ONEOK Partners Reports Higher 2012 Earnings and Lower Fourth-quarter Results

 ONEOK Partners Reports Higher 2012 Earnings and Lower Fourth-quarter Results

Reduces 2013 Earnings Guidance and Revises Three-year Financial Forecasts

Full-Year Net Income Rises 7 Percent Led by Higher Natural Gas and Natural Gas
Liquids Volumes

PR Newswire

TULSA, Okla., Feb. 25, 2013

TULSA, Okla., Feb. 25, 2013 /PRNewswire/ --ONEOK Partners, L.P. (NYSE: OKS)
today announced that 2012 net income attributable to ONEOK Partners was $888.0
million, or $3.04 per unit, a 7 percent increase, compared with $830.3
million, or $3.35 per unit, in 2011.

Fourth-quarter 2012 net income attributable to ONEOK Partners was $210.4
million, or 66 cents per unit, compared with $298.6 million, or $1.26 per
unit, for the same period in 2011.

There was an average of approximately 217.1 million units outstanding for
2012, compared with 203.8 million units outstanding in 2011. An equity
offering and private placement in March 2012 included the issuance of 16
million additional units.

"The partnership performed well in 2012, as completed growth projects resulted
in increased volumes of natural gas and natural gas liquids across our
systems," said John W. Gibson, chairman and chief executive officer of ONEOK
Partners. "During the year, our capital-investment program increased to
approximately $4.7 billion to $5.3 billion to build additional natural gas and
natural gas liquids infrastructure through 2015."

"Our fourth-quarter results reflect significantly narrower natural gas liquids
price differentials, compared with historically wide differentials in 2011 in
our natural gas liquids segment," Gibson said. "Our natural gas gathering and
processing segment benefited from volume growth, primarily from our new Garden
Creek and Stateline I natural gas processing plants in the Williston Basin and
increased well connections in the area."

2013 REVISED EARNINGS GUIDANCE AND THREE-YEAR GROWTH FORECASTS

The partnership reduced its 2013 net income guidance range to $790 million to
$870 million, compared with the previous guidance range of $935 million to
$1.015 billion announced on Sept. 24, 2012. In addition, the partnership's
distributable cash flow (DCF) is now expected to be in the range of $910
million to $1.0 billion, compared with the previous guidance range of $1.05
billion to $1.14 billion. 

Half of the reduction in 2013 operating income and equity earnings guidance is
due to lower expected natural gas liquids (NGL) volumes as a result of
widespread and prolonged ethane rejection. Narrower expected NGL location
price differentials and lower expected NGL prices, particularly ethane and
propane, also are expected to affect 2013 earnings.

2013 revised guidance now includes a projected 0.5-cent-per-unit-per-quarter
increase in unitholder distributions, subject to ONEOK Partners board
approval, compared with its previous guidance of a 2-cent-per-unit-per-quarter
increase.

"If industry conditions improve, we will re-evaluate our 2013 earnings
guidance anddistribution increases," said Gibson. "Our projected 2013
distribution increases will allow us to maintain a coverage ratio of 1.0 to
1.05 times."

ONEOK Partners also revised its 2012 to 2015 three-year growth forecasts for
earnings before interest, taxes, depreciation and amortization (EBITDA) and
distribution growth, compared with the forecasts it announced on Sept. 24,
2012.

ONEOK Partners now expects EBITDA to increase by an average of 15 to 20
percent annually over a three-year period, comparing 2012 results with 2015.
Previously, ONEOK Partners estimated a three-year average annual growth rate
of 17 to 21 percent, comparing 2012 guidance provided on Sept. 24, 2012, with
2015.

The revision to the three-year growth forecast is due primarily to lower than
expected NGL exchange margins in the Rocky Mountain region and lower expected
NGL and natural gas prices in 2014 and 2015.

The partnership now has estimated an average annual distribution increase of 8
to 12 percent between 2012 and 2015, subject to ONEOK Partners board approval,
compared with its previous guidance of 10 to 15 percent.

"We do not expect prolonged ethane rejection to continue into 2014, although
there may be intermittent periods when ethane will be left in the natural gas
stream," said Gibson.

The reduced 2013 earnings guidance and revised three-year growth forecasts are
not expected to affect current or projected timelines or project costs in the
partnership's announced $4.7 billion to $5.3 billion capital-growth program.

FOURTH-QUARTER AND FULL-YEAR 2012 FINANCIAL PERFORMANCE

In the fourth quarter 2012, EBITDA was $314.7 million, compared with $399.8
million in the fourth quarter 2011. EBITDA for the full year was $1.29
billion, a 4 percent increase, compared with $1.24 billion in 2011.

DCF for the fourth quarter 2012 was $227.0 million, compared with $321.3
million in the fourth quarter 2011. DCF for the full year 2012 was $1.0
billion, a 6 percent increase, compared with $946.0 million in 2011.

Operating income for the fourth quarter 2012 was $230.5 million, compared with
$317.5 million in the same period in 2011. For the full year 2012, operating
income was $962.9 million, compared with $939.5 million in 2011.

The decrease in operating income for the fourth quarter 2012 reflects lower
NGL optimization margins primarily from narrower NGL location price
differentials, offset by higher NGL volumes gathered and fractionated in the
natural gas liquids segment. The natural gas gathering and processing segment
benefited from higher natural gas volumes gathered and processed, offset
partially by higher compression costs and less favorable contract terms
associated with volume growth in the Williston Basin, and lower realized
natural gas and NGL prices, particularly ethane and propane.

The increase in operating income for the full-year 2012 period reflects higher
natural gas volumes gathered and processed in the natural gas gathering and
processing segment, offset partially by higher compression costs and less
favorable contract terms associated with volume growth in the Williston Basin
and lower realized natural gas and NGL prices, particularly ethane and
propane. The natural gas liquids segment benefited from higher NGL volumes
gathered and fractionated, offset partially by decreased optimization margins
resulting from narrower NGL location price differentials and less NGL
transportation capacity available for optimization activities.

Operating costs were $122.1 million in the fourth quarter 2012, compared with
$130.7 million for the same period last year. Operating costs for the
full-year 2012 period were $482.5 million, compared with $459.4 million in
2011. The increases for the full-year 2012 period were due primarily to the
partnership's expanding operations from several growth projects placed into
service.

Capital expenditures were $549.0 million in the fourth quarter 2012, compared
with $401.0 million in the same period in 2011. Full-year 2012 capital
expenditures were $1.6 billion, compared with $1.1 billion in 2011. These
increases were related to growth projects in the natural gas liquids segment.

Interest expense was $57.9 million in the fourth quarter 2012, compared with
$52.5 million for the same period in 2011. Fourth-quarter interest expense
reflects an increase due primarily to its September 2012 issuance of $1.3
billion senior notes, offset partially by higher capitalized interest and the
April 2012 repayment of its $350 million senior notes. Interest expense for
the full-year 2012 period was $206.0 million, compared with $223.1 million in
2011. The decrease for the full year 2012 was primarily driven by higher
capitalized interest and the repayment of its $350 million senior notes in
April 2012.

> View earnings tables

2012 SUMMARY AND ADDITIONAL UPDATES:

  o2012 operating income of $962.9 million, compared with $939.5 million in
    2011;
  oNatural gas gathering and processing segment operating income of $210.4
    million, compared with $180.6 million in 2011;
  oNatural gas pipelines segment operating income of $143.8 million, compared
    with $130.1 million in 2011;
  oNatural gas liquids segment operating income of $608.2 million, compared
    with $628.6 million in 2011;
  oEquity earnings from investments of $123.0 million, compared with $127.2
    million in 2011;
  oCapital expenditures of $1.6 billion, compared with $1.1 billion in 2011;
  oEntering into an equity distribution agreement through which it may, from
    time to time, offer common units representing limited-partner interests up
    to an aggregate amount of $300 million;
  oAnnouncing in November 2012 not to proceed with the Bakken Crude Express
    Pipeline due to insufficient long-term transportation commitments during
    its open season, which concluded Nov. 20, 2012;
  oHaving $537.1 million of cash and cash equivalents and no commercial paper
    or borrowings outstanding, under the partnership's $1.2 billion revolving
    credit facility as of Dec. 31, 2012;
  oONEOK Partners in January 2013 increasing its distribution for the fourth
    quarter 2012 by 4 percent from the previous quarter to 71 cents per unit,
    or $2.84 per unit on an annualized basis, payable on Feb. 14, 2013, to
    unitholders of record at the close of business Jan. 31, 2013; and
  oAnnouncing in December 2012 a reorganization to further enhance its
    commercial and operating capabilities. Pierce H. Norton II now leads
    commercial activities; Robert F. Martinovich now leads operating
    activities; Derek S. Reiners was named chief financial officer and
    treasurer; and Sheppard F. Miers III was named chief accounting officer.

BUSINESS-UNIT RESULTS:

Natural Gas Gathering and Processing Segment

The natural gas gathering and processing segment reported fourth-quarter 2012
operating income of $59.1 million, compared with $42.3 million for the fourth
quarter 2011.

Fourth-quarter 2012 results reflect:

  oA $38.4 million increase due to volume growth in the Williston Basin from
    the completion of the Garden Creek and Stateline I natural gas processing
    plants and increased well connections, which resulted in higher natural
    gas volumes gathered, compressed, processed, transported and sold, and
    higher fees;
  oA $10.6 million decrease due primarily to higher compression costs and
    less favorable contract terms associated with volume growth in the
    Williston Basin;
  oA $5.1 million decrease from lower realized natural gas and NGL prices,
    particularly ethane and propane; and
  oA $1.8 million decrease from lower natural gas volumes gathered in the
    Powder River Basin as a result of continued production declines.

Operating income for the full-year 2012 period was $210.4 million, compared
with $180.6 million in 2011.

Full-year 2012 results reflect:

  oA $131.5 million increase due to volume growth in the Williston Basin from
    the completion of the Garden Creek and Stateline I natural gas processing
    plants and increased well connections, which resulted in higher natural
    gas volumes gathered, compressed, processed, transported and sold, and
    higher fees;
  oA $38.1 million decrease due primarily to higher compression costs and
    less favorable contract terms associated with volume growth in the
    Williston Basin;
  oA $31.4 million decrease from lower net realized natural gas and NGL
    prices, particularly ethane and propane; and
  oA $5.9 million decrease from lower natural gas volumes gathered in the
    Powder River Basin as a result of continued production declines.

Operating costs in the fourth quarter 2012 were $43.2 million, compared with
$44.1 million in the same period last year.

Full-year 2012 operating costs were $164.0 million, compared with $153.7
million in 2011. The increase was due primarily to a $4.9 million increase in
materials, supplies and outside services expenses; a $2.1 million increase in
property taxes; and a $1.5 million increase in labor and employee-related
costs.

Key Statistics: More detailed information is listed in tables.

  oNatural gas gathered was 1,201 billion British thermal units per day
    (BBtu/d) in the fourth quarter 2012, up 14 percent compared with the same
    period last year due to increased well connections in the Williston Basin
    and in western Oklahoma, and the completion of additional natural gas
    gathering lines and compression to support the partnership's Garden Creek
    and Stateline I natural gas processing plants in the Williston Basin;
    offset partially by continued production declines in the Powder River
    Basin in Wyoming; and up 5 percent compared with the third quarter 2012;
  oNatural gas processed was 964 BBtu/d in the fourth quarter 2012, up 27
    percent compared with the same period last year due to increased well
    connections in the Williston Basin and western Oklahoma, and the
    completion of the partnership's Garden Creek and Stateline I natural gas
    processing plants in the Williston Basin; and up 6 percent compared with
    the third quarter 2012;
  oThe realized composite NGL net sales price was $1.05 per gallon in the
    fourth quarter 2012, down 1 percent compared with the same period last
    year; and down 5 percent compared with the third quarter 2012;
  oThe realized condensate net sales price was $90.21 per barrel in the
    fourth quarter 2012, up 6 percent compared with the same period last year;
    and up 4 percent compared with the third quarter 2012;
  oThe realized residue natural gas net sales price was $4.27 per million
    British thermal units (MMBtu) in the fourth quarter 2012, down 16 percent
    compared with the same period last year; and up 16 percent compared with
    the third quarter 2012; and
  oThe realized gross processing spread was $7.51 per MMBtu in the fourth
    quarter 2012, down 4 percent compared with the same period last year; and
    down 8 percent compared with the third quarter 2012.

The segment's total equity volumes are increasing, and the composition of the
equity NGL barrel continues to change as new natural gas processing plants in
the Williston Basin are placed into service. The Garden Creek and Stateline I
natural gas processing plants have the capability to recover ethane when
economic conditions warrant but will not do so until the Bakken NGL Pipeline
is completed, which is expected to occur in the first quarter 2013. As a
result, its 2012 equity NGL volumes and realized composite NGL net sales price
were weighted more toward the relatively higher priced propane, iso-butane,
normal butane and natural gasoline, compared with the prior year. This had
the effect of producing a higher realized price for the NGL composite barrel
even though most individual NGL product prices were substantially lower in
2012 compared with 2011.

For the full-year 2012, the segment connected approximately 940 new wells,
compared with approximately 600 in 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)           2012       2011       2012       2011
Percent of proceeds
 NGL sales (Bbl/d) (b)            11,186     6,777      9,803      6,472
 Residue gas sales (MMBtu/d) (b)  71,044     52,338     65,205     48,198
 Condensate sales(Bbl/d)(b)       1,877      1,438      2,104      1,684
 Percentage of total net margin    67%        62%        64%        61%
Fee-based
 Wellhead volumes (MMBtu/d)        1,200,980  1,057,269  1,118,693  1,030,045
 Average rate ($/MMBtu)            $       $       $       $   
                                    0.33      0.35      0.35      0.34
 Percentage of total net margin    30%        32%        31%        32%
Keep-whole
 NGL shrink (MMBtu/d) (c)          7,001      8,668      6,747      10,131
 Plant fuel (MMBtu/d) (c)          743        837        757        1,104
 Condensate shrink (MMBtu/d)(c)    342        761        904        1,082
 Condensate sales (Bbl/d)          69         154        183        219
 Percentage of total net margin    3%         6%         5%         7%
(a) - Includes volumes for consolidated entities only.
(b) - Represent equity volumes.
(c) - 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 for its equity volumes in the
natural gas gathering and processing segment for the periods indicated:

                     Year Ending December 31, 2013
                     Volumes Hedged  Average Price   Percentage Hedged
NGLs (Bbl/d)        6,439           $1.19 / gallon  45%
Condensate (Bbl/d)  2,038           $2.43 / gallon  83%
Total (Bbl/d)        8,477           $1.49 / gallon  51%
Natural gas(MMBtu/d) 60,014          $3.79 / MMBtu   79%
                     Year Ending December 31, 2014
                     Volumes Hedged  Average Price   Percentage Hedged
Condensate (Bbl/d)  868             $2.22 / gallon  33%
Natural gas(MMBtu/d) 36,726          $4.11 / MMBtu   48%

The partnership currently estimates that in its natural gas gathering and
processing segment, a 1-cent-per-gallon change in the composite price of NGLs
would change annual net margin by approximately $2.1 million. A
$1.00-per-barrel change in the price of crude oil would change annual net
margin by approximately $1.1 million. Also, a 10-cent-per-MMBtu change in the
price of natural gas would change annual net margin by approximately $2.8
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 fourth-quarter 2012 operating
income of $44.7 million, compared with $29.5 million for the fourth quarter
2011.

Fourth-quarter 2012 results reflect a $2.0 million increase from higher
retained fuel volumes and a $1.6 million increase due to higher contracted
capacity on its intrastate natural gas pipelines.

Operating income for the full year 2012 was $143.8 million, compared with
$130.1 million in 2011.

Full-year 2012 results reflect a $3.3 million increase from higher contracted
capacity on its intrastate natural gas pipelines, offset partially by lower
negotiated rates on Midwestern Gas Transmission. This increase was offset
partially by a decrease of $1.0 million from lower natural gas prices on its
net retained fuel position.

Additionally, a $5.7 million pre-tax gain on the sale of a natural gas
pipeline lateral was recorded in the fourth quarter 2012.

Operating costs were $23.6 million in the fourth quarter 2012, compared with
$29.5 million in the same period last year. Full-year 2012 operating costs
were $101.9 million, compared with $108.6 million in 2011. The decrease in
operating costs for both the three-month and full-year 2012 periods was due
primarily to lower employee-related costs associated with incentive and
benefit plans.

Equity earnings, primarily from the partnership's 50 percent-owned Northern
Border Pipeline, were $18.2 million in the fourth quarter 2012, compared with
$19.4 million in the same period in 2011. Full-year 2012 equity earnings from
investments were $73.2 million, compared with $76.9 million in the same period
last year. The decrease in equity earnings for full year 2012 was due
primarily to an increase in maintenance expenses on Northern Border Pipeline.

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

  oNatural gas transportation capacity contracted was 5,429 thousand
    dekatherms per day in the fourth quarter 2012, relatively unchanged
    compared with the same period last year; and up 3 percent compared with
    the third quarter 2012;
  oNatural gas transportation capacity subscribed was 90 percent in the
    fourth quarter 2012, unchanged compared with the same period last year;
    and up 3 percent from the third quarter 2012; and
  oThe average natural gas price in the Mid-Continent region was $3.29 per
    MMBtu in the fourth quarter 2012, up 3 percent compared with the same
    period last year; and up 20 percent compared with the third quarter 2012.

Natural Gas Liquids Segment

The natural gas liquids segment reported fourth-quarter 2012 operating income
of $125.8 million, compared with $245.1 million for the fourth quarter 2011.

Fourth-quarter 2012 results reflect:

  oA $141.4 million decrease due primarily to narrower NGL location price
    differentials;
  oA $7.3 million decrease in isomerization margins from lower isomerization
    volumes;
  oA $3.1 million decrease due to the impact of operational measurement
    losses;
  oA $32.8 million increase from higher NGL volumes gathered and
    fractionated, and higher fees from contract renegotiations for its NGL
    exchange-services activities; and
  oA $3.5 million increase due to higher NGL storage margins as a result of
    favorable contract renegotiations.

Operating income for the full year 2012 was $608.2 million, compared with
$628.6 million in 2011.

Full-year 2012 results reflect:

  oA $101.5 million increase from higher NGL volumes gathered and
    fractionated related to the completion of certain growth projects and
    higher fees from contract renegotiations for its NGL exchange-services
    activities;
  oA $13.1 million increase due to higher NGL storage margins as a result of
    favorable contract renegotiations;
  oA $91.2 million decrease in optimization and marketing margins, which
    resulted from a $94.6 million decrease from narrower NGL location price
    differentials and less transportation capacity available for optimization
    activities; an increasing portion of its transportation capacity between
    the Conway, Kan., and Mont Belvieu, Texas, NGL market centers now is
    utilized by its exchange-services activities to produce fee-based
    earnings. This decrease was offset partially by a $3.5 million increase
    in its marketing activities, which benefited from higher NGL truck and
    rail volumes;
  oA $4.5 million decrease due to the impact of operational measurement
    losses; and
  oA $3.4 million decrease due to lower isomerization margins from lower
    isomerization volumes.

Operating costs were $57.2 million in the fourth quarter 2012, compared with
$57.8 million in the fourth quarter 2011. Full-year 2012 operating costs were
$223.8 million, compared with $198.9 million in 2011. The full-year increase
was due to higher material and outside services expenses associated with
scheduled maintenance and an increase in employee-related costs.

Equity earnings from investments were $4.3 million in the fourth quarter 2012,
compared with $5.5 million in the same period in 2011. Full-year 2012 equity
earnings from investments were $20.7 million, compared with $19.9 million in
2011.

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

  oNGLs fractionated were 600,000 barrels per day (bpd) in the fourth quarter
    2012, up 3 percent compared with the same period last year, due primarily
    to increased throughput from existing connections and new supply
    connections in the Mid-Continent and Rocky Mountain regions; and up 3
    percent compared with the third quarter 2012;
  oNGLs transported on gathering lines were 531,000 bpd in the fourth quarter
    2012, up 12 percent compared with the same period last year, due primarily
    to increased production through existing supply connections, and new
    supply connections in the Mid-Continent and Rocky Mountain regions; and
    relatively unchanged compared with the third quarter 2012;
  oNGLs transported on distribution lines were 507,000 bpd in the fourth
    quarter 2012, down 1 percent compared with the same period last year; and
    up 1 percent compared with the third quarter 2012; and
  oThe average Conway-to-Mont Belvieu price differential of ethane in
    ethane/propane mix, based on Oil Price Information Service (OPIS) pricing,
    was 7 cents per gallon in the fourth quarter 2012, compared with 49 cents
    per gallon in the same period last year; and 16 cents per gallon in the
    third quarter 2012.

GROWTH ACTIVITIES:

The partnership has announced approximately $4.7 billion to $5.3 billion in
growth projects, including:

  oApproximately $2.6 billion to $3.0 billion for the following natural gas
    liquids projects:

       oThe installation of seven additional pump stations along its existing
         Sterling I NGL distribution pipeline, which cost approximately $30
         million and was completed at the end of 2011; the additional pump
         stations increased the pipeline's capacity by 15,000 bpd;
       oApproximately $220 million to construct more than 230 miles of 10-
         and 12-inch diameter NGL pipelines that expanded the partnership's
         existing Mid-Continent NGL gathering system in the Cana-Woodfordand
         Granite Wash areas by adding an incremental 75,000 bpd to 80,000 bpd
         of raw, unfractionated NGLs to the partnership's existing NGL
         gathering systems in the Mid-Continent and the Arbuckle Pipeline.
         Construction of these NGL pipelines was completed in April 2012, and
         the partnership connected three new third-party natural gas
         processing facilities and three existing third-party natural gas
         processing facilities that were expanded to its NGL gathering
         system. In addition, the installation of additional pump stations on
         the Arbuckle Pipeline was completed, increasing its capacity to
         240,000 bpd;
       oApproximately $117 million for a 60,000-bpd expansion of the
         partnership's NGL fractionation capacity at Bushton, Kan., which was
         completed in September 2012, to accommodate NGL volumes from the
         Mid-Continent and Williston Basin;
       oApproximately $450 million to $550 million for the construction of an
         approximately 600-mile NGL pipeline – the Bakken NGL Pipeline – to
         transport unfractionated NGLs produced from the Bakken Shale in the
         Williston Basin to the Overland Pass Pipeline, a 760-mile NGL
         pipeline extending from southern Wyoming to Conway, Kan. The Bakken
         NGL Pipeline is expected to be in service during the first quarter
         2013, with an initial capacity of 60,000 bpd;
       oApproximately $35 million to $40 million on the partnership's 50
         percent-owned Overland Pass Pipeline for a 60,000-bpd capacity
         expansion to transport the additional unfractionated NGL volumes from
         the Bakken NGL Pipeline;
       oApproximately $300 million to $390 million for the construction of a
         75,000-bpd NGL fractionator, MB-2, at Mont Belvieu, Texas, that is
         expected to be completed in mid-2013;
       oApproximately $610 million to $810 million for the construction of a
         540-plus-mile, 16-inch NGL pipeline – the Sterling III Pipeline –
         expected to be completed in late 2013, to transport either
         unfractionated NGLs or NGL purity products from the Mid-Continent
         region to the Texas Gulf Coast with an initial capacity of 193,000
         bpd and the ability to expand to 250,000 bpd; and the reconfiguration
         of its existing Sterling I and II NGL distribution pipelines to
         transport either unfractionated NGLs or NGL purity products;
       oApproximately $45 million to install a 40,000 bpd ethane/propane
         (E/P) splitter at its Mont Belvieu storage facility to split E/P mix
         into purity ethane, that is expected to be completed in the second
         quarter 2014;
       oApproximately $525 million to $575 million for the construction of a
         75,000-bpd NGL fractionator, MB-3, and related infrastructure at Mont
         Belvieu, Texas, that is expected to be completed in the fourth
         quarter 2014;
       oApproximately $100 million to install additional pump stations on the
         Bakken NGL Pipeline to increase its capacity to 135,000 bpd from an
         initial capacity of 60,000 bpd. The expansion is expected to be
         completed in the third quarter 2014; and
       oApproximately $140 million, announced in January 2013, for the
         construction of an approximately 95-mile NGL pipeline between
         existing NGL fractionation infrastructure at Hutchinson, Kan., and
         Medford, Okla., and the modification of the partnership's NGL
         fractionation infrastructure at Hutchinson, Kan., to accommodate
         lighter, unfractionated NGLs produced in the Williston Basin; both
         projects are expected to be completed in the first quarter 2015.

  oApproximately $2.1 billion to $2.3 billion for the following natural gas
    gathering and processing projects including:

       oApproximately $360 million for the Garden Creek plant, a 100-MMcf/d
         natural gas processing facility in the Bakken Shale and Three Forks
         formations in the Williston Basin in North Dakota that was placed
         into 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;
       oApproximately $560 million to $660 million to construct the Stateline
         I and II plants, 100-MMcf/d natural gas processing facilities, and
         related NGL infrastructure, expansions and upgrades to the existing
         gathering and compression infrastructure, and new well connections in
         the Bakken Shale and Three Forks formations in the Williston Basin in
         North Dakota. The Stateline I plant was placed in service in
         September 2012, with the Stateline II plant expected to be in service
         in the first quarter 2013;
       oApproximately $140 million to $160 million to construct a 270-mile
         natural gas gathering system and related infrastructure in Divide
         County, N.D. This system, which is expected to be in service in the
         third quarter 2013, will gather and transport natural gas from
         producers in the Bakken Shale and Three Forks formations in the
         Williston Basin to the partnership's previously announced 100-MMcf/d
         Stateline II natural gas processing facility in western Williams
         County, N.D.;
       oApproximately $340 million to $360 million to construct the Canadian
         Valley plant, a 200-MMcf/d natural gas processing facility in the
         Cana-Woodford Shale in Oklahoma, which is expected to be in service
         in the first quarter 2014; and expansions and upgrades to the
         existing gathering and compression infrastructure;
       oApproximately $310 million to $345 million to construct the Garden
         Creek II plant, a 100-MMcf/d natural gas processing facility in the
         Bakken Shale and Three Forks formations in the Williston Basin in
         North Dakota, which is expected to be in service in the third quarter
         2014; and expansions and upgrades to the existing gathering and
         compression infrastructure; and
       oApproximately $325 million to $360 million, announced in January
         2013, to construct the Garden Creek III plant, a 100-MMcf/d natural
         gas processing facility in the Bakken Shale and Three Forks
         formations in the Williston Basin in North Dakota, which is expected
         to be in service in the first quarter 2015; and expansions and
         upgrades to the existing gathering and compression infrastructure.

2013 REVISED EARNINGS GUIDANCE AND THREE-YEAR GROWTH FORECASTS

ONEOK Partners' 2013 net income guidance is expected to be in the range of
$790 million to $870 million, compared with its previous guidance range of
$935 million to $1.015 billion, announced on Sept. 24, 2012.

Estimates for the partnership's 2013 DCF are expected to be in the range of
$910 million to $1.0 billion, compared with its previous range of $1.05
billion to $1.14 billion.

2013 revised guidance now includes a projected 0.5-cent-per-unit-per-quarter
increase in unitholder distributions, subject to ONEOK Partners board
approval, compared with its previous guidance of a 2-cent-per-unit-per-quarter
increase.

Half of the reduction in 2013 operating income and equity earnings guidance
reflects lower anticipated earnings in the partnership's natural gas liquids
segment due to lower expected NGL volumes as a result of widespread and
prolonged ethane rejection. Narrower expected NGL location price
differentials in the natural gas liquids segment and lower expected NGL
prices, particularly ethane and propane, in the natural gas gathering and
processing segment also are expected to affect the partnership's 2013
earnings.

ONEOK Partners now expects EBITDA to increase by an average of 15 to 20
percent annually over a three-year period, comparing 2012 results with 2015.
Previously, ONEOK Partners estimated a three-year average annual growth rate
of 17 to 21 percent, comparing 2012 guidance provided on Sept. 24, 2012, with
2015.

The revision to the three-year growth forecast is due primarily to lower than
expected NGL exchange margins in the Rocky Mountain region and lower expected
NGL and natural gas prices in 2014 and 2015.

The partnership now has estimated an average annual distribution increase of 8
to 12 percent between 2012 and 2015, subject to ONEOK Partners board approval,
compared with its previous guidance of 10 to 15 percent.

The midpoint for ONEOK Partners' 2013 operating income guidance decreased to
$936 million, compared with its previous guidance midpoint of $1.027 billion.

The midpoint of the natural gas gathering and processing segment's 2013
operating income guidance decreased to $238 million, compared with its
previous guidance of $253 million, reflecting lower expected commodity prices.

The average unhedged prices assumed for 2013 are $88.00 per barrel for New
York Mercantile Exchange (NYMEX) crude oil, $3.75 per MMBtu for NYMEX natural
gas and 66 cents per gallon for composite natural gas liquids. Previous
guidance released on Sept. 24, 2012, assumed $95.30 per barrel for NYMEX crude
oil, $4.05 per MMBtu for NYMEX natural gas and 76 cents per gallon for
composite natural gas liquids.

For 2013, hedges are in place on approximately 79 percent of the segment's
expected equity natural gas production at an average price of $3.79 per MMBtu;
45 percent of its expected equity NGL production at an average price of $1.19
per gallon; and 83 percent of its expected equity condensate production at an
average price of $2.43 per gallon.

Currently, 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 $2.1 million. A
$1.00-per-barrel change in the price of crude oil would change annual net
margin by approximately $1.1 million. Also, a 10-cent-per-MMBtu change in the
price of natural gas would change annual net margin by approximately $2.8
million. All of these sensitivities exclude the effects of hedging and assume
normal operating conditions.

The midpoint of the natural gas pipelines segment's 2013 operating income
guidance has been increased to $153 million, compared with its previous
guidance of $144 million, reflecting incremental demand from producers for
services to transport their natural gas production to market, higher
negotiated natural gas storage rates and increased services to electric
generation customers.

The midpoint of the natural gas liquids segment's 2013 operating income
guidance decreased to $545 million, compared with its previous guidance of
$630 million. This updated 2013 guidance reflects the expected impact of
widespread and prolonged ethane rejection, and narrower expected NGL location
price differentials.

For 2013, the average Conway-to-Mont Belvieu OPIS location price differential
of ethane in ethane/propane mix is expected to be 5 cents per gallon, compared
with its previous full-year 2013 guidance of 19 cents per gallon. The impact
of this location price differential in the natural gas liquids segment has
decreased as an increasing portion of its transportation capacity between the
Conway, Kan., and Mont Belvieu, Texas, NGL market centers now is utilized by
its exchange-services activities to produce fee-based earnings.

Equity earnings from investments are expected to be $110 million, compared
with its previous guidance of $138 million, reflecting lower expected earnings
from its 50 percent-interests in Overland Pass Pipeline and Northern Border
Pipeline.

Capital expenditures for 2013 are expected to be approximately $2.64 billion,
comprised of approximately $2.5 billion in growth capital and $120 million in
maintenance capital. These estimates have been updated to reflect the January
2013 announcement of new growth projects in the natural gas gathering and
processing and natural gas liquids segments.

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

EARNINGS CONFERENCE CALL AND WEBCAST:

ONEOK Partners and ONEOK management will conduct a joint conference call on
Tuesday, Feb. 26, 2013, 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 888-427-9421, pass code
2364894, 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 2364894.

LINK TO EARNINGS TABLES:

http://www.oneokpartners.com/~/media/ONEOKPartners/EarningsTables/Q4_Year-End%202012_OKS-Earnings_$dg3S3U.ashx

NON-GAAP (GENERALLY ACCEPTED ACCOUNTING PRINCIPLES) FINANCIAL MEASURES:

ONEOK Partners has disclosed in this news release historical and 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 cash distributions received and certain other items.

The partnership believes the non-GAAP financial measures described above are
useful to investors because these measurements are used by many companies in
its industry as a measurement of financial performance and are commonly
employed by financial analysts and others to evaluate the financial
performance of the partnership and to compare the financial performance of the
partnership with the performance of other publicly traded partnerships within
its industry.

EBITDA and DCF should not be considered alternatives to net income, earnings
per unit or any other measure of financial performance presented in accordance
with GAAP.

These non-GAAP financial measures exclude some, but not all, items that affect
net income. Additionally, these calculations may not be comparable with
similarly titled measures of other companies.Furthermore, these non-GAAP
measures should not be viewed as indicative of the actual amount of cash that
is available for distributions or that is planned to be distributed for a
given period nor do they equate to available cash as defined in the
partnership agreement.

ONEOK Partners, L.P. (pronounced ONE-OAK) (NYSE: OKS) is one of the largest
publicly traded master limited partnerships, and is a leader in the gathering,
processing, storage and transportation of natural gas in the U.S. and owns one
of the nation's premier natural gas liquids (NGL) systems, connecting NGL
supply in the Mid-Continent and Rocky Mountain regions with key market
centers. Its general partner is a wholly owned subsidiary of ONEOK, Inc.
(NYSE: OKE), a diversified energy company, which owns 43.4 percent of the
overall partnership interest. ONEOK is one of the largest natural gas
distributors in the United States, and its energy services operation focuses
primarily on marketing natural gas and related services throughout the U.S.

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

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

Some of the statements contained and incorporated in this news release are
forward-looking statements within the meaning of Section 27A of the Securities
Act, as amended, and Section 21E of the Exchange Act, as amended. The
forward-looking statements relate to our anticipated financial performance
(including projected operating income, net income, capital expenditures, cash
flow and projected levels of distributions), liquidity, management's plans and
objectives for our future growth projects and other future operations
(including plans to construct additional natural gas and natural gas liquids
pipelines and processing facilities), 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:

  othe effects of weather and other natural phenomena, including climate
    change, on our operations, demand for our services and energy prices;
  ocompetition 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;
  othe capital intensive nature of our businesses;
  othe profitability of assets or businesses acquired or constructed by us;
  oour ability to make cost-saving changes in operations;
  orisks of marketing, trading and hedging activities, including the risks of
    changes in energy prices or the financial condition of our counterparties;
  othe uncertainty of estimates, including accruals and costs of
    environmental remediation;
  othe timing and extent of changes in energy commodity prices;
  othe 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;
  othe 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 between producing areas and our facilities;
  odifficulties or delays experienced by trucks or pipelines in delivering
    products to or from our terminals or pipelines;
  ochanges in demand for the use of natural gas because of market conditions
    caused by concerns about global warming;
  oconflicts of interest between us, our general partner, ONEOK Partners GP,
    and related parties of ONEOK Partners GP;
  othe impact of unforeseen changes in interest rates, equity markets,
    inflation rates, economic recession and other external factors over which
    we have no control;
  oour 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;
  oactions by rating agencies concerning the credit ratings of us or the
    parent of our general partner;
  othe 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);
  oour ability to access capital at competitive rates or on terms acceptable
    to us;
  orisks associated with adequate supply to our gathering, processing,
    fractionation and pipeline facilities, including production declines that
    outpace new drilling or extended periods of ethane rejection;
  othe risk that material weaknesses or significant deficiencies in our
    internal control over financial reporting could emerge or that minor
    problems could become significant;
  othe impact and outcome of pending and future litigation;
  othe ability to market pipeline capacity on favorable terms, including the
    effects of:

       ofuture demand for and prices of natural gas, NGLs and crude oil;
       ocompetitive conditions in the overall energy market;
       oavailability of supplies of Canadian and United States natural gas
         and crude oil; and
       oavailability of additional storage capacity;

  operformance of contractual obligations by our customers, service
    providers, contractors and shippers;
  othe timely receipt of approval by applicable governmental entities for
    construction and operation of our pipeline and other projects and required
    regulatory clearances;
  oour 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;
  othe mechanical integrity of facilities operated;
  odemand for our services in the proximity of our facilities;
  oour ability to control operating costs;
  oacts of nature, sabotage, terrorism or other similar acts that cause
    damage to our facilities or our suppliers' or shippers' facilities;
  oeconomic climate and growth in the geographic areas in which we do
    business;
  othe 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;
  othe impact of recently issued and future accounting updates and other
    changes in accounting policies;
  othe 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;
  othe risk of increased costs for insurance premiums, security or other
    items as a consequence of terrorist attacks;
  orisks 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;
  othe impact of uncontracted capacity in our assets being greater or less
    than expected;
  othe 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;
  othe composition and quality of the natural gas and NGLs we gather and
    process in our plants and transport on our pipelines;
  othe efficiency of our plants in processing natural gas and extracting and
    fractionating NGLs;
  othe impact of potential impairment charges;
  othe 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;
  oour ability to control construction costs and completion schedules of our
    pipelines and other projects; and
  othe 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.

Website: http://www.oneokpartners.com
Website: http://www.oneok.com
 
Press spacebar to pause and continue. Press esc to stop.