ONEOK Partners Announces Higher Second-quarter 2012 Financial Results; Increases 2012 Earnings Guidance

TULSA, Okla., July 31, 2012 /PRNewswire/ -- ONEOK Partners, L.P. (NYSE: OKS) today announced second-quarter 2012 earnings of 69 cents per unit, compared with 67 cents per unit for the second quarter 2011.  Net income attributable to ONEOK Partners increased 21 percent for the second quarter 2012 to $206.5 million, compared with $171.1 million for the same period in 2011.

There were approximately 219.8 million units outstanding for the second quarter 2012, compared with 203.8 million units outstanding for the same period last year.  An equity offering and private placement in March 2012 included the issuance of 16 million additional units.

Year-to-date 2012 net income attributable to ONEOK Partners was $445.3 million, or $1.59 per unit, compared with $322.0 million, or $1.25 per unit for the six-month period a year earlier. 

The partnership also increased its 2012 net income guidance range to $860 million to $910 million, compared with the previous guidance range of $810 million to $870 million.  The partnership's distributable cash flow (DCF) is now expected to be in the range of $975 million to $1.025 billion, compared with the previous guidance range of $925 million to $985 million.

"The partnership posted strong financial results during the second quarter," said John W. Gibson, chairman and chief executive officer of ONEOK Partners.  "Our natural gas liquids business segment continued to benefit from favorable natural gas liquids price differentials and higher natural gas liquids volumes gathered and transported as a result of the recent expansion of our Mid-Continent natural gas liquids gathering system." 

"Our natural gas gathering and processing segment continued to experience higher Williston Basin natural gas volumes gathered and processed associated with the startup of our new Garden Creek natural gas processing plant late last year but was affected by lower natural gas and NGL product prices," he said.

In the second quarter 2012, earnings before interest, taxes, depreciation and amortization (EBITDA) were $306.0 million, an 11 percent increase compared with $275.3 million in the second quarter 2011. Year-to-date 2012 EBITDA was $650.1 million, compared with $529.5 million in the same period last year. 

DCF for the second quarter 2012 was $240.4 million, a 16 percent increase compared with $206.9 million in the second quarter 2011. DCF for the first six months of 2012 was $519.3 million, compared with $391.4 million in the same period last year.

Second-quarter 2012 operating income was $228.1 million, a 13 percent increase compared with $202.0 million for the second quarter 2011.  For the first six months of 2012, operating income was $484.1 million, compared with $379.6 million in the prior-year period.   

The increases in operating income for both the three- and six-month 2012 periods reflect favorable natural gas liquids (NGL) price differentials, increased NGL transportation capacity available for optimization activities, and higher NGL volumes gathered in the natural gas liquids segment.  The natural gas gathering and processing segment benefited from higher natural gas volumes gathered and processed offset by lower realized natural gas and NGL product prices.

Operating costs were $123.4 million in the second quarter of 2012, compared with $113.6 million for the same period last year.  Operating costs for the six-month 2012 period were $239.2 million, compared with $222.3 million in the same period last year.  The increases for both the three- and six-month 2012 periods were due primarily to the partnership's expanding operations from several growth projects placed in service.

Capital expenditures were $355.4 million in the second quarter 2012, compared with $265.3 million in the same period in 2011.  Six-month 2012 capital expenditures were $636.2 million, compared with $410.2 million in the same period last year.  These increases were due to increased investments in growth projects in the natural gas gathering and processing and natural gas liquids segments.

> View earnings tables

SECOND-QUARTER 2012 SUMMARY:

• Operating income of $228.1 million, compared with $202.0 million in the second quarter 2011;
• Natural gas gathering and processing segment operating income of $46.7 million, compared with $47.0 million in the second quarter 2011;
• Natural gas pipelines segment operating income of $32.6 million, compared with $29.8 million in the second quarter 2011;
• Natural gas liquids segment operating income of $149.1 million, compared with $125.7 million in the second quarter 2011;
• Equity earnings from investments of $29.2 million, compared with $29.5 million in the second quarter 2011;
• Capital expenditures of $355.4 million, compared with $265.3 million in the second quarter 2011;
• Increasing its 2011 to 2015 internal growth program to a range of approximately $5.7 billion to $6.6 billion by:
  • Announcing in July plans to invest approximately $310 million to $345 million between now and the third quarter of 2014 to construct a new 100 million-cubic-feet-per-day (MMcf/d) natural gas processing facility – the Garden Creek II plant – in eastern McKenzie County, N.D., in the Williston Basin, and related infrastructure;
  • Announcing in July plans to invest $525 million to $575 million between now and the fourth quarter of 2014 to construct a new 75,000 barrel-per-day (bpd) natural gas liquids fractionator, MB-3, and related infrastructure at Mont Belvieu, Texas;
  • Announcing in July plans to invest approximately $100 million between now and the third quarter of 2014 to install additional pump stations on the Bakken NGL Pipeline to increase its capacity to 135,000 bpd from an initial 60,000 bpd;
  • Announcing in July plans to invest approximately $45 million between now and the second quarter of 2014 to install a 40,000 bpd ethane/propane (E/P) splitter at its Mont Belvieu storage facility;
  • Announcing in April plans to invest $1.5 billion to $1.8 billion between now and 2015 to build a 1,300-mile crude-oil pipeline – the Bakken Crude Express Pipeline – with the initial capacity to transport 200,000 bpd of light-sweet crude oil from the Bakken Shale in the Williston Basin in North Dakota to the Cushing, Okla., crude-oil market hub;
  • Announcing in April plans to invest approximately $340 million to $360 million between now and the first quarter of 2014 to construct a new 200 MMcf/d natural gas processing facility – the Canadian Valley plant – in Canadian County, Okla., and related infrastructure in the Cana-Woodford Shale;
  • Announcing in April plans to invest $140 million to $160 million between now and the second half of 2013 to construct a 270-mile natural gas gathering system and related infrastructure in Divide County, N.D., that will supply the partnership's previously announced 100 MMcf/d Stateline II natural gas processing facility in western Williams County, N.D;
• Repaying in April $350 million of senior notes;
• Having $92.2 million of cash and cash equivalents and $24.0 million of commercial paper outstanding and no borrowings outstanding as of June 30, 2012, under the partnership's $1.2 billion revolving credit facility; and
• Increasing the quarterly cash distribution to 66 cents per unit from 63.5 cents per unit, an increase of 4 percent, payable on Aug. 15, 2012, to unitholders of record as of Aug. 6, 2012.

BUSINESS-UNIT RESULTS:

Natural Gas Gathering and Processing Segment

The natural gas gathering and processing segment reported second-quarter 2012 operating income of $46.7 million, compared with $47.0 million for the second quarter 2011. 

Second-quarter 2012 results reflect a $27.1 million increase due primarily to volume growth in the Williston Basin from the new Garden Creek plant and increased drilling activity, which resulted in higher natural gas volumes gathered, compressed, processed, transported and sold, and higher fees.  This increase was offset by a $10.1 million decrease from lower realized natural gas and NGL product prices, particularly ethane and propane, offset partially by higher condensate prices; an $8.6 million decrease due primarily to higher compression costs and third-party transportation and processing costs associated with volume growth, primarily in the Williston Basin; and a $1.4 million decrease from lower natural gas volumes gathered in the Powder River Basin as a result of continued production declines and reduced drilling activity.

Operating income for the six-month 2012 period was $94.3 million, compared with $86.5 million in the same period last year. 

Six-month 2012 results reflect a $55.4 million increase due primarily to volume growth in the Williston Basin from the new Garden Creek plant and increased drilling activity, which resulted in higher natural gas volumes gathered, compressed, processed, transported and sold, and higher fees.  This increase was offset partially by a $15.3 million decrease from lower realized natural gas and NGL product prices, particularly ethane and propane, offset partially by higher condensate prices; a $14.6 million decrease due primarily to higher compression costs and third-party transportation and processing costs associated with volume growth, primarily in the Williston Basin; and a $2.5 million decrease from lower natural gas volumes gathered in the Powder River Basin as a result of continued production declines and reduced drilling activity.

Operating costs in the second quarter 2012 were $41.2 million, compared with $36.5 million in the same period last year.  Six-month 2012 operating costs were $81.4 million, compared with $74.5 million in the same period last year.  The increases in operating costs for both the three- and six-month 2012 periods were due primarily to higher property taxes and employee-related costs associated with the growth in this segment's operations, including the completion of the new Garden Creek natural gas processing plant in the Williston Basin.

Key Statistics: More detailed information is listed in the tables.

• Natural gas gathered was 1,079 billion British thermal units per day (BBtu/d) in the second quarter 2012, up 5 percent compared with the same period last year due to increased drilling activity in the Williston Basin and in western Oklahoma, and the completion of the partnership's new Garden Creek plant in the Williston Basin; offset partially by continued production declines and reduced drilling activity in the Powder River Basin in Wyoming; and up 3 percent compared with the first quarter 2012;
• Natural gas processed was 823 BBtu/d in the second quarter 2012, up 21 percent compared with the same period last year due to increased drilling activity in the Williston Basin and western Oklahoma, and the completion of the partnership's new Garden Creek plant in the Williston Basin; and up 7 percent compared with the first quarter 2012;
• The realized composite NGL net sales price was $1.01 per gallon in the second quarter 2012, down 7 percent compared with the same period last year; and down 7 percent compared with the first quarter 2012;
• The realized condensate net sales price was $86.17 per barrel in the second quarter 2012, up 5 percent compared with the same period last year; and down 4 percent compared with the first quarter 2012;
• The realized residue natural gas net sales price was $3.79 per million British thermal units (MMBtu) in the second quarter 2012, down 34 percent compared with the same period last year; and up 2 percent compared with the first quarter 2012; and
• The realized gross processing spread was $8.03 per MMBtu in the second quarter 2012, down 4 percent compared with the same period last year; and down 7 percent compared with the first quarter 2012.

NGL shrink, plant fuel and condensate shrink discussed in the table below refer to the Btus that are removed from natural gas through the gathering and processing operation; it does not include volumes from the partnership's equity investments.  The following table contains operating information for the periods indicated:

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 for its equity volumes in the natural gas gathering and processing segment for the periods indicated:

The partnership currently estimates that in its natural gas gathering and processing segment, a 1-cent-per-gallon change in the composite price of NGLs would change annual net margin by approximately $2.5 million.  A $1.00-per-barrel change in the price of crude oil would change annual net margin by approximately $1.3 million.  Also, a 10-cent-per-MMBtu change in the price of natural gas would change annual net margin by approximately $2.3 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 second-quarter 2012 operating income of $32.6 million, compared with $29.8 million for the second quarter 2011. 

Second-quarter 2012 results reflect a $1.3 million increase from higher natural gas storage margins due to contract renegotiations and higher short-term storage activity due to periods of higher electric demand and a $1.0 million increase from higher transportation margins due to higher contracted capacity with natural gas producers on its intrastate pipelines partially offset by lower contracted capacity on Midwestern Gas Transmission. These increases were offset partially by a $1.0 million decrease from lower realized natural gas prices on its retained fuel position.

Operating income for the six months 2012 was $65.6 million, compared with $66.6 million in the same period in 2011. 

Six-month 2012 results reflect a $3.7 million decrease primarily from lower realized natural gas prices on its retained fuel position.

Operating costs were $25.9 million in the second quarter 2012, compared with $27.8 million in the same period last year.  Six-month 2012 operating costs were $52.0 million, compared with $54.7 million in the same period last year.  The decreases in operating costs for both the three- and six-month 2012 periods were due primarily to lower employee-related expenses.

Equity earnings from investments were $16.3 million in the second quarter 2012, compared with $16.6 million in the same period in 2011. Six-month 2012 equity earnings from investments were $36.7 million, compared with $37.7 million in the same period last year.

Key Statistics: More detailed information is listed in the tables.

• Natural gas transportation capacity contracted was 5,236 thousand dekatherms per day in the second quarter 2012, down 1 percent compared with the same period last year; and down 6 percent compared with the first quarter 2012;
• Natural gas transportation capacity subscribed was 87 percent in the second quarter 2012 compared with 88 percent in the same period last year; and down from 92 percent in the first quarter 2012; and
• The average natural gas price in the Mid-Continent region was $2.17 per MMBtu in the second quarter 2012, down 48 percent compared with the same period last year; and down 8 percent compared with the first quarter 2012.

Natural Gas Liquids Segment

The natural gas liquids segment reported second-quarter 2012 operating income of $149.1 million, compared with $125.7 million for the second quarter 2011.  

Second-quarter 2012 results reflect:

• An $18.0 million increase from higher NGL volumes gathered in the Mid-Continent and Rocky Mountain regions and Texas, higher NGL volumes fractionated in the Mid-Continent region and contract renegotiations for higher fees associated with its NGL exchange-services activities, offset partially by lower volumes fractionated in Texas due to scheduled maintenance in May 2012 at the Mont Belvieu, Texas, fractionation facility;
• A $10.9 million increase in optimization margins, which consisted of a $24.8 million increase from favorable NGL price differentials and additional transportation capacity available for optimization activities resulting from the completed expansions of the Arbuckle and Sterling I pipelines; offset partially by a $13.8 million decrease due to lower NGL product sales and higher NGL inventory held as a result of scheduled maintenance.  The partnership expects to fractionate this NGL inventory and realize margins resulting from the physical-forward sale of this inventory by the end of 2012;
• A $6.0 million increase due to higher storage margins as a result of favorable contract renegotiations;
• A $1.6 million increase in isomerization margins from wider price differentials between normal butane and iso-butane, offset partially by lower isomerization volumes; and  
• A $2.2 million decrease due to the impact of operational measurement losses.

Operating income for the six months 2012 was $323.6 million, compared with $226.4 million in 2011. 

Six-month 2012 results reflect:

• A $71.2 million increase in optimization margins, which consisted of an $84.8 million increase from favorable NGL price differentials and additional fractionation and transportation capacity available for optimization activities resulting from a fractionation services agreement with a third party and the completed expansions of the Arbuckle and Sterling I pipelines; offset partially by a $13.8 million decrease due primarily to lower NGL product sales and higher NGL inventory held as a result of scheduled maintenance at the Mont Belvieu fractionation facility. The partnership expects to fractionate this NGL inventory and realize margins resulting from the physical-forward sale of this inventory by the end of 2012;
• A $35.8 million increase from higher NGL volumes gathered and fractionated and contract renegotiations for higher fees associated with its NGL exchange-services activities, offset partially by higher costs associated with NGL volumes fractionated by third parties;
• An $8.7 million increase due to higher storage margins as a result of favorable contract renegotiations;
• A $4.2 million increase due to the impact of operational measurement losses in the same period last year; and
• A $1.9 million decrease in isomerization margins from lower isomerization volumes, offset partially by wider price differentials between normal butane and iso-butane.

Operating costs were $57.9 million in the second quarter 2012, compared with $49.5 million in the second quarter 2011.  Six-month 2012 operating costs were $109.8 million, compared with $93.5 million in the same period last year.  The increases were due primarily to higher expenses for materials, outside services and employee-related costs associated with scheduled maintenance and completed growth projects. 

Equity earnings from investments were $5.9 million in the second quarter 2012, compared with $5.2 million in the same period in 2011. Six-month 2012 equity earnings from investments were $11.6 million, compared with $10.0 million in the same period last year.   

Key Statistics: More detailed information is listed in the tables.

• NGLs fractionated were 529,000 bpd in the second quarter 2012, down 2 percent compared with the same period last year due primarily to scheduled maintenance at the Mont Belvieu fractionation facility in May 2012, offset partially by increased volumes at its Mid-Continent fractionation facilities; and down 10 percent compared with the first quarter 2012. In the second quarter 2011, additional Gulf Coast fractionation capacity became available through the partnership's 60,000 bpd fractionation-services agreement with a third party;
• NGLs transported on gathering lines were 523,000 bpd in the second quarter 2012, up 21 percent compared with the same period last year due primarily to increased production through existing supply connections in Texas and the Mid-Continent and Rocky Mountain regions, and new supply connections in the Mid-Continent and Rocky Mountain regions; and up 5 percent compared with the first quarter 2012;
• NGLs transported on distribution lines were 478,000 bpd in the second quarter 2012, up 3 percent compared with the same period last year due primarily to the completion of the Sterling I pipeline expansion project in the fourth quarter of 2011; and down 1 percent compared with the first quarter 2012; and
• The Conway-to-Mont Belvieu average price differential for ethane in ethane/propane mix, based on Oil Price Information Service (OPIS) pricing, was 23 cents per gallon in the second quarter 2012, compared with 20 cents per gallon in the same period last year; and 24 cents per gallon in the first quarter 2012.

GROWTH ACTIVITIES:

The partnership has announced approximately $5.7 billion to $6.6 billion in growth projects, including:

• Approximately $1.5 billion to $1.8 billion to construct a 1,300-mile crude-oil pipeline with the initial capacity to transport 200,000 bpd.  The Bakken Crude Express Pipeline will transport light-sweet crude oil from the Bakken Shale in the Williston Basin in North Dakota to the Cushing, Okla., crude-oil market hub.  Following receipt of all necessary permits and compliance with customary regulatory requirements, construction is expected to begin in late 2013 or early 2014 and be completed by early 2015.
• Approximately $2.4 billion to $2.9 billion for natural gas liquids projects including:
  • Approximately $610 million to $810 million for the construction of a 570-plus-mile, 16-inch NGL pipeline – the Sterling III Pipeline – expected to be completed in late 2013, to transport either unfractionated NGLs or NGL purity products from the Mid-Continent region to the Texas Gulf Coast with the initial capacity of 193,000 bpd and the ability to expand to 250,000 bpd; and the reconfiguration of its existing Sterling I and II NGL distribution pipelines to transport either unfractionated NGLs or NGL purity products;
  • Approximately $300 million to $390 million for the construction of a new 75,000 bpd natural gas liquids fractionator, MB-2, at Mont Belvieu, Texas, that is expected to be completed in mid-2013;
  • Approximately $525 million to $575 million for the construction of a new 75,000 bpd natural gas liquids fractionator, MB-3, and related infrastructure at Mont Belvieu, Texas, that is expected to be completed in the fourth quarter of 2014;
  • Approximately $45 million to install a 40,000 bpd ethane/propane (E/P) splitter at its Mont Belvieu storage facility to split E/P mix into purity ethane, that is expected to be completed in the second quarter of 2014;
  • Approximately $450 million to $550 million for the construction of a 525- to 615-mile NGL pipeline – the Bakken 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.  The Bakken NGL Pipeline is expected to be in service during the first half of 2013, with the initial capacity of 60,000 bpd;
  • Approximately $100 million to install additional pump stations on the Bakken NGL Pipeline to increase its capacity to 135,000 bpd from an initial capacity of 60,000 bpd.  The expansion is expected to be completed in the third quarter of 2014;
  • Approximately $35 million to $40 million on the partnership's 50 percent-owned Overland Pass Pipeline for a 60,000-bpd capacity expansion to transport the additional unfractionated NGL volumes from the new Bakken NGL Pipeline;
  • Approximately $110 million to $140 million for a 60,000-bpd expansion of the partnership's fractionation capacity at Bushton, Kan., which is expected to be in service during the fourth quarter of 2012, to accommodate volumes from the Bakken Shale in the Williston Basin;
  • Approximately $220 million to construct more than 230 miles of 10- and 12-inch diameter NGL pipelines that expanded the partnership's existing Mid-Continent NGL gathering system in the Cana-Woodford and Granite Wash areas, which is expected to add approximately 75,000 to 80,000 bpd of raw, unfractionated NGLs to the partnership's existing NGL gathering systems in the Mid-Continent and the Arbuckle Pipeline.  Construction of the NGL pipelines was completed in April 2012 and connected three new third-party natural gas processing facilities and three existing third-party natural gas processing facilities that have been expanded to the partnership's NGL gathering system.  In addition, the installation of additional pump stations on the Arbuckle Pipeline was completed, increasing its capacity to 240,000 bpd; and
  • At the end of 2011, the partnership completed the installation of seven additional pump stations along its existing Sterling I NGL distribution pipeline, which cost approximately $30 million; the additional pump stations increased the pipeline's capacity by 15,000 bpd. 
• Approximately $1.8 billion to $1.9 billion for natural gas gathering and processing projects including:
  • Approximately $360 million for the Garden Creek plant, a new 100-MMcf/d natural gas processing facility in the Bakken Shale in the Williston Basin in North Dakota that was placed in service at the end of 2011, and related expansions; and for new well connections, expansions and upgrades to the existing natural gas gathering system infrastructure;
  • Approximately $300 million to $355 million 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, which is expected to be in service in the third quarter of 2012, and related NGL infrastructure; expansions and upgrades to the existing gathering and compression infrastructure; and new well connections;
  • Approximately $260 million to $305 million to construct the Stateline II plant, a new 100-MMcf/d natural gas processing facility in the Bakken Shale in the Williston Basin in North Dakota, which is expected to be in service in the first half of 2013; expansions and upgrades to the existing gathering and compression infrastructure; and new well connections;
  • Approximately $140 million to $160 million to construct a 270-mile natural gas gathering system and related infrastructure in Divide County, N.D.  This system, which is expected to be in service in the second half of 2013, will gather and deliver natural gas from producers in the Bakken Shale in the Williston Basin to the partnership's previously announced 100 MMcf/d Stateline II natural gas processing facility in western Williams County, N.D.;
  • Approximately $340 million to $360 million to construct the Canadian Valley plant, a new 200-MMcf/d natural gas processing facility in the Cana-Woodford Shale in Oklahoma, which is expected to be in service in the first quarter 2014; and expansions and upgrades to the existing gathering and compression infrastructure; and
  • Approximately $310 million to $345 million to construct the Garden Creek II plant, a new 100-MMcf/d natural gas processing facility in the Bakken Shale in the Williston Basin in North Dakota, which is expected to be in service in the third quarter of 2014; and expansions and upgrades to the existing gathering and compression infrastructure.

2012 EARNINGS GUIDANCE INCREASED

ONEOK Partners' 2012 net income is expected to be in the range of $860 million to $910 million, compared with its previous range of $810 million to $870 million. The updated guidance reflects higher anticipated earnings in the partnership's natural gas liquids segment offset partially by lower expected earnings in the natural gas gathering and processing segment.

Estimates for the partnership's 2012 DCF were updated and are expected to be in the range of $975 million to $1.025 billion, compared with its previous range of $925 million to $985 million.

Additional information is available in the guidance tables on the ONEOK Partners website.

The midpoint for ONEOK Partners' 2012 operating income guidance has been updated to $948 million, compared with its previous guidance midpoint of $910 million.

The midpoint of the natural gas gathering and processing segment's 2012 operating income guidance has been updated to $220 million, compared with its previous guidance of $247 million, primarily reflecting lower net realized and expected commodity prices.

The average unhedged prices assumed for the second half of 2012 are $85.42 per barrel for New York Mercantile Exchange (NYMEX) crude oil, $2.88 per MMBtu for NYMEX natural gas and $0.71 per gallon for composite natural gas liquids.  Previous guidance assumed $97.75 per barrel for NYMEX crude oil, $3.30 per MMBtu for NYMEX natural gas and $1.20 per gallon for composite natural gas liquids.

For the second half of 2012, financial hedges are in place on approximately 76 percent of the segment's expected equity natural gas production at an average price of $4.25 per MMBtu; 70 percent of its expected equity natural gas liquids production at an average price of $1.26 per gallon; and 74 percent of its expected equity condensate production at an average price of $2.42 per gallon.

The midpoint of the natural gas pipelines segment's 2012 operating income guidance remains $135 million.

The midpoint of the natural gas liquids segment's 2012 operating income guidance has been increased to $593 million, compared with its previous guidance of $528 million. Updated guidance reflects higher expected optimization margins as a result of additional transportation capacity available for optimization activities and higher isomerization margins.

For the second half of 2012, the Conway-to-Mont Belvieu OPIS average ethane in ethane/propane mix price differential is expected to be 28 cents, compared with its previous full-year 2012 guidance of 32 cents.

Capital expenditures for 2012 are expected to be approximately $2.0 billion, comprised of approximately $1.9 billion in growth capital and $108 million in maintenance capital.

2012 earnings guidance includes projected 2.5-cent-per-unit-per-quarter increases in unitholder distributions.  Actual unitholder distribution declarations are subject to ONEOK Partners board approval.

EARNINGS CONFERENCE CALL AND WEBCAST:

ONEOK Partners and ONEOK management will conduct a joint conference call on Wednesday, Aug. 1, 2012, 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 800-467-8998, pass code 1491631, 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 888-203-1112, pass code 1491631.

LINK TO EARNINGS TABLES:

http://www.oneok.com/Investor/FinancialInformation/~/media/ONEOKPartners/EarningsTables/OKS-Q2_2012_Earnings_3pxZQ01.ashx

NON-GAAP (GENERALLY ACCEPTED ACCOUNTING PRINCIPLES) FINANCIAL MEASURES

ONEOK Partners has disclosed in this news release anticipated EBITDA and DCF levels that are non-GAAP financial measures.  EBITDA and DCF are used as measures of the partnership's 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 distributions received and certain other items.

The partnership believes the non-GAAP financial measures described above are useful to investors because these measurements are used by many companies in its 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 its industry.

EBITDA and DCF should not be considered alternatives 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.  Furthermore, these non-GAAP measures should not be viewed as indicative of the actual amount of cash that is available for distributions or that is planned to be distributed for a given period nor do they equate to available cash as defined in the partnership agreement.

ONEOK Partners, L.P. (pronounced ONEOK) (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 43.4 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. 

For more information, visit the website at www.oneokpartners.com.

For the latest news about ONEOK Partners, follow us on Twitter @ONEOKPartners.

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, as amended, and Section 21E of the Exchange Act, as amended.  The forward-looking statements relate to our anticipated financial performance, liquidity, 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 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, pipeline safety, environmental compliance, climate change initiatives and authorized rates of recovery of natural gas and natural 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 Oklahoma Corporation Commission (OCC), Kansas Corporation Commission (KCC), Texas regulatory authorities or any other local, state or federal regulatory body, including the Federal Energy Regulatory Commission (FERC), the National Transportation Safety Board (NTSB), the Pipeline and Hazardous Materials Safety Administration (PHMSA), the Environmental Protection Agency (EPA) and the Commodity Futures Trading Commission (CFTC);
• 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, NGLs and crude oil;
  • competitive conditions in the overall energy market;
  • availability of supplies of Canadian and United States natural gas and crude oil; 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;
• 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 United States or international economies, including liquidity risks in United States or foreign 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 uncontracted capacity in our assets 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 Securities and Exchange Commission (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 the 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.

SOURCE ONEOK Partners

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