ONEOK Partners Reports Higher 2012 Earnings and Lower Fourth-quarter Results - WLOX.com - The News for South Mississippi

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SOURCE ONEOK Partners, L.P.

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

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 and distribution 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:

• 2012 operating income of $962.9 million, compared with $939.5 million in 2011;
• Natural gas gathering and processing segment operating income of $210.4 million, compared with $180.6 million in 2011;
• Natural gas pipelines segment operating income of $143.8 million, compared with $130.1 million in 2011;
• Natural gas liquids segment operating income of $608.2 million, compared with $628.6 million in 2011;
• Equity earnings from investments of $123.0 million, compared with $127.2 million in 2011;
• Capital expenditures of $1.6 billion, compared with $1.1 billion in 2011;
• Entering 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;
• Announcing 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;
• Having $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;
• ONEOK 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
• Announcing 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:

• A $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; 
• A $10.6 million decrease due primarily to higher compression costs and less favorable contract terms associated with volume growth in the Williston Basin;
• A $5.1 million decrease from lower realized natural gas and NGL prices, particularly ethane and propane; and
• A $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:

• A $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;
•  A $38.1 million decrease due primarily to higher compression costs and less favorable contract terms associated with volume growth in the Williston Basin;
• A $31.4 million decrease from lower net realized natural gas and NGL prices, particularly ethane and propane; and
• A $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.

• Natural 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;
• Natural 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;
• The 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;
• The 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;
• The 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
• The 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:

The natural gas gathering and processing segment is exposed to commodity-price risk as a result of receiving commodities in exchange for services.  The following tables provide hedging information for its equity volumes in the natural gas gathering and processing segment for the periods indicated:

The partnership currently estimates that in its natural gas gathering and processing segment, a 1-cent-per-gallon change in the composite price of NGLs would change annual net margin by approximately $2.1 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.

• Natural 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;
• Natural 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
• The 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:

• A $141.4 million decrease due primarily to narrower NGL location price differentials;
• A $7.3 million decrease in isomerization margins from lower isomerization volumes;
• A $3.1 million decrease due to the impact of operational measurement losses;
• A $32.8 million increase from higher NGL volumes gathered and fractionated, and higher fees from contract renegotiations for its NGL exchange-services activities; and
• A $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:

• A $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;
• A $13.1 million increase due to higher NGL storage margins as a result of favorable contract renegotiations;
• A $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;
• A $4.5 million decrease due to the impact of operational measurement losses; and
• A $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.

• NGLs 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;
• NGLs 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;
• NGLs 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
• The 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:

• Approximately $2.6 billion to $3.0 billion for the following natural gas liquids projects:
  • The 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;
  • Approximately $220 million to construct more than 230 miles of 10- and 12-inch diameter NGL pipelines that expanded the partnership's existing Mid-Continent NGL gathering system in the Cana-Woodford and Granite Wash areas 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;
  • Approximately $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;
  • Approximately $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;
  • Approximately $35 million to $40 million on the partnership's 50 percent-owned Overland Pass Pipeline for a 60,000-bpd capacity expansion to transport the additional unfractionated NGL volumes from the Bakken NGL Pipeline;
  • Approximately $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;
  • Approximately $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;
  • Approximately $45 million to install a 40,000 bpd ethane/propane (E/P) splitter at its Mont Belvieu storage facility to split E/P mix into purity ethane, that is expected to be completed in the second quarter 2014;
  • Approximately $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;
  • Approximately $100 million to install additional pump stations on the Bakken NGL Pipeline to increase its capacity to 135,000 bpd from an initial capacity of 60,000 bpd.  The expansion is expected to be completed in the third quarter 2014; and
  • Approximately $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.
• Approximately $2.1 billion to $2.3 billion for the following natural gas gathering and processing projects including:
  • Approximately $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;
  • Approximately $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;
  • Approximately $140 million to $160 million to construct a 270-mile natural gas gathering system and related infrastructure in Divide County, N.D.  This system, which is expected to be in service in the 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.;
  • Approximately $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;
  • Approximately $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
  • Approximately $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:

• 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 between 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 or extended periods of ethane rejection;
• the risk that material weaknesses or significant deficiencies in our internal control over financial reporting could emerge or that minor problems could become significant;
• the impact and outcome of pending and future litigation;
• the ability to market pipeline capacity on favorable terms, including the effects of:
  • future demand for and prices of natural gas, NGLs and crude oil;
  • competitive conditions in the overall energy market;
  • availability of supplies of Canadian and United States natural gas and crude oil; and
  • availability of additional storage capacity;
• performance of contractual obligations by our customers, service providers, contractors and shippers;
• the timely receipt of approval by applicable governmental entities for construction and operation of our pipeline and other projects and required regulatory clearances;
• our ability to acquire all necessary permits, consents and other approvals in a timely manner, to promptly obtain all necessary materials and supplies required for construction, and to construct gathering, processing, storage, fractionation and transportation facilities without labor or contractor problems;
• the mechanical integrity of facilities operated;
• demand for our services in the proximity of our facilities;
• our ability to control operating costs;
• acts of nature, sabotage, terrorism or other similar acts that cause damage to our facilities or our suppliers' or shippers' facilities;
• economic climate and growth in the geographic areas in which we do business;
• the risk of a prolonged slowdown in growth or decline in the United States or international economies, including liquidity risks in United States or foreign credit markets;
• the impact of recently issued and future accounting updates and other changes in accounting policies;
• the possibility of future terrorist attacks or the possibility or occurrence of an outbreak of, or changes in, hostilities or changes in the political conditions in the Middle East and elsewhere;
• the risk of increased costs for insurance premiums, security or other items as a consequence of terrorist attacks;
• risks associated with pending or possible acquisitions and dispositions, including our ability to finance or integrate any such acquisitions and any regulatory delay or conditions imposed by regulatory bodies in connection with any such acquisitions and dispositions;
• the impact of uncontracted capacity in our assets being greater or less than expected;
• the ability to recover operating costs and amounts equivalent to income taxes, costs of property, plant and equipment and regulatory assets in our state and FERC-regulated rates;
• the composition and quality of the natural gas and NGLs we gather and process in our plants and transport on our pipelines;
• the efficiency of our plants in processing natural gas and extracting and fractionating NGLs;
• the impact of potential impairment charges;
• the risk inherent in the use of information systems in our respective businesses, implementation of new software and hardware, and the impact on the timeliness of information for financial reporting;
• our ability to control construction costs and completion schedules of our pipelines and other projects; and
• the risk factors listed in the reports we have filed and may file with the Securities and Exchange Commission (SEC), which are incorporated by reference.

These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements.  Other factors could also have material adverse effects on our future results.  These and other risks are described in greater detail in Part I, Item 1A, Risk Factors, in the Annual Report.  All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors.  Other than as required under securities laws, we undertake no obligation to update publicly any forward-looking statement whether as a result of new information, subsequent events or change in circumstances, expectations or otherwise.

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