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 March 31, 2014

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 April 25, 2014 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	23
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	32
	Item 4.	Controls and Procedures	32
PART II. OTHER INFORMATION			34
	Item 1.	Legal Proceedings	34
	Item 1A.	Risk Factors	34
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	34
	Item 6.	Exhibits	34
		SIGNATURES	35
		Index to Exhibits	36

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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 future acquired operations;

• our ability to complete previously announced or contemplated acquisitions;

• the availability and cost of additional debt and equity financing;

• the possibility of reductions in production or shutdowns at refineries utilizing our pipeline and terminal facilities;

• 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 risk factors and other cautionary statements set forth in our Annual Report on Form 10-K for the year ended December 31, 2013 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

(in thousands, except unit data)

	March 31, 2014			December 31, 2013
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	4,879		$	6,352
Accounts receivable:
Trade	5,365			5,061
Affiliates	29,060			29,675
	34,425			34,736
Prepaid and other current assets	3,499			3,874
Total current assets	42,803			44,962
Properties and equipment, net	958,749			957,814
Transportation agreements, net	85,913			87,650
Goodwill	256,498			256,498
Investment in SLC Pipeline	24,701			24,741
Other assets	10,067			10,843
Total assets	$	1,378,731		$	1,382,508
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	11,163		$	14,414
Affiliates	4,590			8,484
	15,753			22,898
Accrued interest	1,776			10,239
Deferred revenue	6,854			13,981
Accrued property taxes	3,328			2,603
Other current liabilities	2,149			1,845
Total current liabilities	29,860			51,566
Long-term debt	833,790			807,630
Other long-term liabilities	13,817			14,585
Deferred revenue	23,939			21,669
Class B unit	21,748			20,124
Equity:
Partners’ equity:
Common unitholders (58,657,048 units issued and outstanding     at March 31, 2014 and December 31, 2013)	503,899			516,147
General partner interest (2% interest)	(147,024		)	(146,557		)
Accumulated other comprehensive loss	(49		)	(144		)
Total partners’ equity	356,826			369,446
Noncontrolling interest	98,751			97,488
Total equity	455,577			466,934
Total liabilities and equity	$	1,378,731		$	1,382,508

See accompanying notes.

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Table of Contentsril 19,

HOLLY ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

                      (In thousands, except per unit data)

	Three Months Ended March 31,
	2014			2013
Revenues:
Affiliates	$	71,832		$	61,512
Third parties	15,172			12,786
	87,004			74,298
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	22,812			25,865
Depreciation and amortization	15,588			14,154
General and administrative	3,151			3,232
	41,551			43,251
Operating income	45,453			31,047
Other income (expense):
Equity in earnings of SLC Pipeline	522			657
Interest expense	(10,454		)	(12,484		)
Interest income	3			103
Loss on early extinguishment of debt	(7,677		)	—
Gain on sale of assets	—			2,022
Other (income) expense	8			—
	(17,598		)	(9,702		)
Income before income taxes	27,855			21,345
State income tax expense	(75		)	(56		)
Net income	27,780			21,289
Allocation of net income attributable to noncontrolling interests	(3,637		)	(2,890		)
Net income attributable to Holly Energy Partners	24,143			18,399
General partner interest in net income, including incentive distributions	(8,001		)	(6,231		)
Limited partners’ interest in net income	$	16,142		$	12,168
Limited partners’ per unit interest in earnings—basic and diluted	$	0.27		$	0.21
Weighted average limited partners’ units outstanding	58,657			56,990

See accompanying notes.

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HOLLY ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(In thousands)

	Three Months Ended March 31,
	2014			2013
Net income	$	27,780		$	21,289
Other comprehensive income:
Change in fair value of cash flow hedging instruments	(443		)	58
Amortization of unrealized loss attributable to discontinued cash flow hedge	—			849
Reclassification adjustment to net income on partial settlement of cash flow hedge	538			504
Other comprehensive income	95			1,411
Comprehensive income before noncontrolling interest	27,875			22,700
Allocation of comprehensive income to noncontrolling interests	(3,637		)	(2,890		)
Comprehensive income attributable to Holly Energy Partners	$	24,238		$	19,810

See accompanying notes.

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Table of Contentsril 19,

HOLLY ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

	Three Months Ended March 31,
	2014			2013
Cash flows from operating activities
Net income	$	27,780		$	21,289
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	15,588			14,154
Gain on sale of assets	—			(2,022		)
Amortization of deferred charges	511			1,379
Amortization of restricted and performance units	820			1,123
Loss on early extinguishment of debt	7,677			—
(Increase) decrease in operating assets:
Accounts receivable—trade	(302		)	1,053
Accounts receivable—affiliates	615			539
Prepaid and other current assets	374			145
Increase (decrease) in operating liabilities:
Accounts payable—trade	2,568			(1,808		)
Accounts payable—affiliates	(3,894		)	253
Accrued interest	(8,463		)	(7,860		)
Deferred revenue	(4,857		)	1,686
Accrued property taxes	725			33
Other current liabilities	304			531
Other, net	(430		)	354
Net cash provided by operating activities	39,016			30,849
Cash flows from investing activities
Additions to properties and equipment	(20,604		)	(6,645		)
Proceeds from sale of assets	—			2,481
Distributions in excess of equity in earnings of SLC Pipeline	40			30
Net cash used for investing activities	(20,564		)	(4,134		)
Cash flows from financing activities
Borrowings under credit agreement	421,300			57,000
Repayments of credit agreement borrowings	(246,600		)	(110,000		)
Proceeds from issuance of common units	—			73,444
Redemption of senior notes	(156,188		)	—
Contribution from general partner	—			1,499
Distributions to HEP unitholders	(37,342		)	(32,709		)
Distributions to noncontrolling interest	(750		)	—
Purchase of units for incentive grants	(336		)	(2,719		)
Deferred financing costs	(9		)	—
Other	—			(274		)
Net cash used by financing activities	(19,925		)	(13,759		)
Cash and cash equivalents
Increase (decrease) for the period	(1,473		)	12,956
Beginning of period	6,352			5,237
End of period	$	4,879		$	18,193

See accompanying notes.

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Table of Contentsril 19,

HOLLY ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF PARTNERS' EQUITY

(Unaudited)

(In thousands)

	Common Units			General Partner Interest			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interest			Total Equity
Balance December 31, 2013	$	516,147		$	(146,557	)	$	(144	)	$	97,488		$	466,934
Distributions to HEP unitholders	(29,320		)	(8,022		)	—			—			(37,342		)
Distributions to UNEV joint venture partners	—			—			—			(750		)	(750		)
Purchase of units for incentive grants	(336		)	—			—			—			(336		)
Amortization of restricted and performance units	820			—			—			—			820
Class B unit accretion	(1,592		)	(32		)	—			—			(1,624		)
Net income	18,180			7,587			—			2,013			27,780
Other comprehensive income	—			—			95			—			95
Balance March 31, 2014	$	503,899		$	(147,024	)	$	(49	)	$	98,751		$	455,577

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. We commenced operations on July 13, 2004 upon the completion of our initial public offering. In these consolidated financial statements, the words “we,” “our,” “ours” and “us” refer to HEP unless the context otherwise indicates.

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 417-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 exposed directly to changes in commodity prices.

The consolidated financial statements included herein have been prepared without audit, pursuant to the rules and regulations of the United States Securities and Exchange Commission (the “SEC”). The interim financial statements reflect all adjustments, which, in the opinion of management, are necessary for a fair presentation of our results for the interim periods. Such adjustments are considered to be of a normal recurring nature. Although certain notes and other information required by U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted, we believe that the disclosures in these consolidated financial statements are adequate to make the information presented not misleading. These consolidated financial statements should be read in conjunction with our Form 10-K for the year ended December 31, 2013. 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, 2014.

Note 2: Financial Instruments

Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, debt and interest rate swaps. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate fair value. 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:

		March 31, 2014				December 31, 2013
Financial Instrument	Fair Value Input Level	Carrying Value		Fair Value		Carrying Value		Fair Value
		(In thousands)
Liabilities:
Senior notes:
6.5% senior notes	Level 2	$	296,090	$	319,500	$	295,927	$	313,500
8.25% senior notes	Level 2	—		—		148,703		158,250
		296,090		319,500		444,630		471,750
Interest rate swaps	Level 2	49		49		144		144
		$	296,139	$	319,549	$	444,774	$	471,894

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, which were derived using market quotes for similar type instruments, a Level 2 input. 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. The measurements are computed using the forward London Interbank Offered Rate (“LIBOR”) yield curve, a market-based observable input.

See Note 6 for additional information on these instruments.

Note 3: Properties and Equipment

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

	March 31, 2014		December 31, 2013
	(In thousands)
Pipelines, terminals and tankage	$	1,077,058	$	1,077,037
Land and right of way	63,425		63,425
Construction in progress	63,828		50,454
Other	19,995		19,997
	1,224,306		1,210,913
Less accumulated depreciation	265,557		253,099
	$	958,749	$	957,814

We capitalized $0.4 million and $0.1 million in interest attributable to construction projects during the three months ended March 31, 2014 and 2013, respectively.

Depreciation expense was $13.7 million and $12.3 million for the three months ended March 31, 2014 and 2013, respectively.

Note 4: 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).

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HOLLY ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) Continued

The carrying amounts of our transportation agreements are as follows:

	March 31, 2014		December 31, 2013
	(In thousands)
Alon transportation agreement	$	59,933	$	59,933
HFC transportation agreement	74,231		74,231
	134,164		134,164
Less accumulated amortization	48,251		46,514
	$	85,913	$	87,650

We have additional transportation agreements with HFC resulting from historical transactions consisting of pipeline, terminal and tankage assets contributed to us or acquired from HFC. These transactions occurred while we were a consolidated 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 5: Employees, Retirement and Incentive Plans

Direct support for our operations is provided by Holly Logistic Services, L.L.C., an HFC subsidiary, which utilizes personnel employed by HFC who are dedicated to performing services for us. Their costs, including salaries, bonuses, payroll taxes, benefits and other direct costs, are charged to us monthly in accordance with an omnibus agreement that we have with HFC. These employees participate in the retirement and benefit plans of HFC. Our share of retirement and benefit plan costs was $1.7 million and $1.9 million for the three months ended March 31, 2014 and 2013, 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 or phantom units, performance units, unit options and unit appreciation rights. Our accounting policy for the recognition of compensation expense for awards with pro-rata vesting (a significant proportion of our awards) is to expense the costs ratably over the vesting periods.

As of March 31, 2014, we have three types of incentive-based awards which are described below. The compensation cost charged against income was $0.8 million and $1.1 million for the three months ended March 31, 2014 and 2013, 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 March 31, 2014, 2,500,000 units were authorized to be granted under our Long-Term Incentive Plan, of which 1,635,469 have not yet been granted, assuming no forfeitures of the unvested units and full achievement of goals for the performance units already granted.

Restricted and Phantom Units

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

In addition, we grant phantom units to certain employees, which vest over a period of one year. Vested units are paid in common units. Full ownership of the units does not transfer to the recipient until the units vest, and the recipients do not have voting or distribution rights on these units until they vest.

The fair value of each restricted unit and phantom unit award is measured at the market price as of the date of grant and is amortized over the vesting period.

There was no activity or changes for the restricted unit and phantom units during the three months ended March 31, 2014. There were 122,951 nonvested units outstanding as of March 31, 2014, at a weighted average grant date fair value of $33.36 per share. As of March 31, 2014, there was $2.2 million of total unrecognized compensation expense related to nonvested restricted unit and phantom unit grants, which is expected to be recognized over a weighted-average period of 1.2 years.

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HOLLY ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) Continued

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 March 31, 2014, estimated unit payouts for outstanding nonvested performance unit awards were at 100%.

No performance units were granted during three months ended March 31, 2014. Performance units granted in 2013 vest over a three-year performance period ending December 31, 2015, for performance units granted in February 2013 and December 31, 2016, for performance units granted in November 2013 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 Chairman, who received a performance unit award in March 2013 prior to his retirement from Holly Logistic Services, L.L.C., our ultimate general partner ("HLS")) 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.

A summary of performance unit activity and changes during the three months ended March 31, 2014, is presented below:

Performance Units	Units
Outstanding at January 1, 2014 (nonvested)	75,216
Vesting and transfer of common units to recipients	(17,938	)
Outstanding at March 31, 2014 (nonvested)	57,278

The grant-date fair value of performance units vested and transferred to recipients during the three months ended March 31, 2014, was $0.5 million. Based on the weighted average fair value at March 31, 2014, of $2.1 million, there was $1.2 million of total unrecognized compensation expense related to nonvested performance units, which is expected to be recognized over a weighted-average period of 1.8 years.

Note 6: Debt

Credit Agreement

We have a $650 million senior secured revolving credit facility expiring in November 2018 (the “Credit Agreement”) that is available to fund capital expenditures, investments, acquisitions, distribution payments and working capital and for general partnership purposes. It is also available to fund letters of credit up to a $50 million sub-limit.

Our obligations under the Credit Agreement are collateralized by substantially all of our assets. Indebtedness under the Credit Agreement involves recourse to HEP Logistics Holdings, L.P. (“HEP Logistics”), our general partner, and is 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 2014, we redeemed the $150 million aggregate principal amount of 8.25% senior notes (the "8.25% Senior Notes")maturing March 2018 at a redemption cost of $156.2 million, at which time we recognized a $7.7 million early extinguishment loss consisting of a $6.2 million debt redemption premium and unamortized discount and financing costs of $1.5 million. We funded the redemption with borrowings under our Credit Agreement.

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HOLLY ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) Continued

We have $300 million in aggregate principal amount outstanding of 6.5% senior notes (the "6.5% Senior Notes") maturing March 2020. The 6.5% Senior Notes are unsecured and impose certain restrictive covenants, with which we are currently in compliance, 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 6.5% Senior Notes are rated investment grade by both Moody’s and Standard & Poor’s and no default or event of default exists, we will not be subject to many of the foregoing covenants. Additionally, we have certain redemption rights at varying premiums over face value under the 6.5% Senior Notes.

Indebtedness under the 6.5% Senior Notes involves recourse to HEP Logistics, our general partner, and is 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:

	March 31, 2014			December 31, 2013
	(In thousands)
Credit Agreement	$	537,700		$	363,000
6.5% Senior Notes
Principal	300,000			300,000
Unamortized discount	(3,910		)	(4,073		)
	296,090			295,927
8.25% Senior Notes
Principal	—			150,000
Unamortized discount	—			(1,297		)
	—			148,703
Total long-term debt	$	833,790		$	807,630

Interest Rate Risk Management

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

As of March 31, 2014, we have three interest rate swaps that hedge our exposure to the cash flow risk caused by the effects of LIBOR changes on $305 million of Credit Agreement advances. Our first interest rate swap effectively converts $155 million of our LIBOR based debt to fixed rate debt having an interest rate of 0.99% plus an applicable margin of 2.00% as of March 31, 2014, which equaled an effective interest rate of 2.99%. This swap contract matures in February 2016. We also have two additional interest rate swaps with identical terms which effectively convert $150 million of our LIBOR based debt to fixed rate debt having an interest rate of 0.74% plus an applicable margin of 2.00% as of March 31, 2014, which equaled an effective interest rate of 2.74%. 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 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 million of our variable rate debt. Any ineffectiveness is recorded directly to interest expense. As of March 31, 2014, we had no ineffectiveness on our cash flow hedges.

At March 31, 2014, we have accumulated other comprehensive loss of $49 thousand that relates to our current cash flow hedging instruments. Approximately $0.4 million will be transferred from accumulated other comprehensive loss into interest expense as interest is paid on the underlying swap agreement over the next twelve-month period, assuming interest rates remain unchanged.

- 13 -

HOLLY ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) Continued

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)
March 31, 2014
Interest rate swaps designated as cash flow hedging instrument:
Variable-to-fixed interest rate swap contracts ($155 million of LIBOR-based debt interest)	Other long-term     liabilities	$	(1,677	)	Accumulated other     comprehensive loss	$	(1,677	)
Variable-to-fixed interest rate swap contracts ($150 million of LIBOR-based debt interest)	Other long-term     assets	1,628			Accumulated other     comprehensive gain	1,628
		$	(49	)		$	(49	)
December 31, 2013
Interest rate swaps designated as cash flow hedging instrument:
Variable-to-fixed interest rate swap contracts ($155 million of LIBOR-based debt interest)	Other long-term     liabilities	$	(1,814	)	Accumulated other     comprehensive loss	$	(1,814	)
Variable-to-fixed interest rate swap contracts ($150 million of LIBOR-based debt interest)	Other long-term     assets	1,670			Accumulated other     comprehensive gain	1,670
		$	(144	)		$	(144	)

Interest Expense and Other Debt Information

Interest expense consists of the following components:

	Three Months Ended March 31,
	2014		2013
	(In thousands)
Interest on outstanding debt:
Credit Agreement, net of interest on interest rate swaps	$	2,698	$	3,081
6.5% Senior Notes	4,875		4,875
8.25% Senior Notes	2,544		3,094
Amortization of discount and deferred debt issuance costs	511		530
Amortization of unrecognized loss attributable to terminated cash flow hedge	—		849
Commitment fees	202		124
Total interest incurred	10,830		12,553
Less capitalized interest	376		69
Net interest expense	$	10,454	$	12,484
Cash paid for interest	$	18,782	$	19,033

Note 7: Significant Customers

All revenues are domestic revenues, of which 93% 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 March 31,
	2014		2013
HFC	83	%	83	%
Alon	10	%	9	%

- 14 -

HOLLY ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) Continued

Note 8: 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 agrees 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. As of March 31, 2014, these agreements with HFC will result in minimum annual payments to us of $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 the amount of any shortfall in cash by the last day of the month following the end of the quarter. Under certain of these agreements, a shortfall payment may be applied as a credit in the following four quarters after its minimum obligations are met.

Under certain provisions of an omnibus agreement we have with HFC (the “Omnibus Agreement”), we pay HFC an annual administrative fee (currently $2.3 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 HFC who perform services for us on behalf of HLS or the cost of their employee benefits, which are charged to us separately by HFC. Also, we reimburse HFC and its affiliates for direct expenses they incur on our behalf.

Related party transactions with HFC are as follows:

• Revenues received from HFC were $71.8 million and $61.5 million for the three months ended March 31, 2014 and 2013, respectively.

• HFC charged us general and administrative services under the Omnibus Agreement of $0.6 million for the three months ended March 31, 2014 and 2013, respectively.

• We reimbursed HFC for costs of employees supporting our operations of $9.2 million and $9.8 million for the three months ended March 31, 2014 and 2013, respectively.

• HFC reimbursed us $4.5 million and $4.9 million for the three months ended March 31, 2014 and 2013, respectively, for certain reimbursable costs and capital projects.

• We distributed $19.2 million and $17.4 million for the three months ended March 31, 2014 and 2013, respectively, to HFC as regular distributions on its common units and general partner interest, including general partner incentive distributions.

• Accounts receivable from HFC were $29.1 million and $29.7 million at March 31, 2014, and December 31, 2013, respectively.

• Accounts payable to HFC were $4.6 million and $8.5 million at March 31, 2014, and December 31, 2013, respectively.

• Revenues for the three months ended March 31, 2014, include $7.4 million of shortfall payments billed in 2013, as HFC did not exceed its minimum volume commitment in any of the subsequent four quarters. Deferred revenue in the consolidated balance sheets at March 31, 2014, and December 31, 2013, includes $3.7 million and $10.1 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 $3.7 million deferred at March 31, 2014.

Note 9: Partners’ Equity

As of March 31, 2014, HFC held 22,380,030 of our common units and the 2% general partner interest, which together constituted a 39% ownership interest in us.

Allocations of Net Income

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

- 15 -

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 March 31,
	2014		2013
	(In thousands)
General partner interest in net income	$	329	$	248
General partner incentive distribution	7,672		5,983
Total general partner interest in net income	$	8,001	$	6,231

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 April 24, 2014 we announced our cash distribution for the first quarter of 2014 of $0.5075 per unit. The distribution is payable on all common and general partner units and will be paid May 15, 2014 to all unitholders of record on May 4, 2014.

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 March 31,
	2014		2013
	(In thousands, except per unit data)
General partner interest in distribution	$	790	$	719
General partner incentive distribution	7,672		5,983
Total general partner distribution	8,462		6,702
Limited partner distribution	29,768		28,009
Total regular quarterly cash distribution	$	38,230	$	34,711
Cash distribution per unit applicable to limited partners	$	0.5075	$	0.4775

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 at the time of acquisition, as increases to our properties and equipment and intangible assets instead of decreases to our partners’ equity.

Note 10: Supplemental Guarantor/Non-Guarantor Financial Information

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

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

- 16 -

HOLLY ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) Continued

Condensed Consolidating Balance Sheet

March 31, 2014	Parent		Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	2	$	(423	)	$	5,300	$	—		$	4,879
Accounts receivable	—		31,352			3,275		(202		)	34,425
Intercompany accounts receivable	—		272,467			—		(272,467		)	—
Prepaid and other current assets	156		2,359			984		—			3,499
Total current assets	158		305,755			9,559		(272,669		)	42,803
Properties and equipment, net	—		568,047			390,702		—			958,749
Investment in subsidiaries	926,369		296,253			—		(1,222,622		)	—
Transportation agreements, net	—		85,913			—		—			85,913
Goodwill	—		256,498			—		—			256,498
Investment in SLC Pipeline	—		24,701			—		—			24,701
Other assets	1,399		8,668			—		—			10,067
Total assets	$	927,926	$	1,545,835		$	400,261	$	(1,495,291	)	$	1,378,731
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	—	$	13,540		$	2,415	$	(202	)	$	15,753
Intercompany accounts payable	272,467		—			—		(272,467		)	—
Accrued interest	1,679		97			—		—			1,776
Deferred revenue	—		5,834			1,020		—			6,854
Accrued property taxes	—		1,656			1,672		—			3,328
Other current liabilities	642		1,507			—		—			2,149
Total current liabilities	274,788		22,634			5,107		(272,669		)	29,860
Long-term debt	296,201		537,589			—		—			833,790
Other long-term liabilities	111		13,556			150		—			13,817
Deferred revenue	—		23,939			—		—			23,939
Class B unit	—		21,748			—		—			21,748
Equity - partners	356,826		926,369			395,004		(1,321,373		)	356,826
Equity - noncontrolling interest	—		—			—		98,751			98,751
Total liabilities and partners’ equity	$	927,926	$	1,545,835		$	400,261	$	(1,495,291	)	$	1,378,731

- 17 -

HOLLY ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) Continued

Condensed Consolidating Balance Sheet

December 31, 2013	Parent		Guarantor Restricted Subsidiaries		Non-Guarantor Non-Restricted Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	2	$	1,447	$	4,903	$	—		$	6,352
Accounts receivable	—		31,107		4,543		(914		)	34,736
Intercompany accounts receivable	—		62,516		—		(62,516		)	—
Prepaid and other current assets	234		2,590		1,050		—			3,874
Total current assets	236		97,660		10,496		(63,430		)	44,962
Properties and equipment, net	—		564,847		392,967		—			957,814
Investment in subsidiaries	885,598		292,464		—		(1,178,062		)	—
Transportation agreements, net	—		87,650		—		—			87,650
Goodwill	—		256,498		—		—			256,498
Investment in SLC Pipeline	—		24,741		—		—			24,741
Other assets	1,684		9,159		—		—			10,843
Total assets	$	887,518	$	1,333,019	$	403,463	$	(1,241,492	)	$	1,382,508
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	—	$	18,966	$	4,846	$	(914	)	$	22,898
Intercompany accounts payable	62,516		—		—		(62,516		)	—
Accrued interest	10,198		41		—		—			10,239
Deferred revenue	—		6,406		7,575		—			13,981
Accrued property taxes	—		1,661		942		—			2,603
Other current liabilities	629		1,216		—		—			1,845
Total current liabilities	73,343		28,290		13,363		(63,430		)	51,566
Long-term debt	444,630		363,000		—		—			807,630
Other long-term liabilities	99		14,338		148		—			14,585
Deferred revenue	—		21,669		—		—			21,669
Class B unit	—		20,124		—		—			20,124
Equity - partners	369,446		885,598		389,952		(1,275,550		)	369,446
Equity - noncontrolling interest	—		—		—		97,488			97,488
Total liabilities and partners’ equity	$	887,518	$	1,333,019	$	403,463	$	(1,241,492	)	$	1,382,508

- 18 -

HOLLY ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) Continued

Condensed Consolidating Statement of Comprehensive Income

Three Months Ended March 31, 2014	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-restricted Subsidiaries		Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	61,615		$	10,524	$	(307	)	$	71,832
Third parties	—			11,081			4,091		—			15,172
	—			72,696			14,615		(307		)	87,004
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	—			20,151			2,968		(307		)	22,812
Depreciation and amortization	—			11,993			3,595		—			15,588
General and administrative	1,058			2,093			—		—			3,151
	1,058			34,237			6,563		(307		)	41,551
Operating income (loss)	(1,058		)	38,459			8,052		—			45,453
Equity in earnings of subsidiaries	40,564			6,039			—		(46,603		)	—
Equity in earnings of SLC Pipeline	—			522			—		—			522
Interest expense	(7,686		)	(2,768		)	—		—			(10,454		)
Interest income	—			3			—		—			3
Loss on early extinguishment of debt	(7,677		)	—			—		—			(7,677		)
Other (income) expense	—			8			—		—			8
	25,201			3,804			—		(46,603		)	(17,598		)
Income before income taxes	24,143			42,263			8,052		(46,603		)	27,855
State income tax expense	—			(75		)	—		—			(75		)
Net income	24,143			42,188			8,052		(46,603		)	27,780
Allocation of net income attributable to noncontrolling interests	—			—			—		(3,637		)	(3,637		)
Net income attributable to Holly Energy Partners	24,143			42,188			8,052		(50,240		)	24,143
Other comprehensive income	95			95			—		(95		)	95
Comprehensive income	$	24,238		$	42,283		$	8,052	$	(50,335	)	$	24,238

- 19 -

HOLLY ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) Continued

Condensed Consolidating Statement of Comprehensive Income

Three Months Ended March 31, 2013	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries		Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	54,412		$	7,402	$	(302	)	$	61,512
Third parties	—			8,407			4,379		—			12,786
	—			62,819			11,781		(302		)	74,298
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	—			23,366			2,801		(302		)	25,865
Depreciation and amortization	—			10,570			3,584		—			14,154
General and administrative	808			2,424			—		—			3,232
	808			36,360			6,385		(302		)	43,251
Operating income (loss)	(808		)	26,459			5,396		—			31,047
Equity in earnings of subsidiaries	27,459			4,124			—		(31,583		)	—
Equity in earnings of SLC Pipeline	—			657			—		—			657
Interest expense	(8,252		)	(4,232		)	—		—			(12,484		)
Interest income	—			—			103		—			103
Gain on sale of assets	—			2,022			—		—			2,022
	19,207			2,571			103		(31,583		)	(9,702		)
Income before income taxes	18,399			29,030			5,499		(31,583		)	21,345
State income tax expense	—			(56		)	—		—			(56		)
Net income	18,399			28,974			5,499		(31,583		)	21,289
Allocation of net income attributable to noncontrolling interests	—			—			—		(2,890		)	(2,890		)
Net income attributable to Holly Energy Partners	18,399			28,974			5,499		(34,473		)	18,399
Other comprehensive income	1,411			1,411			—		(1,411		)	1,411
Comprehensive income	$	19,810		$	30,385		$	5,499	$	(35,884	)	$	19,810

- 20 -

HOLLY ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) Continued

Condensed Consolidating Statement of Cash Flows

Three Months Ended March 31, 2014	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities	$	(16,085	)	$	48,054		$	7,047		$	—		$	39,016
Cash flows from investing activities
Additions to properties and equipment	—			(16,954		)	(3,650		)	—			(20,604		)
Distributions from UNEV joint venture partners	—			2,250			—			(2,250		)	—
Distributions in excess of earnings of SLC Pipeline	—			40			—			—			40
	—			(14,664		)	(3,650		)	(2,250		)	(20,564		)
Cash flows from financing activities
Net borrowings under credit agreement	—			174,700			—			—			174,700
Net intercompany financing activities	209,951			(209,951		)	—			—			—
Redemption of senior notes	(156,188		)	—			—			—			(156,188		)
Distributions to HEP unitholders	(37,342		)	—			—			—			(37,342		)
Distributions to UNEV joint venture partners	—			—			(3,000		)	2,250			(750		)
Deferred financing cost	—			(9		)	—			—			(9		)
Purchase of units for incentive grants	(336		)	—			—			—			(336		)
	16,085			(35,260		)	(3,000		)	2,250			(19,925		)
Cash and cash equivalents
Increase for the period	—			(1,870		)	397			—			(1,473		)
Beginning of period	2			1,447			4,903			—			6,352
End of period	$	2		$	(423	)	$	5,300		$	—		$	4,879

- 21 -

HOLLY ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) Continued

Condensed Consolidating Statement of Cash Flows

Three Months Ended March 31, 2013	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations		Consolidated
	(In thousands)
Cash flows from operating activities (1)	$	(18,763	)	$	41,244		$	8,368		$	—	$	30,849
Cash flows from investing activities
Additions to properties and equipment	—			(6,422		)	(223		)	—		(6,645		)
Proceeds from sale of assets	—			2,481			—			—		2,481
Distributions in excess of earnings of SLC Pipeline	—			30			—			—		30
	—			(3,911		)	(223		)	—		(4,134		)
Cash flows from financing activities
Net repayments under credit agreement	—			(53,000		)	—			—		(53,000		)
Net intercompany financing activities (1)	(20,478		)	20,478			—			—		—
Proceeds from issuance of common units	73,444			—			—			—		73,444
Contribution from general partner	1,499			—			—			—		1,499
Distributions to HEP unitholders	(32,709		)	—			—			—		(32,709		)
Purchase of units for incentive grants	(2,719		)	—			—			—		(2,719		)
Other	(274		)	—			—			—		(274		)
	18,763			(32,522		)	—			—		(13,759		)
Cash and cash equivalents
Increase (decrease) for the period	—			4,811			8,145			—		12,956
Beginning of period	2			823			4,412			—		5,237
End of period	$	2		$	5,634		$	12,557		$	—	$	18,193

(1) Effective with fiscal year 2013, we changed the cash flow presentation of transactions associated with the partnership's intercompany lending activities by reclassifying certain amounts from operating cash flows to financing cash flows.

- 22 -

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”), the owner of a pipeline running from Woods Cross, Utah to Las Vegas, Nevada (the “UNEV Pipeline”), product terminals and a 25% interest in SLC Pipeline LLC, 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.

We have a long-term strategic relationship with HFC. Our current growth plan is to continue to pursue purchases of logistic assets at HFC's existing refining locations in New Mexico, Utah, Oklahoma, Kansas and Wyoming. We also expect to work with HFC on logistic asset acquisitions in conjunction with HFC’s refinery acquisition strategies. Furthermore, we plan to continue to pursue third-party logistic asset acquisitions that are accretive to our unitholders and increase the diversity of our revenues.

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 has 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. As of March 31, 2014, these agreements with HFC will result in minimum annualized payments to us of $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 the amount of any shortfall in cash by the last day of the month following the end of the quarter. Under certain of the agreements, a shortfall payment may be applied as a credit in the following four quarters after minimum obligations are met.

We 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 is also subject to annual tariff rate adjustments. We also have a capacity lease agreement under which we lease Alon space on our Orla to El Paso pipeline for the shipment of refined product. The terms under this agreement expire beginning in 2018 through 2022. As of March 31, 2014, these agreements with Alon will result in minimum annualized payments to us of $32.1 million.

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

Under certain provisions of an omnibus agreement we have with HFC (“Omnibus Agreement”), we pay HFC an annual administrative fee, currently $2.3 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 HFC who perform services for us on behalf of HLS or the cost of their employee benefits, which are separately charged to us by HFC. We also reimburse HFC and its affiliates for direct expenses they incur on our behalf.

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RESULTS OF OPERATIONS (Unaudited)

Income, Distributable Cash Flow and Volumes

The following tables present income, distributable cash flow and volume information for the three months ended March 31, 2014 and 2013.

	Three Months Ended March 31,						Change from
	2014			2013			2013
	(In thousands, except per unit data)
Revenues:
Pipelines:
Affiliates—refined product pipelines	$	24,173		$	16,770		$	7,403
Affiliates—intermediate pipelines	7,911			6,172			1,739
Affiliates—crude pipelines	12,618			11,579			1,039
	44,702			34,521			10,181
Third parties—refined product pipelines	11,618			10,343			1,275
	56,320			44,864			11,456
Terminals, tanks and loading racks:
Affiliates	27,130			26,991			139
Third parties	3,554			2,443			1,111
	30,684			29,434			1,250
Total revenues	87,004			74,298			12,706
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	22,812			25,865			(3,053		)
Depreciation and amortization	15,588			14,154			1,434
General and administrative	3,151			3,232			(81		)
	41,551			43,251			(1,700		)
Operating income	45,453			31,047			14,406
Other income (expense):
Equity in earnings of SLC Pipeline	522			657			(135		)
Interest expense, including amortization	(10,454		)	(12,484		)	2,030
Interest income	3			103			(100		)
Loss on early extinguishment of debt	(7,677		)	—			(7,677		)
Gain on sale of assets	—			2,022			(2,022		)
Other	8			—			8
	(17,598		)	(9,702		)	(7,896		)
Income before income taxes	27,855			21,345			6,510
State income tax	(75		)	(56		)	(19		)
Net income	27,780			21,289			6,491
Allocation of net income attributable to noncontrolling interests	(3,637		)	(2,890		)	(747		)
Net income attributable to Holly Energy Partners	24,143			18,399			5,744
General partner interest in net income, including incentive distributions (1)	(8,001		)	(6,231		)	(1,770		)
Limited partners’ interest in net income	$	16,142		$	12,168		$	3,974
Limited partners’ earnings per unit—basic and diluted(1)	$	0.27		$	0.21		$	0.06
Weighted average limited partners’ units outstanding	58,657			56,990			1,667
EBITDA(2)	$	57,934		$	44,990		$	12,944
Distributable cash flow(3)	$	41,808		$	32,385		$	9,423
Volumes (bpd)
Pipelines:
Affiliates—refined product pipelines	123,171			94,148			29,023
Affiliates—intermediate pipelines	138,608			120,777			17,831
Affiliates—crude pipelines	176,953			145,926			31,027
	438,732			360,851			77,881
Third parties—refined product pipelines	66,294			52,986			13,308
	505,026			413,837			91,189
Terminals and loading racks:
Affiliates	262,635			260,242			2,393
Third parties	77,704			55,459			22,245
	340,339			315,701			24,638
Total for pipelines and terminal assets (bpd)	845,365			729,538			115,827

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(1) 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.

(2) 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. 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 is also used by our management for internal analysis and as a basis for compliance with financial covenants. Set forth below is our calculation of EBITDA.

	Three Months Ended March 31,
	2014			2013
	(In thousands)
Net income attributable to Holly Energy Partners	$	24,143		$	18,399
Add (subtract):
Interest expense	9,943			11,105
Interest income	(3		)	(103		)
Amortization of discount and deferred debt issuance costs	511			530
Loss on early extinguishment of debt	7,677			—
Increase in interest expense - non-cash charges attributable to interest rate swaps and swap settlement amortization	—			849
State income tax	75			56
Depreciation and amortization	15,588			14,154
EBITDA	$	57,934		$	44,990

(3) Distributable cash flow is not a calculation based upon GAAP. However, the amounts included in the calculation are derived from amounts presented in our consolidated financial statements, with the general exceptions of 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.

	Three Months Ended March 31,
	2014			2013
	(In thousands)
Net income attributable to Holly Energy Partners	$	24,143		$	18,399
Add (subtract):
Depreciation and amortization	15,588			14,154
Amortization of discount and deferred debt issuance costs	511			530
Loss on early extinguishment of debt	7,677			—
Increase in interest expense - non-cash charges attributable to interest rate swaps and swap settlement amortization	—			849
Decrease in deferred revenue related to minimum revenue commitments	(5,898		)	(1,224		)
Maintenance capital expenditures (4)	(849		)	(2,335		)
Crude revenue settlement	—			918
Other non-cash adjustments	636			1,094
Distributable cash flow	$	41,808		$	32,385

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

	March 31, 2014		December 31, 2013
	(In thousands)
Balance Sheet Data
Cash and cash equivalents	$	4,879	$	6,352
Working capital (deficit)	$	12,943	$	(6,604	)
Total assets	$	1,378,731	$	1,382,508
Long-term debt	$	833,790	$	807,630
Partners’ equity (5)	$	356,826	$	369,446

(5) As a master limited partnership, we distribute our available cash, which historically has exceeded our net income because depreciation and amortization expense represents a non-cash charge against income. The result is a decline in partners’ equity since our regular quarterly distributions have exceeded our quarterly net income. Additionally, if the assets contributed and acquired from HFC while under common control of HFC had been acquired from third parties, our acquisition cost in excess of HFC’s basis in the transferred assets of $305.3 million would have been recorded in our financial statements as increases to our properties and equipment and intangible assets instead of decreases to partners’ equity.

Results of Operations—Three Months Ended March 31, 2014 Compared with Three Months Ended March 31, 2013

Summary

Net income attributable to HEP for the first quarter was $24.1 million compared to $18.4 million for the first quarter of 2013. The increase in net income is primarily due to higher pipeline and terminal volumes. Shipments were reduced in the first quarter of 2013 due to maintenance turnarounds at both HFC's Navajo refinery and Alon's Big Spring refinery. Additionally, a charge of $7.7 million related to the redemption of our $150 million 8.25% Senior Notes significantly impacted earnings in the first quarter of 2014.

Revenues for the three months ended March 31, 2014, include the recognition of $9.3 million of prior shortfalls billed to shippers in 2013 compared to revenues at March 31, 2013, which included the recognition of $6.7 million of prior shortfalls billed to shippers in 2012. Deficiency payments of $1.8 million associated with certain guaranteed shipping contracts were deferred during the three months ended March 31, 2014. Such deferred revenue will be recognized in earnings either as payment for shipments in excess of guaranteed levels, if and to the extent the pipeline system will not have the necessary capacity for shipments in excess of guaranteed levels, or when shipping rights expire unused.

Revenues

Total revenues for the quarter were $87.0 million, a $12.7 million increase compared to the first quarter of 2013. The revenue increase was due to the effect of higher volumes, an increase in deferred revenue recognized and annual tariff increases. Overall pipeline volumes were up 22% for the three months ended March 31, 2014, as compared to the three months ended March 31, 2013.

Revenues from our refined product pipelines were $35.8 million, an increase of $8.7 million compared to the first quarter of 2013 primarily due to increased volumes. Additionally benefiting refined product revenues were the effect of annual tariff increases and an increase of $2.0 million in deferred revenue recognized. Shipments averaged 189.5 thousand barrels per day (“mbpd”) compared to 147.1 mbpd for the first quarter of 2013.

Revenues from our intermediate pipelines were $7.9 million, an increase of $1.7 million, on shipments averaging 138.6 mbpd compared to 120.8 mbpd for the first quarter of 2013. Revenues increased due to the increased volumes and a $0.7 million increase in deferred revenue recognized.

Revenues from our crude pipelines were $12.6 million, an increase of $1.0 million, on shipments averaging 177.0 mbpd compared to 145.9 mbpd for the first quarter of 2013.

Revenues from terminal, tankage and loading rack fees were $30.7 million, an increase of $1.3 million compared to the first quarter of 2013. Refined products terminalled in our facilities averaged 340.3 mbpd compared to 315.7 mbpd for the first quarter of 2013.

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Operations Expense

Operations expense for the three months ended March 31, 2014, decreased by $3.1 million compared to the three months ended March 31, 2013. This decrease is due to lower maintenance costs and environmental accruals.

Depreciation and Amortization

Depreciation and amortization for the three months ended March 31, 2014 increased by $1.4 million compared to the three months ended March 31, 2013. The increase is due principally to depreciation and amortization attributable to capitalized projects.

General and Administrative

General and administrative costs for the three months ended March 31, 2014, decreased by $0.1 million compared to the three months ended March 31, 2013.

Equity in Earnings of SLC Pipeline

Our equity in earnings of the SLC Pipeline was $0.5 million for the three months ended March 31, 2014, compared to $0.7 million for the three months ended March 31, 2013.

Interest Expense

Interest expense for the three months ended March 31, 2014, totaled $10.5 million, a decrease of $2.0 million compared to the three months ended March 31, 2013. The decrease is due principally to amortization of costs related to a terminated cash flow hedge that became fully amortized in February 2013 as well as decreased interest expense incurred on our 8.25% Senior Notes due to early retirement in March 2014. Our aggregate effective interest rates were 5.1% and 5.7% for the three months ended March 31, 2014 and 2013, respectively.

Loss on Early Extinguishment of Debt

We recognized a charge of $7.7 million upon the early extinguishment of our 8.25% Senior Notes in the three months ended March 31, 2014. This charge is for the premium paid to noteholders upon their tender of an aggregate principal amount of $150.0 million and related financing costs that were previously deferred.

Gain on Sale of Assets

The gain on the sale of assets for the three months ended March 31, 2013, of $2.0 million is from the sale of property in El Paso, Texas.

State Income Tax

We recorded state income tax expense of $75,000 for the three months ended March 31, 2014, which is solely attributable to the Texas margin tax. For the three months ended March 31, 2013, we recorded state income tax expense of $56,000.

LIQUIDITY AND CAPITAL RESOURCES

Overview

We have a $650 million senior secured revolving credit facility expiring in November 2018 (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.

During the three months ended March 31, 2014, we received advances totaling $421.3 million and repaid $246.6 million resulting in a net increase of $174.7 million under the Credit Agreement and an outstanding balance of $537.7 million at March 31, 2014.

If any particular lender under the Credit Agreement could not honor its commitment, we believe the unused capacity that would be available from the remaining lenders would be sufficient to meet our borrowing needs. Additionally, we review publicly available information on the lenders in order to monitor their financial stability and assess their ongoing ability to honor their commitments under the Credit Agreement. We do not expect to experience any difficulty in the lenders’ ability to honor their respective commitments, and if it were to become necessary, we believe there would be alternative lenders or options available.

In March 2014, we redeemed the $150 million aggregate principal amount of our 8.25% senior notes (the "8.25% Senior Notes") maturing March 2018 at a redemption cost of $156.2 million at which time we recognized a $7.7 million early extinguishment loss consisting of a $6.2 million debt redemption premium and an unamortized discount of $1.5 million. We funded the redemption with borrowings under our Credit Agreement.

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Under our registration statement filed with the SEC using a “shelf” registration process, we currently have the ability to raise up to $2.0 billion by offering securities, through one or more prospectus supplements that would describe, among other things, the specific amounts, prices and terms of any securities offered and how the proceeds would be used. Any proceeds from the sale of securities would be used for general business purposes, which may include, among other things, funding acquisitions of assets or businesses, working capital, capital expenditures, investments in subsidiaries, the retirement of existing debt and/or the repurchase of common units or other securities.

We believe our current cash balances, future internally generated funds and funds available under the Credit Agreement will provide sufficient resources to meet our working capital liquidity needs for the foreseeable future.

In February 2014, we paid regular quarterly cash distributions of $0.50 on all units in an aggregate amount of $37.3 million including $7.3 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 decreased by $1.5 million during the three months ended March 31, 2014. The cash flows provided by operating activities of $39.0 million were less than the sum of cash flows used for financing and investing activities of $19.9 million and $20.6 million, respectively. Working capital increased by $19.5 million to $12.9 million at March 31, 2014, from a negative $6.6 million at December 31, 2013.

Cash Flows—Operating Activities

Cash flows from operating activities increased by $8.2 million from $30.8 million for the three months ended March 31, 2013, to $39.0 million for the three months ended March 31, 2014. This increase is due principally to $7.4 million of greater cash receipts for services performed in the three months ended March 31, 2014, as compared to the prior year.

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 $9.3 million during 2013 related to shortfalls that subsequently expired without recapture and were recognized as revenue during the three months ended March 31, 2014. Another $1.8 million is included as deferred revenue on our balance sheet at March 31, 2014, related to shortfalls billed during the three months ended March 31, 2014.

Cash Flows—Investing Activities

Cash flows used for investing activities increased by $16.4 million from $4.1 million for the three months ended March 31, 2013, to $20.6 million for the three months ended March 31, 2014. During the three months ended March 31, 2014 and 2013, we invested $20.6 million and $6.6 million in additions to properties and equipment, respectively. During the three months ended March 31, 2013, we received $2.5 million proceeds from the sale of assets.

Cash Flows—Financing Activities

Cash flows used for financing activities were $19.9 million for the three months ended March 31, 2014, compared to $13.8 million for the three months ended March 31, 2013, an increase of $6.2 million. During the three months ended March 31, 2014, we received $421.3 million and repaid $246.6 million in advances under the Credit Agreement and paid $156.2 million to redeem the 8.25% Senior Notes. Additionally, we paid $37.3 million in regular quarterly cash distributions to our general and limited partners, paid $0.8 million to our noncontrolling interest and paid $0.3 million for the purchase of common units for recipients of our incentive grants. During the three months ended March 31, 2013, we received $57.0 million and repaid $110.0 million in advances under the Credit Agreement, received net proceeds of $73.4 million from the common unit public offering and and $1.5 million from the general partner to maintain its 2% interest. We paid $32.7 million in regular quarterly cash distributions to our general and limited partners and paid $2.7 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

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expenditures include expenditures to acquire assets, to grow our business and to expand existing facilities, such as projects that increase throughput capacity on our pipelines and in our terminals. Repair and maintenance expenses associated with existing assets that are minor in nature and do not extend the useful life of existing assets are charged to operating expenses as incurred.

Each year the board of directors of Holly Logistic Services, L.L.C., our ultimate general partner ("HLS") 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 2014 capital budget is comprised of $7.3 million for maintenance capital expenditures and $26.2 million for expansion capital expenditures. We expect to spend approximately $52 million in cash for capital projects approved in 2014 plus those approved in prior years but not yet completed, including the planned expansion of our crude oil transportation system in southeastern New Mexico and the UNEV project discussed below. In addition to our capital budget, we may spend funds periodically to perform capital upgrades to our assets where a customer reimburses us for such costs. These reimbursements would be required under contractual agreements, and the upgrades would generally benefit the customer over the remaining life of such agreements.

We are proceeding with the expansion of our crude oil transportation system in southeastern New Mexico in response to increased crude oil production in the area. The expansion should provide shippers with additional pipeline takeaway capacity to either common carrier pipeline stations for transportation to major crude oil markets or to HFC's New Mexico refining facilities. To complete the project, we are converting an existing refined products pipeline to crude oil service, constructing several new pipeline segments, expanding an existing pipeline, and building new truck unloading stations and crude storage capacity. Excluding the value of the existing pipeline to be converted, total capital expenditures are expected to be between $45 million and $50 million. We expect that the increase over the original budget range of $35 million to $40 million will be recovered from HFC over a five year period through an additional fee on shipped volumes. 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 by August 2014.

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

We are collaborating with HFC to evaluate the construction of a rail facility that would enable crude oil loading and unloading near HFC's Artesia and/or Lovington, New Mexico refining facilities. The rail project, which would be connected to our crude oil pipeline transportation system in southeastern New Mexico, would have an initial capacity of up to 70,000 barrels per day and would enable access to a variety of crude oil types including West Texas Intermediate ("WTI"), West Texas Sour ("WTS") and Western Canadian Select ("WCS"). The project would provide both additional crude oil takeaway options for producers as crude production in the region continues to grow and an expanded set of crude oil sourcing options for HFC. We anticipate project completion would take nine to twelve months once the decision to proceed is made. Our decision to proceed with this project is dependent upon shipper interest, which at present does not support project completion.

We have announced that we are evaluating the potential construction of several new tanks at HFC’s El Dorado Refinery as well as additional pipeline connections that could increase the refinery’s crude flexibility. As this potential project is still under consideration, the HLS board has not yet approved a capital budget for such project.

We expect that our currently planned sustaining and maintenance capital expenditures, as well as expenditures for acquisitions and capital development projects, will be funded with cash generated by operations, the sale of additional limited partner common units, the issuance of debt securities and advances under our Credit Agreement, or a combination thereof. With volatility and uncertainty at times in the credit and equity markets, there may be limits on our ability to issue new debt or equity financing. Additionally, due to pricing movements in the debt and equity markets, we may not be able to issue new debt and equity securities at acceptable pricing. Without additional capital beyond amounts available under the Credit Agreement, our ability to obtain funds for some of these capital projects may be limited.

Under the terms of the transaction to acquire HFC's 75% interest in UNEV, we issued to HFC a Class B unit comprising a noncontrolling equity interest in a wholly-owned subsidiary subject to redemption to the extent that HFC is entitled to a 50% interest in our share of annual UNEV earnings before interest, income taxes, depreciation, and amortization above $30 million beginning July 1, 2016, and ending in June 2032, subject to certain limitations.

Credit Agreement

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We have a $650 million senior secured revolving credit facility expiring in November 2018 (the “Credit Agreement”) that is available to fund capital expenditures, investments, acquisitions, distribution payments and working capital and for general partnership purposes. It is also available to fund letters of credit up to a $50 million sub-limit.

Our obligations under the Credit Agreement are collateralized by substantially all of our assets. Indebtedness under the Credit Agreement involves recourse to HEP Logistics Holdings, L.P. (“HEP Logistics”), our general partner, and is 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 2014, we redeemed the $150.0 million aggregate principal amount of 8.25% senior notes (the "8.25% Senior Notes") maturing March 2018 at a redemption cost of $156.2 million at which time we recognized a $7.7 million early extinguishment loss consisting of a $6.2 million debt redemption premium and unamortized discount and financing costs of $1.5 million. We funded the redemption with borrowings under our Credit Agreement.

We have $300 million in aggregate principal amount outstanding of 6.5% senior notes (the "6.5% Senior Notes") maturing March 2020. The 6.5% Senior Notes are unsecured and impose certain restrictive covenants, with which we are currently in compliance, 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 6.5% Senior Notes are rated investment grade by both Moody’s and Standard & Poor’s and no default or event of default exists, we will not be subject to many of the foregoing covenants. Additionally, we have certain redemption rights at varying premiums over face value under the 6.5% Senior Notes.

Indebtedness under the 6.5% Senior Notes involves recourse to HEP Logistics, our general partner, and is 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:

	March 31, 2014			December 31, 2013
	(In thousands)
Credit Agreement	$	537,700		$	363,000
6.5% Senior Notes
Principal	300,000			300,000
Unamortized discount	(3,910		)	(4,073		)
	296,090			295,927
8.25% Senior Notes
Principal	—			150,000
Unamortized discount	—			(1,297		)
	—			148,703
Total long-term debt	$	833,790		$	807,630

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

Contractual Obligations

Other than the redemption of our 8.25% Senior Notes discussed above, there were no significant changes to our long-term contractual obligations during this period.

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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 three months ended March 31, 2014 and 2013. Historically, the PPI has increased an average of 2.2% 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 our operations are in substantial compliance with applicable environmental laws and regulations. However, these laws and regulations, and the interpretation or enforcement thereof, are subject to frequent change by regulatory authorities, and we are unable to predict the ongoing cost to us of complying with these laws and regulations or the future impact of these laws and regulations on our operations. Violation of environmental laws, regulations, and permits can result in the imposition of significant administrative, civil and criminal penalties, injunctions, and construction bans or delays. A major discharge of hydrocarbons or hazardous substances into the environment could, to the extent the event is not insured, subject us to substantial expense, including both the cost to comply with applicable laws and regulations and claims made by employees, neighboring landowners and other third parties for personal injury and property damage.

Under the Omnibus Agreement and certain transportation agreements and purchase agreements with HFC, HFC has agreed to indemnify us, subject to certain monetary and time limitations, for environmental noncompliance and remediation liabilities associated with certain assets transferred to us from HFC and occurring or existing prior to the date of such transfers.

We have an environmental agreement with Alon with respect to pre-closing environmental costs and liabilities relating to the pipelines and terminals acquired from Alon in 2005, under which Alon will indemnify us subject to certain monetary and time limitations.

There are environmental remediation projects that are currently in progress that relate to certain assets acquired from HFC. Certain of these projects were underway prior to our purchase and represent liabilities of HFC as the obligation for future remediation activities was retained by HFC. At March 31, 2014, we have an accrual of $3.2 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, 2013. 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 2014. 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.

RISK MANAGEMENT

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

As of March 31, 2014, we have three interest rate swaps, designated as a cash flow hedge, that hedge our exposure to the cash flow risk caused by the effects of LIBOR changes on $305.0 million of Credit Agreement advances. Our first interest rate swap

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effectively converts $155.0 million of our LIBOR based debt to fixed rate debt having an interest rate of 0.99% plus an applicable margin of 2.00% as of March 31, 2014, which equaled an effective interest rate of 2.99%. 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 2.00% as of March 31, 2014, which equaled an effective interest rate of 2.74%. Both of these swap contracts mature in July 2017.

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

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

At March 31, 2014, we had an outstanding principal balance on our 6.5% Senior Notes of $300 million. A change in interest rates generally would affect the fair value of the Senior Notes, but not our earnings or cash flows. At March 31, 2014, the fair value of our 6.5% Senior Notes was $319.5 million. We estimate a hypothetical 10% change in the yield-to-maturity applicable to the 6.5% Senior Notes at March 31, 2014, would result in a change of approximately $8.4 million 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 March 31, 2014, borrowings outstanding under the Credit Agreement were $537.7 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 $232.7 million, a hypothetical 10% change in interest rates applicable to the Credit Agreement would not materially affect our cash flows.

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

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. See “Risk Management” under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a discussion of market risk exposures that we have with respect to our long-term debt, which disclosure should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our Annual Report on Form 10-K for the fiscal year ended December 31, 2013. 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

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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 March 31, 2014, 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, 2013. In addition to the other information set forth in this quarterly report, you should consider carefully the factors discussed in our 2013 Form 10-K, which could materially affect our business, financial condition or future results. The risks described in our 2013 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
January 2014	—	$	—	—	$	—
February 2014	—	$	—	—	$	—
March 2014	2,450	$	33.68	—	$	—
Total for January through March	2,450			—

The units reported represent a purchase of 2,450 common units in the open market to provide for the vesting of performance units.

Item 6. Exhibits

The Exhibit Index on page 36 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: May 2, 2014	/s/    Douglas S. Aron
	Douglas S. Aron
	Executive Vice President and Chief Financial Officer (Principal Financial Officer)
Date: May 2, 2014	/s/     Kenneth P. Norwood
	Kenneth P. Norwood
	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	Second Amended and Restated Pipeline Delivery, Tankage and Loading Rack Throughput Agreement (El Dorado), dated January 7, 2014, between Frontier El Dorado Refining LLC and El Dorado Logistics LLC (incorporated by reference to Exhibit 10.1 of Registrant's Form 8-K Current Report dated January 13, 2014, File No. 001-32225).
10.2	Ninth Amended and Restated Omnibus Agreement, dated January 7, 2014, among HollyFrontier Corporation, Holly Energy Partners, L.P. and certain of their respective subsidiaries (incorporated by reference to Exhibit 10.2 of Registrant's Form 8-K Current Report dated January 13, 2014, File No. 001-32225).
10.3	Third Amendment to Lease and Access Agreement (El Dorado), dated January 7, 2014, between Frontier El Dorado Refining LLC and El Dorado Logistics LLC (incorporated by reference to Exhibit 10.66 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2013, File No. 001-32225).
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 March 31, 2014, 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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