ONEOK INC /NEW/ - 10-Q Quarterly Report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x	Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended March 31, 2004

¨	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 incorporation or organization)		(I.R.S. Employer Identification No.)

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 ¨

Indicate by checkmark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes x No ¨.

On April 28, 2004, the Company had 102,668,430 shares of common stock outstanding.

ONEOK, Inc.

QUARTERLY REPORT ON FORM 10-Q


		Page No.
Part I.	Financial Information

Item 1.	Financial Statements (Unaudited)

	Consolidated Statements of Income - Three Months Ended March 31, 2004 and 2003	3

	Consolidated Balance Sheets - March 31, 2004 and December 31, 2003	4-5

	Consolidated Statements of Cash Flows - Three Months Ended March 31, 2004 and 2003	6

	Consolidated Statement of Shareholders’ Equity and Comprehensive Income - Three Months Ended March 31, 2004	8-9

	Notes to Consolidated Financial Statements	10-22

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23-41

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	41-42

Item 4.	Controls and Procedures	43

Part II.	Other Information

Item 1.	Legal Proceedings	43-44

Item 2.	Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities	44

Item 3.	Defaults Upon Senior Securities	44

Item 4.	Submission of Matters to a Vote of Security Holders	44

Item 5.	Other Information	44

Item 6.	Exhibits and Reports on Form 8-K	45-46

Signatures		47

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.

Part I - FINANCIAL INFORMATION

Item 1. Financial Statements

ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF INCOME


	Three Months Ended March 31,
*(Unaudited)*	2004		2003
	*(Thousands of Dollars,* *except per share amounts)*
Revenues
Operating revenues, excluding energy trading revenues	$	955,311	$	951,039
Energy trading revenues, net		75,264		135,671
Cost of gas		637,816		683,758

Net Revenues		392,759		402,952

Operating Expenses
Operations and maintenance		130,376		112,443
Depreciation, depletion, and amortization		46,740		40,427
General taxes		20,535		17,645

Total Operating Expenses		197,651		170,515

Operating Income		195,108		232,437

Other income		7,814		854
Other expense		7,590		113
Interest expense		23,688		28,577

Income before Income Taxes		171,644		204,601

Income taxes		66,491		78,994

Income from Continuing Operations		105,153		125,607
Discontinued operations, net of taxes (Note C):
Income from operations of discontinued component		—		2,342
Gain on sale of discontinued component		—		38,369
Cumulative effect of a change in accounting principle, net of tax		—		(143,885	)

Net Income		105,153		22,433
Preferred stock dividends		—		15,166

Income Available for Common Stock	$	105,153	$	7,267

Earnings Per Share of Common Stock (Note M)
Basic:
Earnings per share from continuing operations	$	1.06	$	1.43
Earnings per share from operations of discontinued component		—		0.02
Earnings per share from gain on sale of discontinued component		—		0.34
Earnings per share from cumulative effect of changes in accounting principle		—		(1.28	)

Net earnings per share, basic	$	1.06	$	0.51

Diluted:
Earnings per share from continuing operations	$	1.04	$	1.20
Earnings per share from operations of discontinued component		—		0.02
Earnings per share from gain on sale of discontinued component		—		0.34
Earnings per share from cumulative effect of changes in accounting principle		—		(1.28	)

Net earnings per share, diluted	$	1.04	$	0.28

Average Shares of Common Stock (Thousands)
Basic		99,116		83,733
Diluted		101,298		98,514

Dividends per share of Common Stock	$	0.19	$	0.17

See accompanying Notes to Consolidated Financial Statements.

ONEOK, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS


*(Unaudited)*	March 31, 2004		December 31, 2003
	*(Thousands of Dollars)*
Assets
Current Assets
Cash and cash equivalents	$	22,237	$	12,172
Trade accounts and notes receivable, net		944,341		970,141
Materials and supplies		20,684		18,962
Gas in storage		256,805		500,439
Assets from price risk management activities (Note D)		201,065		289,417
Deposits		26,360		42,424
Other current assets		32,468		46,184

Total Current Assets		1,503,960		1,879,739

Property, Plant and Equipment
Production		412,877		404,254
Gathering and Processing		1,040,946		1,036,080
Transportation and Storage		695,172		699,676
Distribution		2,825,409		2,813,800
Marketing and Trading		126,425		126,315
Other		125,130		99,549

Total Property, Plant and Equipment		5,225,959		5,179,674
Accumulated depreciation, depletion, and amortization		1,529,199		1,487,848

Net Property, Plant and Equipment		3,696,760		3,691,826

Deferred Charges and Other Assets
Regulatory assets, net (Note E)		208,666		213,915
Goodwill (Note F)		225,363		225,615
Assets from price risk management activities (Note D)		123,717		113,052
Prepaid pensions		121,437		120,618
Investments and other		78,005		69,283

Total Deferred Charges and Other Assets		757,188		742,483

Total Assets	$	5,957,908	$	6,314,048

See accompanying Notes to Consolidated Financial Statements.

ONEOK, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS


*(Unaudited)*	March 31, 2004			December 31, 2003
	*(Thousands of Dollars)*
Liabilities and Shareholders’ Equity
Current Liabilities
Current maturities of long-term debt	$	341,334		$	6,334
Notes payable		—			600,000
Accounts payable		820,360			813,895
Accrued taxes		94,352			102,637
Accrued interest		28,586			32,999
Customers’ deposits		35,662			34,692
Unrecovered purchased gas costs		49,695			51,378
Liabilities from price risk management activities (Note D)		268,595			302,878
Deferred income taxes		9,205			6,194
Other		118,102			130,174

Total Current Liabilities		1,765,891			2,081,181

Long-term Debt, excluding current maturities		1,571,068			1,878,264
Deferred Credits and Other Liabilities
Deferred income taxes		570,760			559,356
Liabilities from price risk management activities (Note D)		131,134			112,714
Lease obligation		96,923			100,292
Other deferred credits		338,410			340,849

Total Deferred Credits and Other Liabilities		1,137,227			1,113,211

Total Liabilities		4,474,186			5,072,656

Commitments and Contingencies *(Note J)*
Shareholders’ Equity
Common stock, $0.01 par value: authorized 300,000,000 shares; issued 105,589,157 shares and outstanding 102,552,990 shares at March 31, 2004; issued 98,194,674 shares and outstanding 95,194,666 shares at December 31, 2003		1,056			982
Paid in capital		977,955			815,870
Unearned compensation		(2,871	)		(3,422	)
Accumulated other comprehensive loss (Note G)		(24,318	)		(17,626	)
Retained earnings		583,083			495,971
Treasury stock at cost: 3,036,167 shares at March 31, 2004 and 3,000,008 shares at December 31, 2003		(51,183	)		(50,383	)

Total Shareholders’ Equity		1,483,722			1,241,392

Total Liabilities and Shareholders’ Equity	$	5,957,908		$	6,314,048

See accompanying Notes to Consolidated Financial Statements.

ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Three Months Ended March 31,
*(Unaudited)*	2004			2003
	*(Thousands of Dollars)*
Operating Activities
Income from continuing operations	$	105,153		$	125,607
Depreciation, depletion, and amortization		46,740			40,427
Gain on sale of assets		(6,964	)		—
Income from equity investments		(49	)		(415	)
Deferred income taxes		19,305			44,592
Stock based compensation expense		3,044			332
Allowance for doubtful accounts		8,297			4,530
Changes in assets and liabilities (net of acquisition effects):
Accounts and notes receivable		17,503			(433,575	)
Inventories		241,912			(3,313	)
Unrecovered purchased gas costs		(1,683	)		2,009
Deposits		16,064			(10,977	)
Regulatory assets		(285	)		2,721
Accounts payable and accrued liabilities		18,336			455,467
Price risk management assets and liabilities		(4,860	)		45,607
Other assets and liabilities		(12,799	)		63,521

Cash Provided by Continuing Operations		449,714			336,533
Cash Provided by Discontinued Operations		—			4,705

Cash Provided by Operating Activities		449,714			341,238

Investing Activities
Changes in other investments, net		(82	)		722
Acquisitions		—			(420,000	)
Capital expenditures		(48,902	)		(33,483	)
Proceeds from sale of property		13,073			—
Other investing activities		(4,663	)		—

Cash Used in Continuing Operations		(40,574	)		(452,761	)
Cash Provided by Discontinued Operations		—			280,669

Cash Used in Investing Activities		(40,574	)		(172,092	)

Financing Activities
Payments of notes payable		(600,000	)		(265,500	)
Change in bank overdraft		(23,599	)		21,934
Issuance of debt		—			402,500
Termination of interest rate swaps		82,915			—
Payment of debt issuance costs		—			(2,564	)
Payment of debt		(270	)		(15,430	)
Purchase of Series A Convertible Preferred Stock		—			(300,000	)
Issuance of common stock		160,720			218,521
Issuance (forfeiture) of treasury stock, net		(800	)		1,157
Dividends paid		(18,041	)		(20,298	)

Cash Provided by (Used in) Financing Activities		(399,075	)		40,320

Change in Cash and Cash Equivalents		10,065			209,466
Cash and Cash Equivalents at Beginning of Period		12,172			73,522

Cash and Cash Equivalents at End of Period	$	22,237		$	282,988

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME


*(Unaudited)*	Common Stock Issued	Common Stock		Paid-in Capital			Unearned Compensation
	*(Shares)*	*(Thousands of Dollars)*
December 31, 2003	98,194,674	$	982	$	815,870		$	(3,422	)
Net income	—		—		—			—
Other comprehensive income	—		—		—			—

Total comprehensive income

Forfeitures of restricted stock	—		—		—			—
Issuance of common stock
Common stock offering	6,900,000		69		151,248			—
Stock issuance pursuant to various plans	494,483		5		9,464			—
Offering costs	—		—		(66	)		—
Stock-based employee compensation expense	—		—		1,439			619
Common stock dividends - $0.19 per share	—		—		—			(68	)

March 31, 2004	105,589,157	$	1,056	$	977,955		$	(2,871	)

See accompanying Notes to the Consolidated Financial Statements.

ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

(Continued)


*(Unaudited)*	Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Treasury Stock			Total
	*(Thousands of Dollars)*
December 31, 2003	$	(17,626	)	$	495,971		$	(50,383	)	$	1,241,392
Net income		—			105,153			—			105,153
Other comprehensive income		(6,692	)		—			—			(6,692	)

Total comprehensive income											98,461

Forfeitures of restricted stock		—			—			(800	)		(800	)
Issuance of common stock
Common stock offering		—			—			—			151,317
Stock issuance pursuant to various plans		—			—			—			9,469
Offering costs		—			—			—			(66	)
Stock-based employee compensation expense		—			—			—			2,058
Common stock dividends - $0.19 per share		—			(18,041	)		—			(18,109	)

March 31, 2004	$	(24,318	)	$	583,083		$	(51,183	)	$	1,483,722

ONEOK, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

A. Summary of Accounting Policies

The accompanying unaudited consolidated financial statements of ONEOK, Inc. and its subsidiaries (ONEOK or the Company) have been prepared in accordance with accounting principles generally accepted in the United States of America. The accompanying unaudited 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 months ended March 31, 2004, are not necessarily indicative of the results that may be expected for a twelve-month period. These unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements in the Company’s Annual Report on Form 10-K for the year ended December 31, 2003.

The Company’s accounting policies are consistent with those disclosed in its Form 10-K for the year ended December 31, 2003, except as follows.

Critical Accounting Policies and Estimates

Pension and Postretirement Employee Benefits - In January 2004, the Financial Accounting Standards Board (FASB) issued FASB Staff Position No. FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP FAS 106-1) as preliminary guidance on how employers should account for provisions of the recently enacted Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Reform Act). The Company elected to adopt FSP FAS 106-1 in the first quarter of 2004. See Note I.

Significant Accounting Policies

Common Stock Options and Awards - The following table sets forth the effect on net income and earnings per share if the Company had applied the fair-value recognition provisions of Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” (Statement 123) to all options and awards granted prior to January 1, 2003.


	Three Months Ended March 31,
	2004		2003
	(Thousands of Dollars, except per share amounts)

Net income, as reported	$	105,153	$	22,433
Add: Stock based compensation included in net income, net of related tax effects		1,872		600
Deduct: Total stock based compensation expense determined under fair value based method for all awards, net of related tax effects		2,169		903

Pro forma net income	$	104,856	$	22,130

Earnings per share:
Basic - as reported	$	1.06	$	0.51
Basic - pro forma	$	1.06	$	0.50
Diluted - as reported	$	1.04	$	0.28
Diluted - pro forma	$	1.04	$	0.27

Related Party Transactions - From time to time and in the normal course of business, the Company purchases natural gas and natural gas liquids from, sells natural gas and natural gas liquids to, and provides natural gas transportation services to Frontier Oil Corporation and its subsidiaries (Frontier). Julie H. Edwards, Executive Vice President - Finance and Administration and Chief Financial Officer for Frontier, is a member of the Company’s board of directors. The purchase and sale transactions are conducted under substantially the same terms as comparable third-party transactions. During the first quarter of 2004, purchases

of natural gas and natural gas liquids from Frontier were approximately $6.8 million and sales of natural gas and natural gas liquids and transportation services to Frontier totaled approximately $41.0 million.

In the normal course of business, the Company conducts natural gas and natural gas liquids purchase and sale transactions with Williford Energy Company and TriCounty Gas Processors, Inc. Mollie Williford, Chairman of the Board of the Williford Companies, which consists of numerous companies including Williford Energy Company and TriCounty Gas Processors, Inc., is a member of the Company’s board of directors. These purchase and sale transactions are conducted under substantially the same terms as comparable third-party transactions. During the first quarter of 2004, purchases of natural gas and natural gas liquids from the Williford Companies totaled approximately $1.6 million.

Production Property - The FASB is expected to consider, based on a Securities and Exchange Commission (SEC) request, whether or not acquired oil and gas drilling rights should be classified as an intangible asset pursuant to Statement of Financial Accounting Standards No. 141, “Business Combinations” (Statement 141) and Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets” (Statement 142). The Company classifies the cost of oil and gas mineral rights as property, plant, and equipment on the balance sheet and believes this classification is consistent with oil and gas accounting and industry practice. If the FASB determines that oil and gas drilling rights acquired are intangible assets pursuant to Statement 141 and Statement 142, approximately $274.0 million and $271.8 million would be reclassified from property, plant, and equipment to intangible assets on the March 31, 2004 and December 31, 2003 balance sheets, respectively. The reclassification would have no effect on the statements of income or cash flows. This reclassification to intangible assets would require additional disclosures under accounting standards.

Other

Impact of New Accounting Standards - In December 2003, the FASB issued FASB Interpretation No. 46R, “Consolidation of Variable Interest Entities” (FIN 46R) that addresses the consolidation of variable interest entities. FIN 46R is applicable to variable interest entities or potential variable interest entities commonly referred to as special purpose entities by the end of the first reporting period ending after December 15, 2003. FIN 46R had no impact on the Company’s consolidated financial statements at March 31, 2004.

Reclassifications - Certain amounts in the consolidated financial statements, primarily related to current and non current deferred taxes, have been reclassified to conform to the 2004 presentation. Such reclassifications did not impact previously reported net income or shareholders’ equity.

B. Dispositions

On March 1, 2004, the Company completed a transaction to sell certain natural gas transmission and gathering pipelines and compression for approximately $13 million. As a result of the sale, the Company recorded a pre-tax gain of $6.9 million, which is included in other income in the Transportation and Storage segment.

C. Discontinued Operations

In January 2003, the Company sold approximately 70 percent of the natural gas and oil producing properties of its Production segment (the component) for an adjusted cash price of $294 million. The component is accounted for as a discontinued operation in accordance with Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (Statement 144). Accordingly, amounts in the Company’s financial statements and related notes for all periods shown reflect discontinued operations accounting. The Company’s decision to sell the component was based on strategic evaluations of the Production segment’s goals and favorable market conditions. The properties sold were in Oklahoma, Kansas and Texas. The Company recognized a pretax gain on the sale of the discontinued component of approximately $59 million in the first quarter of 2003. The gain reflects the cash received less adjustments, selling expenses and the net book value of the assets sold.

The amounts of revenue, costs and income taxes reported in discontinued operations are as follows.


	Three Months Ended March 31,
	2004		2003
	*(Thousands of Dollars)*
Natural gas sales	$	—	$	6,036
Oil sales		—		1,705
Other revenues		—		—

Net revenues		—		7,741
Operating costs		—		1,985
Depreciation, depletion, and amortization		—		1,937

Operating income	$	—	$	3,819

Income taxes	$	—	$	1,477

Income from discontinued component	$	—	$	2,342

Gain on sale of discontinued component, net of tax of $20.7 million	$	—	$	38,369

D. Price Risk Management Activities and Derivative Financial Instruments

Accounting Treatment - The Company accounts for derivative instruments and hedging activities in accordance with Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (Statement 133). Under Statement 133, entities are required to record all derivative instruments 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, the reason for holding it. If the derivative instrument does not qualify as part of a hedging relationship, the Company accounts for changes in fair value of the derivative instrument as they occur. If certain conditions are met, entities may elect to designate a derivative instrument as a hedge of exposure to changes in fair values, cash flows or foreign currencies. For hedges of exposure to changes in fair value, 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. The difference between the change in fair value of the derivative instrument and the change in fair value of the hedged item represents hedge ineffectiveness. For hedges of exposure to changes in cash flow, the effective portion of the gain or loss on the derivative instrument is reported initially as a component of other comprehensive income and is 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.

As required by Statement 133, the Company formally documents all relationships between hedging instruments and hedged items, as well as risk management objectives, strategies for undertaking various hedge transactions and methods for assessing and testing correlation and hedge ineffectiveness. The Company specifically identifies the asset, liability, firm commitment or forecasted transaction that has been designated as the hedged item. The Company assesses the effectiveness of hedging relationships, both at the inception of the hedge and on an ongoing basis.

In July 2003, the Emerging Issues Task Force (EITF) of the FASB reached a consensus on EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not ‘Held for Trading Purposes’ as Defined in EITF Issue No. 02-3, ‘Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities’” (EITF 03-11). EITF 03-11 provides that the determination of whether realized gains and losses on physically settled derivative contracts not “held for trading purposes” should be reported in the income statement on a gross or net basis is a matter of judgment that depends on the relevant facts and circumstances. Consideration of the facts and circumstances should be made in the context of the various activities of the entity rather than based solely on the terms of the individual contracts. The Company has continued to present the financial results of all energy trading contracts on a net basis.

Trading Activities

Fair Value Hedges - The Marketing and Trading segment uses basis swaps to hedge the fair value of certain transportation commitments. At March 31, 2004, net price risk management assets include $12.8 million to recognize the fair value of the Marketing and Trading segment’s derivatives that are designated as fair value hedging instruments. The ineffectiveness was

approximately $0.9 million in the first quarter of 2004 related to these hedges. This amount is included in energy trading revenues, net.

Cash Flow Hedges - The Marketing and Trading segment uses futures and swaps to hedge the cash flows associated with its natural gas. Accumulated other comprehensive income (loss) at March 31, 2004, includes losses of approximately $16.6 million, net of tax, related to these hedges that will be realized within the next 10 months. When gas inventory is sold, net gains and losses are reclassified out of accumulated other comprehensive income to energy trading revenues, net. Ineffectiveness related to these cash flow hedges was approximately $1.1 million in the first quarter of 2004. Additionally, losses of approximately $4.6 million were recognized from accumulated other comprehensive income during the first quarter of 2004 due to the discontinuance of cash flow hedge treatment since it was probable that the forecasted transactions would not occur.

Non-Trading Activities

Fair Value Hedges - The Company is subject to the risk of fluctuations 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. During the first quarter of 2004, the Company terminated $670 million of its interest rate swap agreements to lock in savings and received $91.8 million which includes $8.9 million of interest rate savings previously recorded. These interest rate swaps were previously initiated as a strategy to hedge the fair value of fixed-rate long-term debt. The net proceeds received of $81.9 million, after reduction for ineffectiveness and unpaid interest, upon termination of the interest rate swaps will be recognized in the income statement over the term of the debt instruments originally hedged. Consequently, the savings in interest expense will be recognized over the following periods:


2004	$	8.1 million
2005	$	10.0 million
2006	$	10.0 million
2007	$	10.0 million
2008	$	10.0 million
Thereafter	$	33.8 million

The Company has entered into new swap agreements to replace the terminated agreements. Currently, $740 million of fixed rate debt is swapped to floating. The floating rate debt is based on both three and six-month London InterBank Offered Rate (LIBOR) depending upon the swap. In the first quarter of 2004, the Company recorded a $1.7 million asset to recognize the interest rate swaps at fair value. Long-term debt was also increased by $1.7 million to recognize the change in the fair value of the related hedged liability.

Cash Flow Hedges - The Production segment periodically enters into derivative instruments to hedge the cash flows associated with its exposure to changes in the price of natural gas. Accumulated other comprehensive income (loss) at March 31, 2004 includes losses of approximately $5.4 million, net of tax, for the production hedges that will be realized in earnings within the next 21 months. Ineffectiveness related to these cash flow hedges was approximately $0.2 million in the first quarter of 2004.

The Company’s regulated businesses also use derivative instruments from time to time. Gains or losses associated with the derivative instruments are included in and recoverable through the monthly purchased gas adjustment. At March 31, 2004, there were no derivative instruments in place to hedge the cost of gas purchases.

E. Regulatory Assets

The following table is a summary of the regulatory assets, net of amortization, for the periods indicated.


	March 31, 2004		December 31, 2003
	*(Thousands of Dollars)*
Recoupable take-or-pay	$	62,743	$	64,171
Pension costs		16,739		18,060
Postretirement costs other than pension		57,417		59,118
Transition costs		16,577		16,691
Reacquired debt costs		20,420		20,635
Income taxes		20,954		21,782
Weather normalization		2,935		1,075
Line replacements		466		495
Service lines		2,510		3,250
Other		7,905		8,638

Regulatory assets, net	$	208,666	$	213,915

On January 30, 2004, the Oklahoma Corporation Commission (OCC) approved Oklahoma Natural Gas Company’s (ONG) request that it be allowed to recover costs that the Company has incurred since 2000 when it assumed responsibility for its customers’ service lines and enhanced efforts to protect pipelines from corrosion. ONG also sought to recover costs related to its investment in gas in storage and rising levels of fuel-related bad debts. The plan allows rate relief of $17.7 million annually with $10.7 million as interim and subject to refund until a final determination at the Company’s next general rate case. ONG has committed to filing for a general rate review no later than January 31, 2005. Approximately $7.0 million annually is considered final and not subject to refund. With the approval of ONG’s request, the Company began amortizing the deferred costs associated with these OCC directives over an eighteen month period. At March 31, 2004, the Company had approximately $4.6 million remaining to be amortized compared to $6.0 million at December 31, 2003. These deferred costs are included in the captions “Service Lines” and “Other” in the regulatory assets table above.

The current estimate of the future rate relief is substantially in excess of the refund threshold of $10.7 million. The Company believes it is remote that any refund obligation exists and, accordingly, it has not recorded a reserve. The Company will continue to monitor the regulatory environment to determine any changes in its estimated future rate relief and, should its analysis indicate a potential refund liability, the Company will record a reserve for this obligation.

F. Goodwill

The following table reflects the changes in the carrying amount of goodwill for the periods indicated.


	Balance December 31, 2003		Adjustments			Balance March 31, 2004
	*(Thousands of Dollars)*
Gathering and Processing	$	34,343	$	—		$	34,343
Transportation and Storage		22,288		(252	)		22,036
Distribution		158,729		—			158,729
Marketing and Trading		10,255		—			10,255

Total consolidated	$	225,615	$	(252	)	$	225,363


	Balance December 31, 2002		Adjustments			Balance March 31, 2003
	*(Thousands of Dollars)*
Gathering and Processing	$	34,343	$	(702	)	$	33,641
Transportation and Storage		22,183		2,100			24,283
Distribution		51,368		106,809			158,177
Marketing and Trading		5,616		4,384			10,000

Total consolidated	$	113,510	$	112,591		$	226,101

The 2004 adjustment to goodwill resulted from the sale of certain natural gas transmission and gathering pipelines and compression on March 1, 2004. The adjustments to goodwill in 2003 are a result of the preliminary purchase price allocation of the Texas assets acquired in January 2003.

The Company completed its annual analysis of goodwill for impairment as of January 1, 2004 and there was no impairment indicated.

G. Comprehensive Income

The tables below give an overview of comprehensive income for the periods indicated.


	Three Months Ended March 31,
	2004						2003
	*(Thousands of Dollars)*
Net income				$	105,153					$	22,433
Other comprehensive income (loss):
Unrealized losses on derivative instruments	$	(22,477	)				$	(11,446	)
Unrealized holding losses arising during the period		(106	)					(76	)
Realized losses in net income		11,677						2,214

Other comprehensive loss before taxes		(10,906	)					(9,308	)
Income tax benefit on other comprehensive loss		4,214						3,599

Other comprehensive loss					(6,692	)					(5,709	)

Comprehensive income				$	98,461					$	16,724

Accumulated other comprehensive income (loss) reflected in the consolidated balance sheet at March 31, 2004, includes unrealized gains and losses on derivative instruments and minimum pension liability adjustments.

H. Capital Stock

Common Stock - In July 2003, the Company began using shares of its common stock from treasury or newly issued shares to meet the purchase requirements generated by participants in its Thrift Plan for Employees of ONEOK, Inc. and Subsidiaries. All participant purchases under this plan are voluntary. During the three months ended March 31, 2004, the Company issued 325,200 shares for a total of $7.3 million.

2004 Common Stock Offering - During the first quarter of 2004, the Company sold 6.9 million shares of its common stock to an underwriter at $21.93 per share, resulting in proceeds to the Company, before expenses, of $151.3 million.

Dividends - Quarterly dividends on the Company’s common stock for shareholders of record during the three months ended March 31, 2004, were $0.19 per share. In April 2004, the Company’s board of directors increased the quarterly dividend on the Company’s common stock to $0.21 per share.

I. Employee Benefit Plans

The table below provides the components of net periodic benefit cost (income).


	Pension Benefits Three Months Ended March 31,						Postretirement Benefits Three Months Ended March 31,
	2004			2003			2004			2003
	*(Thousands of Dollars)*
Components of Net Periodic Benefit Cost (Income)
Service cost	$	3,981		$	3,403		$	1,641		$	1,303
Interest cost		10,371			10,227			3,607			3,003
Expected return on assets		(15,485	)		(15,681	)		(939	)		(763	)
Amortization of unrecognized net asset at adoption		(79	)		(117	)		864			836
Amortization of unrecognized prior service cost		166			149			24			(30	)
Amortization of loss		578			407			1,857			966

Net periodic benefit cost (income)	$	(468	)	$	(1,612	)	$	7,054		$	5,315

Contributions - For the three months ended March 31, 2004, $0.3 million and $3.9 million of contributions had been made for the pension plan and other postretirement benefit plan, respectively. The Company presently anticipates its total 2004 contributions to be $4.6 million for the pension plan and $13.1 million for the other postretirement benefit plan.

Other Postretirement Benefits Changes - In January 2004, the FASB issued FSP FAS 106-1 as preliminary guidance on how employers should account for provisions of the recently enacted Medicare Reform Act. The Medicare Reform Act allows employers who sponsor a postretirement health care plan that provides a prescription drug benefit to receive a subsidy for the cost of providing that drug benefit. In order for employers to receive the subsidy payment under the Medicare Reform Act, the value of the offered prescription drug plan must be actuarially equivalent to the standard prescription drug coverage provided under Medicare Part D. Due to the Company’s lower deductibles and better coverage of drug costs, the Company believes that its plan is of greater value than Medicare Part D and will meet the actuarially equivalent definitions. As permitted by FSP FAS 106-1, the Company made a one-time election to account for the subsidy in its financial statements. Since the Company uses a September 30 measurement date, it was required to make the election no later than March 31, 2004. The Company’s quarterly expense for the three months ended March 31, 2004 is not affected by the change. Subsequent quarters will reflect the expected reduction in annual expenses. Accordingly, the Company expects its accumulated postretirement benefit obligation to decrease by approximately $18 million and its postemployment benefit expense to decrease by approximately $2.7 million for the remainder of 2004. These amounts are based on preliminary estimates that are dependent on interpretative regulations not yet available, and therefore, subject to change. The Company believes that its plan will continue to provide drug benefits that are actuarially equivalent to Medicare Part D, that its plan will continue to be the primary plan for the Company’s retirees and that the Company will receive the subsidy. The Company does not expect that the Medicare Act will have a significant effect on the Company’s retirees’ participation in its postretirement benefit plan.

The FASB has subsequently proposed FASB Staff Position No. FAS 106-b, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP FAS 106-b). FSP FAS 106-b will provide more specific authoritative guidance on the accounting for this federal subsidy and that guidance, when issued, could require the Company to change its estimates.

J. Commitments and Contingencies

Environmental - The Company is subject to multiple environmental laws and regulations affecting many aspects of present and future operations, including air emissions, water quality, wastewater discharges, solid wastes and hazardous material and substance management. These laws and regulations generally require the Company to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals. Failure to comply with these laws, regulations, permits and licenses may expose the Company to fines, penalties and/or interruptions in operations that could be material to the results of operations. If an accidental leak or spill of hazardous materials occurs from the Company’s lines or facilities, in the process of transporting natural gas, or at any facilities that the Company owns, operates or otherwise uses, the Company could be held jointly and severally liable for all resulting liabilities, including investigation and clean up costs, which could materially affect the Company’s results, operations and cash flow. In addition, emission controls required under the Federal Clean Air Act and other similar federal and state laws could require unexpected capital expenditures at the Company’s facilities. The Company cannot assure that existing environmental regulations will not be revised or that new regulations will not be adopted or become applicable to the Company. Revised or additional regulations that result in increased compliance costs or additional operating

restrictions, particularly if those costs are not fully recoverable from customers, could have a material adverse effect on the Company’s business, financial condition and results of operations.

The Company owns or retains legal responsibility for the environmental conditions at 12 former manufactured gas sites in Kansas. These sites contain potentially harmful materials that are subject to control or remediation under various environmental laws and regulations. A consent agreement with the Kansas Department of Health and Environment (KDHE) presently governs all work at these sites. The terms of the consent agreement allow the Company to investigate these sites and set remediation activities based upon the results of the investigations and risk analysis. The Company has commenced active remediation on three sites with regulatory closure achieved at two of these locations, and has begun assessment at the remaining sites. The site situations are not common and the Company has no previous experience with similar remediation efforts. The Company has not completed a comprehensive study of the remaining nine sites and therefore cannot accurately estimate individual or aggregate costs to satisfy the remedial obligations.

The Company’s preliminary review of similar cleanup efforts at former manufactured gas sites reveals that costs can range from $100,000 to $10 million per site. These estimates do not give effect to potential insurance recoveries, recoveries through rates or from unaffiliated parties, to which the Company may be entitled. At this time, the Company has not recorded any amounts for potential insurance recoveries or recoveries from unaffiliated parties, and the Company is not recovering any environmental amounts in rates. Total costs to remediate the two sites, which have achieved regulatory closure, totaled approximately $800,000. Total remedial costs for each of the remaining sites are expected to exceed $400,000 per site, but there is no assurance that costs to investigate and remediate the remaining sites will not be significantly higher. As more information related to the site investigations and remediation activities becomes available, and to the extent such amounts are expected to exceed the Company’s current estimates, additional expenses could be recorded. Such amounts could be material to the Company’s results of operations and cash flows depending on the remediation done and number of years over which the remediation is completed.

The Company’s expenditures for environmental evaluation and remediation to date have not been significant in relation to the results of operations and there have been no material effects upon earnings during 2004 related to compliance with environmental regulations.

Yaggy Facility - In January 2001, the Yaggy gas storage facility’s operating parameters were changed as mandated by the KDHE following natural gas explosions and eruptions of natural gas geysers in or near Hutchison, Kansas. In July 2002, the KDHE issued an administrative order that assessed a civil penalty against the Company, based on alleged violations of several KDHE regulations. On April 5, 2004 the Company and the KDHE entered into a Consent Order in which the Company paid a civil penalty in the amount of $180,000 and reimbursed the KDHE for its costs related to the investigation of the incident in the amount of approximately $79,000. In addition, the Consent Order requires the Company to conduct an environmental remediation and a geoengineering study. The Company believes there are no adverse long-term environmental effects.

Two 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, and in the vicinity of, the Yaggy facility in January 2001. These class action lawsuits claim that the explosions were caused by the release of natural gas from the Company’s operations. In addition to the two pending class action matters, there are nine currently pending lawsuits that have been filed against the Company or subsidiaries seeking recovery for various claims related to the Yaggy incident, including property damage, personal injury, loss of business and, in some instances, punitive damage. In February 2004, a jury awarded the plaintiffs in one lawsuit $1.7 million in actual damages. In April 2004, the judge awarded punitive damages in the amount of $5.25 million. The Company plans to appeal the punitive damage award. The Company is vigorously defending these matters and, although no assurances can be given, believes its legal reserves and insurance policies are adequate and that the ultimate resolution of these matters will not have a material adverse effect on the Company’s financial position or results of operations.

U.S. Commodity Futures Trading Commission - On April 14, 2004 the Company received a subpoena from the U.S. Commodity Futures Trading Commission (CFTC) requesting information in its industry wide investigation relating to ”Activities Affecting the Price of Natural Gas in the Fall of 2003”. The CFTC has specifically requested information related to reporting of natural gas storage information to Energy Information Agency during the time period of October 31, 2003 - January 2, 2004. The Company is complying with subpoena and will cooperate with the CFTC’s investigation. At the present time the Company cannot determine whether this industry wide investigation will have any adverse impact on the Company.

On January 9, 2003, the Company received a subpoena from the CFTC requesting information regarding certain trading by energy and power marketing firms and information provided by the Company to energy industry publications in connection with the CFTC’s investigation of trading and trade reporting practices of power and natural gas trading companies. The Company ceased providing such information to energy industry publications in 2002. The Company cooperated fully with the CFTC,

producing documents and other material in response to specific requests relating to the reporting of natural gas trading information to energy industry publications, conducting an internal review with regard to its practices in voluntarily reporting information to trade publications, and providing reports on its internal review to the CFTC.

In January 2004, the Company announced a settlement with the CFTC relating to the investigation, whereby the Company agreed, among other things, to pay a civil monetary penalty of $3.0 million. This charge is recorded in earnings for the Marketing and Trading segment for the year ended December 31, 2003. The Company neither admitted nor denied the findings in the CFTC settlement order. The Company does not believe inaccurate trade reporting to the energy industry publications affected the financial accounting treatment of any transactions recorded in the financial statements.

The Company and its wholly owned subsidiary, ONEOK Energy Marketing and Trading Company, L.P., have been named as two of the defendants in a class action lawsuit filed in the United States District Court for the Southern District of New York brought on behalf of persons who bought and sold natural gas futures and options contracts on the New York Mercantile Exchange during the years 2000 through 2002. Although the Company agreed to the civil monetary penalty with the CFTC, it cannot guarantee other additional legal proceedings, civil or criminal fines or penalties, or other regulatory action related to this issue will not arise. However, the Company plans to vigorously defend any claims related to this issue and does not expect this matter to have a material adverse effect.

Other - The Company is a party to other litigation matters and claims including environmental, which are normal in the ordinary course of its operations. While the results of litigation and claims cannot be predicted with certainty, management believes the final outcome of such matters will not have a material adverse effect on the Company’s consolidated results of operations, financial position, or liquidity.

K. Segments

The accounting policies of the Company’s business 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, 2003, except for those changes discussed in Note A. Intersegment gross sales are recorded on the same basis as sales to unaffiliated customers. Intersegment sales for the Marketing and Trading segment were $213.1 million and $197.5 million for the three months ended March 31, 2004 and 2003, respectively. Energy trading contracts included in the following table are reported net of related costs. Corporate overhead costs relating to the segments 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 gross revenues.

The following tables set forth certain selected financial information for the Company’s six operating segments for the periods indicated.


	Regulated				Non-Regulated									Total
Three Months Ended March 31, 2004	Transportation and Storage		Distribution		Marketing and Trading		Gathering and Processing		Production		Other and Eliminations			Total
Sales to unaffiliated customers	$	13,929	$	781,996	$	35,284	$	310,750	$	25,561	$	(212,209	)	$	955,311
Energy trading contracts, net		—		—		75,264		—		—		—		$	75,264
Intersegment sales		24,498		—		—		140,659		826		(165,983	)	$	—

Total Revenues	$	38,427	$	781,996	$	110,548	$	451,409	$	26,387	$	(378,192	)	$	1,030,575

Net revenues	$	30,465	$	203,014	$	75,334	$	59,426	$	26,387	$	(1,867	)	$	392,759
Operating costs	$	12,749	$	91,071	$	10,553	$	30,964	$	8,024	$	(2,450	)	$	150,911
Depreciation, depletion and amortization	$	4,264	$	26,219	$	1,391	$	8,013	$	6,501	$	352		$	46,740
Operating income	$	13,452	$	85,724	$	63,390	$	20,449	$	11,862	$	231		$	195,108
Income from equity investments	$	49	$	—	$	—	$	—	$	—	$	—		$	49
Total assets	$	882,248	$	2,497,077	$	1,292,192	$	1,283,915	$	163,744	$	(161,268	)	$	5,957,908
Capital expenditures	$	2,044	$	25,872	$	110	$	4,077	$	8,472	$	8,327		$	48,902


	Regulated					Non-Regulated											Total
Three Months Ended March 31, 2003	Transportation and Storage			Distribution		Marketing and Trading			Gathering and Processing			Production		Other and Eliminations			Total
Sales to unaffiliated customers	$	20,175		$	692,332	$	12,534		$	410,261		$	12,512	$	(196,775	)	$	951,039
Energy trading contracts, net		—			—		135,671			—			—		—		$	135,671
Intersegment sales		18,375			—		—			130,523			133		(149,031	)	$	—

Total Revenues	$	38,550		$	692,332	$	148,205		$	540,784		$	12,645	$	(345,806	)	$	1,086,710

Net revenues	$	30,145		$	175,338	$	137,501		$	46,327		$	12,645	$	996		$	402,952
Operating costs	$	10,866		$	76,421	$	9,103		$	31,263		$	3,610	$	(1,175	)	$	130,088
Depreciation, depletion and amortization	$	4,154		$	23,888	$	1,462		$	7,201		$	3,358	$	364		$	40,427
Operating income	$	15,125		$	75,029	$	126,936		$	7,863		$	5,677	$	1,807		$	232,437
Income from operations of discontinued component	$	—		$	—	$	—		$	—		$	2,342	$	—		$	2,342
Cumulative effect of changes in accounting principles, net of tax	$	(645	)	$	—	$	(141,982	)	$	(1,375	)	$	117	$	—		$	(143,885	)
Income from equity investments	$	415		$	—	$	—		$	—		$	—	$	—		$	415
Total assets	$	816,124		$	2,416,724	$	1,569,400		$	1,350,306		$	141,060	$	(303,488	)	$	5,990,126
Capital expenditures	$	984		$	24,966	$	83		$	2,472		$	2,948	$	2,030		$	33,483

L. Supplemental Cash Flow Information

The following table sets forth supplemental information with respect to the Company’s cash flows for the periods indicated.


	Three Months Ended March 31,
	2004		2003
	*(Thousands of Dollars)*
Cash paid (received) during the period
Interest (including amounts capitalized)	$	29,614	$	27,847
Income taxes paid (received)	$	56,303	$	(4,528	)
Noncash transactions
Cumulative effect of changes in accounting principle
Rescission of EITF 98-10 (price risk management assets and liabilities)	$	—	$	141,832
Adoption of Statement 143	$	—	$	2,053
Dividends on restricted stock	$	68	$	44
Issuance of restricted stock, net	$	—	$	3,206
Treasury stock transferred to compensation plans	$	—	$	247


	Three Months Ended March 31,
	2004		2003
	*(Thousands of Dollars)*
Acquisitions
Property, plant and equipment	$	—	$	290,000
Current assets		—		70,117
Current liabilities		—		(76,132	)
Regulatory assets and goodwill		—		120,009
Other assets		—		2,871
Lease obligation		—		(4,715	)
Deferred credits		—		(37,399	)
Deferred income taxes		—		55,249

Cash paid for acquisitions	$	—	$	420,000

M. Earnings Per Share Information

Through February 5, 2003, the Company computed its earnings per common share (EPS) in accordance with a pronouncement of the FASB’s Staff at the EITF 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 was 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 determined 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 was a participating instrument with the Company’s common stock with respect to the payment of dividends. For the period from January 1, 2003 to February 5, 2003, the “two-class” method resulted in additional dilution. Accordingly, EPS for the period ended March 31, 2003 reflects this further dilution. As a result of the Company’s repurchase and exchange of its Series A Convertible Preferred Stock in February 2003, the Company no longer applied the provisions of Topic D-95 to its EPS computations beginning in February 2003.

The following tables set forth the computations of the basic and diluted EPS from continuing operations for the periods indicated.


	Three Months Ended March 31, 2004
	Income		Shares	Per Share Amount
	*(Thousands, except per share amounts)*
Basic EPS from continuing operations
Income from continuing operations available for common stock	$	105,153	99,116	$	1.06
Effect of other dilutive securities:
Mandatory convertible units		—	1,677
Options and other dilutive securities		—	505

Diluted EPS from continuing operations
Income from continuing operations available for common stock and assumed conversion	$	105,153	101,298	$	1.04


	Three Months Ended March 31, 2003
	Income		Shares	Per Share Amount
	*(Thousands, except per share amounts)*
Basic EPS from continuing operations
Income from continuing operations available for common stock under D-95	$	26,174	62,055
Series A Convertible Preferred Stock dividends		12,139	39,893

Income from continuing operations available for common stock and assumed conversion of Series A Convertible Preferred Stock		38,313	101,948	$	0.37

Further dilution from applying the “two-class” method				$	(0.08	)

Basic EPS from continuing operations under D-95				$	0.29
Income from continuing operations available for common stock not under D-95		84,267	74,163	$	1.14

Basic EPS from continuing operations				$	1.43

Income from continuing operations available for Series D Convertible Preferred Stock dividends		122,580	83,733
Effect of other dilutive securities:
Mandatory convertible units		—	—
Options and other dilutive securities		—	480
Series D Convertible Preferred Stock dividends		3,027	14,301

Income from continuing operations	$	125,607	98,514	$	1.28

Further dilution from applying the “two-class” method				$	(0.08	)

Diluted EPS from continuing operations				$	1.20

There were 23,892 and 284,799 option shares excluded from the calculation of diluted EPS for the three months ended March 31, 2004 and 2003, respectively, since their inclusion would be antidilutive for each period.

During 2003, the Company issued mandatory convertible equity units. These mandatory convertible units have a dilutive effect on EPS if the average stock price for the most recent 20 trading days exceeds $20.63 per share. For the period ended March 31, 2004, the applicable average stock price was $22.57 which resulted in 1.7 million dilutive units and reduced diluted earnings per share by approximately $0.02 per share.

The repurchase and exchange of the Company’s Series A Convertible Preferred Stock from Westar in February 2003 was recorded at fair value. In accordance with EITF Topic No. D-42, the premium, or the excess of the fair value of the consideration transferred to Westar over the carrying value of the Series A Convertible Preferred Stock, was considered a preferred dividend. The premium recorded on the repurchase and exchange of the Series A Convertible Preferred Stock was approximately $44.2 million and $53.4 million, respectively, for a total premium of $97.6 million. As a result of the Company’s adoption of Topic D-95, the Company has recognized additional dilution of approximately $94.5 million through the application of the “two-class” method of computing EPS. This additional dilution offsets the total premium recorded, resulting in a net premium of $3.1 million, which is reflected as a dividend on the Series A Convertible Preferred Stock in the above EPS calculation for the three months ended March 31, 2003.

N. Debt Covenant Compliance

The Company’s revolving credit facility has customary covenants that relate to liens, investments, fundamental changes in the business, the restriction of certain payments, changes in the nature of the business, transactions with affiliates, burdensome agreements, the use of proceeds, and a limit on the Company’s debt to capital ratio. The facility includes a term-out option, which allows the Company to convert any outstanding borrowings under the credit agreement into a 364-day term note at the expiration of the credit agreement. Other debt agreements to which the Company is a party have negative covenants that relate to liens and sale/leaseback transactions. At March 31, 2004, the Company was in compliance with all covenants.

O. Subsequent Event

Termination of Gulf Coast Fractionators Agreement - The Company’s previously disclosed agreement to acquire a 22.5 percent interest in a partnership, which owns a NGL fractionation facility in Mont Belvieu, Texas, has been terminated due to the closing conditions not being met by the seller.

Sale of Mexico Distribution Assets - In April 2004, the Company signed an agreement to sell its natural gas distribution operations located in Mexico for approximately $2 million. The transaction is expected to close in May 2004.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Executive Summary - From the wellhead to the burner tip, we have grown our company focusing on the entire natural gas value chain and building a combination of regulated and nonregulated businesses.

Our substantial growth as a natural gas distributor began with the acquisition of our Kansas distribution assets in 1997 and, most recently, included the acquisition of our Texas gas distribution assets in 2003. This latest acquisition included 544,000 customers. The September 2003 rate order in Kansas was our first rate relief since the acquisition of the Kansas assets. This $45 million settlement recognizes the substantial investment in capital improvements, as well as increases in the cost of doing business, particularly in the areas such as health care, wages, materials and supplies. The January 2004 rate relief in Oklahoma will provide an additional $17.7 million in annual revenues to allow, among other things, recovery of the cost of maintaining customer service lines, a responsibility we assumed in 2000.

Our contract restructuring effort in our Gathering and Processing segment has allowed us to mitigate risk and become less sensitive to adverse moves in commodity prices. This is a result of our ongoing efforts to add conditioning language to keep whole contracts, to convert keep whole contracts to percent-of-proceeds and fee-based contracts, and to renegotiate certain gas purchase and gathering contracts.

Although employee benefit costs continue to rise, the Medicare Reform Act of 2003 will reduce our costs of providing postretirement benefits to our retirees. It is expected that the decrease in costs for the remainder of 2004 will total $2.7 million as a result of this legislation.

A period of very cold weather early in the winter of 2003 when natural gas storage levels were already at historically low levels created an immediate need for natural gas, driving up both price levels and volatility. In contrast, the lack of volatility in the first quarter of 2004 resulted in reduced net revenues for our Marketing and Trading segment compared to the same period in 2003.

In January, we increased our quarterly dividend by 5.5 percent to 19 cents per share. In April, a 10.5 percent increase brought the quarterly dividend to 21 cents per share. The exchange of our outstanding preferred shares of stock for a new series of preferred stock in 2003 eliminated the disincentive for increasing our common dividend. All of our preferred stock was subsequently eliminated in 2003. We will continue evaluating dividends each quarter and taking steps to ensure that our investors receive a reasonable return.

Acquisitions and Divestitures - In April 2004, we signed an agreement to sell our natural gas distribution operations located in Mexico for approximately $2 million. The transaction is expected to close in May 2004.

On March 1, 2004, we completed a transaction to sell certain natural gas transmission and gathering pipelines and compression for approximately $13 million. As a result of the sale we recorded a pre-tax gain of $6.9 million, which is included in other income in our Transportation and Storage segment.

On December 22, 2003, we purchased approximately $240 million of Texas gas and oil properties and related flow lines. The results of operations for these assets have been included in our consolidated financial statements since that date. The acquisition included approximately 318 wells, 271 of which we operate, and 177.2 Bcfe of estimated proved gas and oil reserves as of the September 1, 2003 effective date, with additional probable and possible reserve potential.

In December 2003, we acquired NGL storage and pipeline facilities located in Conway, Kansas for approximately $13.7 million from ChevronTexaco. In the prior two years we had leased and operated these facilities.

In October 2003, we completed a transaction to sell certain Texas transmission assets for a sales price of approximately $3.1 million. A charge against accumulated depreciation for approximately $7.8 million was recorded in accordance with Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation” (Statement 71) and the regulatory accounting requirements of the Federal Energy Regulatory Commission (FERC) and Railroad Commission of Texas (RRC).

In August 2003, we acquired the gas distribution system at the United States Army’s Fort Bliss in El Paso, Texas for $2.4 million. The gas distribution system at Fort Bliss serves approximately 2,500 customers.

In August 2003, we acquired a pipeline system that extends through the Rio Grande Valley region in Texas for $3.6 million. The Texas Gas Service Company (TGS) Rio pipeline system serves the city gate points for the TGS Rio Grande Valley service area,

providing service to approximately 10 transport customers, two power plants and offers access to production wells that supply the area.

In January 2003, we closed the sale of approximately 70 percent of the natural gas and oil producing properties of our Production segment for a cash sales price of $294 million, including adjustments. The properties sold were in Oklahoma, Kansas and Texas. The effective date of the sale was November 30, 2002. The sale included approximately 1,900 wells, 482 of which we operated. We recorded a pretax gain of approximately $61.2 million in 2003 related to this sale. The statistical and financial information related to the properties sold is reflected as a discontinued component in this Quarterly Report on Form 10-Q. All periods presented have been restated to reflect the discontinued component.

On January 3, 2003, we purchased our Texas gas distribution business and other Texas assets from Southern Union Company. The results of operations for these assets have been included in our consolidated financial statements since that date. We paid approximately $436.6 million for these assets, including $16.6 million in working capital adjustments. The primary assets acquired were gas distribution operations that currently serve approximately 544,000 customers in cities located throughout Texas, including the major cities of El Paso and Austin, as well as the cities of Port Arthur, Galveston, Brownsville and others. Over 90 percent of the customers are residential. The other assets acquired include a 125-mile natural gas transmission system, as well as other energy related domestic assets involved in gas marketing, retail sales of propane and distribution of propane. The purchase also included natural gas distribution investments in Mexico. We currently have a signed agreement to sell these Mexico assets. The gas distribution assets are operated under TGS.

Regulatory - On January 30, 2004, the Oklahoma Corporation Commission (OCC) approved a plan allowing Oklahoma Natural Gas Company (ONG) annual rate relief of $17.7 million in order to recover expenses related to its investment in service lines and cathodic protection, an increased level of uncollectible revenues, and a return on ONG’s investment in gas in storage. The Commission’s order also approved a modified distribution main extension policy and authorized ONG to defer homeland security costs ONG expects to incur in the future. The plan authorized the new rates to be in effect for a maximum of 18 months and categorized $10.7 million of the annual additional revenues as interim and subject to refund until a final determination at ONG’s next general rate case. Approximately $7.0 million annually is considered final and not subject to refund. ONG has committed to filing for a general rate review no later than January 31, 2005.

Our current estimate of the future rate relief is substantially in excess of the refund threshold of $10.7 million. We believe it is highly unlikely any refund obligation exists and, accordingly, have not recorded a reserve. We will continue to monitor the regulatory environment to determine any changes in our estimated future rate relief and, should our analysis indicate a potential refund liability, we will record a reserve for the obligation.

Impact of New Accounting Standards - In January 2004, the FASB issued FASB Staff Position No. FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP FAS 106-1) as preliminary guidance on how employers should account for provisions of the recently enacted Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Reform Act). The Medicare Reform Act allows employers who sponsor a postretirement health care plan that provides a prescription drug benefit to receive a subsidy for the cost of providing that drug benefit. In order for employers to receive the subsidy payment under the Medicare Reform Act, the value of the offered prescription drug plan must be actuarially equivalent to the standard prescription drug coverage provided under Medicare Part D. Due to our lower deductibles and better coverage of drug costs, we believe that our plan is of greater value than Medicare Part D and will meet the actuarially equivalent definitions. As permitted by FSP FAS 106-1, we made a one-time election to account for the subsidy in our financial statements. Since we use a September 30 measurement date, we were required to make the election no later than March 31, 2004. Our quarterly expense for the three months ended March 31, 2004 was not affected by this change. Subsequent quarters will reflect the expected reduction in annual expenses. Accordingly, we expect our accumulated postretirement benefit obligation to decrease by approximately $18 million and our postemployment benefit expense to decrease by approximately $2.7 million for the remainder of 2004. These amounts are based on preliminary estimates that are dependent on interpretative regulations not yet available, and therefore, subject to change. We believe that our plan will continue to provide drug benefits that are actuarially equivalent to Medicare Part D, that our plan will continue to be the primary plan for our retirees and that we will receive the subsidy. We do not expect that the Medicare Act will have a significant effect on our retirees’ participation in our postretirement benefit plan.

In December 2003, the FASB issued FASB Interpretation No. 46R “Consolidation of Variable Interest Entities” (FIN 46R) that addresses the consolidation of variable interest entities. FIN 46R is applicable to variable interest entities or potential variable interest entities commonly referred to as special purpose entities by the end of the first reporting period ending after December 15, 2003. FIN 46R had no impact on our consolidated financial statements at March 31, 2004.

Critical Accounting Policies and Estimates

Energy Trading Derivatives and Risk Management Activities - We engage in wholesale marketing and trading, price risk management activities and asset optimization services. In providing asset optimization services, we partner with other utilities to provide risk management functions on their behalf. We account for derivative instruments utilized in connection with these activities under the fair value basis of accounting in accordance with Statement 133 as amended by Statement of Financial Accounting Standards No. 137, “Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133” (Statement 137), No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities” (Statement 138) and No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (Statement 149). We were not impacted by Statement 149.

Under Statement 133, entities are required to record all derivative instruments in price risk management assets and liabilities at fair value. A number of assumptions are considered in the determination of fair value. Our derivatives are primarily concentrated in exchange-traded and over-the-counter markets where quoted prices in liquid markets exist. Transactions are also executed in exchange-traded or over-the-counter markets for which market prices may exist but the market may be relatively inactive thereby resulting in limited price transparency that requires management’s subjectivity in estimating fair values. Other factors impacting our estimates of fair value include volatility, time value, counterparty credit and the potential impact on market prices of liquidating positions in an orderly manner over a reasonable period of time under current market conditions. Refer to the table on page 41 for amounts in our portfolio at March 31, 2004 that were determined by prices actively quoted (exchange-traded), prices provided by other external sources (over-the-counter), and prices derived from other sources. The gain or loss from changes in fair value is recorded in the period of the change. The volatility of commodity prices may have a significant impact on the gain or loss in any given period. For more information on fair value sensitivity and a discussion of the market risk of pricing changes, see Item 3, Quantitative and Qualitative Disclosures About Market Risk.

Energy-related contracts that are not accounted for pursuant to Statement 133 are no longer carried at fair value, but are accounted for on an accrual basis as executory contracts. Energy trading inventories carried under storage agreements are no longer carried at fair value, but are carried at the lower of cost or market. Changes to the accounting for existing contracts as a result of the rescission of Emerging Issues Task Force Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (EITF 98-10) were reported as a cumulative effect of a change in accounting principle on January 1, 2003. This resulted in a cumulative effect loss, net of tax, of $141.8 million.

Regulation - Our intrastate transmission pipelines and distribution operations are subject to the rate regulation and accounting requirements of the OCC, Kansas Corporation Commission (KCC), RRC and various municipalities in Texas. Certain of our other transportation activities are subject to regulation by the FERC. ONG, Kansas Gas Service Company (KGS), TGS and portions of the Transportation and Storage segment follow the accounting and reporting guidance contained in Statement 71. During the rate-making process, regulatory authorities 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. Accordingly, actions of the regulatory authorities could have an effect on the amount recovered from rate payers. Any difference in the amount recoverable and the amount deferred would be recorded as income or expense at the time of the regulatory action. If all or a portion of the regulated operations becomes no longer subject to the provision of Statement 71, a write-off of regulatory assets and stranded costs may be required. At March 31, 2004, our regulatory assets totaled $208.7 million.

Impairment of Goodwill and Long-Lived Assets - We assess our goodwill for impairment at least annually based on Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets” (Statement 142). An initial assessment is made by comparing the fair value of the operations with goodwill, as determined in accordance with Statement 142, to the book value. If the fair value is less than the book value, an impairment is indicated and we must perform a second test to measure the amount of the impairment. In the second test, we calculate the implied fair value of the goodwill by deducting the fair value of all tangible and intangible net assets of the operations associated with the goodwill from the fair value determined in step one of the assessment. If the carrying value of the goodwill exceeds this calculated implied fair value of the goodwill, an impairment charge is recorded. See Note F of the Notes to Consolidated Financial Statements in this Form 10-Q.

We assess our long-lived assets for impairment based on Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (Statement 144). A long-lived asset is tested for impairment whenever events or changes in circumstances indicate that its carrying amount may exceed its fair value. Fair values are based on sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the assets.

Examples of long-lived asset impairment indicators include:

•

significant and long-term declines in commodity prices

•

a major accident affecting the use of an asset

•

part or all of a regulated business no longer operating under Statement 71

•

a significant decrease in the rate of return for a regulated business

Pension and Postretirement Employee Benefits - We have a defined pension plan covering substantially all full-time employees and a postretirement employee benefits plan covering most employees. Our actuarial consultant, in calculating the expense and liability related to these plans, uses statistical and other factors that attempt to anticipate future events. These factors include assumptions about the discount rate, expected return on plan assets, rate of future compensation increases, age and employment periods. Assumptions used in determining the projected benefit obligations and the costs can change from period to period which could result in material changes in the costs and liabilities we recognize. See Note I of the Notes to Consolidated Financial Statements in this Form 10-Q.

Contingencies - Our accounting for contingencies covers a variety of business activities including contingencies for potentially uncollectible receivables, legal exposures and environmental exposures. We accrue these contingencies when our assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered and an amount can be reasonably estimated in accordance with Statement of Financial Accounting Standards No. 5, “Accounting for Contingencies”. We base our estimates on currently available facts and our projections of the ultimate outcome or resolution. Actual results may differ from our estimates resulting in an impact, positive or negative, on earnings.

For further discussion of our accounting policies, see Note A of Notes to the Consolidated Financial Statements in this Form 10-Q.

Consolidated Operations

The following table sets forth certain selected consolidated financial information for the periods indicated.


	Three Months Ended March 31,
	2004		2003
	*(Thousands of Dollars)*
Financial Results
Operating revenues, excluding energy trading revenues	$	955,311	$	951,039
Energy trading revenues, net		75,264		135,671
Cost of gas		637,816		683,758

Net revenues		392,759		402,952
Operating costs		150,911		130,088
Depreciation, depletion, and amortization		46,740		40,427

Operating income	$	195,108	$	232,437

Other income	$	7,814	$	854
Other expense	$	7,590	$	113

Discontinued operations, net of taxes (Note C)
Income from discontinued component	$	—	$	2,342
Gain on sale of discontinued component	$	—	$	38,369

Cumulative effect of a change in accounting principle, net of tax	$	—	$	(143,885	)

Operating Results - Changes in commodity prices can have a significant impact on our earnings, particularly in our Gathering and Processing segment. Volatility in prices, such as we experienced in the early part of 2003, provides the opportunity for increased margins in our Marketing and Trading segment. Net revenues decreased for the three months ended March 31, 2004 compared to the same period in 2003 primarily due to reduced volatility in natural gas prices partially offset by increases in our

Distribution, Production and Gathering and Processing segments due to rate relief, higher volumes sold and lower cost of sales, respectively.

Operating costs increased for the three months ended March 31, 2004 compared to the same period in 2003, primarily due to:

•

increased employee and contractor costs of $6.4 million in our Distribution segment

•

increased bad debt expense of $4.4 million in our Distribution segment

•

increased production costs of $4.2 million related primarily to our Production segment’s December 2003 acquisition

Depreciation, depletion and amortization increased for the three months ended March 31, 2004 compared to the same period in 2003, primarily due to:

•

additional depreciation of $3.9 million resulting from the new gas and oil properties acquired in December 2003

•

regulatory asset amortization resulting from the Kansas and Oklahoma rate cases

The following tables show the components of other income and other expense for the three months ended March 31, 2004 and 2003.


	Three Months Ended March 31,
	2004		2003
	*(Thousands of Dollars)*
Gains on sale of property	$	6,964	$	289
Partnership income		324		414
Interest income		231		378
Other		295		(227	)

Other income	$	7,814	$	854


	Three Months Ended March 31,
	2004		2003
	*(Thousands of Dollars)*
Litigation expenses and claims, net	$	6,995	$	(967	)
Donations, civic, and governmental		588		429
Other		7		651

Other expense	$	7,590	$	113

In 2002, we sold our claims related to the Enron bankruptcy. In 2004, we were required to repurchase a portion of those claims resulting in an expense of approximately $1.8 million related to the decrease in value of the claims.

More information regarding our results of operations is provided in the discussion of each segment’s results. The discontinued component is discussed in our Production segment discussion and the cumulative effect of a change in accounting principle is discussed in our Marketing and Trading segment discussion.

Production

Overview - Our Production segment currently owns, develops and produces natural gas and oil reserves in Oklahoma and Texas. We focus on development activities rather than exploratory drilling.

As a result of our strategy to grow through acquisitions and developmental drilling, the number of wells we operate increases as we grow our reserves. In our role as operator, we control operating decisions that impact production volumes and lifting costs. We continually focus on reducing finding costs and minimizing production costs.

Acquisition and Divestiture - The following acquisition and divestiture are described beginning on page 23:

•

purchased gas and oil properties and related flow lines in December 2003

•

sold natural gas and oil producing properties in January 2003

Development Activities - Through our developmental drilling program, we participated in drilling 45 wells during the three months ended March 31, 2004. Eleven wells were completed as producing gas wells, while 34 were still drilling or completing at the end of the period. We participated in drilling 13 wells for the three months ended March 31, 2003. Four were completed, while nine were still drilling or completing at the end of the period. There were no dry holes in either period.

Selected Financial and Operating Information - The following tables set forth certain financial and operating information for our Production segment for the periods indicated.


	Three Months Ended March 31,
	2004			2003
	*(Thousands of Dollars)*
Financial Results
Natural gas sales	$	22,766		$	9,579
Oil sales		2,556			2,335
Other revenues		1,065			731

Net revenues		26,387			12,645
Operating costs		8,024			3,610
Depreciation, depletion, and amortization		6,501			3,358

Operating income	$	11,862		$	5,677

Other income (expense), net	$	(26	)	$	(11	)

Discontinued operations, net of taxes (Note C)
Income from discontinued component	$	—		$	2,342
Gain on sale of discontinued component	$	—		$	38,369

Cumulative effect of change in accounting principle, net of tax	$	—		$	117


	Three Months Ended March 31,
	2004			2003
Operating Information
Proved reserves
Continuing operations
Gas (MMcf)		216,808			61,800
Oil (MBbls)		4,138			2,399
Production
Continuing operations
Gas (MMcf)		4,243			1,832
Oil (MBbls)		86			77
Discontinued component
Gas (MMcf)		—			1,472
Oil (MBbls)		—			53
Average realized price (a)
Continuing operations
Gas ($/Mcf)	$	5.36		$	5.23
Oil ($/Bbls)	$	29.60		$	30.32
Discontinued component
Gas ($/Mcf)	$	—		$	4.10
Oil ($/Bbls)	$	—		$	32.28
Capital expenditures (Thousands)
Continuing operations	$	8,472		$	2,948


(a) Average realized price reflects the impact of hedging activities.

All proved undeveloped reserves are attributed to locations directly offsetting (adjacent to) existing production.

Operating Results - Natural gas sales increased for the three months ended March 31, 2004 compared to the same period in 2003 due to:

•

higher volumes produced

•

higher prices received on hedged volumes

The increase in gas production resulted from the Texas properties acquisition in December 2003 that produced 2.5 Bcf of gas during the three months ended March 31, 2004. Average gas prices after hedges for the three months ended March 31, 2004 increased to $5.36 per Mcf compared to $5.23 per Mcf for the same period in 2003. Prices for the same periods before hedges were $5.55 per Mcf in 2004 and $6.24 per Mcf in 2003.

Oil sales increased for the three months ended March 31, 2004 compared to the same period in 2003 due to higher oil volumes resulting from the Texas properties acquisition which produced approximately 35,000 Bbls of oil during the three months ended March 31, 2004.

Other revenues increased for the three months ended March 31, 2004 as the result of the flow line fees and revenues from the Texas flow line system purchased in December 2003.

Operating costs increased for the three months ended March 31, 2004 compared to the same period in 2003 due to the:

•

increase of $1.9 million related to higher overhead costs primarily as a result of the December 2003 acquisition

•

increase of $1.2 million in lease operating costs as a result of the December 2003 acquisition

•

increase of $1.1 million in production taxes as a result of higher production

Depreciation, depletion and amortization increased $3.1 million for the three months ended March 31, 2004 compared to the same period in 2003 primarily due to the new properties acquired in December 2003.

The Production segment added 4.9 Bcfe of net natural gas and oil reserves for the three months ended March 31, 2004. This included 1.0 Bcfe of proved developed reserves, comprised of 0.3 Bcfe of proved developed producing and 0.7 Bcfe of proved developed non-producing.

Discontinued Component - Income from the discontinued component includes only one month of production in 2003 before the properties were sold.

Capital Expenditures - Capital expenditures primarily relate to our developmental drilling program. Production from existing wells naturally declines over time and additional drilling for existing wells is necessary to maintain or enhance production from existing reserves.

Risk Management - The volatility of energy prices has a significant impact on the profitability of this segment. We utilized derivative instruments for the three months ended March 31, 2004 and 2003, in order to hedge anticipated sales of natural gas and oil production. The realized financial impact of the derivative transactions is included in net revenues. For the remainder of 2004, we have hedged approximately 87 percent of our anticipated natural gas production at an average net price at the wellhead of $5.28 per Mcf, and approximately 92 percent of our anticipated oil production at a fixed New York Mercantile Exchange (NYMEX) price of $30.35 per Bbl. Currently, we have hedges on 20 MMcf per day of our 2005 natural gas production at a net wellhead price of $5.68 per Mcf. We have also hedged an additional 10 MMcf per day for the first quarter of 2005 at a net wellhead price of $6.12 per Mcf.

Gathering and Processing

Overview - The Gathering and Processing segment is engaged in the gathering, processing and marketing of natural gas and the fractionation (separation), storage and marketing of natural gas liquids (NGLs). Our Gathering and Processing segment has a processing capacity of approximately 1.9 Bcf/d, of which approximately 0.1 Bcf/d is currently idle. Our Gathering and Processing segment owns approximately 13,800 miles of gathering pipelines that supply our gas processing plants.

The gas processing operation primarily includes the extraction of mixed NGLs from natural gas and the fractionation of mixed NGLs into component products (ethane, propane, isobutane, normal butane and natural gasoline). We generally process gas under three types of contracts. The following table sets forth our risk adjusted contract mix on a volumetric basis for the periods indicated.


	Three Months Ended March 31,
	2004		2003
Contract Type
Fee	46	%	48	%
Percent of Proceeds	31	%	27	%
Keep Whole	23	%	25	%

Characteristics of the contract types are:

•

The fee contract exposes us to little commodity risk because we are paid a fee to gather, compress, dehydrate and process the gas.

•

Under a percent of proceeds (POP) contract, we are paid by keeping a percent of the residue natural gas and NGLs that are extracted at the plant while sharing in the fuel and shrink costs with the producer. The POP contract exposes us to both natural gas and NGL commodity price risk, but puts the producer and us in alignment because we both benefit from higher commodity prices.

•

Under a keep whole contract, we retain 100% of the NGLs extracted and bear 100% of the costs incurred to extract the NGLs and pay the producer for the gas used to make the NGLs. This is commonly referred to as the keep whole spread.

We have been successful in amending contracts covering about 15 percent of the volume associated with our keep whole contracts to allow us to charge conditioning fees for processing when the keep whole spread is negative. This amendment helps mitigate the impact of unfavorable keep whole spreads between the two commodities by effectively converting a keep whole contract to a fee contract during periods of negative keep whole spreads. Our effort to add this conditioning language began in 2002 and remains a strategy that we continue to execute today. Our goal is to have this conditioning language in contracts covering 75 percent of our keep whole volumes within five years. We are also continuing our strategy of restructuring any unprofitable gas purchase and gathering contracts.

Additionally, we are able to modify plant operations to take advantage of market conditions. By changing operations such as rerouting gas around or through the plant or changing the temperatures and pressures at which the gas is processed, we can produce more of the specific commodities that have the most favorable price spread. These strategies are intended to decrease the volatility of our net revenues.

We are exposed to volume risk from both a competitive and a production standpoint. We continue to see increasing declines in the fields that feed our gathering and processing operations and the possibility exists that declines may outpace development from new drilling. The factors that typically affect our ability to compete are the fees charged under the contract, pressures maintained on the gathering systems, location of the gathering systems relative to our competitors, efficiency and reliability of operations and the delivery capabilities that exist at each plant location.

Acquisition - The following acquisition is described beginning on page 23:

•

acquired NGL storage and pipeline facilities located in Conway, Kansas in December 2003

Selected Financial and Operating Information - The following tables set forth certain selected financial and operating information for our Gathering and Processing segment for the periods indicated.


	Three Months Ended March 31,
	2004			2003
	*(Thousands of Dollars)*
Financial Results
Natural gas liquids and condensate sales	$	274,551		$	305,736
Gas sales		154,266			210,454
Gathering, compression, dehydration and processing fees and other revenues		22,592			24,594
Cost of sales		391,983			494,457

Net revenues		59,426			46,327
Operating costs		30,964			31,263
Depreciation, depletion, and amortization		8,013			7,201

Operating income	$	20,449		$	7,863

Other income (expense), net	$	(5	)	$	(11	)

Cumulative effect of a change in accounting principle, net of tax	$	—		$	(1,375	)


	Three Months Ended March 31,
	2004			2003
Operating Information
Total gas gathered (MMMBtu/d)		1,106			1,208
Total gas processed (MMMBtu/d)		1,164			1,216
Natural gas liquids sales (MBbls/d)		111			129
Natural gas liquids produced (MBbls/d)		61			54
Gas sales (MMMBtu/d)		315			351
Capital expenditures (Thousands)	$	4,077		$	2,472
Conway OPIS composite NGL Price ($/gal) (based on our NGL product mix)	$	0.62		$	0.63
Average NYMEX crude oil price ($/Bbl)	$	34.40		$	33.99
Average natural gas price ($/MMBtu) (mid-continent region)	$	5.22		$	6.09

Operating Results - The decrease in cost of sales for the three months ended March 31, 2004 compared to the same period in 2003 more than offset decreases in revenues for the same period resulting in an increase in net revenues for the period.

•

NGL and condensate sales decreased primarily due to reduced third party sales volumes and decreased NGL prices, which were partially offset by higher condensate prices.

•

Gas sales and cost of sales decreased primarily due to a decrease in natural gas prices.

•

Natural gas sales volumes decreased and NGLs produced increased in the first quarter of 2004 because market conditions favored NGL production. In the first quarter of 2003 market conditions favored gas sales.

•

Gathering, compression, dehydration, processing fees and other revenues decreased due to lower natural gas prices and lower volumes gathered and processed as a result of natural field declines.

•

Gas volumes gathered and processed decreased mainly due to natural field declines, bypassing of certain non-processable gas at our plants and the termination of low margin gas purchase agreements.

Net revenues increased primarily as a result of improved keep whole spread conditions in 2004 compared to 2003 and better contractual terms for gas gathering and processing.

Operating costs were relatively flat for the three months ended March 31, 2004 compared to same period in 2003.

Depreciation, depletion and amortization increased for the three months ended March 31, 2004 compared to the same period in 2003 primarily due to the properties acquired and our normal capital expenditure program.

Risk Management - We used derivative instruments during the three months ended March 31, 2004 and 2003 to minimize risk associated with price volatility. The realized financial impact of the derivative transactions is included in our operating income. No hedges were in place at either March 31, 2004 or 2003.

Transportation and Storage

Overview - Our Transportation and Storage segment operates our intrastate natural gas transmission pipelines, natural gas storage and nonprocessable gas gathering facilities. We also provide interstate transportation service under Section 311(a) of the Natural Gas Policy Act. We own or reserve capacity in five storage facilities in Oklahoma, three in Kansas and three in Texas, with a combined working capacity of approximately 59.6 Bcf, of which 8.0 Bcf is temporarily idle. We have significant supply and market connections to 68 pipelines, 34 processing plants and seven producing fields.

We operate approximately 5,400 miles of gathering and intrastate transmission pipelines in Oklahoma, Kansas and Texas and are regulated by the OCC, KCC, and RRC, respectively. We have a peak transportation capacity of 2.9 Bcf per day. The majority of our segment’s revenues are derived from services provided to affiliates. We serve local distribution companies (LDCs), large industrial companies, power generation facilities and marketing companies. We compete directly with other interstate and intrastate pipelines and storage facilities. Competition for transportation services continues to increase as the FERC and state regulatory bodies continue to encourage more competition in the natural gas markets. Factors that affect competition are location, natural gas price, fees for services and quality of service provided.

Our business is affected by the economy, price volatility and weather. Transportation quantities fluctuate due to rainfall that impacts irrigation demand, hot temperatures that affect power generation demand and cold temperatures that affect heating demand. Increased price volatility in today’s natural gas market also impacts our customers’ decisions relating to injection and withdrawal of natural gas in storage.

Acquisition and Divestitures - The following acquisition and divestitures are described beginning on page 23:

•

sold transmission and gathering pipelines and compression in March 2004

•

sold Texas transmission assets in October 2003

•

acquired transmission assets as part of the purchase of our Texas assets in January 2003

Selected Financial and Operating Information - The following tables set forth certain selected financial and operating information for the Transportation and Storage segment for the periods indicated.


	Three Months Ended March 31,
	2004		2003
	*(Thousands of Dollars)*
Financial Results
Transportation and gathering revenues	$	26,116	$	27,485
Storage revenues		10,848		9,067
Gas sales and other		1,463		1,998
Cost of fuel and gas		7,962		8,405

Net revenues		30,465		30,145
Operating costs		12,749		10,866
Depreciation, depletion, and amortization		4,264		4,154

Operating income	$	13,452	$	15,125

Other income (expense), net	$	1,912	$	513

Cumulative effect of a change in accounting principle, net of tax	$	—	$	(645	)


	Three Months Ended March 31,
	2004		2003
Operating Information
Volumes transported (MMcf)		128,935		144,980
Capital expenditures (Thousands)	$	2,044	$	984
Average natural gas price ($/MMBtu) (mid-continent region)	$	5.22	$	6.09

Operating results - Net revenues showed little change for the three months ended March 31, 2004 compared to the same period in 2003.

•

Transportation and gathering revenues decreased slightly primarily due to decreased volumes transported that resulted from milder weather and decreased natural gas prices that impacted the valuation of retained fuel.

•

Storage revenues increased due to additional spot storage transactions associated with favorable market conditions as a result of milder weather and favorable forward pricing. These increases were partially offset by the lower natural gas prices and its impact on the valuation of retained fuel.

•

Cost of fuel and gas decreased primarily due to decreased volumes transported and lower natural gas prices. These decreases were partially offset by higher fuel costs from the additional storage activity.

Operating costs for the three months ended March 31, 2004 compared to the same period in 2003 increased primarily due to increases in:

•

legal costs associated with pending litigation

•

contract labor costs

•

employee costs

These increases were partially offset by lower insurance costs and ad valorem taxes.

The increase in other income, net for the three months ended March 31, 2004 compared to 2003 includes the gain on the sale of the Texas assets of $6.9 million offset by litigation costs.

Distribution

Overview - The Distribution segment provides natural gas distribution services in Kansas, Oklahoma and Texas. Operations in Kansas are conducted through KGS, which serves residential, commercial, industrial, transportation and wholesale customers. Operations in Oklahoma are conducted through ONG, which serves residential, commercial, industrial, and transportation customers, including customers that lease gas pipeline capacity. Operations in Texas are conducted through TGS, which serves residential, commercial, industrial, public authority and transportation customers. Our Distribution segment provides gas service to approximately 71 percent, 86 percent, and 14 percent of the distribution markets of Kansas, Oklahoma and Texas, respectively. KGS and ONG are subject to regulatory oversight by the KCC and OCC, respectively. TGS is subject to regulatory oversight by the various municipalities that it serves, which have primary jurisdiction in their respective areas. TGS’ rates in areas adjacent to the various municipalities and appellate matters are subject to regulatory oversight by the RRC.

Gas sales to residential and commercial customers are seasonal as a substantial portion of gas is used principally for heating. Accordingly, the volume of gas sales is consistently higher during the heating season (November through March) than in the other months of the year.

Acquisitions - The following acquisitions are described beginning on page 23:

•

acquired the gas distribution system at the United States Army’s Fort Bliss in El Paso, Texas in August 2003

•

acquired a pipeline system that extends through the Rio Grande Valley region in Texas in August 2003

•

acquired Texas gas distribution assets in January 2003

Selected Financial Information - The following table sets forth certain selected financial information for the Distribution segment for the periods indicated.


	Three Months Ended March 31,
	2004			2003
	*(Thousands of Dollars)*
Financial Results
Gas sales	$	748,726		$	662,055
Cost of gas		578,982			516,994

Gross margin		169,744			145,061
Transportation revenues		25,262			23,221
Other revenues		8,008			7,056

Net revenues		203,014			175,338
Operating costs		91,071			76,421
Depreciation, depletion, and amortization		26,219			23,888

Operating income	$	85,724		$	75,029

Other income (expense), net	$	(82	)	$	(478	)

Operating Results - The Distribution segment’s operating results are primarily impacted by the number of customers, usage and the ability to establish delivery rates that provide an authorized rate of return on our investment and cost of service. Gas costs are passed through to distribution customers based on the actual cost of gas purchased by the respective distribution division.

Substantial swings in gas sales can occur from year to year without impacting our gross margin since most factors that affect gas sales also affect cost of gas by an equivalent amount. The increase in gross margin for the three months ended March 31, 2004 compared to the same period in 2003 is primarily attributable to:

•

implementation of KGS’ new rate schedule in September 2003 which added $10 million to gross margin

•

implementation of ONG’s new rate schedule in January 2004 which added $5.8 million to gross margin

•

elimination of KGS’ WeatherProof Bill program in December 2003 which added $9.0 million to gross margin

The $10.0 million increase in KGS’ gross margin is a result of an order issued by the KCC approving $45 million annually in rate relief. ONG’s new rate schedule, which added $5.8 million to gross margin in the three months ended March 31, 2004, is part of $17.7 million in rate relief approved by an order from the OCC. The $9.0 million negative effect of KGS’ WeatherProof Bill program on margins for the first quarter of 2003 reversed in the second and third quarters of 2003.

Operating costs increased for the three months ended March 31, 2004 compared to the same period in 2003 primarily due to:

•

increased employee and contractor costs of $6.4 million

•

increased bad debt expense of $4.4 million

Depreciation, depletion and amortization increased for the three months ended March 31, 2004 compared to the same period in 2003 primarily due to regulatory asset amortization resulting from the Kansas and Oklahoma rate cases.

Selected Operating Data - The following table sets forth certain operating information for our Distribution segment for the periods indicated.


	Three Months Ended March 31,
	2004		2003
Operating Information
Average Number of Customers		2,021,496		2,011,764
Customers per employee		663		662
Capital expenditures (Thousands)	$	25,872	$	24,966


	Three Months Ended March 31,
	2004	2003
Volumes *(MMcf)*
Gas sales
Residential	66,304	67,960
Commercial	22,018	23,222
Industrial	1,021	1,543
Wholesale	4,612	3,306
Public Authority	1,262	1,254

Total volumes sold	95,217	97,285
PCL, ECT and Transportation	65,653	64,690

Total volumes delivered	160,870	161,975

Residential and commercial volumes decreased for the three months ended March 31, 2004 compared to the same period in 2003 due to:

•

warmer weather

•

commercial customers migrating to new transportation rates as a result of lower minimum transport thresholds in Oklahoma

Industrial volumes decreased for the three months ended March 31, 2004 compared to the same period in 2003 due to:

•

industrial customers migrating to transportation rates in Oklahoma

•

the current economic environment reducing overall consumption

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. Wholesale volumes increased for the three months ended March 31, 2004 compared to the same period in 2003 as fewer volumes were required to meet the needs of the Kansas residential, commercial, and industrial customers resulting in greater volumes available for wholesale customers.

Public authority volumes reflect volumes used by state agencies and school districts serviced by TGS.

The transportation volumes increased for the three months ended March 31, 2004 compared to the same period in 2003 primarily due to ONG’s commercial and industrial customers moving to transport rates and as a result of ONG’s marketing effort to add small usage transport customers.

Capital Expenditures - Our capital expenditure program includes expenditures for extending service to new areas, modifying customer service lines, increasing system capabilities, general replacements and improvements. It is our practice to maintain and periodically upgrade facilities to assure safe, reliable, and efficient operations. Our capital expenditure program included $8.8 million and $6.0 million for new business development for the three months ended March 31, 2004 and 2003, respectively.

Regulatory Initiatives

Oklahoma - On January 30, 2004, the OCC approved a plan allowing ONG an annual rate relief of $17.7 million in order to recover expenses related to its investment in service lines and cathodic protection, an increased level of uncollectible revenues, and a return on ONG’s investment in gas in storage. The Commission’s order also approved a modified distribution main extension policy and authorized ONG to defer homeland security costs ONG expects to incur in the future. The plan authorized the new rates to be in effect for a maximum of 18 months and categorized $10.7 million of the annual additional revenues as interim and subject to refund until a final determination at ONG’s next general rate case. Approximately $7.0 million annually is considered final and not subject to refund. ONG has committed to filing for a general rate review no later than January 31, 2005.

Our current estimate of the future rate relief is substantially in excess of the refund threshold of $10.7 million. We believe it is remote any refund obligation exists and, accordingly, have not recorded a reserve. We will continue to monitor the regulatory environment to determine any changes in our estimated future rate relief and, should our analysis indicate a potential refund liability, we will record a reserve for the obligation.

Kansas - On September 17, 2003, the KCC issued an order approving $45 million in rate relief for our Kansas customers pursuant to the stipulated settlement agreement with KGS. The order settled the rate case filed by KGS in January 2003 and

allowed KGS to begin operating under the new rate schedules effective September 22, 2003. After amortization of previously deferred costs, it is estimated that operating income will increase by approximately $29.6 million annually.

On June 16, 2003, KGS filed a motion with the KCC to extend the WeatherProof Bill program for an additional three years. However, as a result of notification that KGS’ contractor would not be able to provide sufficient support for the program, KGS was allowed by the KCC to withdraw its request on September 12, 2003. Accordingly, the Weatherproof Bill program ended effective December 1, 2003.

Texas - On November 12, 2003, TGS filed an appeal with the RRC based on the denial of proposed rate filing by the cities of Port Neches, Nederland and Groves, Texas. The proposed rates were implemented in May 2003, subject to refund, resulting in annual revenue relief of approximately $0.8 million. The RRC is expected to rule by July 2004.

General - Certain costs to be recovered through the ratemaking process have been recorded as regulatory assets in accordance with Statement 71. Should recovery cease due to regulatory actions, certain of these assets may no longer meet the criteria of Statement 71 and, accordingly, a write-off of regulatory assets and stranded costs may be required.

Marketing and Trading

Overview - Our Marketing and Trading segment purchases, stores, transports, markets, and trades natural gas in the retail sector in our core distribution area and the wholesale sector throughout most of the United States. We have also diversified our marketing and trading portfolio to include power and crude oil. We have a strong storage and transport position, primarily in the mid-continent region of the United States, with total transportation capacity of 1.2 Bcf/d. With total cyclical storage capacity of 82.6 Bcf, withdrawal capability of 2.3 Bcf/d and injection capability of 1.6 Bcf/d spread across 19 different facilities, we have direct access to most regions of the country and flexibility to capture volatility in the energy markets. Because of seasonal demands on natural gas for heating, this volatility is greater in the winter months. We recently extended our marketing and trading operations into leasing storage and pipeline capacity in Canada.

We continue to enhance our strategy of focusing on higher margin business, which includes providing reliable service during peak demand periods, through the use of our storage and transportation capacity.

Power - Our 300-megawatt peak electric power generating plant is located in Oklahoma 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. Because of seasonal demands for electricity for summer cooling, the demands on our power plant are more volatile in the summer months. In October 2003, we signed a tolling arrangement with a third party for their power plant in Big Springs, Texas, which is connected to our corporate owned gas transmission system. The agreement, which expires in December 2005, allows us to sell the steam and power generated from the Electric Reliability Council of Texas (ERCOT). This agreement increases our owned or contracted power capacity from 300 to 512 megawatts.

Selected Financial and Operating Information - The following tables set forth certain selected financial and operating information for the Marketing and Trading segment for the periods indicated.


	Three Months Ended March 31,
	2004			2003
	*(Thousands of Dollars)*
Financial Results
Energy trading revenues, net	$	75,264		$	135,671
Power sales		35,047			12,238
Cost of power and fuel		35,214			10,704
Other revenues		237			296

Net revenues		75,334			137,501
Operating costs		10,553			9,103
Depreciation, depletion, and amortization		1,391			1,462

Operating income	$	63,390		$	126,936

Other income (expense), net	$	(1,694	)	$	(1,568	)

Cumulative effect of changes in accounting principle, net of tax	$	—		$	(141,982	)


	Three Months Ended March 31,
	2004			2003
Operating Information
Natural gas marketed (MMcf)		286,487			315,937
Natural gas gross margin ($/Mcf)	$	0.20		$	0.35
Electricity marketed (MMwh)		784			290
Physically settled volumes (MMcf) (a)		540,104			577,435
Capital expenditures (Thousands)	$	110		$	83

(a)

This represents the absolute value of gross transaction volumes for both buy and sell energy trading contracts that were physically settled.

Operating Results - Marketing and Storage activities include revenues from storage and transportation contracts, peaking services and fixed-price and basis risk management activities. Marketing and Storage activities decreased during the three months ended March 31, 2004 compared to the same period in 2003. Storage revenues were lower as a result of lower intra-month price volatility. However, this decrease was partially offset as the lower natural gas price volatility enabled us to retain additional reservation fees associated with our peaking service in 2004 compared to same period in 2003.

Trading of Crude, Power and Natural Gas, which includes net gains and losses on energy trading contracts (derivative contracts subject to fair value accounting) and all power related activity, decreased for the three months ended March 31, 2004 compared to the same period in 2003. These activities decreased due to decreases in natural gas price volatility and inter-region basis spreads that exist between the Rocky Mountain and mid-continent trading locations. Included in our net revenues is the change in value of our derivative contracts subject to fair value accounting, which decreased $14.7 million from the three months ended March 31, 2003 to the three months ended March 31, 2004. Power trading margins also decreased due to comparatively weaker spark spreads in the Southwest Power Pool while overall sales and purchases increased due to our Big Springs tolling agreement. The Big Springs tolling agreement margins are expected to increase in the second and third quarters due to the seasonality of the heat rate (ratio of the Btu content of the fuel burned compared to the power generated, normally, expressed in Megawatts).

Natural gas sales volumes decreased for the three months ended March 31, 2004 compared to the same period in 2003 due to:

•

milder temperatures

•

a decrease in storage withdrawals of approximately 40 percent due to market conditions

The reduced storage withdrawals resulted in 33 Bcf of gas in storage at March 31, 2004.

Operating costs increased for the three months ended March 31, 2004 compared to same period in 2003 primarily due to:

•

increased employee costs

•

increased costs associated with our Canadian operations

Liquidity and Capital Resources

General - Part of our strategy is to grow through acquisitions that strengthen and complement our existing assets. We have relied primarily on operating cash flow, borrowings from commercial paper and bank lines of credit, and issuance of debt and equity in the 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. We have no material guarantees of debt or other commitments to unaffiliated parties. During 2003 and through the first quarter of 2004, our capital expenditures were financed through operating cash flows and short and long-term debt. Capital expenditures for 2004 are expected to be $270 million to $280 million compared to $215 million in 2003.

Financing - Financing is provided through our commercial paper program, long-term debt and, as needed, through a revolving credit facility. Other options to obtain financing include, but are not limited to, issuance of equity, issuance of mandatorily convertible debt securities, issuance of trust preferred securities by ONEOK Capital Trust I or ONEOK Capital Trust II, asset securitization and the sale/leaseback of facilities.

Credit Rating - Our credit rating is currently an “A-” (stable outlook) by Standard and Poors and a “Baa1” (negative outlook) by Moody’s Investor Service. 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 assessing our credit rating are the debt to capital ratio, pre-tax and after-tax interest coverage and liquidity. If our credit ratings 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, which expires September 20, 2004. We expect the revolving credit facility to be renewed upon expiration.

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 activities could be significantly limited. Without an investment grade rating, we would be required to fund margin requirements with the few counterparties with which we have a Credit Support Annex within our International Swaps and Derivatives Association Agreements with cash, letters of credit or other negotiable instruments. At March 31, 2004, the total notional amount that could require such funding in the event of a credit rating decline to below investment grade is approximately $53.3 million.

We have reviewed our commercial paper agreement, trust indentures, building leases, equipment leases, and marketing, trading and risk contracts and no rating triggers were identified. Rating triggers are defined as provisions that would create an automatic default or acceleration of indebtedness based on a change in our credit rating. The revolving credit agreement contains a provision that would cause the cost to borrow funds to increase based on the amount borrowed under this agreement if our credit rating is negatively adjusted. The credit agreement also contains a default provision based on a material adverse change. An adverse rating change is not defined as a default or material adverse change. We currently do not have any funds borrowed under this credit agreement.

Commodity Prices - We are subject to commodity price volatility. Significant fluctuations in commodity prices in either physical or financial energy contracts may impact our overall liquidity due to the impact a commodity price change has on items such as the cost of NGLs and gas held in storage, recoverability and timing of recovery, 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.

Pension Plan - Our pension plan is currently overfunded resulting in an asset reported on our balance sheet. Due to the previous poor performance of the equity market and lower interest rates at our plan valuation date of September 30, 2003, the market value of our pension fund assets has decreased and, accordingly, our pension credit for our pension and supplemental retirement plans will decrease in 2004 from $4.4 million to $1.9 million. Should the value of our pension fund assets fall below our accumulated benefit obligation, we would eliminate the asset and record a minimum pension liability on the balance sheet with the difference flowing through other comprehensive income, net of tax. We believe we have adequate resources to fund our obligations under our pension plan.

Cash Flow Analysis

Operating Cash Flows - Operating cash flows increased by $113.2 million for the three months ended March 31, 2004 compared to the same period in 2003, despite a significant decrease in income from continuing operations. The primary impact on operating cash flows resulted from changes in working capital, much of which relates to decreases in gas in storage. Weather can have a significant impact on gas inventory levels. Warmer weather at the end of 2003 resulted in higher than normal inventory levels. During the first quarter of 2004, the withdrawal of inventory from storage reduced our gas inventory levels and positively impacted our operating cash flows.

Decreases in deposits, or margin requirements, by our Marketing and Trading segment had a positive impact on our 2004 operating cash flows. Changes in other assets and liabilities reflect expenditures or recognition of liabilities for insurance costs, salaries, taxes other than income, and other similar items. Period-to-period fluctuations in these accounts reflect changes in the timing of payments or recognition of liabilities and are not directly impacted by seasonal factors.

From December 31, 2002 to March 31, 2003, accounts receivable and accounts payable increased due to increased commodity prices throughout the first quarter of 2003 and the addition of the Texas distribution assets.

Investing Cash Flows - Proceeds from the sale of certain natural gas transmission and gathering pipelines and compression assets totaled $13 million.

Acquisitions in the first quarter of 2003 represent the cash purchase of our Texas distribution assets. Cash provided by investing activities of discontinued operations represents the sale of natural gas and oil producing properties for a cash sales price of $294 million, including adjustments, of which $281 million was received in 2003 and the remaining amount was received in the prior year.

Financing Cash Flows - The following table sets forth our capitalization structure for the periods indicated.


	March 31, 2004		December 31, 2003
Long-tem debt	56	%	60	%
Equity	44	%	40	%

Debt (including Notes payable)	56	%	67	%
Equity	44	%	33	%

At March 31, 2004, we had $1.9 billion of long-term debt outstanding, including current maturities. As of March 31, 2004, we could have issued $2.1 billion of additional long-term debt under the most restrictive provisions contained in our various borrowing agreements. During the first quarter, we paid off $600 million in notes payable using cash generated from operating activities and proceeds from our February 2004 equity offering.

Both Standard and Poors and Moody’s Investment Services consider the equity units we issued in January 2003 to be part equity and part debt. For purposes of computing capitalization ratios, these rating agencies adjust the capitalization structure. Standard and Poors considers the equity units to be equal amounts of debt and equity for the first three years, with the effect being to increase shareholders’ equity by the same amount as long-term debt, which would result in a capitalization structure of 50 percent long-term debt and 50 percent equity at March 31, 2004. Moody’s Investment Services considers 25 percent of the equity units to be long-term debt and 75 percent to be shareholders’ equity, which would result in a capitalization structure of 47 percent long-term debt and 53 percent equity at March 31, 2004.

Our $850 million revolving credit facility was renewed September 22, 2003. The new facility expires in September 2004 and includes a term-out option, which allows us to convert any outstanding borrowings under the credit agreement into a 364-day term note at the expiration of the credit agreement. This facility is primarily used to support our commercial paper program. At March 31, 2004, we had no commercial paper outstanding and approximately $22 million in temporary investments.

During the first quarter of 2004, we sold 6.9 million shares of our common stock to an underwriter at $21.93 per share, resulting in proceeds to us, before expenses of $151.3 million.

We terminated $670 million of our interest rate swap agreements in the first quarter of 2004 to lock-in savings and generate a positive cash flow of $91.8 million, which included $8.9 million of interest savings previously recognized. These interest rate

swaps were previously initiated as a strategy to hedge the fair value of fixed rate long-term debt. The proceeds received upon termination of the interest rate swaps, net of amounts previously recognized, will be recognized in the income statement over the term of the debt instruments originally hedged.

During the first quarter of 2003, we issued a total of 16.1 million equity units. Each equity unit consists of a stock purchase contract for the purchase of shares of our common stock and, initially, a senior note due February 16, 2008, issued pursuant to our existing Indenture with SunTrust Bank, as trustee. The number of shares that we will issue for each stock purchase contract issued as part of the equity units will be determined based on our average closing price over the 20-trading day period ending on the third trading day prior to February 16, 2006. If this average closing price:

•

equals or exceeds $20.63, we will issue 1.2119 shares of our common stock for each purchase contract or unit;

•

equals or is less than $17.19, we will issue 1.4543 shares of our common stock for each purchase contract or unit;

•

is less than $20.63 but greater than $17.19, we will determine the number of shares of our common stock to be issued by multiplying the number of purchase contracts or units by the ratio of $25 divided by the 20-trading day average closing price.

Forward Looking Statements and Risk Factors

Some of the statements contained and incorporated in this 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 anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of 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 Form 10-Q identified by words such as “anticipate,” “estimate,” “expect,” “intend,” “believe,” “projection” or “goal.”

You should not place undue reliance on the forward-looking statements. Known and unknown risks, uncertainties and other factors 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 the 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:

•

risks associated with any reduction in our credit ratings;

•

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 or the financial condition of our trading partners;

•

economic climate and growth in the geographic areas in which we do business;

•

the uncertainty of estimates, including accruals and gas and oil reserves;

•

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, with respect to income taxes, environmental compliance, authorized rates or recovery of gas costs;

•

the impact of recently issued and future accounting pronouncements and other changes in accounting policies;

•

the possibility of future terrorist attacks or the possibility or occurrence of an outbreak of, or changes in, hostilities or changes in the political dynamics in the Middle East and elsewhere;

•

the impact of unforeseen changes in interest rates, equity markets, inflation rates, economic recession and other external factors over which we have no control, including the effect on pension expense and funding resulting from changes in stock market returns;

•

risks associated with pending or possible acquisitions and dispositions, including our ability to finance or to integrate any such acquisitions and any regulatory delay or conditions imposed by regulatory bodies in connection with any such acquisitions and dispositions;

•

the results of administrative proceedings and litigation involving the Oklahoma Corporation Commission, Kansas Corporation Commission, Texas regulatory authorities or any other local, state or federal regulatory body including the Federal Energy Regulatory Commission;

•

our ability to access capital and competitive rates on terms acceptable to us;

•

the risk of a significant slowdown in growth or a decline in the U.S. economy, the risk of delay in growth or recovery in the U.S. economy or the risk of increased costs for insurance premiums, security or other items as a consequence of the September 11, 2001, terrorist attacks; and

•

the other risks and other factors listed in the reports we have filed and may file from time to time with the Securities and Exchange Commission, which are incorporated by reference.

Other factors and assumptions not identified above were also involved in the making of the 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. We have no obligation and make no undertaking to update publicly or revise any forward-looking statements.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Our quantitative and qualitative disclosures about market risk are consistent with those discussed in our Form 10-K for the year ended December 31, 2003, except as follows.

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 March 31, 2004, KGS had no derivative instruments in place to hedge the cost of gas purchases. Gains or losses associated with the KGS hedges are included in and recoverable through the monthly purchased gas adjustment.

TGS may use derivative instruments to mitigate the volatility of gas costs to protect its customers in the city of El Paso. At March 31, 2004, TGS had no derivative instruments in place to hedge the cost of gas purchases. Gains or losses associated with the derivative instruments are included in and recoverable through the monthly purchased gas adjustment.

The following table provides a detail of our Marketing and Trading segment’s maturity of derivatives based on heating injection and withdrawal periods from April to March. Executory storage and transportation contacts and their related hedges are not included in the following table. This maturity schedule is consistent with our Marketing and Trading segment’s trading strategy.


	Fair Value of Contracts at March 31, 2004
Source of Fair Value (1)	Matures through March 2005			Matures through March 2008			Matures through March 2010			Matures after March 2010		Total Fair Value
	*(Thousands of Dollars)*
Prices actively quoted (2)	$	(83	)	$	2,091		$	—		$	—	$	2,008
Prices provided by other external sources (3)		(20,076	)		(22,741	)		(1,488	)		538		(43,767	)
Prices derived from quotes, other external sources and other assumptions (4)		(1,004	)		(210	)		674			74		(466	)

Total	$	(21,163	)	$	(20,860	)	$	(814	)	$	612	$	(42,225	)

(1)	Fair value is the mark-to-market component of forwards, swaps, and options utilized for trading activities, net of applicable reserves. 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 futures 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. Because of the large energy broker network, energy price information by location is readily available.

(4)	Values derived in this category utilize market price information from the other two categories, as well as other assumptions for liquidity and credit.

For further discussion of trading activities and assumptions used in our trading activities, see the Critical Accounting Policies in Note A and Accounting Treatment in Note D of the notes to consolidated financial statements included in this Form 10-Q.

Interest Rate and Currency Risk - At March 31, 2004, the interest rate on 59.4 percent of our long-term debt was fixed after considering the impact of interest rate swaps.

During the first quarter of 2004, we terminated $670 million of our interest rate swap agreements to lock-in savings and generate a positive cash flow of $91.8 million. These interest rate swaps were previously initiated as a strategy to hedge the fair value of fixed rate long-term debt. Included in long-term debt is $83.8 million, the value of the terminated swaps and the existing swaps. Approximately $81.9 million of this long-term debt amount is related to the terminated swaps and will be amortized to income over the following periods:


2004	$	8.1 million
2005	$	10.0 million
2006	$	10.0 million
2007	$	10.0 million
2008	$	10.0 million
Thereafter	$	33.8 million

We have entered into new swap agreements to replace the terminated agreements. Currently, $740 million of fixed rate debt is swapped to floating. The floating rate debt is based on both the three and six-month London InterBank Offered Rate (LIBOR) depending upon the swap. In the first quarter of 2004, we recorded a $1.7 million asset to recognize the interest rate swaps at fair value. Long-term debt was also increased by $1.7 million to recognize the change in fair value of the related hedged liability.

Total savings from the interest rate swaps was $8.7 million for the first quarter of 2004. The swaps are expected to generate the following savings for the remainder of the year:

•

interest expense savings of $7.5 million for remainder of 2004 related to the amortization of the swap value at termination

•

up to $22.9 million in interest savings from the new swaps based on the current LIBOR rates

A 100 basis point move in the LIBOR rate on all of our outstanding long-term debt would change interest expense by approximately $7.4 million before taxes. If interest rates changed significantly, we would take action to manage the exposure to the change. Since a specific action and the possible effects are uncertain, no change has been assumed.

With the Marketing and Trading segment’s expansion into Canada, we are subject to currency exposure. Our objective with respect to currency risk is to reduce the exposure due to exchange-rate fluctuations. We use physical forward transactions, which result in an actual two-way flow of currency on the settlement date since we exchange US dollars for Canadian dollars with another party. We have not designated these transactions for hedge accounting treatment; therefore, the gains and losses associated with the change in fair value are recorded in net revenues. At March 31, 2004, our exposure to risk from currency translation was not material.

Value-at-Risk (VAR) Disclosure of Market Risk - The potential impact on our future earnings, as measured by VAR, was $7.6 million and $4.1 million at March 31, 2004 and 2003, respectively.

The following table details the average, high and low VAR calculations.


	Three Months Ended March 31,
Value-at-Risk	2004		2003
	*(Millions of Dollars)*
Average	$	5.5	$	5.4
High	$	17.7	$	17.1
Low	$	1.6	$	2.6

The variations in the VAR data are reflective of market volatility and changes in the portfolio during the quarter.

Item 4. Controls and Procedures

Quarterly Evaluation of the Company’s Disclosure Controls - We evaluated the effectiveness of the design and operation of our disclosure controls and procedures (Disclosure Controls) as of the end of the period covered by this Quarterly Report on Form 10-Q. This evaluation (the Disclosure Controls Evaluation) was done under the supervision and with the participation of management, including our Chief Executive Officer (CEO) and Chief Financial Officer (CFO). Rules adopted by the Securities and Exchange Commission (SEC) require that in this section of this Quarterly Report on Form 10-Q we present the conclusions of the CEO and the CFO about the effectiveness of our Disclosure Controls based on and as of the date of the Disclosure Controls Evaluation.

Disclosure Controls - Disclosure Controls are procedures that are designed with the objective of ensuring that information required to be disclosed in our reports filed under the Securities Exchange Act of 1934 (Exchange Act), such as this Quarterly Report on Form 10-Q, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure Controls are also designed with the objective of ensuring that such information is accumulated and communicated to our management, including the CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

Limitations on the Effectiveness of Controls - Our management, including the CEO and CFO, does not expect that our Disclosure Controls will prevent all errors and all fraud. A control system, including our Disclosure Controls, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within a company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Over time, some controls may become inadequate because of changes in conditions, or the degree of compliance with policies or procedures that may deteriorate. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.

Scope of the Controls Evaluation - The CEO/CFO evaluation of our Disclosure Controls included a review of the controls’ objectives and design, the controls’ implementation by us and the effect of the controls on the information generated for use in this Quarterly Report on Form 10-Q. In the course of the Disclosure Controls Evaluation, we sought to identify data errors, control problems or acts of fraud and to confirm that appropriate corrective action, including process improvements, were being undertaken. This type of evaluation is done on a quarterly basis so that the conclusions concerning controls effectiveness can be reported in our Quarterly Reports on Form 10-Q and our Annual Report on Form 10-K. The overall goals of these evaluation activities are to monitor our Disclosure Controls and to make modifications as necessary. Our intent in this regard is that the Disclosure Controls will be maintained as dynamic systems that change (including with improvements and corrections) as conditions warrant.

Since the date of the Disclosure Controls Evaluation to the date of this Quarterly Report on Form 10-Q, there have been no significant changes in our internal controls or in other factors that could significantly affect our internal controls, including any corrective actions with regard to significant deficiencies and material weaknesses.

Conclusions - Based upon the Disclosure Controls Evaluation, our CEO and CFO have concluded that, subject to the limitations noted above, our Disclosure Controls are effective in providing reasonable assurance of achieving their objective of timely alerting them to material information required to be disclosed by us in periodic reports we file with the SEC.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings

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 April 5, 2004 we entered into a consent order with the Division of Environment of the Kansas Department of Health and Environment (“KDHE”) consistent with the terms of the administrative order issued by the KDHE on July 23, 2002 as discussed in our 2003 Annual Report on Form 10-K. We additionally were

ordered to reimburse the KDHE for its cost related to the investigation of the Yaggy gas storage facility incident in the amount $79 thousand.

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-0057, in the District Court of Reno County, Kansas. Two separate class action lawsuits were filed against us and several of our subsidiaries in early 2001 relating to certain gas explosions in Hutchinson, Kansas. The court certified two separate classes of claimants, which include all owners of real estate in Reno County, Kansas whose property had allegedly declined in value, and owners of businesses in Reno County whose income had allegedly suffered. The initial petitions seek recovery on behalf of the class claimants for an amount which would fully and fairly compensate all members of the class. The court has subsequently entered an order allowing the classes of claimants to amend their petitions to allege punitive damages. This matter is insured and we will vigorously defend all claims made against us. Any potential damage award is not expected to have a material adverse impact on us. Trial is set for June 2004.

Conerstone Propane Partners, L.P., et al. v. E Prime, Inc., ONEOK Energy Marketing and Trading Company, L.P., ONEOK, Inc., and Calpine Energy Services, L.P., United States District Court for the Southern District of New York, Case No. 04-CV-00758. The Company and our wholly owned subsidiary, ONEOK Energy Marketing and Trading Company, L.P., have been named as two of the defendants in the above-captioned lawsuit filed in the United States District Court for the Southern District of New York brought on behalf of persons who bought and sold natural gas futures and options contracts on the New York Mercantile Exchange during the years 2000 through 2002. The Complaint seeks class certification, actual damages in unspecified amounts for alleged violations of the Commodities Exchange Act, recovery of costs of the suit, including attorney’s fees, and other appropriate relief. The Complaint states that it is filed as a related action to a consolidation class action complaint naming a number of other defendants in the energy industry. Although it is too early to accurately evaluate this matter, based on current information available to us, we do not expect this matter to have a material adverse effect on us. We intend to vigorously defend ourselves against these claims.

Enron Corp. v. Silver Oak Capital, LLC and AG Capital Recovery Partners III, LP, Adversary Proceeding No. 03-93568, relating to Case No. 01-16034, in the United States Bankruptcy Court for the Southern District of New York. Our subsidiary, ONEOK Energy Marketing and Trading Company, L.P. (“OEMT”), has repurchased from Angelo Gordon that portion (such portion the “Repurchased Claims”) of the Enron Corp. guaranty claims (the “Guaranty Claims”) that Enron Corp. has sought to avoid in the adversary proceeding, as contemplated by the Transfer of Claims Agreement. OEMT is now providing the defense of the adversary proceeding for both the portion of the Guaranty Claims constituting the Repurchased Claims and also the portion of the Guaranty Claims still owned by Angelo Gordon. OEMT is also now responsible for enforcement of the Repurchased Claims in the Enron Corp. bankruptcy proceedings, which will likely result in an ultimate payment to OEMT of less than the amount for which it originally sold the Repurchased Claims. However, the difference between the price for which the Repurchased Claims were originally sold and the likely distribution from the Enron Corp. bankruptcy on account of the Repurchased Claims, based on information currently available to us, would not cause this matter to have a material adverse effect on the us.

Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities

Not Applicable.

Item 3. Defaults Upon Senior Securities

Not Applicable.

Item 4. Submission of Matters to Vote of Security Holders

Not Applicable.

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
3		Bylaws of ONEOK, Inc.

12		Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirement for the three months ended March 31, 2004 and 2003.

12.1		Computation of Ratio of Earnings to Fixed Charges for the three months ended March 31, 2004 and 2003.

31.1		Certification of David L. Kyle pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Certification of Jim Kneale pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1		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 (furnished only pursuant to Rule 13a-14(b)).

32.2		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 (furnished only pursuant to Rule 13a-14(b)).

Reports on Form 8-K

We filed the following Current Reports on Form 8-K during the quarter ended March 31, 2004, dated as follows:

January 15, 2004 - Announced that the Company’s board of directors declared a one-cent per share increase in the quarterly dividend to 19 cents per share of ONEOK common stock.

January 16, 2004 - Announced that the Company’s board of directors expanded the board from nine to 10 members and elected Julie H. Edwards, executive vice president-finance and administration and chief financial officer for Frontier Oil Corp. of Houston, Texas, to fill the vacancy created by the expansion.

January 22, 2004 - Announced that the Thrift Plan for Employees of ONEOK, Inc. and Subsidiaries is subject to a “blackout period,” as defined by Regulation BTR (Blackout Trading Restriction), in connection with the quarterly payment of dividends by the Company on its shares of common stock.

January 23, 2004 - Announced that Curtis Dinan was named vice president and chief accounting officer of ONEOK, Inc. and all divisions and subsidiaries.

January 28, 2004 - Announced that the Company and ONEOK Energy Marketing and Trading, LP, and entity wholly owned by the Company reached a settlement with the Commodity Futures Trading Commission (CFTC) regarding the CFTC’s investigation of the Company’s price reporting to industry trade publications.

January 30, 2004 - Announced that the Oklahoma Corporation Commission approved a plan that will allow Oklahoma Natural Gas Company, a division of ONEOK, Inc., to adjust its rates in order to recover certain costs not reflected in its current rate structure.

February 3, 2004 - Announced a public offering of the Company’s common stock.

February 4, 2004 - Announced that the Company received notice that it and its wholly owned subsidiary, ONEOK Energy Marketing and Trading Company, L.P., have been named, along with others, as defendants in a lawsuit filed in the United States District Court for the Southern District of New York brought on behalf of persons who bought and sold natural gas futures and options contracts on the New York Mercantile Exchange during the years 2000 through 2002.

February 19, 2004 - Announced that James C. Day, Chairman of the Board and Chief Executive Officer of Noble Corporation, was elected to the ONEOK, Inc. Board of Directors.

February 23, 2004 - Furnished the Company’s results of operations for the year and quarter ended December 31, 2003.

February 24, 2004 - Announced that the Company’s subsidiary, Palo Duro Pipeline Company, Inc., reached an agreement to sell certain natural gas transmission and gathering pipelines and compression to an affiliate of Houston-based Enbridge Energy Partners L.P. for approximately $13 million.

February 25, 2004 - Announced that the Company entered into an agreement to purchase the 22.5 percent general partnership interest owned by ConocoPhillips in Gulf Coast Fractionators for approximately $23 million.

March 1, 2004 - Announced that the Company’s subsidiary, Palo Duro Pipeline Company, Inc., closed the sale of certain natural gas transmission and gathering pipelines and compression to an affiliate of Houston-based Enbridge Energy Partners L.P. for approximately $13 million.

March 22, 2004 - Announced that the Thrift Plan for Employees of ONEOK, Inc. and Subsidiaries is subject to a “blackout period,” as defined in Regulation BTR (Blackout Trading Restriction), in connection with a change in two of the investment funds available to participants in the plan.

March 25, 2004 - Announced that the Company will present at Howard Weil Inc.’s 32^nd Annual Energy Conference in New Orleans on Wednesday, March 31, 2004, beginning at approximately 10:20 a.m. Central Time.

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: April 30, 2004	By:	/s/ Jim Kneale
		Jim Kneale Senior Vice President, Treasurer and Chief Financial Officer (Principal Financial Officer)