HOLLY ENERGY PARTNERS LP Management’s Discussion and Analysis of Financial Position and Results of Operations (Form 10-Q)

0
This Item 2, including but not limited to the sections under "Results of
Operations" and "Liquidity and Capital Resources," contains forward-looking
statements. See "Forward-Looking Statements" at the beginning of Part I of this
Quarterly Report on Form 10-Q. In this document, the words "we," "our," "ours"
and "us" refer to Holly Energy Partners, L.P. ("HEP") and its consolidated
subsidiaries or to HEP or an individual subsidiary and not to any other person.


OVERVIEW

HEP is a Delaware limited partnership. Through our subsidiaries and joint
ventures, we own and/or operate petroleum product and crude oil pipelines,
terminal, tankage and loading rack facilities and refinery processing units that
support the refining and marketing operations of HollyFrontier Corporation
("HFC") and other refineries in the Mid-Continent, Southwest and Northwest
regions of the United States. HEP, through its subsidiaries and joint ventures,
owns and/or operates petroleum product and crude pipelines, tankage and
terminals in Texas, New Mexico, Washington, Idaho, Oklahoma, Utah, Nevada,
Wyoming and Kansas as well as refinery processing units in Utah and Kansas. HFC
owned 57% of our outstanding common units and the non-economic general
partnership interest as of September 30, 2021.

We generate revenues by charging tariffs for transporting petroleum products and
crude oil through our pipelines, by charging fees for terminalling and storing
refined products and other hydrocarbons, providing other services at our storage
tanks and terminals and charging a tolling fee per barrel or thousand standard
cubic feet of feedstock throughput in our refinery processing units. We do not
take ownership of products that we transport, terminal, store or process, and
therefore, we are not directly exposed to changes in commodity prices.

We believe the long-term global refined product demand and U.S. crude production
should support high utilization rates for the refineries we serve, which in turn
should support volumes in our product pipelines, crude gathering systems and
terminals.

On August 2, 2021, HEP, The Sinclair Companies ("Sinclair"), and Sinclair
Transportation Company, a wholly owned subsidiary of Sinclair ("STC"), entered
into a Contribution Agreement (the "Contribution Agreement") pursuant to which
HEP will acquire all of the outstanding shares of STC in exchange for 21 million
newly issued common units of HEP and cash consideration equal to $325 million
(the "HEP Transactions"), subject to downward adjustment if, as a condition to
obtaining antitrust clearance for the Sinclair Transactions (as defined below),
HEP agrees to divest a portion of its equity interest in UNEV Pipeline, LLC and
the sales price for such interests does not exceed the threshold provided in the
Contribution Agreement.

The Sinclair Transactions are expected to close in mid-2022, subject to
customary closing conditions and regulatory clearance, including the expiration
or termination of the waiting period under the Hart-Scott-Rodino Antitrust
Improvements Act (the "HSR Act"). On August 23, 2021, each of HollyFrontier and
Sinclair filed its respective premerger notification and report regarding the
Sinclair Transactions with the U.S. Department of Justice and the U.S. Federal
Trade Commission (the "FTC") under the HSR Act. On September 22, 2021, HFC and
Sinclair each received a request for additional information and documentary
material ("Second Request") from the FTC in connection with the FTC's review of
the Sinclair Transactions. Issuance of the Second Request extends the waiting
period under the HSR Act until 30 days after both HollyFrontier and Sinclair
have substantially complied with the Second Request, unless the waiting period
is terminated earlier by the FTC or the parties otherwise commit not to close
the Sinclair Transactions for some additional period of time. HollyFrontier and
Sinclair are cooperating with the FTC staff in its review. In addition, the HEP
Transactions are conditioned on the closing of the transactions contemplated by
that certain Business Combination Agreement, dated as of August 2, 2021, by and
among HollyFrontier, Sinclair and certain other parties, which will occur
immediately following the HEP Transactions (the "HFC Transactions," and together
with the HEP Transactions, the "Sinclair Transactions"). See Note 2 of Notes to
Consolidated Financial Statements included in "Item 1. Financial Statements" for
additional information.

Impact of COVID-19 on Our Business
Our business depends in large part on the demand for the various petroleum
products we transport, terminal and store in the markets we serve. The impact of
the COVID-19 pandemic on the global macroeconomy created diminished demand, as
well as lack of forward visibility, for refined products and crude oil
transportation, and for the terminalling and storage services that we provide.
Since the declines in demand at the beginning of the COVID-19 pandemic, we began
to see improvement in demand for these products and services beginning late in
the second quarter of 2020 that continued through the third quarter of 2021,
with aggregate volumes approaching pre-pandemic levels. We expect our customers
will continue to adjust refinery production
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levels commensurate with market demand, and with the increasing availability of
vaccines, we believe there is a path to a fulsome recovery in demand.

With the increasing vaccination rates, most of our employees have returned to
work at our locations, and we continue to follow Centers for Disease Control and
local government guidance. We will continue to monitor developments in the
COVID-19 pandemic and the dynamic environment it has created to properly address
these policies going forward.

The extent to which HEP's future results are affected by the COVID-19 pandemic
will depend on various factors and consequences beyond our control, such as the
duration and scope of the pandemic, the effects of any new variant strains of
the underlying virus, additional actions by businesses and governments in
response to the pandemic and the speed and effectiveness of responses to combat
the virus. However, we have long-term customer contracts with minimum volume
commitments, which have expiration dates from 2022 to 2036. These minimum volume
commitments accounted for approximately 67% and 76% of our total revenues in the
nine months ended September 30, 2021 and the twelve months ended December 31,
2020, respectively. We are currently not aware of any reasons that would prevent
such customers from making the minimum payments required under the contracts or
potentially making payments in excess of the minimum payments. In addition to
these payments, we also expect to collect payments for services provided to
uncommitted shippers. There have been no material changes to customer payment
terms due to the COVID-19 pandemic.

The COVID-19 pandemic, and the volatile regional and global economic conditions
stemming from it, could also exacerbate the risk factors identified in our
Annual Report on Form 10-K for the fiscal year ended December 31, 2020, in our
Quarterly Report on Form 10-Q for the quarter ended June 30, 2021, and in this
Form 10-Q. The COVID-19 pandemic may also materially adversely affect our
results in a manner that is either not currently known or that we do not
currently consider to be a significant risk to our business.

Investment in Joint Venture
On October 2, 2019, HEP Cushing LLC ("HEP Cushing"), a wholly owned subsidiary
of HEP, and Plains Marketing, L.P., a wholly owned subsidiary of Plains All
American Pipeline, L.P. ("Plains"), formed a 50/50 joint venture, Cushing
Connect Pipeline & Terminal LLC (the "Cushing Connect Joint Venture"), for (i)
the development, construction, ownership and operation of a new 160,000 barrel
per day common carrier crude oil pipeline (the "Cushing Connect Pipeline") that
will connect the Cushing, Oklahoma crude oil hub to the Tulsa, Oklahoma refining
complex owned by a subsidiary of HFC and (ii) the ownership and operation of 1.5
million barrels of crude oil storage in Cushing, Oklahoma (the "Cushing Connect
JV Terminal"). The Cushing Connect JV Terminal went in service during the second
quarter of 2020, and the Cushing Connect Pipeline was placed into service at the
end of the third quarter of 2021. Long-term commercial agreements have been
entered into to support the Cushing Connect Joint Venture assets.

The Cushing Connect Joint Venture has contracted with an affiliate of HEP to
manage the construction and operation of the Cushing Connect Pipeline and with
an affiliate of Plains to manage the operation of the Cushing Connect JV
Terminal. The total Cushing Connect Joint Venture investment will generally be
shared equally among HEP and Plains. However, we are solely responsible for any
Cushing Connect Pipeline construction costs that exceed the budget by more than
10%. HEP estimates its share of the cost of the Cushing Connect JV Terminal
contributed by Plains and Cushing Connect Pipeline construction costs are
approximately $70 million to $75 million.

Agreements with HFC
We serve HFC's refineries under long-term pipeline, terminal, tankage and
refinery processing unit throughput agreements expiring from 2022 to 2036. Under
these agreements, HFC agrees to transport, store, and process throughput volumes
of refined product, crude oil and feedstocks on our pipelines, terminal,
tankage, loading rack facilities and refinery processing units that result in
minimum annual payments to us. These minimum annual payments or revenues are
subject to annual rate adjustments on July 1st each year based on the PPI or the
FERC index. On December 17, 2020, FERC established a new price index for the
five-year period commencing July 1, 2021 and ending June 30, 2026, in which
common carriers charging indexed rates are permitted to adjust their indexed
ceilings annually by Producer Price Index plus 0.78%. FERC has received requests
for rehearing of its December 17, 2020 order, which remain pending in FERC
Docket No. RM20-14-000. As of September 30, 2021, these agreements with HFC
require minimum annualized payments to us of $353 million.

If HFC fails to meet its minimum volume commitments under the agreements in any
quarter, it will be required to pay us the amount of any shortfall in cash by
the last day of the month following the end of the quarter. Under certain of the
agreements, a shortfall payment may be applied as a credit in the following four
quarters after minimum obligations are met.

A significant reduction in revenues under these agreements could have a material adverse effect on our results of operations.

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On June 1, 2020, HFC announced plans to permanently cease petroleum refining
operations at its Cheyenne Refinery and to convert certain assets at that
refinery to renewable diesel production. HFC subsequently began winding down
petroleum refining operations at its Cheyenne Refinery on August 3, 2020.

On February 8, 2021, HEP and HFC finalized and executed new agreements for HEP's
Cheyenne assets with the following terms, in each case effective January 1,
2021: (1) a ten-year lease with two five-year renewal option periods for HFC's
use of certain HEP tank and rack assets in the Cheyenne Refinery to facilitate
renewable diesel production with an annual lease payment of approximately $5
million, (2) a five-year contango service fee arrangement that will utilize HEP
tank assets inside the Cheyenne Refinery where HFC will pay a base tariff to HEP
for available crude oil storage and HFC and HEP will split any profits generated
on crude oil contango opportunities and (3) a $10 million one-time cash payment
from HFC to HEP for the termination of the existing minimum volume commitment.

Under certain provisions of an omnibus agreement we have with HFC (the "Omnibus
Agreement"), we pay HFC an annual administrative fee, currently $2.6 million,
for the provision by HFC or its affiliates of various general and administrative
services to us. This fee does not include the salaries of personnel employed by
HFC who perform services for us on behalf of Holly Logistic Services, L.L.C.
("HLS"), or the cost of their employee benefits, which are separately charged to
us by HFC. We also reimburse HFC and its affiliates for direct expenses they
incur on our behalf.

Under HLS's Secondment Agreement with HFC, certain employees of HFC are seconded
to HLS to provide operational and maintenance services for certain of our
processing, refining, pipeline and tankage assets, and HLS reimburses HFC for
its prorated portion of the wages, benefits, and other costs of these employees
for our benefit.

We have a long-term strategic relationship with HFC that has historically
facilitated our growth. Our future growth plans include organic projects around
our existing assets and select investments or acquisitions that enhance our
service platform while creating accretion for our unitholders. While in the near
term, any acquisitions would be subject to economic conditions discussed in
"Overview - Impact of COVID-19 on Our Business" above, we also expect over the
longer term to continue to work with HFC on logistic asset acquisitions in
conjunction with HFC's refinery acquisition strategies. See "Overview" above for
a discussion of the Sinclair Transactions.

Furthermore, as demonstrated by our pending transaction with Sinclair, we plan
to continue to pursue third-party logistic asset acquisitions that are accretive
to our unitholders and increase the diversity of our revenues.

Indicators of Goodwill and Long-lived Asset Impairment
During the three months ended March 31, 2021, changes in our agreements with HFC
related to our Cheyenne assets resulted in an increase in the net book value of
our Cheyenne reporting unit due to sales-type lease accounting, which led us to
determine indicators of potential goodwill impairment for our Cheyenne reporting
unit were present.

The estimated fair values of our Cheyenne reporting unit were derived using a
combination of income and market approaches. The income approach reflects
expected future cash flows based on anticipated gross margins, operating costs,
and capital expenditures. The market approaches include both the guideline
public company and guideline transaction methods. Both methods utilize pricing
multiples derived from historical market transactions of other like-kind assets.
These fair value measurements involve significant unobservable inputs (Level 3
inputs). See Note 6 for further discussion of Level 3 inputs.

Our interim impairment test of our Cheyenne goodwill of the business unit identified an impairment charge of $ 11.0 million, which was registered during the three months ended March 31, 2021.

We performed our annual goodwill impairment testing qualitatively as of July 1,
2021, and determined it was not more likely than not that the carrying amount of
each reporting unit was greater than its fair value. Therefore, a quantitative
test was not necessary, and no additional impairment of goodwill was recorded.


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  Table of
RESULTS OF OPERATIONS (Unaudited)
Income, Distributable Cash Flow, Volumes and Balance Sheet Data
The following tables present income, distributable cash flow and volume
information for the three and nine months ended September 30, 2021 and 2020.
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Table of

                                                                            Three Months Ended September 30,             Change from
                                                                               2021                    2020                 2020
                                                                                     (In thousands, except per unit data)
Revenues:
Pipelines:
Affiliates-refined product pipelines                                    $   

18,702 $ 18,619 $ 83 Affiliate-intermediary pipelines

                                                  7,537                7,537                     -
Affiliates-crude pipelines                                                        19,536               20,218                  (682)
                                                                                  45,775               46,374                  (599)
Third parties-refined product pipelines                                            8,799                9,812                (1,013)
Third parties-crude pipelines                                                     12,780               12,106                   674
                                                                                  67,354               68,292                  (938)
Terminals, tanks and loading racks:
Affiliates                                                                        29,436               34,215                (4,779)
Third parties                                                                      3,881                4,821                  (940)
                                                                                  33,317               39,036                (5,719)

Refinery processing units-Affiliates                                              21,913               20,403                 1,510

Total revenues                                                                   122,584              127,731                (5,147)
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)                           42,793               40,003                 2,790
Depreciation and amortization                                                     21,826               26,190                (4,364)
General and administrative                                                         3,849                2,332                 1,517
Goodwill impairment                                                                    -               35,653               (35,653)
                                                                                  68,468              104,178               (35,710)
Operating income                                                                  54,116               23,553                30,563
Other income (expense):
Equity in earnings of equity method investments                                    3,689                1,316                 2,373
Interest expense, including amortization                                         (13,417)             (14,104)                  687
Interest income                                                                    6,835                2,803                 4,032

Gain on sale of assets and other                                                      77                7,465                (7,388)
                                                                                  (2,816)              (2,520)                 (296)
Income before income taxes                                                        51,300               21,033                30,267
State income tax benefit (expense)                                                     4                  (34)                   38
Net income                                                                        51,304               20,999                30,305

Allocation of net income attributable to non-controlling interests

       (2,144)              (3,186)                1,042
Net income attributable to the partners                                           49,160               17,813                31,347

Limited partners' earnings per unit-basic and diluted                   $   

0.46 $ 0.17 $ 0.29
Weighted average of limited partners’ units outstanding

     105,440              105,440                     -
EBITDA (1)                                                              $         77,564          $    55,338          $     22,226
Adjusted EBITDA (1)                                                     $  

83,270 $ 86,435 $ (3 165)
Distributable cash flow (2)

                                             $   

66 810 $ 76,894 $ (10,084)

Volumes (bpd)
Pipelines:
Affiliates-refined product pipelines                                             115,507              119,403                (3,896)
Affiliates-intermediate pipelines                                                136,398              142,817                (6,419)
Affiliates-crude pipelines                                                       271,717              270,840                   877
                                                                                 523,622              533,060                (9,438)
Third parties-refined product pipelines                                           46,834               60,203               (13,369)
Third parties-crude pipelines                                                    136,247              133,487                 2,760
                                                                                 706,703              726,750               (20,047)
Terminals and loading racks:
Affiliates                                                                       419,665              401,904                17,761
Third parties                                                                     52,541               57,355                (4,814)
                                                                                 472,206              459,259                12,947
Refinery processing units-Affiliates                                              72,297               62,016                10,281
Total for pipelines and terminal and refinery processing unit
assets (bpd)                                                                   1,251,206            1,248,025                 3,181


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Table of

                                                                            Nine Months Ended September 30,              Change from
                                                                               2021                    2020                 2020
                                                                                     (In thousands, except per unit data)
Revenues:
Pipelines:
Affiliates-refined product pipelines                                    $   

56,520 $ 55,004 $ 1,516
Affiliate-intermediary pipelines

                                                 22,564               22,486                    78
Affiliates-crude pipelines                                                        58,241               59,922                (1,681)
                                                                                 137,325              137,412                   (87)
Third parties-refined product pipelines                                           28,188               33,360                (5,172)
Third parties-crude pipelines                                                     36,667               26,946                 9,721
                                                                                 202,180              197,718                 4,462
Terminals, tanks and loading racks:
Affiliates                                                                        95,431              100,711                (5,280)
Third parties                                                                     12,955               12,103                   852
                                                                                 108,386              112,814                (4,428)

Refinery processing units-Affiliates                                              65,436               59,860                 5,576

Total revenues                                                                   376,002              370,392                 5,610
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)                          126,226              109,721                16,505
Depreciation and amortization                                                     71,894               75,202                (3,308)
General and administrative                                                         9,664                7,569                 2,095
Goodwill impairment                                                               11,034               35,653               (24,619)
                                                                                 218,818              228,145                (9,327)
Operating income                                                                 157,184              142,247                14,937
Other income (expense):
Equity in earnings of equity method investments                                    8,875                5,186                 3,689
Interest expense, including amortization                                         (40,595)             (45,650)                5,055
Interest income                                                                   19,997                7,834                12,163
Loss on early extinguishment of debt                                                   -              (25,915)               25,915
Gain on sales-type leases                                                         24,677               33,834                (9,157)
Gain on sale of assets and other                                                   5,994                8,439                (2,445)
                                                                                  18,948              (16,272)               35,220
Income before income taxes                                                       176,132              125,975                50,157
State income tax expense                                                             (60)                (110)                   50
Net income                                                                       176,072              125,865                50,207

Allocation of net income attributable to non-controlling interests

       (6,770)              (6,721)                  (49)
Net income attributable to the partners                                          169,302              119,144                50,158

Limited partners' earnings per unit-basic and diluted                   $   

1.60 $ 1.13 $ 0.47
Weighted average of limited partners’ units outstanding

     105,440              105,440                     -
EBITDA (1)                                                              $        261,854          $   232,272          $     29,582
Adjusted EBITDA (1)                                                     $  

259,466 $ 257,711 $ 1,755
Distributable cash flow (2)

                                             $   

206,707 $ 213,058 $ (6,351)

Volumes (bpd)
Pipelines:
Affiliates-refined product pipelines                                             118,033              116,641                 1,392
Affiliates-intermediate pipelines                                                131,873              137,816                (5,943)
Affiliates-crude pipelines                                                       261,117              276,128               (15,011)
                                                                                 511,023              530,585               (19,562)
Third parties-refined product pipelines                                           47,805               55,921                (8,116)
Third parties-crude pipelines                                                    131,842              103,955                27,887
                                                                                 690,670              690,461                   209
Terminals and loading racks:
Affiliates                                                                       386,400              401,245               (14,845)
Third parties                                                                     50,542               49,753                   789
                                                                                 436,942              450,998               (14,056)
Refinery processing units-Affiliates                                              69,904               60,573                 9,331
Total for pipelines and terminal and refinery processing unit
assets (bpd)                                                                   1,197,516            1,202,032                (4,516)


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Table of

(1)Earnings before interest, taxes, depreciation and amortization ("EBITDA") is
calculated as net income attributable to the partners plus (i) interest expense,
net of interest income, (ii) state income tax expense and (iii) depreciation and
amortization. Adjusted EBITDA is calculated as EBITDA plus (i) loss on early
extinguishment of debt, (ii) goodwill impairment and (iii) tariffs and fees not
included in revenues due to impacts from lease accounting for certain tariffs
and fees minus (iv) gain on sales-type leases, (v) gain on significant asset
sales, and (vi) pipeline lease payments not included in operating costs and
expenses. Portions of our minimum guaranteed pipeline and terminal tariffs and
fees for assets subject to sales-type lease accounting are recorded as interest
income with the remaining amounts recorded as a reduction in net investment in
leases. These tariffs and fees were previously recorded as revenues prior to the
renewal of the throughput agreements, which triggered sales-type lease
accounting. Similarly, certain pipeline lease payments were previously recorded
as operating costs and expenses, but the underlying lease was reclassified from
an operating lease to a financing lease, and these payments are now recorded as
interest expense and reductions in the lease liability. EBITDA and Adjusted
EBITDA are not calculations based upon generally accepted accounting principles
("GAAP"). However, the amounts included in the EBITDA and Adjusted EBITDA
calculations are derived from amounts included in our consolidated financial
statements. EBITDA and Adjusted EBITDA should not be considered as alternatives
to net income attributable to Holly Energy Partners or operating income, as
indications of our operating performance or as alternatives to operating cash
flow as a measure of liquidity. EBITDA and Adjusted EBITDA are not necessarily
comparable to similarly titled measures of other companies. EBITDA and Adjusted
EBITDA are presented here because they are widely used financial indicators used
by investors and analysts to measure performance. EBITDA and Adjusted EBITDA are
also used by our management for internal analysis and as a basis for compliance
with financial covenants. Set forth below are our calculations of EBITDA and
Adjusted EBITDA.

                                                            Three Months Ended                     Nine Months Ended
                                                              September 30,                          September 30,
                                                         2021                2020               2021               2020
                                                                                 (In thousands)
Net income attributable to the partners              $   49,160          $  17,813          $ 169,302          $ 119,144
Add (subtract):
Interest expense                                         13,417             14,104             40,595             45,650
Interest income                                          (6,835)            (2,803)           (19,997)            (7,834)
State income tax (benefit) expense                           (4)                34                 60                110
Depreciation and amortization                            21,826             26,190             71,894             75,202
EBITDA                                               $   77,564          $  55,338          $ 261,854          $ 232,272
Loss on early extinguishment of debt                          -                  -                  -             25,915
Gain on sales-type leases                                     -                  -            (24,677)           (33,834)
Gain on significant asset sales                               -                  -             (5,263)                 -
Goodwill impairment                                           -             35,653             11,034             35,653
HEP's pro-rata share of gain on business                      -             (6,079)                 -             (6,079)
interruption insurance settlement
Tariffs and fees not included in revenues                 7,312              3,129             21,337              8,603
Lease payments not included in operating costs           (1,606)            (1,606)            (4,819)            (4,819)
Adjusted EBITDA                                      $   83,270          $  

86,435 $ 259,466 $ 257,711



(2)Distributable cash flow is not a calculation based upon GAAP. However, the
amounts included in the calculation are derived from amounts presented in our
consolidated financial statements, with the general exceptions of maintenance
capital expenditures. Distributable cash flow should not be considered in
isolation or as an alternative to net income or operating income as an
indication of our operating performance or as an alternative to operating cash
flow as a measure of liquidity. Distributable cash flow is not necessarily
comparable to similarly titled measures of other companies. Distributable cash
flow is presented here because it is a widely accepted financial indicator used
by investors to compare partnership performance. It is also used by management
for internal analysis and for our performance units. We believe that this
measure provides investors an enhanced perspective of the operating performance
of our assets and the cash our business is generating. Set forth below is our
calculation of distributable cash flow.
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  Table of
                                                            Three Months Ended                     Nine Months Ended
                                                              September 30,                          September 30,
                                                         2021                2020               2021               2020
                                                                                 (In thousands)
Net income attributable to the partners              $   49,160          $  17,813          $ 169,302          $ 119,144
Add (subtract):
Depreciation and amortization                            21,826             26,190             71,894             75,202
Amortization of discount and deferred debt                  763                838              2,992              2,479
issuance costs
Loss on early extinguishment of debt                          -                  -                  -             25,915
Customer billings greater than revenue                     (122)              (198)              (301)              (699)

recognized

Maintenance capital expenditures (3)                     (3,351)            (1,565)            (8,834)            (5,192)
Increase in environmental liability                         271                 29                 36                187
Decrease in reimbursable deferred revenue                (2,991)            (3,257)           (10,507)            (9,062)
Gain on sales-type leases                                     -                  -            (24,677)           (33,834)
Gain on significant asset sales                               -                  -             (5,263)                 -
Goodwill impairment                                           -             35,653             11,034             35,653
Other                                                     1,254              1,391              1,031              3,265
Distributable cash flow                              $   66,810          $  76,894          $ 206,707          $ 213,058



(3)Maintenance capital expenditures are capital expenditures made to replace
partially or fully depreciated assets in order to maintain the existing
operating capacity of our assets and to extend their useful lives. Maintenance
capital expenditures include expenditures required to maintain equipment
reliability, tankage and pipeline integrity, safety and to address environmental
regulations.
                                  September 30,       December 31,
                                       2021               2020
                                           (In thousands)
Balance Sheet Data
Cash and cash equivalents        $       12,816      $     21,990
Working capital                  $        3,146      $     14,247
Total assets                     $    2,152,576      $  2,167,565
Long-term debt                   $    1,333,309      $  1,405,603
Partners' equity                 $      437,998      $    379,292



Results of operations-three months completed September 30, 2021 Compared to the three months ended September 30, 2020

Summary

Net income attributable to the partners for the third quarter of 2021 was $49.2
million ($0.46 per basic and diluted limited partner unit) compared to $17.8
million ($0.17 per basic and diluted limited partner unit) for the third quarter
of 2020. Net income attributable to HEP for the third quarter of 2020 included a
goodwill impairment charge of $35.7 million related to our Cheyenne reporting
unit and a $6.1 million gain related to HEP's pro-rata share of a business
interruption insurance claim settlement resulting from a loss at HollyFrontier's
Woods Cross Refinery. Excluding these items, net income attributable to the
partners for the third quarters of 2021 and 2020 were $49.2 million ($0.46 per
basic and diluted limited partner unit) and $47.4 million ($0.45 per basic and
diluted limited partner unit), respectively. The increase in earnings was mainly
due to higher interest income associated with sales-type leases, higher equity
in earnings from our joint ventures and lower depreciation expense partially
offset by lower revenues and higher operating expenses.

Income

Revenues for the third quarter were $122.6 million, a decrease of $5.1 million
compared to the third quarter of 2020. The decrease was mainly due to lower
on-going revenues on our Cheyenne assets as a result of the conversion of the
HollyFrontier
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  Table of
Cheyenne Refinery to renewable diesel production, reclassifications of certain
tariffs and fees from revenue to interest income under sales-type lease
accounting and a 3% decrease in overall crude and product pipeline volumes.

Revenues from our refined product pipelines were $27.5 million, a decrease of
$0.9 million compared to the third quarter of 2020. Shipments averaged 162.3
thousand barrels per day ("mbpd") compared to 179.6 mbpd for the third quarter
of 2020. The volume and revenue decreases were mainly due to lower volumes on
pipelines servicing HollyFrontier's Navajo refinery and our pipelines servicing
Delek's Big Spring refinery.

Revenues from our intermediate pipelines were $7.5 million, consistent with the
third quarter of 2020. Shipments averaged 136.4 mbpd for the third quarter of
2021 compared to 142.8 mbpd for the third quarter of 2020. The decrease in
volumes was mainly due to lower throughputs on our intermediate pipelines
servicing HollyFrontier's Navajo refinery while revenue remained constant mainly
due to contractual minimum volume guarantees.

Revenues from our crude pipelines were $32.3 million, consistent with the third
quarter of 2020. Shipments averaged 408.0 mbpd compared to 404.3 mbpd for the
third quarter of 2020. The increased volume was mainly attributable to our crude
pipeline systems in Wyoming and Utah.

Revenues from terminal, tankage and loading rack fees were $33.3 million, a
decrease of $5.7 million compared to the third quarter of 2020. Refined products
and crude oil terminalled in the facilities averaged 472.2 mbpd compared to
459.3 mbpd for the third quarter of 2020. The increase in volume was mainly the
result of higher throughputs at HollyFrontier's El Dorado refinery. Revenues
decreased mainly due to lower on-going revenues on our Cheyenne assets as a
result of the conversion of the HollyFrontier Cheyenne Refinery to renewable
diesel production and reclassifications of certain tariffs and fees from revenue
to interest income under sales-type lease accounting.

Revenues from refinery processing units were $21.9 million, an increase of $1.5
million compared to the third quarter of 2020, and throughputs averaged 72.3
mbpd compared to 62.0 mbpd for the third quarter of 2020. The increase in
volumes was mainly due to increased throughput for both our Woods Cross and El
Dorado processing units. Revenues increased mainly due to higher natural gas
recoveries in revenues. Revenues did not increase in proportion to the increase
in volumes mainly due to contractual minimum volume guarantees.

Operations Expense
Operations (exclusive of depreciation and amortization and goodwill impairment)
expense was $42.8 million for the three months ended September 30, 2021, an
increase of $2.8 million compared to the third quarter of 2020. The increase was
mainly due to higher natural gas costs and employee costs for the three months
ended September 30, 2021.

Depreciation and Amortization
Depreciation and amortization for the three months ended September 30, 2021
decreased by $4.4 million compared to the three months ended September 30, 2020.
The decrease was mainly due to the acceleration of depreciation on certain of
our Cheyenne tanks in 2020.

General and Administrative
General and administrative costs for the three months ended September 30, 2021
increased by $1.5 million compared to the three months ended September 30, 2020,
mainly due to higher legal and professional expenses associated with our
Sinclair acquisition.

Equity in earnings from investments using the equity method

                                                              Three Months Ended September 30,
Equity Method Investment                                        2021                     2020
                                                                       (in thousands)
Osage Pipe Line Company, LLC                            $           1,090          $          219
Cheyenne Pipeline LLC                                               1,654                     533
Cushing Connect Terminal Holdings LLC                                 945                     564
Total                                                   $           3,689          $        1,316



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Equity in earnings of Osage Pipe Line Company, LLC increased for the three
months ended September 30, 2021, mainly due to higher throughput volumes. Equity
in earnings of Cheyenne Pipeline LLC increased for the three months ended
September 30, 2021, mainly due to the recognition in revenue of prior
contractual minimum commitment billings. Equity in earnings of Cushing Connect
Terminal Holdings LLC increased for the three months ended September 30, 2021,
mainly due to lower operating expenses.

Interest Expense, including Amortization
Interest expense for the three months ended September 30, 2021, totaled $13.4
million, a decrease of $0.7 million compared to the three months ended
September 30, 2020. The decrease was mainly due to lower average borrowings
outstanding under our senior secured revolving credit facility during the third
quarter of 2021. Our aggregate effective interest rates were 3.7% and 3.6% for
the three months ended September 30, 2021 and 2020, respectively.

State Income Tax Expense
We recorded state income tax benefit of $4,000 and a state income tax expense of
$34,000 for the three months ended September 30, 2021 and 2020, respectively.
All tax expense is solely attributable to the Texas margin tax.

Results of Operations – Nine Months Ended September 30, 2021 Compared to the nine months ended September 30, 2020

Summary

Net income attributable to the partners for the nine months ended September 30,
2021, was $169.3 million ($1.60 per basic and diluted limited partner unit)
compared to $119.1 million ($1.13 per basic and diluted limited partner unit)
for the nine months ended September 30, 2020. Results for the nine months ended
September 30, 2021, include special items that collectively increased net income
attributable to the partners by a total of $18.9 million. These items include a
gain on sales-type leases of $24.7 million, a gain on significant asset sales of
$5.3 million and a goodwill impairment charge of $11.0 million. In addition, the
net income attributable to the partners for the nine months ended September 30,
2020, included a gain on sales-type leases of $33.8 million, a loss on early
extinguishment of debt of $25.9 million, a goodwill impairment charge of $35.7
million related to our Cheyenne reporting unit and a $6.1 million gain related
to HEP's pro-rate share of a business interruption insurance claim resulting
from a loss at HollyFrontier's Woods Cross Refinery. Excluding these items, net
income attributable to the partners for the nine months ended September 30, 2021
and 2020, were $150.4 million ($1.43 per basic and diluted limited partner unit)
and $140.8 million ($1.34 per basic and diluted limited partner unit),
respectively. The increase in earnings was mainly due to higher volumes across
our crude pipelines, higher interest income associated with sales-type leases
and lower interest expense, partially offset by higher operating expenses.

Income

Revenues for the nine months ended September 30, 2021, were $376.0 million, an
increase of $5.6 million compared to the nine months ended September 30, 2020.
The increase was mainly attributable to increased volumes on our crude pipeline
systems in Wyoming and Utah, the recognition of the $10 million termination fee
related to the termination of HollyFrontier's minimum volume commitment on our
Cheyenne assets and higher revenues on our refinery processing units partially
offset by lower on-going revenues on our Cheyenne assets and our pipelines
servicing Delek's Big Spring refinery as well as reclassifications of certain
tariffs and fees from revenue to interest income under sales-type lease
accounting.

Revenues from our refined product pipelines were $84.7 million, a decrease of
$3.7 million compared to the nine months ended September 30, 2020. Shipments
averaged 165.8 mbpd compared to 172.6 mbpd for the nine months ended September
30, 2020. The volume and revenue decreases were mainly due to lower volumes on
pipelines servicing Delek's Big Spring refinery.

Revenues from our intermediate pipelines were $22.6 million, an increase of $0.1
million compared to the nine months ended September 30, 2020. Shipments averaged
131.9 mbpd compared to 137.8 mbpd for the nine months ended September 30, 2020.
The decrease in volumes was mainly due to lower throughputs on our intermediate
pipelines servicing HollyFrontier's Tulsa refinery while revenue remained
relatively constant mainly due to contractual minimum volume guarantees.

Revenues from our crude pipelines were $94.9 million, an increase of $8.0
million compared to the nine months ended September 30, 2020. Shipments averaged
393.0 mbpd compared to 380.1 mbpd for the nine months ended September 30, 2020.
The increases were mainly attributable to increased volumes on our crude
pipeline systems in Wyoming and Utah.
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Revenues from terminal, tankage and loading rack fees were $108.4 million, a
decrease of $4.4 million compared to the nine months ended September 30, 2020.
Refined products and crude oil terminalled in the facilities averaged 436.9 mbpd
compared to 451.0 mbpd for the nine months ended September 30, 2020. Volumes
decreased mainly as a result of lower throughputs at HollyFrontier's Tulsa
refinery as well as the cessation of petroleum refinery operations at
HollyFrontier's Cheyenne Refinery. Revenues decreased mainly as a result of
reclassifications of certain tariffs and fees from revenue to interest income
under sales-type lease accounting.

Revenues from refinery processing units were $65.4 million, an increase of $5.6
million compared to the nine months ended September 30, 2020. Throughputs
averaged 69.9 mbpd compared to 60.6 mbpd for the nine months ended September 30,
2020. The increase in volumes was mainly due to increased throughput for both
our Woods Cross and El Dorado processing units. Revenues increased mainly due to
higher recovery of natural gas costs as well as higher throughputs.

Operations Expense
Operations expense (exclusive of depreciation and amortization) for the nine
months ended September 30, 2021, increased by $16.5 million compared to the nine
months ended September 30, 2020. The increase was mainly due to higher
maintenance, natural gas, and pipeline rental costs, partially offset by lower
materials and supplies and property taxes.

Depreciation and Amortization
Depreciation and amortization for the nine months ended September 30, 2021,
decreased by $3.3 million compared to the nine months ended September 30, 2020.
The decrease was mainly due to the acceleration of depreciation on certain of
our Cheyenne tanks in 2020 as well as retirement of assets due to sales-type
lease accounting.

General and Administrative
General and administrative costs for the nine months ended September 30, 2021,
increased by $2.1 million compared to the nine months ended September 30, 2020
mainly due to higher legal and professional expenses incurred in the nine months
ended September 30, 2021.

Equity in earnings from investments using the equity method

                                                              Nine Months Ended September 30,
Equity Method Investment                                        2021                     2020
                                                                       (in thousands)
Osage Pipe Line Company, LLC                                        2,726                   1,599
Cheyenne Pipeline LLC                                               3,428                   2,693
Cushing Connect Terminal Holdings LLC                               2,721                     894
Total                                                   $           8,875          $        5,186



Equity in earnings of Osage Pipe Line Company, LLC increased for the nine months
ended September 30, 2021, mainly due to higher throughput volumes. Equity in
earnings of Cheyenne Pipeline LLC increased for the nine months ended
September 30, 2021, mainly due to the recognition in revenue of prior
contractual minimum commitment billings. Equity in earnings of Cushing Connect
Terminal Holdings LLC increased for the nine months ended September 30, 2021 as
the terminal started operations in the second quarter of 2020.

Interest Expense, including Amortization
Interest expense for the nine months ended September 30, 2021, totaled $40.6
million, a decrease of $5.1 million compared to the nine months ended September
30, 2020. The decrease was mainly due to lower average borrowings outstanding on
our senior secured revolving credit facility and refinancing our $500 million
aggregate principal amount of 6.0% senior notes due 2024, with $500 million
aggregate principal amount of 5.0% senior notes due 2028. Our aggregate
effective interest rates were 3.7% and 3.8% for the nine months ended
September 30, 2021 and 2020, respectively.

State Income Tax Expense
We recorded state income tax expense of $60,000 and $110,000 for the nine months
ended September 30, 2021 and 2020, respectively. All tax expense is solely
attributable to the Texas margin tax.


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LIQUIDITY AND CAPITAL RESOURCES

Overview

In April 2021, we amended our senior secured revolving credit facility (the
"Credit Agreement") decreasing the size of the facility from $1.4 billion to
$1.2 billion and extending the maturity date to July 27, 2025. The Credit
Agreement is available to fund capital expenditures, investments, acquisitions,
distribution payments and working capital and for general partnership purposes.
The Credit Agreement is also available to fund letters of credit up to a $50
million sub-limit and continues to provide for an accordion feature that allows
us to increase commitments under the Credit Agreement up to a maximum amount of
$1.7 billion.

During the nine months ended September 30, 2021, we received advances totaling
$210.5 million and repaid $283.5 million under the Credit Agreement, resulting
in a net decrease of $73.0 million and an outstanding balance of $840.5 million
at September 30, 2021 under the Credit Agreement. As of September 30, 2021, we
have no letters of credit outstanding under the Credit Agreement and the
available capacity under the Credit Agreement was $359.5 million. Amounts repaid
under the Credit Agreement may be reborrowed from time to time.
On February 4, 2020, we closed a private placement of $500 million in aggregate
principal amount of 5% Senior Notes due in 2028. On February 5, 2020, we
redeemed the existing $500 million 6% Senior Notes at a redemption cost of
$522.5 million, at which time we recognized a $25.9 million early extinguishment
loss consisting of a $22.5 million debt redemption premium and unamortized
financing costs of $3.4 million. We funded the $522.5 million redemption with
proceeds from the issuance of our 5% Senior Notes and borrowings under our
Credit Agreement.
We have a continuous offering program under which we may issue and sell common
units from time to time, representing limited partner interests, up to an
aggregate gross sales amount of $200 million. We did not issue any units under
this program during the nine months ended September 30, 2021. As of
September 30, 2021, HEP has issued 2,413,153 units under this program, providing
$82.3 million in gross proceeds.

Under our registration statement filed with the Securities and Exchange
Commission ("SEC") using a "shelf" registration process, we currently have the
authority to raise up to $2.0 billion by offering securities, through one or
more prospectus supplements that would describe, among other things, the
specific amounts, prices and terms of any securities offered and how the
proceeds would be used. Any proceeds from the sale of securities are expected to
be used for general business purposes, which may include, among other things,
funding acquisitions of assets or businesses, working capital, capital
expenditures, investments in subsidiaries, the retirement of existing debt
and/or the repurchase of common units or other securities.

We believe our current sources of liquidity, including cash balances, future
internally generated funds, any future issuances of debt or equity securities
and funds available under the Credit Agreement will provide sufficient resources
to meet our working capital liquidity, capital expenditure and quarterly
distribution needs for the foreseeable future, including funding the cash
portion of the HEP Transactions with Sinclair. Future securities issuances, if
any, will depend on prevailing market conditions, our liquidity requirements,
contractual restrictions and other factors.

We have reduced our quarterly distribution to $ 0.35 per unit as of Q1 2020 distribution, representative of our new distribution strategy focused on funding all capital expenditures and distributions in operating cash flow and improving cash flow hedging. distributable cash at 1.3 times or more with the aim of reducing debt to 3.0 -3.5x.

In August 2021, we made a regular quarterly cash distribution of $ 0.35 on all units for a total amount of $ 37.0 million.

Cash and cash equivalents decreased by $9.2 million during the nine months ended
September 30, 2021. The cash flows provided by operating activities of $240.8
million were less than the cash flows used for financing activities of $182.2
million and investing activities of $67.7 million. Working capital decreased by
$11.1 million to $3.1 million at September 30, 2021, from $14.2 million at
December 31, 2020.

                                     - 46 -
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Cash Flows-Operating Activities
Cash flows from operating activities increased by $15.7 million from $225.0
million for the nine months ended September 30, 2020, to $240.8 million for the
nine months ended September 30, 2021. The increase was mainly due to higher cash
receipts from customers and lower payments for interest expenses partially
offset by higher payments for operating costs and expenses during the nine
months ended September 30, 2021, as compared to the nine months ended
September 30, 2020.

Cash Flows-Investing Activities
Cash flows used for investing activities were $67.7 million for the nine months
ended September 30, 2021, compared to $39.4 million for the nine months ended
September 30, 2020, an increase of $28.3 million. During the nine months ended
September 30, 2021 and 2020, we invested $78.6 million and $38.6 million,
respectively, in additions to properties and equipment. We received $3.5 million
in excess of equity in earnings and $7.4 million in proceeds from the sale of
assets during the nine months ended September 30, 2021.

Cash Flows-Financing Activities
Cash flows used for financing activities were $182.2 million for the nine months
ended September 30, 2021, compared to $180.8 million for the nine months ended
September 30, 2020, an increase of $1.4 million. During the nine months ended
September 30, 2021, we received $210.5 million and repaid $283.5 million in
advances under the Credit Agreement. Additionally, we paid $112.4 million in
regular quarterly cash distributions to our limited partners and $8.7 million to
our noncontrolling interests. We received $21.3 million in contributions from
noncontrolling interests during the nine months ended September 30, 2021. During
the nine months ended September 30, 2020, we received $219.5 million and repaid
$237.0 million in advances under the Credit Agreement. We paid $137.4 million in
regular quarterly cash distributions to our limited partners, and distributed
$7.8 million to our noncontrolling interests. We also received net proceeds of
$491.3 million for issuance of our 5% Senior Notes and paid $522.5 million to
retire our 6% Senior Notes. In addition, we received $15.4 million in
contributions from noncontrolling interests during the nine months ended
September 30, 2020.

Capital Requirements
Our pipeline and terminalling operations are capital intensive, requiring
investments to maintain, expand, upgrade or enhance existing operations and to
meet environmental and operational regulations. Our capital requirements have
consisted of, and are expected to continue to consist of, maintenance capital
expenditures and expansion capital expenditures. "Maintenance capital
expenditures" represent capital expenditures to replace partially or fully
depreciated assets to maintain the operating capacity of existing assets.
Maintenance capital expenditures include expenditures required to maintain
equipment reliability, tankage and pipeline integrity, safety and to address
environmental regulations. "Expansion capital expenditures" represent capital
expenditures to expand the operating capacity of existing or new assets, whether
through construction or acquisition. Expansion capital expenditures include
expenditures to acquire assets, to grow our business and to expand existing
facilities, such as projects that increase throughput capacity on our pipelines
and in our terminals. Repair and maintenance expenses associated with existing
assets that are minor in nature and do not extend the useful life of existing
assets are charged to operating expenses as incurred.

Each year the board of directors of HLS, our ultimate general partner, approves
our annual capital budget, which specifies capital projects that our management
is authorized to undertake. Additionally, at times when conditions warrant or as
new opportunities arise, additional projects may be approved. The funds
allocated for a particular capital project may be expended over a period in
excess of a year, depending on the time required to complete the project.
Therefore, our planned capital expenditures for a given year consist of
expenditures approved for capital projects included in the current year's
capital budget as well as, in certain cases, expenditures approved for capital
projects in capital budgets for prior years. Our current 2021 capital forecast
is comprised of approximately $15 million to $20 million for maintenance capital
expenditures, $2 million to $4 million for refinery unit turnarounds and $40
million to $45 million for expansion capital expenditures and our share of
Cushing Connect Joint Venture investments. We expect the majority of the 2021
expansion capital to be invested in our share of Cushing Connect Joint Venture
investments. In addition to our capital budget, we may spend funds periodically
to perform capital upgrades or additions to our assets where a customer
reimburses us for such costs. The upgrades or additions would generally benefit
the customer over the remaining life of the related service agreements.
We expect that our currently planned sustaining and maintenance capital
expenditures, as well as planned expenditures for acquisitions and capital
development projects, will be funded with cash generated by operations.

Under the terms of the transaction to acquire HFC's 75% interest in UNEV, we
issued to HFC a Class B unit comprising a noncontrolling equity interest in a
wholly owned subsidiary subject to redemption to the extent that HFC is entitled
to a 50%
                                     - 47 -
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interest in our share of annual UNEV earnings before interest, income taxes,
depreciation, and amortization above $30 million beginning July 1, 2015, and
ending in June 2032, subject to certain limitations. However, to the extent
earnings thresholds are not achieved, no redemption payments are required. No
redemption payments have been required to date.

Credit Agreement
In April 2021, we amended our Credit Agreement decreasing the commitments under
the facility from $1.4 billion to $1.2 billion and extending the maturity date
to July 27, 2025. The Credit Agreement is available to fund capital
expenditures, investments, acquisitions, distribution payments and working
capital and for general partnership purposes. The Credit Agreement is also
available to fund letters of credit up to a $50 million sub-limit, and it
continues to provide for an accordion feature that allows us to increase the
commitments under the Credit Agreement up to a maximum amount of $1.7 billion.

Our obligations under the Credit Agreement are collateralized by substantially
all of our assets, and indebtedness under the Credit Agreement is guaranteed by
our material, wholly owned subsidiaries. The Credit Agreement requires us to
maintain compliance with certain financial covenants consisting of total
leverage, senior secured leverage, and interest coverage. It also limits or
restricts our ability to engage in certain activities. If, at any time prior to
the expiration of the Credit Agreement, HEP obtains two investment grade credit
ratings, the Credit Agreement will become unsecured and many of the covenants,
limitations and restrictions will be eliminated.

We may prepay all loans at any time without penalty, except for tranche breakage
costs. If an event of default exists under the Credit Agreement, the lenders
will be able to accelerate the maturity of all loans outstanding and exercise
other rights and remedies. We were in compliance with the covenants under the
Credit Agreement as of September 30, 2021.

Senior Notes
As of September 30, 2021, we had $500 million in aggregate principal amount of
5% Senior Notes due in 2028.

On February 4, 2020, we closed a private placement of $500 million in aggregate
principal amount of 5% Senior Notes due in 2028. On February 5, 2020, we
redeemed the existing $500 million 6% Senior Notes at a redemption cost of
$522.5 million, at which time we recognized a $25.9 million early extinguishment
loss consisting of a $22.5 million debt redemption premium and unamortized
financing costs of $3.4 million. We funded the $522.5 million redemption with
proceeds from the issuance of our 5% Senior Notes and borrowings under our
Credit Agreement.

The 5% Senior Notes are unsecured and impose certain restrictive covenants,
including limitations on our ability to incur additional indebtedness, make
investments, sell assets, incur certain liens, pay distributions, enter into
transactions with affiliates, and enter into mergers. We were in compliance with
the restrictive covenants for the 5% Senior Notes as of September 30, 2021. At
any time when the 5% Senior Notes are rated investment grade by either Moody's
or Standard & Poor's and no default or event of default exists, we will not be
subject to many of the foregoing covenants. Additionally, we have certain
redemption rights at varying premiums over face value under the 5% Senior Notes.

The indebtedness under the 5% Senior Notes is secured by all of our existing wholly-owned subsidiaries (other than Holly Energy Finance Corp. and some insignificant subsidiaries).

Long-term Debt
The carrying amounts of our long-term debt are as follows:
                                      September 30,       December 31,
                                           2021               2020
                                               (In thousands)
Credit Agreement                     $      840,500           913,500

5% Senior Notes
Principal                                   500,000           500,000
Unamortized debt issuance costs              (7,191)           (7,897)
                                            492,809           492,103

Total long-term debt                 $    1,333,309      $  1,405,603



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Contractual Obligations
There were no significant changes to our long-term contractual obligations
during the quarter ended September 30, 2021.

Impact of Inflation
Inflation in the United States did not have a material impact on our results of
operations for the nine months ended September 30, 2021 and 2020. PPI has
increased an average of 0.9% annually over the past five calendar years,
including a decrease of 1.4% in 2020 and an increase of 0.8% in 2019. PPI for
the first nine months of 2021 increased by 7.6% over the first nine months of
2020.

The substantial majority of our revenues are generated under long-term contracts
that provide for increases or decreases in our rates and minimum revenue
guarantees annually for increases or decreases in the PPI. Certain of these
contracts have provisions that limit the level of annual PPI percentage rate
increases or decreases, and the majority of our rates do not decrease when PPI
is negative. A significant and prolonged period of high inflation or a
significant and prolonged period of negative inflation could adversely affect
our cash flows and results of operations if costs increase at a rate greater
than the fees we charge our shippers.

Environmental Matters
Our operation of pipelines, terminals, and associated facilities in connection
with the transportation and storage of refined products and crude oil is subject
to stringent and complex federal, state, and local laws and regulations
governing the discharge of materials into the environment, or otherwise relating
to the protection of the environment. As with the industry generally, compliance
with existing and anticipated laws and regulations increases our overall cost of
business, including our capital costs to construct, maintain, and upgrade
equipment and facilities. While these laws and regulations affect our
maintenance capital expenditures and net income, we believe that they do not
affect our competitive position given that the operations of our competitors are
similarly affected. However, these laws and regulations, and the interpretation
or enforcement thereof, are subject to frequent change by regulatory
authorities, and we are unable to predict the ongoing cost to us of complying
with these laws and regulations or the future impact of these laws and
regulations on our operations. Violation of environmental laws, regulations, and
permits can result in the imposition of significant administrative, civil and
criminal penalties, injunctions, and construction bans or delays. A major
discharge of hydrocarbons or hazardous substances into the environment could, to
the extent the event is not insured, subject us to substantial expense,
including both the cost to comply with applicable laws and regulations and
claims made by employees, neighboring landowners and other third parties for
personal injury and property damage.

Under the Omnibus Agreement and certain transportation agreements and purchase
agreements with HFC, HFC has agreed to indemnify us, subject to certain monetary
and time limitations, for environmental noncompliance and remediation
liabilities associated with certain assets transferred to us from HFC and
occurring or existing prior to the date of such transfers.
We have an environmental agreement with Delek with respect to pre-closing
environmental costs and liabilities relating to the pipelines and terminals
acquired from Delek in 2005, under which Delek will indemnify us subject to
certain monetary and time limitations.

There are environmental remediation projects in progress that relate to certain
assets acquired from HFC. Certain of these projects were underway prior to our
purchase and represent liabilities retained by HFC. At September 30, 2021, we
had an accrual of $4.6 million that related to environmental clean-up projects
for which we have assumed liability or for which the indemnity provided for by
HFC has expired or will expire. The remaining projects, including assessment and
monitoring activities, are covered under the HFC environmental indemnification
discussed above and represent liabilities of HFC.


CRITICAL ACCOUNTING POLICIES

Our discussion and analysis of our financial condition and results of operations
are based upon our consolidated financial statements, which have been prepared
in accordance with accounting principles generally accepted in the United
States. The preparation of these financial statements requires us to make
estimates and judgments that affect the reported amounts of assets, liabilities,
revenues and expenses, and related disclosure of contingent assets and
liabilities as of the date of the financial statements. Actual results may
differ from these estimates under different assumptions or conditions. Our
significant accounting policies are described in "Item 7. Management's
Discussion and Analysis of Financial Condition and Operations-Critical
Accounting Policies" in our Annual Report on Form 10-K for the year ended
December 31, 2020. Certain critical
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accounting policies that materially affect the amounts recorded in our
consolidated financial statements include revenue recognition, assessing the
possible impairment of certain long-lived assets and goodwill, and assessing
contingent liabilities for probable losses. There have been no changes to these
policies in 2021. We consider these policies to be critical to understanding the
judgments that are involved and the uncertainties that could impact our results
of operations, financial condition and cash flows.

Accounting positions adopted during the periods presented

Credit Losses Measurement
In June 2016, ASU 2016-13, "Measurement of Credit Losses on Financial
Instruments," was issued requiring measurement of all expected credit losses for
certain types of financial instruments, including trade receivables, held at the
reporting date based on historical experience, current conditions and reasonable
and supportable forecasts. This standard was effective January 1, 2020. Adoption
of the standard did not have a material impact on our financial condition,
results of operations or cash flows.


RISK MANAGEMENT

The market risk inherent in our debt positions is the potential change resulting from increases or decreases in interest rates, as explained below.

At September 30, 2021, we had an outstanding principal balance of $500 million
on our 5% Senior Notes. A change in interest rates generally would affect the
fair value of the 5% Senior Notes, but not our earnings or cash flows. At
September 30, 2021, the fair value of our 5% Senior Notes was $506.8 million. We
estimate a hypothetical 10% change in the yield-to-maturity applicable to the 5%
Senior Notes at September 30, 2021 would result in a change of approximately
$13.1 million in the fair value of the underlying 5% Senior Notes.

For the variable rate Credit Agreement, changes in interest rates would affect
cash flows, but not the fair value. At September 30, 2021, borrowings
outstanding under the Credit Agreement were $840.5 million. A hypothetical 10%
change in interest rates applicable to the Credit Agreement would not materially
affect our cash flows.

Our operations are subject to normal hazards of operations, including but not
limited to fire, explosion, cyberattacks and weather-related perils. We maintain
various insurance coverages, including property damage, business interruption
and cyber insurance, subject to certain deductibles and insurance policy terms
and conditions. We are not fully insured against certain risks because such
risks are not fully insurable, coverage is unavailable, or premium costs, in our
judgment, do not justify such expenditures.

We have a risk management oversight committee that is made up of members from
our senior management. This committee monitors our risk environment and provides
direction for activities to mitigate, to an acceptable level, identified risks
that may adversely affect the achievement of our goals.

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