UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
---
EXCHANGE ACT OF 1934 for the quarterly period ended November 30, 1999.
OR
___ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 for the transition period from _______ to ________
Commission file number 001-13643
ONEOK, Inc.
(Exact name of registrant as specified in its charter)
Oklahoma 73-1520922
(State or other jurisdiction (I.R.S. Employer
of incorporation of organization) Identification No.)
100 West Fifth Street, Tulsa, OK 74103
(Address of principal (Zip Code)
executive offices)
Registrant's telephone number, including area code (918) 588-7000
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___
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On November 30, 1999, the Company had 30,131,625 shares of common stock
outstanding.
ONEOK, Inc.
QUARTERLY REPORT ON FORM 10-Q
Part I. Financial Information Page No.
Consolidated Condensed Statements of Income -
Three Months Ended November 30, 1999 and 1998 3
Consolidated Condensed Balance Sheets -
November 30, 1999 and August 31, 1999 4
Consolidated Condensed Statements of Cash Flows -
Three Months Ended November 30, 1999 and 1998 5
Notes to Consolidated Condensed Financial Statements 6 - 9
Management's Discussion and Analysis of
Financial Condition and Results of Operations 10 - 18
Part II. Other Information 19 - 20
2
Part I - FINANCIAL INFORMATION
ONEOK, Inc. and Subsidiaries
CONSOLIDATED CONDENSED STATEMENTS OF INCOME
(Unaudited) Three Months Ended
November 30,
1999 1998
- --------------------------------------------------------------------------------
(Thousands of Dollars, except
per share amounts)
Operating Revenues $ 533,482 $ 374,936
Cost of gas 338,994 239,836
- --------------------------------------------------------------------------------
Net Revenues 194,488 135,100
- --------------------------------------------------------------------------------
Operating Expenses
Operations and maintenance 104,821 64,589
Depreciation, depletion, and amortization 32,547 31,138
General taxes 11,043 9,374
- --------------------------------------------------------------------------------
Total Operating Expenses 148,411 105,101
- --------------------------------------------------------------------------------
Operating Income 46,077 29,999
- --------------------------------------------------------------------------------
Other income - 4,993
Interest 20,357 11,355
Income taxes 9,990 9,387
- --------------------------------------------------------------------------------
Net Income 15,730 14,250
Preferred Stock Dividends 9,275 9,324
- --------------------------------------------------------------------------------
Income Available for Common Stock $ 6,455 $ 4,926
================================================================================
Earnings Per Share of Common Stock - Basic $ 0.21 $ 0.16
================================================================================
Earnings Per Share of Common Stock - Diluted $ 0.21 $ 0.16
================================================================================
Dividends Per Share of Common Stock $ 0.31 $ 0.31
================================================================================
Average Shares of Common Stock - Basic
(Thousands) 30,666 31,535
Average Shares of Common Stock - Diluted
(Thousands) 30,681 31,578
See accompanying notes to consolidated condensed financial statements.
3
ONEOK, Inc. and Subsidiaries
CONSOLIDATED CONDENSED BALANCE SHEETS
November 30, August 31,
(Unaudited) 1999 1999
- ---------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Assets
Current Assets
Cash and cash equivalents $ - $ 4,402
Trade accounts and notes receivable 284,055 228,336
Inventories 155,905 118,951
Other current assets 101,171 87,578
- ---------------------------------------------------------------------------------------------------------
Total Current Assets 541,131 439,267
- ---------------------------------------------------------------------------------------------------------
Property, Plant and Equipment 3,119,425 3,057,626
Accumulated depreciation, depletion, and amortization 1,015,845 988,797
- ---------------------------------------------------------------------------------------------------------
Net Property 2,103,580 2,068,829
- ---------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets
Regulatory assets, net 244,831 246,658
Goodwill 80,993 81,560
Investments and other 204,352 188,631
- ---------------------------------------------------------------------------------------------------------
Total Deferred Charges and Other Assets 530,176 516,849
- ---------------------------------------------------------------------------------------------------------
Total Assets $ 3,174,887 $ 3,024,945
=========================================================================================================
Liabilities and Shareholders' Equity
Current Liabilities
Current maturities of long-term debt $ 22,817 $ 22,817
Notes payable 376,946 263,747
Accounts payable 223,292 183,759
Accrued taxes 4,620 11,186
Accrued interest 13,187 7,042
Other 50,561 55,031
- ---------------------------------------------------------------------------------------------------------
Total Current Liabilities 691,423 543,582
- ---------------------------------------------------------------------------------------------------------
Long-term Debt, excluding current maturities 809,428 810,087
Deferred Credits and Other Liabilities
Deferred income taxes 346,782 323,624
Other deferred credits 179,727 173,193
- ---------------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 526,509 496,817
- ---------------------------------------------------------------------------------------------------------
Total Liabilities 2,027,360 1,850,486
- ---------------------------------------------------------------------------------------------------------
Commitments and Contingencies (Note F)
Shareholders' Equity
Convertible Preferred Stock, $0.01 par value: Series A authorized
20,000,000 shares; issued and outstanding 19,946,448 shares 199 199
Common stock, $0.01 par value: authorized 100,000,000 shares; issued
31,599,305 shares, outstanding 30,131,625 and 30,884,225 shares 316 316
Paid in capital 894,978 894,978
Unearned compensation (1,933) -
Retained earnings 298,351 301,536
Treasury stock at cost: 1,467,680 and 715,080 shares (44,384) (22,570)
- ---------------------------------------------------------------------------------------------------------
Total Shareholders' Equity 1,147,527 1,174,459
- ---------------------------------------------------------------------------------------------------------
Total Liabilities and Shareholders' Equity $ 3,174,887 $ 3,024,945
=========================================================================================================
See accompanying notes to consolidated condensed financial statements.
4
ONEOK, Inc. and Subsidiaries
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
Three Months Ended
November 30,
(Unaudited) 1999 1998
- -------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Activities
Net income $ 15,730 $ 14,250
Depreciation, depletion, and amortization 32,547 31,138
Gain on sale of assets - (4,993)
Net income from other investments (1,760) (442)
Deferred income taxes 23,652 (3,883)
Changes in assets and liabilities (80,640) (66,088)
- -------------------------------------------------------------------------------------------
Cash Provided by (Used in) Operating Activities (10,471) (30,018)
- -------------------------------------------------------------------------------------------
Investing Activities
Changes in other investments, net 641 442
Capital expenditures, net of salvage (64,307) (29,371)
Proceeds from sale of property - 22,000
- -------------------------------------------------------------------------------------------
Cash Used in Investing Activities (63,666) (6,929)
- -------------------------------------------------------------------------------------------
Financing Activities
Issuance (payment) of notes payable, net 113,199 (144,000)
Issuance of debt - 200,000
Payment of debt (797) -
Acquisition of treasury stock (23,882) -
Dividends paid (18,785) (19,099)
- -------------------------------------------------------------------------------------------
Cash Provided by Financing Activities 69,735 36,901
- -------------------------------------------------------------------------------------------
Change in Cash and Cash Equivalents (4,402) (46)
Cash and Cash Equivalents at Beginning of Period 4,402 86
- -------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ - $ 40
===========================================================================================
See accompanying notes to consolidated condensed financial statements.
5
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Unaudited)
A. Summary of Significant Accounting Policies
Interim Reporting. The interim consolidated condensed financial statements
reflect all adjustments which, in the opinion of management, are necessary for a
fair presentation of the results for the interim periods presented. All such
adjustments are of a normal recurring nature. Due to the seasonal nature of the
business, the results of operations for the three months ended November 30,
1999, are not necessarily indicative of the results that may be expected for a
twelve-month period. For further information, refer to the consolidated
financial statements and footnotes thereto included in the Company's Form 10-K
for the year ended August 31, 1999.
Reclassification. Certain amounts for 1999 have been reclassified to conform
with the 2000 presentation. In particular, the Company reclassified other
income, including gains on sales of assets, from operating revenue to a separate
caption, and now presents operating income.
B. Significant Events
A July, 1999 order from the Oklahoma Corporation Commission (OCC) removed the
Oklahoma gathering and storage assets from utility regulation effective
November 1, 1999. These assets are now included in the Transportation and
Storage segment where they are being utilized in the competitive marketplace. An
August, 1999 order from the OCC distinguished between upstream (transportation)
and downstream (distribution) assets and cleared the way for future unbundling
activities including competitive bidding for transportation services in
Oklahoma. The Distribution segment issued bids for these services in Oklahoma
during the quarter ended November 30, 1999 with contracts to be awarded in the
spring of 2000.
In October, 1999, the Company's Board of Directors approved a change in the
Company's fiscal year-end. The fiscal year-end will be changed from August 31 to
December 31 effective January 1, 2000. The Transition Report covering the four
months ended December 31, 1999, will be filed on a Form 10-Q.
On May 25, 1999, the Company began buying shares of common stock under a stock
buyback plan authorized in March, 1999. Through November 30, 1999, 1,534,246
shares of common stock were purchased on the open market. The Company is
authorized to buy back up to 15 percent of its capital stock.
C. Regulatory Assets
The table is a summary of regulatory assets, net of amortization, at November
30, 1999, and August 31, 1999.
November 30, August 31,
1999 1999
-------------------------------------------------------------------
(Thousands of Dollars)
Recoupable take-or-pay $ 84,756 $ 85,996
Pension costs 19,836 20,881
Postretirement costs other than pension 61,962 61,830
Other 9,740 8,521
Transition costs 22,785 22,903
Reacquired debt costs 22,221 22,413
Income taxes 23,531 24,114
------------------------------------------------------------------
Regulatory assets, net $ 244,831 $ 246,658
==================================================================
6
D. Supplemental Cash Flow Information
The table is supplemental information relative to the Company's cash flows for
the three months ended November 30, 1999 and 1998.
1999 1998
-------------------------------------------------------------------
(Thousands of Dollars)
Cash paid during the year
Interest (including amounts capitalized) $ 13,258 $ 11,118
Income taxes $ - $ 2,500
Noncash transactions
Gas received as payment in kind $ - $ 61
Treasury stock transferred to
compensation plans $ 2,068 $ -
-------------------------------------------------------------------
E. Earnings per Share Information
The following is a reconciliation of the basic and diluted EPS computations.
Three Months Ended November 30, 1999
Per Share
Income Shares Amount
------------------------------------------------------------------------------
(Thousands, except per share amounts)
Basic EPS
Income available to common stockholders $ 6,455 30,666 $ 0.21
=======
Effect of Dilutive Securities
Options - 15
Convertible preferred stock - -
---------- ------
Diluted EPS
Income available to common stockholders
+ assumed conversions $ 6,455 30,681 $ 0.21
==============================================================================
Three Months Ended November 30, 1998
Per Share
Income Shares Amount
------------------------------------------------------------------------------
(Thousands, except per share amounts)
Basic EPS
Income available to common stockholders $ 4,926 31,535 $ 0.16
=======
Effect of Dilutive Securities
Options - 43
Convertible preferred stock - -
---------- ------
Diluted EPS
Income available to common stockholders
+ assumed conversions $ 4,926 31,578 $ 0.16
===================================================================================
There were 19,874,254 shares of convertible preferred stock and 72,214 option
shares excluded from the calculation of Diluted Earnings per Share due to being
antidilutive for the three months ended November 30, 1999. For the same period
one year ago, there were 20,071,000 convertible preferred shares excluded.
F. Commitments and Contingencies
During the year ended August 31, 1999, the Company and Southwest Gas Corporation
(Southwest) entered into a definitive agreement whereby the Company agreed to
acquire Southwest for $30 per share in an all cash transaction valued at $918
million. The total transaction cost, including assumed debt, is estimated at
$1.8 billion. The transaction is subject to various conditions including
regulatory approvals which are still pending in California and Arizona.
Southwest shareholders approved the agreement on August 10, 1999. On January 4,
7
2000, the Arizona Corporation Commission (ACC) staff filed prefiled testimony
recommending the merger be delayed until a favorable resolution of pending
litigation is reached. The Company and certain of its officers as well as
Southwest have been named as defendants in a lawsuit brought by Southern Union
Company (Southern Union) in connection with the proposed acquisition in the
total amount of $750 million. The Southern Union allegations include, but are
not limited to, Racketeer, Influenced and Corrupt Organization Act violations
and improper interference in a contractual relationship between Southwest and
Southern Union. If the plaintiff should be successful in any of the claims
against the Company or Southwest and substantial damages are awarded, it could
have a material adverse effect on the Company's operations, cash flow, and
financial position. The Company, as third party beneficiary, has filed a lawsuit
against Southern Union for breach of a confidentiality and standstill agreement
with Southern Union and Southwest. The parties are presently involved in
discovery. The Company believes the Southern Union allegations are without merit
and is defending itself vigorously against all claims.
The Company has responsibility for 12 manufactured gas sites located in Kansas
which may contain potentially harmful materials that are classified as hazardous
material. Hazardous materials are subject to control or remediation under
various environmental laws and regulations. A consent agreement with the Kansas
Department of Health and Environment (KDHE) presently governs all future work at
these sites. The terms of the consent agreement allow the Company to investigate
these sites and set remediation priorities based upon the results of the
investigations and risk analysis. The prioritized sites will be investigated
over a ten year period. At November 30, 1999, the costs of the investigations
and risk analysis have been minimal. Limited information is available about the
sites. Management's best estimate of the cost of remediation ranges from $100
thousand to $10 million per site based on a limited comparison of costs incurred
to remediate comparable sites. These estimates do not give effect to potential
insurance recoveries, recoveries through rates or from third parties. The KCC
has permitted others to recover remediation costs through rates. It should be
noted that additional information and testing could result in costs
significantly below or in excess of the amounts estimated above. To the extent
that such remediation costs are not recovered, the costs could be material to
the Company's results of operations and cash flows depending on the remediation
done and number of years over which the remediation is completed.
The Company is a party to litigation matters and claims which are normal in the
course of its operations, and while the results of litigation and claims cannot
be predicted with certainty, management believes the final outcome of such
matters will not have a materially adverse effect on consolidated results of
operations, financial position, or liquidity.
G. Segments
In fiscal 1999, the Company adopted SFAS 131, "Disclosures about Segments of an
Enterprise and Related Information." This statement required the Company to
define and report the Company's business segments based on how management
currently evaluates its business. Management has segmented its business based on
differences in products and services and management responsibility.
The Company conducts its operations through six segments: (1) the Distribution
segment distributes natural gas to residential, commercial and industrial
customers, leases pipeline capacity to others and provides transportation
services for end-use customers; (2) the Transportation and Storage segment
transports and stores natural gas for others; (3) the Marketing segment markets
natural gas to wholesale and retail customers and markets electricity to
wholesale customers; (4) the Gathering and Processing segment gathers and
processes natural gas and natural gas liquids; (5) the Production segment
produces natural gas and oil; and (6) the Other segment primarily operates and
leases the Company's headquarters building and a related parking facility.
Intersegment oil and gas sales are recorded on the same basis as sales to
unaffiliated customers. All corporate overhead costs relating to a reportable
segment have been allocated for the purpose of calculating operating
8
income. The Company's equity method investments do not represent operating
segments of the Company. The Company has no single external customer from which
it receives ten percent or more of its revenues.
Gathering Eliminations
Three Months Ended Transportation and and
November 30, 1999 Distribution and Storage Marketing Processing Production Other Total
- ------------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Sales to unaffiliated customers $ 195,691 $ 13,596 $ 257,144 $ 46,078 $ 15,324 $ 5,649 $ 533,482
Intersegment sales 1,147 17,128 3,714 9,428 3,296 (34,713) -
- -----------------------------------------------------------------------------------------------------------------------------------
Total Revenues $ 196,838 $ 30,724 $ 260,858 $ 55,506 $ 18,620 $ (29,064) $ 533,482
- -----------------------------------------------------------------------------------------------------------------------------------
Net Revenues $ 82,618 $ 30,724 $ 6,866 $ 55,506 $ 18,620 $ 154 $ 194,488
Operating Costs $ 55,410 $ 10,162 $ 2,268 $ 47,282 $ 5,459 $ (4,717) $ 115,864
Depreciation, depletion and
amortization $ 18,636 $ 3,852 $ 182 $ 1,846 $ 7,417 $ 614 $ 32,547
Operating Income $ 8,572 $ 16,710 $ 4,416 $ 6,378 $ 5,744 $ 4,257 $ 46,077
Income from Equity Investments $ - $ 776 $ - $ - $ 984 $ - $ 1,760
Total Assets $ 1,755,218 $ 372,915 $ 309,926 $ 364,602 $ 353,167 $ 19,059 $ 3,174,887
Capital Expenditures $ 22,817 $ 4,392 $ 10,258 $ 21,547 $ 5,153 $ 833 $ 65,000
- -----------------------------------------------------------------------------------------------------------------------------------
Gathering Eliminations
Three Months Ended Transportation and and
November 30, 1999 Distribution and Storage Marketing Processing Production Other Total
- -----------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Sales to unaffiliated customers $ 179,711 $ 6,945 $ 167,825 $ 7,860 $ 8,104 $ 4,491 $ 374,936
Intersegment sales 2,169 20,059 2,596 3,246 5,318 (33,388) -
- -----------------------------------------------------------------------------------------------------------------------------------
Total Revenues $ 181,880 $ 27,004 $ 170,421 $ 11,106 $ 13,422 $ (28,897) $ 374,936
- -----------------------------------------------------------------------------------------------------------------------------------
Net Revenues $ 78,153 $ 27,004 $ 6,441 $ 11,106 $ 13,422 $ (1,026) $ 135,100
Operating Costs $ 56,077 $ 9,262 $ 1,807 $ 7,899 $ 3,767 $ (4,849) $ 73,963
Depreciation, depletion and
amortization $ 18,502 $ 3,315 $ 45 $ 512 $ 7,637 $ 1,127 $ 31,138
Operating Income $ 3,574 $ 14,427 $ 4,589 $ 2,695 $ 2,018 $ 2,696 $ 29,999
Income from Equity Investments $ - $ 433 $ - $ - $ 9 $ - $ 442
Total Assets $ 1,756,980 $ 402,614 $ 144,734 $ 42,833 $ 242,164 $ (93,170) $ 2,496,155
Capital Expenditures $ 19,312 $ 7,173 $ 600 $ 5,004 $ 3,730 $ 2,351 $ 38,170
- -----------------------------------------------------------------------------------------------------------------------------------
9
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
This form 10-Q contains statements concerning Company expectations or
predictions of the future that are "forward-looking statements" within the
meaning of the Private Securities Litigation Reform Act of 1995. these
statements are intended to be covered by the safe harbor provision of the
Securities Act of 1933 and the Securities Exchange Act of 1934. Forward-looking
statements are based on management's beliefs and assumptions based on
information currently available. it is important to note that actual results
could differ materially from those projected in such forward-looking statements.
Factors that may impact forward-looking statements include, but are not limited
to, the following:
. The effects of weather and other natural phenomena;
. increased competition from other energy suppliers as well as alternative
forms of energy;
. the capital intensive nature of the Company's business;
. economic climate and growth in the geographic areas in which the Company
does business;
. the uncertainty of gas and oil reserve estimates;
. the timing and extent of changes in commodity prices for natural gas,
natural gas liquids, electricity, and crude oil;
. the nature and projected profitability of potential projects and other
investments available to the Company;
. conditions of capital markets and equity markets;
. the effects of changes in governmental policies and regulatory actions,
including income taxes, environmental compliance, authorized rates, and
deregulation or "unbundling" of natural gas;
. the pending merger with Southwest Gas Corporation (Southwest); and
. regulatory delay or conditions imposed by regulatory bodies in, and the
results of litigation involving, the Southwest merger.
Accordingly, while the Company believes these forward-looking statements to be
reasonable, there can be no assurance that they will approximate actual
experience or that the expectations derived from them will be realized. when
used in Company documents, the words "anticipate," "expect," "projection,"
"goal" or similar words are intended to identify forward-looking statements. The
Company does not have any intention or obligation to update forward-looking
statements after they distribute this Form 10-Q even if new information, future
events or other circumstances have made them incorrect or misleading.
A. Results of Operations
Consolidated Operations
The Company provides natural gas and related products and services to its
customers through the following segments:
. Distribution
. Transportation And Storage
. Marketing
. Gathering and Processing
. Production
. Other
The Company is the ninth largest natural gas distribution company in the United
States in terms of number of customers. Nonregulated operations involve
transmission, storage, marketing, gathering and processing, and production of
natural gas and natural gas liquids and marketing of electricity .
Operating results continue to be strong despite warmer than normal weather.
while the quarters ended November 30, 1999 and 1998 were both warmer than
normal, the Company is using derivative instruments for fiscal 2000 to reduce
the effect of weather variances during the heating season. During the quarter
ended
10
November 30, 1999, these derivative instruments resulted in revenue of $4.1
million which offset much of the margin variances caused by weather. This
revenue was recorded in the Other segment.
Although some higher interest rate debt was refinanced at a lower interest rate
during fiscal 1999, increased borrowing, primarily due to acquisitions in fiscal
1999, resulted in increased interest expense. Gains on sales of assets of $5.0
million were included in Other Income during the first quarter of fiscal 1999.
Three Months Ended
November 30,
----------------------------------------------------------------------
1999 1998
----------------------------------------------------------------------
(Thousands of Dollars)
Financial Results
Operating revenues $ 533,482 $ 374,936
Cost of gas 338,994 239,836
----------------------------------------------------------------------
Net Revenue 194,488 135,100
Operating costs 115,864 73,963
Depreciation, depletion, and amortization 32,547 31,138
----------------------------------------------------------------------
Operating income $ 46,077 $ 29,999
======================================================================
Other income $ - $ 4,993
======================================================================
Year 2000 - The Year 2000 (Y2K) issue arose because most computer systems,
including application software and computer technology embedded in plant and
equipment were constructed using a two digit date field that assumed the first
two digits are always "19". It was believed that on January 1, 2000, those
systems might incorrectly recognize the date as January 1, 1900, and incorrectly
process critical information or stop processing altogether. Since 1996, the
Company has been in the process of making the necessary conversions to make the
Company Y2K compatible. While there can be no assurance that there will be no
problems related to Y2K, it appears that these efforts were successful. January
1, 2000 passed with no negative impact on any of the Company's systems or
operations.
Distribution
The Distribution segment provides natural gas distribution services in Oklahoma
and Kansas. The Company's operations in Oklahoma are primarily conducted through
Oklahoma Natural Gas Company Division (ONG) which serves residential,
commercial, and industrial customers and leases pipeline capacity. The Company's
operations in Kansas are conducted through Kansas Gas Service Company Division
(KGS) which serves residential, commercial, and industrial customers. KGS also
conducts regulated gas distribution operations in northeastern Oklahoma. The
Distribution segment serves about 80 percent of Oklahoma and about 67 percent of
Kansas. ONG is subject to regulatory oversight by the OCC. KGS is subject to
regulatory oversight by the KCC and the OCC.
Three Months Ended
November 30,
----------------------------------------------------------------------
1999 1998
----------------------------------------------------------------------
(Thousands of Dollars)
Financial Results
Gas sales $ 180,682 $ 164,570
Cost of gas 114,220 103,727
----------------------------------------------------------------------
Gross margin on gas sales 66,462 60,843
PCL and ECT revenues 12,670 13,621
Other revenues 3,486 3,689
----------------------------------------------------------------------
Net revenues 82,618 78,153
Operating costs 55,410 56,077
Depreciation, depletion, and amortization 18,636 18,502
----------------------------------------------------------------------
Operating Income $ 8,572 $ 3,574
======================================================================
11
Three Months Ended
November 30,
1999 1998
-------------------------------------------------------------
Gross Margin Per Mcf
Oklahoma
Residential $ 3.83 $ 4.18
Commercial $ 2.83 $ 2.87
Industrial $ 1.12 $ 1.19
Pipeline capacity leases $ 0.25 $ 0.23
Kansas
Residential $ 3.49 $ 3.36
Commercial $ 2.40 $ 2.23
Industrial $ 2.00 $ 1.99
End-use customer transportation $ 0.55 $ 0.43
-------------------------------------------------------------
Three Months Ended
November 30,
1999 1998
-------------------------------------------------------------
Operating Information
Number of customers 1,419,974 1,401,198
Capital expenditures (Thousands) $ 22,817 $ 19,312
Total assets (Thousands) $ 1,755,218 $ 1,756,980
Customers per employee 537 518
-------------------------------------------------------------
Three Months Ended
November 30,
1999 1998
-------------------------------------------------------------
Volumes (MMcf)
Gas sales
Residential 15,680 15,197
Commercial 5,815 6,124
Industrial 1,207 1,064
-------------------------------------------------------------
Total volumes sold 22,702 22,385
PCL and ECT 45,865 57,541
-------------------------------------------------------------
Total volumes delivered 68,567 79,926
=============================================================
Gross margins on gas sales increased primarily due to reduced transportation
costs paid to an affiliate and an increase in volumes sold during the quarter
ended November 30, 1999 compared to the same period one year ago. Pipeline
Capacity Lease (PCL) and End-use Customer Transportation (ECT) revenues and
volumes decreased primarily due to the loss of three customers and the effect of
warm weather including the temporary shut-down of two power plants served by the
Distribution segment. The volume decrease was partially offset by an increase in
rates.
Two rate cases were combined in Oklahoma, eliminating an interim rate case
scheduled for the summer of 1999 and providing for a one-time interim rate
reduction of $5 million which began September 1, 1999 for residential customers
in Oklahoma. The amount of the rate reduction in the quarter ended November 30,
1999 was $0.8 million. A July, 1999 order from the OCC removed the Oklahoma
gathering and storage assets from utility regulation effective November 1, 1999.
These assets are now included in the Transportation and Storage segment where
they are being utilized in the competitive marketplace. The removal of the
gathering and storage assets from rate base will result in a net reduction of
revenues of $29.0 million on an annualized basis, based on the allocation of
costs from the 1994 rate case. The Transportation and Storage and Marketing
segments are aggressively seeking new business opportunities and have replaced a
substantial portion of the revenues. Additionally, a charge to be collected
through the PGA for ONG's current working gas in storage will replace a portion
of the revenues. These revenue adjustments are subject to review in the current
consolidated rate case with hearings scheduled for the spring of 2000.
12
In August, 1999, the OCC approved a plan to distinguish between upstream and
downstream activities in Oklahoma. The Distribution segment began taking bids
this fall for transportation services in Oklahoma with contracts to be awarded
in the spring of 2000 for service beginning November 1, 2000. As contracts with
PCL customers expire, these contracts may be renewed with the Distribution
segment, the Transportation and Storage segment of the Company or nonaffiliated
service providers. Consequently, this could result in reduced revenues in the
Distribution segment.
Certain costs to be recovered through the rate making process have been recorded
as regulatory assets in accordance with Statement of Financial Accounting
Standards No. 71, "Accounting for the Effects of Certain Types of Regulation"
(SFAS 71). As the Company continues to unbundle its services, certain of these
assets may no longer meet the criteria for following SFAS 71, and accordingly, a
write-off of regulatory assets and stranded costs may be required. The Company
does not anticipate these costs to be significant.
Transportation and Storage
The Company's gathering and storage assets and services in Oklahoma were removed
from utility regulation effective November 1, 1999. Gathering and storage
assets, including current gas in storage, of $325.0 million were removed from
rate base. With unbundling and deregulation of gathering and storage service,
the Company is able to compete for business at market-based rates. The Company's
strategy to increase its storage utilization through greater injection and
withdrawal capabilities has resulted in increased storage revenues for the
quarter ended November 30, 1999 compared to the same period one year ago. A
decrease in transportation for an affiliate and warmer weather resulted in
decreased transportation volumes and revenues for the quarter ended November 30,
1999 compared to the same period one year ago. The increase in other revenues is
due to increased revenues from retained fuel.
Three Months Ended
November 30,
1999 1998
----------------------------------------------------------------------
(Thousands of Dollars)
Financial Results
Transportation revenues $ 15,739 $ 18,568
Storage revenues 9,832 6,573
Other revenues 5,153 1,863
----------------------------------------------------------------------
Net revenues 30,724 27,004
Operating costs 10,162 9,262
Depreciation, depletion, and amortization 3,852 3,315
----------------------------------------------------------------------
Operating income $ 16,710 $ 14,427
======================================================================
Three Months Ended
November 30,
1999 1998
---------------------------------------------------------------
Operating Information
Volumes transported (MMcf) 56,338 74,671
Injection Horsepower 35,300 31,000
Capital expenditures (Thousands) $ 4,392 $ 7,173
Total assets (Thousands) $ 372,915 $ 402,614
---------------------------------------------------------------
13
Marketing
The Company's marketing operation purchases, stores and markets natural gas at
both the retail and wholesale level, primarily in the producing areas of the
United States. The Company continues to develop its niche into new market areas
by arbitraging storage in the day trading market rather than focusing on the
baseload market. Gas volumes increased in the quarter ended November 30, 1999
over the same period one year ago primarily from the Company's expansion into
the Permian/Waha region of the United States. The Company now leases from others
more than 29 Bcf of storage capacity which gives direct access to the west coast
and Texas intrastate markets.
Three Months Ended
November 30,
1999 1998
----------------------------------------------------------------------
(Thousands of Dollars)
Financial Results
Gas sales $ 260,606 $ 168,395
Cost of gas 253,992 163,980
----------------------------------------------------------------------
Gross margin on gas sales 6,614 4,415
Other revenues 252 2,026
----------------------------------------------------------------------
Net revenues 6,866 6,441
Operating costs 2,268 1,807
Depreciation, depletion, and amortization 182 45
----------------------------------------------------------------------
Operating income $ 4,416 $ 4,589
======================================================================
Three Months Ended
November 30,
1999 1998
----------------------------------------------------------------------
Operating Information
Natural gas volumes (MMcf) 93,676 86,556
Capital expenditures (Thousands) $ 10,258 $ 600
Total assets (Thousands) $ 309,926 $ 144,734
----------------------------------------------------------------------
The increase in gross margins is attributable to increased throughput, higher
margins, and a more extensive use of storage. The use of storage has allowed the
Company to concentrate on the day-to-day market and take advantage of volatility
in that market. Emphasis on base load market has been reduced. Increased sales
volumes are primarily due to the expanded niche business into Texas and the west
coast. The decrease in other revenues is due to the recovery of prior period
costs in the quarter ended November 30, 1998. The increase in operating costs is
related to leasing storage and start-up costs for ONEOK Power Marketing Company.
Trading of electricity at market-based wholesale rates has begun but has had
minimal impact on operations to date.
Gathering and Processing
Revenues increased in the quarter ended November 30, 1999 over the same period
one year ago due to the acquisition of the midstream natural gas gathering and
processing assets from Koch Midstream Enterprises in April, 1999. Operating
costs and depreciation, depletion and amortization also increased due to the
additional assets and the cost of operating those assets. Total gas gathered and
total gas processed for the quarter ended November 30, 1999 increased 347.7 MMcf
per day and 281.5 MMcf per day, respectively, compared to the same period one
year ago. Average NGL price per gallon increased as prices continued to
experience an upward correction from the abnormally low prices prevalent
throughout much of fiscal 1999. Other income in fiscal 1999 consisted of the
gains on sales of assets.
14
Three Months Ended
November 30,
-----------------------------------------------------------------------
1999 1998
-----------------------------------------------------------------------
(Thousands of Dollars)
Financial Results
Natural gas liquids and condensate sales $ 32,368 $ 6,708
Gas sales 18,305 3,062
Gathering revenues 5,024 -
Other revenues (191) 1,336
-----------------------------------------------------------------------
Total revenues 55,506 11,106
Cost of sales 40,996 6,214
-----------------------------------------------------------------------
Gross margin 14,510 4,892
Operating costs 6,286 1,685
Depreciation, depletion, and amortization 1,846 512
-----------------------------------------------------------------------
Operating income $ 6,378 $ 2,695
=======================================================================
Other income $ - $ 4,993
=======================================================================
Three Months Ended
November 30,
1999 1998
-----------------------------------------------------------------------
Operating Information
Average NGL's price ($/Gal) $ 0.371 $ 0.225
Average gas price ($/Mcf) $ 2.59 $ 1.77
Capital expenditures (Thousands) $ 21,547 $ 5,004
Total assets (Thousands) $ 364,602 $ 42,833
Total gas gathered (Mcf/D) 471,797 124,111
Total gas processed (Mcf/D) 394,320 112,828
Natural gas liquids sales (MGal) 93,534 29,276
Gas sales (MMMbtu) 7,057 1,733
Natural Gas Liquids by Component (%)
Ethane 46 47
Propane 27 25
Iso butane 5 4
Normal butane 9 9
Natural gasoline 13 15
Contracts %
Percent of Proceeds 64 65
Fuel and Shrink 36 35
-----------------------------------------------------------------------
Production
Increased production from a successful developmental drilling program and
properties acquired during fiscal 1999 were the primary reasons for the
increases in volumes for the quarter ended November 30, 1999 compared to the
same period one year ago. Gas and oil prices for the quarter ended November 30,
1999 increased compared to the same period one year ago. Operating costs also
increased over one year ago due to the Company operating and owning an interest
in an increased number of wells.
Three Months Ended
November 30,
1999 1998
----------------------------------------------------------------------
(Thousands of Dollars)
Financial Results
Natural gas sales $ 15,610 $ 11,950
Oil sales 1,966 1,354
Other revenues 1,044 118
----------------------------------------------------------------------
Net revenues 18,620 13,422
Operating costs 5,459 3,767
Depreciation, depletion, and amortization 7,417 7,637
----------------------------------------------------------------------
Operating income $ 5,744 $ 2,018
======================================================================
15
Three Months Ended
November 30,
1999 1998
----------------------------------------------------------
Operating Information
Proved reserves
Gas (MMcf) 251,593 175,048
Oil (MBbls) 4,109 3,273
Production
Gas (MMcf) 6,347 5,714
Oil (MBbls) 106 105
Average price
Gas (Mcf) $ 2.46 $ 2.07
Oil (Bbls) $ 18.59 $ 12.94
Capital expenditures (Thousands) $ 5,153 $ 3,730
Total assets (Thousands) $ 353,167 $ 242,164
==========================================================
FINANCIAL FLEXIBILITY AND LIQUIDITY
The Company's capitalization structure is 49 percent equity and 51 percent debt
(including short-term debt) at November 30, 1999, compared to 66 percent equity
and 34 percent debt at November 30, 1998.
Cash provided by operating activities remains strong and continues as the
primary source for meeting day-to-day cash requirements. However, due to
seasonal fluctuations, acquisitions, and additional capital requirements, the
Company accesses funds through commercial paper, short-term credit agreements
and, if necessary, through long-term borrowing.
Operating Cash Flows
Operating cash flows for the three months ended November 30, 1999, as compared
to the same period one year ago are higher due to higher operating income.
Additionally, no tax payments have been made this quarter due to the accelerated
depreciation on the assets acquired from Koch.
Investing Cash Flows
Capital expenditures totaled $65.0 million for the quarter ended November 30,
1999. This included $10.1 million for construction of an electric generating
plant and $12.3 million for the purchase of a gathering pipeline in western
Oklahoma. For the same period one year ago, capital expenditures totaled $38.2
million.
Financing Cash Flows
At November 30, 1999, $832.2 million of long-term debt was outstanding. As of
that date, the Company could have issued $695.3 million of additional long-term
debt under the most restrictive provisions contained in its various borrowing
agreements.
On March 18, 1999, the Company authorized a stock buyback plan for up to 15
percent of its capital stock. The program authorizes the Company to make
purchases of its common stock on the open market with the timing and terms of
purchases and the number of shares purchased to be determined by management
based on market conditions and other factors. Purchases began May 25, 1999, with
1,534,246 shares purchased through November 30, 1999. The purchased shares are
held in treasury and are available for general corporate purposes, funding of
stock-based compensation plans, resale, or retirement. Purchases are financed
with short-term debt.
The Company believes that internally generated funds and access to financial
markets will be sufficient to meet its normal debt services, dividend
requirements, and capital expenditures.
16
LIQUIDITY
Competition continues to increase in all segments of the Company's business. The
loss of major customers without recoupment of those revenues and negative
effects of weather are among the events which could have a material adverse
effect on the Company's financial condition. However, rates in the Distribution
segment are structured to reduce the Company's risk in serving its large
customers. Other strategies, such as the use of derivative instruments to offset
the effect of weather variances, and aggressive negotiations with potential new
customers are expected to reduce other risks to the Company.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Risk Management - The Company, substantially through its nonutility segments, is
exposed to market risk in the normal course of its business operations to the
impact of market fluctuations in the price of natural gas and oil. Market risk
refers to the risk of loss in cash flows and future earnings arising from
adverse changes in commodity energy prices. The Company's primary exposure
arises from fixed price purchase or sale agreements which extend for periods of
up to 48 months, gas in storage inventories utilized by the gas marketing
operation, and anticipated sales of oil and gas production. To a lesser extent,
the Company is exposed to risk of changing prices or the cost of intervening
transportation resulting from purchasing gas at one location and selling it at
another (hereinafter referred to as basis risk). To minimize the risk from
market fluctuations in the price of natural gas and oil, the Company uses
commodity derivative instruments such as future contracts, swaps and options to
hedge existing or anticipated purchase and sale agreements, existing physical
gas in storage, and basis risk. None of these derivatives are held for
speculative purposes. The Company adheres to policies and procedures which limit
its exposure to market risk from open positions and monitors its exposure to
market risk. The results of the Company's derivative hedging activities continue
to meet its stated objective.
The Company's regulated distribution operations are exposed to market risk in
the normal course of business operations due to the impact of fluctuations on
gas sales resulting from weather as measured by heating degree days (HDD).
Market risk refers to the risk of loss in cash flows and future earnings arising
from adverse fluctuation in gross margins on gas sales. Kansas Gas Service has
exposure arising from variances in gas consumption by residential and commercial
customers caused by fluctuations in HDD from normal because it does not have a
temperature adjustment clause (TAC) in its rate structure. ONG has a TAC, which
partially mitigates this risk. To minimize the risk of HDD on gas sales margins,
the Company is using weather derivative swaps to manage the risk of adverse
fluctuations in HDD during the 1999/2000 heating season.
The Company has $300 million in long-term debt at a floating interest rate as a
result of an interest rate swap. The rate resets semiannually based on the six-
month LIBOR at the reset date. All of the Company's remaining long-term debt is
fixed-rate and, therefore, does not expose the Company to the risk of earnings
or cash flow loss due to changes in market interest rates.
Kansas Gas Service uses derivative instruments to hedge the cost of some
anticipated gas purchases during the winter heating months to protect their
customers from upward volatility in the market price of natural gas. The gain or
loss resulting from such derivatives is combined with the physical cost of gas
and recovered from the customer through the gas purchase clause in rates. The
Company has no market risk associated with such activities and, accordingly,
these derivatives have been omitted from the value-at-risk disclosures below.
Value-at-Risk Disclosure of Market Risk - The estimation of potential losses
that could arise from changes in market conditions is typically accomplished
through the use of statistical models that seek to predict risk of loss based on
historical price and volatility patterns. The value-at-risk (VAR) measurement
used by the Company is based on J.P. Morgan's RiskMetrics/TM/ model, which
measures recent volatility and correlation in the price of natural gas and oil,
pulls through current price levels and net deltas, and applies estimates made by
management regarding the time required to liquidate positions and the degree of
confidence placed in the accuracy of the volatility and correlation estimates.
The Company's VAR calculation presents a comprehensive market risk
17
disclosure by combining its commodity derivative portfolio used to hedge price
and basis risk together with the current portfolio of firm physical purchase and
sale contracts and nonutility gas-in-storage inventory. At November 30, 1999,
the Company's estimated potential one-day favorable or unfavorable impact on
future earnings, as measured by the VAR, using a 95 percent confidence level,
diversified correlation and assuming three days to liquidate positions is
immaterial.
The Company's calculated VAR exposure represents an estimate of potential losses
that would be recognized for its portfolio of derivative financial instruments
and firm physical contracts and nonutility gas-in-storage assuming hypothetical
movements in future market rates and are not necessarily indicative of actual
results that may occur. It does not represent the maximum possible loss nor any
expected loss that may occur, because actual future gains and losses will differ
from those estimated, based on actual fluctuations in the market rates,
operating exposures, and the timing thereof, and changes in the Company's
portfolio of derivative financial instruments and firm physical contracts.
Under the weather derivative swap agreements, the Company receives a fixed
payment per degree day below the contracted normal HDD and pays a fixed amount
per degree day above the contracted normal HDD. The swaps also contain a
contract cap that limits the amount either party is required to pay. The Company
estimates its VAR exposure on these swaps to be the total contract cap it would
be required to pay if the weather were significantly colder than normal. At
November 30, 1999, the total VAR for the 1999/2000 heating season is
approximately $18.0 million. The Company believes that this risk would be
substantially offset by an increase in gas sales margins resulting from
additional gas sold due to the colder than normal temperatures.
NEW ACCOUNTING PRONOUNCEMENT
Statement of Financial Accounting Standards No. 133, Accounting for Derivatives
Instruments and Hedging Activities (Statement 133), was issued by the FASB in
June, 1998. Statement 133 standardizes the accounting for derivatives
instruments, including certain derivative instruments embedded in other
contracts. Under the standard, entities are required to carry all derivative
instruments in the balance sheet at fair value. The accounting for changes in
the fair value of a derivative instrument depends on whether it has been
designated and qualifies as part of a hedging relationship and, if so, on the
reason for holding it. If certain conditions are met, entities may elect to
designate a derivative instrument as a hedge of exposures to changes in fair
values, cash flows, or foreign currencies. If the hedge exposure is a fair value
exposure, the gain or loss on the derivative instrument is recognized in
earnings in the period of change together with the offsetting loss or gain on
the hedged item attributable to the risk being hedged. If the hedged exposure is
a cash flow exposure, the effective portion of the gain or loss on the
derivative instrument is reported initially as a component of other
comprehensive income (outside earnings) and subsequently reclassified into
earnings when the forecasted transaction affects earnings. Any amounts excluded
from the assessment of hedge effectiveness as well as the ineffective portion of
the gain or loss is reported in earnings immediately. Statement 133 required the
Company to adopt this statement by September 1, 1999. Statement 133 was amended
by Statement No. 137 in June, 1999 which delayed implementation until fiscal
years beginning after June 15, 2000, with early adoption permitted. The Company
has not determined the impact of adopting Statement 133.
In December 1998, the Emerging Issues Task Force reached a consensus on Issue
98-10, "Accounting for Contracts involved in Energy Trading and Risk Management
Activities" (EITF 98-10). EITF 98-10 is effective for the Company's fiscal year
beginning January 1, 2000 and requires energy trading contracts to be recorded
at fair value on the balance sheet, with changes in fair value included in
earnings. Although management has not completed its assessment of the impact
of adopting EITF 98-10, the Marketing segment operates as an interstate
aggregator and follows a strategy of concentrating its efforts toward
capitalizing on day-to-day pricing volatility through the use of gas storage
facilities leased from others, hedging, and transportation arbitraging.
Accordingly, the impact of implementing EITF 98-10 on the Marketing segment is
not expected to be material to the financial position or results of operations.
Energy contracts held by other segments are designated as and considered
effective as hedges and non-trading activities and are not considered energy
trading contracts.
18
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
United States ex rel. Jack J. Grynberg v. ONEOK, Inc., ONEOK Resources Company,
and Oklahoma Natural Gas Company, (CTN-8), No. CIV-97-1006-R (Judge Russell), in
the United States District Court for the Western District of Oklahoma. On
September 24, 1999, a hearing on the motion to transfer and consolidate actions
before a single district court was held. An order was issued on October 20,
1999, transferring all the actions to the federal district court in Wyoming for
pretrial proceedings under multidistrict litigation procedures. The Company and
most other defendants filed motions to dismiss the case in early December. This
motion is set for hearing on March 17, 2000.
ONEOK, Inc. v. Southern Union Company, No. 99-CV-0345-H(M), United States
District Court for the Northern District of Oklahoma, on appeal of preliminary
injunction, United States Court of Appeals for the Tenth Circuit, Case Number
99-5103. On October 12, 1999, ONEOK filed a motion to dismiss the counterclaims
of Southern Union. On October 15, 1999, the Court denied ONEOK's motion to amend
its complaint and on October 27, 1999, ONEOK filed a motion for reconsideration
which was denied on November 4, 1999. On November 10, 1999, as a result of
ONEOK's motion to dismiss, Southern Union filed an amended answer and
counterclaims. The case is now in the discovery stage. In the related case of
Klein v. Southwest Gas Corporation, Superior Court of San Diego County,
California, Case No. 726615, on September 24, 1999, the Court dismissed Southern
Union from the case and stated that Southern Union would not be allowed to
refile until all federal court actions were complete.
Southern Union Company v. Southwest Gas Corporation, et al., No. CIV 99 1294 PHX
ROS, United States District Court for the District of Arizona. Rather than
respond to motions filed by the defendants on October 12, 1999, Southern Union
filed an amended complaint with substantially the same claims as in the original
complaint except that it specifically eliminated its previous allegations that
ONEOK had made payments to Tiffany & Bosco for the benefit of Jack Rose, and
James C. Kneale and Larry W. Brummett were added as additional defendants. The
Company and the other defendants filed motions to dismiss the amended complaint
on December 6, 1999. The motions are to be heard by the Court on February 11,
2000.
Joint Application of Oklahoma Natural Gas Company, a Division of ONEOK, Inc.,
ONEOK Gas Transportation Company, a Division of ONEOK, Inc., and Kansas Gas
Service Company, a Division of ONEOK, Inc., for Approval of Their Unbundling
Plan for Natural Gas Services Upstream of the City Gates or Aggregation Points,
Cause PUD No. 980000177, before the Oklahoma Corporation Commission. On October
21, 1999, the Supreme Court granted a new stay for an additional twenty days. As
settlement had not been reached between the parties, the Company filed a motion
to extend the stay until conclusion of the Commission proceedings. On November
2, 1999, the Supreme Court issued an order directing the parties to respond to
the Company's motion by November 17, 1999. Also, on November 5, 1999, the
Commission Staff filed a response to the Company's motion and a motion to
dismiss the appeal as moot and the Attorney General filed a motion to dismiss on
November 12, 1999. The Company filed a response to the motions to dismiss on
November 29, 1999. On December 13, 1999, the Court issued an order denying an
extension of the stay and the motions to dismiss and directed the parties to
file briefs.
Application of Ernest G. Johnson, Director of the Public Utility Division,
Oklahoma Corporation Commission, to Review the Rates, Charges, Services and
Service Terms of Oklahoma Natural Gas Company, a division of ONEOK, Inc., and
All Affiliated Companies and Any Affiliate or Nonaffiliate Transaction Relevant
to Such Inquiry, Cause PUD No. 980000683, Oklahoma Corporation Commission. On
September 20, 1999, Oklahoma Natural filed updated financial information and
requested a $33.6 million rate increase.
19
In the Matter of the Application of Southwest Gas Corporation and ONEOK, Inc.
for an Order Authorizing Implementation of the Agreement and Plan of Merger
dated December 14, 1998, Docket Nos. G-01551A-99-0112 and G-03713A-99-0112,
before the Arizona Corporation Commission. On January 4, 2000, direct testimony
of the Director of the Utility Division of the Commission was filed in the
proceeding. In her testimony, the Director states that the Commission Staff
believes that the unresolved issues that are outstanding, approval of the merger
by the Commission would be premature because the Company has not provided
sufficient evidence for the Commission to make an affirmative showing that the
proposed merger is in circumstances, are as follows:
1. The companies could withdraw their application to be refiled after the
various litigations have been resolved.
2. The Commission could dismiss the proceedings without prejudice, which would
allow the companies to refile the application at a later date.
3. The Commission could keep the docket open and order the companies to
continue to supplement the record as more information becomes available
from the civil litigation and other developments.
The Commission Staff further recommended that if the Commission decides to
approve the merger at this time that certain specified conditions be attached to
such approval. These conditions are substantially the same conditions contained
in a prior stipulation and agreement filed by the Company, the Commission Staff
and Arizona's consumer advocate recommending that the transaction be approved.
The Company has until January 18, 2000 to file rebuttal testimony to challenge
the Commission Staff recommendations.
Item 6. Exhibits and Reports on Form 8-K and 8-K/A.
(b) Reports
December 15, 1999 - Announced that the Transition Report related to the
change in the Company's fiscal year-end for the four months ended December
31, 1999, would be filed on a Form 10-Q.
20
Signatures
Pursuant to the requirements of Section 13 or 15(d) 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, on this 5/th/ day of
January 2000.
ONEOK, Inc.
Registrant
By: Jim Kneale
-----------------------------------
Jim Kneale
Vice President, Chief Financial
Officer, and Treasurer (Principal
Financial Officer)
21