Company Quick10K Filing
Quick10K
Par Pacific Holdings
Closing Price ($) Shares Out (MM) Market Cap ($MM)
$19.15 49 $944
10-K 2018-12-31 Annual: 2018-12-31
10-Q 2018-09-30 Quarter: 2018-09-30
10-Q 2018-06-30 Quarter: 2018-06-30
10-Q 2018-03-31 Quarter: 2018-03-31
10-K 2017-12-31 Annual: 2017-12-31
10-Q 2017-09-30 Quarter: 2017-09-30
10-Q 2017-06-30 Quarter: 2017-06-30
10-Q 2017-03-31 Quarter: 2017-03-31
10-K 2016-12-31 Annual: 2016-12-31
10-Q 2016-09-30 Quarter: 2016-09-30
10-Q 2016-06-30 Quarter: 2016-06-30
10-Q 2016-03-31 Quarter: 2016-03-31
10-K 2015-12-31 Annual: 2015-12-31
10-Q 2015-09-30 Quarter: 2015-09-30
10-Q 2015-06-30 Quarter: 2015-06-30
10-Q 2015-03-31 Quarter: 2015-03-31
10-K 2014-12-31 Annual: 2014-12-31
10-Q 2014-09-30 Quarter: 2014-09-30
10-Q 2014-06-30 Quarter: 2014-06-30
10-Q 2014-03-31 Quarter: 2014-03-31
10-K 2013-12-31 Annual: 2013-12-31
8-K 2019-04-02 Enter Agreement, Leave Agreement, Off-BS Arrangement, Exhibits
8-K 2019-02-21 Regulation FD, Exhibits
8-K 2019-01-09 Enter Agreement, M&A, Off-BS Arrangement, Sale of Shares, Regulation FD, Exhibits
8-K 2018-12-19 Enter Agreement, Sale of Shares, Regulation FD, Other Events, Exhibits
8-K 2018-12-12 Officers, Regulation FD, Exhibits
8-K 2018-12-10 Enter Agreement, Exhibits
8-K 2018-12-06 Other Events, Exhibits
8-K 2018-11-26 Enter Agreement, Sale of Shares, Regulation FD, Exhibits
8-K 2018-11-07 Regulation FD, Exhibits
8-K 2018-11-06 Earnings, Exhibits
8-K 2018-08-29 Enter Agreement, Sale of Shares, Regulation FD, Exhibits
8-K 2018-08-08 Regulation FD, Exhibits
8-K 2018-08-07 Earnings, Exhibits
8-K 2018-07-26 Enter Agreement, Off-BS Arrangement, Exhibits
8-K 2018-07-19 Enter Agreement, Off-BS Arrangement, Exhibits
8-K 2018-05-14 Shareholder Vote
8-K 2018-05-08 Earnings, Exhibits
8-K 2018-03-26 Regulation FD, Exhibits
8-K 2018-03-23 Other Events, Regulation FD, Exhibits
8-K 2018-03-06 Officers
8-K 2018-03-05 Earnings, Exhibits
8-K 2018-02-14 Regulation FD, Exhibits
8-K 2018-01-09 Enter Agreement, Regulation FD, Exhibits
IPG Interpublic Group of Companies 8,580
CVA Covanta Holding 2,300
RNST Renasant 2,060
CECO Career Education 1,240
CODI Compass Diversified Holdings 1,000
RGR Sturm Ruger & Co 957
ABUS Arbutus Biopharma 206
BBII Brisset Beer 0
TSSI TSS 0
ADGO Advantego 0
PARR 2018-12-31
Part I
Item 1. Business
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 2. Properties
Item 3. Legal Proceedings
Item 4. Mine Safety Disclosures
Part II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Item 6. Selected Financial Data
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8. Financial Statements and Supplementary Data
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial
Item 9A. Controls and Procedures
Item 9B. Other Information
Part III
Item 10. Directors, Executive Officers, and Corporate Governance
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13. Certain Relationships and Related Transactions and Director Independence
Item 14. Principal Accountant Fees and Services
Part IV
Item 15. Exhibits and Financial Statement Schedules
Note 1-Overview
Note 2-Summary of Significant Accounting Policies
Note 3-Investment in Laramie Energy, Llc
Note 4-Acquisitions
Note 5-Revenue Recognition
Note 6-Inventories
Note 7-Prepaid and Other Current Assets
Note 8-Property, Plant, and Equipment
Note 9-Asset Retirement Obligations
Note 10-Goodwill and Intangible Assets
Note 11-Inventory Financing Agreements
Note 12-Debt
Note 13-Derivatives
Note 14-Fair Value Measurements
Note 15-Commitments and Contingencies
Note 16-Stockholders' Equity
Note 17-Benefit Plans
Note 18-Income (Loss) per Share
Note 19-Income Taxes
Note 20-Segment Information
Note 21-Related Party Transactions
Note 22-Subsequent Events
Note 23-Quarterly Financial Data (Unaudited)
Note 24-Supplemental Oil and Gas Disclosures (Unaudited)
Item 16. Form 10-K Summary
EX-10.42 a20181231ex1042-parxamendm.htm
EX-21.1 a20181231ex211subsidiaries.htm
EX-23.1 a20181231ex231-deloittecon.htm
EX-23.2 a20181231ex232laramieenerg.htm
EX-23.3 a20181231ex233nsaipar10-kc.htm
EX-31.1 a20181231ex311-wp20181231.htm
EX-31.2 a20181231ex312-wm20181231.htm
EX-32.1 a20181231ex321-wp20181231.htm
EX-32.2 a20181231ex322-wm20181231.htm
EX-99.1 a20181231ex991parpacificye.htm
EX-99.2 a20181231ex99-22018laramie.htm

Par Pacific Holdings Earnings 2018-12-31

PARR 10K Annual Report

Balance SheetIncome StatementCash Flow

10-K 1 a2018123110-k20181231.htm 10-K Document


 
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. ¨

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.
 






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

i




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 Index
A measure of the complexity of a given refinery compared to crude distillation, which is assigned a 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




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




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 refinerys 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




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




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 December 31,
 
Year Ended December 31,
 
July 14, 2016 to 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




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 December 31,
 
Year Ended December 31,
 
July 14, 2016 to 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

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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:
Location and Channel of Trade
 
“76” Brand
 
Hele Brand
 
Cenex® Zip 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


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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.

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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.


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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
(MMcf)
 
Oil
(Mbbls)
 
NGLs
(Mbbls)
 
Total
(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
Developed
Producing
 
Proved
Developed
Non-producing
 
Proved
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.

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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




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

11




will be required in connection with such permitting to undertake a technology review to determine appropriate controls to be 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

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Safety Administration ("NHTSA") jointly adopted regulations that establish an average industry fuel economy of 54.5 miles per 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

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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

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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.

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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.

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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

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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 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.

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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.

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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.

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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

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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.

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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.

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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.

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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.

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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,

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which could result in an event of default that, if not cured or waived, would have an adverse effect on our business and prospects and could result in bankruptcy.
Our ability to meet expenses, to remain in compliance with the covenants under our debt agreements, and to make future principal and interest payments in respect of our debt depends on, among other things, our operating performance, competitive developments, and financial market conditions, all of which are significantly affected by financial, business, economic, and other factors. We are not able to control many of these factors. If industry and economic conditions deteriorate, our cash flow may not be sufficient to allow them to pay principal and interest on our debt and meet our other obligations.
This increase in our indebtedness may reduce our flexibility to respond to changing business and economic conditions or to fund capital expenditure or working capital needs because we will require additional funds to service our outstanding indebtedness and may not be able to obtain additional financing.
Despite our current debt levels, we may still incur substantially more debt or take other actions which would intensify the risks associated with our substantial leverage.
Despite our current consolidated debt levels, we may be able to incur significant additional indebtedness in the future. Although our debt agreements contain restrictions on the incurrence of additional indebtedness and entering into certain types of other transactions, these restrictions are subject to a number of qualifications and exceptions. Additional indebtedness incurred in compliance with these restrictions could be substantial. These restrictions also do not prevent us or our subsidiaries from incurring obligations, such as trade payables, that do not constitute indebtedness as defined under our debt agreements. To the extent new debt is added to our current debt levels, the substantial leverage risks associated with our indebtedness would increase.
Our debt agreements impose significant operating and financial restrictions on us.
Our debt agreements impose, and the terms of any future debt may impose, significant operating and financial restrictions on us. These restrictions, among other things, may limit our ability to:
pay dividends or distributions, repurchase equity, prepay junior debt, and make certain investments;
incur additional debt or issue certain disqualified stock and preferred stock;
sell or otherwise dispose of assets, including capital stock of subsidiaries;
incur liens on assets;
merge or consolidate with another company or sell all or substantially all assets;
enter into certain transactions with affiliates; and
enter into agreements that would restrict the ability of our subsidiaries to pay dividends or make other payments to the Issuers.
All of these covenants may adversely affect our ability to finance our operations, meet or otherwise address our capital needs, pursue business opportunities, react to market conditions, or otherwise restrict activities or business plans. A breach of any of these covenants could result in a default in respect of the related indebtedness. If a default occurs, the requisite lenders could elect to declare the indebtedness, together with accrued interest and other fees, to be immediately due and payable and proceed against any collateral securing that indebtedness. If repayment of our indebtedness is accelerated as a result of such default, we cannot assure you that they would have sufficient assets or access to credit to repay such indebtedness.
We may incur losses and incur additional costs as a result of our forward-contract activities and derivative transactions.
We enter into derivative contracts from time to time primarily to reduce our exposure to fluctuations in interest rates and in the price of crude oil and refined products. If the instruments we use to hedge our exposure are not effective, or if our counterparties are unable to satisfy their obligations to us, we may incur losses. We may also be required to incur additional costs in connection with future regulation of derivative instruments to the extent such regulation is applicable to us. Additionally, our commodity derivative activities may produce significant period-to-period earnings volatility that is not necessarily reflective of our underlying operational performance.
Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly and otherwise impact our ability to incur indebtedness for acquisitions and working capital needs.
We are subject to interest rate risk in connection with borrowings under certain of our debt agreements, which bear interest at variable rates. Interest rate changes will not affect the market value of indebtedness incurred under such debt agreements, but could affect the amount of our interest payments and, accordingly, our future earnings and cash flows, assuming other factors are held constant. Increases in interest rates could also impact our ability to incur indebtedness to fund acquisitions and working capital needs. A significant increase in prevailing interest rates, that results in a substantial increase in the interest rates applicable to our

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indebtedness, could substantially increase our interest expense and have a material adverse effect on our financial condition, results of operations, and cash flows.
If we are unable to refinance our term loan with the Bank of Hawaii before it matures, we may be unable to repay the amounts that are due thereunder.
In order to fund a portion of the cash purchase price for the acquisition of the Washington refinery, we entered into a $45 million term loan, which matures on July 9, 2019, on which date the entire unpaid principal balance will be due and payable in full. We are considering a variety of options to refinance the term loan, including a new term loan issued by the Bank of Hawaii pursuant to a non-binding term sheet executed by us and the Bank of Hawaii, the security for which is expected to consist of certain unencumbered real estate in Hawaii owned by Mid Pac Petroleum, LLC ("Mid Pac"), a wholly owned subsidiary of Par Petroleum, to be conveyed to our wholly owned subsidiary in a sale-leaseback transaction. We cannot assure you that such refinancing will be available to us or at all. In the event that we are unable to refinance the term loan, we may not have sufficient cash to repay the term loan at its maturity, which would be an event of default under the term loan and could result in an acceleration of the payments due under our other debt agreements.
We cannot be certain that our net operating loss tax carryforwards will continue to be available to offset our tax liability.
As of December 31, 2018, we estimated that we had approximately $1.5 billion of net operating loss tax carryforwards (“NOLs”). In order to utilize the NOLs, we must generate taxable income that can offset such carryforwards. The availability of NOLs to offset taxable income would be substantially reduced or eliminated if we were to undergo an “ownership change” within the meaning of Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”). We will be treated as having had an “ownership change” if there is more than a 50% increase in stock ownership during any three year “testing period” by “5% shareholders.” In order to help us preserve our NOLs, our certificate of incorporation contains stock transfer restrictions designed to reduce the risk of an ownership change for purposes of Section 382 of the Code. We expect that the restrictions will remain in place for the foreseeable future. We cannot assure you, however, that these restrictions will prevent an ownership change.
Our ability to utilize our NOLs to offset future taxable income is subject to various limitations, including that the NOLs will expire in various amounts, if not used, between 2027 through 2036. During 2018, the Internal Revenue Service (“IRS”) completed an audit of our tax returns for the tax years ending 2014 through 2016, which included those returns for the years in which the losses giving rise to the NOLs were reported. Although the IRS made no challenge of the availability of our NOLs during this audit, we cannot assure you that we would prevail if the IRS were to challenge the availability of the NOLs in the event of future audits. If the IRS were successful in challenging our NOLs, all or some portion of the NOLs would not be available to offset any future consolidated income which would negatively impact our results of operations and cash flows. Certain provisions of the Tax Cuts and Jobs Act may also limit our ability to utilize our net operating tax loss carryforwards.
We may be unable to successfully identify, execute, or effectively integrate future acquisitions, which may negatively affect our results of operations.
We will continue to pursue acquisitions in the future. Although we regularly engage in discussions with, and submit proposals to, acquisition candidates, suitable acquisitions may not be available in the future on reasonable terms. If we do identify an appropriate acquisition candidate, we may be unable to successfully negotiate the terms of an acquisition, finance the acquisition, or, if the acquisition occurs, effectively integrate the acquired business into our existing businesses. Negotiations of potential acquisitions and the integration of acquired business operations may require a disproportionate amount of management’s attention and our resources. Even if we complete additional acquisitions, continued acquisition financing may not be available or available on reasonable terms, any new businesses may not generate the anticipated level of revenues, the anticipated cost efficiencies, or synergies may not be realized, and these businesses may not be integrated successfully or operated profitably. Our inability to successfully identify, execute, or effectively integrate future acquisitions may negatively affect our results of operations.
Acquisitions may prove to be worth less than we paid because of uncertainties in evaluating potential liabilities.
Our recent growth is due in large part to acquisitions, such as the acquisitions of PHR, Mid Pac, Wyoming Refining, Northwest Retail, the Washington Refinery, and the assets related to the Hawaii Refinery Expansion. We expect acquisitions to be instrumental to our future growth. Successful acquisitions require an assessment of a number of factors, including estimates of potential unknown and contingent liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform due diligence reviews of acquired businesses and assets that we believe are generally consistent with industry practices. However, such reviews will not reveal all existing or potential problems. In addition, our reviews may not permit us to become sufficiently familiar with potential environmental problems or other contingent and unknown liabilities that may exist or arise. As a result, there may be unknown and contingent liabilities related to acquired businesses and assets of which we are unaware. We could be liable for unknown obligations relating to acquisitions for which indemnification is not available, which could materially adversely affect our business, results of operations, and cash flows.

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We may fail to successfully integrate recent acquisitions with our existing business in a timely manner or fail to realize all of the expected benefits from such acquisitions, which could have a material adverse effect on our business, financial condition, results of operations, or cash flows.
Integration of Washington Refinery Acquisition and the Hawaii Refinery Expansion into our existing business will be a complex, time consuming, and costly process. A failure to complete this integration successfully and in a timely manner could have a material adverse effect on our business, financial condition, results of operations, or cash flows. Difficulties related to the integration of Washington Refinery Acquisition and the Hawaii Refinery Expansion into our existing business could include:
operating a larger combined organization and adding operations;
difficulties in the assimilation of the acquired assets and operations;
the diversion of management's attention from other business concerns;
integrating personnel from diverse business backgrounds and organizational cultures;
potential environmental or regulatory compliance matters or liabilities; and
coordinating and consolidating corporate and administrative functions.
If any of these risks or unanticipated liabilities or costs were to materialize, then any desired benefits of the Washington Refinery Acquisition and the Hawaii Refinery Expansion may not be fully realized, or realized at all, and our future results of operations could be negatively impacted. In addition, acquired assets and businesses may actually perform at levels below the forecasts used to evaluate such acquisitions due to actors outside of our control, which could negatively impact our results and operations and financial condition.
All of our refineries are scheduled for maintenance turnarounds in the next few years that will involve significant expenditures.
Wyoming Refining expects to perform a significant maintenance turnaround during 2020 and our refinery in Hawaii is scheduled to undergo a significant maintenance turnaround between 2019 and 2020. Additionally, our newly-acquired Washington refinery anticipates conducting a turnaround during 2020. During a turnaround, all or a portion of each refinery’s production may be halted or disrupted. Any turnaround, if unsuccessful or delayed, could have a material adverse effect on our business, financial condition, or results of operations.
In addition, all of our refineries may require additional unscheduled down time for unanticipated maintenance or repairs that are more frequent than our scheduled turnarounds. Refinery operations may also be disrupted by external factors such as a suspension of feedstock deliveries or an interruption of electricity, natural gas, water treatment, or other utilities. Other potentially disruptive factors include natural disasters, severe weather conditions, workplace or environmental accidents, interruptions of supply, work stoppages, losses of permits or authorizations, or acts of terrorism. Disruptions to our refining operations could reduce our revenues and profitability during the period of time that our processing units are not operating.
A substantial portion of our refining workforce is unionized and we may face labor disruptions that would interfere with our operations.
As of December 31, 2018, we employed approximately 1,285 people, with a collective bargaining agreement covering 192 of those employees. 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 NLRB alleging a refusal to bargain collectively and in good faith. Accordingly, we may not be able to prevent a strike or work stoppage in the future and any such work stoppage could cause disruptions in our business and have a material adverse effect on our business, financial condition, results of operations, and cash flows.
Adverse changes in global economic conditions and the demand for transportation fuels may impact our business and financial condition in ways that we currently cannot predict.
A recession or prolonged economic downturn would adversely affect the business and economic environment in which we operate. These conditions increase the risks associated with the creditworthiness of our suppliers, customers, and business partners. The consequences of such adverse effects could include interruptions or delays in our suppliers’ performance of our contracts, reductions and delays in customer purchases, delays in or the inability of customers to obtain financing to purchase our products, and bankruptcy of customers. Any of these events may adversely affect our financial condition, cash flows, and profitability.

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RISKS RELATED TO OUR COMMON STOCK
Because we have no near term plans to pay cash dividends on our common stock, investors must look solely to stock appreciation for a return on their investment in us.
We have never declared or paid any cash dividends on our common stock. We currently intend to retain all available funds and any future earnings for use in the operation and expansion of our business and do not anticipate declaring or paying any cash dividends on our common stock in the near term. Any future determination as to the declaration and payment of cash dividends will be at the discretion of our board of directors and will depend on then-existing conditions, including our financial condition, results of operations, contractual restrictions, capital requirements, business prospects, and other factors that our board of directors considers relevant.
If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our common stock, or if our operating results do not meet their expectations, our stock price could decline.
The trading market for our common stock is influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our common stock or if our operating results do not meet their expectations, our stock price could decline.
The price of our common stock historically has been volatile. This volatility may affect the price at which you could sell your common stock.
The market price for our common stock has varied between a high of $20.81 on August 30, 2018, and a low of $13.73 on December 24, 2018, during the year ended December 31, 2018. This volatility may affect the price at which you could sell your common stock. Our stock price is likely to continue to be volatile and subject to significant price and volume fluctuations in response to market and other factors; variations in our quarterly operating results from our expectations or those of securities analysts or investors; downward revisions in securities analysts’ estimates; and announcement by us or our competitors of significant acquisitions, strategic partnerships, joint ventures, or capital commitments.
The market for our common stock has been historically illiquid, which may affect your ability to sell your shares.
The volume of trading in our common stock has historically been low. In addition, a substantial amount of our common stock is beneficially owned by three investors. The lack of substantial liquidity can adversely affect the price of our stock at a time when you might want to sell your shares. There is no guarantee that an active trading market for our common stock will develop or be maintained on the NYSE, or that the volume of trading will be sufficient to allow for timely trades. Investors may not be able to sell their shares quickly or at the latest market price if trading in our stock is not active or if trading volume is limited. In addition, if trading volume in our common stock is limited, trades of relatively small numbers of shares may have a disproportionate effect on the market price of our common stock.
Delaware law, our charter documents, and concentrated stock ownership may impede or discourage a takeover, which could reduce the market price of our common stock.
We are a Delaware corporation and the anti-takeover provisions of Delaware law impose various impediments to the ability of a third party to acquire control of us, even if a change in control would be beneficial to our existing stockholders. For example, the change in ownership limitations contained in Article 11 of our certificate of incorporation could have the effect of discouraging or impeding an unsolicited takeover proposal. In addition, our board of directors or a committee thereof has the power, without stockholder approval, to designate the terms of one or more series of preferred stock and issue shares of preferred stock. The ability of our board of directors or a committee thereof to create and issue a new series of preferred stock and certain provisions of Delaware law and our certificate of incorporation and bylaws could impede a merger, takeover, or other business combination involving us or discourage a potential acquirer from making a tender offer for our common stock, which, under certain circumstances, could reduce the market price of our common stock.
Zell Credit Opportunities Master Fund, L.P. (“ZCOF”), Blackrock, Inc., and Whitebox Advisors, LLC (“Whitebox”), together with their respective affiliates, each owned or had the right to acquire as of December 31, 2018 approximately 27.8%, 9.8%, and 7.1%, respectively, of our outstanding common stock. The level of their combined ownership of shares of our common stock could have the effect of discouraging or impeding an unsolicited acquisition proposal.

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We may issue preferred stock with terms that could adversely affect the voting power or value of our common stock and any future issuances of our common stock may reduce our stock price.
Our certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations, and relative rights, including preferences over our common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock.
Additionally, we are not restricted from issuing additional shares of common stock, or securities convertible into common stock, under a registration statement declared effective by the SEC. We cannot predict the size of future issuances of our common stock. However, one or more large issuances of our common stock, or securities convertible into our common stock, may adversely affect the prevailing market price of our common stock.
Item  1B. UNRESOLVED STAFF COMMENTS
None.
Item  2. PROPERTIES
Please read “Item 1. — Business” of this Form 10-K for the location and general character of the properties used in our refining, retail, and logistics segments. Our corporate headquarters are located at 825 Town & Country Lane, Suite 1500, Houston, Texas 77024. We believe that these properties and facilities are adequate for our operations and are maintained in a good state of repair.
Natural Gas and Oil Properties
Laramie Energy
All of the assets held by Laramie Energy are located in Garfield, Mesa, and Rio Blanco Counties, Colorado. All of the natural gas, natural gas liquids, and crude oil are produced primarily from the Mesaverde Formation and to a lesser extent the Mancos Formation and some of the acreage is contiguous. The geology of the Piceance Basin is characterized as highly consistent and predictable over large areas, which generally equates to reliable timing and cost expectations during drilling and completion activities, as well as minimal well-to-well variance in production and reserves when completed with the same methodology. Laramie Energy considers the Mesaverde Formation within Garfield, Mesa, and Rio Blanco Counties, Colorado, to be a single field. Laramie Energy and its predecessor company have drilled over 300 natural gas wells with over a 99% success rate in the Piceance Basin.
Other
We also own certain immaterial minority working interests in wells located in the various regions of the Southwest United States. Please read Note 24—Supplemental Oil and Gas Disclosures (Unaudited) to our consolidated financial statements under Item 8 of this Form 10-K for additional information.
Reserves
For a table presenting the estimated natural gas and crude oil reserves we own indirectly through Laramie Energy, please read “Item 1. — Business — Other Operations” of this Form 10-K. The natural gas and crude oil reserves we own directly are not material.
Internal Controls Over Reserve Estimates, Technical Qualifications, and Technologies Used
Our policies regarding internal controls require our reserve estimates to be prepared in compliance with the SEC definitions and guidance by an independent third-party reserve engineering firm. These reserve estimates are reviewed and approved by our reserves committee, which ensures that our reserves estimates and related disclosures are prepared in compliance with SEC definitions and guidance taking into consideration recent developments, including the impact of changes in commodity price and drilling and transportation costs, drilling and completion technological innovations, the evaluation of historical conversion rates for previous proved undeveloped reserves, and deviations from previously sanctioned development plans for such reserves.
Our reserves committee is comprised of the following members: our Chief Executive Officer, our Chief Financial Officer, our General Counsel and Secretary, our Chief Accounting Officer, our Associate General Counsel, our Assistant Controller, and

31




a mergers and acquisitions analyst with a background in the oil and gas industry. The reserves committee also consults with representatives from our independent reserve engineering firm. In addition, with respect to the reserves that we own indirectly through Laramie Energy, our Chief Executive Officer, our Chief Financial Officer, and our mergers and acquisitions analyst participate in Laramie Energy’s board of managers meetings (which generally occur at least quarterly) as our appointees to Laramie Energy’s board of managers under the Laramie Energy limited liability company agreement. Together with the other members of our reserves committee, our Chief Executive Officer and our Chief Financial Officer review Laramie Energy’s development plan and related capital expenditures and meet regularly with Laramie Energy’s management in connection with our review of the development and classification of such reserves to ensure that such reserves are prepared in compliance with SEC definitions and guidance. Under the Laramie Energy limited liability company agreement, Laramie Energy is required to provide to us certain reports and other information on a monthly, quarterly, and annual basis, including monthly and quarterly reports with respect to drilling and completion activities and a comparison of budgeted amounts for such month or quarter to the actual results of operations for such month or quarter (with a written explanation of any material variances). This information allows our reserves committee to monitor Laramie Energy’s development activities and to evaluate any deviations from Laramie Energy’s development plan to ensure compliance with SEC definitions and guidance. The reserves committee also utilizes the information received from Laramie Energy to provide feedback to Laramie Energy (through Laramie Energy’s board of managers, if necessary) with respect to such development activities. The enhanced scrutiny and evaluation of Laramie Energy’s development plan by our reserves committee, supported by access to information required by Laramie Energy’s organizational documents and our ability to provide feedback to Laramie Energy at the highest organizational level, ensure that our reserves estimates and related disclosures are prepared in compliance with SEC definitions and guidance.
As we do not operate our interests in our natural gas and crude oil assets, we do not have an internal reserve engineering staff and do not prepare any internal reserve estimates. William Monteleone, our Chief Financial Officer and the chair of our reserves committee, reviews the independence and professional qualifications of the third-party engineering firms we engage with the other members of our reserves committee. He also supervises the submission of technical and financial data to third-party engineering firms and reviews the prepared reports with the other members of our reserves committee. Mr. Monteleone has more than ten years of experience in senior financial positions in the oil and gas industry. The reserves estimates shown herein have been independently evaluated by Netherland, Sewell & Associates, Inc. (“NSAI”), a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Benjamin W. Johnson and Mr. John G. Hattner. Mr. Johnson, a Licensed Professional Engineer in the State of Texas (No. 124738), has been practicing consulting petroleum engineering at NSAI since 2007 and has over two years of prior industry experience. He graduated from Texas Tech University in 2005 with a Bachelor of Science Degree in Petroleum Engineering. Mr. Hattner, a Licensed Professional Geoscientist in the State of Texas, Geophysics (License No. 559), has been practicing consulting petroleum geoscience at NSAI since 1991 and has over 11 years of prior industry experience. He graduated from University of Miami, Florida, in 1976 with a Bachelor of Science Degree in Geology; from Florida State University in 1980 with a Master of Science Degree in Geological Oceanography; and from Saint Mary’s College of California in 1989 with a Master of Business Administration Degree. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines. The professional qualifications of the individuals at NSAI who were responsible for overseeing the preparation of our reserve estimates as of December 31, 2018 have been filed as part of Exhibit 99.1 to this Annual Report on Form 10-K.
A variety of methodologies were used to determine our proved reserves estimates. The principal methodologies employed are decline curve analysis, analog type curve analysis, log analysis, and analogy. Substantially all of our proved reserves estimates are determined based on a combination of these methods.
Production Volumes, Unit Prices and Costs
All of Laramie Energy’s properties are located in Garfield, Mesa, and Rio Blanco Counties, Colorado. Substantially all of Laramie Energy’s total estimated proved reserves are located in the same geological formation, the Mesaverde Formation, which Laramie Energy considers to be a single field.

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The following table sets forth certain information regarding volumes of production sold, average prices received, and production costs associated with our share of Laramie Energy’s production and sales of natural gas and crude oil for the years ended December 31, 2018, 2017, and 2016.
 
 
Year Ended December 31,
 
2018
 
2017
 
2016
Production volumes
 
 
 
 
 
Oil (Mbbls)
106

 
71

 
59

NGLs (Mbbls)
712

 
608

 
552

Natural Gas (MMcf)
25,513

 
18,104

 
15,192

Total (MMcfe)
30,421

 
22,178

 
18,858

Net average daily production
 
 
 
 
 
Oil (Bbls)
290

 
190

 
160

NGLs (Bbls)
1,951

 
1,662

 
1,508

Natural Gas (Mcf)
69,899

 
49,460

 
41,509

Average sales price
 
 
 
 
 
Oil (Per Bbl)
$
55.43

 
$
45.61

 
$
37.85

NGLs (Per Bbl)
26.26

 
20.02

 
11.61

Natural Gas (per Mcf)
2.67

 
2.81

 
2.30

Hedge gain (loss) (per Mcfe)
(0.19
)
 
(1.25
)
 
(1.47
)
Production costs (per Mcfe) (1)
1.28

 
1.36

 
1.38

________________________________________________________
(1) Production costs (per Mcfe) exclude ad valorem and severance taxes.
The table above excludes production volumes related to our other non-operated natural gas and oil interests of 40 MMcfe, 59 MMcfe, and 66 MMcfe for the years ended December 31, 2018, 2017, and 2016, respectively. Please read Note 24—Supplemental Oil and Gas Disclosures (Unaudited) to our consolidated financial statements under Item 8 of this Form 10-K for further information on our proved reserves related to our other non-operated natural gas and oil interests.
Proved Undeveloped Reserves
All of our proved undeveloped reserves at December 31, 2018 are held through our non-controlling equity ownership in Laramie Energy. The following table provides information regarding changes in our share of Laramie Energy’s proved undeveloped reserves for the year ended December 31, 2018.
 
Gas
 
Oil
 
NGLs
 
Total
 
(MMcf)
 
(Mbbl)
 
(Mbbl)
 
(MMcfe)
Proved undeveloped reserves at December 31, 2017
118,578

 
449

 
2,913

 
138,750

Revisions of previous estimates
25,702

 
114


1,787

 
37,108

Extensions and discoveries

 

 

 

Acquisitions

 

 

 

Conversion to proved developed reserves
(62,852
)
 
(238
)
 
(985
)
 
(70,190
)
Proved undeveloped reserves at December 31, 2018
81,428

 
325

 
3,715

 
105,668

As of December 31, 2018, our share of Laramie Energy’s proved undeveloped reserves totaled 105,668 MMcfe, an approximate 24% decrease from proved undeveloped reserves at December 31, 2017. The decrease in our share of Laramie Energy’s proved undeveloped reserves was due to the following:
During the year ended December 31, 2018, Laramie Energy expended approximately $60.4 million in connection with the development of its proved undeveloped reserves. Our share of Laramie Energy’s proved undeveloped reserves converted to proved developed reserves during 2018 was 70,190 MMcfe. This activity represented 51% of the prior year-end proved undeveloped reserves. The total number of proved undeveloped locations converted to proved developed

33




reserves during 2018 was substantially consistent with Laramie Energy’s original development plan. Of the 127 locations converted to proved developed locations in 2018, 112 were originally scheduled to be completed in 2018, and the remaining 15 were accelerated into 2018.
Revisions of previous estimates of 37,108 MMcfe were mainly driven by the addition of 60,679 MMCfe of proved undeveloped reserves primarily located within Laramie Energy's northern acreage where adequate midstream capacity exists and development economics are more favorable due to Laramie Energy's elevated net revenue interests within these reserves. The additions were partially offset by 26,996 MMcfe of proved undeveloped reserves that were removed due to Laramie Energy's primary midstream provider limiting additional volumes from the area where the reserves are located. The remaining positive revisions are related to performance improvements.
In recognition of the potential impact of recent commodity price volatility and Par’s position as an equity interest owner without control of Laramie Energy’s operations, Par continues to base its determination of Laramie Energy’s proved undeveloped reserves at year end 2018 on a two year drilling and three year completion time horizon compared to the 5-year time horizon permitted under SEC requirements. Members of our reserves committee met regularly with Laramie Energy’s management to finalize our determination of proved undeveloped reserves at year end 2018.
Laramie Energy expects to expend approximately $66.8 million and $66.3 million to convert approximately 61 and 53 proved undeveloped locations to proved developed reserves in 2019 and 2020, respectively. At December 31, 2018, Laramie Energy had 23 proved undeveloped locations that were drilled but not yet completed. Through March 1, 2019, Laramie Energy had already drilled 8 and completed 18 of the proved undeveloped locations included in the 2018 reserve report.
As of December 31, 2018, Laramie Energy had no proved undeveloped reserves that remain undeveloped for five years or more after booking as proved reserves.
Productive Wells and Acreage
The table below shows, as of December 31, 2018, our share of Laramie Energy’s gross and net wells and developed acres. Developed acreage consists of acres spaced or assignable to productive wells.
 
 
Productive Wells
 
 
 
 
 
 
Oil 
 
Gas (1)
 
Developed Acres
Location
 
Gross (2)
 
Net (3)
 
Gross (2)
 
Net (3)
 
Gross (2)
 
Net (3)
Colorado (4)
 

 

 
1,855

 
673

 
26,552

 
9,951

_____________________________________________
(1)
Some of the wells classified as “gas” wells also produce minor amounts of crude oil.
(2)
A “gross well” or “gross acre” is a well or acre in which a working interest is held. The number of gross wells or acres is the total number of wells or acres in which a working interest is owned.
(3)
A “net well” or “net acre” is deemed to exist when the sum of fractional ownership interests in gross wells or acres equals one. The number of net wells or net acres is the sum of the fractional working interests owned in gross wells or gross acres expressed as whole numbers and fractions thereof.
(4)
Net wells and net developed acres are reflected as if we owned our interest directly.

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Undeveloped Acreage
At December 31, 2018, our share of undeveloped acreage held through our ownership in Laramie Energy was as follows:
 
 
Undeveloped Acres (1) (2)
Location
 
Gross
 
Net
Colorado (3)
 
338,793

 
92,943

________________________________________________
(1)
Undeveloped acreage is considered to be those lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and gas, regardless of whether such acreage contains proved reserves.
(2)
There are no material near-term lease expirations for which the carrying value at December 31, 2018 has not already been impaired in consideration of these expirations or capital budgeted to convert acreage to held by production.
(3)
Net undeveloped acres are reflected as if we owned our interest directly.

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Drilling Activity
Laramie Energy is currently running one drilling rig performing multi-well pad drilling in the Mesaverde Formation. Due to the emergence and further refinement of certain technological innovations in completion techniques such as low-cost proppantless fracturing, or “sandless fracing,” Laramie Energy is utilizing enhanced frac design to reduce the overall number of wells required to drain the same proven undeveloped acreage. As a result, Laramie Energy adjusted its development well pattern from three to two column spacing per section in 2017 to account for these improvements. This drilling pattern is intended to more efficiently develop the same sections, acreage, and reserves as were targeted in prior development plans with fewer wells per section. Our current development plan is designed to take advantage of the improved efficiencies provided by this drilling pattern as well as cost reductions provided by the January 2017 renegotiation of Laramie Energy's primary gathering and processing agreement, as well as a $17.6 million water gathering, treating, storage, and redelivery system completed by Laramie Energy in 2017 (the “water treatment facility”). During 2018, drill times averaged 4.7 days per well, or 6.5 wells per month, and the typical pad contained 13-21 wells, depending on the well spacing being utilized on the pad. At December 31, 2018, Laramie Energy had 23 gross and net proved undeveloped locations that were drilled but not completed.
The table below shows the number of development wells completed by Laramie Energy during the periods indicated. Laramie Energy drilled no exploratory productive or dry wells during 2018, 2017 or 2016.
 
 
Year ended December 31,
 
 
2018
 
2017
 
2016
 
 
Gross (1)
 
Net (2)
 
Gross (1)
 
Net (2)
 
Gross (1)
 
Net (2)
Development
 
 
 
 
 
 
 
 
 
 
 
 
Productive
 
140

 
140

 
74

 
74

 
56

 
48

Dry
 

 

 

 

 

 

Total
 
140

 
140

 
74

 
74

 
56

 
48


(1)
A “gross well” is a well in which a working interest is held. The number of gross wells is the total number of wells in which a working interest is owned.
(2)
A “net well” is deemed to exist when the sum of fractional ownership interests in gross wells equals one. The number of net wells is the sum of the fractional working interests owned in gross wells expressed as whole numbers and fractions thereof.

Delivery Commitments
Laramie Energy has entered into certain gathering, processing and transportation contracts with third parties that require Laramie Energy to deliver fixed, determinable quantities of production over specified periods of time. Under these agreements, Laramie Energy is required to make deficiency payments for any shortfalls associated with minimum volume commitments. Laramie Energy expects to fulfill delivery commitments under gathering, processing and transportation agreements from proved developed and undeveloped reserves.
    
The table below shows Laramie Energy's minimum volume commitments under gathering, processing, and transportation contracts as of December 31, 2018 (in MMcfe).
2019
69,451

2020
28,473

2021
23,343

2022
10,186

2023
8,987

Thereafter
31,059

Total delivery commitments
171,499



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Item  3. LEGAL PROCEEDINGS
Consent Decree
On July 18, 2016, PHR and subsidiaries of Tesoro entered into a consent decree with the EPA, the 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, including the Par East facility of our Hawaii refinery. 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 in the third quarter of 2016, work related to the Consent Decree is ongoing. 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 date of the closing of the PHR acquisition. Tesoro is obligated to pay all applicable fines and penalties related to the Consent Decree.
Other
From time to time, we may be involved in other litigation relating to claims arising out of our operations in the normal course of our business. As of the date of this Annual Report on Form 10-K, no legal proceedings are pending against us that we believe individually or collectively could have a materially adverse effect upon our financial condition, results of operations, or cash flows. Any litigation pending at the time we emerged from Chapter 11 was transferred to the General Trust for resolution and settlement. For more information, please read “Item 1. — Business—Bankruptcy and Plan of Reorganization – General Recovery Trust” and Note 15—Commitments and Contingencies to our consolidated financial statements under Item 8 of this Form 10-K.
Item  4. MINE SAFETY DISCLOSURES
Not applicable.

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PART II
Item  5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Information
On February 20, 2018, our common stock began trading on the NYSE under the symbol “PARR.” Prior to that date, our common stock was traded on the NYSE American under the symbol “PARR.” As of March 4, 2019, there were 171 common stockholders of record. On March 4, 2019, the closing price of our common stock was $16.66 per share on the NYSE.
Dividends
We have not paid dividends on our common stock and we do not expect to do so in the foreseeable future.
Stock Performance Graph
The following performance graph and related information shall not be deemed “soliciting material” or “filed” with the SEC, nor shall such information be deemed to be incorporated by reference into any future filings under the Securities Act of 1933 or the Securities Exchange Act of 1934, each as amended.
This performance graph and the related textual information are based on historical data and are not indicative of future performance. The following line graph compares the cumulative total return on an investment in our common stock against the cumulative total return of the S&P 500 Composite Index and an index of peer companies (that we selected) for the five fiscal years ended December 31, 2018. The performance graph of our peer group is weighted by market value at the beginning of the period and our peer group consists of the following companies: Calumet Specialty Products Partners, L.P., Casey’s General Stores, Inc., CVR Energy, Inc., Darling Ingredients Inc., Delek US Holdings, Inc., FutureFuel Corp., Green Plains Inc., Macquarie Infrastructure Corporation, Methanex Corporation, Pacific Ethanol, Inc., Renewable Energy Group, Inc., REX American Resources Corporation, SEACOR Holdings Inc., Stepan Company, and Westlake Chemical Corporation. We believe our peer group, which is made up of oil and gas refining and marketing companies, retailers, and companies that are generally similar to our operating segments, provides for meaningful comparability to our business as a whole.
chart-950a25748a375d37bca.jpg
*$100 invested on December 31, 2013 in stock or index, including reinvestment of dividends.

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Recent Sales of Unregistered Securities
During the year ended December 31, 2018, we did not have any sales of securities in transactions that were not registered under the Securities Act that have not been reported on Form 8-K or Form 10-Q.
Issuer Purchases of Equity Securities
The following table sets forth certain information with respect to repurchases of our common stock during the quarter ended December 31, 2018:
Period
 
Total number of shares (or units) purchased (1)
 
Average price paid per share (or unit)
 
Total number of shares (or units) purchased as part of publicly announced plans or programs
 
Maximum number (or approximate dollar value) of shares (or units) that may yet be purchased under the plans or programs
October 1 - October 31, 2018
 

 
$

 

 

November 1 - November 30, 2018
 

 

 

 

December 1 - December 31, 2018
 
1,293

 
14.18

 

 

Total
 
1,293

 
$
14.18

 

 

________________________________________________
(1)
All shares repurchased were surrendered by employees to pay taxes withheld upon the vesting of restricted stock awards.

39




Item 6. SELECTED FINANCIAL DATA
The selected financial information presented below as of December 31, 2018 and 2017 and for the years ended December 31, 2018, 2017, and 2016 was derived from our audited consolidated financial statements included elsewhere in this Annual Report on Form 10-K. The selected financial information presented below as of December 31, 2016, 2015, and 2014 and for the years ended December 31, 2015 and 2014 was derived from our audited consolidated financial statements not included in this Annual Report on Form 10-K. The selected financial information should be read in conjunction with the consolidated financial statements and related notes and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
 
 
Year Ended December 31,
(in thousands, except per share data)
 
2018 (1)
 
2017 (2)
 
2016 (2) (3)
 
2015 (4)
 
2014
Statement of Operations Data:
 
 
 
 
 
 
 
 
 
 
Revenues
 
$
3,410,728

 
$
2,443,066

 
$
1,865,045

 
$
2,066,337

 
$
3,108,025

Depreciation, depletion and amortization
 
52,642

 
45,989

 
31,617

 
19,918

 
14,897

Impairment expense
 

 

 

 
9,639

 

Operating income (loss)
 
81,941

 
93,961

 
(19,649
)
 
61,514

 
(37,532
)
Interest expense and financing costs, net
 
(39,768
)
 
(31,632
)
 
(28,506
)
 
(20,156
)
 
(17,995
)
Debt extinguishment and commitment costs
 
(4,224
)
 
(8,633
)
 

 
(19,669
)
 
(1,788
)
Gain on curtailment of pension obligation
 

 

 
3,067

 

 

Change in value of common stock warrants
 
1,801

 
(1,674
)
 
2,962

 
(3,664
)
 
4,433

Change in value of contingent consideration
 
(10,500
)
 

 
10,770

 
(18,450
)
 
2,849

Equity earnings (losses) from Laramie Energy, LLC
 
9,464

 
18,369

 
(22,381
)
 
(55,983
)
 
2,849

Net income (loss)
 
39,427

 
72,621

 
(45,835
)
 
(39,911
)
 
(47,041
)
Income (loss) per diluted common share
 
0.85

 
1.57

 
(1.08
)
 
(1.06
)
 
(1.44
)
Balance Sheet Data:
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
75,076

 
$
118,333

 
$
47,772

 
$
167,788

 
$
89,210

Total current assets
 
586,592

 
603,544

 
403,108

 
531,752

 
460,789

Total assets
 
1,460,734

 
1,347,407

 
1,145,433

 
892,261

 
735,236

Total current liabilities
 
507,201

 
470,952

 
382,765

 
365,040

 
310,806

Total long-term debt, net of current maturities
 
392,607

 
384,812

 
350,110

 
154,212

 
101,739

Total liabilities
 
948,405

 
899,688

 
776,524

 
551,650

 
443,077

Total stockholders’ equity
 
512,329

 
447,719

 
368,909

 
340,611

 
292,159

_________________________________________________________
(1)
We completed the Northwest Retail Acquisition effective March 23, 2018, therefore the results of Northwest Retail are only included subsequent to March 23, 2018. Please read Note 4—Acquisitions to the consolidated financial statements under Item 8 of this Form 10-K for further information.
(2)
Operating income (loss) for the year ended December 31, 2016 was retrospectively recast to reflect the reclassification of the curtailment gain of $3.1 million related to an amendment on our defined benefit pension plan from Operating expense (excluding depreciation) to a newly defined line within Total other income (expense), net, Gain on curtailment of pension obligation. For the years ended December 31, 2017 and 2016, other immaterial non-service-cost-related components of the net periodic benefit cost related to our defined benefit pension plan were reclassified from Operating expense (excluding depreciation) to Other income (expense), net. Please read Note 2—Summary of Significant Accounting Policies and Note 17—Benefit Plans to the consolidated financial statements under Item 8 of this Form 10-K for further information.
(3)
We completed the WRC Acquisition effective July 14, 2016, therefore the results of WRC are only included subsequent to July 14, 2016. Please read Note 4—Acquisitions to the consolidated financial statements under Item 8 of this Form 10-K for further information.
(4)
We completed the acquisition of Mid Pac effective April 1, 2015, therefore, the results of Mid Pac are only included subsequent to April 1, 2015.

40




Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview
We are a growth-oriented company based in Houston, Texas, that owns and operates market-leading energy and infrastructure businesses. For more information, please read “Part I –Item 1. — Business—Overview” of this Form 10-K.
Recent Events Affecting Comparability of Periods
Hawaii Refinery Expansion
On December 19, 2018, we completed the Hawaii Refinery Expansion 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 newly acquired assets are included in our refining segment commencing December 19, 2018.
Northwest Retail Acquisition
On January 9, 2018, we entered into an Asset Purchase Agreement with CHS, Inc. to acquire 33 retail outlets at various locations in Washington and Idaho. On March 23, 2018, we completed the Northwest Retail Acquisition for cash consideration of approximately $74.5 million. 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 retail outlets.The results of operations of Northwest Retail are included in our retail segment commencing March 23, 2018. Please read Note 4—Acquisitions to our consolidated financial statements under Item 8 of this Form 10-K for more information.
Amended and Restated J. Aron Supply and Offtake Agreements
On June 27, 2018, we and J. Aron amended the Supply and Offtake Agreements to increase the amount that we may defer under the deferred payment arrangement. Prior to June 27, 2018, we had the right to defer payments owed to J. Aron up to the lesser of $125 million or 85% of eligible accounts receivable and inventory. Effective June 27, 2018, we have the right to defer payments owed to J. Aron up to the lesser of $165 million or 85% of eligible accounts receivable and inventory. On December 5, 2018, we amended and restated the Supply and Offtake Agreements to account for additional processing capacity provided through the Hawaii Refinery Expansion. Please read Note 11—Inventory Financing Agreements to our consolidated financial statements under Item 8 of this Form 10-K for more information.
Other Factors Affecting Comparability of Prior Periods
We completed the WRC Acquisition on July 14, 2016, for cash consideration of $209.4 million, including a deposit of $5.0 million paid in June 2016 and assumed debt consisting of term loans of $58.0 million and revolving loans of $10.1 million. The results of operations of WRC are included in our segments effective July 14, 2016. Please read Note 4—Acquisitions to our consolidated financial statements under Item 8 of this Form 10-K for more information.
Subsequent Events
On January 11, 2019, we completed the Washington Refinery Acquisition for total consideration of $326.7 million, including acquired 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 will be included in our refining and logistics segments commencing January 11, 2019. Please read Note 22—Subsequent Events to our consolidated financial statements under Item 8 of this Form 10-K for more information.
Results of Operations
Year Ended December 31, 2018 Compared to Year Ended December 31, 2017
Net Income (Loss). Our net income decreased from $72.6 million for the year ended December 31, 2017 to net income of $39.4 million for the year ended December 31, 2018. The decrease in our net income was primarily driven by lower refining margins, a $10.5 million charge related to the Tesoro earn-out settlement, higher acquisition and integration costs, and a decrease in our Equity earnings (losses) from Laramie Energy, partially offset by improved margins in our retail segment. Other factors impacting our results period over period include increased interest expense and financing fees, and depreciation, depletion, and amortization (“DD&A”).

41




Adjusted EBITDA and Adjusted Net Income (Loss). For the year ended December 31, 2018, Adjusted EBITDA was $132.1 million compared to $140.8 million for the year ended December 31, 2017. The change was primarily related to lower refining margins driven by unfavorable crude differentials, partially offset by improved margins in our retail segment and an increase in refined product sales volumes and crack spreads.
For the year ended December 31, 2018, Adjusted Net Income (Loss) was approximately $49.3 million compared to approximately $63.3 million for the year ended December 31, 2017. The change was primarily related to the same factors described above for the decrease in Adjusted EBITDA, increased interest expense and financing fees, and DD&A.
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016
Net Income (Loss). During 2017, our financial performance was primarily driven by improved crack spreads, which was reflected in a change in our net income (loss) from a net loss of $45.8 million for the year ended December 31, 2016 to net income of $72.6 million for the year ended December 31, 2017. Other factors impacting our results period over period include the full-year contribution provided by Wyoming Refining, which was acquired on July 14, 2016, and an improvement in our Equity earnings (losses) from Laramie Energy, LLC, partially offset by debt extinguishment and commitment costs and the change in value of the contingent consideration obligation during 2016.
Adjusted EBITDA and Adjusted Net Income (Loss). For the year ended December 31, 2017, Adjusted EBITDA was $140.8 million compared to $33.5 million for the year ended December 31, 2016. The change was primarily related to improved crack spreads and the full-year contribution provided by Wyoming Refining, which was acquired on July 14, 2016.
For the year ended December 31, 2017, Adjusted Net Income (Loss) was income of approximately $63.3 million compared to a loss of $32.4 million for the year ended December 31, 2016. The change was primarily related to improved crack spreads, the full-year contribution provided by Wyoming Refining, and an improvement in our Equity earnings (losses) from Laramie Energy excluding our share of Laramie's unrealized gain (loss) on derivatives, partially offset by an increase in Interest expense and financing costs, net.
The following table summarizes our consolidated results of operations for the years ended December 31, 2018, 2017, and 2016 (in thousands). The following should be read in conjunction with our consolidated financial statements under Item 8 of this Annual Report on Form 10-K.
 
Year Ended December 31,
 
2018
 
2017
 
2016
Revenues
$
3,410,728

 
$
2,443,066

 
$
1,865,045

Cost of revenues (excluding depreciation)
3,003,116

 
2,054,627

 
1,636,339

Operating expense (excluding depreciation)
215,284

 
202,016

 
169,371

Depreciation, depletion, and amortization
52,642

 
45,989

 
31,617

General and administrative expense (excluding depreciation)
47,426

 
46,078

 
42,073

Acquisition and integration costs
10,319

 
395

 
5,294

Total operating expenses
3,328,787

 
2,349,105

 
1,884,694

Operating income (loss)
81,941

 
93,961

 
(19,649
)
Other income (expense)
 
 
 
 
 
Interest expense and financing costs, net
(39,768
)
 
(31,632
)
 
(28,506
)
Debt extinguishment and commitment costs
(4,224
)
 
(8,633
)
 

Gain on curtailment of pension obligation

 

 
3,067

Other income (expense), net
1,046

 
911

 
(10
)
Change in value of common stock warrants
1,801

 
(1,674
)
 
2,962

Change in value of contingent consideration
(10,500
)
 

 
10,770

Equity earnings (losses) from Laramie Energy, LLC
9,464

 
18,369

 
(22,381
)
Total other expense, net
(42,181
)
 
(22,659
)
 
(34,098
)
Income (loss) before income taxes
39,760

 
71,302

 
(53,747
)
Income tax benefit (expense)
(333
)
 
1,319

 
7,912

Net income (loss)
$
39,427

 
$
72,621

 
$
(45,835
)

42




The following tables summarize our operating income (loss) by segment for the years ended December 31, 2018, 2017, and 2016 (in thousands). The following should be read in conjunction with our consolidated financial statements under Item 8 of this Annual Report on Form 10-K.
Year ended December 31, 2018
 
Refining
 
Logistics (1)
 
Retail
 
Corporate, Eliminations and Other (2)
 
Total
Revenues
 
$
3,210,067

 
$
125,743

 
$
441,040

 
$
(366,122
)
 
$
3,410,728

Cost of revenues (excluding depreciation)
 
2,957,995

 
77,712

 
333,664

 
(366,255
)
 
3,003,116

Operating expense (excluding depreciation)
 
146,320

 
7,782

 
61,182

 

 
215,284

Depreciation, depletion, and amortization
 
32,483

 
6,860

 
8,962

 
4,337

 
52,642

General and administrative expense (excluding depreciation)
 

 

 

 
47,426

 
47,426

Acquisition and integration costs
 

 

 

 
10,319

 
10,319

Operating income (loss)
 
$
73,269

 
$
33,389

 
$
37,232

 
$
(61,949
)
 
$
81,941

Year ended December 31, 2017
 
Refining
 
Logistics (1)
 
Retail
 
Corporate, Eliminations and Other (2)
 
Total
Revenues
 
$
2,319,638

 
$
121,470

 
$
326,076

 
$
(324,118
)
 
$
2,443,066

Cost of revenues (excluding depreciation)
 
2,062,804

 
66,301

 
249,097

 
(323,575
)
 
2,054,627

Operating expense (excluding depreciation)
 
141,065

 
15,010

 
45,941

 

 
202,016

Depreciation, depletion, and amortization
 
29,753

 
6,166

 
6,338

 
3,732

 
45,989

General and administrative expense (excluding depreciation)
 

 

 

 
46,078

 
46,078

Acquisition and integration costs
 

 

 

 
395

 
395

Operating income (loss)
 
$
86,016

 
$
33,993

 
$
24,700

 
$
(50,748
)
 
$
93,961

Year ended December 31, 2016
 
Refining
 
Logistics (1)
 
Retail
 
Corporate, Eliminations and Other (2)
 
Total
Revenues
 
$
1,702,463

 
$
102,779

 
$
290,402

 
$
(230,599
)
 
$
1,865,045

Cost of revenues (excluding depreciation)
 
1,580,014

 
65,439

 
220,545

 
(229,659
)
 
1,636,339

Operating expense (excluding depreciation)
 
115,818

 
11,239

 
41,291

 
1,023

 
169,371

Depreciation, depletion, and amortization
 
17,565

 
4,679

 
6,372

 
3,001

 
31,617

General and administrative expense (excluding depreciation)
 

 

 

 
42,073

 
42,073

Acquisition and integration costs
 

 

 

 
5,294

 
5,294

Operating income (loss)
 
$
(10,934
)
 
$
21,422

 
$
22,194

 
$
(52,331
)
 
$
(19,649
)
________________________________________________________
(1)
Our logistics operations consist primarily of intercompany transactions which eliminate on a consolidated basis.
(2)
Includes eliminations of intersegment Revenues and Cost of revenues (excluding depreciation) of $365.5 million, $325.2 million, and $271.9 million for the years ended December 31, 2018, 2017, and 2016, respectively.

43




Below is a summary of key operating statistics for the refining segment for the years ended December 31, 2018, 2017, and 2016:
<
 
 
Year Ended December 31,
 
 
2018
 
2017
 
2016
Total Refining Segment
 
 
 
 
 
 
Feedstocks Throughput (Mbpd) (1)
 
91.3

 
89.2

 
86.0

Refined product sales volume (Mbpd) (1)
 
100.3

 
90.7

 
90.6

 
 
 
 
 
 
 
Hawaii Refinery
 
 
 
 
 
 
Feedstocks Throughput (Mbpd)
 
74.9

 
73.7

 
70.2

Source of Crude Oil:
 
 
 
 
 
 
North America
 
35.0
%
 
23.8
%
 
41.7
%
Latin America
 
1.0
%
 
0.1
%
 
3.9
%
Africa
 
32.4
%
 
24.9
%
 
13.7
%
Asia
 
20.6
%
 
23.1
%
 
30.0
%
Middle East
 
11.0
%
 
28.1
%
 
10.7
%
Total
 
100.0
%
 
100.0
%
 
100.0
%