HollyFrontier
Annual Report 2013

Plain-text annual report

H O L L Y F R O N T I E R 2 0 1 3 A N N U A L R E P O R T A N N U A L R E P O R T Edmonton Hardisty Edmonton Hardisty Spokane Spokane PADD IV PADD IV Billings Billings Porta Porta Grand Forks Grand Forks T T e e x x a a c c o o / / B B u u t t t t e e Mountain Home Mountain Home PADD II PADD II Casper Casper Guernsey Guernsey Salt Lake City Salt Lake City Denver Denver Sidney Sidney Omaha Omaha Express Express Platte Platte PADD V PADD V Las Vegas Las Vegas Cedar City Cedar City Bloomfield Bloomfield Albuquerque Albuquerque Moriarty Moriarty Phoenix Phoenix Tucson Tucson El Paso El Paso Orla Orla A NICHE PURE-PLAY REFINER 443,000 capacity 12.1 complexity HollyFrontier refineries HEP terminals Third-party terminals Other HollyFrontier assets Pipelines HEP pipelines UNEV HEP product pipeline Third-party product Third-party crude HollyFrontier pipeline PADD I PADD I Minneapolis Minneapolis Des Moines Des Moines Chicago Chicago Kansas City Kansas City PADD III PADD III J J a a y y h h a a w w k k Wichita Wichita Cushing Cushing Duncan Duncan Wichita Falls Wichita Falls Abilene Abilene Houston Houston PURE-PLAY COMPETITIVE REFINER • Five refineries with 443,000 barrels per stream day refining capacity ATTRACTIVE NICHE PRODUCT MARKETS WITH ADVANTAGED CRUDE SUPPLY • Rocky Mountains, Southwest and Mid-Continent Plains states Edmonton Hardisty Edmonton Hardisty Spokane Spokane PADD IV PADD IV Billings Billings Porta Porta Grand Forks Grand Forks T T e e x x a a c c o o / / B B u u t t t t e e Mountain Home Mountain Home PADD II PADD II Casper Casper Guernsey Guernsey Salt Lake City Salt Lake City Denver Denver Sidney Sidney Omaha Omaha Express Express Platte Platte Minneapolis Minneapolis Des Moines Des Moines Chicago Chicago Kansas City Kansas City PADD V PADD V Las Vegas Las Vegas Cedar City Cedar City Bloomfield Bloomfield Phoenix Phoenix Tucson Tucson Albuquerque Albuquerque Moriarty Moriarty J J a a y y h h a a w w k k Wichita Wichita Cushing Cushing Duncan Duncan Wichita Falls Wichita Falls Abilene Abilene Houston Houston 1 2 4 5 3 Proximity to Growing North American Crude Production All five HFC refineries sit close to production growth. $1.9 BIL CAPITAL RETURNED TO SHAREHOLDERS Since July 2011 merger 6.7% CASH DIVIDEND YIELD LTM Cash Yield – based on January 2, 2013 opening stock price of $47.69 $1.7 BIL CASH AND SHORT-TERM INVESTMENTS in Marketable Securities December 31, 2013 PADD I PADD I 13% RETURN 20% RETURN on Capital Employed (5-year) on Capital Employed (3-year) El Paso El Paso Orla Orla PADD III PADD III HFC* MPC DK WNR TSO VLO ALJ HFC* MPC WNR DK TSO VLO ALJ Based on 5-year and 3-year averages calculated as stockholders’ net income/(total debt + stockholders’ equity). * Reflects combined HOC and FTO financial data for periods prior to merger in July 2011. STRONG INVESTMENT TRACK RECORD • 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 HEP OWNERSHIP • Stable cash flows from HEP through quarterly regular and incentive distributions • HFC owns 39% of HEP including the 2% GP interest • HFC received $71 million in cash distributions in 2013* *Q4 2012 through Q3 2013 quarterly LP and GP distributions, announced and paid in 2013 Increased regular dividend 5 times since merger. Declared 11 special dividends since merger. Dividend Return to Stockholders 300% INCREASE REGULAR SPECIAL Q 1 2011 Q 2 Q 3 Q 4 Q 1 2012 Q 2 Q 3 Q 4 Q 1 2013 Q 2 Q 3 Q 4 $ 0.75 $ 0.75 $ 0.0875 $ 0.10 $ 0.10 0.15 $ $ 0.15 $ 0.20 $ 0.30 $ 0.30 $ 0.30 $ 0.30 – – $ 0.50 $ 0.50 $ 0.50 $ 0.50 $ 0.50 $ 0.50 $ 0.50 $ 0.50 $ 0.50 $ 0.50 $ 0.50 E L D O R A D O R E F I N E R Y • 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 T U L S A R E F I N E R Y • Located in Tulsa, Oklahoma • 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 • Markets high-value specialty lubricants throughout North America and to Central and South America N A V A J O R E F I N E R Y • 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 SOUTHWEST SALES OF REFINERY PRODUCED PRODUCTS 94,830 BPD C H E Y E N N E R E F I N E R Y • 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 W O O D S C R O S S R E F I N E R Y • Located in Woods Cross, Utah (near Salt Lake City) • 31,000 BPSD capacity and Nelson Complexity rating of 12.5 • Processes regional sweet and advantaged waxy crude as well as Canadian sour crude oils • Distributes to high-margin markets in Utah, Idaho, Nevada, Wyoming and eastern Washington H O L L Y E N E R G Y P A R T N E R S • 2,900 miles of crude oil and petroleum product pipelines • 12 million barrels of refined product and crude oil storage • 11 terminals and 10 rack facilities in 10 Western and Mid-Continent states • 75% joint-venture interest in the UNEV Pipeline – a 400-mile refined product pipeline running from Salt Lake City, Utah to Las Vegas, Nevada • 25% joint-venture interest in SLC Pipeline, LLC – a 95-mile crude oil pipeline system that serves refineries in the Salt Lake City area MID-CONTINENT SALES OF REFINERY PRODUCED PRODUCTS 247,030 BPD SOUTHWEST SALES OF REFINERY PRODUCED PRODUCTS 94,830 BPD Crude and Feedstocks n Sour crude oil 72% n Sweet crude oil 8% n Heavy sour crude oil 11% n Other feed- stocks and blends 9% ROCKY MOUNTAIN SALES OF REFINERY PRODUCED PRODUCTS 68,870 BPD Crude and Feedstocks n Sour crude oil 6% n Sweet crude oil 69% n Heavy sour crude oil 16% n Other feedstocks and blends 9% Product Mix n Gasolines 47% n Diesel fuels 31% n Jet fuels 8% n Asphalt 3% n Lubricants 4% n Other 7% Product Mix n Gasolines 51% n Diesel fuels 39% n Asphalt 1% n Other 9% Crude and Feedstocks n Sour crude oil 1% n Sweet crude oil 43% n Heavy sour crude oil 34% n Black wax crude oil 14% n Other feedstocks and blends 8% Product Mix n Gasolines 56% n Diesel fuels 30% n Asphalt 5% n Other 9% T N E N I T N O C - D M I T S E W H T U O S N I A T N U O M Y K C O R The Mid-Continent Region comprises our Tulsa and El Dorado refineries and has a combined crude oil processing capacity of 260,000 BPSD. 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 throughout the Southwest Region. The Rocky Mountain Region comprises our Cheyenne and Woods Cross refineries and has a combined crude oil processing capacity of 83,000 BPSD. Holly Energy Partners owns and operates substantially all of the refined product pipeline and terminalling assets that support our refining and marketing opera- tions in the Mid-Continent, Southwest and Rocky Mountain Regions of the United States. TO OUR SHAREHOLDERS I am pleased to report that 2013 was another strong year for HollyFrontier, a year that included significant financial and operational accomplishments as we delivered healthy earnings results, continued SOLID FINANCIAL RESULTS DRIVEN BY UNDERLYING STRENGTHS The geographic proximity of our refining assets to lower cost feedstocks, and our ability to process both light and heavy crudes continue to be key differentiators for HollyFrontier. While the narrowing of the WTI / Brent crude differential and the market impact of the government’s Renewable Fuel Standard affected our results in 2013, our margins remained strong and we are optimistic about our forward outlook. In 2013 we achieved: • Net Income attributable to HFC stockholders of $735.8 million to return capital to stockholders, • Gross refining margins of $15.99 per produced barrel and successfully completed • Operating cash flow of $869 million major turnaround projects at our refineries. We are proud of what we accomplished in a volatile market and are confident that we are well positioned to continue building on HollyFrontier’s success. • As of December 31, 2013, we had $1.7 billion in cash and short-term investments and approximately $190 million in long-term debt (excluding HEP debt of $808 million) These 2013 financial results demonstrate HollyFrontier’s ability to successfully execute, deliver solid financial performance, and create value for stockholders. We expect contin- ued growth in North American crude oil production, consistent customer demand for our products and we believe that our Company’s fundamental strengths will continue to create attractive opportunities. STRONG TRACK RECORD OF RETURNING CAPITAL TO STOCKHOLDERS In 2013, HollyFrontier returned over $825 million to stockholders through regular quarterly dividends, special dividends and share repurchases. During the year, the Board of Directors increased the Company’s regular quarterly dividend by 50% and approved four special divi- dends. On an annualized basis, the Company’s cash dividend yield is now approximately 7%. In addition, we completed the repurchase of more than $180 million worth of shares under our $700 million share repurchase plan previously approved by the Board. Since completing the HollyFrontier merger in July 2011, the Board has increased the regular dividend by 300% and the Company has returned nearly $2.0 billion in capital to stockholders. Over the last two and half years, we believe we have proven our commitment to returning a significant portion of cash we generate to shareholders. Looking forward, our structural advan- tages should continue to drive strong free cash flow, allowing us to continue with significant dividend and share repurchase distributions driving superior total shareholder returns. INVESTING IN OUR OPERATIONS This was a year of investment and transition for HollyFrontier, as we completed planned turnaround projects at four of our five refineries. While these projects were planned prior to our merger in 2011, moving forward we anticipate staggering these types of projects to better balance production downtime and project management needs across our system. We invested more than $370 million in our facilities in 2013, with the goal of expanding our refining capabilities, improving efficiency of our operations and minimizing environmental impacts by reducing waste, emissions and other releases. We are confident that the invest- ments we are making in our facilities will enable us to achieve stronger margins and drive sustainable long-term value creation. Our 2013 capital investment projects included: • Woods Cross Refinery Expansion Our multi-year expansion program at our facility near Salt Lake City, Utah will increase our capacity to serve the important Las Vegas market through the UNEV Pipeline, as well as Salt Lake City and other markets across 2 HollyFrontier Corporation 2013 Annual Report the Inter-Mountain West. As part of the expansion, we are increasing our capacity to pro- cess locally sourced black wax crude from 10,000 barrels to 24,000 barrels a day. We expect Phase 1, which will increase capacity from 31,000 to 45,000 barrels a day, to be completed in the fourth quarter of 2015. • El Dorado Naphtha Fractionation Ongoing work at our El Dorado refinery will improve liquid yields, enable us to generate hydrogen using Natural Gas as a feedstock rather than crude oil and reduce lower value by-products yields such as fuel gas, propane, butane and benzene by further fractionating our Naphtha stream. This growth project is underway and we expect it to be completed in the spring of 2015. • Holly Energy Partners’ Crude Gathering System Expansion We are expanding our New Mexico gathering capacity from 30,000 barrels per day to 100,000 barrels per day by building 40 miles of new pipeline, bringing 65 miles of existing idled pipeline back into service and adding new connections to major clearing points in Cushing, Oklahoma, Midland, Texas and Crane, Texas. Phases of this project have already been brought online, and we anticipate full completion of the expanded system by mid-year. COMMITTED TO HEALTH, SAFETY AND OUR COMMUNITIES Health, safety and environmental stewardship remain at the center of our business and we put  our employees, contractors and neighboring communities first. As a team, we strive to operate in a safe, reliable and environmentally responsible manner. We are putting tremendous effort into operational training, procedural discipline and process safety. We continue to make key safety initiatives like the Risk-Based Inspection Program and Operational Integrity and Training a top priority. HollyFrontier is made up of 2,662 hardworking employees and we are grateful for their service and dedication. Their hard work enables HollyFrontier to maintain safe and reliable operations. For 2013, we logged a 28% decrease in employee recordable safety inci- dents versus 2012, which in turn represented a 16% improvement versus the prior year. Our goal in terms of safety incidents remains zero. Also during 2013, we actively participated in our com- munities – contributing both our financial resources and our time to make a difference in the lives of the people around us. We feel fortunate to have the support of our customers, the communities that host our operations and our employees, as we engage in our daily work. LOOKING AHEAD This is an exciting time for HollyFrontier as we continue to perform well – both financially and operationally – and take the necessary steps to position our Company for continued long-term success. In the year ahead, we look forward to continuing our focus on operational excellence as we execute on our strategic goals and create value for stockholders. Sincerely, MICHAEL C. JENNINGS Chairman, Chief Executive Officer and President “ Since completing the HollyFrontier merger in July 2011, the Board has increased the reg- ular dividend by 300% and the Company has returned nearly $2.0 billion in capital to stockholders." – MICHAEL C. JENNINGS 3 FINANCIAL HIGHLIGHTS YEAR ENDED DECEMBER 31 Sales and other revenues Income before income taxes Net income attributable to HFC stockholders Net income per common share attributable to HFC stockholders – diluted Cash flows from operating activities Cash flows used for capital expenditures Total assets HFC stockholders’ equity Sales of refined products – barrels per day (“BPD”) Refinery production – BPD Employees 2012 2013 $ 20,090,724,000 $ 20,160,560,000 $ $ $ $ $ 2,787,995,000 1,727,172,000 8.38 1,662,687,000 335,263,000 $ $ $ $ $ 1,159,399,000 735,842,000 3.64 869,174,000 425,127,000 $ 10,328,997,000 $ 10,056,739,000 $ 6,052,954,000 $ 5,999,620,000 443,620 442,730 2,534 446,390 413,820 2,662 09 20 10 104 1,023 1,727 736 Net Income Attributable to HFC Stockholders $ in millions 09 212 09 4,834 10 11 12 13 283 1,338 1,663 869 Cash Flows from Operating Activities $ in millions 10 11 12 13 8,323 15,440 20,091 20,161 Revenues $ in millions 151 226 332 443 414 09 619 09 2,766 697 10 11 12 13 5,204 6,053 6,000 3,050 10 11 12 13 9,576 10,329 10,057 Refinery Production BPD in thousands HFC Stockholders’ Equity $ in millions Total Assets $ in millions 11 12 13 09 10 11 12 13 4 HollyFrontier Corporation 2013 Annual Report UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 _________________________________________________________________ FORM 10-K _________________________________________________________________ (Mark One) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2013 OR For the transition period from __________ to ____________ Commission File Number 1-3876 _________________________________________________________________ HOLLYFRONTIER CORPORATION (Exact name of registrant as specified in its charter) _________________________________________________________________ Delaware (State or other jurisdiction of incorporation or organization) 2828 N. Harwood, Suite 1300 Dallas, Texas (Address of principal executive offices) 75-1056913 (I.R.S. Employer Identification No.) 75201-1507 (Zip Code) (214) 871-3555 Registrant’s telephone number, including area code _________________________________________________________________ Securities registered pursuant to Section 12(b) of the Act: Common Stock, $0.01 par value registered on the New York Stock Exchange. Securities registered pursuant to 12(g) of the Act: None. _________________________________________________________________ Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes No Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15 (d) of the Act. Yes No Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes No Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes No Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. Large accelerated filer Accelerated filer Non-accelerated filer Smaller reporting company Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes No On June 28, 2013, the last business day of the registrant's most recently completed second fiscal quarter, the aggregate market value of the Common Stock, par value $0.01 per share, held by non-affiliates of the registrant was approximately $7.9 billion, based upon the closing price on the New York Stock Exchange on such date. (This is not deemed an admission that any person whose shares were not included in the computation of the amount set forth in the preceding sentence necessarily is an “affiliate” of the registrant.) 198,971,030 shares of Common Stock, par value $.01 per share, were outstanding on February 21, 2014. DOCUMENTS INCORPORATED BY REFERENCE Portions of the registrant's proxy statement for its annual meeting of stockholders to be held on May 14, 2014, which proxy statement will be filed with the Securities and Exchange Commission within 120 days after December 31, 2013, are incorporated by reference in Part III. Table of Content Item TABLE OF CONTENTS Forward-Looking Statements Definitions 1 and 2. Business and properties 1A. Risk Factors 1B. Unresolved staff comments 3. Legal proceedings 4. Mine safety disclosures PART I PART II 5. Market for Registrant's common equity, related stockholder matters and issuer purchases of equity securities 6. Selected financial data 7. Management's discussion and analysis of financial condition and results of operations 7A. Quantitative and qualitative disclosures about market risk Reconciliations to amounts reported under generally accepted accounting principles 8. Financial statements and supplementary data 9. Changes in and disagreements with accountants on accounting and financial disclosure 9A. Controls and procedures 9B. Other information PART III 10. Directors, executive officers and corporate governance 11. Executive compensation 12. Security ownership of certain beneficial owners and management and related stockholder matters 13. Certain relationships and related transactions, and director independence 14. Principal accounting fees and services 15. Exhibits, financial statement schedules PART IV Signatures Index to exhibits 2 Page 3 4 6 21 30 30 31 32 33 34 50 50 54 101 101 101 101 101 101 102 102 102 103 105 Table of Content FORWARD-LOOKING STATEMENTS PART I This Annual Report on Form contains certain “forward-looking statements” within the meaning of the federal securities laws. All statements, other than statements of historical fact included in this Form 10-K, including, but not limited to, those under “Business and Properties” in Items 1 and 2, “Risk Factors” in Item 1A, “Legal Proceedings” in Item 3 and “Management's Discussion and Analysis of Financial Condition and Results of Operations” in Item 7, are forward-looking statements. These statements are based on management's beliefs and assumptions using currently available information and expectations as of the date hereof, are not guarantees of future performance and involve certain risks and uncertainties. Although we believe that the expectations reflected in these forward-looking statements are reasonable, we cannot assure you that our expectations will prove to be correct. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in these statements. Any differences could be caused by a number of factors including, but not limited to: • • • • • • • • • • • • • risks and uncertainties with respect to the actions of actual or potential competitive suppliers of refined petroleum products in our markets; the demand for and supply of crude oil and refined products; the spread between market prices for refined products and market prices for crude oil; the possibility of constraints on the transportation of refined products; the possibility of inefficiencies, curtailments or shutdowns in refinery operations or pipelines; effects of governmental and environmental regulations and policies; the availability and cost of our financing; the effectiveness of our capital investments and marketing strategies; our efficiency in carrying out construction projects; our ability to acquire refined product operations or pipeline and terminal operations on acceptable terms and to integrate any existing or future acquired operations; the possibility of terrorist attacks and the consequences of any such attacks; general economic conditions; and other financial, operational and legal risks and uncertainties detailed from time to time in our Securities and Exchange Commission filings. Cautionary statements identifying important factors that could cause actual results to differ materially from our expectations are set forth in this Form 10-K, including without limitation the forward-looking statements that are referred to above. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements set forth in this Form 10-K under “Risk Factors” in Item 1A and in conjunction with the discussion in this Form 10-K in “Management's Discussion and Analysis of Financial Condition and Results of Operations” under the heading “Liquidity and Capital Resources.” All forward- looking statements included in this Form 10-K and all subsequent written or oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. The forward-looking statements speak only as of the date made and, other than as required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. 3 Table of Content DEFINITIONS Within this report, the following terms have these specific meanings: “Alkylation” means the reaction of propylene or butylene (olefins) with isobutane to form an iso-paraffinic gasoline (inverse of cracking). “Aromatic oil” is long chain oil that is highly aromatic in nature and is used to manufacture tires and industrial rubber products and in the production of specialty asphalt. “BPD” means the number of barrels per calendar day of crude oil or petroleum products. “BPSD” means the number of barrels per stream day (barrels of capacity in a 24 hour period) of crude oil or petroleum products. “Biodiesel” means a alternative fuel produced from renewable biological resources. “Black wax crude oil” is a low sulfur, low gravity crude oil produced in the Uintah Basin in Eastern Utah that has certain characteristics that require specific facilities to transport, store and refine into transportation fuels. “Catalytic reforming” means a refinery process which uses a precious metal (such as platinum) based catalyst to convert low octane naphtha to high octane gasoline blendstock and hydrogen. The hydrogen produced from the reforming process is used to desulfurize other refinery oils and is a primary source of hydrogen for the refinery. “Cracking” means the process of breaking down larger, heavier and more complex hydrocarbon molecules into simpler and lighter molecules. “Crude distillation” means the process of distilling vapor from liquid crudes, usually by heating, and condensing the vapor slightly above atmospheric pressure turning it back to liquid in order to purify, fractionate or form the desired products. “Ethanol” means a high octane gasoline blend stock that is used to make various grades of gasoline. “FCC,” or fluid catalytic cracking, means a refinery process that breaks down large complex hydrocarbon molecules into smaller more useful ones using a circulating bed of catalyst at relatively high temperatures. “Hydrodesulfurization” means to remove sulfur and nitrogen compounds from oil or gas in the presence of hydrogen and a catalyst at relatively high temperatures. “Hydrogen plant” means a refinery unit that converts natural gas and steam to high purity hydrogen, which is then used in the hydrodesulfurization, hydrocracking and isomerization processes. “HF alkylation,” or hydrofluoric alkylation, means a refinery process which combines isobutane and C3/C4 olefins using HF acid as a catalyst to make high octane gasoline blend stock. “Isomerization” means a refinery process for rearranging the structure of C5/C6 molecules without changing their size or chemical composition and is used to improve the octane of C5/C6 gasoline blendstocks. “LPG” means liquid petroleum gases. “Lubricant” or “lube” means a solvent neutral paraffinic product used in commercial heavy duty engine oils, passenger car oils and specialty products for industrial applications such as heat transfer, metalworking, rubber and other general process oil. “MSAT2” means Control of Hazardous Air Pollutants from Mobile Sources, a rule issued by the U.S. Environmental Protection Agency to reduce hazardous emissions from motor vehicles and motor vehicle fuels. “MEK” means a lube process that separates waxy oil from non-waxy oils using methyl ethyl ketone as a solvent. “MMBTU” means one million British thermal units. 4 Table of Content “Natural gasoline” means a low octane gasoline blend stock that is purchased and used to blend with other high octane stocks produced to make various grades of gasoline. “Paraffinic oil” is a high paraffinic, high gravity oil produced by extracting aromatic oils and waxes from gas oil and is used in producing high-grade lubricating oils. “Refinery gross margin” means the difference between average net sales price and average product costs per produced barrel of refined products sold. This does not include the associated depreciation and amortization costs. “Reforming” means the process of converting gasoline type molecules into aromatic, higher octane gasoline blend stocks while producing hydrogen in the process. “Roofing flux” is produced from the bottom cut of crude oil and is the base oil used to make roofing shingles for the housing industry. “ROSE,” or “Solvent deasphalter / residuum oil supercritical extraction,” means 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. “Scanfiner” is a refinery unit that removes sulfur from gasoline to produce low sulfur gasoline blendstock. “Sour crude oil” means crude oil containing quantities of sulfur greater than 0.4 percent by weight, while “sweet crude oil” means crude oil containing quantities of sulfur equal to or less than 0.4 percent by weight. “Vacuum distillation” means the process of distilling vapor from liquid crudes, usually by heating, and condensing the vapor below atmospheric pressure turning it back to a liquid in order to purify, fractionate or form the desired products. “WCS” means Western Canada Select crude oil and is made up of Canadian heavy conventional and bitumen crude oils blended with sweet synthetic and condensate diluents. “WTI” means West Texas Intermediate and is a grade of crude oil used as a common benchmark in oil pricing. WTI is a sweet crude oil and has a relatively low density. “WTS” means West Texas Sour, a medium sour crude oil. 5 Table of Content Items 1 and 2. Business and Properties COMPANY OVERVIEW References herein to HollyFrontier Corporation (“HollyFrontier”) include HollyFrontier and its consolidated subsidiaries. In accordance with the Securities and Exchange Commission's (“SEC”) “Plain English” guidelines, this Annual Report on Form 10- K has been written in the first person. In this document, the words “we,” “our,” “ours” and “us” refer only to HollyFrontier and its consolidated subsidiaries or to HollyFrontier or an individual subsidiary and not to any other person with certain exceptions. Generally, the words “we,” “our,” “ours” and “us” include Holly Energy Partners, L.P. (“HEP”) and its subsidiaries as consolidated subsidiaries of HollyFrontier, unless when used in disclosures of transactions or obligations between HEP and HollyFrontier or its other subsidiaries. This document contains certain disclosures of agreements that are specific to HEP and its consolidated subsidiaries and do not necessarily represent obligations of HollyFrontier. When used in descriptions of agreements and transactions, “HEP” refers to HEP and its consolidated subsidiaries. We merged with Frontier Oil Corporation (“Frontier”) on July 1, 2011. Concurrent with the merger, we changed our name from Holly Corporation (“Holly”) to HollyFrontier and changed the ticker symbol for our common stock traded on the New York Stock Exchange to “HFC.” Accordingly, this document includes Frontier, its consolidated subsidiaries and the operations of the merged Frontier businesses effective July 1, 2011, but not prior to this date. We are principally an independent petroleum refiner that produces high-value refined products such as gasoline, diesel fuel, jet fuel, specialty lubricant products, and specialty and modified asphalt. We were incorporated in Delaware in 1947 and maintain our principal corporate offices at 2828 N. Harwood, Suite 1300, Dallas, Texas 75201-1507. Our telephone number is 214-871-3555 and our internet website address is www.hollyfrontier.com. The information contained on our website does not constitute part of this Annual Report on Form 10-K. A print copy of this Annual Report on Form 10-K will be provided without charge upon written request to the Vice President, Investor Relations at the above address. A direct link to our SEC filings is available on our website under the Investor Relations tab. Also available on our website are copies of our Corporate Governance Guidelines, Audit Committee Charter, Compensation Committee Charter, Nominating / Corporate Governance Committee Charter, Environmental, Health, Safety, and Public Policy Committee Charter and Code of Business Conduct and Ethics, all of which will be provided without charge upon written request to the Vice President, Investor Relations at the above address. Our Code of Business Conduct and Ethics applies to all of our officers, employees and directors, including our principal executive officer, principal financial officer and principal accounting officer. Our common stock is traded on the New York Stock Exchange under the trading symbol “HFC.” On February 21, 2011, we entered into a merger agreement providing for a “merger of equals” business combination between us and Frontier. On July 1, 2011, North Acquisition, Inc., a direct wholly-owned subsidiary of Holly, merged with and into Frontier, with Frontier surviving as a wholly-owned subsidiary of Holly. Subsequent to the merger and following approval by HollyFrontier's post-closing board of directors, Frontier merged with and into HollyFrontier, and HollyFrontier continued as the surviving corporation. This merger combined the legacy Frontier refinery operations consisting of refineries in El Dorado, Kansas (the “El Dorado Refinery”) and Cheyenne, Wyoming (the “Cheyenne Refinery”) with Holly’s legacy refinery operations to form HollyFrontier. The aggregate equity consideration paid in connection with the merger was $3.7 billion. On June 1, 2009, we acquired an 85,000 BPSD refinery located in Tulsa, Oklahoma (the "Tulsa West facility") from an affiliate of Sunoco, Inc. ("Sunoco") for $157.8 million. On December 1, 2009, we acquired a 75,000 BPSD refinery from an affiliate of Sinclair Oil Company ("Sinclair") also located in Tulsa, Oklahoma (the "Tulsa East facility") for $183.3 million. We have integrated certain operations of the Tulsa West and East facilities (collectively, the "Tulsa Refineries"). This resulted in the Tulsa Refineries having an integrated crude processing rate of 125,000 BPSD. HEP, a consolidated variable interest entity ("VIE") as defined under U.S. generally accepted accounting principles ("GAAP"), made several acquisitions between 2010 and 2012. Information on these acquisitions can be found under the “Holly Energy Partners, L.P.” section provided later in this discussion of Items 1 and 2, “Business and Properties.” 6 Table of Content As of December 31, 2013, we: • • • • owned and operated a petroleum refinery in El Dorado, Kansas (the “El Dorado Refinery”), two refinery facilities located in Tulsa, Oklahoma, a refinery in Artesia, New Mexico that is operated in conjunction with crude oil distillation and vacuum distillation and other facilities situated 65 miles away in Lovington, New Mexico (collectively, the “Navajo Refinery”), a refinery located in Cheyenne, Wyoming (the “Cheyenne Refinery”) and a refinery in Woods Cross, Utah (the “Woods Cross Refinery”); owned and operated NK Asphalt Partners (“NK Asphalt”) which operates various asphalt terminals in Arizona and New Mexico; owned a 50% interest in Sabine Biofuels II, LLC (“Sabine Biofuels”), a biodiesel production facility located in Port Arthur, Texas; and owned a 39% interest in HEP, a consolidated VIE, which includes our 2% general partner interest. HEP owns and operates logistic assets consisting of petroleum product and crude oil pipelines and terminal, tankage and loading rack facilities that principally support our refining and marketing operations in the Mid-Continent, Southwest and Rocky Mountain regions of the United States and Alon USA, Inc.'s (“Alon”) refinery in Big Spring, Texas. Additionally, HEP owns a 75% interest in UNEV Pipeline, LLC (“UNEV”), which owns a 12-inch refined products pipeline from Salt Lake City, Utah to Las Vegas, Nevada, together with terminal facilities in the Cedar City, Utah and North Las Vegas areas (the “UNEV Pipeline”), and a 25% interest in SLC Pipeline LLC (the “SLC Pipeline”), which owns a 95-mile intrastate pipeline system that serves refineries in the Salt Lake City area. Our operations are currently organized into two reportable segments, Refining and HEP. The Refining segment includes the operations of our El Dorado, Tulsa, Navajo, Cheyenne and Woods Cross Refineries and NK Asphalt. The HEP segment involves all of the operations of HEP. The financial information about our segments is discussed in Note 20 “Segment Information” in the Notes to Consolidated Financial Statements. REFINERY OPERATIONS Our refinery operations serve the Mid-Continent, Southwest and Rocky Mountain regions of the United States. We own and operate five complex refineries having a combined crude oil processing capacity of 443,000 barrels per stream day. Each of our refineries has the complexity to convert discounted, heavy and sour crude oils into a high percentage of gasoline, diesel and other high-value refined products. For 2013, gasoline, diesel fuel, jet fuel and specialty lubricants (excluding volumes purchased for resale) represented 50%, 33%, 5% and 2%, respectively, of our total refinery sales volumes. The tables presented below and elsewhere in this discussion of our refinery operations set forth information, including non-GAAP performance measures, about our refinery operations. The cost of products and refinery gross and net operating margins do not include the effect of depreciation and amortization. Reconciliations to amounts reported under GAAP are provided under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K. Consolidated Crude charge (BPD) (1) Refinery throughput (BPD) (2) Refinery production (BPD) (3) Sales of produced refined products (BPD) Sales of refined products (BPD) (4) Refinery utilization (5) Years Ended December 31, 2012 2011 (10) 2013 387,520 424,780 413,820 410,730 446,390 415,210 453,740 442,730 431,060 443,620 315,000 340,200 331,890 332,720 340,630 87.5% 93.7% 89.9% 7 Table of Content Consolidated Average per produced barrel (6) Net sales Cost of products (7) Refinery gross margin Refinery operating expenses (8) Net operating margin Refinery operating expenses per throughput barrel (9) Feedstocks: Sweet crude oil Sour crude oil Heavy sour crude oil Black wax crude oil Other feedstocks and blends Total Years Ended December 31, 2012 2011 (10) 2013 $ $ $ 115.60 99.61 15.99 6.15 9.84 5.95 $ $ $ 119.48 94.59 24.89 5.49 19.40 5.22 $ $ $ 118.82 98.18 20.64 5.36 15.28 5.24 52% 21% 17% 2% 8% 100% 51% 22% 17% 2% 8% 100% 56% 23% 12% 2% 7% 100% (1) Crude charge represents the barrels per day of crude oil processed at our refineries. (2) Refinery throughput represents the barrels per day of crude and other refinery feedstocks input to the crude units and other conversion units at our refineries. (3) Refinery production represents the barrels per day of refined products yielded from processing crude and other refinery feedstocks through the crude units and other conversion units at our refineries. (4) Includes refined products purchased for resale. (5) Represents crude charge divided by total crude capacity (BPSD). Effective July 1, 2011, our consolidated crude capacity increased from 256,000 BPSD to 443,000 BPSD as a result of our merger with Frontier. (6) Represents average per barrel amount for produced refined products sold, which is a non-GAAP measure. Reconciliations to amounts reported under GAAP are provided under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K. (7) Transportation, terminal and refinery storage costs billed from HEP are included in cost of products. (8) Represents operating expenses of our refineries, exclusive of depreciation and amortization and pension settlement costs. (9) Represents refinery operating expenses, exclusive of depreciation and amortization and pension settlement costs, divided by refinery throughput. (10) Refining operating data for the year ended December 31, 2011 include crude oil processed and products yielded from the El Dorado and Cheyenne Refineries for the period from July 1, 2011 through December 31, 2011 only, and averaged over the 365 days in the year ended December 31, 2011. Principal Products and Customers Set forth below is information regarding our principal products. Consolidated Sales of produced refined products: Gasolines Diesel fuels Jet fuels Fuel oil Asphalt Lubricants Gas oil / intermediates LPG and other Total Years Ended December 31, 2012 2011 2013 50% 33% 5% 2% 3% 2% —% 5% 100% 50% 31% 6% 2% 3% 3% —% 5% 100% 48% 32% 5% 2% 4% 3% 2% 4% 100% Light products are shipped to customers via product pipelines or are available for loading at our refinery truck facilities and terminals. Light products are also made available to customers at various other locations via exchange with other parties. 8 Table of Content We have several significant customers, of which one accounted for more than 10% of our business in 2013. For the year ended December 31, 2013, Sinclair accounted for $2,134.3 million, or 11%, of our revenues. Our principal customers for gasoline include other refiners, convenience store chains, independent marketers and retailers. Diesel fuel is sold to other refiners, truck stop chains, wholesalers and railroads. Jet fuel is sold for commercial airline use. Specialty lubricant products are sold in both commercial and specialty markets. LPG's are sold to LPG wholesalers and LPG retailers. We produce and purchase asphalt products that are sold to governmental entities, paving contractors or manufacturers. Asphalt is also blended into fuel oil and is either sold locally or is shipped to the Gulf Coast. See Note 22 “Significant Customers” in the Notes to Consolidated Financial Statements for additional information on our significant customers. Mid-Continent Region (El Dorado and Tulsa Refineries) Facilities The El Dorado Refinery is a high-complexity coking refinery with a 135,000 barrels per stream day processing capacity and the ability to process significant volumes of heavy and sour crudes. The Tulsa West and East refinery facilities are both located in Tulsa, Oklahoma. In 2011, we integrated certain refining processes of the Tulsa Refineries which effectively provides us with a highly complex refining operation having a combined crude processing rate of approximately 125,000 barrels per stream day. For 2013, gasoline, diesel fuel, jet fuel and specialty lubricants (excluding volumes purchased for resale) represented 47%, 31%, 8% and 4%, respectively, of our Mid-Continent sales volumes. The following table sets forth information about our Mid-Continent region operations, including non-GAAP performance measures. Mid-Continent Region (El Dorado and Tulsa Refineries) Crude charge (BPD) (1) Refinery throughput (BPD) (2) Refinery production (BPD) (3) Sales of produced refined products (BPD) Sales of refined products (BPD) (4) Refinery utilization (5) Average per produced barrel (6) Net sales Cost of products (7) Refinery gross margin Refinery operating expenses (8) Net operating margin Refinery operating expenses per throughput barrel (9) Feedstocks: Sweet crude oil Sour crude oil Heavy sour crude oil Other feedstocks and blends Total Years Ended December 31, 2012 2011 (10) 2013 234,930 257,030 251,470 247,030 269,790 248,360 269,760 263,310 254,350 258,020 183,070 194,310 188,760 188,020 190,340 90.4% 95.5% 94.8% $ $ $ 115.63 99.35 16.28 5.50 10.78 5.29 $ $ $ 119.19 95.77 23.42 4.83 18.59 4.55 $ $ $ 119.51 99.92 19.59 5.04 14.55 4.88 69% 6% 16% 9% 100% 70% 8% 14% 8% 100% 82% 4% 8% 6% 100% Footnote references are provided under our Consolidated Refinery Operating Data table on page 8. The El Dorado Refinery is located on 1,100 acres south of El Dorado, Kansas and is a fully integrated refinery. The principal processing units at the El Dorado Refinery consist of crude and vacuum distillation; hydrodesulfurization of naphtha, kerosene, diesel, and gas oil streams; isomerization; catalytic reforming; aromatics recovery; catalytic cracking; alkylation; delayed coking; hydrogen production; and sulfur recovery. Refining operations began at the site in 1917 and the operating units now present include both newly constructed units and older units that have been upgraded over the years. Supporting infrastructure includes maintenance shops, warehouses, office buildings, a laboratory, utility facilities, and a wastewater plant (“Supporting Infrastructure”) and logistics assets owned by HEP, which includes approximately 3.6 million barrels of tankage, a truck sales terminal, and a propane terminal. The facility typically processes approximately 135,000 BPSD of crude oil with the capability to handle a significant volume of heavy sour crudes. 9 Table of Content The Tulsa West facility is located on a 750-acre site in Tulsa, Oklahoma situated along the Arkansas River. The principal processing units at the Tulsa West facility consist of crude and vacuum distillation (with light ends recovery), naphtha hydrodesulfurization, catalytic reforming, propane de-asphalting, lubes extraction, MEK dewaxing, delayed coker and butane splitter units. Most of the operating units at the facility currently in service were built in the late 1950s and early 1960s. The refinery was reconfigured to emphasize specialty lubricant production in the early 1990s. Tulsa West facility's Supporting Infrastructure includes approximately 3.2 million barrels of feedstock and product tankage, of which 0.4 million barrels of tankage is owned by Plains All American Pipeline, L.P. (“Plains”). The Tulsa East facility is located on a 466-acre site also in Tulsa, Oklahoma situated along the Arkansas River. The principal process units at the Tulsa East facility consist of crude and vacuum distillation, naphtha hydrodesulfurization, FCC, isomerization, catalytic reforming, alkylation, scanfiner, diesel hydrodesulfurization and sulfur units. The Tulsa East facility's Supporting Infrastructure includes approximately 3.4 million barrels of tankage owned by HEP. Markets and Competition The primary markets for the El Dorado Refinery's refined products are Colorado and the Plains States, which include the Kansas City metropolitan area. The gasoline, diesel and jet fuel produced by the El Dorado Refinery are primarily shipped via pipeline to terminals for distribution by truck or rail. We ship product via the NuStar Pipeline Operating Partnership L.P. Pipeline to the northern Plains States, via the Magellan Pipeline Company, L.P. (“Magellan”) mountain pipeline to Denver, Colorado, and on the Magellan mid-continent pipeline to the Plains States. The El Dorado Refinery faces competition from other Plains States and Mid-Continent refiners, but the principal competitors for the El Dorado Refinery are Gulf Coast refiners. Although our Gulf Coast competitors typically have lower production costs because of economies of scale, we believe that our competitors' higher refined product transportation costs allow our El Dorado Refinery to compete effectively in the Plains States and Rocky Mountain region with the Gulf Coast refineries. For the year ended December 31, 2013, sales to Shell Oil Products US (“Shell”) represented approximately 27% of the El Dorado Refinery's total sales and 9% of our total consolidated sales. We have an offtake agreement with Shell under which Shell purchases gasoline, diesel and jet fuel production of the El Dorado Refinery at market-based prices through the end of 2014 primarily to support its branded and unbranded marketing network. We market gasoline and diesel primarily in Denver and throughout the Plains States. The Tulsa Refineries primarily serve the Mid-Continent region of the United States. Distillates and gasolines are primarily delivered from the Tulsa Refineries to market via pipelines owned and operated by Magellan. These pipelines connect the refinery to distribution channels throughout Colorado, Oklahoma, Kansas, Missouri, Illinois, Iowa, Minnesota, Nebraska and Arkansas. Additionally, HEP's on-site truck and rail racks facilitate access to local refined product markets. In conjunction with our acquisition of the Tulsa East facility in 2009, we entered a five-year offtake agreement through November 2014 with an affiliate of Sinclair whereby Sinclair purchases 45,000 to 50,000 BPD of gasoline and distillate products at market prices from us to supply its branded and unbranded marketing network throughout the Midwest. Upon expiration, the offtake agreement can be renewed by Sinclair for an additional five-year term. For the year ended December 31, 2013, sales to Sinclair represented approximately 36% of the Tulsa Refineries' total sales and 11% of our total consolidated sales. The Tulsa Refineries' principal customers for conventional gasoline include Sinclair, other refiners, convenience store chains, independent marketers and retailers. Sinclair, truck stop operators and railroads are the primary diesel customers. Jet fuel is sold primarily for commercial use. The refinery's asphalt and roofing flux products are sold via truck or railcar directly from the refineries or to customers throughout the Mid-Continent region primarily to paving contractors and manufacturers of roofing products. Our Tulsa West facility also produces specialty lubricant products sold in both commercial and specialty markets throughout North America and to customers with operations in Central America and South America. The specialty lubricant products are high value products that provide a significantly higher margin contribution to the refinery. Base oil customers include blender-compounders who prepare the various finished lubricant and grease products sold to end users. Agricultural products are formulated as supplemental carriers for herbicides and as Environmental Protection Agency (“EPA”) registered pesticide oils, are sold to product formulators. Process oil customers include rubber and chemical industry customers. Specialty waxes are sold primarily to packaging customers as coating material for paper and cardboard, and to non-packaging customers in the construction materials, adhesive and candle-making markets. Our production represents approximately 6% of paraffinic oil capacity and 13% of wax production capacity in the United States market and is one of four refineries of specialty aromatic oils in North America. 10 Table of Content Principal Products Set forth below is information regarding the principal products produced at our El Dorado and Tulsa Refineries: Mid-Continent Region (El Dorado and Tulsa Refineries) Sales of produced refined products: Gasolines Diesel fuels Jet fuels Fuel oil Asphalt Lubricants Gas oil / intermediates LPG and other Total Years Ended December 31, 2012 2011 2013 47% 31% 8% 1% 3% 4% —% 6% 100% 48% 29% 9% 1% 2% 5% —% 6% 100% 44% 32% 7% —% 4% 6% 3% 4% 100% Crude Oil and Feedstock Supplies Both of our Mid-Continent Refineries are connected via pipeline to Cushing, Oklahoma, a significant crude oil pipeline trading and storage hub. The El Dorado and the Tulsa Refineries are located approximately 125 miles and 50 miles, respectively, from Cushing, Oklahoma. Local pipelines provide direct access to regional Oklahoma crude production as well as access to United States onshore, Gulf of Mexico, Canadian and other foreign crudes. The proximity of the refineries to the Cushing pipeline and storage hub provides the flexibility to optimize their crude slate with a wide variety of crude oil supply options. Additionally, we have transportation service agreements to transport Canadian crude oil on the Spearhead and Keystone Pipelines, enabling us to transport Canadian crude oil to Cushing for subsequent shipment to either of our Mid-Continent Refineries or to our Navajo Refinery. We also purchase isobutane, natural gasoline, butane and other feedstocks for processing at our Mid-Continent Refineries. The El Dorado Refinery is connected to Conway, Kansas, a major gas liquids trading and storage hub, via the Oneok Pipeline. From time to time, other feedstocks such gas oil, naptha and light cycle oil are purchased from other refiners for use at our refineries. Southwest Region (Navajo Refinery) Facilities The Navajo Refinery has a crude oil processing capacity of 100,000 barrels per stream day and has the ability to process sour crude oils into high value light products such as gasoline, diesel fuel and jet fuel. For 2013, gasoline and diesel fuel (excluding volumes purchased for resale) represented 51% and 39%, respectively, of our Southwest sales volumes. The following table sets forth information about our Southwest region operations, including non-GAAP performance measures. Southwest Region (Navajo Refinery) Crude charge (BPD) (1) Refinery throughput (BPD) (2) Refinery production (BPD) (3) Sales of produced refined products (BPD) Sales of refined products (BPD) (4) Refinery utilization (5) Average per produced barrel (6) Net sales Cost of products (7) Refinery gross margin Refinery operating expenses (8) Net operating margin Refinery operating expenses per throughput barrel (9) Years Ended December 31, 2012 2011 (10) 2013 87,910 97,310 94,490 94,830 104,320 93,830 103,120 100,810 99,160 104,620 83,700 93,260 91,810 93,950 98,540 87.9% 93.8% 83.7% 117.79 103.88 13.91 6.04 7.87 5.89 $ $ $ 122.62 95.70 26.92 6.07 20.85 5.84 $ $ $ 118.76 98.40 20.36 5.44 14.92 5.48 $ $ $ 11 Table of Content Southwest Region (Navajo Refinery) Feedstocks: Sweet crude oil Sour crude oil Heavy sour crude oil Other feedstocks and blends Total Years Ended December 31, 2012 2011 (10) 2013 8% 72% 11% 9% 100% 2% 77% 12% 9% 100% 3% 75% 11% 11% 100% Footnote references are provided under our Consolidated Refinery Operating Data table on page 8. The Navajo Refinery's Artesia, New Mexico facility is located on a 561-acre site and is a fully integrated refinery with crude distillation, vacuum distillation, FCC, ROSE (solvent deasphalter), HF alkylation, catalytic reforming, hydrodesulfurization, mild hydrocracking, isomerization, sulfur recovery and product blending units. The operating units at the Artesia facility include newly constructed units, older units that have been relocated from other facilities and upgraded and re-erected in Artesia, and units that have been operating as part of the Artesia facility (with periodic major maintenance) for many years, in some very limited cases since before 1970. Supporting Infrastructure includes approximately 2.0 million barrels of feedstock and product tankage, of which 0.3 million barrels of tankage are owned by HEP. The Artesia facility is operated in conjunction with a refining facility located in Lovington, New Mexico, approximately 65 miles east of Artesia. The principal equipment at the Lovington facility consists of a crude distillation unit and associated vacuum distillation units that were constructed after 1970. Supporting Infrastructure includes 1.1 million barrels of feedstock and product tankage of which 0.2 million barrels of tankage are owned by HEP. The Lovington facility processes crude oil into intermediate products that are transported to Artesia by means of three intermediate pipelines owned by HEP. These products are then upgraded into finished products at the Artesia facility. The combined crude oil capacity of the Navajo Refinery facilities is 100,000 BPSD and it typically processes or blends an additional 10,000 BPSD of natural gasoline, butane, gas oil and naphtha. Markets and Competition The Navajo Refinery primarily serves the southwestern United States market, which has historically experienced a high growth rate, including the metropolitan areas of El Paso, Texas; Albuquerque, Moriarty and Bloomfield, New Mexico; Phoenix and Tucson, Arizona; and portions of northern Mexico. Our products are shipped through HEP's pipelines from Artesia, New Mexico to El Paso, Texas and from El Paso to Albuquerque and to Mexico via products pipeline systems owned by Magellan and from El Paso to Tucson and Phoenix via a products pipeline system owned by Kinder Morgan's subsidiary, SFPP, L.P. (“SFPP”). In addition, petroleum products from the Navajo Refinery are transported to markets in northwest New Mexico, to Moriarty, New Mexico, near Albuquerque, via HEP's pipelines running from Artesia to San Juan County, New Mexico, and to Bloomfield, New Mexico. We have refined product storage through our pipelines and terminals agreement with HEP at terminals in El Paso, Texas; Tucson, Arizona; and Artesia and Moriarty, New Mexico. El Paso Market The El Paso market for refined products is currently supplied by a number of area and Gulf Coast refiners and pipelines. Area refiners include Navajo, WRB Refining, LLC (“WRB”) (a joint venture between Phillips 66 and EnCana Corp.), Valero, Alon and Western Refining. Pipelines serving this market are owned by Magellan, NuStar Energy L.P. and HEP. Refined products from the Gulf Coast are transported via Magellan pipelines. Arizona Market The Arizona market for refined products is currently supplied by a number of refiners via pipelines and trucks. Refiners include companies located in west Texas, eastern New Mexico, northern New Mexico, the Gulf Coast and the West Coast. Magellan's pipeline systems deliver refined products from the Texas Gulf Coast to El Paso and, through interconnections with third-party common carrier pipelines, into the Arizona market. New Mexico Markets The Artesia, Albuquerque, Moriarty and Bloomfield markets are supplied by a number of refiners via pipelines and trucks. Refiners include Navajo, Valero, Western Refining, Alon and WRB. 12 Table of Content We use a common carrier pipeline out of El Paso to serve the Albuquerque market. In addition, HEP leases from Mid-America Pipeline Company, L.L.C., a pipeline between White Lakes, New Mexico and the Albuquerque vicinity and Bloomfield, New Mexico. The lease agreement currently runs through 2017, and HEP has options to renew for two ten-year periods. HEP owns and operates a 12-inch pipeline from the Navajo Refinery to the leased pipeline as well as terminalling facilities in Moriarty, which is 40 miles east of Albuquerque. This facility permits us to ship light products to the Albuquerque and Santa Fe, New Mexico areas. In addition, we serve southern Colorado and northern Arizona primarily out of a terminal in Bloomfield, New Mexico, which is owned by Western Refining. Principal Products Set forth below is information regarding the principal products produced at our Navajo Refinery: Southwest Region (Navajo Refinery) Sales of produced refined products: Gasolines Diesel fuels Jet fuels Fuel oil Asphalt LPG and other Total Years Ended December 31, 2012 2011 2013 51% 39% —% 6% 1% 3% 100% 51% 38% —% 6% 2% 3% 100% 52% 34% 1% 6% 4% 3% 100% Crude Oil and Feedstock Supplies The Navajo Refinery is situated near the Permian Basin, an area that has historically, and continues to have, abundant supplies of crude oil available both for regional users and for export to other areas. We purchase crude oil from independent producers in southeastern New Mexico and west Texas as well as from major oil companies. The crude oil is gathered through HEP's pipelines, our tank trucks and through third-party crude oil pipeline systems for delivery to the Navajo Refinery. The Navajo Refinery also has access to a wide variety of crude oils available at Cushing, Oklahoma via HEP's Roadrunner Pipeline that connects to Centurion Pipeline L.P. and to various pipelines and tank facilities located at Cushing, Oklahoma. In 2010, the Navajo Refinery began processing heavy sour crude oil transported from Cushing through these pipelines. We also purchase volumes of isobutane, natural gasoline and other feedstocks to supply the Navajo Refinery from sources in Texas and the Mid-Continent area that are delivered to our region on a common carrier pipeline owned by Enterprise Products, L.P. Ultimately all volumes of these products are shipped to the Artesia refining facilities on HEP's intermediate pipelines running from Lovington to Artesia. From time to time, we purchase gas oil, naphtha and light cycle oil from other refiners for use as feedstock. Rocky Mountain Region (Cheyenne and Woods Cross Refineries) Facilities The Cheyenne Refinery has a crude oil processing capacity of 52,000 barrels per stream day and the Woods Cross Refinery has a crude oil capacity of 31,000 barrels per stream day. The Cheyenne Refinery processes heavy Canadian crudes as well as local sweet crudes such as that produced from the Bakken shale and similar resources. The Woods Cross Refinery processes regional sweet and black wax crude as well as Canadian sour crude oils into high value light products. For 2013, gasoline and diesel fuel (excluding volumes purchased for resale) represented 56% and 30%, respectively, of our Rocky Mountain sales volumes. 13 Table of Content The following table sets forth information about our Rocky Mountain region operations, including non-GAAP performance measures. Rocky Mountain Region (Cheyenne and Woods Cross Refineries) Crude charge (BPD) (1) Refinery throughput (BPD) (2) Refinery production (BPD) (3) Sales of produced refined products (BPD) Sales of refined products (BPD) (4) Refinery utilization (5) Average per produced barrel (6) Net sales Cost of products (7) Refinery gross margin Refinery operating expenses (8) Net operating margin Refinery operating expenses per throughput barrel (9) Feedstocks: Sweet crude oil Sour crude oil Heavy sour crude oil Black wax crude oil Other feedstocks and blends Total Years Ended December 31, 2012 2011 (10) 2013 64,680 70,440 67,860 68,870 72,280 73,020 80,860 78,610 77,550 80,980 48,230 52,630 51,320 50,750 51,750 77.9% 88.0% 84.3% $ $ $ 112.49 94.63 17.86 8.65 9.21 8.46 $ $ $ 116.44 89.29 27.15 6.91 20.24 6.63 $ $ $ 116.37 91.33 25.04 6.41 18.63 6.18 43% 1% 34% 14% 8% 100% 47% 1% 31% 11% 10% 100% 52% 1% 24% 15% 8% 100% Footnote references are provided under our Consolidated Refinery Operating Data table on page 8. The Cheyenne Refinery facility is located on a 255-acre site and is a fully integrated refinery with crude distillation, vacuum distillation, coking, FCCU, HF alkylation, catalytic reforming, hydrodesulfurization of naphtha and distillates, butane isomerization, hydrogen production, sulfur recovery and product blending units. The operating units at the Cheyenne Refinery include both newly constructed units and older units that have been upgraded over the years. Supporting Infrastructure includes approximately 1.9 million barrels of feedstock and product tankage owned by HEP. The Woods Cross Refinery facility is located on a 200-acre site and is a fully integrated refinery with crude distillation, solvent deasphalter, FCC, HF alkylation, catalytic reforming, hydrodesulfurization, isomerization, sulfur recovery and product blending units. The operating units at the Woods Cross Refinery include newly constructed units, older units that have been relocated from other facilities, upgraded and re-erected in Woods Cross, and units that have been operating as part of the Woods Cross facility (with periodic major maintenance) for many years, in some very limited cases since before 1950. Supporting Infrastructure includes approximately 1.5 million barrels of feedstock and product tankage, of which 0.2 million barrels of tankage are owned by HEP. The facility typically processes or blends an additional 2,000 BPSD of natural gasoline, butane and gas oil over its 31,000 BPSD capacity. We own and operate 4 miles of hydrogen pipeline that connects the Woods Cross Refinery to a hydrogen plant located on the property of Chevron's Salt Lake City Refinery. Additionally, HEP owns and operates 12 miles of crude oil and refined products pipelines that allows us to connect our Woods Cross Refinery to common carrier pipeline systems. We are expanding the Woods Cross refinery to a planned capacity of 45,000 BPSD at an anticipated cost of approximately $300.0 million. On November 18, 2013, the Utah Division of Air Quality issued a revised air quality permit (the “Approval Order”) authorizing the expansion. On December 18, 2013, two local environmental groups filed an administrative appeal challenging the issuance of the Approval Order and seeking a stay of the Approval Order. The matter is now pending before an administrative law judge of the Utah Department of Environmental Quality. The expansion is expected to be completed in the fourth quarter of 2015. The expansion scope includes the relocation / revamp of crude, fluid catalytic cracking, and polymerization units as well an expansion of the diesel hydrotreater. The expansion, and expected completion timeline and cost, are subject to the Woods Cross refinery successfully obtaining the Approval Order. 14 Table of Content In conjunction with the expansion, we signed a 10-year, 20,000 BPD crude oil supply agreement with Newfield Exploration Company. This agreement, which commences upon completion of the expansion, will supply black and yellow wax crude oil produced in the nearby Uinta Basin to the Woods Cross Refinery. Upon completion of this expansion, the Woods Cross Refinery's capacity to process waxy crude is expected to double to approximately 24,000 BPD. Markets and Competition The Cheyenne Refinery primarily markets its products in eastern Colorado, including metropolitan Denver, eastern Wyoming and western Nebraska. Because of the location of the Cheyenne Refinery, we are able to sell a significant portion of its diesel from the truck rack at the refinery, thus eliminating transportation costs. Pipeline shipments from the Cheyenne Refinery are on the Magellan pipeline serving Denver and Colorado Springs, Colorado. Denver Market The most competitive market for the Cheyenne Refinery is the Denver metropolitan area. Three other refineries supply the Denver market, Wyoming refineries near Rawlins and in Casper owned by Sinclair and a refinery in Denver owned by Suncor. Five product pipelines also supply Denver, including three from outside the region. Utah Market The Woods Cross Refinery's primary market is Utah, which is currently supplied by a number of local refiners and the Pioneer Pipeline. In addition to our Woods Cross Refinery, local area refiners include Chevron, Tesoro, Big West and Silver Eagle. Other refiners that ship into the Woods Cross market via the Pioneer Pipeline include Sinclair, ExxonMobil, CHS and Phillips 66. We estimate the four local refineries that compete with our Woods Cross Refinery have a combined capacity to process approximately 150,000 BPD of crude oil. The five Utah refineries collectively supply an estimated 70% of the gasoline and distillate products consumed in the states of Utah and Idaho, with the remainder imported from refineries in Wyoming and Montana via the Pioneer Pipeline owned jointly by Sinclair and Phillips 66. Approximately 40% - 45% of the gasoline and diesel fuel produced by our Woods Cross Refinery is sold through a network of Phillips 66 branded marketers under a long-term supply agreement. Idaho, Wyoming, Eastern Washington and Nevada Markets We supply a small percentage of the refined products consumed in the combined Idaho, Wyoming, eastern Washington and Nevada markets. Our Woods Cross Refinery ships refined products over a common carrier pipeline system owned by Tesoro Logistics Northwest Pipelines LLC (“Tesoro Logistics”) to numerous terminals, including HEP's terminal at Spokane, Washington and to terminals at Pocatello and Boise, Idaho and Pasco, Washington that are owned by Tesoro Logistics. We sell to branded and unbranded customers in these markets. In 2012, we began shipping refined products to Cedar City, Utah and Las Vegas, Nevada via the UNEV Pipeline. The majority of the Las Vegas, Nevada market for refined products is supplied by various West Coast refiners and suppliers via Kinder Morgan's CalNev common carrier pipeline system. Principal Products Set forth below is information regarding the principal products produced at our Cheyenne and Woods Cross Refineries: Rocky Mountain Region (Cheyenne and Woods Cross Refineries) Sales of produced refined products: Gasolines Diesel fuels Jet fuels Fuel oil Asphalt LPG and other Total Years Ended December 31, 2012 2011 2013 56% 30% 1% 1% 5% 7% 100% 55% 32% —% 2% 5% 6% 100% 56% 31% 1% 1% 6% 5% 100% Crude Oil and Feedstock Supplies Crude oil is transported to the Cheyenne Refinery from suppliers in Canada, Colorado, Nebraska, North Dakota and Montana via common carrier pipelines owned by Kinder Morgan, Plains All American Pipeline and Suncor Energy, as well as by truck. The Woods Cross Refinery currently obtains crude oil from suppliers in Canada, Wyoming, Utah and Colorado as delivered via common carrier pipelines that originate in Canada, Wyoming and Colorado. We also receive crude oil via the SLC Pipeline, a joint venture common carrier pipeline in which HEP owns a 25% interest. Supplies of black wax crude oil are shipped via truck. 15 Table of Content NK Asphalt Partners We manufacture and market commodity and modified asphalt products in Arizona, New Mexico, Oklahoma, Kansas, Missouri, Texas and northern Mexico. We have three manufacturing facilities located in Glendale, Arizona; Albuquerque, New Mexico; and Artesia, New Mexico. Our Albuquerque and Artesia facilities manufacture modified hot asphalt products and commodity emulsions from base asphalt materials provided by our refineries and third-party suppliers. Our Glendale facility manufactures modified hot asphalt products from base asphalt materials provided by our refineries and third-party suppliers. Our products are shipped via third-party trucking companies to commercial customers that provide asphalt based materials for commercial and government projects. Other Assets We own a 50% joint venture interest in Sabine Biofuels II, LLC, a 30 million gallon per year biodiesel production facility located near Port Arthur, Texas. HOLLY ENERGY PARTNERS, L.P. HEP is a Delaware limited partnership that trades on the New York Stock Exchange under the trading symbol “HEP.” HEP was formed to acquire, own and operate 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. HEP generates revenues by charging tariffs for transporting petroleum products and crude oil through its pipelines, by leasing certain pipeline capacity to Alon, by charging fees for terminalling refined products and other hydrocarbons and by storing and providing other services at its storage tanks and terminals. HEP does not take ownership of products that it transports or terminals; therefore, it is not directly exposed to changes in commodity prices. HEP's recent acquisitions (2009 through present) are summarized below: UNEV Interest Transaction On July 12, 2012, HEP acquired from us our 75% interest in UNEV. We received consideration consisting of $260.0 million in cash and 1.0 million HEP common units. UNEV owns the UNEV Pipeline, a 12-inch refined products pipeline running from Salt Lake City, Utah to Las Vegas, Nevada together with terminal facilities in Cedar City, Utah and North Las Vegas. The UNEV Pipeline was completed in late 2011 and became operational during the first quarter of 2012. Legacy Frontier Pipeline and Tankage Asset Transaction On November 9, 2011, HEP acquired from us certain tankage, loading rack and crude receiving assets located at our El Dorado and Cheyenne Refineries. We received non-cash consideration consisting of promissory notes with an aggregate principal amount of $150.0 million and 3.8 million HEP common units. Tulsa East / Lovington Storage Asset Transaction On March 31, 2010, HEP acquired from us certain storage assets for $93.0 million, consisting of hydrocarbon storage tanks having approximately 2.0 million barrels of storage capacity, a rail loading rack and a truck unloading rack located at our Tulsa East facility and an asphalt loading rack facility located at our Navajo Refinery facility located in Lovington, New Mexico. Sinclair Logistics and Storage Assets Transaction On December 1, 2009, HEP acquired from Sinclair storage tanks having approximately 1.4 million barrels of storage capacity and loading racks at what is now our Tulsa East facility for $79.2 million. Roadrunner / Beeson Pipelines Transaction Also on December 1, 2009, HEP acquired our two newly constructed pipelines for $46.5 million, consisting of a 65-mile, 16-inch crude oil pipeline (the “Roadrunner Pipeline”) that connects our Navajo Refinery Lovington facility to a terminus of Centurion Pipeline L.P.'s pipeline extending between west Texas and Cushing, Oklahoma and a 37-mile, 8-inch crude oil pipeline that connects HEP's New Mexico crude oil gathering system to our Navajo Refinery Lovington facility (the “Beeson Pipeline”). Tulsa West Loading Racks Transaction On August 1, 2009, HEP acquired from us, certain truck and rail loading/unloading facilities located at our Tulsa West facility for $17.5 million. 16 Table of Content Lovington-Artesia Pipeline Transaction On June 1, 2009, HEP acquired our newly constructed, 16-inch intermediate pipeline for $34.2 million that runs 65 miles from our Navajo Refinery's crude oil distillation and vacuum facilities in Lovington, New Mexico to our petroleum refinery located in Artesia, New Mexico. SLC Pipeline Joint Venture Interest On March 1, 2009, HEP acquired a 25% joint venture interest in the SLC Pipeline, a new 95-mile intrastate pipeline system jointly owned with Plains. HEP's capitalized joint venture contribution was $25.5 million. Rio Grande Pipeline Sale On December 1, 2009, HEP sold its 70% interest in Rio Grande Pipeline Company (“Rio Grande”) to a subsidiary of Enterprise Products Partners LP for $35.0 million. Transportation Agreements Agreements with HEP HEP serves our refineries under long-term pipeline and terminal, tankage and throughput agreements expiring in 2019 through 2026. Under these agreements, we pay HEP fees to transport, store and throughput volumes of refined product and crude oil on HEP's pipeline and terminal, tankage and loading rack facilities that result in minimum annual payments to HEP including UNEV (a consolidated subsidiary of HEP). Under these agreements, the agreed upon tariff rates are subject to annual tariff rate adjustments on July 1 at a rate based upon the percentage change in Producer Price Index (“PPI”) or Federal Energy Regulatory Commission (“FERC”) index. As of December 31, 2013, these agreements result in minimum annualized payments to HEP of $225.5 million. Since HEP is a consolidated VIE, our transactions with HEP including the transactions discussed above and fees paid under our transportation agreements with HEP and UNEV, a consolidated subsidiary of HEP, are eliminated and have no impact on our consolidated financial statements. Agreement with Alon HEP has a 15-year pipelines and terminals agreement with Alon expiring in 2020, under which Alon has agreed to transport on HEP's pipelines and throughput through its terminals, volumes of refined products that results in a minimum level of annual revenue. The agreed upon tariff rates are increased or decreased annually at a rate equal to the percentage change in PPI, but will not decrease below the initial tariff rate. Also, HEP has a capacity lease agreement with Alon under which Alon leases space on HEP's Orla to El Paso pipeline for the shipment of up to 15,000 barrels of refined product per day. The terms under this agreement expire in 2018 through 2022. As of December 31, 2013, HEP's assets include: Pipelines • approximately 810 miles of refined product pipelines, including 340 miles of leased pipelines, that transport gasoline, diesel and jet fuel principally from our Navajo Refinery in New Mexico to our customers in the metropolitan and rural areas of Texas, New Mexico, Arizona, Colorado, Utah and northern Mexico; approximately 510 miles of refined product pipelines that transport refined products from Alon's Big Spring refinery in Texas to its customers in Texas and Oklahoma; three 65-mile pipelines that transport intermediate feedstocks and crude oil from our Navajo Refinery crude oil distillation and vacuum facilities in Lovington, New Mexico to our petroleum refinery facilities in Artesia, New Mexico; approximately 970 miles of crude oil trunk, gathering and connection pipelines located in west Texas, New Mexico and Oklahoma that deliver crude oil to our Navajo Refinery; approximately 10 miles of refined product pipelines that support our Woods Cross Refinery located near Salt Lake City, Utah; gasoline and diesel connecting pipelines that support our Tulsa East facility; five intermediate product and gas pipelines between the Tulsa East and Tulsa West facilities; and crude receiving assets located at our Cheyenne Refinery. • • • • • • • Refined Product Terminals and Refinery Tankage • • four refined product terminals located in El Paso, Texas; Moriarty and Bloomfield, New Mexico; and Tucson, Arizona, with an aggregate capacity of approximately 1,300,000 barrels, that are integrated with HEP's refined product pipeline system that serves our Navajo Refinery; one refined product terminal located in Spokane, Washington, with a capacity of approximately 400,000 barrels, that serves third-party common carrier pipelines; 17 Table of Content • • • • • one refined product terminal near Mountain Home, Idaho, with a capacity of 120,000 barrels, that serves a nearby United States Air Force Base; two refined product terminals, located in Wichita Falls and Abilene, Texas, and one tank farm in Orla, Texas with aggregate capacity of approximately 500,000 barrels, that are integrated with HEP's refined product pipelines that serve Alon's Big Spring, Texas refinery; a refined product loading rack facility at each of our El Dorado, Tulsa, Navajo, Cheyenne and Woods Cross Refineries, heavy product / asphalt loading rack facilities at our Tulsa East facility, Navajo Refinery Lovington facility and Cheyenne Refinery, LPG loading rack facilities at our El Dorado Refinery, Tulsa West facility and Cheyenne Refinery, lube oil loading racks at our Tulsa West facility and crude oil Leased Automatic Custody Transfer (“LACT”) units located at our Cheyenne Refinery; on-site crude oil tankage at our Tulsa, Navajo, Cheyenne and Woods Cross Refineries having an aggregate storage capacity of approximately 1,200,000 barrels; and on-site refined and intermediate product tankage at our El Dorado, Tulsa and Cheyenne Refineries having an aggregate storage capacity of approximately 8,400,000 barrels. Additionally, HEP owns a 75% interest in UNEV, which owns the UNEV Pipeline, a 12-inch refined products pipeline from Salt Lake City, Utah to Las Vegas, Nevada together with terminal facilities in the Cedar City, Utah and North Las Vegas areas, and a 25% interest in SLC Pipeline LLC, which owns a 95-mile intrastate pipeline system that serves refineries in the Salt Lake City area. ADDITIONAL OPERATIONS AND OTHER INFORMATION Corporate Offices We lease approximately 60,000 square feet for our principal corporate offices in Dallas, Texas. The lease for our principal corporate offices expires in 2021. Functions performed in the Dallas office include overall corporate management, refinery and HEP management, planning and strategy, corporate finance, crude acquisition, logistics, contract administration, marketing, investor relations, governmental affairs, accounting, tax, treasury, information technology, legal and human resources support functions. Employees and Labor Relations As of December 31, 2013, we had 2,662 employees, of which 886 are currently covered by collective bargaining agreements having various expiration dates between 2015 and 2018. We consider our employee relations to be good. Regulation Refinery and pipeline operations are subject to numerous federal, state and local laws regulating the discharge of substances into the environment or otherwise relating to the protection of the environment. Permits are required under these laws for the operation of our refineries, pipelines and related facilities, and these permits are subject to revocation, modification and renewal. Over the years, there have been and continue to be ongoing communications, including notices of violations, and discussions about environmental matters between us and federal and state authorities, some of which have resulted or will result in changes to operating procedures and in capital expenditures. Compliance with applicable environmental laws, regulations and permits will continue to have an impact on our operations, the results of operations, and our capital requirements. We believe that our current operations are in substantial compliance with applicable federal, state, and local environmental laws, regulations, and permits. Our operations and many of the products we manufacture are subject to certain requirements of the Federal Clean Air Act (“CAA”) as well as related state and local laws and regulations. Certain CAA regulatory programs applicable to our refineries require capital expenditures for the installation of certain air pollution control devices. Additionally, the EPA has the authority under the CAA to modify the formulation of the refined transportation fuel products we manufacture in order to limit the emissions associated with their final use. Subsequent rulemaking authorized by the CAA or similar laws, or new agency interpretations of existing laws and regulations, may necessitate additional expenditures in future years. Also, we are subject to the EPA's new Control of Hazardous Air Pollutants from Mobile Sources (“MSAT2”) regulations on gasoline that impose reductions in the benzene content of our produced gasoline. Our refineries currently purchase a portion of their benzene credits to meet these requirements. If economically justified, we could implement additional benzene reduction projects to eliminate the need to purchase benzene credits. 18 Table of Content The Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007 prescribe certain percentages of renewable fuels (e.g., ethanol and biofuels) that, where required, must be blended into our produced gasoline and diesel. Additional changes in fuel standards, tier III standards, to reduce vehicle emissions are expected to be finalized by the end of February 2014. These new requirements, other requirements of the CAA, and other presently existing or future environmental regulations may, where required, cause us to make substantial capital expenditures and purchase credits at significant cost to enable our refineries to produce products that meet applicable requirements. Further regulatory requirements have emerged from concerns over the potential climate impacts of certain "greenhouse gases" such as carbon dioxide and methane. In response to a statutory directive, the EPA has promulgated rules requiring the reporting of greenhouse gas emissions. In 2010, the EPA promulgated regulations applying construction and operating permit requirements under the CAA's Prevention of Significant Deterioration and Title V programs to sources with potential greenhouse gas emissions above certain threshold levels. The EPA has also announced its intention to issue a New Source Performance Standard directly regulating greenhouse gas emissions from refineries. Proposals both expanding and limiting the EPA's authority in this area continue to be considered in Congress. Litigation challenging the EPA's authority over greenhouse gas emissions also is pending in federal court. The U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) decided in 2012 to uphold the rules, but the U.S. Supreme Court has agreed to review that decision. Our operations are also subject to the Federal Clean Water Act (“CWA”), the Federal Safe Drinking Water Act (“SDWA”) and comparable state and local requirements. The CWA, the SDWA and analogous laws prohibit any discharge into surface waters, ground waters, injection wells and publicly-owned treatment works except in conformance with legal authorization, such as pre- treatment permits and National Pollutant Discharge Elimination System (“NPDES”) permits, issued by federal, state and local governmental agencies. NPDES permits and analogous water discharge permits are valid for a maximum of five years and must be renewed. We generate wastes that may be subject to the Resource Conservation and Recovery Act (“RCRA”) and comparable state and local requirements. The EPA and various state agencies have limited the approved methods of disposal for certain hazardous and non-hazardous wastes. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as “Superfund,” imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons, including the current and past owner or operator of the disposal site or sites from which there is a release of a “hazardous substance,” as well as persons that disposed of or arranged for the disposal or treatment of the hazardous substances at the site or sites. Under CERCLA, such persons may be subject to joint and several liability for such costs as the cost of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. In the course of our historical operations, as well as in our current normal operations, we have generated waste, some of which falls within the statutory definition of a “hazardous substance” and some of which may have been disposed of at sites that may be subject to cleanup and cost recovery actions under CERCLA by a government entity or other third party. Similarly, locations now owned or operated by us, where third parties have disposed such hazardous substances in the past, may also be subject to cleanup and cost recovery actions under CERCLA. Under CERCLA, liable parties may seek contribution from other liable parties to share in the costs of cleanup. Some states have enacted laws similar to CERCLA which impose similar responsibilities and liabilities on responsible parties. It is also not uncommon for neighboring landowners and other third parties to file claims under state law for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. As is the case with all companies engaged in industries similar to ours, we face potential exposure to future claims and lawsuits involving environmental matters. These matters include soil and water contamination, air pollution, personal injury and property damage allegedly caused by substances which we manufactured, handled, used, released or disposed of. We currently have environmental remediation projects that relate to recovery, treatment and monitoring activities resulting from past releases of refined product and crude oil into the environment. As of December 31, 2013, we had an accrual of $87.8 million related to such environmental liabilities. We are and have been the subject of various state, federal and private proceedings and inquiries relating to compliance with environmental regulations and conditions, including those discussed above. Compliance with current and future environmental regulations is expected to require additional expenditures, including expenditures for investigation and remediation, which may be significant, at our refineries and at pipeline transportation facilities. To the extent that future expenditures for these purposes are material and can be reasonably determined, these costs are disclosed and accrued, if applicable. Our operations are also subject to various laws and regulations relating to occupational health and safety. We maintain safety, training and maintenance programs as part of our ongoing efforts to ensure compliance with applicable laws and regulations. Compliance with applicable health and safety laws and regulations has required and continues to require substantial expenditures. 19 Table of Content Health and environmental legislation and regulations change frequently. We cannot predict what additional health and environmental legislation or regulations will be enacted or become effective in the future or how existing or future laws or regulations will be administered or interpreted with respect to our operations. Compliance with more stringent laws or regulations or adverse changes in the interpretation of existing laws or regulations by government agencies could have an adverse effect on our financial position and the results of our operations and could require substantial expenditures for the installation and operation of systems and equipment that we do not currently possess. Insurance Our operations are subject to hazards of operations, including fire, explosion and weather-related perils. We maintain various insurance coverages, including business interruption insurance, subject to certain deductibles. We are not fully insured against certain risks because such risks are not fully insurable, coverage is unavailable, or premium costs, in our judgment, do not justify such expenditures. We have a risk management oversight committee that is made up of members from our senior management. This committee oversees our risk enterprise program, monitors our risk environment and provides direction for activities to mitigate identified risks that may adversely affect the achievement of our goals. 20 Table of Content Item 1A. Risk Factors Investing in us involves a degree of risk, including the risks described below. Our operating results have been, and will continue to be, affected by a wide variety of risk factors, many of which are beyond our control, that could have adverse effects on profitability during any particular period. You should carefully consider the following risk factors together with all of the other information included in this Annual Report on Form 10-K, including the financial statements and related notes, when deciding to invest in us. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may also materially and adversely affect our business operations. If any of the following risks were to actually occur, our business, financial condition or results of operations could be materially and adversely affected. The prices of crude oil and refined products materially affect our profitability, and are dependent upon many factors that are beyond our control, including general market demand and economic conditions, seasonal and weather-related factors, regional and grade differentials and governmental regulations and policies. Among these factors is the demand for crude oil and refined products, which is largely driven by the conditions of local and worldwide economies as well as by weather patterns and the taxation of these products relative to other energy sources. Governmental regulations and policies, particularly in the areas of taxation, energy and the environment, also have a significant impact on our activities. Operating results can be affected by these industry factors, product and crude pipeline capacities, changes in transportation costs, accidents or interruptions in transportation, competition in the particular geographic areas that we serve, and factors that are specific to us, such as the success of particular marketing programs and the efficiency of our refinery operations. The demand for crude oil and refined products can also be reduced due to a local or national recession or other adverse economic condition that results in lower spending by businesses and consumers on gasoline and diesel fuel, higher gasoline prices due to higher crude oil prices, a shift by consumers to more fuel-efficient vehicles or alternative fuel vehicles (such as ethanol or wider adoption of gas/electric hybrid vehicles), or an increase in vehicle fuel economy, whether as a result of technological advances by manufacturers, legislation mandating or encouraging higher fuel economy or the use of alternative fuel. We do not produce crude oil and must purchase all our crude oil, the price of which fluctuates based upon worldwide and local market conditions. Our profitability depends largely on the spread between market prices for refined petroleum products and crude oil prices. This margin is continually changing and may fluctuate significantly from time to time. Crude oil and refined products are commodities whose price levels are determined by market forces beyond our control. For example, the reversal of certain existing pipelines or the construction of certain new pipelines transporting additional crude oil or refined products to markets that serve competing refineries could affect the market dynamic that has allowed us to take advantage of favorable pricing. Additionally, due to the seasonality of refined products markets and refinery maintenance schedules, results of operations for any particular quarter of a fiscal year are not necessarily indicative of results for the full year and can vary year to year in the event of unseasonably cool weather in the summer months and / or unseasonably warm weather in the winter months in the markets in which we sell our petroleum products. In general, prices for refined products are influenced by the price of crude oil. Although an increase or decrease in the price for crude oil may result in a similar increase or decrease in prices for refined products, there may be a time lag in the realization of the similar increase or decrease in prices for refined products. The effect of changes in crude oil prices on operating results therefore depends in part on how quickly refined product prices adjust to reflect these changes. A substantial or prolonged increase in crude oil prices without a corresponding increase in refined product prices, a substantial or prolonged decrease in refined product prices without a corresponding decrease in crude oil prices, or a substantial or prolonged decrease in demand for refined products could have a significant negative effect on our earnings and cash flow. Also, crude oil supply contracts are generally short-term contracts with market-responsive pricing provisions. We purchase our refinery feedstocks weeks before manufacturing and selling the refined products. Price level changes during the period between purchasing feedstocks and selling the manufactured refined products from these feedstocks could have a significant effect on our financial condition and results of operations. We may not be able to successfully execute our business strategies to grow our business. Further, if we are unable to complete capital projects at their expected costs or in a timely manner, if we are unsuccessful in integrating the operations of assets we acquire, or if the market conditions assumed in our project economics deteriorate, our financial condition, results of operations, or cash flows could be materially and adversely affected. One of the ways we may grow our business is through the construction of new refinery processing units (or the purchase and refurbishment of used units from another refinery) and the expansion of existing ones. Projects are generally initiated to increase the yields of higher-value products, increase the amount of lower cost crude oils that can be processed, increase refinery production capacity, meet new governmental requirements, or maintain the operations of our existing assets. Additionally, our growth strategy includes projects that permit access to new and/or more profitable markets. The construction process involves numerous regulatory, environmental, political, and legal uncertainties, most of which are not fully within our control, including: 21 Table of Content • • • • • denial or delay in issuing requisite regulatory approvals and/or permits; compliance with or liability under environmental regulations; unplanned increases in the cost of construction materials or labor; disruptions in transportation of modular components and/or construction materials; severe adverse weather conditions, natural disasters, or other events (such as equipment malfunctions, explosions, fires, spills) affecting our facilities, or those of vendors and suppliers; shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages; • • market-related increases in a project's debt or equity financing costs; and/or • nonperformance or force majeure by, or disputes with, vendors, suppliers, contractors, or sub-contractors involved with a project. If we are unable to complete capital projects at their expected costs or in a timely manner our financial condition, results of operations, or cash flows could be materially and adversely affected. Delays in making required changes or upgrades to our facilities could subject us to fines or penalties as well as affect our ability to supply certain products we make. In addition, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new refinery processing unit, the construction will occur over an extended period of time and we will not receive any material increases in revenues until after completion of the project. Moreover, we may construct facilities to capture anticipated future growth in demand for refined products in a region in which such growth does not materialize. As a result, new capital investments may not achieve our expected investment return, which could adversely affect our financial condition or results of operations. Our forecasted internal rates of return are also based upon our projections of future market fundamentals which are not within our control, including changes in general economic conditions, available alternative supply and customer demand. An additional component of our growth strategy is to selectively acquire complementary assets for our refining operations in order to increase earnings and cash flow. Our ability to do so will be dependent upon a number of factors, including our ability to identify attractive acquisition candidates, consummate acquisitions on favorable terms, successfully integrate acquired assets and obtain financing to fund acquisitions and to support our growth, and other factors beyond our control. Risks associated with acquisitions include those relating to: • • • • • • • • diversion of management time and attention from our existing business; challenges in managing the increased scope, geographic diversity and complexity of operations and inefficiencies that may result therefrom; difficulties in integrating the financial, technological and management standards, processes, procedures and controls of an acquired business with those of our existing operations; liability for known or unknown environmental conditions or other contingent liabilities not covered by indemnification or insurance; greater than anticipated expenditures required for compliance with environmental or other regulatory standards or for investments to improve operating results; difficulties or delays in achieving anticipated operational improvements or benefits; incurrence of additional indebtedness to finance acquisitions or capital expenditures relating to acquired assets; and issuance of additional equity, which could result in further dilution of the ownership interest of existing stockholders. Any acquisitions that we do consummate may have adverse effects on our business and operating results. 22 Table of Content We may incur significant costs to comply with new or changing environmental, energy, health and safety laws and regulations, and face potential exposure for environmental matters. Refinery and pipeline operations are subject to federal, state and local laws regulating, among other things, the generation, storage, handling, use and transportation of petroleum and hazardous substances by pipeline, truck, rail and barge, the emission and discharge of materials into the environment, waste management, and characteristics and composition of gasoline and diesel fuels, and other matters otherwise relating to the protection of the environment. Permits are required under these laws for the operation of our refineries, pipelines and related operations, and these permits are subject to revocation, modification and renewal or may require operational changes, which may involve significant costs. Furthermore, a violation of permit conditions or other legal or regulatory requirements could result in substantial fines, criminal sanctions, permit revocations, injunctions, and/or refinery shutdowns. In addition, major modifications of our operations due to changes in the law could require changes to our existing permits or expensive upgrades to our existing pollution control equipment, which could have a material adverse effect on our business, financial condition, or results of operations. Over the years, there have been and continue to be ongoing communications, including notices of violations, and discussions about environmental matters between us and federal and state authorities, some of which have resulted or will result in changes to operating procedures and in capital expenditures. Compliance with applicable environmental laws, regulations and permits will continue to have an impact on our operations, results of operations and capital requirements. As is the case with all companies engaged in industries similar to ours, we face potential exposure to future claims and lawsuits involving environmental matters. The matters include, but are not limited to, soil, groundwater and waterway contamination, air pollution, personal injury and property damage allegedly caused by substances which we manufactured, handled, used, released or disposed. We are and have been the subject of various state, federal and private proceedings relating to environmental regulations, conditions and inquiries. Current and future environmental regulations are expected to require additional expenditures, including expenditures for investigation and remediation, which may be significant, at our facilities. To the extent that future expenditures for these purposes are material and can be reasonably determined, these costs are disclosed and accrued. Our operations are also subject to various laws and regulations relating to occupational health and safety. We maintain safety, training and maintenance programs as part of our ongoing efforts to ensure compliance with applicable laws and regulations. Compliance with applicable health and safety laws and regulations has required and continues to require substantial expenditures. Failure to appropriately manage occupational health and safety risks associated with our business could also adversely impact our employees, communities, stakeholders, reputation and results of operations. We cannot predict what additional health and environmental legislation or regulations will be enacted or become effective in the future or how existing or future laws or regulations will be administered or interpreted with respect to our operations. However, new environmental laws and regulations, including new regulations relating to alternative energy sources and the risk of global climate change, new interpretations of existing laws and regulations, increased governmental enforcement or other developments could require us to make additional unforeseen expenditures. The EPA has begun regulating certain emissions of greenhouse gases, or “GHGs,” (including carbon dioxide, methane and nitrous oxides) from large stationary sources like refineries under the authority of the CAA, and it is possible that Congress could pass federal legislation that creates a comprehensive GHG regulatory program, either directly or indirectly, such as via a federal renewal energy standard. Also, new federal or state legislation or regulatory programs that restrict emissions of GHGs in areas where we conduct business could adversely affect demand for our products and our results of operations. The costs of environmental and safety regulations are already significant and compliance with more stringent laws or regulations or adverse changes in the interpretation of existing regulations by government agencies could have an adverse effect on the financial position and the results of our operations and could require substantial expenditures for the installation and operation of systems and equipment that we do not currently possess. From time to time, new federal energy policy legislation is enacted by the U.S. Congress. For example, in December 2007, the U.S. Congress passed the Energy Independence and Security Act, which, among other provisions, mandates annually increasing levels for the use of renewable fuels such as ethanol, commencing in 2008 and escalating for 15 years, as well as increasing energy efficiency goals, including higher fuel economy standards for motor vehicles, among other steps. These statutory mandates may have the impact over time of offsetting projected increases in the demand for refined petroleum products in certain markets, particularly gasoline. In the near term, the new renewable fuel standard presents ethanol production and logistics challenges for both the ethanol and refining industries and may require additional capital expenditures or expenses by us to accommodate increased ethanol use. Other legislative changes may similarly alter the expected demand and supply projections for refined petroleum products in ways that cannot be predicted. 23 Table of Content For additional information on regulations and related liabilities or potential liabilities affecting our business, see “Regulation” under Items 1 and 2, “Business and Properties,” and Item 3, “Legal Proceedings.” The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the refined products we produce. In December 2009, the EPA determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the federal CAA. The EPA also adopted two sets of rules regulating GHG emissions under the CAA, one of which requires a reduction in emissions of GHGs from motor vehicles and the other of which may require permits for emissions of GHGs from certain large stationary sources. The EPA’s rules relating to emissions of GHGs from large stationary sources of emissions were upheld by the D.C. Circuit, but the U.S. Supreme Court has agreed to review that decision in response to petitions by numerous parties. The EPA has also adopted rules requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, including petroleum refineries, on an annual basis. The EPA has also announced its intention to issue a New Source Performance Standard directly regulating GHG emissions from refineries. In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of GHGs and almost one-half of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. These cap and trade programs generally work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and on an annual basis surrender emission allowances. The number of allowances available for purchase is reduced over time in an effort to achieve the overall GHG emission reduction goal. The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the refined products that we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. In addition, some scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such events were to occur, they could have an adverse effect on our financial condition and results of operations. Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured. Our operations are subject to operational hazards and unforeseen interruptions such as natural disasters, adverse weather, accidents, fires, explosions, hazardous materials releases, power failures, mechanical failures and other events beyond our control. These events might result in a loss of equipment or life, injury, or extensive property damage or destruction of property, as well as a curtailment or an interruption in our operations and may affect our ability to meet marketing commitments. We maintain significant insurance coverage, but it does not cover all potential losses, costs or liabilities, and our business interruption insurance coverage generally does not apply unless a business interruption exceeds 45 days. If any refinery were to experience an interruption in operations, earnings from the refinery could be materially adversely affected (to the extent not recoverable through insurance) because of lost production and repair costs. The availability of adequate insurance may be affected by conditions in the insurance market over which we have no control, resulting in the inability to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies could increase or, in some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. We could suffer losses for uninsurable or uninsured risks or in amounts in excess of our existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations. 24 Table of Content The energy industry is highly capital intensive, and the entire or partial loss of individual facilities can result in significant costs to both industry companies, such as us, and their insurance carriers. In recent years, several large energy industry claims have resulted in significant increases in the level of premium costs and deductible periods for participants in the energy industry. As a result of large energy industry claims, insurance companies that have historically participated in underwriting energy-related facilities may discontinue that practice or demand significantly higher premiums or deductible periods to cover these facilities. If significant changes in the number or financial solvency of insurance underwriters for the energy industry occur, or if other adverse conditions over which we have no control prevail in the insurance market, we may be unable to obtain and maintain adequate insurance at reasonable cost. In addition, we cannot assure you that our insurers will renew our insurance coverage on acceptable terms, if at all, or that we will be able to arrange for adequate alternative coverage in the event of non-renewal. Further, our underwriters could have credit issues that affect their ability to pay claims. The unavailability of full insurance coverage to cover events in which we suffer significant losses could have a material adverse effect on our business, financial condition and results of operations. The availability and cost of renewable identification numbers could have an adverse effect on our financial condition and results of operations. Pursuant to the 2007 Energy Independence and Security Act, the EPA promulgated the Renewable Fuel Standard 2 (“RFS2”) regulations reflecting the increased volume of renewable fuels mandated to be blended into the nation's fuel supply. The regulations, in part, require refiners to add annually increasing amounts of “renewable fuels” to their petroleum products or purchase credits, known as renewable identification numbers (“RINs”), in lieu of such blending. We currently purchase RINs for some fuel categories on the open market in order to comply with the quantity of renewable fuels we are required to blend under the RFS2. Recently, due in part to the nation's fuel supply approaching the “blend wall” (the 10% ethanol limit prescribed by most automobile warranties), the price of RINs has been extremely volatile with the price dramatically increasing in recognition of the decrease in RINs availability. While we cannot predict the future prices of RINs, the costs to obtain the necessary number of RINs could be material. If we are unable to pass the costs of compliance with the RFS2 on to our customers, if sufficient RINs are unavailable for purchase, if we have to pay a significantly higher price for RINs or if we are otherwise unable to meet the RFS2 mandates, our financial condition and results of operations could be adversely affected. To successfully operate our petroleum refining facilities, we are required to expend significant amounts for capital outlays and operating expenditures. The refining business is characterized by high fixed costs resulting from the significant capital outlays associated with refineries, terminals, pipelines and related facilities. We are dependent on the production and sale of quantities of refined products at refined product margins sufficient to cover operating costs, including any increases in costs resulting from future inflationary pressures or market conditions and increases in costs of fuel and power necessary in operating our facilities. Furthermore, future major capital investment, various environmental compliance related projects, regulatory requirements or competitive pressures could result in additional capital expenditures, which may not produce a return on investment. Such capital expenditures may require significant financial resources that may be contingent on our access to capital markets and commercial bank loans. Additionally, other matters, such as regulatory requirements or legal actions, may restrict our access to funds for capital expenditures. Our refineries consist of many processing units, a number of which have been in operation for many years. One or more of the units may require unscheduled downtime for unanticipated maintenance or repairs that are more frequent than our scheduled turnaround for such units. Scheduled and unscheduled maintenance could reduce our revenues during the period of time that the units are not operating. We have taken significant measures to expand and upgrade units in our refineries by installing new equipment and redesigning older equipment to improve refinery capacity. The installation and redesign of key equipment at our refineries involves significant uncertainties, including the following: our upgraded equipment may not perform at expected throughput levels; operating costs of the upgraded equipment may be higher than expected; the yield and product quality of new equipment may differ from design and/or specifications and redesign, modification or replacement of the equipment may be required to correct equipment that does not perform as expected, which could require facility shutdowns until the equipment has been redesigned or modified. Any of these risks associated with new equipment, redesigned older equipment, or repaired equipment could lead to lower revenues or higher costs or otherwise have a negative impact on our future financial condition and results of operations. In addition, we expect to execute turnarounds at our refineries, which involve numerous risks and uncertainties. These risks include delays and incurrence of additional and unforeseen costs. The turnarounds allow us to perform maintenance, upgrades, overhaul and repair of process equipment and materials, during which time all or a portion of the refinery will be under scheduled downtime. 25 Table of Content Competition in the refining and marketing industry is intense, and an increase in competition in the markets in which we sell our products could adversely affect our earnings and profitability. We compete with a broad range of refining and marketing companies, including certain multinational oil companies. Because of their geographic diversity, larger and more complex refineries, integrated operations and greater resources, some of our competitors may be better able to withstand volatile market conditions, to obtain crude oil in times of shortage and to bear the economic risks inherent in all areas of the refining industry. We are not engaged in petroleum exploration and production activities and do not produce any of the crude oil feedstocks used at our refineries. We do not have a retail business and therefore are dependent upon others for outlets for our refined products. Certain of our competitors, however, obtain a portion of their feedstocks from company-owned production and have retail outlets. Competitors that have their own production or extensive retail outlets, with brand-name recognition, are at times able to offset losses from refining operations with profits from producing or retailing operations, and may be better positioned to withstand periods of depressed refining margins or feedstock shortages. In recent years there have been several refining and marketing consolidations or acquisitions between entities competing in our geographic market. These transactions could increase the future competitive pressures on us. The markets in which we compete may be impacted by competitors' plans for expansion projects and refinery improvements that could increase the production of refined products in our areas of operation and significantly affect our profitability. Also, the potential operation of new or expanded refined product transportation pipelines, or the conversion of existing pipelines into refined product transportation pipelines, could impact the supply of refined products to our existing markets and negatively affect our profitability. In addition, we compete with other industries that provide alternative means to satisfy the energy and fuel requirements of our industrial, commercial and individual consumers. The more successful these alternatives become as a result of governmental regulations, technological advances, consumer demand, improved pricing or otherwise, the greater the impact on pricing and demand for our products and our profitability. There are presently significant governmental and consumer pressures to increase the use of alternative fuels in the United States. A material decrease in the supply of crude oil available to our refineries could significantly reduce our production levels. To maintain or increase production levels at our refineries, we must continually contract for crude oil supplies from third parties. A material decrease in crude oil production from the fields that supply our refineries, as a result of depressed commodity prices, lack of drilling activity, natural production declines or otherwise, could result in a decline in the volume of crude oil available to our refineries. In addition, any prolonged disruption of a significant pipeline that is used in supplying crude oil to our refineries or the potential operation of a new, converted or expanded crude oil pipeline that transports crude oil to other markets could result in a decline in the volume of crude oil available to our refineries. Such an event could result in an overall decline in volumes of refined products processed at our refineries and therefore a corresponding reduction in our cash flow. In addition, the future growth of our operations will depend in part upon whether we can contract for additional supplies of crude oil at a greater rate than the rate of natural decline in our currently connected supplies. If we are unable to secure additional crude oil supplies of sufficient quality or crude pipeline expansion to our refineries, we will be unable to take full advantage of current and future expansion of our refineries' production capacities. A disruption to or proration of the refined product distribution systems we utilize could negatively impact our profitability. We utilize various common carrier or other third party pipeline systems to deliver our products to market. The key systems utilized by the Cheyenne, El Dorado, Navajo, Woods Cross, and Tulsa Refineries are Rocky Mountain, NuStar Energy, SFPP and Plains, Chevron, and Magellan, respectively. All five refineries also utilize systems owned by HEP. If these key pipelines or their associated tanks and terminals become inoperative or decrease the capacity available to us, we may not be able to sell our product, or we may be required to hold our product in inventory or supply products to our customers through an alternative pipeline or by rail or additional tanker trucks from the refinery, all of which could increase our costs and result in a decline in profitability. 26 Table of Content We may be subject to information technology system failures, network disruptions and breaches in data security. Information technology system failures, network disruptions (whether intentional by a third party or due to natural disaster), breaches of network or data security, or disruption or failure of the network system used to monitor and control pipeline operations could disrupt our operations by impeding our processing of transactions, our ability to protect customer or company information and our financial reporting. Our computer systems, including our back-up systems, could be damaged or interrupted by power outages, computer and telecommunications failures, computer viruses, internal or external security breaches, events such as fires, earthquakes, floods, tornadoes and hurricanes, and/or errors by our employees. There can be no assurance that a system failure or data security breach will not have a material adverse effect on our financial condition and results of operations. We may not be able to obtain funding on acceptable terms or at all because of volatility and uncertainty in the credit and capital markets. This may hinder or prevent us from meeting our future capital needs. The domestic and global financial markets and economic conditions are disrupted and volatile from time to time due to a variety of factors, including low consumer confidence, high unemployment, geoeconomic and geopolitical issues, weak economic conditions and uncertainty in the financial services sector. In addition, the fixed-income markets have experienced periods of extreme volatility, which negatively impacted market liquidity conditions. As a result, the cost of raising money in the debt and equity capital markets has increased substantially at times while the availability of funds from these markets diminished significantly. In particular, as a result of concerns about the stability of financial markets generally and the solvency of lending counterparties specifically, the cost of obtaining money from the credit markets may increase as many lenders and institutional investors increase interest rates, enact tighter lending standards, refuse to refinance existing debt on similar terms or at all and reduce, or in some cases cease, to provide funding to borrowers. In addition, lending counterparties under any existing revolving credit facility and other debt instruments may be unwilling or unable to meet their funding obligations. Due to these factors, we cannot be certain that new debt or equity financing will be available on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to meet our obligations as they come due or we may be required to sell assets. Moreover, without adequate funding, we may be unable to execute our growth strategy, complete future acquisitions or construction projects, take advantage of other business opportunities or respond to competitive pressures, comply with regulatory requirements, or meet our short-term or long-term working capital requirements, any of which could have a material adverse effect on our revenues and results of operations. Failure to comply with regulatory requirements in a timely manner or meet our short- term or long-term working capital requirements could subject us to regulatory action. We depend upon HEP for a substantial portion of the crude supply and distribution network that serve our refineries and we own a significant equity interest in HEP. We currently own a 39% interest in HEP, including the 2% general partner interest. HEP operates a system of crude oil and petroleum product pipelines, distribution terminals and refinery tankage in Arizona, Idaho, Kansas, New Mexico, Oklahoma, Texas, Utah, Washington and Wyoming. HEP generates revenues by charging tariffs for transporting petroleum products and crude oil through its pipelines, leasing certain pipeline capacity to Alon, charging fees for terminalling refined products and other hydrocarbons and storing and providing other services at its terminals. HEP serves the Cheyenne, El Dorado, Navajo, Woods Cross and Tulsa Refineries under several long-term pipeline and terminal, tankage and throughput agreements expiring in 2019 through 2026. Furthermore, our financial statements include the consolidated results of HEP. HEP is subject to its own operating and regulatory risks, including, but not limited to: • • • • • • • its reliance on its significant customers, including us; competition from other pipelines; environmental regulations affecting pipeline operations; operational hazards and risks; pipeline tariff regulations affecting the rates HEP can charge; limitations on additional borrowings and other restrictions due to HEP's debt covenants; and other financial, operational and legal risks. The occurrence of any of these risks could directly or indirectly affect HEP's as well as our financial condition, results of operations and cash flows as HEP is a consolidated VIE. Additionally, these risks could affect HEP's ability to continue operations which could affect their ability to serve our supply and distribution network needs. For additional information about HEP, see “Holly Energy Partners, L.P.” under Items 1 and 2, “Business and Properties.” For risks related to HEP's business, see Item 1A of HEP's Annual Report on Form 10-K for the fiscal year ended December 31, 2013. 27 Table of Content We are exposed to the credit risks, and certain other risks, of our key customers and vendors. We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. We derive a significant portion of our revenues from contracts with key customers. If any of our key customers default on their obligations to us, our financial results could be adversely affected. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks. In addition, nonperformance by vendors who have committed to provide us with products or services could result in higher costs or interfere with our ability to successfully conduct our business. Any substantial increase in the nonpayment and/or nonperformance by our customers or vendors could have a material adverse effect on our results of operations and cash flows. Terrorist attacks, and the threat of terrorist attacks or domestic vandalism, have resulted in increased costs to our business. Continued global hostilities or other sustained military campaigns may adversely impact our results of operations. The long-term impacts of terrorist attacks, such as the attacks that occurred on September 11, 2001, and the threat of future terrorist attacks on the energy transportation industry in general, and on us in particular, are not known at this time. Increased security measures taken by us as a precaution against possible terrorist attacks or vandalism have resulted in increased costs to our business. Future terrorist attacks could lead to even stronger, more costly initiatives or regulatory requirements. Uncertainty surrounding continued global hostilities or other sustained military campaigns may affect our operations in unpredictable ways, including disruptions of crude oil supplies and markets for refined products, and the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror. In addition, disruption or significant increases in energy prices could result in government-imposed price controls. Any one of, or a combination of, these occurrences could have a material adverse effect on our business, financial condition and results of operations. Changes in the insurance markets attributable to terrorist attacks could make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital including our ability to repay or refinance debt. Increases in required fuel economy and regulation of CO2 emissions from motor vehicles may reduce demand for transportation fuels. In 2010, the EPA and the National Highway Traffic Safety Administration (“NHTSA”) finalized new standards, raising the required Corporate Average Fuel Economy (“CAFE”) of the nation's passenger fleet by 40% to approximately 35 miles per gallon (“m.p.g.”) by 2016 and imposing the first-ever federal GHG emissions standards on cars and light trucks. In September 2011, the EPA and the Department of Transportation finalized first-time standards for fuel economy of medium and heavy duty trucks. On August 28, 2012 the EPA and NHTSA adopted standards through model year 2025 in two phases. The first phase establishes final standards for 2017-2021 model year vehicles that are projected to require 40.3 - 41.0 m.p.g. in model year 2021 on an average industry fleet- wide basis. The second phase of the CAFE program represents non-final “augural” standards for 2022-2025 model year vehicles that are projected to require 48.7 - 49.7 m.p.g. in model year 2025, on an average industry fleet-wide basis. Such increases in fuel economy standards, along with mandated increases in use of renewable fuels discussed above, could result in decreasing demand for petroleum fuels. Decreasing demand for petroleum fuels could have a material effect on our financial condition and results of operation. We may be unable to pay future regular and/or special dividends. We will only be able to pay dividends from our available cash on hand, cash from operations or borrowings under our credit agreement. The declaration of future regular and/or special dividends on our common stock will be at the discretion of our board of directors and will depend upon many factors, including our results of operations, financial condition, earnings, capital requirements, and restrictions in our debt agreements and legal requirements. We cannot assure you that any dividends will be paid or the frequency of such payments. 28 Table of Content Product liability claims and litigation could adversely affect our business and results of operations. A significant portion of our operating responsibility on refined product pipelines is to insure the quality and purity of the products loaded at our loading racks. If our quality control measures were to fail, we may have contaminated or off-specification commingled pipelines and storage tanks or off-specification product could be sent to public gasoline stations. These types of incidents could result in product liability claims from our customers. Product liability is a significant commercial risk. Substantial damage awards have been made in certain jurisdictions against manufacturers and resellers based upon claims for injuries caused by the use of or exposure to various products. There can be no assurance that product liability claims against us would not have a material adverse effect on our business or results of operations or our ability to maintain existing customers or retain new customers. Our hedging transactions may limit our gains and expose us to other risks. We periodically enter into derivative transactions as it relates to inventory levels and/or future production to manage the risks from changes in the prices of crude oil, refined products and other feedstocks. These transactions limit our potential gains if commodity prices move above or below the certain price levels established by our hedging instruments. We hedge price risk on inventories above our target levels to minimize the impact these price fluctuations have on our earnings and cash flows. Consequently, our hedging results may fluctuate significantly from one reporting period to the next depending on commodity price fluctuations and our relative physical inventory positions. These transactions may also expose us to risks of financial losses; for example, if our production is less than we anticipated at the time we entered into a hedge agreement or if a counterparty to our hedge agreements fails to perform its obligations under the agreements. Changes in our credit profile, or a significant increase in the price of crude oil, may affect our relationship with our suppliers, which could have a material adverse effect on our liquidity and limit our ability to purchase sufficient quantities of crude oil to operate our refineries at desired capacity. An unfavorable credit profile, or a significant increase in the price of crude oil, could affect the way crude oil suppliers view our ability to make payments and induce them to shorten the payment terms of their invoices with us or require credit enhancement. Due to the large dollar amounts and volume of our crude oil and other feedstock purchases, any imposition by our suppliers of more burdensome payment terms or credit enhancement requirements on us may have a material adverse effect on our liquidity and our ability to make payments to our suppliers. This in turn could cause us to be unable to operate our refineries at desired capacity. A failure to operate our refineries at desired capacity could adversely affect our profitability and cash flow. Our debt agreements contain operating and financial restrictions that might constrain our business and financing activities. The operating and financial restrictions and covenants in our credit facility and any future financing agreements could adversely affect our ability to finance future operations or capital needs or to engage, expand or pursue our business activities. For example, our revolving credit facility imposes usual and customary requirements for this type of credit facility, including: (i) limitations on liens, investments, indebtedness and dividends; (ii) a prohibition on changes in control and (iii) restrictions on engaging in mergers, consolidations and sales of assets, entering into certain lease obligations, and making certain investments or capital expenditures. If we fail to satisfy the covenants set forth in the credit facility or another event of default occurs under the facility, the maturity of the loan could be accelerated or we could be prohibited from borrowing for our future working capital needs and issuing letters of credit. We might not have, or be able to obtain, sufficient funds to make these immediate payments. If we desire to undertake a transaction that is prohibited by the covenants in our credit facility, we will need to obtain consent under our credit facility. Such refinancing may not be possible or may not be available on commercially acceptable terms. In addition, our obligations under our credit facility are secured by inventory, receivables and pledged cash assets. If we are unable to repay our indebtedness under our credit facility when due, the lenders could seek to foreclose on the assets or we may be required to contribute additional capital to our subsidiaries. Any of these outcomes could have a material adverse effect on our business, financial condition and results of operations. 29 Table of Content Our business may suffer due to a change in the composition of our Board of Directors, or by the departure of any of our key senior executives or other key employees. Furthermore, a shortage of skilled labor or disruptions in our labor force may make it difficult for us to maintain labor productivity. Our future performance depends to a significant degree upon the continued contributions of our senior management team and key technical personnel. We do not currently maintain key man life insurance, non-compete agreements, or employment agreements with respect to any member of our senior management team. The loss or unavailability to us of any member of our senior management team or a key technical employee could significantly harm us. We face competition for these professionals from our competitors, our customers and other companies operating in our industry. To the extent that the services of members of our senior management team and key technical personnel would be unavailable to us for any reason, we may be required to hire other personnel to manage and operate our company. We may not be able to locate or employ such qualified personnel on acceptable terms, or at all. Furthermore, our operations require skilled and experienced laborers with proficiency in multiple tasks. A shortage of trained workers due to retirements or otherwise could have an adverse impact on our labor productivity and costs and our ability to expand production in the event there is an increase in the demand for our products and services, which could adversely affect our operations. As of December 31, 2013, approximately 33% of our employees were represented by labor unions under collective bargaining agreements with various expiration dates. We may not be able to renegotiate our collective bargaining agreements when they expire on satisfactory terms or at all. A failure to do so may increase our costs. In addition, our existing labor agreements may not prevent a strike or work stoppage at any of our facilities in the future, and any work stoppage could negatively affect our results of operations and financial condition. The market price of our common stock may fluctuate significantly, and the value of a stockholder’s investment could be impacted. The market price of our common stock may be influenced by many factors, some of which are beyond our control, including: • • • • • • • • our quarterly or annual earnings or those of other companies in our industry; changes in accounting standards, policies, guidance, interpretations or principles; general economic and stock market conditions; the failure of securities analysts to cover our common stock or changes in financial estimates by analysts; future sales of our common stock; announcements by us or our competitors of significant contracts or acquisitions; sales of common stock by us, our senior officers or our affiliates; and/or the other factors described in these Risk Factors. In recent years, the stock market has experienced extreme price and volume fluctuations. This volatility has had a significant impact on the market price of securities issued by many companies, including companies in our industry. The price of our common stock could fluctuate based upon factors that have little or nothing to do with our company, and these fluctuations could materially reduce our stock price. Item 1B. Unresolved Staff Comments We do not have any unresolved staff comments. Item 3. Legal Proceedings Commitment and Contingency Reserves We periodically establish reserves for certain legal proceedings. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, future changes in the facts and circumstances could result in the actual liability exceeding the estimated ranges of loss and amounts accrued. 30 Table of Content While the outcome and impact on us cannot be predicted with certainty, management believes that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on our consolidated financial position or cash flow. Operating results, however, could be significantly impacted in the reporting periods in which such matters are resolved. Environmental Matters We are reporting the following proceedings to comply with SEC regulations which require us to disclose proceedings arising under federal, state or local provisions regulating the discharge of materials into the environment or protecting the environment if we reasonably believe that such proceedings may result in monetary sanctions of $100,000 or more. Our respective subsidiaries have or will develop corrective action plans regarding these disclosures that will be implemented in consultation with the respective federal and state agencies. It is not possible to predict the ultimate outcome of these proceedings, although none are currently expected to have a material effect on our consolidated financial position. Frontier Refining LLC (“FR”), our wholly-owned subsidiary, has undertaken environmental audits at the Cheyenne Refinery regarding compliance with federal and state environmental requirements. By letters dated October 5, 2012, and November 7, 2012, and January 10, 2013, and pursuant to EPA's audit policy to the extent applicable, FR submitted reports to the EPA voluntarily disclosing non-compliance with certain emission limitations, reporting requirements, and provisions of a 2009 federal consent decree. By letters dated October 31, 2012, February 6, 2013, June 21, 2013, July 9, 2013, and July 25, 2013, and pursuant to applicable Wyoming audit statutes, FR submitted environmental audit reports to the Wyoming Department of Environmental Quality (“WDEQ”) voluntarily disclosing non-compliance with certain notification, reporting, and other provisions of the refinery's state air permit and other environmental regulatory requirements. Additional self-disclosures and follow-up correspondence are anticipated as the audit activities are completed. No further action has been taken by either agency at this time. The Cheyenne Refinery also has four outstanding Notices of Violations issued in 2010, 2011 and 2013 that are subject to ongoing settlement negotiations with the WDEQ. Additional air and other environmental audits for the Cheyenne Refinery are scheduled for 2014. Between November 2010 and February 2012, certain of our subsidiaries submitted multiple reports to the EPA to voluntarily disclose non-compliance with fuels regulations at the Cheyenne, El Dorado, Navajo, Tulsa and Woods Cross refineries and at the Cedar City, Utah and Henderson, Colorado terminals. The EPA has requested additional information regarding certain of these reports, and our subsidiaries have complied with all requests received to date. Other We are a party to various other litigation and proceedings that we believe, based on advice of counsel, will not either individually or in the aggregate have a materially adverse impact on our financial condition, results of operations or cash flows. Item 4. Mine Safety Disclosures Not Applicable. 31 Table of Content PART II Item 5. Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Our common stock is traded on the New York Stock Exchange under the trading symbol “HFC.” The following table sets forth the range of the daily high and low sales prices per share of common stock, dividends declared per share and the trading volume of common stock for the periods indicated: Years Ended December 31, High Low Dividends Trading Volume 2013 Fourth quarter Third quarter Second quarter First quarter 2012 Fourth quarter Third quarter Second quarter First quarter $ $ $ $ $ $ $ $ 50.63 47.21 52.87 59.20 47.39 42.33 36.10 36.45 $ $ $ $ $ $ $ $ 39.65 38.98 39.96 42.76 36.22 33.92 28.05 23.96 $ $ $ $ $ $ $ $ 0.800 0.800 0.800 0.800 0.700 1.150 0.650 0.600 230,186,600 174,416,900 229,246,900 217,439,700 161,950,900 171,023,300 232,551,400 230,380,300 In January 2012, our Board of Directors approved a $350 million stock repurchase program, and in June 2012, approved an additional $350 million repurchase program that authorizes us to repurchase common stock in the open market or through privately negotiated transactions. The timing and amount of stock repurchases will depend on market conditions, corporate, regulatory and other relevant considerations. These programs may be discontinued at any time by the Board of Directors. The following table includes repurchases made under this program during the fourth quarter of 2013. Period October 2013 November 2013 December 2013 (1) Total for October to December 2013 Total Number of Shares Purchased 423,800 40,000 475,000 938,800 Average Price Paid Per Share 42.80 $ 43.90 $ 47.83 $ Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs Maximum Dollar Value of Shares that May Yet Be Purchased under the Plans or Programs 423,800 40,000 $ $ — $ 463,800 313,327,358 311,571,488 311,571,488 (1) The December 2013 shares repurchased were not purchased under our approved stock repurchase program, but rather pursuant to separate authority from our Board of Directors. These repurchases were made in the open market. As of February 11, 2014, we had approximately 127,580 stockholders, including beneficial owners holding shares in street name. We intend to consider the declaration of a dividend on a quarterly basis, although there is no assurance as to future dividends since they are dependent upon future earnings, capital requirements, our financial condition and other factors. Our credit agreement and senior notes limit the payment of dividends. See Note 12 “Debt” in the Notes to Consolidated Financial Statements. 32 Table of Content Item 6. Selected Financial Data The following table shows our selected financial information as of the dates or for the periods indicated. This table should be read in conjunction with Item 7, “Management's Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes thereto included elsewhere in this Annual Report on Form 10-K. 2013 Years Ended December 31, 2011 2010 2012 2009 FINANCIAL DATA (1) For the period Sales and other revenues Income from continuing operations before income taxes Income tax provision Income from continuing operations Income from discontinued operations, net of taxes (2) Net income Less net income attributable to noncontrolling interest Net income attributable to HollyFrontier stockholders Earnings per share attributable to HollyFrontier stockholders - basic Earnings per share attributable to HollyFrontier stockholders - diluted Cash dividends declared per common share Average number of common shares outstanding: (In thousands, except per share data) $ 20,160,560 1,159,399 391,576 767,823 — 767,823 31,981 735,842 $ $ 20,090,724 2,787,995 1,027,962 1,760,033 — 1,760,033 32,861 $ 1,727,172 $ 15,439,528 1,641,695 581,991 1,059,704 — 1,059,704 36,307 $ 1,023,397 $ 8,322,929 192,363 59,312 133,051 — 133,051 29,087 103,964 $ $ 4,834,268 43,803 7,460 36,343 16,926 53,269 33,736 19,533 $ $ $ $ 3.66 3.64 3.20 $ $ $ 8.41 8.38 3.10 $ $ $ 6.46 6.42 1.34 $ $ $ 0.98 0.97 0.30 $ $ $ 0.20 0.20 0.30 Basic Diluted 200,419 201,234 204,379 205,274 157,948 158,756 106,436 107,218 100,836 101,206 Net cash provided by operating activities Net cash provided by (used for) investing activities Net cash provided by (used for) financing activities At end of period Cash, cash equivalents and investments in marketable securities Working capital Total assets Total debt (3) Total equity 869,174 $ $ (526,735) $ $ (1,160,035) $ $ 1,662,687 (711,104) $ (772,788) $ $ $ 1,338,391 228,494 $ (217,082) $ 283,255 $ (213,232) $ $ 34,482 211,545 (534,603) 406,849 $ 1,665,263 $ 2,221,954 $ 10,056,739 $ 997,519 $ 6,609,398 $ 2,393,401 $ 2,815,821 $ 10,328,997 $ 1,336,238 $ 6,642,658 $ 1,840,610 $ 2,030,063 $ 9,576,243 $ 1,214,742 $ 5,835,900 230,444 $ $ 313,580 $ 3,049,951 $ 810,561 $ 1,288,139 125,819 $ $ 257,899 $ 2,766,318 $ 707,458 $ 1,207,781 (1) We merged with Frontier on July 1, 2011. Our consolidated financial and operating results reflect the operations of the merged Frontier businesses beginning July 1, 2011. See “Company Overview” under Items 1 and 2, “Business and Properties” for information on our merger. (2) On December 1, 2009, HEP sold its 70% interest in Rio Grande. Results of operations of Rio Grande are presented in discontinued operations. (3) Includes total HEP debt of $807.6 million, $864.7 million, $525.9 million, $482.3 million and $379.2 million, respectively, which is non-recourse to HollyFrontier. 33 Table of Content Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations This Item 7 contains “forward-looking” statements. See “Forward-Looking Statements” at the beginning of this Annual Report on Form 10-K. In this document, the words “we,” “our,” “ours” and “us” refer only to HollyFrontier and its consolidated subsidiaries or to HollyFrontier or an individual subsidiary and not to any other person with certain exceptions. Generally, the words “we,” “our,” “ours” and “us” include HEP and its subsidiaries as consolidated subsidiaries of HollyFrontier, unless when used in disclosures of transactions or obligations between HEP and HollyFrontier or its other subsidiaries. This document contains certain disclosures of agreements that are specific to HEP and its consolidated subsidiaries and do not necessarily represent obligations of HollyFrontier. When used in descriptions of agreements and transactions, “HEP” refers to HEP and its consolidated subsidiaries. We merged with Frontier on July 1, 2011. Accordingly, this document includes Frontier, its consolidated subsidiaries and the operations of the merged Frontier businesses effective July 1, 2011, but not prior to this date. Overview We are principally an independent petroleum refiner that produces high-value refined products such as gasoline, diesel fuel, jet fuel, specialty lubricant products, and specialty and modified asphalt. We own and operate refineries having a combined crude oil processing capacity of 443,000 barrels per day that serve markets throughout the Mid-Continent, Southwest and Rocky Mountain regions of the United States. Our refineries are located in El Dorado, Kansas (the El Dorado Refinery), Tulsa, Oklahoma (the Tulsa Refineries), which comprise two production facilities, the Tulsa West and East facilities, a petroleum refinery in Artesia, New Mexico, which operates in conjunction with crude, vacuum distillation and other facilities situated 65 miles away in Lovington, New Mexico (the Navajo Refinery), Cheyenne, Wyoming (the Cheyenne Refinery) and Woods Cross, Utah (the Woods Cross Refinery). For the year ended December 31, 2013, net income attributable to HollyFrontier stockholders was $735.8 million compared to $1,727.2 million for the year ended December 31, 2012. Overall gross refining margins per produced product sold decreased 36% over the year ended December 31, 2012 due principally to significant contraction in WTI to Brent crude differentials as well as lower discounts on heavy sour crudes purchased during the second and third quarters of 2013. Net income for the year ended December 31, 2013 reflects pension settlement and debt extinguishment charges of $39.5 million and $22.1 million, respectively. Also affecting current year net income were the effects of planned turnarounds at our El Dorado, Tulsa and Navajo Refineries as well as unplanned downtime incurred at each of our El Dorado and Cheyenne Refineries due to FCC unit issues during the second quarter of 2013. Our financial and operating results additionally reflect lower crude oil throughput rates for the Southwest region, which averaged 74,370 BPD for the fourth quarter of 2013 compared to 99,610 BPD for the same period last year, as a result of waste water constraints at our Navajo Refinery during late 2013. This matter was resolved in January 2014 and throughput rates have since returned to planned levels. OUTLOOK Our profitability is affected by the spread, or differential, between the market prices for crude oil on the world market (which is based on the price for Brent, North Sea Crude) and the price for inland U.S. crude oil (which is based on the price for WTI). This differential constantly changes and at times can be volatile. While we have experienced wide differentials (with Brent prices in excess of WTI prices) in recent years, which have significantly enhanced our profitability, the differential between Brent and WTI narrowed significantly during the second half of 2013 - averaging approximately one-half of the differential experienced during 2012. Differentials are likely to continue to be volatile in the near term. However, we expect the Brent to WTI differential to rebound upon completion of additional northern tier pipeline capacity into Cushing, Oklahoma, which we believe will create a surplus of light sweet crude oil on the U.S. Gulf Coast. Ultimately, we believe pipeline tariffs from Cushing to the Gulf Coast plus marine transportation costs to transport product from the Gulf Coast to alternative markets will set the inland - coastal differential. 34 Table of Content Pursuant to the 2007 Energy Independence and Security Act, the EPA promulgated the RFS2 regulations reflecting the increased volume of renewable fuels mandated to be blended into the nation's fuel supply. The regulations, in part, require refiners to add annually increasing amounts of “renewable fuels” to their petroleum products or purchase credits, known as RINs, in lieu of such blending. As of December 2013, we are purchasing RINs in order to meet approximately half of our renewable fuel requirements. Recently, due in part to the nation's fuel supply approaching the “blend wall” (the 10% ethanol limit prescribed by most automobile warranties), the price of RINs has been extremely volatile with the price dramatically increasing due to real or perceived future shortages in RINs. As a result, we expect to continue to experience higher than historical costs to comply with the renewable fuel mandate. In the wholesale markets we serve, we are seeing price adjustments to indicate that the cost of RINs is being largely borne by the consumer at the pump. However, we continue to use various approaches to mitigate our exposure to the increasing cost of RINs, which include additional renewable fuel blending, shifts in our refined product slate and changes in the way we conduct marketing operations. We cannot predict with certainty whether and to what extent we will be successful in mitigating our exposure to increased RINs costs, and anticipate that increased compliance costs may negatively impact our future results of operations. In 2013, our ethanol RINs purchases from third parties totaled approximately 215 million RINs. A more detailed discussion of our financial and operating results for the years ended December 31, 2013, 2012 and 2011 is presented in the following sections. 35 Table of Content Results Of Operations Financial Data 2013 Years Ended December 31, 2012 (In thousands, except per share data) 2011 (1) Sales and other revenues Operating costs and expenses: Cost of products sold (exclusive of depreciation and amortization) Operating expenses (exclusive of depreciation and amortization) General and administrative expenses (exclusive of depreciation and amortization) Depreciation and amortization Total operating costs and expenses Income from operations Other income (expense): Earnings (loss) of equity method investments Interest income Interest expense Loss on early extinguishment of debt Gain on sale of marketable securities Merger transaction costs Income before income taxes Income tax provision Net income Less net income attributable to noncontrolling interest Net income attributable to HollyFrontier stockholders Earnings per share attributable to HollyFrontier stockholders: Basic Diluted Cash dividends declared per common share Average number of common shares outstanding: Basic Diluted $ 20,160,560 $ 20,090,724 $ 15,439,528 17,392,227 1,090,850 127,963 303,446 18,914,486 1,246,074 (2,072) 5,556 (68,050) (22,109) — — (86,675) 1,159,399 391,576 767,823 31,981 735,842 3.66 3.64 3.20 $ $ $ $ 15,840,643 994,966 128,101 242,868 17,206,578 2,884,146 2,923 4,786 (104,186) — 326 — (96,151) 2,787,995 1,027,962 1,760,033 32,861 1,727,172 8.41 8.38 3.10 $ $ $ $ 12,680,078 748,081 120,114 159,707 13,707,980 1,731,548 2,300 1,284 (78,323) — — (15,114) (89,853) 1,641,695 581,991 1,059,704 36,307 1,023,397 6.46 6.42 1.34 200,419 201,234 204,379 205,274 157,948 158,756 $ $ $ $ (1) Our consolidated financial and operating results reflect the operations of the merged Frontier businesses beginning July 1, 2011. Other Financial Data Net cash provided by operating activities Net cash provided by (used for) investing activities Net cash used for financing activities Capital expenditures EBITDA (1) 2013 Years Ended December 31, 2012 (In thousands) 2011 $ $ $ $ $ 869,174 $ (526,735) $ (1,160,035) $ $ 425,127 $ 1,515,467 1,662,687 $ (711,104) $ (772,788) $ $ 335,263 $ 3,097,402 1,338,391 228,494 (217,082) 374,241 1,842,134 36 Table of Content (1) 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 and amortization. EBITDA is not a calculation provided for under GAAP; 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. EBITDA presented above is reconciled to net income under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K. Our operations are organized into two reportable segments, Refining and HEP. See Note 20 “Segment Information” in the Notes to Consolidated Financial Statements for additional information on our reportable segments. Refining Operating Data Our refinery operations include the El Dorado, Tulsa, Navajo, Cheyenne and Woods Cross Refineries. The following tables set forth information, including non-GAAP performance measures about our consolidated refinery operations. The cost of products and refinery gross and net operating margins do not include the effect of depreciation and amortization. Reconciliations to amounts reported under GAAP are provided under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K. Consolidated Crude charge (BPD) (1) Refinery throughput (BPD) (2) Refinery production (BPD) (3) Sales of produced refined products (BPD) Sales of refined products (BPD) (4) Refinery utilization (5) Average per produced barrel (6) Net sales Cost of products (7) Refinery gross margin Refinery operating expenses (8) Net operating margin Refinery operating expenses per throughput barrel (9) Years Ended December 31, 2013 2012 2011 (10) 387,520 424,780 413,820 410,730 446,390 415,210 453,740 442,730 431,060 443,620 315,000 340,200 331,890 332,720 340,630 87.5% 93.7% 89.9% $ $ $ 115.60 99.61 15.99 6.15 9.84 5.95 $ $ $ 119.48 94.59 24.89 5.49 19.40 5.22 $ $ $ 118.82 98.18 20.64 5.36 15.28 5.24 (1) Crude charge represents the barrels per day of crude oil processed at our refineries. (2) Refinery throughput represents the barrels per day of crude and other refinery feedstocks input to the crude units and other conversion units at our refineries. (3) Refinery production represents the barrels per day of refined products yielded from processing crude and other refinery feedstocks through the crude units and other conversion units at our refineries. (4) Includes refined products purchased for resale. (5) Represents crude charge divided by total crude capacity (BPSD). Effective July 1, 2011, our consolidated crude capacity increased from 256,000 BPSD to 443,000 BPSD as a result of our merger with Frontier. (6) Represents average per barrel amount for produced refined products sold, which is a non-GAAP measure. Reconciliations to amounts reported under GAAP are provided under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K. (7) Transportation, terminal and refinery storage costs billed from HEP are included in cost of products. (8) Represents operating expenses of our refineries, exclusive of depreciation and amortization and pension settlement costs. (9) Represents refinery operating expenses, exclusive of depreciation and amortization and pension settlement costs, divided by refinery throughput. (10) Refining operating data for the year ended December 31, 2011 include crude oil processed and products yielded from the El Dorado and Cheyenne Refineries for the period from July 1, 2011 through December 31, 2011 only, and averaged over the 365 days in the year ended December 31, 2011. 37 Table of Content Results of Operations – Year Ended December 31, 2013 Compared to Year Ended December 31, 2012 Summary Net income attributable to HollyFrontier stockholders for the year ended December 31, 2013 was $735.8 million ($3.66 per basic and $3.64 per diluted share), a $991.4 million decrease compared to $1,727.2 million ($8.41 per basic and $8.38 per diluted share) for the year ended December 31, 2012. Net income decreased due principally to a year-over-year decrease in refining margins, refinery downtime and pension settlement and debt extinguishment charges. Refinery gross margins for the year ended December 31, 2013 decreased to $15.99 per produced barrel from $24.89 for the year ended December 31, 2012. Sales and Other Revenues Sales and other revenues increased slightly from $20,090.7 million for the year ended December 31, 2012 to $20,160.6 million for the year ended December 31, 2013 due to higher refined product sales volumes, partially offset by a decrease in year-over- year sales prices. The average sales price we received per produced barrel sold decreased 3% from $119.48 for the year ended December 31, 2012 to $115.60 for the year ended December 31, 2013. Refined product sales volumes for the current period reflect higher volumes of purchased products, comprising 8% of total refined products sales compared to 3% for the year ended December 31, 2012 due to a decrease in refinery production and corresponding sales volumes of produced product as a result of planned turnaround and maintenance projects at our refineries and other unplanned refinery outages during the current year. Sales and other revenues for the years ended December 31, 2013 and 2012 include $53.4 million and $47.6 million, respectively, in HEP revenues attributable to pipeline and transportation services provided to unaffiliated parties. Cost of Products Sold Cost of products sold increased 10% from $15,840.6 million for the year ended December 31, 2012 to $17,392.2 million for the year ended December 31, 2013, due principally to higher refined product sales volumes and crude costs for the current year. The sales volume increase is attributable to higher sales volumes of purchased products caused in part, by planned turnaround projects and unplanned refinery outages during the year ended December 31, 2013. The average price we paid per barrel for crude oil and feedstocks and the transportation costs of moving the finished products to the market place increased 5% from $94.59 for the year ended December 31, 2012 to $99.61 for the year ended December 31, 2013. Gross Refinery Margins Gross refinery margin per produced barrel decreased 36% from $24.89 for the year ended December 31, 2012 to $15.99 for the year ended December 31, 2013. This was due to a decrease in average per barrel sales prices for refined products sold combined with increased crude oil and feedstock prices for the current year. Gross refinery margin does not include the effects of depreciation and amortization. See “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K for a reconciliation to the income statement of prices of refined products sold and cost of products purchased. Operating Expenses Operating expenses, exclusive of depreciation and amortization, increased 10% from $995.0 million for the year ended December 31, 2012 to $1,090.9 million for the year ended December 31, 2013 due principally to higher repair and maintenance and fuel costs during the current year period and $31.7 million in pension settlement costs, partially offset by a decrease in environmental remediation costs. For the years ended December 31, 2013 and 2012, operating expenses include $95.7 million and $88.9 million, respectively, in costs attributable to HEP operations. General and Administrative Expenses General and administrative expenses were $128.0 million and $128.1 million for the years ended December 31, 2013 and 2012, respectively. For the years ended December 31, 2013 and 2012, general and administrative expenses include $9.4 million and $5.3 million, respectively, in costs attributable to HEP operations. Depreciation and Amortization Expenses Depreciation and amortization increased 25% from $242.9 million for the year ended December 31, 2012 to $303.4 million for the year ended December 31, 2013. The increase was due principally to depreciation and amortization attributable to capitalized improvement projects and capitalized refinery turnaround costs. For the years ended December 31, 2013 and 2012, depreciation and amortization expenses include $64.7 million and $57.8 million, respectively, in costs attributable to HEP operations. Interest Income Interest income for the year ended December 31, 2013 was $5.6 million compared to $4.8 million for the year ended December 31, 2012. This increase was due to interest received on increased investments in marketable debt securities during the current year period. 38 Table of Content Interest Expense Interest expense was $68.1 million for the year ended December 31, 2013 compared to $104.2 million for the year ended December 31, 2012. This decrease was due to lower year-over-year debt levels principally as a result of the redemption of our $286.8 million 9.875% senior notes in June 2013 and $200 million 8.5% senior notes in September 2012. For the years ended December 31, 2013 and 2012, interest expense included $46.8 million and $57.2 million, respectively, in interest costs attributable to HEP operations. Loss on Early Extinguishment of Debt In June 2013, we redeemed our $286.8 million aggregate principal amount of 9.875% senior notes maturing June 2017 at a redemption cost of $301.0 million, at which time we recognized a $22.1 million early extinguishment loss consisting of a $14.2 million debt redemption premium and an unamortized discount of $7.9 million. Income Taxes For the year ended December 31, 2013, we recorded income tax expense of $391.6 million compared to $1,028.0 million for the year ended December 31, 2012. This decrease was due principally to lower pre-tax earnings during the year ended December 31, 2013 compared to the same period of 2012. Our effective tax rates, before consideration of earnings attributable to the noncontrolling interest, were 33.8% and 36.9% for the years ended December 31, 2013 and 2012, respectively. Our effective tax rate for GAAP disclosure purposes reflects the inclusion of non-taxable earnings attributable to noncontrolling interest holders in the denominator of our effective tax rate computation. Results of Operations – Year Ended December 31, 2012 Compared to Year Ended December 31, 2011 Summary Net income attributable to HollyFrontier stockholders for the year ended December 31, 2012 was $1,727.2 million ($8.41 per basic and $8.38 per diluted share) a $703.8 million increase compared to $1,023.4 million ($6.46 per basic and $6.42 per diluted share) for the year ended December 31, 2011. Net income increased due principally to greater operating scale following our July 1, 2011 merger and higher refining margins in 2012. Refinery gross margins for the year ended December 31, 2012 increased to $24.89 per produced barrel compared to $20.64 for the year ended December 31, 2011. Sales and Other Revenues Sales and other revenues increased 30% from $15,439.5 million for the year ended December 31, 2011 to $20,090.7 million for the year ended December 31, 2012, due principally to the inclusion of sales volumes and related revenues attributable to the El Dorado and Cheyenne Refineries for a full year period and higher sales volumes of refined products produced from the legacy Holly refineries. Additionally, the average sales price we received per produced barrel sold increased 1% from $118.82 for the year ended December 31, 2011 to $119.48 for the year ended December 31, 2012. Sales and other revenues for the years ended December 31, 2012 and 2011, include $47.6 million and $46.4 million, respectively, in HEP revenues attributable to pipeline and transportation services provided to unaffiliated parties. Cost of Products Sold Cost of products sold increased 25% from $12,680.1 million for the year ended December 31, 2011 to $15,840.6 million for the year ended December 31, 2012, due principally to the inclusion of sales volumes and related cost of products sold at the El Dorado and Cheyenne Refineries, partially offset by lower crude oil costs for 2012. The average price we paid per barrel for crude oil and feedstocks and the transportation costs of moving the finished products to the market place decreased 4% from $98.18 for the year ended December 31, 2011 to $94.59 for the year ended December 31, 2012. Gross Refinery Margins Gross refining margin per produced barrel increased 21% from $20.64 for the year ended December 31, 2011 to $24.89 for the year ended December 31, 2012. This is due to the effects of a current year decrease in crude oil and feedstock prices along with slightly higher sales prices received on produced products sold. Gross refinery margin does not include the effects of depreciation or amortization. 39 Table of Content Operating Expenses Operating expenses, exclusive of depreciation and amortization increased 33% from $748.1 million for the year ended December 31, 2011 to $995.0 million for the year ended December 31, 2012, due principally to the inclusion of the legacy Frontier refinery operations for a full-year period and higher repair and maintenance and environmental remediation costs. In 2012, we increased certain environmental remediation accruals by $46.1 million to reflect revisions to certain cost estimates and the timeframe for which certain environmental remediation and monitoring activities are expected to occur. Also contributing to a much lesser extent were increased payroll costs attributable to the legacy Holly refining operations. For the years ended December 31, 2012 and 2011, operating expenses include $88.9 million and $61.1 million, respectively, in costs attributable to HEP operations. General and Administrative Expenses General and administrative expenses increased 7% from $120.1 million for the year ended December 31, 2011 to $128.1 million for the year ended December 31, 2012, due principally to higher employee benefit and equity-based compensation costs and increased corporate staffing levels as a result of our July 1, 2011 merger, net of the effects of merger related severance and integration costs incurred during 2011. For the years ended December 31, 2012 and 2011, general and administrative expenses include $5.3 million and $4.3 million, respectively, in costs attributable to HEP operations. Depreciation and Amortization Expenses Depreciation and amortization increased 52% from $159.7 million for the year ended December 31, 2011 to $242.9 million for the year ended December 31, 2012. The increase was due principally to depreciation and amortization attributable to the legacy Frontier refinery assets, capitalized improvement projects and HEP's UNEV Pipeline. For the years ended December 31, 2012 and 2011, depreciation and amortization expenses include $57.8 million and $33.3 million, respectively, in costs attributable to HEP operations. Interest Income Interest income for the year ended December 31, 2012 was $4.8 million compared to $1.3 million for the year ended December 31, 2011. This increase was due to interest received on our increased cash position and investments in marketable debt securities. Interest Expense Interest expense was $104.2 million for the year ended December 31, 2012 compared to $78.3 million for the year ended December 31, 2011. This increase principally reflects interest on the senior notes assumed upon our merger with Frontier. For the years ended December 31, 2012 and 2011, interest expense included $57.2 million and $38.2 million, respectively, in interest costs attributable to HEP operations. Merger Transaction Costs For the year ended December 31, 2011, we recognized merger transaction costs of $15.1 million related to our merger with Frontier on July 1, 2011. These costs included legal, advisory and other professional fees that were directly attributable to the merger. There were no such costs incurred for the year ended December 31, 2012. Income Taxes For the year ended December 31, 2012, we recorded income tax expense of $1,028.0 million compared to $582.0 million for the year ended December 31, 2011. This increase is due principally to significantly higher pre-tax earnings for the year ended December 31, 2012 compared to the same period of 2011. Our effective tax rates, before consideration of earnings attributable to the noncontrolling interest, were 36.9% and 35.5% for the years ended December 31, 2012 and 2011, respectively. Our effective tax rate for GAAP disclosure purposes reflects the inclusion of non-taxable earnings attributable to noncontrolling interest holders in the denominator of our effective tax rate computation. LIQUIDITY AND CAPITAL RESOURCES HollyFrontier Credit Agreement We have a $1 billion senior secured credit agreement that matures in July 2016 (the “HollyFrontier Credit Agreement”) and may be used to fund working capital requirements, capital expenditures, acquisitions and general corporate purposes. Obligations under the HollyFrontier Credit Agreement are collateralized by our inventory, accounts receivables and certain deposit accounts and guaranteed by our material, wholly-owned subsidiaries. At December 31, 2013, we were in compliance with all covenants, had no outstanding borrowings and had outstanding letters of credit totaling $5.2 million under the HollyFrontier Credit Agreement. 40 Table of Content HEP Credit Agreement HEP has a $650 million senior secured revolving credit facility that matures in November 2018 (the “HEP Credit Agreement”) and is available to fund capital expenditures, investments, acquisitions, distribution payments and working capital and for general partnership purposes. It is also available to fund letters of credit up to a $50 million sub-limit. At December 31, 2013, HEP was in compliance with all of its covenants, had outstanding borrowings of $363.0 million and no outstanding letters of credit under the HEP Credit Agreement. Indebtedness under the HEP Credit Agreement bears interest, at their option, at either a reference rate announced by the administrative agent plus an applicable margin or at a rate equal to LIBOR plus an applicable margin. In each case, the applicable margin is based upon the ratio of HEP’s funded debt to earnings before interest, taxes, depreciation and amortization (as defined in the HEP Credit Agreement). The interest rates in effect on HEP’s Credit Agreement borrowings were 2.163% and 2.456% at December 31, 2013 and 2012, respectively. HEP’s obligations under the HEP Credit Agreement are collateralized by substantially all of HEP’s assets (presented parenthetically in our consolidated balance sheets). Indebtedness under the HEP Credit Agreement involves recourse to HEP Logistics Holdings, L.P., its general partner, and is guaranteed by HEP’s wholly-owned subsidiaries. Any recourse to the general partner would be limited to the extent of HEP Logistics Holdings, L.P.’s assets, which other than its investment in HEP, are not significant. HEP’s creditors have no recourse to our other assets. Furthermore, our creditors have no recourse to the assets of HEP and its consolidated subsidiaries. HollyFrontier Senior Notes Our 6.875% senior notes ($150.0 million principal amount maturing November 2018) (the “HollyFrontier Senior Notes”) are unsecured and impose certain restrictive covenants, including limitations on our ability to incur additional debt, incur liens, enter into sale-and-leaseback transactions, pay dividends, enter into mergers, sell assets and enter into certain transactions with affiliates. Additionally, we have certain redemption rights under the HollyFrontier Senior Notes. At any time, following notice to the trustee, that the HollyFrontier Senior Notes are rated investment grade by both Moody's and Standard & Poor's and no default or event of default exists, we are not subject to many of the foregoing covenants (a "Covenant Suspension"). As of December 31, 2013, the HollyFrontier Senior Notes were rated investment grade (BBB-) by Standard & Poor's and also investment grade (Baa3) by Moody's. As a result, we are under the Covenant Suspension pursuant to the terms of the indenture governing the HollyFrontier Senior Notes. In June 2013, we redeemed our $286.8 million aggregate principal amount of 9.875% senior notes maturing June 2017. HollyFrontier Financing Obligation We have a financing obligation that relates to a sale and lease-back of certain crude oil tankage that we sold to an affiliate of Plains All American Pipeline, L.P. (“Plains”) in October 2009 for $40.0 million. Monthly lease payments are recorded as a reduction in principal over the 15-year lease term ending in 2024. HEP Senior Notes HEP’s senior notes consist of the following: • • 8.25% HEP senior notes ($150 million principal amount maturing March 2018) 6.5% HEP senior notes ($300 million principal amount maturing March 2020) The 8.25% and 6.5% HEP senior notes (collectively, the “HEP Senior Notes”) are unsecured and impose certain restrictive covenants, including limitations on HEP’s ability to incur additional indebtedness, make investments, sell assets, incur certain liens, pay distributions, enter into transactions with affiliates, and enter into mergers. At any time when the HEP Senior Notes are rated investment grade by both Moody’s and Standard & Poor’s and no default or event of default exists, HEP will not be subject to many of the foregoing covenants. Additionally, HEP has certain redemption rights under the HEP Senior Notes. On February 12, 2014, HEP announced that it will redeem all of its outstanding 8.25% senior notes. The redemption price will be equal to 104.125% of the principal amount for a total payment to the holders of the notes of approximately $156.2 million plus accrued interest. The redemption of the 8.25% senior notes is scheduled to occur on March 15, 2014. HEP plans to fund the redemption with borrowings under the HEP Credit Agreement. Indebtedness under the HEP Senior Notes involves recourse to HEP Logistics Holdings, L.P., its general partner, and is guaranteed by HEP’s wholly-owned subsidiaries. However, any recourse to the general partner would be limited to the extent of HEP Logistics Holdings, L.P.’s assets, which other than its investment in HEP, are not significant. HEP’s creditors have no other recourse to our assets. Furthermore, our creditors have no recourse to the assets of HEP and its consolidated subsidiaries. 41 Table of Content HEP Common Unit Issuance In March 2013, HEP closed on a public offering of 1,875,000 of its common units. Additionally, our wholly-owned subsidiary, HollyFrontier Holdings LLC, as a selling unitholder, closed on a public sale of 1,875,000 HEP common units held by it. HEP used net proceeds of $73.4 million to repay indebtedness incurred under its credit facility and for general partnership purposes. Liquidity We believe our current cash and cash equivalents, along with future internally generated cash flow and funds available under our credit facilities will provide sufficient resources to fund currently planned capital projects and our liquidity needs for the foreseeable future. In addition, components of our growth strategy include construction of new refinery processing units and the expansion of existing units at our facilities and selective acquisition of complementary assets for our refining operations intended to increase earnings and cash flow. As of December 31, 2013, our cash, cash equivalents and investments in marketable securities totaled $1.7 billion. We consider all highly-liquid instruments with a maturity of three months or less at the time of purchase to be cash equivalents. Cash equivalents are stated at cost, which approximates market value. These primarily consist of investments in conservative, highly-rated instruments issued by financial institutions, government and corporate entities with strong credit standings and money market funds. We have a Board approved stock repurchase program that authorizes us to repurchase common stock in the open market or through privately negotiated transactions. The timing and amount of stock repurchases will depend on market conditions, corporate, regulatory and other relevant considerations. This program may be discontinued at any time by the Board of Directors. As of December 31, 2013, we had remaining authorization to repurchase up to $311.6 million under this stock repurchase program. Cash and cash equivalents decreased $817.6 million for the year ended December 31, 2013. Net cash used for investing and financing activities of $526.7 million and $1,160.0 million, respectively, exceeded net cash provided by operating activities of $869.2 million. Working capital decreased by $593.9 million during the year ended December 31, 2013. Cash Flows – Operating Activities Year Ended December 31, 2013 Compared to Year Ended December 31, 2012 Net cash flows provided by operating activities were $869.2 million for the year ended December 31, 2013 compared to $1,662.7 million for the year ended December 31, 2012, a decrease of $793.5 million. Net income for the year ended December 31, 2013 was $767.8 million, a decrease of $992.2 million compared to $1,760.0 million for the year ended December 31, 2012. Reconciling adjustments to net income consisted of depreciation and amortization, earnings of equity method investments, net of distributions, the write-off of an unamortized discount on the early extinguishment of debt, gain on sale of equity securities, deferred income taxes, equity-based compensation expense, fair value changes to derivative instruments and loss on settlement of retirement benefit obligations, net of contributions which totaled $430.4 million for the year ended December 31, 2013 compared to $410.7 million for the same period in 2012. Changes in working capital items decreased cash flows by $157.0 million for the year ended December 31, 2013 compared to $398.0 million for the year ended December 31, 2012. Additionally, for the year ended December 31, 2013, refinery turnaround expenditures increased to $193.9 million from $159.7 million for the same period of 2012. Year Ended December 31, 2012 Compared to Year Ended December 31, 2011 Net cash flows provided by operating activities were $1,662.7 million for the year ended December 31, 2012 compared to $1,338.4 million for the year ended December 31, 2011, an increase of $324.3 million. Net income for the year ended December 31, 2012 was $1,760.0 million, an increase of $700.3 million compared to $1,059.7 million for the year ended December 31, 2011. Reconciling adjustments consisting of depreciation and amortization, earnings of equity method investments, net of distributions, gain on sale of equity securities, deferred income taxes, equity-based compensation expense, fair value changes to derivative instruments and loss on settlement of retirement benefit obligations, net of contributions resulted in an increase to operating cash flows of $433.0 million for the year ended December 31, 2012 compared to $182.3 million for the same period in 2011. Changes in working capital items decreased cash flows by $398.0 million for the year ended December 31, 2012 compared to an increase of $147.3 million for the year ended December 31, 2011. The decrease in working capital items for the year ended December 31, 2012 was due principally to higher inventory levels and a decrease in income taxes payable and accrued liabilities due to timing differences of payments during the fourth quarter of 2012 relative to 2011. Additionally, for the year ended December 31, 2012, refinery turnaround expenditures increased to $159.7 million from $32.0 million for the same period of 2011. 42 Table of Content Cash Flows – Investing Activities and Planned Capital Expenditures Year Ended December 31, 2013 Compared to Year Ended December 31, 2012 Net cash flows used for investing activities were $526.7 million for the year ended December 31, 2013 compared to $711.1 million for the year ended December 31, 2012, a decrease of $184.4 million. Cash expenditures for properties, plants and equipment for 2013 increased to $425.1 million from $335.3 million for the same period in 2012. These include HEP capital expenditures of $51.9 million and $44.9 million for the years ended December 31, 2013 and 2012, respectively. In addition, for the year ended December 31, 2013, we received proceeds of $7.8 million from the sale of property and equipment, invested and advanced a net total of $8.7 million to Sabine Biofuels and acquired trucking operations for $11.3 million. For the year ended December 31, 2012, we invested $2.0 million in Sabine Biofuels. Also for the years ended December 31, 2013 and 2012, we invested $935.5 million and $671.6 million, respectively, in marketable securities and received proceeds of $846.1 million and $297.7 million, respectively, from the sale or maturity of marketable securities. Year Ended December 31, 2012 Compared to Year Ended December 31, 2011 Net cash flows used for investing activities were $711.1 million for the year ended December 31, 2012 compared to net cash flows provided by investing activities of $228.5 million for the year ended December 31, 2011, a decrease of $939.6 million. Investing activities for 2011 reflect a net cash inflow due to an $872.7 million increase in cash and cash equivalents as a result of our July 1, 2011 merger with Frontier. Cash expenditures for properties, plants and equipment for 2012 decreased to $335.3 million from $374.2 million for the same period in 2011. These include HEP capital expenditures of $44.9 million and $216.2 million for the years ended December 31, 2012 and 2011, respectively, which include 2011 capital expenditures of $164.3 million to construct the UNEV Pipeline. Also for the years ended December 31, 2012 and 2011, we invested $2.0 million and $9.1 million, respectively, in Sabine Biofuels and $671.6 million and $561.9 million, respectively, in marketable securities and received proceeds of $297.7 million and $301.0 million, respectively, from the sale or maturity of marketable securities. Planned Capital Expenditures HollyFrontier Corporation Each year our Board of Directors approves our annual capital budget which includes specific projects that management is authorized to undertake. Additionally, when conditions warrant or as new opportunities arise, additional projects may be approved. The funds appropriated for a particular capital project may be expended over a period of several years, depending on the time required to complete the project. Therefore, our planned capital expenditures for a given year consist of expenditures appropriated in that year’s capital budget plus expenditures for projects appropriated in prior years which have not yet been completed. Our appropriated capital budget for 2014 is $185.0 million including both sustaining capital and major capital projects. We expect to spend approximately $400.0 million to $450.0 million in cash for capital projects appropriated in 2014 and prior years. In addition, we expect to spend $77.0 million on refinery turnarounds. Refinery turnaround spending is amortized over the useful life of the turnaround. Our new capital appropriation for 2014 and expected cash spending is as follows: New Appropriation Expected Cash Spending Range (In millions) Location: El Dorado Tulsa Navajo Cheyenne Woods Cross Corporate and Other Total Type: Sustaining Reliability and Growth Compliance and Safety Total $ $ $ $ 43.0 22.0 17.0 74.0 14.0 15.0 $ 85.0 – $ 54.0 – 24.0 – 80.0 – 142.0 – 15.0 – 96.0 61.0 27.0 90.0 160.0 16.0 185.0 $ 400.0 – $ 450.0 51.0 40.0 94.0 $ 66.0 – $ 234.0 – 100.0 – 185.0 $ 400.0 – $ 74.0 263.0 113.0 450.0 43 Table of Content A significant portion of our current capital spending is associated with compliance-oriented capital improvements. This spending is required due to existing consent decrees (for projects including FCC unit flue gas scrubbers and tail gas treatment units), federal fuels regulations (particularly, MSAT2 which mandates a reduction in the benzene content of blended gasoline), refinery waste water treatment improvements and other similar initiatives. Our refinery operations and related emissions are highly regulated at both federal and state levels, and we invest in our facilities as needed to remain in compliance with these standards. Additionally, when faced with new emissions or fuels standards, we seek to execute projects that facilitate compliance and also improve the operating costs and/or yields of associated refining processes. El Dorado Refinery Capital projects at the El Dorado Refinery include naphtha fractionation, an additional hydrogen plant and a Low-Nox addition to the FCC unit flue gas scrubber. Continuing project work is planned to include upgrades to the FCC unit to improve liquid yield, upgrades to the crude unit desalter and a new tail gas treatment unit to reduce air emissions in compliance with the El Dorado Refinery's existing EPA consent decree. Tulsa Refineries Capital spending for the Tulsa Refineries in 2014 includes previously approved capital appropriations for a gasoline-blending system and numerous infrastructure upgrades. Spending on maintenance capital items and general improvements continues at an elevated level at the Tulsa Refineries due to perceived opportunities. Navajo Refinery The Navajo Refinery capital spending in 2014 will be principally on previously approved capital appropriations as well as maintenance capital spending. Included among previously approved capital projects is a $25.0 million upgrade to the Navajo Refinery's waste water treatment system. Cheyenne Refinery We are continuing with our previously approved plan to install a new hydrogen plant at the Cheyenne Refinery. The hydrogen plant, along with a previously approved naphtha fractionation project, is anticipated to allow us to reduce benzene content in Cheyenne gasoline production, while at the same time improving the refinery's overall liquid yields and light oils production. Previously appropriated projects still underway at Cheyenne include wastewater treatment plant improvements, a wet gas scrubber for the FCC unit to reduce air emissions, a redundant tail gas unit associated with sulfur recovery processes and additional investment in the waste water treatment plant to reduce selenium concentration in waste water. Woods Cross Refinery Engineering continues on our previously announced expansion project to increase planned processing capacity to 45,000 BPSD, which is expected to cost $300.0 million. On November 18, 2013, the Utah Division of Air Quality issued a revised air quality permit (the “Approval Order”) authorizing the expansion. On December 18, 2013, two local environmental groups filed an administrative appeal challenging the issuance of the Approval Order and seeking a stay of the Approval Order. The matter is now pending before an administrative law judge of the Utah Department of Environmental Quality. The expansion is expected to be completed in the fourth quarter of 2015. This project work includes a new rail loading rack for intermediates and finished products associated with refining waxy crude oil. Long lead equipment has been ordered and detailed engineering is approximately 60% completed. The expansion, and expected completion timeline and cost, are subject to the Woods Cross refinery successfully obtaining the Approval Order. Regulatory compliance items or other presently existing or future environmental regulations / consent decrees could cause us to make additional capital investments beyond those described above and incur additional operating costs to meet applicable requirements. HEP Each year the Holly Logistic Services, L.L.C. board of directors approves HEP’s annual capital budget, which specifies capital projects that HEP management is authorized to undertake. Additionally, at times when conditions warrant or as new opportunities arise, special projects may be approved. The funds allocated for a particular capital project may be expended over a period of several years, depending on the time required to complete the project. Therefore, HEP’s planned capital expenditures for a given year consist of expenditures approved for capital projects included in its current year capital budget as well as, in certain cases, expenditures approved for capital projects in capital budgets for prior years. The 2014 HEP capital budget is comprised of $7.3 million for maintenance capital expenditures and $26.2 million for expansion capital expenditures. HEP expects to spend approximately $52.0 million in cash for capital projects approved in 2014 plus those approved in prior years but not yet completed, such as the projects discussed below. 44 Table of Content HEP is proceeding with the expansion of its crude oil transportation system in southeastern New Mexico in response to increased crude oil production in the area. The expansion should provide shippers with additional pipeline takeaway capacity to either common carrier pipeline stations for transportation to major crude oil markets or to our New Mexico refining facilities. To complete the project, HEP plans to convert an existing refined products pipeline to crude oil service, construct several new pipeline segments, expand an existing pipeline and build new truck unloading stations and crude storage capacity. Excluding the value of the existing pipeline to be converted, total capital expenditures are expected to cost between $45.0 million and $50.0 million. The project is expected to provide increased capacity of up to 100,000 BPD across HEP's system and is expected to be in full service no later than August 2014. UNEV is proceeding with a project to enhance its product terminal in Las Vegas, Nevada. HEP expects that the project will cost approximately $13.0 million with construction expected to be completed no later than the second quarter of 2014. Cash Flows – Financing Activities Year Ended December 31, 2013 Compared to Year Ended December 31, 2012 Net cash flows used for financing activities were $1,160.0 million for the year ended December 31, 2013 compared to $772.8 million for the year ended December 31, 2012, an increase of $387.2 million. During the year ended December 31, 2013, we received $73.4 million from the sale of HEP common units, purchased $225.0 million in common stock, paid $645.9 million in dividends, paid $301.0 million upon the redemption of our 9.875% senior notes and recognized $2.6 million excess tax benefits on our equity-based compensation. Also during this period, HEP received $310.6 million and repaid $368.6 million under the HEP Credit Agreement, paid distributions of $71.2 million to noncontrolling interests, purchased $5.3 million in HEP common units for recipients of its incentive grants and received proceeds of $73.4 million upon its March 2013 common unit offering. During the year ended December 31, 2012, we purchased $209.6 million in common stock, paid $658.1 million in dividends, received an $8.6 million payment pursuant to a structured share repurchase arrangement, paid $205.0 million in principal on our 9.875% senior notes and recognized $23.4 million excess tax benefits on our equity-based compensation. Also during this period, HEP received $294.8 million in net proceeds upon the issuance of the HEP 6.5% senior notes, paid $185.0 million in principal on the HEP 6.25% senior notes, received $587.0 million and repaid $366.0 million under the HEP Credit Agreement, paid distributions of $58.8 million to noncontrolling interests, incurred $3.3 million in deferred financing costs and purchased $5.2 million in HEP common units in the open market for recipients of its incentive grants. Additionally, UNEV joint venture partner contributions of $6.0 million were received during the year ended December 31, 2012. Year Ended December 31, 2012 Compared to Year Ended December 31, 2011 Net cash flows used for financing activities were $772.8 million for the year ended December 31, 2012 compared to $217.1 million for the year ended December 31, 2011, an increase of $555.7 million. During the year ended December 31, 2012, we purchased $209.6 million in common stock, paid $658.1 million in dividends, received an $8.6 million payment pursuant to a structured share repurchase arrangement, paid $205.0 million in principal on our 9.875% senior notes and recognized $23.4 million excess tax benefits on our equity-based compensation. Also during this period, HEP received $294.8 million in net proceeds upon the issuance of the HEP 6.5% senior notes, paid $185.0 million in principal on the HEP 6.25% senior notes, received $587.0 million and repaid $366.0 million under the HEP Credit Agreement, paid distributions of $58.8 million to noncontrolling interests, incurred $3.3 million in deferred financing costs and purchased $5.2 million in HEP common units in the open market for recipients of its incentive grants. During the year ended December 31, 2011, we purchased $42.8 million in common stock, paid $252.1 million in dividends, paid $8.2 million in principal on our senior notes and recognized $1.8 million excess tax benefits on our equity- based compensation. Additionally, we incurred $8.6 million in deferred financing costs. Also during this period, HEP received $75.8 million in net proceeds upon the issuance of HEP common units, received $118.0 million and repaid $77.0 million under the HEP Credit Agreement, paid distributions of $50.9 million to noncontrolling interests, incurred $3.2 million in deferred financing costs and purchased $1.6 million in HEP common units in the open market for recipients of its incentive grants. UNEV joint venture partner contributions received during the years ended December 31, 2012 and 2011 were $6.0 million and $33.5 million, respectively. Contractual Obligations and Commitments The following table presents our long-term contractual obligations as of December 31, 2013 in total and by period due beginning in 2014. The table below does not include our contractual obligations to HEP under our long-term transportation agreements as these related-party transactions are eliminated in the Consolidated Financial Statements. A description of these agreements is provided under “Holly Energy Partners, L.P.” under Items 1 and 2, “Business and Properties.” Also, the table below does not reflect renewal options on our operating leases that are likely to be exercised. 45 Table of Content Contractual Obligations and Commitments Total Less than 1 Year Payments Due by Period 1-3 Years (In thousands) 3-5 Years Over 5 Years HollyFrontier Corporation (1) (2) Long-term debt - principal (3) Long-term debt - interest (4) Supply agreements (5) Transportation and storage agreements (6) Other long-term obligations Operating leases Holly Energy Partners Long-term debt - principal (7) Long-term debt - interest (8) Pipeline operating and right of way leases Other agreements $ 184,835 $ 1,666 $ 4,001 $ 155,093 $ 24,075 78,511 902,799 1,274,077 25,734 63,194 14,446 599,759 144,434 9,838 16,835 28,224 279,030 265,304 14,890 28,600 26,273 13,720 9,568 10,290 205,015 659,324 1,006 13,297 — 4,462 2,529,150 786,978 620,049 414,404 707,719 813,000 221,804 24,607 17,034 1,076,445 — 39,748 6,874 1,987 48,609 — 79,497 13,729 3,904 97,130 513,000 73,309 3,642 3,904 300,000 29,250 362 7,239 593,855 336,851 Total $ 3,605,595 $ 835,587 $ 717,179 $1,008,259 $ 1,044,570 (1) We may be required to make cash outlays related to our unrecognized tax benefits. However, due to the uncertainty of the timing of future cash flows associated with our unrecognized tax benefits, we are unable to make reasonably reliable estimates of the period of cash settlement, if any, with the respective taxing authorities. Accordingly, unrecognized tax benefits of $9.0 million as of December 31, 2013 have been excluded from the contractual obligations table above. For further information related to unrecognized tax benefits, see Note 14 “Income Taxes” in the Notes to Consolidated Financial Statements. (2) Amounts shown do not include commitments to deliver barrels of crude oil held for other parties at our refineries. We periodically hold crude oil owned by third parties in the storage tanks at our refineries, which may be run through production. We will be obligated to deliver these stored barrels of crude oil upon the other party's request. (3) Our long-term debt consists of the $150.0 million principal balance on our 6.875% senior notes and a long-term financing obligation having a principal balance of $34.8 million at December 31, 2013. Interest payments consist of interest on our 6.875% senior notes and on our long-term financing obligation. (4) (5) We have long-term supply agreements to secure certain quantities of crude oil, feedstock and other resources used in the production process at market prices. We have estimated future payments under these fixed-quantity agreements expiring between 2014 and 2020 using current market rates. (6) Consists of contractual obligations under agreements with third parties for the transportation of crude oil, natural gas and feedstocks to our refineries and for terminal and storage services under contracts expiring between 2014 and 2032. (7) HEP's long-term debt consists of the $150.0 million and the $300.0 million principal balances on the 8.25% and 6.5% HEP senior notes and $363.0 (8) million of outstanding borrowings under the HEP Credit Agreement. The HEP Credit Agreement expires in 2017. Interest payments consist of interest on the 6.5% and 8.25% HEP senior notes and interest on long-term debt under the HEP Credit Agreement. Interest on the HEP Credit Agreement debt is based on the applicable rate of 2.17% at December 31, 2013. CRITICAL ACCOUNTING POLICIES Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities as of the date of the financial statements. Actual results may differ from these estimates under different assumptions or conditions. We consider the following policies to be the most critical to understanding the judgments that are involved and the uncertainties that could impact our results of operations, financial condition and cash flows. For additional information, see Note 1 “Description of Business and Summary of Significant Accounting Policies” in the Notes to Consolidated Financial Statements. 46 Table of Content Variable Interest Entities HEP is a VIE as defined under GAAP. A VIE is a legal entity whose equity owners do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support or, as a group, the equity holders lack the power, through voting rights, to direct the activities that most significantly impact the entity's financial performance. As the general partner of HEP, we have the sole ability to direct the activities of HEP that most significantly impact HEP's financial performance, and therefore we consolidate HEP. We have a 50% ownership interest in Sabine Biofuels, a biofuels production facility that is also a VIE. We do not hold a controlling financial interest, nor do we have the power to direct the activities that most significantly impact its financial performance. Accordingly, we account for our investment using the equity method of accounting. Derivative Instruments We have commodity price swap, interest rate swap, physical and NYMEX futures contracts that are measured at fair value and recognized as other assets or liabilities in our consolidated balance sheets. Changes in fair value to derivative instruments are recognized in earnings unless specific hedge accounting criteria is met. Derivatives meeting certain hedge accounting criteria are designated as “accounting hedges” and changes in fair value are recorded directly to other comprehensive income. These gains or losses are reclassified to earnings as the hedging instruments mature. Also, on a quarterly basis, hedge ineffectiveness on our accounting hedges is measured by comparing the change in fair value of the derivative contracts against the expected future cash inflows/outflows on the respective transaction being hedged. Any hedge ineffectiveness is recognized in earnings. See Note 13 “Derivative Instruments and Hedging Activities” in the Notes to Consolidated Financial Statements. Inventory Valuation Our crude oil and refined product inventories are stated at the lower of cost or market. Cost is determined using the LIFO inventory valuation methodology and market is determined using current estimated selling prices. Under the LIFO method, the most recently incurred costs are charged to cost of sales and inventories are valued at the earliest acquisition costs. In periods of rapidly declining prices, LIFO inventories may have to be written down to market value due to the higher costs assigned to LIFO layers in prior periods. In addition, the use of the LIFO inventory method may result in increases or decreases to cost of sales in years when inventory volumes decline and result in charging cost of sales with LIFO inventory costs generated in prior periods. As of December 31, 2013, many of our LIFO inventory layers were valued at historical costs that were established in years when price levels were generally lower; therefore, our results of operation are less sensitive to current market price reductions. As of December 31, 2013, the excess of current cost over the LIFO inventory value of our crude oil and refined product inventories was $273.0 million. An actual valuation of inventory under the LIFO method is made at the end of each year based on the inventory levels at that time. Accordingly, interim LIFO calculations are based on management's estimates of expected year-end inventory levels and are subject to the final year-end LIFO inventory valuation. Deferred Maintenance Costs Our refinery units require regular major maintenance and repairs that are commonly referred to as “turnarounds.” Catalysts used in certain refinery processes also require routine “change-outs.” The required frequency of the maintenance varies by unit and by catalyst, but generally is every two to five years. In order to minimize downtime during turnarounds, we often utilize contract labor as well as our maintenance personnel on a continuous 24 hour basis. Whenever possible, turnarounds are scheduled so that some units continue to operate while others are down for maintenance. We record the costs of turnarounds as deferred charges and amortize the deferred costs over the expected periods of benefit. Long-lived Assets We calculate depreciation and amortization based on estimated useful lives and salvage values of our assets. When assets are placed into service, we make estimates with respect to their useful lives that we believe are reasonable. However, factors such as competition, regulation or environmental matters could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization. We evaluate long-lived assets for potential impairment by identifying whether indicators of impairment exist and, if so, assessing whether the long-lived assets are recoverable from estimated future undiscounted cash flows. The actual amount of impairment loss, if any, to be recorded is equal to the amount by which a long-lived asset's carrying value exceeds its fair value, which is generally determined under an income approach using forecasted cash flows associated with the underlying asset. Estimates of future cash flows require subjective assumptions with regard to future operating results and actual results could differ from those estimates. No impairments of long-lived assets were recorded during the years ended December 31, 2013, 2012 and 2011. 47 Table of Content Intangibles and Goodwill Intangible assets are assets (other than financial assets) that lack physical substance. Goodwill represents the excess of the cost of an acquired entity over the fair value of the assets acquired and liabilities assumed. Goodwill acquired in a business combination and intangible assets with indefinite useful lives are not amortized while intangible assets with finite useful lives are amortized on a straight-line basis. Goodwill and intangible assets not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate the possibility of impairment. Our analysis entails a comparison of the estimated fair value of these assets that are derived using a combination of both income (discounted future expected net cash flows) and comparable market approaches against their respective carrying values. Estimates of future cash flows and fair value of assets require subjective assumptions with regard to future operating results and actual results could differ from those estimates. There were no impairments of intangible assets or goodwill during the years ended December 31, 2013, 2012 and 2011. Environmental Costs: Environmental costs are charged to operating expenses if they relate to an existing condition caused by past operations and do not contribute to current or future revenue generation. Liabilities are recorded when site restoration and environmental remediation, cleanup and other obligations are either known or considered probable and can be reasonably estimated. Such estimates require judgment with respect to costs, time frame and extent of required remedial and clean-up activities and are subject to periodic adjustments based on currently available information. Recoveries of environmental costs through insurance, indemnification arrangements or other sources are included in other assets to the extent such recoveries are considered probable. Contingencies We are subject to proceedings, lawsuits and other claims related to environmental, labor, product and other matters. We are required to assess the likelihood of any adverse judgments or outcomes to these matters as well as potential ranges of probable losses. A determination of the amount of reserves required, if any, for these contingencies is made after careful analysis of each individual issue. The required reserves may change in the future due to new developments in each matter or changes in approach such as a change in settlement strategy in dealing with these matters. RISK MANAGEMENT We use certain strategies to reduce some commodity price and operational risks. We do not attempt to eliminate all market risk exposures when we believe that the exposure relating to such risk would not be significant to our future earnings, financial position, capital resources or liquidity or that the cost of eliminating the exposure would outweigh the benefit. Commodity Price Risk Management Our primary market risk is commodity price risk. We are exposed to market risks related to the volatility in crude oil and refined products, as well as volatility in the price of natural gas used in our refining operations. We periodically enter into derivative contracts in the form of commodity price swaps and futures contracts to mitigate price exposure with respect to: • • • • • our inventory positions; natural gas purchases; costs of crude oil and related grade differentials; prices of refined products; and our refining margins. 48 Table of Content As of December 31, 2013, we have the following notional contract volumes related to all outstanding derivative contracts used to mitigate commodity price risk: Contract Description Notional Contract Volumes by Year of Maturity Total Outstanding Notional 2014 2015 2016 2017 Unit of Measure Natural gas price swap - long 76,800,000 19,200,000 19,200,000 19,200,000 19,200,000 MMBTU Natural gas price swap - short 38,400,000 9,600,000 9,600,000 9,600,000 9,600,000 MMBTU WTI price swap - long 18,797,500 16,242,500 2,555,000 Ultra-low sulfur diesel price swap - short 15,512,500 12,957,500 2,555,000 Sub octane gasoline price swap - short 3,285,000 3,285,000 WCS price swap - long NYMEX futures (WTI) - short Physical contracts - long Physical contracts - short 6,387,500 6,387,500 1,946,000 1,946,000 300,000 300,000 300,000 300,000 — — — — — — — — — — — — — Barrels — Barrels — Barrels — Barrels — Barrels — Barrels — Barrels The following sensitivity analysis provides the hypothetical effects of market price fluctuations to the commodity positions hedged under our derivative contracts: Commodity-based Derivative Contracts 2013 2012 Hypothetical 10% change in underlying commodity prices $ (In thousands) 69,228 $ 29,230 Estimated Change in Fair Value at December 31, Interest Rate Risk Management HEP uses interest rate swaps to manage its exposure to interest rate risk. As of December 31, 2013, HEP had three interest rate swap contracts that hedge its exposure to the cash flow risk caused by the effects of LIBOR changes on $305.0 million in credit agreement advances. The first interest rate swap effectively converts $155.0 million of LIBOR based debt to fixed rate debt having an interest rate of 0.99% plus an applicable margin of 2.00% as of December 31, 2013, which equaled an effective interest rate of 2.99%. This swap matures in February 2016. HEP has two additional interest rate swaps with identical terms which effectively convert $150.0 million of LIBOR based debt to fixed rate debt having an interest rate of 0.74% plus an applicable margin of 2.00% as of December 31, 2013, which equaled an effective interest rate of 2.74%. Both of these swap contracts mature in July 2017. These swap contracts have been designated as cash flow hedges. The market risk inherent in our fixed-rate debt and positions is the potential change arising from increases or decreases in interest rates as discussed below. For the fixed rate HollyFrontier Senior Notes and HEP Senior Notes, changes in interest rates will generally affect fair value of the debt, but not our earnings or cash flows. The outstanding principal, estimated fair value and estimated change in fair value (assuming a hypothetical 10% change in the yield-to-maturity rates) for these debt instruments as of December 31, 2013 is presented below: HollyFrontier Senior Notes HEP Senior Notes Outstanding Principal Estimated Fair Value (In thousands) Estimated Change in Fair Value $ $ 150,000 450,000 $ $ 161,250 471,750 $ $ 3,443 12,884 For the variable rate HEP Credit Agreement, changes in interest rates would affect cash flows, but not the fair value. At December 31, 2013, outstanding borrowings under the HEP Credit Agreement were $363.0 million. By means of its cash flow hedges, HEP has effectively converted the variable rate on $305.0 million of outstanding principal to a weighted average fixed rate of 2.87%. 49 Table of Content At December 31, 2013, our marketable securities included investments in investment grade, highly-liquid investments with maturities generally not greater than one year from the date of purchase and hence the interest rate market risk implicit in these investments is low. Due to the short-term nature of our cash and cash equivalents, a hypothetical 10% increase in interest rates would not have a material effect on the fair market value of our portfolio. Since we have the ability to liquidate this portfolio, we do not expect our operating results or cash flows to be materially affected by the effect of a sudden change in market interest rates on our investment portfolio. Our operations are subject to hazards of petroleum processing operations, including fire, explosion and weather-related perils. We maintain various insurance coverages, including business interruption insurance, subject to certain deductibles. We are not fully insured against certain risks because such risks are not fully insurable, coverage is unavailable, or premium costs, in our judgment, do not justify such expenditures. Financial information is reviewed on the counterparties in order to review and monitor their financial stability and assess their ongoing ability to honor their commitments under the derivative contracts. We have not experienced, nor do we expect to experience, any difficulty in the counterparties honoring their commitments. We have a risk management oversight committee consisting of members from our senior management. This committee oversees our risk enterprise program, monitors our risk environment and provides direction for activities to mitigate identified risks that may adversely affect the achievement of our goals. Item 7A. Quantitative and Qualitative Disclosures About Market Risk See “Risk Management” under “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles Reconciliations of earnings before interest, taxes, depreciation and amortization (“EBITDA”) to amounts reported under generally accepted accounting principles in financial statements. Earnings before interest, taxes, depreciation and amortization, which we refer to as EBITDA, is calculated as net income attributable to HollyFrontier stockholders plus (i) interest expense, net of interest income, (ii) income tax provision, and (iii) depreciation and amortization. EBITDA is not a calculation provided for under GAAP; 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. Set forth below is our calculation of EBITDA. Net income attributable to HollyFrontier stockholders Add income tax provision Add interest expense (1) Subtract interest income Add depreciation and amortization EBITDA Years Ended December 31, 2012 2011 2013 (In thousands) $ $ 735,842 391,576 90,159 (5,556) 303,446 1,515,467 $ $ 1,727,172 1,027,962 104,186 (4,786) 242,868 3,097,402 $ $ 1,023,397 581,991 78,323 (1,284) 159,707 1,842,134 (1) Includes loss on early extinguishment of debt of $22.1 million for the year ended December 31, 2013. 50 Table of Content Reconciliations of refinery operating information (non-GAAP performance measures) to amounts reported under generally accepted accounting principles in financial statements. Refinery gross margin and net operating margin are non-GAAP performance measures that are used by our management and others to compare our refining performance to that of other companies in our industry. We believe these margin measures are helpful to investors in evaluating our refining performance on a relative and absolute basis. Refinery gross margin per barrel is the difference between average net sales price and average cost of products per barrel of produced refined products. Net operating margin per barrel is the difference between refinery gross margin and refinery operating expenses per barrel of produced refined products. These two margins do not include the effect of depreciation and amortization. Each of these component performance measures can be reconciled directly to our consolidated statements of income. Other companies in our industry may not calculate these performance measures in the same manner. Refinery Gross and Net Operating Margins Below are reconciliations to our consolidated statements of income for (i) net sales, cost of products and operating expenses, in each case averaged per produced barrel sold, and (ii) net operating margin and refinery gross margin. Due to rounding of reported numbers, some amounts may not calculate exactly. Reconciliation of produced refined product sales to total sales and other revenues Consolidated Average sales price per produced barrel sold Times sales of produced refined products sold (BPD) Times number of days in period Produced refined product sales Total produced refined product sales Add refined product sales from purchased products and rounding (1) Total refined product sales Add direct sales of excess crude oil (2) Add other refining segment revenue (3) Total refining segment revenue Add HEP segment sales and other revenues Add corporate and other revenues Subtract consolidations and eliminations Sales and other revenues Years Ended December 31, 2012 2011 2013 (Dollars in thousands, except per barrel amounts) $ $ $ $ 115.60 410,730 365 17,330,342 17,330,342 1,581,395 18,911,737 1,052,915 140,791 20,105,443 307,053 1,314 (253,250) 20,160,560 $ $ $ $ 119.48 431,060 366 18,850,116 18,850,116 572,206 19,422,322 505,971 114,662 20,042,955 288,501 1,048 (241,780) 20,090,724 $ $ $ $ 118.82 332,720 365 14,429,833 14,429,833 350,843 14,780,676 558,855 52,899 15,392,430 212,995 1,098 (166,995) 15,439,528 51 Table of Content Reconciliation of average cost of products per produced barrel sold to total cost of products sold Consolidated Average cost of products per produced barrel sold Times sales of produced refined products sold (BPD) Times number of days in period Cost of products for produced products sold Total cost of products for produced products sold Add refined product costs from purchased products and rounding (1) Total cost of refined products sold Add crude oil cost of direct sales of excess crude oil (2) Add other refining segment cost of products sold (4) Total refining segment cost of products sold Subtract consolidations and eliminations Costs of products sold (exclusive of depreciation and amortization) Years Ended December 31, 2012 2011 2013 (Dollars in thousands, except per barrel amounts) $ $ $ $ 99.61 410,730 365 14,933,178 14,933,178 1,553,476 16,486,654 1,048,224 106,241 17,641,119 (248,892) 17,392,227 $ $ $ $ 94.59 431,060 366 14,923,271 14,923,271 572,755 15,496,026 492,790 90,132 16,078,948 (238,305) 15,840,643 $ $ $ $ 98.18 332,720 365 11,923,254 11,923,254 351,788 12,275,042 550,619 18,672 12,844,333 (164,255) 12,680,078 Reconciliation of average refinery operating expenses per produced barrel sold to total operating expenses Consolidated Average refinery operating expenses per produced barrel sold Times sales of produced refined products sold (BPD) Times number of days in period Refinery operating expenses for produced products sold Total refinery operating expenses for produced products sold Add refining segment pension settlement costs Add other refining segment operating expenses and rounding (5) Total refining segment operating expenses Add HEP segment operating expenses Add corporate and other costs Subtract consolidations and eliminations Operating expenses (exclusive of depreciation and amortization) Years Ended December 31, 2012 2011 2013 (Dollars in thousands, except per barrel amounts) $ $ $ $ 6.15 410,730 365 921,986 921,986 31,657 39,812 993,455 97,081 1,739 (1,425) 1,090,850 $ $ $ $ 5.49 431,060 366 866,146 866,146 — 37,231 903,377 89,395 2,721 (527) 994,966 $ $ $ $ 5.36 332,720 365 650,933 650,933 — 35,659 686,592 63,029 427 (1,967) 748,081 52 Table of Content Reconciliation of net operating margin per barrel to refinery gross margin per barrel to total sales and other revenues Consolidated Net operating margin per barrel Add average refinery operating expenses per produced barrel Refinery gross margin per barrel Add average cost of products per produced barrel sold Average sales price per produced barrel sold Times sales of produced refined products sold (BPD) Times number of days in period Produced refined product sales Total produced refined product sales Add refined product sales from purchased products and rounding (1) Total refined product sales Add direct sales of excess crude oil (2) Add other refining segment revenue (3) Total refining segment revenue Add HEP segment sales and other revenues Add corporate and other revenues Subtract consolidations and eliminations Sales and other revenues Years Ended December 31, 2012 2011 2013 (Dollars in thousands, except per barrel amounts) $ $ $ $ $ 9.84 6.15 15.99 99.61 115.60 410,730 365 17,330,342 17,330,342 1,581,395 18,911,737 1,052,915 140,791 20,105,443 307,053 1,314 (253,250) 20,160,560 $ $ $ $ $ 19.40 5.49 24.89 94.59 119.48 431,060 366 18,850,116 18,850,116 572,206 19,422,322 505,971 114,662 20,042,955 288,501 1,048 (241,780) 20,090,724 $ $ $ $ $ 15.28 5.36 20.64 98.18 118.82 332,720 365 14,429,833 14,429,833 350,843 14,780,676 558,855 52,899 15,392,430 212,995 1,098 (166,995) 15,439,528 (1) We purchase finished products when opportunities arise that provide a profit on the sale of such products, or to meet delivery commitments. (2) We purchase crude oil that at times exceeds the supply needs of our refineries. Quantities in excess of our needs are sold at market prices to purchasers of crude oil that are recorded on a gross basis with the sales price recorded as revenues and the corresponding acquisition cost as inventory and then upon sale as cost of products sold. Additionally, at times we enter into buy/sell exchanges of crude oil with certain parties to facilitate the delivery of quantities to certain locations that are netted at carryover cost. (3) Other refining segment revenue includes the incremental revenues associated with NK Asphalt and miscellaneous revenue. (4) Other refining segment cost of products sold includes the incremental cost of products for NK Asphalt and miscellaneous costs. (5) Other refining segment operating expenses include the marketing costs associated with our refining segment and the operating expenses of NK Asphalt. 53 Table of Content Item 8. Financial Statements and Supplementary Data MANAGEMENT'S REPORT ON ITS ASSESSMENT OF THE COMPANY'S INTERNAL CONTROL OVER FINANCIAL REPORTING Management of HollyFrontier Corporation (the “Company”) is responsible for establishing and maintaining adequate internal control over financial reporting. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Management assessed the Company's internal control over financial reporting as of December 31, 2013 using the criteria for effective control over financial reporting established in “Internal Control - Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework). Based on this assessment, management concludes that, as of December 31, 2013, the Company maintained effective internal control over financial reporting. The Company's independent registered public accounting firm has issued an attestation report on the effectiveness of the Company's internal control over financial reporting as of December 31, 2013. That report appears on page 55. 54 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM The Board of Directors and Stockholders of HollyFrontier Corporation We have audited HollyFrontier Corporation's internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework), (the “COSO criteria”). HollyFrontier Corporation's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Report on its Assessment of the Company's Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. In our opinion, HollyFrontier Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on the COSO criteria. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of HollyFrontier Corporation as of December 31, 2013 and 2012, and the related consolidated statements of income, comprehensive income, cash flows and equity for each of the three years in the period ended December 31, 2013 and our report dated February 25, 2014 expressed an unqualified opinion thereon. /s/ ERNST & YOUNG LLP Dallas, Texas February 25, 2014 55 Index to Consolidated Financial Statements Report of Independent Registered Public Accounting Firm Consolidated Balance Sheets at December 31, 2013 and 2012 Consolidated Statements of Income for the years ended December 31, 2013, 2012 and 2011 Consolidated Statements of Comprehensive Income for the years ended December 31, 2013, 2012 and 2011 Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011 Consolidated Statements of Equity for the years ended December 31, 2013, 2012 and 2011 Notes to Consolidated Financial Statements Page Reference 57 58 59 60 61 62 63 56 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM The Board of Directors and Stockholders of HollyFrontier Corporation We have audited the accompanying consolidated balance sheets of HollyFrontier Corporation (the “Company”) as of December 31, 2013 and 2012, and the related consolidated statements of income, comprehensive income, cash flows and equity for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of HollyFrontier Corporation at December 31, 2013 and 2012, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), HollyFrontier Corporation's internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework), and our report dated February 25, 2014 expressed an unqualified opinion thereon. Dallas, Texas February 25, 2014 /s/ ERNST & YOUNG LLP 57 Table of Content ASSETS Current assets: HOLLYFRONTIER CORPORATION CONSOLIDATED BALANCE SHEETS (In thousands, except share data) Cash and cash equivalents (HEP: $6,352 and $5,237, respectively) Marketable securities Total cash, cash equivalents and short-term marketable securities Accounts receivable: Product and transportation (HEP: $34,736 and $38,097, respectively) Crude oil resales Inventories: Crude oil and refined products Materials, supplies and other (HEP: $1,591 and $1,259, respectively) Income taxes receivable Prepayments and other (HEP: $2,283 and $2,360, respectively) Total current assets Properties, plants and equipment, at cost (HEP: $1,199,594 and $1,155,710, respectively) Less accumulated depreciation (HEP: $(194,619) and $(141,154), respectively) Marketable securities (long-term) Other assets: Turnaround costs Goodwill (HEP: $288,991 and $288,991, respectively) Intangibles and other (HEP: $74,979 and $76,300, respectively) Total assets LIABILITIES AND EQUITY Current liabilities: Accounts payable (HEP: $22,898 and $12,030, respectively) Accrued liabilities (HEP: $28,668 and $23,705, respectively) Deferred income tax liabilities Total current liabilities Long-term debt (HEP: $807,630 and $864,673, respectively) Deferred income taxes (HEP: $5,287 and $4,951, respectively) Other long-term liabilities (HEP: $35,918 and $28,683, respectively) Equity: HollyFrontier stockholders’ equity: Preferred stock, $1.00 par value – 5,000,000 shares authorized; none issued Common stock $.01 par value – 320,000,000 shares authorized; 255,962,866 shares issued as of December 31, 2013 and December 31, 2012 Additional capital Retained earnings Accumulated other comprehensive income (loss) Common stock held in treasury, at cost – 57,132,515 and 52,411,370 shares as of December 31, 2013 and December 31, 2012, respectively Total HollyFrontier stockholders’ equity Noncontrolling interest Total equity Total liabilities and equity December 31, 2013 2012 $ $ $ 940,103 725,160 1,665,263 665,098 43,704 708,802 1,241,448 112,799 1,354,247 109,376 58,756 3,896,444 4,343,857 (949,261) 3,394,596 — 258,436 2,331,922 175,341 2,765,699 10,056,739 1,325,376 125,115 223,999 1,674,490 997,519 616,842 158,490 — 2,560 3,990,630 3,144,480 822 (1,138,872) 5,999,620 609,778 6,609,398 10,056,739 $ 1,757,699 630,586 2,388,285 587,728 46,502 634,230 1,238,678 80,954 1,319,632 74,957 53,161 4,470,265 3,943,114 (748,414) 3,194,700 5,116 151,764 2,338,302 168,850 2,658,916 10,328,997 1,314,151 195,077 145,216 1,654,444 1,336,238 536,670 158,987 — 2,560 3,911,353 3,054,769 (8,425) (907,303) 6,052,954 589,704 6,642,658 10,328,997 $ $ $ $ Parenthetical amounts represent asset and liability balances attributable to Holly Energy Partners, L.P. (“HEP”) as of December 31, 2013 and December 31, 2012. HEP is a consolidated variable interest entity. See accompanying notes. 58 Table of Content HOLLYFRONTIER CORPORATION CONSOLIDATED STATEMENTS OF INCOME (In thousands, except per share data) Years Ended December 31, 2012 2011 2013 $ 20,160,560 $ 20,090,724 $ 15,439,528 17,392,227 1,090,850 127,963 303,446 18,914,486 1,246,074 (2,072) 5,556 (68,050) (22,109) — — 15,840,643 12,680,078 994,966 128,101 242,868 748,081 120,114 159,707 17,206,578 2,884,146 13,707,980 1,731,548 2,923 4,786 2,300 1,284 (104,186) (78,323) — 326 — (86,675) 1,159,399 (96,151) 2,787,995 277,172 114,404 391,576 767,823 31,981 735,842 3.66 3.64 200,419 201,234 $ $ $ 932,554 95,408 1,027,962 1,760,033 32,861 1,727,172 8.41 8.38 204,379 205,274 $ $ $ $ $ $ — — (15,114) (89,853) 1,641,695 590,851 (8,860) 581,991 1,059,704 36,307 1,023,397 6.46 6.42 157,948 158,756 Sales and other revenues Operating costs and expenses: Cost of products sold (exclusive of depreciation and amortization) Operating expenses (exclusive of depreciation and amortization) General and administrative expenses (exclusive of depreciation and amortization) Depreciation and amortization Total operating costs and expenses Income from operations Other income (expense): Earnings (loss) of equity method investments Interest income Interest expense Loss on early extinguishment of debt Gain on sale of marketable equity securities Merger transaction costs Income before income taxes Income tax provision: Current Deferred Net income Less net income attributable to noncontrolling interest Net income attributable to HollyFrontier stockholders Earnings per share attributable to HollyFrontier stockholders: Basic Diluted Average number of common shares outstanding: Basic Diluted See accompanying notes. 59 Table of Content HOLLYFRONTIER CORPORATION CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (In thousands) Net income Other comprehensive income (loss): Securities available-for-sale: Unrealized gain (loss) on marketable securities Reclassification adjustments to net income on sale or maturity of marketable securities Net unrealized gain (loss) on marketable securities Hedging instruments: Change in fair value of cash flow hedging instruments Reclassification adjustments to net income on settlement of cash flow hedging instruments Amortization of unrealized loss attributable to discontinued cash flow hedges Net unrealized gain (loss) on hedging instruments Pension and other post-retirement benefit obligations: Loss on pension plan Pension plan loss reclassified to net income Gain (loss) on post-retirement healthcare plan Post-retirement healthcare plan (gain) loss reclassified to net income Gain (loss) on retirement restoration plan Retirement restoration plan loss reclassified to net income Net change in pension and other post-retirement benefit obligations Other comprehensive income (loss) before income taxes Income tax expense (benefit) Other comprehensive income (loss) Total comprehensive income Less noncontrolling interest in comprehensive income Years Ended December 31, 2013 2012 2011 $ 767,823 $ 1,760,033 $ 1,059,704 73 (39) 34 149 (385) (236) (7,614) (252,817) (14,318) 1,749 (20,183) — 37,589 3,301 (4,040) 632 111 37,593 17,444 5,882 11,562 779,385 34,296 56,683 5,095 (191,039) (3,485) 1,956 55,402 (1,952) (593) 63 51,391 (139,884) (54,950) (84,934) 1,675,099 34,225 (530) 14 (516) 171,252 5,643 41 176,936 (2,191) 2,302 (3,673) 158 (281) 99 (3,586) 172,834 66,138 106,696 1,166,400 39,122 Comprehensive income attributable to HollyFrontier stockholders $ 745,089 $ 1,640,874 $ 1,127,278 See accompanying notes. 60 Table of Content HOLLYFRONTIER CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands) Cash flows from operating activities: Net income Adjustments to reconcile net income to net cash provided by operating activities: $ 767,823 $ 1,760,033 $ 1,059,704 Years Ended December 31, 2012 2011 2013 Depreciation and amortization Earnings of equity method investments, net of distributions Loss on early extinguishment of debt attributable to unamortized discount Gain on sale of marketable equity securities Deferred income taxes Equity-based compensation expense Change in fair value – derivative instruments Loss on settlement of retirement benefit obligations, net of contributions (Increase) decrease in current assets: Accounts receivable Inventories Income taxes receivable Prepayments and other Increase (decrease) in current liabilities: Accounts payable Income taxes payable Accrued liabilities Turnaround expenditures Other, net Net cash provided by operating activities Cash flows from investing activities: Additions to properties, plants and equipment Additions to properties, plants and equipment – HEP Acquisition of trucking operations Proceeds from sale of property and equipment Increase in cash due to merger with Frontier Investment in Sabine Biofuels Net advances to Sabine Biofuels Purchases of marketable securities Sales and maturities of marketable securities Net cash provided by (used for) investing activities Cash flows from financing activities: Borrowings under credit agreement – HEP Repayments under credit agreement – HEP Net proceeds from issuance of senior notes – HEP Redemption of senior notes Principal tender on senior notes - HEP Proceeds from sale of HEP common units Proceeds from common unit offerings – HEP Purchase of treasury stock Structured stock repurchase arrangement Contribution from joint venture partner Dividends Distributions to noncontrolling interest Excess tax benefit from equity-based compensation Purchase of units for incentive grants – HEP Deferred financing costs and other Net cash used for financing activities Cash and cash equivalents: Increase (decrease) for the period Beginning of period End of period Supplemental disclosure of cash flow information: Cash paid during the period for: Interest Income taxes See accompanying notes. $ $ $ 61 303,446 5,198 7,948 — 114,404 35,775 (53,185) 16,771 (68,832) (15,929) (34,419) 1,377 2,068 — (41,229) (193,920) 21,878 869,174 (373,271) (51,856) (11,301) 7,802 — (3,000) (5,740) (935,512) 846,143 (526,735) 310,600 (368,600) — (300,973) — 73,444 73,444 (225,023) — — (645,920) (71,201) 2,562 (5,313) (3,055) (1,160,035) (817,596) 1,757,699 940,103 76,647 372,846 242,868 701 — (326) 95,408 39,203 52,335 (19,524) 71,627 (205,013) 19,056 (9,366) (194,051) (40,366) (39,851) (159,707) 49,660 1,662,687 (290,334) (44,929) — — — (2,000) — (671,552) 297,711 (711,104) 587,000 (366,000) 294,750 (205,000) (185,000) — — (209,600) 8,620 6,000 (658,085) (58,788) 23,361 (5,240) (4,806) (772,788) 159,707 387 — — (8,860) 26,825 306 (6,049) 373,591 (56,828) (36,394) (14,214) (251,428) 72,091 60,467 (32,023) (8,891) 1,338,391 (158,026) (216,215) — — 872,739 (9,125) — (561,899) 301,020 228,494 118,000 (77,000) — (8,203) — — 75,815 (42,795) — 33,500 (252,133) (50,874) 1,804 (1,641) (13,555) (217,082) 178,795 1,578,904 1,757,699 101,709 983,618 $ $ $ 1,349,803 229,101 1,578,904 78,483 552,487 $ $ $ Table of Content HOLLYFRONTIER CORPORATION CONSOLIDATED STATEMENTS OF EQUITY (In thousands) HollyFrontier Stockholders' Equity Balance at December 31, 2010 $ 1,526 $ 193,615 $1,206,328 $ (26,246) $ (677,804) $ 590,720 $ 1,288,139 Common Stock Additional Capital Retained Earnings Accumulated Other Comprehensive Income (Loss) Treasury Stock Non- controlling Interest Total Equity Net income Dividends Distribution to noncontrolling interest holders Other comprehensive income, net of tax Issuance of common stock upon merger with Frontier Oil Corporation Allocated equity on HEP common unit issuances, net of tax Contribution from joint venture partner Issuance of common stock under incentive compensation plans, net of forfeitures Equity-based compensation, net of tax benefit Purchase of treasury stock Other Balance at December 31, 2011 Net income Dividends Distributions to noncontrolling interest holders Other comprehensive income, net of tax Allocated equity on HEP common unit issuances, net of tax Contribution from joint venture partner Issuance of common stock under incentive compensation plans, net of forfeitures Equity-based compensation, net of tax benefit Purchase of treasury stock Net proceeds received under structured share repurchase arrangement Purchase of HEP units for restricted grants Balance at December 31, 2012 Net income Dividends Distributions to noncontrolling interest holders Other comprehensive income, net of tax Allocated equity on HEP common unit issuances, net of tax Issuance of common stock under incentive compensation plans, net of forfeitures Equity-based compensation, net of tax benefit Purchase of treasury stock Purchase of HEP units for restricted grants Other Balance at December 31, 2013 See accompanying notes. — 1,023,397 — — — — — — — — — — — — — 1,037 3,704,203 — — — — — — (44,885) — (20,150) 26,584 — — — — — 11,469 — (3) (27,809) — — — — 59,706 — 8,620 — (265,069) — — — — — — — — — (637,059) — — — — — — — — — — — — 103,881 — 238 — — — — — — — — — — — — 20,150 — (42,795) — 36,307 — (50,874) 2,815 1,059,704 (265,069) (50,874) 106,696 — 3,705,240 16,852 36,500 — 2,046 — (2,476) (27,795) 36,500 — 28,630 (42,795) (2,476) — — — (86,298) — — — — — — — — — — — — — 27,812 — (234,666) — — 32,861 — (58,788) 1,364 (18,768) 3,000 — 2,858 — — (4,713) 1,760,033 (637,059) (58,788) (84,934) (7,299) 3,000 — 62,564 (234,666) 8,620 (4,713) $ 2,563 $ 3,859,367 $1,964,656 $ 77,873 $ (700,449) $ 631,890 $ 5,835,900 — 1,727,172 $ 2,560 $ 3,911,353 $3,054,769 $ (8,425) $ (907,303) $ 589,704 $ 6,642,658 — — — — — — — — — — — — — — 54,184 (9,669) 34,762 — — — 735,842 (646,131) — — — — — — — — — — — 9,247 — — — — — — — — — — — 9,669 — (241,238) — — 31,981 — (71,201) 2,315 767,823 (646,131) (71,201) 11,562 58,702 112,886 — — 3,575 — (5,313) 15 38,337 (241,238) (5,313) 15 $ 2,560 $ 3,990,630 $3,144,480 $ 822 $ (1,138,872) $ 609,778 $ 6,609,398 62 Table of Content HOLLYFRONTIER CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1: Description of Business and Summary of Significant Accounting Policies Description of Business: References herein to HollyFrontier Corporation (“HollyFrontier”) include HollyFrontier and its consolidated subsidiaries. In accordance with the Securities and Exchange Commission’s (“SEC”) “Plain English” guidelines, this Annual Report on Form 10-K has been written in the first person. In these financial statements, the words “we,” “our,” “ours” and “us” refer only to HollyFrontier and its consolidated subsidiaries or to HollyFrontier or an individual subsidiary and not to any other person, with certain exceptions. Generally, the words “we,” “our,” “ours” and “us” include Holly Energy Partners, L.P. (“HEP”) and its subsidiaries as consolidated subsidiaries of HollyFrontier, unless when used in disclosures of transactions or obligations between HEP and HollyFrontier or its other subsidiaries. These financial statements contain certain disclosures of agreements that are specific to HEP and its consolidated subsidiaries and do not necessarily represent obligations of HollyFrontier. When used in descriptions of agreements and transactions, “HEP” refers to HEP and its consolidated subsidiaries. We merged with Frontier Oil Corporation (“Frontier”) on July 1, 2011. Concurrent with the merger, we changed our name from Holly Corporation (“Holly”) to HollyFrontier and changed the ticker symbol for our common stock traded on the New York Stock Exchange to “HFC” (see Note 2). Accordingly, these financial statements include Frontier, its consolidated subsidiaries and the operations of the merged Frontier businesses effective July 1, 2011, but not prior to this date. We are principally an independent petroleum refiner that produces high-value light products such as gasoline, diesel fuel, jet fuel, specialty lubricant products, and specialty and modified asphalt. We own and operate petroleum refineries that serve markets throughout the Mid-Continent, Southwest and Rocky Mountain regions of the United States. As of December 31, 2013, we: • • • • owned and operated a petroleum refinery in El Dorado, Kansas (the “El Dorado Refinery”), two refinery facilities located in Tulsa, Oklahoma (collectively, the “Tulsa Refineries”), a refinery in Artesia, New Mexico that is operated in conjunction with crude oil distillation and vacuum distillation and other facilities situated 65 miles away in Lovington, New Mexico (collectively, the “Navajo Refinery”), a refinery located in Cheyenne, Wyoming (the “Cheyenne Refinery”) and a refinery in Woods Cross, Utah (the “Woods Cross Refinery”); owned and operated NK Asphalt Partners (“NK Asphalt”) which operates various asphalt terminals in Arizona and New Mexico; owned a 50% interest in Sabine Biofuels II, LLC (“Sabine Biofuels”), a biodiesel production facility located in Port Arthur, Texas; and owned a 39% interest in HEP, a consolidated variable interest entity (“VIE”), which includes our 2% general partner interest. HEP owns and operates logistic assets consisting of petroleum product and crude oil pipelines and terminal, tankage and loading rack facilities that principally support our refining and marketing operations in the Mid-Continent, Southwest and Rocky Mountain regions of the United States and Alon USA, Inc.'s (“Alon”) refinery in Big Spring, Texas. Additionally, HEP owns a 75% interest in UNEV Pipeline, LLC (“UNEV”), which owns a 12-inch refined products pipeline from Salt Lake City, Utah to Las Vegas, Nevada, together with terminal facilities in the Cedar City, Utah and North Las Vegas areas (the “UNEV Pipeline”) and a 25% interest in SLC Pipeline LLC (the “SLC Pipeline”), which owns a 95-mile intrastate pipeline system that serves refineries in the Salt Lake City area. Principles of Consolidation: Our consolidated financial statements include our accounts and the accounts of partnerships and joint ventures that we control through an ownership interest greater than 50% or through a controlling financial interest with respect to variable interest entities. All significant intercompany transactions and balances have been eliminated. Variable Interest Entities: HEP is a VIE as defined under U.S. generally accepted accounting principles (“GAAP”). A VIE is a legal entity whose equity owners do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support or, as a group, the equity holders lack the power, through voting rights, to direct the activities that most significantly impact the entity's financial performance, the obligation to absorb the entity's expected losses or rights to expected residual returns. As the general partner of HEP, we have the sole ability to direct the activities of HEP that most significantly impact HEP's financial performance, and therefore we consolidate HEP. We have a 50% ownership interest in Sabine Biofuels, a biofuels production facility that is a VIE. We do not hold a controlling financial interest, nor do we have the power to direct the activities that most significantly impact its financial performance. Accordingly, we account for our investment using the equity method of accounting. 63 Table of Contents HOLLYFRONTIER CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued Use of Estimates: The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates. Cash Equivalents: We consider all highly liquid instruments with a maturity of three months or less at the date of purchase to be cash equivalents. Cash equivalents are stated at cost, which approximates market value and are primarily invested in highly-rated instruments issued by government or municipal entities with strong credit standings. Marketable Securities: We consider all marketable debt securities with maturities greater than three months at the date of purchase to be marketable securities. Our marketable securities consist of certificates of deposit, commercial paper, corporate debt securities and government and municipal debt securities with the maximum maturity or put date of any individual issue generally not more than two years, while the maximum duration of the portfolio of investments is not greater than one year. These instruments are classified as available-for-sale, and as a result, are reported at fair value. Unrealized gains and losses, net of related income taxes, are reported as a component of accumulated other comprehensive income. Balance Sheet Offsetting: We purchase and sell inventories of crude oil with certain same-parties that are net settled in accordance with contractual net settlement provisions. Our policy is to present such balances on a net basis because it more appropriately presents our economic resources (accounts receivable) and claims against us (accounts payable) and the future cash flows associated with such assets and liabilities. Accounts Receivable: Our accounts receivable consist of amounts due from customers that are primarily companies in the petroleum industry. Credit is extended based on our evaluation of the customer's financial condition, and in certain circumstances collateral, such as letters of credit or guarantees, is required. We reserve for doubtful accounts based on our historical loss experience as well as specific accounts identified as high risk, which historically have been minimal. Credit losses are charged to the allowance for doubtful accounts when an account is deemed uncollectible. Our allowance for doubtful accounts was $2.4 million and $2.5 million at December 31, 2013 and 2012, respectively. Accounts receivable attributable to crude oil resales generally represent the sell side of excess crude oil sales to other purchasers and / or users in cases when our crude oil supplies are in excess of our immediate needs as well as certain reciprocal buy / sell exchanges of crude oil. At times we enter into such buy / sell exchanges to facilitate the delivery of quantities to certain locations. In many cases, we enter into net settlement agreements relating to the buy/sell arrangements, which may mitigate credit risk. Inventories: Inventories are stated at the lower of cost, using the last-in, first-out (“LIFO”) method for crude oil unfinished and finished refined products and the average cost method for materials and supplies, or market. Cost, consisting of raw material, transportation and conversion costs, is determined using the LIFO inventory valuation methodology and market is determined using current estimated selling prices. Under the LIFO method, the most recently incurred costs are charged to cost of sales and inventories are valued at the earliest acquisition costs. In periods of rapidly declining prices, LIFO inventories may have to be written down to market value due to the higher costs assigned to LIFO layers in prior periods. In addition, the use of the LIFO inventory method may result in increases or decreases to cost of sales in years that inventory volumes decline as the result of charging cost of sales with LIFO inventory costs generated in prior periods. An actual valuation of inventory under the LIFO method is made at the end of each year based on the inventory levels at that time. Accordingly, interim LIFO calculations are based on management's estimates of expected year-end inventory levels and are subject to the final year-end LIFO inventory valuation. Derivative Instruments: All derivative instruments are recognized as either assets or liabilities in our consolidated balance sheets and are measured at fair value. Changes in the derivative instrument's fair value are recognized in earnings unless specific hedge accounting criteria are met. See Note 13 for additional information. Long-lived assets: We calculate depreciation and amortization based on estimated useful lives and salvage values of our assets. We evaluate long-lived assets for potential impairment by identifying whether indicators of impairment exist and, if so, assessing whether the long-lived assets are recoverable from estimated future undiscounted cash flows. The actual amount of impairment loss, if any, to be recorded is equal to the amount by which a long-lived asset's carrying value exceeds its fair value, which is generally determined under an income approach using the forecasted cash flows associated with the underlying asset. Estimates of future cash flows require subjective assumptions with regard to future operating results and actual results could differ from those estimates. No impairments of long-lived assets were recorded during the years ended December 31, 2013, 2012 and 2011. 64 Table of Contents HOLLYFRONTIER CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued Asset Retirement Obligations: We record legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and / or the normal operation of long-lived assets. The fair value of the estimated cost to retire a tangible long-lived asset is recorded as a liability with the associated retirement costs capitalized as part of the asset's carrying amount in the period in which it is incurred and when a reasonable estimate of the fair value of the liability can be made. If a reasonable estimate cannot be made at the time the liability is incurred, we record the liability when sufficient information is available to estimate the liability's fair value. Our asset retirement obligations were $19.1 million and $18.1 million at December 31, 2013 and 2012, respectively, which are included in “Other long-term liabilities” in our consolidated balance sheets. Accretion expense was insignificant for the years ended December 31, 2013, 2012 and 2011. Intangibles and Goodwill: Intangible assets are assets (other than financial assets) that lack physical substance. Goodwill represents the excess of the cost of an acquired entity over the fair value of the assets acquired less liabilities assumed. Goodwill acquired in a business combination and intangible assets with indefinite useful lives are not amortized while, intangible assets with finite useful lives are amortized on a straight-line basis. Goodwill and intangible assets not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate the asset might be impaired. Our analysis entails a comparison of the estimated fair value of these assets that are derived using a combination of both income (discounted future expected net cash flows) and comparable market approaches against their respective carrying values. Estimates of future cash flows and fair value of assets require subjective assumptions with regard to future operating results and actual results could differ from those estimates. In addition to goodwill, our consolidated HEP assets include a third-party transportation agreement that currently generates minimum annual cash inflows of $24.7 million and has an expected remaining term through 2035. The transportation agreement is being amortized on a straight-line basis through 2035 that results in annual amortization expense of $2.0 million. The balance of this transportation agreement was $42.5 million and $44.5 million at December 31, 2013 and 2012, respectively, and is presented net of accumulated amortization of $17.7 million and $15.7 million, respectively, in “Intangibles and other” in our consolidated balance sheets. There were no impairments of intangible assets or goodwill during the years ended December 31, 2013, 2012 and 2011. Investments in Joint Ventures: We consolidate the financial and operating results of joint ventures in which we have an ownership interest of greater than 50% and use the equity method of accounting for investments in which we have a 50% or less ownership interest. Under the equity method of accounting, we record our pro-rata share of earnings, and contributions to and distributions from joint ventures as adjustments to our investment balance. HEP has a 25% joint venture interest in the SLC Pipeline that is accounted for using the equity method of accounting. As of December 31, 2013, HEP's underlying equity in the SLC Pipeline was $59.6 million compared to its recorded investment balance of $24.7 million, a difference of $34.9 million. This is attributable to the difference between HEP's contributed capital and its allocated equity at formation of the SLC Pipeline. This difference is being amortized as an adjustment to HEP's pro-rata share of earnings. Revenue Recognition: Refined product sales and related cost of sales are recognized when products are shipped and title has passed to customers. HEP recognizes pipeline transportation revenues as products are shipped through its pipelines. All revenues are reported inclusive of shipping and handling costs billed and exclusive of any taxes billed to customers. Shipping and handling costs incurred are reported in cost of products sold. Depreciation: Depreciation is provided by the straight-line method over the estimated useful lives of the assets, primarily 20 to 25 years for refining, pipeline and terminal facilities, 10 to 40 years for buildings and improvements, 5 to 30 years for other fixed assets and 5 years for vehicles. Cost Classifications: Costs of products sold include the cost of crude oil, other feedstocks, blendstocks and purchased finished products, inclusive of transportation costs. We purchase crude oil that at times exceeds the supply needs of our refineries. Quantities in excess of our needs are sold at market prices to purchasers of crude oil that are recorded on a gross basis with the sales price recorded as revenues and the corresponding acquisition cost as cost of products sold. Additionally, we enter into buy/sell exchanges of crude oil with certain parties to facilitate the delivery of quantities to certain locations that are netted at carryover cost. Operating expenses include direct costs of labor, maintenance materials and services, utilities, marketing expense and other direct operating costs. General and administrative expenses include compensation, professional services and other support costs. 65 Table of Contents HOLLYFRONTIER CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued Deferred Maintenance Costs: Our refinery units require regular major maintenance and repairs which are commonly referred to as “turnarounds.” Catalysts used in certain refinery processes also require regular “change-outs.” The required frequency of the maintenance varies by unit and by catalyst, but generally is every two to five years. Turnaround costs are deferred and amortized over the period until the next scheduled turnaround. Other repairs and maintenance costs are expensed when incurred. Environmental Costs: Environmental costs are charged to operating expenses if they relate to an existing condition caused by past operations and do not contribute to current or future revenue generation. Liabilities are recorded when site restoration and environmental remediation, cleanup and other obligations are either known or considered probable and can be reasonably estimated. Such estimates require judgment with respect to costs, time frame and extent of required remedial and clean-up activities and are subject to periodic adjustments based on currently available information. Recoveries of environmental costs through insurance, indemnification arrangements or other sources are included in other assets to the extent such recoveries are considered probable. Contingencies: We are subject to proceedings, lawsuits and other claims related to environmental, labor, product and other matters. We are required to assess the likelihood of any adverse judgments or outcomes to these matters as well as potential ranges of probable losses. A determination of the amount of reserves required, if any, for these contingencies is made after careful analysis of each individual issue. The required reserves may change in the future due to new developments in each matter or changes in approach such as a change in settlement strategy in dealing with these matters. Income Taxes: Provisions for income taxes include deferred taxes resulting from temporary differences in income for financial and tax purposes, using the liability method of accounting for income taxes. The liability method requires the effect of tax rate changes on current and accumulated deferred income taxes to be reflected in the period in which the rate change was enacted. The liability method also requires that deferred tax assets be reduced by a valuation allowance unless it is more likely than not that the assets will be realized. Potential interest and penalties related to income tax matters are recognized in income tax expense. We believe we have appropriate support for the income tax positions taken and to be taken on our income tax returns and that our accruals for tax liabilities are adequate for all open years based on an assessment of many factors, including past experience and interpretations of tax law applied to the facts of each matter. NOTE 2: Holly-Frontier Merger On February 21, 2011, we entered into a merger agreement providing for a “merger of equals” business combination between us and Frontier. On July 1, 2011, North Acquisition, Inc., a direct wholly-owned subsidiary of Holly, merged with and into Frontier, with Frontier surviving as a wholly-owned subsidiary of Holly. Subsequent to the merger and following approval by the post- closing board of directors of HollyFrontier, Frontier merged with and into HollyFrontier, with HollyFrontier continuing as the surviving corporation. In accordance with the merger agreement, we issued approximately 102.8 million shares of HollyFrontier common stock in exchange for outstanding shares of Frontier common stock to former Frontier stockholders. Each outstanding share of Frontier common stock was converted into 0.4811 shares of HollyFrontier common stock with any fractional shares paid in cash. The aggregate consideration paid in connection with the merger was approximately $3.7 billion. This is based on our July 1, 2011 market closing price of $35.93 and includes a portion of the fair value of the outstanding equity-based awards assumed from Frontier that relates to pre-merger services. Our consolidated financial and operating results reflect the operations of the merged Frontier businesses beginning July 1, 2011, which consists of crude oil refining and the wholesale marketing of refined petroleum products produced at the El Dorado and Cheyenne Refineries, which serve markets in the Rocky Mountain and Plains States regions of the United States. 66 Table of Contents HOLLYFRONTIER CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued NOTE 3: Variable Interest Entities Holly Energy Partners HEP, a consolidated VIE, is a publicly held master limited partnership that was formed to acquire, own and operate the petroleum product and crude oil pipeline and terminal, tankage and loading rack facilities that support our refining and marketing operations in the Mid-Continent, Southwest and Rocky Mountain regions of the United States. HEP also owns and operates refined product pipelines and terminals, located primarily in Texas, that serve Alon's refinery in Big Spring, Texas. As of December 31, 2013, we owned a 39% interest in HEP, including the 2% general partner interest. As the general partner of HEP, we have the sole ability to direct the activities that most significantly impact HEP's financial performance. We are the primary beneficiary of HEP's earnings and cash flows and therefore we consolidate HEP. See Note 21 for supplemental guarantor/non- guarantor financial information, including HEP balances included in these consolidated financial statements. HEP has two primary customers (including us) and generates revenues by charging tariffs for transporting petroleum products and crude oil though its pipelines, by charging fees for terminalling refined products and other hydrocarbons, and storing and providing other services at its storage tanks and terminals. Under our long-term transportation agreements with HEP (discussed further below), we accounted for 83% of HEP’s total revenues for the year ended December 31, 2013. We do not provide financial or equity support through any liquidity arrangements and / or debt guarantees to HEP. HEP has outstanding debt under a senior secured revolving credit agreement and its senior notes. With the exception of the assets of HEP Logistics Holdings, L.P., one of our wholly-owned subsidiaries and HEP’s general partner, HEP’s creditors have no recourse to our other assets. Any recourse to HEP’s general partner would be limited to the extent of HEP Logistics Holdings, L.P.’s assets, which other than its investment in HEP, are not significant. Furthermore, our creditors have no recourse to the assets of HEP and its consolidated subsidiaries. See Note 12 for a description of HEP’s debt obligations. HEP has risk associated with its operations. If a major customer of HEP were to terminate its contracts or fail to meet desired shipping or throughput levels for an extended period of time, revenue would be reduced and HEP could suffer substantial losses to the extent that a new customer is not found. In the event that HEP incurs a loss, our operating results will reflect HEP’s loss, net of intercompany eliminations, to the extent of our ownership interest in HEP at that point in time. HEP's recent acquisitions (2011 through present) are summarized below: UNEV Interest Transaction On July 12, 2012, HEP acquired from us our 75% interest in UNEV. We received consideration consisting of $260.0 million in cash and 1.0 million HEP common units. Legacy Frontier Tankage and Terminal Asset Transaction On November 9, 2011, HEP acquired from us certain tankage, loading rack and crude receiving assets located at our El Dorado and Cheyenne Refineries. We received non-cash consideration consisting of promissory notes with an aggregate principal amount of $150.0 million and 3.8 million HEP common units. Transportation Agreements HEP serves our refineries under long-term pipeline and terminal, tankage and throughput agreements expiring from 2019 through 2026. Under these agreements, we pay HEP fees to transport, store and throughput volumes of refined product and crude oil on HEP's pipeline and terminal, tankage and loading rack facilities that result in minimum annual payments to HEP including UNEV (a consolidated subsidiary of HEP). Under these agreements, the agreed upon tariff rates are subject to annual tariff rate adjustments on July 1 at a rate based upon the percentage change in Producer Price Index (“PPI”) or Federal Energy Regulatory Commission (“FERC”) index. As of December 31, 2013, these agreements result in minimum annualized payments to HEP of $225.5 million. Our transactions with HEP including the acquisitions discussed above and fees paid under our transportation agreements with HEP and UNEV are eliminated and have no impact on our consolidated financial statements. 67 Table of Contents HOLLYFRONTIER CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued HEP's recent common unit issuances (2011 through present) are summarized below: 2013 Issuances In March 2013, HEP closed on a public offering of 1,875,000 of its common units. Additionally, our wholly-owned subsidiary, HollyFrontier Holdings LLC, as a selling unitholder, closed on a public sale of 1,875,000 HEP common units held by it. HEP used net proceeds of $73.4 million to repay indebtedness incurred under its credit facility and for general partnership purposes. 2012 Issuances In July 2012, HEP issued 1.0 million of its common units to us as partial consideration for its purchase of our 75% interest in UNEV. 2011 Issuances In December 2011, HEP issued 1.5 million of its common units priced at $53.50 per unit. Aggregate net proceeds of $75.8 million were used to repay a portion of the $150 million in promissory notes issued to us in connection with HEP's November 2011 asset acquisition from us. This repayment to us is eliminated in our consolidated financial statements. In November 2011, HEP issued 3.8 million of its common units to us as partial consideration for its purchase from us of certain tankage, loading rack and crude receiving assets located at our El Dorado and Cheyenne Refineries. As a result of these transactions and resulting HEP ownership changes, we adjusted additional capital, other comprehensive income and equity attributable to HEP's noncontrolling interest holders to effectively reallocate a portion of HEP's equity among its unitholders. Sabine Biofuels We have a 50% ownership interest in Sabine Biofuels, an unconsolidated VIE. This investment, accounted for using the equity method of accounting, had a carrying amount of $8.5 million at December 31, 2013 and is classified as a noncurrent asset under “Intangibles and other” in our consolidated balance sheets. Also, we have extended a working capital facility to Sabine Biofuels having an outstanding balance of $9.9 million at December 31, 2013. NOTE 4: Financial Instruments Our financial instruments consist of cash and cash equivalents, investments in marketable securities, accounts receivable, accounts payable, debt and derivative instruments. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate fair value. HEP's outstanding credit agreement borrowings also approximate fair value as interest rates are reset frequently at current interest rates. Fair value measurements are derived using inputs (assumptions that market participants would use in pricing an asset or liability, including assumptions about risk). GAAP categorizes inputs used in fair value measurements into three broad levels as follows: • • • (Level 1) Quoted prices in active markets for identical assets or liabilities. (Level 2) Observable inputs other than quoted prices included in Level 1, such as quoted prices for similar assets and liabilities in active markets, similar assets and liabilities in markets that are not active or can be corroborated by observable market data. (Level 3) Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. This includes valuation techniques that involve significant unobservable inputs. 68 Table of Contents HOLLYFRONTIER CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued The carrying amounts and estimated fair values of our investments in marketable securities, derivative instruments and senior notes at December 31, 2013 and December 31, 2012 were as follows: Financial Instrument December 31, 2013 Assets: Marketable securities Commodity price swaps HEP interest rate swaps Total assets Liabilities: NYMEX futures contracts Commodity price swaps HollyFrontier senior notes HEP senior notes HEP interest rate swaps Total liabilities December 31, 2012 Assets: Marketable securities Commodity price swaps Total assets Liabilities: NYMEX futures contracts Commodity price swaps HollyFrontier senior notes HEP senior notes HEP interest rate swaps Total liabilities Carrying Amount Fair Value Level 1 Level 2 Level 3 Fair Value by Input Level (In thousands) $ $ $ $ $ $ $ $ 725,160 43,284 1,670 770,114 3,569 83,349 155,054 444,630 1,814 688,416 635,702 17,383 653,085 5,563 83,982 435,254 443,673 3,430 971,902 $ $ $ $ $ $ 725,160 43,284 1,670 770,114 3,569 83,349 161,250 471,750 1,814 721,732 635,702 17,383 653,085 $ 5,563 83,982 470,990 484,125 3,430 $ 1,048,090 $ $ $ $ $ $ $ $ — $ — — — $ 725,160 36,312 1,670 763,142 $ $ — $ 3,569 — — — — 3,569 $ $ 41,059 161,250 471,750 1,814 675,873 — $ — — $ 635,702 6,151 641,853 5,563 — — — — 5,563 $ $ — $ 39,092 470,990 484,125 3,430 997,637 $ $ $ $ — 6,972 — 6,972 — 42,290 — — — 42,290 — 11,232 11,232 — 44,890 — — — 44,890 Level 1 Financial Instruments Our NYMEX futures contracts are exchange traded and are measured and recorded at fair value using quoted market prices, a Level 1 input. Level 2 Financial Instruments Investments in marketable securities and derivative instruments consisting of commodity price swaps and HEP's interest rate swaps are measured and recorded at fair value using Level 2 inputs. The fair values of the commodity price and interest rate swap contracts are based on the net present value of expected future cash flows related to both variable and fixed rate legs of the respective swap agreements. The measurements are computed using market-based observable inputs, quoted forward commodity prices with respect to our commodity price swaps and the forward London Interbank Offered Rate (“LIBOR”) yield curve with respect to HEP's interest rate swaps. The fair value of the marketable securities and senior notes is based on values provided by a third party, which were derived using market quotes for similar type instruments, a Level 2 input. 69 Table of Contents HOLLYFRONTIER CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued Level 3 Financial Instruments We have commodity price swap contracts that relate to forecasted sales of diesel and unleaded gasoline and forecasted purchases of WCS for which quoted forward market prices are not readily available. The forward rate used to value these price swaps is derived using a projected forward rate using quoted market rates for similar products, adjusted for regional pricing and grade differentials, a Level 3 input. The following table presents the changes in fair value of our Level 3 assets and liabilities (all related to derivative instruments) for the years ended December 31, 2013 and 2012: Level 3 Financial Instruments Years Ended December 31, 2013 2012 (In thousands) Asset (liability) balance at beginning of period $ (33,658) $ 31,616 Change in fair value: Recognized in other comprehensive income Recognized in cost of products sold Settlement date fair value of contractual maturities: Recognized in sales and other revenues Recognized in cost of products sold Liability balance at end of period (71,751) 35,236 20,060 14,795 (35,318) $ (120,966) (39,463) 98,750 (3,595) (33,658) $ A hypothetical change of 10% to the estimated future cash flows attributable to our Level 3 commodity price swaps would result in an estimated fair value change of $3.5 million. NOTE 5: Earnings Per Share Basic earnings per share is calculated as net income attributable to HollyFrontier stockholders divided by the average number of shares of common stock outstanding. Diluted earnings per share assumes, when dilutive, the issuance of the net incremental shares from variable restricted and variable performance shares. The following is a reconciliation of the denominators of the basic and diluted per share computations for net income attributable to HollyFrontier stockholders: Earnings attributable to HollyFrontier stockholders $ 735,842 $ 1,727,172 $ 1,023,397 2013 Years Ended December 31, 2012 (In thousands, except per share data) 2011 Participating securities' share in earnings Net income attributable to common shares Average number of shares of common stock outstanding Effect of dilutive variable restricted shares and performance share units (1) Average number of shares of common stock outstanding assuming dilution Basic earnings per share Diluted earnings per share 2,754 733,088 200,419 7,648 1,719,524 204,379 3,474 1,019,923 157,948 815 895 808 201,234 205,274 158,756 $ $ 3.66 3.64 $ $ 8.41 8.38 $ $ 6.46 6.42 — (1) Excludes anti-dilutive restricted and performance share units of: 166 166 70 Table of Contents HOLLYFRONTIER CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued NOTE 6: Stock-Based Compensation As of December 31, 2013, we have two principal share-based compensation plans (collectively, the “Long-Term Incentive Compensation Plan”). The compensation cost charged against income for these plans was $32.2 million, $36.3 million and $24.7 million for the years ended December 31, 2013, 2012 and 2011, respectively. Our accounting policy for the recognition of compensation expense for awards with pro-rata vesting (substantially all of our awards) is to expense the costs ratably over the vesting periods. Additionally, HEP maintains a share-based compensation plan for Holly Logistic Services, L.L.C.'s non-employee directors and certain executives and employees. Compensation cost attributable to HEP’s share-based compensation plan was $3.6 million, $2.7 million and $2.1 million for the years ended December 31, 2013, 2012 and 2011, respectively. Restricted Stock and Restricted Stock Units Under our Long-Term Incentive Compensation Plan, we grant certain officers and other key employees restricted stock and restricted stock unit awards with awards generally vesting over a period of one to three years. Restricted stock award recipients are generally entitled to all the rights of absolute ownership of the restricted shares from the date of grant (unless a recipient's tax election requires otherwise) including the right to vote the shares and to receive dividends. Upon vesting, restrictions on the restricted shares lapse at which time they convert to common shares. In addition, we grant non-employee directors restricted stock unit awards, which typically vest over a period of one year and are payable in stock. The fair value of each restricted stock and restricted stock unit award is measured based on the market price as of the date of grant and is amortized over the respective vesting period. A summary of restricted stock and restricted stock unit activity and changes during the year ended December 31, 2013 is presented below: Restricted Stock and Restricted Stock Units Grants Weighted Average Grant Date Fair Value Aggregate Intrinsic Value ($000) Outstanding at January 1, 2013 (non-vested) Granted Vesting (transfer / conversion to common stock) Forfeited Outstanding at December 31, 2013 (non-vested) 843,527 401,394 (491,565) (15,794) 737,562 $ $ 34.52 42.00 33.04 35.86 39.54 $ 36,650 For the year ended December 31, 2013, 491,565 restricted stock and restricted stock units vested having a grant date fair value of $16.2 million. For the years ended December 31, 2012 and 2011, we granted restricted stock having a weighted average grant date fair value of $37.27 and $28.61 per unit, respectively. Additionally, restricted stock vested during these periods having grant date fair values of $27.7 million and $9.1 million, respectively. As of December 31, 2013, there was $19.6 million of total unrecognized compensation cost related to non-vested restricted stock and restricted stock unit grants. That cost is expected to be recognized over a weighted-average period of 1.3 years. Performance Share Units Under our Long-Term Incentive Compensation Plan, we grant certain officers and other key employees performance share units, which are payable in stock upon meeting certain criteria over the service period, and generally vest over a period of three years. Under the terms of our performance share unit grants, awards are subject to either a “financial performance” or “market performance” criteria, or both. The fair value of performance share unit awards subject to financial performance criteria is computed using the grant date closing stock price of each respective award grant and will apply to the number of units ultimately awarded. The number of shares ultimately issued for each award will be based on our financial performance as compared to peer group companies over the performance period and can range from zero to 200%. As of December 31, 2013, estimated share payouts for outstanding non-vested performance share unit awards ranged approximately from 110% to 165%. 71 Table of Contents HOLLYFRONTIER CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued For the performance share units subject to market performance criteria, performance is calculated as the total shareholder return achieved by HollyFrontier stockholders compared with the average shareholder return achieved by an equally-weighted peer group of independent refining companies over a three-year period. These share unit awards are valued using a Monte Carlo valuation model, which simulates future stock price movements using key inputs including grant date stock prices, expected stock price performance, expected rate of return and volatility. These units are payable in stock based on share price performance relative to the defined peer group and can range from zero to 200% of the initial target award. A summary of performance share unit activity and changes during the year ended December 31, 2013 is presented below: Performance Share Units Outstanding at January 1, 2013 (non-vested) Granted Vesting and transfer of ownership to recipients Forfeited Outstanding at December 31, 2013 (non-vested) Grants 875,574 256,671 (126,460) (22,175) 983,610 For the year ended December 31, 2013, we issued 210,819 shares of our common stock, representing a 167% payout on vested performance share units having a grant date fair value of $11.6 million. For the years ended December 31, 2012 and 2011, we issued common stock upon the vesting of the performance share units having a grant date fair value of $6.0 million and $2.6 million, respectively. As of December 31, 2013, based on the weighted-average grant date fair value of $38.75 per share, there was $28.0 million of total unrecognized compensation cost related to non-vested performance share units. That cost is expected to be recognized over a weighted-average period of 1.6 years. NOTE 7: Cash and Cash Equivalents and Investments in Marketable Securities Our investment portfolio at December 31, 2013 consisted of cash, cash equivalents and investments in marketable securities. We currently invest in marketable debt securities with the maximum maturity or put date of any individual issue generally not greater than one year from the date of purchase, which are usually held until maturity. All of these instruments are classified as available-for-sale. As a result, they are reported at fair value using quoted market prices. Interest income is recorded as earned. Unrealized gains and losses, net of related income taxes, are reported as a component of accumulated other comprehensive income. Upon sale or maturity, realized gains on our marketable debt securities are recognized as interest income. These gains are computed based on the specific identification of the underlying cost of the securities, net of unrealized gains and losses previously reported in other comprehensive income. Unrealized gains and losses on our available-for-sale securities are due to changes in market prices and are considered temporary. The following is a summary of our marketable securities: December 31, 2013 Certificates of deposit Commercial paper Corporate debt securities State and political subdivisions debt securities Total marketable securities Amortized Cost Gross Unrealized Gain Gross Unrealized Loss Fair Value (Net Carrying Amount) (In thousands) $ $ 74,802 78,216 96,889 475,235 725,142 $ $ 21 28 6 49 104 $ $ (1) $ — (44) (41) (86) $ 74,822 78,244 96,851 475,243 725,160 72 Table of Contents HOLLYFRONTIER CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued December 31, 2012 Certificates of deposit Commercial paper Corporate debt securities State and political subdivisions debt securities Total marketable securities Amortized Cost Gross Unrealized Gain Gross Unrealized Loss Fair Value (Net Carrying Amount) (In thousands) $ $ 82,791 45,737 49,587 457,615 635,730 $ $ 14 17 2 26 59 $ $ (6) $ — (30) (51) (87) $ 82,799 45,754 49,559 457,590 635,702 Interest income recognized on our marketable securities was $2.1 million and $1.1 million for the years ended December 31, 2013 and 2012, respectively. NOTE 8: Inventories Inventory consists of the following components: Crude oil Other raw materials and unfinished products(1) Finished products(2) Process chemicals(3) Repairs and maintenance supplies and other Total inventory December 31, 2013 2012 (In thousands) $ 567,281 $ 154,534 519,633 3,504 109,295 502,978 150,090 585,610 3,514 77,440 $ 1,354,247 $ 1,319,632 (1) Other raw materials and unfinished products include feedstocks and blendstocks, other than crude. (2) Finished products include gasolines, jet fuels, diesels, lubricants, asphalts, LPG’s and residual fuels. (3) Process chemicals include additives and other chemicals. The excess of current cost over the LIFO value of inventory was $273.0 million and $134.0 million at December 31, 2013 and 2012, respectively. For the year ended December 31, 2013, we recognized a charge of $9.2 million to cost of products sold as we liquidated certain quantities of LIFO inventory that were carried at historical acquisition costs above market prices at the time of liquidation. For the years ended December 31, 2012 and 2011, we recognized reductions of $4.2 million and $0.1 million, respectively, to cost of products sold due to the liquidation of certain quantities of LIFO inventory that were carried at historical acquisition costs below market value at the time of liquidation. 73 Table of Contents HOLLYFRONTIER CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued NOTE 9: Properties, Plants and Equipment December 31, 2013 2012 (In thousands) Land, buildings and improvements $ 235,625 $ Refining facilities Pipelines and terminals Transportation vehicles Other fixed assets Construction in progress Accumulated depreciation 2,510,750 1,158,288 41,066 116,801 281,327 4,343,857 (949,261) 3,394,596 $ $ 198,610 2,261,733 1,113,080 29,970 105,075 234,646 3,943,114 (748,414) 3,194,700 We capitalized interest attributable to construction projects of $12.1 million, $9.1 million and $17.2 million for the years ended December 31, 2013, 2012 and 2011, respectively. Depreciation expense was $213.6 million, $182.9 million and $125.0 million for the years ended December 31, 2013, 2012 and 2011, respectively. For the years ended December 31, 2013, 2012 and 2011, depreciation expense included $62.3 million, $55.5 million and $31.2 million, respectively, attributable to HEP operations. NOTE 10: Goodwill The following table provides a summary of changes to our goodwill balance by segment for the year ended December 31, 2013. Balance at January 1, 2013 Adjustments to goodwill Balance at December 31, 2013 Refining Segment $ $ 2,049,311 (6,380) 2,042,931 HEP (In thousands) 288,991 $ — 288,991 $ Total $ $ 2,338,302 (6,380) 2,331,922 During 2013, we recorded additional in-process inventory and a corresponding reduction in goodwill to correct immaterial errors related to inventories purchased in previous business combinations. NOTE 11: Environmental We expensed $13.2 million, $46.1 million and $14.0 million for the years ended December 31, 2013, 2012 and 2011, respectively, for environmental remediation obligations. In 2012, we increased certain environmental cost accruals to reflect revisions to certain cost estimates and the time frame for which certain environmental remediation and monitoring activities are expected to occur. The accrued environmental liability reflected in our consolidated balance sheets was $87.8 million and $88.9 million at December 31, 2013 and 2012, respectively, of which $73.6 million and $72.6 million, respectively, were classified as other long- term liabilities. These accruals include remediation and monitoring costs expected to be incurred over an extended period of time (up to 30 years for certain projects). 74 Table of Contents NOTE 12: Debt HOLLYFRONTIER CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued HollyFrontier Credit Agreement We have a $1 billion senior secured credit agreement that matures in July 2016 (the “HollyFrontier Credit Agreement”) and may be used to fund working capital requirements, capital expenditures, acquisitions and general corporate purposes. Obligations under the HollyFrontier Credit Agreement are collateralized by our inventory, accounts receivable and certain deposit accounts and guaranteed by our material, wholly-owned subsidiaries. At December 31, 2013, we were in compliance with all covenants, had no outstanding borrowings and had outstanding letters of credit totaling $5.2 million under the HollyFrontier Credit Agreement. HEP Credit Agreement In November 2013, HEP amended its senior secured credit agreement increasing the size of the credit facility from $550 million to $650 million (the “HEP Credit Agreement”). The HEP Credit Agreement matures in November 2018 and is available to fund capital expenditures, investments, acquisitions, distribution payments and working capital and for general partnership purposes. It is also available to fund letters of credit up to a $50 million sub-limit. At December 31, 2013, HEP was in compliance with all its covenants, had outstanding borrowings of $363.0 million and no outstanding letters of credit under the HEP Credit Agreement. Indebtedness under the HEP Credit Agreement bears interest, at their option, at either a reference rate announced by the administrative agent plus an applicable margin or at a rate equal to LIBOR plus an applicable margin. In each case, the applicable margin is based upon the ratio of HEP’s funded debt to earnings before interest, taxes, depreciation and amortization (as defined in the HEP Credit Agreement). The interest rates in effect on HEP’s Credit Agreement borrowings were 2.163% and 2.456% at December 31, 2013 and 2012, respectively. HEP’s obligations under the HEP Credit Agreement are collateralized by substantially all of HEP’s assets (presented parenthetically in our consolidated balance sheets). Indebtedness under the HEP Credit Agreement involves recourse to HEP Logistics Holdings, L.P., its general partner, and is guaranteed by HEP’s wholly-owned subsidiaries. Any recourse to the general partner would be limited to the extent of HEP Logistics Holdings, L.P.’s assets, which other than its investment in HEP, are not significant. HEP’s creditors have no recourse to our other assets. Furthermore, our creditors have no recourse to the assets of HEP and its consolidated subsidiaries. HollyFrontier Senior Notes Our 6.875% senior notes ($150.0 million principal amount maturing November 2018) (the “HollyFrontier Senior Notes”) are unsecured and impose certain restrictive covenants, including limitations on our ability to incur additional debt, incur liens, enter into sale-and-leaseback transactions, pay dividends, enter into mergers, sell assets and enter into certain transactions with affiliates. Additionally, we have certain redemption rights under the HollyFrontier Senior Notes. At any time, following notice to the trustee, that the HollyFrontier Senior Notes are rated investment grade by both Moody's and Standard & Poor's and no default or event of default exists, we are not subject to many of the foregoing covenants (a "Covenant Suspension"). As of December 31, 2013, the HollyFrontier Senior Notes were rated investment grade (BBB-) by Standard & Poor's and also investment grade (Baa3) by Moody's. As a result, we are under the Covenant Suspension pursuant to the terms of the indenture governing the HollyFrontier Senior Notes. In June 2013, we redeemed our $286.8 million aggregate principal amount of 9.875% senior notes maturing June 2017 at a redemption cost of $301.0 million, at which time we recognized a $22.1 million early extinguishment loss consisting of a $14.2 million debt redemption premium and an unamortized discount of $7.9 million. In September 2012, we redeemed our $200 million aggregate principal amount of 8.5% senior notes maturing September 2016 at a redemption price of $208.5 million. HollyFrontier Financing Obligation We have a financing obligation that relates to a sale and lease-back of certain crude oil tankage that we sold to an affiliate of Plains All American Pipeline, L.P. (“Plains”) in October 2009 for $40.0 million. Monthly lease payments are recorded as a reduction in principal over the 15-year lease term ending in 2024. 75 Table of Contents HOLLYFRONTIER CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued HEP Senior Notes HEP’s senior notes consist of the following: • • 8.25% HEP senior notes ($150 million principal amount maturing March 2018) 6.5% HEP senior notes ($300 million principal amount maturing March 2020) In March 2012, HEP issued $300 million in an aggregate principal amount of 6.5% HEP senior notes maturing March 2020. The $294.8 million in net proceeds were used to repay $157.8 million aggregate principal amount of 6.25% HEP senior notes, $72.9 million in promissory notes due to HollyFrontier, related fees, expenses and accrued interest in connection with these transactions and to repay borrowings under the HEP Credit Agreement. In April 2012, HEP called for redemption the remaining $27.2 million aggregate principal amount outstanding of 6.25% HEP senior notes. The 8.25% and 6.5% HEP senior notes (collectively, the “HEP Senior Notes”) are unsecured and impose certain restrictive covenants, including limitations on HEP’s ability to incur additional indebtedness, make investments, sell assets, incur certain liens, pay distributions, enter into transactions with affiliates, and enter into mergers. At any time when the HEP Senior Notes are rated investment grade by both Moody’s and Standard & Poor’s and no default or event of default exists, HEP will not be subject to many of the foregoing covenants. Additionally, HEP has certain redemption rights under the HEP Senior Notes. On February 12, 2014, HEP announced that it will redeem all of its outstanding 8.25% senior notes. The redemption price will be equal to 104.125% of the principal amount for a total payment to the holders of the notes of approximately $156.2 million plus accrued interest. The redemption of the 8.25% senior notes is scheduled to occur on March 15, 2014. HEP plans to fund the redemption with borrowings under the HEP Credit Agreement. Indebtedness under the HEP Senior Notes involves recourse to HEP Logistics Holdings, L.P., its general partner, and is guaranteed by HEP’s wholly-owned subsidiaries. However, any recourse to the general partner would be limited to the extent of HEP Logistics Holdings, L.P.’s assets, which other than its investment in HEP, are not significant. HEP’s creditors have no other recourse to our assets. Furthermore, our creditors have no recourse to the assets of HEP and its consolidated subsidiaries. The carrying amounts of long-term debt are as follows: 9.875% Senior Notes Principal Unamortized discount 6.875% Senior Notes Principal Unamortized premium Financing Obligation Total HollyFrontier long-term debt December 31, 2013 2012 (In thousands) $ — $ — — 150,000 5,054 155,054 34,835 189,889 286,812 (7,468) 279,344 150,000 5,910 155,910 36,311 471,565 76 Table of Contents HOLLYFRONTIER CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued December 31, 2013 2012 (In thousands) 363,000 421,000 150,000 (1,297) 148,703 300,000 (4,073) 295,927 807,630 150,000 (1,602) 148,398 300,000 (4,725) 295,275 864,673 $ 997,519 $ 1,336,238 HEP Credit Agreement HEP 8.25% Senior Notes Principal Unamortized discount HEP 6.5% Senior Notes Principal Unamortized discount Total HEP long-term debt Total long-term debt Principal maturities of long-term debt are as follows: Years Ending December 31, (In thousands) 2014 2015 2016 2017 2018 Thereafter Total $ $ 1,666 1,880 2,121 2,393 665,700 324,075 997,835 NOTE 13: Derivative Instruments and Hedging Activities Commodity Price Risk Management Our primary market risk is commodity price risk. We are exposed to market risks related to the volatility in crude oil and refined products, as well as volatility in the price of natural gas used in our refining operations. We periodically enter into derivative contracts in the form of commodity price swaps and futures contracts to mitigate price exposure with respect to: • • • • • our inventory positions; natural gas purchases; costs of crude oil and related grade differentials; prices of refined products; and our refining margins. Accounting Hedges We have swap contracts serving as cash flow hedges against price risk on forecasted purchases of natural gas and WTI crude oil and forecasted sales of ultra-low sulfur diesel and conventional unleaded gasoline. These contracts have been designated as accounting hedges and are measured quarterly at fair value with offsetting adjustments (gains/losses) recorded directly to other comprehensive income. These fair value adjustments are later reclassified to earnings as the hedging instruments mature. Also on a quarterly basis, hedge ineffectiveness is measured by comparing the change in fair value of the swap contracts against the expected future cash inflows/outflows on the respective transaction being hedged. Any hedge ineffectiveness is also recognized in earnings. The following table presents the pre-tax effect on other comprehensive income (“OCI”) and earnings due to fair value adjustments and maturities of commodity price swaps under hedge accounting: 77 Table of Contents HOLLYFRONTIER CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued Unrealized Gain (Loss) Recognized in OCI Gain (Loss) Recognized in Earnings Due to Settlements Amount Location Gain (Loss) Attributable to Hedge Ineffectiveness Recognized in Earnings Location Amount Year Ended December 31, 2013 Commodity price swaps Change in fair value Gain reclassified to earnings due to settlements Amortization of discontinued hedges reclassified to earnings Total Year Ended December 31, 2012 Commodity price swaps Change in fair value Loss reclassified to earnings due to settlements Total Year Ended December 31, 2011 Commodity price swaps Change in fair value Loss reclassified to earnings due to settlements Total $ $ $ $ $ $ Sales and other revenues Cost of products sold Operating expenses (8,808) (16,410) 900 (24,318) Sales and other revenues Cost of products sold (248,399) 55,175 (193,224) 173,208 166 173,374 Operating expenses $ $ $ $ $ $ (In thousands) Sales and other revenues Cost of products sold (20,060) 38,949 (3,379) 15,510 Sales and other revenues Cost of products sold (98,750) 43,575 (55,175) Cost of products sold (166) (166) $ $ $ $ $ $ 45 515 560 (491) (515) (1,006) 446 446 As of December 31, 2013, we have the following notional contract volumes related to outstanding derivative instruments serving as cash flow hedges against price risk on forecasted purchases of natural gas and crude oil and sales of refined products: Derivative instruments Natural gas - long WTI crude oil - long Notional Contract Volumes by Year of Maturity Total Outstanding Notional 2014 2015 2016 2017 Unit of Measure 38,400,000 9,600,000 9,600,000 9,600,000 9,600,000 MMBTU Ultra-low sulfur diesel - short 15,512,500 12,957,500 2,555,000 Sub octane gasoline - short 3,285,000 3,285,000 — 18,797,500 16,242,500 2,555,000 — — — — Barrels — Barrels — Barrels In the first quarter of 2013, we dedesignated certain commodity price swaps (long positions) that previously received hedge accounting treatment. These contracts now serve as economic hedges against price risk on forecasted natural gas purchases totaling 38,400,000 MMBTU's to be purchased ratably through 2017. As of December 31, 2013, we have an unrealized loss of $4.3 million classified in accumulated other comprehensive income that relates to the application of hedge accounting prior to dedesignation that will be amortized as a charge to operating expenses as the contracts mature. Economic Hedges We also have swap contracts that serve as economic hedges (derivatives used for risk management, but not designated as accounting hedges) to fix our purchase price on forecasted natural gas purchases, and to lock in the spread between WCS and WTI crude oil on forecasted purchases of WCS. Also, we have NYMEX futures contracts to lock in prices on forecasted purchases of inventory. These contracts are measured quarterly at fair value with offsetting adjustments (gains/losses) recorded directly to income. 78 Table of Contents HOLLYFRONTIER CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued The following table presents the pre-tax effect on income due to maturities and fair value adjustments of our economic hedges: Location of Gain (Loss) Recognized in Income 2013 Years Ended December 31, 2012 (In thousands) 2011 Cost of products sold Operating expenses Total $ $ 20,751 (5,250) 15,501 $ $ 12,295 573 12,868 $ $ 3,219 — 3,219 As of December 31, 2013, we have the following notional contract volumes related to our outstanding derivative contracts serving as economic hedges: Derivative Instrument Notional Contract Volumes by Year of Maturity Total Outstanding Notional 2014 2015 2016 2017 Unit of Measure Commodity price swap (WCS spread) - long 6,387,500 6,387,500 — — — Barrels Commodity price swap (natural gas) - long 38,400,000 9,600,000 9,600,000 9,600,000 9,600,000 MMBTU Commodity price swap (natural gas) - short 38,400,000 9,600,000 9,600,000 9,600,000 9,600,000 MMBTU NYMEX futures (WTI) - short 1,946,000 1,946,000 Physical contracts - long Physical contracts - short 300,000 300,000 300,000 300,000 — — — — — — — Barrels — Barrels — Barrels Interest Rate Risk Management HEP uses interest rate swaps to manage its exposure to interest rate risk. As of December 31, 2013, HEP had three interest rate swap contracts that hedge its exposure to the cash flow risk caused by the effects of LIBOR changes on $305.0 million in credit agreement advances. The first interest rate swap effectively converts $155.0 million of LIBOR based debt to fixed rate debt having an interest rate of 0.99% plus an applicable margin of 2.00% as of December 31, 2013, which equaled an effective interest rate of 2.99%. This swap matures in February 2016. HEP has two additional interest rate swaps with identical terms which effectively convert $150.0 million of LIBOR based debt to fixed rate debt having an interest rate of 0.74% plus an applicable margin of 2.00% as of December 31, 2013, which equaled an effective interest rate of 2.74%. Both of these swap contracts mature in July 2017. All of these swap contracts have been designated as cash flow hedges. To date, there has been no ineffectiveness on these cash flow hedges. 79 Table of Contents HOLLYFRONTIER CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued The following table presents the pre-tax effect on other comprehensive income and earnings due to fair value adjustments and maturities of HEP's interest rate swaps under hedge accounting: Unrealized Gain (Loss) Recognized in OCI Loss Recognized in Earnings Due to Settlements Location (In thousands) Amount Year Ended December 31, 2013 Interest rate swaps Change in fair value Loss reclassified to earnings due to settlements Amortization of discontinued hedge reclassified to earnings Total Year Ended December 31, 2012 Interest rate swaps Change in fair value Loss reclassified to earnings due to settlements Amortization of discontinued hedge reclassified to earnings Total Year Ended December 31, 2011 Interest rate swaps Change in fair value Loss reclassified to earnings due to settlements Amortization of discontinued hedge reclassified to earnings Total $ $ $ $ $ $ 1,194 2,092 849 4,135 (4,418) 1,508 5,095 2,185 (1,956) 5,477 41 3,562 Interest expense Interest expense Interest expense $ $ $ $ $ $ (2,941) (2,941) (6,603) (6,603) (5,518) (5,518) The following table presents the fair value and balance sheet locations of our outstanding derivative instruments. These amounts are presented on a gross basis with offsetting balances that reconcile to a net asset or liability position in our consolidated balance sheets. We present on a net basis to reflect the net settlement of these positions in accordance with provisions of our master netting arrangements. Derivatives in Net Asset Position Derivatives in Net Liability Position Gross Liabilities Offset in Balance Sheet Gross Assets Net Assets Recognized in Balance Sheet Gross Liabilities Gross Assets Offset in Balance Sheet (In thousands) Net Liabilities Recognized in Balance Sheet December 31, 2013 Derivatives designated as cash flow hedging instruments: Commodity price swap contracts Interest rate swap contracts $ $ — $ 1,670 1,670 $ Derivatives not designated as cash flow hedging instruments: Commodity price swap contracts NYMEX futures contracts $ $ 6,972 — 6,972 $ $ Total net balance Balance sheet classification: Prepayment and other Intangibles and other — $ — — $ — $ — — $ $ $ $ 80 — $ $ $ $ 1,670 1,670 6,972 — 6,972 8,642 6,972 1,670 8,642 63,561 1,814 65,375 19,766 3,569 23,335 $ $ $ $ (23,679) $ — (23,679) $ (12,611) $ — (12,611) $ Accrued liabilities Other long-term liabilities $ $ $ 39,882 1,814 41,696 7,155 3,569 10,724 52,420 26,843 25,577 52,420 Table of Contents HOLLYFRONTIER CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued Derivatives in Net Asset Position Derivatives in Net Liability Position Gross Liabilities Offset in Balance Sheet Gross Assets Net Assets Recognized in Balance Sheet Gross Liabilities Gross Assets Offset in Balance Sheet (In thousands) Net Liabilities Recognized in Balance Sheet December 31, 2012 Derivatives designated as cash flow hedging instruments: Commodity price swap contracts Interest rate swap contracts $ $ — $ — — $ Derivatives not designated as cash flow hedging instruments: Commodity price swap contracts NYMEX futures contracts $ $ — $ — — $ — $ — — $ — $ — — $ — $ — — $ — $ — — $ 37,828 3,430 41,258 46,154 5,563 51,717 $ $ $ $ (17,383) $ — (17,383) $ — $ — — $ Total net balance Balance sheet classification: $ — Accrued liabilities Other long-term liabilities $ $ $ 20,445 3,430 23,875 46,154 5,563 51,717 75,592 62,388 13,204 75,592 At December 31, 2013, we had a pre-tax net unrealized loss of $44.3 million classified in accumulated other comprehensive income that relates to all accounting hedges having contractual maturities through 2017. Assuming commodity prices and interest rates remain unchanged, an unrealized loss of $22.2 million will be effectively transferred from accumulated other comprehensive income into the statement of income as the hedging instruments contractually mature over the next twelve-month period. NOTE 14: Income Taxes The provision for income taxes is comprised of the following: Current Federal State Deferred Federal State 2013 Years Ended December 31, 2012 (In thousands) 2011 $ $ 270,024 7,148 94,896 19,508 391,576 $ $ 797,406 135,148 70,671 24,737 1,027,962 $ $ 499,535 91,316 (9,679) 819 581,991 81 Table of Contents HOLLYFRONTIER CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued The statutory federal income tax rate applied to pre-tax book income reconciles to income tax expense as follows: Tax computed at statutory rate State income taxes, net of federal tax benefit Domestic production activities deduction Noncontrolling interest in net income Uncertain tax positions Other 2013 Years Ended December 31, 2012 (In thousands) 2011 $ $ 405,790 21,363 (22,101) (12,378) (193) (905) 391,576 $ $ 975,798 110,739 (54,745) (12,783) 7,309 1,644 1,027,962 $ $ 574,682 64,284 (32,194) (14,221) (12,125) 1,565 581,991 Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Our deferred income tax assets and liabilities as of December 31, 2013 and 2012 are as follows: Deferred income taxes Accrued employee benefits Accrued environmental costs Hedging instruments Inventory differences Prepaid insurance Prepayments and other Total current Properties, plants and equipment (due primarily to tax in excess of book depreciation) Accrued employee benefits Accrued post-retirement benefits Accrued environmental costs Hedging instruments Deferred turnaround costs Net operating loss and tax credit carryforwards Investment in HEP Other Total noncurrent Total Assets December 31, 2013 Liabilities (In thousands) Total $ $ 3,138 5,010 12,417 — — — 20,565 — 41,997 — 20,431 3,744 — 24,086 — 10,858 101,116 121,681 $ $ — $ — — (235,823) (7,222) (1,519) (244,564) (578,958) — (8,071) — — (101,158) — (29,771) — (717,958) (962,522) $ 3,138 5,010 12,417 (235,823) (7,222) (1,519) (223,999) (578,958) 41,997 (8,071) 20,431 3,744 (101,158) 24,086 (29,771) 10,858 (616,842) (840,841) 82 Table of Contents HOLLYFRONTIER CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued Deferred income taxes Accrued employee benefits Accrued post-retirement benefits Accrued environmental costs Hedging instruments Inventory differences Prepayments and other Total current Properties, plants and equipment (due primarily to tax in excess of book depreciation) Accrued post-retirement benefits Accrued environmental costs Hedging instruments Deferred turnaround costs Net operating loss and tax credit carryforwards Investment in HEP Debt fair value premium Other Total noncurrent Total Assets December 31, 2012 Liabilities (In thousands) Total $ $ 13,285 — 5,096 23,927 — — 42,308 — 15,628 18,963 3,802 — 21,863 — 8,820 6,766 75,842 118,150 $ — $ (563) — — (181,634) (5,327) (187,524) (536,430) — — — (60,167) — (15,915) — — (612,512) (800,036) $ $ 13,285 (563) 5,096 23,927 (181,634) (5,327) (145,216) (536,430) 15,628 18,963 3,802 (60,167) 21,863 (15,915) 8,820 6,766 (536,670) (681,886) At December 31, 2013, we had a net operating loss carryforward of $46.2 million in the state of Colorado that is scheduled to be utilized in 2014 through 2029 and a Kansas income tax credit of $12.8 million that is scheduled to be utilized in 2014 through 2019. These amounts are reflected in other current and non-current deferred tax assets. As of December 31, 2013, the total amount of unrecognized tax benefits was $9.0 million. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows: Balance at January 1 Additions due to merger with Frontier Additions for tax positions of prior years Reductions for tax positions of prior years Settlements Reductions for statute limitations Balance at December 31 $ $ 2013 $ $ Years Ended December 31, 2012 (In thousands) 2,425 — 10,305 (89) — — 12,641 12,641 — 25,728 (5,092) (24,271) — 9,006 $ $ 2011 1,864 22,577 73 (204) (21,679) (206) 2,425 At December 31, 2013, 2012 and 2011, there were $0.4 million, $10.2 million and $2.2 million, respectively, of unrecognized tax benefits that, if recognized, would affect our effective tax rate. Unrecognized tax benefits are adjusted in the period in which new information about a tax position becomes available or the final outcome differs from the amount recorded. We recognize interest and penalties relating to liabilities for unrecognized tax benefits as an element of tax expense. We have not recorded any penalties related to our uncertain tax positions as we believe that it is more likely than not that there will not be any assessment of penalties. We expect that unrecognized tax benefits for tax positions taken with respect to 2013 and prior years will change within the next 12 months and the majority of these items will be settled with taxing authorities. 83 Table of Contents HOLLYFRONTIER CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued We are subject to U.S. federal income tax, Oklahoma, New Mexico, Kansas, Utah, Arizona, Colorado and Iowa income tax and to income tax of multiple other state jurisdictions. We have substantially concluded all U.S. federal, state and local income tax matters for tax years through December 31, 2009. In late 2013, the Internal Revenue Service commenced an examination of our U.S. federal tax returns for tax years ended December 31, 2010, 2011 and 2012. We anticipate that these audits will be completed in 2014. NOTE 15: Stockholders' Equity Shares of our common stock outstanding and activity for the years ended December 31, 2013, 2012 and 2011 are presented below: Common shares outstanding at January 1 Common shares issued in connection with merger with Frontier Issuance of restricted stock, excluding restricted stock with performance feature Vesting of performance units Vesting of restricted stock with performance feature Forfeitures of restricted stock Purchase of treasury stock (1) Common shares outstanding at December 31 2013 Years Ended December 31, 2012 (In thousands) 2011 203,551,496 — 209,332,646 106,529,376 — 103,270,002 292,855 210,819 15,141 (15,794) (5,224,166) 198,830,351 691,207 869,231 146,400 (3,975) (7,484,013) 203,551,496 512,880 233,134 124,332 (3,730) (1,333,348) 209,332,646 (1) Includes 235,922, 560,484 and 747,225 shares, respectively, withheld under the terms of stock-based compensation agreements to provide funds for the payment of payroll and income taxes due at the vesting of share-based awards, as well as other stock repurchases under separate authority from our Board of Directors. We have a Board approved repurchase program that authorizes us to repurchase common stock in the open market or through privately negotiated transactions. The timing and amount of stock repurchases will depend on market conditions, corporate, regulatory and other relevant considerations. This program may be discontinued at any time by the Board of Directors. As of December 31, 2013, we had remaining authorization to repurchase up to $311.6 million under this stock repurchase program. In May 2012, we entered into a structured share repurchase arrangement with a financial institution under which we provided an up-front cash payment of $100.0 million and, depending on market conditions, would either receive shares of our common stock or cash at the expiration of the agreement. The agreement expired in September 2012 at which time we received our up-front payment plus an additional $8.6 million in cash that was recorded as additional capital. During the years ended December 31, 2013, 2012 and 2011, we withheld shares of our common stock from certain employees in the amounts of $11.3 million, $22.4 million and $24.9 million, respectively. These withholdings were made under the terms of restricted stock and performance share unit agreements upon vesting, at which time, we concurrently made cash payments to fund payroll and income taxes on behalf of officers and employees who elected to have shares withheld from vested amounts to pay such taxes. 84 Table of Contents HOLLYFRONTIER CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued NOTE 16: Other Comprehensive Income (Loss) The components and allocated tax effects of other comprehensive income (loss) are as follows: Year Ended December 31, 2013 Net unrealized gain on marketable securities Net unrealized loss on hedging instruments Net change in pension and other post-retirement benefit obligations Other comprehensive income Less other comprehensive income attributable to noncontrolling interest Other comprehensive income attributable to HollyFrontier stockholders Year Ended December 31, 2012 Net unrealized loss on marketable securities Net unrealized loss on hedging instruments Net change in pension and other post-retirement benefit obligations Other comprehensive loss Less other comprehensive income attributable to noncontrolling interest Other comprehensive loss attributable to HollyFrontier stockholders Year Ended December 31, 2011 Net unrealized loss on marketable securities Net unrealized gain on hedging instruments Net change in pension and other post-retirement benefit obligations Other comprehensive income Less other comprehensive income attributable to noncontrolling interest Other comprehensive income attributable to HollyFrontier stockholders Before-Tax Tax Expense (Benefit) (In thousands) After-Tax $ $ $ $ $ $ 34 (20,183) 37,593 17,444 2,315 15,129 $ $ (236) $ (191,039) 51,391 (139,884) 1,364 (141,248) $ 17 (8,669) 14,534 5,882 — 5,882 $ $ (95) $ (74,846) 19,991 (54,950) — (54,950) $ (516) $ (199) $ 176,936 (3,586) 172,834 2,815 170,019 $ 67,732 (1,395) 66,138 — 66,138 $ 17 (11,514) 23,059 11,562 2,315 9,247 (141) (116,193) 31,400 (84,934) 1,364 (86,298) (317) 109,204 (2,191) 106,696 2,815 103,881 The temporary unrealized gain (loss) on marketable securities is due to changes in market prices. 85 Table of Contents HOLLYFRONTIER CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued The following table presents the income statement line item effects for reclassifications out of accumulated other comprehensive income (“AOCI”): AOCI Component Marketable securities $ Gain (Loss) Reclassified From AOCI (In thousands) Years Ended December 31, 2013 2012 2011 $ 39 — 39 15 24 $ 59 326 385 150 235 Income Statement Line Item Interest income (14) — Gain on sale of marketable equity securities (14) (5) (9) Net of tax Income tax expense (benefit) Hedging instruments: Commodity price swaps Interest rate swaps Pension and other post-retirement benefit obligations: Pension obligation Post-retirement healthcare obligation Retirement restoration plan (20,060) 38,949 (3,379) (2,941) 12,569 5,554 7,015 1,783 8,798 (3,226) (30,127) (4,236) (37,589) (14,547) (23,042) 646 2,868 526 4,040 1,563 2,477 (111) (43) (68) (98,750) 43,575 — (6,603) (61,778) (22,590) (39,188) 3,753 (35,435) (226) (1,486) (244) (1,956) (761) (1,195) — 1,913 39 1,952 759 1,193 (63) (25) (38) — Sales and other revenues — Cost of products sold (166) Operating expenses (5,518) (5,684) (961) Interest expense Income tax expense (benefit) (4,723) Net of tax 3,214 Noncontrolling interest (1,509) Net of tax and noncontrolling interest (155) Cost of products sold (1,056) Operating expenses (1,091) General and administrative expenses (2,302) (895) Income tax benefit (1,407) Net of tax (16) Cost of products sold (125) Operating expenses (17) General and administrative expenses (158) (61) (97) Net of tax Income tax expense (benefit) (99) General and administrative expenses (39) (60) Net of tax Income tax benefit Total reclassifications for the period $ (11,811) $ (35,240) $ (3,082) Accumulated other comprehensive income (loss) in the equity section of our consolidated balance sheets includes: December 31, 2013 2012 Unrealized gain on post-retirement benefit obligations Unrealized gain (loss) on marketable securities Unrealized loss on hedging instruments, net of noncontrolling interest Accumulated other comprehensive income (loss) $ $ 86 $ (In thousands) 27,691 10 (26,879) 822 $ 4,632 (7) (13,050) (8,425) Table of Contents NOTE 17: Retirement Plan HOLLYFRONTIER CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued In 2012, our Compensation Committee, pursuant to authority delegated to it by the Board of Directors, approved the termination of the HollyFrontier Corporation Pension Plan (the "Plan"), a non-contributory defined benefit retirement plan that covered certain employees and was fully frozen prior to 2013. In June 2013, we made contributions of $22.7 million to the Plan, which was sufficient for the Plan to settle its obligations to all participants including the premium paid to the non-participating annuity provider. In 2013, we recognized a pre-tax pension settlement charge of $39.5 million, of which $37.6 million was reclassified out of accumulated other comprehensive income, representing the irrevocable portion of our obligation. The following table sets forth the changes in the benefit obligation and plan assets of our retirement plan for the years ended December 31, 2013 and 2012: Change in plan's benefit obligation Pension plan's benefit obligation - beginning of year Service cost Interest cost Benefits paid Actuarial loss Settlements paid Curtailment Pension plan's benefit obligation - end of year Change in pension plan assets Fair value of plan assets - beginning of year Actual return on plan assets Benefits paid Employer contributions Settlements paid Fair value of plan assets - end of year Funded status Under-funded balance Amounts recognized in consolidated balance sheets Accrued pension liability Amounts recognized in accumulated other comprehensive income (loss) Cumulative actuarial loss Years Ended December 31, 2013 2012 (In thousands) $ 95,485 — 1,797 (3,957) 2,981 (96,306) — — $ $ 77,757 (219) (3,957) 22,725 (96,306) — $ 93,378 679 3,962 (1,379) 13,203 (7,256) (7,102) 95,485 61,398 2,615 (1,379) 22,379 (7,256) 77,757 — $ (17,728) — $ (17,728) — $ (37,589) $ $ $ $ $ $ $ 87 Table of Contents HOLLYFRONTIER CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued Net periodic pension expense consisted of the following components: Service cost – benefit earned during the year Interest cost on projected benefit obligations Expected return on plan assets Amortization of prior service cost Amortization of net loss Curtailment Loss on settlement Loss on plan termination Net periodic pension expense $ $ 2013 2011 $ — $ Years Ended December 31, 2012 (In thousands) 679 3,962 (3,798) 67 1,933 899 2,855 — 6,597 1,797 (92) — 1,386 — 36,203 3,293 42,587 $ $ 5,070 5,125 (5,230) 390 2,126 1,065 3,951 — 12,497 The weighted average assumptions used to determine net periodic benefit expense: 2013 December 31, 2012 2011 Discount rate Rate of future compensation increases Expected long-term rate of return on assets 3.95% —% 0.25% 4.60% 4.00% 6.50% 5.65% 4.00% 8.00% In 2012, we established a program for plan participants whose benefits pursuant to the defined benefit plan were frozen. The program provides for payments after year-end for three years (beginning with 2012) provided the employee is employed by us on the last day of each year. The payments are based on each employee's years of service and eligible salary. Transition benefit costs associated with transition to the new defined contribution plan were $12.5 million and $15.6 million for the years ended December 31, 2013 and 2012, respectively. Post-retirement Healthcare Plans We provide post-retirement medical benefits to certain eligible employees. These plans are unfunded and provide differing levels of healthcare benefits dependent upon hire date and work location. Not all of our employees are covered by these plans at December 31, 2013. Effective December 31, 2012, we amended the post-retirement healthcare plans for participants retiring after December 31, 2012 by eliminating post-retirement benefits after reaching age 65 and eliminating early retirement benefits for most participants who retire before reaching age 62. In addition, certain future retirees will receive a cash payment in lieu of post-retirement benefits after reaching age 65 and other changes were made generally to conform benefits. In the first quarter of 2013, we settled a portion of our post-retirement medical obligation, at which time we reclassified a $1.7 million pretax loss out of accumulated other comprehensive income that was recognized as a charge to net income. 88 Table of Contents HOLLYFRONTIER CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued The following table sets forth the changes in the benefit obligation and plan assets of our post-retirement healthcare plans for the years ended December 31, 2013 and 2012: Change in plans' benefit obligation Post-retirement plans' benefit obligation - beginning of year Service cost Interest cost Participant contributions Amendments Settlements Benefits paid Actuarial gain Post-retirement plans' benefit obligation - end of year Change in plan assets Fair value of plan assets - beginning of year Employer contributions Participant contributions Settlements Benefits paid Fair value of plan assets - end of year Funded status Under-funded balance Amounts recognized in consolidated balance sheets Accrued post-retirement liability Amounts recognized in accumulated other comprehensive income (loss) Cumulative actuarial loss Prior service credit Total $ $ $ $ $ $ $ $ Years Ended December 31, 2013 2012 (In thousands) 26,797 1,112 665 564 (820) (8,627) (1,585) (2,391) 15,715 $ $ — $ 9,648 564 (8,627) (1,585) — $ 77,303 1,892 3,519 760 (49,399) — (1,275) (6,003) 26,797 — 515 760 — (1,275) — (15,715) $ (26,797) (15,715) $ (26,797) (1,022) $ 47,098 46,076 $ (5,359) 52,174 46,815 Benefit payments, which reflect expected future service, are expected to be paid as follows: $1.4 million in 2014; $1.2 million in 2015; $1.2 million in 2016; $1.2 million in 2017; $1.3 million in 2018; and $6.6 million in 2019 through 2023. The weighted average assumptions used to determine end of period benefit obligations: Discount rate Current health care trend rate Ultimate health care trend rate Year rate reaches ultimate trend rate December 31, 2013 2012 4.25% 8.00% 5.00% 2045 3.45% 8.10% 5.00% 2023 89 Table of Contents HOLLYFRONTIER CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued Net periodic post-retirement expense consisted of the following components: Service cost – benefit earned during the year Interest cost on projected benefit obligations Amortization of transition obligation Amortization of prior service credit Amortization of net loss Loss on settlement Net periodic post-retirement expense (credit) $ $ 2013 2011 $ Years Ended December 31, 2012 (In thousands) 1,892 $ 3,519 — (2,221) 269 — 3,459 1,112 665 — (5,896) 130 1,726 (2,263) $ $ 1,569 2,193 44 — 114 — 3,920 Assumed health care cost trend rates have an effect on the amounts reported for the post-retirement health care benefit plans. The weighted average assumptions used to determine net periodic benefit expense follow: Years Ended December 31, 2012 2011 2013 Discount rate Current health care trend rate Ultimate health care trend rate Year rate reaches ultimate trend rate 3.45% 8.10% 5.00% 2023 4.60% 8.40% 5.00% 2023 5.75% 8.70% 5.00% 2023 The effect of a 1% change in health care cost trend rates is as follows: Service cost Interest cost Year-end accumulated post-retirement benefit obligation $ $ $ 1% Point Increase 1% Point Decrease (In thousands) 241 60 1,373 $ $ $ (197) (50) (1,109) Retirement Restoration Plan We adopted an unfunded retirement restoration plan that provides for additional payments from us so that total retirement plan benefits for certain executives will be maintained at the levels provided in the retirement plan before the application of Internal Revenue Code limitations. Effective January 1, 2012, we ceased to accrue benefits under this plan. We expensed $0.4 million, $0.3 million and $0.6 million for the years ended December 31, 2013, 2012 and 2011, respectively, in connection with this plan. The accrued liability reflected in the consolidated balance sheets was $6.8 million and $7.4 million at December 31, 2013 and 2012, respectively. As of December 31, 2013, the projected benefit obligation under this plan was $6.8 million. Benefit payments, which reflect expected future service, are expected to be paid as follows: $2.3 million in 2014; $0.5 million in 2015; $0.5 million in 2016; $1.6 million in 2017; $0.3 million in 2018; and $1.3 million in 2019 through 2023. Defined Contribution Plans We have a defined contribution “401(k)” plan that covers substantially all employees. Our contributions are based on an employee's eligible compensation and years of service. We also partially match the employee's contributions. We expensed $15.5 million, $16.0 million and $9.7 million for the years ended December 31, 2013, 2012 and 2011, respectively, in connection with these plans. 90 Table of Contents HOLLYFRONTIER CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued NOTE 18: Lease Commitments We lease certain office and storage facilities, rail cars and other equipment under long-term operating leases, most of which contain renewal options. At December 31, 2013, the minimum future rental commitments under operating leases having non-cancellable lease terms in excess of one year are as follows: 2014 2015 2016 2017 2018 Thereafter Total (In thousands) $ 23,709 22,139 20,189 11,974 4,965 4,825 87,801 $ Rental expense charged to operations was $48.5 million, $42.6 million and $35.9 million for the years ended December 31, 2013, 2012 and 2011, respectively. For the years ended December 31, 2013, 2012 and 2011, rental expense included $8.3 million, $8.1 million and $7.5 million attributable to the HEP operations. NOTE 19: Contingencies and Contractual Commitments We are a party to various litigation and legal proceedings which we believe, based on advice of counsel, will not either individually or in the aggregate have a materially adverse effect on our financial condition, results of operations or cash flows. Contractual Commitments We have various long-term agreements (entered in the normal course of business) to purchase crude oil, natural gas, feedstocks and other resources to ensure we have adequate supplies to operate our refineries. The substantial majority of our purchase obligations are based on market prices or rates. These contracts expire in 2014 through 2020. We also have long-term agreements with third parties for the transportation and storage of crude oil, natural gas and feedstocks to our refineries and for terminal and storage services that expire in 2014 through 2032. At December 31, 2013, the minimum future transportation and storage fees under transportation agreements having terms in excess of one year are as follows: 2014 2015 2016 2017 2018 Thereafter Total $ (In thousands) 144,434 143,747 121,557 111,131 93,884 659,324 $ 1,274,077 Transportation and storage costs incurred under these agreements totaled $122.0 million for the year ended December 31, 2013. These amounts do not include contractual commitments under our long-term transportation agreements with HEP. HEP is a consolidated VIE; all transactions with HEP are eliminated in these consolidated financial statements. 91 Table of Contents HOLLYFRONTIER CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued NOTE 20: Segment Information Our operations are organized into two reportable segments, Refining and HEP. Our operations that are not included in the Refining and HEP segments are included in Corporate and Other. Intersegment transactions are eliminated in our consolidated financial statements and are included in Consolidations and Eliminations. The Refining segment represents the operations of the El Dorado, Tulsa, Navajo, Cheyenne and Woods Cross Refineries and NK Asphalt (aggregated as a reportable segment). Refining activities involve the purchase and refining of crude oil and wholesale and branded marketing of refined products, such as gasoline, diesel fuel and jet fuel. These petroleum products are primarily marketed in the Mid-Continent, Southwest and Rocky Mountain regions of the United States. Additionally, the Refining segment includes specialty lubricant products produced at our Tulsa Refineries that are marketed throughout North America and are distributed in Central and South America. NK Asphalt operates various asphalt terminals in Arizona and New Mexico. The HEP segment includes all of the operations of HEP, a consolidated VIE, which owns and operates logistics assets consisting of petroleum product and crude oil pipelines and terminal, tankage and loading rack facilities in the Mid-Continent, Southwest and Rocky Mountain regions of the United States. The HEP segment also includes a 75% interest in UNEV (a consolidated subsidiary of HEP) and a 25% interest in the SLC Pipeline. Revenues from the HEP segment are earned through transactions with unaffiliated parties for pipeline transportation, rental and terminalling operations as well as revenues relating to pipeline transportation services provided for our refining operations. Due to certain basis differences, our reported amounts for the HEP segment may not agree to amounts reported in HEP’s periodic public filings. The accounting policies for our segments are the same as those described in the summary of significant accounting policies (see Note 1). Year Ended December 31, 2013 Sales and other revenues Depreciation and amortization Income (loss) from operations Capital expenditures Total assets Year Ended December 31, 2012 Sales and other revenues Depreciation and amortization Income (loss) from operations Capital expenditures Total assets Year Ended December 31, 2011 Sales and other revenues Depreciation and amortization Income (loss) from operations Capital expenditures Total assets Refining HEP Corporate and Other Consolidations and Eliminations Consolidated Total $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ 20,105,443 233,182 1,237,687 344,113 7,094,558 $ 307,053 $ 64,701 $ 133,522 $ 51,856 $1,413,908 20,042,955 181,247 2,879,383 278,705 6,702,872 $ 288,501 $ 57,789 $ 133,723 44,929 $ $1,426,800 15,392,430 122,437 1,739,068 148,699 6,576,966 $ 212,995 $ 33,288 $ 110,102 $ 216,215 $1,418,660 $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ (In thousands) $ 1,314 $ 6,391 (123,030) $ $ 29,158 $ 1,881,119 $ 1,048 $ 4,660 (126,840) $ $ 11,629 $ 2,531,967 $ 1,098 $ 4,810 (117,677) $ $ 9,327 $ 1,997,600 (253,250) $ (828) $ (2,105) $ — $ (332,846) $ 20,160,560 303,446 1,246,074 425,127 10,056,739 (241,780) $ (828) $ (2,120) $ — $ (332,642) $ 20,090,724 242,868 2,884,146 335,263 10,328,997 (166,995) $ (828) $ 55 $ — $ (416,983) $ 15,439,528 159,707 1,731,548 374,241 9,576,243 HEP segment revenues from external customers were $53.4 million, $47.6 million and $46.4 million for the years ended December 31, 2013, 2012 and 2011, respectively. 92 Table of Contents HOLLYFRONTIER CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued NOTE 21: Supplemental Guarantor/Non-Guarantor Financial Information Our obligations under the HollyFrontier Senior Notes have been jointly and severally guaranteed by the substantial majority of our existing and future restricted subsidiaries (“Guarantor Restricted Subsidiaries”). These guarantees are full and unconditional. HEP, in which we have a 39% ownership interest at December 31, 2013, and its subsidiaries (collectively, “Non-Guarantor Non- Restricted Subsidiaries”), and certain of our other subsidiaries (“Non-Guarantor Restricted Subsidiaries”) have not guaranteed these obligations. The following condensed consolidating financial information is provided for HollyFrontier Corporation (the “Parent”), the Guarantor Restricted Subsidiaries, the Non-Guarantor Restricted Subsidiaries and the Non-Guarantor Non-Restricted Subsidiaries. The information has been presented as if the Parent accounted for its ownership in the Guarantor Restricted Subsidiaries, and the Guarantor Restricted Subsidiaries accounted for the ownership of the Non-Guarantor Restricted Subsidiaries and Non-Guarantor Non-Restricted Subsidiaries, using the equity method of accounting. The Guarantor Restricted Subsidiaries and the Non-Guarantor Restricted Subsidiaries are collectively the “Restricted Subsidiaries.” Certain reclassifications have been made to intercompany balances in our prior year condensed parent company balance sheet to conform with our current year presentation. Additionally, we have made certain revisions to our prior year condensed statements of cash flows to reclassify intercompany lending and distribution activity between operating, investing and financing activities. Condensed Consolidating Balance Sheet December 31, 2013 Parent Guarantor Restricted Subsidiaries Non- Guarantor Restricted Subsidiaries HollyFrontier Corp. Before Consolidation of HEP Non-Guarantor Non-Restricted Subsidiaries (HEP Segment) Consolidations and Eliminations Eliminations Consolidated (In thousands) $ — $ — — (463,530) — — — (463,530) — (5,938,712) (25,000) $ (6,427,242) $ $ — $ (463,530) — — (463,530) (25,000) — — — — (5,938,712) — $ (6,427,242) $ 933,751 725,160 712,279 — 1,352,656 109,376 67,256 3,900,478 2,663,770 — 2,403,302 8,967,550 1,340,690 — 107,230 223,999 1,671,919 189,889 245,536 611,555 125,290 128,871 5,994,490 — 8,967,550 $ $ $ $ 6,352 — 34,736 — 1,591 — 2,283 44,962 1,004,975 — 363,970 1,413,907 22,898 — 28,668 — 51,566 807,630 — 5,287 35,918 — 416,018 97,488 1,413,907 $ $ $ $ — $ — (38,213) — — — (10,783) (48,996) (274,149) — (1,573) 940,103 725,160 708,802 — 1,354,247 109,376 58,756 3,896,444 3,394,596 — 2,765,699 (324,718) $ 10,056,739 1,325,376 (38,212) $ — — 125,115 (10,783) 223,999 — 1,674,490 (48,995) 997,519 — — (245,536) 616,842 — 158,490 (2,718) — (128,871) 5,999,620 (410,888) 512,290 609,778 (324,718) $ 10,056,739 ASSETS Current assets: Cash and cash equivalents Marketable securities Accounts receivable, net Intercompany accounts receivable Inventories Income taxes receivable Prepayments and other Total current assets Properties, plants and equip, net Investment in subsidiaries Intangibles and other assets Total assets LIABILITIES AND EQUITY Current liabilities: Accounts payable Intercompany accounts payable Accrued liabilities Deferred income tax liabilities Total current liabilities Long-term debt Liability to HEP Deferred income tax liabilities Other long-term liabilities Investment in HEP Equity – HollyFrontier Equity – noncontrolling interest Total liabilities and equity $ 931,920 725,160 6,095 — — 109,376 21,843 1,794,394 30,007 5,722,025 23,034 $ 7,569,460 $ 16,704 463,530 43,254 223,999 747,487 180,054 — 611,555 35,874 — 5,994,490 — $ 7,569,460 $ $ $ $ 1,817 — 698,109 149,907 1,352,656 — 45,413 2,247,902 2,633,739 216,687 2,380,268 7,478,596 1,323,603 — 63,181 — 1,386,784 34,835 245,536 — 89,416 — 5,722,025 — 7,478,596 $ $ $ $ 14 — 8,075 313,623 — — — 321,712 24 — 25,000 346,736 383 — 795 — 1,178 — — — — 128,871 216,687 — 346,736 93 Table of Contents HOLLYFRONTIER CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued Condensed Consolidating Balance Sheet December 31, 2012 Parent Guarantor Restricted Subsidiaries Non- Guarantor Restricted Subsidiaries HollyFrontier Corp. Before Consolidation of HEP Non-Guarantor Non-Restricted Subsidiaries (HEP Segment) Consolidations and Eliminations Eliminations Consolidated (In thousands) ASSETS Current assets: Cash and cash equivalents Marketable securities Accounts receivable, net Intercompany accounts receivable Inventories Income taxes receivable Prepayments and other Total current assets Properties, plants and equip, net Marketable securities (long-term) Investment in subsidiaries Intangibles and other assets Total assets LIABILITIES AND EQUITY Current liabilities: Accounts payable Intercompany accounts payable Accrued liabilities Deferred income tax liabilities Total current liabilities Long-term debt Liability to HEP Deferred income tax liabilities Other long-term liabilities Investment in HEP Equity – HollyFrontier Equity – noncontrolling interest Total liabilities and equity $ $ $ $ 1,748,808 630,579 4,788 — — 74,957 21,867 2,480,999 24,209 5,116 5,251,396 11,825 7,773,545 1,941 546,655 71,226 145,225 765,047 460,254 — 530,544 48,757 — 5,968,943 — 7,773,545 $ $ $ $ 3,652 7 627,262 285,291 1,318,373 — 34,667 2,269,252 2,444,398 — 74,120 2,284,329 7,072,099 1,336,097 — 105,298 — 1,441,395 36,311 257,777 — 85,220 — 5,251,396 — 7,072,099 $ $ $ $ 2 — — 261,364 — — — 261,366 — — — 25,000 286,366 $ — $ — — (546,655) — — — (546,655) — — (5,325,516) (25,000) $ (5,897,171) $ — $ — 581 (9) 572 — — 1,175 — 210,499 74,120 — 286,366 — $ (546,655) — — (546,655) (25,000) — — — — (5,325,516) — $ (5,897,171) $ 1,752,462 630,586 632,050 — 1,318,373 74,957 56,534 4,464,962 2,468,607 5,116 — 2,296,154 9,234,839 1,338,038 — 177,105 145,216 1,660,359 471,565 257,777 531,719 133,977 210,499 5,968,943 — 9,234,839 $ $ $ $ 5,237 — 38,097 — 1,259 — 2,360 46,953 1,014,556 — — 365,291 1,426,800 12,030 — 23,705 — 35,735 864,673 — — 28,683 — 382,207 115,502 1,426,800 $ $ $ $ — $ — (35,917) — — — (5,733) (41,650) (288,463) — — (2,529) 1,757,699 630,586 634,230 — 1,319,632 74,957 53,161 4,470,265 3,194,700 5,116 — 2,658,916 (332,642) $ 10,328,997 1,314,151 (35,917) $ — — 195,077 (5,733) 145,216 — 1,654,444 (41,650) 1,336,238 — — (257,777) 536,670 4,951 158,987 (3,673) — (210,499) 6,052,954 (298,196) 474,202 589,704 (332,642) $ 10,328,997 94 Table of Contents HOLLYFRONTIER CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued Condensed Consolidating Statement of Income and Comprehensive Income Year Ended December 31, 2013 Parent Guarantor Restricted Subsidiaries Non- Guarantor Restricted Subsidiaries HollyFrontier Corp. Before Consolidation of HEP Non-Guarantor Non-Restricted Subsidiaries (HEP Segment) Consolidations and Eliminations Eliminations Consolidated Sales and other revenues Operating costs and expenses: Cost of products sold Operating expenses General and administrative Depreciation and amortization Total operating costs and expenses Income (loss) from operations Other income (expense): Earnings (loss) of equity method investments Interest income (expense) Loss on early extinguishment of debt Income before income taxes Income tax provision Net income Less net income attributable to noncontrolling interest Net income attributable to HollyFrontier stockholders Comprehensive income attributable to HollyFrontier stockholders $ 878 $ 20,105,726 $ 153 $ (In thousands) — $ 20,106,757 $ 307,053 $ (253,250) $ 20,160,560 — — 113,231 5,548 17,641,119 995,194 2,752 247,514 118,779 18,886,579 (117,901) 1,219,147 1,280,868 (15,849) (22,109) 1,242,910 1,125,009 391,243 733,766 52,752 8,969 — 61,721 1,280,868 — 1,280,868 — — $ $ 733,766 743,013 $ $ 1,280,868 1,258,370 $ $ — — 231 — 231 (78) — — — — — — 57,186 (1,338,518) — — (1,338,518) (1,338,518) — (1,338,518) 542 — 57,728 57,650 — 57,650 — 17,641,119 995,194 116,214 253,062 19,005,589 1,101,168 52,288 (6,338) (22,109) 23,841 1,125,009 391,243 733,766 — — 57,650 $ (1,338,518) $ 733,766 59,470 $ (1,317,840) $ 743,013 $ $ — 97,081 11,749 64,701 173,531 133,522 2,826 (46,849) — (44,023) 89,499 333 89,166 6,632 82,534 84,354 (248,892) (1,425) — (14,317) 17,392,227 1,090,850 127,963 303,446 (264,634) 18,914,486 11,384 1,246,074 (57,186) (9,307) — (66,493) (55,109) — (55,109) (2,072) (62,494) (22,109) (86,675) 1,159,399 391,576 767,823 25,349 31,981 (80,458) $ 735,842 (82,278) $ 745,089 $ $ Condensed Consolidating Statement of Income and Comprehensive Income Year Ended December 31, 2012 Parent Guarantor Restricted Subsidiaries Non- Guarantor Restricted Subsidiaries HollyFrontier Corp. Before Consolidation of HEP Non-Guarantor Non-Restricted Subsidiaries (HEP Segment) Consolidations and Eliminations Eliminations Consolidated Sales and other revenues Operating costs and expenses: Cost of products sold Operating expenses General and administrative Depreciation and amortization Total operating costs and expenses Income (loss) from operations Other income (expense): Earnings of equity method investments Interest income (expense) Gain on sale of marketable securities Income before income taxes Income tax provision Net income Less net income attributable to noncontrolling interest Net income attributable to HollyFrontier stockholders Comprehensive income attributable to HollyFrontier stockholders $ 494 $ 20,043,335 $ 174 $ (In thousands) — $ 20,044,003 $ 288,501 $ (241,780) $ 20,090,724 — — 118,860 4,172 16,078,948 906,098 1,519 181,735 123,032 17,168,300 (122,538) 2,875,035 2,921,077 (41,564) — 2,879,513 2,756,975 1,027,591 1,729,384 49,347 (3,631) 326 46,042 2,921,077 — 2,921,077 — — $ 1,729,384 $ 2,921,077 $ 1,643,086 $ 2,728,675 $ $ — — 128 — 128 46 — — — — — — 49,066 (2,970,865) — — (2,970,865) (2,970,865) — (2,970,865) 676 — 49,742 49,788 — 49,788 — 16,078,948 906,098 120,507 185,907 17,291,460 2,752,543 48,625 (44,519) 326 4,432 2,756,975 1,027,591 1,729,384 — — 49,788 $ (2,970,865) $ 1,729,384 50,610 $ (2,779,285) $ 1,643,086 $ $ 95 — 89,395 7,594 57,789 154,778 133,723 3,364 (57,219) — (53,855) 79,868 371 79,497 1,153 78,344 79,166 (238,305) (527) — (828) 15,840,643 994,966 128,101 242,868 (239,660) 17,206,578 (2,120) 2,884,146 (49,066) 2,338 — (46,728) (48,848) — (48,848) 2,923 (99,400) 326 (96,151) 2,787,995 1,027,962 1,760,033 31,708 32,861 (80,556) $ 1,727,172 (81,378) $ 1,640,874 $ $ Table of Contents HOLLYFRONTIER CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued Condensed Consolidating Statement of Income and Comprehensive Income Year Ended December 31, 2011 Parent Guarantor Restricted Subsidiaries Non- Guarantor Restricted Subsidiaries HollyFrontier Corp. Before Consolidation of HEP Non-Guarantor Non-Restricted Subsidiaries (HEP Segment) Consolidations and Eliminations Eliminations Consolidated $ 1,008 $ 15,392,446 $ 74 $ (In thousands) — $ 15,393,528 $ 212,995 $ (166,995) $ 15,439,528 Sales and other revenues Operating costs and expenses: Cost of products sold Operating expenses General and administrative Depreciation and amortization — — 111,093 4,165 12,844,333 687,381 2,445 123,082 Total operating costs and expenses 115,258 13,657,241 Income (loss) from operations Other income (expense): Earnings of equity method investments Interest income (expense) Merger transaction costs Income before income taxes Income tax provision Net income Less net income attributable to noncontrolling interest Net income attributable to HollyFrontier stockholders Comprehensive income attributable to HollyFrontier stockholders (114,250) 1,735,205 1,771,022 (38,619) (15,114) 1,717,289 1,603,039 581,757 1,021,282 38,546 (2,729) — 35,817 1,771,022 — 1,771,022 — — $ 1,021,282 $ 1,771,022 $ 1,125,163 $ 1,945,142 $ $ — (362) — — (362) 436 38,308 54 — 38,362 38,798 — 38,798 — — — — — — — (1,809,820) — — (1,809,820) (1,809,820) — (1,809,820) 12,844,333 687,019 113,538 127,247 13,772,137 1,621,391 38,056 (41,294) (15,114) (18,352) 1,603,039 581,757 1,021,282 — 63,029 6,576 33,288 102,893 110,102 2,552 (38,209) — (35,657) 74,445 234 74,211 (164,255) (1,967) — (828) 12,680,078 748,081 120,114 159,707 (167,050) 13,707,980 55 1,731,548 (38,308) 2,464 — (35,844) (35,789) — (35,789) 2,300 (77,039) (15,114) (89,853) 1,641,695 581,991 1,059,704 — — (859) 37,166 36,307 38,798 $ (1,809,820) $ 1,021,282 39,544 $ (1,984,686) $ 1,125,163 $ $ 75,070 75,816 $ $ (72,955) $ 1,023,397 (73,701) $ 1,127,278 96 Table of Contents HOLLYFRONTIER CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2013 Parent Guarantor Restricted Subsidiaries Non- Guarantor Restricted Subsidiaries HollyFrontier Corp. Before Consolidation of HEP Non-Guarantor Non-Restricted Subsidiaries (HEP Segment) Consolidations and Eliminations Eliminations Consolidated (In thousands) $ 448,297 $ 1,044,492 $ 70,977 $ (805,981) $ 757,785 $ 182,799 $ (71,410) $ 869,174 Cash flows from operating activities (1) Cash flow from investing activities Additions to properties, plants and equipment Additions to properties, plants and equipment – HEP Acquisition of trucking operations Proceeds from sale of property and equipment Investment in Sabine Biofuels Net advances to Sabine Biofuels Purchases of marketable securities Sales and maturities of marketable securities Net intercompany advances (1) Cash flows from financing activities Net repayments under credit agreement – HEP Redemption of senior notes Proceeds from common unit offerings - HEP Purchase of treasury stock Contribution from general partner Dividends Distributions to noncontrolling interest Excess tax benefit from equity- based compensation Purchase of units for incentive grants - HEP Deferred financing costs and other Net repayment of intercompany advances (1) Distributions to Parent (1) Cash and cash equivalents Increase (decrease) for the period Beginning of period End of period (11,727) (361,520) (24) (373,271) — — (51,856) — — — — — — — — — (11,301) 5,071 (3,000) (5,740) — 8 — — — — — — — 137,613 (238,869) (69,442) (69,466) (68,171) (68,171) — — — — — — — — — (1,477) — (805,981) (807,458) — — — — (1,499) — — — — — — — (1,499) — — — — — — — — — — 68,171 805,981 874,152 — — — — — (935,512) 846,135 — (101,104) — (300,973) 73,444 (225,023) — (645,920) — 2,562 — — (68,171) — (1,164,081) (11,301) 5,071 (3,000) (5,740) (935,512) 846,143 — (477,610) — (300,973) 73,444 (225,023) (1,499) (645,920) — 2,562 — (1,477) — — (1,098,886) — — — — — — — — — — — — — — — — (373,271) (51,856) (11,301) 7,802 (3,000) (5,740) (935,512) 846,143 — (526,735) (58,000) (300,973) 146,888 (225,023) — (645,920) — 2,731 — — — — — (49,125) (58,000) — 73,444 — 1,499 — (142,611) 71,410 (71,201) — (5,313) (1,578) — — (132,559) — — — — 2,562 (5,313) (3,055) — — 71,410 — (1,160,035) (816,888) 1,748,808 $ 931,920 $ (1,835) 3,652 1,817 $ 12 2 14 $ — — — $ (818,711) 1,752,462 933,751 $ 1,115 5,237 6,352 $ — (817,596) — — $ 1,757,699 940,103 (1) Parent operating cash flows includes cash inflows of $806.0 million, $2,727.6 million and $2,147.0 million for the years ended December 31, 2013, 2012 and 2011, respectively, representing distributions of earnings from the Restricted Subsidiaries. 97 Table of Contents HOLLYFRONTIER CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2012 Parent Guarantor Restricted Subsidiaries Non- Guarantor Restricted Subsidiaries HollyFrontier Corp. Before Consolidation of HEP Non-Guarantor Non-Restricted Subsidiaries (HEP Segment) Consolidations and Eliminations Eliminations Consolidated (In thousands) $1,571,928 $ 2,656,514 $ 63,759 $ (2,727,561) $ 1,564,640 $ 162,036 $ (63,989) $ 1,662,687 Cash flows from operating activities (1) Cash flows from investing activities: Additions to properties, plants and equipment Additions to properties, plants and equipment – HEP Investment in Sabine Biofuels Purchases of marketable securities Payments received on promissory notes Sales and maturities of marketable securities Net intercompany advances (1) Cash flows from financing activities: Net borrowings under credit agreement – HEP Net proceeds from issuance of senior notes - HEP Redemption of senior notes Principal tender on senior notes Purchase of treasury stock Structured stock repurchase arrangement Contribution from general partner Contribution from joint venture partner Distribution from HEP upon UNEV transfer Dividends Distributions to noncontrolling interest Excess tax benefit from equity- based compensation Purchase of units for incentive grants - HEP Deferred financing costs and other Net receipt of intercompany advances (1) Distributions to Parent (1) Cash and cash equivalents Increase (decrease) for the period: Beginning of period End of period (7,965) (282,369) — — — (2,000) — — 931 101,943 (181,495) — — — — — — — — 260,922 — — — — (1,370) — (671,552) — 296,780 — (382,737) — — (205,000) — (209,600) 8,620 — — — (658,085) — 23,361 — — 24,430 — (1,016,274) — — — — 72,900 — (126,373) (53,473) — — — — — — (10,286) — — — — — — — — — — — — — — 24,430 24,430 — — — — — — — — — — — — — — (24,430) 2,727,561 2,703,131 (290,334) — — (2,000) (671,552) (44,929) — — 72,900 (72,900) 297,711 — (593,275) — — (205,000) — (209,600) 8,620 (10,286) — 260,922 (658,085) — — (117,829) 221,000 294,750 — (185,000) — — 10,286 6,000 (260,922) — — — — — — — — — — — — — — — — — — — (290,334) (44,929) (2,000) (671,552) — 297,711 — (711,104) 221,000 294,750 (205,000) (185,000) (209,600) 8,620 — 6,000 — (658,085) — (122,777) 63,989 (58,788) 23,361 — (1,370) — — (791,438) — (5,240) (3,436) — — (45,339) — — — — — 63,989 23,361 (5,240) (4,806) — — (772,788) (2,727,561) (2,468,009) — (10,286) 172,917 1,575,891 $1,748,808 $ 7,010 (3,358) 3,652 $ — 2 2 $ — — — $ 179,927 1,572,535 1,752,462 $ (1,132) 6,369 5,237 $ — 178,795 — — $ 1,578,904 1,757,699 98 Table of Contents HOLLYFRONTIER CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2011 Parent Guarantor Restricted Subsidiaries Non- Guarantor Restricted Subsidiaries HollyFrontier Corp. Before Consolidation of HEP Non-Guarantor Non-Restricted Subsidiaries (HEP Segment) Consolidations and Eliminations Eliminations Consolidated (In thousands) $2,275,784 $ 1,099,072 $ 41,866 $ (2,147,006) $ 1,269,716 $ 108,948 $ (40,273) $ 1,338,391 Cash flows from operating activities (1) Cash flows from investing activities: Additions to properties, plants and equipment Additions to properties, plants and equipment – HEP Increase in cash due to merger with Frontier Investment in Sabine Biofuels Payments received on promissory notes Purchases of marketable securities Sales and maturities of marketable securities Net intercompany advances (1) Cash flows from financing activities: Net borrowings under credit agreement – HEP Proceeds from issuance of common units – HEP Purchase of treasury stock Redemptions of senior notes Contribution from general partner Contribution from joint venture partner Dividends Distributions to noncontrolling interest Excess tax benefit from equity- based compensation Purchase of units for restricted grants - HEP Deferred financing costs and other Net repayment of intercompany advances (1) Distributions to Parent (1) Cash and cash equivalents Increase (decrease) for the period: Beginning of period End of period (7,585) (150,441) — — — — 77,100 — — — — — — — — — — 872,557 — — — — 332,655 1,054,771 9,921 87,021 (342,576) (342,576) — — — — — — — — — — — — — — (128,887) — — — — — — — — — — — — — — — — — — 342,576 2,147,006 2,489,582 (8,665) (1,160) (2,147,006) (2,148,166) — (128,887) — 182 (9,125) — (561,899) 301,020 — (277,407) — — (42,795) (8,203) — — (252,133) — 1,804 — (342,576) — (652,568) (158,026) — — (216,215) 872,739 (9,125) — — 77,100 (77,100) (561,899) 301,020 — 521,809 — — (42,795) (8,203) — — — (293,315) 41,000 75,815 — — (128,887) 128,887 — (252,133) 33,500 — — — — — — — — — — — — — — — — — (158,026) (216,215) 872,739 (9,125) — (561,899) 301,020 — 228,494 41,000 75,815 (42,795) (8,203) — 33,500 (252,133) — 1,804 — (9,825) — — (440,039) (91,506) 40,632 (50,874) — (1,641) (3,371) — — 182,684 — — 1,804 (1,641) (359) (13,555) — — 40,273 — — (217,082) 1,345,809 230,082 $1,575,891 $ 5,677 (9,035) (3,358) $ — 2 2 $ — — — $ 1,351,486 221,049 1,572,535 $ (1,683) 8,052 6,369 $ — — — $ 1,349,803 229,101 1,578,904 99 Table of Contents HOLLYFRONTIER CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued NOTE 22: Significant Customers All revenues are domestic revenues, except for refining segment sales of gasoline and diesel fuel for export into Mexico. We have two significant customers (Sinclair and Shell Oil), each of which has historically accounted for 10% or more of our annual revenues. Sinclair accounted for $2,134.3 million (11%), $2,106.6 million (10%) and $2,035.1 million (13%) of our revenues for the years ended December 31, 2013, 2012 and 2011, respectively, and Shell Oil accounted for $1,830.5 million (9%), $2,323.6 million (12%) and $1,540.6 million (10%) for the years ended December 31, 2013, 2012 and 2011, respectively. Our export sales were to an affiliate of PEMEX and accounted for $310.0 million (2%), $429.4 million (2%) and $370.0 million (2%) of our revenues for the years ended December 31, 2013, 2012 and 2011, respectively. NOTE 23: Quarterly Information (Unaudited) $ $ $ $ $ $ $ $ $ $ $ $ Year Ended December 31, 2013 Sales and other revenues Operating costs and expenses Income from operations Income before income taxes Net income attributable to HollyFrontier stockholders Net income per share attributable to HollyFrontier stockholders - basic Net income per share attributable to HollyFrontier stockholders - diluted $ $ Dividends per common share Average number of shares of common stock outstanding: Basic Diluted Year Ended December 31, 2012 Sales and other revenues Operating costs and expenses Income from operations Income before income taxes Net income attributable to HollyFrontier stockholders Net income per share attributable to HollyFrontier stockholders - basic Net income per share attributable to HollyFrontier stockholders - diluted $ $ Dividends per common share Average number of shares of common stock outstanding: Basic Diluted First Quarter 4,707,789 4,158,594 549,195 529,465 333,669 1.64 1.63 0.80 202,726 203,428 4,931,738 4,512,174 419,564 387,426 241,696 1.16 1.16 0.60 Second Quarter Third Quarter (In thousands, except per share data) Fourth Quarter Year $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ 5,298,848 4,838,842 460,006 417,792 256,981 1.27 1.27 0.80 201,543 201,905 4,806,681 3,993,544 813,137 788,088 493,499 2.40 2.39 0.65 $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ 5,327,122 5,177,372 149,750 137,437 82,290 0.41 0.41 0.80 199,098 199,509 5,204,798 4,226,494 978,304 960,272 600,373 2.95 2.94 1.15 $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ 4,826,801 4,739,678 87,123 74,705 $ 20,160,560 $ 18,914,486 1,246,074 $ 1,159,399 $ 62,902 0.32 0.31 0.80 $ $ $ $ 735,842 3.66 3.64 3.20 198,371 199,311 200,419 201,234 5,147,507 4,474,366 673,141 652,209 $ 20,090,724 $ 17,206,578 2,884,146 $ 2,787,995 $ 391,604 1.92 1.92 0.70 $ $ $ $ 1,727,172 8.41 8.38 3.10 207,681 208,288 204,787 205,541 202,655 203,532 202,480 203,498 204,379 205,274 100 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure We have had no change in, or disagreement with, our independent registered public accountants on matters involving accounting and financial disclosure. Item 9A. Controls and Procedures Evaluation of disclosure controls and procedures. Our principal executive officer and principal financial officer have evaluated, as required by Rule 13a-15(b) under the Securities Exchange Act of 1934 (the “Exchange Act”), our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e)) under the Exchange Act as of the end of the period covered by this annual report on Form 10-K. Our disclosure controls and procedures are designed to provide reasonable assurance that the information we are required to disclose in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's rules and forms. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of December 31, 2013. Changes in internal control over financial reporting. There have been no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during our last fiscal quarter that have materially affected or are reasonably likely to materially affect our internal control over financial reporting. See Item 8 for “Management's Report on its Assessment of the Company's Internal Control Over Financial Reporting” and “Report of the Independent Registered Public Accounting Firm.” Item 9B. Other Information There have been no events that occurred in the fourth quarter of 2013 that would need to be reported on Form 8-K that have not previously been reported. Item 10. Directors, Executive Officers and Corporate Governance PART III The information required by Items 401, 405, 406 and 407(c)(3), (d)(4) and (d)(5) of Regulation S-K in response to this item will be set forth in our definitive proxy statement for the annual meeting of stockholders to be held on May 14, 2014 and is incorporated herein by reference. Item 11. Executive Compensation The information required by Items 402 and 407(e)(4) and (e)(5) of Regulation S-K in response to this item will be set forth in our definitive proxy statement for the annual meeting of stockholders to be held on May 14, 2014 and is incorporated herein by reference. Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters The equity compensation plan information required by Item 201(d) and the information required by Item 403 of Regulation S-K in response to this item will be set forth in our definitive proxy statement for the annual meeting of stockholders to be held on May 14, 2014 and is incorporated herein by reference. 101 Table of Content Item 13. Certain Relationships and Related Transactions, and Director Independence The information required by Items 404 and 407(a) of Regulation S-K in response to this item will be set forth in our definitive proxy statement for the annual meeting of stockholders to be held on May 14, 2014 and is incorporated herein by reference. Item 14. Principal Accounting Fees and Services The information required by Item 9(e) of Schedule 14A in response to this item will be set forth in our definitive proxy statement for the annual meeting of stockholders to be held on May 14, 2014 and is incorporated herein by reference. PART IV Item 15. Exhibits, Financial Statement Schedules (a) Documents filed as part of this report (1) Index to Consolidated Financial Statements Report of Independent Registered Public Accounting Firm Consolidated Balance Sheets at December 31, 2013 and 2012 Consolidated Statements of Income for the years ended December 31, 2013, 2012 and 2011 Consolidated Statements of Comprehensive Income for the years ended December 31, 2013, 2012 and 2011 Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011 Consolidated Statements of Equity for the years ended December 31, 2013, 2012 and 2011 Notes to Consolidated Financial Statements (2) Index to Consolidated Financial Statement Schedules Page in Form 10-K 57 58 59 60 61 62 63 All schedules are omitted since the required information is not present or is not present in amounts sufficient to require submission of the schedule, or because the information required is included in the consolidated financial statements or notes thereto. (3) Exhibits The Exhibit Index on pages 105 to 112 of this Annual Report on Form 10-K lists the exhibits that are filed or furnished, as applicable, as part of this Annual Report on Form 10-K. 102 Table of Content Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. SIGNATURES Date: February 25, 2014 HOLLYFRONTIER CORPORATION (Registrant) /s/ Michael C. Jennings Michael C. Jennings Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and as of the date indicated. Signature Capacity Date /s/ Michael C. Jennings Chairman of the Board, Chief February 25, 2014 Michael C. Jennings Executive Officer and President /s/ Douglas S. Aron Douglas S. Aron /s/ J.W. Gann, Jr. J.W. Gann, Jr. Executive Vice President and February 25, 2014 Chief Financial Officer (Principal Financial Officer) Vice President, Controller and February 25, 2014 Chief Accounting Officer (Principal Accounting Officer) /s/ Denise C. McWatters Senior Vice President, General February 25, 2014 Denise C. McWatters Counsel and Secretary /s/ Douglas Y. Bech Douglas Y. Bech /s/ Buford P. Berry Buford P. Berry /s/ Leldon Echols Leldon Echols /s/ R. Kevin Hardage R. Kevin Hardage Director Director Director Director February 25, 2014 February 25, 2014 February 25, 2014 February 25, 2014 /s/ Robert J. Kostelnik Director February 25, 2014 Robert J. Kostelnik /s/ James H. Lee James H. Lee Director February 25, 2014 /s/ Robert G. McKenzie Director February 25, 2014 Robert G. McKenzie 103 Table of Content Signature Capacity Date /s/ Franklin Myers Franklin Myers /s/ Michael E. Rose Michael E. Rose Director Director February 25, 2014 February 25, 2014 /s/ Tommy A. Valenta Director February 25, 2014 Tommy A. Valenta 104 Table of Content Exhibit Number Description HOLLYFRONTIER CORPORATION INDEX TO EXHIBITS Exhibits are numbered to correspond to the exhibit table in Item 601 of Regulation S-K 2.1 2.2 2.3 2.4 3.1 3.2 4.1 4.2 4.3 4.4 4.5 4.6 4.7 4.8 Asset Sale and Purchase Agreement, dated October 19, 2009, between Holly Refining & Marketing-Tulsa LLC, HEP Tulsa LLC and Sinclair Tulsa Refining Company (incorporated by reference to Exhibit 2.1 of Registrant's Current Report on Form 8-K filed October 21, 2009, File No. 1-03876). Amendment No. 1 to Asset Sale and Purchase Agreement, dated December 1, 2009, between Holly Refining & Marketing-Tulsa LLC, HEP Tulsa LLC and Sinclair Tulsa Refining Company (incorporated by reference to Exhibit 2.1 of Registrant's Current Report on Form 8-K filed December 7, 2009, File No. 1-03876). Asset Sale and Purchase Agreement, dated April 15, 2009, between Holly Refining & Marketing-Midcon, L.L.C. and Sunoco, Inc. (incorporated by reference to Exhibit 2.1 of Registrant's Current Report on Form 8-K filed April 16, 2009, File No. 1-03876). Agreement and Plan of Merger among Holly Corporation, North Acquisition, Inc. and Frontier Oil Corporation, dated February 21, 2011 (incorporated by reference to Exhibit 2.1 of Registrant's Current Report on Form 8-K filed February 22, 2011, File No. 1-03876). Amended and Restated Certificate of Incorporation of HollyFrontier Corporation (incorporated by reference to Exhibit 3.1 of Registrant's Current Report on Form 8-K filed July 8, 2011, File No. 1-03876). Amended and Restated Bylaws of HollyFrontier Corporation (incorporated by reference to Exhibit 3.1 of Registrant's Current Report on Form 8-K filed February 20, 2014, File No. 1-03876). Indenture, dated June 10, 2009, among Holly Corporation, the Guarantors and U.S. Bank Trust National Association, providing for the issuance of 9.875% Senior Notes due 2017 (includes the form of certificate for the notes issued thereunder) (incorporated by reference to Exhibit 4.1 of Registrant's Current Report on Form 8-K filed June 11, 2009, File No. 1-03876). First Supplemental Indenture, dated June 14, 2011, among Holly Corporation, the Guarantors and U.S. Bank Trust National Association (incorporated by reference to Exhibit 4.1 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011, File No. 1-03876). Second Supplemental Indenture, dated July 18, 2011, among HollyFrontier Corporation, the Guarantors and U.S. Bank Trust National Association (incorporated by reference to Exhibit 4.11 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2011, File No. 1-03876). Indenture, dated March 10, 2010, among Holly Energy Partners, L.P., Holly Energy Finance Corp., the Guarantors and U.S. Bank National Association, providing for the issuance of 8.25% Senior Notes due 2018 (incorporated by reference to Exhibit 4.1 of Holly Energy Partners, L.P.'s Current Report on Form 8-K filed March 11, 2010, File No. 1-32225). First Supplemental Indenture, dated April 14, 2010, among Holly Energy Storage-Tulsa LLC, Holly Energy Storage- Lovington LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.3 of Holly Energy Partners, L.P.'s Quarterly Report on Form 10- Q for the quarterly period ended June 30, 2010, File No. 1-32225). Second Supplemental Indenture, dated June 4, 2010, among HEP Operations LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.4 of Holly Energy Partners, L.P.'s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2010, File No. 1-32225). Third Supplemental Indenture, dated December 29, 2011, among Cheyenne Logistics LLC, El Dorado Logistics LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.16 of Holly Energy Partners, L.P.'s Annual Report on Form 10-K for its fiscal year ended December 31, 2011, File No. 1-32225). Fourth Supplemental Indenture, dated August 6, 2012, among HEP UNEV Holdings LLC, HEP UNEV Pipeline LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.1 to Registrant's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2012, File No. 1-03876). 105 Table of Content Exhibit Number Description 4.9 4.10 4.11 4.12 4.13 4.14 4.15 10.1 10.2 10.3 10.4 10.5 10.6 Indenture, dated November 22, 2010, among HollyFrontier Corporation (as successor-in-interest to Frontier Oil Corporation), the Guarantors and Wells Fargo Bank, National Association, providing for the issuance of 6 7/8% Senior Notes due 2018 (incorporated by reference to Exhibit 4.1 of Frontier Oil Corporation's Current Report on Form 8-K filed November 22, 2010, File Number 1-07627). First Supplemental Indenture, dated November 22, 2010, among HollyFrontier Corporation (as successor-in-interest to Frontier Oil Corporation), the Guarantors and Wells Fargo Bank, National Association (incorporated by reference to Exhibit 4.2 of Frontier Oil Corporation's Current Report on Form 8-K filed November 22, 2010, File Number 1-07627). Second Supplement Indenture, dated May 26, 2011, among HollyFrontier Corporation (as successor-in-interest to Frontier Oil Corporation), the Guarantors and Wells Fargo Bank, National Association (incorporated by reference to Exhibit 4.2 of Frontier Oil Corporation's Current Report on Form 8-K filed May 27, 2011, File No. 1-07627). Third Supplemental Indenture, dated July 1, 2011, among HollyFrontier Corporation (as successor-in-interest to Frontier Oil Corporation), the Guarantors and Wells Fargo Bank, National Association (incorporated by reference to Exhibit 4.1 of Registrant's Current Report on Form 8-K filed July 8, 2011, File No. 1-03876). Form of 6 7/8% Senior Note Due 2018 (incorporated by reference to Exhibit 4.3 of Frontier Oil Corporation's Current Report on form 8-K filed November 22, 2010, file Number 1-07627). Indenture, dated March 12, 2012, among Holly Energy Partners, L.P., Holly Energy Finance Corp., the Guarantors and U.S. Bank National Association, providing for the issuance of 6.50% Senior Notes due 2020 (incorporated by reference to Exhibit 4.1 of Holly Energy Partners, L.P.'s Current Report on Form 8-K filed March 12, 2012, File No. 1-32225). First Supplemental Indenture, dated August 6, 2012, among HEP UNEV Holdings LLC, HEP UNEV Pipeline LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.2 of the Registrant's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2012, File No. 1-03876). Amended and Restated Intermediate Pipelines Agreement, dated June 1, 2009, among Holly Corporation, Navajo Refining Company, L.L.C, Holly Energy Partners, L.P., Holly Energy Partners – Operating, L.P., HEP Pipeline, L.L.C., Lovington-Artesia, L.L.C., HEP Logistics Holdings, L.P., Holly Logistics Services, L.L.C. and HEP Logistics GP, L.L.C. (incorporated by reference to Exhibit 10.2 of Holly Energy Partners, L.P.'s Current Report on Form 8-K filed June 5, 2009, File No. 1-32225). Amendment to Amended and Restated Intermediate Pipelines Agreement, dated December 9, 2010, among Navajo Refining Company, L.L.C, Holly Energy Partners, L.P., Holly Energy Partners – Operating, L.P., HEP Pipeline, L.L.C., Lovington-Artesia, L.L.C., HEP Logistics Holdings, L.P., Holly Logistics Services, L.L.C. and HEP Logistics GP, L.L.C. (incorporated by reference to Exhibit 10.4 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2010, File No. 1-03876). Assignment and Assumption Agreement (Amended and Restated Intermediate Pipelines Agreement), effective January 1, 2011, between Navajo Refining Company, L.L.C. and Holly Refining & Marketing Company LLC (incorporated by reference to Exhibit 10.5 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2010, File No. 1-03876). Tulsa Equipment and Throughput Agreement, dated August 1, 2009, between Holly Refining & Marketing - Tulsa LLC and HEP Tulsa LLC (incorporated by reference to Exhibit 10.3 of Holly Energy Partners L.P.'s Current Report on Form 8-K filed August 6, 2009, File No. 1-32225). Amendment to Tulsa Equipment and Throughput Agreement, dated December 9, 2010, among Holly Refining & Marketing - Tulsa LLC and HEP Tulsa LLC (incorporated by reference to Exhibit 10.7 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2010, File No. 1-03876). Assignment and Assumption Agreement (Tulsa Equipment and Throughput Agreement), effective January 1, 2011, between Holly Refining & Marketing - Tulsa, LLC and Holly Refining & Marketing Company LLC (incorporated by reference to Exhibit 10.8 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2010, File No. 1-03876). 106 Table of Content Exhibit Number 10.7 10.8 10.9 10.10 10.11 10.12 10.13 Description Tulsa Purchase Option Agreement, dated August 1, 2009, between Holly Refining & Marketing - Tulsa LLC and HEP Tulsa LLC (incorporated by reference to Exhibit 10.4 of Holly Energy Partners L.P.'s Current Report on Form 8-K filed August 6, 2009, File No. 1-32225). Amended and Restated Crude Pipelines and Tankage Agreement, dated December 1, 2009, among Navajo Refining Company, L.L.C., Holly Refining & Marketing Company - Woods Cross, Holly Refining & Marketing Company, Holly Energy Partners - Operating, L.P., HEP Pipeline, L.L.C. and HEP Woods Cross, L.L.C. (incorporated by reference to Exhibit 10.8 of Holly Energy Partners, L.P.'s Current Report on Form 8-K filed December 7, 2009, File No. 1-32225). Letter Agreement, dated October 14, 2011, regarding the Amended and Restated Crude Pipelines and Tankage Agreement, dated December 1, 2009 (incorporated by reference to Exhibit 10.14 of the Registrant's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2011, File No. 1-03876). Second Amended and Restated Crude Pipelines and Tankage Agreement, dated July 16, 2013, among Navajo Refining Company, L.L.C., Holly Refining & Marketing Company - Woods Cross LLC, HollyFrontier Refining & Marketing LLC, Holly Energy Partners-Operating, L.P., HEP Pipeline, LLC and HEP Woods Cross, L.L.C. (incorporated by reference to Exhibit 10.3 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2013, File No. 1-03876). Amended and Restated Refined Product Pipelines and Terminals Agreement, dated December 1, 2009, among Navajo Refining Company, L.L.C., Holly Refining & Marketing Company - Woods Cross, Holly Energy Partners - Operating, L.P., HEP Pipeline Assets, Limited Partnership, HEP Pipeline, L.L.C., HEP Refining Assets, L.P., HEP Refining, L.L.C., HEP Mountain Home, L.L.C. and HEP Woods Cross, L.L.C. (incorporated by reference to Exhibit 10.9 of Holly Energy Partners, L.P.'s Current Report on Form 8-K filed December 7, 2009, File No. 1-32225). Assignment and Assumption Agreement (Amended and Restated Refined Product Pipelines and Terminals Agreement), effective January 1, 2011, among Navajo Refining Company, L.L.C., Holly Refining & Marketing - Woods Cross and Holly Refining & Marketing Company LLC (incorporated by reference to Exhibit 10.12 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2010, File No. 1-03876). Second Amended and Restated Throughput Agreement (Tucson Terminal), dated September 19, 2013, effective June 1, 2013, among HollyFrontier Refining & Marketing LLC, HEP Refining, L.L.C. and Holly Energy Partners - Operating, L.P. (incorporated by reference to Exhibit 10.5 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2013, File No. 1-03876). 10.14* First Amendment to Amended and Restated Refined Product Pipelines and Terminals Agreement, dated November 7, 2013, effective September 30, 2013, among HollyFrontier Refining & Marketing LLC (formerly Holly Refining & Marketing LLC), Holly Energy Partners - Operating, L.P., HEP Pipeline Assets, Limited Partnership, HEP Pipeline, L.L.C., HEP Refining Assets, L.P., HEP Refining L.L.C., HEP Mountain Home, L.L.C. and HEP Woods Cross, L.L.C. 10.15 10.16 10.17 10.18 10.19 10.20 Pipeline Throughput Agreement (Roadrunner), dated December 1, 2009, between Navajo Refining Company, L.L.C. and Holly Energy Partners - Operating, L.P. (incorporated by reference to Exhibit 10.4 of Holly Energy Partners, L.P.'s Current Report on Form 8-K filed December 7, 2009, File No. 1-32225). Assignment and Assumption Agreement (Pipeline Throughput Agreement (Roadrunner)), effective January 1, 2011, between Navajo Refining Company, L.L.C. and Holly Refining & Marketing Company LLC (incorporated by reference to Exhibit 10.14 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2010, File No. 1-03876). Assignment and Assumption Agreement (First Amended and Restated Pipelines, Tankage and Loading Rack Throughput Agreement (Tulsa East)), effective January 1, 2011, between Holly Refining & Marketing - Tulsa LLC and Holly Refining & Marketing Company LLC (incorporated by reference to Exhibit 10.17 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2010, File No. 1-03876). Second Amended and Restated Pipelines, Tankage and Loading Rack Throughput Agreement, dated August 31, 2011, between Holly Refining & Marketing - Tulsa LLC, HEP Tulsa LLC and Holly Energy Storage - Tulsa LLC (incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed September 1, 2011, File No. 1-03876). Indemnification Proceeds and Payments Allocation Agreement, dated December 1, 2009, between HEP Tulsa LLC and Holly Refining & Marketing - Tulsa LLC (incorporated by reference to Exhibit 10.2 of Registrant's Current Report on Form 8-K filed December 7, 2009, File No. 1-03876). Pipeline Systems Operating Agreement, dated February 8, 2010, among Navajo Refining Company, L.L.C., Lea Refining Company, Woods Cross Refining Company, L.L.C., Holly Refining & Marketing - Tulsa LLC and Holly Energy Partners - Operating, L.P. (incorporated by reference to Exhibit 10.1 of Holly Energy Partners, L.P.'s Current Report on Form 8-K filed February 9, 2010, File No. 1-32225). 107 Table of Content Exhibit Number 10.21 10.22 10.23 10.24 10.25 10.26 10.27 10.28 10.29 10.30 10.31 Description First Amendment to Pipeline Systems Operating Agreement, dated March 31, 2010, among Navajo Refining Company, L.L.C., Lea Refining Company, Woods Cross Refining Company, L.L.C., Holly Refining & Marketing - Tulsa LLC and Holly Energy Partners - Operating, L.P. (incorporated by reference to Exhibit 10.5 of Registrant's Current Report on Form 8-K filed April 6, 2010, File No. 1-03876). Loading Rack Throughput Agreement (Lovington), dated March 31, 2010, between Navajo Refining Company, L.L.C. and Holly Energy Storage-Lovington LLC (incorporated by reference to Exhibit 10.2 of Registrant's Current Report on Form 8-K filed April 6, 2010, File No. 1-03876). First Amended and Restated Lease and Access Agreement (East Tulsa), dated March 31, 2010, among Holly Refining & Marketing-Tulsa, HEP Tulsa LLC and Holly Energy Storage-Tulsa LLC (incorporated by reference to Exhibit 10.4 of Registrant's Current Report on Form 8-K filed April 6, 2010, File No. 1-03876). LLC Interest Purchase Agreement, dated November 9, 2011, among HollyFrontier Corporation, Frontier Refining LLC, Frontier El Dorado Refining LLC, Holly Energy Partners-Operating, L.P. and Holly Energy Partners, L.P. (incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed November 10, 2011, File No. 1-03876). First Amended and Restated Tankage, Loading Rack and Crude Oil Receiving Throughput Agreement (Cheyenne), dated November 11, 2011, between Frontier Refining LLC and Cheyenne Logistics LLC (incorporated by reference to Exhibit 10.26 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2011, File No. 1-03876). First Amended and Restated Pipeline Delivery, Tankage and Loading Rack Throughput Agreement (El Dorado), dated November 11, 2011, between Frontier El Dorado Refining LLC and El Dorado Logistics LLC (incorporated by reference to Exhibit 10.27 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2011, File No. 1-03876). Second Amended and Restated Pipeline Delivery, Tankage and Loading Rack Throughput Agreement (El Dorado), dated January 7, 2014, between Frontier El Dorado Refining LLC and El Dorado Logistics LLC (incorporated by reference to Exhibit 10.1 to Registrant's Current Report on Form 8-K filed January 13, 2014, File No. 1-03876). Seventh Amended and Restated Omnibus Agreement, dated July 12, 2012, among HollyFrontier Corporation, Holly Energy Partners, L.P. and certain of their respective subsidiaries (incorporated by reference to Exhibit 10.3 to the Registrant's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2012, File No. 1-03876). Eighth Amended and Restated Omnibus Agreement, dated July 16, 2013, among HollyFrontier Corporation, Holly Energy Partners, L.P. and certain of their respective subsidiaries (incorporated by reference to Exhibit 10.2 of Registrant's Current Report on Form 8-K filed July 22, 2013, File No. 1-03876). Ninth Amended and Restated Omnibus Agreement, dated January 7, 2014, among HollyFrontier Corporation, Holly Energy Partners, L.P. and certain of their respective subsidiaries (incorporated by reference to Exhibit 10.2 of Registrant's Current Report on Form 8-K filed January 13, 2014, File No. 1-03876). Lease and Access Agreement (Cheyenne), dated November 9, 2011, between Frontier Refining LLC and Cheyenne Logistics LLC (incorporated by reference to Exhibit 10.5 of Registrant's Current Report on Form 8-K filed November 10, 2011, File No. 1-03876). 10.32* First Amendment to Lease and Access Agreement (Cheyenne), effective June 5, 2012, between Frontier Refining LLC and Cheyenne Logistics LLC. 10.33 Lease and Access Agreement (El Dorado), dated November 9, 2011, between Frontier El Dorado Refining LLC and El Dorado Logistics LLC (incorporated by reference to Exhibit 10.6 of Registrant's Current Report on Form 8-K filed November 10, 2011, File No. 1-03876). 10.34* First Amendment to Lease and Access Agreement ( El Dorado), effective August 15, 2012, between Frontier El Dorado Refining LLC and El Dorado Logistics LLC. 10.35* Second Amendment to Lease and Access Agreement ( El Dorado), effective December 5, 2012, between Frontier El Dorado Refining LLC and El Dorado Logistics LLC. 10.36* Third Amendment to Lease and Access Agreement ( El Dorado), dated January 7, 2014, between Frontier El Dorado Refining LLC and El Dorado Logistics LLC. 108 Table of Content Exhibit Number 10.37 10.38 10.39 10.40 10.41 10.42 10.43 Description Credit Agreement, dated July 1, 2011, among HollyFrontier Corporation and certain of its subsidiaries, as borrowers, Union Bank, N.A., as administrative agent and certain lenders from time to time party thereto (incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed July 8, 2011, File No. 1-03876). First Amendment to Credit Agreement, dated August 24, 2011, among HollyFrontier Corporation and certain of its subsidiaries, as borrowers, Union Bank, N.A, as administrative agent and certain lenders from time to time party thereto (incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed August 30, 2011, File No. 1-03876). Second Amendment to Credit Agreement and First Amendment to Guarantee and Collateral Agreement, dated March 19, 2013, among HollyFrontier Corporation and certain of its subsidiaries, as borrowers, Union Bank, N.A., as administrative agent and certain lenders from time to time party thereto (incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed March 21, 2013, File No. 1-03876). Guarantee and Collateral Agreement, dated July 1, 2011, among HollyFrontier Corporation and certain of its subsidiaries in favor of Union Bank, N.A., as administrative agent (incorporated by reference to Exhibit 10.2 of Registrant's Current Report on Form 8-K filed July 8, 2011, File No. 1-03876). Frontier Products Offtake Agreement El Dorado Refinery, dated October 19, 1999, between Frontier Oil and Refining Company and Equiva Trading Company (now Shell Oil Products US, assignee of Equiva Trading Company) (“the Agreement”) and First Amendment to the Agreement dated September 18, 2000, Second Amendment to the Agreement dated September 21, 2000, Third Amendment to the Agreement dated December 19, 2000, Fourth Amendment to the Agreement dated February 22, 2001, Fifth Amendment to the Agreement dated August 14, 2001, Sixth Amendment to the Agreement dated November 5, 2001, Seventh Amendment to the Agreement dated April 22, 2002, Eighth Amendment to the Agreement date d May 30, 2003, Ninth Amendment to the Agreement dated May 25, 2004, Tenth Amendment to the Agreement dated May 3, 2005, Eleventh Amendment to the Agreement dated March 31, 2006, Twelfth Amendment to the Agreement dated May 11, 2006, Thirteenth Amendment to the Agreement dated September 30, 2007, Fourteenth Amendment to the Agreement dated May 1, 2008 and Fifteenth Amendment to the Agreement dated May 28, 2008 (incorporated by reference to Exhibit 10.1 to Frontier Oil Corporation's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2008, File No. 1-07627). Sixteenth Amendment dated November 1, 2009, to the Frontier Products Offtake Agreement El Dorado Refinery, dated October 19, 1999, between Frontier Oil and Refining Company and Equiva Trading Company (now Shell Oil Products US, assignee of Equiva Trading Company) (incorporated by reference to Exhibit 10.14 to Frontier Oil Corporation's Annual Report on Form 10-K for its fiscal year ended December 31, 2009, File No. 1-07627). Seventeenth Amendment, dated August 27, 2013, to the Frontier Products Offtake Agreement El Dorado Refinery, dated October 19, 1999, between Frontier Oil and Refining Company (now HollyFrontier Refining & Marketing LLC, as successor-by-merger to Frontier Oil and Refining Company) and Equiva Trading Company (now Shell Oil Products US, assignee of Equiva Trading Company) (incorporated by reference to Exhibit 10.5 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2013, File No. 1-03876). 10.44 Master Crude Oil Purchase and Sale Contract, dated November 1, 2010, among BNP Paribas Energy Trading GP, BNP Paribas Energy Trading Canada Corp., Frontier Oil and Refining Company and Frontier Oil Corporation (incorporated by reference to Exhibit 10.1 to Frontier Oil Corporation's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2010, File No. 1-07627). 10.45 10.46 10.47 10.48 Guaranty, dated November 1, 2010, by Frontier Oil Corporation in favor of BNP Paribas Energy Trading GP and BNP Paribas Energy Trading Canada Corp. (incorporated by reference to Exhibit 10.1 to Frontier Oil Corporation's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2010, File No. 1-07627). LLC Interest Purchase Agreement, dated July 12, 2012, among HollyFrontier Corporation, Holly Energy Partners, L.P. and HEP UNEV Holdings LLC (incorporated by reference to Exhibit 10.2 to the Registrant's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2012, File No. 1-03876). Limited Partial Waiver of Incentive Distribution Rights under the First Amended and Restated Agreement of Limited Partnership of Holly Energy Partners, L.P., dated July 12, 2012 (incorporated by reference to Exhibit 10.4 to the Registrant's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2012, File No. 1-03876). Amended and Restated Limited Liability Company Agreement of HEP UNEV Holdings LLC, dated July 12, 2012, among HEP UNEV Holdings LLC, HollyFrontier Holdings LLC and Holly Energy Partners, L.P. (incorporated by reference to Exhibit 10.5 to the Registrant's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2012, File No. 1-03876). 109 Table of Content Exhibit Number 10.49 10.50 10.51 10.52 10.53 Description Transportation Services Agreement, dated July 16, 2013, between HollyFrontier Refining & Marketing LLC and Holly Energy Partners-Operating, L.P. (incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8- K filed July 22, 2013, File No. 1-03876). Refined Products Purchase Agreement, dated December 1, 2009, between Holly Refining & Marketing - Tulsa LLC and Sinclair Tulsa Refining Company (incorporated by reference to Exhibit 10.4 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2013, File No. 1-03876). First Amendment to Refined Products Purchase Agreement, dated May 17, 2010, between Holly Refining & Marketing - Tulsa LLC and Sinclair Tulsa Refining Company (incorporated by reference to Exhibit 10.5 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2013, File No. 1-03876). Second Amendment to Refined Products Purchase Agreement, dated December 19, 2011, between HollyFrontier Refining & Marketing LLC and Sinclair Oil Corporation (incorporated by reference to Exhibit 10.6 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2013, File No 1-03876). Third Amendment to Refined Products Purchase Agreement, dated June 1, 2012, between HollyFrontier Refining & Marketing LLC and Sinclair Oil Corporation (incorporated by reference to Exhibit 10.7 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2013, File No. 1-03876). 10.54+ HollyFrontier Corporation Long-Term Incentive Compensation Plan (formerly the Holly Corporation Long-Term Incentive Compensation Plan), as amended and restated on May 24, 2007 as approved at the Annual Meeting of Stockholders of Holly Corporation on May 24, 2007 (incorporated by reference to Exhibit 10.4 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2008, File No. 1-03876). 10.55+ First Amendment to the HollyFrontier Corporation Long-Term Incentive Compensation Plan (incorporated by reference to Exhibit 10.5 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2008, File No. 1-03876). 10.56+ Second Amendment to the HollyFrontier Corporation Long-Term Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K filed May 18, 2011, File No. 1-03876). 10.57+ Third Amendment to the HollyFrontier Corporation Long-Term Incentive Compensation Plan (incorporated by reference to Exhibit 4.6 of the Registrant's Registration Statement on Form S-8 filed November 9, 2012, File No. 333-184877). 10.58+ Holly Corporation – Supplemental Payment Agreement for 2001 Service as Director (incorporated by reference to Exhibit 10.19 of Registrant's Annual Report on Form 10-K for its fiscal year ended July 31, 2002, File No. 1-03876). 10.59+ Holly Corporation – Supplemental Payment Agreement for 2002 Service as Director (incorporated by reference to Exhibit 10.20 of Registrant's Annual Report on Form 10-K for its fiscal year ended July 31, 2002, File No. 1-03876). 10.60+ Holly Corporation – Supplemental Payment Agreement for 2003 Service as Director (incorporated by reference to Exhibit 10.2 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended January 31, 2003, File No. 1-03876). 10.61+ Holly Corporation Amended and Restated Change in Control Agreement Policy (incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed March 1, 2011, File No. 1-03876). 10.62+ Holly Corporation Employee Form of Change in Control Agreement (for grandfathered Holly Corporation employees) (incorporated by reference to Exhibit 10.2 of Registrant's Current Report on Form 8-K filed February 20, 2008, File No. 1-03876). 10.63+ HollyFrontier Corporation Form of Change in Control Agreement (for legacy Frontier Oil Corporation executives) (incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed February 24, 2012, File No. 1-03876). 10.64+ HollyFrontier Corporation Form of Amendment to Change in Control Agreement for Chief Executive Officer and Chief Financial Officer (incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed May 10, 2012, File No. 1-03876). 10.65+ HollyFrontier Corporation Form of Change in Control Agreement (for legacy Holly Corporation employees) (incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed March 30, 2012, File No. 1-03876). 110 Table of Content Exhibit Number Description 10.66+ HollyFrontier Corporation Form of Change in Control Agreement (for HollyFrontier Corporation new hires and promotes) (incorporated by reference to Exhibit 10.2 of Registrant's Current Report on Form 8-K filed March 30, 2012, File No. 1-03876). 10.67+ HollyFrontier Corporation Form of Amendment to Change in Control Agreement for David L. Lamp and George J. Damiris (incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed March 14, 2013, File No. 1-03876). 10.68+ Form of Form of Performance Share Unit Agreement (incorporated by reference to Exhibit 10.5 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2009, File No. 1-03876). 10.69+ Form of Executive Restricted Stock Agreement [time and performance based vesting] (incorporated by reference to Exhibit 10.7 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2010, File No. 1-03876). 10.70+ Form of Employee Restricted Stock Agreement [time based vesting] (incorporated by reference to Exhibit 10.10 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2010, File No. 1-03876). 10.71+ Form of Performance Share Unit Agreement (for 162(m) covered employees) (incorporated by reference to Exhibit 4.11 of the Registrant's Registration Statement on Form S-8 filed November 9, 2012, File No. 333-184877). 10.72+ Form of Performance Share Unit Agreement (for non-162(m) covered employees) (incorporated by reference to Exhibit 4.12 of the Registrant's Registration Statement on Form S-8 filed November 9, 2012, File No. 333-184877). 10.73+ Form of Restricted Stock Agreement (time-based vesting) (incorporated by reference to Exhibit 4.13 of the Registrant's Registration Statement on Form S-8 filed November 9, 2012, File No. 333-184877). 10.74+ Form of Notice of Grant of Restricted Stock (incorporated by reference to Exhibit 4.14 of the Registrant's Registration Statement on Form S-8 filed November 9, 2012, File No. 333-184877). 10.75+ Form of Restricted Stock Unit Agreement (for non-employee directors) (incorporated by reference to Exhibit 10.63 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2012, File No. 1-03876). 10.76+ Form of Notice of Grant of Restricted Stock Units (for non-employee directors) (incorporated by reference to Exhibit 10.64 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2012, File No. 1-03876). 10.77+ Form of Indemnification Agreement entered into with directors and officers of Holly Corporation (incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed December 13, 2006, File No. 1-03876). 10.78+ Retention and Assumption Agreement, dated February 21, 2011, among Frontier Oil Corporation, Holly Corporation and Michael C. Jennings (incorporated by reference to Exhibit 10.1 to Frontier Oil Corporation's Current Report on Form 8-K filed February 21, 2011, File No. 1-07627). 10.79+ Retention and Assumption Agreement, dated February 21, 2011, among Frontier Oil Corporation, Holly Corporation and Doug S. Aron (incorporated by reference to Exhibit 10.2 to Frontier Oil Corporation's Current Report on Form 8- K filed February 21, 2011, File No. 1-07627). 10.80+ HollyFrontier Corporation Omnibus Incentive Compensation Plan (formerly the Frontier Oil Corporation Omnibus Incentive Compensation Plan) (incorporated by reference to Exhibit 10.5 of Registrant's Current Report on Form 8-K filed July 8, 2011, File No. 1-03876). 10.81+ 10.82+ Form of Frontier Oil Corporation Omnibus Incentive Compensation Plan Stock Unit Agreement with Double Trigger Vesting (incorporated by reference to Exhibit 10.15 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2011, File No. 1-03876). Form of Frontier Oil Corporation Omnibus Incentive Compensation Plan Restricted Stock Agreement with Double Trigger Vesting (incorporated by reference to Exhibit 10.16 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2011, File No. 1-03876). 10.83+ HollyFrontier Corporation Executive Nonqualified Deferred Compensation Plan (formerly the Frontier Deferred Compensation Plan) (incorporated by reference to Exhibit 10.73 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2012, File No. 1-03876). 111 Table of Content Exhibit Number 10.84+ 10.85+ Description Form of Indemnification Agreement between Frontier and each of its officers and directors (incorporated by reference to Exhibit 10.41 to Frontier Oil Corporation's Annual Report on Form 10-K for its fiscal year ended December 31, 2006, File No. 1-07627). Form of Indemnification Agreement between HollyFrontier Corporation and each of its officers and directors (incorporated by reference to Exhibit 10.79 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2011, File No. 1-03876). 21.1* Subsidiaries of Registrant. 23.1* Consent of Independent Registered Public Accounting Firm. 31.1* Certification of Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002. 31.2* Certification of Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002. 32.1** Certification of Chief Executive Officer under Section 906 of the Sarbanes-Oxley Act of 2002. 32.2** Certification of Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act of 2002. 101++ The following financial information from Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2013, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Income, (iii) Consolidated Statements of Comprehensive Income, (iv) Consolidated Statements of Cash Flows, (v) Consolidated Statements of Equity, and (vi) Notes to the Consolidated Financial Statements. * Filed herewith. ** Furnished herewith. + Constitutes management contracts or compensatory plans or arrangements. ++ Filed electronically herewith. 112 I, Michael C. Jennings, certify that: CERTIFICATION Exhibit 31.1 1. I have reviewed this annual report on Form 10-K of HollyFrontier Corporation; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Rules 13a-15(f) and 15d-15(f)) for the registrant and have: a. designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b. designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; c. evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d. disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and 5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions): a. all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and b. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting Date: February 25, 2014 /s/ Michael C. Jennings Michael C. Jennings Chief Executive Officer and President I, Douglas S. Aron, certify that: CERTIFICATION Exhibit 31.2 1. I have reviewed this annual report on Form 10-K of HollyFrontier Corporation; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Rules 13a-15(f) and 15d-15(f)) for the registrant and have: a. designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b. designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; c. evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d. disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant's most recent fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and 5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions): a. all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and b. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. Date: February 25, 2014 /s/ Douglas S. Aron Douglas S. Aron Executive Vice President and Chief Financial Officer CERTIFICATION OF CHIEF EXECUTIVE OFFICER UNDER SECTION 906 OF THE SARBANES OXLEY ACT OF 2002, 18 U.S.C. § 1350 Exhibit 32.1 In connection with the accompanying report on Form 10-K for the period ending December 31, 2013 and filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Michael C. Jennings, Chief Executive Officer of HollyFrontier Corporation (the “Company”) hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge: 1. The Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and 2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Date: February 25, 2014 /s/ Michael C. Jennings Michael C. Jennings Chief Executive Officer and President CERTIFICATION OF CHIEF FINANCIAL OFFICER UNDER SECTION 906 OF THE SARBANES OXLEY ACT OF 2002, 18 U.S.C. § 1350 Exhibit 32.2 In connection with the accompanying report on Form 10-K for the period ending December 31, 2013 and filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Douglas S. Aron, Chief Financial Officer of HollyFrontier Corporation (the “Company”) hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge: 1. The Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and 2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Date: February 25, 2014 /s/ Douglas S. Aron Douglas S. Aron Executive Vice President and Chief Financial Officer CORPORATE INFORMATION C O R P O R AT E O FFI C E R S Michael C. Jennings Chief Executive Officer and President Doug S. Aron Executive Vice President and Chief Financial Officer George J. Damiris Senior Vice President, Supply and Marketing James M. Stump Senior Vice President, Refining Operations Denise C. McWatters Senior Vice President and General Counsel J.W. Gann Jr. Vice President, Controller and Chief Accounting Officer B OA R D O F D I R E C TO R S Michael C. Jennings Chairman of the Board Douglas Y. Bech Buford P. Berry Leldon E. Echols R. Kevin Hardage Robert J. Kostelnik James H. Lee Robert G. McKenzie Franklin Myers Michael E. Rose Tommy A. Valenta C O R P O R AT E O FFI C E HollyFrontier Corporation 2828 North Harwood, Suite 1300 Dallas, TX 75201-1507 214.871.3555 www.hollyfrontier.com AU D ITO R S Ernst & Young LLP Dallas, Texas S TO C K E XC H A N G E L I S TI N G New York Stock Exchange Ticker Symbol: HFC Design: Savage Brands, Houston, Texas S TO C K T R A N S FE R AG E N T A N D R E G I S T R A R Wells Fargo Shareowner Services 1110 Centre Point Curve, Suite 101 Mendota Heights, MN 55120 1.800.468.9716 www.shareownerline.com Correspondence or questions concerning share holdings, transfers, lost certificates, dividends, or address or registration changes should be directed to Wells Fargo Shareowner Services. A N N UA L M E E TI N G The Annual Meeting of Stockholders will be held at 8:30 a.m. on May 14, 2014, at Hotel Artesia, 203 North 2nd Street, Artesia, New Mexico. S E C FI L I N G S A direct link to the filings of HollyFrontier Corporation at the U.S. Securities and Exchange Commission website is available on the HollyFrontier Corporation website at www.hollyfrontier.com on the Investor Relations page. S TO C K P E R FO R M A N C E Set forth is a line graph comparing, for the period commencing January 1, 2009 and ending December 31, 2013, the annual percentage change in cumulative total stockholder return on our common stock to the cumulative total stockholder return of the S&P Composite 500 Stock Index and an industry peer group chosen by the Company. The stock price performance depicted in the following graph is not necessarily indicative of future price performance. The graph will not be deemed to be incorporated by reference in any filing by the Company under the Securities Act of 1933 or the Securities Exchange of 1934, except to the extent that the Company specifically incorporates such graph by reference. HollyFrontier S&P 500 Index Old Peer Group New Peer Group $800 $600 $400 $200 $0 2008 2009 2010 HollyFrontier S&P 500 Index New Peer Group Old Peer Group 100 100 100 100 144 126 83 83 234 146 117 117 2011 282 149 110 110 2012 610 172 204 192 2013 696 228 308 288 (1) The amounts shown assume that the value of the investment in HollyFrontier and each index was $100 on January 1, 2009 and that all dividends were reinvested. (2) The Old Peer Group consists of Alon USA Energy, Inc., Delek US Holdings, Inc., Marathon Petroleum Corporation (included from 6/23/2011), Phillips 66 Corporation (included from 4/12/2012), Tesoro Corporation, Valero Energy Corporation and Western Refining, Inc. Marathon Petroleum Corporation and Phillips 66 Corporation became public in June 2011 and April 2012, respectively. (3) The New Peer Group consists of Alon USA Energy, Inc., Delek US Holdings, Inc., Marathon Petroleum Corporation (included from 6/23/2011), Tesoro Corporation, Valero Energy Corporation and Western Refining, Inc. H O L L Y F R O N T I E R 2 0 1 3 A N N U A L R E P O R T 2828 North Harwood Suite 1300 Dallas, Texas 75201-1507 

Continue reading text version or see original annual report in PDF format above