ONEOK Partners Announces Higher Second-Quarter 2011 Financial Results; Increases 2011 Earnings Guidance

Net Income Rises More than 60 Percent in the Quarter; Led by Significantly Higher Natural Gas Liquids Operating Results

Aug 02, 2011, 16:05 ET from ONEOK Partners, L.P.

TULSA, Okla., Aug. 2, 2011 /PRNewswire/ -- ONEOK Partners, L.P. (NYSE: OKS) today announced second-quarter 2011 earnings of 67 cents per unit on a split-adjusted basis, compared with 37 cents per unit for the second quarter 2010 on a split-adjusted basis.  Net income attributable to ONEOK Partners was $171.1 million for the second quarter 2011, compared with $105.0 million for the same period in 2010.

Year-to-date 2011 net income attributable to ONEOK Partners was $322.0 million, or $1.25 per unit on a split-adjusted basis, compared with $188.9 million, or 66 cents per unit, for the six-month period a year earlier on a split-adjusted basis.  

The partnership also increased its 2011 net income guidance to a range of $630 million to $660 million compared with the previous guidance range of $525 million to $575 million.  The partnership's distributable cash flow (DCF) is now expected to be in the range of $735 million to $765 million compared with the previous guidance range of $625 million to $675 million.  

"Our natural gas liquids segment performed exceptionally well, with operating income almost doubling in the quarter as a result of higher fee-based exchange margins and the benefits of favorable price differentials," said John W. Gibson, chairman, president and chief executive officer of ONEOK Partners.  

"Through our integrated operations, we were able to capture additional margins from wider natural gas liquids price differentials as more transportation and fractionation capacity became available for our optimization activities.  Increased natural gas liquids volumes gathered and fractionated also contributed to the segment's strong results," he added.

"The natural gas gathering and processing segment continued to benefit from higher commodity prices and contract renegotiations," said Gibson.  "The natural gas pipelines segment results were lower due to higher operating expenses and lower transportation margins on one of its wholly owned pipelines."

In the second quarter 2011, earnings before interest, taxes, depreciation and amortization (EBITDA) were $275.3 million, compared with $207.0 million in the second quarter 2010.  Year-to-date 2011 EBITDA was $529.5 million, compared with $393.7 million in the same period last year.  

DCF for the second quarter 2011 was $206.9 million, compared with $139.5 million in the second quarter 2010.  DCF for the first six months of 2011 was $391.4 million, compared with $261.8 million in the same period last year.

Operating income for the second quarter 2011 was $202.0 million, compared with $146.0 million for the second quarter 2010.  For the first six months of 2011, operating income was $379.6 million, compared with $266.1 million in the prior-year period.  

The increases in operating income for both the three- and six-month 2011 periods reflect favorable natural gas liquids (NGL) price differentials; increased NGL fractionation and transportation capacity available for optimization activities;  higher NGL volumes gathered and fractionated; contract renegotiations; and higher isomerization margins in the natural gas liquids segment.

For the second-quarter and year-to-date periods, the natural gas gathering and processing segment benefited from higher net realized commodity prices and favorable changes in contract terms, offset partially by lower volumes gathered in the Powder River Basin and in certain parts of western Oklahoma and Kansas. These increases were offset partially by the impact of the deconsolidation of Overland Pass Pipeline Company following the sale of a 49-percent ownership interest in September 2010.  These results are included in equity earnings from investments in the natural gas liquids segment.

Operating costs were $113.6 million in the second quarter of 2011, compared with $97.9 million for the same period last year.  Operating costs for the six-month 2011 period were $222.3 million, compared with $194.3 million in the same period last year.  The increases for both the three- and six-month 2011 periods were due primarily to higher employee-related costs associated with incentive and benefit plans, which includes share-based compensation costs, and higher property taxes.

Equity earnings from investments were $29.5 million in the second quarter 2011, compared with $20.7 million in the same period in 2010.  Six-month 2011 equity earnings from investments were $61.6 million, compared with $41.8 million in the same period last year.  This increase was due primarily to increased contracted capacity on Northern Border Pipeline, in which the partnership owns a 50-percent interest.  Additionally, ONEOK Partners' 50-percent interest in Overland Pass Pipeline is included in equity earnings from investments, effective September 2010.

Capital expenditures were $265.3 million in the second quarter 2011, compared with $62.9 million in the same period in 2010.  Six-month 2011 capital expenditures were $410.2 million, compared with $98.7 million in the same period last year.  This increase was due to growth projects in the natural gas gathering and processing and natural gas liquids segments.

    View earnings tables

    SECOND-QUARTER 2011 HIGHLIGHTS:

    • Operating income of $202.0 million, compared with $146.0 million in the second quarter 2010;
    • Natural gas gathering and processing segment operating income of $47.0 million, compared with $43.7 million in the second quarter 2010;
    • Natural gas pipelines segment operating income of $29.8 million, compared with $38.2 million in the second quarter 2010;
    • Natural gas liquids segment operating income of $125.7 million, compared with $64.7 million in the second quarter 2010;
    • Equity earnings from investments of $29.5 million, compared with $20.7 million in the second quarter 2010;
    • Increasing its 2011 to 2014 growth program to a range of approximately $2.7 billion to $3.3 billion by announcing in May investments of $910 million to $1.2 billion for additional NGL projects including:
      • The construction of a new 570-plus-mile, 16-inch diameter NGL pipeline, the Sterling III Pipeline, with the initial capacity to transport 193,000 barrels per day (bpd) and the ability to expand to 250,000 bpd of either unfractionated NGLs or NGL purity products from the Mid-Continent region to the Texas Gulf Coast;
      • The reconfiguration of its existing Sterling I and II NGL distribution pipelines to transport either unfractionated NGLs or NGL purity products; and
      • The construction of a new 75,000-bpd NGL fractionator, MB-2, at Mont Belvieu, Texas;
    • Capital expenditures of $265.3 million, compared with $62.9 million in the second quarter 2010;
    • Having $432.2 million of cash and cash equivalents and no commercial paper or borrowings outstanding as of June 30, 2011, under the partnership's $1.0 billion revolving credit facility;
    • Completing a two-for-one split of the partnership's common units and Class B units on July 12, 2011, with the distribution of one unit for each unit outstanding.  As a result, the partnership now owns 130,827,354 common units and 72,988,252 Class B units outstanding, and its minimum quarterly distribution and target distribution levels have been adjusted proportionately;
    • Entering into in August a new $1.2 billion, five-year senior unsecured revolving credit facility that expires in August 2016; and
    • On a split-adjusted basis, increasing the quarterly cash distribution to 58.5 cents per unit from 57.5 cents per unit, payable on Aug. 12, 2011, to unitholders of record as of Aug. 1, 2011, resulting in an annualized cash distribution of $2.34 per unit.

    BUSINESS-UNIT RESULTS:

    Natural Gas Gathering and Processing Segment

    The natural gas gathering and processing segment reported second-quarter 2011 operating income of $47.0 million, compared with $43.7 million for the second quarter 2010.  

    Second-quarter 2011 results reflect a $7.1 million increase from higher net realized commodity prices and a $4.7 million increase due to favorable changes in contract terms.  These increases were offset partially by a $2.0 million decrease from lower natural gas volumes gathered as a result of continued production declines and reduced drilling activity in the Powder River Basin in Wyoming.

    Operating income for the six-month 2011 period was $86.5 million, compared with $75.8 million in the same period last year.  

    Six-month 2011 results reflect a $15.1 million increase from higher net realized commodity prices; an $8.8 million increase due to favorable changes in contract terms; and a $3.1 million increase from higher natural gas volumes processed in the Williston Basin resulting from increased drilling activity, which offset the impact of reduced drilling activity in certain parts of western Oklahoma and Kansas, and weather-related outages in the first quarter 2011.  

    These increases were offset partially by a $4.1 million decrease from lower natural gas volumes gathered as a result of continued production declines and reduced drilling activity in the Powder River Basin in Wyoming.

    Operating costs in the second quarter 2011 were $36.5 million, compared with $29.8 million in the same period last year.  Six-month 2011 operating costs were $74.5 million, compared with $64.3 million in the same period last year.  The increases in operating costs for both the three- and six-month 2011 periods were due primarily to higher employee-related costs associated with incentive and benefit plans, which includes share-based compensation costs, and higher property taxes.

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

    • Natural gas gathered totaled 1,026 billion British thermal units per day (BBtu/d) in the second quarter 2011, down 6 percent compared with the same period last year due to continued production declines in the Powder River Basin in Wyoming, offset partially by increased drilling activity in the Williston Basin; and up 3 percent compared with the first quarter 2011;
    • Natural gas processed totaled 682 BBtu/d in the second quarter 2011, down 1 percent compared with the same period last year due to natural production declines in western Oklahoma and Kansas, offset partially by increased drilling activity in the Williston Basin; and up 6 percent compared with the first quarter 2011;
    • The realized composite NGL net sales price was $1.09 per gallon in the second quarter 2011, up 21 percent compared with the same period last year; and unchanged compared with the first quarter 2011;
    • The realized condensate net sales price was $82.43 per barrel in the second quarter 2011, up 30 percent compared with the same period last year; and up 8 percent compared with the first quarter 2011;
    • The realized residue gas net sales price was $5.77 per million British thermal units (MMBtu) in the second quarter 2011, up 7 percent compared with the same period last year; and down 5 percent compared with the first quarter 2011; and
    • The realized gross processing spread was $8.38 per MMBtu in the second quarter 2011, up 141 percent compared with the same period last year; and up 1 percent compared with the first quarter 2011.

    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:

    Three Months Ended

    Six Months Ended

    June 30,

    June 30,

    Operating Information (a)

    2011

    2010

    2011

    2010

    Percent of proceeds

       NGL sales (Bbl/d)

    6,563

    5,797

    6,163

    5,408

       Residue gas sales (MMBtu/d)

    46,742

    43,534

    43,990

    40,978

       Condensate sales (Bbl/d)

    1,915

    1,887

    1,933

    1,902

       Percentage of total net margin

    60%

    55%

    59%

    54%

    Fee-based

       Wellhead volumes (MMBtu/d)

    1,025,872

    1,088,438

    1,008,919

    1,090,239

       Average rate ($/MMBtu)

    $        0.34

    $        0.31

    $        0.33

    $        0.30

       Percentage of total net margin

    31%

    34%

    32%

    35%

    Keep-whole

       NGL shrink (MMBtu/d) (b)

    11,173

    14,336

    11,570

    14,079

       Plant fuel (MMBtu/d) (b)

    1,264

    1,537

    1,305

    1,625

       Condensate shrink (MMBtu/d) (b)

    1,480

    1,695

    1,409

    1,638

       Condensate sales (Bbl/d)

    299

    343

    285

    331

       Percentage of total net margin

    9%

    11%

    9%

    11%

    (a) - Includes volumes for consolidated entities only.

    (b) - Refers to the Btus that are removed from natural gas through processing.

    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 periods indicated:

    Six Months Ending

    December 31, 2011

    Volumes Hedged

    Average Price

    Percentage Hedged

    NGLs (Bbl/d) (a)

    5,126

    $1.22

    / gallon

    63%

    Condensate (Bbl/d) (a)

    1,643

    $2.15

    / gallon

    76%

    Total (Bbl/d)

    6,769

    $1.44

    / gallon

    66%

    Natural gas (MMBtu/d)

    25,353

    $5.66

    / MMBtu

    79%

    (a) - Hedged with fixed-price swaps.

    Year Ending

    December 31, 2012

    Volumes Hedged

    Average Price

    Percentage Hedged

    NGLs (Bbl/d) (a)

    5,169

    $1.61

    / gallon

    47%

    Condensate (Bbl/d) (a)

    1,819

    $2.43

    / gallon

    75%

    Total (Bbl/d)

    6,988

    $1.82

    / gallon

    52%

    Natural gas (MMBtu/d)

    25,301

    $5.09

    / MMBtu

    45%

    (a) - Hedged with fixed-price swaps.

    Year Ending

    December 31, 2013

    Volumes Hedged

    Average Price

    Percentage Hedged

    NGLs (Bbl/d) (a)

    367

    $2.55

    / gallon

    2%

    Condensate (Bbl/d) (a)

    649

    $2.55

    / gallon

    25%

    Total (Bbl/d)

    1,016

    $2.55

    / gallon

    5%

    (a) - Hedged with fixed-price swaps.

    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 $1.3 million.  A $1.00 per barrel change in the price of crude oil would change annual net margin by approximately $1.2 million.  Also, a 10 cent per MMBtu change in the price of natural gas would change annual net margin by approximately $1.5 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 2011 operating income of $29.8 million, compared with $38.2 million for the second quarter 2010.  

    Second-quarter 2011 results reflect a $3.0 million decrease from lower transportation margins, primarily due to narrower natural gas price location differentials that decreased interruptible transportation volumes and contracted transportation capacity on Midwestern Gas Transmission.

    Operating income for the six months 2011 was $66.6 million, compared with $83.1 million in the same period in 2010.  

    Six-month 2011 results reflect a $5.9 million decrease from lower transportation margins, primarily due to narrower natural gas price location differentials that decreased interruptible transportation volumes and contracted transportation capacity on Midwestern Gas Transmission; and a $3.3 million decrease from lower margins on its retained fuel position.  These decreases were offset partially by an increase of $2.3 million due to higher natural gas storage margins.

    This segment's other wholly owned natural gas pipelines primarily serve end-users, such as natural gas distribution companies and electric-generation companies that require natural gas to operate their business regardless of natural gas price differentials.

    Operating costs were $27.8 million in the second quarter 2011, compared with $23.6 million in the same period last year.  Six-month 2011 operating costs were $54.7 million, compared with $46.4 million in the same period last year.  The increases in operating costs for both the three- and six-month 2011 periods were due primarily to higher employee-related costs associated with incentive and benefit plans, which includes share-based compensation costs, and higher property taxes.

    Equity earnings from investments were $16.6 million in the second quarter 2011, compared with $12.5 million in the same period in 2010.  Six-month 2011 equity earnings from investments were $37.7 million, compared with $27.6 million in the same period last year. These increases were due to higher contracted capacity on Northern Border Pipeline due to wider natural gas price location differentials between the markets it serves.

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

    • Natural gas transportation capacity contracted totaled 5,295 thousand dekatherms per day in the second quarter 2011, down 4 percent compared with the same period last year due primarily to lower contracted capacity on Midwestern Gas Transmission resulting from narrower natural gas price location differentials; and down 6 percent compared with the first quarter 2011;
    • Natural gas transportation capacity subscribed was 82 percent in the second quarter 2011 compared with 85 percent subscribed for the same period last year; and down from 87 percent in the first quarter 2011; and
    • The average natural gas price in the Mid-Continent region was $4.18 per MMBtu in the second quarter 2011, up 3 percent compared with the same period last year; and up 2 percent compared with the first quarter 2011.

    Natural Gas Liquids Segment

    The natural gas liquids segment reported second-quarter 2011 operating income of $125.7 million, compared with $64.7 million for the second quarter 2010.  

    Second-quarter 2011 results reflect:

    • A $64.6 million increase due to higher NGL optimization margins as a result of favorable NGL price differentials and increased NGL fractionation and transportation capacity available for optimization activities between the Mid-Continent and Gulf-Coast markets;
    • A $7.3 million increase from higher NGL volumes gathered and fractionated, and contract renegotiations associated with its exchange services activities;
    • A $4.0 million increase in isomerization margins from favorable NGL product price differentials; and
    • A $3.2 million increase due to higher storage margins as a result of contract renegotiations.

    These increases were offset partially by a $16.7 million decrease, compared with the same period last year, resulting from the deconsolidation of Overland Pass Pipeline in September 2010.

    Operating costs were $49.5 million in the second quarter 2011, compared with $45.8 million in the second quarter 2010 due primarily to higher employee-related costs associated with incentive and benefit plans, which includes share-based compensation costs, and increased costs for outside services for scheduled maintenance at a Mid-Continent fractionator.  These increases were offset partially by the deconsolidation of Overland Pass Pipeline in September 2010.

    Operating income for the six months 2011 was $226.4 million, compared with $108.7 million in 2010.  

    Six-month 2011 results reflect:

    • A $118.2 million increase from higher NGL optimization margins as a result of favorable NGL price differentials and increased NGL fractionation and transportation capacity available for optimization activities between the Mid-Continent and Gulf-Coast markets;
    • A $21.1 million increase from higher NGL volumes gathered and fractionated, and contract renegotiations associated with its exchange services activities;
    • A $6.1 million increase due to higher storage margins as a result of contract renegotiations; and
    • A $5.5 million increase in isomerization margins from favorable NGL product price differentials.

    These increases were offset partially by a $32.3 million decrease, compared with the same period last year, resulting from the deconsolidation of Overland Pass Pipeline in September 2010.

    Six-month 2011 operating costs were $93.5 million, compared with $86.8 million in the same period last year.  This increase was due primarily to higher employee-related costs associated with incentive and benefit plans, which includes share-based compensation costs, and higher property taxes.  These increases were offset partially by the deconsolidation of Overland Pass Pipeline in September 2010.

    Depreciation and amortization expense was $15.7 million for the second quarter 2011, compared with $17.9 million for the same period in 2010.  Six-month 2011 depreciation and amortization expense was $31.0 million, compared with $36.2 million in the same period last year.  These decreases were due primarily to the deconsolidation of Overland Pass Pipeline in September 2010.

    Equity earnings from investments were $5.2 million in the second quarter 2011, compared with $0.6 million in the same period in 2010.  Six-month 2011 equity earnings from investments were $10.0 million, compared with $1.0 million in the same period last year.  This increase was due to the deconsolidation of Overland Pass Pipeline in September 2010 that is included in equity earnings from investments.

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

    • NGLs fractionated totaled 541 thousand barrels per day (MBbl/d) in the second quarter 2011, up 3 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 11 percent compared with the first quarter 2011;
    • NGLs transported on gathering lines totaled 432 MBbl/d in the second quarter 2011, up 15 percent compared with the same period last year, after adjusting for the September 2010 deconsolidation of Overland Pass, 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 9 percent compared with the first quarter 2011;
    • NGLs transported on distribution lines totaled 462 MBbl/d in the second quarter 2011, down 4 percent compared with the same period last year due primarily to managing the transportation of NGL volumes across the system by placing additional unfractionated NGL volumes on the Arbuckle gathering pipeline to Mont Belvieu to capture additional margins from favorable NGL price differentials; and unchanged compared with the first quarter 2011; and
    • The Conway-to-Mont Belvieu average price differential for ethane, based on Oil Price Information Service (OPIS) pricing, was 20 cents per gallon in the second quarter 2011, up 25 percent compared with the same period last year; and up 33 percent compared with the first quarter 2011.

    GROWTH ACTIVITIES:

    During 2010 and in 2011, the partnership announced approximately $2.7 billion to $3.3 billion in growth projects that include:

    • Approximately $910 million to $1.2 billion for natural gas liquids projects that include:
      • The construction of a 570-plus-mile, 16-inch NGL pipeline, the Sterling III Pipeline,  expected to cost approximately $610 million to $810 million, to transport either unfractionated NGLs or NGL purity products from the Mid-Continent region to the Texas Gulf Coast with the initial capacity to transport 193,000 bpd and the ability to expand to 250,000 bpd;
      • The reconfiguration of its existing Sterling I and II NGL distribution pipelines to transport either unfractionated NGLs or NGL purity products; and
      • The construction of a new 75,000 bpd natural gas liquids fractionator, MB-2, at Mont Belvieu, Texas, that is expected to cost approximately $300 million to $390 million;
    • Approximately $350 million to $415 million to construct the Garden Creek 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 fourth quarter 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 by 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, 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 by the end of 2014 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 $595 million to $730 million of natural gas liquids projects 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., with the initial capacity to transport 60,000 bpd and the ability to expand to 110,000 bpd;
      • 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
      • The expansion of the partnership's fractionation capacity at Bushton, Kan., by 60,000 bpd to accommodate the additional NGL volumes;  
    • Approximately $180 million to $240 million by the first half of 2012 to construct more than 230 miles of 10- and 12-inch diameter NGL pipelines that will expand the partnership's existing Mid-Continent NGL gathering system in the Cana-Woodford and Granite Wash areas, which, when completed, 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. These investments include connecting to three new third-party natural gas processing facilities with total expected capacity of 510 MMcf/d and to three existing third-party natural gas processing facilities that are being expanded; and installing additional pump stations on the Arbuckle Pipeline to increase its capacity to 240,000 bpd; and
    • 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 began last year and is expected to be completed in the third quarter of 2011.

    2011 EARNINGS GUIDANCE INCREASED

    ONEOK Partners' 2011 net income is expected to be in the range of $630 million to $660 million, compared with its previous range of $525 million to $575 million. The updated guidance reflects higher anticipated earnings in the partnership's natural gas liquids segment.

    Estimates for the partnership's 2011 DCF were updated and are expected to be in the range of $735 million to $765 million, compared with its previous range of $625 million to $675 million.

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

    The midpoint for ONEOK Partners' 2011 operating income guidance has been updated to $752 million, compared with its previous guidance of $656 million.

    The midpoint of the natural gas gathering and processing segment's 2011 operating income guidance has been updated to $180 million, compared with its previous guidance of $182 million, reflecting lower than expected natural gas gathering and processing volume growth, primarily in the Mid-Continent, offset partially by higher net realized and expected commodity prices.

    The midpoint of the natural gas pipelines segment's 2011 operating income guidance has been updated to $141 million, compared with its previous guidance of $148 million. These lower earnings are primarily the result of narrower natural gas price location differentials that lower demand for interruptible transportation services across the segment's pipeline system and lower contracted transportation capacity on Midwestern Gas Transmission.

    The midpoint of the natural gas liquids segment's 2011 operating income guidance has been updated to $431 million, compared with its previous guidance of $326 million. Updated guidance reflects higher than expected NGL optimization margins from wider NGL price differentials and increased NGL transportation capacity available for optimization activities. For the remainder of 2011, the Conway-to-Mont Belvieu OPIS average ethane price differential is expected to be 15 cents.

    The midpoint for equity earnings from investments guidance has been increased to $123 million, compared with previous guidance of $106 million. This increase reflects higher anticipated earnings from Northern Border Pipeline and Overland Pass Pipeline, in which ONEOK Partners owns a 50-percent interest in each.  

    The increase in Northern Border Pipeline equity earnings is due to wider natural gas price differentials between the markets it serves. The increase in Overland Pass Pipeline equity earnings is due to lower interest expense as the result of financing the Overland Pass Pipeline at the partnership level versus the joint-venture level assumed in the initial 2011 financial guidance.  

    Capital expenditures for 2011 are expected to be approximately $1.3 billion, comprised of approximately $1.2 billion in growth capital and $102 million in maintenance capital.

    Other income and expense for 2011 has been updated to $4 million, compared with the previous guidance of $17 million.  This decrease is primarily due to lower than expected allowance for equity funds used during construction (AFUDC) as a result of the timing of spending for certain growth projects in the natural gas liquids segment.

    EARNINGS CONFERENCE CALL AND WEBCAST:

    ONEOK Partners and ONEOK management will conduct a joint conference call on Wednesday, August 3, 2011, 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 866-206-6509, pass code 1541976, 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 1541976.

    LINK TO EARNINGS TABLES:

    http://www.oneok.com/Investor/FinancialInformation/~/media/ONEOKPartners/EarningsTables/OKS_Q2_2011_Earnings_15j2hxz.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 a measure 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 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.  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. (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. 

    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 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;
    • 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.

    Analyst Contact:

    Andrew Ziola

    918-588-7163

    Media Contact:

    Brad Borror

    918-588-7582

    SOURCE ONEOK Partners, L.P.



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