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)
|
|
|
Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets (b)
|
|
$
|
-
|
|
|
$
|
6,143
|
|
|
$
|
7,316
|
|
|
$
|
(7,476
|
)
|
|
$
|
5,983
|
|
|
Liabilities (c)
|
|
$
|
-
|
|
|
$
|
(4,444
|
)
|
|
$
|
(4,106
|
)
|
|
$
|
7,476
|
|
|
$
|
(1,074
|
)
|
|
(a) - Our derivative assets and liabilities are presented in our Consolidated Balance Sheet on a net basis. We net derivative assets and liabilities when a legally enforceable master netting arrangement exists between us and the counterparty to a derivative contract.
|
|
|
(b) - Included in derivative financial instruments in our Consolidated Balance Sheet.
|
|
|
|
|
|
|
|
|
|
|
(c) - Included in deferred credits and other liabilities in our Consolidated Balance Sheet.
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008
|
|
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Netting (a)
|
|
|
Total
|
|
|
|
|
(Thousands of dollars)
|
|
|
Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets (b)
|
|
$
|
-
|
|
|
$
|
26,131
|
|
|
$
|
37,649
|
|
|
$
|
-
|
|
|
$
|
63,780
|
|
|
(a) - Our derivative assets and liabilities are presented in our Consolidated Balance Sheet on a net basis. We net derivative assets and liabilities when a legally enforceable master netting arrangement exists between us and the counterparty to a derivative contract.
|
|
|
(b) - Included in derivative financial instruments in our Consolidated Balance Sheet.
|
|
|
|
|
|
|
|
|
|
At September 30, 2009, and December 31, 2008, we had no cash collateral held or posted under our master netting arrangements.
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 derivative instruments categorized as Level 2 include non-exchange traded fixed-price swaps for natural gas and condensate that are valued based on NYMEX-settled prices for natural gas and crude oil, respectively. Our derivative instruments categorized as Level 3 include over-the-counter fixed-price swaps for purity NGL products
and natural gas basis swaps. These swaps are valued based on information from a pricing service, the forward NYMEX curve for crude oil, correlations of specific NGL purity products to crude oil and internally developed basis curves incorporating observable and unobservable market data. We corroborate the data on which our fair value estimates are based using our market knowledge of recent transactions and day-to-day pricing fluctuations and analysis of historical relationships of data from
the pricing service compared with actual settlements and correlations. 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 cash flow hedges for which ineffectiveness is not material.
The following table sets forth a reconciliation of our Level 3 fair value measurements for the periods indicated:
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
Derivative Assets (Liabilities)
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
|
(Thousands of dollars)
|
|
|
Net assets (liabilities) at beginning of period
|
|
$
|
11,597
|
|
|
$
|
(37,704
|
)
|
|
$
|
37,649
|
|
|
$
|
(16,400
|
)
|
|
Total realized/unrealized gains (losses):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in earnings (a)
|
|
|
1,652
|
|
|
|
(3,407
|
)
|
|
|
3,738
|
|
|
|
(2,434
|
)
|
|
Included in other comprehensive income (loss)
|
|
|
(10,039
|
)
|
|
|
56,176
|
|
|
|
(38,177
|
)
|
|
|
33,899
|
|
|
Net assets (liabilities) at end of period
|
|
$
|
3,210
|
|
|
$
|
15,065
|
|
|
$
|
3,210
|
|
|
$
|
15,065
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 the end
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
of the period (a)
|
|
$
|
51
|
|
|
$
|
(3,422
|
)
|
|
$
|
51
|
|
|
$
|
(3,422
|
)
|
|
(a) - Included in revenues in our Consolidated Statements of Income.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 borrowings under our $1.0 billion amended and restated revolving credit agreement
dated March 30, 2007 (Partnership Credit Agreement), approximates the carrying value since the interest rates are periodically adjusted to reflect current market conditions.
The estimated fair value of the aggregate of our senior notes outstanding, including current maturities, was $3.3 billion at September 30, 2009. The book value of the aggregate of our senior notes outstanding, including current maturities, was $3.1 billion at September 30, 2009. The estimated fair value of the aggregate
of our senior notes outstanding has been determined using quoted market prices for similar issues with similar terms and maturities.
C. RISK MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES
Risk Management Activities
- We are sensitive to changes in natural gas, crude oil and NGL prices, principally as a result of contractual terms under which these commodities are processed, purchased and sold. We use physical forward sales and financial derivatives to secure
a certain price for a portion of our natural gas, condensate and NGL products. We follow established policies and procedures to assess risk and approve, monitor and report our risk management activities. We have not used these instruments for trading purposes. We are also subject to the risk of interest rate fluctuation in the normal course of business.
Commodity price risk
- Commodity price risk refers 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 the following commodity derivative instruments to mitigate the commodity price
risk associated with a portion of the forecasted sales of these commodities:
|
·
|
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 the movements in market prices while the other party assumes the risks and benefits of a fixed price for the commodity.
|
In our Natural Gas Gathering and Processing segment, we are exposed to commodity price risk, primarily NGLs and natural gas, as a result of receiving commodities in exchange for services associated with our POP contracts. To a lesser extent, exposures arise from the relative price differential between NGLs and natural gas, or the
gross processing spread, with respect to our keep-whole processing contracts. We are also exposed to basis risk between the various production and market locations where we buy and sell commodities. As part of our hedging strategy, we use the previously described commodity derivative instruments to minimize the impact of price fluctuations related to natural gas, NGLs and condensate. We reduce our gross processing spread exposure through a combination of physical and financial
hedges. We utilize a portion of our
POP equity natural gas as an offset, or natural hedge, to an equivalent portion of our keep-whole shrink requirements. This has the effect of converting our gross processing spread risk to NGL commodity price risk. We hedge a portion of the forecasted sales of the commodities we retain, including NGLs, natural gas and
condensate.
In our Natural Gas Pipelines segment, we are exposed to commodity price risk because our intrastate and interstate natural gas pipelines collect natural gas from our customers for operations or as part of our fee for services provided. When the amount of natural gas consumed in operations by these pipelines differs from the amount provided
by our customers, our pipelines must buy or sell natural gas, or store or use natural gas from inventory, which can expose us to commodity price risk depending on the regulatory treatment for this activity. We use physical forward sales to reduce the impact of price fluctuations related to natural gas. At September 30, 2009, we were not using any financial derivative instruments with respect to our natural gas pipeline operations.
In our Natural Gas Liquids segment, we are exposed to basis risk primarily as a result of the relative value of NGL purchases at one location and sales at another location. To a lesser extent, we are exposed to commodity price risk resulting from the relative values of the various NGL products to each other, NGLs in storage and
the relative value of NGLs to natural gas. We utilize fixed-price physical forward contracts to reduce the impact of price fluctuations related to NGLs. At September 30, 2009, we were not using any financial derivative instruments with respect to our NGL activities.
Interest rate risk
- We manage interest rate risk through the use of fixed-rate debt, floating-rate debt and, at times, 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 cash flow hedging relationship and, if so, the reason for holding it.
The table below summarizes the various ways in which we account for our derivative instruments and the impact on our consolidated financial statements:
|
|
|
Recognition and Measurement
|
|
Accounting Treatment
|
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
|
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 forecasted transaction that has been designated
as the hedged item with a cash flow hedge. We assess the effectiveness of hedging relationships quarterly by performing a regression analysis on our fair value and cash flow 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 that we elect to exempt from derivative accounting treatment.
Cash flows from futures, forwards and swaps that are accounted for as hedges are included in the same Consolidated Statement 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.
As of September 30, 2009, we had $13.5 million of derivative assets and $8.6 million of derivative liabilities, excluding the impact of netting, all of which related to commodity contracts.
As of September 30, 2009, we had fixed-price natural gas swaps with a notional quantity of 4.4 Bcf and natural gas basis swaps with a notional quantity of 4.4 Bcf. Additionally, we had fixed-price crude oil and NGL swaps with a notional quantity of 1.5 MMBbl.
Cash Flow Hedges
- At September 30, 2009, our Consolidated Balance Sheet reflected a net unrealized gain of $6.4 million in accumulated other comprehensive income (loss), with a corresponding offset in derivative financial instrument assets and liabilities that will be realized within
the next 15 months as the forecasted transactions affect earnings. If prices remain at current levels, we will recognize $7.4 million in gains over the next 12 months, and we will recognize losses of $1.0 million thereafter.
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
|
|
$
|
(1,588
|
)
|
|
$
|
(15,232
|
)
|
|
Interest rate contracts
|
|
|
1,035
|
|
|
|
1,599
|
|
|
Total gain (loss) recognized in other comprehensive
income (loss) (effective portion)
|
|
$
|
(553
|
)
|
|
$
|
(13,633
|
)
|
|
|
|
|
|
|
|
|
|
|
The following table sets 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
|
Accumulated Other Comprehensive Income
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
Hedging Relationships
|
(Loss) into Net Income (Effective Portion)
|
|
September 30, 2009
|
|
|
September 30, 2009
|
|
|
|
|
|
(Thousands of dollars)
|
|
|
Commodity contracts
|
Revenues
|
|
$
|
12,500
|
|
|
$
|
47,248
|
|
|
Interest rate contracts
|
Interest expense
|
|
|
365
|
|
|
|
1,237
|
|
|
Total gain (loss) reclassified from accumulated other comprehensive
income (loss) into net income (effective portion)
|
|
$
|
12,865
|
|
|
$
|
48,485
|
|
Ineffectiveness related to our cash flow hedges was not material for the three and nine months ended September 30, 2009 and 2008. In the event that it becomes probable that a forecasted transaction will not occur, we would discontinue cash flow hedge treatment, which would affect earnings. There were no gains or losses
due to the discontinuance of cash flow hedge treatment during the three and nine months ended September 30, 2009 and 2008.
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 not material. Interest expense savings from the amortization of terminated swaps for the nine months ended September 30, 2009 and 2008, were $2.8 million, and the remaining amortization of terminated swaps will be recognized over the following periods.
|
|
|
|
|
|
|
(Millions of dollars)
|
|
Remainder of 2009
|
|
$
|
0.9
|
|
|
2010
|
|
$
|
3.7
|
|
|
2011
|
|
$
|
0.9
|
|
At September 30, 2009, none of the interest on our fixed-rate debt was swapped to floating using interest-rate swaps.
Credit Risk
- All the commodity derivative contracts we enter into are with
ONEOK Energy Services Company, L.P. (OES), a subsidiary of ONEOK. OES enters into similar commodity derivative contracts with third parties
at our direction and on our behalf. We have an indemnification agreement with OES that indemnifies and holds OES harmless from any liability they may incur solely as a result of entering into commodity derivative contracts on our behalf. Derivative assets for which we would indemnify OES in the event of a default by the counterparty totaled $6.0 million at September 30, 2009, and were with investment-grade counterparties that are primarily in the oil and gas sector.
D. OTHER COMPREHENSIVE INCOME (LOSS)
The following table sets forth other comprehensive income (loss) for the periods indicated:
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
|
(Thousands of dollars)
|
|
|
Unrealized gains (losses) on derivatives
|
|
$
|
(553
|
)
|
|
$
|
66,661
|
|
|
$
|
(13,633
|
)
|
|
$
|
13,496
|
|
|
Less: Realized gains (losses) on derivatives
recognized in net income
|
|
|
12,865
|
|
|
|
(14,202
|
)
|
|
|
48,485
|
|
|
|
(31,067
|
)
|
|
Other
|
|
|
-
|
|
|
|
-
|
|
|
|
212
|
|
|
|
-
|
|
|
Other comprehensive income (loss)
|
|
$
|
(13,418
|
)
|
|
$
|
80,863
|
|
|
$
|
(61,906
|
)
|
|
$
|
44,563
|
|
The balance in accumulated other comprehensive income in our Consolidated Balance Sheets as of September 30, 2009, and December 31, 2008 was attributable to unrealized gains and losses on derivatives.
E. PARTNERS’ EQUITY
Equity Issuance
- In June 2009, we 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, we 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. We 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 in us. As a result of these transactions, ONEOK and its subsidiaries now hold an aggregate 45.1 percent
interest in us.
We used the proceeds from the sale of common units and the general partner contributions to repay borrowings under our Partnership Credit Agreement and for general partnership purposes.
Cash Distributions
Paid
- For the nine months ended September 30, 2009, cash distributions included $69.6 million paid to our general partner, of which $62.2 million was related to incentive distributions. The quarterly
distributions paid to our limited partners in each of the first, second and third quarters of 2009 were $1.08 per unit. These distributions pertained to the fourth quarter of 2008, first quarter of 2009 and second quarter of 2009.
Cash Distributions
Declared
- In October 2009, we declared a cash distribution of $1.09 per unit ($4.36 per unit on an annualized basis) for the third quarter of 2009, an increase of $0.01 from the previous quarter. The
distribution will be paid on November 13, 2009, to unitholders of record at the close of business on October 30, 2009.
F. CREDIT FACILITIES
Our Partnership Credit Agreement, which expires in March 2012, contains 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, these covenants include 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, our ratio of indebtedness to adjusted EBITDA was 4.7 to 1, and we were in compliance with all covenants under our Partnership Credit Agreement.
At September 30, 2009, we had $515 million of borrowings outstanding under our Partnership Credit Agreement, and under the most restrictive provisions of our Partnership Credit Agreement had $219.7 million of credit available. At September 30, 2009, we had a total of $49.2 million issued in letters of credit outside of the Partnership
Credit Agreement.
Borrowings under our Partnership 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
Debt Issuance
- In March 2009, we completed an underwritten public offering of $500 million aggregate principal amount of 8.625 percent Senior Notes due 2019 (2019 Notes).
We 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 our 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 our general partner.
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 our Partnership 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. We have no significant assets or operations other than our
investment in our wholly owned subsidiary, the Intermediate Partnership, which is also consolidated. At September 30, 2009, the Intermediate Partnership held partnership interests and the equity in our 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 us 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 our ability to place liens on our property or assets and to sell and leaseback our property.
The 2019 Notes will mature on March 1, 2019. We 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. COMMITMENTS AND CONTINGENCIES
Investment in Northern Border Pipeline
- During the nine months ended September 30, 2009, we made equity contributions of $42.3 million to Northern Border Pipeline. We do 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.
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.
I. 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
|
|
|
|
|
|
|
|
Natural Gas Gathering and Processing
|
|
$
|
1,432,781
|
|
|
$
|
1,368,223
|
|
|
Natural Gas Pipelines
|
|
|
168,316
|
|
|
|
167,625
|
|
|
Natural Gas Liquids
|
|
|
916,495
|
|
|
|
879,047
|
|
|
Other
|
|
|
5,432
|
|
|
|
50,474
|
|
|
Regulated
|
|
|
|
|
|
|
|
|
|
Natural Gas Pipelines
|
|
|
1,506,122
|
|
|
|
1,460,764
|
|
|
Natural Gas Liquids
|
|
|
2,221,616
|
|
|
|
1,882,546
|
|
|
Property, plant and equipment
|
|
|
6,250,762
|
|
|
|
5,808,679
|
|
|
Accumulated depreciation and amortization
|
|
|
933,264
|
|
|
|
875,279
|
|
|
Net property, plant and equipment
|
|
$
|
5,317,498
|
|
|
$
|
4,933,400
|
|
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)
|
|
Natural Gas Gathering and Processing
|
|
$
|
59,573
|
|
|
$
|
135,252
|
|
|
Natural Gas Pipelines
|
|
|
35,544
|
|
|
|
107,686
|
|
|
Natural Gas Liquids
|
|
|
239,938
|
|
|
|
566,843
|
|
|
Other
|
|
|
817
|
|
|
|
197
|
|
|
Total construction work in process
|
|
$
|
335,872
|
|
|
$
|
809,978
|
|
J. SEGMENTS
Segment Descriptions
- As a result of increased integration within our natural gas liquids business, we implemented changes to the structure of our previous reportable business segments during the third quarter of 2009 to better align them with how we manage our businesses. Our
financial results are now reported in these three segments: (i) Natural Gas Gathering and Processing; (ii) Natural Gas Pipelines, both of which remain unchanged; and (iii) Natural Gas Liquids, which is comprised of our former natural gas liquids gathering and fractionation segment and our former natural gas liquids pipelines segment. Prior period amounts have been recast to reflect these segment changes.
Our operations are divided into three reportable business segments based on similarities in economic characteristics, products and services, types of customers, methods of distribution and regulatory environment, as follows:
|
·
|
our Natural Gas Gathering and Processing segment primarily gathers and processes unprocessed natural gas;
|
|
·
|
our Natural Gas Pipelines segment primarily operates regulated interstate and intrastate natural gas transmission pipelines and natural gas storage facilities; and
|
|
·
|
our Natural Gas Liquids segment primarily gathers, treats, fractionates and transports NGLs and stores, markets and distributes NGL products.
|
Accounting Policies
- The accounting policies of the segments are the same as those described in Note A and Note L of the Notes to Consolidated Financial Statements in our Annual Report. Intersegment and affiliate sales are recorded on the same basis as sales to unaffiliated
customers. Net margin is comprised of total revenues less cost of sales and fuel. Cost of sales and fuel includes commodity purchases, fuel and transportation costs.
Customers
- For the three and nine months ended September 30, 2009, and three months ended September 30, 2008, we had no single unaffiliated customer from which we received 10 percent or more of our consolidated revenues. We had one unaffiliated customer from which we received
$686.3 million, or approximately 11 percent, of our consolidated revenues, for the nine months ended September 30, 2008. All of these revenues pertained to our Natural Gas Liquids segment.
For the three and nine months ended September 30, 2009 and 2008, sales to affiliated customers were less than 10 percent of our consolidated revenues. See Note M for additional information about our sales to affiliated customers.
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
|
|
Natural Gas
Gathering and Processing
|
|
|
Natural Gas
Pipelines (a)
|
|
|
Natural Gas
Liquids (b)
|
|
|
Other and
Eliminations
|
|
|
Total
|
|
|
|
|
(Thousands of dollars)
|
|
|
Sales to unaffiliated customers
|
|
$
|
91,349
|
|
|
$
|
68,523
|
|
|
$
|
1,283,549
|
|
|
$
|
-
|
|
|
$
|
1,443,421
|
|
|
Sales to affiliated customers
|
|
|
86,676
|
|
|
|
29,906
|
|
|
|
-
|
|
|
|
-
|
|
|
|
116,582
|
|
|
Intersegment revenues
|
|
|
84,751
|
|
|
|
213
|
|
|
|
5,640
|
|
|
|
(90,604
|
)
|
|
|
-
|
|
|
Total revenues
|
|
$
|
262,776
|
|
|
$
|
98,642
|
|
|
$
|
1,289,189
|
|
|
$
|
(90,604
|
)
|
|
$
|
1,560,003
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net margin
|
|
$
|
89,342
|
|
|
$
|
75,938
|
|
|
$
|
128,917
|
|
|
$
|
(1,318
|
)
|
|
$
|
292,879
|
|
|
Operating costs
|
|
|
33,559
|
|
|
|
22,869
|
|
|
|
49,557
|
|
|
|
(877
|
)
|
|
|
105,108
|
|
|
Depreciation and amortization
|
|
|
15,312
|
|
|
|
10,607
|
|
|
|
15,944
|
|
|
|
(6
|
)
|
|
|
41,857
|
|
|
Gain (loss) on sale of assets
|
|
|
(253
|
)
|
|
|
(730
|
)
|
|
|
(144
|
)
|
|
|
(53
|
)
|
|
|
(1,180
|
)
|
|
Operating income (loss)
|
|
$
|
40,218
|
|
|
$
|
41,732
|
|
|
$
|
63,272
|
|
|
$
|
(488
|
)
|
|
$
|
144,734
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity earnings from investments
|
|
$
|
8,396
|
|
|
$
|
11,039
|
|
|
$
|
619
|
|
|
$
|
-
|
|
|
$
|
20,054
|
|
|
Capital expenditures
|
|
$
|
23,230
|
|
|
$
|
14,000
|
|
|
$
|
131,820
|
|
|
$
|
346
|
|
|
$
|
169,396
|
|
|
(a) - Our Natural Gas Pipelines segment has regulated and non-regulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $81.3 million, net margin of $59.9 million and operating income of $31.7 million.
|
|
|
(b) - Our Natural Gas Liquids segment has regulated and non-regulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $66.8 million, of which $42.4 million related to sales within the segment, net margin of $50.5 million and operating income of $22.4 million.
|
|
|
Three Months Ended
September 30, 2008
|
|
Natural Gas
Gathering and Processing
|
|
|
Natural Gas
Pipelines (a)
|
|
|
Natural Gas
Liquids (b)
|
|
|
Other and
Eliminations
|
|
|
Total
|
|
|
|
|
(Thousands of dollars)
|
|
|
Sales to unaffiliated customers
|
|
$
|
129,305
|
|
|
$
|
55,528
|
|
|
$
|
1,847,464
|
|
|
$
|
48
|
|
|
$
|
2,032,345
|
|
|
Sales to affiliated customers
|
|
|
178,167
|
|
|
|
30,595
|
|
|
|
-
|
|
|
|
-
|
|
|
|
208,762
|
|
|
Intersegment revenues
|
|
|
190,403
|
|
|
|
567
|
|
|
|
6,194
|
|
|
|
(197,164
|
)
|
|
|
-
|
|
|
Total revenues
|
|
$
|
497,875
|
|
|
$
|
86,690
|
|
|
$
|
1,853,658
|
|
|
$
|
(197,116
|
)
|
|
$
|
2,241,107
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net margin
|
|
$
|
111,720
|
|
|
$
|
65,762
|
|
|
$
|
148,384
|
|
|
$
|
(466
|
)
|
|
$
|
325,400
|
|
|
Operating costs
|
|
|
35,651
|
|
|
|
23,852
|
|
|
|
37,940
|
|
|
|
45
|
|
|
|
97,488
|
|
|
Depreciation and amortization
|
|
|
12,533
|
|
|
|
8,607
|
|
|
|
9,262
|
|
|
|
6
|
|
|
|
30,408
|
|
|
Gain (loss) on sale of assets
|
|
|
2
|
|
|
|
-
|
|
|
|
20
|
|
|
|
-
|
|
|
|
22
|
|
|
Operating income (loss)
|
|
$
|
63,538
|
|
|
$
|
33,303
|
|
|
$
|
101,202
|
|
|
$
|
(517
|
)
|
|
$
|
197,526
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity earnings from investments
|
|
$
|
8,819
|
|
|
$
|
20,207
|
|
|
$
|
386
|
|
|
$
|
-
|
|
|
$
|
29,412
|
|
|
Capital expenditures
|
|
$
|
35,769
|
|
|
$
|
107,822
|
|
|
$
|
191,989
|
|
|
$
|
-
|
|
|
$
|
335,580
|
|
|
(a) - Our Natural Gas Pipelines segment has regulated and non-regulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $71.2 million, net margin of $52.8 million and operating income of $25.9 million.
|
|
|
(b) - Our Natural Gas Liquids segment has regulated and non-regulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $33.6 million, of which $23.7 million related to sales within the segment, net margin of $29.3 million and operating income of $11.0 million.
|
|
|
Nine Months Ended
September 30, 2009
|
|
Natural Gas
Gathering and Processing
|
|
|
Natural Gas
Pipelines (a)
|
|
|
Natural Gas
Liquids (b)
|
|
|
Other and
Eliminations
|
|
|
Total
|
|
|
|
|
(Thousands of dollars)
|
|
|
Sales to unaffiliated customers
|
|
$
|
227,162
|
|
|
$
|
168,733
|
|
|
$
|
3,443,743
|
|
|
$
|
-
|
|
|
$
|
3,839,638
|
|
|
Sales to affiliated customers
|
|
|
289,596
|
|
|
|
78,691
|
|
|
|
-
|
|
|
|
-
|
|
|
|
368,287
|
|
|
Intersegment revenues
|
|
|
236,362
|
|
|
|
536
|
|
|
|
15,950
|
|
|
|
(252,848
|
)
|
|
|
-
|
|
|
Total revenues
|
|
$
|
753,120
|
|
|
$
|
247,960
|
|
|
$
|
3,459,693
|
|
|
$
|
(252,848
|
)
|
|
$
|
4,207,925
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net margin
|
|
$
|
261,686
|
|
|
$
|
208,367
|
|
|
$
|
341,361
|
|
|
$
|
(3,012
|
)
|
|
$
|
808,402
|
|
|
Operating costs
|
|
|
99,418
|
|
|
|
67,533
|
|
|
|
129,833
|
|
|
|
(1,723
|
)
|
|
|
295,061
|
|
|
Depreciation and amortization
|
|
|
44,225
|
|
|
|
34,029
|
|
|
|
43,488
|
|
|
|
8
|
|
|
|
121,750
|
|
|
Gain (loss) on sale of assets
|
|
|
2,821
|
|
|
|
(727
|
)
|
|
|
(145
|
)
|
|
|
811
|
|
|
|
2,760
|
|
|
Operating income (loss)
|
|
$
|
120,864
|
|
|
$
|
106,078
|
|
|
$
|
167,895
|
|
|
$
|
(486
|
)
|
|
$
|
394,351
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity earnings from investments
|
|
$
|
20,583
|
|
|
$
|
32,802
|
|
|
$
|
2,079
|
|
|
$
|
-
|
|
|
$
|
55,464
|
|
|
Investments in unconsolidated
affiliates
|
|
$
|
326,722
|
|
|
$
|
418,137
|
|
|
$
|
29,488
|
|
|
$
|
-
|
|
|
$
|
774,347
|
|
|
Total assets
|
|
$
|
1,587,760
|
|
|
$
|
1,488,645
|
|
|
$
|
4,133,618
|
|
|
$
|
407,021
|
|
|
$
|
7,617,044
|
|
|
Noncontrolling interests in
consolidated subsidiaries
|
|
$
|
-
|
|
|
$
|
5,451
|
|
|
$
|
119
|
|
|
$
|
15
|
|
|
$
|
5,585
|
|
|
Capital expenditures
|
|
$
|
75,557
|
|
|
$
|
48,268
|
|
|
$
|
366,614
|
|
|
$
|
817
|
|
|
$
|
491,256
|
|
|
(a) - Our Natural Gas Pipelines segment has regulated and non-regulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $200.7 million, net margin of $164.3 million and operating income of $77.6 million.
|
|
|
(b) - Our Natural Gas Liquids segment has regulated and non-regulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $181.6 million, of which $112.5 million related to sales within the segment, net margin of $139.3 million and operating income of $63.2 million.
|
|
|
Nine Months Ended
September 30, 2008
|
|
Natural Gas
Gathering and Processing
|
|
|
Natural Gas
Pipelines (a)
|
|
|
Natural Gas
Liquids (b)
|
|
|
Other and
Eliminations
|
|
|
Total
|
|
|
|
|
(Thousands of dollars)
|
|
|
Sales to unaffiliated customers
|
|
$
|
366,095
|
|
|
$
|
173,442
|
|
|
$
|
5,308,029
|
|
|
$
|
49
|
|
|
$
|
5,847,615
|
|
|
Sales to affiliated customers
|
|
|
504,541
|
|
|
|
91,878
|
|
|
|
-
|
|
|
|
-
|
|
|
|
596,419
|
|
|
Intersegment revenues
|
|
|
602,542
|
|
|
|
1,338
|
|
|
|
19,573
|
|
|
|
(623,453
|
)
|
|
|
-
|
|
|
Total revenues
|
|
$
|
1,473,178
|
|
|
$
|
266,658
|
|
|
$
|
5,327,602
|
|
|
$
|
(623,404
|
)
|
|
$
|
6,444,034
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net margin
|
|
$
|
336,746
|
|
|
$
|
196,173
|
|
|
$
|
343,974
|
|
|
$
|
(2,035
|
)
|
|
$
|
874,858
|
|
|
Operating costs
|
|
|
101,538
|
|
|
|
67,900
|
|
|
|
103,746
|
|
|
|
(456
|
)
|
|
|
272,728
|
|
|
Depreciation and amortization
|
|
|
36,431
|
|
|
|
25,547
|
|
|
|
28,388
|
|
|
|
17
|
|
|
|
90,383
|
|
|
Gain (loss) on sale of assets
|
|
|
(3
|
)
|
|
|
(18
|
)
|
|
|
39
|
|
|
|
32
|
|
|
|
50
|
|
|
Operating income (loss)
|
|
$
|
198,774
|
|
|
$
|
102,708
|
|
|
$
|
211,879
|
|
|
$
|
(1,564
|
)
|
|
$
|
511,797
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity earnings from investments
|
|
$
|
23,989
|
|
|
$
|
49,421
|
|
|
$
|
1,395
|
|
|
$
|
-
|
|
|
$
|
74,805
|
|
|
Investments in unconsolidated
affiliates
|
|
$
|
323,537
|
|
|
$
|
403,373
|
|
|
$
|
29,539
|
|
|
$
|
-
|
|
|
$
|
756,449
|
|
|
Total assets
|
|
$
|
1,593,872
|
|
|
$
|
1,371,178
|
|
|
$
|
3,669,801
|
|
|
$
|
357,444
|
|
|
$
|
6,992,295
|
|
|
Noncontrolling interests in
consolidated subsidiaries
|
|
$
|
-
|
|
|
$
|
5,800
|
|
|
$
|
132
|
|
|
$
|
15
|
|
|
$
|
5,947
|
|
|
Capital expenditures
|
|
$
|
98,604
|
|
|
$
|
159,810
|
|
|
$
|
601,688
|
|
|
$
|
65
|
|
|
$
|
860,167
|
|
|
(a) - Our Natural Gas Pipelines segment has regulated and non-regulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $221.7 million, net margin of $155.0 million and operating income of $76.9 million.
|
|
|
(b) - Our Natural Gas Liquids segment has regulated and non-regulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $104.1 million, of which $67.2 million related to sales within the segment, net margin of $86.8 million and operating income of $33.6 million.
|
|
K. UNCONSOLIDATED AFFILIATES
Equity Earnings from Investments
- The following table sets forth our equity earnings from investments for the periods indicated:
|
|
|
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
|
|
L. LIMITED PARTNERS’ NET INCOME PER UNIT
Limited partners’ net income per unit is computed by dividing net income attributable to ONEOK Partners, L.P., after deducting the general partner’s allocation as discussed below, by the weighted-average number of outstanding limited partner units, which includes our common and Class B limited partner units. As discussed
in Note B of the Notes to Consolidated Financial Statements in our Annual Report, ONEOK, as sole holder of our Class B units, has waived its right to receive increased quarterly distributions on the Class B units. Because ONEOK has waived its right to increased quarterly distributions, currently each Class B unit and common unit share equally in the earnings of the partnership, and neither has any liquidation or other preferences. ONEOK retains the option to withdraw its waiver at any time
by giving us no less than 90 days advance notice. ONEOK Partners GP owns the entire 2 percent general partnership interest in us, which entitles it to incentive distribution rights that provide for an increasing proportion of cash distributions from the partnership as the distributions made to limited partners increase above specified levels.
For purposes of our calculation of limited partners’ net income per unit, net income attributable to ONEOK Partners, L.P. is generally allocated to the general partner as follows: (i) an amount based upon the 2 percent general partner interest in net income attributable to ONEOK Partners, L.P. and (ii) the amount of the general partner’s
incentive distribution rights based on the total cash distributions declared for the period. The amount of incentive distribution allocated to our general partner totaled $22.5 million and $64.3 million for the three and nine months ended September 30, 2009, respectively. The amount of incentive distribution allocated to our general partner totaled $20.3 million and $55.7 million for the three and nine months ended September 30, 2008, respectively.
The terms of our Partnership Agreement limit the general partner’s incentive distribution to the amount of available cash calculated for the period. As such, incentive distribution rights are not allocated on undistributed earnings or distributions in excess of earnings. Gains resulting from interim capital transactions,
as defined in our Partnership Agreement, are generally not subject to distribution; however, our Partnership Agreement provides that if such distributions were made, the ince