10-Q 1 hep9-30x201710q.htm 10-Q Document


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 ______________________________________________________________________________________
FORM 10-Q
 ______________________________________________________________________________________

(Mark One)
ý
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2017
OR
¨

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ____________ to _____________                    
Commission File Number: 1-32225
  _____________________________________________________________________________________
HOLLY ENERGY PARTNERS, L.P.
(Exact name of registrant as specified in its charter)
 ______________________________________________________________________________________
Delaware
 
20-0833098
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
 
 
 
2828 N. Harwood, Suite 1300
Dallas, Texas
 
75201
(Address of principal executive offices)
 
 (Zip code)
(214) 871-3555
(Registrant’s telephone number, including area code)
________________________________________________________________
(Former name, former address and former fiscal year, if changed since last report)
________________________________________________________________
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.     Yes  ý    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes   ý    No  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth” company in Rule 12b-2 of the Exchange Act.
Large accelerated filer
ý
Accelerated filer
¨
Non-accelerated filer
¨
Smaller reporting company
¨

Emerging growth company
¨

 
 
 
 
 
 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
    
Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Exchange Act).    Yes  ¨ No  ý

The number of the registrant’s outstanding common units at October 31, 2017, was 64,318,955.


HOLLY ENERGY PARTNERS, L.P.
INDEX
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 1.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Consolidated Statement of Equity
 
 
 
 
 
 
 
 
 
 
 
Item 2.
 
 
 
 
 
Item 3.
 
 
 
 
 
Item 4.
 
 
 
 
 
 
 
Item 1.
 
 
 
 
 
Item 1A.
 
 
 
 
 
Item 6.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

- 2 -


FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains certain “forward-looking statements” within the meaning of the federal securities laws. All statements, other than statements of historical fact included in this Form 10-Q, including, but not limited to, those under “Results of Operations” and “Liquidity and Capital Resources” in Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part I are forward-looking statements. Forward-looking statements use words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “intend,” “should,” “would,” “could,” “believe,” “may,” and similar expressions and statements regarding our plans and objectives for future operations. These statements are based on our beliefs and assumptions and those of our general partner using currently available information and expectations as of the date hereof, are not guarantees of future performance and involve certain risks and uncertainties. Although we and our general partner believe that such expectations reflected in such forward-looking statements are reasonable, neither we nor our general partner can give assurance that our expectations will prove to be correct. All statements concerning our expectations for future results of operations are based on forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Certain factors could cause actual results to differ materially from results anticipated in the forward-looking statements. These factors include, but are not limited to:
•
risks and uncertainties with respect to the actual quantities of petroleum products and crude oil shipped on our pipelines and/or terminalled, stored or throughput in our terminals;
•
the economic viability of HollyFrontier Corporation, Alon USA, Inc. and our other customers;
•
the demand for refined petroleum products in markets we serve;
•
our ability to purchase and integrate future acquired operations;
•
our ability to complete previously announced or contemplated acquisitions;
•
the availability and cost of additional debt and equity financing;
•
the possibility of reductions in production or shutdowns at refineries utilizing our pipeline and terminal facilities or containing our processing units;
•
the effects of current and future government regulations and policies;
•
our operational efficiency in carrying out routine operations and capital construction projects;
•
the possibility of terrorist attacks and the consequences of any such attacks;
•
general economic conditions; and
•
other financial, operational and legal risks and uncertainties detailed from time to time in our Securities and Exchange Commission filings.

Cautionary statements identifying important factors that could cause actual results to differ materially from our expectations are set forth in this Form 10-Q, including without limitation, the forward-looking statements that are referred to above. When considering forward-looking statements, you should keep in mind the known material risk factors and other cautionary statements set forth in our Annual Report on Form 10-K for the year ended December 31, 2016, in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and in “Risk Factors.” All forward-looking statements included in this Form 10-Q and all subsequent written or oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. The forward-looking statements speak only as of the date made and, other than as required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.


- 3 -

PART I. FINANCIAL INFORMATION


Item 1.
Financial Statements
HOLLY ENERGY PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands, except unit data)
 
 
September 30, 2017
 
December 31, 2016
 
 
(Unaudited)
 
 
ASSETS
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents
 
$
7,476

 
$
3,657

Accounts receivable:
 
 
 
 
Trade
 
7,330

 
7,846

Affiliates
 
42,753

 
42,562

 
 
50,083

 
50,408

Prepaid and other current assets
 
2,295

 
2,888

Total current assets
 
59,854

 
56,953

 
 
 
 
 
Properties and equipment, net
 
1,307,093

 
1,328,395

Transportation agreements, net
 
61,644

 
66,856

Goodwill
 
256,498

 
256,498

Equity method investments
 
163,873

 
165,609

Other assets
 
16,880

 
9,926

Total assets
 
$
1,865,842

 
$
1,884,237

 
 
 
 
 
LIABILITIES AND EQUITY
 
 
 
 
Current liabilities:
 
 
 
 
Accounts payable:
 
 
 
 
Trade
 
$
13,584

 
$
10,518

Affiliates
 
9,559

 
16,424

 
 
23,143

 
26,942

 
 
 
 
 
Accrued interest
 
5,527

 
18,069

Deferred revenue
 
14,827

 
11,102

Accrued property taxes
 
7,487

 
5,397

Other current liabilities
 
3,492

 
3,225

Total current liabilities
 
54,476

 
64,735

 
 
 
 
 
Long-term debt
 
1,245,066

 
1,243,912

Other long-term liabilities
 
15,477

 
16,445

Deferred revenue
 
46,405

 
47,035

 
 
 
 
 
Class B unit
 
42,412

 
40,319

 
 
 
 
 
Equity:
 
 
 
 
Partners’ equity:
 
 
 
 
Common unitholders (64,318,955 and 62,780,503 units issued and outstanding
    at September 30, 2017 and December 31, 2016, respectively)
 
520,709

 
510,975

General partner interest (2% interest)
 
(149,994
)
 
(132,832
)
Accumulated other comprehensive income
 
—

 
91

Total partners’ equity
 
370,715

 
378,234

Noncontrolling interest
 
91,291

 
93,557

Total equity
 
462,006

 
471,791

Total liabilities and equity
 
$
1,865,842

 
$
1,884,237


See accompanying notes.


- 4 -

HOLLY ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
(In thousands, except per unit data)

 
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
 
2017
 
2016 (1)
 
2017
 
2016 (1)
Revenues:
 
 
 
 
 
 
 
 
Affiliates
 
$
95,138

 
$
77,398

 
$
277,316

 
$
239,423

Third parties
 
15,226

 
15,212

 
47,826

 
50,094

 
 
110,364

 
92,610

 
325,142

 
289,517

Operating costs and expenses:
 
 
 
 
 
 
 
 
Operations (exclusive of depreciation and amortization)
 
35,998

 
32,101

 
102,584

 
89,168

Depreciation and amortization
 
19,007

 
18,920

 
57,729

 
51,183

General and administrative
 
3,623

 
2,664

 
8,872

 
8,618

 
 
58,628

 
53,685

 
169,185

 
148,969

Operating income
 
51,736

 
38,925

 
155,957

 
140,548

 
 
 
 
 
 
 
 
 
Other income (expense):
 
 
 
 
 
 
 
 
Equity in earnings of equity method investments
 
5,072

 
3,767

 
10,965

 
10,155

Interest expense
 
(14,072
)
 
(14,447
)
 
(41,359
)
 
(36,258
)
Interest income
 
101

 
108

 
306

 
332

Loss on early extinguishment of debt
 
—

 
—

 
(12,225
)
 
—

Gain on sale of assets and other
 
155

 
112

 
317

 
104

 
 
(8,744
)
 
(10,460
)
 
(41,996
)
 
(25,667
)
Income before income taxes
 
42,992

 
28,465

 
113,961

 
114,881

State income tax benefit (expense)
 
69

 
(61
)
 
(164
)
 
(210
)
Net income
 
43,061

 
28,404

 
113,797

 
114,671

Allocation of net loss attributable to Predecessor
 
—

 
7,547

 
—

 
10,657

Allocation of net income attributable to noncontrolling interests
 
(990
)
 
(1,166
)
 
(4,827
)
 
(8,448
)
Net income attributable to the partners
 
42,071

 
34,785

 
108,970

 
116,880

General partner interest in net income attributable to the partners
 
419

 
(15,222
)
 
(35,047
)
 
(40,001
)
Limited partners’ interest in net income
 
$
42,490

 
$
19,563

 
$
73,923

 
$
76,879

Limited partners’ per unit interest in earnings—basic and diluted
 
$
0.66

 
$
0.33

 
$
1.16

 
$
1.29

Weighted average limited partners’ units outstanding
 
64,319

 
59,223

 
63,845

 
58,895


(1) Retrospectively adjusted as described in Note 1.

See accompanying notes.


- 5 -

HOLLY ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
(In thousands)

 
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
 
2017
 
2016 (1)
 
2017
 
2016 (1)
Net income
 
$
43,061

 
$
28,404

 
$
113,797

 
$
114,671

 
 
 
 
 
 
 
 
 
Other comprehensive income:
 
 
 
 
 
 
 
 
Change in fair value of cash flow hedging instruments
 
1

 
201

 
88

 
(737
)
Reclassification adjustment to net income on partial settlement of cash flow hedge
 
(64
)
 
95

 
(179
)
 
438

Other comprehensive income (loss)
 
(63
)
 
296

 
(91
)
 
(299
)
Comprehensive income before noncontrolling interest
 
42,998

 
28,700

 
113,706

 
114,372

Allocation of net loss attributable to Predecessor
 
—

 
7,547

 
—

 
10,657

Allocation of comprehensive income to noncontrolling interests
 
(990
)
 
(1,166
)
 
(4,827
)
 
(8,448
)
Comprehensive income attributable to Holly Energy Partners
 
$
42,008

 
$
35,081

 
$
108,879

 
$
116,581


(1) Retrospectively adjusted as described in Note 1.
 
See accompanying notes.


- 6 -

HOLLY ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In thousands)
 
 
 
Nine Months Ended
September 30,
 
 
2017
 
2016 (1)
Cash flows from operating activities
 
 
 
 
Net income
 
$
113,797

 
$
114,671

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
Depreciation and amortization
 
57,729

 
51,183

(Gain) loss on sale of assets
 
(269
)
 
(121
)
Amortization of deferred charges
 
2,317

 
2,294

Amortization of restricted and performance units
 
1,908

 
1,865

Earnings distributions greater (less) than income from equity investments
 
513

 
(1,370
)
Loss on early extinguishment of debt
 
12,225

 
—

(Increase) decrease in operating assets:
 
 
 
 
Accounts receivable—trade
 
516

 
1,521

Accounts receivable—affiliates
 
(191
)
 
2,971

Prepaid and other current assets
 
593

 
814

Increase (decrease) in operating liabilities:
 
 
 
 
Accounts payable—trade
 
3,393

 
(5,757
)
Accounts payable—affiliates
 
(6,866
)
 
1,589

Accrued interest
 
(12,543
)
 
441

Deferred revenue
 
3,096

 
6,288

Accrued property taxes
 
2,090

 
3,199

Other current liabilities
 
(99
)
 
(1,020
)
Other, net
 
(750
)
 
(594
)
Net cash provided by operating activities
 
177,459

 
177,974

 
 
 
 
 
Cash flows from investing activities
 
 
 
 
Additions to properties and equipment
 
(30,675
)
 
(48,224
)
Purchase of Woods Cross refinery processing units
 
—

 
(47,891
)
Purchase of interest in Cheyenne Pipeline
 
—

 
(42,550
)
Proceeds from sale of assets
 
794

 
210

Distributions in excess of equity in earnings of equity investments
 
1,224

 
1,685

Other
 
—

 
(351
)
Net cash used for investing activities
 
(28,657
)
 
(137,121
)
 
 
 
 
 
Cash flows from financing activities
 
 
 
 
Borrowings under credit agreement
 
628,000

 
310,500

Repayments of credit agreement borrowings
 
(431,000
)
 
(642,500
)
Proceeds from issuance of Senior Notes
 
101,750

 
394,000

Redemption of 6.5% Senior Notes
 
(309,750
)
 
—

Proceeds from issuance of common units
 
52,285

 
22,791

Distributions to HEP unitholders
 
(171,560
)
 
(138,798
)
Distributions to noncontrolling interest
 
(5,000
)
 
(3,750
)
Distribution to HFC for Tulsa tank acquisition
 
—

 
(39,500
)
Distribution to HFC for Osage acquisition
 
—

 
(1,245
)
Distribution to HFC for El Dorado tanks
 
(103
)
 
—

Contributions from HFC for acquisitions
 
—

 
55,027

Contributions from general partner
 
1,072

 
470

Purchase of units for incentive grants
 
—

 
(784
)
Deferred financing costs
 
(9,453
)
 
(3,930
)
Other
 
(1,224
)
 
(939
)
Net cash used by financing activities
 
(144,983
)
 
(48,658
)
 
 
 
 
 
Cash and cash equivalents
 
 
 
 
Increase (decrease) for the period
 
3,819

 
(7,805
)
Beginning of period
 
3,657

 
15,013

End of period
 
$
7,476

 
$
7,208

(1) Retrospectively adjusted as described in Note 1.
See accompanying notes.

- 7 -

HOLLY ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENT OF EQUITY
(Unaudited)
(In thousands)
 
 
 
Common
Units
 
General
Partner
Interest
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Noncontrolling Interest
 
Total Equity
 
 
 
Balance December 31, 2016
 
$
510,975

 
$
(132,832
)
 
$
91

 
$
93,557

 
$
471,791

Issuance of common units
 
52,285

 
—

 
—

 
—

 
52,285

Contribution from HFC
 
—

 
1,072

 
—

 
—

 
1,072

Distribution to HFC for acquisition

 
—

 
(103
)
 
—

 
—

 
(103
)
Distributions to HEP unitholders
 
(118,424
)
 
(53,136
)
 
—

 
—

 
(171,560
)
Distributions to noncontrolling interest
 
—

 
—

 
—

 
(5,000
)
 
(5,000
)
Amortization of restricted and performance units
 
1,908

 
—

 
—

 
—

 
1,908

Class B unit accretion
 
(2,051
)
 
(42
)
 
—

 
—

 
(2,093
)
Net income
 
76,016

 
35,047

 
—

 
2,734

 
113,797

Other comprehensive income
 
—

 
—

 
(91
)
 
—

 
(91
)
Balance September 30, 2017
 
$
520,709

 
$
(149,994
)
 
$
—

 
$
91,291

 
$
462,006


See accompanying notes.



- 8 -

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 1:
Description of Business and Presentation of Financial Statements

Holly Energy Partners, L.P. (“HEP”), together with its consolidated subsidiaries, is a publicly held master limited partnership which is 36% owned (including the 2% general partner interest) by HollyFrontier Corporation (“HFC”) and its subsidiaries as of September 30, 2017. We commenced operations on July 13, 2004, upon the completion of our initial public offering. In these consolidated financial statements, the words “we,” “our,” “ours” and “us” refer to HEP unless the context otherwise indicates.

On October 31, 2017, we closed the restructuring transaction set forth in the definitive agreement with HEP Logistics Holdings, L.P. (“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 are canceled, and HEP Logistics' 2% general partner interest in HEP is 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, HFC 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 are eligible to receive distributions. As of October 31, 2017, HFC held approximately 59.6 million HEP common units, representing approximately 59% of the outstanding common units. As a result of this transaction, no distributions will be made on the general partner interest after October 31, 2017.
 
We own and operate petroleum product and crude oil pipelines, terminal, tankage and loading rack facilities and refinery processing units that support HFC’s refining and marketing operations in the Mid-Continent, Southwest and Northwest regions of the United States and Alon USA, Inc.’s (“Alon”) refinery in Big Spring, Texas. As of September 30, 2017, we owned a 75% interest in UNEV Pipeline, LLC (“UNEV”), a 50% interest in Frontier Aspen LLC (“Frontier Aspen”), a 50% interest in Osage Pipe Line Company, LLC (“Osage”), a 50% interest in Cheyenne Pipeline LLC and a 25% interest in SLC Pipeline LLC (“SLC Pipeline”).

We operate in two reportable segments, a Pipelines and Terminals segment and a Refinery Processing Unit segment. Disclosures around these segments are discussed in Note 13.

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 by charging fees for processing hydrocarbon feedstocks through our refinery processing units. We do not take ownership of products that we transport, terminal, store or process, and therefore, we are not exposed directly to changes in commodity prices.

The consolidated financial statements included herein have been prepared without audit, pursuant to the rules and regulations of the United States Securities and Exchange Commission (the “SEC”). The interim financial statements reflect all adjustments, which, in the opinion of management, are necessary for a fair presentation of our results for the interim periods. Such adjustments are considered to be of a normal recurring nature. Although certain notes and other information required by U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted, we believe that the disclosures in these consolidated financial statements are adequate to make the information presented not misleading. These consolidated financial statements should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2016. Results of operations for interim periods are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2017.

Principles of Consolidation and Common Control Transactions
The consolidated financial statements include our accounts, our Predecessor's (defined below) and those of subsidiaries and joint ventures that we control. All significant intercompany transactions and balances have been eliminated.

Most of our acquisitions from HFC occurred while we were a consolidated variable interest entity (“VIE”) of HFC. Therefore, as an entity under common control with HFC, we recorded these acquisitions on our balance sheets at HFC's historical basis instead of our purchase price or fair value. GAAP requires transfers of a business between entities under common control to be accounted for as though the transfer occurred as of the beginning of the period of transfer, and prior period financial statements and financial information are retrospectively adjusted to include the historical results and assets of the acquisitions from HFC for all periods presented prior to the effective dates of each acquisition. We refer to the historical results of the acquisitions prior to their respective acquisition dates as those of our "Predecessor." Many of these transactions are cash purchases and do not involve the issuance of equity; however, GAAP requires the retrospective adjustment of financial statements. Therefore, in such transactions, the prior year balance sheet includes as equity the amount of cost incurred by HFC to that date. See “Acquisitions” below for further discussion as well as effects of the retrospective adjustments.



- 9 -

Acquisitions

Osage
On February 22, 2016, HFC obtained a 50% membership interest in Osage in a non-monetary exchange for a 20-year terminalling services agreement, whereby a subsidiary of Magellan Midstream Partners (“Magellan”) will provide terminalling services for all HFC products originating in Artesia, New Mexico requiring terminalling in or through El Paso, Texas. Osage is the owner of the Osage Pipeline, a 135-mile pipeline that transports crude oil from Cushing, Oklahoma to HFC’s El Dorado Refinery in Kansas and also connects to the Jayhawk pipeline serving the CHS Inc. refinery in McPherson, Kansas. The Osage Pipeline is the primary pipeline supplying HFC’s El Dorado refinery with crude oil.

Concurrent with this transaction, we entered into a non-monetary exchange with HFC, whereby we received HFC’s interest in Osage in exchange for our El Paso terminal. Under this exchange, we agreed to build two connections on our south products pipeline system that will permit HFC access to Magellan’s El Paso terminal. Effective upon the closing of this exchange, we became the named operator of the Osage Pipeline and transitioned into that role on September 1, 2016. Since we are a consolidated VIE of HFC, this transaction was recorded as a transfer between entities under common control and reflects HFC’s carrying basis of its 50% membership interest in Osage of $44.5 million offset by our net carrying basis in the El Paso terminal of $12.1 million with the difference recorded as a contribution from HFC. However, since these transactions were concurrent, there was no impact on periods prior to February 22, 2016.

Tulsa Tanks
On March 31, 2016, we acquired crude oil tanks (the “Tulsa Tanks”) located at HFC’s Tulsa refinery from an affiliate of Plains All American Pipeline, L.P. (“Plains”) for cash consideration of $39.5 million. In 2009, HFC sold these tanks to Plains and leased them back, and due to HFC’s continuing interest in the tanks, HFC accounted for the transaction as a financing arrangement. Accordingly, the tanks had remained on HFC’s balance sheet and were being depreciated for accounting purposes.

As we are a consolidated VIE of HFC, this transaction was recorded as a transfer between entities under common control and reflects HFC’s carrying basis in the net assets acquired. We have retrospectively adjusted our financial position and operating results as if these units were owned for all periods while we were under common control of HFC.

Cheyenne Pipeline
On June 3, 2016, we acquired a 50% interest in Cheyenne Pipeline LLC, owner of the Cheyenne Pipeline, in exchange for a contribution of $42.6 million in cash to Cheyenne Pipeline LLC. Cheyenne Pipeline LLC will continue to be operated by an affiliate of Plains, which owns the remaining 50% interest. The 87-mile crude oil pipeline runs from Fort Laramie to Cheyenne, Wyoming and has an 80,000 barrel per day (“bpd”) capacity.

Woods Cross Operating
Effective October 1, 2016, we acquired all the membership interests of Woods Cross Operating LLC (“Woods Cross Operating”), a wholly owned subsidiary of HFC, which owns the newly constructed atmospheric distillation tower, fluid catalytic cracking unit, and polymerization unit located at HFC’s Woods Cross Refinery, for cash consideration of $278 million. The consideration was funded with $103 million in proceeds from the private placement of 3,420,000 common units with the balance funded with borrowings under our credit facility. In connection with this transaction, we entered into 15-year tolling agreements containing minimum quarterly throughput commitments from HFC. As of September 30, 2017, these commitments provide minimum annualized revenues of $57 million.

The Utah Division of Air Quality issued an air quality permit to HollyFrontier Woods Cross Refining LLC (“HFC Woods Cross Refining”) authorizing the expansion units at the Woods Cross Refinery. The appeal proceeding challenging the Utah Department of Environmental Quality’s decision to uphold the air quality permit was taken under advisement by the Utah Supreme Court in June 2017, and the court issued a decision in favor of the state of Utah and HFC. As a result, the purchase agreement remedies we had against HFC in the event of an unfavorable ruling in the appeal proceeding are no longer applicable.

As we are a consolidated VIE of HFC, this transaction was recorded as a transfer between entities under common control and reflects HFC’s carrying basis in the net assets acquired. We have retrospectively adjusted our financial position and operating results as if these units were owned for all periods while we were under common control of HFC.

The following tables present lines in our previously reported income statement for the three and nine months ended September 30, 2016, that were impacted by Predecessor transactions, and retrospectively adjusts only the acquisition of Woods Cross Operating

- 10 -

as the Tulsa Tanks acquisition included Predecessor transactions in the previously reported income statement for the three and nine months ended September 30, 2016. However, the presentation of the Tulsa Tanks’ Predecessor transactions have been modified as shown in the table below.

 
 
Three Months Ended September 30, 2016
 
 
Holly Energy Partners, L.P.(Previously reported)
 
Tulsa Tanks
 
Woods Cross Operating
 
Holly Energy Partners, L.P. (Currently reported)
 
 
(In Thousands)
Operating costs and expenses:
 
 
 
 
 
 
 
 
       Operations (exclusive of depreciation and
       amortization)
 
$
27,954

 
$
—

 
$
4,147

 
$
32,101

        Depreciation and amortization
 
15,520

 
—

 
3,400

 
18,920

Allocation of net loss attributable to predecessor
 
—

 
—

 
7,547

 
7,547


 
 
Nine Months Ended September 30, 2016
 
 
Holly Energy Partners, L.P.(Previously reported)
 
Tulsa Tanks
 
Woods Cross Operating
 
Holly Energy Partners, L.P. (Currently reported)
 
 
(In Thousands)
Operating costs and expenses:
 
 
 
 
 
 
 
 
       Operations (exclusive of depreciation and
       amortization)
 
$
82,131

 
$
—

 
$
7,037

 
$
89,168

        Depreciation and amortization
 
47,780

 
—

 
3,403

 
51,183

Allocation of net loss attributable to predecessor
 
—

 
217

 
10,440

 
10,657



The following tables present lines in our previously reported cash flows for the nine months ended September 30, 2016, that were impacted by Predecessor transactions, and retrospectively adjusts only the acquisition of Woods Cross Operating as the Tulsa Tanks acquisition included Predecessor transactions in the previously reported cash flows for the nine months ended September 30, 2016.
 
 
Nine Months Ended September 30, 2016
 
 
Holly Energy Partners, L.P.(Previously reported)
 
Woods Cross Operating
 
Holly Energy Partners, L.P.
(Currently reported)
Cash flows from operating activities
 
(In Thousands)
Net income
 
$
125,111

 
$
(10,440
)
 
$
114,671

Depreciation and amortization
 
47,780

 
3,403

 
51,183

Net cash provided (used) by operating activities
 
$
185,011

 
$
(7,037
)
 
$
177,974

 
 
 
 
 
 
 
Cash flows from investing activities
 
 
 
 
 
 
Purchase of Woods Cross refinery processing units
 
$
—

 
$
(47,891
)
 
$
(47,891
)
Net cash used for investing activities
 
$
(89,230
)
 
$
(47,891
)
 
$
(137,121
)
 
 
 
 
 
 
 
Cash flows from financing activities
 
 
 
 
 
 
Contributions from HFC for acquisitions
 
$
99

 
$
54,928

 
$
55,027

Net cash provided (used) by financing activities
 
$
(103,586
)
 
$
54,928

 
$
(48,658
)

SLC Pipeline and Frontier Aspen
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 All American Pipeline, L.P. (“Plains”), for total consideration of $250 million. As of September 30,

- 11 -

2017, 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 will 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 will be remeasured at acquisition date fair value since we will have a controlling interest, and we expect to recognize a gain on the remeasurement in the fourth quarter of 2017.

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.

Accounting Pronouncements Adopted During the Periods Presented

Earnings Per Unit
In April 2015, an accounting standard update was issued requiring changes to the allocation of the earnings or losses of a transferred business for periods before the date of a dropdown of net assets accounted for as a common control transaction entirely to the general partner for purposes of calculating historical earnings per unit. We adopted this standard as of January 1, 2016. In connection with the dropdown of assets from HFC’s Tulsa refinery on March 31, 2016, and the purchase of HFC’s Woods Cross refinery units on October 1, 2016, we reduced net income by $7.5 million and $10.7 million for the three and nine months ended September 30, 2016. These reductions had no impact on the historical earnings per limited partner unit as they were allocated to the general partner.

Share-Based Compensation
In March 2016, an accounting standard update was issued which simplifies the accounting for employee share-based payment transactions, including the accounting for income taxes, forfeitures and statutory tax withholding requirements, as well as classification in the statement of cash flows. We adopted this standard effective January 1, 2017, with no impact to our financial condition, results of operations and cash flows. As permitted by the standard, we continue to account for forfeitures on an estimated basis.

Accounting Pronouncements Not Yet Adopted

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 has an effective date of January 1, 2018, and we intend to account for the new guidance using the modified retrospective implementation method, whereby a cumulative effect adjustment is recorded to retained earnings as of the date of initial application. Our preparation for adoption of this standard is in progress, and we are currently evaluating terms, conditions and our performance obligations of our existing contracts with customers. We are evaluating the effect of this standard on our revenue recognition policies and whether it will have a material impact on our financial condition or results of operations.

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 has an effective date of January 1, 2018, and we are evaluating its impact.

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 will become effective beginning with our 2018 reporting year. We are evaluating the impact of this standard.


- 12 -

Leases
In February 2016, an accounting standard update was issued requiring leases to be measured and recognized as a lease liability, with a corresponding right-of-use asset on the balance sheet. This standard has an effective date of January 1, 2019, and we are evaluating the impact of this standard.


Note 2:
Financial Instruments

Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, debt and interest rate swaps. The carrying amounts of cash equivalents, accounts receivable and accounts payable approximate fair value due to the short-term maturity of these instruments. Debt consists of outstanding principal under our revolving credit agreement (which approximates fair value as interest rates are reset frequently at current interest rates) and our fixed interest rate senior notes.

Fair value measurements are derived using inputs (assumptions that market participants would use in pricing an asset or liability) including assumptions about risk. GAAP categorizes inputs used in fair value measurements into three broad levels as follows:
•
(Level 1) Quoted prices in active markets for identical assets or liabilities.
•
(Level 2) Observable inputs other than quoted prices included in Level 1, such as quoted prices for similar assets and liabilities in active markets, similar assets and liabilities in markets that are not active or can be corroborated by observable market data.
•
(Level 3) Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. This includes valuation techniques that involve significant unobservable inputs.

The carrying amounts and estimated fair values of our senior notes and interest rate swaps were as follows:
 
 
 
 
September 30, 2017
 
December 31, 2016
Financial Instrument
 
Fair Value Input Level
 
Carrying
Value
 
Fair Value
 
Carrying
Value
 
Fair Value
 
 
 
 
(In thousands)
Assets:
 
 
 
 
 
 
 
 
 
 
Interest rate swaps
 
Level 2
 
$
—

 
$
—

 
$
91

 
$
91

 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
6.5% Senior notes
 
Level 2
 
$
—

 
$
—

 
$
297,519

 
$
308,250

6% Senior notes
 
Level 2
 
495,066

 
524,390

 
393,393

 
415,500

 
 
 
 
$
495,066

 
$
524,390

 
$
690,912

 
$
723,750


Level 2 Financial Instruments
Our senior notes and interest rate swaps are measured at fair value using Level 2 inputs. The fair value of the senior notes is based on market values provided by a third-party bank, which were derived using market quotes for similar type debt instruments. The fair value of our interest rate swaps is based on the net present value of expected future cash flows related to both variable and fixed-rate legs of the swap agreement. This measurement is computed using the forward London Interbank Offered Rate (“LIBOR”) yield curve, a market-based observable input.

See Note 6 for additional information on these instruments.



- 13 -

Note 3:
Properties and Equipment 

The carrying amounts of our properties and equipment are as follows:
 
 
September 30,
2017
 
December 31,
2016
 
 
(In thousands)
Pipelines, terminals and tankage
 
$
1,250,567

 
$
1,246,746

Refinery assets
 
347,312

 
346,058

Land and right of way
 
65,337

 
65,331

Construction in progress
 
51,297

 
28,753

Other
 
27,708

 
27,133

 
 
1,742,221

 
1,714,021

Less accumulated depreciation
 
435,128

 
385,626

 
 
$
1,307,093

 
$
1,328,395


We capitalized $0.3 million and $0.2 million during the three months ended September 30, 2017 and 2016, respectively and $0.7 million and $0.5 million during the nine months ended September 30, 2017 and 2016, respectively, in interest attributable to construction projects.

Depreciation expense was $52.1 million and $45.5 million for the nine months ended September 30, 2017 and 2016, respectively, and includes depreciation of assets acquired under capital leases.


Note 4:
Transportation Agreements

Our transportation agreements are intangible assets that represent a portion of the total purchase price of certain assets acquired from Alon in 2005 and from HFC in 2008 prior to HEP becoming a consolidated VIE of HFC. The Alon agreement is being amortized over 30 years ending 2035 (the initial 15-year term of the agreement plus an expected 15-year extension period), and the HFC agreement is being amortized over 15 years ending 2023 (the term of the HFC agreement).

The carrying amounts of our transportation agreements are as follows:
 
 
September 30,
2017
 
December 31,
2016
 
 
(In thousands)
Alon transportation agreement
 
$
59,933

 
$
59,933

HFC transportation agreement
 
74,231

 
74,231

Other
 
50

 
50

 
 
134,214

 
134,214

Less accumulated amortization
 
72,570

 
67,358

 
 
$
61,644

 
$
66,856


Amortization expense was $5.2 million for each of the nine months ended September 30, 2017 and 2016.

We have additional transportation agreements with HFC resulting from historical transactions consisting of pipeline, terminal and tankage assets contributed to us or acquired from HFC. These transactions occurred while we were a consolidated VIE of HFC; therefore, our basis in these agreements is zero and does not reflect a step-up in basis to fair value.



- 14 -

Note 5:
Employees, Retirement and Incentive Plans

Direct support for our operations is provided by Holly Logistic Services, L.L.C. (“HLS”), an HFC subsidiary, which utilizes personnel employed by HFC who are dedicated to performing services for us. Their costs, including salaries, bonuses, payroll taxes, benefits and other direct costs, are charged to us monthly in accordance with an omnibus agreement that we have with HFC. These employees participate in the retirement and benefit plans of HFC. Our share of retirement and benefit plan costs was $1.5 million and $1.4 million for the three months ended September 30, 2017 and 2016, respectively, and $4.5 million and $4.3 million for the nine months ended September 30, 2017 and 2016.

Under HLS’s secondment agreement with HFC (the “Secondment Agreement”), 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 related to these employees.
We have a Long-Term Incentive Plan for employees and non-employee directors who perform services for us. The Long-Term Incentive Plan consists of four components: restricted or phantom units, performance units, unit options and unit appreciation rights. Our accounting policy for the recognition of compensation expense for awards with pro-rata vesting (a significant proportion of our awards) is to expense the costs ratably over the vesting periods.

As of September 30, 2017, we had two types of incentive-based awards outstanding, which are described below. The compensation cost charged against income was $0.7 million for each of the three months ended September 30, 2017 and 2016, and $1.6 million and $1.9 million for the nine months ended September 30, 2017 and 2016, respectively. We currently purchase units in the open market instead of issuing new units for settlement of all unit awards under our Long-Term Incentive Plan. As of September 30, 2017, 2,500,000 units were authorized to be granted under our Long-Term Incentive Plan, of which 1,409,261 have not yet been granted, assuming no forfeitures of the unvested units and full achievement of goals for the unvested performance units.

Restricted Units
Under our Long-Term Incentive Plan, we grant restricted units to non-employee directors and selected employees who perform services for us, with most awards vesting over a period of one to three years. Although full ownership of the units does not transfer to the recipients until the units vest, the recipients have distribution and voting rights on these units from the date of grant.

The fair value of each restricted unit award is measured at the market price as of the date of grant and is amortized on a straight-line basis over the requisite service period for each separately vesting portion of the award.

A summary of restricted unit activity and changes during the nine months ended September 30, 2017, is presented below:
Restricted Units
 
Units
 
Weighted Average Grant-Date Fair Value
Outstanding at January 1, 2017 (nonvested)
 
123,988

 
$
32.96

Granted
 
20,348

 
36.01

Forfeited
 
(20,106
)
 
30.10

Outstanding at September 30, 2017 (nonvested)
 
124,230

 
$
33.92


As of September 30, 2017, there was $1.1 million of total unrecognized compensation expense related to nonvested restricted unit grants, which is expected to be recognized over a weighted-average period of 0.9 year.

Performance Units
Under our Long-Term Incentive Plan, we grant performance units to selected executives who perform services for us. Performance units granted are payable in common units at the end of a three-year performance period based upon the growth in our distributable cash flow per common unit over the performance period. As of September 30, 2017, estimated unit payouts for outstanding nonvested performance unit awards ranged between 100% and 150% of the target number of performance units granted.

We did not grant any performance units during the nine months ended September 30, 2017. Performance units granted in 2016 vest over a three-year performance period ending December 31, 2019, and are payable in HEP common units. The number of units actually earned will be based on the growth of our distributable cash flow per common unit over the performance period,

- 15 -

and can range from 50% to 150% of the target number of performance units granted. Although common units are not transferred to the recipients until the performance units vest, the recipients have distribution rights with respect to the common units from the date of grant.

A summary of performance unit activity and changes during the nine months ended September 30, 2017, is presented below:
Performance Units
 
Units
Outstanding at January 1, 2017 (nonvested)
 
49,520

Vesting and transfer of common units to recipients
 
(2,262
)
Forfeited
 
(21,228
)
Outstanding at September 30, 2017 (nonvested)
 
26,030


The grant-date fair value of performance units vested and transferred to recipients during the nine months ended September 30, 2017, was $0.1 million. Based on the weighted average fair value of performance units outstanding at September 30, 2017, of $0.9 million, there was $0.5 million of total unrecognized compensation expense related to nonvested performance units, which is expected to be recognized over a weighted-average period of 1.8 years.


Note 6:
Debt

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.

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 outstanding at any time without penalty, except for tranche breakage costs.  If an event of default exists under the Credit Agreement, the lenders will be able to accelerate the maturity of all loans outstanding and exercise other rights and remedies.  We were in compliance with the covenants as of September 30, 2017.

Senior Notes
On July 19, 2016, we closed a private placement of $400 million in aggregate principal amount of 6% senior unsecured notes due in 2024 (the “ 6% Senior Notes”). On September 22, 2017, we closed a private placement of an additional $100 million in aggregate offering of the 6% Senior Notes for a combined aggregate principal amount outstanding of $500 million maturing in 2024.

The 6% Senior Notes are unsecured and impose certain restrictive covenants, including limitations on our ability to incur additional indebtedness, make investments, sell assets, incur certain liens, pay distributions, enter into transactions with affiliates and enter into mergers. We were in compliance with the restrictive covenants for the 6% Senior Notes as of September 30, 2017. At any time when the 6% Senior Notes are rated investment grade by both Moody’s and Standard & Poor’s and no default or event of default exists, we will not be subject to many of the foregoing covenants. Additionally, we have certain redemption rights at varying premiums over face value under the 6% Senior Notes.

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

On January 4, 2017, we redeemed the $300 million aggregate principal amount of 6.5% senior notes (the “6.5% Senior Notes”) at a redemption cost of $309.8 million at which time we recognized a $12.2 million early extinguishment loss consisting of a $9.8 million debt redemption premium and unamortized discount and financing costs of $2.4 million. We funded the redemption with borrowings under our Credit Agreement.


- 16 -

Long-term Debt
The carrying amounts of our long-term debt are as follows:
 
 
September 30,
2017
 
December 31,
2016
 
 
(In thousands)
Credit Agreement
 
 
 
 
Amount outstanding
 
$
750,000

 
$
553,000

 
 
 
 
 
6% Senior Notes
 
 
 
 
Principal
 
500,000

 
400,000

Unamortized premium and debt issuance costs
 
(4,934
)
 
(6,607
)
 
 
495,066

 
393,393

6.5% Senior Notes
 
 
 
 
Principal
 
—

 
300,000

Unamortized discount and debt issuance costs
 
—

 
(2,481
)
 
 
—

 
297,519

 
 
 
 
 
Total long-term debt
 
$
1,245,066

 
$
1,243,912


Interest Rate 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 advances matured on July 31, 2017, and were not renewed. The swaps had effectively converted $150 million of our LIBOR based debt to fixed rate debt.

Additional information on our interest rate swaps is as follows:
Derivative Instrument
 
Balance Sheet Location
 
Fair Value
 
Location of Offsetting Balance
 
Offsetting
Amount
 
 
(In thousands)
December 31, 2016
 
 
 
 
 
 
 
 
Interest rate swaps designated as cash flow hedging instrument:
 
 
 
 
 
 
Variable-to-fixed interest rate swap contracts ($150 million of LIBOR-based debt interest)
 
Other current  assets
 
$
91

 
Accumulated other
    comprehensive income
 
$
91

 
 
 
 
$
91

 
 
 
$
91


Interest Expense and Other Debt Information
Interest expense consists of the following components:
 
 
Nine Months Ended September 30,
 
 
2017
 
2016
 
 
(In thousands)
Interest on outstanding debt:
 
 
 
 
Credit Agreement, net of interest on interest rate swaps
 
$
20,338

 
$
13,600

6.5% Senior Notes
 
163

 
14,632

6% Senior Notes
 
18,150

 
4,811

Amortization of discount and deferred debt issuance costs
 
2,317

 
2,294

Commitment fees and other
 
1,137

 
1,419

Total interest incurred
 
42,105

 
36,756

Less capitalized interest
 
746

 
498

Net interest expense
 
$
41,359

 
$
36,258

Cash paid for interest
 
$
53,181

 
$
33,896


Capital Lease Obligations
Our capital lease obligations relate to vehicle leases with initial terms of 33 to 48 months. The total cost of assets under capital leases was $5.2 million and $4.9 million as of September 30, 2017 and December 31, 2016, respectively, with accumulated

- 17 -

depreciation of $3.2 million and $2.4 million as of September 30, 2017 and December 31, 2016, respectively. We include depreciation of capital leases in depreciation and amortization in our consolidated statements of income.


Note 7:
Significant Customers

All revenues are domestic revenues, of which 93% are currently generated from our two largest customers: HFC and Alon.

The following table presents the percentage of total revenues generated by each of these customers:
 
 
Three Months Ended September 30,
 
Nine Months Ended
September 30,
 
 
2017
 
2016
 
2017
 
2016
HFC
 
86
%
 
84
%
 
85
%
 
83
%
Alon
 
7
%
 
8
%
 
7
%
 
8
%


Note 8:
Related Party Transactions

We serve HFC’s refineries under long-term pipeline, terminal and tankage throughput agreements, and refinery processing unit tolling agreements expiring from 2019 to 2036. Under these agreements, HFC agrees to transport, store and process throughput volumes of refined product, crude oil and feedstocks on our pipelines, terminals, 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 Producer Price Index (“PPI”) or Federal Energy Regulatory Commission (“FERC”) index. As of September 30, 2017, these agreements with HFC require minimum annualized payments to us of $321.3 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 these agreements, a shortfall payment may be applied as a credit in the following four quarters after its minimum obligations are met.

Under certain provisions of an omnibus agreement we have with HFC (the “Omnibus Agreement”), we pay HFC an annual administrative fee (currently $2.5 million) for the provision by HFC or its affiliates of various general and administrative services to us. This fee does not include the salaries of personnel employed by HFC who perform services for us on behalf of HLS or the cost of their employee benefits, which are charged to us separately by HFC. Also, we reimburse HFC and its affiliates for direct expenses they incur on our behalf.

Related party transactions with HFC are as follows:
•
Revenues received from HFC were $95.1 million and $77.4 million for the three months ended September 30, 2017 and 2016, respectively, and $277.3 million and $239.4 million for the nine months ended September 30, 2017 and 2016, respectively.
•
HFC charged us general and administrative services under the Omnibus Agreement of $0.6 million for each of the three months ended September 30, 2017 and 2016, and $1.8 million for each of the nine months ended September 30, 2017 and 2016.
•
We reimbursed HFC for costs of employees supporting our operations of $11.7 million and $10.0 million for the three months ended September 30, 2017 and 2016, respectively, and $34.5 million and $29.4 million for the nine months ended September 30, 2017 and 2016, respectively.
•
HFC reimbursed us $1.9 million and $4.5 million for the three months ended September 30, 2017 and 2016, respectively, and $4.7 million and $11.2 million for the nine months ended September 30, 2017 and 2016, respectively, for expense and capital projects.

- 18 -

•
We distributed $32.8 million and $26.2 million for the three months ended September 30, 2017 and 2016, respectively, and $94.8 million and $76.0 million for the nine months ended September 30, 2017 and 2016, respectively, to HFC as regular distributions on its common units and general partner interest, including general partner incentive distributions.
•
Accounts receivable from HFC were $42.8 million and $42.6 million at September 30, 2017, and December 31, 2016, respectively.
•
Accounts payable to HFC were $9.6 million and $16.4 million at September 30, 2017, and December 31, 2016, respectively.
•
Revenues for the nine months ended September 30, 2017 and 2016, include $3.5 million and $5.7 million, respectively, of shortfall payments billed to HFC in 2016 and 2015, respectively. Deferred revenue in the consolidated balance sheets at September 30, 2017 and December 31, 2016, includes $5.8 million and $5.6 million, respectively, relating to certain shortfall billings to HFC. It is possible that HFC may not exceed its minimum obligations to receive credit for any of the $5.8 million deferred at September 30, 2017.


Note 9:
Partners’ Equity

As of September 30, 2017, HFC held 22,380,030 of our common units and the 2% general partner interest, which together constituted a 36% ownership interest in us. Additionally, HFC owned all incentive distribution rights. See Note 1 for a description of the agreement reached with HEP Logistics, our general partner, subsequent to September 30, 2017, impacting its equity interest in HEP.

Continuous Offering Program
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. For the nine months ended September 30, 2017, HEP issued 1,538,452 units under this program, providing $52.3 million in net proceeds. In connection with this program and to maintain the 2% general partner interest, HFC made capital contributions totaling $1.1 million. As of September 30, 2017, HEP has issued 2,241,907 units under this program, providing $77.1 million in gross proceeds.

We intend to use our net proceeds for general partnership purposes, which may include funding working capital, repayment of debt, acquisitions and capital expenditures. Amounts repaid under our credit facility may be reborrowed from time to time.

Allocations of Net Income
Net income attributable to HEP 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 includes incentive distributions that are declared subsequent to quarter end. After incentive distributions and other priority allocations are allocated to the general partner, the remaining net income attributable to HEP is allocated to the partners based on their weighted-average ownership percentage during the period.

See Note 1 for a description of the financial restructuring of the general partner interest owned by HEP Logistics, our general partner, and its IDRs that occurred subsequent to September 30, 2017. After this restructuring, the general partner interest is no longer entitled to any distributions. Therefore, no distributions were declared for the general partner interest related to the three months ended September 30, 2017.


- 19 -

The following table presents the allocation of the general partner interest in net income for the periods presented below: 
 
 
Three Months Ended September 30,
 
Nine Months Ended
September 30,
 
 
2017
 
2016
 
2017
 
2016
 
 
(In thousands)
General partner interest in net income
 
$
(419
)
 
$
399

 
$
919

 
$
1,569

General partner incentive distribution
 
—

 
14,823

 
34,128

 
38,432

Net loss attributable to Predecessor
 
—

 
(7,547
)
 
—

 
(10,657
)
Total general partner interest in net income
 
$
(419
)
 
$
7,675

 
$
35,047

 
$
29,344


Cash Distributions
Prior to the financial restructuring of the general partner interest owned by HEP Logistics, our general partner, and its IDRs that occurred on October 31, 2017, our general partner, HEP Logistics, was entitled to incentive distributions if the amount we distributed with respect to any quarter exceeds specified target levels. After the restructuring of the general partner interest, the general partner interest is no longer entitled to any distributions.

On October 26, 2017, we announced our cash distribution for the third quarter of 2017 of $0.6450 per unit. The distribution is payable on all common units and will be paid November 14, 2017, to all unitholders of record on November 6, 2017. However, Holly Logistics will waive $2.5 million in limited partner cash distributions as discussed in Note 1.

The following table presents the allocation of our regular quarterly cash distributions to the general and limited partners for the periods in which they apply. Our distributions are declared subsequent to quarter end; therefore, the amounts presented do not reflect distributions paid during the periods presented below.
 
 
Three Months Ended September 30,
 
Nine Months Ended
September 30,
 
 
2017
 
2016
 
2017
 
2016
 
 
(In thousands, except per unit data)
General partner interest in distribution
 
$
—

 
$
1,065

 
$
2,335

 
$
2,992

General partner incentive distribution
 
—

 
14,823

 
34,128

 
38,432

Total general partner distribution
 
—

 
15,888

 
36,463

 
41,424

Limited partner distribution
 
63,012

 
37,354

 
143,326

 
105,657

Total regular quarterly cash distribution
 
$
63,012

 
$
53,242

 
$
179,789

 
$
147,081

Cash distribution per unit applicable to limited partners
 
$
0.6450

 
$
0.5950

 
$
1.8975

 
$
1.7550


As a master limited partnership, we distribute our available cash, which historically has exceeded our net income attributable to HEP because depreciation and amortization expense represents a non-cash charge against income. The result is a decline in our partners’ equity since our regular quarterly distributions have exceeded our quarterly net income attributable to HEP. Additionally, if the asset contributions and acquisitions from HFC had occurred while we were not a consolidated variable interest entity of HFC, our acquisition cost, in excess of HFC’s historical basis in the transferred assets, would have been recorded in our financial statements at the time of acquisition as increases to our properties and equipment and intangible assets instead of decreases to our partners’ equity.


Note 10:
Net Income Per Limited Partner Unit

Net income per unit applicable to the limited partners is computed using the two-class method because we have more than one class of participating securities.  The classes of participating securities as of September 30, 2017, included common units, general partner units and incentive distribution rights (“IDRs”). To the extent net income attributable to the partners exceeds or is less than cash distributions, this difference is allocated to the partners based on their weighted-average ownership percentage during the period after consideration of any priority allocations of earnings. The dilutive securities are immaterial for all periods presented. See Note 1 for a description of the financial restructuring of the general partner interest owned by HEP Logistics, our general partner, and its IDRs that occurred subsequent to September 30, 2017. After this restructuring, the general partner interest is no

- 20 -

longer entitled to any distributions. Therefore, no distributions were declared for the general partner interest related to the three months ended September 30, 2017. In addition, HEP issued 37,250,000 of its common units to HEP Logistics on October 31, 2017 in association with this financial restructuring of the general partner interest.

When our financial statements are retrospectively adjusted after a dropdown transaction, the earnings of the acquired business, prior to the closing of the transaction, are allocated entirely to our general partner and presented as net income (loss) attributable to Predecessors. The earnings per unit of our limited partners prior to the close of the transaction do not change as a result of the dropdown. After the closing of a dropdown transaction, the earnings of the acquired business are allocated in accordance with our partnership agreement as previously described.

For purposes of applying the two-class method including the allocation of cash distributions in excess of earnings, net income per limited partner unit is computed as follows:
 
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
 
2017
 
2016
 
2017
 
2016
 
 
(In thousands)
Net income attributable to the partners
 
$
42,071

 
$
34,785

 
$
108,970

 
$
116,880

Less: General partner’s distribution declared (including IDRs)
 
—

 
(15,888
)
 
(36,463
)
 
(41,424
)
Limited partner’s distribution declared on common units
 
(63,012
)
 
(37,354
)
 
(143,326
)
 
(105,657
)
Distributions in excess of net income attributable to the partners
 
$
(20,941
)
 
$
(18,457
)
 
$
(70,819
)
 
$
(30,201
)

 
 
General Partner (including IDRs)
 
Limited Partners’ Common Units
 
Total
 
 
(In thousands, except per unit data)
Three Months Ended September 30, 2017
 
 
 
 
 
 
Net income attributable to the partners:
 
 
 
 
 
 
Distributions declared
 
$
—

 
$
63,012

 
$
63,012

Distributions in excess of net income attributable to the partners
 
(419
)
 
(20,522
)
 
(20,941
)
Net income attributable to the partners
 
$
(419
)
 
$
42,490

 
$
42,071

Weighted average limited partners' units outstanding
 
 
 
64,319

 
 
Limited partners' per unit interest in earnings - basic and diluted
 
 
 
$
0.66

 
 
 
 
 
 
 
 
 
Three Months Ended September 30, 2016
 
 
 
 
 
 
Net income attributable to the partners:
 
 
 
 
 
 
Distributions declared
 
$
15,888

 
$
37,354

 
$
53,242

Distributions in excess of net income attributable to the partners
 
(369
)
 
(18,088
)
 
(18,457
)
Net income attributable to the partners
 
$
15,519

 
$
19,266

 
$
34,785

Weighted average limited partners' units outstanding
 
 
 
59,223

 
 
Limited partners' per unit interest in earnings - basic and diluted
 
 
 
$
0.33

 
 


- 21 -

 
 
General Partner (including IDRs)
 
Limited Partners’ Common Units
 
Total
 
 
(In thousands, except per unit data)
Nine Months Ended September 30, 2017
 
 
 
 
 
 
Net income attributable to partnership:
 
 
 
 
 
 
Distributions declared
 
$
36,463

 
$
143,326

 
$
179,789

Distributions in excess of net income attributable to partnership
 
(1,416
)
 
(69,403
)
 
(70,819
)
Net income attributable to partnership
 
$
35,047

 
$
73,923

 
$
108,970

Weighted average limited partners' units outstanding
 
 
 
63,845

 
 
Limited partners' per unit interest in earnings - basic and diluted
 
 
 
$
1.16

 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2016
 
 
 
 
 
 
Net income attributable to partnership:
 
 
 
 
 
 
Distributions declared
 
$
41,424

 
$
105,657

 
$
147,081

Distributions in excess of net income attributable to partnership
 
(604
)
 
(29,597
)
 
(30,201
)
Net income attributable to partnership
 
$
40,820

 
$
76,060

 
$
116,880

Weighted average limited partners' units outstanding
 
 
 
58,895

 
 
Limited partners' per unit interest in earnings - basic and diluted
 
 
 
$
1.29

 
 


Note 11:
Environmental

We incurred no expenses for environmental remediation obligations for the three and nine months ended September 30, 2017, as well as the three months ended September 30, 2016. For the nine months ended September 30, 2016, we incurred $0.2 million of expense. The accrued environmental liability, net of expected recoveries from indemnifying parties, reflected in our consolidated balance sheets was $6.4 million and $7.1 million at September 30, 2017, and December 31, 2016, respectively, of which $4.7 million and $5.4 million, respectively, were classified as other long-term liabilities. These accruals include remediation and monitoring costs expected to be incurred over an extended period of time.

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. As of September 30, 2017, and December 31, 2016, our consolidated balance sheets included additional accrued environmental liabilities of $0.8 million and $0.9 million, respectively, for HFC indemnified liabilities, and other assets included equal and offsetting balances representing amounts due from HFC related to indemnifications for environmental remediation liabilities.


Note 12:
Contingencies

We are a party to various legal and regulatory proceedings, none of which we believe will have a material adverse impact on our financial condition, results of operations or cash flows.


Note 13:
Operating Segments

Although financial information is reviewed by our chief operating decision makers from a variety of perspectives, they view the business in two operating segments: pipelines and terminals, and refinery processing units. These operating segments adhere to the accounting polices used for our consolidated financial statements.

The pipelines and terminals segment has been aggregated as both pipeline and terminals (1) have similar economic characteristics, (2) similarly provide logistics services of transportation and storage of petroleum products, (3) similarly support the petroleum

- 22 -

refining business, including distribution of its products, (4) have principally the same customers and (5) are subject to similar regulatory requirements.

We evaluate the performance of each segment based on its respective operating income. Certain general and administrative expenses and interest and financing costs are excluded from segment operating income as they are not directly attributable to a specific operating segment. Identifiable assets are those used by the segment, whereas other assets are principally equity method investments, cash, deposits and other assets that are not associated with a specific reportable operating segment.
 
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
 
2017
 
2016
 
2017
 
2016
 
 
 
 
 
 
 
Revenues:
 
 
 
 
 
 
 
 
Pipelines and terminals - affiliate
 
$
74,547

 
$
73,210

 
$
219,806

 
$
226,553

Pipelines and terminals - third-party
 
15,226

 
15,212

 
47,826

 
50,094

Refinery processing units - affiliate
 
20,591

 
4,188

 
57,510

 
12,870

Total segment revenues
 
$
110,364

 
$
92,610

 
$
325,142

 
$
289,517

 
 
 
 
 
 
 
 
 
Segment operating income:
 
 
 
 
 
 
 
 
Pipelines and terminals
 
$
44,896

 
$
48,928

 
$
140,546

 
$
155,657

Refinery processing units
 
10,463

 
(7,339
)
 
24,283

 
(6,491
)
Total segment operating income
 
55,359

 
41,589

 
164,829

 
149,166

Unallocated general and administrative expenses
 
(3,623
)
 
(2,664
)
 
(8,872
)
 
(8,618
)
Interest and financing costs, net
 
(13,971
)
 
(14,339
)
 
(53,278
)
 
(35,926
)
Equity in earnings of unconsolidated affiliates
 
5,072

 
3,767

 
10,965

 
10,155

Gain on sale of assets and other
 
155

 
112

 
317

 
104

Income before income taxes
 
$
42,992

 
$
28,465

 
$
113,961

 
$
114,881

 
 
 
 
 
 
 
 
 
Capital Expenditures:
 
 
 
 
 
 
 
 
  Pipelines and terminals
 
$
10,151

 
$
15,557

 
$
30,437

 
$
47,200

  Refinery processing units
 
—

 
5,173

 
238

 
48,915

Total capital expenditures
 
$
10,151

 
$
20,730

 
$
30,675

 
$
96,115


 
 
September 30, 2017
 
December 31, 2016
 
 
(in thousands)
Identifiable assets:
 
 
 
 
  Pipelines and terminals
 
$
1,353,585

 
$
1,369,756

  Refinery processing units
 
335,388

 
342,506

Other
 
176,869

 
171,975

Total identifiable assets
 
$
1,865,842

 
$
1,884,237


The refinery processing units operating segment loss for the three and nine months ended September 30, 2016, is due to the net loss attributable to Predecessor.
Note 14:
Supplemental Guarantor/Non-Guarantor Financial Information

Obligations of HEP (“Parent”) under the 6% Senior Notes have been jointly and severally guaranteed by each of its direct and indirect 100% owned subsidiaries (“Guarantor Subsidiaries”). These guarantees are full and unconditional, subject to certain customary release provisions. These circumstances include (i) when a Guarantor Subsidiary is sold or sells all or substantially all of its assets, (ii) when a Guarantor Subsidiary is declared “unrestricted” for covenant purposes, (iii) when a Guarantor Subsidiary’s guarantee of other indebtedness is terminated or released and (iv) when the requirements for legal defeasance or covenant defeasance or to discharge the senior notes have been satisfied.

The following financial information presents condensed consolidating balance sheets, statements of comprehensive income, and statements of cash flows of the Parent, the Guarantor Subsidiaries and the Non-Guarantor Subsidiaries. The information has been presented as if the Parent accounted for its ownership in the Guarantor Subsidiaries, and the Guarantor Restricted Subsidiaries accounted for the ownership of the Non-Guarantor Non-Restricted Subsidiaries, using the equity method of accounting.

In conjunction with the preparation of our Condensed Consolidating Balance Sheet and Statements of Comprehensive Income included below, we identified and corrected the presentation of noncontrolling interests presented in the eliminations column in prior periods to reflect such balances and activity within the respective guarantor and non-guarantor subsidiaries columns.


Condensed Consolidating Balance Sheet
September 30, 2017
 
Parent
 
Guarantor
Restricted Subsidiaries
 
Non-Guarantor Non-Restricted Subsidiaries
 
Eliminations
 
Consolidated
 
 
(In thousands)
ASSETS
 
 
 
 
 
 
 
 
 
 
Current assets:
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
2

 
$
6

 
$
7,468

 
$
—

 
$
7,476

Accounts receivable
 
—

 
46,157

 
4,096

 
(170
)
 
50,083

Prepaid and other current assets
 
52

 
1,988

 
255

 
—

 
2,295

Total current assets
 
54

 
48,151

 
11,819

 
(170
)
 
59,854

 
 
 
 
 
 
 
 
 
 
 
Properties and equipment, net
 
—

 
947,094

 
359,999

 
—

 
1,307,093

Investment in subsidiaries

 
1,608,736

 
273,874

 
—

 
(1,882,610
)
 
—

Transportation agreements, net
 
—

 
61,644

 
—

 
—

 
61,644

Goodwill
 
—

 
256,498

 
—

 
—

 
256,498

Equity method investments
 
—

 
163,873

 
—

 
—

 
163,873

Other assets
 
12,329

 
4,551

 
—

 
—

 
16,880

Total assets
 
$
1,621,119

 
$
1,755,685

 
$
371,818

 
$
(1,882,780
)
 
$
1,865,842

 
 
 
 
 
 
 
 
 
 
 
LIABILITIES AND EQUITY
 
 
 
 
 
 
 
 
 
 
Current liabilities:
 
 
 
 
 
 
 
 
 
 
Accounts payable
 
$
—

 
$
21,770

 
$
1,543

 
$
(170
)
 
$
23,143

Accrued interest
 
5,000

 
527

 
—

 
—

 
5,527

Deferred revenue
 
—

 
13,326

 
1,501

 
—

 
14,827

Accrued property taxes
 
—

 
4,073

 
3,414

 
—

 
7,487

Other current liabilities
 
52

 
3,440

 
—

 
—

 
3,492

Total current liabilities
 
5,052

 
43,136

 
6,458

 
(170
)
 
54,476


 
 
 
 
 
 
 
 
 
 
Long-term debt
 
1,245,066

 
—

 
—

 
—

 
1,245,066

Other long-term liabilities
 
286

 
14,996

 
195

 
—

 
15,477

Deferred revenue
 
—

 
46,405

 
—

 
—

 
46,405

Class B unit
 
—

 
42,412

 
—

 
—

 
42,412

Equity - partners
 
370,715

 
1,608,736

 
273,874

 
(1,882,610
)
 
370,715

Equity - noncontrolling interest
 
—

 
—

 
91,291

 
—

 
91,291

Total liabilities and equity
 
$
1,621,119

 
$
1,755,685

 
$
371,818

 
$
(1,882,780
)
 
$
1,865,842



- 23 -


Condensed Consolidating Balance Sheet
December 31, 2016
 
Parent
 
Guarantor
Restricted Subsidiaries
 
Non-Guarantor Non-Restricted Subsidiaries
 
Eliminations
 
Consolidated
 
 
(In thousands)
ASSETS
 
 
 
 
 
 
 
 
 
 
Current assets:
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
2

 
$
301

 
$
3,354

 
$
—

 
$
3,657

Accounts receivable
 
—

 
45,056

 
5,554

 
(202
)
 
50,408

Prepaid and other current assets
 
11

 
2,633

 
244

 
—

 
2,888

Total current assets
 
13

 
47,990

 
9,152

 
(202
)
 
56,953

 
 
 
 
 
 
 
 
 
 
 
Properties and equipment, net
 
—

 
957,045

 
371,350

 
—

 
1,328,395

Investment in subsidiaries
 
1,086,008

 
280,671

 
—

 
(1,366,679
)
 
—

Transportation agreements, net
 
—

 
66,856

 
—

 
—

 
66,856

Goodwill
 
—

 
256,498

 
—

 
—

 
256,498

Equity method investments
 
—

 
165,609

 
—

 
—

 
165,609

Other assets
 
725

 
9,201

 
—

 
—

 
9,926

Total assets
 
$
1,086,746

 
$
1,783,870

 
$
380,502

 
$
(1,366,881
)
 
$
1,884,237

 
 
 
 
 
 
 
 
 
 
 
LIABILITIES AND EQUITY
 
 
 
 
 
 
 
 
 
 
Current liabilities:
 
 
 
 
 
 
 
 
 
 
Accounts payable
 
$
—

 
$
24,245

 
$
2,899

 
$
(202
)
 
$
26,942

Accrued interest
 
17,300

 
769

 
—

 
—

 
18,069

Deferred revenue
 
—

 
8,797

 
2,305

 
—

 
11,102

Accrued property taxes
 
—

 
4,514

 
883

 
—

 
5,397

Other current liabilities
 
14

 
3,208

 
3

 
—

 
3,225

Total current liabilities
 
17,314

 
41,533

 
6,090

 
(202
)
 
64,735

 
 
 
 
 
 
 
 
 
 
 
Long-term debt
 
690,912

 
553,000

 
—

 
—

 
1,243,912

Other long-term liabilities
 
286

 
15,975

 
184

 
—

 
16,445

Deferred revenue
 
—

 
47,035

 
—

 
—

 
47,035

Class B unit
 
—

 
40,319

 
—

 
—

 
40,319

Equity - partners
 
378,234

 
1,086,008

 
280,671

 
(1,366,679
)
 
378,234

Equity - noncontrolling interest
 
—

 
—

 
93,557

 
—

 
93,557

Total liabilities and equity
 
$
1,086,746

 
$
1,783,870

 
$
380,502

 
$
(1,366,881
)
 
$
1,884,237





- 24 -


Condensed Consolidating Statement of Comprehensive Income
Three Months Ended September 30, 2017
 
Parent
 
Guarantor Restricted
Subsidiaries
 
Non-Guarantor Non-restricted Subsidiaries
 
Eliminations
 
Consolidated
 
 
(In thousands)
Revenues:
 
 
 
 
 
 
 
 
 
 
Affiliates
 
$
—

 
$
89,772

 
$
5,366

 
$
—

 
$
95,138

Third parties
 
—

 
10,758

 
4,468

 
—

 
15,226

 
 
—

 
100,530

 
9,834

 
—

 
110,364

Operating costs and expenses:
 
 
 
 
 
 
 
 
 
 
Operations (exclusive of depreciation and amortization)
 
—

 
31,360

 
4,638

 
—

 
35,998

Depreciation and amortization
 


 
14,854

 
4,153

 
—

 
19,007

General and administrative
 
1,050

 
2,573

 
—

 
—

 
3,623

 
 
1,050

 
48,787

 
8,791

 
—

 
58,628

Operating income (loss)
 
(1,050
)
 
51,743

 
1,043

 
—

 
51,736

 
 
 
 
 
 
 
 
 
 
 
Other income (expense):
 
 
 
 
 
 
 
 
 
 
Equity in earnings of subsidiaries
 
57,193

 
783

 
—

 
(57,976
)
 
—

Equity in earnings of equity method investments
 
—

 
5,072

 
—

 
—

 
5,072

Interest expense
 
(14,072
)
 
—

 
—

 
—

 
(14,072
)
Interest income
 
—

 
101

 
—

 
—

 
101

Gain on sale of assets and other
 
—

 
154

 
1

 
—

 
155

 
 
43,121

 
6,110

 
1

 
(57,976
)
 
(8,744
)
Income (loss) before income taxes
 
42,071

 
57,853

 
1,044

 
(57,976
)
 
42,992

State income tax benefit
 
—

 
69

 
—

 
—

 
69

Net income
 
42,071

 
57,922

 
1,044

 
(57,976
)
 
43,061

Allocation of net income attributable to noncontrolling interests
 
—

 
(729
)
 
(261
)
 
—

 
(990
)
Net income attributable to Holly Energy Partners
 
42,071

 
57,193

 
783

 
(57,976
)
 
42,071

Other comprehensive income
 
(63
)
 
(63
)
 
—

 
63

 
(63
)
Comprehensive income attributable to Holly Energy Partners
 
$
42,008

 
$
57,130

 
$
783

 
$
(57,913
)
 
$
42,008



- 25 -


Condensed Consolidating Statement of Comprehensive Income
Three Months Ended September 30, 2016 (1)
 
Parent
 
Guarantor
Restricted Subsidiaries
 
Non-Guarantor Non-Restricted Subsidiaries
 
Eliminations
 
Consolidated
 
 
(In thousands)
Revenues:
 
 
 
 
 
 
 
 
 
 
Affiliates
 
$
—

 
$
72,389

 
$
5,009

 
$
—

 
$
77,398

Third parties
 
—

 
11,360

 
3,852

 
—

 
15,212

 
 
—

 
83,749

 
8,861

 
—

 
92,610

Operating costs and expenses:
 
 
 
 
 
 
 
 
 
 
Operations (exclusive of depreciation and amortization)
 
—

 
29,023

 
3,078

 
—

 
32,101

Depreciation and amortization
 
—

 
15,093

 
3,827

 
—

 
18,920

General and administrative
 
813

 
1,851

 
—

 
—

 
2,664

 
 
813

 
45,967

 
6,905

 
—

 
53,685

Operating income (loss)
 
(813
)
 
37,782

 
1,956

 
—

 
38,925

 
 
 
 
 
 
 
 
 
 
 
Other income (expense):
 
 
 
 
 
 
 
 
 
 
Equity in earnings of subsidiaries
 
44,359

 
1,451

 
—

 
(45,810
)
 
—

Equity in earnings of equity method investments
 
—

 
3,767

 
—

 
—

 
3,767

Interest expense
 
(10,011
)
 
(4,436
)
 
—

 
—

 
(14,447
)
Interest income
 
—

 
103

 
5

 
—

 
108

Gain (loss) on sale of assets and other
 
—

 
138

 
(26
)
 
—

 
112

 
 
34,348

 
1,023

 
(21
)
 
(45,810
)
 
(10,460
)
Income before income taxes
 
33,535

 
38,805

 
1,935

 
(45,810
)
 
28,465

State income tax expense
 
—

 
(61
)
 
—

 
—

 
(61
)
Net income
 
33,535

 
38,744

 
1,935

 
(45,810
)
 
28,404

Allocation of net loss to Predecessor
 
—

 
7,547

 
—

 
—

 
7,547

Allocation of net income attributable to noncontrolling interests
 
—

 
(682
)
 
(484
)
 
—

 
(1,166
)
Net income attributable to Holly Energy Partners
 
33,535

 
45,609

 
1,451

 
(45,810
)
 
34,785

Other comprehensive (loss)
 
296

 
296

 
—

 
(296
)
 
296

Comprehensive income attributable to Holly Energy Partners
 
$
33,831

 
$
45,905

 
$
1,451

 
$
(46,106
)
 
$
35,081


(1) Retrospectively adjusted as described in Note 1.



- 26 -


Condensed Consolidating Statement of Comprehensive Income
Nine Months Ended September 30, 2017
 
Parent
 
Guarantor Restricted
Subsidiaries
 
Non-Guarantor Non-restricted Subsidiaries
 
Eliminations
 
Consolidated
 
 
(In thousands)
Revenues:
 
 
 
 
 
 
 
 
 
 
Affiliates
 
$
—

 
$
258,571

 
$
18,745

 
$
—

 
$
277,316

Third parties
 
—

 
32,146

 
15,680

 
—

 
47,826

 
 
—

 
290,717

 
34,425

 
—

 
325,142

Operating costs and expenses:
 
 
 
 
 
 
 
 
 
 
Operations (exclusive of depreciation and amortization)
 
—

 
91,323

 
11,261

 
—

 
102,584

Depreciation and amortization
 
—

 
45,498

 
12,231

 
—

 
57,729

General and administrative
 
3,070

 
5,802

 
—

 
—

 
8,872

 
 
3,070

 
142,623

 
23,492

 
—

 
169,185

Operating income (loss)
 
(3,070
)
 
148,094

 
10,933

 
—

 
155,957

 
 
 
 
 
 
 
 
 
 
 
Other income (expense):
 
 
 
 
 
 
 
 
 
 
Equity in earnings (loss) of subsidiaries
 
165,624

 
8,203

 
—

 
(173,827
)
 
—

Equity in earnings of equity method investments
 
—

 
10,965

 
—

 
—

 
10,965

Interest expense
 
(41,359
)
 
—

 
—

 
—

 
(41,359
)
Interest income
 
—

 
306

 
—

 
—

 
306

Loss on early extinguishment of debt
 
(12,225
)
 
—

 
—

 
—

 
(12,225
)
Gain (loss) on sale of assets and other
 
—

 
313

 
4

 
—

 
317

 
 
112,040

 
19,787

 
4

 
(173,827
)
 
(41,996
)
Income (loss) before income taxes
 
108,970

 
167,881

 
10,937

 
(173,827
)
 
113,961

State income tax expense
 
—

 
(164
)
 
—

 
—

 
(164
)
Net income (loss)
 
108,970

 
167,717

 
10,937

 
(173,827
)
 
113,797

Allocation of net income attributable to noncontrolling interests
 
—

 
(2,093
)
 
(2,734
)
 
—

 
(4,827
)
Net income (loss) attributable to Holly Energy Partners
 
108,970

 
165,624

 
8,203

 
(173,827
)
 
108,970

Other comprehensive income (loss)
 
(91
)
 
(91
)
 
—

 
91

 
(91
)
Comprehensive income (loss)
 
$
108,879

 
$
165,533

 
$
8,203

 
$
(173,736
)
 
$
108,879






- 27 -


Condensed Consolidating Statement of Comprehensive Income
Nine Months Ended September 30, 2016 (1)
 
Parent
 
Guarantor
Restricted Subsidiaries
 
Non-Guarantor Non-Restricted Subsidiaries
 
Eliminations
 
Consolidated
 
 
(In thousands)
Revenues:
 
 
 
 
 
 
 
 
 
 
Affiliates
 
$
—

 
$
219,428

 
$
19,995

 
$
—

 
$
239,423

Third parties
 
—

 
33,783

 
16,311

 
—

 
50,094

 
 
—

 
253,211

 
36,306

 
—

 
289,517

Operating costs and expenses:
 
 
 
 
 
 
 
 
 
 
Operations (exclusive of depreciation and amortization)
 
—

 
80,248

 
8,920

 
—

 
89,168

Depreciation and amortization
 
—

 
39,811

 
11,372

 
—

 
51,183

General and administrative
 
2,949

 
5,669

 
—

 
—

 
8,618

 
 
2,949

 
125,728

 
20,292

 
—

 
148,969

Operating income (loss)
 
(2,949
)
 
127,483

 
16,014

 
—

 
140,548

 
 
 
 
 
 
 
 
 
 
 
Other income (expense):
 
 
 
 
 
 
 
 
 
 
Equity in earnings (loss) of subsidiaries
 
138,513

 
12,004

 
—

 
(150,517
)
 
—

Equity in earnings of equity method investments
 
—

 
10,155

 
—

 
—

 
10,155

Interest expense
 
(20,151
)
 
(16,107
)
 
—

 
—

 
(36,258
)
Interest income
 
—

 
315

 
17

 
—

 
332

Gain (loss) on sale of assets and other
 
—

 
129

 
(25
)
 
—

 
104

 
 
118,362

 
6,496

 
(8
)
 
(150,517
)
 
(25,667
)
Income (loss) before income taxes
 
115,413

 
133,979

 
16,006

 
(150,517
)
 
114,881

State income tax expense
 
—

 
(210
)
 
—

 
—

 
(210
)
Net income (loss)
 
115,413

 
133,769

 
16,006

 
(150,517
)
 
114,671

Allocation of net loss to Predecessor
 


 
10,657

 
—

 
—

 
10,657

Allocation of net income attributable to noncontrolling interests
 
—

 
(4,446
)
 
(4,002
)
 
—

 
(8,448
)
Net income (loss) attributable to Holly Energy Partners
 
115,413

 
139,980

 
12,004

 
(150,517
)
 
116,880

Other comprehensive income (loss)
 
(299
)
 
(299
)
 
—

 
299

 
(299
)
Comprehensive income (loss)
 
$
115,114

 
$
139,681

 
$
12,004

 
$
(150,218
)
 
$
116,581



(1) Retrospectively adjusted as described in Note 1.




- 28 -

Condensed Consolidating Statement of Cash Flows
Nine Months Ended September 30, 2017
 
Parent
 
Guarantor
Restricted Subsidiaries
 
Non-Guarantor Non-Restricted Subsidiaries
 
Eliminations
 
Consolidated
 
 
(In thousands)
Cash flows from operating activities
 
$
(57,045
)
 
$
215,643

 
$
27,064

 
$
(8,203
)
 
$
177,459

 
 
 
 
 
 
 
 
 
 
 
Cash flows from investing activities
 
 
 
 
 
 
 
 
 
 
Additions to properties and equipment
 
—

 
(27,725
)
 
(2,950
)
 
—

 
(30,675
)
Distributions from UNEV in excess of earnings
 
—

 
6,797

 
—

 
(6,797
)
 
—

Proceeds from sale of assets
 
—

 
794

 
—

 
—

 
794

Distributions in excess of equity in earnings of equity investments
 
—

 
1,224

 
—

 
—

 
1,224

 
 
—

 
(18,910
)
 
(2,950
)
 
(6,797
)
 
(28,657
)
 
 
 
 
 
 
 
 
 
 
 
Cash flows from financing activities
 
 
 
 
 
 
 
 
 
 
Net borrowings under credit agreement
 
750,000

 
(553,000
)
 
—

 
—

 
197,000

Net intercompany financing activities
 
(357,196
)
 
357,196

 
—

 
—

 
—

Proceeds from issuance of 6% Senior Notes
 
103,250

 
(1,500
)
 
—

 
—

 
101,750

Proceeds from issuance of common units
 
52,285

 
—

 
—

 
—

 
52,285

Contribution from general partner
 
1,072

 
—

 
—

 
—

 
1,072

Redemption of senior notes
 
(309,750
)
 
—

 
—

 
—

 
(309,750
)
Distributions to HEP unitholders
 
(171,560
)
 
—

 
—

 
—

 
(171,560
)
Distribution to HFC for El Dorado tanks
 
(103
)
 
—

 
—

 
—

 
(103
)
Distributions to noncontrolling interests
 
—

 
—

 
(20,000
)
 
15,000

 
(5,000
)
Deferred financing cost
 
(10,953
)
 
1,500

 
—

 
—

 
(9,453
)
Other
 
—

 
(1,224
)
 
—

 
—

 
(1,224
)
 
 
57,045

 
(197,028
)
 
(20,000
)
 
15,000

 
(144,983
)
 
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
 
 
 
 
 
 
 
 
 
Increase (decrease) for the period
 
—

 
(295
)
 
4,114

 
—

 
3,819

Beginning of period
 
2

 
301

 
3,354

 
—

 
3,657

End of period
 
$
2

 
$
6

 
$
7,468

 
$
—

 
$
7,476



- 29 -


Condensed Consolidating Statement of Cash Flows
Nine Months Ended September 30, 2016 (1)
 
Parent
 
Guarantor
Restricted Subsidiaries
 
Non-Guarantor Non-Restricted Subsidiaries
 
Eliminations
 
Consolidated
 
 
(In thousands)
Cash flows from operating activities
 
$
(20,467
)
 
$
181,967

 
$
27,724

 
$
(11,250
)
 
$
177,974

 
 
 
 
 
 
 
 
 
 
 
Cash flows from investing activities
 
 
 
 
 
 
 
 
 
 
Additions to properties and equipment
 
—

 
(33,147
)
 
(15,077
)
 
—

 
(48,224
)
Purchase of Woods Cross refinery processing units
 
—

 
(47,891
)
 
—

 
—

 
(47,891
)
Purchase of Cheyenne Pipeline
 
—

 
(42,550
)
 
—

 
—

 
(42,550
)
Proceeds from sale of assets
 
—

 
210

 
—

 
—

 
210

Distributions in excess of equity in earnings of equity investments
 
—

 
1,685

 
—

 
—

 
1,685

Other
 
—

 
(351
)
 
—

 
—

 
(351
)
 
 
—

 
(122,044
)
 
(15,077
)
 
—

 
(137,121
)
 
 
 
 
 
 
 
 
 
 
 
Cash flows from financing activities
 
 
 
 
 
 
 
 
 
 
Net repayments under credit agreement
 
—

 
(332,000
)
 
—

 
—

 
(332,000
)
Net intercompany financing activities
 
(257,172
)
 
257,172

 
—

 
—

 
—

Proceeds from issuance of senior notes
 
394,000

 
—

 
—

 
—

 
394,000

Proceeds from issuance of common units
 
22,591

 
200

 
—

 
—

 
22,791

Distributions to HEP unitholders
 
(138,798
)
 
—

 
—

 
—

 
(138,798
)
Distributions to noncontrolling interests
 
—

 
—

 
(15,000
)
 
11,250

 
(3,750
)
Contributions from general partner for Osage
 
31,285

 
(31,285
)
 
—

 
—

 
—

Distributions to HFC for Tulsa Tank acquisition
 
(30,378
)
 
(9,122
)
 
—

 
—

 
(39,500
)
Distribution to HFC for Osage
 
—

 
(1,245
)
 
—

 
—

 
(1,245
)
Contribution from HFC for acquisitions
 
99

 
54,928

 
—

 
—

 
55,027

Contributions from general partner
 
470

 
—

 
—

 
—

 
470

Purchase of units for incentive grants
 
(784
)
 
—

 
—

 
—

 
(784
)
Deferred financing costs
 
(846
)
 
(3,084
)
 
—

 
—

 
(3,930
)
Other
 
—

 
(939
)
 
—

 
—

 
(939
)
 
 
20,467

 
(65,375
)
 
(15,000
)
 
11,250

 
(48,658
)
 
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
 
 
 
 
 
 
 
 
 
Decrease for the period
 
—

 
(5,452
)
 
(2,353
)
 
—

 
(7,805
)
Beginning of period
 
2

 
5,452

 
9,559

 
—

 
15,013

End of period
 
$
2

 
$
—

 
$
7,206

 
$
—

 
$
7,208


(1) Retrospectively adjusted as described in Note 1.


- 30 -



Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations

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


OVERVIEW

HEP is a Delaware limited partnership. We own and operate petroleum product and crude oil pipelines, terminal, tankage, loading rack facilities and refinery processing units that support the refining and marketing operations of HollyFrontier Corporation (“HFC”) in the Mid-Continent, Southwest and Northwest regions of the United States and Alon USA, Inc’s (“Alon”) refinery in Big Spring, Texas. HEP, through its subsidiaries and joint ventures, owns and/or operates petroleum product and crude gathering pipelines, tankage and terminals in Texas, New Mexico, Arizona, Washington, Idaho, Oklahoma, Utah, Nevada, Wyoming and Kansas as well as refinery processing units in Utah and Kansas. HFC owned a 36% interest in us, including the 2% general partnership interest, as of September 30, 2017.

On October 31, 2017, we closed the restructuring transaction set forth in the definitive agreement with HEP Logistics Holdings, L.P. (“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 are canceled, and HEP Logistics' 2% general partner interest in HEP is 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, HFC 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 are eligible to receive distributions. As of October 31, 2017, HFC held approximately 59.6 million HEP common units, representing approximately 59% of the outstanding common units. As a result of this transaction, no distributions will be made on the general partner interest after October 31, 2017.

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 February 22, 2016, HFC obtained a 50% membership interest in Osage Pipe Line Company, LLC (“Osage”) in a non-monetary exchange for a 20-year terminalling services agreement, whereby a subsidiary of Magellan Midstream Partners (“Magellan”) will provide terminalling services for all HFC products originating in Artesia, New Mexico that require terminalling in or through El Paso, Texas. Osage is the owner of the Osage Pipeline, a 135-mile pipeline that transports crude oil from Cushing, Oklahoma to HFC’s El Dorado Refinery in Kansas and also has a connection to the Jayhawk pipeline that services the CHS Inc. refinery in McPherson, Kansas. The Osage Pipeline is the primary pipeline that supplies HFC’s El Dorado Refinery with crude oil.

Concurrent with this transaction, we entered into a non-monetary exchange with HFC, whereby we received HFC’s interest in Osage in exchange for our El Paso terminal. Under this exchange, we also agreed to build two connections on our south products pipeline system that will permit HFC access to Magellan’s El Paso terminal. Effective upon the closing of this exchange, we became the named operator of the Osage Pipeline and transitioned into that role.

On March 31, 2016, we acquired crude oil tanks located at HFC’s Tulsa refinery from an affiliate of Plains All American Pipeline, L.P. (“Plains”) for $39.5 million. In 2009, HFC sold these tanks to Plains and leased them back, and due to HFC’s continuing interest in the tanks, HFC accounted for the transaction as a financing arrangement. Accordingly, the tanks remained on HFC’s balance sheet and were depreciated for accounting purposes. In connection with this transaction, we entered into a 10-year throughput agreement containing minimum quarterly throughput commitments from HFC. As of September 30, 2017, these commitments provide minimum annualized revenues of $5.7 million.


- 31 -

On June 3, 2016, we acquired a 50% interest in Cheyenne Pipeline LLC, owner of the Cheyenne Pipeline, in exchange for a contribution of $42.6 million in cash to Cheyenne Pipeline LLC. Cheyenne Pipeline LLC will continue to be operated by an affiliate of Plains, which owns the remaining 50% interest. The 87-mile crude oil pipeline runs from Fort Laramie to Cheyenne, Wyoming and has an 80,000 barrel per day (“bpd”) capacity.

Effective October 1, 2016, we acquired all the membership interests of Woods Cross Operating LLC (“Woods Cross Operating”), a wholly owned subsidiary of HFC, which owns the newly constructed atmospheric distillation tower, fluid catalytic cracking unit, and polymerization unit located at HFC’s Woods Cross Refinery, for cash consideration of $278.0 million. In connection with this transaction, we entered into 15-year tolling agreements containing minimum quarterly throughput commitments from HFC. As of September 30, 2017, these commitments provide minimum annualized revenues of $57.3 million.

We are a consolidated variable interest entity (“VIE”) of HFC. Therefore, the acquisitions of the crude tanks at HFC's Tulsa refinery on March 31, 2016, and Woods Cross Operating on October 1, 2016, were accounted for as transfers between entities under common control. Accordingly, this financial data has been retrospectively adjusted to include the historical results of these acquisitions for all periods presented prior to the effective dates of each acquisition. We refer to these historical results as those of our "Predecessor." See Note 1 for further discussion of these acquisitions and basis of presentation.

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 All American Pipeline, L.P. (“Plains”), for total consideration of $250 million. As of September 30, 2017, 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 will 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 will be remeasured at acquisition date fair value since we will have a controlling interest, and we expect to recognize a gain on the remeasurement in the fourth quarter of 2017.

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.

Agreements with HFC and Alon
We serve HFC’s refineries under long-term pipeline, terminal, tankage and refinery processing unit throughput agreements expiring from 2019 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 Producer Price Index (“PPI”) or Federal Energy Regulatory Commission (“FERC”) index. As of September 30, 2017, these agreements with HFC require minimum annualized payments to us of $321.3 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.

We have a pipelines and terminals agreement with Alon expiring in 2020 under which Alon 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 is also subject to annual tariff rate adjustments. We also have a capacity lease agreement under which we lease Alon space on our Orla to El Paso pipeline for the shipment of refined product, which expires in 2022. As of September 30, 2017, these agreements with Alon require minimum annualized payments to us of $33.1 million.

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

Under certain provisions of an omnibus agreement we have with HFC (“Omnibus Agreement”), we pay HFC an annual administrative fee, currently $2.5 million, for the provision by HFC or its affiliates of various general and administrative services to us. This fee does not include the salaries of personnel employed by HFC who perform services for us on behalf of Holly Logistic Services, L.L.C. (“HLS”), or the cost of their employee benefits, which are separately charged to us by HFC. We also reimburse HFC and its affiliates for direct expenses they incur on our behalf.


- 32 -

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.

- 33 -

RESULTS OF OPERATIONS (Unaudited)

Income, Distributable Cash Flow and Volumes
The following tables present income, distributable cash flow and volume information for the nine months ended September 30, 2017 and 2016. These results have been adjusted to include the combined results of our Predecessor. See Note 1 to the Consolidated Financial Statements of HEP for discussion of the basis of this presentation
 
 
Three Months Ended September 30,
 
Change from
 
 
2017
 
2016
 
2016
 
 
(In thousands, except per unit data)
Revenues:
 
 
 
 
 
 
Pipelines:
 
 
 
 
 
 
Affiliates—refined product pipelines
 
$
20,801

 
$
19,227

 
$
1,574

Affiliates—intermediate pipelines
 
7,832

 
6,628

 
1,204

Affiliates—crude pipelines
 
14,089

 
17,034

 
(2,945
)
 
 
42,722

 
42,889

 
(167
)
Third parties—refined product pipelines
 
11,350

 
11,176

 
174

 
 
54,072

 
54,065

 
7

Terminals, tanks and loading racks:
 
 
 
 
 
 
Affiliates
 
31,825

 
30,322

 
1,503

Third parties
 
3,876

 
4,035

 
(159
)
 
 
35,701

 
34,357

 
1,344

 
 
 
 
 
 
 
Affiliates—refinery processing units
 
20,591

 
4,188

 
16,403

 
 
 
 
 
 
 
Total revenues
 
110,364

 
92,610

 
17,754

Operating costs and expenses:
 
 
 
 
 
 
Operations (exclusive of depreciation and amortization)
 
35,998

 
32,101

 
3,897

Depreciation and amortization
 
19,007

 
18,920

 
87

General and administrative
 
3,623

 
2,664

 
959

 
 
58,628

 
53,685

 
4,943

Operating income
 
51,736

 
38,925

 
12,811

Other income (expense):
 
 
 
 
 
 
Equity in earnings of equity method investments
 
5,072

 
3,767

 
1,305

Interest expense, including amortization
 
(14,072
)
 
(14,447
)
 
375

Interest income
 
101

 
108

 
(7
)
Gain on sale of assets and other
 
155

 
112

 
43

 
 
(8,744
)
 
(10,460
)
 
1,716

Income before income taxes
 
42,992

 
28,465

 
14,527

State income tax expense
 
69

 
(61
)
 
130

Net income
 
43,061

 
28,404

 
14,657

Allocation of net loss to Predecessor
 
—

 
7,547

 
(7,547
)
Allocation of net income attributable to noncontrolling interests
 
(990
)
 
(1,166
)
 
176

Net income attributable to the partners
 
42,071

 
34,785

 
7,286

General partner interest in net income attributable to the partners (1)
 
419

 
(15,222
)
 
15,641

Limited partners’ interest in net income
 
$
42,490

 
$
19,563

 
$
22,927

Limited partners’ earnings per unit—basic and diluted (1)
 
$
0.66

 
$
0.33

 
$
0.33

Weighted average limited partners’ units outstanding
 
64,319

 
59,223

 
5,096

EBITDA (2)
 
$
74,980

 
$
64,705

 
$
10,275

Distributable cash flow (3)
 
$
59,248

 
$
49,257

 
$
9,991

 
 
 
 
 
 
 
Volumes (bpd)
 
 
 
 
 
 
Pipelines:
 
 
 
 
 
 
Affiliates—refined product pipelines
 
142,624

 
128,020

 
14,604

Affiliates—intermediate pipelines
 
151,622

 
142,417

 
9,205

Affiliates—crude pipelines
 
267,911

 
271,278

 
(3,367
)
 
 
562,157

 
541,715

 
20,442

Third parties—refined product pipelines
 
74,703

 
73,517

 
1,186

 
 
636,860

 
615,232

 
21,628

Terminals and loading racks:
 
 
 
 
 

Affiliates
 
426,122

 
437,560

 
(11,438
)
Third parties
 
69,405

 
68,276

 
1,129

 
 
495,527

 
505,836

 
(10,309
)
 
 
 
 
 
 
 
Affiliates—refinery processing units
 
61,453

 
46,451

 
15,002

 
 
 
 
 
 
 
Total for pipelines and terminal and refiney processing unit assets (bpd)
 
1,193,840

 
1,167,519

 
26,321


- 34 -

 
 
Nine Months Ended September 30,
 
Change from
 
 
2017
 
2016
 
2016
 
 
(In thousands, except per unit data)
Revenues:
 
 
 
 
 
 
Pipelines:
 
 
 
 
 
 
Affiliates—refined product pipelines
 
$
57,977

 
$
63,801

 
$
(5,824
)
Affiliates—intermediate pipelines
 
20,366

 
20,821

 
(455
)
Affiliates—crude pipelines
 
47,890

 
53,106

 
(5,216
)
 
 
126,233

 
137,728

 
(11,495
)
Third parties—refined product pipelines
 
35,535

 
37,376

 
(1,841
)
 
 
161,768

 
175,104

 
(13,336
)
Terminals, tanks and loading racks:
 
 
 
 
 
 
Affiliates
 
93,573

 
88,825

 
4,748

Third parties
 
12,291

 
12,718

 
(427
)
 
 
105,864

 
101,543

 
4,321

 
 
 
 
 
 
 
Affiliates—refinery processing units
 
57,510

 
12,870

 
44,640

 
 
 
 
 
 
 
Total revenues
 
325,142

 
289,517

 
35,625

Operating costs and expenses:
 
 
 
 
 
 
Operations (exclusive of depreciation and amortization)
 
102,584

 
89,168

 
13,416

Depreciation and amortization
 
57,729

 
51,183

 
6,546

General and administrative
 
8,872

 
8,618

 
254

 
 
169,185

 
148,969

 
20,216

Operating income
 
155,957

 
140,548

 
15,409

Other income (expense):
 
 
 
 
 
 
Equity in earnings of equity method investments
 
10,965

 
10,155

 
810

Interest expense, including amortization
 
(41,359
)
 
(36,258
)
 
(5,101
)
Interest income
 
306

 
332

 
(26
)
Loss on early extinguishment of debt
 
(12,225
)
 
—

 
(12,225
)
Gain on sale of assets
 
317

 
104

 
213

 
 
(41,996
)
 
(25,667
)
 
(16,329
)
Income before income taxes
 
113,961

 
114,881

 
(920
)
State income tax expense
 
(164
)
 
(210
)
 
46

Net income
 
113,797

 
114,671

 
(874
)
Allocation of net loss to Predecessor
 
—

 
10,657

 
(10,657
)
Allocation of net income attributable to noncontrolling interests
 
(4,827
)
 
(8,448
)
 
3,621

Net income attributable to the partners
 
108,970

 
116,880

 
(7,910
)
General partner interest in net income attributable to the partners (1)
 
(35,047
)
 
(40,001
)
 
4,954

Limited partners’ interest in net income
 
$
73,923

 
$
76,879

 
$
(2,956
)
Limited partners’ earnings per unit—basic and diluted (1)
 
$
1.16

 
$
1.29

 
$
(0.13
)
Weighted average limited partners’ units outstanding
 
63,845

 
58,895

 
4,950

EBITDA (2)
 
$
220,141

 
$
200,678

 
$
19,463

Distributable cash flow (3)
 
$
177,436

 
$
160,331

 
$
17,105

 
 
 
 
 
 
 
Volumes (bpd)
 
 
 
 
 
 
Pipelines:
 
 
 
 
 
 
Affiliates—refined product pipelines
 
128,212

 
128,659

 
(447
)
Affiliates—intermediate pipelines
 
136,055

 
138,346

 
(2,291
)
Affiliates—crude pipelines
 
268,736

 
279,014

 
(10,278
)
 
 
533,003

 
546,019

 
(13,016
)
Third parties—refined product pipelines
 
77,114

 
75,405

 
1,709

 
 
610,117

 
621,424

 
(11,307
)
Terminals and loading racks:
 
 
 
 
 

Affiliates
 
420,979

 
404,393

 
16,586

Third parties
 
68,902

 
73,653

 
(4,751
)
 
 
489,881

 
478,046

 
11,835

 
 
 
 
 
 
 
Affiliates—refinery processing units
 
63,858

 
46,423

 
17,435

 
 
 
 
 
 
 
Total for pipelines and terminal and refinery processing unit assets (bpd)
 
1,163,856

 
1,145,893

 
17,963



- 35 -

 
 
September 30,
2017
 
December 31,
2016
 
 
(In thousands)
Balance Sheet Data
 
 
 
 
Cash and cash equivalents
 
$
7,476

 
$
3,657

Working capital (deficit)
 
$
5,378

 
$
(7,782
)
Total assets
 
$
1,865,842

 
$
1,884,237

Long-term debt
 
$
1,245,066

 
$
1,243,912

Partners’ equity (5)
 
$
370,715

 
$
378,234


(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 includes incentive distributions that are 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.

On October 31, 2017, we closed the restructuring transaction set forth in the definitive agreement with HEP Logistics Holdings, L.P. (“HEP Logistics”), a wholly-owned subsidiary of HollyFrontier Corporation and the general partner of HEP, pursuant to which the incentive distribution rights held by HEP Logistics are canceled, and HEP Logistics' 2% general partner interest in HEP is converted into a non-economic general partner interest in HEP. In consideration, HEP issued 37,250,000 of its common units to HEP Logistics. Since this transaction closed prior to the record date for distributions related to third quarter earnings, for purposes of distributions declared, we did not include any incentive or regular distributions on the general partner interest for the third quarter of 2017.

(2)
Earnings before interest, taxes, depreciation and amortization (“EBITDA”) is calculated as net income attributable to the partners plus (i) interest expense and loss on early extinguishment of debt, net of interest income, (ii) state income tax and (iii) depreciation and amortization, excluding amounts related to the Predecessor. EBITDA is not a calculation based upon generally accepted accounting principles (“GAAP”). However, the amounts included in the EBITDA calculation are derived from amounts included in our consolidated financial statements. EBITDA should not be considered as an alternative to net income attributable to the partners or operating income, as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity. EBITDA is not necessarily comparable to similarly titled measures of other companies. EBITDA is presented here because it is a widely used financial indicator used by investors and analysts to measure performance. EBITDA is also used by our management for internal analysis and as a basis for compliance with financial covenants. Set forth below is our calculation of EBITDA.

 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 
2017
 
2016
 
2017
 
2016
 
 
(In thousands)
Net income attributable to the partners
 
$
42,071

 
$
34,785

 
$
108,970

 
$
116,880

Add (subtract):
 
 
 
 
 
 
 
 
Interest expense
 
13,291

 
13,529

 
39,042

 
33,964

Interest income
 
(101
)
 
(108
)
 
(306
)
 
(332
)
Amortization of discount and deferred debt issuance costs
 
781

 
918

 
2,317

 
2,294

Loss on early extinguishment of debt
 
—

 
—

 
12,225

 
—

State income tax expense
 
(69
)
 
61

 
164

 
210

Depreciation and amortization
 
19,007

 
18,920

 
57,729

 
51,183

Predecessor depreciation and amortization
 
—

 
(3,400
)
 
—

 
(3,521
)
EBITDA
 
$
74,980

 
$
64,705

 
$
220,141

 
$
200,678


(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 exceptions of maintenance capital expenditures. Distributable cash flow should not be considered in isolation or as an alternative to net income or operating income as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity. Distributable cash flow is not necessarily comparable to similarly titled measures of other companies. Distributable cash flow is presented here because it is a widely accepted financial indicator used by investors to compare partnership performance. It is also used by management for internal analysis and for our performance units. We believe

- 36 -

that this measure provides investors an enhanced perspective of the operating performance of our assets and the cash our business is generating. Set forth below is our calculation of distributable cash flow.
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 
2017
 
2016
 
2017
 
2016
 
 
(In thousands)
Net income attributable to the partners
 
$
42,071

 
$
34,785

 
$
108,970

 
$
116,880

Add (subtract):
 
 
 
 
 
 
 
 
Depreciation and amortization
 
19,007

 
18,920

 
57,729

 
51,183

Amortization of discount and deferred debt issuance costs
 
781

 
918

 
2,317

 
2,294

Loss on early extinguishment of debt
 
—

 
—

 
12,225

 
—

Increase (decrease) in deferred revenue related to minimum revenue commitments
 
1,134

 
1,748

 
3,835

 
(179
)
Maintenance capital expenditures (4)
 
(3,240
)
 
(3,475
)
 
(6,308
)
 
(7,797
)
Decrease in environmental liability
 
(180
)
 
(277
)
 
(741
)
 
(719
)
Decrease in reimbursable deferred revenue
 
(917
)
 
(750
)
 
(2,765
)
 
(1,906
)
Other non-cash adjustments
 
592

 
788

 
2,174

 
4,096

Predecessor depreciation and amortization
 
—

 
(3,400
)
 
—

 
(3,521
)
Distributable cash flow
 
$
59,248

 
$
49,257

 
$
177,436

 
$
160,331


(4)
Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and to extend their useful lives. Maintenance capital expenditures include expenditures required to maintain equipment reliability, tankage and pipeline integrity, safety and to address environmental regulations.

(5)
As a master limited partnership, we distribute our available cash, which historically has exceeded our net income attributable to the partners because depreciation and amortization expense represents a non-cash charge against income. The result is a decline in partners’ equity since our regular quarterly distributions have exceeded our quarterly net income attributable to the partners. Additionally, if the assets contributed and acquired from HFC while we were a consolidated VIE of HFC had been acquired from third parties, our acquisition cost in excess of HFC’s basis in the transferred assets would have been recorded in our financial statements as increases to our properties and equipment and intangible assets at the time of acquisition instead of decreases to partners’ equity.


Results of Operations—Three Months Ended September 30, 2017 Compared with Three Months Ended September 30, 2016

Summary
Net income attributable to the partners for the third quarter was $42.1 million ($0.66 per basic and diluted limited partner unit) compared to $34.8 million ($0.33 per basic and diluted limited partner unit) for the third quarter of 2016. The increase in earnings is primarily due to increased operating income from our Woods Cross refinery processing units of $8.9 million and increased earnings from our equity method investments of $1.3 million.

Our major shippers are obligated to make deficiency payments to us if they do not exceed their minimum volume shipping obligations. Revenues for the three months ended September 30, 2017, include the recognition of $0.7 million of prior shortfalls billed to shippers in 2016 compared to revenues for the three months ended September 30, 2016, which included the recognition of $0.2 million of prior shortfalls billed to shippers in 2015. Additional net shortfall billings of $2.0 million associated with certain guaranteed shipping contracts were deferred during the three months ended September 30, 2017. Such deferred revenue will be recognized in earnings either as (a) payment for shipments in excess of guaranteed levels, if and to the extent the pipeline system will have the necessary capacity for shipments in excess of guaranteed levels, or (b) when shipping rights expire unused over the contractual make-up period.

Revenues
Revenues for the quarter were $110.4 million, an increase of $17.8 million compared to the third quarter of 2016 primarily due to revenues of $16.6 million from the Woods Cross refinery processing units acquired in the fourth quarter of 2016. Overall pipeline volumes were up 4% compared to the three months ended September 30, 2016, largely due to an increase in both refined product and intermediate pipeline shipments associated with higher production at HFC’s Navajo refinery.

- 37 -


Revenues from our refined product pipelines were $32.2 million, an increase of $1.7 million compared to the third quarter of 2016, and shipments averaged 217.3 mbpd compared to 201.5 mbpd for the third quarter of 2016. Revenues and volumes both increased primarily due to higher shipments on our New Mexico refined product pipelines, in line with increased production at HFC's Navajo refinery.
Revenues from our intermediate pipelines were $7.8 million, an increase of $1.2 million, on shipments averaging 151.6 mbpd compared to 142.4 mbpd for the third quarter of 2016. These volume increases were principally due to increased shipments on our New Mexico intermediate pipelines in line with increased production at HFC's Navajo refinery.
Revenues from our crude pipelines were $14.1 million, a decrease of $2.9 million, on shipments averaging 267.9 mbpd compared to 271.3 mbpd for the third quarter of 2016. This revenue decrease is attributable to a $2.9 million one-time reduction in revenue associated with our crude gathering pipelines. This adjustment will have no material impact on revenues going forward.

Revenues from terminal, tankage and loading rack fees were $35.7 million, an increase of $1.3 million compared to the third quarter of 2016. Refined products and crude oil terminalled in the facilities averaged 495.5 mbpd compared to 505.8 mbpd for the third quarter of 2016. The revenue increases are mainly due to increased reimbursable revenue for projects managed by HEP and reimbursed by HFC.

Revenues from refinery processing units were $20.6 million, an increase of $16.4 million on throughputs averaging 61.5 mbpd compared to 46.5 mbpd for the third quarter of 2016. This increase in revenue and volume is primarily due to the Woods Cross refinery processing units acquired in the fourth quarter of 2016.

Operations Expense
Operations (exclusive of depreciation and amortization) expense for the three months ended September 30, 2017, increased by $3.9 million compared to the three months ended September 30, 2016. The increase is mainly due to an increase in maintenance project costs.

Depreciation and Amortization
Depreciation and amortization for the three months ended September 30, 2017, increased by $0.1 million compared to the three months ended September 30, 2016.

General and Administrative
General and administrative costs for the three months ended September 30, 2017, increased by $1.0 million compared to the three months ended September 30, 2016, mainly due to higher legal and consulting costs associated with our agreement, pursuant to which the incentive distribution rights held by HEP Logistics have been canceled and HEP Logistics' 2% general partner interest in HEP was converted into a non-economic general partner interest in HEP.

Equity in Earnings of Equity Method Investments
 
Three Months Ended September 30,
Equity Method Investment
2017
 
2016
 
(in thousands)
SLC Pipeline LLC
$
1,030

 
$
1,283

Frontier Aspen LLC
1,662

 
586

Osage Pipe Line Company, LLC
1,119

 
975

Cheyenne Pipeline LLC
1,261

 
923

Total
$
5,072

 
$
3,767


Interest Expense
Interest expense for the three months ended September 30, 2017, totaled $14.1 million, a decrease of $0.4 million compared to the three months ended September 30, 2016. Our aggregate effective interest rates were 4.5% and 5.3% for the three months ended September 30, 2017 and 2016, respectively.

State Income Tax
We recorded state income tax benefit of $69,000 and expense of $61,000 for the three months ended September 30, 2017 and 2016, respectively. All tax expense is solely attributable to the Texas margin tax.



- 38 -





Results of Operations—Nine Months Ended September 30, 2017 Compared with Nine Months Ended September 30, 2016

Summary
Net income attributable to Holly Energy Partners for the nine months ended September 30, 2017, was $109.0 million compared to $116.9 million for the nine months ended September 30, 2016. The decrease in earnings is primarily due to (a) a charge of $12.2 million related to the early redemption of our previously outstanding $300 million, 6.5% Senior Notes (the “6.5% Senior Notes”), due in 2020, (b) higher interest expense of $5.1 million, and (c) lower refined product pipeline revenues of $7.7 million offset by (d) earnings from our Woods Cross refinery processing units acquired in the fourth quarter of 2016.

Revenues for the nine months ended September 30, 2017, include the recognition of $3.5 million of prior shortfalls billed to shippers in 2016 as they did not exceed their minimum volume commitments within the contractual make-up period. Additional net shortfall billings of $7.1 million associated with certain guaranteed shipping contracts were deferred during the nine months ended September 30, 2017. Such deferred revenue will be recognized in earnings either as (a) payment for shipments in excess of guaranteed levels, if and to the extent the pipeline system will have the necessary capacity for shipments in excess of guaranteed levels, or (b) when shipping rights expire unused over the contractual make-up period.

Revenues
Revenues for the nine months ended September 30, 2017, were $325.1 million, a $35.6 million increase compared to the nine months ended September 30, 2016. The increase is primarily attributable to the $44.1 million of revenue recorded for the Woods Cross refinery processing units acquired in the fourth quarter of 2016, offset by a $9.8 million decrease in revenues around assets serving HFC's Navajo refinery primarily due to the substantial turnaround at the Navajo refinery during the first quarter of 2017. Overall pipeline volumes were down 1.8% compared to the nine months ended September 30, 2016.

Revenues from our refined product pipelines were $93.5 million, a decrease of $7.7 million, on shipments averaging 205.3 mbpd compared to 204.1 mbpd for the nine months ended September 30, 2016. The decrease in revenues is primarily due to lower volumes on product pipelines due to the turnaround at HFC's Navajo refinery in the first quarter of 2017 as well as a higher amount of shortfalls recognized in revenue for the nine months ended September 30, 2016.

Revenues from our intermediate pipelines were $20.4 million, a decrease of $0.5 million, on shipments averaging 136.1 mbpd compared to 138.3 mbpd for the nine months ended September 30, 2016. These volume decreases were primarily due to the turnaround at HFC's Navajo refinery, which was partially offset by increases in production at the Navajo refinery after the turnaround.

Revenues from our crude pipelines were $47.9 million, a decrease of $5.2 million, on shipments averaging 268.7 mbpd compared to 279.0 mbpd for the nine months ended September 30, 2016. Revenues and volumes decreased principally due to HFC's Navajo refinery turnaround in the first quarter of 2017, a decrease in deferred revenue recognized and the one-time adjustment associated with our crude gathering lines made in the third quarter of 2017.

Revenues from terminal, tankage and loading rack fees were $105.9 million, an increase of $4.3 million compared to the nine months ended September 30, 2016. Refined products and crude oil terminalled in the facilities averaged 489.9 mbpd compared to 478.0 mbpd for the nine months ended September 30, 2016. The volume and revenue increases are mainly due to our Tulsa crude tanks acquired on the last day of the first quarter of 2016 offset by the transfer of the El Paso terminal to HollyFrontier in the first quarter of 2016.

Revenues from refinery processing units were $57.5 million, an increase of $44.6 million on throughputs averaging 63.9 mbpd compared to 46.4 mbpd for the nine months ended September 30, 2016. The increases in revenue and volume is primarily due to the Woods Cross refinery processing units acquired in the fourth quarter of 2016.

Operations Expense
Operations expense (exclusive of depreciation and amortization) for the nine months ended September 30, 2017, increased by $13.4 million compared to the nine months ended September 30, 2016. The increase is primarily due to operating expenses for our newly acquired Woods Cross refinery processing units.

- 39 -


Depreciation and Amortization
Depreciation and amortization for the nine months ended September 30, 2017, increased by $6.5 million compared to the nine months ended September 30, 2016. The increase is mainly due to depreciation from the Woods Cross refinery processing units acquired in the fourth quarter of 2016.

General and Administrative
General and administrative costs for the nine months ended September 30, 2017, increased $0.3 million compared to the nine months ended September 30, 2016, mainly due to higher legal and consulting costs offset by decreased employee compensation.

Equity in Earnings of Equity Method Investments
In the first quarter of 2017, the SLC Pipeline was proactively shut down for a period of 28 days due to land movement along the right-of-way at Mountain Green, Utah. This not only impacted shipments of crude on the SLC Pipeline, but also crude shipments on the connected Frontier Pipeline. This shutdown is primarily responsible for the decrease in SLC Pipeline LLC earnings.
 
Nine Months Ended September 30,
Equity Method Investments
2017
 
2016
 
(in thousands)
SLC Pipeline LLC
$
2,053

 
$
3,397

Frontier Aspen, LLC
3,813

 
3,049

Osage Pipe Line Company, LLC
1,889

 
2,423

Cheyenne Pipeline LLC
3,210

 
1,286

Total
$
10,965

 
$
10,155


Interest Expense
Interest expense for the nine months ended September 30, 2017, totaled $41.4 million, an increase of $5.1 million compared to the nine months ended September 30, 2016. The increase is primarily due to the $400 million 6% Senior Notes issued July 19, 2016, and a higher average balance outstanding on the Credit Agreement. Our aggregate effective interest rates were 4.4% and 4.6% for the nine months ended September 30, 2017 and 2016, respectively.

Loss on Early Extinguishment of Debt
A loss on early extinguishment of debt of $12.2 million was recognized upon redemption of our $300 million aggregate principal amount of 6.5% Senior Notes at a cost of $309.8 million on January 4, 2017. The loss related to the premium paid to noteholders upon their tender of an aggregate principal amount of $300 million and related financing costs that were previously deferred.

State Income Tax
We recorded state income tax expense of $164,000 and $210,000 for the nine months ended September 30, 2017 and 2016, respectively. All 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 nine months ended September 30, 2017, we received advances totaling $628 million and repaid $431 million, resulting in a net increase of $197 million under the Credit Agreement and an outstanding balance of $750 million at September 30, 2017. We have no letters of credit outstanding under the Credit Agreement at September 30, 2017, and the available capacity under the Credit Agreement is $650 million at September 30, 2017. Amounts repaid under our credit facility may be reborrowed from time to time.
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

- 40 -

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 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.

On January 4, 2017, we redeemed the $300 million aggregate principal amount of 6.5% Senior Notes at a redemption cost of $309.8 million at which time we recognized a $12.2 million early extinguishment loss consisting of a $9.8 million debt redemption premium and unamortized discount and financing costs of $2.4 million. We funded the redemption with borrowings under our Credit Agreement.

We have a continuous offering program under which we may issue and sell common units from time to time, representing limited partner interests, up to an aggregate gross sales amount of $200 million. For the nine months ended September 30, 2017, HEP issued 1,538,452 units under this program, providing approximately $52.3 million in net proceeds. We intend to use the net proceeds for general partnership purposes, which may include funding working capital, repayment of debt, acquisitions and capital expenditures. As of September 30, 2017, HEP has issued 2,241,907 units under this program, providing $77.1 million in gross proceeds.

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 and August, we paid regular quarterly cash distributions of $0.6075, $0.6200 and $0.6325, respectively, on all units in an aggregate amount of $171.6 million including $49.7 million of incentive distribution payments to our general partner.

Cash and cash equivalents increased by $3.8 million during the nine months ended September 30, 2017. The cash flows provided by operating activities of $177.5 million were greater than the cash flows used for financing activities of $145.0 million and investing activities of $28.7 million. Working capital increased by $13.2 million to $5.4 million at September 30, 2017, from a negative $7.8 million at December 31, 2016.

Cash Flows—Operating Activities
Cash flows from operating activities decreased by $0.5 million from $178.0 million for the nine months ended September 30, 2016, to $177.5 million for the nine months ended September 30, 2017.

Cash Flows—Investing Activities
Cash flows used for investing activities were $28.7 million for the nine months ended September 30, 2017, compared to $137.1 million for the nine months ended September 30, 2016, a decrease of $108.5 million. During the nine months ended September 30, 2017 and 2016, we invested $30.7 million and $48.2 million in additions to properties and equipment, respectively. During the nine months ended September 30, 2017 and 2016, we also received $1.2 million and $1.7 million for distributions in excess of equity in earnings of equity investments, respectively. Additionally, we have retrospectively adjusted our historical financial results for the nine months ended September 30, 2016, to include the Woods Cross refinery processing units as we are under common control of HFC. Therefore, the cash flows from investing activities reflect outflows of $47.9 million for the Woods Cross refinery processing units and $42.6 million for the purchase of a 50% interest in the Cheyenne Pipeline during the nine months ended September 30, 2016.

- 41 -


Cash Flows—Financing Activities
Cash flows used for financing activities were $145.0 million for the nine months ended September 30, 2017, compared to $48.7 million for the nine months ended September 30, 2016, an increase of $96.3 million. During the nine months ended September 30, 2017, we received $628.0 million and repaid $431.0 million in advances under the Credit Agreement. We redeemed our 6.5% Senior Notes at a redemption cost of $309.8 million. We also received net proceeds of $101.8 million from the issuance of our additional 6% Senior Notes and $52.3 million from the issuance of common units under our continuous offering program. Additionally, we paid $171.6 million in regular quarterly cash distributions to our general and limited partners and $5.0 million to our noncontrolling interest. During the nine months ended September 30, 2016, we paid $39.5 million for the crude oil tanks located at HFC’s Tulsa refinery acquired in March 2016. We received $310.5 million and repaid $642.5 million in advances under the Credit Agreement. We paid $138.8 million in regular quarterly cash distributions to our general and limited partners, distributed $3.8 million to our noncontrolling interest, and paid $3.9 million in deferred financing charges to amend our credit agreement. We also received net proceeds of $394 million from the issuance of our 6% Senior Notes and $22.8 million from the issuance of common units under our continuous offering program. In addition, we received $55.0 million for Woods Cross processing units expenditures from HFC.

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. We are forecasting to spend $9 million for maintenance capital expenditures and approximately $37 million for expansion capital expenditures in 2017. We expect the majority of the expansion capital budget to be invested in refined product pipeline expansions, crude system enhancements, new storage tanks, and enhanced blending capabilities at our racks. 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 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.


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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.

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 outstanding at any time without penalty, except for tranche breakage costs.  If an event of default exists under the Credit Agreement, the lenders will be able to accelerate the maturity of all loans outstanding and exercise other rights and remedies.  We were in compliance with the covenants as of September 30, 2017.

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 consisting of a $9.8 million debt redemption premium and unamortized discount and financing costs of $2.4 million. We funded the redemption with borrowings under our Credit Agreement.

We have $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 revolving credit agreement.

The 6% Senior Notes are unsecured and impose certain restrictive covenants, including limitations on our ability to incur additional indebtedness, make investments, sell assets, incur certain liens, pay distributions, enter into transactions with affiliates, and enter into mergers. We were in compliance with the restrictive covenants for the 6% Senior Notes as of September 30, 2017. At any time when the 6% Senior Notes are rated investment grade by both Moody’s and Standard & Poor’s and no default or event of default exists, we will not be subject to many of the foregoing covenants. Additionally, we have certain redemption rights at varying premiums over face value under the 6% Senior Notes.

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

Long-term Debt
The carrying amounts of our long-term debt are as follows:
 
 
September 30,
2017
 
December 31,
2016
 
 
(In thousands)
Credit Agreement
 
$
750,000

 
$
553,000

 
 
 
 
 
6% Senior Notes
 
 
 
 
Principal
 
500,000

 
400,000

Unamortized debt issuance costs
 
(4,934
)
 
(6,607
)
 
 
495,066

 
393,393

6.5% Senior Notes
 
 
 
 
Principal
 
—

 
300,000

Unamortized discount and debt issuance costs
 
—

 
(2,481
)
 
 
—

 
297,519

 
 
 
 
 
Total long-term debt
 
$
1,245,066

 
$
1,243,912


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


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Contractual Obligations
There were no significant changes to our long-term contractual obligations during this period.

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 nine months ended September 30, 2017 and 2016. Historically, the PPI has increased an average of 0.2% annually over the past five calendar years, including a decrease of 1.0% in 2016.

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. We believe our operations are in substantial compliance with applicable environmental laws and regulations. However, these laws and regulations, and the interpretation or enforcement thereof, are subject to frequent change by regulatory authorities, and we are unable to predict the ongoing cost to us of complying with these laws and regulations or the future impact of these laws and regulations on our operations. Violation of environmental laws, regulations, and permits can result in the imposition of significant administrative, civil and criminal penalties, injunctions, and construction bans or delays. A major discharge of hydrocarbons or hazardous substances into the environment could, to the extent the event is not insured, subject us to substantial expense, including both the cost to comply with applicable laws and regulations and claims made by employees, neighboring landowners and other third parties for personal injury and property damage.

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

There are environmental remediation projects in progress that relate to certain assets acquired from HFC. Certain of these projects were underway prior to our purchase and represent liabilities retained by HFC. At September 30, 2017, we have an accrual of $6.4 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 or will expire. The remaining projects, including assessment and monitoring activities, are covered under the HFC environmental indemnification discussed above and represent liabilities of HFC.


CRITICAL ACCOUNTING POLICIES

Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities as of the date of the financial statements. Actual results may differ from these estimates under different assumptions or conditions. Our significant accounting policies are described in “Item 7. Management’s Discussion and Analysis of Financial Condition and Operations—Critical Accounting Policies” in our Annual Report on Form 10-K for the year ended December 31, 2016. Certain critical accounting policies that materially affect the amounts recorded in our consolidated financial statements include revenue recognition, assessing the possible impairment of certain long-lived assets and goodwill, and assessing contingent liabilities for probable losses. There have been no changes to these policies in 2017. We consider these 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.


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Accounting Pronouncements Adopted During the Periods Presented

Earnings Per Unit
In April 2015, an accounting standard update was issued requiring changes to the allocation of the earnings or losses of a transferred business for periods before the date of a dropdown of net assets accounted for as a common control transaction entirely to the general partner for purposes of calculating historical earnings per unit. We adopted this standard as of January 1, 2016. In connection with the dropdown of assets from HFC’s Tulsa refinery on March 31, 2016, and the purchase of HFC’s Woods Cross refinery units on October 1, 2016, we reduced net income by $7.5 million and $10.7 million for the three and nine months ended September 30, 2016, respectively. These reductions had no impact on the historical earnings per unit as they were allocated to the general partner.

Share-Based Compensation
In March 2016, an accounting standard update was issued which simplifies the accounting for employee share-based payment transactions, including the accounting for income taxes, forfeitures and statutory tax withholding requirements, as well as classification in the statement of cash flows. We adopted this standard effective January 1, 2017, with no impact to our financial condition, results of operations and cash flows. As permitted by the standard, we continue to account for forfeitures on an estimated basis.

Accounting Pronouncements Not Yet Adopted

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 has an effective date of January 1, 2018, and we intend to account for the new guidance using the modified retrospective implementation method, whereby a cumulative effect adjustment is recorded to retained earnings as of the date of initial application. Our preparation for adoption of this standard is in progress, and we are currently evaluating terms, conditions and our performance obligations of our existing contracts with customers. We are evaluating the effect of this standard on our revenue recognition policies and whether it will have a material impact on our financial condition or results of operations.

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 has an effective date of January 1, 2018, and we are evaluating its impact.

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 will become effective beginning with our 2018 reporting year. We are evaluating the impact of this standard.

Leases
In February 2016, an accounting standard update was issued requiring leases to be measured and recognized as a lease liability, with a corresponding right-of-use asset on the balance sheet. This standard has an effective date of January 1, 2019, and we are evaluating the impact of this standard.


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 advances matured on July 31, 2017. The swaps had effectively converted $150 million of our LIBOR based debt to fixed rate debt.

We review publicly available information on our counterparties in order to monitor their financial stability and assess their ongoing ability to honor their commitments under the interest rate swap contracts. These counterparties are large financial institutions. Furthermore, we have not experienced, nor do we expect to experience, any difficulty in the counterparties honoring their respective commitments.

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 September 30, 2017, 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 September 30, 2017, the fair value of our 6% Senior Notes was $524.4 million. We estimate a hypothetical 10% change in the yield-to-maturity applicable to the 6% Senior Notes at September 30, 2017, would result in a change of approximately $15 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 September 30, 2017, borrowings outstanding under the Credit Agreement were $750 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.


Item 3.
Quantitative and Qualitative Disclosures About Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. See “Risk Management” under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a discussion of market risk exposures that we have with respect to our long-term debt, which disclosure should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our Annual Report on Form 10-K for the fiscal year ended December 31, 2016. We utilize derivative instruments to hedge our interest rate exposure, as discussed under “Risk Management.”

Since we do not own products shipped on our pipelines or terminalled at our terminal facilities, we do not have direct market risks associated with commodity prices.


Item 4.
Controls and Procedures

(a) Evaluation of disclosure controls and procedures
Our principal executive officer and principal financial officer have evaluated, as required by Rule 13a-15(b) under the Securities Exchange Act of 1934 (the “Exchange Act”), our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this quarterly report on Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information we are required to disclose in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of September 30, 2017, at a reasonable level of assurance.

(b) Changes in internal control over financial reporting
There have been no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during our last fiscal quarter that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1.
Legal Proceedings

We are a party to various legal and regulatory proceedings, which we believe will not have a material adverse impact on our financial condition, results of operations or cash flows.
 

Item 1A.
Risk Factors

There have been no material changes in our risk factors as previously disclosed in Part 1, “Item 1A. Risk Factors” of our Annual Report on Form 10-K for the fiscal year ended December 31, 2016. In addition to the other information set forth in this quarterly report, you should consider carefully the factors discussed in our 2016 Form 10-K, which could materially affect our business, financial condition or future results. The risks described in our 2016 Form 10-K are not the only risks we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may also materially and adversely affect our business, financial condition or future results.


Item 6.
Exhibits

The Exhibit Index on page 49 of this Quarterly Report on Form 10-Q lists the exhibits that are filed or furnished, as applicable, as part of the Quarterly Report on Form 10-Q.


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Exhibit Index
Exhibit
Number
 
Description
 
 
 
2.1
 

2.2
 
2.3*
 

2.4
 
3.1
 
3.2
 
3.3
 
3.4
 
3.5
 
3.6
 
3.7
 
3.8
 
3.9
 
3.10
 
3.11
 
3.12
 
4.1
 
10.1*
 


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10.2
 

10.3
 
10.4
 

31.1*
 
31.2*
 
32.1**
 
32.2**
 
101++
 
The following financial information from Holly Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2017, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Income, (iii) Consolidated Statements of Comprehensive Income, (iv) Consolidated Statements of Cash Flows, (v) Consolidated Statement of Partners’ Equity, and (vi) Notes to Consolidated Financial Statements.


*
Filed herewith.
 **
Furnished herewith.
 ++
Filed electronically herewith.

HOLLY ENERGY PARTNERS, L.P.
SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
 
HOLLY ENERGY PARTNERS, L.P.
 
(Registrant)
 
 
 
 
 
By: HEP LOGISTICS HOLDINGS, L.P.
its General Partner
 
 
 
 
 
By: HOLLY LOGISTIC SERVICES, L.L.C.
its General Partner
 
 
 
Date: November 2, 2017
 
/s/    Richard L. Voliva III
 
 
Richard L. Voliva III
 
 
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)
 
 
 
Date: November 2, 2017
 
/s/    Kenneth P. Norwood
 
 
Kenneth P. Norwood
 
 
Vice President and Controller
(Principal Accounting Officer)
 


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