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ONEOK Partners Announces Higher Fourth-quarter and Full-year 2011 Financial Results; Increases 2012 Earnings Guidance

TULSA, Okla., Feb. 20, 2012 /PRNewswire/ -- ONEOK Partners, L.P. (NYSE: OKS) today announced fourth-quarter 2011 earnings of $1.26 per unit, compared with $0.54 per unit on a split-adjusted basis for the fourth quarter 2010. Net income attributable to ONEOK Partners was $298.6 million for the fourth quarter 2011, compared with $142.3 million for the same period in 2010.

Full-year 2011 net income attributable to ONEOK Partners was $830.3 million, or $3.35 per unit, compared with $472.7 million, or $1.75 per unit on a split-adjusted basis, in 2010. 2010 results include a $16.3 million, or 8-cent-per-unit, gain on the sale of a 49-percent interest in Overland Pass Pipeline Company, LLC to Williams Partners, L.P. that was completed in September 2010.

The partnership also increased its 2012 net income guidance by more than 9 percent to a range of $810 million to $870 million, compared with the previous guidance range of $740 million to $800 million, released on Sept. 26, 2011. The increase 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.

The partnership's distributable cash flow (DCF) is now expected to be in the range of $925 million to $985 million, compared with the previous guidance range of $845 million to $915 million.

2012 earnings guidance includes a projected 2.5-cent-per-quarter increase in unitholder distributions, higher than the 2-cent-per-quarter increase in guidance provided in September 2011. Actual unitholder distribution declarations are subject to ONEOK Partners board approval.

"The partnership had an exceptional year, growing volumes and benefiting from our integrated midstream natural gas and natural gas liquids assets, while developing new growth projects that now total almost $3 billion," said John W. Gibson, chairman and chief executive officer of ONEOK Partners.

"The partnership posted exceptional results in the fourth quarter, primarily as a result of continued strong natural gas liquids price differentials and higher natural gas liquids and natural gas volume growth," Gibson stated. "In the fourth quarter, the natural gas gathering and processing segment continued to experience higher natural gas volumes gathered and processed, driven primarily by increases in the Williston Basin where we recently completed the first of three new natural gas processing plants and related infrastructure."

In the fourth quarter 2011, earnings before interest, taxes, depreciation and amortization (EBITDA) were $399.8 million, a 70-percent increase compared with $235.0 million in the fourth quarter 2010. Full-year 2011 EBITDA was $1.24 billion, a 43-percent increase compared with $865.4 million in 2010.

DCF for the fourth quarter 2011 was $321.3 million, an 89-percent increase compared with $169.8 million in the fourth quarter 2010. DCF for the full-year 2011 was $946.0 million, a 61-percent increase compared with $587.6 million in 2010.

Operating income for the fourth quarter 2011 was $317.5 million, a 99-percent increase compared with $159.7 million for the fourth quarter 2010. For the full-year 2011, operating income was $939.5 million, a 60-percent increase compared with $586.3 million in 2010.

The increases in operating income for both the three-month and full-year 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 and marketing margins in the natural gas liquids segment. The natural gas gathering and processing segment benefited from higher net realized NGL and condensate prices, higher natural gas volumes processed and favorable changes in contract terms, offset partially by lower natural gas volumes gathered primarily in the Powder River Basin.

Full-year 2011 results reflect the deconsolidation of Overland Pass Pipeline Company that is included in equity earnings from investments in the natural gas liquids segment. 2010 results reflect the gain on the sale of a 49-percent ownership interest in Overland Pass Pipeline Company that was recorded in September 2010.

Operating costs were $130.7 million in the fourth quarter of 2011, compared with $111.4 million for the same period last year. Operating costs for the full-year 2011 period were $459.4 million, compared with $403.5 million in 2010. The increases for both the three-month and full-year 2011 periods were due primarily to higher labor and employee-related costs associated with incentive and benefit plans, which includes equity-based compensation costs; higher property taxes; and higher expenses for materials and outside services, associated primarily with scheduled maintenance at the partnership's NGL fractionation and storage facilities.

Fourth-quarter 2011 equity earnings from investments were $33.6 million, compared with $30.7 million in the same period in 2010. Full-year 2011 equity earnings from investments were $127.2 million, compared with $101.9 million in 2010. The increase for the full-year 2011 period was due primarily to the partnership's 50-percent interest in Overland Pass Pipeline included in equity earnings from investments that became effective in September 2010 and increased contracted capacity on Northern Border Pipeline, in which the partnership owns a 50-percent interest.

Capital expenditures were $401.0 million in the fourth quarter 2011, compared with $149.9 million in the same period in 2010. Full-year 2011 capital expenditures were $1.1 billion, compared with $352.7 million in 2010. This increase was due to growth projects in the natural gas gathering and processing and natural gas liquids segments.

> View earnings tables

2011 SUMMARY AND ADDITIONAL UPDATES:

    --  Full-year 2011 operating income of $939.5 million, compared with $586.3
        million in 2010;
    --  Natural gas gathering and processing segment operating income of $180.6
        million, compared with $153.6 million in 2010;
    --  Natural gas pipelines segment operating income of $130.1 million,
        compared with $163.0 million in 2010;
    --  Natural gas liquids segment operating income of $628.6 million, compared
        with $272.3 million in 2010;
    --  Equity earnings from investments of $127.2 million, compared with $101.9
        million in 2010;
    --  Capital expenditures of $1.1 billion, compared with $352.7 million in
        2010;
    --  Completing a two-for-one split of the partnership's common units and
        Class B units on July 12, 2011. As a result, the partnership now has
        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;
    --  Having $35.1 million of cash and cash equivalents and no commercial
        paper or borrowings outstanding as of Dec. 31, 2011, under the
        partnership's $1.2 billion revolving credit facility;
    --  Entering into in August a new $1.2 billion, five-year senior unsecured
        revolving credit facility that expires in August 2016; and
    --  Increasing the quarterly cash distribution four times, including an
        increase in the quarterly cash distribution to 61 cents per unit from
        59.5 cents per unit, payable on Feb. 14, 2012, to unitholders of record
        as of Jan. 31, 2012, resulting in an annualized cash distribution of
        $2.44 per unit.

BUSINESS-UNIT RESULTS:

Natural Gas Gathering and Processing Segment

The natural gas gathering and processing segment reported fourth-quarter 2011 operating income of $42.3 million, compared with $39.5 million for the fourth quarter 2010.

Fourth-quarter 2011 results reflect a $10.1 million increase from higher natural gas volumes processed in the Williston Basin, offset partially by lower volumes in Kansas due to natural production declines; and a $6.0 million increase from higher net realized NGL and condensate prices. These increases were offset partially by a $3.0 million decrease due to changes in contract terms and a $2.1 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 income for the full-year 2011 period was $180.6 million, compared with $153.6 million in 2010.

Full-year 2011 results reflect a $32.6 million increase as a result of higher net realized NGL and condensate prices; a $19.4 million increase from higher natural gas volumes processed in the Williston Basin and western Oklahoma resulting from increased drilling activity, which more than offset the impact of reduced drilling activity in certain parts of Kansas, and weather-related outages in the first quarter 2011; and an $8.8 million increase due to favorable changes in contract terms. These increases were offset partially by an $8.2 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.

The natural gas gathering and processing segment connected approximately 600 wells to its system in the Williston Basin region and the Mid-Continent in 2011, compared with approximately 300 well connections in 2010.

Operating costs in the fourth quarter 2011 were $44.1 million, compared with $38.3 million in the same period last year. Full-year 2011 operating costs were $153.7 million, compared with $136.8 million in 2010. The increases in operating costs for both the three-month and full-year 2011 periods were due primarily to higher labor and employee-related costs associated with incentive and benefit plans, which includes equity-based compensation costs, and higher materials and supplies expense associated with growth in the segment's operations; offset partially by a reduction in rental costs due to the acquisition of previously leased equipment.

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

    --  Natural gas gathered totaled 1,057 billion British thermal units per day
        (BBtu/d) in the fourth quarter 2011, up 1 percent compared with the same
        period last year due to increased drilling activity in the Williston
        Basin, offset partially by continued production declines in the Powder
        River Basin in Wyoming and certain parts of Kansas; and up 1 percent
        compared with the third quarter 2011;
    --  Natural gas processed totaled 758 BBtu/d in the fourth quarter 2011, up
        13 percent compared with the same period last year due to increased
        drilling activity in the Williston Basin and western Oklahoma, offset
        partially by natural production declines in Kansas; and up 5 percent
        compared with the third quarter 2011;
    --  The realized composite NGL net sales price was $1.06 per gallon in the
        fourth quarter 2011, up 5 percent compared with the same period last
        year; and down 3 percent compared with the third quarter 2011;
    --  The realized condensate net sales price was $85.39 per barrel in the
        fourth quarter 2011, up 33 percent compared with the same period last
        year; and down 3 percent compared with the third quarter 2011;
    --  The realized residue gas net sales price was $5.08 per million British
        thermal units (MMBtu) in the fourth quarter 2011, down 15 percent
        compared with the same period last year; and down 3 percent compared
        with the third quarter 2011; and
    --  The realized gross processing spread was $7.79 per MMBtu in the fourth
        quarter 2011, up 1 percent compared with the same period last year; and
        down 5 percent compared with the third 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             Years Ended
                                       December 31,               December 31,
    Operating
     Information
     (a)                             2011           2010        2011           2010
    ------------
    Percent of proceeds
      NGL sales
       (Bbl/d)                      6,777          7,133       6,472          6,310
      Residue gas
       sales
       (MMBtu/d)                   52,338         44,573      48,198         41,813
      Condensate
       sales
       (Bbl/d)                      1,438          1,652       1,684          1,763
      Percentage
       of total
       net margin                      62%            54%         61%            54%
    Fee-based
      Wellhead
       volumes
       (MMBtu/d)                1,057,269      1,042,159   1,030,045      1,067,090
      Average
       rate
       ($/MMBtu)                    $0.35          $0.33       $0.34          $0.31
      Percentage
       of total
       net margin                      32%            34%         32%            35%
    Keep-whole
      NGL shrink
       (MMBtu/d)
       (b)                          8,668         12,778      10,131         13,545
      Plant fuel
       (MMBtu/d)
       (b)                            837          1,676       1,104          1,648
      Condensate
       shrink
       (MMBtu/d)
       (b)                            761          1,096       1,082          1,433
      Condensate
       sales
       (Bbl/d)                        154            222         219            290
      Percentage
       of total
       net margin                       6%            12%          7%            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:



                                         Year Ending December 31, 2012
                                         -----------------------------
                                 Volumes        Average Price        Percentage
                                 Hedged         -------------          Hedged
                                 ------                                ------
                                                       /
    NGLs (Bbl/d) (a)               8,544       $1.24   gallon                72%
    Condensate (Bbl/d)                                 /
     (a)                           1,818       $2.43   gallon                73%
    ------------------             -----       -----   -------              ---
                                                       /
      Total (Bbl/d)               10,362       $1.45   gallon                72%
      =============               ======       =====   =======              ===
    Natural gas (MMBtu/                                /
     d)                           44,344       $4.13   MMBtu                 73%
    -------------------           ------       -----  ------                ---
    (a) - Hedged with fixed-
     price swaps.

                                        Year Ending December 31, 2013
                                        -----------------------------
                                 Volumes       Average Price        Percentage
                                 Hedged        -------------          Hedged
                                 ------                               ------
                                                       /
    NGLs (Bbl/d) (a)                 367       $2.55   gallon                 2%
    Condensate (Bbl/d)                                 /
     (a)                             649       $2.55   gallon                23%
    ------------------               ---       -----   -------              ---
                                                       /
      Total (Bbl/d)                1,016       $2.55   gallon                 4%
      =============                =====       =====   =======              ===
    Natural gas (MMBtu/                                /
     d)                           50,137       $3.85   MMBtu                 75%
    -------------------           ------       -----   -----                ---
    (a) - Hedged with fixed-price swaps.

                                 `

Natural Gas Pipelines Segment

The natural gas pipelines segment reported fourth-quarter 2011 operating income of $29.5 million, compared with $40.9 million for the fourth quarter 2010.

Fourth-quarter 2011 results reflect a $2.3 million decrease from lower transportation margins, due primarily to narrower natural gas price location differentials, which reduced contracted transportation capacity on Midwestern Gas Transmission, and reduced interruptible transportation volumes across several of its pipelines.

Operating income for the full year 2011 was $130.1 million, compared with $163.0 million in 2010.

Full-year 2011 results reflect a $12.5 million decrease from lower transportation margins, primarily due to narrower natural gas price location differentials that reduced contracted transportation capacity on Midwestern Gas Transmission and reduced interruptible transportation volumes across several of its pipelines; and a $5.0 million decrease from lower realized prices on its retained fuel position.

Operating costs were $29.5 million in the fourth quarter 2011, compared with $25.3 million in the same period last year. Full-year 2011 operating costs were $108.6 million, compared with $96.5 million in 2010. The increase in operating costs for both the three-month and full-year 2011 periods were due primarily to higher labor and employee-related costs associated with incentive and benefit plans, which includes equity-based compensation costs, and higher property taxes.

Equity earnings from investments were $19.4 million in the fourth quarter 2011, compared with $19.9 million in the same period in 2010. Full-year 2011 equity earnings from investments were $76.9 million, compared with $68.8 million in 2010. The full-year 2011 increase was due to higher contracted capacity on Northern Border Pipeline due to wider natural gas price differentials between the markets it serves. Substantially all of Northern Border Pipeline's long-haul capacity is contracted through March 2013.

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

    --  Natural gas transportation capacity contracted totaled 5,433 thousand
        dekatherms per day in the fourth quarter 2011, down 3 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 up 6 percent compared with the
        third quarter 2011;
    --  Natural gas transportation capacity subscribed was 84 percent in the
        fourth quarter 2011 compared with 87 percent in the same period last
        year; and up from 79 percent in the third quarter 2011; and
    --  The average natural gas price in the Mid-Continent region was $3.20 per
        MMBtu in the fourth quarter 2011, down 12 percent compared with the same
        period last year; and down 20 percent compared with the third quarter
        2011.

Natural Gas Liquids Segment

The natural gas liquids segment reported fourth-quarter 2011 operating income of $245.1 million, compared with $80.4 million for the fourth quarter 2010.

Fourth-quarter 2011 results reflect:

    --  A $156.3 million increase in optimization and marketing margins
        primarily due to favorable NGL price differentials and increased NGL
        fractionation and transportation capacity available for optimization
        activities between the Mid-Continent and Gulf-Coast markets;
    --  A $13.6 million increase in isomerization margins from wider price
        differentials between normal butane and iso-butane, and higher
        isomerization volumes;
    --  A $3.2 million increase due to higher storage margins as a result of
        favorable contract renegotiations; and
    --  A $2.9 million increase from higher NGL volumes gathered and
        fractionated, and favorable contract renegotiations associated with its
        exchange-services activities.

Operating costs were $57.8 million in the fourth quarter 2011, compared with $47.8 million in the fourth quarter 2010 due primarily to higher labor and employee-related costs associated with incentive and benefit plans, which includes equity-based compensation costs; and higher expenses for materials and outside services associated with scheduled maintenance at its fractionation and pipeline facilities.

Operating income for the full-year 2011 was $628.6 million, compared with $272.3 million in 2010.

Full-year 2011 results reflect:

    --  A $363.6 million increase in optimization and marketing margins
        primarily due to favorable NGL price differentials and increased NGL
        fractionation and transportation capacity available for optimization
        activities between the Mid-Continent and Gulf-Coast markets;
    --  A $32.5 million increase from higher NGL volumes gathered and
        fractionated, and favorable contract renegotiations associated with its
        exchange-services activities;
    --  A $26.4 million increase in isomerization margins from wider price
        differentials between normal butane and iso-butane, and higher
        isomerization volumes; and
    --  A $12.4 million increase due to higher storage margins as a result of
        favorable contract renegotiations.

These 2011 increases were offset partially by a $42.8 million decrease, compared with 2010, resulting from the deconsolidation of Overland Pass Pipeline in September 2010 and a $16.3 million gain on the sale of a 49-percent ownership interest in Overland Pass Pipeline Company recorded in the third quarter 2010.

Full-year 2011 operating costs were $198.9 million, compared with $173.9 million in 2010. This increase was due primarily to higher labor and employee-related costs associated with incentive and benefit plans, which includes equity-based compensation costs; higher expenses for materials and outside services associated with scheduled maintenance at its fractionation, pipeline and storage facilities; and higher property taxes. These increases were offset partially by the deconsolidation of Overland Pass Pipeline in September 2010.

Equity earnings from investments were $5.5 million in the fourth quarter 2011, compared with $4.0 million in the same period in 2010. Full-year 2011 equity earnings from investments were $19.9 million, compared with $5.6 million in the same period last year. The full-year increase was due to the deconsolidation of Overland Pass Pipeline in September 2010.

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

    --  NGLs fractionated totaled 583 thousand barrels per day (MBbl/d) in the
        fourth quarter 2011, up 10 percent compared with the same period last
        year due primarily to increased throughput 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 10 percent compared with the third quarter 2011;
    --  NGLs transported on gathering lines totaled 473 MBbl/d in the fourth
        quarter 2011, up 17 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 7
        percent compared with the third quarter 2011;
    --  NGLs transported on distribution lines totaled 512 MBbl/d in the fourth
        quarter 2011, up 10 percent compared with the same period last year; and
        up 12 percent compared with the third quarter 2011 due primarily to
        increased volumes transported to Midwest markets on the North System
        pipeline and the completion of the Sterling I pipeline expansion project
        in the fourth quarter of 2011; and
    --  The Conway-to-Mont Belvieu average price differential for ethane, based
        on Oil Price Information Service (OPIS) pricing, was 49 cents per gallon
        in the fourth quarter 2011, compared with 8 cents per gallon in the same
        period last year; and 27 cents per gallon in the third quarter 2011.

GROWTH ACTIVITIES:

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

    --  Approximately $910 million to $1.2 billion for natural gas liquids
        projects including:
        --  The construction of a 570-plus-mile, 16-inch NGL pipeline, the
            Sterling III Pipeline, expected to cost approximately $610 million
            to $810 million and 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
            barrels per day (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 and be completed in
            mid-2013;
    --  Approximately $350 million to $415 million for the Garden Creek plant, a
        new 100-million-cubic-feet-per-day (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 $595 million to $730 million of natural gas liquids
        projects that have 100 percent of the available capacity committed and
        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., which is expected
            to be in service during the first half of 2013, with the initial
            capacity of 60,000 bpd and can be expanded to 110,000 bpd with
            additional pump stations;
        --  A 60,000-bpd capacity expansion on the 50-percent-owned Overland
            Pass Pipeline to transport the additional unfractionated NGL volumes
            from the new Bakken Pipeline; and
        --  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 the additional NGL volumes;
    --  Approximately $180 million to $240 million 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 are expected to be
        completed early in the second quarter 2012 and will connect three new
        third-party natural gas processing facilities with total expected
        capacity of 510 MMcf/d and three existing third-party natural gas
        processing facilities that are being expanded; and include the
        installation of additional pump stations on the Arbuckle Pipeline to
        increase its capacity to 240,000 bpd; and
    --  The partnership completed at the end of 2011 the installation of seven
        additional pump stations along the existing Sterling I NGL distribution
        pipeline, estimated at approximately $30 million; the additional pump
        stations increased its capacity by 15,000 bpd.

2012 EARNINGS GUIDANCE INCREASED

ONEOK Partners increased its 2012 net income guidance to the range of $810 million to $870 million, compared with its previous range of $740 million to $800 million, provided Sept. 26, 2011. 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 increased to the range of $925 million to $985 million, compared with its previous range of $845 million to $915 million.

The midpoint for ONEOK Partners' 2012 EBITDA increased to approximately $1.25 billion, compared with its previous guidance of $1.17 billion.

The midpoint for ONEOK Partners' 2012 operating income increased to $910 million, compared with its previous guidance of $833 million.

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

The midpoint of the natural gas gathering and processing segment's 2012 operating income guidance is $247 million, compared with its previous guidance of $297 million, reflecting lower commodity price assumptions.

The average unhedged prices assumed for 2012 are $97.75 per barrel for New York Mercantile Exchange (NYMEX) crude oil, $3.30 per MMBtu for NYMEX natural gas and $1.20 per gallon for composite natural gas liquids. Previous guidance released on Sept. 26, 2011, assumed $99.30 per barrel for NYMEX crude oil, $4.71 per MMBtu for NYMEX natural gas and $1.42 per gallon for composite natural gas liquids.

For 2012, financial hedges are in place on approximately 73 percent of the segment's expected equity natural gas production at an average price of $4.13 per million British thermal units (MMBtu); 72 percent of its expected equity natural gas liquids production at an average price of $1.24 per gallon; and 73 percent of its expected equity condensate production at an average price of $2.43 per gallon.

For 2012, the partnership 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 $1.7 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 $2.2 million. All of these sensitivities exclude the effects of hedging and assume normal operating conditions.

The midpoint of the natural gas pipelines segment's 2012 operating income guidance is $135 million, compared with its previous guidance of $141 million. These lower expected earnings are due primarily to lower natural gas price assumptions on its retained fuel position. 2012 guidance assumes that approximately 81 percent of transportation capacity and 100 percent of natural gas storage capacity will be contracted for 2012.

The midpoint of the natural gas liquids segment's 2012 operating income guidance has been increased to $528 million, compared with its previous guidance of $395 million. Updated guidance reflects more favorable NGL price differentials.

For 2012, the Conway-to-Mont Belvieu OPIS average ethane price differential is expected to be 32 cents, compared with its previous guidance of 12 cents provided on Sept. 26, 2011.

Capital expenditures for 2012 are expected to be approximately $2.0 billion, comprised of approximately $1.9 billion in growth capital and $109 million in maintenance capital.

2012 earnings guidance includes a projected 2.5-cent-per-quarter increase in unitholder distributions, higher than the 2-cent-per-quarter increase in guidance provided in September 2011. 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 Tuesday, Feb. 21, 2012, at 11 a.m. Eastern Standard Time (10 a.m. Central Standard Time). The call will also be carried live on ONEOK Partners' and ONEOK's websites.

To participate in the telephone conference call, dial 888-857-6931, pass code 7074825, 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 7074825.

LINK TO EARNINGS TABLES:

http://www.oneokpartners.com/Investor/FinancialInformation/~/media/ONEOKPartners/EarningsTables/OKS_Q4_2011_Earnings_19Zxug3.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.

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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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