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 November 3, 2015 - 4:39 PM EST
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ONEOK Partners Announces Third-quarter 2015 Results

- ONEOK Partners reaffirms 2015 financial guidance ranges and the expectation to exceed a 1.0 times distribution coverage in 2016; - The natural gas gathering and processing segment's fee-based margin is expected to increase to more than 70 percent in 2016 compared with 50 percent in 2015; - The Williston Basin well connect target for 2015 increased to 825 from 700; - Williston Basin natural gas gathered volumes reached more than 685 MMcf/d in September, up approximately 25 percent compared with September 2014; and - The Bakken NGL Pipeline reached approximately 111,000 bpd in September, up approximately 106 percent compared with September 2014.

TULSA, Okla., Nov. 3, 2015 /PRNewswire/ -- ONEOK Partners, L.P. (NYSE: OKS) today announced third-quarter 2015 financial results.

THIRD-QUARTER AND YEAR-TO-DATE 2015 FINANCIAL HIGHLIGHTS


Three Months Ended


Nine Months Ended


September 30,


September 30,


2015


2014


2015


2014


(Millions of dollars, except per unit and coverage ratio amounts)









Net income attributable to ONEOK Partners (a)

$

227.0



$

167.2



$

582.3



$

647.1


Net income per limited partner unit (a)

$

0.45



$

0.32



$

1.10



$

1.65


Adjusted EBITDA (b)

$

403.7



$

388.6



$

1,115.3



$

1,143.2


DCF (b)

$

302.8



$

293.3



$

796.9



$

863.5


Cash distribution coverage ratio (b)

0.91



1.05



0.80



1.11


(a) Amounts include a noncash impairment charge of $76.4 million, or 31 cents per unit, in the natural gas gathering and processing segment for the three and nine months ended Sept. 30, 2014.

(b) Adjusted earnings before interest, taxes, depreciation and amortization (adjusted EBITDA); distributable cash flow (DCF); and cash distribution coverage ratio are non-GAAP measures. Reconciliations to relevant GAAP measures are attached to this news release.

 

"Earnings growth continued in the third quarter as natural gas liquids (NGL) and natural gas volumes increased in our highest-margin areas, despite unplanned operational outages in the Williston Basin and minor timing delays in well completions in the Mid-Continent," said Terry K. Spencer, president and chief executive officer of ONEOK Partners.

"We expect NGL volumes to continue to increase as a result of seven third-party natural gas processing plant connections made to our system this year. New connections in the Rocky Mountain region have contributed to the Bakken NGL Pipeline reaching 111,000 barrels per day in September," said Spencer. "We also expect natural gas volumes to continue to increase significantly as our Williston Basin natural gas processing plants reached full capacity and our natural gas gathered volumes reached 685 million cubic feet per day (MMcf/d) in September. Our new 200 MMcf/d Lonesome Creek natural gas processing plant, expected to be completed by the end of November, and three additional compressor stations that are expected to be completed in the fourth quarter, will provide incremental capacity to support the volume growth in the basin. Additionally, we've connected more than 720 new wells through the third quarter, and we expect to connect approximately 825 wells by the end of 2015.

"The unplanned operational outages in the Williston Basin, which have been resolved, impacted the partnership's third quarter results by approximately $16 million in the natural gas gathering and processing and natural gas liquids segments combined," said Spencer.

"We continue to take important steps to increase fee-based earnings in all three of our business segments," added Spencer. "Within the last year, we've announced new, largely fee-based investments in our natural gas liquids and natural gas pipelines segments, including the acquisition of the West Texas LPG pipeline system, the construction of the Roadrunner Gas Transmission pipeline and the expansion of the WesTex Transmission Pipeline system.

"In the natural gas gathering and processing segment, we have successfully converted a portion of our percent-of-proceeds contracts to largely fee-based contracts, resulting in a nearly 20 percent increase in the average fee collected in the third quarter compared with a year ago. We expect this rate to increase significantly into 2016, and we expect to greatly reduce our commodity exposure and increase margins," continued Spencer. "We also expect our percentage of fee-based margin in the natural gas gathering and processing segment to increase to more than 70 percent in 2016 from approximately 50 percent currently. We will continue to actively pursue opportunities to work with producer customers to increase the fee component in our agreements and expect to be substantially complete with these efforts in the Williston Basin by the end of the year."

THIRD-QUARTER AND YEAR-TO-DATE 2015 FINANCIAL PERFORMANCE

Third-quarter 2015 results were impacted positively by higher NGL volumes and natural gas gathered volumes, compared with the third quarter 2014, but were impacted negatively by low commodity prices and unplanned operational outages in the natural gas gathering and processing segment.


Three Months Ended


Nine Months Ended


September 30,


September 30,


2015


2014


2015


2014


(Millions of dollars)









Operating income

$

287.6



$

293.0



$

756.2



$

848.0


Operating costs

$

162.1



$

170.8



$

506.9



$

481.5


Depreciation and amortization

$

87.5



$

73.9



$

259.5



$

212.1


Equity in net earnings (loss) from investments

$

32.2



$

(52.3)



$

93.2



$

6.7


Capital expenditures

$

300.5



$

380.5



$

928.9



$

1,173.0


 

Third-quarter 2015 operating income reflects:

  • Lower net realized NGL, natural gas and condensate prices; offset partially by
  • Higher NGL exchange-services volumes from recently connected natural gas processing plants in the Williston Basin, Powder River Basin and Mid-Continent region;
  • Higher margins due to changes in contract mix resulting from higher fees in the natural gas gathering and processing segment; and
  • Higher NGL transportation margins, primarily from Permian Basin NGL volumes from the acquired West Texas LPG pipeline system.

Operating costs decreased in the third quarter 2015, compared with the same period last year, due primarily to higher scheduled maintenance and chemicals costs in the prior year, offset partially by increased employee costs from the growth of operations related to completed capital projects and acquisitions. Operating costs increased for the nine-month 2015 period, compared with the same period in 2014, due primarily to the growth of operations related to completed capital-growth projects and acquisitions.

Depreciation and amortization increased for the three- and nine-month 2015 periods, compared with the same periods in 2014, due primarily to the growth of operations related to completed capital-growth projects and acquisitions.

Equity in net earnings from investments in the three- and nine-month 2015 periods increased, compared with the same periods in 2014, due primarily to a $76.4 million noncash impairment charge in the third quarter 2014, related to an equity investment in Bighorn Gas Gathering, and higher volumes delivered to the Overland Pass Pipeline from the Bakken NGL Pipeline.

THIRD-QUARTER 2015 EARNINGS PRESENTATION AND KEY STATISTICS:

Additional financial and operating information that will be discussed on the third-quarter 2015 conference call is accessible on ONEOK Partners' website, www.oneokpartners.com, or by selecting the links below.

> View earnings presentation

> View earnings tables

ONEOK PARTNERS HIGHLIGHTS:

  • Reaffirming its 2015 adjusted EBITDA guidance range of $1.51 billion to $1.73 billion; its DCF guidance range of $1.08 billion to $1.26 billion; and its net income guidance range of $845 million to $1.01 billion provided on Feb. 23, 2015;
  • Reaffirming the expectation to exceed a 1.0 times distribution coverage in 2016;
  • Receiving the Presidential Permit and authorization for the Roadrunner Gas Transmission pipeline project (Roadrunner), a 50-50 joint venture with a subsidiary of Fermaca Infrastructure B.V. The Presidential Permit and authorization allows for the construction and operation of border-crossing facilities for the export of natural gas between a point near San Elizario, Texas, and near San Isidro, Chihuahua, Mexico. The Roadrunner project was announced in April 2015 and includes approximately 200 miles of 30-inch diameter pipeline currently designed to transport up to 640 MMcf/d of natural gas, with up to 570 MMcf/d to be transported to Mexico.
  • Connecting another third-party natural gas processing plant to the partnership's NGL system located in the Mid-Continent region;
  • Connecting to another compressor station with 15,000 horsepower in the Williston Basin located in southern Williams County, North Dakota;
  • Raising net proceeds of approximately $749 million in August, through a private placement of 21.5 million common units to ONEOK and a registered direct offering of 3.3 million common units to funds managed by Kayne Anderson Capital Advisors, L.P. ONEOK also contributed approximately $15.3 million to maintain its 2 percent general partner interest. ONEOK's aggregate ownership interest in ONEOK Partners increased to 41.2 percent, as of Sept. 30, 2015, from 36.8 percent at June 30, 2015; and
  • Declaring in October 2015 a third-quarter 2015 distribution of 79 cents per unit, or $3.16 per unit on an annualized basis, a 2 percent increase compared with the third quarter 2014.

BUSINESS-SEGMENT RESULTS:

Key financial and operating statistics are listed in the tables.

Natural Gas Liquids Segment

The natural gas liquids segment benefited from volume growth of NGLs gathered and fractionated during the third quarter 2015 and through the first nine months of the year. NGLs transported on gathering lines increased approximately 49 percent for each period compared with 2014, primarily due to Permian Basin volumes transported on the acquired West Texas LPG pipeline system. Recently connected natural gas processing plants across ONEOK Partners' system, including one new third-party plant connected in the third quarter, and decreased ethane rejection in the Rocky Mountain region also contributed to volume growth. NGLs fractionated increased 7 and 5 percent in the three- and nine-month periods in 2015, respectively, compared with the same periods in 2014.


Three Months Ended


Nine Months Ended


September 30,


September 30,


2015


2014


2015


2014


(Millions of dollars)









Operating income

$

207.5



$

173.8



$

549.6



$

509.5


Operating costs

$

74.5



$

77.0



$

234.1



$

218.2


Depreciation and amortization

$

39.3



$

31.7



$

118.1



$

89.8


Equity in net earnings from investments

$

10.9



$

4.4



$

27.6



$

13.6


 

The increase in third-quarter 2015 operating income, compared with the third quarter 2014, primarily reflects:

  • A $27.5 million increase in exchange-services margins, resulting primarily from increased volumes from recently connected natural gas processing plants in the Williston Basin, Powder River Basin and Mid-Continent region, offset partially by unplanned operational outages at the partnership's natural gas processing plants in the Williston Basin;
  • A $26.1 million increase in transportation margins, primarily from Permian Basin NGL volumes from the acquired West Texas LPG pipeline system; and
  • A $12.5 million increase related to decreased ethane rejection in the Williston Basin, offset partially by higher ethane rejection in the Mid-Continent region; offset partially by
  • A $17.2 million decrease in optimization and marketing margins; and
  • A $6.2 million decrease related to lower isomerization volumes, resulting from the narrower NGL product price differentials between normal butane and iso-butane.

The increase in operating income for the nine-month 2015 period, compared with the same period last year, primarily reflects:

  • A $149.7 million increase in exchange-services margins, resulting primarily from increased volumes from recently connected natural gas processing plants, higher fees for exchange-services activities resulting from contract renegotiations, and higher revenues from minimum volume obligations, offset partially by unplanned operational outages at the partnership's natural gas processing plants in the Williston Basin during the third quarter 2015; and
  • A $67.1 million increase in transportation margins, primarily from higher volumes on the acquired West Texas LPG pipeline system; offset partially by
  • A $100.2 million decrease in optimization and marketing margins related primarily to the increased demand for propane experienced during the first quarter 2014; and
  • A $26.6 million decrease related to lower isomerization volumes.

Operating costs decreased for the third quarter 2015, compared with the same period in 2014, due primarily to decreased outside services expense and miscellaneous supplies and expenses due primarily to scheduled maintenance in the prior year.

Operating costs increased in the nine-month 2015 period, compared with the same period in 2014, due primarily to the completion of capital-growth projects and acquisitions.

Depreciation and amortization expense increased for the three- and nine-month periods, compared with the same periods in 2014, due to depreciation associated with completed capital-growth projects, including acquisitions.

Equity in net earnings from investments increased in the three- and nine-month 2015 periods, compared with the same periods in 2014, due primarily to higher volumes delivered to the Overland Pass Pipeline from the Bakken NGL Pipeline.

Natural Gas Pipelines Segment

The natural gas pipelines segment experienced fairly normal operating conditions during the third quarter 2015. Variances in financial performance between the nine-month 2015 period and the same period in 2014 were primarily a reflection of significantly higher weather-related seasonal demand resulting in higher natural gas prices during the first quarter 2014.


Three Months Ended


Nine Months Ended


September 30,


September 30,


2015


2014


2015


2014


(Millions of dollars)









Operating income

$

37.7



$

36.2



$

106.9



$

128.7


Operating costs

$

26.7



$

28.0



$

79.1



$

82.8


Depreciation and amortization

$

10.9



$

10.9



$

32.5



$

32.6


Equity in net earnings from investments

$

17.0



$

14.4



$

52.1



$

53.7


 

Operating income increased for the third quarter 2015, compared with the same period in 2014, which primarily reflects:

  • A $1.3 million increase due to higher storage revenues from increased rates; and
  • A $1.2 million increase from higher transportation revenues, primarily from higher rates at Viking Gas Transmission Company.

The decrease in operating income for the nine-month 2015 period, compared with the same period in 2014, primarily reflects:

  • A $12.6 million decrease from lower short-term natural gas storage services, due primarily to increased weather-related seasonal demand associated with severely cold weather in the first quarter 2014; and
  • A $9.4 million decrease from lower net retained fuel due to lower natural gas prices and lower natural gas volumes retained; offset partially by
  • A $5.8 million increase due to higher transportation revenues, primarily from increased rates on intrastate pipelines and higher rates at Viking Gas Transmission Company.

Operating costs decreased for the three- and nine-month 2015 periods, compared with the same periods in 2014, primarily as a result of lower costs for materials and supplies.

Equity in net earnings from investments increased for the three-month 2015 period, compared with the same period in 2014, due primarily to an increase in firm transportation on Northern Border Pipeline.

Equity in net earnings from investments decreased for the nine-month 2015 period, compared with the same period in 2014, due primarily to decreased natural gas park-and-loan services on Northern Border Pipeline, resulting from increased weather-related seasonal demand due to severely cold weather in the first quarter 2014, offset partially by an increase in firm transportation.

Natural Gas Gathering and Processing Segment

The natural gas gathering and processing segment's third-quarter and year-to-date 2015 results benefited from additional natural gas compression projects completed in 2015 and natural gas processing plants completed in 2014. For the nine-month 2015 period, natural gas gathered volumes increased approximately 13 percent and natural gas processed volumes increased approximately 12 percent, compared with the same period in 2014. Third-quarter natural gas volumes gathered increased slightly and natural gas volumes processed decreased slightly due to unplanned operational outages in the Williston Basin, which have been resolved, and minor timing delays in well completions in the Mid-Continent region.

Through the first nine months of 2015, the segment successfully restructured many of its percent-of-proceeds contracts to largely fee-based contracts and continues to actively work with its producer customers to similarly restructure additional contracts. Due to successful contract restructuring, the segment's third-quarter 2015 average fee rate increased nearly 20 percent, compared with the same period in 2014. The partnership expects the contract restructuring efforts in the Williston Basin to be substantially complete by the end of 2015 and to receive the benefit from improved margins in 2016. As a result, the segment's fee-based margin is expected to increase to more than 70 percent in 2016, compared with approximately 50 percent in 2015.

 


Three Months Ended


Nine Months Ended


September 30,


September 30,


2015


2014


2015


2014


(Millions of dollars)









Operating income

$

42.3



$

82.9



$

99.9



$

208.9


Operating costs

$

61.2



$

64.3



$

193.9



$

188.5


Depreciation and amortization

$

37.3



$

31.3



$

109.0



$

89.6


Equity in net earnings (loss) from investments

$

4.4



$

(71.1)



$

13.5



$

(60.5)


 

Third-quarter 2015 operating income, compared with the third quarter 2014, primarily reflects:

  • A $53.9 million decrease due primarily to lower net realized NGL, natural gas and condensate prices; and
  • A $7.0 million decrease due primarily to unplanned operational outages in the Williston Basin and decreased natural gas processed volumes in the Cana-Woodford Shale, offset partially by natural gas volume growth in the Williston Basin; offset partially by
  • A $27.1 million increase due primarily to changes in contract mix resulting from higher fees.

Operating income for the nine-month 2015 period decreased, compared with the same period last year, which primarily reflects:

  • A $153.3 million decrease due primarily to lower net realized NGL, natural gas and condensate prices; offset partially by
  • A $47.9 million increase due primarily to changes in contract mix resulting from higher fees; and
  • A $25.8 million increase due primarily to natural gas volume growth in the Williston Basin, offset partially by unplanned operational outages in the Williston Basin and decreased natural gas volumes in the Cana-Woodford Shale.

Operating costs decreased in the third quarter 2015 but increased overall through the first nine months of 2015, compared with the same periods in 2014. The decrease in the third quarter 2015 was due primarily to lower materials and supply costs due primarily to higher chemicals costs in the prior year. The increase in the nine-month 2015 period was due primarily to completed capital-growth projects.

Depreciation and amortization expense increased in the three- and nine-month 2015 periods, compared with the same periods in 2014, due primarily to completed capital-growth projects.

Equity in net earnings from investments increased for the three- and nine-month 2015 periods, compared with the same periods in 2014, due to a $76.4 million noncash impairment charge in the third quarter 2014 related to ONEOK Partners' equity investment in the Bighorn Gas Gathering system in the Powder River Basin.

The following table contains equity-volume information for the periods indicated:


Three Months Ended


Nine Months Ended


September 30,


September 30,

Equity-Volume Information (a)

2015


2014


2015


2014









NGL sales (MBbl/d)

24.9



16.0



21.0



16.6


Condensate sales (MBbl/d)

2.7



2.6



3.0



3.1


Residue natural gas sales (BBtu/d)

136.3



134.5



141.6



109.6


(a) - Includes volumes for consolidated entities only.








 

The natural gas gathering and processing segment is exposed to commodity price risk as a result of percent-of-proceeds contracts, where the segment receives a percentage of volumes processed, or equity volumes, in exchange for services. ONEOK Partners expects NGLs, natural gas and crude oil commodity price sensitivity in the gathering and processing segment to decrease in 2016 as additional contracts are restructured to include higher fee-based components.

The partnership executes hedges to mitigate its commodity price risk. The tables below provide hedging information as of October 2015 for equity volumes in the natural gas gathering and processing segment in the periods indicated. NGLs hedged reflect propane, normal butane, iso-butane and natural gasoline only. The ethane component of the natural gas gathering and processing segment's equity NGL volume is not expected to significantly impact the results of operations.

2016 natural gas equity volumes are expected to be lower due to restructuring a significant portion of the segments' percent-of-proceed contracts. As a result, natural gas volumes hedged were realigned to reflect lower natural gas equity volumes expected in 2016.

 


Three Months Ending December 31, 2015


Volumes
Hedged


Average Price


Percentage
Hedged

NGLs - excluding ethane (MBbl/d) - Conway/Mont Belvieu

13.6



$

0.64


/ gallon


84%

Condensate (MBbl/d) - WTI-NYMEX

2.6



$

54.69


/ Bbl


96%

Natural gas (BBtu/d) - NYMEX and basis

122.8



$

3.64


/ MMBtu


97%

 


Year Ending December 31, 2016


Volumes
Hedged


Average Price


Percentage
Hedged

NGLs - excluding ethane (MBbl/d) - Conway/Mont Belvieu

4.9



$

0.54


/ gallon


49%

Condensate (MBbl/d) - WTI-NYMEX

1.5



$

62.65


/ Bbl


48%

Natural gas (BBtu/d) - NYMEX and basis

74.1



$

2.96


/ MMBtu


83%

 

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 Sept. 30, 2015, 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 for the three months ending Dec. 31, 2015:

  • A 10-cent-per-MMBtu change in the price of residue natural gas would change three-month net margin by approximately $1.2 million;
  • A 1-cent-per-gallon change in the composite price of NGLs would change three-month net margin by approximately $0.8 million; and
  • A $1.00-per-barrel change in the price of crude oil would change three-month net margin by approximately $0.3 million.

The natural gas gathering and processing segment estimates the following sensitivities for the year ending Dec. 31, 2016:

  • A 10-cent-per-MMBtu change in the price of residue natural gas would change 12-month net margin by approximately $3.3 million;
  • A 1-cent-per-gallon change in the composite price of NGLs would change 12-month net margin by approximately $1.8 million; and
  • A $1.00-per-barrel change in the price of crude oil would change 12-month 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 affecting natural gas gathering and processing margins for certain contracts.

GROWTH ACTIVITIES:

The natural gas liquids segment completed the following projects in 2014 and 2015:

Completed Projects

Location

Capacity

Approximate Costs (a)

Completion Date




(In millions)


Ethane/Propane Splitter

Texas Gulf Coast

40 MBbl/d

$46

March 2014

Sterling III Pipeline and reconfigure Sterling I and II

Mid-Continent Region

193 MBbl/d

$808

March 2014

Bakken NGL Pipeline expansion - Phase I

Rocky Mountain Region

75 MBbl/d

$90

September 2014

Niobrara NGL Lateral

Powder River Basin

90 miles

$65

September 2014

West Texas LPG pipeline system (b)

Permian Basin

2,600 miles

$800

November 2014

MB-3 Fractionator

Texas Gulf Coast

75 MBbl/d

$520-$540

December 2014

NGL Pipeline and Hutchinson Fractionator infrastructure

Mid-Continent Region

95 miles

$115-$120

April 2015

(a) Excludes AFUDC.

(b) Acquisition.

 

The partnership has announced approximately $190 million to $220 million of capital-growth projects in the natural gas liquids segment, which include the following:

Projects in Progress

Location

Capacity

Approximate

 Costs (a)

Expected Completion Date




(In millions)


Bakken NGL Pipeline expansion - Phase II

Rocky Mountain Region

25 MBbl/d

$100

Third quarter 2016

Bear Creek NGL infrastructure

Williston Basin

40 miles

$35-$45

Third quarter 2016

Bronco NGL infrastructure

Powder River Basin

65 miles

$45-$60

Suspended

Demicks Lake NGL infrastructure

Williston Basin

12 miles

$10-$15

Suspended

(a) 

Excludes AFUDC.

 

The partnership has announced approximately $520 million to $600 million of projects in the natural gas pipelines segment, which include the Roadrunner Gas Transmission pipeline system, a 50 percent-owned joint venture equity method investment project and the WesTex Transmission Pipeline expansion, a wholly owned project.

Projects in Progress

Location

Capacity

Approximate

 Costs (a)

Expected Completion Date




(In millions)


WesTex Transmission Pipeline expansion

Permian Basin

260 MMcf/d

$70-$100

First quarter 2017

Roadrunner Gas Transmission Pipeline - Phases I, II, III (b)

Permian Basin

640 MMcf/d

$450-$500

Various

-Phase I

Permian Basin

170 MMcf/d

$200-$220

First quarter 2016

-Phase II

Permian Basin

400 MMcf/d

$220-$240

First quarter 2017

-Phase III

Permian Basin

70 MMcf/d

$30-$40

2019

(a)

Excludes AFUDC.

(b) 

50-50 joint venture. Approximate costs represent total project costs.

 

The natural gas gathering and processing segment completed the following projects in 2014:

Completed Projects

Location

Capacity

Approximate

Costs (a)

Completion Date




(In millions)


Rocky Mountain Region



Garden Creek II processing plant and infrastructure

Williston Basin

100 MMcf/d

$310

August 2014

Garden Creek III processing plant and infrastructure

Williston Basin

100 MMcf/d

$310

October 2014

Mid-Continent Region





Canadian Valley processing plant and infrastructure

Cana-Woodford Shale

200 MMcf/d

$255

March 2014

(a)

Excludes AFUDC.

 

The partnership has announced approximately $1.8 billion to $2.6 billion of capital-growth projects in the natural gas gathering and processing segment, which include the following:

Projects in Progress

Location

Capacity

Approximate

Costs (a)

Expected

Completion Date




(In millions)


Rocky Mountain Region



Lonesome Creek processing plant and infrastructure

Williston Basin

200 MMcf/d

$550-$680

November 2015

Sage Creek infrastructure

Powder River Basin

Various

$35

Fourth quarter 2015

Natural gas compression

Williston Basin

100 MMcf/d

$80-$90

Fourth quarter 2015

Stateline de-ethanizers

Williston Basin

26 MBbl/d

$60-$80

Third quarter 2016

Bear Creek processing plant and infrastructure

Williston Basin

80 MMcf/d

$230-$330

Third quarter 2016

Bronco processing plant and infrastructure

Powder River Basin

50 MMcf/d

$130-$200

Suspended

Demicks Lake processing plant and infrastructure

Williston Basin

200 MMcf/d

$475-$670

Suspended

Mid-Continent Region





Knox processing plant and infrastructure

SCOOP

200 MMcf/d

$240-$470

Suspended

(a)

 Excludes AFUDC.

 

EARNINGS CONFERENCE CALL AND WEBCAST:

ONEOK Partners and ONEOK executive management will conduct a joint conference call at 11 a.m. Eastern Standard Time (10 a.m. Central Standard Time) on Wednesday, Nov. 4, 2015. The call also will be carried live on ONEOK Partners' and ONEOK's websites.

To participate in the telephone conference call, dial 888-505-4368, pass-code 1733240, 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 1733240.

LINKS TO EARNINGS TABLES AND PRESENTATION:

Tables:
http://www.oneokpartners.com/~/media/ONEOKPartners/EarningsTables/2015/OKS_Q3_2015_earningsDNw83M.ashx 

Presentation:
http://www.oneok.com/~/media/ONEOK/EarningsTables/2015/OKE_OKS_Q3_2015_EarningsPresentationYnF05s4.ashx

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

ONEOK Partners has disclosed in this news release adjusted EBITDA, DCF, distributable cash flow to limited partners per limited partner unit and cash distribution coverage ratio, which are non-GAAP financial metrics, used to measure the partnership's financial performance and are defined as follows:

  • Adjusted EBITDA is defined as net income adjusted for interest expense, depreciation and amortization, income taxes and allowance for equity funds used during construction and certain other items;
  • DCF is defined as adjusted 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;
  • 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; and
  • Cash distribution 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.

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.

Adjusted EBITDA, DCF, distributable cash flow to limited partners and cash distribution coverage ratio per limited partner unit 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 owns one of the nation's premier natural gas liquids (NGL) systems, connecting NGL supply in the Mid-Continent, Permian and Rocky Mountain regions with key market centers and is a leader in the gathering, processing, storage and transportation of natural gas in the U.S. 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 Sept. 30, 2015.

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 as defined under federal securities laws.  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 federal securities legislation and other applicable laws.  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.  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, railroads or pipelines in delivering products to or from our terminals or pipelines;
  • changes in demand for the use of natural gas, NGLs and crude oil because of market conditions caused by concerns about climate change;
  • 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 any local, state or federal regulatory body, including the FERC, the National Transportation Safety Board, the PHMSA, the EPA and 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 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 our most recent Annual Report and in our other filings that we make with the Securities and Exchange Commission (SEC), which are available on the SEC's website at www.sec.gov and our website at www.oneokpartners.com.  All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors.  Any such forward-looking statement speaks only as of the date on which such statement is made, and, 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

 

 

To view the original version on PR Newswire, visit:http://www.prnewswire.com/news-releases/oneok-partners-announces-third-quarter-2015-results-300171658.html

SOURCE ONEOK Partners, L.P.


Source: PR Newswire (November 3, 2015 - 4:39 PM EST)

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