Exhibit 99.1
| November 2, 2010 | | Analyst Contact: | Andrew Ziola |
| | | | 918-588-7163 |
| | | Media Contact: | Brad Borror |
| | | | 918-588-7582 |
ONEOK Partners Reports Higher Third-quarter 2010 Financial Results
TULSA, Okla. – Nov. 2, 2010 – ONEOK Partners, L.P. (NYSE: OKS) today announced third-quarter 2010 earnings of $1.09 per unit, compared with $1.00 per unit for the third quarter 2009. Net income attributable to ONEOK Partners was $141.5 million for the third quarter 2010, compared with $121.5 million for the same period in 2009.
Year-to-date 2010 net income attributable to ONEOK Partners was $330.4 million, or $2.41 per unit, compared with $318.6 million, or $2.67 per unit, for the nine-month period a year earlier. Third-quarter and nine-month 2010 results include a $16.3 million gain on the sale of a 49 percent interest in Overland Pass Pipeline Company, LLC to Williams Partners L.P.
There were approximately 101.9 million units outstanding for the third quarter 2010, compared with 96.4 million units outstanding for the same period last year. An equity offering in February 2010 included the issuance of approximately 5.5 million additional units.
“The partnership’s business segments posted solid results in the third quarter driven by strong volume growth from our $2 billion-plus capital-investment program completed last year,” said John W. Gibson, chairman, president and chief executive officer of ONEOK Partners.
“Our recently announced plans to invest up to $1.5 billion over the next three years in the natural gas liquids and natural gas gathering and processing segments to meet the needs of producers in the prolific Bakken Shale in the Williston Basin establish a strong foundation for the next phase of earnings growth,” Gibson added.
In the third quarter 2010, earnings before interest, taxes, depreciation and amortization (EBITDA) were $236.7 million, compared with $211.4 million in the third quarter 2009. Distributable cash flow (DCF) for the third quarter 2010 was $156.0 million, compared with $144.1 million in the third quarter 2009.
Year-to-date 2010 EBITDA was $630.4 million, compared with $577.7 million in the same period last year. DCF for the first nine months of 2010 was $417.8 million, compared with $409.6 million in the same period last year.
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ONEOK Partners Reports Higher Third-quarter 2010 Results
November 2, 2010
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Operating income for the third quarter 2010 was $160.5 million, compared with $144.7 million for the third quarter 2009. For the first nine months of 2010, operating income was $426.6 million, compared with $394.4 million in the prior-year period.
The increases in operating income for both the three- and nine-month 2010 periods reflect the gain on the sale of a 49 percent ownership interest in Overland Pass Pipeline Company, higher natural gas liquids (NGL) throughput, primarily from the completion of capital projects in 2009 and new supply connections in the natural gas liquids segment; higher contracted natural gas transportation capacity on the Midwestern Gas Transmission and Viking Gas Transmission pipelines and the impact of higher natural gas prices on retained fuel in the natural gas pipelines segment; and higher storage margins, primarily as a result of contract renegotiations in the natural gas pipelines and natural gas liquids segments.
These increases were offset by lower optimization margins in the natural gas liquids segment due to limited NGL fractionation and transportation capacity available for optimization activities and narrower NGL product price differentials between the Conway, Kan., and Mont Belvieu, Texas, NGL market centers; and lower natural gas volumes gathered in the Powder River Basin in the natural gas gathering and processing segment.
Operating costs were $97.8 million in the third quarter 2010, compared with $105.1 million in the same period last year. Operating costs for the nine-month 2010 period were $292.1 million, compared with $295.1 million for the same period last year. The decreases for both the three- and nine-month 2010 periods were due primarily to lower property taxes associated with the capital projects completed in 2009 and lower costs for outside services. For the nine-month period, these decreases were offset partially by higher property insurance costs and higher employee-related costs.
Depreciation and amortization expense for the third quarter 2010 was $43.8 million, compared with $41.9 million in the same period a year earlier. Depreciation and amortization expense for the nine-month 2010 period was $131.7 million, compared with $121.8 million in the same period last year. These increases were due primarily to the completion of capital projects last year.
Equity earnings from investments were $29.4 million in the third quarter 2010, compared with $20.1 million in the same period in 2009. Nine-month 2010 equity earnings from investments were $71.2 million, compared with $55.5 million in the same period last year. The increases were due to increased contracted capacity on Northern Border Pipeline, of which the partnership owns 50 percent.
Allowance for equity funds used during construction for the third quarter 2010 was $0.3 million, compared with $7.3 million in the same period last year. Allowance for equity funds used during construction for the nine-month 2010 period was $0.7 million, compared with $25.8 million in the same period last year. These decreases were due primarily to the completion of capital projects last year.
ONEOK Partners Reports Higher Third-quarter 2010 Results
November 2, 2010
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> View earnings tables
THIRD-QUARTER 2010 SUMMARY INCLUDES:
| · | Operating income of $160.5 million, compared with $144.7 million in the third quarter 2009; |
| · | Natural gas gathering and processing segment operating income of $38.2 million, compared with $40.2 million in the third quarter 2009; |
| · | Natural gas pipelines segment operating income of $39.0 million, compared with $41.7 million in the third quarter 2009; |
| · | Natural gas liquids segment operating income of $83.2 million, which included a $16.3 million gain on the sale of a 49 percent interest in Overland Pass Pipeline Company, LLC to Williams Partners L.P., compared with $63.3 million in the third quarter 2009; |
| · | Equity earnings from investments of $29.4 million, compared with $20.1 million in the third quarter 2009; |
| · | Announcing in October $300 million to $355 million in growth projects in the natural gas gathering and processing segment, including the construction of the Stateline I plant, a new 100 million cubic feet per day (MMcf/d) natural gas processing facility in the Bakken Shale in the Williston Basin, and related NGL infrastructure; |
| · | Announcing in July $595 million to $730 million in growth projects in the natural gas liquids segment, including the construction of a 525- to 615-mile NGL pipeline with an initial capacity to transport 60,000 barrels per day (bpd) of unfractionated NGLs from the Bakken Shale in the Williston Basin to the Overland Pass Pipeline; an expansion of the capacity of Overland Pass Pipeline to 255,000 bpd; and a 60,000 bpd expansion of fractionation capacity at Bushton, Kan.; |
| · | Announcing in July plans to invest $36 million to increase the capacity of the Sterling I natural gas liquids distribution pipeline by 15,000 bpd; |
| · | Receiving $423.7 million in September from Williams Partners L.P. to increase its ownership of Overland Pass Pipeline Company, LLC to 50 percent from 1 percent; |
| · | Capital expenditures of $104.1 million, compared with $169.4 million in the third quarter 2009; |
| · | Having $326.4 million outstanding in commercial paper and $673.6 million available under the partnership’s $1.0 billion revolving credit facility as of Sept. 30, 2010; and |
| · | Increasing the quarterly cash distribution to $1.13 per unit from $1.12 per unit, payable on Nov. 12, 2010, to unitholders of record as of Oct. 29, 2010. |
BUSINESS-UNIT RESULTS:
Natural Gas Gathering and Processing Segment
The natural gas gathering and processing segment reported third-quarter 2010 operating income of $38.2 million, compared with $40.2 million for the third quarter 2009.
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November 2, 2010
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Third-quarter 2010 results decreased $2.4 million due to lower net realized commodity prices; $1.5 million from lower natural gas gathered volumes as a result of natural production declines and reduced drilling activity, primarily in the Powder River Basin in Wyoming; and $1.2 million due to lower natural gas volumes processed and sold in western Oklahoma and Kansas driven partially by an operational outage, a period of ethane rejection and natural production declines.
These decreases were offset partially by a $2.2 million increase as a result of a favorable contract settlement in the third quarter 2010 and a $1.3 million increase due to changes in contract terms.
Operating costs in the third quarter 2010 were $34.1 million, compared with $33.6 million in the same period last year. The increase was due primarily to higher costs for outside services associated with increased operating activities in the Williston Basin resulting from increased drilling activity.
Operating income for the nine-month 2010 period was $114.1 million in 2010, compared with $120.9 million in the same period last year.
Nine-month 2010 results reflect a $5.3 million decrease due to lower natural gas gathered volumes as a result of natural production declines and reduced drilling activity, primarily in the Powder River Basin in Wyoming, and a $1.2 million decrease as a result of changes in contract terms. These decreases were offset partially by a $3.1 million increase due to higher net realized commodity prices compared with the same period last year.
Nine-month 2010 operating costs were $98.4 million, compared with $99.4 million in the same period last year. The decrease was due primarily to lower costs for outside services and maintenance as a result of reduced drilling activity in the Powder River Basin.
NGL shrink, plant fuel and condensate shrink discussed in the table below refer to the British thermal units (Btus) that are removed from natural gas through the gathering and processing operation and does not include volumes from the partnership’s equity investments. The following table contains operating information for the periods indicated:
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| | | | | | | | | | | | | |
| | | Three Months Ended | | | Nine Months Ended | |
| | | September 30, | | | September 30, | |
| Operating Information (a) | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| Percent of proceeds | | | | | | | | | | | | |
NGL sales (Bbl/d) | | | 6,966 | | | | 5,408 | | | | 5,933 | | | | 5,215 | |
Residue gas sales (MMBtu/d) | | | 40,603 | | | | 46,406 | | | | 40,852 | | | | 41,698 | |
Condensate sales (Bbl/d) | | | 1,482 | | | | 1,488 | | | | 1,761 | | | | 1,786 | |
| Percentage of total net margin | | | 56 | % | | | 50 | % | | | 55 | % | | | 49 | % |
| Fee-based | | | | | | | | | | | | | | | | |
Wellhead volumes (MMBtu/d) | | | 1,046,475 | | | | 1,100,202 | | | | 1,075,491 | | | | 1,131,018 | |
Average rate ($/MMBtu) | | $ | 0.31 | | | $ | 0.31 | | | $ | 0.31 | | | $ | 0.30 | |
| Percentage of total net margin | | | 35 | % | | | 35 | % | | | 35 | % | | | 36 | % |
| Keep-whole | | | | | | | | | | | | | | | | |
NGL shrink (MMBtu/d) (b) | | | 13,443 | | | | 16,843 | | | | 13,800 | | | | 17,875 | |
Plant fuel (MMBtu/d) (b) | | | 1,667 | | | | 1,954 | | | | 1,639 | | | | 2,100 | |
Condensate shrink (MMBtu/d) (b) | | | 1,222 | | | | 1,407 | | | | 1,531 | | | | 1,893 | |
Condensate sales (Bbl/d) | | | 247 | | | | 285 | | | | 310 | | | | 383 | |
| Percentage of total net margin | | | 9 | % | | | 15 | % | | | 10 | % | | | 15 | % |
| (a) - Includes volumes for consolidated entities only. | | | | | | | | | | | | | |
| (b) - Refers to the Btus that are removed from natural gas through processing operation. | | | | | |
The natural gas gathering and processing segment is exposed to commodity price risk as a result of receiving commodities in exchange for services. The following tables provide hedging information in the natural gas gathering and processing segment for the remainder of 2010 and for 2011:
| | | | | | | | | | | | |
| | | Three Months Ending | | |
| | | December 31, 2010 | | |
| | | Volumes Hedged | | Average Price | | Percentage Hedged | |
| NGLs (Bbl/d) (a) | | | 5,267 | | | $ | 1.05 | | / gallon | | 61% | | |
| Condensate (Bbl/d) (a) | | | 1,820 | | | $ | 1.84 | | / gallon | | 79% | | |
| Total (Bbl/d) | | | 7,087 | | | $ | 1.25 | | / gallon | | 65% | | |
| Natural gas (MMBtu/d) | | | 24,020 | | | $ | 5.55 | | / MMBtu | | 99% | | |
| (a) - Hedged with fixed-price swaps. | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | Year Ending | | |
| | | December 31, 2011 | | |
| | | Volumes Hedged | | Average Price | | Percentage Hedged | | |
| NGLs (Bbl/d) (a) | | | 1,316 | | | $ | 1.04 | | / gallon | | 15% | | |
| Condensate (Bbl/d) (a) | | | 596 | | | $ | 2.12 | | / gallon | | 26% | | |
| Total (Bbl/d) | | | 1,912 | | | $ | 1.37 | | / gallon | | 18% | | |
| Natural gas (MMBtu/d) | | | 22,541 | | | $ | 5.72 | | / MMBtu | | 74% | | |
| (a) - Hedged with fixed-price swaps. | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
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The partnership’s natural gas gathering and processing segment currently estimates that a 1 cent per gallon change in the composite price of NGLs would change annual net margin by approximately $1.2 million. A $1.00 per barrel change in the price of crude oil would change annual net margin by approximately $1.1 million. Also, a 10 cent per million British thermal unit (MMBtu) change in the price of natural gas would change annual net margin by approximately $1.0 million. All of these sensitivities exclude the effects of hedging and assume normal operating conditions.
Natural Gas Pipelines Segment
The natural gas pipelines segment reported third-quarter 2010 operating income of $39.0 million, compared with $41.7 million for the third quarter 2009.
Third-quarter 2010 results reflect a $3.2 million decrease in operational natural gas inventory sales volumes and margins, offset partially by a $2.3 million increase from the effect of higher natural gas prices on retained fuel and higher natural gas fuel volumes retained.
Operating costs were $24.9 million in the third quarter 2010, compared with $22.9 million in the same period last year. The increase was due primarily to higher employee-related costs and the timing of various maintenance activities.
Operating income for the first nine months of 2010 was $122.1 million, compared with $106.1 million in the same period in 2009.
Nine-month 2010 results reflect an $11.3 million increase from increased transportation margins, primarily as a result of increased contracted transportation capacity on the Midwestern Gas Transmission pipeline as a result of a new interconnection with the Rockies Express Pipeline that was completed in June 2009, the Viking Gas Transmission Fargo lateral pipeline that was completed in October 2009 and the Guardian Pipeline expansion and extension project that was completed in February 2009; a $5.6 million increase from the effect of higher natural gas prices on retained fuel, offset partially by lower natural gas fuel volumes retained; and a $3.4 million increase from higher natural gas storage margins, primarily as a result of contract renegotiations.
These increases were offset partially by a $3.3 million decrease in operational natural gas inventory sales volumes and margins.
Nine-month 2010 operating costs were $71.3 million, compared with $67.5 million in the same period last year, due primarily to higher employee-related costs and the timing of various maintenance activities.
Equity earnings from investments were $21.3 million in the third quarter 2010, compared with $11.0 million in the same period in 2009. Nine-month 2010 equity earnings from investments were $48.9 million, compared with $32.8 million in the same period last year. The increases were due to increased contracted capacity on Northern Border Pipeline, of which the partnership owns 50 percent.
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Natural Gas Liquids Segment
The natural gas liquids segment reported third-quarter 2010 operating income of $83.2 million, compared with $63.3 million for the third quarter 2009.
Third-quarter 2010 results reflect a $16.3 million gain on the sale of a 49 percent ownership interest in Overland Pass Pipeline Company; a $3.8 million increase due to higher NGL volumes gathered, fractionated and transported, associated primarily with the completion of the Arbuckle Pipeline and the lateral pipelines connected to the Overland Pass Pipeline, as well as new supply connections; and a $2.5 million increase due to higher storage margins as a result of contract renegotiations.
These third-quarter 2010 increases were offset by a $9.9 million decrease due to lower optimization margins due to narrower NGL product price differentials between the Conway and Mont Belvieu NGL market centers and limited NGL fractionation and transportation capacity available for optimization activities; and a $1.6 million decrease from the impact of operational measurement adjustments.
Additional NGL fractionation capacity, which benefits optimization activities, became available on Sept. 1, 2010, when a contract at the partnership’s Mont Belvieu, Texas, fractionator expired. Additional capacity also will become available when a 60,000 bpd fractionation services agreement with Targa Resources Partners begins in the second quarter 2011. The expansion of the Sterling I NGL distribution pipeline, expected to be completed in the second half of 2011, will enable the transportation of additional NGL purity products to the Gulf Coast market.
Operating costs were $39.4 million in the third quarter 2010, compared with $49.6 million in the third quarter 2009, due primarily to lower property taxes associated with the capital projects completed in 2009 and lower costs for outside services.
Nine-month 2010 operating income was $191.9 million, compared with $167.9 million in 2009.
Nine-month 2010 results benefited $49.2 million from higher NGL volumes gathered, fractionated and transported, associated primarily with the completion of the Arbuckle Pipeline and the lateral pipelines connected to the Overland Pass Pipeline, as well as new supply connections; a $16.3 million gain on the sale of a 49 percent ownership interest in Overland Pass Pipeline Company; and a $7.4 million increase due to higher storage margins as a result of contract negotiations. The benefits were offset partially by a $39.5 million decrease due to lower optimization margins due to limited NGL fractionation and transportation capacity available for optimization activities and narrower NGL product price differentials between the Conway and Mont Belvieu NGL market centers; and a $2.1 million decrease from operational measurement adjustments.
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Nine-month 2010 operating costs were $126.2 million, compared with $129.8 million in the same period last year, due primarily to lower property taxes associated with the capital projects completed in 2009 and lower costs for outside services, partially offset by higher property insurance costs and higher employee-related costs.
Depreciation and amortization expense increased to $17.4 million for the third quarter 2010, compared with $15.9 million for the same period in 2009. Nine-month 2010 depreciation and amortization expense was $53.7 million, compared with $43.5 million in the same period last year. These increases were due to the completion of capital projects last year.
The Conway-to-Mont Belvieu average price differential for ethane in the third quarter 2010, based on Oil Price Information Service (OPIS) pricing, was 10 cents per gallon, compared with 15 cents per gallon in the same period in 2009. For the nine months 2010, the average OPIS price differential for ethane was 11 cents per gallon, compared with 12 cents per gallon in the same period last year.
GROWTH ACTIVITIES:
During 2010, the partnership has announced approximately $1.3 billion to $1.6 billion in growth projects that include:
| · | Approximately $300 million to $355 million between now and the end of 2012 to construct the Stateline I plant, a new 100 MMcf/d natural gas processing facility in the Bakken Shale in the Williston Basin in North Dakota, and related NGL infrastructure; expansions and upgrades to the existing gathering and compression infrastructure; and new well connections adjacent to the Stateline I facility; |
| · | Approximately $350 million to $415 million between now and the end of 2011 to construct the Garden Creek plant, a new 100 MMcf/d natural gas processing facility in the Bakken Shale in the Williston Basin, and related expansions; and for new well connections, expansions and upgrades to the existing natural gas gathering system infrastructure; |
| · | Approximately $595 million to $730 million of natural gas liquids projects between now and 2013 that include the construction of a 525- to 615-mile NGL pipeline to transport unfractionated NGLs produced from the Bakken Shale in the Williston Basin to the Overland Pass Pipeline, a 760-mile NGL pipeline extending from southern Wyoming to Conway, Kan.; related capacity expansions for ONEOK Partners’ 50-percent interest in the Overland Pass Pipeline to transport the additional unfractionated NGL volumes from the new Bakken Pipeline; and expansion of the partnership’s fractionation capacity at Bushton, Kan., by 60,000 bpd to accommodate the additional NGL volumes; |
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| · | Approximately $36 million for the installation of seven additional pump stations along the existing Sterling I NGL distribution pipeline, increasing its capacity by 15,000 bpd, which will be supplied by Mid-Continent NGL infrastructure. Installation will begin later this year and is expected to be completed in the second half of 2011; and |
| · | Approximately $55 million investment in 2010 and 2011 in the Woodford Shale in Oklahoma, with projects in both the natural gas gathering and processing and the natural gas liquids segments. |
EARNINGS GUIDANCE:
ONEOK Partners reaffirmed its 2010 guidance that was updated on Sept. 30, 2010. Net income is expected to be in the range of $450 million to $470 million, compared with its previous range of $450 million to $490 million. Estimates for the partnership’s 2010 DCF were updated and are expected to be in the range of $570 million to $590 million, compared with its previous range of $580 million to $620 million. Capital expenditures for 2010 are expected to be approximately $464 million, comprised of $394 million in growth capital and $70 million in maintenance capital. Additional information is available in Exhibits D and E in the guidance tables on the ONEOK Partners website.
In October, ONEOK Partners announced it expects average annual EBITDA growth of 14-18 percent for 2011-2013, resulting in a 1 cent per quarter distribution increase to unitholders in 2011 and 5-10 percent annual distribution growth in 2012 and 2013.
EARNINGS CONFERENCE CALL AND WEBCAST:
ONEOK Partners and ONEOK management will conduct a joint conference call on Wednesday, Nov. 3, 2010, at 11 a.m. Eastern Daylight Time (10 a.m. Central Daylight Time). The call will also be carried live on ONEOK Partners’ and ONEOK’s websites.
To participate in the telephone conference call, dial 866-238-1641, pass code 1488606, or log on to www.oneokpartners.com or www.oneok.com.
If you are unable to participate in the conference call or the webcast, the replay will be available on ONEOK Partners’ website, www.oneokpartners.com, and ONEOK’s website, www.oneok.com, for 30 days. A recording will be available by phone for seven days. The playback call may be accessed at 866-837-8032, pass code 1488606.
LINK TO EARNINGS TABLES:
http://www.oneokpartners.com/~/media/ONEOKPartners/EarningsTables/OKS_Q3_2010_Earnings_Release_
TABLES_ONLY.ashx
NON-GAAP FINANCIAL MEASURES:
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ONEOK Partners has disclosed in this news release EBITDA and DCF amounts that are non-GAAP financial measures. EBITDA and DCF are used as measures of financial performance. EBITDA is defined as net income adjusted for interest expense, depreciation and amortization, income taxes and allowance for equity funds used during construction. DCF is defined as EBITDA, computed as described above, less interest expense, maintenance capital expenditures and equity earnings from investments, adjusted for cash and certain other items.
The non-GAAP financial measures described above are useful to investors because these measurements are used by many companies in the industry as a measurement of financial performance and are commonly employed by financial analysts and others to evaluate the financial performance of the partnership and to compare the financial performance of the partnership with the performance of other publicly traded partnerships within the industry.
EBITDA and DCF should not be considered an alternative to net income, earnings per unit or any other measure of financial performance presented in accordance with GAAP.
These non-GAAP financial measures exclude some, but not all, items that affect net income. Additionally, these calculations may not be comparable with similarly titled measures of other companies. Further, these non-GAAP measures should not be viewed as indicative of the actual amount of cash that is available for distributions or planned for distribution for a given period nor do they equate to available cash as defined in the partnership agreement.
Reconciliations of these non-GAAP financial measures to net income are included in the financial tables.
ONEOK Partners, L.P. (NYSE: OKS) is one of the largest publicly traded master limited partnerships, and is a leader in the gathering, processing, storage and transportation of natural gas in the U.S. and owns one of the nation’s premier natural gas liquids (NGL) systems, connecting NGL supply in the Mid-Continent and Rocky Mountain regions with key market centers. Its general partner is a wholly owned subsidiary of ONEOK, Inc. (NYSE: OKE), a diversified energy company, which owns 42.8 percent of the overall partnership interest. ONEOK is one of the largest natural gas distributors in the United States, and its energy services operation focuses primarily on marketing natural gas and related services throughout the U.S.
Some of the statements contained and incorporated in this news release 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 news release identified by words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should,” “goal,” “forecast,” “guidance,” “could,” “may,” “continue,” “might,” “potential,” “scheduled” and other words and terms of similar meaning.
One should not place undue reliance on forward-looking statements, which are applicable only as of the date of this news release. 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
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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, including climate change, on our operations, 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 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, 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 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; |
| · | difficulties or delays experienced by trucks or pipelines in delivering products to or from our terminals or pipelines; |
| · | changes in demand for the use of natural gas because of market conditions caused by concerns about global warming; |
| · | conflicts of interest between us, our general partner, ONEOK Partners GP, and related parties of ONEOK Partners GP; |
| · | the impact of unforeseen changes in interest rates, equity markets, inflation rates, economic recession and other external factors over which we have no control; |
| · | 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 us or the parent of our general partner; |
| · | the results of administrative proceedings and litigation, regulatory actions, rule changes and receipt of expected clearances involving the OCC, KCC, Texas regulatory authorities or any other local, state or federal regulatory body, including the FERC and the Pipeline and Hazardous Materials Safety Administration; |
| · | 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 control 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 and 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; |
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| · | our ability to control operating costs; |
| · | acts of nature, sabotage, terrorism or other similar acts that cause damage to our facilities or our suppliers’ or shippers’ facilities; |
| · | economic climate and growth in the geographic areas in which we do business; |
| · | the risk of a prolonged slowdown in growth or decline in the U.S. economy or the risk of delay in growth recovery in the U.S. economy, including liquidity risks in U.S. 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 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. OKS-FE OKE-FE
###
ONEOK Partners Reports Higher Third-quarter 2010 Results
November 2, 2010
Page 13
| | | | | | | | | | | | | |
| ONEOK Partners, L.P. and Subsidiaries | | | | | | | | | | | | |
| CONSOLIDATED STATEMENTS OF INCOME | | | | | | | | | | | | |
| | | Three Months Ended | | | Nine Months Ended | |
| | | September 30, | | | September 30, | |
| (Unaudited) | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| | (Thousands of dollars, except per unit amounts) | |
| | | | | | | | | | | | | |
| Revenues | | $ | 2,070,144 | | | $ | 1,560,003 | | | $ | 6,329,271 | | | $ | 4,207,925 | |
| Cost of sales and fuel | | | 1,784,139 | | | | 1,267,124 | | | | 5,493,979 | | | | 3,399,523 | |
| Net margin | | | 286,005 | | | | 292,879 | | | | 835,292 | | | | 808,402 | |
| Operating expenses | | | | | | | | | | | | | | | | |
| Operations and maintenance | | | 90,670 | | | | 92,855 | | | | 263,212 | | | | 258,246 | |
| Depreciation and amortization | | | 43,823 | | | | 41,857 | | | | 131,680 | | | | 121,750 | |
| General taxes | | | 7,127 | | | | 12,253 | | | | 28,851 | | | | 36,815 | |
| Total operating expenses | | | 141,620 | | | | 146,965 | | | | 423,743 | | | | 416,811 | |
| Gain (loss) on sale of assets | | | 16,126 | | | | (1,180 | ) | | | 15,081 | | | | 2,760 | |
| Operating income | | | 160,511 | | | | 144,734 | | | | 426,630 | | | | 394,351 | |
| Equity earnings from investments | | | 29,390 | | | | 20,054 | | | | 71,182 | | | | 55,464 | |
| Allowance for equity funds used during construction | | | 266 | | | | 7,290 | | | | 748 | | | | 25,761 | |
| Other income | | | 3,623 | | | | 5,026 | | | | 2,282 | | | | 8,841 | |
| Other expense | | | (600 | ) | | | (299 | ) | | | (1,341 | ) | | | (2,728 | ) |
| Interest expense | | | (49,131 | ) | | | (50,371 | ) | | | (156,613 | ) | | | (152,167 | ) |
| Income before income taxes | | | 144,059 | | | | 126,434 | | | | 342,888 | | | | 329,522 | |
| Income taxes | | | (2,362 | ) | | | (4,729 | ) | | | (12,022 | ) | | | (10,668 | ) |
| Net income | | | 141,697 | | | | 121,705 | | | | 330,866 | | | | 318,854 | |
| Less: Net income attributable to noncontrolling interests | | | 161 | | | | 212 | | | | 446 | | | | 232 | |
| Net income attributable to ONEOK Partners, L.P. | | $ | 141,536 | | | $ | 121,493 | | | $ | 330,420 | | | $ | 318,622 | |
| | | | | | | | | | | | | | | | | |
| Limited partners' interest in net income: | | | | | | | | | | | | | | | | |
| Net income attributable to ONEOK Partners, L.P. | | $ | 141,536 | | | $ | 121,493 | | | $ | 330,420 | | | $ | 318,622 | |
| General partner's interest in net income | | | (30,498 | ) | | | (25,010 | ) | | | (86,674 | ) | | | (70,710 | ) |
| Limited partners' interest in net income | | $ | 111,038 | | | $ | 96,483 | | | $ | 243,746 | | | $ | 247,912 | |
| | | | | | | | | | | | | | | | | |
| Limited partners' net income per unit, basic and diluted | | $ | 1.09 | | | $ | 1.00 | | | $ | 2.41 | | | $ | 2.67 | |
| | | | | | | | | | | | | | | | | |
Number of units used in computation (thousands) | | | 101,908 | | | | 96,402 | | | | 101,187 | | | | 92,932 | |
| | | | | | | | | | | | | | | | | |
-more-ONEOK Partners Reports Higher Third-quarter 2010 Results
November 2, 2010
Page 14
| | | | | | | |
| ONEOK Partners, L.P. and Subsidiaries | | | | | | |
| CONSOLIDATED BALANCE SHEETS | | | | | | |
| | | September 30, | | | December 31, | |
| (Unaudited) | | 2010 | | | 2009 | |
| Assets | | (Thousands of dollars) | |
| Current assets | | | | | | |
| Cash and cash equivalents | | $ | 4,991 | | | $ | 3,151 | |
| Accounts receivable, net | | | 570,781 | | | | 624,635 | |
| Affiliate receivables | | | 28,110 | | | | 32,397 | |
| Gas and natural gas liquids in storage | | | 263,385 | | | | 217,585 | |
| Commodity imbalances | | | 98,264 | | | | 188,177 | |
| Other current assets | | | 54,318 | | | | 36,148 | |
| Total current assets | | | 1,019,849 | | | | 1,102,093 | |
| | | | | | | | | |
| Property, plant and equipment | | | | | | | | |
| Property, plant and equipment | | | 5,701,670 | | | | 6,353,909 | |
| Accumulated depreciation and amortization | | | 1,065,891 | | | | 972,497 | |
| Net property, plant and equipment | | | 4,635,779 | | | | 5,381,412 | |
| | | | | | | | | |
| Investments and other assets | | | | | | | | |
| Investments in unconsolidated affiliates | | | 1,194,087 | | | | 765,163 | |
| Goodwill and intangible assets | | | 663,120 | | | | 668,870 | |
| Other assets | | | 36,965 | | | | 35,721 | |
| Total investments and other assets | | | 1,894,172 | | | | 1,469,754 | |
| Total assets | | $ | 7,549,800 | | | $ | 7,953,259 | |
| | | | | | | | | |
| Liabilities and equity | | | | | | | | |
| Current liabilities | | | | | | | | |
| Current maturities of long-term debt | | $ | 236,931 | | | $ | 261,931 | |
| Notes payable | | | 326,385 | | | | 523,000 | |
| Accounts payable | | | 623,461 | | | | 694,290 | |
| Affiliate payables | | | 21,135 | | | | 21,866 | |
| Commodity imbalances | | | 235,854 | | | | 392,688 | |
| Other current liabilities | | | 144,858 | | | | 153,539 | |
| Total current liabilities | | | 1,588,624 | | | | 2,047,314 | |
| | | | | | | | | |
| Long-term debt, excluding current maturities | | | 2,585,399 | | | | 2,822,086 | |
| | | | | | | | | |
| Deferred credits and other liabilities | | | 84,648 | | | | 73,798 | |
| | | | | | | | | |
| Commitments and contingencies | | | | | | | | |
| | | | | | | | | |
| Equity | | | | | | | | |
| ONEOK Partners, L.P. partners’ equity: | | | | | | | | |
| General partner | | | 93,782 | | | | 84,434 | |
Common units: 65,413,677 and 59,912,777 units issued and outstanding at September 30, 2010 and December 31, 2009, respectively | | | 1,828,323 | | | | 1,561,762 | |
Class B units: 36,494,126 units issued and outstanding at September 30, 2010 and December 31, 2009 | | | 1,346,885 | | | | 1,380,299 | |
| Accumulated other comprehensive income (loss) | | | 16,878 | | | | (22,037 | ) |
| Total ONEOK Partners, L.P. partners' equity | | | 3,285,868 | | | | 3,004,458 | |
| | | | | | | | | |
| Noncontrolling interests in consolidated subsidiaries | | | 5,261 | | | | 5,603 | |
| | | | | | | | | |
| Total equity | | | 3,291,129 | | | | 3,010,061 | |
| Total liabilities and equity | | $ | 7,549,800 | | | $ | 7,953,259 | |
| | | | | | | | | |
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ONEOK Partners Reports Higher Third-quarter 2010 Results
November 2, 2010
Page 15
| | | | | | | |
| ONEOK Partners, L.P. and Subsidiaries | | | | | | |
| CONSOLIDATED STATEMENTS OF CASH FLOWS | | Nine Months Ended | |
| | | September 30, | |
| (Unaudited) | | 2010 | | | 2009 | |
| | (Thousands of dollars) | |
| Operating Activities | | | | | | |
| Net income | | $ | 330,866 | | | $ | 318,854 | |
| Depreciation and amortization | | | 131,680 | | | | 121,750 | |
| Allowance for equity funds used during construction | | | (748 | ) | | | (25,761 | ) |
| Gain on sale of assets | | | (15,081 | ) | | | (2,760 | ) |
| Deferred income taxes | | | 5,969 | | | | 6,900 | |
| Equity earnings from investments | | | (71,182 | ) | | | (55,464 | ) |
| Distributions received from unconsolidated affiliates | | | 69,889 | | | | 56,896 | |
| Changes in assets and liabilities: | | | | | | | | |
| Accounts receivable | | | 48,067 | | | | (128,003 | ) |
| Affiliate receivables | | | 4,287 | | | | 4,244 | |
| Gas and natural gas liquids in storage | | | (46,393 | ) | | | 2,843 | |
| Accounts payable | | | (78,921 | ) | | | 20,375 | |
| Affiliate payables | | | (731 | ) | | | 9,156 | |
| Commodity imbalances, net | | | (66,921 | ) | | | (16,751 | ) |
| Other assets and liabilities | | | 6,075 | | | | 36,759 | |
| Cash provided by operating activities | | | 316,856 | | | | 349,038 | |
| | | | | | | | | |
| Investing Activities | | | | | | | | |
| Contributions to unconsolidated affiliates | | | (1,313 | ) | | | (46,070 | ) |
| Distributions received from unconsolidated affiliates | | | 9,342 | | | | 26,192 | |
| Capital expenditures (less allowance for equity funds used during construction) | | | (202,773 | ) | | | (491,256 | ) |
| Proceeds from sale of assets | | | 423,975 | | | | 8,528 | |
| Cash provided by (used in) investing activities | | | 229,231 | | | | (502,606 | ) |
| | | | | | | | | |
| Financing Activities | | | | | | | | |
| Cash distributions: | | | | | | | | |
| General and limited partners | | | (417,446 | ) | | | (370,094 | ) |
| Noncontrolling interests | | | (760 | ) | | | (588 | ) |
| Borrowing (repayment) of notes payable, net | | | (196,615 | ) | | | 515,000 | |
| Repayment of notes payable with maturities over 90 days | | | - | | | | (870,000 | ) |
| Issuance of long-term debt, net of discounts | | | - | | | | 498,325 | |
| Long-term debt financing costs | | | - | | | | (4,000 | ) |
| Repayment of long-term debt | | | (258,947 | ) | | | (8,948 | ) |
| Issuance of common units, net of discounts | | | 322,701 | | | | 241,643 | |
| Contribution from general partner | | | 6,820 | | | | 5,130 | |
| Cash provided by (used in) financing activities | | | (544,247 | ) | | | 6,468 | |
| Change in cash and cash equivalents | | | 1,840 | | | | (147,100 | ) |
| Cash and cash equivalents at beginning of period | | | 3,151 | | | | 177,635 | |
| Cash and cash equivalents at end of period | | $ | 4,991 | | | $ | 30,535 | |
| | | | | | | | | |
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ONEOK Partners Reports Higher Third-quarter 2010 Results
November 2, 2010
Page 16
| ONEOK Partners, L.P. and Subsidiaries | | | | | | | | | | | | |
| INFORMATION AT A GLANCE | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | Three Months Ended | | | Nine Months Ended | |
| | | September 30, | | | September 30, | |
| (Unaudited) | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| | | (Millions of dollars, except as noted) | |
| Natural Gas Gathering and Processing | | | | | | | | | | | | |
| Net margin | | $ | 87.8 | | | $ | 89.3 | | | $ | 257.9 | | | $ | 261.7 | |
| Operating costs | | $ | 34.1 | | | $ | 33.6 | | | $ | 98.4 | | | $ | 99.4 | |
| Depreciation and amortization | | $ | 15.3 | | | $ | 15.3 | | | $ | 44.9 | | | $ | 44.2 | |
| Operating income | | $ | 38.2 | | | $ | 40.2 | | | $ | 114.1 | | | $ | 120.9 | |
| Equity earnings from investments | | $ | 7.4 | | | $ | 8.4 | | | $ | 20.7 | | | $ | 20.6 | |
| Natural gas gathered (BBtu/d) (a) | | | 1,046 | | | | 1,100 | | | | 1,075 | | | | 1,131 | |
| Natural gas processed (BBtu/d) (a) | | | 669 | | | | 664 | | | | 674 | | | | 658 | |
| NGL sales (MBbl/d) (a) | | | 44 | | | | 43 | | | | 44 | | | | 42 | |
| Residue gas sales (BBtu/d) (a) | | | 292 | | | | 297 | | | | 286 | | | | 291 | |
Realized composite NGL net sales price ($/gallon) (b) | | $ | 0.87 | | | $ | 0.89 | | | $ | 0.92 | | | $ | 0.87 | |
Realized condensate net sales price ($/Bbl) (b) | | $ | 65.14 | | | $ | 86.90 | | | $ | 63.61 | | | $ | 76.75 | |
Realized residue gas net sales price ($/MMBtu) (b) | | $ | 5.60 | | | $ | 3.34 | | | $ | 5.43 | | | $ | 3.37 | |
Realized gross processing spread ($/MMBtu) (a) | | $ | 5.67 | | | $ | 6.54 | | | $ | 5.97 | | | $ | 6.41 | |
| Capital expenditures - growth | | $ | 64.6 | | | $ | 17.4 | | | $ | 105.4 | | | $ | 60.9 | |
| Capital expenditures - maintenance | | $ | 4.7 | | | $ | 5.8 | | | $ | 12.9 | | | $ | 14.7 | |
| (a) - Includes volumes for consolidated entities only. | | | | | | | | | | | | | | | | |
| (b) - Presented net of the impact of hedging activities and includes equity volumes only. | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Natural Gas Pipelines | | | | | | | | | | | | | | | | |
| Net margin | | $ | 75.0 | | | $ | 75.9 | | | $ | 226.4 | | | $ | 208.4 | |
| Operating costs | | $ | 24.9 | | | $ | 22.9 | | | $ | 71.3 | | | $ | 67.5 | |
| Depreciation and amortization | | $ | 11.2 | | | $ | 10.6 | | | $ | 33.1 | | | $ | 34.0 | |
| Operating income | | $ | 39.0 | | | $ | 41.7 | | | $ | 122.1 | | | $ | 106.1 | |
| Equity earnings from investments | | $ | 21.3 | | | $ | 11.0 | | | $ | 48.9 | | | $ | 32.8 | |
Natural gas transportation capacity contracted (MDth/d) (a) (b) | | | 5,460 | | | | 5,712 | | | | 5,627 | | | | 5,412 | |
| Transportation capacity subscribed (a) | | | 84 | % | | | 86 | % | | | 87 | % | | | 82 | % |
Average natural gas price Mid-Continent region ($/MMBtu) (a) | | $ | 3.94 | | | $ | 2.94 | | | $ | 4.35 | | | $ | 3.01 | |
| Capital expenditures - growth | | $ | 1.6 | | | $ | 8.5 | | | $ | 4.7 | | | $ | 40.8 | |
| Capital expenditures - maintenance | | $ | 5.2 | | | $ | 5.5 | | | $ | 13.7 | | | $ | 7.5 | |
| (a) - Includes volumes for consolidated entities only. | | | | | | | | | | | | | | | | |
| (b) - Unit of measure converted from MMcf/d in third quarter 2010. Prior periods have been recast to reflect this change. | |
| | | | | | | | | | | | | | | | | |
| Natural Gas Liquids | | | | | | | | | | | | | | | | |
| Net margin | | $ | 123.8 | | | $ | 128.9 | | | $ | 356.3 | | | $ | 341.4 | |
| Operating costs | | $ | 39.4 | | | $ | 49.6 | | | $ | 126.2 | | | $ | 129.8 | |
| Depreciation and amortization | | $ | 17.4 | | | $ | 15.9 | | | $ | 53.7 | | | $ | 43.5 | |
| Operating income | | $ | 83.2 | | | $ | 63.3 | | | $ | 191.9 | | | $ | 167.9 | |
| Equity earnings from investments | | $ | 0.7 | | | $ | 0.6 | | | $ | 1.7 | | | $ | 2.1 | |
NGL sales (MBbl/d) (a) | | | 449 | | | | 382 | | | | 443 | | | | 388 | |
NGLs fractionated (MBbl/d) (a) | | | 500 | | | | 496 | | | | 505 | | | | 458 | |
NGLs transported-gathering lines (MBbl/d) (a) | | | 436 | | | | 385 | | | | 452 | | | | 358 | |
NGLs transported-distribution lines (MBbl/d) (a) | | | 455 | | | | 446 | | | | 468 | | | | 451 | |
| Conway-to-Mont Belvieu OPIS average price differential | | | | | | | | | | | | | | | | |
Ethane ($/gallon) | | $ | 0.10 | | | $ | 0.15 | | | $ | 0.11 | | | $ | 0.12 | |
| Capital expenditures - growth | | $ | 22.2 | | | $ | 126.9 | | | $ | 50.6 | | | $ | 352.4 | |
| Capital expenditures - maintenance | | $ | 5.5 | | | $ | 4.9 | | | $ | 14.7 | | | $ | 14.2 | |
| (a) - Includes volumes for consolidated entities only. | | | | | | | | | | | | | | | | |
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ONEOK Partners Reports Higher Third-quarter 2010 Results
November 2, 2010
Page 17
| ONEOK Partners, L.P. and Subsidiaries | | | | | | | | | | | | |
| RECONCILIATION OF NON-GAAP FINANCIAL MEASURES | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | Three Months Ended | | | Nine Months Ended | |
| | | September 30, | | | September 30, | |
| (Unaudited) | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| | | (Thousands of dollars, except per unit amounts) | |
| | | | | | | | | | | | | |
| Reconciliation of Net Income to EBITDA and Distributable Cash Flow | | | | | | | | | | |
| Net income | | $ | 141,697 | | | $ | 121,705 | | | $ | 330,866 | | | $ | 318,854 | |
| Interest expense | | | 49,131 | | | | 50,371 | | | | 156,613 | | | | 152,167 | |
| Depreciation and amortization | | | 43,823 | | | | 41,857 | | | | 131,680 | | | | 121,750 | |
| Income taxes | | | 2,362 | | | | 4,729 | | | | 12,022 | | | | 10,668 | |
| Allowance for equity funds used during construction | | | (266 | ) | | | (7,290 | ) | | | (748 | ) | | | (25,761 | ) |
| EBITDA | | | 236,747 | | | | 211,372 | | | | 630,433 | | | | 577,678 | |
| Interest expense | | | (49,131 | ) | | | (50,371 | ) | | | (156,613 | ) | | | (152,167 | ) |
| Maintenance capital | | | (15,678 | ) | | | (16,120 | ) | | | (42,160 | ) | | | (36,436 | ) |
| Equity earnings from investments | | | (29,390 | ) | | | (20,054 | ) | | | (71,182 | ) | | | (55,464 | ) |
| Distributions received from unconsolidated affiliates | | | 29,587 | | | | 19,615 | | | | 79,231 | | | | 83,088 | |
| Other | | | (16,155 | ) | | | (305 | ) | | | (21,894 | ) | | | (7,115 | ) |
| Distributable cash flow | | $ | 155,980 | | | $ | 144,137 | | | $ | 417,815 | | | $ | 409,584 | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Distributions to general partner | | | (30,582 | ) | | | (25,074 | ) | | | (88,688 | ) | | | (71,923 | ) |
| Distributable cash flow to limited partners | | $ | 125,398 | | | $ | 119,063 | | | $ | 329,127 | | | $ | 337,661 | |
| | | | | | | | | | | | | | | | | |
| Distributions declared per limited partner unit | | $ | 1.13 | | | $ | 1.09 | | | $ | 3.36 | | | $ | 3.25 | |
| Coverage ratio | | | 1.09 | | | | 1.14 | | | | 0.97 | | | | 1.12 | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
Number of units used in computation (thousands) | | | 101,908 | | | | 96,402 | | | | 101,187 | | | | 92,932 | |
| | | | | | | | | | | | | | | | | |
