Officer and
Principal Accounting Officer)
November 14, 1997
<PAGE> 19
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
<S> <C>
11 Computation of Earnings Per Common and Common-equivalent
Share
12 Computation of Ratio of Earnings to Combined Fixed
Charges and Preferred Stock Dividend Requirements
27 Financial Data Schedule
</TABLE>
<PAGE> 1
Exhibit 11
The Williams Companies, Inc.
Computation of Earnings Per Common and Common-Equivalent Share
<TABLE>
<CAPTION>
(Thousands, except per-share amounts)
------------------------------------------------------
Three months ended Nine months ended
September 30, September 30,
------------------------- -------------------------
1997 1996 1997 1996
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
Primary earnings:
Net income (loss) $ (8,400) $ 71,000 $ 205,300 $ 256,300
Preferred stock dividends:
$2.21 cumulative preferred stock 200 400 1,000 1,200
$3.50 cumulative convertible preferred stock 2,200 2,200 6,600 6,600
---------- ---------- ---------- ----------
Income (loss) applicable to common stock $ (10,800) $ 68,400 $ 197,700 $ 248,500
========== ========== ========== ==========
Primary shares:
Average number of common shares outstanding during the period 159,009 157,349 158,518 157,052
Common-equivalent shares attributable to options and deferred stock 3,950 5,063 4,056 5,090
---------- ---------- ---------- ----------
Total common and common-equivalent shares 162,959 162,412 162,574 162,142
========== ========== ========== ==========
Primary earnings per common and common-equivalent share:
Income before extraordinary loss $ .39 $ .42 $ 1.67 $ 1.53
Extraordinary loss from early extinguishment of debt (.45) -- (.45) --
---------- ---------- ---------- ----------
Net income (loss) $ (.06) $ .42 $ 1.22 $ 1.53
========== ========== ========== ==========
Fully diluted earnings:
Net income (loss) $ (8,400) $ 71,000 $ 205,300 $ 256,300
$2.21 cumulative preferred stock dividends 200 400 1,000 1,200
---------- ---------- ---------- ----------
Income (loss) applicable to common stock $ (8,600) $ 70,600 $ 204,300 $ 255,100
========== ========== ========== ==========
Fully diluted shares:
Average number of common shares outstanding during the period 159,009 157,349 158,518 157,052
Common-equivalent shares attributable to options and deferred stock 4,135 5,259 4,287 5,278
Dilutive preferred shares 5,858 5,859 5,858 5,859
---------- ---------- ---------- ----------
Total common and common-equivalent shares 169,002 168,467 168,663 168,189
========== ========== ========== ==========
Fully diluted earnings per common and common-equivalent share:
Income before extraordinary loss $ .39 $ .42 $ 1.65 $ 1.52
Extraordinary loss from early extinguishment of debt (.44) -- (.44) --
---------- ---------- ---------- ----------
Net income (loss) $ (.05) $ .42 $ 1.21 $ 1.52
========== ========== ========== ==========
</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, 1997
------------------
<S> <C>
Earnings:
Income before income taxes $ 412.6
Add:
Interest expense - net 291.2
Rental expense representative of interest factor 18.6
Minority interest in income of consolidated subsidiaries 9.5
Other 1.6
----------
Total earnings as adjusted plus fixed charges $ 733.5
==========
Fixed charges and preferred stock dividend requirements:
Interest expense - net $ 291.2
Capitalized interest 10.4
Rental expense representative of interest factor 18.6
Pretax effect of dividends on preferred stock of
the Company 12.5
----------
Combined fixed charges and preferred stock dividend
requirements $ 332.7
==========
Ratio of earnings to combined fixed charges and
preferred stock dividend requirements 2.20
==========
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> SEP-30-1997
<CASH> 93,957
<SECURITIES> 0
<RECEIVABLES> (1,009,430)
<ALLOWANCES> (8,792)
<INVENTORY> 285,773
<CURRENT-ASSETS> 1,889,941
<PP&E> 12,009,620
<DEPRECIATION> (2,149,037)
<TOTAL-ASSETS> 13,253,652
<CURRENT-LIABILITIES> 3,057,944
<BONDS> 4,043,623
0
142,496
<COMMON> 161,668
<OTHER-SE> 3,224,376
<TOTAL-LIABILITY-AND-EQUITY> 13,253,652
<SALES> 0
<TOTAL-REVENUES> 3,143,043
<CGS> 0
<TOTAL-COSTS> 1,911,729
<OTHER-EXPENSES> 0
<LOSS-PROVISION> (5,694)
<INTEREST-EXPENSE> 301,556
<INCOME-PRETAX> 412,636
<INCOME-TAX> 133,602
<INCOME-CONTINUING> 279,034
<DISCONTINUED> 0
<EXTRAORDINARY> (73,694)
<CHANGES> 0
<NET-INCOME> 205,340
<EPS-PRIMARY> 1.22
<EPS-DILUTED> 1.21
</TABLE>
