Investor Presentation January 2013
2
3
HollyFrontier Investment Highlights 4 Pure play competitive refinery 5 refineries with 443,000 barrels per day refining capacity Attractive niche product markets with advantaged crude supply Rocky Mountains, Southwest and Mid-Continent Strong investment track record with future growth focused on underwritten projects Woods Cross, El Dorado and Tulsa refineries purchased at industry lows on a per barrel basis Strong Financial Performance Industry leading returns on capital Best in class net income per barrel crude capacity Track record of cash return to shareholders Strong Balance Sheet Stable cash flow from HEP through quarterly regular and incentive distributions HFC owns 44% of HEP including the 2% GP interest HFC received approximately $60 million in cash distributions in 2012* *Previously announced Q4 2011 through Q3 2012 quarterly LP and GP distributions, paid in 2012
Footprint of HollyFrontier and HEP Collaboration with HEP provides strategic growth opportunities in logistics and marketing operations 5
Proximity to Growing North American Crude Production Refineries are well-positioned for exposure to the growing supply of lower cost domestic and Canadian crude oil 6 HFC Refining Capacity by PADD Source: Deutsche Bank, Macquarie, Simmons & Co, Canadian Association of Petroleum Producers, Turner, Mason & Co., North Dakota Pipeline Authority, and the EIA. All 5 HFC Refineries Sit Close to Production Growth PADD2 59% PADD3 22% PADD4 19% Crude Production Growth by PADD 2011-2020 -10% 0% 10% 20% 30% 40% 50% 60% 70% 80% PADD1 PADD2 PADD3 PADD4 PADD5 0% 26% 73% 11% -7.5%
- 2,000 4,000 6,000 8,000 10,000 12,000 Canada (conventional and oil sands) Bakken Permian Niobrara Uinta Mississippian Other N. American 2016 2011 11.3 MBPD Crude Growth in our “Backyard” Canadian, Bakken, Permian, Niobrara, Uinta, Mississippi Lime Source: Deutsche Bank, Macquarie, Simmons & Co, Canadian Association of Petroleum Producers, North Dakota Pipeline Authority, and the EIA. *Heavy crude includes High Tan Christina Lake Crude which we began processing as of Q2 2012 7 100% Crude oil “WTI” price based 82% increase in N. American production 58% “backyard basin” production growth 6.2 MBPD
8 Strategic Investment & Acquisition Woods Cross Refinery Expansion Economics Strong track record of buying the right assets at the right time Woods Cross, El Dorado and Tulsa all purchased at industry lows on a per barrel basis High hurdle rate on investments and acquisitions Target AT LEAST 2x our Cost of Capital Focus on underwritten projects often with crude supply and off-take agreements Woods Cross Phase 1 expansion underwritten by Newfield crude supply agreement Continued focus on access to advantaged crudes and new product markets
9 PROJECT ESTIMATED CAPEX PROJECTED EBITDA GENERATION* Woods Cross Phase 1 $225 million $125 million Potential Woods Cross Phase 2 $400-500 million >$200 million *Woods Cross Phase 1 expected EBITDA generation based on an assumed crack spread environment. Woods Cross Phase 2 expected EBITDA generation based on group 2 lubricant cracks. Woods Cross Expansion – Phase 1: Woods Cross refinery expansion from 31,000 BPD to 45,000 BPD Expected payback period of less than 2 years Incremental production to flow down UNEV pipeline to Las Vegas which trades at seasonal premium to Salt Lake Project underwritten by 10 year 20,000 BPD crude supply agreement with Newfield Exploration Company Expected completion: Late 2014 Strategic Investment & Acquisition Woods Cross Refinery Expansion Economics Potential Woods Cross Expansion – Phase 2: Woods Cross refinery expansion from 45,000 BPD to 60,000 BPD Expected payback period of less than 2 years Includes Group 3 Lubricant Processing Targeting crude supply agreement in conjunction with further expansion project Prospective completion: 2016
Capital Expenditure Overview Past investment make legacy refineries stronger Maintenance capital approximately $200 million *2013 projected capex $350m plus $75m spend from 2012 budget Legacy HOC & FTO capital expenditures were combined for periods prior to the 2011 merger. 2011 capital expenditure calculated using 2011 HFC capital expenditure of $374m plus FTO capital expenditure of $42.4m for 2011 period prior to the merger. Does not include capital expenditure attributable to HEP or turnaround costs. 10 $0 $100 $200 $300 $400 $500 $600 2008 2009 2010 2011 2012E 2013E $593 $431 $272 $377 $275 $425* milli o n s
Strong Balance Sheet & Cash Returns 11 $2.3 billion cash balance as of Sept. 30, 2012 $471 million outstanding debt excluding nonrecourse HEP debt $286.8 million 9.875% June 2017 senior notes callable Sept 2013 Total debt to capital ratio 7% as of 9/30/12* Continued commitment to returning excess cash to shareholders *Excluding HEP debt which is nonrecourse **Includes updated buyback details from Q3 2012 earnings call on 11/7 and announced dividends to date Since the July 2011 merger we have returned over $1.1 billion in capital to shareholders $0 $100 $200 $300 $400 $500 $600 $700 $800 $900 2011 YTD 2012 Buyback Dividend $843** $267 milli o n s
Cash Returns to Shareholders *Dividends are split adjusted reflecting HFC’s two-for-one stock split announced August 3, 2011. 12 February May August November 2011 $0.075* $0.075* $0.0875* $0.10 2012 $0.10 $0.15 $0.15 $0.20 Increased regular dividend 4 times since the merger, raising it 166% February May August September November 2011 $0.50* $0.50 2012 $0.50 $0.50 $0.50 $0.50 $0.50 Declared 7 special dividends since the merger Announced 2 share repurchase programs of $350 million each January 2012 Announced the authorization of a $350 million share repurchase program replacing the $100 million share repurchase program announced in September 2011 June 2012 Announced the authorization of a $350 million share repurchase program in addition to the share repurchase program announced in January
Cash Return to Shareholders LTM Cash Yield to Shareholders *WNR includes the $1.50 and $1.00 special dividend issued in November and December 2012; DK includes $0.10 special dividend declared in December 2012 Last Twelve Months includes YTD 2012 dividends declared and excludes cash dividends in the same period through 2011. Data from public filings and press releases. As of 12/31/2012 stock prices. See page 26 for calculations. 13 0.0% 1.0% 2.0% 3.0% 4.0% 5.0% 6.0% 7.0% 8.0% 9.0% 10.0% WNR* HFC DK* VLO MPC AJL PSX TSO PBF 9.7% 6.7% 2.4% 1.9% 1.9% 0.9% 0.8% 0.6% 0%
Best In Class Returns on Capital Employed Pro Forma HollyFrontier Returns on Invested Capital (Average 2007-2011)* 5-year average ROIC calculated by taking the average of ROIC’s for the years 2007-2011. ROIC calculated by dividing net income by the sum of total debt and total equity. For HFC, legacy HOC/FTO earnings, debt & equity were combined for 5-year calculations. *PSX and MPC are 3- and 4-year averages, respectively, based on historical ROCE data provided by the companies. **PBF is a 4-year average, formed on March 1, 2008 so 2008 data is March 1 through Dec 31st. See page 26 for calculations. 14 R O C E 0.0% 2.0% 4.0% 6.0% 8.0% 10.0% 12.0% 14.0% 16.0% 18.0% HFC MPC* PSX* TSO DK VLO PBF** WNR ALJ 17.2% 9.8% 7.7% 4.8% 3.7% 3.3% 1.0% 0.2% 0.2%
Strong Financial Metrics vs Peers Net Income per Barrel of Crude Capacity HFC earnings per bbl strongest in peer sector (2007-2011) HFC earnings calculated by adding legacy HOC plus FTO earnings for periods prior to the merger. *MPC & PSX data based on a 3-year average, PBF based on 4-year average See page 26 for calculations. 15 D o lla rs p er b ar re l
Business not Built on WTI/Brent Spread Between 2001-2010, WTI traded on average at a $1.00 PREMIUM to Brent Between 2001-2010: Average ROIC 22% Average NI/BBL $2.69 -10.0% 0.0% 10.0% 20.0% 30.0% 40.0% 50.0% 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 ROIC Source: Bloomberg HFC financials calculated by adding legacy HOC plus FTO for periods prior to the merger. See page 26 for calculations. 16
HEP Growth: Distributable Cash Flow Since Inception 17 $0 $20 $40 $60 $80 $100 $120 2005 2006 2007 2008 2009 2010 2011 2012 $41 $47 $51 $60 $72 $91 $100 $112** HFC received over $60m in cash distributions for 2012* milli o n s *Q4 2011 through Q3 2012 announced quarterly LP and GP distributions paid in 2012 **9 months YTD
Value of HFC’s LP & GP Interests in HEP 18 *Based on a range of recent HEP unit prices on the NYSE for valuation purposes. NYSE closing price on 12/31/2012 was $65.78. Methodology: • GP values are equal to quarterly GP IDR cash flow (for Q3 2012) on an annualized basis minus the $5m GP giveback for the next 3 years (as part of the HEP UNEV purchase transaction) times the above range of commonly used market multiples. GP IDR cash flow is approximately $4.9MM per quarter. These values do not reflect actual after tax value to HFC. • Approximate limited partner unit value estimated using a range based on recent market price & general partner value estimated using a commonly used range of Wall Street market multiples applied to incentive distributable cash flow. These values do not reflect actual after tax value to HFC. LP INTEREST*: HEP Unit Price 63.78$ 65.78$ 67.78$ HFC owns 12.1m common units (millions): 772$ 796$ 820$ GP INTEREST: Quarterly GP IDR cash flow: Annualized Q3 IDR cashflow (mill ions): 19.6$ Multiple of GP cash flow: 15X 20X 25X Current GP Interest IDR Distributions (millions): 294$ 392$ 490$ HEP VALUE TO HFC (millions): 1,066$ 1,310$
HollyFrontier Corporation (NYSE: HFC) 2828 N. Harwood, Suite 1300 Dallas, Texas 75201 (214) 954-6510 www.hollyfrontier.com Julia Heidenreich, Investor Relations Julia.Heidenreich@hollyfrontier.com 214-871-3422 Blake Barfield, Investor Relations Blake.Barfield@hollyfrontier.com 214-954-6506 19
Appendix 20
Mid-Continent: El Dorado & Tulsa Refineries The Mid-Continent Region comprises our Tulsa and El Dorado Refineries and has a combined crude oil processing capacity of 260,000 BPSD. Product Mix Gasolines, 46% Diesel fuels, 32% Jet fuels, 7% Asphalt, 4% Lubricants, 4% Other, 7% Crude and Feedstocks Sour crude oil, 6% Sweet crude oil, 76% Heavy sour crude oil, 10% Other feedstocks and blends, 8% Mid-Continent Sales of Refinery Produced Products 268,320 BPD • Located in El Dorado, Kansas • 135,000 BPSD capacity and Nelson Complexity rating of 11.8 • Processes sour and heavy (Canadian) crude oils into high value light products • Distributes to high margin markets in Colorado and Mid-Continent/Plains states • Tulsa West and Tulsa East facilities are located less than two miles apart in Tulsa, Oklahoma and are operated as an integrated facility through interconnecting pipelines • 125,000 BPSD capacity and Nelson Complexity rating of 14.0 • Processes predominantly sweet crude oil with up to 10,000 BPD of heavy Canadian crudes • Distributes to the Mid-Continent states and also sells its specialty lubricants, which are high value products that provide a higher margin, throughout the United States and Central and South America TULSA REFINERIES EL DORADO REFINERY 21
Southwest: Navajo Refinery The Southwest Region consists of our Navajo Refinery and has a crude oil processing capacity of 100,000 BPSD. In addition, we manufacture and market commodity and modified asphalt products through the Southwest Region. Southwest Sales of Refinery Produced Products 100,660 BPD • Located in Artesia, New Mexico and operated in conjunction with a refining facility 65 miles east in Lovington, New Mexico • 100,000 BPSD capacity and Nelson Complexity rating of 11.8 • Processes sour and heavy crude oils into high value light products • Distributes to high margin markets in Arizona, New Mexico and West Texas Product Mix Gasolines, 53% Diesel fuels, 35% Asphalt, 5% Other, 7% Crude and Feedstocks Sour crude oil, 78% Sweet crude oil, 2% Heavy sour crude oil, 9% Other feedstocks and blends, 11% NAVAJO REFINERY 22
Rocky Mountain: Woods Cross and Cheyenne Refineries The Rocky Mountain Region comprises of our Cheyenne and Woods Cross Refineries and has a combined crude oil processing capacity of 83,000 BPSD. Rocky Mountain Sales of Refinery Produced Products 73,980 BPD • Located in Cheyenne, Wyoming • 52,000 BPSD capacity and Nelson Complexity rating of 8.9 • Processes sour and heavy Canadian crude oils into high value light products • Distributes to high margin Eastern Rockies and Plains states • Located in Woods Cross, Utah (near Salt Lake City) • 31,000 BPSD capacity and Nelson Complexity rating of 12.5 • Processes regional sweet and lower cost black wax crude as well as Canadian sour crude oils • Distributes to high margin markets in Utah, Idaho, Nevada, Wyoming, and eastern Washington Product Mix Gasolines, 54% Diesel fuels, 32% Asphalt, 7% Other, 7% Crude and Feedstocks Sour crude oil, 2% Sweet crude oil, 48% Heavy sour crude oil, 31% Black wax crude oil, 10% CHEYENNE REFINERY WOODS CROSS REFINERY 23
Holly Energy Partners Holly Energy Partners owns and operates substantially all of the refined product pipeline and terminalling assets that support our refining and marketing operations in the Mid- Continent, Southwest and Rocky Mountain regions of the United States. • 2,800 miles of crude oil and petroleum product pipelines • 12 million barrels of refined product and crude oil storage • 26 terminals and loading rack facilities in 9 Western and Mid-Continent states • 25% joint venture interest in SLC Pipeline, LLC — a 95-mile crude oil pipeline system that serves refineries in the Salt Lake City area • 75% joint venture interest in UNEV Pipeline, LLC – a 400-mile refined products pipeline system connecting Salt Lake area refiners to the Las Vegas product markets. HEP PRODUCTS 24
Feedstock Flexibility* • High WTI/WTS ($3 or higher) • Low WTI/WCS ($8 or less) • WTI/Brent Range ($10 to $20) • Low WTI/WTS ($2 or less) • High WTI/WCS ($20 or higher) • WTI/Brent Range ($10 to $20) • Low WTI/WTS ($2 or less) • Low WTI/WCS ($8 or less) • WTI/Brent Range ($20 or higher) *Please note these are current and estimated maximum crude rates and are subject to change based on a variety of factors. 25
Financial Metrics* 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 Average WTI/Brent (SNAPWTIB) $ 1.11 $ 1.04 $ 2.40 $ 3.35 $ 1.57 $ 0.33 $ (0.28) $ 1.34 $ (0.47) $ (0.57) $ 1.00 ROIC 29.1% 5.2% 7.9% 20.8% 44.0% 45.0% 45.3% 21.8% -2.3% 4.8% 22% NI/BBL $ 2.23 $ 0.41 $ 0.57 $ 1.59 $ 4.45 $ 6.28 $ 7.39 $ 3.61 $ (0.55) $ 0.88 $ 2.69 * HollyFrontier Corporation debt excludes HEP debt; All amounts are based on publicly-available financial statements, which we have assumed to be accurate. 26 Company 2011 ROIC 2010 ROIC 2009 ROIC 2008 ROIC 2007 ROIC 5 Yr. Ave ROIC HFC 16.4% 4.8% -2.3% 21.8% 45.3% 17.2% MPC 19.0% 5.0% 4.0% 11.0% 9.8% PSX 14.0% 7.0% 2.0% 7.7% TSO 10.0% -1.0% -3.0% 6.0% 12.0% 4.8% DK 15.5% -11.0% 0.0% 3.0% 11.0% 3.7% VLO 8.7% 1.0% -9.0% -5.0% 21.0% 3.3% PBF 22.0% -10.0% -33.0% 25.0% 1.0% ALJ 2.9% -10.0% -8.0% 5.0% 11.0% 0.2% WNR 8.2% -1.0% -19.0% 3.0% 10.0% 0.2% Net Income/BBL crude capacity 2011 2010 2009 2008 2007 5 yr ave HFC 8.23 0.88 -0.55 3.61 7.39 3.91 MPC 4.81 1.28 1.06 2.38 PSX 3.37 1.49 0.26 1.71 DK 3.09 -3.65 0.03 1.21 4.40 1.02 TSO 2.25 -0.12 -0.58 1.15 2.36 1.01 VLO 2.61 0.41 -2.17 -1.19 5 31 0.99 PBF 1.29 -1.13 -2.09 3.17 0.31 WNR 2.41 -0.31 -4.29 0.79 2.79 0.28 ALJ 0.46 -1.39 -1.36 1.46 1.67 0.17 LTM Cash Yield LTM dividend Dec 31st Close WNR* 9.7% 2.7400$ 28.19$ HFC 6.7% 3.1000$ 46.55$ DK* 2.4% 0.6000$ 5.32$ VLO 1.9% 0.6500$ 34.12$ MPC 1.9% 1.2000$ 63.00$ AJL 0.9 0.1600$ 18.09$ PSX 0.8 0.4500$ 53.10$ TSO 0.6 0.2700$ 44.05$ PBF 0% -$ 29.05$
Definitions Non GAPP measurements: We report certain financial measures that are not prescribed or authorized by U. S. generally accepted accounting principles ("GAAP"). We discuss management's reasons for reporting these non-GAAP measures below. Although management evaluates and presents these non-GAAP measures for the reasons described below, please be aware that these non-GAAP measures are not alternatives to revenue, operating income, income from continuing operations, net income, or any other comparable operating measure prescribed by GAAP. In addition, these non-GAAP financial measures may be calculated and/or presented differently than measures with the same or similar names that are reported by other companies, and as a result, the non-GAAP measures we report may not be comparable to those reported by others. Refining gross margin or refinery gross margin: the difference between average net sales price and average costs of products per barrel of produced refined products. This does not include the associated depreciation, depletion and amortization costs. Refining gross margin or refinery gross margin is a non-GAAP performance measure that is used by our management and others to compare our refining performance to that of other companies in our industry. This margin does not include the effect of depreciation, depletion and amortization. Other companies in our industry may not calculate this performance measure in the same manner. Our historical refining gross margin or refinery gross margin is reconciled to net income under “Reconciliation to Amounts Reported Under Generally Accepted Accounting Principles” of HollyFrontier Corporation’s 2011 10-K filed February 29, 2012. Net Operating Margin: Net operating margin is a non-GAAP performance measure that is used by our management and others to compare our refining performance to that of other companies in our industry. This margin does not include the effect of depreciation, depletion and amortization. Other companies in our industry may not calculate this performance measure in the same manner. Our historical net operating margin is reconciled to net income under “Reconciliation to Amounts Reported Under Generally Accepted Accounting Principles” of HollyFrontier Corporation’s 2011 10-K filed February 29, 2012. EBITDA: Earnings before interest, taxes, depreciation and amortization, which we refer to as EBITDA, is calculated as net income plus (i) interest expense net of interest income, (ii) income tax provision, and (iii) depreciation, depletion and amortization. EBITDA is not a calculation provided for under accounting principles generally accepted in the United States; however, the amounts included in the EBITDA calculation are derived from amounts included in our consolidated financial statements. EBITDA should not be considered as an alternative to net income or operating income as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity. EBITDA is not necessarily comparable to similarly titled measures of other companies. EBITDA is presented here because it is a widely used financial indicator used by investors and analysts to measure performance. EBITDA is also used by our management for internal analysis and as a basis for financial covenants. Our historical EBITDA is reconciled to net income under “Reconciliation to Amounts Reported Under Generally Accepted Accounting Principles” of HollyFrontier Corporation’s 2011 10-K filed February 29, 2012. Debt-To-Capital: A measurement of a company's financial leverage, calculated as the company's long term debt divided by its total capital. Debt includes all long-term obligations. Total capital includes the company's debt and shareholders' equity. 5 Year Return on Invested Capital: A measurement which for our purposes is calculated using the 5 year average Net Income divided by the sum of the 5 year average of Total Equity and Long Term Debt. We consider ROIC to be a meaningful indicator of our financial performance, and we evaluate this metric because it measures how effectively we use the money invested in our operations. IDR: Incentive Distribution Rights BPD: the number of barrels per calendar day of crude oil or petroleum products. BPSD: the number of barrels per stream day of crude oil or petroleum products. MMSCFD: million standard cubic feet per day. Gas Oil Hydrocracker: a refinery unit which uses catalyst at high pressure and temperature and in the presence of hydrogen to convert high boiling point hydrocarbons to light transportation fuels and low sulfur FCC feedstock. Solvent deasphalter / residuum oil supercritical extraction (“ROSE”): a refinery unit that uses a light hydrocarbon like propane or butane to extract non asphaltene heavy oils from asphalt or atmospheric reduced crude. These deasphalted oils are then further converted to gasoline and diesel in the FCC process. The remaining asphaltenes are either sold, blended to fuel oil or blended with other asphalt as a hardener.. 27