The document discusses SemGroup's non-GAAP financial measures of Adjusted EBITDA, Cash Available for Dividends (CAFD) and Total Segment Profit. It explains that Adjusted EBITDA removes certain selected items from net income to improve comparability between periods and includes a list of the types of items generally excluded. CAFD is based on Adjusted EBITDA less certain cash payments to analyze performance after obligations. Total Segment Profit represents revenue less costs and expenses, adjusted for certain items, and is how management assesses segment performance. The measures are used by management and may be presented to investors but have limitations as analytical tools.

1. Investor Presentation
Third Quarter 2018 Results
November 2018

2. 2
Non-GAAP Financial Measures
SemGroup’s non-GAAP measures, Adjusted EBITDA, Cash Available for Dividends (CAFD) and Total Segment Profit, are not GAAP measures and are not intended to be used in
lieu of GAAP presentation of their most closely associated GAAP measures, net income (loss) for Adjusted EBITDA and CAFD and operating income for Total Segment Profit.
Adjusted EBITDA represents earnings before interest, taxes, depreciation and amortization, adjusted for selected items that SemGroup believes impact the comparability of financial
results between reporting periods. In addition to non-cash items, we have selected items for adjustment to EBITDA which management feels decrease the comparability of our
results among periods. These items are identified as those which are generally outside of the results of day to day operations of the business. These items are not considered non-
recurring, infrequent or unusual, but do erode comparability among periods in which they occur with periods in which they do not occur or occur to a greater or lesser degree.
Historically, we have selected items such as gains on the sale of NGL Energy Partners LP common units, costs related to our predecessor’s bankruptcy, significant business
development related costs, significant legal settlements, severance and other similar costs. Management believes these types of items can make comparability of the results of day
to day operations among periods difficult and have chosen to remove these items from our Adjusted EBITDA. We expect to adjust for similar types of items in the future. Although
we present selected items that we consider in evaluating our performance, you should be aware that the items presented do not represent all items that affect comparability
between the periods presented. Variations in our operating results are also caused by changes in volumes, prices, mechanical interruptions and numerous other factors. We do not
adjust for these types of variances.
CAFD is based on Adjusted EBITDA, as defined above, and reduced for cash income taxes, cash interest expense, preferred stock cash dividends and maintenance capital
expenditures, as adjusted for selected items which management feels decrease the comparability of results among periods. CAFD is a performance measure utilized by
management to analyze our performance after the payment of cash taxes, servicing debt obligations and making sustaining capital expenditures.
Total Segment Profit represents revenue, less cost of products sold (exclusive of depreciation and amortization) and operating expenses, plus equity earnings and is adjusted to
remove unrealized gains and losses on commodity derivatives and to reflect equity earnings on an EBITDA basis. Reflecting equity earnings on an EBITDA basis is achieved by
adjusting equity earnings to exclude our percentage of interest, taxes, depreciation and amortization from equity earnings for operated equity method investees. For our investment
in NGL Energy, we exclude equity earnings and include cash distributions received. Segment profit is the measure by which management assess the performance of our reportable
segments.
These measures may be used periodically by management when discussing our financial results with investors and analysts and are presented as management believes they
provide additional information and metrics relative to the performance of our businesses. These non-GAAP financial measures have important limitations as analytical tools because
they exclude some, but not all, items that affect the most directly comparable GAAP financial measures. You should not consider non-GAAP measures in isolation or as substitutes
for analysis of our results as reported under GAAP. Management compensates for the limitations of our non-GAAP measures as analytical tools by reviewing the comparable GAAP
measures, understanding the differences between the non-GAAP measure and the most comparable GAAP measure and incorporating this knowledge into its decision-making
processes. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating our operating results. Because all
companies do not use identical calculations, our presentations of non-GAAP measures may be different from similarly titled measures of other companies, thereby diminishing their
utility.
SemGroup does not provide guidance for net income, the GAAP financial measure most directly comparable to the non-GAAP financial measure Adjusted EBITDA, because Net
Income includes items such as unrealized gains or losses on derivative activities or similar items which, because of their nature, cannot be accurately forecasted. We do not expect
that such amounts would be significant to Adjusted EBITDA as they are largely non-cash items.

3. 3
Certain matters contained in this Presentation include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation
Reform Act of 1995.
All statements, other than statements of historical fact, included in this presentation including the prospects of our industry, our anticipated financial performance, our anticipated annual
dividend growth rate, management's plans and objectives for future operations, planned capital expenditures, business prospects, outcome of regulatory proceedings, market conditions
and other matters, may constitute forward-looking statements. Although we believe that the expectations reflected in these forward-looking statements are reasonable, we cannot assure
you that these expectations will prove to be correct. These forward-looking statements are subject to certain known and unknown risks and uncertainties, as well as assumptions that
could cause actual results to differ materially from those reflected in these forward-looking statements. Factors that might cause actual results to differ include, but are not limited to, our
ability to generate sufficient cash flow from operations to enable us to pay our debt obligations and our current and expected dividends or to fund our other liquidity needs; any sustained
reduction in demand for, or supply of, the petroleum products we gather, transport, process, market and store; the effect of our debt level on our future financial and operating flexibility,
including our ability to obtain additional capital on terms that are favorable to us; our ability to access the debt and equity markets, which will depend on general market conditions and
the credit ratings for our debt obligations and equity; the failure to realize the anticipated benefits of our acquisition of 100 percent of the equity interests in Buffalo Parent Gulf Coast
Terminals LLC, the parent company of Buffalo Gulf Coast Terminals LLC and HFOTCO LLC, doing business as Houston Fuel Oil Terminal Company (“HFOTCO”); the loss of, or a
material nonpayment or nonperformance by, any of our key customers; the amount of cash distributions, capital requirements and performance of our investments and joint ventures; the
consequences of any divestitures of non-strategic operating assets or divestitures of interests in some of our operating assets through partnerships and/or join ventures; the amount of
collateral required to be posted from time to time in our commodity purchase, sale or derivative transactions; the impact of operational and developmental hazards and unforeseen
interruptions; our ability to obtain new sources of supply of petroleum products; competition from other midstream energy companies; our ability to comply with the covenants contained
in our credit agreements, continuing covenant agreement, and the indentures governing our notes, including requirements under our credit agreements and continuing covenant
agreement to maintain certain financial ratios; our ability to renew or replace expiring storage, transportation and related contracts; the overall forward markets for crude oil, natural gas
and natural gas liquids; the possibility that the construction or acquisition of new assets may not result in the corresponding anticipated revenue increases; any future impairment of
goodwill resulting from the loss of customers or business; changes in currency exchange rates; weather and other natural phenomena, including climate conditions; a cyber attack
involving our information systems and related infrastructure, or that of our business associates; the risks and uncertainties of doing business outside of the U.S., including political and
economic instability and changes in local governmental laws, regulations and policies; costs of, or changes in, laws and regulations and our failure to comply with new or existing laws or
regulations, particularly with regard to taxes, safety and protection of the environment; the possibility that our hedging activities may result in losses or may have a negative impact on
our financial results; general economic, market and business conditions; as well as other risk factors discussed from time to time in our each of our documents and reports filed with the
SEC.
Readers are cautioned not to place undue reliance on any forward-looking statements contained in this press release, which reflect management’s opinions only as of the date hereof.
Except as required by law, we undertake no obligation to revise or publicly release the results of any revision to any forward-looking statements.
We use our Investor Relations website and social media outlets as channels of distribution of material company information. Such information is routinely posted and accessible on our
Investor Relations website at ir.semgroupcorp.com. We are present on Twitter and LinkedIn: SemGroup Twitter and LinkedIn
Forward-Looking Information

4. 4
• 1,700 miles crude pipelines
• 8.8 million barrels crude oil storage capacity
• 230 crude oil trucks/trailers
• 1,000 miles gas gathering pipelines
• 4 gas processing plants (600 mmcf/d total)
• 680,000 dedicated gas gathering acres from
key producers
MID-CONTINENT
• 4 natural gas processing plants
• 600 miles natural gas gathering pipelines
• 200 mmcf/d Wapiti Gas Plant under construction
• 60 mmcf/d Smoke Lake Plant under construction
• 1 bcf/d total processing capacity(1)
with significant sulphur recovery
Unique platform in liquids-rich Montney and Duvernay
• 330 acres on Houston Ship Channel
• 18.2 million barrels product storage
• Connectivity to Gulf Coast refining complex
• Pipeline connectivity to all major basins
• Deepwater marine access
• Rail and truck loading and unloading
• Maurepas Pipeline serving refineries
Strategic position in North America’s largest energy complex
CANADA
GULF COAST t
DJ Basin, STACK, Cushing and Northeast OK
Diversified Operations Across Midstream Value Chain
1) Pro forma with new plants

5. 5
98%
Why Invest in SemGroup?
Stable
Business
Reliable Business Model Provides Highly Predictable Cash Flows
Fee Based
60%
Secure Cash
Flows
Take-or-Pay
70%
Investment Grade
Customers
of revenue
Note: Approximated percentages, see slide 35 in appendix for additional detail and non-GAAP financial data
reconciliations are also included in the appendix to this presentation
Dividend Coverage
1.4x
Adjusted EBITDA CAGR
2016 - 2018e
18%

6. 6
2018 Execution as Promised:
• 1st Quarter
▪ Executed preferred equity raise
▪ Completed sale of SemMaterials Mexico
• 2nd Quarter
▪ Completed sale of SemLogistics
▪ Funded final HFOTCO payment
▪ Announced White Cliffs Pipeline NGL re-purposing
▪ Refinanced HFOTCO term loan, lowered interest rate and extended maturity
• 3rd Quarter
▪ Completed new ship dock and crude tanks at HFOTCO
• 4th Quarter To Date
▪ Completed sale of 49% minority interest in Maurepas Pipeline
▪ Progressing Wapiti and Smoke Lake Plant construction projects
▪ Pipestone Pipeline and Moore Road Pipeline projects began
Transforming
Portfolio
Executing
Opportunities
Delivering
Shareholder
Value
6
Driving Shareholder Value

7. 7
Ñ Secure Cash Flows Drive Quality Earnings
• Nearly 60% of gross margin supported by take-or-pay contracts
• 3Q Adjusted EBITDA $96.4 million
• Declared quarterly dividend of $0.4725 per share, supported by strong dividend coverage of 1.4x
Ñ Balance Sheet Focus and Prudent CAPEX Spending
• Closed Maurepas sale of 49% minority interest for $350 million in October 2018, resulting in over
$1 billion raised to date
• Year-to-date capex spend: $292 million, updated full-year 2018 guidance to $360 million, up 3%
Ñ Project Execution and Asset Utilization in Key Regions
• Gulf Coast:
▪ Completed new ship dock #5 and 1.45 mmbbls crude storage tanks - online 3Q 2018
▪ Moore Road Pipeline announced, expected completion 4Q 2019
▪ Continue to successfully recontract HFOTCO terminal including high grading customers
• Mid-Continent:
▪ Optimizing White Cliffs Pipeline with NGL conversion, expected completion 4Q 2019
▪ Continue to progress Cushing terminal recontracting
• Canada:
▪ Pipestone Pipeline announced, expected completion 4Q 2019
▪ Received regulatory approvals for Pipestone Plant
▪ Wapiti Plant expected completion early 2019 and Smoke Lake Plant expected completion 4Q 2019
Continued Execution of Strategic Transformation
Note: Non-GAAP financial data reconciliations are also included in the appendix to this presentation
Focused on Strengthening Balance Sheet and Completing High-Return Projects

8. 8
Canada
SemCAMS

9. 9
SemCAMS Natural Gas Business
1Q 2Q 3Q 4Q 1Q 2Q 3Q
414
349
414 452 441
382
434
Ñ 600 miles of transport and gathering pipelines
Ñ Strong incumbent position to serve industry’s
growing infrastructure needs
Ñ Wapiti Sour Gas Plant - under construction(4)
Ñ Smoke Lake Gas Plant - under construction(5)
Ñ Pipestone Pipeline - announced November 2018(5)
SemCAMS Areas of Operations Average Throughput Volume(1)
(mmcf/d)
1) SemCAMS volumes include total processed volumes - K3, KA and West Fox Creek facilities
2) Scheduled plant turnaround at K3
3) Scheduled plant turnaround at KA
4) Expected completion early 2019
5) Expected completion 4Q 2019
(2)
2017 2018
(3)

10. 1010
Dominant Footprint in Heart of Montney & Duvernay
Ñ Liquids rich; high percentages of condensate & NGLs
Ñ Condensate & NGL’s command higher prices
Ñ Horizontal drilling has unlocked potential by reducing
drilling cost
Ñ Existing assets ideally situated to take advantage of
aggressive Montney and Duvernay growth
Pipestone Pipeline

11. 11
Canada: SemCAMS - Gas Plant Projects
Producer activity driven by condensate demand
Ñ 200 mmcf/d sour gas processing plant
Ñ Supported by 120 mmcf/d, 15-year contract
Ñ Project cost ~ USD $225 - $250 million
Ñ 6x EBITDA multiple
Ñ Plant completion ~ early 2019
Wapiti Plant - Montney
Smoke Lake Plant - Duvernay
Ñ 60 mmcf/d sweet & sour gas processing plant
Ñ Supported by 15-year contract, 90% of capacity
contracted
Ñ Project cost ~ USD $50 million
Ñ 6x EBITDA multiple
Ñ Plant completion ~ 4Q 2019
Excess sour gas processing-key competitive advantage
11

12. 12
Canada: SemCAMS Pipestone Growth Projects
Pipestone Pipeline System
Ñ Construction commenced, deliver gas to
our Wapiti gas plant for processing
Ñ Supported by 15-year contract
Ñ Project cost ~ USD $40 million
Ñ ~7x EBITDA multiple
Ñ Plant completion ~ 4Q 2019
Ñ Received permit to construct new 280
mmcf/d gas processing plant
Ñ In discussion with multiple producers in
Pipestone area to gauge interest
Ñ Condensate capacity of 20,000 bbls/d
Ñ Acid gas processed in Pipestone area
will be transferred to K3 via existing
SemCAMS infrastructure
Proposed Pipestone Gas
Processing Plant Pipestone Pipeline

13. 13
Ñ Joint Open Season announced
August 2018 with Plains Midstream
Canada
Ñ Proposed project includes utilizing
existing and new pipelines to carry
crude, condensate and NGLs from
Pipestone area delivering to
Edmonton and Fort Saskatchewan
Ñ Initial capacity 100,000 bbl/d;
capacity can be increased to
200,000 bbl/d
Ñ Proposed completion ~4Q 2020
Canada: Proposed Montney to Market Pipeline
13
Montney to Market Pipeline (M2M)
Growth Continues in the Condensate Rich Montney

14. 14
Mid-Continent
Gas

15. 15
SemGas Areas of Operation
Ñ Located in liquids rich oil plays
Ñ Four processing facilities ~600 mmcf/d of current capacity
• ~1,000 miles of gathering pipelines
Ñ STACK Canton Pipeline - delivers STACK volumes to
Rose Valley plant
SemGas Natural Gas Business
Northern OK Avg Processing Volumes(1)
(mmcf/d)
1) SemGas volumes include total processed volumes - Oklahoma and Texas plants
1Q 2Q 3Q 4Q 1Q 2Q 3Q
287 277 265 252
305
367 395
2017 2018

16. 16
Mid-Continent
Crude & Liquids

17. 17
DJ Basin
Ñ White Cliffs Pipeline - 51% ownership
• DJ Basin to Cushing, OK
• Two 527-mile, 12-inch pipelines
• 215,000 bpd current capacity
• Currently ships two crude types
▪ DJ Basin crude/condensate
▪ Kansas common
• May 2018, announced repurposing one of the
pipelines to NGL service(1)
Ñ Wattenberg Oil Trunkline
• 75-mile, 12-inch pipeline and storage in DJ Basin
• Transports Noble Energy production to White Cliffs
• 360,000 barrels of storage capacity
• 4-bay truck unloading facility at Briggsdale, CO
Ñ Platteville Truck Unloading Facility
• 30-lane truck unloading facility
• Origin of White Cliffs Pipeline
• 350,000 barrels of storage capacity
Crude Business Overview
1) See slide 19 for additional project detail

18. 18
Ñ Cushing Storage
• 7.6 million barrels of storage
• Connectivity to all major inbound/outbound pipelines
Ñ Kansas/Oklahoma System
• 450-mile gathering and transportation pipeline system
• Connects to third-party pipelines, Kansas and
Oklahoma refineries and Cushing terminal
• 560,000 barrels of storage capacity
Ñ Isabel Pipeline
• 48 mile, 8-inch crude oil pipeline from Isabel Junction,
KS to Alva, OK
Crude Business Overview
Oklahoma/Kansas Assets Field Services
Ñ Crude Oil Trucking Fleet
• Fleet of ~230 crude oil transport trucks and trailers
• Servicing the Bakken, DJ/Niobrara, Eagle Ford,
STACK, Granite Wash & Mississippi Lime
Crude Operational Summary 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18
Crude Transportation
Transportation Volumes (mbbl/d) 179 182 190 193 182 188 182
White Cliffs Pipeline Volumes (mbbl/d) 111 107 105 92 107 135 112
Crude Facilities
Average Cushing Terminal Utilization 100% 94% 94% 100% 98% 97% 94%

19. 19
Mid-Continent: DJ Basin NGL Take-Away Solution
Long-Term Contract with DCP Midstream
Project de-risks White Cliffs Pipeline & positions upside value
White Cliffs Pipeline NGL Conversion
Ñ Diversify one 12” pipeline to NGL service
Ñ Supported by 50,000 bpd, 10-year contract with DCP
Ñ Transport NGLs from DJ Basin to Mt Belvieu
Ñ Capacity of 90k bpd, expandable to 120k bpd
Ñ SEMG capex spend of ~$30 to 33 million
Ñ < 4x EBITDA multiple, on contracted cash flows
Ñ Project Completion ~ 4Q 2019
19

20. 20
Gulf Coast
HFOTCO

21. 21
Unique Position on the Houston Ship Channel
1) HFOTCO owns two pipelines
2) HFOTCO acquisition closed July 17, 2017
21
Ñ Land
• 330 acres of waterfront land on the Houston Ship Channel
◦ 12 acres of undeveloped land at Moore Road
Junction, hub for multiple pipelines
Ñ Storage tanks
• 155 tanks ranging in size from 10 to 400 mbbls
• 18.2 mmbbls of storage capacity
Ñ Ship & Barge Docks
• Five ship docks which can receive up to Suez-max vessels
with 45-foot draft
• Seven barge docks (accommodating 23 barge
simultaneously)
Ñ Pipelines, Truck & Rail
• Three crude oil pipelines to four refineries(1)
• 72 rail spots
• 14 trucks spots
HFOTCO Operational Summary 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18
Average Terminal Utilization(2)
n/a n/a 98% 98% 97% 97% 96%

22. 22
HFOTCO: Strategic Gulf Coast Position Drives Growth
Ñ 1.45 million barrels of new crude storage
Ñ Ship Dock #5
Ñ Backstopped by investment-grade refiner, 10-year contract
Ñ Strong connectivity to Gulf Coast refining complex
Ñ Multi-modal inbound and outbound capabilities
Ñ Project cost ~$185 million; ~$120 million funded
by SemGroup
Ñ 7x EBITDA multiple
Ñ Project Completed 3Q 2018
Houston Fuel Oil Terminal
Multiple future growth projects largely driven by exports
22

23. 23
Strong Connectivity to the Houston Refinery Complex
23
Ñ Connects directly or indirectly to crude pipelines serving the Eagle Ford, Permian, Bakken, Midcontinent and Canada

24. 24
Ñ HFOTCO terminal currently services nearly 30 active customers
Ñ Current storage demand exceeds available tankage
Ñ Average customer tenure ~15 years, illustrating operational flexibility and customer service
Ñ HFOTCO terminal currently consists of 18.2 million barrels of storage
Ñ Strategically located asset on the Houston Ship Channel with connectivity to the largest U.S. energy hub
Nearly 90% of revenues generated by take-or-pay contracts
HFOTCO Terminal and Customers
18.2 million barrels of capacity (1)
1) Based on LTM September 30, 2018 throughput
Diversification Focus
Ñ Nearly 2 million barrels of heated storage has been converted to crude oil since 2014
Ñ Excluding crude, approximately 50%(1)
of product throughput derived from non-fuel oil products, such as
VGO, asphalt, carbon black and clean products
Customer Base
Crude
38%
Residual Fuel
31%
Other Products
31%

25. 25
HFOTCO, Moore Road Pipeline Connectivity Project
Improves our access to various long-haul, inbound delivery systems while
adding outbound pipeline connectivity
Moore Road Pipeline
Ñ Construct 36 inch, 6.4 mile pipeline
Ñ Project Cost $65 million
Ñ ~4-8x EBITDA multiple(1)
Ñ Project Completion ~ 4Q 2019
1) Moore Road Pipeline multiple range reflects anticipated benefit across HFOTCO system
Essential part of the HFOTCO Strategy, Enhances Connectivity
Moore Road Pipeline

26. 26
Gulf Coast
Maurepas Pipeline

27. 27 1) Call price based on predetermined fixed return on Alinda’s investment, including capital contributions
Maurepas Pipeline
Ñ Maurepas Pipeline
• 24-inch, 35 mile crude oil pipeline connected to LOCAP at St.
James and terminating at Norco refinery
• 12-inch, 35 1/2 mile intermediates pipeline between Convent and
Norco refineries
• 6-inch, 35 1/2 mile intermediates pipeline between Norco and
Convent refineries
Ñ Recent Announcements
• Sold 49% interest in Maurepas for $350 million to Alinda Capital
• Transaction structured as sale of Class B interests, values
Maurepas at ~13x
• SEMG has 5 year call-option to acquire Alinda’s interest(1)
U.S. Gulf Coast

28. 28
Financials

29. 29
($ in millions, except per share)
Net Income (loss) $(33.0) $(2.7) $8.4 $(27.3)
Adjusted EBITDA 93.4 99.0 96.4 288.8
Cash Available for Dividends 51.3 50.6 50.8 152.7
Common Dividend declared per share $0.4725 $0.4725 $0.4725 $1.418
Dividend Coverage Ratio 1.4x 1.4x 1.4x 1.4x
Note: Non-GAAP Financial Data Reconciliations are included in the Appendix to this presentation
Ñ Key Highlights
• Net income improvement primarily due to an unrealized gain on commodity derivatives
• Adjusted EBITDA down over prior quarter due primarily to Crude Supply & Logistics inventory cost timing
• Declared common stock dividend of $0.4725 per share, dividend coverage of 1.4x
• Elected non-cash, payment-in-kind (PIK) preferred stock dividend
Third Quarter 2018 Results
1Q18 YTD3Q182Q18

30. 30
($ in millions)
Crude Transportation $34.3 $37.9 $38.1 $110.3
Crude Facilities 9.3 9.7 8.2 27.2
Crude Supply and Logistics (6.6) (2.0) (7.0) (15.6)
HFOTCO 31.0 34.8 36.2 102.0
SemGas 14.3 15.4 19.8 49.5
SemCAMS 22.1 21.4 20.5 64.0
Corporate/Other 11.0 (0.1) (0.9) 10.0
Total Segment Profit $115.4 $117.1 $114.9 $347.4
Segment Profit
Ñ Third Quarter vs Second Quarter 2018
• Crude Transportation was up slightly primarily due to lower operating expenses, partially offset by a
decrease in White Cliffs Pipeline volumes due to rail demand
• Crude Facilities decreased due to timing of take-or-pay recognition and lower terminal utilization
• Crude Supply & Logistics adversely impacted by inventory cost timing
• HFOTCO improvement driven by contribution from new assets, somewhat offset by non-recurring items
• SemGas increase resulting from higher commodity prices and increased volumes
• SemCAMS results down slightly due to lower opex recoveries
1Q18 YTD3Q182Q18

31. 31
Leverage and Liquidity
($ in millions, unaudited)
9/30/2018
SemGroup (B2 / B+)
Pro Forma Revolving Credit Facility - $1.0 Billion due 2021 $ 110
5.625% Senior unsecured notes due 2022 400
5.625% Senior unsecured notes due 2023 350
6.375% Senior unsecured notes due 2025 325
7.250% Senior unsecured notes due 2026 300
Total Pro Forma SEMG Debt $ 1,485
HFOTCO (Ba3 / BB-)
Term Loan due 2025 599
Hurricane Ike Bonds due 2050 225
Total HFOTCO Debt $ 824
SemGroup Pro Forma Net Leverage Ratio (max 5.5x)(1)
4.2x
Consolidated Pro Forma Net Leverage Ratio(2)
5.4x
Consolidated Pro Forma Available Liquidity(3)
$ 932
Ñ Pro Forma metrics reflect Maurepas sale
proceeds of $350 million received
October 2018
Ñ HFOTCO Term Loan Refinancing - 2Q 2018
• $600 million
• LIBOR + 2.75%, reduction of 75 bps
• Maturity extended to 2025
• Covenant-lite
• Proceeds fully paid and canceled
revolver
Ñ Targeting consolidated leverage of less than
5.0x by year-end 2019
Ñ No significant debt maturities until 2021
1) SemGroup's net leverage ratio calculated per the senior secured credit facility definitions, which includes a pro-rata portion of
projected future annual EBITDA from material projects
2) Calculated as consolidated net debt to LTM consolidated leverage EBITDA. See additional information on slide 43
3) Available liquidity is reduced for outstanding letters of credit

32. 32
Appendix

33. 33
($inmillions)
2016 2017 2018E
$283
$328
$385 - $400
2016 - 2018 CAGR of ~18%
Narrowing 2018 Adjusted EBITDA Guidance
($ in millions)
2018 Adjusted EBITDA $385 - $400
Continuing Portfolio Transformation through 2018 for Long-Term Financial Strength
Ñ Growing earnings while improving quality of earnings
Ñ Divestments contributed $34 million of 2017 Adjusted EBITDA
Ñ Additional EBITDA to come online in 2019 already contracted
Key Guidance Assumptions FY 2018
Crude
White Cliffs Pipeline Average Volumes (mbbl/d) 115-120
Average Cushing Terminal Utilization 95-100%
SemGas
Average Processing Volumes (mmcf/d) 350-375
SemCAMS
Average Throughput Volumes (mmcf/d) 425-440
HFOTCO
Average Terminal Utilization 95-100%
Ñ 2018 divestments contribute ~$9 million of 2018 Adjusted EBITDA
Ñ SemCAMS - KA plant turnaround in 2Q18
Ñ Expect no U.S. cash income taxes

34. 34
Key Projects Driving Financial Growth 2018, 2019 and beyond
Updated 2018 Capital Expenditures Guidance
Total Project Cost 2Q18 3Q18 4Q18 1H19 2H19 2020+
HFOTCO Ship Dock 5 & Crude Storage Tanks: $120mm(1)
~7x EBITDA multiple
Wapiti Plant: $250mm ~6x EBITDA multiple
Smoke Lake Plant: $50mm ~6x EBITDA multiple
Pipestone Pipeline: $40mm(2)
~7x EBITDA multiple
White Cliffs Pipeline, 12" NGL Pipeline Conversion: $32mm(3)
< 4x EBITDA multiple
Moore Road Pipeline: $65mm(4)
~4-8x EBITDA multiple
Maintenance Growth
Total Capital Expenditures
($inmillions)
2016 2017 2018e
$52 $45 $40
$255
$307
$447
$492
$320
$360
Canada
Mid-Continent
Gulf Coast
Maintenance
2018 Capex Guidance - $360 million
Spending by Strategic Area
$203
56%
$50
14%
$67
19%
$40
11%
1) Expected SemGroup project spend on HFOTCO projects; excludes ~$65 million spent prior to close. The 7x
multiple is based on the total project cost of $185 million
2) 2018 guidance includes $10 million expected spend in 2018
3) Represents SemGroup's 51% expected spend; total project spend of $60-66 million, minimal capital in 2018
4) Moore Road Pipeline multiple range reflects anticipated benefit across HFOTCO system
11%

35. 35
70% of SemGroup's pro forma revenue is derived from
investment grade counterparties
98% of total LTM gross margin from
fee-based cash flows
Investment Grade
Non-Investment Grade
70%
30%
Company Strengths
1) LTM September 30, 2018
2) Counterparty ratings LTM September 30, 2018; excludes divested assets, SemLogistics and SemMaterials Mexico
Counterparty Strength(2)
Stable Cash Flows
SemGroup derives a significant portion of cash flows from fixed-fee, contracted
arrangements from credit-worthy counterparties
Take-or-Pay Fixed Fee POP/Marketing
2014 2015 2016 2017 2018
23% 30%
38%
49%
57%
64%
59%
51%
46%
41%
13% 11% 11%
5% 2%
(1)

36. 36
Consolidated Balance Sheets
(in thousands, unaudited, condensed) September 30,
2018
December 31,
2017
ASSETS
Current assets $ 801,099 $ 902,899
Property, plant and equipment, net 3,450,756 3,315,131
Goodwill and other intangible assets 630,741 655,945
Equity method investments 277,021 285,281
Other noncurrent assets, net 138,158 132,600
Noncurrent assets held for sale — 84,961
Total assets $ 5,297,775 $ 5,376,817
LIABILITIES, PREFERRED STOCK AND OWNERS' EQUITY
Current liabilities:
Current portion of long-term debt $ 6,000 $ 5,525
Other current liabilities 675,875 761,036
Total current liabilities 681,875 766,561
Long-term debt, excluding current portion 2,619,486 2,853,095
Other noncurrent liabilities 87,106 85,080
Noncurrent liabilities held for sale — 13,716
Total liabilities 3,388,467 3,718,452
Preferred stock 353,323 —
Owners' equity 1,555,985 1,658,365
Total liabilities, preferred stock and owners' equity $ 5,297,775 $ 5,376,817

37. 37
Consolidated Statements of Operations and Comprehensive Income (Loss)
(in thousands, except per share amounts, unaudited, condensed) 2018 2017
Q1 Q2 Q3 YTD Q1 Q2 Q3 Q4 FY2017
Revenues $ 661,609 $ 595,794 $ 633,996 $ 1,891,399 $ 456,100 $ 473,089 $ 545,922 $ 606,806 $ 2,081,917
Expenses:
Costs of products sold, exclusive of depreciation and
amortization shown below 496,132 412,089 468,871 1,377,092 348,998 340,107 398,252 427,534 1,514,891
Operating 69,791 90,245 64,835 224,871 52,083 73,346 62,666 66,669 254,764
General and administrative 26,477 22,886 21,904 71,267 21,712 26,819 38,389 26,859 113,779
Depreciation and amortization 50,536 51,755 53,598 155,889 24,599 25,602 50,135 58,085 158,421
Loss (gain) on disposal or impairment, net (3,566) 1,824 (383) (2,125) 2,410 (234) 41,625 (30,468) 13,333
Total expenses 639,370 578,799 608,825 1,826,994 449,802 465,640 591,067 548,679 2,055,188
Earnings from equity method investments 12,614 14,351 14,528 41,493 17,091 17,753 17,367 15,120 67,331
Operating income (loss) 34,853 31,346 39,699 105,898 23,389 25,202 (27,778) 73,247 94,060
Other expenses, net 44,805 37,685 33,935 116,425 33,571 11,966 28,574 39,487 113,598
Income (loss) from continuing operations before income taxes (9,952) (6,339) 5,764 (10,527) (10,182) 13,236 (56,352) 33,760 (19,538)
Income tax expense (benefit) 23,083 (3,613) (2,697) 16,773 95 3,625 (37,249) 31,141 (2,388)
Net income (loss) (33,035) (2,726) 8,461 (27,300) (10,277) 9,611 (19,103) 2,619 (17,150)
Less: cumulative preferred stock dividends 4,832 6,211 6,317 17,360 — — — — —
Net income (loss) attributable to common shareholders $ (37,867) $ (8,937) $ 2,144 $ (44,660) $ (10,277) $ 9,611 $ (19,103) $ 2,619 $ (17,150)
Net income (loss) $ (33,035) $ (2,726) $ 8,461 $ (27,300) $ (10,277) $ 9,611 $ (19,103) $ 2,619 $ (17,150)
Other comprehensive income (loss), net of income taxes 18,171 6,180 3,352 27,703 6,033 8,952 9,230 (4,102) 20,113
Comprehensive income (loss) $ (14,864) $ 3,454 $ 11,813 $ 403 $ (4,244) $ 18,563 $ (9,873) $ (1,483) $ 2,963
Net income (loss) per common share:
Basic $ (0.48) $ (0.11) $ 0.03 $ (0.57) $ (0.16) $ 0.15 $ (0.25) $ 0.03 $ (0.24)
Diluted $ (0.48) $ (0.11) $ 0.03 $ (0.57) $ (0.16) $ 0.15 $ (0.25) $ 0.03 $ (0.24)
Weighted average shares (thousands):
Basic 78,198 78,319 78,353 78,290 65,692 65,749 75,974 78,189 71,418
Diluted 78,198 78,319 78,977 78,290 65,692 66,277 75,974 78,749 71,418

38. 38
Non-GAAP Adjusted EBITDA Calculation
(in thousands, unaudited) 2018 2017
Reconciliation of net income to Adjusted EBITDA: Q1 Q2 Q3 YTD Q1 Q2 Q3 Q4 FY2017
Net income (loss) $ (33,035) $ (2,726) $ 8,461 $ (27,300) $ (10,277) $ 9,611 $ (19,103) $ 2,619 $ (17,150)
Add: Interest expense 42,461 35,904 35,318 113,683 13,867 13,477 32,711 42,954 103,009
Add: Income tax expense (benefit) 23,083 (3,613) (2,697) 16,773 95 3,625 (37,249) 31,141 (2,388)
Add: Depreciation and amortization expense 50,536 51,755 53,598 155,889 24,599 25,602 50,135 58,085 158,421
EBITDA 83,045 81,320 94,680 259,045 28,284 52,315 26,494 134,799 241,892
Selected Non-Cash Items and
Other Items Impacting Comparability 10,326 17,690 1,771 29,787 32,383 13,095 64,239 (23,306) 86,411
Adjusted EBITDA $ 93,371 $ 99,010 $ 96,451 $ 288,832 $ 60,667 $ 65,410 $ 90,733 $ 111,493 $ 328,303
Selected Non-Cash Items and
Other Items Impacting Comparability
Loss (gain) on disposal or impairment, net $ (3,566) $ 1,824 $ (383) $ (2,125) $ 2,410 $ (234) $ 41,625 $ (30,468) $ 13,333
Foreign currency transaction loss (gain) 3,294 2,314 (983) 4,625 — (1,011) (747) (2,951) (4,709)
Adjustments to reflect equity earnings on an EBITDA basis 4,883 4,886 4,926 14,695 6,709 6,692 6,678 6,811 26,890
M&A transaction related costs 1,156 648 290 2,094 — 5,453 14,886 1,649 21,988
Pension plan curtailment loss (gain) — — — — — — (3,097) 89 (3,008)
Employee severance and relocation expense 137 211 43 391 558 312 104 720 1,694
Unrealized loss (gain) on derivative activities 2,226 4,409 (4,860) 1,775 27 (928) 1,833 (892) 40
Non-cash equity compensation 2,196 3,398 2,738 8,332 2,757 2,803 2,957 1,736 10,253
Loss on early extinguishment of debt — — — — 19,922 8 — — 19,930
Selected Non-Cash items and
Other Items Impacting Comparability $ 10,326 $ 17,690 $ 1,771 $ 29,787 $ 32,383 $ 13,095 $ 64,239 $ (23,306) $ 86,411

39. 39
(in thousands, unaudited) 2018 2017
Segment Profit: Q1 Q2 Q3 YTD Q1 Q2 Q3 Q4 FY2017
Crude Transportation $ 34,310 $ 37,865 $ 38,135 $ 110,310 $ 28,251 $ 29,028 $ 34,585 $ 41,641 $ 133,505
Crude Facilities 9,341 9,683 8,209 27,233 9,564 9,481 8,806 14,116 41,967
Crude Supply and Logistics (6,583) (1,959) (7,005) (15,547) (2,428) (2,173) (1,693) (1,507) (7,801)
HFOTCO 30,988 34,804 36,161 101,953 — — 28,504 33,032 61,536
SemGas 14,277 15,437 19,754 49,468 18,227 19,483 15,555 14,539 67,805
SemCAMS 22,113 21,448 20,543 64,104 16,865 19,038 16,704 23,668 76,274
Corporate and other 10,963 (172) (913) 9,878 8,367 8,296 8,421 8,153 33,237
Total Segment Profit 115,409 117,106 114,884 347,399 78,846 83,153 110,882 133,642 406,523
Less:
General and administrative expense 26,477 22,886 21,904 71,267 21,712 26,819 38,389 26,859 113,779
Other income (950) (533) (400) (1,883) (218) (508) (3,390) (516) (4,632)
Pension curtailment gain (loss) — — — — — — 3,097 (89) 3,008
Plus:
M&A related costs 1,156 648 290 2,094 — 5,453 14,886 1,649 21,988
Employee severance and relocation 137 211 43 391 558 312 104 720 1,694
Non-cash equity compensation 2,196 3,398 2,738 8,332 2,757 2,803 2,957 1,736 10,253
Consolidated Adjusted EBITDA $ 93,371 $ 99,010 $ 96,451 $ 288,832 $ 60,667 $ 65,410 $ 90,733 $ 111,493 $ 328,303
Segment Profit and Adjusted EBITDA

40. 40
Non-GAAP Adjusted EBITDA Calculation
(in thousands, unaudited) FY2016
Reconciliation of net income to Adjusted EBITDA:
Net income $ 13,262
Add: Interest expense 62,650
Add: Income tax expense 11,268
Add: Depreciation and amortization expense 98,804
EBITDA 185,984
Selected Non-Cash Items and
Other Items Impacting Comparability 96,811
Adjusted EBITDA $ 282,795
Selected Non-Cash Items and
Other Items Impacting Comparability
Loss on disposal or impairment, net $ 16,048
Loss from discontinued operations, net of income taxes 1
Foreign currency transaction loss (gain) 4,759
Adjustments to reflect equity earnings on an EBITDA basis 28,757
Remove loss (gain) on sale or impairment of NGL units 30,644
M&A transaction related costs 3,269
Inventory valuation adjustments including equity method investees —
Employee severance and relocation expense 2,128
Unrealized loss (gain) on derivative activities 989
Change in fair value of warrants —
Bankruptcy related expenses —
Charitable contributions —
Legal settlement expense —
Recovery of receivables written off at emergence —
Non-cash equity compensation 10,216
Selected Non-Cash items and
Other Items Impacting Comparability $ 96,811

41. 41
Reconciliation of Operating Income to Total Segment Profit
(in thousands, unaudited) 2018 2017
Q1 Q2 Q3 YTD Q1 Q2 Q3 Q4 FY2017
Operating income (loss) $ 34,853 $ 31,346 $ 39,699 $ 105,898 $ 23,389 $ 25,202 $ (27,778) $ 73,247 $ 94,060
Plus:
Adjustments to reflect equity earnings on an EBITDA basis 4,883 4,886 4,926 14,695 6,709 6,692 6,678 6,811 26,890
Unrealized loss (gain) on derivatives 2,226 4,409 (4,860) 1,775 27 (928) 1,833 (892) 40
General and administrative expense 26,477 22,886 21,904 71,267 21,712 26,819 38,389 26,859 113,779
Depreciation and amortization 50,536 51,755 53,598 155,889 24,599 25,602 50,135 58,085 158,421
Loss (gain) on disposal or impairment, net (3,566) 1,824 (383) (2,125) 2,410 (234) 41,625 (30,468) 13,333
Total Segment Profit $ 115,409 $ 117,106 $ 114,884 $ 347,399 $ 78,846 $ 83,153 $ 110,882 $ 133,642 $ 406,523

42. 42
Cash Available for Dividends
(in thousands, unaudited) 2018 2017
Q1 Q2 Q3 YTD Q1 Q2 Q3 Q4 FY2017
Adjusted EBITDA $ 93,371 $ 99,010 $ 96,451 $ 288,832 $ 60,667 $ 65,410 $ 90,733 $ 111,493 $ 328,303
Less: Cash interest expense 32,530 34,870 36,377 103,777 17,976 18,396 29,621 35,203 101,196
Less: Maintenance capital 7,729 11,550 8,635 27,914 8,272 11,850 12,693 9,597 42,412
Less: Cash paid for income taxes 1,800 12,900 600 15,300 1,155 1,721 196 4,088 7,160
Selected items impacting comparability:
Add back: Mexico disposal cash taxes — 10,955 — 10,955 — — — — —
Cash available for dividends $ 51,312 $ 50,645 $ 50,839 $ 152,796 $ 33,264 $ 33,443 $ 48,223 $ 62,605 $ 177,535
Dividends declared $ 37,004 $ 37,022 $ 37,022 $ 111,048 $ 29,584 $ 35,171 $ 35,184 $ 36,961 $ 136,900
Dividend coverage ratio 1.4x 1.4x 1.4x 1.4x 1.1x 1.0x 1.4x 1.7x 1.3x

43. 43
Reconciliation of Adjusted EBITDA to Pro Forma
Consolidated Leverage EBITDA
(in millions, unaudited)
Adjusted EBITDA
3Q18 $ 96.4
2Q18 99.0
1Q18 93.4
4Q17 111.5
LTM Adjusted EBITDA 400.3
Adjustments 11.9
LTM PF Consolidated Leverage EBITDA $ 412.2
Acquisition / divestitures adjustment(1) (43.6)
Material projects adjustment(2) 44.7
Tax adjustment 13.1
Miscellaneous adjustment (2.3)
Total Adjustments(3) $ 11.9
1) Includes proforma LTM results for Glass Mountain Pipeline, SemMexico, SemLogistics and Maurepas 49% minority interest
divestitures
2) Pro-rata portion of projected future annual EBITDA from material projects
3) Consistent with adjustments permitted under SemGroup's senior secured credit facility