Business Radar | Par Pacific Holdings, Inc.

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2018 Annual Report Par Pacific

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In 2018 we dramatically expanded our diversified and market- leading businesses – positioned to suceed throughout the cycle. Par Pacific Holdings, Inc. owns and operates market-leading energy and infrastructure businesses. Our strategy is to acquire and develop energy and infrastructure businesses in logistically-complex markets. Our common stock is publicly traded on the NYSE under the trading symbol “PARR.”

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Dear Fellow Shareholders: I am pleased to report on another profitable year at Par Pacific, with net income of $0.85 per share and net cash provided by operating activities of $90.6 million. Adjusted net income was $1.06 per share in 2018, marking the second consecutive year our company generated Adjusted Net Income of greater than $1.00 per share. We achieved this result despite material declines in our Hawaii refining operations’ operating profit due to difficult market conditions. While we are delighted with the profitability of our operations, your management team is more pleased with our 2018 accomplishments in building our enterprise. Our longstanding strategy has been to own attractive businesses in niche markets. Last year, we announced three major transactions in pursuit of that objective. In March, we purchased our first mainland fuel retail operation in Spokane, Washington. In December, after our competitor in Hawaii announced it was shutting down its refining operations, we acquired its crude processing units. Finally, in January 2019, we completed the acquisition of U.S. Oil & Refining Co., a refining and logistics network based in Tacoma, Washington. Each of these acquisitions helps transform our company into a coherent downstream system serving a region that we believe encompasses some of the most attractive markets in the world for our products and services. Entering 2019, we can state our objective with clarity and present an operating system to back up that objective. PAR PACIFIC 1

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INTEGRATED DOWNSTREAM NETWORK We own and operate market-leading critical energy infrastructure businesses in logistically- complex markets. Our first market (Hawaii) may be the most logistically complex market in the United States. With a multitude of demand drivers including heavy reliance on air transportation, one of the largest groups of military depots in the United States, and an isolated network of islands, we believe the value of owning and operating the largest transportation fuels supply network in the state can be significant. The logistical barriers make balancing local supply and demand very important, and the complexity can work against you when the market has excess capacity. We have experienced this problem over the past few years with local refining capacity well in excess of local demand. Due to our competitor’s shutdown of their refinery and our purchase of their crude units in December, we now have a more balanced supply and demand in the market. And with units on two sites located within two miles of each other connected by a network of pipelines, we are able to leverage economies of scale and lower our operating costs per barrel. This acquisition further enhances our distillate and low-sulfur fuel oil profile in Hawaii just as petroleum markets begin to deal with the reduced-sulfur requirements for bunker fuel related to the new IMO 2020 regulations. With the anticipated completion of our previously-announced distillate hydrotreater project this summer, we expect that more than 70% of the product yield from our Hawaii refining assets will benefit from the expected upturn in distillate cracks – we believe the highest exposure of any refining complex in the United States. In summary, we are entering 2019 with a much improved operating base in Hawaii, with strong market share, and with an excellent team to manage our operations.

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As you know, we believe there are other markets that have similar characteristics to Hawaii. Our first acquisition outside of Hawaii, which happened to be in northeastern Wyoming, typifies the types of market in which we seek to operate. Isolated and difficult to supply from afar due to limited distribution systems, our Black Hills market has very similar barriers to entry as Hawaii. Moreover, it has an additional advantage because our refinery is located very close to the Powder River Basin, considered one of the nation’s best emerging crude oil production basins. This year, we entered into two additional markets in the Pacific Northwest. With these acquisitions, we now serve three markets in the Rockies and Pacific Northwest, and we have the ability to provide transportation fuels to other markets. In addition, with our most recent acquisition of U.S. Oil & Refining Co., we now own and operate a marine terminal to provide renewable fuels to our Hawaii operation from the Pacific Northwest, a rail terminal that allows us to increase our exposure to the inland crude production regions that currently provide the best value for feedstock to any refining system in the world, and storage for the movements of products to markets. I would be remiss in not also noting that earlier in 2018, we entered the state of Washington by acquiring a chain of fuel retail locations in the Spokane region. While we do not have an established processing or logistics location there, we believe these retail locations provide value to our nearby refining and logistics operations. More importantly, Spokane has all We own and operate market-leading critical energy infrastructure businesses in logistically complex markets. the market characteristics that we target. This region has a complex transportation fuels supply chain where the marginal barrel is required to be delivered via rail, barge, or truck from western Washington. The flexibility inherent in our combined businesses allows us to opportunistically serve our Spokane station portfolio via rail, truck, or product exchange into the region. This vertical integration advantage is greatest during periods of soft demand. As a result of our 2018 accomplishments, you are now an investor in a business that has established downstream systems throughout the Pacific Northwest, the upper Rockies, and the Pacific. These are markets that fit our areas of expertise, that are growing nicely, and that have a significant need for the jet fuel and other distillates that happen to be our area of focus. We believe there are plenty of opportunities to fill in the white space within this region. You are also invested in a company that we believe will generate significant operational income, and almost all of those profits will result in free cash flow due to our net operating loss carryforwards. PAR PACIFIC 3

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OUR BUSINESSES Refining For 2018, we reported operating income of $73.3 million and Adjusted EBITDA from our Refining business segment of $91.9 million, compared with operating income and Adjusted EBITDA of $86.0 million and $114.1 million in 2017, respectively. The entire decline was related to weaker profitability in Hawaii, which in turn is due to the higher cost of our crude purchases relative to our Brent benchmark. During 2018, we purchased crude oil for our Hawaii operations at an average of $2.19 per barrel in excess of the cost of our benchmark Brent (the “differential”), or $1.91 per barrel more than the 2017 differential to Brent. Virtually none of this increase resulted from an increase in the quality of the average purchased barrel. The higher crude differentials reduced profitability by more than $50 million in 2018. This negative impact meant that our Hawaii refinery Adjusted EBITDA was less than half of the peak LTM Adjusted EBITDA for this business segment. 67% Brent 33% WTI 1 Brent vs. WTI Crude Exposure 47% Distillates 4% Asphalt 2 Est. Combined Product Yield 14% LSFO 10% Other Products 25% Gasoline 1 Calculated as a percentage of expected 2019 throughput exposed to Brent vs. WTI crudes. 2 Product yield is based on expected 2019 refining yields post start-up of the company’s diesel hydrotreater project.

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As I noted, the competing refinery in Hawaii shut down last year. It was a brutal year for Hawaii operations due to the strong pricing of crude oil in the Pacific Basin. We and other waterborne refiners have faced these conditions since the OPEC cutbacks of 2017. The decision this winter to further cut back OPEC production should continue these strong prices. On the other hand, the same factors that are driving cutbacks in the waterborne market are resulting in attractive prices for the North American inland crudes that our Washington and Wyoming refineries consume. In fact, our Wyoming refinery reported strong profits in 2018 and nice growth over 2017. With the U.S. Oil & Refining Co. acquisition, we expect to be well-balanced between the waterborne and North American inland crude supply basins. The battle between shale producers and Saudi-led OPEC will dictate which crude is more affordable, but we should have a balanced profile regardless of which party takes the upper hand. With the recent acquisitions, we now have 208,000 barrels per day of refining capacity in the regions known in the energy sector as PADDs IV and V. We expect to average about 170,000 barrels per day of crude oil throughput. Note that we do not target 100% throughput at our refineries because a portion of our crude distillation capacity is not required to meet the needs of our local markets. Unlike larger refineries in export-oriented markets, our refineries are calibrated to serve local markets. Therefore, we focus on maintaining production to meet local demand and limit the export of our production. In the same manner that export-oriented competitors have difficulty competing with us in our markets, we are not a regular, competitive supplier to distant markets. This issue is most obvious in Hawaii, where the cost to export production to the nearest refined products market can easily exceed our plant-gate profitability. As a result, we do not expect to run both of the crude units in Hawaii much beyond 75%. Our Washington and Wyoming refineries are more closely aligned to market demand; therefore, their throughput should be fairly close to capacity in order for us to optimize profitability. Most importantly, the safety of our employees, environmental compliance, and operational reliability continue to be at the forefront of our daily operations. Our refining teams led by Joseph Israel have done a great job of maintaining a strong safety-first culture throughout a period of acquisition and growth. I would like to congratulate the entire team on another year of solid operational execution. PAR PACIFIC 5

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Logistics Our Logistics business segment largely serves our other business segments by moving crude oil and refined products to and from our retail system and refineries. It is an impressive and large collection of marine terminals, ocean-going barges, pipelines, rail facilities, loading racks, and storage facilities. This system forms the backbone of the energy infrastructure in the markets it serves and has significant standalone value. 2018 Logistics operating income was $33.4 million and Adjusted EBITDA was $40.2 million. This strong result was achieved despite higher fuel costs associated with barge and truck transportation in 2018 that were offset by the higher network throughput in both Wyoming and Hawaii. While most of this business is intercompany, we set our rates for pipeline, rail, barge, and truck movements based on the prices that we pay to others for similar services. This business reflects the steady profitability of a midstream enterprise and should always provide good cash flow to support our business even in periods of economic weakness. Unlike several of our competitors, we have chosen not to place these assets in a master limited partnership, because we do not have any material federal income tax payments. With the U.S. Oil & Refining Co. acquisition, we expect that our Logistics Adjusted EBITDA will increase materially. That acquisition brings to us a greater proportion of logistics assets relative to the Washington refinery given its marine terminal, nearby unit train rail loading facility, proprietary jet fuel pipeline, and rail car movements. Therefore, the contribution (relative to the associated refining profitability) from Logistics is expected to be greater from this system than from our Rockies system.

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Retail Our Retail business segment reported another record year in 2018 with operating income of $37.2 million and Adjusted EBITDA of $46.2 million. Operating income and Adjusted EBITDA in 2018 were approximately 51% and 49% higher than in 2017, respectively. The growth was two-fold in character. First, we acquired a 33-location retail business in the Spokane, Washington region in March 2018. We sell Cenex®-branded fuel at these locations, which are locally known as ZipTrip® convenience stores. This acquisition represents a significant increase in operational responsibility for us, because in Hawaii we own and operate the fuel pumps in partnership with third-party store operators at approximately half of our locations. In Washington, we own and operate both the store and the fuel pumps at every location. We are pleased with the performance of our new team members and the stores. Our Retail team in Hawaii led by Jim Yates works closely with the Spokane leadership to streamline our organization. In addition to the contribution of the acquisition, we also had great performance from our Hawaii Retail store base in 2018. Both our Hele and “76” branded store bases had record performance. While this business unit continues to generate strong growth, we did struggle with same-store sales fuel volumes in 2018 due to the higher price of gasoline and diesel and the impact that change had on consumer buying trends. Higher prices not only cause consumers to be more conscious of their driving patterns but also shift their purchasing to high-volume retailers who offer a lower price but longer waits and less convenient locations. With the late-year swoon in crude oil prices, that negative trend in fuel volumes appears to have abated. PAR PACIFIC 7

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Laramie Laramie contributed $9.5 million in equity earnings to our business in 2018, compared to $18.4 million in 2017. These GAAP results were largely driven by the change in the value of Laramie’s commodities hedging program. When adjusted to exclude changes in the value of unrealized derivatives, equity earnings from Laramie were $10.6 million in 2018, up significantly from a loss of $1.2 million in 2017. The growth was largely due to Laramie’s strong production growth and associated increase in Adjusted EBITDAX. Laramie exited 2018 with daily production of 239 MMcfed, more than 50% above 2017 exit production of 156 MMcfed. Laramie’s net income was $6.3 million for 2018, and Adjusted EBITDAX was $101.1 million. Laramie’s 2018 Adjusted EBITDAX was more than 80% above prior year Adjusted EBITDAX of $55.2 million. Furthermore, Laramie added more than 40% to its proved developed producing reserves with a successful drilling program during the year. Laramie accomplished this growth while reducing its Debt/EBITDAX from 3.1x at year-end 2017 to 2.1x by the end of year 2018. What is not to like about this combination of growth and savvy capital management? With a small purchase of another producer and the redemption of a partner’s stake, our ownership interest ended the year at 46%. Since we do not control Laramie, it is not consolidated with our other operations. Our book carrying value is below the year-end 2018 standardized measure of discounted cash flows for the proved developed producing (PV10 of PDP) portion of the company’s resource base. However, the natural gas futures market is in steep backwardation, and when we take this market outlook into account, we find the market-based PDP PV10 value is closer to our carrying value. Laramie Adjusted EBITDAX ($MM) $101 $55 $34 2016 2017 2018

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The market prospects for natural gas are negative due largely to the anticipated natural gas production from the Permian and other shale oil producing basins. Although demand for natural gas is rising rapidly, our country seems to have an endless supply of natural gas – enough that the United States has quickly become one of the major exporters of natural gas in the last three years. Notwithstanding these macro trends, during the second half of 2018, Laramie’s Adjusted EBITDAX exceeded accrued capital expenditures by $6 million. We expect this positive cash flow generation to continue in 2019. We continue to be pleased with the performance of Bob Boswell and other members of the Laramie team. Their commercial and operational execution has been strong, but the market outlook continues to undercut their excellent performance and cast a negative impression over the prospects for natural gas production. Our Capital Structure We believe the best measure of our success is free cash flow. Free cash flow in 2018 was $42.2 million compared with $74.8 million in 2017. The decline in free cash flow can be attributed in part to additional growth capital expenditures in 2018. We deployed nearly $141 million in capital to complete the Hawaii and Spokane acquisitions during 2018. Of this amount, we issued common stock worth $19 million and used available liquidity for the remainder. Shortly after the end of 2018, we completed the U.S. Oil & Refining Co. acquisition. We borrowed an additional $295 million of debt to complete this transaction, entered into a second inventory intermediation agreement for crude oil and refined products inventory, issued common stock worth $37 million, and used available liquidity to finance the remainder of the acquisition. Pro forma for these transactions, our year-end net debt to total capital would have increased to 54%. As I have noted publicly and in prior letters, we prefer to be in the range of 30 to 35% and have net debt to Adjusted EBITDA be less than 2.5x. Given these objectives, we will dedicate the free cash flow from our business segments to reducing our financial debt. PAR PACIFIC 9

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Outlook We enter 2019 with a much larger asset base. Overall, daily refining throughput has increased from 91,300 bpd in 2018 to an estimated 170,000 bpd for this year. Our retail base has increased by 33 locations. Our logistics capabilities are greatly enhanced by the U.S. Oil & Refining Co. acquisition. With our refining locations in particular, we also now have greater economies of scale that permit better planning for turnarounds and other events and cost benefits. And we have a nice balance of refining locations dependent on inland crude basins. We believe that our Washington and Wyoming locations are major beneficiaries of the expected growth in United States shale oil production. Shale oil production will wane at times (likely when lower crude oil prices cause local rig counts to decline), and then our Hawaii locations should benefit from the relative pricing of OPEC-led waterborne crude oil supplies. More importantly, we now have a fully integrated system with the capability to serve our Hawaii location from the West Coast, rail terminals in our Wyoming and Washington locations, and an ability to move crude oil, refined petroleum products and renewable fuels to and from our operating nodes. This is expected to create new and attractive commercial opportunities for us. The acquisitions of the past year are all expected to be highly accretive to our earnings profile. We look forward to a 2019 when we can demonstrate the value created from this growth. On behalf of Par’s board of directors, management, and employees, I thank you for your support. Sincerely, William Pate President and Chief Executive Officer

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Refining Capacity (Mbpd) Storage (MMbls) Retail Locations 9.0 124 124 208 166 91 6.1 6.1 112 2017 2018 2019 2017 2018 2019 2017 2018 2019 Operating metrics assume a full year of contribution from acquisitions in the year of closing. PAR PACIFIC 11

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NON-GAAP Performance Measures This annual shareholder letter includes certain financial measures that have been adjusted for items impacting comparability. The accompanying information provides reconciliations of these non-GAAP financial measures to their most directly comparable financial measure calculated and presented in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Our non-GAAP financial measures should not be considered as alternatives to GAAP measures such as net income, earnings per share, return on equity or any other GAAP measure of liquidity or financial performance. Adjusted Net Income (Loss) and Adjusted EBITDA Adjusted Net Income (Loss) is defined as Net income (loss) excluding changes in the value of contingent consideration and common stock warrants, acquisition and integration costs, unrealized (gains) losses on derivatives, debt extinguishment and commitment costs, release of tax valuation allowance, inventory valuation adjustment, severance costs, impairment expense, and (gain) loss on sale of assets. Beginning in 2018, Adjusted Net Income (Loss) also excludes Par’s share of Laramie Energy’s unrealized loss (gain) on derivatives and RINs loss in excess of net obligation. The exclusion of Par’s share of Laramie Energy’s unrealized loss (gain) on derivatives from Adjusted Net Income (Loss) is consistent with our treatment of Par’s unrealized (gains) losses on derivatives, which are also excluded from Adjusted Net Income (Loss). Adjusted EBITDA is Adjusted Net Income (Loss) excluding interest expense and financing costs, taxes, DD&A, and beginning in 2018, equity losses (earnings) from Laramie Energy, excluding Par’s share of Laramie’s unrealized loss (gain) on derivatives. We have recast the non-GAAP information for the three months and year ended December 31, 2017 to conform to the current period presentation. We believe Adjusted Net Income (Loss) and Adjusted EBITDA are useful supplemental financial measures that allow investors to assess: • The financial performance of our assets without regard to financing methods, capital structure, or historical cost basis; • The ability of our assets to generate cash to pay interest on our indebtedness; and • Our operating performance and return on invested capital as compared to other companies without regard to financing methods and capital structure.

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Adjusted Net Income (Loss) and Adjusted EBITDA should not be considered in isolation or as a substitute for operating income (loss), net income (loss), cash flows provided by operating, investing, and financing activities, or other income or cash flow statement data prepared in accordance with GAAP. Adjusted Net Income (Loss) and Adjusted EBITDA presented by other companies may not be comparable to our presentation as other companies may define these terms differently. The following table presents a reconciliation of Adjusted Net Income (Loss) and Adjusted EBITDA to the most directly comparable GAAP financial measure, net income (loss), on a historical basis for the periods indicated (in thousands): Three Months Ended Year Ended December 31, December 31, 2018 2017 2018 2017 Net Income $ 13,886 $ 19,005 $ 39,427 $ 72,621 Inventory valuation adjustment 3,159 528 (16,875) (1,461) RINs loss in excess of net obligation 3,136 — 4,544 — Unrealized loss (gain) on derivatives (6,346) (702) (1,497) (623) Acquisition and integration costs 6,804 142 10,319 395 Debt extinguishment and commitment costs 4,224 6,829 4,224 8,633 Release of tax valuation allowance 1 (660) — (660) — Change in value of common stock warrants (2,197) (537) (1,801) 1,674 Change in value of contingent consideration — — 10,500 — Severance costs — — — 1,595 Par’s share of Laramie Energy’s unrealized loss (gain) on derivatives 2 (1,282) $ (4,654) 1,158 (19,568) Adjusted Net Income 3 $ 20,724 $ 20,611 $ 49,339 $ 63,266 Depreciation, depletion, and amortization 13,638 12,141 52,642 45,989 Interest expense and financing costs, net 10,422 6,132 39,768 31,632 Equity losses (earnings) from Laramie Energy, LLC, (3,908) (2,064) (10,622) 1,199 excluding Par’s share of unrealized loss (gain) on derivatives Income tax expense (benefit) 108 (3,081) 993 (1,319) Adjusted EBITDA $ 40,984 $ 33,739 $ 132,120 $ 140,767 1 Included in income tax expense (benefit) on our Condensed Consolidated Statements of Operations. 2 Included in Equity earnings from Laramie Energy, LLC on our Condensed Consolidated Statements of Operations. 3 For the year ended December 31, 2018 and 2017, there was no impairment expense, or (gain) loss on sale of assets. PAR PACIFIC 13

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The following table sets forth the computation of basic and diluted Adjusted Net Income (Loss) per share (in thousands, except per share amounts): Three Months Ended Year Ended December 31, December 31, 2018 2017 2018 2017 Adjusted Net Income $ 20,724 $ 20,611 $ 49,339 $ 63,266 Undistributed Adjusted Net Income allocated to participating securities 1 284 319 695 765 Adjusted Net Income attributable to common stockholders 20,440 20,292 48,644 62,501 Plus: effect of convertible securities 2,722 2,595 — — Numerator for diluted income per common share $ 23,162 $ 22,887 $ 48,644 $ 62,501 Basic weighted-average common stock shares outstanding 46,381 45,596 45,726 45,543 Add dilutive effects of common stock equivalents 6,417 6,482 29 40 Diluted weighted-average common stock shares outstanding 52,798 52,078 45,755 45,583 Basic Adjusted Net Income per common share $ 0.44 $ 0.45 $ 1.06 $ 1.37 Diluted Adjusted Net Income per common share $ 0.44 $ 0.44 $ 1.06 $ 1.37 1 Participating securities include restricted stock that has been issued but has not yet vested.

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Adjusted EBITDA by Segment Adjusted EBITDA by segment is defined as Operating income (loss) by segment excluding depreciation, depletion, and amortization expense, inventory valuation adjustment, unrealized loss (gain) on derivatives, and severance costs. Beginning in 2018, Adjusted EBITDA by segment also excludes RINs loss in excess of net obligation. We have recast the non-GAAP information for the three months and year ended December 31, 2017 to conform to the current period presentation. We believe Adjusted EBITDA by segment is a useful supplemental financial measure to evaluate the economic performance of our segments without regard to financing methods, capital structure, or historical cost basis. The following table presents a reconciliation of Adjusted EBITDA to the most directly comparable GAAP financial measure, operating income (loss), on a historical basis, for selected segments, for the periods indicated (in thousands): Year Ended December 31, 2018 Refining Logistics Retail Operating income by segment $ 73,269 $ 33,389 $ 37,232 Depreciation, depletion and amortization 32,483 6,860 8,962 Inventory valuation adjustment (16,875) — — RINs loss in excess of net obligation 4,544 — — Unrealized loss (gain) on derivatives (1,497) — — 1 Adjusted EBITDA $ 91,924 $ 40,249 $ 46,194 Year Ended December 31, 2017 Refining Logistics Retail Operating income by segment $ 86,016 $ 33,993 $ 24,700 Depreciation, depletion and amortization 29,753 6,166 6,338 Inventory valuation adjustment (1,461) — — RINs loss in excess of net obligation — — — Unrealized loss (gain) on derivatives (623) — — Severance costs 395 — — Adjusted EBITDA $ 114,080 $ 40,159 $ 31,038 1 There were no severance costs for the three months ended December 31, 2018 or for the years ended December 31, 2018 and 2017. PAR PACIFIC 15

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Consolidated Free Cash Flow Free Cash Flow is defined as cash provided by (used in) operations less capital expenditures. We believe Free Cash Flow is a useful supplemental financial measure to evaluate our ability to generate cash to repay our indebtedness or make discretionary investments. Free Cash Flow should be considered in addition to, rather than as a substitute for, net income as a measure of our financial performance and net cash provided by (used in) operations as a measure of our liquidity. Free Cash Flow presented by other companies may not be comparable to our presentation as other companies may define these terms differently. Consolidated Free Cash Flow ($ in thousands) Year Ended December 31, 2018 2017 1 Cash provided by (used in) operations $ 90,620 $ 106,483 Less: Capital Expenditures 48,439 31,708 Free Cash Flow $ 42,181 $ 74,775 1 Cash provided by (used in) operations for 2017 has been recast for recently adopted accounting standards updates.

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Laramie Energy Adjusted EBITDAX Adjusted EBITDAX is defined as net income (loss) excluding commodity derivative loss (gain), losses on settled derivative instruments, interest expense, non-cash preferred dividend, depreciation, depletion, amortization, and accretion, exploration and geological and geographical expense, bonus accrual, equity-based compensation expense, loss (gain) on disposal of assets, pipeline (payment) deficiency accrual, and expired acreage (non-cash). We believe Adjusted EBITDAX is a useful supplemental financial measure to evaluate the economic and operational performance of exploration and production companies such as Laramie Energy. The following table presents a reconciliation of Laramie Energy’s Adjusted EBITDAX to the most directly comparable GAAP financial measure, net income (loss) for the periods indicated (in thousands): Twelve Months Ended Dec. 31, Dec. 31, Dec. 31, 2018 2017 2016 Net income (loss) $ 6,347 $ 30,837 $(61,849) Commodity derivative loss (gains) 13,571 (35,531) 27,728 Loss on settled derivative instruments (9,509) (10,710) 6,724 Interest expense 9,726 5,954 4,367 Non-cash preferred dividend 4,689 4,166 3,194 Depreciation, depletion, amortization, and accretion 68,961 52,091 43,737 Exploration and geological and geographical expense 351 421 104 Bonus accrual, net 554 105 1,982 Equity based compensation expense 3,248 6,195 6,551 Gain on disposal of assets (809) (50) (657) Pipeline definciency accrual (11) (254) 3 Abandoned property and expired acreage 4,019 1,937 2,081 Total adjusted EBITDAX $101,137 $ 55,161 $ 33,965 PAR PACIFIC 17

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, DC 20549 ________________________________________________________________________________________________________________________ FORM 10-K ________________________________________________________________________________________________________________________ (Mark One) ý ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2018 OR ¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission File No. 001-36550 ________________________________________________________________________________________________________________________ PAR PACIFIC HOLDINGS, INC. (Exact name of registrant as specified in its charter) ________________________________________________________________________________________________________________________ Delaware 84-1060803 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 825 Town & Country Lane, Suite 1500 Houston, Texas 77024 (Address of principal executive offices) (Zip Code) Registrant’s telephone number, including area code: (281) 899-4800 Securities registered under Section 12(b) of the Act: Title of each class Name of Exchange on which registered Common stock, par value $0.01 per share The New York Stock Exchange Securities registered pursuant to Section 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 ý 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 ý 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 ý No ¨ Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files). Yes ý 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. ¨

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Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. Large accelerated filer ¨ Accelerated filer ý Non-accelerated filer ¨ Smaller reporting company ¨ Emerging growth company ¨ If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨ Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No ý The aggregate market value of voting and non-voting common equity held by non-affiliates of the registrant was approximately $559,047,131 based on the closing sales price of the common stock on the New York Stock Exchange as of June 29, 2018. As of March 4, 2019, 49,539,919 shares of the registrant’s Common Stock, $0.01 par value, were issued and outstanding. Documents Incorporated By Reference Certain information required to be disclosed in Part III of this report is incorporated by reference from the registrant's definitive proxy statement or an amendment to this report, which will be filed with the SEC not later than 120 days after the end of the fiscal year covered by this report.

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TABLE OF CONTENTS PAGE PART I Item 1. BUSINESS 1 Item 1A. RISK FACTORS 19 Item 1B. UNRESOLVED STAFF COMMENTS 31 Item 2. PROPERTIES 31 Item 3. LEGAL PROCEEDINGS 36 Item 4. MINE SAFETY DISCLOSURES 36 PART II Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER 37 MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES Item 6. SELECTED FINANCIAL DATA 39 Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND 40 RESULTS OF OPERATIONS Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 70 Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 71 Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND 71 FINANCIAL DISCLOSURE Item 9A. CONTROLS AND PROCEDURES 71 Item 9B. OTHER INFORMATION 74 PART III Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 74 Item 11. EXECUTIVE COMPENSATION 74 Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 74 Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE 74 Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES 74 PART IV Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES 75 Item 16. FORM 10-K SUMMARY F-63 i

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Glossary of Selected Industry Terms Unless otherwise noted or indicated by context, the following terms used in this Annual Report on Form 10- K have the following meanings: barrel or bbl A common unit of measure in the oil industry, which equates to 42 gallons. blendstocks Various compounds that are combined with gasoline or diesel from the crude oil refining process to make finished gasoline and diesel; these may include natural gasoline, FCC unit gasoline, ethanol, reformate, or butane, among others. Brent A light, sweet North Sea crude oil, characterized by an API gravity of 38 degrees and a sulfur content of approximately 0.4% by weight that is used as a benchmark for other crude oils. cardlock Automated unattended fueling sites that are open all day and are designed for commercial fleet vehicles. catalyst A substance that alters, accelerates, or instigates chemical changes, but is not produced as a product of the refining process. CO2 Carbon dioxide. condensate Light hydrocarbons which are in gas form underground, but are a liquid at normal temperatures and pressure. crack spread A simplified calculation that measures the difference between the price for light products and crude oil. For example, we reference the 4-1-2-1 crack spread, which is a general industry standard that approximates the per barrel refining margin resulting from processing four barrels of crude oil to produce one barrel of gasoline, two barrels of distillate (jet fuel and diesel), and one barrel of fuel oil. distillates Refers primarily to diesel, heating oil, kerosene, and jet fuel. ethanol A clear, colorless, flammable oxygenated liquid. Ethanol is typically produced chemically from ethylene or biologically from fermentation of various sugars from carbohydrates found in agricultural crops and cellulosic residues from crops or wood. It is used in the United States as a gasoline octane enhancer and oxygenate. feedstocks Crude oil or partially refined petroleum products that are processed or blended into refined products. jobber A petroleum marketer. LSFO Low sulfur fuel oil. Mbbls Thousand barrels of crude oil or other liquid hydrocarbons. Mbpd Thousand barrels per day. MMbbls Million barrels of crude oil or other liquid hydrocarbons MMcf Million cubic feet, a unit of measurement for natural gas. MMcfd Million cubic feet per day. MMcfe Million cubic feet equivalent which is determined by using the ratio of six Mcf of natural gas to one Bbl of crude oil. MMbtu Million British thermal units. MW Megawatt. Nelson Complexity A measure of the complexity of a given refinery compared to crude distillation, which is assigned a Index complexity factor of 1.0. The index number is an indication of an oil refinery's ability to process feedstocks, such as heavier and higher sulfur content crude oils, into value-added products. Generally, more complex refineries have higher index numbers. NGL Natural gas liquid. NOx Nitrogen oxides. refined products Petroleum products, such as gasoline, diesel, and jet fuel, that are produced by a refinery. throughput The volume processed through a unit or refinery. turnaround A periodically required standard procedure to inspect, refurbish, repair, and maintain a refinery. This process involves the shutdown and inspection of major processing units and typically occurs every three to five years. single-point mooring Also known as a single buoy mooring, refers to a loading buoy that is anchored offshore and serves as an interconnect for tankers loading or offloading crude oil and refined products. SO2 Sulfur dioxide. WTI West Texas Intermediate crude oil, a light, sweet crude oil, typically characterized by an API gravity between 38 degrees and 40 degrees and a sulfur content of approximately 0.3% by weight that is used as a benchmark for other crude oils. yield The percentage of refined products that is produced from crude oil and other feedstocks, net of fuel used as energy. ii

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PART I Item 1. BUSINESS OVERVIEW Par Pacific Holdings, Inc., headquartered in Houston, Texas, owns and operates market-leading energy and infrastructure businesses. Our strategy is to acquire and develop energy and infrastructure businesses in logistically-complex markets. Our business is organized into three primary operating segments: 1) Refining - We own and operate three refineries with total throughput capacity of over 200 Mbpd. Our refinery in Kapolei, Hawaii, produces ultra-low sulfur diesel (“ULSD”), gasoline, jet fuel, marine fuel, low sulfur fuel oil (“LSFO”), and other associated refined products primarily for consumption in Hawaii. Our refinery in Newcastle, Wyoming, produces gasoline, ULSD, jet fuel, and other associated refined products that are primarily marketed in Wyoming and South Dakota. Our refinery in Tacoma, Washington, produces distillate, gasoline, asphalt, and other associated refined products that are primarily marketed in the Pacific Northwest. 2) Retail - We operate 124 retail outlets in Hawaii, Washington, and Idaho. Our retail outlets in Hawaii sell gasoline, diesel, and retail merchandise throughout the islands of Oahu, Maui, Hawaii, and Kauai. Our Hawaii retail network includes Hele® and 76® branded retail sites, company-operated convenience stores, 7-Eleven operated convenience stores, other sites operated by third parties, and unattended cardlock stations. During 2018, we completed the rebranding of 24 of our 34 company-operated convenience stores in Hawaii to “nomnom,” a new proprietary brand. Our retail outlets in Washington and Idaho sell gasoline, diesel, and retail merchandise and operate under the “Cenex®” and “Zip Trip®” brand names. 3) Logistics - We operate an extensive, multimodal logistics network spanning the Pacific, the Northwest, and the Rockies. We own and operate terminals, pipelines, a single-point mooring (“SPM”), and trucking operations to distribute refined products throughout the islands of Oahu, Maui, Hawaii, Molokai, and Kauai. We also own and operate a crude oil pipeline gathering system, a refined products pipeline, storage facilities, and loading racks in Wyoming and a jet fuel storage facility and pipeline that serve Ellsworth Air Force Base in South Dakota. In Washington, we own and operate a marine terminal, a unit train-capable rail loading terminal, storage facilities, a truck rack, and a proprietary pipeline that serves McChord Air Force Base. We also own a 46.0% equity investment in Laramie Energy, LLC (“Laramie Energy,”), a joint venture entity focused on producing natural gas in Garfield, Mesa, and Rio Blanco Counties, Colorado. On January 9, 2018, we entered into an Asset Purchase Agreement with CHS Inc. to acquire twenty-one (21) owned retail gasoline, convenience store facilities and twelve (12) leased retail gasoline, convenience store facilities, all at various locations in Washington and Idaho (collectively, “Northwest Retail”). On March 23, 2018, we completed the acquisition for cash consideration of approximately $74.5 million (the “Northwest Retail Acquisition”). The results of operations of Northwest Retail are included in our retail segment commencing March 23, 2018. On August 29, 2018, following the announcement by IES Downstream, LLC (“IES”) that it was ceasing refining operations in Hawaii, we entered into a Topping Unit Purchase Agreement with IES to purchase certain of IES’s refining units and related assets in addition to certain hydrocarbon and non-hydrocarbon inventory (collectively, the “Hawaii Refinery Expansion”). On December 19, 2018, we completed the asset purchase for approximately $66.9 million, net of a $4.3 million receivable related to net working capital adjustments. The purchase price consisted of $47.6 million in cash and approximately 1.1 million shares of our common stock with a fair value of $19.3 million. The results of operations of the acquired assets are included in our refining segment commencing December 19, 2018. On November 26, 2018, we entered into a Purchase and Sale Agreement to acquire U.S. Oil & Refining Co. and certain affiliated entities (collectively, “U.S. Oil”), a privately-held downstream business, for $358 million including working capital acquired (the “Washington Refinery Acquisition”). The Washington Refinery Acquisition includes a 42 Mbpd refinery, a marine terminal, a unit train-capable rail loading terminal, and 2.9 MMbbls of refined product and crude oil storage. The refinery and associated logistics network are located in Tacoma, Washington, and currently serve the Pacific Northwest market. On January 11, 2019, we completed the Washington Refinery Acquisition for a total purchase price of $326.7 million, including acquired net working capital, consisting of cash consideration of $289.7 million and approximately 2.4 million shares of our common stock issued to the seller of U.S. Oil. The Washington refinery's results of operations are included in our refining and logistics segments commencing January 11, 2019. 1

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Our Corporate and Other reportable segment primarily includes general and administrative costs. Please read Note 20— Segment Information to our consolidated financial statements under Item 8 of this Form 10-K for detailed information on our operating results by segment. Corporate Information Our common stock is listed and trades on the New York Stock Exchange (the "NYSE") under the ticker symbol “PARR.” Our principal executive office is located at 825 Town and Country Lane, Suite 1500, Houston, Texas 77024 and our telephone number is (281) 899-4800. Throughout this Annual Report on Form 10-K, the terms “Par,” “the Company,” “we,” “our,” and “us” refer to Par Pacific Holdings, Inc. and its consolidated subsidiaries unless the context suggests otherwise. Available Information Our website address is www.parpacific.com. Information contained on our website is not part of this Annual Report on Form 10-K. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any other materials filed with (or furnished to) the U.S. Securities and Exchange Commission (“SEC”) by us are available on our website (under “Investors”) free of charge, as soon as reasonably practicable after such reports are filed with, or furnished to, the SEC. Alternatively, you may access these reports at the SEC’s website at www.sec.gov. OPERATING SEGMENTS Refining Our refining segment buys and refines crude oil and other feedstocks into petroleum products (such as gasoline and distillates) at our Hawaii, Wyoming, and Washington refineries. Hawaii Refinery Our Hawaii refinery is located in Kapolei, Hawaii, on the island of Oahu and is rated at 148 Mbpd throughput capacity with a Nelson Complexity Index of 4.0. The Hawaii refinery’s major processing units include crude distillation, vacuum distillation, visbreaking, hydrocracking, naphtha hydrotreating, and reforming units, which produce ULSD, gasoline, jet fuel, marine fuel, LSFO, and other associated refined products. We believe the configuration of our Hawaii refinery uniquely fits the demands of the Hawaii market. The co-located refinery has two facility locations that are approximately two miles from one another: 1) Par East - Our legacy refinery assets, which we have owned and operated since the acquisition in 2013 from Tesoro Corporation ("Tesoro," which changed its name to Andeavor Corporation prior to being purchased by Marathon Petroleum Company in October 2018). 2) Par West - The recently-acquired assets from IES. We source our crude oil for the Hawaii refinery from North America, Asia, Latin America, Africa, the Middle East, and other sources. Crude oil is transported to Hawaii in tankers then discharged through our SPM or third-party logistics networks. Our three underwater pipelines from the SPM allow crude oil and refined products to be transferred to and from the Hawaii refinery. Crude oil is received into the Hawaii refinery tank farm, which includes 2.4 MMbbls of total owned crude oil storage, and/or third-party crude oil storage. We process the crude oil through various refining units into products and store them in the Hawaii refinery’s owned 2.5 MMbbls of refined and additional third-party product storage. This storage capacity allows us to manage the various product requirements of our customers in the state of Hawaii. We finance our Hawaii refinery hydrocarbon inventories through our Supply and Offtake Agreements with J. Aron & Company LLC (“J. Aron”). Under the Supply and Offtake Agreements, J. Aron holds title to all crude oil and refined product stored in tankage at the Hawaii refinery. We purchase crude oil from J. Aron on a daily basis at market prices and sell refined products to J. Aron as they are produced. We repurchase these refined products from J. Aron prior to selling them to third parties. 2

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Set forth below are summaries of the capacity of our Hawaii refinery as of December 31, 2018: Hawaii Refining Unit Capacity (Mbpd) Crude Units 148 Vacuum Distillation Units 75 Hydrocracker 19 Catalytic Reformer 13 Visbreaker 11 Naphtha Hydrotreater 13 Hawaii Refining Unit Capacity Hydrogen Plant (MMcfd) 18 Co-generation Turbine Unit (MW) 32 The Hawaii refinery operated at an average throughput of 74.9 Mbpd, or 78% utilization, to meet local demand for the year ended December 31, 2018. Below is a summary of our Hawaii refinery’s throughput percentage by type of crude oil and the product yield percentages for the years ended December 31, 2018, 2017, and 2016: Year Ended December 31, 2018 2017 2016 Feedstocks throughput (Mbpd) 74.9 73.7 70.2 Source of crude oil: North America 35.0% 23.8% 41.7% Asia 20.6% 23.1% 30.0% Africa 32.4% 24.9% 13.7% Latin America 1.0% 0.1% 3.9% Middle East 11.0% 28.1% 10.7% Total 100.0% 100.0% 100.0% Yield (% of total throughput): Gasoline and gasoline blendstocks 27.1% 27.8% 26.8% Distillates 47.4% 48.2% 44.7% Fuel oils 17.8% 15.7% 20.1% Other products 4.5% 5.0% 4.8% Total yield 96.8% 96.7% 96.4% Our Hawaii refining business transports refined products through our logistics network and sells to wholesale and bulk customers and to our retail business in Hawaii. Wholesale customers include jobbers and other non-end users, as well as 33 fueling stations where operations and consumer pricing are controlled by third parties. Bulk customers include utilities, military bases, marine vessels, industrial end-users, and exports. The profitability of our Hawaii refining business is heavily influenced by crack spreads in the Singapore market. This market reflects the closest liquid market alternative to source refined products for Hawaii. We believe the Singapore 4-1-2-1 crack spread (or four barrels of Brent crude oil converted into one barrel of gasoline, two barrels of distillate (diesel and jet fuel) and one barrel of fuel oil) best reflects a market indicator for our Hawaii refinery operations. During the course of 2018, the index exhibited high volatility with lows observed during the first quarter. The Singapore 4-1-2-1 crack spread averaged $7.22 per barrel during 2018 with a low of $6.38 per barrel average in the first quarter and a high of $8.23 per barrel average in the fourth quarter. 3

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Below is a summary of average crack spreads for the years ended December 31, 2018, 2017, and 2016: Year Ended December 31, 2018 2017 2016 4-1-2-1 Singapore Crack Spread $ 7.22 $ 7.18 $ 3.74 We are building a new 10 Mbpd Diesel Hydrotreater ("DHT") unit for an estimated cost of $27 million and we estimate project completion and startup to occur during the third quarter of 2019. The new unit is expected to allow us to convert an additional six to eight thousand barrels per day of intermediate products into jet fuel and/or ULSD and help position us for new regulations regarding marine fuels to be implemented in 2020 by the International Maritime Organization ("IMO 2020"). Wyoming Refinery Our Wyoming refinery is located in Newcastle, Wyoming, on approximately 121 fee-owned acres, and is rated at 18 Mbpd throughput capacity with a Nelson Complexity Index of 10.9. The Wyoming refinery’s major processing units include crude distillation, catalytic cracker, naphtha hydrotreating, and reforming units, which produce gasoline, ULSD, jet fuel, and other associated refined products. We source our crude oil for the Wyoming refinery from local producers in the Petroleum Administration for Defense District IV Rocky Mountain (“PADD IV”) region of the United States as well as other North American sources. Most of the crude oil is delivered to the refinery via our owned pipeline network and the rest is delivered by truck. Crude oil is received into the refinery tank farm and crude oil terminals, which include 256 Mbbls of total crude oil storage. We process the crude oil through various refining units into products and store them in the Wyoming refinery's 451 Mbbls of refined product tankage. The Wyoming refinery's storage capacity allows us to manage the various product requirements of our customers in the states of Wyoming and South Dakota and other targeted market destinations. Set forth below is a summary of the capacity of our Wyoming refinery as of December 31, 2018: Wyoming Refining Unit Capacity (Mbpd) Crude Unit 18 Residual Fluid Catalytic Cracker 7 Catalytic Reformer 3 Naphtha Hydrotreater 3 Diesel Hydrotreater 6 Isomerization 5 The Wyoming refinery operated at an average throughput of 16.4 Mbpd, or 91% utilization, for the year ended December 31, 2018. Below is a summary of the Wyoming refinery's product yield percentages for the years ended December 31, 2018 and 2017, and for the period from July 14, 2016 (the date of acquisition) to December 31, 2016: Year Ended Year Ended July 14, 2016 to December 31, December 31, December 31, 2018 2017 2016 Feedstocks Throughput (Mbpd) 16.4 15.5 15.8 Yield (% of total throughput): Gasoline and gasoline blendstocks 49.5% 51.9% 56.0% Distillate 45.8% 42.8% 39.3% Fuel oil 1.6% 2.2% 1.9% Other products 0.8% 0.8% 1.0% Total yield 97.7% 97.7% 98.2% Our Wyoming refining business sells refined products through our logistics network to wholesale, bulk, and retail customers primarily in the Rapid City, South Dakota, area. Products are also distributed by rail from our refinery to markets beyond our logistics network. 4

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The profitability of our Wyoming refinery is heavily influenced by crack spreads in nearby markets. We believe our Wyoming refining operations are best captured by the Wyoming 3-2-1 Index, or three barrels of WTI converted into two barrels of gasoline and one barrel of distillate (jet fuel and diesel). We believe the Wyoming 3-2-1 crack spread, a 50%/50% blend of Rapid City 3-2-1 and Denver 3-2-1 (WTI based) crack spreads, best reflects a market indicator for our Wyoming refining and fuel distribution operations. The Wyoming 3-2-1 Index averaged $22.69 per barrel during 2018 with a low of $15.65 per barrel average in the first quarter and a high of $26.25 per barrel average in the third quarter. Below is a summary of average crack spreads for the years ended December 31, 2018 and 2017, and for the period from July 14, 2016 (the date of acquisition) to December 31, 2016: Year Ended Year Ended July 14, 2016 to December 31, December 31, December 31, 2018 2017 2016 Wyoming 3-2-1 Index $ 22.69 $ 21.80 $ 16.27 Washington Refinery Our Washington refinery is located in Tacoma, Washington, on approximately 139 fee-owned acres, and is rated at 42 Mbpd throughput capacity with a Nelson Complexity Index of 5.4. The Washington refinery's major processing units include crude distillation, vacuum unit, jet treater, diesel hydrotreater, isomerization, and reforming units, which produce distillate, gasoline, asphalt, and other associated refined products that are primarily marketed in the Pacific Northwest. We source our crude oil for the Washington refinery primarily from Canadian and Bakken producers as well as other North American sources. Most of the crude oil is delivered to the refinery via our owned unit train facility and the rest is delivered by barge. Crude oil is received into the refinery tank farm, which includes 1.4 MMbbls of total crude oil storage. We process the crude oil through various refining units into products and store them in the refinery's 1.5 MMbbls of refined product tankage. This storage capacity allows us to manage the various product requirements of our customers in the state of Washington and other targeted market destinations. Set forth below is a summary of the capacity of our Washington refinery as of December 31, 2018: Washington Refining Unit Capacity (Mbpd) Crude Unit 42 Vacuum Unit 19 Naptha Hydrotreaters 10 Catalytic Reformers 6 Diesel Hydrotreater 8 Isomerization 4 Competition All facets of the energy industry are highly competitive. Our competitors include major integrated, national, and independent energy companies. Many of these competitors have greater financial and technical resources and staff which may allow them to better withstand and react to changing and adverse market conditions. Our refining business sources and obtains all of our crude oil from third-party sources and competes globally for crude oil and feedstocks. Our Hawaii refinery, through our facility with J. Aron, has access to a large variety of markets for crude oil imports and product exports. Please read “Item 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Commitments and Contingencies — Supply and Offtake Agreements” of this Form 10-K for further information. Our Wyoming refinery sources its crude oil and feedstocks primarily from the PADD IV region of the United States. Our Washington refinery utilizes an intermediation arrangement with Merrill Lynch and sources its crude oil and feedstocks primarily from North Dakota and Canada. Our Hawaii refinery product slate is tailored to meet local on-island demand. Outside the Hawaii market, our refined product sales from our Hawaii refinery typically target the Eastern Asia and U.S. West Coast markets. Our Wyoming refinery 5

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primarily sells refined products locally in the PADD IV region. Our Washington refinery primarily sells refined products in the Pacific Northwest region. Retail The retail segment includes 91 locations in Hawaii and 33 locations in Washington and Idaho where we set the price to the retail consumer. Of these, 34 of the Hawaii locations and all 33 Washington and Idaho locations are outlets operated by our personnel and include various sizes of kiosks, snack shops, or convenience stores. The remaining 57 Hawaii locations are cardlocks or sites operated by third parties where we retain ownership of the fuel and set retail pricing. We hold exclusive licenses within the state of Hawaii to utilize the “76” brand for retail locations. Since 2016, we have completed the rebranding of 39 out of our 91 fueling stations in Hawaii to Hele, a new proprietary brand. All of the manned Hawaii locations and one cardlock are currently operated under one of those brands (see table below). The “76” license agreement expires September 24, 2024, unless extended by mutual agreement. During 2018, we completed the rebranding of 24 of our 34 company- operated convenience stores in Hawaii to “nomnom,” a new proprietary brand. Our retail outlets in Washington and Idaho operate under the “Cenex®” and “Zip Trip®” brand names. As part of the Northwest Retail Acquisition, Par and CHS, Inc. entered into a multi-year branded petroleum marketing agreement for the continued supply of Cenex®-branded refined products to the 33 acquired Cenex® Zip Trip convenience stores. The following table shows our owned and leased retail outlets by location and type: Cenex® Zip Location and Channel of Trade “76” Brand Hele Brand Trip Brand Unbranded Total Oahu Company operated 2 18 — — 20 7-Eleven alliance 22 7 — — 29 Fee operated 5 3 — — 8 Cardlock — 1 — 3 4 Oahu total 29 29 — 3 61 Big Island Company operated 3 6 — — 9 Fee operated 3 — — — 3 Big Island total 6 6 — — 12 Maui Company operated 1 4 — — 5 Fee operated 2 — — — 2 Maui total 3 4 — — 7 Kauai Fee operated 3 — — — 3 Cardlock — — — 8 8 Kauai total 3 — — 8 11 Total for Hawaii locations 41 39 — 11 91 Washington Company operated — — 25 — 25 Washington total — — 25 — 25 Idaho Company operated — — 8 — 8 Idaho total — — 8 — 8 Total for Washington and Idaho locations — — 33 — 33 Total for Retail segment 41 39 33 11 124 6

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Competition Competitive factors that affect our retail performance include product price, station appearance, location, customer service, and brand awareness. Our Hawaii competitors include the Shell, Texaco, Costco, Safeway, and Sam’s Club national brands, regional brand Aloha, and other local retailers. Competitors of our Northwest Retail assets include the Chevron, Exxon, Conoco, Safeway, and Costco national brands, regional brands such as Maverik, Holiday, and Fred Meyer, and other local retailers. Logistics Our logistics segment generates revenues by charging fees for transporting crude oil to our refineries, delivering refined products to wholesale and bulk customers and to our retail business, and storing crude oil and refined products. Substantially all of our revenues from our logistics segment represent intercompany transactions that are eliminated in consolidation. Hawaii Logistics Our logistics network extends throughout the state of Hawaii. On Oahu, the system begins with our SPM located 1.7 miles offshore of our Hawaii refinery. This SPM allows for the safe, reliable, and efficient receipt of crude oil shipments to the Hawaii refinery, as well as both the receipt and export of finished products. Connecting the SPM to the Hawaii refinery are three undersea pipelines: a 30-inch line for crude oil, a 20-inch line, and a 16-inch line, both for the import or export of refined products. From the Hawaii refinery gate, we distribute refined products through our logistics network throughout the islands of Oahu, Maui, Hawaii, Molokai, and Kauai and for export to the U.S. West Coast and Asia. The Oahu logistics network includes a 27-mile wholly owned and operated pipeline network that transports refined products from our Hawaii refinery to delivery locations (the "Honolulu Products Pipeline"). The majority of our Oahu refined product volumes are distributed through the Honolulu Products Pipeline to (i) our leased and operated Sand Island terminal, (ii) the Honolulu International Airport, (iii) interconnections to Navy and Air Force fuel facilities, and (iv) a third-party terminal in Honolulu Harbor. In addition to the Honolulu Products Pipeline, we own four proprietary pipelines connecting our Hawaii refinery to Kalaeloa Barbers Point Harbor, approximately three miles from the Hawaii refinery. The four pipelines deliver refined products to barges for distribution to the neighboring islands or export, the local utility pipeline and storage network, and another third- party terminal on the west side of Oahu. The Oahu pipeline network is generally configured to be bidirectional, allowing for both delivery and receipt of products. In connection with the Hawaii Refinery Expansion, we entered into a long-term agreement with IES for storage and throughput at the Par West location. The agreement provides for the right to utilize 2 MMbbls barrels of dedicated crude and refined product storage, as well as certain IES logistics assets, including its off-shore mooring and Honolulu pipeline system. Crude oil is presently transferred to the Par West facility via the IES off-shore mooring and a 30-inch undersea pipeline. We have agreed to construct an on-shore pipeline manifold that will connect the IES pipeline into our owned SPM pipeline (the “Tie-In”). The Tie-In is expected to allow crude to be transferred from our SPM to the Par East facility and the Par West facility, the two locations of our co-located Hawaii refinery. The Tie-In provides operational flexibility and redundancy in the event of maintenance on the off-shore pipelines. It also allows us to avoid throughput charges for use of the IES off-shore mooring. The Tie-In is expected to be completed in mid-2019. Our terminal facilities on Oahu include our Sand Island facility that comprises two tanks with a total capacity of 30 Mbbls, as well as contractual rights to utilize strategically located third-party facilities both near the Hawaii refinery and at Honolulu Harbor near downtown. We also operate a proprietary trucking business on Oahu to distribute gasoline and road diesel to the final point of sale. Our logistics network for the islands neighboring Oahu consists of leased barge equipment and refined product tankage and proprietary trucking operations on the islands of Maui, Hawaii, Molokai, and Kauai. Specifically, we charter two barges to serve our neighbor island markets. This includes the Nale with 86 Mbbls of capacity and the Ne’ena with 52 Mbbls of capacity. In addition to neighbor island deliveries, the Ne’ena is utilized to service our bunker fuel customers, such as passenger cruise ships and container vessels. We also lease the barge Capella primarily for the import of ethanol from the U.S. West Coast with periodic backhauls of refined products for sale in the Pacific Northwest. The barges deliver to, and product is dispensed from, a neighbor island network of seven petroleum terminals with total storage capacity of 301 Mbbls. 7

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Wyoming Logistics Our Wyoming logistics network includes a 140-mile crude oil pipeline gathering system that provides us access to crude oil from the Powder River Basin. This network also includes a 40-mile refined products pipeline that transports product from our Wyoming refinery to a common carrier with access to Rapid City, South Dakota. The logistics network in Wyoming includes storage, loading racks, and a rail siding at the refinery site. Our crude oil and refined product tanks at the Wyoming refinery have a total capacity of 470 Mbbls. We also own and operate a jet fuel storage facility and pipeline that serve Ellsworth Air Force Base in South Dakota. Washington Logistics Our Washington logistics network includes 2.9 MMbbls of storage capacity, a proprietary 14-mile jet fuel pipeline, a marine terminal with 15 acres of waterfront property, a unit train-capable rail loading terminal with 107 unloading spots, and a truck rack with six truck lanes and 10 loading arms. These assets provide connectivity to Bakken, Canadian, and Alaskan crude oil and the Pacific, West Coast, Pacific Northwest, and Rockies product markets. Hawaii Market The Hawaii State Department of Business, Economic Development, and Tourism (“DBEDT”) projected Hawaii’s economic growth at 1% for 2018, continuing the trend of positive but slower growth. Hawaii’s economic growth rate is expected to increase to 1.8% in 2019. With tourism as the principal engine behind Hawaii’s economy, the state registered a record 9.9 million visitor arrivals in 2018, a 6% increase over 2017, and continuing a seven year trend of growth. The corresponding nominal visitor expenditures increased nearly 7%. Total number of air seats on scheduled flights to Hawaii, a leading indicator of the tourism industry, increased 8% during 2018. According to available airline schedules, scheduled air seats to Hawaii during the first nine months of 2019 are expected to increase by 0.3%, leading to an expected arrival growth of approximately 1.8% in 2019. Demand for jet fuel is somewhat higher in Hawaii during the winter months than during the summer months as tourism increases during the winter months. Refining margins remain volatile and our results of operations may not reflect these historical seasonal trends. Pacific Northwest and Rockies Markets Spokane, Washington, and Northwest Idaho are the primary regions of our Pacific Northwest retail operations and the U.S. Census Bureau projected that the population increased 1.5% in Washington and 2.1% in Idaho from 2017 to 2018. Spokane is a regional hub in eastern Washington, with a population of over a half million and a variety of employers in the health care, retail, and other industries. According to the U.S. Bureau of Economic Analysis, personal income for the Spokane metro area grew by 3.3% between 2016 and 2017, continuing the trend of positive growth since the 2008-2009 recession. Additionally, Amazon is constructing a new fulfillment center near the Spokane International Airport that is anticipated to open in late 2019, and future regional growth and increased traffic is expected. The primary market for our Wyoming refined products is the Black Hills Region in South Dakota, driven largely by Pennington, Lawrence, and Meade Counties, which represents nearly half of the state’s taxable tourism sales. According to the U.S. Census Bureau, the population in Pennington County, the state's second largest county, increased by 1.1% from 2016 to 2017. According to the U.S. Bureau of Economic Analysis, personal income in South Dakota grew by 4.9% between the fourth quarter of 2017 and the first quarter of 2018. Unemployment in South Dakota continues to remain below the national average unemployment rate at 3%. Demand for gasoline is highly seasonal, with a large increase in demand during the summer driving season. The South Dakota economy is anchored by tourism, including visitors to Mount Rushmore and the Black Hills, as well as government and health care spending. The South Dakota tourism industry has grown for the ninth consecutive year. Visitor spending in South Dakota was approximately $4.0 billion in 2018, an increase of 2.5% over 2017, and there were approximately 14.1 million visitors, a 1.4% increase as compared to 2017. In 2018, $920 million, or 23%, of tourism dollars were spent on transportation services. We also distribute refined products to customers in central and northeastern Wyoming. The economy in Wyoming is sensitive to demand for Powder River Basin coal and other locally-produced commodities. Coal mine production in the Powder River Basin increased 18.9% in the third quarter as compared to the second quarter of 2018, however production still declined year-over-year. 8

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OTHER OPERATIONS Laramie Energy As of December 31, 2018, we own a 46.0% equity investment in Laramie Energy, a joint venture entity focused on producing natural gas in Garfield, Mesa, and Rio Blanco Counties, Colorado. On March 1, 2016, Laramie Energy acquired certain properties in the Piceance Basin for $152.1 million. The acquired properties consisted of approximately 249 billion cubic feet equivalent of proved developed producing reserves as of December 31, 2016, more than 53 thousand net operated acres, and more than 18 thousand net non-operated acres. On February 28, 2018, Laramie Energy closed on a purchase and contribution agreement with an unaffiliated third party that contributed all of its oil and gas properties located in the Piceance Basin to Laramie Energy, consisting of approximately 24 billion cubic feet equivalent of proved developed producing reserves. The acquired and existing properties produce primarily from the Mesaverde Formation and, to a lesser extent, the Mancos Formation. The majority of the acquired acreage is adjacent to Laramie Energy’s existing assets. As of December 31, 2018, the estimated proved reserves we own indirectly through Laramie Energy are as follows: Gas Oil NGLs Total (MMcf) (Mbbls) (Mbbls) (MMcfe) Company’s share of Laramie Energy Proved developed 256,363 1,420 8,868 318,091 Proved undeveloped 81,428 325 3,715 105,668 Total 337,791 1,745 12,583 423,759 For more information regarding our proved undeveloped reserves, please read “Item 2. — Properties — Reserves — Proved Undeveloped Reserves” of this Form 10-K. The following table presents the estimated future net cash flows related to proved developed producing, proved developed non-producing, and proved undeveloped reserves that we own indirectly through Laramie Energy as of December 31, 2018 (in thousands): Proved Proved Developed Developed Non- Proved Producing producing Undeveloped Total (1) Estimated future undiscounted net cash flows $ 469,132 $ — $ 138,100 $ 607,232 Standardized measure of discounted future net cash flows 268,436 — 50,666 319,102 ________________________________________________ (1) Prices are based on the historical first-day-of-the-month twelve-month average posted price depending on the area. These prices are adjusted for quality, energy content, regional price differentials, and transportation fees. All prices are held constant throughout the lives of the properties. The average adjusted prices are $61.44 per barrel of crude oil, $22.40 per barrel of natural gas liquids, and $2.65 per Mcf of natural gas. Reconciliation of Standardized Measure to PV-10 PV-10 is the estimated present value of the future net revenues calculated based on our estimated proved reserves before income taxes discounted using a 10% discount rate. PV-10 is considered a non-GAAP financial measure under SEC regulations because it does not include the effects of future income taxes, as is required in computing the standardized measure of discounted future net cash flows. This measure should not be considered a substitute for, or superior to, measures prepared in accordance with U.S. generally accepted accounting principles (“GAAP”). We believe that PV-10 is an important measure that can be used to evaluate the relative significance of our natural gas and oil properties to other companies and that PV-10 is widely used by securities analysts and investors when evaluating oil and gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, the use of a pre-tax measure provides greater comparability of assets when evaluating companies. PV-10 is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting income taxes. 9

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The following table provides a reconciliation of our share of Laramie Energy's standardized measure of discounted future net cash flows to PV-10 at December 31, 2018 (in thousands): Standardized measure of discounted future net cash flows $ 319,102 Present value of future income taxes discounted at 10% (1) — PV-10 $ 319,102 ________________________________________________ (1) There is no present value of future income taxes as we believe we have sufficient net operating loss carryforwards to offset any income. Please read Note 19—Income Taxes to our consolidated financial statements under Item 8 of this Form 10-K for further information. For more information on our natural gas and oil operations, please read “Item 2. — Properties” of this Form 10-K. Competition The natural gas and oil business is highly competitive. The principal markets for natural gas and oil are refineries and transmission companies that have facilities near Laramie Energy’s producing properties. Natural gas and oil produced from Laramie Energy’s wells are normally sold to various purchasers. Natural gas wells are connected to pipelines generally owned by the natural gas purchasers. A variety of pipeline transportation charges are usually included in the calculation of the price paid for the natural gas. Crude oil is picked up and transported by the purchaser from the wellhead. In some instances, Laramie Energy is charged a fee for the cost of transporting the crude oil, which is deducted from or accounted for in the price paid for the crude oil. BANKRUPTCY AND PLAN OF REORGANIZATION Background and General Recovery Trust In 2011 and 2012, our predecessor, Delta Petroleum Corporation (“Delta”) and its subsidiaries (collectively “Debtors”) filed voluntary petitions under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the District of Delaware ("Bankruptcy Court"). In March 2012, the Debtors obtained approval from the Bankruptcy Court to proceed with Laramie as the sponsor of a plan of reorganization (“Plan”). Delta emerged from bankruptcy, amended and restated its certificate of incorporation and bylaws, changed its name to Par Petroleum Corporation, and contributed the majority of its natural gas and oil properties to Laramie Energy on August 31, 2012 (the "Emergence Date"). The reorganization converted approximately $265 million of unsecured debt to equity and allowed us to preserve significant tax attributes. On the Emergence Date, the Delta Petroleum General Recovery Trust (“General Trust”) was formed to pursue certain litigation against third parties or causes of action under the U.S. Bankruptcy Code and other claims and potential claims that the Debtors hold against third parties. The General Trust was funded with $1.0 million pursuant to the Plan. The General Trust is pursuing all bankruptcy causes of action, claim objections, and resolutions and is responsible for winding up the bankruptcy. Upon liquidation of the various claims and causes of action held by the General Trust, the proceeds, less certain administrative reserves and expenses, will be transferred to us. It is unknown at this time what proceeds, if any, we will realize from the General Trust’s litigation efforts. Through December 31, 2013, the General Trust released approximately $5.2 million to us, which was available for our general use, due to a negotiated reduction in certain fees and claims associated with the bankruptcy, as well as a favorable variance in actual expenses versus budgeted expenses. No funds were released during the year ended December 31, 2018. Shares Reserved for Unsecured Claims The Plan provides that certain allowed general unsecured claims be paid with shares of our common stock. Pursuant to the Plan, allowed claims are settled at a ratio of 54.4 shares per $1,000 of claim. As of December 31, 2018, two related claims totaling approximately $22.4 million remained to be resolved by the Recovery Trustee. One of the two remaining claims was filed by the U.S. Government for approximately $22.4 million relating to ongoing litigation concerning a plugging and abandonment obligation in Pacific Outer Continental Shelf Lease OCS-P 0320, comprising part of the Sword Unit in the Santa Barbara Channel, California. The second unliquidated claim, which is related to the same plugging and abandonment obligation, was filed by Noble Energy Inc., the operator and majority interest owner of the Sword Unit. We believe the probability of issuing shares to satisfy the full claim amount is remote, as the obligations upon which such proof of claim is asserted are joint and several among all working interest owners and Delta, our predecessor, owned an approximate 3.4% aggregate working interest in the unit. The settlement of claims is subject to ongoing litigation and we are unable to predict with certainty how many shares will be required to satisfy all claims. We have accrued approximately $0.5 million representing the estimated value of claims remaining to be settled which are deemed probable and estimable at December 31, 2018. Please read “Item 7. – Management’s Discussion 10

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and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Commitments and Contingencies – Bankruptcy Matters” of this Form 10-K for further information. Closing of the Bankruptcy Cases On February 27, 2018, the Bankruptcy Court entered its final decree closing the Chapter 11 bankruptcy cases of Delta and the other Debtors, discharging the Recovery Trustee, and finding that all assets of the General Trust were resolved, abandoned, or liquidated and have been distributed in accordance with the requirements of the Plan. In addition, the final decree required the Company or the General Trust, as applicable, to maintain the current reserves owed on account of the remaining claims of the U.S. Government and Noble Energy, Inc. ENVIRONMENTAL REGULATIONS General Our activities are subject to existing federal, state, and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, we believe that, absent the occurrence of an extraordinary event, compliance with existing federal, state, and local laws, regulations, and rules regulating the release of materials in the environment or otherwise relating to the protection of human health, safety, and the environment will not have a material effect upon our capital expenditures, earnings, or competitive position with respect to our existing assets and operations. We cannot predict what effect additional regulation or legislation, enforcement policies, and claims for damages to property, employees, other persons, and the environment resulting from our operations could have on our activities. Periodically, we receive communications from various federal, state, and local governmental authorities asserting violations of environmental laws and/or regulations. These governmental entities may also propose or assess fines or require corrective actions for these asserted violations. We intend to respond in a timely manner to all such communications and to take appropriate corrective action. We do not anticipate that any such matters currently asserted will have a material impact on our financial condition, results of operations, or cash flows. Refining activities Like other petroleum refiners, our operations are subject to extensive and periodically changing federal and state environmental regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities. Many of these regulations are becoming increasingly stringent and the cost of compliance can be expected to increase over time. Our policy is to accrue environmental and clean-up related costs of a non-capital nature when it is probable that a liability has been incurred and the amount can be reasonably estimated. Such estimates may be subject to revision in the future as regulations and other conditions change. Natural gas and oil production Our activities with respect to exploration and production of natural gas and oil, including the drilling of wells and the operation and construction of pipelines, plants, and other facilities for extracting, transporting, processing, treating, or storing natural gas, crude oil, and other petroleum products, are subject to stringent environmental regulation by state and federal authorities, including the U.S. Environmental Protection Agency (“EPA”). Such regulation can increase the costs of planning, designing, installing, and operating such facilities. Although we believe that compliance with environmental regulations will not have a material adverse effect on us, risks of substantial costs and liabilities are inherent in natural gas and oil production, transport, and storage operations and there can be no assurance that significant costs and liabilities will not be incurred. Moreover, it is possible that other developments, such as spills or other unanticipated releases, stricter environmental laws and regulations, and claims for damages to property or persons resulting from oil and gas production, transport, or storage would result in substantial costs and liabilities to us. Climate Change and Regulation of Greenhouse Gases According to certain scientific studies, emissions of CO2, methane, nitrous oxide, and other gases commonly known as greenhouse gases (“GHGs”) may be contributing to global warming of the earth’s atmosphere and to global climate change. In response to the scientific studies, legislative and regulatory initiatives have been underway to limit GHG emissions. The U.S. Supreme Court determined that GHG emissions fall within the federal Clean Air Act (“CAA”) definition of an “air pollutant.” In response, the EPA promulgated an endangerment finding, paving the way for regulation of GHG emissions under the CAA. The EPA has now begun regulating GHG under the CAA. New construction or material expansions that meet certain GHG emissions thresholds will likely require that, among other things, a GHG permit be issued in accordance with the CAA regulations and we will be required in connection with such permitting to undertake a technology review to determine appropriate controls to be 11

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implemented with the project in order to reduce GHG emissions. Based on current company operations, however, our natural gas and oil exploration and production activities and our existing refining activities are not subject to current federal GHG permitting requirements. Furthermore, the EPA is developing refinery-specific GHG regulations and performance standards that are expected to impose GHG emission limits and/or technology requirements. These control requirements may affect a wide range of refinery operations. Any such controls could result in material increased compliance costs, additional operating restrictions for our business, and an increase in cost of the products we produce, which could have a material adverse effect on our financial position, results of operations, and liquidity. We believe it is unlikely that such additional GHG requirements will be finalized in the near term. The EPA has also promulgated rules requiring large sources to report their GHG emissions. Reports are being made in connection with our refining business. Sources subject to these reporting requirements also include on and offshore petroleum and natural gas production and onshore natural gas processing and distribution facilities that emit 25,000 metric tons or more of CO2 equivalent per year in aggregate emissions from all site sources. To date, our natural gas and oil exploration and production activities are not subject to GHG reporting requirements. In 2007, the State of Hawaii passed Act 234, which required that GHG emissions be rolled back on a statewide basis to 1990 levels by the year 2020. Although delayed, the Hawaii Department of Health (“DOH”) has issued regulations that would require each major facility to reduce CO2 emissions by 16% by 2020 relative to a calendar year 2010 baseline (the first year in which GHG emissions were reported to the EPA under 40 CFR Part 98). The GHG rules include an alternative for facilities to demonstrate that further GHG reductions are not economically viable and an additional provision that authorized the DOH to issue a waiver if GHGs are being effectively controlled as a consequence of other state initiatives and regulations such as the Renewable Portfolio Standard. The capacity of our co-located refinery in Hawaii to further reduce fuel use and GHG emissions is limited. Since Hawaii’s GHG emissions have already been reduced below 2010 levels and are projected to be less than the 1990 levels by 2020, we anticipate our refinery in Hawaii will be able to demonstrate that no further reductions are required to meet the statewide goal. Any reductions imposed by the 16% facility-specific mandate would not be cost effective and therefore should not be required. Additionally, the regulation allows for “partnering” with other facilities (principally power plants) which have already dramatically reduced GHG emissions or are on schedule to reduce CO2 emissions in order to comply with the state’s Renewable Portfolio Standards. Regulation of GHG emissions is fairly new and highly controversial. Further regulatory, legislative, and judicial developments are likely to occur in the future. Such developments may affect how these GHG initiatives will impact us. They may also impact the use of and demand for petroleum products, which could impact our business. Further, apart from these developments, tort claims alleging property damage against GHG emissions sources may be asserted. Due to the uncertainties surrounding the regulation of and other risks associated with GHG emissions, we cannot predict the financial impact of related developments on us. National Ambient Air Quality Standards Over the past several years the EPA has adopted a number of new and more stringent National Ambient Air Quality Standards (“NAAQS”). Specifically new NOX and SO2 standards were set in 2010 and a new particulate matter standard was set in 2012. States are required to develop State Implementation Plans and ultimately local air districts are required to adopt rules that will (over time) improve the air quality so that it will be “In Attainment” with the existing and new NAAQS. More stringent air pollutant standards and corresponding rules have already impacted and will continue to cause many refineries to invest heavily in additional air pollution controls. Thus far, Hawaii air quality, particularly on Oahu where our Hawaii refinery is located, has met even the most recent NAAQS and the Hawaii refinery has not been required to install new controls as result of local rules. Even so, NAAQS could and, to a degree, have already forced some changes for our customer base. Power plants on the Big Island, where SO2 levels are already elevated due to volcanic activity, are switching from LSFO to diesel fuel. On Oahu, the state’s largest utility frequently cites compliance with NAAQS as one of its justifications for moving towards a cleaner bridge fuel, potentially diesel or liquefied natural gas, before reaching its renewable goals. On October 1, 2015, the EPA adopted rules that would substantially tighten the NAAQS for ground-level ozone. This rule will cause many areas of the country to fall out of attainment and for the affected states to require additional controls and limits on combustion emissions and emissions of volatile organic compounds. We do not currently anticipate that the more stringent NAAQS will impact our Hawaii, Washington, or Wyoming operations. Fuel Standards In 2007, the U.S. Congress passed the Energy Independence and Security Act (“EISA”) which, among other things, set a target fuel economy standard of 35 miles per gallon for the combined fleet of cars and light trucks in the U.S. by model year 2020 and contained an expanded Renewable Fuel Standard (the “RFS2”). In August 2012, the EPA and National Highway Traffic Safety Administration ("NHTSA") jointly adopted regulations that establish an average industry fuel economy of 54.5 miles per 12

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gallon by model year 2025. On August 8, 2018, the EPA and NHTSA jointly proposed to revise existing fuel economy standards for model years 2021-2025 and to set standards for 2026 for the first time. The agencies have not yet issued a final rule, but they are expected to do so in 2019. Although the revised fuel economy standards are expected to be less stringent than the initial standards for model years 2021-2025, it is uncertain whether the revised standards will increase year over year. Higher fuel economy standards have the potential to reduce demand for our refined transportation fuel products. Under EISA, the RFS2 requires an increasing amount of renewable fuel to be blended into the nation's transportation fuel supply, up to 36.0 billion gallons by 2022. In the near term, the RFS2 will be satisfied primarily with fuel ethanol blended into gasoline. We, and other refiners subject to the EPA issued Renewable Fuel Standard (“RFS”), may meet the RFS requirements by blending the necessary volumes of renewable fuels produced by us or purchased from third parties. To the extent that refiners will not or cannot blend renewable fuels into the products they produce in the quantities required to satisfy their obligations under the RFS program, those refiners must purchase renewable credits, referred to as Renewable Identification Numbers (“RINs”), to maintain compliance. To the extent that we exceed the minimum volumetric requirements for blending of renewable fuels, we generate our own RINs for which we have the option of retaining the RINs for current or future RFS compliance or selling those RINs on the open market. The RFS2 may present production and logistics challenges for both the renewable fuels and petroleum refining and marketing industries in that we may have to enter into arrangements with other parties or purchase D3 waivers from the EPA to meet our obligations to use advanced biofuels, including biomass-based diesel and cellulosic biofuel, with potentially uncertain supplies of these new fuels. In October 2010, the EPA issued a partial waiver decision under the federal CAA to allow for an increase in the amount of ethanol permitted to be blended into gasoline from 10% (“E10”) to 15% (“E15”) for 2007 and newer light duty motor vehicles. In January 2011, the EPA issued a second waiver for the use of E15 in vehicles model years 2001-2006. In 2019, EPA is expected to conduct a rulemaking to allow year-round sales of E15. There are numerous issues, including state and federal regulatory issues, which need to be addressed before E15 can be marketed on a large scale for use in traditional gasoline engines; however, increased renewable fuel in the nation's transportation fuel supply could reduce demand for our refined products. In March 2014, the EPA published a final Tier 3 gasoline standard that requires, among other things, that gasoline contain no more than 10 parts per million (“ppm”) sulfur on an annual average basis and no more than 80 ppm sulfur on a per-gallon basis. The standard also lowers the allowable benzene, aromatics, and olefins content of gasoline. The effective date for the new standard is January 1, 2017, however, approved small volume refineries have until January 1, 2020 to meet the standard. Our Hawaii refinery is required to comply with Tier 3 gasoline standards within 30 months of June 21, 2016, the date our Hawaii refinery was disqualified from small volume refinery status. On March 19, 2015, the EPA confirmed the small refinery status of our Wyoming refinery. The Par East facility of our Hawaii refinery, our Wyoming refinery, and our Washington refinery were all granted small refinery status by the EPA for 2017. The EPA is expected to make small refinery status determinations for 2018 in the first quarter of 2019. Beginning on June 30, 2014, new sulfur standards for fuel oil used by marine vessels operating within 200 miles of the U.S. coastline (which includes the entire Hawaiian Island chain) was lowered from 10,000 ppm (1%) to 1,000 ppm (0.1%). The sulfur standards began at the Hawaii refinery and were phased in so that by January 1, 2015, they were to be fully aligned with the International Marine Organization (“IMO”) standards and deadline. The more stringent standards apply universally to both U.S. and foreign flagged ships. Although the marine fuel regulations provided vessel operators with a few compliance options such as installation of on-board pollution controls and demonstration unavailability, many vessel operators will be forced to switch to a distillate fuel while operating within the Emission Control Area (“ECA”). Beyond the 200 mile ECA, large ocean vessels are still allowed to burn marine fuel with up to 3.5% sulfur. Our Hawaii refinery is capable of producing the 1% sulfur residual fuel oil that was previously required within the ECA. Although our Hawaii refinery remains in a position to supply vessels traveling to and through Hawaii, the market for 0.1% sulfur distillate fuel and 3.5% sulfur residual fuel is much more competitive. In addition to U.S. fuels requirements, the IMO has also adopted newer standards that further reduce the global limit on sulfur content in maritime fuels to 0.5% beginning in 2020 ("IMO 2020"). Like the rest of the refining industry, we are focused on meeting these standards and may incur costs in producing lower-sulfur fuels. There will be compliance costs and uncertainties regarding how we will comply with the various requirements contained in the EISA, IMO 2020, and other fuel-related regulations. We may experience a decrease in demand for refined petroleum products due to an increase in combined fleet mileage or due to refined petroleum products being replaced by renewable fuels. Solid and Hazardous Waste Several of our businesses generate wastes, including hazardous wastes, which are subject to regulation under the federal Resource Conservation and Recovery Act (“RCRA”) and state statutes. The EPA has limited the disposal options for certain hazardous wastes and state regulation of the handling and disposal of refining and natural gas and oil exploration and production wastes and solid wastes is becoming more stringent. Furthermore, it is possible that certain wastes generated by our natural gas 13

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and oil operations which are currently exempt from regulation as “hazardous wastes” may in the future be designated as “hazardous wastes” under RCRA or other applicable statutes and therefore be subject to more rigorous and costly disposal requirements. Naturally Occurring Radioactive Materials (“NORM”) are radioactive materials that accumulate on production equipment or area soils during oil and natural gas extraction or processing. Primary responsibility for NORM regulation has been a state function. Standards have been developed for worker protection; treatment, storage, and disposal of NORM waste; management of waste piles, containers, and tanks; and limitations upon the release of NORM-contaminated land for unrestricted use. We believe that our operations are in material compliance with all applicable NORM standards. Our natural gas and oil properties have been operated by third parties that controlled the treatment of hydrocarbons or other solid wastes and the manner in which such substances may have been disposed or released. State and federal laws applicable to refineries and to natural gas and oil wastes and properties have gradually become stricter over time. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed or released by prior owners or operators) or property contamination (including groundwater contamination by prior owners or operators) or to perform remedial operations to prevent future contamination. Superfund The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on certain persons with respect to the release or threatened release of a “hazardous substance” into the environment. These persons include the current owner and operator of a site, any former owner or operator who operated the site at the time of a release, transporters, and persons that disposed or arranged for the disposal of hazardous substances at a site. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible persons the costs of such action. State statutes impose similar liability. Under CERCLA, the term “hazardous substance” does not include “petroleum, including crude oil or any fraction thereof,” unless specifically listed or designated and the term does not include natural gas, NGLs, liquefied natural gas, or synthetic gas usable for fuel. While this “petroleum exclusion” lessens the significance of CERCLA to our exploration and production operations, we may generate wastes that may fall within CERCLA’s definition of a “hazardous substance” in the course of our ordinary refining and natural gas and oil operations. Although we and, to our knowledge, our predecessors have used operating and disposal practices that were standard in the industry at the time, “hazardous substances” may have been disposed or released on, under, or from the properties currently or historically owned or leased by us or on, under, or from other locations where these wastes have been taken for disposal. At this time, we do not believe that we have any liability associated with any Superfund site and we have not been notified of any claim, liability, or damages under CERCLA. Oil Pollution Act The Oil Pollution Act of 1990 (“OPA”) and regulations thereunder impose a variety of requirements on “responsible parties” related to the prevention of crude oil spills and liability for damages resulting from such spills in U.S. waters. A “responsible party” includes the owner or operator of a facility or vessel or the lessee or permittee of the area in which an offshore facility is located. While liability limits apply in some circumstances, few defenses exist to the liability imposed by the OPA. The OPA establishes a liability limit for onshore facilities of $633.85 million and for offshore facilities of all removal costs plus $137.66 million, with lesser limits for some vessels depending upon their size. The regulations promulgated under OPA impose proof of financial responsibility requirements that can be satisfied through insurance, guarantee, indemnity, surety bond, letter of credit, qualification as a self-insurer, or a combination thereof. Failure to comply with OPA’s requirements or inadequate cooperation during a spill response action may subject a responsible party to civil or criminal enforcement actions. Further, the U.S. Congress has considered legislation that could increase our obligations and potential liability under the OPA, including by eliminating the current cap on liability for damages and increasing minimum levels of financial responsibility. It is uncertain whether, and in what form, such legislation may ultimately be adopted. We are not aware of the occurrence of any action or event that would subject us to liability under OPA and we believe that compliance with OPA’s financial responsibility and other operating requirements will not have a material adverse effect on us. Discharges and Marine Protection The Clean Water Act (“CWA”) regulates the discharge of pollutants to waters of the U.S., including wetlands, and requires a permit for the discharge of pollutants, including petroleum, to such waters. Certain facilities that store or otherwise handle crude oil are required to prepare and implement Spill Prevention, Control, and Countermeasure and Facility Response Plans relating to the possible discharge of oil to surface waters. We are required to prepare and comply with such plans and to obtain and comply with discharge permits. We believe we are in substantial compliance with these requirements and that any noncompliance would 14

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not have a material adverse effect on us. The CWA also prohibits spills of oil and hazardous substances to waters of the U.S. in excess of levels set by regulations and imposes liability in the event of a spill. Other statutes provide protection to animal and plant species. These laws and regulations may require the acquisition of a permit or other authorization before drilling or construction related to the oil and gas industry commences and may limit or prohibit construction, drilling, and other activities on certain lands lying within wilderness or wetlands and other protected areas and impose substantial liabilities for pollution resulting from our operations. For example, the Magnuson amendment to the Marine Mammal Protection Act may limit or restrict certain new oil terminals and oil-by-rail infrastructure in the State of Washington. State laws further regulate discharges of pollutants to surface and groundwaters, require permits that set limits on discharges to such waters, and provide civil and criminal penalties and liabilities for spills to both surface and groundwaters. Some states have imposed regulatory requirements to respond to concerns related to potential for groundwater impact from oil and gas exploration and production. For example, the Colorado Oil and Gas Conservation Commission (“COGCC”) approved rules that require sampling of groundwater for hydrocarbons and other indicator compounds both before and after drilling. Hydraulic Fracturing Our and Laramie Energy’s exploration and production activities may involve the use of hydraulic fracturing techniques to stimulate wells and maximize natural gas production. Some states and localities now regulate the utilization of hydraulic fracturing and other states and localities are in the process of developing, or are considering development of, such rules. A state ballot initiative was introduced in Colorado that would have required oil and gas wells to be at least 2,500 feet from homes and other occupied buildings. This initiative was rejected, but similar legislative action could subject Laramie Energy’s drilling activities to new or enhanced federal, state, and/or local regulatory requirements, including requirements that could restrict the areas in which Laramie Energy is able to operate. Air Emissions Our refining operations and our and Laramie Energy’s exploration and production operations are subject to local, state, and federal regulations for the control of emissions from sources of air pollution. Administrative enforcement actions for failure to comply strictly with air regulations or permits may be resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could impose civil and criminal liability for non-compliance. An agency could require us to forego construction or operation of certain air emission sources. We believe that we are in substantial compliance with air pollution control requirements and that, if a particular permit application were denied, we would have enough permitted or permittable capacity to continue our operations without a material adverse effect on any particular producing field. Our refining business is subject to very significant state and federal air permitting and pollution control requirements, including some that are the subject of ongoing enforcement activities by the EPA as described in more detail below. The EPA continues to review and, in many cases, tighten ambient air quality standards, which standards, along with the advancement of pollution control technologies, could result in new regulatory and permit requirements that will impact our refining activities and involve additional costs. On September 29, 2015, the EPA announced a final rule updating standards that control toxic air emissions from petroleum refineries, addressing, among other things, flaring operations, fenceline air quality monitoring, and additional emission reductions from storage tanks and delayed coking units. Affected existing sources were required to comply with the new requirements no later than 2018, with certain refiners required to comply earlier depending on the relevant provision and refinery construction date. Compliance with this rule has not had a material impact on our financial condition, results of operations, or cash flows to date. More stringent regulation may be imposed in the future as a result of public concern about the impacts of increased oil and gas drilling activity and the availability of new information. For example, the Colorado Department of Natural Resources and the Colorado Department of Public Health and the Environment completed a study of emissions tied to oil and gas development in areas along the northern Front Range of the Rocky Mountains. It is unclear what regulatory or legislative action will be taken in response to this study and we are unable to predict the financial impact of such developments on our company going forward. Coastal Coordination There are various federal and state programs that regulate the conservation and development of coastal resources. The federal Coastal Zone Management Act (“CZMA”) was passed to preserve and, where possible, restore the natural resources of the coastal zone of the U.S. The CZMA provides for federal grants for state management programs that regulate land use, water use, and coastal development. 15

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Environmental Agreement On September 25, 2013 (the “Closing Date”), Par Petroleum, LLC (formerly known as Hawaii Pacific Energy; a wholly owned subsidiary of Par created for purposes of acquiring Par Hawaii Refining, LLC ("PHR")), Tesoro, and PHR entered into an Environmental Agreement (“Environmental Agreement”), which allocated responsibility for known and contingent environmental liabilities related to the acquisition of PHR as follows: Consent Decree On July 18, 2016, PHR and subsidiaries of Tesoro entered into a consent decree with the EPA, the U.S. Department of Justice (“DOJ”), and other state governmental authorities concerning alleged violations of the federal CAA related to the ownership and operation of multiple facilities owned or formerly owned by Tesoro and its affiliates (“Consent Decree”), including the Par East facility of our Hawaii refinery. As a result of the Consent Decree, PHR expanded its previously-announced 2016 turnaround to undertake additional capital improvements to reduce emissions of air pollutants and to provide for certain NOx and SO2 emission controls and monitoring required by the Consent Decree. Although the turnaround was completed during the third quarter of 2016, work related to the Consent Decree is ongoing. This work subjects us to risks associated with engineering, procurement, and construction of improvements and repairs to our facilities and related penalties and fines to the extent applicable deadlines under the Consent Decree are not satisfied, as well as risks related to the performance of equipment required by, or affected by, the Consent Decree. Each of these risks could have a material adverse effect on our business, financial condition, or results of operations. Tesoro is responsible under the Environmental Agreement for directly paying, or reimbursing PHR, for all reasonable third-party capital expenditures incurred pursuant to the Consent Decree to the extent related to acts or omissions prior to the closing date of the acquisition of PHR. Tesoro is obligated to pay all applicable fines and penalties related to the Consent Decree. Through December 31, 2018, Tesoro has reimbursed us for $12.2 million of our total capital expenditures incurred in connection with the Consent Decree. As of December 31, 2018, all reimbursable capital expenditures incurred pursuant to the Consent Decree were collected. Net capital expenditures and reimbursements related to the Consent Decree are presented within Capital expenditures on our consolidated statement of cash flows for the years ended December 31, 2018 and 2017. Please read Note 15—Commitments and Contingencies to our consolidated financial statements under Item 8 of this Form 10-K for more information. Indemnification In addition to its obligation to reimburse us for capital expenditures incurred pursuant to the Consent Decree, Tesoro agreed to indemnify us for claims and losses arising out of related breaches of Tesoro’s representations, warranties, and covenants in the Environment Agreement, certain defined “corrective actions” relating to pre-existing environmental conditions, third-party claims arising under environmental laws for personal injury or property damage arising out of, or relating to, releases of hazardous materials that occurred prior to the closing date, any fine, penalty, or other cost assessed by a governmental authority in connection with violations of environmental laws by us prior to the closing date, certain groundwater remediation work, the replacement of underground storage tanks located at certain retail assets, fines, or penalties imposed on us by the Consent Decree related to acts or omissions of Tesoro prior to the closing date and related to the Pearl City Superfund Site. Tesoro’s indemnification obligations are subject to certain limitations as set forth in the Environmental Agreement. These limitations include a deductible of $1 million and a cap of $15 million for certain of Tesoro’s indemnification obligations related to certain pre-existing conditions as well as certain restrictions regarding the time limits for submitting notice and supporting documentation for remediation actions. Other Government Regulation Impact of Dodd-Frank Act Derivatives Regulation The Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”), which was passed by the U.S. Congress and signed into law in July 2010, contains significant derivatives regulation, including requirements that certain transactions be cleared on exchanges and that collateral (commonly referred to as “margin”) be posted for such transactions. The Dodd-Frank Act provides for a potential exception from these clearing and collateral requirements for commercial end-users and it includes a number of defined terms used in determining how this exception applies to particular derivative transactions and the parties to those transactions. As required by the Dodd-Frank Act, the Commodities Futures and Trading Commission (“CFTC”) has promulgated numerous rules to define these terms. The CFTC has re-proposed new rules that would place limits on certain core futures and equivalent swap contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. As these new positions limit rules are not yet final, the impact of those provisions on us is uncertain at this time. 16

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It is possible that the CFTC, in conjunction with prudential regulators, may mandate that financial counterparties entering into swap transactions with end-users must do so with credit support agreements in place, which could result in negotiated credit thresholds above which an end-user must post collateral. If this should occur, we intend to manage our credit relationships to minimize collateral requirements. The CFTC’s final rules may also have an impact on our hedging counterparties. For example, our bank counterparties may be required to post collateral and assume compliance burdens resulting in additional costs. We expect that much of the increased costs could be passed on to us, thereby decreasing the relative effectiveness of our hedges and our profitability. To the extent we incur increased costs or are required to post collateral, there could be a corresponding decrease in amounts available for our capital investment program. OSHA We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendments and Reauthorization Act, and similar state statutes require us to organize and/or disclose information about hazardous materials used or produced in our operations. Certain of this information must be provided to employees, state and local governmental authorities, and local citizens. SIGNIFICANT CUSTOMERS We sell a variety of refined products to a diverse customer base. The majority of our refined products are primarily sold through short-term contracts or on the spot market. For the year ended December 31, 2017, we had one customer in our refining segment that accounted for 10% of our consolidated revenues. No other customers accounted for more than 10% of our consolidated revenues during the years ended December 31, 2018, 2017, and 2016. EMPLOYEES At December 31, 2018, we employed 1,285 people, 192 of whom are nonexempt employees at our co-located Hawaii refinery who are represented by the United Steelworkers Union (“USW”). Our previous collective bargaining agreement with the union expired in January 2019. We are currently in negotiations with the USW on a new extension of the collective bargaining agreement. On January 13, 2016, a claim against us was brought to the United States National Labor Relations Board (“NLRB”) alleging a refusal to bargain collectively and in good faith. Notwithstanding the claim, we consider our relations with our represented and non-represented employees to be satisfactory. Please read Note 15—Commitments and Contingencies to our consolidated financial statements under Item 8 of this Form 10-K for further information. CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS Certain statements in this Annual Report on Form 10-K may constitute “forward-looking” statements as defined in Section 27A of the Securities Act of 1933 (the “Securities Act”), Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”), the Private Securities Litigation Reform Act of 1995 (“PSLRA”), or in releases made by the SEC, all as may be amended from time to time. Such forward-looking statements involve known and unknown risks, uncertainties, and other important factors that could cause our actual results, performance, or achievements to differ materially from any future results, performance, or achievements expressed or implied by such forward-looking statements. Statements that are not historical fact are forward-looking statements. Forward-looking statements can be identified by, among other things, the use of forward-looking language, such as the words “plan,” “believe,” “expect,” “anticipate,” “intend,” “estimate,” “project,” “may,” “will,” “would,” “could,” “should,” “seeks,” or “scheduled to,” or other similar words or the negative of these terms or other variations of these terms or comparable language or by discussion of strategy or intentions. These cautionary statements are being made pursuant to the Securities Act, the Exchange Act, and the PSLRA with the intention of obtaining the benefits of the “safe harbor” provisions of such laws. The forward-looking statements contained in this Annual Report on Form 10-K are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. All readers are cautioned that the forward-looking statements contained in this Annual Report on Form 10-K are not guarantees of future performance and we cannot assure any reader that such statements will be realized or that the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors described in “Item 1A. — Risk Factors”, “Item 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and elsewhere in this Annual Report 17

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on Form 10-K. All forward-looking statements speak only as of the date they are made. We do not intend to update or revise any forward-looking statements as a result of new information, future events, or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf. 18

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Item 1A. RISK FACTORS Our businesses involve a high degree of risk. You should consider and read carefully the risks and uncertainties described below, together with all of the other information contained in this Annual Report on Form 10-K. If any of the following risks, or any risk described elsewhere in this Annual Report on Form 10-K, actually occurs, our business, prospects, financial condition, results of operations, or cash flows could be materially adversely affected. In any such case, the trading price of our common stock could decline. The risks described below are not the only ones facing our company. Additional risks not currently known to us or that we currently deem immaterial may also adversely affect us. OPERATING RISKS Our operations are subject to operational hazards that could expose us to potentially significant losses. Our operations are subject to potential operational hazards and risks inherent in refining operations, in transporting and storing crude oil and refined products, and in producing natural gas and oil. Any of these risks, such as fires, explosions, maritime disasters, security breaches, pipeline ruptures and spills, mechanical failure of equipment, and severe weather and natural disasters at our or third-party facilities could result in business interruptions or shutdowns and damage to our properties and the properties of others. A serious accident at our facilities could also result in serious injury or death to our employees or contractors and could expose us to significant liability for personal injury claims and reputational risk. Any such event or unplanned shutdown could have a material adverse effect on our business, financial condition, and results of operations. The volatility of crude oil prices and refined product prices and changes in the demand for such products may have a material adverse effect on our cash flow and results of operations. Earnings and cash flows from our refining segment depend on a number of factors, including to a large extent the cost of crude oil and other refinery feedstocks which has fluctuated significantly in recent years. While prices for refined products are influenced by the price of crude oil, the constantly changing margin between the price we pay for crude oil and other refinery feedstocks and the prices we receive for refined products (“crack spread”) also fluctuates significantly. The prices we pay and prices we receive depend on numerous factors beyond our control, including the global supply and demand for crude oil, gasoline, and other refined products, which are subject to, among other things: • changes in the global economy and the level of foreign and domestic production of crude oil and refined products; • availability of crude oil and refined products and the infrastructure to transport crude oil and refined products; • local factors, including market conditions, the level of operations of other refineries in our markets, and the volume and price of refined products imported; • threatened or actual terrorist incidents, acts of war, and other global political conditions; • government regulations or mandated production curtailments or limitations; and • weather conditions, hurricanes, or other natural disasters. For example, our newly acquired Washington refinery sources crude from, among other locations, Western Canada, where the Alberta government recently announced that it will mandate oil production cuts in 2019. This action, or any similar actions, could result in an increase in the price we pay for crude oil, which may result in a decrease in the expected earnings and cash flows generated by the Washington refinery. In addition, we purchase our refinery feedstocks before manufacturing and selling the refined products. Price level changes during the periods between purchasing and selling these refined products could also have a material adverse effect on our business, financial condition, and results of operations. Instability in the global economic and political environment can lead to volatility in the cost and availability of crude oil and prices for refined products, which could adversely impact our results of operations. Instability in the global economic and political environment can lead to volatility in the cost and availability of crude oil and in the price for refined products. This may place downward pressure on our results of operations. This is particularly true of developments in and relating to oil-producing countries, including terrorist activities, military conflicts, embargoes, internal instability, or actions or reactions of the U.S. or foreign governments in anticipation of, or in response to, such developments. Any such events may limit or disrupt markets, which could negatively impact our ability to access global crude oil commodity flows or sell our refined products. 19

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Many of our refined products could cause serious injury or death if mishandled or misused by us or our purchasers, or if defects occur during manufacturing. While we produce, store, transport, and deliver all of our refined products in a safe manner, many of our refined products are highly flammable or explosive and could cause significant damage to persons or property if mishandled. Defects in our products (such as gasoline or jet fuel) or misuse by us or by end purchasers could lead to fatalities or serious damage to property. We may be held liable for such occurrences which could have a material adverse effect on our business and results of operations. Our business is impacted by increased risks of spills, discharges, or other releases of petroleum or hazardous substances in our refining and logistics operations. The operation of refineries, pipelines, and refined products terminals is subject to increased risks of spills, discharges, or other inadvertent releases of petroleum or hazardous substances, and we operate in and around environmentally sensitive coastal waters that are closely regulated and monitored. These events could occur in connection with the operation of our refineries, pipelines, or refined products terminals. If any of these events occur, or is found to have previously occurred, we could be liable for costs and penalties associated with their remediation under federal, state, and local environmental laws or common law, and could be liable for property damage to third parties caused by contamination from releases and spills. The penalties and clean-up costs that we may have to pay for releases or the amounts that we may have to pay to third parties for damages to their property, could be significant and have a material adverse effect on our business, financial condition, or results of operations. Our operations, including the operation of underground storage tanks, are also subject to the risk of environmental litigation and investigations which could affect our results of operations. From time to time we may be subject to litigation or investigations with respect to environmental and related matters, the costs of which could be material. We operate, and have in the past operated, fueling stations with underground storage tanks used primarily for storing and dispensing refined fuels. In addition, some of our fueling stations have been owned by third parties whose operation of the stations was not under our control. Federal and state regulations and legislation govern the storage tanks and compliance with these requirements can be costly. The operation of underground storage tanks poses certain risks, including leaks. Leaks from underground storage tanks, which may occur at one or more of our fueling stations, may impact soil or groundwater and could result in fines or civil liability for us. Our insurance coverage may be inadequate to protect us from the liabilities that could arise in our business. We carry property, casualty, business interruption, and other lines of insurance, but we do not maintain insurance coverage against all potential losses. Marine vessel charter agreements do not include indemnity provisions for oil spills so we also carry marine charterer’s liability insurance. We could suffer losses for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Claims covered by insurance are subject to deductibles, the aggregate amount of which could be material. Insurance policies are also subject to compliance with certain conditions, the failure of which could lead to a denial of coverage as to a particular claim or the voiding of a particular insurance policy. There also can be no assurance that existing insurance coverage can be renewed at commercially reasonable rates or that available coverage will be adequate to cover future claims. The occurrence of an event that is not fully covered by insurance or failure by one or more insurers to honor its coverage commitments for an insured event could have a material adverse effect on our business, financial condition, and results of operations. We are subject to interruptions of supply and increased costs as a result of our reliance on third-party transportation of crude oil and refined products to and from our refineries. Our refineries receive and transport crude oil and refined products via tankers, barges, pipelines, and railcars. In addition to environmental risks, we could experience an interruption of supply or an increased cost to deliver refined products to market if such transportation is disrupted because of accidents, governmental regulation, or third-party action. A prolonged disruption could have a material adverse effect on our business, financial condition, and results of operations. The financial and operating results of our refineries, including the products they refine and sell, can be seasonal. Demand for gasoline in Wyoming and South Dakota is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic. Wyoming Refining’s financial and operating results for the first and fourth calendar quarters may be lower than those for the second and third calendar quarters of each year as a result of this seasonality. Demand for gasoline in Washington is also highly seasonal, with a large increase in demand during the summer driving season. Conversely, the demand for the products the co-located Hawaii refinery refines and sells, and the financial and operating results for the Hawaii refinery, are often strongest in the first and fourth calendar quarters. 20

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We rely upon certain critical information systems for the operation of our business and the failure of any critical information system, including a cyber security breach, may result in harm to our business. We are heavily dependent on our technology infrastructure and maintain and rely upon certain critical information systems for the effective operation of our business. These information systems include data network and telecommunications, internet access and our websites, and various computer hardware equipment and software applications, including those that are critical to the safe operation of our refineries and our pipelines and terminals. Our retail business collects certain customer data, including credit card numbers, for business purposes. The integrity and protection of our customer, employee, and company data is critical to our business. Our information systems are subject to damage or interruption from a number of potential sources including natural disasters, software viruses or other malware, power failures, cyber attacks, and other events. To the extent that these information systems are under our control, we have implemented measures, such as virus protection software and intrusion detection systems, to address the outlined risks. However, security measures for information systems cannot be guaranteed to be failsafe. Any compromise of our data security or our inability to use or access these information systems at critical points in time could unfavorably impact the timely and efficient operation of our business and subject us to additional costs and liabilities, which could adversely affect our business, financial condition, and results of operations. Finally, federal legislation relating to cyber security threats could impose additional requirements on our operations. Through our investment in Laramie Energy, we are subject to all of the risks of natural gas and oil exploration and production, but we lack the ability to control Laramie Energy's operations. Through our investment in Laramie Energy, we are exposed to all of the risks inherent in natural gas and oil exploration and production, including the risks that: • exploration and development drilling may not result in commercially productive reserves; • the operator may act in ways contrary to our best interest; • the marketability of our natural gas products depends mostly on the availability, proximity, and capacity of natural gas gathering systems, pipelines, and processing facilities, which are owned by third parties, as well as adequate water supplies; • we have no long-term contracts to sell natural gas or oil; • compliance with environmental and other governmental regulatory or legislative requirements could result in increased costs of operation or curtailment, delay, or cancellation of development and producing operations; and • a decline in demand for natural gas and oil could adversely affect our financial condition and results of operations. Our ability to extract value from our investment in Laramie Energy is limited. Our 46.0% ownership interest in Laramie Energy is a significant asset. However, the ability of Laramie Energy to make distributions to its owners, including us, is currently prohibited by the terms of Laramie Energy’s credit facility and the terms of its limited liability company agreement. Information concerning our natural gas and oil reserves is uncertain. There are numerous uncertainties inherent in estimating quantities of proved reserves and cash flows from such reserves, including factors beyond our control. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and crude oil that cannot be measured in an exact manner. The accuracy of an estimate of quantities of natural gas and crude oil reserves, or of cash flows attributable to such reserves, is a function of the available data, assumptions regarding future natural gas and crude oil prices, availability and terms of financing, expenditures for future development and exploitation activities, and engineering and geological interpretation and judgment. Reserves and future cash flows may also be subject to material downward or upward revisions based upon production history, development and exploitation activities, natural gas and crude oil prices, and regulatory changes. Actual future production, revenue, taxes, development expenditures, operating expenses, quantities of recoverable reserves, and value of cash flows from those reserves may vary significantly from our assumptions and estimates. In addition, reserve engineers may make different estimates of reserves and cash flows based on the same data. These uncertainties may inhibit our ability to finance development of our reserves in the future. The estimated quantities of proved reserves and the discounted present value of future net cash flows attributable to those reserves as of December 31, 2018, included herein, were prepared by independent reserve engineers in accordance with the rules of the SEC and are not intended to represent the fair market value of such reserves. As required by the SEC, the estimated discounted present value of future net cash flows from proved reserves is generally based on prices and costs on the date of the estimate, while actual future prices and costs may be materially higher or lower. In addition, the 10% discount factor the SEC requires to be used 21

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to calculate discounted future net revenues for reporting purposes is not necessarily the most appropriate discount factor based on the cost of capital in effect from time to time and risks associated with our business and the natural gas and oil industry in general. Under current SEC requirements, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled and developed within five years of the date of booking. This rule may limit our potential to book additional proved undeveloped reserves we own indirectly through our equity investment in Laramie Energy as Laramie Energy pursues its drilling program. Moreover, we may be required to write down our proved undeveloped reserves we own indirectly through our equity investment in Laramie Energy, or we may be required to write down previously disclosed proved undeveloped reserves, if Laramie Energy does not drill and develop those reserves within the required five-year time frame. REGULATORY RISK Meeting the requirements of evolving environmental, health, and safety laws and regulations, including those related to climate change and marine protection, could adversely affect our performance. Consistent with the experience of other U.S. refineries, environmental laws and regulations have raised operating costs and may require significant capital investments at our refineries. We may be required to address conditions that may be discovered in the future and require a response. Potentially material expenditures could be required in the future as a result of evolving environmental, health, and safety and energy laws, regulations, or requirements that may be adopted or imposed in the future, as well as work that is ongoing related to the Consent Decree. Future developments in federal and state laws and regulations governing environmental, health, and safety and energy matters are especially difficult to predict. Currently, multiple legislative and regulatory measures to address GHG emissions (including CO2, methane, and nitrous oxides) are in various phases of consideration, promulgation, or implementation. These include actions to develop national, statewide, or regional programs, each of which could require reductions in our GHG emissions. Requiring reductions in our GHG emissions could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls at our facilities, and/or (iii) administer and manage any GHG emissions programs, including acquiring emission credits or allotments. Requiring reductions in our GHG emissions and increased use of renewable fuels which can be supplied by producers and marketers in other industries that supply alternative forms of energy and fuels to satisfy the requirements of our industrial, commercial, and individual customers could also decrease the demand for our refined products, and could have a material adverse impact on our business, financial condition, and results of operations. Additionally, legislation designed to protect animal and plant species, such as the Magnuson amendment to the Marine Mammal Protection Act, may limit or restrict our ability to construct or expand new oil terminals and oil-by-rail infrastructure in the State of Washington, which could have a material impact on our business, financial condition, and results of operations. Renewable fuels mandates may reduce demand for the petroleum fuels we produce, which could have a material adverse effect on our business results of operations and financial condition. The EPA has issued RFS mandates, requiring refiners such as us to blend renewable fuels into the petroleum fuels we produce and sell in the U.S. On November 30, 2017, the EPA issued final volume mandates for 2018, which are generally lower than the corresponding statutory mandates for that year. During 2018, we received a $1.8 million benefit and incurred a $0.7 million expense for RINs for the Par East facility of our Hawaii refinery and our Wyoming refinery, respectively. On November 30, 2018, the EPA issued final volume mandates for the year 2019 and the biomass-based diesel for 2020. All but biomass-based diesel are below the statutory mandates, with biomass-based diesel significantly greater than the statutory floor of 1.0 billion gallons. We expect to incur costs of approximately $15.2 million for RINs in 2019 for our refineries, including the newly acquired Washington refinery. In addition, as a result of the annual volume mandates, we may experience a decrease in demand for refined products due to refined products being replaced by renewable fuels. Ongoing litigation regarding the standards for 2017, 2018, and 2019 creates some potential that the final volumes of renewable fuels that the EPA established will be revised for one or more of those years. In addition, the EPA is considering changes (not yet proposed) to the existing RFS program regulations and other regulatory initiatives under the RFS program that could impact future standards. Although uncertain, any of these events may cause the price of RINs to rise and result in additional costs in connection with RFS compliance for 2017 and 2018, costs that exceed our estimates in connection with RFS compliance for 2019 and/or increased compliance costs in future years. Such increased costs could be material and may have a material adverse impact on our business, financial condition, and results of operations. Finally, while there is no current regulatory standard that authenticates RINs that may be purchased on the open market from third parties, we believe that the RINs we purchase are from reputable sources, are valid, and serve to demonstrate compliance with applicable RFS requirements. However, if this belief proves incorrect and the RINs that we purchase are not valid or in compliance with applicable RFS requirements, our financial condition and cash flows may be adversely affected. 22

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Several states, including Washington and Hawaii, have pursued or are considering initiatives designed to reduce the carbon intensity of the transportation sector by encouraging increased use of renewable fuels or electric vehicles or by requiring reductions in transportation fuel-related greenhouse gas emissions in the state. Since 2006, Washington has required that denatured ethanol make up at least 2% of total gasoline sold in the state and that biodiesel comprise at least 2% of total diesel sold in the state, and the Washington Department of Ecology is authorized to increase these requirements if certain conditions are met. In addition, the Washington State Legislature is currently considering adopting a clean fuels program that would limit the greenhouse gas emissions per unit of transportation fuel energy to 10 percent below 2017 levels by 2028. Compliance with this program would also be demonstrated through a credit trading program. In 2014, the State of Hawaii signed a memorandum of understanding with the U.S. Department of Energy to collaborate to produce 70% of the state’s energy needs from energy-efficient and renewable sources by 2030 and 100% of the state's energy needs from energy-efficient and renewable sources by 2045. In addition, Hawaii’s alternative fuels standard requires alternative fuels to provide 20% of highway fuel demand by 2020 and 30% by 2030. These state programs could increase the cost of consuming, and thereby reduce demand for our refined petroleum productions, which could have a material adverse effect on our business, results of operations, and financial condition. Potential legislative and regulatory actions addressing climate change could increase our costs, reduce our revenue and cash flow from natural gas and oil sales, or otherwise alter the way we conduct our business. The EPA has issued a notice of finding and determination that emissions of CO2, methane, and other GHG present an endangerment to human health and the environment. In response, the EPA has adopted regulations under existing provisions of the federal CAA that, among other things, establish Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit program requiring reviews for GHG emissions from certain large stationary sources. Facilities required to obtain PSD permits for their GHG emissions will also be required to meet “best available control technology” standards, which will be established by the states or, in some instances, by the EPA on a case-by-case basis. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified large GHG emission sources in the U.S., including petroleum refineries and certain onshore petroleum and natural gas production activities, on an annual basis. We monitor for GHG emissions at our refineries and believe we are in substantial compliance with the applicable GHG reporting requirements. Certain of the third-party drilling and production entities in which we hold a working interest also may be subject to reporting of GHG emissions in the U.S. These EPA policies and rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities. In addition, from time to time, the U.S. Congress has considered, and may in the future consider and adopt “cap and trade” legislation that would establish an economy-wide cap on GHG emissions in the U.S. and would require most sources of GHG emissions to obtain emission “allowances” corresponding to their annual GHG emissions. For those GHG sources that are unable to meet the required limitations, such legislation could impose substantial financial burdens. Any laws or regulations that may be adopted to restrict or reduce GHG emissions would likely require us to incur increased operating costs and could have an adverse effect on demand for our production. The adoption of any legislation or regulations that limits emissions of GHG from our or such drilling and production entities’ facilities, equipment, and operations could require us or such entities to incur costs to reduce emissions of GHG associated with our or such entities’ operations or could adversely affect demand for the refined petroleum products that we produce or the crude oil or natural gas that such drilling and production entities in which we hold a working interest produce. In connection with the WRC Acquisition, we will be required to undertake significant remediation and other corrective actions with respect to certain environmental matters. In connection with the July 14, 2016 purchase of Hermes Consolidated, LLC (d/b/a Wyoming Refining Company) and, indirectly, Wyoming Refining Company’s wholly owned subsidiary, Wyoming Pipeline Company, LLC (collectively, “Wyoming Refining” or “WRC”) (the “WRC Acquisition”), there are several environmental conditions that will require us to undertake significant remediation efforts and other corrective actions. The Wyoming refinery is subject to a number of consent decrees, orders, and settlement agreements involving the EPA and/or the Wyoming Department of Environmental Quality, some of which date back to the late 1970s and several of which remain in effect, requiring further actions at the Wyoming refinery. As is typical of older small refineries like the Wyoming refinery, the largest cost component arising from these various decrees relates to the investigation, monitoring, and remediation of soil, groundwater, surface water, and sediment contamination associated with the facility’s historic operations. Investigative work by Wyoming Refining and negotiations with the relevant agencies as to remedial approaches remain ongoing on a number of aspects of the contamination, meaning that investigation, monitoring, and remediation costs are not reasonably estimable for some elements of these efforts. As of December 31, 2018, we have accrued $17.3 million for the well-understood components of these efforts based on current information, approximately one- third of which we expect to incur in the next five years and the remainder being incurred over approximately 30 years. 23

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Additionally, we believe the Wyoming refinery will need to modify or close a series of wastewater impoundments in the next several years and to replace those impoundments with a new wastewater treatment system. Based on preliminary information, reasonable estimates we have received suggest costs of approximately $11.6 million to design and construct a new wastewater treatment system. Finally, among the various historic consent decrees, orders, and settlement agreements into which the Wyoming refinery has entered, there are several penalty orders associated with exceedances of permitted limits by the Wyoming refinery’s wastewater discharges. Although the frequency of these exceedances appears to be declining over time, we may become subject to new penalty enforcement action in the next several years, which could involve penalties in excess of $100,000. Moreover, in November 2016 the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) conducted an integrated inspection of the products pipeline that we acquired in the WRC Acquisition. As a result of compliance violations identified during the inspection, the Wyoming refinery was assessed a civil penalty of $279 thousand in December 2017, which was paid in January 2018. We may incur significant costs and liabilities resulting from performance of pipeline integrity programs and related repairs. PHMSA has established a series of rules requiring pipeline operators to develop and implement integrity management programs for hazardous liquid pipelines that, in the event of a pipeline leak or rupture, could affect “high consequence areas” (“HCAs”), which are areas where a release could have the most significant adverse consequences, including high-population areas, certain drinking water sources, and unusually sensitive ecological areas. These regulations require operators of covered pipelines to: • perform ongoing assessments of pipeline integrity; • identify and characterize applicable threats to pipeline segments that could impact an HCA; • improve data collection, integration, and analysis; • repair and remediate the pipeline as necessary; and • implement preventive and mitigating actions. In addition, certain states have also adopted regulations similar to existing PHMSA regulations for intrastate gathering and transmission lines. These requirements could require us to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in us incurring increased operating costs that could be significant and have a material adverse effect on our financial position or results of operations. Moreover, changes to pipeline safety laws by Congress and regulations by PHMSA that result in more stringent or costly safety standards could result in our incurring increased operating costs that could have a material adverse effect on our financial position or results of operations. BUSINESS RISKS The locations of our refineries and related assets in certain limited geographic areas create an exposure to localized economic risks. Because of the locations of our refineries in Hawaii, Washington, and Wyoming, we primarily market our refined products in relatively limited geographic areas. As a result, we are more susceptible to regional economic conditions than the operations of more geographically diversified competitors and any unforeseen events or circumstances that affect our operating areas could also materially adversely affect our revenues and our business and operating results. These factors include, among other things, changes in the economy, weather conditions, demographics and population, increased supply of refined products from competitors, and reductions in the supply of crude oil. We must make substantial capital expenditures at our refineries and related assets to maintain their reliability and efficiency. If we are unable to complete capital projects at their expected costs or in a timely manner, or if the market conditions assumed in our project economics deteriorate, our financial condition, results of operations, or cash flows could be adversely affected. Our refineries and related assets have been in operation for many years. Equipment, even if properly maintained, may require significant capital expenditures and expenses to keep the refineries operating at optimum efficiency. These costs do not result in increases in unit capacities, but rather are focused on trying to maintain safe, reliable operations. 24

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Delays or cost increases related to the engineering, procurement, and construction of new facilities, or improvements and repairs to our existing facilities and equipment, could have a material adverse effect on our business, financial condition, or results of operations. Such delays or cost increases may arise as a result of unpredictable factors in the marketplace, many of which are beyond our control, including: • denial or delay in obtaining regulatory approvals and/or permits; • difficulties in executing the capital projects; • unplanned increases in the cost of equipment, materials, or labor; • disruptions in transportation of equipment and materials; • severe adverse weather conditions, natural disasters, or other events (such as equipment malfunctions, explosions, fires, or spills) affecting our facilities, or those of our 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 • non-performance or force majeure by, or disputes with, our vendors, suppliers, contractors, or sub-contractors. Any one or more of these occurrences noted above could have a significant impact on our business. If we are unable to make up the delays or to recover the related costs, or if market conditions change, it could materially and adversely affect our financial position, results of operations, or cash flows. The ongoing work related to the Consent Decree subjects us to risks associated with engineering, procurement, and construction of improvements and repairs to our facilities, related penalties and fines, and the performance of equipment, all of which could have a material adverse effect on our business, financial condition, or results of operations. On July 18, 2016, PHR and subsidiaries of Tesoro entered into the Consent Decree. As a result of the Consent Decree, PHR expanded its previously-announced 2016 Hawaii refinery turnaround to undertake additional capital improvements to reduce emissions of air pollutants and to provide for certain NOx and SO2 emission controls and monitoring required by the Consent Decree. Although the turnaround was completed during the third quarter of 2016, work related to the Consent Decree is ongoing. This work subjects us to risks associated with engineering, procurement, and construction of improvements and repairs to our facilities and related penalties and fines to the extent applicable deadlines under the Consent Decree are not satisfied, as well as risks related to the performance of equipment required by, or affected by, the Consent Decree. Each of these risks could have a material adverse effect on our business, financial condition, or results of operations. The retail market is diverse and highly competitive. Aggressive competition and the development of alternative fuels could adversely impact our business. We face strong competition in the market for the sale of retail gasoline, diesel fuel, and merchandise. Our competitors include outlets owned or operated by fully integrated major oil companies or their dealers, and other well-recognized national or regional retail outlets, often selling products at very competitive prices. We compete with a number of integrated national and international oil companies who produce crude oil, some of which is used in their refining operations. Unlike these oil companies, we must purchase all of our crude oil from unaffiliated sources. Because these oil companies benefit from increased commodity prices, have greater access to capital, and have stronger capital structures, they are able to better withstand poor and volatile market conditions, such as a lower refining margin environment, shortages of crude oil and other feedstocks, or extreme price fluctuations. Additionally, non-traditional retailers such as supermarkets, club stores, and mass merchants are also in the retail business, and these non-traditional gasoline retailers have obtained a significant share of the transportation fuels market. These retailers may use integration of operations, greater financial resources, promotional pricing or discounts, or other advantages to withstand volatile market conditions or levels of no or low profitability. The development of alternative and competing fuels in the retail market could also adversely impact our business. Increased competition from these alternatives as a result of governmental regulations, technological advances, and consumer demand could have an impact on pricing and demand for our products and our profitability. If we are unable to obtain crude oil supplies for our refineries without the benefit of certain intermediation agreements, the capital required to finance our crude oil supply could negatively impact our liquidity. All of the crude oil delivered at our co-located Hawaii refinery is subject to our Supply and Offtake Agreements with J. Aron and the crude oil delivered at our Washington refinery is subject to an intermediation agreement with Merrill Lynch (the “Washington Refinery Intermediation Agreement” and, together with the Supply and Offtake Agreements, the “Intermediation Agreements”). If we are unable to obtain our crude oil supply for our refineries outside of these agreements, our exposure to crude oil pricing risks may increase as the number of days between when we pay for the crude oil and when the crude oil is delivered to us increases. Such increased exposure could negatively impact our liquidity position due to the increase in working capital used to acquire crude oil inventory for our refineries. 25

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The Intermediation Agreements expose us to counterparty credit and performance risk. We have Supply and Offtake Agreements with J. Aron, pursuant to which J. Aron will intermediate crude oil supplies and refined product inventories at our Hawaii refinery. J. Aron will own all of the crude oil in our tanks and substantially all of our refined product inventories prior to our sale of the inventories. Upon termination of the Supply and Offtake Agreements, which may be terminated by J. Aron as early as May 31, 2021, we are obligated to repurchase all crude oil and refined product inventories then owned by J. Aron and located at the specified storage facilities at then current market prices. This repurchase obligation could have a material adverse effect on our business, results of operations, or financial condition. We have a similar intermediation agreement with Merrill Lynch whereby our Washington refinery purchases crude oil supplies from third-party suppliers and Merrill Lynch provides credit support for such purchases in exchange for our pledge of all crude oil and refined products inventories from such refinery. An adverse change in the business, results of operations, liquidity, or financial condition of our intermediation counterparties could adversely affect the ability of such counterparties to perform their obligations, which could consequently have a material adverse effect on our business, results of operations, or liquidity and, as a result, our business and operating results. Inadequate liquidity could materially and adversely affect our business operations in the future. If our cash flow and capital resources are insufficient to fund our obligations, we may be forced to reduce our capital expenditures, seek additional equity or debt capital, or restructure our indebtedness. We cannot assure you that any of these remedies could, if necessary, be affected on commercially reasonable terms, or at all. Our liquidity is constrained by our need to satisfy our obligations under our debt agreements and the Intermediation Agreements. The availability of capital when the need arises will depend upon a number of factors, some of which are beyond our control. These factors include general economic and financial market conditions, the crack spread, natural gas and crude oil prices, our credit ratings, interest rates, market perceptions of us or the industries in which we operate, our market value, and our operating performance. We may be unable to execute our long-term operating strategy if we cannot obtain capital from these or other sources when the need arises. Our ability to generate cash and repay our indebtedness or fund capital expenditures depends on many factors beyond our control and any failure to do so could harm our business, financial condition, and results of operations. Our ability to fund future capital expenditures and repay our indebtedness when due will depend on our ability to generate sufficient cash flow from operations, borrowings under our debt agreements, and distributions from our subsidiaries. To a certain extent, this is subject to general economic, financial, competitive, legislative, and regulatory conditions and other factors that are beyond our control, including the crack spread and the prices we receive for our natural gas and crude oil production. We cannot assure you that our businesses will generate sufficient cash flow from operations, that our subsidiaries can or will make sufficient distributions to us, or that future borrowings will be available to us in an amount sufficient to repay our indebtedness or fund our other liquidity needs. If our cash flow and capital resources are insufficient to fund our needs, we may be forced to reduce our planned capital expenditures, sell assets, seek additional equity or debt capital, or restructure our debt. We cannot assure you that any of these remedies could, if necessary, be affected on commercially reasonable terms, or at all, which could cause us to default on our obligations and could impair our liquidity. Our substantial level of indebtedness could adversely affect our financial condition. We have a substantial amount of indebtedness, which requires significant interest payments. As of December 31, 2018, we had $392.6 million of indebtedness, and Interest expense and financing costs, net for the year ended December 31, 2018 was $39.8 million. In connection with the Washington Refinery Acquisition in January 2019, we entered into a $250 million term loan facility with Goldman Sachs Bank USA and a $45 million term loan with Bank of Hawaii. Additionally, the Washington Refinery Intermediation Agreement was amended and remained in place at the closing of the acquisition of the Washington refinery. Our substantial level of indebtedness could have important consequences, including the following: • we must use a substantial portion of our cash flow from operations to pay interest and principal on our indebtedness and obligations under the Intermediation Agreements, which reduces funds available to us for other purposes, such as working capital, capital expenditures, other general corporate purposes, and potential acquisitions; • our ability to refinance such indebtedness or to obtain additional financing for working capital, capital expenditures, acquisitions, or general corporate purposes may be impaired; • our leverage may be greater than that of some of our competitors, which may put us at a competitive disadvantage and reduce our flexibility in responding to current and changing industry and financial market conditions; • we may be more vulnerable to economic downturns and adverse developments in our business; and • we may be unable to comply with financial and other restrictive covenants in our debt agreements, some of which require us to maintain specified financial ratios and limit our ability to incur additional debt and sell assets, 26

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