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PA R PA C I F I C
H O L D I N G S , I N C .
owns and operates market-leading energy and infrastructure businesses. Our strategy is to
acquire and develop energy and infrastructure businesses in logisti cally complex markets.
Our common stock is publicly traded on the NYSE under the trading symbol “PARR.”
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Dear Shareholders:
We m a d e g r e a t s t r i d e s l a s t y e a r a s w e r e c o v e r e d f r o m a
ver y dif f icult 2020. Adju s te d EB ITDA improve d from a lo s s
of $(8 7 ) million in 2020 to $ 6 1 million in 202 1 . O ur annual
r e s u l t s d o n o t t e l l t h e f u l l s t o r y a s w e f i n i s h e d t h e y e a r
m u c h s t r o n g e r t h a n w e e n t e r e d .
The first half of 2021 was an extension of the troubled business environment of
the last three quarters of 2020 with fuel demand suppressed by the pandemic
and profits reduced by weak margins. The second half approached normal
conditions as margins improved in all our markets and demand improved to
levels not experienced since the onset of the pandemic. We built significant
momentum entering 2022 on financial and strategic fronts, and our focus
shif ted from awaiting a market recover y to a much healthier focus on
operational reliability and measures taken to meet rising demand. Each of
our refining and logistics units is well-balanced to serve our local markets.
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PAR PACIFIC | 2021 ANNUAL REPORT | 01
Discussion of Business Units
REFINING
Our 2021 refining segment Adjusted EBITDA was
a loss of $(11) million, compared to a loss of
$(168) million in 2020. Excluding a non-cash
mark-to-market (“MTM”) expense of $(46) million
related to increasing Renewable Identification
Numbers (“RINs”) pricing throughout the year,
2021 Adjusted EBITDA would have been $35
million, compared to $(130) million on an
MTM-adjusted basis in 2020. The $165 million
improvement in profitability reflects an ongoing
market recovery from the COVID-19 pandemic
and a related return of refined product
demand across our operating regions. Although
we continue to face uncertainty related to the
pandemic, we remain optimistic given improved
vaccination and global mobility trends.
In Hawaii, profitability was negatively impacted
by the pandemic in 2020. Through various
internal initiatives and macroeconomic factors,
we have returned to nearly break-even Adjusted
EBITDA in 2021 and expect to generate profits in
2022. Although the Singapore 3-1-2 crack spread
continued to be historically low during the first
half of the year, it surpassed pre-pandemic
levels by the end of 2021. Through February of
2022, the Singapore 3-1-2 has averaged over
$12 per barrel, which is above midcycle levels.
Much of this improvement is demand-related,
stemming from the return of air and road traffic
and industrial demand.
Various Chinese policies have also impacted
supply and demand dynamics in Asia. By 2025,
the Chinese government plans to cap the
country’s refining capacity at 20 million barrels
per day and eliminate refined product exports.
Export quotas for 2021 were more than 35%
below 2020 levels and are expected to be
significantly lower this year. The Chinese
government has also implemented tax reforms
and begun to crack down on independent
IMPROVING MARKET FUNDAMENTALS
refiners who have historically evaded taxes in the
country. As a result of these actions, refinery runs
have been cut and refined product inventories
have declined in the region, bolstering Singapore
crack spreads. Global refinery closures have
further supported strong product margins, as
demand is forecasted to increase.
On the crude oil side, however, we have faced
negative impacts due to the rapid rise in
prices and backwardation throughout the year.
Our landed crude differential in Hawaii climbed
throughout the year and somewhat offset
favorable product margins. In a higher price
environment, backwardation generally
increases, meaning future oil contracts are
pricing lower than current contracts. In Hawaii,
we hedge our inventory to protect it from
crude price volatility, which is a benefit when
the market is in contango and an expense
when the market is in backwardation. As prices
climb, we also face a price lag impact on the
portion of our sales contracts that are based
on prior period pricing.
Internally, we have taken action to improve our
profitability in Hawaii. In 2020, we negotiated
changes to our on-island product contracts to
better reflect the changing supply and demand
dynamics after our competitor shut down its
refining operations. Operating with these
contractual changes in place has resulted in
significantly improved product margin capture.
From a full year perspective, we were able to
capture nearly the entire combined index,
meaning gross margin was approximately
equal to the Singapore 3-1-2 less the Hawaii
crude differential. This is a material change
over historical periods, even before the
pandemic, when we reported gross margin at a
steep discount to our reported Singapore 3-1-2
combined index.
$10.78
$6.22
$3.15
$29.00
$23.13
$17.80
$15.30
$15.95
$11.44
2017-19
2020
2021
2017-19
2020
2021
2017-19
2020
2021
SINGAPORE 3.1.2
WYOMING 3.2.1
PACIFIC NORTHWEST 5.2.2.1
02 | PAR PACIFIC | 2021 ANNUAL REPORT
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PAR PACIFIC | 2021 ANNUAL REPORT | 03
2021 INLAND VS. WATERBORNE CRUDE EXPOSURE
ALASKAN NORTH SLOPE • 10%
COLD LAKE • 10%
BAKKEN • 21%
POWDER RIVER BASIN • 9%
OTHER WATERBORNE • 50%
WATERBORNE
INLAND
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In Wyoming, we also achieved a noteworthy
improvement in profitability with a return
to more normalized EBITDA contribution.
Wyoming is a highly seasonal market, with
gasoline demand peaking in the summer
months when tourists visit Mount Rushmore,
the Black Hills, Sturgis, and other destinations
in the Rockies region. Demand declines rapidly
after tourism declines in the fall and remains
low throughout the winter months. This past
summer was exceptionally strong as pent-up
demand for domestic travel drove high regional
fuel consumption, which was reflected in
favorable regional cracks. We ran our units at
record throughput during the second quarter
and reported record EBITDA during the third
quarter as we sold fuel into the tight refined
product market.
Although Washington was our most profitable
refinery during the peak of the pandemic in 2020,
rising crude prices and tightening inland crude
differentials negatively impacted the refinery’s
contribution in 2021. Washington tends to be a
counter-cyclical refinery, performing well
when crude prices are falling. In a rising price
environment, Washington experiences negative
backwardation impacts, like Hawaii. Our refinery
is also unique to others in the region because it is
configured to run inland North American crude
oil, unlike many of our competitors who rely on
waterborne cargoes of Alaskan North Slope
(“ANS”) and foreign-sourced crude oil. In 2020,
inland crude differentials were wide and
advantaged compared to ANS, and the refinery
was profitable. The spread between inland
crudes and ANS tightened materially over
the past year; the Washington refinery was
challenged to generate profits.
Washington product pricing has also not fully
rebounded like our other regions. Rising crude
prices impact pricing for heavy products like
asphalt and vacuum gasoil (“VGO”), which make
up about 40% of Washington refinery yields.
As crude costs rise, heavy product prices do
not respond immediately, and margins tend to
compress. Another factor that impacted capture
2021 COMBINED PRODUCT YIELD
was suppressed distillate demand and pricing,
which have not fully recovered in the region.
Distillate makes up another approximately 40%
of Washington yields. When taken together with
crude and heavy product headwinds, the impact
has been significant. As the market recovery
continues and prices stabilize, we expect to see
a return to profitability in this region.
The discussion of each of our refining regions
above leaves out one significant negative factor
that we faced during 2021, which is the
continued lack of clarity around the Renewable
Fuel Standard. The Environmental Protection
Agency’s (“EPA”) delay in acting on outstanding
prior year small refinery exemptions and
adjusting annual volume requirements resulted
in extremely volatile RINs pricing throughout
the year. We were required to book a $(46)
million expense in the refining segment in 2021
related to our 2019 and 2020 open liability.
Although the EPA’s proposed denial of all
pending hardship petitions was published in
December 2021, that proposal is by no means
final and small refineries cannot rely on the
proposal for compliance planning. If the EPA
finalizes the proposal as written, litigation is
expected to ensue, which will extend the period
of uncertainty regarding compliance planning.
Despite this tremendous hardship, in 2022 we
turn our attention to the areas which are under
our control. We continue to prioritize the safety
of our team and communities and protection of
the environments in which we operate. We also
remain focused on strong operational reliability
and optimizing our refineries to meet local
demand. We plan to invest in small-capital,
high-return debottlenecking projects at each
refinery to enable consistent, slightly higher
throughputs. Our principal focus areas are
distillate production in Hawaii, summer peak
rates in Wyoming, and increasing Canadian crude
consumption in Washington. After the successful
completion of the Washington turnaround, we
do not anticipate significant downtime at any of
our locations for the foreseeable future.
DISTILLATE • 44%
GASOLINE • 28%
LSFO • 15%
ASPHALT • 6%
OTHER • 7%
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PAR PACIFIC | 2021 ANNUAL REPORT | 05
LO GI S T IC S
2021 logistics segment Adjusted EBITDA was $73 million, a significant improvement from $57 million
in 2020. The return of Hawaii tourism and outer island demand contributed the most significant
improvement in profitability. Our Wyoming and Washington logistics throughput also rebounded.
Going forward, we expect this segment to perform well and remain a stable business unit mitigating
the volatility inherent in our refining segment profitability.
In Washington, we continue to focus on expanding our renewable fuels logistics capabilities. During the
past year, we completed upgrades that allow us to load ethanol trucks at the refinery rack. The team is
evaluating additional opportunities to further increase our logistics utilization in renewable service. This
activity both supports our logistics business diversification and our positioning through the energy
transition as liquid fuels are increasingly blended to reduce the carbon intensity of finished products.
RE TAIL
Our retail business continues to generate strong profits. 2021 Adjusted EBITDA was $47 million,
compared to $65 million in 2020. Although rising crude oil prices make it harder to maintain elevated
margins, the team has done a great job in positioning the business for success as prices stabilize.
These results were also affected by the higher rents associated with the $113 million sale-leaseback of
certain Hawaii real estate properties during the first quarter of 2021. On the fuel volume side, gasoline
demand has mostly rebounded, and overall volumes have improved significantly over 2020 levels.
We continue to experience some shortfall in Hawaii related to the decrease in international visitors.
While these tourists are smaller in number, they tend to be greater spenders who visit for longer
periods. We believe there will be another increase in Hawaii refined product demand when Asian
countries (particularly Japan) reduce quarantine requirements for returning citizens.
As we look forward, we are focused on growth and new initiatives to leverage our strong market
positions in Hawaii and the Pacific Northwest. We are undertaking a significant transformation in
our Northwest retail locations with the introduction of our proprietary nomnom brand. We are
simultaneously completing several investments in information technology to improve customer
experience at our locations. We are introducing a loyalty card program, running self-checkout tests
at some of our higher volume stores, and instituting technology to facilitate dynamic fuel pricing.
We expect to begin seeing positive results from these investments this year.
L AR AMIE
We hold a 46% equity investment in Laramie Energy, a natural gas E&P company with operations in
western Colorado. Although Laramie is non-core and is not consolidated into our financial results
due to our equity-method accounting treatment, we continue to be pleased with its management
team and performance. Strong financial results last year allowed Laramie to repay a significant
portion of its debt and complete a $160 million refinancing of its senior secured credit facility.
Laramie reported Adjusted EBITDAX of $121 million for 2021 compared to $41 million in 2020. With
no drilling program, free cash flow (after capital expenditures and cash interest) was approximately
$105 million. With its current hedge profile and the current natural gas market outlook, we expect
Laramie to be positioned to pay off most of its debt and refinance the remainder.
Capital Allocation
We made significant progress in reducing our debt in 2021, repaying over $150 million throughout the
year. We ended 2021 with net debt of $468 million, compared to year end 2020 and 2019 net debt of
$663 million and $509 million, respectively. Our objective is to reduce debt levels to where they are
solely supported by our stable retail and logistics profitability, leaving the more volatile refining
segment free of any debt service requirements. We largely reached that level by the end of 2021.
Late last year, our Board of Directors authorized a share repurchase program for up to $50 million
of our outstanding common stock. This program allows us to be flexible in our capital allocation
strategy as our equity and debt values fluctuate. Through February of 2022, we have repurchased
over $5 million of our common equity at an average price of $13.64 per share. We believe these
steps will allow us to increase our return on capital and ultimately lower our overall cost of capital.
Outside of these two areas, we are also evaluating other opportunities to deploy excess capital
including growth projects, business development and acquisition opportunities, and optimizing our
working capital financing.
06 | PAR PACIFIC | 2021 ANNUAL REPORT
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Our team continues to focus on meeting local market
needs and fully expects a strong rebound in both
volume and margin over the next twenty-four months.
08 | PAR PACIFIC | 2021 ANNUAL REPORT
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Sustainability and
Energy Transition
We were pleased to publish our inaugural
sustainability report in 2021. We view
sustainability as a criti cal element of our
mission to serve our local communiti es by
providing safe and reliable energy to address
local demand. We balance this mission with a
commitment to reducing our Scope 1 greenhouse
gas emissions and lowering our carbon footprint.
We are exploring several energy transiti on
opportuniti es to achieve this goal and look
forward to engaging with all our stakeholders
in creati ng a sustainable future.
Short-term opportuniti es include co-feeding
low carbon feedstocks like soybean oil through
our existi ng units. This is a quickly acti onable,
low capital project that will allow us to toggle
between renewables and hydrocarbons. At a
rate of 2,500 barrels per day of co-fed soybean
oil, we would generate enough RINs to fully
off set our systemwide renewable volume
obligati on. Aside from this opportunity, we are
also exploring several longer-term projects.
In Washington, the passage of two state laws to
encourage the reducti on of carbon dioxide
emissions and the greater producti on of lower
carbon intensity fuels is both a challenge and an
opportunity. With our logisti cs system and our
locati on near inexpensive, zero-carbon-emitti ng
hydropower, we are well-positi oned to invest in
renewable fuels. A key step in this regard is
low-carbon, or green, hydrogen. We are working
closely with the local municipal uti lity and private
organizati ons focused on making Tacoma a hub
for low-cost, zero-carbon hydrogen.
In Hawaii, we have opportuniti es to reduce our
carbon footprint by capturing carbon dioxide from
the refi nery, and we are exploring opportuniti es
to use or sequester these emissions.
Outlook
In closing, I want to thank you for your conti nued
support through this challenging ti me. As a
downstream energy company focused on distant
markets like Hawaii, we have a high exposure to
air travel, which remains the area of refi ned
products most impacted by the global pandemic.
Our team conti nues to focus on meeti ng local
market needs and fully expects a strong
rebound in both volume and margin over the
next twenty-four months. Industry issues
notwithstanding, we expect the environment
for our products to be very strong. We also expect
to capitalize on local needs for lower-carbon fuels
that are blended with hydrocarbons to reduce
greenhouse gas emissions. We are pleased to
see the market recovery in the last half of 2021
and look forward to capitalizing on this change
by returning to profi tability in 2022.
On behalf of the management and employees
of Par Pacifi c,
William Pate
President & Chief Executi ve Offi cer
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PAR PACIFIC | 2021 ANNUAL REPORT | 09
NON-GAAP Performance Measures
Management uses certain financial measures to evaluate our operating performance that are considered
non-GAAP financial measures. These measures should not be considered a substitute for, or superior to,
measures of financial performance prepared in accordance with GAAP and our calculations thereof may
not be comparable to similarly titled measures reported by other companies.
ADJUS T ED NE T INCO ME (LOS S) AND ADJUS T ED EBI T DA
Adjusted Net Income (Loss) is defined as Net income (loss) excluding inventory valuation adjustment
(which adjusts for timing differences to reflect the economics of our inventory financing agreements,
including lower of cost or net realizable value adjustments, the impact of the embedded derivative
repurchase or terminal obligations, contango (gains) and backwardation losses associated with our
Washington inventory and intermediation obligation, and purchase price allocation adjustments), the
LIFO layer liquidation impacts associated with our Washington inventory, RINs loss (gain) in excess of
net obligation, unrealized (gain) loss on derivatives, acquisition and integration costs, debt extinguishment
and commitment costs, increase in (release of) tax valuation allowance and other deferred tax
items, changes in the value of contingent consideration and common stock warrants, severance
costs, (gain) loss on sale of assets, impairment expense, impairment expense associated with our
investment in Laramie Energy and our share of Laramie Energy’s asset impairment losses in excess
of our basis difference, and Par’s share of Laramie Energy’s unrealized loss (gain) on derivatives.
Adjusted EBITDA is Adjusted Net Income (Loss) excluding DD&A, interest expense and financing costs,
equity losses (earnings) from Laramie Energy excluding Par’s share of unrealized loss (gain) on
derivatives, impairment of Par’s investment, and our share of Laramie Energy’s asset impairment
losses in excess of our basis difference, and income tax expense (benefit).
We believe Adjusted Net Income (Loss) and Adjusted EBITDA are useful supplemental financial
measures that allow investors to assess:
• The financial performance of our assets without regard to financing methods, capital structure,
or historical cost basis;
• The ability of our assets to generate cash to pay interest on our indebtedness; and
• Our operating performance and return on invested capital as compared to other companies
without regard to financing methods and capital structure.
Adjusted Net Income (Loss) and Adjusted EBITDA should not be considered in isolation or as a
substitute for operating income (loss), net income (loss), cash flows provided by operating, investing,
and financing activities, or other income or cash flow statement data prepared in accordance with
GAAP. Adjusted Net Income (Loss) and Adjusted EBITDA presented by other companies may not be
comparable to our presentation as other companies may define these terms differently.
The following table presents a reconciliation of Adjusted Net Income (Loss) and Adjusted EBITDA to
the most directly comparable GAAP financial measure, net income (loss), on a historical basis for the
periods indicated (in thousands):
10 | PAR PACIFIC | 2021 ANNUAL REPORT
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YEAR ENDED DECEMBER 31,
2021
2020
Net income (loss)
$ (81,297)
$ (409,086)
Inventory valuation adjustment
RINs loss in excess of net obligation
Unrealized loss (gain) on derivatives
Acquisition and integration costs
Debt extinguishment and commitment costs
Changes in valuation allowance and other deferred tax items (1)
Change in value of common stock warrants
Severance costs
Loss (gain) on sale of assets, net
Impairment expense
Impairment of Investment in Laramie Energy, LLC (2)
Par’s share of Laramie Energy’s unrealized gain on derivatives (2)
Adjusted Net Loss (3)
Depreciation, depletion, and amortization
Interest expense and financing costs, net
Equity losses from Laramie Energy, LLC, excluding Par’s share of
unrealized loss (gain) on derivatives and impairment losses
Income tax expense
Adjusted EBITDA
17,089
16,967
1,517
87
8,144
—
—
84
(64,697)
1,838
—
—
14,046
44,071
(4,804)
614
—
(20,896)
(4,270)
512
—
85,806
45,294
(1,110)
(100,268)
(249,823)
94,241
66,493
90,036
70,222
—
2,721
1,021
176
$ 61,487
$ (86,668)
(1) Includes increases in (releases of) our valuation allowance associated with business combinations and changes in deferred tax assets
and liabilities that are not offset by a change in the valuation allowance. These tax expenses (benefits) are included in Income tax
benefit (expense) on our condensed consolidated statements of operations.
(2) Includes our share of Laramie Energy’s unrealized loss (gain) on derivatives, impairment losses on our investment in Laramie
Energy, and our share of Laramie Energy’s asset impairment losses in excess of our basis difference. These impairment losses and
our share of Laramie Energy’s unrealized loss (gain) on derivatives are included in Equity losses from Laramie Energy, LLC on our
condensed consolidated statements of operations.
(3) For the years ended December 31, 2021 and 2020, there was no change in value of contingent consideration or LIFO liquidation adjustment.
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PAR PACIFIC | 2021 ANNUAL REPORT | 11
The following table sets forth the computati on of basic and diluted Adjusted Net Income (Loss) per
share (in thousands, except per share amounts):
Adjusted Net Loss
Undistributed Adjusted Net Income allocated to
parti cipati ng securiti es
YEAR ENDED DECEMBER 31,
2021
2020
$ (100,268)
$ (249,823)
—
—
Adjusted Net Loss att ributable to common stockholders
(100,268)
(249,823)
Plus: eff ect of converti ble securiti es
—
—
Numerator for diluted loss per common share
$ (100,268)
$ (249,823)
Basic weighted-average common stock shares outstanding
58,268
53,295
Add diluti ve eff ects of common stock equivalents (1)
—
—
Diluted weighted-average common stock shares outstanding
58,268
53,295
Basic Adjusted Net Loss per common share
$ (1.72)
$ (4.69)
Diluted Adjusted Net Loss per common share
$ (1.72)
$ (4.69)
(1) Entities with a net loss from continuing operations are prohibited from including potential common shares in the computation of diluted
per share amounts. We have utilized the basic shares outstanding to calculate both basic and diluted Adjusted Net Loss per common share
for the years ended December 31, 2021 and 2020.
ADJUS T ED EBI T DA BY S EGMEN T
Adjusted EBITDA by segment is defi ned as Operati ng income (loss) by segment excluding depreciati on,
depleti on, and amorti zati on expense, inventory valuati on adjustment (which adjusts for ti ming
diff erences to refl ect the economics of our inventory fi nancing agreements, including lower of cost
or net realizable value adjustments, the impact of the embedded derivati ve repurchase or terminal
obligati ons, contango (gains) and backwardati on losses associated with our Washington inventory
and intermediati on obligati on, and purchase price allocati on adjustments), the LIFO layer liquidati on
impacts associated with our Washington inventory, RINs loss (gain) in excess of net obligati on,
unrealized loss (gain) on derivati ves, acquisiti on and integrati on costs, severance costs, loss (gain) on
sale of assets, and impairment expense. Adjusted EBITDA by segment also includes Gain on curtailment
of pension obligati on and Other income (expense), net, which are presented below operati ng income
(loss) on our condensed consolidated statements of operati ons.
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We believe Adjusted EBITDA by segment is a useful supplemental fi nancial measure to evaluate the
economic performance of our segments without regard to fi nancing methods, capital structure, or
historical cost basis. The following table presents a reconciliati on of Adjusted EBITDA by segment to
the most directly comparable GAAP fi nancial measure, operati ng income (loss) by segment, on a
historical basis, for selected segments, for the periods indicated (in thousands):
YEAR ENDED DECEMBER 31, 2021
REFINING
LOGISTICS
RETAIL
CORPORATE
AND OTHER
Operati ng income (loss) by segment
$ (88,799)
$ 51,159
$ 81,249
$ (51,228)
Depreciati on, depleti on and amorti zati on
Inventory valuati on adjustment
RINs loss in excess of net obligati on
Unrealized loss (gain) on derivati ves
Acquisiti on and integrati on costs
Severance costs
Loss (gain) on sale of assets, net
Impairment expense
Gain on curtailment of pension obligati on
Other income (expense), net
58,258
17,089
16,967
1,517
—
61
(19,659)
1,838
1,802
—
22,044
10,880
3,059
—
—
—
—
23
(19)
—
228
—
—
—
—
—
—
(45,034)
—
2
—
—
—
—
87
—
15
—
—
(52)
Adjusted EBITDA (1)
$ (10,926)
$ 73,435
$ 47,097
$ (48,119)
YEAR ENDED DECEMBER 31, 2020
REFINING
LOGISTICS
RETAIL
CORPORATE
AND OTHER
Operati ng income (loss) by segment
$ (331,826)
$ 35,044
$ 24,211
$ (45,427)
Depreciati on, depleti on and amorti zati on
53,930
21,899
10,692
3,515
Inventory valuati on adjustment
RINs loss in excess of net obligati on
Unrealized loss (gain) on derivati ves
Acquisiti on and integrati on costs
Severance costs
Impairment expense
Other income (expense), net
14,046
44,071
(4,804)
—
312
55,989
—
—
—
—
—
8
—
—
—
—
—
—
—
29,817
—
—
—
614
192
—
—
1,049
Adjusted EBITDA (2)
$ (168,282)
$ 56,951
$ 64,720
$ (40,057)
(1) For the year ended December 31, 2021, there was no LIFO liquidation adjustment recorded in Operating income (loss) by segment.
(2) For the year ended December 31, 2020, there was no loss (gain) on sale of assets recorded in Operating income (loss) by segment,
LIFO liquidation adjustment, or gain on curtailment of pension obligation.
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PAR PACIFIC | 2021 ANNUAL REPORT | 13
NET DEBT
The following table summarizes our outstanding debt and net debt (in thousands):
DECEMBER 31,
2021
2020
2019
5.00% Convertible Senior Notes due 2021
$ —
$ 48,665
$ 48,665
ABL Credit Facility due 2022
Retail Property Term Loan due 2024
—
—
—
—
42,494
44,014
7.75% Senior Secured Notes due 2025
296,000
300,000
300,000
Term Loan B due 2026
215,625
228,125
240,625
12.875% Senior Secured Notes due 2026
68,250
105,000
Mid Pac Term Loan due 2028
PHL Term Loan due 2030
—
—
1,399
5,840
—
1,433
—
Principal amount of long-term debt
579,875
731,523
634,737
Less: cash and cash equivalents
(112,221)
(68,309)
(126,015)
Net debt
$ 467,654
$ 663,214
$ 508,722
14 | PAR PACIFIC | 2021 ANNUAL REPORT
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L AR AMIE ENERGY ADJUS T ED EBI T DA X
Adjusted EBITDAX is defined as net income (loss) excluding commodity derivative loss (gain), loss
(gain) on settled derivative instruments, interest expense, gain on extinguishment of debt, non-cash
preferred dividend, depreciation, depletion, amortization, and accretion, exploration and geological
and geographical expense, bonus accrual, equity-based compensation expense, loss (gain) on
disposal of assets, and expired acreage (non-cash). We believe Adjusted EBITDAX is a useful
supplemental financial measure to evaluate the economic and operational performance of exploration
and production companies such as Laramie Energy.
The following table presents a reconciliation of Laramie Energy’s Adjusted EBITDAX to the most directly
comparable GAAP financial measure, net income (loss) for the periods indicated (in thousands):
Net income (loss)
Commodity derivative loss (gain)
Gain (loss) on settled derivative instruments
Interest expense and loan fees
Gain on extinguishment of debt
Non-cash preferred dividend
Depreciation, depletion, amortization, and accretion
Exploration and geological and geographical expense
Bonus accrual
Equity-based compensation expense
Loss (gain) on disposal of assets
Expired acreage (non-cash)
Total Adjusted EBITDAX
2021
2020
$ 32,476
$ (22,589)
42,995
(10,578)
17,155
(695)
7,224
28,860
342
602
—
(6)
2,667
2,201
2,045
9,402
—
6,810
37,960
275
436
16
(102)
4,099
$ 121,042
$ 40,553
L AR AMIE ENERGY FREE C A S HFLOW
Free cashflow is defined as Adjusted EBITDAX less capital expenditures and interest expense and other
financing costs, excluding non-cash interest costs. The following table presents a reconciliation of
Laramie Energy’s Free Cashflow (in thousands):
Adjusted EBITDAX
Less: Capital expenditures
Less: Interest expense and other financing costs
Addback: Non-cash interest costs
Free Cashflow
2021
$ 121,042
(1,371)
(17,896)
3,225
$ 105,000
16 | PAR PACIFIC | 2021 ANNUAL REPORT
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
________________________________________________________________________________________________________________________
FORM 10-K
________________________________________________________________________________________________________________________
(Mark One)
☒
☐
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2021
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
(State or other jurisdiction of
incorporation or organization)
825 Town & Country Lane, Suite 1500
Houston, Texas
(Address of principal executive offices)
84-1060803
(I.R.S. Employer
Identification No.)
77024
(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
Common stock, $0.01 par value
Trading Symbol(s)
PARR
Name of Exchange on which registered
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 ý No ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the
Act. Yes ¨ No 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 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.
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Large accelerated filer
Non-accelerated filer
ý
¨
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 has filed a report on and attestation to its management’s assessment of
the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C.
7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒
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 $743,291,325 based on the closing sales price of the common stock on the New York Stock Exchange on June
30, 2021. As of February 18, 2022, 59,813,700 shares of the registrant’s Common Stock, $0.01 par value, were issued and
outstanding.
Documents Incorporated By Reference
Certain information required to be disclosed in Part III of this report is incorporated by reference from the registrant’s
definitive proxy statement or an amendment to this report, which will be filed with the SEC not later than 120 days after the end
of the fiscal year covered by this report.
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Table of Contents
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
PAR T II
Item 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER
MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES
Item 6.
[RESERVED]
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
Item 9C.
DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTION
PAR T III
Item 10.
DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE
Item 11.
EXECUTIVE COMPENSATION
Item 12.
Item 13.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT AND RELATED STOCKHOLDER MATTERS
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS,
AND DIRECTOR INDEPENDENCE
Item 14.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
PAR T IV
Item 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
Item 16.
FORM 10-K SUMMARY
1
14
26
27
27
27
28
29
29
58
60
60
60
61
61
62
62
62
62
62
63
F-64
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GLOS SARY O F S EL EC T ED INDUS T RY T ERM S
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
blendstocks
Brent
cardlock
catalyst
A common unit of measure in the oil industry, which equates to 42 gallons.
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.
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.
Automated unattended fueling sites that are open all day and are designed for commercial fleet vehicles.
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
distillates
ethanol
A simplified calculation that measures the difference between the price for refined products and crude oil.
For example, we reference the 3-1-2 Singapore crack spread, which approximates the per barrel results from
processing three barrels of Brent crude oil to produce one barrel of gasoline and two barrels of distillates
(diesel and jet fuel).
Refers primarily to diesel, heating oil, kerosene, and jet fuel.
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 further processed into refined products.
jobber
LSFO
Mbbls
Mbpd
MMbbls
MMbtu
MMcfd
MW
A petroleum marketer.
Low sulfur fuel oil.
Thousand barrels of crude oil or other liquid hydrocarbons.
Thousand barrels per day.
Million barrels of crude oil or other liquid hydrocarbons.
Million British thermal units, a unit of measurement for natural gas.
Million cubic feet per day, a unit of measurement for natural gas.
Megawatt, a unit of measurement for electricity or other energy transfer. A watt is a unit of work at the rate
of one joule per second or current at the rate of one ampere across a potential difference of one volt.
NOx
Nitrogen oxides.
refined products
Petroleum products, such as gasoline, diesel, and jet fuel, that are produced by a refinery.
SO2
SPM
throughput
turnaround
ULSD
WTI
yield
Sulfur dioxide.
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.
The volume processed through a unit or refinery.
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 seven
years, depending on unit type.
Ultra-low sulfur diesel.
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.
The percentage of refined products that is produced from crude oil and other feedstocks, net of fuel used
as energy.
ii
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PART I
Item 1. BUSINESS
Overview
Par Pacific Holdings, Inc., headquartered in Houston, Texas, owns and operates market-leading energy and infrastructure
businesses. Our strategy is to acquire and develop energy and infrastructure businesses in logistically complex, niche markets.
Our business is organized into three primary segments:
1) Refining - We own and operate three refineries with total operating crude oil throughput capacity of 154 Mbpd. Our
refinery in Kapolei, Hawaii, produces gasoline, jet fuel, ultra-low sulfur diesel (“ULSD”), marine fuel, low sulfur fuel oil
(“LSFO”), and other associated refined products primarily for consumption in Hawaii. Our refinery in Newcastle, Wyoming,
produces gasoline, jet fuel, ULSD, and other associated refined products that are primarily marketed in Wyoming and
South Dakota. Our refinery in Tacoma, Washington, produces gasoline, jet fuel, ULSD, asphalt, and other associated refined
products that are primarily marketed in the Pacific Northwest.
2) Retail - We operate 119 fuel retail outlets in Hawaii, Washington, and Idaho. Our fuel retail outlets in Hawaii sell gasoline and
diesel throughout the islands of Oahu, Maui, Hawaii, and Kauai. We operate convenience stores at 34 of our Hawaii retail fuel
outlets under our proprietary “nomnom” brand that sell merchandise such as soft drinks, prepared foods, and other sundries.
Our Hawaii retail network includes Hele and “76” branded fuel retail sites, “nomnom” branded company-operated
convenience stores, 7-Eleven operated convenience stores, other sites operated by third parties, and unattended cardlock
stations. Our retail outlets in Washington and Idaho sell gasoline, diesel, and retail merchandise. Through December 31, 2021,
we completed the rebranding of all 29 company-operated convenience stores in Washington and Idaho to “nomnom,” our
proprietary brand.
3) Logistics - We operate an extensive multi-modal logistics network spanning the Pacific, the Northwest, and the Rocky
Mountain regions. 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 lease marine vessels for
the movement of petroleum, refined products, and ethanol between the U.S. West Coast and Hawaii. We 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. We own and operate logistics assets
in Washington, including a marine terminal, a unit train-capable rail loading terminal, storage facilities, a truck rack, and a
proprietary pipeline that serves Joint Base Lewis McChord. In 2020, we completed a project at our Tacoma, Washington,
location to allow for the storage and shipment of ethanol through our unit train and marine terminals.
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 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 (the “Washington Acquisition”). The Washington
Acquisition included 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 system are strategically located in Tacoma, Washington, and
currently serve the Pacific Northwest market. On January 11, 2019, we completed the Washington Acquisition for a total
purchase price of $326.5 million, including acquired working capital, consisting of cash consideration of $289.5 million and
approximately 2.4 million shares of our common stock with a fair value of $37.0 million 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.
Our Corporate and Other reportable segment primarily includes general and administrative costs. Please read Note 22—Segment
Information to our consolidated financial statements under Item 8 of this Form 10-K for detailed information on our operating
results by segment.
IMPAC T S OF T HE COVID -19 PANDEMIC
The spread and severity of the coronavirus (“COVID-19”) pandemic, in conjunction with government and other preventative
measures taken to mitigate the spread of the virus, have caused severe disruptions in the worldwide economy, including the
global demand for crude oil and refined products, the movement of people and goods in the United States, and the global
supply chain for industrial and commercial production, all of which have in turn disrupted our businesses and operations and
impacted our financial performance in 2021 and 2020. We continue to actively monitor the impact of the global situation on
our people, operations, financial condition, liquidity, suppliers, customers, and industry, and are actively responding to the
impacts that these matters have on our business. Please read “Item 1A. — Risk Factors” and “Item 7. — Management’s
Discussion and Analysis of Financial Condition and Results of Operations — Overview” for further discussion of the risks,
uncertainties, and actions we have taken in response to the global COVID-19 pandemic and resulting economic impact.
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CORP OR AT E INFORMAT ION
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 & 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.
AVAIL ABL E INFO RMAT I ON
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 distil-
lates) 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 94 Mbpd operating throughput
capacity. The Hawaii refinery’s major processing units, listed in the table below, produce liquified petroleum gas (“LPG”),
naptha, gasoline, jet fuel, USLD, marine fuel, LSFO, high sulfur fuel oil (“HSFO”), asphalt, and other associated refined
products. We believe the configuration of our Hawaii refinery uniquely fits the demands of the Hawaii market.
Set forth below are summaries of the operating capacity of our Hawaii refinery as of December 31, 2021:
HAWAII REFINING UNIT
CAPACIT Y (MBPD)
Crude Oil Distillation Units
Vacuum Distillation Units
Hydrocracker
Catalytic Reformer
Visbreaker
Naphtha Hydrotreater
Diesel Hydrotreater
94
40
19
13
11
13
10
HAWAII REFINING UNIT
CAPACIT Y
Hydrogen Plant (MMcfd)
Co-generation Turbine Unit (MW)
18
20
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 received into the Hawaii refinery’s tank farm, which includes 3.4 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 3.3 MMbbls of refined product storage and additional third-party product storage. This storage
capacity allows us to manage the various product requirements of our customers.
We finance our Hawaii refinery’s hydrocarbon inventories through our Supply and Offtake Agreement with J. Aron & Company
LLC (“J. Aron”). Under the Supply and Offtake Agreement, J. Aron holds title to all crude oil and refined product stored in tankage
at the Hawaii refinery. We purchase crude oil from J. Aron on a daily basis at market prices and sell refined products to J. Aron as
they are produced. We repurchase these refined products from J. Aron prior to selling them to third parties.
2
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The Hawaii refinery operated at an average combined crude oil throughput of 82.0 Mbpd, or 87% of crude oil utilization, to
meet local demand for the year ended December 31, 2021. Our Par West refinery was idled in March 2020 for economic
reasons and we are evaluating alternative uses for the site. In 2020, we executed a turnaround in Hawaii, which resulted in
lower throughput and utilization outside of market conditions. For further operational statistics regarding our Hawaii refining
operations, please read “Item 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations
— Results of Operations.”
Our Hawaii refining business contracts with wholesale and bulk customers as well as our Hawaii retail network. Many of
these contracts also involve use of our Hawaii logistics assets to ultimately serve each customer. Wholesale customers
include jobbers and other non-end users, as well as 43 locations where we deliver fuel to a location that subsequently sells
the product at retail to the end user. Bulk customers include utilities, airlines, military, marine vessels, industrial end-users,
and exporters.
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. Prior to 2020, the 4-1-2-1 Singapore crack
spread (or four barrels of Brent crude oil converted into one barrel of gasoline, two barrels of distillates (diesel and jet fuel)
and one barrel of fuel oil) best reflected a market indicator for our Hawaii refinery’s operations. The 4-1-2-1 Singapore crack
spread averaged $6.68 per barrel during 2019 with a low of $4.34 per barrel average in the fourth quarter and a high of $9.36
per barrel average in the third quarter. In 2020, we began shifting our Hawaii production profile to supply the local utilities
with low sulfur fuel oil and significantly reduced our high sulfur fuel oil yield. Following the implementation of new standards
by the International Marine Organization (“IMO”) beginning in 2020, we established the 3-1-2 Singapore Crack Spread (or
three barrels of Brent crude oil converted into one barrel of gasoline and two barrels of distillates (diesel and jet fuel)) as a
new benchmark for our Hawaii operations. The 3-1-2 Singapore Crack Spread averaged $6.22 per barrel during the year
ended December 31, 2021 with a low of $3.80 per barrel average in the first quarter and a high of $10.49 per barrel average
in the fourth quarter.
Below is a summary of average crack spreads for the years ended December 31, 2021, 2020, and 2019:
3-1-2 Singapore Crack Spread
$ 6.22
$ 3.15
$ 10.80
YEAR ENDED DECEMBER 31,
2021
2020
2019
WASHINGTON REFINERY
Our Washington refinery is located in Tacoma, Washington, on approximately 139 fee-owned acres and is rated at 42 Mbpd
throughput capacity. The Washington refinery’s major processing units include crude oil distillation, vacuum, jet treating, diesel
hydrotreating, isomerization, and reforming units, which produce ULSD, jet fuel, gasoline, asphalt, and other associated refined
products that are primarily marketed in the Pacific Northwest. For further operational statistics regarding our Washington
refining operations, please read “Item 7. — Management’s Discussion and Analysis of Financial Condition and Results of
Operations — Results of Operations.”
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 1.2 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. In 2020, 0.2 MMbbls of crude oil storage was repositioned as renewable fuels storage as
part of the completion of our project to allow for storage and throughput of renewable fuels at the refinery.
We finance our Washington refinery hydrocarbon inventories through an intermediation arrangement (the “Washington
Refinery Intermediation Agreement”) with Merrill Lynch Commodities, Inc. (“MLC”). Under this arrangement, U.S. Oil
purchases crude oil supplied from third-party suppliers and MLC provides credit support for certain crude oil purchases.
MLC’s credit support can consist of either providing a payment guaranty, causing the issuance of a letter of credit from a third
party issuing bank, or purchasing crude oil directly from third parties on our behalf. U.S. Oil holds title to all crude oil and
refined products inventories at all times and pledges such inventories, together with all receivables arising from the sales of
these inventories, exclusively to MLC.
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Set forth below is a summary of the capacity of our Washington refinery as of December 31, 2021:Set forth below is a
summary of the capacity of our Washington refinery as of December 31, 2021:
WASHINGTON REFINING UNIT
CAPACIT Y (MBPD)
Crude Oil Distillation Units
Vacuum Unit
Naphtha Hydrotreater
Catalytic Reformer
Diesel Hydrotreater
Isomerization
42
19
13
7
8
5
The Washington refinery operated at an average throughput of 36.3 Mbpd, or 86% utilization, for the year ended December 31,
2021. In 2021, we executed the first phase of a turnaround in Washington, which resulted in lower throughput and utilization
outside of market conditions.
Our Washington refining business transports crude oil and refined products through our logistics network and sells refined
products to wholesale, bulk, and retail customers primarily in the Pacific Northwest.
We believe the Pacific Northwest 5-2-2-1 Index is the best market indicator for our operations in Tacoma, Washington. The
Pacific Northwest 5-2-2-1 Index is computed by taking two parts gasoline (sub-octane), two parts middle distillates (ULSD and
jet fuel), and one part fuel oil as created from five barrels of Alaskan North Slope (“ANS”) crude oil. The Pacific Northwest
5-2-2-1 Index averaged $15.95 per barrel during the year ended December 31, 2021 with a low of $11.46 per barrel average in
the first quarter and a high of $18.59 per barrel average in the third quarter.
Below is a summary of average crack spreads and crude oil prices per barrel for the years ended December 31, 2021, 2020, and 2019:
YEAR ENDED DECEMBER 31,
2021
2020
2019
Pacific Northwest 5-2-2-1 Index (1)
$ 15.95
$ 11.44
$ 15.02
Bakken Clearbrook
$ 68.20
$ 37.19
$ 56.04
WCS Hardisty
ANS
$ 54.61
$ 27.45
$ 43.18
$ 71.49
$ 41.77
$ 65.72
(1) The 2019 prices for the year ended December 31, 2019 represent the price averaged over the period from January 11, 2019 to
December 31, 2019.
WYOMING REFINERY
Our Wyoming refinery is located in Newcastle, Wyoming, on approximately 121 fee-owned acres and with a capacity of 18
Mbpd throughput. The Wyoming refinery’s major processing units include crude oil 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 Rocky Mountain region of the United States and
North Dakota 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 267 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 513 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.
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Set forth below is a summary of the capacity of our Wyoming refinery as of December 31, 2021:
W YOMING REFINING UNIT
CAPACIT Y (MBPD)
Crude Oil Distillation Unit
Residual Fluid Catalytic Cracker
Catalytic Reformer
Naphtha Hydrotreater
Diesel Hydrotreater
Isomerization
18
7
4
4
6
5
The Wyoming refinery operated at an average throughput of 16.9 Mbpd, or 94% utilization, for the year ended December 31,
2021. In 2020, we executed a turnaround in Wyoming, which resulted in lower throughput and utilization outside of market
conditions. For further operational statistics regarding our Wyoming refining operations, please read “Item 7. — Management’s
Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations.”
Our Wyoming refining business transports refined products through our logistics network to wholesale, bulk, and retail
customers primarily in Wyoming and South Dakota. Products are also distributed by rail from our refinery to markets beyond
our logistics network.
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, or three barrels of WTI converted into two barrels of gasoline and one barrel of distillates (jet fuel and diesel),
averaged $29.00 per barrel during 2021 with a low of $20.97 per barrel average in the first quarter and a high of $41.78 per
barrel average in the third quarter.
Below is a summary of average crack spreads for the years ended December 31, 2021, 2020, and 2019:
Wyoming 3-2-1 Index
$ 29.00
$ 17.80
$ 24.90
YEAR ENDED DECEMBER 31,
2021
2020
2019
COMPE T I T I O N
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 Note 11—Inventory Financing Agreements to our consolidated financial statements under
Item 8 of this Form 10-K for further information.
Our Washington refinery utilizes an intermediation arrangement with MLC and sources its crude oil and feedstocks primarily
from North Dakota and Canada. Please read Note 11—Inventory Financing Agreements to our consolidated financial statements
under Item 8 of this Form 10-K for further information. Our Wyoming refinery sources its crude oil and feedstocks primarily
from the Petroleum Administration for Defense District IV Rocky Mountain (“PADD IV”) region of the United States.
Our Hawaii refinery’s 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 U.S. West Coast market. Our Washington refinery primarily sells refined
products in the Pacific Northwest region. Our Wyoming refinery primarily sells refined products locally in the PADD IV region.
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RE TAIL
The retail segment includes 90 locations in Hawaii and 29 locations in Washington and Idaho where we set the price to the retail
consumer. Of these, 34 of the Hawaii locations and all 29 Washington and Idaho locations are operated by our personnel and
include various sizes of convenience stores, snack shops, and kiosks. The remaining 56 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, with 40 of our retail sites
branded “76”. The “76” license agreement expires October 31, 2031, unless extended by mutual agreement. An additional 42 of
our sites operate under our proprietary Hele fuel brand. Since its launch in 2016, the Hele brand has won several awards for
being the preferred fuel choice for Hawaii customers. Our eight cardlock locations on Kauai are branded Kauai Automated Fuels
(“KAF”). All 34 company-operated convenience stores in Hawaii are branded “nomnom,” our proprietary brand.
We operate convenience stores at all 29 of our retail fuel outlets in Washington and Idaho. As part of our 2018 acquisition of
these retail outlets, we entered into a multi-year branded petroleum marketing agreement for the continued supply of
Cenex®-branded refined products to the acquired Cenex® Zip Trip convenience stores. As of December 31, 2021, we had
completed the rebranding of all of our retail outlets in Washington and Idaho from the “Cenex®” and “Zip Trip®” brand names
to our proprietary “nomnom” brand. As these stores were rebranded, we began self-supplying the fuel with equity barrels
and/or unbranded fuels procured in the open market.
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 Pacific 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 retail brands.
LO GI S T IC S
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. We also have an on-shore pipeline manifold which allows for crude oil to be transferred from an undersea
pipeline owned by IES Downstream, LLC (“IES”) to the SPM and from the SPM to the Hawaii refinery. From the Hawaii
refinery’s gates, 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 majority of our Oahu refined product volumes are distributed through a
multi-product pipeline (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) two third-party terminals 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 bidirec-
tional, allowing for both delivery and receipt of products. We also operate a proprietary trucking business on Oahu to
distribute gasoline and road diesel to the final point of sale.
We have a long-term agreement with IES for storage and throughput at the Hawaii refinery which provides for the right to utilize
2 MMbbls of dedicated crude oil and refined product storage, as well as certain IES logistics assets, including its off-shore
mooring and Honolulu pipeline system. 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.
Our logistics network for the islands neighboring Oahu consists of leased barge equipment, refined product tankage, and
proprietary trucking operations on the islands of Maui, Hawaii, Molokai, and Kauai. We charter a barge and have service
agreements with third parties to serve our neighbor island markets. The barges deliver to, and product is dispensed from, a
neighbor island network of seven petroleum terminals with total storage capacity of 301 Mbbls.
In addition to the movements within Hawaii, we also lease Jones Act marine vessels to allow for the movement of petroleum,
refined products, and ethanol between the U.S. West Coast and Hawaii.
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WASHINGTON LOGISTICS
Our Washington logistics network includes 2.8 MMbbls of storage capacity, a proprietary 14-mile jet fuel pipeline that serves
Joint Base Lewis McChord, a marine terminal with 15 acres of waterfront property, a unit train-capable rail loading terminal
with 107 unloading spots, a manifest rail siding with 32 spots including asphalt, butane, and biodiesel loading and unloading
facilities, and a truck rack with six truck lanes and 10 loading arms. These assets provide connectivity to Bakken, Canadian,
and Alaskan crude oil, renewable fuels, and the Pacific, West Coast, Pacific Northwest, and Rockies product markets.
WYOMING LOGISTICS
Our Wyoming logistics network includes 190 Mbbls of crude storage tank capacity and a 50-mile crude oil pipeline 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 593 Mbbls. We also own and operate a jet fuel storage
facility and pipeline that serve Ellsworth Air Force Base in South Dakota.
MARKE T S
HAWAII MARKET
The COVID-19 pandemic continued to have an impact on Hawaii’s communities and economy in 2021. In the summer of 2021,
however, there was a strong rebound in domestic tourists visiting Hawaii. Through the Hawaii Safe Travels program, visitors
were able to provide proof of vaccination or a negative COVID-19 test to avoid the 14-day quarantine period. Restrictions
that were in place in 2020 on travel, business closures, and in-person gatherings began to be lifted, which allowed for the
beginning of an economic recovery. While domestic tourism has been near or at pre-pandemic levels since the summer of
2021, international tourism has yet to return. State economists expect a slow but steady multi-year road to recovery.
According to the University of Hawaii Economic Research Organization’s (“UHERO”) fourth quarter 2021 report, unemployment
dropped from 11.8% at the end of 2020 to 7.7% at the end of 2021, which is still well above Hawaii’s pre-pandemic level of 2.6%.
Many workers who left the labor force during the pandemic have yet to return. This has led to a tight labor market and upward
pressure on wages. Unit labor costs increased by 5% year-over-year nationally and inflation increased by more than 5% in both
Hawaii and the U.S., reducing purchasing power. While the payroll job count is expected to expand at a moderate pace over the
next two years, the job base in 2023 is expected to be about 5% lower than its 2019 level.
The emergence of the Omicron variant in late 2021 presented additional uncertainty. Renewed international travel restrictions
have reduced the near-term visitor outlook. Once the situation eases, the return of international tourists is expected to permit a
broader industry recovery in 2022. Moderate job gains are expected heading into 2022, but several factors will weigh on
progress, including continuing labor shortages, the end of pandemic fiscal and monetary support, and higher inflation.
Despite the challenges mentioned above, we expect our business to continue to recover in 2022.
PACIFIC NORTHWEST AND ROCKIES MARKETS
Spokane, Washington, and Northwest Idaho are the primary regions of our Pacific Northwest retail operations and are enjoying
significantly higher population growth rates than the country as a whole. The U.S. Census Bureau noted that the population
increased 14.6% in Washington and 17.3% in Idaho from 2010 to 2020 versus a national increase of only 7.4%. Spokane is a
regional hub in eastern Washington, with a population of over a half million and a variety of employers in health care, retail, and
other industries. According to the U.S. Bureau of Economic Analysis (the “BEA”), personal income for the Spokane metro area
grew by 13.4% between 2018 and 2020, continuing the trend of positive growth since the 2008-2009 recession.
A significant portion of the products produced by our Washington refinery stay within the Puget Sound region. Washington is
one of the fastest growing states in the union and most of this growth is occurring in the Puget Sound area due to large
information industry companies like Microsoft Corporation, Amazon.com, Inc., and Expedia Group, Inc. According to the BEA,
gross domestic product (“GDP”) for the State of Washington grew by 6.3% from 2019 to 2020.
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 8.2% from 2010 to 2020 compared
to 7.4% nationally over the same period. According to the BEA, personal income in South Dakota grew by 8.7% from 2019 to
2020. Additionally, the South Dakota economy expects to get a boost from additional development at Ellsworth Air Force Base
as the main operating base for the B-21 Raider and the home for the training unit and an operational squadron.
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. According to the South Dakota Department of Tourism, despite limitations on mobility and economic disruption
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caused by the COVID-19 pandemic, South Dakota welcomed 13.5 million visitors in 2021, a 26.0% increase as compared to 2020,
resulting in visitor spending of approximately $4.4 billion in 2021, an increase of 29.7% over 2020. In 2021, $832 million, or
19.1%, of tourism dollars were spent on transportation services, an increase of 29% from 2020, when $644 million, or 19.2%, 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 production increased 8% in
2021 and the U.S. Energy Information Administration forecasts that coal production will increase in both 2022 and 2023.
Other Operations
L AR AMIE ENERGY
As of December 31, 2021, we owned 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. We have discontinued the application of the equity method of
accounting for our investment in Laramie Energy because the book value of such investment has been reduced to zero. Our
investment in Laramie Energy is not material to our consolidated financial statements as of December 31, 2021.
Bankruptcy and Plan of Reorganization
BAC KGROUND AND GENER AL RECOVERY T RUS T
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
Energy II, LLC 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 conclude the bankruptcy.
S HARE S RE S ERVED FOR UN S ECURED C L AIM S
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, 2021, two related claims totaling
approximately $22.4 million remained to be resolved by the Trustee for the General Trust. 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, 2021.
C LOS ING OF T HE BANKRUP TC Y C A S E S
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
GENER AL
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.
8
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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. Except as disclosed below, 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 AC T IVI T IE S
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.
C L IMAT E C HANGE AND REGUL AT I ON OF GREENH OUS E GA S E S
According to many scientific studies, emissions of CO2, methane, NOX, 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 U.S.
Environmental Protection Agency (“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 federal CAA regulations, and we 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 existing refining activities are not subject to current federal GHG permitting requirements.
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.
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. In June of 2014, the Hawaii Department of Health (“DOH”) adopted regulations that 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 Hawaii GHG regulation allows for “partnering” with other facilities that have or are
expected to make more significant CO2/GHG reductions. Accordingly, our Par East and Par West Hawaii refineries submitted
a GHG reduction plan and a permit application that incorporated the partnering provisions. The DOH issued a GHG permit,
which caps GHG emissions from both refineries at 904,945 metric tons per year which (as required by regulation) is 16%
below the combined facility GHG emission levels of 2010. In 2020, the year in which operation of the Par West crude unit was
suspended, both refineries reported a combined GHG emission total of 619,609 metric tons (which is 32% below the Title V
permit limit). Consequently no additional operating constraints nor capital for modifications will be required to comply with
the State’s current GHG regulation.
In addition to the Hawaii GHG legislation, the State of Washington and its political subdivisions have passed several climate-focused
laws in 2021 that are relevant to our Tacoma, Washington location. These include a low-carbon fuel standard designed to reduce
the carbon intensity of transportation fuels by twenty percent by 2038 and a “cap and trade”-style program for GHG emissions
covering industrial facilities starting in 2023. As both legislative programs are presently undergoing rulemaking processes at the
Washington Department of Ecology, the contours of both sets of requirements are not yet clear. In addition to action by the State,
on November 16, 2021, the Tacoma City Council adopted its Tideflats and Industrial Land Use Regulations, which prohibits new
petroleum storage and allows for only limited additions of clean fuel infrastructure.
Further regulatory, legislative, and judicial developments are likely to occur in the future. The new Administration’s Executive
Orders signaling a return to the Paris Climate Accord and voiding the prior Administration’s orders on the social cost of
carbon suggest the imminence of such changes. 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.
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NAT I O NAL AMBIEN T AIR QUAL I T Y S TANDARDS
The EPA has adopted a number of more stringent National Ambient Air Quality Standards (“NAAQS”). States are required to
develop State Implementation Plans and ultimately local air districts are required to adopt rules designed to improve air quality
over time. 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, which were reaffirmed in December 2020, that substantially tightened the NAAQS for ground-level
ozone. These rules are causing many areas of the country to develop requirements for additional controls and limits on combustion
emissions and emissions of volatile organic compounds. In October 2021, EPA announced that it intends to revisit the December
2020 decision to retain the 2015 NAAQS standard, opening the door to potential additional tightening of those standards and
additional requirements for states around the country to adopt more stringent controls. We do not currently anticipate that
the more stringent NAAQS will materially impact our Hawaii, Washington, or Wyoming operations, but the risk of impact will
increase in Washington as the standard is lowered.
FUEL S TANDARDS
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 “RFS”). In August 2012, the EPA and National Highway Traffic
Safety Administration (“NHTSA”) jointly adopted regulations that establish vehicle carbon dioxide emissions standards and 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. On March 31, 2020, the agencies released updated fuel economy and vehicle emissions standards, which provide for an
increase in stringency by 1.5% each year through model year 2026, as compared with the standards issued in 2012 that
required 5% annual increases. On December 30, 2021, the EPA and NHTSA published a final rule containing additional fuel
efficiency standards for cars and light trucks that include 5-10% reductions of GHG emissions annually through model year
2026. Higher fuel economy standards have the potential to reduce demand for our refined transportation fuel products.
Under EISA, the RFS requires an increasing amount of renewable fuel to be blended into the nation’s transportation fuel
supply, up to 36 billion gallons by 2022. Over time, higher annual RFS requirements have the potential to reduce demand for
our refined transportation fuel products. In the near term, the RFS will be satisfied primarily with fuel ethanol blended into
gasoline. We, and other refiners subject to the 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 can retain these RINs for
current or future RFS compliance or sell those on the open market. On December 21, 2021, the EPA published proposed RFS
that include retroactive cuts to earlier 2020 quotas, set 2021 targets at levels of renewable fuels that were actually used, and
would establish significantly higher volume requirements for 2022. Whether that rule will be finalized as proposed and how
the final rule will fare in the courts may significantly alter our obligations to blend renewable fuels or purchase RINs. The RFS
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 to purchase RINs with other parties or purchase cellulosic biofuels RINs (“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 2019, the EPA approved year-round sales of E15 but that approval has been overturned by the courts and, as of January 10,
2022, the Supreme Court has declined to review further appeals on that subject. There are numerous issues, including state
and federal regulatory issues, that 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 was January 1, 2017, however, approved small volume refineries had until January 1, 2020 to meet the standard. The
Hawaii refinery was required to comply with Tier 3 gasoline standards within 30 months of June 21, 2016, the date it was
disqualified from small volume refinery status. On March 19, 2015, the EPA confirmed the small refinery status of our
Wyoming refinery. The Hawaii refinery, our Wyoming refinery, and our Washington refinery, acquired in January 2019, were
all granted extensions of small refinery exemptions by the EPA for 2018. All our refineries are Tier 3 compliant.
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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) were 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 fully aligned with the
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 were 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 adopted newer standards that further reduce the global limit on sulfur content in
maritime fuels to 0.5% beginning in 2020 (“IMO 2020”).
In addition to federal requirements, several states, including Washington, have proposed or enacted low carbon fuel standards
applicable to transportation fuels. The Washington proposal would create a carbon intensity score for transportation fuels, and
require fuel producers and importers who fall short of carbon intensity goals to purchase credits.
There will be compliance costs and uncertainties regarding how we will comply with the various requirements contained in
the EISA, RFS, 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.
S O L ID AND HA Z ARD OUS WA S T E
Several of our businesses generate wastes, including hazardous wastes, that 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.
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.
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. While this “petroleum exclusion” lessens the significance of our operations, we may
generate wastes that may fall within CERCLA’s definition of a “hazardous substance” in the course of our ordinary refining
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 P OL LU T ION AC T
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. 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.
DI S C HARGE S AND MARINE PROT EC T I O N
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
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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 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.
AIR EMI S S I O N S
Our refining 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 forgo construction or operation of certain air
emission sources. We believe that we are in substantial compliance with air pollution control requirements.
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. Compliance with this rule has not had a material impact on our
financial condition, results of operations, or cash flows to date.
COA S TAL CO O RDINAT I O N
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.
ENVIRONMEN TAL AGREEMEN T
On September 25, 2013, 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 Corporation (“Tesoro,” which changed its name to Andeavor
Corporation before being purchased by Marathon Petroleum Company in October 2018), and PHR entered into an Environmental
Agreement (“Environmental Agreement”) that allocated responsibility for known and contingent environmental liabilities related to
the acquisition of PHR, including a consent decree.
OT HER GOVERNMEN T REGUL AT I O N
IMPACT OF DODD-FRANK ACT DERIVATIVES REGUL ATION
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.
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
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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 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 each of the years ended December 31, 2021 and 2020, we had one
customer in our refining segment that accounted for 13% of our consolidated revenue. No other customer accounted for
more than 10% of our consolidated revenues during the years ended December 31, 2021, 2020, and 2019.
Human Capital
WORKFORCE COMPOSITION
At Par, we believe our employees are our most valuable asset. By investing in our employees, we are able to achieve success
and continue to execute on our mission and vision. At December 31, 2021, our workforce consisted of 1,336 employees,
including 226 employees, or 17% of our total workforce, at our Hawaii and Washington refineries represented by the United
Steelworkers Union (“USW”) with collective bargaining agreements which expired on January 31, 2022 and are currently
subject to automatic extension periods while the parties continue negotiations. We value all our employees, represented and
non-represented, and constantly strive to maintain and improve satisfactory relationships with them. Our 1,336 employees
work in the following operating segments throughout the United States:
OPERATING SEGMENT
NUMBER OF EMPLOYEES
Refining and Logistics
Retail
Corporate
Total
663
573
100
1,336
DIVERSIT Y
Par is focused on recruiting and developing a diverse workforce. We prioritize outreach activities that increase the diversity
of applicants for open positions and actively ensure that all open positions are posted on job boards that target female,
minority, disabled, and military veteran candidates. We are developing relationships with local organizations that provide
services to historically underserved populations and make them aware of career opportunities at Par. As of December 31,
2021, our workforce consisted of 49% minorities and 6% protected veterans.
CULTURE AND VALUES
Par is a values-driven company. Our tight-knit community values integrity, creativity, hard work, and respect for others. These
four pillars support our successes and strengthen our ability to be an effective and fun place to work. We value innovative
thought and rally behind ideas that create new opportunities. We believe this drives our growth and success. We value the
unique heritage, experiences, and contributions of everyone we get to work with and serve. Our commitment to doing the
good and right thing with the highest ethical standards helps us to achieve our best results. As we pursue growth and
success, we believe it is important to keep our people safe, to value our diversity, and to protect our environment.
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BENEFITS
We offer highly competitive compensation, benefit, and time-off packages to promote employee fulfillment and work-life
balance. Our benefits include our employee stock purchase plan, extensive health and wellness benefits, generous time off
allowance, and a tuition reimbursement program.
HEALTH AND SAFET Y
Safety is paramount to every operation and activity we undertake. We recognize that our responsible stewardship impacts
every employee, every contractor, and every member of the community, and we embrace that responsibility. We promote a
culture of continual safety improvement with a keen eye for evaluating and managing risk. We continually monitor the
implementation of programs, policy, and procedures to achieve this objective.
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, as amended (the “Securities Act”), Section 21E of the Securities Exchange Act of 1934, as amended
(the “Exchange Act”), the Private Securities Litigation Reform Act of 1995 (“PSLRA”), or in releases made by the SEC, all as may
be amended from time to time. Such forward-looking statements involve known and unknown risks, uncertainties, and other
important factors that could cause our actual results, performance, or achievements to differ materially from any future results,
performance, or achievements expressed or implied by such forward-looking statements. Statements that are not historical fact
are forward-looking statements. Forward-looking statements can be identified by, among other things, the use of forward-looking
language, such as the words “plan,” “believe,” “expect,” “anticipate,” “intend,” “estimate,” “project,” “may,” “will,” “would,”
“could,” “should,” “seeks,” or “scheduled to,” or other similar words or the negative of these terms or other variations of
these terms or comparable language or by discussion of strategy or intentions. These cautionary statements are being made
pursuant to the Securities Act, the Exchange Act, and the PSLRA with the intention of obtaining the benefits of the “safe
harbor” provisions of such laws.
The forward-looking statements contained in this Annual Report on Form 10-K are largely based on our expectations, which
reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment
based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be
reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In
addition, management’s assumptions about future events may prove to be inaccurate. All readers are cautioned that the
forward-looking statements contained in this Annual Report on Form 10-K are not guarantees of future performance and we
cannot assure any reader that such statements will be realized or that the forward-looking events and circumstances will
occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors
described in “Item 1A. — Risk Factors”, “Item 7. — Management’s Discussion and Analysis of Financial Condition and Results
of Operations,” and elsewhere in this Annual Report on Form 10-K. Additionally, significant uncertainties remain with respect
to COVID-19 and its economic effects. Due to the unpredictable and unprecedented nature of the COVID-19 pandemic, we
cannot identify all potential risks to, and impacts on, our business, including the ultimate adverse economic impact to the
Company’s business, results of operations, financial condition, and liquidity. 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.
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 occur, 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, cyber threats, 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
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damage to our properties and the properties of others. The scientific consensus suggests that some of these physical risks to
our facilities and third party facilities, especially risks associated with extreme weather, may increase as a result of climate
change. 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, the 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 (including cyber-attacks), acts of war, and other global political conditions;
• changes in the availability or cost of maritime shipping;
• pandemics, public health crises, or other widespread emergencies such as the novel coronavirus (COVID-19);
• government regulations or mandated production curtailments or limitations; and
• weather conditions, hurricanes, or other natural disasters.
For example, the COVID-19 pandemic resulted in significant demand reduction for crude oil and refined products, particularly
in the Hawaii market, and abnormal volatility in oil commodity prices, which may continue for the foreseeable future. In
addition, the Organization of the Petroleum Exporting Countries (“OPEC”) has agreed to adjust downwards their overall
production of crude oil through April 30, 2022, with the agreement to be reassessed in December 2021, to support crude oil
prices. And the Alberta government has previously mandated crude oil production cuts in a region where our Washington
refinery sources crude oil. Such an 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 our refining business.
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.
Our business, financial condition, results of operations, and liquidity have been adversely affected by the COVID-19
pandemic that has caused, and is expected to continue to cause, the global slowdown of economic activity (including the
decrease in demand for crude oil and the refined products that we produce and sell), disruptions in global supply chains,
and significant volatility and disruption of financial markets and that also has adversely affected workforces, customers,
and regional and local economies.
Because the severity, magnitude, and duration of the COVID-19 pandemic and its economic consequences are uncertain, rapidly
changing, and difficult to predict, the impact on our business, results of operations, financial condition, and liquidity remains
uncertain and difficult to predict. The ultimate impact of the COVID-19 pandemic on our results of operations and financial
condition remains uncertain and depends on numerous evolving factors, many of which are not within our control, and which
we may not be able to effectively respond to, including, but not limited to: governmental, business, and individuals’ actions that
have been and continue to be taken in response to the pandemic (including restrictions on travel and transport, workforce
pressures and social distancing, and stay-at-home orders); the effect of the pandemic on economic activity and actions taken
in response; the effect on our customers and their demand for our products; the effect of the pandemic on the creditworthiness
of our customers; national or global supply chain challenges or disruption; workforce availability; facility closures; commodity
cost volatility; general economic uncertainty in key global markets and financial market volatility and ability to access capital
markets; global economic conditions and levels of economic growth; and the pace of recovery when the COVID-19 pandemic
subsides, as well as response to a potential reoccurrence.
Further, the COVID-19 pandemic, and the volatile regional and global economic conditions stemming from the pandemic,
could also precipitate or aggravate the other risk factors that we identify in this Annual Report on Form 10-K, which could
materially adversely affect our business, financial condition, results of operations (including revenues and profitability), and
liquidity and/or stock price. Additionally, COVID-19 may also affect our operating and financial results in a manner that is not
presently known to us or that we currently do not consider to present significant risks to our operations.
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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 and demand for refined products. This may place downward pressure on our results of operations. This is particu-
larly true of developments in and relating to oil-producing countries, including terrorist activities, military conflicts, embar-
goes, 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.
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 fueling stations with underground storage tanks used primarily for storing and
dispensing refined fuels. In addition, some fueling stations where we sell fuel are owned or operated by third parties who are
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 adverse weather, accidents, governmental regulation or sanctions, or
third-party action. A prolonged disruption could have a material adverse effect on our business, financial condition, and
results of operations.
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The financial and operating results of our refineries, including the products they refine and sell, can be seasonal.
Demand for gasoline in the Rockies and Northwest United States is generally higher during the summer months than during the
winter months due to seasonal increases in highway traffic. The Wyoming and Washington refineries’ 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. Conversely, the demand for the products the 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.
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, ransomware, 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. Our systems and procedures for protecting against such attacks and mitigating such risks may prove
to be insufficient in the future and such attacks could have an adverse impact on our business and operations, including damage
to our reputation and competitiveness, remediation costs, litigation, or regulatory. 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. In addition, as technologies evolve, and cyber-attacks become more sophisticated, we may
incur significant costs to upgrade or enhance our security measures to protect against such attacks and we may face difficulties
in fully anticipating or implementing adequate preventive measures or mitigating potential harm. 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 and our ability to extract value is limited.
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. Additionally, 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.
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. 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 NOX) 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,
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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 RFS program sets annual quotas for the quantity of renewable fuels that must be blended into transportation fuels
consumed in the U.S. A RIN is assigned to each gallon of renewable fuel produced in or imported into the U.S. As a producer
of petroleum-based transportation fuels, we are obligated to blend renewable fuels into the petroleum fuels we produce and
sell in the U.S. To the extent we do not, we are required to purchase RINs in the market to satisfy our obligations under the
RFS program. During 2021, we incurred $118.8 million of RINs expense for our Hawaii, Wyoming, and Washington refineries.
On December 21, 2021, the EPA published proposed renewable volume obligations (“RVO”) for 2021 consistent with amounts
of renewable fuels actually blended that year. Until that rule is finalized and the RVO is set, however, the potential associated
expense associated with meeting the 2021 obligations remains uncertain. 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.
We are exposed to the volatility in the market price of RINs and are unable to predict the future prices of RINs. RINs prices
are dependent upon a variety of factors, including EPA regulations, the availability of RINs for purchase, and levels of
transportation fuels produced, which can vary significantly from quarter to quarter. The ultimate outcome of the 2021 RVO
rule will also likely affect RIN prices. If sufficient RINs are unavailable for purchase, if we have to pay a significantly higher
price for RINs, or if we are otherwise unable to meet the EPA’s RFS mandates, our results of operations and cash flows could
be adversely affected. The current administration has also been critical of exemptions from the RFS mandates granted to
small refineries during the previous administration. While litigation over the issue is currently before the U.S. Supreme Court,
the EPA under the current administration may be less willing to grant such waivers going forward and may increase the RVO
in future years. To the extent fewer waivers are granted in the future or the RVO is increased, the demand for and the price of
RINs would likely also increase, and our results of operations and cash flows could be adversely affected. Ongoing litigation
and regulatory activity regarding the standards for 2016, 2017, 2018, 2019, and 2020 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 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 prior years, costs that exceed our estimates in connection with RFS
compliance for 2021, 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. All RIN transactions are recorded in
the EPA Moderated Transaction System (“EMTS”). Under this system, purchasers of RINs are required to self-certify their
validity without verification by the EPA, and are responsible for any invalid RINs submitted to the EPA for compliance. 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.
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 GHG emissions in the state. Since 2006, the State of 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 2020 and 2021 the State of Washington adopted several statutes that are relevant to our Tacoma, Washington
location including a law approving new regulatory requirements regarding zero emission vehicles and a low-carbon fuel
standard designed to reduce the carbon intensity of transportation fuels by twenty percent by 2038. Legislation signed in
March of 2020 directed the Washington Department of Ecology to adopt California’s vehicle emission standards including
requirements to increase zero emission vehicles sold in the state. Washington Department of Ecology adopted by reference
California’s zero emission vehicle standard starting with model year 2025 in a rule issued on November 29, 2021. 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 the State to facilitate
the development of alternate fuels so such fuels 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 products, 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.
Currently, multiple legislative and regulatory measures to address GHG, including CO2, methane, and NOX, and other
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emissions are in various phases of consideration, promulgation, or implementation at various levels of the federal and state
government. These include actions to develop international, federal, regional, or statewide programs, which could require
reductions in our GHG or other emissions, establish a carbon tax and decrease the demand for our refined products.
Requiring reductions in these emissions could result in increased costs to (i) operate and maintain our facilities, (ii) install new
emission controls at our facilities, and (iii) administer and manage any emissions programs, including acquiring emission
credits or allotments.
For example, in 2015, the U.S., Canada, and the U.K. participated in the United Nations Conference on Climate Change, which
led to the creation of the Paris Agreement. The Paris Agreement, which was signed by the U.S. in April 2016, requires
countries to review and “represent a progression” in their intended nationally determined contributions (which set GHG
emission reduction goals) every five years beginning in 2020. In November 2020, the United States’ previously-announced
withdrawal from the Paris Agreement became effective. On January 20, 2021, President Biden announced that the United
States would be reentering the Paris Agreement. This reentry became effective on February 19, 2021. Restrictions on
emissions of methane or carbon dioxide that have been or may be imposed in various U.S. states, at the U.S. federal level, or
in other countries could adversely affect the oil and gas industry.
The EPA has issued a notice of finding and determination that emissions of CO2, methane, and other GHGs present an
endangerment to human health and the environment. In response, the EPA has adopted regulations under existing provisions
of the federal Clean Air Act 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.
At the state level, the State of Hawaii has announced its intention to reduce statewide GHG emissions to 1990 levels by 2020.
Other states, including Washington, have passed low carbon fuel standard legislation and other initiatives to reduce emissions
from the transportation sector. We could also face increased climate-related litigation with respect to our operations or
products. If we are unable to pass the costs of compliance on to our customers, sufficient credits are unavailable for purchase,
we have to pay a significantly higher price for credits, or we are otherwise unable to meet our compliance obligation, our
financial condition and results of operations could be adversely affected.
Federal, regional, and state climate change and air emissions goals and regulatory programs are complex, subject to change,
and create uncertainty due to a number of factors including technological feasibility, legal challenges, and potential changes
in federal policy. Nevertheless, stricter regulation can be expected in the future and any of these or similar changes may have
a material adverse impact on our business, results of operations, and financial condition.
Regulatory and other requirements concerning the transportation of crude oil and other commodities by rail may cause
increases in transportation costs or limit the amount of crude oil that we can transport by rail.
We rely on a variety of systems to transport crude oil, including rail. Rail transportation is regulated by federal, state, and
local authorities. New regulations or changes in existing regulations could result in increased compliance expenditures. For
example, in 2019 Washington enacted a law that limits crude oil by rail deliveries through a cap on off-loadings from existing
facilities and new specifications regarding the vapor pressure of crude oils permitted to be shipped through the state. These
or other regulations that require the reduction of volatile or flammable constituents in crude oil that is transported by rail,
change the design or standards for rail cars used to transport the crude oil we purchase, change the routing or scheduling of
trains carrying crude oil, or require any other changes that detrimentally affect the economics of delivering North American
crude oil by rail, could increase the time required to move crude oil from production areas to our refineries, increase the cost
of rail transportation, and decrease the efficiency of shipments of crude oil by rail within our operations. Any of these
outcomes could have a material adverse effect on our business, results of operations, and financial condition.
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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, indirect-
ly, 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, 2021, we
have accrued $15.6 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 to be incurred over approximately 30 years.
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 current 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. The frequency of these exceedances appears to be declining over time, but we may become subject
to new penalty enforcement action in the future.
We may incur significant costs and liabilities resulting from performance of pipeline integrity programs and related repairs.
Pipeline and Hazardous Materials Safety Administration (“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.
Compliance with and changes in tax laws could materially and adversely affect our financial condition, results of
operations and cash flows.
We are subject to extensive tax liabilities imposed by multiple jurisdictions including, without limitation, income taxes, indirect taxes
(excise/duty, sales/use, gross receipts), payroll taxes, franchise taxes, withholding taxes, and ad valorem taxes. New tax laws and
regulations and changes in existing tax laws and regulations are continuously being enacted or proposed that could result in
increased expenditures for tax liabilities in the future. Many of these liabilities are subject to periodic audits by the respective taxing
authority. Although we believe we have used reasonable interpretations and assumptions in calculating our tax liabilities, the final
determination of these tax audits and any related proceedings cannot be predicted with certainty. Any adverse outcome of such tax
audits or related proceedings could result in unforeseen tax-related liabilities that may, individually or in the aggregate, materially
affect our cash tax liabilities, results of operations, and financial condition. Additionally, tax rates or tax interpretations in the various
jurisdictions in which we operate may change significantly as a result of political or economic factors beyond our control.
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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, refined product mix demand, 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.
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 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.
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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 Hawaii refinery is subject to our Supply and Offtake Agreement with J. Aron and certain
deliveries of crude oil at our Washington refinery are subject to the Washington Refinery Intermediation Agreement
(together, the “Intermediation Agreements”). If we are unable to obtain our crude oil supply for our refineries under 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.
The Intermediation Agreements expose us to counterparty credit and performance risk.
We have the Supply and Offtake Agreement 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 Agreement,
which terminates on May 31, 2024 unless extended by mutual agreement for an additional one year term, 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 also have the Washington Refinery Intermediation Agreement with MLC
whereby our Washington refinery purchases certain crude oil supplies from third-party suppliers and MLC 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.
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, 2021, we
had $564.6 million of indebtedness and Interest expense and financing costs, net for the year ended December 31, 2021 was
$66.5 million.
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;
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• 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, 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 us 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 we 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
indebtedness could substantially increase our interest expense and have a material adverse effect on our financial condition, results
of operations, and cash flows.
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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, 2021, we estimated that we had approximately $1.6 billion of net operating loss (“NOL”) tax carryforwards. 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 a significant portion of our NOLs to offset future taxable income is subject to various limitations,
including that certain NOLs will expire in various amounts, if not used, between 2028 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, enacted in 2017, 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 our Wyoming refining business, our Pacific
Northwest retail business, and U.S. Oil and assets related to the Hawaii refinery. 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.
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, 2021, we employed approximately 1,336 people, 226 of whom are covered by collective bargaining
agreements. At our Hawaii and Washington refineries, all 226 employees covered by collective bargaining agreements are
represented by the USW with collective bargaining agreements which expired on January 31, 2022 and are currently subject
to automatic extension periods while the parties continue negotiations. However, 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 $19.74 on March 11, 2021, and a low of $12.91 on
May 19, 2021, during the year ended December 31, 2021. 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 announcements by us or our
competitors of significant acquisitions, strategic partnerships, joint ventures, or capital commitments.
An impairment of an equity investment, a long-lived asset, or goodwill could reduce our earnings or negatively impact the
value of our common stock.
Consistent with U.S. generally accepted accounting principles (“GAAP”), we evaluate our goodwill for impairment at least
annually and our equity investments and long-lived assets, including intangible assets with finite useful lives, whenever
events or changes in circumstances indicate that the carrying amount may not be recoverable. For the investments we
account for under the equity method, such as Laramie Energy, the impairment test requires us to consider whether the fair
value of the equity investment as a whole, not the underlying net assets, has declined and whether that decline is other than
temporary. If we determine that an other-than-temporary impairment is indicated, we would be required to recognize a
non-cash charge to earnings with a correlative effect on equity and balance sheet leverage as measured by debt to total
capitalization. As a result of the global economic impact of the COVID-19 pandemic and a steep decline in current and
forecasted prices and demand for crude oil and refined products, the goodwill at our refining reporting units in Hawaii and
Washington was fully impaired and the goodwill associated with our retail reporting unit in Washington and Idaho was
partially impaired, resulting in a charge of $67.9 million in our consolidated statement of operations for the year ended
December 31, 2020. Additionally, as a result of our impairment evaluations of our investment in Laramie Energy, we recorded
impairment charges of $45.3 million and $81.5 million on our consolidated statement of operations for the years ended
December 31, 2020 and 2019, respectively. Any additional impairment charges could have a negative impact on the price of
our common stock. Additionally, there can be no assurance that no future impairment charge will be made with respect to
our equity investments, goodwill, and long-lived assets.
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 two shareholders. 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.
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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”) and Blackrock, Inc., together with their respective affiliates, each owned
or had the right to acquire as of December 31, 2021 approximately 19.8% and 12.6%, 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.
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.
Investor sentiment towards climate change, fossil fuels, sustainability, and other Environmental, Social, and Governance
(“ESG”) matters could adversely affect our business and our stock price.
There have been efforts in recent years aimed at the investment community, including investment advisors, sovereign wealth
funds, public pension funds, universities, and other groups, to promote the divestment of shares of energy companies, as
well as to pressure lenders and other financial services companies to limit or curtail activities with energy companies. As a
result, some financial intermediaries, investors, and other capital markets participants have reduced or ceased lending to, or
investing in, companies that operate in industries with higher perceived environmental exposure, such as the energy
industry. If divestment efforts are continued, the price of our common stock or debt securities, and our ability to access
capital markets or to otherwise obtain new investment or financing, may be negatively impacted.
Members of the investment community are also increasing their focus on ESG practices and disclosures, including practices
and disclosures related to GHGs and climate change in the energy industry in particular, and diversity and inclusion initiatives
and governance standards among companies more generally. As a result, we may face increasing pressure regarding our ESG
practices and disclosures. Additionally, members of the investment community may screen companies such as ours for ESG
performance before investing in our common stock or debt securities or lending to us. Over the past few years there has also
been an acceleration in investor demand for ESG investing opportunities, and many large institutional investors have
committed to increasing the percentage of their portfolios that are allocated towards ESG-focused investments. As a result,
there has been a proliferation of ESG-focused investment funds seeking ESG-oriented investment products.
If we are unable to meet the ESG standards or investment or lending criteria set by these investors and funds, we may lose
investors, investors may allocate a portion of their capital away from us, our cost of capital may increase, the price of our
common stock and debt securities may be negatively impacted, and our reputation may also be negatively affected.
Item 1B. UNRESOLVED STAFF COMMENTS
None.
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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, logistics, and retail 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.
NAT UR AL GA S AND OIL PRO PER T IE S
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 condensate 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. As
of December 31, 2019, Laramie Energy ceased all drilling activities due to unfavorable market conditions. During the year ended
December 31, 2020, we discontinued the application of the equity method of accounting for our investment in Laramie Energy.
As of December 31, 2021, the balance of our investment in Laramie Energy on our consolidated balance sheets was zero.
Other
We also own certain immaterial minority interests in wells located in Colorado.
Item 3. LEGAL PROCEEDINGS
From time to time, we may be involved in 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 17—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
MARKE T INFO RMAT I O N
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 February 18, 2022, there were 139 common stockholders
of record. On February 18, 2022, the closing price of our common stock was $14.91 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.
S TO C K PERFORMANC E GR APH
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, 2021. 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: Alto Ingredients, Inc., 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 Holdings, LLC, Methanex Corporation, Renewable Energy Group, Inc., REX American Resources
Corporation, 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.
COMPARISON OF 5-YEAR CUMULATIVE TOTAL RETURN*
AMONG PAR PACIFIC, THE S&P 500 INDEX, AND A PEER GROUP
$300
$250
$200
$150
$100
$50
12/31/16
12/31/17
12/31/18
12/31/19
12/31/20
12/31/21
PAR PACIFIC HOLDINGS, INC.
S&P 500
PEER GROUP
*$100 invested on December 31, 2016 in stock or index, including reinvestment of dividends.
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REC EN T SAL E S OF UNREGI S T ERED S ECURI T IE S
During the year ended December 31, 2021, 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.
I S SUER PURC HA S E S OF EQUI T Y S ECURI T IE S
The following table sets forth certain information with respect to repurchases of our common stock during the quarter ended
December 31, 2021:
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 (1)
MAXIMUM NUMBER
(OR APPROXIMATE
DOLLAR VALUE) OF
SHARES (OR UNITS)
THAT MAY YET BE
PURCHASED UNDER
THE PLANS OR
PROGRAMS (1)
October 1 - October 31, 2021
November 1 - November 30, 2021
December 1 - December 31, 2021
Total
816
—
58,922
59,738
$ 15.41
—
$ 13.46
$ 13.49
—
—
58,804
58,804
—
—
$ 49,208,741
$ 49,208,741
(1) Shares repurchased not associated with the share repurchase program were surrendered by employees to pay taxes withheld upon the vesting of restricted stock
awards. On November 10, 2021, the Board authorized and approved a share repurchase program for up to $50 million of the currently outstanding shares of the
Company’s common stock, with no specified end date. Please read Note 18—Stockholders’ Equity for further information.
Item 6. [RESERVED]
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.
KN OWN T RENDS O R UNC ER TAIN T IE S
While the market indices presented below under “Item 7. — Management’s Discussion and Analysis of Financial Condition
and Results of Operations — Results of Operations” are representative of the results of our refineries, each refinery’s realized
gross margin on a per barrel basis will differ from the benchmark due to a variety of factors that affect the performance of
the specific refinery. These factors include, but are not limited to, the actual type and timing of crude oil throughput; product
yields; transportation and storage costs; fuel burn; product premiums or discounts; inventory fluctuations; feedstock and
product purchases; commodity price risk-management activities; crude oil purchase financing activities; and other factors not
reflected in the benchmark refining margin. We operate in logistically complex, niche markets and, as such, each of our
refineries has unique cost advantages and disadvantages as compared to their respective relevant market indices.
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REC EN T E VEN T S AFFEC T ING COMPAR ABIL I T Y O F PERI O DS
COVID-19 PANDEMIC
The ongoing spread of COVID-19, in conjunction with related government and other preventative measures taken to mitigate
the spread of the virus, continued to cause severe disruptions in the worldwide economy in 2021, including the global
demand for crude oil and refined products, the movement of people and goods in the United States, and the global supply
chain for industrial and commercial production, all of which have in turn disrupted our businesses and operations. During
2021, vaccine availability and acceptance and easing of government responses to the pandemic such as travel restrictions led
to increased travel in the regions in which we operate. The increase in travel has resulted in higher demand for refined
products, an important driver in key aspects of our operations, including sales volumes and the prices of crude oil and refined
products. Full recovery to pre-pandemic levels of global demand remains uncertain, however, as additional variants may emerge
that cause a resurgence of COVID-19 and travel restrictions continue to limit international travel. For more information, please
read “Item 1. — Business — Markets” of this Form 10-K.
We have undertaken additional liquidity-enhancing measures in response to the COVID-19 pandemic, including deferring or
delaying certain capital expenditures related to turnaround activities at our Washington refinery. We closed sale-leaseback
transactions (the “Sale-Leaseback Transactions”) in the first quarter of 2021, in which we sold twenty-two (22) retail convenience
store/fuel station properties located in Hawaii (the “Sale-Leaseback Properties”) for $112.8 million, net of fees. We also entered
into a lease on the properties for fifteen (15) years, unless earlier terminated, with up to four 5-year renewal options. On March 19,
2021, we sold 5.75 million shares of common stock in an underwritten public offering at a public offering price of $16.00 per share
resulting in net proceeds to us of approximately $87.2 million, after deducting underwriting discounts and commissions and
offering expenses.
We believe the steps we have taken strengthen our ability to operate through current conditions. We continue to maintain
existing processes and procedures including, but not limited to, processes and procedures around protection of our technology
systems and proprietary data, even though many of our employees are working from home. The health and well-being of our
employees and customers are our top priorities as we continue navigating the challenges presented by the COVID-19 pandemic.
The financial results contained in this Annual Report on Form 10-K reflect the continued impacts on our business of the
COVID-19 pandemic experienced during 2021 in the regions in which we operate. The COVID-19 pandemic is ongoing and we
continue to actively monitor the impacts of the virus on our people, operations, financial condition, liquidity, suppliers,
customers, and industry. Due to the rapid development and fluidity of the situation, the full magnitude of the COVID-19
impact on our financial condition, future results of operations, and future cash flows and liquidity is uncertain and has been
and may continue to be material.
WASHINGTON ACQUISITION
On January 11, 2019, we completed the Washington Acquisition for total consideration of $326.5 million, including acquired
working capital, consisting of cash consideration of $289.5 million and approximately 2.4 million shares of our common stock
with a fair value of $37.0 million issued to the seller of U.S. Oil. The results of operations for U.S. Oil were included in our refining
and logistics segments commencing January 11, 2019. Please read Note 4—Acquisitions to our consolidated financial statements
under Item 8 of this Form 10-K for more information.
In connection with the consummation of the Washington Acquisition, we assumed the Washington Refinery Intermediation
Agreement with MLC that provides a structured financing arrangement based on U.S. Oil’s crude oil and refined products
inventories and associated accounts receivable. Please read Note 11—Inventory Financing Agreements to our consolidated
financial statements under Item 8 of this Form 10-K for more information.
SECOND AMENDED AND RESTATED J. ARON SUPPLY AND OFFTAKE AGREEMENT
Prior to July 1, 2021, under the first amended and restated supply and offtake agreement we had the right to defer payments owed
to J. Aron under a deferred payment arrangement up to the lesser of $165 million or 85% of eligible accounts receivable and
inventory. On June 1, 2021, we entered into the Second Amended and Restated Supply and Offtake Agreement (the “Supply and
Offtake Agreement”), which provided for a discretionary draw facility to be available to PHR (the “Discretionary Draw Facility”)
commencing as of July 1, 2021. Under the Discretionary Draw Facility, J. Aron agreed to make advances to PHR in an aggregate
principal amount at any one time outstanding not to exceed the lesser of $165 million or the sum of the borrowing base, which is
calculated as (x) 85% of the eligible accounts receivables, plus (y) the lesser of $82.5 million and 85% of eligible hydrocarbon
inventory, minus (z) such reserves as established by J. Aron in respect of eligible receivables and eligible hydrocarbon inventory.
Please read Note 11—Inventory Financing Agreements to our consolidated financial statements under Item 8 of this Form
10-K for more information.
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RE SULT S OF OPER AT ION S
YEAR ENDED DECEMBER 31, 2021 COMPARED TO YEAR ENDED DECEMBER 31, 2020
Net Loss. Our financial results for the year ended December 31, 2021 improved from a net loss of $409.1 million for the year ended
December 31, 2020 to a net loss of $81.3 million for the year ended December 31, 2021. The improvement was primarily driven by
favorable refined product sales pricing and feedstock costs at our Hawaii refinery, partially offset by higher inventory financing
costs at our Washington refinery related to rising inventory financing and product costs. Other factors impacting our results period
over period include a 2021 gain on sale of assets of $63.9 million primarily related to the Sale-Leaseback Transactions we closed in
the first quarter of 2021, asset impairment charges of $1.8 million in 2021 as compared to our 2020 goodwill impairment of $67.9
million and asset impairment charges of $17.9 million, and an other-than-temporary impairment of $45.3 million related to our
equity investment in Laramie Energy in 2020.
Adjusted EBITDA and Adjusted Net Loss. For the year ended December 31, 2021, Adjusted EBITDA was $61.5 million compared
to a loss of $86.7 million for the year ended December 31, 2020. The improvement was primarily related to favorable realized
refined product crack spreads at all our refineries, favorable feedstock, purchased product and derivative costs at our Hawaii
refinery, and higher refined product sales volumes at our Wyoming refinery, partially offset by unfavorable inventory
financing and environmental compliance costs and higher operating expenses.
For the year ended December 31, 2021, Adjusted Net Loss was $100.3 million compared to $249.8 million for the year ended
December 31, 2020. The change was primarily related to the same factors described above for the increase in Adjusted EBITDA.
YEAR ENDED DECEMBER 31, 2020 COMPARED TO YEAR ENDED DECEMBER 31, 2019
Net Income (Loss). Our net income decreased from $40.8 million for the year ended December 31, 2019 to a net loss of
$409.1 million for the year ended December 31, 2020. The decrease in our net income (loss) was primarily driven by lower
refining sales volumes and unfavorable crack spreads related to COVID-19 demand destruction, increased RINs expenses and
derivative costs, goodwill and asset impairments of $85.8 million, and an unfavorable change in lower of cost and net
realizable value adjustments, partially offset by cost reductions across our businesses in response to COVID-19 and higher
retail fuel margins. In addition, we incurred an other-than-temporary impairment of $45.3 million related to our equity
investment in Laramie Energy in 2020, as compared to an other-than-temporary impairment of $83.2 million in 2019. Other
factors impacting our results period over period include a $49.0 million reduction in our income tax benefit and lower debt
extinguishment and commitment costs.
Adjusted EBITDA and Adjusted Net Income (Loss). For the year ended December 31, 2020, Adjusted EBITDA was a loss of
$86.7 million compared to earnings of $258.8 million for the year ended December 31, 2019. The change was primarily
related to lower refining sales volumes and unfavorable crack spreads related to COVID-19 demand destruction, partially
offset by lower operating expense and higher retail fuel margins.
For the year ended December 31, 2020, Adjusted Net Income (Loss) was a loss of $249.8 million compared to income of $90.2
million for the year ended December 31, 2019. The change was primarily related to the same factors described above for the
decrease in Adjusted EBITDA and higher depreciation, depletion, and amortization (“DD&A”) due to recently completed
capital projects, including turnaround projects, partially offset by a $4.6 million decrease in interest expense and financing
costs and a $5.8 million decrease in our Equity losses from Laramie Energy, excluding our share of unrealized gains or losses
on derivatives and excluding impairment changes associated with our investment in Laramie Energy.
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The following table summarizes our consolidated results of operations for the years ended December 31, 2021, 2020, and
2019 (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,
2021
2020
2019
Revenues
$ 4,710,089
$ 3,124,870
$ 5,401,516
Cost of revenues (excluding depreciation)
4,338,474
2,947,697
4,803,589
Operating expense (excluding depreciation)
299,669
277,427
312,899
Depreciation, depletion, and amortization
Impairment expense
Gain on sale of assets, net
94,241
1,838
(64,697)
90,036
85,806
—
General and administrative expense (excluding depreciation)
48,096
41,288
Acquisition and integration costs
87
614
86,121
—
—
46,223
4,704
Total operating expenses
Operating income (loss)
Other income (expense)
4,717,708
3,442,868
5,253,536
(7,619)
(317,998)
147,980
Interest expense and financing costs, net
(66,493)
(70,222)
(74,839)
Debt extinguishment and commitment costs
Gain on curtailment of pension obligation
Other income (expense), net
Change in value of common stock warrants
Equity earnings (losses) from Laramie Energy, LLC
Total other expense, net
Loss before income taxes
Income tax benefit (expense)
Net income (loss)
(8,144)
2,032
(52)
—
—
—
—
1,049
4,270
(11,587)
—
2,516
(3,199)
(46,905)
(89,751)
(72,657)
(111,808)
(176,860)
(80,276)
(429,806)
(28,880)
(1,021)
20,720
69,689
$ (81,297)
$ (409,086)
$ 40,809
32
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The following tables summarize our operating income (loss) by segment for the years ended December 31, 2021, 2020, and
2019 (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, 2021
REFINING
LOGISTICS (1)
RETAIL
CORPORATE,
ELIMINATIONS
AND OTHER (2)
TOTAL
Revenues
$ 4,471,111
$ 184,734
$ 456,416
$ (402,107)
$ 4,701,089
Cost of revenues (excluding depreciation)
4,306,371
Operating expense (excluding depreciation)
213,102
Depreciation, depletion, and amortization
Impairment expense
Loss (gain) on sale of assets, net
General and administrative expense
(excluding depreciation)
Acquisition and integration costs
58,258
1,838
(19,659)
—
—
96,828
14,722
22,044
—
(19)
—
—
337,476
(402,201)
4,338,474
71,845
10,880
—
(45,034)
—
—
—
3,059
—
15
299,669
94,241
1,838
(64,697)
48,096
48,096
87
87
Operating income (loss)
$ (88,799)
$ 51,159
$ 81,249
$ (51,228)
$ (7,619)
YEAR ENDED DECEMBER 31, 2020
REFINING
LOGISTICS (1)
RETAIL
CORPORATE,
ELIMINATIONS
AND OTHER (2)
TOTAL
Revenues
$ 2,886,701
$ 180,909
$ 363,713
$ (306,453)
$ 3,124,870
Cost of revenues (excluding depreciation)
2,908,870
110,385
234,885
(306,443)
2,947,697
Operating expense (excluding depreciation)
199,738
Depreciation, depletion, and amortization
Impairment expense
General and administrative expense
(excluding depreciation)
Acquisition and integration costs
53,930
55,989
—
—
13,581
21,899
—
—
—
64,108
10,692
29,817
—
—
—
3,515
—
41,288
277,427
90,036
85,806
41,288
614
614
Operating income (loss)
$ (331,826)
$ 35,044
$ 24,211
$ (45,427)
$ (317,998)
YEAR ENDED DECEMBER 31, 2019
REFINING
LOGISTICS (1)
RETAIL
CORPORATE,
ELIMINATIONS
AND OTHER (2)
TOTAL
Revenues
$ 5,167,942
$ 199,226
$ 458,889
$ (424,541)
$ 5,401,516
Cost of revenues (excluding depreciation)
4,783,747
112,124
332,302
(424,584)
4,803,589
Operating expense (excluding depreciation)
234,582
Depreciation, depletion, and amortization
55,832
General and administrative expense
(excluding depreciation)
Acquisition and integration costs
—
—
11,010
17,017
—
—
67,307
10,035
—
—
—
312,899
3,237
46,223
86,121
46,223
4,704
4,704
Operating income (loss)
$ 93,781
$ 59,075
$ 49,245
$ (54,121)
$ 147,980
(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 $402.2 million, $306.5 million, and $424.5 million for the years
ended December 31, 2021, 2020, and 2019, respectively.
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Below is a summary of key operating statistics for the refining segment for the years ended December 31, 2021, 2020, and 2019:
Total Refining Segment
Feedstocks Throughput (Mbpd) (1)
Refined product sales volume (Mbpd) (1)
Hawaii Refineries
Combined Feedstocks Throughput (Mbpd)
Par East Throughput (Mbpd)
Par West Throughput (Mbpd)
Yield (% of total throughput)
Gasoline and gasoline blendstocks
Distillates
Fuel oils
Other products
Total yield
Refined product sales volume (Mbpd)
On-island sales volume
Exports sales volume
Total refined product sales volume
Adjusted Gross Margin per bbl ($/throughput bbl) (2)
Production costs per bbl ($/throughput bbl) (3)
DD&A per bbl ($/throughput bbl)
Washington Refinery
Feedstocks Throughput (Mbpd) (1)
Yield (% of total throughput)
Gasoline and gasoline blendstocks
Distillates
Asphalt
Other products
Total yield
Refined product sales volume (Mbpd) (1)
Adjusted Gross Margin per bbl ($/throughput bbl) (2)
Production costs per bbl ($/throughput bbl) (3)
DD&A per bbl ($/throughput bbl)
YEAR ENDED DECEMBER 31,
2021
2020
2019
135.2
138.8
82.0
82.0
—
24.8%
45.0%
26.6%
0.6%
97.0%
82.6
—
82.6
$3.24
3.98
0.66
124.1
136.7
72.7
66.5
6.2
24.6%
42.2%
29.5%
(0.7)%
95.6%
83.5
0.6
84.1
$(1.63)
4.03
0.55
163.8
176.8
109.0
71.5
37.5
23.0%
44.4%
20.3%
8.7%
96.4%
114.1
5.7
119.8
$3.30
3.25
0.40
36.3
39.1
38.9
23.7%
34.5%
20.7%
18.3%
97.2%
39.6
$1.96
3.86
1.57
23.4%
35.3%
18.8%
19.8%
97.3%
39.6
$3.88
3.50
1.39
23.6%
35.6%
18.9%
19.4%
97.5%
41.1
$11.26
4.52
1.56
34
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Wyoming Refinery
Feedstocks Throughput (Mbpd)
Yield (% of total throughput)
Gasoline and gasoline blendstocks
Distillates
Fuel oil
Other products
Total yield
Refined product sales volume (Mbpd)
Adjusted Gross Margin per bbl ($/throughput bbl) (2)
Production costs per bbl ($/throughput bbl) (3)
DD&A per bbl ($/throughput bbl)
Market Indices (average $ per barrel)
3-1-2 Singapore Crack Spread (4)
Pacific Northwest 5-2-2-1 Index (5)
Wyoming 3-2-1 Index (6)
Crude Oil Prices (average $ per barrel)
Brent
WTI
ANS
Bakken Clearbrook
WCS Hardisty
Brent M1-M3
YEAR ENDED DECEMBER 31,
2021
2020
2019
16.9
12.3
17.0
47.3%
45.7%
2.2%
1.7%
96.9%
16.6
$12.66
6.22
2.86
$6.22
15.95
29.00
49.2%
45.2%
1.9%
1.3%
97.6%
13.0
$3.94
8.69
4.34
$3.15
11.44
17.80
49.6%
44.5%
1.7%
1.6%
97.4%
17.0
$18.82
6.32
2.93
$10.80
15.02
24.90
$70.95
$43.21
$64.19
68.11
71.49
68.20
54.61
1.12
39.65
41.77
37.19
27.45
(0.98)
57.08
65.72
56.04
43.18
1.00
(1) Feedstocks throughput and sales volumes per day for the Washington refinery for the year ended December 31, 2019 are calculated based on the 355-day period for
which we owned the Washington refinery in 2019. The amounts for the total refining segment represent the sum of the Hawaii, Washington, and Wyoming refiner-
ies’ throughput or sales volumes averaged over the years ended December 31, 2021, 2020, and 2019.
(2) We calculate Adjusted Gross Margin per barrel by dividing Adjusted Gross Margin by total refining throughput. Adjusted Gross Margin for our Washington refinery
is determined under the last-in, first-out (“LIFO”) inventory costing method. Adjusted Gross Margin for our other refineries is determined under the first-in, first-out
(“FIFO”) inventory costing method. Please see discussion of Adjusted Gross Margin below.
(3) Management uses production costs per barrel to evaluate performance and compare efficiency to other companies in the industry. There are a variety of ways to
calculate production costs per barrel; different companies within the industry calculate it in different ways. We calculate production costs per barrel by dividing
all direct production costs, which include the costs to run the refineries including personnel costs, repair and maintenance costs, insurance, utilities, and other
miscellaneous costs, by total refining throughput. Our production costs are included in Operating expense (excluding depreciation) on our consolidated statement
of operations, which also includes costs related to our bulk marketing operations.
(4) In 2020, following the implementation of IMO 2020, we established the 3-1-2 Singapore Crack Spread (or three barrels of Brent crude oil converted into one barrel of
gasoline and two barrels of distillates (diesel and jet fuel)) as a new benchmark for our Hawaii operations. By removing the high sulfur fuel oil reference in the index,
we believe the 3-1-2 Singapore Crack Spread is the most representative market indicator for our operations in Hawaii.
(5) We believe the Pacific Northwest 5-2-2-1 Index is the most representative market indicator for our operations in Tacoma, Washington. The Pacific Northwest 5-2-2-1
Index is computed by taking two parts gasoline (sub-octane), two parts middle distillates (ultra-low sulfur diesel (“ULSD”) and jet fuel), and one part fuel oil as cre-
ated from five barrels of Alaskan North Slope (“ANS”) crude oil. The 2019 prices for the year ended December 31, 2019 represent the price averaged over the period
from January 11, 2019 to December 31, 2019.
(6) The profitability of our Wyoming refinery is heavily influenced by crack spreads in nearby markets. We believe the Wyoming 3-2-1 Index is the most representative
market indicator for our operations in Wyoming. The Wyoming 3-2-1 Index is computed by taking two parts gasoline and one part distillates (ULSD) as created from
three barrels of West Texas Intermediate Crude Oil (“WTI”). Pricing is based 50% on applicable product pricing in Rapid City, South Dakota, and 50% on applicable
product pricing in Denver, Colorado.
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Below is a summary of key operating statistics for the retail segment for the years ended December 31, 2021, 2020, and 2019:
Retail Segment
Retail sales volumes (thousands of gallons)
109,150
102,798
125,313
YEAR ENDED DECEMBER 31,
2021
2020
2019
NON-GA AP PERFORMANCE MEASURES
Management uses certain financial measures to evaluate our operating performance that are considered non-GAAP financial
measures. These measures should not be considered a substitute for, or superior to, measures of financial performance
prepared in accordance with GAAP and our calculations thereof may not be comparable to similarly titled measures reported
by other companies.
Adjusted Gross Margin. Adjusted Gross Margin is defined as (i) operating income (loss) adjusted for operating expense
(excluding depreciation); depreciation, depletion, and amortization (“DD&A”); impairment expense; loss (gain) on sale of
assets, net; inventory valuation adjustment (which adjusts for timing differences to reflect the economics of our inventory
financing agreements, including lower of cost or net realizable value adjustments, the impact of the embedded derivative
repurchase or terminal obligations, contango (gains) and backwardation losses associated with our Washington inventory
and intermediation obligation, and purchase price allocation adjustments); LIFO layer liquidation impacts associated with our
Washington inventory; Renewable Identification Numbers (“RINs”) loss (gain) in excess of net obligation (which represents
the income statement effect of reflecting our RINs liability on a net basis); and unrealized loss (gain) on derivatives or (ii)
revenues less cost of revenues (excluding depreciation) plus inventory valuation adjustment, unrealized loss (gain) on
derivatives, LIFO layer liquidation impacts associated with our Washington inventory, and RINs loss (gain) in excess of net
obligation. We define cost of revenues (excluding depreciation) as the hydrocarbon-related costs of inventory sold, transportation
costs of delivering product to customers, crude oil consumed in the refining process, costs to satisfy our RINs and environmental
credit obligations, and certain hydrocarbon fees and taxes. Cost of revenues (excluding depreciation) also includes the unrealized
gain (loss) on derivatives and the inventory valuation adjustment that we exclude from Adjusted Gross Margin. Beginning in 2020,
Adjusted Gross Margin also includes the contango gains and backwardation losses associated with our Washington inventory and
intermediation obligation. Prior to 2020, contango gains, and backwardation (losses) captured by our Washington intermediation
agreement were excluded from Adjusted Gross Margin (as part of the inventory valuation adjustment). This change to our
non-GAAP information was made to reflect the favorable or unfavorable impact of the market structure on the profitability of
our Washington refinery consistent with the presentation of such impacts on our other refineries. Also beginning in 2020,
Adjusted Gross Margin excludes the LIFO layer liquidation impacts associated with our Washington inventory. We have recast
the non-GAAP information for the year ended December 31, 2019 to conform to the current period presentation.
Management believes Adjusted Gross Margin is an important measure of operating performance and uses Adjusted Gross
Margin per barrel to evaluate operating performance and compare profitability to other companies in the industry and to
industry benchmarks. Management believes Adjusted Gross Margin provides useful information to investors because it
eliminates the gross impact of volatile commodity prices and adjusts for certain non-cash items and timing differences
created by our inventory financing agreements and lower of cost and net realizable value adjustments to demonstrate the
earnings potential of the business before other fixed and variable costs, which are reported separately in Operating expense
(excluding depreciation) and Depreciation, depletion, and amortization.
Adjusted Gross Margin should not be considered an alternative to operating income (loss), cash flows from operating
activities, or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted Gross
Margin presented by other companies may not be comparable to our presentation since each company may define this term
differently as they may include other manufacturing costs and depreciation expense in cost of revenues.
The following tables present a reconciliation of Adjusted Gross Margin to the most directly comparable GAAP financial
measure, operating income (loss), on a historical basis, for selected segments, for the periods indicated (in thousands):
36
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The following tables present a reconciliation of Adjusted Gross Margin to the most directly comparable GAAP financial
measure, operating income (loss), on a historical basis, for selected segments, for the periods indicated (in thousands):
YEAR ENDED DECEMBER 31, 2021
REFINING
LOGISTICS
RETAIL
Operating income (loss)
Operating expense (excluding depreciation)
Depreciation, depletion, and amortization
Impairment expense
Loss (gain) on sale of assets, net
Inventory valuation adjustment
RINs loss in excess of net obligation
Unrealized loss on derivatives
Adjusted Gross Margin (1)
$(88,799)
213,102
58,258
1,838
(19,659)
17,089
16,967
1,517
$51,159
14,722
22,044
—
(19)
—
—
—
$81,249
71,845
10,880
—
(45,034)
—
—
—
$200,313
$87,906
$118,940
YEAR ENDED DECEMBER 31, 2020
REFINING
LOGISTICS
RETAIL
Operating income (loss)
$(331,826)
$35,044
$24,211
Operating expense (excluding depreciation)
Depreciation, depletion, and amortization
Impairment expense
Inventory valuation adjustment
RINs loss in excess of net obligation
Unrealized loss on derivatives
Adjusted Gross Margin (1)
199,738
53,930
55,989
14,046
44,071
(4,804)
13,581
21,899
—
—
—
—
64,108
10,692
29,817
—
—
—
$31,144
$70,524
$128,828
YEAR ENDED DECEMBER 31, 2019
REFINING
LOGISTICS
RETAIL
Operating income (loss)
Operating expense (excluding depreciation)
Depreciation, depletion, and amortization
Inventory valuation adjustment
RINs loss in excess of net obligation
Unrealized loss on derivatives
Adjusted Gross Margin (1)
$93,781
234,582
55,832
11,938
(3,398)
8,988
$59,075
11,010
17,017
—
—
—
$49,245
67,307
10,035
—
—
—
$401,723
$87,102
$126,587
(1) For the years ended December 31, 2021, 2020 and 2019, there was no LIFO liquidation adjustment. For the years ended December 31, 2020 and 2019, there was no
loss (gain) on sale of assets. For the year ended December 31, 2019, there was no impairment expense.
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Adjusted Net Income (Loss) and Adjusted EBITDA. Adjusted Net Income (Loss) is defined as Net income (loss) excluding inventory
valuation adjustment (which adjusts for timing differences to reflect the economics of our inventory financing agreements,
including lower of cost or net realizable value adjustments, the impact of the embedded derivative repurchase or terminal
obligations, contango (gains) and backwardation losses associated with our Washington inventory and intermediation obligation,
and purchase price allocation adjustments), the LIFO layer liquidation impacts associated with our Washington inventory, RINs loss
(gain) in excess of net obligation, unrealized (gain) loss on derivatives, acquisition and integration costs, debt extinguishment and
commitment costs, increase in (release of) tax valuation allowance and other deferred tax items, changes in the value of contingent
consideration and common stock warrants, severance costs, (gain) loss on sale of assets, impairment expense, impairment expense
associated with our investment in Laramie Energy and our share of Laramie Energy’s asset impairment losses in excess of our basis
difference, and Par’s share of Laramie Energy’s unrealized loss (gain) on derivatives. Beginning in 2020, Adjusted Net Income (Loss)
also includes the contango gains and backwardation losses associated with our Washington inventory and intermediation
obligation. Prior to 2020, contango gains, and backwardation (losses) captured by our Washington intermediation agreement
were excluded from Adjusted Net Income (Loss) (as part of the inventory valuation adjustment). This change to our non-
GAAP information was made to reflect the favorable or unfavorable impact of the market structure on the profitability of our
Washington refinery consistent with the presentation of such impacts on our other refineries. Also beginning in 2020,
Adjusted Net Income (Loss) excludes the LIFO layer liquidation impacts associated with our Washington inventory. We have
recast the non-GAAP information for the year ended December 31, 2019 to conform to the current period presentation.
Adjusted EBITDA is Adjusted Net Income (Loss) excluding DD&A, interest expense and financing costs, equity losses (earnings)
from Laramie Energy excluding Par’s share of unrealized loss (gain) on derivatives, impairment of Par’s investment, and our
share of Laramie Energy’s asset impairment losses in excess of our basis difference, and income tax expense (benefit).
We believe Adjusted Net Income (Loss) and Adjusted EBITDA are useful supplemental financial measures that allow investors
to assess:
• The financial performance of our assets without regard to financing methods, capital structure, or historical cost basis;
• The ability of our assets to generate cash to pay interest on our indebtedness; and
• Our operating performance and return on invested capital as compared to other companies without regard to financing
methods and capital structure.
Adjusted Net Income (Loss) and Adjusted EBITDA should not be considered in isolation or as a substitute for operating
income (loss), net income (loss), cash flows provided by operating, investing, and financing activities, or other income or cash
flow statement data prepared in accordance with GAAP. Adjusted Net Income (Loss) and Adjusted EBITDA presented by other
companies may not be comparable to our presentation as other companies may define these terms differently.
38
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The following table presents a reconciliation of Adjusted Net Income (Loss) and Adjusted EBITDA to the most directly
comparable GAAP financial measure, net income (loss), on a historical basis for the periods indicated (in thousands):
Net income (loss)
Inventory valuation adjustment
RINs loss (gain) in excess of net obligation
Unrealized loss (gain) on derivatives
Acquisition and integration costs
Debt extinguishment and commitment costs
Changes in valuation allowance and other deferred tax items (1)
Change in value of common stock warrants
Severance costs
Impairment expense
Impairment of Investment in Laramie Energy, LLC (2)
Par’s share of Laramie Energy’s unrealized loss (gain) on derivatives (2)
Gain on sale of assets
Adjusted Net Income (Loss) (3)
Depreciation, depletion, and amortization
Interest expense and financing costs, net
Equity losses (earnings) from Laramie Energy, LLC, excluding Par’s
share of unrealized loss (gain) on derivatives and impairment losses
YEAR ENDED DECEMBER 31,
2021
2020
2019
$(81,297)
$(409,086)
$40,809
17,089
16,967
1,517
87
8,144
—
—
84
1,838
—
—
(64,697)
14,046
44,071
(4,804)
614
—
11,938
(3,398)
8,988
4,704
11,587
(20,896)
(68,792)
(4,270)
3,199
512
85,806
45,294
(1,110)
—
—
—
83,152
(1,969)
—
90,218
86,121
74,839
8,568
(100,268)
(249,823)
94,241
66,493
—
90,036
70,222
2,721
Income tax expense (benefit)
Adjusted EBITDA
1,021
176
(897)
$61,487
$(86,668)
$258,849
(1) Includes releases of our valuation allowance associated with business combinations and changes in deferred tax assets and liabilities that are not offset by a change
in the valuation allowance. These tax benefits are included in Income tax expense (benefit) on our consolidated statements of operations.
(2) Includes our share of Laramie Energy’s unrealized loss (gain) on derivatives, impairment losses on our investment in Laramie Energy, and our share of Laramie
Energy’s asset impairment losses in excess of our basis difference. These impairment losses and our share of Laramie Energy’s unrealized loss (gain) on derivatives
are included in Equity earnings (losses) from Laramie Energy, LLC on our consolidated statements of operations.
(3) For the years ended December 31, 2021, 2020, and 2019, there was no LIFO liquidation adjustment or change in value of contingent consideration.
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DI S CUS S I ON OF OPER AT ING INCO ME (LOS S) BY S EGMEN T
YEAR ENDED DECEMBER 31, 2021 COMPARED TO YEAR ENDED DECEMBER 31, 2020
Refining. Operating loss for our refining segment was $88.8 million for the year ended December 31, 2021, an improvement of
$243.0 million compared to operating loss of $331.8 million for the year ended December 31, 2020. The increase in profitability
was primarily driven by favorable realized product crack spreads across all our refineries, favorable purchased product and
feedstock costs at our Hawaii refinery, favorable derivative costs, and a 28% increase in refining sales volume at our Wyoming
refinery, partially offset by higher inventory financing costs related to the rising cost of crude oil. Other factors impacting our
results period over period include asset impairment charges of $1.8 million in 2021 from discontinued capital projects as
compared to our 2020 goodwill impairment of $38.1 million and asset impairment charges of $17.9 million, and a 2021 gain on
sale of assets of $19.7 million primarily related to the Sale-Leaseback Transactions we closed in the first quarter of 2021.
Logistics. Operating income for our logistics segment was $51.2 million for the year ended December 31, 2021, an increase of
$16.2 million compared to operating income of $35.0 million for the year ended December 31, 2020. The increase is primarily
due to net 12% and 32% higher throughput across our Hawaii and Wyoming logistics assets, respectively, related to increased
demand as a result of reduced COVID-19-related travel restrictions and lower lease costs on barges in Hawaii.
Retail. Operating income for our retail segment was $81.2 million for the year ended December 31, 2021, an increase of $57.0
million compared to operating income of $24.2 million for the year ended December 31, 2020. The increase in profitability was
primarily due to a gain on sale of assets of $45.0 million primarily related to the Sale-Leaseback Transactions we closed in the
first quarter of 2021, a 2020 goodwill impairment of $29.8 million with no corresponding impairment in 2021, and an increase in
sales volumes of 6%, partially offset by a decrease in fuel margins of 17% related to rising fuel costs and market-driven margin
compression and additional rent expense related to the Sale-Leaseback Transactions that we closed in the first quarter of 2021.
YEAR ENDED DECEMBER 31, 2020 COMPARED TO YEAR ENDED DECEMBER 31, 2019
Refining. Operating loss for our refining segment was $331.8 million for the year ended December 31, 2020, a decrease of $425.6
million compared to operating income of $93.8 million for the year ended December 31, 2019. The decrease in profitability was
primarily driven by lower refining sales volumes at our Hawaii and Wyoming refineries related to COVID-19 demand destruction
and turnarounds in both locations, unfavorable crude oil differentials and crack spreads, increased RINs expenses and derivative
costs, goodwill impairment charges of $38.1 million, asset impairment charges of $17.9 million, and unfavorable lower of cost and
net realizable value adjustments of $10.6 million, partially offset by improved energy-related cost of sales and operating expense
reductions across our refineries in response to COVID-19.
Logistics. Operating income for our logistics segment was $35.0 million for the year ended December 31, 2020, a decrease of
$24.1 million compared to operating income of $59.1 million for the year ended December 31, 2019. The decrease is primarily
due to a net 30% and 25% lower throughput across our Hawaii and Wyoming logistics assets, respectively, and lower neighbor
island sales in Hawaii related to COVID-19 demand destruction, major turnarounds in both locations, and higher DD&A, partially
offset by a net 9% increase in throughput across our Washington logistics assets.
Retail. Operating income for our retail segment was $24.2 million for the year ended December 31, 2020, a decrease of $25.0
million compared to operating income of $49.2 million for the year ended December 31, 2019. The decrease in profitability was
primarily due to goodwill impairment charges of $29.8 million and an 18% decline in sales volumes, partially offset by an increase in
fuel margins of 25% and operating expense reductions in response to the economic impacts of COVID-19 on our businesses.
DI S CUS S I ON OF ADJUS T ED GROS S MARGIN BY S EGMEN T
YEAR ENDED DECEMBER 31, 2021 COMPARED TO YEAR ENDED DECEMBER 31, 2020
Refining. For the year ended December 31, 2021, our refining Adjusted Gross Margin was approximately $200.3 million, an
increase of $169.2 million compared to $31.1 million for the year ended December 31, 2020. The increase in profitability was
primarily driven by favorable realized product crack spreads across all our refineries and favorable feedstock and purchased
product costs in Hawaii, partially offset by unfavorable feedstock and inventory financing costs in Washington. Adjusted
gross margin for the Hawaii refinery improved from $(1.63) per barrel in 2020 to $3.24 per barrel in 2021 primarily due to
favorable product crack spreads and feedstock, purchased product, and derivative costs. Adjusted gross margin for the
Wyoming refinery increased by $8.72 per barrel primarily due to favorable product crack spreads and a 28% increase in sales
volumes. Adjusted gross margin for the Washington refinery decreased by $1.92 per barrel primarily due to higher inventory
financing and feedstock costs, partially offset by favorable realized product crack spreads and lower logistics costs.
Logistics. For the year ended December 31, 2021, our logistics Adjusted Gross Margin was approximately $87.9 million, an
increase of $17.4 million compared to $70.5 million for the year ended December 31, 2020. The increase was primarily driven by
net 12% and 32% higher throughput across our Hawaii and Wyoming logistics assets, respectively, due to increased sales
volumes in both regions driven by reduced COVID-19-related travel restrictions, and lower lease costs on barges in Hawaii.
Retail. For the year ended December 31, 2021, our retail Adjusted Gross Margin was approximately $118.9 million, a decrease of
$9.9 million compared to $128.8 million for the year ended December 31, 2020. The decrease was primarily due to a 17% decrease
in fuel margins due to rising fuel costs and market-driven margin compression, partially offset by a 6% increase in sales volumes.
40
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YEAR ENDED DECEMBER 31, 2020 COMPARED TO YEAR ENDED DECEMBER 31, 2019
Refining. For the year ended December 31, 2020, our refining Adjusted Gross Margin was approximately $31.1 million, a
decrease of $370.6 million compared to $401.7 million for the year ended December 31, 2019. The decrease in profitability
was primarily driven by a 23% decline in sales volumes and declines in crack spreads. Adjusted gross margin for the Hawaii
refinery decreased from $3.30 per barrel in 2019 to $(1.63) per barrel in 2020 primarily due to 30% lower sales volumes, an
increase in RINs expenses, and unfavorable crude oil differentials. Adjusted gross margin for the Wyoming refinery decreased
$14.88 per barrel primarily due to a 24% decline in sales volumes, an increase in RINs expenses, and a decrease in crack
spreads. The decline in refining sales volumes in Hawaii and Wyoming was driven by COVID-19 demand destruction and
turnarounds in both locations. Adjusted gross margin for the Washington refinery decreased $7.38 per barrel primarily due to
unfavorable crack spreads and higher RINs expenses, partially offset by favorable derivative costs.
Logistics. For the year ended December 31, 2020, our logistics Adjusted Gross Margin was approximately $70.5 million, a
decrease of $16.6 million compared to $87.1 million for the year ended December 31, 2019. The decrease was primarily
driven by a net 30% and 25% lower throughput across our Hawaii and Wyoming logistics assets, respectively, and lower
neighbor island sales in Hawaii related to COVID-19 demand destruction and major turnarounds at both locations, partially
offset by a net 9% increase in throughput across our Washington logistics assets.
Retail. For the year ended December 31, 2020, our retail Adjusted Gross Margin was approximately $128.8 million, an
increase of $2.2 million compared to $126.6 million for the year ended December 31, 2019. The increase was primarily due to
a 25% increase in fuel margins, partially offset by a decline in sales volumes of 18% due to COVID-19 demand destruction.
DI S CUS S I O N OF CON S OL IDAT ED RE SULT S
YEAR ENDED DECEMBER 31, 2021 COMPARED TO YEAR ENDED DECEMBER 31, 2020
Revenues. For the year ended December 31, 2021, revenues were $4.7 billion, a $1.6 billion increase compared to $3.1 billion
for the year ended December 31, 2020. The increase was primarily the result of an increase of $1.5 billion in third-party
revenues at our refining segment primarily as a result of increases in Brent and WTI crude oil prices. Brent crude oil prices
recovered from COVID-19-related lows, averaging $70.95 per barrel for the year ended December 31, 2021 compared to
$43.21 per barrel for the year ended December 31, 2020, and WTI crude oil prices averaged $68.11 per barrel during the year
ended December 31, 2021 compared to $39.65 in the year ended December 31, 2020. Other factors contributing to the
increase in revenues at our refining segment include a 28% increase in refining sales volume at our Wyoming refinery and
improved realized product crack spreads across all our refineries. Revenues in our retail segment increased $92.7 million
primarily due to a 23% increase in fuel prices and a 6% increase in sales volume.
Cost of Revenues (Excluding Depreciation). For the year ended December 31, 2021, cost of revenues (excluding depreciation)
was $4.3 billion, a $1.4 billion increase compared to $2.9 billion for the year ended December 31, 2020. The increase was
primarily due to increases in Brent and WTI crude oil prices and refining sales volumes at our Wyoming refinery as discussed
above, higher inventory financing costs, and 6% higher sales volumes at our Retail segment, partially offset by favorable
purchased product and feedstock costs at our Hawaii refinery and favorable derivative costs.
Operating Expense (Excluding Depreciation). For the year ended December 31, 2021, operating expense (excluding depreciation)
was approximately $299.7 million, an increase of $22.3 million compared to $277.4 million for the year ended December 31, 2020.
The increase was primarily due to higher utilities and maintenance expenses at our Hawaii refinery and increased rent expenses
driven by new leases from the Sale-Leaseback Transactions we completed in the first quarter of 2021.
Depreciation, Depletion, and Amortization. For the year ended December 31, 2021, DD&A expense was approximately $94.2
million, an increase of $4.2 million compared to $90.0 million for the year ended December 31, 2020. The increase was
primarily due to amortization of our Hawaii refinery turnaround completed in 2020.
Impairment Expense. During the year ended December 31, 2021, we recorded asset impairment charges of $1.8 million
primarily related to discontinued capital projects. During the year ended December 31, 2020, we recorded goodwill and asset
impairment charges totaling $85.8 million related to our Refining and Retail segments. Please read Note 10—Goodwill and
Intangible Assets and Note 8—Property, Plant, and Equipment and Impairment of Long-Lived Assets to our consolidated
financial statements under Item 8 of this Form 10-K for further discussion on our 2020 goodwill impairment and our 2021 and
2020 asset impairment charges, respectively.
Gain on Sale of Assets, Net. For the year ended December 31, 2021, the gain on sale of assets, net was approximately $64.7
million and primarily related to the gain recognized as a result of the Sale-Leaseback Transactions we closed on February 23 and
March 12, 2021. Please read Note 16—Leases to our consolidated financial statements under Item 8 of this Form 10-K for
further discussion on the Sale-Leaseback Transactions. No such transaction occurred during the year ended December 31, 2020.
General and Administrative Expense (Excluding Depreciation). For the year ended December 31, 2021, general and administrative
expense (excluding depreciation) was approximately $48.1 million, an increase of $6.8 million compared to $41.3 million for the
year ended December 31, 2020. The increase was primarily due to higher employee costs, an increase in the use of outside services,
and higher information technology infrastructure costs.
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Interest Expense and Financing Costs, Net. For the year ended December 31, 2021, our interest expense and financing costs were
approximately $66.5 million, a decrease of $3.7 million compared to $70.2 million for the year ended December 31, 2020. The
decrease was primarily due to lower outstanding debt balances driven by the maturity of our outstanding 5.00% Convertible Senior
Notes in June 2021, the repayment of the PHL, Mid Pac, and Retail Property Term Loans and interest rate swap related to the Retail
Property Term Loan in the first quarter of 2021, and quarterly principal payments on our Term Loan B Facility. These decreases
were partially offset by higher interest expense related to the 12.875% Senior Secured Notes issued in June 2020 and an increase of
$1.1 million related to increased borrowings under our inventory financing agreements. Please read Note 11—Inventory Financing
Agreements and Note 13—Debt to our consolidated financial statements under Item 8 of this Form 10-K for further discussion on
our inventory financing and indebtedness, respectively.
Change in Value of Common Stock Warrants. For the year ended December 31, 2020, the change in value of common stock
warrants resulted in a gain of $4.3 million. During January and March 2020, one of our stockholders and its affiliates exercised the
remaining 354,350 common stock warrants in exchange for 350,542 shares of common stock. We estimated the fair value of our
outstanding common stock warrants and the income recognized upon exercise using the difference between the strike price of the
warrant and the market price of our common stock. During the three months ended March 31, 2020, our stock price decreased
from $23.24 per share on December 31, 2019 to $7.10 per share on March 31, 2020. During the year ended December 31, 2021,
there were no common stock warrants outstanding.
Debt extinguishment and commitment costs. For the year ended December 31, 2021, our debt extinguishment and commitment
costs were approximately $8.1 million and primarily represent $6.6 million in extinguishment costs associated with the early
repayment of a portion of the outstanding 12.875% Senior Secured Notes on June 14, 2021 and $1.4 million in extinguishment costs
associated with the early repayment of the Retail Property Term Loan on February 23, 2021. Please read Note 13—Debt to our
consolidated financial statements under Item 8 of this Form 10-K for further discussion. There were no debt extinguishment and
commitment costs for the year ended December 31, 2020.
Gain on curtailment of pension obligation. During the year ended December 31, 2021, we recorded a gain on curtailment of
pension obligation of $2.0 million related to the amendment to the Wyoming Refining defined benefit plan. Please read Note
19—Benefit Plans to our consolidated financial statements under Item 8 of this Form 10-K for further discussion on the gain on
curtailment of pension obligation. There was no gain on curtailment of pension obligation for the year ended December 31, 2020.
Equity Earnings (Losses) from Laramie Energy, LLC. For the year ended December 31, 2020, equity losses from Laramie
Energy were approximately $46.9 million. During the year ended December 31, 2020, we recorded an other-than-temporary
impairment charge of $45.3 million related to our investment in Laramie Energy. As of June 30, 2020, we discontinued the
application of the equity method of accounting for our investment in Laramie Energy because the book value of such
investment has been reduced to zero. As such, there were no earnings or losses from Laramie Energy recorded during the
year ended December 31, 2021. Please read Note 3—Investment in Laramie Energy, LLC to our consolidated financial
statements under Item 8 of this Form 10-K for more information.
Income Taxes. For the year ended December 31, 2021, we recorded an income tax expense of $1.0 million primarily driven by
foreign withholding taxes. For the year ended December 31, 2020, we recorded an income tax benefit of $20.7 million primarily
driven by an increase in our net operating loss carryforwards that do not expire and the change in our indefinitely-lived goodwill
due to the impairments.
YEAR ENDED DECEMBER 31, 2020 COMPARED TO YEAR ENDED DECEMBER 31, 2019
Revenues. For the year ended December 31, 2020, revenues were $3.1 billion, a $2.3 billion decrease compared to $5.4 billion
for the year ended December 31, 2019. The decrease was primarily the result of a decrease of $2.2 billion in third-party
revenues at our refining segment primarily as a result of decreases in Brent and WTI crude oil prices and lower sales volumes
related to COVID-19 demand destruction. Refined product sales volumes decreased 23% from 176.8 Mbpd in the year ended
December 31, 2019 to 136.7 Mbpd in the year ended December 31, 2020. Brent crude oil prices averaged $43.21 per barrel for
the year ended December 31, 2020 compared to $64.19 per barrel for the year ended December 31, 2019, with similar decreases
experienced for WTI crude oil prices. Revenues in our retail segment decreased $95.2 million primarily due to 18% declines in
both sales volumes and fuel prices.
Cost of Revenues (Excluding Depreciation). For the year ended December 31, 2020, cost of revenues (excluding depreciation),
was $2.9 billion, a $1.9 billion decrease compared to $4.8 billion for the year ended December 31, 2019. The decrease was
primarily due to the decreases in Brent and WTI crude oil prices and lower refining sales volumes discussed above. These
decreases were partially offset by unfavorable crude oil differentials, higher RINs expenses, increased derivative costs, and an
unfavorable lower of cost and net realizable value adjustment of $10.6 million. Cost of revenues at our retail segment decreased
$97.4 million primarily due to lower fuel costs and an 18% decline in sales volumes.
Operating Expense (Excluding Depreciation). For the year ended December 31, 2020, operating expense (excluding depreciation)
was approximately $277.4 million, a decrease of $35.5 million compared to $312.9 million for the year ended December 31, 2019.
The decrease was primarily due to lower utilities and repairs and maintenance expenses and COVID-19- related reductions in travel,
employee costs, and the use of outside services.
42
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Depreciation, Depletion, and Amortization. For the year ended December 31, 2020, DD&A expense was approximately $90.0
million, an increase of $3.9 million compared to $86.1 million for the year ended December 31, 2019. The increase was primarily
due to recently completed capital projects, including three turnarounds during 2019 and 2020 and our Washington renewables
logistics project.
Impairment Expense. During the year ended December 31, 2020, we recorded goodwill and asset impairment charges totaling
$85.8 million related to our Refining and Retail segments. Please read Note 10—Goodwill and Intangible Assets and Note 8—
Property, Plant, and Equipment and Impairment of Long-Lived Assets to our consolidated financial statements under Item 8 of
this Form 10-K for further discussion on the goodwill impairment of $67.9 million and asset impairment of $17.9 million,
respectively. There was no impairment expense for the year ended December 31, 2019.
General and Administrative Expense (Excluding Depreciation). For the year ended December 31, 2020, general and administrative
expense (excluding depreciation) was approximately $41.3 million, a decrease of $4.9 million compared to $46.2 million for the year
ended December 31, 2019. The decrease was primarily due to COVID-19-related reductions in travel and employee costs and a
reduction in the use of outside services.
Acquisition and Integration Costs. For the year ended December 31, 2020, we incurred approximately $0.6 million of
expenses primarily related to integration costs for the Washington Acquisition. For the year ended December 31, 2019, we
incurred approximately $4.7 million of expenses primarily related to acquisition and integration costs for the Washington and
Par West Acquisitions. Please read Note 4—Acquisitions to our consolidated financial statements under Item 8 of this Form
10-K for more information.
Interest Expense and Financing Costs, Net. For the year ended December 31, 2020, our interest expense and financing costs were
approximately $70.2 million, a decrease of $4.6 million compared to $74.8 million for the year ended December 31, 2019. The
decrease was primarily due to a $4.0 million decrease in due to the exchange of a portion of our outstanding 5.00% Convertible
Senior Notes during 2019, a decrease of $4.7 million due to reduced borrowings under our inventory financing agreements, and a
decrease of $4.3 million due to the reduced principal and lower variable interest rates on our Term Loan B Facility. These decreases
were partially offset by interest expense of $8.1 million related to the 12.875% Senior Secured Notes issued in June 2020. Please
read Note 11—Inventory Financing Agreements and Note 13—Debt to our consolidated financial statements under Item 8 of this
Form 10-K for further discussion on our inventory financing and indebtedness, respectively.
Change in Value of Common Stock Warrants. For the year ended December 31, 2020, the change in value of common stock
warrants resulted in a gain of approximately $4.3 million, a change of $7.5 million compared to a loss of $3.2 million for the
year ended December 31, 2019. During January and March 2020, one of our stockholders and its affiliates exercised the
remaining 354,350 common stock warrants in exchange for 350,542 shares of common stock. We estimated the fair value of
our outstanding common stock warrants and the income recognized upon exercise using the difference between the strike
price of the warrant and the market price of our common stock. During the year ended December 31, 2019, our stock price
increased from $14.18 per share on December 31, 2018 to $23.24 per share on December 31, 2019, which resulted in an
increase in the value of the common stock warrants.
Debt extinguishment and commitment costs. For the year ended December 31, 2019, our debt extinguishment and commitment
costs were approximately $11.6 million and represent the commitment and other fees associated with the financing of the
Washington Acquisition and the extinguishment costs associated with the exchange of a portion of our outstanding 5.00%
Convertible Senior Notes. There were no debt extinguishment and commitment costs for the year ended December 31, 2020.
Equity Earnings (Losses) from Laramie Energy, LLC. For the year ended December 31, 2020, equity losses from Laramie Energy
were approximately $46.9 million, a difference of $42.9 million compared to equity losses of $89.8 million for the year ended
December 31, 2019. During the years ended December 31, 2020 and 2019, we recorded other-than-temporary impairment
charges of $45.3 million and $81.5 million related to our investment in Laramie Energy, respectively. As of June 30, 2020, we
have discontinued the application of the equity method of accounting for our investment in Laramie Energy because the book
value of such investment has been reduced to zero. Please read Note 3—Investment in Laramie Energy, LLC to our consolidated
financial statements under Item 8 of this Form 10-K for more information.
Income Taxes. For the year ended December 31, 2020, we recorded an income tax benefit of $20.7 million primarily driven by an
increase in our net operating loss carryforwards that do not expire and the change in our indefinitely-lived goodwill due to the
impairments. For the year ended December 31, 2019, we recorded an income tax benefit of $69.7 million primarily driven by a
$64.2 million benefit associated with a partial release of our valuation allowance in connection with the Washington Acquisition.
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CONDENSED CONSOLIDATING FINANCIAL INFORMATION
On December 21, 2017, Par Petroleum, LLC (the “Issuer”) issued its 7.75% Senior Secured Notes due 2025 in a private offering
under Rule 144A and Regulation S of the Securities Act. On January 11, 2019, the Issuers (defined below) entered into a term
loan and guaranty agreement with Goldman Sachs Bank USA, as administrative agent, and the lenders party thereto with
respect to a $250.0 million term loan (the “Term Loan B”). On June 5, 2020, the Issuers issued their 12.875% Senior Secured
Notes due 2026 in a private offering under Rule 144A and Regulation S of the Securities Act. The 7.75% Senior Secured Notes,
the Term Loan B, and the 12.875% Senior Secured Notes were co-issued by Par Petroleum Finance Corp. (together with the
Issuer, the “Issuers”), which has no independent assets or operations. The 7.75% Senior Secured Notes, Term Loan B, and
12.875% Senior Secured Notes are guaranteed on a senior unsecured basis only as to payment of principal and interest by Par
Pacific Holdings, Inc. (the “Parent”) and are guaranteed on a senior secured basis by all of the subsidiaries of Par Petroleum,
LLC (other than Par Petroleum Finance Corp.).
The following supplemental condensed consolidating financial information reflects (i) the Parent’s separate accounts, (ii) Par
Petroleum, LLC and its consolidated subsidiaries’ accounts (which are all guarantors of the 7.75% Senior Secured Notes, Term
Loan B, and 12.875% Senior Secured Notes), (iii) the accounts of subsidiaries of the Parent that are not guarantors of the
7.75% Senior Secured Notes, Term Loan B, or 12.875% Senior Secured Notes and consolidating adjustments and eliminations,
and (iv) the Parent’s consolidated accounts for the dates and periods indicated. For purposes of the following condensed
consolidating information, the Parent’s investment in its subsidiaries is accounted for under the equity method of accounting
(dollar amounts in thousands).
AS OF DECEMBER 31, 2021
PARENT
GUARANTOR
ISSUER AND
SUBSIDIARIES
NON-GUARANTOR
SUBSIDIARIES AND
ELIMINATIONS
PAR PACIFIC
HOLDINGS, INC.
AND SUBSIDIARIES
Current assets
Cash and cash equivalents
$4,086
$108,105
$30
$112,221
Restricted cash
Trade accounts receivable
Inventories
Prepaid and other current assets
Due from related parties
Total current assets
Property, plant, and equipment
Property, plant, and equipment
Less accumulated depreciation, depletion,
and amortization
330
—
—
15,664
94,676
3,670
195,104
790,317
12,864
—
114,756
1,110,060
19,535
(13,869)
1,156,906
(307,091)
—
4
—
(3)
(94,676)
(94,645)
3,956
(2,932)
4,000
195,108
790,317
28,525
—
1,130,171
1,180,397
(323,892)
Property, plant, and equipment, net
5,666
849,815
1,024
856,505
Long-term assets
Operating lease right-of-use (“ROU”) assets
Investment in subsidiaries
Intangible assets, net
Goodwill
Other long-term assets
Total assets
3,280
207,483
—
—
724
380,544
—
383,824
—
(207,483)
16,234
124,664
57,382
—
2,598
(1,851)
—
16,234
127,262
56,255
$331,909
$2,538,699
$(300,357)
$2,570,251
44
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AS OF DECEMBER 31, 2021
PARENT
GUARANTOR
ISSUER AND
SUBSIDIARIES
NON-GUARANTOR
SUBSIDIARIES AND
ELIMINATIONS
PAR PACIFIC
HOLDINGS, INC.
AND SUBSIDIARIES
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt
Obligations under inventory
financing agreements
Accounts payable
Accrued taxes
Operating lease liabilities
Other accrued liabilities
Due to related parties
Total current liabilities
Long-term liabilities
Long-term debt, net of current maturities
Finance lease liabilities
Operating lease liabilities
Other liabilities
Total liabilities
Commitments and contingencies
Stockholders’ equity
Preferred stock
Common stock
Additional paid-in capital
Accumulated earnings (deficit)
Accumulated other comprehensive income (loss)
Total stockholders’ equity
$—
—
1,386
48
608
9,805
50,195
62,042
—
17
4,150
—
$10,841
737,704
151,676
28,593
53,032
360,246
10,261
1,352,353
553,717
12,192
330,944
63,098
66,209
2,312,304
—
602
821,713
(559,117)
2,502
265,700
—
—
409,686
(185,096)
1,805
226,395
$—
—
1,481
—
—
373
(60,456)
(58,602)
—
(4,518)
—
(10,842)
(73,962)
—
—
(409,686)
185,096
(1,805)
(226,395)
$10,841
737,704
154,543
28,641
53,640
370,424
—
1,355,793
553,717
7,691
335,094
52,256
2,304,551
—
602
821,713
(559,117)
2,502
265,700
Total liabilities and stockholders’ equity
$331,909
$2,538,699
$(300,357)
$2,570,251
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Current assets
Cash and cash equivalents
Restricted cash
Trade accounts receivable
Inventories
Prepaid and other current assets
Due from related parties
Total current assets
Property, plant, and equipment
Property, plant, and equipment
Less accumulated depreciation, depletion,
and amortization
AS OF DECEMBER 31, 2020
PARENT
GUARANTOR
ISSUER AND
SUBSIDIARIES
NON-GUARANTOR
SUBSIDIARIES AND
ELIMINATIONS
PAR PACIFIC
HOLDINGS, INC.
AND SUBSIDIARIES
$ 480
330
—
—
16,983
107,995
125,788
21,477
(14,368)
$67,147
1,670
111,654
429,855
7,171
—
617,497
$682
—
3
—
494
(107,995)
(106,816)
$68,309
2,000
111,657
429,855
24,648
—
636,469
1,124,587
(233,927)
37,814
(2,818)
1,183,878
(251,113)
Property, plant, and equipment, net
7,109
890,660
34,996
932,765
Long-term assets
Operating lease right-of-use (“ROU”) assets
Investment in subsidiaries
Intangible assets, net
Goodwill
Other long-term assets
Total assets
3,714
209,010
—
—
723
367,850
—
18,892
125,399
59,849
(14,398)
(209,010)
—
2,598
—
357,166
—
18,892
127,997
60,572
$346,344
$2,080,147
$(292,630)
$2,133,861
46
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AS OF DECEMBER 31, 2020
PARENT
GUARANTOR
ISSUER AND
SUBSIDIARIES
NON-GUARANTOR
SUBSIDIARIES AND
ELIMINATIONS
PAR PACIFIC
HOLDINGS, INC.
AND SUBSIDIARIES
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt
Obligations under inventory
financing agreements
Accounts payable
Accrued taxes
Operating lease liabilities
Other accrued liabilities
Due to related parties
Total current liabilities
Long-term liabilities
Long-term debt, net of current maturities
Finance lease liabilities
Operating lease liabilities
Other liabilities
Total liabilities
Commitments and contingencies
Stockholders’ equity
Preferred stock
Common stock
Additional paid-in capital
Accumulated earnings (deficit)
Accumulated other comprehensive income (loss)
Total stockholders’ equity
$47,301
—
2,401
49
750
10,907
33,757
95,165
—
77
4,783
45
$11,048
423,686
103,067
27,371
60,449
194,114
36,124
855,859
608,353
7,848
309,736
87,382
100,070
1,869,178
—
540
726,504
(477,028)
(3,742)
246,274
—
—
307,967
(94,086)
(2,912)
210,969
$1,584
—
1,477
20
(4,234)
(1,310)
(69,881)
(72,344)
40,307
—
(10,164)
(39,460)
(81,661)
—
—
(307,967)
94,086
2,912
(210,969)
$59,933
423,686
106,945
27,440
56,965
203,711
—
878,680
648,660
7,925
304,355
47,967
1,887,587
—
540
726,504
(477,028)
(3,742)
246,274
Total liabilities and stockholders’ equity
$346,344
$2,080,147
$(292,630)
$2,133,861
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YEAR ENDED DECEMBER 31, 2021
PARENT
GUARANTOR
ISSUER AND
SUBSIDIARIES
NON-GUARANTOR
SUBSIDIARIES AND
ELIMINATIONS
PAR PACIFIC
HOLDINGS, INC.
AND SUBSIDIARIES
$—
$4,710,039
$50
$4,710,089
Revenues
Operating expenses
Cost of revenues (excluding depreciation)
Operating expense (excluding depreciation)
—
—
Depreciation, depletion, and amortization
2,452
Impairment expense
Loss (gain) on sale of assets, net
—
15
General and administrative expense
12,435
(excluding depreciation)
4,338,474
300,386
91,550
1,838
(10,949)
35,661
Acquisition and integration costs
87
—
—
(717)
239
—
(53,763)
—
—
4,338,474
299,669
94,241
1,838
(64,697)
48,096
87
Total operating expenses
14,989
4,756,960
(54,241)
4,717,708
Operating income (loss)
Other income (expense)
(14,989)
(46,921)
54,291
(7,619)
Interest expense and financing costs, net
(2,600)
(64,209)
Debt extinguishment and commitment costs
Gain on curtailment of pension obligation
Other income (expense), net
Equity earnings (losses) from subsidiaries
Total other income (expense), net
Income (loss) before income taxes
—
—
(33)
(63,649)
(66,282)
(81,271)
(6,728)
2,032
(19)
—
(68,924)
(115,845)
Income tax benefit (expense) (1)
(26)
24,835
Net income (loss)
$(81,297)
$(91,010)
316
(1,416)
—
—
63,649
62,549
116,840
(25,830)
$91,010
(66,493)
(8,144)
2,032
(52)
—
(72,657)
(80,276)
(1,021)
$(81,297)
Adjusted EBITDA
$(12,468)
$73,188
$767
$61,487
48
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YEAR ENDED DECEMBER 31, 2020
PARENT
GUARANTOR
ISSUER AND
SUBSIDIARIES
NON-GUARANTOR
SUBSIDIARIES AND
ELIMINATIONS
PAR PACIFIC
HOLDINGS, INC.
AND SUBSIDIARIES
$—
$3,124,870
$—
$3,124,870
Revenues
Operating expenses
Cost of revenues (excluding depreciation)
Operating expense (excluding depreciation)
Depreciation, depletion, and amortization
Impairment expense
General and administrative expense
(excluding depreciation)
—
—
2,900
—
11,097
2,947,697
282,159
86,622
85,806
30,191
Acquisition and integration costs
—
614
Total operating expenses
13,997
3,433,089
Operating income (loss)
(13,997)
(308,219)
Other income (expense)
(4,982)
(61,856)
Interest expense and financing costs, net
Other income (expense), net
Change in value of common stock warrants
(3)
4,270
Equity earnings (losses) from subsidiaries
(394,197)
Equity losses from Laramie Energy, LLC
—
1,052
—
—
—
Total other income (expense), net
(394,912)
(60,804)
Income (loss) before income taxes
(408,909)
(369,023)
Income tax benefit (expense) (1)
(177)
80,914
—
2,947,697
(4,732)
514
—
—
—
(4,218)
4,218
(3,384)
—
—
394,197
(46,905)
343,908
348,126
(60,017)
277,427
90,036
85,806
41,288
614
3,442,868
(317,998)
(70,222)
1,049
4,270
—
(46,905)
(111,808)
(429,806)
20,720
Net income (loss)
$(409,086)
$(288,109)
$288,109
$(409,086)
Adjusted EBITDA
$(10,943)
$(80,457)
$4,732
$(86,668)
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YEAR ENDED DECEMBER 31, 2019
PARENT
GUARANTOR
ISSUER AND
SUBSIDIARIES
NON-GUARANTOR
SUBSIDIARIES AND
ELIMINATIONS
PAR PACIFIC
HOLDINGS, INC.
AND SUBSIDIARIES
$—
$5,401,446
$70
$5,401,516
4,803,589
—
4,803,589
Revenues
Operating expenses
Cost of revenues (excluding depreciation)
Operating expense (excluding depreciation)
Depreciation, depletion, and amortization
Loss (gain) on sale of assets, net
General and administrative expense
(excluding depreciation)
—
—
2,969
—
20,017
315,659
82,843
(37,382)
26,007
Acquisition and integration costs
28
4,676
Total operating expenses
23,014
5,195,392
35,130
5,253,536
Operating income (loss)
(23,014)
206,054
(35,060)
147,980
Other income (expense)
Interest expense and financing costs, net
Debt extinguishment and commitment costs
Other income (expense), net
Change in value of common stock warrants
Equity earnings (losses) from subsidiaries
Equity losses from Laramie Energy, LLC
Total other income (expense), net
Income (loss) before income taxes
Income tax benefit (expense) (1)
(9,952)
(6,091)
2,303
(3,199)
81,097
—
64,158
41,144
(335)
(62,098)
(5,354)
213
—
—
—
(67,239)
138,815
(26,507)
Net income (loss)
$40,809
$112,308
$(112,308)
(2,760)
309
37,382
199
—
312,899
86,121
—
46,223
4,704
(2,789)
(142)
—
—
(81,097)
(89,751)
(74,839)
(11,587)
2,516
(3,199)
—
(89,751)
(173,779)
(176,860)
(208,839)
96,531
(28,880)
69,689
$40,809
Adjusted EBITDA
$(17,714)
$273,932
$2,631
$258,849
(1) The income tax benefit (expense) of the Parent Guarantor and Issuer and Subsidiaries is determined using the separate return method. The Non-Guarantor
Subsidiaries and Eliminations column includes tax benefits recognized at the Par consolidated level that are primarily associated with changes to the consolidated
valuation allowance and other deferred tax balances.
50
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NON-GA AP FINANCIAL MEASURES
Adjusted EBITDA for the supplemental consolidating condensed financial information, which is segregated at the “Parent
Guarantor,” “Issuer and Subsidiaries,” and “Non-Guarantor Subsidiaries and Eliminations” levels, is calculated in the same
manner as for the Par Pacific Holdings, Inc. Adjusted EBITDA calculations. See “Results of Operations — Non-GAAP Performance
Measures — Adjusted Net Income (Loss) and Adjusted EBITDA” above.
The following tables present a reconciliation of Adjusted EBITDA to the most directly comparable GAAP financial measure,
net income (loss), on a historical basis for the periods indicated (in thousands):
YEAR ENDED DECEMBER 31, 2021
PARENT
GUARANTOR
ISSUER AND
SUBSIDIARIES
NON-GUARANTOR
SUBSIDIARIES AND
ELIMINATIONS
PAR PACIFIC
HOLDINGS, INC.
AND SUBSIDIARIES
Net income (loss)
$(81,297)
$(91,010)
$91,010
$(81,297)
Inventory valuation adjustment
RINs loss in excess of net obligation
Unrealized loss on derivatives
Acquisition and integration costs
Debt extinguishment and commitment costs
Severance costs
Impairment expense
Loss (gain) on sale of assets, net
Depreciation, depletion, and amortization
Interest expense and financing costs, net
Equity losses (income) from subsidiaries
Income tax expense (benefit)
Adjusted EBITDA (3)
—
—
—
87
—
—
—
15
2,452
2,600
63,649
26
$(12,468)
17,089
16,967
1,517
—
6,728
84
1,838
—
—
—
—
1,416
—
—
17,089
16,967
1,517
87
8,144
84
1,838
(10,949)
(53,763)
(64,697)
91,550
64,209
239
(316)
—
(63,649)
(24,835)
$73,188
25,830
$767
94,241
66,493
—
1,021
$61,487
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YEAR ENDED DECEMBER 31, 2020
PARENT
GUARANTOR
ISSUER AND
SUBSIDIARIES
NON-GUARANTOR
SUBSIDIARIES AND
ELIMINATIONS
PAR PACIFIC
HOLDINGS, INC.
AND SUBSIDIARIES
Net income (loss)
$(409,086)
$(288,109)
$288,109
$(409,086)
Inventory valuation adjustment
RINs loss in excess of net obligation
Unrealized gain on derivatives
Acquisition and integration costs
Changes in valuation allowance and other
deferred tax items (1)
—
—
—
—
—
Change in value of common stock warrants
(4,270)
Severance costs
Impairment expense
Impairments of Laramie Energy, LLC (2)
Par’s share of Laramie Energy’s unrealized
gain on derivatives (2)
Depreciation, depletion, and amortization
Interest expense and financing costs, net
Equity losses from Laramie Energy, LLC,
excluding Par’s share of unrealized gain on
derivatives and impairment losses
157
—
—
—
2,900
4,982
—
Equity losses (income) from subsidiaries
394,197
14,046
44,071
(4,804)
614
—
—
355
85,806
—
—
86,622
61,856
—
—
Income tax expense (benefit)
177
(80,914)
Adjusted EBITDA (3)
$(10,943)
$(80,457)
—
—
—
—
14,046
44,071
(4,804)
614
(20,896)
(20,896)
—
—
—
45,294
(1,110)
514
3,384
2,721
(4,270)
512
85,806
45,294
(1,110)
90,036
70,222
2,721
(394,197)
80,913
$4,732
—
176
$(86,668)
52
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YEAR ENDED DECEMBER 31, 2019
PARENT
GUARANTOR
ISSUER AND
SUBSIDIARIES
NON-GUARANTOR
SUBSIDIARIES AND
ELIMINATIONS
PAR PACIFIC
HOLDINGS, INC.
AND SUBSIDIARIES
Net income (loss)
$40,809
$112,308
$(112,308)
$40,809
Inventory valuation adjustment
RINs gain in excess of net obligation
Unrealized loss on derivatives
Acquisition and integration costs
Debt extinguishment and commitment costs
Changes in valuation allowance and other
deferred tax items (1)
—
—
—
28
6,091
—
Change in value of common stock warrants
3,199
Loss (gain) on sale of assets, net
Impairment of Investment in Laramie Energy, LLC (2)
Par’s share of Laramie Energy’s unrealized gain
on derivatives (2)
Depreciation, depletion, and amortization
Interest expense and financing costs, net
Equity losses from Laramie Energy, LLC,
excluding Par’s share of unrealized gain on
derivatives and impairment losses
—
—
—
2,969
9,952
—
Equity losses (income) from subsidiaries
(81,097)
11,938
(3,398)
8,988
4,676
5,354
—
—
(37,382)
—
—
82,843
62,098
—
—
Income tax expense (benefit)
335
26,507
Adjusted EBITDA (3)
$(17,714)
$273,932
—
—
—
—
142
(68,792)
—
37,382
83,152
(1,969)
309
2,789
8,568
81,097
(27,739)
$2,631
11,938
(3,398)
8,988
4,704
11,587
(68,792)
3,199
—
83,152
(1,969)
86,121
74,839
8,568
—
(897)
$258,849
(1) Includes increases in (releases of) our valuation allowance associated with business combinations and changes in deferred tax assets and liabilities that are not offset
by a change in the valuation allowance. These tax expenses (benefits) are included in Income tax expense (benefit) on our consolidated statements of operations.
(2) Includes impairment losses on our investment in Laramie Energy and our share of Laramie Energy’s asset impairment losses in excess of our basis difference. These
impairment losses and our share of Laramie Energy’s unrealized loss (gain) on derivatives are included in Equity earnings (losses) from Laramie Energy, LLC on our
consolidated statements of operations.
(3) For the year ended December 31, 2021, there were no changes in valuation allowance and other deferred tax items, changes in value of common stock warrants,
or equity losses from Laramie Energy, including impairment losses and our share of Laramie Energy’s unrealized losses (gains) on derivatives. For the year ended
December 31, 2020, there were no debt extinguishment and commitment costs or losses (gains) on sale of assets. For the year ended December 31, 2019, there was no
impairment expense or severance costs. There was no LIFO liquidation adjustment or change in value of contingent consideration for the years ended December 31,
2021, 2020, and 2019.
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L I QUIDI T Y AND C API TAL RE S OURC E S
Our liquidity and capital requirements are primarily a function of our debt maturities and debt service requirements and
contractual obligations, capital expenditures, turnaround outlays, and working capital needs. Examples of working capital
needs include purchases and sales of commodities and associated margin and collateral requirements, facility maintenance
costs, and other costs such as payroll. Our primary sources of liquidity are cash flows from operations, cash on hand,
amounts available under our credit agreements, and access to capital markets.
Our liquidity position as of December 31, 2021 was $178.7 million and consisted of $174.6 million at Par Petroleum, LLC and
subsidiaries, $4.1 million at Par Pacific Holdings, and an immaterial amount at all our other subsidiaries.
As of December 31, 2021, we had access to the J. Aron Discretionary Draw Facility, the ABL Credit Facility, the MLC receivable
advances, and cash on hand of $112.2 million. In addition, we have the Supply and Offtake Agreement with J. Aron and the
Washington Refinery Intermediation Agreement, which are used to finance the majority of the inventory at our Hawaii and
Washington refineries, respectively. Generally, the primary uses of our capital resources have been in the operations of our
refining and retail segments, payments related to acquisitions, and to repay or refinance indebtedness.
We believe our cash flows from operations and available capital resources will be sufficient to meet our current capital and
turnaround expenditures, working capital, and debt service requirements for the next 12 months. We may seek to raise
additional debt or equity capital to fund any other significant changes to our business or to refinance existing debt. We
cannot offer any assurances that such capital will be available in sufficient amounts or at an acceptable cost.
In the first quarter of 2021, we closed on the sale and leaseback of twenty-two (22) of our retail properties in Hawaii for an
aggregate cash purchase price of approximately $112.8 million net of transaction fees (the “Sale-Leaseback Transactions”). We used
approximately $53.1 million of the net cash proceeds to repay the certain financing arrangements which were related to certain of
the retail properties and the remainder for general corporate purposes. Please read Note 16—Leases to our consolidated financial
statements under Item 8 of this Form 10-K for additional discussion on the Sale-Leaseback Transactions.
On March 19, 2021, we sold 5.75 million shares of common stock in an underwritten public offering at a public offering price of
$16.00 per share, resulting in net proceeds of approximately $87.2 million (the “Equity Offering”), after deducting underwriting
discounts and commissions and offering expenses. We used the net proceeds from the Equity Offering to repay the remaining
$48.7 million in aggregate principal amount of 5.00% Convertible Senior Notes at maturity in June 2021 and $36.8 million in
aggregate principal amount of 12.875% Senior Secured Notes, and the remainder for other general corporate purposes,
including capital expenditures, and funding working capital. Please read Note 18—Stockholders’ Equity to our consolidated
financial statements under Item 8 of this Form 10-K for additional discussion on the Equity Offering.
During the years ended December 31, 2021, 2020, and 2019, we had significant activity related to our inventory financing and
debt agreements. Please read Note 11—Inventory Financing Agreements and Note 13—Debt to our consolidated financial
statements under Item 8 of this Form 10-K for further discussion of significant activity related to our inventory financing and
debt agreements, respectively.
We may from time to time seek to retire or purchase our 7.75% Senior Secured Notes, our 12.875% Senior Secured Notes, or our
common stock through cash purchases and/or exchanges for equity securities, in open market purchases, privately negotiated
transactions, or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity
requirements, contractual restrictions, and other factors. The amounts involved may be material. On November 10, 2021, the
Board authorized and approved a share repurchase program for up to $50 million of the currently outstanding shares of our
common stock, with no specified end date. Please read Note 18—Stockholders’ Equity for further information. The Term Loan B
Facility may also require annual prepayments of principal with a variable percentage of our excess cash flow, 50% or 25%
depending on our consolidated year end secured leverage ratio (as defined in the Term Loan B Facility agreement).
CASH FLOWS
The following table summarizes cash activities for the years ended December 31, 2021, 2020, and 2019 (in thousands):
YEARS ENDED DECEMBER 31,
2021
2020
2019
Net cash provided by (used in) operating activities
$(27,622)
$(37,214)
$105,630
Net cash provided by (used in) investing activities
Net cash provided by (used in) financing activities
74,628
(1,094)
(63,464)
(353,229)
42,559
300,208
54
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Net cash used in operating activities was approximately $27.6 million for the year ended December 31, 2021, which resulted
from a net loss of approximately $81.3 million, partially offset by non-cash charges to operations of approximately $41.6 million
and net cash provided by changes in operating assets and liabilities of approximately $12.1 million. The change in our operating
assets and liabilities for the year ended December 31, 2021 was primarily due to a net increase in our Supply and Offtake
Agreement and Washington Refinery Intermediation Agreement obligations of $252.9 million, an increase in our environmental
credit obligations of $160.5 million, and increases in accounts payable and other current liabilities of $49.0 million, partially
offset by an increase in inventories of $350.7 million, an increase in our trade receivables of $84.0 million, and $9.5 million in
deferred turnaround costs associated with the Hawaii and Wyoming turnarounds. The increases in accounts receivable,
inventory, Supply and Offtake Agreement, and accounts payable and other current liabilities were primarily driven by the
increases in crude oil prices in 2021 and an overall increase in sales, purchases, and inventory volumes. The increase in our
environmental credit obligations was primarily driven by current year production and increases in RINs prices. Net cash used
in operating activities was approximately $37.2 million for the year ended December 31, 2020, which resulted from a net loss of
approximately $409.1 million, partially offset by non-cash charges to operations of approximately $219.1 million and net cash
provided by changes in operating assets and liabilities of approximately $152.8 million. Net cash provided by operating activities
was approximately $105.6 million for the year ended December 31, 2019, which resulted from net income of approximately
$40.8 million and non-cash charges to operations of approximately $144.9 million, partially offset by net cash used for changes
in operating assets and liabilities of approximately $80.1 million.
For the year ended December 31, 2021, net cash provided by investing activities was approximately $74.6 million and
primarily related to proceeds received from the Sale-Leaseback Transactions partially offset by additions to property, plant,
and equipment totaling approximately $29.5 million. Net cash used in investing activities was approximately $63.5 million for
the year ended December 31, 2020 and was primarily related to additions to property, plant, and equipment totaling
approximately $63.5 million. Net cash used in investing activities was approximately $353.2 million for the year ended
December 31, 2019 and was primarily related to $273.4 million for the Washington Acquisition and additions to property,
plant, and equipment totaling approximately $83.9 million.
Net cash used in financing activities for the year ended December 31, 2021 was approximately $1.1 million and consisted primarily of
proceeds of $87.2 million from our March 2021 equity offering of common stock partially offset by net repayments on our debt
agreements, J. Aron deferred payment arrangement and Discretionary Draw Facility, and MLC receivable advances of $81.4 million
and $5.6 million in extinguishment costs related to the repayment of the Retail Property Term Loan and a portion of the 12.875%
Senior Secured Notes. Net cash provided by financing activities for the year ended December 31, 2020 of approximately $42.6 million
consisted primarily of proceeds from net borrowings on our debt agreements, J. Aron deferred payment arrangement, and MLC
receivable advances of $49.3 million, partially offset by deferred loan costs of $6.3 million related to the issuance of the 12.875%
Senior Secured Notes. Net cash provided by financing activities for the year ended December 31, 2019 of approximately $300.2
million consisted primarily of proceeds from net borrowings on our debt agreements, J. Aron deferred payment arrangement, and
MLC receivable advances of $313.0 million and the exercise of employee stock options of $8.2 million, partially offset by deferred
loan costs of $13.5 million and payments of $8.1 million in commitment and other fees related to the funding for the Washington
Acquisition and the financing costs related to the repurchase and cancellation of a portion of our 5.00% Convertible Senior Notes.
CASH REQUIREMENTS
We have various cash requirements stemming from investment strategies, contractual obligations, and financial commitments in
the normal course of our operations and financing activities. Contractual obligations include future cash payments required under
existing contractual arrangements, such as debt and lease agreements. These cash requirements and obligations may result from
both general financing activities and from commercial arrangements that are directly related to our operating activities. We also
continue to seek strategic investments in business opportunities, however the amount and timing of those investments are not
predictable. Our material cash requirements as of December 31, 2021 include:
Debt and Interest Payments. Current and long-term debt includes the scheduled principal payments related to our outstanding
debt obligations and letters of credit. Our estimated interest payments due for 2022 are $46.6 million and our total estimated
undiscounted future interest payments will be $194.0 million on the debt obligations held as of December 31, 2021 and using
interest rates in effect as of December 31, 2021. Please read Note 13—Debt to our consolidated financial statements under Item 8
of this Form 10-K for further discussion.
Capital Expenditures and Turnaround Costs. Our deferred turnaround costs and capital expenditures, excluding acquisitions, for
the year ended December 31, 2021, totaled approximately $39.0 million and were primarily related to the 2021 turnaround and
related scheduled maintenance work at our Washington refinery, capital projects at our Hawaii refinery, and underground tank
replacements, rebranding, and point of sale and other equipment upgrades at our Retail segment. Our capital expenditures and
deferred turnaround costs budget for 2022 ranges from $70 to $80 million and primarily relates to the 2022 turnaround at our
Washington refinery, scheduled maintenance, and other capital projects related to regulatory compliance, information technology,
and growth. We expect to spend approximately $35 to $45 million annually on maintenance and sustaining capital projects and
approximately $80 to $90 million on planned turnaround expenditures over the next five years.
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Operating Lease Liabilities. Operating lease liabilities primarily include obligations associated with the lease of land, office space,
retail facilities, and other facilities used in the storage and transportation of crude oil and refined products. Please read Note 16—
Leases to our consolidated financial statements under Item 8 of this Form 10-K for further discussion.
Finance Lease Liabilities. Finance lease liabilities primarily include obligations associated with the lease of retail facilities and vehicles.
Please read Note 16—Leases to our consolidated financial statements under Item 8 of this Form 10-K for further discussion.
Purchase Commitments. Purchase commitments primarily consist of contracts executed as of December 31, 2021 for the
purchase of crude oil for use at our refineries that are scheduled for delivery in 2022. As of December 31, 2021, we have material
purchase commitments of $1.2 billion, with required cash outlays primarily expected in the next twelve months.
Supply and Offtake Agreement. We have a supply and offtake agreement with J. Aron to support the operations of our Hawaii
refinery. On June 1, 2021, we and J. Aron entered into a Second Amended and Restated Supply and Offtake Agreement (the “Supply
and Offtake Agreement”) which expires on May 31, 2024 with a one-year extension option. Please read Note 11—Inventory
Financing Agreements to our consolidated financial statements under Item 8 of this Form 10-K for more information.
Washington Refinery Intermediation Agreement. In connection with the consummation of the Washington Acquisition on
January 11, 2019, we assumed the Washington Refinery Intermediation Agreement with MLC to support the operations of
our Washington refinery. On November 1, 2019, we amended the Washington Refinery Intermediation Agreement and
extended the term through June 30, 2021. We further amended the Washington Refinery Intermediation Agreement on
February 11, 2021 and extended the term through March 31, 2022. On December 17, 2021, we and MLC amended the
Washington Refinery Intermediation Agreement to further extend the term through December 21, 2022 with an automatic
extension to March 31, 2023 upon an ABL extension event and revises certain other terms and conditions in the Washington
Refinery Intermediation Agreement. Please read Note 11—Inventory Financing Agreements to our consolidated financial
statements under Item 8 of this Form 10-K for more information.
Environmental Matters. Our operations are subject to extensive and periodically-changing federal, state, and local environmental
laws and regulations including but not limited to air emissions, wastewater discharges, and solid and hazardous waste management
activities. Additionally, we have asset retirement obligations in the period in which we have a legal obligation, whether by
government or regulatory action or contractual arrangement, to incur these costs and can make a reasonable estimate of the
fair value of the liability. Please read Note 9—Asset Retirement Obligations and Note 17—Commitments and Contingencies to
our consolidated financial statements under Item 8 of this Form 10-K for more information.
C RI T IC AL ACCOUN T ING E S T IMAT E S
The discussion and analysis of our financial condition and results of operations were based on the consolidated financial
statements, which have been prepared in accordance with U.S. GAAP. The preparation of these consolidated financial
statements required us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues,
and expenses. Our significant accounting policies are described in Note 2—Summary of Significant Accounting Policies to our
audited consolidated financial statements under Item 8 of this Form 10-K. We have identified certain estimates as being of
particular importance to the portrayal of our financial position and results of operations and which require the application of
significant judgment by management. We analyze our estimates on a periodic basis, including those related to fair value,
impairments, natural gas and crude oil reserves, bad debts, natural gas and oil properties, income taxes, derivatives,
contingencies, and litigation and base our estimates on historical experience and various other assumptions that we believe
are reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or
conditions. We believe the following critical accounting estimates affect our more significant judgments and estimates used
in the preparation of our consolidated financial statements.
INVENTORY AND OBLIGATIONS UNDER INVENTORY FINANCING AGREEMENTS
Commodity inventories, excluding commodity inventories at the Washington refinery, are stated at the lower of cost and net
realizable value using the FIFO accounting method. Commodity inventories at the Washington refinery are stated at the
lower of cost and net realizable value using the LIFO inventory accounting method. We value merchandise along with spare
parts, materials, and supplies at average cost. Estimating the net realizable value of our inventory requires management to
make assumptions about the timing of sales and the expected proceeds that will be realized for these sales. Please read Note
6—Inventories to our consolidated financial statements under Item 8 of this Form 10-K for additional information.
All of the crude oil utilized at the Hawaii refinery is financed by J. Aron under procurement contracts. The crude oil remains in
the legal title of J. Aron and is stored in our storage tanks governed by a storage agreement. Legal title to the crude oil passes
to us at the tank outlet. After processing, J. Aron takes title to the refined products stored in our storage tanks until they are
sold to our retail locations or to third parties. We record the inventory owned by J. Aron on our behalf as inventory with a
corresponding accrued liability on our balance sheet because we maintain the risk of loss until the refined products are sold
to third parties and we have an obligation to repurchase it. The valuation of our repurchase obligation requires that we make
estimates of the prices and differentials assuming settlement occurs at the end of the reporting period.
In connection with the consummation of the Washington Acquisition, we became a party to the Washington Refinery
Intermediation Agreement with MLC. Under this arrangement, U.S. Oil purchases crude oil supplied from third-party
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suppliers and MLC provides credit support for certain of these purchases. U.S. Oil holds title to all crude oil and refined
products inventories at all times and pledges such inventories, together with all receivables arising from the sales of these
inventories, exclusively to MLC. The valuation of our terminal obligation requires that we make estimates of the prices and
differentials for our then monthly forward purchase obligations.
Please read Note 11—Inventory Financing Agreements to our consolidated financial statements under Item 8 of this Form 10-K
for additional information regarding both our Hawaii and Washington inventory financing agreements.
FAIR VALUE ME A SUREMEN T S
We measure certain assets and liabilities at their fair market value. Assets and liabilities measured at fair value on a recurring
basis include derivative instruments and environmental credit obligations. We also measure certain assets and liabilities at
fair value on a nonrecurring basis when specific triggering events occur, such as business combinations and events which
indicate that a reporting unit’s carrying value exceeds its estimated fair value. Fair value is defined as the price that would be
received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. In estimating fair
value, we use discounted cash flow projections, recent comparable market transactions, if available, or quoted prices. We
consider assumptions that third parties would make in estimating fair value, including the highest and best use of the asset.
The assumptions used by another party could differ significantly from our assumptions.
We classify fair value balances based on the classification of the inputs used to calculate the fair value of a transaction. The
inputs used to measure fair value have been placed in a hierarchy based on priority. The hierarchy gives the highest priority
to unadjusted, readily observable quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and
the lowest priority to unobservable inputs (Level 3 measurement). Please read Note 15—Fair Value Measurements to our
consolidated financial statements under Item 8 of this Form 10-K for additional information.
BUSINESS COMBINATIONS
We recognize assets acquired and liabilities assumed in business combinations separately from goodwill at their estimated fair
values as of the date of acquisition. Significant judgment is required in estimating the fair value of assets acquired. We obtain the
assistance of third-party valuation specialists in estimating fair values of tangible and intangible assets based on available historical
information and on expectations and assumptions about the future, considering the perspectives of marketplace participants.
These valuation methods require management to make estimates and assumptions regarding characteristics of the acquired
property and future revenues and expenses. Changes in these estimates and assumptions would result in different amounts allocat-
ed to the related assets and liabilities. The measurement period may be up to one year from the acquisition date; we may record
adjustments to the preliminary purchase price allocation during this time, concluding at the end of the one year period or final
determination of the values of consideration transferred and asses and liabilities assumed, whichever comes first. Subsequent
adjustments, if any, are recorded to the consolidated statement of operations. Please read Note 4—Acquisitions and Note 15—Fair
Value Measurements to our consolidated financial statements under Item 8 of this Form 10-K for further information.
IMPAIRMENT OF GOODWILL AND LONG-LIVED ASSETS
We assess the recoverability of the carrying value of goodwill during the fourth quarter of each year or whenever events or changes
in circumstances indicate that the carrying amount of the goodwill of a reporting unit may not be fully recoverable. We first assess
qualitative factors to determine whether it is more likely than not that the fair value of the reporting unit is less than its carrying
value. If the qualitative assessment indicates that it is more likely than not that the carrying value of a reporting unit exceeds its
estimated fair value, a quantitative test is required. Under the quantitative test, we compare the carrying value of the net assets of
the reporting unit to the estimated fair value of the reporting unit. If the carrying value exceeds the estimated fair value of the
reporting unit, an impairment loss is recorded. The fair value of a reporting unit is determined using the income approach and the
market approach. Under the income approach, we estimate the present value of expected future cash flows using a market
participant discount rate. Under the market approach, we estimate fair value using observable multiples for comparable companies
within our industry. These valuation methods require us to make significant estimates and assumptions regarding future cash flows,
capital projects, commodity prices, long-term growth rates, and discount rates. Please read Note 10—Goodwill and Intangible
Assets to our consolidated financial statements under Item 8 of this Form 10-K for further information, including the goodwill
impairment we recorded in the first quarter of 2020.
We review property, plant, and equipment, operating leases, and other long-lived assets whenever events or changes in
business circumstances indicate the carrying value of the assets may not be recoverable. We use a cash flows model to
estimate value because there is usually a lack of quoted market prices for long-lived assets. Future cash flows estimates used
for impairment reviews are based on assessments requiring judgment, including future production volumes, commodity
prices, operating costs, margins, discount rates, expected capital expenditures, and other factors based on all available
information available as of the date of the review. Impairment is indicated when the undiscounted cash flows estimated to be
generated by those assets are less than the assets’ carrying value. If this occurs, an impairment loss is recognized for the
difference between the fair value and carrying value. The fair value of long-lived assets is determined using the income
approach. Please read Note 8—Property, Plant, and Equipment and Impairment of Long-Lived Assets to our consolidated
financial statements under Item 8 of this Form 10-K for further information, including the asset impairment we recorded in
the first quarter of 2020.
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IMPAIRMENT OF OUR INVESTMENT IN L ARAMIE ENERGY
We evaluate our investment in Laramie Energy for impairment when factors indicate that a decrease in the value of our
investment has occurred and the carrying amount of our investment may not be recoverable. The fair value of our investment in
Laramie Energy is determined using the income approach and/or the market approach. Under the income approach, we
estimate the present value of expected future cash flows using a market participant discount rate. Other significant inputs used
in the income approach include proved and unproved reserves information and forecasts of operating expenditures obtained
from Laramie Energy’s management. Under the market approach, we estimate fair value using observable multiples for
comparable companies within our industry. These valuation methods require us to make significant estimates and assumptions
regarding future cash flows, capital projects, commodity prices, long-term growth rates, and discount rates. An impairment loss,
based on the difference between the carrying value and the estimated fair value of the investment, is recognized in earnings
when an impairment is deemed to be other than temporary. Please read Note 3—Investment in Laramie Energy, LLC to our
consolidated financial statements under Item 8 of this Form 10-K for further information.
ENVIRONMENTAL MATTERS AND ASSET RETIREMENT OBLIGATIONS
We record liabilities when environmental assessments and/or remedial efforts are probable and can be reasonably estimated.
Cost estimates are based on the expected timing and extent of remedial actions required by governing agencies, experience
gained from similar sites for which environmental assessments or remediation have been completed, and the amount of our
anticipated liability considering the proportional liability and financial abilities of other responsible parties. Usually, the timing of
these accruals coincides with the completion of a feasibility study or our commitment to a formal plan of action. Please read
Note 17—Commitments and Contingencies to our consolidated financial statements under Item 8 of this Form 10-K for further
information about our environmental liabilities and assessments.
We record asset retirement obligations (“AROs”) at fair value in the period in which we have a legal obligation, whether by
government action or contractual arrangement, to incur these costs and can make a reasonable estimate of the fair value of
the liability. Estimating the cost and timing of future remedial efforts is difficult and related technologies, costs, regulatory
and other compliance considerations, timing, discount rates, and other inputs into the valuations are subject to change.
Please read Note 2—Summary of Significant Accounting Policies, “Asset Retirement Obligations,” to our consolidated financial
statements under Item 8 of this Form 10-K for further information.
INCOME TA XES
We use the asset and liability method of accounting for income taxes. Under the asset and liability method, deferred tax
assets and liabilities are recognized for the future tax consequences attributable to differences between the financial
statement carrying amounts of existing assets and liabilities and their respective tax bases and net operating loss (“NOL”) and
tax credit carry forwards. The realizability of deferred tax assets is evaluated quarterly based on a “more likely than not”
standard and, to the extent this threshold is not met, a valuation allowance is recorded. In assessing the realizability of
deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax
assets will not be realized. These liabilities are recorded based on our assessment of existing tax laws and regulations. The
ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in
which these temporary differences become deductible and may vary from our estimates for a number of reasons, including
different interpretations of tax laws and regulations. New tax laws and regulations, and changes to existing tax laws and
regulations, are proposed and promulgated continuously. The implementation of future tax laws and regulatory initiatives, as
well as future interpretations on historical tax laws and regulations, could result in increased tax liabilities that cannot be
predicted at this time. Please read Note 2—Summary of Significant Accounting Policies, “Income Taxes,” to our consolidated
financial statements under Item 8 of this Form 10-K for further information.
Based upon the level of historical taxable income and projections for future results of operations over the periods in which
the deferred tax assets are deductible, among other factors, management concluded that we did not meet the “more likely
than not” requirement in order to recognize deferred tax assets and therefore, a valuation allowance has been recorded for
substantially all of our net deferred tax assets at December 31, 2021 and 2020.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
COMM ODI T Y PRIC E RI S K
Our earnings, cash flows, and liquidity are significantly affected by commodity price volatility. Our Revenues fluctuate with
refined product prices and our Cost of revenues (excluding depreciation) fluctuates with movements in crude oil and
feedstock prices. Assuming all other factors remain constant, a $1 per barrel change in average gross refining margins, based
on our throughput of 135 Mbpd for the full year of 2021, would change annualized operating income by approximately $48.7
million. This analysis may differ from actual results.
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In order to manage commodity price risks, we utilize exchange-traded futures, options, and over-the-counter (“OTC”) swaps
to manage commodity price risks associated with:
• the price for which we sell our refined products;
• the price we pay for crude oil and other feedstocks;
• our crude oil and refined products inventory; and
• our fuel requirements for our refineries.
All of our futures and OTC swaps are executed to economically hedge our physical commodity purchases, sales, and inventory.
Our open futures and OTC swaps will expire in April 2022.
Based on our net open futures positions at December 31, 2021, a $1 change in the price of crude oil, assuming all other
factors remain constant, would result in $2.1 million change to the fair value of our derivative instruments and Cost of
revenues (excluding depreciation).
Our predominant variable operating cost is the cost of fuel consumed in the refining process, which is included in Cost of
revenues (excluding depreciation) on our consolidated statements of operations. For the year ended December 31, 2021, we
consumed approximately 135 Mbpd of crude oil during the refining process across all our refineries. We internally consumed
approximately 3% of this throughput in the refining process, which is accounted for as a fuel cost. We have executed option
collars to economically hedge our internally consumed fuel cost at all our refineries. Please read Note 14—Derivatives to our
consolidated financial statements under Item 8 of this Form 10-K for more information.
COMPL IANC E PRO GR AM PRIC E RI S K
We are exposed to market risks related to the volatility in the price of RINs required to comply with the Renewable Fuel
Standard. Our renewable volume obligation (“RVO”) is based on a percentage of our Hawaii, Wyoming, and Washington
refineries’ production of on-road transportation fuel. The EPA sets the RVO percentages annually. On December 21, 2021, EPA
published proposed RFS that include retroactive cuts to earlier 2020 quotas, set 2021 targets at levels of renewable fuels that
were actually used, and would establish significantly higher volume requirements for 2022. Whether that rule will be finalized
as proposed and how the final rule will fare in the courts may significantly alter our obligations to blend renewable fuels or
purchase RINs. To the degree we are unable to blend the required amount of biofuels to satisfy our RVO, we must purchase RINs
on the open market. To mitigate the impact of this risk on our results of operations and cash flows, we may purchase RINs when
the price of these instruments is deemed favorable. Some of these contracts are derivative instruments, however, we elect the
normal purchases normal sales exception and do not record these contracts at their fair values.
IN T ERE S T R AT E RI S K
As of December 31, 2021, we had $215.6 million of indebtedness that was subject to floating interest rates. We also had interest
rate exposure in connection with our liability under the J. Aron Supply and Offtake Agreement and the MLC Washington
Refinery Intermediation Agreement for which we pay charges based on three-month LIBOR. An increase of 1% in the variable
rate on our indebtedness, after considering the instruments subject to minimum interest rates, would result in an increase to
our Cost of revenues (excluding depreciation) and Interest expense and financing costs, net of approximately $3.8 million and
$3.6 million per year, respectively.
We may utilize interest rate swaps to manage our interest rate risk. As of December 31, 2020, we had entered into an interest
rate swap at an average fixed rate of 3.91% in exchange for the floating interest rate on the notional amounts due under the
Retail Property Term Loan. This swap was set to expire on April 1, 2024, the maturity date of the Retail Property Term Loan.
On February 23, 2021, we terminated and repaid all amounts outstanding under the Retail Property Term Loan and the
related interest rate swap.
We have several contracts that reference London Interbank Offered Rate (“LIBOR”), some of which terminate after LIBOR is
anticipated to cease being reported in 2023. Our facilities that currently reference LIBOR include transition language consistent
with the scheduled transition. We do not expect the transition away from LIBOR to have a material impact on our financial
condition, results of operations, or cash flows.
C REDI T RI S K
We are subject to the risk of loss resulting from nonpayment or nonperformance by our counterparties. We will continue to
closely monitor the creditworthiness of customers to whom we grant credit and establish credit limits in accordance with our
credit policy.
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Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The consolidated financial statements and schedule required by this item are set forth beginning on page F-1.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES
None.
Item 9A. CONTROLS AND PROCEDURES
E VALUAT I ON OF DI S C LOSURE CON T ROL S AND PRO C EDURE S
Disclosure controls and procedures are designed with the objective of ensuring that all information required to be disclosed
in our reports filed under the Securities Exchange Act of 1934, as amended (“Exchange Act”), such as this report, is recorded,
processed, summarized, and reported within the time periods specified by the SEC. In connection with the preparation of this
Annual Report on Form 10-K, as of December 31, 2021, an evaluation was performed under the supervision and with the
participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the
design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the
Exchange Act). Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that these
disclosure controls and procedures were effective as of December 31, 2021.
C HANGE S IN IN T ERNAL CO N T ROL OVER FINANC IAL REP OR T ING
There were no changes during the quarter ended December 31, 2021, in our internal control over financial reporting that
have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management’s Report on Internal Control Over Financial Reporting
The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting (as
defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934). The Company’s internal control system was
designed to provide reasonable assurance to the Company’s management and Board of Directors regarding the reliability of financial
reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting
principles. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems
determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of
December 31, 2021. In making this assessment, management used the criteria set forth by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO) in Internal Control—Integrated Framework (2013). Based on such
assessment, the Company’s management concluded that, as of December 31, 2021, the Company’s internal control over
financial reporting was effective based on those criteria.
Deloitte & Touche LLP, the Company’s independent registered public accounting firm that audited the Company’s financial
statements included in this Annual Report on Form 10-K, has issued an audit report on the effectiveness of the Company’s
internal control over financial reporting as of December 31, 2021, which is included herein.
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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Par Pacific Holdings, Inc.
OPINI ON ON IN T ERNAL CON T RO L OVER FINANC IAL REP O R T ING
We have audited the internal control over financial reporting of Par Pacific Holdings, Inc. and subsidiaries (the “Company”) as
of December 31, 2021, based on criteria established in Internal Control — Integrated Framework (2013) issued by the
Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all
material respects, effective internal control over financial reporting as of December 31, 2021, based on criteria established in
Internal Control — Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(PCAOB), the consolidated financial statements as of and for the year ended December 31, 2021, of the Company and our
report dated February 25, 2022, expressed an unqualified opinion on those financial statements.
BA S I S FOR OPINION
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report
on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over
financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be
independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and
regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in
all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the
risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based
on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.
DEFINI T I ON AND L IMI TAT I ON S OF IN T ERNAL CO N T RO L OVER FINANC IAL REP O RT ING
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with
generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and
procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transac-
tions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as
necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and
that receipts and expenditures of the company are being made only in accordance with authorizations of management and
directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 25, 2022
Item 9B. OTHER INFORMATION
None.
Item 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
None.
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PART III
Item 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE
The information required by this item is incorporated in this Annual Report on Form 10-K by reference to our definitive proxy
statement or an amendment to this Annual Report on Form 10-K to be filed with the Securities and Exchange Commission
not later than 120 days after the end of the fiscal year ended December 31, 2021.
Item 11. EXECUTIVE COMPENSATION
The information required by this item is incorporated in this Annual Report on Form 10-K by reference to our definitive proxy
statement or an amendment to this Annual Report on Form 10-K to be filed with the Securities and Exchange Commission
not later than 120 days after the end of the fiscal year ended December 31, 2021.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required by this item is incorporated in this Annual Report on Form 10-K by reference to our definitive proxy
statement or an amendment to this Annual Report on Form 10-K to be filed with the Securities and Exchange Commission
not later than 120 days after the close of our fiscal year ended December 31, 2021.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
The information required by this item is incorporated in this Annual Report on Form 10-K by reference to our definitive proxy
statement or an amendment to this Annual Report on Form 10-K to be filed with the Securities and Exchange Commission
not later than 120 days after the end of the fiscal year ended December 31, 2021.
Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required by this item is incorporated in this Annual Report on Form 10-K by reference to our definitive proxy
statement or an amendment to this Annual Report on Form 10-K to be filed with the Securities and Exchange Commission not
later than 120 days after the end of the fiscal year ended December 31, 2021.
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PART IV
Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)
The following documents are filed as part of this report:
(1) Consolidated Financial Statements (Included under Item 8). The Index to the Consolidated Financial Statements
is included on page F-1 of this Annual Report on Form 10-K and is incorporated herein by reference.
(2) Financial Statement Schedules
Schedule I – Condensed Financial Information of Registrant
2.1
2.2
2.3
2.4
2.5
2.6
2.7
2.8
2.9
Third Amended Joint Chapter 11 Plan of Reorganization of Delta Petroleum Corporation and Its Debtor Affiliates
dated August 16, 2012. Incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed
on September 7, 2012.
Membership Interest Purchase Agreement dated as of June 17, 2013, by and among Tesoro Corporation, Tesoro
Hawaii, LLC, and Hawaii Pacific Energy, LLC. Incorporated by reference to Exhibit 2.4 to the Company’s Quarterly
Report on Form 10-Q for the quarterly period ended June 30, 2013, filed on August 14, 2013.
Agreement and Plan of Merger dated as of June 2, 2014, by and among the Company, Bogey, Inc., Koko’oha
Investments, Inc., and Bill D. Mills, in his capacity as the Shareholders’ Representative. Incorporated by reference to
Exhibit 2.5 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2014, filed on
August 11, 2014.
Amendment of Agreement and Plan of Merger dated as of September 9, 2014, by and among the Company, Bogey,
Inc., Koko’oha Investments, Inc., and Bill D. Mills, in his capacity as the Shareholders’ Representative. Incorporated
by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on September 10, 2014.
Second Amendment of Agreement and Plan of Merger dated as of December 31, 2014, by and among Par Petroleum
Corporation, Bogey, Inc., Koko’oha Investments, Inc., and Bill D. Mills, in his capacity as the Shareholder’s Representative.
Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on January 7, 2015.
Third Amendment to Agreement and Plan of Merger dated as of March 31, 2015, by and among the Company,
Bogey, Inc., Koko’oha Investments, Inc., and Bill D. Mills, in his capacity as the Shareholders’ Representative.
Incorporated by reference to Exhibit 2.4 to the Company’s Current Report on Form 8-K filed on April 2, 2015.
Unit Purchase Agreement, dated as of June 13, 2016, between Par Wyoming, LLC and Black Elk Refining, LLC.
Incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on June 15, 2016.
First Amendment to Unit Purchase Agreement dated as of July 14, 2016, between Par Wyoming, LLC and Black Elk Refining,
LLC. Incorporated by reference to Exhibit 2.2 to the Company’s Current Report on Form 8-K filed on July 15, 2016.
Purchase and Sale Agreement dated as of November 26, 2018, among Par Petroleum, LLC, TrailStone NA Oil &
Refining Holdings, LLC, and solely for certain purposes specified therein, the Company. Incorporated by reference to
Exhibit 2.1 to the Company’s Current Report on Form 8-K/A filed on November 30, 2018.#
2.10
Amendment No. 1 to Purchase and Sale Agreement dated as of January 11, 2019, among Par Petroleum, LLC,
TrailStone NA Oil & Refining Holdings, LLC, and Par Pacific Holdings, Inc. Incorporated by reference to Exhibit 2.2 to
the Company’s Current Report on Form 8-K filed on January 14, 2019.
3.1
3.2
4.1
4.2
4.3
Restated Certificate of Incorporation of the Company dated October 20, 2015. Incorporated by reference to Exhibit
3.2 to the Company’s Current Report on Form 8-K filed on October 20, 2015.
Second Amended and Restated Bylaws of the Company dated October 20, 2015. Incorporated by reference to
Exhibit 3.3 to the Company’s Current Report on Form 8-K filed on October 20, 2015.
Form of the Company’s Common Stock Certificate. Incorporated by reference to Exhibit 4.1 to the Company’s
Annual Report on Form 10-K filed on March 31, 2014.
Registration Rights Agreement effective as of August 31, 2012, by and among the Company, Zell Credit Opportuni-
ties Master Fund, L.P., Waterstone Capital Management, L.P., Pandora Select Partners, LP, Iam Mini-Fund 14 Limited,
Whitebox Multi-Strategy Partners, LP, Whitebox Credit Arbitrage Partners, LP, HFR RVA Combined Master Trust,
Whitebox Concentrated Convertible Arbitrage Partners, LP, and Whitebox Asymmetric Partners, LP. Incorporated by
reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K filed on September 7, 2012.
First Amendment to Registration Rights Agreement dated as of December 19, 2018, by and among the Company
and the holders party thereto. Incorporated by reference to Exhibit 4.3 to the Company’s registration statement on
Form S-3 filed on December 21, 2018.
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4.4
4.5
4.6
4.7
4.8
4.9
4.10
4.11
Stockholders Agreement dated April 10, 2015. Incorporated by reference to Exhibit 4.1 to the Company’s Current
Report on Form 8-K filed on April 13, 2015.
Indenture, dated June 21, 2016, between Par Pacific Holdings, Inc. and Wilmington Trust, National Association, as
Trustee. Incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on June 22, 2016.
Indenture, dated December 21, 2017, among Par Petroleum, LLC, Par Petroleum Finance Corp., the Guarantors (as
defined therein), and Wilmington Trust, National Association, as Trustee and Collateral Trustee. Incorporated by
reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on December 22, 2017.
First Supplemental Indenture, dated November 20, 2018, among Par Petroleum, LLC, Par Petroleum Finance Corp.,
the Guarantors (as defined therein), and Wilmington Trust, National Association, as Trustee. Incorporated by
reference to Exhibit 4.21 to the Company’s registration statement on Form S-3 filed on December 21, 2018.
Stockholders Agreement dated April 10, 2015. Incorporated by reference to Exhibit 4.1 to the Company’s Current
Report on Form 8-K filed on April 13, 2015.
Second Supplemental Indenture, dated January 11, 2019, among Par Tacoma, LLC (f/k/a TrailStone NA Asset Finance
I, LLC), U.S. Oil & Refining Co., McChord Pipeline Co., Par Petroleum, LLC, Par Petroleum Finance Corp., Par Pacific
Holdings, Inc., the other guarantors party thereto, and Wilmington Trust, National Association. Incorporated by
reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on January 14, 2019.
Third Supplemental Indenture, dated August 15, 2019, among Par Hawaii, LLC (successor by conversion to Par
Hawaii, Inc.), Par Petroleum, LLC, Par Petroleum Finance Corp., Par Pacific Holdings, Inc., the other guarantors party
thereto, and Wilmington Trust, National Association. Incorporated by reference to Exhibit 4.23 to the Company’s
Quarterly Report on Form 10-Q filed on August 10, 2020.
Indenture, dated as of June 5, 2020, among Par Petroleum, LLC, Par Petroleum Finance Corp., the Guarantors (as
defined therein) and Wilmington Trust, National Association, as Trustee and Collateral Trustee. Incorporated by
reference to Exhibit 4.1 to the Company’s current report on Form 8-K filed on June 8, 2020.
4.12
Description of Registrant’s Securities.*
10.1
10.2
10.3
10.4
10.5
10.6
10.7
10.8
10.9
10.10
10.11
10.12
Fourth Amended and Restated Limited Liability Company Agreement of Laramie Energy, LLC, dated as of October
18, 2018, by and among Par Piceance Energy Equity LLC and the other members party thereto. Incorporated by
reference to Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q filed on November 7, 2018.
Delta Petroleum General Recovery Trust Agreement dated August 27, 2012, by and among the Company, DPCA LLC,
Delta Exploration Company, Inc., Delta Pipeline, LLC, DLC, Inc., CEC, Inc., Castle Texas Production Limited Partner-
ship, Amber Resources Company of Colorado, Castle Exploration Company, Inc., and John T. Young. Incorporated by
reference to Exhibit 10.6 to the Company’s Current Report on Form 8-K filed on September 7, 2012.
Par Pacific Holdings, Inc. Amended and Restated 2012 Long Term Incentive Plan. Incorporated by reference to
Appendix A to the Company’s Proxy Statement on Schedule 14A filed on April 21, 2016.****
Par Pacific Holdings, Inc. Second Amended and Restated 2012 Long Term Incentive Plan. Incorporated by reference
to Exhibit 4.1 to the Company’s registration statement on Form S-8 filed on May 18, 2018.****
Par Pacific Holdings, Inc. 2018 Employee Stock Purchase Plan. Incorporated by reference to Exhibit 4.2 to the
Company’s Registration Statement on Form S-8 filed on May 18, 2018.****
Form of Indemnification Agreement between the Company and its Directors and Executive Officers. Incorporated
by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on October 19, 2012.****
Letter Agreement dated as of September 17, 2013 but effective as of January 1, 2013, by and between Equity Group
Investments and the Company. Incorporated by reference to Exhibit 10.17 to the Company’s Quarterly Report on
Form 10-Q filed on November 14, 2013.
Environmental Agreement dated as of September 25, 2013, by and among Tesoro Corporation, Tesoro Hawaii, LLC,
and Hawaii Pacific Energy, LLC. Incorporated by reference to Exhibit 10.16 to the Company’s Quarterly Report on
Form 10-Q filed on November 14, 2013.
Employment Offer Letter with William Monteleone dated September 25, 2013. Incorporated by reference to Exhibit
10.43 to the Company’s Amendment No. 3 to Annual Report on Form 10-K/A filed on July 2, 2014.****
Employment Offer Letter with Joseph Israel dated December 12, 2014. Incorporated by reference to Exhibit 10.1 to
the Company’s Current Report on Form 8-K filed on December 17, 2014.****
Employment Offer Letter with James Matthew Vaughn dated July 3, 2014. Incorporated by reference to Exhibit 10.7
to the Company’s Quarterly Report on Form 10-Q filed on May 5, 2016.****
Employment Offer Letter with Jim Yates dated March 10, 2015. Incorporated by reference to Exhibit 10.10 to the
Company’s Quarterly Report on Form 10-Q filed on May 5, 2016.****
64
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10.13
10.14
10.15
10.16
10.17
10.18
10.19
10.20
10.21
10.22
10.23
10.24
10.25
10.26
10.27
10.28
10.29
10.30
10.31
10.32
10.33
Initial Award with Jim Yates dated May 8, 2015. Incorporated by reference to Exhibit 10.11 to the Company’s
Quarterly Report on Form 10-Q filed on May 5, 2016.****
Form of Award of Restricted Stock (Discretionary Long Term Incentive Plan). Incorporated by reference to Exhibit
10.17 to the Company’s Annual Report on Form 10-K filed on March 2, 2020.****
Form of Award of Restricted Stock Units (Discretionary Long Term Incentive Plan). Incorporated by reference to
Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on April 2, 2015.****
Form of Nonstatutory Stock Option Agreement (Discretionary Long Term Incentive Plan). Incorporated by reference
to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on April 2, 2015.****
Par Petroleum (and subsidiaries) Incentive Compensation Plan. Incorporated by reference to Exhibit 10.1 to the
Company’s Current Report on Form 8-K filed on May 12, 2015.****
Second Amended and Restated Supply and Offtake Agreement dated as of June 1, 2021, between Par Hawaii
Refining, LLC and J. Aron & Company, LLC. Incorporated by reference to Exhibit 10.2 to the Company’s Quarterly
Report on Form 10-Q filed on August 5, 2021.
Amended and Restated Guaranty dated June 1, 2021 in favor of J. Aron & Company LLC by Par Petroleum, LLC.
Incorporated by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q filed on August 5, 2021.
Environmental Indemnity Agreement dated as of June 1, 2015, by Hawaii Independent Energy, LLC in favor of J. Aron &
Company. Incorporated by reference to Exhibit 10.7 to the Company’s Current Report on Form 8-K filed June 2, 2015.
Employment Offer Letter with William C. Pate dated October 12, 2015. Incorporated by reference to Exhibit 10.1 to
the Company’s Current Report on Form 8-K filed October 14, 2015.****
Amendment to Employment Offer Letter with Joseph Israel dated October 12, 2015. Incorporated by reference to
Exhibit 10.3 to the Company’s Current Report on Form 8-K filed October 14, 2015.****
Par Pacific Holdings, Inc. Non-Qualified Deferred Compensation Plan. Incorporated by reference to Exhibit 10.1 to
the Company’s Current Report on Form 8-K filed on March 6, 2017.****
Par Pacific Holdings, Inc. Severance Plan for Senior Officers. Incorporated by reference to Exhibit 10.2 to the
Company’s Current Report on Form 8-K filed on March 6, 2017. ****
Asset Purchase Agreement dated as of January 9, 2018 by and among CHS Inc., Par Hawaii, Inc., and Par Pacific
Holdings, Inc. Incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q filed on
May 10, 2018. #
First Amendment to Asset Purchase Agreement dated as of March 23, 2018 by and among CHS Inc., Par Hawaii, Inc.,
and Par Pacific Holdings, Inc. Incorporated by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form
10-Q filed on May 10, 2018. #
Term Loan and Guaranty Agreement, dated as of January 11, 2019, among Par Petroleum, LLC, Par Petroleum Finance
Corp., the guarantors party thereto, Par Pacific Holdings, Inc. solely for the limited purposes set forth therein, the
lenders party thereto, and Goldman Sachs Bank USA, as administrative agent. Incorporated by reference to Exhibit
10.1 to the Company’s Current Report on Form 8-K filed on January 14, 2019.
Collateral Trust and Intercreditor Agreement, dated as of December 21, 2017, among Par Petroleum, LLC, Par
Petroleum Finance Corp., the guarantors from time to time party thereto, Wilmington Trust, National Association,
as indenture trustee and as collateral trustee, J. Aron & Company LLC, and Goldman Sachs Bank USA. Incorporated
by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on January 14, 2019.
Conformed Copy of First Lien ISDA Master Agreement dated as of January 11, 2019, between Merrill Lynch Commodities,
Inc. and U.S. Oil & Refining Co. Incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K
filed on January 14, 2019.
Ninth Amendment to First Lien ISDA 2002 Master Agreement entered into as of November 1, 2019 by and between
U.S. Oil & Refining Co. and Merrill Lynch Commodities, Inc. Incorporated by reference to Exhibit 10.1 to the
Company’s Current Report on Form 8-K filed on November 4, 2019.
Eighteenth Amendment to First Lien ISDA 2002 Master Agreement entered into as of December 17, 2021 by and
between U.S. Oil & Refining Co. and Merrill Lynch Commodities, Inc. Incorporated by reference to Exhibit 10.1 to
the Company’s Current Report on Form 8-K filed on December 20, 2021
Nineteenth Amendment to First Lien ISDA 2002 Master Agreement entered into as of February 24, 2022 by and
between U.S. Oil & Refining Co. and Merrill Lynch Commodities, Inc.*
Topping Unit Purchase Agreement by and among IES Downstream, LLC, Eagle Island, LLC, Par Hawaii Refining, LLC,
and Par Pacific Holdings, Inc., dated as of August 29, 2018. Incorporated by reference to Exhibit 10.1 to the
Company’s Quarterly Report on Form 10-Q filed on November 7, 2018. #
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10.34
10.35
10.36
10.37
10.38
10.39
10.40
Pledge and Security Agreement dated as of December 21, 2017 among Par Petroleum, LLC, the other grantors party
thereto, and Wilmington Trust, National Association, as collateral trustee. Incorporated by reference to Exhibit
10.45 to the Company’s Annual Report on Form 10-K filed on March 8, 2021.
Amendment No. 1 and Assumption Agreement to Pledge and Security Agreement dated as of August 19, 2019,
among Par Petroleum, LLC, and the other grantors party thereto and Wilmington Trust, National Association, as
collateral trustee.*
Amendment No. 2 and Assumption Agreement to Pledge and Security Agreement dated as of May 12, 2020, among Par
Petroleum, LLC, and the other grantors party thereto and Wilmington Trust, National Association, as collateral trustee.*
Amendment No. 3 and Assumption Agreement to Pledge and Security Agreement dated as of June 4, 2020, among Par
Petroleum, LLC, and the other grantors party thereto and Wilmington Trust, National Association, as collateral trustee.*
Purchase Agreement and Escrow Instructions, dated as of February 11, 2021, by and among Par Hawaii, LLC, Par
Pacific Hawaii Property Company, LLC, MDC Coast HI 1, LLC, and Fidelity National Title Insurance Company.
Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on February 16, 2021.
Amended and Restated Master Land and Building Lease Agreement, dated as of March 12, 2021, by and among Par
Hawaii, LLC, Par Petroleum, LLC and MDC Coast HI 1, LLC. Incorporated by reference to Exhibit 10.2 to the Compa-
ny’s Quarterly Report on Form 10-Q filed on Form 8-K filed on May 7, 2021.
Amended and Restated Loan and Security Agreement dated as of February 2, 2022, among Par Petroleum, LLC, Par
Hawaii, LLC, Hermes Consolidated, LLC, Wyoming Pipeline Company LLC, the guarantors party thereto, the financial
institutions party thereto, as lenders, and Bank of America, N.A., as administrative agent. Incorporated by reference
to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on February 4, 2022.
10.41
Thirteenth Amendment to First Lien ISDA 2002 Master Agreement entered into as of February 11, 2021, by and
between U.S. Oil & Refining Co. and Merrill Lynch Commodities, Inc. Incorporated by reference to Exhibit 10.3 to
the Company’s Quarterly Report on Form 10-Q filed on Form 8-K filed on February 16, 2021.
10.42
Second Amended and Restated Pledge and Security Agreement dated June 1, 2021 in favor of J. Aron & Company
LLC by Par Hawaii Refining, LLC.*
14.1
Par Pacific Holdings, Inc. Code of Business Conduct and Ethics for Employees, Executive Officers and Directors,
effective December 3, 2015. Incorporated by reference to Exhibit 14.1 to the Company’s Annual Report on Form
10-K filed March 3, 2016.
21.1
Subsidiaries of the Registrant.*
23.1
Consent of Deloitte & Touche LLP*
31.1
Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*
31.2
Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*
32.1
Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350.***
32.2
Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350.***
101.INS Inline XBRL Instance Document the instance document does not appear in the Interactive Data File because XBRL
tags are embedded within the Inline XBRL document.*
101.SCH Inline XBRL Taxonomy Extension Schema Documents.*
101.CAL Inline XBRL Taxonomy Extension Calculation Linkbase Document.*
101.LAB Inline XBRL Taxonomy Extension Label Linkbase Document.*
101.PRE Inline XBRL Taxonomy Extension Presentation Linkbase Document.*
101.DEF Inline XBRL Taxonomy Extension Definition Linkbase Document.*
104
Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).*
*
***
Filed herewith.
Furnished herewith.
****
Management contract or compensatory plan or arrangement.
#
Portions of this exhibit have been redacted in accordance with Item 601(b)(10) of Regulation S-K.
66
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Report of Independent Registered Public Accounting Firm
Auditor Name: Deloitte & Touch LLP; Auditor Firm ID: 34; Auditor Location: Houston, Texas
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Comprehensive Income (Loss)
Consolidated Statements of Cash Flows
Consolidated Statements of Changes in Stockholders’ Equity
Notes to Consolidated Financial Statements
PAGE NO.
F-2
F-4
F-5
F-6
F-6
F-8
F-9
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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Par Pacific Holdings, Inc.
OPINI ON ON T HE FINANC IAL S TAT EMEN T S
We have audited the accompanying consolidated balance sheets of Par Pacific Holdings, Inc. and subsidiaries (the “Company”) as
of December 31, 2021 and 2020, the related consolidated statements of operations, comprehensive income, cash flows and
changes in stockholders’ equity for each of the three years in the period ended December 31, 2021, and the related notes and
the schedule listed in the Index at Item 15 (collectively referred to as the “financial statements”). In our opinion, the financial
statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and
the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity
with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(PCAOB), the Company’s internal control over financial reporting as of December 31, 2021, based on criteria established in
Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway
Commission, and our report dated February 25, 2022 expressed an unqualified opinion on the Company’s internal control
over financial reporting.
BA S I S FOR OPINION
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion
on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and
are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the
applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether
due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial
statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included
examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also
included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the
overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
C RI T IC AL AUDI T MAT T ER
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that
was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that
are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The
communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and
we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the
accounts or disclosures to which it relates.
GOODWILL — CERTAIN REPORTING UNITS — REFER TO NOTES 2 AND 10 TO THE FINANCIAL STATEMENTS.
Critical Audit Matter Description
The Company’s evaluation of goodwill for impairment involves the comparison of the fair value of each reporting unit to its
carrying value. The Company determines the fair value of its reporting units using the discounted cash flow model and the
market approach. The determination of the fair value using the discounted cash flow model requires management to make
significant estimates and assumptions related to discount rates and long-term growth rates as well as forecasts of future gross
margin, capital expenditures, and operating expenses. The determination of the fair value using the market approach requires
management to make significant assumptions related to valuation multiples. Changes in these assumptions could have a
significant impact on either the fair value, or the amount of any goodwill impairment charge, or both. The goodwill balance was
$127.3 million as of December 31, 2021. No impairment loss was recorded during the year ended December 31, 2021.
We identified goodwill associated with certain reporting units as a critical audit matter because of the significant judgments
made by management to estimate the fair value of the reporting units and, consequently, the difference between their fair
value and carrying value. The audit procedures performed to evaluate the reasonableness of management’s estimates and
assumptions related to the selection of discount rates, long-term growth rates, valuation multiples, and forecasts of future
gross margin, capital expenditures, and operating expenses required a high degree of auditor judgment and an increased
extent of effort, including the need to involve our fair value specialists.
F-2
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How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the discount rates, long-term growth rates, valuation multiples, and forecasts of future gross
margin, capital expenditures, and operating expenses used by management to estimate the fair value of certain reporting
units included the following, among others:
• We tested the effectiveness of controls over management’s goodwill impairment evaluation, including those over the
determination of the underlying assumptions, such as management’s selection of the discount rates, long-term growth
rates, and valuation multiples as well as forecasts of future gross margin, capital expenditures, and operating expenses.
• We evaluated management’s ability to accurately forecast future gross margin, capital expenditures, and operating
expenses by comparing actual results to management’s historical forecasts.
• We evaluated the reasonableness of management’s forecasts by comparing the forecasts to:
• Historical financial results.
• Internal communications to management and the Board of Directors.
• Forecasted information included in Company press releases as well as in analyst and industry reports for the Company
and certain of its peer companies.
• We evaluated the impact of changes in management’s forecasts from the measurement date to December 31, 2021.
• With the assistance of our fair value specialists, we evaluated the reasonableness of the discount rates, long-term growth
rates, and valuation multiples by:
• Testing the source information underlying the determination of the discount rates, long-term growth rates, and valuation
multiples and the mathematical accuracy of the calculations.
• Developing a range of independent estimates and comparing those to the discount rates, long-term growth rates, and
valuation multiples selected by management.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 25, 2022
We have served as the Company’s auditor since 2013.
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F-3
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PAR PAC IFIC H OL DING S, INC. AND SUB S IDIARIE S CO N S OL IDAT ED BAL ANC E S HEE T S
(in thousands, except share data)
DECEMBER 31, 2021
DECEMBER 31, 2020
ASSETS
Current assets
Cash and cash equivalents
Restricted cash
Total cash, cash equivalents, and restricted cash
Trade accounts receivable, net of allowances of $0.4 million and $0.6 million
at December 31, 2021 and December 31, 2020, respectively
Inventories
Prepaid and other current assets
Total current assets
Property, plant, and equipment
Property, plant, and equipment
Less accumulated depreciation, depletion, and amortization
Property, plant, and equipment, net
Long-term assets
Operating lease right-of-use (“ROU”) assets
Intangible assets, net
Goodwill
Other long-term assets
Total assets
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt
Obligations under inventory financing agreements
Accounts payable
Accrued taxes
Operating lease liabilities
Other accrued liabilities
Total current liabilities
Long-term liabilities
Long-term debt, net of current maturities
Finance lease liabilities
Operating lease liabilities
Other liabilities
Total liabilities
Commitments and Contingencies (Note 17)
Stockholders’ equity
Preferred stock, $0.01 par value: 3,000,000 shares authorized, none issued
Common stock, $0.01 par value; 500,000,000 shares authorized at December
31, 2021 and December 31, 2020, 60,161,955 shares and 54,002,538 shares
issued at December 31, 2021 and December 31, 2020, respectively
Additional paid-in capital
Accumulated deficit
Accumulated other comprehensive income (loss)
Total stockholders’ equity
Total liabilities and stockholders’ equity
See accompanying notes to consolidated financial statements.
F-4
$112,221
4,000
116,221
195,108
790,317
28,525
1,130,171
1,180,397
(323,892)
856,505
383,824
16,234
127,262
56,255
$68,309
2,000
70,309
111,657
429,855
24,648
636,469
1,183,878
(251,113)
932,765
357,166
18,892
127,997
60,572
$2,570,251
$2,133,861
$10,841
737,704
154,543
28,641
53,640
370,424
1,355,793
553,717
7,691
335,094
52,256
2,304,551
—
602
821,713
(559,117)
2,502
265,700
$59,933
423,686
106,945
27,440
56,965
203,711
878,680
648,660
7,925
304,355
47,967
1,887,587
—
540
726,504
(477,028)
(3,742)
246,274
$2,570,251
$2,133,861
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PAR PAC IFIC H OL DING S, INC. AND SUB S IDIARIE S CO N S OL IDAT ED S TAT EMEN T S O F OPER AT I ON S
(in thousands, except per share amounts)
Revenues
Operating expenses
YEAR ENDED DECEMBER 31,
2021
2020
2019
$4,710,089
$3,124,870
$5,401,516
Cost of revenues (excluding depreciation)
4,338,474
2,947,697
4,803,589
Operating expense (excluding depreciation)
299,669
277,427
312,899
Depreciation, depletion, and amortization
Impairment expense
Gain on sale of assets, net
94,241
1,838
(64,697)
90,036
85,806
—
General and administrative expense (excluding depreciation)
48,096
41,288
Acquisition and integration costs
87
614
86,121
—
—
46,223
4,704
Total operating expenses
Operating income (loss)
Other income (expense)
4,717,708
3,442,868
5,253,536
(7,619)
(317,998)
147,980
Interest expense and financing costs, net
(66,493)
(70,222)
(74,839)
Debt extinguishment and commitment costs
Gain on curtailment of pension obligation
Other income (expense), net
Change in value of common stock warrants
Equity losses from Laramie Energy, LLC
Total other expense, net
Loss before income taxes
Income tax benefit (expense)
Net income (loss)
Income (loss) per share
Basic
Diluted
Weighted-average number of shares outstanding
Basic
Diluted
See accompanying notes to consolidated financial statements.
(8,144)
2,032
(52)
—
—
—
—
1,049
4,270
(11,587)
—
2,516
(3,199)
(46,905)
(89,751)
(72,657)
(111,808)
(176,860)
(80,276)
(429,806)
(28,880)
(1,021)
20,720
69,689
$(81,297)
$(409,086)
$40,809
$(1.40)
$(1.40)
58,268
58,268
$(7.68)
$(7.68)
53,295
53,295
$0.80
$0.80
50,352
50,470
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PAR PACIFIC HOLDINGS, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(in thousands)
Net income (loss)
Other comprehensive income (loss):
YEAR ENDED DECEMBER 31,
2021
2020
2019
$(81,297)
$(409,086)
$40,809
Other post-retirement benefits income (loss), net of tax
Total other comprehensive income (loss), net of tax
6,244
6,244
(4,324)
(4,324)
(2,091)
(2,091)
Comprehensive income (loss)
$(75,053)
$(413,410)
$38,718
PAR PACIFIC HOLDINGS, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
Cash flows from operating activities:
Net income (loss)
Adjustments to reconcile net income (loss)
to cash provided by (used in) operating activities:
Depreciation, depletion, and amortization
Impairment expense
Debt extinguishment and commitment costs
Non-cash interest expense
Non-cash lower of cost and net realizable value adjustment
Change in value of common stock warrants
Deferred taxes
Gain on sale of assets, net
Stock-based compensation
Unrealized (gain) loss on derivative contracts
Equity losses from Laramie Energy, LLC
Net changes in operating assets and liabilities:
Trade accounts receivable
Collateral posted with broker for derivative transactions
Prepaid and other assets
Inventories
Deferred turnaround expenditures
Obligations under inventory financing agreements
Accounts payable, other accrued liabilities, and operating lease
ROU assets and liabilities
YEAR ENDED DECEMBER 31,
2021
2020
2019
$(81,297)
$(409,086)
$40,809
94,241
1,838
8,144
5,663
(10,132)
—
(260)
(64,697)
8,165
(1,393)
—
(83,955)
4,564
(10,885)
(350,652)
(9,451)
252,920
209,565
90,036
85,806
—
6,902
10,595
(4,270)
86,121
—
11,587
9,118
(3,752)
3,199
(20,895)
(66,886)
—
7,342
(3,322)
46,905
117,801
7,035
29,465
171,880
(49,770)
(190,831)
67,193
—
6,437
9,350
89,751
(36,652)
(8,797)
(24,121)
(191,688)
(9,800)
121,985
68,969
Net cash provided by (used in) operating activities
(27,622)
(37,214)
105,630
F-6
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YEAR ENDED DECEMBER 31,
2021
2020
2019
Cash flows from investing activities:
Acquisitions of businesses, net of cash acquired
Proceeds related to asset acquisition
Capital expenditures
Proceeds from sale of assets
Net cash provided by (used in) investing activities
Cash flows from financing activities:
Proceeds from sale of common stock, net of offering costs
Proceeds from borrowings
Repayments of borrowings
Net borrowings (repayments) on deferred
payment arrangements and receivable advances
Payment of deferred loan costs
Exercise of stock options
Payments for debt extinguishment and commitment costs
Other financing activities, net
Net cash provided by (used in) financing activities
Net increase (decrease) in cash, cash equivalents, and restricted cash
Cash, cash equivalents, and restricted cash at beginning of period
—
—
(29,533)
104,161
74,628
87,193
186,773
(329,315)
61,098
(346)
—
(5,618)
(879)
(1,094)
45,912
70,309
Cash, cash equivalents, and restricted cash at end of period
$116,221
—
—
(63,522)
58
(273,399)
3,226
(83,920)
864
(63,464)
(353,229)
—
250,387
(159,489)
(41,645)
—
510,906
(241,336)
43,422
(6,266)
(13,450)
—
—
(428)
42,559
(58,119)
128,428
$70,309
8,171
(8,087)
582
300,208
52,609
75,819
$128,428
Supplemental cash flow information:
Net cash received (paid) for:
Interest
Taxes
Non-cash investing and financing activities:
Accrued capital expenditures
Value of warrants reclassified to equity
ROU assets obtained in exchange for new finance lease liabilities
ROU assets obtained in exchange for new operating lease liabilities
ROU assets terminated in exchange for release from finance lease liabilities
ROU assets terminated in exchange for release from
operating lease liabilities
Common stock issued for business combination
Common stock issued to repurchase convertible notes
See accompanying notes to consolidated financial statements.
$(65,221)
$(54,256)
$(58,250)
(795)
190
(136)
$8,177
—
1,936
97,011
—
6,847
—
—
$4,686
3,936
3,476
22,529
—
7,738
—
—
$6,386
—
963
79,382
—
193
36,980
74,290
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PAR PACIFIC HOLDINGS, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
(in thousands)
COMMON STOCK
SHARES
AMOUNT
ADDITIONAL
PAID -IN
CAPITAL
ACCUMUL ATED
DEFICIT
ACCUMUL ATED
OTHER
COMPREHENSIVE
INCOME
TOTAL
EQUIT Y
$470
$617,937
$(108,751)
$2,673
$512,329
Balance, January 1, 2019
Issuance of common stock in
connection with acquisition
Issuance of common
stock for convertible
notes repurchase, net (1)
Issuance of common
stock for employee
stock purchase plan
Stock-based compensation
Purchase of common
stock for retirement
Exercise of stock options
Other comprehensive loss
Net income
46,984
2,364
3,243
68
202
(54)
447
—
—
23
32
1
3
—
4
—
—
36,957
45,585
1,489
6,210
(1,276)
8,167
—
—
—
—
—
—
—
—
—
40,809
Balance, December 31, 2019
53,254
533
715,069
(67,942)
Issuance of common stock for
employee stock purchase plan
Exercise of common
stock warrants
Stock-based compensation
Purchase of common
stock for retirement
Other comprehensive loss
Net loss
145
351
322
(69)
—
—
Balance, December 31, 2020
54,003
Common stock offering,
net of issuance costs
Issuance of common stock for
employee stock purchase plan
Stock-based compensation
Purchase of common
stock for retirement
Exercise of stock options
Other comprehensive income
Net loss
5,750
85
443
(123)
4
—
—
2
3
3
(1)
—
—
540
58
1
4
(1)
—
—
—
1,551
3,933
7,106
(1,155)
—
—
87,135
1,420
7,948
(1,352)
58
—
—
—
—
—
—
—
—
—
—
(792)
—
—
—
—
—
—
—
—
(2,091)
—
582
—
—
—
(4,324)
36,980
45,617
1,490
6,213
(1,276)
8,171
(2,091)
40,809
648,242
1,553
3,936
7,109
(1,156)
—
(4,324)
—
—
—
—
—
—
6,244
246,274
87,193
1,421
7,952
(2,145)
58
6,244
(409,086)
(3,742)
(409,086)
726,504
(477,028)
(81,297)
—
(81,297)
Balance, December 31, 2021
60,162
$602
$821,713
$(559,117)
$2,502
$265,700
(1) The issuance of common stock for the repurchase of a portion of our 5.00% Convertible Senior Notes during the year ended December 31, 2019, is presented net of a
$28.7 million write-off associated with the equity component of the repurchased notes.
F-8
See accompanying notes to consolidated financial statements.
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Note 1—Overview
Par Pacific Holdings, Inc. and its wholly owned subsidiaries (“Par” or the “Company”) own and operate market-leading energy
and infrastructure businesses. Our strategy is to acquire and develop businesses in logistically complex, niche markets.
Currently, we operate in three primary business segments:
1) Refining - We own and operate three refineries with total operating crude oil throughput capacity of 154 thousand barrels
per day (“Mbpd”). Our refinery in Kapolei, Hawaii, produces gasoline, jet fuel, ultra-low sulfur diesel (“ULSD”), marine fuel,
low sulfur fuel oil (“LSFO”), and other associated refined products primarily for consumption in Hawaii. Our refinery in
Newcastle, Wyoming, produces gasoline, jet fuel, ULSD, and other associated refined products that are primarily marketed
in Wyoming and South Dakota. Our refinery in Tacoma, Washington, produces gasoline, jet fuel, ULSD, asphalt, and other
associated refined products primarily marketed in the Pacific Northwest.
2) Retail - We operate 119 retail outlets in Hawaii, Washington, and Idaho. Our fuel retail outlets in Hawaii sell gasoline and
diesel throughout the islands of Oahu, Maui, Hawaii, and Kauai. We operate convenience stores at 34 of our Hawaii retail
fuel outlets under our proprietary “nomnom” brand that sell merchandise such as soft drinks, prepared foods, and other
sundries. Our Hawaii retail network includes Hele and “76” branded retail sites, “nomnom” branded company-operated
convenience stores, 7-Eleven operated convenience stores, other sites operated by third parties, and unattended cardlock
stations. 42 of our sites operate under our proprietary Hele (the Hawaiian word for movement or “let’s go”) fuel brand.
Our eight cardlock locations on Kauai are branded Kauai Automated Fuels (“KAF”).
We operate convenience stores at all 29 of our retail fuel outlets in Washington and Idaho. As part of our 2018 acquisition
of these retail outlets, we entered into a multi-year branded petroleum marketing agreement for the continued supply of
Cenex®-branded refined products to the acquired Cenex® Zip Trip convenience stores. As of December 31, 2021, we had
completed the rebranding of all of our retail outlets in Washington and Idaho from the “Cenex®” and “Zip Trip®”
brand names to our proprietary “nomnom” brand. As these stores were rebranded, we began self-supplying the fuel with
equity barrels and/or unbranded fuels procured in the open market.
3) Logistics - We operate an extensive multi-modal logistics network spanning the Pacific, the Northwest, and the Rocky
Mountain regions. 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 lease marine vessels for
the movement of petroleum, refined products, and ethanol between the U.S. West Coast and Hawaii. We 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. We own and operate logistics assets
in Washington, including a marine terminal, a unit train-capable rail loading terminal, storage facilities, a truck rack, and a
proprietary pipeline that serves Joint Base Lewis McChord.
As of December 31, 2021, we owned a 46.0% equity investment in Laramie Energy, LLC (“Laramie Energy”), a joint venture
entity operated by Laramie Energy II, LLC (“Laramie”). Laramie Energy is focused on producing natural gas in Garfield, Mesa,
and Rio Blanco counties, Colorado.
Our Corporate and Other reportable segment primarily includes general and administrative costs.
Note 2—Summary of Significant Accounting Policies
PRINC IPL E S O F CON S OL IDAT I O N AND BA S I S OF PRE S EN TAT I O N
The consolidated financial statements include the accounts of Par Pacific Holdings, Inc. and its subsidiaries. All intercompany
balances and transactions have been eliminated in consolidation.
Certain amounts previously reported in our consolidated financial statements for prior periods have been reclassified to
conform to the current presentation.
US E OF E S T IMAT E S
The preparation of our consolidated financial statements in conformity with U.S. generally accepted accounting principles
(“GAAP”) requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, and
expenses and the related disclosures. Actual amounts could differ from these estimates.
The worldwide spread and severity of the COVID-19 coronavirus, and certain developments in the global crude oil markets have
impacted our businesses, people, and operations. We are actively responding to these ongoing matters and many uncertainties
remain. Due to the rapid development and fluidity of the situation, the full magnitude of the COVID-19 pandemic’s impact on
our estimates and assumptions, financial condition, future results of operations, and future cash flows and liquidity is uncertain
and has been and may continue to be material.
C A S H AND C A S H EQUIVAL EN T S
Cash and cash equivalents consist of all highly liquid investments with original maturities of three months or less. The
carrying value of cash equivalents approximates fair value because of the short-term nature of these investments.
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RE S T RIC T ED C A S H
Restricted cash consists of cash not readily available for general purpose cash needs. Restricted cash relates to cash held at
commercial banks to support letter of credit facilities and certain ongoing bankruptcy recovery trust claims.
AL LOWANC E FO R C REDI T LOS S E S
We are exposed to credit losses primarily through our sales of refined products. Credit limits and/or prepayment requirements
are set based on such factors as the customer’s financial results, credit rating, payment history, and industry and are reviewed
annually for customers with material credit limits. Credit allowances are reviewed at least quarterly based on changes in the
customer’s creditworthiness due to economic conditions, liquidity, and business strategy as publicly reported and through
discussions between the customer and the Company. We establish provisions for losses on trade receivables based on the
estimated credit loss we expect to incur over the life of the receivable. We did not have a material change in our allowances on
trade receivables during the years ended December 31, 2021, 2020, or 2019.
INVEN TORIE S
Commodity inventories, excluding commodity inventories at the Washington refinery, are stated at the lower of cost and net
realizable value (“NRV”) using the first-in, first-out (“FIFO”) inventory accounting method. Commodity inventories at the
Washington refinery are stated at the lower of cost and NRV using the last-in, first-out (“LIFO”) inventory accounting method.
We value merchandise along with spare parts, materials, and supplies at average cost.
All of the crude oil utilized at the Hawaii refinery is financed by J. Aron & Company LLC (“J. Aron”) under the Supply and Offtake
Agreement as described in Note 11—Inventory Financing Agreements. The crude oil remains in the legal title of J. Aron and is
stored in our storage tanks governed by a storage agreement. Legal title to the crude oil passes to us at the tank outlet. After
processing, J. Aron takes title to the refined products stored in our storage tanks until they are sold to our retail locations or to
third parties. We record the inventory owned by J. Aron on our behalf as inventory with a corresponding obligation on our
balance sheet because we maintain the risk of loss until the refined products are sold to third parties and we are obligated to
repurchase the inventory.
In connection with the consummation of the Washington Acquisition (as defined in Note 4—Acquisitions), we became a party to
an intermediation arrangement (the “Washington Refinery Intermediation Agreement”) with Merrill Lynch Commodities, Inc.
(“MLC”) as described in Note 11—Inventory Financing Agreements. Under this arrangement, U.S. Oil (as defined in Note
4—Acquisitions) purchases crude oil supplied from third-party suppliers and MLC provides credit support for certain crude oil
purchases. MLC’s credit support can consist of either providing a payment guaranty, causing the issuance of a letter of credit
from a third-party issuing bank, or purchasing crude oil directly from third parties on our behalf. U.S. Oil holds title to all crude
oil and refined products inventories at all times and pledges such inventories, together with all receivables arising from the sales
of these inventories, exclusively to MLC.
We enter into refined product and crude oil exchange agreements with other oil companies. Exchange receivables or payables
are stated at cost and are presented within Trade accounts receivable and Accounts payable on our consolidated balance sheets.
ENVIRONMEN TAL C REDI T S AND O BL IGAT I ON S
Inventories also include Renewable Identification Numbers (“RINs”), sulfur credits, and other environmental credits. Our RINs
assets, which include RINs purchased in the open market and RINs obtained by purchasing biofuels which are later blended into
our refined products, are presented as Inventories on our consolidated balance sheets and stated at the lower of cost and NRV
as of the end of the reporting period. Our sulfur credits and other environmental credits generated as part of our refining
process are presented as Inventories on our consolidated balance sheets and stated at the lower of cost and NRV as of the end
of the reporting period. Our renewable volume obligation and other environmental credit obligations to comply with the U.S.
Environmental Protection Agency (“EPA”) regulations (as discussed in Note 17—Commitments and Contingencies) are presented
in Other accrued liabilities on our consolidated balance sheets and measured at fair value as of the end of the reporting period.
The net cost of environmental credits is recognized within Cost of revenues (excluding depreciation) on our consolidated
statements of operations.
INVE S T MEN T IN L AR AMIE ENERGY, L LC
Prior to June 30, 2020, we accounted for our Investment in Laramie Energy, LLC using the equity method as we have the ability
to exert significant influence, but do not control its operating and financial policies. Our proportionate share of the net income
(loss) of this entity was included in Equity losses from Laramie Energy, LLC in the consolidated statements of operations. As of
June 30, 2020, we discontinued the application of the equity method of accounting for our investment in Laramie Energy
because the book value of such investment had been reduced to zero. The investment is reviewed for impairment when events
or changes in circumstances indicate that there may have been an other-than-temporary decline in the value of the investment.
During the years ended December 31, 2020 and 2019, we recorded impairment charges of $45.3 million and $81.5 million in
our consolidated statement of operations due to the significant decline in natural gas prices during the first quarter of 2020
and during the second and third quarters of 2019, respectively. Please read Note 3—Investment in Laramie Energy, LLC for
further information.
F-10
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PRO PER T Y, PL AN T, AND EQUIPMEN T
We capitalize the cost of additions, major improvements, and modifications to property, plant, and equipment. The cost of
repairs and normal maintenance of property, plant, and equipment is expensed as incurred. Major improvements and
modifications of property, plant, and equipment are those expenditures that either extend the useful life, increase the
capacity, or improve the operating efficiency of the asset or the safety of our operations. We compute depreciation of
property, plant, and equipment using the straight-line method, based on the estimated useful life of each asset as follows:
ASSETS
Refining
Logistics
Retail
Corporate
Software
LIVES IN YEARS
2 to 47
3 to 30
3 to 40
3 to 7
3 to 5
IMPAIRMEN T O F LONG-L IVED A S S E T S
We review property, plant, and equipment, operating leases, deferred turnaround costs, and other long-lived assets for
impairment whenever events or changes in business circumstances indicate the carrying value of the assets may not be
recoverable. Impairment is indicated when the undiscounted cash flows estimated to be generated by those assets are less than
the assets’ carrying value. If this occurs, an impairment loss is recognized for the difference between the fair value and carrying
value. Factors that indicate potential impairment include a significant decrease in the market value of the asset, operating or
cash flow losses associated with the use of the asset, and a significant change in the asset’s physical condition or use.
Simultaneously with our review of our property, plant, and equipment, operating leases, deferred turnaround costs, and other
long-lived assets for impairment, we evaluate whether an abandonment has occurred. Abandonment occurs either when a
business terminates its operations or an asset is no longer profitable to operate. When the act of abandonment occurs, we
determine if the assets have a shortened useful life or should be considered abandoned and accelerate depreciation or write off
the asset balance and any associated accumulated depreciation and record an impairment loss.
L E A S E L IABIL I T IE S AND RIGH T- OF-US E A S S E T S
We determine whether a contract is or contains a lease when we have the right to control the use of the identified asset in
exchange for consideration. Lease liabilities and right-of-use assets (“ROU assets”) are recognized at the commencement
date based on the present value of lease payments over the lease term. We use our incremental borrowing rate in the
calculation of present value unless the implicit rate can be readily determined, however, the lease liability associated with
leases calculated through the use of implicit rates is not significant. Certain leases include provisions for variable payments
based upon percentage of sales and/or other operating metrics; escalation provisions to adjust rental payments to reflect
changes in price indices and fair market rents; and provisions for the renewal, termination, and/or purchase of the leased
asset. We only consider fixed payments and those options that are reasonably certain to be exercised in the determination of
the lease term and the initial measurement of lease liabilities and ROU assets. Expense for finance leases is recognized as
amortization expense on a straight-line basis and interest expense on an effective rate basis over the lease term. Expense for
operating lease payments is recognized as lease expense on a straight-line basis over the lease term. We do not separate
lease and nonlease components of a contract. Leases with an initial term of 12 months or less are not recorded on the
balance sheet. Finance lease ROU assets are presented within Property, plant, and equipment and operating lease ROU
assets within Operating lease right-of-use assets on our consolidated balance sheets. Please read Note 16—Leases for further
disclosures and information on leases.
A S S E T RE T IREMEN T OBL IGAT I ON S
We record asset retirement obligations (“AROs”) at fair value in the period in which we have a legal obligation, whether by
government action or contractual arrangement, to incur these costs and can make a reasonable estimate of the fair value of
the liability. Our AROs arise from our refining, logistics, and retail operations. AROs are calculated based on the present value
of the estimated removal and other closure costs using our credit-adjusted risk-free rate. When the liability is initially
recorded, we capitalize the cost by increasing the book value of the related long-lived tangible asset. The liability is accreted
to its estimated settlement value with accretion expense recognized in Depreciation, depletion, and amortization (“DD&A”)
on our consolidated statements of operations and the related capitalized cost is depreciated over the asset’s useful life. The
difference between the settlement amount and the recorded liability is recorded as a gain or loss on asset disposals in our
consolidated statements of operations. We estimate settlement dates by considering our past practice, industry practice,
contractual terms, management’s intent, and estimated economic lives.
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We cannot currently estimate the fair value for certain AROs primarily because we cannot estimate settlement dates (or ranges of
dates) associated with these assets. These AROs include hazardous materials disposal (such as petroleum manufacturing
by-products, chemical catalysts, and sealed insulation material containing asbestos) and removal or dismantlement
requirements associated with the closure of our refining facilities, terminal facilities, or pipelines, including the demolition
or removal of certain major processing units, buildings, tanks, pipelines, or other equipment.
DEFERRED T URNAROUND COS T S
Refinery turnaround costs, which are incurred in connection with planned major maintenance activities at our refineries, are
deferred and amortized on a straight-line basis over the period of time estimated until the next planned turnaround (generally
three to five years). During 2021, 2020, and 2019, we recognized deferred turnaround costs of approximately $9.5 million, $49.8
million, and $9.8 million, respectively. Deferred turnaround costs are presented within Other long-term assets on our consoli-
dated balance sheets.
GO ODWIL L AND OT HER IN TANGIBL E A S S E T S
Goodwill represents the amount the purchase price exceeds the fair value of net assets acquired in a business combination.
Goodwill is not amortized, but is tested for impairment annually on October 1. We assess the recoverability of the carrying value
of goodwill during the fourth quarter of each year or whenever events or changes in circumstances indicate that the carrying
amount of the goodwill of a reporting unit may not be fully recoverable. We first assess qualitative factors to determine whether
it is more likely than not that the fair value of the reporting unit is less than its carrying value. If the qualitative assessment
indicates that it is more likely than not that the carrying value of a reporting unit exceeds its estimated fair value, a quantitative
test is required. Under the quantitative test, we compare the carrying value of the net assets of the reporting unit to the
estimated fair value of the reporting unit. If the carrying value exceeds the estimated fair value of the reporting unit, an
impairment loss is recorded. During the year ended December 31, 2020, we recorded goodwill impairment charges of $67.9
million related to our Refining and Retail segments. Please read Note 10—Goodwill and Intangible Assets for further discussion
on the goodwill impairment.
Our intangible assets include relationships with customers, trade names, and trademarks. These intangible assets are
amortized over their estimated useful lives on a straight-line basis. We evaluate the carrying value of our intangible assets
when impairment indicators are present. When we believe impairment indicators may exist, projections of the undiscounted
future cash flows associated with the use of and eventual disposition of the intangible assets are prepared. If the projections
indicate that their carrying values are not recoverable, we reduce the carrying values to their estimated fair values.
ENVIRO NMEN TAL MAT T ER S
We capitalize environmental expenditures that extend the life or increase the capacity of facilities as well as expenditures
that prevent environmental contamination. We expense costs that relate to an existing condition caused by past operations
and that do not contribute to current or future revenue generation. We record liabilities when environmental assessments
and/or remedial efforts are probable and can be reasonably estimated. Cost estimates are based on the expected timing and
extent of remedial actions required by governing agencies, experience gained from similar sites for which environmental
assessments or remediation have been completed, and the amount of our anticipated liability considering the proportional
liability and financial abilities of other responsible parties. Usually, the timing of these accruals coincides with the completion
of a feasibility study or our commitment to a formal plan of action. Estimated liabilities are not discounted to present value
and are presented within Other liabilities on our consolidated balance sheets. Environmental expenses are recorded in
Operating expense (excluding depreciation) on our consolidated statements of operations.
DERIVAT IVE S AND OT HER FINANC IAL IN S T RUMEN T S
We are exposed to commodity price risk related to crude oil and refined products. We manage this exposure through the use
of various derivative commodity instruments. These instruments include exchange traded futures and over-the-counter
(“OTC”) swaps, forwards, and options.
For our forward contracts that are derivatives, we have elected the normal purchase normal sale exclusion, as it is our policy
to fulfill or accept the physical delivery of the product and we will not net settle. Therefore, we did not recognize the
unrealized gains or losses related to these contracts in our consolidated financial statements.
All derivative instruments not designated as normal purchases or sales are recorded in the balance sheet as either assets or
liabilities measured at their fair values. Changes in the fair value of these derivative instruments are recognized currently in
earnings. We have not designated any derivative instruments as cash flow or fair value hedges and, therefore, do not apply
hedge accounting treatment.
In addition, we may have other financial instruments, such as warrants or embedded debt features, that may be classified as
liabilities when either (a) the holders possess rights to net cash settlement, (b) physical or net equity settlement is not in our
control, or (c) the instruments contain other provisions that cause us to conclude that they are not indexed to our equity. Our
embedded derivatives include our obligations to repurchase crude oil and refined products from J. Aron at the termination of
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the Supply and Offtake Agreement and to repay MLC for monthly crude oil and refined product financing under the Washington
Refinery Intermediation Agreement. These liabilities were initially recorded at fair value and subsequently adjusted to fair value
at the end of each reporting period through earnings.
Please read Note 14—Derivatives and Note 15—Fair Value Measurements for information regarding our derivatives and other
financial instruments.
INCOME TA XE S
We use the asset and liability method of accounting for income taxes. Under the asset and liability method, deferred tax
assets and liabilities are recognized for the future tax consequences attributable to differences between the financial
statement carrying amounts of existing assets and liabilities and their respective tax bases and net operating loss (“NOL”) and
tax credit carry forwards. Deferred tax assets and liabilities are measured using enacted income tax rates expected to apply
to taxable income in the years in which those differences are expected to be recovered or settled. The effect on deferred tax
assets and liabilities of a change in income tax rates is recognized in the results of operations in the period that includes the
enactment date. The realizability of deferred tax assets is evaluated quarterly based on a “more likely than not” standard
and, to the extent this threshold is not met, a valuation allowance is recorded.
We have determined that any uncertain tax positions outstanding at December 31, 2021 and 2020 would not have a material
impact on our financial condition, results of operations, or cash flows as any uncertain tax positions taken would have been fully
covered by the Company’s deferred tax assets related to its historical net operating losses and corresponding valuation allowance.
As a general rule, our open years for Internal Revenue Service (“IRS”) examination purposes are 2018, 2019, and 2020.
However, since we have NOL carryforwards, the IRS has the ability to make adjustments to items that originate in a year
otherwise barred by the statute of limitations in order to re-determine tax for an open year to which those items are carried.
Therefore, in a year in which a NOL deduction is claimed, the IRS may examine the year in which the NOL was generated and
adjust it accordingly for purposes of assessing additional tax in the year the NOL deduction was claimed. Any penalties or
interest as a result of an examination will be recorded in the period assessed.
S TO C K-BA S ED COMPEN SAT ION
We recognize the cost of share-based payments on a straight-line basis over the period the employee provides service,
generally the vesting period, and include such costs in General and administrative expense (excluding depreciation) and
Operating expense (excluding depreciation) in the consolidated statements of operations. We account for forfeitures as they
occur. The grant date fair value of restricted stock awards is equal to the market price of our common stock on the date of
grant. The fair value of stock options is estimated using the Black-Scholes option-pricing model as of the date of grant. The
fair value of the discount offered on the employee stock purchase plan is equal to 15% of the market price of our common
stock on the purchase date.
RE VENUE RECO GNI T I O N
REFINING AND RETAIL
Our refining and retail segment revenues are primarily associated with the sale of refined products. We recognize revenues
upon physical delivery of refined products to a customer, which is the point in time at which control of the refined products is
transferred to the customer. The pricing of our refined products is variable and primarily driven by commodity prices. The
refining segment’s contracts with its customers state the terms of the sale, including the description, quantity, delivery
terms, and price of each product sold. Payments from refining and bulk retail customers are generally due in full within 2 to
30 days of product delivery or invoice date. Payments from our other retail customers occur at the point of sale and are
typically collected in cash or occur by credit or debit card. As such, we have no significant financing element to our revenues
and have immaterial product returns and refunds.
We account for certain transactions on a net basis under Financial Accounting Standards Board (“FASB”) ASC Topic 845, “Non-
monetary Transactions.” These transactions include nonmonetary crude oil and refined product exchange transactions,
certain crude oil buy/sell arrangements, and sale and purchase transactions entered into with the same counterparty that are
deemed to be in contemplation with one another.
We made an accounting policy election to apply the sales tax practical expedient, whereby all taxes assessed by a govern-
mental authority that are both imposed on and concurrent with a revenue-producing transaction and collected from our
customers will be recognized on a net basis within Cost of revenues (excluding depreciation).
LOGISTICS
We recognize transportation and storage fees as services are provided to a customer. Substantially all of our logistics
revenues represent intercompany transactions that are eliminated in consolidation.
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COST CL ASSIFICATIONS
Cost of revenues (excluding depreciation) includes the hydrocarbon-related costs of inventory sold, transportation costs of
delivering product to customers, crude oil consumed in the refining process, costs to satisfy our environmental credit
obligations, and certain hydrocarbon fees and taxes. Cost of revenues (excluding depreciation) also includes the unrealized
gains and losses on derivatives and inventory valuation adjustments. Certain direct operating expenses related to our
logistics segment are also included in Cost of revenues (excluding depreciation).
Operating expense (excluding depreciation) includes direct costs of labor, maintenance and services, energy and utility costs,
property taxes, and environmental compliance costs, as well as chemicals and catalysts and other direct operating expenses.
The following table summarizes depreciation and finance lease amortization expense excluded from each line item in our
consolidated statements of operations (in thousands):
Cost of revenues
Operating expense
General and administrative expense
YEAR ENDED DECEMBER 31,
2021
2020
2019
$ 21,903
$ 21,755
$ 16,882
52,338
2,972
56,637
3,429
55,181
3,145
BENEFI T PL AN S
We recognize an asset for the overfunded status or a liability for the underfunded status of our defined benefit pension
plans. The funded status is recorded within Other liabilities on our consolidated balance sheets. Certain changes in the plans’
funded status are recognized in Other comprehensive income (loss) in the period the change occurs.
FAIR VALUE ME A SUREMEN T S
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market
participants at the measurement date (exit price). Fair value measurements are categorized with the highest priority given to
unadjusted quoted prices in active markets for identical assets or liabilities and the lowest priority given to unobservable inputs.
The three levels of the fair value hierarchy are as follows:
Level 1 – Assets or liabilities for which the item is valued based on quoted prices (unadjusted) for identical assets or
liabilities in active markets.
Level 2 – Assets or liabilities valued based on observable market data for similar instruments.
Level 3 – Assets or liabilities for which significant valuation assumptions are not readily observable in the market; instruments
valued based on the best available data, some of which is internally-developed and considers risk premiums that a
market participant would require.
The level in the fair value hierarchy within which the fair value measurement is categorized is based on the lowest level input
that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value
measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement
within the fair value hierarchy levels. Our policy is to recognize transfers in and/or out of fair value hierarchy levels as of the
end of the reporting period for which the event or change in circumstances caused the transfer. We have consistently applied
these valuation techniques for the periods presented. The fair value of the J. Aron repurchase obligation and Washington
Refinery Intermediation Agreement derivatives are measured using estimates of the prices and differentials assuming
settlement at the end of the reporting period.
INCOME (LOS S) PER S HARE
Basic income (loss) per share (“EPS”) is computed by dividing net income (loss) attributable to common stockholders by the sum
of the weighted-average number of common shares outstanding and the weighted-average number of shares issuable under the
warrants. The common stock warrants were included in the calculation of basic EPS because they were issuable for minimal
consideration. Basic and diluted EPS are computed taking into account the effect of participating securities. Participating
securities include restricted stock that has been issued but has not yet vested. Please read Note 20—Income (Loss) Per Share for
further information.
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FOREIGN CURRENC Y T R AN SAC T ION S
We may, on occasion, enter into transactions denominated in currencies other than the U.S. dollar, which is our functional
currency. Gains and losses resulting from changes in currency exchange rates between the functional currency and the currency
in which a transaction is denominated are included in Other income (expense), net, in the accompanying consolidated statement
of operations in the period in which the currency exchange rates change.
ACCOUN T ING PRINC IPL E S N OT YE T AD OP T ED
In March 2021, FASB issued ASU No. 2021-04, Earnings Per Share (Topic 260), Debt - Modifications and Extinguishments (Subtopic
470-50), Compensation - Stock Compensation (Topic 718), and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic
815-40): Issuer’s Accounting for Certain Modifications or Exchanges of Freestanding Equity-Classified Written Call Options (“ASU
2021-04”). This ASU clarifies that “modifications or exchanges of freestanding equity-classified written call options (for example,
warrants) that remain equity classified after modification or exchange” be accounted for “as an exchange of the original instrument
for a new instrument.” If the modification or exchange is part of or directly related to a modification or exchange of an existing debt
instrument, revolving debt facility, or line-of-credit, the effect is measured as “the difference between the fair value of the written
call option immediately before its modified or exchanged.” The effect of all other modifications or exchanges should be measured
as the excess of fair value of the modified option over the fair value of the same option immediately before modification or
exchange. In both cases, the effect should be calculated as if cash had been paid in the transaction. The guidance in ASU 2021-04 is
effective for fiscal years beginning after December 15, 2021, with early adoption permitted. This ASU will change the policy under
which we account for derivative contracts classified in equity, of which we have none as of December 31, 2021.
In October 2021, the FASB issued Accounting Standards Update (“ASU”) No. 2021-08, Business Combinations (Topic 805):
Accounting for Contract Assets and Contract Liabilities from Contracts with Customers (“ASU 2021-08”). ASU 2021-08 updates
the current guidance to require that an entity recognize and measure contract assets and contract liabilities acquired in a
business combination in accordance with FASB Accounting Standards Codification (“ASC”) Topic 606 “Revenue from Contracts
with Customers” as if the acquiring entity had originated the contracts. This ASU improves comparability by providing consistent
guidance between revenue contracts with customers acquired in a business combination and those not acquired in a business
combination. The guidance in ASU 2021-08 is effective for fiscal years beginning after December 15, 2022, with early adoption
permitted. This ASU will change the policy under which we account for future business combinations.
ACCOUN T ING PRINC IPL E S AD OP T ED
On December 31, 2020, we adopted ASU No. 2018-14, Disclosure Framework—Changes to the Disclosure Requirements for
Defined Benefit Plans (“ASU 2018-14”), using the required retrospective transition method. This ASU amended, added, and
removed certain disclosure requirements under FASB ASC Topic 715 “Compensation—Retirement Benefits.” Our adoption of
ASU 2018-14 did not have a material impact on our financial condition, results of operations, cash flows, or related disclosures.
On January 1, 2021, we adopted ASU No. 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes (“ASU
2019-12”). We adopted this ASU under the prospective method and information that was presented prior to January 1, 2021 has
not been restated and continues to be reported under the accounting standards in effect for that period. This ASU simplified the
accounting for income taxes by removing certain exceptions to general principles and clarified and amended guidance to
improve consistency under FASB ASC Topic 740 “Income Taxes.” Our adoption of ASU 2019-12 did not have a material impact on
our financial condition, results of operations, and cash flows.
On February 11, 2021, we adopted ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference
Rate Reform on Financial Reporting (“ASU 2020-04”) and ASU No. 2021-01, Reference Rate Reform (Topic 848) (“ASU 2021-01”)
following our execution of an amendment to the Washington Refinery Intermediation Agreement which included transition
guidance on the interest rate of the MLC receivable advances to U.S. Oil (as defined in Note 4—Acquisitions) to be based on
another industry standard benchmark rate that will be effective upon the three-month London Interbank Offered Rate’s
(“LIBOR”) scheduled retirement in 2023. These ASUs provide for optional expedients and allowable exceptions to GAAP to ease
the potential burden in recognizing the effects of reference rate reform, especially in regards to the cessation of LIBOR. ASU
2020-04 and ASU 2021-01 are applicable to contract modifications that meet certain requirements and are entered into
between March 12, 2020 and December 31, 2022. Our adoption of ASUs 2020-04 and 2021-01 did not have a material impact on
our financial condition, results of operations, and cash flows.
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Note 3—Investment in Laramie Energy, LLC
As of December 31, 2021, we owned a 46.0% ownership interest in Laramie Energy, a joint venture entity focused on developing
and producing natural gas in Garfield, Mesa, and Rio Blanco counties, Colorado. As of December 31, 2020, Laramie Energy had a
$400.0 million revolving credit facility secured by a lien on its natural gas and crude oil properties and related assets with a
borrowing base set at $139.7 million. On November 20, 2020, Laramie Energy amended its revolving credit facility, reducing the
borrowing base to $140.0 million, resulting in a borrowing base deficiency of $60.0 million. In conjunction with the borrowing
base deficiency, Laramie entered into a forbearance agreement through June 15, 2021 with its lenders. As of December 31, 2020,
the balance outstanding on the revolving credit facility was approximately $139.7 million.
On July 1, 2021, Laramie Energy entered into a term loan agreement which provided a term loan in the principal amount of
$160 million. Laramie Energy used the proceeds from the term loan to repay the outstanding balance on its revolving credit
facility. The term loan is secured by a lien on its natural gas and crude oil properties and related assets. Under the terms of
the term loan, Laramie Energy is generally prohibited from making future cash distributions to its owners, including us,
except for certain permitted tax distributions. Laramie Energy’s term loan matures on July 1, 2025. As of December 31, 2021,
the term loan had an outstanding balance of $140.1 million.
At March 31, 2020, we conducted an impairment evaluation of our investment in Laramie Energy because of (i) the global
economic impact of the COVID-19 pandemic, (ii) an increase in the weighted-average cost of capital for energy companies,
and (iii) continuing declines in natural gas prices through the first quarter of 2020. Based on our evaluation, we determined
that the estimated fair value of our investment in Laramie Energy was $1.9 million, compared to a carrying value of $47.2
million at March 31, 2020. The fair value estimate was determined using a discounted cash flow analysis based on natural gas
forward strip prices as of March 31, 2020 for the years 2020 and 2021 of the forecast, and a blend of forward strip pricing and
third-party analyst pricing for the years 2022 through 2028. Other significant inputs used in the discounted cash flow analysis
included proved and unproved reserves information, forecasts of operating expenditures, and the applicable discount rate.
As a result, we recorded an other-than temporary impairment charge of $45.3 million in Equity losses from Laramie Energy,
LLC on our consolidated statement of operations for the year ended December 31, 2020. Please read Note 15—Fair Value
Measurements for further information. During the quarter ended June 30, 2020, Laramie Energy incurred additional losses
that reduced the book value of our investment to zero and, as such, as of June 30, 2020, we discontinued the application of
the equity method of accounting for our investment in Laramie Energy.
During the fourth quarter of 2019, Laramie Energy recorded an impairment loss of $355.2 million associated with the carrying
value of proved reserves. As a result of Laramie Energy’s impairment loss and the liquidity impact associated with the previous
maturity of the revolving credit facility in December 2020, we updated the impairment evaluation of our investment in Laramie
Energy as of December 31, 2019. The fair value estimate was determined using a discounted cash flow analysis based on
reserves volumes and natural gas forward strip prices as of December 31, 2019. Based on our evaluation, we determined that
the estimated fair value of our investment in Laramie Energy approximated carrying value as of December 31, 2019.
At September 30, 2019, we conducted an impairment evaluation of our investment in Laramie Energy because of the significant
decline in natural gas prices over the second quarter of 2019 and continued deterioration in the third quarter of 2019. Based on
our evaluation, we determined that the estimated fair value of our investment in Laramie Energy was $51.8 million, compared to
a carrying value of $133.3 million at September 30, 2019. The fair value estimate was determined using a discounted cash flow
analysis based on natural gas forward strip prices as of September 30, 2019 for two years through December 31, 2021. A blend
of 2021 forward strip pricing and third-party analyst pricing was used for years after 2021 through December 31, 2028. Other
significant inputs used in the discounted cash flow analysis included proved and unproved reserves information, forecasts of
operating expenditures, and the applicable discount rate. Based on the significant decline in natural gas prices and the reduced
likelihood that natural gas prices would recover in the near term, we concluded that the decline in the fair value of our invest-
ment in Laramie Energy was other than temporary. As a result, we recorded an impairment charge of $81.5 million in Equity
earnings (losses) from Laramie Energy, LLC on our consolidated statement of operations for the year ended December 31, 2019.
Please read Note 15—Fair Value Measurements for further information.
On March 4, 2019, Laramie entered into a binding agreement to divest an insignificant amount of producing property for
approximately $17.5 million. This divestiture did not result in a change in our ownership percentage.
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The change in our equity investment in Laramie Energy is as follows (in thousands):
Beginning balance
YEAR ENDED DECEMBER 31,
2020
2019
$ 46,905
$ 136,656
Equity earnings (losses) from Laramie Energy (1)
(1,611)
(175,018)
Accretion of basis difference
Adjustment of basis difference (2)
—
—
Impairment of our investment in Laramie Energy
(45,294)
5,018
161,764
(81,515)
Ending balance (1)
$ —
$ 46,905
(1) As of June 30, 2020, we have discontinued the application of the equity method of accounting for our investment in Laramie Energy
because the book value of such investment has been reduced to zero.
(2) Represents the reduction in our basis difference resulting from the asset impairment loss recorded by Laramie Energy for the year
ended December 31, 2019.
Summarized financial information for Laramie Energy is as follows (in thousands):
Current assets
Non-current assets
Current liabilities
Non-current liabilities
YEAR ENDED DECEMBER 31,
2021
2019
(Unaudited)
$ 68,779
$ 34,573
328,571
107,976
177,503
355,538
217,523
93,193
YEAR ENDED DECEMBER 31,
2021
2020
2019
(Unaudited)
Natural gas and oil revenues
$ 221,176
$ 121,893
$ 193,906
Income (loss) from operations
Net income (loss)
99,133
32,476
(2,994)
(360,967)
(22,589)
(380,473)
Laramie Energy’s net income (loss) includes (in thousands):
YEAR ENDED DECEMBER 31,
2021
2020
2019
(Unaudited)
Asset impairment loss
$ —
$ —
$ 355,220
Depreciation, depletion, and amortization
Unrealized (gain) loss on derivative instruments
26,458
32,417
34,966
4,245
82,632
(4,283)
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Note 4—Acquisitions
WA S HING TON ACQUI S I T ION
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 (the “Washington Acquisition”). The Washington
Acquisition included 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 system are strategically located in Tacoma, Washington, and
currently serve the Pacific Northwest market. On January 11, 2019, we completed the Washington Acquisition for a total
purchase price of $326.5 million, including acquired working capital, consisting of cash consideration of $289.5 million and
approximately 2.4 million shares of Par’s common stock with a fair value of $37.0 million issued to the seller of U.S. Oil. The cash
consideration was funded in part through cash on hand, proceeds from borrowings under a new term loan facility entered into
with Goldman Sachs Bank USA, as administrative agent, of $250.0 million (the “Term Loan B”), and proceeds from borrowings
under a term loan from the Bank of Hawaii of $45.0 million (the “Par Pacific Term Loan”). Please read Note 13—Debt for further
information on the Term Loan B and Par Pacific Term Loan. During December 2018 and January 2019, we incurred $4.2 million
and $5.4 million of commitment fees associated with the funding of the Washington Acquisition, respectively. Such commitment
fees are presented as Debt extinguishment and commitment costs on our consolidated statements of operations for the years
ended December 31, 2019 and 2018.
In connection with the consummation of the Washington Acquisition, we assumed the Washington Refinery Intermediation
Agreement with MLC that provides a structured financing arrangement based on U.S. Oil’s crude oil and refined products
inventories and associated accounts receivable. Please read Note 11—Inventory Financing Agreements for further information
on the Washington Refinery Intermediation Agreement.
We accounted for the Washington Acquisition as a business combination whereby the purchase price is allocated to the assets
acquired and liabilities assumed based on their estimated fair values on the date of the acquisition. Goodwill recognized in the
transaction was attributable to opportunities expected to arise from combining our operations with those of the Washington
refinery and the utilization of our net operating loss carryforwards, as well as other intangible assets that do not qualify for
separate recognition. Goodwill recognized as a result of the Washington Acquisition is not expected to be deductible for income
tax reporting purposes.
A summary of the fair value of the assets acquired and liabilities assumed is as follows (in thousands):
Cash
Accounts receivable
Inventories
Prepaid and other assets
Property, plant, and equipment
Operating lease right-of-use assets
Goodwill (1)
Total assets (2)
Obligations under inventory financing agreements
Accounts payable
Current operating lease liabilities
Other current liabilities
Long-term operating lease liabilities
Deferred tax liability
Other non-current liabilities
Total liabilities
Total
$ 16,146
34,954
98,367
5,320
412,766
62,337
42,522
672,412
(116,873)
(55,357)
(21,571)
(18,411)
(40,766)
(92,103)
(804)
(345,885)
$ 326,527
(1) We allocated $24.7 million and $17.8 million of goodwill to our refining and logistics segments, respectively.
(2) We allocated $403.9 million and $268.5 million of total assets to our refining and logistics segments, respectively.
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As of December 31, 2019, we finalized the Washington Acquisition purchase price allocation. We incurred $2.2 million and
$2.6 million of acquisition costs related to the Washington Acquisition for the years ended December 31, 2019 and 2018,
respectively. These costs are included in Acquisition and integration costs on our consolidated statements of operations.
The results of operations of U.S. Oil were included in our results beginning on January 11, 2019. For the year ended December
31, 2019, our results of operations included revenues of $1.2 billion and income before income taxes of $65.8 million related
to U.S. Oil. The following unaudited pro forma financial information presents our consolidated revenues and net income (loss)
as if the Washington Acquisition had been completed on January 1, 2018 (in thousands except per share information):
Revenues
Net income (loss)
Income (loss) per share
Basic
Diluted
YEAR ENDED DECEMBER 31,
2019
2018
$ 5,429,530
$ 136,656
(4,547)
(175,018)
$ (0.09)
$ 1.81
$ (0.09)
$ 1.79
These pro forma results were based on estimates and assumptions that we believe are reasonable. They are not necessarily
indicative of our consolidated results of operations in future periods or the results that actually would have been realized had
we been a combined company during the periods presented. The pro forma results for the years ended December 31, 2019 and
2018, include adjustments to remeasure U.S. Oil’s LIFO inventory reserve as if the Washington Acquisition had been completed
on January 1, 2018, record interest and other debt extinguishment costs related to issuance of the Term Loan B and Par Pacific
Term Loan, and adjust U.S. Oil’s historical depreciation expense as a result of the fair value adjustment to Property, plant, and
equipment, net. The pro forma results for the year ended December 31, 2019 also include an adjustment to eliminate the $64.2
million tax benefit associated with a partial release of our valuation allowance in connection with the Washington Acquisition.
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Note 5—Revenue Recognition
As of December 31, 2021 and 2020, receivables from contracts with customers were $189.9 million and $104.9 million, respectively.
Our refining segment recognizes deferred revenues when cash payments are received in advance of delivery of products to the
customer. Deferred revenue was $10.1 million and $4.1 million as of December 31, 2021 and 2020, respectively. We have elected to
apply a practical expedient not to disclose the value of unsatisfied performance obligations for (i) contracts with an original
expected duration of less than one year and (ii) contracts where the variable consideration has been allocated entirely to our
unsatisfied performance obligation.
The following table provides information about disaggregated revenue by major product line and includes a reconciliation of the
disaggregated revenues to total segment revenues (in thousands):
YEAR ENDED DECEMBER 31, 2021
REFINING
LOGISTICS
RETAIL
Product or service:
Gasoline
Distillates (1)
Other refined products (2)
Merchandise
Transportation and terminalling services
Other revenue
Total segment revenues (3)
$ 1,472,335
$ —
$ 333,396
1,927,851
1,065,555
—
—
5,370
—
—
—
184,734
—
27,057
—
92,004
—
3,959
$ 4,471,111
$ 184,734
$ 456,416
YEAR ENDED DECEMBER 31, 2020
REFINING
LOGISTICS
RETAIL
Product or service:
Gasoline
Distillates (1)
Other refined products (2)
Merchandise
Transportation and terminalling services
Other revenue
Total segment revenues (3)
$ 846,294
$ —
$ 241,003
1,256,618
753,591
—
—
30,198
—
—
—
180,909
—
30,739
—
90,173
—
1,798
$ 2,886,701
$ 180,909
$ 363,713
YEAR ENDED DECEMBER 31, 2019
REFINING
LOGISTICS
RETAIL
Product or service:
Gasoline
Distillates (1)
Other refined products (2)
Merchandise
Transportation and terminalling services
Other revenue
Total segment revenues (3)
$ 1,416,706
$ —
$ 326,304
2,503,981
1,242,401
—
—
4,854
—
—
—
199,226
—
40,189
—
90,480
—
1,916
$ 5,167,942
$ 199,226
$ 458,889
(1) Distillates primarily include diesel and jet fuel.
(2) Other refined products include fuel oil, gas oil, asphalt, and naphtha.
(3) Refer to Note 22—Segment Information for the reconciliation of segment revenues to total consolidated revenues.
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Note 6—Inventories
Inventories at December 31, 2021 and 2020 consisted of the following (in thousands):
December 31, 2021
Crude oil and feedstocks
Refined products and blendstock
Warehouse stock and other (2)
Total
December 31, 2020
Crude oil and feedstocks
Refined products and blendstock
Warehouse stock and other (2)
TITLED
INVENTORY
SUPPLY AND
OFFTAKE
AGREEMENT (1)
TOTAL
$ 102,085
$ 199,282
$ 301,367
179,737
166,341
142,872
—
322,609
166,341
$ 448,163
$ 342,154
$ 790,317
$ 88,307
$75,340
$ 163,647
112,146
70,461
83,601
—
195,747
70,461
Total
$ 270,914
$ 158,941
$ 429,855
(1) Please read Note 11—Inventory Financing Agreements for further information.
(2) Includes $120.1 million and $26.7 million of RINs and environmental credits, reported at the lower of cost or NRV, as of December 31, 2021 and 2020, respectively. Our
renewable volume obligation and other gross environmental credit obligations of $311.0 million and $150.5 million, reported at market value, are included in Other
accrued liabilities on our consolidated balance sheets as of December 31, 2021 and 2020, respectively.
Our reserve for the lower of cost and NRV of inventory was $0.5 million and $10.6 million as of December 31, 2021 and 2020,
respectively. As of December 31, 2021, the current replacement cost exceeded the LIFO inventory carrying value by approximately
$46.0 million. Our LIFO inventories, net of the lower of cost or NRV reserve, were equal to current cost as of December 31, 2020.
Note 7—Prepaid and Other Current Assets
Prepaid and other current assets at December 31, 2021 and 2020 consisted of the following (in thousands):
DECEMBER 31,
2021
2020
Collateral posted with broker for derivative instruments (1)
$ 6,053
$ 1,489
Prepaid insurance
Derivative assets
Deferred inventory financing charges
Other
Total
14,110
1,260
4,073
3,029
14,932
1,346
—
6,881
$ 28,525
$ 24,648
(1) Our cash margin that is required as collateral deposits on our commodity derivatives cannot be offset against the fair value of open
contracts except in the event of default. Please read Note 14—Derivatives for further information.
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Note 8—Property, Plant, and Equipment and Impairment of Long-Lived Assets
Major classes of property, plant, and equipment, including assets acquired under finance leases, consisted of the following
(in thousands):
Land
Buildings and equipment (1)
Other (1)
Total property, plant, and equipment
DECEMBER 31,
2021
2020
$ 153,254
$ 188,096
1,007,608
19,535
974,305
21,477
1,180,397
1,183,878
Less accumulated depreciation, depletion, and amortization
(323,892)
(251,113)
Property, plant, and equipment, net
$ 856,505
$ 932,765
(1) Please read Note 16—Leases for further disclosures and information on finance leases.
Depreciation and finance lease amortization expense was approximately $77.2 million, $81.8 million, and $75.2 million for
the years ended December 31, 2021, 2020, and 2019, respectively.
The Par West refinery was idled in the first quarter of 2020 due to the reduction in demand resulting from the COVID-19 global
pandemic’s effect on the economy. Pursuant to GAAP accounting guidelines, this refinery was deemed abandoned in the fourth
quarter of 2020 due to the following factors: the idling of the assets for more than an insignificant amount of time, the significant
cost to restart the refinery, and a lack of a current plan or timeline to restart the refinery. As a result, in the year ended
December 31, 2020, we recorded impairment charges of $10.7 million, $5.0 million, and $2.2 million in Impairment expense
on our consolidated statement of operations related to the write-offs of Par West property, plant, and equipment, deferred
turnaround costs, and inventory, respectively. For the year ended December 31, 2021, we recorded additional impairment
charges of $0.2 million in Impairment expense on our consolidated statement of operations related to the this idling. Please
read Note 15—Fair Value Measurements for additional information.
For the year ended December 31, 2021, we recorded $1.7 million of Impairment expense on our consolidated statement of
operations related to the impairment of a separate capital project.
Note 9—Asset Retirement Obligations
The table below summarizes the changes in our recorded asset retirement obligations (in thousands):
Beginning balance
Accretion expense
Revision in estimate
Liabilities settled during period
YEAR ENDED DECEMBER 31,
2021
2020
2019
$ 10,636
$ 10,180
$ 9,985
873
3,602
(697)
490
—
(34)
331
—
(136)
Ending balance
$ 14,414
$ 10,636
$ 10,180
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Note 10—Goodwill and Intangible Assets
During the years ended December 31, 2021, 2020, and 2019, the change in the net carrying amount of goodwill was as follows
(in thousands):
Balance at January 1, 2019
Acquisition of U.S. Oil (1)
Balance at December 31, 2019
Impairment expense
Balance at December 31, 2020
Reclassified to assets held for sale
Balance at December 31, 2021
(1) Please read Note 4—Acquisitions for further discussion.
$ 153,397
42,522
195,919
(67,922)
127,997
(735)
$ 127,262
The gross carrying value of goodwill was $160.4 million as of January 1, 2019 and $202.9 million as of December 31, 2019,
2020, and 2021. As of January 1 and December 31, 2019, we had accumulated impairment charges of $7.0 million, and as of
December 31, 2020 and 2021, we had accumulated impairment charges of $74.9 million and $75.6 million, respectively.
At March 31, 2020, we performed a quantitative goodwill impairment test of all of our reporting units due to (i) the global
economic impact of the COVID-19 pandemic and (ii) a steep decline in current and forecasted prices and demand for crude oil
and refined products. As part of our quantitative impairment test, we compared the carrying value of the net assets of the
reporting unit to the estimated fair value of the reporting unit. In assessing the fair value of the reporting units, we primarily
utilized a market approach based on observable multiples for comparable companies within our industry. Our refining reporting
units in Hawaii and Washington were fully impaired and the goodwill associated with our retail reporting unit in Washington and
Idaho was partially impaired, resulting in a charge of $67.9 million in our consolidated statement of operations for the year
ended December 31, 2020. The goodwill impairment expense was allocated to the Refining segment ($38.1 million) and to the
Retail segment ($29.8 million).
Intangible assets consisted of the following (in thousands):
Intangible assets:
Trade names and trademarks
Customer relationships
Other
Total intangible assets
Accumulated amortization:
Trade name and trademarks
Customer relationships
Other
DECEMBER 31,
2021
2020
$ 6,267
$ 6,267
32,064
261
38,592
(5,297)
(17,061)
—
32,064
261
38,592
(5,210)
(14,490)
—
Total accumulated amortization
(22,358)
(19,700)
Net:
Trade name and trademarks
Customer relationships
Other
Total intangible assets, net
970
15,003
261
1,057
17,574
261
$ 16,234
$ 18,892
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Amortization expense was approximately $2.7 million for each of the years ended December 31, 2021, 2020, and 2019.
Our intangible assets related to customer relationships and trade names have an average useful life of 13.5 years.
Expected amortization expense for each of the next five years and thereafter is as follows (in thousands):
YEAR ENDED
AMOUNT
2022
2023
2024
2025
2026
Thereafter
$ 2,658
2,658
1,400
979
979
7,560
$ 16,234
Note 11—Inventory Financing Agreements
The following table summarizes our outstanding obligations under our inventory financing agreements (in thousands):
DECEMBER 31,
2021
2020
Supply and Offtake Agreements
$ 569,158
$ 312,185
Washington Refinery Intermediation Agreement
168,546
111,501
Obligations under inventory financing agreements
$ 737,704
$ 423,686
SUPPLY AND OFF TAKE AGREEMEN T
We have an agreement with J. Aron to support our Hawaii refining operations. Under the agreement, J. Aron may enter
into agreements with third parties whereby J. Aron remits payments to these third parties for refinery procurement
contracts for which we will become immediately obligated to reimburse J. Aron. As of December 31, 2021, we had no
obligations due to J. Aron under this contractual undertakings agreement. On May 4, 2021, we amended the first amended
and restated supply and offtake agreement and extended the term expiry date from May 31, 2021, to June 30, 2021.
On June 1, 2021, we entered into the Second Amended and Restated Supply and Offtake Agreement (“Supply and Offtake
Agreement”), which amended and restated the first amended and restated supply and offtake agreement in its entirety. The
Supply and Offtake Agreement expires May 31, 2024 (as extended, the “Expiration Date”), subject to a one-year extension at
the mutual agreement of the parties at least 120 days prior to the Expiration Date. Under the Supply and Offtake Agreement,
we are subject to an early termination fee if we terminate the Supply and Offtake Agreement on or prior to May 31, 2023.
Under the Supply and Offtake Agreement, Par Hawaii Refining, LLC (“PHR”) is required to maintain minimum liquidity of not
less than $15 million for any three consecutive business days, with at least $7.5 million of such liquidity consisting of cash and
cash equivalents. Commencing on July 1, 2021 (the “Adjustment Date”), the Supply and Offtake Agreement makes available a
discretionary draw facility (the “Discretionary Draw Facility”) to PHR.
During the term of the Supply and Offtake Agreement, J. Aron and we will identify mutually acceptable contracts for the
purchase of crude oil from third parties. Per the agreement, J. Aron will provide up to 150 Mbpd of crude oil to our Hawaii
refinery. Additionally, we agreed to sell and J. Aron agreed to buy, at market prices, refined products produced at our Hawaii
refinery. We will then repurchase the refined products from J. Aron prior to selling the refined products to our retail opera-
tions or to third parties. The agreement also provides for the lease of crude oil and certain refined product storage facilities
to J. Aron. Following the expiration or termination of the agreement, we are obligated to purchase the crude oil and refined
product inventories then owned by J. Aron and located at the leased storage facilities at then-current market prices.
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Though title to the crude oil and certain refined product inventories resides with J. Aron, the Supply and Offtake Agreement
is accounted for similar to a product financing arrangement; therefore, the crude oil and refined products inventories will
continue to be included in our consolidated balance sheets until processed and sold to a third party. Each reporting period,
we record a liability in an amount equal to the amount we expect to pay to repurchase the inventory held by J. Aron based on
current market prices.
Prior to July 1, 2021, the supply and offtake agreements also included a deferred payment arrangement whereby we could
defer payments owed under the agreements up to the lesser of $165 million or 85% of the eligible accounts receivable and
inventory. The deferred amounts under the deferred payment arrangement bore interest at a rate equal to three-month
LIBOR plus 3.50% per annum. We also paid a deferred payment availability fee equal to 0.75% of the unused capacity under
the deferred payment arrangement. As of December 31, 2020, the capacity of the deferred payment arrangement was $80.1
million and we had $78.6 million outstanding.
Effective July 1, 2021, the Discretionary Draw Facility became available to PHR up to but excluding the Expiration Date (the
“Discretionary Draw Commitment Period”). Under the Discretionary Draw Facility, J. Aron agreed to make advances to PHR
from time to time at the request of PHR, subject to the satisfaction of certain conditions precedent, in an aggregate principal
amount at any one time outstanding not to exceed the lesser of $165 million or the sum of the borrowing base, which is
calculated as (x) 85% of the eligible accounts receivables, plus (y) the lesser of $82.5 million and 85% of eligible hydrocarbon
inventory, minus (z) such reserves as established by J. Aron in respect of eligible receivables and eligible hydrocarbon
inventory. The advances under the Discretionary Draw Facility bear interest at a rate equal to three-month LIBOR plus 4.00%
per annum until May 31, 2022. Beginning on June 1, 2022, the advances will bear interest at a rate equal to LIBOR (or LIBOR
equivalent) plus an applicable spread between 3.50% and 4.00% to be determined annually based on certain financial ratios.
We also agreed to pay a discretionary draw availability fee equal to 0.75% of the unused capacity under the Discretionary
Draw Facility. Amounts outstanding under the Discretionary Draw Facility are included in Obligations under inventory
financing agreements on our consolidated balance sheets. Changes in the amount outstanding under the Obligations under
inventory financing agreements are included within Cash flows from financing activities on the consolidated statements of
cash flows. As of December 31, 2021, our outstanding balance under the Discretionary Draw Facility was equal to our borrowing
base of $126.2 million.
Under the supply and offtake agreements, we pay or receive certain fees from J. Aron based on changes in market prices over
time. In 2017, we fixed the market fee for the period from June 1, 2018 through May 2021 for an additional $2.2 million. In 2020,
we fixed the market fee for the period from February 1, 2020 through April 1, 2021 for an additional $0.8 million to be settled in
fifteen payments. In 2021, we entered into multiple contracts to fix certain market fees for the period from May 2021 through
May 2022 for $18.2 million. The amount due to or from J. Aron was recorded as an adjustment to our Obligations under
inventory financing agreements as allowed under the Supply and Offtake Agreement. As of December 31, 2021 and 2020, we
had a payable of $6.2 million and a receivable of $0.5 million, respectively.
WA S HING TO N REFINERY IN T ERMEDIAT I ON AGREEMEN T
In connection with the consummation of the Washington Acquisition, we became a party to the Washington Refinery
Intermediation Agreement with MLC that provides a structured financing arrangement based on U.S. Oil’s crude oil and
refined products inventories and associated accounts receivable. Under this arrangement, U.S. Oil purchases crude oil
supplied from third-party suppliers and MLC provides credit support for such crude oil purchases. MLC’s credit support can
consist of either providing a payment guaranty, causing the issuance of a letter of credit from a third-party issuing bank, or
purchasing crude oil directly from third parties on our behalf. U.S. Oil holds title to all crude oil and refined products inventories
at all times and pledges such inventories, together with all receivables arising from the sales of the same, exclusively to MLC. On
February 11, 2021, we and MLC amended the Washington Refinery Intermediation Agreement and extended the term through
March 31, 2022. This amendment also included transition guidance on the interest rate of the MLC receivable advances to be
based on another industry standard benchmark rate that will be effective upon the scheduled retirement of three-month LIBOR
in 2023. On December 17, 2021, we and MLC amended the Washington Refinery Intermediation Agreement to further extend
the term through December 21, 2022, with an automatic extension to March 31, 2023, upon an ABL extension event, and to
revise certain other terms and conditions in the Washington Refinery Intermediation Agreement.
During the remaining term of the Washington Refinery Intermediation Agreement, MLC will make receivable advances to U.S.
Oil based on an advance rate of 95% of eligible receivables, up to a total receivables advance maximum of $90.0 million (the
“MLC receivable advances”), and additional advances based on crude oil and products inventories. Changes in the amount
outstanding under the MLC receivable advances are included within Cash flows from financing activities on the consolidated
statements of cash flows. The MLC receivable advances bear interest at a rate equal to three-month LIBOR plus 3.25% per
annum. We also agreed to pay an availability fee equal to 1.50% of the unused capacity under the MLC receivable advances.
As part of the November 1, 2019 amendment, the availability fee was amended to equal 0.75% of the unused capacity under
the MLC receivable advances. As of December 31, 2021 and 2020, our outstanding balance included in our Obligations under
inventory financing agreements on our consolidated balance sheets under the MLC receivable advances was equal to our
borrowing base of $54.5 million and $41.1 million, respectively. Additionally, as of December 31, 2021 and 2020, we had
approximately $167.0 million and $93.6 million in letters of credit outstanding through MLC’s credit support, respectively.
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The following table summarizes the inventory intermediation fees, which are included in Cost of revenues (excluding
depreciation) on our consolidated statements of operations, and Interest expense and financing costs, net related to the
intermediation agreements (in thousands):
YEAR ENDED DECEMBER 31,
2021
2020
2019
Net fees and expenses:
Supply and Offtake Agreement
Inventory intermediation fees
$ 21,612
$ 12,034
$ 35,459
Interest expense and financing costs, net
3,015
3,044
5,863
Washington Refinery Intermediation Agreement
Inventory intermediation fees
$ 3,236
$ 4,112
$ 3,734
Interest expense and financing costs, net
4,900
2,791
6,359
The Supply and Offtake Agreement and the Washington Refinery Intermediation Agreement also provide us with the ability to
economically hedge price risk on our inventories and crude oil purchases. Please read Note 14—Derivatives for further information.
Note 12—Other Accrued Liabilities
Other accrued liabilities at December 31, 2021 and 2020 consisted of the following (in thousands):
DECEMBER 31,
2021
2020
Accrued payroll and other employee benefits
$ 19,710
$ 14,916
Gross environmental credit obligations (1)
Other
Total
311,014
150,482
39,700
38,313
$ 370,424
$ 203,711
(1) Gross environmental credit obligations are stated at market as of December 31, 2021 and 2020. Please read Note 15—Fair Value Measure-
ments for further information. A portion of these obligations are expected to be settled with our RINs assets and other environmental
credits, which are presented as Inventories on our consolidated balance sheet and are stated at the lower of cost and net realizable
value. The carrying costs of these assets were $120.1 million and $26.7 million as of December 31, 2021 and 2020, respectively.
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Note 13—Debt
The following table summarizes our outstanding debt (in thousands):
5.00% Convertible Senior Notes due 2021
ABL Credit Facility due 2022
Retail Property Term Loan due 2024
7.75% Senior Secured Notes due 2025
Term Loan B due 2026
12.875% Senior Secured Notes due 2026
Mid Pac Term Loan due 2028
PHL Term Loan due 2030
Principal amount of long-term debt
Less: unamortized discount and deferred financing costs
Total debt, net of unamortized discount and deferred financing costs
Less: current maturities, net of unamortized discount and deferred financing costs
DECEMBER 31,
2021
2020
$ —
$ 48,665
—
—
296,000
215,625
68,250
—
—
579,875
(15,317)
564,558
(10,841)
—
42,494
300,000
228,125
105,000
1,399
5,840
731,523
(22,930)
708,593
(59,933)
Long-term debt, net of current maturities
$ 553,717
$ 648,660
Annual maturities of our long-term debt for the next five years and thereafter are as follows (in thousands):
YEAR ENDED
AMOUNT
2022
2023
2024
2025
2026
Thereafter
$ 12,500
12,500
12,500
308,500
233,875
—
$ 579,875
Additionally, as of December 31, 2021 and 2020, we had approximately $18.5 million and $1.7 million in letters of credit
outstanding, respectively, under the Loan and Security Agreement dated as of December 21, 2017 with certain lenders and
Bank of America, N.A., as administrative agent and collateral agent (the “ABL Credit Facility”). We had $5.9 million and $3.6
million in cash-collateralized letters of credit and surety bonds outstanding as of December 31, 2021 and December 31, 2020,
respectively, under agreements with MLC and under certain other facilities.
Under the ABL Credit Facility, the indentures governing the 7.75% Senior Secured Notes and 12.875% Senior Secured Notes,
and the Term Loan B Facility, our subsidiaries are restricted from paying dividends or making other equity distributions,
subject to certain exceptions.
5.00% CONVERT IBL E S ENI OR N OT E S DUE 2021
In June 2016, we completed the issuance and sale of $115 million in aggregate principal amount of the 5.00% Convertible Senior
Notes in a private placement under Rule 144A (the “Notes Offering”). Affiliates of funds managed by or on behalf of Highbridge
Capital Management, LLC (“Highbridge”) and Whitebox Advisors, LLC (“Whitebox”), our related parties, purchased an aggregate
of $47.5 million and $40.4 million, respectively, principal amount of the 5.00% Convertible Senior Notes in the Notes Offering.
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The 5.00% Convertible Senior Notes bore interest at a rate of 5.00% per year (payable semi-annually in arrears on June 15 and
December 15 of each year, beginning on December 15, 2016) and matured on June 15, 2021. During May, June, and December
2019, we entered into privately negotiated exchange agreements with a limited number of holders (the “Noteholders”) to
repurchase $66.3 million in aggregate principal amount of the 5.00% Convertible Senior Notes held by the Noteholders for an
aggregate of $18.6 million in cash and approximately 3.2 million shares of Par’s common stock with a fair value of $74.3 million.
We recognized a loss of approximately $6.1 million related to the extinguishment of the repurchased 5.00% Convertible Senior
Notes in the year ended December 31, 2019. On June 15, 2021, the remaining $48.7 million aggregate principal amount of the
5.00% Convertible Senior Notes was paid in full at maturity.
ABL C REDI T FAC IL I T Y
Under the ABL Credit Facility, we have a revolving credit facility that provides for revolving loans and for the issuance of letters of
credit (the “ABL Revolver”) with a maximum principal amount at any time outstanding of $85 million subject to a borrowing base.
As of December 31, 2021, the ABL Revolver had no outstanding balance and a borrowing base of approximately $85.0 million.
The revolving loans under the ABL Revolver bear interest at a fluctuating rate per annum equal to (i) during the periods such
revolving loan is a base rate loan, the base rate plus the applicable margin in effect from time to time, and (ii) during the
periods such revolving loan is a LIBOR Loan, at LIBOR for the applicable interest period plus the applicable margin in effect
from time to time. The base rate is equal to (i) daily LIBOR (“LIBOR Daily Floating Rate”) or (ii) if the LIBOR Daily Floating Rate
is unavailable for any reason, a rate as calculated per the agreement (the “Prime Rate”) for such day. We also pay a de
minimis fee for any undrawn amounts available under the ABL Revolver. The maturity date of the ABL Revolver is December
21, 2022, on which date all revolving loans will be due and payable in full. The average effective interest rate for 2021 and
2020 on the ABL Revolver loan was 2.6% and 2.3%, respectively.
The applicable margins for the ABL Credit Facility and advances under the ABL Revolver are as specified below:
ARITHMETIC MEAN OF DAILY
AVAILABILITY (AS A PERCENTAGE
OF THE BORROWING BASE)
APPLICABLE MARGIN FOR LIBOR LOANS
AND BASE RATE LOANS SUBJECT TO
LIBOR DAILY FLOATING RATE
APPLICABLE MARGIN FOR
BASE RATE LOANS SUBJECT
TO THE PRIME RATE
1
2
3
>50%
>30% but ≤50%
≤30%
1.75%
2.00%
2.25%
0.75%
1.00%
1.25%
The obligations of the ABL Borrowers are guaranteed by Par and Par Petroleum, LLC’s existing and future direct or indirect
domestic subsidiaries that are not borrowers under the ABL Credit Facility. The loans and letters of credit issued under the
ABL Credit Facility are secured by a first-priority security interest in and lien on certain assets of the borrowers and the
guarantors, including, among other items, cash and cash equivalents, accounts receivables, and inventory, and excluding the
assets of PHR and U.S. Oil.
On February 2, 2022, Par Petroleum, LLC, Par Hawaii, LLC (“PHL”, formerly known as Par Hawaii, Inc. and includes the assets
previously owned by the dissolved entities Mid Pac Petroleum, LLC and HIE Retail, LLC), Hermes Consolidated, LLC, and
Wyoming Pipeline Company, LLC (collectively, the “ABL Borrowers”), entered into the Amended and Restated Loan and
Security Agreement (as amended from time to time, the “ABL Loan Agreement”) dated as of February 2, 2022. The ABL Loan
Agreement increased the maximum principal amount at any time outstanding under the ABL Revolver to $105 million,
extended the maturity date of the ABL Revolver to February 2, 2025, and modified the ABL Revolver interest rate definitions
to be based on the secured overnight financing rate (“SOFR”) as administered by the Federal Reserve Bank of New York,
among other modifications. Please read Note 24—Subsequent Events for additional information.
PAR PAC IFIC T ERM LOAN AGREEMEN T
On January 9, 2019, we entered into a loan agreement (the “Par Pacific Term Loan Agreement”) with Bank of Hawaii (“BOH”),
pursuant to which BOH made a loan to the Company in the principal amount of $45.0 million, the net proceeds of which were
used to finance the Washington Acquisition (the “Par Pacific Term Loan”).
We terminated and repaid all amounts outstanding under the Par Pacific Term Loan Agreement on March 29, 2019 using the
proceeds from the Retail Property Term Loan (as defined below). We recognized approximately $0.1 million of debt extinguishment
costs related to the unamortized deferred financing costs associated with the Par Pacific Term Loan Agreement in the year ended
December 31, 2019.
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RE TAIL PRO PERT Y T ERM LOAN
On March 29, 2019, Par Pacific Hawaii Property Company, LLC (“Par Property LLC”), our wholly owned subsidiary, entered into a
term loan agreement (the “Retail Property Term Loan”) with BOH, which provided a term loan in the principal amount of $45.0
million. The proceeds from the Retail Property Term Loan were used to repay and terminate the Par Pacific Term Loan Agreement.
The Retail Property Term Loan bore interest based on a floating rate equal to the applicable LIBOR for a one-month interest
period plus 1.5%. The average effective interest rate for 2021 on the Retail Property Term Loan was 1.6%. Principal and
interest payments were payable monthly based on a 20-year amortization schedule, principal prepayments were allowed
subject to applicable prepayment penalties, and the remaining unpaid principal, plus any unpaid interest or other charges,
was due on April 1, 2024, the maturity date of the Retail Property Term Loan. On February 23, 2021, we terminated and
repaid all amounts outstanding under the Retail Property Term Loan. We recognized approximately $1.4 million of debt
extinguishment costs in the year ended December 31, 2021 related to our prepayment of the loan principal.
7.75% S ENI O R S ECURED N OT E S DUE 2025
Our 7.75% Senior Secured Notes bear interest at a rate of 7.750% per year (payable semi-annually in arrears on June 15 and
December 15 of each year, beginning on June 15, 2018) and will mature on December 15, 2025. During the year ended
December 31, 2021, we repurchased and cancelled $4 million in aggregate principal amount of the 7.75% Senior Secured
Notes through two repurchases. As of December 31, 2021, the 7.75% Senior Secured Notes had an outstanding principal
balance of $296.0 million.
The indenture governing the 7.75% Senior Secured Notes contains restrictive covenants limiting the ability of Par Petroleum,
LLC and its Restricted Subsidiaries (as defined in the indenture) to, among other things, incur additional indebtedness, issue
certain preferred shares, create liens on certain assets to secure debt, sell or otherwise dispose of all or substantially all
assets, or pay dividends.
The 7.75% Senior Secured Notes are secured on a pari passu basis by first priority liens (subject to the relative priority of permitted
liens) on substantially all of the property and assets of the Issuers and the subsidiary guarantors, including but not limited to,
material real property now owned or hereafter acquired by the Issuers or subsidiary guarantors and their equipment, intellectual
property, and equity interests, but excluding certain property which is collateral under the ABL Credit Facility, the Supply and
Offtake Agreement, and the Washington Refinery Intermediation Agreement. The 7.75% Senior Secured Notes are fully and
unconditionally guaranteed on a senior secured basis, jointly and severally, by each of Par Petroleum, LLC’s existing wholly owned
subsidiaries (other than Par Petroleum Finance Corp.), and are guaranteed on a senior unsecured basis only as to the payment of
principal and interest by Par Pacific Holdings, Inc. In the future, the 7.75% Senior Secured Notes will be guaranteed on a senior
secured basis by additional subsidiaries of Par Petroleum, LLC that guarantee material indebtedness of the Issuers or otherwise
become obligated with respect to material indebtedness under a credit facility, subject to certain exceptions.
T ERM LOAN B FAC IL I T Y DUE 2026
On January 11, 2019, Par Petroleum, LLC and Par Petroleum Finance Corp. (collectively, the “Issuers”) entered into a new
term loan facility with Goldman Sachs Bank USA, as administrative agent, and the lenders party thereto from time to time
(the “Term Loan B Facility”). Pursuant to the Term Loan B Facility, the lenders made a term loan to the borrowers in the
amount of $250.0 million (“Term Loan B”) on the closing date. The net proceeds from Term Loan B totaled $232.0 million
after deducting the original issue discount, deferred financing costs, and commitment and other fees.
Loans under the Term Loan B bear interest at a rate per annum equal to Adjusted LIBOR (as defined in the Term Loan B
Facility) plus an applicable margin of 6.75% or at a rate per annum equal to Alternate Base Rate (as defined in the Term Loan
B Facility) plus an applicable margin of 5.75%. The average effective interest rate for 2021 on the Term Loan B was 7.0%.
In addition to the quarterly interest payments, the Term Loan B requires quarterly principal payments of $3.1 million. The
Term Loan B matures on January 11, 2026.
The obligations of the borrowers under the Term Loan B Facility are guaranteed by Par Petroleum, LLC’s and Par Petroleum
Finance Corp.’s existing and future direct or indirect domestic subsidiaries and, by Par Pacific Holdings, Inc., with respect to
principal and interest only. The Term Loan B Facility is secured on a pari passu basis by first priority liens (subject to the
relative priority of permitted liens) on substantially all of the property and assets of Par Petroleum, LLC, Par Petroleum
Finance Corp., and their subsidiary guarantors, but excluding certain property which is collateral under the ABL Credit
Facility, the Supply and Offtake Agreement, and the Washington Refinery Intermediation Agreement.
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12.875% S ENI OR S ECURED N OT E S DUE 2026
On June 5, 2020, the Issuers completed the issuance and sale of $105.0 million in aggregate principal amount of 12.875%
Senior Secured Notes in a private placement under Rule 144A and Regulation S of the Securities Act of 1933, as amended.
The net proceeds of $98.8 million from the sale were used for general corporate purposes.
The 12.875% Senior Secured Notes bear interest at an annual rate of 12.875% per year (payable semi-annually in arrears on
January 15 and July 15 of each year, beginning on January 15, 2021) and will mature on January 15, 2026. The indenture for the
12.875% Senior Secured Notes also allows for optional early redemptions, some of which require the Issuers to pay a premium
and some of which have certain other restrictions related to timing and the maximum redeemable principal amount.
On June 14, 2021, we redeemed $36.8 million aggregate principal amount of 12.875% Senior Secured Notes at a redemption
price of 112.875% of the aggregate principal amount of the notes redeemed, plus the accrued and unpaid interest as of the
redemption date. On the redemption date, we paid a premium of approximately $4.7 million and incurred additional debt
extinguishment costs of $1.9 million, which were recorded in Debt extinguishment and commitment costs on our consolidated
statement of operations for the year ended December 31, 2021. As of December 31, 2021, $68.3 million in aggregate principal
amount of the 12.875% Senior Secured Notes remained outstanding.
The obligations of the borrowers under the 12.875% Senior Secured Notes are guaranteed by the Issuers’ existing and future
direct or indirect domestic subsidiaries (other than Par Petroleum Finance Corp.) and by Par Pacific Holdings, Inc., with respect
to principal and interest only. The 12.875% Senior Secured Notes are secured on a pari passu basis by first priority liens (subject
to the relative priority of permitted liens) on substantially all of the property and assets of the Issuers and the subsidiary
guarantors, but excluding certain assets which are collateral under the ABL Credit Facility, the Supply and Offtake Agreement,
and the Washington Refinery Intermediation Agreement.
MID PAC T ERM LOAN
Our Mid Pac Term Loan with American Savings Bank, F.S.B. was payable monthly, bore interest at an annual rate of 4.375%, was
secured by a first-priority lien on the real property purchased with the funds, including leases and rents on the property and the
property’s fixed assets and fixtures, and was guaranteed by Par Petroleum, LLC. The Mid Pac Term Loan was scheduled to mature
on October 18, 2028. On March 12, 2021, we terminated and repaid all amounts outstanding under the Mid Pac Term Loan.
PHL T ERM LOAN
On April 13, 2020, PHL, our wholly owned subsidiary, entered into a Term Loan Agreement (“PHL Term Loan”) with American
Savings Bank F.S.B., which provided a term loan in the principal amount of approximately $6.0 million. The proceeds from the
PHL Term Loan were used to finance PHL’s equity in certain real property.
The PHL Term Loan bore interest at a fixed rate of 2.750% per annum. Principal and interest payments were payable monthly
based on a 25-year amortization schedule, principal prepayments were allowed with no prepayment charge, and the
remaining principal, plus any unpaid interest or other charges, was due on April 15, 2030, the maturity date of the PHL Term
Loan. The PHL Term Loan was guaranteed by Par Petroleum, LLC. On February 23, 2021, we terminated and repaid all
amounts outstanding under the PHL Term Loan.
C ROS S DEFAULT PROVI S I ON S
Included within each of our debt agreements are affirmative and negative covenants and customary cross default provisions
that require the repayment of amounts outstanding on demand unless the triggering payment default or acceleration is
remedied, rescinded, or waived. As of December 31, 2021, we were in compliance with all of our debt instruments.
GUAR AN TO R S
In connection with our shelf registration statement on Form S-3, which was filed with the Securities and Exchange Commission
(“SEC”) and declared effective on February 14, 2022 (“Registration Statement”), we may sell non-convertible debt securities and
other securities in one or more offerings with an aggregate initial offering price of up to $750.0 million. Any non-convertible
debt securities issued under the Registration Statement may be fully and unconditionally guaranteed (except for customary
release provisions), on a joint and several basis, by some or all of our subsidiaries, other than subsidiaries that are “minor” within
the meaning of Rule 3-10 of Regulation S-X (the “Guarantor Subsidiaries”). We have no “independent assets or operations”
within the meaning of Rule 3-10 of Regulation S-X and certain of the Guarantor Subsidiaries may be subject to restrictions on
their ability to distribute funds to us, whether by cash dividends, loans, or advances.
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Note 14—Derivatives
COMM ODI T Y DERIVAT IVE S
We utilize commodity derivative contracts to manage our price exposure in our inventory positions, future purchases of
crude oil, future purchases and sales of refined products, and crude oil consumption in our refining process. The derivative
contracts that we execute to manage our price risk include exchange traded futures, options, and OTC swaps. Our futures,
options, and OTC swaps are marked-to-market and changes in the fair value of these contracts are recognized within Cost of
revenues (excluding depreciation) on our consolidated statements of operations.
We are obligated to repurchase the crude oil and refined products from J. Aron at the termination of the Supply and Offtake
Agreement. Our Washington Refinery Intermediation Agreement contains forward purchase obligations for certain volumes
of crude oil and refined products that are required to be settled at market prices on a monthly basis. We have determined
that these obligations under the Supply and Offtake Agreement and Washington Refinery Intermediation Agreement contain
embedded derivatives. As such, we have accounted for these embedded derivatives at fair value with changes in the fair
value recorded in Cost of revenues (excluding depreciation) on our consolidated statements of operations.
We have entered into forward purchase contracts for crude oil and forward purchases and sales contracts of refined
products. We elect the normal purchases normal sales (“NPNS”) exception for all forward contracts that meet the definition
of a derivative and are not expected to net settle. Any gains and losses with respect to these forward contracts designated as
NPNS are not reflected in earnings until the delivery occurs.
We elect to offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master
netting agreement. Our consolidated balance sheets present derivative assets and liabilities on a net basis. Please read Note
15—Fair Value Measurements for the gross fair value and net carrying value of our derivative instruments. Our cash margin that is
required as collateral deposits cannot be offset against the fair value of open contracts except in the event of default.
Our open futures and OTC swaps expire in April 2022. At December 31, 2021, our open commodity derivative contracts
represented (in thousands of barrels):
CONTRACT T YPE
PURCHASES
SALES
Futures
Swaps
Total
1,100
2,100
3,200
(1,650)
(3,600)
(5,250)
NET
(550)
(1,500)
(2,050)
At December 31, 2021, we also had option collars that economically hedge a portion of our internally consumed fuel at our
refineries. The following table provides information on these option collars at each of our refineries as of December 31, 2021:
Average barrels per month
Weighted-average strike price - floor (in dollars)
Weighted-average strike price - ceiling (in dollars)
Commencement date
Expiry date
DECEMBER 31, 2021
35,833
$ 59.47
$ 75.34
January 2022
December 2022
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IN T ERE S T R AT E DERIVAT IVE S
We are exposed to interest rate volatility in our ABL Revolver, Term Loan B Facility, Supply and Offtake Agreement, and
Washington Refinery Intermediation Agreement. We may utilize interest rate swaps to manage our interest rate risk. As of
December 31, 2020, we had entered into an interest rate swap at an average fixed rate of 3.91% in exchange for the floating
interest rate on the notional amounts due under the Retail Property Term Loan. This swap was set to expire on April 1, 2024,
the maturity date of the Retail Property Term Loan. On February 23, 2021, we terminated and repaid all amounts outstanding
under the Retail Property Term Loan and the related interest rate swap.
Upon redemption of our 5.00% Convertible Senior Notes on or after June 20, 2019 at our election, we were obligated to pay a
make-whole premium equal to the present value of the remaining scheduled payments of interest on the 5.00% Convertible
Senior Notes to be redeemed from the relevant redemption date to the maturity date of June 15, 2021. We determined that
the redemption option and the related make-whole premium represented an embedded derivative that was not clearly and
closely related to the 5.00% Convertible Senior Notes. As such, prior to the maturity date of June 15, 2021, we accounted for
this embedded derivative at fair value with changes in the fair value recorded in Interest expense and financing costs, net on
our consolidated statements of operations. On June 15, 2021, the 5.00% Convertible Senior Notes were repaid in full and the
related embedded derivative was settled.
The following table provides information on the fair value amounts (in thousands) of these derivatives as of December 31, 2021
and 2020 and their placement within our consolidated balance sheets.
The following table summarizes the pre-tax gains (losses) recognized in Net income (loss) on our consolidated statements of
operations resulting from changes in fair value of derivative instruments not designated as hedges charged directly to
earnings (in thousands):
BAL ANCE SHEET LOCATION
2021
2020
Asset (Liability)
Prepaid and other current assets
$ 1,260
$ 1,346
DECEMBER 31,
Commodity derivatives (1)
Commodity derivatives
Other accrued liabilities
J. Aron repurchase obligation derivative
Obligations under inventory financing agreements
MLC terminal obligation derivative
Obligations under inventory financing agreements
Interest rate derivatives
Interest rate derivatives
Other accrued liabilities
Other liabilities
(1,431)
(15,151)
(22,170)
—
—
—
(20,797)
(10,161)
(966)
(2,027)
(1) Does not include cash collateral of $6.1 million and $1.5 million recorded in Prepaid and other current assets and $9.5 million and $9.5 million in Other long-term
assets as of December 31, 2021 and 2020, respectively.
STATEMENT OF OPERATIONS
CL ASSIFICATION
2021
2020
2019
YEAR ENDED DECEMBER 31,
Commodity derivatives
Cost of revenues (excluding depreciation)
$ (22,417)
$ (51,902)
$ (1,547)
J. Aron repurchase obligation derivative
Cost of revenues (excluding depreciation)
5,646
MLC terminal obligation derivative
Cost of revenues (excluding depreciation)
(73,256)
Interest rate derivatives
Interest expense and financing costs, net
104
(20,970)
39,820
(2,265)
(3,912)
(19,326)
(1,506)
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Note 15—Fair Value Measurements
A S S E T S AND L IABIL I T IE S ME A SURED AT FAIR VALUE O N A N ONRECURRING BA S I S
PURCHASE PRICE ALLOCATION OF U.S. OIL
The fair values of the assets acquired and liabilities assumed as a result of the Washington Acquisition were estimated as of
January 11, 2019, the date of the acquisition, using valuation techniques described in notes (1) through (6) below.
FAIR VALUE
VALUATION
TECHNIQUE
Net working capital excluding operating leases
$ (35,854)
Property, plant, and equipment
Operating lease right-of-use assets
Goodwill
Current operating lease liabilities
Long-term operating lease liabilities
Deferred tax liability
Other non-current liabilities
Total
412,766
62,337
42,522
(21,571)
(40,766)
(92,103)
(804)
$ 326,527
(1)
(2)
(3)
(4)
(3)
(3)
(5)
(6)
(1) Current assets acquired and liabilities assumed were recorded at their net realizable value.
(2) The fair value of personal property was estimated using the cost approach. Key assumptions in the cost approach include determining
the replacement cost by evaluating recent purchases of comparable assets or published data, and adjusting replacement cost for eco-
nomic and functional obsolescence, location, normal useful lives, and capacity (if applicable). The fair value of real property was estimated
using the market approach. Key assumptions in the market approach include determining the asset value by evaluating recent purchases
of comparable assets under similar circumstances.
(3) Operating lease right-of-use assets and liabilities were recognized based on the present value of lease payments over the lease term
using the incremental borrowing rate at acquisition of 9.6%.
(4) The excess of the purchase price paid over the fair value of the identifiable assets acquired and liabilities assumed is allocated to goodwill.
(5) The deferred tax liability was determined based on the differences between the tax bases of the assets acquired and the values of those
assets recorded on our consolidated balance sheets as of the date of acquisition.
(6) Other non-current liabilities are related to pension plan obligations. The underfunded status of the defined benefit plan represents the
difference between the fair value of the plan’s assets and the projected benefit obligations.
GOODWIL L
At March 31, 2020, we performed a quantitative goodwill impairment test of all of our reporting units due to (i) the global
economic impact of the COVID-19 pandemic and (ii) a steep decline in current and forecasted prices and demand for crude oil
and refined products. As part of our quantitative impairment test, we compared the carrying value of the net assets of the
reporting unit to the estimated fair value of the reporting unit. In assessing the fair value of the reporting units, we primarily
utilized a market approach based on observable multiples for comparable companies within our industry. Our refining reporting
units in Hawaii and Washington were fully impaired and the goodwill associated with our retail reporting unit in Washington and
Idaho was partially impaired, resulting in a charge of $67.9 million in our consolidated statement of operations for the year
ended December 31, 2020. The goodwill impairment expense was allocated to the Refining segment ($38.1 million) and to the
Retail segment ($29.8 million). We consider the impairment of our goodwill to be a Level 3 fair value measurement.
INVE S T MEN T IN L AR AMIE ENERGY
We evaluate equity method investments for impairment when factors indicate that a decrease in the value of our investment
has occurred and the carrying amount of our investment may not be recoverable. An impairment loss, based on the difference
between the carrying value and the estimated fair value of the investment, is recognized in earnings when an impairment is
deemed to be other than temporary.
At March 31, 2020, we conducted an impairment evaluation of our investment in Laramie Energy because of (i) the global
economic impact of the COVID-19 pandemic, (ii) an increase in the weighted-average cost of capital for energy companies, and
(iii) continuing declines in natural gas prices through the first quarter of 2020. Based on our evaluation, we determined that the
estimated fair value of our investment in Laramie Energy was $1.9 million, compared to a carrying value of $47.2 million at
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March 31, 2020. The fair value estimate was determined using a discounted cash flow analysis based on natural gas forward strip
prices as of March 31, 2020 for the years 2020 and 2021 of the forecast, and a blend of forward strip pricing and third-party
analyst pricing for the years 2022 through 2028. Other significant inputs used in the discounted cash flow analysis included
proved and unproved reserves information, forecasts of operating expenditures, and the applicable discount rate. As part of our
evaluation, we considered the likelihood that NYMEX Henry Hub prices, which declined from an average spot price of $2.29 ($/
MMBtu) at December 31, 2019 to $2.03 ($/MMBtu) in the first quarter of 2020, will recover in the near term. A discount rate of
10% was used to reflect the higher cost of capital under the economic conditions as of March 31, 2020. As a result, we recorded
an other-than temporary impairment charge of $45.3 million in Equity losses from Laramie Energy, LLC on our consolidated
statement of operations for the year ended December 31, 2020.
At September 30, 2019, we conducted an impairment evaluation of our investment in Laramie Energy because of the significant
decline in natural gas prices over the second quarter of 2019 and continued deterioration in the third quarter of 2019. At
September 30, 2019, we determined that the estimated fair value of our investment in Laramie Energy was $51.8 million,
compared to a carrying value of $133.3 million. The fair value estimate was determined using a discounted cash flow analysis
based on natural gas forward strip prices as of September 30, 2019 for two years through December 31, 2021. A blend of 2021
forward strip pricing and third-party analyst pricing was used for years after 2021 through December 31, 2028. Other significant
inputs used in the discounted cash flow analysis included proved and unproved reserves information, forecasts of operating
expenditures, and the applicable discount rate. As part of our evaluation, we considered the likelihood that Colorado Interstate
Gas (“CIG”) prices, which declined from an average spot price of $2.48 ($/MMBtu) in the first quarter of 2019, to $1.84 ($/
MMBtu) in the second quarter of 2019 and $1.77 ($/MMBtu) in the third quarter of 2019, will recover in the near term. A
discount rate of 8% was used to reflect the cost of capital under the economic conditions as of September 30, 2019. As a result,
we recorded an impairment charge of $81.5 million on our statement of operations for the year ended December 31, 2019. We
consider the impairments of our investment in Laramie Energy to be Level 3 fair value measurements.
PAR WE S T REFINERY
Pursuant to GAAP accounting guidelines, the Par West refinery was deemed abandoned in the fourth quarter of 2020 due to
the following factors: the idling of the assets for more than an insignificant amount of time, the significant cost to restart the
refinery, and a lack of a current plan or timeline to restart the refinery. Given the lack of alternative uses of the Par West
refinery assets, we impaired all assets that are not expected to be used as part of our ongoing refining operations in Hawaii
down to their salvage value, which is immaterial. As a result of this evaluation, we recorded an impairment charge of $17.9
million on our statement of operations for the year ended December 31, 2020. For the year ended December 31, 2021, we
recorded $0.2 million of Impairment expense on our consolidated statement of operations related to this idling.
A S S E T S AND L IABIL I T IE S ME A SURED AT FAIR VALUE O N A RECURRING BA S I S
COMMON STOCK WARRANTS
As of December 31, 2019, we had 354,350 common stock warrants outstanding. We estimated the fair value of our outstanding
common stock warrants using the difference between the strike price of the warrant and the market price of our common stock,
which was a Level 3 fair value measurement. As of December 31, 2019, the warrants had a weighted-average exercise price of
$0.09 and a remaining term of 2.67 years. The estimated fair value of the common stock warrants was $23.16 per share as of
December 31, 2019.
During January and March 2020, one of our stockholders and its affiliates exercised 354,350 common stock warrants with a fair
value of $3.9 million. As a result of this cashless transaction, 350,542 shares of common stock were issued. As of December 31,
2021 and 2020, we had no common stock warrants outstanding.
DERIVATIVE INSTRUMENTS
We classify financial assets and liabilities according to the fair value hierarchy. Financial assets and liabilities classified as Level 1
instruments are valued using quoted prices in active markets for identical assets and liabilities. These include our exchange
traded futures. Level 2 instruments are valued using quoted prices for similar assets and liabilities in active markets and inputs
other than quoted prices that are observable for the asset or liability. Our Level 2 instruments include OTC swaps and options.
These derivatives are valued using market quotations from independent price reporting agencies and commodity exchange
price curves that are corroborated with market data. Level 3 instruments are valued using significant unobservable inputs that
are not supported by sufficient market activity. The valuation of the embedded derivatives related to our J. Aron repurchase and
MLC terminal obligations is based on estimates of the prices and differentials assuming settlement at the end of the reporting
period. Estimates of the J. Aron and MLC settlement prices are based on observable inputs, such as Brent and WTI indices, and
unobservable inputs, such as contractual price differentials as defined in the Supply and Offtake Agreement and Washington
Refinery Intermediation Agreement. Such contractual differentials vary by location and by the type of product and range from a
discount of $5.64 per barrel to a premium of $56.77 per barrel as of December 31, 2021. Contractual price differentials are
considered unobservable inputs; therefore, these embedded derivatives are classified as Level 3 instruments. We do not have
other commodity derivatives classified as Level 3 at December 31, 2021 or 2020. Please read Note 14—Derivatives for further
information on derivatives.
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GROSS ENVIRONMENTAL CREDIT OBLIGATIONS
Estimates of our gross environmental credit obligations are based on the amount of RINs or other environmental credits
required to comply with EPA regulations and the market prices of those RINs or other environmental credits as of the end of the
reporting period. The gross environmental credit obligations are classified as a Level 2 instruments as we obtain the pricing
inputs for our RINs and other environmental credits from brokers based on market quotes on similar instruments. Please read
Note 17—Commitments and Contingencies for further information on the EPA regulations related to greenhouse gases.
FINANC IAL S TAT EMEN T IMPAC T
Fair value amounts by hierarchy level as of December 31, 2021 and 2020 are presented gross in the tables below (in thousands):
DECEMBER 31, 2021
LEVEL 1
LEVEL 2
LEVEL 3
GROSS FAIR
VALUE
EFFECT OF
COUNTER-
PART Y
NET TING
NET CARRYING
VALUE ON
BALANCE
SHEET (1)
Assets
Commodity derivatives
$ 4,283
$ 4,513
$ —
$ 8,796
$ (7,536)
$ 1,260
Liabilities
Commodity derivatives
$ (3,964)
$ (5,003)
$ —
$ (8,967)
$7,536
$(1,431)
J. Aron repurchase
obligation derivative
MLC terminal
obligation derivative
Gross environmental
credit obligations (2)
—
—
—
—
—
(15,151)
(15,151)
(22,170)
(22,170)
(311,014)
—
(311,014)
—
—
—
(15,151)
(22,170)
(311,014)
Total (3)
$ (3,964)
$ (316,017)
$ (37,321)
$ (357,302)
$ 7,536
$ (349,766)
DECEMBER 31, 2020
LEVEL 1
LEVEL 2
LEVEL 3
GROSS FAIR
VALUE
EFFECT OF
COUNTER-
PART Y
NET TING
NET CARRYING
VALUE ON
BALANCE
SHEET (1)
Assets
Commodity derivatives
$ 616
$ 1,573
$ —
$ 2,189
$ (843)
$ 1,346
Liabilities
Commodity derivatives
$ (3)
$ (840)
$ —
$ (843)
$ 843
$ —
J. Aron repurchase
obligation derivative
MLC terminal
obligation derivative
Interest rate derivatives
Gross environmental
credit obligations (2)
—
—
—
—
—
—
(20,797)
(20,797)
(10,161)
(10,161)
(2,993)
(150,482)
—
—
(2,993)
(150,482)
—
—
—
—
(20,797)
(10,161)
(2,993)
(150,482)
Total (3)
$ (3)
$ (154,315)
$ (30,958)
$ (185,276)
$ 843
$ (184,433)
(1) Does not include cash collateral of $15.6 million and $11.0 million as of December 31, 2021 and 2020, respectively, included within Prepaid and other current assets and
Other long-term assets on our consolidated balance sheets.
(2) Does not include RINs assets and other environmental credits of $120.1 million and $26.7 million presented as Inventories on our consolidated balance sheet and stated at
the lower of cost and net realizable value as of December 31, 2021 and 2020, respectively.
(3) The interest rate derivative was settled in February 2021, therefore, there is no asset or liability related to the interest rate derivative at December 31, 2021. Please read Note
14—Derivatives for further information.
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A roll forward of Level 3 derivative instruments measured at fair value on a recurring basis is as follows (in thousands):
YEAR ENDED DECEMBER 31,
2021
2020
2019
Balance, beginning of period
$ (30,958)
$ (22,750)
$ (922)
Settlements
Acquired
61,247
(31,328)
—
—
13,263
(8,654)
Total gains (losses) included in earnings
(67,610)
23,120
(26,437)
Balance, end of period
$ (37,321)
$ (30,958)
$ (22,750)
The carrying value and fair value of long-term debt and other financial instruments as of December 31, 2021 and 2020
are as follows (in thousands):
DECEMBER 31, 2021
CARRYING VALUE
FAIR VALUE
ABL Credit Facility due 2022
$ —
$ —
7.75% Senior Secured Notes due 2025 (1)
Term Loan B Facility due 2026 (1)
12.875% Senior Secured Notes due 2026 (1)
290,621
208,903
65,034
299,700
214,827
75,758
5.00% Convertible Senior Notes due 2021 (1) (3)
$ 47,301
$ 50,311
DECEMBER 31, 2020
CARRYING VALUE
FAIR VALUE
ABL Credit Facility due 2022
Retail Property Term Loan due 2024 (2)
7.75% Senior Secured Notes due 2025 (1)
Term Loan B Facility due 2026 (1)
12.875% Senior Secured Notes due 2026 (1)
Mid Pac Term Loan due 2028 (2)
PHL Term Loan due 2030 (2)
—
41,891
293,289
219,708
99,213
1,399
5,792
—
41,891
289,521
215,578
112,901
1,399
5,792
(1) The fair value measurements of the 5.00% Convertible Senior Notes, 7.75% Senior Secured Notes, Term Loan B Facility, and 12.875% Senior
Secured Notes are considered Level 2 measurements in the fair value hierarchy as discussed below.
(2) The fair value measurements of the ABL Credit Facility, Mid Pac Term Loan, Retail Property Term Loan, and PHL Term Loan are considered
Level 3 measurements in the fair value hierarchy.
(3) The carrying value of the 5.00% Convertible Senior Notes excludes the fair value of the equity component, which was classified as equity
upon issuance.
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The fair value of the 5.00% Convertible Senior Notes was determined by aggregating the fair value of the liability and equity
components of the notes. The fair value of the liability component of the 5.00% Convertible Senior Notes was determined
using a discounted cash flow analysis in which the projected interest and principal payments were discounted at an estimated
market yield for a similar debt instrument without the conversion feature. The equity component was estimated based on
the Black-Scholes model for a call option with strike price equal to the conversion price, a term matching the remaining life of
the 5.00% Convertible Senior Notes, and an implied volatility based on market values of options outstanding as of the
measurement date. The outstanding aggregate principal amount of the 5.00% Convertible Senior Notes were paid in full at
maturity on June 15, 2021. The fair value of the 5.00% Convertible Senior Notes was considered a Level 2 measurement in the
fair value hierarchy.
The fair value of the 7.75% Senior Secured Notes, Term Loan B Facility, and 12.875% Senior Secured Notes were determined
using a market approach based on quoted prices. The inputs used to measure the fair value are classified as Level 2 inputs
within the fair value hierarchy because the 7.75% Senior Secured Notes, Term Loan B Facility, and 12.875% Senior Secured
Notes may not be actively traded.
The carrying values of our Retail Property, Mid Pac, and PHL Term Loans were determined to approximate fair value as of
December 31, 2020. The Retail Property and PHL Term Loans were repaid in full on February 23, 2021 and the Mid Pac Term
Loan was repaid in full on March 12, 2021. The fair value of all non-derivative financial instruments recorded in current
assets, including cash and cash equivalents, restricted cash, and trade accounts receivable, and current liabilities, including
accounts payable, approximate their carrying value due to their short-term nature.
Note 16—Leases
We have cancellable and non-cancellable finance and operating lease liabilities for the lease of land, vehicles, office space, retail
facilities, and other facilities used in the storage and transportation of crude oil and refined products. Most of our leases include
one or more options to renew, with renewal terms that can extend the lease term from one to 30 years or more. There are no
material lease arrangements where we are the lessor and no material residual value guarantees associated with any of our leases.
The following table provides information on the amounts (in thousands, except lease term and discount rates) of our ROU
assets and liabilities as of December 31, 2021 and 2020 and their placement within our consolidated balance sheets:
LEASE T YPE
BAL ANCE SHEET LOCATION
DECEMBER 31, 2021
DECEMBER 31, 2020
Assets
Finance
Finance
Finance
Operating
Total right-of-use assets
Liabilities
Current
Finance
Operating
Long-term
Finance
Operating
Total lease liabilities
Weighted-average
remaining lease term (in years)
Finance
Operating
Weighted-average discount rate
Finance
Operating
Property, plant, and equipment
$ 20,556
$ 14,998
Accumulated amortization
Property, plant, and equipment, net
Operating lease right-of-use assets
(8,397)
$12,159
383,824
$395,983
(6,486)
$8,512
357,166
$ 365,678
Other accrued liabilities
Operating lease liabilities
Finance lease liabilities
Operating lease liabilities
$ 1,540
53,640
7,691
335,094
$1,491
56,965
7,925
304,355
$ 397,965
$ 370,736
6.29
11.28
7.46%
6.70%
6.97
10.52
7.93%
7.59%
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The following table summarizes the lease costs recognized in our consolidated statements of operations (in thousands):
LEASE COST T YPE
2021
2020
2019
YEAR ENDED DECEMBER 31,
Finance lease cost
Amortization of finance lease ROU assets
$ 1,913
$ 2,007
$ 1,896
Interest on lease liabilities
Operating lease cost
Variable lease cost
Short-term lease cost
Net lease cost
655
654
521
91,882
106,256
100,384
6,716
1,013
9,802
1,926
11,663
1,874
$ 102,179
$ 120,645
$ 116,338
The following table summarizes the supplemental cash flow information related to leases as follows (in thousands):
LEASE T YPE
2021
2020
2019
YEAR ENDED DECEMBER 31,
Cash paid for amounts included in the measurement of liabilities
Financing cash flows from finance leases
$ 1,914
$ 1,932
$ 2,167
Operating cash flows from finance leases
658
656
507
Operating cash flows from operating leases
89,677
103,270
99,713
Non-cash supplemental amounts
ROU assets obtained in exchange for new finance lease liabilities
ROU assets obtained in exchange for new operating lease liabilities
ROU assets terminated in exchange for release from finance lease liabilities
ROU assets terminated in exchange for release from operating lease liabilities
1,936
97,011
—
6,847
3,476
22,529
—
7,738
963
79,382
—
193
The table below includes the estimated future undiscounted cash flows for finance and operating leases as of December 31, 2021
(in thousands):
2022
2023
2024
2025
2026
Thereafter
Total lease payments
Less amount representing interest
FINANCE
LEASES
OPERATING
LEASES
TOTAL
$ 2,139
$ 77,382
$ 79,521
2,161
1,857
1,702
1,235
2,657
11,751
(2,520)
60,257
52,398
51,291
46,696
236,780
524,804
(136,070)
62,418
54,255
52,993
47,931
239,437
536,555
(138,590)
$ 397,965
Present value of lease liabilities
$ 9,231
$ 388,734
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Additionally, we have $15.6 million and $0.4 million in future undiscounted cash flows for operating leases and finance leases
that have not yet commenced, respectively. These leases are expected to commence when the lessor has made the equipment
or location available to us to operate or begin construction, respectively.
SALE-LEASEBACK TRANSACTION
On February 11, 2021, PHL and Par Hawaii Property Company, LLC (collectively, the “Sellers”), both our wholly owned subsidiaries,
entered into a Purchase Agreement and Escrow Instructions with MDC Coast HI 1, LLC, a subsidiary of Realty Income Corporation
(the “Buyer”), and Fidelity National Title Insurance Company, pursuant to which the Sellers and Buyer agreed to consummate a
sale-leaseback transaction (the “Sale-Leaseback Transactions”). Under the terms of the Purchase Agreement, the Sellers agreed to
sell to the Buyer a total of twenty-two (22) retail convenience store/fuel station properties located in Hawaii (the “Sale-Leaseback
Properties”) for an aggregate cash purchase price of $112.8 million, net of transaction fees.
On February 23, 2021, the Sellers and Buyer closed the Sale-Leaseback Transactions with respect to twenty-one (21)
Sale-Leaseback Properties for an aggregate cash purchase price of approximately $107.0 million, net of transaction fees. On
March 12, 2021, the Sellers and Buyer closed the sale of one additional property for an aggregate cash purchase price of
approximately $5.8 million, net of transaction fees. We recognized a gain of $63.9 million as a result of these transactions,
which is included in Loss (gain) on sale of assets, net on our consolidated statements of operations for the year ended
December 31, 2021.
Upon the closings of the sales of the Sale-Leaseback Properties, PHL entered into a Master Land and Building Lease Agreement
(the “Lease Agreement”) with the Buyer, pursuant to which, among other things, PHL leased the Sale-Leaseback Properties from
the Buyer, on a commercial triple-net basis, for 15 years unless earlier terminated. The initial lease term may be extended for up
to four five-year renewal terms in accordance with the terms of the Lease Agreement. Under the terms of the Lease Agreement,
PHL is responsible for monthly rent and all expenses related to the leased facilities, including, but not limited to, insurance
premiums, taxes, and other expenses, such as utilities. As a result of the Sale-Leaseback Transactions, we recorded operating
ROU assets and lease liabilities of $81.3 million. Certain of the Sale-Leaseback Properties were treated as failed sale-leaseback
transactions based on the terms of the lease. As such, we retained the book value of the assets and recognized a finance liability
of $12.4 million included in Other accrued liabilities and Other liabilities on our consolidated balance sheet.
In connection with PHL’s entry into the Lease Agreement, Par Petroleum, LLC, our wholly owned subsidiary, entered into a guaranty
agreement in favor of the Buyer, pursuant to which, among other things, Par Petroleum, LLC guaranteed the payment when due of
the monthly rent, and all other additional rent, interest, and charges payable by PHL to the Buyer under the Lease Agreement, and
the performance by PHL of all the material terms, conditions, covenants, and agreements of the Lease Agreement.
Note 17—Commitments and Contingencies
In the ordinary course of business, we are a party to various lawsuits and other contingent matters. We establish accruals for
specific legal matters when we determine that the likelihood of an unfavorable outcome is probable and the loss is reasonably
estimable. It is possible that an unfavorable outcome of one or more of these lawsuits or other contingencies could have a material
impact on our financial condition, results of operations, or cash flows.
TA X AND REL AT ED MAT T ER S
We are also party to various other legal proceedings, claims, and regulatory, tax or government audits, inquiries and investigations
that arise in the ordinary course of business. On January 4, 2022, U.S. Oil & Refining Co. received a letter of determination from the
Washington Department of Revenue related to a tax audit of certain sales of raw vacuum gas oil (“RVGO”) between January 13, 2014
and September 30, 2016. The audit determined that U.S. Oil & Refining Co. did not pay certain taxes on certain sales of RVGO. We
dispute the results of the audit and intend to appeal. By opinion dated September 22, 2021, the Hawaii Attorney General reversed a
prior 1964 opinion exempting various business transactions conducted in Hawaii free trade zones from certain state taxes. We
understand that we and other similarly situated state taxpayers who had previously claimed such exemptions may anticipate an audit
of their state tax returns filed for such prior tax periods. Similarly, on September 30, 2021, we received notice of a complaint filed on
May 17, 2021, on camera and under seal in the first circuit court of the state of Hawaii alleging that Par Hawaii Refining, LLC, Par
Pacific Holdings, Inc. and certain unnamed defendants made false claims and statements in connection with various state tax returns
related to our business conducted within the Hawaii free trade zones, and seeking unspecified damages, penalties, interest and
injunctive relief. We dispute the allegations in the complaint and intend to vigorously defend ourselves in such proceeding. We
believe the likelihood of an unfavorable outcome in these matters to be neither probable nor reasonably estimable.
ENVIRONMEN TAL MAT T ER S
Like other petroleum refiners, our operations are subject to extensive and periodically-changing federal, state, and local
environmental laws and 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.
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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. Except as disclosed below, 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.
WYOMING REFINERY
Our 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. 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 Hermes Consolidated LLC, and its wholly owned subsidiary, Wyoming Pipeline
Company (collectively, “WRC” or “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, 2021, we have accrued $15.6 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 to be incurred over approximately 30 years.
Additionally, we believe the Wyoming refinery will need to modify or close a series of wastewater impoundments in the
next several years and replace those impoundments with a new wastewater treatment system. Based on current 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 Wyoming Refining 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 has declined over time, Wyoming Refining may become subject to new penalty
enforcement action in the next several years, which could involve penalties in excess of $300,000.
REGUL ATION OF GREENHOUSE GASES
The EPA regulates greenhouse gases (“GHG”) under the federal Clean Air Act (“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 federal CAA regulations and we 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.
Furthermore, the EPA is currently 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 the cost of the products we produce, which could have a material adverse effect on our
financial condition, results of operations, or cash flows.
Additionally, the EPA’s final rule updating standards that control toxic air emissions from petroleum refineries imposed
additional controls and monitoring requirements on flaring operations, storage tanks, sulfur recovery units, delayed coking
units and required fenceline monitoring. Compliance with this rule has not had a material impact on our financial condition,
results of operations, or cash flows to date.
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. In June of 2014, the Hawaii Department of Health (“DOH”) adopted regulations that 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 Hawaii refinery’s capacity to materially reduce fuel use and
GHG emissions is limited because most energy conservation measures have already been implemented over the past 20
years. The regulation allows for “partnering” with other facilities (principally power plants) that have already dramatically
reduced greenhouse emissions or are on schedule to reduce CO2 emissions in order to comply independently with the state’s
Renewable Portfolio Standards.
In addition to the Hawaii GHG legislation, the State of Washington and its political subdivisions have passed several climate-focused
laws in 2021 that are relevant to our Tacoma, Washington location. These include a low-carbon fuel standard designed to reduce
the carbon intensity of transportation fuels by twenty percent by 2038 and a “cap and trade”-style program for GHG emissions
covering industrial facilities starting in 2023. As both legislative programs are presently undergoing rulemaking processes at the
Washington Department of Ecology, the contours of both sets of requirements are not yet clear. In addition to action by the State,
on November 16, 2021, the Tacoma City Council adopted its Tideflats and Industrial Land Use Regulations, which prohibits new
petroleum storage and allows for only limited additions of clean fuel infrastructure.
In 2007, the U.S. Congress passed the Energy Independence and Security Act (the “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 “RFS”). In August 2012, the EPA and National Highway Traffic
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Safety Administration (“NHTSA”) jointly adopted regulations that establish vehicle carbon dioxide emissions standards and 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. On
March 31, 2020, the agencies released updated fuel economy and vehicle emissions standards, which provide for an increase in
stringency by 1.5% each year through model year 2026, as compared with the standards issued in 2012 that required 5% annual
increases. Higher fuel economy standards have the potential to reduce demand for our refined transportation fuel products.
Under EISA, the RFS requires an increasing amount of renewable fuel to be blended into the nation’s transportation fuel
supply, up to 36 billion gallons by 2022. Over time, higher annual RFS requirements have the potential to reduce demand for our
refined transportation fuel products. In the near term, the RFS will be satisfied primarily with fuel ethanol blended into gasoline.
We, and other refiners subject to the 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 RINs, to maintain compliance. To the extent that we exceed the minimum volumetric
requirements for blending of renewable fuels, we have the option of retaining these RINs for current or future RFS compliance
or selling those RINs on the open market. On December 21, 2021, EPA published proposed RFS that include retroactive cuts to
earlier 2020 quotas, set 2021 targets at levels of renewable fuels that were actually used, and would establish significantly
higher volume requirements for 2022. Whether that rule will be finalized as proposed and how the final rule will fare in the
courts may significantly alter our obligations to blend renewable fuels or purchase RINs. The RFS 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 2019, the EPA approved year-round sales of E15. There are numerous issues, including state and federal regulatory issues,
that 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 was January 1, 2017, however, approved small volume refineries had until January 1, 2020 to meet the standard. The
Hawaii refinery was required to comply with Tier 3 gasoline standards within 30 months of June 21, 2016, the date it was
disqualified from small volume refinery status. On March 19, 2015, the EPA confirmed the small refinery status of our Wyoming
refinery. The Hawaii refinery, our Wyoming refinery, and our Washington refinery, acquired in January 2019, were all granted
small refinery status by the EPA for 2018. Owing to the receipt of these small refinery exemptions, our net income for the year
ended December 31, 2019 includes $5.3 million of net RINs benefit. All of our refineries were compliant with the final Tier 3
gasoline standard.
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) were 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, RFS, 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.
ENVIRONMEN TAL AGREEMEN T
On September 25, 2013, Par Petroleum, LLC (formerly Hawaii Pacific Energy, a wholly owned subsidiary of Par created for
purposes of the PHR acquisition), Tesoro, and PHR entered into an Environmental Agreement (“Environmental Agreement”)
that allocated responsibility for known and contingent environmental liabilities related to the acquisition of PHR, including a
consent decree.
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INDEMNIFICATION
In addition to its obligation to reimburse us for capital expenditures incurred pursuant to a 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 Environmental 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 date of the closing of the PHR acquisition, any fine, penalty, or
other cost assessed by a governmental authority in connection with violations of environmental laws by PHR prior to the date
of the closing of the PHR acquisition, certain groundwater remediation work, fines, or penalties imposed on PHR by a consent
decree related to acts or omissions of Tesoro prior to the date of the closing of the PHR acquisition, and claims and losses
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.
RECOVERY T RUS T S
We emerged from the reorganization of Delta Petroleum Corporation (“Delta”) on August 31, 2012 (“Emergence Date”),
when the plan of reorganization (“Plan”) was consummated. On the Emergence Date, we formed the Delta Petroleum
General Recovery Trust (“General Trust”). The General Trust was formed to pursue certain litigation against third parties,
including preference actions, fraudulent transfer and conveyance actions, rights of setoff and other claims, or causes of
action under the U.S. Bankruptcy Code and other claims and potential claims that Delta and its subsidiaries (collectively,
“Debtors”) hold against third parties. 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 trustee for the General Trust, 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
accruals owed on account of the remaining claims of the U.S. Government and Noble Energy, Inc.
As of December 31, 2021, two related claims totaling approximately $22.4 million remained to be resolved and we have
accrued approximately $0.5 million representing the estimated value of claims remaining to be settled which are deemed
probable and estimable at period end.
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 stock 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, only 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. Pursuant to the Plan, allowed claims are settled at a ratio of 54.4 shares per $1,000 of claim.
MA JOR CUS TO MER S
We sell a variety of refined products to a diverse customer base. For each of the years ended December 31, 2021 and 2020,
we had one customer in our refining segment that accounted for 13% of our consolidated revenue. No other customer
accounted for more than 10% of our consolidated revenues during the years ended December 31, 2021, 2020, and 2019.
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Note 18—Stockholders’ Equity
COMM ON S TO C K
Our certificate of incorporation contains restrictions on the transfer of certain of our securities in order to preserve the net
operating loss carryovers, capital loss carryovers, general business credit carryovers, and foreign tax credit carryovers, as well as
any “net unrealized built-in loss” within the meaning of Section 382 of the Internal Revenue Service Code, of us or any direct or
indirect subsidiary thereof. These restrictions include provisions regarding approval by our Board of Directors of transfers of
common stock by holders of five percent or more of the outstanding common stock. Our debt agreements restrict the payment
of dividends.
REGI S T R AT ION RIGH T S AGREEMEN T
In connection with our emergence from bankruptcy on August 31, 2012, we entered into a registration rights agreement
(“Registration Rights Agreement”) providing the stockholders party thereto (“Stockholders”) with certain registration rights.
The Registration Rights Agreement states that at any time after the consummation of a qualified public offering, any Stockholder
or group of Stockholders that, together with its or their affiliates, holds more than fifteen percent of the Registrable Shares (as
defined in the Registration Rights Agreement), will have the right to require us to file with the SEC a registration statement for a
public offering of all or part of its Registrable Shares (each a “Demand Registration”), by delivery of written notice to the
company (each, a “Demand Request”).
Within 90 days after receiving the Demand Request, we must file with the SEC the registration statement with respect to the
Demand Registration, subject to certain limitations as set forth in the Registration Rights Agreement. We are required to use
commercially reasonable efforts to cause the registration statement to be declared effective as soon as practicable after such filing.
In addition, subject to certain exceptions, if we propose to register any class of common stock for sale to the public, we are required,
subject to certain conditions, to include all Registrable Shares with respect to which we have received written requests for inclusion.
In connection with the closing of a private placement, we entered into an additional registration rights agreement with the
purchasers of the shares. Under this registration rights agreement, we agreed to file a registration statement relating to the
shares of common stock with the SEC within 60 days after the closing date of the sale which would be declared effective within
180 days of the closing date of the sale. We also agreed to use commercially reasonable efforts to keep the registration
statement effective until the earliest to occur of (i) the disposition of all registrable securities, (ii) the availability under Rule 144
of the Securities Act of 1933, as amended, for each holder of registrable securities to immediately freely resell such registrable
securities without volume restrictions, or (iii) the third anniversary of the effective date of the registration statement.
This registration rights agreement also provides the right for a holder or group of holders of more than $50 million of registrable
securities to demand that we conduct an underwritten public offering of the registrable securities. However, the demanding
holders are limited to a total of three such underwritten offerings, with no more than one demand request for an underwritten
offering made in any 365 day period. Additionally, this registration rights agreement contains customary indemnification rights
and obligations for both us and the holders of registrable securities.
If this registration statement does not remain effective for the applicable effectiveness period described above then from that
date until cured, we must pay, as liquidated damages and not as a penalty, an amount in cash equal to 0.25% of the purchaser’s
allocated purchase price per calendar month, not to exceed 0.75% of the allocated purchase price.
The registration rights granted in each rights agreement are subject to customary indemnification and contribution provisions,
as well as customary restrictions such as suspension periods and, if a registration is for an underwritten offering, limitations on
the number of shares to be included in the underwritten offering imposed by the managing underwriter.
I S SUANC E O F CO MM O N S TO C K
On March 16, 2021, we entered into an underwriting agreement with J.P. Morgan Securities LLC and Goldman Sachs & Co. LLC,
as representatives of the several underwriters named therein, in connection with an underwritten public offering (the “Equity
Offering”) of 5.75 million shares of common stock, par value $0.01 per share, at a public offering price of $16.00 per share. We
completed the issuance of these shares on March 19, 2021. The net proceeds from the Equity Offering were approximately $87.2
million, after deducting underwriting discounts and commissions and offering expenses. We used the net proceeds from the
Equity Offering to repay the remaining $48.7 million in aggregate 5.00% Convertible Senior Notes due at maturity in June 2021
and $36.8 million in aggregate principal amount of 12.875% Senior Secured Notes, and the remainder for general corporate
purposes, including capital expenditures and funding working capital.
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S HARE REPURC HA S E PRO GR AM
On November 10, 2021, the Board authorized and approved a share repurchase program for up to $50 million of the currently
outstanding shares of the Company’s common stock. Under the share repurchase program, the Company intends to repurchase
shares through open market purchases, privately negotiated transactions, block purchases, or otherwise in accordance with
applicable federal and state laws. The share repurchase program does not have a specified end date and may be limited or
terminated at any time without prior notice. During the year ended December 31, 2021, we repurchased 59 thousand shares for
a total of $0.8 million.
INC EN T IVE PL AN S
Our incentive compensation plans are described below.
LONG TERM INCENTIVE PL AN
Under the Par Petroleum Corporation 2012 Long Term Incentive Plan (“Incentive Plan” or “LTIP”), as amended and restated, the
Board, or a committee of the Board, may grant incentive stock options, nonstatutory stock options, restricted stock, restricted
stock units, and performance restricted stock units to directors and other employees or those of our subsidiaries. The maximum
number of shares that may be granted under the LTIP is 9.0 million shares of common stock. At December 31, 2021, 3.9 million
shares were available for future grants and awards under the LTIP.
Restricted stock and restricted stock units awarded under the Incentive Plan are subject to restrictions, terms, and conditions,
including forfeitures, as may be determined by the Board. During the period in which such restrictions apply, unless specifically
provided otherwise in accordance with the terms of the Incentive Plan, the recipient of the restricted stock would be the record
owner of the shares and have all of the rights of a stockholder with respect to the shares, including the right to vote and the right
to receive dividends or other distributions made or paid with respect to the shares. The recipient of restricted stock units shall
not have any of the rights of a stockholder of the Company until such units vest and convert into shares of common stock. The
fair value of the restricted stock and stock units is generally determined based upon the quoted market price of our common
stock on the date of grant. Restricted stock awards generally vest ratably over a four-year period. Restricted stock units do not
vest ratably, rather they generally vest in full at the end of three years, while some restricted stock units vest over the same
period of time with a one-year cliff.
Stock options are issued with an exercise price equal to the fair market value of our common stock on the date of grant and are
subject to such other terms and conditions as may be determined by the Board. The options generally expire eight years from
the grant date, unless granted by the Board for a shorter term. Option grants generally vest ratably over a four-year period.
STOCK PURCHASE PL AN
The Stock Purchase Plan (as amended, the “SPP”) is limited to the Company’s qualifying executive officers and directors who
qualify as accredited investors under Rule 501(a) of the Securities Act of 1933, as amended. The SPP provides that each
participant may, subject to compliance with securities laws and other regulations and only during “window periods” as
described in our insider trading policy as in effect from time to time, until the later to occur of (a) December 31, 2015 or (b)
the eighteen month anniversary of the date that the participant commenced his or her employment or service with us,
purchase, in a single transaction, up to $1 million of shares of our common stock (“the SPP Shares”) at a per share purchase
price equal to the closing price of the common stock on the date of purchase. The sale or transfer of the SPP Shares by such
participant would be limited for the earlier of (i) two years from the date of purchase or (ii) the termination of the participant’s
service with us or any affiliates for any reason. Additionally, the SPP provides that each purchasing participant will be granted a
number of shares of restricted common stock under the Incentive Plan equal to 20% of the SPP Shares purchased with 50% of
the restricted common stock vesting on each of the two annual anniversaries of the date of grant. Each purchasing participant
will also be granted nonstatutory stock options with a 5-year term to purchase a number of shares of common stock under the
Incentive Plan (with an exercise price equal to the Fair Market Value as defined in the Incentive Plan on the date of grant) equal
to certain specified percentages of the SPP Shares purchased based on a Black-Scholes model with 50% of the options vesting on
each of the two annual anniversaries of the date of grant. Such percentages are as follows: 50% for a non-employee chairman of
the Board, 35% for non-employee members of the Board, and 50% - 70% for executive officers.
The following table summarizes our compensation costs recognized in General and administrative expense (excluding depreciation)
and Operating expense (excluding depreciation) under the Incentive Plan and Stock Purchase Plan (in thousands):
YEARS ENDED DECEMBER 31,
2021
2020
2019
Restricted Stock Awards
$ 4,657
$ 3,939
$ 3,490
Restricted Stock Units
Stock Option Awards
$ 1,356
$ 1,510
$ 1,269
$ 1,939
$ 1,660
$ 1,454
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EMPLOYEE STOCK PURCHASE PL AN
Under the Par Pacific Holdings, Inc. 2018 Employee Stock Purchase Plan (“ESPP”), eligible employees may elect to purchase the
Company’s common stock at 85% of the market price on the purchase date. Eligible employees may invest from 0% to 10% of their
annual income subject to a $15 thousand annual maximum. The Board, or a committee of the Board, is authorized to set the market
price discount percentages, any holding periods, and other purchasing terms and timing. The Company’s shareholders ratified the
ESPP on May 8, 2018. The maximum number of shares that may be issued under the ESPP is 500 thousand shares of common stock.
At December 31, 2021, 201 thousand shares remained available under the ESPP.
During each of the years ended December 31, 2021, 2020, and 2019, we recognized $0.2 million of compensation costs in
General and administrative expense (excluding depreciation) and Operating expense (excluding depreciation) related to the
15% discount offered to employees under the ESPP. During the years ended December 31, 2021, 2020, and 2019, employees
purchased 85 thousand, 145 thousand, and 68 thousand shares under the ESPP, respectively.
MANAGEMENT STOCK PURCHASE PL AN
On February 26, 2019, our Board approved the Par Pacific Holdings, Inc. 2019 Management Stock Purchase Plan (the “MSPP”).
The MSPP provides executive management with an opportunity to receive restricted stock units (“RSUs”) by converting a
portion of their cash bonus compensation into RSUs (“Deferred RSUs”) and receiving awards of matching RSUs, the amount of
which are determined by the amount of compensation converted (“Matching RSUs”). A Deferred RSU and a Matching RSU each
represents a right to receive one share of the Company’s common stock in the future, subject to the terms and conditions of the
MSPP, including, but not limited to, vesting requirements. Shares of common stock issued pursuant to awards of Deferred RSUs
and Matching RSUs will be issued from the shares reserved for issuance under the LTIP. As of December 31, 2021, no Deferred
RSUs or Matching RSUs had been issued under the MSPP.
RE S T RIC T ED S TO C K AWARDS AND RE S T RIC T ED S TO C K UNI T S
The following tables summarize our restricted stock activity (in thousands, except per share amounts):
Unvested balance at December 31, 2020
Granted
Vested
Forfeited
Unvested balance at December 31, 2021
SHARES
629
485
(292)
(62)
760
WEIGHTED-
AVERAGE
GRANT DATE
FAIR VALUE
$ 16.89
16.38
14.97
17.50
$ 17.19
YEARS ENDED DECEMBER 31,
2021
2020
2019
Weighted-average grant-date fair value per share of restricted
$ 16.38
$ 16.97
$ 17.43
stock awards and restricted stock units granted (in dollars)
Fair value of restricted stock awards and restricted stock units vested
$ 4,370
$ 3,787
$ 3,693
As of December 31, 2021 and 2020, there were approximately $9.0 million and $7.1 million of total unrecognized compensation
costs related to restricted stock awards and restricted stock units, which are expected to be recognized on a straight-line basis
over a weighted-average period of 1.74 years and 1.68 years, respectively.
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PERFO RMANC E RE S T RIC T ED S TO C K UNI T S
The following tables summarize our performance restricted stock activity (in thousands, except per unit amounts):
Unvested balance at December 31, 2020
Granted
Vested
Forfeited
Unvested balance at December 31, 2021
UNITS
139
64
(45)
—
158
WEIGHTED-
AVERAGE
GRANT DATE
FAIR VALUE
$ 18.02
16.52
17.34
—
$ 17.61
YEARS ENDED DECEMBER 31,
2021
2020
2019
Weighted-average grant-date fair value per share
$ 16.52
$ 19.73
$ 17.00
of performance restricted stock units granted (in dollars)
Fair value of performance restricted stock units granted
$ 1,053
$ 919
$ 811
Performance restricted stock units are subject to certain annual performance targets based on three-year performance
periods as defined by our Board. As of December 31, 2021 and 2020, there were approximately $1.1 million and $1.0 million
of total unrecognized compensation costs related to the performance restricted stock units, which are expected to be
recognized on a straight-line basis over a weighted-average period of 1.76 years and 1.75 years, respectively.
S TO C K O P T IO N GR AN T S
The fair value of each option is estimated on the grant date using the Black-Scholes option pricing model. The expected term
represents the period of time that options are expected to be outstanding and is based upon the term of the option. The
expected volatility represents the extent to which our stock price is expected to fluctuate between the grant date and the
expected term of the award. We do not use an expected dividend yield in our fair value measurement as we are restricted
from the payment of dividends. The risk-free rate is the implied yield available on U.S. Treasury securities with a remaining
term equal to the expected term of the option at the date of grant. The weighted-average assumptions used to measure
stock options granted during 2021, 2020, and 2019 are presented below.
Expected life from date of grant (in years)
Expected volatility
Risk-free interest rate
2021
5.3
53.2%
0.64%
2020
5.3
33.2%
1.31%
2019
5.3
34.3%
2.46%
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The following table summarizes our stock option activity (in thousands, except per share amounts and term years):
NUMBER OF
OPTIONS
WEIGHTED -
AVER AGE
EXERCISE
PRICE
WEIGHTED -
AVER AGE
REMAINING
CONTR ACTUAL
TERM IN YEARS
AGGREGATE
INTRINSIC
VALUE
Outstanding balance at December 31, 2020
2,128
$ 19.26
4.1
$ —
Issued
Exercised
Forfeited / canceled / expired
Outstanding balance at December 31, 2021
Exercisable, end of year
382
(4)
(311)
2,195
1,400
16.52
14.60
21.29
$ 18.50
$ 19.07
4.2
3.0
$ 446
$ 446
The estimated weighted-average grant-date fair value per share of options granted during the year ended December 31, 2021,
2020, and 2019 was $7.72, $6.30, and $5.98, respectively.
As of December 31, 2021 and 2020, there were approximately $3.8 million and $2.8 million of total unrecognized compensation
costs related to stock option awards, which are expected to be recognized on a straight-line basis over a weighted-average
period of 1.76 years and 1.68 years, respectively.
Note 19—Benefit Plans
DEFINED CO N T RIBU T I O N PL AN S
We maintain defined contribution plans for our employees. All eligible employees, including our U.S. Oil & Refining Co. employees
beginning January 1, 2020, may participate in our Par plan after thirty days of service. For all employees participating in the Par
plan, excluding participating U.S. Oil union employees, we match employee contributions up to a maximum of 6% of the employee’s
eligible compensation, with the employer contributions vesting at 100%. Beginning in January 2021 and as part of cost reductions
in response to the impact of the COVID-19 pandemic on our businesses, we temporarily suspended matching employee contribu-
tions for salaried employees with 2020 annual earnings in excess of the IRS highly compensated limit of $130,000. In January 2022,
we resumed matching of all previously-suspended employee contributions. For the years ended December 31, 2021, 2020, and
2019, we made contributions to the plans totaling approximately $3.1 million, $5.6 million, and $5.6 million, respectively.
DEFINED BENEFI T PL AN S
We maintain defined benefit pension plans (the “Benefit Plans”) covering eligible Wyoming Refining employees and the
employees of U.S. Oil covered by a collective bargaining agreement. Benefits under our Wyoming Refining plan are based on
years of service and the employee’s highest average compensation received during five consecutive years of the last ten
years of employment. Benefits under our U.S. Oil plan are based on the employee’s hourly rate of compensation at the
beginning of each year of employment. Our funding policy is to contribute annually an amount equal to the pension expense,
subject to the minimum funding requirements of the Employee Retirement Income Security Act of 1974 and the tax deductibility
of such contributions. In December 2016, the Wyoming Refining plan was amended to freeze all future benefit accruals for
salaried employees.
In March 2021, the Wyoming Refining plan was amended (the “Plan Amendment”) to freeze all future benefit accruals for
hourly plan participants. The Plan Amendment reduced the projected benefit obligation by $6.0 million. We recorded a $2.0
million Gain on curtailment of pension obligation in our consolidated statements of operations for the year ended December
31, 2021, and an unrealized actuarial gain of $4.0 million as Other post-retirement benefits income (loss), net of tax, in our
consolidated statements of other comprehensive income for the year ended December 31, 2021. Similar to the evaluation
done for the estimate as of December 31, 2020, the projected benefit obligation estimate was determined based on the
present value of projected future benefit payments. In determining the discount rate, we used pricing and yield information
for high-quality corporate bonds that result in payments similar to the estimated distributions of benefits from our plans. The
weighted average discount rate used to determine benefit obligations increased from 2.65% to 3.25%, or 23%, from December
31, 2020 to March 31, 2021. The estimated rate of compensation increase remained 3% at the time of curtailment.
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The changes in the projected benefit obligation and the fair value of plan assets of our Benefit Plans for the years ended
December 31, 2021 and 2020 were as follows (in thousands):
Changes in projected benefit obligation:
Projected benefit obligation as of the beginning of the period
$ 60,479
$ 52,142
2021
2020
Service cost
Interest cost
Plan amendment
Actuarial loss (gain) (1)
Benefits paid
Curtailment
1,140
1,538
(446)
(2,508)
(1,760)
(2,032)
1,347
1,642
—
7,038
(1,690)
—
Projected benefit obligation as of the end of the period
$ 56,411
$ 60,479
Changes in fair value of plan assets:
Fair value of plan assets as of the beginning of the period
$ 46,161
$ 42,866
Actual return (loss) on plan assets
Employer contributions
Benefits paid
5,420
—
(1,760)
4,860
125
(1,690)
Fair value of plan assets as of the end of the period
$ 49,821
$ 46,161
(1) For the year ended December 31, 2021, the change in the actuarial gain was due to an increase in the discount rate and strong asset
performance. For the year ended December 31, 2020, the change in the actuarial loss was due to a decrease in the discount rate, new
entrants to the plan, and salary changes, partially offset by demographic assumption changes.
The underfunded status of our Benefit Plans is recorded within Other liabilities on our consolidated balance sheets.
The reconciliation of the underfunded status of our Benefit Plans of December 31, 2021 and 2020 was as follows:
Projected benefit obligation
Fair value of plan assets
Underfunded status
Gross amounts recognized in accumulated other
comprehensive income (loss): (1)
Net actuarial gain
Total accumulated other comprehensive income
Net actuarial gain (loss)
2021
2020
$ 56,411
$ 60,479
49,821
46,161
$ 6,590
$ 14,318
$ (704)
$ (6,946)
$ (704)
$ (6,946)
$ (704)
$ (6,946)
(1) For the year ended December 31, 2021, we recognized an immaterial amount of service costs in accumulated other comprehensive income.
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Weighted-average assumptions used to measure our projected benefit obligation as of December 31, 2021, 2020, and 2019 and
net periodic benefit costs for the years ended December 31, 2021, 2020 and 2019 are as follows:
Projected benefit obligation:
Wyoming Refining plan
Discount rate (1)
Rate of compensation increase
U.S. Oil plan
Discount rate (1)
Rate of compensation increase
Net periodic benefit costs:
Wyoming Refining plan
Discount rate (1)
Expected long-term rate of return (2)
Rate of compensation increase
U.S. Oil plan
Discount rate (1)
Expected long-term rate of return (2)
Rate of compensation increase
2021
2020
2019
2.85%
—%
2.70%
3.00%
3.25%
5.75%
3.00%
2.35%
6.00%
3.00%
2.65%
3.00%
2.35%
3.00%
3.30%
6.25%
3.00%
3.10%
6.00%
3.00%
3.30%
3.00%
3.10%
3.00%
4.20%
6.50%
3.00%
4.10%
6.00%
3.00%
(1) In determining the discount rate, we use pricing and yield information for high-quality corporate bonds that result in payments similar
to the estimated distributions of benefits from our plans.
(2) The expected long-term rate of return is based on the target asset allocation of each plan and capital market assumptions developed
using forward-looking models and historical market data and trends.
The net periodic benefit cost (credit) for the years ended December 31, 2021, 2020, and 2019 includes the following components:
Components of net periodic benefit cost (credit):
Service cost
Interest cost
Expected return on plan assets
Amortization of net loss
Amortization of prior service cost
Effect of curtailment
2021
2020
2019
$ 1,140
$ 1,347
$ 910
1,538
(2,375)
245
—
(2,032)
1,642
(2,323)
176
1
—
1,794
(1,972)
95
3
—
Net periodic benefit cost (credit)
$ (1,484)
$ 843
$ 830
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The Service cost component of net periodic benefit cost is included in Operating expense (excluding depreciation) on our
consolidated statement of operations for the years ended December 31, 2021, 2020, and 2019. The other components of net
periodic benefit cost are included in Other income (expense), net on our consolidated statement of operations for the years
ended December 31, 2021, 2020, and 2019.
The weighted-average asset allocation for our Wyoming Refining plan at December 31, 2021 is as follows:
Asset category:
Equity securities
Debt securities
Real estate
Total
TARGET
ACTUAL
54%
35%
11%
100%
56%
31%
13%
100%
The weighted-average asset allocation for our U.S. Oil plan at December 31, 2021 is as follows:
Asset category:
Equity securities
Debt securities
Cash and Cash Equivalents
Total
TARGET
ACTUAL
56%
43%
1%
100%
58%
42%
—
100%
We have a long-term, risk-controlled investment approach using diversified investment options with minimal exposure to
volatile investment options like derivatives. Our Benefit Plans’ assets are invested in pooled separate accounts administered
by the Benefit Plans’ custodians. The underlying assets in the pooled separate accounts are invested in equity securities, debt
securities, real estate, or cash and cash equivalents. The pooled separate accounts are valued based upon the fair market
value of the underlying investments and are deemed to be Level 2.
We do not intend to make any contributions to the Wyoming Refining plan or U.S. Oil plan during 2022. Based on current data
and assumptions, the following benefit payments, which reflect expected future service, as appropriate, are expected to be
paid over the next 10 years:
YEAR ENDED
AMOUNT
2022
2023
2024
2025
2026
Thereafter
$ 2,193
2,297
2,313
2,464
2,661
13,424
$ 25,352
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Note 20—Income (Loss) Per Share
Basic income (loss) per share is computed by dividing net income (loss) attributable to common stockholders by the sum of the
weighted-average number of common shares outstanding and the weighted-average number of shares issuable under the common
stock warrants, representing 61 thousand shares during the year ended December 31, 2020 and 354 thousand shares during the
year ended December 31, 2019. The common stock warrants are included in the calculation of basic income (loss) per share for the
years ended December 31, 2020 and 2019 because they were issuable for minimal consideration. As of March 31, 2020, the
previously outstanding common stock warrants had been exercised for common stock and no warrants were outstanding.
The following table sets forth the computation of basic and diluted income (loss) per share (in thousands, except per share amounts):
Net income (loss)
Less: Undistributed income allocated to participating securities (1)
Net income (loss) attributable to common stockholders
Plus: Net income effect of convertible securities
YEAR ENDED DECEMBER 31,
2021
2020
2019
$ (81,297)
$ (409,086)
$ 40,809
—
—
(81,297)
(409,086)
—
—
438
40,371
—
Numerator for diluted income (loss) per common share
$ (81,297)
$ (409,086)
$ 40,371
Basic weighted-average common stock shares outstanding
Plus: dilutive effects of common stock equivalents (2)
Diluted weighted-average common stock shares outstanding
Basic income (loss) per common share
Diluted income (loss) per common share
Diluted income (loss) per common share excludes the following equity
instruments because their effect would be anti-dilutive:
Shares of unvested restricted stock
Shares of stock options
Common stock equivalents using the if-converted method of
settling the 5.00% Convertible Senior Notes
58,268
—
58,268
53,295
—
53,295
50,352
118
50,470
$ (1.40)
$ (7.68)
$ 0.80
$ (1.40)
$ (7.68)
$ 0.80
925
2,386
1,230
475
2,229
2,704
182
1,577
5,122
(1) Participating securities include restricted stock that has been issued but had not yet vested. These participating securities were fully vested as of December 31, 2019.
(2) Entities with a net loss from continuing operations are prohibited from including potential common shares in the computation of diluted per share amounts. We have
utilized the basic shares outstanding to calculate both basic and diluted loss per common share for the years ended December 31, 2021 and 2020.
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Note 21—Income Taxes
As of December 31, 2021, we had approximately $1.6 billion in net operating loss carryforwards (“NOL carryforwards”);
however, we currently have a valuation allowance against this and substantially all of our other deferred tax assets. In
assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion
or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the
generation of future taxable income during the periods in which those temporary differences become deductible. For the
year ended December 31, 2021, we recorded an income tax expense of $1.0 million primarily driven by foreign withholding
taxes. For the year ended December 31, 2020, we recorded an income tax benefit of $20.7 million primarily driven by an
increase in our net operating loss carryforwards and the change in our indefinitely-lived goodwill due to the impairments. For
the year ended December 31, 2019, we recorded an income tax benefit of $69.7 million primarily driven by a $64.2 million
benefit associated with the partial release of our valuation allowance in connection with the recognition of deferred tax
liabilities acquired as part of the Washington Acquisition. Management continues to conclude that we did not meet the
“more likely than not” requirement in order to recognize deferred tax assets on the remaining amounts and a valuation
allowance has been recorded for substantially all of our net deferred tax assets at December 31, 2021 and 2020.
In connection with our emergence from bankruptcy on August 31, 2012, we experienced an ownership change as defined
under Section 382 of the Code. Section 382 generally places a limit on the amount of NOL carryforwards and other tax
attributes arising before an ownership change that may be used to offset taxable income after an ownership change. We
believe that we have qualified for an exception to the general limitation rules under Code Section 382(l)(5) which provides for
substantially less restrictive limitations on our NOL carryforwards. Our amended and restated certificate of incorporation
places restrictions upon the ability of certain equity interest holders to transfer their ownership interest in us. These
restrictions are designed to provide us with the maximum assurance that another ownership change does not occur that
could adversely impact our NOL carryforwards.
We believe that any adjustment to our uncertain tax positions would not have a material impact on our financial statements
given the Company’s deferred tax and corresponding valuation allowance position as of December 31, 2021.
Our net taxable income must be apportioned to various states based upon the income tax laws of the states in which we derive
our revenue. Our NOL carryforwards will not always be available to offset taxable income apportioned to the various states.
The states from which our refining, logistics, and retail revenues are derived are not the same states in which our NOLs were
incurred; therefore, we expect to incur state tax liabilities in connection with our refining, logistics, and retail operations.
We will continue to assess the realizability of our deferred tax assets based on consideration of actual operating results. If
sufficient positive evidence of improving actual operating results becomes available, the amount of the deferred tax asset
considered more likely than not to be recognized would be increased with a corresponding reduction in income tax expense
in the period recorded.
Income tax expense (benefit) consisted of the following (in thousands):
Current:
U.S.—Federal
U.S.—State
Foreign
Deferred:
U.S.—Federal
U.S.—State
Total
YEAR ENDED DECEMBER 31,
2021
2020
2019
$ —
$ —
$ (3,203)
26
1,255
(223)
(37)
51
125
400
—
(20,509)
(387)
(58,461)
(8,425)
$ 1,021
$ (20,720)
$ (69,689)
F-52
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Income tax expense was different from the amounts computed by applying U.S. Federal income tax rate to pretax income as
a result of the following:
Federal statutory rate
State income taxes, net of federal benefit
Foreign taxes
Change in valuation allowance related to current activity
Permanent items
Provision to return adjustments and other
Actual income tax rate
YEAR ENDED DECEMBER 31,
2021
21.0%
—%
(1.6)%
(20.1)%
(0.6)%
—%
(1.3)%
2020
21.0%
0.1%
—%
(14.0)%
(2.3)%
—%
4.8%
2019
21.0%
(1.1)%
—%
227.1%
(4.3)%
(1.4)%
241.3%
Deferred tax assets (liabilities) are comprised of the following (in thousands):
Deferred tax assets:
Net operating loss
Intangible assets
Environmental credit obligations
Other
Total deferred tax assets
Valuation allowance
Net deferred tax assets
Deferred tax liabilities:
Inventory
Property and equipment
Investment in Laramie Energy
Total deferred tax liabilities
Total deferred tax liability, net
DECEMBER 31,
2021
2020
$ 424,112
$ 427,245
1,912
40,097
16,137
482,258
(421,387)
60,871
9,820
56,436
—
66,256
2,958
25,994
22,551
478,748
(411,422)
67,326
10,328
58,122
4,522
72,972
$ (5,385)
$ (5,646)
We have NOL carryforwards as of December 31, 2021 of $1.6 billion for federal income tax purposes. If not utilized, the NOL
carryforwards will expire during 2028 through 2036.
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Note 22—Segment Information
We report the results for the following four reportable segments: (i) Refining, (ii) Logistics, (iii) Retail, and (iv) Corporate and
Other. Commencing January 11, 2019, the results of operations of the Washington Acquisition are included in our refining
and logistics segments.
Summarized financial information concerning reportable segments consists of the following (in thousands):
REFINING
LOGISTICS
RETAIL
CORPOR ATE ,
ELIMINATIONS,
AND OTHER (1)
TOTAL
Revenues
$ 4,471,111
$ 184,734
$ 456,416
$ (402,172)
$ 4,710,089
Cost of revenues (excluding depreciation)
4,306,371
Operating expense (excluding depreciation)
Depreciation, depletion, and amortization
Impairment expense
Loss (gain) on sale of assets, net
General and administrative expense
(excluding depreciation)
Acquisition and integration costs
213,102
58,258
1,838
(19,659)
—
—
96,828
14,722
22,044
—
(19)
—
—
337,476
(402,201)
4,338,474
71,845
10,880
—
(45,034)
—
—
—
3,059
—
15
299,669
94,241
1,838
(64,697)
48,096
48,096
87
87
Operating income (loss)
$ (88,799)
$ 51,159
$ 81,249
$ (51,228)
$ (7,619)
Interest expense and financing costs, net
Debt extinguishment and commitment costs
Gain on curtailment of pension obligation
Other expense, net
Loss before income taxes
Income tax expense
Net loss
Total assets
Goodwill
Capital expenditures
(66,493)
(8,144)
2,032
(52)
(80,276)
(1,021)
$ (81,297)
$ 1,928,987
$ 398,182
$ 228,245
$ 14,837
$ 2,570,251
39,821
15,689
55,232
6,801
32,209
5,917
—
1,126
127,262
29,533
(1) Includes eliminations of intersegment revenues and cost of revenues of $402.2 million for the year ended December 31, 2021.
F-54
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REFINING
LOGISTICS
RETAIL
CORPOR ATE ,
ELIMINATIONS,
AND OTHER (1)
TOTAL
Revenues
$ 2,886,701
$ 180,909
$ 363,713
$ (306,453)
$ 3,124,870
Cost of revenues (excluding depreciation)
2,908,870
110,385
234,885
(306,443)
2,947,697
Operating expense (excluding depreciation)
199,738
Depreciation, depletion, and amortization
Impairment expense
General and administrative expense
(excluding depreciation)
Acquisition and integration costs
53,930
55,989
—
—
13,581
21,899
—
—
—
64,108
10,692
29,817
—
—
—
3,515
—
41,288
277,427
90,036
85,806
41,288
614
614
Operating income (loss)
$ (331,826)
$ 35,044
$ 24,211
$ (45,427)
$ (317,998)
Interest expense and financing costs, net
Debt extinguishment and commitment costs
Other income, net
Change in value of common stock warrants
Equity losses from Laramie Energy, LLC
Loss before income taxes
Income tax benefit
Net loss
Total assets
Goodwill
Capital expenditures
(70,222)
—
1,049
4,270
(46,905)
(429,806)
20,720
$ (409,086)
$ 1,478,603
$ 444,800
$ 193,365
$ 17,093
$ 2,133,861
39,821
38,781
55,232
20,898
32,944
2,547
—
1,296
127,997
63,522
(1) Includes eliminations of intersegment revenues and cost of revenues of $306.5 million for the year ended December 31, 2020.
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REFINING
LOGISTICS
RETAIL
CORPOR ATE ,
ELIMINATIONS,
AND OTHER (1)
TOTAL
Revenues
$ 5,167,942
$ 199,226
$ 458,889
$ (424,541)
$ 5,401,516
Cost of revenues (excluding depreciation)
4,783,747
112,124
332,302
(424,584)
4,803,589
Operating expense (excluding depreciation)
Depreciation, depletion, and amortization
General and administrative expense
(excluding depreciation)
Acquisition and integration costs
234,582
55,832
—
—
11,010
17,017
—
—
67,307
10,035
—
—
—
3,237
46,223
312,899
86,121
46,223
4,704
4,704
Operating income (loss)
$ 93,781
$ 59,075
$ 49,245
$ (54,121)
$ 147,980
Interest expense and financing costs, net
Debt extinguishment and commitment costs
Other income, net
Change in value of common stock warrants
Change in value of contingent consideration
Equity losses from Laramie Energy, LLC
Loss before income taxes
Income tax benefit
Net income
Total assets
Goodwill
Capital expenditures
(74,839)
(11,587)
2,516
(3,199)
—
(89,751)
(28,880)
69,689
$ 40,809
$ 1,907,318
$ 494,209
$ 232,150
$ 66,883
$ 2,700,560
77,927
34,492
55,232
40,730
62,760
6,869
195,919
83,920
1,829
(1) Includes eliminations of intersegment revenues and cost of revenues of $424.5 million for the year ended December 31, 2019.
F-56
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Note 23—Related Party Transactions
CONVERT IBL E N OT E S OFFERING
In June 2016, we issued $115 million in aggregate principal amount of our 5.00% Convertible Senior Notes in a private
placement under Rule 144A in the Notes Offering. Affiliates of Whitebox and Highbridge purchased an aggregate of $47.5
million and $40.4 million, respectively, principal amount of the 5.00% Convertible Senior Notes in the Notes Offering. In June
2021, the remaining aggregate principal amount of the 5.00% Convertible Senior Notes were paid in full at maturity. Please
read Note 13—Debt for further discussion.
EQUI T Y GROUP INVE S T MEN T S (“EGI”) - S ERVIC E AGREEMEN T
On September 17, 2013, we entered into a letter agreement (“Services Agreement”) with Equity Group Investments (“EGI”), an
affiliate of Zell Credit Opportunities Fund, LP (“ZCOF”), which owns 10% or more of our common stock directly or through
affiliates. Pursuant to the Services Agreement, EGI agreed to provide us with ongoing strategic, advisory, and consulting services
that may include (i) advice on financing structures and our relationship with lenders and bankers, (ii) advice regarding public and
private offerings of debt and equity securities, (iii) advice regarding asset dispositions, acquisitions, or other asset management
strategies, (iv) advice regarding potential business acquisitions, dispositions, or combinations involving us or our affiliates, or (v)
such other advice directly related or ancillary to the above strategic, advisory, and consulting services as may be reasonably
requested by us.
EGI does not receive a fee for the provision of the strategic, advisory, or consulting services set forth in the Services Agreement,
but may be periodically reimbursed by us, upon request, for (i) travel and out-of-pocket expenses, provided that, in the event
that such expenses exceed $50 thousand in the aggregate with respect to any single proposed matter, EGI will obtain our
consent prior to incurring additional costs, and (ii) provided that we provide prior consent to their engagement with respect to
any particular proposed matter, all reasonable fees and disbursements of counsel, accountants, and other professionals incurred
in connection with EGI’s services under the Services Agreement. In consideration of the services provided by EGI under the
Services Agreement, we agreed to indemnify EGI for certain losses relating to or arising out of the Services Agreement or the
services provided thereunder.
The Services Agreement has a term of one year and will be automatically extended for successive one-year periods unless
terminated by either party at least 60 days prior to any extension date. There were no costs incurred related to this agreement
during the years ended December 31, 2021, 2020, or 2019.
Note 24—Subsequent Events
On February 2, 2022, Par Petroleum, LLC, PHL, Hermes Consolidated, LLC, and Wyoming Pipeline Company, LLC (collectively, the
“ABL Borrowers”), entered into the Amended and Restated Loan and Security Agreement (as amended from time to time, the
“ABL Loan Agreement”) dated as of February 2, 2022, with certain lenders and Bank of America, N.A., as administrative agent
and collateral agent. The ABL Loan Agreement increases the maximum principal amount of the ABL Revolver at any time
outstanding to $105 million, subject to a borrowing base, including a sublimit of $15 million for swingline loans and a sublimit of
$65 million for the issuance of standby or commercial letters of credit, and extends the maturity date of the ABL Revolver to
February 2, 2025. The ABL Loan Agreement also includes an accordion feature that would allow the ABL Borrowers to increase
the size of the facility by up to $50 million in the aggregate, subject to certain limitations and conditions.
Under the ABL Loan Agreement, the outstanding principal amount of each revolving loan bears interest at a fluctuating rate
per annum equal to (i) during the periods such revolving loan is a base rate loan, the base rate plus the applicable margin in
effect from time to time, and (ii) during the periods such revolving loan is a Term SOFR Loan, at Term SOFR (as defined in the
ABL Loan Agreement) for the applicable interest period plus the applicable margin in effect from time to time. The base rate
for any day is a per annum rate equal to the greater of (a) a rate as calculated per the agreement (the “Prime Rate”) for such
day; (b) a rate as calculated by the Federal Reserve Bank of New York based on such day’s federal funds transactions by
depository institutions (“Federal Funds Rate”) for such day, plus 0.50%; or (c) Term SOFR for a one month interest period as of
such day plus 1.0%, subject to the interest rate floor set forth therein; provided, that in no event shall the base rate be less
than zero. We also pay a de minimis fee for any undrawn amounts available under the ABL Revolver.
Under the ABL Loan Agreement, the applicable margins for the ABL Credit Facility and advances under the ABL Revolver are
as specified below:
ARITHMETIC MEAN OF DAILY
AVAILABILITY (AS A PERCENTAGE
OF THE BORROWING BASE)
TERM SOFR LOANS
BASE RATE LOANS
1
2
3
>50%
>30% but ≤50%
≤30%
1.25%
1.50%
1.75%
0.25%
0.50%
0.75%
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The ABL Loan Agreement requires the ABL Borrowers to comply with certain customary affirmative, as well as certain negative
covenants that, among other things, will restrict, subject to certain exceptions, the ability of the ABL Borrowers and their
guarantors to incur indebtedness, grant liens, make investments, engage in acquisitions, mergers or consolidations and pay
dividends and other restricted payments. Upon the occurrence of a triggering event whereby availability is less than the
greater of (i) $7.5 million and (ii) 12.5% of the borrowing base, the ABL Borrowers are required to comply for at least 30 days
with a minimum fixed charge coverage ratio of 1.00 to 1.00 measured monthly, with respect to (a) Par Petroleum, LLC and its
consolidated subsidiaries, and (b) Par Petroleum, LLC and its consolidated subsidiaries, other than PHR, U.S. Oil, and any other
Future Intermediation Subsidiary (as defined in the ABL Loan Agreement).
ASSETS
Current assets
Cash and cash equivalents
Restricted cash
Total cash, cash equivalents, and restricted cash
Prepaid and other current assets
Due from subsidiaries
Total current assets
Property, plant, and equipment
Property, plant, and equipment
Less accumulated depreciation, depletion, and amortization
Property, plant, and equipment, net
Long-term assets
Operating lease right-of-use (“ROU”) assets
Investment in subsidiaries
Other long-term assets
Total assets
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt
Accounts payable
Accrued taxes
Operating lease liabilities
Other accrued liabilities
Due to subsidiaries
Total current liabilities
Long-term liabilities
Long-term debt, net of current maturities
Finance lease liabilities
Operating lease liabilities
Other liabilities
Total liabilities
Stockholders’ equity
Preferred stock, $0.01 par value: 3,000,000 shares authorized, none issued
Common stock, $0.01 par value; 500,000,000 shares authorized at December
31, 2021 and December 31, 2020, 60,161,955 shares and 54,002,538 shares
issued at December 31, 2021 and December 31, 2020, respectively
Additional paid-in capital
Accumulated deficit
Accumulated other comprehensive income (loss)
Total stockholders’ equity
Total liabilities and stockholders’ equity
This statement should be read in conjunction with the notes to consolidated financial statements.
F-58
DECEMBER 31, 2021
DECEMBER 31, 2020
$ 4,086
$ 480
330
4,416
15,664
94,676
114,756
19,535
(13,869)
5,666
3,280
207,483
724
330
810
16,983
107,995
125,788
21,477
(14,368)
7,109
3,714
209,010
723
$ 331,909
$ 346,344
$ —
$ 47,301
1,386
48
608
9,805
50,195
62,042
—
17
4,150
—
66,209
—
602
821,713
(559,117)
2,502
265,700
2,401
49
750
10,907
33,757
95,165
—
77
4,783
45
100,070
—
540
726,504
(477,028)
(3,742)
246,274
$ 331,909
$ 346,344
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Operating expenses
Depreciation and amortization
Loss (gain) on sale of assets, net
General and administrative expense (excluding depreciation)
Acquisition and integration costs
Total operating expenses
Operating loss
Other income (expense)
Interest expense and financing costs, net
Debt extinguishment and commitment costs
Other income (expense), net
Change in value of common stock warrants
Equity in earnings (losses) from subsidiaries
Total other income (expense), net
Income (loss) before income taxes
Income tax expense
Net income (loss)
This statement should be read in conjunction with the notes to consolidated financial statements.
Net income (loss)
Other comprehensive income (loss): (1)
Other post-retirement benefits income (loss), net of tax
Total other comprehensive income (loss), net of tax
Comprehensive income (loss)
(1) Other comprehensive income (loss) relates to benefit plans at our subsidiaries.
This statement should be read in conjunction with the notes to consolidated financial statements.
YEAR ENDED DECEMBER 31,
2021
2020
2019
$ 2,452
$ 2,900
$ 2,969
15
12,435
87
14,989
(14,989)
—
11,097
—
13,997
(13,997)
—
20,017
28
23,014
(23,014)
(2,600)
(4,982)
(9,952)
—
(33)
—
(63,649)
(66,282)
(81,271)
(26)
—
(3)
4,270
(394,197)
(394,912)
(408,909)
(177)
(6,091)
2,303
(3,199)
81,097
64,158
41,144
(335)
$ (81,297)
$ (409,086)
$ 40,809
YEAR ENDED DECEMBER 31,
2021
2020
2019
$ (81,297)
$ (409,086)
$ 40,809
6,244
6,244
(4,324)
(4,324)
(2,091)
(2,091)
$ (75,053)
$ (413,410)
$ 38,718
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Cash flows from operating activities:
Net income (loss)
Adjustments to reconcile net income (loss) to cash used in operating activities:
Depreciation and amortization
Debt extinguishment and commitment costs
Non-cash interest expense
Change in value of common stock warrants
Loss (gain) on sale of assets, net
Stock-based compensation
Equity in losses (income) of subsidiaries
Net changes in operating assets and liabilities:
Trade accounts receivable
Prepaid and other assets
Accounts payable, other accrued liabilities, and operating lease
ROU assets and liabilities
Net cash used in operating activities
Cash flows from investing activities:
Investments in subsidiaries
Distributions from subsidiaries
Capital expenditures
Due to (from) subsidiaries
Proceeds from sale of assets
Net cash provided by (used in) investing activities
Cash flows from financing activities:
Proceeds from sale of common stock, net of offering costs
Proceeds from borrowings
Repayments of borrowings
Payment of deferred loan costs
Exercise of stock options
Payment for debt extinguishment and commitment costs
Other financing activities, net
Net cash provided by (used in) financing activities
Net increase (decrease) in cash, cash equivalents, and restricted cash
Cash, cash equivalents, and restricted cash at beginning of period
YEAR ENDED DECEMBER 31,
2021
2020
2019
$ (81,297)
$ (409,086)
$ 40,809
2,452
—
1,364
—
15
8,165
63,649
—
1,318
(1,380)
2,900
—
2,518
(4,270)
—
7,342
2,969
6,091
4,600
3,199
—
6,437
394,197
(81,097)
—
(4,253)
(187)
—
1,592
(8,441)
(5,714)
(10,839)
(23,841)
(146,056)
90,183
(1,126)
29,752
—
(27,247)
87,193
12,364
(62,111)
—
—
—
(879)
36,567
3,606
810
—
4,113
(1,296)
5,768
14
8,599
—
14,437
(18,603)
—
—
—
164
(4,002)
(6,242)
7,052
—
16,673
(1,829)
(6,519)
31
8,356
—
63,406
(76,323)
(252)
8,171
(1,899)
(10)
(6,907)
(22,392)
29,444
Cash, cash equivalents, and restricted cash at end of period
$ 4,416
$ 810
$ 7,052
Supplemental cash flow information:
Net cash received (paid) for:
Interest
Taxes
Non-cash investing and financing activities:
Accrued capital expenditures
ROU assets obtained in exchange for new finance lease liabilities
ROU assets obtained in exchange for new operating lease liabilities
Common stock issued for business combination
Non-cash contribution to subsidiary for business combination
Common stock issued to repurchase convertible notes
This statement should be read in conjunction with the notes to consolidated financial statements.
F-60
$ (1,230)
$ (2,475)
$ (5,357)
27
(28)
(220)
$ 131
$ 233
$ 497
—
165
—
—
—
173
—
—
—
—
198
134
36,980
(36,980)
74,290
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Item 16. FORM 10-K SUMMARY
None.
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Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange of Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned, thereunto duly authorized on February 25, 2022.
PAR PAC IFIC H OL DING S, INC.
By:
/s/ William Pate
William Pate
President and Chief Executive Officer
By:
/s/ William Monteleone
William Monteleone
Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this Form 10-K has been signed below by the following
persons on our behalf and in the capacities indicated and on February 25, 2022.
S IGNAT URE
/s/ WILLIAM PATE
William Pate
/s/ WILLIAM MONTELEONE
William Monteleone
/s/ IVAN GUERRA
Ivan Guerra
/s/ MELVYN N. KLEIN
Melvyn N. Klein
/s/ ROBERT S. SILBERMAN
Robert S. Silberman
/s/ TIMOTHY CLOSSEY
Timothy Clossey
/s/ L. MELVIN COOPER
L. Melvin Cooper
/s/ CURTIS ANASTASIO
Curtis Anastasio
/s/ WALTER A. DODS, JR.
Walter A. Dods, Jr.
/s/ KATHERINE HATCHER
Katherine Hatcher
/s/ ANTHONY CHASE
Anthony Chase
/s/ PHILIP DAVIDSON
Philip Davidson
F-62
T I T L E
President and Chief Executive Officer
(Principal Executive Officer)
Chief Financial Officer
(Principal Financial Officer)
Chief Accounting Officer
(Principal Accounting Officer)
Chairman Emeritus
Chairman of the Board of Directors
Director
Director
Director
Director
Director
Director
Director
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DIREC TOR S
Robert S. Silberman
Chairman of the Board
Executive Committee Chairman
Melvyn N. Klein
Chairman Emeritus
Nominating and Corporate Governance
Committee Chairman
Curtis V. Anastasio
Director
Audit Committee Chairman
Timothy Clossey
Director
Operations and Technology
Committee Chairman
Walter A. Dods, Jr.
Director
Compensation Committee Chairman
Anthony Chase
Director
L. Melvin Cooper
Director
Philip Davidson
Director
Katherine Hatcher
Director
William Pate
Director, President & Chief Executive Officer
Will Monteleone
Director, Executive Vice President,
Chief Financial Officer
Corporate Information
MANAGEMEN T
William Pate
President & Chief Executive Officer
Will Monteleone
Executive Vice President, Chief Financial Officer
James Matthew Vaughn
Executive Vice President, Retail
Ryan Kelley
Senior Vice President, Chief Information Officer
Matthew Legg
Senior Vice President,
Chief Human Resources Officer
Eric Wright
President, Par Hawaii, LLC
Jeffrey R. Hollis
Vice President, General Counsel & Secretary
Ivan Guerra
Vice President, Chief Accounting Officer
CORP OR AT E OFFIC E
Par Pacific Holdings, Inc.
825 Town & Country Lane, Suite 1500
Houston, TX 77024
(281) 899-4800
www.parpacific.com
INVE S TO R REL AT I O N S
Additional copies of the Form 10-K are available
without charge. Shareholders, securities analysts,
portfolio managers and others who have questions
or need additional information concerning the
company may contact:
Ashimi Patel
Director, Investor Relations
(832) 916-3355
apatel@parpacific.com
www.parpacific.com/investors
INDEPENDEN T REGI S T ERED
PUBL IC ACCOUN T ING FIRM
Deloitte & Touche LLP
1111 Bagby Street, Suite 4500
Houston, TX 77002
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22_PARPAC_AR_LAYOUT(F).indd 156
22_PARPAC_AR_LAYOUT(F).indd 156
3/21/22 4:46 PM
3/21/22 4:46 PM