The document discusses SemGroup's non-GAAP financial measures and provides forward-looking statements. It includes the following key points: - SemGroup uses measures like Adjusted EBITDA, Cash Available for Dividends, and Total Segment Profit to evaluate performance, which are not substitutes for GAAP measures. - Adjusted EBITDA excludes selected non-cash and other items to improve comparability between periods. - Cash Available for Dividends is based on Adjusted EBITDA less certain cash expenses and capital expenditures. - Total Segment Profit assesses performance at the segment level and excludes certain items. - The document cautions that non-GAAP measures have limitations

1. Alta Corp Capital Conference
Investor Presentation
September 2018

2. Non-GAAP Financial Measures
2
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. Forward-Looking Information
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

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

5. 5
Over 70% of SemGroup's pro forma revenue is
derived from investment grade counterparties
97% of total LTM gross margin from
fee-based cash flows
SemGroup Strengths
1) LTM June 30, 2018, pro forma for full-year HFOTCO acquisition and Maurepas Pipeline
2) LTM June 30, 2018; excludes divested assets, Glass Mountain Pipeline, 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

6. 6
SemGroup Financial Growth Aligned with Stable
Fee-Based Assets
NOTE: Non-GAAP Financial Data Reconciliations are included in the Appendix to this presentation
1) Take-or-pay % of gross margin: LTM June 30, 2018, pro forma for full-year HFOTCO acquisition and Maurepas Pipeline

7. 7
SemGroup Strategic Focus:
▶ Developing unique US Gulf Coast position to leverage export opportunities
▶ Capturing significant growth potential in Montney & Duvernay plays in Canada
▶ Leveraging Mid-Con footprint to capture growing crude and NGL takeaway needs
▶ Driving capital funding initiatives to reduce balance sheet leverage
Transforming
Portfolio
Executing
Opportunities
Delivering
Shareholder
Value
7
Driving Shareholder Value
Clear Path to Long-Term Growth

8. SemCAMS
Overview
8

9. 9
Unique Footprint Difficult to Replicate
▶ Strategic location for processing sour gas originating from the
Wapiti, Montney and Duvernay plays
• Total combined operating capacity of ~1 bcf/d(1) – licensed
capacity of 1.5 bcf/d
• Operator and majority owner in four sour & sweet gas plants
 Kaybob South #3 (K3)
 Kaybob Amagamated (KA)
 West Fox Creek
 West Whitecourt (WWC)
• Announced plant projects
 Wapiti (under construction)
 Smoke Lake (under construction)
 Pipestone (proposed)
• 600 miles of sour and sweet gas gathering pipelines
• Multiple takeaway options provide flexibility to producers
 TransCanada (Gas)
 Alliance (Gas)
 Pembina (Liquids)
 Rail and truck loading capabilities
SemCAMS owns and operates a vast network of essential midstream
infrastructure in Alberta, servicing the prolific Montney and Duvernay plays
1) Pro forma plants under construction

10. SemCAMS Midstream Platform
10
Stable Cash Flows
Supported by Strong
Counterparties
▶ 100% fee-based contracts with no direct commodity price exposure
▶ Take-or-pay contracts account for an estimated 40% of 2018 contracted revenue
▶ Turnaround, opex, and maintenance expenses flow through to producers
Visible Growth
Opportunities
▶ Approximately USD $200 million forecasted growth capex spend in 2018, supported by
long-term take-or-pay contracts at attractive multiples
▶ Identified future plant and pipeline growth opportunities
Unique Asset
Footprint Located in
Prolific Plays
▶ Largest sour gas processor with dominate footprint in the core of the Monteney and
Duverney plays with 1 bcf/d of combined operating sour gas processing capacity
▶ Capable of processing sour and sweet gas as well as condensate and liquids handling
▶ Wapiti Pipeline provides Montney producers with Acid Gas Transfer (AGT) to sulfur-
recovery plants at K3, capable of handling up to 30% H2S
▶ 98% plant reliability over the past 18 years
▶ Unit train capabilities at KA and K3 for liquids and sulfur
▶ Multiple takeaway options provide flexibility to producers

11. 440 426 381 426 407 411
2013 2014 2015 2016 2017 2018 YTD
$34.1
$45.9
$37.2 $40.1
$59.9
2013 2014 2015 2016 2017
99% 97% 99% 100%
92%
97% 95%
100% 100%
96%
100% 99%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
2007T
2008
2009T
2010
2011
2012T
2013T
2014
2015
2016
2017T
2018TYTD
SemCAMS Performance
1) Includes KA and K3 plants; excludes planned outages (plant turnarounds)
2) SemCAMS volumes include total processed volumes - K3, KA and West Fox Creek facilities
3) Scheduled plant turnaround at KA
4) Scheduled plant turnaround at K3
Note: Year to date as of June 30, 2018 and Non-GAAP Financial Data Reconciliations are included in the Appendix to this presentation
11
Plant Reliability(1) Average Throughput Volume(2) (mmcf/d)
(4)
Adjusted EBITDA (USD$MM)Customers
(3)
T = Turnaround Years
(3)
Historical reliability of >98%, excluding planned outages

12. The Montney and
Duvernay Plays
12

13. Canadian Condensate Market Overview
Source: RBC Capital Markets, Government Data
13
“Western Canada will
likely remain short
condensate for the
foreseeable future
supporting its
premium vs.
Edmonton condensate
and rough parity with
WTI (C$)” - RBC
Oil sands diluent demand, combined with short fall in local condensate
supply will continue to drive production growth
“Condensate demand
in western Canada is
expected to outstrip
domestic supply, with
imports bridging the
gap and rail playing
a bigger role.” - RBC

14. 14
Proposed
Pipestone Plant
Wapiti Project
KA Plant & Smoke
Lake Project
West Fox Creek Plant
West Whitecourt
Plant
K3 Plant
Wapiti/Pipestone
Kaybob
Wapiti Pipeline
to KA and K3
Dominate Footprint in Heart of Montney & Duvernay
▶ Liquids rich; high percentages of condensate & NGLs
▶ Condensate & NGL’s command higher prices
▶ Horizontal drilling has unlocked potential by reducing
drilling cost
▶ Existing assets ideally situated to take advantage of
aggressive Montney and Duvernay growth
0.0
2.0
4.0
6.0
8.0
2010 2011 2012 2013 2014 2015 2016 2017 2018
Duvernay Montney AB Montney BC
Fundamentals Underpinned by
Economic Upstream Resource
Exposure to growing Montney & Duvernay production
SemCAMS Growth Area Production Bcf/d
Source: Scotia Bank and GeoScout

15. ▶ As Montney production continues to grow, there is a
deep inventory of potential new build infrastructure
projects across the fairway
▶ SemCAMS’ liquids processing and sour plant
experience are clear competitive advantages as
Montney operators continue to be focused on liquids-
rich opportunities
▶ Producers have increasingly encountered sour gas in
new emerging areas
Montney, Significant Development Potential
15
Cenovus Pipestone
Montney acreage
recently acquired by
NuVista
Wapiti Pipestone Montney Mineral Rights
2017–18 Wapiti/Montney Drilling Activity by Producer
96
32 30
22
11 17 18
11 12 8 8 8 10 5 7 5 5
15
61
19 17
20
23 7 3
10 3
6 4 4 1
5 1
16
0
20
40
60
80
100
120
140
160
180
2017 2018 YTD
NuVista Energy is Top 3 In
Montney Drilling Activity Since
2017 in the Wapiti Pipestone Area
Source: Company disclosures and GeoScout

16. ▶ SemCAMS’ existing area infrastructure, technical
expertise, and operational track record are clear
competitive advantages as operators look for long-term
gathering and processing solutions
▶ Operators are increasingly encountering sour production
in the Duvernay and estimate that as much as 25% of
Duvernay could be sour
▶ Major Duvernay producers in the Kaybob area continue
to flow sour production to our KA facility
▶ Smoke Lake plant under construction located north of KA
to process incremental sour gas production
Footprint in the Core of the Duvernay
16
26
Duvernay Mineral Rights
2017–18 Duvernay Drilling Activity by Producer
32
16 15
6
44
8
15
17 17
10
22
15 1
0
10
20
30
40
50
60
70
Chevron Encana Murphy Paramount Shell XTO Energy Other
2017 2018 YTD
Source: Company disclosures and GeoScout.

17. Announced
Growth Projects
17

18. Wapiti Sour Gas Processing Plant – Underway
SemCAMS Ideally Situated to Take Advantage of Aggressive Montney Growth
18
▶ SemCAMS is building a 100% owned 200 mmcf/d
sour gas processing plant in the Wapiti area of
Alberta
▶ Leverages existing assets in the Kaybob area for a
unique sour gas handling solution
• Acid Gas Transfer - utilize existing Wapiti pipeline
system for transportation of acid gas to K3 plant for
processing
▶ Producer development activity driven by condensate
demand
• Condensate handling capacity of 20,000 bbl/d
▶ Investment is backstopped by NuVista
• 120 mmcf/d, 15-year contract (80% take-or-pay)
▶ Anticipate contracting the remaining capacity by
year-end 2018
▶ Total project cost of ~USD $225 - $250 million
▶ 6x EBITDA multiple
▶ Plant completion early 2019 Photo: Site construction progress as of June, 2018

19. Proposed Pipestone Gas Processing Plant
19
▶ Filed permit to construct new 280
mmcf/d gas processing plant
▶ In discussion with multiple
producers in Pipestone area to
gauge interest
▶ Condensate handling capacity of
20,000 bbls/d
▶ Acid gas processed in Pipestone
area will be transferred to K3 via
existing SemCAMS infrastructure
A
B
C
D
E
F
G
H
I
K
L
J
Pipestone Project
Wapiti Project
Wapiti
Pipeline to
KA and K3
Alberta
British
Columbia

20. 20
▶ Constructing 60 mmcf/d sour &
sweet processing facility located in
close proximity to KA plant
▶ Project cost ~USD $50 million
▶ 6x EBITDA multiple
▶ Plant completion ~ 4Q 2019
▶ Supported by 15-year contract
with Murphy Oil and Athabasca Oil
▶ ~90% of capacity contracted and
underpinned by take-or-pay
contracts
▶ Connectivity to KA for liquids and
excess raw gas providing
producers with a flexible and
reliable processing solution
A
C
D
E
F
G
H
I
K
L
J
Kaybob Amalgamated
Kaybob South #3
Wapiti
Pipeline
Alberta
British
Columbia
B
Smoke Lake Project
Windfall
West Fox Creek
Smoke Lake Plant Enhances Position in Duvernay

21. ▶ Joint Open Season announced August 2018 with Plains Midstream Canada
▶ Proposed project includes utilizing existing and new pipelines to carry crude, condensate and
NGLs from Pipestone area delivering to Edmonton and Fort Saskatchewan
▶ Initial capacity 100,000 bbl/d; capacity can be increased to 200,000 bbl/d
▶ Proposed completion ~4Q 2020
Montney to Market Pipeline (M2M)
21

22. 22
Experienced
and reliable
operator
Stable cash
flows supported
by credit-worthy
customers
Irreplicable sour
gas processing
and
acid gas transfer
solution
Takeaway
optionality
via pipeline,
truck & rail
SemCAMS Competitive Advantages
Facility
interconnections
provide
operational
flexibility &
optimization
Asset footprint
in prolific
Montney and
Duvernay
plays

23. Appendix
23

24. SemCAMS Management
24
SemCAMS Background
David (Dave) Gosse
VP & General Manager
 Vice President and General Manager for SemCAMS
 Responsible for establishing SemCAMS’ goals, strategic direction, workforce safety and accountability
 Started with SemCAMS in 2011 as the Vice President of Operations; responsibility included plant operations,
engineering, health, environment and safety, asset integrity and supply chain management
 MBA from Athabasca University and is a professional engineer with more than 25 years of experience in the
energy industry
Christopher Dutcher
Vice President,
Business Development
 Works with the SemGroup business development teams and the SemCAMS Management team to identify
business development opportunities including joint venture initiatives
 Joined SemCAMS in March of 2015 and has over 25 years of progressive development experience with Keyera
Corporation and Petrofund Energy Trust
 Professional engineer and has Bachelor of Science (Honors) in Mechanical Engineering and an MBA from Queen’s
University
Leanne Campbell
Vice President, Legal
 Accountable for all legal requirements of SemCAMS, relative to its Canadian operations
 Also oversees joint venture administration and data management teams
 Joined SemCAMS in 2013 and has over 25 years of advisory and counsel experience, including a diverse
background in commercial negotiations, compliance and regulatory, corporate reputation, and legal risk
management for companies such as Cenovus and Encana as well as in private practice
 Bachelor of Arts from the University of Calgary, a Bachelor of Law from the University of Alberta
Heather Jones
Director, Finance
 Accountable for the Finance requirements of SemCAMS
 Joined SemCAMS in 2010 with over 20 years of experience with Murphy Oil where she served in capacities of
Internal Audit, Assistant Controller and Controller
 Bachelor of Commerce from the University of Calgary and is a designated Chartered Accountant with the Institute
of Chartered Accountants of Alberta, which she obtained while working with KPMG LLP

25. Sweet Vs. Sour Gas Processing
25
Sweet Gas Processing Sour Gas Processing
Inlet Separation & Compression
- Free Liquid and Solid Removal
Material Selection can vary Material Selection can vary
Emergency Pressure Relief Can be to atmosphere Must be direct to flare
Routine Venting of Gas Over 0.018 mmcf/d to flare All venting to flare
H2S Removal None Required Requires Process – Amine is typical
CO2 Removal Maybe Required – Amine is typical Maybe Required – Amine is typical
H2S/CO2 (Acid Gas) Handling
If CO2 is removed it needs to be vented
or disposed (typically via underground
injection)
Acid Gas needs to be handled through:
CO2 – Vented or Underground Injection
H2S – Conversion to Sulfur (SRU),
Underground Injection (AGI) or Flared
(typically in low volumes of < 1
tonne/day)
Water Dewpoint Conditioning
Maybe Required – Same as Sour -
Glycol or Mole Sieve are typical
Maybe Required – Same as Sweet -
Glycol or Mole Sieve are typical
Hydrocarbon Dewpoint
Conditioning
Maybe Required – Same as Sour -
Refrigeration, Turbo Expander, Joule
Thompson are typical
Maybe Required – Same as Sweet -
Refrigeration, Turbo Expander, Joule
Thompson are typical
Sales Compression Same as Sour Same as Sweet
Water Handling
Stored in tanks that can be open to
atmosphere and either treated or
disposed
Stored in tanks that are not open to
atmosphere and either treated or
disposed
NGL/Condensate Handling Same as Sour Same as Sweet
LPG Handling Same as Sour Same as Sweet
Regulatory / Permitting Minimal barriers to entry of new plants
New sour processing plants must
consider existing sulfur processing in
order to minimize proliferation of sour
plants
Costs
Capital costs approximately $1MM /
mmcf/d throughput
Capital costs range from $1.5MM /
mmcf/d to $2.5MM / mmcf/d throughput
▶ Ability to process sour gas safely is a
barrier to new market entrants
▶ SemCAMS is the largest licensed
sour gas (gas containing significant
amounts of H2S) processors in
Alberta
▶ H2S is toxic and must be processed
through a specialized method
▶ H2S can have a detrimental effect on
the integrity of processing equipment,
pipelines etc., if mishandled
▶ Due to the specialized handling
required of sour gas, numerous
regulatory precautions are applied to
our facilities(1)
▶ SemCAMS has been safely
processing sour gas for over 45 years
with a top quartile safety performance
when compared to industry
benchmarks
1) Source: National Energy Board (“NEB”), Alberta Boilers Safety Association (“ABSA”), Energy Resources Convention Board
(“ERCB”), Department of Fisheries and Oceans (“DFO”), Alberta Environment (“AENV”), Work Health and Safety (“WH&S”)

26. 26
Legend
Sour Gas Processing
Gas
Water
Condensate
Acid Gas
NGLs

27. SemGroup Consolidated Balance Sheets
(in thousands, unaudited, condensed)
June 30,
2018
December 31,
2017
ASSETS
Current assets $ 695,864 $ 902,899
Property, plant and equipment, net 3,415,505 3,315,131
Goodwill and other intangible assets 639,142 655,945
Equity method investments 276,120 285,281
Other noncurrent assets, net 145,044 132,600
Noncurrent assets held for sale — 84,961
Total assets $ 5,171,675 $ 5,376,817
LIABILITIES, PREFERRED STOCK AND OWNERS' EQUITY
Current liabilities:
Current portion of long-term debt $ 6,000 $ 5,525
Other current liabilities 608,196 761,036
Total current liabilities 614,196 766,561
Long-term debt, excluding current portion 2,534,894 2,853,095
Other noncurrent liabilities 90,937 85,080
Noncurrent liabilities held for sale — 13,716
Total liabilities 3,240,027 3,718,452
Preferred stock 347,130 —
Owners' equity 1,584,518 1,658,365
Total liabilities, preferred stock and owners' equity $ 5,171,675 $ 5,376,817
27

28. 28
SemGroup Consolidated Statements of Operations and Comprehensive Income
(Loss)
(in thousands, except per share amounts, unaudited, condensed) 2018 2017
Q1 Q2 YTD Q1 Q2 Q3 Q4 FY2017
Revenues $ 661,609 $ 595,794 $ 1,257,403 $ 456,100 $ 473,089 $ 545,922 $ 606,806 $ 2,081,917
Expenses:
Costs of products sold, exclusive of depreciation and
amortization shown below 496,132 412,089 908,221 348,998 340,107 398,252 427,534 1,514,891
Operating 69,791 90,245 160,036 52,083 73,346 62,666 66,669 254,764
General and administrative 26,477 22,886 49,363 21,712 26,819 38,389 26,859 113,779
Depreciation and amortization 50,536 51,755 102,291 24,599 25,602 50,135 58,085 158,421
Loss (gain) on disposal or impairment, net (3,566) 1,824 (1,742) 2,410 (234) 41,625 (30,468) 13,333
Total expenses 639,370 578,799 1,218,169 449,802 465,640 591,067 548,679 2,055,188
Earnings from equity method investments 12,614 14,351 26,965 17,091 17,753 17,367 15,120 67,331
Operating income (loss) 34,853 31,346 66,199 23,389 25,202 (27,778) 73,247 94,060
Other expenses, net 44,805 37,685 82,490 33,571 11,966 28,574 39,487 113,598
Income (loss) from continuing operations before income taxes (9,952) (6,339) (16,291) (10,182) 13,236 (56,352) 33,760 (19,538)
Income tax expense (benefit) 23,083 (3,613) 19,470 95 3,625 (37,249) 31,141 (2,388)
Net income (loss) (33,035) (2,726) (35,761) (10,277) 9,611 (19,103) 2,619 (17,150)
Less: cumulative preferred stock dividends 4,832 6,211 11,043 — — — — —
Net income (loss) attributable to common shareholders $ (37,867) $ (8,937) $ (46,804) $ (10,277) $ 9,611 $ (19,103) $ 2,619 $ (17,150)
Net income (loss) $ (33,035) $ (2,726) $ (35,761) $ (10,277) $ 9,611 $ (19,103) $ 2,619 $ (17,150)
Other comprehensive income (loss), net of income taxes 18,171 6,180 24,351 6,033 8,952 9,230 (4,102) 20,113
Comprehensive income (loss) $ (14,864) $ 3,454 $ (11,410) $ (4,244) $ 18,563 $ (9,873) $ (1,483) $ 2,963
Net income (loss) per common share:
Basic $ (0.48) $ (0.11) $ (0.60) $ (0.16) $ 0.15 $ (0.25) $ 0.03 $ (0.24)
Diluted $ (0.48) $ (0.11) $ (0.60) $ (0.16) $ 0.15 $ (0.25) $ 0.03 $ (0.24)
Weighted average shares (thousands):
Basic 78,198 78,319 78,259 65,692 65,749 75,974 78,189 71,418
Diluted 78,198 78,319 78,259 65,692 66,277 75,974 78,749 71,418

29. 29
SemGroup Non-GAAP Adjusted EBITDA Calculation
(in thousands, unaudited) 2018 2017
Reconciliation of net income to Adjusted EBITDA: Q1 Q2 YTD Q1 Q2 Q3 Q4 FY2017
Net income (loss) $ (33,035) $ (2,726) $ (35,761) $ (10,277) $ 9,611 $ (19,103) $ 2,619 $ (17,150)
Add: Interest expense 42,461 35,904 78,365 13,867 13,477 32,711 42,954 103,009
Add: Income tax expense (benefit) 23,083 (3,613) 19,470 95 3,625 (37,249) 31,141 (2,388)
Add: Depreciation and amortization expense 50,536 51,755 102,291 24,599 25,602 50,135 58,085 158,421
EBITDA 83,045 81,320 164,365 28,284 52,315 26,494 134,799 241,892
Selected Non-Cash Items and
Other Items Impacting Comparability 10,326 17,690 28,016 32,383 13,095 64,239 (23,306) 86,411
Adjusted EBITDA $ 93,371 $ 99,010 $ 192,381 $ 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 $ (1,742) $ 2,410 $ (234) $ 41,625 $ (30,468) $ 13,333
Foreign currency transaction loss (gain) 3,294 2,314 5,608 — (1,011) (747) (2,951) (4,709)
Adjustments to reflect equity earnings on an EBITDA basis 4,883 4,886 9,769 6,709 6,692 6,678 6,811 26,890
M&A transaction related costs 1,156 648 1,804 — 5,453 14,886 1,649 21,988
Pension plan curtailment loss (gain) — — — — — (3,097) 89 (3,008)
Employee severance and relocation expense 137 211 348 558 312 104 720 1,694
Unrealized loss (gain) on derivative activities 2,226 4,409 6,635 27 (928) 1,833 (892) 40
Non-cash equity compensation 2,196 3,398 5,594 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 $ 28,016 $ 32,383 $ 13,095 $ 64,239 $ (23,306) $ 86,411

30. SemGroup Non-GAAP Adjusted EBITDA Calculation
(in thousands, unaudited) FY2016 FY2015 FY2014
Reconciliation of net income to Adjusted EBITDA:
Net income $ 13,262 $ 42,812 $ 52,057
Add: Interest expense 62,650 69,675 49,044
Add: Income tax expense 11,268 33,530 46,513
Add: Depreciation and amortization expense 98,804 100,882 98,397
EBITDA 185,984 246,899 246,011
Selected Non-Cash Items and
Other Items Impacting Comparability 96,811 58,383 41,430
Adjusted EBITDA $ 282,795 $ 305,282 $ 287,441
Selected Non-Cash Items and
Other Items Impacting Comparability
Loss on disposal or impairment, net $ 16,048 $ 11,472 $ 32,592
Loss from discontinued operations, net of income taxes 1 4 1
Foreign currency transaction loss (gain) 4,759 (1,067) (86)
Adjustments to reflect equity earnings on an EBITDA basis 28,757 32,965 11,033
Remove loss (gain) on sale or impairment of NGL units 30,644 (14,517) (34,211)
M&A transaction related costs 3,269 10,000 —
Inventory valuation adjustments including equity method investees — 3,187 7,781
Employee severance and relocation expense 2,128 90 220
Unrealized loss (gain) on derivative activities 989 2,014 (1,734)
Change in fair value of warrants — — 13,423
Bankruptcy related expenses — 224 1,310
Charitable contributions — — 3,379
Legal settlement expense — 3,394 —
Recovery of receivables written off at emergence — — (664)
Non-cash equity compensation 10,216 10,617 8,386
Selected Non-Cash items and
Other Items Impacting Comparability $ 96,811 $ 58,383 $ 41,430
30

31. SemCAMS Non-GAAP Financial Data Reconciliations
31