ONEOK, INC.. TULSA, Okla., Nov. 4, 2014 /PRNewswire/ -- ONEOK Partners, L.P. (NYSE: OKS) today announced third-quarter 2014 net income attributable to ONEOK Partners of $167.2 million, or 32 cents per unit, which includes a noncash impairment charge of $76.4 million, or 31 cents per unit, in the natural gas gathering and processing segment. In the third quarter 2013, net income attributable to ONEOK Partners was $216.3 million, or 64 cents per unit.
The noncash impairment charge, which is included in equity earnings from investments, resulted from the partnership's equity investment in Bighorn Gas Gathering, a natural gas gathering system located in the coal-bed methane area of the Powder River Basin in Wyoming, where dry natural gas volumes continue to decline.
Third-quarter 2014 adjusted earnings before interest, taxes, depreciation and amortization (adjusted EBITDA) were $388.6 million, a 17 percent increase compared with $331.9 million in the third quarter 2013.
Third-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, and higher margin NGL volumes from connections with new natural gas processing plants in the Williston Basin and Mid-Continent regions in the natural gas liquids segment.
Third-quarter 2014 distributable cash flow (DCF) was $293.3 million, providing 1.05 times coverage of the cash distributions that will be paid, a 13 percent increase compared with third-quarter 2013 DCF of $259.1 million that provided 1.14 times coverage.
"Completed capital-growth projects in our natural gas gathering and processing, and natural gas liquids segments continue to add incremental earnings and distributable cash flow, and increased natural gas volumes on our systems throughout our operating areas," said Terry K. Spencer, president and chief executive officer of ONEOK Partners.
"With our recent announcements of new natural gas processing facilities in North Dakota, Wyoming and Oklahoma, we continue to add natural gas and natural gas liquids infrastructure to better serve our customers and producers. And, our recently announced acquisition of NGL assets - the West Texas LPG and Mesquite NGL pipelines - in the Permian Basin gives us a significant NGL presence in yet another highly productive NGL-rich region," Spencer said.
"Once the acquisition is complete and integrated into our existing systems, these assets are expected to generate ONEOK Partners adjusted EBITDA multiples of six to eight times between 2017 and 2020 through enhanced customer services and volume increases from pipeline capacity expansions which are expected to cost ONEOK Partners approximately $500 million between 2015 and 2019," continued Spencer. "Potential margins realized downstream from fee-based fractionation and storage services at our Mont Belvieu facilities could further enhance these multiples."
"Our strategically positioned assets allow us to serve producers in multiple highly productive NGL-rich areas, including the Williston Basin, the Powder River Basin, the Cana-Woodford, Stack and SCOOP plays in Oklahoma, and the Permian Basin of West Texas and southeastern New Mexico," Spencer added. "In addition to announcing approximately $2.5 billion in capital investments in 2014, we also increased our total backlog of unannounced growth projects to a range of $4 billion to $5 billion."
Year-to-date net income attributable to ONEOK Partners was $647.1 million, or $1.65 per unit, which includes the noncash impairment charge of $76.4 million related to ONEOK Partners' equity investment in Bighorn Gas Gathering, compared with $575.3 million, or $1.68 per unit, in the same period last year.
Year-to-date 2014 adjusted EBITDA was $1.14 billion, a 26 percent increase compared with $907.4 million in the same period last year.
DCF for the first nine months of 2014 was $863.5 million, providing 1.11 times coverage, a 23 percent increase compared with $704.2 million for the same period last year, providing coverage of 1.04 times.
In the third quarter 2014, the partnership issued approximately 1.4 million common units through its at-the-market equity program. No common units were issued through the equity program in the third quarter 2013.
During the first nine months of 2014, the partnership has issued approximately 4.4 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 240.6 million units outstanding for the nine-month period ending Sept. 30, 2014, compared with a weighted average of approximately 222.3 million units outstanding for the nine-month period ending Sept. 30, 2013.
2014 REVISED FINANCIAL GUIDANCE
The partnership revised its 2014 net income guidance range to $910 million to $970 million, compared with the previous guidance range of $975 million to $1.075 billion announced on Dec. 3, 2013. The partnership's DCF is expected to be in the range of $1.155 billion to $1.215 billion, compared with the previous guidance range of $1.15 billion to $1.25 billion.
In addition, the partnership's adjusted EBITDA is expected to be in the range of $1.55 billion to $1.61 billion, compared with the previous guidance range of $1.565 billion to $1.665 billion.
These revisions reflect the noncash impairment charge of $76.4 million in the natural gas gathering and processing segment during the third quarter 2014, and lower anticipated earnings in the partnership's natural gas liquids segment due to narrower NGL location price differentials and lower expected NGL volumes as a result of increased ethane rejection.
Anticipated decreases in the natural gas liquids segment are expected to be partially offset by better than expected performance in the natural gas gathering and processing and natural gas pipelines segments due to increased natural gas volumes in the Williston Basin and Mid-Continent from recently completed projects and higher earnings in the natural gas pipelines segment due to weather-related seasonal demand in the first quarter 2014 and approximately $16 million from anticipated gains on the sale of non-core assets in the fourth quarter 2014.
The partnership also revised 2014 volume guidance for natural gas gathered and processed and NGLs gathered and fractionated. Natural gas gathered is expected to be approximately 1,720 billion British thermal units per day (BBtu/d), compared with the previous guidance of 1,700 BBtu/d, and natural gas processed is expected to be approximately 1,510 BBtu/d, compared with the previous guidance of 1,410 BBtu/d, due primarily to volume growth in the Williston Basin and Mid-Continent from new natural gas processing plants placed in service. Natural gas gathered and natural gas processed are expected to reach approximately 1,850 BBtu/d and 1,600 BBtu/d, respectively, during the fourth quarter 2014.
NGLs gathered are expected to be approximately 520,000 barrels per day (bpd), compared with the previous 2014 guidance of 631,000 bpd, and NGLs fractionated are expected to be approximately 530,000 bpd, compared with the previous guidance of 589,000 bpd, due primarily to increased ethane rejection, the slower than expected ramp-up of previously connected natural gas processing plants and the impact of severely cold weather in the first quarter 2014. NGLs gathered and fractionated are expected to reach approximately 575,000 bpd during the fourth quarter 2014.
The partnership's 2014 capital expenditures are expected to be approximately $1.7 billion, compared with the previous guidance of approximately $2.1 billion. The decrease in 2014 capital expenditures has no impact on projected capital-growth project costs or scheduled completion dates.
> View guidance midpoint tables
THIRD-QUARTER AND YEAR-TO-DATE 2014 FINANCIAL PERFORMANCE
Third-quarter 2014 operating income was $293.0 million, compared with $240.1 million in the third quarter 2013.
Increases in third-quarter 2014 operating income reflect:
-- Higher natural gas volumes gathered, processed and sold, and higher NGL
volumes sold in the natural gas gathering and processing segment as a
result of recently completed capital-growth projects;
-- Higher margin NGL volumes delivered from connections with new natural
gas processing plants in the Williston Basin and Mid-Continent regions;
and
-- Higher natural gas pipeline transportation revenues due to increased
rates on intrastate pipelines and higher natural gas volumes transported
in the natural gas pipelines segment.
These increases were offset partially by lower net realized NGL and condensate prices in the natural gas gathering and processing segment, increased ethane rejection resulting in lower volumes in the natural gas liquids segment and higher operating costs and depreciation and amortization expense from completed capital-growth projects.
Operating costs were $170.8 million in the third quarter 2014, compared with $122.4 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 $73.9 million in the third quarter 2014, compared with $61.2 million for the same period last year, due to the growth of the partnership's operations.
Third-quarter 2014 equity earnings were a loss of $52.3 million, compared with equity earnings of $27.5 million in the third quarter 2013. The decrease in equity earnings is primarily due to the $76.4 million noncash impairment charge related to ONEOK Partners' 49 percent equity investment in Bighorn Gas Gathering, a natural gas gathering system located in the coal-bed methane area of the Powder River Basin in Wyoming, where dry natural gas volumes continue to decline. The remaining net book value of the partnership's equity investment in Bighorn Gas Gathering is $8.8 million.
Capital expenditures were $380.5 million in the third quarter 2014, compared with $449.1 million in the same period in 2013, due to the timing of expenditures on capital-growth projects.
Year-to-date 2014 operating income was $848.0 million, compared with $647.8 million in 2013.
Operating costs for the nine-month 2014 period were $481.6 million, compared with $384.6 million for the same period last year.
Depreciation and amortization expense for the first nine months of 2014 was $212.1 million, compared with $174.1 million for the same period last year.
Year-to-date 2014 equity earnings were $6.7 million, compared with $79.7 million for the same period last year, primarily due to the noncash impairment charge in the natural gas gathering and processing segment.
Year-to-date 2014 capital expenditures were $1.2 billion, compared with $1.4 billion for the same period last year, due to the timing of expenditures on capital-growth projects.
> View earnings tables
THIRD-QUARTER 2014 SUMMARY:
-- Natural gas gathering and processing segment operating income of $82.9
million, compared with $58.5 million in the third quarter 2013;
-- Natural gas liquids segment operating income of $173.8 million, compared
with $146.2 million in the third quarter 2013;
-- Natural gas pipelines segment operating income of $36.2 million,
compared with $35.2 million in the third quarter 2013;
-- Completing the sale of approximately $81.3 million of common units
through the partnership's at-the-market equity program, which resulted
in ONEOK's aggregate ownership interest in ONEOK Partners decreasing to
38.3 percent at Sept. 30, 2014, from 38.5 percent at June 30, 2014;
-- Filing a registration statement with the Securities and Exchange
Commission to register an additional $650 million of common units for
the partnership's at-the-market equity program, which was declared
effective in September 2014;
-- Having $54.0 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 Sept. 30, 2014; and
-- Increasing in October the third-quarter 2014 distribution to 77.5 cents
per unit, or $3.10 per unit on an annualized basis, payable on Nov. 14,
2014, to unitholders of record on Nov. 3, 2014.
RECENTLY ANNOUNCED CAPITAL-GROWTH PROJECTS:
-- Increasing the backlog of unannounced capital-growth projects to a range
of $4 billion to $5 billion from a previous range of $3 billion to $4
billion;
-- Increasing investments in its 2010 to 2016 capital-growth program to a
range of $8.3 billion to $9.0 billion by announcing new projects and
acquisitions, including:
-- Approximately $800 million to acquire approximately 2,600 miles of
NGL pipelines and related assets in the Permian Basin in
southeastern New Mexico and West Texas from affiliates of Chevron
Corporation, including an 80 percent interest in the West Texas LPG
Pipeline Limited Partnership and 100 percent interest in the
Mesquite Pipeline. The transaction is expected to close in the
fourth quarter 2014;
-- $230 million to $330 million to construct the Bear Creek plant, an
80-million cubic feet per day (MMcf/d) natural gas processing
facility and related infrastructure in the Williston Basin in North
Dakota, which is expected to be completed during the second quarter
2016; and an additional $35 million to $45 million to construct an
NGL pipeline connecting the Bear Creek natural gas processing plant
to the partnership's Bakken NGL Pipeline, which is expected to be
completed in the third quarter 2016;
-- $170 million to $245 million to construct the Bronco plant, a
100-MMcf/d natural gas processing facility and related
infrastructure in the Powder River Basin in Wyoming; and an
additional $45 million to $60 million to construct an NGL pipeline
connecting the Bronco plant to the partnership's Niobrara NGL
Lateral. Both projects are expected to be completed during the third
quarter 2016;
-- $515 million to $670 million to construct the Demicks Lake plant, a
200-MMcf/d natural gas processing facility and related
infrastructure in the Williston Basin in North Dakota; and an
additional $10 million to $15 million to construct an NGL pipeline
connecting the Demicks Lake plant to the partnerships' existing
Bakken NGL Pipeline. Both projects are expected to be completed in
the third quarter 2016;
-- $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
-- $365 million to $470 million to construct the Knox plant, a
200-MMcf/d natural gas processing facility and related
infrastructure in Oklahoma's SCOOP play, which is expected to be
completed in the fourth quarter 2016;
-- Completing projects totaling more than $800 million, including:
-- The Garden Creek II and III plants, 100-MMcf/d natural gas
processing facilities in the Williston Basin in North Dakota, which
were completed in August and October, respectively;
-- The expansion of the Bakken NGL Pipeline, which increases the
pipeline's capacity to 135,000 barrels per day (bpd) from 60,000
bpd, which was completed in September; and
-- The Niobrara NGL Lateral, an NGL pipeline that connects the
partnership's Sage Creek natural gas processing facility in the
NGL-rich Niobrara Shale formation in Wyoming's Powder River Basin to
the partnership's Bakken NGL Pipeline; which was completed in
September.
BUSINESS-SEGMENT RESULTS:
Natural Gas Gathering and Processing Segment
The natural gas gathering and processing segment reported third-quarter 2014 operating income of $82.9 million, compared with $58.5 million in the third quarter 2013, which reflects:
-- A $50.0 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;
-- A $3.4 million increase due primarily to changes in contract mix; and
-- A $6.1 million decrease due primarily to lower net realized NGL and
condensate prices.
Operating costs in the third quarter 2014 were $64.3 million, compared with $45.1 million in the third quarter 2013, due primarily to completed capital-growth projects and acquisitions, which reflect:
-- A $10.9 million increase due to higher materials and supplies, and
outside services expenses; and
-- An $8.5 million increase due to higher labor and employee benefit costs.
Depreciation and amortization expense in the third quarter 2014 was $31.3 million, compared with $27.4 million in 2013, due to the completion of capital-growth projects and acquisitions.
Equity earnings from investments were a loss of $71.1 million, including the noncash impairment charge of $76.4 million, in the third quarter 2014, compared with equity earnings of $4.7 million in the same period in 2013.
Operating income for the nine-month 2014 period was $208.9 million, compared with $147.7 million in the same period last year, which reflects:
-- A $111.4 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;
-- An $8.5 million increase due primarily to changes in contract mix;
-- A $7.8 million increase due primarily to higher net realized natural gas
and NGL prices; and
-- A $6.4 million decrease due to a condensate contract settlement in 2013.
Operating costs for the nine-month 2014 period were $188.5 million, compared with $141.7 million for the same period last year, due primarily to completed capital-growth projects and acquisitions, which reflect:
-- A $32.3 million increase due to higher materials and supplies, and
outside services expenses; and
-- A $17.3 million increase due to higher labor and employee benefit costs.
Depreciation and amortization expense for the nine-month 2014 period was $89.6 million, compared with $76.4 million for the same period last year, due to the completion of capital-growth projects and acquisitions.
Equity earnings from investments for the nine-month 2014 period were a loss of $60.5 million, including the noncash impairment charge of $76.4 million in the third quarter 2014, compared with equity earnings of $16.2 million for the same period last year.
Key Statistics: More detailed information is listed in the tables.
-- Natural gas gathered was 1,847 billion British thermal units per day
(BBtu/d) in the third quarter 2014, up 33 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
natural gas production declines in Kansas; and up 12 percent compared
with the second quarter 2014;
-- Natural gas processed was 1,666 BBtu/d in the third quarter 2014, up 47
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 15 percent compared with the second quarter 2014;
-- NGL sales were 111,000 bpd in the third quarter 2014, up 34 percent
compared with the same period in 2013; and up 13 percent compared with
the second quarter 2014;
-- The realized composite NGL net sales price was 93 cents per gallon in
the third quarter 2014, up 3 percent compared with the same period in
2013; and down 3 percent compared with the second quarter 2014;
-- The realized condensate net sales price was $81.02 per barrel in the
third quarter 2014, down 11 percent compared with the same period in
2013; and up 5 percent compared with the second quarter 2014; and
-- The realized residue natural gas net sales price was $3.92 per million
British thermal units (MMBtu) in the third quarter 2014, up 17 percent
compared with the same period in 2013; and down 4 percent compared with
the second 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. As a result, the partnership's realized composite NGL net sales price for the third quarter 2014 increased compared with the same period in 2013, while most individual NGL product prices were lower compared with the third quarter 2013. The Garden Creek, Garden Creek II, 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 first nine months of 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 at least 2016 due to expected ethane rejection.
In the third quarter 2014, the segment connected approximately 420 wells, compared with approximately 340 in the same period in 2013. Year to date, the partnership has connected approximately 1,010 wells, compared with approximately 950 wells connected in the same period in 2013.
The partnership expects to connect approximately 1,300 wells in 2014, compared with approximately 1,160 wells in 2013. Due to improved producer drilling and recovery techniques, natural gas volumes from new wells have increased, resulting in higher volumes gathered from newer well connections.
The following table contains equity-volume information for the periods indicated:
Three Months Ended Nine Months Ended
September 30, September 30,
Equity-Volume
Information (a) 2014 2013 2014 2013
---------------- ---- ---- ---- ----
NGL sales (MBbl/d) 16.0 14.6 16.6 13.8
Condensate sales
(MBbl/d) 2.6 2.0 3.1 2.4
Residue natural gas
sales (BBtu/d) 134.5 76.8 109.6 67.7
------------------- ----- ---- ----- ----
(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:
Three Months Ending December 31, 2014
-------------------------------------
Volumes Average Price Percentage
Hedged Hedged
------ ------
NGLs (MBbl/d) 11.3 $1.17 / gallon 63%
Condensate (MBbl/d) 2.7 $2.21 / gallon 73%
------------------- --- ----- -------- ---
Total (MBbl/d) 14.0 $1.37 / gallon 64%
============== ==== ===== ======== ===
Natural gas (BBtu/d) 96.0 $4.07 / MMBtu 73%
-------------------- ---- ----- ------- ---
Year Ending December 31, 2015
-----------------------------
Volumes Average Price Percentage
Hedged Hedged
------ ------
NGLs (MBbl/d) 1.2 $1.07 / gallon 5%
------------- --- ----- -------- ---
Natural gas (BBtu/d) 61.3 $4.34 / MMBtu 41%
-------------------- ---- ----- ------- ---
The partnership expects its NGL and natural gas commodity-price sensitivities to increase in the future as its capital-growth projects are completed and volumes increase under percent-of-proceeds contracts, with a fee-based component, 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 Sept. 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 12-month forward net margin by approximately $5.1 million;
-- A 1-cent-per-gallon change in the composite price of NGLs would change
12-month forward net margin by approximately $3.1 million; and
-- A $1.00-per-barrel change in the price of crude oil would change
12-month forward net margin by approximately $1.6 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 third-quarter 2014 operating income of $173.8 million, compared with $146.2 million in the third quarter 2013, which reflects:
-- A $53.0 million increase in exchange-services margins, resulting
primarily from increased volumes from new natural gas processing plants
connected in the Williston Basin and Mid-Continent regions, and higher
fees from contract renegotiations for NGL exchange-services activities,
offset partially by lower volumes from the termination of a contract;
-- An $11.7 million increase in optimization and marketing margins, which
resulted from an $8.7 million increase in margins due primarily to
marketing and truck and rail activities, and a $7.5 million increase due
primarily to wider NGL product price differentials; offset by a decrease
of $4.5 million due primarily to lower optimization volumes; and
-- A $5.6 million decrease from the impact of ethane rejection, which
resulted in lower NGL volumes.
Operating costs were $77.0 million in the third quarter 2014, compared with $57.0 million in the third quarter 2013, due primarily to completed capital-growth projects, which reflect:
-- A $7.5 million increase due to higher labor and employee benefit costs;
-- A $5.9 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 $3.3 million increase due to higher property taxes related to
completed capital-growth projects; and
-- A $1.3 million increase due to higher costs for chemicals, materials and
supplies.
Depreciation and amortization expense in the third quarter 2014 was $31.7 million, compared with $23.0 million in the same period in 2013, due to the completion of capital-growth projects.
Equity earnings from investments were $4.4 million in the third quarter 2014, compared with $6.3 million in the same period in 2013.
The decrease in equity earnings in the third quarter 2014 was due primarily to increased ethane rejection and higher operating costs, offset partially by higher volumes delivered to the partnership's 50 percent-owned Overland Pass Pipeline from the Bakken NGL Pipeline, which was placed in service in April 2013.
Operating income for the nine-month 2014 period was $509.5 million, compared with $396.0 million in the same period last year, which reflects:
-- A $92.4 million increase in exchange-services margins, resulting
primarily from increased volumes from new natural gas processing plants
connected in the Williston Basin and Mid-Continent regions, and higher
fees from contract renegotiations for NGL exchange-services activities,
offset partially by lower volumes from the termination of a contract;
-- An $84.1 million increase in optimization and marketing margins,
resulting from a $33.7 million increase due primarily to wider NGL
product price differentials, a $26.7 million increase in marketing
margins, related primarily to increased weather-related seasonal demand
for propane during the first quarter 2014, and marketing and truck and
rail activities in the second and third quarters 2014; and a $23.7
million increase due primarily to significantly wider NGL location price
differentials, primarily related to increased weather-related seasonal
demand for propane during the first quarter 2014;
-- An $18.7 million increase from higher isomerization volumes, resulting
from wider NGL product price differentials between normal butane and
iso-butane;
-- A $4.5 million increase in storage margins due primarily to contract
renegotiations;
-- A $9.4 million decrease from the impact of ethane rejection, which
resulted in lower NGL volumes; and
-- A $5.0 million decrease from the impact of lower operational measurement
gains.
Operating costs for the nine-month 2014 period were $218.2 million, compared with $171.1 million for the same period last year, which reflect:
-- A $16.9 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 $12.5 million increase due to higher labor and employee benefit costs;
-- A $9.9 million increase due to higher property taxes related to
completed capital-growth projects; and
-- A $2.7 million increase due to higher costs for chemicals, materials and
supplies.
Depreciation and amortization expense for the nine-month 2014 period was $89.8 million, compared with $65.0 million for the same period last year.
Nine-month 2014 equity earnings from investments were $13.6 million, compared with $15.4 million for the same period last year.
Key Statistics: More detailed information is listed in the tables.
-- NGLs transported on gathering lines were 529,000 bpd in the third
quarter 2014, down 8 percent compared with the same period in 2013, due
primarily to the termination of a contract and increased ethane
rejection in the Mid-Continent and Rocky Mountain regions, offset
partially by volumes from new plants connected in the Williston Basin
and Mid-Continent regions; and up 2 percent compared with the second
quarter 2014;
-- NGLs fractionated were 553,000 bpd in the third quarter 2014, down 1
percent compared with the same period in 2013, due primarily to the
termination of a contract and increased ethane rejection in the
Mid-Continent and Rocky Mountain regions, offset partially by volumes
from new plants connected in the Williston Basin and Mid-Continent
regions; and up 6 percent compared with the second quarter 2014;
-- NGLs transported on distribution lines were 377,000 bpd in the third
quarter 2014, down 17 percent compared with the same period in 2013, due
primarily to lower volumes transported for the partnership's
optimization business due to narrower location price differentials
between the Conway and Mont Belvieu market centers and increased ethane
rejection, offset partially by an increase in exchange services volumes
delivered to Mont Belvieu due to the completed Sterling III pipeline,
which was placed in service in March 2014; and down 13 percent compared
with the second quarter 2014, due primarily to lower volumes in the
partnership's optimization business due to narrower location price
differentials between the Conway and Mont Belvieu market centers and
increased ethane rejection; 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 third quarter 2014, compared with
4 cents per gallon in the same period in 2013; and 3 cents per gallon in
the second quarter 2014.
Natural Gas Pipelines Segment
The natural gas pipelines segment reported third-quarter 2014 operating income of $36.2 million, compared with $35.2 million for the third quarter 2013, which reflects:
-- A $7.7 million increase from higher firm transportation revenues
resulting primarily from higher rates on its intrastate natural gas
pipelines, increased contracted capacity and rates at Midwestern Gas
Transmission Company and increased interruptible transportation revenues
from higher natural gas volumes transported;
-- A $1.0 million increase from additional storage services to meet utility
customers' peak-day demand; and
-- A $4.3 million decrease due to lower storage revenues from lower
contracted capacity.
Third-quarter 2014 equity earnings from investments were $14.4 million, compared with $16.5 million in the same period in 2013, due primarily to lower contracted capacity.
Operating income for the nine-month 2014 period was $128.7 million, compared with $102.9 million in the same period last year, which reflects:
-- A $21.5 million increase from higher firm transportation revenues
resulting primarily from higher rates on its intrastate natural gas
pipelines, increased contracted capacity and rates at Midwestern Gas
Transmission Company and increased interruptible transportation revenues
from higher natural gas volumes transported;
-- A $6.0 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 $5.9 million increase from higher net retained fuel due to higher
natural gas prices and additional natural gas volumes retained;
-- A $5.0 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 $2.6 million increase primarily from additional storage services to
meet utility customers' peak-day demand; and
-- A $10.0 million decrease due to lower storage revenues from lower
contracted capacity.
Equity earnings from investments for the nine-month 2014 period were $53.7 million, compared with $48.1 million for the same period last year, due primarily to increased park-and-loan services on Northern Border Pipeline as a result of increased weather-related seasonal demand in the first quarter 2014, offset partially by lower contracted capacity in the third quarter 2014.
Key Statistics: More detailed information is listed in the tables.
-- Natural gas transportation capacity contracted was 5,725 thousand
dekatherms per day in the third quarter 2014, up 5 percent compared with
the same period in 2013; and up 1 percent compared with the second
quarter 2014;
-- Natural gas transportation capacity subscribed was 90 percent in the
third quarter 2014, up 1 percent compared with the same period in 2013;
and unchanged from the second quarter 2014; and
-- The average natural gas price in the Mid-Continent region was $3.77 per
MMBtu in the third quarter 2014, up 10 percent compared with the same
period in 2013; and down 14 percent compared with the second quarter
2014.
CAPITAL-GROWTH ACTIVITIES:
The partnership has announced approximately $8.3 billion to $9.0 billion in capital-growth projects and acquisitions between 2010 and 2016, of which approximately $4.7 billion have been completed.
In addition, the partnership increased its unannounced project backlog to a range of $4 billion to $5 billion from its previous range of $3 billion to $4 billion.
Of the approximately $4.2 billion to $4.8 billion of announced capital-growth projects and acquisitions in the natural gas gathering and processing segment, projects totaling approximately $2.3 billion have been completed as follows:
Completed Project Location Capacity Approximate Completion Date
Costs (a)
--- --------
(In millions)
Rocky Mountain
Region
Garden Creek I
processing plant
and infrastructure Williston Basin 100 MMcf/d $360 December 2011
Stateline I & II
processing plants
and infrastructure Williston Basin 200 MMcf/d $565 September 2012/April 2013
Divide County
gathering system Williston Basin 270 miles $125 June 2013
Sage Creek
processing plant
and infrastructure
(b) Powder River Basin 50 MMcf/d $152 September 2013
Garden Creek II
processing plant
and infrastructure Williston Basin 100 MMcf/d $310-$345 August 2014
Garden Creek III
processing plant
and infrastructure Williston Basin 100 MMcf/d $325-$360 October 2014
------------------- --------------- ---------- --------- ------------
Mid-Continent
Region
30 percent interest
in Maysville
processing plant
(b) Cana-Woodford Shale 40 MMcf/d $90 December 2013
Canadian Valley
processing plant
and infrastructure Cana-Woodford Shale 200 MMcf/d $300 March 2014
------------------- ------------------- ---------- ---- ----------
(a) Excludes AFUDC.
(b) Acquisition.
Approximately $2.0 billion to $2.5 billion of announced capital-growth projects in the natural gas gathering and processing segment are in various stages of construction as follows:
Projects in
Progress Location Capacity Approximate Expected
Costs (a) Completion Date
--- --- --------- ---------------
(In millions)
Rocky Mountain Region
Lonesome Creek
processing plant
and infrastructure Williston Basin 200 MMcf/d $550-$680 Fourth quarter 2015
Sage Creek
infrastructure Powder River Basin Various $50 Fourth quarter 2015
Natural gas
compression Williston Basin 100 MMcf/d $80-$100 Fourth quarter 2015
Bear Creek
processing plant
and infrastructure Williston Basin 80 MMcf/d $230-$330 Second quarter 2016
Demicks Lake
processing plant
and infrastructure Williston Basin 200 MMcf/d $515-$670 Third quarter 2016
Bronco processing
plant and
infrastructure Powder River Basin 100 MMcf/d $170-$245 Third quarter 2016
----------------- ------------------ ---------- --------- ------------------
Mid-Continent Region
Knox processing
plant and
infrastructure SCOOP 200 MMcf/d $365-$470 Fourth quarter 2016
--------------- ----- ---------- --------- -------------------
(a) Excludes AFUDC.
Of the approximately $4.1 billion of announced capital-growth projects in the natural gas liquids segment, projects totaling approximately $2.4 billion have been completed as follows:
Completed Project Capacity Approximate Costs (a) Completion Date
----------------- -------- -------------------- ---------------
(In millions)
Sterling I
expansion 15 MBbl/d $30 November 2011
Cana-Woodford/
Granite Wash NGL
plant
connections 60 MBbl/d $220 April 2012
Bushton
fractionator
expansion 60 MBbl/d $117 September 2012
Bakken NGL
Pipeline 60 MBbl/d $455 April 2013
Overland Pass
Pipeline
expansion 45 MBbl/d $36 April 2013
Ethane Header
pipeline 250 MBbl/d $23 April 2013
Sage Creek NGL
infrastructure
(b) Various $153 September 2013
MB-2 Fractionator 75 MBbl/d $375 December 2013
Ethane/Propane
Splitter 40 MBbl/d $46 March 2014
Sterling III
Pipeline and
reconfigure
Sterling I and
II 193 MBbl/d $808 March 2014
Bakken NGL
Pipeline
expansion -
Phase I 75 MBbl/d $100 September 2014
Niobrara NGL
Lateral 90 miles $85 September 2014
------------ -------- --- --------------
(a) Excludes AFUDC.
(b) Acquisition.
Approximately $1.7 billion of announced capital-growth projects and acquisitions in the natural gas liquids segment are in various stages of completion, as follows:
Projects
in
Progress Capacity Approximate Costs (a) Expected Completion Date
-------- -------- -------------------- ------------------------
(In millions)
MB-3
Fractionator 75 MBbl/d $525-$575 Fourth quarter 2014
West
Texas
LPG
System
(b) 2,600 miles $800 Fourth quarter 2014
NGL
Pipeline
and
Hutchinson
Fractionator
infrastructure 95 miles $140 First quarter 2015
Bakken
NGL
Pipeline
expansion
-
Phase
II 25 MBbl/d $100 Second quarter 2016
Bronco
NGL
infrastructure 65 miles $45-$60 Third quarter 2016
Bear
Creek
NGL
infrastructure 40 miles $35-$45 Third quarter 2016
Demicks
Lake
NGL
infrastructure 12 miles $10-$15 Third quarter 2016
-------------- -------- ------- ------------------
(a) Excludes AFUDC.
(b) Acquisition.
EARNINGS CONFERENCE CALL AND WEBCAST:
ONEOK Partners and ONEOK executive management will conduct a joint conference call on Wednesday, Nov. 5, 2014, at 11 a.m. Eastern Standard Time (10 a.m. Central Standard Time). The call also will be carried live on ONEOK Partners' and ONEOK's websites.
To participate in the telephone conference call, dial 888-554-1424, pass code 6956087, 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 6956087.
LINK TO EARNINGS TABLES:
http://www.oneokpartners.com/~/media/ONEOKPartners/EarningsTables/2014/OKS_Q3_2014_earnings_82N7FW6.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, impairment charges, 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.
This news release references forward-looking estimates of annual adjusted EBITDA and adjusted EBITDA investment multiples projected to be generated by projects. A reconciliation of estimated adjusted EBITDA to GAAP net income is not provided because the GAAP net income generated by the individual projects is not available without unreasonable efforts.
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 38.3 percent of the overall partnership interest, as of Sept. 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 as defined under federal securities laws. The forward-looking statements relate to our anticipated financial performance (including projected operating income, net income, capital expenditures, cash flow and projected levels of distributions), liquidity, management's plans and objectives for our future growth projects and other future operations (including plans to construct additional natural gas and natural gas liquids pipelines and processing facilities and related cost estimates), our business prospects, the outcome of regulatory and legal proceedings, market conditions and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under federal securities legislation and other applicable laws. The following discussion is intended to identify important factors that could cause future outcomes to differ materially from those set forth in the forward-looking statements.
Forward-looking statements include the items identified in the preceding paragraph, the information concerning possible or assumed future results of our operations and other statements contained or incorporated in this news release identified by words such as "anticipate," "estimate," "expect," "project," "intend," "plan," "believe," "should," "goal," "forecast," "guidance," "could," "may," "continue," "might," "potential," "scheduled" and other words and terms of similar meaning.
One should not place undue reliance on forward-looking statements. Known and unknown risks, uncertainties and other factors may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by forward-looking statements. Those factors may affect our operations, markets, products, services and prices. In addition to any assumptions and other factors referred to specifically in connection with the forward-looking statements, factors that could cause our actual results to differ materially from those contemplated in any forward-looking statement include, among others, the following:
-- the effects of weather and other natural phenomena, including climate
change, on our operations, demand for our services and energy prices;
-- competition from other United States and foreign energy suppliers and
transporters, as well as alternative forms of energy, including, but not
limited to, solar power, wind power, geothermal energy and biofuels such
as ethanol and biodiesel;
-- the capital intensive nature of our businesses;
-- the profitability of assets or businesses acquired or constructed by us;
-- our ability to make cost-saving changes in operations;
-- risks of marketing, trading and hedging activities, including the risks
of changes in energy prices or the financial condition of our
counterparties;
-- the uncertainty of estimates, including accruals and costs of
environmental remediation;
-- the timing and extent of changes in energy commodity prices;
-- the effects of changes in governmental policies and regulatory actions,
including changes with respect to income and other taxes, pipeline
safety, environmental compliance, climate change initiatives and
authorized rates of recovery of natural gas and natural gas
transportation costs;
-- the impact on drilling and production by factors beyond our control,
including the demand for natural gas and crude oil; producers' desire
and ability to obtain necessary permits; reserve performance; and
capacity constraints on the pipelines that transport crude oil, natural
gas and NGLs from producing areas and our facilities;
-- difficulties or delays experienced by trucks 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 our most recent Annual Report on Form 10-K and in our other filings that we make with the Securities and Exchange Commission (SEC), which are available on the SEC's website at www.sec.gov. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. Any such forward-looking statement speaks only as of the date on which such statement is made, and, other than as required under securities laws, we undertake no obligation to update publicly any forward-looking statement whether as a result of new information, subsequent events or change in circumstances, expectations or otherwise.
Analyst Contact: T.D. Eureste
918-588-7167
Media Contact: Brad Borror
918-588-7582
SOURCE ONEOK Partners, L.P.
