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MarketScreener Homepage  >  Equities  >  Nyse  >  Holly Energy Partners, L.P.    HEP

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-K)

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02/20/2020 | 05:20pm EDT
This Item 7, including but not limited to the sections on "Liquidity and Capital
Resources," contains forward-looking statements. See "Forward-Looking
Statements" at the beginning of Part I and Item 1A. "Risk Factors." In this
document, the words "we," "our," "ours" and "us" refer to 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 HFC and other refineries in the
Mid-Continent, Southwest and Northwest regions of the United States and Delek's
refinery in Big Spring, Texas. 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 partner
interest as of December 31, 2019.

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 or store, and therefore
we are not directly exposed to changes in commodity prices.

We believe the long-term growth of global refined product demand and US crude
production should support high utilization rates for the refineries we serve,
which in turn will support volumes in our product pipelines, crude gathering
system and terminals.
Acquisitions
On October 31, 2017, we acquired the remaining 75% interest in SLC Pipeline and
the remaining 50% interest in Frontier Aspen from subsidiaries of Plains, for
cash consideration of $250 million. Prior to this acquisition, we held
noncontrolling interests of 25% of SLC Pipeline and 50% of Frontier Aspen. As a
result of the acquisitions, SLC Pipeline and Frontier Aspen are wholly-owned
subsidiaries of HEP.

This acquisition was accounted for as a business combination achieved in stages
with the consideration allocated to the acquisition date fair value of assets
and liabilities acquired. The preexisting equity interests in SLC Pipeline and
Frontier Aspen were remeasured at acquisition date fair value since we will have
a controlling interest, and we recognized a gain on the remeasurement in the
fourth quarter of 2017 of $36.3 million.

SLC Pipeline is the owner of a 95-mile crude pipeline that transports crude oil
into the Salt Lake City area from the Utah terminal of the Frontier Pipeline and
from Wahsatch Station. Frontier Aspen is the owner of a 289-mile crude pipeline
from Casper, Wyoming to Frontier Station, Utah that supplies Canadian and Rocky
Mountain crudes to Salt Lake City area refiners through a connection to the SLC
Pipeline.
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 and construction 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 is expected
to be placed in service during the second quarter of 2020, and the Cushing
Connect Pipeline is expected to be placed in service during the first 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. However, any Cushing
Connect Pipeline construction costs exceeding 10% of the budget are borne solely
by us.



                                     - 47 -
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Agreements with HFC and Delek
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. As of December 31, 2019, these agreements with HFC require minimum
annualized payments to us of $348 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 the HFC agreements could have a
material adverse effect on our results of operations.
We have a pipelines and terminals agreement with Delek expiring in 2020 under
which Delek has agreed to transport on our pipelines and throughput through our
terminals volumes of refined products that result in a minimum level of annual
revenue that also is subject to annual tariff rate adjustments. On September 30,
2019, Delek exercised its first renewal option (the "Renewal") under this
agreement for an additional five year period beginning April 1, 2020, but only
with respect to specific assets. For the refined product pipelines and refined
product terminals that were not subject to the Renewal and which currently
account for approximately $15 million to $16 million of HEP's annual revenues
from Delek, the agreement terminates as of March 31, 2020. In light of this
development, we are exploring other potential options with respect to the
pipeline and terminal assets that were not subject to the Renewal.

We also have a capacity lease agreement under which we lease space to Delek on
our Orla to El Paso pipeline for the shipment of refined product. The terms for
a portion of the capacity under this lease agreement expired in 2018 and were
not renewed, and the remaining portions of the capacity expire in 2020 and 2022.

As of December 31, 2019, these agreements with Delek require minimum annualized
payments to us of $32 million before considering the refined product pipelines
and refined product terminals that were not subject to the Renewal.

Under certain provisions of an omnibus agreement that we have with HFC ("Omnibus
Agreement"), we pay HFC an annual administrative fee ($2.6 million in 2019), 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 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. Our current growth plan is
to continue to pursue purchases of logistic and other assets at HFC's existing
refining locations in New Mexico, Utah, Oklahoma, Kansas and Wyoming. We also
expect 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.


RESULTS OF OPERATIONS


Income, Distributable Cash Flow and Volumes
The following tables present income, distributable cash flow and volume
information for the years ended December 31, 2019, 2018 and 2017. These results
have been adjusted to include the combined results of our Predecessor. See Notes
1 and 2 to the Consolidated Financial Statements of HEP for discussion of the
basis of this presentation.


                                     - 48 -
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                                                      Years Ended December 31,        Change from
                                                       2019              2018             2018
                                                        (In thousands, except per unit data)
Revenues
Pipelines:
Affiliates-refined product pipelines              $     77,443$    82,998$     (5,555 )
Affiliates-intermediate pipelines                       29,558            29,639              (81 )
Affiliates-crude pipelines                              85,415            79,741            5,674
                                                       192,416           192,378               38
Third parties-refined product pipelines                 54,914            54,524              390
Third parties-crude pipelines                           45,301            36,605            8,696
                                                       292,631           283,507            9,124
Terminals, tanks and loading racks:
Affiliates                                             139,655           130,251            9,404
Third parties                                           20,812            17,283            3,529
                                                       160,467           147,534           12,933

Affiliates-refinery processing units                    79,679            75,179            4,500

Total revenues                                         532,777           506,220           26,557
Operating costs and expenses
Operations (exclusive of depreciation and
amortization)                                          161,996           146,430           15,566
Depreciation and amortization                           96,705            98,492           (1,787 )
General and administrative                              10,251            11,040             (789 )
                                                       268,952           255,962           12,990
Operating income                                       263,825           250,258           13,567
Other income (expense):
Equity in earnings of equity method investments          5,180             5,825             (645 )
Interest expense, including amortization               (76,823 )         (71,899 )         (4,924 )
Interest income                                          5,517             2,108            3,409
Gain on sales-type leases                               35,166                 -           35,166
Gain on sale of assets and other                           272               121              151
                                                       (30,688 )         (63,845 )         33,157
Income before income taxes                             233,137           186,413           46,724
State income tax expense                                   (41 )             (26 )            (15 )
Net income                                             233,096           186,387           46,709
Allocation of net income attributable to
noncontrolling interests                                (8,212 )          (7,540 )           (672 )
Net income attributable to the partners                224,884           178,847           46,037
General partner interest in net income
attributable to the partners (1)                             -                 -                -
Limited partners' interest in net income          $    224,884$   178,847$     46,037
Limited partners' earnings per unit-basic and
diluted (1)                                       $       2.13$      1.70$       0.43
Weighted average limited partners' units
outstanding                                            105,440           105,042              398
EBITDA (2)                                        $    392,936$   347,156$     45,780
Adjusted EBITDA (2)                               $    359,308$   347,156$     12,152
Distributable cash flow (3)                       $    271,431$   265,087$      6,344

Volumes (bpd)
Pipelines:
Affiliates-refined product pipelines                   123,986           127,865           (3,879 )
Affiliates-intermediate pipelines                      140,585           144,537           (3,952 )
Affiliates-crude pipelines                             368,699           349,686           19,013
                                                       633,270           622,088           11,182
Third parties-refined product pipelines                 71,545            71,784             (239 )
Third parties-crude pipelines                          132,507           115,933           16,574
                                                       837,322           809,805           27,517
Terminals and loading racks:
Affiliates                                             422,119           413,525            8,594
Third parties                                           61,054            61,367             (313 )
                                                       483,173           474,892            8,281

Affiliates-refinery processing units                    68,780            62,787            5,993

Total for pipelines, terminals and refinery
processing unit assets (bpd)                         1,389,275         1,347,484           41,791



                                     - 49 -
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                                                      Years Ended December 31,        Change from
                                                       2018              2017             2017
                                                        (In thousands, except per unit data)
Revenues
Pipelines:
Affiliates-refined product pipelines              $     82,998$    80,030$      2,968
Affiliates-intermediate pipelines                       29,639            28,732              907
Affiliates-crude pipelines                              79,741            65,960           13,781
                                                       192,378           174,722           17,656
Third parties-refined product pipelines                 54,524            52,379            2,145
Third parties-crude pipelines                           36,605             7,939           28,666
                                                       283,507           235,040           48,467
Terminals, tanks and loading racks:
Affiliates                                             130,251           125,510            4,741
Third parties                                           17,283            16,908              375
                                                       147,534           142,418            5,116

Affiliates-refinery processing units                    75,179            76,904           (1,725 )

Total revenues                                         506,220           454,362           51,858
Operating costs and expenses
Operations (exclusive of depreciation and
amortization)                                          146,430           137,605            8,825
Depreciation and amortization                           98,492            79,278           19,214
General and administrative                              11,040            14,323           (3,283 )
                                                       255,962           231,206           24,756
Operating income                                       250,258           223,156           27,102
Other income (expense):
Equity in earnings of equity method investments          5,825            12,510           (6,685 )
Interest expense, including amortization               (71,899 )         (58,448 )        (13,451 )
Interest income                                          2,108               491            1,617
Loss on early extinguishment of debt                         -           (12,225 )         12,225
Remeasurement gain on preexisting equity
interests                                                    -            36,254          (36,254 )
Gain on sale of assets and other                           121               422             (301 )
                                                       (63,845 )         (20,996 )        (42,849 )
Income before income taxes                             186,413           202,160          (15,747 )
State income tax expense                                   (26 )            (249 )            223
Net income                                             186,387           201,911          (15,524 )
Allocation of net income attributable to
noncontrolling interests                                (7,540 )          (6,871 )           (669 )
Net income attributable to the partners                178,847           195,040          (16,193 )
General partner interest in net income
attributable to the partners (1)                             -           (35,047 )         35,047
Limited partners' interest in net income          $    178,847$   159,993$     18,854
Limited partners' earnings per unit-basic and
diluted (1)                                       $       1.70$      2.28$      (0.58 )
Weighted average limited partners' units
outstanding                                            105,042            70,291           34,751
EBITDA (2)                                        $    347,156$   332,524$     14,632
Adjusted EBITDA (2)                               $    347,156$   344,749$      2,407
Distributable cash flow (3)                       $    265,087$   242,955$     22,132

Volumes (bpd)
Pipelines:
Affiliates-refined product pipelines                   127,865           133,822           (5,957 )
Affiliates-intermediate pipelines                      144,537           141,601            2,936
Affiliates-crude pipelines                             349,686           281,093           68,593
                                                       622,088           556,516           65,572
Third parties-refined product pipelines                 71,784            78,013           (6,229 )
Third parties-crude pipelines                          115,933            21,834           94,099
                                                       809,805           656,363          153,442
Terminals and loading racks:
Affiliates                                             413,525           428,001          (14,476 )
Third parties                                           61,367            68,687           (7,320 )
                                                       474,892           496,688          (21,796 )

Affiliates-refinery processing units                    62,787            63,572             (785 )

Total for pipelines, terminals and refinery
processing unit assets (bpd)                         1,347,484         1,216,623          130,861



                                     - 50 -
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(1)    Net income attributable to the partners is allocated between limited
       partners and the general partner interest in accordance with the
       provisions of the partnership agreement. HEP net income allocated to the
       general partner included incentive distributions that were declared

subsequent to quarter end. After the amount of incentive distributions and

       other priority allocations are allocated to the general partner, the
       remaining net income attributable to the partners is allocated to the
       partners based on their weighted average ownership percentage during the
       period. As a result of the IDR Restructuring Transaction, no IDR or
       general partner distributions were made after October 31, 2017. See
       "Business and Properties - Overview."


(2) Earnings before interest, taxes, depreciation and amortization ("EBITDA")

is calculated as net income attributable to Holly Energy Partners plus (i)

interest expense, net of interest income, (ii) state income tax and (iii)

depreciation and amortization. Adjusted EBITDA is calculated as EBITDA

       minus (i) gain on sales-type leases and (ii) pipeline lease payments not
       included in operating costs and expenses plus (iii) pipeline tariffs not

included in revenues due to impacts from lease accounting. 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 agreement, 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

recoded 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. See our calculation of
       EBITDA under Item 6, "Selected Financial Data."


(3) 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 exception 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. See our calculation of

       distributable cash flow under Item 6, "Selected Financial Data."



Results of Operations - Year Ended December 31, 2019 Compared with Year Ended December 31, 2018

Summary

Net income attributable to the partners for the year ended December 31, 2019,
was $224.9 million, a $46.0 million increase compared to the year ended December
31, 2018. During the third quarter of 2019, HEP and HFC renewed the original
throughput agreement on specific HEP assets. Portions of the new throughput
agreement met the definition of sales-type leases, which resulted in an
accounting gain of $35.2 million upon the initial recognition of the sales-type
leases during the third quarter. Excluding this gain, net income attributable to
the partners was $189.7 million ($1.80 per basic and diluted limited partner
unit), an increase of $10.9 million compared to the same period of 2018. The
increase was mainly attributable to higher crude oil pipeline volumes around the
Permian Basin and our crude pipeline systems in Wyoming and Utah, higher
revenues on our refinery processing units and contractual tariff escalators,
partially offset by higher operating costs and expenses.

Revenues

Revenues for the year ended December 31, 2019, were $532.8 million, a $26.6
million increase compared to the same period in 2018. The increase was mainly
attributable to higher crude oil pipeline volumes around the Permian Basin and
our crude pipeline systems in Wyoming and Utah, higher revenues on our refinery
processing units and contractual tariff escalators.
Revenues from our refined product pipelines were $132.4 million, a decrease of
$5.2 million, on shipments averaging 195.5 mbpd compared to 199.6 mbpd for the
year ended December 31, 2018. The revenue decrease was mainly due to a
reclassification of

                                     - 51 -
--------------------------------------------------------------------------------


some pipeline tariffs from revenue to interest income under sales-type lease
accounting as well as lower volumes on pipelines servicing HollyFrontier'sNavajo refinery partially offset by higher volumes on pipelines servicing HFC's
Woods Cross refinery, which had lower throughput in 2018 due to operational
issues, and contractual tariff escalators.
Revenues from our intermediate pipelines were $29.6 million, a decrease of $0.1
million, on shipments averaging 140.6 mbpd compared to 144.5 mbpd for the year
ended December 31, 2018. The decrease in revenue was primarily attributable to a
decrease in deferred revenue realized.
Revenues from our crude pipelines were $130.7 million, an increase of $14.4
million, on shipments averaging 501.2 mbpd compared to 465.6 mbpd for the year
ended December 31, 2018. The increases were mainly attributable to increased
volumes on our crude pipeline systems in New Mexico and Texas and on our crude
pipeline systems in Wyoming and Utah as well as contractual tariff escalators.
Revenues from terminal, tankage and loading rack fees were $160.5 million, an
increase of $12.9 million compared to the year ended December 31, 2018. Refined
products and crude oil terminalled in the facilities averaged 483.2 mbpd
compared to 474.9 mbpd for the year ended December 31, 2018. The revenue and
volume increases were mainly due to volumes at our new Orla diesel rack, higher
volumes at the Spokane and Catoosa terminals and contractual tariff escalators,
partially offset by lower volumes at HFC's Tulsa refinery as a result of the
planned turnaround in the first quarter and flooding in the second quarter.
Revenues from refinery processing units were $79.7 million, an increase of $4.5
million on throughputs averaging 68.8 mbpd compared to 62.8 mbpd for the year
ended December 31, 2018. The increase in revenue was mainly due to an adjustment
in revenue recognition and contractual rate increases.
Operations Expense
Operations (exclusive of depreciation and amortization) expense for the year
ended December 31, 2019, increased by $15.6 million compared to the year ended
December 31, 2018. The increase for the year ended December 31, 2019 was mainly
due to higher maintenance costs and employee compensation expenses.

Depreciation and Amortization
Depreciation and amortization for the year ended December 31, 2019, decreased by
$1.8 million compared to the year ended December 31, 2018. The decrease was
primarily due to depreciation and amortization related to our normal
fluctuations in business activities.

General and Administrative
General and administrative costs for the year ended December 31, 2019, decreased
by $0.8 million compared to the year ended December 31, 2018, mainly due to
lower employee compensation expenses.

Equity in Earnings of Equity Method Investments
See the summary chart below for a description of our equity in earnings of
equity method investments:
                                          Years Ended December 31,
Equity Method Investment                   2019              2018
                                               (in thousands)
Osage Pipe Line Company, LLC          $      1,344$      1,961
Cheyenne Pipeline LLC                        3,976              3,864
Cushing Connect Terminal Holdings LLC         (140 )                -
Total                                 $      5,180$      5,825



Interest Expense
Interest expense for the year ended December 31, 2019, totaled $76.8 million, an
increase of $4.9 million compared to the year ended December 31, 2018. These
increases were mainly due to higher average balances outstanding under our
senior secured revolving credit facility and higher finance lease liabilities
outstanding. Our aggregate weighted-average interest rates were 5.4% and 5.1%
for the years ended December 31, 2019 and 2018, respectively.

State Income Tax
We recorded state income tax expense of $41,000 and $26,000 for the years ended
December 31, 2019 and 2018, respectively. All state income tax expense is solely
attributable to the Texas margin tax.



                                     - 52 -
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Results of Operations-Year Ended December 31, 2018 Compared with Year Ended December 31, 2017

Summary

Net income attributable to the partners for the year ended December 31, 2018,
was $178.8 million, a $16.2 million decrease compared to the year ended
December 31, 2017. The decrease in earnings was primarily due to the recognition
of a $36.3 million remeasurement gain related to our acquisition of the
remaining interests in SLC Pipeline and Frontier Aspen in the fourth quarter of
2017. Excluding this remeasurement gain, net income attributable to the partners
increased $20.1 million primarily due to higher pipeline throughputs and
revenues as well as increased earnings related to our acquisition of the
remaining interests in SLC Pipeline and Frontier Aspen in the fourth quarter of
2017, which were partially offset by higher interest expense.

Revenues

Revenues for the year ended December 31, 2018, were $506.2 million, a $51.9
million increase compared to the same period of 2017. The increase was primarily
attributable to our acquisition of the remaining interests in SLC Pipeline and
Frontier Aspen in the fourth quarter of 2017 and the turnaround at HFC's Navajo
refinery in the first quarter of 2017.
Revenues from our refined product pipelines were $137.5 million, an increase of
$5.1 million, on shipments averaging 199.6 mbpd compared to 211.8 mbpd for the
year ended December 31, 2017. The volume decrease was mainly due to pipelines
servicing HFC's Woods Cross refinery, which had lower throughput due to
operational issues at the refinery beginning in the first quarter of 2018. These
decreases were partially offset by higher volumes on our product pipelines in
New Mexico due to the turnaround at HFC's Navajo refinery in the first quarter
of 2017. Revenue increased as a result of the higher volumes on the New Mexico
product pipelines and remained relatively consistent around pipelines servicing
HFC's Woods Cross refinery due to contractual minimum volume commitments and
tariff escalators.
Revenues from our intermediate pipelines were $29.6 million, an increase of $0.9
million, on shipments averaging 144.5 mbpd compared to 141.6 mbpd for the year
ended December 31, 2017. These increases were principally due to the turnaround
at HFC's Navajo refinery in the first quarter of 2017 and increased production
of base oil and lubricants at HFC's Tulsa refinery.
Revenues from our crude pipelines were $116.3 million, an increase of $42.4
million, on shipments averaging 465.6 mbpd compared to 302.9 mbpd for the year
ended December 31, 2017. The increases were mainly attributable to our
acquisition of the remaining interests in SLC Pipeline and Frontier Aspen in the
fourth quarter of 2017, as well as increased volumes on our crude pipeline
systems in New Mexico and Texas.
Revenues from terminal, tankage and loading rack fees were $147.5 million, an
increase of $5.1 million compared to the year ended December 31, 2017. Refined
products and crude terminalled in our facilities decreased to an average of
474.9 mbpd compared to 496.7 mbpd for the year ended December 31, 2017. Despite
the decrease in volume, revenue increased primarily due to tariff escalators on
minimum revenue commitments.
Revenues from refinery processing units were $75.2 million, a decrease of $1.7
million on throughputs averaging 62.8 mbpd compared to 63.6 mbpd for 2017. The
reduction in revenue and volume was due to an unplanned outage on our fluid
catalytic cracking unit at HFC's Woods Cross refinery in the fourth quarter of
2018.
Operations Expense
Operations (exclusive of depreciation and amortization) expense for the year
ended December 31, 2018, increased by $8.8 million compared to the year ended
December 31, 2017. The increase was primarily due to new operating expenses
related to our acquisition of the remaining interests in SLC Pipeline and
Frontier Aspen in the fourth quarter of 2017.

Depreciation and Amortization
Depreciation and amortization for the year ended December 31, 2018, increased by
$19.2 million compared to the year ended December 31, 2017. The increase was
primarily due to new operating expenses related to our acquisition of the
remaining interests in SLC Pipeline and Frontier Aspen in the fourth quarter of
2017.

General and Administrative
General and administrative costs for the year ended December 31, 2018, decreased
by $3.3 million compared to the year ended December 31, 2017, mainly due to
higher legal and consulting costs incurred in the year ended December 31, 2017,
associated with the IDR Restructuring Transaction.


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Equity in Earnings of Equity Method Investments See the summary chart below for a description of our equity in earnings of equity method investments:

                                  Years Ended December 31,
Equity Method Investment              2018               2017
                                       (in thousands)
SLC Pipeline LLC             $          -              $  2,267Frontier Aspen LLC                      -                 4,089
Osage Pipe Line Company, LLC        1,961                 2,447
Cheyenne Pipeline LLC               3,864                 3,707
Total                        $      5,825$ 12,510



Interest Expense
Interest expense for the year ended December 31, 2018, totaled $71.9 million, an
increase of $13.5 million compared to the year ended December 31, 2017. The
increase was mainly due to interest expense associated with the private
placement of an additional $100 million in aggregate principal amount of our 6%
Senior Notes due 2024 completed in the third quarter of 2017, higher average
balances outstanding under the Credit Agreement, and market interest rate
increases under the Credit Agreement. Our aggregate weighted-average interest
rates were 5.1% and 4.4% for the years ended December 31, 2018 and 2017,
respectively.

State Income Tax
We recorded state income tax expense of $26,000 and $249,000 for the years ended
December 31, 2018 and 2017, respectively. All state income tax expense is solely
attributable to the Texas margin tax.


LIQUIDITY AND CAPITAL RESOURCES

Overview

We have a $1.4 billion senior secured revolving credit facility (the "Credit
Agreement") expiring in July 2022. 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
contains an accordion feature giving us the ability to increase the size of the
facility by up to $300 million with additional lender commitments.

During the year ended December 31, 2019, we received advances totaling $365.5
million and repaid $323.0 million, resulting in a net increase of $42.5 million
under the Credit Agreement and an outstanding balance of $965.5 million at
December 31, 2019. As of December 31, 2019, we had no letters of credit
outstanding under the Credit Agreement, and the available capacity under the
Credit Agreement was $434.5 million.
If any particular lender under the Credit Agreement could not honor its
commitment, we believe the unused capacity that would be available from the
remaining lenders would be sufficient to meet our borrowing needs. Additionally,
we review publicly available information on the lenders in order to monitor
their financial stability and assess their ongoing ability to honor their
commitments under the Credit Agreement. We do not expect to experience any
difficulty in the lenders' ability to honor their respective commitments, and if
it were to become necessary, we believe there would be alternative lenders or
options available.

On February 4, 2020, we closed a private placement of $500 million in aggregate
principal amount of 5% senior unsecured notes due in 2028 (the "5% Senior
Notes"). On February 5, 2020, we redeemed the existing $500 million 6% Senior
Notes at a redemption cost of $522.5 million. We will record any early
extinguishment losses associated with this redemption during the first quarter
of 2020. We funded the $522.5 million redemption with proceeds from the issuance
of our 5% Senior Notes and borrowings under our Credit Agreement.

On January 25, 2018, we entered into a common unit purchase agreement in which
certain purchasers agreed to purchase in a private placement 3,700,000 common
units representing limited partnership interests, at a price of $29.73 per
common unit. The private placement closed on February 6, 2018, and we received
proceeds of approximately $110 million, which were used to repay indebtedness
under the Credit Agreement. After this common unit issuance, HFC owns a 57%
limited partner interest in us.


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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. As of December 31, 2019, HEP has
issued 2,413,153 units under this program, providing $82.3 million in gross
proceeds.

On October 31, 2017, we closed on an equity restructuring transaction with HEP
Logistics, a wholly-owned subsidiary of HFC and the general partner of HEP,
pursuant to which the incentive distribution rights held by HEP Logistics were
canceled, and HEP Logistics' 2% general partner interest in HEP was converted
into a non-economic general partner interest in HEP. In consideration, we issued
37,250,000 of our common units to HEP Logistics. In addition, HEP Logistics
agreed to waive $2.5 million of limited partner cash distributions for each of
twelve consecutive quarters beginning with the first quarter the units issued as
consideration were eligible to receive distributions. This waiver of limited
partner cash distributions will expire after the cash distribution for the
second quarter of 2020, which will be made during the third quarter of 2020.

On September 22, 2017, we closed a private placement of an additional $100
million in aggregate principal of our 6.0% Senior Notes for a combined aggregate
principal amount outstanding of $500 million maturing in 2024. The proceeds were
used to repay indebtedness outstanding under the Credit Agreement.

Under our registration statement filed with the SEC using a "shelf" registration
process, we currently have the authority to raise up to $2.0 billion, less
amounts issued under the $200 million continuous offering program, 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 would 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 needs for the foreseeable future.


In February, May, August and November 2019, we paid regular quarterly cash
distributions of $0.6675, $0.6700, $0.6725 and $0.6725, on all units in an
aggregate amount of $273.2 million. In February 2020, we paid a regular cash
distribution of $0.6725 on all units in an aggregate amount of $68.5 million
after deducting HEP Logistics' waiver of $2.5 million of limited partner cash
distributions.

Cash and cash equivalents increased by $10.2 million during the year ended
December 31, 2019. The cash flows provided by operating activities of $297.1
million were more than the cash flows used for investing and financing
activities of $46.3 million and $240.6 million, respectively. Working capital
increased by $12.2 million to a surplus of $20.8 million at December 31, 2019
from a surplus of $8.6 million at December 31, 2018.

Cash Flows-Operating Activities
Year Ended December 31, 2019 Compared with Year Ended December 31, 2018
Cash flows provided by operating activities increased by $1.8 million from
$295.2 million for the year ended December 31, 2018, to $297.1 million for the
year ended December 31, 2019. This increase was mainly due to higher receipts
from customers partially offset by higher payments for interest and operating
expenses in the year ended December 31, 2019, as compared to the prior year.

Year Ended December 31, 2018 Compared with Year Ended December 31, 2017
Cash flows from operating activities increased by $56.7 million from $238.5
million for the year ended December 31, 2017, to $295.2 million for the year
ended December 31, 2018. This increase was mainly due to higher receipts from
customers partially offset by higher payments for interest and operating
expenses in the year ended December 31, 2018, as compared to the prior year. The
increase in customer receipts was primarily attributable to our acquisition of
the remaining interests in SLC Pipeline and Frontier Aspen in the fourth quarter
of 2017.

Cash Flows-Investing Activities
Year Ended December 31, 2019 Compared with Year Ended December 31, 2018
Cash flows used for investing activities decreased by $6.1 million from $52.3
million for the year ended December 31, 2018, to $46.3 million for the year
ended December 31, 2019. During the years ended December 31, 2019 and 2018, we
invested $30.1 million and $47.3 million in additions to properties and
equipment, respectively. During the year ended December 31, 2019, we acquired a
50% interest in Cushing Connect Pipeline & Terminal LLC for $17.9 million.
Additionally, we acquired businesses and assets for $5.1 million during the year
ended December 31, 2018.


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Year Ended December 31, 2018 Compared with Year Ended December 31, 2017
Cash flows used for investing activities decreased by $233.9 million from $286.3
million for the year ended December 31, 2017, to $52.3 million for the year
ended December 31, 2018. During the years ended December 31, 2018 and 2017, we
invested $47.3 million and $44.8 million in additions to properties and
equipment, respectively. During the year ended December 31, 2018, we acquired
businesses and assets for $5.1 million. Additionally, we acquired the remaining
75% interest in SLC Pipeline and 50% interest in Frontier Aspen for $245.4
million in October 2017.

Cash Flows-Financing Activities
Year Ended December 31, 2019 Compared with Year Ended December 31, 2018
Cash flows used for financing activities decreased by $7.0 million from $247.6
million for the year ended December 31, 2018, to $240.6 million for the year
ended December 31, 2019. During the year ended December 31, 2019, we received
$365.5 million and repaid $323.0 million in advances under the Credit Agreement.
Additionally, we paid $273.2 million in regular quarterly cash distributions to
HEP unitholders and $9.0 million to our noncontrolling interest. During the year
ended December 31, 2018, we received $337.0 million and repaid $426.0 million in
advances under the Credit Agreement. We also received net proceeds of $114.8
million from the issuance of common units. Additionally, we paid $265.0 million
in regular quarterly cash distributions to HEP unitholders and $7.5 million to
our noncontrolling interest.

Year Ended December 31, 2018 Compared with Year Ended December 31, 2017
Cash flows used for financing activities were $247.6 million for the year ended
December 31, 2018, compared to cash flows provided by financing activities of
$51.9 million for the year ended December 31, 2017, a decrease of $299.5
million. During the year ended December 31, 2018, we received $337.0 million and
repaid $426.0 million in advances under the Credit Agreement. We also received
net proceeds of $114.8 million from issuance of common units. Additionally, we
paid $265.0 million in regular quarterly cash distributions to HEP unitholders
and $7.5 million to our noncontrolling interest. During the year ended
December 31, 2017, we received $969.0 million and repaid $510.0 million in
advances under the Credit Agreement. We also received net proceeds of $101.8
million from the issuance of our 6% Senior Notes and $52.1 million from the
issuance of common units. Additionally, we paid $309.8 million for the
redemption of our 6.5% Senior Notes, $234.6 million in regular quarterly cash
distributions to our general and limited partners and $6.5 million to our
noncontrolling interest. We also paid $9.4 million in deferred financing charges
to amend the Credit Agreement.

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. The 2020 capital budget is
comprised of approximately $8 million to $12 million for maintenance capital
expenditures, $5 million to $7 million for refinery unit turnarounds and $45 to
$50 million for expansion capital expenditures and our share of Cushing Connect
Joint Venture investments. We expect the majority of the 2020 expansion capital
budget 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 expenditures for acquisitions and capital development
projects, will be funded with cash generated by operations, the sale of
additional limited partner common units, the issuance of debt securities and
advances under our Credit Agreement, or a combination thereof. With volatility
and uncertainty at times in the credit and equity markets, there may be limits
on our ability to issue new debt or equity financing. Additionally, due to
pricing movements in the debt and equity markets, we may not be able to issue
new debt and equity securities

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at acceptable pricing. Without additional capital beyond amounts available under the Credit Agreement, our ability to obtain funds for some of these capital projects may be limited.


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
We have a $1.4 billion senior secured revolving credit facility (the "Credit
Agreement") expiring in July 2022. 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
contains an accordion feature giving us the ability to increase the size of the
facility by up to $300 million with additional lender commitments. As of
December 31, 2019, we had outstanding borrowings of $965.5 million under the
Credit Agreement, no letters of credit outstanding, and the available capacity
was $434.5 million.

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 all covenants as of
December 31, 2019.

Indebtedness under the Credit Agreement bears interest, at our option, at either
(a) the reference rate as announced by the administrative agent plus an
applicable margin (ranging from 0.50% to 1.50%) or (b) at a rate equal to LIBOR
plus an applicable margin (ranging from 1.50% to 2.50%). In each case, the
applicable margin is based upon the ratio of our funded debt (as defined in the
Credit Agreement) to EBITDA (earnings before interest, taxes, depreciation and
amortization, as defined in the Credit Agreement). The weighted-average interest
rates on our Credit Agreement borrowings for both the years ending December 31,
2019 and 2018, were 4.24%. We incur a commitment fee on the unused portion of
the Credit Agreement at an annual rate ranging from 0.25% to 0.50% based upon
the ratio of our funded debt to EBITDA for the four most recently completed
fiscal quarters.

Senior Notes
On January 4, 2017, we redeemed the $300 million aggregate principal amount of
our 6.5% Senior Notes at a redemption cost of $309.8 million, at which time we
recognized a $12.2 million early extinguishment loss. We funded the redemption
with borrowings under our Credit Agreement.

As of December 31, 2019, we had $500 million in aggregate principal amount of 6%
Senior Notes due in 2024. We used the net proceeds from our offerings of the 6%
Senior Notes to repay indebtedness under our Credit Agreement.

The 6% Senior Notes were unsecured and imposed 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 6% Senior Notes as of December 31, 2019.

Indebtedness under the 6% Senior Notes was guaranteed by our wholly-owned subsidiaries.


On February 4, 2020, we closed the private placement of $500 million in
aggregate principal amount of 5.0% senior unsecured notes due in 2028 (the "5%
Senior Notes"). On February 5, 2020, redeemed the existing $500 million 6%
Senior Notes at a redemption cost of $522.5 million. We will record any early
extinguishment losses associated with this redemption during the first quarter
of 2020. 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. At any time when the 5%
Senior Notes are rated investment grade by either Moody's or Standard & Poor's
and no

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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 our wholly-owned subsidiaries.


Long-term Debt
The carrying amounts of our long-term debt are as follows:
                                   December 31,     December 31,
                                       2019             2018
                                          (In thousands)
Credit Agreement                  $    965,500$    923,000

6% Senior Notes
Principal                              500,000          500,000

Unamortized debt issuance costs (3,469 ) (4,100 )

                                       496,531          495,900

Total long-term debt              $  1,462,031$  1,418,900

See "Risk Management" for a discussion of our interest rate swaps.


Long-term Contractual Obligations
The following table presents our long-term contractual obligations as of
December 31, 2019.

                                                                         Payments Due by Period
                                                         Less than                                      Over 5
                                           Total          1 Year         1-3 Years      3-5 Years        Years
                                                                     (In thousands)
Long-term debt - principal             $ 1,465,500     $         -     $   965,500$  500,000     $       -
Long-term debt - interest                  227,200          64,900         114,800         47,500             -
Site service fees                          248,073           5,444          10,888         10,888       220,853
Pipeline finance lease                      49,248           6,566          13,133         13,133        16,416
Right-of-way agreements and other           17,725           4,253           6,288          2,054         5,131
Total                                  $ 2,007,746$    81,163$ 1,110,609$  573,575$ 242,400


Long-term debt consists of outstanding principal under the Credit Agreement and
the Senior Notes. Interest on the Credit Agreement is calculated using the rate
in effect at December 31, 2019.
Site service fees consist of site service agreements with HFC, expiring in 2058
through 2066, for the provision of certain facility services and utility costs
that relate to our assets located at HFC's refinery facilities. We are
presenting obligations for the full term of these agreements; however, the
agreements can be terminated with 180 day notice if we cease to operate the
applicable assets.
The pipeline finance lease amounts above reflect the exercise of the second
10-year extension, expiring in 2027, on our lease agreement for the refined
products pipeline between White Lakes Junction and Kuntz Station in New Mexico.
Most of our right-of-way agreements are renewable on an annual basis, and the
right-of-way agreements payments above include only obligations under the
remaining non-cancelable terms of these agreements at December 31, 2019. For the
foreseeable future, we intend to continue renewing these agreements and expect
to incur right-of-way expenses in addition to the payments listed.
Other contractual obligations include capital lease obligations related to
vehicles leases, office space leases, and other.

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 years ended
December 31, 2019, 2018 and 2017. PPI has increased an average of 0.6% annually
over the past five calendar years, including increases of 0.8% and 3.1% in 2019
and 2018, respectively.


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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.
Contamination resulting from spills of refined products and crude oil is not
unusual within the petroleum pipeline industry. Historic spills along our
existing pipelines and terminals as a result of past operations have resulted in
contamination of the environment, including soils and groundwater. Site
conditions, including soils and groundwater, are being evaluated at a few of our
properties where operations may have resulted in releases of hydrocarbons and
other wastes, none of which we believe will have a significant effect on our
operations since the remediation of such releases would be covered under
environmental indemnification agreements.
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.
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. As of December 31, 2019, we
have an accrual of $5.5 million that relates to environmental clean-up projects
for which we have assumed liability or for which the indemnity provided for by
HFC has expired. 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. We
consider the following policies to be the most critical to understanding the
judgments that are involved and the uncertainties that could impact our results
of operations, financial condition and cash flows.

Revenue Recognition
Revenues are generally recognized as products are shipped through our pipelines
and terminals, feedstocks are processed through our refinery processing units or
other services are rendered. The majority of our contracts with customers meet
the definition of a lease since (1) performance of the contracts is dependent on
specified property, plant, or equipment and (2) the possibility is remote that
one or more parties other than the customer will take more than a minor amount
of the output associated with the specified property, plant, or equipment. Prior
to the adoption of the new lease standard (see below), we bifurcated the
consideration received between lease and service revenue. The new lease standard
allows the election of a practical expedient whereby a lessor does not have to
separate non-lease (service) components from lease components under certain
conditions. The majority of our contracts meet these conditions, and we have
made this election for those contracts. Under this practical expedient, we treat
the combined components as a single performance obligation in accordance with
Accounting Standards Codification ("ASC") 606, which largely codified ASU
2014-09, if the non-lease (service) component is the dominant component. If the
lease component

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is the dominant component, we treat the combined components as a lease in
accordance with ASC 842, which largely codified ASU 2016-02.
Several of our contracts include incentive or reduced tariffs once a certain
quarterly volume is met. Revenue from the variable element of these transactions
is recognized based on the actual volumes shipped as it relates specifically to
rendering the services during the applicable quarter.
The majority of our long-term transportation contracts specify minimum volume
requirements, whereby, we bill a customer for a minimum level of shipments in
the event a customer ships below their contractual requirements. If there are no
future performance obligations, we will recognize these deficiency payments in
revenue.
In certain of these throughput agreements, a customer may later utilize such
shortfall billings as credit towards future volume shipments in excess of its
minimum levels within its respective contractual shortfall make-up period. Such
amounts represent an obligation to perform future services, which may be
initially deferred and later recognized as revenue based on estimated future
shipping levels, including the likelihood of a customer's ability to utilize
such amounts prior to the end of the contractual shortfall make-up period. We
recognize these deficiency payments in revenue when we do not expect we will be
required to satisfy these performance obligations in the future based on the
pattern of rights exercised by the customer.

Prior to the adoption of ASC 606 on January 1, 2018, billings to customers for
their obligations under their quarterly minimum revenue commitments were
recorded as deferred revenue liabilities if the customer had the right to
receive future services for these billings. The revenue was recognized at the
earlier of:

• the customer receiving the future services provided by these billings,


•         the period in which the customer was contractually allowed to receive
          the services expired, or


•         our determination that we would not be required to provide services
          within the allowed period.



We determined that we would not be required to provide services within the
allowed period when, based on current and projected shipping levels, our
pipeline systems would not have the necessary capacity to enable a customer to
exceed its minimum volume levels to such a degree as to utilize the shortfall
credit within its respective contractual shortfall make-up period.

Goodwill and Long-Lived Assets
Goodwill represents the excess of our cost of an acquired business over the fair
value of the assets acquired, less liabilities assumed. Goodwill is not
amortized. We test goodwill at the reporting unit level for impairment annually
and between annual tests if events or changes in circumstances indicate the
carrying amount may exceed fair value. Our goodwill impairment testing first
entails a comparison of our reporting unit fair values relative to their
respective carrying values, including goodwill. If carrying value exceeds fair
value for a reporting unit, we measure goodwill impairment as the excess of the
carrying amount of reporting unit goodwill over the implied fair value of that
goodwill based on estimates of the fair value of all assets and liabilities in
the reporting unit.

In 2019, we assessed qualitative factors such as macroeconomic conditions,
industry considerations, cost factors, and reporting unit financial performance
and determined it was not more likely than not that the fair value of our
reporting units were less than the respective carrying value. Therefore, in
accordance with GAAP, further testing was not required. In 2018, we used the
present value of the expected future net cash flows and market multiple analyses
to determine the estimated fair values of the reporting units. The impairment
test requires the use of projections, estimates and assumptions as to the future
performance of our operations. Actual results could differ from projections
resulting in revisions to our assumptions, and if required, could result in the
recognition of an impairment loss.

We evaluate long-lived assets, including finite-lived intangible assets, for
potential impairment by identifying whether indicators of impairment exist and,
if so, assessing whether the long-lived assets are recoverable from estimated
future undiscounted cash flows. The actual amount of impairment loss, if any, to
be recorded is equal to the amount by which a long-lived asset's carrying value
exceeds its fair value.

There have been no impairments to goodwill or our long-lived assets through December 31, 2019.

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Accounting Pronouncement Adopted During the Periods Presented


Goodwill Impairment Testing
In January 2017, Accounting Standard Update ("ASU") 2017-04, "Simplifying the
Test for Goodwill Impairment," was issued amending the testing for goodwill
impairment by eliminating Step 2 from the goodwill impairment test. Step 2
measured a goodwill impairment loss by comparing the implied fair value of a
reporting unit's goodwill with the carrying amount of that goodwill. Under this
standard, goodwill impairment is measured as the excess of the carrying amount
of the reporting unit over the related fair value. We adopted this standard
effective in the second quarter of 2019, and the adoption of this standard had
no effect on our financial condition, results of operations or cash flows.

Leases

In February 2016, ASU 2016-02, "Leases" ("ASC 842") was issued requiring leases
to be measured and recognized as a lease liability, with a corresponding
right-of-use asset on the balance sheet. We adopted this standard effective
January 1, 2019, and we elected to adopt using the modified retrospective
transition method, whereby comparative prior period financial information will
not be restated and will continue to be reported under the lease accounting
standard in effect during those periods. We also elected practical expedients
provided by the new standard, including the package of practical expedients and
the short-term lease recognition practical expedient, which allows an entity to
not recognize on the balance sheet leases with a term of 12 months or less. Upon
adoption of this standard, we recognized $78.4 million of lease liabilities and
corresponding right-of-use assets on our consolidated balance sheet. Adoption of
the standard did not have a material impact on our results of operations or cash
flows. See Notes 4 and 5 of Notes to the Consolidated Financial Statements for
additional information on our lease policies.

Revenue Recognition
In May 2014, an accounting standard update was issued requiring revenue to be
recognized when promised goods or services are transferred to customers in an
amount that reflects the expected consideration for these goods or services.
This standard had an effective date of January 1, 2018, and we accounted for the
new guidance using the modified retrospective implementation method, whereby a
cumulative effect adjustment was recorded to retained earnings as of the date of
initial application. In preparing for adoption, we evaluated the terms,
conditions and performance obligations under our existing contracts with
customers. Furthermore, we implemented policies to comply with this new
standard. See above and Note 4 to the consolidated financial statements for
additional information on our revenue recognition policies.

Business Combinations
In December 2014, an accounting standard update was issued to provide new
guidance on the definition of a business in relation to accounting for
identifiable intangible assets in business combinations. This standard had an
effective date of January 1, 2018, and had no effect on our financial condition,
results of operations or cash flows.

Financial Assets and Liabilities
In January 2016, an accounting standard update was issued requiring changes in
the accounting and disclosures for financial instruments. This standard was
effective beginning with our 2018 reporting year and had no effect on our
financial condition, results of operations or cash flows.

Accounting Pronouncements Not Yet Adopted


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 is effective January 1, 2020, and our
preliminary review of historic and expected credit losses indicates the amount
of expected credit losses upon adoption would not have a material impact on our
financial condition, results of operations or cash flows.

RISK MANAGEMENT

The two interest rate swaps that hedged our exposure to the cash flow risk caused by the effects of LIBOR changes on $150 million of Credit Agreement matured on July 31, 2017. The swaps had effectively converted $150 million of our LIBOR based debt to fixed rate debt.

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

                                     - 61 -
--------------------------------------------------------------------------------


At December 31, 2019, we had an outstanding principal balance of $500 million on
our 6% Senior Notes. A change in interest rates generally would affect the fair
value of the 6% Senior Notes, but not our earnings or cash flows. At
December 31, 2019, the fair value of our 6% Senior Notes was $522 million. We
estimate a hypothetical 10% change in the yield-to-maturity applicable to the 6%
Senior Notes at December 31, 2019, would result in a change of approximately $10
million in the fair value of the underlying 6% Senior Notes.

For the variable rate Credit Agreement, changes in interest rates would affect
cash flows, but not the fair value. At December 31, 2019, borrowings outstanding
under the Credit Agreement were $965.5 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 fire,
explosion and weather-related perils. We maintain various insurance coverages,
including business interruption insurance, subject to certain deductibles. 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.

© Edgar Online, source Glimpses

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