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 June 30, 2013

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ____________ to _____________                    

Commission File Number: 1-32225

______________________________________________________________________________________

HOLLY ENERGY PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

______________________________________________________________________________________

Delaware	20-0833098
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

2828 N. Harwood, Suite 1300

Dallas, Texas 75201

(Address of principal executive offices), (Zip code)

(214) 871-3555

(Registrant’s telephone number, including area code)

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.     Yes  ý    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes   ý    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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 July 26, 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)

	June 30, 2013			December 31, 2012
	(In thousands, except unit data)
ASSETS
Current assets:
Cash and cash equivalents	$	8,716		$	5,237
Accounts receivable:
Trade	4,550			7,126
Affiliates	31,571			31,594
	36,121			38,720
Prepaid and other current assets	4,314			3,619
Total current assets	49,151			47,576
Properties and equipment, net	954,132			960,535
Transportation agreements, net	91,123			94,596
Goodwill	256,498			256,498
Investment in SLC Pipeline	24,882			25,041
Other assets	10,925			9,864
Total assets	$	1,386,711		$	1,394,110
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	9,358		$	7,045
Affiliates	4,362			4,985
	13,720			12,030
Accrued interest	10,314			10,226
Deferred revenue	8,601			8,901
Accrued property taxes	3,649			2,688
Other current liabilities	2,042			1,905
Total current liabilities	38,326			35,750
Long-term debt	799,152			864,674
Other long-term liabilities	13,525			15,433
Deferred revenue	17,581			11,494
Class B unit	16,960			13,903
Equity:
Partners’ equity:
Common unitholders (58,657,048 and 56,782,048 units issued and outstanding     at June 30, 2013 and December 31, 2012, respectively)	547,261			502,809
General partner interest (2% interest)	(145,805		)	(145,877		)
Accumulated other comprehensive income (loss)	545			(4,279		)
Total partners’ equity	402,001			352,653
Noncontrolling interest	99,166			100,203
Total equity	501,167			452,856
Total liabilities and equity	$	1,386,711		$	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 June 30,						Six Months Ended June 30,
	2013			2012 (1)			2013			2012 (1)
	(In thousands, except per unit data)
Revenues:
Affiliates	$	63,187		$	57,774		$	124,699		$	114,305
Third parties	12,098			10,886			24,884			22,770
	75,285			68,660			149,583			137,075
Operating costs and expenses:
Operations	24,538			21,907			50,403			42,382
Depreciation and amortization	15,127			14,150			29,281			28,450
General and administrative	3,100			2,487			6,332			4,526
	42,765			38,544			86,016			75,358
Operating income	32,520			30,116			63,567			61,717
Other income (expense):
Equity in earnings of SLC Pipeline	746			794			1,403			1,625
Interest expense	(11,629		)	(11,324		)	(24,113		)	(21,729		)
Interest income	4			—			107			—
Loss on early extinguishment of debt	—			(383		)	—			(2,979		)
Gain on sale of assets	—			—			2,022			—
	(10,879		)	(10,913		)	(20,581		)	(23,083		)
Income before income taxes	21,641			19,203			42,986			38,634
State income tax expense	(344		)	(75		)	(400		)	(150		)
Net income	21,297			19,128			42,586			38,484
Allocation of net loss attributable to Predecessors	—			2,192			—			4,053
Allocation of net loss (income) attributable to noncontrolling interests	(1,130		)	683			(4,020		)	1,240
Net income attributable to Holly Energy Partners	20,167			22,003			38,566			43,777
General partner interest in net income, including incentive distributions	(6,680		)	(5,894		)	(12,910		)	(11,398		)
Limited partners’ interest in net income	$	13,487		$	16,109		$	25,656		$	32,379
Limited partners’ per unit interest in earnings—basic and diluted	$	0.23		$	0.29		$	0.44		$	0.59
Weighted average limited partners’ units outstanding	58,657			54,722			57,828			54,722

⁽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 June 30,						Six Months Ended June 30,
	2013			2012 (1)			2013			2012 (1)
	(In thousands)
Net income	$	21,297		$	19,128		$	42,586		$	38,484
Allocation of net loss attributable to Predecessors	—			2,192			—			4,053
Net income before noncontrolling interests	21,297			21,320			42,586			42,537
Other comprehensive income (loss):
Change in fair value of cash flow hedge	3,413			(1,508		)	3,975			(1,862		)
Amortization of unrealized loss attributable to discontinued cash flow hedge	—			1,273			849			2,547
Other comprehensive income (loss)	3,413			(235		)	4,824			685
Comprehensive income before noncontrolling interest	24,710			21,085			47,410			43,222
Allocation of comprehensive (income) loss to noncontrolling interests	(1,130		)	683			(4,020		)	1,240
Comprehensive income attributable to Holly Energy Partners	$	23,580		$	21,768		$	43,390		$	44,462

⁽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)

	Six Months Ended June 30,
	2013			2012 (1)
	(In thousands)
Cash flows from operating activities
Net income	$	42,586		$	38,484
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	29,281			28,450
Gain on sale of assets	(2,022		)	—
Amortization of deferred charges	1,910			3,949
Equity in earnings of SLC Pipeline, net of distributions	159			(125		)
Amortization of restricted and performance units	1,880			1,629
(Increase) decrease in operating assets:
Accounts receivable—trade	2,576			(3,443		)
Accounts receivable—affiliates	22			3,331
Prepaid and other current assets	(695		)	(723		)
Increase (decrease) in operating liabilities:
Accounts payable—trade	(518		)	(6,235		)
Accounts payable—affiliates	(301		)	(1,264		)
Accrued interest	88			1,375
Deferred revenue	5,787			(429		)
Accrued property taxes	961			(286		)
Other current liabilities	153			4,711
Other, net	335			342
Net cash provided by operating activities	82,202			69,766
Cash flows from investing activities
Additions to properties and equipment	(17,224		)	(26,374		)
Proceeds from sale of assets	2,481			—
Net cash used for investing activities	(14,743		)	(26,374		)
Cash flows from financing activities
Borrowings under credit agreement	154,500			99,000
Repayments of credit agreement borrowings	(220,500		)	(129,000		)
Proceeds from issuance of senior notes	—			294,750
Proceeds from issuance of common units	73,444			—
Repayment of notes	—			(257,900		)
Contribution from general partner	1,499			—
Contributions from UNEV joint venture partners	—			15,000
Distributions to HEP unitholders	(67,419		)	(59,977		)
Distributions to noncontrolling interest	(2,000		)	—
Purchase of units for incentive grants	(3,254		)	(4,533		)
Deferred financing costs	—			(3,162		)
Other	(250		)	277
Net cash used by financing activities	(63,980		)	(45,545		)
Cash and cash equivalents
Increase for the period	3,479			(2,153		)
Beginning of period	5,237			6,369
End of period	$	8,716		$	4,216

⁽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
Net income	29,753			11,870			—			963			42,586
Other comprehensive income	—			—			4,824			—			4,824
Capital contribution	—			1,499			—			—			1,499
Distributions to HEP unitholders	(54,696		)	(12,723		)	—			—			(67,419		)
Distributions to UNEV joint venture partners	—			—			—			(2,000		)	(2,000		)
Purchase of units for restricted grants	(2,933		)	—			—			—			(2,933		)
Amortization of restricted and performance units	1,880			—			—			—			1,880
Class B unit accretion	(2,996		)	(61		)	—			—			(3,057		)
Other	—			(513		)	—			—			(513		)
Balance June 30, 2013	$	547,261		$	(145,805	)	$	545		$	99,166		$	501,167

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 six months ended June 30, 2012 included in the accompanying financial statements and notes thereto were revised from the amounts previously reported for those periods due to accounting rules that require retrospective restatement of previously reported results in cases of business combinations between entities under common control. We have therefore included herein the results of UNEV prior to our acquisition on July 12, 2012 referred to as results attributable to the Predecessor. See Note 2 below for additional information on the UNEV acquisition. Additional revisions were 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 six months ended June 30, 2012 by $1.2 million and $1.4 million, respectively, and reduced the limited partners' per unit interest in net earnings - basic and diluted by $0.02 and $0.03, respectively, and were comprised principally of an adjustment of depreciation expense related to 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 $17.0 million at June 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 $1.1 million and $4.0 million for the three and six months ended June 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 six months ended June 30, 2012 our consolidated statement of income includes Predecessor revenues from UNEV of $3.9 million and $7.8 million, respectively, and Predecessor net losses of $2.2 million and $4.1 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:

		June 30, 2013				December 31, 2012
Financial Instrument	Fair Value Input Level	Carrying Value		Fair Value		Carrying Value		Fair Value
		(In thousands)
Assets:
Interest rate swaps	Level 2	$	545	$	545	$	—	$	—
Liabilities:
Senior notes:
6.5% senior notes	Level 2	$	295,601	$	294,000	$	295,275	$	321,000
8.25% senior notes	Level 2	148,551		158,625		148,399		163,125
		444,152		452,625		443,674		484,125
Interest rate swaps	Level 2	—		—		3,430		3,430
		$	444,152	$	452,625	$	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:

	June 30, 2013		December 31, 2012
	(In thousands)
Pipelines, terminals and tankage	$	1,061,626	$	1,049,531
Land and right of way	63,196		63,248
Construction in progress	37,032		27,150
Other	18,251		24,462
	1,180,105		1,164,391
Less accumulated depreciation	225,973		203,856
	$	954,132	$	960,535

We capitalized $0.2 million and $0.1 million in interest related to construction projects during the six months ended June 30, 2013 and 2012, respectively.

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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:

	June 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	43,041		39,568
	$	91,123	$	94,596

We have additional transportation agreements with HFC that relate to assets contributed to us or acquired from HFC consisting of pipeline, terminal and tankage assets. 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 $1.7 million for the three months ended June 30, 2013 and 2012, respectively, and $3.8 million and $3.1 million for the six months ended June 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 June 30, 2013, we have two types of incentive-based awards which are described below. The compensation cost charged against income was $0.8 million and $0.7 million for the three months ended June 30, 2013 and 2012, respectively, and $1.9 million and $1.6 million for the six months ended June 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 June 30, 2013, 2,500,000 units were authorized to be granted under our Long-Term Incentive Plan, of which 1,732,433 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 six months ended June 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	37,815	41.18
Vesting and transfer of full ownership to recipients	—	—
Outstanding at June 30, 2013 (nonvested)	96,287	$	35.08

As of June 30, 2013, there was $1.6 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 June 30, 2013, estimated unit payouts for outstanding nonvested performance unit awards were at 100% to 125%.

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 six months ended June 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 June 30, 2013 (nonvested)	62,262

The grant-date fair value of performance units vested and transferred to recipients during the six months ended June 30, 2013 was $0.5 million. As of June 30, 2013, there was $1.4 million of total unrecognized compensation expense related to nonvested performance units, which is expected to be recognized over a weighted-average period of 1.7 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:

	June 30, 2013			December 31, 2012
	(In thousands)
Credit Agreement	$	355,000		$	421,000
6.5% Senior Notes
Principal	300,000			300,000
Unamortized discount	(4,399		)	(4,725		)
	295,601			295,275
8.25% Senior Notes
Principal	150,000			150,000
Unamortized discount	(1,449		)	(1,601		)
	148,551			148,399
Total long-term debt	$	799,152		$	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 June 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 2.50% as of June 30, 2013, which equaled an effective interest rate of 3.49%. 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 2.50% as of June 30, 2013, which equaled an effective interest rate of 3.24%. 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 June 30, 2013, we had no ineffectiveness on our cash flow hedges.

At June 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 six months ended June 30, 2013, $0.5 million and $1.9 million, respectively, of other comprehensive loss was reclassified to interest expense due to cash flow hedge settlements. Approximately $0.1 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)
June 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     assets	$	545	Accumulated other     comprehensive income	$	545
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:

	Six Months Ended June 30,
	2013		2012
	(In thousands)
Interest on outstanding debt:
Credit Agreement, net of interest on interest rate swaps	$	6,043	$	2,953
6.5% Senior Notes	9,755		5,966
6.25% Senior Notes	—		2,422
8.25% Senior Notes	6,193		6,193
Promissory Notes	—		543
Amortization of discount and deferred debt issuance costs	849		2,547
Increase in interest expense - non-cash charges attributable to interest rate swaps	1,063		875
Commitment fees	365		362
Total interest incurred	24,268		21,861
Less capitalized interest	155		132
Net interest expense	$	24,113	$	21,729
Cash paid for interest	$	22,258	$	17,039

We recognized a charge of $3.0 million upon the early extinguishment of debt for the six months ended June 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 95% 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 June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
HFC	84	%	84	%	83	%	83	%
Alon	11	%	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 $63.2 million and $57.8 million for the three months ended June 30, 2013 and 2012, respectively, and $124.7 million and $114.3 million for the six months ended June 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 June 30, 2013 and 2012, respectively, and $1.2 million for the six months ended June 30, 2013 and 2012, respectively.

• We reimbursed HFC for costs of employees supporting our operations of $9.4 million and $7.1 million for the three months ended June 30, 2013 and 2012, respectively, and $19.2 million and $14.8 million for the six months ended June 30, 2013 and 2012, respectively.

• HFC reimbursed us $4.3 million and $2.2 million for the three months ended June 30, 2013 and 2012, respectively, and $9.2 million and $4.7 million for the six months ended June 30, 2013 and 2012, respectively, for certain reimbursable costs and capital projects.

• We distributed $17.4 million and $15.7 million for the three months ended June 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 six months ended June 30, 2013 and 2012 we distributed $34.8 million and $31.0 million, respectively.

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

• Accounts payable to HFC were $4.4 million and $5.0 million at June 30, 2013 and December 31, 2012, respectively.

• Revenues for the three and the six months ended June 30, 2013 include $0.7 million and $4.7 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 June 30, 2013 and December 31, 2012, includes $5.0 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 $5.0 million deferred at June 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 June 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.

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.

Allocations of Net Income

Net income attributable to HEP is allocated between limited partners and the general partner interest in accordance with the provisions of the partnership agreement. HEP net income allocated to the general partner includes incentive distributions that are declared subsequent to quarter end. After 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.

- 17 -

HOLLY ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) Continued

The following table presents the allocation of the general partner interest in net income for the periods presented below:

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(In thousands)
General partner interest in net income	$	275	$	329	$	522	$	661
General partner incentive distribution	6,405		5,565		12,388		10,737
Total general partner interest in net income	$	6,680	$	5,894	$	12,910	$	11,398

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 July 26, 2013 we announced our cash distribution for the second quarter of 2013 of $0.4850 per unit. The distribution is payable on all common and general partner units and will be paid August 14, 2013 to all unitholders of record on August 5, 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 June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(In thousands, except per unit data)
General partner interest in net income	$	737	$	622	$	1,456	$	1,227
General partner incentive distribution	6,405		5,565		12,388		10,737
Total general partner distribution	7,142		6,187		13,844		11,964
Limited partner distribution	28,448		24,899		56,457		49,387
Total regular quarterly cash distribution	$	35,590	$	31,086	$	70,301	$	61,351
Cash distribution per unit applicable to limited partners	$	0.485	$	0.455	$	0.963	$	0.903

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.

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 wholly-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.

- 18 -

HOLLY ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) Continued

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 the current year presentation.

Condensed Consolidating Balance Sheet

June 30, 2013	Parent		Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	2	$	—		$	8,714	$	—		$	8,716
Accounts receivable	—		32,791			3,604		(274		)	36,121
Intercompany accounts receivable (payable)	27,621		(27,621		)	—		—			—
Prepaid and other current assets	81		2,837			1,396		—			4,314
Total current assets	27,704		8,007			13,714		(274		)	49,151
Properties and equipment, net	—		562,282			391,850		—			954,132
Investment in subsidiaries	827,307		297,498			—		(1,124,805		)	—
Transportation agreements, net	—		91,123			—		—			91,123
Goodwill	—		256,498			—		—			256,498
Investment in SLC Pipeline	—		24,882			—		—			24,882
Other assets	1,752		9,173			—		—			10,925
Total assets	$	856,763	$	1,249,463		$	405,564	$	(1,125,079	)	$	1,386,711
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	—	$	11,094		$	2,900	$	(274	)	$	13,720
Accrued interest	10,198		116			—		—			10,314
Deferred revenue	—		5,094			3,507		—			8,601
Accrued property taxes	—		1,349			2,300		—			3,649
Other current liabilities	334		1,657			51		—			2,042
Total current liabilities	10,532		19,310			8,758		(274		)	38,326
Long-term debt	444,152		355,000			—		—			799,152
Other long-term liabilities	78		13,305			142		—			13,525
Deferred revenue	—		17,581			—		—			17,581
Class B unit	—		16,960			—		—			16,960
Equity - partners	402,001		827,307			396,664		(1,223,971		)	402,001
Equity - noncontrolling interest	—		—			—		99,166			99,166
Total liabilities and partners’ equity	$	856,763	$	1,249,463		$	405,564	$	(1,125,079	)	$	1,386,711

- 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 June 30, 2013	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	60,797		$	2,698		$	(308	)	$	63,187
Third parties	—			10,116			1,982			—			12,098
	—			70,913			4,680			(308		)	75,285
Operating costs and expenses:
Operations	—			22,104			2,742			(308		)	24,538
Depreciation and amortization	—			11,543			3,584			—			15,127
General and administrative	983			2,117			—			—			3,100
	983			35,764			6,326			(308		)	42,765
Operating income (loss)	(983		)	35,149			(1,646		)	—			32,520
Equity in earnings (loss) of subsidiaries	29,413			(1,234		)	—			(28,179		)	—
Equity in earnings of SLC Pipeline	—			746			—			—			746
Interest expense	(8,263		)	(3,366		)	—			—			(11,629		)
Interest income	—			3			1			—			4
	21,150			(3,851		)	1			(28,179		)	(10,879		)
Income (loss) before income taxes	20,167			31,298			(1,645		)	(28,179		)	21,641
State income tax expense	—			(344		)	—			—			(344		)
Net income (loss)	20,167			30,954			(1,645		)	(28,179		)	21,297
Allocation of net (income) attributable to noncontrolling interests	—			—			—			(1,130		)	(1,130		)
Net income (loss) attributable to Holly Energy Partners	20,167			30,954			(1,645		)	(29,309		)	20,167
Other comprehensive income	3,413			3,413			—			(3,413		)	3,413
Comprehensive income (loss)	$	23,580		$	34,367		$	(1,645	)	$	(32,722	)	$	23,580

- 21 -

HOLLY ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) Continued

Condensed Consolidating Statement of Comprehensive Income

Three Months Ended June 30, 2012	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	55,263		$	2,776		$	(265	)	$	57,774
Third parties	—			9,752			1,134			—			10,886
	—			65,015			3,910			(265		)	68,660
Operating costs and expenses:
Operations	—			19,121			3,051			(265		)	21,907
Depreciation and amortization	—			10,562			3,588			—			14,150
General and administrative	484			2,003			—			—			2,487
	484			31,686			6,639			(265		)	38,544
Operating income (loss)	(484		)	33,329			(2,729		)	—			30,116
Equity in earnings (loss) of subsidiaries	28,987			(2,046		)	—			(26,941		)	—
Equity in earnings of SLC Pipeline	—			794			—			—			794
Interest expense	(8,309		)	(3,015		)	—			—			(11,324		)
Loss on early extinguishment of debt	(383		)	—			—			—			(383		)
	20,295			(4,267		)	—			(26,941		)	(10,913		)
Income (loss) before income taxes	19,811			29,062			(2,729		)	(26,941		)	19,203
State income tax expense	—			(75		)	—			—			(75		)
Net income (loss)	19,811			28,987			(2,729		)	(26,941		)	19,128
Allocation of net loss attributable to Predecessors	2,192			—			—			—			2,192
Allocation of net loss attributable to noncontrolling interests	—			—			—			683			683
Net income (loss) attributable to Holly Energy Partners	22,003			28,987			(2,729		)	(26,258		)	22,003
Other comprehensive income (loss)	(235		)	(235		)	—			235			(235		)
Comprehensive income (loss)	$	21,768		$	28,752		$	(2,729	)	$	(26,023	)	$	21,768

- 22 -

HOLLY ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) Continued

Condensed Consolidating Statement of Comprehensive Income

Six Months Ended June 30, 2013	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-restricted Subsidiaries		Eliminations				Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	115,210		$	10,100	$	(611	)		$	124,699
Third parties	—			18,523			6,361		—				24,884
	—			133,733			16,461		(611		)		149,583
Operating costs and expenses:
Operations	—			45,471			5,543		(611		)		50,403
Depreciation and amortization	—			22,113			7,168		—				29,281
General and administrative	1,791			4,541			—		—				6,332
	1,791			72,125			12,711		(611		)		86,016
Operating income (loss)	(1,791		)	61,608			3,750		—			—	63,567
Equity in earnings (loss) of subsidiaries	56,872			2,890			—		(59,762		)		—
Equity in earnings of SLC Pipeline	—			1,403			—		—				1,403
Interest expense	(16,515		)	(7,598		)	—		—				(24,113		)
Interest income	—			3			104		—				107
Other	—			2,022			—		—				2,022
	40,357			(1,280		)	104		(59,762		)		(20,581		)
Income before income taxes	38,566			60,328			3,854		(59,762		)		42,986
State income tax expense	—			(400		)	—		—				(400		)
Net income	38,566			59,928			3,854		(59,762		)		42,586
Allocation of net (income) attributable to noncontrolling interests	—			—			—		(4,020		)		(4,020		)
Net income attributable to Holly Energy Partners	38,566			59,928			3,854		(63,782		)		38,566
Other comprehensive income	4,824			4,824			—		(4,824		)		4,824
Comprehensive income	$	43,390		$	64,752		$	3,854	$	(68,606	)		$	43,390

- 23 -

HOLLY ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) Continued

Condensed Consolidating Statement of Comprehensive Income

Six Months Ended June 30, 2012	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	109,293		$	5,540		$	(528	)	$	114,305
Third parties	—			20,497			2,273			—			22,770
	—			129,790			7,813			(528		)	137,075
Operating costs and expenses:
Operations	—			37,262			5,648			(528		)	42,382
Depreciation and amortization	—			21,326			7,124			—			28,450
General and administrative	1,926			2,600			—			—			4,526
	1,926			61,188			12,772			(528		)	75,358
Operating income (loss)	(1,926		)	68,602			(4,959		)	—			61,717
Equity in earnings (loss) of subsidiaries	59,647			(3,719		)	—			(55,928		)	—
Equity in earnings of SLC Pipeline	—			1,625			—			—			1,625
Interest expense	(15,018		)	(6,711		)	—			—			(21,729		)
Loss on early extinguishment of debt	(2,979		)	—			—			—			(2,979		)
	41,650			(8,805		)	—			(55,928		)	(23,083		)
Income (loss) before income taxes	39,724			59,797			(4,959		)	(55,928		)	38,634
State income tax expense	—			(150		)	—			—			(150		)
Net income (loss)	39,724			59,647			(4,959		)	(55,928		)	38,484
Allocation of net loss attributable to Predecessors	4,053			—			—			—			4,053
Allocation of net loss attributable to noncontrolling interests	—			—			—			1,240			1,240
Net income (loss) attributable to Holly Energy Partners	43,777			59,647			(4,959		)	(54,688		)	43,777
Other comprehensive income (loss)	685			685			—			(685		)	685
Comprehensive income (loss)	$	44,462		$	60,332		$	(4,959	)	$	(55,373	)	$	44,462

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HOLLY ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) Continued

Condensed Consolidating Statement of Cash Flows

Six Months Ended June 30, 2013	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities	$	(4,020	)	$	79,182		$	13,040		$	(6,000	)	$	82,202
Cash flows from investing activities
Additions to properties and equipment	—			(16,486		)	(738		)	—			(17,224		)
Proceeds from sale of assets	—			2,481			—			—			2,481
	—			(14,005		)	(738		)	—			(14,743		)
Cash flows from financing activities
Net borrowings under credit agreement	—			(66,000		)	—			—			(66,000		)
Proceeds from issuance of common units	73,444			—			—			—			73,444
Contribution from general partners	1,499			—			—			—			1,499
Distributions to HEP unitholders	(67,419		)	—			—			—			(67,419		)
Distributions to noncontrolling interests	—			—			(8,000		)	6,000			(2,000		)
Purchase of units for incentive grants	(3,254		)	—			—			—			(3,254		)
Other	(250		)	—			—			—			(250		)
	4,020			(66,000		)	(8,000		)	6,000			(63,980		)
Cash and cash equivalents
Increase for the period	—			(823		)	4,302			—			3,479
Beginning of period	2			823			4,412			—			5,237
End of period	$	2		$	—		$	8,714		$	—		$	8,716

Condensed Consolidating Statement of Cash Flows

Six Months Ended June 30, 2012	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations		Consolidated
	(In thousands)
Cash flows from operating activities	$	(45,135	)	$	118,635		$	(3,734	)	$	—	$	69,766
Cash flows from investing activities
Additions to properties and equipment	—			(12,008		)	(14,366		)	—		(26,374		)
Cash flows from financing activities
Net borrowings under credit agreement	—			(30,000		)	—			—		(30,000		)
Proceeds from issuance of senior notes	294,750			—			—			—		294,750
Repayments of notes	(185,000		)	(72,900		)	—			—		(257,900		)
Capital contribution from UNEV joint partners	—			—			15,000			—		15,000
Distributions to HEP unitholders	(59,977		)	—			—			—		(59,977		)
Purchase of units for incentive grants	(4,533		)	—			—			—		(4,533		)
Deferred financing costs	(567		)	(2,595		)	—			—		(3,162		)
Other	462			(185		)	—			—		277
	45,135			(105,680		)	15,000			—		(45,545		)
Cash and cash equivalents
Increase (decrease) for the period	—			947			(3,100		)	—		(2,153		)
Beginning of period	2			3,267			3,100			—		6,369
End of period	$	2		$	4,214		$	—		$	—	$	4,216

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Table of Contentsril 19,

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.

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.

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.

We believe the continuing growth of crude production in the Permian Basin and throughout the Mid-Continent and favorable refining economics should support strong throughput to 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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Table of Contentsril 19,

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 June 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 six months ended June 30, 2013 and 2012.

	Three Months Ended June 30,						Change from
	2013			2012 (1)			2012
	(In thousands, except per unit data)
Revenues:
Pipelines:
Affiliates—refined product pipelines	$	16,952		$	15,520		$	1,432
Affiliates—intermediate pipelines	7,291			6,712			579
Affiliates—crude pipelines	12,187			10,994			1,193
	36,430			33,226			3,204
Third parties—refined product pipelines	9,823			8,857			966
	46,253			42,083			4,170
Terminals, tanks and loading racks:
Affiliates	26,757			24,540			2,217
Third parties	2,275			2,037			238
	29,032			26,577			2,455
Total revenues	75,285			68,660			6,625
Operating costs and expenses:
Operations	24,538			21,907			2,631
Depreciation and amortization	15,127			14,150			977
General and administrative	3,100			2,487			613
	42,765			38,544			4,221
Operating income	32,520			30,116			2,404
Other income (expense):
Equity in earnings of SLC Pipeline	746			794			(48		)
Interest expense, including amortization	(11,629		)	(11,324		)	(305		)
Interest income	4			—			4
Loss on early extinguishment of debt	—			(383		)	383
	(10,879		)	(10,913		)	34
Income before income taxes	21,641			19,203			2,438
State income tax expense	(344		)	(75		)	(269		)
Net income	21,297			19,128			2,169
Allocation of net loss attributable to Predecessors	—			2,192			(2,192		)
Allocation of net loss (income) attributable to noncontrolling interests	(1,130		)	683			(1,813		)
Net income attributable to Holly Energy Partners	20,167			22,003			(1,836		)
General partner interest in net income, including incentive distributions (2)	(6,680		)	(5,894		)	(786		)
Limited partners’ interest in net income	$	13,487		$	16,109		$	(2,622	)
Limited partners’ earnings per unit—basic and diluted(2)	$	0.23		$	0.29		$	(0.06	)
Weighted average limited partners’ units outstanding	58,657			54,722			3,935
EBITDA(3)	$	47,263		$	44,201		$	3,062
Distributable cash flow(4)	$	36,065		$	34,520		$	1,545
Volumes (bpd)
Pipelines:
Affiliates—refined product pipelines	119,519			101,886			17,633
Affiliates—intermediate pipelines	142,406			137,115			5,291
Affiliates—crude pipelines	184,267			168,047			16,220
	446,192			407,048			39,144
Third parties—refined product pipelines	67,044			56,297			10,747
	513,236			463,345			49,891
Terminals and loading racks:
Affiliates	274,040			267,988			6,052
Third parties	59,810			48,825			10,985
	333,850			316,813			17,037
Total for pipelines and terminal assets (bpd)	847,086			780,158			66,928

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Table of Contentsril 19,

	Six Months Ended June 30,						Change from
	2013			2012 (1)			2012
	(In thousands, except per unit data)
Revenues:
Pipelines:
Affiliates—refined product pipelines	$	33,723		$	30,384		$	3,339
Affiliates—intermediate pipelines	13,463			13,757			(294		)
Affiliates—crude pipelines	23,765			21,538			2,227
	70,951			65,679			5,272
Third parties—refined product pipelines	20,166			18,318			1,848
	91,117			83,997			7,120
Terminals, tanks and loading racks:
Affiliates	53,748			48,626			5,122
Third parties	4,718			4,452			266
	58,466			53,078			5,388
Total revenues	149,583			137,075			12,508
Operating costs and expenses:
Operations	50,403			42,382			8,021
Depreciation and amortization	29,281			28,450			831
General and administrative	6,332			4,526			1,806
	86,016			75,358			10,658
Operating income	63,567			61,717			1,850
Other income (expense):
Equity in earnings of SLC Pipeline	1,403			1,625			(222		)
Interest expense, including amortization	(24,113		)	(21,729		)	(2,384		)
Interest income	107			—			107
Loss on early extinguishment of debt	—			(2,979		)	2,979
Gain on sale of assets	2,022			—			2,022
	(20,581		)	(23,083		)	2,502
Income before income taxes	42,986			38,634			4,352
State income tax expense	(400		)	(150		)	(250		)
Net income	42,586			38,484			4,102
Allocation of net loss attributable to Predecessors	—			4,053			(4,053		)
Allocation of net loss (income) attributable to noncontrolling interests	(4,020		)	1,240			(5,260		)
Net income attributable to Holly Energy Partners	38,566			43,777			(5,211		)
General partner interest in net income, including incentive distributions (2)	12,910			11,398			1,512
Limited partners’ interest in net income	$	25,656		$	32,379		$	(6,723	)
Limited partners’ earnings per unit—basic and diluted(2)	$	0.44		$	0.59		$	(0.15	)
Weighted average limited partners’ units outstanding	57,828			54,722			3,106
EBITDA(3)	$	92,253		$	89,626		$	2,627
Distributable cash flow(4)	$	68,450		$	71,075		$	(2,625	)
Volumes (bpd)
Pipelines:
Affiliates—refined product pipelines	106,904			99,556			7,348
Affiliates—intermediate pipelines	131,651			130,341			1,310
Affiliates—crude pipelines	165,203			160,855			4,348
	403,758			390,752			13,006
Third parties—refined product pipelines	60,054			60,292			(238		)
	463,812			451,044			12,768
Terminals and loading racks:
Affiliates	267,179			265,109			2,070
Third parties	57,647			50,604			7,043
	324,826			315,713			9,113
Total for pipelines and terminal assets (bpd)	788,638			766,757			21,881

(1) The financial amounts presented here have been restated from those we previously reported for this period. See Note 1 in 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 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.

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Table of Contentsril 19,

(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 June 30,						Six Months Ended June 30,
	2013			2012 (1)			2013			2012 (1)
	(In thousands)
Net income attributable to Holly Energy Partners	$	20,167		$	22,003		$	38,566		$	43,777
Add:
Interest expense	11,096			9,547			22,201			18,307
Interest income	(4		)	—			(107		)	—
Amortization of discount and deferred debt issuance costs	533			503			1,063			875
Loss on early extinguishment of debt	—			383			—			2,979
Increase in interest expense - non-cash charges attributable to interest rate swaps	—			1,274			849			2,547
State income tax	344			75			400			150
Depreciation and amortization	15,127			14,150			29,281			28,450
Predecessor depreciation and amortization	—			(3,734		)	—			(7,459		)
EBITDA	$	47,263		$	44,201		$	92,253		$	89,626

(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 June 30,						Six Months Ended June 30,
	2013			2012 (1)			2013			2012 (1)
	(In thousands)
Net income attributable to Holly Energy Partners	$	20,167		$	22,003		$	38,566		$	43,777
Add (subtract):
Depreciation and amortization	15,127			14,150			29,281			28,450
Predecessor depreciation and amortization	—			(3,734		)	—			(7,459		)
Amortization of discount and deferred debt issuance costs	533			503			1,063			875
Loss on early extinguishment of debt	—			383			—			2,979
Increase in interest expense - non-cash charges attributable to interest rate swaps	—			1,274			849			2,547
Increase (decrease) in deferred revenue attributable to shortfall billings	1,375			163			152			(429		)
Billed crude revenue settlement	—			917			918			1,835
Maintenance capital expenditures (5)	(2,176		)	(1,292		)	(4,512		)	(1,599		)
Other non-cash adjustments	1,039			153			2,133			99
Distributable cash flow	$	36,065		$	34,520		$	68,450		$	71,075

(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.

(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.

	June 30, 2013		December 31, 2012
	(In thousands)
Balance Sheet Data
Cash and cash equivalents	$	8,716	$	5,237
Working capital	$	10,825	$	11,826
Total assets	$	1,386,711	$	1,394,110
Long-term debt	$	799,152	$	864,674
Partners’ equity (6)	$	402,001	$	352,653

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

Summary

Net income for the second quarter was $21.3 million compared to $19.1 million for the second quarter of 2012. The increase in net income is due principally to increased pipeline shipments and annual tariff increases, partially offset by increased operating costs and expenses. Net income attributable to Holly Energy Partners for the second quarter was $20.2 million compared to $22.0 million for the second quarter of 2012. The 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 June 30, 2013 include the recognition of $0.7 million of prior shortfalls billed to shippers in 2012. Deficiency payments of $2.8 million associated with certain guaranteed shipping contracts were deferred during the three months ended June 30, 2013. Such deferred revenue will be recognized in earnings either as payment for shipments in excess

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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 $75.3 million, a $6.6 million increase compared to the second quarter of 2012. The revenue increase was due to increased pipeline shipments and the effect of annual tariff increases. Overall pipeline volumes were up 11% compared to the three months ended June 30, 2012.

Revenues from our refined product pipelines were $26.8 million, an increase of $2.4 million primarily due to increased refined product shipments and the effect of annual tariff increases. Shipments averaged 186.6 thousand barrels per day (“mbpd”) compared to 158.2 mbpd for the second quarter of 2012.

Revenues from our intermediate pipelines were $7.3 million, an increase of $0.6 million, on shipments averaging 142.4 mbpd compared to 137.1 mbpd for the second quarter of 2012.

Revenues from our crude pipelines were $12.2 million, an increase of $1.2 million, on shipments averaging 184.3 mbpd compared to 168.0 mbpd for the second quarter of 2012.

Revenues from terminal, tankage and loading rack fees were $29.0 million, an increase of $2.5 million compared to the second quarter of 2012. Refined products terminalled in our facilities averaged 333.9 mbpd compared to 316.8 mbpd for the second quarter of 2012.

Operations Expense

Operations expense for the three months ended June 30, 2013 increased by $2.6 million compared to the three months ended June 30, 2012. This increase is due to higher maintenance costs, environmental accruals and employee costs.

Depreciation and Amortization

Depreciation and amortization for the three months ended June 30, 2013 increased by $1.0 million compared to the three months ended June 30, 2012 due to asset abandonment charges related to tankage.

General and Administrative

General and administrative costs for the three months ended June 30, 2013 increased by $0.6 million compared to the three months ended June 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 $0.7 million for the three months ended June 30, 2013 compared to $0.8 million for the three months ended June 30, 2012.

Interest Expense

Interest expense for the three months ended June 30, 2013 totaled $11.6 million, an increase of $0.3 million compared to the three months ended June 30, 2012. Our aggregate effective interest rates were 5.8% and 7.3% for the three months ended June 30, 2013 and 2012, respectively.

Loss on Early Extinguishment of Debt

We recognized a charge of $0.4 million upon the early extinguishment of our 6.25% senior notes for the three months ended June 30, 2012.

State Income Tax

We recorded state income tax expense of $344,000 for the three months ended June 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 change also resulted in a one-time charge of $336,000 to establish a deferred tax liability. For the three months ended June 30, 2012, we recorded state income tax expense of $75,000.

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Results of Operations—Six Months Ended June 30, 2013 Compared with Six Months Ended June 30, 2012

Summary

Net income attributable to Holly Energy Partners for the six months ended June 30, 2013 was $38.6 million, a $5.2 million decrease compared to the six months ended June 30, 2012. This decrease in earnings is due principally to increased costs and expenses and income allocations to noncontrolling interests, partially offset by revenue increases. Revenue increased for the six months ended June 30, 2013 due to overall increased pipeline shipments, 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, contributing to the lower 2013 six months earnings.

Revenues for the six months ended June 30, 2013 include the recognition of $7.3 million of prior shortfalls billed to shippers in 2012. Deficiency payments of $7.3 million associated with certain guaranteed shipping contracts were deferred during the six months ended June 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 six months ended June 30, 2013 were $149.6 million, a $12.5 million increase compared to the first six months ended June 30, 2012. This is due principally to a $4.8 million increase in deferred revenue realized, increased pipeline shipments in the second quarter and the effect of annual tariff increases.

Revenues from our refined product pipelines were $53.9 million, an increase of $5.2 million primarily due to the effects of a $5.6 million increase in deferred revenue realized. Shipments averaged 167.0 thousand barrels per day (“mbpd”) compared to 159.8 mbpd for the six months ended June 30, 2012.

Revenues from our intermediate pipelines were $13.5 million, a decrease of $0.3 million, on shipments averaging 131.7 mbpd compared to 130.3 mbpd for the six months ended June 30, 2012. The decrease in revenue is due to the effects of a $0.7 million decrease in deferred revenue realized.

Revenues from our crude pipelines were $23.8 million, an increase of $2.2 million, on shipments averaging 165.2 mbpd compared to 160.9 mbpd for the six months ended June 30, 2012.

Revenues from terminal, tankage and loading rack fees were $58.5 million, an increase of $5.4 million compared to the six months ended June 30, 2012. This increase is due principally to increased tankage revenues. Refined products terminalled in our facilities averaged 324.8 mbpd compared to 315.7 mbpd for the six months ended June 30, 2012.

Operations Expense

Operations expense for the six months ended June 30, 2013 increased by $8.0 million compared to the six months ended June 30, 2012. This increase is due to higher maintenance costs, environmental accruals and employee costs.

Depreciation and Amortization

Depreciation and amortization for the six months ended June 30, 2013 increased by $0.8 million compared to the six months ended June 30, 2012 due to asset abandonment charges related to tankage.

General and Administrative

General and administrative costs for the six months ended June 30, 2013 increased by $1.8 million compared to the six months ended June 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 $1.4 million for the six months ended June 30, 2013 compared to $1.6 million for the six months ended June 30, 2012.

Interest Expense

Interest expense for the six months ended June 30, 2013 totaled $24.1 million, an increase of $2.4 million compared to the six months ended June 30, 2012. This increase reflects interest on a year-over-year increase in debt levels. Our aggregate effective interest rates were 5.8% and 7.4% for the six months ended June 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 six months ended June 30, 2012.

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Gain on Sale of Assets

Gain on sale of assets for the six months ended June 30, 2013 of $2.0 million is a gain on the sale of property in El Paso, Texas.

State Income Tax

We recorded state income tax expense of $400,000 for the six months ended June 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 change also resulted in a one-time charge of $336,000 to establish a deferred tax liability. For the six months ended June 30, 2012, we recorded state income tax expense of $150,000.

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 six months ended June 30, 2013, we received advances totaling $154.5 million and repaid $220.5 million under the Credit Agreement, resulting in net repayments of $66.0 million and an outstanding balance of $355.0 million at June 30, 2013.

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 to fund capital expenditures.

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 May 2013, we paid regular quarterly cash distributions of $0.4775, on all units in an aggregate amount of $67.4 million. Included in these distributions were $6.0 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 $3.5 million during the six months ended June 30, 2013. The cash flows provided by operating activities of $82.2 million was greater than the cash flows used for financing and investing activities of $64.0 million and $14.7 million, respectively. Working capital decreased by $1.0 million to $10.8 million at June 30, 2013 from $11.8 million at December 31, 2012.

Cash Flows—Operating Activities

Cash flows from operating activities increased by $12.4 million from $69.8 million for the six months ended June 30, 2012 to $82.2 million for the six months ended June 30, 2013. This increase is due principally to $16.7 million in additional cash collections from our customers partially offset by payments attributable to increased operating expenses.

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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 $7.3 million during 2012 related to shortfalls that subsequently expired without recapture and were recognized as revenue during the six months ended June 30, 2013. Another $7.4 million is included in our accounts receivable at June 30, 2013 related to shortfalls that occurred during the six months ended June 30, 2013.

Cash Flows—Investing Activities

Cash flows used for investing activities decreased by $11.6 million from $26.4 million for the six months ended June 30, 2012 to $14.7 million for the six months ended June 30, 2013. During the six months ended June 30, 2013 and 2012, we invested $17.2 million and $26.4 million in additions to properties and equipment, respectively. The decrease is attributable to capital costs incurred in early 2012 in completion of the UNEV Pipeline. During the six months ended June 30, 2013, we received $2.5 million proceeds from the sale of assets.

Cash Flows—Financing Activities

Cash flows used for financing activities were $64.0 million for the six months ended June 30, 2013 compared to $45.5 million for the six months ended June 30, 2012, an increase of $18.4 million. During the six months ended June 30, 2013, we received $154.5 million and repaid $220.5 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 $67.4 million in regular quarterly cash distributions to our general and limited partners, and paid $3.3 million for the purchase of common units for recipients of our incentive grants. Also we paid $2.0 million to the UNEV noncontrolling interest joint venture partner. During the six months ended June 30, 2012, we received $99.0 million and repaid $129.0 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. Additionally, we paid $60.0 million in regular quarterly cash distributions to our general and limited partners, we received $15.0 million from UNEV's joint venture partners, paid $3.2 million in financing costs to amend our Credit Agreement and paid $4.5 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 will provide shippers with additional pipeline takeaway capacity to either common carrier pipeline stations for transportation to major crude oil markets or to HFC's New Mexico refining facilities. To complete the project, we will 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.  

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UNEV is proceeding with a project to add certain enhancements to its product terminal in Las Vegas, Nevada.  The project will cost approximately $13 million with construction scheduled to be completed during 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 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. The project 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 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 in the third quarter of 2013.

HFC and we are collaborating to evaluate the construction of a rail facility that will enable crude oil loading and unloading near HFC's Artesia and/or Lovington, New Mexico refining facilities.  The rail project, which will be connected to our crude oil pipeline transportation system in southeastern New Mexico, will have an initial capacity of up to 70,000 barrels per day and will 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 will 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.

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.

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 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 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.

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.

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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:

	June 30, 2013			December 31, 2012
	(In thousands)
Credit Agreement	$	355,000		$	421,000
6.5% Senior Notes
Principal	300,000			300,000
Unamortized discount	(4,399		)	(4,725		)
	295,601			295,275
8.25% Senior Notes
Principal	150,000			150,000
Unamortized discount	(1,449		)	(1,601		)
	148,551			148,399
Total long-term debt	$	799,152		$	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 six months ended June 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.

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,

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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 June 30, 2013, we have an accrual of $3.6 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 June 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 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 2.50% as of June 30, 2013, which equaled an effective interest rate of 3.49%. 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 2.50% as of June 30, 2013, which equaled an effective interest rate of 3.24%. 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.

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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 June 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 June 30, 2013, the fair values of our 6.5% and 8.25% Senior Notes were $294.0 million and $158.6 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 June 30, 2013 would result in a change of approximately $10.8 million and $4.2 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 June 30, 2013, borrowings outstanding under the Credit Agreement were $355.0 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 $50.0 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 June 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

(c) Common Unit Repurchases Made in the Quarter

The following table discloses purchases of our common units made by us or on our behalf for the periods shown below.

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
April 2013	214	$	40.73	—	$	—
May 2013	—	$	—	—	$	—
June 2013	—	$	—	—	$	—
Total for April to June 2013	214			—

The units reported represent purchases settled during the three months ended June 30, 2013 related to withholdings made under the terms of our equity award agreements to provide funds for the payment of payroll and income taxes due at vesting in the case of officers and employees who did not elect to satisfy such taxes by other means.

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: August 1, 2013	/s/    Douglas S. Aron
	Douglas S. Aron
	Executive Vice President and Chief Financial Officer (Principal Financial Officer)
Date: August 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.
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 June 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.

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

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EX-10.3

EXECUTION VERSION

SECOND AMENDED AND RESTATED

CRUDE PIPELINES AND TANKAGE AGREEMENT

This Second Amended and Restated Crude Pipelines and Tankage Agreement (this “Agreement”) is being entered into on July 16, 2013, by and among:

1. Navajo Refining Company, L.L.C., a Delaware limited liability company (“Navajo Refining”),

2. Holly Refining & Marketing Company – Woods Cross LLC (formerly Holly Refining & Marketing Company – Woods Cross), a Delaware limited liability company (“Holly Refining – Woods Cross”), and

3. HollyFrontier Refining & Marketing LLC (formerly known as Holly Refining & Marketing Company), a Delaware limited liability company (“HFRM”, together with Navajo Refining and Holly-Refining – Woods Cross, the “HollyFrontier Entities”),

4. Holly Energy Partners-Operating, L.P., a Delaware limited partnership (the “Operating Partnership”),

5. HEP Pipeline, LLC, a Delaware limited liability company (“HEP Pipeline”), and

6. HEP Woods Cross, L.L.C., a Delaware limited liability company (“HEP Woods Cross”, together with the Operating Partnership and HEP Pipeline, the “Partnership Entities”).

This Agreement amends and restates in its entirety the First Amended Pipelines Agreement. Each of the HollyFrontier Entities and the Partnership Entities are individually referred to herein as a “Party” and collectively as the “Parties.”

RECITALS:

WHEREAS, pursuant to that certain Purchase and Sale Agreement dated as of February 25, 2008 (the “Purchase Agreement”) by and among Holly, Navajo Refining, Navajo Pipeline and Woods Cross Refining (collectively, the “Seller Parties”) and the Partnership, the Operating Partnership, HEP Pipeline and HEP Woods Cross (collectively, the “Buyer Parties”), the Seller Parties transferred and conveyed to the Buyer Parties, and the Buyer Parties acquired, certain assets, including certain of the Drop-Down Assets;

WHEREAS, in connection with the closing of the transactions contemplated by the Purchase Agreement the Seller Parties and the Buyer Parties entered into the Original Pipelines Agreement, pursuant to which the Seller Parties continued to transport Crude Oil and Refined Product in the Drop-Down Assets and the Partnership provides transportation services to the Seller Parties;

WHEREAS, in connection with that certain Asset Purchase Agreement dated as of December 1, 2009by and among Holly, Navajo Pipeline, and HEP Pipeline, Navajo Pipeline transferred and conveyed to HEP Pipeline the Beeson Pipeline, the HollyFrontier Entities and the Partnership Entities amended and restated the Original Pipelines Agreement and entered into the First Amended Pipelines Agreement to, among other things, address lease connection expenses and provide for a volume incentive tariff;

WHEREAS, on November 16, 2011, the HollyFrontier Entities and the Partnership Entities entered into that certain Letter Agreement regarding the First Amended Pipelines Agreement (the “Letter Agreement”) to, among other things, clarify the method by which certain payments due from the HollyFrontier Entities to the Partnership Entities pursuant to the First Amended Pipelines Agreement are calculated; and

WHEREAS, in connection with the Malaga TSA, the Parties desire to amend and restate the First Amended Pipelines Agreement, as supplemented by the Letter Agreement, as provided herein.

NOW, THEREFORE, in consideration of the covenants and obligations contained herein, the Parties hereby agree as follows:

Section 1.Definitions

Capitalized terms used throughout this Agreement and not otherwise defined herein shall have the meanings set forth in Annex A.

Section 1.Agreement to Use Services Relating to Pipelines and Tankage.

This Agreement sets forth a commercial arrangement consistent with historical operational practices between the HollyFrontier Entities and the Partnership Entities as well as the objectives of the Parties. The Parties intend to be strictly bound by the terms set forth in this Agreement, which sets forth revenues to the Partnership Entities to be paid by the HollyFrontier Entities and requires the Partnership Entities to provide certain transportation and storage services to the HollyFrontier Entities. The principal objective of the Partnership Entities is for the HollyFrontier Entities to meet or exceed their obligations with respect to the Minimum Pipeline Revenue Commitment, and to meet their obligations with respect to the Tankage Revenue Commitment and the Roswell Terminal Payment. The principal objective of the HollyFrontier Entities is for the Partnership Entities to provide services to the HollyFrontier Entities in a manner that enables the HollyFrontier Entities to operate their assets in a manner as favorably as their historical practice when the HollyFrontier Entities were the owners of the Drop-Down Assets.

(a)Minimum Pipeline Revenue Commitment. During the Term and subject to the terms and conditions of this Agreement, the HollyFrontier Entities agree as follows:

(i)Minimum Pipeline Revenue Commitment. Subject to Section 3, the HollyFrontier Entities will ship the Product indicated in the following table, using the Pipeline Asset indicated for such Product, which shipments will, in the aggregate, have the

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quantity and consistency that will produce the revenue per Contract Year or Contract Quarter indicated in the final column as a result of the tariffs charged to the HollyFrontier Entities under this Agreement (in each case, as may be adjusted pursuant to Section 2(q)(i) and Schedule I attached hereto):

Pipeline Assets	Product	Minimum Revenue to Partnership Entities for Shipments on such Pipeline Assets
Crude Oil Trunk Pipelines	Crude Oil	$13,552,450 per Contract Year (the “Minimum Trunk Pipeline Revenue Commitment”)
Crude Oil Gathering Pipelines and store at the Artesia Crude Oil Pipeline Tankage and the Lovington Crude Oil Pipeline Tankage	Crude Oil	$9,125,000 per Contract Year  (the “Minimum Gathering Pipeline Revenue Commitment”)
Woods Cross Pipelines	Crude Oil and Refined Product	$730,000 per Contract Year (the “Minimum Woods Cross Pipeline Revenue Commitment”)
Roswell Products Pipeline	Refined Product	$35,000 per Contract Quarter (the “Minimum Roswell Pipeline Revenue Commitment”)

Notwithstanding the foregoing, in the event that the end of the Term occurs on any date other than the final day of a Contract Year or Contract Quarter (as applicable), then the Minimum Trunk Pipeline Revenue Commitment, Minimum Gathering Pipeline Revenue Commitment, Minimum Woods Cross Pipeline Revenue Commitment, and Minimum Roswell Pipeline Revenue Commitment for the final Contract Year or Contract Quarter (as applicable) shall each be prorated based upon the number of days actually in such contract year or contract quarter and the final Contract Year or Contract Quarter (as applicable). The amount of the Minimum Trunk Pipeline Revenue Commitment, Minimum Gathering Pipeline Revenue Commitment, Minimum Woods Cross Pipeline Revenue Commitment and Minimum Roswell Pipeline Revenue Commitment applicable to each Contract Quarter shall be calculated by multiplying the annual revenue commitment for each such amount set forth on Schedule I by a fraction, the numerator of which shall be actual number of days in such Contract Quarter and the denominator of which shall be the total number of days in the Contract Year in which such Contract Quarter is included.

(ii)Service Disruption. If the HollyFrontier Entities are unable for a period in excess of thirty (30) consecutive days to transport on any of the Pipeline Assets the respective volumes of Crude Oil and Refined Product required to meet the Minimum Pipeline Revenue Commitment as a result of the Partnership Entities’ operational difficulties, prorationing, or the inability to provide the following minimum capacities during such thirty (30) day consecutive period:

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Pipeline Assets	Minimum Capacity
Crude Oil Trunk Pipelines	79,000 bpd (the “Trunk Pipeline Minimum Capacity”)
Crude Oil Gathering Pipelines (including storage in the Artesia Crude Oil Pipeline Tankage and Lovington Crude Oil Pipeline Tankage, but excluding storage in the Refinery Tankage)	Effective Time until the fifth anniversary of the Effective Time: 50,000 bpd capacity; Commencing on the fifth anniversary of the Effective Time until the tenth anniversary of the Effective Time: 47,500 bpd capacity; and Commencing on the tenth anniversary of the Effective Time until the expiration of the Term: 45,000 bpd capacity (collectively, the “Gathering Pipeline Minimum Capacity”)
Woods Cross Pipelines	8,000 bpd capacity (the “Woods Cross Minimum Capacity”)
Roswell Products Pipeline	a proportionate amount of 36,000 bpq capacity (the “Roswell Pipeline Minimum Capacity”)

then upon written notice by the HollyFrontier Entities to the Partnership Entities (which notice shall be given reasonably promptly after the expiration of such 30 day consecutive period), the Minimum Pipeline Revenue Commitment, as affected, will be reduced for such period of time by an amount equal to: (A) the volume of Crude Oil or Refined Product that the HollyFrontier Entities were unable to transport on any of the Pipeline Assets, as applicable, as a result of the Partnership Entities’ operational difficulties, prorationing or inability to provide the Trunk Pipeline Minimum Capacity, the Gathering Pipeline Minimum Capacity, the Woods Cross Minimum Capacity or the Roswell Pipeline Minimum Capacity, as applicable, multiplied by (B) the applicable tariffs. This Section 2(a)(ii) shall not apply in the event the Partnership Entities give notice of a Force Majeure event in accordance with Section 3, in which case the HollyFrontier Entities’ Minimum Pipeline Revenue Commitment shall be suspended in accordance with and as provided in Section 3.

(b)Tariffs and Tankage Fees.

(i)Tariff Rates. The HollyFrontier Entities shall pay to the Partnership Entities the applicable tariff rates (as such tariff rate may be revised pursuant to Section 2(q)(ii)) for making shipments of Crude Oil and/or Refined Product on the Pipeline Assets pursuant to this Agreement, as follows (in each case, as such exhibit may be amended from time-to-time in accordance with this Agreement):

(A) service on the Crude Oil Trunk Pipelines as set forth in Exhibit A attached hereto;

(B) service on the Crude Oil Gathering Pipelines as set forth in Exhibit B attached hereto;

(C) service on the Woods Cross Pipelines as set forth in Exhibit C attached hereto;and

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(D) service on Roswell Product Pipeline as set forth in Exhibit D attached hereto.

The rules and regulations governing service on the Pipeline Assets shall be as set forth in the applicable rules and regulations tariffs with respect to such service. The Partnership Entities shall have the right to change the tariff rates applicable to the Pipeline Assets in the event that the Partnership Entities incur increased expenses (or lower revenues) or capital costs, as a direct result of a change in the quality and/or consistency of the Crude Oil or Refined Product, as applicable, and to the extent thereof.

(ii)Renegotiation of Tariff Rates. In the event that Crude Oil throughput at the Artesia Refinery and/or the Lovington Refinery exceeds 110,000 bpd or if Crude Oil viscosity exceeds 50 SSU on greater than 10,000 bpd of such Crude Oil throughput at the Artesia Refinery and/or the Lovington Refinery, and the Partnership Entities incur increased expenses (or lower revenues) or capital costs, as a direct result thereof, the Parties will renegotiate the tariff rates in good faith in order to compensate the Partnership Entities on account of such incremental expenses (or lower revenues) or capital costs, which capital costs shall also include a reasonable rate of return. If the HollyFrontier Entities and the Partnership Entities are unable to agree upon renegotiated tariff rates, the renegotiated tariff rates will be determined by binding arbitration in accordance with Section 12(e) of this Agreement.

(iii)Volume Incentive Tariff. The HollyFrontier Entities shall receive a volume incentive tariff of $0.4246 per barrel as of the date hereof to June 30, 2013, as such incentive may be revised pursuant to Section 2(q)(ii) and Schedule II attached hereto (the “Volume Incentive Tariff”) under the then current applicable tariff on volumes greater than the applicable minimum volumes necessary to meet the portion of the Minimum Gathering Pipeline Revenue Commitment to be shipped during a Contract Quarter, which shall be determined and applied on a quarterly basis for purposes of this Section 2(b)(iii).

(c)Tankage Revenue Commitment. During the Term the HollyFrontier Entities shall pay the Partnership Entities throughput fees associated with the Refinery Tankage in the amount of $184,000 per month as such amount may be revised pursuant to Section 2(q)(ii) and Schedule III attached hereto (the “Tankage Revenue Commitment”) in exchange for the Partnership Entities providing to the HollyFrontier Entities 613,333 barrels per month of crude oil storage capacity at the Refinery Tankage. .

(d)Roswell Terminal Operating Expenses and Payment. During the Term and subject to the terms and conditions of this Agreement, the HollyFrontier Entities shall (i) reimburse all operating expenses incurred by the Partnership Entities in their operation of the Roswell Terminal in an economic and prudent manner, in accordance with the normal and customary practices in the industry and Applicable Laws, and consistent with the historical operation of the Roswell Terminal by the HollyFrontier Entities, and (ii) make annual payment to the Partnership Entities in the amount of $100,000 as such amount may be revised pursuant to Section 2(q)(i) and Schedule IV attached hereto (such annual payment, the “Roswell Terminal Payment”).

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(e)Volumetric Gains and Losses. The HollyFrontier Entities shall, during the Term, (i) absorb all volumetric gains in the Crude Oil Trunk Pipelines and Crude Oil Gathering Pipelines, and (ii) be responsible for all volumetric losses in the Crude Oil Trunk Pipelines and the Crude Oil Gathering Pipelines up to a maximum of 0.5%. The Partnership Entities shall be responsible for all volumetric losses in excess of 0.5% in the Crude Oil Trunk Pipelines and Crude Oil Gathering Pipelines during the Term.

(f)Obligations of the Partnership Entities. During the Term and subject to the terms and conditions of this Agreement, including Section 12(b), the Partnership Entities agree to own or lease, operate and maintain the assets necessary to accept the deliveries from the HollyFrontier Entities and to provide the services required under this Agreement. Notwithstanding the preceding sentence, subject to Section 12(b) of this Agreement and Article V of the Omnibus Agreement, the Partnership Entities are free to sell any of their assets, including assets that provide services under this Agreement, and the Partnership or any of the Partnership Entities are free to merge with another entity (whether or not the Partnership or any of the Partnership Entities is the surviving entity in such merger) and are free to sell all of their assets, including assets that provide services under this Agreement, or all of their equity to another entity at any time. The Partnership Entities shall, upon six (6) months’ prior written notice to the HollyFrontier Entities, except in the event of an emergency or in order to comply with Applicable Law, have the right to discontinue operation with respect to any of the Crude Oil Gathering Pipelines in the event that such operation becomes (i) mechanically unreliable or (ii) uneconomical due to a decline in volume. At the request of the HollyFrontier Entities, and subject in each case to any applicable common carrier proration duties, the Partnership Entities agree to use commercially reasonable efforts to transport by pipeline for the HollyFrontier Entities each month during the Term: (i) quantities of Crude Oil equal to the Trunk Pipeline Minimum Capacity on the Crude Oil Trunk Pipelines; (ii) quantities of Crude Oil equal to the Gathering Pipeline Minimum Capacity on the Crude Oil Gathering Pipelines; (iii) quantities of Crude Oil and Refined Product equal to the Woods Cross Minimum Capacity, collectively, on the Woods Cross Pipelines; and (iv) quantities of Refined Product equal to the Roswell Pipeline Minimum Capacity on the Roswell Products Pipeline. To the extent that the HollyFrontier Entities are entitled to an exception under Section 3 to their obligations under Section 2(a), the corresponding obligations of the Partnership Entities under this Section 2(f) will be proportionately reduced.

(g)Drag Reducing Agents and Additives. If the Partnership Entities determine that adding drag reducing agents (“DRA”) and additives to the Crude Oil and Refined Products is reasonably required to move Crude Oil and Refined Product in the quantities necessary to meet the HollyFrontier Entities’ schedule or as may be otherwise be required to safely move such quantities of Crude Oil and Refined Product, the Partnership Entities shall provide the HollyFrontier Entities with an analysis of the proposed cost and benefits thereof. In the event that the HollyFrontier Entities agree to use such additives as proposed by the Partnership Entities, the HollyFrontier Entities shall reimburse the Partnership Entities for the costs of adding any additive, including DRA and/or other additives to the Crude Oil and Refined Product. All fuel additives, anti-icers and DRA (collectively,“Additives”) added to the Crude Oil and Refined Product pursuant to this Section 2(g) will be provided by the HollyFrontier Entities at no cost to the Partnership Entities or, if the Partnership Entities provide Additives, then the HollyFrontier Entities agree to reimburse the Partnership Entities for the costs of the Additives.

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(h)Reimbursement for Initial Tank Inspections. The HollyFrontier Entities will, during the period that commences on the Effective Time and ends five (5) years thereafter (the “Initial Tank Inspection Period”), reimburse the Partnership Entities for the actual costs incurred by the Partnership Entities in performing the first regularly scheduled API 653 inspection conducted after the Effective Time of the tanks included within the Tankage Assets (the “Initial Tank Inspections”), and any repairs or tests or consequential remediation that may be required to be made to such Tankage Assets as a result of any discovery made during the Initial Tank Inspections; provided, however, that (i) the HollyFrontier Entities are not obligated to reimburse the Partnership Entities for any costs associated with or arising from any inspection of Relocated Tank 437 or Replacement Tank 439, and (ii) upon expiration of the Initial Tank Inspection Period, all of the obligations of the HollyFrontier Entities pursuant to this Section 2(h) shall terminate, except that the Initial Tank Inspection Period shall be extended if, and only to the extent that (a) inaccessibility of the Tankage Assets during the Initial Tank Inspection Period caused the delay of an Initial Tank Inspection originally scheduled to be performed during the Initial Tank Inspection Period, and (b) the HollyFrontier Entities received notice from the Partnership Entities regarding such delay at the time it occurred.

(i)Taxes. The HollyFrontier Entities will pay all taxes, import duties, license fees and other charges by any Governmental Authority levied on or with respect to the Crude Oil and Refined Product delivered by the HollyFrontier Entities for transportation by the Partnership Entities in the Pipeline Assets including, but not limited to, any New Mexico gross receipts and compensating (use) taxes. The HollyFrontier Entities will reimburse the Partnership Entities for the New Mexico gross receipts tax, but not income tax, levied on or with respect to the transportation services provided by the Partnership Entities to the HollyFrontier Entities under this Agreement. Should any Party be required to pay or collect any taxes, duties, charges and or assessments pursuant to any Applicable Law or authority now in effect or hereafter to become effective which are payable by the any other Party pursuant to this Section 2(i) the proper Party shall promptly reimburse the other Party therefor.

(j)Timing of Payments. The HollyFrontier Entities will make payments to the Partnership Entities by electronic payment with immediately available funds on a monthly basis during the Term with respect to services rendered or reimbursable costs or expenses incurred by the Partnership Entities under this Agreement in the prior month. Payments not received by the Partnership Entities on or prior to the applicable payment date will accrue interest at the Prime Rate from the applicable payment date until paid.

(k)Marketing of Transportation and Storage Services. The Partnership Entities may market transportation and storage services to third parties on the Crude Oil Trunk Pipelines or the Crude Oil Gathering Pipelines, providedthat (i) the Partnership Entities provide the HollyFrontier Entities with prior written notice describing the purported transportation and/or storage services to the extent permitted by Applicable Law; and (ii) the HollyFrontier Entities remain satisfied that such transportation and storage services marketed by the Partnership Entities has not negatively affected the HollyFrontier Entities’ ability to utilize the Drop-Down Assets in any material respect and the quality and quantity of the Crude Oil has not been materially degraded or otherwise impaired.

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(l)Change in Pipeline Direction; Product Service or Origination and Destination. Without the HollyFrontier Entities’ prior written consent, which shall not be unreasonably withheld, the Partnership Entities shall not (i) reverse the direction of any of the Pipeline Assets; (ii) change, alter or modify the product service of any of the Pipeline Assets; or (iii) change, alter or modify the origination or destination of any of the Pipeline Assets; provided, however, that the Partnership Entities may take any necessary emergency action to prevent or remedy a release of Crude Oil or Refined Product, as applicable, from any of the Pipeline Assets without obtaining the consent required by this Section 2(l). The HollyFrontier Entities shall have the right to reverse the direction of any of the Pipeline Assets if the HollyFrontier Entities agree to (i) reimburse the Partnership Entities for the additional costs and expenses incurred by the Partnership Entities as a result of such change in direction (both to reverse and re-reverse); (ii) reimburse the Partnership Entities for all costs arising out of the Partnership Entities’ inability to perform under any transportation service contract due to the reversal of the direction of the Pipeline Assets; and (iii) pay the flow reversal rates as set forth on Exhibit E, as it may be amended from time-to-time in accordance with this Agreement. The tariff rates applicable to any such flow reversal shall be as set forth on Exhibit E and shall be adjusted each year as provided in Section 2(q)(i).

(m)Notification of Utilization. Upon request by the Partnership Entities, the HollyFrontier Entities will provide to the Partnership Entities written notification of the HollyFrontier Entities’ reasonable good faith estimate of their anticipated future utilization of any of the Drop-Down Assets as soon as reasonably practicable after receiving such request.

(n)Scheduling and Accepting Deliveries. The Partnership Entities will use their reasonable commercial efforts to schedule movement and accept deliveries of Crude Oil and Refined Product in a manner that is consistent with the historical dealings between the Parties, as such dealings may change from time to time.

(o)Increases in Pipeline Tariff Rates and Tankage Fees. If new Applicable Laws are enacted that require the Partnership Entities to make capital expenditures with respect to the Drop-Down Assets, the Partnership Entities may amend the tariff rates in order to recover the Partnership Entities’ cost of complying with these Applicable Laws (including a reasonable return). The HollyFrontier Entities and the Partnership Entities shall use their reasonable commercial efforts to comply with these Applicable Laws, and shall negotiate in good faith to mitigate the impact of these Applicable Laws and to determine the amount of the new tariff rates. If the HollyFrontier Entities and the Partnership Entities are unable to agree on the amount of the new tariff rates that the Partnership Entities will charge, such tariff rates will be determined by binding arbitration in accordance with Section 12(e). Exhibit A, Exhibit B, Exhibit C, Exhibit D or any other applicable exhibit or schedule to this Agreement will be updated, amended or revised, as applicable, in accordance with this Agreement to reflect any changes in tariff rates agreed to in accordance with this Section 2(o).

(p)Lease Connection Expenses. The Partnership Entities shall construct and add such new lease connection pipelines to the Crude Oil Gathering Pipelines, as requested by the HollyFrontier Entities; provided, however, that the obligation of the Partnership Entities to construct and add such new lease connection pipelines shall be limited to $250,000 per calendar year from

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the Effective Time through the calendar year ending December 31, 2012, and $275,000 per calendar year from the calendar year beginning January 1, 2013 until the end of the Term (the “Lease Connection Expense Cap”). In the event the HollyFrontier Entities request that the Partnership Entities construct new lease connection pipelines in excess of the Lease Connection Expense Cap, then the Partnership Entities will be reimbursed for costs and expenses incurred by them in excess of the Lease Connection Expense Cap as follows:

(i)Incremental Capital and Capital Fee. At the end of each calendar year beginning in 2009 and in each subsequent year, the Partnership Entities will calculate the total lease connection expansion capital spent in the prior calendar year and subtract the Lease Connection Expense Cap (such difference, the “Incremental Capital”); provided, however, that no amounts spent regarding the Devon Lease Connection Pipelines shall be included in calculating Incremental Capital. The Partnership Entities shall use the Incremental Capital to calculate a monthly fee (the “Capital Fee”) to provide the Partnership Entities with a simple 15% return calculated over a seven year period. The Capital Fee shall be charged to the HollyFrontier Entitiesover a seven year period commencing January 1^st of the year following the calendar year in which such Incremental Capital was incurred by the Partnership Entities. The Capital Fee is in addition to the previous agreed gathering fee set forth on Exhibit B.

(ii)Capital Calculation Notice. The Partnership Entities shall provide the HollyFrontier Entities with written notice of their calculation of the Incremental Capital and the Capital Fee (the “Capital Calculation Notice”), as well as supporting documentation, by no later than 30 days following the end of a calendar year.

(iii)Disagreement over Incremental Capital or Capital Fee. If the HollyFrontier Entitiesdisagree with the Partnership Entities’ calculation of the Incremental Capital or Capital Fee, then the HollyFrontier Entities shall send written notice thereof to the Partnership Entities and a senior officer of HollyFrontier (on behalf of the HollyFrontier Entities) and a senior officer of the Partnership (on behalf of the Partnership Entities) shall meet or communicate by telephone at a mutually acceptable time and place, and thereafter as often as they reasonably deem necessary and shall negotiate in good faith to attempt to resolve any differences that they may have with respect to the calculation of the Incremental Capital or the Capital Fee. During the 30-day period following the Partnership Entities’ delivery to the HollyFrontier Entitiesof the Capital Calculation Notice, the HollyFrontier Entities shall have access to the working papers of the Partnership Entities relating to such calculations. If such differences are not resolved within 30 days following the Partnership Entities’ delivery to the HollyFrontier Entitiesof the Capital Calculation Notice, the HollyFrontier Entitiesand the Partnership Entities shall, within forty-five (45) days following the Partnership Entities’ delivery to the HollyFrontier Entitiesof the Capital Calculation Notice, submit any and all matters which remain in dispute to arbitration in accordance with Section 12(e).

(q)PPI and FERC Oil Pipeline Index Adjustments.

(i)PPI Adjustments.

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A.The Minimum Roswell Pipeline Revenue Commitment, the Minimum Trunk Pipeline Revenue Commitment, the Minimum Gathering Pipeline Revenue Commitment, the Minimum Woods Cross Pipeline Revenue Commitment and the Roswell Terminal Payment shall be adjusted on July 1 of each Contract Year commencing on July 1, 2008, by an amount equal to the percentage increase, if any, in the PPI rounded to four decimal places.

B.The change factor shall be calculated as follows: annual PPI index (most current year) less annual PPI index (most current year minus 1) divided by annual PPI index (most current year minus 1). An example for year 2006 change is: [PPI (2005) – PPI (2004)] / PPI (2004) or (155.7 – 148.5) / 148.5 or .0485 or 4.85%. If the PPI index change is negative in a given year then there will be no change in the Minimum Pipeline Revenue Commitment.

(ii)FERC Oil Pipeline Index Adjustments.

A.The tariff rates specified in Section 2(b)(i) and the Volume Incentive Tariff shall be adjusted on the first day of each Contract Year (commencing on July 1, 2008 in the case of tariff rates and commencing July 1, 2010 in the case of the Volume Incentive Tariff), by an amount equal to the percentage change, if any, between the two (2) immediately preceding calendar years, in the FERC Oil Pipeline Index.

B.The amount of the Tankage Revenue Commitment shall be adjusted upward on the first day of each Contract Year commencing on July 1, 2008, by an amount equal to the percentage change, if any, between the two (2) immediately preceding calendar years, in the FERC Oil Pipeline Index. If the percentage change in the FERC Oil Pipeline Index is negative in a given year then there will be no change in the Tankage Revenue Commitment.

(iii)Replacement Index. If the PPI or the FERC Oil Pipeline Index is no longer published, the HollyFrontier Entities and the Partnership Entities shall negotiate in good faith to agree on a new index that gives comparable protection against inflation or deflation and the same method of adjustment for increases in the new index shall be used to calculate increases in the Minimum Pipeline Revenue Commitment, tariff rates, the Volume Incentive Tariff, Tankage Revenue Commitment, or Roswell Terminal Payment, as applicable. If the HollyFrontier Entities and the Partnership Entities are unable to agree, a new index will be determined by binding arbitration in accordance with Section 12(e), and the same method of adjustment for increases or decreases in the new index shall be used to calculate increases in the Minimum Pipeline Revenue Commitment, tariff rates, the Volume Incentive Tariff, Tankage Revenue Commitment, or Roswell Terminal Payment, as applicable.

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(r)Amendments to Schedules and Exhibits. To evidence the Parties’ agreement to each adjusted Minimum Pipeline Revenue Commitment, tariff rate, Volume Incentive Tariff, Tankage Revenue Commitment, or Roswell Terminal Payment, the Parties may, but shall not be required to execute an amended, modified, revised or updated Schedule or Exhibit, as applicable and attach it to this Agreement. Such amended, modified, revised or updated Schedule or Exhibit shall be sequentially numbered (e.g. Schedule I-1, Schedule I-2, etc.), dated and appended as an additional schedule or exhibit to this Agreement and shall replace the prior version of the Schedule or Exhibit in its entirety after its date of effectiveness, except as specified therein.

(s)Crude Oil Trunk Pipelines Volume Measurement. The HollyFrontier Entities will not be charged the tariff rates applicable to services on the Crude Oil Trunk Pipelines for volumes of Crude Oil moved over the 4 inch, 1.2 mile Abo Station to BP Sweet System pipeline (since such volumes of Crude Oil are not ultimately shipped to a HollyFrontier refinery), though such volumes of Crude Oil so shipped may be charged the tariff rates applicable to services on the Crude Oil Gathering Pipelines, as further specified in Section 2(t) below.

(t)Crude Oil Gathering Pipelines Volume Measurements. The HollyFrontier Entities will be charged the tariff applicable to service on the Crude Oil Gathering Pipelines for all volumes (whether shipped by pipeline or truck) of Crude Oil delivered to the following Crude Oil gathering stations:

•Abo	•Monument Sweet
•Artesia	•North Monument
•Barnsdall	•South Monument
•Baumgart	•Riley
•Beeson	•Russell
•Burton Flats	•Seminole
•Lovington Station 126 - Chevron LACTs	•Wood
•Maljamar Park

Additionally, the measurement points for measuring such volumes shall be as follows (with the stations included or excluded at such measurement points set forth in the parenthetical next to such measurement point):

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•Abo

•Artesia (includes Burton Flats)

•Barnsdall

•Beeson (includes Maljamar Park)

•Monument Sour (includes North Monument and South Monument)

•Monument Sweet

•Riley (includes Baumgart)

•Russell (excludes Riley and Baumgart volumes already counted at Riley)

•Wood (includes Seminole)

•Lovington Station 126 – Chevron LACTs

The Parties may, by mutual written agreement, amend the lists above to add or remove stations, or to change measurement points.

Section 2.Force Majeure

In the event that any Party is rendered unable, wholly or in part, by a Force Majeure event from performing its obligations under this Agreement, then, upon the delivery of notice and full particulars of the Force Majeure event in writing within a reasonable time after the occurrence of the Force Majeure event relied on (“Force Majeure Notice”), the obligations of the Parties, so far as they are affected by the Force Majeure event, shall be suspended for the duration of any inability so caused. Any suspension of the obligations of the Parties as a result of this Section 3 for a period of more than thirty (30) consecutive days shall extend the Term (to the extent so affected) for a period equivalent to the duration of the inability set forth in the Force Majeure Notice. The HollyFrontier Entities will be required to pay any amounts accrued and due under this Agreement at the time of the Force Majeure event. The cause of the Force Majeure event shall so far as possible be remedied with all reasonable dispatch, except that no Party shall be compelled to resolve any strikes, lockouts or other industrial disputes other than as it shall determine to be in its best interests. In the event a Force Majeure event prevents the Partnership Entities or the HollyFrontier Entities from performing substantially all of their respective obligations under this Agreement for a period of more than one (1) year, this Agreement may be terminated by the Partnership Entities or the HollyFrontier Entities by providing written notice thereof to the other Party. Nothing in this Section 3 shall alter the liability of the Partnership Entities as set forth in the applicable rules and regulations tariffs for the Pipeline Assets.

Section 3.Agreement to Remain Shipper

With respect to any Refined Product that is produced at a Refinery and transported in the Roswell Products Pipeline or Woods Cross Pipelines or any Crude Oil that is acquired by the HollyFrontier Entities and transported on the Crude Oil Trunk Pipelines, Crude Oil Gathering Pipelines or Woods Cross Pipelines and stored in the Artesia Crude Oil Pipeline Tankage or

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Lovington Crude Oil Pipeline Tankage, the HollyFrontier Entities agree that they will continue their historical commercial practice of owning such Crude Oil or Refined Product, as applicable, from such point as (i) the Refined Product leaves the Refinery until at least such point as it will not be further transported in the Roswell Products Pipeline or Woods Cross Pipelines and to continue acting in the capacity of the shipper of such Refined Product for their own account at all times that such Refined Product is in the Roswell Products Pipeline or Woods Cross Pipeline; and (ii) the Crude Oil is received into the Crude Oil Trunk Pipelines, Crude Oil Gathering Pipelines or Woods Cross Pipelines by the Partnership Entities until such time that it is delivered to the Artesia Crude Oil Pipeline Tankage at the Artesia Refinery or delivered to the Lovington Crude Oil Pipeline Tankage at the Lovington Refinery.

Section 4.Agreement Not to Challenge Tariffs

The HollyFrontier Entities agree to any tariff rate changes for the Pipeline Assets in accordance with this Agreement. The HollyFrontier Entities agree (a) not to challenge, nor to cause their Affiliates to challenge, nor to encourage or recommend to any other Person that it challenge, or voluntarily assist in any way any other Person in challenging, in any forum, tariffs (including joint tariffs) of the Partnership Entities that the Partnership Entities have filed or may file containing rates, rules or regulations that are in effect at any time during the Term and regulate the transportation of the Crude Oil or Refined Product, and (b) not to protest or file a complaint, nor cause their Affiliates to protest or file a complaint, nor encourage or recommend to any other Person that it protest or file a complaint, or voluntarily assist in any way any other Person in protesting or filing a complaint, with respect to regulatory filings that the Partnership Entities have made or may make at any time during the Term to change tariffs (including joint tariffs) for transportation of Crude Oil or Refined Product in each case so long as such tariffs, regulatory filings or rates changed do not conflict with the terms of this Agreement.

Section 5.Effectiveness and Term

This Agreement shall be effective as of the Effective Time, and shall terminate at 12:01 a.m. Dallas, Texas, time on February 28, 2023, unless extended by written mutual agreement of the Parties or as set forth in Section 7 (the “Term”); provided, however, that Section 5 shall survive the termination of this Agreement. The Party(ies) desiring to extend this Agreement pursuant to this Section 6 shall provide prior written notice to the other Parties of its desire to so extend this Agreement; such written notice shall be provided not more than twenty-four (24) months and not less than the later of twelve (12) months prior to the date of termination or ten (10) days after receipt of a written request from another Party (which request may be delivered no earlier than twelve (12) months prior to the date of termination) to provide any such notice or lose such right.

Section 6.Right to Enter into a New Agreement

(a)Prior Written Notice. In the event that the HollyFrontier Entities provide prior written notice to the Partnership Entities of the desire of the HollyFrontier Entities to extend this Agreement by written mutual agreement of the Parties, the Parties shall negotiate in good faith to extend this Agreement by written mutual agreement, but, if such negotiations fail to produce a written mutual agreement for extension by a date six months prior to the termination date, then the Partnership

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Entities shall have the right to negotiate to enter into one or more pipeline and tankage agreements with one or more third parties to begin after the date of termination, provided that until the end of one year following termination without renewal of this Agreement, the HollyFrontier Entities will have the right to enter into a new pipelines and tankage agreement with the Partnership Entities on commercial terms that substantially match the terms upon which the Partnership Entities propose to enter into an agreement with a third party for similar services with respect to all or a material portion of the Drop-Down Assets. In such circumstances, the Partnership Entities shall give the HollyFrontier Entities forty-five (45) days prior written notice of any proposed new pipelines and tankage agreement with a third party, and such notice shall inform the HollyFrontier Entities of the fee schedules, tariffs, duration and any other terms of the proposed third party agreement and the HollyFrontier Entities shall have forty-five (45) days following receipt of such notice to agree to the terms specified in the notice or the HollyFrontier Entities shall lose the rights specified by this Section 7(a) with respect to the assets that are the subject of such notice.

(b)No Prior Written Notice. In the event that the HollyFrontier Entities fail to provide prior written notice to the Partnership Entities of the desire of the HollyFrontier Entities to extend this Agreement by written mutual agreement of the Parties pursuant to Section 6, the Partnership Entities shall have the right, during the period from the date of the HollyFrontier Entities’ failure to provide written notice pursuant to Section 6 to the date of termination of this Agreement, to negotiate to enter into a new pipelines and tankage agreement with a third party, provided however that at any time during the twelve (12) months prior to the expiration of the Term, the HollyFrontier Entities will have the right to enter into a new pipelines and tankage agreement with the Partnership Entities on commercial terms that substantially match the terms upon which the Partnership Entities propose to enter into an agreement with a third party for similar services with respect to all or a material portion of the Drop-Down Assets. In such circumstances, the Partnership Entities shall give the HollyFrontier Entities forty-five (45) days prior written notice of any proposed new pipelines and tankage agreement with a third party, and such notice shall inform the HollyFrontier Entities of the fee schedules, tariffs, duration and any other terms of the proposed third party agreement and the HollyFrontier Entities shall have forty-five (45) days following receipt of such notice to agree to the terms specified in the notice or the HollyFrontier Entities shall lose the rights specified by this Section 7(b) with respect to the assets that are the subject of such notice.

Section 7.Notices

(a)Notices. Any notice or other communication given under this Agreement shall be in writing and shall be (i) delivered personally, (ii) sent by documented overnight delivery service, (iii) sent by email transmission, or (iv) sent by first class mail, postage prepaid (certified or registered mail, return receipt requested). Such notice shall be deemed to have been duly given (x) if received, on the date of the delivery, with a receipt for delivery, (y) if refused, on the date of the refused delivery, with a receipt for refusal, or (z) with respect to email transmissions, on the date the recipient confirms receipt. Notices or other communications shall be directed to the following addresses:

Notices to the HollyFrontier Entities:

c/o HollyFrontier Corporation

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2828 N. Harwood, Suite 1300

Dallas, Texas 75201

Attn: President

Email address: president@hollyfrontier.com

with a copy, which shall not constitute notice, but is required in order to giver proper notice, to:

c/o HollyFrontier Corporation

2828 N. Harwood, Suite 1300

Dallas, Texas 75201

Attn: General Counsel

Email address: generalcounsel@hollyfrontier.com

Notices to the Partnership Entities:

c/o Holly Energy Partners, L.P.

2828 N. Harwood, Suite 1300

Dallas, TX 75201

Attn: President

Email address: president@hollyenergy.com

with a copy, which shall not constitute notice, but is required in order to give proper notice, to:

c/o Holly Energy Partners, L.P.

2828 N. Harwood, Suite 1300

Dallas, Texas 75201

Attn: General Counsel

Email address: general.counsel@hollyenergy.com

(b)Address Change. Any Party may at any time change its address for service from time to time by giving notice to the other Parties in accordance with this Section 8.

Section 8.Deficiency Payments

(a)Deficiency Notice. As soon as practicable following the end of each Contract Quarter under this Agreement, the Partnership Entities shall deliver to the HollyFrontier Entities a written notice (the “Deficiency Notice”) detailing any failure of the HollyFrontier Entities to meet their obligations under Section 2(a)(i), Section 2(c), Section 2(d) or Section 2(p), provided that the HollyFrontier Entities’ obligations pursuant to the Minimum Trunk Pipeline Revenue Commitment, Minimum Gathering Pipeline Revenue Commitment, Minimum Woods Cross Pipeline Revenue Commitment and the Minimum Roswell Pipeline Revenue Commitment shall, in each case, be assessed on a quarterly basis for the purposes of this Section 9. The Deficiency Notice shall

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(i) specify in reasonable detail the nature of any deficiency and (ii) specify the approximate dollar amount that the Partnership Entities believe would have been paid by the HollyFrontier Entities to the Partnership Entities if the HollyFrontier Entities had complied with their respective obligations pursuant to Section 2(a)(i), Section 2(c), Section 2(d) or Section 2(p), as applicable (the “Deficiency Payment”). The HollyFrontier Entities shall pay the Deficiency Payment to the Partnership Entities upon the later of: (A) ten (10) days after their receipt of the Deficiency Notice and (B) thirty (30) days following the end of the related Contract Quarter.

(b)Disagreement regarding Deficiency Notice. If the HollyFrontier Entities disagree with the Deficiency Notice, then, following the payment of the Deficiency Payment to the Partnership Entities, the HollyFrontier Entities shall send written notice thereof to the Partnership Entities and a senior officer of HollyFrontier (on behalf of the HollyFrontier Entities) and a senior officer of the Partnership (on behalf of the Partnership Entities) shall meet or communicate by telephone at a mutually acceptable time and place, and thereafter as often as they reasonably deem necessary and shall negotiate in good faith to attempt to resolve any differences that they may have with respect to matters specified in the Deficiency Notice. During the 30-day period following the payment of the Deficiency Payment, the HollyFrontier Entities shall have access to the working papers of the Partnership Entities relating to the Deficiency Notice. If such differences are not resolved within thirty (30) days following the payment of the Deficiency Payment, the HollyFrontier Entities and the Partnership Entities shall, within forty-five (45) days following the payment of the Deficiency Payment, submit any and all matters which remain in dispute and which were properly included in the Deficiency Notice to arbitration in accordance with Section 12(e).

(c)Refund. If it is finally determined pursuant to this Section 9 that the HollyFrontier Entities are not required to make any or all of the Deficiency Payment (the “Refund”), the Partnership Entities shall promptly pay to the HollyFrontier Entities the Refund, together with interest thereon at the Prime Rate, in immediately available funds.

(d)No Carry-Over Deficiency. The Parties acknowledge and agree that there shall be no carry-over of deficiency volumes with respect to the Minimum Pipeline Revenue Commitment.

(e)No Aggregation. The Parties acknowledge and agree that the Minimum Pipeline Revenue Commitment shall not be aggregated for purposes of determining any deficiency pursuant to this Section 9.

(f)No Right to Setoff. No Party shall have a right to setoff revenue in excess of the minimum revenue commitment of the Minimum Trunk Pipeline Revenue Commitment, the Minimum Gathering Pipeline Revenue Commitment, the Minimum Woods Cross Pipeline Revenue Commitment or the Minimum Roswell Pipeline Revenue Commitment with respect to any deficiency under the Minimum Trunk Pipeline Revenue Commitment, the Minimum Gathering Pipeline Revenue Commitment, the Minimum Woods Cross Pipeline Revenue Commitment or the Minimum Roswell Pipeline Revenue Commitment.

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Section 9.Right of First RefusalThe Parties acknowledge the right of first refusal of the HollyFrontier Entities with respect to the Drop-Down Assets provided in the Omnibus Agreement.

Section 10.Limitation of Damages

(a)Limitation. NOTWITHSTANDING ANYTHING CONTAINED TO THE CONTRARY IN ANY OTHER PROVISION OF THIS AGREEMENT AND EXCEPT FOR CLAIMS MADE BY THIRD PARTIES WHICH SHALL NOT BE LIMITED BY THIS PARAGRAPH, THE PARTIES AGREE THAT THE RECOVERY BY ANY PARTY OF ANY LIABILITIES, DAMAGES, COSTS OR OTHER EXPENSES SUFFERED OR INCURRED BY IT AS A RESULT OF ANY BREACH OR NONFULFILLMENT BY A PARTY OF ANY OF ITS REPRESENTATIONS, WARRANTIES, COVENANTS, AGREEMENTS OR OTHER OBLIGATIONS UNDER THIS AGREEMENT, OR IN CONNECTION WITH A CLAIM FOR INDEMNIFICATION UNDER THIS SECTION 11, SHALL BE LIMITED TO ACTUAL DAMAGES AND SHALL NOT INCLUDE OR APPLY TO, NOR SHALL ANY PARTY BE ENTITLED TO RECOVER, ANY INDIRECT, CONSEQUENTIAL, EXEMPLARY OR PUNITIVE DAMAGES (INCLUDING, WITHOUT LIMITATION, ANY DAMAGES ON ACCOUNT OF LOST PROFITS OR OPPORTUNITIES OR BUSINESS INTERRUPTION OR DIMINUTION IN VALUE) SUFFERED OR INCURRED BY ANY PARTY; PROVIDED, HOWEVER, THAT SUCH RESTRICTION AND LIMITATION SHALL NOT APPLY (x) AS A RESULT OF A THIRD PARTY CLAIM FOR SUCH INDIRECT, CONSEQUENTIAL, EXEMPLARY OR PUNITIVE DAMAGES OR (y) TO INDIRECT, CONSEQUENTIAL, EXEMPLARY OR PUNITIVE DAMAGES (INCLUDING, WITHOUT LIMITATION, ANY DAMAGES ON ACCOUNT OF LOST PROFITS OR OPPORTUNITIES OR BUSINESS INTERRUPTION OR DIMINUTION IN VALUE) THAT ARE A RESULT OF THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF THE BREACHING OR NONFULFILLING PARTY OR ITS AFFILIATES.

(b)HollyFrontier Entity Indemnity. Each HollyFrontier Entity shall indemnify, defend, and hold harmless HEP Operating and its Affiliates from and against any losses, damages, liabilities, claims, demands, causes of action, judgments, settlements, fines, penalties, costs, and expenses (including, without limitation, court costs and reasonable attorneys’ fees) of any and every kind or character, known or unknown, fixed or contingent, suffered or incurred by such HollyFrontier Entity to the extent resulting or arising from, or attributable to, acts or omissions of such HollyFrontier Entity in connection with the performance of such HollyFrontier Entity’s obligations under this Agreement that constitute negligence.

(c)HEP Operating Indemnity. HEP Operating shall indemnify, defend, and hold harmless the HollyFrontier Entities and their Affiliates from and against any losses, damages, liabilities, claims, demands, causes of action, judgments, settlements, fines, penalties, costs, and expenses (including, without limitation, court costs and reasonable attorneys’ fees) of any and every kind or character, known or unknown, fixed or contingent, suffered or incurred by the HollyFrontier Entities and their Affiliates, including loss of Crude Oil from the Pipeline System, to the extent resulting or arising from, or attributable, to (i) events and conditions associated with the operation

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of the Pipeline System, or (ii) acts or omissions of HEP Operating and its Affiliates in connection with the performance of HEP Operating’s obligations under this Agreement that constitute negligence; provided, however, that, with respect to loss of Crude Oil from the Pipeline System, HEP Operating will only be liable for losses in excess of 1,000 barrels with respect to each individual incident of Crude Oil loss.

Section 11.Miscellaneous

(a)Amendments and Waivers. No amendment or modification of this Agreement shall be valid unless it is in writing and signed by the Parties. No waiver of any provision of this Agreement shall be valid unless it is in writing and signed by the Party against whom the waiver is sought to be enforced. Any of the exhibits or schedules to this Agreement may be amended, modified, revised or updated by the Parties if each of the Parties executes an amended, modified, revised or updated exhibit or schedule, as applicable, and attaches it to this Agreement. Such amended, modified, revised or updated exhibits or schedules shall be sequentially numbered (e.g. Exhibit A-1, Exhibit A-2, etc.), dated and appended as an additional exhibit or schedule to this Agreement and shall replace the prior exhibit or schedule, as applicable, in its entirety, after its date of effectiveness, except as specified therein. No failure or delay in exercising any right hereunder, and no course of conduct, shall operate as a waiver of any provision of this Agreement. No single or partial exercise of a right hereunder shall preclude further or complete exercise of that right or any other right hereunder.

(b)Successors and Assigns. This Agreement shall inure to the benefit of, and shall be binding upon, the HollyFrontier Entities, the Partnership Entities and their respective successors and permitted assigns. Neither this Agreement nor any of the rights or obligations hereunder shall be assigned without the prior written consent of the HollyFrontier Entities (in the case of any assignment by the Partnership Entities) or the Partnership Entities (in the case of any assignment by the HollyFrontier Entities), in each case, such consent is not to be unreasonably withheld or delayed; provided, however, that (i) the Partnership Entities may make such an assignment (including a partial pro rata assignment) to an Affiliate of the Partnership Entities without the HollyFrontier Entities’ consent, (ii) the HollyFrontier Entities may make such an assignment (including a pro rata partial assignment) to an Affiliate of the HollyFrontier Entities without the Partnership Entities’ consent, (iii) the HollyFrontier Entities may make a collateral assignment of their rights and obligations hereunder, and (iv) the Partnership Entities may make a collateral assignment of their rights hereunder and/or grant a security interest in their rights and obligations hereunder to a bona fide third party lender or debt holder, or trustee or representative for any of them, without the HollyFrontier Entities’ consent, if such third party lender, debt holder or trustee shall have executed and delivered to the HollyFrontier Entities a non-disturbance agreement in such form as is reasonably satisfactory to the HollyFrontier Entities and such third party lender, debt holder or trustee and HollyFrontier executes an acknowledgment of such collateral assignment in such form as may from time to time be reasonably requested. Any attempt to make an assignment otherwise than as permitted by the foregoing shall be null and void. The Parties agree to require their respective successors, if any, to expressly assume, in a form of agreement reasonably acceptable to the other Parties, their obligations under this Agreement.

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(c)Severability. If any provision of this Agreement shall be held invalid or unenforceable by a court or regulatory body of competent jurisdiction, the remainder of this Agreement shall remain in full force and effect.

(d)Choice of Law. This Agreement shall be subject to and governed by the laws of the State of Delaware, excluding any conflicts-of-law rule or principle that might refer the construction or interpretation of this Agreement to the laws of another state.

(e)Arbitration Provision. Any and all Arbitrable Disputes must be resolved through the use of binding arbitration using three arbitrators, in accordance with the Commercial Arbitration Rules of the American Arbitration Association, as supplemented to the extent necessary to determine any procedural appeal questions by the Federal Arbitration Act (Title 9 of the United States Code). If there is any inconsistency between this Section 11(e) and the Commercial Arbitration Rules or the Federal Arbitration Act, the terms of this Section 11(e) will control the rights and obligations of the Parties. Arbitration must be initiated within the time limits set forth in this Agreement, or if no such limits apply, then within a reasonable time or the time period allowed by the applicable statute of limitations. Arbitration may be initiated by a Party (“Claimant”) serving written notice on the other Party (“Respondent”) that the Claimant elects to refer the Arbitrable Dispute to binding arbitration. Claimant’s notice initiating binding arbitration must identify the arbitrator Claimant has appointed. The Respondent shall respond to Claimant within thirty (30) days after receipt of Claimant’s notice, identifying the arbitrator Respondent has appointed. If the Respondent fails for any reason to name an arbitrator within the 30-day period, Claimant shall petition the American Arbitration Association for appointment of an arbitrator for Respondent’s account. The two arbitrators so chosen shall select a third arbitrator within thirty (30) days after the second arbitrator has been appointed. The Claimant will pay the compensation and expenses of the arbitrator named by it, and the Respondent will pay the compensation and expenses of the arbitrator named by or for it. The costs of petitioning for the appointment of an arbitrator, if any, shall be paid by Respondent. The Claimant and Respondent will each pay one-half of the compensation and expenses of the third arbitrator. All arbitrators must (i) be neutral parties who have never been officers, directors or employees of any of the HollyFrontier Entities, the Partnership Entities or any of their Affiliates and (ii) have not less than seven (7) years’ experience in the petroleum transportation industry. The hearing will be conducted in Dallas, Texas and commence within thirty (30) days after the selection of the third arbitrator. The HollyFrontier Entities, the Partnership Entities and the arbitrators shall proceed diligently and in good faith in order that the award may be made as promptly as possible. Except as provided in the Federal Arbitration Act, the decision of the arbitrators will be binding on and non-appealable by the Parties hereto. The arbitrators shall have no right to grant or award indirect, consequential, punitive or exemplary damages of any kind. The Arbitrable Disputes may be arbitrated in a common proceeding along with disputes under other agreements between the HollyFrontier Entities, the Partnership Entities or their Affiliates to the extent that the issues raised in such disputes are related. Without the written consent of the Parties, no unrelated disputes or third party disputes may be joined to an arbitration pursuant to this Agreement.

(f)Rights of Limited Partners. The provisions of this Agreement are enforceable solely by the Parties, and no limited partner of the Partnership shall have the right, separate and apart from

19

the Partnership, to enforce any provision of this Agreement or to compel any Party to comply with the terms of this Agreement.

(g)Further Assurances. In connection with this Agreement and all transactions contemplated by this Agreement, each signatory Party hereto agrees to execute and deliver such additional documents and instruments and to perform such additional acts as may be necessary or appropriate to effectuate, carry out and perform all of the terms, provisions and conditions of this Agreement and all such transactions.

(h)Headings. Headings of the Sections of this Agreement are for convenience of the Parties only and shall be given no substantive or interpretative effect whatsoever. All references in this Agreement to Sections are to Sections of this Agreement unless otherwise stated.

(i)No Novation. This Agreement shall be considered an amendment and restatement of the Original Pipelines Agreement, and the Original Pipelines Agreement is hereby ratified, approved and confirmed in every respect. This Agreement is not intended to constitute a novation of the Original Pipelines Agreement and all of the obligations owing by the Parties under the Original Pipelines Agreement shall continue (and from and after the date of this Agreement, as amended hereby).

Section 12.Guarantee by HollyFrontier

(a)Payment Guaranty. HollyFrontier unconditionally, absolutely, continually and irrevocably guarantees, as principal and not as surety, to the Partnership Entities the punctual and complete payment in full when due of all amounts due from the HollyFrontier Entities under this Agreement (collectively, the “HollyFrontier Payment Obligations”). HollyFrontier agrees that the Partnership Entities shall be entitled to enforce directly against HollyFrontier any of the HollyFrontier Payment Obligations.

(b)Guaranty Absolute. HollyFrontier hereby guarantees that the HollyFrontier Payment Obligations will be paid strictly in accordance with the terms of the Agreement. The obligations of HollyFrontier under this Agreement constitute a present and continuing guaranty of payment, and not of collection or collectability. The liability of HollyFrontier under this Agreement shall be absolute, unconditional, present, continuing and irrevocable irrespective of:

(i)any assignment or other transfer of this Agreement or any of the rights thereunder of the Partnership Entities;

(ii)any amendment, waiver, renewal, extension or release of or any consent to or departure from or other action or inaction related to this Agreement;

(iii)any acceptance by the Partnership Entities of partial payment or performance from the HollyFrontier Entities;

(iv)any bankruptcy, insolvency, reorganization, arrangement, composition, adjustment, dissolution, liquidation or other like proceeding relating to the HollyFrontier

20

Entities or any action taken with respect to this Agreement by any trustee or receiver, or by any court, in any such proceeding;

(v)any absence of any notice to, or knowledge of, Holly, of the existence or occurrence of any of the matters or events set forth in the foregoing subsections (i) through (iv); or

(vi)any other circumstance which might otherwise constitute a defense available to, or a discharge of, a guarantor.

The obligations of HollyFrontier hereunder shall not be subject to any reduction, limitation, impairment or termination for any reason, including any claim of waiver, release, surrender, alteration or compromise, and shall not be subject to any defense or setoff, counterclaim, recoupment or termination whatsoever by reason of the invalidity, illegality or unenforceability of the HollyFrontier Payment Obligations or otherwise.

(c)Waiver. HollyFrontier hereby waives promptness, diligence, all setoffs, presentments, protests and notice of acceptance and any other notice relating to any of the HollyFrontier Payment Obligations and any requirement for the Partnership Entities to protect, secure, perfect or insure any security interest or lien or any property subject thereto or exhaust any right or take any action against the HollyFrontier Entities, any other entity or any collateral.

(d)Subrogation Waiver. HollyFrontier agrees that for so long as there is a current or ongoing default or breach of this Agreement by any of the HollyFrontier Entities, HollyFrontier shall not have any rights (direct or indirect) of subrogation, contribution, reimbursement, indemnification or other rights of payment or recovery from the HollyFrontier Entities for any payments made by HollyFrontier under this Section 13, and HollyFrontier hereby irrevocably waives and releases, absolutely and unconditionally, any such rights of subrogation, contribution, reimbursement, indemnification and other rights of payment or recovery it may now have or hereafter acquire against the HollyFrontier Entities during any period of default or breach of this Agreement by any of the HollyFrontier Entities until such time as there is no current or ongoing default or breach of this Agreement by the HollyFrontier Entities.

(e)Reinstatement. The obligations of HollyFrontier under this Section 13 shall continue to be effective or shall be reinstated, as the case may be, if at any time any payment of any of the HollyFrontier Payment Obligations is rescinded or must otherwise be returned to the HollyFrontier Entities or any other entity, upon the insolvency, bankruptcy, arrangement, adjustment, composition, liquidation or reorganization of the HollyFrontier Entities or such other entity, or for any other reason, all as though such payment had not been made.

(f)Continuing Guaranty. This Section 13 is a continuing guaranty and shall (i) remain in full force and effect until the first to occur of the indefeasible payment in full of all of the HollyFrontier Payment Obligations, (ii) be binding upon Holly, its successors and assigns and (iii) inure to the benefit of and be enforceable by the Partnership Entities and their respective successors, transferees and assigns.

21

(g)No Duty to Pursue Others. It shall not be necessary for the Partnership Entities (and HollyFrontier hereby waives any rights which HollyFrontier may have to require the Partnership Entities), in order to enforce such payment by Holly, first to (i) institute suit or exhaust its remedies against the HollyFrontier Entities or others liable on the HollyFrontier Payment Obligations or any other person, (ii) enforce the Partnership Entities’ rights against any other guarantors of the HollyFrontier Payment Obligations, (iii) join the HollyFrontier Entities or any others liable on the HollyFrontier Payment Obligations in any action seeking to enforce this Section 13, (iv) exhaust any remedies available to the Partnership Entities against any security which shall ever have been given to secure the HollyFrontier Payment Obligations, or (v) resort to any other means of obtaining payment of the HollyFrontier Payment Obligations.

Section 13.Guarantee by the Partnership and Operating Partnership.

(a)Payment and Performance Guaranty. Each of the Partnership and the Operating Partnership unconditionally, absolutely, continually and irrevocably guarantees, as principal and not as surety, to the HollyFrontier Entities the punctual and complete payment in full when due of all amounts due from the Partnership Entities under the Agreement (collectively, the “HEP Payment Obligations”) and the punctual and complete performance of all other obligations of the Partnership Entities under this Agreement (collectively, the “HEP Performance Obligations”, together with the HEP Payment Obligations, the “HEP Obligations”). Each of the Partnership and the Operating Partnership agrees that the HollyFrontier Entities shall be entitled to enforce directly against the Partnership and the Operating Partnership any of the HEP Obligations.

(b)Guaranty Absolute. Each of the Partnership and the Operating Partnership hereby guarantees that the HEP Payment Obligations will be paid, and the HEP Performance Obligations will be performed, strictly in accordance with the terms of this Agreement. The obligations of each of the Partnership and the Operating Partnership under this Agreement constitute a present and continuing guaranty of payment and performance, and not of collection or collectability. The liability of each of the Partnership and the Operating Partnership under this Agreement shall be absolute, unconditional, present, continuing and irrevocable irrespective of:

(i)any assignment or other transfer of the Agreement or any of the rights thereunder of the HollyFrontier Entities;

(ii)any amendment, waiver, renewal, extension or release of or any consent to or departure from or other action or inaction related to the Agreement;

(iii)any acceptance by the HollyFrontier Entities of partial payment or performance from the Partnership Entities;

(iv)any bankruptcy, insolvency, reorganization, arrangement, composition, adjustment, dissolution, liquidation or other like proceeding relating to the Partnership Entities or any action taken with respect to the Agreement by any trustee or receiver, or by any court, in any such proceeding;

22

(v)any absence of any notice to, or knowledge of, the Partnership or the Operating Partnership, of the existence or occurrence of any of the matters or events set forth in the foregoing subsections (i) through (iv); or

(vi)any other circumstance which might otherwise constitute a defense available to, or a discharge of, a guarantor.

The obligations of each of the Partnership and the Operating Partnership hereunder shall not be subject to any reduction, limitation, impairment or termination for any reason, including any claim of waiver, release, surrender, alteration or compromise, and shall not be subject to any defense or setoff, counterclaim, recoupment or termination whatsoever by reason of the invalidity, illegality or unenforceability of the HEP Obligations or otherwise.

(c)Waiver. Each of the Partnership and the Operating Partnership hereby waives promptness, diligence, all setoffs, presentments, protests and notice of acceptance and any other notice relating to any of the HEP Payment Obligations and any requirement for the HollyFrontier Entities to protect, secure, perfect or insure any security interest or lien or any property subject thereto or exhaust any right or take any action against the Partnership Entities, any other entity or any collateral.

(d)Subrogation Waiver. Each of the Partnership and the Operating Partnership agrees that for so long as there is a current or ongoing default or breach of this Agreement by any of the Partnership Entities, the Partnership and the Operating Partnership shall not have any rights (direct or indirect) of subrogation, contribution, reimbursement, indemnification or other rights of payment or recovery from the Partnership Entities for any payments made by the Partnership or the Operating Partnership under this Section 14, and each of the Partnership and the Operating Partnership hereby irrevocably waives and releases, absolutely and unconditionally, any such rights of subrogation, contribution, reimbursement, indemnification and other rights of payment or recovery it may now have or hereafter acquire against the Partnership Entities during any period of default or breach of this Agreement by any of the Partnership Entities until such time as there is no current or ongoing default or breach of this Agreement by the Partnership Entities.

(e)Reinstatement. The obligations of the Partnership and the Operating Partnership under this Section 14 shall continue to be effective or shall be reinstated, as the case may be, if at any time any payment of any of the HEP Payment Obligations is rescinded or must otherwise be returned to the Partnership Entities or any other entity, upon the insolvency, bankruptcy, arrangement, adjustment, composition, liquidation or reorganization of the Partnership Entities or such other entity, or for any other reason, all as though such payment had not been made.

(f)Continuing Guaranty. This Section 14 is a continuing guaranty and shall (i) remain in full force and effect until the first to occur of the indefeasible payment and/or performance in full of all of the HEP Payment Obligations, (ii) be binding upon the Partnership, the Operating Partnership, and each of their respective successors and assigns and (iii) inure to the benefit of and be enforceable by the HollyFrontier Entities and their respective successors, transferees and assigns.

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(g)No Duty to Pursue Others. It shall not be necessary for the HollyFrontier Entities (and each of the Partnership and the Operating Partnership hereby waives any rights which the Partnership or the Operating Partnership, as applicable, may have to require the HollyFrontier Entities), in order to enforce such payment by the Partnership or the Operating Partnership, first to (i) institute suit or exhaust its remedies against the Partnership Entities or others liable on the HEP Obligations or any other person, (ii) enforce the HollyFrontier Entities’ rights against any other guarantors of the HEP Obligations, (iii) join the Partnership Entities or any others liable on the HEP Obligations in any action seeking to enforce this Section 14, (iv) exhaust any remedies available to the HollyFrontier Entities against any security which shall ever have been given to secure the HEP Obligations, or (v) resort to any other means of obtaining payment of the HEP Obligations.

[Remainder of page intentionally left blank. Signature pages follow.]

24

IN WITNESS WHEREOF, the undersigned Parties have executed this Agreement as of the date first written above.

PARTNERSHIP ENTITIES:

HOLLY ENERGY PARTNERS - OPERATING, L.P.

By: /s/ Bruce R. Shaw    

Bruce R. Shaw

President

HEP WOODS CROSS, L.L.C.

HEP PIPELINE, L.L.C.

By: HOLLY ENERGY PARTNERS —

OPERATING, L.P.,

Sole Member

By: /s/ Bruce R. Shaw    

Bruce R. Shaw

President

HOLLYFRONTIER ENTITIES:

NAVAJO REFINING COMPANY, L.L.C.

HOLLY REFINING & MARKETING

COMPANY – WOODS CROSS LLC

HOLLYFRONTIER REFINING &

MARKETING LLC

By: /s/ Michael C. Jennings    

Michael C. Jennings

Chief Executive Officer and President

[Signature Page 1of 2 to the Second Amended and Restated Crude Pipelines and Tankage Agreement]

ACKNOWLEDGED AND AGREED

FOR PURPOSES OF Section 2(p)(iii),

Section 9(b) AND Section 13 AND

ACKNOWLEDGING THE SECOND AMENDMENT

AND RESTATEMENT OF THE ORIGINAL

PIPELINES AGREEMENT:

HOLLYFRONTIER CORPORATION

By: /s/ Michael C. Jennings    

Michael C. Jennings

Chief Executive Officer and President

ACKNOWLEDGED AND AGREED

FOR PURPOSES OF Section 2(p)(iii),

Section 9(b), Section 12(f) AND Section 14

AND ACKNOWLEDGING THE SECOND AMENDMENT

AND RESTATEMENT OF THE ORIGINAL

PIPELINES AGREEMENT:

HOLLY ENERGY PARTNERS, L.P.

By:    HEP Logistics Holdings, L.P.,

its General Partner

By:    Holly Logistic Services, L.L.C.,

its General Partner

By: /s/ Bruce R. Shaw    

Bruce R. Shaw

President

[Signature Page 2of 2 to the Second Amended and Restated Crude Pipelines and Tankage Agreement]

Annex A

Definitions

“Affiliate” means, with to respect to a specified person, any other person controlling, controlled by or under common control with that first person. As used in this definition, the term “control” includes (a) with respect to any person having voting securities or the equivalent and elected directors, managers or persons performing similar functions, the ownership of or power to vote, directly or indirectly, voting securities or the equivalent representing 50% or more of the power to vote in the election of directors, managers or persons performing similar functions, (b) ownership of 50% or more of the equity or equivalent interest in any person and (c) the ability to direct the business and affairs of any person by acting as a general partner, manager or otherwise. Notwithstanding the foregoing, for purposes of this Agreement, the HollyFrontier Entities, on the one hand, and the Partnership Entities, on the other hand, shall not be considered affiliates of each other.

“Agreement” has the meaning set forth in the preamble to this Agreement.

“Applicable Law” means any applicable statute, law, regulation, ordinance, rule, judgment, rule of law, order, decree, permit, approval, concession, grant, franchise, license, agreement, requirement, or other governmental restriction or any similar form of decision of, or any provision or condition of any permit, license or other operating authorization issued under any of the foregoing by, or any determination of, any Governmental Authority having or asserting jurisdiction over the matter or matters in question, whether now or hereafter in effect and in each case as amended (including, without limitation, all of the terms and provisions of the common law of such Governmental Authority), as interpreted and enforced at the time in question.

“Arbitrable Dispute” means any and all disputes, Claims, controversies and other matters in question between any of the Partnership Entities, on the one hand, and any of the HollyFrontier Entities, on the other hand, arising out of or relating to this Agreement or the alleged breach hereof, or in any way relating to the subject matter of this Agreement regardless of whether (a) allegedly extra-contractual in nature, (b) sounding in contract, tort or otherwise, (c) provided for by Applicable Law or otherwise or (d) seeking damages or any other relief, whether at law, in equity or otherwise.

“Artesia Crude Oil Pipeline Tankage” means the following crude oil tankage associated with the Artesia Delivery System:

(a) Abo Station Tank 1007;

(b) Artesia Station Tank 970;

(c) Barnsdall Station Tank 1028;

(d) Beeson Station Tanks 972 and 973;

(e) Maljamar Park Station Tanks 46, 47 and 48; and

(f) Henshaw Station Tanks 1048 and 1049.

Annex A

“Artesia Delivery System” means

(a) the following crude oil pipelines:

(i) the Beeson to North Artesia pipeline (6-inch) – 11 miles;

(ii) the Barnsdall to North Artesia pipeline (4/6-inch) – 7 miles;

(iii) the Barnsdall jumper pipeline to Lovington pipeline (8-inch) – 2 miles;

(iv) the Artesia Station to North Artesia pipeline (4-inch) – 4 miles;

(v) the North Artesia to Evans Junction pipeline (8-inch) – 6 miles;

(vi) the Abo to Evans Junction pipeline (6-inch) – 1.2 miles; and

(vii) the Artesia to Bad Luck pipeline (12-inch) – 13 miles and

(b) the Artesia Crude Oil receiving, metering and handling facilities.

“Artesia Refinery” means the refining facilities owned by Navajo Refining in Artesia.

“bpd” means barrels per day.

“bpq” means barrels per quarter.

“Beeson Pipeline” means the 37-mile Crude Oil pipeline from Beeson station to Lovington, New Mexico (8-inch).

“Buyer Parties” has the meaning set forth in the recitals to this Agreement.

“Claim” means any existing or threatened future claim, demand, suit, action, investigation, proceeding, governmental action or cause of action of any kind or character (in each case, whether civil, criminal, investigative or administrative), known or unknown, under any theory, including those based on theories of contract, tort, statutory liability, strict liability, employer liability, premises liability, products liability, breach of warranty or malpractice.

“Contract Quarter” means a three-month period that commences on July 1, October 1, January 1, or April 1, and ends on September 30, December 31, March 31 or June 30, respectively, except that the initial Contract Quarter commenced on March 1, 2008.

“Contract Year” means a year that commences on July 1 and ends on the last day of June, except that the initial Contract Year commenced on March 1, 2008.

Annex A

“Control” (including with correlative meaning, the term “controlled by”) means, as used with respect to any Person, the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of such Person, whether through the ownership of voting securities, by contract or otherwise.

“Crude Oil” means the direct liquid product of oil wells, oil processing plants, the indirect liquid petroleum products of oil or gas wells, oil sands or a mixture of such products, but does not include natural gas liquids or Refined Products.

“Crude Oil Gathering Lease Connection Pipelines” means the following pipelines:

(a) Barnsdall Station lease connection pipelines;

(b) Maljamar Park lease connection pipelines;

(c) Beeson Station lease connection pipelines;

(d) Burton Flats lease connection pipelines;

(e) Abo Station lease connection pipelines;

(f) Artesia Station lease connection pipelines;

(g) Eagle lease connection pipelines;

(h) North Monument lease connection pipelines;

(i) South Monument lease connection pipelines;

(j) Monument Sweet lease connection pipelines;

(k) Russell Station lease connection pipelines;

(l) Riley Station lease connection pipelines;

(m) Wood Station (Seminole Gathering) lease connection pipelines;

(n) Baumgart Station lease connection pipelines;

(o) Chevron Lacts at Lovington Station 126 lease connection pipelines; and

(p) the Devon Lease Connection Pipelines.

“Crude Oil Gathering Pipelines” means the following pipelines:

(a) Abo Station to BP Sweet System (4 inch) – 1.2 miles;

(b) Artesia Station to Abo Trunk Line (6 inch) – 6.5 miles;

Annex A

(c) Maljamar Park to Beeson Station (4 inch) – approximately 14 miles;

(d) Wood Station to Russell Station (6 inch) – 13.5 miles;

(e) Riley Station to Russell Station (6 inch) – 5 miles;

(f) Baumgart Station to Riley Station (6 inch) – 7 miles; and

(g) the Crude Oil Gathering Lease Connection Pipelines.

“Crude Oil Trunk Pipelines” means the Artesia Delivery System, the Lovington Delivery System, and the Beeson Pipeline.

“Devon Lease Connection Pipelines” means the 25 Devon Parkway and Devon Hackberry lease connection pipelines set forth on Exhibit D to the Malaga TSA.

“Drop-Down Assets” means, collectively, the Pipeline Assets and Tankage Assets.

“Effective Time” means 12:01 a.m., Dallas, Texas time, on March 1, 2008.

“First Amended Pipelines Agreement” means that certain Amended and Restated Pipelines and Tankage Agreement entered into on December 1, 2009, to be effective as of January 1, 2009, as amended, among Holly, Navajo Pipeline, Navajo Refining, Woods Cross Refining, the Partnership, the Operating Partnership, HEP Pipeline and HEP Woods Cross.

“Force Majeure” means acts of God; strikes, lockouts or other industrial disturbances; acts of the public enemy, wars, blockades, insurrections, civil disturbances, riots; storms, floods, washouts; arrests, the emergency, disaster or crisis order of any Governmental Authority having jurisdiction while the same is in force and effect; explosions, breakage, accident to machinery, storage tanks or lines of pipe; inability to obtain or unavoidable delay in obtaining material or equipment; and any other causes whether of the kind herein enumerated or otherwise not reasonably within the control of the Party claiming suspension and which by the exercise of due diligence such Party is unable to prevent or overcome. Notwithstanding anything in this Agreement to the contrary, inability of a Party to make payments when due, be profitable or to secure funds, arrange bank loans or other financing, obtain credit or have adequate capacity or production (other than for reasons of Force Majeure) shall not be regarded as events of Force Majeure.

“Governmental Authority” means any federal, state, local or foreign government or any provincial, departmental or other political subdivision thereof, or any entity, body or authority exercising executive, legislative, judicial, regulatory, administrative or other governmental functions or any court, department, commission, board, bureau, agency, instrumentality or administrative body of any of the foregoing.

“HollyFrontier” means HollyFrontier Corporation (formerly known as Holly Corporation), a Delaware corporation.

Annex A

“Lovington Crude Oil Pipeline Tankage” means the following crude oil tankage associated with the Lovington Delivery System:

(a) Crouch Station Tank 1038;

(b) Monument Junction Tank;

(c) Hobbs Station Tanks 5201 and 5202;

(d) Russell Station Tanks 5101, 5102 and 5103;

(e) Wood Station Tanks 5301 and 5302;

(f) Riley Station Tanks 5001 and 5003; and

(g) Baumgart Station Tank 5002.

“Lovington Delivery System” means the following crude oil pipelines:

(a) the Russell to Lovington pipeline (12-inch) – 23 miles;

(b) the Hobbs to Lovington pipeline (8-inch) – 20 miles;

(c) the Crouch to Lovington pipeline (6/8-inch) – 11 miles;

(d) the Russell to Hobbs pipeline (6-inch) – 20 miles; and

(e) the Gaines to Hobbs pipeline (6-inch) – 6 miles.

“Lovington Refinery” means the refining facilities owned by Navajo Refining near Lovington, New Mexico.

“Malaga TSA” means that certain Transportation Services Agreement dated as of July 16, 2013, to be effective as of 12:01 a.m., Dallas, Texas time, on June 1, 2013, by and between HFRM and the Operating Partnership, pursuant to which the Operating Partnership will provide certain transportation services for HFRM on the Pipeline System (as defined in the Malaga TSA).

“Minimum Pipeline Revenue Commitment” means the Minimum Roswell Pipeline Revenue Commitment, the Minimum Trunk Pipeline Revenue Commitment, the Minimum Gathering Pipeline Revenue Commitment and the Minimum Woods Cross Pipeline Revenue Commitment.

“Navajo Pipeline” means Navajo Pipeline Co., L.P., a Delaware limited partnership.

“Omnibus Agreement” means the Eighth Amended and Restated Omnibus Agreement, dated as of the date hereof, by and among Holly, the Partnership and certain of their respective subsidiaries.

“Original Pipelines Agreement” means that certain Pipelines and Tankage Agreement dated February 29, 2008, as amended.

Annex A

“Partnership” means Holly Energy Partners, L.P., a Delaware limited partnership.

“Person” means an individual or a corporation, limited liability company, partnership, joint venture, trust, unincorporated organization, association, government agency or political subdivision thereof or other entity.

“Pipeline Assets” means, collectively: (i) the Crude Oil Trunk Pipelines; (ii) the Crude Oil Gathering Pipelines; (iii) the Woods Cross Pipelines; and (iv) the Roswell Products Pipeline.

“PPI” means the Producers Price Index-Commodities-Finished Goods, (PPI), et al., produced by the U.S. Department of Labor, Bureaus of Labor Statistics, series ID WPUSOP3000 (as of December 31, 2007) – located at http://www.bls.gov/data/.

“Prime Rate” means the prime rate per annum announced by Union Bank, N.A., or if Union Bank, N.A. no longer announces a prime rate for any reason, the prime rate per annum announced by the largest U.S. bank measured by deposits from time to time as its base rate on corporate loans, automatically fluctuating upward or downward with each announcement of such prime rate.

“Product” means Refined Products and Crude Oil.

“Refined Product” means jet fuel, gasoline, kerosene and diesel fuel.

“Refineries” means, collectively, the Artesia Refinery, the Lovington Refinery and the Woods Cross Refinery.

“Refinery Tankage” means, collectively:

(a) the crude oil tanks 1201A and 1201B at the Lovington Refinery;

(b) the crude oil tanks 103, 121 and 126 at the Woods Cross Refinery;

(c) the crude oil tank 437 at such time as HollyFrontier completes relocation of the tank within the Artesia Refinery; and

(d) the crude oil tank which will replace the current crude oil tank 439 at the Artesia Refinery, upon such time as HollyFrontier completes construction of the replacement tank.

“Roswell Products Pipeline” means the Artesia to Roswell (4-inch) – 36 mile pipeline that is currently dedicated to the transport of jet fuel.

“Roswell Terminal” means the terminal leased by HEP Pipeline, L.L.C. from the City of Roswell, and located in the Roswell International Air Center in Roswell, New Mexico and Tanks 1216, 1218 and 1219.

“Tankage Assets” means, collectively,

(a) the Refinery Tankage;

Annex A

(b) the Artesia Crude Oil Pipeline Tankage; and

(c) the Lovington Crude Oil Pipeline Tankage.

“Woods Cross Crude Oil Pipeline” means the 4 mile pipeline from Chevron to the Woods Cross Refinery (12 inch).

“Woods Cross Pipelines” means, collectively:

(a) the Woods Cross Crude Oil Pipeline;

(b) the Woods Cross Product Pipeline (Woods Cross-Chevron); and

(c) the Woods Cross Product Pipeline (Woods Cross-Pioneer).

“Woods Cross Product Pipeline (Woods Cross-Chevron)” means the 4 mile pipeline from Woods Cross Refinery to Chevron (8 inch).

“Woods Cross Product Pipeline (Woods Cross-Pioneer)” means the 2 mile pipeline from Woods Cross Refinery to Pioneer Pipeline (10 inch).

“Woods Cross Refinery” means the refining facilities located in Woods Cross, Utah.

“Woods Cross Refining” means Woods Cross Refining Company, L.L.C., a Delaware limited liability company.

In addition, the following terms have the meanings given to them in the Sections indicated in the following table:

Annex A

Term	Section
“Additives”	Section 2(g)
“Capital Calculation Notice”	Section 2(p)(ii)
“Capital Fee”	Section 2(p)(i)
“Claimant”	Section 12(e)
“Deficiency Notice”	Section 9(a)
“Deficiency Payment”	Section 9(a)
“DRA”	Section 2(g)
“Force Majeure Notice”	Section 3
“Gathering Pipeline Minimum Capacity”	Section 2(a)(ii)
“HEP Pipeline”	Preamble
“HEP Woods Cross”	Preamble
“HollyFrontier Entities”	Preamble
“HFRM”	Preamble
“Holly Refining – Woods Cross”	Preamble
“Incremental Capital”	Section 2(p)(i)
“Initial Tank Inspection Period”	Section 2(h)
“Initial Tank Inspections”	Section 2(h)
“Lease Connection Expense Cap”	Section 2(p)
“Letter Agreement”	Recitals
“Minimum Gathering Pipeline Revenue Commitment”	Section 2(a)(i)
“Minimum Roswell Pipeline Revenue Commitment”	Section 2(a)(i)
“Minimum Trunk Pipeline Revenue Commitment”	Section 2(a)(i)
“Minimum Woods Cross Pipeline Revenue Commitment”	Section 2(a)(i)
“Navajo Refining”	Preamble
“Operating Partnership”	Preamble
“Parties” or “Party”	Preamble
“Partnership Entities”	Preamble
“Purchase Agreement”	Recitals
“Refund”	Section 9(c)
“Respondent”	Section 12(e)
“Roswell Pipeline Minimum Capacity”	Section 2(a)(ii)
“Roswell Terminal Payment”	Section 2(d)
“Seller Parties”	Section 2(d)
“Tankage Revenue Commitment”	Section 2(c)
“Term”	Section 6
“Trunk Pipeline Minimum Capacity”	Section 2(a)(ii)
“Volume Incentive Tariff”	Section 2(b)(iii)
“Woods Cross Minimum Capacity”	Section 2(a)(ii)

Annex A

Annex A

SCHEDULE I

MINIMUM PIPELINE REVENUE COMMITMENT

Contract Year	Minimum Trunk Pipeline Revenue Commitment per Year	Minimum Gathering Pipeline Revenue Commitment per Year	Minimum Woods Cross Pipeline Revenue Commitment per Year	Minimum Roswell Pipeline Revenue Commitment per Contract Quarter
March 1, 2008	$13,552,450	$9,125,000	$730,000	$35,000
July 1, 2008	$14,076,293	$9,477,709	$758,217	$36,353
July 1, 2009	$14,963,451	$10,075,041	$806,003	$38,644
July 1, 2010	$14,963,451	$10,075,041	$806,003	$38,644
July 1, 2011	$15,596,689	$10,501,407	$840,113	$40,279
July 1, 2012	$16,524,864	$11,126,356	$890,108	$42,677

Schedule I-1

SCHEDULE II

VOLUME INCENTIVE TARIFF

Contract Year	Volume Incentive Tariff
January 1, 2009	$0.3258 per barrel
July 1, 2009	$0.3658 per barrel
July 1, 2010	$0.3658 per barrel
July 1, 2011	$0.3910 per barrel
July 1, 2012	$0.4246 per barrel

Schedule II-1

SCHEDULE III

TANKAGE REVENUE COMMITMENT

Contract Year	Tankage Revenue Commitment per Month
March 1, 2008	$184,000
July 1, 2008	$193,504
July 1, 2009	$208,215
July 1, 2010	$208,215
July 1, 2011	$222,544
July 1, 2012	$241,685

Schedule III-1

SCHEDULE IV

ROSWELL TERMINAL PAYMENT

Contract Year	Roswell Terminal Payment per Year
March 1, 2008	$100,000
July 1, 2008	$103,865
July 1, 2009	$110,411
July 1, 2010	$110,411
July 1, 2011	$115,083
July 1, 2012	$121,932

Schedule IV-1

EXHIBIT A

Attached to and made

Part of the Second Amended and Restated Crude Pipelines and Tankage Agreement, dated July 16, 2013

Crude Oil Trunk Pipeline Tariff Rate

		If the average volume is equal to or in excess of 85,000 bpd in any month
Contract Year	Volumes less than 85,000 bpd average volume in any month	The first 85,000 bpd average volume in any month	The next 7,500 bpd average volume in any month	Any excess up to a maximum of 110,000 bpd average volume in any month	Any excess above 110,000 bpd average volume in any month
March 1, 2008	$0.47 per barrel	$0.40 per barrel	$0.30 per barrel	$0.20 per barrel	To be mutually agreed upon by the Parties
July 1, 2008	$0.4943 per barrel	$0.4243 per barrel	$0.3243 per barrel	$0.2243 per barrel	To be mutually agreed upon by the Parties
July 1, 2009	$0.5317 per barrel	$0.4619 per barrel	$0.3619 per barrel	$0.2619 per barrel	To be mutually agreed upon by the Parties
July 1, 2010	$0.5317 per barrel	$0.4619 per barrel	$0.3619 per barrel	$0.2619 per barrel	To be mutually agreed upon by the Parties
July 1, 2011	$0.5685 per barrel	$0.4937 per barrel	$0.3868 per barrel	$0.2799 per barrel	To be mutually agreed upon by the Parties
July 1, 2012	$0.6174 per barrel	$0.5362 per barrel	$0.4201per barrel	$0.3040 per barrel	To be mutually agreed upon by the Parties

Exhibit A – Page 1 to Second Amended and Restated Crude Pipelines and Tankage Agreement

EXHIBIT B

Attached to and made

Part of the Second Amended and Restated Crude Pipelines and Tankage Agreement, dated July 16, 2013

Crude Oil Gathering Pipelines Tariff Rate

Contract Year	Crude Oil Gathering Pipelines Tariff Rate
March 1, 2008	$0.50 per barrel (which includes storage in the Artesia Crude Oil Pipeline Tankage and Lovington Crude Oil Pipeline Tankage)
July 1, 2008	$0.5258 per barrel (which includes storage in the Artesia Crude Oil Pipeline Tankage and Lovington Crude Oil Pipeline Tankage)
July 1, 2009	$0.5658 per barrel (which includes storage in the Artesia Crude Oil Pipeline Tankage and Lovington Crude Oil Pipeline Tankage)
July 1, 2010	$0.5658 per barrel (which includes storage in the Artesia Crude Oil Pipeline Tankage and Lovington Crude Oil Pipeline Tankage)
July 1, 2011	$0.6047 per barrel (which includes storage in the Artesia Crude Oil Pipeline Tankage and Lovington Crude Oil Pipeline Tankage)
July 1, 2012	$0.6567 per barrel (which includes storage in the Artesia Crude Oil Pipeline Tankage and Lovington Crude Oil Pipeline Tankage)

Exhibit B – Page 1 to Second Amended and Restated Crude Pipelines and Tankage Agreement

EXHIBIT C

Attached to and made

Part of the Second Amended and Restated Crude Pipelines and Tankage Agreement, dated July 16, 2013

Woods Cross Pipelines Tariff Rate

Contract Year	Woods Cross Pipelines Tariff Rate
March 1, 2008	$0.25 per barrel
July 1, 2008	$0.2629 per barrel
July 1, 2009	$0.2829 per barrel
July 1, 2010	$0.2829 per barrel
July 1, 2011	$0.3024 per barrel
July 1, 2012	$0.3284 per barrel

Exhibit C – Page 1 to Second Amended and Restated Crude Pipelines and Tankage Agreement

EXHIBIT D

Attached to and made

Part of the Second Amended and Restated Crude Pipelines and Tankage Agreement, dated July 16, 2013

Roswell Product Pipeline Tariff Rate

Contract Year	Roswell Product Pipeline Tariff Rate
March 1, 2008	$0.45 per barrel with a $0.50 per barrel capital recovery surcharge (to be indexed and which expires February 28, 2013)
July 1, 2008	$0.4732 per barrel with a $0.50 per barrel capital recovery surcharge (to be indexed and which expires February 28, 2013)
July 1, 2009	$0.5092 per barrel with a $0.50 per barrel capital recovery surcharge (to be indexed and which expires February 28, 2013)
July 1, 2010	$0.5092 per barrel with a $0.50 per barrel capital recovery surcharge (to be indexed and which expires February 28, 2013)
July 1, 2011	$0.5442 per barrel with a $0.50 per barrel capital recovery surcharge (to be indexed and which expires February 28, 2013)
July 1, 2012	$0.5910 per barrel with a $0.50 per barrel capital recovery surcharge (to be indexed and which expires February 28, 2013)

Exhibit D – Page 1 to Second Amended and Restated Crude Pipelines and Tankage Agreement

EXHIBIT E

Attached to and made

Part of the Second Amended and Restated Crude Pipelines and Tankage Agreement, dated July 16, 2013

Flow Reversal Rate

Contract Year	Flow Reversal Rate
March 1, 2008	$0.40 per barrel
July 1, 2008	$0.40 per barrel
July 1, 2009	$0.5319 per barrel
July 1, 2010	$0.5319 per barrel
July 1, 2011	$0.5685 per barrel
July 1, 2012	$0.6174 per barrel

Exhibit E – Page 1 to Second Amended and Restated Crude Pipelines and Tankage Agreement

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Matthew P. Clifton, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Holly Energy Partners, L.P;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a. all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

August 1, 2013	/s/ Matthew P. Clifton
	Matthew P. Clifton
	Chairman of the Board and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Douglas S. Aron, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Holly Energy Partners, L.P;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a. all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

August 1, 2013	/s/ Douglas S. Aron
	Douglas S. Aron
	Executive Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION OF CHIEF EXECUTIVE

OFFICER OF HOLLY ENERGY PARTNERS, L.P.

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying report on Form 10-Q for the quarterly period ended June 30, 2013 and filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Matthew P. Clifton, Chief Executive Officer of Holly Logistic Services, L.L.C., the general partner of HEP Logistics Holdings, L.P., the general partner of Holly Energy Partners, L.P (the “Company”), hereby certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: August 1, 2013	/s/ Matthew P. Clifton
	Matthew P. Clifton
	Chairman of the Board and Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION OF CHIEF FINANCIAL

OFFICER OF HOLLYFRONTIER CORPORATION

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying report on Form 10-Q for the quarterly period ended June 30, 2013 and filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Douglas S. Aron, Chief Financial Officer of Holly Logistic Services, L.L.C., the general partner of HEP Logistics Holdings, L.P., the general partner of Holly Energy Partners, L.P (the “Company”), hereby certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:    August 1, 2013	/s/ Douglas S. Aron
	Douglas S. Aron
	Executive Vice President and Chief Financial Officer

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Partners' Equity

6 Months Ended

Jun. 30, 2013

Partners' Capital [Abstract]

Partners' Equity

Partners’ Equity

As of June 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.

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.

Allocations of Net Income

Net income attributable to HEP is allocated between limited partners and the general partner interest in accordance with the provisions of the partnership agreement. HEP net income allocated to the general partner includes incentive distributions that are declared subsequent to quarter end. After 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 June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(In thousands)
General partner interest in net income	$	275	$	329	$	522	$	661
General partner incentive distribution	6,405		5,565		12,388		10,737
Total general partner interest in net income	$	6,680	$	5,894	$	12,910	$	11,398

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 July 26, 2013 we announced our cash distribution for the second quarter of 2013 of $0.4850 per unit. The distribution is payable on all common and general partner units and will be paid August 14, 2013 to all unitholders of record on August 5, 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 June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(In thousands, except per unit data)
General partner interest in net income	$	737	$	622	$	1,456	$	1,227
General partner incentive distribution	6,405		5,565		12,388		10,737
Total general partner distribution	7,142		6,187		13,844		11,964
Limited partner distribution	28,448		24,899		56,457		49,387
Total regular quarterly cash distribution	$	35,590	$	31,086	$	70,301	$	61,351
Cash distribution per unit applicable to limited partners	$	0.485	$	0.455	$	0.963	$	0.903

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.

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Consolidated Statements of Income (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended			6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012		Jun. 30, 2013		Jun. 30, 2012
Revenues:
Affiliates	$ 63,187	$ 57,774	[1]	$ 124,699	[1]	$ 114,305	[1]
Third parties	12,098	10,886	[1]	24,884		22,770	[1]
Total revenues	75,285	68,660	[1]	149,583		137,075	[1]
Operating costs and expenses:
Operations	24,538	21,907	[1]	50,403		42,382	[1]
Depreciation and amortization	15,127	14,150	[1]	29,281		28,450	[1]
General and administrative	3,100	2,487	[1]	6,332		4,526	[1]
Total operating costs and expenses	42,765	38,544	[1]	86,016		75,358	[1]
Operating income	32,520	30,116	[1]	63,567		61,717	[1]
Other income (expense):
Equity in earnings of SLC Pipeline	746	794	[1]	1,403		1,625	[1]
Interest expense	(11,629)	(11,324)	[1]	(24,113)		(21,729)	[1]
Interest income	4	0	[1]	107		0	[1]
Loss on early extinguishment of debt	0	(383)	[1]	0		(2,979)	[1]
Gain on sale of assets	0	0	[1]	2,022		0	[1]
Other nonoperating income (expense) and equity earnings	(10,879)	(10,913)	[1]	(20,581)		(23,083)	[1]
Income before income taxes	21,641	19,203	[1]	42,986		38,634	[1]
State income tax expense	(344)	(75)	[1]	(400)		(150)	[1]
Net Income	21,297	19,128	[1]	42,586		38,484	[1]
Allocation of net loss attributable to Predecessors	0	2,192	[1]	0		4,053	[1]
Allocation of Net Income (Loss) Attributable to Noncontrolling Interest	(1,130)	683	[1]	(4,020)		1,240	[1]
Net income attributable to Holly Energy Partners	20,167	22,003	[1]	38,566		43,777	[1]
General partner interest in net income, including incentive distributions	(6,680)	(5,894)	[1]	(12,910)		(11,398)	[1]
Limited partners’ interest in net income	$ 13,487	$ 16,109	[1]	$ 25,656		$ 32,379	[1]
Limited partners’ per unit interest in earnings—basic and diluted:	$ 0.23	$ 0.29	[1]	$ 0.44		$ 0.59	[1]
Weighted average limited partners’ units outstanding	58,657	54,722	[1]	57,828		54,722	[1]

[1] Restated as described in Note 1.

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Financial Instruments

6 Months Ended

Jun. 30, 2013

Fair Value Disclosures [Abstract]

Financial Instruments

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.

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

		June 30, 2013				December 31, 2012
Financial Instrument	Fair Value Input Level	Carrying Value		Fair Value		Carrying Value		Fair Value
		(In thousands)
Assets:
Interest rate swaps	Level 2	$	545	$	545	$	—	$	—
Liabilities:
Senior notes:
6.5% senior notes	Level 2	$	295,601	$	294,000	$	295,275	$	321,000
8.25% senior notes	Level 2	148,551		158,625		148,399		163,125
		444,152		452,625		443,674		484,125
Interest rate swaps	Level 2	—		—		3,430		3,430
		$	444,152	$	452,625	$	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.

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Significant Customers (Tables)

6 Months Ended

Jun. 30, 2013

Risks and Uncertainties [Abstract]

Schedules of Concentration of Risk, by Risk Factor

The following table presents the percentage of total revenues generated by each of these customers:

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
HFC	84	%	84	%	83	%	83	%
Alon	11	%	11	%	10	%	11	%

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Supplemental Guarantor / Non-Guarantor Financial Information

6 Months Ended

Jun. 30, 2013

Supplemental Guarantor / Non-Guarantor Financial Information [Abstract]

Supplemental Guarantor / Non-Guarantor Financial Information

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 wholly-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 the current year presentation.

Condensed Consolidating Balance Sheet

June 30, 2013	Parent		Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	2	$	—		$	8,714	$	—		$	8,716
Accounts receivable	—		32,791			3,604		(274		)	36,121
Intercompany accounts receivable (payable)	27,621		(27,621		)	—		—			—
Prepaid and other current assets	81		2,837			1,396		—			4,314
Total current assets	27,704		8,007			13,714		(274		)	49,151
Properties and equipment, net	—		562,282			391,850		—			954,132
Investment in subsidiaries	827,307		297,498			—		(1,124,805		)	—
Transportation agreements, net	—		91,123			—		—			91,123
Goodwill	—		256,498			—		—			256,498
Investment in SLC Pipeline	—		24,882			—		—			24,882
Other assets	1,752		9,173			—		—			10,925
Total assets	$	856,763	$	1,249,463		$	405,564	$	(1,125,079	)	$	1,386,711
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	—	$	11,094		$	2,900	$	(274	)	$	13,720
Accrued interest	10,198		116			—		—			10,314
Deferred revenue	—		5,094			3,507		—			8,601
Accrued property taxes	—		1,349			2,300		—			3,649
Other current liabilities	334		1,657			51		—			2,042
Total current liabilities	10,532		19,310			8,758		(274		)	38,326
Long-term debt	444,152		355,000			—		—			799,152
Other long-term liabilities	78		13,305			142		—			13,525
Deferred revenue	—		17,581			—		—			17,581
Class B unit	—		16,960			—		—			16,960
Equity - partners	402,001		827,307			396,664		(1,223,971		)	402,001
Equity - noncontrolling interest	—		—			—		99,166			99,166
Total liabilities and partners’ equity	$	856,763	$	1,249,463		$	405,564	$	(1,125,079	)	$	1,386,711

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

Condensed Consolidating Statement of Comprehensive Income

Three Months Ended June 30, 2013	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	60,797		$	2,698		$	(308	)	$	63,187
Third parties	—			10,116			1,982			—			12,098
	—			70,913			4,680			(308		)	75,285
Operating costs and expenses:
Operations	—			22,104			2,742			(308		)	24,538
Depreciation and amortization	—			11,543			3,584			—			15,127
General and administrative	983			2,117			—			—			3,100
	983			35,764			6,326			(308		)	42,765
Operating income (loss)	(983		)	35,149			(1,646		)	—			32,520
Equity in earnings (loss) of subsidiaries	29,413			(1,234		)	—			(28,179		)	—
Equity in earnings of SLC Pipeline	—			746			—			—			746
Interest expense	(8,263		)	(3,366		)	—			—			(11,629		)
Interest income	—			3			1			—			4
	21,150			(3,851		)	1			(28,179		)	(10,879		)
Income (loss) before income taxes	20,167			31,298			(1,645		)	(28,179		)	21,641
State income tax expense	—			(344		)	—			—			(344		)
Net income (loss)	20,167			30,954			(1,645		)	(28,179		)	21,297
Allocation of net (income) attributable to noncontrolling interests	—			—			—			(1,130		)	(1,130		)
Net income (loss) attributable to Holly Energy Partners	20,167			30,954			(1,645		)	(29,309		)	20,167
Other comprehensive income	3,413			3,413			—			(3,413		)	3,413
Comprehensive income (loss)	$	23,580		$	34,367		$	(1,645	)	$	(32,722	)	$	23,580

Condensed Consolidating Statement of Comprehensive Income

Three Months Ended June 30, 2012	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	55,263		$	2,776		$	(265	)	$	57,774
Third parties	—			9,752			1,134			—			10,886
	—			65,015			3,910			(265		)	68,660
Operating costs and expenses:
Operations	—			19,121			3,051			(265		)	21,907
Depreciation and amortization	—			10,562			3,588			—			14,150
General and administrative	484			2,003			—			—			2,487
	484			31,686			6,639			(265		)	38,544
Operating income (loss)	(484		)	33,329			(2,729		)	—			30,116
Equity in earnings (loss) of subsidiaries	28,987			(2,046		)	—			(26,941		)	—
Equity in earnings of SLC Pipeline	—			794			—			—			794
Interest expense	(8,309		)	(3,015		)	—			—			(11,324		)
Loss on early extinguishment of debt	(383		)	—			—			—			(383		)
	20,295			(4,267		)	—			(26,941		)	(10,913		)
Income (loss) before income taxes	19,811			29,062			(2,729		)	(26,941		)	19,203
State income tax expense	—			(75		)	—			—			(75		)
Net income (loss)	19,811			28,987			(2,729		)	(26,941		)	19,128
Allocation of net loss attributable to Predecessors	2,192			—			—			—			2,192
Allocation of net loss attributable to noncontrolling interests	—			—			—			683			683
Net income (loss) attributable to Holly Energy Partners	22,003			28,987			(2,729		)	(26,258		)	22,003
Other comprehensive income (loss)	(235		)	(235		)	—			235			(235		)
Comprehensive income (loss)	$	21,768		$	28,752		$	(2,729	)	$	(26,023	)	$	21,768

Condensed Consolidating Statement of Comprehensive Income

Six Months Ended June 30, 2013	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-restricted Subsidiaries		Eliminations				Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	115,210		$	10,100	$	(611	)		$	124,699
Third parties	—			18,523			6,361		—				24,884
	—			133,733			16,461		(611		)		149,583
Operating costs and expenses:
Operations	—			45,471			5,543		(611		)		50,403
Depreciation and amortization	—			22,113			7,168		—				29,281
General and administrative	1,791			4,541			—		—				6,332
	1,791			72,125			12,711		(611		)		86,016
Operating income (loss)	(1,791		)	61,608			3,750		—			—	63,567
Equity in earnings (loss) of subsidiaries	56,872			2,890			—		(59,762		)		—
Equity in earnings of SLC Pipeline	—			1,403			—		—				1,403
Interest expense	(16,515		)	(7,598		)	—		—				(24,113		)
Interest income	—			3			104		—				107
Other	—			2,022			—		—				2,022
	40,357			(1,280		)	104		(59,762		)		(20,581		)
Income before income taxes	38,566			60,328			3,854		(59,762		)		42,986
State income tax expense	—			(400		)	—		—				(400		)
Net income	38,566			59,928			3,854		(59,762		)		42,586
Allocation of net (income) attributable to noncontrolling interests	—			—			—		(4,020		)		(4,020		)
Net income attributable to Holly Energy Partners	38,566			59,928			3,854		(63,782		)		38,566
Other comprehensive income	4,824			4,824			—		(4,824		)		4,824
Comprehensive income	$	43,390		$	64,752		$	3,854	$	(68,606	)		$	43,390

Condensed Consolidating Statement of Comprehensive Income

Six Months Ended June 30, 2012	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	109,293		$	5,540		$	(528	)	$	114,305
Third parties	—			20,497			2,273			—			22,770
	—			129,790			7,813			(528		)	137,075
Operating costs and expenses:
Operations	—			37,262			5,648			(528		)	42,382
Depreciation and amortization	—			21,326			7,124			—			28,450
General and administrative	1,926			2,600			—			—			4,526
	1,926			61,188			12,772			(528		)	75,358
Operating income (loss)	(1,926		)	68,602			(4,959		)	—			61,717
Equity in earnings (loss) of subsidiaries	59,647			(3,719		)	—			(55,928		)	—
Equity in earnings of SLC Pipeline	—			1,625			—			—			1,625
Interest expense	(15,018		)	(6,711		)	—			—			(21,729		)
Loss on early extinguishment of debt	(2,979		)	—			—			—			(2,979		)
	41,650			(8,805		)	—			(55,928		)	(23,083		)
Income (loss) before income taxes	39,724			59,797			(4,959		)	(55,928		)	38,634
State income tax expense	—			(150		)	—			—			(150		)
Net income (loss)	39,724			59,647			(4,959		)	(55,928		)	38,484
Allocation of net loss attributable to Predecessors	4,053			—			—			—			4,053
Allocation of net loss attributable to noncontrolling interests	—			—			—			1,240			1,240
Net income (loss) attributable to Holly Energy Partners	43,777			59,647			(4,959		)	(54,688		)	43,777
Other comprehensive income (loss)	685			685			—			(685		)	685
Comprehensive income (loss)	$	44,462		$	60,332		$	(4,959	)	$	(55,373	)	$	44,462

Condensed Consolidating Statement of Cash Flows

Six Months Ended June 30, 2013	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities	$	(4,020	)	$	79,182		$	13,040		$	(6,000	)	$	82,202
Cash flows from investing activities
Additions to properties and equipment	—			(16,486		)	(738		)	—			(17,224		)
Proceeds from sale of assets	—			2,481			—			—			2,481
	—			(14,005		)	(738		)	—			(14,743		)
Cash flows from financing activities
Net borrowings under credit agreement	—			(66,000		)	—			—			(66,000		)
Proceeds from issuance of common units	73,444			—			—			—			73,444
Contribution from general partners	1,499			—			—			—			1,499
Distributions to HEP unitholders	(67,419		)	—			—			—			(67,419		)
Distributions to noncontrolling interests	—			—			(8,000		)	6,000			(2,000		)
Purchase of units for incentive grants	(3,254		)	—			—			—			(3,254		)
Other	(250		)	—			—			—			(250		)
	4,020			(66,000		)	(8,000		)	6,000			(63,980		)
Cash and cash equivalents
Increase for the period	—			(823		)	4,302			—			3,479
Beginning of period	2			823			4,412			—			5,237
End of period	$	2		$	—		$	8,714		$	—		$	8,716

Condensed Consolidating Statement of Cash Flows

Six Months Ended June 30, 2012	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations		Consolidated
	(In thousands)
Cash flows from operating activities	$	(45,135	)	$	118,635		$	(3,734	)	$	—	$	69,766
Cash flows from investing activities
Additions to properties and equipment	—			(12,008		)	(14,366		)	—		(26,374		)
Cash flows from financing activities
Net borrowings under credit agreement	—			(30,000		)	—			—		(30,000		)
Proceeds from issuance of senior notes	294,750			—			—			—		294,750
Repayments of notes	(185,000		)	(72,900		)	—			—		(257,900		)
Capital contribution from UNEV joint partners	—			—			15,000			—		15,000
Distributions to HEP unitholders	(59,977		)	—			—			—		(59,977		)
Purchase of units for incentive grants	(4,533		)	—			—			—		(4,533		)
Deferred financing costs	(567		)	(2,595		)	—			—		(3,162		)
Other	462			(185		)	—			—		277
	45,135			(105,680		)	15,000			—		(45,545		)
Cash and cash equivalents
Increase (decrease) for the period	—			947			(3,100		)	—		(2,153		)
Beginning of period	2			3,267			3,100			—		6,369
End of period	$	2		$	4,214		$	—		$	—	$	4,216

XML

Debt Interest Rate Risk Management (Details) (USD $)	3 Months Ended	6 Months Ended	12 Months Ended							6 Months Ended	12 Months Ended
	Jun. 30, 2013	Jun. 30, 2013	Dec. 31, 2013	Dec. 31, 2012	Jun. 30, 2013 Interest Rate Swap [Member] Cash Flow Hedging [Member]	Jun. 30, 2013 Interest Rate Swap [Member] Cash Fow Hedging - added in 2011 [Member]	Jun. 30, 2013 Interest Rate Swap [Member] Cash Flow Hedging, Added 2012 [Member]	Jun. 30, 2013 Other Liabilities [Member] Interest Rate Swap [Member] Cash Flow Hedging [Member]	Dec. 31, 2012 Other Liabilities [Member] Interest Rate Swap [Member] Cash Flow Hedging [Member]	Jun. 30, 2013 Accumulated Other Comprehensive Income (Loss) [Member] Interest Rate Swap [Member] Cash Flow Hedging [Member]	Dec. 31, 2012 Accumulated Other Comprehensive Income (Loss) [Member] Interest Rate Swap [Member] Cash Flow Hedging [Member]
Debt Instrument [Line Items]
Line of credit facility, amount outstanding					$ 305,000,000	$ 155,000,000	$ 150,000,000
Long-term debt, fixed interest rate					0.99%		0.74%
Debt instrument, basis spread on variable rate					2.50%		2.50%
Debt instrument, effective interest rate					3.49%		3.24%
Accumulated other comprehensive loss	545,000	545,000		(4,279,000)	500,000
Unrecognized loss on cash flow hedges										(545,000)	(3,430,000)
Derivative liabilities, fair value								545,000	3,430,000
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net	$ 500,000	$ 1,900,000	$ 100,000

XML

Description of Business and Presentation of Financial Statements (Details) (USD $)	3 Months Ended			6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012		Jun. 30, 2013	Jun. 30, 2012
Other Ownership Interests [Line Items]
Ownership percentage, controlling interest	39.00%			39.00%
General partner interest				2.00%
Equity Method Investment, Ownership Percentage	25.00%			25.00%
Sale of Stock, Number of Shares Issued in Transaction	1,875,000
Business Acquisitions, Limited partners interest in net income	$ 13,487,000	$ 16,109,000	[1]	$ 25,656,000	$ 32,379,000	[1]
Limited partners’ per unit interest in earnings—basic and diluted:	$ 0.23	$ 0.29	[1]	$ 0.44	$ 0.59	[1]
Proceeds from sale of common units				73,444,000
Correction of error - net income		1,200,000			1,400,000
Correction of error - limited partners per unit interest		$ 0.02		$ 0.03
SLC Pipeline [Member]
Other Ownership Interests [Line Items]
Equity Method Investment, Ownership Percentage	25.00%			25.00%
Crude Oil Pipeline, Length	95			95
UNEV Pipeline [Member]
Other Ownership Interests [Line Items]
Business Combination, Contingent Consideration Arrangements, Change in Amount of Contingent Consideration, Liability	$ (1,100,000)			$ (4,000,000)
Equity Method Investment, Ownership Percentage	75.00%			75.00%
Crude Oil Pipeline, Length	400			400
Description Of Pipeline Acquired	12			12
General Partner HFC [Member]
Other Ownership Interests [Line Items]
Sale of Stock, Number of Shares Issued in Transaction	1,875,000

[1] Restated as described in Note 1.

XML

Supplemental Guarantor / Non-Guarantor Financial Information (Tables)

6 Months Ended

Jun. 30, 2013

Supplemental Guarantor / Non-Guarantor Financial Information [Abstract]

Condensed Consolidating Balance Sheet

Condensed Consolidating Balance Sheet

June 30, 2013	Parent		Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	2	$	—		$	8,714	$	—		$	8,716
Accounts receivable	—		32,791			3,604		(274		)	36,121
Intercompany accounts receivable (payable)	27,621		(27,621		)	—		—			—
Prepaid and other current assets	81		2,837			1,396		—			4,314
Total current assets	27,704		8,007			13,714		(274		)	49,151
Properties and equipment, net	—		562,282			391,850		—			954,132
Investment in subsidiaries	827,307		297,498			—		(1,124,805		)	—
Transportation agreements, net	—		91,123			—		—			91,123
Goodwill	—		256,498			—		—			256,498
Investment in SLC Pipeline	—		24,882			—		—			24,882
Other assets	1,752		9,173			—		—			10,925
Total assets	$	856,763	$	1,249,463		$	405,564	$	(1,125,079	)	$	1,386,711
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	—	$	11,094		$	2,900	$	(274	)	$	13,720
Accrued interest	10,198		116			—		—			10,314
Deferred revenue	—		5,094			3,507		—			8,601
Accrued property taxes	—		1,349			2,300		—			3,649
Other current liabilities	334		1,657			51		—			2,042
Total current liabilities	10,532		19,310			8,758		(274		)	38,326
Long-term debt	444,152		355,000			—		—			799,152
Other long-term liabilities	78		13,305			142		—			13,525
Deferred revenue	—		17,581			—		—			17,581
Class B unit	—		16,960			—		—			16,960
Equity - partners	402,001		827,307			396,664		(1,223,971		)	402,001
Equity - noncontrolling interest	—		—			—		99,166			99,166
Total liabilities and partners’ equity	$	856,763	$	1,249,463		$	405,564	$	(1,125,079	)	$	1,386,711

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

Condensed Consolidating Statement of Comprehensive Income

Condensed Consolidating Statement of Comprehensive Income

Three Months Ended June 30, 2013	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	60,797		$	2,698		$	(308	)	$	63,187
Third parties	—			10,116			1,982			—			12,098
	—			70,913			4,680			(308		)	75,285
Operating costs and expenses:
Operations	—			22,104			2,742			(308		)	24,538
Depreciation and amortization	—			11,543			3,584			—			15,127
General and administrative	983			2,117			—			—			3,100
	983			35,764			6,326			(308		)	42,765
Operating income (loss)	(983		)	35,149			(1,646		)	—			32,520
Equity in earnings (loss) of subsidiaries	29,413			(1,234		)	—			(28,179		)	—
Equity in earnings of SLC Pipeline	—			746			—			—			746
Interest expense	(8,263		)	(3,366		)	—			—			(11,629		)
Interest income	—			3			1			—			4
	21,150			(3,851		)	1			(28,179		)	(10,879		)
Income (loss) before income taxes	20,167			31,298			(1,645		)	(28,179		)	21,641
State income tax expense	—			(344		)	—			—			(344		)
Net income (loss)	20,167			30,954			(1,645		)	(28,179		)	21,297
Allocation of net (income) attributable to noncontrolling interests	—			—			—			(1,130		)	(1,130		)
Net income (loss) attributable to Holly Energy Partners	20,167			30,954			(1,645		)	(29,309		)	20,167
Other comprehensive income	3,413			3,413			—			(3,413		)	3,413
Comprehensive income (loss)	$	23,580		$	34,367		$	(1,645	)	$	(32,722	)	$	23,580

Condensed Consolidating Statement of Comprehensive Income

Three Months Ended June 30, 2012	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	55,263		$	2,776		$	(265	)	$	57,774
Third parties	—			9,752			1,134			—			10,886
	—			65,015			3,910			(265		)	68,660
Operating costs and expenses:
Operations	—			19,121			3,051			(265		)	21,907
Depreciation and amortization	—			10,562			3,588			—			14,150
General and administrative	484			2,003			—			—			2,487
	484			31,686			6,639			(265		)	38,544
Operating income (loss)	(484		)	33,329			(2,729		)	—			30,116
Equity in earnings (loss) of subsidiaries	28,987			(2,046		)	—			(26,941		)	—
Equity in earnings of SLC Pipeline	—			794			—			—			794
Interest expense	(8,309		)	(3,015		)	—			—			(11,324		)
Loss on early extinguishment of debt	(383		)	—			—			—			(383		)
	20,295			(4,267		)	—			(26,941		)	(10,913		)
Income (loss) before income taxes	19,811			29,062			(2,729		)	(26,941		)	19,203
State income tax expense	—			(75		)	—			—			(75		)
Net income (loss)	19,811			28,987			(2,729		)	(26,941		)	19,128
Allocation of net loss attributable to Predecessors	2,192			—			—			—			2,192
Allocation of net loss attributable to noncontrolling interests	—			—			—			683			683
Net income (loss) attributable to Holly Energy Partners	22,003			28,987			(2,729		)	(26,258		)	22,003
Other comprehensive income (loss)	(235		)	(235		)	—			235			(235		)
Comprehensive income (loss)	$	21,768		$	28,752		$	(2,729	)	$	(26,023	)	$	21,768

Condensed Consolidating Statement of Comprehensive Income

Six Months Ended June 30, 2013	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-restricted Subsidiaries		Eliminations				Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	115,210		$	10,100	$	(611	)		$	124,699
Third parties	—			18,523			6,361		—				24,884
	—			133,733			16,461		(611		)		149,583
Operating costs and expenses:
Operations	—			45,471			5,543		(611		)		50,403
Depreciation and amortization	—			22,113			7,168		—				29,281
General and administrative	1,791			4,541			—		—				6,332
	1,791			72,125			12,711		(611		)		86,016
Operating income (loss)	(1,791		)	61,608			3,750		—			—	63,567
Equity in earnings (loss) of subsidiaries	56,872			2,890			—		(59,762		)		—
Equity in earnings of SLC Pipeline	—			1,403			—		—				1,403
Interest expense	(16,515		)	(7,598		)	—		—				(24,113		)
Interest income	—			3			104		—				107
Other	—			2,022			—		—				2,022
	40,357			(1,280		)	104		(59,762		)		(20,581		)
Income before income taxes	38,566			60,328			3,854		(59,762		)		42,986
State income tax expense	—			(400		)	—		—				(400		)
Net income	38,566			59,928			3,854		(59,762		)		42,586
Allocation of net (income) attributable to noncontrolling interests	—			—			—		(4,020		)		(4,020		)
Net income attributable to Holly Energy Partners	38,566			59,928			3,854		(63,782		)		38,566
Other comprehensive income	4,824			4,824			—		(4,824		)		4,824
Comprehensive income	$	43,390		$	64,752		$	3,854	$	(68,606	)		$	43,390

Condensed Consolidating Statement of Comprehensive Income

Six Months Ended June 30, 2012	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	109,293		$	5,540		$	(528	)	$	114,305
Third parties	—			20,497			2,273			—			22,770
	—			129,790			7,813			(528		)	137,075
Operating costs and expenses:
Operations	—			37,262			5,648			(528		)	42,382
Depreciation and amortization	—			21,326			7,124			—			28,450
General and administrative	1,926			2,600			—			—			4,526
	1,926			61,188			12,772			(528		)	75,358
Operating income (loss)	(1,926		)	68,602			(4,959		)	—			61,717
Equity in earnings (loss) of subsidiaries	59,647			(3,719		)	—			(55,928		)	—
Equity in earnings of SLC Pipeline	—			1,625			—			—			1,625
Interest expense	(15,018		)	(6,711		)	—			—			(21,729		)
Loss on early extinguishment of debt	(2,979		)	—			—			—			(2,979		)
	41,650			(8,805		)	—			(55,928		)	(23,083		)
Income (loss) before income taxes	39,724			59,797			(4,959		)	(55,928		)	38,634
State income tax expense	—			(150		)	—			—			(150		)
Net income (loss)	39,724			59,647			(4,959		)	(55,928		)	38,484
Allocation of net loss attributable to Predecessors	4,053			—			—			—			4,053
Allocation of net loss attributable to noncontrolling interests	—			—			—			1,240			1,240
Net income (loss) attributable to Holly Energy Partners	43,777			59,647			(4,959		)	(54,688		)	43,777
Other comprehensive income (loss)	685			685			—			(685		)	685
Comprehensive income (loss)	$	44,462		$	60,332		$	(4,959	)	$	(55,373	)	$	44,462

Condensed Consolidating Statement of Cash Flows

Condensed Consolidating Statement of Cash Flows

Six Months Ended June 30, 2013	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities	$	(4,020	)	$	79,182		$	13,040		$	(6,000	)	$	82,202
Cash flows from investing activities
Additions to properties and equipment	—			(16,486		)	(738		)	—			(17,224		)
Proceeds from sale of assets	—			2,481			—			—			2,481
	—			(14,005		)	(738		)	—			(14,743		)
Cash flows from financing activities
Net borrowings under credit agreement	—			(66,000		)	—			—			(66,000		)
Proceeds from issuance of common units	73,444			—			—			—			73,444
Contribution from general partners	1,499			—			—			—			1,499
Distributions to HEP unitholders	(67,419		)	—			—			—			(67,419		)
Distributions to noncontrolling interests	—			—			(8,000		)	6,000			(2,000		)
Purchase of units for incentive grants	(3,254		)	—			—			—			(3,254		)
Other	(250		)	—			—			—			(250		)
	4,020			(66,000		)	(8,000		)	6,000			(63,980		)
Cash and cash equivalents
Increase for the period	—			(823		)	4,302			—			3,479
Beginning of period	2			823			4,412			—			5,237
End of period	$	2		$	—		$	8,714		$	—		$	8,716

Condensed Consolidating Statement of Cash Flows

Six Months Ended June 30, 2012	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations		Consolidated
	(In thousands)
Cash flows from operating activities	$	(45,135	)	$	118,635		$	(3,734	)	$	—	$	69,766
Cash flows from investing activities
Additions to properties and equipment	—			(12,008		)	(14,366		)	—		(26,374		)
Cash flows from financing activities
Net borrowings under credit agreement	—			(30,000		)	—			—		(30,000		)
Proceeds from issuance of senior notes	294,750			—			—			—		294,750
Repayments of notes	(185,000		)	(72,900		)	—			—		(257,900		)
Capital contribution from UNEV joint partners	—			—			15,000			—		15,000
Distributions to HEP unitholders	(59,977		)	—			—			—		(59,977		)
Purchase of units for incentive grants	(4,533		)	—			—			—		(4,533		)
Deferred financing costs	(567		)	(2,595		)	—			—		(3,162		)
Other	462			(185		)	—			—		277
	45,135			(105,680		)	15,000			—		(45,545		)
Cash and cash equivalents
Increase (decrease) for the period	—			947			(3,100		)	—		(2,153		)
Beginning of period	2			3,267			3,100			—		6,369
End of period	$	2		$	4,214		$	—		$	—	$	4,216

XML

Supplemental Guarantor / Non-Guarantor Financial Information Condensed Consolidating Statement of Comprehensive Income (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended			6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012		Jun. 30, 2013		Jun. 30, 2012
Revenues [Abstract]
Affiliates	$ 63,187	$ 57,774	[1]	$ 124,699	[1]	$ 114,305	[1]
Third parties	12,098	10,886	[1]	24,884		22,770	[1]
Total revenues	75,285	68,660	[1]	149,583		137,075	[1]
Operating costs and expenses [Abstract]
Operations	24,538	21,907	[1]	50,403		42,382	[1]
Depreciation and amortization	15,127	14,150	[1]	29,281		28,450	[1]
General and administrative	3,100	2,487	[1]	6,332		4,526	[1]
Total operating costs and expenses	42,765	38,544	[1]	86,016		75,358	[1]
Operating income (loss)	32,520	30,116	[1]	63,567		61,717	[1]
Equity in earnings of subsidiaries	0	0		0		0
Equity in earnings of SLC Pipeline	746	794	[1]	1,403		1,625	[1]
Interest Expense	11,629	11,324	[1]	24,113		21,729	[1]
Interest Revenue (Expense), Net		(11,324)				(21,729)
Interest Income	4			107
Other Nonoperating Income (Expense)				2,022
Loss on early extinguishment of debt	0	(383)	[1]	0		(2,979)	[1]
Other Nonoperating Income (Expense), Equity Earnings and Acquisition Costs	(10,879)	(10,913)	[1]	(20,581)		(23,083)	[1]
Income before income taxes	21,641	19,203	[1]	42,986		38,634	[1]
State income tax expense	(344)	(75)		(400)		150
Net Income	21,297	19,128	[1]	42,586		38,484	[1]
Allocation of net loss attributable to Predecessors	0	2,192	[1]	0		4,053	[1]
Allocation of Net Income (Loss) Attributable to Noncontrolling Interest	(1,130)	683	[1]	(4,020)		1,240	[1]
Net Income (Loss) Attributable to Parent	20,167	22,003	[1]	38,566		43,777	[1]
Other comprehensive income (loss)	3,413	(235)	[1]	4,824		685	[1]
Comprehensive income before noncontrolling interest	24,710	21,085	[1]	47,410		43,222	[1]
Comprehensive Income (Loss) net of Noncontrolling Interest	23,580	21,768	[1]	43,390		44,462	[1]
SLC Pipeline [Member]
Operating costs and expenses [Abstract]
Equity in earnings of SLC Pipeline	746	794		1,403		1,625
Parent [Member]
Revenues [Abstract]
Affiliates	0	0		0		0
Third parties	0	0		0		0
Total revenues	0	0		0		0
Operating costs and expenses [Abstract]
Operations	0	0		0		0
Depreciation and amortization	0	0		0		0
General and administrative	983	484		1,791		1,926
Total operating costs and expenses	983	484		1,791		1,926
Operating income (loss)	(983)	(484)		(1,791)		(1,926)
Equity in earnings of subsidiaries	29,413	28,987		56,872		59,647
Interest Expense	(8,263)			(16,515)
Interest Revenue (Expense), Net		(8,309)				(15,018)
Interest Income	0			0
Other Nonoperating Income (Expense)				0
Loss on early extinguishment of debt		(383)				(2,979)
Other Nonoperating Income (Expense), Equity Earnings and Acquisition Costs	21,150	20,295		40,357		41,650
Income before income taxes	20,167	19,811		38,566		39,724
State income tax expense	0	0		0		0
Net Income	20,167	19,811		38,566		39,724
Allocation of net loss attributable to Predecessors		2,192				4,053
Allocation of Net Income (Loss) Attributable to Noncontrolling Interest	0	0		0		0
Net Income (Loss) Attributable to Parent	20,167	22,003		38,566		43,777
Other comprehensive income (loss)	3,413	(235)		4,824		685
Comprehensive income before noncontrolling interest	23,580	21,768		43,390		44,462
Parent [Member] | SLC Pipeline [Member]
Operating costs and expenses [Abstract]
Equity in earnings of SLC Pipeline	0	0		0		0
Guarantor Subsidiaries [Member]
Revenues [Abstract]
Affiliates	60,797	55,263		115,210		109,293
Third parties	10,116	9,752		18,523		20,497
Total revenues	70,913	65,015		133,733		129,790
Operating costs and expenses [Abstract]
Operations	22,104	19,121		45,471		37,262
Depreciation and amortization	11,543	10,562		22,113		21,326
General and administrative	2,117	2,003		4,541		2,600
Total operating costs and expenses	35,764	31,686		72,125		61,188
Operating income (loss)	35,149	33,329		61,608		68,602
Equity in earnings of subsidiaries	(1,234)	(2,046)		2,890		(3,719)
Interest Expense	(3,366)			(7,598)
Interest Revenue (Expense), Net		(3,015)				(6,711)
Interest Income	3			3
Other Nonoperating Income (Expense)				2,022
Loss on early extinguishment of debt		0				0
Other Nonoperating Income (Expense), Equity Earnings and Acquisition Costs	(3,851)	(4,267)		(1,280)		(8,805)
Income before income taxes	31,298	29,062		60,328		59,797
State income tax expense	(344)	(75)		(400)		150
Net Income	30,954	28,987		59,928		59,647
Allocation of net loss attributable to Predecessors		0				0
Allocation of Net Income (Loss) Attributable to Noncontrolling Interest	0	0		0		0
Net Income (Loss) Attributable to Parent	30,954	28,987		59,928		59,647
Other comprehensive income (loss)	3,413	(235)		4,824		685
Comprehensive income before noncontrolling interest	34,367	28,752		64,752		60,332
Guarantor Subsidiaries [Member] | SLC Pipeline [Member]
Operating costs and expenses [Abstract]
Equity in earnings of SLC Pipeline	746	794		1,403		1,625
Non-Guarantor Subsidiaries [Member]
Revenues [Abstract]
Affiliates	2,698	2,776		10,100		5,540
Third parties	1,982	1,134		6,361		2,273
Total revenues	4,680	3,910		16,461		7,813
Operating costs and expenses [Abstract]
Operations	2,742	3,051		5,543		5,648
Depreciation and amortization	3,584	3,588		7,168		7,124
General and administrative	0	0		0		0
Total operating costs and expenses	6,326	6,639		12,711		12,772
Operating income (loss)	(1,646)	(2,729)		3,750		(4,959)
Equity in earnings of subsidiaries	0	0		0		0
Interest Expense	0			0
Interest Revenue (Expense), Net		0				0
Interest Income	1			104
Other Nonoperating Income (Expense)				0
Loss on early extinguishment of debt		0				0
Other Nonoperating Income (Expense), Equity Earnings and Acquisition Costs	1	0		104		0
Income before income taxes	(1,645)	(2,729)		3,854		(4,959)
State income tax expense	0	0		0		0
Net Income	(1,645)	(2,729)		3,854		4,959
Allocation of net loss attributable to Predecessors		0				0
Allocation of Net Income (Loss) Attributable to Noncontrolling Interest	0	0		0		0
Net Income (Loss) Attributable to Parent	(1,645)	(2,729)		3,854		(4,959)
Other comprehensive income (loss)	0	0		0		0
Comprehensive income before noncontrolling interest	(1,645)	(2,729)		3,854		(4,959)
Non-Guarantor Subsidiaries [Member] | SLC Pipeline [Member]
Operating costs and expenses [Abstract]
Equity in earnings of SLC Pipeline	0	0		0		0
Eliminations [Member]
Revenues [Abstract]
Affiliates	(308)	(265)		(611)		(528)
Third parties	0	0		0		0
Total revenues	(308)	(265)		(611)		(528)
Operating costs and expenses [Abstract]
Operations	(308)	(265)		(611)		(528)
Depreciation and amortization	0	0		0		0
General and administrative	0	0		0		0
Total operating costs and expenses	(308)	(265)		(611)		(528)
Operating income (loss)	0	0		0		0
Equity in earnings of subsidiaries	(28,179)	(26,941)		(59,762)		(55,928)
Interest Expense	0			0
Interest Revenue (Expense), Net		0				0
Interest Income	0			0
Other Nonoperating Income (Expense)				0
Loss on early extinguishment of debt		0				0
Other Nonoperating Income (Expense), Equity Earnings and Acquisition Costs	(28,179)	(26,941)		(59,762)		(55,928)
Income before income taxes	(28,179)	(26,941)		(59,762)		(55,928)
State income tax expense	0	0		0		0
Net Income	(28,179)	(26,941)		(59,762)		55,928
Allocation of net loss attributable to Predecessors		0				0
Allocation of Net Income (Loss) Attributable to Noncontrolling Interest	(1,130)	683		(4,020)		1,240
Net Income (Loss) Attributable to Parent	(29,309)	(26,258)		(63,782)		(54,688)
Other comprehensive income (loss)	(3,413)	235		(4,824)		(685)
Comprehensive income before noncontrolling interest	(32,722)	(26,023)		(68,606)		(55,373)
Eliminations [Member] | SLC Pipeline [Member]
Operating costs and expenses [Abstract]
Equity in earnings of SLC Pipeline	$ 0	$ 0		$ 0		$ 0

[1] Restated as described in Note 1.

XML

Employees, Retirement and Incentive Plans Performance Units (Details) (USD $)	6 Months Ended			3 Months Ended		6 Months Ended			3 Months Ended
	Jun. 30, 2013	Jun. 30, 2012		Jun. 30, 2013 Selected Executives [Member] Performance Units [Member]	Jun. 30, 2013 Certain Officers [Member] Performance Units [Member]	Jun. 30, 2013 Long-term Incentive Plan [Member] Performance Units [Member]	Jun. 30, 2013 Long-term Incentive Plan [Member] Certain Officers [Member] Performance Units [Member]	Jun. 30, 2013 Long-term Incentive Plan [Member] Executive Officer [Member] Performance Units [Member]	Jun. 30, 2013 Maximum [Member] Performance Share Units Member
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Estimated Share Payouts, Outstanding Nonvested Performance Unit Awards Maximum				125.00%
Award vesting period				3 years	3 years				3 years
Estimated Share Payouts, Outstanding Nonvested Performance Unit Awards Minimum				100.00%
Grants in period							32,888
Range of performance units earned, based on performance units granted, minimum (percent)							0.00%	50.00%
Range of Performance Units Earned, Based on Performance Units Granted, Maximum							200.00%	150.00%
Grants in period, weighted average grant date fair value							$ 40.86
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward]
Outstanding at January 1, 2013 (nonvested)	54,498
Granted	32,888
Vesting and transfer of full ownership to recipients	(25,124)
Outstanding at June 30, 2013 (nonvested)	62,262
Fair value of vested units transferred to recipients						$ 500,000
Total unrecognized compensation related to nonvested units						1,400,000
Weighted average remaining contractual term (years)						1 year 8 months 16 days
Purchase of units for incentive grants	$ (3,254,000)	$ (4,533,000)	[1]

[1] Restated as described in Note 1.

XML

Significant Customers (Details) (Total Revenue [Member])	3 Months Ended	6 Months Ended	3 Months Ended				6 Months Ended
	Jun. 30, 2013	Jun. 30, 2013 Customers	Jun. 30, 2013 QTD [Member] HFC [Member]	Jun. 30, 2012 QTD [Member] HFC [Member]	Jun. 30, 2013 QTD [Member] Alon [Member]	Jun. 30, 2012 QTD [Member] Alon [Member]	Jun. 30, 2013 YTD [Member] HFC [Member]	Jun. 30, 2012 YTD [Member] HFC [Member]	Jun. 30, 2013 YTD [Member] Alon [Member]	Jun. 30, 2012 YTD [Member] Alon [Member]
Revenue, Major Customer [Line Items]
Concentration risk, percentage	95.00%		84.00%	84.00%	11.00%	11.00%	83.00%	83.00%	10.00%	11.00%
Concentration risk, number of significant customers		2

XML

Transportation Agreements (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Jun. 30, 2013 Y	Dec. 31, 2012
Finite-Lived Intangible Assets, Net [Abstract]
Transportation agreements, gross	$ 134,164	$ 134,164
Less accumulated amortization	43,041	39,568
Transportation agreements, net	91,123	94,596
Alon transportation agreement
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Useful Life (years)	30 years
Finite-Lived Intangible Assets, Useful Life, Initial Term (years)	15
Finite-Lived Intangible Assets, Useful Life, Extension Period (years)	15
Finite-Lived Intangible Assets, Net [Abstract]
Transportation agreements, gross	59,933	59,933
HFC transportation agreement
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Useful Life (years)	15 years
Finite-Lived Intangible Assets, Net [Abstract]
Transportation agreements, gross	$ 74,231	$ 74,231

XML

Partners' Equity, Allocations of Net Income (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended			6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012		Jun. 30, 2013	Jun. 30, 2012
Partners' Capital [Abstract]
General partner interest in net income	$ 275	$ 329		$ 522	$ 661
General partner incentive distribution	(6,405)	(5,565)		(12,388)	(10,737)
General partner interest in net income attributable to HEP	$ (6,680)	$ (5,894)	[1]	$ (12,910)	$ (11,398)	[1]

[1] Restated as described in Note 1.

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Partners' Equity (Tables)

6 Months Ended

Jun. 30, 2013

Partners' Capital [Abstract]

Schedule of Allocation of General Partner Interest in Net Income

The following table presents the allocation of the general partner interest in net income for the periods presented below:

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(In thousands)
General partner interest in net income	$	275	$	329	$	522	$	661
General partner incentive distribution	6,405		5,565		12,388		10,737
Total general partner interest in net income	$	6,680	$	5,894	$	12,910	$	11,398

Schedule of Distributions Made to Members or Limited Partners, by Distribution

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 June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(In thousands, except per unit data)
General partner interest in net income	$	737	$	622	$	1,456	$	1,227
General partner incentive distribution	6,405		5,565		12,388		10,737
Total general partner distribution	7,142		6,187		13,844		11,964
Limited partner distribution	28,448		24,899		56,457		49,387
Total regular quarterly cash distribution	$	35,590	$	31,086	$	70,301	$	61,351
Cash distribution per unit applicable to limited partners	$	0.485	$	0.455	$	0.963	$	0.903

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Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012
Cash flows from operating activities
Net Income	$ 42,586	$ 38,484	[1]
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	29,281	28,450	[1]
Gain on sale of asset	(2,022)	0	[1]
Amortization of Deferred Charges	1,910	3,949	[1]
Equity in earnings of SLC Pipeline, net of distributions	159	(125)	[1]
Amortization of restricted and performance units	1,880	1,629	[1]
(Increase) decrease in current assets:
Accounts receivable – trade	2,576	(3,443)	[1]
Accounts receivable – affiliates	22	3,331	[1]
Prepaid and other current assets	(695)	(723)	[1]
Increase (decrease) in current liabilities:
Accounts payable – trade	(518)	(6,235)	[1]
Accounts payable – affiliates	(301)	(1,264)	[1]
Accrued interest	88	1,375	[1]
Deferred revenue	5,787	(429)	[1]
Accrued property taxes	961	(286)	[1]
Other current liabilities	153	4,711	[1]
Other, net	335	342	[1]
Net cash provided by operating activities	82,202	69,766	[1]
Cash flows from investing activities
Additions to properties and equipment	(17,224)	(26,374)	[1]
Proceeds from Sale of assets	2,481	0	[1]
Net cash used for investing activities	(14,743)	(26,374)	[1]
Cash flows from financing activities
Borrowings under credit agreement	154,500	99,000	[1]
Repayments of credit agreement borrowings	(220,500)	(129,000)	[1]
Proceeds from issuance of senior notes	0	294,750	[1]
Proceeds from sale of common units	73,444	0	[1]
Repayments of notes	0	257,900	[1]
Contribution From UNEV Joint Venture Partner	0	15,000	[1]
Distributions to HEP unitholders	(67,419)	(59,977)	[1]
Distributions made to joint venture partners	(2,000)	0	[1]
Contribution from general partner	1,499	0	[1]
Purchase of units for incentive grants	(3,254)	(4,533)	[1]
Deferred financing costs	0	(3,162)	[1]
Other	(250)	277	[1]
Net cash used for financing activities	(63,980)	(45,545)	[1]
Cash and cash equivalents
Increase for the period	3,479	(2,153)	[1]
Beginning of period	5,237	6,369	[1]
End of period	$ 8,716	$ 4,216	[1]

[1] Restated as described in Note 1.

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Description of Business and Presentation of Financial Statements

6 Months Ended

Jun. 30, 2013

Accounting Policies [Abstract]

Description of Business and Presentation of Financial Statements

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 six months ended June 30, 2012 included in the accompanying financial statements and notes thereto were revised from the amounts previously reported for those periods due to accounting rules that require retrospective restatement of previously reported results in cases of business combinations between entities under common control. We have therefore included herein the results of UNEV prior to our acquisition on July 12, 2012 referred to as results attributable to the Predecessor. See Note 2 below for additional information on the UNEV acquisition. Additional revisions were 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 six months ended June 30, 2012 by $1.2 million and $1.4 million, respectively, and reduced the limited partners' per unit interest in net earnings - basic and diluted by $0.02 and $0.03, respectively, and were comprised principally of an adjustment of depreciation expense related to 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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Properties and Equipment

6 Months Ended

Jun. 30, 2013

Property, Plant and Equipment [Abstract]

Properties and Equipment

Properties and Equipment

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

	June 30, 2013		December 31, 2012
	(In thousands)
Pipelines, terminals and tankage	$	1,061,626	$	1,049,531
Land and right of way	63,196		63,248
Construction in progress	37,032		27,150
Other	18,251		24,462
	1,180,105		1,164,391
Less accumulated depreciation	225,973		203,856
	$	954,132	$	960,535

We capitalized $0.2 million and $0.1 million in interest related to construction projects during the six months ended June 30, 2013 and 2012, respectively.

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Acquisitions

6 Months Ended

Jun. 30, 2013

Business Combinations [Abstract]

Acquisitions

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 $17.0 million at June 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 $1.1 million and $4.0 million for the three and six months ended June 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 six months ended June 30, 2012 our consolidated statement of income includes Predecessor revenues from UNEV of $3.9 million and $7.8 million, respectively, and Predecessor net losses of $2.2 million and $4.1 million, respectively.

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Related Party Transactions (Narrative) (Details) (USD $)	3 Months Ended			6 Months Ended					3 Months Ended		6 Months Ended			3 Months Ended		6 Months Ended		3 Months Ended		6 Months Ended		3 Months Ended		6 Months Ended		3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012		Jun. 30, 2013		Jun. 30, 2012		Dec. 31, 2012	Jun. 30, 2013 Affiliated Entity [Member]	Jun. 30, 2012 Affiliated Entity [Member]	Jun. 30, 2013 Affiliated Entity [Member]	Jun. 30, 2012 Affiliated Entity [Member]	Dec. 31, 2012 Affiliated Entity [Member]	Jun. 30, 2013 Annual Administrative Fee [Member] Affiliated Entity [Member]	Jun. 30, 2012 Annual Administrative Fee [Member] Affiliated Entity [Member]	Jun. 30, 2013 Annual Administrative Fee [Member] Affiliated Entity [Member]	Jun. 30, 2012 Annual Administrative Fee [Member] Affiliated Entity [Member]	Jun. 30, 2013 Reimbursements Paid [Member] Affiliated Entity [Member]	Jun. 30, 2012 Reimbursements Paid [Member] Affiliated Entity [Member]	Jun. 30, 2013 Reimbursements Paid [Member] Affiliated Entity [Member]	Jun. 30, 2012 Reimbursements Paid [Member] Affiliated Entity [Member]	Jun. 30, 2013 Proceeds From Reimbursements Received [Member] Affiliated Entity [Member]	Jun. 30, 2012 Proceeds From Reimbursements Received [Member] Affiliated Entity [Member]	Jun. 30, 2013 Proceeds From Reimbursements Received [Member] Affiliated Entity [Member]	Jun. 30, 2012 Proceeds From Reimbursements Received [Member] Affiliated Entity [Member]	Jun. 30, 2013 Shortfall Payments [Member] Affiliated Entity [Member]	Dec. 31, 2012 Shortfall Payments [Member] Affiliated Entity [Member]	Jun. 30, 2013 Shortfall Payments [Member] Affiliated Entity [Member]	Jun. 30, 2013 UNEV Pipeline [Member]
Related Party Transaction [Line Items]
Minimum Annualized Payments Change									$ 4,700,000		$ 4,700,000
Minimum annualized payments receivable from affiliate									225,500,000		225,500,000
Expenses resulting from agreement with related party																2,300,000
Revenue from related parties	63,187,000	57,774,000	[1]	124,699,000	[1]	114,305,000	[1]																			700,000		4,700,000
Costs and Expenses, Related Party														600,000	600,000	1,200,000	1,200,000
Reimbursements paid to related parties																		9,400,000	7,100,000	19,200,000	14,800,000	4,300,000	2,200,000	9,200,000	4,700,000
Distributions to unitholders				67,419,000		59,977,000	[1]		17,400,000	15,700,000	34,800,000	31,000,000
Due from Affiliates	31,571,000			31,571,000				31,594,000	31,600,000		31,600,000		31,600,000
Due to Affiliate, Current	4,362,000			4,362,000				4,985,000	4,400,000		4,400,000		5,000,000
Deferred revenue, related parties																											$ 5,100,000	$ 5,000,000
Equity Method Investment, Ownership Percentage	25.00%			25.00%																									75.00%

[1] Restated as described in Note 1.

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Acquisitions (Details) (USD $)	0 Months Ended	3 Months Ended			6 Months Ended
	Jul. 12, 2012 Consecutive_Quarters	Jun. 30, 2013	Sep. 30, 2012	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012	Dec. 31, 2012
Business Acquisition [Line Items]
Equity Method Investment, Ownership Percentage		25.00%			25.00%
Class B unit		$ 16,960,000			$ 16,960,000		$ 13,903,000
UNEV Pipeline [Member]
Business Acquisition [Line Items]
Equity Method Investment, Ownership Percentage		75.00%			75.00%
Cash distribution to HFC for UNEV Acquisition	260,000,000
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares	2,059,800
Business Acquisition, Payment of Contingent Consideration	900,000
Business Acquisition, Post Acquisition Incentive Distributions			1,250,000		30,000,000
Number of Consecutive Quarters, Forego Rights to Incentive Distributions	12
Number Of Consecutive Quarters, Forego Rights To Incentive Distributions, Extension	4
Class B unit		17,000,000			17,000,000		13,900,000
Business Combination, Contingent Consideration Arrangements, Change in Amount of Contingent Consideration, Liability		(1,100,000)			(4,000,000)
Compound Percentage Increase to Class B Equity Units					7.00%
Net Income (Loss) for Period Prior to Acquisition				2,200,000		4,100,000
Revenues for period prior to acquisition				$ 3,900,000		$ 7,800,000

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Employees, Retirement and Incentive Plans Retirement and Benefit Plan Costs (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013 Components Types	Jun. 30, 2012	Jun. 30, 2013 Types	Jun. 30, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Long-term incentive plan, components	4
Equity-based compensation, types	2		2
Units authorized under equity-based compensation plans	$ 0.8	$ 0.7	$ 1.9	$ 1.6
Long-term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units authorized under equity-based compensation plans (new)	2,500,000		2,500,000
Number of units available for grant	1,732,433		1,732,433
Retirement Costs [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee benefits and share-based compensation	$ 1.9	$ 1.7	$ 3.8	$ 3.1

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Debt Long-Term Debt (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Debt Instrument [Line Items]
Total long-term debt	$ 799,152	$ 864,674
Credit Agreement [Member]
Debt Instrument [Line Items]
Credit Agreement	355,000	421,000
Senior Notes [Member] | 6.5% Senior Notes [Member]
Debt Instrument [Line Items]
Principal	300,000	300,000
Unamortized discount	(4,399)	4,725
Senior Notes	295,601	295,275
Senior Notes [Member] | 8.25% Senior Notes [Member]
Debt Instrument [Line Items]
Principal	150,000	150,000
Unamortized discount	(1,449)	(1,601)
Senior Notes		$ 148,399

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Supplemental Guarantor / Non-Guarantor Financial Information Condensed Consolidated Balance Sheet (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012	Jun. 30, 2012		Dec. 31, 2011
Current assets:
Cash and cash equivalents	$ 8,716	$ 5,237	$ 4,216	[1]	$ 6,369	[1]
Accounts receivable	36,121	38,720
Intercompany accounts receivable (payable)	0	0
Prepaid and other current assets	4,314	3,619
Total current assets	49,151	47,576
Properties and equipment, net	954,132	960,535
Investments in subsidiaries	0	0
Transportation agreements, net	91,123	94,596
Goodwill	256,498	256,498
Investment in SLC Pipeline	24,882	25,041
Other assets	10,925	9,864
Total assets	1,386,711	1,394,110
Current liabilities:
Accounts payable	13,720	12,030
Accrued interest	10,314	10,226
Deferred revenue	8,601	8,901
Accrued property taxes	3,649	2,688
Other current liabilities	2,042	1,905
Total current liabilities	38,326	35,750
Long-term debt	799,152	864,674
Other long-term liabilities	13,525	15,433
Deferred Revenue, Noncurrent	17,581	11,494
Class B unit	16,960	13,903
Total partners' equity	402,001	352,653
Equity - noncontrolling interest	99,166	100,203
Total liabilities and equity	1,386,711	1,394,110
Parent [Member]
Current assets:
Cash and cash equivalents	2	2	2		2
Accounts receivable	0	0
Intercompany accounts receivable (payable)	27,621	42,194
Prepaid and other current assets	81	224
Total current assets	27,704	42,420
Properties and equipment, net	0	0
Investments in subsidiaries	827,307	763,569
Transportation agreements, net	0	0
Goodwill	0	0
Investment in SLC Pipeline	0	0
Other assets	1,752	1,154
Total assets	856,763	807,143
Current liabilities:
Accounts payable	0	0
Accrued interest	10,198	10,198
Deferred revenue	0	0
Accrued property taxes	0	0
Other current liabilities	334	563
Total current liabilities	10,532	10,761
Long-term debt	444,152	443,674
Other long-term liabilities	78	55
Deferred Revenue, Noncurrent	0	0
Class B unit	0	0
Total partners' equity	402,001	352,653
Equity - noncontrolling interest	0	0
Total liabilities and equity	856,763	807,143
Guarantor Subsidiaries [Member]
Current assets:
Cash and cash equivalents	0	823	4,214		3,267
Accounts receivable	32,791	32,319
Intercompany accounts receivable (payable)	(27,621)	(42,194)
Prepaid and other current assets	2,837	2,395
Total current assets	8,007	(6,657)
Properties and equipment, net	562,282	563,701
Investments in subsidiaries	297,498	300,607
Transportation agreements, net	91,123	94,596
Goodwill	256,498	256,498
Investment in SLC Pipeline	24,882	25,041
Other assets	9,173	8,710
Total assets	1,249,463	1,242,496
Current liabilities:
Accounts payable	11,094	10,745
Accrued interest	116	28
Deferred revenue	5,094	3,319
Accrued property taxes	1,349	1,923
Other current liabilities	1,657	1,274
Total current liabilities	19,310	17,289
Long-term debt	355,000	421,000
Other long-term liabilities	13,305	15,241
Deferred Revenue, Noncurrent	17,581	11,494
Class B unit	16,960	13,903
Total partners' equity	827,307	763,569
Equity - noncontrolling interest	0	0
Total liabilities and equity	1,249,463	1,242,496
Non-Guarantor Subsidiaries [Member]
Current assets:
Cash and cash equivalents	8,714	4,412	0		3,100
Accounts receivable	3,604	6,401
Intercompany accounts receivable (payable)	0	0
Prepaid and other current assets	1,396	1,000
Total current assets	13,714	11,813
Properties and equipment, net	391,850	396,834
Investments in subsidiaries	0	0
Transportation agreements, net	0	0
Goodwill	0	0
Investment in SLC Pipeline	0	0
Other assets	0	0
Total assets	405,564	408,647
Current liabilities:
Accounts payable	2,900	1,285
Accrued interest	0	0
Deferred revenue	3,507	5,582
Accrued property taxes	2,300	765
Other current liabilities	51	68
Total current liabilities	8,758	7,700
Long-term debt	0	0
Other long-term liabilities	142	137
Deferred Revenue, Noncurrent	0	0
Class B unit	0	0
Total partners' equity	396,664	400,810
Equity - noncontrolling interest	0	0
Total liabilities and equity	405,564	408,647
Eliminations [Member]
Current assets:
Cash and cash equivalents	0	0	0		0
Accounts receivable	(274)	0
Intercompany accounts receivable (payable)	0	0
Prepaid and other current assets	0	0
Total current assets	(274)	0
Properties and equipment, net	0	0
Investments in subsidiaries	(1,124,805)	(1,064,176)
Transportation agreements, net	0	0
Goodwill	0	0
Investment in SLC Pipeline	0	0
Other assets	0	0
Total assets	(1,125,079)	(1,064,176)
Current liabilities:
Accounts payable	(274)	0
Accrued interest	0	0
Deferred revenue	0	0
Accrued property taxes	0	0
Other current liabilities	0	0
Total current liabilities	(274)	0
Long-term debt	0	0
Other long-term liabilities	0	0
Deferred Revenue, Noncurrent	0	0
Class B unit	0	0
Total partners' equity	(1,223,971)	(1,164,379)
Equity - noncontrolling interest	99,166	100,203
Total liabilities and equity	$ (1,125,079)	$ (1,064,176)

[1] Restated as described in Note 1.

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Consolidated Balance Sheets (Parenthetical)	6 Months Ended
	Jun. 30, 2013	Dec. 31, 2012
Partners' Equity:
Common units issued	58,657,048	56,782,048
Common units outstanding	58,657,048	56,782,048
General partner interest	2.00%

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Debt

6 Months Ended

Jun. 30, 2013

Debt Instruments [Abstract]

Debt

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 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:

	June 30, 2013			December 31, 2012
	(In thousands)
Credit Agreement	$	355,000		$	421,000
6.5% Senior Notes
Principal	300,000			300,000
Unamortized discount	(4,399		)	(4,725		)
	295,601			295,275
8.25% Senior Notes
Principal	150,000			150,000
Unamortized discount	(1,449		)	(1,601		)
	148,551			148,399
Total long-term debt	$	799,152		$	864,674

Interest Rate Risk Management

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

As of June 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 2.50% as of June 30, 2013, which equaled an effective interest rate of 3.49%. 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 2.50% as of June 30, 2013, which equaled an effective interest rate of 3.24%. 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 June 30, 2013, we had no ineffectiveness on our cash flow hedges.

At June 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 six months ended June 30, 2013, $0.5 million and $1.9 million, respectively, of other comprehensive loss was reclassified to interest expense due to cash flow hedge settlements. Approximately $0.1 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)
June 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     assets	$	545	Accumulated other     comprehensive income	$	545
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	)

Interest Expense and Other Debt Information

Interest expense consists of the following components:

	Six Months Ended June 30,
	2013		2012
	(In thousands)
Interest on outstanding debt:
Credit Agreement, net of interest on interest rate swaps	$	6,043	$	2,953
6.5% Senior Notes	9,755		5,966
6.25% Senior Notes	—		2,422
8.25% Senior Notes	6,193		6,193
Promissory Notes	—		543
Amortization of discount and deferred debt issuance costs	849		2,547
Increase in interest expense - non-cash charges attributable to interest rate swaps	1,063		875
Commitment fees	365		362
Total interest incurred	24,268		21,861
Less capitalized interest	155		132
Net interest expense	$	24,113	$	21,729
Cash paid for interest	$	22,258	$	17,039

We recognized a charge of $3.0 million upon the early extinguishment of debt for the six months ended June 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.

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Consolidated Statement of Comprehensive Income (USD $) In Thousands, unless otherwise specified	3 Months Ended			6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012		Jun. 30, 2013	Jun. 30, 2012
Net Income	$ 21,297	$ 19,128	[1]	$ 42,586	$ 38,484	[1]
Allocation of net loss attributable to Predecessors	0	2,192	[1]	0	4,053	[1]
Net income before noncontrolling interest	21,297	21,320	[1]	42,586	42,537	[1]
Other comprehensive income (loss):
Change in fair value of cash flow hedge	3,413	(1,508)	[1]	3,975	(1,862)	[1]
Amortization of unrealized loss attributable to discontinued cash flow hedge	0	1,273	[1]	849	2,547	[1]
Other comprehensive income (loss)	3,413	(235)	[1]	4,824	685	[1]
Comprehensive income before noncontrolling interest	24,710	21,085	[1]	47,410	43,222	[1]
Allocation of Net Income (Loss) Attributable to Noncontrolling Interest	(1,130)	683	[1]	(4,020)	1,240	[1]
Comprehensive Income attributable to Holly Energy Partners	$ 23,580	$ 21,768	[1]	$ 43,390	$ 44,462	[1]

[1] Restated as described in Note 1.

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Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Current assets:
Cash and cash equivalents	$ 8,716	$ 5,237
Accounts receivable:
Trade	4,550	7,126
Affiliates	31,571	31,594
Total accounts receivable	36,121	38,720
Prepaid and other current assets	4,314	3,619
Total current assets	49,151	47,576
Properties and equipment, net	954,132	960,535
Transportation agreements, net	91,123	94,596
Goodwill	256,498	256,498
Investment in SLC Pipeline	24,882	25,041
Other assets	10,925	9,864
Total assets	1,386,711	1,394,110
Accounts payable:
Trade	9,358	7,045
Affiliates	4,362	4,985
Total accounts payable	13,720	12,030
Accrued interest	10,314	10,226
Deferred revenue	8,601	8,901
Accrued property taxes	3,649	2,688
Other current liabilities	2,042	1,905
Total current liabilities	38,326	35,750
Long-term debt	799,152	864,674
Other long-term liabilities	13,525	15,433
Deferred Revenue, Noncurrent	17,581	11,494
Class B unit	16,960	13,903
Partners’ equity:
Common unitholders (58,657,048 and 56,782,048 units issued and outstanding at June 30, 2013 and December 31, 2012, respectively)	547,261	502,809
General partner interest (2% interest)	(145,805)	(145,877)
Accumulated other comprehensive loss	545	(4,279)
Total partners' equity	402,001	352,653
Noncontrolling interest	99,166	100,203
Total Equity	501,167	452,856
Total liabilities and equity	$ 1,386,711	$ 1,394,110

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Financial Instruments (Narrative) (Details) (USD $) In Thousands, unless otherwise specified	6 Months Ended	12 Months Ended
	Jun. 30, 2013	Dec. 31, 2012
6.5% Senior Notes [Member]
Debt Instrument [Line Items]
Stated interest rate, senior notes	6.50%
6.5% Senior Notes [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Senior Notes	$ 295,601	$ 295,275
8.25% Senior Notes [Member]
Debt Instrument [Line Items]
Stated interest rate, senior notes	8.25%
8.25% Senior Notes [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Senior Notes		148,399
Carrying Amount [Member] | Fair value inputs, Level 2 [Member]
Debt Instrument [Line Items]
Senior notes, carrying value	444,152	443,674
Liabilities, Fair Value Disclosure	444,152	447,104
Carrying Amount [Member] | Interest Rate Swap [Member] | Fair value inputs, Level 2 [Member]
Debt Instrument [Line Items]
Interest rate swap	0	3,430
Carrying Amount [Member] | 6.5% Senior Notes [Member] | Fair value inputs, Level 2 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Fair Value	295,601	295,275
Carrying Amount [Member] | 8.25% Senior Notes [Member] | Fair value inputs, Level 2 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Fair Value		148,399
Senior Notes	148,551
Fair Value [Member] | Fair value inputs, Level 2 [Member]
Debt Instrument [Line Items]
Senior notes, carrying value	452,625	484,125
Liabilities, Fair Value Disclosure	452,625	487,555
Fair Value [Member] | Interest Rate Swap [Member] | Fair value inputs, Level 2 [Member]
Debt Instrument [Line Items]
Interest rate swap	0	3,430
Fair Value [Member] | 6.5% Senior Notes [Member] | Fair value inputs, Level 2 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Fair Value	294,000	321,000
Fair Value [Member] | 8.25% Senior Notes [Member] | Fair value inputs, Level 2 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Fair Value	158,625	163,125
Accumulated Other Comprehensive Income (Loss) [Member] | Cash Flow Hedging [Member] | Interest Rate Swap [Member]
Debt Instrument [Line Items]
Unrealized Gain (Loss) on Interest Rate Cash Flow Hedges, Pretax, Accumulated Other Comprehensive Income (Loss)	545	3,430
Other Liabilities [Member] | Cash Flow Hedging [Member] | Interest Rate Swap [Member]
Debt Instrument [Line Items]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	$ 545	$ 3,430

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Debt (Tables)

6 Months Ended

Jun. 30, 2013

Debt Instruments [Abstract]

Schedule of Long-term Debt Instruments

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

	June 30, 2013			December 31, 2012
	(In thousands)
Credit Agreement	$	355,000		$	421,000
6.5% Senior Notes
Principal	300,000			300,000
Unamortized discount	(4,399		)	(4,725		)
	295,601			295,275
8.25% Senior Notes
Principal	150,000			150,000
Unamortized discount	(1,449		)	(1,601		)
	148,551			148,399
Total long-term debt	$	799,152		$	864,674

Schedule of Derivative Instruments

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)
June 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     assets	$	545	Accumulated other     comprehensive income	$	545
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	)

Schedule of Interest Expense and Other Debt Information

Interest expense consists of the following components:

	Six Months Ended June 30,
	2013		2012
	(In thousands)
Interest on outstanding debt:
Credit Agreement, net of interest on interest rate swaps	$	6,043	$	2,953
6.5% Senior Notes	9,755		5,966
6.25% Senior Notes	—		2,422
8.25% Senior Notes	6,193		6,193
Promissory Notes	—		543
Amortization of discount and deferred debt issuance costs	849		2,547
Increase in interest expense - non-cash charges attributable to interest rate swaps	1,063		875
Commitment fees	365		362
Total interest incurred	24,268		21,861
Less capitalized interest	155		132
Net interest expense	$	24,113	$	21,729
Cash paid for interest	$	22,258	$	17,039

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Partners' Equity, Cash Distributions (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Allocations of Quarterly Cash Distributions to General and Limited Partners
Partners' Capital, Distribution Amount Per Share	$ 0.4850		$ 0.4850
Partner Distributions
General partner interest	$ 737,000	$ 622,000	$ 1,456,000	$ 1,227,000
General partner incentive distribution	6,405,000	5,565,000	12,388,000	10,737,000
Total general partner distribution	7,142,000	6,187,000	13,844,000	11,964,000
Limited partner distribution	28,448,000	24,899,000	56,457,000	49,387,000
Total regular quarterly cash distribution	35,590,000	31,086,000	70,301,000	61,351,000
Cash distribution per unit applicable to limited partners	$ 0.485	$ 0.455	$ 0.963	$ 0.903
Excess Acquisition Costs, Not Recognized due to Common Control	$ 305,300,000		$ 305,300,000

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Debt Interest Expense and Other Debt Information (Details) (USD $)	3 Months Ended			6 Months Ended			12 Months Ended
	Jun. 30, 2013	Jun. 30, 2012		Jun. 30, 2013	Jun. 30, 2012		Dec. 31, 2013
Debt Instrument [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net	$ 500,000			$ 1,900,000			$ 100,000
Interest expense, debt				24,268,000	21,861,000
Amortization of Unrecognized Loss on Cash Flow Hedge				1,063,000	875,000
Less capitalized interest				155,000	132,000
Interest Expense	11,629,000	11,324,000	[1]	24,113,000	21,729,000	[1]
Cash paid for interest				22,258,000	17,039,000
Loss on early extinguishment of debt	0	(383,000)	[1]	0	(2,979,000)	[1]
Repayments of senior notes					185,000,000
6.5% Senior Notes [Member]
Debt Instrument [Line Items]
Stated interest rate, senior notes	6.50%			6.50%
8.25% Senior Notes [Member]
Debt Instrument [Line Items]
Stated interest rate, senior notes	8.25%			8.25%
Senior Notes [Member] | 6.25% Interest Rate [Member]
Debt Instrument [Line Items]
Stated interest rate, senior notes		6.25%			6.25%
Amortization discount and deferred debt issuance costs [Member]
Debt Instrument [Line Items]
Interest expense, debt				849,000	2,547,000
Commitment Fees [Member]
Debt Instrument [Line Items]
Interest expense, debt				365,000	362,000
Long-term Debt [Member] | Credit Agreement [Member]
Debt Instrument [Line Items]
Interest expense, debt				6,043,000	2,953,000
Long-term Debt [Member] | Senior Notes [Member] | 6.5% Senior Notes [Member]
Debt Instrument [Line Items]
Interest expense, debt				9,755,000	5,966,000
Long-term Debt [Member] | Senior Notes [Member] | 6.25% Senior Notes [Member]
Debt Instrument [Line Items]
Interest expense, debt				0	2,422,000
Long-term Debt [Member] | Senior Notes [Member] | 8.25% Senior Notes [Member]
Debt Instrument [Line Items]
Interest expense, debt				6,193,000	6,193,000
Long-term Debt [Member] | Promissory Notes [Member]
Debt Instrument [Line Items]
Interest expense, debt				$ 0	$ 543,000

[1] Restated as described in Note 1.

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Debt Credit Agreement (Details) (USD $)	3 Months Ended			6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012		Jun. 30, 2013	Jun. 30, 2012		Jun. 30, 2013 Credit Agreement [Member]	Dec. 31, 2012 Credit Agreement [Member]	Jun. 30, 2013 New Credit Agreement [Member] Credit Agreement [Member]	Jun. 30, 2013 Letters of Credit [Member] Credit Agreement [Member]	Jun. 30, 2013 Unitholder Distributions [Member] Credit Agreement [Member]
Debt Instrument [Line Items]
Loss on early extinguishment of debt	$ 0	$ (383,000)	[1]	$ 0	$ (2,979,000)	[1]
Credit agreement, maximum borrowing capacity									550,000,000	50,000,000	60,000,000
Proceeds from lines of credit				154,500,000	99,000,000	[1]
Repayments of lines of credit				220,500,000	129,000,000	[1]
Long-term line of credit							$ 355,000,000	$ 421,000,000

[1] Restated as described in Note 1.

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Debt Senior Notes (Details) (USD $)	6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012
Debt Instrument [Line Items]
Proceeds from senior notes	$ 0	$ 294,750,000	[1]
Repayment of senior notes		(257,900,000)
Senior Notes [Member] | 8.25% Interest Rate [Member]
Debt Instrument [Line Items]
Principal	150,000,000
Stated interest rate, senior notes	8.25%
Senior Notes [Member] | 6.5% Interest Rate [Member]
Debt Instrument [Line Items]
Principal	300,000,000
Proceeds from senior notes		294,800,000
Stated interest rate, senior notes	6.50%	6.50%
Senior Notes [Member] | 6.25% Interest Rate [Member]
Debt Instrument [Line Items]
Repayment of senior notes		185,000,000
Stated interest rate, senior notes		6.25%
Promissory Notes [Member] | 6.25% Interest Rate [Member]
Debt Instrument [Line Items]
Repayment of promissory notes		$ (72,900,000)

[1] Restated as described in Note 1.

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Employees, Retirement and Incentive Plans

6 Months Ended

Jun. 30, 2013

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Employees, Retirement and Incentive Plans

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 $1.7 million for the three months ended June 30, 2013 and 2012, respectively, and $3.8 million and $3.1 million for the six months ended June 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 June 30, 2013, we have two types of incentive-based awards which are described below. The compensation cost charged against income was $0.8 million and $0.7 million for the three months ended June 30, 2013 and 2012, respectively, and $1.9 million and $1.6 million for the six months ended June 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 June 30, 2013, 2,500,000 units were authorized to be granted under our Long-Term Incentive Plan, of which 1,732,433 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.

A summary of restricted unit activity and changes during the six months ended June 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	37,815	41.18
Vesting and transfer of full ownership to recipients	—	—
Outstanding at June 30, 2013 (nonvested)	96,287	$	35.08

As of June 30, 2013, there was $1.6 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 June 30, 2013, estimated unit payouts for outstanding nonvested performance unit awards were at 100% to 125%.

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 six months ended June 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 June 30, 2013 (nonvested)	62,262

The grant-date fair value of performance units vested and transferred to recipients during the six months ended June 30, 2013 was $0.5 million. As of June 30, 2013, there was $1.4 million of total unrecognized compensation expense related to nonvested performance units, which is expected to be recognized over a weighted-average period of 1.7 years.

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Properties and Equipment (Details) (USD $) In Thousands, unless otherwise specified	6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Dec. 31, 2012
Property, Plant and Equipment [Line Items]
Properties and equipment, gross	$ 1,180,105		$ 1,164,391
Less accumulated depreciation	225,973		203,856
Properties and equipment, net	954,132		960,535
Interest costs, capitalized during period	(155)	(132)
Pipelines and terminals [Member]
Property, Plant and Equipment [Line Items]
Properties and equipment, gross	1,061,626		1,049,531
Land and right of way [Member]
Property, Plant and Equipment [Line Items]
Properties and equipment, gross	63,196		63,248
Other [Member]
Property, Plant and Equipment [Line Items]
Properties and equipment, gross	37,032		27,150
Construction in progress [Member]
Property, Plant and Equipment [Line Items]
Properties and equipment, gross	$ 18,251		$ 24,462

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Partners' Equity, Issuances (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended	6 Months Ended	0 Months Ended		3 Months Ended
	Jun. 30, 2013	Jun. 30, 2013	Jul. 12, 2012 UNEV Pipeline [Member]	Jun. 30, 2013 UNEV Pipeline [Member]	Jun. 30, 2013 General Partner HFC [Member]
Schedule of Equity Method Investments [Line Items]
Proceeds from sale of common units		$ 73,444
Partners' capital account, units held by controlling interest	22,380,030	22,380,030
General partner ownership interest		2.00%
Ownership percentage, controlling interest	39.00%	39.00%
Sale of Stock, Number of Shares Issued in Transaction	1,875,000				1,875,000
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares			2,059,800
Equity Method Investment, Ownership Percentage	25.00%	25.00%		75.00%

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Related Party Transactions

6 Months Ended

Jun. 30, 2013

Related Party Transactions [Abstract]

Related Party Transactions

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.

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 $63.2 million and $57.8 million for the three months ended June 30, 2013 and 2012, respectively, and $124.7 million and $114.3 million for the six months ended June 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 June 30, 2013 and 2012, respectively, and $1.2 million for the six months ended June 30, 2013 and 2012, respectively.

• We reimbursed HFC for costs of employees supporting our operations of $9.4 million and $7.1 million for the three months ended June 30, 2013 and 2012, respectively, and $19.2 million and $14.8 million for the six months ended June 30, 2013 and 2012, respectively.

• HFC reimbursed us $4.3 million and $2.2 million for the three months ended June 30, 2013 and 2012, respectively, and $9.2 million and $4.7 million for the six months ended June 30, 2013 and 2012, respectively, for certain reimbursable costs and capital projects.

• We distributed $17.4 million and $15.7 million for the three months ended June 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 six months ended June 30, 2013 and 2012 we distributed $34.8 million and $31.0 million, respectively.

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

• Accounts payable to HFC were $4.4 million and $5.0 million at June 30, 2013 and December 31, 2012, respectively.

• Revenues for the three and the six months ended June 30, 2013 include $0.7 million and $4.7 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 June 30, 2013 and December 31, 2012, includes $5.0 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 $5.0 million deferred at June 30, 2013.

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

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Transportation Agreements

6 Months Ended

Jun. 30, 2013

Goodwill and Intangible Assets Disclosure [Abstract]

Transportation Agreements

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:

	June 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	43,041		39,568
	$	91,123	$	94,596

We have additional transportation agreements with HFC that relate to assets contributed to us or acquired from HFC consisting of pipeline, terminal and tankage assets. 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.

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Consolidated Statement of Partners' Equity (USD $) In Thousands, unless otherwise specified	Total	Common Units	General Partner Interest	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interest [Member]
Balance at Dec. 31, 2012	$ 452,856	$ 502,809	$ (145,877)	$ (4,279)	$ 100,203
Increase (Decrease) in Partners' Equity [Roll Forward]
Issuance of common units	73,444	73,444
Net income	42,586	29,753	11,870		963
Other comprehensive income (loss)	4,824			4,824
Contributions from general partner	1,499		1,499		0
Distributions to unitholders	(67,419)	(54,696)	(12,723)
Distributions made to joint venture partners	(2,000)				(2,000)
Purchase of units for restribted grants	(2,933)	(2,933)
Amortization of restricted and performance units	1,880	1,880
Class B Unit Accretion	(3,057)	(2,996)	(61)
Other	(513)		(513)
Balance at Jun. 30, 2013	$ 501,167	$ 547,261	$ (145,805)	$ 545	$ 99,166

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Supplemental Guarantor / Non-Guarantor Financial Information Condensed Consolidating Statement of Cash Flows (Details) (USD $) In Thousands, unless otherwise specified	6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	$ 82,202	$ 69,766	[1]
Cash flows from investing activities
Additions to properties and equipment	(17,224)	(26,374)	[1]
Proceeds from Sale of assets	2,481	0	[1]
Net Cash Provided by (Used in) Investing Activities	(14,743)	(26,374)	[1]
Cash flows from financing activities
Net repayments under credit agreement	(66,000)	30,000
Proceeds from issuance of senior notes	0	294,750	[1]
Proceeds from sale of common units	73,444
Repayments of Long-term Debt		(257,900)
Contribution From UNEV Joint Venture Partner	0	15,000	[1]
Distributions to HEP unitholders	(67,419)	(59,977)	[1]
Distributions made to joint venture partners	2,000	0	[1]
Contributions from general partner	1,499
Purchase of units for incentive grants	(3,254)	(4,533)	[1]
Deferred financing costs	0	(3,162)	[1]
Other	(250)	277	[1]
Net cash used for financing activities	(63,980)	(45,545)	[1]
Increase for the period	3,479	(2,153)	[1]
Beginning of period	5,237	6,369	[1]
End of period	8,716	4,216	[1]
Parent [Member]
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	(4,020)	(45,135)
Cash flows from investing activities
Additions to properties and equipment	0	0
Proceeds from Sale of assets	0
Net Cash Provided by (Used in) Investing Activities	0
Cash flows from financing activities
Net repayments under credit agreement	0	0
Proceeds from issuance of senior notes		294,750
Proceeds from sale of common units	(73,444)
Repayments of Long-term Debt		(185,000)
Contribution From UNEV Joint Venture Partner		0
Distributions to HEP unitholders	(67,419)	(59,977)
Distributions made to joint venture partners	0
Contributions from general partner	1,499
Purchase of units for incentive grants	(3,254)	(4,533)
Deferred financing costs		(567)
Other	(250)	462
Net cash used for financing activities	4,020	45,135
Increase for the period	0	0
Beginning of period	2	2
End of period	2	2
Guarantor Subsidiaries [Member]
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	79,182	118,635
Cash flows from investing activities
Additions to properties and equipment	(16,486)	(12,008)
Proceeds from Sale of assets	2,481
Net Cash Provided by (Used in) Investing Activities	(14,005)
Cash flows from financing activities
Net repayments under credit agreement	(66,000)	(30,000)
Proceeds from issuance of senior notes		0
Proceeds from sale of common units	0
Repayments of Long-term Debt		(72,900)
Contribution From UNEV Joint Venture Partner		0
Distributions to HEP unitholders	0	0
Distributions made to joint venture partners	0
Contributions from general partner	0
Purchase of units for incentive grants	0	0
Deferred financing costs		(2,595)
Other	0	(185)
Net cash used for financing activities	(66,000)	(105,680)
Increase for the period	(823)	947
Beginning of period	823	3,267
End of period	0	4,214
Non-Guarantor Subsidiaries [Member]
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	13,040	(3,734)
Cash flows from investing activities
Additions to properties and equipment	(738)	(14,366)
Proceeds from Sale of assets	0
Net Cash Provided by (Used in) Investing Activities	(738)
Cash flows from financing activities
Net repayments under credit agreement	0	0
Proceeds from issuance of senior notes		0
Proceeds from sale of common units	0
Repayments of Long-term Debt		0
Contribution From UNEV Joint Venture Partner		15,000
Distributions to HEP unitholders	0	0
Distributions made to joint venture partners	(8,000)
Contributions from general partner	0
Purchase of units for incentive grants	0	0
Deferred financing costs		0
Other	0	0
Net cash used for financing activities	(8,000)	15,000
Increase for the period	4,302	(3,100)
Beginning of period	4,412	3,100
End of period	8,714	0
Eliminations [Member]
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	(6,000)	0
Cash flows from investing activities
Additions to properties and equipment	0	0
Proceeds from Sale of assets	0
Net Cash Provided by (Used in) Investing Activities	0
Cash flows from financing activities
Net repayments under credit agreement	0	0
Proceeds from issuance of senior notes		0
Proceeds from sale of common units	0
Repayments of Long-term Debt		0
Contribution From UNEV Joint Venture Partner		0
Distributions to HEP unitholders	0	0
Distributions made to joint venture partners	6,000
Contributions from general partner	0
Purchase of units for incentive grants	0	0
Deferred financing costs		0
Other	0	0
Net cash used for financing activities	6,000	0
Increase for the period	0	0
Beginning of period	0	0
End of period	$ 0	$ 0

[1] Restated as described in Note 1.

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Employees, Retirement and Incentive Plans Restricted Units (Details) (USD $) In Millions, except Share data, unless otherwise specified	6 Months Ended				3 Months Ended
	Jun. 30, 2013	Jun. 30, 2013 Performance Units [Member] Long-term Incentive Plan [Member]	Jun. 30, 2013 Restricted Stock Units (RSUs) [Member]	Jun. 30, 2013 Restricted Stock Units (RSUs) [Member] Long-term Incentive Plan [Member]	Jun. 30, 2013 Restricted Stock Units (RSUs) [Member] Minimum [Member] Long-term Incentive Plan [Member]	Jun. 30, 2013 Restricted Stock Units (RSUs) [Member] Maximum [Member] Long-term Incentive Plan [Member]	Jun. 30, 2013 Restricted Stock [Member] Minimum [Member]	Jun. 30, 2013 Restricted Stock [Member] Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward]
Outstanding at January 1, 2013 (nonvested)	54,498		58,472
Granted	32,888		37,815
Vesting and transfer of full ownership to recipients	(25,124)		0
Outstanding at June 30, 2013 (nonvested)	62,262		96,287
Weighted Average Grant-Date Fair Value
Outstanding at January 1, 2013 (nonvested)			$ 31.21
Granted			$ 41.18
Vesting and transfer of full ownership to recipients			$ 0.00
Outstanding at June 30, 2013 (nonvested)			$ 35.08
Award vesting period					1 year	3 years	1 year	3 years
Weighted average remaining contractual term (years)		1 year 8 months 16 days		1 year 1 month 6 days
Fair value of vested units transferred to recipients		$ 0.5
Total unrecognized compensation related to nonvested units		$ 1.4		$ 1.6

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Financial Instruments (Tables)

6 Months Ended

Jun. 30, 2013

Fair Value Disclosures [Abstract]

Schedule of Fair Value, Financial Instruments Measured on Recurring Basis

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

		June 30, 2013				December 31, 2012
Financial Instrument	Fair Value Input Level	Carrying Value		Fair Value		Carrying Value		Fair Value
		(In thousands)
Assets:
Interest rate swaps	Level 2	$	545	$	545	$	—	$	—
Liabilities:
Senior notes:
6.5% senior notes	Level 2	$	295,601	$	294,000	$	295,275	$	321,000
8.25% senior notes	Level 2	148,551		158,625		148,399		163,125
		444,152		452,625		443,674		484,125
Interest rate swaps	Level 2	—		—		3,430		3,430
		$	444,152	$	452,625	$	447,104	$	487,555

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Significant Customers

6 Months Ended

Jun. 30, 2013

Risks and Uncertainties [Abstract]

Significant Customers

Significant Customers

All revenues are domestic revenues, of which 95% 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 June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
HFC	84	%	84	%	83	%	83	%
Alon	11	%	11	%	10	%	11	%

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Employees, Retirement and Incentive Plans (Tables)

6 Months Ended

Jun. 30, 2013

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Schedule of Nonvested Restricted Stock Units Activity

A summary of restricted unit activity and changes during the six months ended June 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	37,815	41.18
Vesting and transfer of full ownership to recipients	—	—
Outstanding at June 30, 2013 (nonvested)	96,287	$	35.08

Schedule of Nonvested Performance-based Units Activity

A summary of performance unit activity and changes during the six months ended June 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 June 30, 2013 (nonvested)	62,262

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Properties and Equipment (Tables)

6 Months Ended

Jun. 30, 2013

Property, Plant and Equipment [Abstract]

Properties and Equipment

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

	June 30, 2013		December 31, 2012
	(In thousands)
Pipelines, terminals and tankage	$	1,061,626	$	1,049,531
Land and right of way	63,196		63,248
Construction in progress	37,032		27,150
Other	18,251		24,462
	1,180,105		1,164,391
Less accumulated depreciation	225,973		203,856
	$	954,132	$	960,535

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Document Entity Information	6 Months Ended
	Jun. 30, 2013	Jul. 26, 2013
Entity Information [Line Items]
Entity Registrant Name	HOLLY ENERGY PARTNERS LP
Entity Central Index Key	0001283140
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Jun. 30, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q2
Amendment Flag	false
Entity Common Stock, Shares Outstanding		58,657,048

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Transportation Agreements (Tables)

6 Months Ended

Jun. 30, 2013

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Finite-Lived Intangible Assets by Major Class

The carrying amounts of our transportation agreements are as follows:

	June 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	43,041		39,568
	$	91,123	$	94,596