THE WOODLANDS, Texas,
Nov. 8, 2018 /PRNewswire/
-- Summit Midstream Partners, LP (NYSE: SMLP) announced today
its financial and operating results for the three and nine months
ended September 30, 2018. SMLP
reported net income of $57.5 million
for the third quarter of 2018, compared to net income of
$93.6 million for the prior-year
period. Net income in the third quarter of 2018 included
$37.2 million of non-cash income
related to a decrease in the present value of the estimated
Deferred Purchase Price Obligation ("DPPO"). Net income for
the prior-year period included $70.5
million of non-cash income related to a decrease in the
present value of the estimated DPPO. Net cash provided by
operations totaled $56.4 million for
the third quarter of 2018, compared to $75.2
million for the prior-year period. Adjusted EBITDA
totaled $73.4 million and distributable cash flow ("DCF")
totaled $43.6 million for the third quarter of 2018, compared to
$73.5 million and $52.9 million, respectively, for the prior-year
period. Relative to the prior-year period, DCF in the third
quarter of 2018 included a $7.1
million distribution adjustment associated with our issuance
of Series A Preferred units in the fourth quarter of 2017 and
$2.9 million of higher maintenance
capital expenditures.
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Steve Newby, President and Chief
Executive Officer, commented, "SMLP reported another strong quarter
of operating and financial results in the third quarter of 2018,
primarily reflecting our Williston
customers' robust level of drilling and completion activity, which
generated liquids volume growth of nearly 31% compared to the third
quarter of 2017. Our business continues to perform in line
with our expectations and as such, we are reaffirming our 2018
adjusted EBITDA guidance of $285.0
million to $300.0 million and
full year 2018 distribution coverage of approximately 1.00x.
Producer activity levels in our service areas, amidst a
constructive fundamental backdrop, support our volume growth
expectations for the balance of 2018 and into 2019.
Additionally, our gathering and processing projects in the northern
Delaware and DJ Basin are expected
to provide meaningful growth for SMLP upon their commissioning this
quarter. We expect utilization of this new processing
capacity to increase significantly throughout 2019.
We expect to provide formal 2019 financial guidance in
February 2019, in accordance with our
annual budgeting process, with our fourth quarter of 2018 earnings
release. At this time, we are providing a preliminary view on
2019 adjusted EBITDA, which we expect will be at least 10% higher
compared to adjusted EBITDA in 2018. Our balance sheet and
liquidity position remain strong, and we expect that the forecasted
growth in adjusted EBITDA and DCF in 2019 will enable us to return
our distribution coverage ratio to levels in excess of 1.15x by the
fourth quarter of 2019.
Our Double E project continues to represent an important and
strategic project for SMLP, enabling us to provide a natural gas
transportation solution for XTO and other shippers in the northern
Delaware. We have successfully added additional shippers and
continue to engage in discussions with several other prospective
shippers on Double E. We remain on schedule for commercial
operation date in the second quarter of 2021."
SMLP reported net income of $3.7
million for the first nine months of 2018, compared to net
income of $104.3 million for the
prior-year period. Net cash provided by operations totaled
$166.5 million for the first nine
months of 2018, compared to $196.5
million in the prior-year period. SMLP reported
adjusted EBITDA of $217.2 million and
DCF of $134.9 million for the nine
months ended September 30, 2018,
compared to $217.5 million and
$155.8 million, respectively, for the
prior-year period.
Double E Pipeline Project Update
In July 2018, SMLP entered into a precedent
agreement with XTO Energy Inc. ("XTO"), a wholly owned subsidiary
of Exxon Mobil Corporation ("ExxonMobil"), for firm transportation
capacity on the Double E Pipeline Project ("Double E" or the
"Project") under a 10-year take-or-pay agreement which increases up
to 500,000 dekatherms per day ("dth/d"). In August and
September of 2018, SMLP conducted a binding open season process to
gauge market interest in the Project and obtain additional firm
transportation commitments on Double E. As a result of the
binding open season, SMLP executed additional precedent agreements
with new shippers and is continuing to discuss potential firm
volume commitments with other prospective shippers. SMLP
expects to make its final investment decision ("FID") on Double E
once these negotiations have concluded, given that the outcome of
these discussions could have a material impact on the scope of the
Project. The Project will provide up to 1.5 Bcf/d of residue
natural gas transportation capacity from the northern Delaware Basin to the Waha Hub.
SMLP remains on schedule for its original target in-service date
for the Project of the second quarter of 2021; however, the
ultimate in-service date of the Project will be subject to, among
other things, the timing of the FID and approval by the Federal
Energy Regulatory Commission ("FERC") and other governmental
authorities.
SMLP and ExxonMobil executed an equity option agreement in
July 2018, which provides ExxonMobil,
or an affiliate, the right to become an equity partner in Double
E. We expect ExxonMobil to make a decision on its equity
option agreement by June 30,
2019. SMLP has also received significant interest from other
potential shippers and financial parties regarding equity
participation in the Project.
Third Quarter 2018 Segment Results
Natural gas volume
throughput averaged 1,629 million cubic feet per day ("MMcf/d") in
the third quarter of 2018, a decrease of 10.8% compared to 1,826
MMcf/d in the prior-year period, and a decrease of 9.3% compared to
1,797 MMcf/d in the second quarter of 2018. SMLP's natural
gas volume throughput metrics exclude its proportionate share of
volume throughput from its 40% interest in Ohio Gathering, which
averaged 797 MMcf/d in the third quarter of 2018, an increase of
4.5% compared to 763 MMcf/d in the prior-year period.
Crude oil and produced water volume throughput in the third
quarter of 2018 averaged 96.9 thousand barrels per day ("Mbbl/d"),
an increase of 30.9% compared to 74.0 Mbbl/d in the prior-year
period, and an increase of 9.0% compared to 88.9 Mbbl/d in the
second quarter of 2018.
The following table presents average daily throughput by
reportable segment:
|
|
Three months ended
September 30,
|
|
|
Nine months ended
September 30,
|
|
|
|
2018
|
|
|
2017
|
|
|
2018
|
|
|
2017
|
|
Average daily
throughput (MMcf/d):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utica
Shale
|
|
|
357
|
|
|
|
403
|
|
|
|
376
|
|
|
|
364
|
|
Williston
Basin
|
|
|
19
|
|
|
|
21
|
|
|
|
18
|
|
|
|
19
|
|
Piceance/DJ
Basins
|
|
|
571
|
|
|
|
594
|
|
|
|
574
|
|
|
|
601
|
|
Barnett
Shale
|
|
|
232
|
|
|
|
254
|
|
|
|
253
|
|
|
|
270
|
|
Marcellus
Shale
|
|
|
450
|
|
|
|
554
|
|
|
|
499
|
|
|
|
490
|
|
Aggregate average
daily throughput
|
|
|
1,629
|
|
|
|
1,826
|
|
|
|
1,720
|
|
|
|
1,744
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average daily
throughput (Mbbl/d):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williston
Basin
|
|
|
96.9
|
|
|
|
74.0
|
|
|
|
90.9
|
|
|
|
74.7
|
|
Aggregate average
daily throughput
|
|
|
96.9
|
|
|
|
74.0
|
|
|
|
90.9
|
|
|
|
74.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ohio Gathering
average daily throughput
(MMcf/d) (1)
|
|
|
797
|
|
|
|
763
|
|
|
|
765
|
|
|
|
746
|
|
|
|
|
|
|
(1)
|
Gross basis,
represents 100% of volume throughput for Ohio Gathering, based on a
one-month lag.
|
Utica Shale
The Utica Shale reportable segment
includes Summit Midstream Utica ("SMU"), a natural gas gathering system located in
Belmont and Monroe counties in southeastern Ohio.
SMU gathers and delivers dry natural
gas to interconnections with a third-party intrastate pipeline that
provides access to the Clarington Hub.
Segment adjusted EBITDA for the third quarter of 2018 totaled
$6.5 million, a decrease of 22.5%
from $8.4 million for the prior-year
period and a decrease of 29.3% from $9.2
million in the second quarter of 2018. Total volume
throughput averaged 357 MMcf/d in the third quarter of 2018,
compared to 403 MMcf/d in the prior-year period and 415 MMcf/d in
the second quarter of 2018. Volumes were lower in the third
quarter of 2018 compared to both the prior-year period and the
second quarter of 2018 primarily due to natural production
declines, together with an estimated 40 MMcf/d of temporary volume
curtailments related to infill drilling and completion activities
on existing pad sites. Volume throughput on the TPL-7
Connector project, which generates a lower gathering margin
compared to volumes gathered directly from a pad site, totaled 148
MMcf/d in the third quarter of 2018, compared to 74 MMcf/d in the
prior year period and 124 MMcf/d in the second quarter of
2018.
Our customers are currently operating one drilling rig upstream
of the SMU system. One SMU
customer has recently communicated its intent to increase drilling
activities in the liquids-rich and condensate windows of the Utica
Shale in 2018 and 2019, versus SMU's
dry gas service area. This shift is expected to negatively
impact the rate of volume and segment adjusted EBITDA growth in
2019, compared to previous expectations, but should serve as a
positive catalyst for SMLP's Ohio Gathering reportable
segment. Because SMU is an asset that is included in the DPPO
calculation, we have reflected such slower 2019 growth expectations
in the estimated future value of the DPPO as of September 30, 2018.
Ohio Gathering
The Ohio Gathering reportable segment
includes our 40% ownership interest in Ohio Gathering, a natural
gas gathering system spanning the condensate, liquids-rich and dry
gas windows of the Utica Shale in Harrison, Guernsey, Noble, Belmont and Monroe
counties in southeastern Ohio. This segment also includes our
40% ownership interest in Ohio Condensate, a condensate
stabilization facility located in Harrison County, Ohio. Segment adjusted
EBITDA for the Ohio Gathering segment includes our proportional
share of adjusted EBITDA from Ohio Gathering and Ohio Condensate,
based on a one-month lag.
Segment adjusted EBITDA for the third quarter of 2018 totaled
$10.2 million, a decrease of 3.3%
from $10.5 million for the prior-year
period and an increase of 13.8% from $8.9
million for the second quarter of 2018. Volume
throughput on the Ohio Gathering system averaged 797 MMcf/d, gross,
in the third quarter of 2018, compared to 763 MMcf/d, gross, in the
prior-year period and 727 MMcf/d, gross, in the second quarter of
2018. Higher volumes in the third quarter of 2018 were a
result of 20 new wells that were connected late in the second
quarter of 2018 and 20 new wells that were connected in the third
quarter of 2018.
Producer activity levels on the Ohio Gathering system have
steadily increased throughout 2018, particularly in the areas that
serve the rich gas and condensate windows of the Utica Shale, which
have generated attractive well results as a result of improved
drilling and completion techniques and higher commodity
prices. Our customers are currently operating three drilling
rigs upstream of the Ohio Gathering system.
Williston Basin
The
Polar and Divide, Tioga Midstream
and Bison Midstream systems provide our midstream services for the
Williston Basin reportable
segment. The Polar and Divide system gathers crude oil in
Williams and Divide counties in North Dakota and delivers to third-party
intra- and interstate pipelines as well as third-party rail
terminals. The Polar and Divide system also gathers and delivers
produced water to various third-party disposal wells in the
region. Tioga Midstream is a crude oil, produced water and
associated natural gas gathering system in Williams County, North Dakota. All crude
oil and natural gas gathered on the Tioga Midstream system is
delivered to third-party pipelines, and all produced water is
delivered to third-party disposal wells. Bison Midstream
gathers associated natural gas production in Mountrail and Burke counties in North Dakota and delivers to third-party
pipelines serving a third-party processing plant in Channahon,
Illinois.
Segment adjusted EBITDA for the Williston Basin segment totaled $19.8 million for the third quarter of 2018, an
increase of 22.4% compared to $16.2
million for the prior-year period and an increase of 4.3%
from $19.0 million for the second
quarter of 2018. The increase over the second quarter of 2018
primarily resulted from 20 new well connections in the period,
which generated higher liquids volume throughput, primarily across
the Polar and Divide system.
Six of these new wells were drilled by a new customer that executed
a gathering agreement with SMLP in the third quarter of
2017.
Liquids volumes averaged 96.9 Mbbl/d in the third quarter of
2018, a new quarterly record for SMLP. Third quarter 2018
volumes represented an increase of 30.9% from 74.0 Mbbl/d in the
prior-year period and an increase of 9.0% compared to 88.9 Mbbl/d
in the second quarter of 2018. Segment adjusted EBITDA in the
third quarter of 2018 was negatively impacted by an estimated 12.0
Mbbl/d resulting from (i) certain customers initiating temporary
production curtailments on existing wells for nearby drilling and
completion activities, and (ii) produced water capacity constraints
at third party disposal wells, which necessitated third-party
trucking service.
Associated natural gas volumes averaged 19 MMcf/d in the third
quarter of 2018, a decrease of 9.5% from the prior-year period, and
a 5.6% increase from the second quarter of 2018. Six new
associated natural gas wells were connected to our Williston gathering systems in the third
quarter of 2018, four of which were drilled by a new customer that
executed a gathering agreement with SMLP in the third quarter of
2018.
Our Williston Basin segment
continues to benefit from consistent drilling activity and
improving wells results from our customers. Currently, our
customers are operating three drilling rigs upstream of the systems
that comprise our Williston Basin
reportable segment. In addition, our quarterly financial and
operating results have been impacted by recent commercial successes
and our execution of several new gathering agreements in the last
twelve months. We expect that the combination of these
activities will generate continued volume throughput and segment
adjusted EBITDA growth for our Williston Basin segment in the near- and
intermediate-term.
Piceance/DJ Basins
The Grand River and the Niobrara
G&P systems provide our midstream services for the Piceance/DJ
Basins reportable segment. These systems provide natural gas
gathering and processing services for producers operating in the
Piceance Basin located in western Colorado and eastern Utah and in the Denver-Julesburg ("DJ") Basin located in northeastern
Colorado.
Segment adjusted EBITDA totaled $29.8
million for the third quarter of 2018, in line with
$30.0 million in the prior-year
period and an increase of 7.8% from $27.7
million in the second quarter of 2018. The Piceance/DJ
Basins reportable segment generated $1.2
million of lower G&A expense in the third quarter of
2018, compared to the second quarter of 2018, primarily due to
certain expense reimbursement activities. Third quarter 2018
volume throughput averaged 571 MMcf/d, a decrease of 3.9% from 594
MMcf/d in the prior-year period and in line with the 576 MMcf/d in
the second quarter of 2018. Volume declines relative to the
prior-year period were partially offset by the completion of 39 new
wells in the third quarter of 2018, including 23 new wells upstream
of the Niobrara G&P system in the DJ Basin, which generates
higher margin revenue compared to the Grand River system. In
the third quarter of 2018, the Niobrara G&P system operated at
approximately 85% utilization, including approximately 95%
utilization in September 2018.
Volume throughput on the Niobrara G&P system will be
constrained by our current 20 MMcf/d of processing capacity until
our new 60 MMcf/d processing plant is commissioned, which is
expected to occur in the fourth quarter of 2018. Currently,
our Piceance/DJ segment customers are operating four drilling rigs,
all of which are working upstream of the Niobrara G&P system,
and we expect significant drilling and completion activity to
continue in and around this system's service area throughout
2019.
Barnett Shale
The DFW Midstream system provides
our midstream services for the Barnett Shale reportable
segment. This system gathers and delivers low-pressure
natural gas received from pad sites, primarily located in
southeastern Tarrant County,
Texas, to downstream intrastate pipelines serving various
natural gas hubs in the region.
Segment adjusted EBITDA for the Barnett Shale segment totaled
$10.8 million for the third quarter
of 2018, in line with $10.8 million
in the prior-year period and a 2.5% decrease from $11.1 million in the second quarter of
2018. Volume throughput in the third quarter of 2018 averaged
232 MMcf/d, which was down 8.7% compared to the prior-year period
of 254 MMcf/d and down 12.1% from 264 MMcf/d in the second quarter
of 2018. Volume throughput in the third quarter of 2018 was
negatively affected by temporary curtailments associated with
simultaneous drilling and completion activities, together with our
required annual regulatory system shutdown, which resulted in
limited volumes for approximately five days in September.
Collectively, these activities impacted volume throughput in the
third quarter of 2018 by an estimated 15 MMcf/d. In addition,
we recognized an approximate $1.0
million net impact to adjusted EBITDA in the third quarter
of 2018, related to a customer's estimated MVC shortfall payment
due in October 2019.
Drilling and well permitting activities in our DFW Midstream
system service area have remained relatively steady throughout
2018. A customer completed five new wells on the DFW
Midstream system late in the quarter, which increased third quarter
exit rate volumes to approximately 260 MMcf/d. We expect four
new well connections by a separate customer by the end of the 2018,
which we expect will have a positive impact on volume throughput in
the first quarter of 2019.
Marcellus Shale
The Mountaineer Midstream system
provides our midstream services for the Marcellus Shale reportable
segment. This system gathers high-pressure natural gas received
from upstream pipeline interconnections with Antero Midstream
Partners, LP and Crestwood Equity Partners LP. Natural gas on
the Mountaineer Midstream system is delivered to the Sherwood
Processing Complex located in Doddridge County, West
Virginia.
Segment adjusted EBITDA for the Marcellus Shale segment totaled
$5.6 million for the third quarter of
2018, a decrease of 16.9% from $6.7
million for the prior-year period and a decrease of 15.2%
from $6.5 million for the second
quarter of 2018. Segment adjusted EBITDA was lower in the
third quarter of 2018 primarily due to a decrease in volume
throughput, which averaged 450 MMcf/d in the third quarter of 2018,
compared to 554 MMcf/d in the prior-year period and 524 MMcf/d in
the second quarter of 2018. Volume throughput was lower in
the third quarter of 2018 due to natural production declines,
primarily related to the 27 wells that were commissioned upstream
of the Mountaineer Midstream system in 2017 and an additional 9
wells commissioned in the first quarter of 2018.
No new wells were completed in the second or third quarters of
2018, and no new wells are expected for the remainder of 2018.
MVC Shortfall Payments
SMLP billed its customers
$12.4 million in the third quarter of
2018 related to MVC shortfalls. For those customers that do
not have credit banking mechanisms in their gathering agreements,
or do not have the ability to use MVC shortfall payments as
credits, the MVC shortfall payments are accounted for as gathering
revenue in the period in which they are earned.
In the third quarter of 2018, SMLP recognized $18.8 million of gathering revenue associated
with MVC shortfall payments from certain customers in each of its
reportable segments. SMLP also recognized ($3.0) million of adjustments to MVC shortfall
payments in the third quarter of 2018, primarily in the Barnett
Shale segment, which adjusts downward approximately 70% of a
certain customer's aggregate estimated MVC shortfall payment due in
October 2019. SMLP recognized
approximately $6.0 million of this
Barnett Shale customer's estimated aggregate MVC shortfall payment
as gathering revenue in the third quarter of 2018, and will
continue to recognize MVC shortfall payment gathering revenue
associated with this expected MVC shortfall payment, on a ratable
basis, until it is due and fully recognized, in the fourth quarter
of 2019. SMLP's MVC shortfall payment mechanisms contributed
$15.8 million of adjusted EBITDA in
the third quarter of 2018.
|
Three months ended
September 30, 2018
|
|
|
MVC
Billings
|
|
|
|
Gathering
revenue
|
|
|
Adjustments to MVC
shortfall payments
|
|
|
Net impact to
adjusted EBITDA
|
|
|
(In
thousands)
|
|
Net change in
deferred revenue related to MVC shortfall payments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utica
Shale
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Williston
Basin
|
|
—
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
Piceance/DJ
Basins
|
|
3,416
|
|
|
|
|
3,416
|
|
|
|
—
|
|
|
|
3,416
|
|
Barnett
Shale
|
|
—
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
Marcellus
Shale
|
|
—
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
Total net
change
|
$
|
3,416
|
|
|
|
$
|
3,416
|
|
|
$
|
—
|
|
|
$
|
3,416
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MVC shortfall
payment adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utica
Shale
|
$
|
(82)
|
|
|
|
$
|
(82)
|
|
|
$
|
—
|
|
|
$
|
(82)
|
|
Williston
Basin
|
|
765
|
|
|
|
|
765
|
|
|
|
2,032
|
|
|
|
2,797
|
|
Piceance/DJ
Basins
|
|
7,210
|
|
|
|
|
7,500
|
|
|
|
—
|
|
|
|
7,500
|
|
Barnett
Shale
|
|
—
|
|
|
|
|
6,114
|
|
|
|
(5,031)
|
|
|
|
1,083
|
|
Marcellus
Shale
|
|
1,049
|
|
|
|
|
1,049
|
|
|
|
—
|
|
|
|
1,049
|
|
Total MVC shortfall
payment adjustments
|
$
|
8,942
|
|
|
|
$
|
15,346
|
|
|
$
|
(2,999)
|
|
|
$
|
12,347
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
(1)
|
$
|
12,358
|
|
|
|
$
|
18,762
|
|
|
$
|
(2,999)
|
|
|
$
|
15,763
|
|
|
|
|
|
|
(1)
|
Exclusive of Ohio
Gathering due to equity method accounting.
|
|
Nine months ended
September 30, 2018
|
|
|
MVC
Billings
|
|
|
|
Gathering
revenue
|
|
|
Adjustments to MVC
shortfall payments
|
|
|
Net impact to
adjusted EBITDA
|
|
|
(In
thousands)
|
|
Net change in
deferred revenue related to MVC shortfall payments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utica
Shale
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Williston
Basin
|
|
—
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
Piceance/DJ
Basins
|
|
10,363
|
|
|
|
|
10,363
|
|
|
|
—
|
|
|
|
10,363
|
|
Barnett
Shale
|
|
—
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
Marcellus
Shale
|
|
—
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
Total net
change
|
$
|
10,363
|
|
|
|
$
|
10,363
|
|
|
$
|
—
|
|
|
$
|
10,363
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MVC shortfall
payment adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utica
Shale
|
$
|
49
|
|
|
|
$
|
49
|
|
|
$
|
—
|
|
|
$
|
49
|
|
Williston
Basin
|
|
2,250
|
|
|
|
|
9,698
|
|
|
|
(1,354)
|
|
|
|
8,344
|
|
Piceance/DJ
Basins
|
|
20,765
|
|
|
|
|
21,727
|
|
|
|
(93)
|
|
|
|
21,634
|
|
Barnett
Shale
|
|
—
|
|
|
|
|
6,393
|
|
|
|
(5,094)
|
|
|
|
1,299
|
|
Marcellus
Shale
|
|
3,112
|
|
|
|
|
3,112
|
|
|
|
—
|
|
|
|
3,112
|
|
Total MVC shortfall
payment adjustments
|
$
|
26,176
|
|
|
|
$
|
40,979
|
|
|
$
|
(6,541)
|
|
|
$
|
34,438
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
(1)
|
$
|
36,539
|
|
|
|
$
|
51,342
|
|
|
$
|
(6,541)
|
|
|
$
|
44,801
|
|
|
|
|
|
|
(1)
|
Exclusive of Ohio
Gathering due to equity method accounting.
|
Capital Expenditures
Capital expenditures totaled
$46.6 million in the third quarter of
2018, including maintenance capital expenditures of approximately
$6.4 million. Development
activities during the third quarter of 2018 were primarily related
to the ongoing construction and development of associated natural
gas gathering and processing infrastructure in the Delaware and DJ basins. We expect the 60
MMcf/d northern Delaware gathering
and processing system and the 60 MMcf/d processing plant expansion
in the DJ to be commissioned in the fourth quarter of 2018.
Capital & Liquidity
As of September 30, 2018, SMLP had $866.0 million of available borrowing capacity
under its $1.25 billion revolving
credit facility, subject to covenant limits. Based upon the
terms of SMLP's revolving credit facility and total outstanding
debt of $1.18 billion (inclusive of
$800.0 million of senior unsecured
notes), SMLP's total leverage ratio and senior secured leverage
ratio (as defined in the credit agreement) as of September 30, 2018, were 4.02 to 1.0 and 1.31
to 1.0, respectively.
Deferred Purchase Price Obligation
SMLP lowered the
estimated undiscounted amount of the Deferred Purchase Price
Obligation related to the 2016 Drop Down transaction from
$538.4 million at June 30, 2018, to $470.9
million at September 30,
2018. The decrease is primarily related to a decrease in the
number of well connections expected upstream of the SMU gathering system in 2019 from one of our two
primary customers, which, relative to our previous estimate,
results in lower projected volume throughput and Business Adjusted
EBITDA in 2019. This slower expected pace of activity is
expected to be partially offset by the same customer's decision to
shift drilling to the condensate and liquids-rich gas acreage
serviced by the Ohio Gathering system.
Subsequent to September 30, 2018,
SMLP received additional information from customers on our Utica
Shale, Ohio Gathering and Williston Basin segments. The impact of
this new information would result in a decrease to the calculation
of the undiscounted value of the Deferred Purchase Price Obligation
of approximately $16.9 million, from
$470.9 million to $454.0 million.
The consideration for the 2016 Drop Down consisted of (i) an
initial $360.0 million cash payment
(the "Initial Payment") which was funded on March 3, 2016, with borrowings under SMLP's
revolving credit facility and (ii) a deferred payment which will be
paid no later than December 31, 2020
(the "Deferred Purchase Price Obligation," "DPPO" or "Deferred
Payment," as defined below). At the discretion of the board
of directors of SMLP's general partner, the Deferred Payment can be
made in either cash or SMLP common units, or a combination
thereof.
The Deferred Payment will be equal to: (a) six-and-one-half
(6.5) multiplied by the average Business Adjusted EBITDA of the
2016 Drop Down Assets for 2018 and 2019, less the G&A Adjuster,
as defined in the Contribution Agreement; less (b) the Initial
Payment; less (c) all capital expenditures incurred for the 2016
Drop Down Assets between March 3, 2016 and December 31, 2019; plus
(d) all Business Adjusted EBITDA from the 2016 Drop Down Assets
between March 3, 2016 and December 31, 2019, less the Cumulative
G&A Adjuster, as defined in the Contribution
Agreement.
The Deferred Payment calculation was designed to ensure that,
during the deferral period, all of the EBITDA growth and capex
development risk associated with the 2016 Drop Down Assets is held
by the GP, Summit Investments. The Deferred Payment was
structured such that SMLP will ultimately pay a 6.5x multiple of
the actual average EBITDA generated from the 2016 Drop Down Assets
in 2018 and 2019.
SMLP Financial Guidance
SMLP is reaffirming its 2018
adjusted EBITDA financial guidance range of $285.0 million to
$300.0 million and capex guidance
range, including contributions to equity method investees, of
$175.0 million to $225.0 million. SMLP continues to expect to
incur maintenance capex of $15.0 million to $20.0 million in 2018. SMLP expects to
report an average full year 2018 distribution coverage ratio of
approximately 1.00x.
SMLP is also introducing its preliminary view with respect to
2019 financial guidance, including targeted adjusted EBITDA growth
of at least 10% over 2018. SMLP expects its 2019 distribution
coverage ratio to expand generally in line with adjusted EBITDA
growth throughout 2019 with targeted levels in excess of 1.15x by
the fourth quarter of 2019.
Quarterly Distribution
On October 25, 2018, the board of directors of
SMLP's general partner declared a quarterly cash distribution of
$0.575 per unit on all of its
outstanding common units, or $2.30
per unit on an annualized basis, for the quarter ended September 30, 2018. This quarterly
distribution remains unchanged from the previous quarter and from
the quarter ended September 30,
2017. This distribution will be paid on November 14, 2018, to unitholders of record as of
the close of business on November 7,
2018.
Third Quarter 2018 Earnings Call Information
SMLP
will host a conference call at 10:00
a.m. Eastern on Friday, November 9,
2018, to discuss its quarterly operating and financial
results. Interested parties may participate in the call by
dialing 847-585-4405 or toll-free 888-771-4371 and entering the
passcode 47745266. The conference call will also be webcast
live and can be accessed through the Investors section of SMLP's
website at www.summitmidstream.com.
A replay of the conference call will be available until
November 23, 2018, at 11:59 p.m. Eastern, and can be accessed by
dialing 888-843-7419 and entering the replay passcode
47745266#. An archive of the conference call will also be
available on SMLP's website.
Upcoming Investor Conferences
Members of SMLP's
senior management team will participate in RBC Capital Markets'
2018 Midstream Conference in Dallas,
Texas on November 13, 2018 and
November 14, 2018, and in the Wells
Fargo Pipeline, MLP and Utility Symposium in New York, New York on December 5, 2018 and December 6, 2018. The presentation
materials associated with these events will be accessible through
the Investors section of SMLP's website at www.summitmidstream.com
prior to the beginning of each conference.
Use of Non-GAAP Financial Measures
We report
financial results in accordance with U.S. generally accepted
accounting principles ("GAAP"). We also present adjusted EBITDA and
distributable cash flow, each a non-GAAP financial measure.
We define adjusted EBITDA as net income or loss, plus interest
expense, income tax expense, depreciation and amortization, our
proportional adjusted EBITDA for equity method investees,
adjustments related to MVC shortfall payments, adjustments related
to capital reimbursement activity, unit-based and noncash
compensation, the change in the Deferred Purchase Price Obligation
fair value, early extinguishment of debt expense, impairments and
other noncash expenses or losses, less interest income, income tax
benefit, income (loss) from equity method investees and other
noncash income or gains. We define distributable cash flow as
adjusted EBITDA plus cash interest received and cash taxes
received, less cash interest paid, senior notes interest
adjustment, distributions to Series A Preferred unitholders, Series
A Preferred units distribution adjustment, cash taxes paid and
maintenance capital expenditures. Because adjusted EBITDA and
distributable cash flow may be defined differently by other
entities in our industry, our definitions of these non-GAAP
financial measures may not be comparable to similarly titled
measures of other entities, thereby diminishing their utility.
Management uses these non-GAAP financial measures in making
financial, operating and planning decisions and in evaluating our
financial performance. Furthermore, management believes that
these non-GAAP financial measures may provide external users of our
financial statements, such as investors, commercial banks, research
analysts and others, with additional meaningful comparisons between
current results and results of prior periods as they are expected
to be reflective of our core ongoing business.
Adjusted EBITDA and distributable cash flow are used as
supplemental financial measures by external users of our financial
statements such as investors, commercial banks, research analysts
and others.
Adjusted EBITDA is used to assess:
- the ability of our assets to generate cash sufficient to make
cash distributions and support our indebtedness;
- the financial performance of our assets without regard to
financing methods, capital structure or historical cost basis;
- our operating performance and return on capital as compared to
those of other entities in the midstream energy sector, without
regard to financing or capital structure;
- the attractiveness of capital projects and acquisitions and the
overall rates of return on alternative investment opportunities;
and
- the financial performance of our assets without regard to (i)
income or loss from equity method investees, (ii) the impact of the
timing of minimum volume commitments shortfall payments under our
gathering agreements or (iii) the timing of impairments or other
noncash income or expense items.
Distributable cash flow is used to assess:
- the ability of our assets to generate cash sufficient to make
future cash distributions and
- the attractiveness of capital projects and acquisitions and the
overall rates of return on alternative investment
opportunities.
Both of these measures have limitations as analytical tools and
investors should not consider them in isolation or as a substitute
for analysis of our results as reported under GAAP. For
example:
- certain items excluded from adjusted EBITDA and distributable
cash flow are significant components in understanding and assessing
an entity's financial performance, such as an entity's cost of
capital and tax structure;
- adjusted EBITDA and distributable cash flow do not reflect our
cash expenditures or future requirements for capital expenditures
or contractual commitments;
- adjusted EBITDA and distributable cash flow do not reflect
changes in, or cash requirements for, our working capital needs;
and
- although depreciation and amortization are noncash charges, the
assets being depreciated and amortized will often have to be
replaced in the future, and adjusted EBITDA and distributable cash
flow do not reflect any cash requirements for such
replacements.
We compensate for the limitations of adjusted EBITDA and
distributable cash flow as analytical tools by reviewing the
comparable GAAP financial measures, understanding the differences
between the financial measures and incorporating these data points
into our decision-making process. Reconciliations of GAAP to
non-GAAP financial measures are attached to this press release.
We do not provide the GAAP financial measures of net income or
loss or net cash provided by operating activities on a
forward-looking basis because we are unable to predict, without
unreasonable effort, certain components thereof including, but not
limited to, (i) income or loss from equity method investees, (ii)
deferred purchase price obligation and (iii) asset
impairments. These items are inherently uncertain and depend
on various factors, many of which are beyond our control. As
such, any associated estimate and its impact on our GAAP
performance and cash flow measures could vary materially based on a
variety of acceptable management assumptions.
About Summit Midstream Partners, LP
SMLP is a
growth-oriented limited partnership focused on developing, owning
and operating midstream energy infrastructure assets that are
strategically located in the core producing areas of unconventional
resource basins, primarily shale formations, in the continental
United States. SMLP provides
natural gas, crude oil and produced water gathering services
pursuant to primarily long-term and fee-based gathering and
processing agreements with customers and counterparties in five
unconventional resource basins: (i) the Appalachian Basin, which
includes the Marcellus and Utica
shale formations in West Virginia
and Ohio; (ii) the Williston Basin, which includes the Bakken and
Three Forks shale formations in North
Dakota; (iii) the Fort
Worth Basin, which includes the Barnett Shale formation in
Texas; (iv) the Piceance Basin,
which includes the Mesaverde formation as well as the Mancos and Niobrara shale formations in
Colorado and Utah; and (v) the Denver-Julesburg Basin,
which includes the Niobrara and Codell shale formations in
Colorado and Wyoming. SMLP
is in the process of developing new gathering and processing
infrastructure in a sixth basin, the Delaware Basin, in New Mexico. SMLP also owns substantially
all of a 40% ownership interest in Ohio Gathering, which is
developing natural gas gathering and condensate stabilization
infrastructure in the Utica Shale in Ohio. SMLP is headquartered in The Woodlands, Texas, with regional corporate
offices in Denver, Colorado,
Atlanta, Georgia, Pittsburgh, Pennsylvania and Dallas, Texas.
About Summit Midstream Partners, LLC
Summit Midstream
Partners, LLC ("Summit Investments") beneficially owns a 35.2%
limited partner interest in SMLP and indirectly owns and controls
the general partner of SMLP, Summit Midstream GP, LLC, which has
sole responsibility for conducting the business and managing the
operations of SMLP. Summit Investments is a privately held company
controlled by Energy Capital Partners II, LLC, and certain of its
affiliates. An affiliate of Energy Capital Partners II, LLC
directly owns an 8.1% limited partner interest in SMLP.
Forward-Looking Statements
This press release
includes certain statements concerning expectations for the future
that are forward-looking within the meaning of the federal
securities laws. Forward-looking statements contain known and
unknown risks and uncertainties (many of which are difficult to
predict and beyond management's control) that may cause SMLP's
actual results in future periods to differ materially from
anticipated or projected results. An extensive list of
specific material risks and uncertainties affecting SMLP is
contained in its 2017 Annual Report on Form 10-K filed with the
Securities and Exchange Commission on February 26, 2018, and as amended and updated
from time to time. Any forward-looking statements in this press
release, including forward-looking statements regarding preliminary
2019 financial guidance or financial or operating expectations for
2019, are made as of the date of this press release and SMLP
undertakes no obligation to update or revise any forward-looking
statements to reflect new information or events.
We do not provide the GAAP financial measures of net income
or loss or net cash provided by operating activities on a
forward-looking basis because we are unable to predict, without
unreasonable effort, certain components thereof including, but not
limited to, (i) income or loss from equity method investees, (ii)
deferred purchase price obligation and (iii) asset
impairments. These items are inherently uncertain and depend
on various factors, many of which are beyond our control. As
such, any associated estimate and its impact on our GAAP
performance and cash flow measures could vary materially based on a
variety of acceptable management assumptions.
SUMMIT MIDSTREAM
PARTNERS, LP AND SUBSIDIARIES
|
UNAUDITED
CONDENSED CONSOLIDATED BALANCE SHEETS
|
|
|
|
September 30,
|
|
|
December 31,
|
|
|
|
2018
|
|
|
2017
|
|
|
|
(In
thousands)
|
|
Assets
|
|
|
|
|
|
|
|
|
Current
assets:
|
|
|
|
|
|
|
|
|
Cash and cash
equivalents
|
|
$
|
370
|
|
|
$
|
1,430
|
|
Accounts
receivable
|
|
|
85,458
|
|
|
|
72,301
|
|
Other current
assets
|
|
|
4,360
|
|
|
|
4,327
|
|
Total
current assets
|
|
|
90,188
|
|
|
|
78,058
|
|
Property, plant and
equipment, net
|
|
|
1,911,630
|
|
|
|
1,795,129
|
|
Intangible assets,
net
|
|
|
281,207
|
|
|
|
301,345
|
|
Goodwill
|
|
|
16,211
|
|
|
|
16,211
|
|
Investment in equity
method investees
|
|
|
660,254
|
|
|
|
690,485
|
|
Other noncurrent
assets
|
|
|
18,566
|
|
|
|
13,565
|
|
Total
assets
|
|
$
|
2,978,056
|
|
|
$
|
2,894,793
|
|
|
|
|
|
|
|
|
|
|
Liabilities and
Partners' Capital
|
|
|
|
|
|
|
|
|
Current
liabilities:
|
|
|
|
|
|
|
|
|
Trade accounts
payable
|
|
$
|
22,569
|
|
|
$
|
16,375
|
|
Accrued
expenses
|
|
|
18,347
|
|
|
|
12,499
|
|
Due to
affiliate
|
|
|
13
|
|
|
|
1,088
|
|
Deferred
revenue
|
|
|
11,152
|
|
|
|
4,000
|
|
Ad valorem taxes
payable
|
|
|
8,223
|
|
|
|
8,329
|
|
Accrued
interest
|
|
|
15,285
|
|
|
|
12,310
|
|
Accrued environmental
remediation
|
|
|
2,702
|
|
|
|
3,130
|
|
Other current
liabilities
|
|
|
10,388
|
|
|
|
11,258
|
|
Total
current liabilities
|
|
|
88,679
|
|
|
|
68,989
|
|
Long-term
debt
|
|
|
1,175,313
|
|
|
|
1,051,192
|
|
Deferred Purchase
Price Obligation
|
|
|
416,718
|
|
|
|
362,959
|
|
Noncurrent deferred
revenue
|
|
|
39,624
|
|
|
|
12,707
|
|
Noncurrent accrued
environmental remediation
|
|
|
1,182
|
|
|
|
2,214
|
|
Other noncurrent
liabilities
|
|
|
5,525
|
|
|
|
7,063
|
|
Total
liabilities
|
|
|
1,727,041
|
|
|
|
1,505,124
|
|
|
|
|
|
|
|
|
|
|
Series A Preferred
Units
|
|
|
300,741
|
|
|
|
294,426
|
|
Common limited
partner capital
|
|
|
913,913
|
|
|
|
1,056,510
|
|
General Partner
interests
|
|
|
25,380
|
|
|
|
27,920
|
|
Noncontrolling
interest
|
|
|
10,981
|
|
|
|
10,813
|
|
Total partners'
capital
|
|
|
1,251,015
|
|
|
|
1,389,669
|
|
Total liabilities and
partners' capital
|
|
$
|
2,978,056
|
|
|
$
|
2,894,793
|
|
SUMMIT MIDSTREAM
PARTNERS, LP AND SUBSIDIARIES
|
UNAUDITED
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
|
|
|
|
Three months ended
September 30,
|
|
|
Nine months ended
September 30,
|
|
|
|
2018
|
|
|
2017
|
|
|
2018
|
|
|
2017
|
|
|
|
(In thousands,
except per-unit amounts)
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering services
and related fees
|
|
$
|
86,427
|
|
|
$
|
96,070
|
|
|
$
|
260,373
|
|
|
$
|
298,884
|
|
Natural gas, NGLs and
condensate sales
|
|
|
34,017
|
|
|
|
22,940
|
|
|
|
92,025
|
|
|
|
44,655
|
|
Other
revenues
|
|
|
7,035
|
|
|
|
5,935
|
|
|
|
20,584
|
|
|
|
19,003
|
|
Total
revenues
|
|
|
127,479
|
|
|
|
124,945
|
|
|
|
372,982
|
|
|
|
362,542
|
|
Costs and
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of natural gas
and NGLs
|
|
|
26,879
|
|
|
|
18,177
|
|
|
|
71,549
|
|
|
|
36,328
|
|
Operation and
maintenance
|
|
|
24,382
|
|
|
|
22,303
|
|
|
|
73,452
|
|
|
|
70,011
|
|
General and
administrative
|
|
|
11,740
|
|
|
|
13,289
|
|
|
|
39,666
|
|
|
|
40,370
|
|
Depreciation and
amortization
|
|
|
26,743
|
|
|
|
28,927
|
|
|
|
80,204
|
|
|
|
86,184
|
|
Transaction
costs
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
119
|
|
Loss (gain) on asset
sales, net
|
|
|
6
|
|
|
|
460
|
|
|
|
(6)
|
|
|
|
530
|
|
Long-lived asset
impairment
|
|
|
1,540
|
|
|
|
1,290
|
|
|
|
2,127
|
|
|
|
1,577
|
|
Total costs and
expenses
|
|
|
91,290
|
|
|
|
84,446
|
|
|
|
266,992
|
|
|
|
235,119
|
|
Other
income
|
|
|
58
|
|
|
|
79
|
|
|
|
78
|
|
|
|
214
|
|
Interest
expense
|
|
|
(14,862)
|
|
|
|
(17,614)
|
|
|
|
(44,821)
|
|
|
|
(51,883)
|
|
Early extinguishment
of debt
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
(22,020)
|
|
Deferred Purchase
Price Obligation
|
|
|
37,204
|
|
|
|
70,499
|
|
|
|
(53,759)
|
|
|
|
54,674
|
|
Income before income
taxes and (loss) income from
equity method investees
|
|
|
58,589
|
|
|
|
93,463
|
|
|
|
7,488
|
|
|
|
108,408
|
|
Income tax benefit
(expense)
|
|
|
35
|
|
|
|
(176)
|
|
|
|
(88)
|
|
|
|
(417)
|
|
(Loss) income from
equity method investees
|
|
|
(1,169)
|
|
|
|
350
|
|
|
|
(3,703)
|
|
|
|
(3,691)
|
|
Net income
|
|
$
|
57,455
|
|
|
$
|
93,637
|
|
|
$
|
3,697
|
|
|
$
|
104,300
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss)
per limited partner unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common unit –
basic
|
|
$
|
0.64
|
|
|
$
|
1.23
|
|
|
$
|
(0.33)
|
|
|
$
|
1.32
|
|
Common unit –
diluted
|
|
$
|
0.64
|
|
|
$
|
1.22
|
|
|
$
|
(0.33)
|
|
|
$
|
1.31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-average
limited partner units outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units –
basic
|
|
|
73,356
|
|
|
|
73,059
|
|
|
|
73,283
|
|
|
|
72,583
|
|
Common units –
diluted
|
|
|
73,756
|
|
|
|
73,433
|
|
|
|
73,283
|
|
|
|
72,901
|
|
SUMMIT MIDSTREAM
PARTNERS, LP AND SUBSIDIARIES
|
UNAUDITED OTHER
FINANCIAL AND OPERATING DATA
|
|
|
Three months ended
September 30,
|
|
|
Nine months ended
September 30,
|
|
|
2018
|
|
|
2017
|
|
|
2018
|
|
|
2017
|
|
|
(Dollars in
thousands)
|
|
Other financial
data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
$
|
57,455
|
|
|
$
|
93,637
|
|
|
$
|
3,697
|
|
|
$
|
104,300
|
|
Net cash provided by
operating activities
|
$
|
56,443
|
|
|
$
|
75,156
|
|
|
$
|
166,492
|
|
|
$
|
196,497
|
|
Capital
expenditures
|
$
|
46,639
|
|
|
$
|
40,294
|
|
|
$
|
137,033
|
|
|
$
|
86,206
|
|
Contributions to
equity method investees
|
$
|
—
|
|
|
$
|
5,932
|
|
|
$
|
—
|
|
|
$
|
21,581
|
|
Adjusted
EBITDA
|
$
|
73,416
|
|
|
$
|
73,477
|
|
|
$
|
217,220
|
|
|
$
|
217,464
|
|
Distributable cash
flow
|
$
|
43,629
|
|
|
$
|
52,877
|
|
|
$
|
134,941
|
|
|
$
|
155,837
|
|
Distributions
declared (1)
|
$
|
45,216
|
|
|
$
|
45,037
|
|
|
$
|
135,648
|
|
|
$
|
134,651
|
|
Distribution coverage
ratio (2)
|
0.96x
|
|
|
1.17x
|
|
|
0.99x
|
|
|
1.16x
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate average
daily throughput – natural gas (MMcf/d)
|
|
1,629
|
|
|
|
1,826
|
|
|
|
1,720
|
|
|
|
1,744
|
|
Aggregate average
daily throughput – liquids (Mbbl/d)
|
|
96.9
|
|
|
|
74.0
|
|
|
|
90.9
|
|
|
74.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ohio Gathering
average daily throughput (MMcf/d) (3)
|
|
797
|
|
|
|
763
|
|
|
|
765
|
|
|
|
746
|
|
|
|
|
|
(1) Represents
distributions declared to common unitholders in respect of a given
period. For example, for the three months ended September 30, 2018,
represents the distributions to be paid in November
2018.
|
(2) Distribution
coverage ratio calculation for the three months ended September 30,
2018 and 2017 is based on distributions declared to common
unitholders in respect of the third quarter of 2018 and 2017.
Represents the ratio of distributable cash flow to distributions
declared.
|
(3) Gross basis,
represents 100% of volume throughput for Ohio Gathering, based on a
one-month lag.
|
SUMMIT MIDSTREAM
PARTNERS, LP AND SUBSIDIARIES
|
UNAUDITED
RECONCILIATION OF REPORTABLE SEGMENT ADJUSTED EBITDA
|
TO ADJUSTED
EBITDA
|
|
|
|
Three months ended
September 30,
|
|
|
Nine months ended
September 30,
|
|
|
|
2018
|
|
|
2017
|
|
|
2018
|
|
|
2017
|
|
|
|
(In
thousands)
|
|
Reportable segment
adjusted EBITDA (1):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utica
Shale
|
|
$
|
6,521
|
|
|
$
|
8,412
|
|
|
$
|
24,459
|
|
|
$
|
25,857
|
|
Ohio Gathering
(2)
|
|
|
10,171
|
|
|
|
10,522
|
|
|
|
29,583
|
|
|
|
29,201
|
|
Williston
Basin
|
|
|
19,849
|
|
|
|
16,212
|
|
|
|
54,849
|
|
|
|
51,176
|
|
Piceance/DJ
Basins
|
|
|
29,831
|
|
|
|
30,008
|
|
|
|
86,739
|
|
|
|
86,256
|
|
Barnett
Shale
|
|
|
10,818
|
|
|
|
10,838
|
|
|
|
31,770
|
|
|
|
35,924
|
|
Marcellus
Shale
|
|
|
5,550
|
|
|
|
6,682
|
|
|
|
18,769
|
|
|
|
17,775
|
|
Total
|
|
$
|
82,740
|
|
|
$
|
82,674
|
|
|
$
|
246,169
|
|
|
$
|
246,189
|
|
Less Corporate and
Other (3)
|
|
|
9,324
|
|
|
|
9,197
|
|
|
|
28,949
|
|
|
|
28,725
|
|
Adjusted
EBITDA
|
|
$
|
73,416
|
|
|
$
|
73,477
|
|
|
$
|
217,220
|
|
|
$
|
217,464
|
|
|
|
|
|
(1) We define
segment adjusted EBITDA as total revenues less total costs and
expenses; plus (i) other income excluding interest income, (ii) our
proportional adjusted EBITDA for equity method investees, (iii)
depreciation and amortization, (iv) adjustments related to MVC
shortfall payments, (v) unit-based and noncash compensation, (vi)
change in the Deferred Purchase Price Obligation, (vii) early
extinguishment of debt expense, (viii) impairments and (ix) other
noncash expenses or losses, less other noncash income or
gains.
|
(2) Represents
our proportional share of adjusted EBITDA for Ohio Gathering, based
on a one-month lag. We define proportional adjusted EBITDA
for our equity method investees as the product of (i) total
revenues less total expenses, excluding impairments and other
noncash income or expense items and (ii) amortization for
deferred contract costs; multiplied by our ownership interest in
Ohio Gathering during the respective period.
|
(3) Corporate
and Other represents those results that are not specifically
attributable to a reportable segment or that have not been
allocated to our reportable segments, including certain general and
administrative expense items, natural gas and crude oil marketing
services, transaction costs, interest expense, early extinguishment
of debt and a change in the Deferred Purchase Price
Obligation.
|
SUMMIT
MIDSTREAM PARTNERS, LP AND SUBSIDIARIES
|
UNAUDITED
RECONCILIATIONS TO NON-GAAP FINANCIAL MEASURES
|
|
|
|
Three months ended
September 30,
|
|
|
Nine months ended
September 30,
|
|
|
|
2018
|
|
|
2017
|
|
|
2018
|
|
|
2017
|
|
|
|
(In
thousands)
|
|
Reconciliations of
net income or loss to adjusted EBITDA and distributable cash
flow:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
57,455
|
|
|
$
|
93,637
|
|
|
$
|
3,697
|
|
|
$
|
104,300
|
|
Add:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
expense
|
|
|
14,862
|
|
|
|
17,614
|
|
|
|
44,821
|
|
|
|
51,883
|
|
Income tax (benefit)
expense
|
|
|
(35)
|
|
|
|
176
|
|
|
|
88
|
|
|
|
417
|
|
Depreciation and
amortization (1)
|
|
|
26,592
|
|
|
|
28,777
|
|
|
|
79,752
|
|
|
|
85,732
|
|
Proportional adjusted
EBITDA for equity method investees (2)
|
|
|
10,171
|
|
|
|
10,522
|
|
|
|
29,583
|
|
|
|
29,201
|
|
Adjustments related to
MVC shortfall payments (3)
|
|
|
(2,999)
|
|
|
|
(10,124)
|
|
|
|
(6,541)
|
|
|
|
(33,186)
|
|
Adjustments related to
capital reimbursement activity (4)
|
|
|
(106)
|
|
|
|
—
|
|
|
|
49
|
|
|
|
—
|
|
Unit-based and noncash
compensation
|
|
|
1,965
|
|
|
|
1,974
|
|
|
|
6,188
|
|
|
|
5,973
|
|
Deferred Purchase
Price Obligation (5)
|
|
|
(37,204)
|
|
|
|
(70,499)
|
|
|
|
53,759
|
|
|
|
(54,674)
|
|
Early extinguishment
of debt (6)
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
22,020
|
|
Loss (gain) on asset
sales, net
|
|
|
6
|
|
|
|
460
|
|
|
|
(6)
|
|
|
|
530
|
|
Long-lived asset
impairment
|
|
|
1,540
|
|
|
|
1,290
|
|
|
|
2,127
|
|
|
|
1,577
|
|
Income (loss) from
equity method investees
|
|
|
1,169
|
|
|
|
(350)
|
|
|
|
3,703
|
|
|
|
3,691
|
|
Adjusted
EBITDA
|
|
$
|
73,416
|
|
|
$
|
73,477
|
|
|
$
|
217,220
|
|
|
$
|
217,464
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash interest
paid
|
|
|
13,164
|
|
|
|
14,028
|
|
|
|
44,126
|
|
|
|
47,410
|
|
Cash paid for
taxes
|
|
|
—
|
|
|
|
—
|
|
|
|
175
|
|
|
|
—
|
|
Senior notes interest
adjustment (7)
|
|
|
3,063
|
|
|
|
3,063
|
|
|
|
3,063
|
|
|
|
2,594
|
|
Distributions to
Series A Preferred unitholders (8)
|
|
|
—
|
|
|
|
—
|
|
|
|
14,250
|
|
|
|
—
|
|
Series A Preferred
units distribution adjustment (9)
|
|
|
7,125
|
|
|
|
—
|
|
|
|
7,125
|
|
|
|
—
|
|
Maintenance capital
expenditures
|
|
|
6,435
|
|
|
|
3,509
|
|
|
|
13,540
|
|
|
|
11,623
|
|
Distributable cash flow
|
|
$
|
43,629
|
|
|
$
|
52,877
|
|
|
$
|
134,941
|
|
|
$
|
155,837
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions
declared (10)
|
|
$
|
45,216
|
|
|
$
|
45,037
|
|
|
$
|
135,648
|
|
|
$
|
134,651
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distribution coverage
ratio (11)
|
|
0.96x
|
|
|
1.17x
|
|
|
0.99x
|
|
|
1.16x
|
|
|
|
|
|
(1) Includes
the amortization expense associated with our favorable and
unfavorable gas gathering contracts as reported in other
revenues.
|
(2) Reflects
our proportionate share of Ohio Gathering adjusted EBITDA, based on
a one-month lag.
|
(3) Adjustments
related to MVC shortfall payments for the three and nine months
ended September 30, 2017 account for (i) the net increases or
decreases in deferred revenue for MVC shortfall payments and (ii)
our inclusion of expected annual MVC shortfall payments. For
the three and nine months ended September 30, 2018, adjustments
related to MVC shortfall payments are recognized in gathering
services and related fees.
|
(4) Adjustments
related to capital reimbursement activity represent contributions
in aid of construction revenue recognized in accordance with
Accounting Standards Update No. 2014-09 Revenue from Contracts with
Customers ("Topic 606").
|
(5) Deferred
Purchase Price Obligation represents the change in the present
value of the Deferred Purchase Price Obligation.
|
(6) Early
extinguishment of debt includes $17.9 million paid for redemption
and call premiums, as well as $4.1 million of unamortized debt
issuance costs which were written off in connection with the
repurchase of the outstanding $300.0 million 7.5% Senior Notes in
the first quarter of 2017.
|
(7) Senior
notes interest adjustment represents the net of interest expense
accrued and paid during the period. Interest on the $300.0 million
5.5% senior notes is paid in cash semi-annually in arrears on
February 15 and August 15 until maturity in August 2022.
Interest on the $500.0 million 5.75% senior notes is paid in cash
semi-annually in arrears on April 15 and October 15 until maturity
in April 2025.
|
(8)
Distributions on the Series A preferred units are paid in cash
semi-annually in arrears on June 15 and December 15 each year,
through and including December 15, 2022, and, thereafter,
quarterly in arrears on the 15th day of March, June, September and
December of each year.
|
(9) Series A
Preferred unit distribution adjustment represents the net of
distributions paid and accrued on the Series A Preferred
units.
|
(10) Represents
distributions declared to common unitholders in respect of a given
period. For example, for the three months ended September 30, 2018,
represents the distributions to be paid in November
2018.
|
(11)
Distribution coverage ratio calculation for the three months ended
September 30, 2018 and 2017 is based on distributions declared in
respect of the third quarter of 2018 and 2017. Represents the ratio
of distributable cash flow to distributions
declared.
|
SUMMIT
MIDSTREAM PARTNERS, LP AND SUBSIDIARIES
|
UNAUDITED
RECONCILIATIONS TO NON-GAAP FINANCIAL MEASURES
|
|
|
|
Nine months ended
September 30,
|
|
|
|
2018
|
|
|
2017
|
|
|
|
(In
thousands)
|
|
Reconciliation of
net cash provided by operating activities to
adjusted EBITDA and
distributable cash flow:
|
|
|
|
|
|
|
|
|
Net cash provided by
operating activities
|
|
$
|
166,492
|
|
|
$
|
196,497
|
|
Add:
|
|
|
|
|
|
|
|
|
Interest expense,
excluding amortization of debt issuance costs
|
|
|
41,637
|
|
|
|
48,766
|
|
Income tax
expense
|
|
|
88
|
|
|
|
417
|
|
Changes in operating
assets and liabilities
|
|
|
12,440
|
|
|
|
4,786
|
|
Proportional adjusted
EBITDA for equity method investees (1)
|
|
|
29,583
|
|
|
|
29,201
|
|
Adjustments related to
MVC shortfall payments (2)
|
|
|
(6,541)
|
|
|
|
(33,186)
|
|
Adjustments related to
capital reimbursement activity (3)
|
|
|
49
|
|
|
|
—
|
|
Less:
|
|
|
|
|
|
|
|
|
Distributions from
equity method investees
|
|
|
26,528
|
|
|
|
28,715
|
|
Write-off of debt
issuance costs
|
|
|
—
|
|
|
|
302
|
|
Adjusted
EBITDA
|
|
$
|
217,220
|
|
|
$
|
217,464
|
|
Less:
|
|
|
|
|
|
|
|
|
Cash interest
paid
|
|
|
44,126
|
|
|
|
47,410
|
|
Cash paid for
taxes
|
|
|
175
|
|
|
|
—
|
|
Senior notes interest
adjustment (4)
|
|
|
3,063
|
|
|
|
2,594
|
|
Distributions to
Series A Preferred unitholders (5)
|
|
|
14,250
|
|
|
|
—
|
|
Series A Preferred
units distribution adjustment (6)
|
|
|
7,125
|
|
|
|
—
|
|
Maintenance capital
expenditures
|
|
|
13,540
|
|
|
|
11,623
|
|
Distributable cash flow
|
|
$
|
134,941
|
|
|
$
|
155,837
|
|
|
|
|
|
(1) Reflects
our proportionate share of Ohio Gathering adjusted EBITDA, based on
a one-month lag.
|
(2) Adjustments
related to MVC shortfall payments for the nine months ended
September 30, 2017 account for (i) the net increases or decreases
in deferred revenue for MVC shortfall payments and (ii) our
inclusion of expected annual MVC shortfall payments. For the
nine months ended September 30, 2018, adjustments related to MVC
shortfall payments are recognized in gathering services and related
fees.
|
(3) Adjustments
related to capital reimbursement activity represent contributions
in aid of construction revenue recognized in accordance with
Accounting Standards Update No. 2014-09 Revenue from Contracts with
Customers ("Topic 606").
|
(4) Senior
notes interest adjustment represents the net of interest expense
accrued and paid during the period. Interest on the $300.0 million
5.5% senior notes is paid in cash semi-annually in arrears on
February 15 and August 15 until maturity in August 2022.
Interest on the $500.0 million 5.75% senior notes is paid in cash
semi-annually in arrears on April 15 and October 15 until maturity
in April 2025.
|
(5)
Distributions on the Series A Preferred units are paid in cash
semi-annually in arrears on June 15 and December 15 each year,
through and including December 15, 2022, and, thereafter,
quarterly in arrears on the 15th day of March, June, September and
December of each year.
|
(6) Series A
Preferred unit distribution adjustment represents the net of
distributions paid and accrued on the Series A Preferred
units.
|
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SOURCE Summit Midstream Partners, LP