Morgan Stanley Utilities, Clean Tech and Midstream Energy Conference - - PowerPoint PPT Presentation
Morgan Stanley Utilities, Clean Tech and Midstream Energy Conference - - PowerPoint PPT Presentation
Morgan Stanley Utilities, Clean Tech and Midstream Energy Conference February 28, 2018 Disclaimers FORWARD-LOOKING STATEMENTS This presentation includes certain statements, estimates and projections concerning expectations for the future that
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Disclaimers
FORWARD-LOOKING STATEMENTS This presentation includes certain statements, estimates and projections concerning expectations for the future that are forward looking within the meaning of the federal securities laws. These “forward-looking” statements appear in a number of places in this presentation and 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.” They also include, but are not limited to, statements regarding Summit’s plans, intentions, beliefs, expectations and assumptions, as well as other statements that are not historical facts. Generally, these statements can be identified by the use of forward-looking terminology including “will,” “may,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” or other similar
- words. When considering these “forward-looking” statements, you should keep in mind that a number of factors that are beyond Summit’s control
could cause actual results to differ materially from the results contemplated by any such forward-looking statements including, but not limited to, the following risks and uncertainties: fluctuations in oil, natural gas and NGL prices; the extent and quantity of volumes produced within proximity
- f Summit’s assets; failure or delays by Summit’s customers in achieving expected production in their projects; competitive conditions in Summit’s
industry and their impact on Summit’s ability to connect hydrocarbon supplies to its gathering and processing assets or systems; actions or inactions taken or nonperformance by third parties, including suppliers, contractors, operators, processors, transporters, customers and shippers; Summit’s ability to acquire and successfully integrate new businesses; commercial bank and capital market conditions; changes in the availability and cost of capital; restrictions from the agreements governing its debt instruments; the availability, terms and cost of downstream transportation and processing services; operating hazards, natural disasters, accidents, weather-related delays, casualty losses and other matters beyond Summit’s control; timely receipt of necessary approvals and permits and Summit’s ability to control the costs of construction, including costs of materials, labor and rights-of-way and other factors that may impact Summit’s ability to complete projects within budget and on schedule; the effects of existing and future laws and governmental regulations, including environmental requirements; and the effects of litigation on Summit’s business or operations. 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 the Issuer’s actual results in future periods to differ materially from anticipated or projected results. Forward-looking statements in this presentation include statements regarding the necessity of accessing the debt and equity capital markets, financial guidance with respect to distribution growth, distribution coverage ratios, adjusted EBITDA, expected commodity prices and adjusted distributable cash flow, and the expected amount of the deferred payment liability recognized in connection with the 2016 drop down (the “Deferred Payment”). An extensive list of specific material risks and uncertainties affecting the Issuer is contained in its 2017 Annual Report on Form 10-K filed with the Securities and Exchange Commission (the “SEC”) on February 26, 2018 and as amended and updated from time to time. Any forward-looking statements in this presentation are made as of the date of this presentation and the Issuer undertakes no obligation to update
- r revise any forward-looking statements to reflect new information or events.
All of the forward-looking statements made in this document are qualified by these cautionary statements, and Summit cannot assure you that actual results or developments that Summit anticipates will be realized or, even if substantially realized, will have the expected consequences to,
- r effect on, Summit or its business or operations.
Although the expectations in the forward-looking statements are based on Summit’s current beliefs and expectations, caution should be taken not to place undue reliance on any such forward-looking statements because such statements speak only as of the date hereof. Summit expressly disclaims any obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Furthermore, the “forward-looking” statements reflect various assumptions by Summit concerning anticipated results, which assumptions may or may not prove to be correct. Neither Summit nor any of its affiliates has undertaken any independent investigation or evaluation of such assumptions to determine their reasonableness.
SMLP Overview
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SMLP Overview
(1) As of 2/23/2018; Statistics based on Q4 2017. (2) Distribution Coverage is SMLP’s distributable cash flow relative to declared distributions. For a reconciliation of distribut able cash flow to the nearest comparable GAAP financial measure, see slide 33. (3) EBITDA adjustments include adjustments related to MVC shortfall payments and unit -based compensation expense. Adjusted EBITDA includes transaction costs. These unusual and non-recurring expenses are settled in cash. For a reconciliation of adjusted EBITDA to its nearest comparable GAAP financial measure, see slide 33. (4) Represents the midpoint of SMLP’s 2018 adjusted EBITDA guidance range of $285-$300 million provided on 2/22/2018. (5) MQD reflects SMLP’s minimum quarterly distribution at IPO of $0.40 per unit, annualized. (6) Based on $0.575 per unit distribution declared on 1/25/2018.
$17.50 $0.575 per Unit $2.30 per Unit 13.1% $1.3 Billion $2.6 Billion 1.09x 3.62x Ba3 / BB- SMLP Unit Price Quarterly Distribution Annualized Distribution Distribution Yield Market Capitalization Enterprise Value Distribution Coverage(2) Leverage Corporate Ratings (Moody’s / S&P)
Adjusted EBITDA – 2013 to 2018E(3)
$163 $208 $235 $292 $290 $293 $100 $150 $200 $250 $300
2013 2014 2015 2016 2017 2018E
$MM Summit Midstream Partners, LP (NYSE: SMLP) is a growth-
- riented independent natural gas, crude oil and produced
water gathering and processing company with diversified
- perations across seven resource plays in the continental U.S.
Historical Distribution Per Unit
Barnett Piceance / DJ Marcellus Utica Shale Ohio Gathering Williston
2017 Segment Adj. EBITDA 10% 36% 7% 14% 20%
SMLP METRICS(1)
$1.600 $1.795 $2.120 $2.285 $2.300 $2.300 $1.40 $1.50 $1.60 $1.70 $1.80 $1.90 $2.00 $2.10 $2.20 $2.30 $2.40
MQD 2013 2014 2015 2016 2017
(5) (6)
13%
(4)
1 rig 2 rigs 5 rigs 1 rigs N.
Rig count as of February 2018
(Under Construction)
2 rigs
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PE-Backed Producer #2
Diversified Operating Footprint
Piceance / DJ
4Q 2017 Segment Adj. EBITDA(1) Services Provided AMI (acres) Remaining MVCs Key Customers
Natural Gas Gathering & Condensate Stabilization Natural Gas Gathering & Processing Natural Gas Gathering & Compression Natural Gas Gathering & Treating Natural Gas, Crude Oil & Produced Water Gathering 910,000(3) 840,000 n/a 120,000 1,300,000 1,345 Bcf Confidential 3 Bcf 181 Bcfe SMU: $8.2 MM (10%) OGC: $12.0 MM (15%) $31.5 MM (38%) $6.1 MM (7%) $10.3 MM (12%) $15.2 MM (18%)
4Q 2017 Volume Throughput
n/a SMU: 369 MMcf/d OGC:825 MMcf/d(2) Gas: 19 MMcf/d Liquids: 74 Mbbl/d 575 MMcf/d 258 MMcf/d 540 MMcf/d Williston Barnett Marcellus
Large U.S. Independent Producer (1) Segment adjusted EBITDA excludes the effect of corporate expenses. (2) Represents gross volume throughput, based on a one-month lag. (3) Includes dedicated acreage from Ohio Gathering. (4) Rice Energy, Inc. sold its Barnett acreage in 4Q2017 for $175 million to an undisclosed buyer.
Represents selected customer that acquired acreage on SMLP’s systems in 2016 and 2017
PE-Backed Producer #1
- N. Delaware
Natural Gas Gathering & Processing Confidential n/a In Service: 2Q 2018 4x
(4)
In Service: 2Q 2018 Utica 2x
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SMLP Investment Considerations
Attractive Relative Valuation Strategic Utica Shale & Growing N. Delaware Presence
Increased Bakken Rigs to Provide Near-Term Volume Growth
Visible Catalysts Setting Up for Growth in 2019 Diversified Fee-Based Contracts w/ MVCs
13.1% distribution yield vs. 8.4% peer average and 7.9% Alerian MLP Index (1) Strong balance sheet with leverage of 3.62x as of 4Q 2017 Distribution management focus on coverage and leverage Over 900,000 acres dedicated across the dry gas and liquids
- rich windows of the Utica
$110 million development project underway for XTO to gather and process N. Delaware gas SMLP will participate in the substantial future production growth from these basins 2 rigs currently operating behind our liquids gathering systems, adding to DUC inventory New long-haul pipelines and enhanced completion efforts driving producer returns higher New wells from anchor customer generate incremental crude and water revenue streams Turning calendar from 2018 to 2019 will remove ~$8 million of incremental opex Start-up of Delaware project (2Q18) & DJ expansion (4Q18) to add to SMLP’s 2019 adj. EBITDA Visible growth at SMU & OGC beginning in 1Q 2019 based on new wells to be drilled in 2Q 2018 2.6 Tcfe of remaining MVCs with no material near-term contract expirations MVCs average 1.05 Bcfe/d through 2022 and represent 48% of 4Q 2017 throughput Over 95% of 4Q 2017 gross margin was fee-based (2)
1 2 3 4 5
(1) Peers include CEQP, DCP, ENBL, ENLK, TRGP, WPZ; Excludes hypergrowth drop-down MLPs. Alerian MLP Index yield as of 2/16/2018 per Alerian’s website. (2) Reflects SMLP gross margin: excludes favorable and unfavorable amortization of contracts, CO2 pass-through revenue, electricity and other reimbursables, which are pass-through items. Includes gas retainage revenue which is used to partially offset compression power expense in the Barnett.
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Investment Multiple Fully-Developed EBITDA Area Project Commercial Operation Capex Low High Low High Delaware 60 MMcf/d Processing Plant & Gathering 2Q '18 (Minimal Contribution in '18) $110 8.0x
- 10.0x
$11
- $14
DJ 60 MMcf/d Processing Plant 4Q '18 (Minimal Contribution in '18) $60 3.0x
- 5.0x
$12
- $20
Utica Phase 1 Compression 3 Stations Beginning 2Q '19 through 2Q '20 $50 4.0x
- 6.0x
$8
- $13
Total $220 4.8x
- 7.0x
$31
- $46
Identified and Contracted Growth Catalysts
- SMLP has several identified projects that are expected to serve as growth catalysts beginning in 2019
–
Represents opportunities that are either currently under development or contracted for future development
- The fully-developed project economics, shown in the table below, provides visibility regarding certain of SMLP’s growth prospects
- In addition to the identified projects outlined below, SMLP’s will benefit from:
–
New wells at Summit Midstream Utica that are expected to be completed in 1H 2019 (pad connection capex incurred in 2018)
–
Operating expenses normalizing relative to the $8 million of compressor overhauls and right-of-way repairs expected in 2018
Estimated Contribution From Identified Growth Projects
($ in millions)
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Greenfield Development Project in Growing N. Delaware
- In July 2017, SMLP announced a new associated gas
gathering and processing project in the N. Delaware
–
Project includes gathering and discharge pipelines, two compressor stations and a cryogenic processing plant with 60 MMcf/d of processing capacity
–
Ability to expand processing capacity to 600 MMcf/d
–
Well positioned to provide ancillary crude oil and produced water gathering services
- Underpinned by fee-based contract with XTO Energy Inc.
("XTO") servicing acreage located in the N. Delaware Basin in Eddy and Lea counties in New Mexico
–
Currently in discussions with other nearby producers to gather and process incremental volumes
- Initial investment of approximately $110 million
–
Estimate an initial 8.0x to 10.0x EBITDA build multiple and 6.0x to 8.0x at full development
–
Expected to provide platform to pursue additional development projects over the next several years
Overview
Strategically Positioned Initial Development Footprint
Development Timeline Status Signed Agreement with XTO Complete (July 2017) Project Development In Process Construction In Process In-Service Date 2Q 2018
(Under Construction)
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Open Season for N. Delaware Takeaway Project to Waha Hub
Overview
- In January 2018, SMLP announced it is holding a non-
binding open season for its Double E Pipeline project
–
Provides natural gas transportation from multiple receipt points in the northern Delaware basin to various delivery points in and around the Waha Hub
–
Services various receipt points in Eddy and Lea counties in New Mexico, and in Loving, Ward, Reeves and Pecos counties in Texas
–
Connects growing associated natural gas supply basin to a liquid trading point with demand centers along the United States Gulf Coast and Mexico
–
Consists of ~120 miles of 24”-36” diameter pipe with a capacity of 1.0 Bcf/d, expandable to ~1.4 Bcf/d with compression
- Target in service date of 1Q 2021
–
A cost of service-based, daily reservation recourse rate will be available for transportation service
–
The primary term for firm transportation service under the project will be 10 years or longer
Strategic Positioning for Firm Transportation
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Significant Midstream Infrastructure Needs in the N. Delaware
- Robust infrastructure investment is needed to support
future production growth in the N. Delaware
- Activity in the Delaware play continues to push further
north into SMLP’s service area
- SMLP’s initial development project will serve as a platform
for additional growth opportunities, including:
–
Associated natural gas processing
–
Crude oil gathering
–
Produced water gathering
–
Long-haul transmission
- SMLP currently evaluating growth opportunities to expand
its investment in N. Delaware by more than $500 million
- N. Delaware Opportunity Set
(1) Summit production outlook for Eddy and Lea counties in New Mexico; Assumes current rig count of 60+ rigs in both Eddy and Lea counties, ramping to nearly 80 rigs by 2019; Based on development of Bone Springs and Wolfcamp formations; Assumes gas-to-oil ratio of 2.5:1 and water-to-oil ratio of 3:1.
Significant Gas, Crude and Water Growth (1)
Natural Gas Growth(1) 5.2 Bcf/d by 2025 (2.9 Bcf/d Increase) Crude Oil Growth(1) 2.1 MMBbl/d by 2025 (1.2 MMBbl/d Increase) Produced Water Growth(1) 6.2 MMBbl/d by 2025 (3.5 MMBbl/d Increase)
SMLP Estimates $5+ Billion of Midstream Infrastructure is Needed to Support Gas, Oil and Water Production Growth in the N. Delaware
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Overview
Expansion Project in DJ Basin
Existing Geographic Footprint
- In November 2017, SMLP announced plans to develop,
- wn and operate a new 60 MMcf/d cryogenic processing
plant in the DJ Basin
–
Long-term, fee-based agreements with Fifth Creek Energy Company, LLC and a large U.S. Independent Producer
- DJ expansion project will provide incremental processing
capacity needed for volume growth from existing customers and other third-party producers operating in the area
- Project expected to be operational 4Q 2018 at a total
investment cost of approximately $60 million
–
SMLP will finance the Project with borrowings under its $1.25 billion revolving credit facility
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1 Well, 18% 2-3 Wells, 48% 4+ Wells, 34%
Large Utica Footprint Provides Significant Operating Leverage
Large Inventory of Drilling Locations Ohio Gathering Company (1) Summit Midstream Utica
SMLP Ownership Interest
40% 100%
Pipeline Miles
~330 ~50
Acreage Dedication
~825,000 ~90,000
Pad Connections
~100 ~20
Number of Customers
5 2
4Q 2017 Average Daily Production (MMcf/d)
825 369
Utica Windows
Dry / Wet / Cond. Dry
(1) OGC operating metrics shown on a gross (8/8ths) basis.
- Based
- n
existing leaseholds, SMLP estimates that its customers have ~ 1,100 to 1,500 future drilling locations in its Utica AMIs
- Producer activity to-date primarily focused on holding leases
‒ Existing pad sites have an average of 3.2 wells per pad ‒ SMLP estimates that once fully developed, most Utica pad sites will have 6-8 wells
- Represents ~ 250 – 500 future wells that will
not require additional pipe capex
Existing Wells per Pad Site
Levered to In-Fill Drilling
Acre Spacing 160 acres 180 acres 200 acres Leased Acres in AMI (Approx. ) 290,000 290,000 290,000 Acre Spacing 160 180 200 Total Potential Well Locations 1,813 1,611 1,450 Existing Wells 377 377 377 Future Wells 1,436 1,234 1,073 % of AMI Developed 21% 23% 26%
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13 12 10 8 7 7 5 6 7 8 6 5 5 4 2 1 2 1 1 1 0 0 4 5 4 3 4 4 2 2 3 5 3 3 3 3 5 100 200 300 400 500 600 700 800 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15 Jan-16 Feb-16 Mar-16 Apr-16 May-16 Jun-16 Jul-16 Aug-16 Sep-16 Oct-16 Nov-16 Dec-16 Jan-17 Feb-17 Mar-17 Apr-17 May-17 Jun-17 Jul-17 Aug-17 Sep-17 Oct-17 Nov-17 Dec-17 Current MMcf/d Ohio Gathering Utica Shale Rigs Source: Rig information per Drillinginfo as of February 2018. (1) Represents SMLP’s 40% interest in Ohio Gathering volumes based on a one-month lag.
Top Customers Continuing to Develop Utica Position
Utica Basin Rigs (February 2018)
Condensate Wet Gas Dry Gas
Historical Utica Volume & Rig Activity
Rigs on SMLP System
Outlook
Significant Increase in Current Rig Activity
- 5 rigs on SMLP systems currently
- 6 to 9 month lag between rig activity and volume throughput
Customer Outlook is Positive
- Expect basis differentials to narrow as pipeline projects come
- nline in early 2018
- Expecting 50+ wells to be completed in 2018 beginning in Q2
Highly Levered to SMU Dry Gas Development
- 2018 completions expected from infill drilling and new wells
behind SMU’s TPL-7 connector project
- Construction already started on several pad connections with
new wells expected in 2019– offers visibility to 2019 volume growth
- Given SMLP’s 100% interest in SMU, 1.0 SMU dry gas rig is
equivalent to 2.5 OGC dry gas rigs
(1)
Over 250% volume growth since 2015 Higher rig activity represents catalyst for volume growth
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Significant Operating Scale in the Bakken
- SMLP
- ffers
crude
- il,
natural gas and produced water gathering on 16% of its connected pad sites
- Williston assets have a stable base of cash flow and offer
upside potential from: ‒ Completing the backlog of approximately 40 drilled but uncompleted wells already on the system ‒ Significant inventory of in-fill drilling locations that require limited to no incremental capex to SMLP, as well as the potential for additional locations with higher crude prices ‒ Further penetration of SMLP’s existing customer base, providing all gathering services to those pad sites that currently only gather crude oil or natural gas
Existing PADs In-Fill Drilling Potential ~280 PADs
3+ Wells per PAD (40%) 2 Wells per PAD (16%) 1 Well per PAD (44%)
(1) As of 12/31/2017. Represents an estimate of wells and pad sites on selected Williston assets; Excludes wells and pad sites on the Bison system.
In-Fill Drilling Offers “Low Hanging Fruit”
- Currently SMLP has 281 PADs and 584 wells connected to its
system (1)
- 60% of PADs with 2 or less wells
- Limited
incremental capex required from SMLP to bring incremental wells online
SMLP Williston Service Offerings(1)
- Est. Range
Low High
- Approx. wells connected
584 (/) Appox. PADs connected 281
- Avg. wells per PAD
2.1 Incremental wells per PAD 1.9 2.9 Total est. wells per PAD 4.0 5.0 (x) Approx. PADs connected 281 Total est. wells available 1,124 1,405 (-) Approx. wells connected (584) (-) Approx. DUCs (40)
- Est. wells from in-fill drilling
500 781
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1 1 2 1 2 2 2 2 3 3 3 4 3 2 4 2 1 2 Jun-16 Jul-16 Aug-16 Sep-16 Oct-16 Nov-16 Dec-16 Jan-17 Feb-17 Mar-17 Apr-17 May-17 Jun-17 Jul-17 Aug-17 Sep-17 Oct-17 Nov-17 Dec-17 Current Rigs on SMLP's Liquids System
Increasing Williston Rig Activity & Improving Completion Results
Significant Rig Activity on SMLP’s Systems Recent Well Results Beating Type Curves (1)
Enhanced Completions Improving Producer Returns (1)
- SMLP has seen significant rig
activity in its Polar Divide system since late 2016
- Despite this activity, only 6 wells
have been completed though 6/30/2017
- D&C investing will serve as a
catalyst in the Bakken, particularly given enhanced completions and most drilling activity has
- ccurred in
areas where SMLP provides oil and water gathering services.
Liquids System Natural Gas System
Rig Activity On SMLP’s Liquids System in the Williston
(1) Whiting Petroleum Corporation Investor Presentations as of January 2, 2018 and February 22, 2018.
1 Rig Working in this area
Rigs on SMLP System
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Customer Acreage Trades Drive Increased Production
Customer Acreage Trades Significantly Improving SMLP’s Rifle Area Volumes in the Piceance Basin
Acquires Piceance Assets From Acquires Piceance Assets From Acquires Piceance Assets From Rifle Area Volumes
- Customer acreage turnover in the Piceance, specifically the Rifle area, has had a meaningful impact on volumes
– Since the first transaction in 4Q 2012, four customer acreage trades have occurred and volume throughput on SMLP’s Rifle area assets increased 170%
- In July 2017, Encana, SMLP’s anchor customer in the Piceance, sold its acreage to privately-owned Caerus Oil & Gas
– Caerus is expected to significantly increase drilling activity and production in the Piceance Basin over the next several years – SMLP accelerated the frequency of MVC shortfall billings during the consent to assignment process
170% Volume Growth in Rifle Area Since First Transaction in December 2012
Acquires Piceance Assets From
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Encouraged by Recent Customer Acreage Trades in the Barnett
- In 2015, Devon tested 25 horizontal re-fracs in SE Wise, NW
Tarrant, and SW Denton
- According to Devon, the average production uplift was 340%
- New customers on SMLP’s system have indicated that re-
completions are a key part of their strategy to continue to develop their acreage
Transaction Date Buyer Seller Outlook
1Q 2016 GH America Beacon E&P 4Q 2016 TOTAL SA Chesapeake Energy 4Q 2016 Rice Energy Vantage Energy 4Q 2016 Saddle Barnett Resources, LLC EnerVest, Ltd. 3Q 2017 Undisclosed Rice Energy Immediate: Workovers of older wells and returning wells offline to service Near-Term: Production growth from new wells in 4Q 2017 and 1Q 2018 Intermediate-Term: In-fill drilling from existing pads & re-completions of older wells
SMLP Assets Gather from the “Best Rock” Nearby Re-Fracs Deliver Positive Results
Natural gas EURs are highest in the northern and southern portion of the East Tarrant sub-play
Location of SMLP Barnett System
Devon’s re-fracs provided 340% average production uplift
- 5 of the top 10, including the two largest, wells ever drilled in the
Barnett are on SMLP’s system
Source: WoodMackenzie – Barnett key play report: The trailblazer shale gas play (January 2017).
Limited to No Capex Requirements for SMLP
18 2,206 1,050
500 1,000 1,500 2,000 2,500 4Q 2017 Throughput
- Avg. Daily MVCs
Through 2022 MMcfe/d
Downside Protection Through Long-Term Contracts with MVCs
(1) As of December 31, 2017. (2) Weighted averages based on Total Remaining Minimum Revenue (Total Remaining MVCs x Average Rate). Note that some customers ha ve aggregate MVC provisions, which if met before the original stated contract terms, may materially reduce the weighted average remaining period for which our MVCs apply. (3) Weighted averages based on 4Q 2017 volume throughput for material customers’ contracts. (4) Includes dedicated acreage from Ohio Gathering. (5) Includes oil and produced water at a 6:1 conversion ratio.
- Avg. MVCs Through 2022 = 48% of 4Q 2017 Operated Throughput
48%
(5)
Piceance/DJ Basins Barnett Shale Williston Basin Marcellus Shale Utica Shale
- Wtd. Avg. /
Total Acreage Dedication (net acres) 840,000 120,000 1,300,000 n/a 910,000(4) > 3,170,000 Total Remaining Commitment (Bcfe)(1) 1,345 3 181 Confidential n/a 2,637
- Avg. Daily MVCs through 2022 (MMcfe/d)(1)
561 2 99 Confidential n/a 1,050 4Q 2017 Avg. Daily Throughput (MMcf/d) 575 258 19 540 369 1,761 4Q 2017 Avg. Daily Throughput (Mbbl/d)
- 74.1
- 74.1
- Wtd. Avg. Remaining MVC Life(1,2)
7.5 years 0.8 years 4.0 years Confidential n/a 7.4 years Remaining Contract Life Range(1,3) 11.3 years 7.8 years 5.1 years Confidential 10.9 years 9.4 years
SMLP Segment Overview
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132 167 234 211 275 413 403 369 870 937 800 848 769 706 763 825 100 200 300 400 500 600 700 800 900 1,000 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 MMcf/d Utica Shale (Operated) Ohio Gathering (Non-Operated)
Condensate Wet Gas Dry Gas
SMU Focus Area Ohio Gathering Focus Area
Utica: Basin Positioning & Outlook
Geographic Footprint
- SMLP’s Utica assets span the dry gas, wet gas, and condensate windows
in southeastern Ohio
- Top tier drilling economics at strip pricing
─ 15+ Bcf/d of new pipeline takeaway by YE 2018 to improve basis differentials and producer returns
- Utica producer activity to date focused on holding lease expirations and
preparing for differential compression as new takeaway pipelines are commissioned early 2018 ─ SMLP has significant longer-term upside as producers develop existing pad sites from ~ 3 wells to 6-8 wells
Area Strategy Area Positioning Near-Term Outlook
- Focus on opportunities to pursue bolt-on organic growth projects
- Regional asset-level M&A opportunities
- Upside relative to the emerging Deep Utica in PA and WV
- Increasing rig activity across SMLP’s Utica assets as commodity prices
firm and basis differentials compress
- Ascent drilling activity and increased production to meet its Rover
commitment
- Visible cash flow growth from compression services to be added across
the SMU system expected in 2019 (incremental fee and volume uplift) ─ For example, the start-up of OGC’s Larew Compressor Station in March 2017 resulted in a ~45% initial uplift to dry gas production flowing through the system
- Beginning to see certain producers accelerate liquids-rich drilling activity
- Expecting over 50 wells to be completed in 2018 beginning in Q2
- Customers currently operating five rigs behind our systems
Rigs
- n
SMLP System
Source: Rig information per Drillinginfo as of February 2018. (1) Exclusive of volume throughput for Ohio Gathering. (2) Gross basis, represents 100% of volume throughput for Ohio Gathering, based on a one-month lag.
Historical Volume Throughput
(1) (2)
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Marcellus: Basin Positioning & Outlook
- SMLP’s Marcellus assets provide one of two critical high-pressure pipeline
inlets to Sherwood, currently offering over 1.0 Bcf/d of delivery capacity
- SMLP’s Marcellus assets are fully developed and have minimal opex and
capex requirements
Near-Term Outlook
- On February 6, 2017, MPLX formed a joint venture to support the ongoing
expansion of the Sherwood Processing Complex in the Marcellus Shale ‒ The Sherwood Complex currently has 1.6 Bcf/d of processing capacity and the joint venture contemplates adding 1.0 Bcf/d+ of additional processing capacity
- Expect continued volume growth on SMLP’s system that will provide
support for the expansion plans of the Sherwood Complex ‒ Customer to commission 9 new wells in 1Q18
Source: Rig information per Drillinginfo as of February 2018. Legend Zinnia Loop Mountaineer Pipelines Receipt Points Sherwood Plant
SMLP’s Mountaineer Midstream System Can Deliver Over 1.0 Bcf/d Into Sherwood
453 416 418 374 434 480 554 540 250 300 350 400 450 500 550 600 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 MMcf/d Marcellus Shale
Geographic Footprint Area Positioning & Strategy Historical Volume Throughput
22
Williston: Basin Positioning & Outlook
- Expansive gathering footprint with 1,100+ miles of crude, gas and water
pipelines and ~1.3 million dedicated acres
- DUC completions at $45 to $55/bbl crude prices and rig activity at
$55/bbl+ crude prices
- Crude oil system delivery points maximize downstream optionality
‒ DAPL (pipe to Patoka / Nederland) ‒ COLT Hub (Crestwood Rail) ‒ Little Muddy (Enbridge ND Pipeline System) ‒ Stampede (Global Partners’ Rail)
Area Strategy Near-Term Outlook
- Packaged services (i.e. crude, water and gas gathering) are cost efficient
and attractive to the customer
- Broad opportunity set for future growth
‒ Increasing activity related to producer RFPs ‒ Capturing market share from trucks ‒ Consolidation opportunities in basin expected to re-emerge
- Customers to draw down DUC inventory
- Current rig activity on acreage that offers dual revenue stream (crude and
produced water services)
- Compressed basis differentials and firming commodity prices to drive
increased infill drilling
- Enhanced completions driving higher EURs and producer returns
- Customers currently operating two rigs behind our system
Source: Rig information per Drillinginfo as of February 2018.
Historical Volume Throughput
95 86 92 82 76 69 74 74 25 24 24 17 17 20 21 19 30 40 50 60 70 80 90 100 10 15 20 25 30 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 Mbbl/d MMcf/d Williston (Liquids) Williston (Gas)
Liquids System Gas System
Rigs on SMLP System
Geographic Footprint Area Positioning
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Piceance / DJ: Basin Positioning & Outlook
- Positioned in the core of the Piceance & DJ Basins with exposure to the
liquids-rich Mesaverde formation and emerging Mancos & Niobrara formations
- System fully developed with minimal capex requirements
- SMLP’s scale provides significant operating leverage
‒ Significant improvements in Controllable Opex per Mcfe
- Significant customer diversity, offsetting lower activity from anchor customer
‒ 35+ customers (several focused exclusively on Piceance)
- Regional takeaway pipeline recontracting improves producer economics
Area Strategy Near-Term Outlook
- Recent upstream A&D activity transferred acreage from public companies
with large opportunity set to private companies with a single basin focus
- New plant in DJ expected to be operational in late 4Q 2018 (higher margin
business relative to the Piceance)
- Customers expected to draw down over 70 DUC wells in 2018
- Customers currently operating two rigs behind our systems
- Several active customers providing opportunity for accretive organic growth
‒ Minimal capital requirements given reach of existing infrastructure
- MVCs working as designed and providing cash flow stability during recent
commodity price downturn
- Long-term call option on the Mancos / Niobrara shale formations
Rigs on SMLP System
Source: Rig information per Drillinginfo as of February 2018.
Historical Volume Throughput Geographic Footprint Area Positioning
572 564 591 615 615 596 594 575 500 525 550 575 600 625 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 MMcf/d Piceance / DJ Basins
24
Barnett: Basin Positioning & Outlook
- System fully developed with minimal capex requirements
- Continuous improvement in the reservoir
‒ System throughput has outperformed original expectations ‒ Improving per well EUR trend:
- 2009:
2.8 Bcf
- 2011:
3.2 Bcf
- Current:
4.5 Bcf
- Attractive basis differentials given proximity to Henry Hub
- Significant customer diversity with 9 customers
‒ Four of our top five customers turned over in 2016 & 2017
- These four customers represent more than 85% of 4Q 2017
volume throughput in Barnett segment
Near-Term Outlook
- Four upstream A&D transactions in 2016 expected to stimulate volume
growth beginning in 4Q 2017 ‒ TOTAL’s acquisition of Chesapeake acreage creates a new and active anchor customer ‒ Opportunity to return temporarily shut-in wells to production, recompletions of existing wells, and new drilling
- Negotiated agreements with two new customers to promote increased
drilling activity and future volume throughput growth
- Two new customers were each running a rig on our system in 2017
‒ 7 new wells were commissioned in late 4Q 2017 and we expect 6 new wells will be commissioned in 1Q 2018
Source: Rig information per Drillinginfo as of February 2018.
Historical Volume Throughput Geographic Footprint Area Positioning & Strategy
341 341 305 287 286 271 254 258 200 225 250 275 300 325 350 375 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 MMcf/d Barnett Shale
SMLP Financial Overview
26
0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Jan-13 Apr-13 Jul-13 Oct-13 Jan-14 Apr-14 Jul-14 Oct-14 Jan-15 Apr-15 Jul-15 Oct-15 Jan-16 Apr-16 Jun-16 Sep-16 Dec-16 Mar-17 Jun-17 Sep-17 Dec-17 % of Total Volumes % Gas Oriented Drilling % Liquids Oriented Drilling
Growing & Diversifying SMLP’s Business
Key Observations Exposure to Multiple Basins(1) Diversified Across Commodity(2)
- Track record of growth and diversification by basin, customer,
commodity and service ‒ Recently announced growth of SMLP’s operating footprint by expanding into N. Delaware Basin
- Segment Adj. EBITDA CAGR of 18% per year since 2013, while
diversifying business across multiple basins
- SMLP has developed a large and diversified customer base
across its operating footprint
- Over 95% of 4Q 2017 gross margin was fee-based (4)
LTM Average % Gas Volumes: 79%
Piceance / DJ Basins Utica Shale Barnett Shale Williston Basin Marcellus Shale
Large & Diversified Customer Base
(1) Represents reportable segment adjusted EBITDA, which excludes the effect of corporate expenses. (2) Based on historical average daily volume on an Mcfe basis; Assumes oil and water are converted at a 6:1 Mcf to barrel ratio.
Large U.S. Independent Producer
(3)
(3) Utica includes the Utica Shale and Ohio Gathering reportable segments. (4) Pleaser refer to footnote 2 on page 6. (5) Bill Barrett announced acquisition on December 5, 2017.
46% 50% 42% 33% $118 3% 14% 20% $75 40% 27% 23% 17% $46 10% 13% 13% 24% $66 4% 7% 9% 6% $24 $173 $223 $263 $329 $330 $0 $50 $100 $150 $200 $250 $300 $350 2013 2014 2015 2016 2017 Segment Adjusted EBITDA
(5)
27
(1) Excludes SMLP’s proportionate share of volume throughput from Ohio Gathering. (2) Excludes acquisition capital expenditures. Includes contributions to equity method investees. (3) EBITDA adjustments include adjustments related to MVC shortfall payments and unit -based compensation expense. Adjusted EBITDA includes transaction costs. These unusual and non-recurring expenses are settled in
- cash. For a reconciliation of adjusted EBITDA and distributable cash flow to their nearest comparable GAAP financial measures, please see “Non-GAAP Reconciliations.”
Historical Operating and Cash Flow Statistics
$121 $145 $165 $211 $205
$0 $30 $60 $90 $120 $150 $180 $210 $240 2013 2014 2015 2016 2017
$MM
$163 $208 $235 $292 $290 $0 $30 $60 $90 $120 $150 $180 $210 $240 $270 $300 2013 2014 2015 2016 2017
$MM
1,139 1,423 1,499 1,528 1,748 11 41 68 89 75 20 40 60 80 100 400 800 1,200 1,600 2013 2014 2015 2016 2017
MMcf/d
Gas (MMcf/d) Liquids (Mbbl/d)
Adjusted EBITDA(3) Capital Expenditures(2) Distributable Cash Flow Volume Gathered(1)
Mbbl/d $250 $879 $358 $174 $150
$0 $200 $400 $600 $800 $1,000 2013 2014 2015 2016 2017
$MM
28
Strong Balance Sheet Enables SMLP to Execute Growth Strategy
(1) An affiliate of Energy Capital Partners directly owns a 7.9% interest in SMLP.
- Targeting long-term leverage ratio of 3.5x – 4.0x
- Targeting long-term coverage ratio of >1.10x
- $989 million of borrowing availability under $1.25 billion revolver
- ffers ample liquidity for all near-term organic capital projects
- No need to access capital markets
$300 $500 $261 $989 $0 $200 $400 $600 $800 $1,000 $1,200 $1,400 $1,600 $1,800 2018 2019 2020 2021 2022 2023 2024 2025 2026 $ in Millions Revolving Credit Facility 5.50% Senior Notes B1 / BB-
Long-Term Debt Maturity Profile
$989 million of availability at 12/31/17 under $1.25 billion Revolver
SMLP Balance Sheet Provides the Foundation Well-Capitalized with Sponsor Support
Public Unit Holders
55.4%
Common LP Interest
Summit Midstream Partners, LLC (“Summit Investments”) Summit Midstream Partners Holdings, LLC (“SMP Holdings”) 100%
2.0% GP Interest / IDRs 1.5M GP Units 34.7% Common LP Interest 25.9M Common Units
Summit Midstream Partners, LP (NYSE: SMLP) 100%
Perpetual Preferred $300 Million
3.62x
Q4 Leverage
$990MM
Q4 Liquidity
1.09x
Q4 Coverage
Ba3 // BB-
Credit Rating
5.75% Senior Notes B1 / BB- Senior Unsecured Notes Revolving Credit Facility 7.9%
Common LP Interest(1)
($s in millions) Dec-17 Cash and Cash Equivalents $1 Revolving Credit Facility (Due May 2022) $261 5.50% Senior Notes (Due August 2022) 300 5.75% Senior Notes (Due April 2025) 500 Total Debt $1,061 Partners' Capital: Series A Preferred Units $294 Common Limited Partner Capital 1,057 General Partner Interest 28 Noncontrolling interest 11 Total Partners' Capital $1,390 Total Capitalization $2,451 Total Leverage Ratio 3.62x Committed Liquidity Cash & Cash Equivalents $1 Revolver Availability 989 Total Liquidity $990
29
Deferred Payment Overview
- The Deferred Payment will flex up or down based on the actual
performance of the 2016 Drop Down Assets – SMLP will pay a 6.5x multiple of Avg. Business Adj. EBITDA in 2018 and 2019
- The structure of the 2016 Drop Down gives SMLP four years to finance
the Deferred Payment (2016 – 2020) – Deferred Payment due in March 2020 (2 years remaining) – SMLP has the ability to issue equity directly to the GP for up to 100% of the consideration
- SMLP intends to incrementally position the balance sheet over time to
prepare for the Deferred Payment
–
Strategy allows SMLP to match capital markets issuances with cash flow growth from the Drop Down Assets
–
Prior to the Deferred Payment, SMLP will be over covered (i.e. distribution coverage) and under levered
- To date, SMLP has completed the following opportunistic offerings:
–
$125 million equity deal in September 2016
–
$500 million bond deal in February 2017
–
Amended and extended SMLP’s $1.25 billion revolver with a 2022 maturity date, which is outside of the Deferred Payment due date
–
$300 million perpetual preferred equity offering in November 2017
–
Access to ATM program
- The Deferred Payment consideration mix of debt and equity will target
the following pro forma metrics:
–
4.0x leverage and ≥1.20x distribution coverage
Financing the Deferred Payment Overview of Deferred Payment Calculation(1)
(1) Please refer to Contribution Agreement included in SMLP’s 8-K filing with SEC on 3/1/2016 for more detail on Deferred Payment. (2) Cumulative figures based on actual financial results from December 2017 through December 2019. (3) Current estimate as reported in the December 31, 2017 10-K filing; Discounted remaining consideration discounted at a 11.50% discount rate.
The Deferred Payment can include equity issued directly to the GP for up to 100% of the consideration
Average Business Adjusted EBITDA, net of G&A Multiplied by: 6.5x Pre-Adjustments Remaining Consideration Less: $360 Million Initial Cash Consideration Less: Cumulative Capital Expenditures(2) Plus: Cumulative Business Adjusted EBITDA, net of G&A(2) Undiscounted Remaining Consideration Undiscounted Remaining Consideration (12/31/2017): $454 million (3) Discounted Remaining Consideration (12/31/2017): $363 million (3)
30
2018 Financial Guidance
Guidance Range FY 2018(1) ($ in millions) Low High Adjusted EBITDA (FY 2018) $285.0 $300.0 Distribution Coverage 0.95x 1.05x Growth Capex $160.0 $205.0 Maintenance Capex $15.0 $20.0 Total Capex $175.0 $225.0 Full Year 2018 adj. EBITDA guidance of $285.0 million to $300.0 million
(1) Based on guidance provided in SMLP press release on February 22, 2018. Note: 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.
Appendix
32
Reportable Segment Adjusted EBITDA
(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.
Year ended December 31,
($s in 000s)
2017 2016 Reportable segment adjusted EBITDA(1): Utica Shale $34,011 $21,035 Ohio Gathering(2) 41,246 45,602 Williston Basin 66,413 79,475 Piceance/DJ Basins 117,737 109,241 Barnett Shale 46,232 54,634 Marcellus Shale 23,888 19,203 Total $329,527 $329,190 Less: Corporate and other(3) 39,140 37,589 Adjusted EBITDA $290,387 $291,601
33
Non-GAAP Reconciliations
(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 $500.0 million 5.75% senior notes is paid in cash semi-annually in arrears on April 15 and October 15, beginning October 15, 2017 until maturity in April 2025. (7) Distributions on the Series A preferred units are paid in cash semi-annually in arrears on June 15 and December 15 each year, beginning on December 15, 2017 through and including December 15, 2022, and, thereafter, quarterly in arrears on the 15th day of March, June, September and December of each year. (8) Series A Preferred unit distribution adjustment represents the distributions accrued on the Series A preferred units.
Year Ended December 31,
($s in 000s)
2017 2016 2017 2016 2015 2014 2013 Net Income (Loss) ($18,250) $13,995 $86,050 ($38,187) ($222,228) ($47,368) $47,008 Add: Interest expense 16,248 16,160 68,131 63,810 59,092 48,586 21,314 Income tax (benefit) expense (76) (66) 341 75
- 854
729 Depreciation and amortization(1) 29,140 28,603 114,872 112,661 105,903 91,822 72,264 Proportional adjusted EBITDA for equity method investees(2) 12,045 10,429 41,246 45,602 33,667 6,006
- Adjustments related to MVC shortfall payments(3)
(8,187) (22,218) (41,373) 11,600 (11,902) 26,565 17,025 Unit-based and noncash compensation 1,978 1,985 7,951 7,985 7,017 5,841 4,242 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
(3) 69 527 93 42 442 113 Long-lived asset impairment 187,125 23 188,702 1,764 9,305 5,505
- Goodwill impairment
- 248,851
54,199
- Less:
Interest income
- 2
4 5 Income tax benefit
- 603
- Income (loss) from equity method investees
1,468 997 (2,223) (30,344) (6,563) (16,712)
- Gain on asset sales
- 214
- Impact of purchase price adjustment
- 1,185
- Adjusted EBITDA
$72,923 $72,721 $290,387 $291,601 $235,491 $207,975 $162,690 Add: Cash interest received
- 2
4 5 Cash taxes received
- 50
- Less:
Cash interest paid 24,078 5,783 71,488 63,000 59,302 38,453 13,170 Cash taxes paid
- 660
Senior notes interest adjustment(6) (7,855) 9,750 (5,261)
- (1,421)
6,733 12,125 Distributions to Series A Preferred unitholders(7) 2,375
- 2,375
- 660
Series A Preferred units distribution adjustment(8) 1,188
- 1,188
- 660
Maintenance capital expenditures 3,964 4,386 15,587 17,745 12,681 18,082 16,129 Distributable cash flow $49,173 $52,802 $205,010 $210,906 $164,931 $144,711 $119,291 Three Months Ended December 31,
34
Reconciliation of Net Cash Provided by Operating Activities to DCF
(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
- n February 15 and August 15 until maturity in August 2022. Interest on the $500.0 million 5.75% senior notes is paid in cash semi-annually in arrears on April 15 and October 15, beginning October
15, 2017 until maturity in April 2025. (4) Distributions on the Series A preferred units are paid in cash semi-annually in arrears on June 15 and December 15 each year, beginning on December 15, 2017 through and including December 15, 2022, and, thereafter, quarterly in arrears on the 15th day of March, June, September and December of each year. (5) Series A Preferred unit distribution adjustment represents the distributions accrued on the Series A preferred units. (6) Represents distributions declared to common unitholders in respect of a given period. For example, for the three months ended December 31, 2017, represents the distributions paid in February 2018. Year ended December 31, Variance
($s in 000s)
2017 2016 $ % Distributable Cash Flow: Net Cash provided by operating activities $237,832 $230,495 $7,337 3% Add: Interest expense, excluding amortization of debt issuance costs 63,973 59,834 4,139 7% Income tax expense 341 75 266 355% Changes in operating assets and liabilities 28,890 (11,014) 39,904 (362%) Proportional adjusted EBITDA for equity method investees(1) 41,246 45,602 (4,356) (10%) Adjustments related to MVC shortfall payments(2) (41,373) 11,600 (52,973) (457%) Less: Distributions from equity method investees 40,220 44,991 (4,771) (11%) Write-off of debt issuance costs 302
- 302
n/a Adjusted EBITDA $290,387 $291,601 ($1,214) (0%) Add: Cash taxes received
- 50
(50) (100%) Less: Cash interest paid 71,488 63,000 8,488 13% Senior notes interest adjustment(3) (5,261)
- (5,261)
n/a Distributions to Series A Preferred unitholders(4) 2,375
- 2,375
n/a Series A Preferred units distribution adjustment(5) 1,188
- 1,188
n/a Maintenance capital expenditures 15,587 17,745 (2,158) (12%) Distributable cash flow $205,010 $210,906 ($5,896) (3%) Distributions declared(6) $179,705 $170,981 $8,724 5%
35
4Q 2017 Adjustments Related to MVC Shortfall Payments(1)
(1) Adjustments related to MVC shortfall payments account for (i) the net increases or decreases in deferred revenue for MVC shor tfall payments and (ii) our inclusion of expected annual MVC shortfall payments. (2) Exclusive of Ohio Gathering due to equity method accounting. ($s in 000s) MVC Billings Gathering Revenue Adjustments to MVC Shortfall Payments Net Impact to Adjusted EBITDA 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(2) $22,245 $23,332 ($8,187) $15,145 ($s in 000s) MVC Billings Gathering Revenue Adjustments to MVC Shortfall Payments Net Impact to Adjusted EBITDA 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(2) $63,102 $103,860 ($41,373) $62,487 Three Months Ended December 31, 2017 Twelve Months Ended December 31, 2017
36
Research Coverage / Contact Information
Contact Information Equity Research Coverage
Summit Midstream Partners, LP (NYSE: SMLP)
Barclays Capital Capital One Securities, Inc. Citigroup Global Markets Credit Suisse Goldman Sachs Robert W. Baird & Co. RBC Capital Markets SunTrust Robinson Humphrey U.S. Capital Advisors Wells Fargo Securities Website: www.summitmidstream.com Headquarters:
1790 Hughes Landing Blvd. Suite 500 The Woodlands, TX 77380
IR Contact:
Marc Stratton, SVP & Treasurer ir@summitmidstream.com 832.608.6166