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| 8-K - 8-K DK INVESTOR PRESENTATION 10.03.18 - Delek US Holdings, Inc. | dk-8kxinvestorpresentation.htm |
Exhibit 99.1 Delek US Holdings, Inc. Wolfe Research Utilities & Energy Conference Presentation October 2018
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, 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 unlock value, and the estimated savings from the Alon USA Energy, Inc. (“ALJ”) and Alon USA Partners LP (“ALDW”) transactions; the ability to add flexibility and increase margin potential at the Krotz Springs refinery; improved product netbacks; our ability to complete the alkylation project at Krotz Springs 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: risks and uncertainties related to the ability to successfully integrate the businesses of Delek US, ALJ and ALDW; 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 close the pipeline joint venture, obtain commitments and construct the 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"), 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. EBITDA, 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, 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, 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 and distributable cash flow to their most directly comparable financial measures calculated and presented in accordance with U.S. GAAP in the appendix. 2
Investment Overview • Current Price: $43.12/share(1) Overview (NYSE: DK) • Market Capitalization: $3.7 billion(1) • NYSE: DKL: (Market cap $827mm) Own 63.4%, including 2% GP(2) • Operating model built to benefit from crude oil differentials and IMO’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 gas and distillate yields and low residual yields • Focus on growing midstream platform to support Permian position Company Initiatives to Create • Permian Gulf Coast (PGC) crude oil long haul pipeline joint venture project announced Long-Term Value • Krotz Springs alkylation project expected $45-50 million annualized EBITDA and future potential dropdown of approximately $32 million annualized EBITDA(3) • Repurchased $100 million of Delek shares in 3Q; YTD approximately $215 million • Increased regular quarterly dividend(4): Cash Returns to Shareholders • 2Q18 increased by 25% to $0.25/share; following a 33% increase in 1Q18 to $0.20/share • June 30, 2018 balance sheet: Flexible Financial Position to • Delek US: $1.1 billion of cash; $2.0 billion of debt Support Growth • Includes $5.2 million cash and $737.1 million debt of DKL • Net debt (excl. DKL) of $177.8 million 1) Based on price per common share as of close of trading on October 1, 2018. 2) As of June 30, 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 slides 24 and 25 for a reconciliation of forecasted net income to forecasted EBITDA. 3 4) Quarterly dividends mentioned are quarterly dividends per share declared in referenced periods.
Integrated Company with Asset Diversity and Scale Strategically located assets with Permian Basin exposure Source 207,000 bpd from Permian Basin Refining (1) Logistics (2) Asphalt Retail Renewables • 7th largest independent • 10 terminals 6 asphalt terminals located • Approximately 300 Approx. 23m gallons refiner • Approximately 1,290 in: stores biodiesel: • 302,000 bpd in total miles of pipeline • El Dorado, AR • Southwest US locations • Crossett, AR • El Dorado, AR • 11.4 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 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. 4
Permian Basin Outlook Production continues to grow while incremental takeaway capacity outlook is uncertain (1) • Steady growth has continued in production Average Annual Crude Oil Production (Mbpd) (2) • Drilling supported by improved technology and low and WTI-Midland Price costs 7.00 $64.76 $65.98 70.00 $61.57 $60.72 $57.91 • Midland prices still support production growth 6.00 60.00 $49.88 5.00 50.00 • Production may outpace incremental expansion in 2019 Current production 4.00 40.00 • In 2017 and 2018 Permian production outpaced Aug 2018: 3.5m bpd initial forecasts 3.00 5.8 30.00 5.2 4.6 • DUCs have grown at a rapid rate to 3,630 2.00 4.0 20.00 3.4 • Short time to finish well with low capex costs 1.00 2.5 10.00 - - • In past cycles, not all pipelines were completed 2017 2018E 2019E 2020E 2021E 2022E • During 2015 – 2017, 56% of announced pipeline (1) takeaway capacity was cancelled Drilled but Uncompleted Wells • Average pipeline capacity was also smaller 4,000 30% 3,500 25% • Not every announced pipeline will be built 3,000 20% 2,500 • Announced pipelines in past year are very large 15% 2,000 • Locking in sufficient commitments is more 10% 1,500 challenging 1,000 5% • Pipeline operators would prefer one full pipeline 500 0% rather than two half-full pipelines 0 -5% 3/14 6/14 9/14 3/15 6/15 9/15 3/16 6/16 9/16 3/17 6/17 9/17 3/18 6/18 12/14 12/15 12/16 12/17 • Any shortfall in the takeaway balance can create volatility 12/13 in differentials DUCs Incremental DUCs of New Drills % (Rolling 12-Month) 1) Source: Company estimates; current production based on EIA for August 2018, August Drilling Productivity Report, 2018 Drilling Productivity Report. 2) WTI Midland price source: Argus – September 27, 2018; futures based on ICE/NYMEX curve. 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 $7.80 - $8.05 $6.54 - $6.79 $1.10 $0.20 • Current break-even transport economics for exporting from $0.84 (2) $0.20 Cushing approximately $6.67 - $7.92 $2.75 • IMO 2020 expected to increase shipping costs $1.75 $1.00 $1.00 • Cushing inventories expected to build through remainder of $2.75 – $2.75 – 2018 and in 2019 $3.00 $3.00 • Syncrude production, turnarounds, Sunrise pipeline Europe Asia Pipeline Tariff Transport from terminal to water • Global inventories also have declined Shipping Freight Time Value of Money Brent & WTI Backwardation • 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 • Higher flat price environment 50,000 • Steeper backwardation in Brent 40,000 • Increased global refining capacity 30,000 • Higher interest rates on TVM 20,000 • Higher freight rates 10,000 • Declining North Sea production 0 2005 2004 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 Weekly Cushing, OK Ending Stocks excluding SPR of Crude Oil (000 bbls) 1) Market data source: Argus – September 27, 2018; 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 September 14 2018, Weekly Stocks, Area: Cushing, Oklahoma. 6
IMO 2020 Current impact on oil and product markets • Market is NOT pricing a high compliance rate; only ~60-65% WTI-HSFO Spread (1) • Increased compliance will decrease HSFO demand $0 • Excess supply will go into power generation market -$5 -$10 • Expect to see downside pressure on HSFO curve -$15 • Resulting in an increased demand for ULSD -$20 • Expect to see higher ULSD and gas crack spreads -$25 -$30 -$35 Potential range if compliance higher • Gasoline supply may be less than expected -$40 • Delek internal testing showed a minimum VGO feedstock is -$45 required to blend into LSFO Jan-17 Jan-18 Jan-19 Jan-20 Jan-21 Jan-22 Sep-21 Sep-17 Sep-18 Sep-19 Sep-20 Sep-22 May-17 May-18 May-19 May-20 May-21 May-22 • 28-48% range from our hand-blended testing WTI-HSFO Spread WTI-HSFO Spread Forward Curve HSFO2 • 70% of VGO contains gas Delek 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 28% 29% $20 48% $15 58% 14% $10 24% Jan-17 Jan-18 Jan-19 Jan-20 Jan-21 Jan-22 Sep-18 Sep-17 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 – September 27, 2018; futures based on ICE/NYMEX curve. 7
Three Main Drivers for Delek US’ Performance Market Factors Aligning to Extend a Favorable Market for Delek US Through 2022 2018-2019 2019-2022 Wide Midland – Brent crude oil differential driven • IMO 2020 is expected to drive structural market by a combination of factors: changes • Permian production has continued to grow • Decreases marine fuel oil sulfur content to 0.5% supported by current WTI price from 3.5% • Increased light production from shale plays has • Estimated market displacement of 1.5 to 3.0 limited demand from U.S. refining complex million barrels of fuel oil • Limited pipeline takeaway capacity in the • Distillate forward curve has increased ahead of Permian Basin implementation • Transportation cost to clear light crude oil in the export market Delek business model positioned to benefit during this period • Permian sourced crude slate: benefits from wider Midland – Brent crude oil differential • Brent – WTI spread and IMO 2020: WTI-linked crude oil slate; Delek’s refining product yields have high gasoline and distillate cuts • Company initiatives/projects: Delek US’ long-term value creation initiatives 8
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 2% • 75,000 bpd crude oil Crude throughput Throughput WTI 19% 100% WTI • 8.7 complexity Capacity, bpd ETX • 79% 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 14% throughput 100% • WTI 10.2 complexity 207,000 WTI Local AK 21% • Flexibility to process medium 65% 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 29% throughput WTI • 10.5 complexity WTS 71% 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 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 55% WTI 43% WTI • 8.4 complexity linked • Permian Basin, local and Gulf GC Sweet 57% Coast crude oil sources 1) Crude oil slate based on amount received year-to-date as of June 30, 2018. Note: WTI-Brent differential realized through crack spread and capture rates and Midland-WTI differential realized in crude slate. 9
DK Operations Positioned to Benefit from IMO 2020 Delek US positioned to benefit with high value product yields and crude oil slate flexibility 2Q18 Refiners’ Middle Distillates Yield % (1) (2) (4) • Refining system product yields • Middle distillate: average approx. 119,000 bpd of distillate or 44% (5) 44 million barrels annually 40% 40% 37.5% 38% • Gasoline: average approx. 151,000 bpd of gasoline or 55 37% 36% million barrels annually (5) 33% 32% • Low yield of residual products • Crude oil slate has flexibility CVRR DK HFC PSX VLO ANDV MPC PBF • Ability to increase sour crude oil processing to approximately 50% based on market economics 2Q18 Refiners’ Gasoline Yield % (1) (2) (4) • Big Spring refinery currently processes 29% WTS and can increase to 100% 51% 51% 50% • El Dorado refinery flexibility to process light to 48.5% medium sour crude oil (up to 100%) based on 49% 48% 48% economics 47% • Krotz Springs refinery exploring ability to produce low 44% sulfur marine fuel DK ANDV HFC CVRR VLO PBF MPC PSX 2Q18 Refiners’ Residual Yield % (1)(3) 2.7% 4.2% 1) Industry average collected from EIA refinery product yield data. EIA US Refiners DK 2) Middle distillates yield includes distillate fuel oil, kerosene and kerosene-type jet fuel. Latest data up to August 2018. 3) Residual yield includes asphalt and road oil and residual fuel oil from the EIA Latest data up to August 2018. 4) Sourced from Barclays U.S. Independent Refiners Guidebook to Refiners’ Financial & Operating Metrics – 2Q18 Edition, August 15, 2018 10 5) Average calculated from 3Q17 results through 2Q18 results.
Company Initiatives and Projects Delek US’ long-term investments in midstream and its refineries support cash flow generation Gulf Coast CBOB 7.8 – Isobutane Spread • Krotz Springs refinery improvement initiatives $1.40 • Crude oil transportation and flexibility $1.23 $1.21 • Product netback improvement $1.20 $0.97 $1.00 • Alkylation project – approx. $103.0 million cost; $1.00 $0.90 1Q19 expected completion $0.85 $0.84 $0.86 $0.80 $0.69 $0.71 • Estimated annual EBITDA(1) $45-$50 million $0.61 $0.65 $0.69 • Sensitivity: each 10 cents/gallon change in $0.60 spread equals $3.2 million EBITDA change $0.40 Spread,per gallon • Permian Gulf Coast Pipeline $0.20 • JV Partnership with ETP, MMP, and MPLX provides $0.00 expertise, throughput commitments • Supports potential for quicker construction CBOB - Isobutane Base Line Economics and throughput ramp • Currently in open season • 30-inch diameter, 600-mile Permian Gulf Coast pipeline expected to be operational in mid-2020 • Delaware and Midland Basin access • Destinations include access to Gulf Coast terminals Big Spring ETP’s Nederland, TX and MMP’s East Houston, TX • Midstream capital projects to further expand Delek US’ position in the Permian Basin • These investments can be potential future dropdowns to DKL once fully ramped 1) Please see slide 24 for a reconciliation of forecasted net income to forecasted EBITDA. 11
Increased Dropdown Inventory plus Organic Project Creates Platform to Support Logistics Growth Potential Growth for DKL Strong EBITDA Growth Profile Supporting Distribution Growth (1) ($ in millions) • Delek Logistics provides platform to unlock logistics value • Big Spring logistics assets dropdown closed in $204 March 2018, effective March 1 • $40 million est. annualized EBITDA(2) $32 • Completed Paline Pipeline expansion in early $4 $27 Target March 2018 2019 • Capacity to 42,000 bpd from 35,000 bpd $141 • $5 million est. annualized EBITDA uplift • Growing potential logistics assets dropdown inventory: • Krotz Springs assets - $30 to $34 million Note: based on DKL LTM EBITDA + EBITDA / year (2) incremental benefit from Paline and dropdowns • Permian Gulf Coast pipeline from Permian Basin to Houston area being 2Q18 LTM Annualized Big Spring Krotz Springs Total developed EBITDA EBITDA - Paline Dropdown Dropdown Annualized expansion March 2018 Inventory EBITDA (2) (2) March 2018 Potential 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 slides 25 and 26 for a reconciliation of EBITDA of Krotz Springs and Big Spring drop downs, respectively. 12
Main Drivers of Delek’s Expected Performance Delek US positioned to generate strong cash flows to return cash to shareholders Expected Incremental Benefit from Market Changes (2018 Base) and Company Initiatives/Projects $1,400 $168.4 $227.3 $1,200 $16.4 $75.9 $1,000 $1,038 High $800 $791 $600 Low $400 $200 $0 (1) 2018 EBITDA High/Low Estimates 2019 2020 2021 2022 (2) (2) (2) (2) (2) Base Year: 2018 2019 2020 2021 2022 (Change from 2018) (Change from 2018) (Change from 2018) (Change from 2018) Avg Midland Discount: -$6.50 Δ: +$0.80 Δ: +$4.50 Δ: +$4.50 Δ: +$4.50 75 million barrels per year -$60.0 million -$337.5 million -$337.5 million -$337.5 million (3) Avg 5-3-2 ULSD Crack Spread: Δ: +$2.46 Δ: +3.95 Δ: +$3.54 Δ: +$4.74 $16.41 (less WTI-HSFO spread) 80% capture rate 80% capture rate 80% capture rate 80% capture rate 99 million barrels per year $176.1 million $247.2 million $252.2 million $371.1 million (4) Company Initiatives/Projects: Δ: +$50-55 million Δ: $100-110 million Δ: $155-165 million Δ: $190-200 million $0 Incremental Benefit from $168.4 $16.4 $75.9 $227.3 Market Changes 1) Based on NASDAQ IR Insights/Factset as of September 27, 2018. Please see slide 28 for non-GAAP reconciliations. These represent the high and low sell-side estimates and are subject to change based on future updates from each analyst. 2) Differential source: Argus – September 27, 2018; futures based on ICE/NYMEX curve. 3) Formula is the change in crack spreads times the operating leverage of 99 million bbls/yr with an 80% capture rate plus-or-minus any impact of residual products. 13 4) Figures provided are considered forward-looking statements. Please refer to slide 2 for disclaimers surrounding these statements.
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 $909.7 million; net debt excl. DKL of $177.8 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) 12.0x 10.0x 8.0x 6.0x 4.0x 2.0x 0.0x DK-USQ HFC-USQ VLO-USQ ANDV-USQ PBF-USQ MPC-USQ PSX-USQ CVI-USQ 2018 2019 2018 Avg 2019 Avg (1) Based on company filing 10-Q on 8/9/2018 for Q2 2018. Data presented ending June 30, 2018. (2) Based on NASDAQ IR Insights/Factset as of September 27, 2018. 14
Significant Cash Returns to Shareholders Focus on returning cash to shareholders while maintaining financial strength Cash to Shareholders (2)(3) • Target dividend level that can be supported through a cycle • 2Q18 increased regular dividend by 25% to $0.25/qtr(1) • Follows a 1Q18 increased regular dividend by 33% to $0.20/qtr(1) • Share repurchases with surplus cash $115.3 • Purchased $215.3 million shares through 3Q2018, or $100.0 5.7% of current market capitalization $25.0 $25.0 $37.8 $21.3 • Completed $100 million of share repurchases in 2H17 1H18 3Q18 4Q18 2019 2020 Q3 (3) (3) (3) (3) • Actively repurchasing Delek US shares Dividend Share Repurchases Total Dollars Returned to Shareholders (% of Average Rolling 6-Month Market Cap) (4) (5) • Financial strength and flexibility exists • Maintain strong balance sheet • Opportunistically delever when cash supports it • Paid off $150MM of convertible debt in 3Q2018 5.0% 2.4% 0.8% • Disciplined growth through opportunistic acquisitions 1.5% • Prefer to purchase during downturn in the cycle 0.9% 1.3% • The only refiner Delek is buying is itself DK Mid-Cap Avg Peer Avg YTD 2Q18 Dividends Repurchases DK Dividends DK Repurchases 1) Quarterly dividends mentioned are quarterly dividends per share declared in referenced periods. 2) Based on company filings from Q1 2018 through Q2 2018. 3) Arrows indicate a possibility of higher share buybacks as relative to prior periods based on comments made by management. Subject to board approval and market conditions. 4) Share repurchase based on Delek US announcement on 9/6/18. This plan does not have an expiration date. 15 5) Calculations include Delek US announced share repurchases and dividends paid in 3Q18 and peers’ calculations are for the first two quarters of 2018 only.
Questions and Answers Significant Organic Focus on Long-Term Growth / Margin Shareholder Returns Improvement Opportunities An Integrated and Permian Focused Diversified Refining, Financial Flexibility Refining System Logistics and Marketing Company Complementary Logistics Systems
Appendix
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 18
Current Delek US Corporate Structure 94.6% Delek US Holdings, Inc. ownership interest (1) NYSE: DK Market Cap: $3.7 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: $840 million(2) 1) As of June 30, 2018, a 5.4% interest in the Delek US ownership interest in the general partner is held by three members of senior management of Delek US. The remaining ownership interest is indirectly held by Delek US. 2) Market cap based on share and unit prices on October 1, 2018. 19
Access to Midland Crude Oil Benefits Margins WTI Midland vs. WTI Cushing Crude Oil Pricing ($ 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-17 Jul-11 Jul-12 Jul-13 Jul-14 Jul-15 Jul-16 Jul-18 Jan-13 Jan-11 Jan-12 Jan-14 Jan-15 Jan-16 Jan-17 Jan-18 Sep-11 Sep-12 Sep-13 Sep-14 Sep-15 Sep-16 Sep-17 Sep-18 Nov-11 Nov-12 Nov-13 Nov-14 Nov-15 Nov-16 Nov-17 Mar-13 Mar-11 Mar-12 Mar-14 Mar-15 Mar-16 Mar-17 Mar-18 May-11 May-12 May-13 May-14 May-15 May-16 May-17 May-18 Source: Argus – as of October 1, 2018 20
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 -$30 Jul-10 Jul-11 Jul-12 Jul-13 Jul-14 Jul-15 Jul-16 Jul-17 Jul-18 Jan-10 Jan-11 Jan-12 Jan-13 Jan-14 Jan-15 Jan-16 Jan-17 Jan-18 Sep-10 Sep-11 Sep-12 Sep-13 Sep-14 Sep-15 Sep-16 Sep-17 Sep-18 Nov-12 Nov-10 Nov-11 Nov-13 Nov-14 Nov-15 Nov-16 Nov-17 Mar-16 Mar-10 Mar-11 Mar-12 Mar-13 Mar-14 Mar-15 Mar-17 Mar-18 May-10 May-11 May-12 May-13 May-14 May-15 May-16 May-17 May-18 1) Source: Platts as of October 1, 2018; 5-3-2 crack spread based on HSD 2) Crack Spreads: (+/-) Contango/Backwardation 21
Robust Synergy Opportunity from DK/ALJ Combination Steady improvement in expected synergies from transaction ($ in millions) New Apr. 2018 Type Description Corporate Cost of Capital Operational Commercial Estimate Estimate Targets $130-$140 • Logistics, purchase and $131 Commercial trading benefits from a • $33-$40 m • $24-$34 m $115-$130 larger platform $105-$120 • Sharing of resources across the platform; $85-$105 Operational improved insurance • $23-$25 m • $21-$24 m and procurement efficiencies • Benefit from Delek US’ financial position to Cost of reduce interest • $35-$36 m • $34-$35 m Capital expense through refinancing efforts • Reducing the number Corporate of public companies; • $39-$39 m • $36-$37 m consolidating functions to improve efficiencies Org. Target Target #2 Target #3 Target #4 Captured To Feb. 2018 Apr. 2018 Aug. 2018 Date 6/30/18 Expect to achieve run-rate synergies of approximately $130-$140 million in 2018; $131 million of annualized synergies captured as of June 30, 2018 22
Financial Strength and Flexibility to Support Initiatives At June 30, 2018 Approximately $1.1 Billion of Cash (1) • Focused on growing business, while maintaining Cash Balance ($MM) financial flexibility $1,133 $1,018 • Closed Alon transaction on July 1, 2017 $932 $689 • At June 30, 2018, cash balance of $1.1 billion $590 and net debt of $909.7 million $383 $430 $287 • Net debt of $177.8 million excluding DKL $219 related cash/debt $40 2010 2011 2012 2013 2014 2015 2016 (3) 2017 Mar 31 Jun 30 • Current balance sheet expected to have 2018 2018 financial flexibility to support: Capitalization as of June 30, 2018 (2) • Capital allocation program focused on $ in millions • Investment in business Current Debt $180.8 • Return to shareholders Long-Term Debt 1,861.7 • Growth over cycle Total Debt $2,042.5 Cash ($1,132.8) Net Debt Delek US Consolidated $909.7 Delek Logistics Total Debt $737.1 Cash ($5.2) Net Debt Delek Logistics $731.9 Net Debt Delek US excluding DKL $177.8 1) Amounts prior to 4Q16 have been adjusted to remove cash associated the retail operations that were sold for $535 million in November 2016. 2) Based on company filings as of 8/8/18. 23
Non-GAAP Reconciliation of Potential Alkylation Project EBITDA(1) Reconcilation of Forecast U.S. GAAP Net Income (Loss) to Forecast EBITDA for Alkylation Project ($ 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. 24
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. 25
Non-GAAP Reconciliations of 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. 26
Non-GAAP Reconciliations of Adjusted EBITDA Three Months Ended June 30, Reconciliation of Net Income (Loss) to Adjusted EBITDA 2018 2017 (Unaudited) Reported net income (loss) attributable to Delek $ 79.1 $ (37.9) Add: Interest expense, net $ 30.6 $ 14.1 Income tax expense (benefit) - continuing operations $ 32.8 $ (27.0) Depreciation and amortization $ 49.2 $ 29.5 EBITDA $ 191.7 $ (21.3) Adjustments Net inventory valuation (gain) loss $ (0.3) $ 10.7 Unrealized hedging loss $ 9.9 $ 6.6 Transaction related expenses $ 2.6 $ 2.5 Gain on sale of the asphalt business $ (13.2) $ - Discontinued operations loss, net of tax $ 0.8 $ - Non controlling interest loss $ 7.6 $ 5.7 Total adjustments $ 7.4 $ 25.5 Adjusted EBITDA $ 199.1 $ 4.2 27
Non GAAP Reconciliations Non GAAP Reconciliation of 2018 Projected Net Income to Projected Earnings before Interest, Taxes, Depreciation and Amortization (EBITDA) (1) $ in millions High Low Net Income $ 586 $ 369 Add: Taxes 166 102 Interest 127 119 Depreciation and Amortization 159 201 Projected EBITDA range $ 1,038 $ 791 1) Based on NASDAQ IR Insights/Factset as of September 27, 2018. These represent the high and low sell-side estimates and are subject to change based on future updates from each analyst. 28
DKL: Increased Distribution with Conservative Coverage and Leverage Distribution per unit has been increased twenty-two consecutive times since the IPO $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)1Q 13 2Q 13 3Q 13 4Q 13 1Q 14 2Q 14 3Q 14 4Q 14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 Distributable Cash Flow Coverage Ratio (2)(3)(4) Avg. 1.68x in 2014 Avg. 1.35x in 2013 Avg. 1.35x in 2015 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 1.18x 1.20x 1.29x 1.00x 1.14x 0.98x 0.88x 0.97x 0.96x 1Q 13 2Q 13 3Q 13 4Q 13 1Q 14 2Q 14 3Q 14 4Q 14 1Q 15 2Q 15 3Q 15 4Q 15 1Q 16 2Q 16 3Q 16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 Leverage Ratio (5) 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 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 slide 32 for reconciliation. 3) 2Q18 based on total distributions to be paid on August 13, 2018. 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 rather than the cash amounts received for reimbursed capital expenditures during the years ended December 31, 2017, 2016 and 2015. 29 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 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 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) 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 - - 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 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 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) 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 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 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 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 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. Note: May not foot due to rounding and annual adjustments that occurred in year-end reporting. 30
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 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 Cost of Goods Sold (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) Operating Expenses (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) 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 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) 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) 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 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 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) (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 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) 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 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 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 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 Amortization of customer contract intangible assets - - - - - - - - - - - - - - - - - - - - - 0.6 1.8 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 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 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. 31
Investor Relations Contact: Kevin Kremke Keith Johnson Executive Vice President, CFO Vice President of Investor Relations 615-224-1323 615-435-1366