HOLLY ENERGY PARTNERS, L.P. 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 aDelaware 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 ofthe United States and Delek's refinery inBig Spring, Texas . HEP, through its subsidiaries and joint ventures, owns and/or operates petroleum product and crude pipelines, tankage and terminals inTexas ,New Mexico ,Washington ,Idaho ,Oklahoma ,Utah ,Nevada ,Wyoming andKansas as well as refinery processing units inUtah andKansas . HFC owned 57% of our outstanding common units and the non-economic general partner interest as ofDecember 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 OnOctober 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 theSalt Lake City area from theUtah terminal of the Frontier Pipeline and fromWahsatch Station . FrontierAspen is the owner of a 289-mile crude pipeline fromCasper, Wyoming toFrontier Station ,Utah that supplies Canadian andRocky Mountain crudes toSalt Lake City area refiners through a connection to the SLC Pipeline. Investment in Joint Venture OnOctober 2, 2019 ,HEP Cushing LLC ("HEP Cushing"), a wholly-owned subsidiary of HEP, andPlains 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 theCushing, Oklahoma crude oil hub to theTulsa, Oklahoma refining complex owned by a subsidiary of HFC and (ii) the ownership and operation of 1.5 million barrels of crude oil storage inCushing, 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 theCushing 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 theCushing 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 theCushing Connect JV Terminal contributed by Plains and Cushing Connect Pipeline construction costs are approximately$65 million . However, anyCushing Connect Pipeline construction costs exceeding 10% of the budget are borne solely by us. - 47 -
-------------------------------------------------------------------------------- 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 onJuly 1st each year based on the PPI or theFERC index. As ofDecember 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. OnSeptember 30, 2019 , Delek exercised its first renewal option (the "Renewal") under this agreement for an additional five year period beginningApril 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 ofMarch 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 ourOrla toEl 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 ofDecember 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 inNew Mexico ,Utah ,Oklahoma ,Kansas andWyoming . We also expect to work with HFC on logistic asset acquisitions in conjunction withHFC'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 endedDecember 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 ---------------------------------------------------------------------------------
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 ---------------------------------------------------------------------------------
(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 declaredsubsequent 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
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 notincluded 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 asoperating 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
performance or as alternatives to operating cash flow as a measure of
liquidity. EBITDA and Adjusted EBITDA are not necessarily comparable tosimilarly 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 measureprovides 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
Summary
Net income attributable to the partners for the year endedDecember 31, 2019 , was$224.9 million , a$46.0 million increase compared to the year endedDecember 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 thePermian Basin and our crude pipeline systems inWyoming andUtah , higher revenues on our refinery processing units and contractual tariff escalators, partially offset by higher operating costs and expenses.
Revenues
Revenues for the year endedDecember 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 thePermian Basin and our crude pipeline systems inWyoming andUtah , 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 endedDecember 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 servicingHollyFrontier's Navajo refinery partially offset by higher volumes on pipelines servicingHFC'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 endedDecember 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 endedDecember 31, 2018 . The increases were mainly attributable to increased volumes on our crude pipeline systems inNew Mexico andTexas and on our crude pipeline systems inWyoming andUtah 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 endedDecember 31, 2018 . Refined products and crude oil terminalled in the facilities averaged 483.2 mbpd compared to 474.9 mbpd for the year endedDecember 31, 2018 . The revenue and volume increases were mainly due to volumes at our newOrla diesel rack, higher volumes at theSpokane andCatoosa terminals and contractual tariff escalators, partially offset by lower volumes atHFC'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 endedDecember 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 endedDecember 31, 2019 , increased by$15.6 million compared to the year endedDecember 31, 2018 . The increase for the year endedDecember 31, 2019 was mainly due to higher maintenance costs and employee compensation expenses. Depreciation and Amortization Depreciation and amortization for the year endedDecember 31, 2019 , decreased by$1.8 million compared to the year endedDecember 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 endedDecember 31, 2019 , decreased by$0.8 million compared to the year endedDecember 31, 2018 , mainly due to lower employee compensation expenses. Equity in Earnings of Equity Method Investments See the summary chart below for a description of our equity in earnings of equity method investments: Years Ended December 31, Equity Method Investment 2019 2018 (in thousands) Osage Pipe Line Company, LLC$ 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 endedDecember 31, 2019 , totaled$76.8 million , an increase of$4.9 million compared to the year endedDecember 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 endedDecember 31, 2019 and 2018, respectively. State Income Tax We recorded state income tax expense of$41,000 and$26,000 for the years endedDecember 31, 2019 and 2018, respectively. All state income tax expense is solely attributable to theTexas margin tax. - 52 - --------------------------------------------------------------------------------
Results of Operations-Year Ended
Summary
Net income attributable to the partners for the year endedDecember 31, 2018 , was$178.8 million , a$16.2 million decrease compared to the year endedDecember 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 endedDecember 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 atHFC'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 endedDecember 31, 2017 . The volume decrease was mainly due to pipelines servicingHFC'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 inNew Mexico due to the turnaround atHFC's Navajo refinery in the first quarter of 2017. Revenue increased as a result of the higher volumes on theNew Mexico product pipelines and remained relatively consistent around pipelines servicingHFC'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 endedDecember 31, 2017 . These increases were principally due to the turnaround atHFC's Navajo refinery in the first quarter of 2017 and increased production of base oil and lubricants atHFC'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 endedDecember 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 inNew Mexico andTexas . Revenues from terminal, tankage and loading rack fees were$147.5 million , an increase of$5.1 million compared to the year endedDecember 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 endedDecember 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 atHFC's Woods Cross refinery in the fourth quarter of 2018. Operations Expense Operations (exclusive of depreciation and amortization) expense for the year endedDecember 31, 2018 , increased by$8.8 million compared to the year endedDecember 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 endedDecember 31, 2018 , increased by$19.2 million compared to the year endedDecember 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 endedDecember 31, 2018 , decreased by$3.3 million compared to the year endedDecember 31, 2017 , mainly due to higher legal and consulting costs incurred in the year endedDecember 31, 2017 , associated with the IDR Restructuring Transaction. - 53 - --------------------------------------------------------------------------------
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 $ - $ 2,267
Frontier 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 inJuly 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 endedDecember 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 atDecember 31, 2019 . As ofDecember 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. OnFebruary 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"). OnFebruary 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. OnJanuary 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 onFebruary 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. - 54 - -------------------------------------------------------------------------------- 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 ofDecember 31, 2019 , HEP has issued 2,413,153 units under this program, providing$82.3 million in gross proceeds. OnOctober 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. OnSeptember 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 theSEC 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 andNovember 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 . InFebruary 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 endedDecember 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 atDecember 31, 2019 from a surplus of$8.6 million atDecember 31, 2018 . Cash Flows-Operating Activities Year EndedDecember 31, 2019 Compared with Year EndedDecember 31, 2018 Cash flows provided by operating activities increased by$1.8 million from$295.2 million for the year endedDecember 31, 2018 , to$297.1 million for the year endedDecember 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 endedDecember 31, 2019 , as compared to the prior year. Year EndedDecember 31, 2018 Compared with Year EndedDecember 31, 2017 Cash flows from operating activities increased by$56.7 million from$238.5 million for the year endedDecember 31, 2017 , to$295.2 million for the year endedDecember 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 endedDecember 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 EndedDecember 31, 2019 Compared with Year EndedDecember 31, 2018 Cash flows used for investing activities decreased by$6.1 million from$52.3 million for the year endedDecember 31, 2018 , to$46.3 million for the year endedDecember 31, 2019 . During the years endedDecember 31, 2019 and 2018, we invested$30.1 million and$47.3 million in additions to properties and equipment, respectively. During the year endedDecember 31, 2019 , we acquired a 50% interest inCushing Connect Pipeline & Terminal LLC for$17.9 million . Additionally, we acquired businesses and assets for$5.1 million during the year endedDecember 31, 2018 . - 55 -
-------------------------------------------------------------------------------- Year EndedDecember 31, 2018 Compared with Year EndedDecember 31, 2017 Cash flows used for investing activities decreased by$233.9 million from$286.3 million for the year endedDecember 31, 2017 , to$52.3 million for the year endedDecember 31, 2018 . During the years endedDecember 31, 2018 and 2017, we invested$47.3 million and$44.8 million in additions to properties and equipment, respectively. During the year endedDecember 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 inOctober 2017 . Cash Flows-Financing Activities Year EndedDecember 31, 2019 Compared with Year EndedDecember 31, 2018 Cash flows used for financing activities decreased by$7.0 million from$247.6 million for the year endedDecember 31, 2018 , to$240.6 million for the year endedDecember 31, 2019 . During the year endedDecember 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 endedDecember 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 EndedDecember 31, 2018 Compared with Year EndedDecember 31, 2017 Cash flows used for financing activities were$247.6 million for the year endedDecember 31, 2018 , compared to cash flows provided by financing activities of$51.9 million for the year endedDecember 31, 2017 , a decrease of$299.5 million . During the year endedDecember 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 endedDecember 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 - 56 - --------------------------------------------------------------------------------
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 beginningJuly 1, 2015 , and ending inJune 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 inJuly 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 ofDecember 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 ofDecember 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 endingDecember 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 OnJanuary 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 ofDecember 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 ofDecember 31, 2019 .
Indebtedness under the 6% Senior Notes was guaranteed by our wholly-owned subsidiaries.
OnFebruary 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"). OnFebruary 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 orStandard & Poor's and no - 57 - --------------------------------------------------------------------------------
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 500,000 500,000Unamortized 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 ofDecember 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 atDecember 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 atHFC'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 andKuntz Station inNew 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 atDecember 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 inthe United States has been relatively moderate in recent years and did not have a material impact on our results of operations for the years endedDecember 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. - 58 -
-------------------------------------------------------------------------------- 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 ofDecember 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 inthe 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 - 59 - -------------------------------------------------------------------------------- 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 onJanuary 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
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--------------------------------------------------------------------------------Accounting Pronouncement Adopted During the Periods Presented
Goodwill Impairment Testing InJanuary 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
InFebruary 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 effectiveJanuary 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 InMay 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 ofJanuary 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 InDecember 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 ofJanuary 1, 2018 , and had no effect on our financial condition, results of operations or cash flows. Financial Assets and Liabilities InJanuary 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 InJune 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 effectiveJanuary 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
The market risk inherent in our debt positions is the potential change arising from increases or decreases in interest rates as discussed below.
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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.
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