A U G U S T 5 , 2 0 1 5

Second Quarter 2015Financial Results Conference Call

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Forward-Looking Statements

This Presentation has been prepared by Calumet Specialty Products Partners, L.P. (the “Company” or “Calumet”) as of August 5, 2015. The information in this Presentation includes certain “forward-looking statements”. These statements can be identified by the use of forward-looking terminology including “may,” “intend,” “believe,” “expect,” “anticipate,” “estimate,” “forecast,” “continue” or other similar words. The statements discussed in this Presentation that are not purely historical data are forward-looking statements. These forward-looking statements discuss future expectations or state other “forward-looking” information and involved risks and uncertainties. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements included in our most recent Annual Report on Form 10-K and Quarterly Reports on Form 10-Q. The risk factors and other factors noted in our most recent Annual Report on Form 10-K and Quarterly Reports on Form 10-Q could cause our actual results to differ materially from those contained in any forward-looking statement. Our forward-looking statements are not guarantees of future performance, and actual results and future performance may differ materially from those suggested in any forward-looking statement. All subsequent written and oral forward-looking statements attributable to us or to persons acting on our behalf are expressly qualified in their entirety by the foregoing. Existing and prospective investors are cautioned not to place undue reliance on such forward-looking statements, which speak only as of the date of this Presentation. We undertake no obligation to publicly release the results of any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date of this Presentation or to reflect the occurrence of unanticipated events. The information contained herein has been prepared to assist interested parties in making their own evaluation of the Company and does not purport to contain all of the information that an interested party may desire. In all cases, interested parties should conduct their own investigation and analysis of the Company, its assets, financial condition and prospects and of the data set forth in this Presentation. This Presentation shall not be deemed an indication of the state of affairs of the Company, or its businesses described herein, at any time after the date of this Presentation nor an indication that there has been no change in such matters since the date of this Presentation. This Presentation and any other information which you may be given at the time of presentation, in whatever form, do not constitute or form part of any offer or invitation to sell or issue, or any solicitation of any offer to purchase or subscribe for any securities of the Company, nor shall it or any part of it form the basis of, or be relied upon in connection with, any contract or commitment whatsoever. Neither this Presentation nor any information included herein should be construed as or constitute a part of a recommendation regarding the securities of the Company. Furthermore, no representation or warranty (express or implied) is made as to, and no reliance should be placed on, any information, including projections, estimates, targets and opinions contained herein, and no liability whatsoever is accepted as to any errors, omissions or misstatements contained herein. Neither the Company nor any of its officers or employees accepts any liability whatsoever arising directly or indirectly from the use of this Presentation.

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2Q15 PERFORMANCE SUMMARYBill Hatch Interim CEO

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2Q15 Performance Summary

■ Adjusted EBITDA more than doubled y/y in 2Q15. Calumet’s Adjusted EBITDA increased to $95.0 million in second-quarter 2015, versus $39.3 million in the prior-year period, driven by a combination of (1) improved operational reliability within the Partnership’s system of refineries; (2) a year over year increase in sales volumes; and (3) seasonally strong refined product margins. Broad-based strength within the specialty products and fuel products segments was partially offset by a decline in the oilfield services ("OFS") segment.

■ Significant gross profit margin expansion within Specialty and Fuel Products segments in 2Q15. Specialty products gross profit per barrel increased nearly 36% y/y in 2Q15 to $44.22 per barrel; fuel products segment gross profit per barrel increased from ($0.69) per barrel in 2Q14 to $9.29 per barrel in 2Q15.

■ Distributable Cash Flow (“DCF”) net improvement of $88 million y/y in 2Q15. Calumet generated DCF of $73.3 million in 2Q15, versus ($15.0) million in 2Q14, due primarily to a y/y increase in Adjusted EBITDA in the specialty products and fuel products segments, a decline in turnaround costs, and lower cash interest expense.

■ Distribution coverage at nearly 1.3x on a trailing-four-quarter basis through 2Q15. The distribution coverage ratio was 1.3x in 2Q15, versus (0.3)x in 2Q14. The Partnership continues to target a distribution coverage ratio of 1.2-1.5x on a normalized basis.

■ Leverage ratio approaches 4.0x on a trailing four-quarter basis through 2Q15. The Partnership’s ratio of debt-to-trailing-four-quarter Adjusted EBITDA (“Leverage Ratio") was 4.3x as of June 30, 2015, versus 7.4x as of June 30, 2014. The Partnership continues to target a Leverage Ratio at or below 4.0x.

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Capitalizing On Strong Refined Product Demand

0

50,000

100,000

150,000

0

50

100

150

INCREASED OPERATIONAL RELIABILITY HAS TRANSLATED INTO FOUR CONSECUTIVE QUARTERS OF STRONG ADJUSTED EBITDA

SIGNIFICANT Y/Y INCREASE IN SALES VOLUMES ACROSS MULTIPLE SPECIALTY AND FUEL PRODUCT MARKETS (2Q14 VS. 2Q15)

FUEL PRODUCTS PRODUCTION (BPD) SPECIALTY PRODUCTS PRODUCTION (BPD) ADJUSTED EBITDA ($MM)

16% 16%18%

23% 24%25%

Waxes Packaged & Synthetic

Gasoline Lubricating Oils

Diesel Jet Fuel

2Q14 3Q14 4Q14* 1Q15 2Q15

* Excludes special items.

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Gross Profit Per Barrel and Adjusted EBITDA by Operating Segment

SIGNIFICANT Y/Y IMPROVEMENT IN GROSS PROFIT ACROSS SPECIALTY PRODUCTS & FUEL PRODUCTS SEGMENTS ($ PER BARREL)

SIGNIFICANT INCREASE IN SPECIALTY AND FUEL PRODUCTS ADJUSTED EBITDA, PARTIALLY OFFSET BY LOWER OFS CONTRIBUTION ($MM)

2Q14

2Q14

2Q15

2Q15

0.0

2.5

5.0

7.5

10.0

12.5

15.0

17.5

20.0

($0.45)

$10.40

0.0

2.5

5.0

7.5

10.0

12.5

15.0

17.5

20.0

($0.69)

$9.29

0

10

20

30

40

50

$32.67$44.22

$34.3

$59.1

($3.1)

$50.1

0

16

32

48

64

80

$8.1

($14.2)

0

16

32

48

64

80

$39.3

$95.0

Specialty Products Fuel Products Oilfield Services Total Adjusted EBITDA

Specialty Products Segment Gross Profit Per Barrel Fuel Products Segment Gross Profit Per Barrel(Includes Hedging)

Fuel Products Segment Gross Profit Per Barrel(Excludes Hedging)

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Specialty Products Margins Benefit As Crude Oil Price Falls

AVG. SALES PRICE PER SPECIALTY PRODUCTS BARREL LAGS PRICE DECLINE IN WTI PRICE PER BARREL, RESULTING IN SPECIALTY PRODUCTS MARGIN EXPANSION

INCREASED SALES OF PACKAGED & SYNTHETIC PRODUCTS CONTRIBUTE POSITIVELY TO SPECIALTY PRODUCTS SEGMENT MARGIN EXPANSION(1)

$30

$40

$50

$60

$70

$80

$90

$100

$110

2Q14 3Q14 4Q14 1Q15 2Q15 JULY-15$0

$50

$100

$150

$200

$250

(1) Represents packaged and synthetic specialty products at the Royal Purple, Anchor, Bel-Ray, Calumet Packaging and Missouri facilities.

WTI PER BARREL ($) AVG. SALES PRICE PER SPECIALTY PRODUCTS BARREL

$79.8 mm

+22% y/y +37% y/y+55% y/y

+5% y/y+11% y/y

$82.1 mm$75.2 mm

$80.5 mm$88.4 mm

2Q14 3Q14 4Q14 1Q15 2Q15

Crude Oil Prices Declined in July 2015

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Right-Sizing Oilfield Services Segment Relative to Customer Demand

4Q14 1Q15 2Q150

500

1000

1500

2000

2500

-15

-10

-5

0

5

10

($15)

($10)

($5)

$0

$5

$10

0

500

1,000

1,500

2,000

2,500

SIGNIFICANT DECLINE IN U.S. RIG COUNT HAS IMPACTED OFS SEGMENT, ALTHOUGH MARKET HAS BEGUN TO STABILIZE

Avg.

US

Rig

Cou

nt

Seg

men

t Adj

. EB

ITD

A in

Mill

ions

OFS SEGMENT ADJ. EBITDA ($MM)AVERAGE US RIG COUNT

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Organic Growth Projects Reaching Completion

FUELS SPECIALTY

Organic Growth Projects

Completed April 2015

Est. Timing of Completion

Est. Annualized EBITDA Contribution ($MM)

Est. Mid-Point Rate of Return

DAKOTA PRAIRIE REFINERY

MISSOURI ESTERS EXPANSION

SAN ANTONIO REFINERY SOLVENTS PROJECT

MONTANA REFINERY EXPANSION

3Q15

4Q15

1Q16

$8-$12

$20

$70-$90

20%

29%

20%

ONGO

ING

COM

PLET

ED

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0.1x

0.7x

1.3x 1.3x

0.0

0.3

0.6

0.9

1.2

1.5

$55.7

$(0.9) ($1.2)

($16.0)($7.3)

$88.3

0

17

34

51

68

85

($7.2)

Reconciliation of Distributable Cash Flow – 2Q14 vs. 2Q15

Y/Y CHANGE IN DRIVERS OF DISTRIBUTABLE CASH FLOW –2Q14 VS. 2Q15 ($MM) (1)

(1) Distributable Cash Flow (“DCF”) is calculated by taking Adjusted EBITDA less replacement/environmental CAPEX, cash interest expense, loss from unconsolidated affiliates, turnaround costs and income tax expense (benefit). Replacement capital expenditures are defined as those capital expenditures which do not increase operating capacity or reduce operating costs and exclude turnaround costs. Environmental capital expenditures include asset additions to meet or exceed environmental & operating regulations. Cash interest expense represents consolidated interest expense less non-cash interest expense and excludes capitalized interest.

(2) The Distribution Coverage Ratio is a non-GAAP measure that divides the total distributable cash flow available for payment to unitholders by the actual cash distribution. A ratio of above 1.0x implies that the Partnership had sufficient DCF to “cover” its distribution.

DISTRIBUTION COVERAGE RATIO HAS INCREASED TO 1.5X ON A TRAILING FOUR-QUARTER BASIS THROUGH 2Q15 (2)

Adjusted EBITDA Rep./Env. CAPEX Cash Interest Expense Turnaround CostsIncome Tax Benefit DCF

2013 (Avg.) 2014 (Avg.) 2Q15 LTM Avg. (3Q14-2Q15)

Loss from Unconsolidated

Affiliates

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2Q15 FINANCIAL ANALYSISPatrick Murray EVP and Chief Financial Officer

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Adjusted EBITDA Bridge – 2Q14 vs. 2Q15 ($MM)

2Q14 Adj. EBITDA

Fuels Margin LCM RIN Specialty Margin

Volume OFS Adj. EBITDA

Other Hedging 2Q15 Adj. EBITDA

$39.3

$47.8

$24.7

$13.9

$10.3

$19.8

($22.3)

$95.0

($24.5)

($9.7)

($4.3)

SG&A

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Historical Fuel Products Refining Data

IMPROVED FUELS REFINING ECONOMICS DRIVEN BY STRONG GASOLINE CRACK SPREAD IN 2Q15 ($ PER BARREL)

HISTORICAL CRUDE OIL PRICE DIFFERENTIALS FOR KEY CRUDE OIL GRADES USED IN OUR REFINING SYSTEM ($ PER BARREL)

2Q14 1Q15 2Q15

Gulf Coast 2/1/1 Crack Spread (bbl)

2Q15

Eagle Ford Less WTI (bbl) Bakken Less WTI (bbl) Bow River Less WTI (bbl) WCS Less WTI (bbl) LLS Less WTI (bbl)

ULSD Crack (bbl)

1Q15

Gulf Coast Gasoline Crack (bbl)

2Q14

0

5

10

15

20

25

0

5

10

15

20

25

$19 $20 $19 $19$22

$15

$22$19

$25

$5

($1)($3)

($6)

($12)($14)

$5 $4 $3

($20)

$4$2

($9)($12)

($20)

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Cash Bridge – 3/31/15 to 6/30/15 ($MM)

$19.6

$11.7

$103.0

($275.0)

($100.1)

($57.3) ($3.2) ($2.3)

3-31-15Balance

Operating Cash Flow

Working Capital

Revolver Borrowings

Repayment of Senior Notes

Cap Ex & Acquisitions

Distributions Turnaround Other 6-30-2015 Balance

$54.2

$272.8

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Access to Liquidity Supports Business Growth

As of 12/31/14 As of 6/30/15

0.0

62.5

125.0

187.5

250.0

312.5

375.0

437.5

500.0

$9 $120.0

62.5

125.0

187.5

250.0

312.5

375.0

437.5

500.0

0.0

62.5

125.0

187.5

250.0

312.5

375.0

437.5

500.0

$311

$428

$320

$435

Total Available Liquidity (Cash + Revolver)

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Key Credit Metrics

DEBT TO CAPITAL RATIO

52%60%

63% 64%68% 67% 66%

DEBT TO LTM ADJUSTED EBITDA (LEVERAGE) RATIO

4.7 x

6.3 x

7.4 x

6.0 x

4.8 x(2)

4.3 x

5.6 x

REVOLVER AVAILABILITY ($MM)

$472$534

$694

$557

$311

$452(2)

$423

FIXED CHARGE COVERAGE RATIO (1)

2.4 x 2.3 x 1.9 x2.4 x 2.5 x

2.7 x

3.1 x

(1) Fixed Charge Coverage Ratio is defined as Adjusted EBITDA divided by consolidated interest expense (plus capitalized interest), both of which have not been pro forma adjusted for acquisitions or refinancing activity.

(2) Adjusted for the full redemption of 2020 Senior Notes, which occurred in April 2015.

YE2013 3/31/14 6/30/14 9/30/14 12/31/14 3/31/15 6/30/15

YE2013 3/31/14 6/30/14 9/30/14 12/31/14 3/31/15 6/30/15

YE2013 3/31/14 6/30/14 9/30/14 12/31/14 3/31/15 6/30/15

YE2013 3/31/14 6/30/14 9/30/14 12/31/14 3/31/15 6/30/15

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Multi-Year Hedging Program Helps Mitigate Market Risk

WE ENGAGE IN A STRATEGY THAT USES VARIOUS DERIVATIVE INSTRUMENTS TO MITIGATE VOLATILITY IN OUR FUEL PRODUCTS SEGMENT

• Lock in a fixed gross profit per barrel on a fixed volume of anticipated fuels production

• Hedged 1.4 million barrels of anticipated 3Q15 gasoline production at an average gasoline crack of $15.81 per barrel

• Hedged 0.8 million barrels of anticipated 4Q15 gasoline production at an average gasoline crack of $8.05 per barrel

• Hedged 1.4 million barrels of anticipated 2015 diesel production at an average diesel crack of $20.42 per barrel

• Hedged 0.5 million barrels of anticipated 2016 diesel production at an average diesel crack of $19.56 per barrel

• Lock in a fixed percentage of gross profit on gasoline, diesel and jet fuel in excess of the floating value of a barrel of WTI crude oil on a fixed volume of anticipated fuels production

• Hedged 0.1 million barrels of anticipated 2015 diesel production at 132.5% of WTI

• Hedged 2.2 million barrels of anticipated 2016 diesel production at 131.8% of WTI

APPROACH

SELECTPOSITIONSAS OFJUNE 30, 2015

“Crack Spread” Hedge “Percentage” Hedge

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Spending on Growth Projects Represents More Than 60% of Estimated 2015 CAPEX

2013-2015 CAPITAL SPENDING ACTUALS AND FORECAST ($MM)

2013 2014 2015 (Est.)

$110

$64

Capital Improvement Expenditures Replacement/Environmental Expenditures

Turnaround Expenditures

$69

$32

Joint Venture Contributions (including Dakota Prairie Refinery and Juniper GTL projects)

$285

$32 $28

$105

$205

$60-$70

$15-20$30-$40 (1)

2013 Capital Spending:$275 Million

2014 Capital Spending:$450 Million

2015 Capital Spending (Est.):$320-335 Million

(1) Includes construction costs only.

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APPENDIXSupplemental Financial Data

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EXHIBIT A: Capital Structure Overview

Actual Actual Actual Actual Actual$ Millions 6/30/14 9/30/14 12/31/14 3/31/15 6/30/15Cash 14.6$ 7.7$ 8.5$ 272.8$ 11.7$

ABL Revolver Borrowings 59.2$ 124.2$ 150.8$ 0.1$ 103.1$ 7.625% Senior Notes due 2022 350.0$ 350.0$ 350.0$ 350.0$ 350.0$ 6.50% Senior Notes due 2021 900.0$ 900.0$ 900.0$ 900.0$ 900.0$ 9.625% Senior Notes due 2020 275.0$ 275.0$ 275.0$ 275.0$ -$ 7.75% Senior Notes due 2023 -$ -$ -$ 325.0$ 325.0$ Capital Leases 4.5$ 43.8$ 43.6$ 43.5$ 43.4$ Total Debt 1,588.7$ 1,693.0$ 1,719.4$ 1,893.6$ 1,721.5$

Partners’ Capital 950.9$ 945.7$ 810.2$ 939.1$ 871.7$ Total Capitalization 2,539.6$ 2,638.7$ 2,529.6$ 2,832.7$ 2,593.2$

LTM Adjusted EBITDA $213.5 $282.7 $305.9 $348.1 $403.8Total Debt / LTM Adjusted EBITDA 7.4 x 6.0 x 5.6 x 5.4 x 4.3 xTotal Debt / Total Capitalization 63% 64% 68% 67% 66%

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EXHIBIT B: Reconciliation of Adjusted EBITDA and Distributable Cash Flow

(1) Replacement capital expenditures are defined as those capital expenditures which do not increase operating capacity or reduce operating costs and exclude turnaround costs. Environmental capital expenditures include asset additions that meet or exceed environmental and operating regulations. Investors may refer to our Quarterly Reports on Form 10-Q or quarterly earnings releases for a reconciliation of distributable cash flow to net cash provided by (used in) operating activities.

Note: Sum of individual line items may not equal subtotal or total amounts due to rounding.

$ in millions 12/31/13 3/31/14 6/30/14 9/30/14 12/31/14 3/31/15 6/30/15Sales 1,243$ 1,341$ 1,435$ 1,676$ 1,339$ 1,019$ 1,156$ Cost of sales 1,131 1,216 1,336 1,493 1,216 823 954 Gross profit 113 125 99 183 123 195 203

Selling, general and administrative 38 45 62 70 71 78 70Transportation 39 40 41 42 48 42 42Taxes other than income taxes 5 2 4 4 4 4 4Asset impairment - - - - 36 - - Other 2 2 3 5 5 3 3

Total operating expenses 84 90 109 121 163 127 119

Operating income (loss) 29 35 (10) 61 (40) 69 84

Other expenses (income) (45) 85 - (50) (25) (50) (90)

Income tax expense (benefit) - - (2) 2 (1) (5) (9)

Net income (loss) (16)$ (50)$ (8)$ 9$ (64)$ 24$ 3$

Interest expense and debt extinguishment costs 38 116 29 29 28 27 74Depreciation and amortization 30 30 35 35 38 35 36Income tax expense (benefit) - - (2) 2 (1) (5) (9)

EBITDA 52$ 96$ 54$ 76$ -$ 81$ 103$ Hedging adjustments - non-cash (8) (23) (22) 22 30 34 (18) Asset impairment - - - - 36 - -

9 9 7 10 10 10 9

Adjusted EBITDA 53$ 83$ 39$ 108$ 76$ 125$ 95$ Replacement and environmental capital expenditures (1) (16) (6) (11) (7) (8) (7) (10) Cash interest expense (21) (24) (27) (27) (26) (26) (26) Turnaround costs (6) (3) (19) - (5) (3) (3) Loss from unconsolidated affiliates 1 1 1 5 8Income tax (expense) benefit - - 2 (2) 1 5 9

Distributable Cash Flow 11$ 49$ (15)$ 72$ 39$ 99$ 73$

Amortization of turnaround costs and non-cash equity based compensation and other non-cash items

Quarter Ended

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CONTACT INFORMATIONNoel RyanVice President, Investor & Media RelationsDirect | 720.583.0099Email | noel.ryan@clmt.com