The slide presentation used at the Analyst Day presetation at the Ritz-Carlton in Dallas. The slides contain information about the Mariner East 1 & 2 pipelines and Sunoco's estimates of when those projects will be operational.

1. Sunoco Logistics Partners L.P.
NYSE
SXL Analyst Day
November 2014

2. Forward-Looking Statements
Statements we make that are not historical facts are forward-looking statements.
These forward-looking statements are not guarantees of future performance.
Although we believe the assumptions underlying these statements are reasonable,
investors are cautioned that such forward-looking statements involve risks and
uncertainties that may affect our business and cause actual results to differ materially
from those discussed in this presentation. Such risks and uncertainties include
economic, business, competitive and/or regulatory factors affecting our business, as
well as uncertainties related to the outcomes of any pending or future litigation.
Sunoco Logistics Partners L.P. has included in its Annual Report on Form 10-K for the
year ended December 31, 2013 cautionary language identifying important risk factors
(though not necessarily all such factors) that could cause future outcomes to differ
materially from those set forth in the forward-looking statements. For more
information about these risk factors, see our SEC filings, available on our website at
www.sunocologistics.com. We expressly disclaim any obligation to update or alter
these forward-looking statements, whether as a result of new information, future
events or otherwise.
This presentation includes certain non-GAAP financial measures intended to
supplement, not substitute for, comparable GAAP measures. Reconciliations of non-
GAAP financial measures to GAAP financial measures are provided in the appendix
to this presentation. You should consider carefully the comparable GAAP measures
and the reconciliations to those measures provided in this presentation. 2

3. Agenda
 Sunoco Logistics Overview p. 4
 Crude Market Summary p. 15
 Crude Projects p. 22
 Refined Products Projects p. 25
 NGL Market Summary p. 27
 NGL Projects p. 30
Mariner East 2
PDH Overview
 Summary p. 48
 Appendix p. 52

4. Sunoco Logistics Overview

5. Sunoco Logistics Assets
5

6. Sunoco Logistics and Energy Transfer Assets
6

7. Energy Transfer Family of Companies
ENERGY TRANSFER EQUITY, L.P.
LP Interest, GP Interest, IDRs, Class H Units(1) LP Interest, GP Interest, IDRs
LP Interest, GP Interest, IDRs
Gathering and
Processing
Contract
Compression
& Treating
Lone Star
NGL
70% ETP Interest 30% RGP Interest
(1) Class H Units track 50% of the SXL GP and IDR economics
(2) Previously called Susser Petroleum Partners ("Susser") and traded under the ticker symbol SUSP on NYSE
7
SUNOCO LP(2)
(NYSE: SUN)
Crude Oil
Pipelines
Crude Oil
Acquisition &
Marketing
Terminal
Facilities
NGL / Refined
Product
Pipelines
(NYSE: ETE)
ENERGY TRANSFER
PARTNERS, L.P.
(NYSE: ETP)
REGENCY ENERGY
PARTNERS LP
SUNOCO LOGISTICS (NYSE: RGP)
PARTNERS L.P.
Intrastate (NYSE: SXL)
Transportation
and Storage
Interstate
Transportation
and Storage
Midstream
Sunoco, Inc.
Retail
Marketing
NGL
Transportation
and Services
Retail
Operations
Joint
Ventures
LP Interest, GP Interest, IDRs

8. Recent Highlights
 3Q14 Results:
– EBITDA $246MM… 2nd biggest quarter ever
– 10th consecutive 5% quarter-over-quarter distribution increase
 2 Additional Successful Open Seasons:
– Mariner East 2
– Permian Longview & Louisiana Extension
 September 2014 YTD Organic Growth Capital of $1.8B:
– Updated guidance for 2014 at ~$2.5B
– New guidance for 2015 at ~$2B… on committed projects only
8

9. EBITDA by Segment
($MM)
9
2010 2011 2012 2013 LTM*
Crude Oil Pipeline 1 56 207 275 349 394
Crude Oil Acq. & Mktg. 3 9 148 239 233 164
Terminal Facilities 1 27 149 225 233 306
Products Pipeline 7 7 69 71 56 80
Total EBITDA 3 99 573 810 871 944
*LTM = last twelve months ended September 30, 2014

10. Adjusted EBITDA: Ratable and Market Related
 Maximize asset base by
taking advantage of
market opportunities
 Distributions based on
ratable cash
 Market related cash flow
increases coverage ratio
10
1,200
1,000
800
600
400
200
-
2010 2011 2012 2013 LTM*
Adjusted EBITDA ($MM)
Ratable Market Related
399
573
810
871
944
*LTM = last twelve months ended September 30, 2014

11. 10 Consecutive Quarters of 5% Distribution Growth
 Guidance ~5% quarter over quarter increases in 2014
Note: Values adjusted for the two-for-one unit split completed on June 12, 2014 11

12. Major Organic Projects
 13 Successful Open Seasons:
3 West Texas Crude expansion projects (crude oil)
Permian Express 1 (crude oil)
Permian Express 2 (crude oil)
Eaglebine Express (crude oil)
Granite Wash Extension (crude oil)
Permian Longview & Louisiana Extension (crude oil)
Allegheny Access (refined products)
Mariner West (natural gas liquids)
Mariner East 1 (natural gas liquids)
Mariner East 2 (natural gas liquids)
Mariner South (natural gas liquids)
 Actively developing:
Delaware Basin Extension (crude oil)
12

13. Organic Capital
13
2,500
2,000
1,500
1,000
500
0
2010 2011 2012 2013 2014P 2015P
Investment ($MM)
Organic Expansion Capital

14. Acquisitions
600
500
400
300
200
100
0
2010 2011 2012 2013 2014*
Investment ($MM)
Acquisition Capital
*SXL does not comment on future acquisitions
*Includes the acquisition of an additional 3.9% interest in Explorer Pipeline for $42MM 14

15. Crude Market Summary

16. Dated Brent Daily Price 2008 - Present
$/bbl
$160
$140
$120
$100
$80
$60
$40
$20
16

17. World Non-OPEC Liquids Supply Growth
Change Year-Over-Year
17
Source: PIRA

18. Top 20 Crude Producers – November 2014 (MMBPD)
OPEC
Non-OPEC
18
Source: PIRA

19. Shale is the Lowest Cost Barrel Today
Source: PIRA
19
Approximate $/BBL Breakeven Price
$100
$80
$60
$40
Oil Sands Offshore Deepwater Shale
2010 2015

20. WTI Oil Breakeven by Basin
$32
$46
$53
$62 $66
$72 $73
$/BBL
$100
$75
$50
$25
$0
Source: Credit Suisse
20

21. Permian Basin Output
*** About 200 MBPD growth projected in 2014
*** Actual Growth now estimated at over 300 MBPD
Source: PIRA 21

22. Crude Projects

23. Crude Projects: 8 Successful Open Seasons (1 in progress)
Granite Wash Extension
Granite Wash Crude to multiple markets
4Q 2014
Permian Express 1
Permian Crude to Nederland
2Q 2013
3 West Texas Crude Expansions
Permian Crude to multiple markets
2012 - 2014
Delaware Basin Extension
Delaware Basin Crude to Midland
Committed Fee-based Income
1H 2016*
Permian LV & LA Extension
Permian Crude to multiple markets
Mid-2016*
Eaglebine Express
Eaglebine / Woodbine Crude to Nederland
4Q 2014
Permian Express 2
Permian Crude to multiple markets
Mid-2015*
*Expected Start-up 23

24. Nederland Terminal
24

25. Refined Products Projects

26. Allegheny Access – Refined Products
Allegheny Access
Ohio Products to Pittsburgh
4Q 2014*
26
Committed Fee-based Income
*Expected Start-up

27. NGL Market Summary

28. Top 20 NGL Producers – 2014 (MMBPD)
OPEC
Non-OPEC
Source: PIRA
28

29. 1,400,000
1,200,000
1,000,000
BPD
Marcellus / Utica NGL Forecast
800,000
600,000
400,000
200,000
-
Over 800 MBPD liquids by 2016
2012 2013 2014 2015 2016 2017 2018 2019 2020
Source: Dominion, SXL
Propane Normal Butane Isobutane
Nat Gasoline Must-Recover Ethane Discretionary Ethane
29

30. NGL Projects

31. Mariner Franchise
Mariner West
Ethane from Houston to Sarnia
4Q 2013
Mariner South
Propane / Butane from Mont Belvieu to Nederland
End of 2014*
Mariner East 1
Ethane / Propane from Houston to Marcus Hook
4Q 2014*
Mariner East 2
NGLs from Shales to Marcus Hook
4Q 2016*
Committed Fee-based Income
*Expected Start-up 31

32. Mariner South – Natural Gas Liquids
32
Lone Star
Fractionators
Committed Fee-based Income
SXL
Terminal
Mariner South
Propane / Butane from Mont Belvieu to Nederland
End of 2014*
*Expected Start-up

33. Mariner South at Nederland Terminal
33

34. Nederland Terminal
34

35. Mariner West and East – Natural Gas Liquids
Mariner West
Ethane from Houston to Sarnia
4Q 2013
Mariner East 1
E/P from Houston to Marcus Hook
End of year 2014*
35
Mariner East 2
NGLs to Marcus Hook
4Q 2016*
Committed Fee-based Income
*Expected Start-up

36. Mariner East 2

37. Mariner East
37
Connecting to 4 Fractionator
Origin Locations in the Basin
275,000 B/D Initial Capacity
345,000 B/D including ME 1
World-Class NGL Facility at
Marcus Hook Industrial Complex
37

38. Marcus Hook Industrial Complex
Mariner
Infrastructure
38

39. Marcus Hook Terminal Build-Out
39

40. Marcus Hook – Natural Gas Liquids
40

41. Marcus Hook – Natural Gas Liquids
41

42. PDH at Marcus Hook
In Development

43. Global Propylene Supply and Demand
- Global Propylene market is
expected to grow by 33MM
Metric Tons by 2020
- Lighter feed to crackers
- PDH is a preferred choice
43

44. Propylene Supply and Demand
44

45. Why PDH in Marcus Hook?
 Perfect location for local demand
Better logistics
 Perfect location for propylene export to North West Europe
Advantaged shipping and logistics costs
Delivered cash cost competitive with international markets
 Perfect location for Petrochemical Project
Existing infrastructure, Lower CAPEX, Optimized schedule
Plenty of dock capacity, uncrowded ship channel
Government support for MHIC industrial redevelopment
ME 2 assures long term, reliable propane supply
45

46. Propylene – Propane Spread 2000 – 2014
$/mt
Source: IHS Global
46

47. Marcus Hook Industrial Complex
Mariner
Infrastructure
PROPOSED
PDH
47

48. Summary

49. Key SXL Takeaways – Recent History
49
 Strategic Focus on Crude and Natural Gas Liquids
 First Mover…
 First West Texas crude projects on line since the shale boom
 First Marcellus ethane pipeline on line
 First waterborne propane exports from the Northeast
 First waterborne ethane export project (Mid-2015 with ME1)
 Robust Organic Program
 13 Successful Open Seasons since 2011
 ~ $ 2.5 B Organic Capital Plan in 2014 (~ $ 4 B last 4 years)
 ~ $ 1 B in M&A over last five years
 Commitment to Rewarding our Owners
 10 consecutive quarters of 5 % distribution growth
 5 year unit price growth over 400 %

50. Scheduled Project Start-up
50

51. Key SXL Takeaways – Going Forward
51
 Commitment to Growth
 14th Open Season in progress
 New phase of growth in processing at Marcus Hook
 Opportunities within the Energy Transfer family
 M&A - Actively looking for right, strategic opportunities
 Commitment to Rewarding our Owners
 Competitive, sustainable distribution growth
 Commitment to Investment Grade credit rating
 Excellent balance sheet
• Long-term target of 3.5x to 4.0x Debt to Adjusted EBITDA
 Balance Debt and Equity issuance to maintain rating
• $1.5B revolver for liquidity

52. Appendix

53. SXL Non-GAAP Financial Measures
2010 2011 2012 2013 LTM*
348 322 531 474 530
($MM)
Interest expense, net 73 89 79 77 70
Depreciation and amortization expense 64 86 139 265 289
Impairment charge 3 31 9 - -
Provision for income taxes 8 25 32 30 28
Non-cash compensation expense 5 6 8 14 16
Unrealized losses / (gains) on commodity risk management activities 2 (2) 3 (1) (3)
Proportionate share of unconsolidated affiliates' interest, depreciation
and provision for income taxes 24 16 21 20 21
Adjustments to commodity hedges resulting from "push-down" accounting - - (12) - -
Amortization of excess joint venture investment - - - 2 3
Non-cash accrued liability adjustment - - - (10) ( 10)
Gain on investments in affiliates (128) - - - -
Adjusted EBITDA(1) 399 573 810 871 944
Interest expense, net (73) (89) (79) (77) ( 70)
Provision for income taxes(2) (8) (27) (34) (24) ( 31)
Amortization of fair value adjustments on long-term debt - - (6) (23) ( 17)
Distributions versus Adjusted EBITDA of unconsolidated affiliates (36) (17) (28) (27) ( 32)
Maintenance capital expenditures (37) (42) (50) (53) ( 63)
Distributable Cash Flow attributable to noncontrolling interests (3) (10) (11) (16) ( 13)
Acquisition costs reimbursement - - - 9 12
Distributable Cash Flow (DCF)(1) 242 388 602 660 730
(1)
(2)
Twelve Months Ended December 31,
Net Income
Management of the Partnership believes Adjusted EBITDA and distributable cash flow information enhances an investor's understanding of a
business’s ability to generate cash for payment of distributions and other purposes. Adjusted EBITDA and Distributable Cash Flow do not represent
and should not be considered alternatives to net income or cash flows from operating activities as determined under United States generally accepted
accounting principles (GAAP) and may not be comparable to other similarly titled measures of other businesses. Historical amounts presented have
been recast to conform to current period.
During the third quarter 2014, we changed our definition of distributable cash flow to conform to the presentation utilized by Energy Transfer Partners,
L.P., the controlling member of our general partner. This change did not have a material impact on our distributable cash flows. Prior period amounts
have been recast to conform to current presentation.
*LTM = Last Twelve Months, period ended September 30, 2014 53

54. 2010 2011 2012 2013 LTM*
Historical Financial Results
($MM)
Crude Oil Pipelines 156 2 07 275 3 49 394
Crude Oil Acquisition & Marketing 39 148 239 2 33 164
Terminal Facilities 127 1 49 225 2 33 306
Refined Products Pipelines 77 69 71 56 80
Total Adjusted EBITDA 399 5 73 810 8 71 944
Interest expense, net ( 73) (89) (79) (77) (70)
Provision for income taxes(1) ( 8) (27) (34) (24) (31)
Maintenance Capital Expenditures ( 37) (42) (50) (53) (63)
Amortization of fair value adjustment on long-term debt - - ( 6) (23) (17)
Distributions versus adjusted EBITDA of unconsolidated affiliates ( 36) (17) (28) (27) (32)
Distributable cash flow attributable to noncontrolling interests ( 3) (10) (11) (16) (13)
Acquisition costs reimbursement - - - 9 12
Distributable Cash Flow (DCF) 242 3 88 602 6 60 730
Expansion Capital(2) 1 46 1 71 324 9 65 2,207
Total Distribution (accrual basis) 1 93 2 14 277 3 78 468
Distribution Coverage Ratio 1.3x 1.8x 2.2x 1.7x 1.6x
(1) During the third quarter 2014, we changed our definition of distributable cash flow to conform to the presentation utilized by Energy Transfer Partners, L.P., the controlling
54
member of our general partner. This change did not have a material impact on our distributable cash flows. Prior period amounts have been recast to conform to current
presentation.
(2) Excludes major acquisitions
*LTM = Last Twelve Months, period ended September 30, 2014

55. Consolidated JV's:
West Texas Gulf
Mid-Valley Inland
SXL 60.3% SXL 91.0% SXL 83.8%
Chevron 28.3% Chevron 9.0% Citgo 16.2%
Citgo 11.4%
Equity Interest JV's:
Explorer* West Shore Wolverine**
Shell 36.0% Buckeye 34.6% ExxonMobil 53.4% Phillips 66 46.0%
Marathon 24.5% Shell 18.9% SXL 31.5% ExxonMobil 40.0%
Phillips 66 19.4% Citgo 18.4% Citgo 9.5% SXL 14.0%
SXL 13.3% SXL 17.1% Marathon 5.6%
American Capital Group 6.8% ExxonMobil 11.0%
SXL 50%
Vitol 50%
Undivided Interest JV's:
Harbor
SXL 66.7% Plains 63.0%
Phillips 66 33.3% SXL 37.0%
Yellowstone
Mesa
SunVit
Joint Venture Ownership
Bold - denotes operator
* Operated by Explorer’s employees
** Operated by Wolverine’s employees
55

56. Crude Oil Pipeline System
 42% of total EBITDA for the twelve months ended September 30, 2014
 Approximately 5,300 miles of crude oil trunk lines located in the Southwest and
Midwest U.S.
Approximately 500 miles of gathering lines
 60.3% controlling interest in West Texas Gulf Pipeline, approximately 600-mile
crude oil pipeline
 91.0% controlling interest in Mid-Valley Pipeline, approximately 1,000-mile
crude oil pipeline
56

57. Crude Oil Acquisition and Marketing
 17% of total EBITDA for the twelve months ended September 30, 2014
 Crude truck fleet of over 300 trucks
 Purchase crude oil at the wellhead from producers and in bulk from aggregators
at major pipeline interconnections and trading locations
 Buying and selling crude oil of different grades, at different locations in order to
maximize value
 Marketing crude oil to major integrated oil companies, independent refiners and
resellers through various types of sale and exchange transactions
 Wellhead volumes of approximately 400,000 barrels per day from approximately
3,000 producers who operate approximately 60 thousand active leases
 Storing inventory during contango market conditions – maintain balanced book
to mitigate commodity risk
 Transporting crude oil on our pipelines and trucks or when necessary or cost
effective, pipelines or trucks owned and operated by third parties
57

58. Terminal Facilities
 32% of total EBITDA for the twelve months ended September 30, 2014
 Nederland, TX Crude Oil Terminal - One of the largest onshore crude facilities in U.S.
22 million barrel capacity currently
 Eagle Point, NJ Crude Oil and Refined Products Terminal
5 million barrel capacity for crude oil and refined product storage
Pipeline and rail connections with import/export capabilities
 Marcus Hook Industrial Complex
Pipeline, rail and trucking connections with import/export capabilities
5 million barrel capacity for refined product and NGL storage
• Includes five underground NGL storage caverns
 Refinery Terminal Facilities with combined 5 million barrel capacity
Serve Philadelphia area refineries
 39 active Refined Products Marketing Terminals located in 11 states with a combined
capacity of 8 million barrels
 Inkster, MI LPG Terminal with a capacity of approximately 1 million barrels
 Total terminal capacity of approximately 46 million barrels
 Patented technology to blend butane into gasoline
58

59. Refined Products Pipeline System
 9% of total EBITDA for the twelve months ended September 30, 2014
 Refined products pipeline system (approximately 2,300 miles), located in the
Northeast, Midwest and Southwest U.S.
 Equity interest in four product pipelines
Explorer (13.3%)
West Shore (17.1%)
Wolverine (31.5%)
Yellowstone (14.0%)
 83.8% controlling interest in Inland Pipeline, an approximately 350-mile refined
products pipeline system
59

60. Distribution History
$2.00
$1.53
$1.50
$1.00
$0.50
$0.00
2009 2010 2011 2012 2013 CAD*
Average Annual
Distribution
(per LP unit)
 10 consecutive
quarter over quarter
distribution increases
of 5%
 38 consecutive
quarterly distribution
increases
 Current annualized
distribution of $1.53
Distribution
Coverage 1.5x 1.3x 1.8x 2.2x 1.7x
LP/GP
Split (%)
50/50
63/37
85/15
98/2
60
$1.06
$0.38
$0.33
*CAD: Current Annualized Distribution @ $1.53 per LP Unit
Note: Values adjusted for the two-for-one unit split completed on June 12, 2014

61. $1.5 Billion Revolving Credit Facility
($MM)
61
$100MM Lenders $40.5MM Lenders
Citibank(1) $100.0 Bank of Nova Scotia $40.5
Barclays Bank 100.0 BNP Paribas 40.5
Bank of Tokyo-Mitsubishi UFJ 100.0 Comerica Bank 40.5
PNC Bank(2) 100.0 Deutsche Bank 40.5
TD Bank 100.0 DNB Capital 40.5
Wells Fargo Bank 100.0 Goldman Sachs Bank 40.5
Subtotal $600.0 Morgan Stanley Senior Funding 40.5
SunTrust Bank 40.5
Subtotal $324.0
$64MM Lenders
Bank of America $64.0
Compass Bank 64.0
Credit Suisse 64.0
JPMorgan Chase Bank 64.0
Mizuho Bank 64.0
Royal Bank of Canada 64.0 Lender
Royal Bank of Scotland 64.0 $100.0MM Lenders Total $600.0
UBS 64.0 $64.0MM Lenders Total 576.0
US Bank 64.0 $40.5MM Lenders Total 324.0
Subtotal $576.0 Total $1,500.0
(1) Citibank is the administrative agent for the $1.5 billion revolver
(2) PNC Bank is administrative agent and sole lender on a separate $35MM West Texas Gulf revolver
$1.5B Facility
Allocation
Facility
Allocation
Facility
Allocation
Facility
Allocation

62. Debt to Adjusted EBITDA
($MM) December 31,
2009 2010 2011 2012 2013
Debt to Adjusted EBITDA Ratio
Total Debt 868 1,229 1,698 1,732 2,503
Less: Unamortized FV adjustments, net(1) - - - 143 120
868 1,229 1,698 1,589 2,383
Adjusted EBITDA (trailing 12 months) 372 399 573 810 871
Debt to Adjusted EBITDA Ratio 2.3x 3.1x 3.0x 2.0x 2.7x
(1) In accordance with purchase accounting guidance, the Partnership's Senior Notes were adjusted to fair value (“FV”)
upon the closing of Energy Transfer's acquisition of the Partnership's general partner in October 2012.
62

63. Capitalization
($MM) As of 9/30/14
Debt
Senior Notes, net 2 ,975 fixed
Unamortized fair value adjustments, net(1) 105
$1.5 B SXL Revolver (matures November 2018)(2) 5 25 floating
$35 MM WTG Revolver (matures April 2015) 3 5 floating
Total Debt(1) 3,640
Equity
Limited Partners 5,966
General Partner 9 28
Total Partners’ Capital 6,894
Non-Controlling Interest 124
Total Equity 7,018
Rating: BBB / Baa3 / BBB (S&P, Moody’s, Fitch), stable outlook
(1) In accordance with purchase accounting, the Partnership's Senior Notes were accounted for at fair value upon the closing of Energy
Transfer's acquisition of the Partnership's general partner. At 09/30/2014, there was $105 MM of net unamortized fair value adjustments.
(2) New $1.5 billion revolver closed in November 2013, replaced the existing SXL revolvers.
63

64. Debt Maturity Schedule at 9/30/2014
($MM)
6.13% 5.50% 4.65% 3.45% 4.25% 6.85% 6.10% 4.95% 5.30%
Note: Excludes borrowings under the revolvers
64

65. Acquisition History ($1.5B Since IPO)
November 2002  Joint-venture interests in 3 refined product pipelines from Unocal, for $54MM
Wolverine (31.5%), West Shore (9.2%), and Yellowstone (14.0%)
November 2002  43.8% joint-venture interest from Sunoco/Unocal in West Texas Gulf crude pipeline for $11MM
September 2003  Additional joint-venture interest in West Shore for $4MM increasing ownership
interest from 9.2% to 12.3%
March 2004  Logistics assets of Eagle Point refinery from Sunoco, Inc. for $20MM
April 2004  Baltimore, MD and Manassas, VA refined product terminal facilities from ConocoPhillips for $12MM
June 2004  Additional 1/3rd joint-venture interest in Harbor Pipeline from El Paso for $7MM, increasing ownership
interest to 2/3rds
November 2004  Columbus, OH refined product terminal facilities from Certified Oil for $8MM
August 2005  Texas crude oil pipeline system from ExxonMobil for $100MM
December 2005
March 2006
 37% joint-venture interest in Mesa crude oil pipeline system from Sunoco/Chevron for $7MM
 Texas crude oil pipeline system from Black Hills for $41MM
 Texas crude oil pipeline system from Alon for $68MM
August 2006
June 2007
November 2008
 55.3% joint-venture interest in Mid-Valley crude oil pipeline from Sunoco, Inc. for $65MM
 50% joint-venture interest in a refined products terminal in Syracuse, NY from ExxonMobil for $13MM
Texas refined products pipeline system and terminal facilities from ExxonMobil for $186MM
65

66. Acquisition History ($1.5B Since IPO), Continued
September 2009  Oklahoma crude oil pipeline from Excel Pipeline LLC and Romulus, MI refined products terminal facility
from R.K.A. Petroleum LLC for an aggregate $50MM
July 2010  Butane blending business from Texon L.P. for $152MM including inventory
 Additional joint-venture interest in West Shore from BP for $7MM increasing ownership
interest from 12.3% to 17.1%
 Additional joint-venture interest in Mid-Valley from BP for $58MM increasing ownership
interest from 55.3% to 91.0%
August 2010  Additional joint-venture interest in West Texas Gulf from BP for $27MM increasing ownership
interest from 43.8% to 60.3%
May 2011  83.8% controlling joint-venture interest in Inland refined products pipeline for $99MM
July 2011  Eagle Point Tank Farm from Sunoco, Inc. for $100MM in deferred distribution units
August 2011  Crude Oil Acquisition and Marketing business from Texon L.P. for $222MM including inventory
 East Boston products terminal and pipeline from ConocoPhillips for $73MM including inventory
April 2013
March 2014
May 2014
 Marcus Hook Industrial Complex from Sunoco, Inc. for $60MM
 Additional joint-venture interest in Explorer Pipeline from Chevron for $42MM increasing ownership
interest from 9.4% to 13.3%
 Crude Oil Acquisition and Marketing business from EDF for $80MM including inventory
66

67. SXL Key Financial and Operating Statistics
2012 2013 2014
2010 2011
Total Total 1st 2nd 3rd 4th Total 1st 2nd 3rd 4th Total 1st 2nd 3rd Total
67
Financial highlights (in millions)
Sales and other operating revenue
Crude Oil Pipelines $ 221 $ 319 $ 80 $ 100 $ 108 $ 110 $ 398 $ 95 $ 122 $ 139 $ 139 $ 495 $ 131 $ 138 $ 1 44 $ 413
Crude Oil Acquisition and Marketing 7,282 10,163 3,192 3,056 3,010 2,888 12,146 3,259 4,047 4,244 3,968 15,518 4,094 4,432 4 ,497 13,023
Terminal Facilities 287 435 135 170 101 206 612 183 176 177 215 751 287 283 298 868
Refined Products Pipelines 120 130 3 1 32 33 35 131 3 0 32 34 34 130 4 1 40 46 127
Intersegment eliminations (102) (142) ( 37) (45) (45) (50) (177) ( 55) (66) (66) (68) (255) ( 76) (72) (70) (218)
Total sales and other operating revenue $ 7 ,808 $ 10,905 $ 3 ,401 $ 3,313 $ 3,207 $ 3,189 $ 13,110 $ 3 ,512 $ 4,311 $ 4,528 $ 4,288 $ 1 6,639 $ 4 ,477 $ 4,821 $ 4 ,915 $ 14,213
Adjusted earnings before interest, taxes, depreciation and amortization (Adjusted EBITDA)
Crude Oil Pipelines $ 156 $ 207 $ 60 $ 70 $ 73 $ 72 $ 275 $ 61 $ 88 $ 98 $ 102 $ 349 $ 93 $ 104 $ 95 $ 292
Crude Oil Acquisition and Marketing 3 9 148 4 7 57 54 81 239 112 7 0 18 33 233 1 2 53 66 131
Terminal Facilities 127 149 4 7 74 52 52 225 5 4 70 47 62 233 8 6 97 61 244
Refined Products Pipelines 7 7 69 15 17 25 14 71 9 16 18 13 56 17 26 24 67
Total Adjusted EBITDA $ 399 $ 573 $ 169 $ 218 $ 204 $ 219 $ 810 $ 236 $ 244 $ 181 $ 210 $ 871 $ 208 $ 280 $ 2 46 $ 734
Operating highlights
Crude Oil Pipelines
Pipeline throughput (thousands of barrels per day "bpd") 1,183 1,587 1,467 1,571 1,601 1,584 1,556 1,582 1,890 1,976 2,009 1,866 2,041 2,130 2 ,204 2,126
Pipeline revenue per barrel (cents) 50.7 55.0 59.6 70.0 73.6 75.6 69.9 67.0 70.8 76.3 75.2 72.7 71.6 71.2 70.8 71.2
Crude Oil Acquisition and Marketing
Crude oil purchases (thousands of bpd) 638 663 631 700 692 669 673 750 796 716 734 749 840 854 894 863
Gross profit per barrel purchased (cents) (1) 21.0 66.0 89.5 97.1 91.5 138.0 104.1 172.0 101.8 33.9 55.9 91.4 21.1 74.8 85.9 61.4
Average crude oil price (per barrel) $ 7 9.55 $ 95.14 $ 102.94 $ 9 3.50 $ 92.19 $ 88.20 $ 94.19 $ 94.34 $ 94.23 $ 105.82 $ 9 7.50 $ 98.00 $ 98.61 $ 102.98 $ 97.21 $ 99.60
Terminal Facilities (thousands of bpd)
Refined products terminals throughput 488 492 487 515 495 451 487 414 454 432 422 431 413 420 420 418
Nederland terminal throughput 729 757 697 690 721 787 724 850 932 968 977 932 1,322 1,216 1 ,262 1,266
Refinery terminals throughput 465 443 383 345 381 411 380 325 444 495 324 397 226 345 297 290
Refined Products Pipelines (2)
Pipeline throughput (thousands of bpd) 4 68 522 528 591 576 601 582 522 599 577 586 571 521 551 582 552
Pipeline revenue per barrel (cents) 7 0.0 68.3 65.1 59.5 62.2 63.0 61.6 62.9 59.1 64.3 63.9 62.5 88.3 79.4 85.5 84.4

68. SXL Key Financial and Operating Statistics
2010 2011
Total Total 1st 2nd 3rd 4th Total 1st 2nd 3rd 4th Total 1st 2nd 3rd Total
68
Reconciliation of Segment Operating Income to Net Income Attributable to Sunoco Logistics Partners L.P. (in millions)
Operating income:
Crude Oil Pipelines $ 113 $ 181 $ 52 $ 63 $ 67 $ 49 $ 231 $ 38 $ 65 $ 74 $ 80 $ 257 $ 68 $ 79 $ 68 $ 215
Crude Oil Acquisition and Marketing 3 6 137 3 4 52 48 69 203 100 5 7 5 22 184 ( 1) 39 51 89
Terminal Facilities 9 4 85 37 60 39 44 180 3 1 46 27 27 131 6 0 5 9 52 171
Refined Products Pipelines 2 8 20 4 4 - ( 3) 5 (4) (3) ( 2) (3) (12) - 3 1 4
Total segment operating income 271 423 127 179 154 159 619 165 165 104 126 560 127 180 172 479
Interest expense, net ( 73) (89) (24) (21) (20) (14) (79) (19) (17) (22) (19) ( 77) (16) (21) (14) (51)
Gain on investments in affiliates 128 - - - - - - - - - - - - - - -
Other income 3 0 13 2 5 11 5 23 2 7 7 5 21 4 7 7 18
Provision for income taxes ( 8) (25) ( 8) (8) (8) (8) (32) ( 6) (9) ( 8) (7) (30) ( 5) (8) (8) (21)
Net income 348 322 9 7 155 137 142 531 142 146 8 1 105 474 110 158 157 425
Net income attributable to noncontrolling interests ( 2) (9) (2) (3) (3) (3) (11) ( 2) (3) ( 3) (3) (11) ( 3) (2) (2) (7)
Net income attributable to Partners $ 346 $ 313 $ 95 $ 152 $ 134 $ 139 $ 520 $ 140 $ 143 $ 78 $ 102 $ 463 $ 107 $ 156 $ 1 55 $ 418
Reconciliation of Net Income to Adjusted EBITDA and Distributable Cash Flow (in millions)
Net income $ 348 $ 322 $ 97 $ 155 $ 137 $ 142 $ 531 $ 142 $ 146 $ 81 $ 105 $ 474 $ 110 $ 158 $ 1 57 $ 425
Add: Interest expense, net 7 3 89 24 21 20 14 79 19 17 22 19 77 16 2 1 14 51
Add: Depreciation and amortization expense 6 4 86 25 25 26 63 139 6 4 64 68 69 265 6 9 7 4 77 220
Add: Impairment charge 3 31 9 - - - 9 - - - - - - - - -
Add: Provision for income taxes 8 25 8 8 8 8 32 6 9 8 7 30 5 8 8 21
Add: Non-cash compensation expense 5 6 3 2 1 2 8 4 2 4 4 14 5 3 4 12
Add: Unrealized (gain)/losses on commodity risk management activities 2 (2) - 3 3 (3) 3 (3) (1) ( 8) 11 ( 1) (1) 8 (21) (14)
Add: Amortization of excess joint venture investment - - - - - - - - 1 - 1 2 - 1 1 2
Add: Proportionate share of unconsolidated affiliates interest,
depreciation and provision for income taxes 2 4 16 3 4 9 5 21 4 6 6 4 20 4 7 6 17
Less: Adjustments to commodity hedges resulting from "push-down"
accounting - - - - - (12) (12) - - - - - - - - -
Less: Non-cash accrued liability adjustment - - - - - - - - - - (10) (10) - - - -
Less: Gain on investments in affiliates (128) - - - - - - - - - - - - - - -
Adjusted EBITDA 399 573 169 218 204 219 810 236 244 181 210 871 208 280 246 734
Less: Interest expense, net ( 73) (89) (24) (21) (20) (14) (79) (19) (17) (22) (19) (77) (16) (21) (14) (51)
Less: Provision for current income taxes (3) ( 8) (27) ( 7) (9) (8) (10) (34) ( 7) (4) ( 7) (6) (24) ( 7) (9) (9) (25)
Less: Amortization of fair value adjustments on long-term debt - - - - - ( 6) (6) (6) (6) ( 5) (6) (23) ( 4) (4) (3) (11)
Less: Distributions versus Adjusted EBITDA of unconsolidated affiliates ( 36) (17) ( 3) (6) (16) ( 3) (28) ( 3) (8) (10) ( 6) (27) ( 6) (10) (10) (26)
Less: Maintenance capital expenditures ( 37) (42) ( 7) (11) (11) (21) (50) ( 4) (18) (15) (16) (53) (18) (13) (16) (47)
Less: Distributable cash flow attributable to noncontrolling interests ( 3) (10) ( 3) (3) (3) (2) (11) ( 3) (5) ( 5) (3) (16) ( 3) (4) (3) (10)
Add: Acquisition costs reimbursement - - - - - - - - 3 3 3 9 3 3 3 9
Distributable Cash Flow (3) $ 242 $ 388 $ 125 $ 168 $ 146 $ 163 $ 602 $ 194 $ 189 $ 120 $ 157 $ 660 $ 157 $ 222 $ 1 94 $ 573
(1)
(2)
(3)
2012 2013 2014
Represents total segment sales and other operating revenue minus cost of products sold and operating expenses divided by total crude purchases.
Excludes amounts attributable to equity ownership interests which are not consolidated.
During the third quarter 2014, we changed our definition of distributable cash flow to conform to the presentation utilized by Energy Transfer Partners, L.P., the controlling member of our general partner. This change did not have a material impact on our distributable cash flows.