<PAGE>
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 March 31, 2000.
--------------
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 of (I.R.S. Employer Identification No.)
incorporation of organization)
100 West Fifth Street, Tulsa, OK 74103
(Address of principal executive offices) (Zip Code)
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
--- ---
On March 31, 2000, the Company had 29,193,196 shares of common stock
outstanding.
<PAGE>
ONEOK, Inc.
QUARTERLY REPORT ON FORM 10-Q
Part I. Financial Information Page No.
Consolidated Condensed Statements of Income -
Three Months Ended March 31, 2000 and 1999 3
Consolidated Condensed Balance Sheets -
March 31, 2000 and December 31, 1999 4
Consolidated Condensed Statements of Cash Flows -
Three Months Ended March 31, 2000 and 1999 5
Notes to Consolidated Condensed Financial Statements 6 - 10
Management's Discussion and Analysis of
Financial Condition and Results of Operations 11 - 21
Quantitative and Qualitative Disclosures
about Market Risk 22 - 23
Part II. Other Information 24 - 28
2
<PAGE>
Part I - FINANCIAL INFORMATION
ONEOK, Inc. and Subsidiaries
CONSOLIDATED CONDENSED STATEMENTS OF INCOME
<TABLE>
<CAPTION>
Three Months Ended
March 31,
(Unaudited) 2000 1999
- -------------------------------------------------------------------------------------------------------
(Thousands of Dollars,
except per share amounts)
<S> <C> <C>
Operating Revenues $823,949 $547,171
Cost of gas 558,296 331,071
- -------------------------------------------------------------------------------------------------------
Net Revenues 265,653 216,100
- -------------------------------------------------------------------------------------------------------
Operating Expenses
Operations and maintenance 112,030 61,248
Depreciation, depletion, and amortization 34,327 32,092
General taxes 12,239 10,298
- -------------------------------------------------------------------------------------------------------
Total Operating Expenses 158,596 103,638
- -------------------------------------------------------------------------------------------------------
Operating Income 107,057 112,462
- -------------------------------------------------------------------------------------------------------
Other income and expenses, net 14,281 -
Interest expense 21,985 12,582
Income taxes 38,446 39,430
- -------------------------------------------------------------------------------------------------------
Income before cumulative effect of a change in
accounting principle 60,907 60,450
Cumulative effect of a change in accounting principle,
net of tax (Note J) 2,115 -
- -------------------------------------------------------------------------------------------------------
Net Income 63,022 60,450
Preferred Stock Dividends 9,275 9,324
- -------------------------------------------------------------------------------------------------------
Income Available for Common Stock $ 53,747 $ 51,126
=======================================================================================================
Earnings Per Share of Common Stock - Basic (Note F) $ 1.84 $ 1.62
=======================================================================================================
Earnings Per Share of Common Stock - Diluted (Note F) $ 1.28 $ 1.17
=======================================================================================================
Average Shares of Common Stock - Basic (Thousands) 29,242 31,629
Average Shares of Common Stock - Diluted (Thousands) 49,189 51,715
</TABLE>
See accompanying notes to consolidated condensed financial statements.
3
<PAGE>
ONEOK, Inc. and Subsidiaries
CONSOLIDATED CONDENSED BALANCE SHEETS
<TABLE>
<CAPTION>
March 31, December 31,
(Unaudited) 2000 1999
- -------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
Assets
Current Assets
Cash and cash equivalents $ 50,001 $ 72
Trade accounts and notes receivable 394,444 371,313
Inventories 61,345 134,871
Other current assets 106,633 87,465
- -------------------------------------------------------------------------------------------------------
Total Current Assets 612,423 593,721
- -------------------------------------------------------------------------------------------------------
Property, Plant and Equipment 3,465,399 3,143,693
Accumulated depreciation, depletion, and amortization 1,041,582 1,021,915
- -------------------------------------------------------------------------------------------------------
Net Property 2,423,817 2,121,778
- -------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets
Regulatory assets, net (Note D) 256,517 247,486
Goodwill 77,698 80,743
Investments and other 204,093 195,847
- -------------------------------------------------------------------------------------------------------
Total Deferred Charges and Other Assets 538,308 524,076
- -------------------------------------------------------------------------------------------------------
Total Assets $3,574,548 $3,239,575
=======================================================================================================
Liabilities and Shareholders' Equity
Current Liabilities
Current maturities of long-term debt $ 21,767 $ 21,767
Notes payable 255,101 462,242
Accounts payable 286,618 237,653
Accrued taxes 35,217 359
Accrued interest 11,742 16,628
Other 111,233 48,064
- -------------------------------------------------------------------------------------------------------
Total Current Liabilities 721,678 786,713
- -------------------------------------------------------------------------------------------------------
Long-term Debt, excluding current maturities 1,122,184 775,074
Deferred Credits and Other Liabilities
Deferred income taxes 364,332 348,218
Other deferred credits 179,846 178,046
- -------------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 544,178 526,264
- -------------------------------------------------------------------------------------------------------
Total Liabilities 2,388,040 2,088,051
- -------------------------------------------------------------------------------------------------------
Commitments and Contingencies (Note G)
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 and outstanding 29,193,196 and 29,554,623 shares 316 316
Paid in capital (Note I) 894,976 894,976
Unearned compensation (1,664) (1,825)
Retained earnings 361,988 317,964
Treasury stock at cost: 2,406,109 and 2,044,682 shares (69,307) (60,106)
- -------------------------------------------------------------------------------------------------------
Total Shareholders' Equity 1,186,508 1,151,524
- -------------------------------------------------------------------------------------------------------
Total Liabilities and Shareholders' Equity $3,574,548 $3,239,575
=======================================================================================================
</TABLE>
See accompanying notes to consolidated condensed financial statements.
4
<PAGE>
ONEOK, Inc. and Subsidiaries
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
Three Months Ended
March 31,
(Unaudited) 2000 1999
- -----------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
Operating Activities
Net income $ 63,022 $ 60,450
Depreciation, depletion, and amortization 34,327 32,092
Gain on sale of assets (26,852) -
Net income from equity investments (1,236) (712)
Deferred income taxes 5,765 (2,827)
Changes in assets and liabilities 170,877 52,477
- -----------------------------------------------------------------------------------------------------
Cash Provided by Operating Activities 245,903 141,480
- -----------------------------------------------------------------------------------------------------
Investing Activities
Changes in other investments, net (1,102) (61,006)
Acquisitions, net (305,497) -
Capital expenditures, net of retirements (53,644) (63,080)
Proceeds from sale of property 55,169 -
- -----------------------------------------------------------------------------------------------------
Cash Used in Investing Activities (305,074) (124,086)
- -----------------------------------------------------------------------------------------------------
Financing Activities
Payment of notes payable, net (207,141) (190,000)
Issuance of debt 349,429 199,494
Payment of debt (4,928) (9,061)
Issuance of common stock - 1,380
Issuance of treasury stock 1,878 -
Acquisition of treasury stock (11,813) -
Dividends paid (18,325) (19,131)
- -----------------------------------------------------------------------------------------------------
Cash Provided by (Used in) Financing Activities 109,100 (17,318)
- -----------------------------------------------------------------------------------------------------
Change in Cash and Cash Equivalents 49,929 76
Cash and Cash Equivalents at Beginning of Period 72 -
- -----------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 50,001 $ 76
=====================================================================================================
</TABLE>
See accompanying notes to consolidated condensed financial statements.
5
<PAGE>
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Unaudited)
A. Change in Fiscal Year End.
In October 1999, the Company's Board of Directors approved a change in the
Company's fiscal year-end from August 31 to December 31 beginning January 1,
2000. The consolidated condensed financial statements for the first quarter
under the new fiscal year are presented in this Form 10-Q. A transition report
was filed on Form 10-Q for the period September 1, 1999 through December 31,
1999.
B. 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 March 31, 2000
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.
C. Significant Events
In April 2000, the Company completed the acquisition of natural gas gathering
and processing assets located in Oklahoma, Kansas and West Texas from Kinder
Morgan, Inc. (KMI). The Company also acquired KMI's marketing and trading
operations, as well as some storage and transmission pipelines in the mid-
continent region. The Company paid approximately $109 million for these assets
plus an adjustment for working capital of approximately $53 million. The Company
also assumed liabilities including those related to an operating lease for a
processing plant and some firm capacity lease obligations to third parties.
In March 2000, the Company completed the sale of its 42.4 percent interest in
Indian Basin Gas Processing Plant and gathering system for $55 million.
In March 2000 the Company completed the acquisition of assets located in
Oklahoma, Kansas, and the Texas panhandle from Dynegy, Inc. for $308 million in
cash less a purchase price adjustment of approximately $3 million. The assets
include gathering systems, gas processing facilities, and transmission
pipelines.
On January 20, 2000, the Board of Directors of the Company voted unanimously to
terminate the merger agreement with Southwest Gas Corporation (Southwest) in
accordance with the terms of the merger agreement. The Company charged $6.8
million of previously deferred transaction and ongoing litigation costs to Other
Income and Expense during the first quarter of 2000.
The Company has negotiated a joint stipulation in the rate case with the
Oklahoma Corporation Commission (OCC) staff and other parties. The
Administrative Law Judges have recommended OCC approval. If approved by the OCC,
the stipulation provides for a $20 million net revenue reduction in rates which
will be offset by an annual reduction in depreciation expense of $11.4 million.
The joint stipulation transfers the Oklahoma assets and customers of Kansas Gas
Service Company Division (KGS) to Oklahoma Natural Gas Company Division (ONG),
separates the distribution assets of ONG and the transmission and storage assets
of ONEOK Gas Transportation, L.L.C., and related affiliates into two separate
public utilities, adjusts for the removal of the gathering and storage assets no
longer collected in base rates and provides for the recovery of gas purchase
operations and maintenance expenses and line losses through a rider rather than
base rates. Additionally, the joint stipulation allows for the approval of a
contract between the Distribution segment and the affiliated
6
<PAGE>
Transportation and Storage segment for transportation and storage services.
D. Regulatory Assets
The following table is a summary of the Company's regulatory assets, net of
amortization.
<TABLE>
<CAPTION>
March 31, December 31,
2000 1999
----------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
Recoupable take-or-pay $ 83,100 $ 84,343
Pension costs 18,442 19,487
Postretirement costs other than pension 62,885 62,207
Transition costs 22,628 22,746
Reacquired debt costs 23,853 24,068
Income taxes 33,479 23,337
Other 12,130 11,298
--------------------------------------------------------------------
Regulatory assets, net $ 256,517 $ 247,486
====================================================================
</TABLE>
E. Supplemental Cash Flow Information
The following table is supplemental information relative to the Company's cash
flows.
<TABLE>
<CAPTION>
Three Months Ended
March 31,
2000 1999
--------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
Cash paid during the year
Interest (including amounts capitalized) $ 25,275 $ 8,767
Income taxes $ - $ 20,089
Noncash transactions
Treasury stock transferred to compensation plans $ 61 $ -
--------------------------------------------------------------------------------
</TABLE>
F. Earnings per Share Information
The following is a reconciliation of the basic and diluted EPS computations.
<TABLE>
<CAPTION>
Three Months Ended March 31, 2000
Per Share
Income Shares Amount
----------------------------------------------------------------------------------
(Thousands, except per share amounts)
<S> <C> <C> <C>
Basic EPS
Income available to common stockholders $ 53,747 29,242 $ 1.84
=======
Effect of Dilutive Securities
Options - 1
Convertible preferred stock 9,275 19,946
---------- ------
Diluted EPS
Income available to common stockholders
+ assumed conversions $ 63,022 49,189 $ 1.28
==================================================================================
</TABLE>
7
<PAGE>
<TABLE>
<CAPTION>
Three Months Ended March 31, 1999
Per Share
Income Shares Amount
- ----------------------------------------------------------------------------------
(Thousands, except per share amounts)
<S> <C> <C> <C>
Basic EPS
Income available to common stockholders $ 51,126 31,629 $ 1.62
=======
Effect of Dilutive Securities
Options - 13
Convertible preferred stock 9,324 20,073
---------- ------
Diluted EPS
Income available to common stockholders
+ assumed conversions $ 60,450 51,715 $ 1.17
==================================================================================
</TABLE>
There were 262,505 antidilutive option shares excluded from the calculation of
Diluted Earnings per Share for the three months ended March 31, 2000. For the
same period one year ago, there were 80,122 option shares excluded.
The following is a reconciliation of the basic and diluted EPS computations on
income before the cumulative effect of a change in accounting principle to net
income.
<TABLE>
<CAPTION>
Three Months Ended March 31,
Basic EPS Diluted EPS
--------------- ---------------
2000 1999 2000 1999
- ----------------------------------------------------------------------------------------------
(Per share amounts)
<S> <C> <C> <C> <C>
Income available for common stockholders before $ 1.77 $ 1.62 $ 1.24 $ 1.17
cumulative effect of a change in accounting principle
Cumulative effect of a change in accounting principle,
net of tax 0.07 - 0.04 -
------ ------ ------ ------
Income available for common stockholders $ 1.84 $ 1.62 $ 1.28 $ 1.17
==============================================================================================
</TABLE>
G. Commitments and Contingencies
The Company and Southwest entered into a merger agreement, as amended, in which
the Company agreed to acquire Southwest for $30 per share of common stock in an
all cash transaction valued at $918 million. On January 20, 2000, the Company
terminated the merger agreement in accordance with the terms of the merger
agreement.
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). The
complaint asks for $750 million damages to be trebled for racketeering and
unlawful violations, compensatory damages of not less than $750 million and
rescission of the Confidentiality and Standstill Agreement.
Southwest has filed a complaint against the Company and Southern Union in the
United States District Court in Arizona. Southwest seeks actual, consequential,
incidental and punitive damages in an amount in excess of $75,000 and a
declaration that the Company has breached the merger agreement.
On February 3, 2000, two substantially identical derivative actions were filed
in the District Court in Tulsa, Oklahoma by shareholders against the members of
the Board of Directors of the Company for alleged violation of their fiduciary
duties to the Company by causing or allowing the Company to engage in certain
fraudulent and improper schemes relating to the planned merger with Southwest.
Such conduct allegedly caused the Company to be sued by both Southwest and
Southern Union which exposed the Company to millions of dollars in liabilities.
The plaintiffs seek an award of compensatory and punitive damages and costs,
disbursements and reasonable attorney fees.
8
<PAGE>
It is anticipated that Southern Union and Southwest will continue their
litigation against the Company. If any of the plaintiffs should be successful in
any of their claims against the Company and substantial damages are awarded, it
could have a material adverse effect on the Company's operations, cash flow and
financial position. The Company intends to vigorously defend against the claims
asserted by Southern Union and Southwest and all other matters relating to the
now terminated merger with Southwest.
The Company has responsibility for 12 manufactured gas sites located in Kansas
which may contain potentially harmful materials that are classified as hazardous
substances. Hazardous substances are subject to control or remediation under
various environmental laws and regulations. A consent agreement with the Kansas
Department of Health and Environment 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 March 31, 2000, 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 Kansas
Corporation Commission (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 other 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.
H. Segments
The Company conducts its operations through six segments: (1) the Marketing
segment markets natural gas to wholesale and retail customers and markets
electricity to wholesale customers; (2) the Gathering and Processing segment
gathers and processes natural gas and natural gas liquids; (3) the
Transportation and Storage segment transports and stores natural gas for others;
(4) 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; (5) the Production segment
develops and produces natural gas and oil; and (6) the Other segment primarily
operates and leases the Company's headquarters building and a related parking
facility.
9
<PAGE>
Intersegment 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 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.
<TABLE>
<CAPTION>
Three Months Ended Gathering Trans-
March 31, 2000 and portation Eliminations
Marketing Processing and Storage Distribution Production and Other Total
- ------------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C> <C>
Sales to unaffiliated customers $356,124 $ 50,049 $ 15,058 $ 379,710 $ 14,522 $ 8,486 $ 823,949
Intersegment sales 92,716 18,396 14,364 912 5,316 (131,704) -
- ------------------------------------------------------------------------------------------------------------------------------------
Total Revenues $448,840 $ 68,445 $ 29,422 $ 380,622 $ 19,838 $(123,218) $ 823,949
- ------------------------------------------------------------------------------------------------------------------------------------
Net Revenues $ 15,810 $ 68,445 $ 29,422 $ 140,663 $ 19,838 $ (8,525) $ 265,653
Operating Costs $ 2,539 $ 58,932 $ 11,419 $ 54,986 $ 5,646 $ (9,253) $ 124,269
Depreciation, depletion and
amortization $ 191 $ 2,289 $ 4,193 $ 18,571 $ 8,462 $ 621 $ 34,327
Operating Income $ 13,080 $ 7,224 $ 13,810 $ 67,106 $ 5,730 $ 107 $ 107,057
Cumulative Effect of a Change
in Accounting Principle,
before Tax $ 3,449 $ - $ - $ - $ - $ - $ 3,449
Income from Equity
Investments $ - $ - $ 1,229 $ - $ 7 $ - $ 1,236
Total Assets $332,391 $624,524 $407,322 $1,761,383 $354,947 $ 93,981 $3,574,548
Capital Expenditures,
including Acquisitions $ 9,500 $303,331 $ 12,657 $ 26,374 $ 9,364 $ 1,429 $ 362,655
- ------------------------------------------------------------------------------------------------------------------------------------
<CAPTION>
Three Months Ended Gathering Trans-
March 31, 1999 and portation Eliminations
Marketing Processing and Storage Distribution Production and Other Total
- ------------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C> <C>
Sales to unaffiliated customers $157,998 $ 6,172 $ 7,128 $ 362,484 $ 13,224 $ 165 $ 547,171
Intersegment sales 31,188 2,932 19,536 2,927 6,079 (62,662) -
- ------------------------------------------------------------------------------------------------------------------------------------
Total Revenues $189,186 $ 9,104 $ 26,664 $ 365,411 $ 19,303 $ (62,497) $ 547,171
- ------------------------------------------------------------------------------------------------------------------------------------
Net Revenues $ 11,097 $ 9,104 $ 26,664 $ 155,245 $ 19,303 $ (5,313) $ 216,100
Operating Costs $ 2,016 $ 7,320 $ 6,748 $ 55,384 $ 4,991 $ (4,913) $ 71,546
Depreciation, depletion and
amortization $ 151 $ 359 $ 3,415 $ 19,858 $ 8,487 $ (178) $ 32,092
Operating Income $ 8,930 $ 1,425 $ 16,501 $ 80,003 $ 5,825 $ (222) $ 112,462
Income from Equity
Investments $ - $ - $ 684 $ - $ 28 $ - $ 712
Total Assets $131,607 $ 42,558 $431,489 $1,776,019 $363,436 $(119,483) $2,625,626
Capital Expenditures,
including Acquisitions $ 139 $ 788 $ 6,267 $ 21,966 $ 47,482 $ 414 $ 77,056
- ------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
I. Paid in Capital
Paid in Capital at March 31, 2000 and December 31, 1999, was $330.8 million for
common stock and $564.2 million for convertible preferred stock.
J. Energy Trading and Risk Management
Effective January 1, 2000, the Company adopted the provisions of Emerging Issues
Task Force Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading
and Risk Management Activities" (EITF 98-10) for certain energy trading
contracts. EITF 98-10 requires entities involved in energy trading activities to
record energy trading contracts using the mark-to-market method of accounting.
Under this methodology, the energy trading contracts with third parties are
adjusted to market value and the resulting net gains and losses are recognized
in current period gross margins and are included in the Company's Marketing
segment. The cumulative effect to January 1, 2000 of adopting EITF 98-10 was a
gain of $3.4 million, $2.1 million, net of tax, or $0.04 per diluted share of
common stock. In prior years, these contracts were accounted for under the
accrual method of accounting, therefore, gains and losses were recognized as the
contracts settled. Energy contracts held by other Company segments are
designated as and considered effective as hedges of non-trading activities and
are not considered energy trading contracts.
10
<PAGE>
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 on sales and prices;
. increased competition from other energy suppliers as well as alternative
forms of energy;
. the capital intensive nature of our business;
. further deregulation, or "unbundling," of the natural gas business;
. competitive changes in the natural gas gathering, transportation and
storage business resulting from deregulation, or "unbundling," of the
natural gas business;
. the profitability of assets or businesses acquired by us;
. risks of hedging and marketing activities as a result of changes in
energy prices;
. economic climate and growth in the geographic areas in which we do
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 effects of changes in governmental policies and regulatory actions,
including income taxes, environmental compliance, and authorized rates;
. the results of litigation related to our previously proposed acquisition
of Southwest Gas Corporation or to the termination of our merger
agreement with Southwest Gas; and
. the other factors listed in the reports we have filed and may file with
the Securities and Exchange Commission, which are incorporated by
reference.
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. Acquisitions and Sales
Kinder Morgan, Inc.
In April 2000, the Company completed the acquisition of natural gas gathering
and processing assets located in Oklahoma, Kansas and West Texas from Kinder
Morgan, Inc. (KMI). The Company also acquired KMI's marketing and trading
operations, as well as some storage and transmission pipelines in the mid-
continent region. The Company paid approximately $109 million for these assets
plus an adjustment for working capital of approximately $53 million. The Company
also assumed liabilities including those related to an operating lease for a
processing plant for which the Company anticipates establishing a liability for
uneconomic lease obligation terms and some firm capacity lease obligations to
third parties for which the Company anticipates establishing a liability for
out-of-market terms of those obligations. This acquisition includes more than
12,000 miles of pipeline, six gas processing plants with capacity of 1.26
billion cubic feet per day and 10.5 billion cubic feet of storage. Approximately
350 employees were added to the ONEOK workforce as part of the acquisition. Most
are located in Kansas and West Texas.
11
<PAGE>
Indian Basin Gas Processing Plant
On March 31, 2000, the Company completed the sale of its 42.4 percent interest
in the Indian Basin Gas Processing Plant and gathering system for $55 million to
El Paso Field Services Company, a business unit of El Paso Energy Corporation.
The Company acquired most of its interest in the plant, located in Eddy County,
New Mexico, when it acquired the natural gas properties of Western Resources,
Inc. (Western). The gain on this sale is shown in Other Income and Expenses.
Dynegy, Inc.
In March 2000, the Company completed the acquisition of eight gas processing
plants, interests in two other gas processing plants and approximately 7,000
miles of gas gathering and transmission pipeline systems in Oklahoma, Kansas and
Texas from Dynegy, Inc. (Dynegy). The Company paid approximately $308 million
for these assets less a purchase price adjustment of approximately $3 million.
The current throughput of the assets is approximately 240 million cubic feet per
day with an approximate capacity of 375 million cubic feet per day. Production
of natural gas liquids from the assets averages 25,000 barrels per day, a 230
percent increase in the Company's existing production. A Kansas portion of the
transaction is expected to be completed mid-summer 2000 upon KCC approval.
Approximately 75 employees are being added to the ONEOK workforce as part of the
acquisition. The majority of these employees will be in field operations in
Western Oklahoma, the Texas panhandle and Southern Kansas.
Southwest Gas Corporation
On January 18, 2000, the Company received a letter from Michael O. Maffie,
President and Chief Executive Officer of Southwest, taking the position that the
Company had breached the merger agreement entered into between the Company and
Southwest and demanding that the breach be cured.
On January 20, 2000, the Board of Directors of the Company voted unanimously to
terminate the merger agreement in accordance with the terms of the merger
agreement. On January 21, 2000, a letter was sent to Southwest denying that the
Company was in breach of the merger agreement and advising Southwest of the
Company's election to terminate the merger agreement.
On the same date, the Company filed a complaint in Federal District Court in
Tulsa, Oklahoma asking the court to declare that under the terms of the merger
agreement, the Company has properly terminated the merger agreement. On the
same date, the Company advised the Arizona Corporation Commission (ACC) of the
termination of the merger agreement and gave notice the Company withdrew the
Application asking for authorization to implement the merger agreement. On
January 25, 2000, Southwest filed an objection that the Company could not
unilaterally withdraw a joint application. On February 4, 2000, the Hearing
Officer granted the withdrawal and closed the docket.
On January 24, 2000, in reaction to the notice of termination of the merger
agreement, Southwest filed a complaint against the Company and Southern Union in
the United States District Court in Arizona. In the complaint, Southwest
alleges, among other things, that the Company failed to disclose to Southwest
that the Company had purportedly participated in improper lobbying efforts
allegedly involving a state regulatory official for the purpose of influencing
state utility regulators to oppose Southern Union's attempt to acquire Southwest
and inducing Southwest to enter into the merger agreement with the Company
instead of accepting Southern Union's acquisition proposal. The complaint also
alleges that the Company failed to use commercially reasonable efforts to obtain
all necessary governmental authorization for the planned merger with Southwest
by failing to remedy alleged improper conduct and by failing to make truthful
disclosure of such purportedly improper lobbying and relationships to the ACC.
The complaint further alleges that, because of the Company's
12
<PAGE>
alleged breach of the merger agreement, the Company was contractually unable to
terminate the merger agreement and that the Company's notice of termination of
the agreement was therefore wrongful. The complaint uses these allegations as a
basis for causes of action for fraud in the inducement, fraud, breach of
contract, breach of implied covenant of good faith and fair dealing, and
declaratory relief. Southwest seeks actual, consequential, incidental and
punitive damages in an amount in excess of $75,000 and a declaration that the
Company has breached the merger agreement.
On February 3, 2000, two substantially identical derivative actions were filed
in the District Court in Tulsa, Oklahoma by shareholders against the members of
the Board of Directors of the Company for alleged violation of their fiduciary
duties to the Company by causing or allowing the Company to engage in certain
fraudulent and improper schemes relating to the planned merger with Southwest.
Such conduct allegedly caused the Company to be sued by both Southwest and
Southern Union which exposed the Company to millions of dollars in liabilities.
The plaintiffs seek an award of compensatory and punitive damages and costs,
disbursements and reasonable attorney fees.
It is anticipated that Southern Union and Southwest will continue their
litigation against the Company (see discussions under "Legal Proceedings"). If
any of the plaintiffs should be successful in any of their claims against the
Company and substantial damages are awarded, it could have a material adverse
effect on the Company's operations, cash flow and financial position. The
Company intends to vigorously defend against the claims asserted by Southern
Union and Southwest and all other matters relating to the now terminated merger
with Southwest. The Company charged $6.8 million of previously deferred
transaction and ongoing litigation costs to Other Income and Expense during the
first quarter of 2000.
B. Results of Operations
Consolidated Operations
The Company is a diversified energy company whose objective has been to maximize
value for shareholders by vertically integrating its business operations from
the wellhead to the burner tip. This strategy has focused on acquiring assets
that provide synergistic trading and marketing opportunities all along the
natural gas energy chain. Products and services are provided to its customers
through the following segments:
. Marketing
. Gathering and Processing
. Transportation and Storage
. Distribution
. Production
. Other
13
<PAGE>
<TABLE>
<CAPTION>
Three Months Ended
March 31,
-----------------------------------------------------------------------------------
2000 1999
-----------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
Financial Results
Operating revenues $ 823,949 $ 547,171
Cost of gas 558,296 331,071
-----------------------------------------------------------------------------------
Net revenue 265,653 216,100
Operating costs 124,269 71,546
Depreciation, depletion, and amortization 34,327 32,092
-----------------------------------------------------------------------------------
Operating income $ 107,057 $ 112,462
===================================================================================
Other income and expenses, net $ 14,281 $ -
===================================================================================
Cumulative effect of a change in accounting principle $ 3,449 $ -
Income tax 1,334 -
-----------------------------------------------------------------------------------
Cumulative effect of a change in accounting principle,
net of tax $ 2,115 $ -
===================================================================================
</TABLE>
Operating results continue to be strong. The growth of the Marketing and
Gathering and Processing segments partially offset the effect of the warmer than
normal weather on the Distribution segment. Use of derivative instruments for
the 1999/2000 heating season reduced the volatility created by weather
variances. These derivative instruments resulted in revenue which offset nearly
half of the $12.6 million margin variances caused by weather. This revenue was
recorded in the Other segment.
The cumulative effect of the Company adopting EITF 98-10 was a gain of $2.1
million, net of tax, at January 1, 2000. For the three months ended March 31,
2000, the Company had a mark-to-market loss of $2.7 million which reduced net
revenues. See Marketing, page 15.
The $26.7 million gain on the sale of the Company's interest in the Indian Basin
Gas Processing Plant is included in Other Income and Expenses for the three
month period ended March 31, 2000. Other nonoperating costs include a
contribution to the ONEOK Foundation of $5.0 million and the $6.8 million write
off of previously deferred transaction and ongoing litigation costs associated
with the terminated acquisition of Southwest.
Although some higher interest rate debt was refinanced at a lower interest rate
during 1999, increased borrowing, primarily due to acquisitions, resulted in
increased interest expense.
A stock buyback plan also contributed to the increase in earnings per share.
14
<PAGE>
Marketing
<TABLE>
<CAPTION>
Three Months Ended
March 31,
2000 1999
----------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
Financial Results
Gas sales $ 448,639 $ 189,095
Cost of gas 433,030 178,089
----------------------------------------------------------------------------------------------
Gross margin on gas sales 15,609 11,006
Other revenues 201 91
----------------------------------------------------------------------------------------------
Net revenues 15,810 11,097
Operating costs 2,539 2,016
Depreciation, depletion, and amortization 191 151
----------------------------------------------------------------------------------------------
Operating income $ 13,080 $ 8,930
==============================================================================================
Cumulative effect of a change in accounting principle, before tax $ 3,449 $ -
==============================================================================================
<CAPTION>
Three Months Ended
March 31,
2000 1999
----------------------------------------------------------------------------------------------
<S> <C> <C>
Operating Information
Natural gas volumes (MMcf) 170,614 98,073
Capital expenditures, including acquisitions (Thousands) $ 9,500 $ 139
Total assets (Thousands) $ 332,391 $ 131,607
----------------------------------------------------------------------------------------------
</TABLE>
With the completion of the acquisition of KMI's marketing and trading operation
in April 2000, the Company's marketing operation purchases, stores and markets
natural gas at both the retail and wholesale level in 25 states. The Company
continues to develop new market areas by arbitraging storage in the day trading
market rather than focusing on the baseload market. Expanding its midcontinent
presence, the Marketing segment increased it sales volumes by 74% in the three
months ended March 31, 2000 compared to the same period one year ago and
increased storage capacity in both the Permian/Waha region of the United States
and along the Gulf Coast and Texas intrastates. The Company now leases from
others, including affiliates, more than 50 Bcf of storage capacity which gives
direct access to the west coast and Texas intrastate markets. Gross Margins on
Gas Sales continued to be enhanced with the increase in storage capacity and
optionality.
Trading of electricity at market-based wholesale rates has begun but has had
minimal impact on operations to date. The increase in capital expenditures for
the three month period is related to the 300-megawatt gas-fired electric
generating plant to be constructed in Logan County, Oklahoma. The plant is
expected to be in service in June, 2001. The Company has signed a definitive
agreement with a third party for a 15-year contract providing for the purchase
of about 25 percent of the plant's generating capacity.
Effective January 1, 2000, the Company adopted EITF 98-10. EITF 98-10 requires
entities involved in energy trading activities to record energy trading
contracts using the mark-to-market method of accounting. Under this methodology,
the energy trading contracts with third parties are adjusted to market value and
the resulting net gains and losses are recognized in current period gross
margins. For the three months ended March 31, 2000, the Company recorded a
mark-to-market loss of $2.7 million. The cumulative effect at January 1, 2000 of
adopting EITF 98-10 was a gain of $3.4 million, $2.1 million net of tax, or
$0.04 per diluted share of common stock. In prior years, these contracts were
accounted for under the accrual method of accounting, therefore, gains and
losses were recognized as the contracts settled. The net effect on net income
for the cumulative effect and the current period loss is a net $0.7 million
gain.
15
<PAGE>
Gathering and Processing
<TABLE>
<CAPTION>
Three Months Ended
March 31,
----------------------------------------------------------------------------------------------
2000 1999
----------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
Financial Results
Natural gas liquids and condensate sales $ 35,925 $ 6,307
Gas sales 25,938 2,932
Gathering, compression and dehydration revenues 5,116 -
Other revenues 1,466 (135)
---------------------------------------------------------------------------------------------
Total revenues 68,445 9,104
Cost of sales 52,405 5,789
---------------------------------------------------------------------------------------------
Gross margin 16,040 3,315
Operating costs 6,527 1,531
Depreciation, depletion, and amortization 2,289 359
---------------------------------------------------------------------------------------------
Operating income $ 7,224 $ 1,425
=============================================================================================
Other income and expenses, net $ 26,585 $ -
=============================================================================================
</TABLE>
Revenues increased for the three month period ended March 31, 2000 compared to
the same period one year ago as a result of the acquisition of gathering and
processing assets in April, 1999. Operating costs and depreciation also
increased due to the additional assets and the cost of operating those assets.
Average NGL price per gallon increased as prices continued to experience an
upward correction from the abnormally low prices prevalent throughout much of
1998 and early 1999. The Company uses derivative instruments to reduce the
volatility in prices.
In March 2000, the Company completed the sale of its 42.4 percent interest in
the Indian Basin Gas Processing Plant and gathering system for $55 million to El
Paso Field Services Company, a business unit of El Paso Energy Corporation. The
Company acquired most of its interest in the plant, located in Eddy County, New
Mexico, when it acquired the natural gas properties of Western. The gain on this
sale is shown in Other Income and Expenses.
<TABLE>
<CAPTION>
Three Months Ended
March 31,
2000 1999
----------------------------------------------------------------------------------------------
<S> <C> <C>
Operating Information
Average NGL's price ($/Gal) $ 0.352 $ 0.212
Average gas price ($/Mcf) $ 2.27 $ 1.85
Capital expenditures, including acquisitions (Thousands) $ 303,331 $ 788
Total assets (Thousands) $ 624,524 $ 42,558
Total gas gathered (Mcf/D) 513,233 131,351
Total gas processed (Mcf/D) 409,809 119,410
Natural gas liquids sales (MGal) 101,948 29,739
Gas sales (MMMbtu) 11,448 1,586
Natural Gas Liquids by Component (%)
Ethane 50 49
Propane 26 25
Iso butane 4 3
Normal butane 9 10
Natural gasoline 11 13
----------------------------------------------------------------------------------------------
</TABLE>
In March 2000, the Company completed the acquisition of eight gas processing
plants and interests in two other gas processing plants from Dynegy, Inc.
(Dynegy). The current throughput of the assets is approximately 240 million
cubic feet per day with an approximate capacity of 375 million cubic feet per
day. Production of natural gas liquids from the assets averages 25,000 barrels
per day, a 230 percent increase in the Company's existing production.
16
<PAGE>
In April 2000, the Company completed the acquisition of natural gas gathering
and processing assets located in Oklahoma, Kansas and West Texas from Kinder
Morgan, Inc. (KMI). This acquisition includes gathering systems and six gas
processing plants with capacity of 1.26 billion cubic feet per day.
Transportation and Storage
The transportation and storage segment represents our intrastate transmission
pipelines and natural gas storage facilities. The Company has five storage
facilities in Oklahoma and two in Kansas with a combined working capacity of 48
bcf.
<TABLE>
<CAPTION>
Three Months Ended
March 31,
2000 1999
----------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
Financial Results
Transportation revenues $ 14,890 $ 18,097
Storage revenues 7,786 6,387
Other revenues 6,746 2,180
----------------------------------------------------------------------------------------------
Net revenues 29,422 26,664
Operating costs 11,419 6,748
Depreciation, depletion, and amortization 4,193 3,415
----------------------------------------------------------------------------------------------
Operating income $ 13,810 $ 16,501
==============================================================================================
<CAPTION>
Three Months Ended
March 31,
2000 1999
----------------------------------------------------------------------------------------------
<S> <C> <C>
Operating Information
Volumes transported (MMcf) 113,422 104,928
Capital expenditures, including acquisitions
(Thousands) $ 12,657 $ 6,267
Total assets (Thousands) $ 407,322 $ 431,489
----------------------------------------------------------------------------------------------
</TABLE>
A decrease in transportation rates for an affiliate decreased transportation
revenues despite the increase in volumes transported for the three months ended
March 31, 2000 compared to the same period one year ago. As part of the
unbundling and deregulation process, the Company's gathering and storage assets
and services in Oklahoma were removed from utility regulation effective November
1, 1999. These gathering and storage assets of $325.0 million which include
current gas in storage were removed from rate base. The Company is now in a
position to compete for business at market-based rates and is aggressively
seeking new business. Its strategy to increase its storage utilization through
greater injection and withdrawal capabilities has resulted in increased storage
revenues and increased other revenues, primarily retained fuel, as well as
increased compressor fuel expense for the three months ended March 31, 2000,
compared to the same period one year ago.
Acquisitions of transmission pipelines and storage fields from Dynegy and KMI
were completed in March and April 2000, respectively. The acquisitions increase
transportation capacity by 300 percent, miles of transmission pipelines by 95
percent, and Company-owned storage capacity by 23 percent.
The Company has negotiated a joint stipulation in the rate case with the OCC
staff and other parties. The Administrative Law Judges have recommended OCC
approval. If approved by the OCC, the stipulation separates the distribution
assets of ONG and the transmission and storage assets of ONEOK Gas
Transportation, L.L.C., and related affiliates into two separate public
utilities, adjusts for the removal of the gathering and storage assets no longer
collected in base rates and allows for the approval of a contract between the
Transportation and Storage segment and the affiliated Distribution segment for
transportation and storage services.
17
<PAGE>
Distribution
The Distribution segment provides natural gas distribution services in Oklahoma
and Kansas. The Company's operations in Oklahoma are primarily conducted through
ONG which serves residential, commercial, and industrial customers and leases
pipeline capacity. The Company's operations in Kansas are conducted through 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.
<TABLE>
<CAPTION>
Three Months Ended
March 31,
----------------------------------------------------------------------------------------------
2000 1999
----------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
Financial Results
Gas sales $ 357,690 $ 342,926
Cost of gas 239,959 210,166
---------------------------------------------------------------------------------------------
Gross margin on gas sales 117,731 132,760
PCL and ECT revenues 18,851 18,085
Other revenues 4,081 4,400
---------------------------------------------------------------------------------------------
Net revenues 140,663 155,245
Operating costs 54,986 55,384
Depreciation, depletion, and amortization 18,571 19,858
---------------------------------------------------------------------------------------------
Operating income $ 67,106 $ 80,003
=============================================================================================
</TABLE>
Revenues and gross margin for the three months ended March 31, 2000 decreased as
a result of warmer than normal weather primarily in Kansas, the interim rate
reduction in Oklahoma and the impact of unbundling which removed the Oklahoma
gathering and storage assets from rate base discussed below.
The Oklahoma gathering and storage assets operated in connection with ONG were
removed 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. A one-time interim rate reduction began
September 1, 1999 for residential customers in Oklahoma. The net effect of these
actions and the reduction of transportation costs due to unbundling was a
reduction in margin of $7.2 million for the quarter ended March 31, 2000.
The Distribution segment continues its strategy of increased operational
efficiency while maintaining quality customer service, resulting in reductions
in labor expenses and other operating efficiencies.
The Company has negotiated a joint stipulation in the rate case with the OCC
staff and other parties. The Administrative Law Judges have recommended OCC
approval. If approved by the OCC, the stipulation provides for a $20 million net
revenue reduction in rates which will be offset by an annual reduction in
depreciation expense of $11.4 million. The joint stipulation transfers KGS's
Oklahoma assets and customers to ONG, separates the distribution assets of ONG
and the transmission and storage assets of ONEOK Gas Transportation, L.L.C., and
related affiliates into two separate public utilities, adjusts for the removal
of the gathering and storage assets no longer collected in base rates and
provides for the recovery of gas purchase operations and maintenance expenses
and line losses through a rider rather than base rates. Additionally, the joint
stipulation allows for the approval of a contract between the Distribution
segment and the affiliated Transportation and Storage segment for transportation
and storage services.
18
<PAGE>
<TABLE>
<CAPTION>
Three Months Ended
March 31,
2000 1999
------------------------------------------------------------------------------------------
<S> <C> <C>
Gross Margin per Mcf
Oklahoma
Residential $2.02 $2.11
Commercial $2.13 $2.13
Industrial $1.30 $1.29
Pipeline capacity leases $0.27 $0.26
Kansas
Residential $1.93 $1.94
Commercial $1.64 $1.62
Industrial $1.75 $1.88
End-use customer transportation $0.67 $0.58
------------------------------------------------------------------------------------------
<CAPTION>
Three Months Ended
March 31,
2000 1999
------------------------------------------------------------------------------------------
<S> <C> <C>
Operating Information
Number of customers 1,442,457 1,428,222
Capital expenditures, including
acquisitions (Thousands) $ 26,374 $ 21,966
Total assets (Thousands) $ 1,761,383 $ 1,776,019
Customers per employee 553 533
------------------------------------------------------------------------------------------
<CAPTION>
Three Months Ended
March 31,
2000 1999
------------------------------------------------------------------------------------------
<S> <C> <C>
Volumes (MMcf)
Gas sales
Residential 51,389 54,305
Commercial 18,808 20,911
Industrial 2,082 2,141
------------------------------------------------------------------------------------------
Total volumes sold 72,279 77,357
PCL and ECT 51,903 55,111
------------------------------------------------------------------------------------------
Total volumes delivered 124,182 132,468
==========================================================================================
</TABLE>
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 of a regulatory asset, and accordingly, a
write-off of regulatory assets and stranded costs may be required. The Company
does not anticipate these costs to be significant.
19
<PAGE>
Production
<TABLE>
<CAPTION>
Three Months Ended
March 31,
2000 1999
------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
Financial Results
Natural gas sales $ 16,176 $ 16,408
Oil sales 2,412 1,289
Other revenues 1,250 1,606
------------------------------------------------------------------------------------------
Net revenues 19,838 19,303
Operating costs 5,646 4,991
Depreciation, depletion, and amortization 8,462 8,487
------------------------------------------------------------------------------------------
Operating income $ 5,730 $ 5,825
==========================================================================================
Other income and expenses, net $ 167 $ -
==========================================================================================
</TABLE>
The increase in oil and gas prices was partially offset by the decrease in gas
volumes. Volumes are down due to normal production declines. This normal decline
would normally be offset by exploitation of drilling prospects. However,
drilling projects were delayed due to low product prices in early 1999.
<TABLE>
<CAPTION>
Three Months Ended
March 31,
2000 1999
------------------------------------------------------------------------------------------
<S> <C> <C>
Operating Information
Proved reserves
Gas (MMcf) 249,871 226,048
Oil (MBbls) 4,075 3,687
Production
Gas (MMcf) 6,975 7,645
Oil (MBbls) 128 123
Average price
Gas (Mcf) $ 2.32 $ 2.15
Oil (Bbls) $ 18.82 $ 10.49
Capital expenditures, including acquisitions
(Thousands) $ 9,364 $ 47,482
Total assets (Thousands) $ 354,947 $ 363,436
------------------------------------------------------------------------------------------
</TABLE>
B. Financial Flexibility and Liquidity
The Company's capitalization structure is 46 percent equity and 54 percent debt
(including short-term debt) at March 31, 2000, compared to 48 percent equity and
52 percent debt at December 31, 1999. Cash provided by operating activities
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 for the quarter as compared to the same period one year ago
are higher primarily because of the fluctuations in working capital associated
with the Marketing segment and the increase in gas costs recovered from
customers. 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.
20
<PAGE>
Capital expenditures, including acquisitions, totaled $362.7 million for the
quarter ended March 31, 2000. This included $9.5 million for construction of an
electric generating plant and $305.5 million for assets purchased from Dynegy.
For the same period one year ago, capital expenditures, including acquisitions,
totaled $77.1 million including $44.0 million for the purchase of production
assets.
At March 31, 2000, $1.1 billion of long-term debt was outstanding. As of that
date, the Company could have issued $660.7 million of additional long-term debt
under the most restrictive provisions contained in its various borrowing
agreements.
In March 2000, the Company issued $350 million of long-term debt to refinance
short term debt.
In March 2000, the Company entered into a $200 million Revolving Credit Facility
with Bank of America, N.A. and other financial institutions with a maturity date
of June 30, 2000. This credit facility is in addition to the previously existing
$600 million Revolving Credit Facility dated July 2, 1999 with a maturity date
of June 30, 2000. At March 31, 2000, $255 million was outstanding under these
two facilities.
In April 2000, the Company issued $240 million of two-year floating-rate notes.
The interest rate for the notes will reset quarterly at a 0.65 percent spread
over the three month LIBOR.
On April 20, 2000, the Board of Directors of the Company renewed the authorized
stock buyback plan for up to 15 percent of its capital stock for an additional
year. 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 in May 1999. Through March 31, 2000, 2,562,958
shares had been purchased. The purchased shares are held in treasury and are
available for general corporate purposes, funding of stock-based compensation
plans, resale, or retirement. Through March 31, 2000, shares reissued for
compensation and benefit plans totaled 156,849. 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.
C. New Accounting Pronouncements
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 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.
21
<PAGE>
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 through
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.
To minimize the impact of weather on operations, the Company is using weather
derivative swaps to manage the risk of fluctuations in heating degree days (HDD)
during the 1999/2000 heating season.
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 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.
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. There are
no HDD swaps outstanding at March 31, 2000.
KGS 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.
Most of the Company's 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. The Company has entered into an interest rate swap on
$300 million in long-term debt. The rate resets semiannually based on the six-
month LIBOR at the reset date. In April 2000, the Company issued $240 million of
two-year floating-rate notes. The interest rate for the notes will be reset
quarterly at a 0.65 percent spread over the three month LIBOR.
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 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 March 31, 2000, 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.
22
<PAGE>
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.
23
<PAGE>
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 was heard on March 14, 2000 and the Court has not yet issued its ruling.
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. The case is now in the discovery stage. Oral argument on the appeal of
the preliminary injunction occurred on March 8, 2000; the Court of Appeals
remanded the matter to District Court for certain determinations related to
ONEOK's argument that the appeal is moot.
Southern Union Company v. Southwest Gas Corporation, et al., No. CIV 99 1294 PHX
ROS, United States District Court for the District of Arizona. 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 June 30, 2000.
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. The Company has withdrawn its
Application and the docket has been closed.
ONEOK, Inc. v. Southwest Gas Corporation, No. 00CV 063H (E). United States
District Court for the Northern District of Oklahoma. On January 21, 2000, the
Company filed a complaint in Federal District Court in Tulsa, Oklahoma asking
the Court to declare that under the terms of the Agreement and Plan of Merger,
the Company has properly terminated the Agreement. This case is in the
preliminary stages of motion practice concerning venue of this case and the
related case pending in the U. S. District Court for the District of Arizona.
Southwest Gas Corporation v. ONEOK, Inc., CIV 119 PHX VAM, United States
District Court for the District of Arizona. This case is in the preliminary
stages of motion practice concerning venue of this case and the related case
pending in the U.S. District Court for the Northern District of Oklahoma.
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 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. The Company filed its reply brief on January 27, 2000.
The case has been assigned to the Tulsa Division of the Oklahoma Court of Civil
Appeals. No decision has been reached by the Court of Civil Appeals.
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. The
24
<PAGE>
parties executed a Joint Stipulation, that provides for a $20 million net
revenue reduction in rates which will be offset by an annual reduction in
depreciation expense of $11.4 million. The joint stipulation transfers the
Oklahoma assets and customers of Kansas Gas Service Company Division (KGS) to
Oklahoma Natural Gas Company Division (ONG), separates the distribution assets
of ONG and the transmission and storage assets of ONEOK Gas Transportation,
L.L.C., and related affiliates into two separate public utilities, adjusts for
the removal of the gathering and storage assets no longer collected in base
rates and provides for the recovery of gas purchase operations and maintenance
expenses and line losses through a rider rather than base rates. Additionally,
the joint stipulation allows for the approval of a contract between the
Distribution segment and the affiliated Transportation and Storage segment for
transportation and storage services. The Administrative Law Judges issued a
Report on April 24, 2000 recommending approval of the Stipulation. A commission
order remains pending.
Gaetan Lavalla, Derivatively on Behalf of Nominal Defendant ONEOK, Inc. v. Larry
W. Brummett, et al., District Court of Tulsa County, No. CJ-2000-598 and Hayward
Lane, Derivatively on Behalf of Nominal Defendant ONEOK, Inc. v. Larry W.
Brummett, et al., District Court of Tulsa County, No. CJ-2000-593. Neither the
Company nor the other defendants has yet been served with process in these
cases.
Chesapeake Panhandle Limited Partnership, an Oklahoma Limited Partnership, and
Chesapeake Energy Marketing, Inc., an Oklahoma corporation v. Kinder Morgan,
Inc., a Kansas corporation, formerly known as KN Energy, Inc.; MidCon Gas
Products Corp., a Delaware corporation; MidCon Gas Services Corp., a Delaware
corporation; Natural Gas Pipeline Company of America, a Delaware corporation,
U.S.D.C., Western District of Oklahoma, Case No. CIV-00-397L; This case was
filed on February 25, 2000, amended on April 5, 2000, by Chesapeake Group
premised on a certain Gas Sales and Purchase Agreement providing for the
purchase, sale and gathering of gas from certain oil and gas wells. Chesapeake
alleges that because Defendants failed and refused to renegotiate in good faith
certain contract provisions provided under the Subject Agreement, a breach has
occurred and the Agreement is thus unenforceable. Chesapeake brings claims for
relief for breach of contract asserting (1) anticipatory repudiation and (2)
breach of implied covenant of good faith and fair dealing, and further seeks
declaratory judgment. Chesapeake seeks the jurisdictional amount of in excess of
$75,000. One of the Defendants is a corporation recently purchased by the
Company from Kinder Morgan, Inc. The case is still in the initial pleading
stages.
For additional information regarding the above matters, see the Company's Form
10-K for the period ending August 31, 1999 and the Company's Form 10-Q for the
Transition Period ending December 31, 1999.
25
<PAGE>
Item 4. Submission of Matters to Vote of Security Holders
(A) Date of Annual Meeting
April 20, 2000
(B) Directors Elected Directors Continuing
Edwyna G. Anderson William M. Bell
William L. Ford Larry W. Brummett
Bert H. Mackie Douglas R. Cummings
Gary D. Parker Howard R. Fricke
David L. Kyle
Douglas T. Lake
Douglas Ann Newsom
J. D. Scott
(C) Matters Voted Upon Votes
--------------------------------
For Against Abstain
Approval of 1,400,000
Common Shares of Stock
for the ONEOK, Inc.
Employee Stock Purchase Plan 24,089,638 1,503,759 316,384
Appointment of KPMG LLP as principal
independent auditor 25,466,538 163,862 279,379
Election of Directors For Withheld
Edwyna G. Anderson 25,481,827 427,952
William L. Ford 25,531,022 378,757
Bert H. Mackie 25,524,420 385,359
Gary D. Parker 25,443,418 466,361
26
<PAGE>
Item 6. Exhibits and Reports on Form 8-K
(A) Exhibits Incorporated by Reference
Certificate of Incorporation of the Company, filed May 16, 1997
(Incorporated by reference from Exhibit 3.1 to Amendment No. 3 to the
Company's Registration Statement on Form S-4 filed August 6, 1997).
Certificate of Merger of the Company filed November 26, 1997
(Incorporated by reference from Exhibit (1)(b) to the Company's
Quarterly Report on Form 10-Q for the quarter ended May 31, 1998).
Amendment to Certificate of Incorporation of ONEOK, Inc., filed
January 16, 1998 (Incorporated by reference from Exhibit (1)(b) to the
Company's Quarterly Report on Form 10-Q for the quarter ended May 31,
1998).
By-laws of ONEOK, Inc., as amended (Incorporated by reference from
Exhibit (3)(d) to the Compnay's Annual Report on Form 10-K for the
year ended August 31, 1999.
Sixth Supplemental Indenture dated March 1, 2000, between the Company
and Chase Bank of Texas, National Association, incorporated by
reference from Registration Statement on Form S-4 filed March 13,
2000.
Registration Rights Agreement dated March 1, 2000 among the Company
and the Initial Purchasers described therein, incorporated by
reference from Registration Statement on Form S-4 filed March 13,
2000.
Seventh Supplemental Indenture dated April 24, 2000, between the
Company and Chase Bank of Texas, National Association, incorporated by
reference from Form 8-K dated April 24, 2000
(B) Reports on Form 8-K
January 7, 2000 - Announced plans to move forward with the Company's
proposed merger with Southwest Gas Corporation.
January 24, 2000 - Announced that the Company had terminated its
proposed merger with Southwest Gas Corporation.
January 27, 2000 - Announced that Southwest Gas Corporation filed a
complaint against the Company and Southern Union Company in the United
States District Court in Arizona.
February 1, 2000 - Announced that the Company had purchased the mid-
continent midstream assets of Dynegy, Inc.
February 9, 2000 - Announced that the Company had purchased the
natural gas gathering and processing businesses, marketing and trading
business, and storage and transmission pipelines from Kinder Morgan,
Inc.
February 22, 2000 - Reported a conference call with financial analysts
to discuss two recently announced acquisitions.
March 21, 2000 - Announced that the Company had entered into an
agreement to sell its interest in the Indian Basin Gas Processing
Plant and gathering system.
March 28, 2000 - Announced the closing of the acquisition of midstream
assets from Dynegy, Inc.
April 4, 2000 - ONEOK, Inc. signed a short-term credit agreement with
Bank of America.
27
<PAGE>
April 4, 2000 - Announced the closing of the sale of the Company's
interest in the Indian Basin Gas Processing Plant and gathering system
to El Paso Field Services Company.
April 6 - 2000 - Announced the closing of the previously announced
acquisition of natural gas gathering and processing businesses of
Kinder Morgan, Inc.
April 24, 2000 - Announced the consummation of an underwritten public
offering of $240,000,000 aggregate principal amount of the Company's
floating rate notes due April 24, 2002.
28
<PAGE>
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 11th day of May
2000.
ONEOK, Inc.
Registrant
By: /s/ Jim Kneale
----------------------------------------
Jim Kneale
Vice President, Chief Financial Officer,
and Treasurer (Principal Financial Officer)
29
<PAGE>
EXHIBIT (12)
ONEOK, Inc.
Computation of Ratio of Earnings to Combined Fixed Charges
and Preferred Stock Dividend Requirements
<TABLE>
<CAPTION>
For the Three Months
Ended March 31,
2000 1999
- --------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
Fixed Charges, as defined
Interest on long-term debt $ 16,220 $ 8,575
Other interest 5,151 3,559
Amortization of debt discount and expense 614 448
Interest on lease agreements 620 651
- --------------------------------------------------------------------------------
Total Fixed Charges 22,605 13,233
Preferred dividend requirements 14,960 15,039
- --------------------------------------------------------------------------------
Total fixed charges and
preferred dividend requirements $ 37,565 $ 28,272
================================================================================
Earnings before income taxes and income from
equity investees $ 98,117 $ 99,168
Total fixed charges 22,605 13,233
- --------------------------------------------------------------------------------
Earnings available for combined fixed
charges and preferred dividend requirements $ 120,722 $ 112,401
================================================================================
Ratio of earnings to combined fixed charges and
preferred dividend requirements 3.21x 3.98x
================================================================================
</TABLE>
For purposes of computing the ratio of earnings to combined fixed charges and
preferred dividend requirements, "earnings" consists of income before cumulative
effect of a change in accounting principle plus fixed charges and income taxes,
less undistributed income from equity investees. "Fixed charges" consists of
interest charges, the amortization of debt discounts and issue costs and the
representative interest portion of operating leases. "Preferred dividend
requirements" consists of the pre-tax preferred dividend requirement.
1
<PAGE>
EXHIBIT (12)(a)
ONEOK, Inc.
Computation of Ratio of Earnings to Fixed Charges
<TABLE>
<CAPTION>
For the Three Months
Ended March 31,
2000 1999
- --------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
Fixed Charges, as defined
Interest on long-term debt $ 16,220 $ 8,575
Other interest 5,151 3,559
Amortization of debt discount and expense 614 448
Interest on lease agreements 620 651
- --------------------------------------------------------------------------------
Total Fixed Charges 22,605 13,233
- --------------------------------------------------------------------------------
Earnings before income taxes and income from
equity investees 98,117 99,168
- --------------------------------------------------------------------------------
Earnings available for fixed charges $ 120,722 $ 112,401
================================================================================
Ratio of earnings to combined fixed charges 5.34x 8.49x
================================================================================
</TABLE>
For purposes of computing the ratio of earnings to fixed charges, "earnings"
consists of income before cumulative effect of a change in accounting principle
plus fixed charges and income taxes, less undistributed income from equity
investees. "Fixed charges" consists of interest charges, the amortization of
debt discounts and issue costs and the representative interest portion of
operating leases.
1
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED CONDENSED FINANCIAL STATEMENTS OF ONEOK, INC. FOR THE QUARTER ENDED
MARCH 31, 2000, AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL
STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-2000
<PERIOD-START> JAN-01-2000
<PERIOD-END> MAR-31-2000
<CASH> 50,001
<SECURITIES> 0
<RECEIVABLES> 394,444
<ALLOWANCES> 0
<INVENTORY> 61,345
<CURRENT-ASSETS> 612,423
<PP&E> 3,465,399
<DEPRECIATION> 1,041,582
<TOTAL-ASSETS> 3,574,548
<CURRENT-LIABILITIES> 721,678
<BONDS> 1,122,184
0
199
<COMMON> 316
<OTHER-SE> 1,185,993
<TOTAL-LIABILITY-AND-EQUITY> 3,574,548
<SALES> 823,949
<TOTAL-REVENUES> 823,949
<CGS> 558,296
<TOTAL-COSTS> 558,296
<OTHER-EXPENSES> 158,596
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 21,985
<INCOME-PRETAX> 99,353
<INCOME-TAX> 38,446
<INCOME-CONTINUING> 60,907
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 2,115
<NET-INCOME> 63,022
<EPS-BASIC> 1.84
<EPS-DILUTED> 1.28
</TABLE>
