PRE PREL LIMINA IMINARY RY W WO ORKING RKING DRAF DRAFT T – – S SUB UBJECT JECT TO TO FURTHE FURTHER R RE REV VIE IEW W A AND ND MOD MODIFICA IFICATIO TION N Exhibit (c)(3)(B) PROJECT APPLE DISCUSSION MATERIALS June 26, 2023

PRELIMINARY WORKING DRAFT – SUBJECT TO FURTHER REVIEW AND MODIFICATION Table of Contents I. Situation Update 2 II. Review of Management Projections 8 Tab A: HEP 9 Tab B: DINO 14 III. Appendix 21 1

PRELIMINARY WORKING DRAFT – SUBJECT TO FURTHER REVIEW AND MODIFICATION I. SITUATION UPDATE 2

PRELIMINARY WORKING DRAFT – SUBJECT TO FURTHER REVIEW AND MODIFICATION Market Performance and Implied Proposal | “Then” vs. “Now” 5/3/23 (“Then”) 6/21/23 (“Now”) Change (%) DINO Unit Price $41.91 $44.54 +6.3% HEP Unit Price $15.92 $18.24 +14.6% Spot Exchange Ratio 0.3799x 0.4095x +7.8% Implied Value at Proposal (0.3714x) $15.57 $16.54 +6.3% (2.2%) (9.3%) Premium / Discount vs. HEP Price (2.2%) +3.9% Premium / Discount vs. Unaff. HEP price HEP Peers | LT&S +15.4% HEP Peers | Small Cap. (19.1%) DINO Peers | Large Cap. +1.1% DINO Peers | SMID Cap. +8.8% Note: Market data as of June 21, 2023. LT&S Peers include: DKL, NS, PAA. Small Cap MLP peers include CAPL, GEL, GLP, MMLP, USDP. Large Cap Refining peers include MPC, PSX, VLO. SMID 3 Cap Refining peers include CVI, DK, PARR, PBF, VTNR. Source: FactSet, public disclosure. Peer Trading Perf.

Volume (000) Volume (000) PRELIMINARY WORKING DRAFT – SUBJECT TO FURTHER REVIEW AND MODIFICATION HEP and DINO Trading Analysis Since Proposal HEP Price Performance and Volume Since Proposal DINO Price Performance and Volume Since Proposal $48.00 8,000 $19.00 8,000 LT&S: HEP: +15% $18.24 +15% $47.00 SMID Cap. 7,000 7,000 Refining: $18.00 +9% XR: $46.00 +8% 6,000 6,000 DINO: $17.00 XR: $45.00 $44.54 +8% +6% 5,000 5,000 $44.00 Large Cap. $16.00 Refining: +1% $15.92 $43.00 4,000 4,000 MMP/OKE $15.00 $42.00 Announcement 3,000 3,000 Unaffected 30-Day $41.91 ADTV: 2,547 $41.00 $14.00 2,000 2,000 $40.00 $13.00 1,000 1,000 983,200-unit Small Cap. $39.00 trade at $16.44 MLPs: (19%) Unaffected 30-Day ADTV: 90 $12.00 -- $38.00 -- Volume DINO Volume HEP LT&S Peers Small Cap. MLP Peers Exchange Ratio Large Cap. Refining SMID Cap. Refining Unaffected 30-Day ADTV (in '000s) Exchange Ratio Unaffected 30-Day ADTV (in '000s) Note: Market data as of June 21, 2023. LT&S Peers include: DKL, NS, PAA. Small Cap. MLP peers include CAPL, GEL, GLP, MMLP, USDP. Large Cap. Refining peers include MPC, PSX, VLO. 4 SMID Cap. Refining peers include CVI, DK, PARR, PBF, VTNR. Source: FactSet, company disclosure. Unit Price ($) | Indexed to HEP Share Price ($) | Indexed to DINO

PRELIMINARY WORKING DRAFT – SUBJECT TO FURTHER REVIEW AND MODIFICATION Exchange Ratio Analysis | HEP / DINO The spot exchange ratio has traded up 10% vs. the Proposal Exchange Ratio Analysis Proposal vs. 0.460x Unaffected Date Exchange Ratio Ref. Period Current (06/21/23) 0.4095x (9.3%) (5/3/2023) VWAP Since Proposal 0.4136x (10.2%) 0.440x Unaffected Close (05/03/2023) 0.3799x (2.2%) Unaffected 30-Day VWAP 0.3719x (0.1%) Unaffected 90-Day VWAP 0.3648x 1.8% Unaffected 180-Day VWAP 0.3419x 8.6% 0.420x Unaffected 1-Year VWAP 0.3475x 6.9% Benefits HEP 0.4095x 0.400x 0.380x 0.3799x 0.3719x 0.3714x 0.3648x 0.360x 0.3475x 0.3419x 0.340x 0.320x Benefits DINO 0.300x 0.280x Jun-22 Sep-22 Nov-22 Jan-23 Apr-23 Jun-23 HEP/DINO Unaffected 30-Day VWAP Unaffected 90-Day VWAP Unaffected 180-Day VWAP Unaffected 1-Year VWAP Proposal Unaffected Close (5/3/23) 5 Note: Market data as of June 21, 2023. Source: FactSet, public disclosure.

PRELIMINARY WORKING DRAFT – SUBJECT TO FURTHER REVIEW AND MODIFICATION Summary of Intrepid’s Due Diligence to Date ▪ May 26, 2023 – Intrepid provides initial due diligence and data request list to DINO/HEP ▪ June 12, 2023 – in-person management presentation with DINO/HEP management ▪ June 13, 2023 – Intrepid receives access to the virtual dataroom ▪ June 13, 2023 – DINO/HEP provide initial responses to Intrepid’s due diligence items ▪ June 15, 2023 – call between Intrepid and Barclays to discuss data requests ▪ June 16, 2023 – Intrepid provides follow-up due diligence and data request items to DINO/HEP ▪ June 22, 2023 – call between Intrepid and DINO/HEP to discuss the financial forecast, model assumptions/drivers and other remaining financial diligence items ▪ As of June 22, 2023, Intrepid and Gibson Dunn have submitted ~120 due diligence and data request items, of which ~80 have been addressed ▪ Remaining key diligence items include: – Additional DINO forecast detail – Supporting detail for certain forecast assumptions – Sensitivity analysis 6

PRELIMINARY WORKING DRAFT – SUBJECT TO FURTHER REVIEW AND MODIFICATION Key Diligence Focus Areas & Value Drivers (1) Segment Key Financial Stats Selected Diligence Topics ▪ Crack spread assumptions and comparison vs. benchmarks (e.g., Gulf Coast 3-2-1, DINO West/MidCon Indicators) ▪ ’23E – ’28E EBITDA: $9.9bn (58% of total)▪ Utilization and capture rates vs. historical performance Refining ▪ “Mid-cycle” EBITDA: ▪ Turnaround schedule, capital requirements and impact on throughput / $1.34bn/yr. utilization ▪ Hydrogen supply to Navajo refiner vs. Cheyenne RD unit ▪ ’23E – ’28E EBITDA: ▪ Crack spread assumptions and comparison vs. benchmarks (e.g., DINO $2.4bn (14% of total) Group I, II, III Base Oil Indicators) Lubricants ▪ ’23E – ’28E EBITDA ▪ McKinsey improvements to EBITDA (16% of total lubricants EBITDA) CAGR: 7% ▪ ’23E – ’28E EBITDA: $2.4bn (14% of total)▪ Volume and rate assumptions HEP ▪ ’23E – ’28E EBITDA ▪ Contract expirations / renewals CAGR: 3% ▪ ’23E – ’28E EBITDA: ▪ EBITDA growth from ($74mm) in ’22A to $400mm in ’28E $1.9bn (11% of total) Renewables ▪ Pricing assumptions, including RINs, BTC/PTC and LCFS ▪ ’23E – ’28E EBITDA ▪ Utilization and capture rates CAGR: 40% ▪ ’23E – ’28E EBITDA: $0.5bn (3% of total)▪ EBITDA growth from $63mm in ’22A to $112mm in ’28E Marketing ▪ ’23E – ’28E EBITDA ▪ Volumetric growth CAGR: 13% 7 (1) Segment contribution includes segment G&A; excludes corporate, other, and eliminations. Source: DINO management.

PRELIMINARY WORKING DRAFT – SUBJECT TO FURTHER REVIEW AND MODIFICATION II. REVIEW OF MANAGEMENT PROJECTIONS 8

PRELIMINARY WORKING DRAFT – SUBJECT TO FURTHER REVIEW AND MODIFICATION TAB A: HEP 9

PRELIMINARY WORKING DRAFT – SUBJECT TO FURTHER REVIEW AND MODIFICATION Key Forecast Assumptions – HEP • Projection model includes bottoms-up revenue build by segment (i.e., pipelines, terminals, refinery processing units), including a breakout of affiliate vs. third-party revenues • Projected throughput volumes are implied by DINO refining model assumptions and management estimates for third-party volumes – Downtime and turnarounds derived from historical performance and planned turnarounds (typically 5-year cycle) Revenue • All contracts are renewed at similar rates and volumes, with the exception of the Malaga and Roadrunner contracts – Malaga – ~$9.5mm annual revenue impact – Roadrunner – ~$6mm annual revenue impact • Contract rates escalated at 13.5% PPI in July 2023 and 2% PPI in following years, subject to individual contract inflation caps • $272mm of capex from 2023E – 2028E • No growth capex other than $3mm in 1H23A for Moriarty terminal butane blending project – Future growth opportunities mentioned in the Management Presentation are excluded (gasoline storage at Cheyenne; butane transloading at Cedar City) • Maintenance capex of $30mm – $32mm per year • Turnaround capex of $3mm and $30mm in 2024E (El Dorado hydrogen unit) and 2028E (Woods Cross crude unit), respectively Capital • $7mm of capex in 2023E related to Osage Pipeline release Assumptions – Oil release in July 2022 and resumed operations in 3Q22; remediation efforts are underway • $40mm of aggregate capex related to bring the Midcon Product system to desired operating condition from 2024E – 2027E ($10mm p.a.) – Estimates for actual capex could range from $20mm – $60mm and work is ongoing – ~$1.5mm EBITDA impact to HEP, or implied ~27x investment multiple – Alternatively, the shutdown cost is $4mm (subject to further diligence) 10

PRELIMINARY WORKING DRAFT – SUBJECT TO FURTHER REVIEW AND MODIFICATION Key Forecast Assumptions – HEP (Cont’d) • Quarterly distributions held flat at $0.35/unit ($1.40/unit annualized) throughout forecast – Coverage ratio peaks at 2.3x in 2027E and averages 2.1x during the forecast period • Capex and distributions are fully-funded by cash flow Financing • All excess cash used to repay RCF ($652mm balance as of 3/31/2023A); cash builds on balance sheet thereafter Assumptions – Gross and net leverage reach 1.7x and 0.6x, respectively by year-end 2028E • Bonds are refinanced at similar rates • $15mm minimum cash balance • Quarterly projections provided through 2023E and annually through 2028E • Equity earnings expected to reach ~$25mm in 2025E and remain flat thereafter Other – Distributions from equity method investments assumed to equal equity earnings 11

PRELIMINARY WORKING DRAFT – SUBJECT TO FURTHER REVIEW AND MODIFICATION HEP | Financial Projection Summary Adjusted EBITDA and Distributable Cash Flow ($mm) Capex ($mm) ’23E – ’28E EBITDA CAGR: 2.2% ’23E – ’28E DCF CAGR: 3.7% $511 $497 $477 $480 $474 $77 $458 $415 $62 $25 $400 $44 $398 $42 $42 $42 $41 $378 $30 $360 $349 $21 $0 $332 $10 $10 $10 $10 $307 $10 $3 $31 $31 $32 $32 $32 $32 $30 2022A 2023E 2024E 2025E 2026E 2027E 2028E 2022A 2023E 2024E 2025E 2026E 2027E 2028E Maintenance Capex Growth & JV Investment Adjusted EBITDA Distributable Cash Flow Turnaround Capital MidCon Capital DPU ($) and Coverage (x) Leverage – End of Period (x) 3.8x 2.1x 2.3x 2.2x 2.0x 2.0x 1.9x 3.1x 1.7x 2.5x $1.40 $1.40 $1.40 $1.40 $1.40 $1.40 $1.40 2.1x 1.9x 1.8x 1.7x 3.7x 3.0x 2.5x 2.1x 1.6x 1.1x 0.6x 2022A 2023E 2024E 2025E 2026E 2027E 2028E 2022A 2023E 2024E 2025E 2026E 2027E 2028E Gross Leverage Net Leverage Distribution Per Unit Coverage 12 Source: Management guidance, public disclosure.

PRELIMINARY WORKING DRAFT – SUBJECT TO FURTHER REVIEW AND MODIFICATION HEP | Estimates Summary: 2023E – 2028E Adjusted EBITDA ($mm) Distributable Cash Flow ($mm) # of Brokers 3 3 2 0 0 0 # of Brokers 2 2 0 0 0 0 $511 $497 $480 $480 $400 $475 $398 $460 $477 $474 $378 $458 $360 $463 $466 $356 $447 $415 $457 $336 $448 $349 $435 $332 $307 $313 $313 $289 $271 2022A 2023E 2024E 2025E 2026E 2027E 2028E 2022A 2023E 2024E 2025E 2026E 2027E 2028E (1) Total Capex ($mm) Distribution per Unit ($/unit) # of Brokers 2 2 0 0 0 0 # of Brokers 2 2 1 1 1 1 Includes $30mm of Turnaround Capital $77 $1.81 $1.66 Includes $25mm of $1.73 $1.58 $1.51 $1.65 $1.63 Turnaround Capital $62 $1.40 $1.49 $1.60 $1.46 $1.40 $1.40 $1.40 $1.40 $1.40 $1.40 $40 $1.40 $1.40 $42 $42 $42 $38 $44 $41 $39 $36 $35 $38 2022A 2023E 2024E 2025E 2026E 2027E 2028E 2022A 2023E 2024E 2025E 2026E 2027E 2028E Management Consensus Broker Estimate Range Note: Market data as of June 21, 2023. 13 (1) Includes maintenance capex, growth capex and turnaround capital. Source: Company disclosure, Management guidance, Wall Street research.

PRELIMINARY WORKING DRAFT – SUBJECT TO FURTHER REVIEW AND MODIFICATION TAB B: DINO 14

PRELIMINARY WORKING DRAFT – SUBJECT TO FURTHER REVIEW AND MODIFICATION Key Forecast Assumptions – DINO • Forecast based on a bottoms-up build for each of DINO’s seven refineries • EBITDA forecast based on refinery-specific assumptions for (i) crude and product advantages (net of logistics costs) (ii) capture rates (iii) throughput rate and (iv) opex – Crude/product advantages and capture rates held flat during the forecast period – Opex is escalated at 2% annually Refining • Throughput volumes vary by refinery and are impacted by turnarounds – Detailed turnaround schedule provided through 2028E • Includes $35mm of asphalt / trucking EBITDA in 2023E; grown at 3% CAGR through 2028E • SG&A escalated annually at 2% • Volumes forecasted to grow at 10% annually through 2028E • Marketing EBITDA forecast driven by rack uplift and credit card margin Marketing – Rack uplift margin and credit card margin held flat at $0.05/gal and $0.01/gal, respectively • SG&A escalated annually at 2% • Forecast based on a bottoms-up build for each of DINO’s three RD units • Includes location-specific assumptions for (i) volume (ii) capture rate and (iii) opex – Artesia assumes large throughput increase in 2024E (37%) and steady annual growth thereafter (~2%) – Cheyenne assumes large throughput increase in 2024E (21%) and flat volume thereafter Renewables – Parco assumes steady growth (~1.5% per year) through the forecast – For all RD units, capture rate increases from 50% in 2023E to 70% in 2024E and 80% in 2025E and beyond • Opex escalates at varying rates around ~2% • SG&A escalated annually at 2% 15

PRELIMINARY WORKING DRAFT – SUBJECT TO FURTHER REVIEW AND MODIFICATION Key Forecast Assumptions – DINO (Cont’d) • Forecast is derived from base oil and finished product margin • Base oil sales volume declines at 5% CAGR through the forecast period • Finished product volumes increase at 1% CAGR, with declines in third-party finished volumes offset by internal volumes – Internal volumes grow at 10% annually through 2025E and 5% annually thereafter Lubricants • Capture rate held flat at 80% through the forecast • Opex and SG&A escalates at 2% annually • McKinsey identified improvements increase EBITDA by $33mm in 2024E, $65mm in 2025E and $98mm thereafter – Additional detail requested in diligence • $44mm of discretionary capex in 2023E and $100mm per year in 2024E and beyond – Assumes no credit for growth capex spend (subject to further diligence) Capital Program • Sustaining capex (excl. HEP) averages $737mm per year and includes turnarounds – Detailed turnaround schedule has been provided • Certain add-backs to HEP Adjusted EBITDA are eliminated in consolidation (e.g., sales-type lease and tariff cash flow) • DINO to receive $2mm related to the UNEV class B units in 2023E; no additional cash flow forecasted Other • SG&A is included at the segment level; unallocated portion of ~$40mm per year is listed separately • Pro forma synergies estimated at $4mm in 2023E and $5mm in 2024E; escalated at 2% annually thereafter 16

PRELIMINARY WORKING DRAFT – SUBJECT TO FURTHER REVIEW AND MODIFICATION Historical and Projected Gulf Coast 3-2-1 Crack Spread Reflects refinery crude yield based on two barrels of gasoline and one barrel of diesel for every three barrels of crude input Historical and Forecasted Yield ($/Bbl) 15 -'19 Avg. 2020A 2021A 2022A 2023 YTD 2023E 2024E 2025E $15.87 $9.02 $17.93 $36.79 $32.12 Historical Performance $70 DINO Forecast Assumptions $25.00 $22.00 $21.00 (1) Implied by Futures Markets $26.12 $22.40 $21.51 th April 20 , 2020 WTI crude closes at (~$38) $60 $50 $40 Limited futures contracts data available after 2025 $30 $20.00 $20 (2) DINO’s Publicly-stated Mid-cycle Assumption: $14 $10 $0 Jan-15 Oct-17 Aug-20 May-23 Mar-26 Dec-28 Historical Performance DINO Forecast Assumptions Implied by Futures Markets DINO Mid-Cycle Assumption Note: Market data as of June 21, 2023. (1) Reflects average of remaining days in 2023. 17 (2) Reflects Gulf Coast 3-2-1 of $10 plus Brent/WTI spread of $4. Source: Management guidance, FactSet, CME Group.

PRELIMINARY WORKING DRAFT – SUBJECT TO FURTHER REVIEW AND MODIFICATION DINO | Consolidated Financial Projection Summary (1) EBITDA ($mm) (2) Corp/Other: ($38) ($39) ($39) ($40) ($41) ($42) $4,620 $3,191 $2,886 $2,842 $2,602 $2,670 $2,661 $377 $391 $414 $395 $397 $428 $319 $441 $445 $360 $410 $75 $437 $1,307 $400 $395 $258 $361 $62 $2,395 $391 $1,798 $112 $1,685 $70 $1,328 $1,361 $100 $1,318 $79 $89 ($194) 2020A 2021A 2022A 2023E 2024E 2025E 2026E 2027E 2028E Refining Marketing Renewables Lubricants HEP Capex (incl. Turnarounds) ($mm) $1,020 $1,028 $946 $30 $887 $44 $851 $828 $42 $62 $42 $705 $44 $42 $682 $100 $10 $100 $100 $100 $425 $100 $936 $802 $745 $687 $689 $563 2020A 2021A 2022A 2023E 2024E 2025E 2026E 2027E 2028E DINO Sustaining DINO Discretionary HEP Discretionary HEP Sustaining (3) Unlevered FCF ($mm) $3,938 $2,171 $2,000 $1,965 $1,896 $1,774 $1,810 $279 ($619) 2020A 2021A 2022A 2023E 2024E 2025E 2026E 2027E 2028E (1) Historical metrics are as presented by management. (2) Adjusted to reflect full consolidation of HEP. 18 (3) Calculated as EBITDA less Capex (incl. Turnarounds). Source: Management, Company disclosure.

PRELIMINARY WORKING DRAFT – SUBJECT TO FURTHER REVIEW AND MODIFICATION DINO | Consolidated Estimates Summary: 2023E – 2028E (1)(2) EBITDA ($mm) # of Brokers 11 10 4 2 1 0 $4,620 $3,473 $3,371 $3,191 $2,758 $2,994 $2,842 $2,602 $2,670 $2,886 $2,661 $2,666 $2,396 $2,228 $2,723 $2,018 $2,354 $2,096 $1,725 $1,808 2022A 2023E 2024E 2025E 2026E 2027E 2028E Capex ($mm) # of Brokers 3 3 2 1 1 0 $1,045 $1,020 $946 $1,019 $887 $920 $990 $851 $828 $879 $831 $808 $705 $757 $808 $682 $727 2022A 2023E 2024E 2025E 2026E 2027E 2028E Management Consensus Broker Estimate Range Note: Market data as of June 21, 2023. (1) Historical metrics are as presented in the Management Presentation. 19 (2) 2023E Management EBITDA adjusted to fully consolidate HEP. Consensus and broker estimate ranges adjusted to include ~53% of respective HEP EBITDA metrics. Source: Company disclosure, Management guidance, Wall Street research.

PRELIMINARY WORKING DRAFT – SUBJECT TO FURTHER REVIEW AND MODIFICATION DINO | Turnaround Schedule Total Turnaround Duration (days) 382 382 45 45 35 35 62 62 253 45 44 44 49 49 74 154 152 (1) 42 45 45 45 37 29 34 27 27 42 36 34 75 75 55 47 39 2023E 2024E 2025E 2026E 2027E 2028E Puget Sound Navajo Woods Cross El Dorado PCLI Parco Casper Tulsa 20 Source: Management guidance. (1) Duration for additional required turnaround has not been determined by management.

PRELIMINARY WORKING DRAFT – SUBJECT TO FURTHER REVIEW AND MODIFICATION III. APPENDIX 21

PRELIMINARY WORKING DRAFT – SUBJECT TO FURTHER REVIEW AND MODIFICATION HEP | Financial Forecast Detail '23E-'28E ($ in millions, except where noted) 1Q23A 2Q23E 3Q23E 4Q23E 2023E 2024E 2025E 2026E 2027E 2028E CAGR (+) Third Party Revenue $26 $29 $30 $33 $119 $128 $130 $132 $134 $137 2.9% (+) DINO Revenue 117 113 130 128 489 511 511 516 533 546 2.2% Total Revenue $143 $143 $160 $162 $608 $639 $641 $649 $667 $683 2.4% (-) Operating Expenses (52) (60) (59) (54) (224) (239) (247) (248) (250) (252) (-) Sales, General & Administrative (5) (5) (4) (4) (18) (19) (20) (20) (20) (20) (1) (+) Other 1 2 3 4 10 14 17 17 17 17 Book EBITDA $88 $79 $101 $107 $375 $395 $391 $397 $414 $428 (+) Income from Sales-type Leases 20 23 23 23 89 89 87 87 87 87 (+) Tariffs -- 1 1 1 3 6 8 8 8 8 (-) Adjusted Operating Expenses -- (3) (3) (3) (10) (13) (13) (13) (13) (13) (2) (+/-) Other 0 -- -- -- 0 -- -- -- -- -- Adjusted EBITDA $108 $100 $121 $128 $458 $477 $474 $480 $497 $511 2.2% (-) Maint. & Turnaround Capex (2) (7) (12) (9) (30) (44) (42) (42) (42) (62) (-) Interest Expense (26) (24) (26) (23) (99) (84) (71) (60) (55) (50) (-) Tariffs -- (1) (1) (1) (3) (6) (8) (8) (8) (8) (+) Opex Adjustment -- 3 3 3 10 13 13 13 13 13 (-) Taxes (0) (0) (0) (0) (0) (1) (1) (1) (1) (1) (3) (+/-) Other 4 (2) (2) (2) (3) (6) (5) (5) (5) (5) Distributable Cash Flow $84 $68 $84 $96 $332 $349 $360 $378 $400 $398 3.7% (-) Growth Capex (5) (3) (1) (1) (10) -- -- -- -- -- (+) Tariffs -- 1 1 1 3 6 8 8 8 8 (-) Changes in Net Working Capital (15) 25 (10) (5) (5) 6 (1) (2) (2) (2) (4) (+/-) Other (7) 8 1 8 10 14 12 12 12 12 Levered Free Cash Flow $57 $100 $74 $99 $330 $375 $380 $397 $419 $417 Per Unit Metrics Distribution per Unit $0.35 $0.35 $0.35 $0.35 $1.40 $1.40 $1.40 $1.40 $1.40 $1.40 --% DCF per Unit $0.66 $0.54 $0.66 $0.76 $2.62 $2.76 $2.85 $2.98 $3.16 $3.15 3.7% Coverage 1.9x 1.5x 1.9x 2.2x 1.9x 2.0x 2.0x 2.1x 2.3x 2.2x Balance Sheet and Credit Metrics Cash $7 $15 $15 $15 $15 $15 $15 $118 $360 $600 Debt 1,540 1,492 1,462 1,408 1,408 1,209 1,006 889 889 889 Net Debt 1,533 1,477 1,447 1,393 1,393 1,194 991 771 529 289 Total Debt / LTM EBITDA 3.5x 3.4x 3.3x 3.1x 3.1x 2.5x 2.1x 1.9x 1.8x 1.7x Net Debt / LTM EBITDA 3.5x 3.4x 3.2x 3.0x 3.0x 2.5x 2.1x 1.6x 1.1x 0.6x (1) Reflects Equity in Earnings from Join Ventures, Income Attributable to NCI and gains on asset sales. (2) Reflects adjustments to NCI. (3) Reflects reimbursables, stock-based compensation and other cash adjustments. 22 (4) Reflects other cash reconciling items. Source: Management guidance.

PRELIMINARY WORKING DRAFT – SUBJECT TO FURTHER REVIEW AND MODIFICATION DINO | Financial Forecast Detail Pricing Forecast 2023E 2024E 2025E 2026E 2027E 2028E ($ in millions, except where noted) WTI $/bbl $83.00 $80.00 $78.00 $78.00 $78.00 $78.00 Gulf Coast WTI 3-2-1 $/bbl 25.00 22.00 21.00 20.00 20.00 20.00 Renewable Diesel Indicator $/gal $1.74 $1.95 $2.14 $2.24 $2.24 $2.24 VGO Based Base Oil Crack Group I $/bbl $40.00 $33.00 $25.00 $24.00 $24.00 $24.00 Group II $/bbl 45.00 36.00 28.00 27.00 27.00 27.00 Group III $/bbl 130.00 120.00 110.00 100.00 100.00 100.00 Marketing Rack Uplift Margin $/gal $0.05 $0.05 $0.05 $0.05 $0.05 $0.05 Gross Margin 2023E 2024E 2025E 2026E 2027E 2028E Refining $4,409 $3,852 $3,780 $3,465 $3,540 $3,542 Marketing 85 94 103 114 125 138 Renewables 213 399 506 538 545 553 Lubricants 763 813 872 908 922 935 Total Gross Margin $5,471 $5,158 $5,261 $5,025 $5,133 $5,168 Opex (2,215) (2,260) (2,305) (2,351) (2,398) (2,446) SG&A (404) (412) (421) (429) (438) (446) Corporate, Other & Eliminations EBITDA (38) (39) (39) (40) (41) (42) DINO EBITDA Excluding HEP $2,814 $2,447 $2,495 $2,204 $2,256 $2,233 HEP Book EBITDA $375 $395 $391 $397 $414 $428 DINO Adds Back UNEV Class B NCI 2 -- -- -- -- -- HEP EBITDA $377 $395 $391 $397 $414 $428 DINO Consolidated EBITDA $3,191 $2,842 $2,886 $2,602 $2,670 $2,661 EBITDA by Segment Refining $2,395 $1,798 $1,685 $1,328 $1,361 $1,318 Marketing 62 70 79 89 100 112 Renewables 75 258 361 391 395 400 Lubricants 319 360 410 437 441 445 HEP 377 395 391 397 414 428 (-) Corporate, Other & Eliminations (38) (39) (39) (40) (41) (42) Consolidated EBITDA $3,191 $2,842 $2,886 $2,602 $2,670 $2,661 Capex by Segment DINO Discretionary $44 $100 $100 $100 $100 $100 DINO Sustaining 936 802 745 687 563 689 DINO Total Capex 980 902 845 787 663 789 HEP Discretionary 10 -- -- -- -- -- HEP Sustaining 30 44 42 42 42 62 (1) DINO Consolidated Capex $1,020 $946 $887 $828 $705 $851 (1) Capex includes turnaround capital. 23 Source: Management guidance.

PRELIMINARY WORKING DRAFT – SUBJECT TO FURTHER REVIEW AND MODIFICATION Comparison of Management vs. Consensus | DINO Refining Refining Throughput (kb/d) Gross Refining Margin ($/bbl) # of Brokers 5 5 3 2 2 0 # of Brokers 8 8 5 3 3 1 680 684 677 $26.78 667 661 659 665 659 659 659 $21.10 647 657 $19.38 643 631 647 647 647 $19.33 633 $16.84 620 635 $15.23 $15.23 $15.23 $15.23 $16.47 $17.95 618 $15.57 $14.56 $15.14 $14.60 $13.41 $13.69 $14.52 $13.61 608 $12.51 $12.60 $12.42 $10.54 2022A 2023E 2024E 2025E 2026E 2027E 2028E 2022A 2023E 2024E 2025E 2026E 2027E 2028E Refining Opex ($/bbl) Refining EBITDA ($mm) # of Brokers 6 6 4 2 1 1 # of Brokers 2 2 2 1 1 0 $8.98 $8.63 $8.63 $8.65 $8.60 $4,179 $8.46 $7.96 $8.18 $8.15 $7.69 $8.02 $7.83 $7.75 $8.29 $7.45 $7.39 $7.43 $6.70 $6.18 $6.25 $6.22 $2,222 $2,395 $2,037 $1,684 $1,615 $1,798 $1,685 $1,328 $1,318 $1,361 $1,591 $1,853 $1,399 $1,497 $883 $794 $1,183 2022A 2023E 2024E 2025E 2026E 2027E 2028E 2022A 2023E 2024E 2025E 2026E 2027E 2028E Management Consensus Broker Estimate Range 24 Note: Market data as of June 21, 2023. Source: Bloomberg, Management guidance.

PRELIMINARY WORKING DRAFT – SUBJECT TO FURTHER REVIEW AND MODIFICATION Segment Detail – DINO Refining (West Region) Key Takeaways Crack Spread – West Indicator ($/Bbl) $56.68 • The charts to the right compare the key forecast drivers for the West $45.16 Region refineries vs. historical $33.65 results $31.15 $30.42 $30.64 $29.62 $28.62 $28.62 $28.63 $37.07 – Includes five refineries (Puget $26.99 $26.50 $19.52 Sound, Navajo, Parco, Woods $25.38 $18.18 Cross, Casper) and represents $21.61 $15.99 62% of DINO’s total refining capacity – Further diligence required to 2019A 2020A 2021A 2022A 2023E 2024E 2025E 2026E 2027E 2028E confirm historical calculations are comparable to projections Capture Rate (%) • West Indicator: WTI-based 3-2-1 Mid-cycle capture rate (DINO Investor Presentation) crack spread benchmark specific to DINO’s West Region refineries, as 76% 78% 78% 78% 78% 78% 78% 69% publicly calculated and reported 64% 66% monthly by DINO 64% 53% 70% 60% – Reflects regional pricing of 59% 50% 59% 57% gasoline and diesel 48% – Excludes impact of RINs – Long-term, mid-cycle assumption of ~$29/Bbl is within historical range, but 2019A 2020A 2021A 2022A 2023E 2024E 2025E 2026E 2027E 2028E ~19% higher than 2019A • Capture Rate: Ratio of (i) realized Throughput (MBbls/d) & Utilization (%) gross margin to (ii) benchmark Mid-cycle utilization (DINO Investor Presentation) crack spread 89% 81% 86% 83% 94% – Projected levels are above 70% 376 90% 90% 90% 88% 88% 85% “mid-cycle” levels in DINO 347 public investor presentations 340 – 78% capture rate has not been consistently achieved since 2019 158 149 375 375 375 367 370 357 120 155 • Utilization: Ratio of (i) crude 138 114 148 charge to (ii) refinery capacity 129 111 – Projected utilization is above historical performance 2015-2019 2020A 2021A 2022A 2023E 2024E 2025E 2026E 2027E 2028E th th (1) Historical Range (25 – 75 Percentile) Average 25 (1) Based on quarterly data, except crack spread data, which is monthly. Source: Management guidance, Public disclosure.

PRELIMINARY WORKING DRAFT – SUBJECT TO FURTHER REVIEW AND MODIFICATION Segment Detail – DINO Refining (MidCon Region) Key Takeaways Crack Spread – MidCon Indicator ($/Bbl) • The charts to the right compare the key forecast drivers for the $41.05 MidCon Region refineries vs. historical results $33.18 – Includes two refineries (El $25.85 $20.19 $22.86 $21.86 $19.22 $20.88 $20.86 $20.86 Dorado and Tulsa) and represents 38% of DINO’s total $17.81 $23.47 $16.03 $8.72 refining capacity $15.59 $8.57 $13.24 – Further diligence required to $7.55 confirm historical calculations 2015 - 2019 2020A 2021A 2022A 2023E 2024E 2025E 2026E 2027E 2028E are comparable to projections • MidCon Indicator: WTI-based Capture Rate (%) 3-2-1 crack spread benchmark specific to DINO’s MidCon Mid-cycle capture rate (DINO Investor Presentation) 85% 82% Region refineries, as publicly 75% 75% 75% 75% 75% 75% 69% calculated and reported monthly by 75% 59% 70% DINO 64% 59% – Reflects regional pricing of 64% 62% 51% gasoline and diesel – Excludes impact of RINs 41% 36% – Long-term, mid-cycle assumption of ~$21/Bbl is within historical range, but 2015 - 2019 2020A 2021A 2022A 2023E 2024E 2025E 2026E 2027E 2028E ~30% higher than 2015-2019 average Throughput (MBbls/d) & Utilization (%) • Capture Rate: Ratio of (i) realized gross margin to (ii) benchmark crack spread Mid-cycle utilization (DINO Investor Presentation) 109% 100% – Projected levels are above 70% 99% 93% 305 294 “mid-cycle” levels in DINO 109% 109% 109% 293 273 105% 102% 101% 299 public investor presentations 276 274 257 294 – 75% capture rate has not been 273 94% 252 248 consistently achieved since 2019 283 283 283 266 273 262 • Utilization: Ratio of (i) crude charge to (ii) refinery capacity – Projected utilization is above historical performance 2015 - 2019 2020A 2021A 2022A 2023E 2024E 2025E 2026E 2027E 2028E th th (1) Historical Range (25 – 75 Percentile) Average 26 (1) Based on quarterly data, except crack spread data, which is monthly. Source: Management guidance, Public disclosure.

PRELIMINARY WORKING DRAFT – SUBJECT TO FURTHER REVIEW AND MODIFICATION Segment Detail – DINO Lubricants Key Takeaways VGO Based Base Oil Crack – Group 1 ($/Bbl) $114 • Lubricants cracks experienced dramatic $91 volatility coming out of $65 COVID in 2021 and 2022 $73 $54 $40 $32 $26 $33 • Long-term projections for $43 $25 $24 $24 $24 $22 $21 Group 1 and 2 are largely $13 $10 within pre-COVID ranges '17-'19 Avg. 2020A 2021A 2022A 2023E 2024E 2025E 2026E 2027E 2028E • Group 3 cracks are projected to remain above VGO Based Base Oil Crack – Group 2 ($/Bbl) pre-2021 $122 $97 $76 $75 $60 $45 $34 $36 $28 $28 $27 $27 $27 $44 $21 $20 $14 $8 '17-'19 Avg. 2020A 2021A 2022A 2023E 2024E 2025E 2026E 2027E 2028E VGO Based Base Oil Crack – Group 3 ($/Bbl) $169 $146 $141 $130 $120 $129 $110 $100 $100 $100 $125 $115 $69 $54 $59 $50 $51 $44 '17-'19 Avg. 2020A 2021A 2022A 2023E 2024E 2025E 2026E 2027E 2028E th th (1) 25 – 75 Percentile Average 27 (1) Based on monthly data. Source: Management guidance, Public disclosure.

PRELIMINARY WORKING DRAFT – SUBJECT TO FURTHER REVIEW AND MODIFICATION Segment Detail – DINO Lubricants (Cont’d) Key Takeaways Volume (Kbpd) th th (1) 25 – 75 Percentile Average • Management forecasts growing EBITDA despite 35.5 34.4 34.3 34.7 decreasing volumes 34.0 32.7 32.5 31.0 • Projections include 32.4 31.9 31.6 30.4 26.3 26.2 26.3 26.1 25.8 25.5 separate EBITDA add- back for “McKinsey Identified Improvements” – Represents > 20% of forecasted EBITDA by 2028E – McKinsey adjustments are subject to further 2016 - 2019 2020A 2021A 2022A 2023E 2024E 2025E 2026E 2027E 2028E diligence EBITDA ($mm) McKinsey Identified Improvements $445 $441 $437 $410 $383 $360 $98 $98 $98 $65 $331 $319 $33 $157 $345 $343 $348 $134 $339 $328 2016 - 2019 2020A 2021A 2022A 2023E 2024E 2025E 2026E 2027E 2028E 28 (1) Based on quarterly data. Source: Management guidance, Public disclosure.

PRELIMINARY WORKING DRAFT – SUBJECT TO FURTHER REVIEW AND MODIFICATION Comparison of Management vs. Consensus | DINO Lubricants Lubricants & Specialty Products Segment EBITDA ($mm) # of Brokers 3 3 2 0 0 0 $445 $441 $437 $410 $383 $360 $331 $325 $319 $300 $299 $306 $290 $282 $280 February 2019: $266 $266 Acquired Sonneborn for $655mm at a 9.9x multiple (7.7x incl. synergies) $157 $122 $121 2018A 2019A 2020A 2021A 2022A 2023E 2024E 2025E 2026E 2027E 2028E Management Consensus Broker Estimate Range 29 Note: Market data as of June 21, 2023. Source: Bloomberg, Enverus, Management guidance.

PRELIMINARY WORKING DRAFT – SUBJECT TO FURTHER REVIEW AND MODIFICATION Segment Detail – DINO Renewables Key Takeaways Renewable Diesel Indicator ($/Bbl) • Large step-change in EBITDA forecasted in $2.24 $2.24 $2.24 $2.14 $2.02 $1.95 2024E $1.74 $1.78 – Driven by a combination of volume, capture rate $1.40 and improved profitability from exhaustion of legacy 2022A 2023E 2024E 2025E 2026E 2027E 2028E high-priced feedstocks Volume (MMgal) • Capture rate estimated at 304 309 296 300 292 50% in 2023E, 70% in 245 2024E and 80% in 2025E and beyond 136 2022A 2023E 2024E 2025E 2026E 2027E 2028E EBITDA ($mm) $391 $395 $400 $361 $258 $75 ($74) 2022A 2023E 2024E 2025E 2026E 2027E 2028E th th (1) 25 – 75 Percentile Average 30 (1) Based on monthly data. Source: Management guidance, Public disclosure.

PRELIMINARY WORKING DRAFT – SUBJECT TO FURTHER REVIEW AND MODIFICATION Comparison of Management vs. Consensus | DINO Renewables Renewable Segment EBITDA ($mm) # of Brokers 4 4 3 1 1 1 $400 $395 $391 $361 $268 $265 $258 $263 $261 $262 $211 $195 $103 $107 $75 $57 $45 $34 ($74) 2022A 2023E 2024E 2025E 2026E 2027E 2028E Management Consensus Broker Estimate Range 31 Note: Market data as of June 21, 2023. Source: Bloomberg, Management guidance.

PRELIMINARY WORKING DRAFT – SUBJECT TO FURTHER REVIEW AND MODIFICATION Segment Detail – DINO Marketing Key Takeaways Volume (MMgal) 2,318 • Volumes are forecasted to 2,108 grow at 10% annually 1,916 1,742 1,583 – Management indicated 1,439 1,118 the additional volume could come from a mix of NTIs and market share gains • Rack uplift and credit card 2022A 2023E 2024E 2025E 2026E 2027E 2028E margins are held flat Gross Margin ($mm) $138 $125 $114 $103 $94 $85 $66 2022A 2023E 2024E 2025E 2026E 2027E 2028E EBITDA ($mm) $112 $100 $89 $79 $70 $63 $62 2022A 2023E 2024E 2025E 2026E 2027E 2028E 32 Source: Management guidance, Company disclosure.

PRELIMINARY WORKING DRAFT – SUBJECT TO FURTHER REVIEW AND MODIFICATION Key Forecast Assumptions – DINO Commodity Price Assumptions Refining 2023E 2024E 2025E 2026E 2027E 2028E WTI $/bbl $83.00 $80.00 $78.00 $78.00 $78.00 $78.00 Gulf Coast WTI 3-2-1 $/bbl 25.00 22.00 21.00 20.00 20.00 20.00 D6 RIN $/RIN 1.43 1.65 1.69 1.78 1.78 1.78 D5 RIN $/RIN 1.51 1.73 1.78 1.87 1.87 1.87 3-2-1 RIN Cost $/bbl $5.06 $5.83 $5.98 $6.29 $6.29 $6.29 Gulf Coast WTI 3-2-1, net RINs $/bbl $19.94 $16.17 $15.02 $13.71 $13.71 $13.71 Renewables 2023E 2024E 2025E 2026E 2027E 2028E BOHO Spread $/gal ($2.31) ($2.64) ($2.72) ($2.85) ($2.85) ($2.85) D4 RIN $/RIN 1.54 1.76 1.81 1.90 1.90 1.90 LCFS $/t 100.00 140.00 180.00 200.00 200.00 200.00 BTC / PTC $/gal 1.00 1.00 1.00 1.00 1.00 1.00 Renewable Diesel Indicator $/gal $1.74 $1.95 $2.14 $2.24 $2.24 $2.24 Lubricants 2023E 2024E 2025E 2026E 2027E 2028E VGO Based Base Oil Crack Group I $/bbl $40.00 $33.00 $25.00 $24.00 $24.00 $24.00 Group II $/bbl 45.00 36.00 28.00 27.00 27.00 27.00 Group III $/bbl 130.00 120.00 110.00 100.00 100.00 100.00 Base Oil Crack $/bbl $59.59 $51.26 $42.87 $40.09 $40.09 $40.09 33 Source: Management guidance.

PRELIMINARY WORKING DRAFT – SUBJECT TO FURTHER REVIEW AND MODIFICATION Disclaimer These materials have been prepared by Intrepid Partners, LLC (“Intrepid”) for the Conflicts Committee (the “Committee”) of the Board of Directors of Holly Logistic Services, L.L.C. (the “General Partner”), the ultimate general partner of Holly Energy Partners, L.P. (“HEP”), to whom such materials are directly addressed and delivered. These materials are confidential and may not be used or relied upon by any other person or for any purpose other than as specifically contemplated by a written agreement with Intrepid. These materials have been developed by and are proprietary to Intrepid and were prepared exclusively for the benefit and internal use of the Committee in connection with evaluating the Proposed Transaction with HEP and HF Sinclair Corporation (“DINO”). These materials are based upon information provided by or on behalf of the management of DINO and the General Partner, from public sources, or otherwise reviewed by Intrepid. Intrepid has relied upon and assumes no responsibility for independent investigation or verification of such information and has relied upon such information being complete and accurate in all material respects. To the extent such information includes estimates and forecasts of future performance prepared by or reviewed with management of DINO or the General Partner and/or other potential transaction participants or obtained from public sources, Intrepid has assumed that such estimates and forecasts have been reasonably prepared on bases reflecting the best currently available estimates and judgments of management of DINO, and the General Partner or such other potential transaction participants (or, with respect to estimates and forecasts obtained from public sources, represent reasonable estimates). Actual results may differ materially from such estimates and forecasts. No representation or warranty, express or implied, is made as to the accuracy or completeness of such information, and nothing contained herein is, or shall be relied upon as, a representation or warranty, whether as to the past, the present or the future. The materials and related commentary are not intended to provide the only basis for evaluating, and should not be considered a recommendation with respect to, the consideration paid, the proposed transaction or any transaction or other matter. These materials are also subject to the qualifications and limitations described in any accompanying written opinion letter. These materials were compiled on a confidential basis solely for use by the Committee and may not be relied on by any other party (including stakeholders in either entity), even if such parties are provided a copy of these materials. These materials were prepared without a view to public disclosure or filing thereof under state or federal laws, and may not be redistributed, reproduced, distributed, passed to others, transmitted, quoted or referred to, in whole or in part, without the prior written permission of Intrepid in accordance with the terms of our engagement letter with the Committee. These materials speak only as of the date on the cover and Intrepid assumes no obligation to update these materials or inform any recipient of changed circumstances, events or information. These materials were prepared for a specific use by specific persons and were not prepared to conform with any disclosure standards under securities laws or otherwise. In the ordinary course of its business, each of Intrepid and its affiliates may actively trade or hold the securities of DINO, HEP or other parties involved in a proposed transaction for its own account or for the account of its customers and, accordingly, may at any time hold a long or short position in such securities. Intrepid will receive a fee in connection with delivery of an opinion relating to the proposed transaction. These materials do not constitute, nor do they form part of, an offer or solicitation to sell or purchase any securities or instruments and are not a commitment by Intrepid or any of its affiliates to provide, arrange or underwrite any financing for any transaction or to purchase any security in connection therewith. These materials may not reflect information known to other professionals in other business areas of Intrepid and its affiliates. Intrepid and its affiliates do not provide legal, regulatory, accounting, bankruptcy, securities or tax advice. Any statements contained herein as to tax matters were neither written nor intended by Intrepid or its affiliates to be used and cannot be used by any taxpayer for the purpose of avoiding tax penalties that may be imposed on such taxpayer. Each person should seek legal, regulatory accounting and tax advice based on his, her or its particular circumstances from independent advisors regarding the evaluation and impact of any transactions or matters described herein.