ONEOK, INC.. TULSA, Okla., Aug. 5, 2014 /PRNewswire/ -- ONEOK Partners, L.P. (NYSE: OKS) today announced second-quarter 2014 net income attributable to ONEOK Partners of $214.4 million, or 54 cents per unit, compared with $202.4 million, or 62 cents per unit, in the second quarter 2013.
Second-quarter 2014 adjusted earnings before interest, taxes, depreciation and amortization (adjusted EBITDA) increased 15 percent to $360.9 million, compared with $315.1 million in the second quarter 2013.
Second-quarter 2014 results reflect higher natural gas volumes gathered, processed and sold, and higher natural gas liquids (NGL) volumes sold in the natural gas gathering and processing segment, as a result of recently completed capital-growth projects.
Second-quarter 2014 distributable cash flow (DCF) was $272.0 million, providing 1.02 times coverage of the cash distributions that will be paid, compared with second-quarter 2013 DCF of $251.9 million that provided 1.17 times coverage.
"Our natural gas gathering and processing segment reported strong volume growth in the second quarter from recently completed projects," said Terry K. Spencer, president and chief executive officer of ONEOK Partners. "As we've said previously, we expect natural gas and NGL volumes to continue to increase during the remainder of 2014 as we continue to add natural gas gathering and processing infrastructure and connect new natural gas plants to our NGL systems and as previously connected plants continue to ramp up.
"Our capital-growth program increased approximately $1.1 billion to $7.0 billion to $7.5 billion, and our backlog remains $3 billion to $4 billion after our recently announced projects in the natural gas gathering and processing segment, which include new natural gas processing plants and related infrastructure in Oklahoma and North Dakota that will increase our ability to gather and process growing supply in those areas," Spencer said. "The Demicks Lake plant in North Dakota will increase our natural gas processing capacity in the Williston Basin to approximately 1.1 billion cubic feet per day (Bcf/d), which will be more than 10 times our processing capacity in the region, compared with 2010. The Knox plant will be our first natural gas processing plant built in the emerging South Central Oklahoma Oil Province (SCOOP) play and will increase our Oklahoma processing capacity to approximately 900 million cubic feet per day (MMcf/d).
"These new projects, combined with our previously announced projects, are expected to further increase natural gas and NGL volumes and contracted capacity on our systems and create long-term value for our unitholders through increased earnings and distributions," Spencer added. "Pending board approval, we expect to announce additional Williston Basin natural gas processing capacity by the end of this year."
Year-to-date net income attributable to ONEOK Partners was $479.8 million, or $1.35 per unit, compared with $359.0 million, or $1.03 per unit, in the same period last year. Year-to-date 2014 adjusted EBITDA was $754.6 million, compared with $575.5 million in the same period last year.
DCF for the first six months of 2014 was $570.2 million, providing 1.14 times coverage, compared with $445.1 million for the same period last year, providing coverage of 0.99 times.
In the second quarter 2014, the partnership completed a public offering of approximately 13.9 million common units generating net proceeds of approximately $730 million and issued approximately 1.9 million common units through its at-the-market equity program. No common units were issued through the equity program in the second quarter 2013.
During the first six months of 2014, the partnership has issued approximately 3.0 million common units through its at-the-market equity program, compared with 300,000 during the same period last year.
There was a weighted average of approximately 236.4 million units outstanding for the six-month period ending June 30, 2014, compared with a weighted average of approximately 220.0 million units outstanding for the six-month period ending June 30, 2013.
The partnership also reaffirmed its 2014 net income guidance range of $975 million to $1.075 billion; its adjusted EBITDA guidance range of $1.565 billion to $1.665 billion; and its DCF guidance range of $1.15 billion to $1.25 billion, provided on Dec. 2, 2013.
2014 earnings guidance includes a projected 1.5-cent-per-unit-per-quarter increase in unitholder distributions declared while maintaining an annual coverage ratio of 1.05 to 1.15 times. Actual unitholder distribution declarations are subject to ONEOK Partners board approval.
SECOND-QUARTER AND YEAR-TO-DATE 2014 FINANCIAL PERFORMANCE
Second-quarter 2014 operating income was $262.2 million, compared with $230.0 million in the second quarter 2013.
Increases in second-quarter 2014 operating income reflect:
-- Higher natural gas volumes gathered, processed and sold, and higher NGL
volumes sold as a result of recently completed capital-growth projects;
and higher net realized prices, all in the natural gas gathering and
processing segment;
-- Higher margin NGL volumes delivered from the Bakken NGL Pipeline and
from new plants connected in the Mid-Continent region; and
-- Higher natural gas pipeline transportation revenues due to increased
rates on intrastate pipelines, and higher contracted capacity and
natural gas volumes transported in the natural gas pipelines segment.
These increases were offset partially by higher operating costs and depreciation and amortization expense from completed capital-growth projects.
Operating costs were $160.7 million in the second quarter 2014, compared with $124.0 million in the same period last year, due primarily to the growth of the partnership's operations related to completed capital-growth projects.
Depreciation and amortization expense was $71.4 million in the second quarter 2014, compared with $58.2 million for the same period last year, due to the growth of the partnership's operations.
Second-quarter 2014 equity earnings were $25.4 million, compared with $26.4 million in the second quarter 2013.
Capital expenditures were $389.4 million in the second quarter 2014, compared with $481.4 million in the same period in 2013, due to the timing of expenditures on capital-growth projects.
Year-to-date 2014 operating income was $555.0 million, compared with $407.7 million in 2013.
Operating costs for the six-month 2014 period were $310.8 million, compared with $262.2 million for the same period last year.
Depreciation and amortization expense for the first six months of 2014 was $138.2 million, compared with $112.9 million for the same period last year.
Year-to-date 2014 equity earnings were $59.1 million, compared with $52.3 million for the same period last year, due to increased park-and-loan services in the natural gas pipelines segment on Northern Border Pipeline in the first quarter 2014 and higher NGL volumes on the Overland Pass Pipeline, delivered from the Bakken NGL Pipeline, offset partially by increased ethane rejection and higher operating costs.
Year-to-date 2014 capital expenditures were $792.4 million, compared with $924.8 million for the same period last year.
>View earnings tables
SECOND-QUARTER 2014 SUMMARY:
-- Natural gas gathering and processing segment operating income of $66.1
million, compared with $55.5 million in the second quarter 2013;
-- Natural gas liquids segment operating income of $159.0 million, compared
with $142.7 million in the second quarter 2013;
-- Natural gas pipelines segment operating income of $37.3 million,
compared with $31.9 million in the second quarter 2013;
-- Increasing in July 2014 investments in its 2010-2016 capital-growth
program by approximately $1.1 billion to a range of $7.0 billion to $7.5
billion, which includes:
-- Announcing an investment of approximately $515 million to $670
million to construct the Demicks Lake plant, a 200-MMcf/d natural
gas processing facility in the Williston Basin in North Dakota,
which is expected to be completed in the third quarter 2016; and
expansions and upgrades to the existing natural gas gathering and
compression infrastructure;
-- Announcing an investment of approximately $80 million to $100
million to construct additional natural gas compression to take
advantage of additional natural gas processing capacity as a result
of better than expected plant performance at the partnership's
existing and planned Garden Creek and Stateline natural gas
processing plants in the Williston Basin by a total of 100 MMcf/d,
which is expected to be completed in the fourth quarter 2015;
-- Announcing an investment of approximately $10 million to $15 million
to construct approximately 12 miles of natural gas liquids (NGL)
gathering pipeline from the Demicks Lake plant to the partnerships'
existing Bakken NGL Pipeline, which is expected to be completed in
the third quarter 2016; and
-- Announcing an investment of approximately $365 million to $470
million to construct the Knox plant, a 200-MMcf/d natural gas
processing facility in Oklahoma's SCOOP play, which is expected to
be completed in the fourth quarter 2016; and expansions and upgrades
to the existing gathering and compression infrastructure;
-- Completing in May 2014 a public offering of approximately 13.9 million
common units, generating net proceeds of approximately $730 million;
-- Completing the sale of approximately $107.2 million of common units
through the partnership's $300 million at-the-market equity program,
which combined with the public offering in May, resulted in ONEOK's
aggregate ownership interest in ONEOK Partners decreasing to 38.5
percent at June 30, 2014, from 41.0 percent at March 31, 2014;
-- Increasing the partnership's commercial paper program to $1.7 billion
from $1.2 billion;
-- Having $278.0 million of cash and cash equivalents, $14.0 million in
letters of credit issued, no commercial paper outstanding and no
borrowings outstanding under the partnership's $1.7 billion revolving
credit facility as of June 30, 2014; and
-- Increasing in July 2014 the second-quarter 2014 distribution to 76 cents
per unit, or $3.04 per unit on an annualized basis, payable on Aug. 14,
2014, to unitholders of record on Aug. 4, 2014.
BUSINESS-SEGMENT RESULTS:
Natural Gas Gathering and Processing Segment
The natural gas gathering and processing segment reported second-quarter 2014 operating income of $66.1 million, compared with $55.5 million in the second quarter 2013, which reflects:
-- A $24.6 million increase due primarily to natural gas volume growth in
the Williston Basin and Cana-Woodford Shale and increased ownership in
the Maysville, Oklahoma, natural gas processing plant, which resulted in
higher natural gas volumes gathered, compressed, processed, transported
and sold, and higher NGL volumes sold;
-- An $8.1 million increase due primarily to higher net realized prices;
-- A $3.4 million increase due primarily to changes in contract mix; and
-- A $6.4 million decrease due to a condensate contract settlement in 2013.
Operating costs in the second quarter 2014 were $59.4 million, compared with $45.0 million in the second quarter 2013, due primarily to completed capital-growth projects and acquisitions, which reflect:
-- A $9.4 million increase due to higher materials and supplies, and
outside services expenses;
-- A $7.6 million increase due to higher labor and employee benefit costs;
and
-- A $2.6 million decrease due to the timing of property tax estimates in
2014.
Depreciation and amortization expense in the second quarter 2014 was $29.4 million, compared with $25.1 million in 2013, due to the completion of capital-growth projects and acquisitions.
Operating income for the six-month 2014 period was $126.0 million, compared with $89.2 million in the same period last year, which reflects:
-- A $61.4 million increase due primarily to natural gas volume growth in
the Williston Basin and Cana-Woodford Shale and increased ownership in
the Maysville, Oklahoma, natural gas processing plant, which resulted in
higher natural gas volumes gathered, compressed, processed, transported
and sold, higher NGL volumes sold, and higher fees, offset partially by
wellhead freeze-offs due to severely cold weather in the first quarter
2014;
-- A $13.9 million increase due primarily to higher net realized prices;
-- A $5.1 million increase due primarily to changes in contract mix; and
-- A $6.4 million decrease due to a condensate contract settlement in 2013.
Operating costs for the six-month 2014 period were $124.2 million, compared with $96.7 million for the same period last year, due primarily to completed capital-growth projects and acquisitions, which reflect:
-- A $21.4 million increase due to higher materials and supplies, and
outside services expenses;
-- An $8.8 million increase due to higher labor and employee benefit costs;
and
-- A $2.7 million decrease due to the timing of property tax estimates in
2014.
Depreciation and amortization expense for the six-month 2014 period was $58.3 million, compared with $49.0 million for the same period last year.
Key Statistics: More detailed information is listed in the tables.
-- Natural gas gathered was 1,646 billion British thermal units per day
(BBtu/d) in the second quarter 2014, up 24 percent compared with the
same period in 2013 due to volume growth from new natural gas processing
plants placed in service and increased ownership in the Maysville,
Oklahoma, natural gas processing plant, offset partially by continued
dry natural gas production declines in the Powder River Basin in Wyoming
and natural gas production declines in Kansas; and up 10 percent
compared with the first quarter 2014;
-- Natural gas processed was 1,447 BBtu/d in the second quarter 2014, up 37
percent compared with the same period in 2013 due to volume growth from
new natural gas processing plants placed in service and the increased
ownership in the Maysville, Oklahoma, natural gas processing plant; and
up 14 percent compared with the first quarter 2014;
-- NGL sales were 98,000 barrels per day (bpd) in the second quarter 2014,
up 31 percent compared with the same period in 2013; and up 9 percent
compared with the first quarter 2014;
-- The realized composite NGL net sales price was 96 cents per gallon in
the second quarter 2014, up 13 percent compared with the same period in
2013; and down 9 percent compared with the first quarter 2014, due
primarily to higher prices from increased demand associated with colder
than normal weather and lower propane storage levels in the first
quarter 2014;
-- The realized condensate net sales price was $77.46 per barrel in the
second quarter 2014, down 8 percent compared with the same period in
2013; and up 2 percent compared with the first quarter 2014; and
-- The realized residue natural gas net sales price was $4.07 per million
British thermal units (MMBtu) in the second quarter 2014, up 14 percent
compared with the same period in 2013; and up 13 percent compared with
the first quarter 2014.
In March 2014, the Canadian Valley natural gas processing plant in Oklahoma was completed, which has better ethane-rejection capabilities than the partnership's other processing plants in the Mid-Continent region. The Garden Creek, Stateline I and Stateline II natural gas processing plants in the Williston Basin have the capability to recover ethane when economic conditions warrant but did not do so during the second quarter 2014. As a result, the partnership's equity NGL volumes were weighted less toward ethane and more toward propane, iso-butane, normal butane and natural gasoline, and are expected to remain this way through much of 2016.
In the second quarter 2014, the segment connected approximately 360 wells, compared with approximately 350 in the same period in 2013. Year-to-date, the partnership has connected approximately 590 wells, compared with approximately 600 wells connected in the same period in 2013. This decrease is due to much colder than normal weather, which impacted construction activities in the Williston Basin during the first quarter 2014.
The partnership expects to connect approximately 1,300 wells in 2014, compared with approximately 1,160 wells in 2013.
The following table contains equity-volume information for the periods indicated:
Three Months Ended Six Months Ended
June 30, June 30,
Equity-Volume
Information
(a) 2014 2013 2014 2013
------------- ---- ---- ---- ----
NGL sales
(MBbl/d) 15.9 13.9 16.8 13.4
Condensate
sales (MBbl/
d) 3.1 2.5 3.3 2.6
Residue natural
gas sales
(BBtu/d) 105.3 68.8 96.9 63.1
--------------- ----- ---- ---- ----
(a) -Includes
volumes for
consolidated
entities only.
The natural gas gathering and processing segment is exposed to commodity-price risk as a result of receiving commodities in exchange for services. The following tables provide hedging information for equity volumes in the natural gas gathering and processing segment in the periods indicated:
Six Months Ending December 31, 2014
-----------------------------------
Volumes Average Price Percentage
Hedged Hedged
------ ------
NGLs
(MBbl/
d) 11.1 $1.17 / gallon 57%
Condensate
(MBbl/
d) 2.5 $2.22 / gallon 73%
---------- --- ----- -------- ---
Total
(MBbl/
d) 13.6 $1.36 / gallon 60%
======= ==== ===== ======== ===
Natural
gas
(BBtu/
d) 89.2 $4.06 / MMBtu 76%
------- ---- ----- ------- ---
Year Ending December 31, 2015
-----------------------------
Volumes Average Price Percentage
Hedged Hedged
------ ------
NGLs (MBbl/d) 1.2 $1.07 / gallon 7%
------------- --- ----- -------- ---
Natural gas (BBtu/d) 61.3 $4.34 / MMBtu 44%
-------------------- ---- ----- ------- ---
The partnership expects its NGL and natural gas commodity-price sensitivities to increase in the future as its capital-growth projects are completed and volumes increase under percent-of-proceeds contracts with its customers.
All of the natural gas gathering and processing segment's commodity-price sensitivities are estimated as a hypothetical change in the price of natural gas, NGLs and crude oil as of June 30, 2014, excluding the effects of hedging and assuming normal operating conditions. Condensate sales are based on the price of crude oil.
The natural gas gathering and processing segment estimates the following sensitivities:
-- A 10-cent-per-MMBtu change in the price of residue natural gas would
change annual net margin by approximately $4.6 million;
-- A 1-cent-per-gallon change in the composite price of NGLs would change
annual net margin by approximately $2.7 million; and
-- A $1.00-per-barrel change in the price of crude oil would change annual
net margin by approximately $1.3 million.
These estimates do not include any effects on demand for ONEOK Partners' services or natural gas processing plant operations that might be caused by, or arise in conjunction with, price changes. For example, a change in the gross processing spread may cause a change in the amount of ethane extracted from the natural gas stream, affecting natural gas gathering and processing margins for certain contracts.
Natural Gas Liquids Segment
The natural gas liquids segment reported second-quarter 2014 operating income of $159.0 million, compared with $142.7 million in the second quarter 2013, which reflects:
-- A $31.4 million increase in exchange-services margins, resulting
primarily from higher volumes delivered from the Bakken NGL Pipeline,
volumes from new plants connected in the Mid-Continent region and higher
fees from contract renegotiations for NGL exchange-services activities,
offset partially by lower volumes from the termination of a contract;
-- A $17.3 million increase from higher isomerization volumes, resulting
from wider NGL product price differentials between normal butane and
iso-butane;
-- A $1.3 million increase in storage margins due primarily to contract
renegotiations; and
-- A $2.7 million decrease from the impact of lower operational measurement
gains.
Optimization and marketing margins were relatively unchanged, primarily due to a $12.5 million decrease from narrower NGL location price differentials and lower volumes, offset partially by an $8.0 million increase due primarily to wider NGL product price differentials; and a $4.4 million increase in marketing margins.
Operating costs were $76.0 million in the second quarter 2014, compared with $54.2 million in the second quarter 2013, which reflect:
-- An $8.7 million increase due to higher outside services expenses
associated primarily with scheduled maintenance and the growth of
operations related to completed capital-growth projects;
-- A $4.5 million increase due to higher property taxes related to
completed capital-growth projects; and
-- A $4.0 million increase due to higher employee-related expenses due to
recently completed capital-growth projects and growth of the
partnership's operations.
Depreciation and amortization expense in the second quarter 2014 was $31.1 million, compared with $22.3 million in the same period in 2013.
Equity earnings from investments were $4.5 million in the second quarter 2014, compared with $5.9 million in the same period in 2013.
The decrease in equity earnings in the second quarter 2014 was due primarily to increased ethane rejection and higher operating costs, offset partially by higher volumes delivered to the Overland Pass Pipeline from the Bakken NGL Pipeline, which was placed in service in April 2013.
Operating income for the six-month 2014 period was $335.7 million, compared with $249.7 million in the same period last year, which reflects:
-- A $72.4 million increase in optimization and marketing margins,
resulting from a $28.2 million increase due to significantly wider NGL
location price differentials from the impact of severely cold weather
during the first quarter 2014, related primarily to propane; a $26.2
million increase from more favorable NGL product price differentials;
and an $18.0 million increase in marketing margins, related primarily to
increased weather-related seasonal demand for propane during the first
quarter 2014;
-- A $39.4 million increase in exchange-services margins, resulting
primarily from higher volumes from the Bakken NGL Pipeline, volumes from
new plants connected in the Mid-Continent region and higher fees from
contract renegotiations for NGL exchange-services activities, offset
partially by lower volumes from the termination of a contract;
-- A $20.6 million increase from higher isomerization volumes, resulting
from wider NGL product price differentials between normal butane and
iso-butane;
-- A $4.7 million increase in storage margins due primarily to contract
renegotiations;
-- A $4.1 million decrease from the impact of lower operational measurement
gains; and
-- A $3.8 million decrease from the impact of ethane rejection, which
resulted in lower NGL volumes.
Operating costs for the six-month 2014 period were $141.2 million, compared with $114.1 million for the same period last year, which reflect:
-- An $11.0 million increase due to higher outside services expenses
associated primarily with scheduled maintenance and the growth of
operations related to completed capital-growth projects;
-- A $6.6 million increase due to higher property taxes related to
completed capital-growth projects;
-- A $5.0 million increase due to higher employee-related expenses due to
recently completed capital-growth projects and growth of the
partnership's operations; and
-- A $1.4 million increase due to higher costs for chemicals, materials and
supplies.
Depreciation and amortization expense for the six-month 2014 period was $58.2 million, compared with $42.0 million for the same period last year.
Six-month 2014 equity earnings from investments were $9.2 million, compared with $9.0 million for the same period last year.
Key Statistics: More detailed information is listed in the tables.
-- NGLs transported on gathering lines were 520,000 bpd in the second
quarter 2014, down 6 percent compared with the same period in 2013, due
primarily to the termination of a contract and increased ethane
rejection in the Mid-Continent region, offset partially by increased
volumes from the Williston Basin made available by the Bakken NGL
Pipeline that was placed in service in April 2013 and volumes from new
plants connected in the Mid-Continent; and up 9 percent compared with
the first quarter 2014;
-- NGLs fractionated were 520,000 bpd in the second quarter 2014, down 3
percent compared with the same period in 2013, due primarily to the
termination of a contract and increased ethane rejection in the
Mid-Continent region, offset partially by increased volumes from the
Williston Basin made available by the Bakken NGL Pipeline and volumes
from new plants connected in the Mid-Continent; and up 10 percent
compared with the first quarter 2014;
-- NGLs transported on distribution lines were 431,000 bpd in the second
quarter 2014, relatively unchanged compared with the same period in 2013
and the first quarter 2014; and
-- The average Conway-to-Mont Belvieu price differential of ethane in
ethane/propane mix, based on Oil Price Information Service (OPIS)
pricing, was 3 cents per gallon in the second quarter 2014, compared
with 6 cents per gallon in the same period in 2013; and 12 cents per
gallon in the first quarter 2014.
Natural Gas Pipelines Segment
The natural gas pipelines segment reported second-quarter 2014 operating income of $37.3 million, compared with $31.9 million for the second quarter 2013, which reflects:
-- A $9.4 million increase from higher firm transportation revenues
resulting primarily from higher rates on its intrastate natural gas
pipelines, increased contracted capacity and rates on Midwestern Gas
Transmission Company and increased interruptible transportation revenues
from higher natural gas volumes transported;
-- A $1.4 million increase from additional storage services to meet utility
customers' peak-day demand;
-- A $1.3 million increase from higher net retained fuel due primarily to
additional natural gas volumes retained; and
-- A $4.3 million decrease due to lower storage revenues from lower
contracted capacity.
Second-quarter 2014 equity earnings from investments were $15.9 million, compared with $15.3 million in the same period in 2013.
Operating income for the six-month 2014 period was $92.4 million, compared with $67.8 million in the same period last year, which reflects:
-- A $13.8 million increase from higher firm transportation revenues
resulting primarily from higher rates on its intrastate natural gas
pipelines, increased contracted capacity and rates on Midwestern Gas
Transmission Company and increased interruptible transportation revenues
from higher natural gas volumes transported;
-- A $6.1 million increase from higher short-term natural gas storage
services due to increased park-and-loan services associated with
weather-related seasonal demand primarily in the first quarter 2014;
-- A $6.0 million increase from higher net retained fuel due to higher
natural gas prices and additional natural gas volumes retained;
-- A $5.3 million increase from higher park-and-loan services as a result
of weather-related seasonal demand on its interstate natural gas
pipelines in the first quarter 2014;
-- A $1.6 million increase primarily from additional storage services to
meet utility customers' peak-day demand; and
-- A $5.7 million decrease due to lower storage revenues from lower
contracted capacity.
Equity earnings from investments for the six-month 2014 period were $39.3 million, compared with $31.7 million for the same period last year, primarily due to increased park-and-loan services on Northern Border Pipeline as a result of increased weather-related seasonal demand in the first quarter 2014.
Key Statistics: More detailed information is listed in the tables.
-- Natural gas transportation capacity contracted was 5,691 thousand
dekatherms per day in the second quarter 2014, up 6 percent compared
with the same period in 2013; and down 3 percent compared with the first
quarter 2014;
-- Natural gas transportation capacity subscribed was 90 percent in the
second quarter 2014, up 2 percent compared with the same period in 2013;
and down 3 percent compared with the first quarter 2014; and
-- The average natural gas price in the Mid-Continent region was $4.36 per
MMBtu in the second quarter 2014, up 13 percent compared with the same
period in 2013; and down 22 percent compared with the first quarter
2014, due primarily to higher natural gas prices in the first quarter
2014 as a result of weather-related seasonal demand.
CAPITAL-GROWTH ACTIVITIES:
The partnership has announced approximately $7.0 billion to $7.5 billion in capital-growth projects and acquisitions between 2010 and 2016, of which approximately $3.8 billion have been completed.
Of the approximately $3.8 billion to $4.3 billion of announced capital-growth projects and acquisitions in the natural gas gathering and processing segment, projects totaling approximately $1.6 billion have been completed as follows:
-- Approximately $300 million to construct the Canadian Valley plant, a
200-MMcf/d natural gas processing facility in the Cana-Woodford Shale
area in Oklahoma, which was completed in March 2014; and expansions and
upgrades to existing natural gas gathering and compression
infrastructure;
-- Approximately $305 million in September 2013 to acquire the Sage Creek
plant, a 50-MMcf/d natural gas processing facility, and related natural
gas gathering and natural gas liquids infrastructure in the Niobrara
Shale, an NGL-rich area in the Powder River Basin in Wyoming;
-- Approximately $90 million in the fourth quarter 2013 to acquire the
remaining 30 percent interest in the Maysville, Oklahoma, natural gas
processing facility in the Cana-Woodford Shale in Oklahoma;
-- Approximately $125 million to construct a 270-mile natural gas gathering
system and related infrastructure in Divide County, North Dakota. The
system, which required less infrastructure than originally anticipated,
gathers and transports natural gas from producers in the Williston Basin
to the partnership's Stateline I and Stateline II natural gas processing
plants, each with 100 MMcf/d of natural gas processing capacity in
western Williams County, North Dakota. The majority of the system was
placed in service in the second quarter 2013, with the remaining portion
of the system expected to be completed by the end of 2014;
-- Approximately $565 million to construct the Stateline I and Stateline II
plants, each with 100 MMcf/d of natural gas processing capacity, and
related expansions and upgrades to existing gathering and compression
infrastructure 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 $360 million to construct 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 expansions and upgrades to existing
natural gas gathering system infrastructure.
Approximately $2.2 billion to $2.7 billion of announced capital-growth projects in the natural gas gathering and processing segment are in various stages of construction as follows:
-- Approximately $310 million to $345 million to construct the Garden Creek
II plant, a 100-MMcf/d natural gas processing facility in the Williston
Basin in North Dakota, which is expected to be completed in the third
quarter 2014; and expansions and upgrades to existing natural gas
gathering and compression infrastructure;
-- Approximately $325 million to $360 million to construct the Garden Creek
III plant, a 100-MMcf/d natural gas processing facility in the Williston
Basin in North Dakota, which is expected to be completed in the fourth
quarter 2014; and expansions and upgrades to existing natural gas
gathering and compression infrastructure;
-- Approximately $550 million to $680 million to construct the Lonesome
Creek plant, a 200-MMcf/d natural gas processing facility in the
Williston Basin in North Dakota, which is expected to be completed in
the fourth quarter 2015; and expansions and upgrades to existing natural
gas gathering and compression infrastructure;
-- Approximately $50 million to upgrade the Sage Creek natural gas
processing plant and construct natural gas gathering infrastructure
through 2015;
-- Approximately $515 million to $670 million to construct the Demicks Lake
plant, a 200-MMcf/d natural gas processing facility in the Williston
Basin in North Dakota, which is expected to be completed in the third
quarter 2016; and expansions and upgrades to the existing gathering and
compression infrastructure;
-- Approximately $80 million to $100 million to construct additional
natural gas compression to take advantage of additional natural gas
processing capacity as a result of better than expected plant
performance at the partnership's existing and planned Garden Creek and
Stateline natural gas processing plants in the Williston Basin by a
total of 100 MMcf/d, which is expected to be completed in the fourth
quarter 2015; and
-- Approximately $365 million to $470 million to construct the Knox plant,
a 200-MMcf/d natural gas processing facility in Oklahoma's SCOOP play,
which is expected to be completed in the fourth quarter 2016; and
expansions and upgrades to the existing gathering and compression
infrastructure.
Of the approximately $3.2 billion of announced capital-growth projects in the natural gas liquids segment, projects totaling approximately $2.2 billion have been completed as follows:
-- Approximately $767 million to construct a 550-plus-mile, 16-inch
diameter NGL pipeline - the Sterling III Pipeline - which was completed
in March 2014, to transport either unfractionated NGLs or NGL purity
products from the Mid-Continent region to the Texas Gulf Coast, with an
initial capacity of 193,000 bpd and the ability to expand to 260,000
bpd; and the reconfiguration of its existing Sterling I and II NGL
distribution pipelines to transport either unfractionated NGLs or NGL
purity products, which was completed in July 2014;
-- Approximately $46 million to install a 40,000-bpd ethane/propane (E/P)
splitter at its Mont Belvieu, Texas, NGL storage facility to split E/P
mix into purity ethane, which was completed in March 2014;
-- Approximately $375 million to construct a 75,000-bpd NGL fractionator,
MB-2, at Mont Belvieu, Texas, which was placed in service in December
2013;
-- Approximately $455 million to construct the 600-mile, 12-inch diameter
Bakken NGL Pipeline to transport unfractionated NGLs produced from the
Bakken Shale in the Williston Basin to the partnership's 50
percent-owned Overland Pass Pipeline, a 760-mile NGL pipeline extending
from southern Wyoming to Conway, Kansas. The Bakken NGL Pipeline was
placed in service in April 2013, with a current capacity of 60,000 bpd;
-- Approximately $23 million for the construction of a 12-inch diameter
ethane header pipeline that creates a new point of interconnection
between the Mont Belvieu, Texas, NGL fractionation and storage assets,
and several petrochemical customers. The ethane header pipeline has the
capacity to transport 400,000 bpd of purity ethane from the
partnership's NGL storage facilities; from its 80 percent-owned,
160,000-bpd MB-1 NGL fractionator; from its two wholly owned, 75,000-bpd
NGL fractionators - MB-2, which was placed in service in December 2013,
and MB-3, which currently is being constructed; and from its recently
completed E/P splitter. The ethane header pipeline was placed in service
in April 2013;
-- Approximately $36 million to expand by 60,000 bpd the capacity of the
partnership's 50 percent-owned Overland Pass Pipeline, which was placed
in service in the second quarter 2013, to transport the additional
unfractionated NGL volumes from the Bakken NGL Pipeline;
-- Approximately $117 million to expand by 60,000 bpd the partnership's NGL
fractionation capacity at Bushton, Kansas, which was placed in service
in September 2012, to accommodate NGL volumes from the Mid-Continent and
Williston Basin;
-- Approximately $220 million to construct more than 230 miles of 10- and
12-inch diameter NGL pipelines that expanded the partnership's existing
Mid-Continent NGL gathering system in the Cana-Woodford and Granite Wash
areas by adding an incremental 75,000 bpd to 80,000 bpd of
unfractionated NGLs to the partnership's existing NGL gathering systems
in the Mid-Continent and the Arbuckle Pipeline. These NGL pipelines were
placed in service in April 2012, and the partnership connected to its
NGL gathering system three new third-party natural gas processing
facilities and three existing third-party natural gas processing
facilities that were expanded. In addition, the installation of
additional pump stations and pipeline looping on the Arbuckle Pipeline
was completed, increasing its capacity to 260,000 bpd; and
-- Approximately $30 million to install seven additional pump stations
along its existing Sterling I NGL distribution pipeline that were placed
in service at the end of 2011; the additional pump stations increased
the pipeline's capacity by 15,000 bpd.
Approximately $1.0 billion of announced capital-growth projects in the natural gas liquids segment are in various stages of construction, as follows:
-- Approximately $100 million to install additional pump stations on the
Bakken NGL Pipeline to increase its capacity to 135,000 bpd from its
current capacity of 60,000 bpd, which is expected to be completed in the
third quarter 2014;
-- Approximately $100 million, announced in November 2013, for a second
expansion of the Bakken NGL Pipeline, which will increase the pipeline's
capacity to 160,000 bpd from 135,000. The expansion is expected to be
completed in the second quarter 2016;
-- Approximately $525 million to $575 million to construct a 75,000-bpd NGL
fractionator, MB-3, and related infrastructure at Mont Belvieu, Texas,
which is expected to be completed in the fourth quarter 2014;
-- Approximately $85 million to construct new NGL pipeline infrastructure
and connect the Sage Creek natural gas processing plant to the
partnership's Bakken NGL Pipeline; these projects are expected to be
completed in the fourth quarter 2015;
-- Approximately $140 million to construct an approximately 95-mile NGL
pipeline between existing NGL fractionation infrastructure at
Hutchinson, Kansas, and Medford, Oklahoma, and the modification of the
partnership's NGL fractionation infrastructure at Hutchinson, Kansas, to
accommodate unfractionated NGLs produced in the Williston Basin; both
projects are expected to be completed in the first quarter 2015; and
-- Approximately $10 million to $15 million to construct an approximately
12-mile NGL gathering pipeline connecting the Demicks Lake natural gas
processing plant to the partnership's Bakken NGL Pipeline, which is
expected to be completed in the third quarter 2016.
EARNINGS CONFERENCE CALL AND WEBCAST:
ONEOK Partners and ONEOK executive management will conduct a joint conference call on Wednesday, Aug. 6, 2014, at 11 a.m. Eastern Daylight Time (10 a.m. Central Daylight Time). The call also will be carried live on ONEOK Partners' and ONEOK's websites.
To participate in the telephone conference call, dial 800-967-7185, pass code 5696330, 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 5696330.
LINK TO EARNINGS TABLES:
http://www.oneokpartners.com/~/media/ONEOKPartners/EarningsTables/2014/%20OKS_Q2_2014_earnings_MxIN856.ashx
NON-GAAP (GENERALLY ACCEPTED ACCOUNTING PRINCIPLES) FINANCIAL MEASURES:
ONEOK Partners has disclosed in this news release historical adjusted EBITDA, DCF, coverage ratio and distributable cash flow to limited partners per limited partner unit, 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;
-- 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
-- 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, coverage ratio and distributable cash flow to limited partners 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 is a leader in the gathering, processing, storage and transportation of natural gas in the U.S. and owns one of the nation's premier natural gas liquids (NGL) systems, connecting NGL supply in the Mid-Continent and Rocky Mountain regions with key market centers. Its general partner is a wholly owned subsidiary of ONEOK, Inc. (NYSE: OKE), a pure-play publicly traded general partner, which owns 38.5 percent of the overall partnership interest, as of June 30, 2014.
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, NGLs 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 any
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.
