ONEOK, INC.. 
By TULSA, Okla., Nov. 5, 2013 /PRNewswire/ -- ONEOK Partners, L.P. (NYSE: OKS) today announced third-quarter 2013 net income attributable to ONEOK Partners of $216.3 million, or 64 cents per unit, compared with $232.3 million, or 78 cents per unit, in the third quarter 2012. Earnings before interest, taxes, depreciation and amortization (EBITDA) were $331.9 million in the third quarter 2013, compared with $329.2 million in the third quarter 2012.
The partnership also updated its 2013 net income guidance range to $790 million to $830 million, compared with the previous guidance range of $790 million to $870 million, reflecting lower anticipated earnings in the partnership's natural gas liquids segment due to narrower natural gas liquids (NGL) location price differentials. The partnership's distributable cash flow (DCF) is expected to be in the range of $930 million to $980 million, compared with the previous guidance range of $910 million to $1.0 billion.
Third-quarter 2013 results reflect higher natural gas volumes gathered and processed, and natural gas liquids gathered as a result of recently completed growth projects. NGL exchange-services margins continued to increase, while NGL optimization margins decreased as a result of narrower NGL location price differentials and ONEOK Partners' strategy to convert NGL optimization capacity to fee-based exchange-services capacity.
"Our natural gas gathering and processing, and natural gas liquids segments continued to benefit from volume growth in the third quarter due primarily to completed growth projects and increased well connections in the Williston Basin," said John W. Gibson, chairman and chief executive officer of ONEOK Partners. "We expect continued volume growth across our operations as we execute our $5.3 billion to $5.6 billion capital-growth program through 2015, which includes our recently announced acquisition of the Sage Creek natural gas processing plant and related investments in the NGL-rich area of the Powder River Basin.
"As expected, continued lower NGL prices, narrower location price differentials and ethane rejection adversely affected our natural gas liquids segment," Gibson added. "While we anticipate ethane rejection will continue through 2015 - although at lower levels than we're currently experiencing - we expect that new NGL supply commitments will provide incremental volumes over the next two years to help offset the impact on our natural gas liquids segment."
Third-quarter 2013 DCF was $259.1 million, providing 1.14 times coverage of the cash distributions that will be paid on Nov. 14, 2013, to unitholders of record on Nov. 4, 2013, compared with third quarter 2012 DCF of $261.4 million that provided 1.34 times coverage. DCF for the first nine months of 2013 was $704.2 million, providing 1.04 times coverage, compared with $780.7 million for the same period last year that provided 1.45 times coverage.
Year-to-date net income attributable to ONEOK Partners was $575.3 million, or $1.68 per unit, compared with $677.6 million, or $2.38 per unit, for the same period last year. Year-to-date 2013 EBITDA was $907.4 million, compared with $979.3 million in the same period last year.
THIRD-QUARTER AND YEAR-TO-DATE 2013 FINANCIAL PERFORMANCE
Third-quarter 2013 operating income was $240.1 million, compared with $248.4 million in the third quarter 2012.
In the third quarter 2013, 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 were offset by:
-- Significantly narrower NGL location price differentials;
-- Lower realized natural gas and NGL product prices;
-- Lower NGL volumes as a result of ethane rejection; and
-- Increased depreciation and amortization expense from the completed
growth projects.
Operating income for the first nine months of 2013 was $647.8 million, compared with $732.5 million for the same period last year.
The decrease in operating income for the nine-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.
Third-quarter 2013 equity earnings were $27.5 million, compared with $28.6 million in the third quarter 2012. Year-to-date 2013 equity earnings were $79.7 million, compared with $92.4 million for the same period last year. These decreases in equity earnings in the three- and nine-month 2013 periods were due to the impact of decreased transportation rates on Northern Border Pipeline and lower NGL volumes on Overland Pass Pipeline due to ethane rejection.
Operating costs were $122.4 million in the third quarter 2013, compared with $121.2 million for the same period last year. Operating costs for the nine-month 2013 period were $384.6 million, compared with $360.4 million for the same period last year. The increase for the nine-month 2013 period is a result of the growth in the partnership's operations.
Depreciation and amortization expense was $61.2 million in the third quarter 2013, compared with $49.8 million for the same period last year. Depreciation and amortization expense for the first nine months of 2013 was $174.1 million, compared with $150.0 million for the same period last year. These increases for the three- and nine-month 2013 periods were due primarily to the partnership's completed growth projects.
Capital expenditures were $449.1 million in the third quarter 2013, compared with $375.3 million for the same period in 2012. Year-to-date 2013 capital expenditures were approximately $1.4 billion, compared with $1.0 billion 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.
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THIRD-QUARTER 2013 SUMMARY:
-- Natural gas gathering and processing segment operating income of $58.5
million, compared with $57.0 million in the third quarter 2012;
-- Natural gas liquids segment operating income of $146.2 million, compared
with $158.8 million in the third quarter 2012;
-- Natural gas pipelines segment operating income of $35.2 million,
compared with $33.5 million in the third quarter 2012;
-- Completing in August 2013 a public offering of 11.5 million common units
generating net proceeds of approximately $553.4 million;
-- Completing in September 2013 a $1.25 billion public offering of senior
notes, consisting of $425 million of five-year senior notes at 3.2
percent; $425 million of 10-year senior notes at 5.0 percent; and $400
million of 30-year senior notes at 6.2 percent, generating net proceeds
of approximately $1.24 billion;
-- Increasing investments in its 2010 to 2015 growth program to a range of
$5.3 billion to $5.6 billion by:
-- Completing in September 2013 the acquisition of a 50-million cubic
feet per day (MMcf/d) natural gas processing facility - the Sage
Creek plant and related natural gas gathering and NGL infrastructure
- in Converse and Campbell Counties, Wyo., for $305 million; and
-- Announcing an investment of $135 million in the Sage Creek assets to
upgrade and construct natural gas gathering and processing related
infrastructure, construct new NGL pipeline infrastructure and
connect the Sage Creek natural gas processing plant to the
partnership's Bakken NGL Pipeline;
-- Having $723.0 million of cash and cash equivalents and $47.0 million in
commercial paper outstanding and no borrowings outstanding under the
partnership's $1.2 billion revolving credit facility as of Sept. 30,
2013; and
-- Increasing in October 2013 its third-quarter distribution to 72.5 cents
per unit, or $2.90 per unit on an annualized basis, payable on Nov. 14,
2013, to unitholders of record at the close of business Nov. 4, 2013.
BUSINESS-UNIT RESULTS:
Natural Gas Gathering and Processing Segment
The natural gas gathering and processing segment reported third-quarter 2013 operating income of $58.5 million, compared with operating income of $57.0 million for the third quarter 2012, which reflects:
-- A $21.1 million increase due primarily to volume growth in the Williston
Basin from the Stateline I and Stateline II natural gas processing
plants and increased well connections, which resulted in higher natural
gas volumes gathered, compressed, processed, transported and sold;
-- A $4.3 million decrease due primarily to lower realized NGL product
prices;
-- A $1.8 million decrease due to changes in contract mix and terms
associated with volume growth; and
-- A $13.5 million increase in operating costs and depreciation and
amortization expense.
Operating income for the nine-month 2013 period was $147.7 million, compared with $151.3 million in the same period last year, which reflects:
-- A $66.0 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;
-- A $6.4 million increase due to a contract settlement;
-- A $25.8 million decrease due primarily to lower realized NGL product
prices;
-- An $8.3 million decrease due to changes in contract mix and terms
associated with volume growth;
-- A $2.8 million decrease from lower dry natural gas volumes gathered in
the Powder River Basin as a result of continued production declines; and
-- A $35.9 million increase in operating costs and depreciation and
amortization expense.
Operating costs in the third quarter 2013 were $45.1 million, compared with $39.4 million for the third quarter 2012. Third-quarter 2013 operating costs, compared with operating costs in the same period 2012, reflect:
-- A $4.7 million increase due to higher materials, supplies and outside
services expenses; and
-- A $1.0 million increase due to higher labor and employee benefit costs,
offset partially by other employee-related expenses.
Operating costs for the nine-month 2013 period were $141.7 million, compared with $120.9 million for the same period last year. Nine-month 2013 operating costs, compared with operating costs in the same period 2012, reflect:
-- A $10.4 million increase due to higher materials, supplies and outside
services expenses;
-- A $6.6 million increase due to higher labor and employee benefit costs,
offset partially by other employee-related expenses; and
-- A $2.1 million increase from higher property taxes.
Depreciation and amortization expense for the three-month 2013 period was $27.4 million, compared with $19.6 million for the same period last year. Depreciation and amortization expense for the nine-month 2013 period was $76.4 million, compared with $61.3 million for the same period last year. These increases were due to the completion of the Stateline I and Stateline II natural gas processing plants, well connections and infrastructure projects, supporting the volume growth in the Williston Basin.
Key Statistics: More detailed information is listed on page 22 in the tables.
-- Natural gas gathered was 1,389 billion British thermal units per day
(BBtu/d) in the third quarter 2013, up 21 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; including its Divide County gathering
system, to support the Stateline I and Stateline II natural gas
processing plants in the Williston Basin, offset partially by continued
dry natural gas production declines in the Powder River Basin in
Wyoming; and up 5 percent compared with the second quarter 2013;
-- Natural gas processed was 1,135 BBtu/d in the third quarter 2013, up 25
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, including its Divide County gathering
system; and up 8 percent compared with the second quarter 2013;
-- NGL sales were 83,000 barrels per day (bpd) in the third quarter 2013,
up 34 percent compared with the same period last year due to the
completion of the Stateline I and Stateline II natural gas processing
plants in the Williston Basin; and up 11 percent compared with the
second quarter 2013;
-- The realized composite NGL net sales price was 90 cents per gallon in
the third quarter 2013, down 18 percent compared with the same period
last year; and up 6 percent compared with the second quarter 2013;
-- The realized condensate net sales price was $90.68 per barrel in the
third quarter 2013, up 5 percent compared with the same period last
year; and up 8 percent compared with the second quarter 2013; and
-- The realized residue natural gas net sales price was $3.36 per million
British thermal units (MMBtu) in the third quarter 2013, down 9 percent
compared with the same period last year; and down 6 percent compared
with the second quarter 2013.
The natural gas gathering and processing segment's quantity and composition of natural gas liquids and natural gas volumes continue to change as new natural gas processing plants in the Williston Basin are placed into service. The Garden Creek, Stateline I and Stateline II natural gas processing plants have the capability to recover ethane when economic conditions warrant but did not recover ethane during the first nine months of 2013. As a result, the partnership's equity NGL volumes were weighted less toward ethane and more toward propane, iso-butane, normal butane and natural gasoline, compared with the same period in the previous year.
For the third-quarter 2013, the segment connected approximately 340 new wells, compared with approximately 280 wells for the same period in 2012. For the first nine months of 2013, the segment connected approximately 950 new wells, compared with approximately 710 wells for the same period in 2012. The partnership expects to connect approximately 1,200 wells in 2013.
The following table contains operating information for the periods indicated:
Three Months Ended Nine Months Ended
September 30, September 30,
Operating
Information
(a) (d) 2013 2012 2013 2012
------------ ---- ---- ---- ----
Commodity
NGL sales
(Bbl/d)
(b) 14,621 11,487 13,827 11,097
Residue gas
sales
(MMBtu/d)
(c) 76,801 54,435 67,722 46,636
Condensate
sales (Bbl/
d) (b) 2,018 2,025 2,373 2,401
Percentage
of total
net margin 66% 70% 65% 69%
Fee-based
Wellhead
volumes
(MMBtu/d) 1,389,485 1,149,072 1,310,734 1,091,063
Average rate
($/MMBtu) $0.35 $0.34 $0.35 $0.35
Percentage
of total
net margin 34% 30% 35% 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 two 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:
Three Months Ending December
31, 2013
-----------------------------
Volumes Average
Price Percentage
Hedged Hedged
------ ------
NGLs (Bbl/d) 9,034 $1.11 / gallon 61%
Condensate (Bbl/
d) 2,213 $2.41 / gallon 80%
---------------- ----- --- -------- ---
Total (Bbl/d) 11,247 $1.37 / gallon 64%
============= ====== === ======== ===
Natural gas
(MMBtu/d) 68,315 $3.90 / MMBtu 75%
----------- ------ --- ------- ---
Year Ending December 31, 2014
-----------------------------
Volumes Average
Price Percentage
Hedged Hedged
------ ------
NGLs (Bbl/d) 1,475 $1.37 / gallon 11%
Condensate (Bbl/
d) 2,233 $2.24 / gallon 66%
---------------- ----- --- -------- ---
Total (Bbl/d) 3,708 $1.89 / gallon 22%
============= ===== === ======== ===
Natural gas
(MMBtu/d) 69,274 $4.11 / MMBtu 63%
----------- ------ --- ------- ---
Year Ending December 31, 2015
-----------------------------
Volumes Average
Price Percentage
Hedged Hedged
------ ------
Natural gas
(MMBtu/d) 48,877 $4.19 / MMBtu 41%
----------- ------ --- ------- ---
The partnership expects its NGL and natural gas commodity-price sensitivities to increase in the future as its capital 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 Sept. 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 $2.0 million;
-- A $1.00-per-barrel change in the price of crude oil would change annual
net margin by approximately $1.3 million; and
-- A 10-cent-per-MMBtu change in the price of natural gas would change
annual net margin by approximately $3.7 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 Liquids Segment
The natural gas liquids segment reported third-quarter 2013 operating income of $146.2 million, compared with $158.8 million in the same period last year, which reflects:
-- A $35.0 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 $9.8 million increase in operational measurement gains of
approximately $2.8 million in the third quarter 2013, compared with
losses of approximately $7.0 million in the same period last year;
-- A $4.1 million increase in storage margins due primarily to contract
renegotiations;
-- A $42.3 million decrease in optimization and marketing margins,
primarily as a result of a $39.5 million decrease from significantly
narrower NGL location price differentials, offset partially by higher
transportation capacity available for optimization activities due to
ethane rejection, and a $17.8 million decrease in marketing margins,
offset partially by a $15.0 million increase due primarily to more
favorable NGL product price differentials. In the third quarter 2012,
the segment realized higher marketing margins on the sale of NGL
inventory held as a result of scheduled maintenance at its Mont Belvieu,
Texas, NGL fractionation facility;
-- An $8.0 million decrease from the impact of ethane rejection, which
resulted in lower NGL volumes;
-- A $6.9 million decrease from lower isomerization volumes, resulting from
narrower price differentials between normal butane and iso-butane; and
-- A $4.6 million increase in operating costs and depreciation and
amortization expense.
Operating income for the nine-month 2013 period was $396.0 million, compared with $482.4 million for the same period last year, which reflects:
-- A $124.6 million increase in exchange-services margins from higher NGL
volumes gathered, higher fees from contract renegotiations for its NGL
exchange-services activities and higher revenues from customers with
minimum volume obligations;
-- A $19.7 million increase due to the impact of operational measurement
gains of approximately $11.5 million in 2013, compared with losses of
approximately $8.2 million in the same period last year;
-- A $5.7 million increase in storage margins due primarily to contract
renegotiations;
-- A $173.8 million decrease in optimization and marketing margins,
primarily as a result of significantly narrower NGL location price
differentials;
-- A $32.0 million decrease from the impact of ethane rejection, which
resulted in lower NGL volumes;
-- A $15.8 million decrease from lower isomerization volumes, resulting
from the narrower price differential between normal butane and
iso-butane; and
-- A $15.3 million increase in operating costs and depreciation and
amortization expense.
Operating costs were $57.0 million in the third quarter 2013, compared with $56.8 million in the third quarter 2012, which reflect:
-- A $2.8 million increase due to higher property taxes related to
completed capital projects; and
-- A $1.7 million decrease due to other employee-related expenses, offset
partially by higher labor and employee benefit costs due to growth in
operations related to completed capital projects.
Operating costs for the nine-month 2013 period were $171.1 million, compared with $166.6 million for the same period last year, which reflect:
-- A $2.0 million increase due to higher labor and employee benefit costs
associated with the growth in operations related to completed capital
projects, offset partially by other lower employee-related expenses; and
-- A $3.6 million increase due to higher property taxes.
Depreciation and amortization expense for the three-month 2013 period was $23.0 million, compared with $18.6 million for the same period last year. Depreciation and amortization expense for the nine-month 2013 period was $65.0 million, compared with $54.2 million for the same period last year, due primarily to higher depreciation associated with completed capital projects.
Equity earnings from investments were $6.3 million in the third quarter 2013, compared with $4.7 million for the same period in 2012. Nine-month 2013 equity earnings from investments were $15.4 million, compared with $16.4 million for the same period last year.
The increase in equity earnings for the third-quarter 2013 period was due primarily to higher volumes delivered to the partnership's 50 percent-owned Overland Pass Pipeline from its Bakken NGL Pipeline, which was placed in service in April 2013, offset partially by reduced volumes as a result of ethane rejection.
The impact of ethane rejection decreased equity earnings $2.8 million and $10.7 million for the three- and nine-month 2013 periods, respectively, compared with the same periods last year.
Key Statistics: More detailed information is listed on page 22 in the tables.
-- NGLs transported on gathering lines were 574,000 bpd in the third
quarter 2013, up 8 percent compared with the same period last year, due
primarily to increased volumes from the Williston Basin made available
by the completed Bakken NGL Pipeline; and NGLs gathered as a result of
the capacity increase in the Mid-Continent and Texas made available
through the partnership's Cana-Woodford Shale and Granite Wash projects;
offset partially by decreases in NGL volumes gathered as a result of
ethane rejection; and up 4 percent compared with the second quarter 2013
;
-- NGLs fractionated were 557,000 bpd in the third quarter 2013, down 4
percent compared with the same period last year, due to lower volumes
from ethane rejection during 2013, offset partially by higher volumes
from the Williston Basin made available by the segment's completed
Bakken NGL Pipeline; and up 4 percent compared with the second quarter
2013;
-- NGLs transported on distribution lines were 454,000 bpd in the third
quarter 2013, down 10 percent compared with the same period last year,
due primarily to decreased volumes from ethane rejection; and up 5
percent compared with the second 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 4 cents per gallon in the third quarter 2013, compared with
16 cents per gallon in the same period last year; and 6 cents per gallon
in the second quarter 2013.
Natural Gas Pipelines Segment
The natural gas pipelines segment reported third-quarter 2013 operating income of $35.2 million, compared with $33.5 million for the third quarter 2012. Operating income for the nine-month 2013 period was $102.9 million, compared with $99.1 million for the same period last year. Third-quarter and year-to-date 2013 results reflect an increase of $1.8 million and $6.1 million, respectively, in transportation margins due primarily to higher rates on Guardian Pipeline and higher contracted capacity with natural gas producers on our intrastate pipelines.
Third-quarter 2013 equity earnings from investments, primarily from the partnership's 50 percent-owned Northern Border Pipeline, were $16.5 million, compared with $18.3 million in the same period in 2012. Nine-month 2013 equity earnings were $48.1 million, compared with $55.0 million in the same period last year.
These decreases in equity earnings for the third-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. Substantially all of Northern Border Pipeline's long-haul transportation capacity has been contracted through March 2015.
Key Statistics: More detailed information is listed on page 22 in the tables.
-- Natural gas transportation capacity contracted was 5,428 thousand
dekatherms per day in the third quarter 2013, up 3 percent compared with
the same period last year; and up 1 percent compared with the second
quarter 2013;
-- Natural gas transportation capacity subscribed was 89 percent in the
third quarter 2013, up 2 percent compared with the same period last
year; and up 1 percent compared with the second quarter 2013; and
-- The average natural gas price in the Mid-Continent region was $3.42 per
MMBtu in the third quarter 2013, up 24 percent compared with the same
period last year; and down 11 percent compared with the second quarter
2013.
GROWTH ACTIVITIES:
The partnership has announced approximately $5.3 billion to $5.6 billion in growth projects and acquisitions between 2010 and 2015, of which approximately $2.2 billion have been completed.
-- Of the approximately $2.4 billion to $2.5 billion of announced growth
projects and acquisitions in the natural gas gathering and processing
segment, projects totaling approximately $1.3 billion have 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;
-- 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; and
-- Approximately $305 million to acquire the Sage Creek plant, a 50
MMcf/d natural gas processing facility, and related natural gas
gathering and natural gas liquids infrastructure in the Powder River
Basin in Wyoming.
-- 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.,
that was placed in service in 2013. The remaining $20 million of
additional expansion of the system is expected to be completed by
year-end 2014. 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 Stateline I and Stateline II
plants, each with 100 MMcf/d of natural gas processing capacity 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;
-- Approximately $50 million to upgrade the recently acquired Sage
Creek natural gas processing plant, and construct natural gas
gathering and processing infrastructure through 2016; 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 approximately $2.9 billion to $3.1 billion of announced growth
projects and acquisitions in the natural gas liquids segment, projects
totaling approximately $900 million 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 $36 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 $2.0 billion to $2.2 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, which is
expected to be in service in November 2013;
-- Approximately $700 million to $800 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
its 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;
-- Approximately $85 for the construction of new NGL pipeline
infrastructure to connect the recently acquired Sage Creek natural
gas processing plant to the partnerships' Bakken NGL Pipeline, which
is expected to be completed by year-end 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, Nov. 6, 2013, at 11 a.m. Eastern Standard Time (10 a.m. Central Standard Time). The call also will be carried live on ONEOK Partners' and ONEOK's websites.
To participate in the telephone conference call, dial 888-850-2545, pass code 2072368, 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 2072368.
LINK TO EARNINGS TABLES:
http://www.oneokpartners.com/~/media/ONEOKPartners/EarningsTables/2013/OKS-Q3_2013_Earnings_FG83SoP.ashx
NON-GAAP (GENERALLY ACCEPTED ACCOUNTING PRINCIPLES) FINANCIAL MEASURES:
ONEOK Partners has disclosed in this news release historical EBITDA, DCF and coverage ratio levels, and anticipated DCF levels that are non-GAAP financial measures. EBITDA, DCF and coverage ratio are used as measures of the partnership's financial performance and are defined as follows:
-- EBITDA is defined as net income adjusted for interest expense,
depreciation and amortization, income taxes and allowance for equity
funds used during construction;
-- DCF is defined as EBITDA, computed as described above, less interest
expense, maintenance capital expenditures and equity earnings from
investments, adjusted for cash distributions received and certain other
items;
-- Coverage ratio is defined as distributable cash flow to limited partners
per limited partner unit divided by the distribution declared per
limited partner unit for the period; and
-- 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.
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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 41.3 percent of the overall partnership interest, as of Sept. 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.; ONEOK, Inc.
