ONEOK Partners Announces Second-quarter 2013 Financial Results; Affirms 2013 Earnings Guidance and Three-year Financial Forecasts

TULSA, Okla., July 30, 2013 /PRNewswire/ -- ONEOK Partners, L.P. (NYSE: OKS) today announced second-quarter 2013 net income attributable to ONEOK Partners of $202.4 million, or 62 cents per unit, compared with $206.5 million, or 69 cents per unit, in the second quarter 2012.

Second-quarter 2013 results reflect significantly higher natural gas volumes gathered and processed, and natural gas liquids (NGL) gathered as a result of completed growth projects. 

As expected, NGL exchange-services margins continued to grow, while NGL optimization margins continued to decline as a result of ONEOK Partners' strategy to convert NGL optimization capacity to fee-based exchange-services capacity, and narrower NGL price differentials.   

As anticipated, ethane rejection affected ONEOK Partners' natural gas liquids segment's second-quarter operating results and equity earnings by approximately $14.6 million, which does not include the benefit of minimum volume obligations.

Second-quarter 2013 distributable cash flow (DCF) was $251.9 million, providing 1.17 times coverage of the cash distributions that will be paid on Aug. 15, 2013, to unitholders of record on Aug. 5, 2013.  This compares with DCF of $240.4 million in the second quarter 2012 that provided 1.29 times coverage.  DCF for the first six months of 2013 was $445.1 million, providing 0.99 times coverage, compared with $519.3 million for the same period last year providing coverage of 1.50 times.

"Our natural gas gathering and processing and natural gas liquids segments reported strong volume growth from several completed projects, including the Bakken NGL Pipeline and the Stateline I and II natural gas processing plants in the Williston Basin," said John W. Gibson, chairman and chief executive officer of ONEOK Partners.

"As expected, narrower NGL price differentials and less transportation capacity available for NGL optimization activities affected the natural gas liquids segment.  We are continuing to convert a portion of our NGL transportation capacity to fee-based earnings to reduce earnings volatility in the natural gas liquids segment," Gibson added.

"Although we anticipate that ongoing ethane rejection will continue to affect our short-term financial results, the execution of our approximately $4.7 billion to $5.2 billion capital-growth program through 2015 is expected to continue to provide incremental and long-term, fee-based earnings and cash flows to the partnership," said Gibson.

Year-to-date net income attributable to ONEOK Partners was $359.0 million, or $1.03 per unit, compared with $445.3 million, or $1.59 per unit, for the same period last year.

2013 AND THREE-YEAR FINANCIAL GUIDANCE AFFIRMED

ONEOK Partners affirmed its 2013 net income guidance range of $790 million to $870 million, announced on Feb. 25, 2013.  The partnership's DCF is expected to remain in the range of $910 million to $1.0 billion.  Operating income in the partnership's natural gas liquids segment is expected to increase, while operating income in the natural gas gathering and processing segment is expected to decrease from the previous earnings guidance.

ONEOK Partners affirmed that its earnings before interest, taxes, depreciation and amortization (EBITDA) is expected to increase by an average of 15 to 20 percent annually over a three-year period, comparing 2012 results with 2015.

ONEOK Partners also affirmed that it still estimates an average annual distribution increase of 8 to 12 percent between 2012 and 2015, subject to ONEOK Partners board approval.

SECOND-QUARTER AND YEAR-TO-DATE 2013 FINANCIAL PERFORMANCE

In the second quarter 2013, EBITDA was $315.1 million, compared with $306.0 million in the second quarter 2012.  Year-to-date 2013 EBITDA was $575.5 million, compared with $650.1 million in the same period last year.  Additional information is available in the guidance tables on the ONEOK Partners website.

Second-quarter 2013 operating income was $230.0 million, compared with $228.1 million in the second quarter 2012.

Second-quarter 2013 operating income was relatively unchanged but reflects higher natural gas volumes gathered and processed, and natural gas liquids (NGL) volumes gathered as a result of the completed growth projects in the natural gas gathering and processing, and the natural gas liquids segments.  Operating income from higher volumes was offset by:

  • Significantly narrower NGL location price differentials;
  • Lower realized natural gas and NGL product prices;
  • The impact of ethane rejection; and
  • Increased depreciation and amortization expense from the completed growth projects.

Operating income for the first six months of 2013 was $407.7 million, compared with $484.1 million for the same period last year.

The decrease in operating income for the six-month 2013 period reflects lower net margins from significantly narrower NGL location price differentials, lower realized natural gas and NGL product prices, and the impact of ethane rejection.  These decreases were offset partially by higher natural gas volumes gathered and processed, and NGL volumes gathered as a result of the completed growth projects in the natural gas gathering and processing, and the natural gas liquids segments.

Second-quarter 2013 equity earnings were $26.4 million, compared with $29.2 million in the second quarter 2012.  Year-to-date 2013 equity earnings were $52.3 million, compared with $63.8 million for the same period last year.  These decreases were due to the impact of lower NGL volumes on Overland Pass Pipeline due to ethane rejection and decreased transportation rates on Northern Border Pipeline.

Operating costs were $124.0 million in the second quarter 2013, compared with $123.4 million for the same period last year.  Operating costs for the six-month 2013 period were $262.2 million, compared with $239.2 million for the same period last year.  Operating costs were relatively unchanged due to an increase in labor and employee benefit costs associated with the growth of operations, offset by lower other employee-related expenses and the timing of scheduled maintenance.

Depreciation and amortization expense was $58.2 million in the second quarter 2013, compared with $51.0 million for the same period last year.  Depreciation and amortization expense for the first six months of 2013 was $112.9 million, compared with $100.3 million for the same period last year.  These increases for the three- and six-month 2013 periods were due primarily to the partnership's recently completed growth projects.

Capital expenditures were $481.4 million in the second quarter 2013, compared with $355.4 million for the same period in 2012.  Year-to-date 2013 capital expenditures were $924.8 million, compared with $636.2 million for the same period last year.  These increases were due primarily to growth projects in the natural gas gathering and processing, and natural gas liquids segments.

> View earnings tables

SECOND-QUARTER 2013 SUMMARY:

  • Natural gas gathering and processing segment operating income of $55.5 million, compared with $46.7 million in the second quarter 2012;
  • Natural gas pipelines segment operating income of $31.9 million, compared with $32.6 million in the second quarter 2012;
  • Natural gas liquids segment operating income of $142.7 million, compared with $149.1 million in the second quarter 2012;
  • Placing in service in the second quarter 2013 the following growth projects:
    • The 600-mile Bakken NGL Pipeline that has a current capacity to transport 60,000 barrels per day (bpd) of unfractionated NGLs in the Williston Basin to the partnership's 50 percent-owned Overland Pass Pipeline;
    • The 100-Million cubic feet per day (MMcf/d) Stateline II natural gas processing facility in western Williams County, N.D.;
    • An ethane header pipeline that creates a new point of interconnection between the partnership's Mont Belvieu, Texas, NGL fractionation and storage assets, and several petrochemical customers;
    • A significant portion of the Divide County, N.D., natural gas gathering system;  the remaining portion is expected to be completed in the second half 2013;
  • Having $6.2 million of cash and cash equivalents and $429.0 million in commercial paper outstanding and no borrowings outstanding under the partnership's $1.2 billion revolving credit facility as of June 30, 2013; and
  • Increasing in July 2013 its distribution for the second quarter 2013 to 72 cents per unit, or $2.88 per unit on an annualized basis, payable on Aug. 15, 2013, to unitholders of record at the close of business Aug. 5, 2013.

BUSINESS-UNIT RESULTS:

Natural Gas Gathering and Processing Segment

The natural gas gathering and processing segment reported second-quarter 2013 operating income of $55.5 million, compared with operating income of $46.7 million for the second quarter 2012.  Second-quarter 2013 results reflect:

  • A $22.3 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, and higher fees; 
  • A $6.4 million increase due to a contract settlement;
  • An $8.8 million decrease due primarily to lower realized NGL product prices;
  • A $1.6 million decrease due to changes in contract mix and terms associated with volume growth; and
  • A $1.1 million decrease from lower natural gas volumes gathered in the Powder River Basin as a result of continued production declines.

Operating income for the six-month 2013 period was $89.2 million, compared with $94.3 million in the same period last year.  Six-month 2013 results reflect:

  • A $44.9 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, and higher fees;
  • A $6.4 million increase due to a contract settlement;
  • A $21.5 million decrease due primarily to lower realized NGL product prices;
  • A $6.5 million decrease due to changes in contract mix and terms associated with volume growth; and
  • A $2.3 million decrease from lower natural gas volumes gathered in the Powder River Basin as a result of continued production declines.

Operating costs in the second quarter 2013 were $45.0 million, compared with $41.2 million for the second quarter 2012.  Second-quarter 2013 operating costs, compared with operating costs in the same period 2012, reflect:

  • A $3.3 million increase in labor and employee benefit costs associated with the growth in operations;
  • A $1.2 million increase from higher materials, supplies and outside services expenses;
  • A $1.0 million increase from higher property taxes; and
  • A $2.0 million decrease in other employee-related expenses.

Operating costs for the six-month 2013 period were $96.7 million, compared with $81.5 million for the same period last year.  Six-month 2013 operating costs, compared with operating costs in the same period 2012, reflect:

  • A $6.2 million increase from higher materials, supplies and outside services expenses;
  • A $5.7 million increase in labor and employee benefit costs associated with the growth in operations; and
  • A $2.2 million increase from higher property taxes.

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

  • Natural gas gathered was 1,326 billion British thermal units per day (BBtu/d) in the second quarter 2013, up 23 percent compared with the same period last year due to increased well connections in the Williston Basin and western Oklahoma, and the completion of additional natural gas gathering lines and compression to support the Stateline I and Stateline II natural gas processing plants in the Williston Basin, offset partially by continued production declines in the Powder River Basin in Wyoming; and up 9 percent compared with the first quarter 2013;
  • Natural gas processed was 1,055 BBtu/d in the second quarter 2013, up 28 percent compared with the same period last year due to increased well connections in the Williston Basin and western Oklahoma, and the completion of the Stateline I and Stateline II natural gas processing plants in the Williston Basin; and up 7 percent compared with the first quarter 2013;
  • The realized composite NGL net sales price was 85 cents per gallon in the second quarter 2013, down 16 percent compared with the same period last year; and unchanged compared with the first quarter 2013;
  • The realized condensate net sales price was $83.86 per barrel in the second quarter 2013, down 3 percent compared with the same period last year; and down 5 percent compared with the first quarter 2013; and
  • The realized residue natural gas net sales price was $3.57 per million British thermal units (MMBtu) in the second quarter 2013, down 6 percent compared with the same period last year; and unchanged compared with the first quarter 2013.

The gathering and processing segment's total equity volumes are increasing, and the composition of the equity NGL barrel continues to change under various percent-of-proceeds contracts as new natural gas processing plants in the Williston Basin are placed into service.  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 the second quarter 2013.  As a result, second-quarter 2013 equity NGL volumes were weighted less toward ethane and more toward propane, iso-butane, normal butane and natural gasoline compared with the same period in the previous year.

For the second-quarter 2013, the segment connected approximately 350 new wells, compared with approximately 250 wells for the same period in 2012.  For the first six months of 2013, the segment connected approximately 600 new wells, despite periods of challenging weather conditions in North Dakota, compared with approximately 450 wells for the same period in 2012.  The partnership expects to connect more than 1,000 wells in 2013.

The following table contains operating information for the periods indicated:


Three Months Ended


Six Months Ended


June 30, 


June 30, 

Operating Information (a) (d)

2013


2012


2013


2012

Commodity








     NGL sales (Bbl/d) (b)

13,890


12,101


13,423


10,900

     Residue gas sales (MMBtu/d) (c)

68,812


44,192


63,108


42,694

     Condensate sales(Bbl/d) (b)

2,496


2,441


2,553


2,592

     Percentage of total net margin

65%


69%


64%


69%

Fee-based








     Wellhead volumes(MMBtu/d)

1,326,008


1,078,840


1,270,706


1,061,741

     Average rate($/MMBtu)

$        0.34


$        0.35


$        0.35


$        0.36

     Percentage of total net margin

35%


31%


36%


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 its equity volumes in the natural gas gathering and processing segment for the periods indicated:


Six Months Ending December 31, 2013


Volumes Hedged


Average Price


Percentage Hedged

NGLs (Bbl/d) 

9,028


$ 1.11

/ gallon


66%

Condensate (Bbl/d) 

2,015


$ 2.42

/ gallon


82%

     Total (Bbl/d)

11,043


$ 1.35

/ gallon


69%

Natural gas(MMBtu/d)

67,310


$ 3.83

/ MMBtu


81%
















Year Ending December 31, 2014


Volumes Hedged


Average Price


Percentage Hedged

NGLs (Bbl/d) 

347


$ 2.23

/ gallon


2%

Condensate (Bbl/d) 

1,661


$ 2.23

/ gallon


53%

     Total (Bbl/d)

2,008


$ 2.23

/ gallon


10%

Natural gas(MMBtu/d)

69,274


$ 4.11

/ MMBtu


86%
















Year Ending December 31, 2015


Volumes Hedged


Average Price


Percentage Hedged

Natural gas(MMBtu/d)

48,877


$ 4.19

/ MMBtu


44%








The partnership expects its NGL and natural gas commodity-price sensitivities to increase in the future as its capital 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 NGLs, crude oil and natural gas as of June 30, 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 1-cent-per-gallon change in the composite price of NGLs would change annual net margin by approximately $2.2 million;
  • A $1.00-per-barrel change in the price of crude oil would change annual net margin by approximately $1.2 million; and 
  • A 10-cent-per-MMBtu change in the price of natural gas would change annual net margin by approximately $2.9 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 gathering and processing margins for certain contracts.

Natural Gas Pipelines Segment

The natural gas pipelines segment reported second-quarter 2013 operating income of $31.9 million, compared with $32.6 million for the second quarter 2012.  Second-quarter 2013 results reflect a $1.3 million increase from higher rates on Guardian Pipeline; and a $1.3 million decrease from lower natural gas storage margins, primarily as a result of lower contracted capacity.

Operating income for the six-month 2013 period was $67.8 million, compared with $65.6 million for the same period last year.  The increase for the six-month 2013 period reflects a $4.3 million increase from higher rates on Guardian Pipeline and higher contracted capacity with natural gas producers on its intrastate pipelines.

Second-quarter 2013 equity earnings from investments, primarily from the partnership's 50 percent-owned Northern Border Pipeline, were $15.3 million, compared with $16.3 million in the same period in 2012.  Six-month 2013 equity earnings were $31.7 million, compared with $36.7 million in the same period last year. 

These decreases in equity earnings for the second-quarter and year-to-date 2013 periods were due primarily to reduced transportation rates resulting from a Northern Border Pipeline rate settlement that became effective Jan. 1, 2013.  The decrease in equity earnings in the second quarter 2013 was partially offset by higher transportation volumes.  Substantially all of Northern Border Pipeline's long-haul transportation capacity has been contracted through March 2015.

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

  • Natural gas transportation capacity contracted was 5,362 thousand dekatherms per day in the second quarter 2013, up 2 percent compared with the same period last year; and down 5 percent compared with the first quarter 2013;
  • Natural gas transportation capacity subscribed was 88 percent in the second quarter 2013, up 1 percent compared with the same period last year; and down 5 percent compared with the first quarter 2013; and
  • The average natural gas price in the Mid-Continent region was $3.85 per MMBtu in the second quarter 2013, up 77 percent compared with the same period last year; and up 13 percent compared with the first quarter 2013.

Natural Gas Liquids Segment

The natural gas liquids segment reported second-quarter 2013 operating income of $142.7 million, compared with $149.1 million in the same period last year.  Second-quarter 2013 results reflect:

  • A $46.3 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 $7.1 million increase from the impact of operational measurement gains of approximately $5.2 million in the second quarter 2013, compared with losses of approximately $1.9 million in the same period last year;
  • A $41.4 million decrease in optimization and marketing margins, primarily as a result of a $54.2 million decrease from significantly narrower NGL location price differentials and less transportation capacity available for optimization activities, offset partially by a $12.8 million increase in its marketing activities.  An increasing portion of its transportation capacity between the Conway, Kan., and Mont Belvieu, Texas, NGL market centers now is utilized for exchange-services activities to produce fee-based earnings.  The segment's marketing activities experienced lower NGL product sales and higher inventories in the second quarter 2012 as a result of scheduled maintenance at its Mont Belvieu NGL fractionation facility;
  • An $11.3 million decrease from the impact of ethane rejection, which resulted in lower NGL volumes; and
  • A $7.3 million decrease from lower isomerization volumes, resulting from narrower price differentials between normal butane and iso-butane.

Operating income for the six-month 2013 period was $249.7 million, compared with $323.6 million in the same period last year.  Six-month 2013 results reflect:

  • An $89.6 million increase in exchange-services margins, which resulted 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 $9.9 million increase from the impact of operational measurement gains of approximately $8.7 million in the six-month period 2013, compared with losses of approximately $1.2 million in the same period last year;
  • A $131.5 million decrease in optimization and marketing margins, primarily as a result of a $147.0 million decrease from significantly narrower NGL location price differentials and less transportation capacity available for optimization activities, offset partially by a $15.4 million increase in its marketing activities.  An increasing portion of its transportation capacity between the Conway, Kan., and Mont Belvieu, Texas, NGL market centers now is utilized for exchange-services activities to produce fee-based earnings.  The segment's marketing activities experienced lower NGL product sales and higher inventories in the second quarter 2012 as a result of scheduled maintenance at its Mont Belvieu NGL fractionation facility;
  • A $24.0 million decrease from the impact of ethane rejection, which resulted in lower NGL volumes; and
  • An $8.9 million decrease from lower isomerization volumes, resulting from narrower price differentials between normal butane and iso-butane.

Operating costs were $54.3 million in the second quarter 2013, compared with $57.9 million in the second quarter 2012.  Second quarter 2013 operating costs decreased primarily due to the timing of $3.6 million of expenses associated with scheduled maintenance.  Additionally, operating costs decreased $3.2 million as a result of lower other employee-related expenses, offset partially by an increase of $2.4 million in labor and employee benefit costs associated with the growth of operations related to completed capital projects.

Operating costs for the six-month 2013 period were $114.1 million, compared with $109.9 million for the same period last year.  Six-month 2013 operating costs reflect a $3.9 million increase in labor and employee benefit costs associated with the growth in operations; and a $1.0 million increase from higher outside services expenses associated primarily with scheduled maintenance and the growth of operations related to the completed capital projects.

Equity earnings from investments were $5.9 million in the second quarter 2013, unchanged compared with the same period in 2012.  Six-month 2013 equity earnings from investments were $9.0 million, compared with $11.6 million for the same period last year. 

The decrease for the six-month 2013 period was due primarily to lower earnings from the partnership's 50 percent-owned Overland Pass Pipeline, as a result of lower volumes due to ethane rejection, offset partially by lower operational measurement losses and higher volumes delivered to Overland Pass Pipeline from its Bakken NGL Pipeline, which was placed in service in April 2013. 

Ethane rejection decreased equity earnings $3.3 million and $7.9 million for the three- and six-month 2013 periods, respectively, compared with the same periods last year.

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

  • NGLs fractionated were 537,000 bpd in the second quarter 2013, up 2 percent compared with the same period last year, due to increased volumes from the Williston Basin made available by the segment's completed Bakken NGL Pipeline, the impact of scheduled maintenance at its Mont Belvieu NGL fractionation facility in the second quarter 2012; offset partially by lower volumes from ethane rejection; and up 5 percent compared with the first quarter 2013;
  • NGLs transported on gathering lines were 554,000 bpd in the second quarter 2013, up 6 percent compared with the same period last year, due primarily to increased volumes of 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 that were placed in service in April 2012 and increased volumes from the Williston Basin made available by its completed Bakken NGL Pipeline, the impact of scheduled maintenance at its Mont Belvieu NGL fractionation facility in the second quarter 2012; offset partially by decreases in NGL volumes gathered as a result of ethane rejection; and up 11 percent compared with the first quarter 2013;
  • NGLs transported on distribution lines were 432,000 bpd in the second quarter 2013, down 10 percent compared with the same period last year, due primarily to decreased volumes resulting from ethane rejection; and up 10 percent compared with the first 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 6 cents per gallon in the second quarter 2013, compared with 23 cents per gallon in the same period last year; and 1 cent per gallon in the first quarter 2013.

2013 EARNINGS GUIDANCE AND THREE-YEAR GROWTH FORECASTS

ONEOK Partners affirmed its 2013 net income guidance range of $790 million to $870 million announced Feb. 25, 2013.  ONEOK Partners' operating income reflects an expected increase in the natural gas liquids segment, while operating income in the natural gas gathering and processing segment is expected to decrease from previous earnings guidance provided on Feb. 25, 2013.

ONEOK Partners also affirmed its 2013 DCF guidance range of $910 million to $1.0 billion.

ONEOK Partners' 2013 guidance includes a projected 0.5-cent-per-unit-per-quarter increase in unitholder distributions, subject to ONEOK Partners board approval.

ONEOK Partners still expects EBITDA to increase by an average of 15 to 20 percent annually over a three-year period, comparing 2012 results with 2015.

The partnership estimates an average annual distribution increase of 8 to 12 percent between 2012 and 2015, subject to ONEOK Partners board approval.

The midpoint for ONEOK Partners' 2013 operating income guidance is expected to be approximately $935 million.

Natural Gas Gathering and Processing

The midpoint of the natural gas gathering and processing segment's updated 2013 operating income guidance is $209 million, compared with its previous guidance of $238 million, reflecting lower expected natural gas volumes gathered and processed, compared with previous estimates. These decreases are primarily a result of the challenging conditions from melting snow and rain during the second quarter 2013, which caused construction and well-completion delays.

In 2013, natural gas volumes gathered are now expected to average 1,350 BBtu/d, a slight decrease compared with the previous estimate of 1,370 BBtu/d provided in February 2013.  Natural gas volumes processed are now expected to average 1,085 BBtu/d, a 4 percent decrease compared with the previous estimate of 1,125 BBtu/d provided in February 2013. 

The average unhedged prices assumed for the remainder of 2013 are $102.60 per barrel for New York Mercantile Exchange (NYMEX) crude oil, $3.75 per MMBtu for NYMEX natural gas and 62 cents per gallon, on a full ethane recovery basis, for composite natural gas liquids.  Previous guidance for full year 2013 released on Feb. 25, 2013, assumed $88.00 per barrel for NYMEX crude oil, $3.75 per MMBtu for NYMEX natural gas and 66 cents per gallon, on a full ethane recovery basis, for composite natural gas liquids.

For the second half of 2013, hedges are in place on approximately 81 percent of the segment's expected equity natural gas production at an average price of $3.83 per MMBtu; 66 percent of its expected equity NGL production at an average price of $1.11 per gallon; and 82 percent of its expected equity condensate production at an average price of $2.42 per gallon.

Currently, the partnership estimates that in its natural gas gathering and processing segment, a 1-cent-per-gallon change in the composite price of NGLs would change annual net margin by approximately $2.2 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 $2.9 million.  All of these sensitivities exclude the effects of hedging and assume normal operating conditions.

Natural Gas Pipelines

The midpoint of the natural gas pipelines segment's 2013 operating income guidance is expected to be approximately $150 million, reflecting weaker than expected electric power demand due to milder weather in 2013, compared with 2012.

Natural Gas Liquids

The midpoint of the natural gas liquids segment's updated 2013 operating income guidance is expected to increase to approximately $575 million, compared with its previous guidance of $545 million.

This updated 2013 guidance reflects additional capacity available for optimization activities as a result of ethane rejection; more favorable NGL location and product differentials; higher expected isomerization margins; and new volume growth from commercial activities.  Due to ethane rejection occurring across its system, NGL pipeline capacity typically utilized for exchange-services business became available, allowing the partnership the ability to benefit from the NGL price differentials between the Mid-Continent and Gulf Coast market centers.

For the second half of 2013, the average Conway-to-Mont Belvieu OPIS location price differential of ethane in ethane/propane mix is expected to be 6 cents per gallon, compared with its previous full-year 2013 guidance of 5 cents per gallon. The impact of this location price differential in the natural gas liquids segment has decreased as an increasing portion of its transportation capacity between the Conway, Kan., and Mont Belvieu, Texas, NGL market centers now is utilized by its exchange-services activities to produce fee-based earnings.

In 2013, NGL volumes fractionated are now expected to average 545 MBbl/d, a 12 percent decrease compared with the previous estimate of 620 MBbl/d provided in February 2013.  NGL volumes transported on gathering lines are now expected to average 560 MBbl/d, a 6 percent decrease compared with the previous estimate of 593 MBbl/d provided in February 2013.  

The lower NGL volume forecasts – compared with previous estimates provided in February 2013 – are primarily the result of lower than expected volume increases from third-party natural gas processors during the first half 2013 and projected ethane rejection at many natural gas processing plants connected to the partnership's NGL system for the remainder of 2013.  The financial impact of these volume decreases is mitigated by minimum volume obligations, and the ability to utilize the available transportation capacity for optimization activities.

Capital Expenditures

Capital expenditures for 2013 are expected to be approximately $2.36 billion, comprised of approximately $2.24 billion in growth capital and $120 million in maintenance capital.

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

GROWTH ACTIVITIES:

The partnership has announced approximately $4.7 billion to $5.2 billion for growth projects between 2010 and 2015, of which approximately $1.9 billion have been completed. 

  • Of the approximately $2.1 billion to $2.2 billion of announced growth projects in the natural gas gathering and processing segment, approximately $1.0 billion has been completed, as follows:
    • 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; and
    • Approximately $600 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 $1.1 billion to $1.2 billion of announced growth projects in the natural gas gathering and processing segment are in various stages of construction, as follows:
    • Approximately $150 million to construct a 270-mile natural gas gathering system and related infrastructure in Divide County, N.D.  A significant portion of this system was placed in service in the second quarter 2013, with the final portions of the system expected to be completed in the second half 2013.  The system gathers and transports natural gas from producers in the Bakken Shale and Three Forks formations in the Williston Basin to the partnership's previously announced 100 MMcf/d Stateline II natural gas processing facility in western Williams County, N.D.;
    • Approximately $350 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 completed in the first quarter 2014; and expansions and upgrades to the existing gathering and compression infrastructure;
    • Approximately $310 million to $345 million to construct the Garden Creek II plant, a 100 MMcf/d natural gas processing facility in the Bakken Shale and Three Forks formations in the Williston Basin in North Dakota, which is expected to be completed in the third quarter 2014; and expansions and upgrades to the existing gathering and compression infrastructure; and
    • Approximately $325 million to $360 million to construct the Garden Creek III plant, a 100 MMcf/d natural gas processing facility in the Bakken Shale and Three Forks formations in the Williston Basin in North Dakota, which is expected to be completed in the first quarter 2015; and expansions and upgrades to the existing gathering and compression infrastructure.
  • Of the $2.6 billion to $3.0 billion of announced growth projects in the natural gas liquids segment, approximately $900 million of them have been completed, as follows:
    • 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 $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 three new third-party natural gas processing facilities and three existing third-party natural gas processing facilities that were expanded to its NGL gathering system.  In addition, the installation of additional pump stations on the Arbuckle Pipeline was completed, increasing its capacity to 240,000 bpd;
    • Approximately $117 million for a 60,000 bpd expansion of the partnership's NGL fractionation capacity at Bushton, Kan., which was placed in service in September 2012, to accommodate NGL volumes from the Mid-Continent and Williston Basin;
    • Approximately $490 million to $520 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 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; its 80 percent-owned, 160,000 bpd MB-1 NGL fractionator; and its two wholly owned, 75,000-bpd MB-2 and MB-3 NGL fractionators that are under construction.  The ethane header pipeline was placed in service in April 2013; and
    • 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, which was completed in the second quarter 2013.
  • Approximately $1.7 billion to $2.1 billion of announced growth projects in the natural gas liquids segment are in various stages of construction, as follows:
    • Approximately $360 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 the third quarter 2013;
    • Approximately $610 million to $810 million for the construction of a 540-plus-mile, 16-inch NGL pipeline – the Sterling III Pipeline – expected to be completed in late 2013, to transport either unfractionated NGLs or NGL purity products from the Mid-Continent region to the Texas Gulf Coast with an initial capacity of 193,000 bpd and the ability to expand to 250,000 bpd; and the reconfiguration of its existing Sterling I and II NGL distribution pipelines to transport either unfractionated NGLs or NGL purity products;
    • Approximately $45 million to install a 40,000 bpd ethane/propane (E/P) splitter at its Mont Belvieu NGL storage facility to split E/P mix into purity ethane, which is expected to be completed in the first quarter 2014;
    • Approximately $100 million to install additional pump stations on the Bakken NGL Pipeline to increase its capacity to 135,000 bpd from the current capacity of 60,000 bpd.  The expansion is expected to be completed in the third quarter 2014;
    • Approximately $525 million to $575 million for the construction of a 75,000 bpd NGL fractionator, MB-3, and related infrastructure at Mont Belvieu, Texas, that is expected to be completed in the fourth quarter 2014; and
    • Approximately $140 million, announced in January 2013, for the construction of an approximately 95-mile NGL pipeline between existing NGL fractionation infrastructure at Hutchinson, Kan., and Medford, Okla., and the modification of the partnership's NGL fractionation infrastructure at Hutchinson, Kan., to accommodate 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 Wednesday, July 31, 2013, at 11 a.m. Eastern Daylight Time (10 a.m. Central Daylight Time).  The call also will be carried live on ONEOK Partners' and ONEOK's websites.

To participate in the telephone conference call, dial 888-298-3451, pass code 5921668, 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 5921668.

LINK TO EARNINGS TABLES:

http://www.oneokpartners.com/~/media/ONEOKPartners/EarningsTables/2013/OKS-Q2_2013_Earnings_7dDF9sz.ashx

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

ONEOK Partners has disclosed in this news release historical 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. 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 for the period.  Distributable cash flow to limited partners per limited partner unit is computed as DCF less distributions declared to the general partner for the period, divided by the weighted average number of units outstanding for the period.

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, 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 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 43.3 percent of the overall partnership interest as of June 30, 2013.  ONEOK is one of the largest natural gas distributors in the United States, and its energy services operation focuses primarily on marketing natural gas and related services throughout the U.S. 

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

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

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