| Value of $100 Investment Assuming Reinvestment of Dividends At December 31, 2002, and at the End of Every Year Through December 31, 2007
Among ONEOK, Inc., The S&P 500 Index and The S&P Utilities Index
| | | | | | | | | | | | | | | | | | | | | | | | Cumulative Total Return | | | | Years Ending December 31, | | | | | | 2002 | | 2003 | | 2004 | | 2005 | | 2006 | | 2007 | | | ONEOK, Inc. | | $ | 100.00 | | $ | 119.08 | | $ | 159.26 | | $ | 154.82 | | $ | 259.72 | | $ | 277.69 | | | S&P 500 Index | | $ | 100.00 | | $ | 128.68 | | $ | 142.69 | | $ | 149.70 | | $ | 173.34 | | $ | 182.87 | | | S&P Utilities Index (a) | | $ | 100.00 | | $ | 126.26 | | $ | 156.91 | | $ | 183.34 | | $ | 221.82 | | $ | 264.81 | | |
| | | | | (a)At December 31, 2003, and at the End of Every Year Through December 31, 2008 | | - | | Among ONEOK, Inc., The Standard & PoorsS&P 500 Index and The S&P Utilities Index is comprised of the following companies: AES Corp.; Allegheny Energy, Inc.; Ameren Corp.; American Electric Power Co., Inc.; Centerpoint Energy, Inc.; CMS Energy Corp.; Consolidated Edison, Inc.; Constellation Energy Group, Inc.; Dominion Resources, Inc.; DTE Energy Co.; Duke Energy Corp.; Dynegy, Inc.; Edison International; Entergy Corp.; Exelon Corp.; FirstEnergy Corp.; FPL Group, Inc.; Integrys Energy Group, Inc.; Nicor, Inc.; NiSource, Inc.; Pepco Holdings, Inc.; PG&E Corp.; Pinnacle West Capital Corp.; PPL Corp.; Progress Energy, Inc.; Public Service Enterprise Group, Inc.; Questar Corp.; Sempra Energy; Southern Co.; TECO Energy, Inc.; and Xcel Energy, Inc. |
ITEM 6. | SELECTED FINANCIAL DATA |
| | | Cumulative Total Return | | | | | Years Ending December 31, | | | | | 2003 | | | 2004 | | | 2005 | | | 2006 | | | 2007 | | | 2008 | | | | | | | | | | | | | | | | | | | | | | | ONEOK, Inc. | | $ | 100.00 | | | $ | 133.74 | | | $ | 130.01 | | | $ | 218.10 | | | $ | 233.19 | | | $ | 157.65 | | | S&P 500 Index | | $ | 100.00 | | | $ | 110.88 | | | $ | 116.32 | | | $ | 134.69 | | | $ | 142.09 | | | $ | 89.52 | | | S&P Utilities Index (a) | | $ | 100.00 | | | $ | 124.28 | | | $ | 145.21 | | | $ | 175.69 | | | $ | 209.73 | | | $ | 148.95 | | | (a) - The Standard & Poors Utilities Index is comprised of the following companies: AES Corp.; Allegheny Energy, Inc.; | | | Ameren Corp.; American Electric Power Co., Inc.; Centerpoint Energy, Inc.; CMS Energy Corp.; Consolidated Edison, Inc.; | | | Constellation Energy Group, Inc.; Dominion Resources, Inc.; DTE Energy Co.; Duke Energy Corp.; Dynegy, Inc.; Edison | | | International; Entergy Corp.; Equitable Resources, Inc.; Exelon Corp.; FirstEnergy Corp.; FPL Group, Inc.; Integrys Energy | | | Group, Inc.; Nicor, Inc.; NiSource, Inc.; Pepco Holdings, Inc.; PG&E Corp.; Pinnacle West Capital Corp.; PPL Corp.; Progress | | | Energy, Inc.; Public Service Enterprise Group, Inc.; Questar Corp.; SCANA Corp.; Sempra Energy; Southern Co.; TECO | | | Energy, Inc.; Wisconsin Energy Corp.; and Xcel Energy, Inc. | | | | | | | | | | | | | | | | | |
The following table sets forth our selected financial data for each of the periods indicated. | | | | | | | | | | | | | | | | | | | | | Years Ended December 31, | | | | 2007 | | 2006 | | 2005 | | 2004 | | 2003 | | | | | | (Millions of dollars, except per share amounts) | | | Net margin from continuing operations | | $ | 1,810.1 | | $ | 1,722.0 | | $ | 1,338.2 | | $ | 1,137.2 | | $ | 1,084.8 | | | Operating income from continuing operations | | $ | 822.5 | | $ | 862.2 | | $ | 803.8 | | $ | 443.7 | | $ | 427.9 | | | Income from continuing operations | | $ | 304.9 | | $ | 306.7 | | $ | 403.1 | | $ | 224.7 | | $ | 206.4 | | | Total assets | | $ | 11,062.0 | | $ | 10,391.1 | | $ | 9,284.2 | | $ | 7,199.2 | | $ | 6,211.9 | | | Long-term debt | | $ | 4,635.5 | | $ | 4,049.0 | | $ | 2,030.6 | | $ | 1,884.7 | | $ | 1,884.6 | | | Basic earnings per share - continuing operations | | $ | 2.84 | | $ | 2.74 | | $ | 4.01 | | $ | 2.21 | | $ | 2.28 | | | Basic earnings per share - total | | $ | 2.84 | | $ | 2.74 | | $ | 5.44 | | $ | 2.38 | | $ | 1.48 | | | Diluted earnings per share - continuing operations | | $ | 2.79 | | $ | 2.68 | | $ | 3.73 | | $ | 2.13 | | $ | 2.05 | | | Diluted earnings per share - total | | $ | 2.79 | | $ | 2.68 | | $ | 5.06 | | $ | 2.30 | | $ | 1.22 | | | Dividends declared per common share | | $ | 1.40 | | $ | 1.22 | | $ | 1.09 | | $ | 0.88 | | $ | 0.69 | | |
| | | Years Ended December 31, | | | | | 2008 | | | 2007 | | | 2006 | | | 2005 | | | 2004 | | | | | (Millions of dollars, except per share amounts) | �� | | Revenues | | $ | 16,157.4 | | | $ | 13,477.4 | | | $ | 11,920.3 | | | $ | 12,676.2 | | | $ | 5,785.5 | | | Income from continuing operations | | $ | 311.9 | | | $ | 304.9 | | | $ | 306.7 | | | $ | 403.1 | | | $ | 224.7 | | | Net income | | $ | 311.9 | | | $ | 304.9 | | | $ | 306.3 | | | $ | 546.5 | | | $ | 242.2 | | | Total assets | | $ | 13,126.1 | | | $ | 11,062.0 | | | $ | 10,391.1 | | | $ | 9,284.2 | | | $ | 7,199.2 | | | Long-term debt, including current maturities | | $ | 4,230.8 | | | $ | 4,635.5 | | | $ | 4,049.0 | | | $ | 2,030.6 | | | $ | 1,884.7 | | | Basic earnings per share - continuing operations | | $ | 2.99 | | | $ | 2.84 | | | $ | 2.74 | | | $ | 4.01 | | | $ | 2.21 | | | Basic earnings per share - total | | $ | 2.99 | | | $ | 2.84 | | | $ | 2.74 | | | $ | 5.44 | | | $ | 2.38 | | | Diluted earnings per share - continuing operations | | $ | 2.95 | | | $ | 2.79 | | | $ | 2.68 | | | $ | 3.73 | | | $ | 2.13 | | | Diluted earnings per share - total | | $ | 2.95 | | | $ | 2.79 | | | $ | 2.68 | | | $ | 5.06 | | | $ | 2.30 | | | Dividends declared per common share | | $ | 1.56 | | | $ | 1.40 | | | $ | 1.22 | | | $ | 1.09 | | | $ | 0.88 | |
Financial data for 2008, 2007 and 2006 is not directly comparable with 2005 and 2004 due to the significance of the sale of certain assets to ONEOK Partners in April 2006. See discussion of acquisitions dispositions and changes in consolidationdispositions beginning on page 2936 under “Significant Acquisitions and Divestitures” in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation. ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION |
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION
The following discussion and analysis should be read in conjunction with our audited consolidated financial statements and the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
The following discussion highlights some of our achievements and significant issues affecting us this past year. Please refer to the Financial“Financial Results and Operating Results sectionInformation,” “Liquidity and Capital Resources,” and “Capital Projects” sections of Management’s Discussion and Analysis of Financial Condition and Results of Operation and the Consolidated Financial Statementsour consolidated financial statements for a complete explanation of the following items.additional information.
Operating Results - Diluted earnings per share of common stock from continuing operations (EPS) increased to $2.95 in 2008, compared with $2.79 in 2007, compared with $2.68 in 2006. The increase in operating2007. Operating income for 2007, compared with 2006, and exclusive of the gain on sale of assets,2008 increased to $917.0 million from $822.5 million for 2007. This increase is primarily due to the implementation of new rate schedules in Kansas and Texas in our Distribution segment and new supply connections and higherwider NGL product price spreads in our ONEOK Partners’ natural gas liquids businesses. This increase was partially offset by reduceddifferentials, higher realized commodity prices, increased NGL gathering and fractionation volumes, and incremental operating income in our Energy Services segment primarily due to decreased transportation margins during 2007.In September 2007, ONEOK Partners completed an underwritten public debt offering of $600 million to financeassociated with the assets acquired from Kinder Morgan Energy Partners, L.P. (Kinder Morgan), all in our ONEOK Partners segment. This increase in operating income was partially offset by decreases in storage and marketing margins and transportation margins, net of hedging activities, in our Energy Services segment.
ONEOK Partners’ Equity Issuance - In March 2008, we purchased from ONEOK Partners, in a private placement, an additional 5.4 million of ONEOK Partners’ common units for a total purchase price of approximately $303.2 million. In addition, ONEOK Partners completed a public offering of 2.5 million common units at $58.10 per common unit and received net proceeds of $140.4 million after deducting underwriting discounts but before offering expenses. In conjunction with ONEOK Partners’ private placement and public offering of common units, ONEOK Partners GP contributed $9.4 million to ONEOK Partners in order to maintain its 2 percent general partner interest.
In April 2008, ONEOK Partners sold an additional 128,873 common units at $58.10 per common unit to the underwriters of the public offering upon the partial exercise of their option to purchase additional common units to cover over-allotments. ONEOK Partners received net proceeds of approximately $7.2 million from the sale of these common units after deducting underwriting discounts but before offering expenses. In conjunction with the partial exercise by the underwriters, ONEOK Partners GP contributed $0.2 million to ONEOK Partners in order to maintain its 2 percent general partner interest. Following these transactions, our interest in ONEOK Partners is 47.7 percent.
ONEOK Partners used a portion of the proceeds from the sale of common units and the general partner contributions to repay outstanding debtborrowings under theits $1.0 billion revolving credit agreement dated March 30, 2007, as amended July 31, 2007 (the ONEOK Partners Credit Agreement, which was incurred to fund ONEOK Partners’ internal growth capital projects. The assets acquired from Kinder Morgan and ONEOK Partners’ capital projects are discussed below inAgreement).
Dividends/Distributions - During 2008, we paid dividends totaling $1.56 per share, an increase of approximately 11 percent over the Significant Acquisitions and Divestitures and the Capital Projects sections, respectively.$1.40 per share paid during 2007. We declared a quarterly dividend of $0.38$0.40 per share ($1.521.60 per share on an annualized basis) in January 2008,2009, an increase of approximately 125 percent over the $0.34$0.38 declared in January 2008. During 2008, ONEOK Partners paid cash distributions totaling $4.205 per unit, an increase of approximately 6 percent over the $3.98 per unit paid during 2007. ONEOK Partners declared an increase in itsa cash distribution to $1.025of $1.08 per unit ($4.104.32 per unit on an annualized basis) in January 2008,2009, an increase of approximately 5 percent over the $0.98$1.025 declared in January 2008.
Capital Projects - ONEOK Partners placed the following projects in-service during 2008: | · | January - Midwestern Gas Transmission’s eastern extension pipeline; |
| · | July - final phase of Fort Union Gas Gathering expansion project; |
| · | September - Woodford Shale natural gas liquids pipeline extension; |
| · | October - Bushton Fractionation expansion; |
| · | November - Overland Pass Pipeline from Opal, Wyoming to Conway, Kansas; and |
| · | December - partial operations of the Guardian pipeline extension with interruptible service from Ixonia, Wisconsin, to Green Bay, Wisconsin. |
Key Performance Indicators - Key performance indicators reviewed by management include: | · | return on invested capital; and |
| · | shareholder appreciation. |
For 2008, our basic and diluted earnings per share from continuing operations were $2.99 and $2.95, respectively, representing a 5 percent increase in basic earnings per share and a 6 percent increase in diluted earnings per share from continuing operations compared with 2007. For 2007, our basic and diluted earnings per share from continuing operations were $2.84 and $2.79, respectively, representing a 4 percent increase in basic earnings per share and a 4 percent increase in diluted earnings per share from continuing operations compared with 2006. Return on invested capital was 13 percent in 2008 and 14 percent in 2007 and 2006, respectively.
To evaluate shareholder appreciation, we compare the total return over a three-year period of an investment in our stock with the total return of an investment in the stock of a group of peer companies. For the three-year period ended December 31, 2008, we ranked fifth in this shareholder appreciation calculation when compared with 18 of our peers.
Outlook for 2009 - We expect continued deteriorating economic conditions in 2009, with significant downward pressures, relative to 2008, on commodity prices for natural gas, NGLs and crude oil. We anticipate that lower commodity prices will result in reduced drilling activity, and economic conditions will reduce petrochemical demand. We also expect continued volatility and disruption in the financial markets which could result in an increased cost of capital. We expect depressed commodity prices and tighter capital markets to also result in the sale or consolidation of underperforming assets in the industry, which may present opportunities for us.
SIGNIFICANT ACQUISITIONS AND DIVESTITURES
Acquisition of NGL Pipeline - In October 2007, ONEOK Partners completed the acquisition of an interstate natural gas liquids and refined petroleum products pipeline system and related assets from a subsidiary of Kinder Morgan for approximately $300 million, before working capital adjustments. The system extends from Bushton and Conway, Kansas, to Chicago, Illinois, and transports, stores and delivers a full range of NGL products and refined petroleum products. The FERC-regulated system spans 1,6271,624 miles and has a capacity to transport up to 134 MBbl/d. The transaction includesalso included approximately 978 MBbl of owned storage capacity, eight NGL terminals and a 50 percent ownership of Heartland. ConocoPhillips owns the other 50 percent of Heartland and is the managing partner of the Heartland joint venture, which consists primarily of threea refined petroleum products terminals terminal and connecting pipelines.pipelines with access to two other refined petroleum products terminals. ONEOK Partners’ investment in Heartland is accounted for under the equity method of accounting. Financing for this transaction came from a portion of the proceeds of ONEOK Partners’ September 2007 issuance of $600 million 6.85 percent Senior Notes due 2037 (the 2037 Notes). See Note I of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for a discussion onof the 2037 Notes. The working capital settlement was finalized in April 2008, with no material adjustments.
Overland Pass Pipeline Company - - See “Capital Projects” for discussion of Overland Pass Pipeline Company.
ONEOK Partners - In April 2006, we sold certain assets comprising our former gathering and processing, natural gas liquids, and pipelines and storage segments to ONEOK Partners for approximately $3 billion, including $1.35 billion in cash, before adjustments, and approximately 36.5 million Class B limited partner units in ONEOK Partners. The Class B limited partner units and the related general partner interest contribution were valued at approximately $1.65 billion. We also purchased, through ONEOK Partners GP, from an affiliate of TransCanada, 17.5 percent of the general partner interest in ONEOK Partners for $40 million. This purchase resulted in our owningownership of the entire 2 percent general partner interest in ONEOK Partners. Following the completion of the transactions, we ownowned a total of approximately 37.0 million common and Class B limited partner units and the entire 2 percent general partner interest and control of the partnership. Our overall interest in ONEOK Partners, including the 2 percent general partner interest, iswas 45.7 percent.percent at the date of acquisition.
The sale of certain assets comprising our former gathering and processing, pipelines and storage, and natural gas liquids segments did not affect our consolidated operating income on our Consolidated Statements of Income or total assets on our Consolidated Balance Sheets, as we were already required under EITF 04-5 to consolidate our investment in ONEOK Partners effective January 1, 2006. However, minority interest expense and net income arewere affected. See Note A of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K beginning on page 6876 for additional discussion of EITF 04-5.our consolidation of ONEOK Partners.
Disposition of 20 percent interest in Northern Border Pipeline - In April 2006, in connection with the transactions described immediately above, our ONEOK Partners segment completed the sale of a 20 percent partnership interest in Northern Border Pipeline to TC PipeLines for approximately $297 million. Our ONEOK Partners segment recorded a gain on sale of approximately $113.9 million in the second quarter of 2006. ONEOK Partners and TC PipeLines each now own a 50 percent interest in Northern Border Pipeline, and an affiliate of TransCanada became operator of the pipeline in April 2007. As a result of this transaction, ONEOK Partners’ interest in Northern Border Pipeline is accounted for as an investment under the equity method applied on a retroactive basis to January 1, 2006.Also in
Acquisition of Guardian Pipeline Interests - In April 2006, our ONEOK Partners segment acquired the 66-2/3 percent interest in Guardian Pipeline not previously owned by ONEOK Partners for approximately $77 million, increasing its ownership interest to 100 percent. ONEOK Partners used borrowings from its credit facility to fund the acquisition of the additional interest in Guardian Pipeline. Following the completion of the transaction, we consolidated Guardian Pipeline in our consolidated financial statements. This change was accounted for on a retroactive basis to January 1, 2006.In December 2005, we sold our natural gas gathering and processing assets located in Texas to a subsidiary of Eagle Rock Energy, Inc. for approximately $527.2 million and recorded a pre-tax gain of $264.2 million, which is included in gain on sale of assets in our ONEOK Partners segment’s operating income. The gain reflects the cash received less adjustments, selling expenses and the net book value of the assets sold. We used the net cash proceeds from this sale to prepay our 7.75 percent $300 million long-term debt that was due in August 2006.
In October 2005, we entered into an agreement to sell our Spring Creek power plant, located in Oklahoma, to Westar for $53 million. The transaction received FERC approval and the sale was completed on October 31, 2006. The 300-megawatt gas-fired merchant power plant was built in 2001 to supply electrical power during peak periods using gas-powered turbine generators. The financial information related to the properties sold is reflected as a discontinued component in this Annual Report on Form 10-K. All periods presented have been restated to reflect the discontinued component. See “Discontinued Operations” on page 46 for additional information.
In September 2005, we completed the sale of our former production segment to TXOK Acquisition, Inc. for $645 million, before adjustments and recognized a pre-tax gain on the sale of approximately $240.3 million. The gain reflects the cash received less adjustments, selling expenses and the net book value of the assets sold. The proceeds from the sale were used to reduce debt. The financial information related to the properties sold is reflected as a discontinued component in this Annual Report on Form 10-K. All periods presented have been restated to reflect the discontinued component.
In July 2005, we completed the acquisition of the natural gas liquids businesses owned by Koch for approximately $1.33 billion, net of working capital and cash received. This transaction included Koch Hydrocarbon, LP’s entire Mid-Continent natural gas liquids fractionation business; Koch Pipeline Company, LP’s natural gas liquids pipeline distribution systems; Chisholm Pipeline Holdings, Inc., now Chisholm Pipeline Holdings, L.L.C., which has a 50 percent ownership interest in Chisholm Pipeline Company; MBFF, LP, now ONEOK MBI, L.P., which owns an 80 percent interest in a 160 MBbl/d fractionator at Mont Belvieu, Texas; and Koch Vesco Holdings, LLC, now ONEOK Vesco Holdings, L.L.C., an entity that
owns a 10.2 percent interest in Venice Energy Services Company, L.LC. These assets are included in our consolidated financial statements beginning on July 1, 2005, and were part of the assets ONEOK Partners acquired from us in April 2006.
All of the capital projects discussed below are in our ONEOK Partners segment.
Woodford Shale Natural Gas Liquids Pipeline Extension - In February 2008, ONEOK Partners announced plans to construct aThe 78-mile natural gas liquids gathering pipeline to connectconnecting two natural gas processing plants, operated by Devon Energy Corporation and Antero Resources Corporation, was placed into service in the Woodford Shale area in southeast Oklahoma at aSeptember 2008. The cost of the project was approximately $25$36 million, excluding AFUDC. The project is currently scheduled for completion in the second quarter of 2008. These two plants are expectedhave the capacity to produce approximately 25 MBbl/d of unfractionated NGLs. Until the Arbuckle Pipeline project is completed, theThe natural gas liquids production will be transportedis gathered by ONEOK Partners’ existing Mid-Continent natural gas liquids gathering pipelines. Upon completion of the Arbuckle Pipeline project, the Woodford Shale natural gas liquids production is expected to be transported through the Arbuckle Pipeline to ONEOK Partners’ Mont Belvieu, Texas, fractionation facility.
Overland Pass Pipeline Company - - In May 2006, a subsidiary of ONEOK Partners entered into an agreement with a subsidiary of The Williams Companies, Inc. (Williams) to form a joint venture called Overland Pass Pipeline Company. In November 2008, Overland Pass Pipeline Company is buildingcompleted construction of a 760-mile natural gas liquids pipeline from Opal, Wyoming, to the Mid-Continent natural gas liquids market center in Conway, Kansas. The pipelineOverland Pass Pipeline is designed to transport approximately 110 MBbl/d of unfractionated NGLs whichand can be increased to approximately 150255 MBbl/d with additional pump facilities. During 2006, ONEOK Partners paid $11.6 million to Williams for the acquisition of its interest in the joint venture and for reimbursement of initial capital expenditures. A subsidiary of ONEOK Partners owns 99 percent of the joint venture, and will managemanaged the construction project, advanceadvanced all costs associated with construction and operateis currently operating the pipeline. Within two years of the pipeline becoming operational,On or before November 17, 2010, Williams will have the option to increase its ownership up to 50 percent, by reimbursing ONEOK Partners for its proportionate share of all construction costs.with the purchase price determined in accordance with the joint venture’s operating agreement. If Williams exercises its option to increase its ownership to the full 50 percent, Williams would have the option to become operator. ThisThe pipeline project has received the required approvals of various state and federal regulatory authorities, and ONEOK Partners is constructing the pipeline with start-up currently scheduled for the second quarter of 2008.cost was approximately $575 million, excluding AFUDC.
As part of a long-term agreement, Williams dedicated its NGL production from two of its natural gas processing plants in Wyoming, estimated to be approximately 60 MBbl/d, to the joint-venture company.Overland Pass Pipeline. Subsidiaries of ONEOK Partners will
provide downstream fractionation, storage and transportation services to Williams. The pipeline project is currently estimated to cost approximately $535 million, excluding AFUDC. Since ONEOK Partners’ initial estimate in early 2006, there has been a significant increase in the demand for pipeline construction-related services, which has led to higher rates, particularly for construction labor and equipment. Additionally, due to the extended permitting process, ONEOK Partners has also reached agreements with certain producers for supply commitments of up to an additional 80 MBbl/d and is constructingnegotiating agreements with other producers for supply commitments that could add an additional 60 MBbl/d of supply to this pipeline within the pipeline during the winter months, which could contributenext three to added construction costs and could cause further delays. The severity of the winter conditions could further impact ONEOK Partners’ cost and schedule estimates. In addition, five years.
ONEOK Partners is investingalso invested approximately $216$239 million, excluding AFUDC, to expand its existing fractionation and storage capabilities and to increase the capacity of its natural gas liquids distribution pipelines. Part of this expansion included adding new fractionation facilities at ONEOK Partners’ financing forBushton location, increasing total fractionation capacity at Bushton to 150 MBbl/d. The addition of the projects may include a combinationnew facilities and the upgrade to the existing fractionator was completed in October 2008. Additionally, portions of short- or long-term debt or equity.the natural gas liquids distribution pipeline upgrades were completed in the second and third quarters of 2008.
Piceance Lateral Pipeline - In March 2007, ONEOK Partners announced that Overland Pass Pipeline Company also plans to construct a 150-mile lateral pipeline with capacity to transport as much as 100 MBbl/d of unfractionated NGLs from the Piceance Basin in Colorado to the Overland Pass Pipeline. Williams announced that it intends to construct a new natural gas processing plant in the Piceance Basin and will dedicate its NGL production from that plant and an existing plant, with estimated volumes totaling approximately 30 MBbl/d, to be transported by the lateral pipeline. ThisONEOK Partners continues to negotiate with other producers for supply commitments. In October 2008, this project requires thereceived approval of various state and federal regulatory authorities. Assuming Overland Pass Pipeline Company obtainsauthorities allowing construction to commence. Construction began during the required statefourth quarter of 2008 and federal regulatory approvals, construction of this lateral pipeline is currently expected to begin in late 2008 and be completed during the secondthird quarter of 2009, at a current2009. The project is currently estimated to cost estimatein the range of approximately $120$110 million to $140 million, excluding AFUDC.
D-J Basin Lateral Pipeline - In September 2008, ONEOK Partners announced plans to construct a 125-mile natural gas liquids lateral pipeline from the Denver-Julesburg Basin in northeastern Colorado to the Overland Pass Pipeline, with capacity to transport as much as 55 MBbl/d of unfractionated NGLs. The project is currently estimated to cost in the range of $70 million to $80 million, excluding AFUDC. ONEOK Partners has supply commitments for up to 33 MBbl/d of unfractionated NGLs with potential for an additional 10 MBbl/d of supply from new drilling and plant upgrades in the next two years. The pipeline is currently under construction and is expected to be fully completed during the first quarter of 2009.
Arbuckle Pipeline Natural Gas Liquids Pipeline - In March 2007, ONEOK Partners announced plans to build the 440-mile Arbuckle Pipeline, a natural gas liquids pipeline from southern Oklahoma through northern Texas and continuing on to the Texas Gulf Coast, at a current estimated cost of approximately $260 million, excluding AFUDC.Coast. The Arbuckle Pipeline will have the capacity to transport 160 MBbl/d of unfractionated natural gas liquidsNGLs, expandable to 210 MBbl/d with additional pump facilities, and will connect with ONEOK Partners’ existing Mid-Continent infrastructure andwith its fractionation facility in Mont Belvieu, Texas, and other Gulf Coast region fractionators. ONEOK Partners has supply commitments from producers that it expects will be sufficient to fill the 210 MBbl/d capacity level over the next three to five years. Construction on the pipeline has been underway since the third quarter of 2008. Much of the Oklahoma and north Texas portions are either complete or nearing completion. However, right-of-way acquisition has been challenging, time consuming and expensive, which could affect the completion schedule and final cost of the project. Many of Arbuckle Pipeline’s remaining right-of-way tracts are being acquired through a condemnation process, which adds to the cost and time to construct the pipeline. The demand for surface easements has increased dramatically in Texas and Oklahoma in the last 12 to 18 months because of increased oil and natural gas exploration and production activities, as well as pipeline construction. Because of the delays associated with right-of-way acquisition, we anticipate construction on the south end of the project will require permits from various federal, statebe more difficult and local regulatory bodies. Construction is currently expectedexpensive due to beginwet low-lying areas and potential for spring rains. Accordingly, we expect the project to be operational in mid-2008the second quarter of 2009. Based on the increased costs and be completed by early 2009.delays associated with right-of-way acquisition and potential weather impacts, our project costs could increase 10 percent to 15 percent above the range of $340 million to $360 million, excluding AFUDC, as previously reported.
Williston Basin Gas Processing Plant Expansion - In March 2007, ONEOK Partners announced the expansion of its Grasslands natural gas processing facility in North Dakota, at acurrently estimated to cost in the range of approximately$40 million to $45 million, excluding AFUDC. ONEOK Partners’ estimated project costs increased from $30 million excluding AFUDC.primarily as a result of higher contract labor and equipment costs. The Grasslands facility is ONEOK Partners’ largest natural gas processing plant in the Williston Basin. The expansion increases processing capacity to approximately 100 MMcf/d from its current capacity of 63 MMcf/d and increases fractionation capacity to approximately 12 MBbl/d from 8 MBbl/d. The construction of the expansion project is expected to come on-line in phases, with the final phase currently expected to be on-linecomplete in the thirdfirst quarter of 2008.2009.
Fort Union Gas Gathering Expansion - In January 2007, Fort Union Gas Gathering announced that it willplans to double its existing gathering pipeline capacity by adding 148 miles of new gathering lines, resulting in approximately 649 MMcf/d of additional capacity in the Powder River basin of Wyoming. The expansion is expected tooccurred in two phases and cost approximately $110$121 million, excluding AFUDC, which will bewas financed within the Fort Union Gas Gathering partnership and will occur in two phases.partnership. Any cost overruns are covered through escalation clauses to preserve the original economics of the project. Phase 1,I, with more than 200 MMcf/d
capacity, was placed in service during the fourth quarter of 2007. Phase 2,II, with approximately 450 MMcf/d capacity, is currently expected to bewas completed in service during the second quarter ofJuly 2008. The additional capacity has been fully subscribed for 10 years beginning with the in-service date of the expansion.years. ONEOK Partners owns approximately 37 percent of Fort Union Gas Gathering, and accounts for its ownership under the equity method of accounting.
Guardian Pipeline Expansion and Extension - In December 2007, Guardian Pipeline received and accepted the certificate of public convenience and necessity issued by the FERC for its expansion and extension project. The certificate authorizes ONEOK Partners to construct, install and operate approximately 119 miles of a 20-inch and 30-inch natural gas transportation pipeline with a capacity to transport 537 MMcf/d of natural gas north from Ixonia, Wisconsin to the Green Bay, Wisconsin, area. The project is supported by long-term15-year shipper commitments.commitments with We Energies and Wisconsin Public Service Corporation and the capacity has been fully subscribed. The cost of the project is currently estimated to be $260cost in the range of $277 million and $305 million, excluding AFUDC. ONEOK Partners’ estimated project costs increased from the initial estimate of $241 million in 2006, which excluded AFUDC, primarily due to weather delays, equipment delivery delays, construction in environmentally sensitive areas, rocky terrain, and escalating costs associated with crop damage and condemnation costs. ONEOK Partners received the notice to proceed from the FERC in May 2008. On December 22, 2008, the FERC issued a letter order granting Guardian Pipeline’s request for an extension of time for a phased in-service. On December 29, 2008, the FERC issued a letter order granting Guardian Pipeline’s request to commence service. On December 31, 2008, the pipeline and seven meter stations were placed into service with the ability to transport natural gas on a limited basis. Construction on one compressor station is complete, and construction on a second compressor station is near completion. The pipelineproject is currently expected to be fully in service in the fourthfirst quarter of 2008.2009.Midwestern Gas Transmission Eastern Extension - Midwestern Gas Transmission’s eastern extension pipeline was placed into service in January 2008. The extension added approximately 31 miles of natural gas transportation pipeline, with a capacity to transport 120 MMcf/d of natural gas from Midwestern’s previous terminus at Portland, Tennessee, to interconnects with Columbia Gulf Transmission Company and East Tennessee Natural Gas, LLC, near Hartsville, Tennessee. The project is supported by a long-term shipper commitment. Total capital expenditures are expected to be $62 million, excluding AFUDC.
Several regulatory initiatives positively impacted the earnings and future earnings potential for our Distribution segment and our ONEOK Partners segment. See discussion of our Distribution segment’s regulatory initiative beginning on page 43.49.
IMPACT OF NEW ACCOUNTING STANDARDS
Information about the impact of Statement 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” Statement 157, “Fair Value Measurements,” Statement 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” FIN 48, “Accounting for Uncertainty in Income Taxes - An Interpretation of FASB Statement No. 109,” FASB Staff Position No. FIN 39-1, “Amendment of FASB Interpretation No. 39,” EITF Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights,” Statement 123R, “Share-Based Payment,” Statement 141R, “Business Combinations” and Statement 160, “Noncontrolling Interest in Consolidated Financial Statements - an amendment to ARB No. 51,” arefollowing new accounting standards is included in Note A of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.10-K: | · | Statement 123R, “Share-Based Payment;” |
| · | Statement 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans;” |
| · | FIN 48, “Accounting for Uncertainty in Income Taxes - An Interpretation of FASB Statement No. 109;” |
| · | Statement 157, “Fair Value Measurements,” and related FASB Staff Position (FSP) 157-2, “Effective Date of FASB Statement no. 157,” and FSP 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active;” |
| · | Statement 159, “The Fair Value Option for Financial Assets and Financial Liabilities;” |
| · | FSP FIN 39-1, “Amendment of FASB Interpretation No. 39;” |
| · | Statement 141R, “Business Combinations;” |
| · | Statement 160, “Noncontrolling Interest in Consolidated Financial Statements - an amendment to ARB No. 51;” |
| · | Statement 161, “Disclosures about Derivative Instruments and Hedging Activities - an amendment to FASB Statement No. 133;” |
| · | EITF 08-6, “Equity Method Investment Accounting Considerations;” and |
| · | Statement 132R-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets.” |
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of our consolidated financial statements and related disclosures in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions that cannot be known with certainty that affect the reported amount of assets and liabilities, and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements. These estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Although we believe these estimates and assumptions are reasonable, actual results could differ from our estimates.
The following is a summary of our most critical accounting policies,estimates, which are defined as those policiesestimates most important to the portrayal of our financial condition and results of operations and requiring management’s most difficult, subjective or complex judgment, particularly because of the need to make estimates concerning the impact of inherently uncertain matters. We have discussed the development and selection of our critical accounting policies and estimates with the Audit Committee of our Board of Directors.
Fair Value Measurements - General - In September 2006, the FASB issued Statement 157 that establishes a framework for measuring fair value and requires additional disclosures about fair value measurements. Beginning January 1, 2008, we partially applied Statement 157 as allowed by FSP 157-2 that delayed the effective date of Statement 157 for nonrecurring fair value measurements associated with our nonfinancial assets and liabilities. As of January 1, 2008, we applied the provisions of Statement 157 to our recurring fair value measurements, and the impact was not material upon adoption. As of January 1, 2009, we have applied the provisions of Statement 157 to our nonrecurring fair value measurements associated with our nonfinancial assets and liabilities, and the impact was not material. FSP 157-3, which clarified the application of Statement 157 in inactive markets, was issued in October 2008 and was effective for our September 30, 2008, consolidated financial statements. FSP 157-3 did not have a material impact on our consolidated financial statements.
In February 2007, the FASB issued Statement 159 that allows companies to elect to measure specified financial assets and liabilities, firm commitments, and nonfinancial warranty and insurance contracts at fair value on a contract-by-contract basis, with changes in fair value recognized in earnings each reporting period. At January 1, 2008, we did not elect the fair value option under Statement 159, and therefore there was no impact on our consolidated financial statements.
Determining Fair Value - Statement 157 defines fair value as the price that would be received to sell an asset or transfer a liability in an orderly transaction between market participants at the measurement date. We use the market and income approaches to determine the fair value of our assets and liabilities and consider the markets in which the transactions are executed. While many of the contracts in our portfolio are executed in liquid markets where price transparency exists, some contracts are executed in markets for which market prices may exist but the market may be relatively inactive. This results in limited price transparency that requires management’s judgment and assumptions to estimate fair values. Inputs into our fair value estimates include commodity exchange prices, over-the-counter quotes, volatility, historical correlations of pricing data and LIBOR and other liquid money market instrument rates. We also utilize internally developed basis curves that incorporate observable and unobservable market data. We validate our valuation inputs with third-party information and settlement prices from other sources, where available. In addition, as prescribed by the income approach, we compute the fair value of our derivative portfolio by discounting the projected future cash flows from our derivative assets and liabilities to present value. The interest rate yields used to calculate the present value discount factors are derived from LIBOR, Eurodollar futures and Treasury swaps. The projected cash flows are then multiplied by the appropriate discount factors to determine the present value or fair value of our derivative instruments. We also take into consideration the potential impact on market prices of liquidating positions in an orderly manner over a reasonable period of time under current market conditions. Finally, we consider credit risk of our counterparties on the fair value of our derivative assets, as well as our own credit risk for derivative liabilities, using default probabilities and recovery rates, net of collateral. We also take into consideration current market data in our evaluation when available, such as bond prices and yields and credit default swaps. Although we use our best estimates to determine the fair value of the derivative contracts we have executed, the ultimate market prices realized could differ from our estimates, and the differences could be material.
Fair Value Hierarchy - - Statement 157 establishes the fair value hierarchy that prioritizes inputs to valuation techniques based on observable and unobservable data and categorizes the inputs into three levels, with the highest priority given to Level 1 and the lowest priority given to Level 3. The levels are described below. | · | Level 1 - Unadjusted quoted prices in active markets for identical assets or liabilities; |
| · | Level 2 - Significant observable pricing inputs other than quoted prices included within Level 1 that are either directly or indirectly observable as of the reporting date. Essentially, this represents inputs that are derived principally from or corroborated by observable market data; and |
| · | Level 3 - Generally unobservable inputs, which are developed based on the best information available and may include our own internal data. |
Determining the appropriate classification of our fair value measurements within the fair value hierarchy requires management’s judgment regarding the degree to which market data is observable or corroborated by observable market data. Transfers in and out of Level 3 typically result from derivatives for which fair value is determined based on multiple inputs. If prices change for a particular input from the previous measurement date to the current measurement date, the impact could result in the derivative being moved between Level 2 and Level 3, depending upon management judgment of the significance of the price change of that particular input to the total fair value of the derivative.
See Note C of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for more discussion of fair value measurements.
Derivatives, Accounting for Financially Settled Transactions and Risk Management Activities- We engage in wholesale energy marketing, retail marketing, trading and risk management activities. We account for derivative instruments utilized in connection with these activities and services under the fair value basis of accounting in accordance with Statement 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended.
Under Statement 133, entities are required to record derivative instruments at fair value. The fair value, with the exception of a derivative instrument is determined by commodity exchange prices, over-the-counter quotes, volatility, time value, counterparty creditnormal purchases and the potential impact on market prices of liquidating positionsnormal sales that are expected to result in an orderly manner over a reasonable period of time under current market conditions. Refer to the table on page 57physical delivery. See previous discussion in “Fair Value Measurements” for amounts in our portfolio at December 31, 2007, that were determined by prices actively quoted, prices provided by other external sources and prices derived from other sources. The majority of our portfolio’s fair values are based on actual market prices. 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.additional information. Market value changes result in a change in the fair value of our derivative instruments. 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 nature of the risk being hedged and how we will determine if the hedging instrument is effective. If the derivative instrument does not qualify or is not designated as part of a hedging relationship, then we account for changes in fair value of the derivative in earnings as they occur. Commodity price volatility 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 7A, Quantitative and Qualitative Disclosures about Market Risk.
To minimize the risk ofreduce our exposure to fluctuations in natural gas, NGLs and condensate prices, we periodically enter into futures, collarsforwards, options or swap transactions in order to hedge anticipated purchases and sales of natural gas, NGLs and condensate and fuel requirements. Interest-rate swaps are also used to manage interest-rate risk. Under certain conditions, we designate these derivative instruments as a hedge of exposure to changes in fair values or cash flow. 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 accumulated other comprehensive income (loss) and is subsequently recorded to earnings when the forecasted transaction affects earnings. Any ineffectiveness of designated hedges is reported in earnings during the period the ineffectiveness occurs. For hedges of exposure to changes in fair value, the gain or loss on the derivative instrument is recognized in earnings during the period of change together with the offsetting gain or loss on the hedged item attributable to the risk being hedged.
Upon election, many of our purchase and sale agreements that otherwise would be required to follow derivative accounting qualify as normal purchases and normal sales under Statement 133 and are therefore exempt from fair value accounting treatment.
The presentation of settled derivative instruments on either a gross or net basis in our Consolidated Statements of Income is dependent on a number of factors, including whether the derivative instrument (i) is (i) held for trading purposes,purposes; (ii) is financially settled,settled; (iii) results in physical delivery or services rendered,rendered; and (iv) qualifies for the normal purchase or sale exception as defined in Statement 133. In accordance with EITF 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and not ‘Held for Trading’ as Defined in EITF Issue No. 02-3,” EITF 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent,” and Statement 133, we report settled derivative instruments as follows: all financially settled derivative contracts are reported on a net basis,
derivative instruments considered held for trading purposes that result in physical delivery are reported on a net basis,
| · | all financially settled derivative contracts are reported on a net basis; |
derivative instruments not considered held for trading purposes that result in physical delivery or services rendered are reported on a gross basis, and
| · | derivative instruments considered held for trading purposes that result in physical delivery are reported on a net basis; |
derivatives that qualify for the normal purchase or sale exception as defined in Statement 133 are reported on a gross basis.
| · | derivative instruments not considered held for trading purposes that result in physical delivery or services rendered are reported on a gross basis; and |
| · | derivatives that qualify for the normal purchase or sale exception as defined in Statement 133 are reported on a gross basis. |
We apply the indicators in EITF 99-19 to determine the appropriate accounting treatment for non-derivative contracts that result in physical delivery.
See Note D of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for moreadditional discussion of derivatives and risk management activities.
Impairment of Long-Lived Assets, Goodwill and Intangible Assets - We assess our long-lived assets for impairment based on Statement 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.
We assess our goodwill and indefinite-lived intangible assets for impairment at least annually based on Statement 142, “Goodwill and Other Intangible Assets.” There were no impairment charges resulting from theour July 1, 2007,2008, impairment teststest. As a result of recent events in the financial markets and no events indicatingcurrent economic conditions, we performed a review and determined that interim testing of goodwill as of December 31, 2008, was not necessary. As a part of our impairment test, an impairment have occurred subsequent to that date. An initial assessment is made by comparing the fair value of the operationsa reporting unit with goodwill, as determined in accordance with Statement 142, to theits book value, of each reporting unit.including goodwill. 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 with goodwillreporting unit from the fair value determined in step one of the assessment. If the carrying value of the goodwill exceeds this calculatedthe implied fair value of the goodwill, we will record an impairment charge.
We use two generally accepted valuation approaches, an income approach and a market approach, to estimate the fair value of a reporting unit. Under the income approach, we use anticipated cash flows over a three-year period plus a terminal value and discount these amounts to their present value using appropriate rates of return. Under the market approach, we apply multiples to forecasted EBITDA amounts. The multiples used are consistent with historical asset transactions, and the EBITDA amounts are based on average EBITDA for a reporting unit over a three-year forecasted period. At December 31, 2007,2008 we had $600.7$602.8 million of goodwill recorded on our Consolidated Balance Sheet as shown below. | | | | | | | | | (Thousands of dollars) | | | ONEOK Partners | | $ | 431,418 | | | Distribution | | | 157,953 | | | Energy Services | | | 10,255 | | | Other | | | 1,099 | | | Total goodwill | | $ | 600,725 | | | | |
| | | | | | | | | | | | (Thousands of dollars) | | ONEOK Partners | | | | $ | 433,537 | | | | | | Distribution | | | | | 157,953 | | | | | | Energy Services | | | | | 10,255 | | | | | | Other | | | | | 1,099 | | | | | | Total goodwill | | | | $ | 602,844 | | | | |
Intangible assets with a finite useful life are amortized over their estimated useful life, while intangible assets with an indefinite useful life are not amortized. All intangible assets are subject to impairment testing. Our ONEOK Partners segmentWe had $443.0$435.4 million of intangible assets recorded on our Consolidated Balance Sheet as of December 31, 2007,2008, of which $287.5$279.8 million in our ONEOK Partners segment is being amortized over an aggregate weighted-average period of 40 years, while the remaining balance has an indefinite life.
Our impairment tests require the use of assumptions and estimates. If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may be exposed to an impairment charge.
During 2006, we recorded a goodwill and asset impairment related to ONEOK Partners’ Black Mesa Pipeline of $8.4 million and $3.6 million, respectively, which werewas recorded as depreciation and amortization. The reduction to our net income, net of minority interests and income taxes, was $3.0 million. In
For the third quarter of 2005,investments we madeaccount for under the decision to sell our Spring Creek power plant, located in Oklahoma, and exitequity method, the power generation business. In October 2005, we concluded that our Spring Creek power plant had been impaired and recorded an impairment expense of $52.2 million. This conclusion was based on our Statement 144 impairment analysis of the results of operations for this plant through September 30, 2005, and also the net sales proceeds from the anticipated sale of the plant. The sale was completed on October 31, 2006. This component of our business is accounted for as discontinued operations in accordance with Statement 144. See “Discontinued Operations” on page 46 for additional information.Our total unamortizedpremium or excess cost over underlying fair value of net assets accounted for under the equity method was $185.6 million as of December 31, 2007 and 2006. Based on Statement 142, this amount,is referred to as equity method goodwill should continueand under Statement 142, is not subject to be recognized in accordance withamortization but rather to impairment testing pursuant to APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.” Accordingly,The impairment test under APB Opinion No. 18 considers whether the fair value of the equity investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. Therefore, we included thisperiodically reevaluate the amount at which we carry the excess of cost over fair value of net assets accounted for under the equity method to determine whether current events or circumstances warrant adjustments to our carrying value in investment in unconsolidated affiliates on our accompanying Consolidated Balance Sheets.
accordance with APB Opinion No. 18.
Pension and Postretirement Employee Benefits - We have defined benefit retirement plans covering certain full-time employees. We sponsor welfare plans that provide postretirement medical and life insurance benefits to certain employees who retire with at least five years of service. Our actuarial consultant calculates the expense and liability related to these plans and 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. In determining the projected benefit obligations and costs, assumptions can change from period to period and result in material changes in the costs and liabilities we recognize. See Note J of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.
Assumed health care cost trend rates have a significant effect on the amounts reported for our health care plans. A one-percentage point change in assumed health care cost trend rates would have the following effects. | | | | | | | | | | | | | One-Percentage
Point Increase | | One-Percentage
Point Decrease | | | | | | | (Thousands of dollars) | | | | Effect on total of service and interest cost | | $ | 1,969 | | $ | (1,665 | ) | | | Effect on postretirement benefit obligation | | $ | 20,685 | | $ | (18,014 | ) | | |
| | | One-Percentage | | | One-Percentage | | | | | Point Increase | | | Point Decrease | | | | | (Thousands of dollars) | | Effect on total of service and interest cost | | $ | 1,989 | | | | $ | (1,706 | ) | | | Effect on postretirement benefit obligation | | $ | 19,585 | | | | $ | (17,171 | ) | |
During 2007,2008, we recorded net periodic benefit costs of $29.1 million related to our defined benefit pension plans and $26.7 million related to postretirement benefits. We estimate that in 2008, we will record net periodic benefit costs of $19.8 million related to our defined benefit pension planplans and $28.3 million related to postretirement benefits. We estimate that in 2009, we will record net periodic benefit costs of $26.6 million related to our defined benefit pension plans and $26.1 million related to postretirement benefits. In determining our estimated expenses for 2008,2009, our actuarial consultant assumed an 8.758.50 percent expected return on plan assets and a discount rate of 6.25 percent. A decrease in our expected return on plan assets to 8.508.25 percent would increase our 20082009 estimated net periodic benefit costs by approximately $1.8$1.9 million for our defined benefit pension planplans and would not have a significant impact on our postretirement benefit plan. A decrease in our assumed discount rate to 6.00 percent would increase our 20082009 estimated net periodic benefit costs by approximately $2.5$2.4 million for our defined benefit pension planplans and $0.7$0.6 million for our postretirement benefit plan. For 2008,2009, we anticipate our total contributions to our defined benefit pension planplans and postretirement benefit plan to be $3.1$31.2 million and $11.0$11.4 million, respectively, and the expected benefit payments for our postretirement benefit plan are estimated to be $16.7$16.2 million.
Contingencies - Our accounting for contingencies covers a variety of business activities, including contingencies for 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 5, “Accounting for Contingencies.” We base our estimates on currently available facts and our estimates of the ultimate outcome or resolution. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than completion of the remediation feasibility study. Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable. Actual results may differ from our estimates resulting in an impact, positive or negative, on earnings. See Note K of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional discussion of contingencies.
FINANCIAL RESULTS AND OPERATING RESULTSINFORMATION
Selected Financial InformationResults - The following table sets forth certain selected financial informationresults for the periods indicated. | | | | | | | | | | | | | | | | Years Ended December 31, | | | | Financial Results | | 2007 | | | 2006 | | 2005 | | | | | | (Thousands of dollars) | | | Operating revenues, excluding energy trading revenues | | $ | 13,488,027 | | | $ | 11,913,529 | | $ | 12,663,550 | | | Energy trading revenues, net | | | (10,613 | ) | | | 6,797 | | | 12,680 | | | Cost of sales and fuel | | | 11,667,306 | | | | 10,198,342 | | | 11,338,076 | | | Net margin | | | 1,810,108 | | | | 1,721,984 | | | 1,338,154 | | | Operating costs | | | 761,510 | | | | 740,767 | | | 619,995 | | | Depreciation and amortization | | | 227,964 | | | | 235,543 | | | 183,394 | | | Gain (loss) on sale of assets | | | 1,909 | | | | 116,528 | | | 269,040 | | | Operating income | | $ | 822,543 | | | $ | 862,202 | | $ | 803,805 | | | | | Equity earnings from investments | | $ | 89,908 | | | $ | 95,883 | | $ | 8,621 | | | Allowance for equity funds used during construction | | $ | 12,538 | | | $ | 2,205 | | $ | - | | | Interest Expense | | $ | 256,325 | | | $ | 239,725 | | $ | 147,608 | | | Minority interests in income of consolidated subsidiaries | | $ | 193,199 | | | $ | 222,000 | | $ | - | | |
| | | | | | | | | Variances | | | Variances | | | | | Years Ended December 31, | | 2008 vs. 2007 | | | 2007 vs. 2006 | | | Financial Results | | 2008 | | 2007 | | 2006 | | Increase (Decrease) | | | Increase (Decrease) | | | | | (Millions of dollars) | | | Revenues | | $ | 16,157.4 | | $ | 13,477.4 | | $ | 11,920.3 | | $ | 2,680.0 | | 20 | % | | $ | 1,557.1 | | 13 | % | | Cost of sales and fuel | | | 14,221.9 | | | 11,667.3 | | | 10,198.3 | | | 2,554.6 | | 22 | % | | | 1,469.0 | | 14 | % | | Net margin | | | 1,935.5 | | | 1,810.1 | | | 1,722.0 | | | 125.4 | | 7 | % | | | 88.1 | | 5 | % | | Operating costs | | | 776.9 | | | 761.5 | | | 740.8 | | | 15.4 | | 2 | % | | | 20.7 | | 3 | % | | Depreciation and amortization | | | 243.9 | | | 228.0 | | | 235.5 | | | 15.9 | | 7 | % | | | (7.5 | ) | (3 | %) | | Gain (loss) on sale of assets | | | 2.3 | | | 1.9 | | | 116.5 | | | 0.4 | | 21 | % | | | (114.6 | ) | (98 | %) | | Operating income | | $ | 917.0 | | $ | 822.5 | | $ | 862.2 | | $ | 94.5 | | 11 | % | | $ | (39.7 | ) | (5 | %) | | Equity earnings from investments | | $ | 101.4 | | $ | 89.9 | | $ | 95.9 | | $ | 11.5 | | 13 | % | | $ | (6.0 | ) | (6 | %) | Allowance for equity funds used during construction | | $ | 50.9 | | $ | 12.5 | | $ | 2.2 | | $ | 38.4 | | * | | | $ | 10.3 | | * | | | Other income (expense) | | $ | (10.6 | ) | $ | 14.1 | | $ | 1.9 | | $ | (24.7 | ) | * | | | $ | 12.2 | | * | | | Interest expense | | $ | (264.2 | ) | $ | (256.3 | ) | $ | (239.7 | ) | $ | 7.9 | | 3 | % | | $ | 16.6 | | 7 | % | Minority interests in income of consolidated subsidiaries | | $ | (288.6 | ) | $ | (193.2 | ) | $ | (222.0 | ) | $ | 95.4 | | 49 | % | | $ | (28.8 | ) | (13 | %) | | Capital expenditures | | $ | 1,473.1 | | $ | 883.7 | | $ | 376.3 | | $ | 589.4 | | 67 | % | | $ | 507.4 | | * | | | | | | | | | | | | | | | | | | | | | | | | | | * Percentage change is greater than 100 percent. | | | | | | | | | | |
Operating Results2008 vs. 2007 - Net margin increased primarily due to wider NGL product price differentials, higher realized commodity prices, incremental net margin associated with the assets acquired from Kinder Morgan, and increased NGL gathering and fractionation volumes, all in our ONEOK Partners segment. Additionally, net margin increased due to implementation of new rate mechanisms in our Distribution segment. These increases were partially offset by decreases in storage and marketing margins and transportation margins, net of hedging activities, in our Energy Services segment.
Operating costs increased primarily due to incremental operating expenses associated with the assets acquired from Kinder Morgan, outside services primarily associated with scheduled maintenance expenses at ONEOK Partners’ Medford and Mont Belvieu fractionators, and chemical costs. Operating costs also increased due to costs associated with the startup of the newly expanded Bushton fractionator and Overland Pass Pipeline, both in our ONEOK Partners segment.
Depreciation and amortization increased primarily due to the assets acquired from Kinder Morgan and depreciation expense associated with ONEOK Partners’ completed capital projects. Additionally, our Distribution segment had an increase in depreciation and amortization, primarily due to additional investment in property, plant and equipment.
Equity earnings from investments increased primarily due to ONEOK Partners’ share of the gain on the sale of Bison Pipeline LLC by Northern Border Pipeline and ONEOK Partners’ earnings related to higher gathering revenues in its natural gas gathering and processing business’ various investments, partially offset by reduced throughput on Northern Border Pipeline. ONEOK Partners owns a 50 percent equity interest in Northern Border Pipeline.
Allowance for equity funds used during construction and capital expenditures increased due to ONEOK Partners’ capital projects.
Other income (expense) fluctuated primarily due to investment gains (losses) and fluctuations in interest income. In addition, other income (expense) was impacted by realized and unrealized gains on available-for-sale securities sold and transferred to trading. Our available-for-sale securities were reclassified to trading securities due to a reconsideration event in August 2008 when our NYMEX Holding, Inc. Class A shares held were converted to CME Group, Inc. (CME) Class A shares, due to the NYMEX Holding, Inc. and CME merger. A modification was made to the number of shares required to be maintained by NYMEX Holding, Inc. Class A Members, which resulted in our sale of certain shares and the reclassification of the remaining shares to trading.
Interest expense increased primarily due to increased borrowings to fund ONEOK Partners’ capital projects.
Minority interest in income of consolidated subsidiaries for 2008 and 2007 compared withreflects the remaining 52.3 percent and 54.3 percent, respectively, of ONEOK Partners that we did not own. The increase in minority interest is due to the increase in income for our ONEOK Partners segment, partially offset by our increased equity ownership interest in ONEOK Partners.
2007 vs. 2006 - Net margin increased primarily due to the implementation of new rate schedules in Kansas and Texas in our Distribution segment. Net margin was also positively impacted during 2007 by our ONEOK Partners segment due to its natural gas liquids businesses, which benefited primarily from new supply connections that increased volumes gathered, transported, fractionated and sold. Net margin also increased due to ONEOK Partners’natural gas liquids gathering and fractionation business benefiting from higher product price spreadsdifferentials and higher isomerization price spreadsdifferentials, as well as the incremental net margin related to the assets acquired from Kinder Morgan in October 2007. These increases were offset by decreased transportation margins in our Energy Services segment and decreased net margin in ONEOK Partners’ natural gas gathering and processing business, primarily due to lower natural gas volumes processed as a result of contract terminations in late 2006. For an explanation of energy trading revenues, net, see the discussion of our Energy Services segment beginning on page 43.
Consolidated operating costs increased for 2007, compared with 2006, primarily due to higher employee-related costs and the incremental operating expenses associated with ONEOK Partners’ acquisition of assets from Kinder Morgan in October 2007, coupled with increased bad debt expense and higher property taxes in our Distribution segment. These increases were partially offset by lower litigation costs in our ONEOK Partners segment and lower employee-related costs in our Distribution segment.
Depreciation and amortization decreased for 2007, compared with 2006, primarily due to a goodwill and asset impairment charge of $12.0 million recorded in the second quarter of 2006 related to Black Mesa Pipeline, which is included in our ONEOK Partners segment.
Gain (loss) on sale of assets decreased for 2007, compared with 2006, primarily due to the $113.9 million gain on sale of a 20 percent partnership interest in Northern Border Pipeline recorded in the second quarter of 2006 in our ONEOK Partners segment.
Equity earnings from investments decreased for 2007, compared with 2006, primarily due to the decrease in ONEOK Partners’ share of Northern Border Pipeline’s earnings from 70 percent in the first quarter of 2006 to 50 percent beginning in the second quarter of 2006.
Allowance for equity funds used during construction and capital expenditures increased for 2007, compared with 2006, due to ONEOK Partners’ capital projects, which are discussed beginning on page 31.projects.
Other income (expense) fluctuated primarily due to increased civic donations and expenses incurred by ONEOK Partners in 2006 related to costs associated with transitioning operations from Omaha, Nebraska.
Interest expense increased for 2007, primarily due to the additional borrowings by ONEOK Partners to complete the April 2006 transactions with us. The additional borrowings resulted in $21.3 million in higher interest expense in the first quarter of 2007 compared with the same period in 2006.2007. Increased interest expense was partially offset by lower interest expense on ONEOK’s short-term debt of $11.8 million during 2007, compared with the same period in 2006, as a result of the proceeds from the sale of assets to ONEOK Partners, which reduced ONEOK’s short-term debt.
Minority interest in income of consolidated subsidiaries for 2007 and 2006 reflects the remaining 54.3 percent of ONEOK Partners that we dodid not own. For 2007, minority interest was lower due to the $113.9 million gain on sale of a 20 percent partnership interest in Northern Border Pipeline recorded in the second quarter of 2006 in our ONEOK Partners segment. Additionally, minority interest in net income of consolidated subsidiaries for our ONEOK Partners’ segment for 2006 included the 66-2/3 percent interest in Guardian Pipeline that ONEOK Partners did not own until April 2006. ONEOK Partners owned 100 percent of Guardian Pipeline beginning in April 2006, resulting in no minority interest in income of consolidated subsidiaries related to Guardian Pipeline after March 31, 2006. Net margin increased for 2006, compared with 2005, primarily due to:
the consolidation of our investment in ONEOK Partners as required by EITF 04-5,
the effect of the natural gas liquids assets acquired from Koch in our ONEOK Partners segment,
strong commodity prices, higher gross processing spreads and increased natural gas transportation revenue in our ONEOK Partners segment, and
improved natural gas basis differentials on transportation contracts, net of hedging activities, in our Energy Services segment.
Consolidated operating costs for 2006 increased, compared with 2005, primarily because of consolidation of the legacy ONEOK Partners operations and the natural gas liquids assets acquired in 2005, offset by the sale of the Texas natural gas gathering and processing assets in December 2005.
Depreciation and amortization increased for 2006, compared with 2005, primarily due to the consolidation of the legacy ONEOK Partners operations, the Black Mesa Pipeline impairment, and the costs associated with the natural gas liquids assets acquired from Koch.
Operating income for 2006 includes the gain on sale of assets of $113.9 million related to ONEOK Partners’ sale of a 20 percent partnership interest in Northern Border Pipeline to TC PipeLines in April 2006. Operating income for 2005 includes the gain on sale of assets in our ONEOK Partners segment of $264.2 million. This gain was the result of the sale of certain natural gas gathering and processing assets located in Texas to a subsidiary of Eagle Rock Energy, Inc. in December 2005. For additional information, see discussion on page 30.
Equity earnings from investments increased $87.3 million in 2006, compared with 2005, primarily as a result of our adoption of EITF 04-5 as of January 1, 2006, which resulted in our consolidation of ONEOK Partners. ONEOK Partners holds various investments in unconsolidated affiliates, including a 50 percent interest in Northern Border Pipeline. Prior to January 1, 2006, ONEOK Partners was accounted for as an investment under the equity method.
Minority interests in income of consolidated subsidiaries, which reflects the remaining 54.3 percent of ONEOK Partners that we do not own, increased $222.0 million in 2006, compared with 2005, as a result of our 2006 adoption of EITF 04-5.
AdditionalMore information regarding our results of operations is provided in the following discussion of each segment’s results. The discontinued component is discussed in our Discontinued Operations and Energy Services segment sections.
Key Performance Indicators - Key performance indicators reviewed by management include:
return on invested capital, and
shareholder appreciation.
For 2007, our basic and diluted earnings per share from continuing operations were $2.84 and $2.79, respectively, representing a 4 percent increase in basic earnings per share and a 4 percent increase in diluted earnings per share from continuing operations compared with 2006. For 2006, our basic and diluted earnings per share from continuing operations were $2.74 and $2.68, respectively, representing a 32 percent decrease in basic earnings per share and a 28 percent decrease in diluted earnings per share from continuing operations compared with 2005. Return on invested capital was 14 percent in 2007 and 2006 compared with 23 percent in 2005. Our 2006operating results include the impact from the gain on the sale of a 20 percent interest in Northern Border Pipeline. The significantly higher earnings per share results in 2005 are primarily related to the gain on the salefor each of our Texas gathering and processing assets; this gain on sale, coupled with the gain on the sale of our production assets, increased our return on invested capital in 2005.
To evaluate shareholder appreciation, we compare the total return of an investment in our stock with the total return of an investment in the stock of our peer companies. For the year ended December 31, 2007, we ranked third in this shareholder appreciation calculation when compared with our peers.
segments.
ONEOK Partners Overview - Effective January 1, 2006, we were required to consolidate ONEOK Partners’ operations in our consolidated financial statements under EITF 04-5, and we elected to use the prospective method. In April 2006, we sold certain assets comprising our former gathering and processing, natural gas liquids, and pipelines and storage segments to ONEOK Partners for approximately $3 billion, including $1.35 billion in cash before adjustments, and approximately 36.5 million Class B limited partner units in ONEOK Partners. These former segments are included in our ONEOK Partners segment for all periods presented. We own 45.7 percent of ONEOK Partners; the remaining interest in ONEOK Partners is reflected as minority interest in income of consolidated subsidiaries on our Consolidated Statements of Income.
ONEOK Partners gathers and processes natural gas and fractionates NGLs primarily in the Mid-Continent and Rocky Mountain regions. ONEOK Partners’ operations include the gathering of natural gas production from oil and natural gas wells. Through gathering systems, these volumes are aggregated and treated or processed to remove water vapor, solids and other contaminants, and to extract NGLs in order to provide marketable natural gas, commonly referred to as residue gas. When the liquids are separated from the raw natural gas at the processing plants, the liquids are generally in the form of a mixed, unfractionated NGL stream.
ONEOK Partners also gathers, treats, fractionates, transports and stores NGLs. ONEOK Partners’ natural gas liquids gathering pipelines deliver unfractionated NGLs gathered from natural gas processing plants located in Oklahoma, Kansas and the Texas panhandle to fractionators it owns in Oklahoma, Kansas and Texas. ONEOK Partners’ NGL distribution assets connect the key NGL market centers in Conway, Kansas, and Mont Belvieu, Texas, as well as the Midwest markets near Chicago, Illinois.
ONEOK Partners operates interstate and intrastate natural gas transmission pipelines, natural gas storage facilities and non-processable natural gas gathering facilities. ONEOK Partners’ interstate assets transport natural gas through FERC-regulated interstate natural gas pipelines. ONEOK Partners’ intrastate natural gas pipeline assets access the major natural gas producing areas and transport natural gas throughout Oklahoma, Kansas and Texas. ONEOK Partners’ owns or reserves storage capacity in underground natural gas storage facilities in Oklahoma, Kansas and Texas.
Acquisition and Divestitures - The following acquisition and divestitures are described beginning on page 75.
In October 2007, ONEOK Partners completed the acquisition of an interstate natural gas liquids and refined petroleum products pipeline system and related assets from a subsidiary of Kinder Morgan for approximately $300 million, before working capital adjustments. The system extends from Bushton and Conway, Kansas, to Chicago, Illinois, and transports, stores and delivers a full range of NGL and refined petroleum products. The FERC-regulated system spans 1,627 miles and has a capacity to transport up to 134 MBbl/d. The transaction includes approximately 978 MBbl of owned storage capacity, eight NGL terminals and a 50 percent ownership of Heartland.
In April 2006, ONEOK Partners completed the sale of a 20 percent partnership interest in Northern Border Pipeline to TC PipeLines. ONEOK Partners and TC PipeLines each now own a 50 percent interest in Northern Border Pipeline, and an affiliate of TransCanada became operator of the pipeline in April 2007.
In April 2006, we sold certain assets comprising our former gathering and processing, natural gas liquids, and pipelines and storage segments to ONEOK Partners for approximately $3 billion, including $1.35 billion in cash, before adjustments, and approximately 36.5 million Class B limited partner units in ONEOK Partners. The Class B limited partner units and the related general partner interest contribution were valued at approximately $1.65 billion. We also purchased, through ONEOK Partners GP, from an affiliate of TransCanada, 17.5 percent of the general partner interest in ONEOK Partners for $40 million. This purchase resulted in our owning the entire 2 percent general partner interest in ONEOK Partners.
In April 2006, our ONEOK Partners segment acquired the 66-2/3 percent interest in Guardian Pipeline not previously owned by ONEOK Partners for approximately $77 million, increasing its ownership interest to 100 percent.
In December 2005, we sold our natural gas gathering and processing assets located in Texas. This sale included approximately 3,700 miles of pipe and six processing plants with a capacity of 0.2 Bcf/d. The impact of these assets on our ONEOK Partners segment’s operating income for the year ended December 31, 2005, was a decrease of $42.0 million. Additionally, we sold approximately 10 miles of non-contiguous, natural gas gathering pipelines in Texas.
In July 2005, we acquired natural gas liquids businesses from Koch. We also acquired Koch Vesco Holdings, LLC, an entity, which owns a 10.2 percent interest in Venice Energy Services Company, L.L.C. Venice Energy Services Company, L.L.C. owns a gas processing complex near Venice, Louisiana.
Selected Financial Results and Operating Information - The following tables set forth certain selected financial results and operating information for our ONEOK Partners segment for the periods indicated. | | | | | | | | | | | | | | | | Years Ended December 31, | | | | | Financial Results | | 2007 | | 2006 | | 2005 | | | | | | | (Thousands of dollars) | | | | Revenues | | $ | 5,831,558 | | $ | 4,738,248 | | $ | 4,334,599 | | | | Cost of sales and fuel | | | 4,935,665 | | | 3,894,700 | | | 3,787,830 | | | | Net margin | | | 895,893 | | | 843,548 | | | 546,769 | | | | Operating costs | | | 337,356 | | | 325,774 | | | 220,171 | | | | Depreciation and amortization | | | 113,704 | | | 122,045 | | | 67,411 | | | | Gain on sale of assets | | | 1,950 | | | 115,483 | | | 264,579 | | | | Operating income | | $ | 446,783 | | $ | 511,212 | | $ | 523,766 | | | | | | Equity earnings from investments | | $ | 89,908 | | $ | 95,883 | | $ | (1,511 | ) | | | Allowance for equity funds used during construction | | $ | 12,538 | | $ | 2,205 | | $ | - | | | | Minority interests in income of consolidated subsidiaries | | $ | 416 | | $ | 2,392 | | $ | - | | | |
| | | | | | | | | | | | | | | | | | Years Ended December 31, | | | | | | | Operating Information | | 2007 | | 2006 | | 2005 | | | | | | Natural gas gathered(BBtu/d) | | | 1,171 | | | 1,168 | | | 1,077 | | | | | | Natural gas processed(BBtu/d) | | | 621 | | | 988 | | | 1,117 | | | | | | Natural gas transported(MMcf/d) | | | 3,579 | | | 3,634 | | | 1,333 | | | | | | Natural gas sales(BBtu/d) | | | 281 | | | 302 | | | 334 | | | | | | Natural gas liquids gathered(MBbl/d) | | | 228 | | | 206 | | | 191 | | (a | ) | | | Natural gas liquids sales(MBbl/d) | | | 231 | | | 207 | | | 207 | | | | | | Natural gas liquids fractionated(MBbl/d) | | | 356 | | | 313 | | | 292 | | (a | ) | | | Natural gas liquids transported(MBbl/d) | | | 299 | | | 200 | | | 187 | | (a | ) | | | Capital expenditures(Thousands of dollars) | | $ | 709,858 | | $ | 201,746 | | $ | 56,255 | | | | | | Conway-to-Mount Belvieu OPIS average spread
Ethane/Propane mixture ($/gallon) | | $ | 0.06 | | $ | 0.05 | | $ | 0.05 | | | | | | Realized composite NGL sales prices ($/gallon) (b) | | $ | 1.06 | | $ | 0.93 | | $ | 0.89 | | | | | | Realized condensate sales price ($/Bbl) (b) | | $ | 67.35 | | $ | 57.84 | | $ | 52.69 | | | | | | Realized natural gas sales price ($/MMBtu)(b) | | $ | 6.21 | | $ | 6.31 | | $ | 7.30 | | | | | | Realized gross processing spread ($/MMBtu) (b) | | $ | 5.21 | | $ | 5.05 | | $ | 2.77 | | | | | | (a) - Data presented for 2005 represents the per day results of operations from July 1, 2005. | (b) - Statistics relate to our natural gas gathering and processing business. |
Operating results
| | | | | | | | | Variances | | | Variances | | | | Years Ended December 31, | | 2008 vs. 2007 | | | 2007 vs. 2006 | | | Financial Results | | 2008 | | 2007 | | 2006 | | Increase (Decrease) | | | Increase (Decrease) | | | | (Millions of dollars) | | | Revenues | | $ | 7,720.2 | | $ | 5,831.6 | | $ | 4,738.2 | | $ | 1,888.6 | | 32 | % | | $ | 1,093.4 | | 23 | % | | Cost of sales and fuel | | | 6,579.5 | | | 4,935.7 | | | 3,894.7 | | | 1,643.8 | | 33 | % | | | 1,041.0 | | 27 | % | | Net margin | | | 1,140.7 | | | 895.9 | | | 843.5 | | | 244.8 | | 27 | % | | | 52.4 | | 6 | % | | Operating costs | | | 371.8 | | | 337.4 | | | 325.8 | | | 34.4 | | 10 | % | | | 11.6 | | 4 | % | | Depreciation and amortization | | | 124.8 | | | 113.7 | | | 122.0 | | | 11.1 | | 10 | % | | | (8.3 | ) | (7 | %) | | Gain on sale of assets | | | 0.7 | | | 2.0 | | | 115.5 | | | (1.3 | ) | (65 | %) | | | (113.5 | ) | (98 | %) | | Operating income | | $ | 644.8 | | $ | 446.8 | | $ | 511.2 | | $ | 198.0 | | 44 | % | | $ | (64.4 | ) | (13 | %) | | Equity earnings from investments | | $ | 101.4 | | $ | 89.9 | | $ | 95.9 | | $ | 11.5 | | 13 | % | | $ | (6.0 | ) | (6 | %) | Allowance for equity funds used during construction | | $ | 50.9 | | $ | 12.5 | | $ | 2.2 | | $ | 38.4 | | * | | | $ | 10.3 | | * | | Minority interests in income of consolidated subsidiaries | | $ | (0.4 | ) | $ | (0.4 | ) | $ | (2.4 | ) | $ | - | | 0 | % | | $ | 2.0 | | 83 | % | | Capital expenditures | | $ | 1,253.9 | | $ | 709.9 | | $ | 201.7 | | $ | 544.0 | | 77 | % | | $ | 508.2 | | * | | | | | | | | | | | | | | | | | | | | | | | | | | * Percentage change is greater than 100 percent. | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, | | | Operating Information | | 2008 | | | 2007 | | | 2006 | | Natural gas gathered (BBtu/d) (a) | | | 1,164 | | | | 1,171 | | | | 1,168 | | Natural gas processed (BBtu/d) (a) | | | 641 | | | | 621 | | | | 988 | | Natural gas transported (MMcf/d) | | | 3,665 | | | | 3,579 | | | | 3,634 | | Residue gas sales (BBtu/d) (a) | | | 279 | | | | 281 | | | | 302 | | NGLs gathered (MBbl/d) | | | 276 | | | | 248 | | | | 226 | | NGL sales (MBbl/d) | | | 283 | | | | 231 | | | | 207 | | NGLs fractionated (MBbl/d) | | | 373 | | | | 356 | | | | 313 | | NGLs transported (MBbl/d) | | | 333 | | | | 299 | | | | 200 | | | Conway-to-Mont Belvieu OPIS average price differential | | | | | | | | | | | | | Ethane ($/gallon) | | $ | 0.15 | | | $ | 0.06 | | | $ | 0.05 | | Realized composite NGL sales prices ($/gallon) (a) | | $ | 1.27 | | | $ | 1.06 | | | $ | 0.93 | | Realized condensate sales price ($/Bbl) (a) | | $ | 89.30 | | | $ | 67.35 | | | $ | 57.84 | | Realized residue gas sales price ($/MMBtu) (a) | | $ | 7.34 | | | $ | 6.21 | | | $ | 6.31 | | Realized gross processing spread ($/MMBtu) (a) | | $ | 7.47 | | | $ | 5.21 | | | $ | 5.05 | | | (a) - Statistics relate to ONEOK Partners’ natural gas gathering and processing business. | |
- We began consolidating our investment in ONEOK Partners as45 - -
2008 vs. 2007 - Net margin increased by $52.3 million in 2007, compared with 2006, primarily due to the following: | · | an increase in ONEOK Partners’ natural gas liquids gathering and fractionation business due to the following: |
| o | an increase of $70.8 million in wider NGL product price differentials; |
| o | an increase of $32.1 million due to increased NGL gathering and fractionation volumes; and |
| o | an increase of $8.4 million in certain operational measurement gains, primarily at NGL storage caverns; |
| · | an increase in ONEOK Partners’ natural gas gathering and processing business due to the following: |
| o | an increase of $58.4 million due to higher realized commodity prices; |
| o | an increase of $11.9 million due to improved contractual terms; |
| o | an increase of $7.0 million due to higher volumes sold and processed; partially offset by |
| o | a decrease of $8.6 million due to a one-time favorable contract settlement that occurred in the fourth quarter of 2007; |
| · | an increase of $44.3 million in incremental margin in ONEOK Partners’ natural gas liquids pipelines business, due to the assets acquired from Kinder Morgan in October 2007, including $10.3 million due to increased throughput during the fourth quarter of 2008, compared with the fourth quarter of 2007; |
| · | an increase of $11.7 million due to increased transportation and storage margins primarily as a result of the impact of higher natural gas prices on retained fuel, and new and renegotiated storage contracts in ONEOK Partners’ natural gas pipelines business; and |
| · | an increase of $6.9 million primarily due to increased throughput from new NGL supply connections, including $2.6 million from Overland Pass Pipeline, which began operations during the fourth quarter 2008. |
Operating costs increased performanceprimarily due to incremental operating expenses associated with the assets acquired from Kinder Morgan, outside service costs primarily associated with scheduled maintenance expenses at ONEOK Partners’ Medford and Mont Belvieu fractionators, and chemical costs. Operating costs also increased due to costs associated with the startup of ONEOK Partners’ natural gas liquids businesses, which benefitednewly expanded Bushton fractionator and Overland Pass Pipeline.
Depreciation and amortization increased primarily due to depreciation expense associated with ONEOK Partners’ completed capital projects and the assets acquired from new supply connections thatKinder Morgan.
Equity earnings from investments increased volumes gathered, transported, fractionated and sold, primarily due to higher NGL product price spreads and higher isomerization price spreadsgathering revenues in ONEOK Partners’ natural gas liquids gatheringvarious investments, as well as a $8.3 million gain on the sale of Bison Pipeline LLC by Northern Border Pipeline, partially offset by reduced throughput on Northern Border Pipeline. ONEOK Partners owns a 50 percent equity interest in Northern Border Pipeline.
Allowance for equity funds used during construction and fractionation business,capital expenditures increased due to ONEOK Partners’ capital projects. 2007 vs. 2006 - Net margin relatedincreased primarily due to the acquisition of assets from Kinder Morgan in October 2007 in ONEOK Partners’ natural gas liquids pipelines business, andfollowing: increased storage margins in ONEOK Partners’ natural gas pipelines business, that was partially offset by
| · | an increase of $27.3 million from increased performance of ONEOK Partners’ natural gas liquids businesses, which benefited primarily from new supply connections that increased volumes gathered, transported, fractionated and sold; |
decreased natural gas processing and transportation margins in ONEOK Partners’ natural gas businesses resulting primarily from lower throughput, higher fuel costs and lower natural gas volumes processed as a result of various contract terminations.
| · | an increase of $20.6 million from new and renegotiated contractual terms and increased volumes in ONEOK Partners’ natural gas and natural gas liquids businesses; |
| · | an increase of $13.5 million in higher NGL product price differentials and higher isomerization price differentials in ONEOK Partners’ natural gas liquids gathering and fractionation business; |
| · | an increase of $11.5 million in incremental net margin in ONEOK Partners’ natural gas liquids pipeline business, due to the assets acquired from Kinder Morgan in October 2007; and |
| · | an increase of $5.4 million in storage margins in ONEOK Partners’ natural gas pipelines business; partially offset by |
| · | a decrease of $32.9 million in natural gas processing and transportation margins in ONEOK Partners’ natural gas businesses resulting primarily from lower throughput, higher fuel costs and lower volumes processed as a result of various contract terminations. |
Operating costs increased by $11.6 million during 2007, compared with 2006, primarily due to higher employee-related costs and the incremental operating expenses associated with the assets acquired from Kinder Morgan, partially offset by lower litigation costs.
Depreciation and amortization decreased by $8.3 million during 2007, compared with 2006, primarily due to a goodwill and asset impairment charge of $12.0 million recorded in the second quarter of 2006 related to Black Mesa Pipeline.
Gain on sale of assets decreased by $113.5 million during 2007, compared with 2006, primarily due to the $113.9 million gain on the sale of a 20 percent partnership interest in Northern Border Pipeline recorded in the second quarter of 2006. Equity earnings from investments for 2007 and 2006 primarily include earnings from ONEOK Partners’ interest in Northern Border Pipeline. The decrease of $6.0 million duringfor 2007 compared with 2006, iswas primarily due to the decrease in ONEOK Partners’ share of Northern Border Pipeline’s earnings from 70 percent in the first quarter of 2006 to 50 percent beginning in the second quarter of 2006. See page 7585 for discussion of the disposition of the 20 percent partnership interest in Northern Border Pipeline.
Allowance for equity funds used during construction and capital expenditures increased for 2007, compared with 2006, due to ONEOK Partners’ capital projects, which are discussed beginning on page 31.projects.
Minority interest in income of consolidated subsidiaries decreased $2.0 million during 2007, compared with 2006, primarily due to our acquisition of the remaining interest in Guardian Pipeline. Minority interest in net income of consolidated subsidiaries for our ONEOK Partners’ segment for 2006 included the 66-2/3 percent interest in Guardian Pipeline that ONEOK Partners did not own until April 2006. ONEOK Partners owned 100 percent of Guardian Pipeline beginning in April 2006, resulting in no minority interest in income of consolidated subsidiaries related to Guardian Pipeline after March 31, 2006. The increase
Commodity Price Risk - ONEOK Partners is exposed to commodity price risk, primarily from NGLs, as a result of $508.1 million in capital expenditures during 2007, compared with 2006,its contractual obligations for services provided. A small percentage of its services, based on volume, is driven primarily byprovided through keep-whole arrangements. See discussion regarding ONEOK Partners’ capital projects that are discussedcommodity price risk beginning on page 31.Net margin increased by $296.8 million for 2006, compared with 2005, primarily due to:
an increase of $191.1 million from the legacy ONEOK Partners operations, which were consolidated beginning January 1, 2006,
an increase of $101.8 million related to net margins on natural gas liquids gathering and distribution pipelines acquired from Koch63 under “Commodity Price Risk” in July 2005,
an increase of $72.1 million from the operations of the assets ONEOK Partners acquired from us in April 2006, driven primarily by strong commodity prices, higher gross processing spreads and increased natural gas transportation revenues, and
a decrease of $80.5 million resulting from the sale of natural gas gathering and processing assets located in Texas in December 2005.
The increase in operating costs of $105.6 million for 2006, compared with 2005, is primarily related to the consolidation of the legacy ONEOK Partners operations as of January 1, 2006, and the natural gas liquids assets acquired in 2005, offset by the sale of the Texas natural gas gathering and processing assets in December 2005.
Depreciation and amortization expense increased by $54.6 million for 2006, compared with 2005, primarily due to $37.9 million related to the consolidation of the legacy ONEOK Partners operations, $12.0 million for the Black Mesa Pipeline impairment and $15.5 million for the acquisition of natural gas liquids assets from Koch in 2005. These increases were offset by an $8.2 million decrease resulting from the December 2005 sale of natural gas gathering and processing assets located in Texas.
Operating income for 2006 includes the gain on sale of assets of $113.9 million related to ONEOK Partners’ sale of a 20 percent partnership interest in Northern Border Pipeline to TC PipeLines in April 2006. Operating income for 2005 includes a $264.2 million gain on the sale of the natural gas gathering and processing assets located in Texas to a subsidiary of Eagle Rock Energy, Inc. in December 2005. See Note B of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.
The increase in equity earnings from investments of $97.4 million for 2006, compared with 2005, resulted primarily from ONEOK Partners’ 50 percent interest in Northern Border Pipeline and gathering and processing joint venture interests in the Powder River and Wind River Basins.
The $145.5 million increase in capital expenditures for 2006, compared with 2005, is primarily related to $80.4 million in expenditures by ONEOK Partners’ legacy operations and $36.7 million in expenditures related to Overland Pass Pipeline Company.
For a discussion of market risk, see Item 7A, Quantitative and Qualitative Disclosures Aboutabout Market Risk in this Annual Report on Form 10-K.
Risk.
Distribution
DistributionOverview - Our Distribution segment provides natural gas distribution services to over two million customers in Oklahoma, Kansas and Texas through Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service, respectively. We serve residential, commercial, industrial and transportation customers in all three states. In addition, our distribution companies in Oklahoma and Kansas serve wholesale customers, and in Texas we serve public authority customers.
Selected Financial InformationResults - The following table sets forth certain selected financial informationresults for our Distribution segment for the periods indicated. | | | | | | | | | | | | | | | | Years Ended December 31, | | | | Financial Results | | 2007 | | | 2006 | | 2005 | | | | | | (Thousands of dollars) | | | Gas sales | | $ | 1,976,330 | | | $ | 1,836,862 | | $ | 2,094,126 | | | Transportation revenues | | | 87,301 | | | | 88,306 | | | 94,160 | | | Cost of gas | | | 1,435,415 | | | | 1,358,402 | | | 1,628,507 | | | Gross margin | | | 628,216 | | | | 566,766 | | | 559,779 | | | Other revenues | | | 35,432 | | | | 33,031 | | | 27,921 | | | Net margin | | | 663,648 | | | | 599,797 | | | 587,700 | | | Operating costs | | | 377,778 | | | | 371,460 | | | 360,351 | | | Depreciation and amortization | | | 111,615 | | | | 110,858 | | | 113,437 | | | Gain (loss) on sale of assets | | | (56 | ) | | | 18 | | | 5 | | | Operating income | | $ | 174,199 | | | $ | 117,497 | | $ | 113,917 | | | | |
| | | | | | | | | Variances | | | Variances | | | | | Years Ended December 31, | | 2008 vs. 2007 | | | 2007 vs. 2006 | | | Financial Results | | 2008 | | 2007 | | 2006 | | Increase (Decrease) | | | Increase (Decrease) | | | | | (Millions of dollars) | | | Gas sales | | $ | 2,049.0 | | $ | 1,976.3 | | $ | 1,836.9 | | $ | 72.7 | | 4 | % | | $ | 139.4 | | 8 | % | | Transportation revenues | | | 87.3 | | | 87.3 | | | 88.3 | | | - | | 0 | % | | | (1.0 | ) | (1 | %) | | Cost of gas | | | 1,496.7 | | | 1,435.4 | | | 1,358.4 | | | 61.3 | | 4 | % | | | 77.0 | | 6 | % | | Net margin, excluding other | | | 639.6 | | | 628.2 | | | 566.8 | | | 11.4 | | 2 | % | | | 61.4 | | 11 | % | | Other revenues | | | 41.3 | | | 35.4 | | | 33.0 | | | 5.9 | | 17 | % | | | 2.4 | | 7 | % | | Net margin | | | 680.9 | | | 663.6 | | | 599.8 | | | 17.3 | | 3 | % | | | 63.8 | | 11 | % | | Operating costs | | | 375.3 | | | 377.8 | | | 371.5 | | | (2.5 | ) | (1 | %) | | | 6.3 | | 2 | % | | Depreciation and amortization | | | 116.8 | | | 111.6 | | | 110.9 | | | 5.2 | | 5 | % | | | 0.7 | | 1 | % | | Gain (loss) on sale of assets | | | - | | | (0.1 | ) | | - | | | 0.1 | | 100 | % | | | (0.1 | ) | (100 | %) | | Operating income | | $ | 188.8 | | $ | 174.1 | | $ | 117.4 | | $ | 14.7 | | 8 | % | | $ | 56.7 | | 48 | % | | Capital expenditures | | $ | 169.0 | | $ | 162.0 | | $ | 159.0 | | $ | 7.0 | | 4 | % | | $ | 3.0 | | 2 | % |
Operating Results2008 vs. 2007 - Net margin increased by $63.9 million during 2007, compared with 2006, primarily due to:
| · | an increase of $15.7 million resulting from the implementation of new rate mechanisms, which includes a $12.4 million increase in Oklahoma and a $3.3 million increase in Texas; and |
| · | an increase of $2.2 million related to recovery of carrying costs for natural gas in storage. |
Operating costs decreased primarily due to: | · | a decrease of $4.3 million in employee-related costs; and |
| · | a decrease of $1.0 million in bad debt expense; partially offset by |
| · | an increase of $2.4 million in fuel-related vehicle costs. |
Depreciation and amortization increased primarily due to: | · | an increase of $4.0 million in depreciation expense related to our investment in property, plant and equipment; and |
| · | an increase of $1.2 million of regulatory amortization associated with revenue rider recoveries. |
2007 vs. 2006 - Net margin increased primarily due to: | · | an increase of $55.2 million resulting from the implementation of new rate schedules, which includes $51.1 million in Kansas and $4.1 million in Texas; and |
| · | an increase of $8.0 million from higher customer sales volumes as a result of a return to more normal weather in our entire service territory. |
an increase of $8.0 million from higher customer sales volumes as a result of a return to more normal weather in our entire service territory.
Operating costs increased $6.3 million during 2007, compared with 2006, primarily due to: an increase of $4.8 million in bad debt expense primarily in Oklahoma,
an increase of $5.3 million due to higher property taxes in Kansas, and
| · | an increase of $4.8 million in bad debt expense, primarily in Oklahoma; and |
a decrease of $4.0 million in labor and employee benefit costs.
Net margin increased $12.1 million for 2006, compared with 2005, due to:
an increase of $42.3 million resulting from the implementation of new rate schedules, which was made up of $39.7 million in Oklahoma and $2.6 million in Texas,
| · | an increase of $5.3 million due to higher property taxes in Kansas; partially offset by |
a decrease of $19.0 million primarily due to expiring riders and lower volumetric rider collections in Oklahoma,
| · | a decrease of $4.0 million in labor and employee benefit costs. |
a decrease of $10.0 million in customer sales due to warmer weather in our entire service territory, and
a decrease of $1.8 million due to reduced wholesale volumes in Kansas.
Operating costs increased $11.1 million for 2006, compared with 2005, due to:
an increase of $17.2 million in labor and employee benefit costs,
an increase of $1.7 million due to increased property taxes, partially offset by
a decrease of $7.6 million in bad debt expense.
Depreciation and amortization decreased $2.6 million for 2006, compared with 2005, primarily due to:
a decrease of $2.8 million in cathodic protection and service line amortization in Oklahoma from a limited issue rider which expired in the second quarter of 2005,
a decrease of $2.9 million related to the replacement of our field customer service system in Texas during the first quarter of 2005, and
an offsetting increase of $2.3 million for depreciation expense related to our investment in property, plant and equipment.
Selected Operating Data - The following tables set forth certain selected financial and operating information for our Distribution segment for the periods indicated.
| | | | | | | | | | | | | | | Years Ended December 31, | | | | Operating Information | | 2007 | | 2006 | | 2005 | | | Average number of customers | | | 2,050,767 | | | 2,031,551 | | | 2,018,900 | | | Customers per employee | | | 732 | | | 713 | | | 689 | | | Capital expenditures(Thousands of dollars) | | $ | 162,044 | | $ | 159,026 | | $ | 143,765 | | | | | | | | | Years Ended December 31, | | | | Volumes(MMcf) | | 2007 | | 2006 | | 2005 | | | Gas sales | | | | | | | | | | | | Residential | | | 121,587 | | | 110,123 | | | 122,010 | | | Commercial | | | 37,295 | | | 34,865 | | | 39,294 | | | Industrial | | | 1,758 | | | 1,624 | | | 2,432 | | | Wholesale | | | 13,231 | | | 29,263 | | | 33,521 | | | Public Authority | | | 2,679 | | | 2,520 | | | 2,559 | | | Total volumes sold | | | 176,550 | | | 178,395 | | | 199,816 | | | Transportation | | | 204,049 | | | 200,828 | | | 252,180 | | | Total volumes delivered | | | 380,599 | | | 379,223 | | | 451,996 | | | | | | | | | | | Years Ended December 31, | | | | Margin | | 2007 | | 2006 | | 2005 | | | | Gas Sales | | (Thousands of dollars) | | | Residential | | $ | 440,836 | | $ | 390,229 | | $ | 373,812 | | | Commercial | | | 99,521 | | | 88,752 | | | 93,014 | | | Industrial | | | 2,330 | | | 2,867 | | | 3,103 | | | Wholesale | | | 1,212 | | | 4,826 | | | 6,672 | | | Public Authority | | | 3,675 | | | 3,188 | | | 3,069 | | | Gross margin on gas sales | | | 547,574 | | | 489,862 | | | 479,670 | | | Transportation | | | 80,642 | | | 76,904 | | | 80,109 | | | Gross margin | | $ | 628,216 | | $ | 566,766 | | $ | 559,779 | | | | |
Residential and commercial volumes increased during 2007, compared with 2006, primarily due to a return to more normal weather from the unseasonably warm weather in 2006.
Residential, commercial and industrial volumes decreased in 2006, compared with 2005, due to warmer weather, primarily in the first quarter of 2006, which affects residential and commercial customers.
Wholesale sales represent contracted gas volumes that exceed the needs of our residential, commercial and industrial customer base and are available for sale to other parties. Wholesale volumes decreased during 2007, compared with 2006 and 2005, due to reduced volumes available for sale.
Public authority natural gas volumes reflect volumes used by state agencies and school districts served by Texas Gas Service.
Capital Expenditures - Our capital expenditure program includes expenditures for extending service to new areas, modifying customer service lines, increasing system capabilities, general replacements and improvements. It is our practice to maintain and periodically upgrade facilities to assureensure safe, reliable and efficient operations. Our capital expenditure program included $51.8 million, $50.6 million $54.9 million and $38.6$54.9 million for new business development in 2008, 2007 and 2006, and 2005, respectively. Capital expenditures
Selected Operating Information - - The following tables set forth certain selected operating information for new business development inour Distribution segment for the periods indicated. | | | Years Ended December 31, | | Operating Information | | 2008 | | 2007 | | 2006 | | Customers per employee | | | 719 | | | | 732 | | | | 713 | | Inventory storage balance (Bcf) | | | 25.1 | | | | 22.7 | | | | 26.3 | |
| | | Years Ended December 31, | | Volumes (MMcf) | | 2008 | | | 2007 | | | 2006 | | | Gas sales | | | | | | | | | | | Residential | | | 125,834 | | | | 121,587 | | | | 110,123 | | | Commercial | | | 37,758 | | | | 37,295 | | | | 34,865 | | | Industrial | | | 1,395 | | | | 1,758 | | | | 1,624 | | | Wholesale | | | 7,186 | | | | 13,231 | | | | 29,263 | | | Public Authority | | | 2,592 | | | | 2,679 | | | | 2,520 | | | Total volumes sold | | | 174,765 | | | | 176,550 | | | | 178,395 | | | Transportation | | | 219,398 | | | | 204,049 | | | | 200,828 | | | Total volumes delivered | | | 394,163 | | | | 380,599 | | | | 379,223 | |
| | | Years Ended December 31, | | | Margin | | 2008 | | | 2007 | | | 2006 | | | Gas Sales | | (Millions of dollars) | | | Residential | | $ | 444.0 | | | $ | 440.9 | | | $ | 390.2 | | | Commercial | | | 101.3 | | | | 99.5 | | | | 88.8 | | | Industrial | | | 2.6 | | | | 2.3 | | | | 2.9 | | | Wholesale | | | 0.6 | | | | 1.2 | | | | 4.8 | | | Public Authority | | | 3.8 | | | | 3.7 | | | | 3.2 | | | Net margin on gas sales | | | 552.3 | | | | 547.6 | | | | 489.9 | | | Transportation revenues | | | 87.3 | | | | 80.6 | | | | 76.9 | | | Net margin, excluding other | | $ | 639.6 | | | $ | 628.2 | | | $ | 566.8 | |
| | | Years Ended December 31, | | | Number of Customers | | 2008 | | | 2007 | | | 2006 | | | Residential | | | 1,886,118 | | | | 1,876,054 | | | | 1,859,480 | | | Commercial | | | 159,748 | | | | 160,517 | | | | 159,214 | | | Industrial | | | 1,420 | | | | 1,455 | | | | 1,528 | | | Wholesale | | | 28 | | | | 27 | | | | 18 | | | Public Authority | | | 2,963 | | | | 2,952 | | | | 2,645 | | | Transportation | | | 10,376 | | | | 9,762 | | | | 8,666 | | | Total customers | | | 2,060,653 | | | | 2,050,767 | | | | 2,031,551 | |
Residential volumes increased during 2008, compared with 2007, was impacted by delayed housing starts due to wetter thancolder temperatures in our Oklahoma and Kansas service territories; however, margins were moderated by weather normalization mechanisms.
Residential and commercial volumes increased during 2007, compared with 2006, primarily due to a return to more normal weather from the unseasonably warm weather in 2006.
Wholesale sales represent contracted gas volumes that exceed the needs of our residential, commercial and a decrease in housing permits in Oklahoma. Increased newindustrial customer installation in the Austinbase and El Paso areas of Texas and the Tulsa and Oklahoma City areas of Oklahoma were primarily responsibleare available for the increase in new business capital expendituressale to other parties. Wholesale volumes decreased during 2006,2008, compared with 2005.2007 and 2006, due to reduced volumes available for sale.
Public authority natural gas volumes reflect volumes used by state agencies and school districts served by Texas Gas Service.
Transportation margins increased during 2008, compared with 2007, primarily due to increased transportation volumes in Oklahoma and Kansas.
Regulatory Initiatives
OklahomaOklahoma - OnIn August 17, 2007, Oklahoma Natural Gas filed an application for authorization of a capital investment recovery mechanism asmechanism. In February 2008, the OCC approved a means to more timely recover and earn a rate of return on the capital investments made for maintaining its distribution system. A joint stipulation, was agreed to and signed by all parties in January 2008. This joint stipulation will allowwhich allows Oklahoma Natural Gas to collect a rate of return, depreciation and 50 percent of the carrying costsproperty tax expense associated with non-revenue producing incremental capital expenditures betweeninvestments since its 2005 rate filings. A general hearing on this matter was held on February 15, 2008.case. The rates, are expected to generatewhich were effective in March 2008, generated margins of approximately $7.6$7.7 million in revenues and are expected to be in place in March 2008.
In July 2008, Oklahoma Natural Gas filed to increase the capital investment recovery mechanism from $7.6 million to $12.6 million annually. In October 2008, the parties signed a joint stipulation approving the request, and an administrative law judge of the OCC subsequently recommended approval of the joint stipulation. The final order was recently authorizedapproved by the OCC in December 2008, and the increased recovery level was effective in January 2009.
The OCC has authorized Oklahoma Natural Gas to implement a natural gas hedge program as a three-year pilot program, with up to $10 million per year in hedge costs to be recovered from customers.In a 2005 rate filing, the parties stipulated thatdefer transmission pipeline Integrity Management Program (IMP) costs incurred (inclusive of operations and maintenance expense, depreciation, property taxes and a rate of return) in compliance with the Federal Pipeline Safety Improvement Act of 2002 should be addressed in a subsequent proceeding, and in an order issued in October of 2005, the OCC authorized Oklahoma Natural Gas to defer such costs (inclusive of operations and maintenance expense, depreciation, ad valorem taxes and a rate of return).2002. On January 31, 2007, Oklahoma Natural Gas filed anthe first application with the OCC seeking recovery of these costs. On August 31, 2007, the OCC issued an order approving a stipulation of the parties, which providesprovided for recovery of $7.2 million in IMP deferrals incurred as of July 31, 2007. 2007, and these deferrals were recovered during the months of October 2007 through June 2008.
The 2008second IMP application was made at the OCC on January 31, 2008, and covered the IMP deferrals for the months of August through December 2007 and the true-ups associated with the prior recovery period. This filing also requested $7.2 million to be recovered with a new IMP billing rate to be put in place in July 2008. The OCC approved this request, and billings under the 2008 IMP application began in July 2008. The third IMP application was made at the OCC on January 30, 2009, and covered the IMP deferrals for 2008, and the true-ups associated with the prior recovery period. This filing requests a total of $10.8 million with a new IMP billing rate to be put in place in July 2009. Oklahoma Natural Gas will continue to defer IMP costs as they are incurred and will filemake future filings to recover those costs.
In August 2008, Oklahoma Natural Gas filed with the OCC for approval to include the fuel-related portion of bad debts in the Purchased Gas Adjustment mechanism for cost recovery. In October 2008, all parties signed the joint stipulation approving the request, and an administrative law judge of the OCC subsequently recommended approval of the joint stipulation. The joint stipulation allows Oklahoma Natural Gas to begin deferring its fuel-related bad debts beginning in January 2009 and to collect those amounts above the levels in base rates through the Purchased Gas Adjustment beginning in January 2010. The final order was issued by the OCC in December 2008. The associated deferrals began in January 2009.
In October 2008, a newjoint application each year for recovery of any additional costs.incentive-based rates was filed by the OCC staff and Oklahoma Natural Gas. This application proposes that the OCC adopt an incentive-based rate design and more streamlined regulatory process. If approved, this will provide for more timely rate changes.
Kansas - In October 2006, Kansas Gas Service reached a settlement with the KCC staff and all other parties to increase annual revenues by approximately $52 million. The terms of the settlement were approved by the KCC in November 2006. The rate increase is effective for services rendered on or after January 1, 2007. Texas -
In August 2007, Texas2008, Kansas Gas Service filed for a rate adjustmentan application with the cityKCC to impose a surcharge designed to annually collect approximately $2.9 million in costs associated with its Gas System Reliability Surcharge (GSRS) mechanism. The GSRS mechanism allows natural gas utilities to earn a return and recover carrying costs associated with investments made to comply with state and federal pipeline safety requirements or costs to relocate existing facilities pursuant to requests made by a government entity. The KCC approved the request in December 2008, with authorized GSRS collections effective with customer billings on January 1, 2009.
Texas Gas Service requested a total increase of $5.5 million. On February 5, 2008, the El Paso City Council approved a rate increase of approximately $3.1 million. The increase is effective for meters read on or after February 15, 2008. - Texas Gas Service has received several regulatory approvals to implement rate increases in various municipalities in Texas. A total of $1.7 million in annual rate increases were approved and implemented in the fourth quarter of 2007. A total of $5.5 million in annual rate increases were approved and implemented in 2006.
In August 2007, Texas Gas Service filed for a rate adjustment with the city of El Paso, Texas, and the municipalities of Anthony, Clint, Horizon City, Socorro and Vinton. Texas Gas Service requested a total annual increase of $5.5 million. In February 2008, the El Paso City Council approved an annual rate increase of approximately $3.1 million. The increase was effective in February 2008.
In April 2008, the RRC approved a rate increase in our South Texas jurisdiction. The rate increase was effective May 2008 and will increase revenues by $1.1 million annually.
In May 2008, Texas Gas Service filed for interim rate relief under the Gas Reliability Infrastructure Program with the city of El Paso, Texas, and surrounding communities for approximately $1.1 million. This program is a capital recovery mechanism that allows for an interim rate adjustment providing recovery and a return on incremental capital investments made between rate cases. In August 2008, an annual rate increase of approximately $1.0 million was approved; the new rates were effective in September 2008.
In February 2009, Texas Gas Service filed a statement of intent to increase rates in its central Texas service area for approximately $3.6 million. If approved, new rates are expected to become effective in June 2009.
General - Certain costs to be recovered through the ratemaking process have been recorded as regulatory assets in accordance with Statement 71, “Accounting for the Effects of Certain Types of Regulation.” 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.
Overview - Our Energy Services segment’s primary focus is to create value for our customers by delivering physical natural gas products and risk management services through our network of contracted transportation and storage capacity and natural gas supply. These services include meeting our customers’ baseload, swing and peaking natural gas commodity requirements on a year-round basis. To provide these bundled services, we lease storage and transportation capacity. Our total storage capacity under lease is 96 Bcf, with maximum withdrawal capability of 2.4 Bcf/d and maximum injection capability of 1.6 Bcf/d. Our current transportation capacity is 1.8 Bcf/d. Our contracted storage and transportation capacity connects the major supply and demand centers throughout the United States and into Canada. With these contracted assets, our business strategies include identifying, developing and delivering specialized services and products for value to our customers, which are primarily LDCs, electric utilities, and commercial and industrial end users. Our storage and transportation capacity allows us opportunities to optimize these positions through our application of market knowledge and risk management skills.Our Energy Services segment regularly conducts business with ONEOK Partners, our 45.7 percent owned affiliate, which comprises our ONEOK Partners segment. This segment also conducts business with our Distribution segment. These services are provided under agreements with market-based terms.
Selected Financial and Operating InformationResults - The following tables settable sets forth certain selected financial and operating informationresults for our Energy Services segment for the periods indicated. | | | | | | | | | | | | | | | | Years Ended December 31, | | | | Financial Results | | 2007 | | | 2006 | | 2005 | | | | | | (Thousands of dollars) | | | Energy and power revenues | | $ | 6,639,884 | | | $ | 6,328,893 | | $ | 8,345,091 | | | Energy trading revenues, net | | | (10,613 | ) | | | 6,797 | | | 12,680 | | | Other revenues | | | 132 | | | | 117 | | | 980 | | | Cost of sales and fuel | | | 6,382,001 | | | | 6,061,989 | | | 8,152,391 | | | Net margin | | | 247,402 | | | | 273,818 | | | 206,360 | | | Operating costs | | | 39,920 | | | | 42,464 | | | 38,719 | | | Depreciation and amortization | | | 2,147 | | | | 2,149 | | | 2,071 | | | Operating income | | $ | 205,335 | | | $ | 229,205 | | $ | 165,570 | | | | | | | | | | | Years Ended December 31, | | | | Operating Information | | 2007 | | | 2006 | | 2005 | | | Natural gas marketed(Bcf) | | | 1,191 | | | | 1,132 | | | 1,191 | | | Natural gas gross margin($/Mcf) | | $ | 0.19 | | | $ | 0.22 | | $ | 0.14 | | | Physically settled volumes(Bcf) | | | 2,370 | | | | 2,288 | | | 2,387 | | | Capital expenditures(Thousands of dollars) | | $ | 158 | | | $ | - | | $ | 159 | | |
| | | | | | | | | Variances | | | Variances | | | | | Years Ended December 31, | | 2008 vs. 2007 | | | 2007 vs. 2006 | | | Financial Results | | 2008 | | 2007 | | 2006 | | Increase (Decrease) | | | Increase (Decrease) | | | | | (Millions of dollars) | | | Revenues | | $ | 7,585.8 | | $ | 6,629.4 | | $ | 6,335.8 | | $ | 956.4 | | 14 | % | | $ | 293.6 | | 5 | % | | Cost of sales and fuel | | | 7,475.1 | | | 6,382.0 | | | 6,062.0 | | | 1,093.1 | | 17 | % | | | 320.0 | | 5 | % | | Net margin | | | 110.7 | | | 247.4 | | | 273.8 | | | (136.7 | ) | (55 | %) | | | (26.4 | ) | (10 | %) | | Operating costs | | | 35.6 | | | 39.9 | | | 42.5 | | | (4.3 | ) | (11 | %) | | | (2.6 | ) | (6 | %) | | Depreciation and amortization | | | 0.9 | | | 2.1 | | | 2.1 | | | (1.2 | ) | (57 | %) | | | - | | 0 | % | | Gain on sale of assets | | | 1.5 | | | - | | | - | | | 1.5 | | 100 | % | | | - | | 0 | % | | Operating income | | $ | 75.7 | | $ | 205.4 | | $ | 229.2 | | $ | (129.7 | ) | (63 | %) | | $ | (23.8 | ) | (10 | %) | | Capital expenditures | | $ | 0.1 | | $ | 0.2 | | $ | - | | $ | (0.1 | ) | (50 | %) | | $ | 0.2 | | 100 | % |
Energy markets were affected by higher commodity prices during 2008, compared with 2007. The increase in commodity prices had a direct impact on our revenues and the cost of sales and fuel.
Operating Results2008 vs. 2007 - Net margin decreased by $26.4 million during primarily due to the following:
| · | a net decrease of $40.3 million in transportation margins, net of hedging activities, primarily due to decreased basis differentials between the Rocky Mountain and Mid-Continent regions, and increased transportation-related costs in 2008; |
| · | a decrease of $13.9 million in financial trading margins; and |
| · | a net decrease of $83.3 million in storage and marketing margins, net of hedging activities, primarily due to: |
| o | a net decrease of $87.3 million in physical storage margins net of hedging activities, as a result of: |
| · | hedging opportunities associated with weather related events that led to higher storage margins in 2007 compared with 2008; |
| · | lower 2008 storage margins related to storage risk management positions and the impact of changes in natural gas prices on these positions; and |
| · | fewer opportunities to optimize storage capacity due to the significant decline in natural gas prices in the second half of 2008; |
| o | a decrease of $9.7 million in physical storage margins due to a lower of cost or market write-down on natural gas inventory; and |
| o | a decrease of $2.1 million due to colder than anticipated weather and market conditions that increased the supply cost of managing our peaking and load-following services and provided fewer opportunities to increase margins through optimization activities, primarily in the first quarter of 2008; partially offset by |
| o | an increase of $15.8 million from changes in the unrealized fair value of derivative instruments associated with storage and marketing activities and improved marketing margins, which benefited from price movements and optimization activities. |
Operating costs decreased primarily due to lower employee-related costs and depreciation expense.
2007 compared withvs. 2006 - Net margin decreased primarily due to:a decrease of $22.0 million in transportation margins, net of hedging activities, associated with changes in the unrealized fair value of derivative instruments and the impact of a force majeure event on the Cheyenne Plains Gas Pipeline, as more fully described below,
a decrease of $5.0 million in retail activities from lower physical margins due to market conditions and increased competition,
a decrease of $4.3 million in financial trading margins, that was partially offset by
an increase of $4.9 million in storage and marketing margins, net of hedging activities, related to:
| · | a decrease of $22.0 million in transportation margins, net of hedging activities, associated with changes in the unrealized fair value of derivative instruments and the impact of a force majeure event on the Cheyenne Plains Gas Pipeline, as more fully described below; |
| · | a decrease of $5.0 million in retail activities from lower physical margins due to market conditions and increased competition; |
| · | a decrease of $4.3 million in financial trading margins that was partially offset by |
| · | an increase of $4.9 million in storage and marketing margins, net of hedging activities, related to: |
| o | an increase in physical storage margins, net of hedging activity, due to higher realized seasonal storage spreads and optimization activities,activities; partially offset by |
| o | a decrease in marketing margins,margins; and |
| o | a net increase in the cost associated with managing our peaking and load following services, slightly offset by higher demand fees collected for these services. |
In September 2007, a portion of the volume contracted under our firm transportation agreement with Cheyenne Plains Gas Pipeline Company was curtailed due to a fire at a Cheyenne Plains pipeline compressor station. The fire damaged a significant amount of instrumentation and electrical wiring, causing Cheyenne Plains Gas Pipeline Company to declare a force majeure event on the pipeline. This firm commitment was hedged in accordance with Statement 133. The discontinuance of fair value hedge accounting on the portion of the firm commitment that was impacted by the force majeure event resulted in a loss of approximately $5.5 million that was recognized in the third quarter. In addition, we incurred a margin lossquarter of approximately2007, of which $2.4 million of insurance proceeds were recovered and recognized in late 2007 on our actual physical transportation. We have filed a claim with our insurance carriers under our business interruption policy for reimbursementthe first quarter of losses incurred during the Cheyenne Plains pipeline capacity curtailments, which is currently being processed.2008. Cheyenne Plains Gas Pipeline Company resumed full operations in November 2007.
Operating costs decreased $2.5 million in 2007, compared with 2006, primarily due to decreased legal and employee-related costs, and reduced ad-valorem tax expense. Net margin increased $67.5 million
Selected Operating Information - - The following table sets forth certain selected operating information for 2006,our Energy Services segment for the periods indicated. | | | Years Ended December 31, | | | Operating Information | | 2008 | | | 2007 | | | 2006 | | Natural gas marketed (Bcf) | | | 1,160 | | | | 1,191 | | | | 1,132 | | Natural gas gross margin ($/Mcf) | | $ | 0.07 | | | $ | 0.19 | | | $ | 0.22 | | Physically settled volumes (Bcf) | | | 2,359 | | | | 2,370 | | | | 2,288 | |
Our natural gas in storage at December 31, 2008, was 81.9 Bcf, compared with 2005, primarily due to:an increase of $58.0 million in transportation margins, net of hedging activities, primarily due to improved66.7 Bcf at December 31, 2007. At December 31, 2008, our total natural gas basis differentials between Mid-Continent and Gulf Coast regions,
an increase of $7.1 million in our natural gas trading operations primarily associated with favorable basis spread and fixed-price movement in our basis trading and fixed-price portfolios,
a net increase of $0.9 million related to storage and marketing margins primarily due to:
| o | an increase of $7.1 million due to improved physical storage and marketing margins, net of hedging activities, and increased demand fees and optimization activities associated with peaking services, partially offset by, |
| o | a decrease of $6.2 million related to power margins associated with a tolling transaction that expired December 31, 2005, and |
an increase of $1.5 million in retail activities due to improved physical margins.
Operating costs increased $3.7 million in 2006,capacity under lease was 91 Bcf, compared with 2005, primarily96 Bcf at December 31, 2007.
Natural gas volumes marketed decreased slightly during 2008, compared with 2007, due to increased employee-related costs.injections in the third quarter of 2008. In addition, demand for natural gas was impacted by weather-related events in the third quarter of 2008, including a 15 percent decrease in cooling degree-days and demand disruption caused by Hurricane Ike.
Natural gas volumes marketed increased during 2007, compared with 2006, due to an increase in sales activity in the southeastern United States in the third quarter of 2007. Natural gas volumes were also impacted by a 14 percent increase in heating degree daysdegree-days in our service territory, compared with the same period in 2006. Natural gas volumes marketed decreased for 2006, compared with 2005, primarily due to higher storage injections in the second and third quarters of 2006, warmer temperatures in the majority of our service territory in the first and fourth quarters of 2006, and decreased sales in our Canadian operations.
Our natural gas in storage at December 31, 2007, was 66.7 Bcf, compared with 74.1 Bcf at December 31, 2006. At December 31, 2007, our total natural gas storage capacity under lease was 96 Bcf, compared with 86 Bcf at December 31, 2006.
The acquisition of natural gas storage capacity has becomeis more competitive as a result of new entrants, increases in the spread between summer and winter natural gas prices, and natural gas price volatility.market entrants. The increased demand for storage capacity has resulted in an increase in both the cost of leasing storage capacity and the required term of the lease. Longer terms and increased costs for our storage capacity leases could result in significant increases in the cost of our contractual commitments which are shown on page 52.commitments.
The following table shows theour margins by activity for the periods indicated. | | | | | | | | | | | | | | | | | | Years Ended December 31, | | | | | | | 2007 | | | 2006 | | | 2005 | | | | | | | (Thousands of dollars) | | | | Marketing and storage, gross | | $ | 409,051 | | | $ | 414,951 | | | $ | 350,227 | | | | Less: Storage and transportation costs | | | (191,863 | ) | | | (180,708 | ) | | | (174,838 | ) | | | Marketing and storage, net | | | 217,188 | | | | 234,243 | | | | 175,389 | | | | Retail marketing | | | 13,990 | | | | 19,006 | | | | 17,526 | | | | Financial trading | | | 16,224 | | | | 20,569 | | | | 13,445 | | | | Net margin | | $ | 247,402 | | | $ | 273,818 | | | $ | 206,360 | | | | | |
| | Years Ended December 31, | | | | | 2008 | | | 2007 | | | 2006 | | | | (Millions of dollars) | | | Marketing, storage and transportation, gross | | $ | 313.4 | | | $ | 409.1 | | | $ | 414.9 | | | Less: Storage and transportation costs | | | (219.8 | ) | | | (191.9 | ) | | | (180.7 | ) | | Marketing, storage and transportation, net | | | 93.6 | | | | 217.2 | | | | 234.2 | | | Retail marketing | | | 14.8 | | | | 14.0 | | | | 19.0 | | | Financial trading | | | 2.3 | | | | 16.2 | | | | 20.6 | | | Net margin | | $ | 110.7 | | | $ | 247.4 | | | $ | 273.8 | |
Marketing, storage and storage activities,transportation, net, primarily includeincludes physical marketing, purchases and sales, firm storage and transportation capacity expense, including the impact of cash flow and fair value hedges, and other derivative instruments used to manage our risk associated with these activities. The combinationRisk management and operational decisions have a significant impact on the net result of owning supply, controlling strategic assetsour marketing and storage activities. Origination gains are also a component of marketing activity, which is the fair value recognition of contracts that our wholesale marketing department structures to meet the risk management services allows us to provide commodity-diverse products and services toneeds of our customers such as peaking and load following services.customers.
Retail marketing includes revenues from providing physical marketing and supply services, coupled with risk management services, to residential, municipal, and small commercial and industrial customers.
Financial trading margin includes activities that are generally executed using financially settled derivatives. These activities are normally short term in nature, with a focus ofon capturing short-term price volatility. Energy trading revenues, net,Revenues in our Consolidated Statements of Income Statements includesinclude financial trading margins, as well as certain physical natural gas transactions with our trading counterparties. Revenues and cost of sales and fuel from such physical transactions are required to be reported on a net basis.
Contingencies
ContingenciesLegal Proceedings - We are a party to various litigation matters and claims that are normal in the course of our operations. While the results of litigation and claims cannot be predicted with certainty, we believe the final outcome of such matters will not have a material adverse effect on our consolidated results of operations, financial position or liquidity.
OtherFERC Matter - As a result of an internal review of a transaction that was brought to the attention of one of our affiliates by a third party, we have commencedconducted an internal review of transactions that may have violated FERC natural gas capacity release rules or related rules. While our internal review is ongoing, we believe it is likelyrules and determined that a limited number of thesethere were transactions will have violated FERC capacity release rules or related rules.that should be disclosed to the FERC. We have notified the FERC of this review and expect to filefiled a report with the FERC regarding these transactions in March 2008. We cooperated fully with the FERC in its investigation of this matter and have taken steps to better ensure that current and future transactions comply with applicable FERC regulations by mid-March 2008 concerning any violations. Atimplementing a compliance plan dealing with capacity release. We entered into a global settlement with the FERC to resolve this time, we do not believe that penalties, if any, associated with potential violations will havematter and other FERC enforcement matters, which was approved by the FERC on January 15, 2009. The global settlement provides for a material impacttotal civil penalty of $4.5 million and approximately $2.2 million in disgorgement of profits and interest, of which $1.7 million of the civil penalty was allocated to ONEOK Partners. The amounts were recorded as a liability on our resultsConsolidated Balance Sheet as of operations, financial position or liquidity.DISCONTINUED OPERATIONS
Overview - In September 2005, we completed the sale of our former production segment to TXOK Acquisition, Inc. for $645 million, before adjustments, and recognized a pre-tax gain on the sale of approximately $240.3 million. The gain reflects the cash received less adjustments, selling expenses and the net book value of the assets sold. The proceeds from the sale were used to reduce debt.
Additionally, in the third quarter of 2005, weDecember 31, 2008. We made the decision to sell our Spring Creek power plant, locatedrequired payments in Oklahoma, and exit the power generation business. In October 2005, we concluded that our Spring Creek power plant had been impaired and recorded an impairment expenseJanuary 2009.
Table of $52.2 million. We subsequently entered into an agreement to sell our Spring Creek power plant to Westar Energy, Inc. for $53 million. The transaction received FERC approval and the sale was completed on October 31, 2006.At the time of the sale, we retained a contract with the Oklahoma Municipal Power Authority (OMPA) that required us to provide OMPA with 75 megawatts of firm capacity per month for a monthly fixed charge of approximately $0.4 million through December 31, 2015. To fulfill our obligations under this contract, we entered into an agreement with Westar to purchase 75 megawatts of firm capacity on the same terms as our agreement with OMPA. In an arbitration ruling dated October 11, 2007, our contract with OMPA was terminated as of that date, and we were awarded payment for our services through that date. We are currently evaluating our alternatives with respect to our contract with Westar.
These components of our business are accounted for as discontinued operations. Accordingly, amounts in our consolidated financial statements and related notes for all periods shown relating to our former production segment and our power generation business are reflected as discontinued operations. The sale of our former production segment and the sale of our power generation business are in line with our business strategy to sell assets when deemed to be less strategic or as other conditions warrant.
Selected Financial Information - The amounts of revenue, costs and income taxes reported in discontinued operations are shown in the table below for the periods indicated.Contents
| | | | | | | | | | | | | | Years Ended December 31, | | | | | | | 2006 | | | 2005 | | | | | | | (Thousands of dollars) | | | | Operating revenues | | $ | 10,646 | | | $ | 135,213 | | | | Cost of sales and fuel | | | 7,393 | | | | 38,398 | | | | Net margin | | | 3,253 | | | | 96,815 | | | | Impairment expense | | | - | | | | 52,226 | | | | Operating costs | | | 837 | | | | 24,302 | | | | Depreciation and amortization | | | - | | | | 17,919 | | | | Operating income | | | 2,416 | | | | 2,368 | | | | Other income (expense), net | | | - | | | | 252 | | | | Interest expense | | | 3,013 | | | | 12,588 | | | | Income taxes | | | (232 | ) | | | (3,788 | ) | | | Income (loss) from operations of discontinued components, net | | $ | (365 | ) | | $ | (6,180 | ) | | | | | Gain on sale of discontinued components, net of tax of $90.7 million | | $ | - | | | $ | 149,577 | | | |
LIQUIDITY AND CAPITAL RESOURCES
General General- Part of our strategy is to grow through acquisitions and internally generated growth projects that strengthen and complement our existing assets. We have relied primarily on operating cash flow, borrowings from commercial paper and credit agreements, 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.
Beginning in 2007 and continuing in 2008, the capital markets have been impacted by macroeconomic, liquidity and other recessionary concerns. During this period, ONEOK and ONEOK Partners have continued to have access to ONEOK’s commercial paper program and the ONEOK Partners Credit Agreement, respectively, to fund short-term liquidity needs. Additionally, ONEOK Partners issued $600 million of long-term debt in September 2007. We anticipate that our existing capital resources, ability to obtain financing and cash flow generated from future operations will enable us to maintain our current level of operations and our planned operations including capital expenditures for the foreseeable future. We have no material guarantees of debt or other similar commitments to unaffiliated parties.
During 20072008 and 2006,continuing into 2009, the capital markets experienced volatility and disruption, which could limit our access to those markets or increase the cost of issuing new securities in the future. Higher commodity prices and wider basis differentials, particularly in 2008, have also resulted in higher collateral requirements and natural gas inventory costs in our Energy Services segment. Throughout this period, ONEOK has continued to have access to its $1.2 billion revolving credit agreement (ONEOK Credit Agreement); also, ONEOK Partners has continued to have access to the ONEOK Partners Credit Agreement, which has been adequate to fund short-term liquidity needs. In addition, beginning in August 2008, ONEOK had access to its new short-term credit agreement. In the third quarter of 2008, ONEOK began to utilize both of its credit agreements and lessened its use of commercial paper due to decreased liquidity and rising costs in the commercial paper market. See discussion below under “Short-term Liquidity.” Also in 2008, ONEOK Partners issued common units and received additional contributions from ONEOK Partners GP. See discussion below under “Long-term Financing.”
We expect continued deteriorating economic conditions in 2009, with downward pressures, relative to 2008, on commodity prices. We also expect continued volatility and disruption in the financial markets, which could result in an increased cost of capital. ONEOK and ONEOK Partners’ ability to continue to access capital expenditures were financed through operatingmarkets for debt and equity financing under reasonable terms depends on the Company’s and Partnership’s respective financial condition, credit ratings and market conditions. ONEOK and ONEOK Partners anticipate that cash flowsflow generated from operations, existing capital resources and short-ability to obtain financing will enable both to maintain current levels of operations and planned operations, collateral requirements and capital expenditures.
Capitalization Structure - The following table sets forth our capitalization structure for the periods indicated. | | Years Ended December 31, | | | | 2008 | | 2007 | | | Long-term debt | | 67% | | 70% | | | Equity | | 33% | | 30% | | | | | | | | | | Debt (including notes payable) | | 76% | | 71% | | | Equity | | 24% | | 29% | |
ONEOK does not guarantee the debt of ONEOK Partners. For purposes of determining compliance with financial covenants in the ONEOK Credit Agreement and ONEOK’s $400 million 364-day revolving credit facility dated August 6, 2008 (the 364-Day Facility), the debt of ONEOK Partners is excluded. At December 31, 2008, ONEOK’s capitalization structure, excluding the debt of ONEOK Partners, was 44 percent long-term debt. Capital expenditures for 2007 were $883.7 million,debt and 56 percent equity, compared with $376.351 percent long-term debt and 49 percent equity at December 31, 2007. At December 31, 2008, ONEOK’s capitalization structure, including notes payable and excluding the debt of ONEOK Partners, was 59 percent debt and 41 percent equity, compared with 52 percent debt and 48 percent equity at December 31, 2007. In February 2008, ONEOK repaid $402.3 million of maturing long-term debt with cash from operations and short-term borrowings. In February 2009, ONEOK repaid $100 million of maturing long-term debt with cash from operations and short-term borrowings.
Cash Management - ONEOK and ONEOK Partners each use similar centralized cash management programs that concentrate the cash assets of their operating subsidiaries in 2006, exclusivejoint accounts for the purpose of acquisitions. Of these amounts,providing financial flexibility and lowering the cost of borrowing, transaction costs and bank fees. Both centralized cash management programs provide that funds in excess of the daily needs of the operating subsidiaries are concentrated, consolidated or otherwise made available for use by other entities within the respective consolidated groups. ONEOK Partners’ capital expenditures during 2007 were $709.9 million, compared with $201.7 million foroperating subsidiaries participate in these programs to the same period in 2006, exclusiveextent they are permitted under FERC regulations. Under these cash management programs, depending on whether a participating subsidiary has short-term cash surpluses or cash requirements, ONEOK and ONEOK Partners provide cash to their subsidiary or the subsidiary provides cash to them.
Short-term Liquidity - ONEOK’s principal sources of short-term liquidity consist of cash generated from operating activities, quarterly distributions from ONEOK Partners’ capital projects, which arePartners, the ONEOK Credit Agreement and the 364-Day Facility, as discussed beginning on page 31.Financing - For ONEOK, financing is provided through available cash, commercial paper and long-term debt.below. ONEOK also has a credit agreement, which is used as a back-up for its commercial paper program andthat can be utilized for short-term liquidity needs. Other optionsneeds, to obtain financing include, butthe extent funds are not limited to, issuance of equity, issuance of mandatory convertible debt securities, issuance of trust preferred securities, asset securitizationavailable under the ONEOK Credit Agreement and sale/leaseback of facilities.the 364-Day Facility. ONEOK Partners’ operations are financed throughprincipal sources of short-term liquidity consist of cash generated from operating activities and the ONEOK Partners Credit Agreement.
During late 2008, ONEOK and ONEOK Partners decided to borrow under their available cashcredit facilities to fund their respective anticipated working capital requirements for the remainder of 2008 and into 2009.
In August 2008, ONEOK entered into the 364-Day Facility. The interest rate is based, at ONEOK’s election, on either (i) the higher of prime or one-half of one percent above the issuanceFederal Funds Rate or (ii) the Eurodollar rate plus a set number of basis points based on ONEOK’s current long-term unsecured debt or limited partner units.ratings by Moody’s and S&P. The 364-Day Facility is being used for working capital, capital expenditures and other general corporate purposes.
In September 2008, ONEOK entered into an amendment to the ONEOK Credit Agreement. The amendment changed certain sublimits but did not change the lenders’ aggregate commitment to lend up to $1.2 billion under the ONEOK Credit Agreement.
The total amount of short-term borrowings authorized by ONEOK’s Board of Directors is $2.5 billion. At December 31, 2008, ONEOK had no commercial paper outstanding, $1.4 billion in borrowings outstanding, $64.9 million in letters of credit issued, which includes $64.6 million under the ONEOK Credit Agreement and an additional $0.3 million in other letters of credit, and available cash and cash equivalents of approximately $332.4 million. Considering outstanding borrowings, commercial paper and letters of credit under the ONEOK Credit Agreement, ONEOK had $135.4 million of credit available at December 31, 2008, under the ONEOK Credit Agreement and the 364-Day Facility. As of December 31, 2008, ONEOK could have issued $1.5 billion of additional short- and long-term debt under the most restrictive provisions contained in its various borrowing agreements.
The total amount of short-term borrowings authorized by the Board of Directors of ONEOK Partners GP, the general partner of ONEOK Partners, is $1.5 billion. At December 31, 2007, ONEOK had $102.6 million of commercial paper outstanding, $58.7 million in letters of credit issued and available cash and cash equivalents of approximately $15.9 million. At December 31, 2007,2008, ONEOK Partners had $900$870 million in borrowings outstanding and $130 million of credit available under the ONEOK Partners Credit Agreement $100 million of borrowings outstanding under the ONEOK Partners Credit Agreement, as described in Note H of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K, and available cash and cash equivalents of approximately $3.2$177.6 million. As of December 31, 2007, ONEOK could have issued $2.0 billion of additional debt under the most restrictive provisions contained in its various borrowing agreements. As of December 31, 2007,2008, ONEOK Partners could have issued a $772.6 million of additional short- and long-term debt under the most restrictive provisions of its agreements, $1.1 billion of additional debt.In November 2007, agreements.
ONEOK Partners entered intohas an outstanding $25 million letter of credit issued by Royal Bank of Canada, which is used for counterparty credit support.
ONEOK Partners also has a $15 million Senior Unsecured Letter of Credit Facility and Reimbursement Agreement with Wells Fargo Bank, N.A., of which $12 million is currently being used, and a $12 million Standby Letter of Credit Agreementan agreement with Royal Bank of Canada.Canada, pursuant to which a $12 million letter of credit was issued. Both agreements are used to support various permits required by the KDHE for ONEOK Partners’ ongoing business in Kansas. In July 2007,
The ONEOK Partners exercisedCredit Agreement and the accordion feature364-Day Facility contain certain financial, operational and legal covenants. These requirements include, among others: | · | a $400 million sublimit for the issuance of standby letters of credit; |
| · | a limitation on ONEOK’s stand-alone debt-to-capital ratio, which may not exceed 67.5 percent at the end of any calendar quarter; |
| · | a requirement that ONEOK maintains the power to control the management and policies of ONEOK Partners, |
| · | a limit on new investments in master limited partnerships; and |
| · | other customary affirmative and negative covenants, including covenants relating to liens, investments, fundamental changes in ONEOK’s businesses, changes in the nature of ONEOK’s businesses, transactions with affiliates, the use of proceeds and a covenant that prevents ONEOK from restricting its subsidiaries’ ability to pay dividends. |
The debt covenant calculations in the ONEOK Credit Agreement and the 364-Day Facility exclude the debt of ONEOK Partners. Upon breach of any covenant by ONEOK, amounts outstanding under the ONEOK Credit Agreement or the 364-Day Facility may become immediately due and payable. At December 31, 2008, ONEOK’s stand-alone debt-to-capital ratio was 58.2 percent, and ONEOK was in compliance with all covenants under the ONEOK Credit Agreement and the ONEOK 364-Day Facility.
Under the ONEOK Partners Credit Agreement, ONEOK Partners is required to increasecomply with certain financial, operational and legal covenants. Among other things, these requirements include maintaining a ratio of indebtedness to adjusted EBITDA (EBITDA plus minority interest in income of consolidated subsidiaries, distributions received from investments and EBITDA related to any approved capital projects less equity earnings from investments and the commitmentequity portion of AFUDC) of no more than 5 to 1. If ONEOK Partners consummates one or more acquisitions in which the aggregate purchase price is $25 million or more, the allowable ratio of indebtedness to adjusted EBITDA will be increased to 5.5 to 1 for the three calendar quarters following the acquisition. Upon any breach of any covenant by ONEOK Partners in its ONEOK Partners Credit Agreement, amounts by $250 million to a total of $1.0 billion.ONEOK’s $1.2 billion credit agreement (ONEOK Credit Agreement) andoutstanding under the ONEOK Partners Credit Agreement contain typical covenants as discussed in Note H of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.may become immediately due and payable. At December 31, 2007,2008, ONEOK Partners’ ratio of indebtedness to adjusted EBITDA was 4.1 to 1, and ONEOK Partners was in compliance with all covenants under the ONEOK Partners Credit Agreement.
The average interest rate on ONEOK and ONEOK Partners wereshort-term debt outstanding at December 31, 2008, was 4.51 percent and 4.22 percent, respectively, compared with a weighted average rate of 3.88 percent and 3.94 percent, respectively, for the year ended December 31, 2008. Based on the forward LIBOR curve, we expect the interest rate on ONEOK and ONEOK Partners’ short-term borrowings to decrease in compliance2009, compared with all covenants.2008.
Long-term Financing - In addition to the principal sources of short-term liquidity discussed above, options available to ONEOK to meet its longer-term cash requirements include the issuance of equity, issuance of long-term notes, issuance of convertible debt securities, asset securitization and sale/leaseback of facilities. Options available to ONEOK Partners to meet its longer-term cash requirements include the issuance of common units, issuance of long-term notes, issuance of convertible debt securities, and asset securitization and sale/leaseback of facilities.
ONEOK and ONEOK Partners are subject, however, to changes in the equity and debt markets, and there is no assurance they will be able or willing to access the public or private markets in the future. ONEOK and ONEOK Partners may choose to meet their cash requirements by utilizing some combination of cash flows from operations, altering the timing of controllable expenditures, restricting future acquisitions and capital projects, borrowing under existing credit facilities or pursuing other debt or equity financing alternatives. Some of these alternatives could involve higher costs or negatively affect their respective credit ratings. Based on ONEOK’s and ONEOK Partners’ investment-grade credit ratings, general financial condition and market expectations regarding their future earnings and projected cash flows, ONEOK and ONEOK Partners believe that they will be able to meet their respective cash requirements and maintain their investment-grade credit ratings.
ONEOK Partners Debt Issuance - In September 2007, ONEOK Partners completed an underwritten public offering of $600 million aggregate principal amount of 6.85 percent Senior Notes due 2037 (the 2037 Notes). The 2037 Notes were issued under ONEOK Partners’ existing shelf registration statement filed with the SEC.
ONEOK Partners may redeem the 2037 Notes, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount of the 2037 Notes, plus accrued and unpaid interest and a make-whole premium. The redemption price will never be less than 100 percent of the principal amount of the 2037 Notes plus accrued and unpaid interest. The 2037 Notes are senior unsecured obligations, ranking equally in right of payment with all of ONEOK Partners’ existing and future unsecured senior indebtedness, and effectively junior to all of the existing debt and other liabilities of its non-guarantor subsidiaries. The 2037 Notes are non-recourse to ONEOK. For more information regarding
Debt Covenants - The terms of ONEOK’s long-term notes are governed by indentures containing covenants that include, among other provisions, limitations on ONEOK’s ability to place liens on its property or assets and its ability to sell and lease back its property.
We filed a new form of indenture in 2008. The new indenture includes covenants that are similar to those contained in our prior indentures. The new indenture does not limit the 2037 Notes, refer to discussion in Note I of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.In September 2006, ONEOK Partners completed an underwritten public offering of (i) $350 million aggregate principal amount of 5.90 percent Seniordebt securities that may be issued and provides that debt securities may be issued from time to time in one or more additional series.
The indenture governing ONEOK Partners’ 2037 Notes due 2012, (ii) $450 milliondoes not limit the aggregate principal amount of 6.15 percent Senior Notes due 2016 and (iii) $600 million aggregate principal amount of 6.65 percent Senior Notes due 2036 (collectively, the Notes). ONEOK Partners registered the sale of the Notes with the SEC pursuant to a shelf registration statement filed on September19, 2006. The Notes are non-recourse to ONEOK. For more information regarding the Notes, refer to discussion in Note I of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Capitalization Structure - The following table sets forth our consolidated capitalization structure for the periods indicated.
| | | | | | | | | | | | Years Ended December 31, | | | | | | | 2007 | | | 2006 | | | | Long-term debt | | 70 | % | | 65 | % | | | Equity | | 30 | % | | 35 | % | | | Debt (including Notes payable) | | 71 | % | | 65 | % | | | Equity | | 29 | % | | 35 | % | | |
ONEOK does not guarantee the debt of ONEOK Partners. For purposes of determining compliance with financial covenants in ONEOK’s Credit Agreement, the debt of ONEOK Partners is excluded. At December 31, 2007, ONEOK’s capitalization structure, excluding the debt of ONEOK Partners, was 51 percent long-term debt and 49 percent equity, compared with 48 percent long-term debt and 52 percent equity at December 31, 2006. In February 2008, we repaid $402.3 million of maturing long-term debt with cash from operations.
Credit Ratings - Our investment grade credit ratings as of December 31, 2007, are shown in the table below.
| | | | | | | | | | | | | ONEOK | | ONEOK Partners | | | Rating Agency | | Rating | | Outlook | | Rating | | Outlook | | | Moody’s
| | Baa2 | | Stable | | Baa2 | | Stable | | | S&P
| | BBB | | Stable | | BBB | | Stable | | |
ONEOK’s commercial paper is rated P2 by Moody’s and A2 by S&P. Credit ratingssecurities that may be affected by a material changeissued and provides that debt securities may be issued from time to time in financial ratiosone or a material event affecting the business.more additional series. The most common criteria for assessment of credit ratings are the debt-to-capital ratio, business risk profile, pretaxindenture contains covenants including, among other provisions, limitations on ONEOK Partners’ ability to place liens on its property or assets and after-tax interest coverage,its ability to sell and liquidity. If our credit ratings were downgraded, the interest rates on our commercial paper borrowings would increase, resulting in an increase in our cost to borrow funds, and we could potentially lose access to the commercial paper market. 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 $1.2 billion credit agreement, which expires July 2011, and ONEOK Partners has access to a $1.0 billion revolving credit agreement that expires March 2012.
lease back its property.
ONEOK Partners’ $250 million and $225 million long-termsenior notes, payable, due 2010 and 2011, respectively, contain provisions that require ONEOK Partners to offer to repurchase the senior notes at par value if its Moody’s or S&P credit rating falls below investment grade (Baa3 for Moody’s or BBB- for S&P) and the investment gradeinvestment-grade rating is not reinstated within a period of 40 days. Further, the indentures governing ONEOK Partners’ senior notes due 2010 and 2011 include an event of default
upon acceleration of other indebtedness of $25 million or more and the indentures governing the senior notes due 2012, 2016, 2036 and 2037 include an event of default upon the acceleration of other indebtedness of $100 million or more that would be triggered by such an offer to repurchase. Such an event of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding senior notes due 2010, 2011, 2012, 2016, 2036 and 2037 to declare those notes immediately due and payable in full.
ONEOK Partners Equity Issuance - In March 2008, ONEOK purchased from ONEOK Partners, in a private placement, an additional 5.4 million of ONEOK Partners’ common units for a total purchase price of approximately $303.2 million. In addition, ONEOK Partners completed a public offering of 2.5 million common units at $58.10 per common unit and received net proceeds of $140.4 million after deducting underwriting discounts but before offering expenses. In conjunction with ONEOK Partners’ private placement and the public offering of common units, ONEOK Partners GP contributed $9.4 million to ONEOK Partners in order to maintain its 2 percent general partner interest. ONEOK and ONEOK Partners GP funded these amounts with available cash and short-term borrowings.
In April 2008, ONEOK Partners sold an additional 128,873 common units at $58.10 per common unit to the underwriters of the public offering upon the partial exercise of their option to purchase additional common units to cover over-allotments. ONEOK Partners received net proceeds of approximately $7.2 million from the sale of these common units after deducting underwriting discounts but before offering expenses. In conjunction with the partial exercise by the underwriters, ONEOK Partners GP contributed $0.2 million to ONEOK Partners in order to maintain its 2 percent general partner interest. Following these transactions, our interest in ONEOK Partners is 47.7 percent.
ONEOK Partners used a portion of the proceeds from the sale of common units and the general partner contributions to repay borrowings under its existing ONEOK Partners Credit Agreement.
Capital Expenditures - ONEOK’s and ONEOK Partners’ capital expenditures are typically financed through operating cash flows, short- and long-term debt and the issuance of equity. Total capital expenditures for 2008 were $1,473.1 million, compared with $883.7 million in 2007, exclusive of acquisitions. Of these amounts, ONEOK Partners’ capital expenditures for 2008 were $1,253.9 million, compared with $709.9 million in 2007, exclusive of acquisitions. The increase in capital expenditures for 2008, compared with 2007, is driven primarily by ONEOK Partners’ internal capital projects discussed beginning on page 37, and ONEOK’s purchase of ONEOK Plaza. ONEOK and ONEOK Partners expect to continue to finance future capital expenditures with a combination of operating cash flows, short- and long-term debt, and the issuance of common units by ONEOK Partners.
The following table summarizes our 2009 projected capital expenditures, excluding AFUDC.
| 2009 Projected Capital Expenditures | | | | | | (Millions of dollars) | | ONEOK Partners | | | | $ | 425 | | | | Distribution | | | | | 137 | | | | Energy Services | | | | | - | | | | Other | | | | | 19 | | | | Total projected capital expenditures | | | | $ | 581 | | |
Projected 2009 capital expenditures are significantly less than 2008 capital expenditures, primarily due to the completion of the Overland Pass Pipeline and related projects and the Guardian Pipeline expansion and extension. Additional information about our capital expenditures is included under “Capital Projects” on page 37. ONEOK Partners anticipates spending $300 million to $500 million per year on growth capital expenditures for the years 2010 through 2015.
Investment in Northern Border Pipeline - Northern Border Pipeline anticipates an equity contribution of approximately $85 million that will be required of its partners in 2009, of which ONEOK Partners’ share will be approximately $43 million for its 50 percent equity interest.
Credit Ratings - Our credit ratings as of December 31, 2008, are shown in the table below.
| | ONEOK | | | ONEOK Partners | | Rating Agency | | Rating | | Outlook | | | Rating | | Outlook | | Moody's | | Baa2 | | Stable | | | Baa2 | | Stable | | S&P | | BBB | | Stable | | | BBB | | Stable |
ONEOK’s commercial paper is rated P2 by Moody’s and A2 by S&P. ONEOK’s and ONEOK Partners’ credit ratings, which are currently investment grade, may be affected by a material change in financial ratios or a material event affecting the business. The most common criteria for assessment of credit ratings are the debt-to-capital ratio, business risk profile, pretax and after-tax interest coverage, and liquidity. ONEOK and ONEOK Partners do not anticipate their respective credit ratings to be downgraded. However, if our credit ratings were downgraded, the interest rates on our commercial paper borrowings, the ONEOK Credit Agreement and the 364-Day Facility would increase, resulting in an increase in our cost to borrow funds, and we could potentially lose access to the commercial paper market. Likewise, ONEOK Partners would see increased borrowing costs under the ONEOK Partners Credit Agreement. In the event that ONEOK is unable to borrow funds under its commercial paper program and there has not been a material adverse change in its business, ONEOK would continue to have access to the ONEOK Credit Agreement, which expires in July 2011, and the 364-Day Facility, which expires in August 2009. An adverse rating change alone is not a default under the ONEOK Credit Agreement, the 364-Day Facility or the ONEOK Partners Credit Agreement but could trigger repurchase obligations with respect to certain long-term debt. See additional discussion about our credit ratings under “Debt Covenants.”
If ONEOK Partners’ repurchase obligations are triggered, it may not have sufficient cash on hand to repurchase and repay any accelerated senior notes, which may cause it to borrow money under its credit facilities or seek alternative financing sources to finance the repurchases and repayment. ONEOK Partners could also face difficulties accessing capital or its borrowing costs could increase, impacting its ability to obtain financing for acquisitions or capital expenditures, to refinance indebtedness and to fulfill its debt obligations. A decline in ONEOK Partners’ credit rating below investment grade may also require ONEOK Partners to provide security to its counterparties in the form of cash, letters of credit or other negotiable instruments.
Our Energy Services segment relies upon the investment gradeinvestment-grade rating of ONEOK’s senior unsecured long-term debt to satisfy credit requirements with most of our counterparties.reduce its collateral requirements. If ONEOK’s 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 gradeinvestment-grade rating, we may be required to fund margin requirements with our counterparties with cash, letters of credit or other negotiable instruments. At December 31, 2007,2008, we could have been required to fund approximately $56.8$36.2 million in margin requirements related to financial contracts upon such a downgrade. A decline in ONEOK’s credit rating below investment grade may also significantly impact other business segments.
Other than ONEOK Partners’ note repurchase obligations and the margin requirementrequirements for our Energy Services segment described above, we have determined that we do not have significant exposure to rating triggers under ONEOK’s commercial paper agreement, trust indentures, building leases, equipment leases and other various contracts. Rating triggers are defined as provisions that would create an automatic default or acceleration of indebtedness based on a change in our credit rating.
In the normal course of business, ONEOK’s and ONEOK Partners’ credit agreements contain provisions that would causecounterparties provide secured and unsecured credit. In the cost to borrow funds to increase if their respective credit rating is negatively adjusted. An adverse rating change is not defined asevent of a default ofdowngrade in ONEOK’s or ONEOK Partners’ credit agreements.Capital Projects - Seerating or a significant change in ONEOK’s or ONEOK Partners’ counterparties’ evaluation of our creditworthiness, ONEOK or ONEOK Partners could be asked to provide additional collateral in the “Capital Projects” section beginning on page 31 for discussionform of capital projects.
cash, letters of credit or other negotiable instruments.
ONEOK Partners’ Class B Units - - The units we received from ONEOK Partners were newly created Class B limited partner units. Distributions on the Class B limited partner units were prorated from the date of issuance. As of April 7, 2007, the Class B limited partner units are no longer subordinated to distributions on ONEOK PartnersPartners’ common units and generally have the same voting rights as the common units.
At a special meeting of the ONEOK Partners common unitholders held March 29, 2007, the unitholders approved a proposal to permit the conversion of all or a portion of the Class B limited partner units issued in the acquisition and consolidation of certain companies comprising our former gathering and processing, natural gas liquids, and pipelines and storage segments in a series of transactions (collectively the ONEOK Transactions) into common units at the option of the Class B unitholder. The March 29, 2007, special meeting was adjourned to May 10, 2007, to allow unitholders additional time to vote on a proposal to approve amendments to the ONEOK Partners’ Partnership Agreement, which had the amendments been approved, would have granted voting rights for units held by us and our affiliates if a vote is held to remove us as the general partner and would have required fair market value compensation for our general partner interest if we are removed as general partner. While a majority of ONEOK Partners common unitholders voted in favor of the proposed amendments to the ONEOK Partners Partnership Agreement at the reconvened meeting of the common unitholders held May 10, 2007, the proposed amendments were not approved by the required two-thirds affirmative vote of the outstanding units, excluding the common units and Class B units held by us and our affiliates. As a result, effective April 7, 2007, the Class B limited partner units are entitled to receive increased quarterly distributions and distributions upon liquidation equal to 110 percent of the distributions paid with respect to the common units.
On June 21, 2007, we, as the sole holder of ONEOK PartnersPartners’ Class B limited partner units, waived our right to receive the increased quarterly distributions on the Class B units for the period April 7, 2007, through December 31, 2007, and
continuing thereafter until we give ONEOK Partners no less than 90 days advance notice that we have withdrawn our waiver. Any such withdrawal of the waiver will be effective with respect to any distribution on the Class B units declared or paid on or after 90 days following delivery of the notice.
In addition, since the proposed amendments to the ONEOK Partners’ Partnership Agreement were not approved by the common unitholders, if the common unitholders vote at any time to remove us or our affiliates as the general partner, quarterly distributions payable on Class B limited partner units would increase to 123.5 percent of the distributions payable with respect to the common units, and distributions payable upon liquidation of the Class B limited partner units would increase to 123.5 percent of the distributions payable with respect to the common units.
Stock Repurchase Plan - For more information regarding the Stock Repurchase Plan, refer to discussion in Note G of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Commodity Prices - We are subject to commodity price volatility. Significant fluctuations in commodity price in either physical or financial energy contracts may impact our overall liquidity due to the impact the commodity price change haschanges have on items such asour cash flows from operating activities, including the cost ofimpact on working capital for NGLs and natural gas held in storage, increased margin requirements the cost of transportation to various market locations, collectibility ofand certain energy-related receivables and working capital.receivables. We believe that our current commercial paper programONEOK’s and ONEOK Partners’ lines ofavailable credit and cash and cash equivalents are adequate to meet liquidity requirements associated with commodity price volatility. See discussion beginning on page 63 under “Commodity Price Risk” in Item 7A, Quantitative and Qualitative Disclosures about Market Risk for information on our hedging activities.
Pension and Postretirement Benefit Plans - Information about our pension and postretirement benefits plans, including anticipated contributions, is included under Note J of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
At December 31, 2007, the funded status of our pension plans exceeded 94 percent as required by federal regulations. General market factors in 2008 negatively impacted the fair value of our plan assets, and as a result, we made a voluntary contribution to our pension plans of $112 million on December 31, 2008. We do not expect that our funding requirements in 2009 will have a material impact on our liquidity.
ENVIRONMENTAL LIABILITIES
Information about our environmental liabilities is included in Note K of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
We use the indirect method to prepare our Consolidated Statements of Cash Flows combineFlows. Under this method, we reconcile net income to cash flows provided by operating activities by adjusting net income for those items that impact net income but may not result in actual cash receipts or payments during the period. These reconciling items include depreciation and amortization, allowance for equity funds used during construction, gain on sale of assets, minority interests in income of consolidated affiliates, undistributed earnings from discontinued operations withequity investments in excess of distributions received, deferred income taxes, stock-based compensation expense, allowance for doubtful accounts, inventory adjustments and investment securities gains. The following table sets forth the changes in cash flows from continuing operations within each category. Discontinued operations accountedby operating, investing and financing activities for approximately $77.2the periods indicated.
| | | | | | | Variances | | Variances | | | | Years Ended December 31, | | 2008 vs. 2007 | | 2007 vs. 2006 | | | | 2008 | | 2007 | | 2006 | | Increase (Decrease) | | Increase (Decrease) | | | | (Millions of dollars) | | | Total cash provided by (used in): | | | | | | | | | | | | | | | | | | Operating activities | | $ | 475.7 | | $ | 1,029.7 | | $ | 873.3 | | $ | (554.0 | ) | (54 | %) | | $ | 156.4 | | 18 | % | | Investing activities | | | (1,454.3 | ) | | (1,151.8 | ) | | (237.2 | ) | | (302.5 | ) | (26 | %) | | | (914.6 | ) | * | | | Financing activities | | | 1,469.6 | | | 72.9 | | | (618.8 | ) | | 1,396.7 | | * | | | | 691.7 | | * | | | Change in cash and cash equivalents | | | 491.0 | | | (49.2 | ) | | 17.3 | | | 540.2 | | * | | | | (66.5 | ) | * | | | Cash and cash equivalents at beginning of period | | | 19.1 | | | 68.3 | | | 7.9 | | | (49.2 | ) | (72 | %) | | | 60.4 | | * | | Effect of Accounting Change on Cash and Cash Equivalents | | | - | | | - | | | 43.1 | | | - | | 0 | % | | | (43.1 | ) | (100 | %) | | Cash and cash equivalents at end of period | | $ | 510.1 | | $ | 19.1 | | $ | 68.3 | | $ | 491.0 | | * | | | $ | (49.2 | ) | (72 | %) | | * Percentage change is greater than 100 percent. | | | | | | | | | | | | | | | | | | | | | |
Operating Cash Flows - Operating cash flows decreased by $554.0 million for 2008, compared with 2007, primarily due to changes in working capital. These changes decreased operating cash flows by $515.3 million for 2008, compared with an increase of $203.6 million for 2007, primarily due to decreases in accounts payable and increased funding for our pension plans, partially offset by decreases in accounts and notes receivable. The decrease in operating cash inflowsflows due to increases in working capital for the year ended December 31, 2005. Discontinued operations accounted for approximately $44.4 million in investing cash outflows for the year ended December 31, 2005, and did not account for any financing cash flows. The absence of cash flows from our discontinued operations did not have a significant impact on our future cash flows.Operating Cash Flows - 2008 was partially offset by higher net income.
Operating cash flows increased by $156.4 million for 2007, compared with 2006. Working capital increased operating cash flows by $209.9$203.6 million for 2007, compared with an increase of $59.7 million for 2006. Operating cash flows increased by $1.0 billion for 2006, compared with 2005, primarily as a result of changes in components of working capital which increased operating cash flows by $59.7 million for 2006, compared with a decrease of $580.8 million for 2005, as a result of decreased accounts receivable, decreased inventories and decreased accounts payable. The impact of lower commodity prices on accounts receivable, accounts payable and natural gas inventory positively impacted operating cash flows in 2006, compared with 2005.
The increase in 2006 operating cash flows, compared with 2005, was also impacted by the consolidation of ONEOK Partners as of January 1, 2006. During the year ended December 31, 2006, we received $123.4 million in distributions, primarily from Northern Border Pipeline, compared with distributions primarily from ONEOK Partners of $11.0 million in the prior year.
Investing Cash Flows - Cash used in investing activities was $1.2 billion for 2007, compared with $237.2 million for 2006. The increased use of cash during 20072008 was primarily related to ana $589.4 million increase in capital expenditures, ofcompared with 2007. Capital expenditures increased $507.4 million whenfor 2007, compared with 2006. For further discussion ofThese increases are primarily related to ONEOK Partners’ capital projects, see page 31.projects.
In October 2007, ONEOK Partners acquired an interstate natural gas liquids and refined petroleum products pipeline system and related assets from a subsidiary of Kinder Morgan for approximately $300 million, before working capital adjustments. Our
In April 2006, our ONEOK Partners segment received $297.0 million for the sale of a 20 percent partnership interest in Northern Border Pipeline in April 2006.Pipeline. Our Energy Services segment received $53.0 million for the sale of our discontinued component, Spring Creek, in October 2006.
Acquisitions in 2006 primarily relate to our ONEOK Partners segment acquiring the 66-2/3 percent interest in Guardian Pipeline not previously owned by ONEOK Partners for approximately $77 million. This purchase increased ONEOK Partners’ ownership interest to 100 percent. We also purchased from TransCanada its 17.5 percent general partner interest in ONEOK Partners for $40 million. This purchase resulted in our ownership of the entire 2 percent general partner interest in ONEOK Partners. Additionally, ONEOK Partners paid $11.6 million to Williams for a 99 percent interest in, and initial capital expenditures related to, the Overland Pass Pipeline Company natural gas liquids pipeline joint venture. Acquisitions in 2005 primarily represent the purchase of the natural gas liquids assets from Koch. The sale of our former production segment resulted in proceeds from the sale of a discontinued component. The proceeds from the sale of assets in 2005 primarily resulted from the sale of our natural gas gathering and processing assets located in Texas. Additionally, the sale of Cimarex Energy Company common stock, formerly Magnum Hunter Resources (MHR) common stock, is also included in proceeds from sale of assets. This common stock was acquired upon exercise of MHR stock purchase warrants in February 2005, resulting in our paying $22.7 million, which is included in other investing activities.
We had a decrease in short-term investments of $31.1 million between December 31, 2006, and December 31,for 2007, compared with a total investment of $31.1 million for 2006. During 2007, we had less cash to invest following our repurchase of 7.5 million shares of our outstanding common stock in June.
Investing cash flows for 2006 also include the impact of the deconsolidation of Northern Border Pipeline and consolidation of Guardian Pipeline.
Financing Cash Flows - Cash provided by financing activities was $73.0Net short-term borrowings were $2.1 billion for 2008, compared with $196.6 million for 2007, compared with cash2007. The increased short-term borrowings during 2008 were used to repay a portion of $402.3 million of maturing long-term debt. Short-term borrowings also increased as the result ONEOK’s and ONEOK Partners’ decision in financing activitieslate 2008 to borrow under their available credit facilities to fund their respective anticipated working capital requirements for the remainder of $618.82008 and into 2009, and ONEOK Partners’ capital projects.
During 2008, ONEOK Partners’ public sale of 2.6 million for 2006, and cash provided by financing activities of $694.9common units generated approximately $147 million, in 2005.after deducting underwriting discounts but before offering expenses.
In 2007, short-term financing was primarily used to fund ONEOK Partners’ capital projects. ONEOK Partners’ $598 million debt issuance, net of discounts, was used to repay borrowings under the ONEOK Partners Credit agreement and finance the $300 million acquisition of assets, before working capital adjustments, from a subsidiary of Kinder Morgan in October 2007.
In 2006, we repaid the remaining $900 million outstanding on our $1.0 billion short-term bridge financing agreement. During the second quarter of 2006, ONEOK Partners borrowed $1.05 billion under the ONEOK Partners Bridge Facilityits $1.1 billion 364-day credit facility dated April 6, 2006, (Bridge Facility) to finance a portion of the acquisition of the ONEOK Energy Assets and $77 million under the ONEOK Partners Credit Agreementits then existing credit agreement to acquire the 66-2/3 percent interest in Guardian Pipeline not previously owned by ONEOK Partners. During the third quarter of 2006, ONEOK Partners completed the underwritten public offering of senior notes totaling $1.4 billion in net proceeds, before offering expenses, which were used to repay all of the amounts outstanding of the $1.05 billion borrowed under the ONEOK Partners Bridge Facility and to repay $335 million of indebtedness outstanding under the ONEOK Partners Credit Agreement.its then existing credit agreement.
On February 16, 2006, we successfully settled our 16.1 million equity units to 19.5 million shares of our common stock. With the settlement of the equity units, we received $402.4 million in cash, which we used to repay a portion of our commercial paper. We repaid a total of $641.5 million of our commercial paper during 2006. See Note G of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional discussion regarding the equity unit conversion.
In March 2006, our ONEOK Partners segment borrowed $33 million under the ONEOK Partners Credit Agreementits then existing credit agreement to redeem all of the outstanding Viking Gas Transmission Series A, B, C and D senior notes and paid a redemption premium of $3.6 million. During 2005, we borrowed $1.0 billion under our short-term bridge financing agreement to assist in financing the acquisition of natural gas liquids assets from Koch. We funded the remaining acquisition cost through our commercial paper program. We reduced our indebtedness under our short-term bridge financing agreement by $100.0 million as a result of a required prepayment due to the sale of our former production segment.
In June 2005, we issued $800 million of long-term notes and used a portion of the proceeds to repay commercial paper. The commercial paper had been issued to finance the Northern Border Partners acquisition, to repay $335 million of long-term debt that matured on March 1, 2005, and to meet operating needs. This increase was partially offset by $643 million in payments on notes payable and commercial paper, which represents the cash received from the sale of our former production segment, and payments made in the normal course of operations.
In December 2005, we made an early redemption of our $300.0 million long-term notes. In addition to the principal payment, we were required to pay a make-whole call premium of $5.7 million and accrued interest of $8.7 million, for a total payment of $314.4 million. We funded this early redemption with the proceeds from the sale of our natural gas gathering and processing assets located in Texas.
During 2007, we paid $20.1 million for the settlement of the forward purchase contract related to our stock repurchase in February and approximately $370 million for our stock repurchase in June. We paid $281.4 million to repurchase shares in August 2006. During 2005, we paid $233.0 million to repurchase 7.5 million shares. All of these stock repurchases were pursuant to the plans approved by our Board of Directors.During 2007 and 2006, we paid $182.9 million and $165.3 million in distributions to minority interests, which primarily resulted from our consolidation of ONEOK Partners in accordance with EITF 04-5 as of January 1, 2006, and represents distributions to the unitholders of the 54.3 percent of ONEOK Partners that we do not own.
CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS
The following table sets forth our contractual obligations related to debt, operating leases and other long-term obligations as of December 31, 2007.2008. For furtheradditional discussion of the debt and operating lease agreements, see Notes I and K, respectively, of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K. | | | | | | | | | | | | | | | | | | | | | | | | | | | Payments Due by Period | | Contractual Obligations | | Total | | 2008 | | 2009 | | 2010 | | 2011 | | 2012 | | Thereafter | | | | ONEOK | | (Thousands of dollars) | | | Commercial paper | | $ | 102,600 | | $ | 102,600 | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | | | Long-term debt | | | 1,988,163 | | | 408,549 | | | 106,265 | | | 6,284 | | | 406,306 | | | 6,329 | | | 1,054,430 | | | Interest payments on debt | | | 1,174,600 | | | 96,900 | | | 86,300 | | | 87,000 | | | 67,700 | | | 59,800 | | | 776,900 | | | Operating leases | | | 457,739 | | | 120,994 | | | 94,038 | | | 74,355 | | | 75,077 | | | 37,619 | | | 55,656 | | | Building acquisition | | | 30,900 | | | 30,900 | | | - | | | - | | | - | | | - | | | - | | | Firm transportation contracts | | | 575,419 | | | 121,100 | | | 104,616 | | | 90,167 | | | 68,874 | | | 64,905 | | | 125,757 | | | Financial and physical derivatives | | | 657,511 | | | 576,696 | | | 64,596 | | | 16,000 | | | 109 | | | 110 | | | - | | | Pension plan | | | 127,214 | | | 3,080 | | | 19,580 | | | 34,955 | | | 39,086 | | | 30,513 | | | - | | | Other postretirement benefit plan | | | 92,668 | | | 16,682 | | | 17,191 | | | 18,454 | | | 19,655 | | | 20,686 | | | - | | | | | | $ | 5,206,814 | | $ | 1,477,501 | | $ | 492,586 | | $ | 327,215 | | $ | 676,807 | | $ | 219,962 | | $ | 2,012,743 | | | | | | | | | | | | | ONEOK Partners | | | | | | | | | | | | | | | | | $1 billion credit agreement | | $ | 100,000 | | $ | 100,000 | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | | | Long-term debt | | | 2,608,641 | | | 11,930 | | | 11,931 | | | 261,931 | | | 236,931 | | | 361,062 | | | 1,724,856 | | | Interest payments on debt | | | 2,789,800 | | | 177,600 | | | 176,700 | | | 163,700 | | | 140,000 | | | 120,200 | | | 2,011,600 | | | Operating leases | | | 37,629 | | | 7,309 | | | 2,394 | | | 1,355 | | | 1,232 | | | 1,071 | | | 24,268 | | | Firm transportation contracts | | | 26,820 | | | 11,881 | | | 11,260 | | | 3,679 | | | - | | | - | | | - | | | Financial and physical derivatives | | | 46,856 | | | 46,856 | | | - | | | - | | | - | | | - | | | - | | | Purchase commitments, rights-of-way and other | | | 58,366 | | | 52,971 | | | 935 | | | 935 | | | 935 | | | 935 | | | 1,655 | | | | | | $ | 5,668,112 | | $ | 408,547 | | $ | 203,220 | | $ | 431,600 | | $ | 379,098 | | $ | 483,268 | | $ | 3,762,379 | | | Total | | $ | 10,874,926 | | $ | 1,886,048 | | $ | 695,806 | | $ | 758,815 | | $ | 1,055,905 | | $ | 703,230 | | $ | 5,775,122 | | | | |
| | | Payments Due by Period | | | Contractual Obligations | | Total | | 2009 | | 2010 | | 2011 | | 2012 | | 2013 | | Thereafter | | | ONEOK | | (Thousands of dollars) | | | $1.2 billion credit agreement | | $ | 1,100,000 | | $ | 1,100,000 | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | | | $400 million credit agreement | | | 300,000 | | | 300,000 | | | - | | | - | | | - | | | - | | | - | | | Long-term debt | | | 1,584,053 | | | 106,265 | | | 6,284 | | | 406,306 | | | 6,329 | | | 6,205 | | | 1,052,664 | | | Interest payments on debt | | | 1,100,500 | | | 92,100 | | | 91,400 | | | 70,900 | | | 62,100 | | | 61,700 | | | 722,300 | | | Operating leases | | | 300,795 | | | 88,837 | | | 55,888 | | | 61,232 | | | 32,943 | | | 25,376 | | | 36,519 | | | Firm transportation contracts | | | 552,509 | | | 123,352 | | | 103,157 | | | 81,833 | | | 80,389 | | | 57,249 | | | 106,529 | | | Financial and physical derivatives | | | 927,635 | | | 816,319 | | | 97,225 | | | 13,623 | | | 468 | | | - | | | - | | | Employee benefit plans | | | 42,602 | | | 42,602 | | | - | | | - | | | - | | | - | | | - | | | Other | | | 850 | | | 567 | | | 283 | | | - | | | - | | | - | | | - | | | | | $ | 5,908,944 | | $ | 2,670,042 | | $ | 354,237 | | $ | 633,894 | | $ | 182,229 | | $ | 150,530 | | $ | 1,918,012 | | | | | | | | | | | | | | | | | | | | | | | | | | | ONEOK Partners | | | | | | | | | | | | | | | | | | | | | | | | $1 billion credit agreement | | $ | 870,000 | | $ | 870,000 | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | | | Long-term debt | | | 2,596,711 | | | 11,931 | | | 261,931 | | | 236,931 | | | 361,062 | | | 7,650 | | | 1,717,206 | | | Interest payments on debt | | | 2,686,400 | | | 176,700 | | | 163,700 | | | 140,000 | | | 120,200 | | | 114,300 | | | 1,971,500 | | | Operating leases | | | 86,508 | | | 18,362 | | | 16,027 | | | 15,527 | | | 8,755 | | | 2,063 | | | 25,774 | | | Firm transportation contracts | | | 14,765 | | | 11,086 | | | 3,679 | | | - | | | - | | | - | | | - | | | Financial and physical derivatives | | | 48,467 | | | 48,467 | | | - | | | - | | | - | | | - | | | - | | | Purchase commitments, | | | | | | | | | | | | | | | | | | | | | | | | rights-of-way and other | | | 35,582 | | | 30,914 | | | 977 | | | 976 | | | 977 | | | 977 | | | 761 | | | | | $ | 6,338,433 | | $ | 1,167,460 | | $ | 446,314 | | $ | 393,434 | | $ | 490,994 | | $ | 124,990 | | $ | 3,715,241 | | | Total | | $ | 12,247,377 | | $ | 3,837,502 | | $ | 800,551 | | $ | 1,027,328 | | $ | 673,223 | | $ | 275,520 | | $ | 5,633,253 | |
Long-term Debt - Long-term debt as reported in our Consolidated Balance Sheets includes unamortized debt discount and the mark-to-market effect of interest-rate swaps.
Interest Payments on Debt - Interest expense is calculated by multiplying long-term debt by the respective coupon rates, adjusted for active swaps.
Operating Leases - Our operating leases include a natural gas processing plant, storage contracts, office space, pipeline equipment, rights-of-wayrights of way and vehicles. Operating leaseslease obligations for ONEOK Partners exclude intercompany payments related to the lease of a gas processing plant. In July 2007, ONEOK Leasing Company gave notice of its intent to exercise its option to purchase ONEOK Plaza on or before the end of the current lease term, set to expire on September 30, 2009. In addition, ONEOK Leasing Company has entered into a purchase agreement with the owner of ONEOK Plaza that, if certain conditions are met, would accelerate the purchase of the building to a date on or before March 31, 2008. The total purchase price of approximately $48 million would include $17.1 million for the present value of the lease payments and the $30.9 million base purchase price. These amounts are included in the 2008 column above.
Firm Transportation Contracts - Our ONEOK Partners, Distribution and Energy Services segments are party to fixed-price transportation contracts. However, the costs associated with our Distribution segment’s contracts are recovered through rates as allowed by the applicable regulatory agency and are excluded from the table above. Firm transportation agreements with our ONEOK Partners segment’s natural gas gathering and processing joint-venturesjoint ventures require minimum monthly payments.
Financial and Physical Derivatives - These are obligations arising from our ONEOK Partners and Energy Services segment’ssegments’ physical and financial derivatives for fixed-price purchase commitments and are based on market information at December 31, 2007.2008. Not included in these amounts are offsetting cash inflows from our Energy Services segment’s product sales and net positive settlements of $865 million at December 31, 2007.settlements. As market information changes daily and is potentially volatile, these values may change significantly. Additionally, product sales may require additional purchase obligations to fulfill sales obligations that are not reflected in these amounts.
Employee Benefit Plans - No payment amounts are provided forEmployee benefit plans include our minimum required contribution to our pension and other postretirement benefit plans for 2009. See Note J of the Notes to Consolidated Financial Statements in the “Thereafter” column since there is no termination datethis Annual Report on Form 10-K for thesediscussion of our employee benefit plans.
Purchase Commitments - - Purchase commitments include purchasescommitments related to ONEOK Partners’ growth capital expenditures and other rightrights of way commitments. Purchase commitments exclude commodity purchase contracts, which are included in the “Financial and physical derivatives” amounts.
FORWARD-LOOKING STATEMENTS
Some of the statements contained and incorporated in this Annual Report on Form 10-K are forward-looking statements within the meaning of Section 27A of the Private Securities Litigation Reform Act of 1995.1933, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended. The forward-looking statements relate to our anticipated financial performance, management’s plans and objectives for our future operations, our business prospects, the outcome of regulatory and legal proceedings, market conditions and other matters. TheWe make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995 provides a safe harbor for forward-looking statements in certain circumstances.1995. 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 our operations and other statements contained or incorporated in this Annual Report on Form 10-K identified by words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should,” “goal,” “forecast”“forecast,” “could,” “may,” “continue,” “might,” “potential,” “scheduled,” and other words and terms of similar meaning.
You should not place undue reliance on 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 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: | · | the effects of weather and other natural phenomena on our operations, including energy sales and demand for our services and energy prices; |
| · | competition from other United States and Canadian energy suppliers and transporters as well as alternative forms of energy, including, but not limited to, biofuels such as ethanol and biodiesel; |
| · | the status of deregulation of retail natural gas distribution; |
| · | the capital intensive nature of our businesses; |
| · | the profitability of assets or businesses acquired or constructed by us; |
| · | our ability to make cost-saving changes in operations; |
| · | risks of marketing, trading and hedging activities, including the risks of changes in energy prices or the financial condition of our counterparties; |
| · | the uncertainty of estimates, including accruals and costs of environmental remediation; |
| · | the timing and extent of changes in energy commodity prices; |
| · | the effects of changes in governmental policies and regulatory actions, including changes with respect to income and other taxes, environmental compliance, climate change initiatives, and authorized rates or recovery of gas and gas transportation costs; |
| · | the impact on drilling and production by factors beyond our control, including the demand for natural gas and refinery-grade crude oil; producers’ desire and ability to obtain necessary permits; reserve performance; and capacity constraints on the pipelines that transport crude oil, natural gas and NGLs from producing areas and our facilities; |
| · | changes in demand for the use of natural gas because of market conditions caused by concerns about global warming; |
| · | 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; |
| · | our indebtedness could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds, and/or place us at competitive disadvantages compared to our competitors that have less debt, or have other adverse consequences; |
| · | actions by rating agencies concerning the credit ratings of ONEOK and ONEOK Partners; |
competition from other United States and Canadian energy suppliers and transporters as well as alternative forms of energy;
the capital intensive nature of our businesses;
the profitability of assets or businesses acquired by us;
risks of marketing, trading and hedging activities, including the risks of changes in energy prices or the financial condition of our counterparties;
the uncertainty of estimates, including accruals and costs of environmental remediation;
the timing and extent of changes in energy commodity prices;
the effects of changes in governmental policies and regulatory actions, including changes with respect to income and other taxes, environmental compliance, and authorized rates or recovery of gas and gas transportation costs;
impact on drilling and production by factors beyond our control, including the demand for natural gas and refinery-grade crude oil; producers’ desire and ability to obtain necessary permits; reserve performance; and capacity constraints on the pipelines that transport crude oil, natural gas and NGLs from producing areas and our facilities;
changes in demand for the use of natural gas because of market conditions caused by concerns about global warming or changes in governmental policies and regulations due to climate change initiatives;
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;
actions by rating agencies concerning the credit ratings of ONEOK and ONEOK Partners;
the results of administrative proceedings and litigation, regulatory actions and receipt of expected clearances involving the OCC, KCC, Texas regulatory authorities or any other local, state or federal regulatory body, including the FERC;
our ability to access capital at competitive rates or on terms acceptable to us;
risks associated with adequate supply to our gathering, processing, fractionation and pipeline facilities, including production declines which outpace new drilling;
the risk that material weaknesses or significant deficiencies in our internal controls over financial reporting could emerge or that minor problems could become significant;
the impact and outcome of pending and future litigation;
the ability to market pipeline capacity on favorable terms, including the affects of:
| · | the results of administrative proceedings and litigation, regulatory actions and receipt of expected clearances involving the OCC, KCC, Texas regulatory authorities or any other local, state or federal regulatory body, including the FERC; |
| · | our ability to access capital at competitive rates or on terms acceptable to us; |
| · | risks associated with adequate supply to our gathering, processing, fractionation and pipeline facilities, including production declines that outpace new drilling; |
| · | the risk that material weaknesses or significant deficiencies in our internal controls over financial reporting could emerge or that minor problems could become significant; |
| · | the impact and outcome of pending and future litigation; |
| · | the ability to market pipeline capacity on favorable terms, including the effects of: |
| - | future demand for and prices of natural gas and NGLs; |
| - | competitive conditions in the overall energy market; |
| - | availability of supplies of Canadian and United States natural gas; and |
| - | availability of additional storage capacity; |
| · | -performance of contractual obligations by our customers, service providers, contractors and shippers; |
| · | weather conditions;the timely receipt of approval by applicable governmental entities for construction and operation of our pipeline and other projects and required regulatory clearances; |
| · | our ability to acquire all necessary permits, consents or other approvals in a timely manner, to promptly obtain all necessary materials and supplies required for construction, and to construct gathering, processing, storage, fractionation and transportation facilities without labor or contractor problems; |
| · | the mechanical integrity of facilities operated; |
| · | demand for our services in the proximity of our facilities; |
| · | our ability to control operating costs; |
| · | adverse labor relations; |
| · | acts of nature, sabotage, terrorism or other similar acts that cause damage to our facilities or our suppliers’ or shippers’ facilities; |
| · | economic climate and growth in the geographic areas in which we do business; |
| · | the risk of a prolonged slowdown in growth or decline in the United States economy or the risk of delay in growth recovery in the United States economy, including increasing liquidity risks in United States credit markets; |
| · | 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 conditions in the Middle East and elsewhere; |
| · | the risk of increased costs for insurance premiums, security or other items as a consequence of terrorist attacks; |
| · | risks associated with pending or possible acquisitions and dispositions, including our ability to finance or integrate any such acquisitions and any regulatory delay or conditions imposed by regulatory bodies in connection with any such acquisitions and dispositions; |
| · | the possible loss of gas distribution franchises or other adverse effects caused by the actions of municipalities; |
| · | the impact of unsold pipeline capacity being greater or less than expected; |
| · | the ability to recover operating costs and amounts equivalent to income taxes, costs of property, plant and equipment and regulatory assets in our state and FERC-regulated rates; |
| · | the composition and quality of the natural gas and NGLs we gather and process in our plants and transport on our pipelines; |
| · | the efficiency of our plants in processing natural gas and extracting and fractionating NGLs; |
| · | the impact of potential impairment charges; |
| · | the risk inherent in the use of information systems in our respective businesses, implementation of new software and hardware, and the impact on the timeliness of information for financial reporting; |
| · | our ability to control construction costs and completion schedules of our pipelines and other projects; and |
| · | - | competitive developmentsthe risk factors listed in the reports we have filed and may file with the SEC, which are incorporated by Canadian and U.S. natural gas transmission peers;reference. |
performance of contractual obligations by our customers, service providers, contractors and shippers;
the timely receipt of approval by applicable governmental entities for construction and operation of our pipeline and other projects and required regulatory clearances;
our ability to acquire all necessary rights-of-way permits and consents in a timely manner, to promptly obtain all necessary materials and supplies required for construction, and to construct pipelines without labor or contractor problems;
the mechanical integrity of facilities operated;
demand for our services in the proximity of our facilities;
our ability to control operating costs;
acts of nature, sabotage, terrorism or other similar acts that cause damage to our facilities or our suppliers’ or shippers’ facilities;
economic climate and growth in the geographic areas in which we do business;
the risk of a significant slowdown in growth or decline in the U.S. economy or the risk of delay in growth recovery in the U.S. economy;
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 conditions in the Middle East and elsewhere;
the risk of increased costs for insurance premiums, security or other items as a consequence of terrorist attacks;
risks associated with pending or possible acquisitions and dispositions, including our ability to finance or integrate any such acquisitions and any regulatory delay or conditions imposed by regulatory bodies in connection with any such acquisitions and dispositions;
the possible loss of gas distribution franchises or other adverse effects caused by the actions of municipalities;
the impact of unsold pipeline capacity being greater or less than expected;
the ability to recover operating costs and amounts equivalent to income taxes, costs of property, plant and equipment and regulatory assets in our state and FERC-regulated rates;
our ability to promptly obtain all necessary materials and supplies required for construction of gathering, processing, storage, fractionation and transportation facilities;
the composition and quality of the natural gas and NGLs we gather and process in our plants and transport on our pipelines;
the efficiency of our plants in processing natural gas and extracting and fractionating NGLs;
the impact of potential impairment charges;
the risk inherent in the use of information systems in our respective businesses, implementation of new software and hardware, and the impact on the timeliness of information for financial reporting;
our ability to control construction costs and completion schedules of our pipelines and other projects; and
the risk factors listed in the reports we have filed and may file with the SEC, which are incorporated by reference.
These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other factors could also have material adverse effects on our future results. These and other risks are described in greater detail in Item 1A, Risk Factors, in this Annual Report on Form 10-K. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. Other than as required under securities laws, we undertake no obligation to update publicly any forward-looking statement whether as a result of new information, subsequent events or change in circumstances, expectations or otherwise.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
| QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
Risk Policy and Oversight - We control the scope of risk management, marketing and trading operations through a comprehensive set of policies and procedures involving senior levels of management. The Audit Committee of our Board of Directors has oversight responsibilities for our risk management limits and policies. Our risk oversight committee, comprised of corporate and business segment officers, oversees all activities related to commodity price and credit risk management, and marketing and trading activities. The committee also monitors risk metrics including value-at-risk (VAR) and mark-to-market losses. We have a corporate risk control organization led by our vice president of audit, business development and risk control, whogroup that is assigned responsibility for establishing and enforcing the policies and procedures and monitoring certain risk metrics. Key risk control activities include credit review and approval, credit and performance risk measurement and monitoring, validation of transactions, portfolio valuation, VAR and other risk metrics. COMMODITY PRICE RISK
Our exposure to market risk discussed below includes forward-looking statements and represents an estimate of possible changes in future earnings that would occur assuming hypothetical future movements in interest rates or commodity prices. Our views on market risk are not necessarily indicative of actual results that may occur and do not represent the maximum possible gains and losses that may occur since actual gains and losses will differ from those estimated based on actual fluctuations in interest rates or commodity prices and the timing of transactions.
COMMODITY PRICE RISK
We are exposed to marketcommodity price risk and the impact of market price fluctuations of natural gas, NGLs and crude oil prices. MarketCommodity price risk refers to the risk of loss in cash flows and future earnings arising from adverse changes in commodity energy prices. To minimize the risk from market price fluctuations of natural gas, NGLs and crude oil, we use commodity derivative instruments such as futures, physical forward contracts, swaps and options to manage marketcommodity price risk ofassociated with existing or anticipated purchase and sale agreements, existing physical natural gas in storage, and basis risk. We adhere to policies and procedures that limit our exposure to market risk from open positions and that monitor our market risk exposure.
ONEOK Partners ONEOK Partners is exposed to commodity price risk as its natural gas interstate and intrastate pipelines collect natural gas from its customers for operations or as part of their fee for services provided. When the amount of natural gas consumed in operations by these pipelines differs from the amount provided by its customers, the pipelines must buy or sell natural gas, store or use natural gas from inventory, and are exposed to commodity price risk. At December 31, 2007, there were no hedges in place with respect to natural gas price risk from ONEOK Partners’ natural gas pipeline business.
In addition,
ONEOK Partners is exposed to commodity price risk, primarily as a result of NGLs in storage, spread risk associated with the relative values of the various components of the NGL stream and the relative value of NGL purchases at one location and sales at another location, known as basis risk. ONEOK Partners has not entered into any hedges with respect to its NGL marketing activities.ONEOK Partners is also exposed to commodity price risk, primarily NGLs, as a result of receiving commodities in exchange for its gathering and processing services. To a lesser extent, ONEOK Partners is exposed to the relative price differential between NGLs and natural gas, or the gross processing spread, with respect to its keep-whole processing contracts andcontracts. ONEOK Partners is also exposed to the risk of price fluctuations and the cost of intervening transportation at various market locations. As part of ONEOK Partners’ hedging strategy, ONEOK Partners uses commodity fixed-price physical forwards and derivative contracts, including NYMEX-based futures and over-the-counter swaps, to minimize earnings volatility in its natural gas gathering and processing business related to natural gas, NGL and condensate price fluctuations.
ONEOK Partners reduces its gross processing spread exposure through a combination of physical and financial hedges. ONEOK Partners utilizes a portion of its POPpercent-of-proceeds equity natural gas as an offset, or natural hedge, to an equivalent portion of its keep-whole shrink requirements. This has the effect of converting ONEOK Partners’ gross processing spread risk to NGL commodity price risk, and ONEOK Partners then uses financial instruments to hedge the sale of NGLs.
The following table sets forth ONEOK Partners’ hedging information for the year ending December 31, 2008. | | | | | | | | | | | | | | | | Year Ending December 31, 2008 | | | | Volumes
Hedged | | Average Price Per Unit | | | Volumes
Hedged | | | | Natural gas liquids(Bbl/d) (a) | | 8,085 | | $ 1.28 | | ($/gallon | ) | | 70 | % | | | Condensate(Bbl/d) (a) | | 818 | | $ 2.15 | | ($/gallon | ) | | 74 | % | | | Total liquid sales(Bbl/d) | | 8,903 | | $ 1.36 | | ($/gallon | ) | | 71 | % | | | (a) - Hedged with fixed-price swaps. | | | | | | | | | | | | |
2009.
| | Year Ending December 31, 2009 | | | Volumes Hedged | | | Average Price | Percentage Hedged | NGLs (Bbl/d) (a) | 5,010 | | | $ | 1.18 | / gallon | 57% | Condensate (Bbl/d) (a) | 666 | | | $ | 3.23 | / gallon | 32% | Total liquid sales (Bbl/d) | 5,676 | | | $ | 1.42 | / gallon | 52% | | (a) - Hedged with fixed-price swaps. | | | | | | | |
ONEOK Partners’ commodity price risk is estimated as a hypothetical change in the price of NGLs, crude oil and natural gas at December 31, 2007,2008, excluding the effects of hedging and assuming normal operating conditions. ONEOK Partners’ condensate sales are based on the price of crude oil. ONEOK Partners estimates the following: a $0.01 per gallon increase in the composite price of NGLs would increase annual net margin by approximately $1.7 million,
a $1.00 per barrel increase in the price of crude oil would increase annual net margin by approximately $0.5 million, and
| · | a $0.01 per gallon decrease in the composite price of NGLs would decrease annual net margin by approximately $1.2 million; |
a $0.10 per MMBtu increase in the price of natural gas would increase annual net margin by approximately $0.3 million.
| · | a $1.00 per barrel decrease in the price of crude oil would decrease annual net margin by approximately $1.0 million; and |
| · | a $0.10 per MMBtu decrease in the price of natural gas would decrease annual net margin by approximately $0.6 million. |
The above estimates of commodity price risk do not include any effects on demand for its services that might be caused by, or arise in conjunction with, price changes. For example, a change in the gross processing spread may cause a change in the amount of ethane to be sold inextracted from the natural gas stream, impacting gathering and processing margins, NGL exchange margins,revenues, natural gas deliveries, and NGL volumes shipped.shipped and fractionated.
ONEOK Partners is also exposed to commodity price risk primarily as a result of NGLs in storage, the relative values of the various NGL products to each other, the relative value of NGLs to natural gas and the relative value of NGL purchases at one location and sales at another location, known as basis risk. ONEOK Partners utilizes fixed-price physical forward contracts to reduce earnings volatility related to NGL price fluctuations. ONEOK Partners has not entered into any financial instruments with respect to its NGL marketing activities.
In addition, ONEOK Partners is exposed to commodity price risk as its natural gas interstate and intrastate pipelines collect natural gas from its customers for operations or as part of its fee for services provided. When the amount of natural gas consumed in operations by these pipelines differs from the amount provided by its customers, the pipelines must buy or sell natural gas, or store or use natural gas from inventory, which exposes ONEOK Partners to commodity price risk. At December 31, 2008, there were no hedges in place with respect to natural gas price risk from ONEOK Partners’ natural gas pipeline business.
Our Distribution segment uses derivative instruments to hedge the cost of anticipated natural gas purchases during the winter heating months to protect their customers from upward volatility in the market price of natural gas. Gains or losses associated with these derivative instruments are included in, and recoverable through, the monthly purchased gas cost mechanism.
Our Energy Services segment is exposed to commodity price risk, including basis risk and price volatility arising from natural gas in storage, requirement contracts, asset management contracts and index-based purchases and sales of natural gas at various market locations. We minimize the volatility of our exposure to commodity price risk through the use of derivative instruments, which, under certain circumstances, are designated as cash flow or fair value hedges. We are also exposed to commodity price risk from fixed pricefixed-price purchases and sales of natural gas, which we hedge with derivative instruments. Both the fixed pricefixed-price purchases and sales and related derivatives are recorded at fair value.
Fair Value Component of the Energy Marketing and Risk Management Assets and Liabilities - The following table sets forth the fair value component of the energy marketing and risk management assets and liabilities, excluding $3.5$21.0 million of net ofliabilities from derivative instruments that have been declared as either fair value or cash flow hedges, and $15.7 million, nethedges. | Fair Value Component of Energy Marketing and Risk Management Assets and Liabilities | | | | | (Thousands of dollars) | | Net fair value of derivatives outstanding at December 31, 2007 | | | $ | 25,171 | | | | Derivatives reclassified or otherwise settled during the period | | | | (55,874 | ) | | | Fair value of new derivatives entered into during the period | | | | 236,772 | | | | Other changes in fair value | | | | 52,731 | | | | Net fair value of derivatives outstanding at December 31, 2008 (a) | | | $ | 258,800 | | | | | | | | | | | (a) - The maturities of derivatives are based on injection and withdrawal periods from April through March, which is consistent with our business strategy. The maturities are as follows: $225.0 million matures through March 2009, $33.9 million matures through March 2012 and $(0.1) million matures through March 2014. | | |
Table of deferred option premiums.Contents | | | | | | | Fair Value Component of Energy Marketing and Risk Management Assets and Liabilities | | | | (Thousands of dollars) | | | | Net fair value of derivatives outstanding at December 31, 2006 | | $ | (13,133 | ) | | | Derivatives realized or otherwise settled during the period | | | 27,251 | | | | Fair value of new derivatives entered into during the period | | | 8,287 | | | | Other changes in fair value | | | 2,766 | | | | Net fair value of derivatives outstanding at December 31, 2007 | | $ | 25,171 | | | | | |
The change in the net fair value of derivatives outstanding includes the effect of settled energy contracts and current period changes resulting primarily from newly originated transactions and the impact of market movements on the fair value of energy marketing and risk management assets and liabilities. Fair value estimates considerof new derivatives entered into during the marketperiod includes $298.8 million of cash flow hedges reclassified into earnings from accumulated other comprehensive income (loss) related to the write-down of our natural gas in which the transactions are executed. The market in which exchange traded and over-the-counter transactions are executed is a factor in determining fairvalue. We utilize third-party references for pricing points from NYMEX and third-party over-the-counter brokersstorage to establish the commodity pricing and volatility curves. We believe the reported transactions from these sources are the most reflectiveits lower of current market prices. Fair values are subject to change based on valuation factors. The estimateweighted-average cost or market.
For further discussion of fair value includes an adjustment for the liquidation of the position in an orderly manner over a reasonable period of time under current market conditions. The fair value estimate also considers the risk of nonperformance based on credit considerations of the counterparty.Maturity of Derivatives - The following table provides details of our Energy Services segment’s maturity of derivatives based on injectionmeasurements and withdrawal periods from April through March. This maturity schedule is consistent with our business strategy. Derivative instruments that have been declared as either fair value or cash flow hedges are not included in the following table.
| | | | | | | | | | | | | | | | | | | | | | Fair Value of Derivatives at December 31, 2007 | | Source of Fair Value (a) | | Matures
through
March 2008 | | | Matures
through
March 2011 | | | Matures
through
March 2013 | | | Total Fair
Value | | | | | | | (Thousands of dollars) | | | | Prices actively quoted (b) | | $ | (2,602 | ) | | $ | (40 | ) | | $ | - | | | $ | (2,642 | ) | | | Prices provided by other external sources (c) | | | (15,693 | ) | | | (11,337 | ) | | | (110 | ) | | | (27,140 | ) | | | Prices derived from quotes, other external sources and other assumptions (d) | | | 37,132 | | | | 17,858 | | | | (37 | ) | | | 54,953 | | | | Total | | $ | 18,837 | | | $ | 6,481 | | | $ | (147 | ) | | $ | 25,171 | | | | | |
(a) | Fair value is the mark-to-market component of forwards, futures, swaps and options, net of applicable reserves. These fair values are reflected as a component of assets and liabilities from energy marketing and risk management activities in our Consolidated Balance Sheets. |
(b) | Values are derived from the energy market price quotes from national commodity trading exchanges that primarily trade futures and option commodity contracts. |
(c) | Values are obtained through energy commodity brokers or electronic trading platforms, whose primary service is to match willing buyers and sellers of energy commodities. Energy price information by location is readily available because of the large energy broker network. |
(d) | 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 and Estimates” section of Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation in this Annual Report on Form 10-K.Operation. Also, see NoteNotes C and D of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Value-at-Risk (VAR) Disclosure of MarketCommodity Price Risk - We measure marketcommodity price risk in the energy marketing and risk management, trading and non-trading portfolios of our Energy Services segment using a VAR methodology, which estimates the expected maximum loss of theour portfolio over a specified time horizon within a given confidence interval. Our VAR calculations are based on the Monte Carlo approach. The quantification of marketcommodity price risk using VAR provides a consistent measure of risk across diverse energy markets and products with different risk factors in order to set overall risk tolerance and to determine risk targets and set position limits.thresholds. The use of this methodology requires a number of key assumptions, including the selection of a confidence level and the holding period to liquidation. Inputs to the calculation include prices, volatilities, positions, instrument valuations and the variance-covariance matrix. Historical data is used to estimate our VAR with more weight given to recent data, which is considered a more relevant predictor of immediate future commodity market movements. We rely on VAR to determine the potential reduction in the portfolio values arising from changes in market conditions over a defined period. While management believes that the referenced assumptions and approximations are reasonable, no uniform industry methodology exists for estimating VAR. Different assumptions and approximations could produce materially different VAR estimates.
Our VAR exposure represents an estimate of potential losses that would be recognized fordue to adverse commodity price movements in our non-regulated businesses’ energy marketing and risk management, non-trading and trading portfoliosEnergy Services segment’s portfolio of derivative financial instruments, physical commodity contracts, leased transport, storage capacity contracts and natural gas in storage due to adverse market movements.storage. A one-day time horizon and a 95 percent confidence level wereare used in our VAR data. Actual future gains and losses will differ from those estimated by the VAR calculation based on actual fluctuations in commodity prices, operating exposures and timing thereof, and the changes in our derivative financial instruments, physical contracts and natural gas in storage. VAR information should be evaluated in light of these assumptions and the methodology’s other limitations.
The potential impact on our future earnings, as measured by the VAR, was $6.0$7.9 million and $12.5$6.0 million at December 31, 20072008 and 2006,2007, respectively. The following table details the average, high and low VAR calculations for the periods indicated. | | | | | | | | | | | | Years Ended December 31, | | | | 2007 | | 2006 | | | | | | (Millions of dollars) | | | Average | | $ | 8.9 | | $ | 18.5 | | | High | | $ | 23.0 | | $ | 65.0 | | | Low | | $ | 3.4 | | $ | 3.6 | | |
| | Years Ended December 31, | | Value-at-Risk | | 2008 | | | 2007 | | | | (Millions of dollars) | | Average | | $ | 12.3 | | | $ | 8.9 | | | High | | $ | 24.9 | | | $ | 23.0 | | | Low | | $ | 4.0 | | | $ | 3.4 | |
Our VAR calculation includes derivatives, executory storage and transportation agreements and their related hedges. The variations in the VAR data are reflective of market volatility and changes in the portfoliosour portfolio during the year. The decreaseincrease in average VAR for 2007,2008, compared with 2006,2007, was primarily due to lower commoditya significant increase in natural gas prices and decreasedduring the second quarter of 2008.
Our VAR calculation uses historical prices, placing more emphasis on the most recent price volatility in 2007, particularlymovements. We revised our assumptions in the firstthird quarter of 2007.2008 to decrease the weight given to the most recent price changes and spread the relative weighting over more historical data. This methodology reduces the effects of the market anomalies and better reflects an efficient market. We believe this methodology is more reflective of portfolio risk and have applied the change on a prospective basis.
During 2008, we also began calculating the VAR on our mark-to-market derivative positions, which reflects the risk associated with derivatives whose change in fair value will impact current period earnings. These transactions are subject to mark-to-market accounting treatment because they are not part of a hedging relationship under Statement 133. VAR associated with these derivative positions was not material during 2008. To the extent open commodity positions exist, fluctuating commodity prices can impact our financial results and financial position either favorably or unfavorably. As a result, we cannot predict with precision the impact risk management decisions may have on the business, operating results or financial position. INTEREST RATE RISK
GeneralGeneral - We are subject to the risk of interest-rate fluctuation in the normal course of business. We manage interest-rate risk through the use of fixed-rate debt, floating-rate debt and, at times, interest-rate swaps. Fixed-rate swaps are used to reduce our risk of increased interest costs during periods of rising interest rates. Floating-rate swaps are used to convert the fixed rates of long-term borrowings into short-term variable rates. At December 31, 2007,2008, the interest rate on 82.989.3 percent of our long-term debt, exclusive of the debt of our ONEOK Partners segment, was fixed after considering the impact of interest-rate swaps.
ONEOK Partners terminated two floating-rate swaps in 2007. The total value ONEOK Partners received for the terminated swaps was not material. At December 31, 2007,2008, the interest rate on all of ONEOK Partners’ long-term debt was fixed.
We terminated a $100 million interest-rate swap in the fourth quarter of 2008. The total value we received was $19.2 million, which includes $0.3 million of swap savings previously recorded. The remaining savings of $18.9 million will be recognized in interest expense over the remaining term of the debt instrument originally hedged.
In the fourth quarter of 2008, our counterparties exercised the option to terminate two additional interest-rate swap agreements totaling $140 million. The swap terminations were effective in December 2008 and January 2009. The total value we received for the terminated swaps was not material.
At December 31, 2007,2008, a 100 basis point move in the annual interest rate on all of our outstandingswapped long-term debt would change our annual interest expense by $3.4$1.7 million before taxes. This 100 basis point change assumes a parallel shift in the yield curve. If interest rates changed significantly, we would take actions to manage our exposure to the change. Since a specific action and the possible effects are uncertain, no change has been assumed.
Fair Value Hedges - See Note D of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for discussion of the impact of interest-rate swaps and net interest expense savings from terminated swaps.
Total net swap savings for 20072008 were $8.2$17.4 million, compared with $7.6$8.2 million for 2006.2007. Total swap savings for 2008 is2009 are expected to be $14.3$10.5 million.
CURRENCY EXCHANGE RATE RISK
As a result of our Energy Services segment’s expansion intooperations in Canada, we are subjectexposed to currency exposureexchange rate risk from our commodity purchases and sales related to our firm transportation and storage contracts. Our objective with respect to currency risk is toTo reduce theour exposure due to exchange-rate fluctuations. Wefluctuations, 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 December 31, 20072008 and 2006,2007, our exposure to risk from currency translation was not material. We recognized a currency translation loss of $3.1 million during 2008 and currency translation gains of $4.1 million and $2.5 million during 2007 and 2006, respectively. At December 31, 2005, there was no material currency translation gain or loss recorded.
COUNTERPARTY CREDIT RISK
ONEOK and ONEOK Partners assess the creditworthiness of their counterparties on an on going basis and require security, including prepayments and other forms of cash collateral, when appropriate.
| FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders
In our opinion, the accompanying consolidated balance sheetsheets and the related consolidated statementstatements of income, shareholders'shareholders’ equity and comprehensive income and cash flows present fairly, in all material respects, the financial position of ONEOK, Inc. and its subsidiaries (the Company) at December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the yeartwo years in the period ended December 31, 2007,2008, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007,2008, based on criteria established inInternal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company'sCompany’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management'sManagement’s Report on Internal Control over Financial Reporting appearing under Item 9A in the Company'sCompany’s Form 10-K for the year ended December 31, 2007.2008. Our responsibility is to express opinions on these financial statements and on the Company'sCompany’s internal control over financial reporting based on our integrated audit.audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our auditaudits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
February 27, 200824, 2009
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders
We have audited the accompanying consolidated balance sheetstatement of income, cash flows, and shareholders’ equity and comprehensive income of ONEOK, Inc. and subsidiaries as of December 31, 2006, and the related consolidated statements of income, shareholders’ equity and comprehensive income, and cash flows for each of the years in the two-year period ended December 31, 2006. TheseThe consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.audit.
We conducted our auditsaudit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provideaudit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial positionresults of operations and cash flows of ONEOK, Inc. and subsidiaries as of December 31, 2006, andfor the results of their operations and their cash flows for each of the years in the two-year periodyear ended December 31, 2006, in conformity with U.S. generally accepted accounting principles.
As discussed in Note A of Notes to the Consolidated Financial Statements, the Company adopted the provisions of Statement of Financial Accounting Standards (SFAS) No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” Emerging Issues Task Force Issue 04-5, “Determining Whether a General Partner, or General Partners as a Group Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights,” and SFAS No. 123R, “Share-Based Payment.”
| ONEOK, Inc. and Subsidiaries | | | | | | | | | | | CONSOLIDATED STATEMENTS OF INCOME | | | | | | | | | | | | | Years Ended December 31, | | | | | 2008 | | | 2007 | | | 2006 | | | | (Thousands of dollars, except per share amounts) | | | | | | | | | | | | | Revenues | | $ | 16,157,433 | | | $ | 13,477,414 | | | $ | 11,920,326 | | Cost of sales and fuel | | | 14,221,906 | | | | 11,667,306 | | | | 10,198,342 | | | Net Margin | | | 1,935,527 | | | | 1,810,108 | | | | 1,721,984 | | | Operating Expenses | | | | | | | | | | | | | | Operations and maintenance | | | 694,597 | | | | 675,575 | | | | 662,681 | | | Depreciation and amortization | | | 243,927 | | | | 227,964 | | | | 235,543 | | | General taxes | | | 82,315 | | | | 85,935 | | | | 78,086 | | | Total Operating Expenses | | | 1,020,839 | | | | 989,474 | | | | 976,310 | | | Gain (Loss) on Sale of Assets | | | 2,316 | | | | 1,909 | | | | 116,528 | | | Operating Income | | | 917,004 | | | | 822,543 | | | | 862,202 | | | Equity earnings from investments (Note O) | | | 101,432 | | | | 89,908 | | | | 95,883 | | | Allowance for equity funds used during construction | | | 50,906 | | | | 12,538 | | | | 2,205 | | | Other income | | | 16,838 | | | | 21,932 | | | | 26,030 | | | Other expense | | | (27,475 | ) | | | (7,879 | ) | | | (24,154 | ) | | Interest expense | | | (264,167 | ) | | | (256,325 | ) | | | (239,725 | ) | | Income before Minority Interests and Income Taxes | | | 794,538 | | | | 682,717 | | | | 722,441 | | | Minority interests in income of consolidated subsidiaries | | | (288,558 | ) | | | (193,199 | ) | | | (222,000 | ) | | Income taxes (Note L) | | | (194,071 | ) | | | (184,597 | ) | | | (193,764 | ) | | Income from Continuing Operations | | | 311,909 | | | | 304,921 | | | | 306,677 | | | Gain (Loss) from operations of discontinued components, net of tax | | | - | | | | - | | | | (365 | ) | | Net Income | | $ | 311,909 | | | $ | 304,921 | | | $ | 306,312 | | | | | | | | | | | | | | | | | Earnings Per Share of Common Stock (Note P) | | | | | | | | | | | | | | Net Earnings Per Share, Basic | | $ | 2.99 | | | $ | 2.84 | | | $ | 2.74 | | | Net Earnings Per Share, Diluted | | $ | 2.95 | | | $ | 2.79 | | | $ | 2.68 | | | | | | | | | | | | | | | | Average Shares of Common Stock (Thousands) | | | | | | | | | | | | | | Basic | | | 104,369 | | | | 107,346 | | | | 112,006 | | | Diluted | | | 105,760 | | | | 109,298 | | | | 114,477 | | | | | | | | | | | | | | | | | Dividends Declared Per Share of Common Stock | | $ | 1.56 | | | $ | 1.40 | | | $ | 1.22 | | | See accompanying Notes to Consolidated Financial Statements. | | | | | | | | | | | | |
| ONEOK, Inc. and Subsidiaries | | | | | | | | CONSOLIDATED BALANCE SHEETS | | | | | | | | | | December 31, | | | December 31, | | | | | 2008 | | | 2007 | | | Assets | | (Thousands of dollars) | | | | | | | | | | | Current Assets | | | | | | | | Cash and cash equivalents | | $ | 510,058 | | | $ | 19,105 | | | Accounts receivable, net | | | 1,265,300 | | | | 1,723,212 | | | Gas and natural gas liquids in storage | | | 858,966 | | | | 841,362 | | | Commodity exchanges and imbalances | | | 56,248 | | | | 82,938 | | | Energy marketing and risk management assets (Notes C and D) | | | 362,808 | | | | 143,941 | | | Other current assets | | | 324,222 | | | | 140,917 | | | Total Current Assets | | | 3,377,602 | | | | 2,951,475 | | | | | | | | | | | | | Property, Plant and Equipment | | | | | | | | | | Property, plant and equipment | | | 9,476,619 | | | | 7,893,492 | | | Accumulated depreciation and amortization | | | 2,212,850 | | | | 2,048,311 | | | Net Property, Plant and Equipment (Note A) | | | 7,263,769 | | | | 5,845,181 | | | | | | | | | | | | | Investments and Other Assets | | | | | | | | | | Goodwill and intangible assets (Note E) | | | 1,038,226 | | | | 1,043,773 | | | Energy marketing and risk management assets (Notes C and D) | | | 45,900 | | | | 3,978 | | | Investments in unconsolidated affiliates (Note O) | | | 755,492 | | | | 756,260 | | | Other assets | | | 645,073 | | | | 461,367 | | | Total Investments and Other Assets | | | 2,484,691 | | | | 2,265,378 | | | Total Assets | | $ | 13,126,062 | | | $ | 11,062,034 | | | See accompanying Notes to Consolidated Financial Statements. | | | | | | | | |
| ONEOK, Inc. and Subsidiaries | | | | | | | | CONSOLIDATED BALANCE SHEETS | | | | | | | | | | December 31, | | | December 31, | | | | | 2008 | | | 2007 | | | Liabilities and Shareholders’ Equity | | (Thousands of dollars) | | | | | | | | | | | Current Liabilities | | | | | | | | Current maturities of long-term debt (Note I) | | $ | 118,195 | | | $ | 420,479 | | | Notes payable | | | 2,270,000 | | | | 202,600 | | | Accounts payable | | | 1,122,761 | | | | 1,436,005 | | | Commodity exchanges and imbalances | | | 188,030 | | | | 252,095 | | | Energy marketing and risk management liabilities (Notes C and D) | | | 175,006 | | | | 133,903 | | | Other current liabilities | | | 319,772 | | | | 436,585 | | | Total Current Liabilities | | | 4,193,764 | | | | 2,881,667 | | | | | | | | | | | | | Long-term Debt, excluding current maturities (Note I) | | | 4,112,581 | | | | 4,215,046 | | | | | | | | | | | | | Deferred Credits and Other Liabilities | | | | | | | | | | Deferred income taxes | | | 890,815 | | | | 680,543 | | | Energy marketing and risk management liabilities (Notes C and D) | | | 46,311 | | | | 26,861 | | | Other deferred credits | | | 715,052 | | | | 486,645 | | | Total Deferred Credits and Other Liabilities | | | 1,652,178 | | | | 1,194,049 | | | | | | | | | | | | | Commitments and Contingencies (Note K) | | | | | | | | | | | | | | | | | | | | Minority Interests in Consolidated Subsidiaries | | | 1,079,369 | | | | 801,964 | | | | | | | | | | | | | Shareholders’ Equity | | | | | | | | | | Common stock, $0.01 par value: | | | | | | | | | | authorized 300,000,000 shares; issued 121,647,007 shares | | | | | | | | | | and outstanding 104,845,231 shares at December 31, 2008; | | | | | | | | | | issued 121,115,217 shares and outstanding 103,987,476 | | | | | | | | | | shares at December 31, 2007 | | | 1,216 | | | | 1,211 | | | Paid in capital | | | 1,301,153 | | | | 1,273,800 | | | Accumulated other comprehensive loss (Note F) | | | (70,616 | ) | | | (7,069 | ) | | Retained earnings | | | 1,553,033 | | | | 1,411,492 | | | Treasury stock, at cost: 16,801,776 shares at December 31, | | | | | | | | | | 2008 and 17,127,741 shares at December 31, 2007 | | | (696,616 | ) | | | (710,126 | ) | | Total Shareholders’ Equity | | | 2,088,170 | | | | 1,969,308 | | | Total Liabilities and Shareholders’ Equity | | $ | 13,126,062 | | | $ | 11,062,034 | | | See accompanying Notes to Consolidated Financial Statements. | | | | | | | | |
This page intentionally left blank. | ONEOK, Inc. and Subsidiaries | | | | | | | | CONSOLIDATED STATEMENTS OF CASH FLOWS | | | | | | | | | Years Ended December 31, | | | | 2008 | | 2007 | | 2006 | | | Operating Activities | (Thousands of dollars) | | | Net income | $ | 311,909 | | $ | 304,921 | | $ | 306,312 | | | Depreciation and amortization | | 243,927 | | | 227,964 | | | 235,543 | | | Allowance for equity funds used during construction | | (50,906 | ) | | (12,538 | ) | | (2,205 | ) | | Gain on sale of assets | | (2,316 | ) | | (1,909 | ) | | (116,528 | ) | | Minority interests in income of consolidated subsidiaries | | 288,558 | | | 193,199 | | | 222,000 | | | Equity earnings from investments | | (101,432 | ) | | (89,908 | ) | | (95,883 | ) | | Distributions received from unconsolidated affiliates | | 93,261 | | | 103,785 | | | 123,427 | | | Deferred income taxes | | 165,191 | | | 65,017 | | | 115,384 | | | Stock-based compensation expense | | 30,791 | | | 20,909 | | | 16,499 | | | Allowance for doubtful accounts | | 13,476 | | | 14,578 | | | 9,056 | | | Inventory adjustment, net | | 9,658 | | | - | | | - | | | Investment securities gains | | (11,142 | ) | | - | | | - | | | Changes in assets and liabilities (net of acquisition and disposition effects): | | | | | | | | | | | Accounts and notes receivable | | 433,859 | | | (378,876 | ) | | 649,415 | | | Gas and natural gas liquids in storage | | (370,662 | ) | | 88,937 | | | (13,801 | ) | | Accounts payable | | (340,584 | ) | | 343,144 | | | (425,715 | ) | | Commodity exchanges and imbalances, net | | (37,375 | ) | | 40,572 | | | 18,001 | | | Unrecovered purchased gas costs | | (35,790 | ) | | 9,530 | | | (73,534 | ) | | Accrued interest | | 16,002 | | | 9,001 | | | 25,329 | | | Energy marketing and risk management assets and liabilities | | 60,846 | | | 41,649 | | | (63,040 | ) | | Fair value of firm commitments | | 505 | | | 5,631 | | | 190,795 | | | Pension and postretirement benefit plans | | (83,254 | ) | | 28,573 | | | (14,496 | ) | | Other assets and liabilities | | (158,845 | ) | | 15,481 | | | (233,283 | ) | | Cash Provided by Operating Activities | | 475,677 | | | 1,029,660 | | | 873,276 | | | Investing Activities | | | | | | | | | | | Changes in investments in unconsolidated affiliates | | 3,963 | | | (3,668 | ) | | (6,608 | ) | | Acquisitions | | 2,450 | | | (299,560 | ) | | (148,892 | ) | | Capital expenditures (less allowance for equity funds used during construction) | | (1,473,136 | ) | | (883,703 | ) | | (376,306 | ) | | Proceeds from sale of discontinued component | | - | | | - | | | 53,000 | | | Proceeds from sale of assets | | 2,630 | | | 4,022 | | | 298,964 | | | Proceeds from insurance | | 9,792 | | | - | | | - | | | Changes in short-term investments | | - | | | 31,125 | | | (31,125 | ) | | Increase in cash and cash equivalents attributable to previously unconsolidated subsidiaries | | - | | | - | | | 1,334 | | | Decrease in cash and cash equivalents attributable to previously consolidated subsidiaries | | - | | | - | | | (22,039 | ) | | Other investing activities | | - | | | - | | | (5,565 | ) | | Cash Used in Investing Activities | | (1,454,301 | ) | | (1,151,784 | ) | | (237,237 | ) | | Financing Activities | | | | | | | | | | | Borrowing (repayment) of notes payable, net | | 1,197,400 | | | 196,600 | | | (842,000 | ) | | Borrowing (repayment) of notes payable with maturities over 90 days | | 870,000 | | | - | | | (900,000 | ) | | Issuance of debt, net of issuance costs | | - | | | 598,146 | | | 1,397,328 | | | Long-term debt financing costs | | - | | | (5,805 | ) | | (12,003 | ) | | Payment of debt | | (416,040 | ) | | (13,588 | ) | | (44,359 | ) | | Equity unit conversion | | - | | | - | | | 402,448 | | | Repurchase of common stock | | (29 | ) | | (390,213 | ) | | (281,444 | ) | | Issuance of common stock | | 16,495 | | | 20,730 | | | 10,829 | | | Issuance of common units, net of discounts | | 146,969 | | | - | | | - | | | Dividends paid | | (162,785 | ) | | (150,188 | ) | | (135,451 | ) | | Distributions to minority interests | | (201,658 | ) | | (182,891 | ) | | (165,283 | ) | | Other financing activities | | 19,225 | | | 170 | | | (48,841 | ) | | Cash Provided by (Used in) Financing Activities | | 1,469,577 | | | 72,961 | | | (618,776 | ) | | Change in Cash and Cash Equivalents | | 490,953 | | | (49,163 | ) | | 17,263 | | | Cash and Cash Equivalents at Beginning of Period | | 19,105 | | | 68,268 | | | 7,915 | | | Effect of Accounting Change on Cash and Cash Equivalents | | - | | | - | | | 43,090 | | | Cash and Cash Equivalents at End of Period | $ | 510,058 | | $ | 19,105 | | $ | 68,268 | | | Supplemental Cash Flow Information: | | | | | | | | | | | Cash Paid for Interest | $ | 237,577 | | $ | 253,678 | | $ | 225,998 | | | Cash Paid for Taxes | $ | 82,965 | | $ | 57,281 | | $ | 262,504 | | | See accompanying Notes to Consolidated Financial Statements. | | | | | | | | | |
CONSOLIDATED STATEMENTS OF INCOMETable of Contents | | | | | | | | | | | | | | | | | | Years Ended December 31, | | | | | | | 2007 | | | 2006 | | | 2005 | | | | | Revenues | | (Thousands of dollars, except per share amounts) | | | | Operating revenues, excluding energy trading revenues | | $ | 13,488,027 | | | $ | 11,913,529 | | | $ | 12,663,550 | | | | Energy trading revenues, net | | | (10,613 | ) | | | 6,797 | | | | 12,680 | | | | Total Revenues | | | 13,477,414 | | | | 11,920,326 | | | | 12,676,230 | | | | Cost of sales and fuel | | | 11,667,306 | | | | 10,198,342 | | | | 11,338,076 | | | | Net Margin | | | 1,810,108 | | | | 1,721,984 | | | | 1,338,154 | | | | | Operating Expenses | | | | | | | | | | | | Operations and maintenance | | | 675,575 | | | | 662,681 | | | | 552,531 | | | | Depreciation and amortization | | | 227,964 | | | | 235,543 | | | | 183,394 | | | | General taxes | | | 85,935 | | | | 78,086 | | | | 67,464 | | | | Total Operating Expenses | | | 989,474 | | | | 976,310 | | | | 803,389 | | | | Gain on sale of assets | | | 1,909 | | | | 116,528 | | | | 269,040 | | | | Operating Income | | | 822,543 | | | | 862,202 | | | | 803,805 | | | | Equity earnings from investments (Note P) | | | 89,908 | | | | 95,883 | | | | 8,621 | | | | Allowance for equity funds used during construction | | | 12,538 | | | | 2,205 | | | | - | | | | Other income | | | 21,932 | | | | 26,030 | | | | (84 | ) | | | Other expense | | | 7,879 | | | | 24,154 | | | | 19,065 | | | | Interest expense | | | 256,325 | | | | 239,725 | | | | 147,608 | | | | Income before Minority Interests and Income Taxes | | | 682,717 | | | | 722,441 | | | | 645,669 | | | | Minority interests in income of consolidated subsidiaries | | | 193,199 | | | | 222,000 | | | | - | | | | Income taxes | | | 184,597 | | | | 193,764 | | | | 242,521 | | | | Income from Continuing Operations | | | 304,921 | | | | 306,677 | | | | 403,148 | | | | Discontinued operations, net of taxes (Note C): | | | | | | | | | | | | | | | Loss from operations of discontinued components, net of tax | | | - | | | | (365 | ) | | | (6,180 | ) | | | Gain on sale of discontinued component, net of tax | | | - | | | | - | | | | 149,577 | | | | Net Income | | $ | 304,921 | | | $ | 306,312 | | | $ | 546,545 | | | | | | Earnings Per Share of Common Stock (Note Q) | | | | | | | | | | | | | | | Basic: | | | | | | | | | | | | | | | Earnings per share from continuing operations | | $ | 2.84 | | | $ | 2.74 | | | $ | 4.01 | | | | Loss per share from operations of discontinued components, net of tax | | | - | | | | - | | | | (0.06 | ) | | | Earnings per share from gain on sale of discontinued component, net of tax | | | - | | | | - | | | | 1.49 | | | | Net Earnings Per Share, Basic | | $ | 2.84 | | | $ | 2.74 | | | $ | 5.44 | | | | | | Diluted: | | | | | | | | | | | | | | | Earnings per share from continuing operations | | $ | 2.79 | | | $ | 2.68 | | | $ | 3.73 | | | | Loss per share from operations of discontinued components, net of tax | | | - | | | | - | | | | (0.06 | ) | | | Earnings per share from gain on sale of discontinued component, net of tax | | | - | | | | - | | | | 1.39 | | | | Net Earnings Per Share, Diluted | | $ | 2.79 | | | $ | 2.68 | | | $ | 5.06 | | | | | | Average Shares of Common Stock(Thousands) | | | | | | | | | | | | | | | Basic | | | 107,346 | | | | 112,006 | | | | 100,536 | | | | Diluted | | | 109,298 | | | | 114,477 | | | | 108,006 | | | | | | Dividends Declared Per Share of Common Stock | | $ | 1.40 | | | $ | 1.22 | | | $ | 1.09 | | | | | |
See accompanying Notes to Consolidated Financial Statements.
| ONEOK, Inc. and Subsidiaries | | | | | | | | | | | | | | CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY AND COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Common | | | | | | | | | | | | | | Stock | | | Common | | | Paid-in | | | Unearned | | | | | Issued | | | Stock | | | Capital | | | Compensation | | | | | (Shares) | | | (Thousands of dollars) | | | | | | | | | | | | | | | | | December 31, 2005 | | | 107,973,436 | | | $ | 1,080 | | | $ | 1,044,283 | | | $ | (105 | ) | | Net income | | | - | | | | - | | | | - | | | | - | | | Other comprehensive income (loss) | | | - | | | | - | | | | - | | | | - | | | Total comprehensive income | | | | | | | | | | | | | | | | | | Adoption of Statement 158 | | | - | | | | - | | | | - | | | | - | | | Equity unit conversion | | | 11,208,998 | | | | 112 | | | | 177,572 | | | | - | | | Repurchase of common stock | | | - | | | | - | | | | - | | | | - | | | Common stock issued | | | 1,151,474 | | | | 11 | | | | 36,862 | | | | 158 | | | Common stock dividends - | | | | | | | | | | | | | | | | | | $1.22 per share | | | - | | | | - | | | | - | | | | (53 | ) | | December 31, 2006 | | | 120,333,908 | | | | 1,203 | | | | 1,258,717 | | | | - | | | Net income | | | - | | | | - | | | | - | | | | - | | | Other comprehensive income (loss) | | | - | | | | - | | | | - | | | | - | | | Total comprehensive income | | | | | | | | | | | | | | | | | | Repurchase of common stock | | | - | | | | - | | | | (11,103 | ) | | | - | | | Common stock issued | | | 781,309 | | | | 8 | | | | 26,186 | | | | - | | | Common stock dividends - | | | | | | | | | | | | | | | | | | $1.40 per share | | | - | | | | - | | | | - | | | | - | | | December 31, 2007 | | | 121,115,217 | | | | 1,211 | | | | 1,273,800 | | | | - | | | Net income | | | - | | | | - | | | | - | | | | - | | | Other comprehensive income (loss) | | | - | | | | - | | | | - | | | | - | | | Total comprehensive income | | | | | | | | | | | | | | | | | | Repurchase of common stock | | | - | | | | - | | | | - | | | | - | | | Common stock issued | | | 531,790 | | | | 5 | | | | 27,353 | | | | - | | | Common stock dividends - | | | | | | | | | | | | | | | | | | $1.56 per share | | | - | | | | - | | | | - | | | | - | | | Change in measurement date for | | | | | | | | | | | | | | | | | | employee benefit plans | | | - | | | | - | | | | - | | | | - | | | December 31, 2008 | | | 121,647,007 | | | $ | 1,216 | | | $ | 1,301,153 | | | $ | - | | | See accompanying Notes to Consolidated Financial Statements. | | | | | | | | | |
| ONEOK, Inc. and Subsidiaries | | | | | | | | | | | | | | CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY AND COMPREHENSIVE INCOME | | | (Continued) | | | | | | | | | | | | | | | | Accumulated | | | | | | | | | | | | | | Other | | | | | | | | | | | | | | Comprehensive | | | Retained | | | Treasury | | | | | | | | Income (Loss) | | | Earnings | | | Stock | | | Total | | | | | (Thousands of dollars) | | | | | | | | | | | | | | | | | December 31, 2005 | | $ | (56,991 | ) | | $ | 1,085,845 | | | $ | (279,355 | ) | | $ | 1,794,757 | | | Net income | | | - | | | | 306,312 | | | | - | | | | 306,312 | | | Other comprehensive income (loss) | | | 63,878 | | | | - | | | | - | | | | 63,878 | | | Total comprehensive income | | | | | | | | | | | | | | | 370,190 | | | Adoption of Statement 158 | | | 32,645 | | | | - | | | | - | | | | 32,645 | | | Equity unit conversion | | | - | | | | - | | | | 224,764 | | | | 402,448 | | | Repurchase of common stock | | | - | | | | - | | | | (285,662 | ) | | | (285,662 | ) | | Common Stock issued | | | - | | | | - | | | | - | | | | 37,031 | | | Common stock dividends - | | | | | | | | | | | | | | | | | | $1.22 per share | | | - | | | | (135,398 | ) | | | - | | | | (135,451 | ) | | December 31, 2006 | | | 39,532 | | | | 1,256,759 | | | | (340,253 | ) | | | 2,215,958 | | | Net income | | | - | | | | 304,921 | | | | - | | | | 304,921 | | | Other comprehensive income (loss) | | | (46,601 | ) | | | - | | | | - | | | | (46,601 | ) | | Total comprehensive income | | | | | | | | | | | | | | | 258,320 | | | Repurchase of common stock | | | - | | | | - | | | | (379,110 | ) | | | (390,213 | ) | | Common stock issued | | | - | | | | - | | | | 9,237 | | | | 35,431 | | | Common stock dividends - | | | | | | | | | | | | | | | | | | $1.40 per share | | | - | | | | (150,188 | ) | | | - | | | | (150,188 | ) | | December 31, 2007 | | | (7,069 | ) | | | 1,411,492 | | | | (710,126 | ) | | | 1,969,308 | | | Net income | | | - | | | | 311,909 | | | | - | | | | 311,909 | | | Other comprehensive income (loss) | | | (63,547 | ) | | | - | | | | - | | | | (63,547 | ) | | Total comprehensive income | | | | | | | | | | | | | | | 248,362 | | | Repurchase of common stock | | | - | | | | - | | | | (29 | ) | | | (29 | ) | | Common stock issued | | | - | | | | - | | | | 13,539 | | | | 40,897 | | | Common stock dividends - | | | | | | | | | | | | | | | | | | $1.56 per share | | | - | | | | (162,785 | ) | | | - | | | | (162,785 | ) | | Change in measurement date for | | | | | | | | | | | | | | | | | | employee benefit plans | | | - | | | | (7,583 | ) | | | | | | | (7,583 | ) | | December 31, 2008 | | $ | (70,616 | ) | | $ | 1,553,033 | | | $ | (696,616 | ) | | $ | 2,088,170 | |
CONSOLIDATED BALANCE SHEETSTable of Contents | | | | | | | | | | | | December 31,
2007 | | December 31,
2006 | | | | Assets | | (Thousands of dollars) | | | | | | | Current Assets | | | | | | | | | Cash and cash equivalents | | $ | 19,105 | | $ | 68,268 | | | Short-term investments | | | - | | | 31,125 | | | Trade accounts and notes receivable, net | | | 1,723,212 | | | 1,348,490 | | | Gas and natural gas liquids in storage | | | 841,362 | | | 925,194 | | | Commodity exchanges and imbalances | | | 82,938 | | | 53,433 | | | Energy marketing and risk management assets (Note D) | | | 168,609 | | | 401,670 | | | Other current assets | | | 116,249 | | | 296,781 | | | Total Current Assets | | | 2,951,475 | | | 3,124,961 | | | | | | | Property, Plant and Equipment | | | | | | | | | Property, plant and equipment | | | 7,893,492 | | | 6,724,759 | | | Accumulated depreciation and amortization | | | 2,048,311 | | | 1,879,838 | | | Net Property, Plant and Equipment | | | 5,845,181 | | | 4,844,921 | | | | | | | Deferred Charges and Other Assets | | | | | | | | | Goodwill and intangible assets (Note E) | | | 1,043,773 | | | 1,051,440 | | | Energy marketing and risk management assets (Note D) | | | 3,978 | | | 91,133 | | | Investments in unconsolidated affiliates (Note P) | | | 756,260 | | | 748,879 | | | Other assets | | | 461,367 | | | 529,748 | | | Total Deferred Charges and Other Assets | | | 2,265,378 | | | 2,421,200 | | | Total Assets | | $ | 11,062,034 | | $ | 10,391,082 | | | | |
See accompanying Notes to Consolidated Financial Statements.
ONEOK, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
| | | | | | | | | | | | | | December 31, 2007 | | | December 31,
2006 | | | | | Liabilities and Shareholders’ Equity | | (Thousands of dollars) | | | | | | | | Current Liabilities | | | | | | | | | | | Current maturities of long-term debt | | $ | 420,479 | | | $ | 18,159 | | | | Notes payable | | | 202,600 | | | | 6,000 | | | | Accounts payable | | | 1,436,005 | | | | 1,076,954 | | | | Commodity exchanges and imbalances | | | 252,095 | | | | 176,451 | | | | Energy marketing and risk management liabilities (Note D) | | | 133,903 | | | | 306,658 | | | | Other | | | 436,585 | | | | 366,316 | | | | Total Current Liabilities | | | 2,881,667 | | | | 1,950,538 | | | | | | | | Long-term Debt, excluding current maturities | | | 4,215,046 | | | | 4,030,855 | | | | | | | | Deferred Credits and Other Liabilities | | | | | | | | | | | Deferred income taxes | | | 680,543 | | | | 707,444 | | | | Energy marketing and risk management liabilities (Note D) | | | 26,861 | | | | 137,312 | | | | Other deferred credits | | | 486,645 | | | | 548,330 | | | | Total Deferred Credits and Other Liabilities | | | 1,194,049 | | | | 1,393,086 | | | | | | | | Commitments and Contingencies (Note K) | | | | | | | | | | | | | | | Minority Interests in Consolidated Subsidiaries | | | 801,964 | | | | 800,645 | | | | | | | | Shareholders’ Equity | | | | | | | | | | | Common stock, $0.01 par value: | | | | | | | | | | | authorized 300,000,000 shares; issued 121,115,217 shares
and outstanding 103,987,476 shares at December 31, 2007;
issued 120,333,908 shares and outstanding 110,678,499
shares at December 31, 2006 | | | 1,211 | | | | 1,203 | | | | Paid in capital | | | 1,273,800 | | | | 1,258,717 | | | | Accumulated other comprehensive income (loss) (Note F) | | | (7,069 | ) | | | 39,532 | | | | Retained earnings | | | 1,411,492 | | | | 1,256,759 | | | | Treasury stock, at cost: 17,127,741 shares at December 31, 2007
and 9,655,409 shares at December 31, 2006 | | | (710,126 | ) | | | (340,253 | ) | | | Total Shareholders’ Equity | | | 1,969,308 | | | | 2,215,958 | | | | Total Liabilities and Shareholders’ Equity | | $ | 11,062,034 | | | $ | 10,391,082 | | | | | |
See accompanying Notes to Consolidated Financial Statements.
ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
| | | | | | | | | | | | | | | | | | Years Ended December 31, | | | | | | | 2007 | | | 2006 | | | 2005 | | | | | Operating Activities | | (Thousands of dollars) | | | | Net income | | $ | 304,921 | | | $ | 306,312 | | | $ | 546,545 | | | | Depreciation and amortization | | | 227,964 | | | | 235,543 | | | | 183,394 | | | | Allowance for equity funds used during construction | | | (12,538 | ) | | | (2,205 | ) | | | - | | | | Impairment expense on discontinued operations | | | - | | | | - | | | | 52,226 | | | | Gain on sale of discontinued component, net | | | - | | | | - | | | | (149,577 | ) | | | Gain on sale of assets | | | (1,909 | ) | | | (116,528 | ) | | | (269,040 | ) | | | Minority interests in income of consolidated subsidiaries | | | 193,199 | | | | 222,000 | | | | - | | | | Distributions received from unconsolidated affiliates | | | 103,785 | | | | 123,427 | | | | 10,983 | | | | Income from equity investments | | | (89,908 | ) | | | (95,883 | ) | | | (8,621 | ) | | | Deferred income taxes | | | 65,017 | | | | 115,384 | | | | 16,372 | | | | Stock-based compensation expense | | | 14,639 | | | | 16,499 | | | | 11,842 | | | | Allowance for doubtful accounts | | | 14,578 | | | | 9,056 | | | | 16,329 | | | | Changes in assets and liabilities (net of acquisition and disposition effects): | | | | | | | | | | | | | | | Accounts and notes receivable | | | (378,876 | ) | | | 649,415 | | | | (733,367 | ) | | | Inventories | | | 88,860 | | | | (14,107 | ) | | | (320,632 | ) | | | Unrecovered purchased gas costs | | | 9,530 | | | | (73,534 | ) | | | (8,943 | ) | | | Commodity exchanges and imbalances, net | | | 40,572 | | | | 18,001 | | | | 106,775 | | | | Deposits | | | 77,525 | | | | 50,445 | | | | (118,214 | ) | | | Regulatory assets | | | (2,225 | ) | | | 15,441 | | | | (6,357 | ) | | | Accounts payable and accrued liabilities | | | 353,104 | | | | (499,996 | ) | | | 518,406 | | | | Energy marketing and risk management assets and liabilities | | | (60,544 | ) | | | (139,488 | ) | | | 223,965 | | | | Other assets and liabilities | | | 81,966 | | | | 53,494 | | | | (242,463 | ) | | | Cash Provided by (Used in) Operating Activities | | | 1,029,660 | | | | 873,276 | | | | (170,377 | ) | | | | Investing Activities | | | | | | | | | | | | Changes in investments in unconsolidated affiliates | | | (3,668 | ) | | | (6,608 | ) | | | 6,209 | | | | Acquisitions | | | (299,560 | ) | | | (148,892 | ) | | | (1,327,907 | ) | | | Capital expenditures (less allowance for equity funds used during construction) | | | (883,703 | ) | | | (376,306 | ) | | | (250,493 | ) | | | Proceeds from sale of discontinued component | | | - | | | | 53,000 | | | | 519,279 | | | | Changes in short-term investments | | | 31,125 | | | | (31,125 | ) | | | - | | | | Proceeds from sale of assets | | | 4,022 | | | | 298,964 | | | | 556,434 | | | | Increase in cash and cash equivalents attributable to previously unconsolidated subsidiaries | | | - | | | | 1,334 | | | | - | | | | Decrease in cash and cash equivalents attributable to previously consolidated subsidiaries | | | - | | | | (22,039 | ) | | | - | | | | Other investing activities | | | - | | | | (5,565 | ) | | | (29,592 | ) | | | Cash Used in Investing Activities | | | (1,151,784 | ) | | | (237,237 | ) | | | (526,070 | ) | | | Financing Activities | | | | | | | | | | | | | | | Borrowing (repayment) of notes payable, net | | | 196,600 | | | | (842,000 | ) | | | (2,500 | ) | | | Short-term financing payments | | | - | | | | (900,000 | ) | | | (100,000 | ) | | | Short-term financing borrowings | | | - | | | | - | | | | 1,000,000 | | | | Issuance of debt, net of discounts | | | 598,146 | | | | 1,397,328 | | | | 798,792 | | | | Long-term debt financing costs | | | (5,805 | ) | | | (12,003 | ) | | | - | | | | Payment of debt | | | (13,588 | ) | | | (44,359 | ) | | | (636,288 | ) | | | Equity unit conversion | | | - | | | | 402,448 | | | | - | | | | Repurchase of common stock | | | (390,213 | ) | | | (281,444 | ) | | | (233,074 | ) | | | Issuance of common stock | | | 20,730 | | | | 10,829 | | | | 4,672 | | | | Dividends paid | | | (150,188 | ) | | | (135,451 | ) | | | (110,157 | ) | | | Distributions to minority interests | | | (182,891 | ) | | | (165,283 | ) | | | - | | | | Other financing activities | | | 170 | | | | (48,841 | ) | | | (26,541 | ) | | | Cash Provided by (Used in) Financing Activities | | | 72,961 | | | | (618,776 | ) | | | 694,904 | | | | Change in Cash and Cash Equivalents | | | (49,163 | ) | | | 17,263 | | | | (1,543 | ) | | | Cash and Cash Equivalents at Beginning of Period | | | 68,268 | | | | 7,915 | | | | 9,458 | | | | Effect of Accounting Change on Cash and Cash Equivalents | | | - | | | | 43,090 | | | | - | | | | Cash and Cash Equivalents at End of Period | | $ | 19,105 | | | $ | 68,268 | | | $ | 7,915 | | | | | |
See accompanying Notes to Consolidated Financial Statements.
ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME
| | | | | | | | | | | | | | | | | | | Common Stock Issued | | Common Stock | | Paid-in Capital | | | Unearned
Compensation | | | | | | | (Shares) | | (Thousands of dollars) | | | | December 31, 2004 | | 107,143,722 | | $ | 1,071 | | $ | 1,017,603 | | | $ | (1,413 | ) | | | Net income | | - | | | - | | | - | | | | - | | | | Other comprehensive loss | | - | | | - | | | - | | | | - | | | | Total comprehensive income | | | | | | | | | | | | | | | | Repurchase of common stock | | - | | | - | | | - | | | | - | | | | Common stock issuance pursuant to various plans | | 829,714 | | | 9 | | | 16,363 | | | | - | | | | Stock-based employee compensation expense | | - | | | - | | | 10,317 | | | | 1,525 | | | | Common stock dividends - $1.09 per share | | - | | | - | | | - | | | | (217 | ) | | | December 31, 2005 | | 107,973,436 | | | 1,080 | | | 1,044,283 | | | | (105 | ) | | | Net income | | - | | | - | | | - | | | | - | | | | Other comprehensive income | | - | | | - | | | - | | | | - | | | | Total comprehensive income | | | | | | | | | | | | | | | | Adoption of Statement 158 | | - | | | - | | | - | | | | - | | | | Equity unit conversion | | 11,208,998 | | | 112 | | | 177,572 | | | | - | | | | Repurchase of common stock | | - | | | - | | | - | | | | - | | | | Common stock issuance pursuant to various plans | | 1,151,474 | | | 11 | | | 20,521 | | | | - | | | | Stock-based employee compensation expense | | - | | | - | | | 16,341 | | | | 158 | | | | Common stock dividends - $1.22 per share | | - | | | - | | | - | | | | (53 | ) | | | December 31, 2006 | | 120,333,908 | | | 1,203 | | | 1,258,717 | | | | - | | | | Net income | | - | | | - | | | - | | | | - | | | | Other comprehensive loss | | - | | | - | | | - | | | | - | | | | Total comprehensive income | | | | | | | | | | | | | | | | Repurchase of common stock | | - | | | - | | | (11,103 | ) | | | - | | | | Common stock issuance pursuant to various plans | | 781,309 | | | 8 | | | 9,434 | | | | - | | | | Stock-based employee compensation expense | | - | | | - | | | 16,752 | | | | - | | | | Common stock dividends - $1.40 per share | | - | | | - | | | - | | | | - | | | | December 31, 2007 | | 121,115,217 | | $ | 1,211 | | $ | 1,273,800 | | | $ | - | | | | | |
See accompanying Notes to Consolidated Financial Statements.
ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME
(Continued)
| | | | | | | | | | | | | | | | | | | | | | Accumulated
Other
Comprehensive
Income (Loss) | | | Retained
Earnings | | | Treasury Stock | | | Total | | | | | | | (Thousands of dollars) | | | | December 31, 2004 | | $ | (9,591 | ) | | $ | 649,240 | | | $ | (51,206 | ) | | $ | 1,605,704 | | | | Net income | | | - | | | | 546,545 | | | | - | | | | 546,545 | | | | Other comprehensive loss | | | (47,400 | ) | | | - | | | | - | | | | (47,400 | ) | | | | | | | | | | | | | | | | | | | | | | Total comprehensive income | | | | | | | | | | | | | | | 499,145 | | | | | | | | | | | | | | | | | | | | | | | Repurchase of common stock | | | - | | | | - | | | | (228,149 | ) | | | (228,149 | ) | | | Common stock issuance pursuant to various plans | | | - | | | | - | | | | - | | | | 16,372 | | | | Stock-based employee compensation expense | | | - | | | | - | | | | - | | | | 11,842 | | | | Common stock dividends - $1.09 per share | | | - | | | | (109,940 | ) | | | - | | | | (110,157 | ) | | | December 31, 2005 | | | (56,991 | ) | | | 1,085,845 | | | | (279,355 | ) | | | 1,794,757 | | | | Net income | | | - | | | | 306,312 | | | | - | | | | 306,312 | | | | Other comprehensive income | | | 63,878 | | | | - | | | | - | | | | 63,878 | | | | | | | | | | | | | | | | | | | | | | | Total comprehensive income | | | | | | | | | | | | | | | 370,190 | | | | | | | | | | | | | | | | | | | | | | | Adoption of Statement 158 | | | 32,645 | | | | - | | | | - | | | | 32,645 | | | | Equity unit conversion | | | - | | | | - | | | | 224,764 | | | | 402,448 | | | | Repurchase of common stock | | | - | | | | - | | | | (285,662 | ) | | | (285,662 | ) | | | Common stock issuance pursuant to various plans | | | - | | | | - | | | | - | | | | 20,532 | | | | Stock-based employee compensation expense | | | - | | | | - | | | | - | | | | 16,499 | | | | Common stock dividends - $1.22 per share | | | - | | | | (135,398 | ) | | | - | | | | (135,451 | ) | | | December 31, 2006 | | | 39,532 | | | | 1,256,759 | | | | (340,253 | ) | | | 2,215,958 | | | | Net income | | | - | | | | 304,921 | | | | - | | | | 304,921 | | | | Other comprehensive loss | | | (46,601 | ) | | | - | | | | - | | | | (46,601 | ) | | | | | | | | | | | | | | | | | | | | | | Total comprehensive income | | | | | | | | | | | | | | | 258,320 | | | | | | | | | | | | | | | | | | | | | | | Repurchase of common stock | | | - | | | | - | | | | (379,110 | ) | | | (390,213 | ) | | | Common stock issuance pursuant to various plans | | | - | | | | - | | | | 9,012 | | | | 18,454 | | | | Stock-based employee compensation expense | | | - | | | | - | | | | 225 | | | | 16,977 | | | | Common stock dividends - $1.40 per share | | | - | | | | (150,188 | ) | | | - | | | | (150,188 | ) | | | December 31, 2007 | | $ | (7,069 | ) | | $ | 1,411,492 | | | $ | (710,126 | ) | | $ | 1,969,308 | | | | | |
ONEOK, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS A. | SUMMARY OF ACCOUNTING POLICIES |
A. SUMMARY OF ACCOUNTING POLICIES
Organization and Nature of Operations - We purchase, transport, storeare a diversified energy company and distribute natural gas. We aresuccessor to the largest natural gas distributorcompany founded in 1906 known as Oklahoma and Kansas andNatural Gas Company. Our common stock is listed on the third largest natural gas distributor in Texas, providing service as a regulated public utility to wholesale and retail customers. Our largest distribution markets are Oklahoma City and Tulsa, Oklahoma; Kansas City, Wichita, and Topeka, Kansas; and Austin and El Paso, Texas. Our energy services operation is engaged in wholesale and retail natural gas marketing andNYSE under the trading activities and provides services to customers in many states and Canada.symbol “OKE.” We are the sole general partner and own 45.747.7 percent of ONEOK Partners, L.P. (NYSE: OKS), aone of the largest publicly traded master limited partnership.partnerships.
We have divided our operations into four reportable business segments based on similarities in economic characteristics, products and services, types of customers, methods of distribution and regulatory environment. These segments are as follows:
Our ONEOK Partners gathers, processes, stores and transports natural gassegment is engaged in the United Statesgathering and owns natural gas liquids systems that connect muchprocessing of theunprocessed natural gas and NGL supplyfractionation of NGLs, primarily in the Mid-Continent and Gulf CoastRocky Mountain regions with keycovering Oklahoma, Kansas, Montana, North Dakota and Wyoming. These operations include the gathering of unprocessed natural gas produced from crude oil and natural gas wells. Through gathering systems, unprocessed natural gas is aggregated and treated or processed for removal of water vapor, solids and other contaminants, and to extract NGLs in order to provide marketable natural gas, commonly referred to as residue gas. When the NGLs are separated from the unprocessed natural gas at the processing plants, the NGLs are generally in the form of a mixed, unfractionated NGL stream. This stream is then separated by a distillation process, referred to as fractionation, into marketable product components such as ethane, ethane/propane (E/P), propane, iso-butane, normal butane and natural gasoline (collectively, NGL products). These NGL products can then be stored, transported and marketed to a diverse customer base of end-users.
ONEOK Partners also gathers, treats, fractionates, transports and stores NGLs. ONEOK Partners’ natural gas liquids gathering pipelines deliver unfractionated NGLs gathered from natural gas processing plants located in Oklahoma, Kansas, the Texas panhandle and the Rocky Mountain region to fractionators it owns in Oklahoma, Kansas and Texas. The NGLs are then separated through the fractionation process into the individual NGL products that realize the greater economic value of the NGL components. The individual NGL products are then stored or distributed to petrochemical manufacturers, heating fuel users, refineries and propane distributors through ONEOK Partners’ distribution pipelines that move NGL products from Oklahoma and Kansas to the market centers in Conway, Kansas, and Mont Belvieu, Texas, andas well as the Midwest markets near Chicago, Illinois.
ONEOK Partners operates interstate and intrastate natural gas transmission pipelines, natural gas storage facilities and non-processable natural gas gathering facilities. ONEOK Partners’ interstate assets transport natural gas through FERC-regulated interstate natural gas pipelines that access supply from Canada, and the Mid-Continent, Rocky Mountain and Gulf Coast regions.
ONEOK Partners’ intrastate natural gas pipeline assets in Oklahoma have access to the major natural gas producing areas and transport natural gas throughout the state. ONEOK Partners also has access to the major natural gas producing area in south central Kansas. In Texas, its intrastate natural gas pipelines are connected to the major natural gas producing areas in the Texas panhandle and the Permian Basin and transport natural gas to the Waha Hub, where other pipelines may be accessed for transportation east to the Houston Ship Channel market, north into the Mid-Continent market and west to the California market. ONEOK Partners owns or leases storage capacity in underground natural gas storage facilities in Oklahoma, Kansas and Texas. ONEOK Partners’ natural gas pipelines primarily serve LDCs, large industrial companies, municipalities, irrigation customers, power generation facilities and marketing companies.
Our Distribution segment provides natural gas distribution services to more than two million customers in Oklahoma, Kansas and Texas through Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service, respectively, each a division of ONEOK. We serve residential, commercial, industrial and transportation customers in all three states. In addition, our distribution companies in Oklahoma and Kansas serve wholesale customers, and in Texas we serve public authority customers, such as cities, governmental agencies and schools. Our Energy Services segment’s primary focus is to create value for our customers by delivering physical natural gas products and risk management services through our network of contracted transportation and storage capacity and natural gas supply. These services include meeting our customers’ baseload, swing and peaking natural gas commodity requirements on a year-round basis. To provide these bundled services, we lease storage and transportation capacity. Our contracted storage and transportation capacity connects major supply and demand centers throughout the United States and into Canada. With these contracted assets, our business strategies include identifying, developing and delivering specialized services and products valued by our customers, which are primarily LDCs, electric utilities, and commercial and industrial end users. Our storage and transportation capacity allows us opportunities to optimize value through our application of market knowledge and risk management skills.
Critical Accounting Policies
The following is a summary of our most critical accounting policies, which are defined as those policies most important to the portrayal of our financial condition and results of operations and requiring our management’s most difficult, subjective or complex judgment, particularly because of the need to make estimates concerning the impact of inherently uncertain matters. We have discussed the development and selection of our critical accounting policies and estimates with the Audit Committee of our Board of Directors.
Fair Value Measurements - General - In September 2006, the FASB issued Statement 157, “Fair Value Measurements” that establishes a framework for measuring fair value and requires additional disclosures about fair value measurements. Beginning January 1, 2008, we partially applied Statement 157 as allowed by FASB Staff Position (FSP) 157-2, “Effective Date of FASB Statement No. 157” that delayed the effective date of Statement 157 for nonrecurring fair value measurements associated with our nonfinancial assets and liabilities. As of January 1, 2008, we applied the provisions of Statement 157 to our recurring fair value measurements, and the impact was not material upon adoption. As of January 1, 2009, we have applied the provisions of Statement 157 to our nonrecurring fair value measurements associated with our nonfinancial assets and liabilities, and the impact was not material. FSP 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active,” which clarified the application of Statement 157 in inactive markets, was issued in October 2008 and was effective for our September 30, 2008, unaudited consolidated financial statements. FSP 157-3 did not have a material impact on our consolidated financial statements.
In February 2007, the FASB issued Statement 159, “The Fair Value Option for Financial Assets and Financial Liabilities” that allows companies to elect to measure specified financial assets and liabilities, firm commitments, and nonfinancial warranty and insurance contracts at fair value on a contract-by-contract basis, with changes in fair value recognized in earnings each reporting period. At January 1, 2008, we did not elect the fair value option under Statement 159, and therefore there was no impact on our consolidated financial statements.
Determining Fair Value - Statement 157 defines fair value as the price that would be received to sell an asset or transfer a liability in an orderly transaction between market participants at the measurement date. We use the market and income approaches to determine the fair value of our assets and liabilities and consider the markets in which the transactions are executed. While many of the contracts in our portfolio are executed in liquid markets where price transparency exists, some contracts are executed in markets for which market prices may exist but the market may be relatively inactive. This results in limited price transparency that requires management’s judgment and assumptions to estimate fair values. Inputs into our fair value estimates include commodity exchange prices, over-the-counter quotes, volatility, historical correlations of pricing data and LIBOR and other liquid money market instrument rates. We also utilize internally developed basis curves that incorporate observable and unobservable market data. We validate our valuation inputs with third-party information and settlement prices from other sources, where available. In addition, as prescribed by the income approach, we compute the fair value of our derivative portfolio by discounting the projected future cash flows from our derivative assets and liabilities to present value. The interest rate yields used to calculate the present value discount factors are derived from LIBOR, Eurodollar futures and Treasury swaps. The projected cash flows are then multiplied by the appropriate discount factors to determine the present value or fair value of our derivative instruments. We also take into consideration the potential impact on market prices of liquidating positions in an orderly manner over a reasonable period of time under current market conditions. Finally, we consider credit risk of our counterparties on the fair value of our derivative assets, as well as our own credit risk for derivative liabilities, using default probabilities and recovery rates, net of collateral. We also take into consideration current market data in our evaluation when available, such as bond prices and yields and credit default swaps. Although we use our best estimates to determine the fair value of the derivative contracts we have executed, the ultimate market prices realized could differ from our estimates, and the differences could be material. Fair Value Hierarchy - - Statement 157 establishes the fair value hierarchy that prioritizes inputs to valuation techniques based on observable and unobservable data and categorizes the inputs into three levels, with the highest priority given to Level 1 and the lowest priority given to Level 3. The levels are described below. | · | Level 1 - Unadjusted quoted prices in active markets for identical assets or liabilities. |
| · | Level 2 - Significant observable pricing inputs other than quoted prices included within Level 1 that are either directly or indirectly observable as of the reporting date. Essentially, this represents inputs that are derived principally from or corroborated by observable market data. |
| · | Level 3 - Generally unobservable inputs, which are developed based on the best information available and may include our own internal data. |
Determining the appropriate classification of our fair value measurements within the fair value hierarchy requires management’s judgment regarding the degree to which market data is observable or corroborated by observable market data.
See Note C for more discussion of our fair value measurements.
Derivatives, Accounting for Financially Settled Transactions and Risk Management Activities- We engage in wholesale energy marketing, retail marketing, trading and risk management activities. We account for derivative instruments utilized in connection with these activities and services under the fair value basis of accounting in accordance with Statement 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended.
Under Statement 133, entities are required to record all derivative instruments at fair value. The fair value, with the exception of a derivative instrument is determined by commodity exchange prices, over-the-counter quotes, volatility, time value, counterparty creditnormal purchases and the potential impact on market prices of liquidating positionsnormal sales that are expected to result in an orderly manner over a reasonable period of time under current market conditions. The majority of our portfolio’s fair values are based on actual market prices. Transactions are also executedphysical delivery. See previous discussion in markets“Fair Value Measurements” 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.additional information. Market value changes result in a change in the fair value of our derivative instruments. 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 nature of the risk being hedged and how we will determine if the hedging instrument is effective. If the derivative instrument does not qualify or is not designated as part of a hedging relationship, then we account for changes in fair value of the derivative in earnings as they occur. Commodity price volatility may have a significant impact on the gain or loss in a given period.
To minimize the risk ofreduce our exposure to fluctuations in natural gas, NGLs and condensate prices, we periodically enter into futures, collarsforwards, options or swap transactions in order to hedge anticipated purchases and sales of natural gas, NGLs, condensate and fuel requirements. Interest-rate swaps are also used to manage interest-rate risk. Under certain conditions, we designate these derivative instruments as a hedge of exposure to changes in fair values or cash flows. 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 accumulated other comprehensive income (loss) and is subsequently recorded to earnings when the forecasted transaction affects earnings. Any ineffectiveness of designated hedges is reported in earnings during the period the ineffectiveness occurs. For hedges of exposure to changes in fair value, the gain or loss on the derivative instrument is recognized in earnings during the period of change, together with the offsetting gain or loss on the hedged item attributable to the risk being hedged.
Upon election, many of our purchase and sale agreements that otherwise would be required to follow derivative accounting qualify as normal purchases and normal sales under Statement 133 and are therefore exempt from fair value accounting treatment.
The presentation of settled derivative instruments on either a gross or net basis in our Consolidated Statements of Income is dependent on a number of factors, including whether the derivative instrument (i) is (i) held for trading purposes,purposes; (ii) is financially settled,settled; (iii) results in physical delivery or services rendered,rendered; and (iv) qualifies for the normal purchase or sale exception as defined in Statement 133. In accordance with EITF 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and not ‘Held for Trading’ as Defined in EITF Issue No. 02-3,” EITF 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent,” and Statement 133, we report settled derivative instruments as follows: all financially settled derivative contracts are reported on a net basis,
derivative instruments considered held for trading purposes that result in physical delivery are reported on a net basis,
| · | all financially settled derivative contracts are reported on a net basis; |
derivative instruments not considered held for trading purposes that result in physical delivery or services rendered are reported on a gross basis, and
| · | derivative instruments considered held for trading purposes that result in physical delivery are reported on a net basis; |
derivatives that qualify for the normal purchase or sale exception as defined in Statement 133 are reported on a gross basis.
| · | derivative instruments not considered held for trading purposes that result in physical delivery or services rendered are reported on a gross basis; and |
| · | derivatives that qualify for the normal purchase or sale exception as defined in Statement 133 are reported on a gross basis. |
We apply the indicators in EITF 99-19 to determine the appropriate accounting treatment for non-derivative contracts that result in physical delivery.
See Note D for more discussion of derivatives and risk management activities.
Impairment of Long-Lived Assets, Goodwill and Intangible Assets- We assess our long-lived assets for impairment based on Statement 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.
We assess our goodwill and indefinite-lived intangible assets for impairment at least annually based on Statement 142, “Goodwill and Other Intangible Assets.” AnThere were no impairment charges resulting from our July 1, 2008, impairment test. As a result of recent events in the financial markets and current economic conditions, we performed a review and determined that interim testing of goodwill as of December 31, 2008, was not necessary. As a part of our impairment test, an initial assessment is made by comparing the fair value of the operationsa reporting unit with goodwill, as determined in accordance with Statement 142, to theits book value, of each reporting unit.including goodwill. 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 with goodwillreporting unit from the fair value determined in step one of the assessment. If the carrying value of the goodwill exceeds this calculatedthe implied fair value of the goodwill, we will record an impairment charge.
We use two generally accepted valuation approaches, an income approach and a market approach, to estimate the fair value of a reporting unit. Under the income approach, we use anticipated cash flows over a three-year period plus a terminal value and discount these amounts to their present value using appropriate rates of return. Under the market approach, we apply multiples to forecasted EBITDA amounts. The multiples used are consistent with historical asset transactions, and the EBITDA amounts are based on average EBITDA for a reporting unit over a three-year forecasted period. See Note E for more discussion of goodwill.
Intangible assets with a finite useful life are amortized over their estimated useful life, while intangible assets with an indefinite useful life are not amortized. All intangible assets are subject to impairment testing. Our ONEOK Partners segmentWe had $443.0$435.4 million of intangible assets recorded on our Consolidated Balance Sheet as of December 31, 2007,2008, of which $287.5$279.8 million in our ONEOK Partners segment is being amortized over an aggregate weighted-average period of 40 years, while the remaining balance has an indefinite life. During 2006,
Our impairment tests require the use of assumptions and estimates. If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we recorded a goodwill and asset impairment relatedmay be exposed to ONEOK Partners’ Black Mesa Pipeline of $8.4 million and $3.6 million, respectively, which were recorded as depreciation and amortization. The reduction to our net income, net of minority interests and income taxes, was $3.0 million.In the third quarter of 2005, we made the decision to sell our Spring Creek power plant, located in Oklahoma, and exit the power generation business. In October 2005, we concluded that our Spring Creek power plant had been impaired and recorded an impairment expense of $52.2 million. This conclusion was based on our Statement 144 impairment analysis ofcharge.
For the results of operationsinvestments we account for this plant through September 30, 2005, and alsounder the net sales proceeds fromequity method, the anticipated sale of the plant. The sale was completed on October 31, 2006. This component of our business is accounted for as discontinued operations in accordance with Statement 144.Our total unamortizedpremium or excess cost over underlying fair value of net assets accounted for under the equity method was $185.6 million as of December 31, 2007 and 2006. Based on Statement 142, this amount,is referred to as equity method goodwill should continueand under Statement 142, is not subject to be recognized in accordance withamortization but rather to impairment testing pursuant to APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.” Accordingly,The impairment test under APB Opinion No. 18 considers whether the fair value of the equity investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. Therefore, we included thisperiodically reevaluate the amount at which we carry the excess of cost over fair value of net assets accounted for under the equity method to determine whether current events or circumstances warrant adjustments to our carrying value in investment in unconsolidated affiliates on our accompanying Consolidated Balance Sheets.
accordance with APB Opinion No. 18.
Pension and Postretirement Employee Benefits - We have defined benefit retirement plans covering certain full-time employees. We sponsor welfare plans that provide postretirement medical and life insurance benefits to certain employees who retire with at least five years of service. Our actuarial consultant calculates the expense and liability related to these plans and 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. In determining the projected benefit obligations and costs, assumptions can change from period to period and result in material changes in the costs and liabilities we recognize. See Note J for more discussion of pension and postretirement employee benefits.
In September 2006, the FASB issued Statement 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” which required us to record a balance sheet liability equal to the difference between our benefit obligations and plan assets. Statement 158 also required us to change our measurement date from September 30 to December 31. Statement 158 was effective for our year ended December 31, 2006, except for the measurement date change, from September 30 to December 31, which will bewas effective for our year ending December 31, 2008. We determined our net periodic benefit cost for the period October 1, 2007, through December 31, 2008, based on a measurement date of September 30, 2007. The net periodic benefit cost for the period of October 1, 2007, through December 31, 2007, was reflected as an adjustment to retained earnings as of December 31, 2008. The impact of this adjustment was a $7.6 million reduction to retained earnings, net of taxes.
Contingencies - Our accounting for contingencies covers a variety of business activities, including contingencies for 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 5, “Accounting for Contingencies.” We base our estimates on currently available facts and our estimates of the ultimate outcome or resolution. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than completion of the remediation feasibility study. Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable. Actual results may differ from our estimates resulting in an impact, either positive or negative, on earnings. See Note K for additional discussion of contingencies.
Significant Accounting Policies
ConsolidationConsolidation - Our consolidated financial statements include the accounts of ONEOK and our subsidiaries over which we have control. We have recorded minority interests in consolidated subsidiaries on our Consolidated Balance Sheets to recognize the percent of ONEOK Partners that we do not own. We reflected our percent share of ONEOK Partners’ accumulated other comprehensive income (loss) in our consolidated accumulated other comprehensive income (loss). The remaining percent is reflected as an adjustment to minority interests in consolidated subsidiaries. All significant intercompany accountsbalances and transactions have been eliminated in consolidation. Investments in affiliates are accounted for using the equity method if we have the ability to exercise significant influence over operating and financial policies of our investee; conversely, if we do not have the ability to exercise significant influence, then we use the cost method. Impairment of equity and cost method investments is assessedrecorded when the impairments are other than temporary.
In June 2005, the FASB ratified the consensus reached in EITF Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights,” which presumes that a general partner controls a limited partnership and therefore should consolidate the partnership in the financial statements
Use of the general partner. Effective January 1, 2006, we were required to consolidate ONEOK Partners’ operations inEstimates - The preparation of our consolidated financial statements and we electedrelated disclosures in accordance with GAAP requires us to usemake estimates and assumptions with respect to values or conditions that cannot be known with certainty that affect the prospective method. Accordingly, prior periodreported amount of assets and liabilities, and the disclosure of contingent assets and liabilities at the date of the consolidated financial statementsstatements. These estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Items that may be estimated include, but are not limited to, the economic useful life of assets, fair value of assets and liabilities, obligations under employee benefit plans, provisions for uncollectible accounts receivable, unbilled revenues for natural gas delivered but for which meters have not been restated. The adoptionread, gas purchased expense for natural gas purchased but for which no invoice has been received, provision for income taxes, including any deferred tax valuation allowances, the results of EITF 04-5 did not havelitigation and various other recorded or disclosed amounts.
We evaluate these estimates on an impactongoing basis using historical experience, consultation with experts and other methods we consider reasonable based on the particular circumstances. Nevertheless, actual results may differ significantly from the estimates. Any effects on our net income; however, reported revenues, costs and expenses reflect the operatingfinancial position or results of ONEOK Partners. Additionally, weoperations from revisions to these estimates are recorded a minority interests liability on our Consolidated Balance Sheetsin the period when the facts that give rise to recognize the 54.3 percent of ONEOK Partners that we do not own. We reflected our 45.7 percent share of ONEOK Partners’ accumulated other comprehensive income (loss) in our consolidated accumulated other comprehensive income (loss). The remaining 54.3 percent is reflected as an adjustment to minority interests in consolidated subsidiaries.revision become known.
Cash and Cash Equivalents - Cash equivalents consist of highly liquid investments, which are readily convertible into cash and have original maturities of three months or less.
Short-Term InvestmentsAccounts Receivable, net - Our short-term investments consistAccounts receivable represent valid claims against non-affiliated customers for products sold or services rendered, net of auction-rate securities, which are corporate or municipal bonds that have underlying long-term maturities. The interest rates are reset through auctions that are typically held every 7-35 days, at which timeallowances for doubtful accounts. We assess the securities can be sold. Short-term investments in auction-rate securities are used as partcredit worthiness of our counterparties on an ongoing basis and require security, including prepayments and other forms of cash management program. At December 31, 2007, we had no short-term investments.collateral, when appropriate. Outstanding customer receivables are regularly reviewed for possible non-payment indicators and allowances for doubtful accounts are recorded based upon management’s estimate of collectibility at each balance sheet date.
Inventories - Materials and supplies are valued at average cost. Noncurrent natural gas is classified as property and valued at cost. For our ONEOK Partners segment,Our current natural gas and NGLs in storage are determined using the lower of weighted-average cost or market method. Our Energy Services segment values currentNoncurrent natural gas in storage usingand NGLs are classified as property and valued at cost. Materials and supplies are valued at average cost. Through December 31, 2007, the lower of cost or market method. Cost of current natural gas in storage for Oklahoma Natural Gas iswas determined under the last-in, first-out (LIFO) methodology. The estimated replacement cost of current natural gas in storage was $72.4 million and $45.4 million at December 31, 2007, and 2006, respectively, compared with its value under the LIFO method of $85.4 million and $60.7 million at December 31, 2007 and 2006, respectively.2007. As of January 1, 2008, Oklahoma Natural Gas iswas required to change from LIFO to the weighted-average cost methodology based on a change in state law. The impact of this change on our consolidated financial statements iswas immaterial, as the actual cost of gas is recovered from our rate payers through our purchased gas recovery mechanism.
Natural Gas Imbalances and Commodity Exchanges - ImbalancesNatural gas imbalances and NGL exchanges are valued at market or their contractually stipulated rate. Imbalances and NGL exchanges are settled in cash or made up in-kind, subject to the terms of the pipelines’ tariffs or by agreement. In September 2005, the FASB ratified the consensus reached in
EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” EITF 04-13Counterparty” defines when a purchase and a sale of inventory with the same party that operates in the same line of business should be considered a single nonmonetary transaction. EITF 04-13 was effective for new arrangements that a company enters into in periods beginning after March 15, 2006. We completed our review ofreviewed the applicability of EITF 04-13 to our operations and determined that it did not have a material impact on our financial position or results of operations or financial position.operations.
Property, Plant and Equipment - - The following table sets forth our property, plant and equipment by segment, for the periods presented. | | | | | | | | | | | | December 31, | | | | | | 2007 | | 2006 | | | | | | (Thousands of dollars) | | | Non-Regulated | | | | | | | | | ONEOK Partners | | $ | 2,112,394 | | $ | 1,894,529 | | | Energy Services | | | 7,845 | | | 7,689 | | | Other | | | 177,356 | | | 166,430 | | | Regulated | | | | | | | | | ONEOK Partners | | | 2,323,977 | | | 1,529,923 | | | Distribution | | | 3,271,920 | | | 3,126,188 | | | Property, plant and equipment | | | 7,893,492 | | | 6,724,759 | | | Accumulated depreciation and amortization | | | 2,048,311 | | | 1,879,838 | | | Net property, plant and equipment | | $ | 5,845,181 | | $ | 4,844,921 | | | | |
Gas processing plants, natural gas liquids fractionation plants and all other
| | | December 31, | | | December 31, | | | | | 2008 | | | 2007 | | | | | (Thousands of dollars) | | | Non-Regulated | | | | | | | | ONEOK Partners | | $ | 2,465,369 | | | $ | 2,112,394 | | | Energy Services | | | 7,907 | | | | 7,845 | | | Other | | | 225,479 | | | | 177,356 | | | Regulated | | | | | | | | | | ONEOK Partners | | | 3,343,310 | | | | 2,323,977 | | | Distribution | | | 3,434,554 | | | | 3,271,920 | | | Property, plant and equipment | | | 9,476,619 | | | | 7,893,492 | | | Accumulated depreciation and amortization | | | 2,212,850 | | | | 2,048,311 | | | Net property, plant and equipment | | $ | 7,263,769 | | | $ | 5,845,181 | |
Our properties are stated at cost. Gas processing plants, natural gas liquids fractionation plants and all othercost which includes AFUDC. Generally, the cost of regulated property and equipment are depreciated using the straight-line method over the estimated useful life.Generally, we apply composite depreciation ratesretired or sold, plus removal costs, less salvage, is charged to functional groups of property having similar economic circumstances.
At December 31, 2007, we had construction work in process of $954.3 million that had not yet been put in service and therefore was not being depreciated. Of this amount, $859.8 million was related to our ONEOK Partners segment, $51.3 million was related to our Distribution segment and $43.2 million was related to our Other segment.
Certain maintenance and repairs are charged directly to expense.accumulated depreciation. Gains and losses from sales or transfers of non-regulated properties or an entire operating unit or system of our regulated properties are recognized in income.
Maintenance and repairs are charged directly to expense.
The interest portion of AFUDC represents the cost of borrowed funds used to finance construction activities. We capitalize interest expense during the construction or upgrade of qualifying assets. Interest expense capitalized in 2008, 2007 and 2006 was $15.7$39.9 million, which was$15.4 million and $2.0 million, respectively. Capitalized interest is recorded as a reduction to interest expense, and was not material in 2006 or 2005.Regulated properties are stated at cost, which includes the equity portion of AFUDC.expense. The equity portion of AFUDC represents the capitalization of the estimated average cost of equity used during the construction of major projects and is recorded in the cost of our regulated properties and as a credit to the allowance for equity funds used during construction.
Our properties are depreciated using the straight-line method over their estimated useful lives. Generally, the costwe apply composite depreciation rates to functional groups of property retiredhaving similar economic circumstances. We periodically conduct depreciation studies to assess the economic lives of our assets. For our regulated assets, these deprecation studies are completed as a part of our rate proceedings, and the changes in economic lives, if applicable, are implemented prospectively when the new rates are billed. For our non-regulated assets, if it is determined that the estimated economic life changes, then the changes are made prospectively. Changes in the estimated economic lives of our property, plant and equipment could have a material effect on our financial position or sold, plus removal costs, less salvage, is charged to accumulated depreciation.result of operations.
The average depreciation rates for our regulated property are set forth in the following table for the periods indicated. | | | | | | | | | | | | Years Ended December 31, | | | | Regulated Property | | 2007 | | 2006 | | 2005 | | | ONEOK Partners | | 2.4% - 2.5% | | 2.4% - 2.6% | | 2.7% | | | Distribution | | 2.7% - 3.0% | | 2.7% - 3.3% | | 2.8% - 3.3% | | |
Environmental Expenditures - We accrue
| | | Years Ended December 31, | | | Regulated Property | | 2008 | | | 2007 | | | 2006 | | | ONEOK Partners | | | 2.0% - 2.4 | % | | | 2.4% - 2.5 | % | | | 2.4% - 2.6 | % | | Distribution | | | 2.7% - 3.0 | % | | | 2.7% - 3.0 | % | | | 2.7% - 3.3 | % |
ONEOK Partners’ average depreciation rates for losses associatedits regulated property decreased in 2008, compared with environmental remediation obligations2007, due to placing newly constructed natural gas liquids pipeline assets with longer economic lives in service.
Property, plant and equipment on our Consolidated Balance Sheets includes construction work in process for capital projects that have not yet been put in service and therefore are not being depreciated. The following table sets forth our construction work in process, by segment, for the periods presented.
| | | December 31, | | | December 31, | | | | | 2008 | | | 2007 | | | | (Millions of dollars) | | ONEOK Partners | | $ | 810.0 | | | $ | 859.8 | | | Distribution | | | 57.0 | | | | 51.3 | | | Other | | | 11.0 | | | | 7.1 | | | Total construction work in process | | $ | 878.0 | | | $ | 918.2 | |
Assets are transferred out of construction work in process when such lossesthey are probablesubstantially complete and reasonably estimable. Accrualsready for estimated losses from environmental remediation obligations generally are recognized no later than completiontheir intended use, in accordance with Statement 34, “Capitalization of the remedial feasibility study. Such accruals are adjusted as further information becomes available or circumstances change. Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable.Interest Cost.”
Revenue Recognition - Our ONEOK Partners segment includes natural gas gathering and processing, natural gas liquids gathering and fractionation, natural gas pipelines, and natural gas liquids pipelines operations. ONEOK Partners’ natural gas gathering and processing operations record revenue when gas is processed in or transported through company facilities. ONEOK Partners’ natural gas liquids gathering and fractionation operations record operating revenues based upon contracted services and actual volumes exchanged or stored under service agreements in the month services are provided. Operating revenueRevenue for ONEOK Partners’ natural gas pipelines and natural gas liquids pipelines operations is recognized based upon contracted capacity and contracted volumes transported and stored under service agreements in the period services are provided.
Our Distribution segment recognizes revenue when services are rendered or product is delivered. Majorsegment’s major industrial and commercial natural gas distribution customers are invoiced as of the end of each month. All natural gas residential distribution customers and some commercial customers are invoiced on a cyclical basis throughout the month, and we accrue unbilled revenues at the end of each month.
Our Energy Services segment recognizes revenue when services are rendered or product is delivered. Wholesale and retailsegment’s wholesale customers are invoiced as of the end of each month based on physical sales. Retail customers are invoiced on a cyclical basis throughout the month, and we accrue unbilled revenues at the end of each month. Demand payments received for requirements contracts are recognized in the period in which the service is provided. Our fixed-price physical sales are accounted for as derivatives and are recorded at fair value. Demand payments received for a requirements contract are recognized in the period in which the service is provided. See Note D “Accounting Treatment” for additional information. Accounts receivable from customers are reviewed regularly for collectibility. An allowance for doubtful accounts is recorded in situations where collectibility is not reasonably assured.
Income Taxes - Income taxes are accounted for using the provisions of Statement 109, “Accounting for Income Taxes.” Deferred income taxes are provided for the difference between the financial statement and income tax basis of assets and liabilities and carry forward items, based on income tax laws and rates existing at the time the temporary differences are expected to reverse. The effect on deferred taxes of a change in tax rates is deferred and amortized for operations regulated by the OCC, KCC, RRC and various municipalities in Texas. For all other operations, the effect is recognized in income in the period that includes the enactment date. We continue to amortize previously deferred investment tax credits for ratemaking purposes over the period prescribed by the OCC, KCC, RRC and various municipalities in Texas.
In June 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes - An Interpretation of FASB Statement No. 109,” which was effective for our year beginning January 1, 2007. This interpretation was issued to clarify the accounting for uncertainty in income taxes recognized in the financial statements by prescribing a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 requires the recognition of penalties and interest on any unrecognized tax benefits. Our policy is to reflect penalties and interest as part of income tax expense as they become applicable. The adoption of FIN 48 had an immaterial impact on our consolidated financial statements.statements, and the impact for 2008 and 2007 was not material.
We file numerous consolidated and separate income tax returns in the United States federal jurisdiction and in many state jurisdictions. We also file returns in Canada. No returns are currently under audit, and no extensions of statute of limitations have been requested or granted. Our 2007 and 2006 United States federal income tax returns are currently under audit.
Regulation- Our distribution operations and ONEOK Partners’ intrastate natural gas transmission pipelines are subject to the rate regulation and accounting requirements of the OCC, KCC, RRC and various municipalities in Texas. OtherONEOK Partners’ interstate natural gas and natural gas liquids transportation activitiespipelines are subject to regulation by the FERC. In Kansas and Texas, natural gas storage may be regulated by the state and the FERC for certain types of services. Oklahoma Natural Gas, Kansas Gas Service, Texas Gas Service and portions of our ONEOK Partners segment follow the accounting and reporting guidance contained in Statement 71, “Accounting for the Effects of Certain Types of Regulation.” During the rate-making process, regulatory authorities may requireset the framework for what we can charge customers for our services and establish the manner that our costs are accounted for, including allowing us to defer recognition of certain costs to be recoveredand permitting recovery of the amounts through rates over time as opposed to expensing such costs as incurred. Certain examples of types of regulatory guidance include costs for fuel and losses, acquisition costs, contributions in aid of construction, charges for depreciation, and gains or losses on disposition of assets. This allows us to stabilize rates over time rather than passing such costs on to the customer for immediate recovery. Accordingly, actions of theActions by regulatory authorities could have an affect on the amount recovered from rate payers. Any difference in the amount recoverable and the amount deferred would beis recorded as income or expense at the time of the regulatory action. If all or a portion of the regulated operations becomesare no longer subject to the provisions of Statement 71, a write-off of regulatory assets and stranded costs not recovered may be required.
At December 31, 2008 and 2007, we hadrecorded regulatory assets thatof approximately $523.3 million and $309.4 million, respectively, which are being recovered through various rate cases in the amountor are expected to be recovered. Regulatory assets are being recovered as a result of $309.4 million, includedapproved rate proceedings over varying time periods up to 40 years. These assets are reflected in other assets on our 2007 Consolidated Balance Sheet.Sheets.
Asset Retirement Obligations - Statement 143, “Accounting for Asset Retirement Obligations”Obligations,” applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. Statement 143 requires that we recognize the fair value of a liability for an asset retirement obligation in the period when it is incurred if a reasonable estimate of the fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset, and this additional carrying amount is depreciated over the life of the asset. The liability is accreted at the end of each period through charges to operating expense. If the obligation is settled for an amount other than the carrying amount of the liability, we will recognize a gain or loss on settlement. The depreciation and amortization expense is immaterial to our consolidated financial statements.
In accordance with long-standing regulatory treatment, we collect through rates the estimated costs of removal on certain regulated properties through depreciation expense, with a corresponding credit to accumulated depreciation and amortization. These removal costs are non-legal obligations as defined by Statement 143. However, these non-legal asset removalasset-removal obligations should beare accounted for as a regulatory liability under Statement 71. Historically, the regulatory authorities that have jurisdiction over our regulated operations have not required us to track this amount; rather, these costs are addressed prospectively as depreciation rates and are set in each general rate order. We have made an estimate of our removal cost liability using current rates since the last general rate order in each of our jurisdictions. However, significant uncertainty exists regarding the ultimate determination of this liability, pending, among other issues, clarification of regulatory intent. We continue to monitor the regulatory authorities and the liability may be adjusted as more information is obtained. We have reclassified the estimated non-legal asset removal obligation from accumulated deprecation and amortization to non-current liabilities in other deferred credits on our Consolidated Balance Sheets. To the extent this estimated liability is adjusted, such amounts will be reclassified between accumulated depreciation and amortization and other deferred credits and therefore will not have an impact on earnings.
Share-Based Payment- In December 2004, the FASB issued Statement 123R, “Share-Based Payment,” which requires companies to expense the fair value of share-based payments net of estimated forfeitures. We adopted Statement 123R as of January 1, 2006, and elected to use the modified prospective method. Statement 123R did not have a material impact on our consolidated financial statements as we have been expensing share-based payments since our adoption of Statement 148, “Accounting for Stock-Based Compensation - Transition and Disclosure,” on January 1, 2003. Awards granted after the adoption of Statement 123R are expensed under the requirements of Statement 123R, while equity awards granted prior to the adoption of Statement 123R will continue to be expensed under Statement 148. Earnings per Common Share - Basic EPS is calculated based on the daily weighted averageweighted-average number of shares of common stock outstanding during the period. Diluted EPS is calculated based on the daily weighted averageweighted-average number of shares of common stock outstanding during the period plus potentially dilutive components. The dilutive components are calculated based on the dilutive effect for each quarter. For fiscal year periods, the dilutive components for each quarter are averaged to arrive at the fiscal year-to-date dilutive component.
Other
Use of EstimatesMaster Netting Arrangements - The preparation of our consolidated financial statements and related disclosures in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions that cannot be known with certainty that affect the reported amount of assets and liabilities, and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements. These estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Items that may be estimated include, but are not limited to, the economic useful life of assets, fair value of assets and liabilities, obligations under employee benefit plans, provisions for uncollectible accounts receivable, unbilled revenues for natural gas delivered but for which meters have not been read, gas purchased expense for natural gas purchased but for which no invoice has been received, provision for income taxes including any deferred tax valuation allowances, the results of litigation and various other recorded or disclosed amounts.We evaluate these estimates on an ongoing basis using historical experience, consultation with experts and other methods we consider reasonable based on the particular circumstances. Nevertheless, actual results may differ significantly from the estimates. Any effects on our financial position or results of operations from revisions to these estimates are recorded in the period when the facts that give rise to the revision become known.
Other
Fair Value Measurements - In September 2006, the FASB issued Statement 157, “Fair Value Measurements,” which establishes a framework for measuring fair value and requires additional disclosures about fair value measurements. Beginning January 1, 2008, we partially applied Statement 157 as allowed by FASB Staff Position (FSP) 157-2, which delayed the effective date of Statement 157 for nonfinancial assets and liabilities. As of January 1, 2008, we have applied the provisions of Statement 157 to our financial instruments and the impact was not material. Under FSP 157-2, we will be required to apply Statement 157 to our nonfinancial assets and liabilities beginning January 1, 2009. We are currently reviewing the applicability of Statement 157 to our nonfinancial assets and liabilities as well as the potential impact on our consolidated financial statements.
In February 2007, the FASB issued Statement 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” which allows companies to elect to measure specified financial assets and liabilities, firm commitments, and nonfinancial warranty and insurance contracts at fair value on a contract-by-contract basis, with changes in fair value recognized in earnings each reporting period. At January 1, 2008, we did not elect the fair value option under Statement 159 and therefore there was no impact to our consolidated financial statements.
In April 2007, the FASB issued Staff Position No.FSP FIN 39-1, “Amendment of FASB Interpretation No. 39,” which permits companiesrequires entities that enter intooffset the fair value amounts recognized for derivative receivables and payables to also offset the fair value amounts recognized for the right to reclaim cash collateral with the same counterparty under a master netting arrangements to offset cash collateral receivables or payables with net derivative positions under certain circumstances. FIN 39-1 is effective for our year beginning January 1, 2008.arrangement. We have reviewedapplied the applicabilityprovisions of FSP FIN 39-1 to our operations and its potential impact on our consolidated financial statements beginning January 1, 2008, and have concluded the impact is immaterial. was not material. See Note C for applicable disclosures.
Business Combinations - In December 2007, the FASB issued Statement 141R, “Business Combinations,” which will require most identifiable assets, liabilities, noncontrolling interest (previously referred to as minority interests)interest) and goodwill acquired in a business combination to be recorded at full fair value. Statement 141R iswas effective for our year beginning January 1, 2009, and will be applied prospectively. We are currently reviewing2009. Because the applicabilityprovisions of Statement 141R toare applied prospectively, our operations2009 and its potential impact on oursubsequent consolidated financial statements.statements will not be impacted unless we complete a business combination.
Noncontrolling Interests - In December 2007, the FASB issued Statement 160, “Noncontrolling Interest in Consolidated Financial Statements - an amendment to ARB No. 51,” which requires a noncontrolling interestsinterest (previously referred to as minority interests)interest) to be reported as a component of equity. Statement 160 iswas effective for our year beginning January 1, 2009, and will requirerequires retroactive adoption of the presentation and disclosure requirements for existing minority interests. We are currently reviewing the applicability ofinterests beginning with our March 31, 2009, Quarterly Report on Form 10-Q. Statement 160 is not expected to have a material impact on our operationsconsolidated financial statements; however, certain financial statement presentation changes and its potentialadditional required disclosures will be made.
Derivative Instruments and Hedging Activities Disclosure - In March 2008, the FASB issued Statement 161, “Disclosures about Derivative Instruments and Hedging Activities - an amendment to FASB Statement No. 133,” which requires enhanced disclosures about how derivative and hedging activities affect our financial position, financial performance and cash flows. Statement 161 was effective for our year beginning January 1, 2009, and will be applied prospectively beginning with our March 31, 2009, Quarterly Report on Form 10-Q.
Equity Method Investments - In November 2008, the FASB ratified EITF 08-6, “Equity Method Investment Accounting Considerations,” which clarified certain issues that arose following the issuance of Statements 141R and 160 related to the accounting for equity method investments. EITF 08-6 was effective for our year beginning January 1, 2009, and is not expected to have a material impact on our consolidated financial statements.
Postretirement Benefit Plan Assets - In December 2008, the FASB issued FSP FAS 132R-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets,” which amends Statement 132R, “Employers’ Disclosures about Pensions and Other Postretirement Benefits,” to require enhanced disclosures about our plan assets, including our investment policies, major categories of plan assets, significant concentrations of risk within plan assets, and inputs and valuation techniques used to measure the fair value of plan assets. FSP FAS 132R-1 is effective for our fiscal year ending December 31, 2009, and will be applied prospectively.
Reclassifications- Certain amounts in our consolidated financial statements have been reclassified to conform to the 20072008 presentation. These reclassifications did not impact previously reported net income or shareholders’ equity.
B. ACQUISITIONS AND DIVESTITURES
B.
| ACQUISITIONS AND DIVESTITURES |
Acquisition of NGL Pipeline - In October 2007, ONEOK Partners completed the acquisition of an interstate natural gas liquids and refined petroleum products pipeline system and related assets from a subsidiary of Kinder Morgan Energy Partners, L.P. (Kinder Morgan) for approximately $300 million, before working capital adjustments. The system extends from Bushton and Conway, Kansas, to Chicago, Illinois, and transports, stores and delivers a full range of NGL and refined petroleum products. The FERC-regulated system spans 1,6271,624 miles and has a capacity to transport up to 134 MBbl/d. The transaction includesalso included approximately 978 MBbl of owned storage capacity, eight NGL terminals and a 50 percent ownership of Heartland. ConocoPhillips owns the other 50 percent of Heartland and is the managing partner of the Heartland joint venture, which consists primarily of threea refined petroleum products terminalsterminal and connecting pipelines.pipelines with access to two other refined petroleum products terminals. ONEOK Partners’ investment in Heartland is accounted for under the equity method of accounting. Financing for this transaction came from a portion of the proceeds of ONEOK Partners’ September 2007 issuance of $600 million 6.85 percent Senior Notes due 2037 (the 2037 Notes). See Note I for a discussion of the 2037 Notes. The working capital settlement has not been finalized; however, ONEOK Partners does not expectwas finalized in April 2008, with no material adjustments.
Overland Pass Pipeline Company - - In May 2006, a subsidiary of ONEOK Partners entered into an agreement with a subsidiary of The Williams Companies, Inc. (Williams) to form a joint venture called Overland Pass Pipeline Company. In November 2008, Overland Pass Pipeline Company is buildingcompleted construction of a 760-mile natural gas liquids pipeline from Opal, Wyoming, to the Mid-Continent natural gas liquids market center in Conway, Kansas. The pipelineOverland Pass Pipeline is designed to transport approximately 110 MBbl/d of unfractionated NGLs whichand can be increased to approximately 150255 MBbl/d with additional pump facilities. During 2006, ONEOK Partners paid $11.6 million to Williams for the acquisition of its interest in the joint venture and for reimbursement of initial capital expenditures. A subsidiary of ONEOK Partners owns 99 percent of the joint venture, and will managemanaged the construction project, advanceadvanced all costs associated with construction and operateis currently operating the pipeline. Within two years of the pipeline becoming operational,On or before November 17, 2010, Williams will have the option to increase its ownership up to 50 percent, by reimbursing ONEOK Partners for its proportionate share of all construction costs.with the purchase price being determined in accordance with the joint venture’s operating agreement. If Williams exercises its option to increase its ownership to the full 50 percent, Williams would have the option to become operator. ThisThe pipeline project has received the required approvals of various state and federal regulatory authorities, and ONEOK Partners is constructing the pipeline with start-up currently scheduled for the second quarter 2008.cost was approximately $575 million, excluding AFUDC.
As part of a long-term agreement, Williams dedicated its NGL production from two of its natural gas processing plants in Wyoming to the joint-venture company.Overland Pass Pipeline. Subsidiaries of ONEOK Partners will provide downstream fractionation, storage and transportation services to Williams. The pipeline project is currently estimated to cost approximately $535 million, excluding AFUDC. In addition,
ONEOK Partners is investing approximately $216 million, excluding AFUDC, to expand its existing fractionation and storage capabilities and the capacity of its natural gas liquids distribution pipelines. ONEOK Partners’ financing for the projects may include a combination of short- or long-term debt or equity.ONEOK Partners - In April 2006, we sold certain assets comprising our former gathering and processing, natural gas liquids, and pipelines and storage segments to ONEOK Partners for approximately $3 billion, including $1.35 billion in cash, before adjustments, and approximately 36.5 million Class B limited partner units in ONEOK Partners. The Class B limited partner units and the related general partner interest contribution were valued at approximately $1.65 billion. We also purchased, through ONEOK Partners GP, from an affiliate of TransCanada, 17.5 percent of the general partner interest in ONEOK Partners for $40 million. This purchase resulted in our owningownership of the entire 2 percent general partner interest in ONEOK Partners. Following the completion of the transactions, we ownowned a total of approximately 37.0 million common and Class B limited partner units and the entire 2 percent general partner interest and control the partnership. Our overall interest in ONEOK Partners, including the 2 percent general partner interest, iswas 45.7 percent.percent at the date of acquisition.
Disposition of 20 percent interest in Northern Border Pipeline - In April 2006, in connection with the transactions described immediately above, our ONEOK Partners segment completed the sale of a 20 percent partnership interest in Northern Border Pipeline to TC PipeLines for approximately $297 million. Our ONEOK Partners segment recorded a gain on the sale of approximately $113.9 million in the second quarter of 2006. ONEOK Partners and TC PipeLines each now own a 50 percent interest in Northern Border Pipeline, and an affiliate of TransCanada became operator of the pipeline in April 2007. Neither ONEOK Partners nor TC PipeLines has control of Northern Border Pipeline, as control is shared equally through Northern Border Pipeline’s Management Committee. As a result of this transaction, ONEOK Partners’ interest in Northern Border Pipeline ishas been accounted for as an investment under the equity method, applied on a retroactive basis to January 1, 2006.
Acquisition of Guardian Pipeline Interests - In April 2006, our ONEOK Partners segment acquired the 66-2/3 percent interest in Guardian Pipeline not previously owned by ONEOK Partners for approximately $77 million, increasing its ownership interest to 100 percent. ONEOK Partners used borrowings from its credit facility to fund the acquisition of the additional interest in Guardian Pipeline. Following the completion of the transaction, we consolidated Guardian Pipeline in our consolidated financial statements. This change was accounted for on a retroactive basis to January 1, 2006.
C. FAIR VALUE MEASUREMENTS
See Note A for a discussion of our Spring Creek power plant, located in Oklahoma, to Westar Energy, Inc. (Westar) for $53 million. The transaction received FERC approvalfair value measurements and the sale was completedfair value hierarchy.
Recurring Fair Value Measurements - The following table sets forth our recurring fair value measurements for the period indicated.
| | | December 31, 2008 | | | | | Level 1 | | | Level 2 | | | Level 3 | | | Netting (a) | | | Total | | | | | (Thousands of dollars) | | | Assets | | | | | | | | | | | | | | | | | Derivatives | | $ | 580,029 | | | $ | 215,116 | | | $ | 454,377 | | | $ | (840,814 | ) | | $ | 408,708 | | | Trading securities | | | 4,910 | | | | - | | | | - | | | | - | | | | 4,910 | | | Available-for-sale investment securities | | | 1,665 | | | | - | | | | - | | | | - | | | | 1,665 | | | Fair value of firm commitments | | | - | | | | - | | | | 42,179 | | | | - | | | | 42,179 | | | Total assets | | $ | 586,604 | | | $ | 215,116 | | | $ | 496,556 | | | $ | (840,814 | ) | | $ | 457,462 | | | | | | | | | | | | | | | | | | | | | | | | | Liabilities | | | | | | | | | | | | | | | | | | | | | | Derivatives | | $ | (501,726 | ) | | $ | (55,705 | ) | | $ | (412,022 | ) | | $ | 748,136 | | | $ | (221,317 | ) | | Long-term debt swapped to floating | | | - | | | | - | | | | (171,455 | ) | | | - | | | | (171,455 | ) | | Total liabilities | | $ | (501,726 | ) | | $ | (55,705 | ) | | $ | (583,477 | ) | | $ | 748,136 | | | $ | (392,772 | ) | (a) - Our derivative assets and liabilities are presented in our Consolidated Balance Sheets on a net basis. We net derivative assets and liabilities, including cash collateral in accordance with FSP FIN 39-1, when a legally enforceable master netting arrangement exists between us and the counterparty to a derivative contract. At December 31, 2008, we held $92.7 million of cash collateral. | |
For derivatives for which fair value is determined based on October 31, 2006. The 300-megawatt gas-fired merchant power plant was built in 2001 to supply electrical power during peak periods using gas-powered turbine generators. The financial information relatedmultiple inputs, Statement 157 requires that the measurement for an individual derivative be categorized within a single level based on the lowest-level input that is significant to the properties sold is reflectedfair value measurement in its entirety.
Our Level 1 fair value measurements are based on NYMEX-settled prices, actively quoted prices for equity securities and foreign currency forward exchange rates. These balances are predominantly comprised of exchange-traded derivative contracts, including futures and certain options for natural gas and crude oil, that are valued based on unadjusted quoted prices in active markets. Also included in Level 1 are available-for-sale and trading securities and foreign currency forwards.
Our Level 2 fair value inputs are based on NYMEX-settled prices that are utilized to determine the fair value of certain non-exchange-traded financial instruments, including natural gas and crude oil swaps.
Our Level 3 inputs are based on over-the-counter quotes, market volatilities derived from NYMEX-settled prices, internally developed basis curves incorporating observable and unobservable market data, modeling techniques using observable market data and historical correlations of NGL product prices to crude oil, and spot and forward LIBOR curves. The derivatives categorized as a discontinued componentLevel 3 include over-the-counter swaps and options for natural gas and crude oil, NGL swaps and forwards, natural gas basis and swing swaps and physical forward contracts, and interest-rate swaps. Also included in our consolidated financial statements. All periods presentedLevel 3 are the fair values of firm commitments and long-term debt that have been restated to reflecthedged.
Transfers in and out of Level 3 typically result from derivatives for which fair value is determined based on multiple inputs. Since we categorize our derivatives based on the discontinued component. See Note C for additional information.Dispositionlowest level input that is significant, a derivative can move between Level 2 and Level 3 as the value of Production Segmentthe various inputs changes.
- In September 2005, we completed86 - -
The following table sets forth the salereconciliation of our former production segmentLevel 3 fair value measurements for the period indicated.
| | | Derivative Assets (Liabilities) | | | Fair Value of Firm Commitments | | | Long-Term Debt | | | Total | | | | | (Thousands of dollars) | | | January 1, 2008 | | $ | (54,582 | ) | | $ | 42,684 | | | $ | (338,538 | ) | | $ | (350,436 | ) | | Total realized/unrealized gains (losses): | | | | | | | | | | | | | | | | | | Included in earnings (a) | | | 6,080 | | | | (505 | ) | | | (2,917 | ) | | | 2,658 | | Included in other comprehensive income (loss) | | | 84,592 | | | | - | | | | - | | | | 84,592 | | | Terminations prior to maturity | | | (5,074 | ) | | | - | | | | 170,000 | | | | 164,926 | | | Transfers in and/or out of Level 3 | | | 11,339 | | | | - | | | | - | | | | 11,339 | | | December 31, 2008 | | $ | 42,355 | | | $ | 42,179 | | | $ | (171,455 | ) | | $ | (86,921 | ) | | | | | | | | | | | | | | | | | | | Total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities still held as of December 31, 2008 (a) | | $ | (116,127 | ) | | $ | 153,221 | | | $ | (2,917 | ) | | $ | 34,177 | | | (a) - Reported in revenues in our Consolidated Statements of Income. | | | | | | | | | | | | | |
Realized/unrealized gains (losses) include the realization of our fair value derivative contracts through maturity, changes in fair value of our hedged firm commitments and fixed-rate debt swapped to TXOK Acquisition, Inc.floating. Terminations prior to maturity represents swap contracts terminated prior to maturity that will remain in accumulated other comprehensive income (loss) until the underlying forecasted transaction occurs; and the long-term debt associated with the interest rate swaps that were terminated during the period. Transfers into Level 3 represent existing assets or liabilities that were previously categorized at a higher level for $645 million, before adjustments,which the inputs to our models became unobservable. Transfers out of Level 3 represent existing assets and liabilities that were previously classified as Level 3 for which the inputs became observable in accordance with our hierarchy policy discussed on page 78.
Fair Value - The following table represents the fair value of our energy marketing and risk management assets and liabilities for the periods indicated.
| | | December 31, 2008 | | | December 31, 2007 | | | | | Assets | | | Liabilities | | | Assets | | | Liabilities | | | | | (Thousands of dollars) | | | Energy Services - financial non-trading instruments: | | | | | | | | | | | | | | Natural gas | | | | | | | | | | | | | | Exchange-traded instruments | | $ | 31,509 | | | $ | 640 | | | $ | 4,739 | | | $ | 14,853 | | | Over-the-counter swaps | | | 73,095 | | | | 1,624 | | | | 41,633 | | | | 19,160 | | | Options | | | 186 | | | | - | | | | 1,887 | | | | 2,467 | | | Other (a) | | | 39,453 | | | | 2,515 | | | | 7,469 | | | | 2,741 | | | | | | 144,243 | | | | 4,779 | | | | 55,728 | | | | 39,221 | | | Energy Services - financial trading instruments: | | | | | | | | | | | | | | | | | | Natural gas | | | | | | | | | | | | | | | | | | Exchange-traded instruments | | | 6,158 | | | | 144 | | | | 1,641 | | | | 888 | | | Over-the-counter swaps | | | 14,002 | | | | 321 | | | | 11,258 | | | | 8,013 | | | Options | | | 7,043 | | | | 191 | | | | 14,173 | | | | 18,654 | | | Other (a) | | | 358 | | | | 249 | | | | 420 | | | | 287 | | | | | | 27,561 | | | | 905 | | | | 27,492 | | | | 27,842 | | | ONEOK Partners - cash flow hedges | | | 63,780 | | | | - | | | | - | | | | 21,304 | | | Distribution - natural gas swaps | | | - | | | | 23,003 | | | | - | | | | 9,752 | | | Energy Services - cash flow hedges | | | 62,250 | | | | 44,248 | | | | 57,966 | | | | 8,344 | | | Energy Services - fair value hedges | | | 109,419 | | | | 148,382 | | | | 5,237 | | | | 51,343 | | | Interest rate swaps - fair value hedges | | | 1,455 | | | | - | | | | 1,496 | | | | 2,958 | | | | | | | | | | | | | | | | | | | | | Total fair value | | $ | 408,708 | | | $ | 221,317 | | | $ | 147,919 | | | $ | 160,764 | | | (a) - Other includes physical natural gas. | | | | | | | | | | | | | | | | |
Financial Instruments - The following information represents the carrying amounts and estimated fair values of our financial instruments for the periods indicated, excluding energy marketing and risk management assets and liabilities, which are listed in the table above.
The approximate fair value of cash and cash equivalents, short-term investments, accounts and notes receivable and accounts and notes payable is equal to book value, due to their short-term nature. The estimated fair value of long-term debt has been determined using quoted market prices of the same or similar issues, discounted cash flows, and/or rates currently available to us for debt with similar terms and remaining maturities. The book value of our long-term debt was $4.23 billion and $4.64 billion at December 31, 2008 and 2007, respectively. The approximate fair value of our long-term debt was $3.95 billion and $4.75 billion at December 31, 2008 and 2007, respectively.
The tables below show information about our investment securities classified as available-for-sale.
| | | December 31, | | | | | 2008 | | | 2007 | | | 2006 | | | | (Thousands of dollars) | | | Available-for-sale securities held | | | | | | | | | | | Aggregate fair value | | $ | 1,665 | | | $ | 24,151 | | | $ | 22,416 | | Reported in accumulated other comprehensive income (loss) for net unrealized holding gains | | $ | 815 | | | $ | 13,678 | | | $ | 12,614 | |
| | | Years Ended December 31, | | | | | 2008 | | | 2007 | | | 2006 | | | | | (Thousands of dollars) | | | Available-for-sale securities held | | | | | | | | | | Gains reclassified to earnings from accumulated other comprehensive income (loss) | | $ | 11,142 | | | $ | - | | | $ | - | | | | | | | | | | | | | | | | | Available-for-sale securities sold | | | | | | | | | | | | | | Proceeds from sale (a) | | $ | 3,886 | | | $ | - | | | $ | - | | | Gain from sale (a) | | $ | 3,369 | | | $ | - | | | $ | - | | (a) - We sold a portion of our available-for-sale securities and used specific identification to determine the cost of the securities sold. | |
We transferred securities from available-for-sale to trading during the year ended December 31, 2008, and recognized a pre-tax$7.7 million gain, due to a reconsideration event in August 2008 when our NYMEX Holding, Inc. Class A shares held were converted to CME Group, Inc. (CME) Class A shares due to the NYMEX Holding, Inc. and CME merger. A modification was made to the number of shares required to be maintained by NYMEX Holding, Inc. Class A Members which resulted in our sale of certain shares and the reclassification of the remaining shares to trading. These trading securities were still held as of December 31, 2008.
The gains reclassified into earnings from accumulated other comprehensive income (loss) for the year ended December 31, 2008, of $11.1 million include the $7.7 million gain discussed in the previous paragraph, as well as a $3.4 million realized gain on the sale of approximately $240.3 million. The gain reflects the cash received less adjustments, selling expenses and the net book value of the assets sold. The proceeds from the sale were used to reduce debt. The financial information related to the properties sold is reflected as a discontinued component in our consolidated financial statements. All periods presented have been restated to reflect the discontinued component. See Note C for additional information.available-for-sale securities.
D. ENERGY MARKETING AND RISK MANAGEMENT ACTIVITIES
Acquisition of Koch Industries Natural Gas Liquids Business - In July 2005, we completed the acquisition of the natural gas liquids businesses owned by several affiliates and a subsidiary of Koch Industries, Inc. (Koch) for approximately $1.33 billion, net of working capital and cash received. This transaction included Koch Hydrocarbon, LP’s entire Mid-Continent natural gas liquids fractionation business; Koch Pipeline Company, L.P.’s natural gas liquids pipeline distribution systems; Chisholm Pipeline Holdings, Inc., now Chisholm Pipeline Holdings, L.L.C., which has a 50 percent ownership interest in Chisholm Pipeline Company; MBFF, L.P., now ONEOK MBI, L.P., which owns an 80 percent interest in a 160 MBbl/d fractionator at Mont Belvieu, Texas; and Koch Vesco Holdings, L.L.C., now ONEOK Vesco Holdings, L.L.C., an entity that owns a 10.2 percent interest in Venice Energy Services Company, L.LC. These assets are included in our consolidated financial statements beginning on July 1, 2005.The unaudited pro forma information in the table below presents a summary of our consolidated results of operations as if the acquisition of the Koch natural gas liquids businesses had occurred at the beginning of the periods presented. The results do not necessarily reflect the results that would have been obtained if the acquisition had actually occurred on the dates indicated or results that may be expected in the future.
| | | | | | | | | Pro Forma Year Ended December 31, 2005 | | | | | | (Thousand of dollars, except per share amounts) | | | Net margin | | $ | 1,409,232 | | | Net income | | $ | 550,998 | | | Net earnings per share, basic | | $ | 5.48 | | | Net earnings per share, diluted | | $ | 5.10 | | |
Other - In December 2005, we sold our natural gas gathering and processing assets located in Texas to a subsidiary of Eagle Rock Energy, Inc. for approximately $527.2 million and recorded a pre-tax gain of $264.2 million, which is included in gain on sale of assets in our operating income. The gain reflects the cash received less adjustments, selling expenses and the net book value of the assets sold.
C. | DISCONTINUED OPERATIONS |
In September 2005, we completed the sale of our former production segment to TXOK Acquisition, Inc. for $645 million, before adjustments, and recognized a pre-tax gain on the sale of approximately $240.3 million. The gain reflects the cash received less adjustments, selling expenses and the net book value of the assets sold. The proceeds from the sale were used to reduce debt. Our Board of Directors authorized management to pursue the sale in July 2005, which resulted in our former production segment being classified as held for sale beginning July 1, 2005.
Additionally, in the third quarter of 2005, we made the decision to sell our Spring Creek power plant, located in Oklahoma, and exit the power generation business. In October 2005, we concluded that our Spring Creek power plant had been impaired and recorded an impairment expense of $52.2 million. We subsequently entered into an agreement to sell our Spring Creek power plant to Westar for $53 million. The transaction received FERC approval and the sale was completed on October 31, 2006. The 300-megawatt gas-fired merchant power plant was built in 2001 to supply electrical power during peak periods using gas-powered turbine generators.
At the time of the sale, we retained a contract with the Oklahoma Municipal Power Authority (OMPA) that required us to provide OMPA with 75 megawatts of firm capacity per month for a monthly fixed charge of approximately $0.4 million through December 31, 2015. To fulfill our obligations under this contract, we entered into an agreement with Westar to purchase 75 megawatts of firm capacity on the same terms as our agreement with OMPA. In an arbitration ruling dated October 11, 2007, our contract with OMPA was terminated as of that date and we were awarded payment for our services through that date. We are currently evaluating our alternatives with respect to our contract with Westar.
These components of our business are accounted for as discontinued operations in accordance with Statement 144. Accordingly, amounts in our consolidated financial statements and related notes for all periods shown relating to our former production segment and our power generation business are reflected as discontinued operations.
The amounts of revenue, costs and income taxes reported in discontinued operations are set forth in the table below for the periods indicated.
| | | | | | | | | | | | | | Years Ended
December 31, | | | | | | | 2006 | | | 2005 | | | | | | | (Thousands of dollars) | | | | Operating revenues | | $ | 10,646 | | | $ | 135,213 | | | | Cost of sales and fuel | | | 7,393 | | | | 38,398 | | | | Net margin | | | 3,253 | | | | 96,815 | | | | Impairment expense | | | - | | | | 52,226 | | | | Operating costs | | | 837 | | | | 24,302 | | | | Depreciation and amortization | | | - | | | | 17,919 | | | | Operating income | | | 2,416 | | | | 2,368 | | | | Other income (expense), net | | | - | | | | 252 | | | | Interest expense | | | 3,013 | | | | 12,588 | | | | Income taxes | | | (232 | ) | | | (3,788 | ) | | | Income (loss) from operations of discontinued components, net | | $ | (365 | ) | | $ | (6,180 | ) | | | | | Gain on sale of discontinued components, net of tax of $90.7 million | | $ | - | | | $ | 149,577 | | | |
D. | ENERGY MARKETING AND RISK MANAGEMENT ACTIVITIES AND FAIR VALUE OF FINANCIAL INSTRUMENTS |
Risk Policy and Oversight - Market risks are monitored by our risk control group that operates independently from the operating segments that create or actively manage these risk exposures. The risk control group ensuresis responsible for ensuring compliance with our risk management policies.
We control the scope of risk management, marketing and trading operations through a comprehensive set of policies and procedures involving senior levels of management. The Audit Committee of our Board of Directors has oversight responsibilities for our risk management limits and policies. Our risk oversight committee, comprised of corporate and business segment officers, oversees all activities related to commodity price and credit risk management, and marketing and trading activities. The committee also monitors risk metrics including value-at-risk (VAR) and mark-to-market losses. We have a corporate risk control organization that is assigned responsibility for establishing and enforcing the policies and procedures and monitoring certain risk metrics. Key risk control activities include credit review and approval, credit and performance risk measurement and monitoring, validation of transactions, portfolio valuation, VAR and other risk metrics.
Commodity and Interest Rate Risk Management Activities- Our operating results are affected by commodity price fluctuations. We routinely enter into derivative financial instruments to minimize the risk of commodity price fluctuations related to anticipated sales of natural gas and condensate, NGLs, purchase and sale commitments, fuel requirements, currency exposure, transportation and storage contracts, and natural gas inventories. We are also subject to the risk of interest rateinterest-rate fluctuations in the normal course of business. We manage interest rateinterest-rate risk through the use of fixed-rate debt, floating-rate debt and, at times, interest-rate swaps.
Our Energy Services segment includes our wholesale and retail natural gas marketing and financial trading operations. Our Energy Services segment generally attempts to managemitigates the commodity risk ofassociated with our fixed-price physical purchase and sale commitments through the use of derivative instruments. With respect to the net open positions that exist within our marketing and financial trading operations, fluctuating commodity market prices can impact our financial position and results of operations, either favorably or unfavorably. The net open positions are actively managed, and the impact of the changing prices on our financial condition at a point in time is not necessarily indicative of the impact of price movements throughout the year.
Operating margins associated with our ONEOK Partners segments’Partners’ natural gas gathering and processing and natural gas liquids gathering and fractionation activitiesbusinesses are sensitive to changes in natural gas, condensate and NGL prices, principally as a result of contractual terms under which natural gas is processed and products are sold. ONEOK Partners uses physical forward sales and derivative instruments to secure a certain price for natural gas, condensate and NGL products.
Our Distribution segment also uses derivative instruments to hedge the cost of anticipated natural gas purchases during the winter heating months to protect their customers from upward volatility in the market price of natural gas. Gains or losses associated with these derivative instruments are included in, and recoverable through, the monthly purchased gas cost mechanism.
Accounting Treatment- We account for derivative instruments and hedging activities in accordance with Statement 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended.133. Under Statement 133, entities are required to record all derivative instruments at fair value.value, with the exception of normal purchases and normal sales that are expected to result in physical delivery. 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, then we account for changes in fair value of the derivative instrument in earnings as they occur. We record changes in the fair value of derivative instruments that are considered held for trading purposes as energy trading revenues net and derivative instruments considered not held for trading purposes as cost of sales and fuel in our Consolidated Statements of Income. 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 during 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, which is reported in earnings during the period the ineffectiveness occurs. 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 accumulated other comprehensive income (loss) and is subsequently recorded toin earnings when the forecasted transaction affects earnings.
As required by Statement 133, we formally document 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. We specifically identify the asset, liability, firm commitment or forecasted transaction that has been designated as the hedged item. We assess the effectiveness of hedging relationships by performing a regression analysis on our cash flow and fair value hedging relationships quarterly to ensure the hedge relationships are highly effective on a retrospective and prospective basis, as required by Statement 133. We also document our normal physical purchases and physical sales transactions that we elect to exempt from fair value accounting treatment. Although we believe we have appropriate internal controls over our accounting for derivatives, interpreting Statement 133 and the related documentation requirements is very complex. In addition, future interpretations may impact our application of Statement 133. EITF 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ as Defined in EITF Issue No. 02-3,” 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 statementConsolidated Statements of Income 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.
We evaluate 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 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” are used to determine the proper treatment. These activities and all financially settled derivative contracts are 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,” are used to determine the proper treatment. We account for the realized revenues and purchase costs of these contracts that result in physical delivery on a gross basis. We apply the indicators in EITF 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.
Cash flows from futures, forwards, options and swaps that are accounted for as hedges are included in the same cash flow statement category as the cash flows from the related hedged items.
Fair Value Hedges - In 20072008 and prior years, we and ONEOK Partners terminated various interest-rate swap agreements. The net savings from the termination of these swaps areis being recognized in interest expense over the terms of the debt instruments originally hedged. Net interest expense savings for 2007 for all2008 from amortization of terminated swaps was $10.3$10.5 million, and the remaining net savings for all terminated swaps will be recognized over the following periods. | | | | | | | | | | | | | | | ONEOK | | ONEOK Partners | | Total | | | | | | (Millions of dollars) | | | 2008 | | $ | 6.7 | | $ | 3.7 | | $ | 10.4 | | | 2009 | | | 5.6 | | | 3.7 | | | 9.3 | | | 2010 | | | 5.5 | | | 3.7 | | | 9.2 | | | 2011 | | | 2.5 | | | 0.9 | | | 3.4 | | | 2012 | | | 0.8 | | | - | | | 0.8 | | | Thereafter | | | 12.0 | | | - | | | 12.0 | | |
| | | | | | ONEOK | | | | | | | | ONEOK | | | Partners | | | Total | | | | | (Millions of dollars) | | | 2009 | | $ | 6.5 | | | $ | 3.7 | | | $ | 10.2 | | | 2010 | | $ | 6.4 | | | $ | 3.7 | | | $ | 10.1 | | | 2011 | | $ | 3.4 | | | $ | 0.9 | | | $ | 4.3 | | | 2012 | | $ | 1.7 | | | $ | - | | | $ | 1.7 | | | 2013 | | $ | 1.7 | | | $ | - | | | $ | 1.7 | | | Thereafter | | $ | 25.3 | | | $ | - | | | $ | 25.3 | |
At December 31, 2007,2008, the interest on $340$170 million of our fixed-rate debt was swapped to floating using interest-rate swaps. The floating rate was based on both the three- and six-month LIBOR, depending upon the swap. Based on the actual performance throughfor the year ended December 31, 2007,2008, the weighted-average interest rate on the swapped debt increaseddecreased from 6.446.17 percent to 6.744.39 percent. At December 31, 2007,2008, we recorded a net liabilityasset of $1.5 million to recognize the interest-rate swaps at fair value. Long-term debt was decreased byincludes an additional $1.5 million to recognize the change in the fair value of the related hedged liability.debt. ONEOK Partners had no interest-rate swap agreements at December 31, 2008. See Note I for additional discussion of long-term debt.
Our Energy Services segment uses basis swaps to hedge the fair value of certain firm transportation commitments. Net gains or losses from the fair value hedges and ineffectiveness are recorded to cost of sales and fuel. The ineffectiveness related to these hedges included losses of $3.3 million, $5.3 million and $9.0 million for 2008, 2007 and 2006, respectively, and was not material in 2005.respectively.
In September 2007, our Energy Services segment was notified that a portion of the volume contracted under our firm transportation agreement with Cheyenne Plains Gas Pipeline Company would be curtailed due to a fire at a Cheyenne Plains pipeline compressor station. The fire damaged a significant amount of instrumentation and electrical wiring, causing Cheyenne Plains Gas Pipeline Company to declare a force majeure event on the pipeline. This firm commitment was hedged in accordance with Statement 133. The discontinuance of fair value hedge accounting on the portion of the firm commitment that was impacted by the force majeure event resulted in a loss of approximately $5.5 million.million in the third quarter of 2007, of which $2.4 million of insurance proceeds were recovered and recognized in the first quarter of 2008.
Cash Flow Hedges - Our Energy Services segment uses futures and swapsderivative instruments to hedge the cash flows associated with our anticipated purchases and sales of natural gas and the cost of fuel used in transportation of natural gas. Accumulated other comprehensive income (loss) at December 31, 2007,2008, includes gains of approximately $36.2$10.3 million, net of tax, related to these hedges that will be realized within the next 1724 months as forecasted transactions affect earnings. If prices remain at current levels, we will recognize $40.2$7.2 million in net gains over the next 12 months, and we will recognize net lossesgains of $4.0$3.1 million thereafter. In accordance with Statement 133, the actual gains or losses will be reclassified into earnings when the related physical transactions affect earnings. Our
During the third and fourth quarters of 2008, the carrying value of natural gas in storage was written down by $308.5 million in order to record inventory at the lower of cost or market. As required by Statement 133, we reclassified $298.8 million of deferred gains, before income taxes, on associated cash flow hedges from accumulated other comprehensive income (loss) into earnings.
Through an affiliate, our ONEOK Partners segment periodically enters into derivative instruments to hedge the cash flows associated with its exposure to changes in the price of natural gas, condensateNGLs and NGL products and the gross processing spread. If prices remain at current levels,condensate. At December 31, 2008, our ONEOK PartnersPartners’ segment will recognize $4.6reflected an unrealized gain of $20.1 million, net of tax, in net losses,accumulated other comprehensive income (loss), with a corresponding offset in energy marketing and risk management assets and liabilities, all of which will be recognized over the next 12 months. For all of our segments, net gains and losses are reclassified out of accumulated other comprehensive income (loss) to operating revenues or cost of sales and fuel in the period the ineffectiveness occurs.
Ineffectiveness related to our cash flow hedges resulted in gains of approximately $1.4 million, $0.2 million and $15.0 million in 2008, 2007 and 2006, respectively, and losses of approximately $33.9 million in 2005.respectively. In the event that it becomes probable that a forecasted transactions dotransaction will not occur, we would discontinue cash flow hedge treatment, which would affect earnings. There were no material gains or losses in 2008, 2007 2006 or 20052006 due to the discontinuance of cash flow hedge treatment.
Fair Value - The following table represents the fair value of our energy marketing and risk management assets and liabilities for the periods indicated. | | | | | | | | | | | | | | | | | | December 31, 2007 | | December 31, 2006 | | | | Assets | | Liabilities | | Assets | | Liabilities | | | | | | (Thousands of dollars) | | | Energy Services - financial non-trading instruments: | | | | | | | | | | | | | | | Natural gas | | | | | | | | | | | | | | | Exchange-traded instruments | | $ | 4,739 | | $ | 14,853 | | $ | 19,681 | | $ | 67,741 | | | Over-the-counter swaps | | | 41,633 | | | 19,160 | | | 119,244 | | | 94,588 | | | Options | | | 4,786 | | | 2,467 | | | 16,738 | | | 5,733 | | | Other (a) | | | 7,469 | | | 2,741 | | | 37,333 | | | 27,080 | | | | | | | | | | | | | | | | | | | | | 58,627 | | | 39,221 | | | 192,996 | | | 195,142 | | | Energy Services - financial trading instruments: | | | | | | | | | | | | | | | Natural gas | | | | | | | | | | | | | | | Exchange-traded instruments | | | 1,641 | | | 888 | | | 25,800 | | | 26,310 | | | Over-the-counter swaps | | | 11,258 | | | 8,013 | | | 42,740 | | | 45,452 | | | Options | | | 35,942 | | | 18,654 | | | 4,013 | | | 5,134 | | | Other (a) | | | 420 | | | 287 | | | 34 | | | 36 | | | | | | | | | | | | | | | | | | | | | 49,261 | | | 27,842 | | | 72,587 | | | 76,932 | | | ONEOK Partners - cash flow hedges | | | - | | | 21,304 | | | 2,154 | | | 3,875 | | | Distribution - natural gas swaps | | | - | | | 9,752 | | | - | | | 15,239 | | | Energy Services - cash flow hedges | | | 57,966 | | | 8,344 | | | 209,590 | | | 71,061 | | | Energy Services - fair value hedges | | | 5,237 | | | 51,343 | | | 15,476 | | | 68,177 | | | Interest rate swaps - fair value hedges | | | 1,496 | | | 2,958 | | | - | | | 13,544 | | | | | | | | | | | | | | | | | | Total fair value | | $ | 172,587 | | $ | 160,764 | | $ | 492,803 | | $ | 443,970 | | | | |
(a) - Other includes physical.
Fair value estimates consider the market in which the transactions are executed. The market in which exchange-traded and over-the-counter transactions are executed is a factor in determining fair value. We utilize third-party references for pricing points from NYMEX and third-party over-the-counter brokers to establish the commodity pricing and volatility curves. We believe the reported transactions from these sources are the most reflective of current market prices. The estimate of fair value includes an adjustment for the liquidation of the position in an orderly manner over a reasonable period of time under current market conditions. The fair value estimate also considers the risk of nonperformance based on credit considerations of the counterparty.
Credit Risk- We maintain credit policies with regard to our counterparties that we believe minimize overall credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit ratings)ratings and credit default swap rates), collateral requirements under certain circumstances and the use of standardized agreements which allow for netting of positive and negative exposures associated with a single counterparty.
Our counterparties consist primarily of financial institutions, major energy companies, LDCs, electric utilities and commercial and industrial end-users. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. Based on our policies, exposures, credit and other reserves, we do not anticipate a material adverse effect on our financial position or results of operations as a result of counterparty nonperformance.
E. GOODWILL AND INTANGIBLE ASSETS
Goodwill
Financial InstrumentsCarrying Amount - The following information represents the carrying amounts and estimated fair values oftable sets forth goodwill recorded on our financial instrumentsConsolidated Balance Sheets for the periods indicated, excluding energy marketing and risk management assets and liabilities, which are listed in the table above.The approximate fair value of cash and cash equivalents, short-term investments, accounts and notes receivable and accounts and notes payable is equal to book value due to their short-term nature. The estimated fair value of long-term debt has been determined using quoted market prices of the same or similar issues, discounted cash flows, and/or rates currently available to us for debt with similar terms and remaining maturities. The book value of our long-term debt was $4.64 billion and $4.05 billion at December 31, 2007 and 2006, respectively. The approximate fair value of our long-term debt was $4.75 billion and $4.09 billion at December 31, 2007 and 2006, respectively.
At December 31, 2007, our investment securities classified as available for sale had an aggregate fair value of $24.2 million. We reported $13.7 million and $12.6 million in accumulated other comprehensive income (loss) for net unrealized holding gains on available-for-sale securities in 2007 and 2006, respectively. For 2007 and 2006, no gains or losses related to available-for-sale securities were reclassified to earnings from other comprehensive income (loss). We had no material securities classified as available for sale at December 31, 2005.
E. | GOODWILL AND INTANGIBLE ASSETS |
Goodwill
Activity - There was no change in the carrying amounts of goodwill during 2007. The following table reflects the changes in the carrying amount of goodwill for the period indicated.
| | | | | | | | | | | | | | | | | | | | | | Balance December 31, 2005 | | Additions | | Adjustments | | | Adoption of EITF 04-5 | | Balance December 31, 2006 | | | | | | (Thousands of dollars) | | | ONEOK Partners | | $ | 211,087 | | $ | 37,489 | | $ | (2,001 | ) | | $ | 184,843 | | $ | 431,418 | | | Distribution | | | 157,953 | | | - | | | - | | | | - | | | 157,953 | | | Energy Services | | | 10,255 | | | - | | | - | | | | - | | | 10,255 | | | Other | | | 1,099 | | | - | | | - | | | | - | | | 1,099 | | | Total Goodwill | | $ | 380,394 | | $ | 37,489 | | $ | (2,001 | ) | | $ | 184,843 | | $ | 600,725 | | | | |
Goodwill additions for 2006 in our ONEOK Partners segment include $7.5 million related to the consolidation of Guardian Pipeline, of which $5.7 million relates to the purchase of the 66-2/3 percent interest not previously owned by ONEOK Partners, and $2.1 million related to the incremental 1 percent acquisition in an affiliate that was previously accounted for under the equity method. Following ONEOK Partners’ acquisition of the additional 1 percent interest, we began consolidating the entity.
Goodwill increased by approximately $27.9 million relating to ONEOK Partners’ 2003 acquisition of Viking Gas Transmission. In accounting for the acquisition, the entire purchase price was allocated to the fair value of the tangible assets including plant in service. Since that date, we have determined that the amount of purchase price representing a premium over Viking Gas Transmission’s historic rate base is not being recovered in its rates and, accordingly, should be accounted for as goodwill under Statement 142.
Goodwill adjustments for 2006 in our ONEOK Partners segment include an $8.4 million reduction related to the Black Mesa Pipeline impairment, offset by $6.4 million in purchase price adjustments.
In accordance with EITF 04-5, we consolidated our ONEOK Partners segment beginning January 1, 2006. The adoption of EITF 04-5 resulted in $152.8 million of ONEOK Partners’ goodwill being included on our 2006 Consolidated Balance Sheet and $32.0 million of goodwill that was previously recorded as our equity investment in ONEOK Partners.
| | | December 31, | | | | | 2008 | | | 2007 | | | | | (Thousands of dollars) | | | ONEOK Partners | | $ | 433,537 | | | $ | 431,418 | | | Distribution | | | 157,953 | | | | 157,953 | | | Energy Services | | | 10,255 | | | | 10,255 | | | Other | | | 1,099 | | | | 1,099 | | | Total Goodwill | | $ | 602,844 | | | $ | 600,725 | |
Equity Method Goodwill- For the investments we account for under the equity method, the premium or excess cost over underlying fair value of net assets is referred to as equity method goodwill. Investment in unconsolidated affiliates on our accompanying Consolidated Balance Sheets includes equity method goodwill of $185.6 million as of December 31, 20072008 and 2006.2007. Impairment Test - We apply the provisions of Statement 142 “Goodwill and Other Intangible Assets,” and perform our annual goodwill impairment testingtest on July 1. There were no impairment charges resulting from theour July 1, 2007,2008, impairment test. As a result of recent events in the financial markets and current economic conditions, we performed a review and determined that interim testing of goodwill as of December 31, 2008, was not necessary.
Black Mesa - During 2006, we recorded a goodwill and no events indicatingasset impairment have occurred subsequentrelated to that date.ONEOK Partners’ Black Mesa Pipeline of $8.4 million and $3.6 million, respectively, which was recorded as depreciation and amortization. The reduction to our net income, net of minority interests and income taxes, was $3.0 million.
Our ONEOK Partners segment had $287.5$279.8 million of intangible assets primarily related to contracts acquired through our acquisition of the natural gas liquids businesses from Koch,contracts, which are being amortized over an aggregate weighted-average period of 40 years. The remaining intangible asset balance has an indefinite life. TheAmortization expense for intangible assets for both 2008 and 2007 was $7.7 million, and the aggregate amortization expense for each of the next five years is estimated to be approximately $7.7 million. Amortization expense for intangible assets for both 2007 and 2006 was $7.7 million. The following table reflects the gross carrying amount and accumulated amortization of intangible assets for the periods presented. | | | | | | | | | | | | | | | | Gross Intangibles | | Accumulated Amortization | | | Net Intangibles | | | | | | (Thousands of dollars) | | | December 31, 2007 | | $ | 462,214 | | $ | (19,166 | ) | | $ | 443,048 | | | December 31, 2006 | | | 462,214 | | | (11,499 | ) | | | 450,715 | | |
The adoption of EITF 04-5 resulted in the addition of $123.0 million of intangible assets, which was previously recorded as our equity investment in ONEOK Partners. An additional $32.5 million was recorded related to the general partner incentive distribution rights acquired through the purchase of the remaining 17.5 percent of the general partner interest from TransCanada. These intangible assets have an indefinite life; accordingly, they are not subject to amortization but are subject to impairment testing.
| | | Gross | | | Accumulated | | | Net | | | | | Intangible Assets | | | Amortization | | | Intangible Assets | | | | (Thousands of dollars) | | December 31, 2007 | | $ | 462,214 | | | $ | (19,166 | ) | | $ | 443,048 | | | December 31, 2008 | | $ | 462,214 | | | $ | (26,832 | ) | | $ | 435,382 | |
F. OTHER COMPREHENSIVE INCOME (LOSS)
F.
| COMPREHENSIVE INCOME |
The table below shows the gross amount of other comprehensive income (loss) and related tax (expense) benefit for the periods indicated. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Year Ended
December 31, 2007 | | | Year Ended
December 31, 2006 | | | | Gross | | | Tax (Expense) or Benefit | | | Net | | | Gross | | | Tax (Expense) or Benefit | | | Net | | | | | | | (Thousands of dollars) | | | | Unrealized gains (losses) on energy marketing and risk management assets/liabilities | | $ | 48,888 | | | $ | (21,836 | ) | | $ | 27,052 | | | $ | 342,629 | | | $ | (132,810 | ) | | $ | 209,819 | | | | Unrealized holding gains (losses) arising during the period | | | 1,735 | | | | (671 | ) | | | 1,064 | | | | 20,571 | | | | (7,957 | ) | | | 12,614 | | | | Realized (gains) losses in net income | | | (149,535 | ) | | | 57,840 | | | | (91,695 | ) | | | (115,222 | ) | | | 44,568 | | | | (70,654 | ) | | | Change in pension and postretirement benefit plan liability | | | 27,687 | | | | (10,709 | ) | | | 16,978 | | | | (143,348 | ) | | | 55,447 | | | | (87,901 | ) | | | Other comprehensive income (loss) | | $ | (71,225 | ) | | $ | 24,624 | | | $ | (46,601 | ) | | $ | 104,630 | | | $ | (40,752 | ) | | $ | 63,878 | | | | | |
| | | | | Year Ended | | | | | | Year Ended | | | | | | | December 31, 2008 | | December 31, 2007 | | | | | Gross | | Tax (Expense) or Benefit | | Net | | Gross | | Tax (Expense) or Benefit | | Net | | | | | (Thousands of dollars) | | Unrealized gains on energy marketing and risk management assets/liabilities | | $ | 276,400 | | | (103,705 | ) | $ | 172,695 | | $ | 48,888 | | $ | (21,836 | ) | $ | 27,052 | | Less: Gains on energy marketing and risk management assets/liabilities recognized in net income | | | 277,413 | | | (107,303 | ) | | 170,110 | | | 149,535 | | | (57,840 | ) | | 91,695 | | Unrealized holding gains (losses) on investment securities arising during the period | | | (9,837 | ) | | 3,805 | | | (6,032 | ) | | 1,735 | | | (671 | ) | | 1,064 | | Less: Gains on investment securities recognized in net income | | | 11,142 | | | (4,310 | ) | | 6,832 | | | - | | | - | | | - | | Change in pension and postretirement benefit plan liability | | | (86,869 | ) | | 33,601 | | | (53,268 | ) | | 27,687 | | | (10,709 | ) | | 16,978 | | | Other comprehensive income (loss) | | $ | (108,861 | ) | $ | 45,314 | | $ | (63,547 | ) | $ | (71,225 | ) | $ | 24,624 | | $ | (46,601 | ) |
The gains on energy marketing and risk management assets/liabilities recognized in net income presented in the table above include the reclassification of gains on our cash flow hedges from accumulated other comprehensive income (loss) into earnings as discussed in Note D.
The table below shows the balance in accumulated other comprehensive income (loss) for the periods indicated. See Note J for more information regarding the adoption of Statement 158. | | | | | | | | | | | | | | | | | | | | | Unrealized Gains (Losses) on Energy Marketing and Risk
Management Assets/Liabilities | | | Unrealized Gains on Available-for-Sale Securities | | Pension and Postretirement Benefit Plan Obligations | | | Accumulated Other Comprehensive
Income (Loss) | | | | | | | (Thousands of dollars) | | | | December 31, 2005 | | $ | (49,194 | ) | | $ | - | | $ | (7,797 | ) | | $ | (56,991 | ) | | | Other comprehensive income (loss) | | | 139,165 | | | | 12,614 | | | (87,901 | ) | | | 63,878 | | | | Adoption of Statement 158 | | | - | | | | - | | | 32,645 | | | | 32,645 | | | | December 31, 2006 | | $ | 89,971 | | | $ | 12,614 | | $ | (63,053 | ) | | $ | 39,532 | | | | Other comprehensive income (loss) | | | (64,643 | ) | | | 1,064 | | | 16,978 | | | | (46,601 | ) | | | December 31, 2007 | | $ | 25,328 | | | $ | 13,678 | | $ | (46,075 | ) | | $ | (7,069 | ) | | | | |
| | | Unrealized Gains (Losses) on Energy Marketing and Risk Management Assets/Liabilities | | Unrealized Holding Gains (Losses) on Investment Securities | | Pension and Postretirement Benefit Plan Obligations | | Accumulated Other Comprehensive Income (Loss) | | | | | (Thousands of dollars) | | | December 31, 2006 | | $ | 89,971 | | | $ | 12,614 | | | $ | (63,053) | | | $ | 39,532 | | | Other comprehensive income (loss) | | | (64,643) | | | | 1,064 | | | | 16,978 | | | | (46,601) | | | December 31, 2007 | | $ | 25,328 | | | $ | 13,678 | | | $ | (46,075) | | | $ | (7,069) | | | Other comprehensive income (loss) | | | 2,585 | | | | (12,864) | | | | (53,268) | | | | (63,547) | | | December 31, 2008 | | $ | 27,913 | | | $ | 814 | | | $ | (99,343) | | | $ | (70,616) | |
G. CAPITAL STOCK
G.
| CAPITAL STOCK |
Series A and B Convertible Preferred Stock- There are no shares of Series A or Series B currently outstanding.
Series C Preferred Stock- Series C Preferred Stock (Series C) is designed to protect our shareholders from coercive or unfair takeover tactics. If issued, holders of shares of Series C are entitled to receive, in preference to the holders of ONEOK Common Stock, quarterly dividends in an amount per share equal to the greater of $0.50 or, subject to adjustment, 100 times the aggregate per share amount of all cash dividends, and 100 times the aggregate per share amount (payable in kind) of all non-cash dividends. No shares of Series C have been issued.
Common Stock - At December 31, 2007,2008, we had approximately 179175 million shares of authorized and unreserved common stock available for issuance.
Stock Repurchase Plan - On May 17, 2007, our Board of Directors authorized a stock buy back program to repurchase up to 7.5 million shares of our currently issued and outstanding common stock. On June 28, 2007, we repurchased 7.5 million shares of our outstanding common stock under an accelerated share repurchase agreement with Bank of America, N.A. (Bank of America) at an initial price of $49.33 per share for a total of $370 million. Bank of America borrowed 7.5 million of our shares from third parties and purchased shares in the open market to settle its short position. Our repurchase was subject to a financial adjustment based on the volume-weighted average price, less a discount, of the shares subsequently repurchased by Bank of America over the course of the repurchase period. The price adjustment could have been settled, at our option, in cash or in shares of our common stock. In September 2007, the accelerated share repurchase agreement with Bank of America was settled, which resulted in Bank of America delivering an additional 186,402 shares of our common stock to us at no additional cost. All shares under this accelerated repurchase agreement were recorded as treasury shares in our Consolidated Balance Sheet as of December 31, 2007.Sheets. These transactions completed the plan approved by our Board of Directors and we have no remaining shares available for repurchase under our stock repurchase plan.
On August 7, 2006, under a previously authorized stock repurchase plan, we repurchased 7.5 million shares of our outstanding common stock under an accelerated share repurchase agreement with UBS Securities LLC (UBS) at an initial price of $37.52 per share for a total of $281.4 million. These shares were recorded as treasury shares in our Consolidated Balance Sheets. UBS borrowed 7.5 million of our shares from third parties and purchased shares in the open market to settle its short position. Our repurchase was subject to a financial adjustment based on the volume-weighted average price, less a discount, of the shares subsequently repurchased by UBS over the course of the repurchase period. The price adjustment could have been settled, at our option, in cash or in shares of our common stock. In February 2007, the forward purchase contract with UBS was settled for a cash payment of $20.1 million, which was recorded in equity.
In accordance with EITF Issue No. 99-7, “Accounting for an Accelerated Share Repurchase Program,” the repurchases were accounted for as two separate transactions: (i) as shares of common stock acquired in a treasury stock transaction recorded on the acquisition datedate; and (ii) as a forward contract indexed to our common stock. Additionally, we classified the forward contracts as equity under EITF Issue No. 00-19, “Accounting for Derivative Financial Instruments Indexed to, and Potentially Settled in, a Company’s Own Stock.” During 2005, we repurchased 7.5 million shares
Dividends - Quarterly dividends paid on our common stock for shareholders of record as of the close of business on January 31, 2007,2008, April 30, 2007,2008, July 31, 2007,2008, and October 31, 2007,2008, were $0.34$0.38 per share, $0.34$0.38 per share, $0.36$0.40 per share and $0.36$0.40 per share, respectively. Additionally, a quarterly dividend of $0.38$0.40 per share was declared in January 2008,2009, payable in the first quarter of 2008.2009.
Equity Units - On February 16, 2006, we successfully settled our 16.1 million equity units to 19.5 million shares of our common stock. Of this amount, 8.3 million shares were issued from treasury stock and approximately 11.2 million shares were newly issued. Holders of the equity units received 1.2119 shares of our common stock for each equity unit they owned. The number of shares that we issued for each stock purchase contract was determined based on our average closing price over the 20 trading day period ending on the third trading day prior to February 16, 2006. With the settlement, we received $402.4 million in cash, which was used to pay down our short-term bridge financing agreement.
H. CREDIT FACILITIES AND SHORT-TERM NOTES PAYABLE
H.
| CREDIT FACILITIES AND SHORT-TERM NOTES PAYABLE |
General - The total amount of short-term borrowings authorized by our Board of Directors is $2.5 billion. Our commercial paper and short-term notes payable, excluding ONEOK Partners’ short-term notes payable, carried an average interest rate of 5.00 percent at December 31, 2007, and there was none outstanding at December 31, 2006. ONEOK Partners’ short-term notes payable carried average interest rates of 5.40 percent and 6.75 percent at December 31, 2007 and 2006, respectively.
ONEOK Credit Agreement - In AprilJuly 2006 weand September 2008, ONEOK amended our 2004and restated its $1.2 billion credit agreement (ONEOK Credit Agreement) to accommodate the transaction with ONEOK Partners. This amendment included changes to the material adverse effect representation, the burdensome agreement representation and the covenant regarding maintenance of control of ONEOK Partners. In July 2006, we amended and restated our ONEOK Credit Agreement.. The amended agreement includes revised pricing, an extension of the maturity date from 2009 to 2011, an option for additional extensions of the maturity date with the consent of the lenders, and an option to request an increase in the commitments of the lenders of up to an additional $500 million.million and a change in certain sublimits. The interest rates applicable to extensions of credit under this agreement are based, at ourONEOK’s election, on either (i) the higher of prime or one-half of one percent above the Federal Funds Rate, which is the rate that banks charge each other for the overnight borrowing of funds,funds; or (ii) the Eurodollar rate plus a set number of basis points based on ourONEOK’s current long-term unsecured debt ratings.
Under the ONEOK Credit Agreement, we areONEOK is required to comply with certain financial, operational and legal covenants. Among other things, these requirements include: a $500 million sublimit for the issuance of standby letters of credit,
a limitation on our debt-to-capital ratio, which may not exceed 67.5 percent at the end of any calendar quarter,
| · | a $400 million sublimit for the issuance of standby letters of credit; |
a requirement that we maintain the power to control the management and policies of ONEOK Partners, and
| · | a limitation on ONEOK’s stand-alone debt-to-capital ratio, which may not exceed 67.5 percent at the end of any calendar quarter; |
a limit on new investments in master limited partnerships.
| · | a requirement that ONEOK maintains the power to control the management and policies of ONEOK Partners; and |
| · | a limit on new investments in master limited partnerships. |
The ONEOK Credit Agreement also contains customary affirmative and negative covenants, including covenants relating to liens, investments, fundamental changes in our businesses, changes in the nature of ourONEOK’s businesses, transactions with affiliates, the use of proceeds and a covenant that prevents usONEOK from restricting ourits subsidiaries’ ability to pay dividends.
ONEOK 364-Day Facility - In August 2008, ONEOK entered into a $400 million 364-day credit agreement (364-Day Facility). The interest rate is based, at ONEOK’s election, on either (i) the higher of prime or one-half of one percent above the Federal Funds Rate; or (ii) the Eurodollar rate plus a set number of basis points based on ONEOK’s current long-term unsecured debt ratings by Moody’s and S&P. The 364-Day Facility is being used as an additional back-up to ONEOK’s commercial paper program and for working capital, capital expenditures and other general corporate purposes. The 364-Day Facility contains substantially similar affirmative and negative covenants as the ONEOK Credit Agreement.
The debt covenant calculations in the ONEOK Credit Agreement and the 364-Day Facility exclude the debt of ONEOK Partners. Upon breach of any covenant by ONEOK, amounts outstanding under the ONEOK Credit Agreement or the 364-Day Facility may become immediately due and payable. At December 31, 2007, we were2008, ONEOK’s stand-alone debt-to-capital ratio was 58.2 percent and ONEOK was in compliance with these covenants. As of December 31, 2007, $1.0 billion was availableall covenants under this agreement.the ONEOK Credit Agreement and the ONEOK 364-Day Facility.
At December 31, 2007, we had $102.6 million commercial paper or short-term notes payable outstanding. At December 31, 2006, we2008, ONEOK had no commercial paper or short-term notes payable outstanding. We had $58.7 millionoutstanding, $1.4 billion in borrowings outstanding and $58.5$64.6 million in letters of credit issued under the ONEOK Credit Agreement, leaving $135.4 million of credit available under the ONEOK Credit Agreement and 364-Day Facility. The ONEOK Credit Agreement and the 364-Day Facility also serve as a back-up to ONEOK’s commercial paper program.
The average interest rate on ONEOK’s short-term debt outstanding was 4.51 percent and 5.00 percent at December 31, 2008 and 2007, respectively. At December 31, 2007, ONEOK had $102.6 million in commercial paper outstanding, no borrowings outstanding and 2006, respectively.$38.1 million in letters of credit issued under the ONEOK Credit Agreement, leaving $1.1 billion of credit available under the ONEOK Credit Agreement. In addition, ONEOK had $20.6 million in other letters of credit issued at December 31, 2007.
ONEOK Partners Credit Agreement - In March 2007, ONEOK Partners amended and restated its revolving credit facility agreement (ONEOK Partners Credit Agreement), with several banks and other financial institutions and lenders in the following principal ways: (i) revised the pricing,pricing; (ii) extended the maturity by one year to March 2012,2012; (iii) eliminated the interest coverage ratio covenant,covenant; (iv) increased the permitted ratio of indebtedness to EBITDA to 5 to 1 (from 4.75 to 1) ,; (v) increased the swingline sub-facility commitments from $15 million to $50 millionmillion; and (vi) changed the permitted amount of subsidiary indebtedness from $35 million to 10 percent of ONEOK Partners’ consolidated indebtedness. The interest rates applicable to extensions of credit under this agreement are based, at ONEOK Partners’ election, on either (i) the higher of prime or one-half of one percent above the Federal Funds Rate, which is the rate that banks charge each other for the overnight borrowing of funds,funds; or (ii) the Eurodollar rate plus a set number of basis points, depending on ONEOK Partners’ current long-term unsecured debt ratings.
In July 2007, ONEOK Partners exercised the accordion feature in the ONEOK Partners Credit Agreement to increase the commitment amounts by $250 million to a total of $1.0 billion. In December 2006, ONEOK Partners amended its Partnership Credit Agreement. This agreement now provides for the exclusion of hybrid securities from debt in an amount not to exceed 15 percent of total capitalization when calculating the leverage ratio. Material projects may now be approved by the administrative agent as opposed to requiring approval from 50 percent of the lenders. The methodology of making pro forma adjustments to EBITDA (net income before interest expense, income taxes and depreciation and amortization) that is used in the calculation of the financial covenants with respect to approved material projects was also amended. The amendment excluded the Overland Pass Pipeline Company agreement from the covenant that limits ONEOK Partners’ ability to enter into agreements that restrict its ability to grant liens to the lenders under its Partnership Credit Agreement.
Under the ONEOK Partners Credit Agreement, ONEOK Partners is required to comply with certain financial, operational and legal covenants. Among other things, these requirements include maintaining a ratio of indebtedness to adjusted EBITDA (EBITDA adjusted forplus minority interest in income of consolidated subsidiaries, distributions received from investments and EBITDA related to any approved capital projects)projects less equity earnings from investments and the equity portion of AFUDC) of no more than 5 to 1. If ONEOK Partners consummates one or more acquisitions in which the aggregate purchase price is $25 million or more, the allowable ratio of indebtedness to adjusted EBITDA will be increased to 5.5 to 1 for the three calendar quarters following the acquisition. Upon breach of any covenant, discussed above, amounts outstanding under the ONEOK Partners Credit Agreement may become immediately due and payable. At December 31, 2008, ONEOK Partners’ ratio of indebtedness to adjusted EBITDA was 4.1 to 1, and ONEOK Partners was in compliance with theseall covenants under the ONEOK Partners Credit Agreement.
The average interest rate of borrowings under the ONEOK Partners Credit Agreement was 4.22 percent and 5.40 percent at December 31, 2007. At December 31,2008 and 2007, respectively. ONEOK Partners had $870 million and $100 million of borrowings outstanding under this agreementand $130 million and $900 million was available.In November 2007,available under the ONEOK Partners entered intoCredit Agreement at December 31, 2008 and 2007, respectively.
ONEOK Partners has an outstanding $25 million letter of credit issued by Royal Bank of Canada, which is used for counterparty credit support.
ONEOK Partners also has a $15 million Senior Unsecured Letter of Credit Facility and Reimbursement Agreement with Wells Fargo Bank, N.A., of which $12 million is being used, and a $12 million Standby Letter of Credit Agreementan agreement with Royal Bank of Canada.Canada, pursuant to which a $12 million letter of credit was issued. Both agreements are used to support various permits required by the KDHE for ONEOK Partners’ ongoing business in Kansas. ONEOK Partners Bridge Facility
- In April 2006, ONEOK Partners entered into a $1.1 billion 364-day credit agreement (Bridge Facility) with a syndicate95 - -
I. LONG-TERM DEBT
The following table sets forth our long-term debt for the periods indicated. All notes are senior unsecured obligations, ranking equally in right of payment with all of our existing and future unsecured senior indebtedness. | | | | | | | | | | | | | | December 31,
2007 | | | December 31,
2006 | | | | | | | (Thousands of dollars) | | | | ONEOK | | | | | | | | | | | $402,500 at 5.51% due 2008 | | $ | 402,303 | | | $ | 402,302 | | | | $100,000 at 6.0% due 2009 | | | 100,000 | | | | 100,000 | | | | $400,000 at 7.125% due 2011 | | | 400,000 | | | | 400,000 | | | | $400,000 at 5.2% due 2015 | | | 400,000 | | | | 400,000 | | | | $100,000 at 6.4% due 2019 | | | 92,000 | | | | 92,613 | | | | $100,000 at 6.5% due 2028 | | | 90,902 | | | | 91,718 | | | | $100,000 at 6.875% due 2028 | | | 100,000 | | | | 100,000 | | | | $400,000 at 6.0% due 2035 | | | 400,000 | | | | 400,000 | | | | Other | | | 2,958 | | | | 3,187 | | | | | | | | | | | | | | | | | | 1,988,163 | | | | 1,989,820 | | | | | | | | | | | | | | | ONEOK Partners | | | | | | | | | | | $250,000 at 8.875% due 2010 | | | 250,000 | | | | 250,000 | | | | $225,000 at 7.10% due 2011 | | | 225,000 | | | | 225,000 | | | | $350,000 at 5.90% due 2012 | | | 350,000 | | | | 350,000 | | | | $450,000 at 6.15% due 2016 | | | 450,000 | | | | 450,000 | | | | $600,000 at 6.65% due 2036 | | | 600,000 | | | | 600,000 | | | | $600,000 at 6.85% due 2037 | | | 600,000 | | | | - | | | | | | | | | | | | | | | | | | 2,475,000 | | | | 1,875,000 | | | | | | | | | | | | | | | Guardian Pipeline | | | | | | | | | | | Average 7.85%, due 2022 | | | 133,641 | | | | 145,572 | | | | | | | | | | | | | | | Total long-term notes payable | | | 4,596,804 | | | | 4,010,392 | | | | Change in fair value of hedged debt | | | 43,682 | | | | 41,619 | | | | Unamortized debt premium | | | (4,961 | ) | | | (2,997 | ) | | | Current maturities | | | (420,479 | ) | | | (18,159 | ) | | | Long-term debt | | $ | 4,215,046 | | | $ | 4,030,855 | | | | | |
| | | December 31, | | | December 31, | | | | | 2008 | | | 2007 | | | | | (Thousands of dollars) | | | ONEOK | | | | | | | | $402,500 at 5.51% due 2008 | | $ | - | | | $ | 402,303 | | | $100,000 at 6.0% due 2009 | | | 100,000 | | | | 100,000 | | | $400,000 at 7.125% due 2011 | | | 400,000 | | | | 400,000 | | | $400,000 at 5.2% due 2015 | | | 400,000 | | | | 400,000 | | | $100,000 at 6.4% due 2019 | | | 91,371 | | | | 92,000 | | | $100,000 at 6.5% due 2028 | | | 89,970 | | | | 90,902 | | | $100,000 at 6.875% due 2028 | | | 100,000 | | | | 100,000 | | | $400,000 at 6.0% due 2035 | | | 400,000 | | | | 400,000 | | | Other | | | 2,712 | | | | 2,958 | | | | | | 1,584,053 | | | | 1,988,163 | | | ONEOK Partners | | | | | | | | | | $250,000 at 8.875% due 2010 | | | 250,000 | | | | 250,000 | | | $225,000 at 7.10% due 2011 | | | 225,000 | | | | 225,000 | | | $350,000 at 5.90% due 2012 | | | 350,000 | | | | 350,000 | | | $450,000 at 6.15% due 2016 | | | 450,000 | | | | 450,000 | | | $600,000 at 6.65% due 2036 | | | 600,000 | | | | 600,000 | | | $600,000 at 6.85% due 2037 | | | 600,000 | | | | 600,000 | | | | | | 2,475,000 | | | | 2,475,000 | | | | | | | | | | | | | Guardian Pipeline | | | | | | | | | | Average 7.85%, due 2022 | | | 121,711 | | | | 133,641 | | | | | | | | | | | | | Total long-term notes payable | | | 4,180,764 | | | | 4,596,804 | | Unamortized portion of terminated swaps and fair value of hedged debt | | | 55,035 | | | | 43,682 | | | Unamortized debt premium | | | (5,023 | ) | | | (4,961 | ) | | Current maturities | | | (118,195 | ) | | | (420,479 | ) | | Long-term debt | | $ | 4,112,581 | | | $ | 4,215,046 | |
The aggregate maturities of long-term debt outstanding for the years 20082009 through 20122013 are shown below. | | | | | | | | | | | | | | | | | | ONEOK | | ONEOK
Partners | | Guardian
Pipeline | | Total | | | | | | (Millions of dollars) | | | 2008 | | $ | 408.5 | | $ | - | | $ | 11.9 | | $ | 420.4 | | | 2009 | | | 106.3 | | | - | | | 11.9 | | | 118.2 | | | 2010 | | | 6.3 | | | 250.0 | | | 11.9 | | | 268.2 | | | 2011 | | | 406.3 | | | 225.0 | | | 11.9 | | | 643.2 | | | 2012 | | | 6.3 | | | 350.0 | | | 11.1 | | | 367.4 | | |
| | | | | | ONEOK | Guardian | | | | | | ONEOK | | Partners | Pipeline | | Total | | | | (Millions of dollars) | | 2009 | | $ | 106.3 | | $ - | | $ | 11.9 | | $ 118.2 | | 2010 | | $ | 6.3 | | $ 250.0 | | $ | 11.9 | | $ 268.2 | | 2011 | | $ | 406.3 | | $ 225.0 | | $ | 11.9 | | $ 643.2 | | 2012 | | $ | 6.3 | | $ 350.0 | | $ | 11.1 | | $ 367.4 | | 2013 | | $ | 6.2 | | $ - | | $ | 7.7 | | $ 13.9 | | | | | | | | | | | | |
$182.9$181.4 million of our debt is callable at par at our option from now until maturity, which is 2019 for $92.0$91.4 million and 2028 for $90.9$90.0 million. Certain debt agreements have negative covenants that relate to liens and sale/leaseback transactions.ONEOK Partners’ 2007 Debt Issuance- In September 2007, ONEOK Partners completed an underwritten public offering of $600 million aggregate principal amount of 6.85 percent Senior Notes due 2037 (the 2037 Notes). The 2037 Notes were issued under ONEOK Partners’ existing shelf registration statement filed with the SEC.
ONEOK Partners may redeem the 2037 Notes, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount of the 2037 Notes, plus accrued and unpaid interest and a make-whole premium. The redemption price will never be less than 100 percent of the principal amount of the 2037 Notes plus accrued and unpaid interest. The 2037 Notes are senior unsecured obligations, ranking equally in right of payment with all of ONEOK Partners’ existing and future unsecured senior indebtedness, and effectively junior to all of the existing debt and other liabilities of its non-guarantor subsidiaries. The 2037 Notes are non-recourse to ONEOK.
Debt Covenants - The net proceedsterms of ONEOK’s long-term notes are governed by indentures containing covenants that include, among other provisions, limitations on ONEOK’s ability to place liens on its property or assets and its ability to sell and lease back its property.
We filed a new form of indenture in 2008. The new indenture includes covenants that are similar to those contained in our prior indentures. The new indenture does not limit the aggregate principal amount of debt securities that may be issued and provides that debt securities may be issued from time to time in one or more additional series.
The indenture governing the 2037 Notes after deducting underwriting discounts and commissions and expenses, of $592.9 million were used to finance ONEOK Partners’ $300 million acquisition, before working capital adjustments, of an interstate natural gas liquids and refined petroleum products pipeline system and related assets from a subsidiary of Kinder Morgan and to repay debt outstanding under the ONEOK Partners Credit Agreement.The terms of the 2037 Notes are governed by the Indenture, dated as of September 25, 2006, between ONEOK Partners and Wells Fargo Bank, N.A., as trustee, as supplemented by the Fourth Supplemental Indenture, dated September 28, 2007 (Indenture). The Indenture does not limit the aggregate principal amount of debt securities that may be issued and provides that debt securities may be issued from time to time in one or more additional series. The Indentureindenture contains covenants including, among other provisions, limitations on ONEOK Partners’ ability to place liens on its property or assets and its ability to sell and lease back its property.
The 2037 Notes will mature on October 15, 2037. ONEOK Partners will pay interest on the 2037 Notes on April 15 and October 15 of each year. The first payment of interest on the 2037 Notes will be made on April 15, 2008. Interest on the 2037 Notes accrues from September 28, 2007, which was the issuance date of the 2037 Notes.
ONEOK Partners’ 2006 Debt Issuance - In September 2006, ONEOK Partners completed an underwritten public offering of (i) $350 million aggregate principal amount of 5.90 percent Senior Notes due 2012 (the 2012 Notes), (ii) $450 million aggregate principal amount of 6.15 percent Senior Notes due 2016 (the 2016 Notes) and (iii) $600 million aggregate principal amount of 6.65 percent Senior Notes due 2036 (the 2036 Notes and collectively with the 2012 Notes and the 2016 Notes, the Notes). ONEOK Partners registered the sale of the Notes with the SEC pursuant to a shelf registration statement filed on September 19, 2006. The Notes are guaranteed on a senior unsecured basis by the Intermediate Partnership. The guarantee ranks equally in right of payment to all of the Intermediate Partnership’s existing and future unsecured senior indebtedness.
ONEOK Partners may redeem the Notes, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount of the Notes, plus accrued interest and a make-whole premium. The redemption price will never be less than 100 percent of the principal amount of the relevant Notes plus accrued and unpaid interest. The Notes are senior unsecured obligations, ranking equally in right of payment with all of ONEOK Partners’ existing and future unsecured senior indebtedness, and effectively junior to all of the existing and future debt and other liabilities of its non-guarantor subsidiaries. The Notes are non-recourse to us.
The net proceeds from the Notes of approximately $1.39 billion, after deducting underwriting discounts and commissions and expenses but before offering expenses, were used to repay all of the $1.05 billion outstanding under the Bridge Facility and to repay $335 million of indebtedness outstanding under the ONEOK Partners Credit Agreement. The terms of the Notes are governed by the Indenture, dated as of September 25, 2006, between ONEOK Partners and Wells Fargo Bank, N.A., as trustee, as supplemented by the First Supplemental Indenture (with respect to the 2012 Notes), the Second Supplemental Indenture (with respect to the 2016 Notes) and the Third Supplemental Indenture (with respect to the 2036 Notes), each dated September 25, 2006. The Indenture does not limit the aggregate principal amount of debt securities that may be issued and provides that debt securities may be issued from time to time in one or more additional series. The Indenture contains covenants including, among other provisions, limitations on ONEOK Partners’ ability to place liens on its property or assets, and sell and lease back its property.
The 2012 Notes, 2016 Notes and 2036 Notes will mature on April 1, 2012, October 1, 2016, and October 1, 2036, respectively. ONEOK Partners pays interest on the Notes on April 1 and October 1 of each year. The first payment of interest on the Notes was made on April 1, 2007. Interest on the Notes accrues from September 25, 2006, which was the issuance date of the Notes.
Debt Covenants - We have debt covenants in addition to the covenants discussed in “ONEOK Partners’ 2007 Debt Issuance” and “ONEOK Partners’ 2006 Debt Issuance” above.
ONEOK Partners’ $250 million and $225 million long-termsenior notes, payable, due 2010 and 2011, respectively, contain provisions that require ONEOK Partners to offer to repurchase the senior notes at par value if its Moody’s or S&P credit rating falls below investment grade (Baa3 for Moody’s or BBB- for S&P) and the investment grade rating is not reinstated within a period of 40 days. Further, the indentures governing ONEOK Partners’ senior notes due 2010 and 2011 include an event of default upon acceleration of other indebtedness of $25 million or more and the indentures governing the senior notes due 2012, 2016, 2036 and 2037 include an event of default upon the acceleration of other indebtedness of $100 million or more that would be triggered by such an offer to repurchase. Such an event of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding senior notes due 2010, 2011, 2012, 2016, 2036 and 2037 to declare those notes immediately due and payable in full.
Guardian Pipeline Senior Notes - - These notes were issued under a master shelf agreement with certain financial institutions. Principal payments are due annuallyquarterly through 2022. Interest rates on the $133.6$121.7 million in notes outstanding at December 31, 2007,2008, range from 7.61 percent to 8.27 percent, with an average rate of 7.85 percent. Guardian Pipeline’s senior notes contain financial covenants that require the maintenance of a ratio of (i) EBITDAR (net income plus interest expense, income taxes, operating lease expense and depreciation and amortization) to the sum of interestfixed charges (interest expense plus operating lease expenseexpense) of not less than 1.5 to 11; and (ii) total indebtedness to EBITDAR of not greater than 5.75 to 1. Upon any breach of these covenants, all amounts outstanding under the master shelf agreement may become due and payable immediately. At December 31, 2007,2008, Guardian Pipeline’s EBITDAR-to-fixed-charges ratio was 4.95 to 1, the ratio of total indebtedness to EBITDAR was 3.34 to 1, and Guardian Pipeline was in compliance with its financial covenants. Unamortized Debt Premium, Discount and Expense -
Other
We amortize premiums, discounts and expenses incurred in connection with the issuance of long-term debt consistent with the terms of the respective debt instrument.
J. EMPLOYEE BENEFIT PLANS
Retirement and Other Postretirement Benefit Plans
Retirement Plans - We have defined benefit retirement plans covering certain full-time employees. Nonbargaining unit employees hired after December 31, 2004, are not eligible for our defined benefit pension plan; however, they are covered by a defined contribution profit-sharing plan. Certain officers and key employees are also eligible to participate in supplemental retirement plans. We generally fund pension costs at a level equal to the minimum amount required under the Employee Retirement Income Security Act of 1974.
Other Postretirement Benefit Plans - We sponsor welfare plans that provide postretirement medical and life insurance benefits to certain employees who retire with at least five years of service. The postretirement medical plan is contributory based on hire date, age and years of service, with retiree contributions adjusted periodically, and contains other cost-sharing features such as deductibles and coinsurance.
MeasurementStatement 158 - We useSee Note A for a September 30 measurement date for our plans.Statement 158 - In September 2006,discussion of the FASB issuedimpact of the adoption of Statement 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” which was effective forincluding the change in our year ending December 31, 2006, except for the measurement date change from September 30 to December 31, which will be effective for our year ending December 31, 2008. Statement 158 required us to recognize the overfunded or underfunded status of our plans as an asset or liability on our Consolidated Balance Sheets and to recognize changes in the funded status in accumulated other comprehensive income (loss) in the year in which the changes occur.31.
Regulatory Treatment - The OCC, KCC, and regulatory authorities in Texas have approved the recovery of pension costs and other postretirement benefits costs through rates for Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service, respectively. The costs recovered through rates are based on current funding requirements and the net periodic benefit cost for pension and postretirement costs. Differences, if any, between the expense and the amount recovered through rates are reflected in earnings.
Our regulated entities have historically recovered pension and other postretirement benefit costs, as determined by Statement 87, “Employers’ Accounting for Pensions,” and Statement 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” respectively, through rates. We believe it is probable that regulators will continue to include the net periodic pension and other postretirement benefit costs in our regulated entities’ cost of service. Accordingly, we have recorded a regulatory asset for the minimum liability associated with our regulated entities’ pension and other postretirement benefit obligations that otherwise would have been recorded in accumulated other comprehensive income.
Obligations and Funded Status - - The following tables set forth our pension and other postretirement benefit plans benefit obligations and fair value of plan assets for the periods indicated. Due to the change in our measurement date as discussed in Note A, the changes in benefit obligation and plan assets shown in the following tables are for the 15-month period from October 1, 2007 through December 31, 2008. | | | | | | | | | | | | | | | | | | | | | | Pension Benefits
December 31, | | | Postretirement Benefits
December 31, | | | | 2007 | | | 2006 | | | 2007 | | | 2006 | | | | | Change in Benefit Obligation | | (Thousands of dollars) | | | | Benefit obligation, beginning of period | | $ | 832,980 | | | $ | 777,438 | | | $ | 271,510 | | | $ | 253,213 | | | | Service cost | | | 21,050 | | | | 20,980 | | | | 6,392 | | | | 6,332 | | | | Interest cost | | | 48,608 | | | | 43,425 | | | | 15,830 | | | | 14,156 | | | | Plan participants’ contributions | | | - | | | | - | | | | 2,882 | | | | 2,787 | | | | Actuarial (gain) loss | | | (32,697 | ) | | | 37,205 | | | | 14,742 | | | | 11,335 | | | | Benefits paid | | | (49,942 | ) | | | (46,068 | ) | | | (16,626 | ) | | | (16,313 | ) | | | Benefit obligation, end of period | | $ | 819,999 | | | $ | 832,980 | | | $ | 294,730 | | | $ | 271,510 | | | | | | | | | | | | Change in Plan Assets | | | | | | | | | | | | | | | | | | | Fair value of plan assets, beginning of period | | $ | 710,377 | | | $ | 703,861 | | | $ | 68,440 | | | $ | 51,110 | | | | Actual return on plan assets | | | 107,305 | | | | 50,810 | | | | 5,214 | | | | 2,684 | | | | Employer contributions | | | 4,138 | | | | 1,774 | | | | 5,660 | | | | 14,646 | | | | Benefits Paid | | | (49,942 | ) | | | (46,068 | ) | | | - | | | | - | | | | Fair value of assets, end of period | | $ | 771,878 | | | $ | 710,377 | | | $ | 79,314 | | | $ | 68,440 | | | | | | | | | | | | Funded status of plans at September 30 | | $ | (48,121 | ) | | $ | (122,603 | ) | | $ | (215,416 | ) | | $ | (203,070 | ) | | | Fourth quarter contributions | | | - | | | | - | | | | 9,265 | | | | 5,578 | | | | Balance at December 31 | | $ | (48,121 | ) | | $ | (122,603 | ) | | $ | (206,151 | ) | | $ | (197,492 | ) | | | | | | | | | | | Non-current assets | | $ | 10,028 | | | $ | - | | | $ | - | | | $ | - | | | | Current liabilities | | | (2,497 | ) | | | (2,303 | ) | | | - | | | | - | | | | Non-current liabilities | | | (55,652 | ) | | | (120,300 | ) | | | (206,151 | ) | | | (197,492 | ) | | | Balance at December 31 | | $ | (48,121 | ) | | $ | (122,603 | ) | | $ | (206,151 | ) | | $ | (197,492 | ) | | | | |
| | | Pension Benefits | | | Postretirement Benefits | | | | | December 31, | | | December 31, | | | | | 2008 | | | 2007 | | | 2008 | | | 2007 | | | Change in Benefit Obligation | (Thousands of dollars) | | | Benefit obligation, beginning of period | | $ | 819,999 | | | $ | 832,980 | | | $ | 294,730 | | | $ | 271,510 | | | Service cost | | | 25,577 | | | | 21,050 | | | | 7,198 | | | | 6,392 | | | Interest cost | | | 61,649 | | | | 48,608 | | | | 22,206 | | | | 15,830 | | | Plan participants' contributions | | | - | | | | - | | | | 3,299 | | | | 2,882 | | | Actuarial (gain) loss | | | 46,967 | | | | (32,697 | ) | | | (21,983 | ) | | | 14,742 | | | Benefits paid | | | (66,629 | ) | | | (49,942 | ) | | | (26,685 | ) | | | (16,626 | ) | | Benefit obligation, end of period | | $ | 887,563 | | | $ | 819,999 | | | $ | 278,765 | | | $ | 294,730 | | | | | | | | | | | | | | | | | | | | | Change in Plan Assets | | | | | | | | | | | | | | | | | | Fair value of plan assets, beginning of period | | $ | 771,878 | | | $ | 710,377 | | | $ | 79,314 | | | $ | 68,440 | | | Actual return on plan assets | | | (220,955 | ) | | | 107,305 | | | | (17,644 | ) | | | 5,214 | | | Employer contributions | | | 117,597 | | | | 4,138 | | | | 12,444 | | | | 14,925 | | | Transfers in | | | - | | | | - | | | | 3,573 | | | | - | | | Benefits paid | | | (66,629 | ) | | | (49,942 | ) | | | - | | | | - | | | Fair value of assets, end of period | | $ | 601,891 | | | $ | 771,878 | | | $ | 77,687 | | | $ | 88,579 | | | Balance at December 31 | | $ | (285,672 | ) | | $ | (48,121 | ) | | $ | (201,078 | ) | | $ | (206,151 | ) | | | | | | | | | | | | | | | | | | | | Non-current assets | | $ | - | | | $ | 10,028 | | | $ | - | | | $ | - | | | Current liabilities | | | (2,706 | ) | | | (2,497 | ) | | | - | | | | - | | | Non-current liabilities | | | (282,966 | ) | | | (55,652 | ) | | | (201,078 | ) | | | (206,151 | ) | | Balance at December 31 | | $ | (285,672 | ) | | $ | (48,121 | ) | | $ | (201,078 | ) | | $ | (206,151 | ) |
The accumulated benefit obligation for our pension planplans was $759.2$824.7 million and $767.3$759.2 million at December 31, 2008 and 2007, and 2006, respectively.
There are no plan assets expected to be withdrawn and returned to us in 2008.2009.
Components of Net Periodic Benefit Cost- The following tables set forth the components of net periodic benefit cost for our pension and other postretirement benefit plans for the periods indicated. | | | | | | | | | | | | | | | | | | Pension Benefits Years Ended December 31, | | | | | | | 2007 | | | 2006 | | | 2005 | | | | | Components of Net Periodic Benefit Cost | | (Thousands of dollars) | | | | Service cost | | $ | 21,050 | | | $ | 20,980 | | | $ | 19,764 | | | | Interest cost | | | 48,608 | | | | 43,425 | | | | 43,030 | | | | Expected return on plan assets | | | (58,154 | ) | | | (57,586 | ) | | | (59,706 | ) | | | Amortization of prior service cost | | | 1,486 | | | | 1,511 | | | | 1,443 | | | | Amortization of net loss | | | 16,139 | | | | 13,314 | | | | 8,502 | | | | Net periodic benefit cost | | $ | 29,129 | | | $ | 21,644 | | | $ | 13,033 | | | | | | | | | | | | Postretirement Benefits Years Ended December 31, | | | | | | | 2007 | | | 2006 | | | 2005 | | | | | Components of Net Periodic Benefit Cost | | (Thousands of dollars) | | | | Service cost | | $ | 6,392 | | | $ | 6,332 | | | $ | 7,058 | | | | Interest cost | | | 15,830 | | | | 14,156 | | | | 14,270 | | | | Expected return on plan assets | | | (6,389 | ) | | | (4,565 | ) | | | (4,343 | ) | | | Amortization of transition obligation | | | 3,189 | | | | 3,189 | | | | 3,456 | | | | Amortization of prior service cost (credit) | | | (2,277 | ) | | | (2,286 | ) | | | 471 | | | | Amortization of net loss | | | 9,927 | | | | 9,085 | | | | 6,469 | | | | Net periodic benefit cost | | $ | 26,672 | | | $ | 25,911 | | | $ | 27,381 | | | | | |
| | | Pension Benefits | | | | | Years Ended December 31, | | | | | 2008 | | | 2007 | | | 2006 | | | Components of Net Periodic Benefit Cost | (Thousands of dollars) | | Service cost | | $ | 20,165 | | | $ | 21,050 | | | $ | 20,980 | | | Interest cost | | | 49,801 | | | | 48,608 | | | | 43,425 | | | Expected return on plan assets | | | (61,268 | ) | | | (58,154 | ) | | | (57,586 | ) | | Amortization of unrecognized prior service cost | | | 1,551 | | | | 1,486 | | | | 1,511 | | | Amortization of net loss | | | 9,548 | | | | 16,139 | | | | 13,314 | | | Net periodic benefit cost | | $ | 19,797 | | | $ | 29,129 | | | $ | 21,644 | |
| | | Postretirement Benefits | | | | | Years Ended December 31, | | | | | 2008 | | | 2007 | | | 2006 | | | Components of Net Periodic Benefit Cost | | (Thousands of dollars) | | | Service cost | | $ | 5,675 | | | $ | 6,392 | | | $ | 6,332 | | | Interest cost | | | 17,899 | | | | 15,830 | | | | 14,156 | | | Expected return on plan assets | | | (7,421 | ) | | | (6,389 | ) | | | (4,565 | ) | | Amortization of unrecognized net asset at adoption | | | 3,189 | | | | 3,189 | | | | 3,189 | | | Amortization of unrecognized prior service cost | | | (2,003 | ) | | | (2,277 | ) | | | (2,286 | ) | | Amortization of net loss | | | 10,972 | | | | 9,927 | | | | 9,085 | | | Net periodic benefit cost | | $ | 28,311 | | | $ | 26,672 | | | $ | 25,911 | |
Other Comprehensive Income (Loss) - The following table sets forth the amounts recognized in other comprehensive income (loss) for 20072008 related to our pension benefits and postretirement benefits. | | | | | | | | | | | | | | Pension Benefits
December 31, 2007 | | | Postretirement Benefits
December 31, 2007 | | | | Regulatory asset loss (gain) | | $ | (66,243 | ) | | $ | 13,883 | | | | Net loss (gain) arising during the period | | | 81,849 | | | | (15,916 | ) | | | Amortization of regulatory asset | | | (5,772 | ) | | | (8,578 | ) | | | Amortization of transition obligation | | | - | | | | 3,189 | | | | Amortization of prior service (cost) credit | | | 1,486 | | | | (2,277 | ) | | | Amortization of loss | | | 16,139 | | | | 9,927 | | | | Deferred income taxes | | | (10,622 | ) | | | (87 | ) | | | Total recognized in other comprehensive income (loss) | | $ | 16,837 | | | $ | 141 | | | | | |
| | | Pension Benefits | | | Postretirement Benefits | | | | | December 31, 2008 | | | December 31, 2008 | | | | | (Thousands of dollars) | | | Regulatory asset gain (loss) | | $ | 252,747 | | | $ | 492 | | | Net gain (loss) arising during the period | | | (343,274 | ) | | | (1,531 | ) | | Amortization of regulatory asset | | | (11,465 | ) | | | (12,911 | ) | | Amortization of transition obligation | | | - | | | | 3,986 | | | Amortization of prior service (cost) credit | | | 1,941 | | | | (2,504 | ) | | Amortization of loss | | | 11,935 | | | | 13,715 | | | Deferred income taxes | | | 34,417 | | | | (816 | ) | | Total recognized in other comprehensive income (loss) | | $ | (53,699 | ) | | $ | 431 | |
The table below sets forth the amounts in accumulated other comprehensive income (loss) that had not yet been recognized as components of net periodic benefit expense. | | | | | | | | | | | | | | | | | | | | | | Pension Benefits
December 31, | | | Postretirement Benefits
December 31, | | | | 2007 | | | 2006 | | | 2007 | | | 2006 | | | | | | | (Thousands of dollars) | | | | Transition obligation | | $ | - | | | $ | - | | | $ | (16,711 | ) | | $ | (19,900 | ) | | | Prior service credit (cost) | | | (8,791 | ) | | | (10,277 | ) | | | 10,888 | | | | 13,165 | | | | Accumulated gain (loss) | | | (123,750 | ) | | | (221,738 | ) | | | (125,412 | ) | | | (119,423 | ) | | | Accumulated other comprehensive income (loss) before regulatory assets | | | (132,541 | ) | | | (232,015 | ) | | | (131,235 | ) | | | (126,158 | ) | | | Regulatory asset for regulated entities | | | 90,600 | | | | 162,615 | | | | 98,038 | | | | 92,732 | | | | Accumulated other comprehensive income (loss) after regulatory assets | | | (41,941 | ) | | | (69,400 | ) | | | (33,197 | ) | | | (33,426 | ) | | | Deferred income taxes | | | 16,222 | | | | 26,844 | | | | 12,841 | | | | 12,929 | | | | Accumulated other comprehensive income (loss), net of tax | | $ | (25,719 | ) | | $ | (42,556 | ) | | $ | (20,356 | ) | | $ | (20,497 | ) | | | | |
| | | Pension Benefits | | | Postretirement Benefits | | | | | December 31, | | | December 31, | | | | | 2008 | | | 2007 | | | 2008 | | | 2007 | | | | | (Thousands of dollars) | | | Transition obligation | | $ | - | | | $ | - | | | $ | (12,724 | ) | | $ | (16,711 | ) | | Prior service credit (cost) | | | (6,852 | ) | | | (8,791 | ) | | | 8,384 | | | | 10,888 | | | Accumulated gain (loss) | | | (455,089 | ) | | | (123,750 | ) | | | (113,228 | ) | | | (125,412 | ) | Accumulated other comprehensive income (loss) before regulatory assets | | | (461,941 | ) | | | (132,541 | ) | | | (117,568 | ) | | | (131,235 | ) | | Regulatory asset for regulated entities | | | 331,882 | | | | 90,600 | | | | 85,619 | | | | 98,038 | | Accumulated other comprehensive income (loss) after regulatory assets | | | (130,059 | ) | | | (41,941 | ) | | | (31,949 | ) | | | (33,197 | ) | | Deferred income taxes | | | 50,307 | | | | 16,222 | | | | 12,358 | | | | 12,841 | | Accumulated other comprehensive income (loss), net of tax | | $ | (79,752 | ) | | $ | (25,719 | ) | | $ | (19,591 | ) | | $ | (20,356 | ) |
The following table sets forth the amounts recognized in either accumulated comprehensive income (loss) or regulatory assets expected to be recognized as components of net periodic benefit expense in the next fiscal year. | | | | | | | | | | | | | Pension
Benefits | | Postretirement
Benefits | | | | | Amounts to be recognized in 2008 | | (Thousands of dollars) | | | | Transition obligation | | $ | - | | $ | 3,189 | | | | Prior service credit (cost) | | $ | 1,551 | | $ | (2,003 | ) | | | Net loss | | $ | 9,548 | | $ | 10,972 | | | |
| | | Pension | | | Postretirement | | | | | Benefits | | | Benefits | | | Amounts to be recognized in 2009 | (Thousands of dollars) | | Transition obligation | | $ | - | | | $ | 3,189 | | | Prior service credit (cost) | | $ | 1,565 | | | $ | (2,003 | ) | | Net loss | | $ | 17,322 | | | $ | 9,660 | |
Actuarial Assumptions - The following table sets forth the weighted-average assumptions used to determine benefit obligations for the periods indicated. | | | | | | | | | | | | | | Pension Benefits
December 31, | | Postretirement Benefits
December 31, | | | | 2007 | | 2006 | | 2007 | | 2006 | | | Discount rate | | 6.25% | | 6.00% | | 6.25% | | 6.00% | | | Compensation increase rate | | 3.5% - 4.5% | | 3.5% - 4.5% | | 3.5% - 4.0% | | 3.5% - 4.0% | | |
| | | Pension Benefits | | Postretirement Benefits | | | | December 31, | | | December 31, | | | | | 2008 | | 2007 | | | 2008 | | 2007 | | | Discount rate | | 6.25% | | 6.25% | | | 6.25% | | 6.25% | | | Compensation increase rate | | 4.3% - 4.8% | | 3.5% - 4.5% | | | 4.3% - 4.8% | | 3.5% - 4.0% | |
The following table sets forth the weighted-average assumptions used to determine net periodic benefit costs for the periods indicated. | | | | | | | | | | | | | | Pension Benefits
December 31, | | Postretirement Benefits
December 31, | | | | 2007 | | 2006 | | 2007 | | 2006 | | | Discount rate | | 6.00% | | 5.75% | | 6.00% | | 5.75% | | | Expected long-term return on plan assets | | 8.75% | | 8.75% | | 8.75% | | 8.75% | | | Compensation increase rate | | 3.5% - 4.5% | | 3.5% - 4.5% | | 3.5% - 4.0% | | 3.5% - 4.0% | | |
| | | Pension Benefits | | Postretirement Benefits | | | | December 31, | | | December 31, | | | | | 2008 | | 2007 | | | 2008 | | 2007 | | | Discount rate | | 6.25% | | 6.00% | | | 6.25% | | 6.00% | | | Expected long-term return on plan assets | | 8.50% | | 8.75% | | | 8.50% | | 8.75% | | | Compensation increase rate | | 3.5% - 4.5% | | 3.5% - 4.5% | | | 3.5% - 4.0% | | 3.5% - 4.0% | |
We determine our overall expected long-term rate of return on plan assets assumption based on our review of historical returns and the building block and economic growth models from our consultants.
Our discount rates for 20072008 and 20062007 are based on matching the amount and timing of the projected benefit payments to a spot-rate yield curve, which provides zero couponzero-coupon interest rates into the future. The methodology for developing the yield curve includes selecting the bonds to be included (only bonds rated Aa by Moody’s but excluding callable bonds, bonds with less than a minimum issue size, yield “outliers” and various other filtering criteria to remove unsuitable bonds). Once the bonds are selected, a best-fit regression curve to the bond data is determined, modeling yield to maturity as a function of years to maturity. This coupon yield curve is converted to a spot-yield curve using the calculation technique that assumes the price of a coupon bond for a given maturity equals the present value of the underlying bond cash flows using zero-coupon spot rates. Once the yield curve is developed, the projected cash flows for the plan for each year in the future are calculated. These projected cash flows values are based on the most recent valuation. Each annual cash flow of the plan obligations is discounted using the yield at the appropriate point on the curve, and then the single equivalent discount rate that would yield the same value for the cash flow is determined.
Health Care Cost Trend Rates- The following table sets forth the assumed health care cost trend rates for the periods indicated. | | | | | | | | | | 2007 | | 2006 | | | Health care cost trend rate assumed for next year | | 6.6% - 9.0% | | 6.6% - 9.0% | | | Rate to which the cost trend rate is assumed to decline (the ultimate trend rate) | | 5.0% | | 5.0% | | | Year that the rate reaches the ultimate trend rate | | 2012 | | 2011 | | |
| | | | 2008 | | 2007 | | Health care cost trend rate assumed for next year | | 5.0% - 9.0% | | 6.6% - 9.0% | | Rate to which the cost trend rate is assumed | | | | | | | to decline (the ultimate trend rate) | | | 5.0% | | 5.0% | | Year that the rate reaches the ultimate trend rate | | | 2018 | | 2012 |
Assumed health care cost trend rates have a significant effect on the amounts reported for our health care plans. A one-percentage point change in assumed health care cost trend rates would have the following effects. | | | | | | | | | | | | | One-Percentage Point Increase | | One-Percentage Point Decrease | | | | | | | (Thousands of dollars) | | | | Effect on total of service and interest cost | | $ | 1,969 | | $ | (1,665 | ) | | | Effect on postretirement benefit obligation | | $ | 20,685 | | $ | (18,014 | ) | | |
| | | One-Percentage | | | One-Percentage | | | | | Point Increase | | | Point Decrease | | | | | (Thousands of dollars) | | | Effect on total of service and interest cost | | $ | 1,989 | | | $ | (1,706 | ) | | Effect on postretirement benefit obligation | | $ | 19,585 | | | $ | (17,171 | ) |
Plan Assets- The following table sets forth our pension and postretirement benefit plan weighted-average asset allocations as of the measurement date. | | | | | | | | | | | | | | | | Asset | | Pension Benefits
Percentage of Plan Assets | | | Postretirement Benefits
Percentage of Plan Assets | | Category | | 2007 | | | 2006 | | | 2007 | | | 2006 | | | | Corporate bonds | | 6 | % | | 6 | % | | 14 | % | | 16 | % | | | Insurance contracts | | 11 | % | | 13 | % | | - | | | - | | | | High yield corporate bonds | | 10 | % | | 10 | % | | - | | | - | | | | Large-cap value equities | | 15 | % | | 14 | % | | 15 | % | | 16 | % | | | Large-cap growth equities | | 18 | % | | 16 | % | | 22 | % | | 23 | % | | | Mid-cap equities | | 13 | % | | 14 | % | | - | | | - | | | | Small-cap equities | | 11 | % | | 12 | % | | 24 | % | | 24 | % | | | International equities | | 16 | % | | 14 | % | | 13 | % | | 13 | % | | | Other | | - | | | 1 | % | | 12 | % | | 8 | % | | | Total | | 100 | % | | 100 | % | | 100 | % | | 100 | % | | | | |
| | Pension Benefits | | | Postretirement Benefits | | | | Percentage of Plan Assets | | | Percentage of Plan Assets | | | Asset Category | | 2008 | | | 2007 | | | 2008 | | | 2007 | | | Corporate bonds | | | 5 | % | | | 6 | % | | | 25 | % | | | 14 | % | | Insurance contracts | | | 13 | % | | | 11 | % | | | - | | | | - | | | High yield corporate bonds | | | 9 | % | | | 10 | % | | | - | | | | - | | | Large-cap value equities | | | 12 | % | | | 15 | % | | | 14 | % | | | 15 | % | | Large-cap growth equities | | | 14 | % | | | 18 | % | | | 17 | % | | | 22 | % | | Mid-cap equities | | | 9 | % | | | 13 | % | | | 6 | % | | | 8 | % | | Small-cap equities | | | 7 | % | | | 11 | % | | | 12 | % | | | 16 | % | | International equities | | | 12 | % | | | 16 | % | | | 10 | % | | | 13 | % | | Other (a) | | | 19 | % | | | - | | | | 16 | % | | | 12 | % | | Total | | | 100 | % | | | 100 | % | | | 100 | % | | | 100 | % | | (a) - Primarily money market funds | | | | | | | | | | | | | |
Our investment strategy is to invest plan assets in accordance with sound investment practices that emphasize long-term fundamentals. The goal of this strategy is to maximize investment returns while managing risk in order to meet the plan’s current and projected financial obligations. The plan’s investments include a diverse blend of various US and international equities, investments in various classes of debt securities, insurance contracts and venture capital. The target allocation for the assets of our pension plan is as follows.
| | | | | | Corporate bonds / insurance contracts | | | 20 | % | | | High yield corporate bonds | | | 10 | % | | | Large-cap value equities | | | 16 | % | | | Large-cap growth equities | | | 16 | % | | | Mid- and small-cap value equities | | | 10 | % | | | Mid- and small-cap growth equities | | | 10 | % | | | International equities | | | 15 | % | | | Alternative investments | | | 2 | % | | | Venture capital | | | 1 | % | | Total | | Total
| | 100 | % | | | |
As part of our risk management for the plans, minimums and maximums have been set for each of the asset classes listed above. All investment managers for the plan are subject to certain restrictions on the securities they purchase and, with the exception of indexing purposes, are prohibited from owning our stock.
Contributions- For 2007, $4.12008, $113.7 million and $7.6$8.0 million of contributions were made to our pension plan and other postretirement benefit plan, respectively. We presently anticipate our total 20082009 contributions will be $3.1$31.2 million for the pension plan and $11.0$11.4 million for the other postretirement benefit plan.
Pension and Other Postretirement Benefit Payments - For 2007, benefitBenefit payments for our pension and other postretirement benefit plans for the 15-month period ending December 31, 2008, were $50.6$66.6 million and $15.5$26.7 million, respectively. The following table sets forth the pension benefits and postretirement benefit payments expected to be paid in 2008-2017.2009-2018. | | | | | | | | | | | | Pension Benefits | | Postretirement Benefits | | | | Benefits to be paid in: | | (Thousands of dollars) | | | 2008 | | $ | 48,901 | | $ | 16,682 | | | 2009 | | | 51,417 | | | 17,191 | | | 2010 | | | 52,488 | | | 18,454 | | | 2011 | | | 54,752 | | | 19,655 | | | 2012 | | | 57,948 | | | 20,686 | | | 2013 through 2017 | | | 326,740 | | | 115,474 | | |
| | Pension Benefits | Postretirement Benefits | | Benefits to be paid in: | (Thousands of dollars) | | 2009 | $ 52,958 | | | $ | 16,155 | | | 2010 | $ 54,317 | | | $ | 17,253 | | | 2011 | $ 55,882 | | | $ | 18,300 | | | 2012 | $ 58,275 | | | $ | 19,238 | | | 2013 | $ 60,136 | | | $ | 19,354 | | | 2014 through 2018 | $ 339,437 | | | $ | 113,661 | |
The expected benefits to be paid are based on the same assumptions used to measure our benefit obligation at December 31, 2007,2008, and include estimated future employee service.
Other Employee Benefit Plans
Thrift Plan - We have a Thrift Plan covering all full-time employees. Employee contributions are discretionary. We match 100 percent of employee contributions up to 6 percent of each participant’s eligible compensation, subject to certain limits. Our contributions made to the plan were $14.7 million, $13.2 million and $12.8 million in 2008, 2007 and $10.5 million in 2007, 2006, and 2005, respectively.
Profit-Sharing Plan - We have a profit-sharing plan for all nonbargaining unit employees hired after December 31, 2004. Nonbargaining unit employees who were employed prior to January 1, 2005, were given a one-time opportunity to make an irrevocable election to participate in the profit-sharing plan and not accrue any additional benefits under our defined benefit pension plan after December 31, 2004. We plan to make a contribution to the profit-sharing plan each quarter equal to 1 percent of each participant’s eligible compensation during the quarter. Additional discretionary employer contributions may be made at the end of each year. Employee contributions are not allowed under the plan. Our contributions made to the plan were $3.2 million, $2.7 million and $1.6 million in 2008, 2007 and $0.6 million in 2007, 2006, and 2005, respectively. Employee Deferred Compensation Plan- The ONEOK, Inc. 2005 Nonqualified Deferred Compensation Plan provides select employees, as approved by our Board of Directors, with the option to defer portions of their compensation and provides nonqualified deferred compensation benefits that are not available due to limitations on employer and employee contributions to qualified defined contribution plans under the federal tax laws. Our contributions made to the plan were $0.3 million, $0.4 millionnot material in 2008, 2007 and $0.2 million in 2007, 2006 and 2005, respectively.2006.
K. COMMITMENTS AND CONTINGENCIES
K.
| COMMITMENTS AND CONTINGENCIES |
Operating Leases - The initial lease term of our headquarters building, ONEOK Plaza, is for 25 years, expiring in 2009, with six five-year renewal options. At the end of the initial term or any renewal period, we can purchase the property at its fair market value. In July 2007, ONEOK Leasing Company, our subsidiary, gave notice of its intent to exercise its option to purchase ONEOK Plaza on or before the end of the current lease term set to expire on September 30, 2009. In addition,March 2008, ONEOK Leasing Company has entered into a purchase agreement with the owner ofpurchased ONEOK Plaza that, if certain conditions are met, would accelerate the purchase of the building tofor a date on or before March 31, 2008. The total purchase price of approximately $48 million, would includewhich included $17.1 million for the present value of the remaining lease payments and the $30.9 million for the base purchase price. The $17.1 million amount is included in the 2008 amount in the table below. If the purchase transaction does not occur, annual rent expense for the lease will be approximately $6.8 million in 2008 and 2009, and estimated future minimum rental payments for the lease will be $9.3 million in 2008 and 2009. Rent payments were $9.3 million in 2007, 2006 and 2005.
We have the right to subletlease excess office space in ONEOK Plaza. We received rental revenue of $2.6 million in 2008 and $2.9 million in 2007 2006 and 2005.2006. Estimated minimum future rental payments to be received under existing contracts for subleases are $2.6$1.9 million in 2008, $1.8 million in 2009, and $0.8 million in 2010 and $0.7 million in 2011.
Future minimum lease payments under non-cancelable operating leases on a gas processing plant, storage contracts, office space, pipeline equipment, rights-of-way and vehicles are shown in the table below. | | | | | | | | | | | | | | | ONEOK | | ONEOK
Partners | | Total | | | | | | (Millions of dollars) | | | 2008 | | $ | 121.0 | | $ | 7.3 | | $ | 128.3 | | | 2009 | | | 94.0 | | | 2.4 | | | 96.4 | | | 2010 | | | 74.4 | | | 1.4 | | | 75.8 | | | 2011 | | | 75.1 | | | 1.2 | | | 76.3 | | | 2012 | | | 37.6 | | | 1.1 | | | 38.7 | | |
| | | | ONEOK | ONEOK Partners | Total | | | | | (Millions of dollars) | | | 2009 | | $ 88.8 | $ 18.4 | $ 107.2 | | | 2010 | | $ 55.9 | $ 16.0 | $ 71.9 | | | 2011 | | $ 61.2 | $ 15.5 | $ 76.7 | | | 2012 | | $ 32.9 | $ 8.8 | $ 41.7 | | | 2013 | | $ 25.4 | $ 2.1 | $ 27.5 |
The amounts in the ONEOK column above include the following minimum lease payments relating to the lease of a gas processing plant for $24.2 million in 2008, $24.0 million in 2009, $24.2 million in 2010, and $30.6 million in 2011. We acquired the lease in a business combination and recorded a liability for uneconomic lease terms. The liability is accreted to rent expense in the amount of $13.0 million per year over the term of the lease; however, the cash outflow under the lease remains the same. The amounts in the ONEOK Partners column above excludesexclude intercompany payments relating to the lease of a gas processing plant.
Environmental Liabilities - We are subject to multiple environmental, historical and wildlife preservation laws and regulations affecting many aspects of our present and future operations, includingoperations. Regulated activities include those involving air emissions, water quality,stormwater and wastewater discharges, handling and disposal of solid wastes and hazardous material,wastes, hazardous materials transportation, and substance management.pipeline and facility construction. These laws and regulations generally require us to obtain and comply with a wide variety of environmental clearances, registrations, licenses, permits inspections and other approvals. Failure to comply with these laws, regulations, permits and licenses may expose us to fines, penalties and/or interruptions in our operations that could be material to theour results of operations. If an accidentala leak or spill of hazardous materialssubstances or petroleum products occurs from our lines or facilities, in the process of transporting natural gas, NGLs, or refined products, or at any facility that we own, operate or otherwise use, we could be held jointly and severally liable for all resulting liabilities, including investigation and clean upclean-up costs, which could materially affect our results of operations and cash flows. In addition, emission controls required under the federal Clean Air Act and other similar federal and state laws could require unexpected capital expenditures at our facilities. We cannot assure that existing environmental regulations will not be revised or that new regulations will not be adopted or become applicable to us. 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 our business, financial condition and results of operations.
We own or retain 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 KDHE presently governs all work at these sites. The terms of the consent agreement allow us to investigate these sites and set remediation activities based upon the results of the investigations and risk analysis. Remediation typically involves the management of contaminated soils and may involve removal of structures and monitoring and/or remediation of groundwater. We
Of the 12 sites, we have commenced soil remediation on 11 sites, with regulatorysites. Regulatory closure has been achieved at two of these locations. Of the remaining nine sites,locations, and we have completed or are near completion of soil remediation at seven sites and have commenced soil remediation on the other twonine sites. We have begun site assessment at the remaining site where no active remediation has occurred. Our expenditures for environmental evaluation and remediation to date have not been significant in relation to our results of operations, and there have been no material effects upon earnings during 2007, 2006 or 2005 related to compliance with environmental regulations.
To date, we have incurred remediation costs of $6.9$7.8 million and have accrued an additional $5.1$4.2 million related to the sites where soil remediation has yet to be completed. These estimates are recorded on an undiscounted basis. For the site that is currently in the assessment phase, we have completed some analysis but are unable at this point to accurately estimate aggregate costs that may be required to satisfy our remedial obligations at this site. Until the site assessment is complete and the KDHE approves the remediation plan, we will not have complete information available to us to accurately estimate remediation costs.
The costs associated with these sites do not include other potential expenses that might be incurred, such as ongoing and additional water monitoring and remediation, unasserted property damage claims, personal injury or natural resource claims, unbudgeted legal expenses or other costs for which we may be held liable but with respect to which we cannot reasonably estimate an amount. As of this date, we have no knowledge of any of these types of claims. The foregoing estimates do not consider potential insurance recoveries, recoveries through rates or recoveries from unaffiliated parties, to which we may be entitled. We have filed claims with our insurance carriers relating to these sites, and we have recovered a portion of our costs incurred to date. We have not recorded any amounts for potential insurance recoveries or recoveries from unaffiliated parties, and we are not recovering any environmental amounts in rates. As more information related to the site investigations and remediation activities becomes available, and to the extent such amounts are expected to exceed our current estimates, additional expenses could be recorded. Such amounts could be material to our results of operations and cash flows depending on the remediation and number of years over which the remediation is required to be completed.
Our expenditures for environmental evaluation, mitigation and remediation to date have not been significant in relation to our results of operations, and there were no material effects upon earnings during 2008, 2007 or 2006 related to compliance with environmental regulations.
Legal Proceedings - We are a party to various litigation matters and claims that are normal in the normal course of our operations. While the results of litigation and claims cannot be predicted with certainty, we believe the final outcome of such matters will not have a material adverse effect on our consolidated results of operations, financial position or liquidity.
OtherFERC Matter - As a result of an internal review of a transaction that was brought to the attention of one of our affiliates by a third party, we have commencedconducted an internal review of transactions that may have violated FERC natural gas capacity release rules or related rules. While our internal review is ongoing, we believe it is likelyrules and determined that a limited number of thesethere were transactions will have violated FERC capacity release rules or related rules.that should be disclosed to the FERC. We have notified the FERC of this review and expect to filefiled a report with the FERC regarding these transactions in March 2008. We cooperated fully with the FERC in its investigation of this matter and have taken steps to better ensure that current and future transactions comply with applicable FERC regulations by mid-March 2008 concerning any violations. Atimplementing a compliance plan dealing with capacity release. We entered into a global settlement with the FERC to resolve this time, we do not believe that penalties, if any, associated with potential violations will havematter and other FERC enforcement matters, which was approved by the FERC on January 15, 2009. The global settlement provides for a material impacttotal civil penalty of $4.5 million and approximately $2.2 million in disgorgement of profits and interest, of which $1.7 million of the civil penalty was allocated to ONEOK Partners. The amounts were recorded as a liability on our resultsConsolidated Balance Sheet as of operations, financial position or liquidity.December 31, 2008. We made the required payments in January 2009.
L. INCOME TAXES
L.
| INCOME TAXES |
The following table sets forth our provisions for income taxes for the periods indicated. | | | | | | | | | | | | | | | | Years Ended December 31, | | | | | | 2007 | | 2006 | | | 2005 | | | | Current income taxes | | (Thousands of dollars) | | | Federal | | $ | 100,517 | | $ | 69,698 | | | $ | 186,486 | | | State | | | 19,063 | | | 10,312 | | | | 27,589 | | | Total current income taxes from continuing operations | | | 119,580 | | | 80,010 | | | | 214,075 | | | Deferred income taxes | | | | | | | | | | | | | Federal | | | 56,887 | | | 96,464 | | | | 24,780 | | | State | | | 8,130 | | | 17,290 | | | | 3,666 | | | Total deferred income taxes from continuing operations | | | 65,017 | | | 113,754 | | | | 28,446 | | | | | | | | Total provision for income taxes before discontinued operations | | | 184,597 | | | 193,764 | | | | 242,521 | | | Discontinued operations | | | - | | | (232 | ) | | | 86,926 | | | Total provision for income taxes | | $ | 184,597 | | $ | 193,532 | | | $ | 329,447 | | | | |
| | Years Ended December 31, | | | | | 2008 | | | 2007 | | | 2006 | | | Current income taxes | (Thousands of dollars) | | | Federal | | $ | 18,833 | | | $ | 100,517 | | | $ | 69,698 | | | State | | | 10,047 | | | | 19,063 | | | | 10,312 | | | Total current income taxes from continuing operations | | | 28,880 | | | | 119,580 | | | | 80,010 | | | Deferred income taxes | | | | | | | | | | | | | | Federal | | | 143,807 | | | | 56,887 | | | | 96,464 | | | State | | | 21,384 | | | | 8,130 | | | | 17,290 | | | Total deferred income taxes from continuing operations | | | 165,191 | | | | 65,017 | | | | 113,754 | | | | | | | | | | | | | | | | | Total provision for income taxes before discontinued operations | | | 194,071 | | | | 184,597 | | | | 193,764 | | | Discontinued operations | | | - | | | | - | | | | (232 | ) | | Total provision for income taxes | | $ | 194,071 | | | $ | 184,597 | | | $ | 193,532 | |
The following table is a reconciliation of our provision for income taxestax expense for the periods indicated. | | | | | | | | | | | | | | | | | | Years Ended December 31, | | | | | | | 2007 | | | 2006 | | | 2005 | | | | | | | (Thousands of dollars) | | | | Pretax income from continuing operations | | $ | 489,518 | | | $ | 500,441 | | | $ | 645,669 | | | | Federal statutory income tax rate | | | 35 | % | | | 35 | % | | | 35 | % | | | Provision for federal income taxes | | | 171,331 | | | | 175,154 | | | | 225,984 | | | | Amortization of distribution property investment tax credit | | | (505 | ) | | | (525 | ) | | | (568 | ) | | | State income taxes, net of federal tax benefit | | | 17,676 | | | | 18,809 | | | | 20,316 | | | | Other, net | | | (3,905 | ) | | | 326 | | | | (3,211 | ) | | | Income tax expense | | $ | 184,597 | | | $ | 193,764 | | | $ | 242,521 | | | | | |
| | | Years Ended December 31, | | | | | 2008 | | | 2007 | | | 2006 | | | | | (Thousands of dollars) | | | Pretax income from continuing operations | | $ | 505,980 | | | $ | 489,518 | | | $ | 500,441 | | | Federal statutory income tax rate | | | 35 | % | | | 35 | % | | | 35 | % | | Provision for federal income taxes | | | 177,093 | | | | 171,331 | | | | 175,154 | | | Amortization of distribution property investment tax credit | | | (455 | ) | | | (505 | ) | | | (525 | ) | | State income taxes, net of federal tax benefit | | | 20,431 | | | | 17,676 | | | | 18,809 | | | Other, net | | | (2,998 | ) | | | (3,905 | ) | | | 326 | | | Income tax expense | | $ | 194,071 | | | $ | 184,597 | | | $ | 193,764 | |
The following table sets forth the tax effects of temporary differences that gave rise to significant portions of the deferred tax assets and liabilities for the periods indicated. | | | | | | | | | | | | December 31, | | | | | | 2007 | | 2006 | | | | Deferred tax assets | | (Thousands of dollars) | | | Employee benefits and other accrued liabilities | | $ | 134,056 | | $ | 129,571 | | | Net operating loss carryforward | | | 4,715 | | | 7,971 | | | Other | | | 27,374 | | | 38,967 | | | Total deferred tax assets | | | 166,145 | | | 176,509 | | | | | | | Deferred tax liabilities | | | | | | | | | Excess of tax over book depreciation and depletion | | | 344,601 | | | 414,223 | | | Purchased gas adjustment | | | 9,015 | | | 13,107 | | | Investment in joint ventures | | | 490,093 | | | 374,057 | | | Regulatory assets | | | 115,689 | | | 108,182 | | | Other comprehensive income | | | 1,567 | | | 26,256 | | | Other | | | 2,720 | | | - | | | Total deferred tax liabilities | | | 963,685 | | | 935,825 | | | Net deferred tax liabilities | | $ | 797,540 | | $ | 759,316 | | | | |
| | | December 31, | | | | | 2008 | | | 2007 | | | Deferred tax assets | | (Thousands of dollars) | | | Employee benefits and other accrued liabilities | | $ | 161,947 | | | $ | 134,056 | | | Net operating loss carryforward | | | 4,226 | | | | 4,715 | | | Other comprehensive income | | | 43,747 | | | | - | | | Other | | | 23,051 | | | | 27,374 | | | Total deferred tax assets | | | 232,971 | | | | 166,145 | | | | | | | | | | | | | Deferred tax liabilities | | | | | | | | | | Excess of tax over book depreciation and depletion | | | 372,123 | | | | 344,601 | | | Purchased gas adjustment | | | 20,047 | | | | 9,015 | | | Investment in joint ventures | | | 564,234 | | | | 490,093 | | | Regulatory assets | | | 180,037 | | | | 115,689 | | | Other comprehensive income | | | - | | | | 1,567 | | | Other | | | 746 | | | | 2,720 | | | Total deferred tax liabilities | | | 1,137,187 | | | | 963,685 | | | Net deferred tax liabilities | | $ | 904,216 | | | $ | 797,540 | |
At December 31, 2007,2008, ONEOK Partners had approximately $5.0$4.2 million of tax benefits available related to net operating loss carryforwards, which will expire between the years 2022 and 2026.2027. We believe that it is more likely than not that the tax benefits of the net operating loss carryforwards will be utilized prior to their expiration; therefore, no valuation allowance is necessary.
We had income taxes receivable of approximately $13.2$77.1 million and $70.0$13.2 million at December 31, 2008 and 2007, and 2006, respectively. Segment Descriptions - We have divided our operations into four reportable business segments based on similarities in economic characteristics, products and services, types of customers, methods of distribution and regulatory environment. These segments are as follows: (i) our ONEOK Partners segment gathers, processes, transports, stores and sells natural gas and gathers, treats, fractionates, stores, distributes and markets NGLs; (ii) our Distribution segment delivers natural gas to residential, commercial and industrial customers, and transports natural gas; (iii) our Energy Services segment markets natural gas to wholesale and retail customers; and (iv) our Other segment primarily consists of the operating and leasing operations of our headquarters building and a related parking facility. Our Distribution segment is comprised of regulated public utilities, and portions of our ONEOK Partners segment are also regulated. In September 2005, we completed the sale of our former production segment. Additionally, in the third quarter of 2005, we made the decision to sell our Spring Creek power plant, located in Oklahoma, and exit the power generation business. The transaction received FERC approval and was completed on October 31, 2006. These components of our business are accounted for as discontinued operations in accordance with Statement 144. Our production business is included in our Other segment in the 2005 table below, while our power generation business is included in our Energy Services segment.
Accounting Policies - The accounting policies of the segments are described in Note A. Intersegment sales are recorded on the same basis as sales to unaffiliated customers. Corporate overheadOverhead costs relating to a reportable segment have been allocated for the purpose of calculating operating income. Our equity method investments do not represent operating segments.
Customers - The primary customers for our ONEOK Partners segment include major and independent oil and gas production companies, natural gas gathering and processing companies, petrochemical, refining and refiningNGL marketing companies, LDCs, power generating companies, natural gas producers, marketers, industrial facilities, LDCsmarketing companies, NGL gathering companies and electric power generating plants.propane distributors. Our Distribution segment provides natural gas to residential, commercial, industrial, wholesale, public authority and transportation customers. Our Energy Services segment buys natural gas from producers and other marketing companies and sells natural gas and power to LDCs, municipalities, producers, large industrials, power generators, retail aggregators and other marketing companies, as well as residential and small commercial/industrial companies.
In 2008, 2007 2006 and 2005,2006, we had no single external customer from which we received 10 percent or more of our consolidated gross revenues.
Operating Segment Information - - The following tables set forth certain selected financial information for our four operating segments for the periods indicated. | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2007 | | ONEOK Partners (a) | | Distribution (b) | | | Energy Services | | | Other and Eliminations | | | Total | | | | | | | (Thousands of dollars) | Sales to unaffiliated customers | | $ | 5,204,794 | | $ | 2,099,056 | | | $ | 6,180,697 | | | $ | 3,480 | | | $ | 13,488,027 | | | | Energy trading revenues, net | | | - | | | - | | | | (10,613 | ) | | | - | | | | (10,613 | ) | | | Intersegment sales | | | 626,764 | | | 7 | | | | 459,319 | | | | (1,086,090 | ) | | | - | | | | Total Revenues | | $ | 5,831,558 | | $ | 2,099,063 | | | $ | 6,629,403 | | | $ | (1,082,610 | ) | | $ | 13,477,414 | | | | | | | | | | | Net margin | �� | $ | 895,893 | | $ | 663,648 | | | $ | 247,402 | | | $ | 3,165 | | | $ | 1,810,108 | | | | Operating costs | | | 337,356 | | | 377,778 | | | | 39,920 | | | | 6,456 | | | | 761,510 | | | | Depreciation and amortization | | | 113,704 | | | 111,615 | | | | 2,147 | | | | 498 | | | | 227,964 | | | | Gain on sale of assets | | | 1,950 | | | (56 | ) | | | - | | | | 15 | | | | 1,909 | | | | Operating income | | $ | 446,783 | | $ | 174,199 | | | $ | 205,335 | | | $ | (3,774 | ) | | $ | 822,543 | | | | | | | | | | | Equity earnings from investments | | $ | 89,908 | | $ | - | | | $ | - | | | $ | - | | | $ | 89,908 | | | | Investments in unconsolidated affiliates | | $ | 756,260 | | $ | - | | | $ | - | | | $ | - | | | $ | 756,260 | | | | Minority Interests in consolidated subsidiaries | | $ | 5,802 | | $ | - | | | $ | - | | | $ | 796,162 | | | $ | 801,964 | | | | Total assets | | $ | 6,112,065 | | $ | 2,757,796 | | | $ | 1,178,006 | | | $ | 1,014,167 | | | $ | 11,062,034 | | | | Capital expenditures | | $ | 709,858 | | $ | 162,044 | | | $ | 158 | | | $ | 11,643 | | | $ | 883,703 | | | |
| | | | | | | | | | | | | | | | | (a) | | - | | Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment’s regulated operations had revenues of $344.3 million, net margin of $274.0 million and operating income of $122.4 million. | (b) | | - | | All of our Distribution segment’s operations are regulated. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2006 | | ONEOK
Partners (a) | | Distribution (b) | | Energy
Services | | | Other and
Eliminations | | | Total | | | | | | | (Thousands of dollars) | | | | Sales to unaffiliated customers | | $ | 4,142,546 | | $ | 1,958,192 | | $ | 5,839,461 | | | $ | (26,670 | ) | | $ | 11,913,529 | | | | Energy trading revenues, net | | | - | | | - | | | 6,797 | | | | - | | | | 6,797 | | | | Intersegment sales | | | 595,702 | | | 7 | | | 489,549 | | | | (1,085,258 | ) | | | - | | | | Total Revenues | | $ | 4,738,248 | | $ | 1,958,199 | | $ | 6,335,807 | | | $ | (1,111,928 | ) | | $ | 11,920,326 | | | | | | | | | | | Net margin | | $ | 843,548 | | $ | 599,797 | | $ | 273,818 | | | $ | 4,821 | | | $ | 1,721,984 | | | | Operating costs | | | 325,774 | | | 371,460 | | | 42,464 | | | | 1,069 | | | | 740,767 | | | | Depreciation and amortization | | | 122,045 | | | 110,858 | | | 2,149 | | | | 491 | | | | 235,543 | | | | Gain on sale of assets | | | 115,483 | | | 18 | | | - | | | | 1,027 | | | | 116,528 | | | | Operating income | | $ | 511,212 | | $ | 117,497 | | $ | 229,205 | | | $ | 4,288 | | | $ | 862,202 | | | | | | | | | | | Income (loss) from operations of discontinued components | | $ | - | | $ | - | | $ | (365 | ) | | $ | - | | | $ | (365 | ) | | | Equity earnings from investments | | $ | 95,883 | | $ | - | | $ | - | | | $ | - | | | $ | 95,883 | | | | Investments in unconsolidated affiliates | | $ | 748,879 | | $ | - | | $ | - | | | $ | - | | | $ | 748,879 | | | | Minority Interests in consolidated subsidiaries | | $ | 5,606 | | $ | - | | $ | - | | | $ | 795,039 | | | $ | 800,645 | | | | Total assets | | $ | 4,921,717 | | $ | 2,756,673 | | $ | 2,042,935 | | | $ | 669,757 | | | $ | 10,391,082 | | | | Capital expenditures | | $ | 201,746 | | $ | 159,026 | | $ | - | | | $ | 15,534 | | | $ | 376,306 | | | |
| | | | | (a) | | - | | Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment’s regulated operations had revenues of $335.9 million, net margin of $261.9 million and operating income of $240.1 million, including $113.9 million from a gain on sale of assets, for the year ended December 31, 2006. | (b) | | - | | All of our Distribution segment’s operations are regulated. |
| | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2005 | | ONEOK
Partners (a) | | | Distribution (b) | | Energy
Services | | | Other and
Eliminations | | | Total | | | | | | | (Thousands of dollars) | | | | Sales to unaffiliated customers | | $ | 3,519,774 | | | $ | 2,216,207 | | $ | 7,638,711 | | | $ | (711,142 | ) | | $ | 12,663,550 | | | | Energy trading revenues, net | | | - | | | | - | | | 12,680 | | | | - | | | | 12,680 | | | | Intersegment sales | | | 814,825 | | | | - | | | 707,360 | | | | (1,522,185 | ) | | | - | | | | Total Revenues | | $ | 4,334,599 | | | $ | 2,216,207 | | $ | 8,358,751 | | | $ | (2,233,327 | ) | | $ | 12,676,230 | | | | | | | | | | | Net margin | | $ | 546,769 | | | $ | 587,700 | | $ | 206,360 | | | $ | (2,675 | ) | | $ | 1,338,154 | | | | Operating costs | | | 220,171 | | | | 360,351 | | | 38,719 | | | | 754 | | | | 619,995 | | | | Depreciation and amortization | | | 67,411 | | | | 113,437 | | | 2,071 | | | | 475 | | | | 183,394 | | | | Gain on sale of assets | | | 264,579 | | | | 5 | | | - | | | | 4,456 | | | | 269,040 | | | | Operating income | | $ | 523,766 | | | $ | 113,917 | | $ | 165,570 | | | $ | 552 | | | $ | 803,805 | | | | | | | | | | | Income (loss) from operations of discontinued components | | $ | - | | | $ | - | | $ | (34,675 | ) | | $ | 28,495 | | | $ | (6,180 | ) | | | Equity earnings from investments | | $ | (1,511 | ) | | $ | - | | $ | - | | | $ | 10,132 | | | $ | 8,621 | | | | Investments in unconsolidated affiliates | | $ | 66,537 | | | $ | 29 | | $ | - | | | $ | 178,443 | | | $ | 245,009 | | | | Total assets | | $ | 4,272,350 | | | $ | 2,824,523 | | $ | 2,328,674 | | | $ | (141,392 | ) | | $ | 9,284,155 | | | | Capital expenditures | | $ | 56,255 | | | $ | 143,765 | | $ | 159 | | | $ | 50,314 | | | $ | 250,493 | | | |
| | | | | (a) | | - | | Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment’s regulated operations had revenues of $168.1 million, net margin of $118.3 million and operating income of $54.9 million for the year ended December 31, 2005. | (b) | | - | | All of our Distribution segment’s operations are regulated. |
N. | SUPPLEMENTAL CASH FLOW INFORMATION |
The following table sets forth supplemental information relative to our cash flow for the periods indicated.
| | | | | | | | | | | | | | | Years Ended December 31, | | | | | | 2007 | | 2006 | | 2005 | | | | Cash paid during the year | | (Thousands of dollars) | | | Interest, net of amounts capitalized | | $ | 253,678 | | $ | 225,998 | | $ | 219,918 | | | Income taxes | | $ | 57,281 | | $ | 262,504 | | $ | 244,925 | | |
Cash paid for interest includes swap terminations, treasury rate-lock terminations and ineffectiveness
| Year Ended December 31, 2008 | | ONEOK Partners (a) | | | Distribution (b) | | | Energy Services | | | Other and Eliminations | | | Total | | | | | (Thousands of dollars) | | | Sales to unaffiliated customers | | $ | 6,975,320 | | | $ | 2,177,615 | | | $ | 7,001,296 | | | $ | 3,202 | | | $ | 16,157,433 | | | Intersegment revenues | | | 744,886 | | | | 7 | | | | 584,507 | | | | (1,329,400 | ) | | | - | | | Total revenues | | $ | 7,720,206 | | | $ | 2,177,622 | | | $ | 7,585,803 | | | $ | (1,326,198 | ) | | $ | 16,157,433 | | | | | | | | | | | | | | | | | | | | | | | | | Net margin | | $ | 1,140,659 | | | $ | 680,971 | | | $ | 110,716 | | | $ | 3,181 | | | $ | 1,935,527 | | | Operating costs | | | 371,797 | | | | 375,328 | | | | 35,593 | | | | (5,806 | ) | | | 776,912 | | | Depreciation and amortization | | | 124,765 | | | | 116,782 | | | | 921 | | | | 1,459 | | | | 243,927 | | | Gain or (loss) on sale of assets | | | 713 | | | | (21 | ) | | | 1,500 | | | | 124 | | | | 2,316 | | | Operating income | | $ | 644,810 | | | $ | 188,840 | | | $ | 75,702 | | | $ | 7,652 | | | $ | 917,004 | | | | | | | | | | | | | | | | | | | | | | | | Equity earnings from investments | | $ | 101,432 | | | $ | - | | | $ | - | | | $ | - | | | $ | 101,432 | | Investments in unconsolidated affiliates | | $ | 755,492 | | | $ | - | | | $ | - | | | $ | - | | | $ | 755,492 | | Minority interests in consolidated subsidiaries | | $ | 5,941 | | | $ | - | | | $ | - | | | $ | 1,073,428 | | | $ | 1,079,369 | | | Total assets | | $ | 7,254,272 | | | $ | 3,063,374 | | | $ | 1,752,256 | | | $ | 1,056,160 | | | $ | 13,126,062 | | | Capital expenditures | | $ | 1,253,853 | | | $ | 169,049 | | | $ | 62 | | | $ | 50,172 | | | $ | 1,473,136 | | | (a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment's regulated operations had revenues of $439.3 million, net margin of $334.1 million and operating income of $158.8 million. | | | (b) - All of our Distribution segment's operations are regulated. | |
| Year Ended December 31, 2007 | | ONEOK Partners (a) | | | Distribution (b) | | | Energy Services | | | Other and Eliminations | | | Total | | | | | (Thousands of dollars) | | | Sales to unaffiliated customers | | $ | 5,204,794 | | | $ | 2,099,056 | | | $ | 6,170,084 | | | $ | 3,480 | | | $ | 13,477,414 | | | Intersegment revenues | | | 626,764 | | | | 7 | | | | 459,319 | | | | (1,086,090 | ) | | | - | | | Total revenues | | $ | 5,831,558 | | | $ | 2,099,063 | | | $ | 6,629,403 | | | $ | (1,082,610 | ) | | $ | 13,477,414 | | | | | | | | | | | | | | | | | | | | | | | | | Net margin | | $ | 895,893 | | | $ | 663,648 | | | $ | 247,402 | | | $ | 3,165 | | | $ | 1,810,108 | | | Operating costs | | | 337,356 | | | | 377,778 | | | | 39,920 | | | | 6,456 | | | | 761,510 | | | Depreciation and amortization | | | 113,704 | | | | 111,615 | | | | 2,147 | | | | 498 | | | | 227,964 | | | Gain or (loss) on sale of assets | | | 1,950 | | | | (56 | ) | | | - | | | | 15 | | | | 1,909 | | | Operating income | | $ | 446,783 | | | $ | 174,199 | | | $ | 205,335 | | | $ | (3,774 | ) | | $ | 822,543 | | | | | | | | | | | | | | | | | | | | | | | | Equity earnings from investments | | $ | 89,908 | | | $ | - | | | $ | - | | | $ | - | | | $ | 89,908 | | Investments in unconsolidated affiliates | | $ | 756,260 | | | $ | - | | | $ | - | | | $ | - | | | $ | 756,260 | | Minority interests in consolidated subsidiaries | | $ | 5,802 | | | $ | - | | | $ | - | | | $ | 796,162 | | | $ | 801,964 | | | Total assets | | $ | 6,112,065 | | | $ | 3,045,249 | | | $ | 1,549,012 | | | $ | 355,708 | | | $ | 11,062,034 | | | Capital expenditures | | $ | 709,858 | | | $ | 162,044 | | | $ | 158 | | | $ | 11,643 | | | $ | 883,703 | | | (a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment's regulated operations had revenues of $344.3 million, net margin of $273.7 million and operating income of $122.4 million. | | | (b) - All of our Distribution segment's operations are regulated. | |
| Year Ended December 31, 2006 | | ONEOK Partners (a) | | | Distribution (b) | | | Energy Services | | | Other and Eliminations | | | Total | | | | | (Thousands of dollars) | | | Sales to unaffiliated customers | | $ | 4,142,546 | | | $ | 1,958,192 | | | $ | 5,846,258 | | | $ | (26,670 | ) | | $ | 11,920,326 | | | Intersegment revenues | | | 595,702 | | | | 7 | | | | 489,549 | | | | (1,085,258 | ) | | | - | | | Total revenues | | $ | 4,738,248 | | | $ | 1,958,199 | | | $ | 6,335,807 | | | $ | (1,111,928 | ) | | $ | 11,920,326 | | | | | | | | | | | | | | | | | | | | | | | | | Net margin | | $ | 843,548 | | | $ | 599,797 | | | $ | 273,818 | | | $ | 4,821 | | | $ | 1,721,984 | | | Operating costs | | | 325,774 | | | | 371,460 | | | | 42,464 | | | | 1,069 | | | | 740,767 | | | Depreciation and amortization | | | 122,045 | | | | 110,858 | | | | 2,149 | | | | 491 | | | | 235,543 | | | Gain on sale of assets | | | 115,483 | | | | 18 | | | | - | | | | 1,027 | | | | 116,528 | | | Operating income | | $ | 511,212 | | | $ | 117,497 | | | $ | 229,205 | | | $ | 4,288 | | | $ | 862,202 | | | | | | | | | | | | | | | | | | | | | | | | Equity earnings from investments | | $ | 95,883 | | | $ | - | | | $ | - | | | $ | - | | | $ | 95,883 | | Investments in unconsolidated affiliates | | $ | 748,879 | | | $ | - | | | $ | - | | | $ | - | | | $ | 748,879 | | Minority interests in consolidated subsidiaries | | $ | 5,606 | | | $ | - | | | $ | - | | | $ | 795,039 | | | $ | 800,645 | | | Total assets | | $ | 4,921,717 | | | $ | 2,940,514 | | | $ | 2,023,663 | | | $ | 505,188 | | | $ | 10,391,082 | | | Capital expenditures | | $ | 201,746 | | | $ | 159,026 | | | $ | - | | | $ | 15,534 | | | $ | 376,306 | | | (a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment's regulated operations had revenues of $335.9 million, net margin of $261.8 million and operating income of $240.1 million, including $113.9 million from a gain on sale of assets, for the year ended December 31, 2006. | | | (b) - All of our Distribution segment's operations are regulated. | |
N. STOCK-BASED COMPENSATION
The ONEOK, Inc. Equity Compensation Plan provides for the granting of stock-based compensation, including incentive stock options, non-statutory stock options, stock bonus awards, restricted stock awards, restricted stock unit awards, performance stock awards and performance unit awards to eligible employees and the granting of stock awards to non-employee directors. We have reserved a total of approximately 3.05.0 million shares of common stock for issuance under the plan. Options - Stock options may be In December 2008, we amended the Equity Compensation Plan to allow for the deferral of awards granted that are not exercisable until a fixed future datein stock or cash, in installments. Options issued to date become void upon voluntary termination of employment other than retirement. In the event of retirement or involuntary termination, the optionee may exercise theaccordance with Internal Revenue Code section 409A requirements. This deferral option within a period determined by the Executive Compensation Committee (the Committee)is applicable for certain awards granted in 2006 and stated in the option. In the event of death, the option may be exercised by the personal representative of the optionee within a period to be determined by the Committeelater, and stated in the option. A portion of the options issued to date
can be exercisedvesting after one year from grant date provided an option must be exercised no later than ten years after grant date. Effective January 1, 2007, we eliminated the restored option feature for outstanding stock option grants.
2008.
Restricted Stock Incentive Units - Restricted stock incentive units may be granted to key employees with ownership of the common stock underlying the incentive unit vesting over a period determined by the Committee. Awards granted in 2007 and 2006to date vest over a three-year periodperiod. Awards granted in 2008, 2007 and 2006 entitle the grantee to receive shares of our common stock. Awards granted in 2005 and 2004 entitleentitled the grantee to receive two-thirds of the grant in our common stock (equity awards) and one-third of the grant in cash (liability awards). The equity awards are measured at fair value as if they were vested and issued on the grant date, reduced by expected dividend payments and adjusted for estimated forfeitures.Theforfeitures. The portion of the grants that are settled in cash are classified as liability awards with fair value based on the fair market value of our common stock, reduced by expected dividend payments and adjusted for estimated forfeitures, at each reporting date. No dividends are paid on the restricted stock incentive units. Compensation expense is recognized on a straight-line basis over the vesting period of the award.
Performance Unit Awards- Performance unit awards may be granted to key employees. The shares of our common stock underlying the performance units vest at the expiration of a period determined by the Committee if certain performance criteria are met by us. Performance units granted to date vest at the expiration of a three-year period. Upon vesting, a holder of performance units is entitled to receive a number of shares of our common stock equal to a percentage (0 percent to 200 percent) of the performance units granted based on our total shareholder return over the vesting period, compared with the total shareholder return of a peer group of other energy companies over the same period. Compensation expense is recognized on a straight-line basis over the period of the award with adjustments as needed based on our probable performance.award.
If paid, the performance unit awards granted in 2008, 2007 and 2006 entitle the grantee to receive the grant in shares of our common stock. Under Statement 123R, our 2008, 2007 and 2006 performance unit awards are equity awards with a market-based condition, which results in the compensation cost for these awards being recognized over the requisite service period, provided that the requisite service period is fulfilled, regardless of when, if ever, the market condition is satisfied. The fair value of these performance units was estimated on the grant date based on a Monte Carlo model. The compensation expense on these awards will only be adjusted for changes in forfeitures.If paid, the
The performance unit awards granted in 2005 entitleentitled the grantee to receive two-thirds of the grant in shares of our common stock (equity awards) and one-third of the grant in cash (liability awards). These awards vest over a three-year period. The fair values of these performance units that arewere classified as equity awards were calculated as of the date of grant and remain fixed as equity unitswere not adjusted upon adoption of Statement 123R. The fair values of the one-third liability portion of the performance units arewere estimated at each reporting date based on a Monte Carlo model. Awards
Long-Term Incentive Plan
The ONEOK, Inc. Long-Term Incentive Plan (the LTIP) provides for the granting of stock awards similar to those described above with respect to the Equity Compensation Plan. We have reserved a total of approximately 7.8 million shares of common stock for issuance under the plan. The maximum number of shares for which options or other awards may be granted to any employee during any year is 300,000.
Options - Stock options may be granted that are not exercisable until a fixed future date or in 2004 vested during 2007 withinstallments. Options issued to date become void upon voluntary termination of employment other than retirement. In the event of retirement or involuntary termination, the optionee may exercise the option within a performance factorperiod determined by the Executive Compensation Committee (the Committee) and stated in the option. In the event of 150 percent anddeath, the grantee received two-thirdsoption may be exercised by the personal representative of the grantoptionee within a period to be determined by the Committee and stated in shares of our common stock (equity awards) and one-thirdthe option. A portion of the options issued to date can be exercised after one year from grant in cash (liability awards).date and an option must be exercised no later than 10 years after grant date. Effective January 1, 2007, we eliminated the restored option feature for outstanding stock option grants.
Stock Compensation Plan for Non-Employee Directors
The ONEOK, Inc. Stock Compensation Plan for Non-Employee Directors (the DSCP) provides for the granting of stock options, stock bonus awards, including performance unit awards, restricted stock awards and restricted stock unit awards. Under the DSCP, these awards may be granted by the Committee at any time, until grants have been made for all shares authorized under the DSCP. We have reserved a total of 700,000 shares of common stock for issuance under the DSCP. The maximum number of shares of common stock which can be issued to a participant under the DSCP during any year is 20,000. No performance unit awards or restricted stock awards have been made to non-employee directors under the DSCP.
Options - Options may be exercisable in full atgranted to non-employee directors on the time of grant or may become exercisable in one or more installments. Options must be exercised no later than ten years aftersame terms as those granted under the date of grant of the option. In the event of retirement or termination, the optionee may exercise the option within a period determined by the Committee. Effective January 1, 2007, we eliminated the restored option feature for outstanding stock option grants. In the event of death, the option may be exercised by the personal representative of the optionee over a period of time determined by the Committee.LTIP.
Effective January 1, 2006, we adopted Statement 123R. See Note A for additional information. For all awards outstanding, we used a forfeiture rate ranging from zero percent to 22.613 percent based on historical forfeitures under our share-based payment plans. We use a combination of issuances from treasury stock and repurchases in the open market to satisfy our share-based payment obligations.
Compensation cost expensed for our share-based payment plans described below was $19.5$13.1 million, $28.8$12.0 million and $13.6$17.6 million 2008, 2007 2006 and 2005,2006, respectively, which includesis net of $8.3 million, $7.5 million $11.2 million and $5.3$11.2 million of tax benefits, respectively. No compensation cost was capitalized for 2008, 2007 2006 and 2005.2006.
Cash received from the exercise of awards under all share-based payment arrangements was $3.8 million and $7.4 million for 2007.2008 and 2007, respectively. The actual tax benefit realized for the anticipated tax deductions of the exercise of share-based payment arrangements totaled $1.4 million and $4.6 million for 2007.2008 and 2007, respectively. No cash was used to settle the equity portion of the restricted stock unit and performance unit awards granted under share-based payment arrangements.
Stock Option Activity The total fair value of stock options vested during 2007 was $1.0 million.
The following table sets forth the stock option activity for employees and non-employee directors for the periods indicated. | | | | | | | | | | | | Number of
Shares | | | Weighted
Average Price | | | Outstanding December 31, 2006 | | 1,460,668 | | | $ | 24.90 | | | Exercised | | (494,229 | ) | | $ | 25.20 | | | Expired | | (13,293 | ) | | $ | 29.15 | | | | | | | | | | | | Outstanding December 31, 2007 | | 953,146 | | | $ | 24.69 | | | | | Exercisable December 31, 2007 | | 953,146 | | | $ | 24.69 | | | | |
| | | Number of | | | Weighted | | | | | Shares | | | Average Price | | | Outstanding December 31, 2007 | | | 953,146 | | | $ | 24.69 | | | Exercised | | | (176,215 | ) | | $ | 25.72 | | | Expired | | | (2,625 | ) | | $ | 28.69 | | | Outstanding December 31, 2008 | | | 774,306 | | | $ | 24.44 | | | | | | | | | | | | | Exercisable December 31, 2008 | | | 774,306 | | | $ | 24.44 | |
The aggregate intrinsic value in the table below represents the total pre-tax intrinsic value, based on our year-end closing stock price of $44.77,$29.12, that would have been received by the option holders had all option holders exercised their options as of December 31, 2007. | | | | | | | | | | | | | | | | Stock Options Outstanding and Exercisable | Range of Exercise Prices | | Number
of Awards | | Weighted Average Remaining Life (yrs) | | Weighted Average
Exercise Price | | Aggregate Intrinsic Value (in 000’s) | | | $14.58 to $ 21.87 | | 441,910 | | 3.85 | | $ | 16.99 | | $ | 12,276 | | | $21.88 to $ 32.82 | | 242,384 | | 2.66 | | $ | 24.97 | | $ | 4,799 | | | $32.83 to $ 43.67 | | 268,852 | | 2.77 | | $ | 37.09 | | $ | 2,065 | | |
2008.
| | | | Stock Options Outstanding and Exercisable | | | | | | | | | Weighted | | | | | | Aggregate | | | | | | | | | Average | | | Weighted | | | Intrinsic | | | Range of | | | Number | | | Remaining | | | Average | | | Value | | | Exercise Prices | | | of Awards | | | Life (yrs) | | | Exercise Price | | | (in 000's) | | | $14.58 to $21.87 | | | 376,485 | | | 3.04 | | | $ | 16.98 | | | $ | 4,571 | | | $21.88 to $32.82 | | | 179,666 | | | 1.86 | | | $ | 24.69 | | | $ | 796 | | | $32.83 to $43.67 | | | 218,155 | | | 2.15 | | | $ | 37.11 | | | $ | - | |
The fair value of each restored option was estimated on the date of grant using the Black-Scholes model and the assumptions in the table below. | | | | | | | | | | December 31, | | December 31, | | | | | | 2006 | | 2005 | | | Volatility (a) | | 15.43% to 25.23% | | 14.90% to 18.51% | | | Dividend Yield | | 3.24% to 4.00% | | 3.57% to 4.05% | | | Risk-free Interest Rate | | 4.39% to 5.18% | | 3.47% to 4.43% | | | | (a) - Volatility was based on historical volatility over twelve months using daily stock price observations. | | |
| | December 31, 2006 | | | Volatility (a) | | 15.43% to 25.23% | | | Dividend Yield | | 3.24% to 4.00% | | | Risk-free Interest Rate | | 4.39% to 5.18% | | (a) - Volatility was based on historical volatility over twelve months using daily stock price observations. |
The expected lifeweighted-average period of outstanding options ranged from one to 10 years based upon experience to date and the make-up of the optionees.is 2.5 years. As of December 31, 2007,2008, all stock options were fully vested and expensed. The following table sets forth various statistics relating to our stock option activity. | | | | | | | | | | | | | | | | December 31, 2007 | | | December 31, 2006 | | December 31, 2005 | | | Weighted average grant date fair value of options restored (per share) | | | (a | ) | | $ | 5.57 | | $ | 3.65 | | | Intrinsic value of options exercised (thousands of dollars) | | $ | 12,129 | | | $ | 10,246 | | $ | 12,716 | | | Fair value of options granted (thousands of dollars) | | | (a | ) | | $ | 1,990 | | $ | 1,975 | | | | (a) - Due to our elimination of the restored option feature effective January 1, 2007, no grants were restored in 2007. |
| | | December 31, 2008 | | | December 31, 2007 | | | December 31, 2006 | | | Weighted-average grant date fair value of options restored (per share) | | (a) | | | (a) | | | $ | 5.57 | | | Intrinsic value of options exercised (thousands of dollars) | | $ | 3,652 | | | $ | 12,129 | | | $ | 10,246 | | | Fair value of options granted (thousands of dollars) | | (a) | | | (a) | | | $ | 1,990 | | | (a) - Due to our elimination of the restored option feature effective January 1, 2007, no grants were restored in 2007 or 2008. | |
Restricted Stock Unit Activity
The total fair value of shares vested during 20072008 was $8.3$5.9 million. As of December 31, 2007,2008, there was $7.7$5.5 million of total unrecognized compensation cost related to our nonvested restricted stock unit awards, which is expected to be recognized over a weighted-average period of 2.01.5 years. The following tables set forth activity and various statistics for the equity portion of the restricted stock unit awards. | | | | | | | | | | | | Number of
Shares | | | Weighted
Average Price | | | Nonvested December 31, 2006 | | 369,686 | | | $ | 23.45 | | | Granted | | 264,350 | | | $ | 36.82 | | | Released to participants | | (132,331 | ) | | $ | 20.65 | | | Forfeited | | (40,078 | ) | | $ | 27.43 | | | | | | | | | | | | Nonvested December 31, 2007 | | 461,627 | | | $ | 31.56 | | | | |
| | | | | | | | | | | | | | | December 31,
2007 | | December 31,
2006 | | December 31,
2005 | | | Weighted average grant date fair value (per share) | | $ | 36.82 | | $ | 25.98 | | $ | 25.19 | | | Fair value of shares granted (thousands of dollars) | | $ | 9,733 | | $ | 3,761 | | $ | 2,896 | | |
| | | Number of | | | Weighted | | | | | Shares | | | Average Price | | | Nonvested December 31, 2007 | | | 461,627 | | | $ | 31.56 | | | Granted | | | 53,550 | | | $ | 47.44 | | | Released to participants | | | (86,076 | ) | | $ | 25.34 | | | Forfeited | | | (1,969 | ) | | $ | 38.16 | | | Nonvested December 31, 2008 | | | 427,132 | | | $ | 34.78 | |
| | | December 31, 2008 | | | December 31, 2007 | | | December 31, 2006 | | | Weighted-average grant date fair value (per share) | | $ | 43.22 | | | $ | 36.82 | | | $ | 25.98 | | | Fair value of shares granted (thousands of dollars) | | $ | 2,314 | | | $ | 9,733 | | | $ | 3,761 | |
The following table sets forth activity for the liability portion of the restricted stock unit awards. | | | | | | | | | | | | Number of
Shares | | | Weighted
Average Price | | | Nonvested December 31, 2006 | | 112,516 | | | $ | 22.45 | | | Released to participants | | (64,016 | ) | | $ | 20.45 | | | Forfeited | | (7,917 | ) | | $ | 25.19 | | | | | | | | | | | | Nonvested December 31, 2007 | | 40,583 | | | $ | 25.07 | | | | |
| | | Number of | | | Weighted | | | | | Shares | | | Average Price | | | Nonvested December 31, 2007 | | | 40,583 | | | $ | 25.07 | | | Released to participants | | | (40,583 | ) | | $ | 25.19 | | | Forfeited | | | - | | | $ | - | | | Nonvested December 31, 2008 | | | - | | | $ | - | |
Performance Unit Activity
The total fair value of shares vested during 20072008 was $10.7$14.9 million. As of December 31, 2007,2008, there was $10.8$14.5 million of total unrecognized compensation cost related to the nonvested performance unit awards, which is expected to be recognized over a weighted-average period of 1.21.1 years. The following tables set forth activity and various statistics related to the performance unit equity awards and the assumptions used in the valuations of the 2008, 2007 2006 and 20052006 grants at the grant date. | | | | | | | | | | | | Number of
Units | | | Weighted
Average Price | | | Nonvested December 31, 2006 | | 876,015 | | | $ | 24.73 | | | Granted | | 329,050 | | | $ | 37.58 | | | Released to participants (a) | | (168,836 | ) | | $ | 20.21 | | | Forfeited | | (99,313 | ) | | $ | 28.79 | | | | | | | | | | | | Nonvested December 31, 2007 | | 936,916 | | | $ | 29.63 | | | | |
| | | | | | | (a)
| | - | | Performance awards granted in 2004 and released in 2007 were adjusted with a 150 percent performance factor; for the equity awards, this resulted in an additional 84,335 shares released to participants. |
| | | | | | | | | | | | | | | 2007 | | | 2006 | | | 2005 | | | | Volatility (a) | | 20.30 | % | | 18.80 | % | | (b | ) | | | Dividend Yield | | 3.79 | % | | 3.70 | % | | 3.34 | % | | | Risk-free Interest Rate | | 4.80 | % | | 4.32 | % | | 4.16 | % | | |
| | | | | (a)
| | - | | Volatility was based on historical volatility over three years using daily stock price observations. | (b) | | - | | Volatility was not a factor used for the 2005 grants. |
| | | | | | | | | | | | | | | December 31,
2007 | | December 31,
2006 | | December 31,
2005 | | | Weighted average grant date fair value (per share) | | $ | 37.58 | | $ | 25.98 | | $ | 25.50 | | | Fair value of shares granted (thousands of dollars) | | $ | 12,366 | | $ | 12,444 | | $ | 6,804 | | |
| | | Number of | | | Weighted | | | | | Units | | | Average Price | | | Nonvested December 31, 2007 | | | 936,916 | | | $ | 29.63 | | | Granted | | | 387,125 | | | $ | 47.44 | | | Released to participants (a) | | | (211,517 | ) | | $ | 25.48 | | | Forfeited | | | (20,975 | ) | | $ | 38.32 | | | Nonvested December 31, 2008 | | | 1,091,549 | | | $ | 36.58 | | (a) - Performance awards granted in 2005 and released in 2008 were adjusted with a 150 percent performance factor; for the equity awards, this resulted in an additional 105,760 shares released to participants. | |
| | | 2008 | | | 2007 | | 2006 | | Volatility (a) | | 22.50% | | | 20.30% | | 18.80% | | Dividend Yield | | 3.20% | | | 3.79% | | 3.70% | | Risk-free Interest Rate | | 2.46% | | | 4.80% | | 4.32% | | (a) - Volatility was based on historical volatility over three years using daily stock price observations. |
| | | December 31, 2008 | | | December 31, 2007 | | | December 31, 2006 | | | Weighted-average grant date fair value (per share) | | $ | 43.88 | | | $ | 37.58 | | | $ | 25.98 | | | Fair value of shares granted (thousands of dollars) | | $ | 16,987 | | | $ | 12,366 | | | $ | 12,444 | |
The following tables set forth activity for the performance unit liability awards and the assumptions used in the valuations at the end of each period indicated. | | | | | | | | | | | | Number of
Units | | | Weighted
Average Price | | | Nonvested December 31, 2006 | | 202,885 | | | $ | 23.28 | | | Released to participants (a) | | (84,418 | ) | | $ | 20.21 | | | Forfeited | | (12,328 | ) | | $ | 25.35 | | | | | | | | | | | | Nonvested December 31, 2007 | | 106,139 | | | $ | 25.48 | | | | |
| | | | | (a)
| | - | | Performance awards granted in 2004 and released in 2007 were adjusted with a 150 percent performance factor; for the liability awards, this resulted in an additional 42,167 shares released to participants. |
| | | | | | | | | | | | | | | 2007 | | | 2006 | | | 2005 | | | | Volatility (a) | | 21.80 | % | | 20.30 | % | | (b | ) | | | Dividend Yield | | 3.05 | % | | 3.62 | % | | (b | ) | | | Risk-free Interest Rate | | 3.07 | % | | 4.74 | % | | (b | ) | | |
| | | | | (a)
| | - | | Volatility was based on historical volatility over three years using daily stock price observations. | (b)
| | - | | Valuation for 2005 was based upon year-end stock price. |
| | | Number of | | | Weighted | | | | | Units | | | Average Price | | | Nonvested December 31, 2007 | | | 106,139 | | | $ | 25.48 | | | Released to participants (a) | | | (105,758 | ) | | $ | 25.48 | | | Forfeited | | | (381 | ) | | $ | 26.57 | | | Nonvested December 31, 2008 | | | - | | | $ | - | | (a) - Performance awards granted in 2005 and released in 2008 were adjusted with a 150 percent performance factor; for the liability awards, this resulted in an additional 52,880 liability units released to participants. | |
| | | 2008 | | | 2007 | | 2006 | | Volatility (a) | | (b) | | | 21.80% | | 20.30% | | Dividend Yield | | (b) | | | 3.05% | | 3.62% | | Risk-free Interest Rate | | (b) | | | 3.07% | | 4.74% | | (a) - Volatility was based on historical volatility over three years using daily stock price observations. | | (b) - Nonvested balance at December 31, 2008 was zero. |
Employee Stock Purchase Plan The
We have reserved a total number of 4.8 million shares of our common stock available and remaining for issuance under our ONEOK, Inc. Employee Stock Purchase Plan (the ESPP) is approximately 0.6 million of the initially authorized and reserved 3.8 million shares.. Subject to certain exclusions, all full-time employees are eligible to participate in the ESPP. Employees can choose to have up to 10 percent of their annual base pay withheld to purchase our common stock, subject to terms and limitations of the plan. The Committee may allow contributions to be made by other means, provided that in no event will contributions from all means exceed 10 percent of the employee’s annual base pay. The purchase price of the stock is 85 percent of the lower of its grant date or exercise date market price. Approximately 52 percent, 59 percent and 63 percent of employees participated in the plan in 2008, 2007 while 63 percent of employees participated in bothand 2006, and 2005.respectively. Under the plan, we sold 297,864 shares at $24.41 in 2008, 217,369 shares at $36.85 per share in 2007, and 340,364 shares at $22.57 per share in 2006, and 289,558 shares at $22.57 per share in 2005.2006.
Employee Stock Award Program
Under our Employee Stock Award Program, we issued, 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 NYSE was for the first time at or above $26 per share, and we have issued and will continue to 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. TheWe have reserved a total number of 300,000 shares of our common stock available and remaining for issuance under this program.
There were no shares issued to employees under this program is approximately 56,000 of the initially authorized and reserved 200,000 shares.in 2008. Shares issued to employees under this program totaled 44,099 40,705 and 32,73440,705 for the years ended December 31, 2007 2006 and 2005,2006, respectively. Compensation expense related to the Employee Stock Award Plan was $2.2 million $1.6 million and $1.1$1.6 million in 2007 and 2006, and 2005, respectively.
Deferred Compensation Plan for Non-Employee Directors
The ONEOK, Inc. Nonqualified Deferred Compensation Plan for Non-Employee Directors provides our directors, who are not our employees, the option to defer all or a portion of their compensation for their service on our Board of Directors. Under the plan, directors may elect either a cash deferral option or a phantom stock option. Under the cash deferral option, directors may defer the receipt of all or a portion of their annual retainer and/or meeting fees, plus accrued interest. Under the phantom stock option, directors may defer all or a portion of their annual retainer and/or meeting fees and receive such fees on a deferred basis in the form of shares of common stock under our Long-Term Incentive Plan or Equity Compensation Plan. Shares are distributed to non-employee directors at the fair market value of our common stock at the date of distribution. | In December 2008, we amended the Deferred Compensation Plan for Non-Employee Directors in accordance with Internal Revenue Code section 409A requirements.
O. UNCONSOLIDATED AFFILIATES
P.
| UNCONSOLIDATED AFFILIATES |
Investments in Unconsolidated Affiliates - The following table sets forth our investments in unconsolidated affiliates for the periods indicated. | | | | | | | | | | | | | | | | | Net Ownership Interest | | | December 31, 2007 | | | December 31, 2006 | | | | | | | | | | (Thousands of dollars) | | | | Northern Border Pipeline | | 50 | % | | $ | 418,982 | | | $ | 437,518 | | | | Bighorn Gas Gathering, L.L.C. | | 49 | % | | | 97,716 | | | | 98,299 | | | | Fort Union Gas Gathering | | 37 | % | | | 85,197 | | | | 82,220 | | | | Lost Creek Gathering Company, L.L.C. (a) | | 35 | % | | | 75,612 | | | | 74,151 | | | | Other | | Various | | | | 78,753 | | | | 56,691 | | | | Investments in unconsolidated affiliates | | | | | $ | 756,260 | (b) | | $ | 748,879 | (b) | | | | |
| | | | | (a) | | - | | ONEOK Partners is entitled to receive an incentive allocation of earnings from third-party gathering services revenue recognized by Lost Creek Gathering Company, L.L.C. As a result of the incentive, ONEOK Partners’ share of Lost Creek Gathering Company, L.L.C.’s income exceeds its 35 percent ownership interest. | (b) | | - | | Equity method goodwill (Note E) was $185.6 million at December 31, 2007 and 2006, respectively. |
| | | Net | | | | | | | | | | | | | Ownership | | | December 31, | | | | December 31, | | | | | | Interest | | | 2008 | | | | 2007 | | | | | | | | | (Thousands of dollars) | | | | Northern Border Pipeline | | | 50 % | | | $ | 392,601 | | | | $ | 418,982 | | | | Bighorn Gas Gathering, L.L.C. | | | 49 % | | | | 97,289 | | | | | 97,716 | | | | Fort Union Gas Gathering | | | 37 % | | | | 108,642 | | | | | 85,197 | | | | Lost Creek Gathering Company, L.L.C. (a) | | | 35 % | | | | 77,773 | | | | | 75,612 | | | | Other | | Various | | | | 79,187 | | | | | 78,753 | | | | Investments in unconsolidated affiliates | | | | | | $ | 755,492 | | (b) | | $ | 756,260 | | (b) | | | | | | | | | | | | | | | | | | (a) - ONEOK Partners is entitled to receive an incentive allocation of earnings from third-party gathering services revenue recognized by Lost Creek Gathering Company, L.L.C. As a result of the incentive, ONEOK Partners’ share of Lost Creek Gathering Company, L.L.C.'s income exceeds its 35 percent ownership interest. | | (b) - Equity method goodwill (Note E) was $185.6 million at December 31, 2008 and 2007. | | | | | | | |
Equity Earnings from Investments- The following table sets forth our equity earnings from investments for the periods indicated. All 2007 and 2006 amounts in the table below are equity earnings from investments in our ONEOK Partners segment. | | | | | | | | | | | | | | | | Years Ended December 31, | | | | | | | 2007 | | 2006 | | 2005 | | | | | | | (Thousands of dollars) | | | | Northern Border Pipeline (a) | | $ | 62,008 | | $ | 72,393 | | $ | - | | | | Bighorn Gas Gathering, L.L.C. | | | 7,416 | | | 8,223 | | | - | | | | Fort Union Gas Gathering | | | 9,681 | | | 9,030 | | | - | | | | Lost Creek Gathering Company, L.L.C. | | | 4,790 | | | 5,363 | | | - | | | | ONEOK Partners (b) | | | - | | | - | | | 10,132 | | | | Other | | | 6,013 | | | 874 | | | (1,511 | ) | | | Equity Earnings From Investments | | $ | 89,908 | | $ | 95,883 | | $ | 8,621 | | | | | |
| | | | | (a)
| | - | | Beginning January 1, 2006, ONEOK Partners’ interest in Northern Border Pipeline is accounted for as an investment under the equity method (Note B). For the first three months of 2006, ONEOK Partners included 70 percent of Northern Border Pipeline’s income in equity earnings from investments. After the sale of a 20 percent interest in Northern Border Pipeline in April 2006, ONEOK Partners included 50 percent of Northern Border Pipeline’s income in equity earnings from investments. | (b)
| | - | | ONEOK Partners was consolidated beginning January 1, 2006, in accordance with EITF 04-5. Prior to January 1, 2006, ONEOK Partners was accounted for as an investment under the equity method. |
| | | Years Ended December 31, | | | | | 2008 | | | 2007 | | | 2006 | | | | | (Thousands of dollars) | | | Northern Border Pipeline (a) | | $ | 65,912 | | | $ | 62,008 | | | $ | 72,393 | | | Bighorn Gas Gathering, L.L.C. | | | 8,195 | | | | 7,416 | | | | 8,223 | | | Fort Union Gas Gathering | | | 14,172 | | | | 9,681 | | | | 9,030 | | | Lost Creek Gathering Company, L.L.C. | | | 5,365 | | | | 4,790 | | | | 5,363 | | | Other | | | 7,788 | | | | 6,013 | | | | 874 | | | Equity Earnings From Investments | | $ | 101,432 | | | $ | 89,908 | | | $ | 95,883 | | | | | | | | | | | | | | | | | (a) - For the first three months of 2006, ONEOK Partners included 70 percent of Northern Border Pipeline’s income in equity earnings from investments. After the sale of a 20 percent interest in Northern Border Pipeline in April 2006, ONEOK Partners included 50 percent of Northern Border Pipeline’s income in equity earnings from investments (Note B). | |
Unconsolidated Affiliates Financial Information- Summarized combined financial information of our unconsolidated affiliates is presented below. | | | | | | | | | | | | | December 31, | | | | | | 2007 | | | 2006 | | | | | | (Thousands of dollars) | | | Balance Sheet | | | | | | | | | | Current assets | | $ | 102,805 | | | $ | 76,376 | | | Property, plant and equipment, net | | | 1,724,330 | | | | 1,678,099 | | | Other noncurrent assets | | | 25,882 | | | | 24,109 | | | Current liabilities | | | 79,593 | | | | 240,358 | | | Long-term debt | | | 717,301 | | | | 492,017 | | | Other noncurrent liabilities | | | 10,278 | | | | 2,494 | | | Accumulated other comprehensive income (loss) | | | (2,441 | ) | | | 978 | | | Owners’ equity | | | 1,048,286 | | | | 1,042,737 | | | | | | | | | Years Ended December 31, | | | | | | 2007 | | | 2006 | | | | | | (Thousands of dollars) | | | Income Statement | | | | | | | | | | Operating revenue | | $ | 404,399 | | | $ | 386,448 | | | Operating expenses | | | 172,997 | | | | 159,452 | | | Net income | | | 184,434 | | | | 183,732 | | | Distributions paid to us | | $ | 103,785 | | | $ | 123,427 | | |
| | | December 31, | | | | | 2008 | | | 2007 | | | | | (Thousands of dollars) | | | Balance Sheet | | | | | | | | Current assets | | $ | 106,833 | | | $ | 102,805 | | | Property, plant and equipment, net | | $ | 1,777,350 | | | $ | 1,724,330 | | | Other noncurrent assets | | $ | 27,547 | | | $ | 25,882 | | | Current liabilities | | $ | 279,996 | | | $ | 79,593 | | | Long-term debt | | $ | 543,894 | | | $ | 717,301 | | | Other noncurrent liabilities | | $ | 14,360 | | | $ | 10,278 | | | Accumulated other comprehensive income (loss) | | $ | (5,708 | ) | | $ | (2,441 | ) | | Owners' equity | | $ | 1,079,188 | | | $ | 1,048,286 | |
| | | Years Ended December 31, | | | | | 2008 | | | 2007 | | | 2006 | | | | | (Thousands of dollars) | | | Income Statement | | | | | | | | | | | Operating revenue | | $ | 415,552 | | | $ | 404,399 | | | $ | 386,448 | | | Operating expenses | | $ | 179,380 | | | $ | 172,997 | | | $ | 159,452 | | | Net income | | $ | 209,915 | | | $ | 184,434 | | | $ | 183,732 | | | | | | | | | | | | | | | | | Distributions paid to us | | $ | 118,010 | | | $ | 103,785 | | | $ | 123,427 | |
P. EARNINGS PER SHARE INFORMATION
Q.
| EARNINGS PER SHARE INFORMATION |
The following table sets forth the computation of basic and diluted EPS from continuing operations for the periods indicated. | | | | | | | | | | | | | | Year Ended December 31, 2007 | | | | | | Income | | Shares | | Per Share
Amount | | | | Basic EPS from continuing operations | | (Thousands, except per share amounts) | | | Income from continuing operations available for common stock | | $ | 304,921 | | 107,346 | | $ | 2.84 | | | Diluted EPS from continuing operations | | | | | | | | | | | Effect of dilutive securities: | | | | | | | | | | | Options and other dilutive securities | | | - | | 1,952 | | | | | | | | | | | | | | | | | Income from continuing operations available for common stock and common stock equivalents | | $ | 304,921 | | 109,298 | | $ | 2.79 | | | | |
| | | | | | | | | | | | | | Year Ended December 31, 2006 | | | | | | Income | | Shares | | Per Share
Amount | | | | Basic EPS from continuing operations | | (Thousands, except per share amounts) | | | Income from continuing operations available for common stock | | $ | 306,677 | | 112,006 | | $ | 2.74 | | | Diluted EPS from continuing operations | | | | | | | | | | | Effect of other dilutive securities: | | | | | | | | | | | Mandatory convertible units | | | - | | 629 | | | | | | Options and other dilutive securities | | | - | | 1,842 | | | | | | | | | | | | | | | | | Income from continuing operations available for common stock and common stock equivalents | | $ | 306,677 | | 114,477 | | $ | 2.68 | | | | |
| | | | | | | | | | | | | | Year Ended December 31, 2005 | | | | | | Income | | Shares | | Per Share
Amount | | | | Basic EPS from continuing operations | | (Thousands, except per share amounts) | | | Income from continuing operations available for common stock | | $ | 403,148 | | 100,536 | | $ | 4.01 | | | Diluted EPS from continuing operations | | | | | | | | | | | Effect of other dilutive securities: | | | | | | | | | | | Mandatory convertible units | | | - | | 6,366 | | | | | | Options and other dilutive securities | | | - | | 1,104 | | | | | | | | | | | | | | | | | Income from continuing operations available for common stock and common stock equivalents | | $ | 403,148 | | 108,006 | | $ | 3.73 | | | | |
| | Year Ended December 31, 2008 | | | | | | | | | Per Share | | | | Income | | | Shares | | Amount | | Basic EPS from continuing operations | (Thousands, except per share amounts) | | Income from continuing operations available for common stock | | $ | 311,909 | | | | 104,369 | | | $ | 2.99 | | | Diluted EPS from continuing operations | | | | | | | | | | | | | | Effect of dilutive securities: | | | | | | | | | | | | | | Options and other dilutive securities | | | - | | | | 1,391 | | | | | | | Income from continuing operations available for common stock | | | | | | | | | | | | | | and common stock equivalents | | $ | 311,909 | | | | 105,760 | | | $ | 2.95 | |
| | | Year Ended December 31, 2007 | | | | | | | | | Per Share | | | | Income | | | Shares | | Amount | | Basic EPS from continuing operations | (Thousands, except per share amounts) | | Income from continuing operations available for common stock | | $ | 304,921 | | | | 107,346 | | | $ | 2.84 | | | Diluted EPS from continuing operations | | | | | | | | | | | | | | Effect of other dilutive securities: | | | | | | | | | | | | | | Options and other dilutive securities | | | - | | | | 1,952 | | | | | | | Income from continuing operations available for common stock | | | | | | | | | | | | | | and common stock equivalents | | $ | 304,921 | | | | 109,298 | | | $ | 2.79 | |
| | | Year Ended December 31, 2006 | | | | | | | | | Per Share | | | | Income | | | Shares | | Amount | | Basic EPS from continuing operations | (Thousands, except per share amounts) | | Income from continuing operations available for common stock | | $ | 306,677 | | | | 112,006 | | | $ | 2.74 | | | Diluted EPS from continuing operations | | | | | | | | | | | | | | Effect of other dilutive securities: | | | | | | | | | | | | | | Mandatory convertible units | | | - | | | | 629 | | | | | | | Options and other dilutive securities | | | - | | | | 1,842 | | | | | | | Income from continuing operations available for common stock | | | | | | | | | | | | | | and common stock equivalents | | $ | 306,677 | | | | 114,477 | | | $ | 2.68 | |
There were 64,989, 4,601 66,463 and 28,10766,463 option shares excluded from the calculation of diluted EPS for 2008, 2007 2006 and 2005,2006, respectively, since their inclusion would be antidilutive.R.anti-dilutive.
Q. ONEOK PARTNERS
Ownership Interest in ONEOK Partners | ONEOK PARTNERS |
General Partner Interest - See Note B for discussion of the April 2006 acquisition of the additional general partner interest in ONEOK Partners. The limited partner units
In April 2006, we received from ONEOK Partners were newly created Class B limited partner units.units from ONEOK Partners. As of April 7, 2007, the Class B limited partner units are no longer subordinated to distributions on ONEOK Partners’ common units and generally have the same voting rights as the common units and are entitled to receive increased quarterly distributions and distributions on liquidation equal to 110 percent of the distributions paid with respect to the common units. On June 21, 2007, we, as the sole holder of ONEOK Partners Class B limited partner units, waived our right to receive the increased quarterly distributions on the Class B units for the period April 7, 2007, through December 31, 2007, and continuing thereafter until we give ONEOK Partners no less than 90 days advance notice that we have withdrawn our waiver. Any such withdrawal of the waiver will be effective with respect to any distribution on the Class B units declared or paid on or after 90 days following delivery of the notice.
Under the ONEOK Partners’ partnership agreement and in conjunction with the issuance of additional common units by ONEOK Partners, we, as the general partner, are required to make equity contributions in order to maintain our representative general partner interest.
Our investmentownership interest in ONEOK Partners is shown in the table below for the periods presented. | | | | | | | | | | | | | | | December 31, | | | December 31, | | | December 31, | | | | | | | 2007 | | | 2006 | | | 2005 | | | | General partner interest | | 2.00 | % | | 2.00 | % | | 1.65 | % | | | Limited partner interest | | 43.70 | % (a) | | 43.70 | % (a) | | 1.05 | % (b) | | | Total ownership interest | | 45.70 | % | | 45.70 | % | | 2.70 | % | | | | | (a) - Represents approximately 0.5 million common units and 36.5 million Class B units. (b) - Represents approximately 0.5 million common units. |
| | | December 31, | | December 31, | | December 31, | | | | 2008 | | 2007 | | 2006 | | General partner interest | | 2.00% | | | 2.00% | | | 2.00% | | | Limited partner interest | | 45.70% | (a) | | 43.70% | (b) | | 43.70% | (b) | | Total ownership interest | | 47.70% | | | 45.70% | | | 45.70% | | | (a) - Represents 5.9 million common units and approximately 36.5 million Class B units, which are convertible, at our option, into common units. | | (b) - Represents 0.5 million common units and approximately 36.5 million Class B units, which are convertible, at our option, into common units. |
In March 2008, we purchased from ONEOK Partners, in a private placement, an additional 5.4 million of ONEOK Partners’ common units for a total purchase price of approximately $303.2 million. In addition, ONEOK Partners completed a public offering of 2.5 million common units at $58.10 per common unit and received net proceeds of $140.4 million after deducting underwriting discounts but before offering expenses. In conjunction with ONEOK Partners’ private placement and public offering of common units, ONEOK Partners GP contributed $9.4 million to ONEOK Partners in order to maintain its 2 percent general partner interest. We and ONEOK Partners GP funded these amounts with available cash and short-term borrowings.
In April 2008, ONEOK Partners sold an additional 128,873 common units at $58.10 per common unit to the underwriters of the public offering upon their partial exercise of their option to purchase additional common units to cover over-allotments. ONEOK Partners received net proceeds of approximately $7.2 million from the sale of these common units after deducting underwriting discounts but before offering expenses. In conjunction with the partial exercise by the underwriters, ONEOK Partners GP contributed $0.2 million to ONEOK Partners in order to maintain its 2 percent general partner interest.
Cash Distributions - Under the ONEOK Partners’ partnership agreement, distributions are made to the partners with respect to each calendar quarter in an amount equal to 100 percent of available cash. Available cash generally consists of all cash receipts adjusted for cash disbursements and net changes to cash reserves. Available cash will generally be distributed 98 percent to limited partners and 2 percent to the general partner. As an incentive, theThe general partner’s percentage interest in quarterly distributions is increased after certain specified target levels are met. Under the incentive distribution provisions, the general partner receives: 15 percent of amounts distributed in excess of $0.605 per unit,
25 percent of amounts distributed in excess of $0.715 per unit, and| · | 15 percent of amounts distributed in excess of $0.605 per unit; |
50 percent of amounts distributed in excess of $0.935 per unit.| · | 25 percent of amounts distributed in excess of $0.715 per unit; and |
| · | 50 percent of amounts distributed in excess of $0.935 per unit. |
ONEOK Partners’ income is allocated to the general and limited partners in accordance with their respective partnership ownership percentages. The effect of any incremental income allocations for incentive distributions that are allocated to the general partner is calculated after the income allocation for the general partner’s partnership interest and before the income allocation to the limited partners.
The following table shows ONEOK Partners’ general partner and incentive distributions related to the periods indicated. | | | | | | | | | | | | | | | Years Ended December 31, | | | | 2007 | | 2006 | | 2005 | | | | | | (Thousands of dollars) | | | General partner distributions | | $ | 7,842 | | $ | 6,228 | | $ | 2,632 | | | Incentive distributions | | | 50,627 | | | 31,102 | | | 6,568 | | | Total distributions from ONEOK Partners | | $ | 58,469 | | $ | 37,330 | | $ | 9,200 | | | | |
| | | Years Ended December 31, | | | | 2008 | | | 2007 | | | 2006 | | | | (Thousands of dollars) | | General partner distributions | | $ | 9,456 | | | $ | 7,842 | | | $ | 6,228 | | | Incentive distributions | | | 76,042 | | | | 50,627 | | | | 31,102 | | | Total distributions to general partner | | $ | 85,498 | | | $ | 58,469 | | | $ | 37,330 | |
The quarterly distributions paid by ONEOK Partners to limited partners in the first, second, third and fourth quarters of 20072008 were $0.98$1.025 per unit, $0.99$1.04 per unit, $1.00$1.06 per unit, and $1.01$1.08 per unit, respectively.
In January 2008,2009, ONEOK Partners declared a cash distribution of $1.025$1.08 per unit payable in the first quarter. On February 14, 2008,13, 2009, we received the related incentive distribution of $14.1$20.3 million for the fourth quarter of 2007,2008, which is included in the table above.
Relationship- We own 45.747.7 percent of ONEOK Partners and consolidate ONEOK Partners in our consolidated financial statements; however, we are restricted from the assets and cash flows from ONEOK Partners except for our distributions. Distributions are declared quarterly by ONEOK PartnersPartners’ general partner based on the terms of its partnership agreement, and foragreement. For the years ended December 31, 2008, 2007 2006 and 2005,2006, cash distributions declared from ONEOK Partners to us totaled $266.1 million, $207.4 million $145.1 million and $10.8$145.1 million, respectively. See Note M for more information on ONEOK Partners results.
Affiliate Transactions - We have certain transactions with our ONEOK Partners affiliate and its subsidiaries, which comprise our ONEOK Partners segment.
ONEOK Partners sells natural gas from its natural gas gathering and processing operations to our Energy Services segment. In addition, a large portion of ONEOK Partners’ revenues from its natural gas pipelines businesses are from our Energy Services and Distribution segments, which utilize ONEOK Partners’ natural gas transportation and storage services. As part of the transaction between us and ONEOK Partners also purchases natural gas from our Energy Services segment for its natural gas liquids operations and its gathering and processing operations.
ONEOK Partners acquiredhas certain contractual rights to the Bushton Plant from us through a Processing and Services Agreement with us, which sets out the terms for processing and related services we provide at the Bushton Plant through 2012. ONEOK Partners has contracted for all of the capacity of the Bushton Plant from OBPI. In exchange, ONEOK Partners pays us for all direct costs and expenses of the Bushton Plant, including reimbursement of a portion of our obligations under equipment leases covering the Bushton Plant.
We provide a variety of services to our affiliates, including cash management and financingfinancial services, employee benefits provided through our benefit plans, administrative services provided by our employees and management, insurance and office space leased in our headquarters building and other field locations. Where costs are specifically incurred on behalf of an affiliate, the costs are billed directly to the affiliate by us. In other situations, the costs aremay be allocated to the affiliates through a variety of methods, depending upon the nature of the expenses and the activities of the affiliates. For example, a benefitservice that applies equally to all employees is allocated based upon the number of employees in each affiliate. However, an expense benefiting the consolidated company but having no direct basis for allocation is allocated through aby the modified Distrigas method, a method using a combination of ratios ofthat include gross plant and investment, operating incomeearnings before interest and wages.taxes and payroll expense.
The following table shows transactions with ONEOK Partners for the periods shown. | | | | | | | | | | | | | | | Years Ended December 31, | | | | 2007 | | 2006 | | 2005 | | | Revenue | | $ | 626,764 | | $ | 595,702 | | $ | 7,683 | | | | | | | | | | Expense | | | | | | | | | | | | Administrative and general expenses | | $ | 171,741 | | $ | 175,270 | | $ | 52,579 | | | Interest expense | | | - | | | 21,372 | | | - | | | Total expense | | $ | 171,741 | | $ | 196,642 | | $ | 52,579 | | | | |
S. | QUARTERLY FINANCIAL DATA (UNAUDITED) |
Total operating revenues are consistently greater during the heating season from November through
| | | Years Ended December 31, | | | | | 2008 | | | 2007 | | | 2006 | | | | | (Thousands of dollars) | | | Revenues | | $ | 744,886 | | | $ | 626,764 | | | $ | 595,702 | | | | | | | | | | | | | | | | | Expenses | | | | | | | | | | | | | | Cost of sales and fuel | | $ | 107,983 | | | $ | 89,792 | | | $ | 177,367 | | | Administrative and general expenses | | | 191,798 | | | | 171,741 | | | | 175,270 | | | Interest expense | | | - | | | | - | | | | 21,372 | | | Total expenses | | $ | 299,781 | | | $ | 261,533 | | | $ | 374,009 | |
See “Ownership Interest in ONEOK Partners” above for additional discussion of our purchase of common units and ONEOK Partners GP’s additional general partner contributions in March due to the large volume of natural gas sold to customers for heating. The following tables set forth the unaudited quarterly results of operations for the periods indicated. | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2007 | | First Quarter | | | Second
Quarter | | | Third
Quarter | | | Fourth
Quarter | | | | | | (Thousands of dollars, except per share amounts) | Total Revenues | | $ | 3,806,208 | | | $ | 2,876,241 | | | $ | 2,809,997 | | | $ | 3,984,968 | | | Net Margin | | $ | 564,850 | | | $ | 367,699 | | | $ | 340,160 | | | $ | 537,399 | | | Operating Income | | $ | 328,301 | | | $ | 135,745 | | | $ | 102,770 | | | $ | 255,727 | | | Net Income | | $ | 152,880 | | | $ | 35,203 | | | $ | 13,914 | | | $ | 102,924 | | | Earnings per share from continuing operations | | | | | | | | | | | | | | | | | | Basic | | $ | 1.38 | | | $ | 0.32 | | | $ | 0.13 | | | $ | 0.99 | | | Diluted | | $ | 1.36 | | | $ | 0.31 | | | $ | 0.13 | | | $ | 0.98 | | | | | | | | | Year Ended December 31, 2006 | | First Quarter | | | Second Quarter | | | Third Quarter | | | Fourth Quarter | | | | | | (Thousands of dollars, except per share amounts) | Total Revenues | | $ | 3,765,424 | | | $ | 2,436,415 | | | $ | 2,644,835 | | | $ | 3,073,652 | | | Net Margin | | $ | 501,652 | | | $ | 399,559 | | | $ | 349,770 | | | $ | 471,003 | | | Operating Income | | $ | 270,376 | | | $ | 269,569 | | | $ | 119,571 | | | $ | 202,686 | | | Income from Continuing Operations | | $ | 129,739 | | | $ | 77,945 | | | $ | 24,413 | | | $ | 74,580 | | | Income (loss) from operations of discontinued components, net of tax | | $ | (247 | ) | | $ | (150 | ) | | $ | (13 | ) | | $ | 45 | | | Net Income | | $ | 129,492 | | | $ | 77,795 | | | $ | 24,400 | | | $ | 74,625 | | | Earnings per share from continuing operations | | | | | | | | | | | | | | | | | | Basic | | $ | 1.21 | | | $ | 0.66 | | | $ | 0.22 | | | $ | 0.68 | | | Diluted | | $ | 1.17 | | | $ | 0.65 | | | $ | 0.21 | | | $ | 0.66 | | |
Total revenues and net margin for the first and second quarters in the tables above were restated to be consistent with the classification used in our September 30, 2007 Quarterly Report on Form 10-Q and in this Annual Report on Form 10-K. The change was not material.
ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
April 2008.
R. QUARTERLY FINANCIAL DATA (UNAUDITED)
| | | First | | | Second | | | Third | | | Fourth | | | Year Ended December 31, 2008 | | Quarter | | | Quarter | | | Quarter | | | Quarter | | | | | (Thousands of dollars, except per share amounts) | | | Total Revenues | | $ | 4,902,076 | | | $ | 4,172,866 | | | $ | 4,239,246 | | | $ | 2,843,245 | | | Net Margin | | $ | 585,912 | | | $ | 420,828 | | | $ | 455,026 | | | $ | 473,761 | | | Operating Income | | $ | 333,123 | | | $ | 173,012 | | | $ | 192,179 | | | $ | 218,690 | | | Net Income | | $ | 143,837 | | | $ | 41,865 | | | $ | 58,033 | | | $ | 68,174 | | | Earnings per share from continuing operations | | | | | | | | | | | | | | | | | | Basic | | $ | 1.38 | | | $ | 0.40 | | | $ | 0.56 | | | $ | 0.65 | | | Diluted | | $ | 1.36 | | | $ | 0.39 | | | $ | 0.55 | | | $ | 0.65 | |
| | | First | | | Second | | | Third | | | Fourth | | | Year Ended December 31, 2007 | | Quarter | | | Quarter | | | Quarter | | | Quarter | | | | | (Thousands of dollars, except per share amounts) | | | Total Revenues | | $ | 3,806,208 | | | $ | 2,876,241 | | | $ | 2,809,997 | | | $ | 3,984,968 | | | Net Margin | | $ | 564,850 | | | $ | 367,699 | | | $ | 340,160 | | | $ | 537,399 | | | Operating Income | | $ | 328,301 | | | $ | 135,745 | | | $ | 102,770 | | | $ | 255,727 | | | Net Income | | $ | 152,880 | | | $ | 35,203 | | | $ | 13,914 | | | $ | 102,924 | | | Earnings per share from continuing operations | | | | | | | | | | | | | | | | | | Basic | | $ | 1.38 | | | $ | 0.32 | | | $ | 0.13 | | | $ | 0.99 | | | Diluted | | $ | 1.36 | | | $ | 0.31 | | | $ | 0.13 | | | $ | 0.98 | |
ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None. ITEM 9A. | CONTROLS AND PROCEDURES |
Evaluation of Disclosure Controls and Procedures
We have established disclosure controls and procedures to ensure that information required to be disclosed by us, including our consolidated entities, in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Under the supervision and with the participation of senior management, including our Chief Executive Officer (“Principal Executive Officer”) and our Chief Financial Officer (“Principal Financial Officer”), we evaluated our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Exchange Act. Based on this evaluation, our Principal Executive Officer and our Principal Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2007, to ensure the timely disclosure of required information in our periodic SEC filings.2008.
Management’s Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of our management, including our Principal Executive Officer and Principal Financial Officer, we evaluated the effectiveness of our internal control over financial reporting based on the framework inInternal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Based on our evaluation under that framework and applicable SEC rules, our management concluded that our internal control over financial reporting was effective as of December 31, 2007.2008.
Our internal control over financial reporting as of December 31, 2007,2008, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein (Item 8).
Changes in Internal Controls Over Financial Reporting
We have made no changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the yearquarter ended December 31, 2007,2008, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting as described below.In September 2007, we implemented a new software system to support our accounting for hedging instruments. This system replaced a manually intensive process for reviewing and calculating hedge ineffectiveness.
reporting.
ITEM 9B. OTHER INFORMATION
Not applicable. PART III.
ITEM 9B. | OTHER INFORMATION |
Not applicable.
PART III.
| ITEM 10. | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE |
Directors of the Registrant
Information concerning our directors is set forth in our 20082009 definitive Proxy Statement and is incorporated herein by this reference.
Executive Officers of the Registrant
Information concerning our executive officers is included in Part I, Item 1. Business, of this Annual Report on Form 10-K.
Compliance with Section 16(a) of the Exchange Act
Information on compliance with Section 16(a) of the Exchange Act is set forth in our 20082009 definitive Proxy Statement and is incorporated herein by this reference.
Information concerning the code of ethics, or code of business conduct, is set forth in our 20082009 definitive Proxy Statement and is incorporated herein by this reference.
Nominating Committee Procedures
Information concerning the nominating committee procedures is set forth in our 20082009 definitive Proxy Statement and is incorporated herein by this reference.
Information concerning the Audit Committee is set forth in our 20082009 definitive Proxy Statement and is incorporated herein by this reference.
Audit Committee Financial Expert
Information concerning the Audit Committee Financial Expert is set forth in our 20082009 definitive Proxy Statement and is incorporated herein by this reference. ITEM 11. | EXECUTIVE COMPENSATION |
Information on executive compensation is set forth in our 20082009 definitive Proxy Statement and is incorporated herein by this reference. ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Security Ownership of Certain Beneficial Owners
Information concerning the ownership of certain beneficial owners is set forth in our 20082009 definitive Proxy Statement and is incorporated herein by this reference.
Security Ownership of Management
Information on security ownership of directors and officers is set forth in our 20082009 definitive Proxy Statement and is incorporated herein by this reference.
Equity Compensation Plan Information Information
The following table sets forth certain information concerning our equity compensation plans is included in Part II, Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchasesas of Equity Securities,December 31, 2008.
| | | | | | | | | Number of Securities | | | | | | | | | | Remaining Available For | | | | Number of Securities | Weighted-Average | Future Issuance Under | | | | to be Issued Upon | Exercise Price of | Equity Compensation | | | | Exercise of Outstanding | Outstanding Options, | Plans (Excluding | | | Options, Warrants and Rights | Warrants and Rights | Securities in Column (a)) | | Plan Category | (a) | (b) | (c) | | Equity compensation plans | | | | | | | | | | | approved by security holders (1) | | 2,300,035 | | | $31.71 | | | 6,053,331 | | | Equity compensation plans | | | | | | | | | | | not approved by security holders (2) | | 179,133 | | | $27.03 | (3) | | 4,153,578 | | | Total | | 2,479,168 | | | $31.37 | | | 10,206,909 | | | | | | | | | | | | | | | (1) - | Includes shares granted under our Employee Stock Purchase Plan, Employee Stock Award Program, stock options, restricted stock incentive units and performance unit awards granted under our Long-Term Incentive Plan and Equity Compensation Plan. For a brief description of the material features of these plans, see Note N of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K. Column (c) includes 1,408,443, 155,648, 2,120,616 and 2,368,624 shares available for future issuance under our Employee Stock Purchase Plan, Employee Stock Award Program, Long-Term Incentive Plan and Equity Compensation Plan, respectively. | | (2) - | Includes our Employee Non-Qualified Deferred Compensation Plan, Deferred Compensation Plan for Non-Employee Directors and Stock Compensation Plan for Non-Employee Directors. For a brief description of the material features of these plans, see Note N of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K. Column (c) includes 503,602, 2,707,003 and 942,973 shares available for future issuance under our Stock Compensation Plan for Non-Employee Directors, Thrift Plan and Profit Sharing Plan, respectively. | | (3) - | Compensation deferred into our common stock under our Employee Non-Qualified Deferred Compensation Plan and Deferred Compensation Plan for Non-Employee Directors is distributed to participants at fair market value on the date of distribution. The price used for these plans to calculate the weighted-average exercise price in the table is $29.12, which represents the year-end closing price of our common stock on the NYSE. |
| ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE |
Information on certain relationships and related transactions and director independence is set forth in our 20082009 definitive Proxy Statement and is incorporated herein by this reference. ITEM 14. | PRINCIPAL ACCOUNTANT FEES AND SERVICES |
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Information concerning the principal accountant’s fees and services is set forth in our 20082009 definitive Proxy Statement and is incorporated herein by this reference.
PART IV.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES ITEM 15.(1) Financial Statements | EXHIBITS, FINANCIAL STATEMENT SCHEDULES |
Documents Filed as Part of this Report
(1) Exhibits
| | Page No. | 2.1 (a) | Reports of Independent Registered Public Accounting Firms | 67-68 | | (b) | Consolidated Statements of Income for the years ended December 31, 2008, 2007 and 2006 | 69 | | (c) | Consolidated Balance Sheets as of December 31, 2008 and 2007 | 70-71 | | (d) | Consolidated Statements of Cash Flows for the years ended December 31, 2008, 2007 and 200 | 73 | | (e) | Consolidated Statements of Shareholders’ Equity and Comprehensive Income for the years ended December 31, 2008, 2007 and 2006 | 74-75 | | (f) | Notes to Consolidated Financial Statements | 76-117 |
(2) Financial Statement Schedules
All schedules have been omitted because of the absence of conditions under which they are required.
(3) Exhibits
| 3.4 | Amended and Sale Agreement by and between TransCan Northwest Border Ltd. and Northern Plains Natural Gas Company, LLC, dated February 14, 2006Restated Bylaws of ONEOK, Inc. (incorporated by reference from Exhibit 10.3099.1 to our Form 10-K for the year ended December 31, 2005, filed March 13, 2006). |
| | | 2.2 | | Purchase and Sale Agreement by and between ONEOK, Inc. and Northern Border Partners, L.P., dated February 14, 2006 (incorporated by reference from Exhibit 10.31 to our Form 10-K for the year ended December 31, 2005, filed March 13, 2006). | | | 2.3 | | Contribution Agreement by and among ONEOK, Inc., Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership, dated February 14, 2006 (incorporated by reference from Exhibit 10.32 to our Form 10-K for the year ended December 31, 2005, filed March 13, 2006). | | | 2.4 | | First Amendment to Contribution Agreement by and among ONEOK, Inc., Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership dated April 6, 2006 (incorporated by reference from Exhibit 2.4 to our Form 8-K filed April 12, 2006)January 20, 2009). |
| | 2.5 | | First Amendment to Purchase3.5 | Amended and Sale Agreement by and among ONEOK, Inc., Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership, dated April 6, 2006 (incorporated by reference from Exhibit 2.5 to our Form 8-K filed April 12, 2006). | | | 2.6 | | Second Amendment to Contribution Agreement by and between ONEOK, Inc. and ONEOK Partners, L.P. dated January 16, 2007 (incorporated by reference from Exhibit 2.6 to our Form 10-K for the year ended December 31, 2006, filed March 1, 2007). | | | 2.7 | | Second Amendment to the Purchase and Sale Agreement by and between ONEOK, Inc. and ONEOK Partners, L.P. dated January 16, 2007 (incorporated by reference from Exhibit 2.7 to our Form 10-K for the year ended December 31, 2006, filed March 1, 2007). | | | 3 | | Certificate of Incorporation of WAI, Inc. (now ONEOK, Inc.) filed May 16, 1997 (incorporated by reference from Exhibit 3.1 to Amendment No. 3 to Registration Statement on Form S-4 filed August 6, 1997, Commission File No. 333-27467). | | | 3.1 | | Certificate of Merger of ONEOK, Inc. (formerly WAI, Inc.) filed November 26, 1997 (incorporated by reference from Exhibit (1)(b) to Form 10-Q for the quarter ended May 31, 1998, filed June 26, 1998). | | | 3.2 | | AmendedRestated Certificate of Incorporation of ONEOK, Inc. filed January 16, 1998 (incorporated by reference from Exhibit (1)(a) to Form 10-Q for the quarter endeddated May 31, 1998, filed June 26, 1998). | | | 3.3 | | Amendment to Certificate of Incorporation of ONEOK, Inc. filed May 23, 2001 (incorporated by reference from Exhibit 4.15 to Registration Statement on Form S-3 filed July 19, 2001, as amended, Commission File No. 333-65392). | | | 3.4 | | Bylaws of ONEOK, Inc., as amended and restated15, 2008 (incorporated by reference from Exhibit 3.1 to Form 8-K filed October 22, 2007)May 19, 2008). | | |
4 | 3.6 | Certificate of Correction form dated November 5, 2008 (incorporated by reference from Exhibit 4.2 to Registration Statement on Form S-3 filed November 21, 2008). |
| 4 | Certificate of Designation for Convertible Preferred Stock of WAI, Inc. (now ONEOK, Inc.) filed November 26, 199721, 2008 (incorporated by reference from Exhibit 3.3 to Amendment No 3.4.2 to Registration Statement on Form S-4S-3 filed August 6, 1997,November 21, 2008, Commission File No. 333-27467)333-155593). | | |
4.1 | 4.1 | Certificate of Designation for Series C Participating Preferred Stock of ONEOK, Inc. filed November 26, 199721, 2008 (incorporated by reference from Exhibit No. 14.2 to Registration Statement on Form 8-AS-3 filed November 28, 1997)21, 2008). | | |
4.2 | 4.2 | Form of Common Stock Certificate (incorporated by reference from Exhibit 1 to Registration Statement on Form 8-A filed November 21, 1997). | | |
4.3 | 4.3 | Indenture, dated September 24, 1998, between ONEOK, Inc. and Chase Bank of Texas (incorporated by reference from Exhibit 4.1 to Registration Statement on Form S-3 filed August 26, 1998, Commission File No. 333-62279). |
| | | | 4.4 | | Indenture dated December 28, 2001, between ONEOK, Inc. and SunTrust Bank (incorporated by reference from Exhibit 4.1 to Amendment No. 1 to Registration Statement on Form S-3 filed December 28, 2001, Commission File No. 333-65392). | | |
4.5 | 4.5 | First Supplemental Indenture dated September 24, 1998, between ONEOK, Inc. and Chase Bank of Texas (incorporated by reference from Exhibit 5(a) to Form 8-K filed September 24, 1998). |
| | 4.6 | | 4.6 | Second Supplemental Indenture dated September 25, 1998, between ONEOK, Inc. and Chase Bank of Texas (incorporated by reference from Exhibit 5(b) to Form 8-K filed September 24, 1998). | | |
4.7 | 4.7 | Third Supplemental Indenture dated February 8, 1999, between ONEOK, Inc. and Chase Bank of Texas (incorporated by reference from Exhibit 4 to Form 8-K filed February 8, 1999). | | |
4.8 | 4.8 | Fourth Supplemental Indenture dated February 17, 1999, between ONEOK, Inc. and Chase Bank of Texas (incorporated by reference from Exhibit 4.5 to Registration Statement on Form S-3 filed April 15, 1999, Commission File No. 333-76375). |
| | 4.9 | | Fifth Supplemental Indenture dated August 17, 1999, between ONEOK, Inc. and Chase Bank of Texas (incorporated by reference from Exhibit 4 to Form 8-K filed August 17, 1999).4.9 | Not used. |
| | 4.10 | | Sixth Supplemental Indenture dated March 1, 2000, between ONEOK, Inc. and Chase Bank of Texas (incorporated by reference from Exhibit 4.11 to the Registration Statement on Form S-4 filed March 13, 2000, Commission File No. 333-32254).4.10 | Not used. |
| | 4.11 | | Seventh Supplemental Indenture dated April 24, 2000, between ONEOK, Inc. and Chase Bank of Texas (incorporated by reference from Exhibit 4 to Form 8-K filed April 26, 2000).4.11 | Not used. | | |
4.12 | 4.12 | Eighth Supplemental Indenture dated April 6, 2001, between ONEOK, Inc. and The Chase Manhattan Bank (incorporated by reference from Exhibit 4.9 to Registration Statement on Form S-3 filed July 19, 2001, Commission File No. 333-65392). | | |
4.13 | 4.13 | First Supplemental Indenture, dated as of January 28, 2003, between ONEOK, Inc. and SunTrust Bank (incorporated by reference from Exhibit 4.22 to Registration Statement on Form 8-A/A filed January 31, 2003). | | |
4.14 | 4.14 | Second Supplemental Indenture, dated June 17, 2005, between ONEOK, Inc. and SunTrust Bank (incorporated by reference from Exhibit 4.1 to Form 8-K filed June 17, 2005). | | |
4.15 | 4.15 | Third Supplemental Indenture, dated June 17, 2005, between ONEOK, Inc. and SunTrust Bank (incorporated by reference from Exhibit 4.3 to Form 8-K filed June 17, 2005). | | |
4.16 | 4.16 | Form of Senior Note Due 2008 (included in Exhibit 4.13). | | |
4.17 | 4.17 | Form of 5.20 percent Notes Due 2015 (included in Exhibit 4.14). | | |
4.18 | 4.18 | Form of 6.00 percent Notes due 2035 (included in Exhibit 4.15). |
| | 4.19 | | Not used. | | | 4.20 | | Not used. | | | 4.21 | | Not used. | | | 4.22 | | Not used. | | | 4.23 | 4.19 | Not used. |
4.20 Not used.
| 4.24 | Amended and Restated Rights Agreement dated as of February 5, 2003, between ONEOK, Inc. and UMB Bank, N.A., as Rights Agent (incorporated by reference from Exhibit 1 to Registration Statement on Form 8-A/A (Amendment No. 1) filed February 6, 2003). |
| | | 10 | | ONEOK, Inc. Long-Term Incentive Plan (incorporated by reference from Exhibit 10(a) to Form 10-K for the fiscal year ended December 31, 2001, filed March 14, 2002). |
| | | 10.1 | | ONEOK, Inc. Stock Compensation Plan for Non-Employee Directors (incorporated by reference from Exhibit 99 to Form S-8 filed January 25, 2001). |
| | | 10.2 | | ONEOK, Inc. Supplemental Executive Retirement Plan terminated and frozen December 31, 2004 (incorporated by reference from Exhibit 10.1 to Form 8-K filed on December 20, 2004). |
| | | 10.3 | | ONEOK, Inc. 2005 Supplemental Executive Retirement Plan, as amended and restated, dated January 1, 2005 (incorporated by reference from Exhibit 10.2 to Form 8-K filed on December 20, 2004).18, 2008. |
| | | 10.4 | | Form of Termination Agreement between ONEOK, Inc. and ONEOK, Inc. executives, as amended, dated January 1, 2003 (incorporated by reference from Exhibit 10.3 to Form 10-K for the fiscal year ended December 31, 2002, filed March 10, 2003). |
| | | 10.5 | | Form of Indemnification Agreement between ONEOK, Inc. and ONEOK, Inc. officers and directors, as amended, dated January 1, 2003 (incorporated by reference from Exhibit 10.4 to Form 10-K for the fiscal year ended December 31, 2002, filed March 10, 2003). |
| | | 10.6 | | ONEOK, Inc. Annual Officer Incentive Plan (incorporated by reference from Exhibit 10(f) to Form 10-K for the fiscal year ended December 31, 2001, filed March 14, 2002). |
| | | 10.7 | | ONEOK, Inc. Employee Nonqualified Deferred Compensation Plan, as amended and restated December 16, 2004 (incorporated by reference from Exhibit 10.3 to Form 8-K filed December 20, 2004). |
| | | 10.8 | | ONEOK, Inc. 2005 Nonqualified Deferred Compensation Plan, as amended and restated, dated January 1, 2005 (incorporated by reference from Exhibit 10.4 to Form 8-K filed December 20, 2004).18, 2008. |
| | | 10.9 | | ONEOK, Inc. Deferred Compensation Plan for Non-Employee Directors, as amended and restated, November 19, 1998 (incorporated by reference from Exhibit 10.7 to Form 10-K for the fiscal year endeddated December 31, 2002, filed March 10, 2003).18, 2008. |
| | | 10.10 | | Ground Lease between ONEOK Leasing Company and Southwestern Associates dated May 15, 1983 (incorporated by reference from Form 10-K dated August 31, 1983).Not used. |
| | | 10.11 | | First Amendment to Ground Lease between ONEOK Leasing Company and Southwestern Associates dated October 1, 1984 (incorporated by reference from Form 10-K dated August 31, 1984).Not used. |
| | | 10.12 | | Sublease between RMZ Corp. and ONEOK Leasing Company dated May 15, 1983 (incorporated by reference from Form 10-K dated August 31, 1984).Not used. |
| | | 10.13 | | First Amendment to Sublease between RMZ Corp. and ONEOK Leasing Company dated October 1, 1984 (incorporated by reference from Form 10-K dated August 31, 1984).Not used. |
| | | 10.14 | | ONEOK Leasing Company Lease Agreement with Oklahoma Natural Gas Company dated August 31, 1984 (incorporated by reference from Form 10-K dated August 31, 1985).Not used. |
| | | 10.15 | | $1,000,000,000 Credit Agreement dated as of June 27, 2005, among ONEOK, Inc., as the Borrower, Citibank, N.A, as the Administrative Agent and as a Lender, and the Lenders party thereto (incorporated by reference from Exhibit 10.1 to Form 8-K filed June 29, 2005).Not used. |
| | First Amendment to Credit Agreement among ONEOK, Inc., Citibank, N.A., as Administrative Agent and as a Lender, and the Lenders party thereto, dated September 1, 2005 (incorporated by reference from Exhibit 10.1 to the Form 10-Q for the quarter ended September 30, 2005, filed November 4, 2005). | | | | 10.17 | | $1,200,000,000 Amended and Restated Credit Agreement dated as of July 14, 2006 among ONEOK, Inc., as the Borrower, Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer, Citibank, N.A., as L/C Issuer, and the Lenders party hereto (incorporated by reference from Exhibit 10.1 to the Form 10-Q for the quarter ended June 30, 2006, filed August 4, 2006). |
| | 10.18 | | 364-day Credit Agreement dated April 6, 2006, by and among ONEOK Partners, L.P., the several banks and other financial institutions and lenders from time to time party thereto, SunTrust Bank, as Administrative Agent, Citicorp North America, Inc., as Syndication Agent, and Bank of Montreal (doing business as Harris Nesbitt), UBS Loan Finance LLC, and Wachovia Bank, National Association, as Co- Documentation Agents (incorporated by reference to Exhibit 10.1 to ONEOK Partners, L.P.’s Form 8-K filed on April 12, 2006 (File No. 1-12202)). | | | 10.19 | | Amended and Restated Revolving Credit Agreement dated March 30, 2006, among ONEOK Partners, L.P., the lenders from time to time party thereto, SunTrust Bank, as administrative agent, Wachovia Bank, National Association, as Syndication Agent, Bank of Montreal (doing business as Harris Nesbit), Barclays Bank PLC and Citibank, N.A., as Co-Documentation Agents. (incorporated by reference to Exhibit 10.1 to ONEOK Partners, L.P. Form 8-K filed March 31, 2006 (File No. 1-2202)). | | | 10.20 | | First Amendment to Amended and Restated Revolving Credit Agreement among ONEOK Partner, L.P., the lenders from time to time party thereto, SunTrust Bank as administrative agent, Wachovia Bank, National Association, as syndication agent, and BMO Capital Markets Financing, Inc., Barclays Bank PLC and Citibank, N.A. as co-documentation agents, dated December 13, 2006 (incorporated by reference from Exhibit 10.20 to our Form 10-K for the year ended December 31, 2006, filed March 1, 2007). | | | 10.21 | 10.18 | Not used. |
| | 10.22 | | Purchase Agreement between CCE Holdings, LLC and ONEOK, Inc.10.19 | Not used. |
| 10.21 | First Amendment, dated as of September 16, 2004 (incorporated by reference from Exhibit 10.2526, 2008, to the Form 10-K forAmended and Restated Credit Agreement, dated as of July 14, 2006, among ONEOK, Inc., as the year ended December 13, 2004, filed March 8, 2005). | | | 10.23 | | Purchase Agreement between Koch Hydrocarbon Management Company, LLCBorrower, Bank of America, N.A., as the Administrative Agent, Swing Line Lender and ONEOK, Inc. dated May 9, 2005L/C Issuer, Citibank N.A., as L/C Issuer and the financial institutions named therein as lenders (incorporated by reference from Exhibit 10.1 to theour Form 10-Q for the quarter ended June 30, 2005, filed August 3, 2005)November 6, 2008). |
| 10.24 | | Asset Purchase Agreement between Koch Pipeline Company, L.P. and ONEOK, Inc. dated May 9, 2005 (incorporated by reference from Exhibit 10.2 to the Form 10-Q for the quarter ended June 30, 2005, filed August 3, 2005).Not used. |
| | | 10.25 | | Amendment No. 1 to Asset Purchase Agreement between Koch Pipeline Company, L.P. and ONEOK, Inc. dated June 28, 2005 (incorporated by reference from Exhibit 10.25 to our Form 10-K for the year ended December 31, 2006, filed March 1, 2007).Not used. |
| | | 10.26 | | Limited Liability Company Membership Interest Purchase Agreement between Koch Holdings Enterprises, LLC and ONEOK, Inc. dated May 9, 2005 (incorporated by reference from Exhibit 10.3 to the Form 10-Q for the quarter ended June 30, 2005, filed August 3, 2005).Not used. |
| | | 10.27 | | Limited Liability Company Membership Interest Purchase Agreement between Koch Hydrocarbon Management Company, LLC and ONEOK, Inc. dated May 9, 2005 (incorporated by reference from Exhibit 10.4 to the Form 10-Q for the quarter ended June 30, 2005, filed August 3, 2005).Not used. |
| | | 10.28 | | Limited Liability Company Membership Interest Purchase Agreement between TXOK Acquisition, Inc. and ONEOK Energy Resources Company dated September 19, 2005 (incorporated by reference from Exhibit 10.4 to the Form 10-Q for the quarter ended September 30, 2005, filed November 4, 2005).Not used. |
| | | | 10.29 | | Amendment No. 1 to Limited Liability Company Membership Interest Purchase Agreement between TXOK Acquisition, Inc. and ONEOK Energy Resources Company dated September 27, 2005 (incorporated by reference from Exhibit 10.6 to the Form 10-Q for the quarter ended September 30, 2005, filed November 4, 2005).Not used. |
| | | 10.30 | | Stock Purchase Agreement between TXOK Acquisition, Inc. and ONEOK, Inc., dated September 19, 2005 (incorporated by reference from Exhibit 10.5 to the Form 10-Q for the quarter ended September 30, 2005, filed November 4, 2005).Not used. |
| | Amendment No. 1 to Stock Purchase Agreement between TXOK Acquisition, Inc. and ONEOK, Inc., dated September 27, 2005 (incorporated by reference from Exhibit 10.7 to the Form 10-Q for the quarter ended September 30, 2005, filed November 4, 2005). | | | | 10.32 | | Services Agreement among ONEOK, Inc. and its affiliates and Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership executed April 6, 2006, but effective as of April 1, 2006 (incorporated by reference from Exhibit 10.1 to our Form 8-K filed April 12, 2006). |
| | | 10.33 | | Third Amended and Restated Agreement of Limited Partnership of ONEOK Partners, L.P. dated as of September 15, 2006 (incorporated by reference to Exhibit 3.1 to ONEOK Partners, L.P.’s Form 8-K filed on September 19, 2006 (File No. 1-12202)). |
| | | 10.34 | | Purchase Agreement dated August 7, 2006, by and between ONEOK, Inc., and UBS AG, London Branch acting through UBS Securities LLC as agent (incorporated by reference from Exhibit 10.1 to our Form 10- Q for the quarter ended September 30, 2006, filed November 3, 2006).Not used. |
| | | 10.35 | | Amendment No. 1 to Purchase Agreement dated January 2, 2007 by and between ONEOK, Inc. and UBS AG, London Branch acting through UBS Securities LLC as agent (incorporated by reference from Exhibit 10.35 to our Form 10-K for the year ended December 31, 2006, filed March 1, 2007).Not used. |
| | Underwriting Agreement by and between ONEOK Partners, L.P., Citigroup Global Markets Inc. and SunTrust Capital Markets, Inc. as representatives of the underwriters dated September 20, 2006 (incorporated by reference to Exhibit 1.1 to ONEOK Partners, L.P.’s Form 8-K filed on September 26, 2006 (File No. 1-12202)). | | | | 10.37 | | ONEOK, Inc. Profit Sharing Plan dated January 1, 2005 (incorporated by reference from Exhibit 99 to Registration Statement on Form S-8 filed December 30, 2004). |
| | | 10.38 | | ONEOK, Inc. Employee Stock Purchase Plan as amended and restated February 17, 2005effective as of December 20, 2007 (incorporated by reference from Exhibit 10.24.2 to theRegistration Statement on Form 8-KS-8 filed February 23, 2005)August 4, 2008). |
| | | 10.39 | | Form of Non-Statutory Stock Option Agreement (incorporated by reference from Exhibit 10.1 to Form 10- Q for the quarter ended September 30, 2004, filed November 3, 2004). | | | 10.40 | | Form of Restricted Stock Award Agreement (incorporated by reference from Exhibit 10.2 to Form 10-Q for the quarter ended September 30, 2004, filed November 3, 2004). |
| 10.41 | | Form of Performance Shares Award Agreement (incorporated by reference from Exhibit 10.3 to Form 10-Q for the quarter ended September 30, 2004, filed November 3, 2004).Not used. |
| | | 10.42 | | Form of Restricted Stock Incentive Award Agreement (incorporated by reference from Exhibit 10.4 to Form 10-Q for the quarter ended September 30, 2004, filed November 3, 2004).Not used. |
| | Form of Performance Shares Award Agreement (incorporated by reference from Exhibit 10.5 to Form 10-Q for the quarter ended September 30, 2004, filed November 3, 2004). | | | | 10.44 | | ONEOK, Inc. Equity Compensation Plan, as amended and restated, dated effective February 17, 2005 (incorporated by reference from Exhibit 10.1 to Form 8-K filed February 23, 2005).December 18, 2008. |
| | | | 10.45 | | Form of Restricted Unit Award Agreement (incorporated by reference from Exhibit 10.45 to Form 10-K filed February 28, 2007). |
| | | 10.46 | | Form of Performance Unit Award Agreement (incorporated by reference from Exhibit 10.46 to Form 10-K filed February 28, 2007). |
| | | 10.47 | | First Amendment to Letter of Credit Reimbursement Agreement by and between KBC Bank N.V. and ONEOK, Inc. dated December 19, 2005 (incorporated by reference from Exhibit 10.47 to our Form 10-K for the year ended December 31, 2006, filed March 1, 2007). |
| | | 10.48 | | Amended and Restated Revolving Credit Agreement dated March 30, 2007, among ONEOK Partners, L.P., as Borrower, the lenders from time to time party thereto, SunTrust Bank, as Administrative Agent, Wachovia Bank, National Association, as Syndication Agent, and BMO Capital Markets, Barclays Bank PLC, and Citibank, N.A., as Co-Documentation Agents (incorporated by reference from Exhibit 10.1 to our Form 10-Q filed May 2, 2007). |
| | | 10.49 | | Purchase Agreement dated June 27, 2007, by and between ONEOK, Inc. (the “Issuer”), and Bank of America, N.A., acting through Banc of America Securities LLC (“Agent”) as agent (incorporated by reference from Exhibit 10.1 to our Form 10-Q filed August 3, 2007). |
| | | 10.50 | | Thrift Plan for Employees of ONEOK, Inc. and Subsidiaries as Amendedamended and Restated Effectiverestated effective as of January 1, 20072008 (incorporated by reference from Exhibit 4.14.3 to ourRegistration Statement on Form S-8 filed February 12, 2007)August 4, 2008). |
| | | 10.51 | | Amendment No. 1 to Third Amended and Restated Agreement of Limited Partnership of ONEOK Partners, L.P. dated July 20, 2007 (incorporated by reference to Exhibit 3.1 to ONEOK Partners, L.P.’s Form 10-Q filed on August 3, 2007 (File No. 1-12202)). |
| | 12 | | Computation10.52 | $400,000,000 364-Day Revolving Credit Agreement dated as of RatioAugust 6, 2008, among ONEOK, Inc., as Borrower, Bank of EarningsAmerica, N.A., as the Administrative Agent and Swing Line Lender, the lenders named therein, Barclays Bank, PLC, BNP Paribas, Suntrust Bank and UBS Loan Finance LLC as Co-Documentation Agents, and Banc of America Securities LLC as sole Lead Arranger and sole Book Manager (incorporated by reference from Exhibit 10.4 to Combined Fixed Charges and Preferred Stock Dividend Requirementsthe Form 10-Q for the yearsquarter ended December 31, 2007, 2006, 2005, 2004June 30, 2008, filed August 6, 2008). |
| 10.53 | Common Unit Purchase Agreement between ONEOK, Inc. and 2003.ONEOK Partners, L.P. dated March 11, 2008 (incorporated by reference from Exhibit 1.1 to our Form 8-K filed March 12, 2008). |
| 10.54 | Form of Performance Unit Award Agreement dated January 15, 2009. |
12.1 | 10.55 | Form of Restricted Unit Stock Bonus Award Agreement dated January 15, 2009. |
| 12 | Computation of Ratio of Earnings to Fixed Charges for the years ended December 31, 2008, 2007, 2006, 2005 2004 and 2003.2004. |
| | | 16.1 | | Letter from KPMG LLP dated May 2, 2007, to the Securities and Exchange Commission regarding change in certifying accountant (incorporated by reference to Exhibit 16.1 to our Form 8-K filed on May 2, 2007). |
| | | 21 | | Required information concerning the registrant’s subsidiaries. |
| | | 23.1 | | Consent of Independent Registered Public Accounting Firm - PricewaterhouseCoopers LLP. |
| | | 23.2 | | Consent of Independent Registered Public Accounting Firm - KPMG LLP. |
| | | 31.1 | | Certification of John W. Gibson pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| | | 31.2 | | Certification of Curtis L. Dinan pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| | | 32.1 | | Certification of John W. Gibson 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 Curtis L. Dinan 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)). |
Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
ONEOK, Inc. Registrant
Date: February 24, 2009 By: /s/ Curtis L. Dinan Curtis L. Dinan Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
Pursuant to the requirements of the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on this 24th day of February 2009.
| | | | | | | | | | | | | | | | | | | ONEOK, Inc. | | | | | | | | | Registrant | | | | | Date: February 27, 2008 | | | | By: | | /s/ Curtis L. Dinan
| | | | | | | | | Curtis L. Dinan | | | | | | | | | Senior Vice President, | | | | | | | | | Chief Financial Officer and Treasurer | | | | | | | | | (Principal Financial Officer) | | Pursuant to the requirements of the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on this 27th day of February 2008. | | | | | | | | | /s/ John W. Gibson | | | | | | /s/ David L. Kyle | | | | | John W. Gibson | | | | | | David L. Kyle | | | | | Chief Executive Officer | | Chairman of the | | | | | Chairman of the Board of Directors | | | | | | | | | | | | | /s/ Caron A. Lawhorn | | | | | | /s/ William M. Bell | | James C. Day | | | Caron A. Lawhorn | | | | | | William M. Bell | | James C. Day | | | Senior Vice President and | | Director | | Chief Accounting Officer | | | | | | | Director | | | | | | | | | | | /s/ James C. Day
| | | | | | /s/ Julie H. Edwards | | /s/ William L. Ford | | | James C. Day | | | | | | Julie H. Edwards | | William L. Ford | | Director | | Director | | | | | | | Director | | | | | | | | | | | /s/ William L. Ford
| | | | | | /s/ Bert H. Mackie | | /s/ Jim W. Mogg | | | William L. Ford | | | | | | Bert H. Mackie | | Jim W. Mogg | | Director | | Director | | | | | | | Director | | | | | | | | | | | /s/ Jim W. Mogg
| | | | | | /s/ Pattye L. Moore | | /s/ Gary D. Parker | | | Jim W. Mogg | | | | | | Pattye L. Moore | | Gary D. Parker | | Director | | Director | | | | | | | Director | | | | | | | | | | | /s/ Gary D. Parker
| | | | | | /s/ Eduardo A. Rodriguez | | /s/ David J. Tippeconnic | | | Gary D. Parker | | | | | | Eduardo A. Rodriguez | | David J. Tippeconnic | | Director | | Director | | | | | | | /s/ Mollie B. Williford | | Director | | | | | | | | | | | /s/ David J. Tippeconnic
| | | | | | | | | | | David J. Tippeconnic | | | | | | Mollie B. Williford | | | | | Director | | | | | | Director | | |
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