2014

ONEOK Partners Reports Higher Fourth-quarter 2013 Results And Announces Full-year 2013 Financial Results; Affirms 2014 Earnings Guidance Ranges Natural Gas and Natural Gas Liquids Volumes Continue to Increase

TULSA, Okla., Feb. 24, 2014 /PRNewswire/ -- ONEOK Partners, L.P. (NYSE: OKS) today announced that fourth-quarter 2013 net income attributable to ONEOK Partners was $228.4 million, or 67 cents per unit, compared with $210.4 million, or 66 cents per unit, in the fourth quarter 2012. 

Earnings before interest, taxes, depreciation and amortization (EBITDA) in the fourth quarter 2013 were $350.4 million, compared with $314.7 million in the fourth quarter 2012.  Higher fourth-quarter results reflect higher natural gas volumes gathered, processed and sold, and higher natural gas liquids (NGL) volumes gathered, as a result of recently completed capital-growth projects.

Fourth-quarter 2013 distributable cash flow (DCF) was $245 million, providing 1.02 times coverage of the cash distributions that will be paid, compared with fourth-quarter 2012 DCF of $227.0 million that provided 1.04 times coverage.

2013 net income attributable to ONEOK Partners was $803.6 million, or $2.35 per unit, compared with $888.0 million, or $3.04 per unit, in 2012.

2013 EBITDA was $1.26 billion, compared with $1.29 billion in 2012.  Full-year results benefited from volume growth in the natural gas gathering and processing, and natural gas liquids segments, which was more than offset by narrower NGL location price differentials, lower NGL product prices and ethane rejection. 

2013 DCF was $949.2 million, providing 1.03 times coverage, compared with DCF of $1.0 billion that provided 1.34 times coverage in 2012.

There was an average of approximately 224.7 million units outstanding in 2013, compared with 217.1 million units outstanding in 2012.  In 2013, 12.2 million common units were issued, including 11.5 million common units issued in an equity offering in August 2013 with the remainder of the common units issued during 2013 through the partnership's at-the-market equity program.

"Completed growth projects – part of our $6.0 billion to $6.4 billion capital-growth program through 2016 – continue to increase natural gas and natural gas liquids volumes on our systems, which drove higher fourth-quarter results," said Terry K. Spencer, president and chief executive officer of ONEOK Partners.    

"2013 earnings were affected by significantly narrower NGL location price differentials, lower NGL product prices and reduced volumes due to ethane rejection," Spencer said. 

"We anticipate that some of those challenges will remain in 2014 but will be offset by higher volumes of natural gas gathered and processed, and higher NGL volumes gathered and fractionated as a result of our capital-growth projects." 

FOURTH-QUARTER AND FULL-YEAR 2013 FINANCIAL PERFORMANCE

Fourth-quarter 2013 operating income was $252.9 million, compared with $230.5 million in the fourth quarter 2012. 

In the fourth quarter 2013, higher natural gas volumes gathered, processed and sold, and higher NGL volumes gathered, as a result of the completed capital-growth projects in the natural gas gathering and processing, and the natural gas liquids segments, and more favorable NGL product price differentials were offset partially by:

  • Narrower NGL location price differentials;
  • Lower NGL product prices;
  • Lower NGL volumes as a result of ethane rejection; and
  • Increased operating costs and depreciation and amortization expense from the completed capital-growth projects.

Operating costs were $136.9 million in the fourth quarter 2013, compared with $122.1 million in the same period in 2012, as a result of the growth in the partnership's operations.

Depreciation and amortization expense was $62.7 million in the fourth quarter 2013, compared with $53.1 million in the same period in 2012 due to the completion of several capital-growth projects.   

Capital expenditures were $565.4 million in the fourth quarter 2013, compared with $549.0 million for the same period in 2012. 

2013 operating income was $900.7 million, compared with $962.9 million in 2012.  Higher natural gas volumes gathered and processed in the natural gas gathering and processing segment, and more favorable NGL product price differentials and NGL volumes gathered in the natural gas liquids segment as a result of completed capital-growth projects were offset by significantly narrower NGL location price differentials, lower realized natural gas and NGL product prices, and the impact of ethane rejection. 

Operating costs in 2013 were $521.5 million, compared with $482.5 million in 2012, as a result of the growth in the partnership's operations.

2013 depreciation and amortization expense was $236.7 million, compared with $203.1 million in 2012, due primarily to the partnership's completed capital-growth projects.

2013 capital expenditures were $1.9 billion, compared with $1.6 billion in 2012, due primarily to capital-growth projects in the natural gas gathering and processing, and natural gas liquids segments. 

2013 interest expense was $236.7 million, compared with $206.0 million in 2012. 

The fourth-quarter 2013 and 2013 full-year interest expense increases were primarily the result of full-year 2013 interest costs on $1.3 billion of senior notes issued in September 2012 and higher interest costs associated with the issuance of $1.25 billion of senior notes in September 2013, offset partially by higher capitalized interest associated with investments in capital-growth projects.

> View earnings tables

2013 SUMMARY AND ADDITIONAL UPDATES:   

  • 2013 operating income of $900.7 million, compared with $962.9 million in 2012;
  • Natural gas gathering and processing segment operating income of $203.8 million, compared with $210.4 million in 2012;
  • Natural gas liquids segment operating income of $544.9 million, compared with $608.2 million in 2012;
  • Natural gas pipelines segment operating income of $151.6 million, compared with $143.8 million in 2012;
  • Equity earnings from investments of $110.5 million, compared with $123.0 million in 2012;
  • Capital expenditures of $1.9 billion, compared with $1.6 billion in 2012;
  • Increasing investments in its 2010-2016 capital-growth program by approximately $1.2 billion to a range of $6.0 billion to $6.4 billion, which includes:
    • Announcing an investment of approximately $550 million to $680 million in November 2013 to construct the Lonesome Creek plant, a 200-million cubic feet per day (MMcf/d) natural gas processing facility in the Williston Basin in North Dakota, which is expected to be completed in the fourth quarter 2015; and expansions and upgrades to the existing gathering and compression infrastructure;
    • Announcing an investment of approximately $100 million in November 2013 for a second expansion of the Bakken NGL Pipeline, which will increase the pipeline's capacity to 160,000 barrels per day (bpd) from 135,000 and is expected to be completed during the second quarter 2016; and
    • Announcing an investment of $305 million in September 2013 to acquire the Sage Creek plant, a 50 MMcf/d natural gas processing facility, and related natural gas gathering and natural gas liquids infrastructure in the Niobrara Shale, an NGL-rich area in the Powder River Basin in Wyoming;
  • Increasing the partnership's revolving credit facility to $1.7 billion from $1.2 billion, effective in January 2014;
  • Having $134.5 million of cash and cash equivalents, no commercial paper outstanding, no letters of credit issued and no borrowings outstanding under the partnership's credit facility as of Dec. 31, 2013;
  • Increasing in January 2014 the fourth-quarter 2013 distribution to 73 cents per unit, or $2.92 per unit on an annualized basis, payable on Feb. 14, 2014, to unitholders of record on Jan. 31, 2014; and
  • Celebrating in December 2013 ONEOK Partners' 20th anniversary of being listed on the New York Stock Exchange by ringing the closing bell.

BUSINESS-UNIT RESULTS:

Natural Gas Gathering and Processing Segment

The natural gas gathering and processing segment reported fourth-quarter 2013 operating income of $56.1 million, compared with $59.1 million for the fourth quarter 2012, which reflects:

  • A $34.1 million increase due primarily to volume growth in the Williston Basin from the Stateline I and Stateline II natural gas processing plants and increased well connections, which resulted in higher natural gas volumes gathered, compressed, processed, transported and sold, higher NGL volumes sold and higher fees;
  • A $15.9 million decrease due primarily to lower realized NGL product prices;
  • A $5.1 million decrease due primarily to changes in contract mix and terms associated with volume growth; and
  • A $14.3 million increase in operating costs and depreciation and amortization expense due to completed capital-growth projects.

Operating costs in the fourth quarter 2013 were $51.6 million, compared with $43.2 million for the fourth quarter 2012, which reflect:

  • A $6.4 million increase due to higher materials, supplies and outside services expenses; and
  • A $3.7 million increase due to higher labor and employee benefit costs, offset partially by a decrease in other employee-related expenses.

Depreciation and amortization expense in the fourth quarter 2013 was $27.5 million, compared with $21.7 million in 2012. 

2013 operating income was $203.8 million, compared with $210.4 million in 2012, which reflects:

  • A $100.1 million increase due primarily to volume growth in the Williston Basin from the Stateline I and Stateline II natural gas processing plants and increased well connections, which resulted in higher natural gas volumes gathered, compressed, processed, transported and sold, higher NGL volumes sold and higher fees;
  • A $6.4 million increase due to a contract settlement in 2013;
  • A $41.7 million decrease due primarily to lower realized NGL product prices;
  • A $13.4 million decrease due primarily to changes in contract mix and terms associated with volume growth;
  • A $3.5 million decrease from lower dry natural gas volumes gathered in the Powder River Basin as a result of continued production declines; and
  • A $50.2 million increase in operating costs and depreciation and amortization expense due to completed capital-growth projects.

2013 operating costs were $193.3 million, compared with $164.0 million in 2012. Recently completed capital-growth projects contributed to the increased operating costs, which included:

  • A $16.8 million increase due to higher materials, supplies and outside services expenses;
  • A $10.3 million increase due to higher labor and employee benefit costs, offset partially by a decrease in other employee-related expenses; and
  • A $2.2 million increase from higher property taxes.

2013 depreciation and amortization expense was $103.9 million, compared with $83.0 million in 2012.  These increases were due to the completion of the Stateline I and Stateline II natural gas processing plants, well connections and infrastructure projects supporting the volume growth in the Williston Basin and the acquisition of the Sage Creek natural gas processing plant in the NGL-rich Niobrara Shale area in the Powder River Basin in Wyoming.

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

  • Natural gas gathered was 1,454 billion British thermal units per day (BBtu/d) in the fourth quarter 2013, up 21 percent compared with the same period in 2012 due to increased well connections in the Williston Basin, offset partially by continued dry natural gas production declines in the Powder River Basin in Wyoming and production declines in Kansas; and up 5 percent compared with the third quarter 2013;
  • Natural gas processed was 1,193 BBtu/d in the fourth quarter 2013, up 24 percent compared with the same period in 2012 due to increased well connections in the Williston Basin; and up 5 percent compared with the third quarter 2013;
  • NGL sales were 88,000 barrels per day (bpd) in the fourth quarter 2013, up 26 percent compared with the same period in 2012 due to increased well connections in the Williston Basin; and up 6 percent compared with the third quarter 2013;
  • The realized composite NGL net sales price was 87 cents per gallon in the fourth quarter 2013, down 17 percent compared with the same period in 2012; and down 3 percent compared with the third quarter 2013;
  • The realized condensate net sales price was $82.31 per barrel in the fourth quarter 2013, down 9 percent compared with the same period in 2012; and down 9 percent compared with the third quarter 2013; and
  • The realized residue natural gas net sales price was $3.64 per million British thermal units (MMBtu) in the fourth quarter 2013, down 15 percent compared with the same period in 2012; and up 8 percent compared with the third quarter 2013.

The Garden Creek, Stateline I and Stateline II natural gas processing plants have the capability to recover ethane when economic conditions warrant but did not recover ethane during 2013.  As a result, the partnership's equity NGL volumes were weighted less toward ethane and more toward propane, iso-butane, normal butane and natural gasoline, and are expected to remain this way until ethane recovery resumes.

In the fourth quarter 2013, the segment connected approximately 210 new wells, compared with approximately 230 in the same period in 2012. 

In 2013, the segment connected approximately 1,160 new wells, compared with approximately 940 wells in the same period in 2012. 

The partnership expects to connect approximately 1,300 wells in 2014.

The following table contains operating information in the periods indicated:









Three Months Ended


Years Ended



December 31,


December 31,

Operating Information (a) (d)


2013


2012


2013


2012

Commodity









NGL sales (Bbl/d) (b)


16,060



13,001



14,390



11,575


Residue gas sales (MMBtu/d) (c)


83,542



55,174



71,710



48,782


Condensate sales (Bbl/d) (b)


2,340



1,946



2,365



2,287


Percentage of total net margin


68%



70%



66%



69%


Fee-based









Wellhead volumes (MMBtu/d)


1,454,030



1,200,979



1,346,852



1,118,693


Average rate ($/MMBtu)


$

0.33



$

0.33



$

0.34



$

0.35


Percentage of total net margin


32%



30%



34%



31%


(a) - Includes volumes for consolidated entities only.
(b) - Represents equity volumes.

(c) - Represents equity volumes net of fuel.

(d) - Keep-whole quantities represent less than 2 percent of our contracts by volume.  The quantities of natural gas for fuel and shrink associated with our keep-whole contracts have been deducted from residue gas sales, and the NGLs and condensate retained from our keep-whole contracts are included in NGL sales and condensate sales.  Prior periods have been recast to conform to current presentation.


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




Year Ending December 31, 2014



Volumes
Hedged


Average Price


Percentage
Hedged

NGLs (Bbl/d)


9,351


$

1.19

/ gallon


71%

Condensate (Bbl/d)


2,545


$

2.25

/ gallon


75%

Total (Bbl/d)


11,896


$

1.42

/ gallon


72%

Natural gas (MMBtu/d)


82,808


$

4.06

/ MMBtu


75%



















Year Ending December 31, 2015



Volumes
Hedged


Average Price


Percentage
Hedged

Natural gas (MMBtu/d)


48,877


$

4.19

/ MMBtu


41%


The partnership expects its NGL and natural gas commodity-price sensitivities to increase in the future as its capital-growth projects are completed and volumes increase under percent-of-proceeds contracts with its customers. 

All of the natural gas gathering and processing segment's commodity-price sensitivities are estimated as a hypothetical change in the price of natural gas, NGLs and crude oil as of Dec. 31, 2013, excluding the effects of hedging and assuming normal operating conditions.  Condensate sales are based on the price of crude oil. 

The natural gas gathering and processing segment estimates the following sensitivities:

  • A 10-cent-per-MMBtu change in the price of natural gas would change annual net margin by approximately $4.0 million;
  • A 1-cent-per-gallon change in the composite price of NGLs would change annual net margin by approximately $2.0 million; and
  • A $1.00-per-barrel change in the price of crude oil would change annual net margin by approximately $1.3 million.

These estimates do not include any effects on demand for ONEOK Partners' services or natural gas processing plant operations that might be caused by, or arise in conjunction with, price changes.  For example, a change in the gross processing spread may cause a change in the amount of ethane extracted from the natural gas stream, impacting natural gas gathering and processing margins for certain contracts.

Natural Gas Liquids Segment

The natural gas liquids segment reported fourth-quarter 2013 operating income of $148.9 million, compared with $125.8 million in the same period 2012, which reflects:

  • A $41.9 million increase in exchange-services margins from higher NGL volumes gathered, higher fees from contract renegotiations for its NGL exchange-services activities and higher revenues from customers with minimum volume obligations;
  • An $11.1 million increase in optimization and marketing margins, primarily as a result of a $19.3 million increase from more favorable NGL product price differentials and a $6.4 million increase in marketing margins, offset partially by a $14.6 million decrease due primarily to narrower NGL location price differentials;
  • A $4.8 million increase in storage margins due primarily to contract renegotiations;
  • A $16.8 million decrease from the impact of ethane rejection, which resulted in lower NGL volumes;
  • A $6.7 million decrease from lower isomerization volumes, resulting from narrower price differentials between normal butane and iso-butane; and
  • A $12.3 million increase in operating costs and depreciation and amortization expense due to completed capital-growth projects.

Operating costs were $65.5 million in the fourth quarter 2013, compared with $57.2 million in the fourth quarter 2012, which reflect:

  • An $8.4 million increase due primarily to the growth of its operations related to completed capital-growth projects; and
  • A $1.8 million increase due to higher property taxes primarily related to completed capital-growth projects.

Depreciation and amortization expense in the fourth quarter 2013 was $24.2 million, compared with $20.2 million in the same period in 2012. 

Equity earnings from investments were $6.6 million in the fourth quarter 2013, compared with $4.3 million in the same period in 2012. 

The increase in equity earnings in the fourth-quarter 2013 period was due primarily to higher volumes delivered to the partnership's 50 percent-owned Overland Pass Pipeline from its Bakken NGL Pipeline, which was placed in service in April 2013, offset partially by a $2.6 million decrease due to reduced volumes as a result of ethane rejection. 

Operating income in 2013 was $544.9 million, compared with $608.2 million in the same period in 2012, which reflects:

  • A $166.5 million increase in exchange-services margins from higher NGL volumes gathered, higher fees from contract renegotiations for its NGL exchange-services activities and higher revenues from customers with minimum volume obligations;
  • A $19.5 million increase due to the impact of operational measurement gains of approximately $9.7 million in 2013, compared with losses of approximately $9.8 million in 2012;
  • A $10.5 million increase in storage margins due primarily to contract renegotiations;
  • A $162.7 million decrease in optimization and marketing margins, primarily as a result of a $202.5 million decrease due to significantly narrower NGL location price differentials, offset partially by a $35.7 million increase due primarily to more favorable NGL product price differentials;
  • A $48.8 million decrease from the impact of ethane rejection, which resulted in lower NGL volumes;
  • A $27.7 million increase in operating costs and depreciation and amortization expense due to completed capital-growth projects in the natural gas liquids segment; and
  • A $22.4 million decrease from lower isomerization volumes, resulting from the narrower price differential between normal butane and iso-butane.

2013 operating costs were $236.6 million, compared with $223.8 million in 2012, which reflect:

  • A $5.4 million increase due to higher property taxes primarily related to completed capital-growth projects; and
  • A $5.0 million increase due to higher labor and employee benefit costs associated with the growth in operations related to completed capital-growth projects, offset partially by other employee-related expenses.

Depreciation and amortization expense in 2013 was $89.2 million, compared with $74.3 million in 2012, due primarily to depreciation expense associated with completed capital-growth projects.

2013 equity earnings from investments were $22.0 million, compared with $20.7 million in 2012, due primarily to higher NGL volumes delivered to the Overland Pass Pipeline from the Bakken NGL Pipeline, which was placed in service in April 2013.  The increase in equity earnings was offset partially by a $13.3 million decrease from the impact of ethane rejection.     

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

  • NGLs transported on gathering lines were 563,000 bpd in the fourth quarter 2013, up 6 percent compared with the same period in 2012, due primarily to increased volumes from the Williston Basin made available by the completed Bakken NGL Pipeline; and NGLs gathered as a result of the capacity increase in the Mid-Continent and Texas made available through the partnership's Cana-Woodford Shale and Granite Wash projects; offset partially by decreases in NGL volumes gathered as a result of ethane rejection; and down 2 percent compared with the third quarter 2013;
  • NGLs fractionated were 537,000 bpd in the fourth quarter 2013, down 11 percent compared with the same period in 2012, due to lower volumes from ethane rejection, offset partially by higher volumes from the Williston Basin made available by the segment's completed Bakken NGL Pipeline; and down 4 percent compared with the third quarter 2013;
  • NGLs transported on distribution lines were 459,000 bpd in the fourth quarter 2013, down 9 percent compared with the same period in 2012, due primarily to ethane rejection; and up 1 percent compared with the third quarter 2013; and
  • The average Conway-to-Mont Belvieu price differential of ethane in ethane/propane mix, based on Oil Price Information Service (OPIS) pricing, was 5 cents per gallon in the fourth quarter 2013, compared with 7 cents per gallon in the same period in 2012; and 4 cents per gallon in the third quarter 2013.

Natural Gas Pipelines Segment

The natural gas pipelines segment reported fourth-quarter 2013 operating income of $48.7 million, compared with $44.7 million in the fourth quarter 2012. 

2013 operating income was $151.6 million, compared with $143.8 million in the same period in 2012. 

Fourth-quarter and full-year 2013 results reflect increases of $3.5 million and $9.6 million, respectively, in transportation margins due primarily to higher rates on Guardian Pipeline and higher contracted capacity with natural gas producers on its intrastate pipelines.  These increases were offset partially by decreases in the fourth-quarter and full-year 2013 periods of $2.9 million and $3.9 million, respectively, from lower net retained fuel.

Additionally, the segment's gain on the sale of assets in the fourth quarter 2013 was $4.8 million higher due to a $10.5 million sale of excess natural gas in storage, which resulted in additional working natural gas storage capacity of 2.0 Bcf; compared with a gain on the sale of a natural gas pipeline lateral of $5.7 million in 2012.

Fourth-quarter 2013 equity earnings from investments, primarily from the partnership's 50 percent-owned Northern Border Pipeline, were $16.9 million, compared with $18.2 million in the same period in 2012. 

2013 equity earnings were $65.0 million, compared with $73.2 million in 2012. 

These decreases in equity earnings in the fourth-quarter and full-year 2013 periods were due primarily to reduced transportation rates resulting from a Northern Border Pipeline rate settlement that became effective Jan. 1, 2013.  Substantially all of Northern Border Pipeline's long-haul transportation capacity has been contracted through June 2015.

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

  • Natural gas transportation capacity contracted was 5,632 thousand dekatherms per day in the fourth quarter 2013, up 4 percent compared with the same period in 2012; and up 4 percent compared with the third quarter 2013;
  • Natural gas transportation capacity subscribed was 92 percent in the fourth quarter 2013, up 2 percent compared with the same period in 2012; and up 3 percent compared with the third quarter 2013; and
  • The average natural gas price in the Mid-Continent region was $3.75 per MMBtu in the fourth quarter 2013, up 14 percent compared with the same period in 2012; and up 10 percent compared with the third quarter 2013.

2014 EARNINGS GUIDANCE

ONEOK Partners affirmed its 2014 financial guidance and expects its 2014 net income to be in the range of $975 million to $1.075 billion.

2014 EBITDA is expected to be in the range of $1.565 billion to $1.665 billion.

The midpoint of ONEOK Partners' 2014 operating income guidance is $1.2 billion, reflecting higher anticipated natural gas gathering and processing volumes in the natural gas gathering and processing segment, and higher expected NGL volumes gathered and fractionated in the natural gas liquids segment. 

These expected volume increases are the result of full-year operations and earnings from capital-growth projects completed throughout 2013 and reflect expected earnings from the completion of capital-growth projects through 2014 in the natural gas gathering and processing, and natural gas liquids segments. 

Preliminary estimates of the partnership's 2014 DCF are expected to be in the range of $1.15 billion to $1.25 billion.

2014 financial guidance includes a projected 1.5-cent-per-unit-per-quarter increase in unitholder distributions declared, while maintaining an annual coverage ratio of 1.05 to 1.15 times distributable cash flow.  Actual unitholder distribution declarations are subject to ONEOK Partners board approval.

CAPITAL-GROWTH ACTIVITIES:

The partnership has announced approximately $6.0 billion to $6.4 billion in capital-growth projects and acquisitions between 2010 and 2016, of which approximately $2.7 billion have been completed. 

  • Of the approximately $3.0 billion to $3.3 billion of announced capital-growth projects and acquisitions in the natural gas gathering and processing segment, projects totaling approximately $1.5 billion have been completed, as follows:
    • Approximately $565 million to construct the Stateline I and Stateline II plants, each with 100 MMcf/d of natural gas processing capacity, and related 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, and the Stateline II plant was placed in service in April 2013;
    • Approximately $305 million in September 2013 to acquire the Sage Creek plant, a 50 MMcf/d natural gas processing facility, and related natural gas gathering and natural gas liquids infrastructure in the Niobrara Shale, an NGL-rich area in the Powder River Basin in Wyoming;
    • Approximately $90 million in the fourth quarter 2013 to acquire the remaining 30 percent interest in the Maysville natural gas processing facility in the Cana-Woodford Shale in Oklahoma;
    • Approximately $150 million to construct a 270-mile natural gas gathering system and related infrastructure in Divide County, N.D., portions of which were placed in service in the second quarter of 2013, and the remaining expansions to the system are expected to be completed by year-end 2014. The system gathers and transports natural gas from producers in the Williston Basin to the partnership's Stateline I and Stateline II plants, each with 100 MMcf/d of natural gas processing capacity in western Williams County, N.D.; and
    • 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 in service in December 2011, and related expansions; and for new well connections, expansions and upgrades to the existing natural gas gathering system infrastructure.
  • Approximately $1.6 billion to $1.8 billion of announced capital-growth projects in the natural gas gathering and processing segment are in various stages of construction, as follows:
    • 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 area in Oklahoma, which is expected to be completed in March 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 Williston Basin in North Dakota, which is expected to be completed in the third quarter 2014; and expansions and upgrades to the existing gathering and compression infrastructure;
    • Approximately $325 million to $360 million to construct the Garden Creek III plant, a 100 MMcf/d natural gas processing facility in the Williston Basin in North Dakota, which is expected to be completed in the first quarter 2015; and expansions and upgrades to the existing gathering and compression infrastructure;
    • Approximately $550 million to $680 million to construct the Lonesome Creek plant, a 200-MMcf/d natural gas processing facility in the Williston Basin in North Dakota, which is expected to be completed in the fourth quarter 2015; and expansions and upgrades to the existing gathering and compression infrastructure; and
    • Approximately $50 million to upgrade the recently acquired Sage Creek natural gas processing plant, and construct natural gas gathering and processing infrastructure through 2016.
  • Of the approximately $3.0 billion to $3.1 billion of announced capital-growth projects and acquisitions in the natural gas liquids segment, projects totaling approximately $1.3 billion have been completed, as follows:
    • Approximately $375 million for the construction of a 75,000 bpd NGL fractionator, MB-2, at Mont Belvieu, Texas, which was placed in service in December 2013;
    • Approximately $455 million for the construction of the 600-mile, 12-inch diameter Bakken NGL Pipeline to transport unfractionated NGLs produced from the Bakken Shale in the Williston Basin to the partnership's 50 percent-owned Overland Pass Pipeline, a 760-mile NGL pipeline extending from southern Wyoming to Conway, Kan. The Bakken NGL Pipeline was placed in service in April 2013, with current capacity of 60,000 bpd;
    • Approximately $23 million for the construction of a 12-inch diameter ethane header pipeline that creates a new point of interconnection between the Mont Belvieu, Texas, NGL fractionation and storage assets, and several petrochemical customers. The ethane header pipeline has the capacity to transport 400,000 bpd of purity ethane from the partnership's NGL storage facilities, from its 80 percent-owned, 160,000-bpd MB-1 NGL fractionator; and from its two wholly owned, 75,000-bpd NGL fractionators – MB-2, which was placed in service in December 2013, and MB-3, which is currently under construction. The ethane header pipeline was placed in service in April 2013;
    • Approximately $36 million in 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, which was placed in service in the second quarter 2013;
    • Approximately $117 million for a 60,000 bpd expansion of the partnership's NGL fractionation capacity at Bushton, Kan., which was placed in service in September 2012, to accommodate NGL 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 by adding an incremental 75,000 bpd to 80,000 bpd of unfractionated NGLs to the partnership's existing NGL gathering systems in the Mid-Continent and the Arbuckle Pipeline. These NGL pipelines were placed in service in April 2012, and the partnership connected to its NGL gathering system three new third-party natural gas processing facilities and three existing third-party natural gas processing facilities that were expanded. In addition, the installation of additional pump stations on the Arbuckle Pipeline was completed, increasing its capacity to 240,000 bpd; and
    • Approximately $30 million for the installation of seven additional pump stations along its existing Sterling I NGL distribution pipeline that was placed in service at the end of 2011; the additional pump stations increased the pipeline's capacity by 15,000 bpd.
  • Approximately $1.8 billion of announced capital-growth projects in the natural gas liquids segment are in various stages of construction, as follows:
    • Approximately $750 million to $800 million for the construction of a 540-plus-mile, 16-inch diameter NGL pipeline – the Sterling III Pipeline – expected to be completed in March 2014, 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 $46 million to install a 40,000 bpd ethane/propane (E/P) splitter at its Mont Belvieu NGL storage facility to split E/P mix into purity ethane, which is expected to be completed in March 2014;
    • Approximately $100 million to install additional pump stations on the Bakken NGL Pipeline to increase its capacity to 135,000 bpd from its current capacity of 60,000 bpd, which is expected to be completed in the third quarter 2014;
    • Approximately $100 million, announced in November 2013, for a second expansion of the Bakken NGL Pipeline, which will increase the pipeline's capacity to 160,000 bpd from 135,000. The expansion is expected to be completed in the second quarter 2016;
    • 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, which is expected to be completed in the fourth quarter 2014;
    • Approximately $85 million for the construction of new NGL pipeline infrastructure to connect the recently acquired Sage Creek natural gas processing plant to the partnerships' Bakken NGL Pipeline, which is expected to be completed in the fourth quarter 2014; and
    • Approximately $140 million 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 unfractionated NGLs produced in the Williston Basin; both projects are expected to be completed in the first quarter 2015.

EARNINGS CONFERENCE CALL AND WEBCAST:

ONEOK Partners and ONEOK executive management will conduct a joint conference call on Tuesday, Feb. 25, 2014, at 11 a.m. Eastern Standard Time (10 a.m. Central Standard Time).  The call also will be carried live on ONEOK Partners' and ONEOK's websites.

To participate in the telephone conference call, dial 877-419-6593, pass code 5357777, 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 5357777.

LINK TO EARNINGS TABLES:

http://www.oneokpartners.com/~/media/ONEOKPartners/EarningsTables/2013/OKS_Q4_2013_Earnings_921PEM6.ashx

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

ONEOK Partners has disclosed in this news release historical EBITDA, DCF and coverage ratio levels, and anticipated EBITDA, DCF and coverage ratio levels that are non-GAAP financial measures.  EBITDA, DCF and coverage ratio are used as measures of the partnership's financial performance and are defined as follows:

  • 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;
  • Coverage ratio is defined as distributable cash flow to limited partners per limited partner unit divided by the distribution declared per limited partner unit in the period; and
  • Distributable cash flow to limited partners per limited partner unit is computed as DCF less distributions declared to the general partner in the period, divided by the weighted-average number of units outstanding in the period.

The partnership believes the non-GAAP financial measures described above are useful to investors because they are used by many companies in its industry to measure 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, DCF and coverage ratio 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 in 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 in the United States 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 pure-play publicly traded general partner, which owns 41.2 percent of the overall partnership interest, as of Dec. 31, 2013. 

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 and related cost estimates), 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 and crude oil 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 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.

Analyst Contact:

T.D. Eureste


918-588-7167



Media Contact: 

Brad Borror


918-588-7582

 











SOURCE ONEOK Partners, L.P.



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