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OFFON

HOLLY ENERGY PARTNERS, L.P.

(HEP)
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Holly Energy Partners L P : LP Management's Discussion and Analysis of Financial Condition and Results of Operations (form 10-Q)

05/05/2021 | 03:20pm EDT
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 March 31, 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 growth of 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.

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 has 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.
Over the course of the last three quarters, demand for transportation fuels
showed incremental improvement over the second quarter of 2020. We expect our
customers will continue to adjust refinery production levels commensurate with
market demand and ultimately expect demand to return to pre-COVID-19 levels.

In response to the COVID-19 pandemic, and with the health and safety of our
employees as a top priority, we took several actions, including limiting onsite
staff at all of our facilities, implementing a work-from-home policy for certain
employees and restricting travel unless approved by senior leadership. We will
continue to monitor COVID-19 developments and the dynamic environment to
properly address these policies going forward.

In light of current circumstances and our expectations for the future, HEP
reduced its quarterly distribution to $0.35 per unit beginning with the
distribution for the first quarter of 2020, representative of a new distribution
strategy focused on funding all capital expenditures and distributions within
operating cash flow and improving distributable cash flow coverage to 1.3x or
greater with the goal of reducing leverage to 3.0-3.5x.

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, 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 2021 to 2036.
These minimum volume commitments accounted for approximately 71% and 76% of our
total revenues in the three months ended March 31, 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, other than with respect to the agreement reached with HFC with respect
to HEP's Cheyenne assets, which became effective on January 1, 2021 and is
discussed below. In addition to these payments, we
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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. 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, 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 is expected to be placed in service during 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, and HEP estimates its share of the cost of
the Cushing Connect JV Terminal contributed by Plains and Cushing Connect
Pipeline construction costs are approximately $65 million to $70 million.
However, we are solely responsible for any Cushing Connect Pipeline construction
costs which exceed 10% of the budget.

Agreements with HFC
We serve HFC's refineries under long-term pipeline, terminal, tankage and
refinery processing unit throughput agreements expiring from 2021 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 March 31, 2021, these agreements with HFC require
minimum annualized payments to us of $338 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.


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.

HEP and HFC finalized and executed new agreements for HEP's Cheyenne assets on
February 8, 2021, 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.


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Indicators of goodwill and long-lived asset impairment
The changes in our new 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 5 for further discussion of Level 3 inputs.

Our interim impairment testing of our Cheyenne reporting unit goodwill identified an impairment charge of $11.0 million, which was recorded in the three months ended March 31, 2021.


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.

Furthermore, we plan to continue to pursue third-party logistic asset acquisitions that are accretive to our unitholders and increase the diversity of our revenues.

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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 months ended March 31, 2021 and 2020.

                                     - 33 -

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Table of

                                                                             Three Months Ended March 31,               Change from
                                                                               2021                   2020                 2020
                                                                                    (In thousands, except per unit data)
Revenues:
Pipelines:
Affiliates-refined product pipelines                                    $   

18,606 $ 20,083 $ (1,477) Affiliates-intermediate pipelines

                                                 7,506                7,474                    32
Affiliates-crude pipelines                                                       19,454               20,393                  (939)
                                                                                 45,566               47,950                (2,384)
Third parties-refined product pipelines                                           9,863               14,798                (4,935)
Third parties-crude pipelines                                                    11,076                7,724                 3,352
                                                                                 66,505               70,472                (3,967)
Terminals, tanks and loading racks:
Affiliates                                                                       33,864               33,594                   270
Third parties                                                                     4,318                3,904                   414
                                                                                 38,182               37,498                   684

Refinery processing units-Affiliates                                             22,496               19,884                 2,612

Total revenues                                                                  127,183              127,854                  (671)
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)                          41,365               34,981                 6,384
Depreciation and amortization                                                    25,065               23,978                 1,087
General and administrative                                                        2,968                2,702                   266
Goodwill impairment                                                              11,034                    -                11,034
                                                                                 80,432               61,661                18,771
Operating income                                                                 46,751               66,193               (19,442)
Other income (expense):
Equity in earnings of equity method investments                                   1,763                1,714                    49
Interest expense, including amortization                                        (13,240)             (17,767)                4,527
Interest income                                                                   6,548                2,218                 4,330
Loss on early extinguishment of debt                                                  -              (25,915)               25,915
Gain on sales-type leases                                                        24,650                    -                24,650
Gain on sale of assets and other                                                    502                  506                    (4)
                                                                                 20,223              (39,244)               59,467
Income before income taxes                                                       66,974               26,949                40,025
State income tax expense                                                            (37)                 (37)                    -
Net income                                                                       66,937               26,912                40,025

Allocation of net income attributable to noncontrolling interests

      (2,540)              (2,051)                 (489)
Net income attributable to the partners                                          64,397               24,861                39,536

Limited partners' earnings per unit-basic and diluted                   $   

0.61 $ 0.24 $ 0.37 Weighted average limited partners' units outstanding

    105,440              105,440                     -
EBITDA (1)                                                              $        96,191          $    64,425          $     31,766
Adjusted EBITDA (1)                                                     $  

87,936 $ 91,109 $ (3,173) Distributable cash flow (2)

                                             $   

73,218 $ 70,708 $ 2,510


Volumes (bpd)
Pipelines:
Affiliates-refined product pipelines                                            119,590              129,966               (10,376)
Affiliates-intermediate pipelines                                               115,225              142,112               (26,887)
Affiliates-crude pipelines                                                      250,647              305,031               (54,384)
                                                                                485,462              577,109               (91,647)
Third parties-refined product pipelines                                          44,428               49,637                (5,209)
Third parties-crude pipelines                                                   123,232               92,203                31,029
                                                                                653,122              718,949               (65,827)
Terminals and loading racks:
Affiliates                                                                      323,286              429,730              (106,444)
Third parties                                                                    45,753               45,945                  (192)
                                                                                369,039              475,675              (106,636)
Refinery processing units-Affiliates                                             60,699               69,795                (9,096)
Total for pipelines and terminal and refinery processing unit
assets (bpd)                                                                  1,082,860            1,264,419              (181,559)


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(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) pipeline tariffs not
included in revenues due to impacts from lease accounting for certain pipeline
tariffs minus (iv) gain on sales-type leases, and (v) pipeline lease payments
not included in operating costs and expenses. Portions of our minimum guaranteed
pipeline tariffs 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 pipeline tariffs 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
                                                            March 31,
                                                        2021           2020
                                                           (In thousands)
Net income attributable to the partners             $   64,397      $ 24,861
Add (subtract):
Interest expense                                        13,240        17,767
Interest income                                         (6,548)       (2,218)
State income tax expense                                    37            37
Depreciation and amortization                           25,065        

23,978

EBITDA                                              $   96,191      $ 

64,425

Loss on early extinguishment of debt                         -        25,915
Gain on sales-type leases                              (24,650)            -
Goodwill impairment                                     11,034             -

Pipeline tariffs not included in revenues                6,967         

2,375

Lease payments not included in operating costs (1,606) (1,606) Adjusted EBITDA

                                     $   87,936      $ 91,109



(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
                                                                       March 31,
                                                                   2021           2020
                                                                      (In thousands)
Net income attributable to the partners                        $   64,397      $ 24,861
Add (subtract):
Depreciation and amortization                                      25,065   

23,978

Amortization of discount and deferred debt issuance costs             844   

799

Loss on early extinguishment of debt                                    -   

25,915

Customer billings greater than revenue recognized                   3,394   

264

Maintenance capital expenditures (3)                               (1,372)  

(2,487)

Increase (decrease) in environmental liability                       (156)  

1

Decrease in reimbursable deferred revenue                          (4,014)       (2,800)
Gain on sales-type leases                                         (24,650)            -
Goodwill impairment                                                11,034             -
Other                                                              (1,324)          177
Distributable cash flow                                        $   73,218      $ 70,708



(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.
                                   March 31,       December 31,
                                     2021              2020
                                         (In thousands)
Balance Sheet Data
Cash and cash equivalents        $    19,753      $     21,990
Working capital                  $    20,275      $     14,247
Total assets                     $ 2,170,526      $  2,167,565
Long-term debt                   $ 1,388,335      $  1,405,603
Partners' equity                 $   405,976      $    379,292



Results of Operations-Three Months Ended March 31, 2021 Compared with Three Months Ended March 31, 2020

Summary

Net income attributable to the partners for the first quarter was $64.4 million
($0.61 per basic and diluted limited partner unit) compared to $24.9 million
($0.24 per basic and diluted limited partner unit) for the first quarter of
2020. Results for the first quarter of 2021 reflect special items that
collectively increased net income attributable to the partners by a total of
$13.6 million. These items included a gain on sales-type leases of $24.7 million
and a goodwill impairment charge of $11.0 million related to our Cheyenne
assets. In addition, net income attributable to the partners for the first
quarter of 2020 included a loss on early extinguishment of debt of $25.9
million. Excluding these items, net income attributable to the partners for both
the first quarters of 2021 and 2020 was $50.8 million ($0.48 per basic and
diluted limited partner unit).

Revenues

Revenues for the first quarter were $127.2 million, a decrease of $0.7 million
compared to the first quarter of 2020. The decrease was mainly attributable to a
9% reduction in overall crude and product pipeline volumes. Revenues did not
decrease in proportion to the decrease in volumes mainly due to contractual
minimum volume guarantees as well as the recognition in revenue of $6.5 million
of the $10 million termination fee related to the termination of HFC's existing
minimum volume commitment on our Cheyenne assets.

Revenues from our refined product pipelines were $28.5 million, a decrease of
$6.4 million compared to the first quarter of 2020. Shipments averaged 164.0
thousand barrels per day ("mbpd") compared to 179.6 mbpd for the first quarter
of 2020.
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  Table of
The volume and revenue decreases were mainly due to lower volumes on pipelines
servicing HFC's Navajo refinery, Delek's Big Spring refinery and our UNEV
pipeline. Revenue also decreased due to a reclassification of certain pipeline
income from revenue to interest income under sales-type lease accounting.

Revenues from our intermediate pipelines were $7.5 million, consistent with the
first quarter of 2020. Shipments averaged 115.2 mbpd for the first quarter of
2021 compared to 142.1 mbpd for the first quarter of 2020. The decrease in
volumes was mainly due to lower throughputs on our intermediate pipelines
servicing HFC's Navajo refinery while revenue remained relatively constant
mainly due to contractual minimum volume guarantees.

Revenues from our crude pipelines were $30.5 million, an increase of $2.4
million compared to the first quarter of 2020, and shipments averaged 373.9 mbpd
compared to 397.2 mbpd for the first quarter of 2020. The revenue increase was
mainly attributable to higher volumes on our crude pipeline systems in Wyoming
and Utah. Those volume increases were more than offset by decreased volumes on
our crude pipeline systems in New Mexico and Texas. Revenues did not decrease in
proportion to the decrease in volumes mainly due to contractual minimum volume
guarantees.

Revenues from terminal, tankage and loading rack fees were $38.2 million, an
increase of $0.7 million compared to the first quarter of 2020. Refined products
and crude oil terminalled in the facilities averaged 369.0 mbpd compared to
475.7 mbpd for the first quarter of 2020. The volume decrease was mainly the
result of lower throughputs at HFC's Tulsa refinery as well as the cessation of
petroleum refinery operations at HFC's Cheyenne refinery. Revenues did not
decrease in proportion to the decrease in volumes mainly due to the recognition
of $6.5 million of the $10 million termination fee related to the termination of
HFC's existing minimum volume commitment on our Cheyenne assets and contractual
minimum volume guarantees partially offset by lower on-going revenues on our
Cheyenne assets as a result of the conversion of the HFC Cheyenne refinery to
renewable diesel production.

Revenues from refinery processing units were $22.5 million, an increase of $2.6
million compared to the first quarter of 2020, and throughputs averaged 60.7
mbpd compared to 69.8 mbpd for the first quarter of 2020. The decrease in
volumes was mainly due to reduced throughput for both our Woods Cross and El
Dorado processing units largely as a result of extreme weather while revenue
increased due to higher recovery of natural gas costs.

Operations Expense
Operations (exclusive of depreciation and amortization and goodwill impairment)
expense was $41.4 million for the three months ended March 31, 2021, an increase
of $6.4 million compared to the first quarter of 2020. The increase was mainly
due to higher natural gas costs and maintenance expense project costs, partially
offset by lower expenses for materials and supplies, chemicals and catalysts and
property tax for the three months ended March 31, 2021.

Depreciation and Amortization
Depreciation and amortization for the three months ended March 31, 2021
increased by $1.1 million compared to the three months ended March 31, 2020. The
increase was mainly due to the acceleration of depreciation on certain of our
Cheyenne tanks.

General and Administrative
General and administrative costs for the three months ended March 31, 2021
increased by $0.3 million compared to the three months ended March 31, 2020,
mainly due to higher legal expenses for the three months ended March 31, 2021.

Equity in Earnings of Equity Method Investments

                                              Three Months Ended March 31,
        Equity Method Investment                    2021                   

2020

                                                     (in thousands)
        Osage Pipe Line Company, LLC   $          721                    $ 1,014
        Cheyenne Pipeline LLC                    (104)                     1,075
        Cushing Terminal                        1,146                       (375)
        Total                          $        1,763                    $ 1,714



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  Table of
Equity in earnings of Osage Pipe Line Company, LLC and Cheyenne Pipeline LLC
decreased for the three months ended March 31, 2021, mainly due to lower
throughput volumes. Equity in earnings of Cushing Terminal increased for the
three months ended March 31, 2021 as the terminal started operations in the
second quarter of 2020.

Interest Expense
Interest expense for the three months ended March 31, 2021, totaled $13.2
million, a decrease of $4.5 million compared to the three months ended March 31,
2020. The decrease was mainly due to market interest rate decreases under our
senior secured revolving credit facility and refinancing our $500 million
aggregate principal amount of 6% Senior Notes due 2024 ("6% Senior Notes") with
$500 million aggregate principal amount of 5% Senior Notes due 2028 ("5% Senior
Notes"). Our aggregate effective interest rates were 3.5% and 4.5% for the three
months ended March 31, 2021 and 2020, respectively.

State Income Tax
We recorded a state income tax expense of $37,000 for both the three months
ended March 31, 2021 and 2020. All tax expense is solely attributable to the
Texas margin tax.


LIQUIDITY AND CAPITAL RESOURCES

Overview

As of March 31, 2021, we had a $1.4 billion senior secured revolving credit
facility (the "Credit Agreement") maturing in July 2022. On April 30, 2021, the
Credit Agreement was amended, (the "Amended 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 Amended Credit Agreement is available to
fund capital expenditures, investments, acquisitions, distribution payments and
working capital and for general partnership purposes. The Amended 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 Amended Credit Agreement up to a maximum amount
of $1.7 billion.

During the three months ended March 31, 2021, we received advances totaling
$73.0 million and repaid $90.5 million, resulting in a net decrease of $17.5
million under the Credit Agreement and an outstanding balance of $896.0 million
at March 31, 2021. As of March 31, 2021, we have no letters of credit
outstanding under the Credit Agreement and the available capacity under the
Credit Agreement was $504.0 million. Amounts repaid under the Credit Agreement
may be reborrowed under the Amended Credit Agreement 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 three months ended March 31, 2021. As of March 31, 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 cash balances, future internally generated funds 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.

In February 2021, we paid a regular quarterly cash distribution of $0.35 on all units in an aggregate amount of $37.0 million.

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Table of


Cash and cash equivalents decreased by $2.2 million during the three months
ended March 31, 2021. The cash flows provided by operating activities of $82.1
million were less than the cash flows used for financing activities of $54.3
million and investing activities of $30.0 million. Working capital increased by
$6.0 million to $20.3 million at March 31, 2021, from $14.2 million at
December 31, 2020.

Cash Flows-Operating Activities
Cash flows from operating activities increased by $4.2 million from $77.9
million for the three months ended March 31, 2020, to $82.1 million for the
three months ended March 31, 2021. The increase was mainly due to lower payments
for interest expenses and operating expenses partially offset by lower cash
receipts from customers during the three months ended March 31, 2021, as
compared to the three months ended March 31, 2020.

Cash Flows-Investing Activities
Cash flows used for investing activities were $30.0 million for the three months
ended March 31, 2021, compared to $20.9 million for the three months ended
March 31, 2020, an increase of $9.2 million. During the three months ended
March 31, 2021 and 2020, we invested $33.2 million and $18.9 million,
respectively, in additions to properties and equipment. We received $2.9 million
in excess of equity in earnings during the three months ended March 31, 2021.

Cash Flows-Financing Activities
Cash flows used for financing activities were $54.3 million for the three months
ended March 31, 2021, compared to $51.1 million for the three months ended
March 31, 2020, an increase of $3.3 million. During the three months ended
March 31, 2021, we received $73.0 million and repaid $90.5 million in advances
under the Credit Agreement. Additionally, we paid $38.3 million in regular
quarterly cash distributions to our limited partners and $3.8 million to our
noncontrolling interests. We received $6.3 million in contributions from
noncontrolling interests during the three months ended March 31, 2021. During
the three months ended March 31, 2020, we received $112.0 million and repaid
$67.0 million in advances under the Credit Agreement. We paid $68.5 million in
regular quarterly cash distributions to our limited partners, and distributed
$3.0 million to our noncontrolling interests. We also received net proceeds of
$491.5 million for issuance of our 5% Senior Notes and paid $522.5 million to
retire our 6% Senior Notes.

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 $14 million to $18 million for maintenance capital
expenditures, $5 million to $8 million for refinery unit turnarounds and $30
million to $35 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.
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Table of 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% 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
On March 31, 2021, we had a $1.4 billion Credit Agreement maturing in July 2022.
On April 30, 2021, the Credit Agreement was amended (the "Amended 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 amended
Credit Agreement is available to fund capital expenditures, investments,
acquisitions, distribution payments and working capital and for general
partnership purposes. The Amended 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
Amended Credit Agreement up to a maximum amount of $1.7 billion.

Our obligations under the Amended Credit Agreement are collateralized by
substantially all of our assets, and indebtedness under the Amended Credit
Agreement is guaranteed by our material, wholly-owned subsidiaries. The Amended
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 Amended Credit
Agreement, HEP obtains two investment grade credit ratings, the Amended 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 Amended 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 March 31, 2021.

Senior Notes
As of March 31, 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 March 31, 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.

Indebtedness under the 5% Senior Notes is guaranteed by all of our existing wholly-owned subsidiaries (other than Holly Energy Finance Corp. and certain immaterial subsidiaries).



                                     - 40 -
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  Table of
Long-term Debt
The carrying amounts of our long-term debt are as follows:
                                       March 31,       December 31,
                                         2021              2020
                                             (In thousands)
Credit Agreement                     $   896,000      $    913,500

5% Senior Notes
Principal                                500,000           500,000
Unamortized debt issuance costs           (7,665)           (7,897)
                                         492,335           492,103

Total long-term debt                 $ 1,388,335      $  1,405,603


Contractual Obligations There were no significant changes to our long-term contractual obligations during the quarter ended March 31, 2021.


Impact of Inflation
Inflation in the United States has been relatively moderate in recent years and
did not have a material impact on our results of operations for the three months
ended March 31, 2021 and 2020. PPI has increased an average of 0.9% annually
over the past five calendar years, including a decrease of 1.3% in 2020 and an
increase of 0.8% in 2019.

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. 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 March 31, 2021, we had an
accrual of $4.4 million that related to environmental clean-up projects for
which we have assumed liability or for which the indemnity
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Table of 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 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 Pronouncements 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 arising from increases or decreases in interest rates as discussed below.


At March 31, 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 March 31,
2021, the fair value of our 5% Senior Notes was $505.0 million. We estimate a
hypothetical 10% change in the yield-to-maturity applicable to the 5% Senior
Notes at March 31, 2021 would result in a change of approximately $14.2 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 March 31, 2021, borrowings outstanding
under the Credit Agreement were $896.0 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 and weather-related perils. We maintain various
insurance coverages, including property damage and business interruption
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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Table of

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