HOLLY ENERGY PARTNERS LP - Quarter Report: 2013 September (Form 10-Q)

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, 2013



¨	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, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.



Large accelerated filer	ý	Accelerated filer	¨	Non-accelerated filer	¨	Smaller reporting company	¨

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 25, 2013 was 58,657,048.

Table of Contentsril 19,

HOLLY ENERGY PARTNERS, L.P.

INDEX





	FORWARD-LOOKING STATEMENTS		3

PART I. FINANCIAL INFORMATION			4

	Item 1.	Financial Statements (Unaudited)	4

		Consolidated Balance Sheets	4

		Consolidated Statements of Income	5

		Consolidated Statements of Comprehensive Income	6

		Consolidated Statements of Cash Flows	7

		Consolidated Statements of Partners’ Equity	8

		Notes to Consolidated Financial Statements	9

	Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	26

	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	40

	Item 4.	Controls and Procedures	40

PART II. OTHER INFORMATION			41

	Item 1.	Legal Proceedings	41

	Item 1A.	Risk Factors	41

	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	41

	Item 6.	Exhibits	41

		SIGNATURES	42

		Index to Exhibits	43

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Table of Contentsril 19,

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 additional operations in the future successfully;


•	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;


•	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, 2012 in “Risk Factors” and in this Form 10-Q in “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” 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.

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Table of Contentsril 19,

PART I. FINANCIAL INFORMATION


Item 1.	Financial Statements

HOLLY ENERGY PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(Unaudited)



	September 30, 2013			December 31, 2012
	(In thousands, except unit data)
ASSETS
Current assets:
Cash and cash equivalents	$	11,220		$	5,237
Accounts receivable:
Trade	5,185			7,126
Affiliates	30,691			31,594
	35,876			38,720
Prepaid and other current assets	4,339			3,619
Total current assets	51,435			47,576

Properties and equipment, net	950,564			960,535
Transportation agreements, net	89,386			94,596
Goodwill	256,498			256,498
Investment in SLC Pipeline	24,966			25,041
Other assets	9,523			9,864
Total assets	$	1,382,372		$	1,394,110

LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	8,839		$	7,045
Affiliates	4,162			4,985
	13,001			12,030

Accrued interest	2,280			10,226
Deferred revenue	12,427			8,901
Accrued property taxes	5,209			2,688
Other current liabilities	2,408			1,905
Total current liabilities	35,325			35,750

Long-term debt	809,391			864,674
Other long-term liabilities	13,639			15,433
Deferred revenue	19,835			11,494

Class B unit	18,528			13,903

Equity:
Partners’ equity:
Common unitholders (58,657,048 and 56,782,048 units issued and outstanding at September 30, 2013 and December 31, 2012, respectively)	534,076			502,809
General partner interest (2% interest)	(146,014		)	(145,877		)
Accumulated other comprehensive loss	(552		)	(4,279		)
Total partners’ equity	387,510			352,653
Noncontrolling interest	98,144			100,203
Total equity	485,654			452,856
Total liabilities and equity	$	1,382,372		$	1,394,110

See accompanying notes.

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Table of Contentsril 19,

HOLLY ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012 ⁽¹⁾			2013			2012 ⁽¹⁾
	(In thousands, except per unit data)
Revenues:
Affiliates	$	65,523		$	62,115		$	190,222		$	176,420
Third parties	12,200			11,939			37,084			34,709
	77,723			74,054			227,306			211,129
Operating costs and expenses:
Operations	21,686			22,732			72,089			65,114
Depreciation and amortization	19,449			14,351			48,730			42,801
General and administrative	2,415			1,399			8,747			5,925
	43,550			38,482			129,566			113,840
Operating income	34,173			35,572			97,740			97,289

Other income (expense):
Equity in earnings of SLC Pipeline	835			877			2,238			2,502
Interest expense	(11,816		)	(12,540		)	(35,929		)	(34,269		)
Interest income	3			—			110			—
Other income	61			—			61			—
Loss on early extinguishment of debt	—			—			—			(2,979		)
Gain (loss) on sale of assets	(159		)	—			1,863			—
	(11,076		)	(11,663		)	(31,657		)	(34,746		)
Income before income taxes	23,097			23,909			66,083			62,543
State income tax expense	(40		)	(137		)	(440		)	(287		)
Net income	23,057			23,772			65,643			62,256
Allocation of net loss attributable to Predecessor	—			146			—			4,199
Allocation of net loss (income) attributable to noncontrolling interests	(1,172		)	(582		)	(5,192		)	658
Net income attributable to Holly Energy Partners	21,885			23,336			60,451			67,113
General partner interest in net income, including incentive distributions	(7,128		)	(5,276		)	(20,038		)	(16,674		)
Limited partners’ interest in net income	$	14,757		$	18,060		$	40,413		$	50,439
Limited partners’ per unit interest in earnings—basic and diluted	$	0.25		$	0.32		$	0.69		$	0.91
Weighted average limited partners’ units outstanding	58,657			56,536			58,108			55,332

⁽¹⁾ Restated as described in Note 1.

See accompanying notes.

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HOLLY ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012 ⁽¹⁾			2013			2012 ⁽¹⁾
	(In thousands)
Net income	$	23,057		$	23,772		$	65,643		$	62,256
Allocation of net loss attributable to Predecessor	—			146			—			4,199
Net income before noncontrolling interests	23,057			23,918			65,643			66,455

Other comprehensive income (loss):
Change in fair value of cash flow hedge	(1,097		)	(1,381		)	2,878			(3,243		)
Amortization of unrealized loss attributable to discontinued cash flow hedge	—			1,274			849			3,821
Other comprehensive income (loss)	(1,097		)	(107		)	3,727			578
Comprehensive income before noncontrolling interest	21,960			23,811			69,370			67,033
Allocation of comprehensive (income) loss to noncontrolling interests	(1,172		)	(582		)	(5,192		)	658
Comprehensive income attributable to Holly Energy Partners	$	20,788		$	23,229		$	64,178		$	67,691

⁽¹⁾ Restated as described in Note 1.

See accompanying notes.

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Table of Contentsril 19,

HOLLY ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Nine Months Ended September 30,
	2013			2012 ⁽¹⁾
	(In thousands)
Cash flows from operating activities
Net income	$	65,643		$	62,256
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	48,730			42,801
Gain on sale of assets	(1,863		)	—
Amortization of deferred charges	2,440			5,752
Equity in earnings of SLC Pipeline, net of distributions	75			123
Amortization of restricted and performance units	2,642			2,233
(Increase) decrease in operating assets:
Accounts receivable—trade	2,191			(3,397		)
Accounts receivable—affiliates	903			(1,240		)
Prepaid and other current assets	(720		)	(584		)
Increase (decrease) in operating liabilities:
Accounts payable—trade	821			(7,097		)
Accounts payable—affiliates	(501		)	(833		)
Accrued interest	(7,946		)	(5,774		)
Deferred revenue	11,867			9,809
Accrued property taxes	2,521			2,845
Other current liabilities	519			711
Other, net	366			283
Net cash provided by operating activities	127,688			107,888

Cash flows from investing activities
Additions to properties and equipment	(33,539		)	(36,648		)
Proceeds from sale of assets	2,481			—
Net cash used for investing activities	(31,058		)	(36,648		)

Cash flows from financing activities
Borrowings under credit agreement	256,500			523,000
Repayments of credit agreement borrowings	(312,500		)	(292,000		)
Proceeds from issuance of senior notes	—			294,750
Proceeds from issuance of common units	73,444			—
Cash distribution to HFC for UNEV Acquisition	—			(260,922		)
Repayment of notes	—			(257,900		)
Contribution from general partner	1,499			—
Contributions from UNEV joint venture partners	—			16,748
Distributions to HEP unitholders	(103,016		)	(91,063		)
Distributions to noncontrolling interest	(2,625		)	—
Purchase of units for incentive grants	(3,700		)	(4,919		)
Deferred financing costs	—			(3,222		)
Other	(249		)	(88		)
Net cash used by financing activities	(90,647		)	(75,616		)

Cash and cash equivalents
Increase (decrease) for the period	5,983			(4,376		)
Beginning of period	5,237			6,369
End of period	$	11,220		$	1,993

⁽¹⁾ Restated as described in Note 1.

See accompanying notes.

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Table of Contentsril 19,

HOLLY ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF PARTNERS' EQUITY

(Unaudited)



	Common Units			General Partner Interest			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interest			Total Equity
	(In thousands)

Balance at December 31, 2012	$	502,809		$	(145,877	)	$	(4,279	)	$	100,203		$	452,856
Issuance of common units	73,444			—			—			—			73,444
Capital contribution	—			1,499			—			—			1,499
Net income	46,493			18,584			—			566			65,643
Other comprehensive income	—			—			3,727			—			3,727
Distributions to HEP unitholders	(83,151		)	(19,865		)	—			—			(103,016		)
Distributions to UNEV joint venture partners	—			—			—			(2,625		)	(2,625		)
Purchase of units for restricted grants	(3,379		)	—			—			—			(3,379		)
Amortization of restricted and performance units	2,642			—			—			—			2,642
Class B unit accretion	(4,533		)	(92		)	—			—			(4,625		)
Other	(249		)	(263		)	—			—			(512		)
Balance September 30, 2013	$	534,076		$	(146,014	)	$	(552	)	$	98,144		$	485,654

See accompanying notes.

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Table of Contentsril 19,

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 39% owned (including the 2% general partner interest) by HollyFrontier Corporation (“HFC”) and its subsidiaries. In these consolidated financial statements, the words “we,” “our,” “ours” and “us” refer to HEP unless the context otherwise indicates.

We own and operate petroleum product and crude oil pipelines and terminal, tankage and loading rack facilities that support HFC’s refining and marketing operations in the Mid-Continent, Southwest and Rocky Mountain regions of the United States and Alon USA, Inc.’s (“Alon”) refinery in Big Spring, Texas. Additionally, we own a 75% interest in UNEV Pipeline, LLC (“UNEV”), which owns a 400-mile, 12-inch refined products pipeline running from Woods Cross, Utah to Las Vegas, Nevada (the “UNEV Pipeline”), product terminals near Cedar City, Utah and Las Vegas, Nevada and related assets, and a 25% interest in SLC Pipeline LLC, which owns a 95-mile intrastate crude oil pipeline system (the “SLC Pipeline”) that serves refineries in the Salt Lake City, Utah area.

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 and providing other services at our storage tanks and terminals. 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.

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 Form 10-K for the year ended December 31, 2012. 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, 2013.

On January 16, 2013, a two-for-one unit split was paid in the form of a common unit distribution for each issued and outstanding common unit to all unitholders of record on January 7, 2013. All references to unit and per unit amounts in this document and related disclosures have been adjusted to reflect the effect of the unit split.

In March 2013, we closed on a public offering of 1,875,000 of our common units. Additionally, an affiliate of HFC, as a selling unitholder, closed on a public sale of 1,875,000 of its HEP common units. We used our net proceeds of $73.4 million to repay indebtedness incurred under our credit facility and for general partnership purposes. Amounts repaid under our credit facility may be reborrowed from time to time, and we intend to reborrow certain amounts to fund capital expenditures.

The financial information for the three and nine months ended September 30, 2012 included in the accompanying financial statements and notes thereto were revised from the amounts previously reported for those periods due to revisions made in order to correct certain immaterial items in previously reported amounts. These revisions reduced net income attributable to Holly Energy Partners for the three and nine months ended September 30, 2012 by $1.2 million and $2.5 million, respectively, and reduced the limited partners' per unit interest in net earnings - basic and diluted by $0.02 and $0.05, respectively, and were comprised principally of an adjustment of depreciation expense related to an abandonment of certain property and equipment. For more information about these revisions, see the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2012.

New Accounting Pronouncements

Presentation of Comprehensive Income

Effective January 1, 2013, we adopted the accounting standard update that requires the disclosure of significant amounts reclassified out of accumulated other comprehensive income by component either on the face of the financial statements or in the notes. The adoption of this accounting standard did not have an impact on our financial condition, results of operations or cash flows.

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HOLLY ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) Continued


Note 2:	Acquisitions

UNEV Pipeline Interest Acquisition

On July 12, 2012, we acquired HFC's 75% interest in UNEV. We paid consideration consisting of $260.0 million in cash and 2,059,800 of our common units. We paid an additional $0.9 million to HFC for a post-closing working capital adjustment. Also under the terms of the transaction, 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, 2016 and ending in June 2032, subject to certain limitations. Such contingent redemption payments are limited to a maximum payment amount calculated as described below. However, to the extent earnings thresholds are not achieved, no redemption payments are required. Contemporaneously with this transaction, HFC (our general partner) agreed to forego its right to incentive distributions of up to $1.25 million per quarter over twelve consecutive quarterly periods following the closing of the transaction and up to an additional four quarters in certain circumstances. The Class B unit increases with each foregone incentive distribution as described above and by a 7% factor compounded annually on the outstanding unredeemed balance through its expiration date. At our option, we may redeem, in whole or in part, the Class B unit at the current unredeemed value based on the calculation described. The Class B unit had a value of $13.9 million at December 31, 2012 and $18.5 million at September 30, 2013.

Noncontrolling interests reported in the consolidated statements of income include the minority partner's 25% interest in UNEV and income attributable to the Class B unit representing foregone incentive distribution rights and the 7% accretion factor, which collectively amounted to $1.2 million and $5.2 million for the three and nine months ended September 30, 2013, respectively.

We are a consolidated variable interest entity of HFC. Therefore, this transaction was recorded as a transfer between entities under common control and reflects HFC's carrying basis in UNEV's assets and liabilities. We have retrospectively adjusted our financial position and operating results as if UNEV were a consolidated subsidiary for all periods while we were under common control of HFC. For the three and nine months ended September 30, 2012 our consolidated statement of income includes Predecessor revenues from UNEV of $3.0 million and $10.8 million, respectively, and Predecessor net losses of $2.7 million and $6.7 million, respectively.


Note 3:	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 and 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.

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HOLLY ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) Continued

The carrying amounts and estimated fair values of our senior notes and interest rate swaps were as follows:



		September 30, 2013				December 31, 2012
Financial Instrument	Fair Value Input Level	Carrying Value		Fair Value		Carrying Value		Fair Value
		(In thousands)
Liabilities:
Senior notes:
6.5% senior notes	Level 2	$	295,764	$	307,500	$	295,275	$	321,000
8.25% senior notes	Level 2	148,627		157,875		148,399		163,125
		444,391		465,375		443,674		484,125

Interest rate swaps	Level 2	552		552		3,430		3,430
		$	444,943	$	465,927	$	447,104	$	487,555

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 7 for additional information on these instruments.


Note 4:	Properties and Equipment

The carrying amounts of our properties and equipment are as follows:



	September 30, 2013		December 31, 2012
	(In thousands)
Pipelines, terminals and tankage	$	1,060,689	$	1,049,531
Land and right of way	62,973		63,248
Construction in progress	46,288		27,150
Other	19,140		24,462
	1,189,090		1,164,391
Less accumulated depreciation	238,526		203,856
	$	950,564	$	960,535

We capitalized $0.3 million and $0.2 million in interest related to construction projects during the nine months ended September 30, 2013 and 2012, respectively.

Depreciation expense was $43.2 million and $37.5 million for the nine months ended September 30, 2013 and 2012, respectively. Included in depreciation expense were asset abandonment charges of $5.4 million and $2.9 million for the nine months ended September 30, 2013 and 2012, respectively, for assets permanently removed from service.

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HOLLY ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) Continued


Note 5:	Transportation Agreements

Our transportation agreements represent a portion of the total purchase price of certain assets acquired from Alon in 2005 and from HFC in 2008. 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, 2013		December 31, 2012
	(In thousands)
Alon transportation agreement	$	59,933	$	59,933
HFC transportation agreement	74,231		74,231
	134,164		134,164
Less accumulated amortization	44,778		39,568
	$	89,386	$	94,596

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


Note 6:	Employees, Retirement and Incentive Plans

Employees who provide direct services to us are employed by Holly Logistic Services, L.L.C., an HFC subsidiary. 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 $1.9 million and $1.6 million for the three months ended September 30, 2013 and 2012, respectively, and $5.7 million and $4.7 million for the nine months ended September 30, 2013 and 2012, respectively.

We have an incentive plan (“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 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, 2013, we have two types of incentive-based awards which are described below. The compensation cost charged against income was $0.7 million and $0.5 million for the three months ended September 30, 2013 and 2012, respectively, and $2.6 million and $2.1 million for the nine months ended September 30, 2013 and 2012, 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, 2013, 2,500,000 units were authorized to be granted under our Long-Term Incentive Plan, of which 1,720,547 have not yet been granted, assuming no forfeitures of the unvested units and full achievement of goals for the performance units already granted.

Restricted Units

Under our Long-Term Incentive Plan, we grant restricted units to selected employees and non-employee directors 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 over the vesting period.

- 12 -

HOLLY ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) Continued

A summary of restricted unit activity and changes during the nine months ended September 30, 2013 is presented below:



Restricted Units	Units		Weighted- Average Grant-Date Fair Value
Outstanding at January 1, 2013 (nonvested)	58,472		$	31.21
Granted	49,701		40.39
Vesting and transfer of full ownership to recipients	(13,512	)	33.31
Outstanding at September 30, 2013 (nonvested)	94,661		$	35.68

As of September 30, 2013, there was $1.5 million of total unrecognized compensation expense related to nonvested restricted unit grants which is expected to be recognized over a weighted-average period of 1.1 years.

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 based upon the growth in our distributable cash flow per common unit over the performance period, and vest over a period of three years. As of September 30, 2013, estimated unit payouts for outstanding nonvested performance unit awards were at 100% to 140%.

We granted 32,888 target performance units to certain officers in March 2013. These units will vest over a three-year performance period ending December 31, 2015 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 and can range from 0% to 200% of the target number of performance units granted (in the case of our Chief Executive Officer) or from 50% to 150% of the target number of performance units granted (in the case of other officers granted performance units). 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. The fair value of these performance units is based on the grant date closing unit price of $40.86 and will apply to the number of units ultimately awarded.

A summary of performance unit activity and changes during the nine months ended September 30, 2013 is presented below:



Performance Units	Units
Outstanding at January 1, 2013 (nonvested)	54,498
Granted	32,888
Vesting and transfer of common units to recipients	(25,124	)
Outstanding at September 30, 2013 (nonvested)	62,262

The grant-date fair value of performance units vested and transferred to recipients during the nine months ended September 30, 2013 was $0.5 million. As of September 30, 2013, there was $1.2 million of total unrecognized compensation expense related to nonvested performance units, which is expected to be recognized over a weighted-average period of 1.5 years.


Note 7:	Debt

Credit Agreement

We have a $550 million senior secured revolving credit facility expiring in June 2017 (the “Credit Agreement”) that is available to fund capital expenditures, investments, acquisitions, distribution payments and working capital and for general partnership purposes. It is available also to fund letters of credit up to a $50 million sub-limit and to fund distributions to unitholders up to a $60 million sub-limit.

Our obligations under the Credit Agreement are collateralized by substantially all of our assets. Indebtedness under the Credit Agreement is recourse to HEP Logistics Holdings, L.P. (“HEP Logistics”), our general partner, and guaranteed by our material wholly-owned subsidiaries. Any recourse to HEP Logistics would be limited to the extent of its assets, which other than its

- 13 -

HOLLY ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) Continued

investment in us, are not significant. We may prepay all loans at any time without penalty, except for payment of certain breakage and related costs.

The Credit Agreement imposes certain requirements on us which we are currently in compliance with, including: a prohibition against distribution to unitholders if, before or after the distribution, a potential default or an event of default as defined in the agreement would occur; limitations on our ability to incur debt, make loans, acquire other companies, change the nature of our business, enter into a merger or consolidation, or sell assets; and covenants that require maintenance of a specified EBITDA to interest expense ratio, total debt to EBITDA ratio and senior debt to EBITDA ratio. If an event of default exists under the Credit Agreement, the lenders will be able to accelerate the maturity of the debt and exercise other rights and remedies.

Senior Notes

In March 2012, we issued $300 million in aggregate principal amount outstanding of 6.5% senior notes maturing March 1, 2020 (the “6.5% Senior Notes”). Net proceeds of $294.8 million were used in March and April 2012 to redeem $185.0 million aggregate principal amount of our 6.25% senior notes maturing March 1, 2015 (the “6.25% Senior Notes”) tendered pursuant to a cash tender offer and consent solicitation, to repay HFC $72.9 million in promissory notes related to our November 2011 acquisition of assets located at HFC's El Dorado and Cheyenne refineries, to pay related fees, expenses and accrued interest in connection with these transactions and to repay borrowings under the Credit Agreement.

Also, we have $150 million in aggregate principal amount outstanding of 8.25% senior notes maturing March 15, 2018 (the “8.25% Senior Notes”).

The 6.5% Senior Notes and 8.25% Senior Notes (collectively, the “Senior Notes”) are unsecured and impose certain restrictive covenants, which we are currently in compliance with, including limitations on our ability to incur additional indebtedness, make investments, sell assets, incur certain liens, pay distributions, enter into transactions with affiliates, and enter into mergers. At any time when the 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 under the Senior Notes.

Indebtedness under the Senior Notes is recourse to HEP Logistics, our general partner, and guaranteed by our wholly-owned subsidiaries. However, any recourse to HEP Logistics would be limited to the extent of its assets, which other than its investment in us, are not significant.

Long-term Debt

The carrying amounts of our long-term debt are as follows:



	September 30, 2013			December 31, 2012
	(In thousands)
Credit Agreement	$	365,000		$	421,000
6.5% Senior Notes
Principal	300,000			300,000
Unamortized discount	(4,236		)	(4,725		)
	295,764			295,275
8.25% Senior Notes
Principal	150,000			150,000
Unamortized discount	(1,373		)	(1,601		)
	148,627			148,399

Total long-term debt	$	809,391		$	864,674

- 14 -

HOLLY ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) Continued

Interest Rate Risk Management

We use interest rate swaps (derivative instruments) to manage our exposure to interest rate risk.

As of September 30, 2013, we have three interest rate swaps that hedge our exposure to the cash flow risk caused by the effects of LIBOR changes on $305.0 million of Credit Agreement advances. Our first interest rate swap entered into in December 2011, effectively converts $155.0 million of our LIBOR-based debt to fixed rate debt having an interest rate of 0.99% plus an applicable margin of 2.25% as of September 30, 2013, which equaled an effective interest rate of 3.24%. This swap contract matures in February 2016. In August 2012, we entered into two similar interest rate swaps with identical terms which effectively convert $150.0 million of our LIBOR-based debt to fixed rate debt having an interest rate of 0.74% plus an applicable margin of 2.25% as of September 30, 2013, which equaled an effective interest rate of 2.99%. Both of these swap contracts mature in July 2017.

We have designated these interest rate swaps as cash flow hedges. Based on our assessment of effectiveness using the change in variable cash flows method, we have determined that these interest rate swaps are effective in offsetting the variability in interest payments on $305.0 million of our variable-rate debt resulting from changes in LIBOR. Under hedge accounting, we adjust our cash flow hedges on a quarterly basis to their fair values with the offsetting fair value adjustments to accumulated other comprehensive income (loss). Also on a quarterly basis, we measure hedge effectiveness by comparing the present value of the cumulative change in the expected future interest to be paid or received on the variable leg of our swaps against the expected future interest payments on $305.0 million of our variable rate debt. Any ineffectiveness is recorded directly to interest expense. As of September 30, 2013, we had no ineffectiveness on our cash flow hedges.

At September 30, 2013, we have accumulated other comprehensive income of $0.5 million that relates to our current cash flow hedging instruments. For the three and nine months ended September 30, 2013, $0.5 million and $2.4 million, respectively, of other comprehensive loss was reclassified to interest expense due to cash flow hedge settlements. Approximately $0.4 million will be transferred from accumulated other comprehensive loss into interest expense as interest is paid on the underlying swap agreement over the next twelve-month period, assuming interest rates remain unchanged.

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)

September 30, 2013

Interest rate swaps designated as cash flow hedging instrument:

Variable-to-fixed interest rate swap contracts ($305.0 million of LIBOR-based debt interest)

Other long-term

liabilities

552

Accumulated other

comprehensive (loss)

(552

)

December 31, 2012

Interest rate swaps designated as cash flow hedging instrument:

Variable-to-fixed interest rate swap contracts ($305.0 million of LIBOR-based debt interest)

Other long-term

liabilities

3,430

Accumulated other

comprehensive (loss)

(3,430

)

- 15 -

HOLLY ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) Continued

Interest Expense and Other Debt Information

Interest expense consists of the following components:



	Nine Months Ended September 30,
	2013		2012
	(In thousands)
Interest on outstanding debt:
Credit Agreement, net of interest on interest rate swaps	$	9,273	$	5,667
6.5% Senior Notes	14,631		10,842
6.25% Senior Notes	—		2,422
8.25% Senior Notes	9,286		9,286
Promissory Notes	—		543
Amortization of discount and deferred debt issuance costs	1,590		1,403
Amortization of unrecognized loss attributable to terminated cash flow hedge	849		3,821
Commitment fees	629		507
Total interest incurred	36,258		34,491
Less capitalized interest	329		222
Net interest expense	$	35,929	$	34,269
Cash paid for interest	$	41,751	$	35,007

We recognized a charge of $3.0 million upon the early extinguishment of debt for the nine months ended September 30, 2012. This charge represents the premium paid to our 6.25% Senior Note holders upon their tender of an aggregate principal amount of $185.0 million and related net discount.


Note 8:	Significant Customers

All revenues are domestic revenues, of which 94% are generated currently from our two largest customers: HFC and Alon. The vast majority of our revenues are derived from activities conducted in the southwest United States.

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,
	2013		2012		2013		2012
HFC	84	%	84	%	84	%	84	%
Alon	10	%	11	%	10	%	11	%


Note 9:	Related Party Transactions

We serve HFC's refineries under long-term pipeline and terminal, tankage and throughput agreements expiring from 2019 to 2026. Under these agreements, HFC agreed to transport, store and throughput volumes of refined product and crude oil on our pipelines and terminal, tankage and loading rack facilities that result in minimum annual payments to us. These minimum annual payments or revenues are subject to annual tariff rate adjustments on July 1, based on the Producer Price Index (“PPI”) or Federal Energy Regulatory Commission (“FERC”) index. Additionally such agreements require HFC to reimburse us for certain costs. Following the July 1, 2013 PPI adjustment HFC's minimum annualized payments to us under these agreements increased by $4.7 million to$225.5 million.

If HFC fails to meet its minimum volume commitments under the agreements in any quarter, it will be required to pay us in cash the amount of any shortfall 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.

- 16 -

HOLLY ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) Continued

Under certain provisions of an omnibus agreement we have with HFC (the “Omnibus Agreement”) we pay HFC an annual administrative fee for the provision by HFC or its affiliates of various general and administrative services to us, currently $2.3 million. This fee does not include the salaries of personnel employed by HLS who perform services for us 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 $65.5 million and $62.1 million for the three months ended September 30, 2013 and 2012, respectively, and $190.2 million and $176.4 million for the nine months ended September 30, 2013 and 2012, respectively.


•	HFC charged us general and administrative services under the Omnibus Agreement of $0.6 million for the three months ended September 30, 2013 and 2012, respectively, and $1.7 million for the nine months ended September 30, 2013 and 2012, respectively.

•

We reimbursed HFC for costs of employees supporting our operations of $5.9 million and $7.8 million for the three months ended September 30, 2013 and 2012, respectively, and $25.0 million and $22.6 million for the nine months ended September 30, 2013 and 2012, respectively. Netted against the cost of employees for the three and nine months ended September 30, 2013 is a $3.5 million refund from HFC related to refunds of taxes covering a multi-year period.


•	HFC reimbursed us $5.8 million and $2.9 million for the three months ended September 30, 2013 and 2012, respectively, and $15.1 million and $7.5 million for the nine months ended September 30, 2013 and 2012, respectively, for certain reimbursable costs and capital projects.


•	We distributed $18.0 million and $16.3 million for the three months ended September 30, 2013 and 2012, respectively, to HFC as regular distributions on its common units and general partner interest, including general partner incentive distributions. For the nine months ended September 30, 2013 and 2012 we distributed $52.8 million and $47.3 million, respectively.


•	Accounts receivable from HFC were $30.7 million and $31.6 million at September 30, 2013 and December 31, 2012, respectively.


•	Accounts payable to HFC were $4.2 million and $5.0 million at September 30, 2013 and December 31, 2012, respectively.

•

Revenues for the three and the nine months ended September 30, 2013 include $0.2 million and $4.9 million, respectively, of shortfall payments billed in 2012, as HFC did not exceed its minimum volume commitment in any of the subsequent four quarters. Deferred revenue in the consolidated balance sheets at September 30, 2013 and December 31, 2012, includes $7.4 million and $5.1 million, respectively, relating to certain shortfall billings. It is possible that HFC may not exceed its minimum obligations to receive credit for any of the $7.4 million deferred at September 30, 2013.


•	We acquired from HFC 75% interest in the UNEV Pipeline in July 2012. See Note 2 for a description of this transaction.


Note 10:	Partners’ Equity

As of September 30, 2013, HFC held 22,380,030 of our common units and the 2% general partner interest, which together constituted a 39% ownership interest in us.

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

- 17 -

HOLLY ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) Continued

declared subsequent to quarter end. After the amount of incentive distributions is 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.

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,
	2013		2012		2013		2012
	(In thousands)
General partner interest in net income	$	301	$	369	$	823	$	1,030
General partner incentive distribution	6,827		4,907		19,215		15,644
Total general partner interest in net income	$	7,128	$	5,276	$	20,038	$	16,674

Cash Distributions

Our general partner, HEP Logistics, is entitled to incentive distributions if the amount we distribute with respect to any quarter exceeds specified target levels.

On October 25, 2013 we announced our cash distribution for the third quarter of 2013 of $0.4925 per unit. The distribution is payable on all common and general partner units and will be paid November 14, 2013 to all unitholders of record on November 4, 2013.

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,
	2013		2012		2013		2012
	(In thousands, except per unit data)
General partner interest in distribution	$	754	$	659	$	2,210	$	1,886
General partner incentive distribution	6,827		4,907		19,215		15,644
Total general partner distribution	7,581		5,566		21,425		17,530
Limited partner distribution	28,889		26,148		85,346		75,534
Total regular quarterly cash distribution	$	36,470	$	31,714	$	106,771	$	93,064
Cash distribution per unit applicable to limited partners	$	0.4925	$	0.4625	$	1.455	$	1.365

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 of $305.3 million would have been recorded in our financial statements, as increases to our properties and equipment and intangible assets instead of decreases to our partners’ equity.

- 18 -

HOLLY ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) Continued


Note 11:	Supplemental Guarantor/Non-Guarantor Financial Information

Obligations of HEP (“Parent”) under the 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 using the equity method of accounting.

Prior period amounts have been recast to include UNEV operations acquired July 12, 2012, as if it had been acquired January 1, 2012. This treatment is required as the transactions were between entities under common control. Additionally, certain reclassifications for prior periods have been made to conform to current year presentation.

Condensed Consolidating Balance Sheet



September 30, 2013	Parent			Guarantor Restricted Subsidiaries		Non-Guarantor Non-Restricted Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	2		$	6,331	$	4,887	$	—		$	11,220
Accounts receivable	—			31,489		4,919		(532		)	35,876
Intercompany accounts receivable (payable)	(24,584		)	24,584		—		—			—
Prepaid and other current assets	440			2,735		1,164		—			4,339
Total current assets	(24,142		)	65,139		10,970		(532		)	51,435
Properties and equipment, net	—			558,267		392,297		—			950,564
Investment in subsidiaries	857,101			294,431		—		(1,151,532		)	—
Transportation agreements, net	—			89,386		—		—			89,386
Goodwill	—			256,498		—		—			256,498
Investment in SLC Pipeline	—			24,966		—		—			24,966
Other assets	1,718			7,805		—		—			9,523
Total assets	$	834,677		$	1,296,492	$	403,267	$	(1,152,064	)	$	1,382,372

LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	—		$	12,318	$	1,215	$	(532	)	$	13,001
Accrued interest	2,229			51		—		—			2,280
Deferred revenue	—			6,020		6,407		—			12,427
Accrued property taxes	—			2,302		2,907		—			5,209
Other current liabilities	458			1,932		18		—			2,408
Total current liabilities	2,687			22,623		10,547		(532		)	35,325

Long-term debt	444,391			365,000		—		—			809,391
Other long-term liabilities	89			13,405		145		—			13,639
Deferred revenue	—			19,835		—		—			19,835
Class B unit	—			18,528		—		—			18,528
Equity - partners	387,510			857,101		392,575		(1,249,676		)	387,510
Equity - noncontrolling interest	—			—		—		98,144			98,144
Total liabilities and partners’ equity	$	834,677		$	1,296,492	$	403,267	$	(1,152,064	)	$	1,382,372

- 19 -

HOLLY ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) Continued

Condensed Consolidating Balance Sheet



December 31, 2012	Parent		Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	2	$	823		$	4,412	$	—		$	5,237
Accounts receivable	—		32,319			6,401		—			38,720
Intercompany accounts receivable (payable)	42,194		(42,194		)	—		—			—
Prepaid and other current assets	224		2,395			1,000		—			3,619
Total current assets	42,420		(6,657		)	11,813		—			47,576
Properties and equipment, net	—		563,701			396,834		—			960,535
Investment in subsidiaries	763,569		300,607			—		(1,064,176		)	—
Transportation agreements, net	—		94,596			—		—			94,596
Goodwill	—		256,498			—		—			256,498
Investment in SLC Pipeline	—		25,041			—		—			25,041
Other assets	1,154		8,710			—		—			9,864
Total assets	$	807,143	$	1,242,496		$	408,647	$	(1,064,176	)	$	1,394,110

LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	—	$	10,745		$	1,285	$	—		$	12,030
Accrued interest	10,198		28			—		—			10,226
Deferred revenue	—		3,319			5,582		—			8,901
Accrued property taxes	—		1,923			765		—			2,688
Other current liabilities	563		1,274			68		—			1,905
Total current liabilities	10,761		17,289			7,700		—			35,750
Long-term debt	443,674		421,000			—		—			864,674
Other long-term liabilities	55		15,241			137		—			15,433
Deferred revenue	—		11,494			—		—			11,494
Class B unit	—		13,903			—		—			13,903
Equity - partners	352,653		763,569			400,810		(1,164,379		)	352,653
Equity - noncontrolling interest	—		—			—		100,203			100,203
Total liabilities and partners’ equity	$	807,143	$	1,242,496		$	408,647	$	(1,064,176	)	$	1,394,110

- 20 -

HOLLY ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) Continued

Condensed Consolidating Statement of Comprehensive Income



Three Months Ended September 30, 2013	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	62,903		$	2,930		$	(310	)	$	65,523
Third parties	—			10,644			1,556			—			12,200
	—			73,547			4,486			(310		)	77,723
Operating costs and expenses:
Operations	—			19,501			2,495			(310		)	21,686
Depreciation and amortization	—			15,867			3,582			—			19,449
General and administrative	752			1,663			—			—			2,415
	752			37,031			6,077			(310		)	43,550
Operating income (loss)	(752		)	36,516			(1,591		)	—			34,173
Equity in earnings (loss) of subsidiaries	30,890			(1,191		)	—			(29,699		)	—
Equity in earnings of SLC Pipeline	—			835			—			—			835
Interest expense	(8,253		)	(3,563		)	—			—			(11,816		)
Interest income	—			2			1			—			3
Loss on sale of assets	—			(159		)	—			—			(159		)
Other	—			61			—			—			61
	22,637			(4,015		)	1			(29,699		)	(11,076		)
Income (loss) before income taxes	21,885			32,501			(1,590		)	(29,699		)	23,097
State income tax expense	—			(40		)	—			—			(40		)
Net income (loss)	21,885			32,461			(1,590		)	(29,699		)	23,057
Allocation of net income attributable to noncontrolling interests	—			—			—			(1,172		)	(1,172		)
Net income (loss) attributable to Holly Energy Partners	21,885			32,461			(1,590		)	(30,871		)	21,885
Other comprehensive income	(1,097		)	(1,097		)	—			1,097			(1,097		)
Comprehensive income (loss)	$	20,788		$	31,364		$	(1,590	)	$	(29,774	)	$	20,788

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HOLLY ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) Continued

Condensed Consolidating Statement of Comprehensive Income



Three Months Ended September 30, 2012	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	60,848		$	1,542		$	(275	)	$	62,115
Third parties	—			10,529			1,410			—			11,939
	—			71,377			2,952			(275		)	74,054
Operating costs and expenses:
Operations	—			20,105			2,902			(275		)	22,732
Depreciation and amortization	—			10,771			3,580			—			14,351
General and administrative	743			656			—			—			1,399
	743			31,532			6,482			(275		)	38,482
Operating income (loss)	(743		)	39,845			(3,530		)	—			35,572
Equity in earnings (loss) of subsidiaries	32,186			(2,645		)	—			(29,541		)	—
Equity in earnings of SLC Pipeline	—			877			—			—			877
Interest income (expense)	(8,253		)	(4,291		)	4			—			(12,540		)
	23,933			(6,059		)	4			(29,541		)	(11,663		)
Income (loss) before income taxes	23,190			33,786			(3,526		)	(29,541		)	23,909
State income tax expense	—			(137		)	—			—			(137		)
Net income (loss)	23,190			33,649			(3,526		)	(29,541		)	23,772
Allocation of net loss attributable to Predecessor	146			—			—			—			146
Allocation of net income attributable to noncontrolling interests	—			—			—			(582		)	(582		)
Net income (loss) attributable to Holly Energy Partners	23,336			33,649			(3,526		)	(30,123		)	23,336
Other comprehensive income (loss)	(107		)	(107		)	—			107			(107		)
Comprehensive income (loss)	$	23,229		$	33,542		$	(3,526	)	$	(30,016	)	$	23,229

- 22 -

HOLLY ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) Continued

Condensed Consolidating Statement of Comprehensive Income



Nine Months Ended September 30, 2013	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-restricted Subsidiaries		Eliminations				Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	178,113		$	13,030	$	(921	)		$	190,222
Third parties	—			29,167			7,917		—				37,084
	—			207,280			20,947		(921		)		227,306
Operating costs and expenses:
Operations	—			64,972			8,038		(921		)		72,089
Depreciation and amortization	—			37,980			10,750		—				48,730
General and administrative	2,543			6,204			—		—				8,747
	2,543			109,156			18,788		(921		)		129,566
Operating income (loss)	(2,543		)	98,124			2,159		—			—	97,740
Equity in earnings (loss) of subsidiaries	87,762			1,699			—		(89,461		)		—
Equity in earnings of SLC Pipeline	—			2,238			—		—				2,238
Interest expense	(24,768		)	(11,161		)	—		—				(35,929		)
Interest income	—			5			105		—				110
Gain on sale of assets	—			1,863			—		—				1,863
Other income	—			61			—		—				61
	62,994			(5,295		)	105		(89,461		)		(31,657		)
Income before income taxes	60,451			92,829			2,264		(89,461		)		66,083
State income tax expense	—			(440		)	—		—				(440		)
Net income	60,451			92,389			2,264		(89,461		)		65,643
Allocation of net income attributable to noncontrolling interests	—			—			—		(5,192		)		(5,192		)
Net income attributable to Holly Energy Partners	60,451			92,389			2,264		(94,653		)		60,451
Other comprehensive income	3,727			3,727			—		(3,727		)		3,727
Comprehensive income	$	64,178		$	96,116		$	2,264	$	(98,380	)		$	64,178

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HOLLY ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) Continued

Condensed Consolidating Statement of Comprehensive Income



Nine Months Ended September 30, 2012	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	170,141		$	7,082		$	(803	)	$	176,420
Third parties	—			31,026			3,683			—			34,709
	—			201,167			10,765			(803		)	211,129
Operating costs and expenses:
Operations	—			57,367			8,550			(803		)	65,114
Depreciation and amortization	—			32,097			10,704			—			42,801
General and administrative	2,669			3,256			—			—			5,925
	2,669			92,720			19,254			(803		)	113,840
Operating income (loss)	(2,669		)	108,447			(8,489		)	—			97,289
Equity in earnings (loss) of subsidiaries	91,833			(6,364		)	—			(85,469		)	—
Equity in earnings of SLC Pipeline	—			2,502			—			—			2,502
Interest income (expense)	(23,271		)	(11,002		)	4			—			(34,269		)
Loss on early extinguishment of debt	(2,979		)	—			—			—			(2,979		)
	65,583			(14,864		)	4			(85,469		)	(34,746		)
Income (loss) before income taxes	62,914			93,583			(8,485		)	(85,469		)	62,543
State income tax expense	—			(287		)	—			—			(287		)
Net income (loss)	62,914			93,296			(8,485		)	(85,469		)	62,256
Allocation of net loss attributable to Predecessor	4,199			—			—			—			4,199
Allocation of net loss attributable to noncontrolling interests	—			—			—			658			658
Net income (loss) attributable to Holly Energy Partners	67,113			93,296			(8,485		)	(84,811		)	67,113
Other comprehensive income (loss)	578			578			—			(578		)	578
Comprehensive income (loss)	$	67,691		$	93,874		$	(8,485	)	$	(85,389	)	$	67,691

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HOLLY ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) Continued

Condensed Consolidating Statement of Cash Flows



Nine Months Ended September 30, 2013	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities	$	32,022		$	86,424		$	17,117		$	(7,875	)	$	127,688

Cash flows from investing activities
Additions to properties and equipment	—			(27,397		)	(6,142		)	—			(33,539		)
Proceeds from sale of assets	—			2,481			—			—			2,481
	—			(24,916		)	(6,142		)	—			(31,058		)

Cash flows from financing activities
Net borrowings under credit agreement	—			(56,000		)	—			—			(56,000		)
Proceeds from issuance of common units	73,444			—			—			—			73,444
Contribution from general partners	1,499			—			—			—			—
Distributions to HEP unitholders	(103,016		)	—			—			—			(103,016		)
Distributions to noncontrolling interests	—			—			(10,500		)	7,875			(2,625		)
Purchase of units for incentive grants	(3,700		)	—			—			—			(3,700		)
Other	(249		)	—			—			—			(249		)
	(32,022		)	(56,000		)	(10,500		)	7,875			(90,647		)
Cash and cash equivalents
Increase for the period	—			5,508			475			—			5,983
Beginning of period	2			823			4,412			—			5,237
End of period	$	2		$	6,331		$	4,887		$	—		$	11,220

Condensed Consolidating Statement of Cash Flows



Nine Months Ended September 30, 2012	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations		Consolidated
	(In thousands)
Cash flows from operating activities	$	(14,603	)	$	127,198		$	(4,707	)	$	—	$	107,888

Cash flows from investing activities
Additions to properties and equipment	—			(23,255		)	(13,393		)	—		(36,648		)

Cash flows from financing activities
Net borrowings under credit agreement	—			231,000			—			—		231,000
Proceeds from issuance of senior notes	294,750			—			—			—		294,750
Cash distribution to HFC for UNEV acquisition	—			(260,922		)	—			—		(260,922		)
Repayments of notes	(185,000		)	(72,900		)	—			—		(257,900		)
Capital contribution from UNEV joint partners	1,748			—			15,000			—		16,748
Distributions to HEP unitholders	(91,063		)	—			—			—		(91,063		)
Purchase of units for incentive grants	(4,919		)	—			—			—		(4,919		)
Deferred financing costs	(913		)	(2,309		)	—			—		(3,222		)
Other	—			(88		)	—			—		(88		)
	14,603			(105,219		)	15,000			—		(75,616		)
Cash and cash equivalents
Increase (decrease) for the period	—			(1,276		)	(3,100		)	—		(4,376		)
Beginning of period	2			3,267			3,100			—		6,369
End of period	$	2		$	1,991		$	—		$	—	$	1,993

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HOLLY ENERGY PARTNERS, L.P.


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

This Item 2, including but not limited to the sections on “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 pipelines and terminal, tankage and loading rack facilities that support the refining and marketing operations of HollyFrontier Corporation (“HFC”) in the Mid-Continent, Southwest and Rocky Mountain regions of the United States and Alon USA, Inc’s (“Alon”) refinery in Big Spring, Texas. HFC owns a 39% interest in us including the 2% general partnership interest. Additionally, we own a 75% interest in UNEV Pipeline, LLC (“UNEV”), which owns a 400-mile, 12-inch refined products pipeline running from Woods Cross, Utah to Las Vegas, Nevada (the “UNEV Pipeline”), product terminals near Cedar City, Utah and Las Vegas, Nevada and related assets, and a 25% interest in SLC Pipeline LLC, which owns a 95-mile intrastate crude oil pipeline system (the “SLC Pipeline”), that serves refineries in the Salt Lake City area.

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 and providing other services at our storage tanks and terminals. 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 continuing growth of crude production in the Permian Basin and throughout the Mid-Continent and favorable refining economics 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.

UNEV Pipeline Interest Acquisition

We acquired HFC's 75% interest in UNEV on July 12, 2012. We paid consideration consisting of $260.9 million in cash and 2,059,800 of our common units. Also, under the terms of the transaction, we issued to HFC a Class B unit comprising an equity interest in a wholly-owned subsidiary that entitles HFC to an interest in our share of annual UNEV earnings before interest, income taxes, depreciation, and amortization above $30 million beginning July 1, 2016 and ending in June 2032, subject to certain limitations. Contemporaneously with this transaction, HFC (our general partner) agreed to forego its right to incentive distributions of up to $1.25 million per quarter over twelve consecutive quarterly periods following the closing of the transaction and up to an additional four quarters in certain circumstances.

Agreements with HFC and Alon

We serve HFC’s refineries under long-term pipeline and terminal, tankage and throughput agreements expiring from 2019 to 2026. Under these agreements, HFC agreed to transport, store and throughput volumes of refined product and crude oil on our pipelines and terminal, tankage and loading rack facilities that result in minimum annual payments to us. These minimum annual payments or revenues are subject to annual tariff rate adjustments on July 1, based on the Producer Price Index (“PPI”) or Federal Energy Regulatory Commission (“FERC”) index. Following the July 1, 2013 PPI adjustment HFC's minimum annualized payments to us under these agreements increased by $4.7 million to $225.5 million.

If HFC fails to meet its minimum volume commitments under the agreements in any quarter, it will be required to pay us in cash the amount of any shortfall 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.

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We also 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 also is subject to annual tariff rate adjustments. The terms under this agreement expire beginning in 2018 through 2022. 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. As of September 30, 2013, these agreements with Alon will result in minimum annualized payments to us of $31.7 million.

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

Under certain provisions of the Omnibus Agreement (“Omnibus Agreement”) that we have with HFC, we pay HFC an annual administrative fee, currently $2.3 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 HLS who perform services for us 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.

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Table of Contentsril 19,

RESULTS OF OPERATIONS (Unaudited)

Income, Distributable Cash Flow and Volumes

The following tables present income, distributable cash flow and volume information for the three and nine months ended September 30, 2013 and 2012.



	Three Months Ended September 30,						Change from
	2013			2012 ⁽¹⁾			2012
	(In thousands, except per unit data)
Revenues:
Pipelines:
Affiliates—refined product pipelines	$	17,196		$	16,351		$	845
Affiliates—intermediate pipelines	6,567			7,319			(752		)
Affiliates—crude pipelines	12,994			12,306			688
	36,757			35,976			781
Third parties—refined product pipelines	9,246			9,538			(292		)
	46,003			45,514			489
Terminals, tanks and loading racks:
Affiliates	28,766			26,139			2,627
Third parties	2,954			2,401			553
	31,720			28,540			3,180
Total revenues	77,723			74,054			3,669
Operating costs and expenses:
Operations	21,686			22,732			(1,046		)
Depreciation and amortization	19,449			14,351			5,098
General and administrative	2,415			1,399			1,016
	43,550			38,482			5,068
Operating income	34,173			35,572			(1,399		)
Other income (expense):
Equity in earnings of SLC Pipeline	835			877			(42		)
Interest expense, including amortization	(11,816		)	(12,540		)	724
Interest income	3			—			3
Other income	61			—			61
Loss on sale of assets	(159		)	—			(159		)
	(11,076		)	(11,663		)	587
Income before income taxes	23,097			23,909			(812		)
State income tax expense	(40		)	(137		)	97
Net income	23,057			23,772			(715		)
Allocation of net loss attributable to Predecessor	—			146			(146		)
Allocation of net income attributable to noncontrolling interests	(1,172		)	(582		)	(590		)
Net income attributable to Holly Energy Partners	21,885			23,336			(1,451		)
General partner interest in net income, including incentive distributions ⁽²⁾	(7,128		)	(5,276		)	(1,852		)
Limited partners’ interest in net income	$	14,757		$	18,060		$	(3,303	)
Limited partners’ earnings per unit—basic and diluted ⁽²⁾	$	0.25		$	0.32		$	(0.07	)
Weighted average limited partners’ units outstanding	58,657			56,536			2,121
EBITDA ⁽³⁾	$	53,187		$	49,920		$	3,267
Distributable cash flow ⁽⁴⁾	$	43,865		$	40,431		$	3,434

Volumes (bpd)
Pipelines:
Affiliates—refined product pipelines	116,078			114,113			1,965
Affiliates—intermediate pipelines	136,312			132,220			4,092
Affiliates—crude pipelines	172,569			187,861			(15,292		)
	424,959			434,194			(9,235		)
Third parties—refined product pipelines	59,036			66,274			(7,238		)
	483,995			500,468			(16,473		)
Terminals and loading racks:
Affiliates	261,431			267,638			(6,207		)
Third parties	64,615			57,496			7,119
	326,046			325,134			912
Total for pipelines and terminal assets (bpd)	810,041			825,602			(15,561		)

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	Nine Months Ended September 30,						Change from
	2013			2012 ⁽¹⁾			2012
	(In thousands, except per unit data)
Revenues:
Pipelines:
Affiliates—refined product pipelines	$	50,918		$	46,727		$	4,191
Affiliates—intermediate pipelines	20,030			21,076			(1,046		)
Affiliates—crude pipelines	36,760			33,844			2,916
	107,708			101,647			6,061
Third parties—refined product pipelines	29,412			27,856			1,556
	137,120			129,503			7,617
Terminals, tanks and loading racks:
Affiliates	82,514			74,773			7,741
Third parties	7,672			6,853			819
	90,186			81,626			8,560
Total revenues	227,306			211,129			16,177
Operating costs and expenses:
Operations	72,089			65,114			6,975
Depreciation and amortization	48,730			42,801			5,929
General and administrative	8,747			5,925			2,822
	129,566			113,840			15,726
Operating income	97,740			97,289			451
Other income (expense):
Equity in earnings of SLC Pipeline	2,238			2,502			(264		)
Interest expense, including amortization	(35,929		)	(34,269		)	(1,660		)
Interest income	110			—			110
Other income	61			—			61
Loss on early extinguishment of debt	—			(2,979		)	2,979
Gain on sale of assets	1,863			—			1,863
	(31,657		)	(34,746		)	3,089
Income before income taxes	66,083			62,543			3,540
State income tax expense	(440		)	(287		)	(153		)
Net income	65,643			62,256			3,387
Allocation of net loss attributable to Predecessor	—			4,199			(4,199		)
Allocation of net loss (income) attributable to noncontrolling interests	(5,192		)	658			(5,850		)
Net income attributable to Holly Energy Partners	60,451			67,113			(6,662		)
General partner interest in net income, including incentive distributions ⁽²⁾	20,038			16,674			3,364
Limited partners’ interest in net income	$	40,413		$	50,439		$	(10,026	)
Limited partners’ earnings per unit—basic and diluted ⁽²⁾	$	0.69		$	0.91		$	(0.22	)
Weighted average limited partners’ units outstanding	58,108			55,332			2,776
EBITDA ⁽³⁾	$	145,440		$	139,546		$	5,894
Distributable cash flow ⁽⁴⁾	$	112,316		$	111,506		$	810

Volumes (bpd)
Pipelines:
Affiliates—refined product pipelines	109,995			104,444			5,551
Affiliates—intermediate pipelines	133,222			130,972			2,250
Affiliates—crude pipelines	167,685			169,922			(2,237		)
	410,902			405,338			5,564
Third parties—refined product pipelines	59,711			62,301			(2,590		)
	470,613			467,639			2,974
Terminals and loading racks:
Affiliates	265,242			265,958			(716		)
Third parties	59,995			52,918			7,077
	325,237			318,876			6,361
Total for pipelines and terminal assets (bpd)	795,850			786,515			9,335


(1)	The financial amounts presented here have been restated from those we previously reported for this period. See Note 1 of Notes to Consolidated Financial Statements included in Item 1 for a discussion of these revisions.


(2)	Net income is allocated between limited partners and the general partner interest in accordance with the provisions of the partnership agreement. Net income allocated to the general partner includes incentive distributions declared

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Table of Contentsril 19,

subsequent to quarter end. Net income attributable to the limited partners is divided by the weighted average limited partner units outstanding in computing the limited partners’ per unit interest in net income.

(3)

EBITDA is calculated as net income attributable to Holly Energy Partners plus (i) interest expense, net of interest income, (ii) state income tax and (iii) depreciation and amortization (excluding amounts related to Predecessor operations). EBITDA is not a calculation based upon U.S. 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 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 also is 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,
	2013			2012 ⁽¹⁾			2013			2012 ⁽¹⁾
	(In thousands)
Net income attributable to Holly Energy Partners	$	21,885		$	23,336		$	60,451		$	67,113
Add:
Interest expense	11,289			10,738			33,490			29,045
Interest income	(3		)	—			(110		)	—
Amortization of discount and deferred debt issuance costs	527			528			1,590			1,403
Loss on early extinguishment of debt	—			—			—			2,979
Amortization of unrecognized loss attributable to terminated cash flow hedge	—			1,274			849			3,821
State income tax	40			137			440			287
Depreciation and amortization	19,449			14,351			48,730			42,801
Predecessor depreciation and amortization	—			(444		)	—			(7,903		)
EBITDA	$	53,187		$	49,920		$	145,440		$	139,546

(4)

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 a billed crude revenue settlement and 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. Also it is used by management for internal analysis and for our performance units. We believe that this measure provides investors an enhanced perspective of the operating performance of our assets and the cash our business is generating. Set forth below is our calculation of distributable cash flow.

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	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012 ⁽¹⁾			2013			2012 ⁽¹⁾
	(In thousands)
Net income attributable to Holly Energy Partners	$	21,885		$	23,336		$	60,451		$	67,113
Add (subtract):
Depreciation and amortization	19,449			14,351			48,730			42,801
Predecessor depreciation and amortization	—			(444		)	—			(7,903		)
Amortization of discount and deferred debt issuance costs	527			528			1,590			1,403
Loss on early extinguishment of debt	—			—			—			2,979
Amortization of unrecognized loss attributable to terminated cash flow hedge	—			1,274			849			3,821
Increase in deferred revenue attributable to shortfall billings	3,472			2,162			3,624			1,733
Billed crude revenue settlement	—			917			918			2,753
Maintenance capital expenditures⁽⁵⁾	(2,045		)	(2,287		)	(6,557		)	(3,886		)
Other non-cash adjustments	577			594			2,711			692
Distributable cash flow	$	43,865		$	40,431		$	112,316		$	111,506


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



	September 30, 2013		December 31, 2012
	(In thousands)
Balance Sheet Data
Cash and cash equivalents	$	11,220	$	5,237
Working capital	$	16,110	$	11,826
Total assets	$	1,382,372	$	1,394,110
Long-term debt	$	809,391	$	864,674
Partners’ equity ⁽⁶⁾	$	387,510	$	352,653

(6)

As a master limited partnership, we distribute our available cash, which historically has exceeded our net income 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. Additionally, if the assets contributed and acquired from HFC while under common control of HFC had been acquired from third parties, our acquisition cost in excess of HFC’s basis in the transferred assets of $305.3 million would have been recorded in our financial statements as increases to our properties and equipment and intangible assets instead of decreases to partners’ equity.

Results of Operations—Three Months Ended September 30, 2013 Compared with Three Months Ended September 30, 2012

Summary

Net income for the third quarter was $23.1 million compared to $23.8 million for the third quarter of 2012. The decrease in net income is due principally to increased depreciation resulting from asset abandonment charges related to tankage permanently removed from service, partially offset by increased revenues and a payroll related tax refund. Net income attributable to Holly Energy Partners for the third quarter was $21.9 million compared to $23.3 million for the third quarter of 2012. The additional decrease in net income attributable to Holly Energy Partners is due principally to allocations of income to noncontrolling interests.

Revenues for the three months ended September 30, 2013 include the recognition of $0.2 million of prior shortfalls billed to shippers in 2012. Deficiency payments of $4.0 million associated with certain guaranteed shipping contracts were deferred during

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the three months ended September 30, 2013. Such deferred revenue will be recognized in earnings either as payment for shipments in excess of guaranteed levels, if and to the extent the pipeline system will not have the necessary capacity for shipments in excess of guaranteed levels, or when shipping rights expire unused.

Revenues

Total revenues for the quarter were $77.7 million, a $3.7 million increase compared to the third quarter of 2012. The revenue increase was due the effect of annual tariff increases combined with higher cost reimbursement receipts from HFC. Overall pipeline volumes were down 3% compared to the three months ended September 30, 2012.

Revenues from our refined product pipelines were $26.4 million, an increase of $0.6 million primarily due to the effect of annual tariff increases. Shipments averaged 175.1 thousand barrels per day (“mbpd”) compared to 180.4 mbpd for the third quarter of 2012.

Revenues from our intermediate pipelines were $6.6 million, a decrease of $0.8 million, on shipments averaging 136.3 mbpd compared to 132.2 mbpd for the third quarter of 2012. Although overall intermediate pipeline shipments were up, revenues decreased due to a $0.5 million decrease in deferred revenue realized and decreased volumes on certain pipeline segments.

Revenues from our crude pipelines were $13.0 million, an increase of $0.7 million, on shipments averaging 172.6 mbpd compared to 187.9 mbpd for the third quarter of 2012. Although crude oil pipeline shipments were down, revenues increased due to the annual tariff increases and minimum quarterly revenue billings on segments where volumes decreased.

Revenues from terminal, tankage and loading rack fees were $31.7 million, an increase of $3.2 million compared to the third quarter of 2012. The increase in revenues is due to annual fee increases and higher tank cost reimbursement receipts from HFC. Refined products terminalled in our facilities averaged 326.0 mbpd compared to 325.1 mbpd for the third quarter of 2012.

Operations Expense

Operations expense for the three months ended September 30, 2013 decreased by $1.0 million compared to the three months ended September 30, 2012. This decrease is due to a $3.5 million net tax refund related to payroll costs covering a multi-year period, offset by higher maintenance costs, environmental accruals and employee costs.

Depreciation and Amortization

Depreciation and amortization for the three months ended September 30, 2013 increased by $5.1 million compared to the three months ended September 30, 2012 due principally to asset abandonment charges related to tankage permanently removed from service.

General and Administrative

General and administrative costs for the three months ended September 30, 2013 increased by $1.0 million compared to the three months ended September 30, 2012 due to increased employee costs and professional fees.

Equity in Earnings of SLC Pipeline

Our equity in earnings of the SLC Pipeline was $0.8 million for the three months ended September 30, 2013 compared to $0.9 million for the three months ended September 30, 2012.

Interest Expense

Interest expense for the three months ended September 30, 2013 totaled $11.8 million, a decrease of $0.7 million compared to the three months ended September 30, 2012. The decrease is due principally to amortization of costs related to a terminated cash flow hedge in December 2011, with such costs fully amortized by February 2013. Our aggregate effective interest rates were 5.9% and 5.7% for the three months ended September 30, 2013 and 2012, respectively.

Loss on Sale of Assets

The loss on the sale of assets for the three months ended September 30, 2013 of $0.2 million is from the sale of our 50% ownership interest in product terminals located in Boise and Burley, Idaho.

State Income Tax

We recorded state income tax expense of $40,000 for the three months ended September 30, 2013 which is solely attributable to the Texas margin tax. We are subject to the Texas margin tax that is based on our Texas sourced taxable margin. Due to a statutory change that was enacted in June 2013, we are now able to deduct cost of goods sold which will result in lower cash taxes to HEP in the current and future years. For the three months ended September 30, 2012, we recorded state income tax expense of $137,000.

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Results of Operations—Nine Months Ended September 30, 2013 Compared with Nine Months Ended September 30, 2012

Summary

Net income for the nine months ended September 30, 2013 was $65.6 million, a $3.4 million increase compared to the nine months ended September 30, 2012. The increase in net income is due principally to revenue gains and an increase in non-operating income, offset by increased operating costs and expenses. Net income attributable to Holly Energy Partners for the nine months ended September 30, 2013 was $60.5 million, a $6.7 million decrease compared to the nine months ended September 30, 2012. This decrease in net income attributable to Holly Energy Partners is due principally to allocations of income to noncontrolling interests. Revenue increased for the nine months ended September 30, 2013 due to annual tariff increases and deferred revenue recognition. Additionally, major maintenance turnarounds at both HFC's Navajo refinery and Alon's Big Spring refinery had a significant impact on pipeline and terminal volumes during the first quarter of 2013 reducing income in the current year.

Revenues for the nine months ended September 30, 2013 include the recognition of $7.6 million of prior shortfalls billed to shippers in 2012. Deficiency payments of $11.4 million associated with certain guaranteed shipping contracts were deferred during the nine months ended September 30, 2013. Such deferred revenue will be recognized in earnings either as payment for shipments in excess of guaranteed levels, if and to the extent the pipeline system will not have the necessary capacity for shipments in excess of guaranteed levels, or when shipping rights expire unused.

Revenues

Total revenues for the nine months ended September 30, 2013 were $227.3 million, a $16.2 million increase compared to the first nine months ended September 30, 2012. This is due principally to a $4.4 million increase in deferred revenue realized, the effect of annual tariff increases, increased pipeline shipments in the second quarter and higher cost reimbursement receipts from HFC.

Revenues from our refined product pipelines were $80.3 million, an increase of $5.7 million primarily due to the effects of a $5.6 million increase in deferred revenue realized and the effect of annual tariff increases. Shipments averaged 169.7 thousand barrels per day (“mbpd”) compared to 166.7 mbpd for the nine months ended September 30, 2012.

Revenues from our intermediate pipelines were $20.0 million, a decrease of $1.0 million, on shipments averaging 133.2 mbpd compared to 131.0 mbpd for the nine months ended September 30, 2012. The decrease in revenue is due to a $1.2 million decrease in deferred revenue realized.

Revenues from our crude pipelines were $36.8 million, an increase of $2.9 million, on shipments averaging 167.7 mbpd compared to 169.9 mbpd for the nine months ended September 30, 2012. Revenues increased due to the annual tariff increases.

Revenues from terminal, tankage and loading rack fees were $90.2 million, an increase of $8.6 million compared to the nine months ended September 30, 2012. The increase in revenues is due to annual fee increases, increased terminal volumes and higher tank cost reimbursement receipts from HFC. Refined products terminalled in our facilities averaged 325.2 mbpd compared to 318.9 mbpd for the nine months ended September 30, 2012.

Operations Expense

Operations expense for the nine months ended September 30, 2013 increased by $7.0 million compared to the nine months ended September 30, 2012. This increase is due to higher maintenance costs, environmental accruals and employee costs offset by a $3.5 million net tax refund related to payroll costs covering a multi-year period.

Depreciation and Amortization

Depreciation and amortization for the nine months ended September 30, 2013 increased by $5.9 million compared to the nine months ended September 30, 2012 due principally to asset abandonment charges related to tankage permanently removed from service.

General and Administrative

General and administrative costs for the nine months ended September 30, 2013 increased by $2.8 million compared to the nine months ended September 30, 2012 due to increased employee costs and professional fees.

Equity in Earnings of SLC Pipeline

Our equity in earnings of the SLC Pipeline was $2.2 million for the nine months ended September 30, 2013 compared to $2.5 million for the nine months ended September 30, 2012.

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Interest Expense

Interest expense for the nine months ended September 30, 2013 totaled $35.9 million, an increase of $1.7 million compared to the nine months ended September 30, 2012. This increase reflects interest on a year-over-year increase in debt levels. Our aggregate effective interest rates were 5.8% and 6.7% for the nine months ended September 30, 2013 and 2012, respectively.

Loss on Early Extinguishment of Debt

We recognized a charge of $3.0 million upon the early extinguishment of our 6.25% senior notes for the nine months ended September 30, 2012.

Gain on Sale of Assets

Gain on sale of assets for the nine months ended September 30, 2013 of $1.9 million is comprised of a gain of $2.0 million on the sale of property in El Paso, Texas, partially offset by a $0.2 million loss from the sale of our 50% ownership interest in product terminals located in Boise and Burley, Idaho.

State Income Tax

We recorded state income tax expense of $440,000 for the nine months ended September 30, 2013 which is solely attributable to the Texas margin tax. We are subject to the Texas margin tax that is based on our Texas sourced taxable margin. Due to a statutory change that was enacted in June 2013, we are now able to deduct cost of goods sold which will result in lower cash taxes to HEP in the current and future years. The statutory change also resulted in a one-time charge of $336,000 to establish a deferred tax liability. For the nine months ended September 30, 2012, we recorded state income tax expense of $287,000.

LIQUIDITY AND CAPITAL RESOURCES

Overview

We have a $550 million senior secured revolving credit facility expiring in June 2017 (the “Credit Agreement”) that is available to fund capital expenditures, investments, acquisitions, distribution payments and working capital and for general partnership purposes. It also is available to fund letters of credit up to a $50 million sub-limit and to fund distributions to unitholders up to a $60 million sub-limit.

During the nine months ended September 30, 2013, we received advances totaling $256.5 million and repaid $312.5 million under the Credit Agreement, resulting in net repayments of $56.0 million and an outstanding balance of $365.0 million at September 30, 2013.

Under our registration statement filed with the SEC using a “shelf” registration process, we currently have the ability to raise up to $2.0 billion by offering securities, through one or more prospectus supplements that would describe, among other things, the specific amounts, prices and terms of any securities offered and how the proceeds would be used. Any proceeds from the sale of securities 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 2013, we paid regular quarterly cash distributions of $0.4700, $0.4775 and $0.4850, respectively, on all units in an aggregate amount of $103.0 million. Included in these distributions were $17.7 million of incentive distribution payments to the general partner.

Contemporaneously with our UNEV Pipeline interest acquisition on July 12, 2012, HFC (our general partner) agreed to forego its right to incentive distributions of $1.25 million per quarter over twelve consecutive quarterly periods following the close of the transaction and up to an additional four quarters in certain circumstances.

Cash and cash equivalents increased by $6.0 million during the nine months ended September 30, 2013. The cash flows provided by operating activities of $127.7 million was greater than the cash flows used for financing and investing activities of $90.6 million

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and $31.1 million, respectively. Working capital increased by $4.3 million to $16.1 million at September 30, 2013 from $11.8 million at December 31, 2012.

Cash Flows—Operating Activities

Cash flows from operating activities increased by $19.8 million from $107.9 million for the nine months ended September 30, 2012 to $127.7 million for the nine months ended September 30, 2013. This increase is due principally to $24.8 million in additional cash collections from our customers, partially offset by net payments attributable to increased operating expenses.

Our major shippers are obligated to make deficiency payments to us if they do not meet their minimum volume shipping obligations. Under certain agreements with these shippers, they have the right to recapture these amounts if future volumes exceed minimum levels. We billed $7.6 million during 2012 related to shortfalls that subsequently expired without recapture and were recognized as revenue during the nine months ended September 30, 2013. Another $4.0 million is included in our accounts receivable at September 30, 2013 related to shortfalls that occurred during the three months ended September 30, 2013.

Cash Flows—Investing Activities

Cash flows used for investing activities decreased by $5.6 million from $36.6 million for the nine months ended September 30, 2012 to $31.1 million for the nine months ended September 30, 2013. During the nine months ended September 30, 2013 and 2012, we invested $33.5 million and $36.6 million in additions to properties and equipment, respectively. During the nine months ended September 30, 2013, we received $2.5 million proceeds from the sale of assets.

Cash Flows—Financing Activities

Cash flows used for financing activities were $90.6 million for the nine months ended September 30, 2013 compared to $75.6 million for the nine months ended September 30, 2012, an increase of $15.0 million. During the nine months ended September 30, 2013, we received $256.5 million and repaid $312.5 million in advances under the Credit Agreement, received net proceeds of $73.4 million from the common unit public offering and $1.5 million from the general partner to maintain its 2% interest. Additionally, we paid $103.0 million in regular quarterly cash distributions to our general and limited partners, and paid $3.7 million for the purchase of common units for recipients of our incentive grants. Also we distributed $2.6 million to the UNEV noncontrolling interest joint venture partner. During the nine months ended September 30, 2012, we received $523.0 million and repaid $292.0 million in advances under the Credit Agreement, received net proceeds of $294.8 million from the issuance of our 6.5% senior notes and repaid $257.9 million of our notes. We paid HFC a $260.9 million distribution as partial consideration for the acquisition of HFC's 75% interest in UNEV. Additionally, we paid $91.1 million in regular quarterly cash distributions to our general and limited partners, we received $16.7 million from UNEV's joint venture partners, paid $3.2 million in financing costs to amend our Credit Agreement and paid $4.9 million for the purchase of common units for recipients of our incentive grants.

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 HLS board of directors approves our annual capital budget, which specifies capital projects that our management is authorized to undertake. Additionally, at times when conditions warrant or as new opportunities arise, additional projects may be approved. The funds allocated for a particular capital project may be expended over a period in excess of a year, depending on the time required to complete the project. Therefore, our planned capital expenditures for a given year consist of expenditures approved for capital projects included in the current year's capital budget as well as, in certain cases, expenditures approved for capital projects in capital budgets for prior years. The 2013 regular capital budget is comprised of $10.1 million for maintenance capital expenditures and $2.0 million for expansion capital expenditures exclusive of the projects discussed below. In addition to our capital budget, we may spend funds periodically to do capital upgrades of our assets where a customer reimburses us for such costs. These reimbursements would be required under contractual agreements and would generally benefit the customer over the remaining life of such agreements.

We are proceeding with the expansion of our crude oil transportation system in southeastern New Mexico in response to increased crude oil production in the area. The expansion should provide shippers with additional pipeline takeaway capacity to either

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common carrier pipeline stations for transportation to major crude oil markets or to HFC's New Mexico refining facilities. To complete the project, we plan to convert an existing refined products pipeline to crude oil service, construct several new pipeline segments, expand an existing pipeline, and build new truck unloading stations and crude storage capacity. Excluding the value of the existing pipeline to be converted, total capital expenditures are expected to cost between $35 million and $40 million. We estimate the project will provide increased capacity of up to 100,000 barrels per day across the system and anticipate it will be in full service no later than May 2014 though some segments may be completed and in service in late 2013.

UNEV is proceeding with a project to add certain enhancements to its product terminal in Las Vegas, Nevada. We expect that the project will cost approximately $13 million with construction expected to be completed no later than the second quarter of 2014.

We also are currently evaluating two proposed new pipelines. The first proposed pipeline would be a new intrastate crude oil pipeline between Cushing, Oklahoma and HFC's Tulsa, Oklahoma refinery. The 50-mile line would aim to provide safe and reliable transport of Cushing sourced domestic and Canadian crude oil to HFC's 125,000 BPD Tulsa facility. The pipeline would allow for a significant portion of crude oil transported to be heavy Canadian and sour crude oil. Crude oil processed at HFC's Tulsa facility currently is transported on pipelines owned by Sunoco Logistics and Magellan Pipeline Company. The second proposed pipeline would be a new 100-mile interstate petroleum products pipeline between HFC's Cheyenne, Wyoming refinery and Denver, Colorado. The 52,000 BPD refinery, with its ability to process up to 35,000 BPD of heavy Canadian crude and its close proximity to growing domestic crude production, is a significant supplier of petroleum products to the Denver market. We also will evaluate the construction of a new petroleum products terminal in North Denver or, alternatively, the routing of the new pipeline to existing third-party product terminals in the Denver area. This infrastructure addition would aim to ensure safe and reliable transport of petroleum products from HFC's location-advantaged refinery to its largest market. Petroleum products produced at HFC's Cheyenne, Wyoming refinery currently are transported to Denver on the Rocky Mountain Pipeline's products line owned by Plains All-American. We anticipate that we will decide whether to proceed with these projects by late 2013 or early 2014.

HFC and we are collaborating to evaluate the construction of a rail facility that would enable crude oil loading and unloading near HFC's Artesia and/or Lovington, New Mexico refining facilities. The rail project, which would be connected to our crude oil pipeline transportation system in southeastern New Mexico, would have an initial capacity of up to 70,000 barrels per day and would enable access to a variety of crude oil types including West Texas Intermediate (WTI), West Texas Sour (WTS) and Western Canadian Select (WCS). The project would provide both additional crude oil takeaway options for producers as crude production in the region continues to grow, and an expanded set of crude oil sourcing options for HFC. We anticipate project completion would take nine to twelve months once the decision to proceed is made. This project is currently on hold due to the volatility of price differentials for various types of crude oil that form the foundation of the project's economics.

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 existing 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.

Credit Agreement

We have a $550 million senior secured revolving credit facility expiring in June 2017 that is available to fund capital expenditures, investments, acquisitions, distribution payments and working capital and for general partnership purposes. It is available also to fund letters of credit up to a $50 million sub-limit and to fund distributions to unitholders up to a $60 million sub-limit.

The Credit Agreement imposes certain requirements on us which we are in compliance with currently, including: a prohibition against distribution to unitholders if, before or after the distribution, a potential default or an event of default as defined in the agreement would occur; limitations on our ability to incur debt, make loans, acquire other companies, change the nature of our business, enter into a merger or consolidation, or sell assets; and covenants that require maintenance of a specified EBITDA to interest expense ratio, total debt to EBITDA ratio and senior debt to EBITDA ratio. If an event of default exists under the Credit Agreement, the lenders will be able to accelerate the maturity of the debt and exercise other rights and remedies.

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Senior Notes

In March 2012, we issued $300 million in aggregate principal amount outstanding of 6.5% senior notes maturing March 1, 2020 (the “6.5% Senior Notes”). Net proceeds of $294.8 million were used in March and April 2012 to redeem $185.0 million aggregate principal amount of 6.25% senior notes maturing March 1, 2015 (the “6.25 Senior Notes”) tendered pursuant to a cash tender offer and consent solicitation, to repay $72.9 million in promissory notes due to HFC, to pay related fees, expenses and accrued interest in connection with these transactions and to repay borrowings under the Credit Agreement.

Also, we have $150 million in aggregate principal amount outstanding of 8.25% senior notes maturing March 15, 2018 (the "8.25 Senior Notes").

Our 6.5% Senior Notes and 8.25% Senior Notes (collectively, the “Senior Notes”) are unsecured and impose certain restrictive covenants which we are in compliance with currently, including limitations on our ability to incur additional indebtedness, make investments, sell assets, incur certain liens, pay distributions, enter into transactions with affiliates, and enter into mergers. At any time when the 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 under the Senior Notes.

Indebtedness under the Senior Notes is recourse to HEP Logistics, and guaranteed by our wholly-owned subsidiaries. However, any recourse to HEP Logistics would be limited to the extent of its assets, which other than its investment in us, are not significant.

Long-term Debt

The carrying amounts of our long-term debt are as follows:



	September 30, 2013			December 31, 2012
	(In thousands)
Credit Agreement	$	365,000		$	421,000

6.5% Senior Notes
Principal	300,000			300,000
Unamortized discount	(4,236		)	(4,725		)
	295,764			295,275
8.25% Senior Notes
Principal	150,000			150,000
Unamortized discount	(1,373		)	(1,601		)
	148,627			148,399

Total long-term debt	$	809,391		$	864,674

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

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, 2013 and 2012. Historically, the PPI has increased an average of 3.2% annually over the past 5 calendar years.

The substantial majority of our revenues are generated under long-term contracts that provide for increases in our rates and minimum revenue guarantees annually for increases in the PPI. Certain of these contracts have provisions that limit the level of annual PPI percentage rate increases. Although the recent PPI increase may not be indicative of additional increases to be realized in the future, a significant and prolonged period of high 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.

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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 that 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 that are currently in progress that relate to certain assets acquired from HFC. Certain of these projects were underway prior to our purchase and represent liabilities of HFC as the obligation for future remediation activities was retained by HFC. At September 30, 2013, we have an accrual of $3.8 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, 2012. 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 2013. 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.

New Accounting Pronouncements

Presentation of Comprehensive Income

Effective January 1, 2013, we adopted the accounting standard update that required the disclosure of significant amounts reclassified out of accumulated other comprehensive income by component either on the face of the financial statements or in the notes. The adoption of this accounting standard did not have an impact on our financial condition, results of operations or cash flows.

RISK MANAGEMENT

We use interest rate swaps (derivative instruments) to manage our exposure to interest rate risk.

As of September 30, 2013, we have three interest rate swaps, designated as a cash flow hedge, that hedge our exposure to the cash flow risk caused by the effects of LIBOR changes on $305.0 million of Credit Agreement advances. Our first interest rate swap

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effectively converts $155.0 million of our LIBOR based debt to fixed rate debt having an interest rate of 0.99% plus an applicable margin of 2.25% as of September 30, 2013, which equaled an effective interest rate of 3.24%. This swap contract matures in February 2016. Also we have two similar interest rate swaps with identical terms which effectively convert $150.0 million of our LIBOR based debt to fixed rate debt having an interest rate of 0.74% plus an applicable margin of 2.25% as of September 30, 2013, which equaled an effective interest rate of 2.99%. Both of these swap contracts mature in July 2017.

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.

At September 30, 2013, we had an outstanding principal balance on our 6.5% Senior Notes and 8.25% Senior Notes of $300 million and $150 million, respectively. A change in interest rates generally would affect the fair value of the Senior Notes, but not our earnings or cash flows. At September 30, 2013, the fair values of our 6.5% and 8.25% Senior Notes were $307.5 million and $157.9 million, respectively. We estimate a hypothetical 10% change in the yield-to-maturity applicable to the 6.5% Senior Notes and 8.25% Senior Notes at September 30, 2013 would result in a change of approximately $9.8 million and $4.0 million, respectively, in the fair value of the underlying notes.

For the variable rate Credit Agreement, changes in interest rates would affect cash flows, but not the fair value. At September 30, 2013, borrowings outstanding under the Credit Agreement were $365.0 million. By means of our cash flow hedges, we have effectively converted the variable rate on $305.0 million of outstanding borrowings to a fixed rate. For the remaining unhedged Credit Agreement borrowings of $60.0 million, a hypothetical 10% change in interest rates applicable to the Credit Agreement would not materially affect our cash flows.

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

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

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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, 2012. 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, 2013 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, 2012. In addition to the other information set forth in this quarterly report, you should consider carefully the factors discussed in our 2012 Form 10-K, which could materially affect our business, financial condition or future results. The risks described in this quarterly report and in our 2012 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 2.	Unregistered Sales of Equity Securities and Use of Proceeds

In the third quarter of 2013, we paid $0.4 million for the purchase of 11,672 of our common units in the open market for recipients of our 2013 restricted grants. The following table shows these purchases.



Period	Total Number of Units Purchased	Average Price Paid Per Unit		Total Number of Units Purchased as Part of Publicly Announced Plan or Program	Maximum Number of Units that May Yet be Purchased Under a Publicly Announced Plan or Program
July 2013	—	$	—	—	$	—
August 2013	11,672	$	38.217	—	$	—
September 2013	—	$	—	—	$	—
Total for July to September 2013	11,672			—


Item 6.	Exhibits

The Exhibit Index on page 43 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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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 1, 2013		/s/ Douglas S. Aron
		Douglas S. Aron
		Executive Vice President and Chief Financial Officer (Principal Financial Officer)

Date: November 1, 2013		/s/ Scott C. Surplus
		Scott C. Surplus
		Vice President and Controller (Principal Accounting Officer)

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Exhibit Index



Exhibit Number		Description

3.1		First Amended and Restated Agreement of Limited Partnership of Holly Energy Partners, L.P. (incorporated by reference to Exhibit 3.1 of Registrant's Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2004, File No. 1-32225).
3.2		Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of Holly Energy Partners, L.P., dated February 28, 2005 (incorporated by reference to Exhibit 3.1 of Registrant's Form 8-K Current Report dated February 28, 2005, File No. 1-32225).
3.3		Amendment No. 2 to the First Amended and Restated Agreement of Limited Partnership of Holly Energy Partners, L.P., as amended, dated July 6, 2005 (incorporated by reference to Exhibit 3.1 of Registrant's Form 8-K Current Report dated July 6, 2005, File No. 1-32225).
3.4		Amendment No. 3 to First Amended and Restated Agreement of Limited Partnership of Holly Energy Partners, L.P., dated April 11, 2008 (incorporated by reference to Exhibit 4.1 of Registrant's Current Report on Form 8-K dated April 15, 2008, File No. 1-32225).
3.5		Amendment No. 4 to First Amended and Restated Agreement of Limited Partnership of Holly Energy Partners, L.P., dated January 16, 2013 (incorporated by reference to Exhibit 3.1 of Registrant's Current Report on Form 8-K dated January 16, 2013, File No. 1-32225).
3.6		Limited Partial Waiver of Incentive Distribution Rights under the First Amended and Restated Agreement of Limited Partnership of Holly Energy Partners, L.P., dated as of July 12, 2012 (incorporated by reference to Exhibit 3.1 of Registrant's Current Report on Form 8-K dated July 12, 2012, File No. 1-32225).
3.7		First Amended and Restated Agreement of Limited Partnership of Holly Energy Partners - Operating Company, L.P. (incorporated by reference to Exhibit 3.2 of Registrant's Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2004, File No. 1-32225).
3.8		First Amended and Restated Agreement of Limited Partnership of HEP Logistics Holdings, L.P. (incorporated by reference to Exhibit 3.4 of Registrant's Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2004, File No. 1-32225).
3.9		First Amended and Restated Limited Liability Company Agreement of Holly Logistic Services, L.L.C. (incorporated by reference to Exhibit 3.5 of Registrant's Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2004, File No. 1-32225).
3.10		Amendment No. 1 to the First Amended and Restated Limited Liability Company Agreement of Holly Logistic Services, L.L.C., dated April 27, 2011 (incorporated by reference to Exhibit 3.1 of Registrant's Form 8-K Current Report dated May 3, 2011, File No. 1-32225).
3.11		First Amended and Restated Limited Liability Company Agreement of HEP Logistics GP, L.L.C. (incorporated by reference to Exhibit 3.6 of Registrant's Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2004, File No. 1-32225).
10.1		Transportation Services Agreement dated July 16, 2013 by and between HollyFrontier Refining & Marketing LLC and Holly Energy Partners-Operating, L.P. (incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed July 22, 2013, File No. 1-32225).
10.2		Eighth Amended and Restated Omnibus Agreement dated July 16, 2013 by and among HollyFrontier Corporation, Holly Energy Partners, L.P. and certain of their respective subsidiaries (incorporated by reference to Exhibit 10.2 of Registrant's Current Report on Form 8-K filed July 22, 2013, File No. 1-32225).
10.3		Second Amended and Restated Crude Pipeline and Tankage Agreement, dated as of July 16, 2013, by and among Navajo Refining Company, L.L.C., Holly Refining & Marketing Company - Woods Cross LLC, HollyFrontier Refining & Marketing LLC, Holly Energy Partners-Operating, L.P., HEP Pipeline, LLC and HEP Woods Cross, L.L.C. . (incorporated by reference to Exhibit 10.3 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2013, File No. 1-32225).
10.4+		Second Amended and Restated Throughput Agreement (Tucson Terminal), dated September 19, 2013 to be effective June 1, 2013, by and among HollyFrontier Refining & Marketing LLC, HEP Refining, L.L.C., and Holly Energy Partners - Operating, L.P.
10.5+*		Form of Notice of Grant of Restricted Units (Directors).
10.6+*		Form of Restricted Unit Agreement (Directors).
31.1+		Certification of Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002.
31.2+		Certification of Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002.
32.1++		Certification of Chief Executive Officer under Section 906 of the Sarbanes-Oxley Act of 2002.
32.2++		Certification of Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act of 2002.
101**		The following financial information from Holly Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2013, 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.

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+	Filed herewith.
++	Furnished herewith.
*	Constitutes management contracts or compensatory plans or arrangements.
**	Filed electronically herewith.

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