October 30, 2012 at 16:05 PM EDT
ONEOK Partners Announces Higher Third-quarter 2012 Financial Results; Affirms 2012 Earnings Guidance Ranges
Net Income Rises 11 Percent in the Third Quarter, 27 Percent Year to Date

TULSA, Okla., Oct. 30, 2012 /PRNewswire/ -- ONEOK Partners, L.P. (NYSE: OKS) today announced third-quarter 2012 earnings of 78 cents per unit, compared with 84 cents per unit for the third quarter 2011.  Net income attributable to ONEOK Partners increased 11 percent for the third quarter 2012 to $232.3 million, compared with $209.7 million for the same period in 2011.

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

Year-to-date 2012 net income attributable to ONEOK Partners was $677.6 million, a 27 percent increase, or $2.38 per unit, compared with $531.7 million, or $2.09 per unit for the nine-month period a year earlier.

The partnership also affirmed its 2012 net income guidance range of $860 million to $910 million.  The partnership's distributable cash flow (DCF) is expected to be in the range of $975 million to $1.025 billion.

"The completion of growth projects continued to benefit the partnership in the third quarter," said John W. Gibson, chairman and chief executive officer of ONEOK Partners.  "Our natural gas liquids segment continued to benefit from higher natural gas liquids volumes gathered and fractionated, offset partially by narrower NGL price differentials and less transportation capacity available for optimization."

"Our natural gas gathering and processing segment performed well in the third quarter, due primarily to volume growth in the Williston Basin from our Garden Creek plant and increased drilling activity, which resulted in higher natural gas volumes gathered, compressed, processed, transported and sold," he said.

In the third quarter 2012, earnings before interest, taxes, depreciation and amortization (EBITDA) were $329.2 million, a 5 percent increase, compared with $312.6 million in the third quarter 2011.  Year-to-date 2012 EBITDA was $979.3 million, a 16 percent increase, compared with $842.1 million in the same period last year.

DCF for the third quarter 2012 was $261.4 million, a 12 percent increase, compared with $233.4 million in the third quarter 2011.  DCF for the first nine months of 2012 was $780.7 million, a 25 percent increase, compared with $624.7 million in the same period last year.

Third-quarter 2012 operating income was $248.4 million, compared with $242.4 million for the third quarter 2011.  For the first nine months of 2012, operating income was $732.5 million, compared with $622.0 million in the prior-year period.

The increases in operating income for the third quarter 2012 reflect higher natural gas volumes gathered and processed in the natural gas gathering and processing segment offset by lower realized natural gas and natural gas liquids (NGL) product 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 price differentials and lower NGL transportation capacity available for optimization activities.

The increases in operating income for the nine-month 2012 period reflect higher natural gas volumes gathered and processed in the natural gas gathering and processing segment offset by lower realized natural gas and NGL product prices.  The natural gas liquids segment benefited from higher NGL volumes gathered and fractionated and higher optimization margins from favorable NGL price differentials.

Operating costs were $121.1 million in the third quarter of 2012, compared with $106.3 million for the same period last year.  Operating costs for the nine-month 2012 period were $360.4 million, compared with $328.6 million in the same period last year.  The increases for both the three- and nine-month 2012 periods were due primarily to the partnership's expanding operations from several growth projects placed in service.

Capital expenditures were $375.3 million in the third quarter 2012, compared with $252.2 million for the same period last year.  Nine-month 2012 capital expenditures were $1.012 billion, compared with $662.4 million in the same period last year.  These increases were due to increased investments in growth projects in the natural gas gathering and processing and natural gas liquids segments.

Interest expense was $47.8 million in the third quarter 2012, compared with $55.7 million in the same period last year.  Nine-month 2012 interest expense was $148.1 million, compared with $170.6 million in the same period last year.  This decrease was primarily driven by higher capitalized interest as a result of increased investments in the growth projects in the natural gas gathering and processing and natural gas liquids segments.

> View earnings tables

THIRD-QUARTER 2012 SUMMARY:

  • Operating income of $248.4 million, compared with $242.4 million in the third quarter 2011;
  • Natural gas gathering and processing segment operating income of $57.0 million, compared with $51.8 million in the third quarter 2011;
  • Natural gas pipelines segment operating income of $33.5 million, compared with $34.0 million in the third quarter 2011;
  • Natural gas liquids segment operating income of $158.8 million, compared with $157.1 million in the third quarter 2011;
  • Equity earnings from investments of $28.6 million, compared with $32.0 million in the third quarter 2011;
  • Capital expenditures of $375.3 million, compared with $252.2 million in the third quarter 2011;
  • In the natural gas pipelines segment, Viking Gas Transmission earning the Minnesota Governor's Award in Occupational Safety and the 2011 Wisconsin Corporate Safety Award;
  • Completing in September a $1.3 billion public offering of senior notes, consisting of $400 million of five-year senior notes at 2.0 percent and $900 million of 10-year senior notes at 3.375 percent;
  • Increasing investments in its 2011 to 2015 internal-growth program to a range of approximately $5.7 billion to $6.6 billion by:
    • Announcing in July plans to invest approximately $310 million to $345 million between now and the third quarter of 2014 to construct a 100 million-cubic-feet-per-day (MMcf/d) natural gas processing facility – the Garden Creek II plant – in eastern McKenzie County, N.D., in the Williston Basin, and related infrastructure;
    • Announcing in July plans to invest $525 million to $575 million between now and the fourth quarter of 2014 to construct a 75,000 barrel-per-day (bpd) natural gas liquids fractionator, MB-3, and related infrastructure at Mont Belvieu, Texas;
    • Announcing in July plans to invest approximately $100 million between now and the third quarter of 2014 to install additional pump stations on the Bakken NGL Pipeline to increase its capacity to 135,000 bpd from an initial 60,000 bpd;
    • Announcing in July plans to invest approximately $45 million between now and the second quarter of 2014 to install a 40,000 bpd ethane/propane (E/P) splitter at its Mont Belvieu storage facility;
  • Completing in September the 60,000 bpd expansion of the Bushton, Kan., NGL fractionator;
  • Completing in September the 100 MMcf/d Stateline I natural gas processing facility in the Williston Basin in the Bakken Shale;  
  • Announcing the open season for the Bakken Crude Express Pipeline, which began Sept. 21, 2012, and will conclude Nov. 20, 2012;
  • Announcing 2013 guidance in September 2012, with net income expected to increase 10 percent compared with current 2012 earnings guidance; and the annual distribution declared expected to increase 10 to 15 percent between 2012 and 2015, including 2-cent-per-unit-per-quarter increases in 2013, subject to board approval, while maintaining a minimum annual coverage ratio of 1.05 times;
  • Having $963.6 million of cash and cash equivalents and no commercial paper or borrowings outstanding as of Sept. 30, 2012, under the partnership's $1.2 billion revolving credit facility; and
  • Increasing the quarterly cash distribution to 68.5 cents per unit from 66 cents per unit, an increase of 4 percent, payable on Nov. 14, 2012, to unitholders of record as of Nov. 5, 2012.

BUSINESS-UNIT RESULTS:

Natural Gas Gathering and Processing Segment

The natural gas gathering and processing segment reported third-quarter 2012 operating income of $57.0 million, compared with $51.8 million for the third quarter 2011. 

Third-quarter 2012 results reflect a $33.4 million increase due primarily to volume growth in the Williston Basin from the Garden Creek plant and increased drilling activity, which resulted in higher natural gas volumes gathered, compressed, processed, transported and sold, and higher fees.  This increase was offset by an $11.0 million decrease from lower realized natural gas and NGL product prices, particularly ethane and propane; a $9.0 million decrease due primarily to higher compression and processing costs associated with volume growth, primarily in the Williston Basin; and a $1.6 million decrease from lower natural gas volumes gathered in the Powder River Basin as a result of continued production declines.

Operating income for the nine-month 2012 period was $151.3 million, compared with $138.3 million in the same period last year.

Nine-month 2012 results reflect an $88.8 million increase due primarily to volume growth in the Williston Basin from the Garden Creek plant and increased drilling activity, which resulted in higher natural gas volumes gathered, compressed, processed, transported and sold, and higher fees.  This increase was offset partially by a $26.4 million decrease from lower realized natural gas and NGL product prices, particularly ethane and propane, offset partially by higher condensate prices; a $23.7 million decrease due primarily to higher compression and processing costs associated with volume growth, primarily in the Williston Basin; and a $4.1 million decrease from lower natural gas volumes gathered in the Powder River Basin as a result of continued production declines.

Operating costs in the third quarter 2012 were $39.4 million, compared with $35.0 million in the same period last year.  Third quarter results reflect a $2.7 million increase in labor and employee-related costs and a $1.9 million increase in materials, supplies and outside services expenses.

Nine-month 2012 operating costs were $120.9 million, compared with $109.6 million in the same period last year.  The increase was primarily due to a $5.0 million increase in labor and employee-related costs; a $2.9 million increase in materials, supplies and outside services expenses; and a $1.4 million increase in property taxes.

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

  • Natural gas gathered was 1,149 billion British thermal units per day (BBtu/d) in the third quarter 2012, up 10 percent compared with the same period last year due to increased drilling activity in the Williston Basin and in western Oklahoma, and completion of additional gathering lines and compression to support the partnership's Garden Creek natural gas processing plant in the Williston Basin; offset partially by continued production declines in the Powder River Basin in Wyoming; and up 6 percent compared with the second quarter 2012;
  • Natural gas processed was 906 BBtu/d in the third quarter 2012, up 25 percent compared with the same period last year due to increased drilling activity in the Williston Basin and western Oklahoma, and the completion of the partnership's Garden Creek natural gas processing plant in the Williston Basin; and up 10 percent compared with the second quarter 2012;
  • The realized composite NGL net sales price was $1.10 per gallon in the third quarter 2012, up 1 percent compared with the same period last year; and up 9 percent compared with the second quarter 2012;
  • The realized condensate net sales price was $86.54 per barrel in the third quarter 2012, down 2 percent compared with the same period last year; and relatively unchanged compared with the second quarter 2012;
  • The realized residue natural gas net sales price was $3.69 per million British thermal units (MMBtu) in the third quarter 2012, down 30 percent compared with the same period last year; and down 3 percent compared with the second quarter 2012; and
  • The realized gross processing spread was $8.14 per MMBtu in the third quarter 2012, relatively unchanged compared with the same period last year; and up 1 percent compared with the second quarter 2012.

The segment's total equity volumes and the composition of the equity NGL barrel continue to change as new natural gas processing plants in the Williston Basin are placed into service.  The Garden Creek and Stateline I plants are capable of but currently are not recovering ethane due to the current lack of NGL pipeline takeaway transportation capacity.  The natural gas liquids segment's Bakken NGL Pipeline that is expected to be completed in the first quarter of 2013 will enable ethane recovery.  As a result, its 2012 equity NGL volumes and realized composite NGL net sales price are weighted more toward the relatively higher priced propane, iso-butane, normal butane and natural gasoline compared with the prior year.  This has the effect of producing a higher NGL composite barrel realized price while most individual NGL product prices are substantially lower this year compared with the prior year.

During the third quarter of 2012, the natural gas gathering and processing segment connected approximately 280 new wells to its systems, compared with approximately 180 in the same period last year.  For the nine months ended Sept. 30, 2012, it connected approximately 710 new wells, compared with approximately 420 in the same period last year.  This segment expects to connect more than 900 wells in 2012.

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



Three Months Ended


Nine Months Ended



September 30,


September 30,

Operating Information (a)


2012


2011


2012


2011

Percent of proceeds









  NGL sales (Bbl/d) (b) 


9,941


6,963


9,338


6,433

  Residue gas sales (MMBtu/d) (b) 


69,952


52,038


63,244


46,702

  Condensate sales(Bbl/d) (b) 


1,825


1,401


2,180


1,754

  Percentage of total net margin


65%


63%


63%


61%

Fee-based









  Wellhead volumes (MMBtu/d)


1,149,072


1,044,385


1,091,063


1,020,871

  Average rate ($/MMBtu)


$           0.34


$           0.35


$           0.35


$           0.34

  Percentage of total net margin


30%


31%


31%


32%

Keep-whole









  NGL shrink (MMBtu/d) (c)


6,040


9,145


6,643


10,753

  Plant fuel (MMBtu/d) (c)


656


973


761


1,193

  Condensate shrink (MMBtu/d) (c)


924


801


1,072


1,204

  Condensate sales (Bbl/d)


187


162


217


244

  Percentage of total net margin


5%


6%


6%


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:



Three Months Ending December 31, 2012



Volumes
Hedged

(a)

Average Price

Percentage
Hedged

NGLs (Bbl/d) 


9,488


$1.25

/ gallon

71%

Condensate (Bbl/d) 


1,987


$2.42

/ gallon

77%

  Total (Bbl/d)


11,475


$1.46

/ gallon

72%

Natural gas(MMBtu/d)


50,109


$4.54

/ MMBtu

77%

(a) - Hedged with futures and swaps.


















Year Ending December 31, 2013



Volumes
Hedged

(a)

Average Price

Percentage
Hedged

NGLs (Bbl/d) 


428


$2.51

/ gallon

2%

Condensate (Bbl/d) 


2,038


$2.43

/ gallon

70%

  Total (Bbl/d)


2,466


$2.44

/ gallon

10%

Natural gas(MMBtu/d)


50,137


$3.85

/ MMBtu

80%

(a) - Hedged with futures and swaps.


















Year Ending December 31, 2014



Volumes
Hedged

(a)

Average Price

Percentage
Hedged

Natural gas(MMBtu/d)


36,726


$4.11

/ MMBtu

50%

(a) - Hedged with futures and swaps.

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 $2.8 million.  A $1.00-per-barrel change in the price of crude oil would change annual net margin by approximately $1.2 million.  Also, a 10-cent-per-MMBtu change in the price of natural gas would change annual net margin by approximately $2.3 million.  All of these sensitivities exclude the effects of hedging and assume normal operating conditions.

Natural Gas Pipelines Segment

The natural gas pipelines segment reported third-quarter 2012 operating income of $33.5 million, compared with $34.0 million for the third quarter 2011. 

Third-quarter 2012 results reflect higher contracted capacity with natural gas producers on its intrastate pipelines to transport increasing natural gas supply to market.  This increase was offset by outside services costs associated with maintenance projects and higher employee-related costs.

Operating income for the nine months 2012 was $99.1 million, compared with $100.6 million in the same period in 2011. 

Nine-month 2012 results reflect a $3.1 million decrease, primarily from lower realized natural gas prices on its net retained fuel position, offset partially by higher retained fuel volumes.  This decrease was offset partially by an increase of $2.4 million from higher contracted capacity on its intrastate pipelines, offset partially by lower contracted capacity on Midwestern Gas Transmission.

Operating costs were $26.3 million in the third quarter 2012, compared with $24.4 million in the same period last year.  Nine-month 2012 operating costs were $78.3 million, compared with $79.1 million in the same period last year.

Equity earnings, primarily from the partnership's 50 percent-owned Northern Border Pipeline, were $18.3 million in the third quarter 2012, compared with $19.8 million in the same period in 2011.  Nine-month 2012 equity earnings from investments were $55.0 million, compared with $57.4 million in the same period last year.

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

  • Natural gas transportation capacity contracted was 5,249 thousand dekatherms per day in the third quarter 2012, up 2 percent compared with the same period last year; and relatively unchanged compared with the second quarter 2012;
  • Natural gas transportation capacity subscribed was 87 percent in the third quarter 2012 compared with 85 percent in the same period last year; and unchanged from the second quarter 2012; and
  • The average natural gas price in the Mid-Continent region was $2.75 per MMBtu in the third quarter 2012, down 32 percent compared with the same period last year; and up 27 percent compared with the second quarter 2012.

Natural Gas Liquids Segment

The natural gas liquids segment reported third-quarter 2012 operating income of $158.8 million, compared with $157.1 million for the third quarter 2011. 

Third-quarter 2012 results reflect:

  • A $32.9 million increase from higher NGL volumes gathered and fractionated and higher fees from contract renegotiations for its NGL exchange-services activities;
  • A $5.8 million increase in isomerization margins resulting from wider price differentials between normal butane and iso-butane and higher isomerization volumes;
  • A decrease of $20.9 million in optimization and marketing margins, which resulted from a $43.4 million decrease due to narrower NGL price differentials and lower transportation capacity available for optimization activities, as an increasing portion of its transportation capacity between the Conway, Kan., and Mont Belvieu, Texas, NGL market centers is utilized by its exchange services activities to produce fee-based earnings.  This decrease was offset partially by a $22.5 million increase in its marketing activities due primarily to margins realized on the fractionation and sale of NGL inventory held at the end of the second quarter of 2012 associated with the scheduled maintenance at the Mont Belvieu NGL fractionation facility; and
  • A $5.5 million decrease due to the impact of operational measurement losses.

Operating income for the nine months 2012 was $482.4 million, compared with $383.5 million in 2011. 

Nine-month 2012 results reflect:

  • A $68.8 million increase from higher NGL volumes gathered and fractionated and higher fees from contract renegotiations for its NGL exchange-services activities;
  • A $50.3 million increase in optimization and marketing margins, which resulted primarily from wider NGL product price differentials;
  • A $9.6 million increase due to higher storage margins as a result of favorable contract renegotiations;
  • A $3.9 million increase due to higher isomerization margins, which resulted from wider NGL price differentials between normal butane and iso-butane; and
  • A $1.3 million decrease due to the impact of operational measurement losses.

Operating costs were $56.8 million in the third quarter 2012, compared with $47.6 million in the third quarter 2011.  Nine-month 2012 operating costs were $166.6 million, compared with $141.1 million in the same period last year.  The increases were due primarily to higher expenses for materials, outside services and employee-related costs associated with scheduled maintenance and completed growth projects.

Equity earnings from investments were $4.8 million in the third quarter 2012, compared with $4.3 million in the same period in 2011.  Nine-month 2012 equity earnings from investments were $16.4 million, compared with $14.3 million in the same period last year.  

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

  • NGLs fractionated were 581,000 bpd in the third quarter 2012, up 10 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 10 percent compared with the second quarter 2012;
  • NGLs transported on gathering lines were 530,000 bpd in the third quarter 2012, up 20 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 up 1 percent compared with the second quarter 2012;
  • NGLs transported on distribution lines were 504,000 bpd in the third quarter 2012, up 10 percent compared with the same period last year due primarily to the completion of the Sterling I pipeline expansion project in the fourth quarter of 2011 and higher volumes transported on its distribution pipelines between its Mid-Continent NGL fractionators; and up 5 percent compared with the second quarter 2012; and
  • The Conway-to-Mont Belvieu average price differential for ethane in ethane/propane mix, based on Oil Price Information Service (OPIS) pricing, was 16 cents per gallon in the third quarter 2012, compared with 27 cents per gallon in the same period last year; and 23 cents per gallon in the second quarter 2012.

GROWTH ACTIVITIES:

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

  • Approximately $1.5 billion to $1.8 billion to construct a 1,300-mile crude-oil pipeline with the initial capacity to transport 200,000 bpd.  The Bakken Crude Express Pipeline will transport light-sweet crude oil from the Bakken Shale in the Williston Basin in North Dakota to the Cushing, Okla., crude-oil market hub.  In September, the partnership announced an open-season process that provides potential shippers the opportunity to execute long-term transportation contracts on the proposed pipeline in exchange for priority transportation service.  The open season began on Sept. 21, 2012, and will conclude on Nov. 20, 2012.  Following receipt of sufficient supply commitments and all necessary permits and compliance with customary regulatory requirements, construction is expected to begin in early 2014 and be completed by mid-2015.
  • Approximately $2.4 billion to $2.9 billion for natural gas liquids projects including:
    • Approximately $610 million to $810 million for the construction of a 570-plus-mile, 16-inch NGL pipeline – the Sterling III Pipeline – expected to be completed in late 2013, to transport either unfractionated NGLs or NGL purity products from the Mid-Continent region to the Texas Gulf Coast with the initial capacity of 193,000 bpd and the ability to expand to 250,000 bpd; and the reconfiguration of its existing Sterling I and II NGL distribution pipelines to transport either unfractionated NGLs or NGL purity products;
    • Approximately $300 million to $390 million for the construction of a 75,000 bpd NGL fractionator, MB-2, at Mont Belvieu, Texas, that is expected to be completed in mid-2013;
    • Approximately $525 million to $575 million for the construction of a 75,000 bpd NGL fractionator, MB-3, and related infrastructure at Mont Belvieu, Texas, that is expected to be completed in the fourth quarter of 2014;
    • Approximately $45 million to install a 40,000 bpd ethane/propane (E/P) splitter at its Mont Belvieu storage facility to split E/P mix into purity ethane, that is expected to be completed in the second quarter of 2014;
    • Approximately $450 million to $550 million for the construction of 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 of 2013, with an initial capacity of 60,000 bpd;
    • Approximately $100 million to install additional pump stations on the Bakken NGL Pipeline to increase its capacity to 135,000 bpd from an initial capacity of 60,000 bpd.  The expansion is expected to be completed in the third quarter of 2014;
    • Approximately $35 million to $40 million on the partnership's 50 percent-owned Overland Pass Pipeline for a 60,000-bpd capacity expansion to transport the additional unfractionated NGL volumes from the Bakken NGL Pipeline;
    • 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 volumes from the Mid-Continent and Williston Basin;
    • Approximately $220 million to construct more than 230 miles of 10- and 12-inch diameter NGL pipelines that expanded the partnership's existing Mid-Continent NGL gathering system in the Cana-Woodford and Granite Wash areas, which is expected to add approximately 75,000 to 80,000 bpd of raw, unfractionated NGLs to the partnership's existing NGL gathering systems in the Mid-Continent and the Arbuckle Pipeline.  Construction of the NGL pipelines was completed in April 2012 and connected three new third-party natural gas processing facilities and three existing third-party natural gas processing facilities that were expanded to the partnership's NGL gathering system.  In addition, the installation of additional pump stations on the Arbuckle Pipeline was completed, increasing its capacity to 240,000 bpd; and
    • At the end of 2011, the partnership completed the installation of seven additional pump stations along its existing Sterling I NGL distribution pipeline, which cost approximately $30 million; the additional pump stations increased the pipeline's capacity by 15,000 bpd. 
  • Approximately $1.8 billion to $1.9 billion for natural gas gathering and processing projects including:
    • Approximately $360 million for the Garden Creek plant, a 100-MMcf/d natural gas processing facility in the Bakken Shale in the Williston Basin in North Dakota that was placed in service at the end of 2011, and related expansions; and for new well connections, expansions and upgrades to the existing natural gas gathering system infrastructure;
    • Approximately $300 million to $355 million to construct the Stateline I plant, a 100-MMcf/d natural gas processing facility in the Bakken Shale in the Williston Basin in North Dakota, which was completed in September 2012, and related NGL infrastructure; expansions and upgrades to the existing gathering and compression infrastructure; and new well connections;
    • Approximately $260 million to $305 million to construct the Stateline II plant, a 100-MMcf/d natural gas processing facility in the Bakken Shale in the Williston Basin in North Dakota, which is expected to be in service in the first quarter of 2013; expansions and upgrades to the existing gathering and compression infrastructure; and new well connections;
    • Approximately $140 million to $160 million to construct a 270-mile natural gas gathering system and related infrastructure in Divide County, N.D.  This system, which is expected to be in service in the third quarter 2013, will gather and transport natural gas from producers in the Bakken Shale in the Williston Basin to the partnership's previously announced 100 MMcf/d Stateline II natural gas processing facility in western Williams County, N.D.;
    • Approximately $340 million to $360 million to construct the Canadian Valley plant, a 200-MMcf/d natural gas processing facility in the Cana-Woodford Shale in Oklahoma, which is expected to be in service in the first quarter 2014; and expansions and upgrades to the existing gathering and compression infrastructure; and
    • Approximately $310 million to $345 million to construct the Garden Creek II plant, a 100-MMcf/d natural gas processing facility in the Bakken Shale in the Williston Basin in North Dakota, which is expected to be in service in the third quarter of 2014; and expansions and upgrades to the existing gathering and compression infrastructure.

EARNINGS CONFERENCE CALL AND WEBCAST:

ONEOK Partners and ONEOK management will conduct a joint conference call on Wednesday, Oct. 31, 2012, at 11 a.m. Eastern Daylight Time (10 a.m. Central Daylight Time).  The call will also be carried live on ONEOK Partners' and ONEOK's websites.

To participate in the telephone conference call, dial 800-946-0712, pass code 8481950, 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 8481950.

LINK TO EARNINGS TABLES:

http://www.oneokpartners.com/~/media/ONEOKPartners/EarningsTables/OKS-Q3_2012_Earnings_0xLK8dz.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 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.

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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 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 from producing areas and our facilities;
  • difficulties or delays experienced by trucks or pipelines in delivering products to or from our terminals or pipelines;
  • changes in demand for the use of natural gas because of market conditions caused by concerns about global warming;
  • conflicts of interest between us, our general partner, ONEOK Partners GP, and related parties of ONEOK Partners GP;
  • the impact of unforeseen changes in interest rates, equity markets, inflation rates, economic recession and other external factors over which we have no control;
  • our indebtedness could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds and/or place us at competitive disadvantages compared with our competitors that have less debt or have other adverse consequences;
  • actions by rating agencies concerning the credit ratings of us or the parent of our general partner;
  • the results of administrative proceedings and litigation, regulatory actions, rule changes and receipt of expected clearances involving the Oklahoma Corporation Commission (OCC), Kansas Corporation Commission (KCC), Texas regulatory authorities or any other local, state or federal regulatory body, including the Federal Energy Regulatory Commission (FERC), the National Transportation Safety Board (NTSB), the Pipeline and Hazardous Materials Safety Administration (PHMSA), the Environmental Protection Agency (EPA) and the Commodity Futures Trading Commission (CFTC);
  • our ability to access capital at competitive rates or on terms acceptable to us;
  • risks associated with adequate supply to our gathering, processing, fractionation and pipeline facilities, including production declines that outpace new drilling;
  • the risk that material weaknesses or significant deficiencies in our internal control over financial reporting could emerge or that minor problems could become significant;
  • the impact and outcome of pending and future litigation;
  • the ability to market pipeline capacity on favorable terms, including the effects of:
    • future demand for and prices of natural gas, NGLs and crude oil;
    • competitive conditions in the overall energy market;
    • availability of supplies of Canadian and United States natural gas and crude oil; and
    • availability of additional storage capacity;
  • performance of contractual obligations by our customers, service providers, contractors and shippers;
  • the timely receipt of approval by applicable governmental entities for construction and operation of our pipeline and other projects and required regulatory clearances;
  • our ability to acquire all necessary permits, consents and other approvals in a timely manner, to promptly obtain all necessary materials and supplies required for construction, and to construct gathering, processing, storage, fractionation and transportation facilities without labor or contractor problems;
  • the mechanical integrity of facilities operated;
  • demand for our services in the proximity of our facilities;
  • our ability to control operating costs;
  • acts of nature, sabotage, terrorism or other similar acts that cause damage to our facilities or our suppliers' or shippers' facilities;
  • economic climate and growth in the geographic areas in which we do business;
  • the risk of a prolonged slowdown in growth or decline in the United States or international economies, including liquidity risks in United States or foreign credit markets;
  • the impact of recently issued and future accounting updates and other changes in accounting policies;
  • the possibility of future terrorist attacks or the possibility or occurrence of an outbreak of, or changes in, hostilities or changes in the political conditions in the Middle East and elsewhere;
  • the risk of increased costs for insurance premiums, security or other items as a consequence of terrorist attacks;
  • risks associated with pending or possible acquisitions and dispositions, including our ability to finance or integrate any such acquisitions and any regulatory delay or conditions imposed by regulatory bodies in connection with any such acquisitions and dispositions;
  • the impact of uncontracted capacity in our assets being greater or less than expected;
  • the ability to recover operating costs and amounts equivalent to income taxes, costs of property, plant and equipment and regulatory assets in our state and FERC-regulated rates;
  • the composition and quality of the natural gas and NGLs we gather and process in our plants and transport on our pipelines;
  • the efficiency of our plants in processing natural gas and extracting and fractionating NGLs;
  • the impact of potential impairment charges;
  • the risk inherent in the use of information systems in our respective businesses, implementation of new software and hardware, and the impact on the timeliness of information for financial reporting;
  • our ability to control construction costs and completion schedules of our pipelines and other projects; and
  • the risk factors listed in the reports we have filed and may file with the Securities and Exchange Commission (SEC), which are incorporated by reference.

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

 

Analyst Contact:

Andrew Ziola


918-588-7163



Media Contact:

Brad Borror


 918-588-7582

SOURCE ONEOK Partners, L.P.

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