Exhibit 99.1 Delek US Holdings, Inc. Mizuho Energy Summit April 2019

Disclaimers Forward Looking Statements: Delek US Holdings, Inc. (“Delek US”) and Delek Logistics Partners, LP (“Delek Logistics”; and collectively with Delek US, “we” or “our”) are traded on the New York Stock Exchange in the United States under the symbols “DK” and ”DKL”, respectively. These slides and any accompanying oral and written presentations contain forward-looking statements that are based upon current expectations and involve a number of risks and uncertainties. Statements concerning current estimates, expectations and projections about future results, performance, prospects, opportunities, plans, actions and events and other statements, concerns, or matters that are not historical facts are “forward-looking statements,” as that term is defined under the federal securities laws. These forward-looking statements include, but are not limited to, the statements regarding the following: future crude slates; financial strength and flexibility; potential for and projections of growth; return of cash to shareholders, stock repurchases and the payment of dividends, including the amount and timing thereof; crude oil throughput; crude oil market trends, including production, quality, pricing, demand, imports, exports and transportation costs; light production from shale plays and Permian growth; risks related to Delek US’ exposure to Permian Basin crude oil, such as supply, pricing, production and transportation capacity; differentials including increases, trends and the impact thereof on crack spreads and refineries; pipeline takeaway capacity and projects related thereto; refinery complexity, configurations, utilization, crude oil slate flexibility, capacities, equipment limits and margins; the ability to add flexibility and increase margin potential at the Krotz Springs refinery; our ability to complete the alkylation project at Krotz Springs, the Big Spring Gathering System, and a long haul crude oil pipeline successfully or at all and the benefits, flexibility, returns and EBITDA therefrom; the potential for, and estimates of cost savings and other benefits from, acquisitions, divestitures, dropdowns and financing activities; divestiture of non-core assets and matters pertaining thereto; increased capacity on the Paline Pipeline and the impacts and benefits therefrom; retail growth and the opportunities and value derived therefrom; long-term value creation from capital allocation; execution of strategic initiatives and the benefits therefrom; and access to crude oil and the benefits therefrom. Words such as "may," "will," "should," "could," "would," "predicts," "potential," "continue," "expects," "anticipates," "future," "intends," "plans," "believes," "estimates," "appears," "projects" and similar expressions, as well as statements in future tense, identify forward-looking statements. Investors are cautioned that the following important factors, among others, may affect these forward-looking statements: the risks that the combined company may be unable to achieve cost-cutting synergies, or it may take longer than expected to achieve those synergies; uncertainty related to timing and amount of value returned to shareholders; risks and uncertainties with respect to the quantities and costs of crude oil we are able to obtain and the price of the refined petroleum products we ultimately sell; gains and losses from derivative instruments; management's ability to execute its strategy of growth through acquisitions and the transactional risks associated with acquisitions and dispositions; acquired assets may suffer a diminishment in fair value as a result of which we may need to record a write-down or impairment in carrying value of the asset; changes in the scope, costs, and/or timing of capital and maintenance projects; the ability to negotiate, obtain commitments, finance and construct the long haul crude oil pipeline; operating hazards inherent in transporting, storing and processing crude oil and intermediate and finished petroleum products; our competitive position and the effects of competition; the projected growth of the industries in which we operate; general economic and business conditions affecting the geographic areas in which we operate; and other risks contained in Delek US’ and Delek Logistics’ filings with the United States Securities and Exchange Commission. Forward-looking statements should not be read as a guarantee of future performance or results, and will not be accurate indications of the times at, or by which such performance or results will be achieved. Forward-looking information is based on information available at the time and/or management’s good faith belief with respect to future events, and is subject to risks and uncertainties that could cause actual performance or results to differ materially from those expressed in the statements. Neither Delek US nor Delek Logistics undertakes any obligation to update or revise any such forward-looking statements. Non-GAAP Disclosures: Delek US and Delek Logistics believe that the presentation of earnings before interest, taxes, depreciation and amortization ("EBITDA"), free cash flow, distributable cash flow and distribution coverage ratio provide useful information to investors in assessing their financial condition, results of operations and cash flow their business is generating. Distributable cash flow is calculated as net cash flow from operating activities plus or minus changes in assets and liabilities, less maintenance capital expenditures net of reimbursements and other adjustments not expected to settle in cash. EBITDA, adjusted EBITDA, free cash flow, distributable cash flow and distribution coverage ratio should not be considered as alternatives to net income, operating income, cash from operations or any other measure of financial performance or liquidity presented in accordance with U.S. GAAP. EBITDA, adjusted EBITDA, free cash flow, distributable cash flow and distribution coverage ratio have important limitations as analytical tools because they exclude some, but not all, items that affect net income. Additionally, because EBITDA, adjusted EBITDA, free cash flow, distributable cash flow and distribution coverage ratio may be defined differently by other companies in its industry, Delek US' and Delek Logistics’ definitions may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. Please see reconciliations of EBITDA, adjusted EBITDA, distributable cash flow and distribution coverage ratio to their most directly comparable financial measures calculated and presented in accordance with U.S. GAAP in the appendix. 2

Investment Overview • Current Price: $36.91/share(1) • Market Capitalization: $2.9 billion(1) Overview (NYSE: DK) • NYSE: DKL: (Market cap $790 mm)(1) Owns 63.4%, including 2% GP(2) • 4Q18 Net Income: $121.6 million; Adjusted EBITDA: $251.4 million(3) • December 31, 2018 balance sheet: Flexible Financial Position to • Delek US: $1.1 billion of cash; $1.8 billion of debt Support Growth • Includes $4.5 million cash and $700.4 million debt of DKL • Net debt (excl. DKL) of $8.1 million • Announced Big Spring Gathering System with over 200,000 dedicated acres Company Initiatives to Create • Allows Delek US to participate in value chain from wellhead to Gulf Coast; exploring Long-Term Value options for a long haul crude oil pipeline joint venture • Krotz Springs alkylation project forecasted $45-50 million annualized EBITDA(3) • Operating model built to benefit from crude oil differentials and IMO 2020’s impact on market trends Favorable Market Factors for • 262,000 bpd of 302,000 bpd crude oil slate is WTI linked barrels Delek US Through 2022 • Approximately 207,000 bpd sourced from Permian Basin crude oil • Light products priced on Gulf Coast basis • Crude oil slate flexibility and high motor gas and distillate yields and low residual yields • Repurchased $157.9 million of DK shares in 4Q18, $365 million in FY2018 • Increased regular quarterly dividend(4): Cash Returns to Shareholders • 1Q19 increased by 4% to $0.27/share • Fourth increase from $0.15/share, paid in December 2017 1) Based on price per common share or common unit, as applicable, as of close of trading on March 28, 2019. 2) As of December 31, 2018, 5.4% of the ownership interest in the general partner is owned by three members of senior management of Delek US (who are also directors of the general partner). The remaining ownership interest is held by a subsidiary of Delek US. 3) Please see page 35 for a reconciliation of net income to adjusted EBITDA and page 32 for a reconciliation of forecasted net income to forecasted EBITDA for the Krotz Spring alkylation project. 4) Quarterly dividends mentioned are quarterly dividends per share declared in referenced periods. 3

Integrated Company with Asset Diversity and Scale Strategically located assets with Permian Basin exposure • Source 207,000 bpd from Permian Basin • Growing gathering system Refining (1) Logistics (2) Asphalt Retail Renewables • 6th largest independent • 10 terminals 6 asphalt terminals located • Approximately 300 Approx. 23m gallons refiner • Approximately 1,320 in: stores biodiesel: • 302,000 bpd in total miles of pipeline • El Dorado, AR • Southwest US locations • Crossett, AR • El Dorado, AR • 11.0 million bbls of • Muskogee, OK • Largest licensee of 7- • Cleburne, TX • Tyler, TX storage capacity • Memphis, TN Eleven stores in the US • Big Spring, TX • West Texas wholesale • Big Spring & Henderson, • West Texas wholesale • Krotz Springs, LA • Joint venture crude oil TX marketing business • Crude oil supply: 262,000 pipelines: RIO / Caddo • Richmond Beach, WA bpd WTI linked (207,000 • Own 63.4%, incl. 2% GP, bpd of Permian access) of DKL(3) 1) California refinery located in Bakersfield, which is not shown on the map, has not operated since 2012. 2) Amounts include the Big Spring dropdown that closed in March 2018 with an effective date of March 1, 2018. 3) As of December 31, 2018, 5.4% of the ownership interest in the general partner is owned by three members of senior management of Delek US (who are also directors of the general partner). The remaining ownership interest is held by a subsidiary of Delek US. 4

WTI-Linked Refining System with Permian Based Crude Oil Slate System with over 300,000 bpd of crude oil throughput capacity (~70% Permian Basin based) Crude Oil Supply is Primarily WTI-Linked Tyler(1) Tyler, Texas 16% 1% • 75,000 bpd crude oil Crude throughput Throughput WTI 100% WTI • 8.7 complexity Capacity, bpd ETX • 83% linked Light crude oil refinery WTI-Linked Other • 302,000 Permian Basin and East Texas Crude, bpd sourced crude oil El Dorado, Arkansas 262,000 Permian Basin El Dorado(1) • 80,000 bpd crude oil Access, bpd 20% throughput 100% • 10.2 complexity WTI 207,000 WTI Local AK 21% • Flexibility to process medium 59% linked and light crude oil 1 2 Other • Permian Basin, local Arkansas, East Texas and Gulf Coast crude oils Big Spring(1) Big Spring, Texas • 73,000 bpd crude oil 100% WTI 26% throughput WTI • 10.5 complexity WTS 74% linked • Process WTI and WTS crude oil 1) Approx. 96 million barrels of WTI-linked crude annually; changes • Located in the Permian Basin realized through crack spread and capture rate Krotz Springs, Louisiana Krotz Springs(1) • 74,000 bpd crude oil 2) Approx. 75 million barrels of Permian crude annually; changes realized throughput in crude slate 62% WTI 39% WTI • 8.4 complexity linked • Permian Basin, local and Gulf GC Sweet 61% Coast crude oil sources 1) Crude oil slate based on amount received year-to-date as of December 31, 2018. Note: WTI-Brent differential realized through crack spread and capture rates and Midland-WTI differential realized in crude slate. 5

Brent – WTI Differential Transportation economics should keep the differential wide (1)(2) • Transportation economics should play a role in the Indication of Cushing Sourced Export Transport Economics differential $10.00 $5.91 - $10.05 • Current break-even transport economics for exporting from $8.00 $3.18 - $7.82 $0.30 (2) Cushing approximately $3.18 - $10.05 $6.00 $0.25 $4.00–$4.75 • IMO 2020 expected to increase shipping costs $4.00 $1.50–$2.75 $0.48 $0.48 $2.00 • Cushing inventories expected to build in 2019 $1.42–$4.36 $1.42–$4.36 Growing Mid-Continent production, Enbridge Line 3 $0.00 • -$0.24 -$0.06 replacement, max utilization on southbound pipelines -$2.00 Europe Asia Brent & WTI Backwardation (Contango) Time Value of Money • Global inventories also have declined Shipping Freight Transport from terminal to water Pipeline Tariff • Demand from US, EU, China, and India strong (3) • Could decline further, pushing Brent into further Weekly Cushing, OK Ending Stocks (000 bbls) backwardation 80,000 70,000 • Brent-WTI spread can widen further due to 60,000 • OPEC+ cuts • Increased global refining capacity 50,000 • Higher interest rates on Time Value of Money 40,000 • Higher freight rates 30,000 • Declining North Sea production 20,000 10,000 - 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 1) Market data source: Argus – March 21, 2019; futures based on ICE/NYMEX curve. 2) Source: Company estimates; based on publicly available pipeline tariffs. 3) Source: Company estimates; current production based on EIA for March 22, 2019, Weekly Stocks, Area: Cushing, Oklahoma. 6

Permian Basin Outlook Production continues to grow while incremental takeaway capacity outlook is uncertain • Steady growth has continued in production Average Annual Crude Oil Production (Mbpd) (1) • Drilling supported by improved technology and low costs and WTI-Midland Price (2) • Low break-even rates 7.00 $58.43 65.00 $58.76 • Lower prices still support growth although more subdued $56.60 $54.89 6.00 $49.88 $59.63 55.00 • Some producers have announced plans to reduce rigs but expect production growth 5.00 Current production 45.00 Feb 2019: 4.1 mm bpd 4.00 35.00 • Production less likely to outpace incremental expansion in 2019 3.00 5.9 25.00 5.3 • In 2017 and 2018 Permian production outpaced initial 4.7 2.00 4.1 15.00 forecasts 3.4 • DUCs have grown at a rapid rate to 4,004(1) 1.00 2.5 5.00 • Short time to finish well with low capex costs - (5.00) 2017 2018 2019E 2020E 2021E 2022E • In past cycles, not all pipelines were completed (1) • During 2015 – 2017, 56% of announced pipeline Drilled but Uncompleted Wells takeaway capacity was cancelled (3) 4,500 25% • Average pipeline capacity was also smaller 4,000 20% • Locking in sufficient commitments is more challenging 3,500 • Pipeline operators would prefer one full pipeline rather 3,000 15% 2,500 than two half-full pipelines 10% 2,000 1,500 5% • Any shortfall in the takeaway balance can create volatility in 1,000 0% differentials 500 0 -5% 8/18 4/14 8/14 4/15 8/15 4/16 8/16 4/17 8/17 4/18 12/13 12/14 12/15 12/16 12/17 12/18 DUCs Incremental DUCs of New Drills % (Rolling 12-Month) 1) Source: Company estimates; current production based on EIA for February 2019, Drilling Productivity Report, March 2019 Drilling Productivity Report. 2) WTI Midland price source: Argus – March 28, 2019; futures based on ICE/NYMEX curve. 3) Source: Company estimates. 7

Delek US Forecast Case EBITDA Under current Midland-Cushing conditions Forecast Case Segment EBITDA(1)(2) $1,200 RefiningRefiningBasic Assumptions*Assumptions $165 $35 MidlandMidland– Cushing Differential Differential -$3.91 $1,000 HSD 5-3-2 Crack Spread $821 $856 WTI HSD 5-3-2 Crack Spread $13.50 ULSD 5-3-2 Crack Spread $800 ($165) WTISystem ULSD 5-3--wide2 Crack Utilization Spread Rate$15.65 $600 System-wide Utilization Rate 97% *Crack spreads are 12-year averages. $400 Midland-Cushing differential approximate average of Cal18 and Cal19 (frwd curve) as of March 28, 2019. Sustaining Capex $200 $0 Refining Logistics Retail Corporate & Delek US Refining SG&A Consolidated EBITDA • Corporate/Refining SG&A (excluding Logistics and Retail) $165.5 million • Logistics and Retail SG&A included in EBITDA above • Delek US Forecast Case EBITDA under Cal 18 & 19 average Midland-Cushing conditions is approximately $856 million(2) • As segments stand today, excluding any current growth projects/initiatives such as the alkylation unit at Krotz Springs and midstream growth initiatives 1) EBITDA numbers provided are indicative and represent that of a “base case” operating platform for Delek US. Results will vary on market conditions, cash flow options. Please see page 2 regarding forward looking statements. 2) We are unable to provide a reconciliation of this forward-looking estimate of EBITDA because certain information needed to make a reasonable forward-looking estimate of net income is difficult to estimate and dependent on future events, which are uncertain or outside of our control, including with respect to future market pricing and other potential variables. Accordingly, a reconciliation to net income as the most comparable GAAP measure is not available without unreasonable effort. These amounts that would require unreasonable effort to quantify could be significant, such that the amount of projected GAAP net income would vary substantially from the amount of EBITDA projected. 8

Delek US Forecast Case Free Cash Flow Potential Under Cal 18/19 average Midland-Cushing conditions Indicative Free Cash Flow Available for Buybacks, Dividend Growth & Growth Capex(1) 900 $856 (2) $100 800 $120 700 $130 600 $55 500 $120 400 $331 (2) 300 200 Sustaining Capex 100 0 Delek US Forecast Cash Taxes Interest Sustaining Capex Turnarounds Growth Capex Free Cash Flow Case EBITDA • Delek US’ forecast case (under referenced Midland-Cushing conditions) potential free cash flow yield of 11.4% ($331 million, ex-dividends)(2)(3) allows growth initiatives, growing dividends, and further share repurchases • Investments and return of capital options do not compromise DK’s strong balance sheet • Delek US can use its strong balance sheet to support these strategic objectives • Expect to use a healthy mix of debt (60-70%) and cash generated from operations (30-40%) to fund current organic growth initiatives 1) EBITDA and cash flow numbers provided are indicative and represent that of a “base case” operating platform for Delek US. Results will vary on market conditions, cash flow options. Please see page 2 regarding forward looking statements. 2) We are unable to provide a reconciliation of this forward-looking estimate of EBITDA and free cash flow because certain information needed to make a reasonable forward-looking estimate of net income and cash from operating activities is difficult to estimate and dependent on future events, which are uncertain or outside of our control, including with respect to future market pricing and other potential variables. Accordingly, a reconciliation to net income and cash from operating activities as the most comparable GAAP measures are not available without unreasonable effort. These amounts that would require unreasonable effort to quantify could be significant, such that the amount of projected GAAP net income and cash from operating activities would vary substantially from the amount of EBITDA and free cash flow projected. 9 3) Based on market capitalization as of close of trading on March 28, 2019.

Capital Allocation Framework Balance the following objectives using a rigorous and disciplined capital allocation program to create long-term value for our shareholders: • Invest: Capital allocation program focuses on safety, maintenance, and reliability as priority • Grow: Maintain financial strength and flexibility to support the company’s strategic objectives • Return cash to shareholders: Maintain a competitive dividend and opportunistically repurchase DK shares Non-Discretionary Discretionary Sustaining & Regulatory Capex Growth Capex • Approximately $130 million sustaining capex/yr • 25% IRR for >$5mm projects at Refining; <$5mm is 50% IRR • Between $40-$60 million per turnaround • >15% IRR minimum hurdle rate for Retail projects, dependent on size • One each year for next 4 years • >15% IRR hurdle rate for stable cash flow Logistics projects • CriticalSustaining for safe and Capex reliable operations • Various amounts for regulatory capex Cash Returns to Shareholders Dividend • Share repurchases opportunistic based on alternative investment opportunities and relative valuations • Committed to competitive dividend consistent with growth company profile Acquisitions • Target mid-point of peer group • Level that can be maintained through the cycle • Evaluate accretive opportunities as they arise vs. alternative uses of cash Deleveraging • Continue to optimize the balance sheet • Opportunistically repay DK debt when FCF supports it • $150mm convertible debt paid in Sept of 2018 10

Capital Allocation Discipline in Practice Capital Allocation(1) • Maintaining strong balance sheet Returned $445 million or ~15% of current market cap to • DK excluding DKL, $8.1 million net debt at 12/31/18 shareholders in 2018 through buybacks and dividends(2) • Investing in the business • 4 refinery turnarounds over next 4 years • El Dorado March/April 2019 • Growing the business $157.9 • Big Spring Gathering System • Exploring options for a long-haul pipeline $92.1 $95.3 • Krotz alkylation project $20.9 $21.0 • Committed to competitive, through-cycle dividend and $12.7 $17.0 $20.0 $52.0 $23.9 $20.8 opportunistic share repurchases $30.6 $53.4 $54.9 $38.4 $54.8 • Raised quarterly dividend four times over last year to $39.5 $32.7 $0.27/share from $0.15/share $16.3 • Repurchased approximately $365 million of DK shares 4Q17 1Q18 2Q18 3Q18 4Q18 Sustaining Capex Discretionary Capex Dividend Share Repurchases in 2018; Expect to repurchase $50 million in 1Q19 Dividends Declared ($/share) Cash Balance & Net Debt (DK Ex. DKL)(1) $1.00 $0.95 $1,128 $1,090 $1,079 $1.08 $1,013 $0.40 $0.96 $0.40 $927 $0.60 $0.60 $0.60 $0.60 $0.60 $0.33 $0.39 $0.55 $209 $178 $0.15 $0.18 $116 $8 $0.15 $0.21 4Q17 1Q18 2Q18 3Q18 $(5) 4Q18 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 E Cash Balance Net Debt Regular Special 1) Based on company filings from Q4 2017 through Q4 2018. Sustaining capex defined as regulatory & maintenance capital expenditures. 2) Based on market capitalization as of close of trading on March 28, 2019. 11

Growth and Market Opportunities

Krotz Springs Refinery- Alkylation Project • Alkylation unit with 6,000 bpd capacity Change in Yields, in 000 bpd • Approx. $130.0 million estimated capital costs with $103.0 million spent as of December 31, 2018 Gasoline Diesel/Jet Heavy Oils Other 8.7 • Improves refinery flexibility 11.1 8.0 • Converts lower priced isobutane into higher value 8.0 alkylate 22.2 • Enables multiple summer grades of gasoline to be 22.2 produced • Increases octane to produce premium gasoline 44.0 • Ability to access local markets 38.4 • Forecasted project returns • Forecasted annual EBITDA(1) $45-$50 million Base Alky • 40% IRR and 2.6 year payout at $50 million EBITDA • Driven by the conversion/reduces dependency on Gulf Coast CBOB 7.8 – Isobutane Spread(2) crack spread environment for project return $1.40 $1.23 $1.21 • Economics based on 95 cents/gallon spread $1.20 between CBOB 7.8 and isobutane $0.97 $1.00 $0.90 • Sensitivity: each 10 cents/gallon change in spread $0.91 $0.85 $0.77 equals $3.2 million EBITDA change $0.80 $0.69 $0.71 $0.61 $0.67 $0.63 $0.60 $0.40 Spread, per gallon per Spread, $0.20 $0.00 CBOB - Isobutane Base Line Economics 1) Please see page 32 for a reconciliation of forecasted net income to forecasted EBITDA 2) NYMEX, 2019 Isobutane spread as March 21, 2019. 13

Growing Midstream - Big Spring Gathering System Delek US’ Gathering Helps Control Crude Oil Quality and Costs into Refineries • Approximately 200-mile gathering • Allows Delek US to get closer to system, 300Kbpd throughput capacity wellhead to control crude oil quality • Currently more than 200,000 and cost dedicated acres • Provides improvement in refining • Points of origin: Howard, Borden, performance and cost structure Martin and Midland counties • Total terminal storage of 650K bbls • Forecasted annualized EBITDA benefit • Connection to Delek US’ Big • $35 to $45 million by 2022 (1) Spring, TX terminal • Expected total capital cost: • Potential future dropdown to DKL once approximately $170 million fully ramped 1) Includes benefit from quality uplift for refineries. We are unable to provide a reconciliation of this forward-looking estimate of EBITDA because certain information needed to make a reasonable forward-looking estimate is difficult to estimate and dependent on future events, which are uncertain or outside of our control, including with respect to unknown construction timing, unanticipated construction costs and other potential variables. Accordingly, a reconciliation to net income as the most comparable GAAP measure is not available without unreasonable effort. 14

Growing Midstream – Potential Permian Basin Crude Oil Long Haul Pipeline • Exploring potential options for a joint venture long haul crude oil pipeline Big Spring • Potential destinations include access to Gulf Coast terminals • Delek US’ investment can be potential future dropdown to DKL once fully ramped 15

DK Operations Positioned to Benefit from IMO 2020 Delek US positioned to benefit with high value product yields and crude oil slate flexibility 4Q18 Refiners’ Middle Distillates Yield % (1) (2) (3) • Refining system product yields • Middle distillate: average approx. 115,000 bpd of distillate or 44 million barrels annually(4) 41% 39% • Gasoline: average approx. 150,000 bpd of gasoline or 55 38% 37% 37% (4) 35% million barrels annually 33% • Low residual products: approximately 2.9% yield (4) • Crude oil slate has flexibility CVRR PSX DK HFC VLO MPC PBF • Ability to increase sour crude oil processing to approximately 50% based on market economics 4Q18 Refiners’ Gasoline Yield % (1) (2) (3) • Big Spring refinery currently processes 26% WTS and can increase to 100% • 53% 53% El Dorado refinery flexibility to process light to 52% medium sour crude oil (up to 100%) based on 50% 50% economics 49% • Krotz Springs refinery exploring ability to produce low 45% sulfur marine fuel DK CVRR HFC PBF MPC VLO PSX 1) Industry average based on peer group. 2) Middle distillates yield includes distillate fuel oil, kerosene and kerosene-type jet fuel. 3) Sourced from Barclays U.S. Independent Refiners Guidebook to Refiners’ Financial & Operating Metrics – 4Q18 Edition, March 18, 2019. 4) Average calculated based on 2018 results. Residual yield includes asphalt, road oil and residual fuel oil. 16

Delek US’ Initiatives Drive Potential EBITDA Growth Delek US positioned to generate strong cash flows to return cash to shareholders Difference $ in millions between -$2.50 Expected Incremental Benefit from Company Initiatives/Projects $1,200 and -$3.91 Midland-Cushing $205 differential $160 $105 $1,000 $53 $856 $800 $106 $600 $750 $400 Supports DK’s objective to reach $370 - $390 million of midstream EBITDA by 2022 Please refer to slide 8 for $200 assumptions Average 2018 midstream market transactions were approximately 12.8x on a 1-year Forward EBITDA basis (3) $0 Forecast Case Delek US EBITDA 2019 2020 2021 2022 (1) (2) See Refining Basic Assumptions below Base Year: 2018 2019 2020 2021 2022 (Change from 2018) (Change from 2018) (Change from 2018) (Change from 2018) Company Initiatives/Projects: (2) Δ: +$50-55 million Δ: $100-110 million Δ: $155-165 million Δ: $200-210 million $0 Forecast Base Case Delek US EBITDA with Company $803 million $855 million $910 million $955 million Initiatives/Projects (1) (2) Refining Basic Assumptions(2) Midland – Cushing Differential -$2.50 WTI HSD 5-3-2 Crack Spread $13.50 WTI ULSD 5-3-2 Crack Spread $15.65 System-wide Utilization Rate 97% 1) Includes benefit from quality uplift for refineries. We are unable to provide a reconciliation of this forward-looking estimate of EBITDA because certain information needed to make a reasonable forward-looking estimate is difficult to estimate and dependent on future events, which are uncertain or outside of our control, including with respect to market pricing, unknown construction timing, unanticipated construction costs and other potential variables. Accordingly, a reconciliation to net income as the most comparable GAAP measure is not available without unreasonable effort. These amounts that would require unreasonable effort to quantify could be significant, such that the amount of projected GAAP net income would vary substantially from the amount of EBITDA projected. 2) Please see page 8 for further detail for market assumptions regarding these forecasts. 17 3) Based on private equity midstream transaction in 2018, Wells Fargo.

Organic Projects Create Platform to Support Midstream Growth Supports Delek US’ goal to generate approximately $370 million to $390 million of annual midstream EBITDA • Big Spring logistics assets dropdown closed Strong EBITDA Growth Profile from Midstream Initiatives (1) in March 2018, effective March 1 ($ in millions) • $40 million forecasted annualized $368 EBITDA(2) • Completed Paline Pipeline expansion in early March 2018 • Capacity to 42,000 bpd from 35,000 $165 bpd • $5 million forecasted annualized EBITDA uplift $7 $32 • Growing midstream assets: Target $164 2019 • Krotz Springs assets - $30 to $34 million EBITDA / year(2) Note: based on DKL LTM EBITDA + • Big Spring Gathering system under remaining incremental benefit from construction the Big Spring dropdown since completion • $35 to $45 million EBITDA / year(3) (2) • 2018 EBITDA Big Spring Krotz Springs Midstream Total Other midstream growth projects of Dropdown Dropdown growth projects(3) Annualized (3)(4) (2) (2) $115 to $125 million EBITDA / year March 2018 Inventory EBITDA (4) Potential • Delek Logistics provides platform to unlock logistics value 1) Information for illustrative purposes only to show potential based on estimated dropdown assets listed. Actual amounts will vary based on market conditions, which assets are dropped, timing of dropdowns, actual performance of the assets and Delek Logistics in the future. Expected amounts adjusted for what is captured in the LTM period. 2) Please see pages 33 and 34 for a reconciliation of EBITDA of Krotz Springs and Big Spring drop downs, respectively. Please see page 38 for reconciliations of EBITDA to net income for the respective periods. 3) We are unable to provide a reconciliation of this forward-looking estimate of EBITDA because certain information needed to make a reasonable forward-looking estimate is difficult to estimate and dependent on future events, which are uncertain or outside of our control, including with respect to unknown construction timing, unanticipated construction costs and other potential variables. Accordingly, a reconciliation to net income as the most comparable GAAP measure is not available without unreasonable effort. 18 4) Subject to final scope on economics for long-haul pipeline.

Market Update Trends benefit Delek US’ WTI-linked refining system • Crack spread has increased through 1Q19 • Refining industry utilization currently 86.6% (1) Increasing US Gulf Coast WTI 5-3-2 (2) • Gasoline industry inventory position improved through 1Q19 $18.00 $16.00 • Gasoline crack spread increased from seasonal $14.00 low in February 2019 $12.00 $10.00 • Brent-WTI differential supportive $8.00 • Delek US refining system has approximately 262,000 bpd barrel per $ $6.00 of WTI-linked crude oil $4.00 • Differential supported by growing US light crude $2.00 production and transportation economics to clear to the $0.00 export markets US Gulf Coast WTI Gas Crack Spread (2) Brent – WTI Differential Remains Wide (2) $18.00 $16.00 $0.00 $14.00 -$2.00 $12.00 $10.00 -$4.00 $8.00 $ per barrel per $ $6.00 -$6.00 $4.00 barrel per $ -$8.00 $2.00 $0.00 -$10.00 -$12.00 1) Based on DOE report as of March 22, 2019 2) Current data as of March 27, 2019. Argus data. 19

Current Valuation Below Peer EV-to-EBITDA DK positioned to benefit from Midland to Brent crude diffs and IMO; low valuation to peer group • Strong balance sheet with $1.1 billion of cash; net debt of $704.0 million; net debt excl. DKL of $8.1 million(1) • Operations positioned to generate strong cash flow based on current differential and crack spread outlook • Returning cash to shareholders through repurchases/dividends; Investing in business to create long term value EV/EBITDA(2) 9.0x 8.0x 7.0x 6.0x 5.0x 4.0x 3.0x 2.0x 1.0x 0.0x DK-USQ HFC-USQ VLO-USQ PBF-USQ MPC-USQ PSX-USQ CVI-USQ 2019 2020 2019 Avg 2020 Avg (1) Data presented ending December 31, 2018. (2) Based on NASDAQ IR Insights/Factset as of March 28, 2019. 20

An Integrated and Financial Flexibility to Diversified Refining, Support Strategic Logistics and Marketing Company Objectives Invest in the Business to Permian Focused Focus on Long-Term Operate Reliably and Refining System Shareholder Returns Safely Growing Midstream Platform to Diversify EBITDA Stream

Appendix

4Q18 Highlights – Cash Flow • Strong cash flow generation in Total Consolidated Cash Flows 4Q18 supported investment in 1,600 the business and returning cash $359.1 to shareholders 1,400 ($88.1) • Operating cash flow from 1,200 $1,109.1 continuing ops $359.1 million $1,079.3 ($300.8 ) • Investing activities include cash 1,000 capex and investments of $94.0 million 800 600 • Free cash flow $265.1 million (1) supported: 400 • Total shareholder distributions $179.2 million 200 • Includes $157.9 million through repurchases 0 9/30/2018 Cash Operating Cash Flow Investing Activities Financing Activities 12/31/2018 Cash Balance from Continuing Ops Balance 1) Free cash flow defined as net cash from operating activities less cash capital expenditures and investments. 23

Guidance 1Q19 Guidance Low High Total Crude Throughput 250,000 260,000 El Dorado Crude Throughput 37,000 42,000 Realized Midland-Cushing Discount, $/bbl $4.40 $4.65 Backwardation/(Contango) ($0.35) ($0.40) Consolidated Operating Expenses, $ in millions $165.0 $175.0 Consolidated G&A, $ in millions $55.0 $60.0 Consolidated Depreciation and Amort., $ in millions $52.0 $54.0 Net interest expense, $ in millions $26.0 $28.0 Effective Tax Rate 23% 25% Estimated Diluted Share Count (excl. share repurchase) 79.0 79.5 2019 Capital Expenditures $ in millions Refining $224 Logistics 17 Retail 18 Corporate/Other 91 Total $ 350 1) Interest expense guidance excludes any contract termination/modification charges that may occur. 24

Delek US Growth Focused on Growth through Acquisitions 2005 to 2007 2011 to 2012 2013 to Current 2011 Crude Oil Increased Gathering SALA Gathering East and West Texas Gathering Lion Oil acquisition 2012 DKL Joint Ventures 2011 Crude Oil Nettleton RIO Pipeline Paline Pipeline Pipeline Caddo Pipeline Logistics $50 mm $12.3 mm Exp. Inv.: ~$104 mm 2005 2011 2013 2014 2015 2018 2017 Tyler refinery & Lion refinery & Biodiesel Biodiesel 47% Acquired rest Acquired rest Refining related assets related pipeline & terminals Facility Facility ownership of Alon USA of Alon USA $68.1 mm(1) $228.7 mm(1) $5.3 mm $11.1 mm in Alon USA Partners 2014 2006 2012 2013 2013 2014 Assets Purchased Assets Frank Product Abilene & San Angelo Big Sandy Tyler-Big Sandy North Little Rock Mt. Pleasant Thompson terminals terminal & pipeline Pipeline Product Terminal System Logistics Transport $55.1 mm $11.0 mm $5.7 mm $5.0 mm $11.1 mm (2) $11.9 mm Acquisition Completed 2015 171 retail fuel & 2016 2017 2011 - 2014 47% convenience stores Sold MAPCO Acquired rest Retail Building new large format convenience stores ownership & related assets for $535mm of Alon USA in Alon USA $157.3 mm (1) Includes logistic assets in purchase price. Purchase price includes working capital for refineries. (2) Mt. Pleasant includes $1.1 million of inventory. Refining Segment Logistics Segment Retail Segment 25

Current Delek US Corporate Structure 94.6% Delek US Holdings, Inc. ownership interest (1) NYSE: DK Market Cap: $2.9 billion(2) Delek Logistics GP, LLC (the General Partner) 61.4% interest in LP units 2.0% interest General partner interest Incentive distribution Delek Logistics Partners, LP rights NYSE: DKL Market Cap: $790 million(2) 1) As of December 31, 2018, a 5.4% interest in the Delek US ownership interest in the general partner is held by three members of senior management of Delek US. The remaining ownership interest is indirectly held by Delek US. 2) Market capitalization based on price per common share and common unit, as applicable, as of close of trading on March 28, 2019. 26

Market Data

IMO 2020 Current impact on oil and product markets • Market is pricing a higher scrubber uptake rate WTI-HSFO Spread (1) • Increased scrubber uptakes could decrease ULSD demand $5 • Led to upside pressure on the HFSO curve over past month -$5 • If scrubber adoption is less than projected, could result in -$15 increased demand for ULSD • Would expect to see higher ULSD and gas crack spreads -$25 Potential range if compliance higher • Global and EM demand growth concerns have suppressed the gas crack -$35 • Delek US internal testing showed a minimum VGO feedstock is required to blend into LSFO -$45 • Uplift in gas crack spread in 2020 may be due to this Jan-17 Jan-18 Jan-19 Jan-20 Jan-21 Jan-22 Sep-17 Sep-18 Sep-19 Sep-20 Sep-21 Sep-22 May-18 May-19 May-20 May-21 May-22 uptick in VGO feedstock demand May-17 WTI-HSFO Spread WTI-HSFO Spread Forward Curve • 28-48% range from our hand-blended testing • 70% of VGO contains gas Delek US Study: Range on VGO Requirements for LSFO Blends ULSD and Gas Crack Spreads (1) Minimum Gas Case Maximum Case $35 Potential range if compliance higher $30 $25 Potential range if compliance higher $20 28% 29% 48% $15 $10 58% 14% $5 24% Jan-17 Jan-18 Jan-19 Jan-20 Jan-21 Jan-22 Sep-17 Sep-18 Sep-19 Sep-20 Sep-21 Sep-22 May-17 May-18 May-19 May-20 May-21 May-22 ULSD Crack Spread Gas Crack Spread ULSD Slurry FCC / Coker Feed ULSD Slurry FCC / Coker Feed ULSD Crack Spread Forward Curve (Annual Average) Gas Crack Spread Forward Curve (Annual Average) 1) Spread sources: Argus – March 28, 2019; futures based on ICE/NYMEX curve. 28

Access to Midland Crude Oil Benefits Margins WTI Midland vs. WTI Cushing Crude Oil Pricing ($ per barrel) $2.00 $0.00 ($2.00) ($4.00) ($6.00) ($8.00) ($10.00) ($12.00) ($14.00) Approx. 207,000 bpd of Midland ($16.00) crude oil in DK system ($18.00) Jul-11 Jul-12 Jul-13 Jul-14 Jul-15 Jul-16 Jul-17 Jul-18 Jan-13 Jan-17 Jan-11 Jan-12 Jan-14 Jan-15 Jan-16 Jan-18 Jan-19 Sep-11 Sep-12 Sep-13 Sep-14 Sep-15 Sep-16 Sep-17 Sep-18 Nov-15 Nov-11 Nov-12 Nov-13 Nov-14 Nov-16 Nov-17 Nov-18 Mar-11 Mar-12 Mar-13 Mar-14 Mar-15 Mar-16 Mar-17 Mar-18 Mar-19 May-11 May-12 May-13 May-14 May-15 May-16 May-17 May-18 Source: Argus – as of March 26, 2019 29

U.S Refining Environment Trends Refined Product Margins and WTI-Linked Feedstock Favor Delek US (1) (2) (2) $50 Brent-WTI Cushing Spread Per Barrel WTI 5-3-2 Gulf Coast Crack Spread Per Barrel LLS 5-3-2 Gulf Coast Crack Spread Per Barrel $40 $30 $20 $10 $0 -$10 -$20 -$30 Jul-18 Jul-10 Jul-11 Jul-12 Jul-13 Jul-14 Jul-15 Jul-16 Jul-17 Jan-11 Jan-10 Jan-12 Jan-13 Jan-14 Jan-15 Jan-16 Jan-17 Jan-18 Jan-19 Sep-10 Sep-11 Sep-12 Sep-13 Sep-14 Sep-15 Sep-16 Sep-17 Sep-18 Nov-10 Nov-11 Nov-12 Nov-13 Nov-14 Nov-15 Nov-16 Nov-17 Nov-18 Mar-13 Mar-10 Mar-11 Mar-12 Mar-14 Mar-15 Mar-16 Mar-17 Mar-18 Mar-19 May-15 May-10 May-11 May-12 May-13 May-14 May-16 May-17 May-18 1) Source: Platts as of March 28, 2019; 5-3-2 crack spread based on HSD 2) Crack Spreads: (+/-) Contango/Backwardation 30

Reconciliations

Non-GAAP Reconciliation of Potential Project EBITDA(1) Reconcilation of Forecast U.S. GAAP Net Income (Loss) to Forecast EBITDA for Alkylation Project ($ in millions) Forecasted Range Forecasted Net Income $ 24.1 $ 27.3 Add: Interest expense, net - - Income tax expense 14.0 15.8 Depreciation and amortization 6.9 6.9 Forecasted EBITDA $ 45.0 $ 50.0 1) Based on projected range of potential future performance from the alkylation unit project at Krotz Springs. Amounts of EBITDA, net income and timing will vary. Actual amounts will be based on timing of completion, performance of the project and market conditions. 32

Non-GAAP Reconciliation of Krotz Spring Potential Dropdown EBITDA(1) Krotz Springs Logistics Drop Down Reconciliation of Forecasted Annualized Net Income to Forecasted EBITDA ($ in millions) Forecasted Range Forecasted Net Income $ 2.9 $ 3.3 Add: Depreciation and amortization 15.6 17.7 Interest and financing costs, net 11.5 13.0 Forecasted EBITDA $ 30.0 $ 34.0 1) Based on projected range of potential future logistics assets that could be dropped to Delek Logistics from Delek US in the future. Amounts of EBITDA, net income and timing will vary, which will affect the potential future EBITDA and associated deprecation and interest at DKL. Actual amounts will be based on timing, performance of the assets, DKL’s growth plans and valuation multiples for such assets at the time of any transaction. 33

Non-GAAP Reconciliations of Big Spring Potential Dropdown EBITDA(1) Big Spring Logistics Drop Down and Marketing Agreement Reconciliation of Forecasted Annualized Net Income to Forecasted EBITDA Tanks, Terminals ($ in millions) and Marketing Agreement Forecasted Net Income $ 13.3 Add: Income tax expense - Depreciation and amortization 5.1 Amortization of customer contract intangible assets 7.2 Interest expense, net 14.6 Forecasted EBITDA $ 40.2 1) Amounts of EBITDA, net income and timing vary, which affect the potential future EBITDA and associated deprecation and interest at DKL. Actual amounts are based on timing, performance of the assets, DKL’s growth plans and valuation multiples for such assets at the time of any transaction. 34

Non-GAAP Reconciliations of Adjusted EBITDA Three Months Ended December 31, Reconciliation of Net Income (Loss) to Adjusted EBITDA 2018 2017 (Unaudited) Reported net income (loss) attributable to Delek $ 121.6 $ 211.1 Add: Interest expense, net 27.9 30.0 Loss on extinguishment of debt - 0 Income tax expense (benefit) - continuing operations 29.6 (140.7) Depreciation and amortization 53.0 47.9 EBITDA $ 232.1 $ 148.3 Adjustments Net inventory valuation (gain) loss 53.4 (14.4) Contracting Termination/Modifications Charges 6.2 - Adjusted unrealized hedging (gain) loss (27.1) 13.1 Environmental Indemnification Proceeds (20.0) - Transaction related expenses 0.9 2.3 Gain on sale of the asphalt business (0.1) - Discontinued operations loss, net of tax 0.2 1.8 Non controlling interest (income) 5.8 14.0 Total adjustments $ 19.3 $ 16.8 Adjusted EBITDA $ 251.4 $ 165.1 35

DKL: Increased Distribution with Conservative Coverage and Leverage Distribution per unit has been increased twenty-four consecutive times since the IPO $0.790 $0.810 $0.705 $0.715 $0.725 $0.750 $0.770 $0.630 $0.655 $0.680 $0.690 $0.550 $0.570 $0.590 $0.610 $0.475 $0.490 $0.510 $0.530 $0.375 $0.385 $0.395 $0.405 $0.415 $0.425 MQD (1) 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 Distributable Cash Flow Coverage Ratio (2)(3)(4) Avg. 1.68x in 2014 Avg. 1.35x in 2015 1.19x in 2018 Avg. 1.35x in 2013 Avg. 1.11x in 2016 Avg. 0.97x in 2017 1.61x 2.02x 1.42x 1.67x 1.39x 1.30x 1.32x 1.35x 1.25x 1.49x 1.47x 1.06x 1.34x 1.25x 1.18x 1.20x 1.29x 1.00x 1.14x 1.02x 0.98x 0.88x 0.97x 0.96x 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 Leverage Ratio (5) 4.53x 4.08x 3.83x 4.60x 4.44x 3.21x 2.69x 2.55x 2.56x 3.00x 3.14x 3.11x 3.49x 3.48x 3.47x 3.70x 3.85x 3.88x 3.72x 3.77x 2.28x 2.40x 1.70x 1.58x 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 1) MQD = minimum quarterly distribution set pursuant to the Partnership Agreement. 2) Distribution coverage based on distributable cash flow divided by distribution amount in each period. Please see reconciliations starting on page 37. 3) 4Q18 based on total distributions paid on February 12, 2019. 4) In 4Q17, the reimbursed capital expenditure amounts in the determination of distributable cash flow were revised to reflect the accrual of reimbursed capital expenditures from Delek US rather than the cash amounts received for reimbursed capital expenditures during the years ended December 31, 2017, 2016 and 2015. 36 5) Leverage ratio based on LTM EBITDA as defined by credit facility covenants for respective periods.

DKL: Reconciliation of Cash Available for Distribution (dollars in millions, except coverage) 2013 (2) 1Q14 (2) 2Q14(2) 3Q14(2) 4Q14(2) 2014 (2) 1Q15(2) 2Q15 3Q15 4Q15 2015 (3) 1Q16 2Q16 3Q16 4Q16 2016 (3) 1Q17 2Q17 3Q17 4Q17 (3) 2017(3) 1Q18 2Q18 3Q18 4Q18 2018 Reconciliation of Distributable Cash Flow to net cash from operating activities Net cash provided by operating activities $49.4 $14.4 $31.2 $20.1 $20.8 $86.6 $15.8 $30.8 $20.2 $1.3 $68.0 $26.4 $31.2 $29.2 $13.9 $100.7 $23.5 $23.9 $30.5 $9.8 $87.7 $23.7 $28.0 $6.0 $90.4 $148.0 Accretion of asset retirement obligations (0.2) (0.1) (0.1) (0.1) 0.0 (0.2) (0.1) (0.1) (0.1) (0.1) (0.3) (0.1) (0.1) (0.1) (0.1) (0.3) (0.1) (0.1) (0.1) (0.1) (0.3) (0.1) (0.1) (0.1) (0.1) (0.4) Deferred income taxes (0.3) 0.0 (0.1) (0.0) 0.2 0.1 (0.2) 0.2 0.0 0.0 (0.0) - - - 0.2 0.2 - (0.1) (0.0) 0.3 0.1 - - - (0.2) (0.2) Gain (Loss) on asset disposals (0.2) - (0.1) - (0.0) (0.1) (0.0) 0.0 - (0.1) (0.1) 0.0 - (0.0) - 0.0 (0.0) 0.0 0.0 0.0 0.0 (0.1) 0.1 (0.7) (0.2) (0.9) Changes in assets and liabilities 8.3 3.4 (6.0) (1.6) 3.0 (1.2) 3.3 (7.3) 3.6 20.5 20.1 (5.4) (7.1) (10.0) 7.7 (14.9) (3.6) 0.9 (8.5) 14.6 3.4 3.7 6.2 28.1 (59.9) (21.9) Distributions from equity method investments 0.3 0.2 1.2 Maint. & Reg. Capital Expenditures (5.1) (0.8) (1.0) (0.8) (3.9) (6.5) (3.3) (3.9) (3.5) (2.7) (13.4) (0.7) (0.9) (0.7) (3.6) (5.9) (2.2) (2.1) (0.7) (4.4) (9.4) (0.3) (1.0) (2.4) (3.5) (7.2) Reimbursement for Capital Expenditures 0.8 - - - 1.6 1.6 1.6 1.8 2.0 0.2 5.5 0.2 0.2 0.4 2.4 3.3 0.9 0.5 0.4 1.7 3.5 0.4 0.3 1.3 0.9 2.9 Distributable Cash Flow $52.9 $17.0 $24.0 $17.7 $21.8 $80.3 $17.1 $21.4 $22.2 $19.0 $79.8 $20.4 $23.3 $18.8 $20.6 $83.0 $18.4 $23.0 $21.6 $21.9 $85.0 $27.3 $33.5 $32.4 $27.6 $121.5 Distribution Coverage Ratio (1) 1.35x 1.61x 2.02x 1.42x 1.67x 1.68x 1.25x 1.49x 1.47x 1.18x 1.35x 1.20x 1.29x 0.98x 1.00x 1.11x 0.88x 1.06x 0.97x 0.96x 0.97x 1.14x 1.34x 1.25x 1.02x 1.19x Total Distribution (1) $39.3 $10.5 $11.9 $12.4 $13.1 $47.9 $13.7 $14.4 $15.1 $16.1 $59.3 $17.1 $18.1 $19.3 $20.5 $75.0 $21.0 $21.8 $22.3 $22.8 $87.9 $24.0 $25.0 $26.0 $26.9 $101.9 1) Distribution based on actual amounts distributed during the periods; does not include LTIP accrual. Coverage is defined as cash available for distribution divided by total distribution. 2) Results in 2013, 2014 and 2015 are as reported excluding predecessor costs related to the dropdown of the tank farms and product terminals at both Tyler and El Dorado during the respective periods. 3) In 4Q17, the reimbursed capital expenditure amounts in the determination of distributable cash flow were revised to reflect the accrual of reimbursed capital expenditures from Delek US rather than the cash amounts received for reimbursed capital expenditures during the years ended December 31, 2017, 2016 and 2015. 37 Note: May not foot due to rounding and annual adjustments that occurred in year-end reporting.

DKL: Income Statement and Non-GAAP EBITDA Reconciliation 2013(1) 1Q14(1) 2Q14 3Q14 4Q14 2014 (1) 1Q15(2) 2Q15 3Q15 4Q15 2015 1Q16 2Q16 3Q16 4Q16 2016 1Q17 2Q17 3Q17 4Q17 2017 1Q18 2Q18 3Q18 4Q18 2018 Net Revenue $907.4 $203.5 $236.3 $228.0 $173.3 $841.2 $143.5 $172.1 $165.1 $108.9 $589.7 $104.1 $111.9 $107.5 $124.7 $448.1 $129.5 $126.8 $130.6 $151.2 $538.1 $167.9 $166.3 $164.1 $159.3 $657.6 Cost of Sales (811.4) (172.2) (196.6) (194.1) (134.3) (697.2) (108.4) (132.5) (124.4) (71.0) (436.3) (66.8) (73.1) ($73.5) ($88.8) (302.2) (92.6) (85.0) ($89.1) ($106.1) (372.9) (119.0) (106.0) (105.6) (98.4) (429.1) Operating Expenses (excluding depreciation and amortization presented below) (25.8) (8.5) (9.5) (10.2) (9.7) (38.0) (10.6) (10.8) (11.6) (11.7) (44.8) (10.5) (8.7) ($9.3) ($8.8) (37.2) (10.4) (10.0) ($10.7) ($12.3) (43.3) (12.6) (14.9) (14.5) (15.4) (57.4) Depreciation and Amortization (6.3) (5.8) (12.1) Contribution Margin $70.3 $22.8 $30.2 $23.7 $29.3 $106.0 $24.5 $28.8 $29.1 $26.2 $108.6 $26.8 $30.0 $24.7 $27.2 $108.7 $26.5 $31.8 $30.8 $32.8 $121.9 $36.3 $45.3 $37.8 $39.6 $159.1 Operating Expenses (excluding depreciation and amortization presented below) (0.9) ($0.4) (1.3) Depreciation and Amortization (10.7) (3.4) (3.5) (3.7) (3.9) (14.6) (4.0) (4.7) (4.5) (5.9) (19.2) (5.0) (4.8) ($5.4) ($5.6) (20.8) (5.2) (5.7) ($5.5) ($5.5) (21.9) (6.0) (7.0) (0.5) (0.4) (13.9) General and Administration Expense (6.3) (2.6) (2.2) (2.5) (3.3) (10.6) (3.4) (3.0) (2.7) (2.3) (11.4) (2.9) (2.7) ($2.3) ($2.3) (10.3) (2.8) (2.7) ($2.8) ($3.6) (11.8) (3.0) (3.7) (3.1) (7.4) (17.2) Gain (Loss) on Asset Disposal (0.2) - (0.1) - - (0.1) - - - (0.1) (0.1) 0.0 - ($0.0) $0.0 0.0 (0.0) 0.0 ($0.0) ($0.0) (0.0) - 0.1 (0.7) (0.2) (0.8) Operating Income $53.2 $16.8 $24.4 $17.5 $22.1 $80.8 $17.1 $21.1 $21.8 $17.9 $77.9 $19.0 $22.5 $17.0 $19.2 $77.7 $18.5 $23.4 $22.6 $23.7 $88.1 27.3 34.7 32.6 31.1 $125.8 Interest Expense, net (4.6) (2.0) (2.3) (2.2) (2.1) (8.7) (2.2) (2.6) (2.8) (3.0) (10.7) (3.2) (3.3) ($3.4) ($3.7) (13.6) (4.1) (5.5) ($7.1) ($7.3) (23.9) (8.1) (10.9) (11.1) (11.2) (41.3) (Loss) Income from Equity Method Invesments (0.1) (0.3) (0.1) (0.6) (0.2) (0.2) ($0.3) ($0.4) (1.2) 0.2 1.2 $1.6 $1.9 5.0 0.8 1.9 1.9 1.5 6.2 Income Taxes (0.8) (0.1) (0.3) (0.2) 0.5 (0.1) (0.3) (0.1) (0.1) 0.6 0.2 (0.1) (0.129) ($0.1) $0.3 (0.1) (0.1) (0.1) ($0.2) $0.6 0.2 (0.1) (0.1) (0.1) (0.2) (0.5) Net Income $47.8 $14.7 $21.8 $15.1 $20.5 $72.0 $14.6 $18.3 $18.6 $15.3 $66.8 $15.4 $18.9 $13.2 $15.3 $62.8 $14.6 $19.0 $16.9 $18.9 $69.4 $20.0 $25.6 $23.3 $21.3 $90.2 EBITDA: Net Income $47.8 $14.7 $21.8 $15.1 $20.5 $72.0 $14.6 $18.3 $18.6 $15.3 $66.8 $15.4 $18.9 $13.2 $15.3 $62.8 $14.6 $19.0 $16.9 $18.9 $69.4 $20.0 $25.6 $23.3 $21.3 $90.2 Income Taxes 0.8 0.1 0.3 0.2 (0.5) 0.1 0.3 0.1 0.1 (0.6) (0.2) 0.1 0.1 0.13 (0.28) 0.1 0.1 0.1 0.2 ($0.6) (0.2) 0.1 0.1 0.1 0.2 0.5 Depreciation and Amortization 10.7 3.4 3.5 3.7 3.9 14.6 4.0 4.7 4.5 5.9 19.2 5.0 4.8 5.4 5.6 20.8 5.2 5.7 5.5 5.5 21.9 6.0 7.0 6.7 6.3 26.0 Amortization of customer contract intangible assets - - - - - - - - - - - - - - - - - - - - - 0.6 1.8 1.8 1.8 6.0 Interest Expense, net 4.6 2.0 2.3 2.2 2.1 8.7 2.2 2.6 2.8 3.0 10.7 3.2 3.3 3.4 3.7 13.6 4.1 5.5 7.1 7.3 23.9 8.1 10.9 11.1 11.2 41.3 EBITDA $63.8 $20.2 $27.9 $21.2 $26.1 $95.4 $21.1 $25.7 $26.1 $23.6 $96.5 $23.7 $27.1 $22.0 $24.4 $97.3 $23.9 $30.3 $29.7 $31.1 $115.0 $34.7 $45.4 $43.0 $40.7 $163.9 1) Results in 2013 and 2014 are as reported excluding predecessor costs related to the dropdown of the tank farms and product terminals at both Tyler and El Dorado during the respective periods. 2) Results for 1Q15 are as reported excluding predecessor costs related to the 1Q15 dropdowns. Note: May not foot due to rounding. 38

Investor Relations Contact: Assi Ginzburg Keith Johnson Executive Vice President, CFO Vice President of Investor Relations 615-224-1158 615-435-1366