Press Release
Natural gas volume throughput averaged 1,761 million cubic feet per day ("MMcf/d") in the fourth quarter of 2017, an increase of 17.1% compared to 1,504 MMcf/d in the prior-year period, and a decrease of 3.6% compared to 1,826 MMcf/d in the third quarter of 2017. SMLP's natural gas volume throughput metrics exclude its proportionate share of volume from its 40% ownership interest in Ohio Gathering. Crude oil and produced water volume throughput in the fourth quarter of 2017 averaged 74.1 thousand barrels per day ("Mbbl/d"), a decrease of 10.0% compared to 82.3 Mbbl/d in the prior-year period, and flat compared to 74.0 Mbbl/d in the third quarter of 2017.
SMLP reported net income of
2018 Financial Guidance
SMLP is announcing its 2018 financial guidance, which is summarized in the table below:
2018 Financial Guidance Range |
||||||
($ in millions) |
Low |
High |
||||
Adjusted EBITDA |
$285 |
- |
$300 |
|||
Capital Expenditures(1) |
$175 |
- |
$225 |
|||
Maintenance Capital Expenditures |
$ 15 |
- |
$ 20 |
|||
Distribution Coverage Ratio |
0.95x |
- |
1.05x |
(1) Includes maintenance capital expenditures and capital contributions to equity method investees. |
SMLP's 2018 adjusted EBITDA guidance includes approximately
Capital expenditures in 2018 will primarily relate to the continued development of SMLP's northern
Mr. Newby commented, "Due to the 2016 Drop Down payment mechanics, the estimated undiscounted amount of the DPPO was reduced by approximately
Fourth Quarter 2017 Segment Results
The following table presents average daily throughput by reportable segment:
Three months ended |
Year ended |
||||||||||
2017 |
2016 |
2017 |
2016 |
||||||||
Average daily throughput (MMcf/d): |
|||||||||||
Utica Shale |
369 |
211 |
365 |
186 |
|||||||
Williston Basin |
19 |
17 |
19 |
22 |
|||||||
Piceance/DJ Basins |
575 |
615 |
595 |
586 |
|||||||
Barnett Shale |
258 |
287 |
267 |
319 |
|||||||
Marcellus Shale |
540 |
374 |
502 |
415 |
|||||||
Aggregate average daily throughput |
1,761 |
1,504 |
1,748 |
1,528 |
|||||||
Average daily throughput (Mbbl/d): |
|||||||||||
Williston Basin |
74.1 |
82.3 |
75.2 |
88.9 |
|||||||
Aggregate average daily throughput |
74.1 |
82.3 |
75.2 |
88.9 |
|||||||
Ohio Gathering average daily throughput (MMcf/d) (1) |
825 |
848 |
766 |
865 |
(1) Gross basis, represents 100% of volume throughput for Ohio Gathering, based on a one-month lag. |
Segment adjusted EBITDA for the fourth quarter of 2017 totaled
Our customers currently have one drilling rig running on acreage behind the
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
Segment adjusted EBITDA for the fourth quarter of 2017 totaled
Our customers are currently running four drilling rigs in Ohio Gathering's operating footprint. We expect volume throughput on Ohio Gathering to be positively impacted by the completion of over 40 new wells throughout 2018, which we expect will begin in the second quarter of 2018. Relative to 2017, we expect higher operating expense in 2018 related to an increase in compressor overhaul work and right-of-way repair expense. We expect these expenses will revert to more normal levels in 2019.
The Polar and
Segment adjusted EBITDA for the
Compared to the prior-year period, fourth quarter 2017 liquids volumes were impacted by natural volume declines, partially offset by 46 new wells in 2017, including 20 new wells late in the fourth quarter of 2017. Liquids volumes were also impacted by operational issues at third-party produced water disposal sites, as well as temporary crude oil production curtailments from certain customers implementing simultaneous completion activities on pad sites with flowing wells. For the fourth quarter of 2017, we estimate that these issues impacted our liquids volumes by nearly 8,000 Bbl/d. The majority of these upstream and downstream issues were resolved in
Certain of our customers remain active across the Polar and
Associated natural gas volumes averaged 19 MMcf/d in the fourth quarter of 2017, an increase of 11.8% from 17 MMcf/d in the prior-year period and a decrease of 9.5% from 21 MMcf/d in the third quarter of 2017. Relative to the prior-year period, volume increases were primarily related a two-week suspension of gathering activities on the Bison Midstream system in the fourth quarter of 2016 due to scheduled maintenance on third-party, downstream midstream infrastructure. No new wells were connected during the quarter and we expect 12 new associated natural gas wells in 2018.
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
Segment adjusted EBITDA totaled
Certain of our customers remain active across our Piceance and DJ gathering systems with four drilling rigs currently working. We expect volume growth to resume in this segment beginning in the first quarter of 2018.
The DFW Midstream system provides our midstream services for the
Segment adjusted EBITDA for the
We have visibility towards our customers commissioning six new wells in the first quarter of 2018. We expect that certain of our customers will operate workover rigs and drilling rigs intermittently in the second and third quarters of 2018 with additional new well completions in the fourth quarter of 2018, resulting in relatively flat volume throughput compared to 2017.
The Mountaineer Midstream system provides our midstream services for the
Segment adjusted EBITDA for the
There are no drilling rigs currently working behind our system. We expect our customer will complete nine new wells, currently in our customer's DUC inventory, beginning in the second quarter of 2018.
MVC Shortfall Payments
SMLP billed its customers
MVC shortfall payment adjustments in the fourth quarter of 2017 totaled
SMLP's MVC shortfall payment mechanisms contributed
Three months ended December 31, 2017 |
|||||||||||||||||
MVC |
Gathering |
Adjustments |
Net impact |
||||||||||||||
(In thousands) |
|||||||||||||||||
Net change in deferred revenue related to MVC shortfall payments: |
|||||||||||||||||
Utica Shale |
$ |
— |
$ |
— |
$ |
— |
$ |
— |
|||||||||
Williston Basin |
— |
— |
— |
— |
|||||||||||||
Piceance/DJ Basins |
3,082 |
4,169 |
(1,087) |
3,082 |
|||||||||||||
Barnett Shale |
— |
— |
— |
— |
|||||||||||||
Marcellus Shale |
— |
— |
— |
— |
|||||||||||||
Total net change |
$ |
3,082 |
$ |
4,169 |
$ |
(1,087) |
$ |
3,082 |
|||||||||
MVC shortfall payment adjustments: |
|||||||||||||||||
Utica Shale |
$ |
— |
$ |
— |
$ |
— |
$ |
— |
|||||||||
Williston Basin |
9,166 |
9,166 |
(5,946) |
3,220 |
|||||||||||||
Piceance/DJ Basins |
8,608 |
8,608 |
(870) |
7,738 |
|||||||||||||
Barnett Shale |
382 |
382 |
(284) |
98 |
|||||||||||||
Marcellus Shale |
1,007 |
1,007 |
— |
1,007 |
|||||||||||||
Total MVC shortfall payment adjustments |
$ |
19,163 |
$ |
19,163 |
$ |
(7,100) |
$ |
12,063 |
|||||||||
Total (1) |
$ |
22,245 |
$ |
23,332 |
$ |
(8,187) |
$ |
15,145 |
(1) Exclusive of Ohio Gathering due to equity method accounting. |
Year ended December 31, 2017 |
|||||||||||||||||
MVC |
Gathering |
Adjustments |
Net impact |
||||||||||||||
(In thousands) |
|||||||||||||||||
Net change in deferred revenue related to MVC shortfall payments: |
|||||||||||||||||
Utica Shale |
$ |
— |
$ |
— |
$ |
— |
$ |
— |
|||||||||
Williston Basin |
— |
37,693 |
(37,693) |
— |
|||||||||||||
Piceance/DJ Basins |
13,106 |
16,171 |
(3,065) |
13,106 |
|||||||||||||
Barnett Shale |
— |
— |
— |
— |
|||||||||||||
Marcellus Shale |
— |
— |
— |
— |
|||||||||||||
Total net change |
$ |
13,106 |
$ |
53,864 |
$ |
(40,758) |
$ |
13,106 |
|||||||||
MVC shortfall payment adjustments: |
|||||||||||||||||
Utica Shale |
$ |
— |
$ |
— |
$ |
— |
$ |
— |
|||||||||
Williston Basin |
12,958 |
12,958 |
— |
12,958 |
|||||||||||||
Piceance/DJ Basins |
28,608 |
28,608 |
(3) |
28,605 |
|||||||||||||
Barnett Shale |
4,032 |
4,032 |
(612) |
3,420 |
|||||||||||||
Marcellus Shale |
4,398 |
4,398 |
— |
4,398 |
|||||||||||||
Total MVC shortfall payment adjustments |
$ |
49,996 |
$ |
49,996 |
$ |
(615) |
$ |
49,381 |
|||||||||
Total (1) |
$ |
63,102 |
$ |
103,860 |
$ |
(41,373) |
$ |
62,487 |
(1) Exclusive of Ohio Gathering due to equity method accounting. |
Capital Expenditures
Capital expenditures totaled
Capital & Liquidity
As of
In
Deferred Purchase Price Obligation
The consideration for the 2016 Drop Down consisted of (i) an initial
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 EBITDA generated from the 2016 Drop Down Assets in 2018 and 2019.
SMLP reduced the estimated undiscounted amount of the Deferred Payment related to the 2016 Drop Down transaction from
A slower pace of growth capital expenditures, particularly in the
Quarterly Distribution
On
Fourth Quarter 2017 Earnings Call Information
SMLP will host a conference call at
A replay of the conference call will be available until
Upcoming Investor Conferences
Members of SMLP's senior management team will participate in the Barclays Select Series: MLP Corporate Access Day in
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, unit-based and noncash compensation, Deferred Purchase Price Obligation, 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, 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
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
About
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 2016 Annual Report on Form 10-K as updated and superseded by the Current Report on Form 8-K filed with the
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 |
||||||||
December 31, |
||||||||
2017 |
2016 |
|||||||
(In thousands) |
||||||||
Assets |
||||||||
Current assets: |
||||||||
Cash and cash equivalents |
$ |
1,430 |
$ |
7,428 |
||||
Accounts receivable |
72,301 |
97,364 |
||||||
Other current assets |
4,327 |
4,309 |
||||||
Total current assets |
78,058 |
109,101 |
||||||
Property, plant and equipment, net |
1,795,129 |
1,853,671 |
||||||
Intangible assets, net |
301,345 |
421,452 |
||||||
Goodwill |
16,211 |
16,211 |
||||||
Investment in equity method investees |
690,485 |
707,415 |
||||||
Other noncurrent assets |
13,565 |
7,329 |
||||||
Total assets |
$ |
2,894,793 |
$ |
3,115,179 |
||||
Liabilities and Partners' Capital |
||||||||
Current liabilities: |
||||||||
Trade accounts payable |
$ |
16,375 |
$ |
16,251 |
||||
Accrued expenses |
12,499 |
11,389 |
||||||
Due to affiliate |
1,088 |
258 |
||||||
Deferred revenue |
4,000 |
— |
||||||
Ad valorem taxes payable |
8,329 |
10,588 |
||||||
Accrued interest |
12,310 |
17,483 |
||||||
Accrued environmental remediation |
3,130 |
4,301 |
||||||
Other current liabilities |
11,258 |
11,471 |
||||||
Total current liabilities |
68,989 |
71,741 |
||||||
Long-term debt |
1,051,192 |
1,240,301 |
||||||
Deferred Purchase Price Obligation |
362,959 |
563,281 |
||||||
Deferred revenue |
12,707 |
57,465 |
||||||
Noncurrent accrued environmental remediation |
2,214 |
5,152 |
||||||
Other noncurrent liabilities |
7,063 |
7,566 |
||||||
Total liabilities |
1,505,124 |
1,945,506 |
||||||
Series A Preferred Units |
294,426 |
— |
||||||
Common limited partner capital |
1,056,510 |
1,129,132 |
||||||
General Partner interests |
27,920 |
29,294 |
||||||
Noncontrolling interest |
10,813 |
11,247 |
||||||
Total partners' capital |
1,389,669 |
1,169,673 |
||||||
Total liabilities and partners' capital |
$ |
2,894,793 |
$ |
3,115,179 |
SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES |
||||||||||||||||
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS |
||||||||||||||||
Three months ended |
Year ended |
|||||||||||||||
2017 |
2016 |
2017 |
2016 |
|||||||||||||
(In thousands, except per-unit amounts) |
||||||||||||||||
Revenues: |
||||||||||||||||
Gathering services and related fees |
$ |
95,543 |
$ |
111,378 |
$ |
394,427 |
$ |
345,961 |
||||||||
Natural gas, NGLs and condensate sales |
23,804 |
10,086 |
68,459 |
35,833 |
||||||||||||
Other revenues |
6,852 |
5,619 |
25,855 |
20,568 |
||||||||||||
Total revenues |
126,199 |
127,083 |
488,741 |
402,362 |
||||||||||||
Costs and expenses: |
||||||||||||||||
Cost of natural gas and NGLs |
20,909 |
7,281 |
57,237 |
27,421 |
||||||||||||
Operation and maintenance |
23,871 |
23,023 |
93,882 |
95,334 |
||||||||||||
General and administrative |
14,311 |
14,287 |
54,681 |
52,410 |
||||||||||||
Depreciation and amortization |
29,291 |
28,569 |
115,475 |
112,239 |
||||||||||||
Transaction costs |
(46) |
25 |
73 |
1,321 |
||||||||||||
(Gain) Loss on asset sales, net |
(3) |
69 |
527 |
93 |
||||||||||||
Long-lived asset impairment |
187,125 |
23 |
188,702 |
1,764 |
||||||||||||
Total costs and expenses |
275,458 |
73,277 |
510,577 |
290,582 |
||||||||||||
Other income |
84 |
24 |
298 |
116 |
||||||||||||
Interest expense |
(16,248) |
(16,160) |
(68,131) |
(63,810) |
||||||||||||
Early extinguishment of debt |
(19) |
— |
(22,039) |
— |
||||||||||||
Deferred Purchase Price Obligation |
145,648 |
(24,738) |
200,322 |
(55,854) |
||||||||||||
(Loss) income before income taxes and income (loss) from equity method investees |
(19,794) |
12,932 |
88,614 |
(7,768) |
||||||||||||
Income tax benefit (expense) |
76 |
66 |
(341) |
(75) |
||||||||||||
Income (loss) from equity method investees |
1,468 |
997 |
(2,223) |
(30,344) |
||||||||||||
Net (loss) income |
$ |
(18,250) |
$ |
13,995 |
$ |
86,050 |
$ |
(38,187) |
||||||||
Earnings (loss) per limited partner unit: |
||||||||||||||||
Common unit – basic |
$ |
(0.32) |
$ |
0.16 |
$ |
0.99 |
$ |
(0.71) |
||||||||
Common unit – diluted |
$ |
(0.32) |
$ |
0.16 |
$ |
0.98 |
$ |
(0.71) |
||||||||
Weighted-average limited partner units outstanding: |
||||||||||||||||
Common units – basic |
73,068 |
72,096 |
72,705 |
68,264 |
||||||||||||
Common units – diluted |
73,068 |
72,096 |
73,047 |
68,264 |
SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES |
|||||||||||||||
UNAUDITED OTHER FINANCIAL AND OPERATING DATA |
|||||||||||||||
Three months ended |
Year ended |
||||||||||||||
2017 |
2016 |
2017 |
2016 |
||||||||||||
(Dollars in thousands) |
|||||||||||||||
Other financial data: |
|||||||||||||||
Net (loss) income |
$ |
(18,250) |
$ |
13,995 |
$ |
86,050 |
$ |
(38,187) |
|||||||
Net cash provided by operating activities |
$ |
41,335 |
$ |
61,790 |
$ |
237,832 |
$ |
230,495 |
|||||||
Capital expenditures |
$ |
38,009 |
$ |
19,984 |
$ |
124,215 |
$ |
142,719 |
|||||||
Contributions to equity method investees |
$ |
3,932 |
$ |
11,425 |
$ |
25,513 |
$ |
31,582 |
|||||||
Acquisitions of gathering systems (1) |
$ |
— |
$ |
— |
$ |
— |
$ |
866,858 |
|||||||
Adjusted EBITDA |
$ |
72,923 |
$ |
72,721 |
$ |
290,387 |
$ |
291,601 |
|||||||
Distributable cash flow |
$ |
49,173 |
$ |
52,802 |
$ |
205,010 |
$ |
210,906 |
|||||||
Distributions declared (2) |
$ |
45,054 |
$ |
44,452 |
$ |
179,705 |
$ |
170,981 |
|||||||
Distribution coverage ratio (3) |
1.09x |
1.19x |
1.14x |
1.23x |
|||||||||||
Operating data: |
|||||||||||||||
Aggregate average daily throughput – natural gas (MMcf/d) |
1,761 |
1,504 |
1,748 |
1,528 |
|||||||||||
Aggregate average daily throughput – liquids (Mbbl/d) |
74.1 |
82.3 |
75.2 |
88.9 |
|||||||||||
Ohio Gathering average daily throughput (MMcf/d) (4) |
825 |
848 |
766 |
865 |
(1) Reflects cash and noncash consideration, including working capital and capital expenditure adjustments paid (received), for acquisitions and/or drop downs. |
||||||
(2) Represents distributions declared to common unitholders in respect of a given period. For example, for the three months ended December 31, 2017, represents the distributions paid in February 2018. |
||||||
(3) Distribution coverage ratio calculation for the three months ended December 31, 2017 and 2016 is based on distributions declared to common unitholders in respect of the fourth quarter of 2017 and 2016. Represents the ratio of distributable cash flow to distributions declared. |
||||||
(4) 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 |
Year ended |
|||||||||||||||
2017 |
2016 |
2017 |
2016 |
|||||||||||||
(In thousands) |
||||||||||||||||
Reportable segment adjusted EBITDA (1): |
||||||||||||||||
Utica Shale |
$ |
8,154 |
$ |
6,137 |
$ |
34,011 |
$ |
21,035 |
||||||||
Ohio Gathering (2) |
12,045 |
10,429 |
41,246 |
45,602 |
||||||||||||
Williston Basin |
15,237 |
18,730 |
66,413 |
79,475 |
||||||||||||
Piceance/DJ Basins |
31,481 |
30,121 |
117,737 |
109,241 |
||||||||||||
Barnett Shale |
10,308 |
13,516 |
46,232 |
54,634 |
||||||||||||
Marcellus Shale |
6,113 |
4,649 |
23,888 |
19,203 |
||||||||||||
Total |
$ |
83,338 |
$ |
83,582 |
$ |
329,527 |
$ |
329,190 |
||||||||
Less Corporate and other (3) |
10,415 |
10,861 |
39,140 |
37,589 |
||||||||||||
Adjusted EBITDA |
$ |
72,923 |
$ |
72,721 |
$ |
290,387 |
$ |
291,601 |
(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 |
Year ended |
|||||||||||||||
2017 |
2016 |
2017 |
2016 |
|||||||||||||
(In thousands) |
||||||||||||||||
Reconciliations of net income or loss to adjusted EBITDA and distributable cash flow: |
||||||||||||||||
Net (loss) income |
$ |
(18,250) |
$ |
13,995 |
$ |
86,050 |
$ |
(38,187) |
||||||||
Add: |
||||||||||||||||
Interest expense |
16,248 |
16,160 |
68,131 |
63,810 |
||||||||||||
Income tax (benefit) expense |
(76) |
(66) |
341 |
75 |
||||||||||||
Depreciation and amortization (1) |
29,140 |
28,603 |
114,872 |
112,661 |
||||||||||||
Proportional adjusted EBITDA for equity method investees (2) |
12,045 |
10,429 |
41,246 |
45,602 |
||||||||||||
Adjustments related to MVC shortfall payments (3) |
(8,187) |
(22,218) |
(41,373) |
11,600 |
||||||||||||
Unit-based and noncash compensation |
1,978 |
1,985 |
7,951 |
7,985 |
||||||||||||
Deferred Purchase Price Obligation (4) |
(145,648) |
24,738 |
(200,322) |
55,854 |
||||||||||||
Early extinguishment of debt (5) |
19 |
— |
22,039 |
— |
||||||||||||
(Gain) loss on asset sales, net |
(3) |
69 |
527 |
93 |
||||||||||||
Long-lived asset impairment |
187,125 |
23 |
188,702 |
1,764 |
||||||||||||
Less: |
||||||||||||||||
Income (loss) from equity method investees |
1,468 |
997 |
(2,223) |
(30,344) |
||||||||||||
Adjusted EBITDA |
$ |
72,923 |
$ |
72,721 |
$ |
290,387 |
$ |
291,601 |
||||||||
Add: |
||||||||||||||||
Cash taxes received |
— |
— |
— |
50 |
||||||||||||
Less: |
||||||||||||||||
Cash interest paid |
24,078 |
5,783 |
71,488 |
63,000 |
||||||||||||
Senior notes interest adjustment (6) |
(7,855) |
9,750 |
(5,261) |
— |
||||||||||||
Distributions to Series A Preferred unitholders (7) |
2,375 |
— |
2,375 |
— |
||||||||||||
Series A Preferred units distribution adjustment (8) |
1,188 |
— |
1,188 |
— |
||||||||||||
Maintenance capital expenditures |
3,964 |
4,386 |
15,587 |
17,745 |
||||||||||||
Distributable cash flow |
$ |
49,173 |
$ |
52,802 |
$ |
205,010 |
$ |
210,906 |
||||||||
Distributions declared (9) |
$ |
45,054 |
$ |
44,452 |
$ |
179,705 |
$ |
170,981 |
||||||||
Distribution coverage ratio (10) |
1.09x |
1.19x |
1.14x |
1.23x |
(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 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. |
|||||||
(4) Deferred Purchase Price Obligation represents the change in the present value of the Deferred Purchase Price Obligation. |
|||||||
(5) 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. |
|||||||
(6) 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, beginning October 15, 2017 until maturity in April 2025. |
|||||||
(7) Distributions on the Series A preferred units are paid in cash semi-annually in arrears on June 15 and December 15 each year, beginning on December 15, 2017 through and including December 15, 2022, and, thereafter, quarterly in arrears on the 15th day of March, June, September and December of each year. |
|||||||
(8) Series A Preferred unit distribution adjustment represents the distributions accrued on the Series A preferred units. |
|||||||
(9) Represents distributions declared to common unitholders in respect of a given period. For example, for the three months ended December 31, 2017, represents the distributions paid in February 2018. |
|||||||
(10) Distribution coverage ratio calculation for the three months ended December 31, 2017 and 2016 is based on distributions declared in respect of the fourth quarter of 2017 and 2016. Represents the ratio of distributable cash flow to distributions declared. |
SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES |
||||||||
UNAUDITED RECONCILIATIONS TO NON-GAAP FINANCIAL MEASURES |
||||||||
Year ended December 31, |
||||||||
2017 |
2016 |
|||||||
Reconciliation of net cash provided by operating activities to adjusted EBITDA and distributable cash flow: |
||||||||
Net cash provided by operating activities |
$ |
237,832 |
$ |
230,495 |
||||
Add: |
||||||||
Interest expense, excluding amortization of debt issuance costs |
63,973 |
59,834 |
||||||
Income tax expense |
341 |
75 |
||||||
Changes in operating assets and liabilities |
28,890 |
(11,014) |
||||||
Proportional adjusted EBITDA for equity method investees (1) |
41,246 |
45,602 |
||||||
Adjustments related to MVC shortfall payments (2) |
(41,373) |
11,600 |
||||||
Less: |
||||||||
Distributions from equity method investees |
40,220 |
44,991 |
||||||
Write-off of debt issuance costs |
302 |
— |
||||||
Adjusted EBITDA |
$ |
290,387 |
$ |
291,601 |
||||
Add: |
||||||||
Cash taxes received |
— |
50 |
||||||
Less: |
||||||||
Cash interest paid |
71,488 |
63,000 |
||||||
Senior notes interest adjustment (3) |
(5,261) |
— |
||||||
Distributions to Series A Preferred unitholders (4) |
2,375 |
— |
||||||
Series A Preferred units distribution adjustment (5) |
1,188 |
— |
||||||
Maintenance capital expenditures |
15,587 |
17,745 |
||||||
Distributable cash flow |
$ |
205,010 |
$ |
210,906 |
(1) Reflects our proportionate share of Ohio Gathering adjusted EBITDA, based on a one-month lag. |
||||||
(2) Adjustments related to MVC shortfall payments 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. |
||||||
(3) 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, beginning October 15, 2017 until maturity in April 2025. |
||||||
(4) Distributions on the Series A preferred units are paid in cash semi-annually in arrears on June 15 and December 15 each year, beginning on December 15, 2017 through and including December 15, 2022, and, thereafter, quarterly in arrears on the 15th day of March, June, September and December of each year. |
||||||
(5) Series A Preferred unit distribution adjustment represents the distributions accrued on the Series A preferred units. |
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SOURCE
Marc Stratton, Senior Vice President and Treasurer, 832-608-6166, ir@summitmidstream.com