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 September 30, 2004
OR
| ¨ | Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
For the transition period from to .
Commission file number 001-13643
ONEOK, Inc.
(Exact name of registrant as specified in its charter)
| Oklahoma | 73-1520922 | |
| (State or other jurisdiction of 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 November 1, 2004, the Company had 103,412,019 shares of common stock outstanding.
QUARTERLY REPORT ON FORM 10-Q
As used in this Quarterly Report on Form 10-Q, the terms “we”, “our” or “us” mean ONEOK, Inc., an Oklahoma corporation, and its predecessors and subsidiaries, unless the context indicates otherwise.
2
Part I - FINANCIAL INFORMATION
CONSOLIDATED STATEMENTS OF INCOME
| Three Months Ended September 30, |
Nine Months Ended September 30, |
||||||||||||
| (Unaudited) |
2004 |
2003 |
2004 |
2003 |
|||||||||
| (Thousands of dollars, except per share amounts) | |||||||||||||
| Revenues |
|||||||||||||
| Operating revenues, excluding energy trading revenues |
$ | 1,709,351 | $ | 557,093 | $ | 3,282,893 | $ | 1,966,030 | |||||
| Energy trading revenues, net |
17,411 | 11,177 | 106,583 | 183,938 | |||||||||
| Total Revenues |
1,726,762 | 568,270 | 3,389,476 | 2,149,968 | |||||||||
| Cost of sales and fuel |
1,480,662 | 373,888 | 2,520,565 | 1,320,198 | |||||||||
| Net Margin |
246,100 | 194,382 | 868,911 | 829,770 | |||||||||
| Operating Expenses |
|||||||||||||
| Operations and maintenance |
124,000 | 106,433 | 368,022 | 332,996 | |||||||||
| Depreciation, depletion, and amortization |
47,307 | 40,105 | 140,273 | 120,241 | |||||||||
| General taxes |
15,290 | 16,024 | 52,399 | 50,267 | |||||||||
| Total Operating Expenses |
186,597 | 162,562 | 560,694 | 503,504 | |||||||||
| Operating Income |
59,503 | 31,820 | 308,217 | 326,266 | |||||||||
| Other income |
1,632 | 1,252 | 11,101 | 4,157 | |||||||||
| Other expense |
1,338 | 472 | 9,811 | 1,590 | |||||||||
| Interest expense |
25,248 | 24,972 | 73,885 | 78,518 | |||||||||
| Income before Income Taxes |
34,549 | 7,628 | 235,622 | 250,315 | |||||||||
| Income taxes |
13,710 | 3,033 | 91,841 | 97,565 | |||||||||
| Income from Continuing Operations |
20,839 | 4,595 | 143,781 | 152,750 | |||||||||
| 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 changes in accounting principle, net of tax |
— | — | — | (143,885 | ) | ||||||||
| Net Income |
20,839 | 4,595 | 143,781 | 49,576 | |||||||||
| Preferred stock dividends |
— | 4,000 | — | 24,211 | |||||||||
| Income Available for Common Stock |
$ | 20,839 | $ | 595 | $ | 143,781 | $ | 25,365 | |||||
| Earnings Per Share of Common Stock (Note M) |
|||||||||||||
| Basic: |
|||||||||||||
| Earnings per share from continuing operations |
$ | 0.20 | $ | 0.01 | $ | 1.42 | $ | 1.64 | |||||
| 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 |
$ | 0.20 | $ | 0.01 | $ | 1.42 | $ | 0.72 | |||||
| Diluted: |
|||||||||||||
| Earnings per share from continuing operations |
$ | 0.19 | $ | 0.01 | $ | 1.38 | $ | 1.49 | |||||
| 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 |
$ | 0.19 | $ | 0.01 | $ | 1.38 | $ | 0.57 | |||||
| Average Shares of Common Stock (Thousands) |
|||||||||||||
| Basic |
102,914 | 77,865 | 101,530 | 78,650 | |||||||||
| Diluted |
106,942 | 78,701 | 104,080 | 97,385 | |||||||||
| Dividends Declared per share of Common Stock |
$ | 0.25 | $ | 0.18 | $ | 0.88 | $ | 0.52 | |||||
See accompanying Notes to Consolidated Financial Statements.
3
CONSOLIDATED BALANCE SHEETS
| (Unaudited) |
September 30, 2004 |
December 31, 2003 | ||||
| (Thousands of dollars) | ||||||
| Assets |
||||||
| Current Assets |
||||||
| Cash and cash equivalents |
$ | 17,759 | $ | 12,172 | ||
| Trade accounts and notes receivable, net |
696,907 | 970,141 | ||||
| Materials and supplies |
20,585 | 18,962 | ||||
| Gas in storage |
636,229 | 500,439 | ||||
| Assets from price risk management activities (Note D) |
469,312 | 233,013 | ||||
| Deposits |
19,963 | 42,424 | ||||
| Deferred income taxes |
22,408 | — | ||||
| Other current assets |
59,418 | 46,184 | ||||
| Total Current Assets |
1,942,581 | 1,823,335 | ||||
| Property, Plant and Equipment |
||||||
| Production |
442,667 | 404,254 | ||||
| Gathering and Processing |
1,055,075 | 1,036,080 | ||||
| Transportation and Storage |
700,781 | 699,676 | ||||
| Distribution |
2,888,524 | 2,813,800 | ||||
| Energy Services |
127,687 | 126,315 | ||||
| Other |
133,002 | 99,549 | ||||
| Total Property, Plant and Equipment |
5,347,736 | 5,179,674 | ||||
| Accumulated depreciation, depletion, and amortization |
1,586,456 | 1,487,848 | ||||
| Net Property, Plant and Equipment |
3,761,280 | 3,691,826 | ||||
| Deferred Charges and Other Assets |
||||||
| Regulatory assets, net (Note E) |
201,576 | 213,915 | ||||
| Goodwill (Note F) |
225,363 | 225,615 | ||||
| Assets from price risk management activities (Note D) |
83,103 | 67,294 | ||||
| Prepaid pensions |
126,974 | 120,618 | ||||
| Investments and other |
83,459 | 69,283 | ||||
| Total Deferred Charges and Other Assets |
720,475 | 696,725 | ||||
| Total Assets |
$ | 6,424,336 | $ | 6,211,886 | ||
See accompanying Notes to Consolidated Financial Statements.
4
ONEOK, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
| (Unaudited) |
September 30, 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 |
298,000 | 600,000 | ||||||
| Accounts payable |
775,078 | 813,895 | ||||||
| Dividends payable |
25,840 | — | ||||||
| Accrued taxes |
24,155 | 102,637 | ||||||
| Accrued interest |
28,671 | 32,999 | ||||||
| Customers’ deposits |
36,970 | 34,692 | ||||||
| Unrecovered purchased gas costs |
68,535 | 51,378 | ||||||
| Liabilities from price risk management activities (Note D) |
610,122 | 246,474 | ||||||
| Deferred income taxes |
— | 6,194 | ||||||
| Other |
112,341 | 130,174 | ||||||
| Total Current Liabilities |
2,321,046 | 2,024,777 | ||||||
| Long-term Debt, excluding current maturities |
1,549,232 | 1,878,264 | ||||||
| Deferred Credits and Other Liabilities |
||||||||
| Deferred income taxes |
614,292 | 559,356 | ||||||
| Liabilities from price risk management activities (Note D) |
121,179 | 66,956 | ||||||
| Lease obligation |
90,186 | 100,292 | ||||||
| Other deferred credits |
329,013 | 340,849 | ||||||
| Total Deferred Credits and Other Liabilities |
1,154,670 | 1,067,453 | ||||||
| Total Liabilities |
5,024,948 | 4,970,494 | ||||||
| Commitments and Contingencies (Note J) |
||||||||
| Shareholders’ Equity |
||||||||
| Common stock, $0.01 par value: authorized 300,000,000 shares; issued 106,396,240 shares and outstanding 103,359,074 shares at September 30, 2004; issued 98,194,674 shares and outstanding 95,194,666 shares at December 31, 2003 |
1,064 | 982 | ||||||
| Paid in capital |
996,855 | 815,870 | ||||||
| Unearned compensation |
(2,007 | ) | (3,422 | ) | ||||
| Accumulated other comprehensive loss (Note G) |
(96,183 | ) | (17,626 | ) | ||||
| Retained earnings |
550,858 | 495,971 | ||||||
| Treasury stock, at cost: 3,037,166 shares at September 30, 2004 and 3,000,008 shares at December 31, 2003 |
(51,199 | ) | (50,383 | ) | ||||
| Total Shareholders’ Equity |
1,399,388 | 1,241,392 | ||||||
| Total Liabilities and Shareholders’ Equity |
$ | 6,424,336 | $ | 6,211,886 | ||||
See accompanying Notes to Consolidated Financial Statements.
5
CONSOLIDATED STATEMENTS OF CASH FLOWS
| Nine Months Ended September 30, |
||||||||
| (Unaudited) |
2004 |
2003 |
||||||
| (Thousands of dollars) | ||||||||
| Operating Activities |
||||||||
| Income from continuing operations |
$ | 143,781 | $ | 152,750 | ||||
| Depreciation, depletion, and amortization |
140,273 | 120,241 | ||||||
| Gain on sales of assets |
(9,345 | ) | (289 | ) | ||||
| Income from equity investments |
(802 | ) | (1,141 | ) | ||||
| Deferred income taxes |
77,906 | 93,451 | ||||||
| Stock based compensation expense |
6,695 | 3,588 | ||||||
| Allowance for doubtful accounts |
10,238 | 10,313 | ||||||
| Changes in assets and liabilities (net of acquisition effects): |
||||||||
| Accounts and notes receivable |
262,659 | 215,271 | ||||||
| Inventories |
(137,771 | ) | (441,143 | ) | ||||
| Unrecovered purchased gas costs |
17,157 | 15,765 | ||||||
| Deposits |
22,461 | (7,965 | ) | |||||
| Regulatory assets |
(6,921 | ) | (2,848 | ) | ||||
| Accounts payable and accrued liabilities |
(123,583 | ) | (51,445 | ) | ||||
| Price risk management assets and liabilities |
(33,780 | ) | 5,468 | |||||
| Other assets and liabilities |
(82,730 | ) | 14,674 | |||||
| Cash Provided by Continuing Operations |
286,238 | 126,690 | ||||||
| Cash Provided by Discontinued Operations |
— | 8,285 | ||||||
| Cash Provided by Operating Activities |
286,238 | 134,975 | ||||||
| Investing Activities |
||||||||
| Changes in other investments, net |
1,372 | 1,167 | ||||||
| Acquisitions |
— | (436,630 | ) | |||||
| Capital expenditures |
(192,335 | ) | (150,685 | ) | ||||
| Proceeds from sale of property |
17,249 | — | ||||||
| Other investing activities |
(2,990 | ) | (2,733 | ) | ||||
| Cash Used in Continuing Operations |
(176,704 | ) | (588,881 | ) | ||||
| Cash Provided by Discontinued Operations |
— | 280,669 | ||||||
| Cash Used in Investing Activities |
(176,704 | ) | (308,212 | ) | ||||
| Financing Activities |
||||||||
| Payments of notes payable, net |
(302,000 | ) | (98,500 | ) | ||||
| Change in bank overdraft |
4,262 | 253 | ||||||
| Issuance of debt |
— | 404,964 | ||||||
| Termination of interest rate swaps |
82,915 | — | ||||||
| Payment of debt issuance costs |
— | (2,564 | ) | |||||
| Payment of debt |
(1,041 | ) | (15,792 | ) | ||||
| Purchase of Series A Convertible Preferred Stock |
— | (300,000 | ) | |||||
| Purchase of common stock |
— | (50,000 | ) | |||||
| Issuance of common stock |
176,107 | 218,521 | ||||||
| Issuance (receipt) of treasury stock, net |
(816 | ) | 7,358 | |||||
| Dividends paid |
(63,374 | ) | (52,410 | ) | ||||
| Cash Provided by (Used in) Financing Activities |
(103,947 | ) | 111,830 | |||||
| Change in Cash and Cash Equivalents |
5,587 | (61,407 | ) | |||||
| Cash and Cash Equivalents at Beginning of Period |
12,172 | 73,522 | ||||||
| Cash and Cash Equivalents at End of Period |
$ | 17,759 | $ | 12,115 | ||||
See accompanying Notes to Consolidated Financial Statements.
6
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7
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 (loss) |
— | — | — | — | |||||||||
| Total comprehensive income |
|||||||||||||
| Receipts of restricted stock |
— | — | — | — | |||||||||
| Issuance of common stock |
|||||||||||||
| Common stock offering |
6,900,000 | 69 | 151,248 | — | |||||||||
| Stock issuance pursuant to various plans |
1,301,566 | 13 | 25,072 | — | |||||||||
| Offering costs |
— | — | (295 | ) | — | ||||||||
| Stock-based employee compensation expense |
— | — | 4,960 | 1,735 | |||||||||
| Common stock dividends (Note H) |
— | — | — | (320 | ) | ||||||||
| September 30, 2004 |
106,396,240 | $ | 1,064 | $ | 996,855 | $ | (2,007 | ) | |||||
See accompanying Notes to the Consolidated Financial Statements.
8
ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME
(Continued)
| (Unaudited) |
Accumulated Other |
Retained Earnings |
Treasury Stock |
Total |
||||||||||||
| (Thousands of dollars) | ||||||||||||||||
| December 31, 2003 |
$ | (17,626 | ) | $ | 495,971 | $ | (50,383 | ) | $ | 1,241,392 | ||||||
| Net income |
— | 143,781 | — | 143,781 | ||||||||||||
| Other comprehensive income (loss) |
(78,557 | ) | — | — | (78,557 | ) | ||||||||||
| Total comprehensive income |
65,224 | |||||||||||||||
| Receipts of restricted stock |
— | — | (816 | ) | (816 | ) | ||||||||||
| Issuance of common stock |
||||||||||||||||
| Common stock offering |
— | — | — | 151,317 | ||||||||||||
| Stock issuance pursuant to various plans |
— | — | — | 25,085 | ||||||||||||
| Offering costs |
— | — | — | (295 | ) | |||||||||||
| Stock-based employee compensation expense |
— | — | — | 6,695 | ||||||||||||
| Common stock dividends (Note H) |
— | (88,894 | ) | — | (89,214 | ) | ||||||||||
| September 30, 2004 |
$ | (96,183 | ) | $ | 550,858 | $ | (51,199 | ) | $ | 1,399,388 | ||||||
9
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 and nine months ended September 30, 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 Note A of the Notes to Consolidated Financial Statements in the Company’s Annual Report on Form 10-K for the year ended December 31, 2003, except as follows.
Critical Accounting Policies and Estimates
Pension and Postretirement Employee Benefits - In May 2004, the Financial Accounting Standards Board (FASB) issued FASB Staff Position No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP FAS 106-2) as guidance on how employers should account for provisions of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Reform Act). The Company adopted FSP FAS 106-2 in the second quarter of 2004. FSP FAS 106-2 superceded 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), which was adopted by the Company 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” to all options and awards granted prior to January 1, 2003.
| Three Months Ended September 30, |
Nine Months Ended September 30, | |||||||||||
| 2004 |
2003 |
2004 |
2003 | |||||||||
| (Thousands of dollars, except per share amounts) | ||||||||||||
| Net income, as reported |
$ | 20,839 | $ | 4,595 | $ | 143,781 | $ | 49,576 | ||||
| Add: Stock based compensation included in net income, net of related tax effects |
1,576 | 1,015 | 4,926 | 2,712 | ||||||||
| Deduct: Total stock based compensation expense determined under fair value based method for all awards, net of related tax effects |
1,873 | 1,318 | 5,816 | 3,622 | ||||||||
| Pro forma net income |
$ | 20,542 | $ | 4,292 | $ | 142,891 | $ | 48,666 | ||||
| Earnings per share: |
||||||||||||
| Basic - as reported |
$ | 0.20 | $ | 0.01 | $ | 1.42 | $ | 0.72 | ||||
| Basic - pro forma |
$ | 0.20 | $ | 0.00 | $ | 1.41 | $ | 0.71 | ||||
| Diluted - as reported |
$ | 0.19 | $ | 0.01 | $ | 1.38 | $ | 0.57 | ||||
| Diluted - pro forma |
$ | 0.19 | $ | 0.00 | $ | 1.37 | $ | 0.56 | ||||
10
Related Party Transactions - From time to time and in the ordinary 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 and natural gas liquids 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. |
| • | 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. |
| • | Conducts natural gas sale transactions with Shawnee Milling Company (Shawnee). William L. Ford, President of Shawnee, is a member of the Company’s board of directors. |
The table below shows the purchase and sale transactions with the related parties. The purchase and sale transactions are conducted under substantially the same terms as comparable third-party transactions.
| Three Months Ended September 30, 2004 |
Nine Months Ended September 30, 2004 | |||||||||||
| Sales |
Purchases |
Sales |
Purchases | |||||||||
| (Thousands of dollars) | ||||||||||||
| Frontier |
$ | 38,120 | $ | 1,872 | $ | 116,546 | $ | 14,223 | ||||
| Williford Companies |
$ | 42 | $ | 1,706 | $ | 121 | $ | 4,996 | ||||
| Shawnee Milling |
$ | 36 | $ | — | $ | 133 | $ | — | ||||
Production Property - In September 2004, the FASB issued FASB Staff Position No. 142-2, “Application of FASB Statement No. 142, Goodwill and Other Intangible Assets, to Oil- and Gas-Producing Entities” (FSP FAS 142-2) to clarify that oil and gas producing properties are excluded from the requirements in Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets.” The Company classifies the cost of oil and gas mineral rights as property, plant and equipment on the balance sheet, which is consistent with FSP FAS 142-2.
Other
Reclassifications - Certain amounts in the consolidated financial statements, primarily related to current and noncurrent deferred taxes and assets and liabilities from price risk management activities, have been reclassified to conform to the 2004 presentation. These reclassifications did not impact previously reported net income or shareholders’ equity.
B. Acquisitions and Divestitures
In September 2004, the Company announced that it had entered into an agreement to purchase Northern Plains Natural Gas Company, which owns 82.5 percent of the general partnership interest and 500,000 limited partnership units, together representing a 2.73 percent ownership interest in Northern Border Partners, L.P., from CCE Holdings, LLC for $175 million. This transaction is subject to CCE Holdings, LLC closing its acquisition of CrossCountry Energy, LLC from Enron Corp. and certain of its affiliates, which is expected to occur in the fourth quarter of 2004.
In May and July 2004, the Company completed its sale of its propane bottle operations located in Texas and New Mexico in two separate transactions totaling approximately $1.4 million and recorded a pre-tax gain of $0.9 million, which is included in other income in the Gathering and Processing segment.
In May 2004, the Company sold its investment in natural gas distribution operations located in Mexico for approximately $2 million and recorded a pre-tax gain of $1.6 million, which is included in other income in the Other segment.
In March 2004, the Company sold certain natural gas transmission and gathering pipelines and compression facilities for approximately $13 million and recorded a pre-tax gain of $6.9 million, which is included in other income in the Transportation and Storage segment.
11
C. Discontinued Operations
In January 2003, the Company sold a portion of its Production segment (the component). 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.” Accordingly, amounts in the Company’s financial statements and related notes for all periods shown reflect discontinued operations accounting.
The amounts of revenue, costs and income taxes reported in discontinued operations are as follows:
| Three Months Ended September 30, |
Nine Months Ended September 30, | |||||||||||
| 2004 |
2003 |
2004 |
2003 | |||||||||
| (Thousands of dollars) | ||||||||||||
| Natural gas sales |
$ | — | $ | — | $ | — | $ | 6,036 | ||||
| Oil sales |
— | — | — | 1,705 | ||||||||
| Net margin |
— | — | — | 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 or is not designated as part of a hedging relationship, the Company accounts for changes in fair value of the derivative instrument in earnings 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.
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.
12
At the beginning of the third quarter, the Company completed a reorganization of its Energy Services segment with renewed focus on the physical marketing and storage business. The Company separated the management and operations of its physical marketing, retail marketing and trading activities and began accounting separately for the different types of revenue earned from these activities. Prior to the third quarter, the Company managed the Energy Services segment on an integrated basis and presented all energy trading activity on a net basis.
Concurrent with this reorganization, the Company evaluated the accounting treatment related to the presentation of revenues from the different types of activities to determine which amounts should be reported on a gross or net basis under the guidance in EITF 03-11. For derivative instruments considered held for trading purposes that result in physical delivery, the indicators 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” were used to determine the proper treatment. These activities and all financially settled derivative contracts will continue to be reported on a net basis.
For derivative instruments that are not considered “held for trading purposes” and that result in physical delivery, the indicators in EITF 03-11 and EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent” (EITF 99-19) were used to determine the proper treatment. The Company began accounting for the realized revenues and purchase costs of these contracts that result in physical delivery on a gross basis beginning with the third quarter of 2004. The Company applies the indicators in EITF No. 99-19 to determine the appropriate accounting treatment for non-derivative contracts that result in physical delivery. Derivatives that qualify for the normal purchase or sale exception as defined in Statement 133 are also reported on a gross basis. No prior periods have been adjusted for this change; therefore, comparisons to prior periods may not be meaningful. Reporting of these transactions on a gross basis did not impact operating income but resulted in an increase to revenues and cost of sales and fuel.
Fair Value Hedges
The Energy Services segment uses basis swaps to hedge the fair value of certain transportation commitments. At September 30, 2004, net price risk management assets include $11.6 million to recognize the fair value of the Energy Services segment’s derivatives that are designated as fair value hedging instruments. The ineffectiveness related to these hedges was a loss of approximately $0.4 million and $1.8 million for the three and nine months ended September 30, 2004, respectively. These amounts are included as a reduction in operating revenues.
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 upon termination of the interest rate swaps were $81.9 million, after reduction for ineffectiveness and unpaid interest. Through September 30, 2004, $5.6 million in interest expense savings has been recognized and the remaining amount of $76.3 million will be recognized in the income statement over the remaining term of the debt instruments originally hedged. Consequently, the remaining savings in interest expense will be recognized over the following periods:
| Remainder of 2004 |
$ | 2.5 million | |
| 2005 |
$ | 10.0 million | |
| 2006 |
$ | 10.0 million | |
| 2007 |
$ | 10.0 million | |
| 2008 |
$ | 10.0 million | |
| Thereafter |
$ | 33.8 million |
The Company 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. At September 30, 2004, the Company recorded a $14.5 million net liability to recognize the interest rate swaps at fair value. Long-term debt was also decreased by $14.5 million to recognize the change in the fair value of the related hedged liability.
13
Cash Flow Hedges
The Energy Services segment uses futures and basis swaps to hedge the cash flows associated with its anticipated purchases and sales of natural gas. Accumulated other comprehensive loss at September 30, 2004, includes losses of approximately $82.4
million, net of tax, related to these hedges that will be realized within the next 39 months. Net gains and losses are reclassified out of accumulated other comprehensive loss to cost of sales and fuel when the anticipated purchase or sale occurs. Ineffectiveness related to these cash flow hedges resulted in a gain of approximately $0.1 million for the three months ended September 30, 2004 and a loss of approximately $4.0 million for the nine months ended September 30, 2004. Additionally, losses of approximately $4.6 million were recognized from accumulated other comprehensive loss during the nine months ended September 30, 2004, due to the discontinuance of cash flow hedge treatment on certain transactions since it was probable that the forecasted transactions would not occur.
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 and oil. Accumulated other comprehensive loss at September 30, 2004, includes losses of approximately $11.3 million, net of tax, for the production hedges that will be realized in the income statement within the next 15 months.
The Company’s regulated businesses also use derivative instruments from time to time. Gains or losses associated with these derivative instruments are included in and recoverable through the monthly purchased gas adjustment. At September 30, 2004, Kansas Gas Service Company (KGS) and Texas Gas Service Company (TGS) had derivative instruments in place to hedge the cost of natural gas purchases for 11.0 Bcf and 0.4 Bcf of natural gas, respectively, which represents part of their gas purchase requirements for the 2004/2005 winter heating months.
E. Regulatory Assets
The following table is a summary of the regulatory assets, net of amortization, for the periods indicated.
| September 30, 2004 |
December 31, 2003 | |||||
| (Thousands of dollars) | ||||||
| Recoupable take-or-pay |
$ | 59,863 | $ | 64,171 | ||
| Postretirement costs other than pension |
54,124 | 59,118 | ||||
| Reacquired debt costs |
19,991 | 20,635 | ||||
| Income taxes |
19,298 | 21,782 | ||||
| Transition costs |
16,332 | 16,691 | ||||
| Pension costs |
14,098 | 18,060 | ||||
| Weather normalization |
5,023 | 1,075 | ||||
| Ad valorem tax |
3,269 | — | ||||
| Service lines |
2,036 | 3,250 | ||||
| Line replacements |
582 | 495 | ||||
| Other |
6,960 | 8,638 | ||||
| Regulatory assets, net |
$ | 201,576 | $ | 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. The order also allows ONG to recover costs related to its investment in gas in storage and rising levels of fuel-related bad debts. The OCC’s order also approved a modified distribution main extension policy and authorized ONG to defer expected homeland security costs. The order 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 18 month period. At September 30, 2004, the Company had approximately $3.8 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.
ONG’s current estimate of future rate relief is substantially in excess of the refund threshold of $10.7 million. The Company believes that any refund obligation is remote 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. Should its analysis indicate a potential refund liability, the Company will record a reserve for this obligation.
14
“Weather normalization” represents the revenue over- or under-recovered through the weather normalization adjustment program in Kansas. This amount is deferred as a regulatory asset during April 1 through March 31 of each year, at which time, KGS begins applying an adjustment to the customers’ bills to refund the over-collected revenue or bill the under-collected revenue over the next twelve-month period.
The $3.3 million “Ad valorem tax” represents an increase in KGS’ taxes above the amount approved in the September 2003 rate case. Kansas law permits a utility to file a tariff to recover additional ad valorem tax expense incurred above the amount currently recovered in the cost of service rate. This excess amount is recoverable through a surcharge and can be recovered, provided the utility reports the change in rates to the Kansas Corporation Commission (KCC), on an annual basis. KGS filed the tariff and received approval from the KCC during the third quarter of 2004.
F. Goodwill
The following table reflects the changes in the carrying amount of goodwill for the periods indicated.
| December 31, 2003 |
Adjustments |
September 30, 2004 | ||||||||
| (Thousands of dollars) | ||||||||||
| Gathering and Processing |
$ | 34,343 | $ | — | $ | 34,343 | ||||
| Transportation and Storage |
22,288 | (252 | ) | 22,036 | ||||||
| Distribution |
158,729 | — | 158,729 | |||||||
| Energy Services |
10,255 | — | 10,255 | |||||||
| Total consolidated |
$ | 225,615 | $ | (252 | ) | $ | 225,363 | |||
The 2004 adjustment to goodwill resulted from the sale of certain natural gas transmission and gathering pipelines and compression facilities on March 1, 2004. The 2003 adjustments to goodwill resulted from the preliminary purchase price allocation of the Company’s 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 following tables give an overview of comprehensive income for the periods indicated.
| Three Months Ended September 30, | |||||||||||||||
| 2004 |
2003 | ||||||||||||||
| (Thousands of dollars) | |||||||||||||||
| Net income |
$ | 20,839 | $ | 4,595 | |||||||||||
| Unrealized gains (losses) on derivative instruments |
$ | (101,688 | ) | $ | 32,244 | ||||||||||
| Unrealized holding losses arising during the period |
(136 | ) | (165 | ) | |||||||||||
| Realized losses in net income |
1,405 | 643 | |||||||||||||
| Other comprehensive income (loss) before taxes |
(100,419 | ) | 32,722 | ||||||||||||
| Income tax benefit (provision) on other comprehensive loss |
38,839 | (12,688 | ) | ||||||||||||
| Other comprehensive income (loss) |
(61,580 | ) | 20,034 | ||||||||||||
| Comprehensive income (loss) |
$ | (40,741 | ) | $ | 24,629 | ||||||||||
15
| Nine Months Ended September 30, | |||||||||||||||
| 2004 |
2003 | ||||||||||||||
| (Thousands of dollars) | |||||||||||||||
| Net income |
$ | 143,781 | $ | 49,576 | |||||||||||
| Unrealized gains (losses) on derivative instruments |
$ | (144,480 | ) | $ | 36,582 | ||||||||||
| Unrealized holding losses arising during the period |
(212 | ) | (59 | ) | |||||||||||
| Realized losses in net income |
16,592 | 3,662 | |||||||||||||
| Other comprehensive income (loss) before taxes |
(128,100 | ) | 40,185 | ||||||||||||
| Income tax benefit (provision) on other comprehensive loss |
49,543 | (15,573 | ) | ||||||||||||
| Other comprehensive income (loss) |
(78,557 | ) | 24,612 | ||||||||||||
| Comprehensive income |
$ | 65,224 | $ | 74,188 | |||||||||||
Accumulated other comprehensive loss reflected in the consolidated balance sheet at September 30, 2004, includes unrealized gains and losses on derivative instruments and minimum pension liability adjustments.
H. Capital Stock
Common Stock - Since September 17, 2004, the Thrift Plan for Employees of ONEOK, Inc. and subsidiaries (the Thrift Plan) has from time to time purchased shares of ONEOK common stock on the open market to meet the purchase requirements generated by participants in the Thrift Plan. Previously, the Thrift Plan used newly issued shares to meet the participants’ purchase requirements. All participant purchases of ONEOK common stock under the Thrift Plan are voluntary. The Company uses newly issued shares to meet the purchase requirements generated by the Company’s Dividend Reinvestment Plan and the Long-Term Incentive Plan.
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 paid on the Company’s common stock for shareholders of record during the three and nine months ended September 30, 2004, were $0.23 per share and $0.63 per share, respectively. In September 2004, the Company’s board of directors announced an increase in the quarterly dividend on the Company’s common stock to $0.25 per share payable in the fourth quarter of 2004.
I. Employee Benefit Plans
The table below provides the components of net periodic benefit cost (income) for the Company’s pension and other postretirement benefit plans.
| Pension Benefits Three Months Ended |
Pension Benefits Nine Months Ended |
|||||||||||||||
| Components of Net Periodic Benefit Cost (Income) |
2004 |
2003 |
2004 |
2003 |
||||||||||||
| (Thousands of dollars) | ||||||||||||||||
| Service cost |
$ | 3,925 | $ | 3,402 | $ | 11,888 | $ | 10,208 | ||||||||
| Interest cost |
10,555 | 10,227 | 31,299 | 30,681 | ||||||||||||
| Expected return on assets |
(13,817 | ) | (15,679 | ) | (44,787 | ) | (47,041 | ) | ||||||||
| Amortization of unrecognized net asset at adoption |
(78 | ) | (116 | ) | (236 | ) | (350 | ) | ||||||||
| Amortization of unrecognized prior service cost |
166 | 147 | 496 | 445 | ||||||||||||
| Amortization of loss |
1,145 | 407 | 2,301 | 1,221 | ||||||||||||
| Net periodic benefit cost (income) |
$ | 1,896 | $ | (1,612 | ) | $ | 961 | $ | (4,836 | ) | ||||||
16
| Postretirement Benefits September 30, |
Postretirement Benefits September 30, |
|||||||||||||||
| Components of Net Periodic Benefit Cost (Income) |
2004 |
2003 |
2004 |
2003 |
||||||||||||
| (Thousands of dollars) | ||||||||||||||||
| Service cost |
$ | 1,411 | $ | 1,304 | $ | 4,534 | $ | 3,910 | ||||||||
| Interest cost |
3,329 | 3,002 | 10,229 | 9,008 | ||||||||||||
| Expected return on assets |
(966 | ) | (762 | ) | (2,845 | ) | (2,288 | ) | ||||||||
| Amortization of unrecognized net asset at adoption |
864 | 835 | 2,592 | 2,507 | ||||||||||||
| Amortization of unrecognized prior service cost |
24 | (30 | ) | 73 | (90 | ) | ||||||||||
| Amortization of loss |
998 | 967 | 4,289 | 2,899 | ||||||||||||
| Net periodic benefit cost |
$ | 5,660 | $ | 5,316 | $ | 18,872 | $ | 15,946 | ||||||||
Contributions - For the nine months ended September 30, 2004, $6.4 million and $9.4 million of contributions were made to the Company’s pension plan and other postretirement benefit plan, respectively. The Company presently anticipates its total 2004 contributions will be $6.8 million for the pension plan and $12.6 million for the other postretirement benefit plan.
Actuarial Assumptions and Adjustments - Changes to the collective bargaining agreements that went into effect on July 1, 2004, required the re-measurement of the pension and other postretirement benefits with a discount rate that reflected the economic conditions as of that date. As a result, the discount rate was adjusted to 6.75 percent from 6.25 percent. In addition, there was a nonrecurring reduction in the value of the assets of $1.7 million in the third quarter of 2004.
Other Postretirement Benefits Changes - In May 2004, the FASB issued FSP FAS 106-2 as guidance on how employers should account for provisions of the Medicare Reform Act. The Company adopted FSP FAS 106-2 in the second quarter of 2004. FSP FAS 106-2 superceded FSP FAS 106-1, which was adopted by the Company in the first quarter of 2004. 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 at least 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. The three months ended June 30, 2004 was the first time the Company could record a benefit related to the Medicare Reform Act, since a September 30 measurement date is used for this plan. The reduction in the accumulated postretirement benefit obligation related to benefits attributed to past service was $18.1 million. The amortization for the actuarial experience gain as a component of the net amortization was $0.4 million and $0.9 million for three and nine months ended September 30, 2004, respectively. The reduction in current period service cost due to the subsidy was $0.1 million and $0.2 million for the three and nine months ended September 30, 2004, respectively. There was no change to the interest cost on the accumulated postretirement benefit obligation for the three months ended September 30, 2004, while there was a $0.3 million reduction for the nine months ended September 30, 2004. The Company believes that its plan will continue to provide drug benefits that are at least 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 Reform Act will have a significant effect on the Company’s retirees’ participation in its postretirement benefit plan.
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 the Company’s 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 natural gas liquids 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 of operations and cash flow. In addition, emission controls mandated 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.
17
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 five sites with regulatory closure achieved at two of these locations, and has begun assessment at the remaining sites. The site situations are not similar and the Company has no previous experience with similar remediation efforts. The Company has completed some analysis of the remaining seven sites, but is unable to accurately estimate individual or aggregate costs that may be required 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. The cost 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 $500,000 per site and 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. Based on information currently available to the Company, it does not believe there are any material adverse effects resulting from the Consent Order.
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 has filed its notice of appeal of the jury verdict and the punitive damage award. Based on information currently available to the Company, it believes its legal reserves and insurance coverage are adequate and that this matter will not have a material adverse effect on the Company.
The two class action lawsuits 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 resulted in jury verdicts in September 2004. The jury awarded the plaintiffs in the residential class $5 million in actual damages, which is covered by insurance. In the other class action relating to business claims, the jury awarded no actual damages. The jury rejected claims for punitive damages in both cases. The Company is reviewing its options for appealing the verdict rendered in the residential claimants’ class action.
With the exception of appeals, all litigation regarding the Yaggy facility has been resolved.
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 connection with the CFTC’s industry wide investigation relating to ”Activities Affecting the Price of Natural Gas in the Fall of 2003.” The CFTC specifically requested information related to reporting of natural gas storage information to the Energy Information Agency during the time period of October 31, 2003 - January 2, 2004. The Company cooperated fully with the CFTC’s request and has furnished the requested information. On August 30, 2004, the CFTC announced it had completed its investigation and did not uncover evidence that any entity or individual engaged in activity with an intent to cause an artificial price in natural gas in late 2003.
18
Natural Gas Price Reporting Litigation - The Company and its wholly owned subsidiary, ONEOK Energy Services 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. Based on information currently available to the Company, it does not expect this matter to have a material adverse effect on the Company.
Although the Company agreed to a civil monetary penalty with the CFTC in its investigation into natural gas price reporting in January 2004, it cannot guarantee other additional legal proceedings, civil or criminal fines or penalties, or other regulatory action related to this issue will not arise. The Company plans to vigorously defend any claims related to this issue.
Enron - The Company has repurchased a portion of the Enron Corp. guaranty claim that Enron Corp. sought to avoid in the adversary proceeding. The Company is now providing the defense of the adversary proceeding for both the portion of the guaranty claim constituting the repurchased claim and also the portion of the guaranty claim previously sold. Based on information currently available to the Company, it does not expect the adversary proceeding to have a material adverse effect on the Company.
In addition to the adversary proceeding, Enron Corp. and Enron North American Corp. (“ENA”) have filed a new objection to portions of the guaranty claim and to portions of the underlying claim against ENA, creating a new contested matter in the Enron Corp. bankruptcy case which involves different legal and factual issues than those raised in the adversary proceeding. Enron Corp. and ENA allege in this matter that the guaranty claim and underlying claim against ENA are overstated. The filing of this matter may trigger additional obligations of the Company to repurchase some of the claims previously sold. Based on the information currently available to the Company, it does not expect this matter to have a material adverse effect on the Company.
Labor Negotiations - On July 1, 2004, KGS and the United Steelworkers of America Locals 12561, 13417, and 14228, the Gas Workers Metal Trades of the United Association of Journeyman and Apprentices of the Plumbing and Pipefitting Industry of the United States and Canada Local 781 and the International Union of Operating Engineers Local 126 labor unions agreed upon a five-year contract expiring June 30, 2009. Approximately 463 KGS employees are members of these three labor unions, comprising approximately 41 percent of the KGS workforce. The parties agreed to a three percent wage increase retroactive to June 1, 2004 and an increase for each of the next four years as follows:
| • | three percent beginning July 1, 2005 |
| • | two and one-half percent beginning July 1, 2006 |
| • | two and one-half percent beginning July 1, 2007 |
| • | two and one-half percent beginning July 1, 2008 |
Currently, the Company has no ongoing labor negotiations.
Other - The Company is a party to other litigation matters and claims including environmental matters, which are normal in the ordinary course of its operations. While the results of litigation and claims cannot be predicted with certainty, based on information currently available to the Company it does not expect the final outcome of such matters to have a material adverse effect on the Company.
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 and Note D. As discussed in Note D, at the beginning of the third quarter the Company completed a reorganization of its Energy Services segment and separated the management and operations of its physical marketing, retail marketing and trading activities. The Company began accounting separately for the different types of revenue earned from these activities with certain revenues accounted for on a gross rather than a net basis.
Intersegment sales are recorded on the same basis as sales to unaffiliated customers. 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.
19
| Regulated |
Non-Regulated |
||||||||||||||||||||||
| Three Months Ended September 30, 2004 |
Transportation Storage |
Distribution |
Energy Services |
Gathering and Processing |
Production |
Other and Eliminations |
Total | ||||||||||||||||
| (Thousands of dollars) | |||||||||||||||||||||||
| Sales to unaffiliated customers |
$ | 10,914 | $ | 247,659 | $ | 1,036,367 | $ | 390,001 | $ | 23,552 | $ | 858 | $ | 1,709,351 | |||||||||
| Energy trading revenues, net |
— | — | 17,411 | — | — | — | $ | 17,411 | |||||||||||||||
| Intersegment sales |
25,464 | — | 91,863 | 129,739 | 1,216 | (248,282 | ) | — | |||||||||||||||
| Total Revenues |
$ | 36,378 | $ | 247,659 | $ | 1,145,641 | $ | 519,740 | $ | 24,768 | $ | (247,424 | ) | $ | 1,726,762 | ||||||||
| Net margin |
$ | 28,443 | $ | 88,626 | $ | 19,602 | $ | 84,371 | $ | 24,768 | $ | 290 | $ | 246,100 | |||||||||
| Operating costs |
$ | 12,236 | $ | 79,711 | $ | 7,197 | $ | 34,748 | $ | 7,242 | $ | (1,844 | ) | $ | 139,290 | ||||||||
| Depreciation, depletion and amortization |
$ | 4,382 | $ | 26,518 | $ | 1,398 | $ | 8,304 | $ | 6,593 | $ | 112 | $ | 47,307 | |||||||||
| Operating income (loss) |
$ | 11,825 | $ | (17,603 | ) | $ | 11,007 | $ | 41,319 | $ | 10,933 | $ | 2,022 | $ | 59,503 | ||||||||
| Income from equity investments |
$ | 261 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 261 | |||||||||
| Capital expenditures |
$ | 3,685 | $ | 43,732 | $ | 558 | $ | 8,500 | $ | 17,190 | $ | 4,268 | $ | 77,933 | |||||||||
| Regulated |
Non-Regulated |
|||||||||||||||||||||||
| Three Months Ended September 30, 2003 |
Transportation Storage |
Distribution |
Energy Services |
Gathering and Processing |
Production |
Other and Eliminations |
Total | |||||||||||||||||
| (Thousands of dollars) | ||||||||||||||||||||||||
| Sales to unaffiliated customers |
$ | 11,603 | $ | 221,834 | $ | 27,055 | $ | 351,272 | $ | 8,784 | $ | (63,455 | ) | $ | 557,093 | |||||||||
| Energy trading revenues, net |
— | — | 11,177 | — | — | — | $ | 11,177 | ||||||||||||||||
| Intersegment sales |
26,371 | — | (a | ) | 83,422 | 1,025 | (110,818 | ) | — | |||||||||||||||
| Total Revenues |
$ | 37,974 | $ | 221,834 | $ | 38,232 | $ | 434,694 | $ | 9,809 | $ | (174,273 | ) | $ | 568,270 | |||||||||
| Net margin |
$ | 26,848 | $ | 89,501 | $ | 14,496 | $ | 53,456 | $ | 9,809 | $ | 272 | $ | 194,382 | ||||||||||
| Operating costs |
$ | 11,840 | $ | 71,460 | $ | 6,750 | $ | 28,597 | $ | 3,547 | $ | 263 | $ | 122,457 | ||||||||||
| Depreciation, depletion and |
$ | 4,180 | $ | 24,023 | $ | 1,397 | $ | 7,383 | $ | 2,795 | $ | 327 | $ | 40,105 | ||||||||||
| Operating income (loss) |
$ | 10,828 | $ | (5,982 | ) | $ | 6,349 | $ | 17,476 | $ | 3,467 | $ | (318 | ) | $ | 31,820 | ||||||||
| Income from equity investments |
$ | 326 | $ | — | $ | — | $ | — | $ | — | $ | 53 | $ | 379 | ||||||||||
| Capital expenditures |
$ | 5,640 | $ | 47,865 | $ | 92 | $ | 4,239 | $ | 6,142 | $ | 2,266 | $ | 66,244 | ||||||||||
| (a) | - Intersegment sales for Energy Services were $64.5 million for the three months ended September 30, 2003. |
| Regulated |
Non-Regulated |
|||||||||||||||||||||
| Nine Months Ended September 30, 2004 |
Transportation Storage |
Distribution |
Energy Services |
Gathering and Processing |
Production |
Other and Eliminations |
Total | |||||||||||||||
| (Thousands of dollars) | ||||||||||||||||||||||
| Sales to unaffiliated customers |
$ | 36,160 | $ | 1,337,475 | $ | 1,118,916 | $ | 1,042,992 | $ | 72,121 | $ | (324,771 | ) | $ | 3,282,893 | |||||||
| Energy trading revenues, net |
— | — | 106,583 | — | — | — | $ | 106,583 | ||||||||||||||
| Intersegment sales (a) |
75,700 | — | 91,863 | 380,091 | 3,178 | (550,832 | ) | — | ||||||||||||||
| Total Revenues |
$ | 111,860 | $ | 1,337,475 | $ | 1,317,362 | $ | 1,423,083 | $ | 75,299 | $ | (875,603 | ) | $ | 3,389,476 | |||||||
| Net margin |
$ | 85,421 | $ | 395,612 | $ | 109,218 | $ | 207,356 | $ | 75,299 | $ | (3,995 | ) | $ | 868,911 | |||||||
| Operating costs |
$ | 36,076 | $ | 251,516 | $ | 25,669 | $ | 93,769 | $ | 21,283 | $ | (7,892 | ) | $ | 420,421 | |||||||
| Depreciation, depletion and amortization |
$ | 12,938 | $ | 78,669 | $ | 4,213 | $ | 24,470 | $ | 19,247 | $ | 736 | $ | 140,273 | ||||||||
| Operating income |
$ | 36,407 | $ | 65,427 | $ | 79,336 | $ | 89,117 | $ | 34,769 | $ | 3,161 | $ | 308,217 | ||||||||
| Income from equity investments |
$ | 861 | $ | — | $ | — | $ | — | $ | — | $ | (59 | ) | $ | 802 | |||||||
| Total assets |
$ | 801,266 | $ | 2,390,165 | $ | 1,484,257 | $ | 971,977 | $ | 205,840 | $ | 570,831 | $ | 6,424,336 | ||||||||
| Capital expenditures |
$ | 7,696 | $ | 106,332 | $ | 1,372 | $ | 18,457 | $ | 37,608 | $ | 20,870 | $ | 192,335 | ||||||||
| (a) | - Intersegment sales for Energy Services were $327.3 million for the six months ended June 30, 2004. |
20
| Regulated |
Non-Regulated |
|||||||||||||||||||||||||
| Nine Months Ended September 30, 2003 |
Transportation Storage |
Distribution |
Energy Services |
Gathering and Processing |
Production |
Other and Eliminations |
Total |
|||||||||||||||||||
| (Thousands of dollars) | ||||||||||||||||||||||||||
| Sales to unaffiliated customers |
$ | 51,875 | $ | 1,212,869 | $ | 61,196 | $ | 980,234 | $ | 30,080 | $ | (370,224 | ) | $ | 1,966,030 | |||||||||||
| Energy trading revenues, net |
— | — | 183,938 | — | — | — | $ | 183,938 | ||||||||||||||||||
| Intersegment sales |
63,138 | — | (a | ) | 382,405 | 2,121 | (447,664 | ) | — | |||||||||||||||||
| Total Revenues |
$ | 115,013 | $ | 1,212,869 | $ | 245,134 | $ | 1,362,639 | $ | 32,201 | $ | (817,888 | ) | $ | 2,149,968 | |||||||||||
| Net margin |
$ | 84,010 | $ | 367,795 | $ | 191,374 | $ | 152,121 | $ | 32,201 | $ | 2,269 | $ | 829,770 | ||||||||||||
| Operating costs |
$ | 34,190 | $ | 226,697 | $ | 23,275 | $ | 89,086 | $ | 11,092 | $ | (1,077 | ) | $ | 383,263 | |||||||||||
| Depreciation, depletion and amortization |
$ | 12,518 | $ | 71,633 | $ | 4,328 | $ | 21,921 | $ | 8,790 | $ | 1,051 | $ | 120,241 | ||||||||||||
| Operating income |
$ | 37,302 | $ | 69,465 | $ | 163,771 | $ | 41,114 | $ | 12,319 | $ | 2,295 | $ | 326,266 | ||||||||||||
| 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 |
$ | 1,088 | $ | — | $ | — | $ | — | $ | — | $ | 53 | $ | 1,141 | ||||||||||||
| Total assets |
$ | 862,511 | $ | 2,288,523 | $ | 1,178,553 | $ | 1,305,563 | $ | 141,757 | $ | (227,416 | ) | $ | 5,549,491 | |||||||||||
| Capital expenditures |
$ | 10,441 | $ | 106,991 | $ | 488 | $ | 12,231 | $ | 12,870 | $ | 7,664 | $ | 150,685 | ||||||||||||
(a) - Intersegment sales for Energy Services were $373.0 million for the nine months ended September 30, 2003.
L. Supplemental Cash Flow Information
The following table sets forth supplemental information with respect to the Company’s cash flows for the periods indicated.
| Nine Months Ended September 30, |
|||||||
| 2004 |
2003 |
||||||
| (Thousands of dollars) | |||||||
| Cash paid (received) during the period |
|||||||
| Interest (including amounts capitalized) |
$ | 64,078 | $ | 68,532 | |||
| Income taxes paid (received) |
$ | 106,775 | $ | (10,848 | ) | ||
| 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 payable |
$ | 25,840 | $ | 18,614 | |||
| Dividends on restricted stock |
$ | 320 | $ | 202 | |||
| Treasury stock transferred to compensation plans |
$ | — | $ | 4,022 | |||
| Issuance of restricted stock, net |
$ | — | $ | 3,201 | |||
21
| Nine Months Ended September 30, |
|||||||
| 2004 |
2003 |
||||||
| (Thousands of dollars) | |||||||
| Acquisitions |
|||||||
| Property, plant and equipment |
$ | — | $ | 290,000 | |||
| Current assets |
— | 69,919 | |||||
| Current liabilities |
— | (63,205 | ) | ||||
| Regulatory assets and goodwill |
— | 126,708 | |||||
| Other assets |
— | 2,875 | |||||
| Lease obligation |
— | (4,715 | ) | ||||
| Deferred credits |
— | (37,399 | ) | ||||
| Deferred income taxes |
— | 52,447 | |||||
| Cash paid for acquisitions |
$ | — | $ | 436,630 | |||
M. Earnings Per Share Information
The Company computes earnings per common share (EPS) as described in Note S of the Notes to Consolidated Financial Statements in the Company’s Annual Report on Form 10-K for the year ended December 31, 2003.
The following tables set forth the computations of the basic and diluted EPS from continuing operations for the periods indicated.
| Three Months Ended September 30, 2004 | ||||||||
| Income |
Shares |
Per Share Amount | ||||||
| (Thousands, except per share amounts) | ||||||||
| Basic EPS from continuing operations |
||||||||
| Income from continuing operations available for common stock |
$ | 20,839 | 102,914 | $ | 0.20 | |||
| Effect of other dilutive securities: |
||||||||
| Mandatory convertible units |
— | 3,236 | ||||||
| Options and other dilutive securities |
— | 792 | ||||||
| Diluted EPS from continuing operations |
||||||||
| Income from continuing operations available for common stock |
$ | 20,839 | 106,942 | $ | 0.19 | |||
| Three Months Ended September 30, 2003 | ||||||||
| Income |
Shares |
Per Share Amount | ||||||
| (Thousands, except per share amounts) | ||||||||
| Basic EPS from continuing operations |
||||||||
| Income from continuing operations available for common stock |
$ | 595 | 77,865 | $ | 0.01 | |||
| Effect of other dilutive securities: |
||||||||
| Options and other dilutive securities |
— | 836 | ||||||
| Diluted EPS from continuing operations |
||||||||
| Income from continuing operations available for common stock and common stock equivalents |
$ | 595 | 78,701 | $ | 0.01 | |||
22
| Nine Months Ended September 30, 2004 | ||||||||
| Income |
Shares |
Per Share Amount | ||||||
| (Thousands, except per share amounts) | ||||||||
| Basic EPS from continuing operations |
||||||||
| Income from continuing operations available for common stock |
$ | 143,781 | 101,530 | $ | 1.42 | |||
| Effect of other dilutive securities: |
||||||||
| Mandatory convertible units |
— | 1,893 | ||||||
| Options and other dilutive securities |
— | 657 | ||||||
| Diluted EPS from continuing operations |
||||||||
| Income from continuing operations available for common stock and common stock equivalents |
$ | 143,781 | 104,080 | $ | 1.38 | |||
| Nine Months Ended September 30, 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 |
102,365 | 75,665 | $ | 1.35 | |||||
| Basic EPS from continuing operations |
$ | 1.64 | |||||||
| Income from continuing operations available for Series D |
|||||||||
| Convertible Preferred Stock dividends |
140,678 | 78,650 | |||||||
| Effect of other dilutive securities: |
|||||||||
| Options and other dilutive securities |
— | 685 | |||||||
| Series D Convertible Preferred Stock dividends |
12,072 | 18,050 | |||||||
| Income from continuing operations |
$ | 152,750 | 97,385 | $ | 1.57 | ||||
| Further dilution from applying the “two-class” method |
$ | (0.08 | ) | ||||||
| Diluted EPS from continuing operations |
$ | 1.49 | |||||||
There were 8,997 and 171,249 option shares excluded from the calculation of diluted EPS for the three months ended September 30, 2004 and 2003, respectively, since their inclusion would be antidilutive for each period. For the nine months ended September 30, 2004 and 2003, there were 14,711 and 92,203 option shares, respectively, excluded from the calculation of diluted EPS 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 three months ended September 30, 2004, the applicable average stock price was $24.73 which resulted in 3.2 million dilutive units and reduced diluted EPS by approximately $0.01 per share. For the nine months ended September 30, 2004, the applicable average stock price was $22.92 which resulted in 1.9 million dilutive units and reduced diluted EPS by approximately $0.03 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 nine months ended September 30, 2003.
23
N. Debt Covenant Compliance
On September 17, 2004, the Company entered into a $1.0 billion five-year credit agreement. The principal amount of the credit facility may be increased by $200 million if requested by the Company and the incremental commitment is received from new or existing lenders. The interest rate is a floating rate based on the Eurodollar rate plus a set number of basis points based on the Company’s current debt ratings by Moody’s Investors Service and Standard and Poors. The credit agreement contains customary affirmative and negative covenants relating to liens, investments, fundamental changes in the Company’s business, the restriction of certain payments, changes in the nature of the Company’s business, transactions with affiliates, burdensome agreements, the use of proceeds, and a limit on the Company’s debt to capital ratio.
The Company entered into an agreement with KBC Bank NV on April 20, 2004. The agreement gives the Company access to an uncommitted line of credit for loans and letters of credit up to a maximum principal amount of $10 million. The rate charged on any outstanding amount is the higher of prime or one-half of one percent above the Fed Funds overnight rate, which is the rate that banks charge each other for the overnight borrowing of funds. This agreement remains in effect until canceled by KBC Bank NV. This agreement does not contain any covenants more restrictive than those in the Company’s $1.0 billion five-year credit agreement.
The total amount of short term borrowings authorized by the board of directors is $1.2 billion.
Other debt agreements to which the Company is a party contain negative covenants that relate to liens and sale/leaseback transactions. At September 30, 2004, the Company was in compliance with all covenants.
O. Subsequent Event
In November 2004, the Company completed the sale of the propane distribution operations in and around Austin, Texas for approximately $2 million. The Company recorded a loss on the sale of approximately $0.3 million in the third quarter of 2004.
In October 2004, the Company entered into an agreement with Texas State Natural Gas, to sell the gas distribution system in Eagle Pass, Texas for approximately $2 million. The sale is expected to close in the fourth quarter of 2004.
24
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Executive Summary - On November 1, 2004, we increased our earnings guidance for 2004 to a range of $2.25 to $2.31 per diluted share of common stock from a range of $2.18 to $2.24 per diluted share of common stock. This increase is the result of continued strength in natural gas prices, natural gas liquids prices and keep whole spreads in the Gathering and Processing segment. We also reaffirmed our earnings guidance for 2005 in the range of $2.22 to $2.28 per diluted share of common stock. Because 2005 guidance includes no benefits from financial trading operations, any margins from trading activities will increase this guidance.
Our acquisition of Northern Plains Natural Gas Company is expected to close in the fourth quarter and we will own 82.5 percent of the general partner interest in Northern Border Partners, L.P., one of the largest publicly-traded master limited partnerships. The assets owned by this master limited partnership complement our existing asset base, and the acquisition provides an infrastructure that will serve as a new growth vehicle for us.
During this quarter, our board of directors voted to increase our quarterly dividend to 25 cents per share of common stock. This was the sixth increase in two years and resulted in a dividend increase of 61 percent during that period of time. Our board of directors will continue to evaluate our dividend payout in relation to both our financial performance and our peer companies, making adjustments when appropriate, to provide a fair return to our investors.
Our Energy Services segment, formerly known as Marketing and Trading, has continued our efforts to grow our wholesale and retail marketing businesses while de-emphasizing both gas options trading and unhedged pipeline arbitrage. We expect trading activity to be a smaller part of our operating income with our focus on the physical purchase and sale of natural gas. As a result of this shift in focus, we have evaluated the accounting treatment related to the presentation of revenues and on July 1, 2004 began reporting revenues from certain activities on a gross rather than net basis. Reporting of these transactions on a gross basis affects revenues and cost of sales and fuel but does not impact net margin or operating income. We also adopted Energy Services as the new name for this segment, which more clearly differentiates our organization within the industry.
In September, the class action lawsuits related to the explosions or eruptions of natural gas geysers that occurred at or near the Yaggy storage field outside of Hutchinson, Kansas were concluded. The jury awarded the plaintiffs in the residential class $5 million in actual damages, which is covered by insurance. In the other class action relating to business claims, the jury awarded no actual damages. The jury rejected claims for punitive damages in both cases.
On October 4, 2004, Moody’s Investors Service changed our ratings outlook from negative to stable. Moody’s cited our sustained improved financial leverage, financial flexibility and demonstrated commitment to improving our credit profile.
Acquisitions and Divestitures - In November 2004, we completed the sale of the propane distribution operations in and around Austin, Texas for approximately $2 million. We recorded a loss on the sale of approximately $0.3 million in the third quarter of 2004.
In October 2004, we entered into an agreement with Texas State Natural Gas to sell the gas distribution system in Eagle Pass, Texas for approximately $2 million. The sale is expected to close in the fourth quarter of 2004.
In September 2004, we announced that we entered into an agreement to purchase Northern Plains Natural Gas Company, which owns 82.5 percent of the general partnership interest and 500,000 limited partnership units, together representing a 2.73 percent ownership interest in Northern Border Partners, L.P., from CCE Holdings, LLC for $175 million. This transaction is subject to CCE Holdings, LLC closing its acquisition of CrossCountry Energy, LLC from Enron Corp. and certain of its affiliates, which is expected to occur in the fourth quarter of 2004.
In May and July 2004, we completed the sale of our propane bottle operations located in Texas and New Mexico in two separate transactions totaling approximately $1.4 million and recorded a pre-tax gain of $0.9 million, which is included in other income in the Gathering and Processing segment.
In May 2004, we sold our investment in natural gas distribution operations located in Mexico for approximately $2 million and recorded a pre-tax gain of $1.6 million, which is included in other income in the Other segment.
In March 2004, we sold certain natural gas transmission and gathering pipelines and compression facilities for approximately $13 million and recorded a pre-tax gain of $6.9 million, which is included in other income in our Transportation and Storage segment.
25
Regulatory - On January 30, 2004, the Oklahoma Corporation Commission (OCC) issued an order allowing Oklahoma Natural Gas Company (ONG) annual rate relief of $17.7 million 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 service lines and gas in storage investment. The Commission’s order also approved a modified distribution main extension policy and authorized ONG to defer expected homeland security costs. The order 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 any refund obligation is remote 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. Should our analysis indicate a potential refund liability, we will record a reserve for the obligation.
During the third quarter of 2004, the Kansas Corporation Commission (KCC) approved Kansas Gas Service Company’s (KGS) request that it be allowed to recover additional ad valorem tax expense of $3.3 million incurred above the amount currently recovered in the cost of service rate. This excess is recoverable through a surcharge.
Impact of New Accounting Standards - In May 2004, the Financial Accounting Standards Board (FASB) issued FASB Staff Position No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP FAS 106-2) as guidance on how employers should account for provisions of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Reform Act). We adopted FSP FAS 106-2 in the second quarter of 2004. FSP FAS 106-2 superceded FASB Staff Position No. FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003”, which we adopted in the first quarter of 2004. 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 at least 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. The three months ended June 30, 2004 was the first time we could record a benefit from the Medicare Reform Act, since a September 30 measurement date is used for this plan. The reduction in the accumulated postretirement benefit obligation related to benefits attributed to past service was $18.1 million. The amortization for the actuarial experience gain as a component of the net amortization was $0.4 million and $0.9 million for the three and nine months ended September 30, 2004, respectively. The reduction in current period service cost due to the subsidy was $0.1 million and $0.2 million for the three and nine months ended September 30, 2004, respectively. There was no change to the interest cost on the accumulated postretirement benefit obligation for the three months ended September 30, 2004, while there was a $0.3 million reduction for the nine months ended September 30, 2004. 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 Reform Act will have a significant effect on our retirees’ participation in our postretirement benefit plan.
Critical Accounting Policies and Estimates
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 of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (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”, No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities” 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 at fair value. A number of assumptions are considered in the determination of fair value. Our derivatives are primarily concentrated in markets where quoted prices exist. Transactions are also executed in 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 47 for amounts in our portfolio at September 30, 2004 that were determined by prices actively quoted, prices provided by other external sources, and prices derived
26
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” 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, KCC, Railroad Commission of Texas (RRC) and various municipalities in Texas. Certain of our other transportation activities are subject to regulation by the Federal Energy Regulatory Commission (FERC). ONG, KGS, Texas Gas Service Company (TGS) and portions of our Transportation and Storage segment follow the accounting and reporting guidance contained in Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation” (Statement 71). 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 September 30, 2004, our regulatory assets totaled $201.6 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.” 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 the 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. As discussed in the Liquidity and Capital Resources section of this Form 10-Q, we adjusted the discount rate from 6.25 percent to 6.75 percent when we remeasured our pension and postretirement employee benefits plans’ assets and liabilities at July 1, 2004. Our annual remeasurement will occur as of September 30, 2004 and will affect the amount of pension and postretirement benefit expenses we will record beginning January 1, 2005. Based on market conditions at September 30, 2004, we anticipate using a discount rate of 6.00 percent during this remeasurement. Absent other changes in our assumptions, this impact will increase the level of expenses in 2005 compared to 2004. See Note I of the Notes to Consolidated Financial Statements in this Form 10-Q.
27
Contingencies - Our accounting for contingencies covers a variety of business activities including contingencies for potentially uncollectible receivables and legal 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 September 30, |
Nine Months Ended September 30, |
||||||||||||
| Financial Results |
2004 |
2003 |
2004 |
2003 |
|||||||||
| (Thousands of dollars) | |||||||||||||
| Operating revenues, excluding energy trading revenues |
$ | 1,709,351 | $ | 557,093 | $ | 3,282,893 | $ | 1,966,030 | |||||
| Energy trading revenues, net |
17,411 | 11,177 | 106,583 | 183,938 | |||||||||
| Cost of gas |
1,480,662 | 373,888 | 2,520,565 | 1,320,198 | |||||||||
| Net margin |
246,100 | 194,382 | 868,911 | 829,770 | |||||||||
| Operating costs |
139,290 | 122,457 | 420,421 | 383,263 | |||||||||
| Depreciation, depletion, and amortization |
47,307 | 40,105 | 140,273 | 120,241 | |||||||||
| Operating income |
$ | 59,503 | $ | 31,820 | $ | 308,217 | $ | 326,266 | |||||
| Other income |
$ | 1,632 | $ | 1,252 | $ | 11,101 | $ | 4,157 | |||||
| Other expense |
$ | 1,338 | $ | 472 | $ | 9,811 | $ | 1,590 | |||||
| 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. Net margin increased for the three and nine months ended September 30, 2004 compared to the same periods in 2003 primarily due to:
| • | a favorable pricing environment for natural gas processing |
| • | improved margins resulting from the strategy of restructuring unprofitable gas purchase, gathering and processing contracts |
| • | volumes produced from our Texas gas and oil properties acquired in December 2003 |
| • | the impact of higher prices on our Production segment |
| • | rate relief in our Distribution segment |
These increases were partially offset by the impact of reduced volatility in natural gas prices in our results from the Energy Services segment.
Consolidated operating costs increased for both the three and nine months ended September 30, 2004 compared to the same periods in 2003, primarily due to:
| • | increased labor and employee benefit costs |
| • | increased production costs related to the acquisition of our Texas gas and oil properties |
Depreciation, depletion and amortization increased for the three and nine months ended September 30, 2004 compared to the same periods in 2003, primarily due to:
| • | additional depreciation resulting from the acquisition of the Texas gas and oil properties |
| • | regulatory asset amortization resulting from the Kansas and Oklahoma rate cases |
28
In order to consolidate the three customer service systems in our Distribution segment and provide better customer service, we are implementing a new customer service system. The system was installed in Texas and Kansas in June 2004 and September 2004, respectively. Installation will follow in Oklahoma in the future. We have implemented control processes and performed extensive testing on this system. This resulted in us identifying certain implementation issues which we are addressing. As with any implementation, there are inherent risks and uncertainties that could negatively impact us; however, we do not believe they will have a material impact on our financial statements.
The following tables show the components of other income and other expense for the three and nine months ended September 30, 2004 and 2003.
| Three Months Ended September 30, |
Nine Months Ended September 30, | |||||||||||||
| 2004 |
2003 |
2004 |
2003 | |||||||||||
| (Thousands of dollars) | ||||||||||||||
| Gain on sales of property |
$ | 1,158 | $ | — | $ | 9,765 | $ | 289 | ||||||
| Interest income |
357 | 539 | 811 | 1,623 | ||||||||||
| Partnership income |
262 | 351 | 803 | 1,137 | ||||||||||
| Income (expense) from benefit plan investments |
112 | 170 | (609 | ) | 507 | |||||||||
| Other |
(257 | ) | 192 | 331 | 601 | |||||||||
| Other income |
$ | 1,632 | $ | 1,252 | $ | 11,101 | $ | 4,157 | ||||||
| Three Months Ended September 30, |
Nine Months Ended September 30, |
||||||||||||
| 2004 |
2003 |
2004 |
2003 |
||||||||||
| (Thousands of dollars) | |||||||||||||
| Litigation expenses and claims, net |
$ | 317 | $ | 48 | $ | 7,537 | $ | (809 | ) | ||||
| Donations, civic, and governmental |
463 | 420 | 1,592 | 1,386 | |||||||||
| Loss on sales of property |
420 | — | 420 | — | |||||||||
| Other |
138 | 4 | 262 | 1,013 | |||||||||
| Other expense |
$ | 1,338 | $ | 472 | $ | 9,811 | $ | 1,590 | |||||
In 2002, we sold our claims related to the Enron bankruptcy. In the first quarter of 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. See Part II, Item 1 Legal Proceedings for additional discussion of the Enron case.
More information regarding our results of operations is provided in the discussion of operating results for each of our segments. The discontinued component is included in our Production segment’s financial results and the cumulative effect of a change in accounting principle is included in our Energy Services segment’s financial results.
Production
Overview - Our Production segment 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 producing reserves. In our role as operator, we control operating decisions that impact production volumes and lifting costs, which are costs incurred to extract the natural gas and oil. We continually focus on reducing finding costs, which is the cost per Mcfe of adding proved reserves through drilling, and minimizing production costs.
Acquisition and Divestiture - The following acquisition and divestiture are described in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2003:
| • | purchased gas and oil properties and related flow lines in December 2003 |
| • | sold natural gas and oil producing properties in January 2003 |
Development Activities - For the nine months ended September 30, 2004, we had the following results:
| • | participated in drilling 86 wells, including 19 wells during the third quarter |
29
| • | participated in completing 50 producing gas wells and three producing oil wells, including 25 gas wells and one oil well during the third quarter |
| • | 33 wells were still being drilled or completed at September 30, 2004 |
| • | no dry holes |
For the nine months ended September 30, 2003, we had the following results:
| • | participated in drilling 24 wells, including five wells during the third quarter |
| • | participated in completing 14 producing gas wells and one producing oil well, including seven producing gas wells during the third quarter |
| • | eight wells were still being drilled or completed at September 30, 2003 |
| • | one dry hole of which our net interest was six percent |
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 September 30, |
Nine Months Ended September 30, | ||||||||||||||
| Financial Results |
2004 |
2003 |
2004 |
2003 | |||||||||||
| (Thousands of dollars) | |||||||||||||||
| Natural gas sales |
$ | 20,860 | $ | 7,940 | $ | 64,085 | $ | 25,785 | |||||||
| Oil sales |
2,652 | 1,798 | 7,526 | 5,591 | |||||||||||
| Other revenues |
1,256 | 71 | 3,688 | 825 | |||||||||||
| Net margin |
24,768 | 9,809 | 75,299 | 32,201 | |||||||||||
| Operating costs |
7,242 | 3,547 | 21,283 | 11,092 | |||||||||||
| Depreciation, depletion, and amortization |
6,593 | 2,795 | 19,247 | 8,790 | |||||||||||
| Operating income |
$ | 10,933 | $ | 3,467 | $ | 34,769 | $ | 12,319 | |||||||
| Other income (expense), net |
$ | (20 | ) | $ | (3 | ) | $ | (110 | ) | $ | 2 | ||||
| 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 | |||||||
30
| Three Months Ended September 30, |
Nine Months Ended September 30, | |||||||||||||
| Operating Information |
2004 |
2003 |
2004 |
2003 | ||||||||||
| Proved reserves (a) |
||||||||||||||
| Continuing operations |
||||||||||||||
| Gas (MMcf) |
(b | ) | (b | ) | 204,793 | 62,759 | ||||||||
| Oil (MBbls) |
(b | ) | (b | ) | 3,620 | 2,140 | ||||||||
| Production |
||||||||||||||
| Continuing operations |
||||||||||||||
| Gas (MMcf) |
4,036 | 1,709 | 12,339 | 5,282 | ||||||||||
| Oil (MBbls) |
89 | 67 | 258 | 202 | ||||||||||
| Discontinued component |
||||||||||||||
| Gas (MMcf) |
— | — | — | 1,472 | ||||||||||
| Oil (MBbls) |
— | — | — | 53 | ||||||||||
| Average realized price (c) |
||||||||||||||
| Continuing operations |
||||||||||||||
| Gas ($/Mcf) |
$ | 5.17 | $ | 4.65 | $ | 5.19 | $ | 4.88 | ||||||
| Oil ($/Bbls) |
$ | 29.80 | $ | 26.84 | $ | 29.16 | $ | 27.68 | ||||||
| Discontinued component |
||||||||||||||
| Gas ($/Mcf) |
$ | — | $ | — | $ | — | $ | 4.10 | ||||||
| Oil ($/Bbls) |
$ | — | $ | — | $ | — | $ | 32.28 | ||||||
| Capital expenditures (Thousands of dollars) |
||||||||||||||
| Continuing operations |
$ | 17,190 | $ | 6,142 | $ | 37,608 | $ | 12,870 | ||||||
| (a) | Proved reserves include proved undeveloped reserves which are attributed to locations directly offsetting (adjacent to) existing production. |
| (b) | Reserves are disclosed at a point in time, therefore reserves are only shown once as of September 30, 2004 and 2003. |
| (c) | Average realized price reflects the impact of hedging activities. |
Operating Results - Natural gas and crude oil sales increased for the three and nine months ended September 30, 2004 compared to the same periods in 2003 due to:
| • | volumes produced from our Texas properties acquired in December 2003 |
| • | higher prices received on current year volumes |
Our Texas properties produced 2.1 Bcf and 6.9 Bcf of natural gas during the three and nine months ended September 30, 2004, respectively. Oil production from these properties was 28,600 Bbls and 95,600 Bbls for the same periods.
Other revenues increased for the three and nine months ended September 30, 2004 as a result of the flow line fees and revenues from our Texas flow line system which was included in the December 2003 purchase.
For both the three and nine months ended September 30, 2004 compared to the same periods in 2003, the following increases in operating costs were primarily due to the Texas acquisition:
| • | $1.1 million and $3.4 million in lease operating expenses, respectively |
| • | $0.5 million and $2.0 million in overhead costs, respectively |
| • | $0.8 million and $1.8 million in production taxes, respectively |
| • | $0.7 million and $1.7 million in ad valorem taxes, respectively |
| • | $0.6 million and $1.3 million in gathering expenses, respectively |
The increases in depreciation, depletion and amortization for the three and nine-month periods were also primarily due to the Texas acquisition.
The Production segment added 8.2 Bcfe of net natural gas and oil reserves for the nine months ended September 30, 2004. This included 4.0 Bcfe of proved developed reserves, comprised of 1.4 Bcfe of proved developed producing reserves and 2.6 Bcfe of proved developed non-producing reserves.
Discontinued Component - Income from the discontinued component includes only one month of production in 2003 before the properties were sold.
31
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 and nine months ended September 30, 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 margin. For the remainder of 2004, we have hedged approximately 95 percent of our anticipated natural gas production at an average net price at the wellhead of $5.50 per Mcf, and 100 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 19 MMcf per day of our 2005 natural gas production at a net wellhead price of $5.69 per Mcf. We have also hedged an additional 9.8 MMcf per day of our first quarter 2005 natural gas production at a net wellhead price of $6.12 per Mcf and 9.8 MMcf per day of natural gas production for the remaining three quarters of 2005 at a net wellhead price of $6.22 per Mcf. Oil production is hedged in 2005 for 15,000 Bbls per month at a fixed NYMEX price of $39.75 per Bbl.
Gathering and Processing
Overview - Our 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) primarily in Texas, Oklahoma and Kansas. We have processing capacity of approximately 1.9 Bcf/d, of which approximately 0.1 Bcf/d is currently idle. We own approximately 13,800 miles of gathering pipelines that supply gas to our processing plants.
Gathering and processing operations include the gathering of natural gas production from oil and gas wells and the processing of this raw natural gas into merchantable natural gas by extracting NGLs and removing impurities. When the liquids are separated from the raw natural gas at the processing plants, the liquids are generally in the form of a mixed stream. This stream is then separated by a distillation process into component products (ethane, propane, isobutane, normal butane and natural gasoline) by third party and company-owned fractionation facilities. The component products can then be stored, transported and marketed to a diverse customer base of end users.
We generally gather and process gas under three types of contracts. The following table sets forth our contract mix on a volumetric basis for the periods indicated.
| Three Months Ended September 30, |
Nine Months Ended September 30, |
|||||||||||
| Contract Type |
2004 |
2003 |
2004 |
2003 |
||||||||
| Fee |
43 | % | 44 | % | 45 | % | 46 | % | ||||
| Percent of Proceeds |
33 | % | 27 | % | 31 | % | 27 | % | ||||
| Keep Whole |
24 | % | 29 | % | 24 | % | 27 | % | ||||
Characteristics of the contract types are explained below.
| • | Under a fee contract, we are paid a fee for each Btu gathered, compressed and/or processed. The producer may take its share of the NGLs and natural gas in kind or receive its share of proceeds from our sale of the commodities. This type of contract exposes us to little commodity risk. |
| • | Under a percent of proceeds (POP) contract, we retain a percentage of the NGLs and/or a percentage of the natural gas as payment for gathering, compressing and processing the producer’s raw natural gas. The producer may take its share of the NGLs and natural gas in kind or receive its share of proceeds from our sale of the commodities. The POP contract exposes us to both natural gas and NGL commodity price risk, but puts the producer in economic alignment with us because we both benefit from higher commodity prices. |
| • | Under a keep whole contract, we extract NGLs and return to the producer quantities of merchantable natural gas containing the same number of Btus as the raw natural gas that was delivered to us. We retain the NGLs as our fee for processing. Accordingly, we must purchase and return to the producer sufficient quantities of merchantable natural gas to replace the Btus that were removed as NGLs through processing. By using this method, the producer is kept whole on a Btu basis. This type of contract exposes us to the keep whole, or gross processing, spread which is the difference in value between NGLs and natural gas on a Btu basis. |
32
We have been successful in amending contracts covering about 22 percent of the quantities 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. 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 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 or prices. These strategies are intended to decrease the volatility of the net margin generated by this segment.
We are exposed to volume risk from both a competitive and a production standpoint. We continue to see 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 and Divestiture - The sale of the propane bottle operations located in Texas and New Mexico in May and July, 2004 is described on page 25.
The acquisition of NGL storage and pipeline facilities located in Conway, Kansas in December 2003 is described in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 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 September 30, |
Nine Months Ended September 30, |
|||||||||||||
| Financial Results |
2004 |
2003 |
2004 |
2003 |
||||||||||
| (Thousands of dollars) | ||||||||||||||
| Natural gas liquids and condensate sales |
$ | 325,504 | $ | 259,572 | $ | 863,708 | $ | 774,355 | ||||||
| Gas sales |
166,770 | 151,146 | 483,029 | 517,768 | ||||||||||
| Gathering, compression, dehydration |
27,466 | 23,976 | 76,346 | 70,516 | ||||||||||
| Cost of sales |
435,369 | 381,238 | 1,215,727 | 1,210,518 | ||||||||||
| Net margin |
84,371 | 53,456 | 207,356 | 152,121 | ||||||||||
| Operating costs |
34,748 | 28,597 | 93,769 | 89,086 | ||||||||||
| Depreciation, depletion, and amortization |
8,304 | 7,383 | 24,470 | 21,921 | ||||||||||
| Operating income |
$ | 41,319 | $ | 17,476 | $ | 89,117 | $ | 41,114 | ||||||
| Other income (expense), net |
$ | 312 | $ | (130 | ) | $ | 23 | $ | (145 | ) | ||||
| Cumulative effect of a change in accounting |
$ | — | $ | — | $ | — | $ | (1,375 | ) | |||||
33
| Three Months Ended September 30, |
Nine Months Ended September 30, | |||||||||||
| Operating Information |
2004 |
2003 |
2004 |
2003 | ||||||||
| Total gas gathered (MMMBtu/d) |
1,099 | 1,162 | 1,106 | 1,178 | ||||||||
| Total gas processed (MMMBtu/d) |
1,175 | 1,201 | 1,162 | 1,215 | ||||||||
| Natural gas liquids sales (MBbls/d) |
108 | 112 | 107 | 113 | ||||||||
| Natural gas liquids produced (MBbls/d) |
64 | 62 | 61 | 58 | ||||||||
| Gas sales (MMMBtu/d) |
330 | 340 | 325 | 339 | ||||||||
| Capital expenditures (Thousands of dollars) |
$ | 8,500 | $ | 4,239 | $ | 18,457 | $ | 12,231 | ||||
| Conway OPIS composite NGL price ($/gal) |
$ | 0.76 | $ | 0.57 | $ | 0.68 | $ | 0.58 | ||||
| Average NYMEX crude oil price ($/Bbl) |
$ | 42.28 | $ | 30.65 | $ | 38.41 | $ | 31.30 | ||||
| Average natural gas price ($/MMBtu) (mid-continent region) |
$ | 5.43 | $ | 4.80 | $ | 5.38 | $ | 5.30 | ||||
Operating Results - Net margin for both the three and nine months ended September 30, 2004 increased compared to the same periods in 2003 primarily due to the pricing environment for natural gas processed during the third quarter of 2004 being more favorable than during any period in the last five years. Higher NGL and condensate prices, which are generally affected by crude oil prices, increased the profitability of our POP contracts as well as improved the keep whole pricing environment. Our composite gross processing spread increased as follows:
| • | $3.07 per MMBtu for the three month period in 2004 compared to $1.43 per MMBtu for the same period in 2003 |
| • | $2.17 per MMBtu for the nine month period in 2004 compared to $1.08 per MMBtu for the same period in 2003 |
The gross processing spread for both periods in 2004 was considerably higher than the five year average of $1.58. Based on current market conditions for 2005, we expect a return to the historical average as evidenced by natural gas prices recently strengthening against NGL prices despite the strong price of crude.
The renegotiation of certain NGL storage agreements at our Bushton facility and the addition of NGL storage and pipeline assets located at Conway, Kansas increased net margin for both the three and nine-month periods in 2004 compared to the same periods in 2003. Improved contractual terms for gas gathering and processing resulting from our continued efforts to restructure unprofitable gas purchase and gathering contracts continues to contribute to the increase in net margin.
Operating costs remain in line with management expectations but were higher for both the three and nine-month periods in 2004 than in the same periods in 2003 primarily as the result of higher labor and employee benefit costs. Additionally, approximately $3.3 million of the increase for both periods was related to charges associated with various contractual dispute settlements.
Depreciation, depletion and amortization increased for both the three and nine months ended September 30, 2004 compared to the same periods in 2003 primarily due to the properties acquired and our normal capital expenditure program.
Capital expenditures increased in 2004 for both the three and nine-month periods relative to the same periods in 2003 primarily due to the construction of a new 33-mile NGL pipeline that will connect our Kansas NGL storage facilities at Bushton and Conway. This pipeline is expected to cost approximately $9.2 million and be in service by December 31, 2004.
Risk Management - We used derivative instruments during the three and nine months ended September 30, 2004 and 2003 to minimize risk associated with natural gas price volatility. For the nine months ended September 30, 2004, we used derivative instruments to minimize the risk associated with our natural gas and NGL sales. The realized financial impact of the derivative transactions is included in our operating income.
Currently, for the remainder of 2004 we have:
| • | hedged approximately 66 percent of our anticipated company-owned condensate sales at an average NYMEX price of $39.40 per Bbl |
| • | pre-sold approximately 57 percent of our anticipated company-owned NGLs at a weighted average price of $0.61 per gallon |
| • | hedged approximately 67 percent of our anticipated keep whole quantities at an average gross processing spread of $3.44 per MMBtu |
34
Currently, for 2005 we have:
| • | hedged approximately 50 percent of our anticipated company-owned condensate sales at an average NYMEX price of $44.59 per Bbl |
| • | pre-sold approximately 34 percent of our anticipated company- owned NGLs at a weighted average price of $0.74 per gallon |
| • | hedged approximately 52 percent of our anticipated equity natural gas sales at a weighed average price of $6.66 per MMBtu |
Management continues to evaluate market conditions for the remainder of 2004 as well as 2005 to take advantage of favorable pricing opportunities for our company-owned production associated with the POP contracts as well as our keep whole quantities. We use a variety of risk management tools including swaps, forward sales of NGLs, and the purchase and sale of NYMEX natural gas and crude futures, respectively.
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 operate approximately 5,500 miles of gathering and intrastate transmission pipelines in Oklahoma, Kansas and Texas where we 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 revenues are derived from services provided to affiliates. We serve local distribution companies, 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 prices, fees for services and quality of service provided.
Our business is affected by the economy, price volatility and weather. Transportation throughput fluctuates due to rainfall that impacts irrigation demand, hot temperatures that affect power generation demand and cold temperatures that affect heating demand. Volatility in the natural gas market also impacts our customers’ decisions relating to injection and withdrawal of natural gas in storage.
Acquisition and Divestitures - The sale of transmission and gathering pipelines and compression facilities in March 2004 is described on page 25.
The following acquisition and divestiture are described in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2003:
| • | sold Texas transmission assets in October 2003 |
| • | acquired transmission assets as part of the purchase of our Texas assets in January 2003 |
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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 September 30, |
Nine Months Ended September 30, |
||||||||||||
| Financial Results |
2004 |
2003 |
2004 |
2003 |
|||||||||
| (Thousands of dollars) | |||||||||||||
| Transportation and gathering revenues |
$ | 24,615 | $ | 25,898 | $ | 75,186 | $ | 79,046 | |||||
| Storage revenues |
10,575 | 10,428 | 32,828 | 30,731 | |||||||||
| Gas sales and other |
1,188 | 1,648 | 3,846 | 5,236 | |||||||||
| Cost of fuel and gas |
7,935 | 11,126 | 26,439 | 31,003 | |||||||||
| Net margin |
28,443 | 26,848 | 85,421 | 84,010 | |||||||||
| Operating costs |
12,236 | 11,840 | 36,076 | 34,190 | |||||||||
| Depreciation, depletion, and amortization |
4,382 | 4,180 | 12,938 | 12,518 | |||||||||
| Operating income |
$ | 11,825 | $ | 10,828 | $ | 36,407 | $ | 37,302 | |||||
| Other income (expense), net |
$ | 238 | $ | 283 | $ | 2,335 | $ | 1,172 | |||||
| Cumulative effect of a change in accounting principle, net of tax |
$ | — | $ | — | $ | — | $ | (645 | ) | ||||
| Three Months Ended September 30, |
Nine Months Ended September 30, | |||||||||||
| Operating Information |
2004 |
2003 |
2004 |
2003 | ||||||||
| Volumes transported (MMcf) |
92,409 | 101,025 | 314,156 | 341,143 | ||||||||
| Capital expenditures (Thousands of dollars) |
$ | 3,685 | $ | 5,640 | $ | 7,696 | $ | 10,441 | ||||
| Average natural gas price ($/MMBtu) |
$ | 5.43 | $ | 4.80 | $ | 5.38 | $ | 5.30 | ||||
Operating results - Net margin showed little change for the three and nine months ended September 30, 2004 compared to the same periods in 2003 and was impacted by the following:
| • | decreased volumes transported as a result of milder and wetter weather reducing irrigation and power plant demand |
| • | increased storage revenues due to additional spot storage transactions associated with favorable market conditions resulting from the weather and favorable forward pricing in 2004 |
| • | decreased cost of fuel and gas due to lower transportation volumes partially offset by the impact of increased storage activity on fuel consumed and higher fuel prices |
Operating costs remain in line with management expectations but were slightly higher for both the three and nine-month periods in 2004 than in the same periods in 2003 primarily as the result of higher labor and employee benefit costs.
The increase in other income (expense), net for the nine months ended September 30, 2004 compared to the same period in 2003 includes the gain on the sale of the Texas assets of $6.9 million, offset by litigation costs.
Distribution
Overview - Our Distribution segment provides natural gas distribution services to approximately 2 million customers 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. 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 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.
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Acquisitions - The following acquisitions are described in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2003:
| • | 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 |
In order to consolidate the three customer service systems in our Distribution segment and provide better customer service, we are implementing a new customer service system. The system was installed in Texas and Kansas in June 2004 and September 2004, respectively. Installation will follow in Oklahoma in the future. We have implemented control processes and performed extensive testing on this system. This resulted in us identifying certain implementation issues which we are addressing. As with any implementation, there are inherent risks and uncertainties that could negatively impact us; however, we do not believe they will have a material impact on our financial statements.
Selected Financial Information - The following table sets forth certain selected financial information for the Distribution segment for the periods indicated.
| Three Months Ended September 30, |
Nine Months Ended September 30, |
|||||||||||||||
| Financial Results |
2004 |
2003 |
2004 |
2003 |
||||||||||||
| (Thousands of dollars) | ||||||||||||||||
| Gas sales |
$ | 224,727 | $ | 200,524 | $ | 1,257,299 | $ | 1,140,551 | ||||||||
| Cost of gas |
159,033 | 132,333 | 941,863 | 845,074 | ||||||||||||
| Gross margin |
65,694 | 68,191 | 315,436 | 295,477 | ||||||||||||
| Transportation revenues |
17,510 | 16,141 | 59,993 | 53,638 | ||||||||||||
| Other revenues |
5,422 | 5,169 | 20,183 | 18,680 | ||||||||||||
| Net margin |
88,626 | 89,501 | 395,612 | 367,795 | ||||||||||||
| Operating costs |
79,711 | 71,460 | 251,516 | 226,697 | ||||||||||||
| Depreciation, depletion, and amortization |
26,518 | 24,023 | 78,669 | 71,633 | ||||||||||||
| Operating income (loss) |
$ | (17,603 | ) | $ | (5,982 | ) | $ | 65,427 | $ | 69,465 | ||||||
| Other income (expense), net |
$ | (124 | ) | $ | 162 | $ | (942 | ) | (427 | ) | ||||||
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 significantly impacting our gross margin since most factors that affect gas sales also affect cost of gas by an equivalent amount.
Implementation of new rate schedules in Kansas and Oklahoma increased gross margin by $6.0 million and $1.1 million, respectively, for the three months ended September 30, 2004, compared to the same period in 2003. These increases were more than offset by the following reductions in gross margin:
| • | $1.2 million due to decreased customer usage in Oklahoma |
| • | $1.3 million due to increased line loss expense, net of rider recoveries in Oklahoma |
| • | elimination of the WeatherProof Bill program in Kansas which reduced gross margin by $7.1 million and offset the remainder of the benefit seen in the first quarter |
The increase in gross margin for the nine months ended September 30, 2004, compared to the same period in 2003, is primarily attributable to new rate schedules in Kansas and Oklahoma, which added $22.5 million and $9.4 million, respectively.
These increases in gross margin were partially offset by:
| • | $7.8 million due to decreased customer usage in all three states |
| • | $2.5 million due to increased line loss expense and decreased recoveries through rate riders |
The increase in transportation revenues for the three and nine months ended September 30, 2004 is primarily due to the acquisitions of the distribution system at the United States Army’s Fort Bliss in El Paso, Texas and a pipeline system that extends through the Rio Grande Valley region in Texas in August 2003. Additionally, lower thresholds to qualify for transportation rates in Oklahoma have contributed to the increase, as certain commercial and industrial customers have converted to transportation rates.
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Operating costs increased for the three months ended September 30, 2004 compared to the same period in 2003 primarily due to increased labor and employee benefit costs of $9.7 million.
These increases in operating costs were partially offset by:
| • | decreased property taxes of $2.0 million |
| • | decreased bad debt expense of $1.2 million |
Operating costs increased for the nine months ended September 30, 2004 compared to the same period in 2003 primarily due to:
| • | increased labor and employee benefit costs of $20.5 million |
| • | increased bad debt expense of $1.3 million |
| • | increased legal costs of $1.1 million |
| • | increased operating costs of $0.8 million due to the acquisitions of the distribution systems at the United States Army’s Fort Bliss in El Paso, Texas and a pipeline system that extends through the Rio Grande Valley region in Texas in August 2003 |
These increases in operating costs were partially offset by decreased property taxes of $0.9 million.
Depreciation, depletion and amortization increased for the three and nine months ended September 30, 2004 compared to the same period in 2003 primarily due to:
| • | regulatory asset amortization resulting from the Kansas and Oklahoma rate cases |
| • | the acquisitions of the distribution systems at the United States Army’s Fort Bliss in El Paso, Texas and a pipeline system that extends through the Rio Grande Valley region in Texas in August 2003 |
Selected Operating Data - The following table sets forth certain operating information for our Distribution segment for the periods indicated.
| Three Months Ended September 30, |
Nine Months Ended September 30, | |||||||||||
| Operating Information |
2004 |
2003 |
2004 |
2003 | ||||||||
| Average Number of Customers |
1,991,117 | 1,970,074 | 2,006,276 | 1,989,907 | ||||||||
| Customers per employee |
659 | 660 | 662 | 666 | ||||||||
| Capital expenditures (Thousands of dollars) |
$ | 43,732 | $ | 47,865 | $ | 106,332 | $ | 106,991 | ||||
| Three Months Ended September 30, |
Nine Months Ended September 30, | |||||||
| Volumes (MMcf) |
2004 |
2003 |
2004 |
2003 | ||||
| Gas sales |
||||||||
| Residential |
8,049 | 8,885 | 83,162 | 87,179 | ||||
| Commercial |
4,059 | 4,099 | 29,362 | 31,777 | ||||
| Industrial |
602 | 547 | 1,962 | 2,641 | ||||
| Wholesale |
11,360 | 8,312 | 26,765 | 21,857 | ||||
| Public Authority |
263 | 280 | 1,605 | 1,683 | ||||
| Total volumes sold |
24,333 | 22,123 | 142,856 | 145,137 | ||||
| Transportation |
55,492 | 54,125 | 177,066 | 166,772 | ||||
| Total volumes delivered |
79,825 | 76,248 | 319,922 | 311,909 | ||||
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| Three Months Ended September 30, |
Nine Months Ended September 30, | |||||||||||
| Margin |
2004 |
2003 |
2004 |
2003 | ||||||||
| (Thousands of dollars) | ||||||||||||
| Gas sales |
||||||||||||
| Residential |
$ | 52,286 | $ | 55,166 | $ | 241,309 | $ | 224,953 | ||||
| Commercial |
11,007 | 11,069 | 65,290 | 62,382 | ||||||||
| Industrial |
367 | 327 | 2,434 | 2,240 | ||||||||
| Wholesale |
1,616 | 1,209 | 4,252 | 3,957 | ||||||||
| Public Authority |
418 | 420 | 2,151 | 1,945 | ||||||||
| Gross margin |
65,694 | 68,191 | 315,436 | 295,477 | ||||||||
| Transportation |
17,510 | 16,141 | 59,993 | 53,638 | ||||||||
| Total margin |
$ | 83,204 | $ | 84,332 | $ | 375,429 | $ | 349,115 | ||||
Residential and commercial volumes decreased for the three and nine months ended September 30, 2004 compared to the same periods 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 nine months ended September 30, 2004 compared to the same period in 2003 due to industrial customers migrating to new transportation rates in Oklahoma.
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 and nine months ended September 30, 2004 compared to the same periods in 2003 as fewer volumes were required to meet the needs of 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.
Transportation volumes increased for the three and nine months ended September 30, 2004 compared to the same periods in 2003 primarily due to:
| • | the acquisitions of the distribution systems at the United States Army’s Fort Bliss in El Paso, Texas and a pipeline system that extends through the Rio Grande Valley region in Texas in August 2003 |
| • | ONG’s commercial and industrial customers migrating to new transportation rates |
| • | 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 upgrade facilities to assure safe, reliable, and efficient operations. Our capital expenditure program included $8.0 million and $10.6 million for new business development for the three months ended September 30, 2004 and 2003, respectively, and $25.0 million and $22.5 million for new business development for the nine months ended September 30, 2004 and 2003, respectively.
Regulatory Initiatives
Oklahoma - On January 30, 2004, the OCC issued an order allowing 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 service lines and gas in storage investment. The Commission’s order also approved a modified distribution main extension policy and authorized ONG to defer expected homeland security costs. The order 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 any refund obligation is remote 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.
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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, we estimate that operating income will increase by approximately $29.6 million annually.
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. On July 22, 2004, the RRC approved approximately $0.9 million in annual revenue relief. The interim rates were implemented in May 2003.
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.
Energy Services
Overview - Our Energy Services segment, formerly known as Marketing and Trading, primarily purchases, stores, transports and markets natural gas in the retail sector in our core distribution area and the wholesale sector throughout most of the United States. We have a large storage and transport position, primarily in the mid-continent region of the United States, with total transportation capacity of 1.4 Bcf/d. With total cyclical storage capacity of 84.7 Bcf, maximum withdrawal capability of 2.3 Bcf/d and maximum injection capability of 1.6 Bcf/d spread across 18 different facilities, we have direct access to most regions of the country and flexibility to capture volatility in the energy markets. Due to seasonality of supply and demand balances, earnings will be significantly higher during the winter period than the summer period. We recently extended our energy services operations into Canada by leasing storage and pipeline capacity. Our Canadian operations bring gas supply from western Canada into the market areas of the upper midwestern and northeastern parts of the United States. We also trade natural gas and power on a smaller scale.
We continue to enhance our customer focused strategy by providing reliable service during peak demand periods through the use of our storage and transportation capacities. The physical and financial energy services we provide to our customers help them better execute their commodity procurement and asset management strategies.
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 its 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 increased our owned or contracted power capacity from 300 to 512 megawatts.
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Selected Financial and Operating Information - The following tables set forth certain selected financial and operating information for the Energy Services segment for the periods indicated.
| Three Months Ended September 30, |
Nine Months Ended September 30, |
|||||||||||||||
| Financial Results |
2004 |
2003 |
2004 |
2003 |
||||||||||||
| (Thousands of dollars) | ||||||||||||||||
| Energy and power revenues |
$ | 1,128,025 | $ | 26,896 | $ | 1,210,130 | $ | 60,421 | ||||||||
| Energy trading revenues, net |
17,411 | 11,177 | 106,583 | 183,938 | ||||||||||||
| Other revenues |
205 | 159 | 649 | 775 | ||||||||||||
| Cost of sales and fuel |
1,126,039 | 23,736 | 1,208,144 | 53,760 | ||||||||||||
| Net margin |
19,602 | 14,496 | 109,218 | 191,374 | ||||||||||||
| Operating costs |
7,197 | 6,750 | 25,669 | 23,275 | ||||||||||||
| Depreciation, depletion, and amortization |
1,398 | 1,397 | 4,213 | 4,328 | ||||||||||||
| Operating income |
$ | 11,007 | $ | 6,349 | $ | 79,336 | $ | 163,771 | ||||||||
| Other income (expense), net |
$ | (1,874 | ) | $ | (1,632 | ) | $ | (5,398 | ) | $ | (4,617 | ) | ||||
| Cumulative effect of changes in accounting principle, net of tax |
$ | — | $ | — | $ | — | $ | (141,982 | ) | |||||||
| Three Months Ended September 30, |
Nine Months Ended September 30, | |||||||||||
| Operating Information |
2004 |
2003 |
2004 |
2003 | ||||||||
| Natural gas marketed (MMcf) |
240,462 | 220,622 | 775,618 | 754,769 | ||||||||
| Natural gas gross margin ($/Mcf) |
$ | 0.07 | $ | 0.03 | $ | 0.11 | $ | 0.19 | ||||
| Electricity marketed (MMwh) |
1,661 | 561 | 3,412 | 1,304 | ||||||||
| Physically settled volumes (MMcf) |
507,965 | 469,958 | 1,558,578 | 1,519,694 | ||||||||
| Capital expenditures (Thousands of dollars) |
$ | 558 | $ | 92 | $ | 1,372 | $ | 488 | ||||
Operating Results - At the beginning of the third quarter, we completed a reorganization of our Energy Services segment and renewed our focus on our physical marketing and storage business. We separated the management and operations of our physical marketing, retail marketing and trading activities and began accounting separately for the different types of revenue earned from these activities. Prior to the third quarter, we managed the Energy Services segment on an integrated basis and presented all energy trading activity on a net basis. Power sales are accounted for as trading activities and, accordingly, are included in trading. The following table shows these types of margins by activity:
| Three Months Ended September 30, 2004 |
||||
| (Thousands of dollars) | ||||
| Marketing and storage |
$ | 29,906 | ||
| Trading |
18,589 | |||
| Retail marketing |
3,051 | |||
| Transportation and storage costs |
(31,944 | ) | ||
| Net margin |
$ | 19,602 | ||
Concurrent with this reorganization, we evaluated the accounting treatment related to the presentation of revenues from the different types of activities to determine which amounts should be reported on a gross or net basis under the guidance in 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). For derivative instruments considered held for trading purposes that result in physical delivery, the indicators 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” were used to determine the proper treatment. These activities and all financially settled derivative contracts will continue to be reported on a net basis.
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For derivative instruments that are not considered “held for trading purposes” and that result in physical delivery, the indicators in EITF 03-11 and EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent” (EITF 99-19) were used to determine the proper treatment. We began accounting for the realized revenues and purchase costs of these contracts that result in physical delivery on a gross basis beginning with the third quarter of 2004. We apply the indicators in EITF No. 99-19, to determine the appropriate accounting treatment for non-derivative contracts that result in physical delivery. Derivatives that qualify for the normal purchase or sale exception as defined in Statement 133 are also reported on a gross basis. No prior periods have been adjusted for this change; therefore, comparisons to prior periods may not be meaningful. Reporting of these transactions on a gross basis did not impact operating income but resulted in an increase to revenues and cost of sales and fuel.
Net margin increased for the three months ended September 30, 2004 compared to the same period in 2003 primarily due to the increase in the mark to market value of our derivative contracts subject to fair value accounting, which increased $17.9 million, primarily due to increased natural gas volatility. A decrease of approximately 17 percent in cooling degree days led to reduced demand for electric generation offsetting much of this increase.
Other decreases in net margin were:
| • | increased expenses of $2.8 million included in cost of sales and fuel resulting from increased storage and transportation capacity |
| • | weaker spark spreads of $2.0 million in the Southwest Power Pool and ERCOT resulting from unseasonably mild weather conditions in July and August 2004 |
| • | a decrease of $0.6 million in our retail natural gas operations primarily due to lack of irrigation demand because of above normal rainfall in Kansas and Nebraska |
For the nine months ended September 30, 2004, compared to the same period in 2003, net margin decreased primarily by:
| • | $37.7 million due to lower natural gas price volatility and the impact it has on our trading portfolio |
| • | $43.7 million due to lower inter-regional basis spreads early in 2004 |
| • | $5.5 million due to weaker spark spreads in the Southwest Power Pool and ERCOT |
These decreases were partially offset by increased revenues of $8.0 million from reservation fees for natural gas peaking services.
Natural gas sales volumes increased for the three months ended September 30, 2004, compared to the same period in 2003 due to expanded Canadian operations and higher natural gas storage inventory levels at the beginning of the third quarter of 2004, which shifted purchased volumes from storage injections to regional sales.
Our natural gas storage inventory level at September 30, 2004 was 79.1 Bcf, or 86.8 percent of capacity, compared to 71.1 Bcf, or 88.4 percent of capacity, at September 30, 2003.
Operating costs increased $2.4 million for the nine months ended September 30, 2004 compared to the same period in 2003 primarily due to:
| • | $0.7 million increase in start-up costs associated with our Canadian operations |
| • | $0.8 million increase in ad valorem taxes |
| • | $0.9 million increase in employee-related costs |
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 half 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 in the range of $270 million to $280 million compared to $215 million in 2003, exclusive of any acquisitions.
Financing - Financing is provided through our commercial paper program, long-term debt and, as needed, through a credit agreement. Other options to obtain financing include, but are not limited to, issuance of equity, issuance of mandatory 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. We expect to issue commercial paper to finance the acquisition of Northern Plains Natural Gas Company.
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Credit Rating - Our credit ratings are currently an “A-” (stable outlook) by Standard and Poors and a “Baa1” (stable outlook) by Moody’s Investors Service. Our credit ratings 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 ratings 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 a $1 billion credit agreement, which expires September 16, 2009.
Our Energy Services segment relies heavily upon the investment grade rating of our senior unsecured long-term debt to satisfy credit requirements with most of our 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 may be required to fund margin requirements with our counterparties with cash, letters of credit or other negotiable instruments. At September 30, 2004, the amount we could be required to fund the few counterparties with which we have a Credit Support Annex within our International Swaps and Derivatives Association Agreements is approximately $81.7 million. A decline in our credit rating below investment grade may also significantly impact other business segments.
We have reviewed our commercial paper agreement, trust indentures, building leases, equipment leases, marketing, trading and risk contracts and other various contracts which may be subject to rating triggers and no such 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, 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. Additionally, a remeasurement of plan assets and liabilities at July 1, 2004 was triggered by changes in our contracts with the bargaining units. Because of market conditions at July 1, 2004, we selected a discount rate of 6.75 percent to remeasure our plan. The net impact of these changes increased our pension costs for 2004 by approximately $2.8 million. We also had a nonrecurring reduction in the value of the assets of $1.7 million in the third quarter of 2004. Accordingly, our pension credit for our pension and supplemental retirement plans will decrease from $4.4 million in 2003 to a charge of $0.9 million in 2004. If the value of our pension fund assets decreases below our accumulated benefit obligation, we will eliminate the asset and record a minimum pension liability on our 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 $151.3 million for the nine months ended September 30, 2004 compared to the same period in 2003, despite a 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 nine months ended September 30, 2003, we injected higher levels of inventory into storage, which negatively impacted our 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.
Investing Cash Flows - Proceeds from the sale of certain natural gas transmission and gathering pipelines, compression assets and investments totaled approximately $17.2 million.
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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.
| September 30, 2004 |
December 31, 2003 |
|||||
| Long-term debt |
57 | % | 60 | % | ||
| Equity |
43 | % | 40 | % | ||
| Debt (including Notes payable) |
61 | % | 67 | % | ||
| Equity |
39 | % | 33 | % | ||
At September 30, 2004, we had $1.9 billion of long-term debt outstanding, including current maturities. As of September 30, 2004, we could have issued $1.6 billion of additional long-term debt under the most restrictive provisions contained in our various borrowing agreements. During the first quarter of 2004, we paid off $600 million in notes payable using cash generated from operating activities and proceeds from our February 2004 equity offering. During the third quarter of 2004, we incurred $258 million of notes payable used in the ordinary course of business.
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 51 percent long-term debt and 49 percent equity at September 30, 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 48 percent long-term debt and 52 percent equity at September 30, 2004.
We signed a $1 billion, five year credit agreement on September 17, 2004. The agreement expires on September 16, 2009, at which time all outstanding amounts under the credit agreement will be due and payable. This agreement is primarily used to support our commercial paper program. At September 30, 2004, we had $298 million in commercial paper outstanding and approximately $17.8 million in cash and temporary investments.
Since September 17, 2004, the Thrift Plan for Employees of ONEOK, Inc. and subsidiaries (the Thrift Plan) has from time to time purchased shares of our common stock on the open market to meet the purchase requirements generated by participants in the Thrift Plan. Previously, the Thrift Plan used newly issued shares to meet the participants’ purchase requirements. All participant purchases under this plan are voluntary. We use newly issued shares to meet the purchase requirements generated by our Dividend Reinvestment Plan and our Long-Term Incentive Plan.
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; |
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| • | 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. |
Other
Labor Negotiations - On July 1, 2004, KGS and the United Steelworkers of America Locals 12561, 13417, and 14228, the Gas Workers Metal Trades of the United Association of Journeyman and Apprentices of the Plumbing and Pipefitting Industry of the United States and Canada Local 781 and the International Union of Operating Engineers Local 126 labor unions agreed upon a five-year contract expiring June 30, 2009. Approximately 463 of our KGS employees are members of these three labor unions, comprising approximately 41 percent of our KGS workforce. The parties agreed to a three percent wage increase retroactive to June 1, 2004 and an increase for each of the next four years as follows:
| • | three percent beginning July 1, 2005 |
| • | two and one-half percent beginning July 1, 2006 |
| • | two and one-half percent beginning July 1, 2007 |
| • | two and one-half percent beginning July 1, 2008 |
Currently, we have no ongoing labor negotiations.
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 of the natural gas business; |
| • | competitive changes in the natural gas gathering, transportation and storage business resulting from deregulation of the natural gas business; |
| • | the profitability of assets or businesses acquired by us; |
| • | risks of marketing, hedging, and trading activities as a result of changes in energy prices or the financial condition of our counterparties; |
| • | economic climate and growth in the geographic areas in which we do business; |
| • | the uncertainty of estimates, including accruals, cost of environmental remediation, 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; |
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| • | 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 and bond 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 at 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 terrorist attacks; |
| • | risks associated with the adequate supply of natural gas to our gathering and processing facilities, including from production declines, which outpace new drilling; |
| • | risks inherent in the implementation of new software, such as our customer service system, and the impact on the timeliness of information for financial reporting; |
| • | the risk that material weaknesses or significant deficiencies in internal control over financial reporting could emerge or that minor problems could become significant; |
| • | the impact of the outcome of pending and future litigation; 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 Ris k
Our quantitative and qualitative disclosures about market risk are consistent with those discussed in our Annual Report on 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. TGS may use derivative instruments to mitigate the volatility of gas costs to protect its customers in the city of El Paso. At September 30, 2004, KGS and TGS had derivative instruments in place to hedge the cost of natural gas purchases for 11.0 Bcf and 0.4 Bcf, respectively, which represents part of their gas purchase requirements for the 2004/2005 winter heating months based on normal weather conditions. Gains or losses associated with the KGS and TGS hedges are included in and recoverable through the monthly purchased gas adjustment.
The following table provides a detail of our Energy Services segment’s maturity of derivatives based on heating injection and withdrawal periods from April to March. Executory storage and transportation contracts and their related hedges are not included in the following table. This maturity schedule is consistent with our Energy Services segment’s trading strategy.
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| Fair Value of Contracts at September 30, 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) |
$ | 116,799 | $ | 5,190 | $ | — | $ | — | $ | 121,989 | |||||||||
| Prices provided by other external sources (3) |
(116,308 | ) | (11,729 | ) | — | (128,037 | ) | ||||||||||||
| Prices derived from quotes, other external sources and other assumptions (4) |
(11 | ) | (218 | ) | (1,232 | ) | 426 | (1,035 | ) | ||||||||||
| Total |
$ | 480 | $ | (6,757 | ) | $ | (1,232 | ) | $ | 426 | $ | (7,083 | ) | ||||||
| (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 September 30, 2004, the interest rate on approximately 59 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 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 upon termination of the interest rate swaps were $81.9 million, after reduction for ineffectiveness and unpaid interest. Through September 30, 2004, $5.6 million in interest expense savings has been recognized and the remaining amount of $76.3 million will be recognized in the income statement over the remaining term of the debt instruments originally hedged. Consequently, the remaining savings in interest expense will be recognized over the following periods:
| Remainder of 2004 |
$ | 2.5 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. At September 30, 2004, we recorded a $14.5 million net liability to recognize the interest rate swaps at fair value. Long-term debt was also decreased by $14.5 million to recognize the change in the fair value of the related hedged liability.
Total savings from the interest rate swaps was $23.2 million for the first nine months of 2004. The swaps are expected to generate the following savings for the remainder of the year:
| • | interest expense savings of $2.6 million for remainder of 2004 related to the amortization of the swap value at termination |
| • | up to $2.3 million in interest savings from the new swaps based on current LIBOR rates |
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Total swap savings for 2004 are expected to be $28.1 million, which is an increase over the savings of $24.4 million and $20.6 million in 2003 and 2002, respectively.
A 100 basis point move in the LIBOR rate on all of our outstanding long-term debt would change annual interest expense by approximately $7.4 million before taxes. If interest rates changed significantly, we may have the ability to 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 our Energy Services 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 U.S. 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 margin. At September 30, 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 $4.2 million and $9.0 million at September 30, 2004 and 2003, respectively.
The following table details the average, high and low VAR calculations.
| Three Months Ended September 30, |
Nine Months Ended September 30, | |||||||||||
| Value-at-Risk |
2004 |
2003 |
2004 |
2003 | ||||||||
| (Millions of dollars) | ||||||||||||
| Average |
$ | 1.8 | $ | 1.8 | $ | 3.5 | $ | 3.5 | ||||
| High |
$ | 4.2 | $ | 3.9 | $ | 17.7 | $ | 17.1 | ||||
| Low |
$ | 0.6 | $ | 0.8 | $ | 0.6 | $ | 0.8 | ||||
The variations in the VAR data are reflective of market volatility and changes in the portfolio during the quarter.
Item 4. Controls and Procedur es
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 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 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.
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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.
Conclusions - In the course of our ongoing evaluation, management has identified certain implementation issues which we are addressing related to the implementation of the new customer service system for our Distribution segment. We are implementing this system in order to consolidate the three customer service systems in our Distribution segment and to provide better customer service. The system was installed in Texas and Kansas in June 2004 and September 2004, respectively. Installation will follow in Oklahoma in the future. We have implemented control processes and performed extensive testing. As with any implementation, there are inherent risks and uncertainties that could negatively impact us; however, we do not believe they will have a material impact on our financial statements.
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.
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. These two separate class action lawsuits filed against us in early 2001 relating to the natural gas explosions in Hutchinson, Kansas, resulted in jury verdicts in September 2004 in both cases. In the class action relating to the residential claimants, the jury awarded the claimants $5 million in actual damages, which is covered by insurance. In the other class action relating to business claims, the jury awarded no actual damages. The jury rejected claims for punitive damages in both cases. We are reviewing our options for appeal of the residential claimants’ class action. With the exception of a related lawsuit that was filed in Sedgwick County, Kansas, which is now on appeal (see Note J of the Notes to Consolidated Financial Statements included in this Form 10-Q for additional discussion on this matter), all other litigation regarding the gas explosions has been resolved.
Cornerstone 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., Case No. 04-CV-00758, in the United States District Court for the Southern District of New York. On August 17, 2004, this case was consolidated for all purposes with a related lawsuit which names a number of other defendants in the energy industry. Plaintiffs in the related case assert allegations similar to those alleged against us in this case. On September 24, 2004, our motion to dismiss was denied. Discovery is underway. 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; Related Contested Matter in Case No. 01-16034. As reported previously, our subsidiary, ONEOK Energy Services, L.P. (formerly ONEOK Energy Marketing and Trading Company, L.P.) (“OES”), has repurchased from Angelo Gordon a portion (the “Repurchased Claim”) of the Enron Corp. guaranty claim (the “Guaranty Claim”) that Enron Corp. sought to avoid in the adversary proceeding (the “Adversary Proceeding”), as contemplated by the Transfer of Claims Agreement whereby OES originally sold the Guaranty Claim. OES is now providing the defense of the Adversary Proceeding for both the portion of the Guaranty Claim constituting the Repurchased Claim and also the portion of the Guaranty Claim still owned by Angelo Gordon’s successors in interest. Based on information currently available to us, we do not expect the Adversary Proceeding to have a
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material adverse effect on us. In addition to the Adversary Proceeding, Enron Corp. and Enron North America Corp. (“ENA”) have filed a new objection to portions of the Guaranty Claim and to portions of the underlying claim against ENA (the “Underlying ENA Claim”), instituting a new contested matter in the Enron Corp. bankruptcy case (the “Contested Matter”). The Contested Matter involves different legal and factual issues than those raised in the Adversary Proceeding. Enron Corp. and ENA allege in the Contested Matter that the Guaranty Claim and the Underlying ENA Claim are overstated. The filing of the Contested Matter may trigger additional obligations of OES under the Transfer of Claims Agreement to repurchase some of the claims previously sold. However, based on information currently available to us, we do not expect the Contested Matter to have a material adverse effect on us.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Issuer Purchases of Equity Securities
The following table sets forth information relating to our recent purchases of equity securities.
| Period |
Total Number of Shares (or Units) Purchased |
Average Price Paid per Share (or Unit) |
Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs |
Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs | ||||||
| July 1-31, 2004 |
32,860 | (1)(2)(3) | $ | 21.84 | — | — | ||||
| August 1-31, 2004 |
24,989 | (2)(3) | $ | 22.72 | — | — | ||||
| September 1-30, 2004 |
34,453 | (2) | $ | 24.20 | — | — | ||||
| Total |
92,302 | $ | 22.96 | — | — | |||||
| (1) | Includes restricted stock forfeitures for failure to satisfy vesting conditions as follows: |
985 shares for the period July 1-31, 2004
| (2) | Includes shares withheld pursuant to attestation of ownership and deemed tendered to the Company in connection with the exercise of stock options under the ONEOK, Inc. Long-Term Incentive Plan, as follows : |
31,869 shares for the period July 1-31, 2004
24,985 shares for the period August 1-31, 2004
34,453 shares for the period September 1-30, 2004
| (3) | Includes shares repurchased directly from employees as follows: |
six shares for the period July 1-31, 2004
four shares for the period August 1-31, 2004
Employee Stock Award Program
Under our Employee Stock Award Program, we will issue, for no consideration, to all eligible employees (all full-time employees and employees on short-term disability) one share of our common stock when the per-share closing price of our common stock on the New York Stock Exchange (“NYSE”) is for the first time at or above $26 per share, and we will issue, for no consideration, one additional share of our common stock to all eligible employees when the closing price on the NYSE is for the first time at or above each one dollar increment above $26 per share. A total of 50,000 shares of our common stock are available for issuance under this program.
On September 30, 2004, the per-share price of our common stock closed for the first time at or above $26 on the NYSE. Accordingly, we issued one share of our common stock to each of our eligible employees on September 30, 2004, for a total of 4,223 shares. The issuance of shares under this program has not been registered under the Securities Act of 1933, as amended (“1933 Act”) in reliance upon Securities and Exchange Commission releases, including Release No. 6188, dated February 1, 1980, stating that there is no sale of the shares in the 1933 Act sense to employees under this type of program.
Item 3. Defaults Upon Senior Securitie s
Not Applicable.
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Item 4. Submission of Matters to Vote of Security Holders
Not Applicable.
Not Applicable.
The following exhibits are filed as part of this Quarterly Report on Form 10-Q:
| Exhibit No. |
Exhibit Description | |
| 10.1 | Form of 2003 Non-Statutory Stock Option. | |
| 10.2 | Form of 2003 Restricted Stock Award. | |
| 10.3 | Form of 2003 Performance Shares Award. | |
| 10.4 | Form of 2004 Restricted Stock Incentive Award. | |
| 10.5 | Form of 2004 Performance Shares Award. | |
| 12 | Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirement for the nine months ended September 30, 2004 and 2003. | |
| 12.1 | Computation of Ratio of Earnings to Fixed Charges for the nine months ended September 30, 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)). | |
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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: November 3, 2004 |
By: |
/s/ Jim Kneale | ||
| Jim Kneale Executive Vice President - Finance and Administration and Chief Financial Officer (Principal Financial Officer) | ||||
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