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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 June 30, 2002 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 ___
---
Common stock, with par value of $0.01-60,408,566 shares outstanding at August 9,
2002.
ONEOK, Inc.
QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTER ENDED JUNE 30, 2002
Part I. Financial Information Page No.
Item 1. Financial Statements (Unaudited)
Consolidated Statements of Income -
Three and Six Months Ended June 30, 2002 and 2001 3
Consolidated Balance Sheets -
June 30, 2002 and December 31, 2001 4-5
Consolidated Statements of Cash Flows -
Six Months Ended June 30, 2002 and 2001 6
Notes to Consolidated Financial Statements 7
Item 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations 23
Item 3. Quantitative and Qualitative Disclosures about Market Risk 41
Part II. Other Information
Item 1. Legal Proceedings 44
Item 2. Changes in Securities and Use of Proceeds 45
Item 3. Defaults Upon Senior Securities 45
Item 4. Submission of Matters to a Vote of Security Holders 45
Item 5. Other Information 46
Item 6. Exhibits and Reports on Form 8-K 46
Signatures
As used in this Quarterly Report on Form 10-Q, the terms "we", "our" or "us"
mean ONEOK, Inc., an Oklahoma corporation, and its predecessors and
subsidiaries, unless the context indicates otherwise.
2
Part I - FINANCIAL INFORMATION
Item 1. Financial Statements
ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF INCOME
Three Months Ended Six Months Ended
June 30, June 30,
(Unaudited) 2002 2001 2002 2001
- ------------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars, except per share amounts)
Operating Revenues $ 1,171,444 $ 1,402,399 $ 2,637,102 $ 4,359,323
Cost of gas 916,525 1,181,444 2,074,611 3,847,507
- ------------------------------------------------------------------------------------------------------------------------------------
Net Revenues 254,919 220,955 562,491 511,816
- ------------------------------------------------------------------------------------------------------------------------------------
Operating Expenses
Operations and maintenance 110,098 96,179 219,164 190,974
Depreciation, depletion, and amortization 44,976 37,856 85,212 74,811
General taxes 15,528 14,978 30,850 31,043
- ------------------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 170,602 149,013 335,226 296,828
- ------------------------------------------------------------------------------------------------------------------------------------
Operating Income 84,317 71,942 227,265 214,988
- ------------------------------------------------------------------------------------------------------------------------------------
Other income, net 5,131 566 4,411 3,865
Interest expense 27,853 36,249 54,035 73,784
Income taxes 26,212 12,651 69,660 54,451
- ------------------------------------------------------------------------------------------------------------------------------------
Income before cumulative effect of a change in
accounting principle 35,383 23,608 107,981 90,618
Cumulative effect of a change in
accounting principle, net of tax (Note H) -- -- -- (2,151)
- ------------------------------------------------------------------------------------------------------------------------------------
Net Income 35,383 23,608 107,981 88,467
Preferred stock dividends 9,275 9,275 18,550 18,550
- ------------------------------------------------------------------------------------------------------------------------------------
Income Available for Common Stock $ 26,108 $ 14,333 $ 89,431 $ 69,917
====================================================================================================================================
Earnings Per Share of Common Stock (Note D)
Basic $ 0.29 $ 0.20 $ 0.90 $ 0.74
====================================================================================================================================
Diluted $ 0.29 $ 0.20 $ 0.89 $ 0.74
====================================================================================================================================
Average Shares of Common Stock (Thousands)
Basic 99,877 99,407 99,808 99,311
Diluted 100,707 99,733 100,488 99,665
See accompanying Notes to Consolidated Financial Statements.
3
ONEOK, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
June 30, December 31,
(Unaudited) 2002 2001
- ---------------------------------------------------------------------------------------------
Assets (Thousands of Dollars)
Current Assets
Cash and cash equivalents $ 43,778 $ 28,229
Trade accounts and notes receivable, net 561,753 677,796
Materials and supplies 17,897 20,310
Gas in storage 57,309 82,694
Unrecovered purchased gas costs - 45,098
Assets from price risk management activities 798,610 587,740
Deposits - 41,781
Other current assets 25,872 78,321
- --------------------------------------------------------------------------------------------
Total Current Assets 1,505,219 1,561,969
- --------------------------------------------------------------------------------------------
Property, Plant and Equipment
Marketing and Trading 123,751 122,172
Gathering and Processing 1,065,447 1,040,195
Transportation and Storage 808,214 792,641
Distribution 2,035,353 1,985,177
Production 505,723 482,404
Other 91,681 85,168
- --------------------------------------------------------------------------------------------
Total Property, Plant and Equipment 4,630,169 4,507,757
Accumulated depreciation, depletion, and amortization 1,307,681 1,234,789
- --------------------------------------------------------------------------------------------
Net Property, Plant and Equipment 3,322,488 3,272,968
- --------------------------------------------------------------------------------------------
Deferred Charges and Other Assets
Regulatory assets, net (Note B) 228,568 232,520
Goodwill 113,868 113,868
Assets from price risk management activities 359,781 475,066
Investments and other 176,207 222,768
- --------------------------------------------------------------------------------------------
Total Deferred Charges and Other Assets 878,424 1,044,222
- --------------------------------------------------------------------------------------------
Total Assets $ 5,706,131 $ 5,879,159
============================================================================================
See accompanying Notes to Consolidated Financial Statements.
4
ONEOK, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
June 30, December 31,
(Unaudited) 2002 2001
- ----------------------------------------------------------------------------------------------------------
Liabilities and Shareholders' Equity (Thousands of Dollars)
Current Liabilities
Current maturities of long-term debt $ 10,000 $ 250,000
Notes payable 351,106 599,106
Accounts payable 435,940 390,479
Accrued taxes 13,957 11,528
Accrued interest 31,433 31,954
Unrecovered purchased gas costs 14,112 -
Customers' deposits 21,147 21,697
Liabilities from price risk management activities 506,303 381,409
Other 190,868 132,244
- ----------------------------------------------------------------------------------------------------------
Total Current Liabilities 1,574,866 1,818,417
- ----------------------------------------------------------------------------------------------------------
Long-term Debt, excluding current maturities 1,519,249 1,498,012
Deferred Credits and Other Liabilities
Deferred income taxes 571,458 499,432
Liabilities from price risk management activities 374,141 491,374
Lease obligation 115,531 122,011
Other deferred credits 208,955 184,623
- ----------------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 1,270,085 1,297,440
- ----------------------------------------------------------------------------------------------------------
Total Liabilities 4,364,200 4,613,869
- ----------------------------------------------------------------------------------------------------------
Commitments and Contingencies (Note E)
Shareholders' Equity
Convertible preferred stock, $0.01 par value:
Series A authorized 20,000,000 shares; issued and
outstanding 19,946,448 shares at June 30, 2002
and December 31, 2001 199 199
Common stock, $0.01 par value:
authorized 300,000,000 shares; issued 63,438,441 shares
with 60,352,331 and 60,002,218 shares outstanding
at June 30, 2002 and December 31, 2001, respectively 634 634
Paid in capital (Note G) 902,963 902,269
Unearned compensation (3,716) (2,000)
Accumulated other comprehensive income (loss) (Note I) (747) (1,780)
Retained earnings 486,381 415,513
Treasury stock at cost: 3,036,534 shares at June 30, 2002;
and 3,436,223 shares at December 31, 2001 (43,783) (49,545)
- ----------------------------------------------------------------------------------------------------------
Total Shareholders' Equity 1,341,931 1,265,290
- ----------------------------------------------------------------------------------------------------------
Total Liabilities and Shareholders' Equity $ 5,706,131 $ 5,879,159
==========================================================================================================
5
ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
Six Months Ended
June 30,
(Unaudited) 2002 2001
- ----------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Activities
Net income $ 107,981 $ 88,467
Depreciation, depletion, and amortization 85,212 74,811
Gain on sale of assets (813) (1,120)
Gain on sale of equity investment (7,622) (758)
(Income) loss from equity investments 553 (6,209)
Deferred income taxes 110,954 16,582
Amortization of restricted stock 1,058 627
Allowance for doubtful accounts 4,344 13,839
Mark-to-market income (52,416) (27,609)
Changes in assets and liabilities:
Accounts and notes receivable 111,699 942,459
Inventories 27,798 (4,743)
Unrecovered purchased gas costs 59,210 (80,237)
Deposits 41,781 37,170
Accounts payable and accrued liabilities 18,062 (652,369)
Price risk management assets and liabilities (35,031) (121,777)
Other assets and liabilities 113,008 (24,821)
- ----------------------------------------------------------------------------------------------------------
Cash Provided by Operating Activities 585,778 254,312
- ----------------------------------------------------------------------------------------------------------
Investing Activities
Changes in other investments, net 1,869 1,504
Acquisitions (3,489) (15,337)
Capital expenditures (133,872) (173,990)
Proceeds from sale of property 1,400 7,911
Proceeds from sale of equity investment 57,461 7,425
- ----------------------------------------------------------------------------------------------------------
Cash Used in Investing Activities (76,631) (172,487)
- ----------------------------------------------------------------------------------------------------------
Financing Activities
Payments of notes payable, net (248,000) (390,750)
Change in bank overdraft 28,757 (57,739)
Issuance of debt - 400,000
Payment of debt (241,040) (2,455)
Issuance of common stock - 5,169
Issuance of treasury stock, net 3,798 839
Dividends paid (37,113) (36,896)
- ----------------------------------------------------------------------------------------------------------
Cash Used In Financing Activities (493,598) (81,832)
- ----------------------------------------------------------------------------------------------------------
Change in Cash and Cash Equivalents 15,549 (7)
Cash and Cash Equivalents at Beginning of Period 28,229 249
- ----------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 43,778 $ 242
==========================================================================================================
See accompanying Notes to Consolidated Financial Statements.
6
ONEOK, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
A. Summary of Accounting Policies
Interim Reporting - The accompanying unaudited consolidated financial statements
of ONEOK, Inc. and its subsidiaries (the "Company") have been prepared in
accordance with accounting principles generally accepted in the United States of
America for interim financial information. The interim consolidated 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 Company's business, the results of operations for the
three and six months ended June 30, 2002, 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 Annual Report on Form 10-K for the year ended December 31, 2001.
Goodwill - On January 1, 2002, the Company adopted Statement of Financial
Accounting Standards No. 142, "Goodwill and Other Intangible Assets" (Statement
142). Accordingly, the Company has discontinued the amortization of goodwill
effective January 1, 2002. In accordance with the provisions of Statement 142,
the Company has completed its analysis of goodwill for impairment and there was
no impairment indicated. See Note J.
Reclassifications - Certain amounts in the consolidated financial statements
have been reclassified to conform to the 2002 presentation.
Critical Accounting Policies
Energy Trading and Risk Management Activities- The Company engages in price risk
management activities for both energy trading and non-trading purposes. The
Company accounts for price risk management activities for its energy trading
contracts in accordance with Emerging Issues Task Force Issue No. 98-10,
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities" (EITF 98-10). EITF 98-10 requires entities involved in energy
trading activities to account for energy trading contracts using mark-to-market
accounting. Forwards, swaps, options, and energy transportation and storage
contracts utilized for trading activities are reflected in the consolidated
balance sheets at fair value as assets and liabilities resulting from price risk
management activities. The fair value of these assets and liabilities is
affected by the actual timing of settlements related to these contracts and
current period changes resulting primarily from newly originated transactions
and the impact of price movements. Changes in fair value are recognized in net
revenues in the consolidated statements of income. Market prices used to
determine the fair value of these assets and liabilities reflect management's
best estimate considering various factors including closing exchange and
over-the-counter quotations, time value and volatility underlying the
commitments. Market prices are adjusted for the potential impact of liquidating
the Company's position in an orderly manner over a reasonable period of time
under currently existing market conditions.
The Marketing and Trading segment's gas in storage inventory is recorded at fair
value and is included in current price risk management assets.
7
Regulation - The Company's intrastate transmission pipelines and distribution
operations are subject to the rate regulation and accounting requirements of the
Oklahoma Corporation Commission (OCC), Kansas Corporation Commission (KCC) and
Texas Railroad Commission (TRC). Certain other transportation activities of the
Company are subject to regulation by the Federal Energy Regulatory Commission
(FERC). Oklahoma Natural Gas (ONG) and Kansas Gas Service (KGS) follow the
accounting and reporting guidance contained in Statement of Financial Accounting
Standards No. 71, "Accounting for the Effects of Certain Types of Regulation"
(Statement 71). Allocation of costs and revenues to accounting periods for
ratemaking and regulatory purposes may differ from allocations generally applied
by non-regulated operations. Allocations of costs and revenues made by the
Company to meet regulatory accounting requirements are considered to be in
accordance with generally accepted accounting principles for regulated
utilities.
During the ratemaking process, regulatory commissions may require a utility to
defer recognition of certain costs to be recovered through rates over time as
opposed to expensing such costs as incurred. This allows the utility to
stabilize rates over time rather than passing such costs on to the customer for
immediate recovery. This causes certain expenses to be deferred as a regulatory
asset and amortized to expense as they are recovered through rates. Total
regulatory assets resulting from this deferral process were approximately $228.6
million and $232.5 million at June 30, 2002 and December 31, 2001, respectively.
Should unbundling of services occur, certain of these assets may no longer meet
the criteria for accounting for these assets in accordance with Statement 71
and, accordingly, a write-off of regulatory assets and stranded costs may be
required. However, the Company does not anticipate that these costs, if any,
will be significant. See Note B.
KGS was subject to a three-year rate moratorium, which was set to expire in
November 2000. As a result of implementing a weather normalization mechanism in
Kansas, KGS agreed to a two-year extension of the rate moratorium. The extended
rate moratorium expires in November 2002 and KGS expects to file a rate case at
that time. ONG is not subject to a rate moratorium.
Impairment of Long-Lived Assets - The Company recognizes the impairment of a
long-lived asset when indicators of impairment are present and the undiscounted
cash flow is not sufficient to recover the carrying amount of these assets. The
impairment loss is measured by comparing the fair value of the asset to its
carrying amount. Fair values are based on discounted future cash flows or
information provided by sales and purchases of similar assets.
8
B. Regulatory Assets
The following table is a summary of the Company's regulatory assets, net of
amortization, for the periods indicated.
June 30, December 31,
2002 2001
-----------------------------------------------------------------------
(Thousands of Dollars)
Recoupable take-or-pay $ 72,588 $ 75,336
Pension costs 9,033 11,124
Postretirement costs other than pension 59,976 60,170
Transition costs 21,307 21,598
Reacquired debt costs 21,925 22,351
Income taxes 26,754 28,365
Weather normalization 9,717 7,984
Line replacements 2,392 94
Other 4,876 5,498
--------------------------------------------------------------------
Regulatory assets, net $228,568 $232,520
====================================================================
C. Supplemental Cash Flow Information
The following table sets forth supplemental information with respect to the
Company's cash flows for the periods indicated.
Six Months Ended
June 30,
2002 2001
--------------------------------------------------------------------------------
(Thousands of Dollars)
Cash paid during the period
Interest (including amounts capitalized) $54,557 $64,024
Income taxes $ 8,527 $12,666
Income tax refund received $61,058 $ --
Noncash transactions
Dividends on restricted stock $ 116 $ 96
Treasury stock transferred to compensation plans $ 25 $ 131
Issuance of restricted stock, net $ 2,658 $ 1,984
Acquisitions
Property, plant and equipment $ 3,489 $ 837
Goodwill $ -- $14,500
=============================================================================
9
D. Earnings Per Share Information
The Company computes its earnings per common share (EPS) in accordance with a
pronouncement of the Financial Accounting Standards Board's Staff at the
Emerging Issues Task Force meeting in April 2001, codified as EITF Topic No.
D-95 (Topic D-95). In accordance with Topic D-95, the dilutive effect of the
Company's Series A Convertible Preferred Stock is considered in the computation
of basic EPS utilizing the "if-converted" method. Under the Company's
"if-converted" method, the dilutive effect of the Company's Series A Convertible
Preferred Stock on EPS cannot be less than the amount that would result from the
application of the "two-class" method of computing EPS. The "two-class" method
is an earnings allocation formula that determines EPS for the Company's common
stock and its participating Series A Convertible Preferred Stock according to
dividends declared and participating rights in the undistributed earnings. The
Company's Series A Convertible Preferred Stock is a participating instrument
with the Company's common stock with respect to the payment of dividends. For
all periods presented, the "two-class" method resulted in additional dilution.
Accordingly, EPS for such periods reflects this further dilution.
The following is a reconciliation of the basic and diluted EPS computations for
the periods indicated.
Three Months Ended June 30, 2002
Per Share
Income Shares Amount
----------------------------------------------------------------------------------------------------
(Thousands, except per share amounts)
Basic EPS
Income available for common stock $ 26,108 59,985
Convertible preferred stock 9,275 39,892
--------------------------
Income available for common stock
and assumed conversion of preferred stock 35,383 99,877 $ 0.35
Further dilution from applying the "two-
class" method (0.06)
--------
Basic earnings per share $ 0.29
========
Effect of Other Dilutive Securities
Options and other dilutive securities - 830
--------------------------
Diluted EPS
Income available for common stock
and assumed exercise of stock options $ 35,383 100,707 $ 0.35
==========================
Further dilution from applying the "two-
class" method (0.06)
--------
Diluted earnings per share $ 0.29
===================================================================================================
10
Three Months Ended June 30, 2001
Per Share
Income Shares Amount
- ------------------------------------------------------------------------------------------------------
(Thousands, except per share amounts)
Basic EPS
Income available for common stock $ 14,333 59,515
Convertible preferred stock 9,275 39,892
--------------------
Income available for common stock
and assumed conversion of preferred stock 23,608 99,407 $ 0.24
Further dilution from applying the "two-
class" method (0.04)
---------
Basic earnings per share $ 0.20
=========
Effect of Other Dilutive Securities
Options and other dilutive securities - 326
--------------------
Diluted EPS
Income available for common stock
and assumed exercise of stock options $ 23,608 99,733 $ 0.24
====================
Further dilution from applying the "two-
class" method (0.04)
---------
Diluted earnings per share $ 0.20
=======================================================================================================
Six Months Ended June 30, 2002
Per Share
Income Shares Amount
- ------------------------------------------------------------------------------------------------------
(Thousands, except per share amounts)
Basic EPS
Income available for common stock $ 89,431 59,916
Convertible preferred stock 18,550 39,892
--------------------
Income available for common stock
and assumed conversion of preferred stock 107,981 99,808 $ 1.08
Further dilution from applying the "two-
class" method (0.18)
----------
Basic earnings per share $ 0.90
==========
Effect of Other Dilutive Securities
Options and other dilutive securities - 680
--------------------
Diluted EPS
Income available for common stock
and assumed exercise of stock options $ 107,981 100,488 $ 1.07
====================
Further dilution from applying the "two-
class" method (0.18)
----------
Diluted earnings per share $ 0.89
=======================================================================================================
11
Six Months Ended June 30, 2001
Per Share
Income Shares Amount
------------------------------------------------------------------------------------------------------
(Thousands, except per share amounts)
Basic EPS
Income available for common stock $ 69,917 59,419
Convertible preferred stock 18,550 39,892
--------------------
Income available for common stock
and assumed conversion of preferred stock 88,467 99,311 $ 0.89
Further dilution from applying the "two-
class" method (0.15)
----------
Basic earnings per share $ 0.74
==========
Effect of Other Dilutive Securities
Options and other dilutive securities - 354
--------------------
Diluted EPS
Income available for common stock
and assumed exercise of stock options $ 88,467 99,665 $ 0.89
====================
Further dilution from applying the "two-
class" method (0.15)
----------
Diluted earnings per share $ 0.74
=======================================================================================================
There were 51,839 and 64,148 option shares excluded from the calculation of
diluted EPS for the three months ended June 30, 2002 and 2001, respectively,
since their inclusion would be antidilutive for each period. For the six months
ended June 30, 2002 and 2001, there were 139,897 and 37,384 option shares,
respectively, excluded from the calculation of diluted EPS since their inclusion
would be antidilutive for each period.
The following is a reconciliation of the basic and diluted EPS computations
before the cumulative effect of a change in accounting principle to net income
for the periods indicated.
Six Months Ended June 30,
Basic EPS Diluted EPS
2002 2001 2002 2001
- -------------------------------------------------------------------------------
(Per share amounts)
Income available for common stock
before cumulative effect of a
change in accounting principle $ 0.90 $ 0.76 $ 0.89 $ 0.76
Cumulative effect of a change in
accounting principle, net of tax - (0.02) - (0.02)
------ ------- ------ ------
Income available for common stock $ 0.90 $ 0.74 $ 0.89 $ 0.74
===============================================================================
12
E. Commitments and Contingencies
Enron - Certain of the financial instruments discussed in the Company's Annual
Report on Form 10-K for the year ended December 31, 2001, have Enron North
America as the counterparty. Enron Corporation and various subsidiaries,
including Enron North America, filed for protection from creditors under Chapter
11 of the United States Bankruptcy Code on December 3, 2001. In the fourth
quarter of 2001, the Company took a charge of $37.4 million to provide an
allowance for forward financial positions and to establish an allowance for
uncollectible accounts related to previously settled financial and physical
positions with Enron. In the first quarter of 2002, the Company recorded a cash
recovery of approximately $22.1 million resulting in a gain of approximately
$14.0 million as a result of an agreement to sell the related Enron claim to a
third party. The sale of the Enron claim is subject to normal representations as
to the validity of the claims and the guarantees from Enron.
The filing of the voluntary bankruptcy proceeding by Enron created a possible
technical default related to various financing leases tied to the Company's
Bushton gas processing plant in south central Kansas. The Company acquired the
Bushton gas processing plant and related leases from Kinder Morgan, Inc. (KMI)
in April 2000. KMI had previously acquired the plant and leases from Enron.
Enron is one of three guarantors of these Bushton plant leases. However, the
Company is the primary guarantor. In January 2002, the Company was granted a
waiver on the possible technical default related to these leases. The Company
will continue to make all payments due under these leases.
Westar Energy - In May 2002, Westar Energy, Inc. (formerly known as Western
Resources, Inc.) and its wholly owned subsidiary, Westar Industries, Inc.
delivered a sale notice to the Company giving notice of Westar's intent to sell
4,714,434 shares of the Company's common stock and 19,946,448 shares of the
Company's Series A Convertible Preferred Stock, representing all of the
Company's common and preferred stock held by Westar.
The delivery of the sale notice to the Company gives the Company or its designee
the option to purchase all, but not less than all, of the common and preferred
stock held by Westar at a price equal to 98.5% of the average of the closing
prices of the Company's common stock during the 20 trading days prior to the
date of the sale notice, which equals $21.77 per share for a total purchase
price of approximately $971 million. The purchase period is 90 days after the
date of notice and expires August 28, 2002. This period can be extended for 30
days after any necessary regulatory approvals, but cannot exceed 180 days after
the date of the sale notice. The Company is currently considering its options
related to the notice.
Southwest Gas Corporation - In connection with the now terminated proposed
acquisition of Southwest Gas Corporation (Southwest), the Company is a party to
various lawsuits.
The Company and certain of its officers, as well as Southwest and certain of its
officers, and others have been named as defendants in a lawsuit brought by
Southern Union Company (Southern Union). The Southern Union allegations include,
but are not limited to, violations of the Racketeer Influenced and Corrupt
Organizations Act and improper interference in a contractual relationship
between Southwest and Southern Union. The original claim asked for not less than
$750 million compensatory damages, to be trebled for racketeering and unlawful
violations, and rescission of a Confidentiality and Standstill Agreement between
the Company and Southern Union.
13
On June 29, 2001, the Company filed Motions for Summary Judgment. On September
26, 2001, the Court entered an order that, among other things, denied the
Motions for Summary Judgment by the Company on Southern Union's claim for
tortious interference with Southern Union's prospective relationship with
Southwest. However, the Court's ruling limited any recovery by Southern Union to
out-of-pocket damages and punitive damages. On June 10, 2002, the Company filed
a motion for summary judgment against Southern Union as to Southern Union's sole
remaining claim for tortious interference with a prospective relationship, and
also moved for summary judgment on Southern Union's claim for punitive damages.
Eugene Dubay and John A. Gaberino, Jr., each an officer of the Company, joined
in that motion. Trial is currently scheduled to begin October 15, 2002. Based on
discovery at this point, the Company believes that Southern Union's
out-of-pocket damages potentially recoverable at trial, exclusive of punitive
damages, legal fees and expenses, are less than $1.0 million.
Southwest filed a lawsuit against the Company and Southern Union alleging, among
other things, fraud and breach of contract. On August 9, 2002, the Company
settled with Southwest all claims asserted against each other in these cases in
consideration for a payment of $3.0 million to be paid by the Company to
Southwest.
On August 6, 2002, Southwest and Southern Union settled their claims against
each other. Trial on the remaining claims asserted by Southern Union against the
Company is scheduled to begin October 15, 2002.
Two substantially identical derivative actions were filed by shareholders
against members of the Board of Directors of the Company alleging violation of
their fiduciary duties to the Company by causing or allowing the Company to
engage in certain fraudulent and improper schemes related to the planned
acquisition of Southwest and waste of corporate assets. These two cases have
been consolidated. They allege conduct by the Company 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. The
Company and its independent directors and officers named as defendants filed
Motions to Dismiss the action for failure of the plaintiffs to make a pre-suit
demand on the Company's Board of Directors. In addition, the independent
directors and certain officers filed Motions to Dismiss the action for failure
to state a claim. On February 26, 2001, the action was stayed until one of the
parties notifies the Court that a dissolution of the stay is requested.
Except as set forth above, the Company is unable to estimate the possible loss,
if any, associated with these matters. If substantial damages were ultimately
awarded, this could have a material adverse effect on the Company's results of
operations, cash flows and financial position. The Company is defending itself
vigorously against all claims asserted by Southern Union and all other matters
relating to the now terminated proposed acquisition of Southwest.
Environmental - The Company has 12 manufactured gas sites in Kansas, which were
acquired in 1997, that may contain potentially harmful materials classified as
hazardous. Hazardous materials are subject to control or remediation under
various state and federal 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 and set remediation priorities for these sites based
upon the results of the investigations and risk analysis. The prioritized sites
will be investigated over a period of time as negotiated with the KDHE. Through
June 30, 2002, the costs of the investigation and risk analysis related to these
manufactured gas sites have been immaterial.
14
Although remedial investigation and interim clean up has begun on four sites,
limited information is available about the sites. Management's best estimate of
the cost of remediation ranges from $100,000 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 recoveries from unaffiliated 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 current estimates. 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.
In January 2001, the Company's Yaggy gas storage facility, located in Hutchison,
Kansas, was idled following a series of natural gas explosions and eruptions of
natural gas geysers. In July 2002, the KDHE issued an administrative order that
assesses a $180,000 civil penalty against the Company, based on alleged
violations of several KDHE regulations. The Company is currently assessing if it
will appeal this order. The Company believes there are no long-term
environmental effects from the Yaggy storage facility.
Other - The OCC staff filed an application on February 1, 2001 to review the gas
procurement practices of ONG in acquiring its gas supply for the 2000/2001
heating season and to determine if these practices were consistent with least
cost procurement practices and whether the Company's procurement decisions
resulted in fair, just and reasonable costs being borne by ONG customers. In a
hearing on October 31, 2001, the OCC issued an oral ruling that ONG not be
allowed to recover the balance in the Company's unrecovered purchased gas cost
(UPGC) account related to the unrecovered gas costs from the 2000/2001 winter.
This was effective with the first billing cycle for the month following the
issuance of a final order. A final order, issued on November 20, 2001, halted
the recovery process effective December 1, 2001. On December 12, 2001, the OCC
approved a request to stay the order and allowed ONG to begin collecting
unrecovered gas costs, subject to refund should the Company ultimately lose the
case. In the fourth quarter of 2001, the Company took a charge of $34.6 million
as a result of this order. In May 2002, the Company, along with the staff of the
Public Utility Division and the Consumer Services Division of the OCC, the
Oklahoma Attorney General, and other stipulating parties, entered into a joint
settlement agreement resolving this gas cost issue and ongoing litigation
related to a contract with Dynamic Energy Resources, Inc.
The settlement agreement has a $33.7 million value to ONG customers that will be
realized over a three-year period. In July 2002, immediate cash savings were
provided to all ONG customers in the form of billing credits totaling
approximately $10.1 million. ONG is replacing certain gas contracts, which is
expected to reduce gas costs by approximately $13.8 million due to avoided
reservation fees between April 2003 and October 2005. Additional savings of
approximately $8.0 million from the use of storage service in lieu of those
contracts are expected to occur between November 2003 and March 2005. Any
expected savings from the use of storage that are not achieved and a $1.8
million credit will be added to the final billing credit scheduled to be
provided to customers in December 2005. As a result of this settlement
agreement, the Company revised its estimate of the charge taken in the fourth
quarter of 2001 downward by $14.2 million to $20.4 million and recorded the
adjustment in the second quarter of 2002 as a decrease to cost of gas.
15
Two separate class action lawsuits have been filed against the Company in
connection with the natural gas explosions and eruptions of natural gas geysers
that occurred at the Yaggy storage facility in Hutchinson, Kansas in January
2001. Although no assurances can be given, the Company believes that the
ultimate resolution of these matters will not have a material adverse effect on
its financial position or results of operations. The Company and its
subsidiaries are represented by their insurance carrier in these cases. The
Company is vigorously defending itself against all claims.
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 the Company's
consolidated results of operations, financial position, or liquidity.
F. Segments
Management has divided the Company's operations into the following six
reportable segments based on similarities in economic characteristics, products
and services, types of customers, methods of distribution and regulatory
environment: (1) the Marketing and Trading 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
fractionates, stores and markets natural gas liquids; (3) the Transportation and
Storage segment transports and stores natural gas for others and buys and sells
natural gas; (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.
During the first quarter of 2002, the Power segment was combined with the
Marketing and Trading segment, eliminating the Power segment. This presentation
reflects the Company's strategy of trading around the Company's recently
completed electric generating power plant. The prior period has been restated to
reflect this combination.
The accounting policies of the segments are substantially the same as those
described in the Summary of Significant Accounting Policies in the Company's
Annual Report on Form 10-K for the year ended December 31, 2001. Intersegment
sales are recorded on the same basis as sales to unaffiliated customers.
Corporate overhead costs relating to a reportable segment are 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 consolidated
revenues.
The following tables set forth certain selected financial information for the
Company's six operating segments for the periods indicated.
16
Three Months Marketing Gathering Transportation Other
Ended and and and and
June 30, 2002 Trading Processing Storage Distribution Production Eliminations Total
- -----------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Sales to unaffiliated
customers $ 729,924 $ 189,051 $ 18,986 $ 211,663 $ 20,587 $ 1,233 $ 1,171,444
Intersegment sales 69,565 79,054 23,600 1,100 3,804 (177,123) $ -
- -----------------------------------------------------------------------------------------------------------------------------------
Total Revenues $ 799,489 $ 268,105 $ 42,586 $ 212,763 $ 24,391 $ (175,890) $ 1,171,444
- -----------------------------------------------------------------------------------------------------------------------------------
Net revenues $ 67,177 $ 44,559 $ 27,214 $ 91,444 $ 24,391 $ 134 $ 254,919
Operating costs $ 8,076 $ 35,940 $ 16,556 $ 54,745 $ 7,809 $ 2,500 $ 125,626
Depreciation, depletion and
amortization $ 1,465 $ 8,591 $ 5,471 $ 19,575 $ 9,483 $ 391 $ 44,976
Operating income $ 57,636 $ 28 $ 5,187 $ 17,124 $ 7,099 $ (2,757) $ 84,317
Income from equity
investments $ - $ - $ 24 $ - $ - $ 438 $ 462
Capital expenditures $ 1,442 $ 14,007 $ 9,741 $ 32,403 $ 11,349 $ 4,080 $ 73,022
- -----------------------------------------------------------------------------------------------------------------------------------
Three Months Marketing Gathering Transportation Other
Ended and and and and
June 30, 2001 Trading Processing Storage Distribution Production Eliminations Total
- -----------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Sales to unaffiliated
customers $ 909,114 $ 218,033 $ 22,173 $ 225,051 $ 27,842 $ 186 $ 1,402,399
Intersegment sales 105,810 135,634 25,706 772 7,182 (275,104) $ -
- -----------------------------------------------------------------------------------------------------------------------------------
Total Revenues $ 1,014,924 $ 353,667 $ 47,879 $ 225,823 $ 35,024 $ (274,918) $ 1,402,399
- -----------------------------------------------------------------------------------------------------------------------------------
Net revenues $ 39,333 $ 43,080 $ 32,698 $ 72,290 $ 35,024 $ (1,470) $ 220,955
Operating costs $ 2,383 $ 29,219 $ 12,348 $ 61,629 $ 7,149 $ (1,571) $ 111,157
Depreciation, depletion and
amortization $ 142 $ 6,995 $ 4,751 $ 17,159 $ 8,159 $ 650 $ 37,856
Operating income $ 36,808 $ 6,866 $ 15,599 $ (6,498) $ 19,716 $ (549) $ 71,942
Income (loss) from equity
investments $ - $ - $ 849 $ - $ 39 $ (86) $ 802
Capital expenditures $ 11,975 $ 9,562 $ 7,308 $ 30,216 $ 14,959 $ 8,957 $ 82,977
- -----------------------------------------------------------------------------------------------------------------------------------
Six Months Marketing Gathering Transportation Other
Ended and and and and
June 30, 2002 Trading Processing Storage Distribution Production Eliminations Total
- -----------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Sales to unaffiliated
customers $ 1,503,488 $ 346,093 $ 38,115 $ 709,648 $ 37,425 $ 2,333 $ 2,637,102
Intersegment sales 208,485 137,607 53,674 2,244 6,623 (408,633) $ -
- -----------------------------------------------------------------------------------------------------------------------------------
Total Revenues $ 1,711,973 $ 483,700 $ 91,789 $ 711,892 $ 44,048 $ (406,300) $ 2,637,102
- -----------------------------------------------------------------------------------------------------------------------------------
Net revenues $ 139,086 $ 85,882 $ 63,946 $ 229,439 $ 44,048 $ 90 $ 562,491
Operating costs $ 16,241 $ 68,010 $ 31,221 $ 117,630 $ 15,104 $ 1,808 $ 250,014
Depreciation, depletion and
amortization $ 2,648 $ 16,561 $ 10,045 $ 36,524 $ 18,657 $ 777 $ 85,212
Operating income $ 120,197 $ 1,311 $ 22,680 $ 75,285 $ 10,287 $ (2,495) $ 227,265
Income (loss) from equity
investments $ - $ - $ 462 $ - $ - $ (1,015) $ (553)
Total assets $ 1,511,871 $ 1,231,211 $ 818,742 $ 1,719,809 $ 327,957 $ 96,541 $ 5,706,131
Capital expenditures $ 1,580 $ 24,815 $ 24,500 $ 53,524 $ 22,971 $ 6,482 $ 133,872
- -----------------------------------------------------------------------------------------------------------------------------------
17
Six Months Marketing Gathering Transportation Other
Ended and and and and
June 30, 2001 Trading Processing Storage Distribution Production Eliminations Total
- ----------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Sales to unaffiliated
customers $ 2,777,234 $ 491,720 $ 57,013 $ 986,226 $ 44,681 $ 2,449 $ 4,359,323
Intersegment sales 525,848 338,539 44,069 1,505 19,629 (929,590) $ -
- ----------------------------------------------------------------------------------------------------------------------------------
Total Revenues $ 3,303,082 $ 830,259 $ 101,082 $ 987,731 $ 64,310 $ (927,141) 4,359,323
- ----------------------------------------------------------------------------------------------------------------------------------
Net revenues $ 68,614 $ 92,305 $ 70,259 $ 213,062 $ 64,310 $ 3,266 $ 511,816
Operating costs $ 6,805 $ 58,396 $ 25,237 $ 119,694 14,954 $ (3,069) $ 222,017
Depreciation, depletion and
amortization $ 298 $ 13,806 $ 9,501 $ 34,136 $ 15,744 $ 1,326 $ 74,811
Operating income $ 61,511 $ 20,103 $ 35,521 $ 59,232 $ 33,612 $ 5,009 $ 214,988
Cumulative effect of a change
in accounting principle,
net of tax $ - $ - $ - $ - $ (2,151) $ - $ (2,151)
Income from equity
investments $ - $ - $ 1,508 $ - $ (141) $ 4,842 $ 6,209
Total assets $ 1,987,556 $ 1,247,510 $ 643,849 $ 1,844,662 $ 319,293 $ (107,173) $ 5,935,697
Capital expenditures $ 40,358 $ 16,713 $ 18,122 $ 57,394 $ 26,220 $ 15,183 $ 173,990
- ----------------------------------------------------------------------------------------------------------------------------------
G. Paid in Capital
Paid in capital is $338.8 million and $338.1 million for common stock at June
30, 2002, and December 31, 2001, respectively. Paid in capital for convertible
preferred stock was $564.2 million at June 30, 2002, and December 31, 2001.
H. Derivative Instruments and Hedging Activities
On January 1, 2001, the Company adopted the provisions of Statement of Financial
Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities" (Statement 133), amended by Statement No. 137 and Statement No. 138.
Statement 137 delayed the implementation of Statement 133 until fiscal years
beginning after June 15, 2000. Statement 138 amended the accounting and
reporting standards of Statement 133 for certain derivative instruments and
hedging activities. Statement 138 also amends Statement 133 for decisions made
by the Financial Accounting Standards Board (FASB) relating to the Derivatives
Implementation Group (DIG) process. The DIG is addressing Statement 133
implementation issues, the ultimate resolution of which may impact the
application of Statement 133.
Under Statement 133, entities are required to record 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 hedged 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 hedge, are reported in
earnings immediately.
18
In 2000, the Company entered into derivative instruments related to the
production of natural gas, most of which expired by the end of 2001. These
derivative instruments were designed to hedge the Company's Production segment's
exposure to changes in the price of natural gas. Changes in the fair value of
the derivative instruments were reflected initially in other comprehensive
income (loss) and subsequently realized in earnings when the forecasted
transaction affected earnings. At the adoption of Statement 133 the Company
recorded a cumulative effect charge of $2.2 million, net of tax, in the income
statement and $28 million, net of tax, in accumulated other comprehensive loss
to recognize at fair value the ineffective and effective portions, respectively,
of the losses on all derivative instruments that were designated as cash flow
hedging instruments, which primarily consisted of no cost option collars and
swaps on natural gas production.
The Company realized gains in earnings of approximately $0.6 million and $1.3
million for the three and six months ended June 30, 2002, respectively, related
to production hedges entered into in 2002. These realized gains were
reclassified from accumulated other comprehensive income resulting from the
settlement of contracts when the natural gas was sold. The gains are reported in
operating revenues. Other comprehensive income for the three and six months
ended June 30, 2002 includes approximately $2.6 million and $1.8 million,
respectively, related to a cash flow exposure for production hedges and will be
realized in earnings within the next 30 months.
The Company is subject to the risk of fluctuation in interest rates in the
normal course of business. The Company manages interest rate risk through the
use of fixed rate debt, floating rate debt and, at times, interest rate swaps.
In July 2001, the Company entered into interest rate swaps on a total of $400
million in fixed rate long-term debt. The interest rate under these swaps resets
periodically based on the three-month London InterBank Offered Rate (LIBOR) or
the six-month LIBOR rate at the reset date. In October 2001, the Company entered
into an agreement to lock in the interest rates for each reset period under the
swap agreements through the first quarter of 2003. In December 2001, the Company
entered into interest rate swaps on a total of $200 million in fixed rate
long-term debt. These swaps were designated as fair value hedges. Price risk
management assets include $30.7 million to recognize the fair value of the
Company's derivatives that are designated as fair value hedging instruments in
June 2002. Long-term debt includes approximately $29.3 million to recognize the
change in fair value of the related hedged liability. The Company also increased
interest expense by $0.8 million for the three months ended June 30, 2002 to
recognize the ineffectiveness caused by locking the LIBOR rates into future
periods.
I. Comprehensive Income
The tables below give an overview of comprehensive income for the three and six
months ended June 30, 2002 and 2001. Other comprehensive income for the three
and six months ended June 30, 2002 includes unrealized gains on derivative
instruments, unrealized holding gains arising during the period relating to the
investment in Magnum Hunter Resources (MHR) and realized gains on derivative
instruments and the sale of the Company's common stock ownership in MHR.
In March 2002, the Company began accounting for its investment in MHR as an
available-for-sale security and, accordingly, marked the investment to fair
value through other comprehensive income. This is a result of MHR's merger with
Prize Energy Corp. (Prize), which reduced the Company's direct ownership in MHR
to approximately 11 percent and reduced the number of MHR board of director
positions held by the Company from two to one. In April and June 2002, the
Company sold its common stock ownership in MHR.
19
Other comprehensive income for the three and six months ended June 30, 2001
includes the cumulative effect of a change in accounting principle due to the
adoption of Statement 133 and unrealized gains and realized losses on derivative
instruments.
Three Months Ended Six Months Ended
June 30, 2002 June 30, 2002
- --------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Net Income $ 35,383 $ 107,981
Other comprehensive income (loss):
Unrealized gains on derivative instruments $ 2,586 $ 1,786
Unrealized holding gains (losses) arising during the period (115) 13,927
Realized gains in net income (13,227) (13,961)
------------ -----------
Other comprehensive income before taxes (10,756) 1,752
Income tax benefit (expense) on other comprehensive income (loss) 3,858 (719)
----------- -----------
Other comprehensive income (loss) $ (6,898) $ 1,033
----------- -----------
Comprehensive income $ 28,485 $ 109,014
==========================================================================================================================
Three Months Ended Six Months Ended
June 30, 2001 June 30, 2001
- --------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Net Income $ 23,608 $ 88,467
Other comprehensive income:
Cumulative effect of a change in accounting principle $ - $ (45,556)
Unrealized gains on derivative instruments 10,300 22,726
Realized losses in net income 5,179 26,015
----------- -----------
Other comprehensive income before taxes 15,479 3,185
Income tax benefit on other comprehensive income (5,987) (1,231)
----------- -----------
Other comprehensive income $ 9,492 $ 1,954
----------- -----------
Comprehensive income $ 33,100 $ 90,421
==========================================================================================================================
Accumulated other comprehensive loss of $0.7 million at June 30, 2002, includes
unrealized and realized gains and losses on derivative instruments, unrealized
and realized holding gains and losses related to the investment in MHR and
minimum pension liability adjustments.
20
J. Goodwill
The Company adopted Statement of Financial Accounting Standards No. 142 on
January 1, 2002. Under Statement 142, goodwill is no longer amortized but
reviewed for impairment annually or more frequently if certain indicators arise.
Statement 142 prescribes a two phase process for testing the impairment of
goodwill. The first phase, required to be completed by June 30, 2002, identifies
indicators for impairment. If an impairment is indicated, the second phase,
required to be completed by December 31, 2002, measures the impairment. In
accordance with the provisions of Statement 142, the Company has performed the
first of the required impairment tests of goodwill and, based upon this
transition impairment test, no impairment to goodwill was indicated and the
Company will not record a charge in connection with the adoption of this
standard. Had the Company been accounting for its goodwill under Statement 142
for all periods presented, the Company's net income and income per share would
have been as follows:
Six Months Ended June 30,
2002 2001
- -----------------------------------------------------------------------------------------------
(Thousands of Dollars)
Reported net income $ 107,981 $ 88,467
Add back goodwill amortization, net of tax
- 1,348
--------------- ---------------
Pro forma adjusted net income $ 107,981 $ 89,815
=============== ===============
Basic net income per share:
Reported net income $ 0.90 $ 0.74
Goodwill amortization, net of tax - 0.01
--------------- ---------------
Pro forma adjusted basic net income per share $ 0.90 $ 0.75
=============== ===============
Diluted net income per share:
Reported net income $ 0.89 $ 0.74
Goodwill amortization, net of tax - 0.01
---------------- ---------------
Pro forma adjusted diluted net income per share $ 0.89 $ 0.75
===============================================================================================
The changes in the carrying amount of goodwill for the six months ended June 30,
2002 and 2001 are as follows:
Balance Balance
December 31, 2001 Additions Amortization June 30, 2002
--------------------------------------------------------------
(Thousands of Dollars)
Marketing and Trading $ 5,616 $ - $ - $ 5,616
Gathering and Processing 34,343 - - 34,343
Transportation and Storage 37,842 - - 37,842
Distribution 35,709 - - 35,709
Production 358 - - 358
--------------------------------------------------------------
Total consolidated $ 113,868 $ - $ - $ 113,868
==============================================================
21
Balance Balance
December 31, 2000 Additions Amortization June 30, 2001
---------------------------------------------------------------
(Thousands of Dollars)
Marketing and Trading $ 5,123 $ - $ (107) $ 5,016
Gathering and Processing 17,887 20,482 (303) 38,066
Transportation and Storage 33,328 5,394 (439) 38,283
Distribution 36,703 - (497) 36,206
Production 368 - (5) 363
---------------------------------------------------------------
Total consolidated $ 93,409 $ 25,876 $ (1,351) $ 117,934
===============================================================
K. Subsequent Event
On August 5, 2002, the Company launched a tender offer to purchase with cash all
the outstanding 8.44% Senior Notes due 2004 and the 8.32% Senior Notes due 2007
for a total purchase price of approximately $69 million. The total purchase
price includes a premium of approximately $5 million to purchase the notes. The
offer expires August 20, 2002. If completed, the Company will recognize the
transaction in the third quarter of 2002.
On August 9, 2002, the Company settled with Southwest all claims asserted
against each other related to the Company's terminated acquisition of Southwest.
The claims were settled for a payment of $3.0 million to be paid by the Company
to Southwest. This charge has been included in the consolidated financial
statements at June 30, 2002. See Note E.
22
Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operation
Forward Looking Statements
Some of the statements contained and incorporated in this Quarterly Report on
Form 10-Q are forward-looking statements within the meaning of the Private
Securities Litigation Reform Act of 1995. The forward-looking statements relate
to the anticipated financial performance, management's plans and objectives for
future operations, business prospects, outcome of pending litigation and
regulatory proceedings, market conditions and other matters. The Private
Securities Litigation Reform Act of 1995 provides a safe harbor for
forward-looking statements in various circumstances. The following discussion is
intended to identify important factors that could cause future outcomes to
differ materially from those set forth in the forward-looking statements.
Forward-looking statements include the items identified in the preceding
paragraph, the information concerning possible or assumed future results of
operations and other statements contained or incorporated in this report
identified by words such as "anticipate," "estimate," "expect," "intend,"
"believe," "projection" or "goal."
You should not place undue reliance on forward-looking statements. They are
based on known and unknown risks, uncertainties and other factors that may cause
our actual results, performance or achievements to be materially different from
any future results, performance or achievements expressed or implied by the
forward-looking statements. Those factors may affect our operations, markets,
products, services and prices. In addition to any assumptions and other factors
referred to specifically in connection with forward-looking statements, factors
that could cause our actual results to differ materially from those contemplated
in any forward-looking statement include, among others, the following:
.. the effects of weather and other natural phenomena on sales and prices;
.. 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 marketing, trading, and hedging activities as a result of
changes in energy prices, creditworthiness of counterparties and
government regulation;
.. 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 now terminated proposed
acquisition of Southwest Gas Corporation (Southwest);
.. the results of administrative proceedings and litigation involving the
Oklahoma Corporation Commission (OCC) and Kansas Corporation Commission
(KCC);
.. our ability to access capital at competitive rates;
23
.. the effect (including the effect on our liquidity and capital resources)
of a decision to purchase or not to purchase our shares of common and
preferred stock held by Westar Energy, Inc.; and
.. the other factors listed in the reports we have filed and may file from
time to time with the Securities and Exchange Commission
Other factors and assumptions not identified above also may have been involved
in the making of forward-looking statements. The failure of those assumptions to
be realized, as well as other factors, may also cause actual results to differ
materially from those projected.
Results of Operations
Consolidated Operations
We are a diversified energy company whose objective is to maximize value for
shareholders by vertically integrating our business operations from the wellhead
to the burner tip. This strategy has led us to focus on acquiring assets that
provide synergistic trading and marketing opportunities along the natural gas
energy chain. Products and services are provided to our customers through the
following segments:
.. Marketing and Trading
.. Gathering and Processing
.. Transportation and Storage
.. Distribution
.. Production
.. Other
During the first quarter of 2002, the Power segment was combined with the
Marketing and Trading segment, eliminating the Power segment. All segment data
has been restated to reflect this combination.
We sold and received cash for our claim related to the Enron bankruptcy for
$22.1 million resulting in a gain of $14.0 million in the first quarter of 2002.
The sale is subject to normal representations as to the validity of the claim
and guarantees from Enron. We had previously recorded a charge of $37.4 million
in the fourth quarter of 2001 related to the Enron bankruptcy.
During the second quarter of 2002, we settled a number of outstanding issues
pending before the OCC. We had previously recorded a charge of $34.6 million in
the fourth quarter of 2001 related to these matters. As a result of the
settlement agreement, we revised the estimated amount of the charge and reversed
$14.2 million of the charge in the second quarter of 2002.
24
On March 15, 2002, Magnum Hunter Resources (MHR) merged with Prize Energy Corp.
(Prize) reducing our direct ownership to approximately 11 percent and reducing
the number of positions held by us on the MHR board of directors from two to
one. We began accounting for our investment in MHR as an available-for-sale
security and, accordingly, marked the investment to fair value through other
comprehensive income at March 31, 2002. During the second quarter of 2002, we
sold the majority of our investment in MHR for a pre-tax gain of approximately
$7.6 million, which is included in other income, net for the three and six
months ended June 30, 2002. We retained approximately 1.5 million stock
warrants. We also relinquished our remaining seat on MHR's board of directors.
The MHR investment and related equity income and loss are reported in the Other
segment.
The following table sets forth certain selected financial information for the
periods indicated.
Three Months Ended Six Months Ended
June 30, June 30,
Financial Results 2002 2001 2002 2001
- ------------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating revenues $ 1,171,444 $ 1,402,399 $ 2,637,102 $ 4,359,323
Cost of gas 916,525 1,181,444 2,074,611 3,847,507
- ---------------------------------------------------------------------------------------------------------------------------------
Net revenues 254,919 220,955 562,491 511,816
Operating costs 125,626 111,157 250,014 222,017
Depreciation, depletion, and amortization 44,976 37,856 85,212 74,811
- ---------------------------------------------------------------------------------------------------------------------------------
Operating income $ 84,317 $ 71,942 $ 227,265 $ 214,988
=================================================================================================================================
Other income, net $ 5,131 $ 566 $ 4,411 $ 3,865
=================================================================================================================================
Cumulative effect of a change in accounting principle $ - $ - $ - $ (3,508)
Income tax - - - 1,357
- ---------------------------------------------------------------------------------------------------------------------------------
Cumulative effect of a change in accounting principle, net of tax $ - $ - $ - $ (2,151)
=================================================================================================================================
Our operating revenues and cost of gas decreased for the three and six months
ended June 30, 2002 compared to the same periods in 2001 primarily due to lower
natural gas prices. Although operating revenues and cost of gas decreased in
2002 compared to 2001, our net revenues increased primarily due to increased
margins from our marketing and trading business, the $14.0 million Enron
recovery in the first quarter of 2002 of a portion of the costs related to Enron
sales contracts that were written off in the fourth quarter of 2001, and the
$14.2 million adjustment due to the OCC settlement. These increases were offset
by decreases in net revenues in the Gathering and Processing, Transportation and
Storage and Production segments.
Increased employee costs were part of the increase in operating costs for the
three and six months ended June 30, 2002 compared to the same periods in 2001.
Other changes in operating costs are discussed in the applicable segment's
section.
Other income, net for the three and six months ended June 30, 2002, includes a
$7.6 million gain related to the sale of our investment in MHR. This was
partially offset by a $3.0 million charge for the settlement of litigation with
Southwest related to our terminated acquisition of Southwest. Other income, net
for the six months ended June 30, 2001, includes approximately $6.2 million in
income from equity investments that was partially offset by a charge of $2.2
million related to ongoing litigation costs associated with the terminated
acquisition of Southwest.
25
Marketing and Trading
Our Marketing and Trading segment purchases, stores, markets and trades natural
gas to both wholesale and retail customers in 28 states. We have strong
mid-continent region storage positions and transport capacity of approximately
one Bcf/d (Bcf per day) that allows us to trade storage capacity and
transportation from the California border, throughout the Rockies, to the
Chicago city gate. With total storage capacity of 80 Bcf, withdrawal capability
of 2.3 Bcf/d and injection capability of 1.3 Bcf/d, we have direct access to all
regions of the country and flexibility to capture volatility in the energy
markets. We have constructed a peak electric power generating plant that began
operations in mid-2001. This 300-megawatt plant is located adjacent to one of
our natural gas storage facilities and is configured to supply electric power
during peak demand periods. This plant allows us to capture the "spark spread
premium", which is the value added by converting natural gas to electricity,
during peak demand periods. We continue to enhance our strategy of focusing on
higher margin business (as opposed to volume) which includes providing reliable
service during peak demand periods through the use of storage.
During the first quarter of 2002, the Power segment was combined with the
Marketing and Trading segment, eliminating the Power segment. This combination
reflects our strategy of trading around the capacity of our electric generating
plant. All segment data has been restated to reflect this combination.
The following tables set forth certain selected financial and operating
information relative to our Marketing and Trading segment for the periods
indicated.
Three Months Ended Six Months Ended
June 30, June 30,
Financial Results 2002 2001 2002 2001
- ------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Energy sales $ 799,295 $ 1,014,411 $ 1,711,567 $ 3,301,824
Cost of sales 732,312 975,591 1,572,887 3,234,468
- -----------------------------------------------------------------------------------------------------------
Gross margin on sales 66,983 38,820 138,680 67,356
Other revenues 194 513 406 1,258
- -----------------------------------------------------------------------------------------------------------
Net revenues 67,177 39,333 139,086 68,614
Operating costs 8,076 2,383 16,241 6,805
Depreciation, depletion, and amortization 1,465 142 2,648 298
- -----------------------------------------------------------------------------------------------------------
Operating income $ 57,636 $ 36,808 $ 120,197 $ 61,511
===========================================================================================================
Other expense, net $ (2,352) $ - $ (2,211) $ -
===========================================================================================================
Three Months Ended Six Months Ended
June 30, June 30,
Operating Information 2002 2001 2002 2001
- -----------------------------------------------------------------------------------------------------------
Natural gas volumes (MMcf) 214,832 200,999 470,621 498,352
Natural gas gross margin ($/Mcf) $ 0.20 $ 0.19 $ 0.17 $ 0.13
Power volumes (MMwh) 336 73 652 73
Power gross margin ($/Mwh) $ 2.74 $ 12.30 $ 1.38 $ 12.30
Capital expenditures (Thousands) $ 1,442 $ 11,975 $ 1,580 $ 40,358
- -----------------------------------------------------------------------------------------------------------
26
Lower natural gas prices across the mid-continent region for the three months
ended June 30, 2002 compared to the same period in 2001, resulted in lower
energy sales and cost of sales. Natural gas sales volumes increased relative to
the prior year due to slightly lower storage injection rates that allowed us to
sell increased volumes. Energy sales include natural gas, power, reservation
fees, crude oil, natural gas liquids, and basis. Basis is the natural gas price
differential that exists between two trading locations relative to the Henry Hub
price. We began actively trading crude oil and natural gas liquids in the first
quarter of 2002. Gross margin on sales increased for the three months ended June
30, 2002 compared to the same period for 2001 due to our ability to successfully
execute our strategy to capture higher margins, even in the current
comparatively lower price environment, by trading around our asset base,
arbitraging intra-month price volatility through the use of storage and
transport capacity and capturing option value on gas storage and other energy
assets. We also benefited from comparatively lower prices that positively
impacted fuel costs associated with our long-term transportation contracts.
For the six-month period ended June 30, 2002, lower gas prices and sales volumes
resulted in lower sales and cost of sales in 2002 compared to the same period in
2001. Sales volumes were lower due to relatively milder temperatures during the
first quarter of 2002. Gross margin on sales increased for the six-month period
in 2002 compared to the same period in 2001 due to our ability to capture higher
margins by arbitraging the intra-month price volatility and capture option value
on stored gas and other energy assets. In addition, we benefited by $10.4
million from the sale of our Enron claim in the first quarter of 2002. Our gross
margin for the three and six months ended June 30, 2002 includes income
recognized from mark-to-market accounting of approximately $66 million and $52
million, respectively.
Operating costs for the three and six months ended June 30, 2002 compared to the
same periods in 2001 include increased employee costs and the addition of
trading and support personnel.
Capital expenditures for the three and six months ended June 30, 2001 include
construction costs of $11.6 million and $40.0 million, respectively, related to
the construction of the electric generating plant, which was completed in
mid-2001.
Gathering and Processing
Our Gathering and Processing segment currently has a processing capacity of 2.2
Bcf/d. The capacity associated with plants owned or leased is 1.9 Bcf/d while
the proportionate amount of the plant capacity that we own an interest in but do
not operate is 0.12 Bcf/d. Of the current total plant processing capacity, 0.14
Bcf/d is currently idle. Our gathering and processing segment owns a total of
approximately 19,700 miles of gathering pipelines, which support our gas
processing plants.
The following tables set forth certain selected financial and operating
information relating to our Gathering and Processing segment for the periods
indicated.
27
Three Months Ended Six Months Ended
June 30, June 30,
Financial Results 2002 2001 2002 2001
- -------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Natural gas liquids and condensate sales $ 149,156 $ 157,300 $ 280,505 $ 342,687
Gas sales 93,418 174,855 156,621 439,591
Gathering, compression, dehydration and processing fees
and other revenues 25,531 21,512 46,574 47,981
Cost of sales 223,546 310,587 397,818 737,954
- -------------------------------------------------------------------------------------------------------------
Net revenues 44,559 43,080 85,882 92,305
Operating costs 35,940 29,219 68,010 58,396
Depreciation, depletion, and amortization 8,591 6,995 16,561 13,806
- -------------------------------------------------------------------------------------------------------------
Operating income $ 28 $ 6,866 $ 1,311 $ 20,103
============================================================================================================
Other expense, net $ (198) $ - $ (237) $ -
============================================================================================================
Three Months Ended Six Months Ended
June 30, June 30,
Operating Information 2002 2001 2002 2001
- -------------------------------------------------------------------------------------------------------------
Total gas gathered (MMMBtu/d) 1,227 1,347 1,220 1,283
Total gas processed (MMMBtu/d) 1,464 1,432 1,411 1,322
Natural gas liquids sales (MBbls/d) 90 71 89 70
Natural gas liquids produced (MBbls/d) 75 71 70 66
Gas sales (MMMBtu/d) 337 365 341 380
Capital expenditures (Thousands) $ 14,007 $ 9,562 $ 24,815 $ 16,713
- -------------------------------------------------------------------------------------------------------------
The decrease in natural gas liquids (NGL) and condensate sales revenues for the
three months ended June 30, 2002, compared to the same period in 2001 is
primarily due to a decrease in composite NGL prices and crude oil prices. The
Conway OPIS composite NGL price decreased from $0.521 per gallon for the three
months ended June 30, 2001 to $0.393 per gallon for the same period in 2002.
These decreases are partially offset by the additional revenues generated from
the NGL pipeline facilities leased at the end of 2001 that increased our access
to different NGL markets and increased our NGL sales volumes in 2002 compared to
2001. In addition, NGL volumes produced and sold increased, and conversely gas
volumes sold decreased, because of additional gas processed and customer
elections regarding their options for processing NGL's at our Bushton facility.
Gas sales and cost of sales decreased for the three months ended June 30, 2002
compared to the same period in 2001, primarily due to decreases in natural gas
prices and volumes sold in 2002. Average natural gas price for the mid-continent
region decreased from $4.55 MMBtu for the three months ended June 30, 2001 to
$3.15 MMBtu for the same period in 2002.
Gathering, compression, dehydration and processing fees and other revenues
increased for the three months ended June 30, 2002 compared to the same period
in 2001 as certain transportation revenues that were received in the first
quarter of 2001 were received in the second quarter of 2002.
The increase in operating costs for the three months ended June 30, 2002
compared to the same period in 2001 is primarily due to increased customer
charge offs and bad debt reserves. Additionally, we experienced increased costs
for leased compression added to our existing gathering operations. We also
incurred additional costs associated with the NGL pipeline facilities leased at
the end of 2001.
28
The decrease in NGL and condensate sales revenues for the six months ended June
30, 2002, compared to the same period in 2001 is primarily due to a decrease in
composite NGL prices and crude oil prices. The Conway OPIS composite NGL price
decreased from $0.578 per gallon for the six months ended June 30, 2001 to
$0.361 per gallon for the same period in 2002. The average NYMEX crude oil price
decreased from $28.85 per barrel for the six-month period in 2001 to $22.74 per
barrel for the same period in 2002. These decreases are partially offset by the
additional revenues generated from the NGL pipeline facilities leased at the end
of 2001 that increased our access to different NGL markets and increased our NGL
sales volumes in 2002 compared to 2001. In addition, NGL volumes produced and
sold increased, and conversely gas volumes sold decreased, because of the change
in plant operations in the first quarter of 2001 due to the high value of
natural gas relative to NGL prices.
Gas sales and cost of sales decreased for the six months ended June 30, 2002
compared to the same period in 2001, primarily due to decreases in natural gas
prices. Average natural gas price for the mid-continent region decreased from
$5.79 MMBtu for the six months ended June 30, 2001 to $2.68 MMBtu for the same
period in 2002.
The decrease in net revenues for the six months ended June 30, 2002 compared to
the same period in 2001 is primarily due the decline in NGL and natural gas
prices, the relative value of NGL's compared to natural gas and the change in
plant operations as a result of market conditions. We also experienced lower net
revenues as a result of lower of cost or market adjustments associated with NGL
inventories and losses associated with Enron's non-performance on a gas sale
contract. Net revenues were also negatively impacted by the ice storm that
caused plant outages across much of Oklahoma in the first quarter of 2002.
The increases in operating costs for the six months ended June 30, 2002 compared
to the same period in 2001 are primarily due to increased bad debt expense.
Operating costs also increased as a result of additional compression we added to
our existing gathering operations and higher employee costs. We also incurred
additional costs associated with the NGL pipeline facilities leased at the end
of 2001.
Transportation and Storage
Our Transportation and Storage segment represents our intrastate natural gas
transmission pipelines and natural gas storage facilities. We have four storage
facilities in Oklahoma, two in Kansas and three in Texas, with a combined
working capacity of approximately 58 Bcf, of which 8 Bcf is idled. Our
intrastate transmission pipelines operate in Oklahoma, Kansas and Texas and are
regulated by the OCC, KCC, and Texas Railroad Commission (TRC), respectively.
The following tables set forth certain selected financial and operating
information relating to our Transportation and Storage segment for the periods
indicated.
29
Three Months Ended Six Months Ended
June 30, June 30,
Financial Results 2002 2001 2002 2001
- -------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Transportation and gathering revenues $ 27,645 $ 28,591 $ 53,796 $ 64,757
Storage revenues 9,511 11,384 17,058 21,338
Gas sales and other 5,430 7,904 20,935 14,987
Cost of fuel and gas 15,372 15,181 27,843 30,823
- -------------------------------------------------------------------------------------------------------
Net revenues 27,214 32,698 63,946 70,259
Operating costs 16,556 12,348 31,221 25,237
Depreciation, depletion, and amortization 5,471 4,751 10,045 9,501
- -------------------------------------------------------------------------------------------------------
Operating income $ 5,187 $ 15,599 $ 22,680 $ 35,521
=======================================================================================================
Other income, net $ 188 $ 849 $ 1,397 $ 8
=======================================================================================================
Three Months Ended Six Months Ended
June 30, June 30,
Operating Information 2002 2001 2002 2001
- -------------------------------------------------------------------------------------------------------
Volumes transported (MMcf) 129,036 126,940 288,679 286,785
Capital expenditures (Thousands) $ 9,741 $ 7,308 $ 24,500 $ 18,122
- -------------------------------------------------------------------------------------------------------
Transportation and gathering revenues decreased for the three months ended June
30, 2002 compared to the same period in 2001 primarily due to the decrease in
price of natural gas and its impact on the valuation of retained fuel. Storage
revenue decreased for the three months ended June 30, 2002 compared to the same
period in 2001 due to a decrease in available capacity resulting from idling
certain storage facilities in 2001. Gas sales and other revenues decreased in
the three months ended June 30, 2002 compared to the same period in 2001 due to
decreases in the price of natural gas and a reduction in sales volumes
associated to our wellhead purchases.
Cost of fuel and gas for the three-month period in 2002 compared to 2001
decreased as a result of lower natural gas prices for fuel and the reduction in
sales volumes associated with wellhead purchases. These decreases were offset by
adjustments resulting from the reconciliation of third party contractual storage
and pipeline imbalance positions.
The increase in operating costs for the three-month period in 2002 compared to
2001 is primarily due to increased customer charge offs, litigation costs and ad
valorem taxes. Additionally, other income, net was lower as a result of lower
income distributions from our partnership interests.
Transportation and gathering revenues decreased for the six months ended June
30, 2002 compared to the same period in 2001 due to the decrease in the price of
natural gas and its impact on the valuation of retained fuel. Storage revenue
decreased for the six-month period in 2002 compared to the same period in 2001
due to a decrease in available storage capacity resulting from the idling of
certain storage facilities in 2001. The increase in gas sales and other is due
to gas inventory sales in the first quarter of 2002. This increase was partially
offset by decreases in natural gas prices and sales volumes associated with our
wellhead purchases.
30
Cost of fuel and gas decreased for the six months ended June 30, 2002 compared
to the same period in 2001 due to decreases in natural gas prices for fuel and
sales volumes associated with our wellhead purchases. These decreases were
partially offset by adjustments resulting from the reconciliation of third party
contractual storage and pipeline imbalance positions. In addition, cost of fuel
and gas increased as a result of gas inventory sales in the first quarter of
2002.
The increase in operating costs for the six-month period in 2002 compared to
2001 is due primarily to increased bad debt expense, litigation costs,
regulatory fees, ad valorem taxes and employee costs. Other income, net for the
six months ended June 30, 2001 includes a $1.5 million insurance deductible
charge related to the Yaggy storage facility.
Distribution
Our Distribution segment provides natural gas distribution services in Oklahoma
and Kansas to residential, commercial and industrial customers. Our distribution
operations in Oklahoma are conducted through Oklahoma Natural Gas (ONG), which
serves residential, commercial, and industrial customers and leases gas pipeline
capacity. Our distribution operations in Kansas are conducted through Kansas Gas
Service (KGS), which serves residential, commercial, and industrial customers.
Our Distribution segment provides gas service to about 80 percent of the
population of Oklahoma and about 71 percent of the population of Kansas. ONG and
KGS are subject to regulatory oversight by the OCC and KCC, respectively.
A January 2002 order from the OCC authorized ONG to increase the level of line
loss recoveries made through the Company's line loss recovery rider. Recoveries
related to throughput delivered through the ONG system were increased from 1.0%
to 1.35% while recoveries related to throughput delivered through the ONEOK Gas
Transportation (OGT) system, which is included in our Transportation and Storage
segment, increased from 0.66% to 1.0%. All recoveries are calculated at our
weighted average cost of gas for each month. The increased recovery percentages
allow for a more timely recovery of costs incurred.
In May 2002, the KCC approved an order allowing the transfer of the MCMC
transmission pipeline assets to KGS. The operation of these assets is regulated
by the KCC. The MCMC transportation system provides access to the major natural
gas producing areas in Kansas intersecting with the nine intra/interstate
pipelines at 18 interconnect points, four processing plants, and approximately
three producing fields effectively allowing gas to be moved throughout the
state. With the transfer of these assets, KGS will be able to provide itself
with firm transportation service. The order was effective July 1, 2002. The MCMC
transmission pipeline assets will be transferred to KGS in the third quarter of
2002. At June 30, 2002, the MCMC assets are reported as part of our
Transportation and Storage segment.
A Joint Stipulation approved by the OCC on May 16, 2002, settled a number of
outstanding cases pending before the OCC. The major cases settled were the
Commission's inquiry into our gas cost procurement practices during the winter
of 2000/2001; an application seeking relief from improper and excessive
purchased gas costs; and enforcement action against us, our subsidiaries and
affiliated companies of ONG. In addition, all of the open inquiries related to
the annual audits of ONG's fuel adjustment clause for 1996 to 2000 were closed
as a result of this Stipulation.
31
The Stipulation has a $33.7 million value to ONG customers that will be realized
over a three-year period. In July 2002, immediate cash savings were provided to
all ONG customers in the form of billing credits totaling approximately $10.1
million. ONG is replacing certain gas contracts, which is expected to reduce gas
costs by approximately $13.8 million, due to avoided reservation fees between
April 2003 and October 2005. Additional savings of approximately $8.0 million
from the use of storage gas are expected to occur between November 2003 and
March 2005. Any expected savings from the use of storage that are not achieved
and a $1.8 million credit will be added to the final billing credit scheduled to
be provided to customers in December 2005. ONG operating income increased in the
second quarter of 2002 compared to 2001 by $14.2 million as a result of this
settlement.
The following table sets forth certain selected financial information relating
to our Distribution segment for the periods indicated.
Three Months Ended Six Months Ended
June 30, June 30,
Financial Results 2002 2001 2002 2001
- ---------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Gas sales $ 194,492 $ 210,867 $ 669,129 $ 948,583
Cost of gas 121,319 153,533 482,453 774,669
- ---------------------------------------------------------------------------------------------------
Gross margin 73,173 57,334 186,676 173,914
PCL and ECT Revenues 12,446 10,652 30,250 28,782
Other revenues 5,825 4,304 12,513 10,366
- ---------------------------------------------------------------------------------------------------
Net revenues 91,444 72,290 229,439 213,062
Operating costs 54,745 61,629 117,630 119,694
Depreciation, depletion, and amortization 19,575 17,159 36,524 34,136
- ---------------------------------------------------------------------------------------------------
Operating income (loss) $ 17,124 $ (6,498) $ 75,285 $ 59,232
===================================================================================================
Other expense, net $ (585) $ - $ (921) $ -
===================================================================================================
The decrease in gas sales and cost of gas for the three and six months ended
June 30, 2002 compared to the same periods in 2001 is primarily attributable to
decreased gas costs resulting from lower market prices. Additional gas cost
reductions of approximately $14.2 million for the three and six months ended
June 30, 2002 resulted from the OCC Stipulation. Warmer than normal weather
during the first quarter of 2002 also contributed to the decrease for the six
months ended June 30, 2002. We experienced higher gas sales in the first quarter
of 2001 due to colder than normal weather and high gas costs, which resulted in
higher gas sales and cost of gas for the six months ended June 30, 2001.
Operating costs were down for the three and six months ended June 30, 2002
compared to the same periods in 2001 due primarily to reduced bad debt expense.
Bad debt expense decreased $5.3 million and $7.5 million for the three and six
months, respectively. The reduced bad debt expense was partially offset by
increased employee costs. Unprecedented levels of high gas prices in the first
quarter of 2001 resulted in increased bad debt expense during the three and six
months ended June 30, 2001.
32
The following tables set forth certain operating information relating to our
Distribution segment for the periods indicated.
Three Months Ended Six Months Ended
June 30, June 30,
Gross Margin per Mcf 2002 2001 2002 2001
- -------------------------------------------------------------------------------
Oklahoma
Residential $4.43 $4.87 $2.43 $2.51
Commercial $2.95 $2.76 $2.29 $2.05
Industrial $2.57 $1.89 $1.64 $1.22
Pipeline capacity leases $0.30 $0.30 $0.29 $0.30
Kansas
Residential $4.45 $5.07 $2.13 $2.06
Commercial $2.80 $3.28 $1.70 $1.60
Industrial $1.10 $1.53 $1.32 $1.44
Wholesale $0.14 $0.08 $0.12 $0.13
End-use customer transportation $0.49 $0.51 $0.61 $0.65
- -------------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30, June 30,
Volumes (MMcf) 2002 2001 2002 2001
- ------------------------------------------------------------------------------
Gas sales
Residential 12,311 10,658 63,224 64,430
Commercial 4,474 4,388 21,707 25,257
Industrial 335 518 1,812 2,469
Wholesale 9,047 6,440 14,516 7,758
- ------------------------------------------------------------------------------
Total volumes sold 26,167 22,004 101,259 99,914
PCL and ECT 34,047 29,344 76,654 68,775
- ------------------------------------------------------------------------------
Total volumes delivered 60,214 51,348 177,913 168,689
==============================================================================
Residential gross margin per Mcf for our Oklahoma customers decreased for the
three months ended June 30, 2002 compared to the same period in 2001 due to
increased volumes in Oklahoma which resulted in customer-based fixed fees being
spread over greater volumes. Commercial and industrial gross margins per Mcf for
Oklahoma customers increased due to reduced volumes, which resulted in
customer-based fixed fees being spread over fewer volumes.
Kansas residential, commercial and industrial gross margin per Mcf decreased for
the three months ended June 30, 2002 compared to the same period in 2001 due to
weather normalization. The Kansas weather normalization program adjusts revenues
for residential and commercial customers each month to reflect the variance with
normal weather based on a measurement of heating degree days made by stations
throughout the Kansas territory. Weather for the three months ended June 30,
2002 was closer to normal while the same period of 2001 was warmer than normal.
The gross margin per Mcf for residential and commercial customers was higher for
the six months ended June 30, 2002 compared to the same period in 2001 due to
increased weather normalization revenues.
33
Kansas wholesale sales, also known as "as available" gas sales, represent gas
volumes available under contracts that exceed the needs of our residential and
commercial customer base and are available for sale to other parties. The
increase in wholesale sales margins for the three months ended June 30, 2002,
primarily relates to higher gas prices. Wholesale sales volumes increased during
the three and six months ended June 30, 2002, compared to the same periods of
2001 as fewer volumes were required to meet the needs of the residential,
commercial, and industrial customers due to warmer weather, thus allowing more
gas sales to wholesale customers. End-use customer transportation (ECT) margins
decreased for the three and six months ended June 30, 2002 compared to the same
periods in 2001 due to an increase in volumes sold to lower margin large
industrial customers not using fuel oil in 2002 and additional volumes sold to
irrigation customers.
The following table sets forth certain selected operating information relating
to our Distribution segment for the periods indicated.
Three Months Ended Six Months Ended
June 30, June 30,
Operating Information 2002 2001 2002 2001
- -----------------------------------------------------------------------------------------------
Average Number of Customers 1,440,844 1,468,896 1,445,677 1,473,315
Customers per employee 620 605 598 594
Capital expenditures (Thousands) $ 32,403 $ 30,216 $ 53,524 $ 57,394
- -----------------------------------------------------------------------------------------------
Certain costs to be recovered through the ratemaking 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".
Total regulatory assets resulting from this deferral process for our
Distribution segment were approximately $228.6 million at June 30, 2002. Should
unbundling of our gas services occur, 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. We do not anticipate that such a
write-off of costs, if any, will be material.
Production
Our Production segment owns, develops and produces natural gas and oil reserves
primarily in Oklahoma, Kansas and Texas. Our strategy is to add value not only
to our existing oil and gas production operations, but also to the related
marketing, gathering, processing, transportation and storage businesses.
Accordingly, we focus on exploitation activities rather than exploratory
drilling.
The following tables set forth certain financial and operating information
relating to our Production segment for the periods indicated.
34
Three Months Ended Six Months Ended
June 30, June 30,
Financial Results 2002 2001 2002 2001
- ---------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Natural gas sales $ 20,340 $ 32,188 $ 37,735 $ 58,741
Oil sales 3,111 2,787 5,256 5,440
Other revenues 940 49 1,057 129
- ---------------------------------------------------------------------------------------------------------
Net revenues 24,391 35,024 44,048 64,310
Operating costs 7,809 7,149 15,104 14,954
Depreciation, depletion, and amortization 9,483 8,159 18,657 15,744
- ---------------------------------------------------------------------------------------------------------
Operating income $ 7,099 $ 19,716 $ 10,287 $ 33,612
=========================================================================================================
Other income (expense), net $ (130) $ 776 $ (88) $ 1,178
=========================================================================================================
Cumulative effect of change in accounting principle,
before tax $ - $ - $ - $ (3,508)
=========================================================================================================
Three Months Ended Six Months Ended
June 30, June 30,
Operating Information 2002 2001 2002 2001
- ---------------------------------------------------------------------------------------------------------
Proved reserves
Gas (MMcf) - - 238,528 250,403
Oil (MBbls) - - 4,724 4,299
Production
Gas (MMcf) 6,206 6,528 12,565 12,650
Oil (MBbls) 114 106 236 201
Average realized price (a)
Gas (Mcf) $ 3.28 $ 4.93 $ 3.00 $ 4.64
Oil (Bbls) $ 27.29 $ 26.29 $ 22.27 $ 27.06
Capital expenditures (Thousands) $ 11,349 $ 14,959 $ 22,971 $ 26,220
- ---------------------------------------------------------------------------------------------------------
(a) Average realized price reflects the impact of hedging activities.
Natural gas sales decreased for the three and six months ended June 30, 2002,
compared to the same periods in 2001, due to the decrease in gas prices. The gas
volumes produced for the three months ended June 30, 2002 compared to the same
period in 2001 decreased due to normal production declines. Sales for the six
months ended June 30, 2002, includes a recovery of $2.7 million related to the
sale of our Enron claim on hedging contracts. At June 30, 2002 approximately 61%
of our remaining anticipated 2002 natural gas production is hedged at an average
wellhead price of $3.51/Mcf.
The increase in oil sales for the three-month period ended June 30, 2002,
compared to the same period in 2001, is due to both increased production volumes
of oil and an increase in the average realized sales price resulting from higher
market prices.
Operating costs increased for the three and six months ended June 30, 2002
compared to the same periods in 2001 due to additional employee costs as well as
higher workover costs and lower overhead recovery from producing wells. The
lower overhead recovery relates to a decrease in the allowable rate of recovery
set by the Council of Petroleum Accounting Societies (COPAS). The increased
costs were partially offset by lower production taxes resulting from lower
natural gas and oil prices. Production taxes are calculated based on wellhead
prices rather than realized prices. The increase in depreciation, depletion, and
amortization for the three and six months ended June 30, 2002 compared to the
same periods in 2001 is due to a higher rate per unit of production, caused by
higher capital costs incurred in the last twelve months.
35
Our Production segment added 21.1 Bcfe of net reserves for the six months ended
June 30, 2002 after adjustments, including 14.1 Bcfe proved developed, 2.0 Bcfe
proved behind pipe, and 5.0 Bcfe proved undeveloped.
Financial Flexibility and Liquidity
Liquidity and Capital Resources
A part of our strategy has been and continues to be growth through acquisitions
that strengthen and complement our existing assets. We have relied primarily on
a combination of operating cash flow and borrowings from a combination of
commercial paper, bank lines of credit, and capital markets for our liquidity
and capital resource requirements. We expect to continue to use these sources
for liquidity and capital resource needs on both a short and long-term basis.
During 2001 and the first six months of 2002, our capital expenditures were
financed through operating cash flows and short and long-term debt.
Financing is provided through our commercial paper program, long-term debt and,
if needed, through a revolving credit facility. Other options to obtain
financing include, but are not limited to, issuance of equity, asset
securitization and sale/leaseback of facilities. We currently have a $500
million shelf registration in effect covering debt securities (including
convertible debt) and common stock.
On August 5, 2002, the Company launched a tender offer to purchase with cash all
the outstanding 8.44% Senior Notes due 2004 and the 8.32% Senior Notes due 2007
for a total purchase price of approximately $69 million. The total purchase
price includes a premium of approximately $5 million to purchase the notes. The
offer expires August 20, 2002. The Company will recognize the transaction in the
third quarter of 2002. See Note K of Notes to Consolidated Financial Statements.
Our credit rating is currently A2 under review for possible downgrade by Moody's
and A by Standard and Poors. Our credit rating may be affected by a material
change in our financial ratios or a material adverse event affecting our
business. The most common criteria for assessment of our credit rating are the
debt to capital ratio, pre-tax and after-tax interest coverage and liquidity. If
our credit rating were downgraded, the interest rates on our commercial paper
would increase resulting in an increase in our cost to borrow funds. In the
event that we are unable to borrow funds under our commercial paper program and
there has not been a material adverse change in our business, we have access to
an $850 million revolving credit facility. In June 2002, we entered into a
90-day extension of the revolving credit facility, which expires September 30,
2002 and which we expect to renew on or prior to the present maturity date. In
addition, downgrades in our credit rating could impact our Marketing and Trading
segment's ability to do business by requiring the Company to post margins with
the few counterparties with which we have a Credit Support Annex within our
International Swaps and Derivatives Association Agreement. For further
discussion of rating triggers, see the Liquidity and Capital Resources section
of our Annual Report on Form 10-K for the year ended December 31, 2001.
Our energy marketing and trading business relies upon the investment grade
rating of our senior unsecured long-term debt to satisfy credit support
requirements with several counterparties. If our credit ratings were to decline
below investment grade, our ability to participate in energy marketing and
trading activity could be significantly limited. Without an investment grade
rating, we would be required to fund margin requirements under industry standard
derivative agreements
36
with cash, letters of credit or other negotiable instruments. At June 30, 2002,
the total notional amounts that could require such funding in the event of a
credit rating decline to below investment grade is approximately $65 million.
We are subject to commodity price volatility. Significant fluctuations in
commodity price in either physical or financial energy contracts may impact our
overall liquidity due to the impact the commodity price change has on items such
as the cost of gas held in storage, recoverability and timing of recovery of
regulated natural gas costs, increased margin requirements, collectibility of
certain energy related receivables and working capital. We believe that our
current commercial paper program and debt capacity are adequate to meet our
liquidity requirements associated with commodity price volatility.
Westar Energy Sale Notice. Westar Energy, Inc. (formerly known as Western
Resources, Inc.) and its affiliates beneficially own approximately 42.5% of our
outstanding common stock after giving effect to the conversion of the
outstanding shares of our Series A convertible preferred stock held by an
affiliate of Westar. On May 30, 2002, pursuant to our shareholder agreement with
Westar, Westar notified us that it intends to dispose of all of the shares of
our stock that it beneficially owns, which include 4,714,434 shares of our
common stock and 19,946,448 shares of our Series A convertible preferred stock
that are convertible into 39,892,896 shares of our common stock at Westar's
option, subject to certain conditions. Under the shareholder agreement, we have
a period of 90 days after the date that Westar notified us of its intention to
dispose of our shares and 30 days from the date of receipt of all necessary
regulatory approvals, but in no event more than 180 days from the date of the
sale notice, within which to effect the purchase of all, but not less than all,
of the shares specified in the notice at a price of $21.77 per share, for a
total purchase price of approximately $971.1 million. Assuming that all
regulatory approvals have been received, we believe that our right to repurchase
the shares expires on August 28, 2002. If we do not elect to purchase the shares
specified in Westar's notice to us or agree to provide Westar with price
protection in accordance with the shareholder agreement, Westar would have 16
months from May 30, 2002 to dispose of those shares in accordance with the terms
and conditions of the shareholder agreement.
Our Board of Directors has formed a special committee, consisting of all
directors other than the two members of the Board designated by Westar, to
consider, review and evaluate the potential actions we may take in response to
the Westar sale notice and to make recommendations with respect to those
potential actions to our full Board of Directors. The special committee is
currently evaluating our alternatives with respect to the possible repurchase of
our stock owned by Westar. We cannot assure you that we will elect to purchase
the shares. If we were to elect to purchase the shares, we would need to secure
additional financing to complete the purchase. Financing may not be available on
acceptable terms or at all. Any such financing could involve the incurrence of a
significant amount of debt, which would substantially increase our leverage and
may adversely effect our creditworthiness. In addition, any such financing,
whether debt or otherwise, could contain covenants that restrict our operations
or lead to a reduction in our credit ratings or an increase in our cost of
capital and reduction in availability of capital, any of which could have a
material adverse effect on our business, financial condition, results of
operations and cash flows. We also may seek to finance a portion of the purchase
with the proceeds generated through other financing transactions. There can be
no assurance that we will be able to effect any such financing transactions on
acceptable terms or at all. In addition, any election to purchase our shares
from Westar would affect our ability to effect future financings, to make
capital expenditures or acquisitions and to take advantage of other significant
business opportunities that may arise, and may otherwise restrict corporate
activities.
37
Enron. Enron North America is the counterparty in certain of the financial
instruments discussed in our Annual Report on Form 10-K for the year-ended
December 31, 2001. Enron Corporation and various subsidiaries, including Enron
North America (Enron), filed for protection from creditors under Chapter 11 of
the United States Bankruptcy Code on December 3, 2001. In 2001, we took a charge
of $37.4 million to provide an allowance for forward financial positions and to
establish an allowance for uncollectible accounts related to previously settled
financial and physical positions with Enron. In the first quarter of 2002, we
recorded a recovery of approximately $14.0 million as a result of an agreement
to sell our Enron claim to a third party, which is subject to normal
representations as to the validity of the claims and the guarantees from Enron.
The filing of the voluntary bankruptcy proceeding by Enron created a possible
technical default related to various financing leases tied to our Bushton gas
processing plant in south central Kansas. We acquired the Bushton gas processing
plant and related leases from Kinder Morgan, Inc. (KMI) in April 2000. KMI had
previously acquired the plant and leases from Enron. Enron is one of three
guarantors of the Bushton plant lease. We are the primary guarantor. In January
2002, we were granted a waiver on the possible technical default related to
these leases. We will continue to make all payments due under these leases.
Oklahoma Corporation Commission. The OCC staff filed an application on February
1, 2001 to review the gas procurement practices of our ONG division in acquiring
its gas supply for the 2000/2001 heating season to determine if these
procurement practices were consistent with least cost procurement practices and
whether ONG's decisions resulted in fair, just and reasonable costs to its
customers. On November 20, 2001, the OCC entered an order stating that ONG not
be allowed to recover the balance in ONG's unrecovered purchased gas cost (UPGC)
account related to the unrecovered gas costs from the 2000/2001 winter effective
with the first billing cycle for the month following the issuance of a final
order. This order halted ONG's recovery process effective December 1, 2001. On
December 12, 2001, the OCC approved a request to stay the order and allowed ONG
to begin collecting unrecovered gas costs, subject to refund should ONG
ultimately lose the case. In the fourth quarter of 2001, we took a charge of
$34.6 million as a result of this OCC order. In April 2002, we, along with the
staff of the Public Utility Division and the Consumer Services Division of the
OCC, the Oklahoma Attorney General, and other stipulating parties filed a joint
agreement proposing settlement of this and other issues. A hearing with the OCC
was held in May 2002 and an order approving the settlement was issued at that
time. As a result, we recorded a $14.2 million recovery in the second quarter of
2002 and have the potential of an additional $8.0 recovery before December 2005
depending upon the potential value that could be generated by gas storage
savings.
Cash Flow Analysis
Operating Cash Flows. Operating cash flows for the six months ended June 30,
2002, were $585.8 million compared to $254.3 million for the same period one
year ago. The changes in operating cash flows primarily reflect changes in
working capital accounts, mark-to-market income, deferred income taxes and price
risk management assets and liabilities. Operating cash flows were positively
impacted in the six months ended June 30, 2002 due to the collection of accounts
receivable and reduced deposits. Receivables decreased for the six-month period
due to the decrease in energy prices and receivables are typically higher during
the heating season resulting in increased cash receipts in the first six months
of the year. A reduction in restricted deposits for the Marketing and Trading
segment is due to increased purchases of option contracts during the six months
ended June 30, 2002. The decrease in inventories during the six months ended
June 30, 2002 is partially due to the decrease in natural gas prices for the
six-month period.
38
In addition, inventories are typically higher at December 31 and are used
throughout the remainder of the winter. The change in inventories excludes the
change in the Marketing and Trading segment's gas in storage, which is included
in price risk management assets. The change in unrecovered purchased gas costs
is due to the recovery of outstanding receivables from the 2000/2001 winter.
For the six months ended June 30, 2001, the changes in cash flow provided by
operating activities are primarily due to the higher gas prices. Accounts
receivable and accounts payable are typically higher during the heating season.
However, they were higher than normal at December 31, 2000 due to the higher gas
prices and integration of the businesses we acquired in 2000. The increase in
inventories during the six months ended June 30, 2001 is a result of increased
volumes in storage as well as higher gas prices as we focused on
opportunistically securing volumes that are then hedged at favorable
winter/summer spreads.
Investing Cash Flows. Cash paid for capital expenditures for the six months
ended June 30, 2002 was $133.9 million. For the same period in 2001, capital
expenditures were $174.0 million, which included $40.0 million for the
construction of our electric generating plant that was completed in the second
quarter of 2001. Acquisitions were $3.5 million and $15.3 million for the six
months ended June 30, 2002 and 2001, respectively.
Financing Cash Flows. Our capitalization structure is 47 percent equity and 53
percent long-term debt at June 30, 2002, compared to 42 percent equity and 58
percent long-term debt at December 31, 2001. At June 30, 2002, we had $1.5
billion of long-term debt outstanding. As of that date, we could have issued
$1.1 billion of additional long-term debt under the most restrictive provisions
contained in our various borrowing agreements.
Our $850 million revolving credit facility is primarily used to support our
commercial paper program. At June 30, 2002, $351.1 million of commercial paper
was outstanding, which includes approximately $43.7 million in temporary
investments.
Impact of Recently Issued Accounting Pronouncements
In July 2001, the FASB issued Statement of Financial Accounting Standards No.
143, "Accounting for Asset Retirement Obligations" (Statement 143). Statement
143 requires entities to record the fair value of a liability for an asset
retirement obligation in the period in which it is incurred and a corresponding
increase in the carrying amount of the related long-lived asset. Statement 143
is effective for fiscal years beginning after June 15, 2002. We are currently
assessing the impact of Statement 143 on our financial condition and results of
operations.
In April 2002, the FASB issued Statement of Financial Accounting Standards No.
145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB
Statement No. 13 and Technical Corrections" (Statement 145). Statement 145
rescinds FASB Statement No. 4, "Reporting Gains and Losses from Extinguishment
of Debt" (Statement 4), and an amendment to that Statement, FASB Statement No.
64 "Extinguishment of Debt Made to Satisfy Sinking-Fund Requirements" (Statement
64). Statement 145 also rescinds FASB Statement No. 13, "Accounting for Leases"
(Statement 13) to eliminate the inconsistency between the required accounting
for sale-leaseback transactions and the required accounting for certain lease
modifications that have economic effects that are similar to sale-leaseback
transactions. Statement 145 also amends other existing authoritative
pronouncements to make various technical corrections, clarify meanings or
describe their applicability under changed conditions. The provisions of
Statement 145 related to the rescission of Statement 4 are effective for fiscal
39
years beginning after May 15, 2002. If our tender offer to purchase our 8.44%
Senior Notes due 2004 and 8.32% Senior Notes due 2007 is successful, we will
record a charge in the third quarter of 2002 in accordance with Statement 145
related to the extinguishment of this debt. See Note K of the Notes to the
Consolidated Financial Statements. The provisions of Statement 145 related to
Statement 13 are effective prospectively for transactions occurring after May
15, 2002. All other provisions of Statement 145 are effective prospectively for
financial statements issued on or after May 15, 2002.
In July 2002, the FASB issued Statement of Financial Accounting Standards No.
146, "Accounting for Restructuring Costs" (Statement 146). Under Statement 146,
a company will record a liability for a cost associated with an exit or disposal
activity when that liability is incurred and can be measured at fair value.
Statement 146 also provides guidance on accounting for specified employee and
contract terminations that are part of restructuring activities. Statement 146
is effective prospectively for exit or disposal activities initiated after
December 31, 2002.
In July 2002, the Emerging Issues Task Force (EITF) issued EITF Issues No. 02-3,
"Recognition and Reporting Gains and Losses on Energy Trading Contracts under
EITF Issues No. 98-10, "Accounting for Contracts Involved in Energy Trading and
Risk Management Activities," and No. 00-17, "Measuring the Fair Value of
Energy-Related Contracts in Applying Issue No. 98-10" (EITF 02-3). EITF 02-3
provides that all mark-to-market gains and losses on energy trading contracts
should be shown net in the income statement whether or not settled physically.
An entity should disclose the gross transaction volumes for those energy trading
contracts that are physically settled. These provisions of EITF 02-3 are
effective for interim and annual financial statements issued for periods ending
after July 15, 2002. Our adoption of this provision will have a material impact
on the presentation of our operating revenues and cost of gas as a result of
presenting our energy trading activities net in the income statement. This
income statement presentation change will not affect net income. In addition,
under EITF 02-3 entities involved in energy trading activities are required to
disclose all of the following: (1) the applicability of EITF 98-10; (2) the
types of contracts that are accounted for as energy trading contracts; (3) the
fair values of its energy trading contracts, aggregated by source or method of
estimating fair value and by maturity dates of contracts; (4) a description of
the methods and significant assumptions used to estimate fair value of its
various classes of energy trading contracts; (5) a reconciliation of the
beginning and ending carrying values for similarly aggregated trading contracts;
and (6) the sensitivity of its estimates to changes in the near term. These
disclosure provisions of EITF 02-3 are effective for financial statements issued
for fiscal years ending after July 15, 2002. Also, EITF 02-3 discusses whether
recognition of unrealized gains and losses at inception of energy trading
contracts is appropriate in the absence of quoted market prices or current
market transactions for contracts with similar terms. The EITF has not reached a
consensus on this issue. Resolutions of this issue may have a material impact on
the application of mark-to-market accounting for energy trading contracts.
Other
Southwest Gas Corporation. Information related to the termination of our
proposed acquisition of Southwest Gas Corporation is presented in Note E in the
Notes to the Consolidated Financial Statements and Part II, Item 1 of this Form
10-Q.
40
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Risk Management. We are, substantially through our nonutility segments, exposed
to market risk in the normal course of our business operations and to the impact
of market fluctuations in the price of natural gas, NGLs, crude oil and power
prices. Market risk refers to the risk of loss in cash flows and future earnings
arising from adverse changes in commodity energy prices. Our primary exposure
arises from fixed price purchase or sale agreements that extend for periods of
up to 48 months, gas in storage utilized by the marketing and trading operation,
and anticipated sales of natural gas and oil production. To a lesser extent, we
are exposed to risk of changing prices or the cost of intervening transportation
resulting from purchasing gas at one location and selling it at another
(referred to as basis risk). To minimize the risk from market fluctuations in
the price of natural gas, NGLs and crude oil, we use commodity derivative
instruments such as futures contracts, swaps and options to manage market risk
of existing or anticipated purchase and sale agreements, existing physical gas
in storage, and basis risk. We adhere to policies and procedures that limit our
exposure to market risk from open positions and that monitor market risk
exposure.
KGS uses derivative instruments to hedge the cost of anticipated gas purchases
during the winter heating months to protect KGS customers from upward volatility
in the market price of natural gas. At June 30, 2002, KGS had derivative
instruments in place to hedge the cost of purchases for 99.8 Bcf of gas. This
represents all of KGS gas purchase requirements for the winter heating months
based on normal weather conditions.
The following is a detail of the Marketing and Trading segment's maturity of
energy trading contracts based on heating injection and withdrawal periods from
April through March. This maturity schedule is consistent with the Marketing and
Trading segment's trading strategy. The Marketing and Trading segment has
contracted approximately 40 Bcf of storage with an affiliate, which is excluded
from outstanding fair value at June 30, 2002 in accordance with generally
accepted accounting principles.
Fair Value of Contracts at June 30, 2002
-----------------------------------------------------------------
Matures Matures Matures Matures Total
through through through after fair
Source of Fair Value (1) March 2003 March 2006 March 2008 March 2008 value
- ----------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Prices actively quoted (2) $ 23,328 $ 313 $ - $ - $ 23,641
Prices provided by other external sources (3) $ (32,295) 1,958 (2,934) (2,693) $ (35,964)
Prices based on models and other
valuation models (4) $ 74,534 42,547 10,150 (2,881) $ 124,350
- ---------------------------------------------------------------------------------------------------------------
Total $ 65,567 $ 44,818 $ 7,216 $ (5,574) $ 112,027
===============================================================================================================
(1) Fair value is the mark-to-market component of forwards, swaps,
option, and energy transportation and storage contracts, net of
applicable reserves utilized for trading activities. These fair
values are reflected as a component of assets and liabilities from
price risk management activities in the consolidated balance
sheets.
(2) Values are derived from energy market price quotes from national
commodity trading exchanges that primarily trade future and option
commodity contracts.
(3) Values are obtained through energy commodity brokers or electronic
trading platforms, whose primary service is to match willing
buyers and sellers of energy commodities.
41
Because of the large energy broker network, energy price
information by location is readily available.
(4) Values include primarily natural gas storage and transportation
capacity. Values derived in this category utilize market price
information from the two other categories as well as other
modeling assumptions that include, among others, assumptions for
liquidity, credit, time value and other external attributes.
Values attributable to storage models are determined on a heating
injection/withdraw model.
For further discussion of trading activities and models and assumptions used in
our trading activities, see the Critical Accounting Policies in Notes A and H of
Notes to Consolidated Financial Statements.
Interest Rate Risk. We are subject to the risk of fluctuation in interest rates
in the normal course of business. We manage interest rate risk through the use
of fixed rate debt, floating rate debt and, at times, interest rate swaps. Fixed
rate swaps are used to reduce our risk of increased interest costs during
periods of rising interest rates. Floating rate swaps are used to convert the
fixed rates of long-term borrowings into short-term variable rates.
At June 30, 2002, the interest rate on 49 percent of our debt was fixed. In July
2001, we entered into interest rate swaps on a total of $400 million in fixed
rate long-term debt. The interest rate under these swaps resets periodically
based on the three-month LIBOR or the six-month LIBOR at the reset date. In
October 2001, we entered into an agreement to lock in the interest rates for
each reset period under the swap agreements through the first quarter of 2003.
In December 2001, we entered into additional interest rate swaps on a total of
$200 million in fixed rate long-term debt. In June 2002, we recorded a $30.7
million net increase in price risk management assets to recognize at fair value
our derivatives that are designated as fair value hedging instruments. Long-term
debt was increased by approximately $29.3 million to recognize the change in
fair value of the related hedged liability. We also increased interest expense
by $0.8 million for the three months ended June 30, 2002 to recognize the
ineffectiveness caused by locking the LIBOR settings into future periods.
A 100 basis point move in the annual interest rate would change our annual
interest expense by $5.5 million before taxes. This amount is limited based on
the LIBOR locks, which we have in place through the first quarter of 2003. If
these locks were not in place, a 100 basis point change in the interest rates
would affect our annual interest expense by $9.5 million before taxes. This 100
basis point change assumes a parallel shift in the yield curve. If interest
rates changed significantly, we would take actions to manage our exposure to the
change. Since a specific action and the possible effects are uncertain, no
change has been assumed.
Value-at-Risk Disclosure of Market Risk. We measure entity-wide market risk in
our trading, price risk management, and our non-trading portfolios using
value-at-risk (VAR). Our VAR calculations are based on the Risk Works Monte
Carlo approach, assuming a one-day holding period. The quantification of market
risk using VAR provides a consistent measure of risk across diverse energy
markets and products with different risk factors in order to set overall risk
tolerance, to determine risk targets and set position limits. The use of this
methodology requires a number of key assumptions, including the selection of a
confidence level and the holding period to liquidation. Inputs to the
calculation include prices, positions, instrument valuations and the
variance-co-variance matrix. Historical data is used to estimate our VAR with
more weight given to recent data, which is considered a more relevant predictor
of immediate future commodity market movements. We rely on VAR to determine the
potential reduction in the trading and price risk management portfolio values
arising from changes in market conditions over a defined
42
period. While management believes that the referenced assumptions and
approximations are reasonable, no uniform industry methodology exists for
estimating VAR and different assumptions and approximations could produce
materially different VAR estimates.
Our VAR exposure represents an estimate of potential losses that would be
recognized for our trading and price risk management portfolio of derivative
financial instruments, physical contracts and gas in storage due to adverse
market movements over a defined time horizon within a specified confidence
level. A one-day time horizon and a 95 percent confidence level were used in our
VAR data. Actual future gains and losses will differ from those estimated by the
VAR calculation based on actual fluctuations in commodity prices, operating
exposures and timing thereof, and the changes in the Company's trading and price
risk management portfolio of derivative financial instruments and physical
contracts. VAR information should be evaluated in light of this information and
the methodology's other limitations.
The potential impact on our future earnings, as measured by the VAR, was $2.0
million and $3.5 million at June 30, 2002 and 2001, respectively. The following
table details the average, high and low VAR calculations:
Three Months Ended Six Months Ended
June 30, June 30,
Value at Risk 2002 2001 2002 2001
----------------------------------------------------------------------
(Millions of dollars)
Average $ 5.0 $ 2.7 $ 5.7 $ 3.2
High $ 11.1 $ 5.1 $ 17.8 $ 8.8
Low $ 1.9 $ 1.0 $ 1.9 $ 1.0
----------------------------------------------------------------------
The variations in the VAR data are reflective of our marketing and trading
growth and market volatility during the quarter.
Risk Policy and Oversight. We control the scope of risk management, marketing
and trading operations through a comprehensive set of policies and procedures
involving senior levels of management. Our Board of Directors affirms the risk
limit parameters with our audit committee having oversight responsibilities for
the policies. A risk oversight committee, comprised of corporate and business
segment officers, oversees all activities related to commodity price, credit and
interest rate risk management, marketing and trading activities. The committee
also proposes risk metrics, including VAR and position loss limits. We have a
corporate risk control organization led by our Vice-President of Risk Control,
which is assigned responsibility for establishing and enforcing the policies,
procedures and limits and evaluating the risks inherent in proposed
transactions. Key risk control activities include credit review and approval,
credit and performance risk measurement and monitoring, validation of
transactions, portfolio valuation, VAR and other risk metrics.
To the extent open commodity positions exist, fluctuating commodity prices can
impact our financial results and financial position either favorably or
unfavorably. As a result, we cannot predict with precision the impact risk
management decisions may have on our business, operating results or financial
position.
43
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
Will Price, et al. v. Gas Pipelines, et al. (f/k/a Quinque Operating Company, et
al. v. Gas Pipelines, et al.), 26th Judicial District, Stevens County, Kansas,
Civil Department, Case No. 99C30. The name of this case has been changed due to
substitution of plaintiffs. On February 25, 2002, the court entered an order
allowing supplemental briefing on the pending motion to dismiss and further
extending the dates for briefing on personal jurisdiction and class
certification issues. Supplemental briefing has been completed and we are
awaiting the court's decision on the motion to dismiss on the pleadings.
Briefing on motions to dismiss for lack of personal jurisdiction was completed
on August 9, 2002 and a hearing on those motions is scheduled for August 29,
2002.
Cause PUD 01-57, Oklahoma Corporation Commission. On May 16, 2002, the OCC
approved a settlement of this case and Cause No. PUD 980000188, which provides
for an aggregate value of $33,750,000 over a 3-year period to ONG customers. The
settlement includes a July 2002 billing credit of $10.1 million to ONG sales
customers who were receiving service in December 2001, an aggregate $21.8
million in customer savings from replacing certain existing load following
service with storage service, and a final credit to ONG customers of
approximately $1.8 million in December 2005 (subject to final true up). Under
the settlement, ONG's appeal to the Oklahoma Supreme Court from the OCC order
was dismissed on July 15, 2002.
Southern Union Company v. Southwest Gas Corporation, et al., No.
CIV-99-1294-PHX-ROS, United States District Court for the District of Arizona.
On June 10, 2002, we filed a motion for summary judgment against Southern Union
as to Southern Union's sole remaining claim for tortious interference with a
prospective relationship, and also moved for summary judgment on Southern
Union's claim for punitive damages. Eugene Dubay and John A. Gaberino, Jr.,
executive officers, joined in that motion. On August 6, 2002, Southwest and
Southern Union settled their claims against each other for the payment of $17.5
million by Southwest to Southern Union. The Court has dismissed the claims
between Southern Union and Southwest, including claims asserted against some
Southwest officers, from the case. Trial on the remaining claims asserted by
Southern Union against us is scheduled to begin October 15, 2002.
ONEOK Inc. v. Southwest Gas Corporation, No. 00-CV-063-H(E), United States
District Court for the Northern District of Oklahoma, transferred, No.
00-1775-PHX-ROS, United States District Court for the District of Arizona; and
Southwest Gas Corporation v. ONEOK, Inc., No. CIV-00-0119-PHX-ROS, United States
District Court for the District of Arizona. On August 9, 2002, we settled with
Southwest all claims asserted against each other in these cases in consideration
for a payment of $3,000,000 to be paid by us to Southwest.
In the Matter of the Natural Gas Explosion at Hutchinson, Kansas during January,
2001, Case No. 02-E-0155, before the Secretary of the Department of Health and
Environment. On July 23, 2002 the Division of Environment of the Kansas
Department of Health and Environment (KDHE) issued an Administrative Order which
assesses a $180,000 civil penalty against our Kansas Gas Service division. The
penalty is based upon allegations of violations of various KDHE regulations
relating to our operation of hydrocarbon storage wells, monitoring requirements
applicable to stored hydrocarbon products, and spill reporting in connection
with
44
the gas explosions at our Yaggy gas storage facility in Hutchinson, Kansas in
January 2001. In addition, the Order requires us to monitor existing unplugged
vent wells, drill additional observation, monitoring and vent wells as directed
by the KDHE, perform cleanup activities relating to certain brine wells, and
prepare a geoengineering plan with respect to the Yaggy gas field. We are
currently evaluating the order and our response, including our appeal rights.
Loyd Smith, et al v. Kansas Gas Service Company, Inc., ONEOK, Inc., Western
Resources, Inc., Mid Continent Market Center, Inc., ONEOK Gas Storage, L.L.C.,
ONEOK Gas Storage Holdings, Inc., and ONEOK Gas Transportation, L.L.C., Case No.
01-C-0029, in the District Court of Reno County, Kansas, and Gilley, et al. v.
Kansas Gas Service Company, Western Resources, Inc., ONEOK, Inc., ONEOK Gas
Storage, L.L.C., ONEOK Gas Storage Holdings, Inc., ONEOK Gas Transportation,
L.L.C., and Mid Continent Market Center, Inc., Case No. 01-C-0157, in the
District Court of Reno County, Kansas. There have been no material changes in
the status of these two separate class action lawsuits. However, the case filed
against us based on a wrongful death claim and punitive damages arising out of
the Hutchinson explosion that was previously reported in conjunction with the
two class action lawsuits has been settled with no material financial impact to
us.
Item 2. Changes in Securities and Use of Proceeds
Not Applicable.
Item 3. Defaults Upon Senior Securities
Not Applicable.
Item 4. Submission of Matters to Vote of Security Holders
On May 16, 2002, we held our annual meeting of shareholders. At this meeting,
the individuals set forth below were elected by a plurality vote to our Board of
Directors for a term of three years:
Election of Directors
William M. Bell, Class B
John B. Dicus, Class B
David L. Kyle, Class B
Pattye L. Moore, Class B
The individuals set forth below are the members of our Board of Directors whose
term of office as a director continued after the meeting:
Continuing Directors
Edwyna G. Anderson, Class C
William L. Ford, Class C
Douglas T. Lake, Class A
Bert H. Mackie, Class C
Douglas Ann Newsom, Class A
Gary D. Parker, Class C
J.D. Scott, Class A
45
In addition, at the annual meeting the appointment of KPMG LLP as our
independent auditor for the 2002 fiscal year was ratified by our shareholders as
follows:
Votes
---------------------------------------
For Against Abstain
Appointment of KPMG LLP as
principal independent auditor 48,486,201 2,493,128 184,178
Item 5. Other Information
Not Applicable.
Item 6. Exhibits and Reports on Form 8-K
Exhibits
The following exhibits are filed as part of this Quarterly Report on Form 10-Q:
Exhibit No. Exhibit Description
12 Computation of Ratio of Earnings to Combined Fixed Charges and
Preferred Stock Dividend Requirement for the three and six
months ended June 30, 2002 and 2001.
12.1 Computation of Ratio of Earnings to Fixed Charges for the three
and six months ended June 30, 2002 and 2001.
99.1 Certification of David L. Kyle pursuant to 18.U.S.C. Section
1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002.
99.2 Certification of Jim Kneale pursuant to 18.U.S.C. Section 1350
as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
2002.
Reports on Form 8-K
We filed the following Current Reports on Form 8-K during the quarter ended June
30, 2002.
June 3, 2002 - Announced Western Resources, Inc. and its wholly-owned
subsidiary, Westar Industries, Inc. delivered a sale notice to
the Company giving notice of their intent to sell 4,714,434
shares of common stock and 19,946,448 shares of Series A
Convertible Preferred Stock of the Company.
June 5, 2002 - Announced the sale of the Company's remaining common stock in
Magnum Hunter Resources, Inc.
June 24, 2002 - Announced the extension of the Company's $850 million revolving
credit facility.
46
Signatures
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
ONEOK, Inc.
Registrant
Date: August 12, 2002 By: /s/ Jim Kneale
-----------------------------------------
Jim Kneale
Senior Vice President, Treasurer and
Chief Financial Officer
(Principal Financial Officer)
47