A. SUMMARY OF ACCOUNTING POLICIES
Our accompanying unaudited consolidated financial statements have been prepared in accordance with GAAP and reflect all adjustments that, in our opinion, are necessary for a fair presentation of the results for the interim periods presented. All such adjustments are of a normal recurring nature. The 2008 year-end consolidated
balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP. These unaudited consolidated financial statements should be read in conjunction with our audited consolidated financial statements in our Annual Report. Due to the seasonal nature of our business, the results of operations for the three and nine months ended September 30, 2009, are not necessarily indicative of the results that may be expected for a 12-month period.
Our accounting policies are consistent with those disclosed in Note A of the Notes to Consolidated Financial Statements in our Annual Report.
Goodwill and Indefinite-lived Intangible Assets Impairment Test - We assess our goodwill and indefinite-lived intangible assets for impairment at least annually. There were no impairment charges resulting from our July 1, 2009, impairment test.
Recently Issued Accounting Updates
The following recently issued accounting updates affect our consolidated financial statements during 2009:
FASB Accounting Standards Codification - In June 2009, the FASB established the FASB Accounting Standards Codification (Codification) as the source of authoritative accounting principles recognized by the FASB to be applied by nongovernmental entities in the preparation of financial statements
in conformity with GAAP. While the Codification does not change GAAP, it does change the manner in which we reference authoritative accounting principles in our consolidated financial statements. The Codification is effective for and has been implemented in this Quarterly Report.
Noncontrolling Interests - Effective for our year beginning January 1, 2009, we retroactively adopted new presentation and disclosure requirements for existing noncontrolling interests (previously referred to as minority interests). We report noncontrolling interests as a component
of equity in our Consolidated Balance Sheets and the amounts of consolidated net income attributable to noncontrolling interests and to us in our Consolidated Statements of Income.
Derivative Instruments and Hedging Activities - Effective for our year beginning January 1, 2009, we provide enhanced disclosures about how derivative and hedging activities affect our financial position, financial performance and cash flows. These additional disclosures have
been applied prospectively. See Note C for applicable disclosures.
Fair Value Measurements - As of January 1, 2009, we began measuring our assets and liabilities that are measured at fair value on a nonrecurring basis subsequent to initial recognition based upon a revised definition of fair value. The impact of these measurement changes was
not material. See Note B for disclosures of our fair value measurements.
Measuring Liabilities at Fair Value - In August 2009, the FASB provided clarification for measuring liabilities at fair value. When a quoted price in an active market for an identical liability is not available, we will be required to measure fair value using a valuation technique
that uses quoted prices of similar liabilities, quoted prices of identical or similar liabilities when traded as assets, or another valuation technique that is consistent with GAAP, such as the income or market approach. Additionally, when estimating the fair value of a liability, we will not be required to include a separate input or adjustment to other inputs relating to the existence of a restriction that prevents the transfer of the liability. We will consider liabilities measured using
an unadjusted quoted price in an active market for either an identical liability or an identical liability when traded as an asset as a Level 1 fair value measurement. We will apply this guidance when measuring liabilities at fair value beginning in the fourth quarter of 2009 and do not expect the impact on those measurements to be material.
Interim Disclosures about Fair Value - Effective for our quarter ended June 30, 2009, we provide disclosures of fair value of financial instruments for interim reporting periods. These disclosures are included in Note B.
Postretirement Benefit Plan Assets - Effective for our fiscal year ending December 31, 2009, we will provide 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. These additional disclosure requirements will be applied prospectively.
Subsequent Events - Effective for our quarter ended June 30, 2009, the FASB established standards related to the accounting for and disclosure of events that occur after the balance sheet date but before consolidated financial statements are issued. We have evaluated subsequent
events through November 5, 2009, the date our consolidated financial statements were issued, and all required disclosures have been made.
B. FAIR VALUE MEASUREMENTS
Refer to Notes A and C of the Notes to Consolidated Financial Statements in our Annual Report for a discussion of our fair value measurements and the fair value hierarchy.
Recurring Fair Value Measurements - The following tables set forth our recurring fair value measurements for the periods indicated:
| |
|
September 30, 2009 |
|
| |
|
Level 1 |
|
|
Level 2 |
|
|
Level 3 |
|
|
Netting (a) |
|
|
Total |
|
| |
|
(Thousands of dollars) |
|
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives |
|
$ |
188,255 |
|
|
$ |
28,437 |
|
|
$ |
736,131 |
|
|
$ |
(792,755 |
) |
|
$ |
160,068 |
|
|
Trading securities |
|
|
7,271 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
7,271 |
|
|
Available-for-sale investment securities |
|
|
2,466 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
2,466 |
|
|
Total assets |
|
$ |
197,992 |
|
|
$ |
28,437 |
|
|
$ |
736,131 |
|
|
$ |
(792,755 |
) |
|
$ |
169,805 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives |
|
$ |
(147,567 |
) |
|
$ |
(11,894 |
) |
|
$ |
(564,092 |
) |
|
$ |
661,324 |
|
|
$ |
(62,229 |
) |
|
Fair value of firm commitments |
|
|
- |
|
|
|
- |
|
|
|
(156,337 |
) |
|
|
- |
|
|
|
(156,337 |
) |
|
Total liabilities |
|
$ |
(147,567 |
) |
|
$ |
(11,894 |
) |
|
$ |
(720,429 |
) |
|
$ |
661,324 |
|
|
$ |
(218,566 |
) |
|
(a) - Our derivative assets and liabilities are presented in our Consolidated Balance Sheet on a net basis. We net derivative assets and liabilities, including cash collateral, when a legally enforceable master netting arrangement exists between us and the counterparty to a derivative contract. At September 30, 2009, we held $149.1
million of cash collateral and had posted $17.7 million of cash collateral with various counterparties. |
|
| |
|
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 Sheet on a net basis. We net derivative assets and liabilities, including cash collateral, 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. |
|
We categorize derivatives for which fair value is determined based on multiple inputs within a single level, based on the lowest level input that is significant to the fair 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, which are valued
based on unadjusted quoted prices in active markets. Also included in Level 1 are equity securities and foreign currency forwards.
Our Level 2 fair value inputs are based on NYMEX-settled prices for natural gas and crude oil that are utilized to determine the fair value of certain non-exchange traded financial instruments, including natural gas and crude oil swaps, respectively.
Our Level 3 inputs include internally developed basis curves incorporating observable and unobservable market data, NGL price curves from a pricing service, historical correlations of NGL product prices to published NYMEX crude oil prices, market volatilities derived from the most recent NYMEX close spot prices and forward LIBOR curves, and
adjustments for the credit risk of our counterparties. We corroborate the data on which our fair value estimates are based using our market knowledge of recent transactions, analysis of historical correlations and validation with independent broker quotes or a pricing service. The derivatives categorized as Level 3 include natural gas basis swaps, swing swaps, options and physical forward contracts, NGL swaps and interest-rate swaps. Also included in Level 3 are the fair values
of firm commitments and long-term debt that have been hedged. We do not believe that our Level 3 fair value estimates have a material impact on our results of operations, as the majority of our derivatives are accounted for as hedges for which ineffectiveness is not material.
The following tables set forth the reconciliation of our Level 3 fair value measurements for the periods indicated:
| |
Derivative
Assets
(Liabilities) |
|
Fair Value of
Firm
Commitments |
|
|
Long-Term
Debt |
|
|
Total |
|
| |
|
(Thousands of dollars) |
|
|
July 1, 2009 |
|
$ |
170,414 |
|
|
|
$ |
(137,403 |
) |
|
|
$ |
- |
|
|
$ |
33,011 |
|
|
Total realized/unrealized gains (losses): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in earnings |
|
|
(1,815 |
) |
(a) |
|
|
(18,934 |
) |
(a) |
|
|
- |
|
|
|
(20,749 |
) |
|
Included in other comprehensive income (loss) |
|
|
(13,137 |
) |
|
|
|
- |
|
|
|
|
- |
|
|
|
(13,137 |
) |
|
Transfers in and/or out of Level 3 |
|
|
16,577 |
|
|
|
|
- |
|
|
|
|
- |
|
|
|
16,577 |
|
|
September 30, 2009 |
|
$ |
172,039 |
|
|
|
$ |
(156,337 |
) |
|
|
$ |
- |
|
|
$ |
15,702 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 September 30, 2009 |
|
$ |
59,180 |
|
(a) |
|
$ |
(43,737 |
) |
(a) |
|
|
- |
|
|
$ |
15,443 |
|
|
(a) - Reported in revenues and cost of sales and fuel in our Consolidated Statements of Income. |
|
|
|
|
|
|
|
|
| |
Derivative
Assets
(Liabilities) |
|
Fair Value of
Firm
Commitments |
|
|
Long-Term
Debt |
|
|
Total |
|
| |
|
(Thousands of dollars) |
|
|
July 1, 2008 |
|
$ |
(410,361 |
) |
|
|
$ |
393,310 |
|
|
|
$ |
(340,208 |
) |
|
$ |
(357,259 |
) |
|
Total realized/unrealized gains (losses): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in earnings |
|
|
193,256 |
|
(a) |
|
|
(214,801 |
) |
(a) |
|
|
(3,304 |
) |
(b) |
(24,849 |
) |
|
Included in other comprehensive income (loss) |
|
|
49,429 |
|
|
|
|
- |
|
|
|
|
- |
|
|
|
49,429 |
|
|
Transfers in and/or out of Level 3 |
|
|
(7,862 |
) |
|
|
|
- |
|
|
|
|
- |
|
|
|
(7,862 |
) |
|
September 30, 2008 |
|
$ |
(175,538 |
) |
|
|
$ |
178,509 |
|
|
|
$ |
(343,512 |
) |
|
$ |
(340,541 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 September 30, 2008 |
|
$ |
116,031 |
|
(a) |
|
$ |
(134,270 |
) |
(a) |
|
$ |
(3,304 |
) |
(b) |
$ |
(21,543 |
) |
|
(a) - Reported in revenues and cost of sales and fuel in our Consolidated Statements of Income. |
|
|
|
|
|
|
|
|
|
(b) - Reported in interest expense in our Consolidated Statements of Income. |
|
|
|
|
|
|
|
|
|
|
| |
|
Derivative
Assets
(Liabilities) |
|
|
|
Fair Value of
Firm
Commitments |
|
|
|
Long-Term
Debt |
|
|
Total |
|
| |
|
(Thousands of dollars) |
|
|
January 1, 2009 |
|
$ |
42,355 |
|
|
|
$ |
42,179 |
|
|
|
$ |
(171,455 |
) |
|
$ |
(86,921 |
) |
|
Total realized/unrealized gains (losses): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in earnings |
|
|
194,085 |
|
(a) |
|
|
(198,516 |
) |
(a) |
|
|
1,455 |
|
(b) |
|
(2,976 |
) |
|
Included in other comprehensive income (loss) |
|
|
(73,197 |
) |
|
|
|
- |
|
|
|
|
- |
|
|
|
(73,197 |
) |
|
Maturities |
|
|
- |
|
|
|
|
- |
|
|
|
|
100,000 |
|
|
|
100,000 |
|
|
Terminations prior to maturity |
|
|
- |
|
|
|
|
- |
|
|
|
|
70,000 |
|
|
|
70,000 |
|
|
Transfers in and/or out of Level 3 |
|
|
8,796 |
|
|
|
|
- |
|
|
|
|
- |
|
|
|
8,796 |
|
|
September 30, 2009 |
|
$ |
172,039 |
|
|
|
$ |
(156,337 |
) |
|
|
$ |
- |
|
|
$ |
15,702 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 September 30, 2009 |
|
$ |
212,621 |
|
(a) |
|
$ |
(182,093 |
) |
(a) |
|
$ |
- |
|
|
$ |
30,528 |
|
|
(a) - Reported in revenues and cost of sales and fuel in our Consolidated Statements of Income. |
|
|
|
|
|
|
|
|
|
(b) - Reported in interest expense in our Consolidated Statements of Income. |
|
|
|
|
|
|
|
|
|
|
| |
|
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 |
|
|
(164,397 |
) |
(a) |
|
|
135,825 |
|
(a) |
|
|
(4,974 |
) |
(b) |
|
(33,546 |
) |
|
Included in other comprehensive income (loss) |
|
|
45,423 |
|
|
|
|
- |
|
|
|
|
- |
|
|
|
45,423 |
|
|
Transfers in and/or out of Level 3 |
|
|
(1,982 |
) |
|
|
|
- |
|
|
|
|
- |
|
|
|
(1,982 |
) |
|
September 30, 2008 |
|
$ |
(175,538 |
) |
|
|
$ |
178,509 |
|
|
|
$ |
(343,512 |
) |
|
$ |
(340,541 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 September 30, 2008 |
|
$ |
(138,518 |
) |
(a) |
|
$ |
142,751 |
|
(a) |
|
$ |
(4,974 |
) |
(b) |
$ |
(741 |
) |
|
(a) - Reported in revenues and cost of sales and fuel in our Consolidated Statements of Income. |
|
|
|
|
|
|
|
|
|
(b) - Reported in interest expense in our Consolidated Statements of Income. |
|
|
|
|
|
|
|
|
|
|
Realized/unrealized gains (losses) include the realization of our derivative contracts through maturity and changes in fair value of our hedged firm commitments and fixed-rate debt swapped to a floating rate. Maturities represent the long-term debt associated with an interest-rate swap that matured during the period. Terminations
prior to maturity represent the long-term debt associated with an interest rate swap that was terminated during the period. Transfers into Level 3 represent existing assets or liabilities that were previously categorized at a higher level for which the inputs to our fair value estimates 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 in Note A of the Notes to Consolidated Financial Statements in our Annual Report.
Investment Securities - Net unrealized holding gains, net of tax, for our investment securities classified as available for sale and reported in accumulated other comprehensive income (loss) were immaterial as of December 31, 2008. Net unrealized holding gains, net of tax, for our
investment securities classified as available for sale and reported in accumulated other comprehensive income (loss) were $1.3 million as of September 30, 2009. For the three and nine months ended September 30, 2009, net unrealized holding gains (losses) on available-for-sale securities included in other comprehensive income were immaterial. For the nine months ended September 30, 2009, we recorded a net gain of $2.4 million, which represents the total mark-to-market effect of trading securities still
held as of September 30, 2009. The net gain (loss) recorded for the three months ended September 30, 2009, was immaterial.
Other Financial Instruments - The approximate fair value of cash and cash equivalents, accounts receivable and accounts payable is equal to book value, due to its short-term nature. The fair value of notes payable
approximates the carrying value since the interest rates, prescribed by each borrowing’s respective credit agreement, are periodically adjusted to reflect current market conditions.
The estimated fair value of long-term debt, including current maturities, was $4.9 billion at September 30, 2009. The book value of long-term debt, including current maturities, was $4.6 billion at September 30, 2009. The estimated fair value of long-term debt has been determined using quoted market prices of the same
or similar issues with similar terms and maturities.
C. RISK MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES
Energy Marketing and Risk Management Activities
Our Energy Services and ONEOK Partners segments are exposed to various risks that we manage by periodically entering into derivative instruments. These risks include the following:
|
· |
Commodity price risk - We are exposed to the risk of loss in cash flows and future earnings arising from adverse changes in the price of natural gas, NGLs and crude oil. We use commodity derivative instruments such as futures, physical forward contracts, swaps and options to mitigate
the commodity price risk associated with a portion of the forecasted purchases and sales of commodities and natural gas and natural gas liquids in storage. |
|
· |
Basis risk - We are exposed to the risk of loss in cash flows and future earnings arising from adverse changes in the price differentials between pipeline receipt and delivery locations. Our firm transportation capacity allows us to purchase gas at a pipeline receipt point and
sell gas at a pipeline delivery point. Our Energy Services segment periodically enters into basis swaps between the transportation receipt and delivery points in order to protect the fair value of these location price differentials related to our firm commitments. |
|
· |
Currency exchange rate risk - As a result of our Energy Services segment’s activities in Canada, we are exposed to the risk of loss in cash flows and future earnings from adverse changes in currency exchange rates on our commodity purchases and sales primarily related to our firm transportation
and storage contracts that are transacted in a currency other than our functional currency, the U.S. dollar. To reduce our exposure to exchange-rate fluctuations, we use physical forward transactions, which result in an actual two-way flow of currency on the settlement date in which we exchange U.S. dollars for Canadian dollars with another party. |
The following derivative instruments are used to manage our exposure to these risks:
|
· |
Futures contracts - Standardized exchange-traded contracts to purchase or sell natural gas and crude oil at a specified price, requiring delivery on or settlement through the sale or purchase of an offsetting contract by a specified future date under the provisions of exchange regulations. |
|
· |
Forward contracts - Commitments to purchase or sell natural gas, crude oil or NGLs for delivery at some specified time in the future. Forward contracts are different from futures in that forwards are customized and non-exchange traded. |
|
· |
Swaps - Financial trades involving the exchange of payments based on two different pricing structures for a commodity. In a typical commodity swap, parties exchange payments based on changes in the price of a commodity or a market index, while fixing the price they effectively
pay or receive for the physical commodity. As a result, one party assumes the risks and benefits of movements in market prices, while the other party assumes the risks and benefits of a fixed price for the commodity. |
|
· |
Options - Contractual agreements that give the holder the right, but not the obligation, to buy or sell a fixed quantity of a commodity, at a fixed price, within a specified period of time. Options may either be standardized, exchange traded or customized and non-exchange traded. |
Our objectives for entering into such contracts include, but are not limited to:
|
· |
reducing the variability of cash flows by locking in the price for all or a portion of anticipated index-based physical purchases and sales, transportation fuel requirements, asset management transactions and customer-related business activities; |
|
· |
locking in a price differential to protect the fair value between transportation receipt and delivery points and to protect the fair value of natural gas or NGLs that are purchased in one month and sold in a later month; and |
|
· |
reducing our exposure to fluctuations in foreign currency exchange rates. |
Our Energy Services segment also enters into derivative contracts for financial trading purposes primarily to capitalize on opportunities created by market volatility, weather-related events, supply-demand imbalances and market liquidity
inefficiency, which allows us to capture additional margin. Financial trading activities are executed generally using financially settled derivatives and are normally short term in nature.
With respect to the net open positions that exist within our marketing and financial trading operations, fluctuating commodity prices can impact our financial position and results of operations. 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.
Our Distribution segment also uses derivative instruments to hedge the cost of anticipated natural gas purchases during the winter heating months to protect our customers from upward volatility in the market price of natural gas. The use of these derivative instruments and the associated recovery of these costs have been approved
by the OCC, KCC and regulatory authorities in certain of our Texas jurisdictions.
We are also subject to fluctuation in interest rates. We manage interest-rate risk through the use of fixed-rate debt, floating-rate debt and interest-rate swaps. Interest-rate swaps are agreements to exchange an interest payment at some future point based on the differential between two interest rates.
Accounting Treatment
We record derivative instruments at fair 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 certain conditions are met, we may elect to designate a derivative instrument as a hedge of exposure to changes in fair values, cash flows or foreign currency. Certain non-trading derivative transactions, which are economic hedges of our accrual transactions, such as our storage and transportation contracts, do not qualify for
hedge accounting treatment.
The table below summarizes the various ways in which we account for our derivative instruments and the impact on our consolidated financial statements:
|
Accounting Treatment |
|
Recognition and Measurement |
| |
Balance Sheet |
|
Income Statement |
|
Normal purchases and
normal sales |
- |
Fair value not recorded |
- |
Change in fair value not recognized in earnings |
|
Mark-to-market |
- |
Recorded at fair value |
- |
Change in fair value recognized in earnings |
|
Cash flow hedge |
- |
Recorded at fair value |
- |
Ineffective portion of the gain or loss on the derivative
instrument is recognized in earnings |
| |
- |
Effective portion of the gain or loss on the
derivative instrument is reported initially as
a component of accumulated other
comprehensive income (loss) |
- |
Effective portion of the gain or loss on the derivative
instrument is reclassified out of accumulated other
comprehensive income (loss) into earnings when the
forecasted transaction affects earnings |
|
Fair value hedge |
- |
Recorded at fair value |
- |
The gain or loss on the derivative instrument is
recognized in earnings |
| |
- |
Change in fair value of the hedged item is
recorded as an adjustment to book value |
- |
Change in fair value of the hedged item is recognized
in earnings |
| |
|
|
|
|
Gains or losses associated with the fair value of derivative instruments entered into by our Distribution segment are included in, and recoverable through, the monthly purchased-gas cost mechanism.
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 quarterly by performing a regression analysis on our cash flow and fair value hedging relationships to determine whether the hedge relationships are highly effective on a retrospective and prospective basis. We also document our normal purchases and normal sales transactions that we expect to result in physical delivery and which we elect to exempt from derivative accounting treatment.
The presentation of settled derivative instruments on either a gross or net basis in our Consolidated Statements of Income is dependent on the relevant facts and circumstances of our different types of activities rather than based solely on the terms of the individual contracts. All financially settled derivative instruments, as
well as derivative instruments considered held for trading purposes that result in physical delivery, are reported on a net basis in revenues in our Consolidated Statements of Income. The realized revenues and purchase costs of derivative instruments that are not considered held for trading purposes and non-derivative contracts are reported on a gross basis. Derivatives that qualify as normal purchases or normal sales that are expected to result in physical delivery are also reported on
a gross basis.
Revenues in our Consolidated Statements of Income include 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 reported on a net basis.
Cash flows from futures, forwards, options and swaps that are accounted for as hedges are included in the same Consolidated Statements of Cash Flows category as the cash flows from the related hedged items.
Fair Values of Derivative Instruments
Fair value is defined 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. See Note B for a discussion of the inputs associated with our fair value measurements and our fair value hierarchy disclosures.
The following table sets forth the fair values of our derivative instruments for the period indicated:
| |
|
September 30, 2009 |
|
| |
|
Fair Values of Derivatives (a) |
|
| |
|
Assets |
|
|
(Liabilities) |
|
| |
|
(Thousands of dollars) |
|
|
Derivative commodity contracts designated as hedging |
|
|
|
|
|
|
|
instruments |
|
$ |
739,304 |
|
|
$ |
(511,691 |
) |
| |
|
|
|
|
|
|
|
|
|
Derivatives not designated as hedging instruments |
|
|
|
|
|
|
|
|
|
Commodity contracts |
|
|
213,505 |
|
|
|
(211,667 |
) |
|
Foreign exchange contracts |
|
|
14 |
|
|
|
(195 |
) |
|
Total derivatives not designated as hedging instruments |
|
|
213,519 |
|
|
|
(211,862 |
) |
|
Total derivatives |
|
$ |
952,823 |
|
|
$ |
(723,553 |
) |
| |
|
|
|
|
|
|
|
|
|
(a) - Included on a net basis in energy marketing and risk management assets and liabilities on our Consolidated
Balance Sheet. |
|
| |
|
|
|
|
|
|
|
|
The following table sets forth the notional quantities for derivative instruments held for the period indicated:
| |
September 30, 2009 |
|
|
|
Contract
Type |
|
Purchased/
Payor |
|
|
Sold/
Receiver |
|
|
Derivatives designated as hedging instruments: |
|
|
|
|
|
|
|
Cash flow hedges |
|
|
|
|
|
|
|
|
Fixed price |
|
|
|
|
|
|
|
|
- Natural gas (Bcf) |
Exchange futures |
|
|
8.3 |
|
|
|
(27.1 |
) |
|
|
Swaps |
|
|
15.3 |
|
|
|
(87.8 |
) |
|
- Crude oil and NGLs (MMBbl) |
Swaps |
|
|
- |
|
|
|
(1.5 |
) |
|
Basis |
|
|
|
|
|
|
|
|
|
|
- Natural gas (Bcf) |
Swaps |
|
|
22.2 |
|
|
|
(113.0 |
) |
|
Fair value hedges |
|
|
|
|
|
|
|
|
|
|
Basis |
|
|
|
|
|
|
|
|
|
|
- Natural gas (Bcf) |
Forwards and swaps |
|
|
283.5 |
|
|
|
(283.5 |
) |
| |
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as hedging instruments: |
|
|
|
|
|
|
|
|
|
Fixed price |
|
|
|
|
|
|
|
|
|
|
- Natural gas (Bcf) |
Exchange futures |
|
|
34.1 |
|
|
|
(17.1 |
) |
|
|
Forwards and swaps |
|
|
74.2 |
|
|
|
(91.1 |
) |
|
|
Options |
|
|
113.6 |
|
|
|
(89.2 |
) |
|
- Foreign currency (Millions of dollars) |
Swaps |
|
$ |
6.1 |
|
|
$ |
- |
|
|
Basis |
|
|
|
|
|
|
|
|
|
|
- Natural gas (Bcf) |
Forwards and swaps |
|
|
937.5 |
|
|
|
(965.0 |
) |
|
Index |
|
|
|
|
|
|
|
|
|
|
- Natural gas (Bcf) |
Forwards and swaps |
|
|
70.7 |
|
|
|
(43.7 |
) |
These notional amounts are used to summarize the volume of financial instruments. However, they do not reflect the extent to which the positions offset one another and consequently do not reflect our actual exposure to market or credit risk.
Cash Flow Hedges - Our Energy Services and ONEOK Partners segments use derivative instruments to hedge the cash flows associated with anticipated purchases and sales of natural gas, NGLs and condensate and cost of fuel used
in the transportation of natural gas. Accumulated other comprehensive income (loss) at September 30, 2009, includes losses of approximately $9.2 million, net of tax, related to these hedges that will be realized within the next 25 months as the forecasted transactions affect earnings. If prices remain at current levels, we will recognize $5.4 million in net losses over the next 12 months, and we will recognize net losses of $3.8 million thereafter.
For the nine months ended September 30, 2009, cost of sales and fuel in our Consolidated Statements of Income includes $11.3 million reflecting an adjustment to inventory at the lower of cost or market. We reclassified $11.3 million of deferred gains, before income taxes, on associated cash flow hedges from accumulated other comprehensive
income (loss) into earnings.
The following table sets forth the effect of cash flow hedges recognized in other comprehensive income (loss) for the periods indicated:
|
Derivatives in Cash Flow
Hedging Relationships |
Three Months Ended
September 30, 2009 |
Nine Months Ended
September 30, 2009 |
| |
|
(Thousands of dollars) |
|
|
Commodity contracts |
|
$ |
(32,603 |
) |
|
$ |
33,642 |
|
|
Interest rate contracts |
|
|
1,035 |
|
|
|
1,599 |
|
|
Total gain (loss) recognized in other comprehensive
income (loss) on derivatives (effective portion) |
|
$ |
(31,568 |
) |
|
$ |
35,241 |
|
| |
|
|
|
|
|
|
|
|
The following tables set forth the effect of cash flow hedges on our Consolidated Statements of Income for the periods indicated:
| |
Location of Gain (Loss) Reclassified from |
|
|
|
|
|
|
|
Derivatives in Cash Flow
Hedging Relationships |
Accumulated Other Comprehensive Income |
|
Three Months Ended |
|
Nine Months Ended |
|
(Loss) into Net Income (Effective Portion) |
|
September 30, 2009 |
|
September 30, 2009 |
| |
|
|
(Thousands of dollars) |
|
|
Commodity contracts |
Revenues |
|
$ |
37,640 |
|
|
$ |
151,512 |
|
|
Commodity contracts |
Cost of sales and fuel |
|
|
(9,529 |
) |
|
|
(20,707 |
) |
|
Interest rate contracts |
Interest expense |
|
|
365 |
|
|
|
1,237 |
|
|
Total gain (loss) reclassified from accumulated other comprehensive
income (loss) into net income on derivatives (effective portion) |
|
$ |
28,476 |
|
|
$ |
132,042 |
|
| |
|
|
|
|
|
|
|
|
|
| |
Location of Gain (Loss) Recognized in Income on |
|
|
|
|
|
|
|
Derivatives in Cash Flow
Hedging Relationships |
Derivatives (Ineffective Portion and Amount |
|
Three Months Ended |
|
Nine Months Ended |
|
Excluded from Effectiveness Testing) |
|
September 30, 2009 |
|
September 30, 2009 |
| |
|
|
(Thousands of dollars) |
|
|
Commodity contracts |
Revenues |
|
$ |
(1,597 |
) |
|
$ |
1,223 |
|
|
Commodity contracts |
Cost of sales and fuel |
|
|
120 |
|
|
|
(627 |
) |
|
Total gain (loss) recognized in income on derivatives (ineffective
portion and amount excluded from effectiveness testing) |
|
$ |
(1,477 |
) |
|
$ |
596 |
|
| |
|
|
|
|
|
|
|
|
|
Ineffectiveness related to our cash flow hedges resulted in gains of approximately $1.2 million for the three months ended September 30, 2008. Ineffectiveness related to our cash flow hedges resulted in losses of approximately $0.6 million for the nine months ended September 30, 2008. In the event that it becomes probable
that a forecasted transaction will not occur, we will discontinue cash flow hedge treatment, which will affect earnings. For the three and nine months ended September 30, 2009 and 2008, there were no gains or losses due to the discontinuance of cash flow hedge treatment since the underlying transactions were no longer probable.
Other Derivative Instruments - The following table sets forth the effect of our derivative instruments that are not part of a hedging relationship on our Consolidated Statements of Income for the periods indicated:
|
Derivatives Not Designated as
Hedging Instruments |
Location of Gain (Loss) |
|
Three Months Ended
September 30, 2009 |
|
Nine Months Ended
September 30, 2009 |
| |
|
|
(Thousands of dollars) |
|
|
Commodity contracts - trading |
Revenues |
|
$ |
46 |
|
|
$ |
3,455 |
|
|
Commodity contracts - non-trading (a) |
Cost of gas and fuel |
|
|
7,441 |
|
|
|
9,378 |
|
|
Foreign exchange contracts |
Revenues |
|
|
462 |
|
|
|
785 |
|
|
Total gain (loss) recognized in income on derivatives |
|
$ |
7,949 |
|
|
$ |
13,618 |
|
|
(a) - For the three and nine months ended September 30, 2009, we recognized $1.8 million and $3.9 million, respectively, of
losses associated with the fair value of derivative instruments entered into by our Distribution segment that were deferred as they
are included in, and recoverable through, the monthly purchased-gas cost mechanism. |
|
Fair Value Hedges - In prior years, we terminated various interest-rate swap agreements. The net savings from the termination of these swaps is being recognized in interest expense over the terms of the debt instruments originally hedged. Interest expense savings
from the amortization of terminated swaps for the three months ended September 30, 2009 and 2008, were $2.5 million and $2.6 million, respectively. Interest expense savings from the amortization of terminated swaps for the nine months ended September 30, 2009 and 2008, were $7.7 million and $7.8 million, respectively, and the remaining amortization of terminated swaps will be recognized over the following periods:
| |
|
|
|
|
ONEOK |
|
|
|
| |
|
ONEOK |
|
Partners |
|
Total |
| |
|
(Millions of dollars) |
|
|
Remainder of 2009 |
|
$ |
1.6 |
|
|
$ |
0.9 |
|
|
$ |
2.5 |
|
|
2010 |
|
$ |
6.4 |
|
|
$ |
3.7 |
|
|
$ |
10.1 |
|
|
2011 |
|
$ |
3.4 |
|
|
$ |
0.9 |
|
|
$ |
4.3 |
|
|
2012 |
|
$ |
1.7 |
|
|
$ |
- |
|
|
$ |
1.7 |
|
|
2013 |
|
$ |
1.7 |
|
|
$ |
- |
|
|
$ |
1.7 |
|
|
2014 |
|
$ |
1.7 |
|
|
$ |
- |
|
|
$ |
1.7 |
|
|
Thereafter |
|
$ |
23.6 |
|
|
$ |
- |
|
|
$ |
23.6 |
|
ONEOK and ONEOK Partners had no interest-rate swap agreements at September 30, 2009.
Our Energy Services segment uses basis swaps to hedge the fair value of location price differentials related to 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 gains
of $1.2 million and losses of $3.6 million for the three months ended September 30, 2009 and 2008, respectively. The ineffectiveness related to these hedges included gains of $0.5 million and losses of $3.2 million for the nine months ended September 30, 2009 and 2008, respectively.
For the three and nine months ended September 30, 2009, cost of sales and fuel in our Consolidated Statements of Income include gains of $53.4 million and $231.7 million, respectively, related to the change in fair value of derivatives declared as fair value hedges. Revenues include losses of $52.2 million and $231.3 million for
the three and nine months ended September 30, 2009, respectively, to recognize the change in fair value of the hedged firm commitments.
Credit Risk - We monitor the creditworthiness of our counterparties and compliance with management’s risk tolerance as determined by our Risk Oversight and Strategy Committee. 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, bond yields and credit default swap rates), collateral requirements under certain circumstances and the use of standardized master-netting agreements that allow us to net the positive and negative exposures associated with a single counterparty. We have counterparties whose credit is not rated and for those customers, we use internally developed credit ratings.
Some of our derivative instruments contain provisions that require us to maintain an investment grade credit rating from S&P and/or Moody’s. If our credit ratings on senior unsecured long-term debt were to decline below investment grade, we would be in violation of these provisions, and the counterparties to the derivative
instruments could request collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with contingent features related to credit risk that were in a net liability position as of September 30, 2009, was $29.5 million for which we have posted collateral of $17.7 million in the normal course of business. If the contingent features underlying these agreements were triggered on September 30, 2009, we would have been required to
post an additional $11.8 million of collateral to our counterparties.
The counterparties to our derivative contracts consist primarily of major energy companies, LDCs, electric utilities, financial institutions 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.
The following table sets forth the net credit exposure from our derivative assets for the period indicated:
| |
|
September 30, 2009 |
|
| |
|
Investment |
|
|
Non-investment |
|
|
Not |
|
| |
|
Grade |
|
|
Grade |
|
|
Rated |
|
|
Counterparty sector |
|
(Thousands of dollars) |
|
|
Gas and electric utilities |
|
$ |
44,222 |
|
|
$ |
4,723 |
|
|
$ |
9,145 |
|
|
Oil and gas |
|
|
62,036 |
|
|
|
358 |
|
|
|
5,982 |
|
|
Industrial |
|
|
1,346 |
|
|
|
- |
|
|
|
6 |
|
|
Financial |
|
|
32,179 |
|
|
|
- |
|
|
|
11 |
|
|
Other |
|
|
17 |
|
|
|
39 |
|
|
|
4 |
|
|
Total |
|
$ |
139,800 |
|
|
$ |
5,120 |
|
|
$ |
15,148 |
|
D. OTHER COMPREHENSIVE INCOME (LOSS)
The following tables set forth the gross amount of other comprehensive income (loss) and related tax (expense) benefit for the periods indicated:
| |
|
Three Months Ended |
|
|
Three Months Ended |
|
| |
|
September 30, 2009 |
|
|
September 30, 2008 |
|
| |
|
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 |
|
$ |
(31,568 |
) |
|
$ |
12,104 |
|
|
$ |
(19,464 |
) |
|
$ |
275,374 |
|
|
$ |
(93,027 |
) |
|
$ |
182,347 |
|
|
Less: Gains on energy marketing
and risk management assets/liabilities
recognized in net income |
|
|
28,476 |
|
|
|
(8,283 |
) |
|
|
20,193 |
|
|
|
145,476 |
|
|
|
(59,143 |
) |
|
|
86,333 |
|
|
Unrealized holding gains (losses) on
investment securities arising
during the period |
|
|
(23 |
) |
|
|
9 |
|
|
|
(14 |
) |
|
|
352 |
|
|
|
(136 |
) |
|
|
216 |
|
|
Less: Gains on investment securities
recognized in net income |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
11,142 |
|
|
|
(4,310 |
) |
|
|
6,832 |
|
|
Change in pension and postretirement
benefit plan liability |
|
|
(5,317 |
) |
|
|
2,057 |
|
|
|
(3,260 |
) |
|
|
(4,025 |
) |
|
|
1,557 |
|
|
|
(2,468 |
) |
|
Other |
|
|
29 |
|
|
|
(11 |
) |
|
|
18 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Other comprehensive income (loss) |
|
|
(65,355 |
) |
|
|
22,442 |
|
|
|
(42,913 |
) |
|
|
115,083 |
|
|
|
(28,153 |
) |
|
|
86,930 |
|
|
Less: Other comprehensive income (loss)
attributable to noncontrolling interests |
|
|
(7,333 |
) |
|
|
- |
|
|
|
(7,333 |
) |
|
|
42,297 |
|
|
|
- |
|
|
|
42,297 |
|
|
Total other comprehensive income (loss)
attributable to ONEOK |
|
$ |
(58,022 |
) |
|
$ |
22,442 |
|
|
$ |
(35,580 |
) |
|
$ |
72,786 |
|
|
$ |
(28,153 |
) |
|
$ |
44,633 |
|
| |
|
Nine Months Ended |
|
|
Nine Months Ended |
|
| |
|
September 30, 2009 |
|
|
September 30, 2008 |
|
| |
|
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 |
|
$ |
35,241 |
|
|
$ |
(16,237 |
) |
|
$ |
19,004 |
|
|
$ |
94,095 |
|
|
$ |
(30,318 |
) |
|
$ |
63,777 |
|
|
Less: Gains on energy marketing
and risk management assets/liabilities
recognized in net income |
|
|
132,042 |
|
|
|
(41,135 |
) |
|
|
90,907 |
|
|
|
144,516 |
|
|
|
(62,183 |
) |
|
|
82,333 |
|
|
Unrealized holding gains (losses) on
investment securities arising
during the period |
|
|
801 |
|
|
|
(310 |
) |
|
|
491 |
|
|
|
(8,529 |
) |
|
|
3,299 |
|
|
|
(5,230 |
) |
|
Less: Gains on investment securities
recognized in net income |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
11,142 |
|
|
|
(4,310 |
) |
|
|
6,832 |
|
|
Change in pension and postretirement
benefit plan liability |
|
|
(14,767 |
) |
|
|
5,712 |
|
|
|
(9,055 |
) |
|
|
(12,075 |
) |
|
|
4,670 |
|
|
|
(7,405 |
) |
|
Other |
|
|
299 |
|
|
|
(71 |
) |
|
|
228 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Other comprehensive income (loss) |
|
|
(110,468 |
) |
|
|
30,229 |
|
|
|
(80,239 |
) |
|
|
(82,167 |
) |
|
|
44,144 |
|
|
|
(38,023 |
) |
|
Less: Other comprehensive income (loss)
attributable to noncontrolling interests |
|
|
(32,315 |
) |
|
|
- |
|
|
|
(32,315 |
) |
|
|
23,671 |
|
|
|
- |
|
|
|
23,671 |
|
|
Total other comprehensive income (loss)
attributable to ONEOK |
|
$ |
(78,153 |
) |
|
$ |
30,229 |
|
|
$ |
(47,924 |
) |
|
$ |
(105,838 |
) |
|
$ |
44,144 |
|
|
$ |
(61,694 |
) |
The following table sets forth the balance in accumulated other comprehensive income (loss) for the periods indicated:
| |
|
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, 2008 |
|
$ |
27,913 |
|
|
$ |
814 |
|
|
$ |
(99,343) |
|
|
$ |
(70,616) |
|
|
Other comprehensive income (loss)
attributable to ONEOK |
|
|
(39,360) |
|
|
|
491 |
|
|
|
(9,055) |
|
|
|
(47,924) |
|
|
September 30, 2009 |
|
$ |
(11,447) |
|
|
$ |
1,305 |
|
|
$ |
(108,398) |
|
|
$ |
(118,540) |
|
E. CAPITAL STOCK
Dividends - Fourth-quarter 2008 and first-quarter 2009 dividends paid on our common stock to shareholders of record at the close of business on January 30, 2009, and April 30, 2009, respectively, were $0.40 per share. A second-quarter 2009 dividend paid on our common stock
to shareholders of record at the close of business on July 31, 2009, was $0.42 per share. Additionally, a third-quarter 2009 dividend of $0.42 per share was declared for shareholders of record at the close of business on October 30, 2009, payable on November 13, 2009.
F. CREDIT FACILITIES AND SHORT-TERM NOTES PAYABLE
ONEOK’s $1.2 billion amended and restated credit agreement dated July 14, 2006 (ONEOK Credit Agreement), which expires in July 2011, and ONEOK Partners’ $1.0 billion amended and restated revolving credit agreement dated March 30, 2007 (ONEOK Partners Credit Agreement), which expires in March 2012, contain certain financial and
other typical covenants as discussed in Note H of the Notes to Consolidated Financial Statements in our Annual Report. Among other things, the ONEOK Credit Agreement’s covenants include 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. At September 30, 2009, ONEOK’s stand-alone debt-to-capital ratio, as calculated under the terms of the ONEOK Credit Agreement, was 45.4 percent, and ONEOK was
in compliance with all covenants under the ONEOK Credit Agreement.
ONEOK’s $400 million 364-day revolving credit facility dated August 6, 2008, expired on August 5, 2009.
The ONEOK Partners Credit Agreement’s covenants include, among other things, maintaining a ratio of indebtedness to adjusted EBITDA (EBITDA as adjusted for all non-cash charges and increased for projected EBITDA from certain lender-approved capital expansion projects) of no more than 5 to 1. At September 30, 2009, ONEOK Partners’
ratio of indebtedness to adjusted EBITDA was 4.7 to 1, and ONEOK Partners was in compliance with all covenants under the ONEOK Partners Credit Agreement at September 30, 2009.
At September 30, 2009, ONEOK had $309 million in commercial paper outstanding and $42 million in letters of credit issued under the ONEOK Credit Agreement. At September 30, 2009, ONEOK had approximately $849 million of credit available under the ONEOK Credit Agreement.
At September 30, 2009, ONEOK Partners had $515 million in borrowings outstanding under the ONEOK Partners Credit Agreement, and under the most restrictive provisions of the ONEOK Partners Credit Agreement had $219.7 million of credit available. ONEOK Partners had a total
of $49.2 million issued in letters of credit outside of the ONEOK Partners Credit Agreement.
Borrowings under the ONEOK Credit Agreement and the ONEOK Partners Credit Agreement are short term in nature, ranging from one day to six months. Accordingly, these borrowings are classified as short-term notes payable.
G. LONG-TERM DEBT
In February 2009, ONEOK repaid $100 million of maturing long-term debt with cash from operations and short-term borrowings.
ONEOK Partners’ Debt Issuance - In March 2009, ONEOK Partners completed an underwritten public offering of $500 million aggregate principal amount of 8.625 percent Senior Notes due 2019 (2019 Notes).
ONEOK Partners may redeem the 2019 Notes, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, 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 2019 Notes plus accrued and unpaid
interest to the redemption date. The 2019 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 any non-guarantor subsidiaries. The 2019 Notes are nonrecourse to ONEOK.
The net proceeds from the 2019 Notes, after deducting underwriting discounts and commissions and expenses, of approximately $494.3 million were used to repay indebtedness outstanding under the ONEOK Partners Credit Agreement.
The 2019 Notes are fully and unconditionally 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 has no significant assets or operations other
than its investment in its wholly owned subsidiary, the Intermediate Partnership, which is also consolidated. At September 30, 2009, the Intermediate Partnership held partnership interests in the equity of ONEOK Partners’ subsidiaries, as well as a 50 percent interest in Northern Border Pipeline.
The terms of the 2019 Notes are governed by an indenture, dated as of September 25, 2006, between ONEOK Partners and Wells Fargo Bank, N.A., as trustee, as supplemented by the Fifth Supplemental Indenture, dated March 3, 2009 (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 Indenture contains covenants including, among other provisions, limitations on ONEOK Partners’ ability to place liens on its property or assets and to sell and leaseback its property.
The 2019 Notes will mature on March 1, 2019. ONEOK Partners will pay interest on the 2019 Notes on March 1 and September 1 of each year. The first payment of interest on the 2019 Notes was made on September 1, 2009. Interest on the 2019 Notes accrues from March 3, 2009, which was the issuance date.
H. EMPLOYEE BENEFIT PLANS
The following table sets forth the components of net periodic benefit cost for our pension and other postretirement benefit plans for the periods indicated:
| |
|
Pension Benefits |
|
|
Pension Benefits |
|
| |
|
Three Months Ended |
|
|
Nine Months Ended |
|
| |
|
September 30, |
|
|
September 30, |
|
| |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
| |
(Thousands of dollars) |
|
Components of net periodic benefit cost |
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost |
|
$ |
4,983 |
|
|
$ |
5,042 |
|
|
$ |
14,951 |
|
|
$ |
15,124 |
|
|
Interest cost |
|
|
13,456 |
|
|
|
12,448 |
|
|
|
42,115 |
|
|
|
37,350 |
|
|
Expected return on assets |
|
|
(16,510 |
) |
|
|
(15,317 |
) |
|
|
(49,526 |
) |
|
|
(45,951 |
) |
|
Amortization of unrecognized prior service cost |
|
|
392 |
|
|
|
387 |
|
|
|
1,174 |
|
|
|
1,163 |
|
|
Amortization of net loss |
|
|
4,331 |
|
|
|
2,389 |
|
|
|
15,475 |
|
|
|
7,161 |
|
|
Net periodic benefit cost |
|
$ |
6,652 |
|
|
$ |
4,949 |
|
|
$ |
24,189 |
|
|
$ |
14,847 |
|
| |
|
Postretirement Benefits |
|
|
Postretirement Benefits |
|
| |
|
Three Months Ended |
|
|
Nine Months Ended |
|
| |
|
September 30, |
|
|
September 30, |
|
| |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
| |
(Thousands of dollars) |
|
Components of net periodic benefit cost |
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost |
|
$ |
1,293 |
|
|
$ |
1,418 |
|
|
$ |
3,880 |
|
|
$ |
4,256 |
|
|
Interest cost |
|
|
4,229 |
|
|
|
4,474 |
|
|
|
12,688 |
|
|
|
13,424 |
|
|
Expected return on assets |
|
|
(1,703 |
) |
|
|
(1,856 |
) |
|
|
(5,107 |
) |
|
|
(5,566 |
) |
|
Amortization of unrecognized net asset at adoption |
|
|
798 |
|
|
|
798 |
|
|
|
2,392 |
|
|
|
2,392 |
|
|
Amortization of unrecognized prior service cost |
|
|
(500 |
) |
|
|
(500 |
) |
|
|
(1,502 |
) |
|
|
(1,502 |
) |
|
Amortization of net loss |
|
|
2,415 |
|
|
|
2,743 |
|
|
|
7,245 |
|
|
|
8,229 |
|
|
Net periodic benefit cost |
|
$ |
6,532 |
|
|
$ |
7,077 |
|
|
$ |
19,596 |
|
|
$ |
21,233 |
|
I. COMMITMENTS AND CONTINGENCIES
Investment in Northern Border Pipeline - During the nine months ended September 30, 2009, ONEOK Partners made equity contributions of $42.3 million to Northern Border. ONEOK Partners does not anticipate any additional equity contributions in 2009 or material equity contributions
in 2010.
Environmental Liabilities - We are subject to multiple environmental, historical and wildlife preservation laws and regulations affecting many aspects of our present and future operations. Regulated activities include those involving air emissions, stormwater and wastewater
discharges, handling and disposal of solid and hazardous wastes, hazardous materials transportation, and pipeline and facility construction. These laws and regulations require us to obtain and comply with a wide variety of environmental clearances, registrations, licenses, permits 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 our results of operations. If
a leak or spill of hazardous substances or petroleum products occurs from lines or facilities that we own, operate or otherwise use, we could be held jointly and severally liable for all resulting liabilities, including response, investigation and clean 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, 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.
Of the 12 sites, we have begun soil remediation on 11 sites. Regulatory closure has been achieved at two locations, and we have completed or are near completion of soil remediation at nine sites. We have begun site assessment at the remaining site where no active remediation has occurred.
Our expenditures for environmental evaluation, mitigation, remediation and compliance to date have not been significant in relation to our financial position or results of operations, and our expenditures related to environmental matters had no material effect on earnings or cash flows during the three and nine months ended September 30, 2009
and 2008.
Legal Proceedings - We are a party to various litigation matters and claims that have arisen 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.
J. PROPERTY, PLANT AND EQUIPMENT
The following table sets forth our property, plant and equipment, by segment, for the periods indicated:
| |
|
September 30, |
|
|
December 31, |
|
| |
|
2009 |
|
|
2008 |
|
| |
|
(Thousands of dollars) |
|
|
Non-Regulated |
|
|
|
|
|
|
|
ONEOK Partners |
|
$ |
2,523,024 |
|
|
$ |
2,465,369 |
|
|
Energy Services |
|
|
7,907 |
|
|
|
7,907 |
|
|
Other |
|
|
239,569 |
|
|
|
225,479 |
|
|
Regulated |
|
|
|
|
|
|
|
|
|
ONEOK Partners |
|
|
3,727,738 |
|
|
|
3,343,310 |
|
|
Distribution |
|
|
3,512,168 |
|
|
|
3,434,554 |
|
|
Property, plant and equipment |
|
|
10,010,406 |
|
|
|
9,476,619 |
|
|
Accumulated depreciation and amortization |
|
|
2,311,810 |
|
|
|
2,212,850 |
|
|
Net property, plant and equipment |
|
$ |
7,698,596 |
|
|
$ |
7,263,769 |
|
Property, plant and equipment on our Consolidated Balance Sheets includes construction work in process for capital projects that have not yet been placed in service and therefore are not being depreciated. The following table sets forth our construction work in process, by segment, for the periods indicated:
| |
|
September 30, |
|
|
December 31, |
|
| |
|
2009 |
|
|
2008 |
|
| |
(Thousands of dollars) |
|
ONEOK Partners |
|
$ |
335,872 |
|
|
$ |
809,978 |
|
|
Distribution |
|
|
25,630 |
|
|
|
57,038 |
|
|
Other |
|
|
16,566 |
|
|
|
10,984 |
|
|
Total construction work in process |
|
$ |
378,068 |
|
|
$ |
878,000 |
|
K. SEGMENTS
Segment Descriptions - Our operations are divided 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.
Accounting Policies - The accounting policies of the segments are the same as those described in Note A and Note M of the Notes to Consolidated Financial Statements in our Annual Report. Intersegment sales are recorded on the same basis as sales to unaffiliated customers and
are discussed in further detail in Note N. Net margin is comprised of total revenues less cost of sales and fuel. Cost of sales and fuel includes commodity purchases, fuel, and storage and transportation costs.
Customers - For the three and nine months ended September 30, 2009 and 2008, we had no single external customer from which we received 10 percent or more of our consolidated revenues.
Operating Segment Information - The following tables set forth certain selected financial information for our operating segments for the periods indicated:
|
Three Months Ended
September 30, 2009 |
|
ONEOK
Partners (a) |
|
|
Distribution (b) |
|
Energy
Services |
|
|
Other and
Eliminations |
|
|
Total |
|
| |
|
(Thousands of dollars) |
|
|
Sales to unaffiliated customers |
|
$ |
1,443,421 |
|
|
$ |
214,255 |
|
|
$ |
706,334 |
|
|
$ |
726 |
|
|
$ |
2,364,736 |
|
|
Intersegment revenues |
|
|
116,582 |
|
|
|
1 |
|
|
|
21,328 |
|
|
|
(137,911 |
) |
|
|
- |
|
|
Total revenues |
|
$ |
1,560,003 |
|
|
$ |
214,256 |
|
|
$ |
727,662 |
|
|
$ |
(137,185 |
) |
|
$ |
2,364,736 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net margin |
|
$ |
292,879 |
|
|
$ |
128,479 |
|
|
$ |
29,749 |
|
|
$ |
747 |
|
|
$ |
451,854 |
|
|
Operating costs |
|
|
105,108 |
|
|
|
90,976 |
|
|
|
8,371 |
|
|
|
123 |
|
|
|
204,578 |
|
|
Depreciation and amortization |
|
|
41,857 |
|
|
|
29,911 |
|
|
|
154 |
|
|
|
396 |
|
|
|
72,318 |
|
|
Gain (loss) on sale of assets |
|
|
(1,180 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(1,180 |
) |
|
Operating income |
|
$ |
144,734 |
|
|
$ |
7,592 |
|
|
$ |
21,224 |
|
|
$ |
228 |
|
|
$ |
173,778 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity earnings from investments |
|
$ |
20,054 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
20,054 |
|
|
Capital expenditures |
|
$ |
169,396 |
|
|
$ |
33,603 |
|
|
$ |
- |
|
|
$ |
4,158 |
|
|
$ |
207,157 |
|
|
(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment’s regulated operations had revenues of $148.1 million, net margin of $110.4 million and operating income of $54.1 million. |
|
|
(b) - All of our Distribution segment’s operations are regulated. |
|
|
Three Months Ended
September 30, 2008 |
|
ONEOK
Partners (a) |
|
|
Distribution (b) |
|
Energy
Services |
|
|
Other and
Eliminations |
|
|
Total |
|
| |
|
(Thousands of dollars) |
|
|
Sales to unaffiliated customers |
|
$ |
2,032,345 |
|
|
$ |
270,719 |
|
|
$ |
1,935,414 |
|
|
$ |
768 |
|
|
$ |
4,239,246 |
|
|
Intersegment revenues |
|
|
208,762 |
|
|
|
2 |
|
|
|
103,033 |
|
|
|
(311,797 |
) |
|
|
- |
|
|
Total revenues |
|
$ |
2,241,107 |
|
|
$ |
270,721 |
|
|
$ |
2,038,447 |
|
|
$ |
(311,029 |
) |
|
$ |
4,239,246 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net margin |
|
$ |
325,400 |
|
|
$ |
123,929 |
|
|
$ |
4,819 |
|
|
$ |
878 |
|
|
$ |
455,026 |
|
|
Operating costs |
|
|
97,488 |
|
|
|
97,558 |
|
|
|
9,465 |
|
|
|
(603 |
) |
|
|
203,908 |
|
|
Depreciation and amortization |
|
|
30,408 |
|
|
|
29,271 |
|
|
|
178 |
|
|
|
392 |
|
|
|
60,249 |
|
|
Gain (loss) on sale of assets |
|
|
22 |
|
|
|
(3 |
) |
|
|
1,288 |
|
|
|
3 |
|
|
|
1,310 |
|
|
Operating income (loss) |
|
$ |
197,526 |
|
|
$ |
(2,903 |
) |
|
$ |
(3,536 |
) |
|
$ |
1,092 |
|
|
$ |
192,179 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity earnings from investments |
|
$ |
29,412 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
29,412 |
|
|
Capital expenditures |
|
$ |
335,580 |
|
|
$ |
56,052 |
|
|
$ |
- |
|
|
$ |
1,383 |
|
|
$ |
393,015 |
|
|
(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment’s regulated operations had revenues of $104.8 million, net margin of $82.1 million and operating income of $36.9 million. |
|
|
(b) - All of our Distribution segment’s operations are regulated. |
|
|
Nine Months Ended
September 30, 2009 |
|
ONEOK
Partners (a) |
|
|
Distribution (b) |
|
Energy
Services |
|
|
Other and
Eliminations |
|
|
Total |
|
| |
|
(Thousands of dollars) |
|
|
Sales to unaffiliated customers |
|
$ |
3,839,638 |
|
|
$ |
1,245,209 |
|
|
$ |
2,295,087 |
|
|
$ |
2,256 |
|
|
$ |
7,382,190 |
|
|
Intersegment revenues |
|
|
368,287 |
|
|
|
5 |
|
|
|
273,080 |
|
|
|
(641,372 |
) |
|
|
- |
|
|
Total revenues |
|
$ |
4,207,925 |
|
|
$ |
1,245,214 |
|
|
$ |
2,568,167 |
|
|
$ |
(639,116 |
) |
|
$ |
7,382,190 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net margin |
|
$ |
808,402 |
|
|
$ |
502,601 |
|
|
$ |
122,431 |
|
|
$ |
2,257 |
|
|
$ |
1,435,691 |
|
|
Operating costs |
|
|
295,061 |
|
|
|
280,520 |
|
|
|
26,407 |
|
|
|
(329 |
) |
|
|
601,659 |
|
|
Depreciation and amortization |
|
|
121,750 |
|
|
|
92,240 |
|
|
|
445 |
|
|
|
1,258 |
|
|
|
215,693 |
|
|
Gain (loss) on sale of assets |
|
|
2,760 |
|
|
|
486 |
|
|
|
- |
|
|
|
- |
|
|
|
3,246 |
|
|
Operating income |
|
$ |
394,351 |
|
|
$ |
130,327 |
|
|
$ |
95,579 |
|
|
$ |
1,328 |
|
|
$ |
621,585 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity earnings from investments |
|
$ |
55,464 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
55,464 |
|
|
Investments in unconsolidated
affiliates |
|
$ |
774,347 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
774,347 |
|
|
Total assets |
|
$ |
7,617,044 |
|
|
$ |
2,696,924 |
|
|
$ |
899,812 |
|
|
$ |
815,690 |
|
|
$ |
12,029,470 |
|
|
Noncontrolling interests in
consolidated subsidiaries |
|
$ |
5,585 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
1,254,575 |
|
|
$ |
1,260,160 |
|
|
Capital expenditures |
|
$ |
491,256 |
|
|
$ |
110,887 |
|
|
$ |
- |
|
|
$ |
12,614 |
|
|
$ |
614,757 |
|
|
(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment’s regulated operations had revenues of $382.3 million, net margin of $303.6 million and operating income of $140.8 million. |
|
|
(b) - All of our Distribution segment’s operations are regulated. |
|
|
Nine Months Ended
September 30, 2008 |
|
ONEOK
Partners (a) |
|
|
Distribution (b) |
|
Energy
Services |
|
|
Other and
Eliminations |
|
|
Total |
|
| |
|
(Thousands of dollars) |
|
|
Sales to unaffiliated customers |
|
$ |
5,847,615 |
|
|
$ |
1,558,495 |
|
|
$ |
5,905,638 |
|
|
$ |
2,440 |
|
|
$ |
13,314,188 |
|
|
Intersegment revenues |
|
|
596,419 |
|
|
|
6 |
|
|
|
502,276 |
|
|
|
(1,098,701 |
) |
|
|
- |
|
|
Total revenues |
|
$ |
6,444,034 |
|
|
$ |
1,558,501 |
|
|
$ |
6,407,914 |
|
|
$ |
(1,096,261 |
) |
|
$ |
13,314,188 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net margin |
|
$ |
874,858 |
|
|
$ |
490,610 |
|
|
$ |
93,857 |
|
|
$ |
2,441 |
|
|
$ |
1,461,766 |
|
|
Operating costs |
|
|
272,728 |
|
|
|
285,623 |
|
|
|
27,987 |
|
|
|
(996 |
) |
|
|
585,342 |
|
|
Depreciation and amortization |
|
|
90,383 |
|
|
|
87,295 |
|
|
|
754 |
|
|
|
997 |
|
|
|
179,429 |
|
|
Gain (loss) on sale of assets |
|
|
50 |
|
|
|
(21 |
) |
|
|
1,288 |
|
|
|
2 |
|
|
|
1,319 |
|
|
Operating income |
|
$ |
511,797 |
|
|
$ |
117,671 |
|
|
$ |
66,404 |
|
|
$ |
2,442 |
|
|
$ |
698,314 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity earnings from investments |
|
$ |
74,805 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
74,805 |
|
|
Investments in unconsolidated
affiliates |
|
$ |
756,449 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
756,449 |
|
|
Total assets |
|
$ |
6,992,295 |
|
|
$ |
2,934,614 |
|
|
$ |
1,786,002 |
|
|
$ |
509,152 |
|
|
$ |
12,222,063 |
|
|
Noncontrolling interests in
consolidated subsidiaries |
|
$ |
5,947 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
1,052,895 |
|
|
$ |
1,058,842 |
|
|
Capital expenditures |
|
$ |
860,167 |
|
|
$ |
126,407 |
|
|
$ |
15 |
|
|
$ |
46,474 |
|
|
$ |
1,033,063 |
|
|
(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment’s regulated operations had revenues of $325.8 million, net margin of $241.8 million and operating income of $110.5 million. |
|
|
(b) - All of our Distribution segment’s operations are regulated. |
|
L. UNCONSOLIDATED AFFILIATES
Equity Earnings from Investments - The following table sets forth our equity earnings from investments for the periods indicated. All amounts in the table below are equity earnings from investments in our ONEOK Partners segment:
| |
|
Three Months Ended |
|
|
Nine Months Ended |
|
| |
|
September 30, |
|
|
September 30, |
|
| |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
| |
|
(Thousands of dollars) |
|
|
Northern Border Pipeline |
|
$ |
10,882 |
|
|
$ |
20,090 |
|
|
$ |
32,374 |
|
|
$ |
48,752 |
|
|
Fort Union Gas Gathering, L.L.C. |
|
|
4,397 |
|
|
|
4,033 |
|
|
|
10,412 |
|
|
|
9,792 |
|
|
Bighorn Gas Gathering, L.L.C. |
|
|
1,935 |
|
|
|
2,044 |
|
|
|
5,845 |
|
|
|
6,367 |
|
|
Lost Creek Gathering Company, L.L.C. |
|
|
1,445 |
|
|
|
1,345 |
|
|
|
3,647 |
|
|
|
4,427 |
|
|
Other |
|
|
1,395 |
|
|
|
1,900 |
|
|
|
3,186 |
|
|
|
5,467 |
|
|
Equity earnings from investments |
|
$ |
20,054 |
|
|
$ |
29,412 |
|
|
$ |
55,464 |
|
|
$ |
74,805 |
|
Unconsolidated Affiliates Financial Information - The following table sets forth summarized combined financial information of our unconsolidated affiliates for the periods indicated:
| |
|
Three Months Ended |
|
|
Nine Months Ended |
|
| |
|
September 30, |
|
|
September 30, |
|
| |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
| |
|
(Thousands of dollars) |
|
|
Income Statement |
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues |
|
$ |
101,987 |
|
|
$ |
98,298 |
|
|
$ |
296,004 |
|
|
$ |
304,733 |
|
|
Operating expenses |
|
$ |
49,312 |
|
|
$ |
44,382 |
|
|
$ |
138,544 |
|
|
$ |
132,927 |
|
|
Net income |
|
$ |
42,929 |
|
|
$ |
64,217 |
|
|
$ |
125,574 |
|
|
$ |
153,965 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions paid to us |
|
$ |
19,615 |
|
|
$ |
30,466 |
|
|
$ |
83,088 |
|
|
$ |
91,093 |
|
M. EARNINGS PER SHARE INFORMATION
The following tables set forth the computations of basic and diluted EPS from continuing operations for the periods indicated:
| |
Three Months Ended September 30, 2009 |
| |
|
|
|
|
|
|
Per Share |
| |
|
Income |
|
|
Shares |
|
Amount |
| |
(Thousands, except per share amounts) |
|
Basic EPS from continuing operations |
|
|
|
|
|
|
|
|
|
|
Net income attributable to ONEOK available for common stock |
|
$ |
48,042 |
|
|
|
105,420 |
|
|
$ |
0.46 |
|
|
Diluted EPS from continuing operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of options and other dilutive securities |
|
|
- |
|
|
|
1,068 |
|
|
|
|
|
|
Net income attributable to ONEOK available for common stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
and common stock equivalents |
|
$ |
48,042 |
|
|
|
106,488 |
|
|
$ |
0.45 |
|
| |
Three Months Ended September 30, 2008 |
| |
|
|
|
|
|
|
Per Share |
| |
|
Income |
|
|
Shares |
|
Amount |
| |
(Thousands, except per share amounts) |
|
Basic EPS from continuing operations |
|
|
|
|
|
|
|
|
|
|
Net income attributable to ONEOK available for common stock |
|
$ |
58,033 |
|
|
|
104,446 |
|
|
$ |
0.56 |
|
|
Diluted EPS from continuing operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of options and other dilutive securities |
|
|
- |
|
|
|
1,190 |
|
|
|
|
|
|
Net income attributable to ONEOK available for common stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
and common stock equivalents |
|
$ |
58,033 |
|
|
|
105,636 |
|
|
$ |
0.55 |
|
| |
Nine Months Ended September 30, 2009 |
| |
|
|
|
|
|
|
Per Share |
| |
|
Income |
|
|
Shares |
|
Amount |
| |
(Thousands, except per share amounts) |
|
Basic EPS from continuing operations |
|
|
|
|
|
|
|
|
|
|
Net income attributable to ONEOK available for common stock |
|
$ |
212,006 |
|
|
|
105,306 |
|
|
$ |
2.01 |
|
|
Diluted EPS from continuing operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of options and other dilutive securities |
|
|
- |
|
|
|
755 |
|
|
|
|
|
|
Net income attributable to ONEOK available for common stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
and common stock equivalents |
|
$ |
212,006 |
|
|
|
106,061 |
|
|
$ |
2.00 |
|
| |
Nine Months Ended September 30, 2008 |
| |
|
|
|
|
|
|
Per Share |
| |
|
Income |
|
|
Shares |
|
Amount |
| |
(Thousands, except per share amounts) |
|
Basic EPS from continuing operations |
|
|
|
|
|
|
|
|
|
|
Net income attributable to ONEOK available for common stock |
|
$ |
243,735 |
|
|
|
104,319 |
|
|
$ |
2.34 |
|
|
Diluted EPS from continuing operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of options and other dilutive securities |
|
|
- |
|
|
|
1,524 |
|
|
|
|
|
|
Net income attributable to ONEOK available for common stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
and common stock equivalents |
|
$ |
243,735 |
|
|
|
105,843 |
|
|
$ |
2.30 |
|
There were 231,453 and 251,574 option shares excluded from the calculation of diluted EPS for the three and nine months ended September 30, 2009, respectively, since their inclusion would have been anti-dilutive. There were 13,746 and 4,582 anti-dilutive option shares for the three and nine months ended September 30, 2008.
N. ONEOK PARTNERS
Ownership Interest in ONEOK Partners - Our ownership interest in ONEOK Partners is shown in the following table for the periods indicated.
| |
|
September 30, |
|
December 31, |
|
| |
|
2009 |
|
2008 |
|
|
General partner interest |
|
2.0% |
|
|
2.0% |
|
|
|
Limited partner interest |
|
43.1% |
(a) |
|
45.7% |
(a) |
|
|
Total ownership interest |
|
45.1% |
|
|
47.7% |
|
|
|
(a) - Represents 5.9 million common units and approximately 36.5 million Class B units, which are convertible, at our option, into common units. |
|
In June 2009, ONEOK Partners completed an underwritten public offering of 5,000,000 common units at $45.81 per common unit, generating net proceeds of approximately $219.9 million after deducting underwriting discounts but before offering expenses.
In July 2009, ONEOK Partners sold an additional 486,690 common units at $45.81 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 $21.4 million from the sale of the
common units after deducting underwriting discounts but before offering expenses.
In conjunction with the public offering and partial exercise by the underwriters of their overallotment option, ONEOK Partners GP contributed an aggregate of $5.1 million to ONEOK Partners in order to maintain its 2 percent general partner interest.
Cash Distributions - The following table sets forth ONEOK Partners’ general partner and incentive distributions declared for the periods indicated:
| |
|
Three Months Ended |
|
|
Nine Months Ended |
|
| |
|
September 30, |
|
|
September 30, |
|
| |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
| |
(Thousands of dollars) |
|
General partner distributions |
|
$ |
2,603 |
|
|
$ |
2,419 |
|
|
$ |
7,586 |
|
|
$ |
7,038 |
|
|
Incentive distributions |
|
|
22,471 |
|
|
|
20,320 |
|
|
|
64,337 |
|
|
|
55,722 |
|
|
Total distributions to general partner |
|
$ |
25,074 |
|
|
$ |
22,739 |
|
|
$ |
71,923 |
|
|
$ |
62,760 |
|
The quarterly distributions paid by ONEOK Partners to limited partners in each of the first, second and third quarters of 2009 were $1.08 per unit. The quarterly distributions paid by ONEOK Partners to limited partners in the first, second and third quarters of 2008 were $1.025 per unit, $1.04 per unit and $1.06 per unit, respectively. In
October 2009, ONEOK Partners declared a third-quarter 2009 cash distribution of $1.09 per unit, payable in the fourth quarter.
For the three months ended September 30, 2009 and 2008, cash distributions paid by ONEOK Partners to us totaled $69.9 million and $65.9 million, respectively. For the nine months ended September 30, 2009 and 2008, cash distributions paid by ONEOK Partners to us totaled $206.9 million and $183.1 million, respectively.
Relationship - We consolidate ONEOK Partners in our consolidated financial statements; however, we are restricted from the assets and cash flows of ONEOK Partners except for our distributions. Distributions are declared quarterly by ONEOK Partners’ general partner based
on the terms of the ONEOK Partners partnership agreement. See Note K 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 portion of ONEOK Partners’ revenues from its natural gas pipelines business is from our Energy Services and Distribution segments, which utilize ONEOK Partners’ natural gas transportation
and storage services. ONEOK Partners also purchases natural gas from our Energy Services segment for its natural gas liquids and natural gas gathering and processing operations.
ONEOK Partners has certain contractual rights to our Bushton Plant 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 our wholly owned subsidiary,
OBPI. In exchange, ONEOK Partners pays OBPI for all 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 financial services, 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 are 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 service 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 by the modified Distrigas method, a method using a combination of ratios that include gross plant and investment, earnings before interest and taxes and payroll expense. It
is not practicable to determine what these general overhead costs would be on a stand-alone basis.
The following table sets forth transactions with ONEOK Partners for the periods indicated:
| |
|
Three Months Ended |
|
|
Nine Months Ended |
|
| |
|
September 30, |
|
|
September 30, |
|
| |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
| |
(Thousands of dollars) |
|
Revenues |
|
$ |
116,582 |
|
|
$ |
208,762 |
|
|
$ |
368,287 |
|
|
$ |
596,419 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of sales and fuel |
|
$ |
10,267 |
|
|
$ |
34,338 |
|
|
$ |
36,321 |
|
|
$ |
94,398 |
|
|
Administrative and general expenses |
|
|
43,800 |
|
|
|
53,154 |
|
|
|
142,278 |
|
|
|
143,387 |
|
|
Total expenses |
|
$ |
54,067 |
|
|
$ |
87,492 |
|
|
$ |
178,599 |
|
|
$ |
237,785 |
|
|
|
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
The following discussion and analysis should be read in conjunction with our unaudited consolidated financial statements and the Notes to Consolidated Financial Statements in this Quarterly Report, as well as our Annual Report. Due to the seasonal nature of our business, the results of operations for the three and nine months ended
September 30, 2009, are not necessarily indicative of the results that may be expected for a 12-month period.
EXECUTIVE SUMMARY
The following discussion highlights some of our achievements and significant issues affecting us for the periods presented. Please refer to the “Capital Projects,” “Financial Results and Operating Information,” and “Liquidity and Capital Resources” sections of Management’s Discussion and
Analysis of Financial Condition and Results of Operations and our consolidated financial statements for additional information:
Outlook - We expect improving economic conditions for the remainder of 2009 and into 2010, compared with the fourth quarter of 2008 and the first two quarters of 2009, when we began to experience reduced drilling activity, less supply growth and lower commodity prices for natural gas,
NGLs and crude oil. Although ONEOK has been able to access the commercial paper markets and ONEOK Partners has been able to access the debt and equity markets to meet the liquidity and capital resource needs of each in 2009, we expect continued volatility in the financial markets, which could limit our access to these markets or increase the cost of issuing new securities in the future.
Operating Results - Diluted earnings per share of common stock from continuing operations (EPS) were $0.45 and $0.55 for the three months ended September 30, 2009, and 2008, respectively. For the nine-month period, EPS decreased to $2.00 from $2.30 for the same period last
year. Operating income for the three months ended September 30, 2009, decreased to $173.8 million from $192.2 million for the same period last year. For the nine months ended September 30, 2009, operating income decreased to $621.6 million from $698.3 million for the same period last year. These decreases were due primarily to lower realized commodity prices and narrower NGL product price differentials in our ONEOK Partners segment and were partially offset by increased volumes
gathered, fractionated and transported, primarily associated with the completion of the Overland Pass Pipeline and related expansion projects and the Arbuckle Pipeline, as well as new NGL supply connections in our ONEOK Partners segment.
ONEOK Partners’ Equity Issuance - In June 2009, ONEOK Partners completed an underwritten public offering of 5,000,000 common units at $45.81 per common unit, generating net proceeds of approximately $219.9 million after deducting underwriting discounts but before offering expenses.
In July 2009, ONEOK Partners sold an additional 486,690 common units at $45.81 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 $21.4 million from the sale of the
common units after deducting underwriting discounts but before offering expenses.
In conjunction with the public offering and partial exercise by the underwriters of their overallotment option, ONEOK Partners GP contributed an aggregate of $5.1 million in order to maintain its 2 percent general partner interest. As a result of these transactions, our interest in ONEOK Partners is 45.1 percent.
ONEOK Partners used the proceeds from the sale of common units and the general partner contributions to repay borrowings under its $1.0 billion amended and restated revolving credit agreement dated March 30, 2007 (ONEOK Partners Credit Agreement) and for general partnership purposes.
ONEOK Partners’ Debt Issuance - In March 2009, ONEOK Partners completed an underwritten public offering of $500 million aggregate principal amount of 8.625 percent Senior Notes due 2019. After deducting underwriting discounts, commissions and expenses, ONEOK Partners
used the net proceeds of approximately $494.3 million from the offering to repay indebtedness outstanding under the ONEOK Partners Credit Agreement.
Dividends/Distributions - We declared a quarterly dividend of $0.42 per share ($1.68 per share on an annualized basis) in October 2009, an increase of approximately 5 percent from the $0.40 per share declared in October 2008. ONEOK Partners declared a cash distribution of $1.09
per unit ($4.36 per unit on an annualized basis) in October 2009, an increase of approximately 1 percent from the $1.08 per unit declared in October 2008.
Capital Projects - ONEOK Partners placed the following projects in service during the first ten months of 2009:
|
· |
Guardian Pipeline’s natural gas pipeline expansion and extension project; |
|
· |
D-J Basin lateral natural gas liquids pipeline; |
|
· |
Williston Basin natural gas processing plant expansion; |
|
· |
Arbuckle natural gas liquids pipeline; and |
|
· |
Piceance lateral natural gas liquids pipeline. |
CAPITAL PROJECTS
All of the capital projects discussed below are in our ONEOK Partners segment.
Overland Pass Pipeline - In November 2008, Overland Pass Pipeline Company completed 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 Overland Pass Pipeline is designed to
transport approximately 110 MBbl/d of unfractionated NGLs and can be increased to approximately 255 MBbl/d with additional pump facilities. At the end of the third quarter 2009, average flow rates on the Overland Pass Pipeline were approximately 99 MBbl/d. Overland Pass Pipeline Company is a joint venture between ONEOK Partners and a subsidiary of The Williams Companies, Inc. (Williams). A subsidiary of ONEOK Partners owns 99 percent of the joint venture and is currently operating
the pipeline. On or before November 17, 2010, Williams has the option to increase its ownership in Overland Pass Pipeline Company, which includes the Piceance Lateral and D-J Basin Lateral pipeline projects, up to 50 percent, 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. If Williams does
not elect to increase its ownership to at least 10 percent, ONEOK Partners will have the right, but not the obligation, to purchase Williams’ entire ownership interest, with the purchase price being determined in accordance with the joint venture’s operating agreement. The project costs for the Overland Pass Pipeline, the Piceance Lateral Pipeline and the DJ Basin Lateral Pipeline in total are expected to be approximately $780 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 70 MBbl/d to 80 MBbl/d, to the Overland Pass Pipeline. Subsidiaries of ONEOK Partners are providing downstream fractionation, storage and transportation services to Williams. ONEOK
Partners has also reached agreements with certain producers for supply commitments from the D-J Basin and Piceance Lateral pipelines. During the fourth quarter of 2009 and following the completion of the Piceance Lateral, throughput on the Overland Pass Pipeline is expected to reach 130 MBbl/d to 140 MBbl/d, and ONEOK Partners is negotiating agreements with other producers for supply commitments that could add an additional 60 MBbl/d of supply to this pipeline within the next three to five years.
ONEOK Partners also invested approximately $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’ Bushton, Kansas, location,
which increased the total fractionation capacity at the Bushton facility to 150 MBbl/d from 80 MBbl/d. The addition of the new facilities and the upgrade to the existing fractionator were completed in October 2008. Additionally, portions of the natural gas liquids distribution pipeline upgrades were completed in the second and third quarters of 2008.
Piceance Lateral Pipeline - In October 2008, Overland Pass Pipeline Company began construction of a 150-mile lateral pipeline with capacity to transport as much as 100 MBbl/d, from the Piceance Basin in Colorado to the Overland Pass Pipeline. Williams has dedicated its NGL
production from its new Willow Creek natural gas processing plant, and will dedicate NGL production from an additional existing natural gas processing plant. Another plant owned by a third party has also been dedicated. We expect the total throughput on the lateral pipeline to reach approximately 30 MBbl/d during the fourth quarter of 2009. ONEOK Partners continues to negotiate with other producers for supply commitments. Construction was completed and the lateral pipeline
was placed in service in October 2009. The project is currently estimated to cost in the range of $135 million to $140 million, excluding AFUDC.
D-J Basin Lateral Pipeline - In March 2009, Overland Pass Pipeline Company placed in service the 125-mile natural gas liquids lateral pipeline from the Denver-Julesburg Basin in northeastern Colorado to the Overland Pass Pipeline. The pipeline has capacity to transport as much
as 55 MBbl/d of unfractionated NGLs. The project cost was approximately $70 million, excluding AFUDC. Daily volumes reached approximately 30 MBbl/d during the third quarter of 2009, with the potential for an additional 10 MBbl/d from new drilling and plant upgrades in the next two years.
Arbuckle Natural Gas Liquids Pipeline - In July 2009, ONEOK Partners completed construction of the 440-mile Arbuckle pipeline project, a natural gas liquids pipeline system that delivers unfractionated NGLs from points in southern Oklahoma and Texas to the Texas Gulf Coast. The
Arbuckle pipeline system has the capacity to transport 160 MBbl/d of unfractionated NGLs, expandable to 240 MBbl/d with additional pump facilities, and connects ONEOK Partners’ existing Mid-Continent infrastructure with its fractionation facility in Mont Belvieu, Texas, and other Gulf Coast region fractionators. ONEOK Partners has NGL production dedicated from existing and new natural gas processing plants that it expects to provide throughput of approximately 210 MBbl/d over the next three to
five years.
The demand for surface easements increased dramatically in Texas and Oklahoma over the last two years because of increased oil and natural gas exploration and production activities, as well as pipeline construction. As previously reported, project costs have been more expensive than originally estimated due to delays associated
with right-of-way acquisition, increased materials costs and difficult construction conditions associated with several weeks of heavy spring rains, resulting in greatly reduced construction productivity. ONEOK Partners also experienced increased costs due to a number of scope changes, arising primarily from additional supply development opportunities. As previously discussed, ONEOK Partners currently estimates project costs will be approximately $490 million, excluding AFUDC, for the current
capacity. ONEOK Partners began filling the pipeline with product in July 2009 and placed the project in service in August 2009. Volumes reached 80 MBbl/d during the month of October 2009.
Williston Basin Gas Processing Plant Expansion - The expansion of ONEOK Partners’ Grasslands natural gas processing facility in North Dakota was placed in service in March 2009. The expansion increased processing capacity to approximately 100 MMcf/d from its previous capacity
of 63 MMcf/d and increased fractionation capacity to approximately 12 MBbl/d from 8 MBbl/d. The cost of the project was approximately $46 million, excluding AFUDC.
Guardian Pipeline Expansion and Extension - In February 2009, ONEOK Partners completed the 119-mile extension of its Guardian Pipeline. The pipeline has capacity to transport 537 MMcf/d of natural gas north from Ixonia, Wisconsin, to the Green Bay, Wisconsin, area. The
project is supported by 15-year shipper commitments with We Energies and Wisconsin Public Service Corporation, and the capacity is close to fully subscribed. The project cost approximately $325 million, excluding AFUDC.
REGULATORY
Several regulatory initiatives impacted the earnings and future earnings potential for our Distribution segment. See discussion of our Distribution segment’s regulatory initiatives on page 44.
IMPACT OF NEW ACCOUNTING STANDARDS
Information about the impact of new accounting standards is included in Note A of the Notes to Consolidated Financial Statements in this Quarterly Report.
CRITICAL ACCOUNTING 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 revenues and expenses during the reporting period. Although we believe these estimates and assumptions are reasonable, actual results could differ from our estimates.
Information about our critical accounting estimates is included under Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Critical Accounting Estimates,” in our Annual Report.
Goodwill and Indefinite-lived Intangible Assets Impairment Test - We assess our goodwill and indefinite-lived intangible assets for impairment at least annually. There were no impairment charges resulting from our July 1, 2009, impairment test.
As part of our goodwill impairment test, an initial assessment is made by comparing the fair value of a reporting unit with its book value, including goodwill. To estimate the fair value of our reporting units, we use two generally accepted valuation approaches, an income approach and a market approach. Under the income
approach, we use anticipated cash flows over a period of years 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 forecasted EBITDA for a reporting unit over a period of years.
As part of our indefinite-lived intangible asset impairment test, we compare the estimated fair value of our indefinite-lived intangible asset with its book value. The fair value of our indefinite-lived intangible asset is estimated using the market approach. Under the market approach, we apply multiples to forecasted
cash flows of the assets associated with our indefinite-lived intangible asset. The multiples used are consistent with historical asset transactions.
Our estimates of fair value significantly exceeded the book value of our reporting units and indefinite-lived intangible asset in our July 1, 2009, impairment test. Even if the estimated fair values used in our July 1, 2009, impairment test were reduced by 10 percent, no impairment charges would have resulted. At September
30, 2009, and December 31, 2008, we had $602.8 million of goodwill and a $155.6 million indefinite-lived intangible asset recorded on our Consolidated Balance Sheets.
Derivatives and Risk Management - We utilize financial instruments to reduce our market risk exposure to commodity price and interest rate risk. We do not believe that changes in our fair value estimates of our derivative instruments have a material impact on our results of
operations, as the majority of our derivatives are accounted for as hedges for which ineffectiveness is not material. See Notes B and C of the Notes to Consolidated Financial Statements in this Quarterly Report for additional discussion of our fair value measurements and derivatives and risk management activities.
FINANCIAL RESULTS AND OPERATING INFORMATION
Consolidated Operations
Selected Financial Results - The following table sets forth certain selected consolidated financial results for the periods indicated:
| |
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
Increase (Decrease) |
|
|
Increase (Decrease) |
|
| |
|
September 30, |
|
|
September 30, |
|
|
Three Months |
|
|
Nine Months |
|
|
Financial Results |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
2009 vs. 2008 |
|
|
2009 vs. 2008 |
|
| |
(Millions of dollars) |
|
|
Revenues |
|
$ |
2,364.7 |
|
|
$ |
4,239.2 |
|
|
$ |
7,382.1 |
|
|
$ |
13,314.2 |
|
|
$ |
(1,874.5 |
) |
|
|
(44 |
%) |
|
$ |
(5,932.1 |
) |
|
|
(45 |
%) |
|
Cost of sales and fuel |
|
|
1,912.9 |
|
|
|
3,784.2 |
|
|
|
5,946.5 |
|
|
|
11,852.4 |
|
|
|
(1,871.3 |
) |
|
|
(49 |
%) |
|
|
(5,905.9 |
) |
|
|
(50 |
%) |
|
Net margin |
|
|
451.8 |
|
|
|
455.0 |
|
|
|
1,435.6 |
|
|
|
1,461.8 |
|
|
|
(3.2 |
) |
|
|
(1 |
%) |
|
|
(26.2 |
) |
|
|
(2 |
%) |
|
Operating costs |
|
|
204.6 |
|
|
|
203.9 |
|
|
|
601.7 |
|
|
|
585.3 |
|
|
|
0.7 |
|
|
|
0 |
% |
|
|
16.4 |
|
|
|
3 |
% |
|
Depreciation and amortization |
|
|
72.3 |
|
|
|
60.2 |
|
|
|
215.7 |
|
|
|
179.4 |
|
|
|
12.1 |
|
|
|
20 |
% |
|
|
36.3 |
|
|
|
20 |
% |
|
Gain (loss) on sale of assets |
|
|
(1.1 |
) |
|
|
1.3 |
|
|
|
3.3 |
|
|
|
1.3 |
|
|
|
(2.4 |
) |
|
|
* |
|
|
|
2.0 |
|
|
|
* |
|
|
Operating income |
|
$ |
173.8 |
|
|
$ |
192.2 |
|
|
$ |
621.5 |
|
|
$ |
698.4 |
|
|
$ |
(18.4 |
) |
|
|
(10 |
%) |
|
$ |
(76.9 |
) |
|
|
(11 |
%) |
|
Equity earnings from investments |
|
$ |
20.1 |
|
|
$ |
29.4 |
|
|
$ |
55.5 |
|
|
$ |
74.8 |
|
|
$ |
(9.3 |
) |
|
|
(32 |
%) |
|
$ |
(19.3 |
) |
|
|
(26 |
%) |
|
Allowance for equity funds used
during construction |
|
$ |
7.3 |
|
|
$ |
15.6 |
|
|
$ |
25.8 |
|
|
$ |
35.8 |
|
|
$ |
(8.3 |
) |
|
|
(53 |
%) |
|
$ |
(10.0 |
) |
|
|
(28 |
%) |
|
Other income (expense) |
|
$ |
8.0 |
|
|
$ |
1.4 |
|
|
$ |
12.2 |
|
|
$ |
0.3 |
|
|
$ |
6.6 |
|
|
|
* |
|
|
$ |
11.9 |
|
|
|
* |
|
|
Interest expense |
|
$ |
(72.7 |
) |
|
$ |
(61.2 |
) |
|
$ |
(224.0 |
) |
|
$ |
(183.1 |
) |
|
$ |
11.5 |
|
|
|
19 |
% |
|
$ |
40.9 |
|
|
|
22 |
% |
|
Net income attributable to
noncontrolling interests |
|
$ |
54.3 |
|
|
$ |
95.4 |
|
|
$ |
135.2 |
|
|
$ |
235.4 |
|
|
$ |
(41.1 |
) |
|
|
(43 |
%) |
|
$ |
(100.2 |
) |
|
|
(43 |
%) |
|
Capital expenditures |
|
$ |
207.2 |
|
|
$ |
393.0 |
|
|
$ |
614.8 |
|
|
$ |
1,033.1 |
|
|
$ |
(185.8 |
) |
|
|
(47 |
%) |
|
$ |
(418.3 |
) |
|
|
(40 |
%) |
|
* Percentage change is greater than 100 percent. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net margin decreased for the three months ended September 30, 2009, compared with the same period last year, due primarily to the following:
|
· |
decreased net margin in our ONEOK Partners segment, due primarily to: |
|
- |
lower realized commodity prices and narrower NGL product price differentials; partially offset by |
|
- |
higher NGL volumes gathered, fractionated and transported, primarily associated with the completion of the Overland Pass Pipeline and related expansion projects, and the Arbuckle Pipeline, as well as new NGL supply connections; |
|
- |
higher natural gas volumes processed and sold in ONEOK Partners’ gathering and processing business; |
|
- |
higher natural gas transportation margins from the Guardian Pipeline expansion and extension that was completed in February 2009, and an increase in volumes contracted on Midwestern Gas Transmission in ONEOK Partners’ natural gas pipelines business; |
|
· |
increased margin in our Distribution segment, due primarily to the implementation of new rate mechanisms; and |
|
· |
increased margin in our Energy Services segment, due primarily to an increase in transportation margins, net of hedging activities. |
Net margin decreased for the nine months ended September 30, 2009, compared with the same period last year, due primarily to the following:
|
· |
decreased net margin in our ONEOK Partners segment, due primarily to: |
|
- |
lower realized commodity prices and narrower NGL product price differentials; partially offset by |
|
- |
higher NGL volumes gathered, fractionated, transported and marketed, primarily associated with the completion of, the Overland Pass Pipeline and related expansion projects, and the Arbuckle Pipeline, as well as new NGL supply connections; |
|
- |
higher natural gas transportation margins from the Guardian Pipeline expansion and extension that was completed in February 2009, and an increase in volumes contracted on Midwestern Gas Transmission in ONEOK Partners’ natural gas pipelines business; and |
|
- |
higher natural gas volumes processed and sold in our ONEOK Partners segment’s gathering and processing business; |
|
· |
increased margin in our Distribution segment, due primarily to the implementation of new rate mechanisms; and |
|
· |
increased margin in our Energy Services segment, due primarily to an increase in transportation margins, net of hedging activities, and an increase in premium services, partially offset by a decrease in storage and marketing margins, net of hedging activities. |
Operating costs increased for the three and nine months ended September 30, 2009, compared with the same periods last year, due primarily to higher operating costs resulting from the operation of the Overland Pass Pipeline and the Arbuckle Pipeline and increased costs at ONEOK Partners’ NGL fractionation facilities, which includes the
expanded Bushton Plant fractionator, and increased employee-related costs in our Distribution segment. These increases were slightly offset by lower bad-debt expense in our Distribution segment.
Depreciation and amortization expense increased for the three and nine months ended September 30, 2009, compared with the same periods last year, due primarily to higher depreciation expense associated with ONEOK Partners’ completed capital projects.
Equity earnings from investments decreased for the three and nine months ended September 30, 2009, compared with the same periods last year, due primarily to a gain on the sale of Bison Pipeline LLC by Northern Border Pipeline in the third quarter of 2008 and lower subscription volumes and rates on Northern Border Pipeline, of which ONEOK
Partners owns a 50 percent interest. Equity earnings from investments also decreased due to lower natural gas volumes gathered in ONEOK Partners’ various natural gas gathering and processing equity investments whose assets are primarily located in the Powder River Basin of Wyoming.
Allowance for equity funds used during construction decreased for the three and nine months ended September 30, 2009, compared with the same periods last year, due primarily to the completion of the Arbuckle Pipeline, the Overland Pass Pipeline and related expansion projects, and the Guardian Pipeline expansion and extension.
Interest expense increased for the three and nine months ended September 30, 2009, compared with the same periods last year, due primarily to ONEOK Partners’ March 2009 debt issuance and a decrease in capitalized interest due to the completion of ONEOK Partners’ capital projects.
Net income attributable to noncontrolling interests for the three and nine months ended September 30, 2009 and 2008, primarily reflects the remaining 54.9 percent and 52.3 percent, respectively, of ONEOK Partners that we do not own. The decrease in net income attributable to noncontrolling interests is due to the decreased income
of our ONEOK Partners segment.
Capital expenditures decreased for the three and nine months ended September 30, 2009, compared with the same periods last year, due to the completion of the Arbuckle Pipeline, the Overland Pass Pipeline and related expansion projects, the Williston Basin gas processing plant expansion and the Guardian Pipeline expansion and extension in our
ONEOK Partners segment.
Additional information regarding our financial results and operating information is provided in the following discussion for each of our segments:
ONEOK Partners
Overview - We currently own a 45.1 percent equity interest in ONEOK Partners. The remaining interest in ONEOK Partners is reflected as net income attributable to noncontrolling interests on our Consolidated Statements of Income and in noncontrolling interests in consolidated
subsidiaries on our Consolidated Balance Sheets. See Note N of the Notes to Consolidated Financial Statements in this Quarterly Report for additional information on the ONEOK Partners’ equity issuance and related transactions.
Our ONEOK Partners segment is engaged in the gathering and processing of unprocessed natural gas and fractionation of NGLs, primarily in the Mid-Continent and Rocky Mountain regions and the Williston Basin, covering 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. In portions of the
Rocky Mountain region, the natural gas that ONEOK Partners gathers is coal bed methane, or dry gas, that does not require processing in order to be marketable; dry gas is gathered, compressed and delivered into a pipeline for a fee.
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’ FERC-regulated distribution pipelines that move NGL products from Oklahoma and Kansas to the 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 also provides natural gas transportation and storage services in accordance with Section 311(a) of the Natural Gas Policy Act. ONEOK
Partners’ interstate assets transport natural gas through FERC-regulated interstate natural gas pipelines that access supply from Canada and from the Mid-Continent, Rocky Mountain and Gulf Coast regions. ONEOK Partners’ intrastate natural gas pipeline assets are located in Oklahoma, Texas and Kansas, and have access to major natural gas producing areas in those states. ONEOK Partners owns underground natural gas storage facilities in Oklahoma, Kansas and Texas.
Selected Financial Results and Operating Information - The following table sets forth certain selected financial results for our ONEOK Partners segment for the periods indicated:
| |
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
Increase (Decrease) |
|
|
Increase (Decrease) |
|
| |
|
September 30, |
|
|
September 30, |
|
|
Three Months |
|
|
Nine Months |
|
|
Financial Results |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
2009 vs. 2008 |
|
|
2009 vs. 2008 |
|
| |
(Millions of dollars) |
|
|
Revenues |
|
$ |
1,560.0 |
|
|
$ |
2,241.1 |
|
|
$ |
4,207.9 |
|
|
$ |
6,444.0 |
|
|
$ |
(681.1 |
) |
|
|
(30 |
%) |
|
$ |
(2,236.1 |
) |
|
|
(35 |
%) |
|
Cost of sales and fuel |
|
|
1,267.1 |
|
|
|
1,915.7 |
|
|
|
3,399.5 |
|
|
|
5,569.1 |
|
|
|
(648.6 |
) |
|
|
(34 |
%) |
|
|
(2,169.6 |
) |
|
|
(39 |
%) |
|
Net margin |
|
|
292.9 |
|
|
|
325.4 |
|
|
|
808.4 |
|
|
|
874.9 |
|
|
|
(32.5 |
) |
|
|
(10 |
%) |
|
|
(66.5 |
) |
|
|
(8 |
%) |
|
Operating costs |
|
|
105.1 |
|
|
|
97.5 |
|
|
|
295.0 |
|
|
|
272.7 |
|
|
|
7.6 |
|
|
|
8 |
% |
|
|
22.3 |
|
|
|
8 |
% |
|
Depreciation and amortization |
|
|
41.9 |
|
|
|
30.4 |
|
|
|
121.8 |
|
|
|
90.4 |
|
|
|
11.5 |
|
|
|
38 |
% |
|
|
31.4 |
|
|
|
35 |
% |
|
Gain (loss) on sale of assets |
|
|
(1.2 |
) |
|
|
- |
|
|
|
2.8 |
|
|
|
- |
|
|
|
(1.2 |
) |
|
|
(100 |
%) |
|
|
2.8 |
|
|
|
100 |
% |
|
Operating income |
|
$ |
144.7 |
|
|
$ |
197.5 |
|
|
$ |
394.4 |
|
|
$ |
511.8 |
|
|
$ |
(52.8 |
) |
|
|
(27 |
%) |
|
$ |
(117.4 |
) |
|
|
(23 |
%) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity earnings from investments |
|
$ |
20.1 |
|
|
$ |
29.4 |
|
|
$ |
55.5 |
|
|
$ |
74.8 |
|
|
$ |
(9.3 |
) |
|
|
(32 |
%) |
|
$ |
(19.3 |
) |
|
|
(26 |
%) |
|
Allowance for equity funds used
during construction |
|
$ |
7.3 |
|
|
$ |
15.6 |
|
|
$ |
25.8 |
|
|
$ |
35.8 |
|
|
$ |
(8.3 |
) |
|
|
(53 |
%) |
|
$ |
(10.0 |
) |
|
|
(28 |
%) |
|
Capital expenditures |
|
$ |
169.4 |
|
|
$ |
335.6 |
|
|
$ |
491.3 |
|
|
$ |
860.2 |
|
|
$ |
(166.2 |
) |
|
|
(50 |
%) |
|
$ |
(368.9 |
) |
|
|
(43 |
%) |
Net margin decreased for the three months ended September 30, 2009, compared with the same period last year, primarily due to the following:
|
· |
a decrease of $33.7 million due to lower realized commodity prices in ONEOK Partners’ natural gas gathering and processing business; |
|
· |
a decrease of $28.0 million due to narrower NGL product price differentials, partially offset by increased volumes marketed in ONEOK Partners’ natural gas liquids business; and |
|
· |
a decrease of $11.6 million due to prior-year operational measurement gains, primarily at NGL storage caverns; partially offset by |
|
· |
an increase of $18.2 million due to increased NGL volumes gathered, fractionated and transported, primarily associated with the completion of the Overland Pass Pipeline and related expansion projects, the Arbuckle Pipeline, and new supply connections in ONEOK Partners’ natural gas liquids business; |
|
· |
an increase of $11.4 million due to higher natural gas volumes processed and sold in ONEOK Partners’ natural gas gathering and processing business; and |
|
· |
an increase of $10.1 million due to higher natural gas transportation margins from the Guardian Pipeline expansion and extension that was completed in February 2009, and an increase in volumes contracted on Midwestern Gas Transmission in ONEOK Partners’ natural gas pipelines business. |
Net margin decreased for the nine months ended September 30, 2009, compared with the same period last year, primarily due to the following:
|
· |
a decrease of $95.1 million due to significantly lower realized commodity prices in ONEOK Partners’ natural gas gathering and processing business; |
|
· |
a decrease of $38.4 million due to narrower NGL product price differentials, partially offset by increased volumes marketed in ONEOK Partners’ natural gas liquids business; and |
|
· |
a decrease of $12.5 million due to prior-year operational measurement gains, primarily at NGL storage caverns; partially offset by |
|
· |
an increase of $46.2 million due to increased NGL volumes gathered, fractionated and transported, primarily associated with the completion of the Overland Pass Pipeline and related expansion projects, the Arbuckle Pipeline, and new supply connections in ONEOK Partners’ natural gas liquids business; |
|
· |
an increase of $23.3 million due to higher natural gas transportation margins from the Guardian Pipeline expansion and extension that was completed in February 2009, and an increase in volumes contracted on Midwestern Gas Transmission in ONEOK Partners’ natural gas pipelines business; and |
|
· |
an increase of $20.1 million due to higher natural gas volumes processed and sold in ONEOK Partners’ natural gas gathering and processing business. |
Operating costs increased for the three and nine months ended September 30, 2009, compared with the same periods last year, due primarily to higher operating costs resulting from the operation of the Overland Pass Pipeline and the Arbuckle
Pipeline and increased costs at ONEOK Partners’ fractionation facilities, which includes the expanded Bushton Plant fractionator.
Depreciation and amortization expense increased for the three and nine months ended September 30, 2009, compared with the same periods last year, due primarily to higher depreciation expense associated with ONEOK Partners’ completed capital projects.
Equity earnings from investments decreased for the three and nine months ended September 30, 2009, compared with the same periods last year, due primarily to a gain on the sale of Bison Pipeline LLC by Northern Border Pipeline in the third quarter of 2008 and due to lower subscription volumes and rates on Northern Border Pipeline. Equity
earnings from investments also decreased due to lower natural gas volumes gathered in ONEOK Partners’ various natural gas gathering and processing equity investments whose assets are primarily located in the Powder River Basin of Wyoming.
Allowance for equity funds used during construction decreased for the three and nine months ended September 30, 2009, compared with the same periods last year, due primarily to the completion of the Arbuckle Pipeline, the Overland Pass Pipeline and related expansion projects, and the Guardian Pipeline expansion and extension.
Capital expenditures decreased for the three and nine months ended September 30, 2009, compared with the same periods last year, due primarily to the completion of the Arbuckle Pipeline, the Overland Pass Pipeline and related expansion projects, the Williston Basin gas processing plant expansion and the Guardian Pipeline expansion and extension.
Selected Operating Information - The following table sets forth selected operating information for our ONEOK Partners segment for the periods indicated:
| |
|
Three Months Ended |
|
|
Nine Months Ended |
|
| |
|
September 30, |
|
|
September 30, |
|
|
Operating Information |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
Natural gas gathered (BBtu/d) (a) |
|
|
1,100 |
|
|
|
1,146 |
|
|
|
1,131 |
|
|
|
1,174 |
|
|
Natural gas processed (BBtu/d) (a) |
|
|
664 |
|
|
|
649 |
|
|
|
658 |
|
|
|
641 |
|
|
Natural gas transportation capacity contracted (MMcf/d) |
|
|
5,764 |
|
|
|
4,765 |
|
|
|
5,461 |
|
|
|
4,877 |
|
|
Transportation capacity subscribed |
|
|
87 |
% |
|
|
81 |
% |
|
|
83 |
% |
|
|
83 |
% |
|
Residue gas sales (BBtu/d) (a) |
|
|
297 |
|
|
|
281 |
|
|
|
291 |
|
|
|
280 |
|
|
NGL sales (MBbl/d) |
|
|
382 |
|
|
|
273 |
|
|
|
388 |
|
|
|
275 |
|
|
NGLs fractionated (MBbl/d) |
|
|
496 |
|
|
|
375 |
|
|
|
458 |
|
|
|
379 |
|
|
NGLs transported-gathering lines (MBbl/d) |
|
|
385 |
|
|
|
253 |
|
|
|
358 |
|
|
|
255 |
|
|
NGLs transported-distribution lines (MBbl/d) |
|
|
446 |
|
|
|
430 |
|
|
|
451 |
|
|
|
347 |
|
|
Conway-to-Mont Belvieu OPIS average price differential |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ethane ($/gallon) |
|
$ |
0.15 |
|
|
$ |
0.24 |
|
|
$ |
0.12 |
|
|
$ |
0.15 |
|
|
Realized composite NGL sales prices ($/gallon) (a) |
|
$ |
0.76 |
|
|
$ |
1.51 |
|
|
$ |
0.70 |
|
|
$ |
1.44 |
|
|
Realized condensate sales price ($/Bbl) (a) |
|
$ |
79.46 |
|
|
$ |
99.61 |
|
|
$ |
70.66 |
|
|
$ |
96.91 |
|
|
Realized residue gas sales price ($/MMBtu) (a) |
|
$ |
2.99 |
|
|
$ |
8.33 |
|
|
$ |
3.11 |
|
|
$ |
8.39 |
|
|
Realized gross processing spread ($/MMBtu) (a) |
|
$ |
6.54 |
|
|
$ |
6.69 |
|
|
$ |
6.41 |
|
|
$ |
6.94 |
|
|
(a) - Statistics relate to ONEOK Partners’ natural gas gathering and processing business. |
|
|
|
|
|
|
|
|
|
Commodity Price Risk - The following tables set forth ONEOK Partners’ hedging information for the remainder of 2009 and for the year ending December 31, 2010, as of November 3, 2009.
| |
|
Three Months Ending |
| |
|
December 31, 2009 |
| |
|
Volumes Hedged |
Average Price |
Percentage Hedged |
|
NGLs (Bbl/d) (a) |
7,857 |
|
$1.04 |
/ gallon |
87% |
|
Condensate (Bbl/d) (a) |
2,064 |
|
$2.08 |
/ gallon |
91% |
|
Total (Bbl/d) |
9,921 |
|
$1.26 |
/ gallon |
88% |
|
Natural gas (MMBtu/d) |
17,009 |
|
$4.25 |
/ MMBtu |
88% |
|
(a) - Hedged with fixed-price swaps. |
|
|
|
|
|
|
| |
|
Year Ending |
| |
|
December 31, 2010 |
| |
|
Volumes Hedged |
Average Price |
Percentage Hedged |
|
NGLs (Bbl/d) (a) |
3,881 |
|
$1.19 |
/ gallon |
55% |
|
Condensate (Bbl/d) (a) |
1,696 |
|
$1.79 |
/ gallon |
75% |
|
Total (Bbl/d) |
5,577 |
|
$1.38 |
/ gallon |
60% |
|
Natural gas (MMBtu/d) |
25,225 |
|
$5.55 |
/ MMBtu |
75% |
|
(a) - Hedged with fixed-price swaps. |
|
|
|
|
|
|
See Note C of the Notes to Consolidated Financial Statements in this Quarterly Report for more information on our hedging activities.
Commodity price risks related to estimated physical sales of commodities for ONEOK Partners’ natural gas gathering and processing business are estimated as a hypothetical change in the price of NGLs, crude oil and natural gas at September 30, 2009. ONEOK Partners estimates the following for its natural gas gathering and processing
business:
|
· |
a $0.01 per gallon decrease in the composite price of NGLs would decrease annual net margin by approximately $1.1 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 $1.1 million. |
The above estimates of commodity price risk exclude the effects of hedging and assume normal operating conditions. Further, these estimates do not include any effects on demand for ONEOK Partners’ services or processing plant operations 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 extracted from the natural gas stream, affecting gathering and processing margins.
Distribution
Overview - 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.
Selected Financial Results - The following table sets forth certain selected financial results for our Distribution segment for the periods indicated:
| |
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
Increase (Decrease) |
|
|
Increase (Decrease) |
|
| |
|
September 30, |
|
|
September 30, |
|
|
Three Months |
|
|
Nine Months |
|
|
Financial Results |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
2009 vs. 2008 |
|
|
2009 vs. 2008 |
|
| |
(Millions of dollars) |
|
|
Gas sales |
|
$ |
186.0 |
|
|
$ |
242.8 |
|
|
$ |
1,147.8 |
|
|
$ |
1,463.7 |
|
|
$ |
(56.8 |
) |
|
|
(23 |
%) |
|
$ |
(315.9 |
) |
|
|
(22 |
%) |
|
Transportation revenues |
|
|
17.8 |
|
|
|
18.1 |
|
|
|
63.6 |
|
|
|
64.2 |
|
|
|
(0.3 |
) |
|
|
(2 |
%) |
|
|
(0.6 |
) |
|
|
(1 |
%) |
|
Cost of gas |
|
|
85.8 |
|
|
|
146.8 |
|
|
|
742.6 |
|
|
|
1,067.9 |
|
|
|
(61.0 |
) |
|
|
(42 |
%) |
|
|
(325.3 |
) |
|
|
(30 |
%) |
|
Net margin, excluding other revenues |
|
|
118.0 |
|
|
|
114.1 |
|
|
|
468.8 |
|
|
|
460.0 |
|
|
|
3.9 |
|
|
|
3 |
% |
|
|
8.8 |
|
|
|
2 |
% |
|
Other revenues |
|
|
10.5 |
|
|
|
9.9 |
|
|
|
33.8 |
|
|
|
30.6 |
|
|
|
0.6 |
|
|
|
6 |
% |
|
|
3.2 |
|
|
|
10 |
% |
|
Net margin |
|
|
128.5 |
|
|
|
124.0 |
|
|
|
502.6 |
|
|
|
490.6 |
|
|
|
4.5 |
|
|
|
4 |
% |
|
|
12.0 |
|
|
|
2 |
% |
|
Operating costs |
|
|
91.0 |
|
|
|
97.6 |
|
|
|
280.5 |
|
|
|
285.6 |
|
|
|
(6.6 |
) |
|
|
(7 |
%) |
|
|
(5.1 |
) |
|
|
(2 |
%) |
|
Depreciation and amortization |
|
|
29.9 |
|
|
|
29.3 |
|
|
|
92.2 |
|
|
|
87.3 |
|
|
|
0.6 |
|
|
|
2 |
% |
|
|
4.9 |
|
|
|
6 |
% |
|
Gain on sale of assets |
|
|
- |
|
|
|
- |
|
|
|
0.4 |
|
|
|
- |
|
|
|
- |
|
|
|
0 |
% |
|
|
0.4 |
|
|
|
100 |
% |
|
Operating income (loss) |
|
$ |
7.6 |
|
|
$ |
(2.9 |
) |
|
$ |
130.3 |
|
|
$ |
117.7 |
|
|
$ |
10.5 |
|
|
|
* |
|
|
$ |
12.6 |
|
|
|
11 |
% |
|
Capital expenditures |
|
$ |
33.6 |
|
|
$ |
56.0 |
|
|
$ |
110.9 |
|
|
$ |
126.4 |
|
|
$ |
(22.4 |
) |
|
|
(40 |
%) |
|
$ |
(15.5 |
) |
|
|
(12 |
%) |
|
* Percentage change is greater than 100 percent. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net margin increased for the three months ended September 30, 2009, compared with the same period last year, due primarily to an increase of $4.4 million resulting from the implementation of new rate mechanisms, which includes a $2.0 million increase in Oklahoma, a $1.2 million increase in Kansas and a $1.2 million increase in Texas.
Net margin increased for the nine months ended September 30, 2009, compared with the same period last year, due primarily to the following:
|
· |
an increase of $12.8 million resulting from the implementation of new rate mechanisms, which includes a $4.8 million increase in Oklahoma, a $5.4 million increase in Kansas and a $2.6 million increase in Texas; and |
|
· |
an increase of $2.2 million related to recovery of carrying costs for natural gas in storage; partially offset by |
|
· |
a decrease of $1.8 million due to lower sales volumes due to warmer weather across our entire service territory; and |
|
· |
a decrease of $1.9 million due to lower transportation margins. |
Operating costs decreased for the three months ended September 30, 2009, compared with the same period last year, due primarily to the following:
|
· |
a decrease of $3.8 million in bad-debt expense that includes the impact of the authorized recovery of the fuel-related portion of bad debts in Oklahoma, effective January 2009; and |
|
· |
a decrease of $2.1 million in vehicle-related costs. |
Operating costs decreased for the nine months ended September 30, 2009, compared with the same period last year, due primarily to the following:
|
· |
a decrease of $9.6 million in bad-debt expense that includes the impact of the authorized recovery of the fuel-related portion of bad debts in Oklahoma, effective January 2009; |
|
· |
a decrease of $3.8 million in vehicle-related costs; partially offset by |
|
· |
an increase of $6.1 million in employee-related costs; and |
|
· |
an increase of $1.9 million in property tax expense. |
Depreciation and amortization expense increased for the nine months ended September 30, 2009, compared with the same period last year, due primarily to the following:
|
· |
an increase of $3.2 million in regulatory amortization associated with previously deferred costs that have been approved for recovery in our revenues; and |
|
· |
an increase of $1.7 million in depreciation expense related to our investment in property, plant and equipment. |
Capital Expenditures - Our capital expenditure program includes expenditures for extending service to new areas, modifications to customer service lines, increasing system capabilities, general replacements and improvements. It is our practice to maintain and upgrade facilities
to ensure safe, reliable and efficient operations. Our capital expenditure program included $7.5 million and $13.5 million for new business development for the three months ended September 30, 2009 and 2008, respectively, and $28.0 million and $35.4 million for the nine months ended September 30, 2009 and 2008, respectively. Capital expenditures decreased for the three months and nine months ended September 30, 2009, compared with the same periods last year, primarily as a result of timing
and lower spending on modifications to customer service lines, general replacements and improvements, as well as lower spending on growth projects during 2009.
Selected Operating Information - The following tables set forth selected operating information for our Distribution segment for the periods indicated:
| |
|
Three Months Ended |
|
|
Nine Months Ended |
|
| |
|
September 30, |
|
|
September 30, |
|
|
Volumes (MMcf) |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
Gas sales |
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential |
|
|
7,820 |
|
|
|
7,688 |
|
|
|
76,565 |
|
|
|
83,027 |
|
|
Commercial |
|
|
3,204 |
|
|
|
3,258 |
|
|
|
23,416 |
|
|
|
25,966 |
|
|
Industrial |
|
|
293 |
|
|
|
260 |
|
|
|
960 |
|
|
|
1,233 |
|
|
Wholesale |
|
|
4,000 |
|
|
|
2,521 |
|
|
|
8,712 |
|
|
|
5,080 |
|
|
Public Authority |
|
|
312 |
|
|
|
288 |
|
|
|
1,529 |
|
|
|
1,623 |
|
|
Total volumes sold |
|
|
15,629 |
|
|
|
14,015 |
|
|
|
111,182 |
|
|
|
116,929 |
|
|
Transportation |
|
|
43,366 |
|
|
|
50,344 |
|
|
|
146,761 |
|
|
|
163,362 |
|
|
Total volumes delivered |
|
|
58,995 |
|
|
|
64,359 |
|
|
|
257,943 |
|
|
|
280,291 |
|
| |
|
Three Months Ended |
|
|
Nine Months Ended |
|
| |
|
September 30, |
|
|
September 30, |
|
|
Net margin, excluding other revenues |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
Gas Sales |
|
(Millions of dollars) |
|
|
Residential |
|
$ |
81.4 |
|
|
$ |
77.8 |
|
|
$ |
326.4 |
|
|
$ |
317.3 |
|
|
Commercial |
|
|
17.4 |
|
|
|
16.9 |
|
|
|
73.9 |
|
|
|
73.3 |
|
|
Industrial |
|
|
0.6 |
|
|
|
0.5 |
|
|
|
2.0 |
|
|
|
2.2 |
|
|
Wholesale |
|
|
0.1 |
|
|
|
0.2 |
|
|
|
0.3 |
|
|
|
0.5 |
|
|
Public Authority |
|
|
0.7 |
|
|
|
0.6 |
|
|
|
2.7 |
|
|
|
2.5 |
|
|
Net margin on gas sales |
|
|
100.2 |
|
|
|
96.0 |
|
|
|
405.3 |
|
|
|
395.8 |
|
|
Transportation revenues |
|
|
17.8 |
|
|
|
18.1 |
|
|
|
63.5 |
|
|
|
64.2 |
|
|
Net margin, excluding other revenues |
|
$ |
118.0 |
|
|
$ |
114.1 |
|
|
$ |
468.8 |
|
|
$ |
460.0 |
|
| |
|
Three Months Ended |
|
|
Nine Months Ended |
|
| |
|
September 30, |
|
|
September 30, |
|
|
Number of Customers |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
Residential |
|
|
1,883,674 |
|
|
|
1,867,984 |
|
|
|
1,900,565 |
|
|
|
1,887,848 |
|
|
Commercial |
|
|
153,319 |
|
|
|
156,074 |
|
|
|
157,077 |
|
|
|
160,422 |
|
|
Industrial |
|
|
1,323 |
|
|
|
1,399 |
|
|
|
1,353 |
|
|
|
1,430 |
|
|
Wholesale |
|
|
26 |
|
|
|
27 |
|
|
|
27 |
|
|
|
28 |
|
|
Public Authority |
|
|
2,564 |
|
|
|
2,980 |
|
|
|
2,790 |
|
|
|
2,984 |
|
|
Transportation |
|
|
10,882 |
|
|
|
10,465 |
|
|
|
10,235 |
|
|
|
10,310 |
|
|
Total customers |
|
|
2,051,788 |
|
|
|
2,038,929 |
|
|
|
2,072,047 |
|
|
|
2,063,022 |
|
Residential volumes decreased for the nine months ended September 30, 2009, compared with the same periods last year, due to warmer temperatures across our entire service territory; however, the impact on margin decreases was moderated by weather-normalization mechanisms.
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 increased for the three and nine months ended September 30, 2009, compared with the same periods last year, due to increased volumes available
for sale caused by warmer temperatures across our entire service territory.
Regulatory Initiatives
Oklahoma - In December 2008, the OCC approved a final order to increase the recovery level of Oklahoma Natural Gas’ Capital Investment Mechanism (CIM) to $12.6 million from $7.6 million annually. The recovery mechanism allows Oklahoma Natural Gas to collect a
rate of return, depreciation and 50 percent of the property tax expense associated with incremental capital investments to maintain its facilities since its 2005 rate case. The increased recovery level was effective in January 2009.
In August 2009, Oklahoma Natural Gas filed the 2009 CIM application with the OCC. The application seeks recoveries of $17.3 million through a CIM rider in 2010. The OCC filed responsive testimony on October 9, 2009, supporting the application. On October 13, 2009, the Oklahoma Attorney General filed a Statement
of Position supporting the OCC Staff’s position. On October 26, 2009, Oklahoma Natural Gas, the OCC Staff and the Oklahoma Attorney General signed and filed a joint stipulation approving Oklahoma Natural Gas’ request. On October 29, the administrative law judge approved the joint stipulation and is recommending approval by the OCC.
In December 2008, the OCC issued a final order authorizing Oklahoma Natural Gas to defer the fuel-related portion of bad debts for recovery in the purchased-gas adjustment mechanism. The associated deferrals began in January 2009.
The OCC has authorized Oklahoma Natural Gas to defer 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. An IMP application was made at the
OCC on January 30, 2009,
covering the IMP deferrals for 2008 and the true-ups associated with the prior recovery period. The OCC approved this application for recovery of $10.5 million in IMP costs in June 2009.
In October 2008, a joint application for performance-based rates was filed by the OCC staff and Oklahoma Natural Gas. This application proposes that the OCC adopt a performance-based rate design and a more streamlined regulatory process. In April 2009, a joint stipulation was signed and filed that supports a performance-based
rate mechanism for Oklahoma Natural Gas. Upon hearing evidence and testimony supporting the joint stipulation in a hearing on April 23, 2009, the administrative law judge recommended the OCC approve the application. The OCC adopted the recommendation of the administrative law judge and approved the joint stipulation of the parties on May 7, 2009.
In June 2009, Oklahoma Natural Gas filed an application with the OCC requesting an increase of approximately $66.1 million in base rates, which includes existing riders that would effectively reduce the requested rate increase to a net amount of $37.6 million. On October 28, 2009, Oklahoma Natural Gas, the OCC Staff, the Oklahoma
Attorney General and other intervening parties signed and filed a Stipulation Settlement in this case. If approved as filed, the estimated annual impact on operating income will be approximately $14.0 million. The Stipulation Settlement must first be approved by an administrative law judge who will then submit the matter to the OCC for final approval.
Kansas - In December 2008, the KCC approved our request to impose a surcharge designed to annually collect approximately $2.9 million in costs associated with its Gas System Recovery Surcharge (GSRS) mechanism. The GSRS mechanism allows natural gas utilities to earn a return
and recover carrying charges 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 authorized GSRS collections were billed effective with customer billings on January 1, 2009.
In August 2009, Kansas Gas Service filed the required annual update of the GSRS mechanism. If approved, the requested $3.9 million increase would be effective with customer billings in January 2010. On October 30, 2009, the KCC Staff issued its report for this filing recommending that Kansas Gas Service be authorized
to recover $3.9 million. The matter will be submitted to the KCC for final approval, and the KCC order is required to be issued by December 29, 2009.
In September 2009, the KCC issued an order permitting us to defer the difference between current GAAP pension and post retirement expenses and the level of these expenses incorporated in base rates as either a regulatory asset or liability, effective with fiscal year 2009. In conjunction with the deferral, we are required to fund the
applicable amount of our pension and post retirement expense. Amortization and recovery of the accumulated deferrals will begin with the effective date of our next rate change request continuing no more than five years. The impact from the KCC order was a decrease in operating expenses of $2.4 million for the three months ended September 30, 2009, and the anticipated 2009 impact from the KCC order is an increase in operating income of $3.2 million.
Texas - In June 2009, Austin and the surrounding cities in our central Texas service area approved an increase in base rates of $1.1 million, which included a $5.0 million decrease in depreciation and amortization expense, plus recovery of the fuel-related portion of bad debts
and carrying costs for natural gas in storage. The new rates were effective July 2009.
In August 2009, the cities of the Rio Grande Valley service area approved an increase in base rates of $1.3 million, which included a $1.6 million decrease in depreciation and amortization expense, plus recovery of the fuel-related portion of bad debts. The new rates were effective September 2009.
General - Certain costs to be recovered through the ratemaking process have been capitalized as regulatory assets. Should recovery cease due to regulatory actions, certain of these assets may no longer meet the criteria for capitalization, and, accordingly, a write-off of regulatory
assets and stranded costs may be required. There were no write-offs of regulatory assets resulting from the failure to meet the criteria for capitalization during the three and nine months ended September 30, 2009 and 2008, respectively.
Energy Services
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. This contracted
storage and transportation capacity connects the major supply and demand centers throughout the United States and into Canada. Our customers are primarily LDCs, electric utilities, and commercial and industrial end users. Our customers’ natural gas needs vary with seasonal changes in weather and are therefore somewhat unpredictable. To ensure natural gas is available when our customers need it, we offer premium services and products that satisfy our customers’ swing
and peaking natural gas commodity requirements on a year-round basis. We also provide no-notice
service, weather-related protection and other custom solutions based on our customers’ specific needs. Our storage and transportation capacity allows us opportunities to optimize our contracted assets through our application of market knowledge and risk management skills.
Our Energy Services segment conducts business with our ONEOK Partners and our Distribution segments. These services are provided under agreements with market-based terms. Our Energy Services segment’s business with our Distribution segment is awarded through a competitive bidding process.
Due to the seasonality of natural gas consumption, storage withdrawals and demand for our products and services, earnings are normally higher during the winter months than the summer months. Natural gas sales volumes are typically higher in the winter heating months than in the summer months, reflecting increased demand due to greater
heating requirements and, typically, higher natural gas prices. During periods of high natural gas demand, we utilize storage capacity to supplement natural gas supply volumes to meet our premium product and service obligations or market needs.
We utilize our experience to optimize the value of our contracted assets, and we use our risk management and marketing capabilities to both manage risk and generate additional margins. We apply a combination of cash flow and fair value hedge accounting when implementing hedging strategies that take advantage of favorable market
conditions. See Note C of the Notes to Consolidated Financial Statements in this Quarterly Report for additional information. Additionally, certain non-trading transactions, which are economic hedges of our accrual transactions, such as our storage and transportation contracts, will not qualify for hedge accounting treatment. These economic hedges receive mark-to-market accounting treatment, as they are derivative contracts and are not designated as part of a hedge relationship. As
a result, the underlying risk being hedged receives accrual accounting treatment, while we use mark-to-market accounting treatment for the economic hedges. We cannot predict the earnings fluctuations from mark-to-market accounting, and the impact on earnings could be material.
Selected Financial Results - The following table sets forth selected financial results for our Energy Services segment for the periods indicated:
| |
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
Increase (Decrease) |
|
|
Increase (Decrease) |
|
| |
|
September 30, |
|
|
September 30, |
|
|
Three Months |
|
|
Nine Months |
|
|
Financial Results |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
2009 vs. 2008 |
|
|
2009 vs. 2008 |
|
| |
(Millions of dollars) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
727.7 |
|
|
$ |
2,038.4 |
|
|
$ |
2,568.2 |
|
|
$ |
6,408.0 |
|
|
$ |
(1,310.7 |
) |
|
|
(64 |
%) |
|
$ |
(3,839.8 |
) |
|
|
(60 |
%) |
|
Cost of sales and fuel |
|
|
698.0 |
|
|
|
2,033.6 |
|
|
|
2,445.8 |
|
|
|
6,314.1 |
|
|
|
(1,335.6 |
) |
|
|
(66 |
%) |
|
|
(3,868.3 |
) |
|
|
(61 |
%) |
|
Net margin |
|
|
29.7 |
|
|
|
4.8 |
|
|
|
122.4 |
|
|
|
93.9 |
|
|
|
24.9 |
|
|
|
* |
|
|
|
28.5 |
|
|
|
30 |
% |
|
Operating costs |
|
|
8.4 |
|
|
|
9.4 |
|
|
|
26.4 |
|
|
|
28.0 |
|
|
|
(1.0 |
) |
|
|
(11 |
%) |
|
|
(1.6 |
) |
|
|
(6 |
%) |
|
Depreciation and amortization |
|
|
0.1 |
|
|
|
0.2 |
|
|
|
0.4 |
|
|
|
0.8 |
|
|
|
(0.1 |
) |
|
|
(50 |
%) |
|
|
(0.4 |
) |
|
|
(50 |
%) |
|
Gain on sale of assets |
|
|
- |
|
|
|
1.3 |
|
|
|
- |
|
|
|
1.3 |
|
|
|
(1.3 |
) |
|
|
(100 |
%) |
|
|
(1.3 |
) |
|
|
(100 |
%) |
|
Operating income (loss) |
|
$ |
21.2 |
|
|
$ |
(3.5 |
) |
|
$ |
95.6 |
|
|
$ |
66.4 |
|
|
$ |
24.7 |
|
|
|
* |
|
|
|
29.2 |
|
|
|
44 |
% |
|
* Percentage change is greater than 100 percent. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy markets were affected by lower commodity prices during the three and nine months ended September 30, 2009, compared with the same periods last year. The decrease in commodity prices had a direct impact on our revenues and the cost of sales and fuel. Our average sales price was 63 percent lower for the three months ended
September 30, 2009, and 58 percent lower for the nine months ended September 30, 2009, compared with the same periods last year.
Net margin increased for the three months ended September 30, 2009, compared with the same period last year, due primarily to the following:
|
· |
an increase of $17.8 million in transportation margins, net of hedging activities, due primarily to higher realized Rockies-to-Mid-Continent transportation margins; |
|
· |
an increase of $4.5 million in storage and marketing margins, net of hedging activities, due primarily to the following: |
|
- |
the impact of an inventory write-down of $9.7 million in third quarter of 2008; partially offset by |
|
- |
a decrease in storage margins associated with less favorable unrealized fair value changes on non-qualifying economic hedge activity; |
|
· |
an increase of $1.7 million in premium services, due primarily to additions to our customer base; and |
|
· |
an increase of $1.4 million in retail marketing margins. |
Net margin increased for the nine months ended September 30, 2009, compared with the same period last year, due primarily to the following:
|
· |
an increase of $32.0 million in premium services, due primarily to additions to our customer base; |
|
· |
an increase of $27.9 million in transportation margins, net of hedging activities, due primarily to higher realized Rockies-to-Mid-Continent transportation margins; |
|
· |
an increase of $5.0 million in retail marketing margins; and |
|
· |
an increase of $2.0 million in financial trading margins; partially offset by |
|
· |
a decrease of $38.1 million in storage and marketing margins, net of hedging activities, due primarily to the following: |
|
- |
lower realized seasonal storage differentials; partially offset by |
|
- |
the impact of an inventory write-down of $9.7 million in third quarter 2008. |
Operating costs decreased for the three and nine months ending September 30, 2009, compared with the same periods last year, due to lower employee-related costs.
Selected Operating Information - The following table sets forth selected operating information for our Energy Services segment for the periods indicated:
| |
|
Three Months Ended |
|
|
Nine Months Ended |
|
| |
|
September 30, |
|
|
September 30, |
|
|
Operating Information |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
Natural gas marketed (Bcf) |
|
|
255 |
|
|
|
261 |
|
|
|
841 |
|
|
|
867 |
|
|
Natural gas gross margin ($/Mcf) |
|
$ |
0.11 |
|
|
$ |
0.02 |
|
|
$ |
0.14 |
|
|
$ |
0.08 |
|
|
Physically settled volumes (Bcf) |
|
|
524 |
|
|
|
560 |
|
|
|
1,702 |
|
|
|
1,756 |
|
Our natural gas in storage at September 30, 2009, was 79.6 Bcf, compared with 74.7 Bcf at September 30, 2008. At September 30, 2009, our total natural gas storage capacity under lease was 82.8 Bcf, with maximum withdrawal capability of 2.3 Bcf/d and maximum injection capability of 1.4 Bcf/d. Our current natural gas transportation
capacity is 1.6 Bcf/d.
The following table sets forth our margins by activity for the periods indicated:
| |
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
Increase (Decrease) |
|
Increase (Decrease) |
| |
|
September 30, |
|
|
September 30, |
|
|
Three Months |
|
Nine Months |
| |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
2009 vs. 2008 |
|
2009 vs. 2008 |
| |
(Millions of dollars) |
|
|
Marketing, storage and transportation, gross |
|
$ |
79.7 |
|
|
$ |
57.3 |
|
|
$ |
266.3 |
|
|
$ |
246.1 |
|
|
$ |
22.4 |
|
39 |
% |
|
$ |
20.2 |
|
8 |
% |
|
Storage and transportation costs |
|
|
53.1 |
|
|
|
54.6 |
|
|
|
161.7 |
|
|
|
163.1 |
|
|
|
(1.5 |
) |
(3 |
%) |
|
|
(1.4 |
) |
(1 |
%) |
|
Marketing, storage and transportation, net |
|
|
26.6 |
|
|
|
2.7 |
|
|
|
104.6 |
|
|
|
83.0 |
|
|
|
23.9 |
|
* |
|
|
|
21.6 |
|
26 |
% |
|
Retail marketing, net |
|
|
3.1 |
|
|
|
1.7 |
|
|
|
14.3 |
|
|
|
9.3 |
|
|
|
1.4 |
|
82 |
% |
|
|
5.0 |
|
54 |
% |
|
Financial trading, net |
|
|
- |
|
|
|
0.4 |
|
|
|
3.5 |
|
|
|
1.6 |
|
|
|
(0.4 |
) |
(100 |
%) |
|
|
1.9 |
|
* |
|
|
Net margin |
|
$ |
29.7 |
|
|
$ |
4.8 |
|
|
$ |
122.4 |
|
|
$ |
93.9 |
|
|
$ |
24.9 |
|
* |
|
|
$ |
28.5 |
|
30 |
% |
|
* Percentage change is greater than 100 percent. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marketing, storage and transportation, gross, primarily includes marketing, purchases and sales, premium services and the impact of cash flow and fair value hedges and other derivative instruments used to manage our risk associated with these activities. Storage and transportation costs primarily include the cost of leasing capacity,
storage injection and withdrawal fees, fuel charges and gathering fees. Risk management and operational decisions have an impact on the net result of our marketing, premium services and storage activities. We evaluate our strategies on an ongoing basis to optimize the value of our contracted assets and to minimize the financial impact of market conditions on the services we provide.
Retail marketing includes net margin from providing physical marketing, supply services and risk management services to residential, municipal and small commercial and industrial customers.
Financial trading net margin includes activities that are generally executed using financially settled derivatives. These activities are normally short term in nature, with a focus on capturing value from short-term price volatility. Revenues in our
Consolidated Statements of Income include 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 reported on a net basis.
Contingencies
Legal Proceedings - We are a party to various litigation matters and claims that are 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. Additional information about our legal proceedings is included under Part II, Item 1, Legal Proceedings of this Quarterly Report and under Part I, Item 3, Legal Proceedings, in our Annual Report.
LIQUIDITY AND CAPITAL RESOURCES
General - Part of our strategy is to grow through internally generated growth projects and acquisitions that strengthen and complement our existing assets. ONEOK and ONEOK Partners have relied primarily on operating cash flow, commercial paper, bank credit facilities, debt
issuances and/or the sale of equity for their liquidity and capital resource requirements. ONEOK and ONEOK Partners fund their operating expenses, debt service, dividends to shareholders and distributions to unitholders primarily with operating cash flow. We expect to continue to use these sources for liquidity and capital resource needs on both a short- and long-term basis. Neither ONEOK nor ONEOK Partners guarantees the debt or other similar commitments to unaffiliated parties,
and ONEOK does not guarantee the debt or other similar commitments of ONEOK Partners.
During 2009, the capital markets have improved significantly from year-end 2008. Throughout 2009, ONEOK has been able to access the commercial paper markets to meet its short-term funding needs, and has continued to have access to its $1.2 billion amended and restated credit agreement dated July 14, 2006 (ONEOK Credit Agreement),
which expires in July 2011. ONEOK Partners has continued to have access to its ONEOK Partners Credit Agreement, which has been adequate to fund its short-term liquidity needs and expires in March 2012. Additionally, ONEOK Partners has been able to access the debt and equity markets to meet its long-term financing needs for 2009.
We expect improving economic conditions for the remainder of 2009 and into 2010, compared with the fourth quarter of 2008 and the first two quarters of 2009, when we began to experience reduced drilling activity, less supply growth and lower commodity prices for natural gas, NGLs and crude oil. We also expect continued volatility
in the financial markets, which could limit our access to these markets or increase the cost of issuing new securities in the future. ONEOK’s and ONEOK Partners’ ability to continue to access capital markets for debt and equity financing under reasonable terms depends on the Company’s and Partnership’s respective financial condition and credit ratings, and market conditions. ONEOK and ONEOK Partners anticipate that cash flow generated from operations, existing capital
resources and ability to obtain financing will enable both to maintain current levels of operations and planned operations, collateral requirements and capital expenditures.
Capital Structure - The following table sets forth our consolidated capital structure for the periods indicated:
| |
|
September 30, |
|
December 31, |
| |
|
2009 |
|
2008 |
|
Long-term debt |
|
58% |
|
67% |
|
Equity |
|
42% |
|
33% |
| |
|
|
|
|
|
Debt (including notes payable) |
|
62% |
|
76% |
|
Equity |
|
38% |
|
24% |
For purposes of determining compliance with financial covenants in the ONEOK Credit Agreement, the debt of ONEOK Partners is excluded. The following table sets forth ONEOK’s capitalization structure, excluding the debt of ONEOK Partners, for the periods indicated:
| |
|
September 30, |
|
December 31, |
| |
|
2009 |
|
2008 |
|
Long-term debt |
|
42% |
|
44% |
|
Equity |
|
58% |
|
56% |
| |
|
|
|
|
|
Debt (including notes payable) |
|
46% |
|
59% |
|
Equity |
|
54% |
|
41% |
In February 2009, ONEOK repaid $100 million of maturing long-term debt with cash from operations and short-term borrowings. In February 2008, ONEOK repaid $402.3 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 joint accounts for the purpose of 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’ operating subsidiaries participate in these programs to the extent they are permitted pursuant to FERC regulations or their operating agreements. 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 respective subsidiaries or the subsidiaries provide 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 and the ONEOK Credit Agreement as discussed below. ONEOK also has a commercial paper program that
is utilized for short-term liquidity needs, and to the extent commercial paper is unavailable, the ONEOK Credit Agreement is utilized. ONEOK Partners’ principal sources of short-term liquidity consist of cash generated from operating activities and borrowings under the ONEOK Partners Credit Agreement.
The total amount of short-term borrowings authorized by ONEOK’s Board of Directors is $2.5 billion. At September 30, 2009, ONEOK had $309 million in commercial paper outstanding, $42 million in letters of credit issued under the ONEOK Credit Agreement and available cash and cash equivalents of approximately $21.7 million. ONEOK
had approximately $849 million of credit available at September 30, 2009, under the ONEOK Credit Agreement. The amount of credit available under committed bank lines decreased by $400 million when ONEOK’s 364-day revolving credit facility dated August 6, 2008, expired on August 5, 2009. As of September 30, 2009, ONEOK could have issued $2.8 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 September 30, 2009, ONEOK Partners had $515 million in borrowings outstanding under the ONEOK Partners Credit Agreement and available cash and cash equivalents of approximately
$30.5 million. As of September 30, 2009, ONEOK Partners’ borrowing capacity was limited to $219.7 million of additional short- and long-term debt under the most restrictive provisions of the ONEOK Partners Credit Agreement. At September 30, 2009, ONEOK Partners had a total of $49.2 million in letters of credit issued outside the ONEOK Partners Credit Agreement.
The ONEOK Credit Agreement and the ONEOK Partners Credit Agreement contain certain financial, operational and legal covenants as discussed in Note H of the Notes to Consolidated Financial Statements in our Annual Report. Among other things, the ONEOK Credit Agreement’s covenants include 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. At September 30, 2009, ONEOK’s stand-alone debt-to-capital ratio, as calculated under the terms of the ONEOK Credit Agreement, was 45.4 percent, and ONEOK was in compliance with all covenants under the ONEOK Credit Agreement. The ONEOK Partners Credit Agreement’s covenants include, among other things, maintaining a ratio of indebtedness to adjusted EBITDA (EBITDA, as adjusted for all
non-cash charges and increased for projected EBITDA from certain lender-approved capital expansion projects) of no more than 5 to 1. At September 30, 2009, ONEOK Partners’ ratio of indebtedness to adjusted EBITDA was 4.7 to 1, and ONEOK Partners was in compliance with all covenants under the ONEOK Partners Credit Agreement.
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 the sale and 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, asset securitization and the sale and leaseback of facilities.
ONEOK and ONEOK Partners are subject to changes in the debt and equity 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, borrowing under
existing credit facilities, altering the timing of controllable expenditures, restricting future acquisitions and capital projects, or pursuing other debt or equity financing alternatives. Some of these alternatives could involve higher costs or negatively affect their respective credit ratings, among other factors. 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’ Equity Issuance - In June 2009, ONEOK Partners completed an underwritten public offering of 5,000,000 common units at $45.81 per common unit, generating net proceeds of approximately $219.9 million after deducting underwriting discounts but before offering
expenses.
In July 2009, ONEOK Partners sold an additional 486,690 common units at $45.81 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 $21.4 million from the sale of the
common units after deducting underwriting discounts but before offering expenses.
In conjunction with the public offering and partial exercise by the underwriters of their overallotment option, ONEOK Partners GP contributed an aggregate of $5.1 million to ONEOK Partners in order to maintain its 2 percent general partner interest. As a result of these transactions, our interest in ONEOK Partners is 45.1 percent.
ONEOK Partners used the proceeds from the sale of common units and the general partner contributions to repay borrowings under its existing ONEOK Partners Credit Agreement and for general partnership purposes.
ONEOK Partners’ Debt Issuance - In March 2009, ONEOK Partners completed an underwritten public offering of $500 million aggregate principal amount of 8.625 percent Senior Notes due 2019.
ONEOK Partners may redeem the 2019 Notes, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, 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 2019 Notes plus accrued and unpaid
interest to the redemption date.
The 2019 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 2019 Notes are nonrecourse to ONEOK. For
more information regarding the 2019 Notes, refer to discussion in Note G of the Notes to Consolidated Financial Statements in this Quarterly Report.
Debt Covenants - The terms of the 2019 Notes are governed by an indenture, dated as of September 25, 2006, between ONEOK Partners and Wells Fargo Bank, N.A., as trustee, as supplemented by the Fifth Supplemental Indenture, dated March 3, 2009 (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 Indenture contains covenants including, among other provisions, limitations on ONEOK Partners’ ability to place liens on its property or assets and to sell and lease back its property.
ONEOK Partners’ $250 million and $225 million senior notes, 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, 2019, 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 events 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, 2019, 2036 and 2037 to declare those notes immediately due and payable in full.
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 were $614.8 million and $1.0 billion for the nine months
ended September 30, 2009 and 2008, respectively. Of these amounts, ONEOK Partners’ capital expenditures were $491.3 million and $860.2 million for the nine months ended September 30, 2009 and 2008, respectively. Our capital expenditures are driven primarily by ONEOK Partners’ capital projects discussed beginning on page 35.
Projected 2009 capital expenditures are significantly less than 2008 capital expenditures, primarily due to the completion of the Arbuckle Pipeline, the Overland Pass Pipeline and related expansion projects, the Williston Basin gas processing plant expansion and the Guardian Pipeline expansion and extension. The following table
sets forth our 2009 projected capital expenditures, excluding AFUDC:
|
2009 Projected Capital Expenditures |
|
| |
(Millions of dollars) |
|
ONEOK Partners |
|
$ |
583 |
|
|
Distribution |
|
|
158 |
|
|
Other |
|
|
15 |
|
|
Total projected capital expenditures |
|
$ |
756 |
|
Investment in Northern Border Pipeline - During the nine months ended September 30, 2009, ONEOK Partners made equity contributions of $42.3 million to Northern Border. ONEOK Partners does not anticipate any additional equity contributions in 2009 or material equity contributions
in 2010.
Credit Ratings - ONEOK’s and ONEOK Partners’ credit ratings as of September 30, 2009, 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 and borrowings under the ONEOK Credit Agreement would increase, 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. An adverse rating change alone is not a default under the ONEOK Credit Agreement or the ONEOK Partners Credit Agreement but could trigger repurchase obligations with respect to certain ONEOK Partners’
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.
Our Energy Services segment relies upon the investment-grade credit rating of ONEOK’s senior unsecured long-term debt to 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-grade rating, we may be required to fund margin requirements with our counterparties with cash, letters of credit or other negotiable instruments. At September 30, 2009, ONEOK could have been required to fund approximately $11.8 million in margin requirements related to financial contracts upon such a downgrade. A decline in ONEOK’s credit ratings below investment grade may also significantly impact other business segments.
Other than ONEOK Partners’ note repurchase obligations and the margin requirements for our Energy Services segment described above, we have determined that we do not have significant exposure to rating triggers under ONEOK’s 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’ counterparties provide secured and unsecured credit. In the event of a downgrade in ONEOK’s or ONEOK Partners’ credit ratings or a significant change in ONEOK’s or ONEOK Partners’ counterparties’ evaluation of creditworthiness,
ONEOK or ONEOK Partners could be required to provide
additional collateral in the form of cash, letters of credit or other negotiable instruments as a condition of continuing to conduct business with such counterparties.
Commodity Prices - We are subject to commodity price volatility. Significant fluctuations in commodity prices may impact our overall liquidity due to the impact commodity price changes have on our cash flows from operating activities, including the impact on working capital
for NGLs and natural gas held in storage, margin requirements and certain energy-related receivables. We believe that ONEOK’s and ONEOK Partners’ available credit and cash and cash equivalents are adequate to meet liquidity requirements associated with commodity price volatility. See discussion beginning on page 57 under “Commodity Price Risk” in Item 3, 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 is included in Note J of the Notes to Consolidated Financial Statements in our Annual Report. See Note H of the Notes to Consolidated Financial Statements in this Quarterly
Report for additional information.
CASH FLOW ANALYSIS
We use the indirect method to prepare our Consolidated Statements of Cash Flows. 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, equity earnings from investments, distributions received from unconsolidated affiliates, deferred income taxes, stock-based compensation expense, allowance for doubtful accounts, and changes in our assets and liabilities not classified as investing or financing activities.
The following table sets forth the changes in cash flows by operating, investing and financing activities for the periods indicated:
| |
|
Nine Months Ended |
|
|
Increase (Decrease) |
|
| |
|
September 30, |
|
|
Nine Months |
|
| |
|
2009 |
|
|
2008 |
|
|
2009 vs. 2008 |
|
| |
|
(Millions of dollars) |
|
|
Total cash provided by (used in): |
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities |
|
$ |
1,270.9 |
|
|
$ |
478.4 |
|
|
$ |
792.5 |
|
|
|
* |
|
|
Investing activities |
|
|
(621.6 |
) |
|
|
(1,016.0 |
) |
|
|
394.4 |
|
|
|
39 |
% |
|
Financing activities |
|
|
(1,107.2 |
) |
|
|
591.4 |
|
|
|
(1,698.6 |
) |
|
|
* |
|
|
Change in cash and cash equivalents |
|
|
(457.9 |
) |
|
|
53.8 |
|
|
|
(511.7 |
) |
|
|
* |
|
|
Cash and cash equivalents at beginning of period |
|
|
510.1 |
|
|
|
19.1 |
|
|
|
491.0 |
|
|
|
* |
|
|
Cash and cash equivalents at end of period |
|
$ |
52.2 |
|
|
$ |
72.9 |
|
|
$ |
(20.7 |
) |
|
|
(28 |
%) |
|
* Percentage change is greater than 100 percent. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Cash Flows - Operating cash flows are affected by earnings from our business activities. We provide services for producers and consumers of natural gas and NGLs. Changes in commodity prices and demand for our services or products, whether because of general
economic conditions, changes in demand for the end products that are made with our products or increased competition from other service providers, could affect our earnings and operating cash flows.
The changes in operating assets and liabilities increased operating cash flows $647.5 million for the nine months ended September 30, 2009, compared with a decrease of $245.9 million for the same period last year, primarily as a result of the following:
· a decrease in cash collateral and margin requirements in our Energy Services segment;
· the impact of lower commodity prices on our operating assets and liabilities;
· the timing of cash receipts from our revenues resulting in decreased accounts receivable; partially offset by
· the timing of payments for purchases of commodities and other expenses resulting in decreased accounts payable.
Operating cash flows, before changes in operating assets and liabilities, were $623.4 million for the nine months ended September 30, 2009, compared with $724.3 million for the same period last year. The decrease was due primarily to lower realized commodity prices and narrower NGL product price differentials in our ONEOK Partners
segment, partially offset by increased NGL volumes gathered, fractionated and transported, primarily associated with the completion of the Overland
Pass Pipeline and related expansion projects, and the Arbuckle Pipeline, as well as new NGL supply connections in our ONEOK Partners segment, and increased transportation margins, net of hedging activities, in our Energy Services segment.
Investing Cash Flows - Cash used in investing activities decreased for the nine months ended September 30, 2009, compared with the same period last year, due primarily to reduced capital expenditures as a result of the completion of the Arbuckle Pipeline and Overland Pass Pipeline and
related expansion projects, the Williston Basin gas processing plant expansion and the Guardian Pipeline expansion and extension in our ONEOK Partners segment.
Financing Cash Flows - During the nine months ended September 30, 2009, we had a net repayment of notes payable of $1.4 billion. The repayments were made with the proceeds ONEOK Partners received from the senior notes and public offering of common units, as discussed below,
and cash generated from operations. During the nine months ended September 30, 2008, we had net borrowings of $1.1 billion, which were used to repay $402.3 million of ONEOK’s maturing long-term debt and fund ONEOK Partners’ capital projects.
During 2009, ONEOK Partners’ common unit offering generated net proceeds of approximately $241.6 million. ONEOK Partners used the proceeds to repay borrowings under the ONEOK Partners Partnership Credit Agreement and for general partnership purposes.
In March 2009, ONEOK Partners completed an underwritten public offering of senior notes and received proceeds totaling approximately $498.3 million, net of discounts but before offering expenses. ONEOK Partners used the net proceeds from the notes to repay borrowings under the ONEOK Partners Partnership Credit Agreement.
In February 2009 and 2008, ONEOK repaid $100.0 million and $402.3 million, respectively, of maturing long-term debt with available cash and short-term borrowings.
During 2008, ONEOK Partners’ public sale of 2.6 million common units generated net proceeds of approximately $147.0 million after deducting underwriting discounts but before offering expenses. ONEOK Partners used a portion of the proceeds to repay borrowings under the ONEOK Partners Partnership Credit Agreement.
Dividends paid were $1.22 per share and $1.16 per share for the nine months ended September 30, 2009 and 2008, respectively.
Distributions paid to limited partners by ONEOK Partners were $3.24 per unit and $3.125 per unit for the nine months ended September 30, 2009 and 2008, respectively.
ENVIRONMENTAL AND SAFETY MATTERS
Information about our environmental matters is included in Note I of the Notes to Consolidated Financial Statements in this Quarterly Report.
Pipeline Safety - We are subject to United States Department of Transportation regulations, including integrity management regulations. The Pipeline Safety Improvement Act requires pipeline companies to perform integrity assessments on pipeline segments that pass through densely
populated areas or near specifically designated high consequence areas. To our knowledge, we are in compliance with all material requirements associated with the various pipeline safety regulations. We cannot be assured that existing pipeline safety regulations will not be revised or that new regulations will not be adopted that could result in increased compliance costs or additional operating restrictions.
Air and Water Emissions - The federal Clean Air Act, the federal Clean Water Act and analogous state laws impose restrictions and controls regarding the discharge of pollutants into the air and water in the United States. Under the Clean Air Act, a federally enforceable operating
permit is required for sources of significant air emissions. We may be required to incur certain capital expenditures for air pollution-control equipment in connection with obtaining or maintaining permits and approvals for sources of air emissions. The Clean Water Act imposes substantial potential liability for the removal of pollutants discharged to waters of the United States and remediation of waters affected by such discharge. To our knowledge, we are in compliance with all
material requirements associated with the various air and water quality regulations.
The United States Congress is actively considering legislation to reduce greenhouse gas emissions, including carbon dioxide and methane. In addition, state and regional initiatives to regulate greenhouse gas emissions are under way. We are monitoring federal and state legislation to assess the potential impact on our
operations. We estimate our direct greenhouse
gas emissions annually as we collect all applicable greenhouse gas emission data for the previous year. Our most recent estimate for ONEOK and ONEOK Partners, based on 2008 data, indicates that our emissions are less than 5 million metric tons of carbon dioxide equivalents on an annual basis. We will continue efforts
to improve our ability to quantify our direct greenhouse gas emissions and will report such emissions as required by the United States Environmental Protection Agency’s (EPA) Mandatory Greenhouse Gas Reporting rule released in September 2009. The rule requires greenhouse gas emissions reporting for affected facilities on an annual basis, beginning with our 2010 emissions report that will be due in March 2011.
Superfund - The Comprehensive Environmental Response, Compensation and Liability Act, also known as CERCLA or Superfund, imposes liability, without regard to fault or the legality of the original act, on certain classes of persons who contributed to the release of a hazardous substance
into the environment. These persons include the owner or operator of a facility where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the facility. Under CERCLA, these persons may be liable for the costs of cleaning up the hazardous substances released into the environment, damages to natural resources and the costs of certain health studies.
Chemical Site Security - The United States Department of Homeland Security (Homeland Security) released an interim rule in April 2007 that requires companies to provide reports on sites where certain chemicals, including many hydrocarbon products, are stored. We completed the
Homeland Security assessments, and our facilities were subsequently assigned one of four risk-based tiers ranging from high (Tier 1) to low (Tier 4) risk, or not tiered at all due to low risk. A majority of our facilities were not tiered. We are currently waiting for Homeland Security’s analysis to determine if any of the tiered facilities will require Site Security Plans and possible physical security enhancements. In addition, the Transportation Security Administration
and the Department of Transportation have completed a review and inspection of our “critical facilities” with no material issues.
Environmental Footprint - Our environmental and climate change strategy focuses on taking steps to minimize the impact of our operations on the environment. These strategies include: (i) developing and maintaining an accurate greenhouse gas emissions inventory, according to
new rules issued by the EPA; (ii) improving the efficiency of our various pipelines, natural gas processing facilities and natural gas liquids fractionation facilities; (iii) following developing technologies for emission control; (iv) following developing technologies to capture carbon dioxide to keep it from reaching the atmosphere; and (v) analyzing options for future energy investment.
Currently, certain subsidiaries of ONEOK Partners participate in the Processing and Transmission sectors, and LDCs in our Distribution segment participate in the Distribution sector of the EPA’s Natural Gas STAR Program to voluntarily reduce methane emissions. A subsidiary in our ONEOK Partners’ segment was honored in
2008 as the “Natural Gas STAR Gathering and Processing Partner of the Year” for its efforts to positively address environmental issues through voluntary implementation of emission-reduction opportunities. In addition, we continue to focus on maintaining low rates of lost-and-unaccounted-for methane gas through expanded implementation of best practices to limit the release of methane during pipeline and facility maintenance and operations. Our 2008 calculation of our annual lost-and-unaccounted-for
natural gas, for all of our business operations, is less than 1 percent of total throughput.
FORWARD-LOOKING STATEMENTS
Some of the statements contained and incorporated in this Quarterly Report are forward-looking statements within the meaning of Section 27A of the Securities Act, and Section 21E of the Exchange Act. 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. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 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 Quarterly Report identified by words such as “anticipate,” “estimate,” “expect,” “project,”
“intend,” “plan,” “believe,” “should,” “goal,” “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, which are applicable only as of the date of this Quarterly Report. 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 foreign energy suppliers and transporters, as well as alternative forms of energy, including, but not limited to, solar power, wind power, geothermal energy and 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 of 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 with our competitors that have less debt, or have other adverse consequences; |
|
· |
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 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; |
|
· |
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 U.S. 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 updates 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 |
|
· |
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 Part
I, Item 1A, Risk Factors, in our Annual Report. 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 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Our quantitative and qualitative disclosures about market risk are consistent with those discussed in Part II, Item 7A, Quantitative and Qualitative Disclosures About Market Risk in our Annual Report.
COMMODITY PRICE RISK
See Note C of the Notes to Consolidated Financial Statements and the discussion under ONEOK Partners’ “Commodity Price Risk” in Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations, in this Quarterly Report for information on our hedging activities.
Fair Value Component of Energy Marketing and Risk Management Assets and Liabilities - The following table sets forth the fair value component of our energy marketing and risk management assets and liabilities, excluding $173.8 million of net assets at September 30, 2009, from derivative
instruments designated as either fair value or cash flow hedges, for the periods indicated:
|
Fair Value Component of Energy Marketing and Risk Management Assets and Liabilities |
|
| |
(Thousands of dollars) |
|
Net fair value of derivatives outstanding at December 31, 2008 (a) |
|
$ |
3,656 |
|
|
Derivatives reclassified or otherwise settled during the period |
|
|
(11,306 |
) |
|
Fair value of new derivatives entered into during the period |
|
|
1,761 |
|
|
Other changes in fair value |
|
|
11,857 |
|
|
Net fair value of derivatives outstanding at September 30, 2009 (b) |
|
$ |
5,968 |
|
| |
|
|
|
|
|
(a) - This balance has been adjusted by $255.1 million from the amount reported in our Annual Report.
The adjustment was made in order to exclude from this table the gains on cash flow hedges that were
reclassified into earnings from accumulated other comprehensive income (loss) related to the write
down of our natural gas in storage to its lower of weighted-average cost or market. |
|
(b) - 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: $1.5 million matures
through March 2010, $4.2 million matures through March 2011 and $0.3 million matures through
March 2015. |
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.
For further discussion of derivative instruments and fair value measurements, see the “Critical Accounting Estimates” section of Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report. Also, see Notes B and C of the Notes to Consolidated Financial Statements
in this Quarterly Report.
Value-at-Risk (VAR) Disclosure of Market Risk - The potential impact on our future earnings, as measured by VAR, was $8.2 million and $12.5 million at September 30, 2009 and 2008, respectively. The following table
sets forth the average, high and low VAR calculations for the periods indicated:
| |
|
Three Months Ended |
|
|
Nine Months Ended |
|
| |
|
September 30, |
|
|
September 30, |
|
|
Value-at-Risk |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
| |
(Millions of dollars) |
|
Average |
|
$ |
6.8 |
|
|
$ |
12.0 |
|
|
$ |
8.6 |
|
|
$ |
12.4 |
|
|
High |
|
$ |
9.1 |
|
|
$ |
15.0 |
|
|
$ |
14.1 |
|
|
$ |
17.7 |
|
|
Low |
|
$ |
4.6 |
|
|
$ |
7.7 |
|
|
$ |
4.6 |
|
|
$ |
6.5 |
|
Quarterly Evaluation of Disclosure Controls and Procedures - As of the end of the period covered by this report, our Chief Executive Officer (Principal Executive Officer) and Chief Financial Officer (Principal Financial Officer) evaluated the effectiveness of our disclosure controls and
procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is accumulated and communicated to management, including our principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. Based on their
evaluation, they concluded that as of September 30, 2009, our disclosure controls and procedures were effective in ensuring that the information required to be disclosed by us in the reports 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.
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 third quarter ended September 30, 2009, that have materially affected, or are
reasonably likely to materially affect, our internal control over financial reporting.
PART II - OTHER INFORMATION
Additional information about our legal proceedings is included under Part I, Item 3, Legal Proceedings, in our Annual Report.
Will Price, et al. v. Gas Pipelines, et al. (f/k/a Quinque Operating Company, et al. v. Gas Pipelines, et al.), 26th Judicial District, District Court of Stevens County, Kansas, Civil Department, Case No. 99C30
(“Price I”) - As previously reported, we, our division, Oklahoma Natural Gas, four subsidiaries of ONEOK Partners, Mid-Continent Market Center, L.L.C., ONEOK Field Services Company, L.L.C., ONEOK WesTex Transmission, L.L.C. and ONEOK Hydrocarbon, L.P. (formerly Koch Hydrocarbon, LP, successor to Koch Hydrocarbon Company), as well as approximately 225 other defendants, are defending against a lawsuit claiming underpayment of gas purchase proceeds. The plaintiffs initially asserted
that the defendants understated both the volume and the heating content of the purchased gas, and sought class certification for gas producers and royalty owners throughout the United States. The Court refused to certify the class that resulted in the plaintiffs amending their petition to limit the purported class to gas producers and royalty owners in Kansas, Colorado and Wyoming, and limiting the claim to undermeasurement of volume. Oral arguments on the plaintiffs’ motion to certify
this suit as a class action were conducted on April 1, 2005. On September 18, 2009, the Court denied the plaintiffs’ motions for class certification, which, in effect, limited the named plaintiffs to pursuing individual claims against only those defendants who purchased or measured their gas. On October 2, 2009, the plaintiffs filed a motion for reconsideration of the Court’s denial of class certification. Briefing, oral arguments and a ruling by the Court on this
motion are pending.
Will Price and Stixon Petroleum, et al. v. Gas Pipelines, et al., 26th Judicial District, District Court of Stevens County, Kansas, Civil Department, Case No. 03C232 (“Price II”) - As
previously reported, 21 groups of defendants, including us, our division, Oklahoma Natural Gas, four subsidiaries of ONEOK Partners, Mid-Continent Market Center, L.L.C., ONEOK Field Services Company, L.L.C., ONEOK WesTex Transmission, L.L.C. and ONEOK Hydrocarbon, L.P. (formerly Koch Hydrocarbon, LP, successor to Koch Hydrocarbon Company), are defending against a lawsuit claiming underpayment of gas producers and royalty owners by allegedly understating the heating content of purchased gas in Kansas, Colorado
and Wyoming. This action was filed by the plaintiffs after the Court denied the initial motion for class status in Price I, and Price II was consolidated with Price I to determine whether either or both cases may properly be certified. Oral arguments on the plaintiffs’ motion to certify this suit as a class action were conducted on April 1, 2005. On September 18, 2009, the Court denied the plaintiffs’ motions for class certification, which, in effect, limited the named
plaintiffs to pursuing individual claims against only those defendants who purchased or measured their gas. On October 2, 2009, the plaintiffs filed a motion for reconsideration of the Court’s denial of class certification. Briefing, oral arguments and a ruling by the Court on this motion are pending.
Mont Belvieu Emissions, Texas Commission on Environmental Quality - As previously reported, personnel of ONEOK Hydrocarbon Southwest, L.L.C. (OHSL), a subsidiary of ONEOK Partners, are in discussions with
the Texas Commission on Environmental Quality (TCEQ) staff regarding air emissions at ONEOK Partners’ Mont Belvieu fractionator, which may have exceeded the emissions allowed under its air permit. On March 13, 2009, the TCEQ issued a Notice of Enforcement,
alleging that OHSL failed to isolate the source of the emissions in a timely manner. In a letter dated April 15, 2009, the TCEQ proposed settling the matter by entering into an Agreed Order with an administrative penalty of $160,000 and requiring OHSL to perform certain preventative procedures. OHSL has tentatively reached an agreement
with the TCEQ staff on the terms of a settlement under which it would pay $160,000. Half of the payment obligation would be satisfied by contributions to two local environmental projects in Texas. OHSL expects to enter into an Agreed Order memorializing the settlement, which will be subject to approval by the TCEQ, in early November 2009.
Gas Index Pricing Litigation - As previously reported, we, our subsidiary, ONEOK Energy Services Company, L.P. (“OESC”) and one other affiliate are defending, either individually or together,
against multiple lawsuits claiming damages resulting from the alleged market manipulation or false reporting of prices to gas index publications by us and others. On April 27, 2009, the Tennessee Supreme Court granted the defendants’ (including our and OESC’s) application to appeal the decision of the Tennessee Court of Appeals that reversed the trial court’s granting of the defendants’ motion to dismiss in the Samuel P. Leggett,
et al. v. Duke Energy Corporation, et al., case. Briefing on the appeal has been completed, and a hearing before the Tennessee Supreme Court is scheduled for November 2009.
Additionally, on May 6, 2009, the NewPage Wisconsin System Inc. v. CMS Energy Resource Management Company, et al., case was transferred to a multi-district litigation matter in the United States District Court for the District of Nevada for further proceedings. We continue
to vigorously defend all claims made in these cases.
Our investors should consider the risks set forth in Part I, Item 1A, Risk Factors of our Annual Report that could affect us and our business. Although we have tried to discuss key factors, our investors need to be aware that other risks may prove to be important in the future. New risks may emerge at any time, and we
cannot predict such risks or estimate the extent to which they may affect our financial performance. Investors should carefully consider the discussion of risks and the other information included or incorporated by reference in this Quarterly Report, including “Forward-Looking Statements,” which are included in Part I, Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
ISSUER PURCHASES OF EQUITY SECURITIES
The following table sets forth information relating to our purchases of our common stock for the periods shown:
|
Period |
Total Number of Shares
Purchased |
Average Price
Paid per Share |
|
Total Number of
Shares Purchased as
Part of Publicly
Announced Plans or
Programs |
|
Maximum Number (or
Approximate Dollar Value) of
Shares (or Units) that May
Be Purchased Under the
Plans or Programs |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
July 1-31, 2009 |
|
2,800 |
(a) |
|
$14.58 |
|
|
|
- |
|
|
|
- |
|
|
|
August 1-31, 2009 |
|
16,751 |
(a), (b) |
|
$18.84 |
|
|
|
- |
|
|
|
- |
|
|
|
September 1-30, 2009 |
|
21,959 |
(a), (b) |
|
$30.13 |
|
|
|
- |
|
|
|
- |
|
|
|
Total |
|
41,510 |
|
|
$24.52 |
|
|
|
- |
|
|
|
- |
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) - Includes shares withheld pursuant to attestation of ownership and deemed tendered to us in connection with the exercise |
|
of stock options under the ONEOK, Inc. Long-Term Incentive Plan, as follows |
|
|
|
|
|
|
|
2,800 shares for the period of July 1-31, 2009 |
|
|
|
|
|
|
|
|
|
|
|
|
16,741 shares for the period of August 1-31, 2009 |
|
|
|
|
|
|
|
|
|
|
|
21,921 shares for the period of September 1-30, 2009 |
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(b) - Includes shares repurchased directly from employees, pursuant to our Employee Stock Award Program, as follows: |
|
10 shares for the period August 1-31, 2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
38 shares for the period September 1-30, 2009 |
|
|
|
|
|
|
|
|
|
|
|
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
Not Applicable.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not Applicable.
Not Applicable.
Readers of this report should not rely on or assume the accuracy of any representation or warranty or the validity of any opinion contained in any agreement filed as an exhibit to this Quarterly Report, because such representation, warranty or opinion may be subject to exceptions and qualifications contained in separate disclosure schedules,
may represent an allocation of risk between parties in the particular transaction, may be qualified by materiality standards that differ from what may be viewed as material for securities law purposes, or may no longer continue to be true as of any given date. All exhibits attached to this Quarterly Report are included for the purpose of complying with requirements of the SEC, and, other than the certifications made by our officers pursuant to the Sarbanes-Oxley Act of 2002 included as exhibits to this
Quarterly Report, all exhibits are included only to provide information to investors regarding their respective terms and should not be relied upon as constituting or providing any factual disclosures about us, any other persons, any state of affairs or other matters.
The following exhibits are filed as part of this Quarterly Report:
Exhibit No. Exhibit Description
|
|
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)). |
|
|
101.INS |
XBRL Instance Document |
|
|
101.SCH |
XBRL Taxonomy Extension Schema Document |
|
|
101.CAL |
XBRL Taxonomy Calculation Linkbase Document |
|
|
101.DEF |
XBRL Taxonomy Extension Definitions Document |
|
|
101.LAB |
XBRL Taxonomy Label Linkbase Document |
|
|
101.PRE |
XBRL Taxonomy Presentation Linkbase Document |
Attached as Exhibit 101 to this Quarterly Report are the following documents formatted in XBRL: (i) Document and Entity Information; (ii) Consolidated Statements of Income for the three and nine months ended September 30, 2009 and 2008; (iii) Consolidated Balance Sheets at September 30, 2009, and December 31, 2008; (iv) Consolidated
Statements of Cash Flows for the nine months ended September 30, 2009 and 2008; (v) Consolidated Statement of Shareholders’ Equity for the nine months ended September 30, 2009; (vi) Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2009 and 2008; and (vii) Notes to Consolidated Financial Statements.
Users of this data are advised pursuant to Rule 401 of Regulation S-T that the information contained in the XBRL documents is unaudited, and these XBRL documents are not the official publicly filed consolidated financial statements of ONEOK, Inc. The purpose of submitting these XBRL formatted documents is to test the related format
and technology, and, as a result, investors should continue to rely on the official filed version of the furnished documents and not rely on this information in making investment decisions.
In accordance with Rule 402 of Regulation S-T, the XBRL related information in Exhibit 101 to this Quarterly Report shall not be deemed to be “filed” for purposes of Section 18 of the Exchange Act, or otherwise subject to the liability of that section, and shall not be incorporated by reference into any registration statement
or other document filed under the Securities Act or the Exchange Act, except as shall be expressly set forth by specific reference in such filing. We also make available on our Web site the Interactive Data Files submitted as Exhibit 101 to this Quarterly Report.
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
| |
ONEOK, Inc.
Registrant |
|
Date: November 5, 2009 |
By: |
/s/ Curtis L. Dinan |
| |
|
Curtis L. Dinan
Senior Vice President,
Chief Financial Officer and Treasurer
(Principal Financial Officer) |