HOUSTON, Feb. 25, 2022 /PRNewswire/ -- Summit
Midstream Partners, LP (NYSE: SMLP) ("Summit", "SMLP" or the
"Partnership") announced today its financial and operating results
for the three months ended December 31,
2021, including net loss of $16.2
million, adjusted EBITDA of $54.7
million and DCF of $29.9
million. Operated natural gas throughput from wholly
owned assets averaged 1,307 million cubic feet per day ("MMcf/d")
and liquids throughput averaged 62 thousand barrels per day
("Mbbl/d"). Operated natural gas volumes from wholly owned
assets decreased 2.0% relative to the third quarter of 2021,
largely due to natural production declines, which was partially
offset by volumes from 25 new wells that were turned-in-line
primarily towards the latter half of the fourth quarter, including
four new Utica wells that were
connected in the Northeast segment in late November with initial
production of nearly 100 MMcf/d. Fourth quarter 2021 liquids
volume decreased modestly relative to the third quarter of 2021,
primarily as a result of natural production declines, partially
offset by crude volumes gathered from 16 new Williston wells that were turned-in-line in
November and December of 2021.
Heath Deneke, President, Chief
Executive Officer and Chairman, commented, "Summit's fourth quarter
financial and operating results were in-line with our
expectations. For full year 2021, adjusted EBITDA of
$238 million was near the top of our
$225 million to $240 million revised guidance range and almost
$20 million above the midpoint of our
initial guidance. In 2021, we spent $25 million on capital expenditures, which was
towards the low end of our $20
million to $35 million
guidance range. Well connect activity from our upstream
customers during the fourth quarter of 2021 represented a
significant increase versus the first three quarters of 2021, with
45 of the 95 wells turned-in-line behind our systems during the
last quarter of the year. We also successfully placed the
Double E Pipeline in-service during the fourth quarter of
2021. Double E is a very important new pipeline system for
the northern Delaware Basin, with
the initial capacity to transport an incremental 1.35 Bcf/d of
natural gas from growing production in Eddy and Lea
counties, New Mexico to multiple
Gulf Coast oriented pipelines originating out of Waha, TX.
The pipeline is anchored by 1.0 Bcf/d of long term take-or-pay
contracts from some of the largest producers in the Permian Basin
and is well positioned for a highly efficient expansion to 2.0
Bcf/d as production continues to increase in the region. We are
very proud of the team for delivering this important project on
time, approximately 20% below the original $500 million budget, all while maintaining an
outstanding safety, environmental and compliance record. We
expect Double E to be a significant growth catalyst for Summit as
our initial 1.0 Bcf/d of sculpted take-or-pay contracts ramp up
between 2022 and 2024 and as we secure new contracts from
Northern Delaware customers that
need incremental gas takeaway capacity."
"As previously announced, we also achieved a critical milestone
for Summit during the fourth quarter with the successful
refinancing of our 2022 debt maturities which provided an extended,
multi-year runaway to continue our focus on maximizing free cash
flow and further de-levering the balance sheet. During the
quarter, we also launched a cash-less preferred for common equity
exchange transaction which closed in January of 2022, whereby
holders of nearly $95 million of our
Series A Preferred Equity, including accrued and unpaid
distributions, exchanged into approximately 2.9 million SMLP common
units. This transaction enabled Summit to continue its
efforts to simplify and improve the balance sheet by further
reducing our outstanding fixed capital obligations while preserving
cash for debt repayment. The transaction also eliminated
nearly $17 million of unpaid
preferred distributions that have accrued on the balance sheet
since June of 2020, while reducing the remaining amount of Series A
Preferred Equity to which distributions are expected to continue to
accrue by more than half. Additionally, with the reduction in
the face value of the remaining Series A Preferred Equity to a
level below $100 million, SMLP is now
able to issue or assume a separate class of parity preferred
equity, which further enhances our strategic and financial
flexibility as we continue to evaluate long-term value enhancing
opportunities in the future."
"Our 2022 guidance includes an adjusted EBITDA range of
$195 million to $220 million based on approximately 75 to 110 new
well connections. Given the current commodity price
environment and the momentum in activity that we experienced in the
second half of 2021, we are disappointed and frankly surprised by
the limited amount of new wells that our customers' most recent
plans are indicating will be turned on-line behind our systems in
2022. As a point of reference, between 2017 and 2019, we
averaged over 260 new well connects per year at a time when Henry
Hub prices averaged below $3.00 MMbtu
and WTI averaged below $60 per
barrel. At current strip pricing levels, we believe that
nearly all of the remaining inventory behind our gas and crude
systems would be economic to develop. Furthermore, through a
combination of industry consolidation and capital discipline, our
customers have significantly improved their balance sheets and
financial capability to responsibly increase development activity
on the high-quality acreage behind our systems as economic
conditions warrant. While our current 2022 guidance levels do
not indicate the beginning of the U-shape recovery that we have
been anticipating, we continue to expect that drilling activity
behind our systems will increase as our customers gain further
confidence that the fundamentals underlying the current commodity
price outlook will hold in the future. Last year is a good example
of how customer plans can change throughout the year. Initially we
expected approximately 60 new wells based on customer plans as of
February 2021, and by the end of the
second quarter, those plans increased to approximately 95 new
wells, which was a key driver for increasing our 2021 guidance
range in June of last year. Similar to last year, we plan to
provide updated 2022 guidance if we expect the outlook to be
materially different than our initial guidance range. In the
meantime, we will continue to focus on maximizing free cash flow
and reducing debt, providing safe, efficient and reliable
operations for our customers and a positive and safe work
environment for our employees."
New Business Segments
As previously announced, during the fourth quarter of 2021 we
implemented changes to our reportable segments. The new
segment reporting resulted from changes enacted to optimize
commercial efforts and our geographic workforce in order to better
align our commercial, engineering and operational
capabilities. The five reportable segments we will utilize
going forward are described below, along with a management
categorization of the commodity that has the most influence on
customer drilling and completion decisions:
- Natural gas price driven: Our cash flows in the
Northeast, Piceance and Barnett segments are significantly
influenced by the price of natural gas because the drilling,
completion and recompletion decisions by our customers in these
segments are based on well economics most heavily impacted by the
price of natural gas and natural gas liquids. Increased upstream
activity by our customers in these basins therefore result in
higher throughput and cash flows for those segments in which we
collect fees for gathering natural gas or natural gas liquids.
-
- Northeast – Includes our wholly owned midstream assets
located in the Utica and Marcellus
shale plays and our equity method investment in Ohio Gathering that
is focused on the Utica Shale
- Piceance – Includes our wholly owned midstream assets
located in the Piceance Basin
- Barnett – Includes our wholly owned midstream assets
located in the Barnett Shale
- Oil price driven: Customer activity and our cash flows
in the Permian and Rockies segments are significantly influenced by
the price of oil because the drilling and completion decisions by
our customers in these segments are based on well economics most
heavily impacted by the price of oil. Decisions to drill and
complete wells in these basins therefore result in higher
throughput and cash flows for our midstream assets in which we
collect fees for gathering or processing hydrocarbons, gathering
produced water, or transporting natural gas.
-
- Permian – Includes our wholly owned midstream assets
located in the Permian Basin and our equity method investment in
the Double E Pipeline
- Rockies – Includes our wholly owned midstream assets
located in the Williston Basin and
the DJ Basin
A comparison of prior and current reportable segments is listed
in the table below for illustrative purposes.
Prior Reportable
Segment(s)
|
New Reportable
Segment
|
Utica Shale, Ohio
Gathering, Marcellus Shale
|
Northeast
|
Piceance
Basin
|
Piceance
|
Barnett
Shale
|
Barnett
|
Permian Basin, Double
E (new)
|
Permian
|
Williston Basin, DJ
Basin
|
Rockies
|
2022 Guidance
SMLP is releasing guidance for 2022, which is summarized in the
table below. These projections are subject to risks and
uncertainties as described in the "Forward-Looking Statements"
section at the end of the release.
We have taken a similar approach to our 2022 guidance range that
we did with our 2021 guidance range. If our producer customers hit
their production targets and upper end of planned well connects, as
they did in 2021, we would expect to be near the high end of our
2022 guidance range. We believe the midpoint of our guidance
range reflects a conservative, yet appropriate, level of risking to
the most recent drill schedules and volume forecasts provided by
our customers.
($ in
millions)
|
|
|
|
2022 Guidance
Range
|
|
|
|
|
Low
|
|
High
|
Well
Connections
|
|
Average (2017 -
2019)
|
|
|
|
|
Northeast (includes
OGC)
|
|
61
|
|
31
|
|
44
|
Piceance
|
|
50
|
|
17
|
|
17
|
Barnett
|
|
9
|
|
4
|
|
11
|
Permian
|
|
8
|
|
4
|
|
6
|
Rockies
|
|
134
|
|
20
|
|
30
|
Total
|
|
262
|
|
76
|
|
108
|
|
|
|
|
|
|
|
Natural Gas
Throughput (MMcf/d)
|
|
|
|
|
Northeast (excludes
OGC)
|
|
636
|
|
700
|
Piceance
|
|
299
|
|
303
|
Barnett
|
|
188
|
|
200
|
Permian (excludes
Double E)
|
|
17
|
|
32
|
Rockies
|
|
32
|
|
35
|
Total
|
|
1,172
|
|
1,270
|
|
|
|
|
|
|
|
Rockies Liquids
Throughput (Mbbl/d)
|
|
60
|
|
63
|
OGC Natural Gas
Throughput (MMcf/d, gross)
|
|
602
|
|
681
|
Double E Natural
Gas Throughput (MMcf/d, gross)
|
|
195
|
|
265
|
|
|
|
|
|
|
|
Adjusted
EBITDA
|
|
|
|
|
Northeast
|
|
$68
|
|
$77
|
Piceance
|
|
60
|
|
63
|
Barnett
|
|
26
|
|
28
|
Permian
|
|
18
|
|
25
|
Rockies
|
|
53
|
|
57
|
Unallocated G&A,
Other
|
|
(30)
|
|
(30)
|
Total
|
|
$195
|
|
$220
|
|
|
|
|
|
|
|
Capital
Expenditures
|
|
|
|
|
|
|
Growth
|
|
|
|
$10
|
|
$20
|
Maintenance
|
|
|
|
$10
|
|
$15
|
Total
|
|
|
|
$20
|
|
$35
|
|
|
|
|
|
|
|
Investment in Double
E equity method investee
|
|
$10
|
|
$10
|
We expect approximately 75 to 110 well connections in 2022,
which remains significantly below pre-COVID levels averaging 262
well connections per year from 2017 through 2019 in a less
favorable commodity price environment. The current commodity price
environment should support increasing development activity and we
believe if prices remain strong, we will begin to see producers
increase activity behind our systems. We continue to see producers
drill longer laterals, with several 2022 well connections expected
to have 15,000' laterals, which helps mitigate the impact of
limited well connections. We are encouraged by the level of
activity we expect in the Barnett and Piceance, as customers in
these areas take advantage of the favorable commodity price
environment. Of our expected 2022 well connections, 34 wells are
either online, DUCs or have a rig present. The remaining new wells
expected in our 2022 forecast are permitted and have been recently
affirmed by our customers.
We expect our wholly owned natural gas gathering system
throughput to range from approximately 1,172 MMcf/d to 1,270
MMcf/d, as compared to 1,356 MMcf/d in 2021. The year-over-year
expected decline is primarily due to natural production declines
and limited expected well connections in the Northeast, Permian and
Rockies. OGC gross volume throughput is expected to range from
approximately 602 MMcf/d to 681 MMcf/d, as compared to 526 MMcf/d
in 2021, representing over 20% year-over-year growth at the
mid-point. With the commercial operation of Double E commencing in
November 2021, we expect Double E
throughput to increase throughout the course of 2022, with average
annual gross throughput ranging from approximately 195 MMcf/d to
265 MMcf/d. Given nearly 90 active rigs in New Mexico, we are optimistic about overall
volume growth in the basin and the potential for additional firm
take-or-pay contracts. Double E benefits from existing take-or-pay
contracts of 585 MMcf/d currently, contractually increasing to 810
MMcf/d beginning in November 2022,
985 MMcf/d beginning in November 2023
and 1.0 Bcf/d beginning in November
2024, leaving only 350 MMcf/d of remaining long-term
capacity on the pipeline before an expansion is required. Liquids
volumes are expected to remain relatively flat year-over-year,
ranging from 60 Mbbl/d to 63 Mbbl/d, despite no well connections
from certain key customers to whom we provide both crude oil and
produced water gathering services.
Adjusted EBITDA is expected to range from $195 million to $220
million, a decrease from 2021 primarily due to limited
drilling and completion activity, an approximately $12 million reduction in MVC shortfall payments
that expired in 2021, $7 million in
energy management and COVID-19 related tax credits in 2021 and
approximately $5 million of one-time
operating expenses expected in 2022. We are optimistic that we will
find ways to mitigate the increasing pressure of inflation on our
operating costs and believe that the approximately $5 million of expected one-time operating
expenses in 2022 will mitigate operating expenses beginning in
2023.
Our 2022 capital expenditure guidance of $20 million to $35
million, excluding Double E, is presented on a gross basis
and does not include asset sales or capital reimbursements related
to specific development projects with certain customers. We
do expect to continue to monetize latent inventory, or other
underutilized assets, which is not reflected in our financial
guidance. In 2021, we sold approximately $8
million of such assets and have sold approximately
$2 million to date in 2022. Our full
year 2022 growth capex guidance range of $10
million to $20 million,
excluding Double E, is dependent on new well connect activity and
is expected to be directed towards new pad connections in our
Northeast and Rockies segments. All other expected well connections
are either on existing pad sites, or will be delivered to our
gathering systems. We also expect that the vast majority, if
not all, of the remaining $10 million
investment in Double E will be funded with cash-on-hand at our
unrestricted subsidiaries, or through Double E distributions
generated from operations. We expect approximately
$10 million to $15 million of maintenance capex, an increase
relative to our 2021 maintenance capex of $8
million, primarily due to approximately $6 million of expected one-time capital
expenditures related to certain asset integrity initiatives and
modifications to assets for emission reductions.
In 2022, we expect to generate cash flow after interest expense,
capital expenditures, investments in Double E and other cash
expenditures of $65 million to
$85 million, which we plan to utilize
to further reduce our indebtedness.
Fourth Quarter 2021 Business Highlights
In the fourth quarter of 2021, SMLP's average daily natural gas
throughput for its wholly owned operated systems decreased by 2.0%
to 1,307 MMcf/d, and liquids volumes decreased by 1.6% to 62
Mbbl/d, relative to the third quarter of 2021. In
November 2021, Double E Pipeline
commenced operations and began transporting residue gas from the
Northern Delaware Basin to the
Waha hub in Texas, resulting in an
average of 124 MMcf/d of gross volumes transported since
commissioning and approximately $1.9
million of adjusted EBITDA net to SMLP for the fourth
quarter of 2021. SMLP's customers are currently operating
four drilling rigs on acreage behind SMLP's gathering systems, and
there are approximately 34 new wells that were already connected to
the system, have been drilled or are currently under
development.
Natural gas price driven segments:
- Natural gas price driven segments had combined quarterly
segment adjusted EBITDA of $45.1
million and combined capital expenditures of $5.1 million in the fourth quarter of 2021.
- Northeast segment adjusted EBITDA totaled $19.0 million, an 8.2% decrease relative to the
third quarter of 2021 driven by natural production declines of
approximately 35 MMcf/d behind our SMU
system, partially offset by 16 new wells, of which the majority
were connected during the second half of the fourth quarter of
2021. These new well connects included a new four well pad behind
our SMU system, as well as four well
connects behind our Mountaineer system in the Marcellus shale. The
new four well pad behind the SMU system
was connected in late November 2021
and averaged 96 MMcf/d while online, or approximately 75 MMcf/d for
the fourth quarter of 2021. The Northeast segment has 15 wells that
are either online, have been drilled, or are under development,
which represents 48% of the midpoint for Northeast segment well
connects in our 2022 guidance.
- Piceance segment adjusted EBITDA of $15.9 million decreased by 16.1% from the third
quarter of 2021, primarily due to the expiration of an MVC at the
end of September 2021 that
contributed $3.4 million of adjusted
EBITDA to the segment in the third quarter of 2021 and natural
production declines, partially offset by volumes from 9 new wells
that were connected during the quarter by one of our larger
customers. These 9 wells represented the first new wells connected
to our Piceance system since the third quarter of 2018 and
contributed approximately 9.1 MMcf/d while online, averaging 7.6
MMcf/d for the fourth quarter of 2021. Based on its 2022 capital
program, this same customer is planning to connect 17 wells, which
have all been permitted towards the middle to latter part of 2022.
This customer also has plans for another 74 wells behind our system
in the 2023 to 2024 timeframe and has entered into a capital
reimbursement agreement with SMLP so that planning activities for
those well connections can be undertaken.
- Barnett segment adjusted EBITDA of $10.2
million increased by 5.7% from the third quarter of 2021,
primarily due to a 21 MMcf/d increase in volume throughput driven
by continued strong performance from the 7 wells that were
turned-in-line in September of 2021. These wells continue to be
some of the largest natural gas wells ever drilled in the Barnett
Shale and averaged 47 MMcf/d during the fourth quarter of 2021. The
low end of our 2022 guidance range includes four new well connects,
of which all have been drilled.
Oil price driven segments
- Oil price driven segments generated $17.5 million of combined segment adjusted EBITDA
in the fourth quarter of 2021 and had combined capital expenditures
of $8.1 million.
- Permian segment EBITDA totaled $2.6
million in the fourth quarter of 2021, a $2.0 million increase relative to the third
quarter of 2021 primarily due to the commencement of operations at
Double E in mid-November 2021. Double
E is an equity method investment, so the Permian segment is
allocated SMLP's proportionate share of Double E EBITDA. There were
no new wells connected behind the Permian gathering and processing
system during the fourth quarter of 2021 and the 4 well pad that
was expected to come online in December
2021 was delayed until 2022. In 2022, we currently expect
limited activity behind our Permian gathering and processing system
from our existing customers and for the majority of adjusted EBITDA
for the segment to come from offloads and our proportionate share
of Double E.
- Rockies segment EBITDA of $14.9
million decreased by 20.4% from the prior quarter primarily
due to a one-time $1.8 million
benefit from the settlement of a legal matter in the third quarter
of 2021. In the Williston Basin,
16 new wells were connected to our crude gathering infrastructure;
however, all of these wells were connected in November and
December, resulting in limited impact to fourth quarter of 2021
performance. The Rockies segment has 11 wells that are either
online, have been drilled or are under development, which
represents approximately 55% of the midpoint for Rockies segment
well connects in our 2022 guidance. We currently expect limited new
well connect activity in the DJ Basin from our existing customers
in 2022, but may benefit from additional volumes related to an
offload agreement we are actively negotiating.
The following table presents average daily throughput by
reportable segment for the periods indicated:
|
Three Months Ended
December 31,
|
|
Year Ended
December 31,
|
|
2021
|
|
2020
|
|
2021
|
|
2020
|
Average daily
throughput (MMcf/d):
|
|
|
|
|
|
|
|
Northeast
(2)
|
710
|
|
813
|
|
765
|
|
726
|
Rockies
|
34
|
|
39
|
|
35
|
|
40
|
Permian
(2)
|
24
|
|
33
|
|
26
|
|
33
|
Piceance
|
317
|
|
347
|
|
326
|
|
364
|
Barnett
|
222
|
|
204
|
|
204
|
|
212
|
Aggregate average
daily throughput
|
1,307
|
|
1,436
|
|
1,356
|
|
1,375
|
|
|
|
|
|
|
|
|
Average daily
throughput (Mbbl/d):
|
|
|
|
|
|
|
|
Rockies
|
62
|
|
71
|
|
63
|
|
79
|
Aggregate average
daily throughput
|
62
|
|
71
|
|
63
|
|
79
|
|
|
|
|
|
|
|
|
Ohio Gathering
average daily throughput (MMcf/d) (1)
|
530
|
|
621
|
|
526
|
|
571
|
|
|
|
|
|
|
|
|
Double E average
daily throughput (MMcf/d) (3)
|
58
|
|
–
|
|
15
|
|
–
|
|
|
(1)
|
Gross basis,
represents 100% of volume throughput for Ohio Gathering, subject to
a one-month lag.
|
|
|
(2)
|
Exclusive of Ohio
Gathering and Double E due to equity method accounting.
|
|
|
(3)
|
Gross, basis,
represents 100% of volume throughput for Double E.
|
The following table presents adjusted EBITDA by reportable
segment for the periods indicated:
|
Three Months Ended
December 31,
|
|
Year Ended
December 31,
|
|
2021
|
|
2020
|
|
2021
|
|
2020
|
|
(In
thousands)
|
|
(In
thousands)
|
Reportable segment
adjusted EBITDA (1):
|
|
|
|
|
|
|
|
Northeast
(2)
|
$
19,013
|
|
$
22,969
|
|
$
83,287
|
|
$
85,854
|
Rockies
|
14,911
|
|
15,861
|
|
64,517
|
|
71,509
|
Permian
(3)
|
2,600
|
|
(62)
|
|
6,614
|
|
5,744
|
Piceance
|
15,865
|
|
22,026
|
|
76,131
|
|
88,820
|
Barnett
|
10,187
|
|
7,617
|
|
36,729
|
|
32,093
|
Total
|
$
62,576
|
|
$
68,411
|
|
$
267,278
|
|
$
284,020
|
Less: Corporate
and Other (4)
|
7,870
|
|
6,620
|
|
28,855
|
|
31,905
|
Adjusted
EBITDA
|
$
54,706
|
|
$
61,791
|
|
$
238,423
|
|
$
252,115
|
__________
(1)
|
We define segment
adjusted EBITDA as total revenues less total costs and expenses,
plus (i) other income, (ii) our proportional adjusted EBITDA for
equity method investees, (iii) depreciation and amortization, (iv)
adjustments related to MVC shortfall payments, (v) adjustments
related to capital reimbursement activity, (vi) unit-based and
noncash compensation, (vii) impairments and (viii) other noncash
expenses or losses, less other noncash income or gains.
|
|
|
(2)
|
Includes our
proportional share of adjusted EBITDA for Ohio Gathering, subject
to 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
during the respective period.
|
|
|
(3)
|
Includes our
proportional share of adjusted EBITDA for Double E. We define
proportional adjusted EBITDA for our equity method investees as the
product of total revenues less total expenses, excluding
impairments and other noncash income or expense items;
multiplied by our ownership interest during the respective
period.
|
|
|
(4)
|
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 and natural gas and crude oil marketing
services.
|
Capital Expenditures
Capital expenditures totaled $13.3
million in the fourth quarter of 2021, inclusive of
maintenance capital expenditures of $3.2
million. Capital expenditures in the fourth quarter of
2021 were primarily related to growth projects to connect new pad
sites in our Northeast, Rockies and Permian segments.
|
Year Ended
December 31,
|
|
2021
|
|
2020
|
|
(In
thousands)
|
Cash paid for
capital expenditures (1):
|
|
|
|
Northeast
|
$
11,237
|
|
$
7,657
|
Rockies
|
9,875
|
|
21,596
|
Permian
|
2,042
|
|
7,014
|
Piceance
|
579
|
|
1,370
|
Barnett
|
766
|
|
1,878
|
Total reportable
segment capital expenditures
|
$
24,499
|
|
$
39,515
|
Corporate and
Other
|
531
|
|
3,613
|
Total cash paid for
capital expenditures
|
$
25,030
|
|
$
43,128
|
__________
(1)
|
Excludes cash paid
for capital expenditures by Ohio Gathering (after June 2019) and
Double E due to equity method accounting.
|
Capital & Liquidity
As of December 31, 2021, SMLP had $267 million drawn under its $400 million ABL Revolver and $109.1 million of borrowing availability, after
accounting for $23.9 million of
issued, but undrawn letters of credit. As of
December 31, 2021, SMLP's gross availability based on the
borrowing base calculation in the credit agreement was $691 million, which is $291 million greater than the $400 million of lender commitments to the ABL
Revolver. As of December 31,
2021 SMLP was in compliance with all financial covenants,
including interest coverage of 4.3x relative to a minimum interest
coverage covenant of 2.0x and first lien leverage ratio of 1.1x
relative to a maximum first lien leverage ratio of 2.5x. As of
December 31, 2021, SMLP reported a
total leverage ratio of 5.16x and is no longer subject to a total
leverage ratio covenant.
As of December 31, 2021, the
Permian Transmission Credit Facility was fully drawn and
$160 million was outstanding.
In January 2022, the Permian
Transmission Credit Facility was converted to a term loan and
mandatory quarterly amortization will commence in March of
2022. The Permian Transmission Term Loan remains non-recourse
to SMLP.
MVC Shortfall Payments
SMLP billed its customers $16.7
million in the fourth quarter of 2021 related to MVC
shortfalls. For those customers that do not have MVC
shortfall credit banking mechanisms in their gathering agreements,
the MVC shortfall payments are accounted for as gathering revenue
in the period in which they are earned. In the fourth quarter
of 2021, SMLP recognized $10.3
million of gathering revenue associated with MVC shortfall
payments. SMLP had no adjustments to MVC shortfall payments
in the fourth quarter of 2021. SMLP's MVC shortfall payment
mechanisms contributed $10.3 million
of total adjusted EBITDA in the fourth quarter of 2021 and
$51.1 million of total adjusted
EBITDA for full year 2021.
|
Three Months Ended
December 31, 2021
|
|
MVC
Billings
|
|
Gathering
revenue
|
|
Adjustments
to MVC
shortfall
payments
|
|
Net impact to
adjusted
EBITDA
|
|
|
Net change in
deferred revenue related to MVC
shortfall payments:
|
|
|
|
|
|
|
|
Piceance
Basin
|
$
300
|
|
$
300
|
|
$
—
|
|
$
300
|
Total net
change
|
$
300
|
|
$
300
|
|
$
—
|
|
$
300
|
|
|
|
|
|
|
|
|
MVC shortfall
payment adjustments:
|
|
|
|
|
|
|
|
Rockies
|
$
8,580
|
|
$
2,145
|
|
$
—
|
|
$
2,145
|
Piceance
|
6,335
|
|
6,335
|
|
—
|
|
6,335
|
Northeast
|
1,470
|
|
1,470
|
|
—
|
|
1,470
|
Total MVC shortfall
payment adjustments
|
$
16,385
|
|
$
9,950
|
|
$
—
|
|
$
9,950
|
|
|
|
|
|
|
|
|
Total
(1)
|
$
16,685
|
|
$
10,250
|
|
$
—
|
|
$
10,250
|
__________
(1)
|
Exclusive of Ohio
Gathering and Double E due to equity method accounting.
|
|
Year Ended
December 31, 2021
|
|
MVC
Billings
|
|
Gathering
revenue
|
|
Adjustments
to MVC
shortfall p
ayments
|
|
Net impact to
adjusted
EBITDA
|
|
|
Net change in
deferred revenue related to MVC
shortfall payments:
|
|
|
|
|
|
|
|
Piceance
|
$
11,307
|
|
$
11,307
|
|
$
—
|
|
$
11,307
|
Total net
change
|
$
11,307
|
|
$
11,307
|
|
$
—
|
|
$
11,307
|
|
|
|
|
|
|
|
|
MVC shortfall
payment adjustments:
|
|
|
|
|
|
|
|
Rockies
|
$
8,580
|
|
$
8,580
|
|
$
—
|
|
$
8,580
|
Piceance
|
24,923
|
|
24,923
|
|
—
|
|
24,923
|
Northeast
|
6,248
|
|
6,248
|
|
—
|
|
6,248
|
Total MVC shortfall
payment adjustments
|
$
39,751
|
|
$
39,751
|
|
$
—
|
|
$
39,751
|
|
|
|
|
|
|
|
|
Total
(1)
|
$
51,058
|
|
$
51,058
|
|
$
—
|
|
$
51,058
|
__________
(1)
|
Exclusive of Ohio
Gathering and Double E due to equity method accounting.
|
Quarterly Distribution
The board of directors of SMLP's general partner continued to
suspend cash distributions payable on its common units and on its
9.50% Series A fixed-to-floating rate cumulative redeemable
perpetual preferred units (the "Series A Preferred Units") for the
period ended December 31, 2021.
Unpaid distributions on the Series A Preferred Units will continue
to accumulate. Subsequent to year end, SMLP closed a
preferred-for-common unit exchange that eliminated $16.6 million of accumulated
distributions.
Fourth Quarter 2021 Earnings Call Information
SMLP will host a conference call at 10:00
a.m. Eastern on Friday, February 25,
2022, 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 50277720. The conference call, live webcast and
archive of the call can be accessed through the Investors section
of SMLP's website at www.summitmidstream.com.
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, non-GAAP financial
measures.
Adjusted EBITDA
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, impairments, items of income or loss that we
characterize as unrepresentative of our ongoing operations and
other noncash expenses or losses, income tax benefit, income (loss)
from equity method investees and other noncash income or
gains. Because adjusted EBITDA may be defined
differently by other entities in our industry, our definition of
this non-GAAP financial measure may not be comparable to similarly
titled measures of other entities, thereby diminishing its
utility.
Management uses adjusted EBITDA in making financial, operating
and planning decisions and in evaluating our financial performance.
Furthermore, management believes that adjusted EBITDA 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 is used as a supplemental financial measure to
assess:
- the ability of our assets to generate cash sufficient to make
future potential 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
income or expense items that we characterize as unrepresentative of
our ongoing operations.
- Adjusted EBITDA has limitations as an analytical tool and
investors should not consider it in isolation or as a substitute
for analysis of our results as reported under GAAP. For
example:
- certain items excluded from adjusted EBITDA 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 does not reflect our cash expenditures or
future requirements for capital expenditures or contractual
commitments;
- adjusted EBITDA does 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 does not reflect any
cash requirements for such replacements.
We compensate for the limitations of adjusted EBITDA as an
analytical tool by reviewing the comparable GAAP financial
measures, understanding the differences between the financial
measures and incorporating these data points into our
decision-making process.
Distributable Cash Flow
We define Distributable Cash Flow as adjusted EBITDA, as defined
above, less cash interest paid, cash paid for taxes, net interest
expense accrued and paid on the senior notes, and maintenance
capital expenditures.
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 and
(ii) 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 value-driven 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, processing and
transportation services pursuant to primarily long-term, fee-based
agreements with customers and counterparties in six unconventional
resource basins: (i) the Appalachian Basin, which includes the
Utica and Marcellus shale
formations in Ohio and
West Virginia; (ii) the
Williston Basin, which includes
the Bakken and Three Forks shale formations in North Dakota; (iii) the Denver-Julesburg
Basin, which includes the Niobrara
and Codell shale formations in Colorado and Wyoming; (iv) the Permian Basin, which
includes the Bone Spring and Wolfcamp formations in New Mexico; (v) the Fort Worth Basin, which includes the Barnett
Shale formation in Texas; and (vi)
the Piceance Basin, which includes the Mesaverde formation as well
as the Mancos and Niobrara shale formations in Colorado.
SMLP has an equity method investment in Double E Pipeline, LLC,
which provides interstate natural gas transportation service
from multiple receipt points in the Delaware Basin to various delivery points in
and around the Waha Hub in Texas. SMLP also has an equity
method investment in Ohio Gathering, which operates extensive
natural gas gathering and condensate stabilization infrastructure
in the Utica Shale in Ohio. SMLP is headquartered in
Houston, Texas.
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 include, without limitation, any statement that may
project, indicate or imply future results, events, performance or
achievements and may contain the words "expect," "intend," "plan,"
"anticipate," "estimate," "believe," "will be," "will continue,"
"will likely result," and similar expressions, or future
conditional verbs such as "may," "will," "should," "would," and
"could." In addition, any statement concerning future
financial performance (including future revenues, earnings or
growth rates), ongoing business strategies and possible actions
taken by us or our subsidiaries are also forward-looking
statements. Forward-looking statements also 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 2020 Annual Report on Form 10-K filed with
the Securities and Exchange Commission (the
"SEC") on March 4, 2021, as amended and updated from time
to time. Any forward-looking statements in this press release 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.
SUMMIT MIDSTREAM
PARTNERS, LP AND SUBSIDIARIES
UNAUDITED
CONDENSED CONSOLIDATED BALANCE SHEETS
|
|
|
December
31,
2021
|
|
December
31,
2020
|
|
(In
thousands)
|
ASSETS
|
|
|
|
Cash and cash
equivalents
|
$
7,349
|
|
$
15,544
|
Restricted
cash
|
12,223
|
|
—
|
Accounts
receivable
|
62,121
|
|
61,932
|
Other current
assets
|
5,676
|
|
4,623
|
Total current
assets
|
87,369
|
|
82,099
|
Property, plant and
equipment, net
|
1,726,082
|
|
1,813,810
|
Intangible assets,
net
|
172,927
|
|
199,566
|
Investment in equity
method investees
|
523,196
|
|
392,740
|
Other noncurrent
assets
|
12,888
|
|
11,602
|
TOTAL
ASSETS
|
$
2,522,462
|
|
$
2,499,817
|
|
|
|
|
LIABILITIES AND
CAPITAL
|
|
|
|
Trade accounts
payable
|
$
10,498
|
|
$
11,878
|
Accrued
expenses
|
14,462
|
|
13,036
|
Deferred
revenue
|
10,374
|
|
9,988
|
Ad valorem taxes
payable
|
8,570
|
|
9,086
|
Accrued compensation
and employee benefits
|
11,019
|
|
9,658
|
Accrued
interest
|
12,737
|
|
8,007
|
Accrued environmental
remediation
|
3,068
|
|
1,392
|
Accrued settlement
payable
|
4,833
|
|
—
|
Other current
liabilities
|
3,676
|
|
5,363
|
Total current
liabilities
|
79,237
|
|
68,408
|
Long-term debt,
net
|
1,355,072
|
|
1,347,326
|
Noncurrent deferred
revenue
|
42,570
|
|
48,250
|
Noncurrent accrued
environmental remediation
|
2,538
|
|
1,537
|
Other noncurrent
liabilities
|
32,357
|
|
21,747
|
Total
liabilities
|
1,511,774
|
|
1,487,268
|
Commitments and
contingencies
|
|
|
|
|
|
|
|
Mezzanine
Capital
|
|
|
|
Subsidiary Series A
Preferred Units
|
106,325
|
|
89,658
|
|
|
|
|
Partners'
Capital
|
|
|
|
Series A Preferred
Units
|
169,769
|
|
174,425
|
Common limited
partner capital
|
734,594
|
|
748,466
|
Total partners'
capital
|
904,363
|
|
922,891
|
TOTAL LIABILITIES AND
CAPITAL
|
$
2,522,462
|
|
$
2,499,817
|
|
|
|
|
SUMMIT MIDSTREAM
PARTNERS, LP AND SUBSIDIARIES
UNAUDITED
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
|
|
|
Three Months Ended
December 31,
|
|
Year Ended
December 31,
|
|
2021
|
|
2020
|
|
2021
|
|
2020
|
|
(In thousands,
except per-unit amounts)
|
Revenues:
|
|
|
|
|
|
|
|
Gathering services
and related fees
|
$
66,201
|
|
$
73,125
|
|
$
281,705
|
|
$
302,792
|
Natural gas, NGLs and
condensate sales
|
23,467
|
|
14,073
|
|
82,768
|
|
49,319
|
Other
revenues
|
9,546
|
|
9,212
|
|
36,145
|
|
31,362
|
Total
revenues
|
99,214
|
|
96,410
|
|
400,618
|
|
383,473
|
Costs and
expenses:
|
|
|
|
|
|
|
|
Cost of natural gas
and NGLs
|
23,795
|
|
13,708
|
|
81,969
|
|
36,653
|
Operation and
maintenance
|
19,297
|
|
20,899
|
|
74,178
|
|
86,030
|
General and
administrative (1)
|
9,752
|
|
33,530
|
|
58,166
|
|
73,438
|
Depreciation and
amortization
|
31,210
|
|
29,331
|
|
119,076
|
|
118,132
|
Transaction
costs
|
401
|
|
1,049
|
|
1,677
|
|
2,993
|
Gain on asset sales,
net
|
(17)
|
|
(37)
|
|
(369)
|
|
(307)
|
Long-lived asset
impairment
|
8,378
|
|
8,614
|
|
10,151
|
|
13,089
|
Total costs and
expenses
|
92,816
|
|
107,094
|
|
344,848
|
|
330,028
|
Other income
(expense), net
|
919
|
|
(596)
|
|
(613)
|
|
48
|
Loss on ECP
Warrants
|
—
|
|
—
|
|
(13,634)
|
|
—
|
Interest
expense
|
(21,171)
|
|
(14,058)
|
|
(66,156)
|
|
(78,894)
|
Gain on early
extinguishment of debt (2)
|
(3,523)
|
|
124,137
|
|
(3,523)
|
|
203,062
|
Income (loss) before
income taxes and equity method investment income
|
(17,377)
|
|
98,799
|
|
(28,156)
|
|
177,661
|
Income tax benefit
(expense)
|
(14)
|
|
42
|
|
327
|
|
146
|
Income from equity
method investees
|
1,186
|
|
4,125
|
|
7,880
|
|
11,271
|
Net income
(loss)
|
$
(16,205)
|
|
$
102,966
|
|
$
(19,949)
|
|
$
189,078
|
|
|
|
|
|
|
|
|
Net income (loss)
per limited partner unit:
|
|
|
|
|
|
|
|
Common unit –
basic
|
$
(3.42)
|
|
$
30.45
|
|
$
(6.57)
|
|
$
73.22
|
Common unit –
diluted
|
$
(3.42)
|
|
$
29.73
|
|
$
(6.57)
|
|
$
71.19
|
|
|
|
|
|
|
|
|
Weighted-average
limited partner units outstanding:
|
|
|
|
|
|
|
|
Common units –
basic
|
7,170
|
|
4,894
|
|
6,741
|
|
3,592
|
Common units –
diluted
|
7,170
|
|
5,013
|
|
6,741
|
|
3,694
|
__________
(1)
|
For the year ended
December 31, 2021, the amount includes a $22.4 million loss related
to the Blacktail Release. For the three months ended December 31,
2020, the amount includes a $17.0 loss related to the Blacktail
Release and $5.6 million of restructuring expenses. For the year
ended December 31, 2020, the amount includes a $17.0 million loss
related to the Blacktail Release and $9.0 million of restructuring
expenses.
|
|
|
(2)
|
For the year ended
December 31, 2020, the amount includes early extinguishment of
debt, primarily related to liability management initiatives
undertaken during 2020 that resulted in a $86.4 million gain from
the Open Market Repurchases, a $23.3 million gain from the Debt
Tender Offers, and a $93.9 million gain from our TL
Restructuring.
|
SUMMIT MIDSTREAM
PARTNERS, LP AND SUBSIDIARIES
UNAUDITED OTHER
FINANCIAL AND OPERATING DATA
|
|
|
Three Months Ended
December 31,
|
|
Year Ended
December 31,
|
|
2021
|
|
2020
|
|
2021
|
|
2020
|
|
(In
thousands)
|
Other financial
data:
|
|
|
|
|
|
|
|
Net income
(loss)
|
$
(16,205)
|
|
$
102,966
|
|
$
(19,949)
|
|
$
189,078
|
Net cash provided by
operating activities
|
37,368
|
|
51,782
|
|
165,099
|
|
198,589
|
Capital
expenditures
|
13,250
|
|
7,816
|
|
25,030
|
|
43,128
|
Contributions to
equity method investees
|
46,590
|
|
7,855
|
|
(148,699)
|
|
(99,927)
|
Adjusted
EBITDA
|
54,706
|
|
61,791
|
|
238,423
|
|
252,115
|
Cash flow available
for distributions (1)
|
$
29,924
|
|
$
44,755
|
|
$
168,288
|
|
$
162,835
|
Distributions
(2)
|
n/a
|
|
n/a
|
|
n/a
|
|
n/a
|
|
|
|
|
|
|
|
|
Operating
data:
|
|
|
|
|
|
|
|
Aggregate average
daily throughput – natural
gas (MMcf/d)
|
1,307
|
|
1,436
|
|
1,356
|
|
1,375
|
Aggregate average
daily throughput – liquids (Mbbl/d)
|
62
|
|
71
|
|
63
|
|
79
|
|
|
|
|
|
|
|
|
Ohio Gathering
average daily throughput (MMcf/d) (3)
|
530
|
|
621
|
|
526
|
|
571
|
Double E average
daily throughput (MMcf/d) (4)
|
58
|
|
–
|
|
15
|
|
–
|
__________
(1)
|
Cash flow available
for distributions is also referred to as Distributable Cash Flow,
or DCF.
|
|
|
(2)
|
Represents
distributions declared and ultimately paid or expected to be paid
to preferred and common unitholders in respect of a given period.
On May 3, 2020, the board of directors of SMLP's general partner
announced an immediate suspension of the cash distributions payable
on its preferred and common units.
|
|
|
(3)
|
Gross basis,
represents 100% of volume throughput for Ohio Gathering, subject to
a one-month lag.
|
|
|
(4)
|
Gross, basis,
represents 100% of volume throughput for Double E.
|
SUMMIT MIDSTREAM
PARTNERS, LP AND SUBSIDIARIES
UNAUDITED
RECONCILIATIONS TO NON-GAAP FINANCIAL MEASURES
|
|
|
Three Months Ended
December 31,
|
|
Year Ended
December 31,
|
|
2021
|
|
2020
|
|
2021
|
|
2020
|
|
(In
thousands)
|
Reconciliations of
net income or loss to
adjusted EBITDA and Distributable
Cash Flow:
|
|
|
|
|
|
|
|
Net income
|
$
(16,205)
|
|
$
102,966
|
|
$
(19,949)
|
|
$
189,078
|
Add:
|
|
|
|
|
|
|
|
Interest
expense
|
21,171
|
|
14,058
|
|
66,156
|
|
78,894
|
Income tax (benefit)
expense
|
14
|
|
(42)
|
|
(327)
|
|
(146)
|
Depreciation and
amortization (1)
|
31,425
|
|
29,565
|
|
119,995
|
|
119,070
|
Proportional adjusted
EBITDA for equity
method investees (2)
|
8,619
|
|
8,474
|
|
29,022
|
|
31,056
|
Adjustments related to
MVC shortfall
payments (3)
|
—
|
|
859
|
|
—
|
|
—
|
Adjustments related to
capital reimbursement
activity (4)
|
(1,552)
|
|
(619)
|
|
(6,571)
|
|
(1,395)
|
Unit-based and noncash
compensation
|
861
|
|
1,920
|
|
4,744
|
|
8,111
|
(Gain) loss on early
extinguishment of debt
|
3,523
|
|
(124,137)
|
|
3,523
|
|
(203,062)
|
Gain on asset sales,
net
|
(17)
|
|
(37)
|
|
(369)
|
|
(307)
|
Long-lived asset
impairment
|
8,378
|
|
8,614
|
|
10,151
|
|
13,089
|
Other, net
(5)
|
(325)
|
|
24,295
|
|
39,928
|
|
28,998
|
Less:
|
|
|
|
|
|
|
|
Income from equity
method investees
|
1,186
|
|
4,125
|
|
7,880
|
|
11,271
|
Adjusted
EBITDA
|
$
54,706
|
|
$
61,791
|
|
$
238,423
|
|
$
252,115
|
Less:
|
|
|
|
|
|
|
|
Cash interest
paid
|
17,302
|
|
17,009
|
|
57,655
|
|
79,450
|
Cash paid for
taxes
|
—
|
|
—
|
|
191
|
|
190
|
Senior notes interest
adjustment (6)
|
4,245
|
|
(3,091)
|
|
4,757
|
|
(4,487)
|
Maintenance capital
expenditures
|
3,235
|
|
3,118
|
|
7,532
|
|
14,127
|
Cash flow available
for distributions (7)
|
$
29,924
|
|
$
44,755
|
|
$
168,288
|
|
$
162,835
|
__________
(1)
|
Includes the
amortization expense associated with our favorable gas gathering
contracts as reported in other revenues.
|
|
|
(2)
|
Reflects our
proportionate share of Double E and Ohio Gathering (subject to a
one-month lag) adjusted EBITDA.
|
|
|
(3)
|
Adjustments related
to MVC shortfall payments are recognized ratably over the term of
the associated MVC.
|
|
|
(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)
|
Represents items of
income or loss that we characterize as unrepresentative of our
ongoing operations. For the year ended December 31, 2021, the
amount includes $22.2 million of losses related to the Blacktail
Release and a $13.6 million loss related to the ECP Warrants. For
the three months ended December 31, 2020, the amount includes a
$17.0 million loss related to the Blacktail Release, $5.6 million
of restructuring expenses and $1.0 million of transaction costs
associated with the GP Buy-In Transaction. For the year ended
December 31, 2020, the amount includes a $17.0 million loss related
to the Blacktail Release, $9.0 million of restructuring expenses
and $3.2 million of transaction costs associated with the GP Buy-In
Transaction.
|
|
|
(6)
|
Senior notes interest
adjustment represents the net of interest expense accrued and paid
during the period. Interest on the 5.5% senior notes was paid in
cash semi-annually in arrears on February 15 and August 15.
Interest on the 5.75% senior notes is paid in cash semi-annually in
arrears on April 15 and October 15 until maturity in April 2025.
Interest on the 8.5% senior notes is paid in cash semi-annually in
arrears on April 15 and October 15 until maturity in October
2026.
|
|
|
(7)
|
Represents cash flow
available for distribution to preferred and common unitholders.
Common distributions cannot be paid unless all accrued preferred
distributions are paid. Cash flow available for distributions is
also referred to as Distributable Cash Flow, or DCF.
|
SUMMIT MIDSTREAM
PARTNERS, LP AND SUBSIDIARIES
UNAUDITED
RECONCILIATIONS TO NON-GAAP FINANCIAL MEASURES
|
|
|
Year Ended
December 31,
|
|
2021
|
|
2020
|
|
(In
thousands)
|
Reconciliation of
net cash provided by operating activities to
adjusted
EBITDA and distributable cash flow:
|
|
|
|
Net cash provided by
operating activities
|
$
165,099
|
|
$
198,589
|
Add:
|
|
|
|
Interest expense,
excluding amortization of debt issuance costs
|
59,139
|
|
72,286
|
Income tax (benefit)
expense
|
(327)
|
|
(146)
|
Gain (loss) on ECP
warrants and unsettled interest rate swaps
|
(14,414)
|
|
259
|
Transaction
costs
|
1,677
|
|
3,913
|
Changes in operating
assets and liabilities
|
(5,867)
|
|
(50,018)
|
Proportional adjusted
EBITDA for equity method investees (1)
|
29,022
|
|
31,056
|
Adjustments related to
capital reimbursement activity (2)
|
(6,571)
|
|
(1,395)
|
Other, net
(3)
|
38,529
|
|
28,998
|
Less:
|
|
|
|
Distributions from
equity method investees
|
26,760
|
|
28,185
|
Noncash lease
expense
|
1,104
|
|
3,242
|
Adjusted
EBITDA
|
$
238,423
|
|
$
252,115
|
Less:
|
|
|
|
Cash interest
paid
|
57,655
|
|
79,450
|
Cash paid for
taxes
|
191
|
|
190
|
Senior notes interest
adjustment (4)
|
4,757
|
|
(4,487)
|
Maintenance capital
expenditures
|
7,532
|
|
14,127
|
Cash flow available
for distributions (5)
|
$
168,288
|
|
$
162,835
|
__________
(1)
|
Reflects our
proportionate share of Double E and Ohio Gathering adjusted EBITDA,
subject to a one-month lag.
|
|
|
(2)
|
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").
|
|
|
(3)
|
Represents items of
income or loss that we characterize as unrepresentative of our
ongoing operations. For the year ended December 31, 2021, the
amount includes $22.2 million of losses related to the Blacktail
Release and a $13.6 million loss related to ECP Warrants. For the
year ended December 31, 2020, the amount includes a $17.0 million
loss related to the Blacktail Release, $9.0 million of
restructuring expenses and $3.2 million of transaction costs
associated with the GP Buy-In Transaction.
|
|
|
(4)
|
Senior notes interest
adjustment represents the net of interest expense accrued and paid
during the period. Interest on the 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 5.75% senior notes is paid
in cash semi-annually in arrears on April 15 and October 15 until
maturity in April 2025.
|
|
|
(5)
|
Represents cash flow
available for distribution to preferred and common unitholders.
Common distributions cannot be paid unless all accrued preferred
distributions are paid. Cash flow available for distributions is
also referred to as Distributable Cash Flow, or DCF.
|
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SOURCE Summit Midstream Partners, LP