Attached files
| file | filename |
|---|---|
| 8-K - SMLP 2Q17 ER FORM 8-K - Summit Midstream Partners, LP | a0617earnings8-k.htm |
EXHIBIT 99.1
 | Summit Midstream Partners, LP 1790 Hughes Landing Blvd, Suite 500 The Woodlands, TX 77380 |
Summit Midstream Partners, LP Reports Second Quarter 2017 Financial Results
– | Second quarter 2017 net income of $11.2 million |
– | Second quarter 2017 adjusted EBITDA of $72.6 million and DCF of $50.0 million |
– | Second quarter 2017 distribution coverage ratio was 1.11x |
– | Strong natural gas volume growth in the second quarter of 2017 offset by liquids volume decline; liquids volumes impacted by deferred completion activities |
– | In July 2017, SMLP announced a new $110.0 million gathering and processing project in the Delaware Basin for XTO Energy |
The Woodlands, Texas (August 3, 2017) - Summit Midstream Partners, LP (NYSE: SMLP) announced today its financial and operating results for the three and six months ended June 30, 2017. SMLP reported net income of $11.2 million for the second quarter of 2017 compared to a net loss of $50.6 million for the prior-year period. Net cash provided by operations totaled $58.9 million in the second quarter of 2017 compared to $64.7 million in the prior-year period. Adjusted EBITDA totaled $72.6 million and distributable cash flow totaled $50.0 million for the second quarter of 2017 compared to $72.4 million and $51.0 million, respectively, for the prior-year period.
Natural gas volume throughput averaged 1,780 million cubic feet per day (“MMcf/d”) in the second quarter of 2017, an increase of 17.7% compared to 1,512 MMcf/d in the prior-year period, and an increase of 9.4% compared to 1,627 MMcf/d in the first quarter of 2017. Crude oil and produced water volume throughput in the second quarter of 2017 averaged 68.9 thousand barrels per day (“Mbbl/d”), a decrease of 19.9% compared to 86.0 Mbbl/d in the prior-year period, and a decrease of 9.8% compared to 76.4 Mbbl/d in the first quarter of 2017. SMLP’s natural gas volume throughput metrics exclude its proportionate share of volume throughput from its 40% ownership interest in Ohio Gathering.
Steve Newby, President and Chief Executive Officer, commented, “SMLP’s financial and operating results for the second quarter of 2017 were in line with our expectations, and we continue to expect volume and cash flow growth in the second half of 2017. Based on recent feedback from certain customers, we expect well completion activity, particularly in the Williston, Piceance and Utica segments, to be slower than originally expected. In many cases, well completion activity will be pushed to later dates in the second half of 2017 and in some cases, from the second half of 2017 into the first half of 2018. As a result, we have lowered the midpoint of our 2017 adjusted EBITDA financial guidance by 4.1% from $305.0 million to $292.5 million.
SMLP had a number of positive developments in the second quarter of 2017 that we expect will benefit our business over the long term. We announced a new gathering and processing project for XTO Energy in the Delaware Basin which is expected to commence operations in the second quarter of 2018. Our largest customer, Encana, sold its Piceance acreage to a private equity-backed E&P company that we expect will be significantly more active behind our Piceance gathering system going forward. We commissioned the TPL-7 connector project behind our Summit Midstream Utica system which helped drive sequential quarterly volume growth on that system from 275 MMcf/d in the first quarter of 2017 to 413 MMcf/d in the second quarter of 2017. We amended our $1.25 billion revolving credit facility and extended the term of the facility from November 2018 to May 2022. Our customers continued their pace of drilling behind our systems with 11 to 12 rigs working throughout the second quarter.
We expect volume and cash flow growth from our existing asset base for the balance of 2017. We are encouraged by our team’s commercial efforts, including our recently announced Delaware Basin organic development project, which is expected to be operational in the first half of 2018 at a total investment cost of $110.0 million. We are also currently evaluating a number of new commercial opportunities in and around our existing service area and we expect that these opportunities will lead to incremental growth beginning in 2018.”
SMLP reported net income of $10.7 million for the first six months of 2017 compared to a net loss of $54.2 million for the prior-year period. Net cash provided by operations totaled $121.3 million for the first six months of 2017
EX 99.1-1
EXHIBIT 99.1
compared to $131.5 million in the prior-year period. SMLP reported adjusted EBITDA of $144.0 million and distributable cash flow of $103.0 million compared to $142.4 million and $102.5 million, respectively for the prior-year period. Natural gas volume throughput averaged 1,704 MMcf/d for the first six months of 2017 compared to 1,518 MMcf/d in the prior-year period. Crude oil and produced water volume throughput averaged 72.6 Mbbl/d in the first six months of 2017 compared to 90.5 Mbbl/d in the prior-year period.
2017 Financial Guidance
On July 27, 2017, SMLP revised its 2017 financial guidance due to our expectation for a slower pace of well completions in the second half of 2017. The original 2017 adjusted EBITDA guidance range of $295.0 million to $315.0 million was revised to a new range of $285.0 million to $300.0 million. At the midpoint, 2017 adjusted EBITDA was reduced by 4.1% from $305.0 million to $292.5 million.
As a result of our recently announced organic development project in the Delaware Basin, partially offset by slower capital spending across our other basins, SMLP also updated its 2017 capital expenditure guidance to a new range of $125.0 million to $150.0 million, including maintenance capex of $15.0 million to $20.0 million. SMLP’s 2017 capex guidance reflects the inclusion of our contributions to equity method investees. SMLP expects its full year distribution coverage will range from 1.10x to 1.20x.
Second Quarter 2017 Segment Results
The following table presents average daily throughput by reportable segment:
Three months ended June 30, | Six months ended June 30, | ||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||
Average daily throughput (MMcf/d): | |||||||||||
Utica Shale | 413 | 167 | 344 | 150 | |||||||
Williston Basin | 20 | 24 | 19 | 24 | |||||||
Piceance/DJ Basins | 596 | 564 | 605 | 568 | |||||||
Barnett Shale | 271 | 341 | 279 | 341 | |||||||
Marcellus Shale | 480 | 416 | 457 | 435 | |||||||
Aggregate average daily throughput | 1,780 | 1,512 | 1,704 | 1,518 | |||||||
Average daily throughput (Mbbl/d): | |||||||||||
Williston Basin | 68.9 | 86.0 | 72.6 | 90.5 | |||||||
Aggregate average daily throughput | 68.9 | 86.0 | 72.6 | 90.5 | |||||||
Ohio Gathering average daily throughput (MMcf/d) (1) | 706 | 937 | 737 | 903 | |||||||
__________
(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”), the natural gas gathering system operated by SMLP which is currently in service and under development in Belmont and Monroe counties in southeastern Ohio. Summit Utica 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 second quarter of 2017 totaled $9.5 million, up 102% from $4.7 million for the prior-year period, primarily due to higher volume throughput across the SMU system. Volume throughput at SMU averaged 413 MMcf/d in the second quarter of 2017 compared to 167 MMcf/d in the prior-year period and 275 MMcf/d in the first quarter of 2017. Volume throughput for the second quarter of 2017 increased relative to the prior-year period due to our customers’ completion of six new wells behind the system in the first quarter of 2017 and another five new wells in the second quarter of 2017. In addition, in April 2017, we commissioned the TPL-7 connector project, a new pipeline designed to offload capacity constrained natural gas from a third-party gathering system adjacent to the SMU system. This project significantly increased volumes across SMU in the second quarter of 2017.
EX 99.1-2
EXHIBIT 99.1
We have one drilling rig currently running behind our SMU system and we expect that our customers will complete another four wells behind the SMU system in the second half of 2017.
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 first quarter of 2017 totaled $9.6 million, down 24.5% from $12.7 million for the prior-year period, primarily due to lower volume throughput on Ohio Gathering and lower stabilization revenue at Ohio Condensate. Segment adjusted EBITDA for the second quarter of 2017 was also negatively impacted by higher operating expenses related to compressor overhauls in the quarter. Volume throughput on the Ohio Gathering system, which is based on a one-month lag, averaged 706 MMcf/d, gross, in the second quarter of 2017 compared to 937 MMcf/d, gross, in the prior-year period and 769 MMcf/d, gross, in the first quarter of 2017. Volume throughput on Ohio Gathering in the second quarter of 2017 was impacted by natural production declines from existing wells on the system and was partially offset by volumes from 10 new condensate wells that were commissioned during the quarter. Dry natural gas volumes on the Ohio Gathering system were favorably impacted by the commissioning of the Larew Compressor Station in March 2017 which lowered pressures across the dry gas system and facilitated increased volumes.
Our customers are currently running two drilling rigs in Ohio Gathering’s operating footprint. We expect to see the production volume increase beginning in the third quarter of 2017 based on our customers running five drilling rigs across the Ohio Gathering system in the first five months of 2017.
Williston Basin
The Bison Midstream, Polar and Divide and Tioga Midstream systems provide our midstream services for the Williston Basin reportable segment. 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. The Polar and Divide system gathers crude oil production in Williams and Divide counties in North Dakota and delivers to the COLT and Basin Transload rail terminals, as well as other third-party, intra- and interstate pipelines. 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.
Segment adjusted EBITDA for the Williston Basin segment totaled $17.2 million for the second quarter of 2017 compared to $19.2 million for the prior-year period. Compared to the prior-year period, second quarter 2017 volumes were negatively impacted due to a lack of new well completions behind our gathering systems during the quarter. In addition to lower volumes, a certain Williston customer has gathering rates that reset lower in July 2016 which negatively impacted our year-over-year comparisons. The Williston Basin segment benefitted in the second quarter of 2017 from the recognition of $2.8 million of gathering revenue related to (i) gathering services fees from previously billed but unearned revenue, and (ii) crude oil and produced water volumes that a customer trucked around our gathering system in the second half of 2016.
Liquids volumes averaged 68.9 Mbbl/d in the second quarter of 2017, a decrease of 19.9% over the prior-year period and a decrease of 9.8% compared to the first quarter of 2017. Lower liquids volumes were primarily related to natural production declines from existing wells on the Polar and Divide system as six new wells were completed late in the second quarter of 2017. Certain of our customers remain active across the Polar and Divide system, with four drilling rigs currently working and adding to an existing backlog of approximately 40 drilled uncompleted wells (“DUCs”) currently behind our Polar and Divide gathering system. We expect many of these DUCs to begin to be completed over the next several months. Overall, we expect the pace of well completions by our customers on the Polar and Divide system to be slower than originally anticipated.
Associated natural gas volumes averaged 20 MMcf/d in the second quarter of 2017, a decrease of 16.7% over the prior-year period and up 17.6% from the first quarter of 2017. Relative to the prior-year period, volume declines were primarily related to natural production declines from existing wells on the Bison Midstream and Tioga Midstream
EX 99.1-3
EXHIBIT 99.1
systems as no new wells were connected during the quarter. Volumes increased relative to the first quarter of 2017 due to the severe winter weather that impacted natural gas volumes in this segment in the first quarter of 2017.
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 $27.3 million for the second quarter of 2017, an increase of 4.0% from $26.2 million for the prior-year period. Second quarter 2017 volume throughput averaged 596 MMcf/d, an increase of 5.7% from 564 MMcf/d in the prior-year period and a decrease of 3.1% from 615 MMcf/d in the first quarter of 2017. Volume growth relative to the prior-year period was primarily due to ongoing drilling and completion activity from our single-basin focused, private equity-backed customers. These customers commissioned dozens of new wells across our Piceance and DJ Basin gathering systems in 2016, and in the first quarter of 2017, these customers commissioned another 31 new wells; seven new wells were commissioned behind our systems late in the second quarter of 2017. This activity was partially offset by the impact of our anchor customer’s continued suspension of drilling activities in the basin and the resulting natural declines from existing production. This impact of our anchor customer’s volume declines was partially offset by higher minimum volume commitment (“MVC”) shortfall payment adjustments associated with our gas gathering agreements. Certain of our customers remain active across our Piceance and DJ gathering systems with four drilling rigs currently working. We expect drilling levels to increase and volume growth to follow as a result of Caerus’ recent acquisition of Encana’s acreage in the Piceance Basin.
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 $13.0 million for the second quarter of 2017, a decrease of 6.6% from the prior-year period. Volume throughput of 271 MMcf/d in the second quarter of 2017 was down 20.5% compared to the prior-year period average of 341 MMcf/d and down 5.2% from 286 MMcf/d in the first quarter of 2017. No new wells were completed behind the DFW gathering system in the second quarter of 2017, but two of our customers resumed drilling activity behind the DFW system beginning in April 2017. The two new rigs were added by single basin-focused, private equity-backed customers who acquired the underlying acreage in the last 18 months. Two workover rigs also continue to operate behind our system and return several dormant wells to service. We expect this workover activity will continue across the second half of 2017 and, together with the expected completions of the new wells currently being drilled, will increase volume throughput beginning in the fourth quarter of 2017.
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 $5.4 million for the second quarter of 2017, an increase of 13.3% from $4.8 million for the prior-year period, primarily due to an increase in volume throughput, partially offset by $0.5 million of right-of-way repair expenses incurred during the quarter. Volume throughput for this segment averaged 480 MMcf/d in the second quarter of 2017, an increase of 15.4% from 416 MMcf/d in the prior-year period, and an increase of 10.6% from 434 MMcf/d in the first quarter of 2017. Volume throughput increased relative to the first quarter of 2017 as a result of our customer completing 11 new wells behind our system. Although there are no rigs currently working behind our system, we expect our customer to continue to complete its inventory of DUCs behind the Mountaineer Midstream system throughout the balance of the year, which we expect to drive volumes higher in the third and fourth quarter of 2017.
MVC Shortfall Payments
SMLP billed its customers $9.0 million in the second quarter of 2017 related to MVCs. 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 that they are earned. For the second quarter of 2017, SMLP recognized $10.2 million of gathering revenue associated with MVC
EX 99.1-4
EXHIBIT 99.1
shortfall payments from certain customers in the Williston Basin, Piceance/DJ Basins, Barnett Shale and Marcellus Shale reportable segments.
MVC shortfall payment adjustments in the second quarter of 2017 totaled $5.6 million and included ($1.2) million of deferred revenue related to MVC shortfall payments and $6.8 million related to MVC shortfall payment adjustments from certain customers in the Piceance/DJ Basins, Williston Basin and Barnett Shale reportable segments.
SMLP’s MVC shortfall payment mechanisms contributed $15.7 million of adjusted EBITDA in the second quarter of 2017.
Three months ended June 30, 2017 | ||||||||||||||||
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 | 3,096 | 4,282 | (1,186 | ) | 3,096 | |||||||||||
Barnett Shale | — | — | — | — | ||||||||||||
Marcellus Shale | — | — | — | — | ||||||||||||
Total net change | $ | 3,096 | $ | 4,282 | $ | (1,186 | ) | $ | 3,096 | |||||||
MVC shortfall payment adjustments: | ||||||||||||||||
Utica Shale | $ | — | $ | — | $ | — | $ | — | ||||||||
Williston Basin | 1,081 | 1,081 | 1,982 | 3,063 | ||||||||||||
Piceance/DJ Basins | 266 | 266 | 6,522 | 6,788 | ||||||||||||
Barnett Shale | 3,366 | 3,366 | (1,740 | ) | 1,626 | |||||||||||
Marcellus Shale | 1,162 | 1,162 | — | 1,162 | ||||||||||||
Total MVC shortfall payment adjustments | $ | 5,875 | $ | 5,875 | $ | 6,764 | $ | 12,639 | ||||||||
Total (1) | $ | 8,971 | $ | 10,157 | $ | 5,578 | $ | 15,735 | ||||||||
__________
(1) Exclusive of Ohio Gathering due to equity method accounting.
EX 99.1-5
EXHIBIT 99.1
Six months ended June 30, 2017 | ||||||||||||||||
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 | — | 37,693 | (37,693 | ) | — | |||||||||||
Piceance/DJ Basins | 6,670 | 8,648 | (1,978 | ) | 6,670 | |||||||||||
Barnett Shale | — | — | — | — | ||||||||||||
Marcellus Shale | — | — | — | — | ||||||||||||
Total net change | $ | 6,670 | $ | 46,341 | $ | (39,671 | ) | $ | 6,670 | |||||||
MVC shortfall payment adjustments: | ||||||||||||||||
Utica Shale | $ | — | $ | — | $ | — | $ | — | ||||||||
Williston Basin | 2,687 | 2,687 | 3,964 | 6,651 | ||||||||||||
Piceance/DJ Basins | 518 | 518 | 13,067 | 13,585 | ||||||||||||
Barnett Shale | 3,650 | 3,650 | (422 | ) | 3,228 | |||||||||||
Marcellus Shale | 2,402 | 2,402 | — | 2,402 | ||||||||||||
Total MVC shortfall payment adjustments | $ | 9,257 | $ | 9,257 | $ | 16,609 | $ | 25,866 | ||||||||
Total (1) | $ | 15,927 | $ | 55,598 | $ | (23,062 | ) | $ | 32,536 | |||||||
__________
(1) Exclusive of Ohio Gathering due to equity method accounting.
Capital Expenditures
Capital expenditures totaled $42.2 million in the second quarter of 2017, including $10.7 million of contributions to equity method investees and maintenance capital expenditures of approximately $5.9 million. Development activities during the second quarter of 2017 were primarily related to the ongoing expansion of our Summit Midstream Utica natural gas gathering system as well as the continued development of certain pipeline and compression expansion projects in the Williston and Piceance/DJ Basins segment.
Capital & Liquidity
As of June 30, 2017, SMLP had $759.0 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 $1.291 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 June 30, 2017 were 4.35 to 1.0 and 1.65 to 1.0, respectively.
In May 2017, SMLP executed an amendment and extension of its $1.25 billion revolving credit facility. The maturity date of the revolving credit facility was extended by approximately 3.5 years, from November 2018 to May 2022. The facility includes a $250.0 million accordion and has the same pricing and a similar covenant package to the previous facility. The total leverage ratio financial covenant, as defined in the credit agreement, was increased from 5.00 to 1.00 to 5.50 to 1.00 in exchange for including a new senior secured leverage ratio financial covenant of 3.75 to 1.00.
During the second quarter of 2017, SMLP issued 745,848 common units under its $150.0 million At-The-Market program raising gross proceeds of $17.3 million.
Deferred Purchase Price Obligation
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” or the “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.
EX 99.1-6
EXHIBIT 99.1
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 (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. SMLP currently estimates that the undiscounted future value of the Deferred Payment will be approximately $800.0 million.
Quarterly Distribution
On July 27, 2017, 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 June 30, 2017. This quarterly distribution remains unchanged from the previous quarter and from the quarter ended June 30, 2016. This distribution will be paid on August 14, 2017, to unitholders of record as of the close of business on August 7, 2017.
Second Quarter 2017 Earnings Call Information
SMLP will host a conference call at 10:00 a.m. Eastern on Friday, August 4, 2017, 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 45198036. 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 August 18, 2017 at 11:59 p.m. Eastern, and can be accessed by dialing 888-843-7419 and entering the replay passcode 45198036#. 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 the 2017 Citi One-on-One MLP/Midstream Infrastructure Conference being held in Las Vegas, Nevada on August 16, 2017 and August 17, 2017. The presentation materials associated with this event will be accessible through the Investors section of SMLP’s website at www.summitmidstream.com prior to the beginning of the 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, 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; |
EX 99.1-7
EXHIBIT 99.1
• | 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 and Atlanta, Georgia.
About Summit Midstream Partners, LLC
Summit Midstream Partners, LLC (“Summit Investments”) beneficially owns a 34.7% 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
EX 99.1-8
EXHIBIT 99.1
controlled by Energy Capital Partners II, LLC, and certain of its affiliates. An affiliate of Energy Capital Partners II, LLC directly owns an 7.9% 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 2016 Annual Report on Form 10-K filed with the Securities and Exchange Commission on February 27, 2017, and 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.
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.
EX 99.1-9
EXHIBIT 99.1
SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
June 30, 2017 | December 31, 2016 | ||||||
(In thousands) | |||||||
Assets | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 2,588 | $ | 7,428 | |||
Accounts receivable | 55,837 | 97,364 | |||||
Other current assets | 2,264 | 4,309 | |||||
Total current assets | 60,689 | 109,101 | |||||
Property, plant and equipment, net | 1,859,953 | 1,853,671 | |||||
Intangible assets, net | 402,020 | 421,452 | |||||
Goodwill | 16,211 | 16,211 | |||||
Investment in equity method investees | 701,020 | 707,415 | |||||
Other noncurrent assets | 14,457 | 7,329 | |||||
Total assets | $ | 3,054,350 | $ | 3,115,179 | |||
Liabilities and Partners' Capital | |||||||
Current liabilities: | |||||||
Trade accounts payable | $ | 10,327 | $ | 16,251 | |||
Accrued expenses | 8,278 | 11,389 | |||||
Due to affiliate | 470 | 258 | |||||
Deferred revenue | 4,745 | — | |||||
Ad valorem taxes payable | 7,295 | 10,588 | |||||
Accrued interest | 17,015 | 17,483 | |||||
Accrued environmental remediation | 6,183 | 4,301 | |||||
Other current liabilities | 6,305 | 11,471 | |||||
Total current liabilities | 60,618 | 71,741 | |||||
Long-term debt | 1,280,645 | 1,240,301 | |||||
Deferred Purchase Price Obligation | 579,106 | 563,281 | |||||
Deferred revenue | 13,049 | 57,465 | |||||
Noncurrent accrued environmental remediation | 2,346 | 5,152 | |||||
Other noncurrent liabilities | 7,687 | 7,566 | |||||
Total liabilities | 1,943,451 | 1,945,506 | |||||
Common limited partner capital | 1,071,244 | 1,129,132 | |||||
General Partner interests | 28,217 | 29,294 | |||||
Noncontrolling interest | 11,438 | 11,247 | |||||
Total partners' capital | 1,110,899 | 1,169,673 | |||||
Total liabilities and partners' capital | $ | 3,054,350 | $ | 3,115,179 | |||
EX 99.1-10
EXHIBIT 99.1
SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
Three months ended June 30, | Six months ended June 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
(In thousands, except per-unit amounts) | |||||||||||||||
Revenues: | |||||||||||||||
Gathering services and related fees | $ | 84,801 | $ | 76,187 | $ | 202,814 | $ | 154,287 | |||||||
Natural gas, NGLs and condensate sales | 10,595 | 8,581 | 21,715 | 16,169 | |||||||||||
Other revenues | 6,396 | 4,867 | 13,068 | 9,750 | |||||||||||
Total revenues | 101,792 | 89,635 | 237,597 | 180,206 | |||||||||||
Costs and expenses: | |||||||||||||||
Cost of natural gas and NGLs | 9,099 | 6,864 | 18,151 | 13,154 | |||||||||||
Operation and maintenance | 24,016 | 23,410 | 47,708 | 49,252 | |||||||||||
General and administrative | 12,949 | 12,876 | 27,081 | 25,755 | |||||||||||
Depreciation and amortization | 28,688 | 27,963 | 57,257 | 55,691 | |||||||||||
Transaction costs | 119 | 122 | 119 | 1,296 | |||||||||||
Loss on asset sales, net | 67 | 74 | 70 | 11 | |||||||||||
Long-lived asset impairment | 3 | 569 | 287 | 569 | |||||||||||
Total costs and expenses | 74,941 | 71,878 | 150,673 | 145,728 | |||||||||||
Other income | 64 | 19 | 135 | 41 | |||||||||||
Interest expense | (17,553 | ) | (16,035 | ) | (34,269 | ) | (31,917 | ) | |||||||
Early extinguishment of debt | — | — | (22,020 | ) | — | ||||||||||
Deferred Purchase Price Obligation | 5,058 | (17,465 | ) | (15,825 | ) | (24,928 | ) | ||||||||
Income (loss) before income taxes and loss from equity method investees | 14,420 | (15,724 | ) | 14,945 | (22,326 | ) | |||||||||
Income tax benefit (expense) | 211 | (360 | ) | (241 | ) | (283 | ) | ||||||||
Loss from equity method investees | (3,385 | ) | (34,471 | ) | (4,041 | ) | (31,611 | ) | |||||||
Net income (loss) | $ | 11,246 | $ | (50,555 | ) | $ | 10,663 | $ | (54,220 | ) | |||||
Earnings (loss) per limited partner unit: | |||||||||||||||
Common unit – basic | $ | 0.12 | $ | (0.77 | ) | $ | 0.08 | $ | (0.89 | ) | |||||
Common unit – diluted | $ | 0.12 | $ | (0.77 | ) | $ | 0.08 | $ | (0.89 | ) | |||||
Weighted-average limited partner units outstanding: | |||||||||||||||
Common units – basic | 72,532 | 66,587 | 72,341 | 66,540 | |||||||||||
Common units – diluted | 72,842 | 66,587 | 72,708 | 66,540 | |||||||||||
EX 99.1-11
EXHIBIT 99.1
SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES
UNAUDITED OTHER FINANCIAL AND OPERATING DATA
Three months ended June 30, | Six months ended June 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
(Dollars in thousands) | |||||||||||||||
Other financial data: | |||||||||||||||
Net income (loss) | $ | 11,246 | $ | (50,555 | ) | $ | 10,663 | $ | (54,220 | ) | |||||
Net cash provided by operating activities | $ | 58,892 | $ | 64,651 | $ | 121,341 | $ | 131,500 | |||||||
Capital expenditures | $ | 31,484 | $ | 30,046 | $ | 45,912 | $ | 91,372 | |||||||
Contributions to equity method investees | $ | 10,713 | $ | — | $ | 15,649 | $ | 15,645 | |||||||
Acquisitions of gathering systems (1) | $ | — | $ | (569 | ) | $ | — | $ | 866,858 | ||||||
Adjusted EBITDA | $ | 72,577 | $ | 72,365 | $ | 143,987 | $ | 142,396 | |||||||
Distributable cash flow | $ | 50,009 | $ | 51,024 | $ | 102,960 | $ | 102,535 | |||||||
Distributions declared (2) | $ | 45,037 | $ | 41,045 | $ | 89,614 | $ | 82,090 | |||||||
Distribution coverage ratio (3) | 1.11 | x | 1.24 | x | 1.15 | x | 1.25 | x | |||||||
Operating data: | |||||||||||||||
Aggregate average daily throughput – natural gas (MMcf/d) | 1,780 | 1,512 | 1,704 | 1,518 | |||||||||||
Aggregate average daily throughput – liquids (Mbbl/d) | 68.9 | 86.0 | 72.6 | 90.5 | |||||||||||
Ohio Gathering average daily throughput (MMcf/d) (4) | 706 | 937 | 737 | 903 | |||||||||||
__________
(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 in respect of a given period. For example, for the three months ended June 30, 2017, represents the distributions to be paid in August 2017.
(3) Distribution coverage ratio calculation for the three months ended June 30, 2017 and 2016 is based on distributions declared in respect of the second 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.
EX 99.1-12
EXHIBIT 99.1
SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES
UNAUDITED RECONCILIATION OF REPORTABLE SEGMENT ADJUSTED EBITDA
TO ADJUSTED EBITDA
Three months ended June 30, | Six months ended June 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
(In thousands) | |||||||||||||||
Reportable segment adjusted EBITDA (1): | |||||||||||||||
Utica Shale | $ | 9,533 | $ | 4,727 | $ | 17,445 | $ | 7,916 | |||||||
Ohio Gathering (2) | 9,606 | 12,725 | 18,679 | 25,113 | |||||||||||
Williston Basin | 17,155 | 19,209 | 34,964 | 38,929 | |||||||||||
Piceance/DJ Basins | 27,274 | 26,231 | 56,248 | 51,046 | |||||||||||
Barnett Shale | 12,998 | 13,913 | 25,086 | 27,990 | |||||||||||
Marcellus Shale | 5,446 | 4,807 | 11,093 | 9,408 | |||||||||||
Total | 82,012 | 81,612 | 163,515 | 160,402 | |||||||||||
Less Corporate and other (3) | 9,435 | 9,247 | 19,528 | 18,006 | |||||||||||
Adjusted EBITDA | $ | 72,577 | $ | 72,365 | $ | 143,987 | $ | 142,396 | |||||||
__________
(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.
EX 99.1-13
EXHIBIT 99.1
SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES
UNAUDITED RECONCILIATIONS TO NON-GAAP FINANCIAL MEASURES
Three months ended June 30, | Six months ended June 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
(Dollars in thousands) | |||||||||||||||
Reconciliations of net income or loss to adjusted EBITDA and distributable cash flow: | |||||||||||||||
Net income (loss) | $ | 11,246 | $ | (50,555 | ) | $ | 10,663 | $ | (54,220 | ) | |||||
Add: | |||||||||||||||
Interest expense | 17,553 | 16,035 | 34,269 | 31,917 | |||||||||||
Income tax expense | — | 360 | 241 | 283 | |||||||||||
Depreciation and amortization (1) | 28,537 | 28,092 | 56,955 | 55,957 | |||||||||||
Proportional adjusted EBITDA for equity method investees (2) | 9,606 | 12,725 | 18,679 | 25,113 | |||||||||||
Adjustments related to MVC shortfall payments (3) | 5,578 | 11,135 | (23,062 | ) | 22,277 | ||||||||||
Unit-based and noncash compensation | 1,871 | 1,994 | 3,999 | 3,950 | |||||||||||
Deferred Purchase Price Obligation (4) | (5,058 | ) | 17,465 | 15,825 | 24,928 | ||||||||||
Early extinguishment of debt (5) | — | — | 22,020 | — | |||||||||||
Loss on asset sales, net | 67 | 74 | 70 | 11 | |||||||||||
Long-lived asset impairment | 3 | 569 | 287 | 569 | |||||||||||
Less: | |||||||||||||||
Income tax benefit | 211 | — | — | — | |||||||||||
Loss from equity method investees | (3,385 | ) | (34,471 | ) | (4,041 | ) | (31,611 | ) | |||||||
Adjusted EBITDA | $ | 72,577 | $ | 72,365 | $ | 143,987 | $ | 142,396 | |||||||
Add: | |||||||||||||||
Cash taxes received | — | — | — | 50 | |||||||||||
Less: | |||||||||||||||
Cash interest paid | 5,342 | 6,300 | 33,382 | 31,464 | |||||||||||
Senior notes interest adjustment (6) | 11,312 | 9,750 | (469 | ) | — | ||||||||||
Maintenance capital expenditures | 5,914 | 5,291 | 8,114 | 8,447 | |||||||||||
Distributable cash flow | $ | 50,009 | $ | 51,024 | $ | 102,960 | $ | 102,535 | |||||||
Distributions declared (7) | $ | 45,037 | $ | 41,045 | $ | 89,614 | $ | 82,090 | |||||||
Distribution coverage ratio (8) | 1.11 | x | 1.24 | x | 1.15 | x | 1.25 | x | |||||||
(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) Represents distributions declared in respect of a given period. For example, for the three months ended June 30, 2017, represents the distributions to be paid in August 2017.
EX 99.1-14
EXHIBIT 99.1
(8) Distribution coverage ratio calculation for the three months ended June 30, 2017 and 2016 is based on distributions declared in respect of the second quarter of 2017 and 2016. Represents the ratio of distributable cash flow to distributions declared.
EX 99.1-15
EXHIBIT 99.1
SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES
UNAUDITED RECONCILIATIONS TO NON-GAAP FINANCIAL MEASURES
Six months ended June 30, | |||||||
2017 | 2016 | ||||||
(In thousands) | |||||||
Reconciliation of net cash provided by operating activities to adjusted EBITDA and distributable cash flow: | |||||||
Net cash provided by operating activities | $ | 121,341 | $ | 131,500 | |||
Add: | |||||||
Interest expense, excluding amortization of debt issuance costs | 32,197 | 29,970 | |||||
Income tax expense | 241 | 283 | |||||
Changes in operating assets and liabilities | 12,896 | (42,566 | ) | ||||
Proportional adjusted EBITDA for equity method investees (1) | 18,679 | 25,113 | |||||
Adjustments related to MVC shortfall payments (2) | (23,062 | ) | 22,277 | ||||
Less: | |||||||
Distributions from equity method investees | 18,003 | 24,181 | |||||
Write-off of debt issuance costs | 302 | — | |||||
Adjusted EBITDA | $ | 143,987 | $ | 142,396 | |||
Add: | |||||||
Cash taxes received | — | 50 | |||||
Less: | |||||||
Cash interest paid | 33,382 | 31,464 | |||||
Senior notes interest adjustment (3) | (469 | ) | — | ||||
Maintenance capital expenditures | 8,114 | 8,447 | |||||
Distributable cash flow | $ | 102,960 | $ | 102,535 | |||
__________
(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.
Contact: Marc Stratton, Senior Vice President and Treasurer, 832-608-6166, ir@summitmidstream.com
SOURCE: Summit Midstream Partners, LP
EX 99.1-16