10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_________________________________________________________________

FORM 10-K

_________________________________________________________________

(Mark One)
ý	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 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

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HOLLY ENERGY PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

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Delaware	20-0833098
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
2828 N. Harwood, Suite 1300 Dallas, Texas	75201-1507
(Address of principal executive offices)	(Zip Code)

(214) 871-3555

Registrant’s telephone number, including area code

_________________________________________________________________

Securities registered pursuant to Section 12(b) of the Act:

Common Limited Partner Units

Securities registered pursuant to 12(g) of the Act:

None.

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Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes  ý    No  ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15 (d) of the Act. Yes  ¨    No  ý

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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.       ý

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 in Rule 12b-2 of the Exchange Act).     Yes  ¨    No  ý

The aggregate market value of common limited partner units held by non-affiliates of the registrant was approximately $1.2 billion on June 30, 2014, the last day of the registrant's most recently completed second fiscal quarter, based on the last sales price as quoted on the New York Stock Exchange on such date.

The number of the registrant’s outstanding common limited partners units at February 20, 2015 was 58,657,048.

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DOCUMENTS INCORPORATED BY REFERENCE: None

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TABLE OF CONTENTS

Item		Page
	PART I
Forward-Looking Statements		3
1.	Business	5
1A.	Risk factors	11
1B.	Unresolved staff comments	27
2.	Properties	27
3.	Legal proceedings	34
4.	Mine safety disclosures	34
	PART II
5.	Market for the Registrant’s common units, related unitholder matters and issuer purchases of common units	35
6.	Selected financial data	37
7.	Management’s discussion and analysis of financial condition and results of operations	39
7A.	Quantitative and qualitative disclosures about market risk	53
8.	Financial statements and supplementary data	54
9.	Changes in and disagreements with accountants on accounting and financial disclosure	86
9A.	Controls and procedures	86
9B.	Other information	86
	PART III
10.	Directors, executive officers and corporate governance	87
11.	Executive compensation	98
12.	Security ownership of certain beneficial owners and management and related unitholder matters	124
13.	Certain relationships and related transactions, and director independence	127
14.	Principal accounting fees and services	130
	PART IV
15.	Exhibits and Financial Statement Schedules	131
Signatures		131
Index to exhibits		133

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PART I

FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K 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-K, including, but not limited to, those under “Business”, “Risk Factors” and “Properties” in Items 1, 1A and 2 and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7, 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-K, including without limitation, the forward-looking statements that are referred to above. When considering forward-looking statements, you should keep in mind the known material risk factors and other cautionary statements set forth in this Form 10-K under “Risk Factors” in Item 1A. All forward-looking statements included in this Form 10-K 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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INDEX TO DEFINED TERMS AND NAMES

The following terms and names that appear in this form 10-K are defined on the following pages:

6.25% Senior Notes	45
6.5% Senior Notes	13
8.25% Senior Notes	6
Alon	5
Beeson Pipeline	28
bpd	8
Credit Agreement	6
DOT	8
EBITDA	37
Expansion capital expenditures	7
FERC	6
GAAP	38
Guarantor subsidiaries	77
HEP	5
HEP Logistics	21
HLS	5
HFC	5
LACT	6
LIBOR	49
Long-term Incentive Plan	36
LPG	6
Maintenance capital expenditures	7
mbbls	28
mbpd	43
MMSCFD	28
Mid-America	28
Non-Guarantor	77
NuStar	32
Omnibus Agreement	7
OSHA	17
Parent	77
Plains	5
PHMSA	8
PPI	6
Predecessor	37
SEC	5
Sinclair	30
SLC Pipeline	5
UNEV	5
UNEV Pipeline	5

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Item 1. Business

OVERVIEW

Holly Energy Partners, L.P. (“HEP”) is a Delaware limited partnership engaged principally in the business of operating a system of petroleum product and crude pipelines, storage tanks, distribution terminals and loading rack facilities in West Texas, New Mexico, Utah, Nevada, Oklahoma, Wyoming, Kansas, Arizona, Idaho and Washington. We were formed in Delaware in 2004 and maintain our principal corporate offices at 2828 N. Harwood, Suite 1300, Dallas, Texas 75201-1507. Our telephone number is 214-871-3555 and our internet website address is www.hollyenergy.com. The information contained on our website does not constitute part of this Annual Report on Form 10-K. A copy of this Annual Report on Form 10-K will be provided without charge upon written request to the Vice President, Investor Relations at the above address. A direct link to our filings at the U.S. Securities and Exchange Commission (“SEC”) website is available on our website on the Investors page. Also available on our website are copies of our Governance Guidelines, Audit Committee Charter, Compensation Committee Charter, and Code of Business Conduct and Ethics, all of which will be provided without charge upon written request to the Vice President, Investor Relations at the above address. In this document, the words “we,” “our,” “ours” and “us” refer to HEP and its consolidated subsidiaries or to HEP or an individual subsidiary and not to any other person. “HFC” refers to HollyFrontier Corporation and its subsidiaries, other than HEP and its subsidiaries and other than Holly Logistic Services, L.L.C. (“HLS”), a subsidiary of HollyFrontier Corporation that is the general partner of the general partner of HEP and manages HEP.

We own and operate petroleum product and crude 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. HFC currently owns a 39% interest in us, including the 2% general partner interest. Additionally, we own a 75% interest in UNEV Pipeline, LLC (“UNEV”), which owns a 427-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% joint venture interest in 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.

Our assets include:

Pipelines:

• approximately 810 miles of refined product pipelines, including 340 miles of leased pipelines, that transport gasoline, diesel and jet fuel principally from HFC’s Navajo refinery in New Mexico to its customers in the metropolitan and rural areas of Texas, New Mexico, Arizona, Utah and northern Mexico;

• approximately 510 miles of refined product pipelines that transport refined products from Alon’s Big Spring refinery in Texas to its customers in Texas and Oklahoma;

• three 65-mile intermediate pipelines that transport intermediate feedstocks and crude oil from HFC’s Navajo refinery crude oil distillation and vacuum facilities in Lovington, New Mexico to its petroleum refinery facilities in Artesia, New Mexico;

• approximately 910 miles of crude oil trunk, gathering and connection pipelines located in West Texas, New Mexico and Oklahoma that deliver crude oil to HFC’s Navajo refinery;

• approximately 8 miles of refined product pipelines that support HFC’s Woods Cross refinery located near Salt Lake City, Utah;

• gasoline and diesel connecting pipelines located at HFC’s Tulsa East refinery facility;

• five intermediate product and gas pipelines between HFC’s Tulsa East and West refinery facilities;

• crude receiving assets located at HFC’s Cheyenne refinery;

• a 75% interest in the UNEV Pipeline, a 427-mile refined products pipeline running from Woods Cross, Utah to Las Vegas, Nevada; and

• a 25% joint venture interest in the SLC Pipeline, a 95-mile intrastate crude oil pipeline system that transports crude oil into the Salt Lake City, Utah area from the Utah terminus of the Frontier Pipeline, as well as crude oil flowing from Wyoming and Utah via Plains All American Pipeline, L. P.’s (“Plains”) Rocky Mountain Pipeline.

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Refined Product Terminals and Refinery Tankage:

• four refined product terminals located in El Paso, Texas; Moriarty and Bloomfield, New Mexico; and Tucson, Arizona, with an aggregate capacity of approximately 1,200,000 barrels, that are integrated with our refined product pipeline system that serves HFC’s Navajo refinery;

• one refined product terminal located in Spokane, Washington, with a capacity of approximately 400,000 barrels, that serves third-party common carrier pipelines;

• one refined product terminal near Mountain Home, Idaho with a capacity of approximately 120,000 barrels, that serves a nearby United States Air Force Base;

• two refined product terminals, located in Wichita Falls and Abilene, Texas, and one tank farm in Orla, Texas with aggregate capacity of approximately 500,000 barrels, that are integrated with our refined product pipelines that serve Alon’s Big Spring refinery;

• a refined product loading rack facility at each of HFC’s refineries, heavy product / asphalt loading rack facilities at HFC’s Navajo refinery Lovington facility, Tulsa refinery East facility and the Cheyenne refinery, liquefied petroleum gas (“LPG”) loading rack facilities at HFC’s Tulsa refinery West facility, Cheyenne refinery and El Dorado refinery, lube oil loading racks at HFC’s Tulsa refinery West facility and crude oil Leased Automatic Custody Transfer (“LACT”) units located at HFC’s Cheyenne refinery;

• on-site crude oil tankage at HFC’s Navajo, Woods Cross, Tulsa and Cheyenne refineries having an aggregate storage capacity of approximately 1,300,000 barrels;

• on-site refined and intermediate product tankage at HFC’s Tulsa, Cheyenne and El Dorado refineries having an aggregate storage capacity of approximately 8,100,000 barrels; and

• a 75% interest in UNEV Pipeline's product terminals near Cedar City, Utah and Las Vegas, Nevada with an aggregate capacity of approximately 615,000 barrels.

We have a long-term strategic relationship with HFC. Our 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 will also work with HFC on logistic asset acquisitions in conjunction with HFC’s refinery acquisition strategies. Furthermore, we will continue to pursue third-party logistic asset acquisitions that are accretive to our unitholders and increase the diversity of our revenues.

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.

2012 Acquisition

UNEV Pipeline Interest Acquisition

On July 12, 2012, we acquired from HFC a 75% interest in UNEV. We paid consideration consisting of $260.9 million in cash and 2,059,800 of our common units. Also under the terms of the transaction, we issued to HFC a Class B unit comprising a noncontrolling equity interest in a wholly-owned subsidiary that entitles HFC to an interest in our share of annual UNEV earnings before interest, income taxes, depreciation, and amortization above $30 million beginning July 1, 2016 and ending in June 2032, subject to certain limitations. Contemporaneously with this transaction, HFC (our general partner) agreed to forego its right to incentive distributions of up to $1.25 million per quarter over twelve consecutive quarterly periods following the close of the transaction and up to an additional four quarters in certain circumstances. In connection with the transaction, we entered into 15-year throughput agreements with shippers containing minimum annual revenue commitments to us of $27 million.

Agreements with HFC and Alon

We serve HFC’s refineries under long-term pipeline and terminal, tankage and throughput agreements expiring from 2019 to 2026. Under these agreements, HFC agreed to transport, store and throughput volumes of refined product and crude oil on our pipelines and terminal, tankage and loading rack facilities that result in minimum annual payments to us. These minimum annual payments or revenues are subject to annual tariff rate adjustments on July 1, based on the Producer Price Index (“PPI”) or Federal Energy Regulatory Commission (“FERC”) index. As of December 31, 2014, these agreements with HFC will result in minimum payments to us of $231.6 million.

If HFC fails to meet its minimum volume commitments under the agreements in any quarter, it will be required to pay us in cash the amount of any shortfall by the last day of the month following the end of the quarter. Under certain of the agreements, a shortfall payment may be applied as a credit in the following four quarters after minimum obligations are met.

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We have a pipelines and terminals agreement with Alon expiring in 2020 under which Alon has agreed to transport on our pipelines and throughput through our terminals volumes of refined products that result in a minimum level of annual revenue that also is subject to annual tariff rate adjustments. Also, we 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 lease agreement expire beginning in 2018 through 2022. As of December 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.

Furthermore, if new laws or regulations that affect terminals or pipelines are enacted that require us to make substantial and unanticipated capital expenditures at the pipelines or terminals, we will have the right after we have made efforts to mitigate their effects to negotiate a monthly surcharge on HFC for the use of the terminals or to file for an increased tariff rate for use of the pipelines to cover HFC’s pro rata portion of the cost of complying with these laws or regulations including a reasonable rate of return. In such instances, we will negotiate in good faith with HFC to agree on the level of the monthly surcharge or increased tariff rate.

For additional information regarding our significant customers, see Note 9 to the Consolidated Financial Statements included in Item 8 of Part II of this Form 10-K.

Omnibus Agreement

Under certain provisions of an omnibus agreement we have with HFC (the “Omnibus Agreement”), we pay HFC an annual administrative fee ($2.3 million in 2014 and currently $2.4 million) for the provision by HFC of various general and administrative services to us. This fee includes expenses incurred by HFC to perform centralized corporate functions, such as executive management, legal, accounting, treasury, information technology and other corporate services, including the administration of employee benefit plans. 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, such as 401(k), pension and health insurance benefits, which are separately charged to us by HFC. We also reimburse HFC for direct expenses they incur on our behalf. In addition, we also pay for our own direct general and administrative costs, including costs relating to operating as a separate publicly held entity, such as costs for preparation of partners’ K-1 tax information, SEC filings, investor relations, directors’ compensation, directors’ and officers’ insurance and registrar and transfer agent fees.

Under HLS’s secondment arrangement with HFC, effective January 1, 2015, certain employees of HFC are seconded to HLS, the general partner of our general partner, to provide operational and maintenance services with respect to certain pipelines and terminals at the Cheyenne and El Dorado refineries, including routine operational and maintenance activities. During their period of secondment, the seconded employees are under the management and supervision of HLS. HLS reimburses HFC for our benefit for the cost of the seconded employees, including their wages and benefits, based on the percentage of the employee’s time spent working for HLS.

CAPITAL REQUIREMENTS

Our pipeline and terminalling operations are capital intensive, requiring investments to maintain, expand, upgrade or enhance existing operations and to meet environmental and operational regulations. Our capital requirements have consisted of, and are expected to continue to consist of, maintenance capital expenditures and expansion capital expenditures. “Maintenance capital expenditures” represent capital expenditures to replace partially or fully depreciated assets to maintain the operating capacity of existing assets. Maintenance capital expenditures include expenditures required to maintain equipment reliability, tankage and pipeline integrity, safety and to address environmental regulations. “Expansion capital expenditures” represent capital expenditures to expand the operating capacity of existing or new assets, whether through construction or acquisition. Expansion capital expenditures include expenditures to acquire assets, to grow our business and to expand existing facilities, such as projects that increase throughput capacity on our pipelines and in our terminals. Repair and maintenance expenses associated with existing assets that are minor in nature and do not extend the useful life of existing assets are charged to operating expenses as incurred.

Each year the board of directors of HLS, 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 2015 capital budget is comprised of $9.7 million for maintenance capital expenditures and $77.7 million for expansion capital expenditures. We expect the majority of the expansion capital budget to be invested in crude storage for HFC's El Dorado refinery, product distribution enhancements, new storage tanks, and an additional UNEV origin connection. In addition to our capital budget, we may spend funds periodically to perform capital upgrades or

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additions to our assets where a customer reimburses us for such costs. The upgrades or additions would generally benefit the customer over the remaining life of the related service agreements.

We substantially completed the expansion of our crude oil transportation system in southeastern New Mexico in the third quarter of 2014 in response to increased crude oil production in the area. The expansion provides 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 converted an existing refined products pipeline to crude oil service, constructed several new pipeline segments, expanded an existing pipeline, and built new truck unloading stations and crude storage capacity. Excluding the value of the existing pipeline converted, total capital expenditures were approximately $50 million. HFC has contracted to reimburse us for the increase over the original budget range of $35 million to $40 million 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 ("bpd") across the system.

UNEV completed a project to enhance its product terminal in Las Vegas, Nevada in the third quarter of 2014 with total capital expenditures of approximately $15 million.

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 have received engineering estimates for this potential project. Alternatively, we are evaluating the potential purchase of existing tanks.

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.

SAFETY AND MAINTENANCE

Many of our pipelines are subject to regulation by the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) of the DOT. PHMSA has promulgated regulations governing, among other things, maximum operating pressures, pipeline patrols and leak surveys, minimum depth requirements, and emergency procedures, as well as other matters intended to prevent accidents and failures. Additionally, PHMSA has promulgated regulations requiring pipeline operators to develop and implement integrity management programs for certain pipelines that, in the event of a pipeline leak or rupture, could affect “high consequence areas,” which are areas where a release could have the most significant adverse consequences, including high-population areas, certain drinking water sources and unusually sensitive ecological areas. We believe that our pipeline operations are in substantial compliance with requirements; however, due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, future compliance could result in increased costs.

In addition, many states have adopted regulations, similar to existing PHMSA regulations, for certain intrastate pipelines. For example, Texas has developed regulatory programs that largely parallel the federal regulatory scheme and impose additional requirements for certain pipelines.

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We perform preventive and normal maintenance on all of our pipeline systems and make repairs and replacements when necessary or appropriate. We also conduct routine and required inspections of our pipelines and other assets as required by regulations. We inject corrosion inhibitors into our mainlines to help control internal corrosion. External coatings and impressed current cathodic protection systems are used to protect against external corrosion. We regularly monitor, test and record the effectiveness of these corrosion-inhibiting systems. We monitor the structural integrity of covered segments of our pipeline systems through a program of periodic internal inspections using both “dent pigs” and electronic “smart pigs”, as well as hydrostatic testing that conforms to federal standards. We follow these inspections with a review of the data, and we make repairs as necessary to ensure the integrity of the pipeline. We have initiated a risk-based approach to prioritizing the pipeline segments for future smart pig runs or other approved integrity testing methods. We believe this approach will allow the pipelines that have the greatest risk potential to receive the highest priority in being scheduled for inspections or pressure tests for integrity. We believe our inspection process substantially complies with all applicable regulatory requirements. Nonetheless, the adoption of new or amended regulations or the reinterpretation of existing laws and regulations by PHMSA or the states that result in more stringent or costly pipeline integrity management or safety standards could possibly have a substantial effect on us and similarly situated midstream operators.

Maintenance facilities containing equipment for pipe repairs, spare parts, and trained response personnel are located along the pipelines. Employees participate in simulated spill deployment exercises on a regular basis. Also they participate in actual spill response boom deployment exercises in planned spill scenarios in accordance with Oil Pollution Act of 1990 requirements. We believe that all of our pipelines have been constructed and are maintained in all material respects in accordance with applicable federal and state laws, the regulations prescribed by PHMSA, standards prescribed by the American Petroleum Institute and accepted industry practice.

At our terminals, tanks designed for gasoline storage are equipped with internal or external floating roofs that minimize emissions and prevent potentially flammable vapor accumulation between fluid levels and the roof of the tank. Our terminal facilities have facility response plans, spill prevention and control plans, and other plans and programs to respond to emergencies.

Many of our terminal loading racks are protected with water deluge systems activated by either heat sensors or an emergency switch. Several of our terminals are also protected by foam systems that are activated in case of fire. All of our terminals are subject to participation in a comprehensive environmental management program to assure compliance with applicable air, solid waste, and wastewater regulations.

COMPETITION

As a result of our physical integration with HFC’s refineries, our contractual relationship with HFC under the Omnibus Agreement and the HFC pipelines and terminals, tankage and throughput agreements, we believe that we will not face significant competition for barrels of refined products transported from HFC’s refineries, particularly during the terms of our long-term transportation agreements with HFC expiring in 2019 through 2026. Additionally, under our throughput agreement with Alon expiring in 2020, we believe that we will not face significant competition for those barrels of refined products we transport from Alon’s Big Spring refinery.

However, we do face competition from other pipelines that may be able to supply the end-user markets of HFC or Alon with refined products on a more competitive basis. Additionally, if HFC’s wholesale customers reduced their purchases of refined products due to the increased availability of cheaper product from other suppliers or for other reasons, the volumes transported through our pipelines could be reduced, which, subject to the minimum revenue commitments, could cause a decrease in cash and revenues generated from our operations.

The petroleum refining business is highly competitive. Among HFC’s competitors are some of the world’s largest integrated petroleum companies, which have their own crude oil supplies and distribution and marketing systems. HFC competes with independent refiners as well. Competition in particular geographic areas is affected primarily by the amounts of refined products produced by refineries located in such areas and by the availability of refined products and the cost of transportation to such areas from refineries located outside those areas.

In addition, we face competition from trucks that deliver product in a number of areas we serve. Although their costs may not be competitive for longer hauls or large volume shipments, trucks compete effectively for incremental and marginal volumes in many areas we serve. The availability of truck transportation places some competitive constraints on us.

Historically, the significant majority of the throughput at our terminal facilities has come from HFC, with the exception of third-party receipts at the Spokane terminal, Alon volumes at El Paso, and the Abilene and Wichita Falls terminals that serve Alon’s Big Springs refinery.

Our ten refined product terminals compete with other independent terminal operators as well as integrated oil companies based on terminal location, price, versatility and services provided. Our competition primarily comes from integrated petroleum

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companies, refining and marketing companies, independent terminal companies and distribution companies with marketing and trading arms.

RATE REGULATION

Some of our existing pipelines are subject to rate regulation by the FERC under the Interstate Commerce Act. The Interstate Commerce Act requires that tariff rates for oil pipelines, a category that includes crude oil and petroleum product pipelines, be just and reasonable and not unduly discriminatory. The Interstate Commerce Act permits challenges to rates that are already on file and in effect by complaint. A successful challenge under a complaint may result in the complainant obtaining damages or reparations for up to two years prior to the date the complaint was filed. The Interstate Commerce Act also permits challenges to a proposed new or changed rate by a protest. A successful challenge under a protest may result in the protestant obtaining refunds or reparations from the date the proposed new or changed rate becomes effective. In either challenge process, the third party must be able to show it has a substantial economic interest in those rates to proceed. The FERC generally has not investigated interstate rates on its own initiative but will likely become a party to any proceedings when the rates receive either a complaint or a protest. However, the FERC is not prohibited from bringing an interstate rate under investigation without a third-party intervention.

While the FERC regulates the rates for interstate shipments on our refined product pipelines, the New Mexico Public Regulation Commission regulates the rates for intrastate shipments in New Mexico, the Texas Railroad Commission regulates the rates for intrastate shipments in Texas, the Oklahoma Corporation Commission regulates the rates for intrastate shipments in Oklahoma and the Idaho Public Utilities Commission regulates the rates for intrastate shipments in Idaho. State commissions have generally not been aggressive in regulating common carrier pipelines and generally have not investigated the rates or practices of petroleum pipelines in the absence of shipper complaints, and we do not believe the intrastate tariffs now in effect are likely to be challenged. However, a state regulatory commission could investigate our rates if such a challenge were filed.

ENVIRONMENTAL REGULATION AND REMEDIATION

Our operation of pipelines, terminals, and associated facilities in connection with the storage and transportation of refined products 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. Although these laws and regulations affect our maintenance capital expenditures and net income, we believe that they do not affect our competitive position in that the operations of our competitors are similarly affected. We believe that our operations are in substantial compliance with applicable environmental laws and regulations. However, these laws and regulations, and the interpretation or enforcement thereof, are subject to frequent change by regulatory authorities, and we are unable to predict the ongoing cost to us of complying with these laws and regulations or the future impact of these laws and regulations on our operations. Violation of environmental laws, regulations, and permits can result in the imposition of significant administrative, civil and criminal penalties, injunctions, and construction bans or delays. A discharge of hydrocarbons or hazardous substances into the environment could, to the extent the event is not insured, subject us to substantial expense, including both the cost to comply with applicable laws and regulations and claims made by employees, neighboring landowners and other third parties for personal injury and property damage.

Contamination resulting from spills of refined products and crude oil is not unusual within the petroleum pipeline industry. Historic spills along our existing pipelines and terminals as a result of past operations have resulted in contamination of the environment, including soils and groundwater. Site conditions, including soils and groundwater, are being evaluated at a few of our properties where operations may have resulted in releases of hydrocarbons and other wastes, none of which we believe will have a significant effect on our operations since the remediation of such releases would be covered under environmental indemnification agreements. For example, 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. In addition, under the Omnibus Agreement and certain transportation agreements and purchase agreements with HFC, HFC has agreed to indemnify us, subject to certain monetary and time limitations, for environmental noncompliance and remediation liabilities associated with certain assets transferred to us from HFC and occurring or existing prior to the date of such transfers. There are environmental remediation projects 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 for future remediation activities retained by HFC. Additionally, as of December 31, 2014, we have an accrual of $5.2 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.

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We may experience future releases into the environment from our pipelines and terminals or discover historical releases that were previously unidentified or not assessed. Although we maintain an extensive inspection and audit program designed, as applicable, to prevent, detect and address these releases promptly, damages and liabilities incurred due to any future environmental releases from our assets have the potential to substantially affect our business.

EMPLOYEES

Neither we nor our general partner has employees. Direct support for our operations is provided by HLS, which utilizes 273 people employed by HFC dedicated to performing services for us. We reimburse HFC for direct expenses that HFC or its affiliates incurs on our behalf for these employees. HFC considers its employee relations to be good.

Under HLS’s secondment arrangement with HFC, certain employees of HFC are seconded to HLS to provide operational and maintenance services for certain of our pipelines and tankage assets at the El Dorado and Cheyenne refineries, and HLS reimburses HFC for its prorated portion of the wages, benefits, and other costs of these employees for our benefit.

Several of the seconded employees at the El Dorado and Cheyenne refineries are represented by the United Steelworkers Union.  In early February 2015, HFC received communications from the United Steelworkers Union representing employees at the El Dorado refinery of its intention to commence a work stoppage in early May 2015 and could receive a similar communication from the United Steelworkers Union representing employees at the Cheyenne refinery.  HFC has plans allowing for the continued operations of both refineries in the event the union does commence a work stoppage and believes such plans are adequate to allow continued operations of both refineries as well as support for our operations provided by the seconded employees.

Item 1A. Risk Factors

Investing in us involves a degree of risk, including the risks described below. Our operating results have been, and will continue to be, affected by a wide variety of risk factors, many of which are beyond our control, that could have adverse effects on profitability during any particular period. You should consider the following risk factors carefully together with all of the other information included in this Annual Report on Form 10-K, including the financial statements and related notes, when deciding to invest in us. 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 operations. If any of the following risks were to actually occur, our business, financial condition, results of operations or treatment of unitholders could be materially and adversely affected.

The headings provided in this Item 1A. are for convenience and reference purposes only and shall not affect or limit the extent or interpretation of the risk factors.

RISKS RELATED TO OUR BUSINESS

If we are unable to generate sufficient cash flow, our ability to pay quarterly distributions to our common unitholders at current levels or to increase our quarterly distributions in the future could be impaired materially.

Our ability to pay quarterly distributions depends primarily on cash flow (including cash flow from operations, financial reserves and credit facilities) and not solely on profitability, which is affected by non-cash items. As a result, we may pay cash distributions during periods of losses and may be unable to pay cash distributions during periods of income. Our ability to generate sufficient cash from operations is largely dependent on our ability to manage our business successfully which may also be affected by economic, financial, competitive, regulatory, and other factors that are beyond our control. Because the cash we generate from operations will fluctuate from quarter to quarter, quarterly distributions may also fluctuate from quarter to quarter.

We depend on HFC and particularly its Navajo refinery for a majority of our revenues; if those revenues were significantly reduced or if HFC's financial condition materially deteriorated, there would be a material adverse effect on our results of operations.

For the year ended December 31, 2014, HFC accounted for 79% of the revenues of our petroleum product and crude pipelines and 89% of the revenues of our terminals, tankage, and truck loading racks. We expect to continue to derive a majority of our revenues from HFC for the foreseeable future. If HFC satisfies only its minimum obligations under the long-term pipeline and terminal, tankage and throughput agreements that it has with us or is unable to meet its minimum annual payment commitment for any reason, including due to prolonged downtime or a shutdown at HFC's refineries, our revenues and cash flow would decline.

Any significant reduction in production at the Navajo refinery could reduce throughput in our pipelines and terminals, resulting in materially lower levels of revenues and cash flow for the duration of the shutdown. For the year ended December 31, 2014, production from the Navajo refinery accounted for 79.0% of the throughput volumes transported by our refined product and crude

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pipelines. The Navajo refinery also received 98% of the petroleum products shipped on our New Mexico intermediate pipelines. Operations at any of HFC's refineries could be partially or completely shut down, temporarily or permanently, as the result of:

• competition from other refineries and pipelines that may be able to supply the refinery's end-user markets on a more cost-effective basis;

• operational problems such as catastrophic events at the refinery, labor difficulties, environmental proceedings or other litigation that cause a stoppage of all or a portion of the operations at the refinery;

• planned maintenance or capital projects;

• increasingly stringent environmental laws and regulations, such as the U.S. Environmental Protection Agency's gasoline and diesel sulfur control requirements that limit the concentration of sulfur in motor gasoline and diesel fuel for both on-road and non-road usage as well as various state and federal emission requirements that may affect the refinery itself and potential future climate change regulations;

• an inability to obtain crude oil for the refinery at competitive prices; or

• a general reduction in demand for refined products in the area due to:

◦ a local or national recession or other adverse economic condition that results in lower spending by businesses and consumers on gasoline and diesel fuel;

◦ higher gasoline prices due to higher crude oil costs, higher taxes or stricter environmental laws or regulations; or

◦ a shift by consumers to more fuel-efficient or alternative fuel vehicles or an increase in fuel economy, whether as a result of technological advances by manufacturers, legislation either mandating or encouraging higher fuel economy or the use of alternative fuel or otherwise. 

The effect on us of any shutdown would depend on the length of the shutdown and the extent of the refinery operations affected by the shutdown. We have no control over the factors that may lead to a shutdown or the measures HFC may take in response to a shutdown. HFC makes all decisions at each of its refineries concerning levels of production, regulatory compliance, refinery turnarounds (planned shutdowns of individual process units within the refinery to perform major maintenance activities), labor relations, environmental remediation, emission control and capital expenditures and is responsible for all related costs. HFC is under no contractual obligation to us to maintain operations at its refineries.

Furthermore, HFC's obligations under the long-term pipeline and terminal, tankage and throughput agreements with us would be temporarily suspended during the occurrence of a force majeure event that renders performance impossible with respect to an asset for at least 30 days. If such an event were to continue for a year, we or HFC could terminate the agreements. The occurrence of any of these events could reduce our revenues and cash flows.

We depend on Alon and particularly its Big Spring refinery for a portion of our revenues; if those revenues were significantly reduced, there could be a material adverse effect on our results of operations.

For the year ended December 31, 2014, Alon accounted for 10% of the combined revenues of our petroleum product and crude pipelines and of our terminals and truck loading racks, including revenues we received from Alon under a capacity lease agreement. If Alon satisfies only its minimum obligations under the long-term pipeline and terminal, tankage and throughput agreements that it has with us or is unable to meet its minimum annual payment commitment for any reason, including due to prolonged downtime or a shutdown at Alon’s refineries, our revenues and cash flow would decline.

A decline in production at Alon's Big Spring refinery could reduce materially the volume of refined products we transport and terminal for Alon and, as a result, our revenues could be materially adversely affected. The Big Spring refinery could partially or completely shut down its operations, temporarily or permanently, due to factors affecting its ability to produce refined products or for planned maintenance or capital projects. Such factors would include the factors discussed above under the discussion of risk with respect to the Navajo refinery.

The effect on us of any shutdown depends on the length of the shutdown and the extent of the refinery operations affected. We have no control over the factors that may lead to a shutdown or the measures Alon may take in response to a shutdown. Alon makes all decisions and is responsible for all costs at the Big Spring refinery concerning levels of production, regulatory compliance, refinery turnarounds, labor relations, environmental remediation, emission control and capital expenditures.

In addition, under our throughput agreement with Alon, if we are unable to transport or terminal refined products that Alon is prepared to ship, then Alon has the right to reduce its minimum volume commitment to us during the period of interruption. If a force majeure event occurs, we or Alon could terminate the Alon pipelines and terminals agreement after the expiration of certain time periods. The occurrence of any of these events could reduce our revenues and cash flows.

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Due to our lack of asset diversification, adverse developments in our businesses could materially and adversely affect our financial condition, results of operations, or cash flows.

We rely exclusively on the revenues generated from our business. Due to our lack of asset diversification, especially a large concentration of pipeline assets serving the Navajo refinery, an adverse development in our business could have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets.

Our leverage may limit our ability to borrow additional funds, comply with the terms of our indebtedness or capitalize on business opportunities.

As of December 31, 2014, the principal amount of our total outstanding debt was $871.0 million. Our results of operations, cash flows and financial position could be adversely affected by significant increases in interest rates above current levels. Various limitations in our Credit Agreement and the indenture for our 6.50% senior notes due 2020 (the “6.5% Senior Notes”) may reduce our ability to incur additional debt, to engage in some transactions and to capitalize on business opportunities. Any subsequent refinancing of our current indebtedness or any new indebtedness could have similar or greater restrictions.

Our leverage could have important consequences. We require substantial cash flow to meet our payment obligations with respect to our indebtedness. Our ability to make scheduled payments, to refinance our obligations with respect to our indebtedness or our ability to obtain additional financing in the future will depend on our financial and operating performance, which, in turn, is subject to then-current economic conditions and to financial, business and other factors. We believe that we will have sufficient cash flow from operations and available borrowings under our Credit Agreement to service our indebtedness. However, a significant downturn in our business or other development adversely affecting our cash flow could materially impair our ability to service our indebtedness. If our cash flow and capital resources are insufficient to fund our debt service obligations, we may be forced to refinance all or a portion of our debt or sell assets. We cannot guarantee that we would be able to refinance our existing indebtedness at maturity or otherwise or sell assets on terms that are commercially reasonable.

The instruments governing our debt contain restrictive covenants that may prevent us from engaging in certain beneficial transactions. The agreements governing our debt generally require us to comply with various affirmative and negative covenants including the maintenance of certain financial ratios and restrictions on incurring additional debt, entering into mergers, consolidations and sales of assets, making investments and granting liens. Additionally, our purchase and contribution agreements with HFC with respect to the intermediate pipelines acquired in 2005 and the crude pipelines and tankage assets acquired in 2008, restrict us from selling these pipelines and terminals acquired from HFC. Under these agreements, we are restricted from prepaying borrowings and long-term debt to outstanding balances below $206 million prior to March 1, 2015 and $171 million prior to March 1, 2018, subject to certain limited exceptions. Our leverage may affect adversely our ability to fund future working capital, capital expenditures and other general partnership requirements, future acquisitions, construction or development activities, or to otherwise realize fully the value of our assets and opportunities because of the need to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness or to comply with any restrictive terms of our indebtedness. Our leverage also may make our results of operations more susceptible to adverse economic and industry conditions by limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate and may place us at a competitive disadvantage as compared to our competitors that have less debt.

We may not be able to obtain funding on acceptable terms or at all because of volatility and uncertainty in the credit and capital markets. This may hinder or prevent us from meeting our future capital needs.

The domestic and global financial markets and economic conditions are disrupted and volatile from time to time due to a variety of factors, including low consumer confidence, high unemployment, geoeconomic and geopolitical issues, weak economic conditions and uncertainty in the financial services sector. In addition, the fixed-income markets have experienced periods of extreme volatility, which negatively impacted market liquidity conditions. As a result, the cost of raising money in the debt and equity capital markets has increased substantially at times while the availability of funds from these markets diminished significantly. In particular, as a result of concerns about the stability of financial markets generally and the solvency of lending counterparties specifically, the cost of obtaining money from the credit markets may increase as many lenders and institutional investors increase interest rates, enact tighter lending standards, refuse to refinance existing debt on similar terms or at all and reduce, or in some cases cease, to provide funding to borrowers. In addition, lending counterparties under existing revolving credit facilities and other debt instruments may be unwilling or unable to meet their funding obligations.

Due to these factors, we cannot be certain that new debt or equity financing will be available on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to:

• meet our obligations as they come due;

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• execute our growth strategy;

• complete future acquisitions or construction projects;

• take advantage of other business opportunities; or

• respond to competitive pressures.

Any of the above could have a material adverse effect on our revenues and results of operations.

We may not be able to fully execute our growth strategy if we encounter illiquid capital markets or increased competition for investment opportunities, if our assumptions concerning population growth are inaccurate, or if an agreement cannot be reached with HFC for the acquisition of assets on which we have a right of first offer.

Our strategy contemplates growth through the development and acquisition of crude, intermediate and refined products transportation and storage assets while maintaining a strong balance sheet. This strategy includes constructing and acquiring additional assets and businesses, either from HFC or third parties, to enhance our ability to compete effectively and diversifying our asset portfolio, thereby providing more stable cash flow. We regularly consider and enter into discussions regarding, and are currently contemplating and/or pursuing, potential joint ventures, stand-alone projects or other transactions that we believe will present opportunities to realize synergies, expand our role in our chosen businesses and increase our market position.

We will require substantial new capital to finance the future development and acquisition of assets and businesses. Any limitations on our access to capital will impair our ability to execute this strategy. If the cost of such capital becomes too expensive, or if the development or acquisition opportunities are on terms that do not allow us to obtain appropriate financing, our ability to develop or acquire accretive assets will be limited. We may not be able to raise the necessary funds on satisfactory terms, if at all. The primary factors that influence our cost of equity include market conditions, fees we pay to underwriters and other offering costs, which include amounts we pay for legal and accounting services. The primary factors influencing our cost of borrowing include interest rates, credit spreads, covenants, underwriting or loan origination fees and similar charges we pay to lenders.

In addition, we experience competition for the types of assets and businesses we have historically purchased or acquired. High competition, particularly for a limited pool of assets, may result in higher, less attractive asset prices, and therefore, we may lose to more competitive bidders. Such occurrences limit our ability to execute our growth strategy, which may materially adversely affect our ability to maintain or pay higher distributions in the future.

Our growth strategy also depends upon:

• the accuracy of our assumptions about growth in the markets that we currently serve or have plans to serve in the Southwestern, Rocky Mountain and Mid-Continent regions of the United States;

• HFC's willingness and ability to capture a share of additional demand in its existing markets; and

• HFC's willingness and ability to identify and penetrate new markets in the Southwestern, Rocky Mountain and Mid-Continent regions of the United States.

If our assumptions about increased market demand prove incorrect, HFC may not have any incentive to increase refinery capacity and production or shift additional throughput to our pipelines, which would adversely affect our growth strategy.

Our Omnibus Agreement with HFC provides us with a right of first offer on certain of HFC’s existing or acquired logistics assets. The consummation and timing of any future acquisitions of these assets will depend upon, among other things, our ability to negotiate acceptable purchase agreements and commercial agreements with respect to the assets and our ability to obtain financing on acceptable terms. We can offer no assurance that we will be able to successfully consummate any future acquisitions pursuant to our right of first offer. In addition, certain of the assets covered by our right of first offer may require substantial capital expenditures in order to maintain compliance with applicable regulatory requirements or otherwise make them suitable for our commercial needs. For these or a variety of other reasons, we may decide not to exercise our right of first offer if and when any assets are offered for sale, and our decision will not be subject to unitholder approval. In addition, our right of first offer may be terminated upon a change of control of HFC.

We are exposed to the credit risks and certain other risks, of our key customers, vendors, and other counterparties.

We are subject to risks of loss resulting from nonpayment or nonperformance by our customers, vendors or other counterparties. We derive a significant portion of our revenues from contracts with key customers, including HFC and Alon under their respective pipelines and terminals, tankage and throughput agreements. To the extent that our customers may be unable to meet the specifications of their customers, we would be adversely affected unless we were able to make comparably profitable arrangements with other customers.

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Mergers among our existing customers could provide strong economic incentives for the combined entities to use systems other than ours, and we could experience difficulty in replacing lost volumes and revenues. Because a significant portion of our operating costs are fixed, a reduction in volumes would result not only in a reduction of revenues, but also a decline in net income and cash flow of a similar magnitude, which would reduce our ability to meet our financial obligations and make distributions to unitholders.

If any of our key customers default on their obligations to us, our financial results could be adversely affected. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks. In addition, nonperformance by vendors who have committed to provide us with products or services could result in higher costs or interfere with our ability to successfully conduct our business.

Any substantial increase in the nonpayment and/or nonperformance by our customers or vendors could have a material adverse effect on our results of operations and cash flows.

In addition, in connection with the acquisition of certain of our assets, we have entered into agreements pursuant to which various counterparties, including HFC, have agreed to indemnify us, subject to certain limitations, for:

• certain pre-closing environmental liabilities discovered within specified time periods after the date of the applicable acquisition;

• certain matters arising from the pre-closing ownership and operation of assets; and

• ongoing remediation related to the assets.

Our business, results of operation, cash flows and our ability to make cash distributions to our unitholders could be adversely affected in the future if third parties fail to satisfy an indemnification obligation owed to us.

Competition from other pipelines that may be able to supply our shippers' customers with refined products at a lower price could cause us to reduce our rates or could reduce our revenues.

We and our shippers could face increased competition if other pipelines are able to supply our shippers' end-user markets competitively with refined products. For example, increased supplies of refined product delivered by Kinder Morgan's El Paso to Phoenix pipeline could result in additional downward pressure on wholesale-refined product prices and refined product margins in El Paso and related markets. Additionally, further increases in products from Gulf Coast refiners entering the El Paso and Arizona markets on this pipeline and a resulting increase in the demand for shipping product on the interconnecting common carrier pipelines could cause a decline in the demand for refined product from HFC and/or Alon. This could reduce our opportunity to earn revenues from HFC and Alon in excess of their minimum volume commitment obligations.

An additional factor that could affect some of HFC's and Alon's markets is excess pipeline capacity from the West Coast into our shippers' Arizona markets. Additional increases in shipments of refined products from the West Coast into our shippers' Arizona markets could result in additional downward pressure on refined product prices that, if sustained over the long term, could influence product shipments by HFC and Alon to these markets.

A material decrease in the supply, or a material increase in the price, of crude oil available to HFC's and Alon's refineries, and a corresponding decrease in demand for refined products in the markets served by our pipelines and terminals, could reduce our revenues materially.

The volume of refined products we transport in our refined product pipelines depends on the level of production of refined products from HFC's and Alon's refineries, which, in turn, depends on the availability of attractively-priced crude oil produced in the areas accessible to those refineries. In order to maintain or increase production levels at their refineries, our shippers must continually contract for new crude oil supplies. A material decrease in crude oil production from the fields that supply their refineries, as a result of depressed commodity prices, decreased demand, lack of drilling activity, natural production declines or otherwise, could result in a decline in the volume of crude oil our shippers refine, absent the availability of transported crude oil to offset such declines. Such an event would result in an overall decline in volumes of refined products transported through our pipelines and therefore a corresponding reduction in our cash flow. In addition, the future growth of our shippers' operations will depend in part upon whether our shippers can contract for additional supplies of crude oil at a greater rate than the rate of natural decline in their currently connected supplies.

Fluctuations in crude oil prices can greatly affect production rates and investments by third parties in the development of new oil reserves. Drilling activity generally decreases as crude oil prices decrease. We and our shippers have no control over producers or their production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for

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hydrocarbons, geological considerations, governmental regulation and the availability and cost of capital, or over the level of drilling activity in the areas of operations, the amount of reserves underlying the wells and the rate at which production from a well will decline. Similarly, a material increase in the price of crude oil supplied to our shippers' refineries without an increase in the market value of the products produced by the refineries, either temporary or permanent, which causes a reduction in the production of refined products at the refineries, would cause a reduction in the volumes of refined products we transport, and our cash flow could be adversely affected.

Finally, our business depends in large part on the demand for the various petroleum products we gather, transport and store in the markets we serve. Reductions in that demand adversely affect our business. Market demand varies based upon the different end uses of the petroleum products we gather, transport and store. We cannot predict the impact of future fuel conservation measures, alternate fuel requirements, government regulation, technological advances in fuel economy and energy-generation devices, exploration and production activities, and actions by foreign nations, any of which could reduce the demand for the petroleum products in the areas we serve.

We may not be able to retain existing customers or acquire new customers.

The renewal or replacement of existing contracts with our customers at rates sufficient to maintain attractive revenues and cash flows depends on a number of factors outside our control, including competition from other pipelines and the demand for refined products in the markets that we serve. Our long-term pipeline and terminal, tankage and throughput agreements with HFC and Alon expire beginning in 2019 through 2026.

Our operations are subject to evolving federal, state and local environmental, health and safety laws and regulations, and potential liabilities that could affect our operations and adversely affect our performance.

Environmental laws and regulations have raised operating costs for the oil and refined products industry, and compliance with such laws and regulations may cause us, and the HFC and Alon refineries that we support, to incur potentially material capital expenditures associated with the construction, maintenance, and upgrading of equipment and facilities. We may also be required to address conditions discovered in the future that require environmental response actions or remediation. Future environmental, health and safety requirements (or changed interpretations of existing requirements) may impose more stringent requirements on our assets and operations and require us to incur potentially material expenditures to ensure our continued compliance.

Currently, various legislative and regulatory measures to address greenhouse gas emissions (including carbon dioxide, methane and other gases) are in various phases of discussion or implementation. These include requirements that HFC's and Alon's refineries report emissions of greenhouse gases to the EPA, and proposed federal, state, and regional initiatives that require (or could require) us, HFC and Alon to reduce greenhouse gas emissions from our facilities. Requiring reductions in greenhouse gas emissions could cause us to incur substantial costs to (i) operate and maintain our facilities, (ii) install new emission controls at our facilities and (iii) administer and manage any greenhouse gas emissions programs, including the acquisition or maintenance of emission credits or allowances. These requirements may affect HFC's and Alon's refinery operations and have an indirect adverse effect on our business, financial condition and results of our operations.

Requiring a reduction in greenhouse gas emissions and the increased use of renewable fuels could also decrease demand for refined products, which could have an indirect, but material, adverse effect on our business, financial condition and results of operations. For example, in 2010, the EPA promulgated a rule establishing greenhouse gas emission standards for new-model passenger cars, light-duty trucks, and medium-duty passenger vehicles. Also in 2010, the EPA promulgated a rule establishing greenhouse gas emission thresholds for the permitting of certain stationary sources, which could require greenhouse emission controls for those sources. Discussions are underway for proposed additional regulations in both of these areas. For example, consistent with its Climate Action Plan announced in 2014, the Obama Administration is expected to release a series of new regulations affecting the oil and gas industry in 2015, including regulations limiting methane emissions from certain new and modified oil and gas facilities. These requirements could have an indirect adverse effect on our business due to reduced demand for crude oil and refined products, and a direct adverse effect on our business from increased regulation of our facilities.

We may incur significant costs and liabilities resulting from performance of pipeline integrity programs and related repairs.

PHMSA has promulgated regulations requiring pipeline operators to develop and implement integrity management programs for certain pipelines that, in the event of a pipeline leak or rupture could affect “high consequence areas,” which are areas where a release could have the most significant adverse consequences, including high-population areas, certain drinking water sources and unusually sensitive ecological areas. These regulations require operators of covered pipelines to perform a variety of heightened inspection, analysis, prevention and repair activities. A number of states have adopted regulations similar to existing PHMSA regulations for certain pipelines.

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Moreover, changes to pipeline safety laws by Congress and regulations by PHMSA or states that result in more stringent or costly safety standards could possibly have a substantial effect on us and similarly situated midstream operators.

Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation.

Among other things, the 2011 Amendments to the Pipeline Safety Act direct the Secretary of Transportation to study, and where appropriate based on the results and statutory factors, promulgate regulations relating to expanded integrity management requirements, automatic or remote-controlled valves, leak detection, and other requirements. The 2011 Amendments also increased the maximum penalty for violation of pipeline safety regulations from $100,000 to $200,000 per violation per day and also from $1 million to $2 million for a related series of violations. The safety enhancement requirements and other provisions of the 2011 Amendments as well as any implementation of PHMSA regulations thereunder, reinterpretation of existing laws or regulations, or any issuance or reinterpretation of guidance by PHMSA or any state agencies with respect to the 2011 Amendments could require us to install new or modified safety controls, pursue additional capital projects or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could have a material adverse effect on our results of operations or financial position. For example, PHMSA is expected to issue new and expanded proposed regulations in 2015 applicable to pipeline operators, including provisions that may expand to the integrity management requirements to additional pipeline mileage. Such new and expanded requirements may result in additional capital costs, possible operational delays and increased costs of operation that, in some instances, may be significant.

Increases in interest rates could adversely affect our business.

We use both fixed and variable rate debt, and we are exposed to market risk due to the floating interest rates on our credit facility. From time to time we use interest rate derivatives to hedge interest obligations on specific debt. In addition, interest rates on future debt offerings could be higher, causing our financing costs to increase accordingly. Our results of operations, cash flows and financial position could be adversely affected by significant increases in interest rates above current levels.

We may be subject to information technology system failures, network disruptions and breaches in data security.

Information technology system failures, network disruptions (whether intentional by a third party or due to natural disaster), breaches of network or data security, or disruption or failure of the network system used to monitor and control pipeline operations could disrupt our operations by impeding our processing of transactions, our ability to protect customer or company information and our financial reporting. Our computer systems, including our back-up systems, could be damaged or interrupted by power outages, computer and telecommunications failures, computer viruses, internal or external security breaches, events such as fires, earthquakes, floods, tornadoes and hurricanes, and/or errors by our employees. Although we have taken steps to address these concerns by implementing sophisticated network security and internal control measures, a system failure or data security breach could have a material adverse effect on our financial condition and results of operations.

Our operations are subject to federal, state, and local laws and regulations, and permit and authorization requirements, relating to product quality specifications, environmental protection and operational safety that could require us to make substantial expenditures.

Our pipelines and terminals, tankage and loading rack operations are subject to increasingly strict environmental and safety laws and regulations. Also, the transportation and storage of refined products produces a risk that refined products and other hydrocarbons may be suddenly or gradually released into the environment, potentially causing substantial expenditures for a response action, significant government penalties, liability to government agencies for natural resources damages, personal injury or property damages to private parties and significant business interruption. We own or lease a number of properties that have been used to store or distribute refined products for many years. Many of these properties also have been operated by third parties whose handling, disposal, or release of hydrocarbons and other wastes were not under our control. If we were to incur a significant liability pursuant to environmental laws or regulations, it could have a material adverse effect on us. Also we are subject to the requirements of the Federal Occupational Safety and Health Administration (“OSHA”), and comparable state statutes. Any violation of OSHA could impose substantial costs on us.

Petroleum products that we store and transport are sold by our customers for consumption into the public market. Various federal, state and local agencies have the authority to prescribe specific product quality specifications of refined products. Changes in product quality specifications or blending requirements could reduce our throughput volume, require us to incur additional handling costs or require capital expenditures. For example, different product specifications for different markets impact the fungibility of

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the products in our system and could require the construction of additional storage. If we are unable to recover these costs through increased revenues, our cash flows and ability to pay cash distributions could be adversely affected. In addition, changes in the product quality of the products we receive on our petroleum products pipeline system could reduce or eliminate our ability to blend products.

Our operations require numerous permits and authorizations under various laws and regulations, including environmental and health and safety laws and regulations. These authorizations and permits are subject to revocation, renewal or modification and can require operational changes that may involve significant costs to limit impacts or potential impacts on the environment and/or health and safety. A violation of these authorization or permit conditions or other legal or regulatory requirements could result in substantial fines, criminal sanctions, permit revocations and injunctions prohibiting our operations. In addition, major modifications of our operations could require modifications to our existing permits or expensive upgrades to our existing pollution control equipment that could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.

Our operations are subject to operational hazards and unforeseen interruptions such as natural disasters, adverse weather, accidents, fires, explosions, hazardous materials releases, mechanical failures and other events beyond our control. These events might result in a loss of life, loss of equipment or destruction of property, injury, or extensive property damage, as well as a curtailment or interruption in our operations. In addition, third-party damage, mechanical malfunctions, undetected leaks in pipelines, faulty measurement or other errors may result in significant costs or lost revenues.

We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates and exclusions from coverage may limit our ability to recover the amount of the full loss in all situations. As a result of market conditions, premiums and deductibles for certain of our insurance policies could increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position. Because of our distribution policy, we do not have the same flexibility as other legal entities to accumulate cash to protect against underinsured or uninsured losses.

There can be no assurance that insurance will cover all damages and losses resulting from these types of hazards. We are not fully insured against all risks incident to our business. We are not insured against all environmental accidents that might occur, other than some coverage for third party sudden and accidental claims. Our property insurance includes business interruption coverage for lost profit arising from physical damage to our facilities. If a significant accident or event occurs that is not fully insured, our operations could be temporarily or permanently impaired, and our liabilities and expenses could be significant.

Any reduction in the capacity of, or the allocations to, our shippers on interconnecting, third-party pipelines could cause a reduction of volumes transported in our pipelines and through our terminals.

HFC, Alon and the other users of our pipelines and terminals are dependent upon connections to third-party pipelines to receive and deliver crude oil and refined products. Any reduction of capacities of these interconnecting pipelines due to testing, line repair, reduced operating pressures, or other causes could result in reduced volumes transported in our pipelines or through our terminals. Similarly, if additional shippers begin transporting volumes of refined products over interconnecting pipelines, the allocations to existing shippers in these pipelines would be reduced, which could also reduce volumes transported in our pipelines or through our terminals.

We could be subject to damages based on claims brought against us by our customers or lose customers as a result of the failure of products we distribute to meet certain quality specifications.

A significant portion of our operating responsibility on refined product pipelines is to ensure the quality and purity of the products loaded at our loading racks. If our quality control measures fail, off-specification product could be sent out to public gasoline stations. This type of incident could result in liability claims regarding damages caused by the off-specification fuel or could impact our ability to retain existing customers or to acquire new customers, any of which could have a material adverse impact on our results of operations and cash flows.

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Growing our business by constructing new pipelines and terminals, or expanding existing ones, subjects us to construction risks.

One of the ways we may grow our business is through the construction of new pipelines and terminals or the expansion of existing ones. The construction of a new pipeline or the expansion of an existing pipeline, by adding horsepower or pump stations or by adding a second pipeline along an existing pipeline, involves numerous regulatory, environmental, political, and legal uncertainties, most of which are beyond our control. These projects may not be completed on schedule (or at all) or at the budgeted cost. In addition, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new pipeline, the construction will occur over an extended period of time and we will not receive any material increases in revenues until after completion of the project. Moreover, we may construct facilities to capture anticipated future growth in demand for refined products in a region in which such growth does not materialize. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition.

Rate regulation, changes to rate-making rules, or a successful challenge to the rates we charge may reduce our revenues and the amount of cash we generate.

The FERC regulates the tariff rates for interstate movements and state regulatory authorities regulate the tariff rates for intrastate movements on our pipeline systems. The regulatory agencies that regulate our systems periodically implement new rules, regulations and terms and conditions of services subject to their jurisdiction. New initiatives or orders may adversely affect the rates charged for our services.

The primary rate-making methodology of the FERC is price indexing. We use this methodology in all of our interstate markets. The indexing method allows a pipeline to increase its rates based on a percentage change in the producer price index for finished goods. If the index falls, we will be required to reduce our rates that are based on the FERC's price indexing methodology if they exceed the new maximum allowable rate. If the FERC price indexing methodology permits a rate increase that is not large enough to fully reflect actual increases in our costs, we may need to file for a rate increase using an alternative method with a much higher burden of proof and without the guarantee of success. These FERC rate-making methodologies may limit our ability to set rates based on our true costs or may delay the use of rates that reflect increased costs. Any of the foregoing would adversely affect our revenues and cash flow.

If a party with an economic interest were to file either a protest of our proposal for increased rates or a complaint against our existing tariff rates, or the FERC were to initiate an investigation of our existing rates, then our rates could be subject to detailed review. If our proposed rate increases were found to be in excess of levels justified by our cost of service, the FERC could order us to reduce our rates, and to refund the amount by which the rate increases were determined to be excessive, plus interest. If our existing rates were found to be in excess of our cost of services, we could be ordered to refund the excess we collected for up to two years prior to the date of the filing of the complaint challenging the rates, and we could be ordered to reduce our rates prospectively. In addition, a state commission also could investigate our intrastate rates or our terms and conditions of service on its own initiative or at the urging of a shipper or other interested party. If a state commission found that our rates exceeded levels justified by our cost of service, the state commission could order us to reduce our rates. Any such reductions may result in lower revenues and cash flows if additional volumes and/or capacity are unavailable to offset such rate reductions.

HFC and Alon have agreed not to challenge, or to cause others to challenge or assist others in challenging, our tariff rates in effect during the terms of their respective pipelines and terminals agreements; however, other current or future shippers may still challenge our tariff rates.

Terrorist attacks, and the threat of terrorist attacks or domestic vandalism, have resulted in increased costs to our business. Continued global hostilities or other sustained military campaigns may adversely impact our results of operations.

The long-term impact of terrorist attacks, such as the attacks that occurred on September 11, 2001, and the threat of future terrorist attacks, on the energy transportation industry in general, and on us in particular, is unknown. Increased security measures taken by us as a precaution against possible terrorist attacks or vandalism have resulted in increased costs to our business. Uncertainty surrounding continued global hostilities or other sustained military campaigns, and the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror, may affect our operations in unpredictable ways, including disruptions of crude oil supplies and markets for refined products.

Changes in the insurance markets attributable to terrorist attacks could make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance

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coverage. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital including our ability to repay or refinance debt.

Adverse changes in our and/or our general partner's credit ratings and risk profile may negatively affect us.

Our ability to access capital markets is important to our ability to operate our business. Regional and national economic conditions, increased scrutiny of the energy industry and regulatory changes, as well as changes in our economic performance, could result in credit agencies reexamining our credit rating. While credit ratings reflect the opinions of the credit agencies issuing such ratings and may not necessarily reflect actual performance, a downgrade in our credit rating could restrict or discontinue our ability to access capital markets at attractive rates, could result in an increase in our borrowing costs and a reduction in our level of capital expenditures and could impact our future earnings and cash flows.

We are in compliance with all covenants or other requirements set forth in our Credit Agreement. Further, we do not have any rating downgrade triggers that would automatically accelerate the maturity dates of any debt. However, a downgrade in our credit rating could affect adversely our ability to borrow on, renew existing, or obtain access to new financing arrangements and would increase the cost of such financing arrangements.

The credit and business risk profiles of our general partner, and of HFC as the indirect owner of our general partner, may be factors in credit evaluations of us as a master limited partnership due to the significant influence of our general partner and its indirect owner over our business activities, including our cash distribution acquisition strategy and business risk profile. Another factor that may be considered is the financial condition of our general partner and its owners, including the degree of their financial leverage and their dependence on cash flow from the partnership to service their indebtedness.

We may be unsuccessful in integrating the operations of the assets we have acquired or may acquire with our operations, and in realizing all or any part of the anticipated benefits of any such acquisitions.

From time to time, we evaluate and acquire assets and businesses that we believe complement our existing assets and businesses. Acquisitions may require substantial capital or the incurrence of substantial indebtedness. Our capitalization and results of operations may change significantly as a result of completed or future acquisitions. Acquisitions and business expansions involve numerous risks, including difficulties in the assimilation of the assets and operations of the acquired businesses, inefficiencies and difficulties that arise because of unfamiliarity with new assets and the businesses associated with them, and new geographic areas and the diversion of management's attention from other business concerns. Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. Also, following an acquisition, we may discover previously unknown liabilities associated with the acquired business or assets for which we have no recourse under applicable indemnification provisions.

If we are unable to complete capital projects at their expected costs or in a timely manner, or if the market conditions assumed in our project economics deteriorate, our financial condition, results of operations, or cash flows could be materially and adversely affected.

Delays or cost increases related to capital spending programs involving construction of new facilities (or improvements and repairs to our existing facilities) could adversely affect our ability to achieve forecasted operating results. Although we evaluate and monitor each capital spending project and try to anticipate difficulties that may arise, such delays or cost increases may arise as a result of numerous factors, such as:

• denial or delay in issuing requisite regulatory approvals and/or permits;

• unplanned increases in the cost of construction materials or labor;

• disruptions in transportation of modular components and/or construction materials;

• severe adverse weather conditions, natural disasters, or other events (such as equipment malfunctions explosions, fires or spills) affecting our facilities, or those of vendors and suppliers;

• shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;

• market-related increases in a project's debt or equity financing costs; and/or

• nonperformance by, or disputes with, vendors, suppliers, contractors, or sub-contractors involved with a project.

If we are unable to complete capital projects at their expected costs or in a timely manner our financial condition, results of operations, or cash flows could be materially and adversely affected.

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We do not own all of the land on which our pipeline systems and other assets are located, which could result in disruptions to our operations.

We do not own all of the land on which our pipeline systems and other assets are located, and we are, therefore, subject to the risk of increased costs or more burdensome terms to maintain necessary land use. We obtain the right to construct and operate pipelines and other assets on land owned by third parties and government agencies for specified periods. If we were to lose these rights through an inability to renew leases, right-of-way contracts or similar agreements, we may be required to relocate our pipelines or other assets and our business could be adversely affected. Additionally, it may become more expensive for us to obtain new rights-of-ways or leases or to renew existing rights-of-ways or leases. If the cost of obtaining or renewing such agreements increases, it may adversely affect our operations and the cash flows available for distribution to unitholders.

Our business may suffer due to a change in the composition of our Board of Directors, if any of our key senior executives or other key employees who provide services to us discontinue employment, or if certain of our executive officers, who also allocate time to our general partner and its affiliates, do not have enough time to dedicate to our business. Furthermore, a shortage of skilled labor or disruptions in the labor force that provides services to us may make it difficult for us to maintain labor productivity.

Our future success depends to a large extent on the services of HLS's Board of Directors, key senior executives and key senior employees who provide services to us. Also, our business depends on the continuing ability to recruit, train and retain highly qualified employees in all areas of our operations, including accounting, business operations, finance and other key back-office and mid-office personnel. The competition for these employees is intense, and the loss of these executives or employees could harm our business. If any of these executives or other key personnel resign or become unable to continue in their present roles and are not adequately replaced, our business operations could be materially adversely affected. We do not maintain any “key man” life insurance for any executives. Furthermore, our operations require skilled and experienced laborers with proficiency in multiple tasks.

Our general partner shares officers and administrative personnel with HFC to operate both our business and HFC's business. These officers face conflicts regarding the allocation of their and other employees' time, which may affect adversely our results of operations, cash flows and financial condition.

As of December 31, 2014, approximately 15% of HFC's employees dedicated to providing services for us were represented by labor unions under collective bargaining agreements with various expiration dates. HFC may not be able to renegotiate the collective bargaining agreements when they expire on satisfactory terms or at all. A failure to do so may increase our costs. In addition, existing labor agreements may not prevent a future strike or work stoppage, and any work stoppage could negatively affect our results of operations and financial condition.

RISKS TO COMMON UNITHOLDERS

HFC and its affiliates may have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests.

Currently, HFC indirectly owns the 2% general partner interest and a 37% limited partner interest in us and owns and controls HLS, the general partner of our general partner, HEP Logistics Holdings, L.P. (“HEP Logistics”). Conflicts of interest may arise between HFC and its affiliates, including our general partner, on the one hand, and us, on the other hand. As a result of these conflicts, the general partner may favor its own interests and the interests of its other affiliates over our interests. These conflicts include, among others, the following situations:

• HFC, as a shipper on our pipelines, has an economic incentive not to cause us to seek higher tariff rates or terminalling fees, even if such higher rates or terminalling fees would reflect rates that could be obtained in arm's-length, third-party transactions;

• neither our partnership agreement nor any other agreement requires HFC to pursue a business strategy that favors us or utilizes our assets, including whether to increase or decrease refinery production, whether to shut down or reconfigure a refinery, or what markets to pursue or grow. HFC's directors and officers have a fiduciary duty to make these decisions in the best interests of the stockholders of HFC;

• our general partner is allowed to take into account the interests of parties other than us, such as HFC, in resolving conflicts of interest;

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• our partnership agreement provides for modified or reduced fiduciary duties for our general partner, and also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;

• our general partner determines which costs incurred by HFC and its affiliates are reimbursable by us;

• our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;

• our general partner may, in some circumstances, cause us to borrow funds to make cash distributions, even where the purpose or effect of the borrowing benefits our general partner or affiliates;

• our general partner determines the amount and timing of our asset purchases and sales, capital expenditures and borrowings, each of which can affect the amount of cash available to us; and

• our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including the pipelines and terminals agreement with HFC.

Cost reimbursements, which will be determined by our general partner, and fees due to our general partner and its affiliates for services provided, are substantial.

Under our Omnibus Agreement, we are obligated to pay HFC an administrative fee ($2.3 million in 2014 and currently $2.4 million) per year for the provision by HFC or its affiliates of various general and administrative services for our benefit. In addition, we are required to reimburse HFC pursuant to the secondment arrangement for the wages, benefits, and other costs of HFC employees seconded to HLS to perform services at certain of our pipelines and tankage assets. We can neither provide assurance that HFC will continue to provide us the officers and employees that are necessary for the conduct of our business nor that such provision will be on terms that are acceptable to us. If HFC fails to provide us with adequate personnel, our operations could be adversely impacted.

The administrative fee is subject to annual review and may increase if we make an acquisition that requires an increase in the level of general and administrative services that we receive from HFC or its affiliates. Our general partner will determine the amount of general and administrative expenses that will be allocated to us in accordance with the terms of our partnership agreement. In addition, our general partner and its affiliates are entitled to reimbursement for all other expenses they incur on our behalf, including the salaries of and the cost of employee benefits for employees of HLS who provide services to us.

Prior to making any distribution on the common units, we will reimburse our general partner and its affiliates, including officers and directors of the general partner, for all expenses incurred on our behalf, plus the administrative fee. The reimbursement of expenses and the payment of fees could adversely affect our ability to make distributions. The general partner has sole discretion to determine the amount of these expenses. Our general partner and its affiliates also may provide us other services for which we are charged fees as determined by our general partner.

Increases in interest rates could adversely impact our unit price and our ability to issue additional equity to make acquisitions, fund expansion capital expenditures, or for other purposes.

As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity to make acquisitions, fund expansion capital expenditures or for other purposes. If we then issue additional equity at a significantly lower price, material dilution to our existing unitholders could result.

Even if unitholders are dissatisfied, they cannot remove our general partner without its consent.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management's decisions regarding our business. Unitholders did not elect our general partner or the board of directors of HLS and have no right to do so on an annual or other continuing basis. The board of directors of HLS is chosen by the sole member of HLS. If unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

The vote of the holders of at least 66 2/3% of all outstanding units voting together as a single class is required to remove the general partner. Unitholders will be unable to remove the general partner without its consent because the general partner and its affiliates own sufficient units to prevent its removal. Unitholders' voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding (other than the

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general partner, its affiliates, their transferees, and persons who acquired such units with the prior approval of the board of directors of the general partner's general partner) cannot vote on any matter; however, no such person currently exists. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings, acquire information about our operations, and influence the manner or direction of management.

The control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the partners of our general partner from transferring their respective partnership interests in our general partner to a third party. The new partners of our general partner would then be in a position to replace the board of directors and officers of the general partner of our general partner with their own choices and to control the decisions made by the board of directors and officers.

We may issue additional common units without unitholder approval, which would dilute an existing unitholder's ownership interests.

Under our partnership agreement, provided there is no significant decrease in our operating performance, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders, and HEP currently has a shelf registration on file with the SEC pursuant to which it may issue up to $2.0 billion in additional common units.

The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

• our unitholders' proportionate ownership interest in us will decrease;

• the amount of cash available for distribution on each unit may decrease;

• the relative voting strength of each previously outstanding unit may be diminished; and

• the market price of the common units may decline.

Our partnership agreement does not give our unitholders the right to approve our issuance of equity securities ranking junior to the common units at any time.

In establishing cash reserves, our general partner may reduce the amount of cash available for distribution to unitholders.

Our partnership agreement requires our general partner to deduct from operating surplus cash reserves that it establishes are necessary to fund our future operating expenditures. In addition, our partnership agreement permits our general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party, or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash available to make the required payments to our debt holders or to pay the minimum quarterly distribution on our common units every quarter.

HFC and its affiliates may engage in limited competition with us.

HFC and its affiliates may engage in limited competition with us. Pursuant to the Omnibus Agreement, HFC and its affiliates agreed not to engage in the business of operating intermediate or refined product pipelines or terminals, crude oil pipelines or terminals, truck racks or crude oil gathering systems in the continental United States. The Omnibus Agreement, however, does not apply to:

• any business operated by HFC or any of its subsidiaries at the closing of our initial public offering;

• any business or asset that HFC or any of its subsidiaries acquires or constructs that has a fair market value or construction cost of less than $5 million; and

• any business or asset that HFC or any of its subsidiaries acquires or constructs that has a fair market value or construction cost of $5 million or more if we have been offered the opportunity to purchase the business or asset at fair market value, and we decline to do so.

In the event that HFC or its affiliates no longer control our partnership or there is a change of control of HFC, the non-competition provisions of the Omnibus Agreement will terminate.

Our general partner has a limited call right that may require a unitholder to sell its common units at an undesirable time or price.

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If at any time our general partner and its affiliates own more than 80% of the common units (which it does not presently), our general partner will have the right (which it may assign to any of its affiliates or to us) but not the obligation to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, a holder of common units may be required to sell its units at a time or price that is undesirable to it and may not receive any return on its investment. A common unitholder may also incur a tax liability upon a sale of its units.

A unitholder may not have limited liability if a court finds that unitholder actions constitute control of our business or that we have not complied with state partnership law.

Under Delaware law, a unitholder could be held liable for our obligations to the same extent as a general partner if a court determined that the right of unitholders to remove our general partner or to take other action under our partnership agreement constituted participation in the “control” of our business. Our general partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities, except for those contractual obligations that are expressly made without recourse to our general partner.

In addition, Section 17-607 and 17-804 of the Delaware Revised Uniform Limited Partnership Act provides that under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.

Further, we conduct business in a number of states. In some of those states the limitations on the liability of limited partners for the obligations of a limited partnership have not been clearly established. The unitholders might be held liable for the partnership's obligations as if they were a general partner if a court or government agency determined that we were conducting business in the state but had not complied with the state's partnership statute.

HFC may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.

HFC currently holds 22,380,030 of our common units, which is approximately 37% of our outstanding common units. Additionally, we agreed to provide HFC registration rights with respect to our common units that it holds. The sale of these units in the public or private markets could have an adverse impact on the trading price of our common units.

TAX RISKS TO COMMON UNITHOLDERS

Our tax treatment depends on our status as a partnership for federal income tax purposes as well as our not being subject to a material amount of entity-level taxation by individual states. If the U.S. Internal Revenue Service (the “IRS”) were to treat us as a corporation for federal income tax purposes or if we were to become subject to additional amounts of entity-level taxation for federal or state tax purposes, our cash available for distribution to unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes.

Despite the fact that we are organized as a limited partnership under Delaware law, we would be treated as a corporation for U.S. federal income tax purposes unless we satisfy a "qualifying income" requirement and are not treated as an investment company. Based upon our current operations, we believe we satisfy the qualifying income requirement and are not treated as an investment company. Failing to meet the qualifying income requirement, being treated as an investment company, or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. Distributions to unitholders would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to unitholders, likely causing a substantial reduction in the value of our common units.

At the entity level, were we to be subject to federal income tax, we would also be subject to the income tax provisions of many states. Moreover, because of widespread state budget deficits and other reasons, several states are evaluating ways to independently subject partnerships to entity-level taxation through the imposition of state income taxes, franchise taxes and other forms of

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taxation. For example, we are required to pay Texas margin tax on any income apportioned to Texas. Imposition of any additional such taxes on us or an increase in the existing tax rates would reduce the cash available for distributions to our unitholders.

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, from time to time, the administration or members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. One such legislative proposal would eliminate the qualifying income exception upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units. Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible to meet the qualifying income requirement to be treated as a partnership for U.S. federal income tax purposes.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.

The IRS may adopt positions that differ from the positions we have taken or may take on tax matters. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, the costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

Even if you do not receive any cash distributions from us, you will be required to pay taxes on your share of our taxable income.

You will be required to pay federal income taxes and, in some cases, state and local income taxes, on your share of our taxable income, whether or not you receive cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax due from you with respect to that income.

Tax gain or loss on the disposition of our common units could be more or less than expected.

If a unitholder disposes of common units, it will recognize gain or loss equal to the difference between the amount realized and its tax basis in those common units. Because distributions in excess of a unitholder's allocable share of our net taxable income result in a decrease of the unitholder's tax basis in its common units, the amount, if any, of such prior excess distributions with respect to the units sold will, in effect, become taxable income to the unitholder if it sells such units at a price greater than its tax basis in those units, even if the price the unitholder receives is less than its original cost. Moreover, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture of items including depreciation recapture. In addition, because the amount realized includes a unitholder's share of our nonrecourse liabilities, if unitholders sell their units, they may incur a tax liability in excess of the amount of cash they receive from the sale.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

An investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts ("IRAs"), Keogh Plans and other retirement plans and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be “unrelated business taxable income” and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and each non-U.S. person will be required to file U.S. federal tax returns and pay tax on their share of our taxable income. Tax-exempt entities and non-U.S. persons should consult their tax adviser before investing in our common units.

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We treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units and because of other reasons, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from unitholders' sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to their tax returns.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing treasury regulations, and although the Department of the Treasury issued proposed treasury regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items, the proposed regulations are not final and do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of units) may be considered as having disposed of those units. If so, it would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, such unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

When we issue units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders' sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders' tax returns without the benefit of additional deductions.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have terminated our partnership for federal income tax purposes if there are sales or exchanges which, in the aggregate, constitute 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes

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of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders may receive two Schedules K-1) for one fiscal year and may result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in its taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership for federal tax purposes, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership may be permitted to provide only a single Schedule K-1 to unitholders for the tax years in which the termination occurs.

Unitholders likely will be subject to state and local taxes and return filing requirements as a result of investing in our common units.

In addition to federal income taxes, unitholders likely will be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance, or intangible taxes that are imposed by the various jurisdictions in which we do business or own property now or in the future. Unitholders likely will be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions, even if they do not live in these jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We currently own property and conduct business in Texas, New Mexico, Arizona, Utah, Idaho, Oklahoma, Washington, Kansas, Wyoming and Nevada. We may own property or conduct business in other states or foreign countries in the future. It is the unitholder's responsibility to file all federal, state, local and foreign tax returns.

Item 1B. Unresolved Staff Comments

We do not have any unresolved SEC staff comments.

Item 2. Properties

PIPELINES

Our refined product pipelines transport light refined products from HFC’s Navajo refinery in New Mexico and Alon’s Big Spring refinery in Texas to their customers in the metropolitan and rural areas of Texas, New Mexico, Arizona, Utah, Oklahoma and northern Mexico and from various refineries in Utah, Wyoming, and Montana (including HFC's Woods Cross refinery in Utah) to Las Vegas, Nevada and Cedar City, Utah. The refined products transported in these pipelines include conventional gasolines, federal, state and local specification reformulated gasoline, low-octane gasoline for oxygenate blending, distillates that include high- and low-sulfur diesel and jet fuel and LPGs (such as propane, butane and isobutane).

Our intermediate product pipelines consist principally of three parallel pipelines that originate at the Navajo refinery Lovington facilities and terminate at its Artesia facilities. These pipelines transport intermediate feedstocks and crude oil for HFC’s refining operations in New Mexico.

Our crude pipelines consist of crude oil trunk, gathering and connection pipelines located in West Texas, New Mexico and Oklahoma that deliver crude oil to the Navajo refinery and crude oil and refined product pipelines that support HFC’s Woods Cross refinery.

Our pipelines are regularly inspected, are well maintained and, we believe, are in good repair. Generally, other than as may be provided in certain pipelines and terminal agreements, substantially all of our pipelines are unrestricted as to the direction in which product flows and the types of refined products that we can transport on them. The FERC regulates the transportation tariffs for interstate shipments on our refined product pipelines and state regulatory agencies regulate the transportation tariffs for intrastate shipments on our pipelines.

The following table details the average aggregate daily number of barrels of petroleum products transported on our pipelines in each of the periods set forth below for HFC and for third parties.

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	Years Ended December 31,
	2014	2013	2012	2011	2010
Volumes transported for (bpd):
HFC	457,014	397,359	405,718	345,990	324,382
Third parties	64,055	63,337	63,152	52,361	38,910
Total	521,069	460,696	468,870	398,351	363,292
Total barrels in thousands (“mbbls”)	190,190	168,154	171,606	145,398	132,602

The following table sets forth certain operating data for each of our refined product, intermediate and crude pipelines. Throughput is the total average number of barrels per day transported on a pipeline but does not aggregate barrels moved between different points on the same pipeline. Revenues reflect tariff revenues generated by barrels shipped from an origin to a delivery point on a pipeline. Revenues also include payments made by Alon under capacity lease arrangements on our Orla to El Paso pipeline. Under these arrangements, we provide space on our pipeline for the shipment of up to 15,000 barrels of refined product per day. Alon pays us whether or not it actually ships the full volumes of refined products it is entitled to ship. To the extent Alon does not use its capacity; we are entitled to use it. We calculate the capacity of our pipelines based on the throughput capacity for barrels of gasoline equivalent that may be transported in the existing configuration; in some cases, this includes the use of drag reducing agents.

Origin and Destination	Diameter (inches)	Length (miles)	Capacity (bpd)
Refined Product Pipelines:
Artesia, NM to El Paso, TX	6	156	19,000
Artesia, NM to Orla, TX to El Paso, TX	8/12/8	214	70,000	(1)
Artesia, NM to Moriarty, NM(2)	12/8	215	27,000	(3)
Moriarty, NM to Bloomfield, NM(2)	8	191	14,400	(3)
Big Spring, TX to Abilene, TX	6/8	100	20,000
Big Spring, TX to Wichita Falls, TX	6/8	227	23,000
Wichita Falls, TX to Duncan, OK	6	47	21,000
Midland, TX to Orla, TX	8/10	135	25,000
Artesia, NM to Roswell, NM	4	35	5,300
Woods Cross, UT	10/12/8	8	70,000
Woods Cross, UT to Las Vegas, NV	12	427	62,000
Tulsa, OK(4)
Intermediate Product Pipelines:
Lovington, NM to Artesia, NM	8	65	48,000
Lovington, NM to Artesia, NM	10	65	72,000
Lovington, NM to Artesia, NM	16	65	98,400
Tulsa, OK(5)	8/10/12	7		(5)
Crude Pipelines:
Artesia Region Gathering	Various	497	60,000
West Texas Gathering	Various	305	35,000
Roadrunner Pipeline	16	69	62,400
Beeson Pipeline	8	41	50,400

(1) Includes 15,000 bpd of capacity on the Orla to El Paso segment of this pipeline that is leased to Alon under capacity lease agreements.

(2) The White Lakes Junction to Moriarty segment of our Artesia to Moriarty pipeline and the Moriarty to Bloomfield pipeline is leased from Mid-America Pipeline Company, LLC (“Mid-America”) under a long-term lease agreement.

(3) Capacity for this pipeline is reflected in the information for the Artesia to Moriarty pipeline.

(4) Tulsa gasoline and diesel fuel connections to Magellan’s pipeline of less than one mile.

(5) The capacities of the three gas pipelines are 10 million standard cubic feet per day (“MMSCFD”), 22 MMSCFD, and 10 MMSCFD and the two liquid pipelines are 45,000 BPD and 60,000 BPD.

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HFC shipped an aggregate of 65.0% of the petroleum products transported on our refined product pipelines and 98.0% of the petroleum products transported on our intermediate pipelines and crude oil pipelines in 2014. These pipelines transported 81.1% of the light refined products produced by HFC’s Navajo refinery in 2014.

Artesia, New Mexico to El Paso, Texas

The Artesia to El Paso refined product pipeline is regulated by the FERC. It was constructed in 1959 and consists of 156 miles of 6-inch pipeline. This pipeline is used primarily for the shipment of refined products produced at the Navajo refinery to our El Paso terminal, where we deliver to common carrier pipelines for transportation to Arizona, northern New Mexico, northern Mexico and to the terminal’s tank farm for truck rack loading for local delivery by tanker truck. Refined products produced at the Navajo refinery destined for El Paso are transported on either this pipeline or our Artesia to Orla to El Paso pipeline.

Artesia, New Mexico to Orla, Texas to El Paso, Texas

The Artesia to Orla to El Paso refined product pipeline is a common-carrier pipeline regulated by the FERC and consists of three segments:

• an 8-inch and a 12-inch, 82-mile segment from the Navajo refinery to Orla, Texas;

• a 12-inch, 126-mile segment from Orla to outside El Paso, Texas; and

• an 8-inch, 7-mile segment from outside El Paso to our El Paso terminal.

There are two shippers on this pipeline, HFC and Alon. As mentioned above, refined products destined to our El Paso terminal are delivered to common carrier pipelines for transportation to Arizona, northern New Mexico and northern Mexico and to the terminal’s truck rack for local delivery by tanker truck.

Artesia, New Mexico to Moriarty, New Mexico

The Artesia to Moriarty refined product pipeline consists of a 60-mile, 12-inch pipeline that was constructed in 1999 and extends from the Navajo refinery Artesia facility to White Lakes Junction, New Mexico, and 155 miles of 8-inch pipeline that was constructed in 1973 and extends from White Lakes Junction to our Moriarty terminal, where it also connects to our Moriarty to Bloomfield pipeline. We own the 12-inch pipeline from Artesia to White Lakes Junction. We lease the White Lakes Junction to Moriarty segment of this pipeline and the Moriarty to Bloomfield pipeline described below, from Mid-America Pipeline Company, LLC under a long-term lease agreement entered into in 1996, which expires in 2017 and has two ten-year extensions at our option. At our Moriarty terminal, volumes shipped on this pipeline can be transported to other markets in the area, including Albuquerque, Santa Fe and West Texas, via tanker truck. The 155-mile White Lakes Junction to Moriarty segment of this pipeline is operated by Mid-America (or its designee). HFC is the only shipper on this pipeline. Currently, we pay a monthly fee (which is subject to adjustments based on changes in the PPI) of $559,000 to Mid-America to lease the White Lakes Junction to Moriarty and Moriarty to Bloomfield pipelines.

Moriarty, New Mexico to Bloomfield, New Mexico

The Moriarty to Bloomfield refined product pipeline was constructed in 1973 and consists of 191 miles of 8-inch pipeline leased from Mid-America. This pipeline serves Western Refining's terminal in Bloomfield and our Bloomfield terminal, which is currently idled. This pipeline is operated by Mid-America (or its designee). HFC is the only shipper on this pipeline.

Big Spring, Texas to Abilene, Texas

The Big Spring to Abilene refined product pipeline was constructed in 1957 and consists of 95 miles of 6-inch pipeline and 5 miles of 8-inch pipeline. This pipeline is used for the shipment of refined products produced at the Big Spring refinery to the Abilene terminal. Alon is the only shipper on this pipeline.

Big Spring, Texas to Wichita Falls, Texas

Segments of the Big Spring to Wichita Falls refined product pipeline were constructed in 1969 and 1989, and consist of 95 miles of 6-inch pipeline and 132 miles of 8-inch pipeline. This pipeline is used for the shipment of refined products produced at the Big Spring refinery to the Wichita Falls terminal. Alon is the only shipper on this pipeline.

Wichita Falls, Texas to Duncan, Oklahoma

The Wichita Falls to Duncan refined product pipeline is a common carrier and is regulated by the FERC. It was constructed in 1958 and consists of 47 miles of 6-inch pipeline. This pipeline is used for the shipment of refined products from the Wichita Falls terminal to Alon’s Duncan terminal, which we do not own. Alon is the only shipper on this pipeline.

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Midland, Texas to Orla, Texas

Segments of the Midland to Orla refined product pipeline were constructed in 1928 and 1998, and consist of 50 miles of 10-inch pipeline and 86 miles of 8-inch pipeline. This pipeline is used for the shipment of refined products produced at the Big Spring refinery from Midland to our tank farm at Orla. Alon is the only shipper on this pipeline.

Artesia, New Mexico to Roswell, New Mexico

The 35-mile, 4-inch diameter Artesia to Roswell refined product pipeline is currently idled.

Woods Cross, Utah refined product pipelines

The Woods Cross refined product pipelines consist of three pipeline segments. The Woods Cross to Pioneer segment represents 2 miles of 10-inch pipeline that is also used for product shipments to and through the Pioneer terminal. The Woods Cross to UNEV Pipeline segment consists of 2 miles of 12-inch pipeline and is used for product shipments from HFC's Woods Cross refinery to the UNEV Pipeline origin pump station. The Woods Cross to Chevron Pipeline’s Salt Lake Products Pipeline segment consists of 4 miles of 8-inch pipeline and is used for product shipments from HFC’s Woods Cross refinery to Tesoro's Northwest Pipeline origin station. HFC is the only shipper on these pipelines.

UNEV refined product pipeline

The 427-mile, 12-inch refined products pipeline was completed in early 2012. This pipeline is used for the shipment of refined products from Woods Cross, Utah to terminals in Las Vegas, Nevada and Cedar City, Utah. HFC and Sinclair Transportation Company (“Sinclair”) are the primary shippers on this pipeline.

8” Pipeline from Lovington, New Mexico to Artesia, New Mexico

The 65-mile, 8-inch diameter pipeline was constructed in 1981. This pipeline is used for the shipment of intermediate feedstocks, crude oil and LPGs from the Navajo refinery Lovington facility to its Artesia facility. HFC is the primary shipper on this pipeline.

10” Pipeline from Lovington, New Mexico to Artesia, New Mexico

The 65-mile, 10-inch diameter pipeline was constructed in 1999. This pipeline is used for the shipment of intermediate feedstocks and crude oil from the Navajo refinery Lovington facility to its Artesia facility. HFC is the only shipper on this pipeline.

16” Pipeline from Lovington, New Mexico to Artesia, New Mexico

The 65-mile, 16-inch diameter pipeline was constructed in 2009. This pipeline is used for the shipment of intermediate feedstocks and crude oil from the Navajo refinery Lovington facility to its Artesia facility. This pipeline can also be reversed to deliver crude oil out of the gathering system from Beeson and Barnsdall to either the Lovington facility or the Artesia facility. HFC is the only shipper on this pipeline.

Tulsa, Oklahoma Interconnect Pipelines

Five intermediate product and gas pipelines totaling 7 miles between HFC’s Tulsa East and West refinery facilities were completed in 2011. These pipelines are used in the shipment of gas and liquids between the two facilities.

Lovington / Artesia, New Mexico crude oil pipelines

The crude oil gathering and trunk pipelines deliver crude oil to HFC’s Navajo refinery and consist of 802 miles of 4-inch, 6-inch, 8-inch, and 12-inch diameter pipeline. The crude oil trunk pipelines consist of five pipeline segments that deliver crude oil to the Navajo refinery Lovington facility and seven pipeline segments that deliver crude oil to the Navajo refinery Artesia facility.

The Lovington system crude oil mainlines include five pipeline segments consisting of a 23-mile, 12-inch pipeline from Russell to Lovington, a 20-mile, 8-inch pipeline from Russell to Hobbs, an 11-mile, 6-inch and 8-inch pipeline from Crouch to Lovington, a 20-mile, 8-inch pipeline from Hobbs to Lovington and a 6-mile, 6-inch pipeline from Gaines to Hobbs.

The Artesia system crude oil mainlines include seven pipeline segments consisting of an 11-mile, 6-inch pipeline from Beeson to North Artesia, a 7-mile, 4-inch and 6-inch pipeline from Barnsdall to North Artesia, a 2-mile, 8-inch pipeline from the Barnsdall jumper line to Lovington, a 4-mile, 4-inch pipeline from the Artesia Station to North Artesia, a 6-mile, 8-inch pipeline from North Artesia to Evans Junction and a 1-mile, 6-inch pipeline from Abo to Evans Junction.

We operate a 12-mile, 8-inch pipeline from Evans Junction to Artesia, New Mexico that supplies natural gas to the Navajo refinery Artesia facility. We operate a newly constructed 14 mile, 12-inch pipeline from Beeson station to the Plains Bisti connection. We also reactivated 62 miles of 8-inch pipe for crude movements from Whites City Station to Artesia Station.

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Roadrunner Pipeline

The Roadrunner crude oil pipeline connects the Navajo refinery Lovington facility to a West Texas terminal of the Centurion Pipeline that extends to Cushing, Oklahoma. It was constructed in 2009 and consists of 69 miles of 16-inch pipeline. This pipeline is used for the shipment of crude oil from Cushing to the Navajo refinery Lovington facility. It is also reversible to deliver crude from Lovington to Slaughter.

Beeson Pipeline

The Beeson crude oil pipeline delivers crude oil to the Navajo refinery Lovington facility ("Beeson Pipeline"). It was constructed in 2009 and consists of 41 miles of 8-inch pipeline. This pipeline ships crude oil from our crude oil gathering system to the Navajo refinery Lovington facility for processing.

REFINED PRODUCT TERMINALS, LOADING RACKS AND REFINERY TANKAGE

Refined Product Terminals and Loading Racks

Our refined product terminals receive products from pipelines connected to HFC’s refineries and Alon’s Big Spring refinery. We then distribute them to HFC and third parties, who in turn deliver them to end-users and retail outlets. Our terminals are generally complementary to our pipeline assets and serve HFC’s and Alon’s marketing activities and other customers. Terminals play a key role in moving product to the end-user market by providing the following services:

• distribution;

• blending to achieve specified grades of gasoline;

• other ancillary services that include the injection of additives and filtering of jet fuel; and

• storage and inventory management.

Typically, our refined product terminal facilities consist of multiple storage tanks and are equipped with automated truck loading equipment that operates 24 hours a day. This automated system provides for control of security, allocations, and credit and carrier certification by remote input of data by our customers. In addition, nearly all of our terminals are equipped with truck loading racks capable of providing automated blending to individual customer specifications.

Our refined product terminals derive most of their revenues from terminalling fees paid by customers. We charge a fee for transferring refined products from the terminal to trucks or to pipelines connected to the terminal. In addition to terminalling fees, we generate revenues by charging our customers fees for blending, injecting additives, and filtering jet fuel. HFC currently accounts for the substantial majority of our refined product terminal revenues.

The table below sets forth the total average throughput for our refined product terminals in each of the periods presented:

	Years Ended December 31,
	2014	2013	2012	2011	2010
Refined products terminalled for (bpd):
HFC	261,888	255,108	271,549	193,645	178,903
Third parties	69,100	63,791	53,456	44,454	39,568
Total	330,988	318,899	325,005	238,099	218,471
Total (mbbls)	120,811	116,398	118,952	86,906	79,742

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The following table outlines the locations of our terminals and their storage capacities, number of tanks, supply source, and mode of delivery:

Terminal Location	Storage Capacity (barrels)	Number of Tanks	Supply Source	Mode of Delivery
El Paso, TX	636,000	19	Pipeline/rail	Truck/Pipeline
Moriarty, NM	211,000	9	Pipeline	Truck
Bloomfield, NM (1)	203,000	7	Pipeline	Truck
Tucson, AZ(2)	186,000	9	Pipeline	Truck
Mountain Home, ID(3)	122,000	4	Pipeline	Pipeline
Spokane, WA	384,000	28	Pipeline/Rail	Truck
Abilene, TX	157,000	6	Pipeline	Truck/Pipeline
Wichita Falls, TX	220,000	11	Pipeline	Truck/Pipeline
Las Vegas, NV	381,000	12	Pipeline/Truck	Truck
Cedar City, UT	235,000	7	Pipeline/Rail/Truck	Truck
Orla tank farm	129,000	5	Pipeline	Pipeline
Artesia facility truck rack	N/A	N/A	Refinery	Truck
Lovington facility asphalt truck rack	N/A	N/A	Refinery	Truck
Woods Cross facility truck rack	N/A	N/A	Refinery	Truck/Pipeline
Tulsa West facility truck and rail rack	N/A	N/A	Refinery	Truck/Rail/Pipeline
Tulsa East facility truck and rail racks	N/A	N/A	Refinery	Truck/Rail/Pipeline
Cheyenne facility truck and rail racks	N/A	N/A	Refinery	Truck/Rail
El Dorado facility truck racks	N/A	N/A	Refinery	Truck
Total	2,864,000

(1) Inactive

(2) The underlying ground at the Tucson terminal is leased.

(3) Handles only jet fuel.

El Paso Terminal

We receive light refined products at this terminal from the Navajo refinery Artesia facility through our Artesia to El Paso and Artesia to Orla to El Paso pipelines and by rail that account for 88% of the volumes at this terminal. We also receive product from the Big Spring refinery that accounted for 12% of the volumes at this terminal in 2014. Refined products received at this terminal are sold locally via the truck rack or transported to our Tucson terminal and other terminals in Phoenix on Kinder Morgan’s East System pipeline. Competition in this market includes a refinery and terminal owned by Western Refining, Inc., a joint venture pipeline and terminal owned by ConocoPhillips and NuStar Energy, L.P. (“NuStar”).

Moriarty Terminal

We receive light refined products at this terminal from the Navajo refinery Artesia facility through our pipelines. Refined products received at this terminal are sold locally, via the truck rack. HFC is our only customer at this terminal. There are no competing terminals in Moriarty.

Bloomfield Terminal

We historically have received light refined products at this terminal from the Navajo refinery Artesia facility through our pipelines. This terminal is currently idled with no throughput.

Tucson Terminal

We own 100% of the improvements and lease the underlying ground at this terminal. The Tucson terminal receives light refined products from Kinder Morgan’s East System pipeline, which transports refined products from the Navajo refinery Artesia facility that it receives at our El Paso terminal. Refined products received at this terminal are sold locally, via the truck rack. Competition in this market includes terminals owned by Kinder Morgan.

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Mountain Home Terminal

We receive jet fuel from third parties at this terminal that is transported on Tesoro Logistics' Salt Lake City to Boise, Idaho pipeline. We then transport the jet fuel from the Mountain Home terminal through our 13-mile, 4-inch pipeline to the United States Air Force base outside of Mountain Home. Our pipeline associated with this terminal is the only pipeline that supplies jet fuel to the air base. We are paid a single fee, from the Defense Energy Support Center, for injecting, storing, testing and transporting jet fuel at this terminal.

Spokane Terminal

This terminal is connected to the Woods Cross refinery via a Tesoro Logistics common carrier pipeline. The Spokane terminal is also supplied by rail and truck. Refined products received at this terminal are sold locally, via the truck rack. We have several major customers at this terminal. Other terminals in the Spokane area include terminals owned by ExxonMobil and ConocoPhillips.

Abilene Terminal

This terminal receives refined products from Alon's Big Spring refinery, which accounted for all of its volumes in 2014. Refined products received at this terminal are sold locally via a truck rack or pumped over a 2-mile pipeline to Dyess Air Force Base. Alon is the only customer at this terminal.

Wichita Falls Terminal

This terminal receives refined products from the Alon's Big Spring refinery, which accounted for all of its volumes in 2014. Refined products received at this terminal are sold via a truck rack or shipped via pipeline connections to Alon’s terminal in Duncan, Oklahoma and also to NuStar’s Southlake Pipeline. Alon is the only customer at this terminal.

Las Vegas Terminal

This terminal is owned by UNEV and receives product from HFC and Sinclair shipped through the UNEV Pipeline originating in Woods Cross, Utah. Refined products received at this terminal are sold locally. HFC and Sinclair are the primary customers at this terminal.

Cedar City Terminal

This terminal is owned by UNEV and receives product from HFC and Sinclair shipped through the UNEV Pipeline originating in Woods Cross, Utah. Refined products received at this terminal are sold locally. HFC and Sinclair are the primary customers at this terminal.

Orla Tank Farm

The Orla tank farm was constructed in 1998. It receives refined products from Alon's Big Spring refinery that accounted for all of its volumes in 2014. Refined products received at the tank farm are delivered into our Orla to El Paso pipeline. Alon is the only customer at this tank farm.

Artesia Facility Truck Rack

The truck rack at the Navajo refinery Artesia facility loads light refined products produced at the Navajo refinery onto tanker trucks for delivery to markets in the surrounding area. HFC is the only customer of this truck rack.

Lovington Facility Asphalt Truck Rack

The asphalt loading rack facility at the Lovington refinery loads asphalt produced at the Lovington facility onto tanker trucks.  HFC is the only customer of this truck rack.

Woods Cross Facility Truck Rack

The truck rack at the Woods Cross facility loads light refined products produced at the refinery onto tanker trucks for delivery to markets in the surrounding area. HFC is the only customer of this truck rack. HFC also makes transfers to a common carrier pipeline at this facility.

Tulsa Facilities Truck and Rail Racks

The Tulsa truck and rail loading rack facilities consist of loading racks located at HFC’s Tulsa refinery West and East facilities. Loading racks at the Tulsa refinery West facility consist of rail and truck racks that load refined products and lube oil produced at the refinery onto rail cars and tanker trucks. Loading racks at the Tulsa refinery East facility consist of truck and rail racks at which we load refined products and off load crude. The truck racks also load asphalt and LPG.

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Cheyenne Facility Truck and Rail Racks

The Cheyenne loading rack facilities consist of light refined products, heavy products and LPG truck and rail racks. These racks load refined products and propane onto tanker trucks for delivery to markets in surrounding areas. Additionally, these facilities include four crude oil LACT units that unload crude oil from tanker trucks.

El Dorado Facility Truck Racks

The El Dorado loading rack facilities consist of a light refined products truck rack and a propane truck rack. These racks load refined products and propane onto tanker trucks for delivery to markets in surrounding areas.

Refinery Tankage

Our refinery tankage consists of on-site tankage at HFC’s refineries. Our refinery tankage derives its revenues from fixed fees or throughput charges in providing HFC’s refining facilities with approximately 9,400,000 barrels of storage.

The following table outlines the locations of our refinery tankage, storage capacity, tankage type and number of tanks:

Refinery Location	Storage Capacity (barrels)	Tankage Type	Number of Tanks
Artesia , NM	180,000	Crude oil	2
Lovington, NM	309,000	Crude oil	2
Woods Cross, UT	190,000	Crude oil	3
Tulsa, OK	3,272,000	Crude oil and refined product	51
Cheyenne, WY	1,815,000	Crude oil and refined product	51
El Dorado, KS	3,639,000	Refined and intermediate product	84
Total	9,405,000

PIPELINE AND TERMINAL CONTROL OPERATIONS

All of our pipelines are operated via geosynchronous satellite, microwave, radio and frame relay communication systems from our central control room located in Artesia, New Mexico. We also monitor activity at our terminals from this control room. The control center operates with state-of-the-art System Control and Data Acquisition, or SCADA, systems. Our control center is equipped with computer systems designed to continuously monitor operational data, including refined product and crude oil throughput, flow rates, and pressures. In addition, the control center monitors alarms and throughput balances. The control center operates remote pumps, motors, engines, and valves associated with the delivery of refined products and crude oil. The computer systems are designed to enhance leak-detection capabilities, sound automatic alarms if operational conditions outside of pre-established parameters occur, and provide for remote-controlled shutdown of pump stations on the pipelines. Pump stations and meter-measurement points on the pipelines are linked by satellite or telephone communication systems for remote monitoring and control, which reduces our requirement for full-time on-site personnel at most of these locations.

Item 3. 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 4. Mine Safety Disclosures

Not applicable.

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PART II

Item 5. Market for the Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Common Units

Our common limited partner units are traded on the New York Stock Exchange under the symbol “HEP.” The following table sets forth the range of the daily high and low sales prices per common unit, cash distributions per common unit and the trading volume of common units for the periods indicated.

Years Ended December 31,	High		Low		Cash Distributions		Trading Volume
2014
Fourth quarter	$	37.44	$	28.50	$	0.5300	7,685,800
Third quarter	$	36.66	$	32.50	$	0.5225	4,374,200
Second quarter	$	36.64	$	29.83	$	0.5150	7,935,600
First quarter	$	34.24	$	31.65	$	0.5075	3,884,600
2013
Fourth quarter	$	34.32	$	29.55	$	0.5000	7,533,300
Third quarter	$	40.00	$	32.54	$	0.4925	4,562,500
Second quarter	$	40.74	$	35.03	$	0.4850	7,744,600
First quarter	$	36.13	$	35.00	$	0.4775	11,037,400

The cash distribution for the fourth quarter of 2014 was declared on January 22, 2015, and was paid on February 13, 2015, to all unitholders of record on February 2, 2015.

As of February 18, 2015, we had approximately 17,303 common unitholders, including beneficial owners of common units held in street name.

We consider regular cash distributions to unitholders on a quarterly basis, although there is no assurance as to the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors. See “Liquidity and Capital Resources” under Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a discussion of conditions and limitations prohibiting distributions under the Credit Agreement and indentures relating to our senior notes.

Within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement) to unitholders of record on the applicable record date. The amount of available cash generally is all cash on hand at the end of the quarter; less the amount of cash reserves established by our general partner to provide for the proper conduct of our business, comply with applicable laws, any of our debt instruments, or other agreements; or provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters; plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter.

We make distributions in the following manner: 98% to our common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter and any arrearages in payment of the minimum quarterly distributions for any prior quarters, thereafter.

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

	Total Quarterly  Distribution Target Amount	Marginal Percentage Interest in Distributions
		Unitholders	General Partner
Minimum quarterly distribution	$0.25	98%	2%
First target distribution	Up to $0.275	98%	2%
Second target distribution	above $0.275 up to $0.3125	85%	15%
Third target distribution	above $0.3125 up to $0.375	75%	25%
Thereafter	Above $0.375	50%	50%

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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
October 2014	—	$	—	—	$	—
November 2014	55,690	$	34.48	—	$	—
December 2014	—	$	—	—	$	—
Total for October to December 2014	55,690			—

We have an incentive plan (“Long-Term Incentive Plan”) for employees and non-employee directors who perform services for us. The units reported represent common units purchased in the open market for delivery to recipients of our restricted unit, phantom unit and performance unit awards under our Long-Term Incentive Plan at the time of grant or settlement, as applicable.

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Item 6. Selected Financial Data

The following table shows selected financial information for HEP. This table should be read in conjunction with Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements of HEP and related notes thereto included elsewhere in this Form 10-K.

	Years Ended December 31,
	2014			2013			2012			2011			2010
	(In thousands, except per unit data)
Statement of Income Data:
Revenues	$	332,545		$	305,182		$	292,560		$	214,268		$	182,137
Operating costs and expenses
Operations (exclusive of depreciation and amortization)	104,801			99,444			89,242			64,521			54,946
Depreciation and amortization	62,166			65,423			57,461			36,958			31,363
General and administrative	10,824			11,749			7,594			6,576			7,719
	177,791			176,616			154,297			108,055			94,028
Operating income	154,754			128,566			138,263			106,213			88,109
Equity in earnings of SLC Pipeline	2,987			2,826			3,364			2,552			2,393
Interest expense	(36,101		)	(47,010		)	(47,182		)	(35,959		)	(34,001		)
Interest Income	3			161			—			—			7
Loss on early extinguishment of debt	(7,677		)	—			(2,979		)	—			—
Gain on sale of assets	—			1,810			—			—			—
Other income	82			61			10			17			17
	(40,706		)	(42,152		)	(46,787		)	(33,390		)	(31,584		)
Income from continuing operations before income taxes	114,048			86,414			91,476			72,823			56,525
State income tax	(235		)	(333		)	(371		)	(234		)	(296		)
Income from continuing operations	113,813			86,081			91,105			72,589			56,229
Add net loss attributable to Predecessor	—			—			4,200			6,351			70
Allocation of net loss (income) attributable to noncontrolling interests	(8,288		)	(6,632		)	(1,153		)	859			24
Net income attributable to Holly Energy Partners	105,525			79,449			94,152			79,799			56,323
Less general partner interest in net income, including incentive distributions(1)	34,667			27,523			22,450			16,806			12,084
Limited partners’ interest in net income	$	70,858		$	51,926		$	71,702		$	62,993		$	44,239
Limited partners’ per unit interest in net income – basic and diluted(1)	$	1.20		$	0.88		$	1.29		$	1.38		$	1.00
Distributions per limited partner unit	$	2.08		$	1.96		$	1.84		$	1.74		$	1.66
Other Financial Data:
Cash flows from operating activities	$	186,640		$	183,080		$	161,149		$	98,907		$	104,736
Cash flows from investing activities	$	(79,696	)	$	(49,070	)	$	(42,599	)	$	(206,174	)	$	(142,051	)
Cash flows from financing activities	$	(110,466	)	$	(132,895	)	$	(119,682	)	$	105,584		$	35,856
EBITDA(2)	$	211,701		$	192,054		$	194,242		$	149,766		$	122,089
Distributable cash flow(3)	$	172,718		$	146,579		$	153,125		$	100,295		$	91,054
Maintenance capital expenditures(4)	$	4,616		$	8,683		$	5,649		$	5,415		$	4,487
Expansion capital expenditures	75,343			43,418			37,212			200,894			137,442
Total capital expenditures	$	79,959		$	52,101		$	42,861		$	206,309		$	141,929
Balance Sheet Data (at period end):
Net property, plant and equipment	$	980,479		$	957,814		$	960,499		$	683,793		$	553,233
Total assets	$	1,401,555		$	1,382,508		$	1,399,196		$	913,263		$	779,035
Long-term debt(5)	$	867,579		$	807,630		$	605,888		$	491,648		$	390,827
Total liabilities	$	986,111		$	915,574		$	661,518		$	548,402		$	425,633
Total equity(6)	$	415,444		$	466,934		$	737,678		$	364,861		$	353,402

(1) Net income is allocated between limited partners and the general partner interest in accordance with the provisions of the partnership agreement. Net income allocated to the general partner includes incentive distributions declared subsequent to quarter end. Net income attributable to the limited partners is divided by the weighted average limited partner units outstanding in computing the limited partners’ per unit interest in net income.

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(2) Earnings before interest, taxes, depreciation and amortization (“EBITDA”) is calculated as net income attributable to Holly Energy Partners plus (i) interest expense net of interest income, (ii) state income tax and (iii) depreciation and amortization excluding amounts related to previous owners (“Predecessor”). EBITDA is not a calculation based upon generally accepted accounting principles (“GAAP”). However, the amounts included in the EBITDA calculation are derived from amounts included in our consolidated financial statements, with the exception of EBITDA from discontinued operations. 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.

	Years Ended December 31,
	2014			2013			2012			2011			2010
	(In thousands)
Income from continuing operations attributable to HEP	$	105,525		$	79,449		$	94,152		$	79,799		$	56,323
Add (subtract):
Interest expense	34,280			44,041			40,141			34,706			30,453
Interest income	(3		)	(161		)	—			—			(7		)
Amortization of discount and deferred debt issuance costs	1,821			2,120			1,946			1,212			1,008
Loss on early extinguishment of debt	7,677			—			2,979			—			—
Amortization of unrealized loss attributable to discontinued cash flow hedge	—			849			5,095			41			2,540
State income tax	235			333			371			234			296
Depreciation and amortization	62,166			65,423			57,461			36,958			31,363
Predecessor depreciation and amortization	—			—			(7,903		)	(3,184		)	113
EBITDA	$	211,701		$	192,054		$	194,242		$	149,766		$	122,089

(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, maintenance capital expenditures and distributable cash flow from discontinued operations. 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 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.

	Years Ended December 31,
	2014			2013			2012			2011			2010
	(In thousands)
Income from continuing operations attributable to HEP	$	105,525		$	79,449		$	94,152		$	79,799		$	56,323
Add (subtract):
Depreciation and amortization	62,166			65,423			57,461			36,958			31,363
Predecessor depreciation and amortization	—			—			(7,903		)	(3,184		)	113
Amortization of discount and deferred debt issuance costs	1,821			2,120			1,946			1,212			1,008
Amortization of unrealized loss attributable to discontinued cash flow hedge	—			849			5,095			41			2,540
Loss on early extinguishment of debt	7,677			—			2,979			—			—
Increase (decrease) in deferred revenue related to minimum revenue commitments	(2,503		)	3,686			462			(6,405		)	2,035
Maintenance capital expenditures (4)	(4,616		)	(8,683		)	(5,649		)	(5,415		)	(4,487		)
Crude revenue settlement	—			918			3,670			(4,588		)	—
Other non-cash adjustments	2,648			2,817			912			1,877			2,159
Distributable cash flow	$	172,718		$	146,579		$	153,125		$	100,295		$	91,054

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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.

(5) Includes $571 million, $363 million, $200 million, $159 million and $206 million in Credit Agreement advances that were classified as long-term debt at December 31, 2014, 2013, 2012, 2011 and 2010, respectively.

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

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

This Item 7, including but not limited to the sections on “Liquidity and Capital Resources,” contains forward-looking statements. See “Forward-Looking Statements” at the beginning of Part I and Item 1A. “Risk Factors.” In this document, the words “we,” “our,” “ours” and “us” refer to HEP and its consolidated subsidiaries or to HEP or an individual subsidiary and not to any other person.

OVERVIEW

HEP is a Delaware limited partnership. 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’s refinery in Big Spring, Texas. At December 31, 2014, HFC owned a 39% interest in us including the 2% general partnership interest. Additionally, we own a 75% interest in UNEV, the owner of a pipeline running from Woods Cross, Utah to Las Vegas, Nevada and related products terminals and a 25% joint venture interest in the SLC Pipeline, a 95-mile intrastate crude oil pipeline system 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.

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

In March 2013, we closed on a public offering of 1,875,000 of our common units. Additionally, an affiliate of HFC, as a selling unitholder, closed on a public sale of 1,875,000 of its HEP common units for which we did not receive any proceeds. We used our net proceeds of $73.4 million to repay indebtedness incurred under our credit facility and for general partnership purposes. Amounts repaid under our credit facility may be reborrowed from time to time, and we intend to reborrow certain amounts to fund capital expenditures.

In March 2014, we redeemed the $150 million aggregate principal amount of 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 believe the growth of crude production in the Permian Basin and throughout the Mid-Continent and refining economics should support high utilization rates for the refineries we serve, which in turn will support volumes in our product pipelines, crude gathering system and terminals.

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UNEV Pipeline Interest Acquisition

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. However, to the extent earnings thresholds are not achieved, no redemption payments are required. Contemporaneously with this transaction, HFC (our general partner) agreed to forego its right to incentive distributions of up to $1.25 million per quarter over twelve consecutive quarterly periods following the closing of the transaction and up to an additional four quarters in certain circumstances. In connection with the transaction, we entered into 15-year throughput agreements with shippers containing minimum annual revenue commitments to us of $27 million.

Agreements with HFC and Alon

We serve HFC’s refineries under long-term pipeline and terminal, tankage and throughput agreements expiring from 2019 to 2026. Under these agreements, HFC agreed to transport, store and throughput volumes of refined product and crude oil on our pipelines and terminal, tankage and loading rack facilities that result in minimum annual payments to us. Additionally, such agreements require HFC to reimburse us for certain costs. These minimum annual payments or revenues are subject to annual tariff rate adjustments on July 1, based on the PPI or FERC index. As of December 31, 2014, these agreements with HFC will result in minimum annualized payments to us of $231.6 million.

If HFC fails to meet its minimum volume commitments under the agreements in any quarter, it will be required to pay us in cash the amount of any shortfall by the last day of the month following the end of the quarter. Under certain of the agreements, a shortfall payment may be applied as a credit in the following four quarters after minimum obligations are met.

We have a pipelines and terminals agreement with Alon expiring in 2020 under which Alon has agreed to transport on our pipelines and throughput through our terminals volumes of refined products that result in a minimum level of annual revenue that also is 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 lease agreement expire beginning in 2018 through 2022. As of December 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 the Omnibus Agreement that we have with HFC, we pay HFC an annual administrative fee ($2.3 million in 2014 and currently $2.4 million), for the provision by HFC of various general and administrative services to us on behalf of HLS. This fee does not include the salaries of personnel employed by HFC who perform services for us or the cost of their employee benefits, which are separately charged to us by HFC. We also reimburse HFC for direct expenses they incur on our behalf.

Under HLS’s secondment arrangement with HFC, certain employees of HFC are seconded to HLS to provide operational and maintenance services for certain of our pipelines and tankage assets at the El Dorado and Cheyenne refineries, and HLS reimburses HFC for its prorated portion of the wages, benefits, and other costs of these employees for our benefit.

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RESULTS OF OPERATIONS

Income, Distributable Cash Flow and Volumes

The following tables present income, distributable cash flow and volume information for the years ended December 31, 2014, 2013 and 2012.

	Years Ended December 31,						Change from
	2014			2013			2013
	(In thousands, except per unit data)
Revenues
Pipelines:
Affiliates—refined product pipelines	$	77,852		$	66,441		$	11,411
Affiliates—intermediate pipelines	29,813			25,397			4,416
Affiliates—crude pipelines	56,804			48,749			8,055
	164,469			140,587			23,882
Third parties—refined product pipelines	43,377			41,837			1,540
	207,846			182,424			25,422
Terminals, tanks and loading racks:
Affiliates	110,726			111,781			(1,055		)
Third parties	13,973			10,977			2,996
	124,699			122,758			1,941
Total revenues	332,545			305,182			27,363
Operating costs and expenses
Operations (exclusive of depreciation and amortization)	104,801			99,444			5,357
Depreciation and amortization	62,166			65,423			(3,257		)
General and administrative	10,824			11,749			(925		)
	177,791			176,616			1,175
Operating income	154,754			128,566			26,188
Equity in earnings of SLC Pipeline	2,987			2,826			161
Interest expense, including amortization	(36,101		)	(47,010		)	10,909
Interest income	3			161			(158		)
Loss on early extinguishment of debt	(7,677		)	—			(7,677		)
Gain on sale of assets	—			1,810			(1,810		)
Other	82			61			21
	(40,706		)	(42,152		)	1,446
Income before income taxes	114,048			86,414			27,634
State income tax	(235		)	(333		)	98
Net income	113,813			86,081			27,732
Allocation of net loss income attributable to noncontrolling interests	(8,288		)	(6,632		)	(1,656		)
Net income attributable to Holly Energy Partners	105,525			79,449			26,076
General partner interest in net income, including incentive distributions (1)	(34,667		)	(27,523		)	(7,144		)
Limited partners’ interest in net income	$	70,858		$	51,926		$	18,932
Limited partners’ earnings per unit—basic and diluted(1)	$	1.20		$	0.88		$	0.32
Weighted average limited partners’ units outstanding	58,657			58,246			411
EBITDA(2)	$	211,701		$	192,054		$	19,647
Distributable cash flow(3)	$	172,718		$	146,579		$	26,139
Volumes (bpd)
Pipelines:
Affiliates—refined product pipelines	119,156			107,493			11,663
Affiliates—intermediate pipelines	138,258			128,475			9,783
Affiliates—crude pipelines	199,600			161,391			38,209
	457,014			397,359			59,655
Third parties—refined product pipelines	64,055			63,337			718
	521,069			460,696			60,373
Terminals and loading racks:
Affiliates	261,888			255,108			6,780
Third parties	69,100			63,791			5,309
	330,988			318,899			12,089
Total for pipelines and terminal assets (bpd)	852,057			779,595			72,462

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	Years Ended December 31,						Change from
	2013			2012			2012
	(In thousands, except per unit data)
Revenues
Pipelines:
Affiliates—refined product pipelines	$	66,441		$	67,682		$	(1,241	)
Affiliates—intermediate pipelines	25,397			28,540			(3,143		)
Affiliates—crude pipelines	48,749			45,888			2,861
	140,587			142,110			(1,523		)
Third parties—refined product pipelines	41,837			37,521			4,316
	182,424			179,631			2,793
Terminals, tanks and loading racks:
Affiliates	111,781			103,472			8,309
Third parties	10,977			9,457			1,520
	122,758			112,929			9,829
Total revenues	305,182			292,560			12,622
Operating costs and expenses
Operations (exclusive of depreciation and amortization)	99,444			89,242			10,202
Depreciation and amortization	65,423			57,461			7,962
General and administrative	11,749			7,594			4,155
	176,616			154,297			22,319
Operating income	128,566			138,263			(9,697		)
Equity in earnings of SLC Pipeline	2,826			3,364			(538		)
Interest expense, including amortization	(47,010		)	(47,182		)	172
Interest income	161			—			161
Loss on early extinguishment of debt	—			(2,979		)	2,979
Gain on sale of assets	1,810			—			1,810
Other expense	61			10			51
	(42,152		)	(46,787		)	4,635
Income before income taxes	86,414			91,476			(5,062		)
State income tax	(333		)	(371		)	38
Net income	86,081			91,105			(5,024		)
Allocation of net loss attributable to Predecessors	—			4,200			(4,200		)
Allocation of net income attributable to noncontrolling interests	(6,632		)	(1,153		)	(5,479		)
Net income attributable to Holly Energy Partners	79,449			94,152			(14,703		)
General partner interest in net income, including incentive distributions (1)	(27,523		)	(22,450		)	(5,073		)
Limited partners’ interest in net income	$	51,926		$	71,702		$	(19,776	)
Limited partners’ earnings per unit—basic and diluted(1)	$	0.88		$	1.29		$	(0.41	)
Weighted average limited partners’ units outstanding	58,246			55,696			2,550
EBITDA(2)	$	192,054		$	194,242		$	(2,188	)
Distributable cash flow(3)	$	146,579		$	153,125		$	(6,546	)
Volumes (bpd)
Pipelines:
Affiliates—refined product pipelines	107,493			107,509			(16		)
Affiliates—intermediate pipelines	128,475			127,169			1,306
Affiliates—crude pipelines	161,391			171,040			(9,649		)
	397,359			405,718			(8,359		)
Third parties—refined product pipelines	63,337			63,152			185
	460,696			468,870			(8,174		)
Terminals and loading racks:
Affiliates	255,108			271,549			(16,441		)
Third parties	63,791			53,456			10,335
	318,899			325,005			(6,106		)
Total for pipelines and terminal assets (bpd)	779,595			793,875			(14,280		)

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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, excluding amounts related to Predecessor. EBITDA is not a calculation based upon GAAP. However, the amounts included in the EBITDA calculation are derived from amounts included in our consolidated financial statements, with the exception of EBITDA from discontinued operations. 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. See our calculation of EBITDA under Item 6, “Selected Financial Data.”

(3) Distributable cash flow is not a calculation based upon GAAP. However, the amounts included in the calculation are derived from amounts presented in our consolidated financial statements, with the general exceptions of a billed crude revenue settlement, maintenance capital expenditures and distributable cash flow from discontinued operations. 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. See our calculation of distributable cash flow under Item 6, “Selected Financial Data.”

Results of Operations — Year Ended December 31, 2014 Compared with Year Ended December 31, 2013

Summary

Net income attributable to HEP for the year ended December 31, 2014, was $105.5 million, a $26.1 million increase compared to the year ended December 31, 2013. This increase in earnings is due principally to higher pipeline and terminal volumes and annual tariff increases, as well as decreased interest expense due to the early retirement of our 8.25% Senior Notes in March 2014.

Revenues for the year ended December 31, 2014, include the recognition of $12.0 million of prior shortfalls billed to shippers in 2013. As of December 31, 2014, deferred revenue on our consolidated balance sheet related to shortfalls billed was $9.3 million. Such deferred revenue will be recognized in earnings either as (a) payment for shipments in excess of guaranteed levels, if and to the extent the pipeline system will have the necessary capacity to provide for shipments in excess of guaranteed levels, or (b) when shipping rights expire unused over the contractual make-up period.

Revenues

Total revenues for the year ended December 31, 2014, were $332.5 million, a $27.4 million increase compared to the year ended December 31, 2013. The revenue increase was due to the effect of annual tariff increases, increased pipeline shipments and a $4.2 million increase in previously deferred revenue realized. Overall pipeline volumes were up 13% compared to the year ended December 31, 2013, largely due to low volumes in 2013 resulting from a major maintenance turnaround at HFC's Navajo refinery in the first quarter of 2013 as well as the reduced crude throughput at HFC's Navajo refinery during the fourth quarter of 2013.

Revenues from our refined product pipelines were $121.2 million, an increase of $13.0 million compared to the year ended December 31, 2013, primarily due to increased volumes and the effect of a $2.1 million increase in deferred revenue realized. Shipments averaged 183.2 thousand barrels per day (“mbpd”) compared to 170.8 mbpd for 2013.

Revenues from our intermediate pipelines were $29.8 million, an increase of $4.4 million on shipments averaging 138.3 mbpd compared to 128.5 mbpd for the year ended December 31, 2013. The increase in revenue is due to the effects of a $2.2 million increase in deferred revenue realized and increased volumes on intermediate pipeline segments.

Revenues from our crude pipelines were $56.8 million, an increase of $8.1 million on shipments averaging 199.6 mbpd compared to 161.4 mbpd for the year ended December 31, 2013. Revenues increased due to the annual tariff increases and higher volumes

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resulting from the New Mexico gathering system expansion. In addition, volumes were lower in 2013 due to the turnaround at HFC's Navajo refinery and the fourth quarter 2013 processing constraints at HFC's Navajo refinery.

Revenues from terminal, tankage and loading rack fees were $124.7 million, an increase of $1.9 million compared to the year ended December 31, 2013. The increase in revenues is due principally to increased volumes. Refined products terminalled in our facilities increased to an average of 331.0 mbpd compared to 318.9 mbpd for 2013.

Operations Expense

Operations expense for the year ended December 31, 2014, increased by $5.4 million compared to the year ended December 31, 2013. This increase is due to higher maintenance costs and environmental accruals.

Depreciation and Amortization

Depreciation and amortization for the year ended December 31, 2014, decreased by $3.3 million compared to the year ended December 31, 2013, due principally to lower asset abandonment charges related to tankage permanently removed from service.

General and Administrative

General and administrative costs for the year ended December 31, 2014, decreased by $0.9 million compared to the year ended December 31, 2013, due to lower costs for professional services.

Equity in Earnings of SLC Pipeline

Our equity in earnings of the SLC Pipeline was $3.0 million and $2.8 million for the years ended December 31, 2014 and 2013.

Interest Expense

Interest expense for the year ended December 31, 2014, totaled $36.1 million, a decrease of $10.9 million compared to the year ended December 31, 2013. Our aggregate effective interest rate was 4.3% and 5.7% for the years ended December 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 for the year ended December 31, 2014. This charge related to 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 year ended December 31, 2013, of $1.8 million is comprised of a gain of $2.0 million on the sale of property in El Paso, Texas, partially offset by a $0.2 million loss from the sale of our 50% ownership interest in product terminals located in Boise and Burley, Idaho.

State Income Tax

We recorded state income tax expense of $235,000 and $333,000 for the years ended December 31, 2014 and 2013, respectively, which is solely attributable to the Texas margin tax. Due to a statutory change in June 2013, there was a one-time charge of $366,000 to establish a deferred tax liability. We are subject to the Texas margin tax based on our Texas sourced taxable margin. 

Results of Operations—Year Ended December 31, 2013 Compared with Year Ended December 31, 2012

Summary

Net income attributable to HEP for the year ended December 31, 2013, was $79.4 million, a $14.7 million decrease compared to the year ended December 31, 2012. This decrease in earnings is due principally to increased operating costs and expenses, including higher depreciation resulting from asset abandonment charges related to tankage permanently removed from service, combined with higher allocations of income to noncontrolling interests. Overall revenues increased but did not keep pace with the cost increases as pipeline volumes supporting HFC's Navajo refinery were reduced in 2013 as the refinery experienced a planned turnaround in the first quarter and unplanned refinery downtime in the fourth quarter. Limited partners' per unit interest in earnings decreased from $1.29 per unit in 2012 to $0.88 per unit in 2013 due to the income decreases combined with higher incentive distributions to the general partner.

Revenues for the year ended December 31, 2013, include the recognition of $7.8 million of prior shortfalls billed to shippers in 2012. As of December 31, 2013, deferred revenue on our consolidated balance sheet related to shortfalls billed was $12.0 million.

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Revenues

Total revenues for the year ended December 31, 2013, were $305.2 million, a $12.6 million increase compared to the year ended December 31, 2012. The revenue increase was due to the effect of annual tariff increases, higher cost reimbursement receipts from HFC and a $1.5 million increase in previously deferred revenue realized. Overall pipeline volumes were down 2% compared to the year ended December 31, 2012.

Revenues from our refined product pipelines were $108.3 million, an increase of $3.1 million compared to the year ended December 31, 2012, primarily due to the effects of a $3.3 million increase in previously deferred revenue realized and annual tariff increases. Shipments averaged 170.8 mbpd compared to 170.7 mbpd for 2012.

Revenues from our intermediate pipelines were $25.4 million, a decrease of $3.1 million on shipments averaging 128.5 mbpd compared to 127.2 mbpd for the year ended December 31, 2012. The decrease in revenue is due to the effects of a $1.8 million decrease in deferred revenue realized and reduced volumes on certain high tariff pipeline segments.

Revenues from our crude pipelines were $48.7 million, an increase of $2.9 million on shipments averaging 161.4 mbpd compared to 171.0 mbpd for the year ended December 31, 2012. Although crude oil pipeline shipments were down, revenues increased due to the annual tariff increases and minimum billings on certain pipeline segments.

Revenues from terminal, tankage and loading rack fees were $122.8 million, an increase of $9.8 million compared to year ended December 31, 2012. The increase in revenues is due to annual fee increases and higher tank cost reimbursement receipts from HFC. Refined products terminalled in our facilities decreased to an average of 318.9 mbpd compared to 325.0 mbpd for 2012.

Operations Expense

Operations expense for the year ended December 31, 2013, increased by $10.2 million compared to the year ended December 31, 2012. This increase is due to higher maintenance costs, environmental accruals, employee costs and property taxes, offset by a $3.5 million net tax refund related to payroll costs covering a multi-year period.

Depreciation and Amortization

Depreciation and amortization for the year ended December 31, 2013, increased by $8.0 million compared to the year ended December 31, 2012 due principally to asset abandonment charges related to tankage permanently removed from service.

General and Administrative

General and administrative costs for the year ended December 31, 2013, increased by $4.2 million compared to the year ended December 31, 2012, due to increased employee costs.

Equity in Earnings of SLC Pipeline

Our equity in earnings of the SLC Pipeline was $2.8 million and $3.4 million for the years ended December 31, 2013 and 2012, respectively.

Interest Expense

Interest expense for the year ended December 31, 2013, totaled $47.0 million, a decrease of $0.2 million compared to the year ended December 31, 2012. Our aggregate effective interest rate was 5.7% and 6.5% for the years ended December 31, 2013 and 2012, respectively.

Loss on Early Extinguishment of Debt

We recognized a charge of $3.0 million upon the early extinguishment of our 6.25% Senior Notes ("6.25% Senior Notes") for the year ended December 31, 2012. This charge related to the premium paid to noteholders upon their tender of an aggregate principal amount of $185.0 million and related financing costs that were previously deferred.

Gain on Sale of Assets

The gain on the sale of assets for the year ended December 31, 2013, of $1.8 million is comprised of a gain of $2.0 million on the sale of property in El Paso, Texas, partially offset by a $0.2 million loss from the sale of our 50% ownership interest in product terminals located in Boise and Burley, Idaho.

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State Income Tax

We recorded state income tax expense of $333,000 and $371,000 for the years ended December 31, 2013 and 2012, respectively, which is solely attributable to the Texas margin tax. We are subject to the Texas margin tax based on our Texas sourced taxable margin.  Due to a statutory change that was enacted in June 2013, we are now able to deduct additional expenses which will result in lower cash taxes to HEP in the current and future years. 

LIQUIDITY AND CAPITAL RESOURCES

Overview

Our $650 million senior secured revolving credit facility (the "Credit Agreement") expires in November 2018 and 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.

During the year ended December 31, 2014, we received advances totaling $642.3 million and repaid $434.3 million, resulting in a net increase of $208.0 million under the Credit Agreement and an outstanding balance of $571.0 million at December 31, 2014. We have no letters of credit outstanding under the Credit Agreement at December 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.

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

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

In February, May, August and November 2014, we paid regular quarterly cash distributions of $0.5000, $0.5075, $0.5150 and $0.5225, respectively, on all units in an aggregate amount of $154.7 million. Included in this aggregate amount were $31.5 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 $3.5 million during the year ended December 31, 2014. The cash flows provided by operating activities of $186.6 million were less than the cash flows used for financing and investing activities of $110.5 million and $79.7 million, respectively. Working capital increased by $9.7 million to $3.1 million at December 31, 2014 from a deficit of $6.6 million at December 31, 2013.

Cash Flows—Operating Activities

Year Ended December 31, 2014 Compared with Year Ended December 31, 2013

Cash flows from operating activities increased by $3.6 million from $183.1 million for the year ended December 31, 2013, to $186.6 million for the year ended December 31, 2014. This increase is due principally to $12.1 million of greater cash receipts for services performed in the year ended December 31, 2014, as compared to the prior year, partially offset by payments made for increased operating expenses.

Our major shippers are obligated to make deficiency payments to us if they do not meet their minimum volume shipping obligations. Under certain agreements with these shippers, they have the right to recapture these amounts if future volumes exceed minimum levels. We billed $12.0 million during the year ended December 31, 2013, related to shortfalls that subsequently expired without recapture and were recognized as revenue during the year ended December 31, 2014. Another $9.3 million is included as deferred revenue on our balance sheet at December 31, 2014, related to shortfalls billed during the year ended December 31, 2014.

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Year Ended December 31, 2013 Compared with Year Ended December 31, 2012

Cash flows from operating activities increased by $21.9 million from $161.1 million for the year ended December 31, 2012, to $183.1 million for the year ended December 31, 2013. This increase is due principally to $30.7 million of greater cash receipts for services performed in the year ended December 31, 2013, as compared to the prior year, partially offset by payments made for increased operating expenses.

We billed $9.3 million during the year ended December 31, 2012, related to shortfalls that subsequently expired without recapture and were recognized as revenue during the year ended December 31, 2013. Another $12.0 million was included in our accounts receivable at December 31, 2013 related to shortfalls that occurred during the year ended December 31, 2013

Cash Flows—Investing Activities

Year Ended December 31, 2014 Compared with Year Ended December 31, 2013

Cash flows used for investing activities increased by $30.6 million from $49.1 million for the year ended December 31, 2013, to $79.7 million for the year ended December 31, 2014. During the years ended December 31, 2014 and 2013, we invested $80.0 million and $52.1 million in additions to properties and equipment, respectively. During the year ended December 31, 2013, we received $2.7 million proceeds from the sale of assets.

Year Ended December 31, 2013 Compared with Year Ended December 31, 2012

Cash flows used for investing activities increased by $6.5 million from $42.6 million for the year ended December 31, 2012 to $49.1 million for the year ended December 31, 2013. During the years ended December 31, 2013 and 2012, we invested $52.1 million and $42.9 million in additions to properties and equipment, respectively. During the year ended December 31, 2013, we received $2.7 million proceeds from the sale of assets. Distributions in excess of equity in earnings of the SLC Pipeline was $0.3 million for the years ended December 31, 2013 and 2012.

Cash Flows—Financing Activities

Year Ended December 31, 2014 Compared with Year Ended December 31, 2013

Cash flows used for financing activities were $110.5 million for the year ended December 31, 2014, compared to $132.9 million for the year ended December 31, 2013, a decrease of $22.4 million. During the year ended December 31, 2014, we received $642.3 million and repaid $434.3 million in advances under the Credit Agreement and paid $156.2 million to redeem the 8.25% Senior Notes. Additionally, we paid $154.7 million in regular quarterly cash distributions to our general and limited partners, paid $4.0 million to our noncontrolling interest and paid $3.6 million for the purchase of common units for recipients of our incentive grants. During the year ended December 31, 2013, we received $310.6 million and repaid $368.6 million in advances under the Credit Agreement and received net proceeds of $73.4 million from the common unit public offering. We paid $139.5 million in regular quarterly cash distributions to our general and limited partners, and paid $3.1 million to our noncontrolling interest. We received $1.5 million from our general partner, paid $1.3 million in financing costs to amend our Credit Agreement and paid $5.6 million for the purchase of common units for recipients of our incentive grants.

Year Ended December 31, 2013 Compared with Year Ended December 31, 2012

Cash flows used for financing activities were $132.9 million for the year ended December 31, 2013, compared to $119.7 million for the year ended December 31, 2012, an increase of $13.2 million. During the year ended December 31, 2013, we received $310.6 million and repaid $368.6 million in advances under the Credit Agreement, received net proceeds of $73.4 million from the common unit public offering and $1.5 million from the general partner to maintain its 2% interest. Additionally, we paid $139.5 million in regular quarterly cash distributions to our general and limited partners, and paid $5.6 million for the purchase of common units for recipients of our incentive grants. Also, we paid $3.1 million to our noncontrolling interest and paid $1.3 million in financing costs to amend our Credit Facility. During the year ended December 31, 2012, we received $587.0 million and repaid $366.0 million in advances under the Credit Agreement, received net proceeds of $294.8 million from the issuance of our 6.5% Senior Notes and repaid $260.2 million of our notes. We paid HFC $260.9 million as partial consideration for the acquisition of HFC's 75% interest in UNEV. Additionally, we paid $122.8 million in regular quarterly cash distributions to our general and limited partners, we received $15.0 million from our noncontrolling interest, received $1.8 million from our general partner, paid $3.2 million in financing costs to amend our Credit Agreement and paid $4.9 million for the purchase of common units for recipients of our incentive grants.

Capital Requirements

Our pipeline and terminalling operations are capital intensive, requiring investments to maintain, expand, upgrade or enhance existing operations and to meet environmental and operational regulations. Our capital requirements have consisted of, and are expected to continue to consist of, maintenance capital expenditures and expansion capital expenditures. “Maintenance capital expenditures” represent capital expenditures to replace partially or fully depreciated assets to maintain the operating capacity of existing assets. Maintenance capital expenditures include expenditures required to maintain equipment reliability, tankage and

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pipeline integrity, safety and to address environmental regulations. “Expansion capital expenditures” represent capital expenditures to expand the operating capacity of existing or new assets, whether through construction or acquisition. Expansion capital expenditures include expenditures to acquire assets, to grow our business and to expand existing facilities, such as projects that increase throughput capacity on our pipelines and in our terminals. Repair and maintenance expenses associated with existing assets that are minor in nature and do not extend the useful life of existing assets are charged to operating expenses as incurred.

Each year the board of directors of HLS 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 2015 capital budget is comprised of $9.7 million for maintenance capital expenditures and $77.7 million for expansion capital expenditures. We expect the majority of the expansion capital budget to be invested in crude storage for HFC's El Dorado refinery, product distribution enhancements, new storage tanks, and an additional UNEV origin connection. In addition to our capital budget, we may spend funds periodically to perform capital upgrades or additions to our assets where a customer reimburses us for such costs. The upgrades or additions would generally benefit the customer over the remaining life of the related service agreements.

We substantially completed the expansion of our crude oil transportation system in southeastern New Mexico in the third quarter of 2014 in response to increased crude oil production in the area. The expansion provides 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 converted an existing refined products pipeline to crude oil service, constructed several new pipeline segments, expanded an existing pipeline, and built new truck unloading stations and crude storage capacity. Excluding the value of the existing pipeline converted, total capital expenditures were approximately $50 million. HFC has contracted to reimburse us for the increase over the original budget range of $35 million to $40 million 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.

UNEV completed a project to enhance its product terminal in Las Vegas, Nevada in the third quarter of 2014 with total capital expenditures of approximately $15 million.

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 have received engineering estimates for this potential project. Alternatively, we are evaluating the potential purchase of existing tanks.

We expect that our currently planned 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.

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

Our $650.0 million senior secured revolving credit facility expires in November 2018 (the “Credit Agreement”) and 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 is recourse to 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.

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Indebtedness under the Credit Agreement bears interest, at our option, at either (a) the reference rate as announced by the administrative agent plus an applicable margin (ranging from 0.625% to 1.50%) or (b) at a rate equal to the London Interbank Offered Rate ("LIBOR") plus an applicable margin (ranging from 1.625% to 2.50%). In each case, the applicable margin is based upon the ratio of our funded debt (as defined in the Credit Agreement) to EBITDA (earnings before interest, taxes, depreciation and amortization, as defined in the Credit Agreement). We incur a commitment fee on the unused portion of the Credit Agreement at an annual rate ranging from 0.30% to 0.45% based upon the ratio of our funded debt to EBITDA for the four most recently completed fiscal quarters.

The Credit Agreement imposes certain requirements on us with which we are currently in compliance, 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 our 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 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 is recourse to HEP Logistics, our general partner, and is guaranteed by our material, 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.

Our purchase and contribution agreements with HFC with respect to the intermediate pipelines acquired in 2005 and the crude pipelines and tankage assets acquired in 2008, restrict us from selling these pipelines and terminals acquired from HFC. Under these agreements, we are restricted from prepaying borrowings and long-term debt to outstanding balances below $206 million prior to 2015 and $171 million prior to 2018, subject to certain limited exceptions.

Long-term Debt

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

	December 31, 2014			December 31, 2013
	(In thousands)
Credit Agreement	$	571,000		$	363,000
6.5% Senior Notes
Principal	300,000			300,000
Unamortized discount	(3,421		)	(4,073		)
	296,579			295,927
8.25% Senior Notes
Principal	—			150,000
Unamortized discount	—			(1,297		)
	—			148,703
Total long-term debt	$	867,579		$	807,630

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

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Long-term Contractual Obligations

The following table presents our long-term contractual obligations as of December 31, 2014.

			Payments Due by Period
	Total		Less than 1 Year		1-3 Years		3-5 Years		Over 5 Years
	(In thousands)
Long-term debt – principal	$	871,000	$	—	$	—	$	571,000	$	300,000
Long-term debt - interest	156,795		31,886		63,773		51,386		9,750
Pipeline operating lease	16,770		6,708		10,062		—		—
Right-of-way leases	1,202		220		400		316		266
Other	13,823		1,785		3,388		2,356		6,294
Total	$	1,059,590	$	40,599	$	77,623	$	625,058	$	316,310

Long-term debt consists of outstanding principal under the Credit Agreement and 6.5% Senior Notes. Interest on the credit agreement is calculated using the rate in effect at December 31, 2014.

The pipeline operating lease amounts above reflect the exercise of the 10-year extension, expiring in 2017, on our lease agreement for the refined products pipeline between White Lakes Junction and Kuntz Station in New Mexico.

Most of our right-of-way agreements are renewable on an annual basis, and the right-of-way lease payments above include only obligations under the remaining non-cancelable terms of these agreements at December 31, 2014. For the foreseeable future, we intend to continue renewing these agreements and expect to incur right-of-way expenses in addition to the payments listed.

Other contractual obligations consist of site service agreements with HFC, expiring in 2024 through 2026, for the provision of certain facility services and utility costs that relate to our assets located at HFC’s refinery facilities.

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 years ended December 31, 2014, 2013 and 2012. Historically, the PPI has increased an average of 2.2% annually over the past five 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 storage and transportation of refined products 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. Although these laws and regulations affect our maintenance capital expenditures and net income, we do not believe they affect our competitive position as the operations of our competitors are similarly affected. We believe that our operations are in substantial compliance with applicable environmental laws and regulations. However, these laws and regulations, and the interpretation or enforcement thereof, are subject to frequent change by regulatory authorities, and we are unable to predict the ongoing cost to us of complying with these laws and regulations or the future impact of these laws and regulations on our operations. Violation of environmental laws, regulations, and permits can result in the imposition of significant administrative, civil and criminal penalties, injunctions, and construction bans or delays. A discharge of hydrocarbons or hazardous substances into the environment could, to the extent the event is not insured, subject us to substantial expense, including both the cost to comply with applicable laws and regulations and claims made by employees, neighboring landowners and other third parties for personal injury and property damage.

Contamination resulting from spills of refined products and crude oil is not unusual within the petroleum pipeline industry. Historic spills along our existing pipelines and terminals as a result of past operations have resulted in contamination of the environment, including soils and groundwater. Site conditions, including soils and groundwater, are being evaluated at a few of our properties where operations may have resulted in releases of hydrocarbons and other wastes, none of which we believe will have a significant

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effect on our operations since the remediation of such releases would be covered under environmental indemnification agreements. For example, 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. In addition, under the Omnibus Agreement and certain transportation agreements and purchase agreements with HFC, HFC has agreed to indemnify us, subject to certain monetary and time limitations, for environmental noncompliance and remediation liabilities associated with certain assets transferred to us from HFC and occurring or existing prior to the date of such transfers. There are environmental remediation projects 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 for future remediation activities retained by HFC. Additionally, as of December 31, 2014, we have an accrual of $5.2 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. We consider the following policies to be the most critical to understanding the judgments that are involved and the uncertainties that could impact our results of operations, financial condition and cash flows.

Revenue Recognition

Revenues are recognized as products are shipped through our pipelines and terminals. Additional pipeline transportation revenues result from an operating lease by Alon USA, L.P. of an interest in the capacity of one of our pipelines.

Billings to customers for their obligations under their quarterly minimum revenue commitments are recorded as deferred revenue liabilities if the customer has the right to receive future services for these billings. The revenue is recognized at the earlier of:

• the customer receiving the future services provided by these billings,

• the period in which the customer is contractually allowed to receive the services expires, or

• our determination that we will not be required to provide services within the allowed period.

We determine that we will not be required to provide services within the allowed period when, based on current and projected shipping levels, our pipeline systems will not have the necessary capacity to enable a customer to exceed its minimum volume levels to such a degree as to utilize the shortfall credit within its respective contractual shortfall make-up period.

Goodwill and Long-Lived Assets

Goodwill represents the excess of our cost of an acquired business over the fair value of the assets acquired, less liabilities assumed. Goodwill is not amortized and is tested for impairment annually or more frequently if events or changes in circumstances indicate goodwill may be impaired. We test goodwill at the reporting unit level for impairment annually and between annual tests if events or changes in circumstances indicate the carrying amount may exceed fair value. Recoverability is determined by comparing the estimated fair value of a reporting unit to the carrying value, including the related goodwill, of that reporting unit. We use the present value of the expected future net cash flows and market multiple analyses to determine the estimated fair values of the reporting units. The impairment test requires the use of projections, estimates and assumptions as to the future performance of our operations. Actual results could differ from projections resulting in revisions to our assumptions, and if required, recognizing an impairment loss.

We evaluate long-lived assets, including finite-lived intangible assets, for potential impairment by identifying whether indicators of impairment exist and, if so, assessing whether the long-lived assets are recoverable from estimated future undiscounted cash flows. The actual amount of impairment loss, if any, to be recorded is equal to the amount by which a long-lived asset’s carrying value exceeds its fair value.

There have been no impairments to goodwill or our long-lived assets as of December 31, 2014.

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Contingencies

It is common in our industry to be subject to proceedings, lawsuits and other claims related to environmental, labor, product and other matters. We are required to assess the likelihood of any adverse judgments or outcomes to these types of matters as well as potential ranges of probable losses. A determination of the amount of reserves required, if any, for these types of contingencies is made after careful analysis of each individual issue. The required reserves may change in the future due to developments in each matter or changes in approach such as a change in settlement strategy in dealing with these potential matters.

New Accounting Pronouncements

Revenue Recognition

In May 2014, an accounting standard update (ASU 2014-09, "Revenue from Contracts with Customers") was issued requiring revenue to be recognized when promised goods or services are transferred to customers in an amount that reflects the expected consideration for these goods or services. This standard is effective January 1, 2017, and we are evaluating the impact of this standard.

RISK MANAGEMENT

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

As of December 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 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 December 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 $150.0 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 December 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 December 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 6.5% Senior Notes, but not our earnings or cash flows. At December 31, 2014, the fair value of our 6.5% Senior Notes was $291.0 million. We estimate a hypothetical 10% change in the yield-to-maturity applicable to the 6.5% Senior Notes at December 31, 2014, would result in a change of approximately $8.5 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 December 31, 2014, borrowings outstanding under the Credit Agreement were $571.0 million. By means of our cash flow hedges, we have effectively converted the variable rate on $305.0 million of outstanding borrowings to a fixed rate. For the remaining unhedged Credit Agreement borrowings of $266.0 million, a hypothetical 10% change in interest rates applicable to the Credit Agreement would not materially affect our cash flows.

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

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

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Item 7A. 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. 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.

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Item 8. Financial Statements and Supplementary Data

MANAGEMENT’S REPORT ON ITS ASSESSMENT OF THE PARTNERSHIP’S INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of Holly Energy Partners, L.P. (the “Partnership”) is responsible for establishing and maintaining adequate internal control over financial reporting.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Management assessed the Partnership’s internal control over financial reporting as of December 31, 2014, using the criteria for effective control over financial reporting established in “Internal Control – Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework). Based on this assessment, management concluded that, as of December 31, 2014, the Partnership maintained effective internal control over financial reporting.

The Partnership’s independent registered public accounting firm has issued an attestation report on the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2014. That report appears on page 55.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors of Holly Logistic Services, L.L.C. and

Unitholders of Holly Energy Partners, L.P.

We have audited Holly Energy Partners, L.P.’s (the "Partnership") internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). Holly Energy Partners, L.P.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on its Assessment of the Partnership’s Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Holly Energy Partners, L.P. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Holly Energy Partners, L.P. as of December 31, 2014 and 2013, and the related consolidated statements of income, comprehensive income, cash flows, and partners’ equity for each of the three years in the period ended December 31, 2014, and our report dated February 25, 2015, expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Dallas, Texas

February 25, 2015

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Index to Consolidated Financial Statements

	Page Reference
Report of Independent Registered Public Accounting Firm	57
Consolidated Balance Sheets as of December 31, 2014 and 2013	58
Consolidated Statements of Income for the years ended December 31, 2014, 2013 and 2012	59
Consolidated Statements of Comprehensive Income for the years ended December 31, 2014, 2013 and 2012	60
Consolidated Statements of Cash Flows for the years ended December 31, 2014, 2013 and 2012	61
Consolidated Statements of Partners’ Equity for the years ended December 31, 2014, 2013 and 2012	62
Notes to Consolidated Financial Statements	63

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors of Holly Logistic Services, L.L.C. and

Unitholders of Holly Energy Partners, L.P.

We have audited the accompanying consolidated balance sheets of Holly Energy Partners, L.P. (the “Partnership”) as of December 31, 2014 and 2013, and the related consolidated statements of income, comprehensive income, cash flows, and partners’ equity for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Holly Energy Partners, L.P. at December 31, 2014 and 2013, and the consolidated results of its operations and its cash flows, for each of the three years in the period ended December 31, 2014, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Holly Energy Partners, L.P.’s internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013framework) and our report dated February 25, 2015 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Dallas, Texas

February 25, 2015

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HOLLY ENERGY PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(in thousands, except unit data)  

	December 31, 2014			December 31, 2013
ASSETS
Current assets:
Cash and cash equivalents	$	2,830		$	6,352
Accounts receivable:
Trade	6,737			5,061
Affiliates	33,392			29,675
	40,129			34,736
Prepaid and other current assets	4,383			3,874
Total current assets	47,342			44,962
Properties and equipment, net	980,479			957,814
Transportation agreements, net	80,703			87,650
Goodwill	256,498			256,498
Investment in SLC Pipeline	24,478			24,741
Other assets	12,055			10,843
Total assets	$	1,401,555		$	1,382,508
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	12,642		$	14,414
Affiliates	5,239			8,484
	17,881			22,898
Accrued interest	6,615			10,239
Deferred revenue	12,432			13,981
Accrued property taxes	2,703			2,603
Other current liabilities	4,571			1,845
Total current liabilities	44,202			51,566
Long-term debt	867,579			807,630
Other long-term liabilities	18,145			14,585
Deferred revenue	29,392			21,669
Class B unit	26,793			20,124
Equity:
Partners’ equity:
Common unitholders (58,657,048 units issued and outstanding     at December 31, 2014 and 2013)	468,813			516,147
General partner interest (2% interest)	(148,405		)	(146,557		)
Accumulated other comprehensive loss	(46		)	(144		)
Total partners’ equity	320,362			369,446
Noncontrolling interest	95,082			97,488
Total equity	415,444			466,934
Total liabilities and equity	$	1,401,555		$	1,382,508

See accompanying notes.

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HOLLY ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except per unit data) 

	Years Ended December 31,
	2014			2013			2012
Revenues:
Affiliates	$	275,196		$	252,368		$	245,582
Third parties	57,349			52,814			46,978
	332,545			305,182			292,560
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	104,801			99,444			89,242
Depreciation and amortization	62,166			65,423			57,461
General and administrative	10,824			11,749			7,594
	177,791			176,616			154,297
Operating income	154,754			128,566			138,263
Other income (expense):
Equity in earnings of SLC Pipeline	2,987			2,826			3,364
Interest expense	(36,101		)	(47,010		)	(47,182		)
Interest income	3			161			—
Loss on early extinguishment of debt	(7,677		)	—			(2,979		)
Gain on sale of assets	—			1,810			—
Other income	82			61			10
	(40,706		)	(42,152		)	(46,787		)
Income before income taxes	114,048			86,414			91,476
State income tax expense	(235		)	(333		)	(371		)
Net income	113,813			86,081			91,105
Allocation of net loss attributable to Predecessors	—			—			4,200
Allocation of net income attributable to noncontrolling interests	(8,288		)	(6,632		)	(1,153		)
Net income attributable to Holly Energy Partners	105,525			79,449			94,152
General partner interest in net income, including incentive distributions	(34,667		)	(27,523		)	(22,450		)
Limited partners’ interest in net income	$	70,858		$	51,926		$	71,702
Limited partners’ per unit interest in earnings—basic and diluted	$	1.20		$	0.88		$	1.29
Weighted average limited partners’ units outstanding	58,657			58,246			55,696

See accompanying notes.

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HOLLY ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In thousands)

	Years Ended December 31,
	2014			2013			2012
Net income	$	113,813		$	86,081		$	91,105
Other comprehensive income:
Change in fair value of cash flow hedging instruments	(2,104		)	1,194			(4,418		)
Amortization of unrealized loss attributable to discontinued cash flow hedge	—			849			5,095
Reclassification adjustment to net income on partial settlement of cash flow hedge	2,202			2,092			1,508
Other comprehensive income	98			4,135			2,185
Comprehensive income before noncontrolling interest	113,911			90,216			93,290
Allocation of comprehensive income to noncontrolling interests	(8,288		)	(6,632		)	(1,153		)
Allocation of net loss attributable to Predecessors	—			—			4,200
Comprehensive income attributable to Holly Energy Partners	$	105,623		$	83,584		$	96,337

See accompanying notes.

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HOLLY ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)     

	Years Ended December 31,
	2014			2013			2012
Cash flows from operating activities
Net income	$	113,813		$	86,081		$	91,105
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	62,166			65,423			57,461
Gain on sale of assets	—			(1,810		)	—
Amortization of deferred charges	1,820			2,970			7,556
Amortization of restricted and performance units	3,539			3,575			2,858
Loss on early extinguishment of debt	7,677			—			2,979
(Increase) decrease in operating assets:
Accounts receivable—trade	(1,676		)	2,065			(3,997		)
Accounts receivable—affiliates	(3,717		)	1,919			(135		)
Prepaid and other current assets	(510		)	(255		)	110
Increase (decrease) in operating liabilities:
Accounts payable—trade	2,469			3,365			(9,003		)
Accounts payable—affiliates	(3,245		)	3,821			(1,811		)
Accrued interest	(3,624		)	13			1,945
Deferred revenue	6,173			15,255			11,333
Accrued property taxes	100			(85		)	492
Other current liabilities	1,819			(45		)	113
Other, net	(164		)	788			143
Net cash provided by operating activities	186,640			183,080			161,149
Cash flows from investing activities
Additions to properties and equipment	(79,959		)	(52,101		)	(42,861		)
Proceeds from sale of assets	—			2,731			—
Distributions in excess of equity in earnings in SLC pipeline	263			300			262
Net cash used for investing activities	(79,696		)	(49,070		)	(42,599		)
Cash flows from financing activities
Borrowings under credit agreement	642,300			310,600			587,000
Repayments of credit agreement borrowings	(434,300		)	(368,600		)	(366,000		)
Proceeds from issuance of senior notes	—			—			294,750
Proceeds from issuance of common units	—			73,444			—
Cash distribution to HFC for UNEV acquisition	—			—			(260,922		)
Redemption of senior notes	(156,188		)	—			(260,235		)
Contributions from noncontrolling interests	—			—			15,000
Contributions from general partner	—			1,499			1,748
Distributions to HEP unitholders	(154,670		)	(139,486		)	(122,777		)
Distributions to noncontrolling interest	(4,025		)	(3,125		)	—
Purchase of units for incentive grants	(3,577		)	(5,634		)	(4,919		)
Deferred financing costs	—			(1,344		)	(3,238		)
Other	(6		)	(249		)	(89		)
Net cash used by financing activities	(110,466		)	(132,895		)	(119,682		)
Cash and cash equivalents
Increase (decrease) for the year	(3,522		)	1,115			(1,132		)
Beginning of year	6,352			5,237			6,369
End of year	$	2,830		$	6,352		$	5,237

See accompanying notes.

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HOLLY ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF PARTNERS' EQUITY

(In thousands)

	Holly Energy Partners, L.P. Partners’ Equity (Deficit):
	Common Units			General Partner Interest			Accumulated Other Comprehensive Loss			Noncontrolling Interest			Total
Balance December 31, 2011	481,439			163,701			(6,464		)	99,002			737,678
Capital contribution	—			10,286			—			3,000			13,286
Distributions to HEP unitholders	(99,744		)	(23,033		)	—			—			(122,777		)
Purchase of 75% interest in UNEV from HFC:
Cash distribution	—			(260,922		)	—			—			(260,922		)
Issuance of common units	45,839			(45,839		)	—			—			—
Issuance of Class B unit	—			(12,200		)	—			—			(12,200		)
Purchase of units for incentive grants	(4,713		)	—			—			—			(4,713		)
Amortization of restricted and performance units	2,858			—			—			—			2,858
Class B unit accretion	(1,694		)	(9		)	—			—			(1,703		)
Tankage and terminal assets acquired from HFC:
Transferred basis in properties	7,947			—			—			—			7,947
Other	—			112			—			—			112
Net income	70,877			22,027			—			(1,799		)	91,105
Other comprehensive income	—			—			2,185			—			2,185
Balance December 31, 2012	502,809			(145,877		)	(4,279		)	100,203			452,856
Issuance of common units	73,444			—			—			—			73,444
Capital contribution	—			1,499			—			—			1,499
Distributions to HEP unitholders	(112,039		)	(27,447		)	—			—			(139,486		)
Distributions to noncontrolling interests	—			—			—			(3,125		)	(3,125		)
Purchase of units for incentive grants	(5,313		)	—			—			—			(5,313		)
Amortization of restricted and performance units	3,575			—			—			—			3,575
Class B unit accretion	(6,097		)	(124		)	—			—			(6,221		)
Other	(248		)	(263		)	—			—			(511		)
Net income	60,016			25,655			—			410			86,081
Other comprehensive income	—			—			4,135			—			4,135
Balance December 31, 2013	$	516,147		$	(146,557	)	$	(144	)	$	97,488		$	466,934
Distributions to HEP unitholders	(119,944		)	(34,726		)	—			—			(154,670		)
Distributions to noncontrolling interests	—			—			—			(4,025		)	(4,025		)
Purchase of units for incentive grants	(3,577		)	—			—			—			(3,577		)
Amortization of restricted and performance units	3,539			—			—			—			3,539
Class B unit accretion	(6,534		)	(134		)	—			—			(6,668		)
Net income	79,182			33,012			—			1,619			113,813
Other comprehensive income	—			—			98			—			98
Balance December 31, 2014	$	468,813		$	(148,405	)	$	(46	)	$	95,082		$	415,444

See accompanying notes.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2014

Note 1: Description of Business and Summary of Significant Accounting Policies

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 operate in one reportable segment which represents the aggregation of our petroleum product and crude pipelines business and terminals, tankage and loading rack facilities operations.

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 the UNEV Pipeline, LLC (“UNEV”), which owns a 427-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.

Principles of Consolidation and Common Control Transactions

The consolidated financial statements include our accounts and those of subsidiaries and joint ventures that we control through a 50% or more ownership interest. All significant inter-company transactions and balances have been eliminated.

Most of our asset acquisitions from HFC occurred while we were a consolidated variable interest entity of HFC. Therefore, as an entity under common control with HFC, we recorded these assets on our balance sheets at HFC's historical basis instead of our purchase price or fair value.

Use of Estimates

The preparation of financial statements in accordance with U.S. generally accepted accounting principles (“GAAP”) requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates.

Cash and Cash Equivalents

For purposes of the statements of cash flows, we consider all highly liquid investments with maturities of three months or less at the time of purchase to be cash equivalents. The carrying amounts reported on the balance sheets approximate fair value due to the short-term maturity of these instruments.

Accounts Receivable

The majority of the accounts receivable are due from affiliates of HFC, Alon or independent companies in the petroleum industry. Credit is extended based on evaluation of the customer's financial condition and, in certain circumstances, collateral such as letters of credit or guarantees, may be required. Credit losses are charged to income when accounts are deemed uncollectible and historically have been minimal.

Properties and Equipment

Properties and equipment are stated at cost. Properties and equipment acquired from HFC while under common control of HFC are stated at HFC's historical basis. Depreciation is provided by the straight-line method over the estimated useful lives of the assets, primarily 15 to 25 years for terminal facilities and tankage, 25 to 32 years for pipelines and 5 to 10 years for corporate and other assets. We depreciate assets acquired under capital leases over the lesser of the lease term or the economic life of the assets. Maintenance, repairs and minor replacements are expensed as incurred. Costs of replacements constituting improvements are capitalized.

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Transportation Agreements

The transportation agreement assets are stated at acquisition date fair value and are being amortized over the periods of the agreements using the straight-line method. See Note 5 for additional information on our transportation agreements.

Goodwill and Long-Lived Assets

Goodwill represents the excess of our cost of an acquired business over the fair value of the assets acquired, less liabilities assumed. Goodwill is not amortized and is tested for impairment annually or more frequently if events or changes in circumstances indicate goodwill may be impaired. We test goodwill at the reporting unit level for impairment annually and between annual tests if events or changes in circumstances indicate the carrying amount may exceed fair value. Recoverability is determined by comparing the estimated fair value of a reporting unit to the carrying value, including the related goodwill, of that reporting unit. We use the present value of the expected future net cash flows and market multiple analyses to determine the estimated fair values of the reporting units. The impairment test requires the use of projections, estimates and assumptions as to the future performance of our operations. Actual results could differ from projections resulting in revisions to our assumptions, and if required, recognizing an impairment loss.

We evaluate long-lived assets, including finite intangible assets, for potential impairment by identifying whether indicators of impairment exist and, if so, assessing whether the long-lived assets are recoverable from estimated future undiscounted cash flows. The actual amount of impairment loss, if any, to be recorded is equal to the amount by which a long-lived asset's carrying value exceeds its fair value.

There have been no impairments to goodwill or our long-lived assets as of December 31, 2014.

Investment in SLC Pipeline

We account for our 25% SLC Pipeline joint venture interest using the equity method of accounting, whereby we record our pro-rata share of earnings of the SLC Pipeline, and contributions to and distributions from the SLC Pipeline as adjustments to our investment balance. As of December 31, 2014, our underlying equity in the SLC Pipeline was $58.9 million compared to our recorded investment balance of $24.5 million, a difference of $34.4 million. We are amortizing this difference as an adjustment to our pro-rata share of earnings over the useful lives of the underlying assets of SLC Pipeline.

Asset Retirement Obligations

We record legal obligations associated with the retirement of certain of our long-lived assets that result from the acquisition, construction, development and/or the normal operation of our long-lived assets. The fair value of the estimated cost to retire a tangible long-lived asset is recorded in the period in which the liability is incurred and when a reasonable estimate of the fair value of the liability can be made. For our pipeline assets, the right-of-way agreements typically do not require the dismantling, removal and reclamation of the right-of-way upon cessation of the pipeline service. Additionally, management is unable to predict when, or if, our pipelines and related facilities would become obsolete and require decommissioning. Accordingly, we have recorded no liability or corresponding asset related to an asset retirement obligation for the majority of our pipelines as both the amounts and timing of such potential future costs are indeterminable. For our remaining assets, at December 31, 2014 and 2013, we have asset retirement obligations of $6.8 million and $6.5 million, respectively, that are recorded under “Other long-term liabilities” in our consolidated balance sheets.

Revenue Recognition

Revenues are recognized as products are shipped through our pipelines and terminals or other services are rendered. Billings to customers for their obligations under their quarterly minimum revenue commitments are recorded as deferred revenue liabilities if the customer has the right to receive future services for these billings. The revenue is recognized at the earlier of:

• the customer receiving the future services provided by these billings,

• the period in which the customer is contractually allowed to receive the services expires, or

• our determination that we will not be required to provide services within the allowed period.

We determine that we will not be required to provide services within the allowed period when, based on current and projected shipping levels, our pipeline systems will not have the necessary capacity to enable a customer to exceed its minimum volume levels to such a degree as to utilize the shortfall credit within its respective contractual shortfall make-up period.

We have additional revenues under an operating lease to a third party of an interest in the capacity of one of our pipelines.

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As of December 31, 2014, billings to customers under their minimum revenue commitments per the terms of long-term throughput agreements expiring in 2019 through 2026 and the third party operating lease will result in minimum annualized payments to us in the aggregate of $2.5 billion including $272.4 million for each of the next five years. These agreements provide for increases in the minimum revenue guarantees annually for increases in the Producer Price Index ("PPI") or the Federal Energy Regulatory Commission ("FERC") index, with certain contracts having provisions that limit the level of the rate increases.

We have other cost reimbursement provisions in our throughput / storage agreements providing that customers (including HFC) reimburse us for certain costs. Such reimbursement receipts are recorded as revenue or deferred revenue depending on the nature of the cost. Deferred revenue is recognized over the remaining contractual term of the related throughput agreement.

Taxes billed and collected from our pipeline and terminal customers are recorded on a net basis with no effect on net income.

Environmental Costs

Environmental costs are expensed if they relate to an existing condition caused by past operations and do not contribute to current or future revenue generation. Liabilities are recorded when site restoration and environmental remediation, cleanup and other obligations are either known or considered probable and can be reasonably estimated. Such estimates require judgment with respect to costs, time frame and extent of required remedial and clean-up activities and are subject to periodic adjustments based on currently available information. At December 31, 2014 and 2013, we had accrued liabilities, measured on an undiscounted basis, net of expected recoveries from indemnifying parties, for environmental remediation obligations of $5.2 million and $3.6 million respectively, of which $2.3 million and $0.4 million, respectively, were classified as other current liabilities.

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 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. Environmental costs recoverable through insurance, indemnification agreements or other sources are included in other assets to the extent such recoveries are considered probable.

Income Tax

We are subject to the Texas margin tax that is based on our Texas sourced taxable margin. The tax is calculated by applying a tax rate to a base that considers both revenues and expenses and therefore has the characteristics of an income tax.

We are organized as a pass-through entity for federal income tax purposes. As a result, our partners are responsible for federal income taxes based on their respective share of taxable income.

Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under the partnership agreement.

Net Income per Limited Partners' Unit

We use the two-class method when calculating the net income per unit applicable to limited partners, which is based on the weighted-average number of common and subordinated units outstanding during the year. Net income per unit applicable to limited partners is computed by dividing limited partners' interest in net income, after adjusting for the allocation of net income or loss attributable to previous owners ("Predecessor"), the allocation of net income or loss attributable to noncontrolling interests and the general partner's 2% interest and incentive distributions and other participating securities, by the weighted-average number of outstanding common, subordinated units and other dilutive securities. Other participating securities and dilutive securities are not significant.

New Accounting Pronouncements

Revenue Recognition

In May 2014, an accounting standard update was issued requiring revenue to be recognized when promised goods or services are transferred to customers in an amount that reflects the expected consideration for these goods or services. This standard is effective January 1, 2017, and we are evaluating the impact of this standard.

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Note 2: Acquisitions

2012 UNEV Acquisition

On July 12, 2012, we acquired HFC's 75% interest in UNEV for consideration consisting of $260.0 million in cash and 2,059,800 of our common units. We paid an additional $0.9 million to HFC for a post-closing working capital adjustment. We also issued HFC a Class B unit comprising a noncontrolling equity interest in a wholly-owned subsidiary subject to redemption to the extent that HFC is entitled to a 50% interest in our share of annual UNEV earnings before interest, income taxes, depreciation, and amortization above $30 million beginning July 1, 2016, and ending in June 2032, subject to certain limitations. Such contingent redemption payments are limited to a maximum payment amount calculated as described below. However, to the extent earnings thresholds are not achieved, no redemption payments are required. Contemporaneously with this transaction, HFC (our general partner) agreed to forego its right to incentive distributions of up to $1.25 million per quarter over twelve consecutive quarterly periods and up to an additional four quarters in certain circumstances. The Class B unit increases with each foregone incentive distribution and by a 7% factor compounded annually on the outstanding unredeemed balance through its expiration date. At our option, we may redeem, in whole or in part, the Class B unit at the current unredeemed value based on the calculation described. The Class B unit had a carrying value of $26.8 million at December 31, 2014, and $20.1 million at December 31, 2013.

Noncontrolling interests reported in the Consolidated Statements of Income include the minority partner's 25% interest in UNEV, foregone incentive distributions and the 7% accretion factor, which collectively amounted to $8.3 million at December 31, 2014, $6.6 million at December 31, 2013, and $1.2 million at December 31, 2012.

We are a consolidated variable interest entity of HFC. Therefore, this transaction was recorded as a transfer between entities under common control and reflects HFC's carrying basis in UNEV's assets and liabilities. We have retrospectively adjusted our financial position and operating results as if UNEV were a consolidated subsidiary for all periods while we were under common control of HFC. Results of operations of UNEV prior to our acquisition on July 12, 2012, are herein referred to as operations attributable to the Predecessor. For the year ended December 31, 2012, our consolidated statement of income includes revenues from UNEV of $18.7 million and net losses of $7.2 million. Predecessor revenues for the year ended December 31, 2012, are $8.1 million and Predecessor net losses are $4.2 million. At December 31, 2014, UNEV had transportation agreements with shippers that provide minimum annualized revenues of $27.1 million, of which $18.4 million relates to a transportation agreement with HFC.

Note 3: Financial Instruments

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

Fair value measurements are derived using inputs (assumptions that market participants would use in pricing an asset or liability) including assumptions about risk. GAAP categorizes inputs used in fair value measurements into three broad levels as follows:

• (Level 1) Quoted prices in active markets for identical assets or liabilities.

• (Level 2) Observable inputs other than quoted prices included in Level 1, such as quoted prices for similar assets and liabilities in active markets, similar assets and liabilities in markets that are not active or can be corroborated by observable market data.

• (Level 3) Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. This includes valuation techniques that involve significant unobservable inputs.

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

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		December 31, 2014				December 31, 2013
Financial Instrument	Fair Value Input Level	Carrying Value		Fair Value		Carrying Value		Fair Value
		(In thousands)
Assets:
Interest rate swaps	Level 2	$	1,019	$	1,019	$	1,670	$	1,670
Liabilities:
Senior notes:
6.5% Senior Notes	Level 2	$	296,579	$	291,000	$	295,927	$	313,500
8.25% Senior Notes	Level 2	—		—		148,703		158,250
		296,579		291,000		444,630		471,750
Interest rate swaps	Level 2	1,065		1,065		1,814		1,814
		$	297,644	$	292,065	$	446,444	$	473,564

Level 2 Financial Instruments

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

See Note 7 for additional information on these instruments.

Note 4: Properties and Equipment

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

	December 31, 2014		December 31, 2013
	(In thousands)
Pipelines, terminals and tankage	$	1,137,157	$	1,077,037
Land and right of way	64,458		63,425
Construction in progress	56,228		50,454
Other	22,636		19,997
	1,280,479		1,210,913
Less accumulated depreciation	300,000		253,099
	$	980,479	$	957,814

We capitalized $1.5 million and $0.6 million in interest related to construction projects during the years ended December 31, 2014 and 2013, respectively.

Depreciation expense was $54.7 million, $58.1 million, and $50.1 million for the years ended December 31, 2014, 2013 and 2012, respectively, and includes depreciation of assets acquired under capital leases. Asset abandonment charges of $1.9 million, $6.2 million and $4.8 million for assets permanently removed from service were included in depreciation expense for the years ended December 31, 2014, 2013 and 2012, respectively.

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Note 5: Transportation Agreements

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

The carrying amounts of our transportation agreements are as follows:

	December 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	53,461		46,514
	$	80,703	$	87,650

Amortization expense was $6.9 million for each of the years ended December 31, 2014, 2013 and 2012, respectively.

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 6: 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 $7.4 million, $7.4 million and $6.9 million for the years ended December 31, 2014, 2013 and 2012, respectively. These costs include retirement costs of $4.4 million, $5.0 million and $4.3 million for the years ended December 31, 2014, 2013 and 2012, respectively.

We have an incentive plan (“Long-Term Incentive Plan”) for employees and non-employee directors who perform services for us. The Long-Term Incentive Plan consists of four components: restricted 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 December 31, 2014, we have three types of incentive-based awards which are described below. The compensation cost charged against income was $3.5 million, $3.6 million and $2.9 million for the years ended December 31, 2014, 2013 and 2012, respectively. We currently purchase units in the open market instead of issuing new units for settlement of all unit awards under our Long-Term Incentive Plan. As of December 31, 2014, 2,500,000 units were authorized to be granted under our Long-Term Incentive Plan, of which 1,530,748 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.

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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.

A summary of restricted unit and phantom unit activity and changes during the year ended December 31, 2014, is presented below:

Restricted and Phantom Units	Units		Weighted- Average Grant-Date Fair Value
Outstanding at January 1, 2014 (nonvested)	122,951		$	33.36
Granted	91,852		33.49
Vesting and transfer of full ownership to recipients	(80,645	)	33.22
Forfeited	(8,081	)	35.28
Outstanding at December 31, 2014 (nonvested)	126,077		$	33.43

The fair values of restricted and phantom units that were vested and transferred to recipients during the years ended December 31, 2014, 2013 and 2012 were $2.7 million, $1.2 million and $2.4 million respectively. As of December 31, 2014, there was $3.0 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 1.5 years. For the years ended December 31, 2013 and 2012, the grant date closing unit price applied to the number of restricted units and phantom units ultimately awarded was $34.66 and $31.01 respectively.

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.

We granted 13,967 target performance units to certain officers in October 2014. These units will vest over a three year period ending December 31, 2017. The performance units granted 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 50% to 150% of the target number of performance units granted. Although common units are not transferred to the recipients until the performance units vest, the recipients have distribution rights with respect to the common units from the date of grant. The fair value of these performance units is based on the grant date closing unit price of $33.57 for the performance units granted in October 2014 and will apply to the number of units ultimately awarded. For the years ended December 31, 2013 and 2012, the weighted average grant date closing unit price applied to the number of units awarded was $37.90 and $30.61 respectively.

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

Performance Units	Units
Outstanding at January 1, 2014 (nonvested)	75,216
Granted	13,967
Vesting and transfer of common units to recipients	(17,938	)
Outstanding at December 31, 2014 (nonvested)	71,245

The grant date fair value of performance units vested and transferred to recipients was $0.5 million during each of the three years ended December 31, 2014, 2013 and 2012. Based on the weighted average fair value of performance units outstanding at December 31, 2014, of $2.6 million, there was $1.1 million of total unrecognized compensation expense related to nonvested performance units, which is expected to be recognized over a weighted-average period of 1.2 years.

During the year ended December 31, 2014, we paid $3.6 million for the purchase of our common units in the open market for the issuance and settlement of all unit awards under our Long-Term Incentive Plan.

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Note 7: 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 is 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.

Indebtedness under the Credit Agreement bears interest, at our option, at either (a) the reference rate as announced by the administrative agent plus an applicable margin (ranging from 0.625% to 1.50%) or (b) at a rate equal to LIBOR plus an applicable margin (ranging from 1.625% to 2.50%). In each case, the applicable margin is based upon the ratio of our funded debt (as defined in the Credit Agreement) to EBITDA (earnings before interest, taxes, depreciation and amortization, as defined in the Credit Agreement). The weighted-average interest rates on our Credit Agreement borrowings in effect at December 31, 2014 and 2013, were 2.152% and 2.163%, respectively. We incur a commitment fee on the unused portion of the Credit Agreement at an annual rate ranging from 0.30% to 0.45% based upon the ratio of our funded debt to EBITDA for the four most recently completed fiscal quarters.

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

Senior Notes

In March 2012, we issued $300 million in aggregate principal amount outstanding of 6.5% Senior Notes maturing March 2020. Net proceeds of $294.8 million were used in March and April 2012 to redeem $185.0 million aggregate principal amount of our 6.25% Senior Notes maturing March 1, 2015, tendered pursuant to a cash tender offer and consent solicitation, to repay $72.9 million in promissory notes related to our November 2011 acquisition of assets located at HFC's El Dorado and Cheyenne refineries, to pay related fees, expenses and accrued interest in connection with these transactions and to repay borrowings under the Credit Agreement. We recognized a charge of $3.0 million upon the early extinguishment of our 6.25% Senior Notes for the year ended December 31, 2012. This charge represents the premium paid to our 6.25% Senior Note holders upon their tender of an aggregate principal amount of $185.0 million and related net discount.

In March 2014, we redeemed the $150 million aggregate principal amount of 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.

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 is recourse to HEP Logistics, our general partner, and is guaranteed by our material, 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.

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Our purchase and contribution agreements with HFC with respect to the intermediate pipelines acquired in 2005 and the crude pipelines and tankage assets acquired in 2008, restrict us from selling these pipelines and terminals acquired from HFC. Under these agreements, we are restricted from prepaying borrowings and long-term debt to outstanding balances below $206 million prior to 2015 and $171 million prior to 2018, subject to certain limited exceptions.

Long-term Debt

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

	December 31, 2014			December 31, 2013
	(In thousands)
Credit Agreement	$	571,000		$	363,000
6.5% Senior Notes
Principal	300,000			300,000
Unamortized discount	(3,421		)	(4,073		)
	296,579			295,927
8.25% Senior Notes
Principal	—			150,000
Unamortized discount	—			(1,297		)
	—			148,703
Total long-term debt	$	867,579		$	807,630

Maturities of our long-term debt are as follows:

Years Ending December 31,	(In thousands)
2015	$	—
2016	—
2017	—
2018	571,000
2019	—
Thereafter	300,000
Total	$	871,000

Interest Rate Risk Management

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

As of December 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 December 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 December 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 December 31, 2014, we had no ineffectiveness on our cash flow hedges.

Prior to entering into our first swap contract (discussed above), we terminated our previous interest rate swap that prior to settlement

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also served to hedge our exposure to the effects of LIBOR changes on the same $155 million Credit Agreement advance. We terminated this swap at a cost of $6 million, to lock in a lower effective interest rate on this $155 million advance, which by means of the previous swap contract was effectively fixed at 6.24% at the time of termination. This cost of terminating the swap was amortized as a charge to interest expense through February 2013, the remaining term of the terminated swap contract.

At December 31, 2014, we have accumulated other comprehensive loss of $46,000 that relates to our current cash flow hedging instruments. Approximately $0.5 million will be transferred from accumulated other comprehensive loss into interest expense as interest is paid on the underlying swap agreement over the next twelve-month period, assuming interest rates remain unchanged.

Additional information on our interest rate swaps is as follows:

Derivative Instrument	Balance Sheet Location	Fair Value			Location of Offsetting Balance	Offsetting Amount
	(In thousands)
December 31, 2014
Interest rate swaps designated as cash flow hedging instrument:
Variable-to-fixed interest rate swap contract ($155 million of LIBOR based debt interest)	Other long-term     liabilities	$	(1,065	)	Accumulated other     comprehensive loss	$	(1,065	)
Variable-to-fixed interest rate swap contract ($150 million of LIBOR based debt interest)	Other long-term assets	1,019			Accumulated other     comprehensive income	1,019
		$	(46	)		$	(46	)
December 31, 2013
Interest rate swaps designated as cash flow hedging instrument:
Variable-to-fixed interest rate swap contract ($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 contract ($150 million of LIBOR based debt interest)	Other long-term assets	1,670			Accumulated other     comprehensive income	1,670
		$	(144	)		$	(144	)

Interest Expense and Other Debt Information

Interest expense consists of the following components:

	Years Ended December 31,
	2014		2013		2012
	(In thousands)
Interest on outstanding debt:
Credit Agreement, net of interest on interest rate swaps	$	13,350	$	11,961	$	8,736
6.5% Senior Notes	19,446		19,506		15,716
6.25% Senior Notes	—		—		2,422
8.25% Senior Notes	2,544		12,380		12,380
Promissory Notes	—		—		543
Amortization of discount and deferred debt issuance costs	1,821		2,120		1,946
Amortization of unrecognized loss attributable to terminated cash flow hedge	—		849		5,095
Commitment fees	450		835		621
Total interest incurred	37,611		47,651		47,459
Less capitalized interest	1,510		641		277
Net interest expense	$	36,101	$	47,010	$	47,182
Cash paid for interest	$	39,414	$	44,655	$	38,476

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Note 8: Commitments and Contingencies

We lease certain facilities, pipelines and rights of way under operating leases, most of which contain renewal options. The right of way agreements have various termination dates through 2053.

As of December 31, 2014, the minimum future rental commitments under operating leases having non-cancelable lease terms in excess of one year are as follows:

Years Ending December 31,	(In thousands)
2015	$	6,928
2016	6,913
2017	3,549
2018	192
2019	124
Thereafter	266
Total	$	17,972

Rental expense charged to operations was $8.0 million, $8.3 million and $8.1 million for the years ended December 31, 2014, 2013 and 2012, respectively.

We also have other long-term contractual obligations primarily consisting of long-term site service agreements with HFC, expiring in 2024 through 2026, for the provision of certain facility services and utility costs that relate to our assets located at HFC’s refinery facilities. At December 31, 2014, these minimum future contractual obligations having terms in excess of one year are as follows:

Years Ending December 31,	(In thousands)
2015	$	1,067
2016	1,067
2017	1,067
2018	1,067
2019	1,032
Thereafter	6,294
Total	$	11,594

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

Note 9: Significant Customers

All revenues are domestic revenues, of which 93% are currently generated 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:

	Years Ended December 31,
	2014		2013		2012
HFC	83	%	83	%	84	%
Alon	10	%	11	%	11	%

Note 10: 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 1st each year based on the Producer Price Index (“PPI”) or Federal Energy Regulatory Commission (“FERC”) index. As of December 31, 2014, these agreements with HFC will result in minimum payments to us of $231.6 million.

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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 ($2.3 million in 2014 and currently $2.4 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 $275.2 million, $252.4 million and $245.6 million for the years ended December 31, 2014, 2013 and 2012, respectively.

• HFC charged us general and administrative services under the Omnibus Agreement of $2.3 million for each of the years ended December 31, 2014, 2013 and 2012.

• We reimbursed HFC for costs of employees supporting our operations of $38.9 million, $34.6 million and $31.1 million for the years ended December 31, 2014, 2013 and 2012, respectively. Netted against the cost of employees for the year ended December 31, 2013, is a $3.5 million refund from HFC related to refunds of taxes covering a multi-year period.

• HFC reimbursed us $16.8 million, $21.6 million and $13.4 million for the years ended December 31, 2014, 2013 and 2012, respectively, for certain reimbursable costs and capital projects.

• We distributed $80.5 million, $71.4 million and $64.0 million, for the years ended December 31, 2014, 2013 and 2012, respectively, to HFC as regular distributions on its common units and general partner interest, including general partner incentive distributions.

• Accounts receivable from HFC were $33.4 million and $29.7 million at December 31, 2014 and 2013, respectively.

• Accounts payable to HFC were $5.2 million and $8.5 million at December 31, 2014 and 2013, respectively.

• Revenues for the years ended December 31, 2014, 2013 and 2012 include $10.1 million, $5.1 million and $7.8 million, respectively, of shortfall payments billed in 2013, 2012 and 2011, respectively, as HFC did not exceed its minimum volume commitment in any of the subsequent four quarters in 2014, 2013 and 2012. Deferred revenue in the consolidated balance sheets at December 31, 2014 and 2013, includes $7.3 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 $7.3 million deferred at December 31, 2014.

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

Note 11: Partners’ Equity, Income Allocations and Cash Distributions

As of December 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.

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

Common Unit Issuances

2013 Issuances

In March 2013, we closed on a public offering of 1,875,000 of our common units. Additionally, an affiliate of HFC, as a selling unitholder, closed on a public sale of 1,875,000 of its HEP common units for which we did not receive any proceeds. We used our net proceeds of $73.4 million to repay indebtedness incurred under our credit facility and for general partnership purposes.

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2012 Issuances

On July 12, 2012, we issued HFC 2,059,800 of our common units as partial consideration for our acquisition of its 75% interest in UNEV.

We received aggregate capital contributions of $1.7 million from our general partner to maintain its 2% general partner interest concurrent with the 2012 common unit issuance described above.

Under our registration statement filed with the SEC using a “shelf” registration process, $2.0 billion of securities have been registered. Any potential sale of such securities, through one or more prospectus supplements, 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.

Allocations of Net Income

Net income attributable to HEP is allocated between limited partners and the general partner interest in accordance with the provisions of the partnership agreement. HEP net income allocated to the general partner includes incentive distributions that are declared subsequent to quarter end. After the amount of incentive distributions is allocated to the general partner, the remaining net income attributable to HEP is allocated to the partners based on their weighted-average ownership percentage during the period.

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

	Years Ended December 31,
	2014		2013		2012
	(in thousands)
General partner interest in net income	$	1,446	$	1,059	$	1,464
General partner incentive distribution	33,221		26,464		20,986
Total general partner interest in net income	$	34,667	$	27,523	$	22,450

Cash Distributions

We consider regular cash distributions to unitholders on a quarterly basis, although there is no assurance as to the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors.

Within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement) to unitholders of record on the applicable record date. The amount of available cash generally is all cash on hand at the end of the quarter; less the amount of cash reserves established by our general partner to provide for the proper conduct of our business, comply with applicable laws, any of our debt instruments, or other agreements; or provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters; plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter.

We make distributions in the following manner: 98% to our common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter and any arrearages in payment of the minimum quarterly distributions for any prior quarters, thereafter. Cash in excess of the minimum quarterly distributions is distributed to the unitholders and the general partner based on certain percentages presented below.

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

	Total Quarterly Distribution	Marginal Percentage Interest in Distributions
	Target Amount	Unitholders	General Partner
Minimum quarterly distribution	$0.25	98%	2%
First target distribution	Up to $0.275	98%	2%
Second target distribution	above $0.275 up to $0.3125	85%	15%
Third target distribution	above $0.3125 up to $0.375	75%	25%
Thereafter	Above $0.375	50%	50%

On January 22, 2015, we announced our cash distribution for the fourth quarter of 2014 of $0.53 per unit. The distribution is payable on all common and general partner units and was paid February 13, 2015, to all unitholders of record on February 2, 2015.

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.

	Years Ended December 31,
	2014		2013		2012
	(In thousands, except per unit data)
General partner interest in distribution	$	3,264	$	2,982	$	2,566
General partner incentive distribution	33,221		26,464		20,986
Total general partner distribution	36,485		29,446		23,552
Limited partner distribution	121,714		114,675		102,222
Total regular quarterly cash distribution	$	158,199	$	144,121	$	125,774
Cash distribution per unit applicable to limited partners	$	2.075	$	1.955	$	1.835

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

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Note 12: Quarterly Financial Data (Unaudited)

Summarized quarterly financial data is as follows:

	First		Second		Third		Fourth		Total
	(In thousands, except per unit data)
Year Ended December 31, 2014
Revenues	$	87,004	$	74,998	$	82,130	$	88,413	$	332,545
Operating income	$	45,453	$	32,033	$	38,925	$	38,343	$	154,754
Income before income taxes	$	27,855	$	24,478	$	31,231	$	30,484	$	114,048
Net income	$	27,780	$	24,450	$	31,189	$	30,394	$	113,813
Net income attributable to Holly Energy Partners	$	24,143	$	23,034	$	29,680	$	28,668	$	105,525
Limited partners’ per unit interest in net income – basic and diluted	$	0.27	$	0.25	$	0.35	$	0.33	$	1.20
Distributions per limited partner unit	$	0.508	$	0.515	$	0.523	$	0.530	$	2.075
Year Ended December 31, 2013
Revenues	$	74,298	$	75,285	$	77,723	$	77,876	$	305,182
Operating income	$	31,047	$	32,520	$	34,173	$	30,826	$	128,566
Income before income taxes	$	21,345	$	21,641	$	23,097	$	20,331	$	86,414
Net income	$	21,289	$	21,297	$	23,057	$	20,438	$	86,081
Net income attributable to Holly Energy Partners	$	18,399	$	20,167	$	21,885	$	18,998	$	79,449
Limited partners’ per unit interest in net income – basic and diluted	$	0.21	$	0.23	$	0.25	$	0.19	$	0.88
Distributions per limited partner unit	$	0.478	$	0.485	$	0.493	$	0.500	$	1.955

Note 13: 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.

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Condensed Consolidating Balance Sheet

December 31, 2014	Parent		Guarantor Restricted Subsidiaries		Non-Guarantor Non-Restricted Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	2	$	2,828	$	—	$	—		$	2,830
Accounts receivable	—		34,274		6,044		(189		)	40,129
Prepaid and other current assets	212		2,856		1,315		—			4,383
Total current assets	214		39,958		7,359		(189		)	47,342
Properties and equipment, net	—		596,988		383,491		—			980,479
Investment in subsidiaries	622,100		285,247		—		(907,347		)	—
Transportation agreements, net	—		80,703		—		—			80,703
Goodwill	—		256,498		—		—			256,498
Investment in SLC Pipeline	—		24,478		—		—			24,478
Other assets	1,319		10,736		—		—			12,055
Total assets	$	623,633	$	1,294,608	$	390,850	$	(907,536	)	$	1,401,555
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	—	$	15,495	$	2,575	$	(189	)	$	17,881
Accrued interest	6,500		115		—		—			6,615
Deferred revenue	—		5,672		6,760		—			12,432
Accrued property taxes	—		1,902		801		—			2,703
Other current liabilities	45		4,408		118		—			4,571
Total current liabilities	6,545		27,592		10,254		(189		)	44,202
Long-term debt	296,579		571,000		—		—			867,579
Other long-term liabilities	147		17,731		267		—			18,145
Deferred revenue	—		29,392		—		—			29,392
Class B unit	—		26,793		—		—			26,793
Equity - partners	320,362		622,100		380,329		(1,002,429		)	320,362
Equity - noncontrolling interest	—		—		—		95,082			95,082
Total liabilities and partners’ equity	$	623,633	$	1,294,608	$	390,850	$	(907,536	)	$	1,401,555

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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

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Condensed Consolidating Statement of Comprehensive Income

Year Ended December 31, 2014	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries		Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	254,364		$	22,073	$	(1,241	)	$	275,196
Third parties	—			45,711			11,638		—			57,349
	—			300,075			33,711		(1,241		)	332,545
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	—			93,382			12,660		(1,241		)	104,801
Depreciation and amortization	—			47,592			14,574		—			62,166
General and administrative	2,658			8,166			—		—			10,824
	2,658			149,140			27,234		(1,241		)	177,791
Operating income (loss)	(2,658		)	150,935			6,477		—			154,754
Equity in earnings of subsidiaries	138,691			4,858			—		(143,549		)	—
Equity in earnings of SLC Pipeline	—			2,987			—		—			2,987
Interest income	—			3			—		—			3
Interest expense	(22,831		)	(13,270		)	—		—			(36,101		)
Loss on early extinguishment of debt	(7,677		)	—			—		—			(7,677		)
Other	—			82			—		—			82
	108,183			(5,340		)	—		(143,549		)	(40,706		)
Income (loss) before income taxes	105,525			145,595			6,477		(143,549		)	114,048
State income tax expense	—			(235		)	—		—			(235		)
Net income (loss)	105,525			145,360			6,477		(143,549		)	113,813
Allocation of net (income) attributable to noncontrolling interests	—			—			—		(8,288		)	(8,288		)
Net income (loss) attributable to Holly Energy Partners	105,525			145,360			6,477		(151,837		)	105,525
Other comprehensive (loss)	98			98			—		(98		)	98
Comprehensive income (loss)	$	105,623		$	145,458		$	6,477	$	(151,935	)	$	105,623

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Condensed Consolidating Statement of Comprehensive Income

Year Ended December 31, 2013	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries		Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	236,336		$	17,258	$	(1,226	)	$	252,368
Third parties	—			42,139			10,675		—			52,814
	—			278,475			27,933		(1,226		)	305,182
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	—			88,614			12,056		(1,226		)	99,444
Depreciation and amortization	—			51,082			14,341		—			65,423
General and administrative	3,381			8,368			—		—			11,749
	3,381			148,064			26,397		(1,226		)	176,616
Operating income (loss)	(3,381		)	130,411			1,536		—			128,566
Equity in earnings of subsidiaries	115,850			1,231			—		(117,081		)	—
Equity in earnings of SLC Pipeline	—			2,826			—		—			2,826
Interest income	—			56			105		—			161
Interest expense	(33,020		)	(13,990		)	—		—			(47,010		)
Gain on sale of assets	—			1,810			—		—			1,810
Other	—			61			—		—			61
	82,830			(8,006		)	105		(117,081		)	(42,152		)
Income (loss) before income taxes	79,449			122,405			1,641		(117,081		)	86,414
State income tax expense	—			(333		)	—		—			(333		)
Net income (loss)	79,449			122,072			1,641		(117,081		)	86,081
Allocation of net loss attributable to noncontrolling interests	—			—			—		(6,632		)	(6,632		)
Net income (loss) attributable to Holly Energy Partners	79,449			122,072			1,641		(123,713		)	79,449
Other comprehensive income	4,135			4,135			—		(4,135		)	4,135
Comprehensive income (loss)	$	83,584		$	126,207		$	1,641	$	(127,848	)	$	83,584

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Condensed Consolidating Statement of Comprehensive Income

Year Ended December 31, 2012	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	232,986		$	13,754		$	(1,158	)	$	245,582
Third parties	—			41,984			4,994			—			46,978
	—			274,970			18,748			(1,158		)	292,560
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	—			78,766			11,634			(1,158		)	89,242
Depreciation and amortization	—			43,147			14,314			—			57,461
General and administrative	3,336			4,258			—			—			7,594
	3,336			126,171			25,948			(1,158		)	154,297
Operating income (loss)	(3,336		)	148,799			(7,200		)	—			138,263
Equity in earnings (loss) of subsidiaries	130,743			(5,400		)	—			(125,343		)	—
Equity in earnings of SLC Pipeline	—			3,364			—			—			3,364
Interest expense	(31,523		)	(15,659		)	—			—			(47,182		)
Loss on early extinguishment of debt	(2,979		)	—			—			—			(2,979		)
Other	—			10			—			—			10
	96,241			(17,685		)	—			(125,343		)	(46,787		)
Income (loss) before income taxes	92,905			131,114			(7,200		)	(125,343		)	91,476
State income tax expense	—			(371		)	—			—			(371		)
Net income (loss)	92,905			130,743			(7,200		)	(125,343		)	91,105
Allocation of net loss attributable to Predecessors	4,200			—			—			—			4,200
Allocation of net loss attributable to noncontrolling interests	(2,953		)	—			—			1,800			(1,153		)
Net income (loss) attributable to Holly Energy Partners	94,152			130,743			(7,200		)	(123,543		)	94,152
Other comprehensive (loss)	2,185			2,185			—			(2,185		)	2,185
Comprehensive income (loss)	$	96,337		$	132,928		$	(7,200	)	$	(125,728	)	$	96,337

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Condensed Consolidating Statement of Cash Flows

Year Ended December 31, 2014	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities	$	(25,339	)	$	193,273		$	19,398		$	(692	)	$	186,640
Cash flows from investing activities
Additions to properties and equipment	—			(71,758		)	(8,201		)	—			(79,959		)
Distributions from UNEV	—			11,383			—			(11,383		)	—
Distributions in excess of equity in earnings in SLC Pipeline	—			263			—			—			263
	—			(60,112		)	(8,201		)	(11,383		)	(79,696		)
Cash flows from financing activities
Net borrowings under credit agreement	—			208,000			—			—			208,000
Net intercompany financing activities	339,771			(339,771		)	—			—			—
Repayments of senior notes	(156,188		)	—			—			—			(156,188		)
Distributions to HEP unitholders	(154,670		)	—			—			—			(154,670		)
Distributions to noncontrolling interests	—			—			(16,100		)	12,075			(4,025		)
Purchase of units for incentive grants	(3,577		)	—			—			—			(3,577		)
Other	3			(9		)	—			—			(6		)
	25,339			(131,780		)	(16,100		)	12,075			(110,466		)
Cash and cash equivalents
Increase (decrease) for the period	—			1,381			(4,903		)	—			(3,522		)
Beginning of period	2			1,447			4,903			—			6,352
End of period	$	2		$	2,828		$	—		$	—		$	2,830

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Condensed Consolidating Statement of Cash Flows

Year Ended December 31, 2013	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities	$	(34,605	)	$	197,678		$	20,007		$	—		$	183,080
Cash flows from investing activities
Additions to properties and equipment	—			(45,085		)	(7,016		)	—			(52,101		)
Proceeds from the sale of assets	—			2,731			—			—			2,731
Distributions from UNEV	—			9,375			—			(9,375		)	—
Distribution in excess of equity in earnings in SLC Pipeline	—			300			—			—			300
	—			(32,679		)	(7,016		)	(9,375		)	(49,070		)
Cash flows from financing activities
Net repayments under credit agreement	—			(58,000		)	—			—			(58,000		)
Net intercompany financing activities	105,031			(105,031		)	—			—			—
Proceeds from issuance of common units	73,444			—			—			—			73,444
Distributions to noncontrolling interests	—			—			(12,500		)	9,375			(3,125		)
Contributions from general partner	1,499			—			—			—			1,499
Distributions to HEP unitholders	(139,486		)	—			—			—			(139,486		)
Purchase of units for restricted grants	(5,634		)	—			—			—			(5,634		)
Deferred financing costs	—			(1,344		)	—			—			(1,344		)
Other	(249		)	—			—			—			(249		)
	34,605			(164,375		)	(12,500		)	9,375			(132,895		)
Cash and cash equivalents
Increase for the period	—			624			491			—			1,115
Beginning of period	2			823			4,412			—			5,237
End of period	$	2		$	1,447		$	4,903		$	—		$	6,352

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Condensed Consolidating Statement of Cash Flows

Year Ended December 31, 2012	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations		Consolidated
	(In thousands)
Cash flows from operating activities	$	(34,557	)	$	194,667		$	1,039		$	—	$	161,149
Cash flows from investing activities
Additions to properties and equipment	—			(28,134		)	(14,727		)	—		(42,861		)
Distributions in excess of equity in earnings in SLC Pipeline	—			262			—			—		262
	—			(27,872		)	(14,727		)	—		(42,599		)
Cash flows from financing activities
Net borrowings under credit agreement	—			221,000			—			—		221,000
Proceeds from issuance of senior notes	294,750			—			—			—		294,750
Net intercompany financing activities	51,989			(51,989		)	—			—		—
Cash distribution to HFC for UNEV acquisition	—			(260,922		)	—			—		(260,922		)
Redemption of senior notes	(185,000		)	(75,235		)	—			—		(260,235		)
Contributions from UNEV joint venture partners	—			—			15,000			—		15,000
Contributions from general partner	1,748			—			—			—		1,748
Distributions to HEP unitholders	(122,777		)	—			—			—		(122,777		)
Purchase of units for restricted grants	(5,240		)	321			—			—		(4,919		)
Deferred financing costs	(913		)	(2,325		)	—			—		(3,238		)
Other	—			(89		)	—			—		(89		)
	34,557			(169,239		)	15,000			—		(119,682		)
Cash and cash equivalents
Increase (decrease) for the period	—			(2,444		)	1,312			—		(1,132		)
Beginning of period	2			3,267			3,100			—		6,369
End of period	$	2		$	823		$	4,412		$	—	$	5,237

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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

We have had no change in, or disagreement with, our independent registered public accounting firm on matters involving accounting and financial disclosure.

Item 9A. 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 annual report on Form 10-K. 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 SEC’s rules and forms. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of December 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.

See Item 8 for “Management’s Report on its Assessment of the Partnership’s Internal Control Over Financial Reporting” and “Report of Independent Registered Public Accounting Firm.”

Item 9B. Other Information

There have been no events that occurred in the fourth quarter of 2014 that would need to be reported on Form 8-K that have not been previously reported.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

Holly Logistic Services, L.L.C. (“HLS”), the general partner of HEP Logistics Holdings, L.P. (“HEP Logistics”), our general partner, manages our operations and activities. Neither our general partner nor our directors are elected by our unitholders. Unitholders are not entitled to directly or indirectly participate in our management or operations. The sole member of HLS, which is a subsidiary of HFC, appoints the directors of HLS to serve until their death, resignation or removal.

Our general partner owes a fiduciary duty to our unitholders. Our general partner is liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically non-recourse to it. Whenever possible, our general partner intends to incur indebtedness or other obligations that are non-recourse.

Executive Officers

The following sets forth information regarding the executive officers of HLS as of February 13, 2015:

Name	Age	Position with HLS
Michael C. Jennings	49	Chief Executive Officer
Bruce R. Shaw	47	President
Douglas S. Aron	41	Executive Vice President and Chief Financial Officer
Mark T. Cunningham	55	Senior Vice President, Operations
Denise C. McWatters	55	Senior Vice President, General Counsel and Secretary

Certain executive officers of HLS are also officers of HFC or provide services to HFC. During 2014, Messrs. Shaw and Cunningham were the only HLS executive officers who spent all of their professional time managing our business and affairs. Messrs. Jennings and Aron and Ms. McWatters are also officers of HFC and devoted as much of their professional time in 2014 as was necessary to oversee the management of our business and affairs.

Information regarding Mr. Jennings is included below under “Directors.”

Bruce R. Shaw was appointed President in November 2012. Mr. Shaw served as Senior Vice President and Chief Financial Officer from December 2011 until November 2012, Senior Vice President, Strategy and Corporate Development from July 2011 until December 2011, Senior Vice President and Chief Financial Officer from January 2008 until July 2011, and Vice President, Corporate Development from August 2004 to January 2007. Mr. Shaw served as Senior Vice President, Strategy and Corporation Development of HFC from July 2011 through December 2012, Senior Vice President and Chief Financial Officer of Holly Corporation from 2008 until the effective time of the merger between Holly Corporation and Frontier Oil Corporation in July 2011, and Vice President, Special Projects for Holly Corporation from September 2007 to December 2007. Mr. Shaw served on the Board of HLS from April 2007 to April 2008. Mr. Shaw briefly left Holly Corporation in June 2007 and served as President of Standard Supply and Distributing Company, Inc. and Bartos Industries, Ltd., two companies that are affiliated with each other in the heating, ventilation, and air conditioning industry. Mr. Shaw previously served Holly Corporation in various positions with increasing seniority from 1997 to 2007. Prior to joining Holly Corporation, Mr. Shaw was a consultant at McKinsey & Company, a global management consulting firm.

Douglas S. Aron was appointed Executive Vice President and Chief Financial Officer in November 2012. He previously served in such position from July 2011 until December 2011. Mr. Aron currently also serves as Executive Vice President and Chief Financial Officer of HFC since the merger of Holly Corporation and Frontier Oil Corporation in July 2011. Prior to joining HFC, Mr. Aron was Executive Vice President and Chief Financial Officer of Frontier Oil Corporation from 2009 until 2011. Additionally, he served as Vice President-Corporate Finance of Frontier Oil Corporation from 2005 to 2009 and Director-Investor Relations from 2001 to 2005. Prior to joining Frontier Oil Corporation, Mr. Aron was a lending officer for Amegy Bank.

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Mark T. Cunningham was appointed Senior Vice President, Operations in January 2013. He previously served as Vice President, Operations from July 2007 to January 2013. He served Holly Corporation as Senior Manager of Special Projects from December 2006 through June 2007 and as Senior Manager of Integrity Management and Environmental, Health and Safety from July 2004 through December 2006. Prior to joining Holly Corporation, Mr. Cunningham served Diamond Shamrock/Ultramar Diamond Shamrock for 20 years in several engineering and pipeline operations capacities.

Denise C. McWatters was appointed Senior Vice President, General Counsel and Secretary in January 2013.  Ms. McWatters also serves in a similar capacity for HFC. Ms. McWatters previously served as Vice President, General Counsel and Secretary from April 2008 until January 2013. She joined Holly Corporation in October 2007 with more than 20 years of legal experience and served as Deputy General Counsel of Holly Corporation until April 2008 and as Vice President, General Counsel and Secretary of HFC (formerly Holly Corporation) from April 2008 until January 2013.  Ms. McWatters served as the General Counsel of The Beck Group from 2005 through 2007.  Prior to joining The Beck Group, Ms. McWatters practiced law in various capacities at the predecessor firm to Locke Lord Bissell & Liddell LLP, the Law Offices of Denise McWatters, the legal department at Citigroup, N.A., and the law firm of Cox Smith Matthews Incorporated.

Board Leadership Structure

The Board of Directors of HLS (the “Board”) is responsible for selecting the Board leadership structure that is in the best interest of HLS and HEP. Effective January 1, 2014, the Board separated the positions of Chairman and Chief Executive Officer. Currently, Mr. Clifton serves as Chairman of the Board in a non-employee capacity, and Mr. Jennings serves as the Chief Executive Officer of HLS. The Board believes that at this time the separation of these positions enhances the oversight of management by the Board and HLS’s and HEP’s overall leadership structure. In addition, as a result of his former role as HLS’s Chief Executive Officer, Mr. Clifton has company-specific experience and expertise and as Chairman of the Board can identify strategic priorities, lead the discussion and execution of strategy, and facilitate the flow of information between management and the Board.

Presiding Director

Mr. Charles M. Darling, IV was appointed by the non-employee directors of HLS to serve as the lead independent director (the “Presiding Director”) of the Board. The Presiding Director has the following responsibilities:

• presiding at all executive sessions of the non-employee directors of the Board;

• consulting with management on Board and committee meeting agendas;

• acting as a liaison in appropriate instances between management and the non-employee directors, including advising the Chairman and the Chief Executive Officer on the efficiency of the Board meetings; and

• facilitating teamwork and communication between the non-employee directors and management.

Persons wishing to communicate with the non-employee directors are invited to email the Presiding Director at presiding.director.HEP@hollyenergy.com or write to: Charles M. Darling, IV, Presiding Director, c/o Secretary, Holly Logistic Services, L.L.C., 2828 N. Harwood, Suite 1300, Dallas, Texas 75201-1507. The Secretary will forward all communication to the appropriate director or directors, other than those communications that are merely solicitations for products or services or relate to matters that are of a type that are clearly improper or irrelevant to the functioning of the Board or the business and affairs of HLS and HEP.

Risk Management

The Board has an active role in overseeing management of the risks affecting HLS and HEP. The Board regularly reviews information regarding HLS and HEP’s credit, liquidity and business and operations, as well as the risks associated with each. The Board committees are also engaged in overseeing risk associated with HLS and HEP.

• The Compensation Committee oversees the management of risks relating to HLS’s executive compensation plans and arrangements.

• The Audit Committee oversees management of financial reporting and controls risks.

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• The Conflicts Committee oversees specific matters that the Board or the Conflicts Committee believes may involve conflicts of interest with HFC.

While each committee is responsible for evaluating certain risks and overseeing the management of such risks, the entire Board is ultimately responsible for the risk management of HLS and HEP and is regularly informed through committee reports about such risks.

The sole member of HLS manages risks associated with the independence of the Board. The Audit Committee and the Board also receive input and reports from HLS’s risk management oversight committee on management’s views of the risks facing HLS and HEP. The risk management oversight committee is made up of management personnel, none of whom serve on the Board and all of whom have a range of different backgrounds, skills and experiences with regard to the operational, financial and strategic risk profile of HLS and HEP. The risk management oversight committee monitors the risk environment for HLS and HEP as a whole, and reviews the activities that mitigate risks to an achievable and acceptable level.

Director Qualifications

The Board believes that it is necessary for each of HLS’s directors to possess a variety of qualities and skills. When searching for new candidates, the sole member of HLS considers the evolving needs of the Board and searches for candidates that fill any current or anticipated future needs. The Board also believes that all directors must possess a considerable amount of business management, business leadership and educational experience. When considering director candidates, the sole member of HLS first considers a candidate’s management experience and then considers issues of judgment, background, stature, conflicts of interest, integrity, ethics and commitment to the goal of maximizing unitholder value. The sole member of HLS also focuses on issues of diversity, such as diversity of education, professional experience and differences in viewpoints and skills. The sole member of HLS does not have a formal policy with respect to diversity; however, the Board and the sole member of HLS believe that it is essential that the Board members represent diverse viewpoints. In considering candidates for the Board, the sole member of HLS considers the entirety of each candidate’s credentials in the context of these standards. All our directors bring to the Board executive leadership experience derived from their service in many areas.

Director Independence

The Board has determined that Messrs. Darling, William J. Gray, Jerry W. Pinkerton, P. Dean Ridenour, William P. Stengel and James G. Townsend meet the applicable criteria for independence under the currently applicable rules of the New York Stock Exchange.

Audit Committee. The Audit Committee of HLS is composed of three directors, Messrs. Pinkerton, Ridenour and Darling. The Board has determined that each member of the Audit Committee is “independent” as defined by the New York Stock Exchange listing standards and Rule 10A-3 of the Securities Exchange Act of 1934 (the “Exchange Act”).

Conflicts Committee. The Conflicts Committee of HLS is composed of four directors, Messrs. Stengel, Pinkerton, Gray and Townsend. The Board has determined that each member of the Conflicts Committee is “independent” as defined by the New York Stock Exchange listing standards and Rule 10A-3 of the Exchange Act, as required by the Conflicts Committee Charter.

Compensation Committee. The Compensation Committee of HLS is composed of five directors, Messrs. Jennings, Darling, Gray, Stengel and Townsend. The Board has determined that each of Messrs. Darling, Gray, Stengel and Townsend is “independent” as defined by the New York Stock Exchange listing standards. Because we are a master limited partnership, Rule 303A.05 of the New York Stock Exchange Listed Company Manual, which requires a publicly traded company to have a compensation committee composed entirely of independent directors, does not apply to us.

Independence Determinations. In making its independence determinations, the Board considered certain transactions, relationships and arrangements. In determining Mr. Ridenour’s independence, the Board considered that Mr. Ridenour has not been employed by HFC or HLS since 2008 and has not received compensation in excess of $120,000 since 2009. In determining Mr. Townsend’s independence, the Board considered that Mr. Townsend has not been employed by HFC or HLS since 2011 and has not received compensation in excess of $120,000 since 2011. The Board has determined that these historical relationships do not impair Mr. Ridenour’s or Mr. Townsend’s independence. In addition, in determining Mr. Clifton’s and Mr. Gray’s independence, the Board considered the consulting fees each of them receives from HFC and determined that such consulting fees do not impair their independence.

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Code of Ethics

HLS has adopted a Code of Business Conduct and Ethics that applies to all of its officers, directors and employees, including HLS’s principal executive officer, principal financial officer, and principal accounting officer. The purpose of the Code of Business Conduct and Ethics is to, among other things, affirm HLS’s and HEP’s commitment to a high standard of integrity and ethics. The Code sets forth a common set of values and standards to which all of HLS’s officers, directors and employees must adhere. We will post information regarding an amendment to, or a waiver from, the Code of Business Conduct and Ethics on our website.

Copies of our Governance Guidelines, Audit Committee Charter, Compensation Committee Charter, and Code of Business Conduct and Ethics are available on our website at www.hollyenergy.com. Copies of these documents may also be obtained free of charge upon written request to Holly Energy Partners, L.P., Attention: Vice President, Investor Relations, 2828 N. Harwood, Suite 1300, Dallas, Texas, 75201-1507.

The Board, Its Committees and Director Compensation

Directors

The following individuals serve as directors of HLS:

_________________________________________________________________________________________

Matthew P. Clifton Director since July 2004. Age 63.

Principal Occupation: Chairman of the Board of HLS

Business Experience: Mr. Clifton has served as Chairman of the Board of HLS, in a non-employee capacity, since February 2014. Mr. Clifton also serves as a consultant for HFC since June 2014. Mr. Clifton previously served as Executive Chairman of HLS from January 2014 until his retirement in February 2014, as Chairman of the Board and Chief Executive Officer of HLS from March 2004 through December 2013 and as President of HLS from July 2011 to November 2012. Mr. Clifton joined Holly Corporation in 1980 and served as the Executive Chairman of HFC from July 2011 through December 2012. Mr. Clifton previously served as Chief Executive Officer of Holly Corporation from 2006 until the merger with Frontier Oil Corporation in July 2011, as Chairman of the Board of Holly Corporation from April 2007 until the merger with Frontier Oil Corporation in July 2011 and as President of Holly Corporation from 1995 until 2006.

Additional Directorships: Mr. Clifton served as a director of HFC from 1995 through December 2012.

Qualifications: Mr. Clifton has extensive knowledge of the operations of HLS and HEP, the refining industry and macro-economic conditions, as well as valuable industry relationships throughout the country. Mr. Clifton brings a unique and valuable perspective as well as an understanding of HLS’s and HEP’s history, culture, vision and strategy to the Board.

_________________________________________________________________________________________

Charles M. Darling, IV Director since July 2004. Age 66.

Principal Occupation: President of DQ Holdings, L.L.C.

Business Experience: Mr. Darling has served as President of DQ Holdings, L.L.C., a venture capital investment and consulting firm focused primarily on opportunities in the energy industry, since August 1998. Mr. Darling was previously the General Manager of Desert Power, LP and of its general partner, Desert Power, LLC, which was an indirect affiliate of DQ Holdings, L.L.C. In late 2006, Desert Power, LLC and Desert Power, LP, along with certain of their subsidiaries, filed for bankruptcy in Nevada. In late 2007, the bankruptcy court approved the plan of reorganization, which became final in accordance with its terms in early 2008. Mr. Darling also previously practiced law at the law firm of Baker Botts, L.L.P. for over 20 years.

Qualifications: Mr. Darling has significant experience addressing financial, legal, regulatory and risk matters affecting HLS and HEP. His service as a partner of a major international law firm practicing energy law, as President and General Counsel of a publicly traded energy company with a publicly traded pipelines

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master limited partnership and his subsequent endeavors in the energy industry as President of an investment and development firm provide him with valuable insight into our industry. Mr. Darling’s leadership skills, management and legal experience make him particularly well suited to be our Presiding Director.

________________________________________________________________________________________

William J. Gray Director since April 2008. Age 74.

Principal Occupation: Private Consultant

Business Experience: Mr. Gray is a private consultant. He served as a member of the New Mexico House of Representatives from November 2006 until January 2015. Mr. Gray has served as a governmental affairs consultant for HFC since January 2003. He also served as a consultant to Holly Corporation from October 1999 through September 2001. Mr. Gray served as a director of Holly Corporation from September 1996 until May 2008.  Mr. Gray was employed by Holly Corporation for over 30 years and retired in October 1999 at which time Mr. Gray was Senior Vice President, Marketing and Supply.

Qualifications: Mr. Gray brings to the Board forty years of experience in pipeline, refining, and marketing and supply. Mr. Gray also brings business and management expertise and extensive knowledge of, and a unique perspective on, regulatory matters affecting our industry as a result of his government experience.

__________________________________________________________________________________________

Michael C. Jennings Director since October 2011. Age 49.

Principal Occupation: Chief Executive Officer and President of HFC and Chief Executive Officer of HLS

Business Experience: Mr. Jennings was appointed as Chief Executive Officer of HLS in January 2014. Mr. Jennings has served as the Chief Executive Officer and President of HFC since the merger of Holly Corporation and Frontier Oil Corporation in July 2011 and as Chairman of the Board of HFC since January 2013. Mr. Jennings previously served as the President and Chief Executive Officer of Frontier Oil Corporation from 2009 until the merger in July 2011 and as the Executive Vice President and Chief Financial Officer of Frontier Oil Corporation from 2005 until 2009.

Additional Directorships: Mr. Jennings currently serves as the Chairman of the Board and a director of HFC and a director of ION Geophysical Corporation. Mr. Jennings served as a director of Frontier Oil Corporation from 2008 until the merger in July 2011 and as Chairman of the board of directors of Frontier Oil Corporation from 2010 until the merger in July 2011.

Qualifications: Mr. Jennings provides valuable and extensive industry knowledge and experience. His knowledge of the day-to-day operations of HFC provides a significant resource for the Board and facilitates discussions between the Board and HFC management.

________________________________________________________________________________________

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Jerry W. Pinkerton Director since July 2004. Age 74.

Principal Occupation: Retired

Business Experience: Mr. Pinkerton retired in December 2003. From December 2000 to December 2003, Mr. Pinkerton served as a consultant to TXU Corp. (now Energy Future Holdings Corp.), and from August 1997 to December 2000, Mr. Pinkerton served as Controller of TXU Corp. and its U.S. subsidiaries. Mr. Pinkerton previously served as the Vice President and Chief Accounting Officer of ENSERCH Corporation and was employed for 26 years as an auditor by Deloitte Haskins & Sells, a predecessor firm of Deloitte & Touche, LLP, including 15 years as an audit partner.

Additional Directorships: Since April 2012, Mr. Pinkerton has served on the board of directors of Southcross Energy Partners GP, LLC, the general partner of Southcross Energy Partners, L.P., and serves as the chair of the audit and conflicts committees of the board of directors of Southcross Energy Partners GP, LLC. Mr. Pinkerton served on the board of directors of Animal Health International, Inc., and served as chair of its audit committee, from May 2008 to June 2011.

Qualifications: Mr. Pinkerton brings to the Board his audit, accounting and financial reporting expertise and a level of financial sophistication that qualifies him as an audit committee financial expert. Due to his executive management experience with public companies and public accounting firms, Mr. Pinkerton possesses business and management expertise that provide an invaluable insight into HLS’s and HEP’s business.

__________________________________________________________________________________________

P. Dean Ridenour Director since August 2004. Age 73.

Principal Occupation: Retired

Business Experience: Mr. Ridenour retired in February 2010. Mr. Ridenour provided consulting services to Holly Corporation from January 2008 until February 2010, and served as Vice President and Chief Accounting Officer of Holly Corporation and HLS from January 2005 to January 2008. Mr. Ridenour served as Vice President, Special Projects of Holly Corporation from August 2004 to December 2004 and prior to becoming a full-time employee, provided full-time consulting services to Holly Corporation beginning in October 2002. Mr. Ridenour was employed for 34 years by Ernst & Young LLP, including 20 years as an audit partner, prior to retiring from such position in 1997.

Qualifications: Mr. Ridenour’s management experience and his accounting and financial reporting expertise qualify him as an audit committee financial expert and make him a valuable member of the Board. In addition, Mr. Ridenour’s prior experience at HLS and Holly Corporation provide him with a deep understanding of our business and industry.

__________________________________________________________________________________________

William P. Stengel Director since July 2004. Age 66.

Principal Occupation: Retired

Business Experience: Mr. Stengel retired in May 2003. From 1997 to May 2003, Mr. Stengel served as Managing Director of the global energy and mining group at Citigroup/Citibank, N.A.

Qualifications: Mr. Stengel’s executive management experience in public companies, banking and financial expertise, and general business and management expertise provides him with significant insight into our operations, management and finance.

____________________________________________________________________________________________

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James G. Townsend Director since January 2012. Age 60.

Principal Occupation: Member of the New Mexico House of Representatives

Business Experience: Mr. Townsend has served as a member of the New Mexico House of Representatives since January 2015. Mr. Townsend retired from HFC in December 2011. He was employed by Holly Corporation (and HFC) and/or HLS for more than 25 years. From 2008 until his retirement, Mr. Townsend served as Senior Vice President of UNEV Pipeline, LLC, a joint venture between Sinclair Oil Corporation and a subsidiary of HEP. Mr. Townsend served as Vice President, Operations for HLS from 2004 to 2007 and was responsible for all pipeline and terminal operations for Holly Corporation prior to the formation of HEP. Prior to such time, Mr. Townsend served in positions of increasing seniority at Holly Corporation.

Qualifications: Mr. Townsend brings to the Board his knowledge of the operations of HFC, HLS and their subsidiaries, his 25 years of experience in the industry, and his business expertise.

_____________________________________________________________________________________________

None of our directors reported any litigation for the period from 2005 to 2015 that is required to be reported in this Annual Report on Form 10-K.

The Board

Under the Company’s Governance Guidelines, Board members are expected to prepare for, attend and participate in all meetings of the Board and Board committees on which they serve. During 2014, the Board held ten meetings. Each director attended at least 75% of the total number of meetings of the Board and committees on which he served.

Board Committees

The Board currently has four standing committees:

• an Audit Committee;

• a Compensation Committee;

• a Conflicts Committee; and

• an Executive Committee.

Other than the Executive Committee, each of these committees operates under a written charter adopted by the Board.

During 2014, the Audit Committee held eightmeetings, the Conflicts Committee held fivemeetings and the Compensation Committee held fourmeetings.

The Board appoints committee members annually.The following table sets forth the current composition of our committees:

Name	Executive Committee	Audit Committee	Compensation Committee	Conflicts Committee
Matthew P. Clifton	x (Chair)
Charles M. Darling, IV		x	x (1)
William J. Gray			x	x
Michael C. Jennings	x		x (Chair)
Jerry W. Pinkerton	x	x (Chair)		x
P. Dean Ridenour		x
William P. Stengel	x		x	x (Chair)
James G. Townsend			x	x

________________________

(1) Mr. Darling serves as the chairman of the subcommittee of the Compensation Committee.

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Audit Committee

The functions of the Audit Committee include the following:

• selecting our independent registered public accounting firm and reviewing the professional services they provide;

• reviewing the scope of the audit performed by the independent registered public accounting firm;

• overseeing matters related to the internal audit function;

• reviewing the audit report issued by the independent auditor;

• reviewing HEP’s annual and quarterly financial statements;

• reviewing any material comments contained in the auditor’s letters to management;

• reviewing HEP’s internal accounting controls; and

• reviewing the type and extent of any non-audit work to be performed by the independent registered public accounting firm and its compatibility with their continued objectivity and independence.

Each member of the Audit Committee has the ability to read and understand fundamental financial statements. The Board has determined that Messrs. Pinkerton and Ridenour meet the requirements of an “audit committee financial expert”as defined by the rules of the SEC.

Conflicts Committee

The functions of the Conflicts Committee include reviewing specific matters that the Board or the Conflicts Committee believes may involve conflicts of interest with HFC. The Conflicts Committee determines if the resolution of the conflict of interest is fair and reasonable to HEP. Any matters approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties it may owe us or our unitholders.

Compensation Committee

The functions of the Compensation Committee include:

• reviewing, evaluating and approving the agreements, plans, policies and programs of HLS and HEP;

• discharging the Board’s responsibilities relating to compensation of HLS’s officers and directors;

• overseeing the preparation of the Compensation Discussion and Analysis to be included in the Annual Report and preparing the Compensation Committee Report to be included in the Annual Report; and

• administering HEP’s equity plan and HLS’s annual incentive plan.

The Compensation Committee has appointed a subcommittee comprised of four directors, Messrs. Darling, Gray, Stengel and Townsend, all of whom are “independent” as defined by the New York Stock Exchange listing standards, for purposes of approving equity awards, including performance goals applicable to such awards, if applicable, and any other matters that are within the responsibilities of the Compensation Committee requiring approval solely by independent members of the Board. During 2014, the subcommittee of the Compensation Committee held four meetings.

The Compensation Committee has engaged Frederic W. Cook & Co. (the “Compensation Consultant” or “FWC”), an executive compensation consulting firm, to advise it regarding the compensation of HLS’s officers and directors. In selecting FWC as its independent compensation consultant, the Compensation Committee assessed the independence of FWC pursuant to SEC rules and considered, among other things, whether FWC provides any other services to HLS or us, the fees paid by us to FWC as a percentage of FWC’s total revenues, the policies of FWC that are designed to prevent any conflict of interest between FWC, the Compensation Committee, HLS and us, any personal or business relationship between FWC and a member of the Compensation Committee or one of HLS’s executive officers and whether FWC owned any of our common units. In addition to the foregoing,

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the Compensation Committee received an independence letter from FWC, as well as other documentation addressing the firm’s independence. FWC reports exclusively to the Compensation Committee and does not provide any additional services to HLS or us. The Compensation Committee has discussed these considerations and has concluded that FWC is independent and that neither we nor HLS have any conflicts of interest with FWC.

Executive Committee

The Executive Committee has such authority as the Board may delegate to it from time to time.

Report of the Audit Committee for the Year Ended December 31, 2014

Management of Holly Logistic Services, L.L.C. is responsible for Holly Energy Partners, L.P.’s system of internal controls over financial reporting. The Audit Committee selected, and the Board approved, the selection of, Ernst & Young LLP as Holly Energy Partners, L.P.’s independent registered public accounting firm to audit the books, records and accounts of Holly Energy Partners, L.P. for the year ended December 31, 2014.Ernst & Young LLP is responsible for performing an independent audit of Holly Energy Partners, L.P.’s consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board and to issue a report thereon. The Audit Committee also is responsible for selecting, engaging and overseeing the work of the independent registered public accounting firm, which reports directly to the Audit Committee, and evaluating its qualifications and performance. Among other things, to fulfill its responsibilities, the Audit Committee:

• reviewed and discussed Holly Energy Partners, L.P.’s quarterly unaudited consolidated financial statements and its audited annual consolidated financial statements for the year ended December 31, 2014 with management and Ernst & Young LLP, including a discussion of the quality, not just the acceptability, of the accounting principles, the reasonableness of significant judgments and the clarity of disclosures in the financial statements, including those in management’s discussion and analysis thereof;

• discussed with Ernst & Young LLP the matters required to be discussed by Auditing Standards No. 16, Communications with Audit Committees, as adopted by the Public Company Accounting Oversight Board;

• discussed with Ernst & Young LLP matters relating to its independence and received the written disclosures and letter from Ernst & Young required by applicable requirements of PCAOB regarding the independent accountant’s communications with the Audit Committee concerning the firm’s independence;

• discussed with Holly Energy Partners, L.P.’s internal auditors and Ernst & Young LLP the overall scope and plans for their respective audits (the Audit Committee meets with the internal auditors and Ernst & Young LLP, with and without management present, to discuss the results of their examinations, their evaluations of our internal controls and the overall quality of Holly Energy Partners, L.P.’s financial reporting); and

• considered whether Ernst & Young LLP’s provision of non-audit services to Holly Energy Partners, L.P. is compatible with the auditor’s independence

The Audit Committee charter requires the Audit Committee to approve in advance all audit and non-audit services to be provided by our independent registered public accounting firm. All fees for audit, audit-related and tax services as well as all other fees presented under Item 14 “Principal Accountant Fees and Services” were approved by the Audit Committee in accordance with its charter.

Based on the foregoing review and discussions and such other matters the Audit Committee deemed relevant and appropriate, the Audit Committee recommended to the Board that the audited consolidated financial statements of Holly Energy Partners, L.P. for the year ended December 31, 2014 be included in Holly Energy Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2014 for filing with the SEC.

Members of the Audit Committee:

Jerry W. Pinkerton, Chairman

Charles M. Darling, IV

P. Dean Ridenour

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Director Compensation

The Compensation Committee annually evaluates the compensation program for members of the Board who are not officers or employees of HLS or HFC (“non-employee directors”). In 2014, based on a recommendation from the Compensation Committee, the Board approved changes to the non-employee director compensation program, effective August 1, 2014. The components of non-employee director compensation prior to and after August 1, 2014 are described below. Directors who also serve as officers or employees of HLS or HFC do not receive additional compensation for serving on the Board.

	Effective Prior to August 1, 2014		Effective August 1, 2014
Annual cash retainer (payable in four quarterly installments)	$	50,000	$	60,000
Board meeting or committee meeting attended in person (also paid to non-members of committees who are invited to attend by such committee’s chairman) (1)	$	1,500	$	1,500
Telephonic special board or committee meeting (2)	$	1,000	$	1,000
Each attended strategy meeting with HLS management	$	1,500	$	1,500
Annual equity retainer of restricted units under the Long-Term Incentive Plan	$	75,000	$	75,000
Special cash retainer for chairmen of committees and subcommittees (payable in four quarterly installments) (3)	$	10,000	$	10,000

__________________

(1)	Upon submission of appropriate documentation, non-employee directors also are reimbursed for reasonable out-of-pocket expenses incurred in connection with attending Board or committee meetings.
(2)	Prior to August 1, 2014, non-employee directors received $1,000 for telephonic special meetings that lasted over 30 minutes, and the Chairman of the Board and the chairman of each committee had authority to exercise his discretion as to whether the topics discussed at a telephonic special meeting of the Board or committee, as applicable, that lasted 30 minutes or less warranted a fee of $1,000. Effective August 1, 2014, non-employee directors receive $1,000 for all telephonic special meetings regardless of the length of the meeting.
(3)	In connection with his retirement from HLS, the Compensation Committee approved a special retainer for Mr. Clifton for 2014, which is described in greater detail in footnote (2) to the Director Compensation Table below.

Annual Equity Awards

Non-employee directors receive an annual equity award grant under the Holly Energy Partners, L.P. Amended and Restated Long-Term Incentive Plan (“Long-Term Incentive Plan”) in the form of restricted units having a fair market value of $75,000 on the date of grant, with the number of restricted units rounded up to the nearest whole unit in the case of fractional units. The fair market value of the grant is calculated based on the closing price of our common units on the day of grant (or the last business day prior to the date of grant if the date of grant occurs on a Saturday or Sunday). Continued service on the Board through the stated vesting date, which in most cases is approximately one year following the date of grant, is required in order for the restricted units to vest. Vesting of all unvested units will accelerate upon a change in control of HFC, HLS, HEP or HEP Logistics. In addition, vesting of unvested units will accelerate on a pro-rata basis upon the director’s death, total and permanent disability or retirement. Directors are entitled to receive all distributions paid with respect to outstanding restricted units. The distributions are not subject to forfeiture. The directors also have a right to vote with respect to the restricted units.

At its regularly scheduled third quarter meeting in 2014, the Compensation Committee decided to change the timing of the annual equity award grants for non-employee directors. Specifically, the Compensation Committee determined that (a) annual restricted unit grants beginning in 2015 and later years will be made in the fourth quarter of each year, rather than in the third quarter of each year, and (b) annual restricted unit grants will vest on December 1 of the year following the year in which the grant is made, rather than on August 1 of that year, so that continued service on the Board for a full year following the date of grant of the award is required in order for the restricted units to become vested. As a result, for 2014 only, the non-employee directors received an annual equity award grant on August 1, 2014 in the form of restricted units having a fair market value of $100,000 on the date of grant (instead of the typical $75,000), which will vest in full on December 1, 2015, subject to continued service on the Board through that date. The additional $25,000 compensates the non-employee directors for the extended restricted period for the 2014 grant beyond the typical one-year period. The next annual equity award grant to the non-employee directors is scheduled to be made in the fourth quarter of 2015.

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Non-Qualified Deferred Compensation

Non-employee directors are eligible to participate in the HollyFrontier Corporation Executive Nonqualified Deferred Compensation Plan, which is not tax-qualified under Section 401 of the Internal Revenue Code and allows participants to defer receipt of certain compensation (the “NQDC Plan”). The NQDC Plan allows non-employee directors the ability to defer up to 100% of their cash retainers and meeting fees for a calendar year. Participating directors have full discretion over how their contributions to the NQDC Plan are invested among the offered investment options. Earnings on amounts contributed to the NQDC Plan are calculated in the same manner and at the same rate as earnings on actual investments. Neither HLS nor HFC subsidizes a participant’s earnings under the NQDC Plan.

Mr. Pinkerton was the only non-employee director that participated in the NQDC Plan in 2014. During 2014, no above market or preferential earnings were paid to Mr. Pinkerton under the NQDC Plan and, therefore, none of the earnings received by Mr. Pinkerton during 2014 are included in the Director Compensation Table below. For additional information on the NQDC Plan, see “Compensation Discussion and Analysis-Overview of 2014 Executive Compensation Components and Decisions-Retirement and Benefit Plans-Deferred Compensation Plan” and thenarrative preceding the “Nonqualified Deferred Compensation Table.”

Unit Ownership and Retention Policy for Directors

Effective October 2013, our directors became subject to a new unit ownership and retention policy. Pursuant to the policy, each director is required to hold during service on the Board common units equal in value to at least two times the annual equity retainer paid to non-employee directors. For 2014, each non-employee director was required to hold common units equal in value to $200,000. Each subject director is required to meet the applicable requirements within five years of first being subject to the policy. Mr. Clifton first became subject to the director unit ownership and retention policy upon his appointment as Chairman of the Board in a non-employee capacity, effective February 28, 2014.

Directors are also required to continuously own sufficient units to meet the unit ownership and retention requirements once attained. Until directors meet the requirements, they will be required to hold 25% of the units received from any equity award. If a director attains compliance with the policy and subsequently falls below the requirement because of a decrease in the price of our common units, the director will be deemed in compliance provided that the director retains the units then held.

As of December 31, 2014, all of our directors were in compliance with the unit ownership and retention policy.

Anti-Hedging and Anti-Pledging Policy

Members of the Board are subject to the HEP Insider Trading Policy, which, among other things, prohibits such directors from entering into short sales or hedging or pledging our common units and HFC common stock.

Director Compensation Table

The table below sets forth the compensation earned in 2014 by each of the non-employee directors of HLS:

Name (1)	Fees Earned or Paid in Cash (2)	Unit Awards (3)	All Other Compensation	Total
Matthew P. Clifton (4)	$154,494	$100,033	$ 69,637 (5)	$324,164
Charles M. Darling, IV	99,167	100,033	—	199,200
William J. Gray	86,167	100,033	32,231 (6)	218,431
Jerry W. Pinkerton	94,667	100,033	—	194,700
P. Dean Ridenour	77,167	100,033	—	177,200
William P. Stengel	96,167	100,033	—	196,200
James G. Townsend	80,167	100,033	—	180,200

__________________

(1) Mr. Jennings is not included in this table because he received no additional compensation for his service on the Board since, during 2014, Mr. Jennings was also an officer of HFC and HLS. The compensation paid by HFC to Mr. Jennings in 2014 will be shown in HFC’s 2015 Proxy Statement. A portion of the compensation paid to Mr. Jennings by HFC is allocated to the services he performs for us in his capacity as an officer of HLS and is disclosed in the “Summary Compensation Table” below.

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(2) For Mr. Clifton, includes a special retainer paid to him in 2014 of $125,000, less the amount of salary paid to him from January 1, 2014 until February 27, 2014, which salary amount is included in the “All Other Compensation” column of this table.

(3) Reflects the aggregate grant date fair value of restricted units granted to the non-employee directors on August 1, 2014, computed in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 718 (“FASB ASC Topic 718”), determined without regard to forfeitures. See Note 6 to our consolidated financial statements for the fiscal year ended December 31, 2014, for a discussion of the assumptions used in determining the FASB ASC Topic 718 grant date fair value of these awards.

On August 1, 2014, each of the non-employee directors received an award of 2,995 restricted units that vest on December 1, 2015, subject to continued service on the Board. As of December 31, 2014, these are the only restricted units held by our non-employee directors. Mr. Clifton also holds 48,948 performance units (assuming a maximum payout level of 200% at the time of vesting), which were granted to him while he served as Executive Chairman of HLS. For additional information regarding the annual restricted unit grants made on August 1, 2014 and certain changes to our annual equity award grant process for non-employee directors, please see “Annual Equity Retainer Awards” above.

(4) From January 1, 2014 until February 27, 2014, Mr. Clifton served as Executive Chairman of HLS. Effective February 28, 2014, Mr. Clifton retired from employment and was appointed Chairman of the Board in a non-employee capacity.

(5) During the period he served as Executive Chairman in 2014, Mr. Clifton received base salary payments for service as an employee. In addition, during that same period, the Compensation Committee approved cash payments to Mr. Clifton, as additional regular earnings, equal to amounts he would have received for service on the Board if he were a non-employee director. Thus, the amount reported in the “All Other Compensation” column represents (a) $27,404 earned by Mr. Clifton as salary in 2014 prior to his retirement on February 28, 2014, and (b) $15,500 earned as additional regular earnings for amounts he would have received for service on the Board if he were a non-employee director during the period from January 1, 2014 through February 27, 2014. In addition, the amount reported in the “All Other Compensation” column represents $26,733 in fees for consulting services provided by Mr. Clifton to HFC during 2014. None of the consulting fees were paid by us.

(6) Represents fees for consulting services provided by Mr. Gray to HFC during 2014. None of the consulting fees were paid by us.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires directors, executive officers and persons who beneficially own more than 10% of HEP’s units to file certain reports with the SEC and New York Stock Exchange concerning their beneficial ownership of HEP’s equity securities. Based on a review of these reports, other information available to us and written representations from reporting persons indicating that no other reports were required, all such reports concerning beneficial ownership were filed in a timely manner by reporting persons during the year ended December 31, 2014.

Item 11. Executive Compensation

Compensation Discussion and Analysis

This compensation discussion and analysis provides information about our compensation objectives and policies for the HLS executive officers who are our “Named Executive Officers” for 2014, to the extent the Compensation Committee of the Board (the “Compensation Committee”) determines the compensation of these individuals or such compensation is allocated to us pursuant to SEC rules. In addition, the compensation discussion and analysis is intended to place in perspective the information contained in the executive compensation tables that follow this discussion. Additionally, we describe our policies relating to reimbursement to HFC and HLS for compensation expenses.

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Overview

We are managed by HLS, the general partner of HEP Logistics, our general partner. HLS is a subsidiary of HFC. The employees providing services to us are provided by HLS, which utilizes people employed by HFC to perform services for us, as we do not have any employees. As of December 31, 2014, HLS utilized 273 people employed by HFC to provide general, administrative and operational services to us.

For 2014, the HLS executive officers who were our “Named Executive Officers” are as follows:

Name	Position with HLS
Michael C. Jennings	Chief Executive Officer
Douglas S. Aron	Executive Vice President and Chief Financial Officer
Bruce R. Shaw	President
Mark T. Cunningham	Senior Vice President, Operations
Denise C. McWatters	Senior Vice President, General Counsel and Secretary

Certain executive officers of HLS are also officers of HFC or provide services to HFC. During 2014, Messrs. Shaw and Cunningham spent all of their professional time managing our business and affairs. Messrs. Jennings and Aron and Ms. McWatters also served as executive officers of HFC and devoted as much of their professional time as was necessary to oversee the management of our business and affairs.

Under the terms of the Omnibus Agreement, we pay an annual administrative fee to HFC ($2.3 million in 2014 and $2.4 million as of January 1, 2015) for the provision of general and administrative services for our benefit, which may be increased or decreased as permitted under the Omnibus Agreement. The administrative services covered by the Omnibus Agreement include, without limitation, the costs of corporate services provided to us by HFC such as accounting, tax, information technology, human resources, in-house legal support and outside legal support for general corporate and tax matters; and office space, furnishings and equipment. None of the services covered by the administrative fee is assigned any particular value individually. Although certain Named Executive Officers provide services to both HFC and us, no portion of the administrative fee is specifically allocated to services provided by the Named Executive Officers to us. Rather, the administrative fee generally covers services provided to us by HFC and, except as described below, there is no reimbursement by us for the specific costs of such services. See Item 13, “Certain Relationships and Related Transactions, and Director Independence” of this Annual Report on Form 10-K for additional discussion of our relationships and transactions with HFC.

Under the Omnibus Agreement, we also reimburse HFC for certain expenses incurred on our behalf, such as for salaries and employee benefits for certain personnel employed by HFC who perform services for us on behalf of HLS, as described in greater detail below. The partnership agreement provides that our general partner will determine the expenses that are allocable to us. With respect to equity compensation paid by us to the Named Executive Officers, HLS purchases the units delivered pursuant to awards under our Long-Term Incentive Plan, and we reimburse HLS for the purchase price of the units.

In 2014, compensation decisions for Messrs. Shaw and Cunningham were made by the Compensation Committee, and we reimbursed HFC for 100% of the compensation expenses incurred by HFC for salary, bonus, retirement and other benefits provided to them. For the same period, we also reimbursed HLS for 100% of the expenses incurred in providing Messrs. Shaw and Cunningham with awards under our Long-Term Incentive Plan. All compensation provided to Messrs. Shaw and Cunningham for 2014 is discussed and reported, in accordance with SEC rules, in the narratives and tables that follow.

At its January 24, 2012 meeting, the Compensation Committee determined that, beginning in 2012, the executive officers of HLS that also served as executive officers of HFC, including Messrs. Jennings and Aron and Ms. McWatters, would no longer receive awards of equity-based compensation under the Long-Term Incentive Plan for the services provided to us. Instead, all compensation paid to such executive officers beginning in 2012 was paid and determined by HFC, without input from the Compensation Committee.

The compensation for the services performed for us by Messrs. Jennings and Aron and Ms. McWatters is covered by the administrative fee under the Omnibus Agreement (and therefore not subject to reimbursement by us); however, in accordance with SEC rules, for purposes of these disclosures, a portion of the compensation paid by HFC to Messrs. Jennings and Aron and Ms. McWatters for 2014 is allocated to the services they performed for us during 2014. The allocation was made based on the assumption that Mr. Jennings spent, in the aggregate, approximately 15% of his professional time in 2014 on our business and affairs; Mr. Aron spent, in the aggregate, approximately 20% of his professional time in 2014 on our business and affairs; and Ms. McWatters

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spent, in the aggregate, approximately 30% of her professional time in 2014 on our business and affairs. As a result, only 15% of the total amount of compensation Mr. Jennings received from HFC for 2014, only 20% of the total amount of compensation Mr. Aron received from HFC for 2014 and only 30% of the total amount of compensation Ms. McWatters received from HFC for 2014 is disclosed in the tables that follow. Because HFC made all decisions regarding the compensation paid to Messrs. Jennings and Aron and Ms. McWatters, those decisions are not discussed in this compensation discussion and analysis. The total compensation paid by HFC to Messrs. Jennings and Aron and Ms. McWatters in 2014 will be disclosed in HFC’s 2015 Proxy Statement.

The Compensation Committee does not review or approve pension or retirement benefits for any of the Named Executive Officers. Rather, all pension and retirement benefits provided to the executives are the same pension and retirement benefits that are provided to employees of HFC generally, and such benefits are sponsored and administered entirely by HFC without input from HLS or the Compensation Committee. The pension and retirement benefits provided to Messrs. Shaw and Cunningham are described below and are charged to us monthly in accordance with the Omnibus Agreement.

Objectives of Compensation Program

Our compensation program is designed to attract and retain talented and productive executives who are motivated to protect and enhance our long-term value for the benefit of our unitholders. Our objective is to be competitive with our industry and encourage high levels of performance from our executives.

In supporting our objectives, the Compensation Committee balances the use of cash and equity compensation in the total direct compensation package provided to Messrs. Shaw and Cunningham; however, the Compensation Committee has not adopted any formal policies for allocating their compensation among salary, bonus and long-term equity compensation.

In the fourth quarter of 2013, the Compensation Committee, with the assistance of the Chief Executive Officer, reviewed the mix and level of cash and long-term equity incentive compensation for Messrs. Shaw and Cunningham with a goal of providing competitive compensation to retain them, while at the same time providing them incentives to maximize long-term value for us and our unitholders. After reviewing internal evaluations, input by management, and market data provided by the Compensation Consultant, the Compensation Committee believes that the 2014 compensation paid to Messrs. Shaw and Cunningham reflects an appropriate allocation of compensation between salary, bonus and equity compensation.

Role of the Compensation Consultant and the CompensationCommittee in the Compensation Setting Process

The Compensation Committee has engaged Frederic W. Cook & Co. (the “Compensation Consultant” or “FWC”), a consulting firm specializing in executive compensation, to advise the Compensation Committee on matters related to executive and non-employee director compensation and long-term equity incentive awards. The Compensation Consultant provides the Compensation Committee with relevant market data, updates on related trends and developments, advice on program design, and input on compensation decisions for executive officers and non-employee directors. As discussed above under “-The Board, Its Committees and Director Compensation-Board Committees-Compensation Committee,” the Compensation Committee has concluded that we do not have any conflicts of interest with FWC.

The Compensation Consultant does not have authority to determine the ultimate compensation paid to executive officers or non-employee directors, and the Compensation Committee is under no obligation to utilize the information provided by the Compensation Consultant when making compensation decisions. The Compensation Consultant provides external context and other input to the Compensation Committee prior to the Compensation Committee approving salaries and fees, awarding bonuses and equity compensation or establishing awards for the upcoming year.

Review of Market Data

Market pay levels are one of many factors considered by the Compensation Committee in setting compensation for the Named Executive Officers. The Compensation Committee regularly reviews comparison data provided by the Compensation Consultant with respect to salary, annual incentive levels and long-term incentive levels as one point of reference in evaluating the reasonableness and competitiveness of the compensation paid to our executive officers as compared to companies with which we compete for executive talent. In addition, the Compensation Committee reviews such data to evaluate whether our compensation reflects practices of comparable companies of generally similar size and scope of operations. The Compensation Consultant obtains market information from various sources, including published compensation surveys (such asthe Liquid Pipeline Roundtable Compensation Survey) and SEC filings of publicly traded companies that the Compensation Consultant and the Compensation Committee consider appropriate peer group companies. The purpose of the peer group is to provide a frame of reference with respect to executive compensation at companies of generally comparable size and scope of operations, rather than

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to set specific benchmarks for the compensation provided to the Named Executive Officers. We select peer group companies that we believe provide relevant data points for our consideration.

The peer group used in determining 2014 compensation included the following publicly traded master limited partnerships, which are representative of the companies with which we compete for executives:

Atlas Pipeline Partners, L.P.	NuStar Energy L.P.
Crosstex Energy, L.P.	PAA Natural Gas Storage, L.P.
DCP Midstream Partners L.P.	PVR Partners, L.P.
Eagle Rock Energy Partners, L.P.	Regency Energy Partners, L.P.
Genesis Energy, L.P.	Summit Midstream Partners, L.P.
Crestwood Equity Partners LP (formerly known as Inergy L.P.)	Targa Resources Partners, L.P.

The peer group used in 2014 was changed from the peer group used in 2013 due to the initial public offerings of more similarly situated publicly traded master limited partnerships and merger and acquisition activity.

Our objective generally is to position pay at levels approximately in the middle range of market practice, taking into account median levels derived from our peer group analysis. Following advice from the Compensation Consultant, we consider our salary and non-salary compensation components relative to the median compensation levels generally within the peer group rather than to an exact percentile above or below the median. If compensation is generally within plus or minus 20% of the market median, it is considered to be in the middle range of the market.

In 2014, the total direct compensation paid to Messrs. Shaw and Cunningham was generally in the middle range of the market. As noted, however, this market analysis is just one of many factors considered when making overall compensation decisions for our executives.

Role of Named Executive Officers in Determining Executive Compensation

In making executive compensation decisions, the Compensation Committee reviewed the total compensation provided to each executive in the prior year, the executive’s overall performance and market data provided by the Compensation Consultant. The Compensation Committee also considered recommendations by the Chief Executive Officer and other factors in determining the appropriate final compensation amounts.

Various members of management facilitate the Compensation Committee’s consideration of compensation for Named Executive Officers by providing data for the Compensation Committee’s review. This data includes, but is not limited to, performance evaluations, performance-based compensation provided to the Named Executive Officers in previous years, tax-related considerations and accounting-related considerations. Management provides the Compensation Committee with guidance as to how such data impacts performance goals set by the Compensation Committee during the previous year. Given the day-to-day familiarity that management has with the work performed, the Compensation Committee values management’s recommendations, although no Named Executive Officer has authority to determine or comment on compensation decisions directly related to himself. The Compensation Committee makes the final decision as to the compensation of the Named Executive Officers (other than Messrs. Jennings and Aron and Ms. McWatters).

Overview of 2014 Executive Compensation Components and Decisions

In 2014, compensation decisions for Messrs. Shaw and Cunningham were made by the Compensation Committee. The components of compensation actually received by Messrs. Shaw and Cunningham in 2014 are as follows:

• base salary;

• annual incentive cash bonus compensation;

• long-term equity incentive compensation;

• severance and change in control benefits;

• health and retirement benefits; and

• perquisites.

Each of these components is described in further detail in the narrative that follows.

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Base Salary

In the fourth quarter of 2013, the Compensation Committee conducted its annual review of base salaries for Messrs. Shaw and Cunningham and considered each of their respective positions, level of responsibility and performance in 2013. The Compensation Committee also reviewed competitive market data relevant to each individual’s position provided by the Compensation Consultant. Following a review of the various factors listed above, the Compensation Committee determined that an increase in each of Messrs. Shaw and Cunningham’s base salary was warranted for 2014. The following table sets forth the 2014 base salaries for Messrs. Shaw and Cunningham:

Name	2013 Base Salary	2014 Base Salary (1)	Percentage Increase from 2013
Bruce R. Shaw	$450,000	$468,000	4%
Mark T. Cunningham	$270,000	$278,100	3%

______________________

(1) Represents salaries effective January 1, 2014.

Annual Incentive Cash Bonus Compensation

The Board adopted the HLS Annual Incentive Plan (the “Annual Incentive Plan”) in August 2004 to motivate eligible employees to produce outstanding results, encourage superior performance, increase productivity, contribute to health and safety goals, and aid in attracting and retaining key employees. The Compensation Committee oversees the administration of the Annual Incentive Plan, and any potential awards granted pursuant to the plan are subject to final determination by the Compensation Committee of achievement of the performance metrics for the applicable performance periods.

In the fourth quarter of 2013, the Compensation Committee approved target awards under the Annual Incentive Plan for 2014 and determined that the applicable performance period for the Annual Incentive Plan awards would be the 12-month period beginning October 1, 2013 and ending September 30, 2014, with determination and payment of the cash bonus amounts occurring in the fourth quarter of 2014.

The 2014 Annual Incentive Plan awards were subject to achievement of the following metrics:

• Actual Distributable Cash Flow vs. Budget: Half of the award is equal to a pre-established percentage of the employee’s base salary and is earned based upon our actual distributable cash flow during the performance period compared to the budgeted distributable cash flow for the performance period, adjusted for differences in estimated and actual Producers Price Index adjustments and differences in the timing of known acquisitions.

The payout on this metric is based on the following:

Actual Distributable Cash Flow vs. Budget	Bonus Achievement (1)
Less than 100%	Actual Distributable Cash Flow as Percentage of Budget
100%	100%
Greater than 100%	100% plus 3% for each 1% Actual Distributable Cash Flow exceeds Budget

_________________________

(1) The percentages are interpolated between percentage points and rounded to the nearest hundredth percent.

The performance metric of distributable cash flow is used because it is a widely accepted financial indicator for comparing partnership performance. We believe that this measure provides an enhanced perspective of the operating performance of our assets and the cash our business is generating, and is therefore a useful criterion in evaluating management’s performance and in linking the payout of the award to our performance.

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• Individual Performance: The other half of the award is equal to a pre-established percentage of the employee’s base salary and is earned based on the employee’s individual performance during the performance period, as determined in the discretion of the employee’s immediate supervisor. The employee’s individual performance is evaluated through a performance review by the employee’s immediate supervisor, which includes a written assessment. The assessment reviews several criteria, including how well the employee performed his or her pre-established individual goals during the performance period and the employee’s interpersonal effectiveness, integrity, and business conduct.

In addition to the pre-defined performance metrics described above, the Compensation Committee has discretion to approve an increase or a decrease in the executive officer’s bonus. Increases and decreases are determined using the same factors used to establish bonuses, and poor results on the indicated factors could, in the discretion of the Compensation Committee, result in a decrease in a bonus. The Compensation Committee may also consider other factors, including environmental, health and safety and conditions outside the control of the executive that could have affected the performance metrics. If the Compensation Committee believes additional compensation is warranted to reward an executive for outstanding performance, the Compensation Committee may increase the executive’s bonus amount in its discretion. In making the determination as to whether such discretion should be applied (either to decrease or increase a bonus), the Compensation Committee reviews recommendations from management.

The following table sets forth the target and maximum award opportunities (as a percentage of annual base salary) for Messrs. Shaw and Cunningham for 2014, and the portion of their target award opportunity allocated to each performance metric. The award opportunity amounts and allocations were not changed from 2013.

	Allocation Between Performance Metrics		Award Opportunities
Name	Actual vs. Budgeted DCF	Individual	Target	Maximum
Bruce R. Shaw	27.5%	27.5%	55.0%	110.0%
Mark T. Cunningham	20.0%	20.0%	40.0%	80.0%

Following the end of the performance period, the Chief Executive Officer evaluates the extent to which the applicable performance metrics have been achieved and recommends a bonus amount for each executive officer to the Compensation Committee. The Compensation Committee then determines the actual amount of the bonus award earned by and payable to each executive officer. Pursuant to our Annual Incentive Plan, the Compensation Committee determines actual achievement of each performance metric individually and the percentages determined with respect to the two performance metrics are then added together and multiplied by the individual’s base salary to calculate the bonus amount.

For the 2014 performance period, the actual distributable cash flow ($165.15 million) exceeded the budgeted distributable cash flow ($160.05 million) by 3.19%. As a result, the payout on this metric was approximately 109.56%. The following table sets forth the actual payouts to Messrs. Shaw and Cunningham for 2014 as a percentage of base salary, including payments made based on actual distributable cash flow versus budget and discretionary bonuses awarded for individual performance.

Name	Actual vs. Budgeted DCF	Individual	Total
Bruce R. Shaw	30.1%	26.1%	56.2%
Mark T. Cunningham	21.9%	23.7%	45.6%

In addition, for 2014, we awarded special one-time discretionary bonuses to Messrs. Shaw and Cunningham to recognize their contributions to us during the year in the amount of $10,680 and $7,992, respectively. Specifically, a special discretionary bonus was awarded to Mr. Shaw due to his understanding of our business, his credibility and approach with our employees and his overall commitment to the organization, and a special discretionary bonus was awarded to Mr. Cunningham for his efforts and contributions to us in 2014.

Long-Term Equity Incentive Compensation

The Long-Term Incentive Plan was adopted by the Board in August 2004 with the objective of promoting our interests by providing equity incentive compensation awards to eligible individuals. The Long-Term Incentive Plan also is intended to enhance our ability to attract and retain the services of individuals who are essential for our growth and profitability, to encourage those individuals to devote their best efforts to advancing our business, and to align the interests of those individuals with the interests of our unitholders. The Long-Term Incentive Plan was most recently amended and restated effective February 10, 2012.

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The Long-Term Incentive Plan provides for the granting of the following awards: unit options, unit appreciation rights, restricted units, phantom units, unit awards and substitute awards. The Compensation Committee may approve grants of awards on terms that it determines appropriate, including the period during and the conditions on which the award will vest. Since our inception, we have granted only awards of restricted units, phantom units with time based vesting, fully vested unit awards, and phantom units with performance vesting (referred to as “performance units”).

The Compensation Committee typically grants long-term equity incentive awards to the Named Executive Officers (other than the Named Executive Officers who are also executive officers of HFC) on an annual basis. In determining the appropriate amount and type of long-term equity incentive awards to be granted to the Named Executive Officers each year, the Compensation Committee considers the executive’s position, scope of responsibility, base salary and available compensation information for executives in comparable positions in similar companies. Our goal is to reward the creation of value and strong performance with variable compensation dependent on that performance. For the 2014 year, the Compensation Committee awarded both restricted units and performance units to Messrs. Shaw and Cunningham. Any equity compensation awards granted by HFC to Messrs. Jennings and Aron and Ms. McWatters for the 2014 year will be disclosed in HFC’s 2015 Proxy Statement.

Historically, annual long-term equity incentive awards were granted during the first quarter of each year. In the fourth quarter of 2013, the Compensation Committee decided to make certain changes to its long-term equity incentive award grant process, including changes to the timing of annual grants for each year. Specifically, the Compensation Committee determined that annual grants of long-term equity incentive awards for 2014 and later years will be made in the fourth quarter of the year preceding the year to which the award relates, in order to align the timing of the long-term equity incentive award grants with the timing of the other compensation decisions made for our executive officers. Pursuant to SEC rules, the long-term equity incentive awards granted in November 2013 for the 2014 year are disclosed as 2013 compensation in the Summary Compensation Table (with respect to those Named Executive Officers who received long-term equity incentive awards from us in November 2013) and are not included in the 2014 Grants of Plan-Based Awards table below; however, because these awards relate to the 2014 year, they are described in greater detail below.

Restricted Unit Awards

A restricted unit award is an award of common units that are subject to a risk of forfeiture. In November 2013, Messrs. Shaw and Cunninghamwere the only current executive officers who were granted restricted units. The number of restricted units awarded is initially approved by the Compensation Committee in dollar amounts established according to the pay grade of the executive officer. The award is then converted to a number of units by dividing the targeted dollar amount by the closing price of our common units on the grant date of the award. The following table sets forth the number of restricted units awarded to each of them in November 2013 for the 2014 year:

Name	Number of Restricted Units
Bruce R. Shaw	10,692
Mark T. Cunningham	6,786

Restricted unitholders have all the rights of a unitholder with respect to the restricted units, including the right to receive all distributions paid with respect to such restricted units (at the same rate as distributions paid on our common units) and any right to vote with respect to the restricted units, subject to limitations on transfer and disposition of the units during the restricted period. The distributions are not subject to forfeiture.

The restricted units granted in November 2013 to Messrs. Shaw and Cunningham vest in three equal annual installments as noted in the following table and will be fully vested and nonforfeitable after December 15, 2016.

Restricted Unit Vesting Criteria
Vesting Date (1)	Cumulative Amount of Restricted Units Vested
Immediately following December 15, 2014	1/3
Immediately following December 15, 2015	2/3
Immediately following December 15, 2016	All

(1) Vesting will occur on the first business day following December 15 if December 15 falls on a Saturday or a Sunday. The provisions affecting the vesting of these awards upon a change in control or certain terminations of employment are described in greater detail below in the section titled “Potential Payments upon Termination and Change in Control.”

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Performance Unit Awards

A performance unit is a notational phantom unit subject to certain performance conditions that entitles the grantee to receive a common unit upon the vesting of the unit. Performance units are generally settled only upon the attainment of pre-established performance targets, which may include the achievement of specified financial objectives determined by the Compensation Committee. The Compensation Committee also approves the period over which the performance targets must be attained in order for performance units to vest. In November 2013, Messrs. Shaw and Cunningham were the only executive officers who were granted performance units. The performance period for the November 2013 awards began on January 1, 2014 and ends on December 31, 2016. An executive officer generally must remain employed through the end of the performance period in order to be eligible to earn any of the performance units. The provisions affecting the vesting of these awards upon a change in control or certain terminations of employment are described in greater detail below in the section titled “Potential Payments upon Termination and Change in Control.”

With respect to the performance unit awards for the 2014 year, Messrs. Shaw and Cunningham were each granted a target number of performance units. The target number is initially approved by the Compensation Committee in dollar amounts established according to the pay grade of the executive officer. The target award is then converted to a number of units by dividing the targeted dollar amount by the closing price of our common units on the grant date of the award. The following table sets forth the target number of performance units granted to Messrs. Shaw and Cunningham in November 2013 for the 2014 year:

Name	Target Number of Performance Units
Bruce R. Shaw	10,692
Mark T. Cunningham	2,262

The Compensation Committee determined that the increase in distributable cash flow per common unit during the performance period should be used as the performance objective for the performance unit awards granted in November 2013. The actual number of units earned at the end of the performance period is based on the “Achieved Distributable Cash Flow/Unit” as compared to the “Base Distributable Cash Flow/Unit,” “Target Distributable Cash Flow/Unit” and “Incentive Distributable Cash Flow/Unit.” Specifically, the actual number of units earned at the end of the performance period will be determined by multiplying the target number of performance units awarded by the performance percentage as follows:

Achieved Distributable Cash Flow/Unit Equals	Performance Percentage (%) (1)
Base Distributable Cash Flow/Unit or Less	50%
Target Distributable Cash Flow/Unit	100%
Incentive Distributable Cash Flow/Unit	150%

____________________

(1) The percentages above are interpolated between points up to a maximum of 150% but no less than 50%. The result is rounded to the nearest whole percentage, but not to a number in excess of 150%.

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For the performance units:

Term	What It Means
Achieved Distributable Cash Flow/Unit	Actual Distributable Cash Flow in 2016 adjusted, on an annualized basis, to the extent such adjustment is not reflected in Actual Distributable Cash Flow in 2016, to include the effect of the closing of any acquisition to income and/or outstanding HEP common units and/or to eliminate any general partner give-back and any other aberrational event, as determined by the Compensation Committee, divided by the number of common units outstanding as of year-end 2016
Base Distributable Cash Flow/Unit	Distributable Cash Flow for 2013 adjusted, on an annualized basis, to include the effect of the closing of any acquisition to income and/or outstanding HEP common units and/or to eliminate any general partner give-back and any other aberrational event, as determined by the Compensation Committee, divided by the number of common units outstanding as of year-end 2013
Target Distributable Cash Flow/Unit	Base Distributable Cash Flow/Unit x (100% + WAIA1) x (100% + WAIA2) x (100% + WAIA3)
Incentive Distributable Cash Flow/Unit	Base Distributable Cash Flow/Unit x (100% + (WAIA1 + 4%)) x (100% + (WAIA2 + 4%)) x (100% + (WAIA3 + 4%))
WAIA	The weighted after inflation adjustment for each of years 1, 2 and 3 of the performance period (identified as WAIA1, WAIA2, and WAIA3, respectively) to HEP’s applicable sources of revenue calculated as follows: annual percentage increase of the Producers Price Index - Commodities-Finished Goods published by the U.S. Department of Labor, Bureau of Labor Statistics plus 1.5% For purposes of calculating Target Distributable Cash Flow/Unit and Incentive Distributable Cash Flow/Unit, the WAIA is rounded to the nearest 0.1%

Prior to vesting, distributions are paid on each outstanding performance unit, based on the target number of performance units subject to the award, at the same rate as distributions paid on our common units. The distributions are not subject to forfeiture.

Acquisition of Common Units for Long-Term Incentive Plan Awards

Common units delivered in connection with long-term equity incentive awards may be common units acquired by HLS on the open market, common units already owned by HLS, common units acquired by HLS directly from us or any other person or any combination of the foregoing. We currently do not hold treasury units. HLS is entitled to reimbursement by us for the cost of acquiring the common units utilized for the grant or settlement of long-term equity incentive awards.

Retirement and Other Benefits

Our Named Executive Officers participate in certain retirement plans sponsored and maintained by HFC. The cost of retirement benefits for the Named Executive Officers who are not also executive officers of HFC are charged monthly to us in accordance with the terms of the Omnibus Agreement. The terms of these benefit arrangements are described below.

Defined Contribution Plan

For 2014, our Named Executive Officers were eligible to participate in the HollyFrontier Corporation 401(k) Retirement Savings Plan, a tax qualified defined contribution plan (the “401(k) Plan”). Employees who are not eligible to participate in the NQDC Plan may contribute amounts between 0% and 75% of their eligible compensation to the 401(k) Plan, while employees who participate in the NQDC Plan may contribute amounts between 0% and 50% of their eligible compensation to the 401(k) Plan. Employee contributions that were made on a tax-deferred basis were generally limited to $17,500 for 2014, with employees 50 years of age or over able to make additional tax-deferred contributions of $5,500.

For 2014, all employees received an employer retirement contribution to the 401(k) Plan of 3% to 8% of the participating employee’s eligible compensation under the 401(k) Plan, subject to applicable Internal Revenue Code limitations, based on years of service, as follows:

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Years of Service	Retirement Contribution (as percentage of eligible compensation)
Less than 5 years	3%
5 to 10 years	4%
10 to 15 years	5.25%
15 to 20 years	6.5%
20 years and over	8%

In addition to the retirement contribution, in 2014, employees received employer matching contributions to the 401(k) Plan equal to 100% of the first 6% of the employee’s eligible compensation up to compensation limits. Matching contributions vest immediately, and retirement contributions are subject to a three-year cliff-vesting period.

The 401(k) Plan benefits for Messrs. Shaw and Cunningham were charged to us in 2014 pursuant to the Omnibus Agreement.

Deferred Compensation Plan

In 2014, our Named Executive Officers were eligible to participate in the NQDC Plan. The NQDC Plan provides certain management and other highly compensated employees an opportunity to defer compensation in excess of qualified retirement plan limitations on a pre-tax basis and accumulate tax-deferred earnings to achieve their financial goals.

Participants in the NQDC Plan can contribute between 1% and 50% of their eligible earnings, which includes base salary and bonuses, to the NQDC Plan. Participants in the NQDC Plan may also receive certain employer-provided contributions, including matching restoration contributions, retirement restoration contributions, transition benefit contributions (pursuant to the Transition Benefit Plan described below), and nonqualified nonelective contributions. Matching restoration contributions and retirement restoration contributions represent contribution amounts that could not be made under the 401(k) Plan due to Internal Revenue Code limitations on tax-qualified plans. See the narrative preceding the “Nonqualified Deferred Compensation Table” for additional information regarding these contributions and the other terms and conditions of the NQDC Plan.

The NQDC Plan benefits for Messrs. Shaw and Cunningham were charged to us in 2014 pursuant to the Omnibus Agreement.

Retirement Pension Plans and Transition Benefit

HFC traditionally maintained the Holly Retirement Plan, a tax-qualified defined benefit retirement plan

(the “Retirement Plan”), and the Holly Retirement Restoration Plan, an unfunded plan that provides additional payments to participating executives whose Retirement Plan benefits were subject to certain Internal Revenue Code limitations (the “Restoration Plan”).

Until January 1, 2012, employees hired prior to 2007 and not subject to a collective bargaining agreement, were eligible to participate in the Retirement Plan. Employees participating in the Retirement Plan were also eligible to participate in the 401(k) Plan, but were generally not eligible to receive an employer retirement contribution under the 401(k) Plan for years prior to 2012. As of January 1, 2012, participants in the Retirement Plan and the Restoration Plan who are not subject to a collective bargaining agreement were no longer accruing additional benefits under these plans, and as of May 1, 2012, all participants in these plans ceased accruing additional benefits. The Retirement Plan was liquidated in June 2013.

In connection with the cessation of benefit accruals under the Retirement Plan and the Restoration Plan, HFC adopted a Transition Benefit Plan pursuant to which eligible participants in the Retirement Plan are provided a transition benefit for each of 2012, 2013, and 2014. The amount of the transition benefit for each year is equal to the participant’s eligible compensation as of December 31 of that year, multiplied by a transition benefit percentage determined based on the participant’s eligible years of service as of January 1, 2012 (in the case of salaried employees). The participant must be employed on the last day of the year (subject to certain exceptions for death or disability) in order to earn a transition benefit for that year. For executive officers, the transition benefit is paid in the form of a transition benefit contribution to the NQDC Plan. For additional information regarding these transition benefit contributions, see the narrative preceding the “Nonqualified Deferred Compensation Plan Table.”

Messrs. Shaw and Cunningham were the only Named Executive Officers who participated in the Retirement Plan. Mr. Shaw is the only Named Executive Officer who is a participant in the Restoration Plan. Mr. Shaw’s Restoration Plan benefits were charged to us in 2014 pursuant to the Omnibus Agreement.

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Other Benefits and Perquisites

Our Named Executive Officers are eligible to participate in the same health and welfare benefit plans, including medical, dental, life insurance, and disability programs sponsored and maintained by HFC, that are generally made available to all full-time employees of HFC. Health and welfare benefits for Messrs. Shaw and Cunningham were charged to us in 2014 pursuant to the Omnibus Agreement.

It is the Compensation Committee’s policy to provide only limited perquisites to our Named Executive Officers. For security reasons as a result of our increased size and value, we reimburse Mr. Shaw up to $9,500 per year for any out-of-pocket expenses related to security training, consulting or technology. Mr. Shaw did not elect to utilize the security perquisite in 2014. We also provide reserved parking spaces for Messrs. Shaw and Cunningham.

Change in Control Agreements

As of the date of this Annual Report on Form 10-K, neither we nor HLS has entered into any employment agreements with any of the Named Executive Officers. On February 14, 2011, the Board adopted the Holly Energy Partners, L.P. Change in Control Policy (the “Change in Control Policy”) and the related form of Change in Control Agreement for certain officers of HLS (each, a “Change in Control Agreement”). The material terms of, and the quantification of, the potential amounts payable under the Change in Control Agreements currently in effect with certain Named Executive Officers are described below in the section titled “Potential Payments upon Termination or Change in Control.” The Change in Control Agreements contain “double-trigger” payment provisions that require not only a change in control of HFC, HLS or HEP, but also a qualifying termination of the executive’s employment within a specified period of time following the change in control in order for an officer to be entitled to benefits. We believe the Change in Control Agreements provide for management continuity in the event of a change in control and provide competitive benefits for the recruitment and retention of executives.

We entered to a Change in Control Agreement with Mr. Cunningham, effective as of February 14, 2011, and with Mr. Shaw, effective as of January 1, 2013, in each case, in accordance with the Change in Control Policy. We bear all costs and expenses associated with these agreements.

HFC has entered into Change in Control Agreements with Messrs. Jennings and Aron and Ms. McWatters, which were in effect during 2014 and the costs of which are fully borne by HFC (the “HFC Change in Control Agreements”). Payments and benefits under the HFC Change in Control Agreements are triggered only upon a change in control of HFC. The material terms, and the qualification, of the potential amounts payable under the HFC Change in Control Agreements will be described in HFC’s 2015 Proxy Statement.

Unit Ownership and Retention Policy for Executives

The Board, the Compensation Committee and our executive officers recognize that ownership of our common units is an effective means by which to align the interests of our officers with those of our unitholders. In October 2013, the Compensation Committee recommended, and the Board approved, a new unit ownership and retention policy, which increased the retention requirements for Mr. Shaw and subjected Mr. Cunningham to unit retention requirements, in each case equal in value to the following:

Executive Officer	Value of Units
Bruce R. Shaw	2x Base Salary
Mark T. Cunningham	1x Base Salary

Each covered officer is required to meet the applicable requirements within five years of first being subject to the policy.Officers are required to continuously own sufficient units to meet the unit ownership and retention requirements once attained. Until the officers attain compliance with the unit ownership and retention policy, the officers will be required to hold 25% of the units received from any equity award, net of any units used to pay the exercise price or tax withholdings. If an officer attains compliance with the unit ownership and retention policy and subsequently falls below the requirement because of a decrease in the price of our common units, the officer will be deemed in compliance provided that the officer retains the units then held.

As of December 31, 2014, the Named Executive Officers listed above were in compliance with the unit ownership and retention policy.

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Anti-Hedging and Anti-Pledging Policy

Our Named Executive Officers are subject to the HEP Insider Trading Policy, which, among other things, prohibits such individuals from entering into short sales or hedging or pledging our common units and HFC common stock.

Tax and Accounting Implications

We account for equity compensation expenses under the rules of FASB ASC Topic 718, which requires us to estimate and record an expense for each award of equity compensation over the vesting period of the award. Accounting rules also require us to record cash compensation as an expense at the time the obligation is accrued. Because we are a partnership, Section 162(m) of the Code does not apply to compensation paid to our Named Executive Officers. Accordingly, the Compensation Committee does not consider its impact in determining compensation levels. The Compensation Committee has taken into account the tax implications to us in its decision to grant long-term equity incentive compensation awards in the form of restricted units and performance units as opposed to options or unit appreciation rights.

Recoupment of Compensation

To date, the Board has not adopted a formal clawback policy to recoup incentive based compensation upon the occurrence of a financial restatement, misconduct, or other specified events. However, equity awards granted to Named Executive Officers are subject to the terms of the Long-Term Incentive Plan, which states that such awards may be cancelled, repurchased and/or recouped to the extent required by applicable law or any clawback policy that we adopt. The Compensation Committee will evaluate the practical, administrative and other implications of adopting, implementing and enforcing a clawback policy.

2015 Compensation Decisions

Long-Term Equity Incentive Compensation

In October 2014, the Compensation Committee approved annual grants of restricted units and performance units to certain of our Named Executive Officers for the 2015 year. Pursuant to SEC rules, the long-term equity incentive awards granted in October 2014 for the 2015 year are disclosed as 2014 compensation in the Summary Compensation Table and are reported in the 2014 Grants of Plan-Based Awards table below. These awards are also described in greater detail in the narrative that follows.

Restricted Unit Awards

In October 2014, Messrs. Shaw and Cunninghamwere the only Named Executive Officers who were granted restricted units. The number of restricted units granted to each Named Executive Officer that received restricted units in October 2014 was determined in the same manner as the November 2013 restricted unit awards described above. The following table sets forth the number of restricted units awarded to each of them in October 2014 for the 2015 year:

Name	Number of Restricted Units
Bruce R. Shaw	9,684
Mark T. Cunningham	6,705

Restricted unitholders have all the rights of a unitholder with respect to the restricted units, including the right to receive all distributions paid with respect to such restricted units (at the same rate as distributions paid on our common units) and any right to vote with respect to the restricted units, subject to limitations on transfer and disposition of the units during the restricted period. The distributions are not subject to forfeiture.

The restricted units granted in October 2014 to Messrs. Shaw and Cunningham vest in three equal annual installments as noted in the following table and will be fully vested and nonforfeitable after December 15, 2017.

Restricted Unit Vesting Criteria
Vesting Date (1)	Cumulative Amount of Restricted Units Vested
Immediately following December 15, 2015	1/3
Immediately following December 15, 2016	2/3
Immediately following December 15, 2017	All

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(1) Vesting will occur on the first business day following December 15 if December 15 falls on a Saturday or a Sunday. The provisions affecting the vesting of these awards upon a change in control or certain terminations of employment are described in greater detail below in the section titled “Potential Payments upon Termination and Change in Control.”

Performance Unit Awards

In October 2014, Messrs. Shaw and Cunningham were the only Named Executive Officers who were granted performance units. The performance period for the October 2014 awards began on January 1, 2015 and ends on December 31, 2017. The target number of performance units granted to each Named Executive Officer that received performance units in October 2014 was determined in the same manner as the November 2013 performance unit awards described above. The following table sets forth the target performance units granted to Messrs. Shaw and Cunningham in October 2014 for the 2015 year:

Name	Target Number of Performance Units
Bruce R. Shaw	9,684
Mark T. Cunningham	2,235

The Compensation Committee determined that the increase in distributable cash flow per common unit during the performance period should be used as the performance objective for the performance unit awards granted in October 2014, which is the same performance objective utilized for the November 2013 awards. The actual number of units earned at the end of the performance period is based on the “Achieved Distributable Cash Flow/Unit” as compared to the “Base Distributable Cash Flow/Unit,” “Target Distributable Cash Flow/Unit” and “Incentive Distributable Cash Flow/Unit.” The actual number of units earned at the end of the performance period will be calculated in the same manner as the performance unit awards granted in November 2013, as adjusted to reflect the applicable performance period for the 2015 awards.

Prior to vesting, distributions are paid on each outstanding performance unit, based on the target number of performance units subject to the award, at the same rate as distributions paid on our common units. The distributions are not subject to forfeiture.

Compensation Committee Report

The Compensation Committee of the Holly Logistic Services, L.L.C. Board of Directors has reviewed and discussed the Compensation Discussion and Analysis required by Item 402(b) of Regulation S-K with management and, based on such review and discussion, the Compensation Committee recommended to the Board that the Compensation Discussion and Analysis be included in this Form 10-K.

Members of the Compensation Committee:

Michael C. Jennings, Chairman

Charles M. Darling, IV

William J. Gray

William P. Stengel

James G. Townsend

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Executive Compensation Tables

The following executive compensation tables and related information are intended to be read together with the more detailed disclosure regarding our executive compensation program presented under the caption “Compensation Discussion and Analysis.”

Summary Compensation Table

The table below summarizes the total compensation paid or earned by each of the Named Executive Officers for the years specified to the extent such compensation is allocable to us pursuant to SEC rules.

Name and Principal Position (1)	Year	Salary		Bonus (2)		Unit Awards (3)		Non-Equity Incentive Plan Compensation (4)		Change in Pension Value and Non-Qualified Deferred Compensation Earnings (5)		All Other Compensation (6)		Total
Michael C. Jennings Chief Executive Officer (7)	2014	$	1,060,000	—		—		$	262,411	—		—		$	1,322,411
Douglas S. Aron Executive Vice President and Chief Financial Officer (8)	2014	$	560,000	—		—		$	11,967	—		—		$	571,967
	2013	530,000		—		—		124,850		—		—		654,850
	2012	261,350		—		—		—		—		—		261,350
Bruce R. Shaw President	2014	$	468,000	$	132,945	$	650,184	$	141,055	$	2,200	$	92,690	$	1,487,074
	2013	450,000		156,335		1,200,172		151,965		—		96,069		2,054,541
	2012	400,707		—		—		—		—		—		400,707
Mark T. Cunningham Senior Vice President, Operations	2014	$	278,100	$	74,041	$	300,116	$	60,960	—		$	100,870	$	814,086
	2013	270,000		67,588		550,129		66,312		—		97,900		1,051,929
	2012	236,160		47,920		250,043		52,080		31,211		97,280		714,694
Denise C. McWatters Senior Vice President, General Counsel and Secretary (9)	2014	$	400,000	—		—		$	45,057	—		—		$	445,057

(1) As a result of changes to our grant timing practices adopted by the Compensation Committee during the fourth quarter of 2013, Messrs. Shaw and Cunningham received two grants of long-term equity incentive awards during 2013-(a) one for the 2013 year, granted in March 2013, and (b) one for the 2014 year, granted in November 2013. Because the awards for the 2014 year were granted during 2013, they are reported in the “Unit Awards” column of the Summary Compensation Table for 2013 rather than 2014, in accordance with SEC rules. As a result of this reporting requirement, the amount of compensation awarded to Messrs. Shaw and Cunningham for 2013 is overstated. Long-term equity incentive awards granted in October 2014 for the 2015 year are reported in the “Unit Awards” column of the Summary Compensation Table for 2014, in accordance with SEC rules. The awards for the 2015 year are described above in the section titled “Compensation Discussion and Analysis-2015 Compensation Decisions-Long-Term Equity Incentive Compensation.”

(2) Represents the discretionary bonus amount, if any, paid pursuant to the individual performance metric under our Annual Incentive Plan and any other bonus paid outside our Annual Incentive Plan. Other payments made under our Annual Incentive Plan are included in the “Non-Equity Incentive Plan Compensation” column.

For 2014, includes a special one-time discretionary bonus paid to (a) Mr. Shaw ($10,680) due to his understanding of our business, his credibility and approach with our employees and his overall commitment to the organization, and (b) Mr. Cunningham ($7,992) for his efforts and contributions to us in 2014.

(3) Represents the aggregate grant date fair value of awards of restricted units and performance units made in the year indicated computed in accordance with FASB ASC Topic 718, determined without regard to forfeitures, and does not reflect the actual value that may be recognized by the executive. See Note 6 to our consolidated financial statements for the fiscal year ended December 31, 2014 for a discussion of the assumptions used in determining the FASB ASC Topic 718 grant date fair value of these awards.

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Because the awards for the 2014 year were granted in November 2013, they are reported in the “Unit Awards” column of the Summary Compensation Table for 2013 rather than 2014, in accordance with SEC rules. The restricted unit and performance unit awards for the 2015 year were granted in October 2014 and are reported in the “Unit Awards” column of the Summary Compensation Table for 2014 rather than 2015, in accordance with SEC rules.

With respect to performance units awarded in October 2014, the amounts in the Summary Compensation Table are based on a probable payout percentage of 100%. If the performance units granted in October 2014 are paid out at the maximum payout level of 150% for Messrs. Shaw and Cunningham, the grant date fair value of their 2015 award of performance units would be as follows: Mr. Shaw, $487,638and Mr. Cunningham, $112,527.

The terms of the restricted unit and performance unit awards granted in October 2014 for the 2015 year are described under “Compensation Discussion and Analysis -2015 Compensation Decisions - Long-Term Equity Incentive Compensation.” For additional information on outstanding restricted unit and performance unit awards, see below under “Outstanding Equity Awards at Fiscal Year End.” No forfeitures of equity awards held by the Named Executive Officers occurred in 2014.

(4) Represents the bonus amount, if any, paid under our Annual Incentive Plan, other than with respect to the individual performance metric (which amounts are reported in the “Bonus” column). The 2014 bonus amounts under our Annual Incentive Plan are described above in greater detail under “Compensation Discussion and Analysis-Overview of 2014 Executive Compensation Components and Decisions-Annual Incentive Cash Bonus Compensation.” See notes 7 through 9 to the Summary Compensation Table for a discussion of the amounts reported as “Non-Equity Incentive Plan Compensation” with respect to Messrs. Jennings and Aron and Ms. McWatters, respectively.

(5) For Mr. Shaw, represents the aggregate change in the actuarial present value of his accumulated benefits under the Restoration Plan. The Retirement Plan was liquidated in June 2013.    

(6) For 2014, includes the compensation as described under “All Other Compensation” below.

(7) During 2014, Mr. Jennings split his professional time between HFC and us, and all compensation paid to him for 2014 was determined and paid by HFC. In accordance with SEC rules, a portion of the total compensation paid by HFC to Mr. Jennings for 2014 is allocated to the services he performed for us during 2014. The allocation was made based on the assumption that Mr. Jennings spent, in the aggregate, approximately 15% of his professional time in 2014 on our business and affairs. As a result 15% of the total amount of compensation Mr. Jennings received from HFC for 2014 has been reported in this table and the allocated amount has been solely attributed in the table above to Mr. Jennings’s base salary and non-equity incentive plan compensation. This amount represents the aggregate dollar value of total compensation paid to Mr. Jennings by HFC (including base salary, non-equity incentive plan compensation, equity awards and other compensation), calculated pursuant to SEC rules, and multiplied by 15%. The total compensation paid by HFC to Mr. Jennings in 2014 (including the portion of his salary and non-equity incentive plan compensation reported in this table) as well as a discussion of how the total amount of his non-equity incentive plan compensation for 2014 was determined will be disclosed in HFC’s 2015 Proxy Statement.

(8) During 2014, Mr. Aron split his professional time between HFC and us, and all compensation paid to him for 2014 was determined and paid by HFC. In accordance with SEC rules, a portion of the total compensation paid by HFC to Mr. Aron for 2014 is allocated to the services he performed for us during 2014. The allocation was made based on the assumption that Mr. Aron spent, in the aggregate, approximately 20% of his professional time in 2014 on our business and affairs. As a result, 20% of the total amount of compensation Mr. Aron received from HFC for 2014 has been reported in this table and the allocated amount has been solely attributed in the table above to Mr. Aron’s base salary and non-equity incentive plan compensation. This amount represents the aggregate dollar value of total compensation paid to Mr. Aron by HFC (including base salary, non-equity incentive plan compensation, equity awards and other compensation), calculated pursuant to SEC rules, and multiplied by 20%. The total compensation paid by HFC to Mr. Aron in 2014 (including the portion of his salary and non-equity incentive plan compensation reported in this table) as well as a discussion of how the total amount of his non-equity incentive plan compensation for 2014 was determined will be disclosed in HFC’s 2015 Proxy Statement.

(9) During 2014, Ms. McWatters split her professional time between HFC and us, and all compensation paid to her for 2014 was determined and paid by HFC. In accordance with SEC rules, a portion of the total compensation paid by HFC to Ms. McWatters for 2014 is allocated to the services she performed for us during 2014. The allocation was made based on the assumption that Ms. McWatters spent, in the aggregate, approximately 30% of her professional time in 2014 on our business and affairs. As a result, 30% of the total amount of compensation Ms. WcWatters received from HFC for 2014 has been reported in this table and the allocated amount has been solely attributed in the table above to Ms. McWatters’s base salary and non-equity incentive plan compensation. This amount represents the aggregate dollar value of total compensation paid to Ms. McWatters by HFC (including base salary, non-equity incentive plan compensation, equity awards and other compensation), calculated

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pursuant to SEC rules, and multiplied by 30%. The total compensation paid by HFC to Ms. McWatters in 2014 (including the portion of her salary and non-equity incentive plan compensation reported in this table) as well as a discussion of how the total amount of her non-equity incentive plan compensation for 2014 was determined will be disclosed in HFC’s 2015 Proxy Statement.

All Other Compensation

The table below describes the components of the compensation included in the “All Other Compensation” column for 2014 in the Summary Compensation Table above.

Name	401(k) Plan Company Matching Contributions		401(k) Plan Retirement Contributions		NQDC Plan Company Matching Contributions		NQDC Plan Retirement Contributions		Transition Benefit Contributions		Tax Reimbursements (1)		Total
Michael C. Jennings	—		—		—		—		—		—		—
Douglas S. Aron	—		—		—		—		—		—		—
Bruce R. Shaw	$	15,600	$	16,900	$	28,891	$	31,299	—		—		$	92,690
Mark T. Cunningham	15,600		13,650		10,373		9,076		$	52,000	$	171	100,870
Denise C. McWatters	—		—		—		—		—		—		—

___________________

(1) For Mr. Cunningham, represents tax payments made on the executive's behalf with respect to imputed income for family travel on HFC’s aircraft when the executive was traveling for business purposes and the family travel is business related.

Grants of Plan-Based Awards

The following table sets forth information about plan-based awards granted to our Named Executive Officers under our equity and non-equity incentive plans during 2014. In this table, awards are abbreviated as “AICP” for the annual incentive cash awards under our Annual Incentive Plan (other than with respect to the discretionary individual performance portion of the awards), as “RUA” for restricted unit awards, and as “PUA” for performance unit awards. In 2014, awards of performance units and restricted units were issued under our Long-Term Incentive Plan. Messrs. Jennings and Aron and Ms. McWatters did not receive any plan-based awards from us during 2014.

The restricted unit and performance unit grants reported below were granted in October 2014 for the 2015 year and are reported in this table as 2014 compensation in accordance with SEC rules. These awards are described in greater detail above under “Compensation Discussion and Analysis-2015 Compensation Decisions-Long-Term Equity Incentive Compensation.” Annual long-term equity incentive awards are made once each year in the fourth quarter of the year preceding the year to which the award relates in order to align the timing of the long-term equity incentive award grants with the timing of the other compensation decisions made for our executive officers. In accordance with SEC rules, the annual long-term equity incentive awards granted in November 2013 for the 2014 year were previously reported as 2013 compensation in the Grants of Plan-Based Awards table contained in our Annual Report on Form 10-K for the fiscal year ended December 31, 2013.

	Type	Grant  Date	Estimated Future Payouts Under Non-Equity Incentive Plan Awards (1)			Estimated Future Payouts Under Equity Incentive Plan Awards (2)
Name			Threshold	Target	Maximum	Threshold	Target	Maximum	All other Equity Awards (3)	Grant Date Fair Value (4)
Michael C. Jennings	—	—	—	—	—	—	—	—	—	—
Douglas S. Aron	—	—	—	—	—	—	—	—	—	—
Bruce R. Shaw	AICP		$0	$128,700	$257,400
	PUA	10/29/2014				4,842	9,684	14,526		$	325,092
	RUA	10/29/2014							9,684	$	325,092
Mark T. Cunningham	AICP		$0	$55,620	$111,240
	PUA	10/29/2014				1,118	2,235	3,352		$	75,029
	RUA	10/29/2014							6,705	$	225,087
Denise C. McWatters	—	—	—	—	—	—	—	—	—	—

(1) Represents the potential payouts for the awards under our Annual Incentive Plan, which were subject to the achievement of certain performance metrics. The performance metrics and awards are described under “Compensation Discussion and Analysis -Overview of 2014 Executive Compensation Components and Decisions - Annual Incentive Cash Bonus Compensation.” Amounts reported do not include amounts potentially payable pursuant to the discretionary individual performance portion of the award. The amount actually paid with respect to the individual performance portion of the award is reported in the “Bonus” column of the Summary Compensation Table for 2014, and the amount actually paid with respect

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to the portion of the award reported in this table is reported in the “Non-Equity Incentive Plan Compensation” column of the Summary Compensation Table for 2014.

(2) Represents the potential number of performance units payable under the Long-Term Incentive Plan. The number of units paid at the end of the performance period may vary from the target amount, based on our achievement of specified performance measures. The terms of the performance unit awards granted in October 2014 for the 2015 year are described above under “Compensation Discussion and Analysis -2015 Compensation Decisions - Long-Term Equity Incentive Compensation - Performance Unit Awards.”

(3) Represents awards of restricted units. The terms of the restricted unit awards granted in October 2014 for the 2015 year are described above under and “Compensation Discussion and Analysis -2015 Compensation Decisions - Long-Term Equity Incentive Compensation - Restricted Unit Awards.”

(4) Represents the grant date fair value determined pursuant to FASB ASC Topic 718, based on a closing price of our common units of $33.57 on October 29, 2014. The value of performance units granted on October 29, 2014 reflects a probable payout percentage of 100%.

Outstanding Equity Awards at Fiscal Year End

The following table sets forth information regarding outstanding restricted units and performance units held by each Named Executive Officer as of December 31, 2014, including awards that were granted prior to 2014. The value of these awards was calculated based on a price of $29.91 per unit, the closing price of our common units on December 31, 2014. Messrs. Jennings and Aron and Ms. McWatters do not hold any outstanding equity awards under our Long-Term Incentive Plan.

Under SEC rules, the number and value of performance units reported is based on the number of units payable at the end of the performance period assuming the maximum level of performance is achieved. In this table, awards are abbreviated as “RUA” for restricted unit awards and as “PUA” for performance unit awards. The provisions applicable to these awards upon certain terminations of employment or a change in control are described below in the section titled “Potential Payments upon Termination or Change in Control.”

Name	Award Type	Number of Units That Have Not Vested (1)	Market Value of Units That Have Not Vested		Equity Incentive Plan Awards: Number of Unearned Units or Other Rights That Have Not Vested	Equity Incentive Plan Awards: Market or Payout Value of Unearned Units or Other Rights That Have Not Vested
Michael C. Jennings	—	—	—		—	—
Douglas S. Aron	—	—	—		—	—
Bruce R. Shaw	RUA	19,056	$	569,965
	PUA				40,661	$	1,216,156
Mark T. Cunningham	RUA	12,912	$	386,198
	PUA				9,270	$	277,266
Denise C. McWatters	—	—	—		—	—

(1) Includes the following restricted unit awards granted by us:

• in March 2013 to Mr. Shaw (6,732) and Mr. Cunningham (5,049), of which one third vested on December 15, 2013, one third vested on December 15, 2014 and the remaining one third vests on December 15, 2015;

• in November 2013 to Mr. Shaw (10,692) and Mr. Cunningham (6,786), of which one third vested on December 15, 2014, one third vests on December 15, 2015 and the remaining one third vests on December 15, 2016; and

• in October 2014 to Mr. Shaw (9,684) and Mr. Cunningham (6,705), of which one third vests on December 15, 2015, one third vests on December 15, 2016 and the remaining one third vests on December 15, 2017.

(2) Includes the following performance unit awards granted by us (the amounts included in the parentheticals reflect the target number of performance units subject to each award):

• in March 2013 to Mr. Shaw (6,731) and Mr. Cunningham (1,683), in each case, with a performance period that ends on December 31, 2015;

• in November 2013 to Mr. Shaw (10,692) and Mr. Cunningham (2,262), in each case, with a performance period that ends on December 31, 2016; and

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• in October 2014 to Mr. Shaw (9,684) and Mr. Cunningham (2,235), in each case, with a performance period that ends on December 31, 2017.

For the performance units, the actual number of units earned at the end of the performance period is based on the “Achieved Distributable Cash Flow/Unit” as compared to the “Base Distributable Cash Flow/Unit,” “Target Distributable Cash Flow/Unit” and “Incentive Distributable Cash Flow/Unit.” Under the terms of the grants, each of Messrs. Shaw and Cunningham may earn from 50% to 150% of the target number of performance units granted to him.

Option Exercises and Units Vested

The following table provides information regarding the vesting in 2014 of restricted unit awards held by the Named Executive Officers. None of the performance unit awards held by the Named Executive Officers vested in 2014. Messrs. Jennings and Aron and Ms. McWatters do not currently hold any equity awards under our Long-Term Incentive Plan and did not have any equity awards under our Long-Term Incentive Plan that vested during 2014. To date, we have not granted any unit options.

The value realized from the vesting of restricted unit awards is equal to the closing price of our common units on the vesting date (or, if the vesting date is not a trading day, on the trading day immediately following the vesting date, unless provided otherwise by the applicable award agreement) multiplied by the number of units acquired on vesting. The value is calculated before payment of any applicable withholding or other income taxes.

Named Executive Officer	Unit Awards
	Number of Units Acquired on Vesting	Value Realized on Vesting
Michael C. Jennings	—	—
Douglas S. Aron	—	—
Bruce R. Shaw	5,808	$	168,374
Mark T. Cunningham	6,668	$	193,305
Denise C. McWatters	—	—

Pension Benefits Table

As discussed in greater detail above under “Compensation Discussion and Analysis-Overview of 2014 Executive Compensation Components and Decisions-Retirement and Other Benefits-Retirement Pension Plans and Transition Benefit,” HFC previously maintained the Retirement Plan, a tax-qualified defined benefit retirement plan, that was liquidated in 2013. Messrs. Shaw and Cunningham were the only Named Executive Officers who were participants in the Retirement Plan. As part of the liquidation of the Retirement Plan, the retirement benefits owed to Messrs. Shaw and Cunningham were distributed in a lump sum, and neither Mr. Shaw nor Mr. Cunningham is owed any additional benefits under the Retirement Plan.

HFC continues to maintain the Restoration Plan, which is an unfunded non-qualified plan that provides supplemental retirement benefits to participating executives whose Retirement Plan benefits were subject to certain Internal Revenue Code limitations. As of January 1, 2012, participants in the Restoration Plan are no longer accruing additional benefits. Mr. Shaw is the only Named Executive Officer who has accumulated benefits under the Restoration Plan.

The supplemental retirement benefits under the Restoration Plan are provided so that the total retirement benefits for the participants are maintained at the levels contemplated in the Retirement Plan before application of Internal Revenue Code limitations. Specifically, the amount of benefits payable under the Restoration Plan is equal to a participant’s benefit payable in the form of a life annuity calculated under the Retirement Plan without regard to the Internal Revenue Code limitations less the amount of the Retirement Plan benefit that can be paid under the Retirement Plan after application of Internal Revenue Code limits. Benefits under the Restoration Plan are generally payable in the same form and at the same time as the participant’s benefits under the Retirement Plan for benefits earned through 2004 (pre-409A benefits), and as a lump sum for benefits earned after 2004 (post-409A benefits).The Restoration Plan has not been terminated and post-409A benefits will generally not be paid until a participant’s separation from service in accordance with applicable Internal Revenue Code rules.

In connection with the cessation of benefit accruals under the Retirement Plan and the Restoration Plan in 2012, HFC adopted a Transition Benefit Plan pursuant to which eligible participants are provided a transition benefit for each of 2012, 2013, and 2014. For executive officers, the transition benefit is paid in the form of a transition benefit contribution to the NQDC Plan. For additional information regarding these transition benefit contributions, see the narrative preceding the “Nonqualified Deferred Compensation Table.”

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Name	Plan Name	Number of Years Credited Service	Present Value of Accumulated Benefit	Payments During Last Fiscal Year
Michael C. Jennings	—	—	—	—
Douglas S. Aron	—	—	—	—
Bruce R. Shaw	Restoration Plan	8.25	$10,956	—
Mark T. Cunningham	—	—	—	—
Denise C. McWatters	—	—	—	—

The actuarial present value of the accumulated benefits under the Restoration Plan reflected in the above chart was determined using the same assumptions as used for financial reporting purposes (which are discussed further in Note 16 to HFC’s consolidated financial statements for the fiscal year ended December 31, 2014), except the payment date was assumed to be age 62 rather than age 65. The earliest age at which a benefit can be paid with no benefit reduction under the Restoration Plan is age 62. In addition, the material assumptions used for these calculations include the following:

Discount Rate 3.65%

Mortality Table RP-2014 Mortality with Scale MP-2014 - Generational Annuitant, male and female

Nonqualified Deferred Compensation

In 2014, all of the Named Executive Officers participated in the NQDC Plan. The NQDC Plan functions as a pour-over plan, allowing key employees to defer tax on income in excess of Internal Revenue Code limits that apply under the 401(k) Plan. For 2014, the annual deferral contribution limit under the 401(k) Plan was $17,500, and the annual compensation limit was $260,000. Deferral elections made by eligible employees under the NQDC Plan apply to the total amount of eligible earnings the employees want to contribute across both the 401(k) Plan and the NQDC Plan. Once eligible employees reach the Internal Revenue Code limits on contributions under the 401(k) Plan, contributions automatically begin being contributed to the NQDC Plan. Federal and state income taxes are generally not payable on income deferred under the NQDC Plan until funds are withdrawn.

Eligible employees may make salary deferral contributions between 1% and 50% of eligible earnings to the NQDC Plan. Eligible earnings include base pay, bonuses and overtime, but exclude extraordinary pay such as severance, accrued vacation, equity compensation, and certain other items. Eligible participants are required to make catch-up contributions to the 401(k) Plan before any contributions will be deposited into the NQDC Plan. For 2014, the catch-up contribution limit was $5,500. Deferral elections are irrevocable for an entire plan year and must be made prior to December 31 immediately preceding the plan year. Elections will carry over to the next plan year unless changed or otherwise revoked.

Participants in the NQDC Plan are eligible to receive a matching restoration contribution with respect to their elective deferrals made up to 6% of the participant’s eligible earnings for the plan year in excess of the limits under Section 401(k) of the Internal Revenue Code. These matching restoration contributions are fully vested at all times. In addition, participants are eligible for a retirement restoration contribution ranging from 3% to 8% of the participant’s eligible earnings for the plan year in excess of the limits under Section 401(k) of the Internal Revenue Code, based on years of service, as follows:

Years of Services	Retirement Contribution (as percentage of eligible compensation)
Less than 5 years	3%
5 to 10 years	4%
10 to 15 years	5.25%
15 to 20 years	6.5%
20 years and over	8%

Retirement restoration contributions are subject to a three-year cliff vesting period and will become fully vested in the event of the participant’s death or a change in control. Participants may also receive nonqualified nonelective contributions under the NQDC Plan, which contributions may be subject to a vesting schedule determined at the time the contributions are made.

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Former participants in the Retirement Plan whose benefit accruals ceased as of the close of business on December 31, 2011 are also eligible to receive a transition benefit contribution under the NQDC Plan for plan years 2012, 2013 and 2014. The amount of the transition benefit contribution for each year is equal to the participant’s eligible compensation (determined in accordance with the Transition Benefit Plan) as of December 31 of that year, multiplied by a transition benefit percentage determined based on the participant’s eligible years of service as of January 1, 2012 (in the case of salaried employees) in accordance with the following table:

Years of Services	Transition Benefit (as percentage of eligible compensation)
Less than 5 years	10%
5 to 15 years	20%
15 to 20 years	25%
20 years and over	35%

The participant must be employed on the last day of the year (subject to certain exceptions for death or disability) in order to earn a transition benefit contribution for that year. Transition benefit contributions are fully vested immediately. Eligible compensation used to calculate the transition benefit contribution is subject to applicable Internal Revenue Code limits ($260,000 in 2014), except that if an employee participated in the Restoration Plan, all of his or her eligible compensation will be taken into consideration in determining the transition benefit contribution.

Participating employees have full discretion over how their contributions to the NQDC Plan are invested among the offered investment options, and earnings on amounts contributed to the NQDC Plan are calculated in the same manner and at the same rate as earnings on actual investments. Neither HLS nor HFC subsidizes a participant’s earnings under the NQDC Plan. During 2014, the investment options offered under the NQDC Plan were the same as the investment options available to participants in the tax-qualified 401(k) Plan, except that the tax-qualified 401(k) Plan offers the Principal Stable Value Fund and the NQDC Plan instead offers the Principal Money Market Fund. Earnings for 2014 with respect to NQDC Plan amounts invested in the Principal Money Market Fund did not exceed 120% of the applicable long-term federal rate (2.60%) and, as a result, no above market or preferential earnings were paid under the NQDC Plan for 2014. The following table lists the investment options for the NQDC Plan in 2014 with the annual rate of return for each fund:

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Investment Funds	Rate of Return
AllianzGI NFJ Small Cap Value I Fund	2.01%
American Century Mid-Cap Value Instl Fund	16.55%
Buffalo Small Cap Fund	-6.55%
Columbia Acorn International Z Fund	-4.28%
Columbia Acorn Z Fund	0.82%
Fidelity Contrafund	9.56%
Fidelity Low-Priced Stock Fund	7.65%
Harbor Capital Appreciation Inst Fund	9.93%
LargeCap S&P 500 Index Inst Fund	13.50%
MidCap S&P 400 Index Inst Fund	9.51%
Money Market Inst Fund	—
Oppenheimer Developing Markets Institutional Fund	-4.39%
PIMCO Total Return Instl Fund	4.69%
PIMCO All Asset All Authority Inst Fund	-2.35%
SmallCap S&P 600 Index Inst Fund	5.52%
T. Rowe Price Retirement Balanced Fund	3.91%
T. Rowe Price Retirement 2005 Fund	4.72%
T. Rowe Price Retirement 2010 Fund	4.99%
T. Rowe Price Retirement 2015 Fund	5.37%
T. Rowe Price Retirement 2020 Fund	5.63%
T. Rowe Price Retirement 2025 Fund	5.84%
T. Rowe Price Retirement 2030 Fund	6.05%
T. Rowe Price Retirement 2035 Fund	6.07%
T. Rowe Price Retirement 2040 Fund	6.18%
T. Rowe Price Retirement 2045 Fund	6.14%
T. Rowe Price Retirement 2050 Fund	6.19%
T. Rowe Price Retirement 2055 Fund	6.18%
Thornburg International Value R6 Fund	-5.37%
Vanguard Equity-Income Adm. Fund	11.38%
Vanguard Total Bond Market Index Admiral Fund	5.89%
Vanguard Total International Stock Index Admiral Fund	-4.17%

Benefits under the NQDC Plan may be distributed upon the earliest to occur of a separation from service (subject to a six month payment delay for certain specified employees under Section 409A of the Internal Revenue Code), the participant’s death, a change in control or a specified date selected by the participant in accordance with the terms of the NQDC Plan. Benefits are distributed from the NQDC Plan in the form of a lump sum payment or, in certain circumstances if elected by the participant, in the form of annual installments for up to a five year period.

Nonqualified Deferred Compensation Table

The NQDC Plan benefits for Messrs. Shaw and Cunningham were charged to us in 2014 pursuant to the Omnibus Agreement. The following table provides information regarding contributions to, and the year-end balance of, the NQDC Plan accounts for the Named Executive Officers (other than Messrs. Jennings and Aron and Ms. McWatters) in 2014. Even though Messrs. Jennings and Aron and Ms. McWatters are also participants in the NQDC Plan, we have not provided any disclosure with respect to their NQDC Plan benefits since those benefits are paid for by HFC. Additional information regarding the NQDC Plan, and participation in the NQDC Plan by Messrs. Jennings and Aron and Ms. McWatters, will be provided in HFC’s 2015 Proxy Statement.

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Name	Executive Contributions (1)	Company Contributions (2)	Aggregate Earnings	Aggregate Withdrawals/ Distributions	Aggregate Balance at December 31, 2014 (3)
Michael C. Jennings	—	—	—	—	—
Douglas S. Aron	—	—	—	—	—
Bruce R. Shaw	$26,991	$60,190	$0	—	$342,153
Mark T. Cunningham	47,432	71,449	12,667	—	376,437
Denise C. McWatters	—	—	—	—	—

_______________

(1) The amounts reported were deferred at the election of the Named Executive Officer and are also included in the amounts reported in the “Salary,” “Bonus” and/or “Non-Equity Incentive Plan Compensation” columns of the Summary Compensation Table for 2014.

(2) These amounts are also included in the “All Other Compensation” column of the Summary Compensation Table for 2014.

(3) The aggregate balance for each Named Executive Officer reflects the cumulative value, as of December 31, 2014, of the employee and employer-provided contributions to the NQDC Plan for the Named Executive Officer’s account, and any earnings on these amounts, since the Named Executive Officer began participating in the NQDC Plan in 2012. In addition, for Mr. Cunningham, the aggregate balance also includes his transition benefit payment earned for 2014 that was not paid to him until 2015. We previously reported executive and company contributions for Messrs. Shaw and Cunningham in the Summary Compensation Table in the following aggregate amounts: (a) Mr. Shaw - $90,762 (for 2013), and (b) Mr. Cunningham - $116,120 (for 2012) and $113,145 (for 2013).

Potential Payments upon Termination or Change in Control

We have Change in Control Agreements with certain of the Named Executive Officers and maintain the Long-Term Incentive Plan, each of which provide for severance compensation and/or accelerated vesting of equity compensation in the event of a termination of employment following a change in control or under other specified circumstances. These arrangements are summarized below.

Change in Control Agreements

During 2014, Messrs. Shaw and Cunningham were each party to a Change in Control Agreement with us, in accordance with our Change in Control Policy. We entered into a Change in Control Agreement with Mr. Shaw, effective as of January 1, 2013, and with Mr. Cunningham, effective as of February 14, 2011. We bear all costs and expenses associated with these agreements.

HFC has Change in Control Agreements with each of Messrs. Jennings and Aron and Ms. McWatters, which were in effect during 2014. Payments and benefits under the HFC Change in Control Agreements are triggered only upon a change in control of HFC. The terms of the HFC Change in Control Agreements, and a quantification of potential benefits under the HFC Change in Control Agreements with Messrs. Jennings and Aron and Ms. McWatters will be disclosed in HFC’s 2015 Proxy Statement.

The Change in Control Agreements under our Change in Control Policy terminate on the day prior to the three year anniversary of the effective date, and thereafter automatically renew for successive one year terms (on each anniversary date thereafter) unless a cancellation notice is given by us 60 days prior to the automatic extension date. The Change in Control Agreements provide that if, in connection with or within two years after a “Change in Control” of HFC, HLS or HEP (1) the executive’s employment is terminated without “Cause,” voluntarily for “Good Reason,” or as a condition of the occurrence of the transaction constituting the “Change in Control,” and (2) the executive is not offered employment with HFC, HLS, HEP, HEP Logistics or any of their affiliates on substantially the same terms in the aggregate as his previous employment within 30 days after the termination, then the executive will receive the following cash severance amounts paid by us:

• an amount equal to his accrued and unpaid salary, unreimbursed expenses and accrued vacation pay, and

• a lump sum amount equal to a designated multiplier times (i) the executive’s annual base salary as of the date of termination or the date immediately prior to the “Change in Control,” whichever is greater, and (ii) the executive’s annual bonus amount, calculated as the average annual bonus paid to him for the prior three years. The severance multiplier is (a) 2.0 for Mr. Shaw, and (b) 1.0 for Mr. Cunningham.

The executive will also receive continued participation by the executive and his or her dependents in medical and dental benefits for the number of years equal to the executive’s designated multiplier.

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For purposes of the Change in Control Agreements, a “Change in Control” occurs if:

• a person or group of persons (other than HFC or any of its wholly-owned subsidiaries or HLS, HEP, HEP Logistics or any of their subsidiaries) becomes the beneficial owner of more than 50% of the combined voting power of the then outstanding securities of HFC, HLS, HEP or HEP Logistics or more than 50% of the outstanding common stock or membership interests, as applicable or HFC or HLS;

• a majority of HFC’s Board of Directors is replaced during a 12-month period by directors who were not endorsed by a majority of the previous board members;

• the consummation of a merger, consolidation or recapitalization of HFC, HLS, HEP or HEP Logistics resulting in the holders of voting securities of HFC, HLS, HEP or HEP Logistics, as applicable, prior to the merger or consolidation owning less than 50% of the combined voting power of the voting securities of HFC, HLS, HEP or HEP Logistics, as applicable, or a recapitalization of HFC, HLS, HEP or HEP Logistics in which a person or group becomes the beneficial owner of securities of HFC, HLS, HEP or HEP Logistics, as applicable, representing more than 50% of the combined voting power of the then outstanding securities of HFC, HLS, HEP or HEP Logistics, as applicable;

• the holders of voting securities of HFC or HEP approve a plan of complete liquidation or dissolution of HFC or HEP, as applicable; or

• the holders of voting securities of HFC or HEP approve the sale or disposition of all or substantially all of the assets of HFC or HEP, as applicable, other than to an entity holding at least 60% of the combined voting power of the voting securities immediately prior to such sale or disposition.

For purposes of the Change in Control Agreements, “Cause” is defined as:

• the engagement in any act of willful gross negligence or willful misconduct on a matter that is not inconsequential; or

• conviction of a felony.

For purposes of the Change in Control Agreements, “Good Reason” is defined as, without the express written consent of the executive:

• a material reduction in the executive’s (or his supervisor’s) authority, duties or responsibilities;

• a material reduction in the executive’s base compensation; or

• the relocation of the executive to an office or location more than 50 miles from the location at which the executive normally performed the executive’s services, except for travel reasonably required in the performance of the executive’s responsibilities.

All payments and benefits due under the Change in Control Agreements will be conditioned on the execution and non-revocation by the executive of a release of claims for the benefit of HFC, HLS, HEP and HEP Logistics and their related entities and agents. The Change in Control Agreements also contain confidentiality provisions pursuant to which each executive agrees not to disclose or otherwise use the confidential information of HFC, HLS, HEP or HEP Logistics. Violation of the confidentiality provisions entitles HFC, HLS, HEP or HEP Logistics to complete relief, including injunctive relief. Further, in the event of a breach of the confidentiality covenants, the executive could be terminated for Cause (provided the breach constituted willful gross negligence or misconduct on the executive’s part that is not inconsequential). The agreements do not prohibit the waiver of a breach of these covenants.

If amounts payable to an executive under a Change in Control Agreement (together with any other amounts that are payable by HFC, HLS, HEP or HEP Logistics as a result of a change in ownership or control) exceed the amount allowed under Section 280G of the Internal Revenue Code for such executive by 10% or more, we will pay the executive an amount necessary to allow the executive to retain a net amount equal to the total present value of the payments on the date they are to be paid. Conversely, if the payments exceed the 280G limit for the executive by less than 10%, the payments will be reduced to the level at which no excise tax applies.

Long-Term Equity Incentive Awards

The outstanding long-term equity incentive awards granted under the Long-Term Incentive Plan to our Named Executive Officers vest upon a “Special Involuntary Termination,” which occurs when, within 60 days prior to or at any time after a “Change in Control”:

• the executive’s employment is terminated, other than for “Cause,” or

• the executive resigns within 90 days following an “Adverse Change.”

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All outstanding performance units will vest at 150% in the event of a Special Involuntary Termination.

In the event of an executive’s death, disability or retirement, restricted units and performance units vest as follows:

• Restricted Units:The executive will vest with respect to a pro rata number of units attributable to the period of service completed during the applicable vesting period and will forfeit any unvested units.

• Performance Units:The executive will remain eligible to vest with respect to a pro rata number of units attributable to the period of service completed during the applicable performance period (rounded up to include the month of termination) and will forfeit any unvested units. The Compensation Committee will determine the number of remaining performance units earned and the amount to be paid to the executive as soon as administratively possible after the end of the performance period based upon the performance actually attained for the entire performance period (provided that executives will earn and receive payment with respect to no less than 50% of the performance units awarded in 2013 and 2014). The foregoing also applies if the executive separates from employment for any other reason other than a voluntary separation, Special Involuntary Separation or for “Cause.”

For purposes of the long-term equity incentive awards, a “Change in Control” occurs if:

• a person or group of persons (other than HFC or any of its wholly-owned subsidiaries or HLS, HEP, HEP Logistics or any of their subsidiaries) becomes the beneficial owner of more than 40% of the combined voting power of the then outstanding securities of HFC, HLS, HEP or HEP Logistics;

• the individuals who as of the date of grant constituted a majority of HFC’s Board of Directors cease for any reason to constitute a majority of HFC’s Board of Directors;

• the consummation of a merger, consolidation or recapitalization of HFC, HLS, HEP or HEP Logistics resulting in the holders of voting securities of HFC, HLS, HEP or HEP Logistics, as applicable, prior to the merger or consolidation owning less than 60% of the combined voting power of the voting securities of HFC, HLS, HEP or HEP Logistics, as applicable, or a recapitalization of HFC, HLS, HEP, or HEP Logistics in which a person or group becomes the beneficial owner of securities of HFC, HLS, HEP or HEP Logistics, as applicable, representing more than 40% of the combined voting power of the then outstanding securities of HFC, HLS, HEP or HEP Logistics, as applicable;

• the holders of voting securities of HFC, HLS, HEP or HEP Logistics approve a plan of complete liquidation or dissolution of HFC, HLS, HEP or HEP Logistics, as applicable; or

• the holders of voting securities of HFC, HLS, HEP or HEP Logistics approve the sale or disposition of all or substantially all of the assets of HFC, HLS, HEP or HEP Logistics, as applicable, other than to an entity holding at least 60% of the combined voting power of the voting securities immediately prior to such sale or disposition.

For purposes of the restricted unit awards, “Adverse Change” is defined as:

• a change in the city in which the executive is required to work;

• a substantial increase in travel requirements of employment;

• a substantial reduction in the duties of the type previously performed by the executive; or

• a significant reduction in compensation or benefits (other than bonuses and other discretionary items of compensation) that does not apply generally to executives.

For purposes of the performance unit awards, “Adverse Change” is defined as, without the consent of the executive:

• a change in the executive’s principal office of employment of more than 25 miles from the executive’s work address at the time of grant of the award;

• a material increase (without adequate consideration) or material reduction in the duties to be performed by the executive; or

• a material reduction in the executive’s base compensation (other than bonuses and other discretionary items of compensation) that does not apply generally to employees.

For purposes of the long-term equity incentive awards, “Cause” is defined as:

• an act of dishonesty constituting a felony or serious misdemeanor and resulting (or intended to result in) gain or personal enrichment to the executive at the expense of HLS;

• gross or willful and wanton negligence in the performance of the executive’s material and substantial duties; or

• conviction of a felony involving moral turpitude.

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Holly Retirement Restoration Plan

The Restoration Plan provides benefits to participants in the event of a change in control of HFC. Mr. Shaw is the only Named Executive Officer who is a participant in the Restoration Plan. Under the Restoration Plan, each participant’s benefits are paid, in the form of an annuity contract and a cash payment, immediately upon such a change in control, where the stockholders of HFC before the transaction own, after the transaction, less than 40% of the effective voting power of HFC. The annuity contract is in an amount equal to the benefits otherwise due the recipient under the Restoration Plan reduced by the amount of the cash payment. Although we and HFC typically believe that double-trigger arrangements more effectively advance the interests of our unitholders and stockholders in the face of potential “change in control” transactions, HFC has elected to maintain the historical single-trigger terms of the Restoration Plan with respect to these retirement benefits held by long-time executives. Further, in light of the double-trigger arrangements in our other severance agreements, we believe our executive officers are adequately incentivized to remain employed by us (or our successor) following a corporate transaction, unless and until their employment is terminated without “cause” or due to a constructive termination. The Restoration Plan is the only arrangement in the current compensation program that provides single-trigger benefits. Because the Restoration Plan has not been liquidated, the amounts payable under the Restoration Plan upon a change in control transaction are reflected in the table below.

Quantification of Benefits

The following table summarizes the compensation and other benefits that would have been payable to the Named Executive Officers under the arrangements described above assuming their employment terminated under various scenarios, including in connection with a change in control, on December 31, 2014. For these purposes, our common unit price was assumed to be $29.91, which was the closing price per unit on December 31, 2014.

In reviewing the table, please note the following:

• Accrued vacation for a specific year is not allowed to be carried over to a subsequent year, so we assumed all accrued vacation for the 2014 year was taken prior to December 31, 2014. Because we accrue vacation in any given year for the following year, amounts reported as “Cash Payments” include accrued vacation amounts accrued in 2014 for the 2015 year.

• For amounts payable to the Named Executive Officers with respect to performance units upon a termination due to death, disability, retirement, or other separation (other than a voluntary separation, a for “Cause” separation or a Special Involuntary Termination), we assumed the performance units would be settled at the maximum level based on performance through December 31, 2014. The number of units paid at the end of the performance period may vary from the amounts reflected in the following tables, based on our actual achievement compared to the performance targets. Due to the change in vesting dates of outstanding restricted unit awards to December 15 of a given year, no amounts are reported for accelerated vesting of restricted unit awards upon termination due to death, disability or retirement because units attributable to fiscal year 2014 vested on December 15, 2014.

• The amount shown for “Value of Welfare Benefits” represents amounts equal to the monthly premium payable pursuant to the Consolidated Omnibus Budget Reconciliation Act of 1985, as amended (“COBRA”), for medical and dental premiums, multiplied by (a) 24 months for Mr. Shaw, and (b) 12 months for Mr. Cunningham.

• In calculating whether any tax reimbursements were owed to the Named Executive Officers, we used the following assumptions: (a)  no amounts will be discounted as attributable to reasonable compensation, (b) all cash severance payments are contingent upon a change in control, and (c) the presumption required under applicable regulations that the equity awards granted in 2014 were contingent upon a change in control could be rebutted. Based on these assumptions, none of the Named Executive Officers would receive any tax reimbursement or “gross-up” payments with respect to any amounts reported in the table below.

• No amounts potentially payable pursuant to the NQDC Plan are included in the table below since neither the form nor amount of any such benefits would be enhanced nor vesting or other provisions accelerated in connection with any of the triggering events disclosed below. Please refer to the section titled “Nonqualified Deferred Compensation” for additional information regarding these benefits.

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Named Executive Officer	Cash Payments (1)		Value of Welfare Benefits		Vesting of Equity Awards		Total
Michael C. Jennings	—		—		—		—
Douglas S. Aron	—		—		—		—
Bruce R. Shaw Termination in connection with or following a Change in Control	$	1,722,939	$	39,232	$	1,786,136	$	3,548,307
Termination due to Death, Disability, Retirement or without Cause	—		—		$	506,047	$	506,047
Mark T. Cunningham Termination in connection with or following a Change in Control	$	427,104	$	13,891	$	663,464	$	1,104,459
Termination due to Death, Disability, Retirement or without Cause	—		—		$	117,576	$	117,576
Denise C. McWatters	—		—		—		—

(1) For Mr. Shaw, includes (a) $6,617, the amount of the Restoration Plan annuity contract (which is equal to benefits otherwise due to Mr. Shaw under the Restoration Plan, reduced by the amount of the Restoration Plan cash payment), and (b) $4,339, the amount of the Restoration Plan cash payment (which includes the reasonable estimate of the federal income tax liability resulting from the annuity contract and the cash payment, calculated using the highest 2014 marginal federal income tax rate of 39.6%).

Compensation Practices as They Relate To Risk Management

Although a significant portion of the compensation provided to the Named Executive Officers is performance-based, we believe our compensation programs do not encourage excessive and unnecessary risk taking by executive officers (or other employees) because these programs are designed to encourage employees to remain focused on both our short- and long-term operational and financial goals.

While annual cash-based incentive bonus awards play an appropriate role in the executive compensation program, the Compensation Committee believes that payment determined based on an evaluation of our performance on a variety of measures, including comparing our performance over the last year to our past performance, mitigates excessive risk-taking that could produce unsustainable gains in one area of performance at the expense of our overall long-term interests. In addition, we set performance goals that we believe are reasonable in light of our past performance and market conditions.

For Named Executive Officers performing all or a majority of their services for us, an appropriate part of total compensation is fixed, while another portion is variable and linked to performance. A portion of the variable compensation we provide is comprised of long-term incentives. A portion of the long-term incentives we provide is in the form of restricted units subject to time-based vesting conditions, which retains value even in a depressed market, so executives are less likely to take unreasonable risks. With respect to our performance units, payouts result in some compensation at levels below full target achievement, in lieu of an “all or nothing” approach. Further, our unit ownership guidelines require certain of our executives to hold at least a specified level of units (in addition to unvested and unsettled equity-based awards), which aligns an appropriate portion of their personal wealth to our long-term performance and the interests of our unitholders.

Based on the foregoing and our annual review of our compensation programs, we do not believe that our compensation policies and practices are reasonably likely to have a material adverse effect on us or our unitholders.

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Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

The following table sets forth as of February 13, 2015 the beneficial ownership of common units of HEP held by:

• each person known to us to be a beneficial owner of 5% or more of the common units;

• directors of HLS, the general partner of our general partner;

• each Named Executive Officer of HLS; and

• all directors and executive officers of HLS as a group.

The percentage of common units noted below is based on 58,657,048 common units outstanding as of February 13, 2015. Unless otherwise indicated, the address for each unitholder shall be c/o Holly Energy Partners, L.P., 2828 N. Harwood, Suite 1300, Dallas, Texas 75201-1507.

Beneficial ownership of the common units of HEP is determined in accordance with SEC rules and regulations and generally includes voting power or investment power with respect to the common units held. Except as indicated and subject to applicable community property laws, to our knowledge the persons named in the tables below have sole voting and investment power with respect to all common units shown as beneficially owned by them.

Name of Beneficial Owner	Common Units	Percentage of Outstanding Common Units
HollyFrontier Corporation (1)	22,380,030	39.39%
Oppenheimer Funds, Inc. (2)	7,074,413	12.06%
Tortoise Capital Advisors, L.L.C. (3)	3,145,664	5.36%
Energy Income Partners, LLC (4)	2,969,314	5.06%
Matthew P. Clifton (5)(6)(8)	271,011	*
P. Dean Ridenour (6)	66,120	*
Bruce R. Shaw (7)(8)	51,062	*
Charles M. Darling, IV (6)(8)(9)	44,048	*
Mark T. Cunningham (7)	39,668	*
Jerry W. Pinkerton (6)	26,748	*
William J. Gray (6)(8)	23,546	*
James G. Townsend (6)(8)	20,732	*
William P. Stengel (6)(10)	14,324	*
Douglas S. Aron (8)(11)	7,340	*
Michael C. Jennings (8)	7,000	*
Denise C. McWatters (8)	4,881	*
All directors and executive officers as group (12 persons) (12)	576,480	*

* Less than 1%

(1) HollyFrontier Corporation directly holds 5,006 common units over which it has sole voting and dispositive power and 22,375,024 common units over which it has shared voting and dispositive power. HollyFrontier Corporation is the record holder of 140,000 common units as nominee for Navajo Pipeline Co., L.P. The 22,375,024 common units over which HollyFrontier Corporation has shared voting and dispositive power are held as follows: Holly Logistics Limited LLC directly holds 21,615,230 common units; HollyFrontier Holdings LLC directly holds 184,000 common units; Navajo Pipeline Co., L.P. directly holds 254,880 common units; and other wholly-owned subsidiaries of HollyFrontier Corporation directly own 180,114 common units. HollyFrontier Corporation is the ultimate parent company of each such entity and may therefore be deemed to beneficially own the units held by each such entity. HollyFrontier Corporation files information with or furnishes information to, the Securities and Exchange Commission pursuant to the information requirements of the Exchange Act. The percentage of outstanding common units owned includes a 2% general partner interest held by HEP Logistics Holdings, L.P. which is HEP’s general partner and an indirect wholly-owned subsidiary of HollyFrontier Corporation. The address of HollyFrontier Corporation is 2828N. Harwood, Suite 1300, Dallas, Texas 75201-1507.

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(2) Oppenheimer Funds, Inc. filed with the SEC a Schedule 13G/A, dated February 5, 2015. Based on this Schedule 13G/A, Oppenheimer Funds, Inc. has shared voting power and shared dispositive power with respect to 7,074,413 units. The address of Oppenheimer Funds, Inc. is Two World Financial Center, 225 Liberty Street, New York, NY 10281.

(3) Tortoise Capital Advisors, L.L.C. filed with the SEC a Schedule 13G/A on February 10, 2015. Based on this Schedule 13G/A, Tortoise Capital Advisors, L.L.C. reported that it had sole voting power and sole dispositive power with respect to 68 units and shared voting power and shared dispositive power with respect to 3,145,596 units. The address of Tortoise Capital Advisors, L.L.C. is 11550 Ash St., Suite 300, Leawood, KS 66211.

(4) Based on the Schedule 13G filed with the Securities and Exchange Commission on February 17, 2015 by Energy Income Partners, LLC, James J. Murchie, Eva Pao, Linda A. Longville and Saul Ballesteros. James J. Murchie and Eva Pao are the Portfolio Managers with respect to the portfolios managed by Energy Income Partners, LLC. Linda A. Longville and Saul Ballesteros are control persons of Energy Income Partners, LLC. Each of the foregoing report shared voting and dispositive power over 2,969,314 common units. The address of each of the foregoing is 49 Riverside Avenue, Westport, Connecticut 06880.

(5) The number does not include performance units held by Mr. Clifton, which were granted to him while he was an employee of HLS.

(6) The number reported includes 2,995 restricted units for which the non-employee director has sole voting power but no dispositive power.

(7) The number reported includes restricted units for which the executive has sole voting power but no dispositive power, as follows: Mr. Shaw (19,056 units) and Mr. Cunningham (12,912 units). The number does not include performance units held by Mr. Shaw and Mr. Cunningham.

(8) Messrs. Jennings, Aron Clifton, Townsend, Darling, Shaw and Gray and Ms. McWatters each own common stock of HFC. Each of these individuals own common stock of HFC as set forth in the following table:

Name of Beneficial Owner	Number of Shares
Michael C. Jennings (a)	409,238
Douglas S. Aron (a)	155,327
Matthew P. Clifton	111,986
Denise C. McWatters (a)	33,059
James G. Townsend (b)	23,779
Charles M. Darling, IV (c)	7,500
Bruce R. Shaw	7,044
William J. Gray	4,224
Total	752,157

(a) The number reported includes shares of HFC restricted stock for which the executive officer has sole voting power but no dispositive power, as follows: Mr. Jennings (132,802 shares), Mr. Aron (36,859 shares), and Ms. McWatters (14,793 shares). The number does not include unvested performance share units.

(b) The number reported represents shares of HFC common stock owned by a trust whose beneficiaries are Mr. Townsend’s children and grandchildren and for which Mr. Townsend and his spouse serve as trustees.

(c) Mr. Darling is an owner and general manager of DQ Holdings, L.L.C. The number reported represents shares of HFC common stock owned by DQ Holdings, L.L.C. for which Mr. Darling has shared voting and dispositive power. Mr. Darling disclaims beneficial ownership as to the shares of HFC common stock held by DQ Holdings, L.L.C. except to the extent of his pecuniary interest therein.

As of February 13, 2015, there were 195,775,664 shares of HFC common stock outstanding. Each of Messrs. Jennings, Aron Clifton, Townsend, Darling, Shaw and Gray and Ms. McWatters own less than 1% of the outstanding common stock of HFC.

HFC.

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(9) Mr. Darling is an owner and general manager of DQ Holdings, L.L.C. The number reported includes 22,400 common units owned by DQ Holdings, L.L.C. for which Mr. Darling has shared voting and dispositive power. Mr. Darling disclaims beneficial ownership as to the common units held by DQ Holdings, L.L.C. except to the extent of his pecuniary interest therein.

(10) The number reported includes 1,000 common units owned by Mr. Stengel’s spouse for which Mr. Stengel shares voting and disposition power. Mr. Stengel disclaims beneficial ownership as to the common units owned by his spouse.

(11) Includes 420 common units held by Mr. Aron as custodian for his son in an account under the Uniform Transfer to Minors Act and 420 common units held by Mr. Aron as custodian for his daughter in an account under the Uniform Transfer to Minors Act. Mr. Aron disclaims beneficial ownership of these common units.

(12) The number reported includes 31,968 restricted units held by executive officers for which they have sole voting power but no dispositive power and 20,965 restricted units held by non-employee directors for which they have sole voting power but no dispositive power. The number reported also includes 22,400 common units as to which Mr. Darling disclaims beneficial ownership, except to the extent of his pecuniary interest therein, 1,000 common units for which Mr. Stengel disclaims beneficial ownership, and 840 common units for which Mr. Aron disclaims beneficial ownership.

Equity Compensation Plan Table

The following table summarizes information about our equity compensation plans as of December 31, 2014:

Plan Category (1)	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted average exercise price of outstanding options, warrants and rights	Number of securities remaining available for future issuance under equity compensation plans
Equity compensation plans approved by security holders (2)	101,951 (3)	—	1,526,406
Equity compensation plans not approved by security holders	—	—	—
Total	101,951	—	1,526,406

(1) All stock-based compensation plans are described in Note 6 to our consolidated financial statements for the fiscal year ended December 31, 2014.

(2) On April 25, 2012, at a Special Meeting of the Unitholders of the Partnership, the unitholders approved the Amended and Restated Long-Term Incentive Plan, which, among other things, provided for an increase in the maximum number of common units reserved for delivery with respect to awards under the Long-Term Incentive Plan to 2,500,000 common units (as adjusted to reflect the two-for-one common unit split that occurred on January 16, 2013). All securities reported as available for future issuances are available from the additional common units approved by unitholders under the Amended and Restated Long-Term Incentive Plan. At the time the Long-Term Incentive Plan was originally adopted in 2004, it was not required to be approved by the Partnership’s unitholders.

(3) Represents units subject to performance units granted to (a) Mr. Clifton in March 2013 assuming a maximum payout level of 200% at the time of vesting, (b) Messrs. Shaw and Cunningham in March 2013, November 2013 and October 2014 assuming a maximum payout level of 150% at the time of vesting, and (c) Mr. Kenneth Norwood, our Vice President and Controller, in October 2014 assuming a maximum payout level of 150% at the time of vesting. If the performance units granted to Messrs. Clifton, Shaw, Cunningham and Norwood in 2013 and 2014 are paid at target, 59,809 units would be issued upon the vesting of such performance units.

For more information about our Amended and Restated Long-Term Incentive Plan, refer to Item 11, “Executive Compensation - Overview of 2014 Executive Compensation Components and Decisions - Long-Term Incentive Equity Compensation.”

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Item 13. Certain Relationships and Related Transactions, and Director Independence

Our general partner and its affiliates own 22,380,030 of our common units representing a 37% limited partner interest in us. In addition, the general partner owns a 2% general partner interest in us. Transactions with our general partner are discussed later in this section.

DISTRIBUTIONS AND PAYMENTS TO THE GENERAL PARTNER AND ITS AFFILIATES

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the ongoing operation and liquidation of HEP. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.

Operational stage

Distributions of available cash to our general partner and its affiliates	We generally make cash distributions 98% to the unitholders, including our general partner and its affiliates as the holders of an aggregate of 22,380,030 of the common units and 2% to the general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target levels, our general partner is entitled to increasing percentages of the distributions, up to 50% of the distributions above the highest target level.
Payments to our general partner and its affiliates	We pay HFC or its affiliates an administrative fee, $2.3 million per year in 2014 and currently $2.4 million, for the provision of various general and administrative services for our benefit. The administrative fee may increase if we make an acquisition that requires an increase in the level of general and administrative services that we receive from HFC or its affiliates. In addition, the general partner is entitled to reimbursement for all expenses it incurs on our behalf, including other general and administrative expenses. These reimbursable expenses include the salaries and the cost of employee benefits of employees of HFC who provide services to us on behalf of HLS. Finally, HLS is required to reimburse HFC for our benefit pursuant to the secondment arrangement for the wages, benefits, and other costs of HFC employees seconded to HLS to perform services at certain of our pipelines and tankage assets. Please read “Omnibus Agreement” and “Secondment Arrangement” below. Our general partner determines the amount of these expenses.
Withdrawal or removal of our general partner	If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.

Liquidation stage

Liquidation Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their particular capital account balances.

OMNIBUS AGREEMENT

Our Omnibus Agreement with HFC and our general partner that addresses the following matters:

• our obligation to pay HFC an annual administrative fee, in the amount of $2.3 million in 2014 and $2.4 currently, for the provision by HFC of certain general and administrative services;

• HFC’s and its affiliates’ agreement not to compete with us under certain circumstances and our right to notice of, and right of first offer to purchase, certain logistics assets constructed by HFC and acquired as part of an acquisition by HFC of refining assets;

• an indemnity by HFC for certain potential environmental liabilities;

• our obligation to indemnify HFC for environmental liabilities related to our assets existing on the date of our initial public offering to the extent HFC is not required to indemnify us; and

• HFC’s right of first refusal to purchase our assets that serve HFC’s refineries.

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Payment of general and administrative services fee

Under the Omnibus Agreement we pay HFC an annual administrative fee, in the amount of $2.3 million in 2014 and $2.4 million currently, for the provision of various general and administrative services for our benefit. Our general partner may agree to further increases in connection with expansions of our operations through the acquisition or construction of new assets or businesses.

The $2.3 million fee includes expenses incurred by HFC and its affiliates to perform centralized corporate functions, such as legal, accounting, treasury, information technology and other corporate services, including the administration of employee benefit plans. The fee does not include salaries of pipeline and terminal personnel or other employees of HFC who perform services for us on behalf of HLS or the cost of their employee benefits, such as 401(k), pension, and health insurance benefits, which are separately charged to us by HFC. We also reimburse HFC and its affiliates for direct general and administrative expenses they incur on our behalf.

Noncompetition

HFC and its affiliates have agreed, for so long as HFC controls our general partner, not to engage in, whether by acquisition or otherwise, the business of operating crude oil pipelines or terminals, refined product pipelines or terminals, intermediate pipelines or terminals, truck racks or crude oil gathering systems in the continental United States. This restriction will not apply to:

• any business operated by HFC or any of its affiliates at the time of the closing of our initial public offering;

• any business conducted by HFC with the approval of our general partner;

• any business or asset that HFC or any of its affiliates acquires or constructs that has a fair market value or construction cost of less than $5 million; and

• any business or asset that HFC or any of its affiliates acquires or constructs that has a fair market value or construction cost of $5 million or more if we have been offered the opportunity to purchase the business or asset at fair market value, and we decline to do so.

The limitations on the ability of HFC and its affiliates to compete with us will terminate if HFC ceases to control our general partner.

Indemnification

Under the Omnibus Agreement, certain transportation agreements and purchase agreements with HFC, HFC has agreed to indemnify us, subject to certain 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. The Omnibus Agreement provides environmental indemnification with respect to certain transferred assets of up to $15 million through 2021, plus additional indemnification of $2.5 million through 2015 and up to $7.5 million through 2023. HFC's indemnification obligations under the Omnibus Agreement do not apply to (i) the Tulsa West loading racks acquired in August 2009, (ii) the 16-inch intermediate pipeline acquired in June 2009, (iii) the Roadrunner Pipeline, (iv) the Beeson Pipeline, (v) the logistics and storage assets acquired from Sinclair in December 2009, (vi) the Tulsa East storage tanks and loading racks acquired in March 2010, (vii) the UNEV Pipeline, (viii) the Tulsa Interconnecting Pipelines, (ix) the Malaga Pipeline System or (x) Tank 647 at the El Dorado Refinery. For the Tulsa loading racks acquired from HFC in August 2009 and the Tulsa logistics and storage assets acquired from Sinclair in December 2009, HFC agreed to indemnify us for environmental liabilities arising from our pre-ownership operations of these assets. Additionally, HFC agreed to indemnify us for any liabilities arising from its operation of our loading racks located at HFC's Tulsa refinery west facility.

We have indemnified HFC and its affiliates against environmental liabilities related to events that occur on our assets after the date we acquired such asset.

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Right of first refusal to purchase our assets

The Omnibus Agreement also contains the terms under which HFC has a right of first refusal to purchase our assets that serve its refineries. Before we enter into any contract to sell pipeline and terminal assets serving HFC’s refineries, we must give written notice of the terms of such proposed sale to HFC. The notice must set forth the name of the third-party purchaser, the assets to be sold, the purchase price, all details of the payment terms and all other terms and conditions of the offer. To the extent the third-party offer consists of consideration other than cash (or in addition to cash), the purchase price shall be deemed equal to the amount of any such cash plus the fair market value of such non-cash consideration, determined as set forth in the Omnibus Agreement. HFC will then have the sole and exclusive option for a period of thirty days following receipt of the notice, to purchase the subject assets on the terms specified in the notice.

SECONDMENT ARRANGEMENT

Under HLS’s secondment arrangement with HFC, effective January 1, 2015, certain employees of HFC are seconded to HLS, our general partner’s general partner, to provide operational and maintenance services with respect to certain of our pipelines and terminals at the Cheyenne and El Dorado refineries, including routine operational and maintenance activities. During their period of secondment, the seconded employees are under the management and supervision of HLS. HLS is required to reimburse HFC for our benefit for the cost of the seconded employees, including their wages and benefits, based on the percentage of the employee’s time spent working for HLS. The secondment arrangement continues until HLS’s mutual agreement with HFC to terminate.

PIPELINE AND TERMINAL, TANKAGE AND THROUGHPUT AGREEMENTS

We serve HFC’s refineries under long-term pipeline and terminal, tankage and throughput agreements expiring in 2019 to 2026. Under these agreements, HFC agreed to transport, store and throughput volumes of refined product and crude oil on our pipelines and terminal, tankage and loading rack facilities that result in minimum annual payments to us. These minimum annual payments or revenues are subject to annual tariff rate adjustments on July 1, based on the Producer Price Index (“PPI”) or the Federal Energy Regulatory Commission (“FERC”) index. As of December 31, 2014, these agreements with HFC will result in minimum payments to us of $231.6 million.

HFC’s obligations under these agreements will not terminate if HFC and its affiliates no longer own the general partner. These agreements may be assigned by HFC only with the consent of our conflicts committee.

SUMMARY OF TRANSACTIONS WITH HFC

• UNEV Pipeline Interest Acquisition - On July 12, 2012, we acquired HFC's 75% interest in UNEV. We paid consideration consisting of $260.9 million in cash and 2,059,800 of our common units.

• See “2012 Acquisition” under Item 1, “Business” of this Annual Report on Form 10-K for additional information on these acquisitions from HFC.

• Revenues received from HFC were $275.2 million, $252.4 million and $245.6 million for the years ended December 31, 2014, 2013 and 2012, respectively.

• HFC charged us for general and administrative services under the Omnibus Agreement of $2.3 million for each of the years ended December 31, 2014, 2013 and 2012, respectively.

• We reimbursed HFC for costs of employees supporting our operations of $38.9 million, $34.6 million and $31.1 million for the years ended December 31, 2014, 2013 and 2012, respectively.

• HFC reimbursed us $16.8 million, $21.6 million and $13.4 million for certain reimbursable costs and capital projects for the years ended December 31, 2014, 2013 and 2012, respectively.

• We distributed $80.5 million, $71.4 million and $64.0 million for the years ended December 31, 2014, 2013 and 2012, respectively, to HFC as regular distributions on its common units, subordinated units and general partner interest, including general partner incentive distributions.

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REVIEW, APPROVAL OR RATIFICATION OF TRANSACTIONS WITH RELATED PERSONS

The disclosure, review and approval of any transactions with related persons is governed by our Code of Business Conduct and Ethics, which provides guidelines for disclosure, review and approval of any transaction that creates a conflict of interest between us and our employees, officers or directors and members of their immediate family. Conflict of interest transactions may be authorized if they are found to be in the best interest of the Partnership based on all relevant facts. Pursuant to the Code of Business Conduct and Ethics, conflicts of interest are to be disclosed to and reviewed by a supervisor who does not have a conflict of interest, and the supervisor must report in writing on the action taken to the General Counsel. Conflicts of interest involving directors or senior executive officers are reviewed by the full Board of Directors or by a committee of the Board of Directors on which the related person does not serve. Related party transactions required to be disclosed in our SEC reports are reported through our disclosure controls and procedures.

There are no transactions disclosed in this Item 13 entered into since January 1, 2014, that were not required to be reviewed, ratified or approved pursuant to our Code of Business Conduct and Ethics or with respect to which our policies and procedures with respect to conflicts of interest were not followed.

See Item 10 for a discussion of “Director Independence.”

Item 14. Principal Accounting Fees and Services

The audit committee of the board of directors of HLS selected Ernst & Young LLP, Independent Registered Public Accounting Firm, to audit the books, records and accounts of the HEP for the 2014 calendar year.

Fees paid to Ernst & Young LLP for 2014 and 2013 are as follows:

	2014		2013
Audit Fees (1)	$	610,000	$	669,000
Tax Fees	184,000		287,000
Total	$	794,000	$	956,000

(1) Represents fees for professional services provided in connection with the audit of our annual financial statements and internal controls over financial reporting, review of our quarterly financial statements, and procedures performed as part of our securities filings.

The audit committee of our general partner’s board of directors operates under a written audit committee charter adopted by the board. A copy of the charter is available on our website at www.hollyenergy.com. The charter requires the audit committee to approve in advance all audit and non-audit services to be provided by our independent registered public accounting firm. All services reported in the audit, audit-related, tax and all other fee categories above were approved by the audit committee in advance.

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Part IV

Item 15. Exhibits and Financial Statement Schedules

(a) Documents filed as part of this report

(1) Index to Consolidated Financial Statements

	Page in Form 10-K
Report of Independent Registered Public Accounting Firm	57
Consolidated Balance Sheets at December 31, 2014 and 2013	58
Consolidated Statements of Income for the years ended December 31, 2014, 2013 and 2012	59
Consolidated Statements of Comprehensive Income for the years ended December 31, 2014, 2013 and 2012	60
Consolidated Statements of Cash Flows for the years ended December 31, 2014, 2013 and 2012	61
Consolidated Statements of Equity for the years ended December 31, 2014, 2013 and 2012	62
Notes to Consolidated Financial Statements	63

(2) Index to Consolidated Financial Statement Schedules

All schedules are omitted since the required information is not present in or not present in amounts sufficient to require submission of the schedule, or because the information required is included in the consolidated financial statements or notes thereto.

(3) Exhibits

See Index to Exhibits on pages 133 to 139.

HOLLY ENERGY PARTNERS, L.P.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities 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: February 25, 2015	/s/ Michael C. Jennings
	Michael C. Jennings
	Chief Executive Officer

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Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Date: February 25, 2015	/s/ Michael C. Jennings
	Michael C. Jennings
	Chief Executive Officer and Director
Date: February 25, 2015	/s/ Bruce R. Shaw
	Bruce R. Shaw
	President
Date: February 25, 2015	/s/ Douglas S. Aron
	Douglas S. Aron
	Executive Vice President and Chief Financial Officer
	(Principal Financial Officer)
Date: February 25, 2015	/s/ Kenneth P. Norwood
	Kenneth P. Norwood
	Vice President and Controller
	(Principal Accounting Officer)
Date: February 25, 2015	/s/ Matthew P. Clifton
	Matthew P. Clifton
	Chairman of the Board
Date: February 25, 2015	/s/ Charles M. Darling, IV
	Charles M. Darling, IV
	Director
Date: February 25, 2015	/s/ William J. Gray
	William J. Gray
	Director

Date: February 25, 2015	/s/ Jerry W. Pinkerton
	Jerry W. Pinkerton
	Director
Date: February 25, 2015	/s/ P. Dean Ridenour
	P. Dean Ridenour
	Director
Date: February 25, 2015	/s/ William P. Stengel
	William P. Stengel
	Director
Date: February 25, 2015	/s/ James G. Townsend
	James G. Townsend
	Director

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Exhibit Index

Exhibit Number	Description
2.1	Purchase and Sale Agreement, dated February 25, 2008, between Holly Corporation, Navajo Pipeline Co., L.P., Navajo Refining Company, L.L.C., Woods Cross Refining Company, L.L.C., Holly Energy Partners, L.P., Holly Energy Partners - Operating, L.P., HEP Pipeline, L.L.C. and HEP Woods Cross, L.L.C. (incorporated by reference to Exhibit 2.1 of Registrant's Form 8-K Current Report dated February 27, 2008, File No. 001-32225).
2.2	Asset Sale and Purchase Agreement, dated October 19, 2009, between Holly Refining & Marketing - Tulsa LLC, HEP Tulsa LLC and Sinclair Tulsa Refining Company (incorporated by reference to Exhibit 2.1 of Registrant's Form 8-K Current Report dated October 21, 2009, File No. 001-32225).
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. 001-32225).
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. 001-32225).
3.3	Amendment No. 2 to the First Amended and Restated Agreement of Limited Partnership of Holly Energy Partners, L.P., 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. 001-32225).
3.4	Amendment No. 3 to the 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 Form 8-K Current Report dated April 15, 2008, File No. 001-32225).
3.5	Limited Partial Waiver of Incentive Distribution Rights under the First Amended and Restated Agreement of Limited Partnership of Holly Energy Partners, L.P., dated July 12, 2012 (incorporated by reference to Exhibit 3.1 of Registrant's Form 8-K Current Report dated July 12, 2012, File No. 001-32225).
3.6	Amendment No. 4 to the 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 Form 8-K Current Report dated January 16, 2013, File No. 001-32225).
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. 001-32225).
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. 001-32225).
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. 001-32225).
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. 001-32225).
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. 001-32225).
4.1	Indenture, dated March 10, 2010, among Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors and U.S. Bank National Association, providing for the issuance of 8.25% Senior Notes due 2018 (incorporated by reference to Exhibit 4.1 of Registrant's Form 8-K Current Report dated March 11, 2010, File No. 001-32225).
4.2	First Supplemental Indenture, dated April 14, 2010, among Holly Energy Storage-Tulsa LLC, Holly Energy Storage-Lovington LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.3 of Registrant's Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2010, File No. 001-32225).
4.3	Second Supplemental Indenture, dated June 4, 2010, among HEP Operations LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.4 of Registrant's Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2010, File No. 001-32225).
4.4	Third Supplemental Indenture, dated December 29, 2011, among Cheyenne Logistics LLC, El Dorado Logistics LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.16 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2011, File No. 001-32225)

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4.5	Fourth Supplemental Indenture, dated August 6, 2012, among HEP UNEV Holdings LLC, HEP UNEV Pipeline LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.1 to Registrant's Quarterly Report on Form 10-Q for its quarterly period ended September 30, 2012, File No. 001-32225).
4.6	Indenture, dated March 12, 2012, among Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors and U.S. Bank National Association, providing for the issuance of 6.50% Senior Notes due 2020 (incorporated by reference to Exhibit 4.1 of Registrant's Form 8-K Current Report dated March 12, 2012, File No. 001-32225).
4.7	First Supplemental Indenture, dated August 6, 2012, among HEP UNEV Holdings LLC, HEP UNEV Pipeline LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.2 of Registrant's Quarterly Report on Form 10-Q for its quarterly period ended September 30, 2012, File No. 001-32225).
10.1	Mortgage, Line of Credit Mortgage and Deed of Trust, dated February 29, 2008, by HEP Pipeline, L.L.C. for the benefit of Holly Corporation (incorporated by reference to Exhibit 10.2 of Registrant's Form 8-K Current Report dated March 6, 2008, File No. 001-32225).
10.2	Mortgage, Line of Credit Mortgage and Deed of Trust, dated February 29, 2008, by HEP Pipeline, L.L.C. for the benefit of Holly Corporation (incorporated by reference to Exhibit 10.3 of Registrant's Form 8-K Current Report dated March 6, 2008, File No. 001-32225).
10.3	Mortgage, Line of Credit Mortgage and Deed of Trust, dated February 29, 2008, by HEP Pipeline, L.L.C. for the benefit of Holly Corporation (incorporated by reference to Exhibit 10.4 of Registrant's Form 8-K Current Report dated March 6, 2008, File No. 001-32225).
10.4	Mortgage and Deed of Trust, dated February 29, 2008, by HEP Pipeline, L.L.C. for the benefit of Holly Corporation (incorporated by reference to Exhibit 10.5 of Registrant's Form 8-K Current Report dated March 6, 2008, File No. 001-32225).
10.5	Mortgage and Deed of Trust, dated February 29, 2008, by HEP Pipeline, L.L.C. for the benefit of Holly Corporation (incorporated by reference to Exhibit 10.6 of Registrant's Form 8-K Current Report dated March 6, 2008, File No. 001-32225).
10.6	Fee and Leasehold Deed of Trust, dated February 29, 2008, by HEP Woods Cross, L.L.C. for the benefit of Holly Corporation (incorporated by reference to Exhibit 10.7 of Registrant's Form 8-K Current Report dated March 6, 2008, File No. 001-32225).
10.7	Second Amended and Restated Credit Agreement, dated February 14, 2011, among Holly Energy Partners - Operating, L.P., Wells Fargo Bank, N.A., as administrative agent and issuing bank, Union Bank, N.A., as syndication agent, BBVA Compass Bank and U.S. Bank N.A., as co-documentation agents and certain other lenders (incorporated by reference to Exhibit 10.1 of Registrant's Form 8-K Current Report dated February 18, 2011, File No. 001-32225).
10.8	Agreement and Amendment No. 1 to Second Amended and Restated Credit Agreement, dated February 3, 2012, among Holly Energy Partners - Operating, L.P., certain of its subsidiaries acting as guarantors, Wells Fargo Bank, N.A., as administrative agent, an issuing bank and a lender and certain other lenders party thereto (incorporated by reference to Exhibit 10.1 of Registrant's Form 8-K Current Report dated February 9, 2012, File No. 001-32225).
10.9	Agreement and Amendment No. 2 to Second Amended and Restated Credit Agreement, dated June 29, 2012, among Holly Energy Partners - Operating, L.P., certain of its subsidiaries acting as guarantors, Wells Fargo Bank, N.A., as administrative agent, an issuing bank and lender and certain other lenders party thereto (incorporated by reference to Exhibit 10.1 of Registrant's Form 8-K Current Report dated June 29, 2012, File No. 001-32225).
10.10	Amendment No. 3 to Second Amended and Restated Credit Agreement and Amendment No. 1 to Second Amended and Restated Security Agreement, dated November 22, 2013, Holly Energy Partners - Operating, L.P., certain of its subsidiaries acting as guarantors, Wells Fargo Bank, N.A., as administrative agent, an issuing bank and lender and certain other lenders party thereto (incorporated by reference to Exhibit 10.1 of Registrant's Form 8-K Current Report dated November 26, 2013, File No. 001-32225).
10.11	Pipelines and Terminals Agreement, dated February 28, 2005, between Holly Energy Partners, L.P. and ALON USA, LP (incorporated by reference to Exhibit 10.1 of Registrant's Form 8-K Current Report dated February 28, 2005, File No. 001-32225).
10.12	First Amendment to Pipelines and Terminals Agreement between Holly Energy Partners, L.P. and ALON USA, LP, dated September 1, 2008 (incorporated by reference to Exhibit 10.4 of Registrant's Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2011, File No. 001-32225).
10.13	Second Amendment to Pipelines and Terminals Agreement between Holly Energy Partners, L.P. and ALON USA, LP, dated March 1, 2011 (incorporated by reference to Exhibit 10.5 of Registrant's Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2011, File No. 001-32225).
10.14	Third Amendment to Pipelines and Terminals Agreement between Holly Energy Partners, L.P. and ALON USA, LP, dated June 6, 2011 (incorporated by reference to Exhibit 10.6 of Registrant's Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2011, File No. 001-32225).

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10.15	Fourth Amendment to Pipelines and Terminals Agreement between Holly Energy Partners, L.P. and ALON USA, LP, dated October 6, 2014 (incorporated by reference to Exhibit 10.3 of Registrant's Quarterly Report on Form 10-Q for its quarterly period ended September 30, 2014, File No. 001-32225).
10.16	First Letter Agreement with respect to Pipelines and Terminals Agreement between Holly Energy Partners, L.P. and ALON USA, LP, dated January 25, 2005 (incorporated by reference to Exhibit 10.1 of Registrant's Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2011, File No. 001-32225).
10.17	Second Letter Agreement with respect to Pipelines and Terminals Agreement between Holly Energy Partners, L.P. and ALON USA, LP, dated June 29, 2007 (incorporated by reference to Exhibit 10.2 of Registrant's Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2011, File No. 001-32225).
10.18	Third Letter Agreement with respect to Pipelines and Terminals Agreement between Holly Energy Partners, L.P. and ALON USA, LP, dated April 1, 2011 (incorporated by reference to Exhibit 10.3 of Registrant's Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2011, File No. 001-32225).
10.19	Corrected Version dated October 10, 2007 of Amendment and Supplement to Pipeline Lease Agreement effective August 31, 2007 between HEP Pipeline Assets, Limited Partnership and Alon USA, LP (incorporated by reference to Exhibit 10.1 of Registrant's Form 8-K Current Report dated October 16, 2007, File No. 001-32225)
10.20	LLC Interest Purchase Agreement, dated June 1, 2009, among Holly Corporation, Navajo Pipeline Co., L.P. and Holly Energy Partners - Operating, L.P. (incorporated by reference to Exhibit 10.1 of Registrant's Form 8-K Current Report dated June 5, 2009, File No. 001-32225).
10.21	Amended and Restated Intermediate Pipelines Agreement, dated June 1, 2009, among Holly Corporation, Navajo Refining Company, L.L.C., Holly Energy Partners, L.P., Holly Energy Partners - Operating, L.P., HEP Pipeline, L.L.C., Lovington-Artesia, L.L.C., HEP Logistics Holdings, L.P., Holly Logistic Services, L.L.C. and HEP Logistics GP, L.L.C. (incorporated by reference to Exhibit 10.2 of Registrant's Form 8-K Current Report dated June 5, 2009, File No. 001-32225).
10.22	Amendment to Amended and Restated Intermediate Pipelines Agreement, dated December 9, 2010, among Navajo Refining Company, L.L.C., Holly Energy Partners, L.P., Holly Energy Partners - Operating, L.P., HEP Pipeline, L.L.C., Lovington-Artesia, L.L.C., HEP Logistics Holdings, L.P., Holly Logistic Services, L.L.C. and HEP Logistics GP, L.L.C. (incorporated by reference to Exhibit 10.23 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2010, File No. 001-32225).
10.23	Assignment and Assumption Agreement (Amended and Restated Intermediate Pipelines Agreement), effective January 1, 2011, between Navajo Refining Company, L.L.C. and Holly Refining & Marketing Company LLC (incorporated by reference to Exhibit 10.24 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2010, File No. 001-32225).
10.24	Mortgage, Line of Credit Mortgage and Deed of Trust, dated June 1, 2009, by Lovington-Artesia, L.L.C. for the benefit of Holly Corporation (incorporated by reference to Exhibit 10.4 of Registrant's Form 8-K Current Report dated June 5, 2009, File No. 001-32225).
10.25	Asset Purchase Agreement, dated August 1, 2009, between Holly Refining & Marketing - Tulsa LLC and HEP Tulsa LLC (incorporated by reference to Exhibit 10.1 of Registrant's Form 8-K Current Report dated August 6, 2009, File No. 001-32225).
10.26	Tulsa Equipment and Throughput Agreement, dated August 1, 2009, between Holly Refining & Marketing - Tulsa LLC and HEP Tulsa LLC (incorporated by reference to Exhibit 10.3 of Registrant's Form 8-K Current Report dated August 6, 2009, File No. 001-32225).
10.27	Amendment to Tulsa Equipment and Throughput Agreement, dated December 9, 2010, among Holly Refining & Marketing - Tulsa LLC and HEP Tulsa LLC (incorporated by reference to Exhibit 10.28 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2010, File No. 001-32225).
10.28	Assignment and Assumption Agreement (Tulsa Equipment and Throughput Agreement), effective January 1, 2011, between Holly Refining & Marketing - Tulsa, LLC and Holly Refining & Marketing Company LLC (incorporated by reference to Exhibit 10.29 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2010, File No. 001-32225).
10.29	Tulsa Purchase Option Agreement, dated August 1, 2009, between Holly Refining & Marketing - Tulsa LLC and HEP Tulsa LLC (incorporated by reference to Exhibit 10.4 of Registrant's Form 8-K Current Report dated August 6, 2009, File No. 001-32225).
10.30	LLC Interest Purchase Agreement, dated December 1, 2009, among Holly Corporation, Navajo Pipeline Co., L.P. and Holly Energy Partners - Operating, L.P. (incorporated by reference to Exhibit 10.1 of Registrant's Form 8-K Current Report dated December 7, 2009, File No. 001-32225).
10.31	Asset Purchase Agreement, dated December 1, 2009, between Holly Corporation, Navajo Pipeline Co., L.P. and HEP Pipeline, L.L.C. (incorporated by reference to Exhibit 10.2 of Registrant's Form 8-K Current Report dated December 7, 2009, File No. 001-32225).
10.32	Pipeline Throughput Agreement, dated December 1, 2009, between Navajo Refining Company, L.L.C. and Holly Energy Partners - Operating, L.P. (incorporated by reference to Exhibit 10.4 of Registrant's Form 8-K Current Report dated December 7, 2009, File No. 001-32225).

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10.33	Assignment and Assumption Agreement (Pipeline Throughput Agreement (Roadrunner)), effective January 1, 2011, between Navajo Refining Company, L.L.C. and Holly Refining & Marketing Company LLC (incorporated by reference to Exhibit 10.34 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2010, File No. 001-32225).
10.34	Form of Mortgage, Line of Credit Mortgage and Deed of Trust, to be entered into by HEP Pipeline L.L.C. and Holly Energy Partners, L.P. for the benefit of Holly Corporation (incorporated by reference to Exhibit 10.5 of Registrant's Form 8-K Current Report dated December 7, 2009, File No. 001-32225).
10.35	Form of Mortgage and Deed of Trust, to be entered into by Roadrunner Pipeline, L.L.C for the benefit of Holly Corporation (incorporated by reference to Exhibit 10.6 of Registrant's Form 8-K Current Report dated December 7, 2009, File No. 001-32225).
10.36	Form of Mortgage, Line of Credit Mortgage and Deed of Trust, to be entered into by Roadrunner Pipeline, L.L.C. for the benefit of Holly Corporation (incorporated by reference to Exhibit 10.7 of Registrant's Form 8-K Current Report dated December 7, 2009, File No. 001-32225).
10.37	Second Amended and Restated Crude Pipeline and Tankage Agreement, dated July 16, 2013, among Navajo Refining Company, L.L.C., Holly Refining & Marketing Company - Woods Cross LLC, HollyFrontier Refining & Marketing LLC, Holly Energy Partners-Operating, L.P., HEP Pipeline, LLC and HEP Woods Cross, L.L.C. (incorporated by reference to Exhibit 10.3 of Registrant's Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2013, File No. 001-32225).
10.38	Amended and Restated Refined Product Pipelines and Terminals Agreement, entered into on December 1, 2009, effective February 1, 2009, among Navajo Refining Company, L.L.C., Holly Refining & Marketing Company - Woods Cross, Holly Energy Partners - Operating, L.P., HEP Pipeline Assets, Limited Partnership, HEP Pipeline, LLC, HEP Refining Assets, L.P., HEP Refining, L.L.C., HEP Mountain Home, L.L.C. and HEP Woods Cross, L.L.C. (incorporated by reference to Exhibit 10.9 of Registrant's Form 8-K Current Report dated December 7, 2009, File No. 001-32225).
10.39	Assignment and Assumption Agreement (Amended and Restated Refined Product Pipelines and Terminals Agreement), effective January 1, 2011, among Navajo Refining Company, L.L.C., Holly Refining & Marketing-Woods Cross and Holly Refining & Marketing Company LLC (incorporated by reference to Exhibit 10.40 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2010, File No. 001-32225).
10.40	First Amendment to Amended and Restated Refined Product Pipelines and Terminals Agreement, entered into on November 7, 2013, effective September 30, 2013, among HollyFrontier Refining & Marketing LLC, Holly Energy Partners - Operating, L.P., HEP Pipeline Assets, Limited Partnership, HEP Pipeline, LLC, HEP Refining Assets, L.P., HEP Refining, L.L.C., HEP Mountain Home, L.L.C. and HEP Woods Cross, L.L.C. (incorporated by reference to Exhibit 10.42 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2014, File No. 001-32225).
10.41	Second Amended and Restated Throughput Agreement (Tucson Terminal), dated September 19, 2013 to be effective June 1, 2013, by and among HollyFrontier Refining & Marketing LLC, HEP Refining, L.L.C., and Holly Energy Partners - Operating, L.P. (incorporated by reference to Exhibit 10.4 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2013, File No. 001-32225).
10.42	Indemnification Proceeds and Payments Allocation Agreement, dated December 1, 2009, between Holly Refining & Marketing - Tulsa, LLC and HEP Tulsa LLC (incorporated by reference to Exhibit 10.2 of Registrant's Form 8-K Current Report dated December 7, 2009, File No. 001-32225).
10.43	LLC Interest Purchase Agreement, dated March 31, 2010, among Holly Corporation, Holly Refining & Marketing-Tulsa, LLC, Lea Refining Company, HEP Tulsa LLC and HEP Refining, L.L.C. (incorporated by reference to Exhibit 10.1 of Registrant's Form 8-K Current Report dated April 6, 2010, File No. 001-32225).
10.44	Second Amended and Restated Pipelines, Tankage and Loading Rack Throughput Agreement, dated August 31, 2011, between Holly Refining and Marketing-Tulsa LLC, HEP Tulsa LLC and Holly Energy Storage - Tulsa LLC (incorporated by reference to Exhibit 10.1 of Registrant's Form 8-K Current Report dated September 1, 2011, File No. 001-32225).
10.45	Assignment and Assumption Agreement (First Amended and Restated Pipelines, Tankage and Loading Rack Throughput Agreement (Tulsa East)), effective January 1, 2011, between Holly Refining & Marketing-Tulsa, LLC and Holly Refining & Marketing Company LLC (incorporated by reference to Exhibit 10.45 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2010, File No. 001-32225).
10.46	Loading Rack Throughput Agreement (Lovington), dated March 31, 2010, between Navajo Refining Company, L.L.C. and Holly Energy Storage-Lovington LLC (incorporated by reference to Exhibit 10.3 of Registrant's Form 8-K Current Report dated April 6, 2010, File No. 001-32225).
10.47	First Amended and Restated Lease and Access Agreement (East Tulsa), dated March 31, 2010, between Holly Refining & Marketing-Tulsa, LLC, HEP Tulsa LLC and Holly Energy Storage-Tulsa LLC (incorporated by reference to Exhibit 10.5 of Registrant's Form 8-K Current Report dated April 6, 2010, File No. 001-32225).
10.48	Pipeline Systems Operating Agreement, dated February 8, 2010, among Navajo Refining Company, L.L.C., Lea Refining Company, Woods Cross Refining Company, L.L.C., Holly Refining & Marketing - Tulsa LLC and Holly Energy Partners-Operating, L.P. (incorporated by reference to Exhibit 10.1 of Registrant's Form 8-K Current Report dated February 9, 2010, File No. 001-32225).

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10.49	First Amendment to Pipeline Systems Operating Agreement, dated March 31, 2010, among Navajo Refining Company, L.L.C., Lea Refining Company, Woods Cross Refining Company, L.L.C., Holly Refining & Marketing-Tulsa, LLC and Holly Energy Partners-Operating, L.P. (incorporated by reference to Exhibit 10.6 of Registrant's Form 8-K Current Report dated April 6, 2010, File No. 001-32225).
10.50	LLC Interest Purchase Agreement, dated November 9, 2011, among HollyFrontier Corporation, Frontier Refining LLC, Frontier El Dorado Refining LLC, Holly Energy Partners - Operating, L.P. and Holly Energy Partners, L.P. (incorporated by reference to Exhibit 10.1 of Registrant's Form 8-K Current Report dated November 10, 2011, File No. 001-32225).
10.51	First Amended and Restated Tankage, Loading Rack and Crude Oil Receiving Throughput Agreement (Cheyenne), dated January 11, 2012, effective November 1, 2011, between Frontier Refining LLC and Cheyenne Logistics LLC (incorporated by reference to Exhibit 10.54 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2011, File No. 001-32225).
10.52	First Amended and Restated Pipeline Delivery, Tankage and Loading Rack Throughput Agreement (El Dorado), dated January 11, 2012 effective November 1, 2011, between Frontier El Dorado Refining LLC and El Dorado Logistics LLC (incorporated by reference to Exhibit 10.55 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2011, File No. 001-32225).
10.53	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 Annual Report on Form 8-K Current Report dated January 13, 2014, File No. 001-32225).
10.54	Eighth Amended and Restated Omnibus Agreement, dated July 16, 2013, 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 July 22, 2013, File No. 001-32225).
10.55	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).
10.56	Tenth Amended and Restated Omnibus Agreement, dated September 26, 2014, by and among HollyFrontier Corporation, Holly Energy Partners, L.P. and certain of their respective subsidiaries (incorporated by reference to Exhibit 10.2 of Registrant's Current Report on Form 8-K filed September 29, 2014, File No. 001-32225).
10.57	Lease and Access Agreement (Cheyenne), dated November 9, 2011, between Frontier Refining LLC and Cheyenne Logistics LLC (incorporated by reference to Exhibit 10.5 of Registrant's Form 8-K Current Report dated November 10, 2011, File No. 001-32225).
10.58	First Amendment to Lease and Access Agreement (Cheyenne), effective June 5, 2012, between Frontier Refining LLC and Cheyenne Logistics LLC (incorporated by reference to Exhibit 10.62 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2014, File No. 001-32225).
10.59	Lease and Access Agreement (El Dorado), dated November 9, 2011, between Frontier El Dorado Refining LLC and El Dorado Logistics LLC (incorporated by reference to Exhibit 10.6 of Registrant's Form 8-K Current Report dated November 10, 2011, File No. 001-32225).
10.60	First Amendment to Lease and Access Agreement (El Dorado), effective August 15, 2012, between Frontier El Dorado Refining LLC and El Dorado Logistics LLC (incorporated by reference to Exhibit 10.64 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2014, File No. 001-32225).
10.61	Second Amendment to Lease and Access Agreement (El Dorado), effective December 5, 2012, between Frontier El Dorado Refining LLC and El Dorado Logistics LLC (incorporated by reference to Exhibit 10.65 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2014, File No. 001-32225).
10.62	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, 2014, File No. 001-32225).
10.63	Mortgage, dated January 31, 2012, by Cheyenne Logistics LLC for the benefit of HollyFrontier Corporation (incorporated by reference to Exhibit 10.61 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2011, File No. 001-32225).
10.64	Mortgage and Deed of Trust, dated January 31, 2012, by El Dorado Logistics LLC for the benefit of HollyFrontier Corporation (incorporated by reference to Exhibit 10.2 of Registrant's Quarterly Report on Form 10-Q for its quarterly period ended March 31, 2012, File No. 001-32225).
10.65	Purchase Agreement, dated February 28, 2012, among Holly Energy Partners, L.P., Holly Energy Finance Corp., each of the guarantors party thereto and Citigroup Global Markets, Inc., UBS Securities LLC and Wells Fargo Securities, LLC, as representatives of the initial purchasers named therein (incorporated by reference to Exhibit 10.1 of Registrant's Form 8-K Current Report dated March 5, 2012, File No. 001-32225).
10.66	LLC Interest Purchase Agreement, dated July 12, 2012, among HollyFrontier Corporation, Holly Energy Partners, L.P and HEP UNEV Holdings LLC (incorporated by reference to Exhibit 10.5 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2012, File No. 001-32225).

- 137 -

10.67	Amended and Restated Limited Liability Company Agreement of HEP UNEV Holdings LLC, dated July 12, 2012, among HEP UNEV Holdings LLC, Holly Energy Partners, L.P. and HollyFrontier Holdings LLC (incorporated by reference to Exhibit 10.7 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2012, File No. 001-32225).
10.68	Transportation Services Agreement, dated July 16, 2013, between HollyFrontier Refining & Marketing LLC and Holly Energy Partners-Operating, L.P. (incorporated by reference to Exhibit 10.1 of Registrant's Form 8-K Current Report dated July 22, 2013, File No. 001-32225).
10.69	Amended and Restated Transportation Services Agreement, dated September 26, 2014, by and between HollyFrontier Refining & Marketing LLC and Holly Energy Partners-Operating, L.P. (incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed September 29, 2014, File No. 001-32225).
10.70+	Holly Energy Partners, L.P. Long-Term Incentive Plan (as amended and restated effective February 10, 2012) (incorporated by reference to Exhibit 10.1 of Registrant's Form 8-K Current Report dated April 30, 2012, File No. 001-32225).
10.71+	First Amendment to the Holly Energy Partners, L.P. Long-Term Incentive Plan, effective January 16, 2013 (incorporated by reference to Exhibit 10.68 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2012, File No. 001-32225).
10.72+	Form of Restricted Unit Agreement (without Performance Vesting) (incorporated by reference to Exhibit 10.2 of Registrant's Form 8-K Current Report dated August 4, 2005, File No. 001-32225).
10.73+	Form of Holly Energy Partners, L.P. Indemnification Agreement to be entered into with officers and directors of Holly Logistic Services, L.L.C. (incorporated by reference to Exhibit 10.2 of Registrant's Form 8-K Current Report dated February 18, 2011, File No. 001-32225).
10.74+	HollyFrontier Corporation Executive Nonqualified Deferred Compensation Plan (incorporated by reference to Exhibit 10.73 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2012, File No. 001-32225).
10.75+	Holly Energy Partners, L.P. Change in Control Agreement Policy (incorporated by reference to Exhibit 10.3 of Registrant's Form 8-K Current Report dated February 18, 2011, File No. 001-32225).
10.76+	Form of Change in Control Agreement (incorporated by reference to Exhibit 10.4 of Registrant's Form 8-K Current Report dated February 18, 2011, File No. 001-32225).
10.77+	Form of Performance Unit Agreement (incorporated by reference to Exhibit 10.2 of Registrant's Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2010, File No. 001-32225).
10.78+	Amended and Restated Annual Incentive Plan (incorporated by reference to Exhibit 10.77 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2012, File No. 001-32225).
10.79+	Form of Performance Unit Agreement (Chairman) (incorporated by reference to Exhibit 10.1 of Registrant's Quarterly Report on Form 10-Q for its quarterly period ended March 31, 2013, File No. 001-32225).
10.80+	Form of Performance Unit Agreement (Executive) (incorporated by reference to Exhibit 10.2 of Registrant's Quarterly Report on Form 10-Q for its quarterly period ended March 31, 2013, File No. 001-32225).
10.81+	Form of Restricted Unit Agreement (Employee) (incorporated by reference to Exhibit 10.3 of Registrant's Quarterly Report on Form 10-Q for its quarterly period ended March 31, 2013, File No. 001-32225).
10.82+	Form of Notice of Grant of Restricted Units (Employee) (incorporated by reference to Exhibit 10.4 of Registrant's Quarterly Report on Form 10-Q for its quarterly period ended March 31, 2013, File No. 001-32225).
10.83+*	Form of Restricted Unit Agreement (Executive Chairman) (incorporated by reference to Exhibit 10.86 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2014, File No. 001-32225).
10.84+*	Form of Notice of Grant of Restricted Units (Executive Chairman) (incorporated by reference to Exhibit 10.87 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2014, File No. 001-32225).
10.85+	Form of Amended and Restated Restricted Unit Agreement (Chairman) (incorporated by reference to Exhibit 10.1 of Registrant's Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2014, File No. 001-32225).
10.86+	Form of Amended and Restated Performance Unit Agreement (Chairman) (2012 Grant) (incorporated by reference to Exhibit 10.2 of Registrant's Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2014, File No. 001-32225).
10.87+	Form of Amended and Restated Performance Unit Agreement (Chairman) (2013 Grant) (incorporated by reference to Exhibit 10.3 of Registrant's Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2014, File No. 001-32225).
10.88+	Form of Notice of Grant of Restricted Units (Directors) (incorporated by reference to Exhibit 10.5 of Registrant's Quarterly Report on Form 10-Q for its quarterly period ended September 30, 2013, File No. 001-32225).
10.89+	Form of Notice of Grant of Restricted Units (Directors) (incorporated by reference to Exhibit 10.4 of Registrant's Quarterly Report on Form 10-Q for its quarterly period ended September 30, 2014, File No. 001-32225).
10.90+	Form of Restricted Unit Agreement (Directors) (incorporated by reference to Exhibit 10.6 of Registrant's Quarterly Report on Form 10-Q for its quarterly period ended September 30, 2013, File No. 001-32225).

- 138 -

10.91+	Form of Restricted Unit Agreement (Directors) (incorporated by reference to Exhibit 10.5 of Registrant's Quarterly Report on Form 10-Q for its quarterly period ended September 30, 2014, File No. 001-32225).
21.1*	Subsidiaries of Registrant.
23.1*	Consent of Independent Registered Public Accounting Firm.
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 Annual Report on Form 10-K for the fiscal year ended December 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.

+ Constitutes management contracts or compensatory plans or arrangements.

++ Filed electronically herewith.

- 139 -

EX-21.1

Exhibit 21.1

HOLLY ENERGY PARTNERS, L.P.

SUBSIDIARIES OF REGISTRANT

State of

Incorporation or

Name of EntityOrganization

HEP Fin-Tex/Trust-River, L.P.            Texas

HEP Logistics GP, L.L.C            Delaware

HEP Mountain Home, L.L.C.            Delaware

HEP Navajo Southern, L.P.            Delaware

HEP Pipeline Assets, Limited Partnership        Delaware

HEP Pipeline GP, L.L.C.            Delaware

HEP Pipeline, L.L.C.                Delaware

HEP Refining GP, L.L.C.            Delaware

HEP Refining Assets, L.P.            Delaware

HEP Refining, L.L.C.                Delaware

HEP SLC, LLC                    Delaware

HEP Tulsa LLC                    Delaware

HEP Woods Cross, L.L.C.            Delaware

HEP UNEV Holdings LLC    Delaware

HEP UNEV Pipeline LLC    Delaware

Holly Energy Finance Corp.    Delaware

Holly Energy Partners – Operating, L.P. ⁽¹⁾        Delaware

Holly Energy Storage – Lovington LLC    Delaware

Cheyenne Logistics LLC    Delaware

El Dorado Logistics LLC    Delaware

Lovington-Artesia, L.L.C    Delaware

Roadrunner Pipeline, L.L.C.    Delaware

UNEV Pipeline, LLC    Delaware

(1) Holly Energy Partners - Operating, L.P. also does business as Holly Energy Partners.

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in the following Registration Statements:

(1) Registration Statement (Form S-3 No. 333-178304) of Holly Energy Partners, L.P.,

(2) Registration Statement (Form S-8 No. 333-134784) of Holly Energy Partners, L.P., and

(3) Registration Statement (Form S-8 No. 333-182865) of Holly Energy Partners, L.P.

of our reports dated February 25, 2015, with respect to the consolidated financial statements of Holly Energy Partners, L.P., and the effectiveness of internal control over financial reporting of Holly Energy Partners, L.P., included in this Annual Report (Form 10-K) for the year ended December 31, 2014.

/s/ Ernst & Young LLP

Dallas, Texas

February 25, 2015

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Michael C. Jennings, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:    February 25, 2015	/s/ Michael C. Jennings
	Michael C. Jennings
	Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Douglas S. Aron, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:    February 25, 2015	/s/ Douglas S. Aron
	Douglas S. Aron
	Executive Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION OF CHIEF EXECUTIVE

OFFICER OF HOLLY ENERGY PARTNERS, L.P.

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying report on Form 10-K for the annual period ended December 31, 2014 and filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Michael C. Jennings, Chief Executive Officer of Holly Logistic Services, L.L.C., the general partner of HEP Logistics Holdings, L.P., the general partner of Holly Energy Partners, L.P (the “Company”), hereby certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

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

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

Date: February 25, 2015	/s/ Michael C. Jennings
	Michael C. Jennings
	Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION OF CHIEF FINANCIAL

OFFICER OF HOLLYFRONTIER CORPORATION

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying report on Form 10-K for the annual period ended December 31, 2014 and filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Douglas S. Aron, Executive Vice President and Chief Financial Officer of Holly Logistic Services, L.L.C., the general partner of HEP Logistics Holdings, L.P., the general partner of Holly Energy Partners, L.P (the “Company”), hereby certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

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

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

Date:   February 25, 2015	/s/ Douglas S. Aron
	Douglas S. Aron
	Executive Vice President and Chief Financial Officer

XML

Employees, Retirement and Incentive Plans Performance Units (Details) (USD $)	12 Months Ended			3 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Mar. 31, 2014	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward]
Purchase of units for incentive grants	$ (3,577,000)	$ (5,634,000)	$ (4,919,000)
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward]
Outstanding at January 1, 2014 (nonvested)	75,216			75,216
Granted	13,967
Vesting and transfer of full ownership to recipients	(17,938)
Outstanding at December 31, 2014 (nonvested)	71,245				71,245
Phantom Share Units (PSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period	1 year
Executive Officer [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period	3 years
Certain Officers [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period	3 years
Long-term Incentive Plan [Member] | Certain Officers [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Net of Forfeitures				13,967
Maximum [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period					3 years
Long-term Incentive Plan [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward]
Fair value of vested units transferred to recipients	500,000
Weighted average fair value, units vested and transferred to recipients	$ 2,600,000				2,600,000
Total unrecognized compensation related to nonvested units	$ 1,100,000				1,100,000
Weighted average remaining contractual term (years)	1 year 2 months 13 days
Long-term Incentive Plan [Member] | Certain Officers [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Range of performance units earned, based on performance units granted, minimum (percent)	50.00%
Range of performance units earned, based on performance units granted, maximum (percent)	150.00%
Grants in period, weighted average grant date fair value		$ 37.90	$ 30.61		33.57

XML

Supplemental Guarantor / Non-Guarantor Financial Information Condensed Consolidating Statement of Comprehensive Income (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues [Abstract]
Affiliates									$ 275,196	$ 252,368	$ 245,582
Third parties									57,349	52,814	46,978
Total revenues	88,413	82,130	74,998	87,004	77,876	77,723	75,285	74,298	332,545	305,182	292,560
Operating costs and expenses [Abstract]
Operations (exclusive of depreciation and amortization)									104,801	99,444	89,242
Depreciation and amortization									62,166	65,423	57,461
General and administrative									10,824	11,749	7,594
Operating Expenses									177,791	176,616	154,297
Operating income (loss)	38,343	38,925	32,033	45,453	30,826	34,173	32,520	31,047	154,754	128,566	138,263
Income (Loss) from Equity Method Investments									0	0	0
Interest Income									3	161	0
Interest expense									(36,101)	(47,010)	(47,182)
Interest Revenue (Expense), Net										(47,010)	(47,182)
Gain on sale of assets									0	1,810	0
Loss on early extinguishment of debt									(7,677)	0	(2,979)
Other Income									82	61	10
Total other income (expense)									(40,706)	(42,152)	(46,787)
Income before Income Taxes	30,484	31,231	24,478	27,855	20,331	23,097	21,641	21,345	114,048	86,414	91,476
State income tax expense									(235)	(333)	(371)
Net income									113,813	86,081	91,105
Allocation of net loss attributable to Predecessors									0	0	4,200
Allocation of net income (loss) attributable to noncontrolling interest									(8,288)	(6,632)	(1,153)
Net Income attributable to Holly Energy Partners	28,668	29,680	23,034	24,143	18,998	21,885	20,167	18,399	105,525	79,449	94,152
Other comprehensive income (loss)									98	4,135	2,185
Comprehensive Income									105,623	83,584	96,337
SLC Pipeline [Member]
Operating costs and expenses [Abstract]
Income (Loss) from Equity Method Investments									(2,987)	(2,826)	(3,364)
Parent [Member]
Revenues [Abstract]
Affiliates									0	0	0
Third parties									0	0	0
Total revenues									0	0	0
Operating costs and expenses [Abstract]
Operations (exclusive of depreciation and amortization)									0	0	0
Depreciation and amortization									0	0	0
General and administrative									2,658	3,381	3,336
Operating Expenses									2,658	3,381	3,336
Operating income (loss)									(2,658)	(3,381)	(3,336)
Income (Loss) from Equity Method Investments									(138,691)	(115,850)	(130,743)
Interest Income									0	0
Interest expense									(22,831)
Interest Revenue (Expense), Net										(33,020)	(31,523)
Gain on sale of assets										0
Loss on early extinguishment of debt									(7,677)		(2,979)
Other Income									0	0	0
Total other income (expense)									108,183	82,830	96,241
Income before Income Taxes									105,525	79,449	92,905
State income tax expense									0	0	0
Net income									105,525	79,449	92,905
Allocation of net loss attributable to Predecessors											4,200
Allocation of net income (loss) attributable to noncontrolling interest									0	0	(2,953)
Net Income attributable to Holly Energy Partners									105,525	79,449	94,152
Other comprehensive income (loss)									98	4,135	2,185
Comprehensive Income									105,623	83,584	96,337
Parent [Member] | SLC Pipeline [Member]
Operating costs and expenses [Abstract]
Income (Loss) from Equity Method Investments									0	0	0
Guarantor Subsidiaries [Member]
Revenues [Abstract]
Affiliates									254,364	236,336	232,986
Third parties									45,711	42,139	41,984
Total revenues									300,075	278,475	274,970
Operating costs and expenses [Abstract]
Operations (exclusive of depreciation and amortization)									93,382	88,614	78,766
Depreciation and amortization									47,592	51,082	43,147
General and administrative									8,166	8,368	4,258
Operating Expenses									149,140	148,064	126,171
Operating income (loss)									150,935	130,411	148,799
Income (Loss) from Equity Method Investments									(4,858)	(1,231)	5,400
Interest Income									3	56
Interest expense									(13,270)
Interest Revenue (Expense), Net										(13,990)	(15,659)
Gain on sale of assets										1,810
Loss on early extinguishment of debt									0		0
Other Income									82	61	10
Total other income (expense)									(5,340)	(8,006)	(17,685)
Income before Income Taxes									145,595	122,405	131,114
State income tax expense									(235)	(333)	(371)
Net income									145,360	122,072	130,743
Allocation of net loss attributable to Predecessors											0
Allocation of net income (loss) attributable to noncontrolling interest									0	0	0
Net Income attributable to Holly Energy Partners									145,360	122,072	130,743
Other comprehensive income (loss)									98	4,135	2,185
Comprehensive Income									145,458	126,207	132,928
Guarantor Subsidiaries [Member] | SLC Pipeline [Member]
Operating costs and expenses [Abstract]
Income (Loss) from Equity Method Investments									(2,987)	(2,826)	(3,364)
Non-Guarantor Subsidiaries [Member]
Revenues [Abstract]
Affiliates									22,073	17,258	13,754
Third parties									11,638	10,675	4,994
Total revenues									33,711	27,933	18,748
Operating costs and expenses [Abstract]
Operations (exclusive of depreciation and amortization)									12,660	12,056	11,634
Depreciation and amortization									14,574	14,341	14,314
General and administrative									0	0	0
Operating Expenses									27,234	26,397	25,948
Operating income (loss)									6,477	1,536	(7,200)
Income (Loss) from Equity Method Investments									0	0	0
Interest Income									0	105
Interest expense									0
Interest Revenue (Expense), Net										0	0
Gain on sale of assets										0
Loss on early extinguishment of debt									0		0
Other Income									0	0	0
Total other income (expense)									0	105	0
Income before Income Taxes									6,477	1,641	(7,200)
State income tax expense									0	0	0
Net income									6,477	1,641	(7,200)
Allocation of net loss attributable to Predecessors											0
Allocation of net income (loss) attributable to noncontrolling interest									0	0	0
Net Income attributable to Holly Energy Partners									6,477	1,641	(7,200)
Other comprehensive income (loss)									0	0	0
Comprehensive Income									6,477	1,641	(7,200)
Non-Guarantor Subsidiaries [Member] | SLC Pipeline [Member]
Operating costs and expenses [Abstract]
Income (Loss) from Equity Method Investments									0	0	0
Eliminations [Member]
Revenues [Abstract]
Affiliates									(1,241)	(1,226)	(1,158)
Third parties									0	0	0
Total revenues									(1,241)	(1,226)	(1,158)
Operating costs and expenses [Abstract]
Operations (exclusive of depreciation and amortization)									(1,241)	(1,226)	(1,158)
Depreciation and amortization									0	0	0
General and administrative									0	0	0
Operating Expenses									(1,241)	(1,226)	(1,158)
Operating income (loss)									0	0	0
Income (Loss) from Equity Method Investments									143,549	117,081	125,343
Interest Income									0	0
Interest expense									0
Interest Revenue (Expense), Net										0	0
Gain on sale of assets										0
Loss on early extinguishment of debt									0		0
Other Income									0	0	0
Total other income (expense)									(143,549)	(117,081)	(125,343)
Income before Income Taxes									(143,549)	(117,081)	(125,343)
State income tax expense									0	0	0
Net income									(143,549)	(117,081)	(125,343)
Allocation of net loss attributable to Predecessors											0
Allocation of net income (loss) attributable to noncontrolling interest									(8,288)	(6,632)	1,800
Net Income attributable to Holly Energy Partners									(151,837)	(123,713)	(123,543)
Other comprehensive income (loss)									(98)	(4,135)	(2,185)
Comprehensive Income									(151,935)	(127,848)	(125,728)
Eliminations [Member] | SLC Pipeline [Member]
Operating costs and expenses [Abstract]
Income (Loss) from Equity Method Investments									$ 0	$ 0	$ 0

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Related Party Transactions (Narrative) (Details) (USD $)	12 Months Ended			3 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2014
Related Party Transaction [Line Items]
Minimum Annualized Payments Receivable	$ 272,400,000			$ 272,400,000
Affiliates	275,196,000	252,368,000	245,582,000
Due from Affiliates	33,392,000	29,675,000		33,392,000
Due to Affiliate, Current	5,239,000	8,484,000		5,239,000
Equity method investment, ownership percentage	50.00%			50.00%
HFC [Member]
Related Party Transaction [Line Items]
Costs and Expenses, Related Party	2,300,000			2,400,000
Minimum Annualized Payments Receivable	231,600,000			231,600,000
UNEV Pipeline [Member]
Related Party Transaction [Line Items]
Equity method investment, ownership percentage	75.00%			75.00%
Annual Administrative Fee [Member]
Related Party Transaction [Line Items]
Costs and Expenses, Related Party	2,300,000
Shortfall Payments [Member]
Related Party Transaction [Line Items]
Affiliates	10,100,000	5,100,000	7,800,000
Deferred Revenue, Additions	7,300,000	10,100,000
Reimbursements Paid [Member]
Related Party Transaction [Line Items]
Expenses resulting from agreement with related party	38,900,000	34,600,000	31,100,000
Proceeds From Reimbursements Received [Member]
Related Party Transaction [Line Items]
Reimbursements paid to related parties	16,800,000	21,600,000	13,400,000
Affiliated Entity [Member]
Related Party Transaction [Line Items]
Distribution Made to Limited Liability Company (LLC) Member, Cash Distributions Paid	$ 80,500,000	$ 71,400,000	$ 64,000,000

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Supplemental Guarantor / Non-Guarantor Financial Information Condensed Consolidating Statement of Cash Flows (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	$ 186,640	$ 183,080	$ 161,149
Cash flows from investing activities
Additions to properties and equipment	(79,959)	(52,101)	(42,861)
Proceeds from sale of assets	0	2,731	0
Distributions from UNEV	0	0
Distributions in Excess of Equity in Earnings in SLC Pipeline	263	300	262
Net Cash Provided by (Used in) Investing Activities	(79,696)	(49,070)	(42,599)
Cash flows from financing activities
Proceeds from (Repayments of) Lines of Credit	208,000	(58,000)	221,000
Proceeds from issuance of senior notes	0	0	294,750
Net Intercompany Financing Activities	0	0	0
Cash distribution to HFC for UNEV acquisition	0	0	(260,922)
Proceeds from issuance of common units	0	73,444	0
Repayments of senior notes	(156,188)	0	(260,235)
Contributions from noncontrolling interests	0	0	15,000
Distributions to HEP unitholders	(154,670)	(139,486)	(122,777)
Distributions to noncontrolling interest	(4,025)	(3,125)	0
Contribution from general partner		1,499	1,748
Purchase of units for incentive grants	(3,577)	(5,634)	(4,919)
Deferred financing costs	0	(1,344)	(3,238)
Other	(6)	(249)	(89)
Net cash used by financing activities	(110,466)	(132,895)	(119,682)
Increase (decrease) for the year	(3,522)	1,115	(1,132)
Beginning of period	6,352	5,237	6,369
End of period	2,830	6,352	5,237
Parent [Member]
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	(25,339)	(34,605)	(34,557)
Cash flows from investing activities
Additions to properties and equipment	0	0	0
Proceeds from sale of assets		0
Distributions from UNEV	0	0
Distributions in Excess of Equity in Earnings in SLC Pipeline	0	0	0
Net Cash Provided by (Used in) Investing Activities	0	0	0
Cash flows from financing activities
Proceeds from (Repayments of) Lines of Credit	0	0	0
Proceeds from issuance of senior notes			294,750
Net Intercompany Financing Activities	339,771	105,031	51,989
Cash distribution to HFC for UNEV acquisition			0
Proceeds from issuance of common units		73,444
Repayments of senior notes	(156,188)		(185,000)
Contributions from noncontrolling interests			0
Distributions to HEP unitholders	(154,670)	(139,486)	(122,777)
Distributions to noncontrolling interest	0	0
Contribution from general partner		1,499	1,748
Purchase of units for incentive grants	(3,577)	(5,634)	(5,240)
Deferred financing costs		0	(913)
Other	3	(249)	0
Net cash used by financing activities	25,339	34,605	34,557
Increase (decrease) for the year	0	0	0
Beginning of period	2	2	2
End of period	2	2	2
Guarantor Subsidiaries [Member]
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	193,273	197,678	194,667
Cash flows from investing activities
Additions to properties and equipment	(71,758)	(45,085)	(28,134)
Proceeds from sale of assets		2,731
Distributions from UNEV	11,383	9,375
Distributions in Excess of Equity in Earnings in SLC Pipeline	263	300	262
Net Cash Provided by (Used in) Investing Activities	(60,112)	(32,679)	(27,872)
Cash flows from financing activities
Proceeds from (Repayments of) Lines of Credit	208,000	(58,000)	221,000
Proceeds from issuance of senior notes			0
Net Intercompany Financing Activities	(339,771)	(105,031)	(51,989)
Cash distribution to HFC for UNEV acquisition			(260,922)
Proceeds from issuance of common units		0
Repayments of senior notes	0		(75,235)
Contributions from noncontrolling interests			0
Distributions to HEP unitholders	0	0	0
Distributions to noncontrolling interest	0	0
Contribution from general partner		0	0
Purchase of units for incentive grants	0	0	321
Deferred financing costs		(1,344)	(2,325)
Other	(9)	0	(89)
Net cash used by financing activities	(131,780)	(164,375)	(169,239)
Increase (decrease) for the year	1,381	624	(2,444)
Beginning of period	1,447	823	3,267
End of period	2,828	1,447	823
Non-Guarantor Subsidiaries [Member]
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	19,398	20,007	1,039
Cash flows from investing activities
Additions to properties and equipment	(8,201)	(7,016)	(14,727)
Proceeds from sale of assets		0
Distributions from UNEV	0	0
Distributions in Excess of Equity in Earnings in SLC Pipeline	0	0	0
Net Cash Provided by (Used in) Investing Activities	(8,201)	(7,016)	(14,727)
Cash flows from financing activities
Proceeds from (Repayments of) Lines of Credit	0	0	0
Proceeds from issuance of senior notes			0
Net Intercompany Financing Activities	0	0	0
Cash distribution to HFC for UNEV acquisition			0
Proceeds from issuance of common units		0
Repayments of senior notes	0		0
Contributions from noncontrolling interests			15,000
Distributions to HEP unitholders	0	0	0
Distributions to noncontrolling interest	(16,100)	12,500
Contribution from general partner		0	0
Purchase of units for incentive grants	0	0	0
Deferred financing costs		0	0
Other	0	0	0
Net cash used by financing activities	(16,100)	(12,500)	15,000
Increase (decrease) for the year	(4,903)	491	1,312
Beginning of period	4,903	4,412	3,100
End of period	0	4,903	4,412
Eliminations [Member]
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	(692)	0	0
Cash flows from investing activities
Additions to properties and equipment	0	0	0
Proceeds from sale of assets		0
Distributions from UNEV	(11,383)	(9,375)
Distributions in Excess of Equity in Earnings in SLC Pipeline	0	0	0
Net Cash Provided by (Used in) Investing Activities	(11,383)	(9,375)	0
Cash flows from financing activities
Proceeds from (Repayments of) Lines of Credit	0	0	0
Proceeds from issuance of senior notes			0
Net Intercompany Financing Activities	0	0	0
Cash distribution to HFC for UNEV acquisition			0
Proceeds from issuance of common units		0
Repayments of senior notes	0		0
Contributions from noncontrolling interests			0
Distributions to HEP unitholders	0	0	0
Distributions to noncontrolling interest	12,075	(9,375)
Contribution from general partner		0	0
Purchase of units for incentive grants	0	0	0
Deferred financing costs		0	0
Other	0	0	0
Net cash used by financing activities	12,075	9,375	0
Increase (decrease) for the year	0	0	0
Beginning of period	0	0	0
End of period	$ 0	$ 0	$ 0

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Commitments and Contingencies (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Long-term Purchase Commitment [Line Items]
Operating Leases, Future Minimum Payments Due, Current Year	$ 6,928,000
Operating Leases, Future Minimum Payments, Due in Two Years	6,913,000
Operating Leases, Future Minimum Payments, Due in Three Years	3,549,000
Operating Leases, Future Minimum Payments, Due in Four Years	192,000
Operating Leases, Future Minimum Payments, Due in Five Years	124,000
Operating Leases, Future Minimum Payments, Due Thereafter	266,000
Operating Leases, Future Minimum Payments Due	17,972,000
Operating Leases, Rent Expense	8,000,000	8,300,000	8,100,000
Site Service Commitments
Long-term Purchase Commitment [Line Items]
Operating Leases, Future Minimum Payments Due, Current Year	1,067,000
Operating Leases, Future Minimum Payments, Due in Two Years	1,067,000
Operating Leases, Future Minimum Payments, Due in Three Years	1,067,000
Operating Leases, Future Minimum Payments, Due in Four Years	1,067,000
Operating Leases, Future Minimum Payments, Due in Five Years	1,032,000
Operating Leases, Future Minimum Payments, Due Thereafter	6,294,000
Operating Leases, Future Minimum Payments Due	$ 11,594,000

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Acquisitions (Details) (USD $)	3 Months Ended								12 Months Ended			0 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jul. 12, 2012 Consecutive_Quarters
Business Acquisition [Line Items]
Equity method investment, ownership percentage	50.00%								50.00%
Business Acquisition, Cost of Acquired Entity, Other Noncash Consideration	$ 26,793,000				$ 20,124,000				$ 26,793,000	$ 20,124,000
Net Income (Loss) Attributable to Noncontrolling Interest									8,288,000	6,632,000	1,153,000
Total revenues	88,413,000	82,130,000	74,998,000	87,004,000	77,876,000	77,723,000	75,285,000	74,298,000	332,545,000	305,182,000	292,560,000
Net Income	30,394,000	31,189,000	24,450,000	27,780,000	20,438,000	23,057,000	21,297,000	21,289,000	113,813,000	86,081,000	91,105,000
Business Acquisition, minimum annual revenue commitments									18,400,000
UNEV Pipeline [Member]
Business Acquisition [Line Items]
Equity method investment, ownership percentage	75.00%								75.00%			75.00%
Cash distribution to HFC for UNEV Acquisition												260,000,000
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares												2,059,800
Business Acquisition, Payment of Contingent Consideration												900,000
Business Acquisition Percent Share of UNEV Earnings												50.00%
Business Acquisition, Post Acquisition Incentive Distributions									30,000,000			1,250,000
Number of Consecutive Quarters, Forego Rights to Incentive Distributions												12
Number Of Consecutive Quarters, Forego Rights To Incentive Distributions, Extension												4
Compound Percentage Increase to Class B Equity Units												7.00%
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners	25.00%								25.00%
Total revenues										18,700,000
Net Income										7,200,000
Net Income (Loss) for Period Prior to Acquisition										4,200,000
Revenues for period prior to acquisition										8,100,000
Business Acquisition, minimum annual revenue commitments									$ 27,100,000

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Employees, Retirement and Incentive Plans (Tables)

12 Months Ended

Dec. 31, 2014

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

Schedule of Nonvested Restricted Stock Units Activity

A summary of restricted unit and phantom unit activity and changes during the year ended December 31, 2014, is presented below:

Restricted and Phantom Units	Units		Weighted- Average Grant-Date Fair Value
Outstanding at January 1, 2014 (nonvested)	122,951		$	33.36
Granted	91,852		33.49
Vesting and transfer of full ownership to recipients	(80,645	)	33.22
Forfeited	(8,081	)	35.28
Outstanding at December 31, 2014 (nonvested)	126,077		$	33.43

Schedule of Nonvested Performance-based Units Activity

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

Performance Units	Units
Outstanding at January 1, 2014 (nonvested)	75,216
Granted	13,967
Vesting and transfer of common units to recipients	(17,938	)
Outstanding at December 31, 2014 (nonvested)	71,245

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Partners' Equity, Allocations of Net Income (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Partners' Capital [Abstract]
General partner interest in net income	$ 1,446	$ 1,059	$ 1,464
General partner incentive distribution	33,221	26,464	20,986
Total general partner interest in net income	$ 34,667	$ 27,523	$ 22,450

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Debt Long-Term Debt (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Line of Credit Facility, Amount Outstanding	$ 571,000	$ 363,000
Total long-term debt	867,579	807,630
6.5% Senior Notes [Member]
Debt Instrument [Line Items]
Principal	300,000	300,000
Unamortized discount	(3,421)	(4,073)
Senior Notes	296,579	295,927
8.25% Senior Notes [Member]
Debt Instrument [Line Items]
Principal	0	150,000
Unamortized discount	0	(1,297)
Senior Notes	$ 0	$ 148,703

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Employees, Retirement and Incentive Plans Retirement and Benefit Plan Costs (Details) (USD $)	3 Months Ended	12 Months Ended
	Dec. 31, 2014 Components Y	Dec. 31, 2014 Y	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee benefits and share-based compensation		$ 7,400,000	$ 7,400,000	$ 6,900,000
Pension Expense		4,400,000	5,000,000	4,300,000
Long-term incentive plan, components	4
Equity-based compensation, types	3	3
Compensation Costs Charged to Income		$ 3,539,000	$ 3,575,000	$ 2,858,000
Long-term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units authorized under equity-based compensation plans	2,500,000	2,500,000
Number of units available for grant	1,530,748	1,530,748

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Quarterly Financial Data (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Quarterly Financial Data [Abstract]
Total revenues	$ 88,413	$ 82,130	$ 74,998	$ 87,004	$ 77,876	$ 77,723	$ 75,285	$ 74,298	$ 332,545	$ 305,182	$ 292,560
Operating Income (Loss)	38,343	38,925	32,033	45,453	30,826	34,173	32,520	31,047	154,754	128,566	138,263
Income before Income Taxes	30,484	31,231	24,478	27,855	20,331	23,097	21,641	21,345	114,048	86,414	91,476
Net Income	30,394	31,189	24,450	27,780	20,438	23,057	21,297	21,289	113,813	86,081	91,105
Net Income attributable to Holly Energy Partners	$ 28,668	$ 29,680	$ 23,034	$ 24,143	$ 18,998	$ 21,885	$ 20,167	$ 18,399	$ 105,525	$ 79,449	$ 94,152
Limited partners’ per unit interest in earnings—basic and diluted:	$ 0.33	$ 0.35	$ 0.25	$ 0.27	$ 0.19	$ 0.25	$ 0.23	$ 0.21	$ 1.20	$ 0.88	$ 1.29
Limited Partners' per unit interest in net income - basic and diluted	$ 0.530	$ 0.523	$ 0.515	$ 0.5075	$ 0.500	$ 0.493	$ 0.485	$ 0.478	$ 2.075	$ 1.955	$ 1.835

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Significant Customers (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenue, Major Customer [Line Items]
Concentration risk, percentage	93.00%
Concentration risk, number of significant customers	2
HFC [Member]
Revenue, Major Customer [Line Items]
Concentration risk, percentage	83.00%	83.00%	84.00%
Alon [Member]
Revenue, Major Customer [Line Items]
Concentration risk, percentage	10.00%	11.00%	11.00%

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Acquisitions

12 Months Ended

Dec. 31, 2014

Business Combinations [Abstract]

Acquisitions

Acquisitions

2012 UNEV Acquisition

On July 12, 2012, we acquired HFC's 75% interest in UNEV for consideration consisting of $260.0 million in cash and 2,059,800 of our common units. We paid an additional $0.9 million to HFC for a post-closing working capital adjustment. We also issued HFC a Class B unit comprising a noncontrolling equity interest in a wholly-owned subsidiary subject to redemption to the extent that HFC is entitled to a 50% interest in our share of annual UNEV earnings before interest, income taxes, depreciation, and amortization above $30 million beginning July 1, 2016, and ending in June 2032, subject to certain limitations. Such contingent redemption payments are limited to a maximum payment amount calculated as described below. However, to the extent earnings thresholds are not achieved, no redemption payments are required. Contemporaneously with this transaction, HFC (our general partner) agreed to forego its right to incentive distributions of up to $1.25 million per quarter over twelve consecutive quarterly periods and up to an additional four quarters in certain circumstances. The Class B unit increases with each foregone incentive distribution and by a 7% factor compounded annually on the outstanding unredeemed balance through its expiration date. At our option, we may redeem, in whole or in part, the Class B unit at the current unredeemed value based on the calculation described. The Class B unit had a carrying value of $26.8 million at December 31, 2014, and $20.1 million at December 31, 2013.

Noncontrolling interests reported in the Consolidated Statements of Income include the minority partner's 25% interest in UNEV, foregone incentive distributions and the 7% accretion factor, which collectively amounted to $8.3 million at December 31, 2014, $6.6 million at December 31, 2013, and $1.2 million at December 31, 2012.

We are a consolidated variable interest entity of HFC. Therefore, this transaction was recorded as a transfer between entities under common control and reflects HFC's carrying basis in UNEV's assets and liabilities. We have retrospectively adjusted our financial position and operating results as if UNEV were a consolidated subsidiary for all periods while we were under common control of HFC. Results of operations of UNEV prior to our acquisition on July 12, 2012, are herein referred to as operations attributable to the Predecessor. For the year ended December 31, 2012, our consolidated statement of income includes revenues from UNEV of $18.7 million and net losses of $7.2 million. Predecessor revenues for the year ended December 31, 2012, are $8.1 million and Predecessor net losses are $4.2 million. At December 31, 2014, UNEV had transportation agreements with shippers that provide minimum annualized revenues of $27.1 million, of which $18.4 million relates to a transportation agreement with HFC.

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Debt Interest Rate Risk Management (Details) (USD $)	12 Months Ended	3 Months Ended
	Dec. 31, 2014	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Line of Credit Facility, Amount Outstanding	$ 571,000,000	$ 571,000,000	$ 363,000,000
Debt instrument, effective interest rate	2.152%	2.152%	2.163%
Accumulated other comprehensive loss	(46,000)	(46,000)	(144,000)
Derivative liabilities, fair value	46,000	46,000	144,000
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net	500,000
Cash Flow Hedging [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Amount Outstanding	305,000,000	305,000,000
Interest Rate Swap [Member] | Cash Flow Hedging [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Amount Outstanding	155,000,000	155,000,000
Long-term debt, fixed interest rate	0.99%	0.99%
Debt Instrument, Basis Spread on Variable Rate	2.00%
Debt instrument, effective interest rate	2.99%	2.99%
Accumulated other comprehensive loss	0	0
Interest Rate Swap [Member] | Cash Flow Hedging, Added 2012 [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Amount Outstanding	150,000,000	150,000,000
Long-term debt, fixed interest rate	0.74%	0.74%
Debt Instrument, Basis Spread on Variable Rate	2.00%
Debt instrument, effective interest rate	2.74%	2.74%
Number of interest rate swaps	2	2
Previous Interest Rate Swap [Member] | Cash Flow Hedging [Member]
Debt Instrument [Line Items]
Derivative, Cost of Hedge		6,000,000
Debt instrument, effective interest rate	6.24%	6.24%
Other Liabilities [Member] | Interest Rate Swap [Member] | Cash Flow Hedging [Member]
Debt Instrument [Line Items]
Derivative liabilities, fair value	1,065,000	1,065,000	1,814,000
Accumulated Other Comprehensive Income (Loss) [Member] | Interest Rate Swap [Member] | Cash Flow Hedging [Member]
Debt Instrument [Line Items]
Derivative liabilities, fair value	1,065,000	1,065,000	1,814,000
Derivative Asset	1,019,000	1,019,000	1,670,000
Other Noncurrent Assets [Member] | Interest Rate Swap [Member] | Cash Flow Hedging [Member]
Debt Instrument [Line Items]
Derivative Asset	1,019,000	1,019,000	1,670,000
Fair Value, Inputs, Level 2 [Member]
Debt Instrument [Line Items]
Derivative liabilities, fair value	$ 46,000	$ 46,000	$ 144,000

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Partners' Equity (Tables)

12 Months Ended

Dec. 31, 2014

Partners' Capital [Abstract]

Schedule of Allocation of General Partner Interest in Net Income

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

	Years Ended December 31,
	2014		2013		2012
	(in thousands)
General partner interest in net income	$	1,446	$	1,059	$	1,464
General partner incentive distribution	33,221		26,464		20,986
Total general partner interest in net income	$	34,667	$	27,523	$	22,450

Schedule of Distributions Made to Partners Percentages

	Total Quarterly Distribution	Marginal Percentage Interest in Distributions
	Target Amount	Unitholders	General Partner
Minimum quarterly distribution	$0.25	98%	2%
First target distribution	Up to $0.275	98%	2%
Second target distribution	above $0.275 up to $0.3125	85%	15%
Third target distribution	above $0.3125 up to $0.375	75%	25%
Thereafter	Above $0.375	50%	50%

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

The following table presents the allocation of our regular quarterly cash distributions to the general and limited partners for the periods in which they apply. Our distributions are declared subsequent to quarter end; therefore, the amounts presented do not reflect distributions paid during the periods presented below.

	Years Ended December 31,
	2014		2013		2012
	(In thousands, except per unit data)
General partner interest in distribution	$	3,264	$	2,982	$	2,566
General partner incentive distribution	33,221		26,464		20,986
Total general partner distribution	36,485		29,446		23,552
Limited partner distribution	121,714		114,675		102,222
Total regular quarterly cash distribution	$	158,199	$	144,121	$	125,774
Cash distribution per unit applicable to limited partners	$	2.075	$	1.955	$	1.835

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Significant Customers (Tables)

12 Months Ended

Dec. 31, 2014

Risks and Uncertainties [Abstract]

Schedules of Concentration of Risk, by Risk Factor

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

	Years Ended December 31,
	2014		2013		2012
HFC	83	%	83	%	84	%
Alon	10	%	11	%	11	%

XML

Debt Interest Expense and Other Debt Information (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Mar. 31, 2012
Debt Instrument [Line Items]
Interest expense, debt		$ 37,611	$ 47,651	$ 47,459
Unrealized Gain (Loss) on Cash Flow Hedging Instruments		0	849	5,095
Less capitalized interest		1,510	641	277
Net interest expense		36,101	47,010	47,182
Cash paid for interest		39,414	44,655	38,476
Loss on early extinguishment of debt		7,677	0	2,979
Repayments of senior notes	185,000	156,188	0	260,235
6.25% Interest Rate [Member]
Debt Instrument [Line Items]
Stated interest rate, senior notes					6.25%
6.5% Senior Notes [Member]
Debt Instrument [Line Items]
Interest expense, debt		19,446	19,506	15,716
Stated interest rate, senior notes		6.50%
6.25% Senior Notes [Member]
Debt Instrument [Line Items]
Interest expense, debt		0	0	2,422
Stated interest rate, senior notes
8.25% Senior Notes [Member]
Debt Instrument [Line Items]
Interest expense, debt		2,544	12,380	12,380
Stated interest rate, senior notes
Notes Payable, Other Payables [Member]
Debt Instrument [Line Items]
Interest expense, debt		0	0	543
Amortization discount and deferred debt issuance costs [Member]
Debt Instrument [Line Items]
Interest expense, debt		1,821	2,120	1,946
Commitment Fees [Member]
Debt Instrument [Line Items]
Interest expense, debt		450	835	621
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Interest expense, debt		$ 13,350	$ 11,961	$ 8,736

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Quarterly Financial Data (Tables)

12 Months Ended

Dec. 31, 2014

Quarterly Financial Data [Abstract]

Schedule of Quarterly Financial Information

Summarized quarterly financial data is as follows:

	First		Second		Third		Fourth		Total
	(In thousands, except per unit data)
Year Ended December 31, 2014
Revenues	$	87,004	$	74,998	$	82,130	$	88,413	$	332,545
Operating income	$	45,453	$	32,033	$	38,925	$	38,343	$	154,754
Income before income taxes	$	27,855	$	24,478	$	31,231	$	30,484	$	114,048
Net income	$	27,780	$	24,450	$	31,189	$	30,394	$	113,813
Net income attributable to Holly Energy Partners	$	24,143	$	23,034	$	29,680	$	28,668	$	105,525
Limited partners’ per unit interest in net income – basic and diluted	$	0.27	$	0.25	$	0.35	$	0.33	$	1.20
Distributions per limited partner unit	$	0.508	$	0.515	$	0.523	$	0.530	$	2.075
Year Ended December 31, 2013
Revenues	$	74,298	$	75,285	$	77,723	$	77,876	$	305,182
Operating income	$	31,047	$	32,520	$	34,173	$	30,826	$	128,566
Income before income taxes	$	21,345	$	21,641	$	23,097	$	20,331	$	86,414
Net income	$	21,289	$	21,297	$	23,057	$	20,438	$	86,081
Net income attributable to Holly Energy Partners	$	18,399	$	20,167	$	21,885	$	18,998	$	79,449
Limited partners’ per unit interest in net income – basic and diluted	$	0.21	$	0.23	$	0.25	$	0.19	$	0.88
Distributions per limited partner unit	$	0.478	$	0.485	$	0.493	$	0.500	$	1.955

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Supplemental Guarantor / Non-Guarantor Financial Information (Tables)

12 Months Ended

Dec. 31, 2014

Supplemental Guarantor / Non-Guarantor Financial Information [Abstract]

Condensed Consolidating Balance Sheet

Condensed Consolidating Balance Sheet

December 31, 2014	Parent		Guarantor Restricted Subsidiaries		Non-Guarantor Non-Restricted Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	2	$	2,828	$	—	$	—		$	2,830
Accounts receivable	—		34,274		6,044		(189		)	40,129
Prepaid and other current assets	212		2,856		1,315		—			4,383
Total current assets	214		39,958		7,359		(189		)	47,342
Properties and equipment, net	—		596,988		383,491		—			980,479
Investment in subsidiaries	622,100		285,247		—		(907,347		)	—
Transportation agreements, net	—		80,703		—		—			80,703
Goodwill	—		256,498		—		—			256,498
Investment in SLC Pipeline	—		24,478		—		—			24,478
Other assets	1,319		10,736		—		—			12,055
Total assets	$	623,633	$	1,294,608	$	390,850	$	(907,536	)	$	1,401,555
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	—	$	15,495	$	2,575	$	(189	)	$	17,881
Accrued interest	6,500		115		—		—			6,615
Deferred revenue	—		5,672		6,760		—			12,432
Accrued property taxes	—		1,902		801		—			2,703
Other current liabilities	45		4,408		118		—			4,571
Total current liabilities	6,545		27,592		10,254		(189		)	44,202
Long-term debt	296,579		571,000		—		—			867,579
Other long-term liabilities	147		17,731		267		—			18,145
Deferred revenue	—		29,392		—		—			29,392
Class B unit	—		26,793		—		—			26,793
Equity - partners	320,362		622,100		380,329		(1,002,429		)	320,362
Equity - noncontrolling interest	—		—		—		95,082			95,082
Total liabilities and partners’ equity	$	623,633	$	1,294,608	$	390,850	$	(907,536	)	$	1,401,555

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

Condensed Consolidating Statement of Comprehensive Income

Condensed Consolidating Statement of Comprehensive Income

Year Ended December 31, 2014	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries		Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	254,364		$	22,073	$	(1,241	)	$	275,196
Third parties	—			45,711			11,638		—			57,349
	—			300,075			33,711		(1,241		)	332,545
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	—			93,382			12,660		(1,241		)	104,801
Depreciation and amortization	—			47,592			14,574		—			62,166
General and administrative	2,658			8,166			—		—			10,824
	2,658			149,140			27,234		(1,241		)	177,791
Operating income (loss)	(2,658		)	150,935			6,477		—			154,754
Equity in earnings of subsidiaries	138,691			4,858			—		(143,549		)	—
Equity in earnings of SLC Pipeline	—			2,987			—		—			2,987
Interest income	—			3			—		—			3
Interest expense	(22,831		)	(13,270		)	—		—			(36,101		)
Loss on early extinguishment of debt	(7,677		)	—			—		—			(7,677		)
Other	—			82			—		—			82
	108,183			(5,340		)	—		(143,549		)	(40,706		)
Income (loss) before income taxes	105,525			145,595			6,477		(143,549		)	114,048
State income tax expense	—			(235		)	—		—			(235		)
Net income (loss)	105,525			145,360			6,477		(143,549		)	113,813
Allocation of net (income) attributable to noncontrolling interests	—			—			—		(8,288		)	(8,288		)
Net income (loss) attributable to Holly Energy Partners	105,525			145,360			6,477		(151,837		)	105,525
Other comprehensive (loss)	98			98			—		(98		)	98
Comprehensive income (loss)	$	105,623		$	145,458		$	6,477	$	(151,935	)	$	105,623

Condensed Consolidating Statement of Comprehensive Income

Year Ended December 31, 2013	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries		Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	236,336		$	17,258	$	(1,226	)	$	252,368
Third parties	—			42,139			10,675		—			52,814
	—			278,475			27,933		(1,226		)	305,182
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	—			88,614			12,056		(1,226		)	99,444
Depreciation and amortization	—			51,082			14,341		—			65,423
General and administrative	3,381			8,368			—		—			11,749
	3,381			148,064			26,397		(1,226		)	176,616
Operating income (loss)	(3,381		)	130,411			1,536		—			128,566
Equity in earnings of subsidiaries	115,850			1,231			—		(117,081		)	—
Equity in earnings of SLC Pipeline	—			2,826			—		—			2,826
Interest income	—			56			105		—			161
Interest expense	(33,020		)	(13,990		)	—		—			(47,010		)
Gain on sale of assets	—			1,810			—		—			1,810
Other	—			61			—		—			61
	82,830			(8,006		)	105		(117,081		)	(42,152		)
Income (loss) before income taxes	79,449			122,405			1,641		(117,081		)	86,414
State income tax expense	—			(333		)	—		—			(333		)
Net income (loss)	79,449			122,072			1,641		(117,081		)	86,081
Allocation of net loss attributable to noncontrolling interests	—			—			—		(6,632		)	(6,632		)
Net income (loss) attributable to Holly Energy Partners	79,449			122,072			1,641		(123,713		)	79,449
Other comprehensive income	4,135			4,135			—		(4,135		)	4,135
Comprehensive income (loss)	$	83,584		$	126,207		$	1,641	$	(127,848	)	$	83,584

Condensed Consolidating Statement of Comprehensive Income

Year Ended December 31, 2012	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	232,986		$	13,754		$	(1,158	)	$	245,582
Third parties	—			41,984			4,994			—			46,978
	—			274,970			18,748			(1,158		)	292,560
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	—			78,766			11,634			(1,158		)	89,242
Depreciation and amortization	—			43,147			14,314			—			57,461
General and administrative	3,336			4,258			—			—			7,594
	3,336			126,171			25,948			(1,158		)	154,297
Operating income (loss)	(3,336		)	148,799			(7,200		)	—			138,263
Equity in earnings (loss) of subsidiaries	130,743			(5,400		)	—			(125,343		)	—
Equity in earnings of SLC Pipeline	—			3,364			—			—			3,364
Interest expense	(31,523		)	(15,659		)	—			—			(47,182		)
Loss on early extinguishment of debt	(2,979		)	—			—			—			(2,979		)
Other	—			10			—			—			10
	96,241			(17,685		)	—			(125,343		)	(46,787		)
Income (loss) before income taxes	92,905			131,114			(7,200		)	(125,343		)	91,476
State income tax expense	—			(371		)	—			—			(371		)
Net income (loss)	92,905			130,743			(7,200		)	(125,343		)	91,105
Allocation of net loss attributable to Predecessors	4,200			—			—			—			4,200
Allocation of net loss attributable to noncontrolling interests	(2,953		)	—			—			1,800			(1,153		)
Net income (loss) attributable to Holly Energy Partners	94,152			130,743			(7,200		)	(123,543		)	94,152
Other comprehensive (loss)	2,185			2,185			—			(2,185		)	2,185
Comprehensive income (loss)	$	96,337		$	132,928		$	(7,200	)	$	(125,728	)	$	96,337

Condensed Consolidating Statement of Cash Flows

Condensed Consolidating Statement of Cash Flows

Year Ended December 31, 2014	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities	$	(25,339	)	$	193,273		$	19,398		$	(692	)	$	186,640
Cash flows from investing activities
Additions to properties and equipment	—			(71,758		)	(8,201		)	—			(79,959		)
Distributions from UNEV	—			11,383			—			(11,383		)	—
Distributions in excess of equity in earnings in SLC Pipeline	—			263			—			—			263
	—			(60,112		)	(8,201		)	(11,383		)	(79,696		)
Cash flows from financing activities
Net borrowings under credit agreement	—			208,000			—			—			208,000
Net intercompany financing activities	339,771			(339,771		)	—			—			—
Repayments of senior notes	(156,188		)	—			—			—			(156,188		)
Distributions to HEP unitholders	(154,670		)	—			—			—			(154,670		)
Distributions to noncontrolling interests	—			—			(16,100		)	12,075			(4,025		)
Purchase of units for incentive grants	(3,577		)	—			—			—			(3,577		)
Other	3			(9		)	—			—			(6		)
	25,339			(131,780		)	(16,100		)	12,075			(110,466		)
Cash and cash equivalents
Increase (decrease) for the period	—			1,381			(4,903		)	—			(3,522		)
Beginning of period	2			1,447			4,903			—			6,352
End of period	$	2		$	2,828		$	—		$	—		$	2,830

Condensed Consolidating Statement of Cash Flows

Year Ended December 31, 2013	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities	$	(34,605	)	$	197,678		$	20,007		$	—		$	183,080
Cash flows from investing activities
Additions to properties and equipment	—			(45,085		)	(7,016		)	—			(52,101		)
Proceeds from the sale of assets	—			2,731			—			—			2,731
Distributions from UNEV	—			9,375			—			(9,375		)	—
Distribution in excess of equity in earnings in SLC Pipeline	—			300			—			—			300
	—			(32,679		)	(7,016		)	(9,375		)	(49,070		)
Cash flows from financing activities
Net repayments under credit agreement	—			(58,000		)	—			—			(58,000		)
Net intercompany financing activities	105,031			(105,031		)	—			—			—
Proceeds from issuance of common units	73,444			—			—			—			73,444
Distributions to noncontrolling interests	—			—			(12,500		)	9,375			(3,125		)
Contributions from general partner	1,499			—			—			—			1,499
Distributions to HEP unitholders	(139,486		)	—			—			—			(139,486		)
Purchase of units for restricted grants	(5,634		)	—			—			—			(5,634		)
Deferred financing costs	—			(1,344		)	—			—			(1,344		)
Other	(249		)	—			—			—			(249		)
	34,605			(164,375		)	(12,500		)	9,375			(132,895		)
Cash and cash equivalents
Increase for the period	—			624			491			—			1,115
Beginning of period	2			823			4,412			—			5,237
End of period	$	2		$	1,447		$	4,903		$	—		$	6,352

Condensed Consolidating Statement of Cash Flows

Year Ended December 31, 2012	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations		Consolidated
	(In thousands)
Cash flows from operating activities	$	(34,557	)	$	194,667		$	1,039		$	—	$	161,149
Cash flows from investing activities
Additions to properties and equipment	—			(28,134		)	(14,727		)	—		(42,861		)
Distributions in excess of equity in earnings in SLC Pipeline	—			262			—			—		262
	—			(27,872		)	(14,727		)	—		(42,599		)
Cash flows from financing activities
Net borrowings under credit agreement	—			221,000			—			—		221,000
Proceeds from issuance of senior notes	294,750			—			—			—		294,750
Net intercompany financing activities	51,989			(51,989		)	—			—		—
Cash distribution to HFC for UNEV acquisition	—			(260,922		)	—			—		(260,922		)
Redemption of senior notes	(185,000		)	(75,235		)	—			—		(260,235		)
Contributions from UNEV joint venture partners	—			—			15,000			—		15,000
Contributions from general partner	1,748			—			—			—		1,748
Distributions to HEP unitholders	(122,777		)	—			—			—		(122,777		)
Purchase of units for restricted grants	(5,240		)	321			—			—		(4,919		)
Deferred financing costs	(913		)	(2,325		)	—			—		(3,238		)
Other	—			(89		)	—			—		(89		)
	34,557			(169,239		)	15,000			—		(119,682		)
Cash and cash equivalents
Increase (decrease) for the period	—			(2,444		)	1,312			—		(1,132		)
Beginning of period	2			3,267			3,100			—		6,369
End of period	$	2		$	823		$	4,412		$	—	$	5,237

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Description of Business and Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2014

Accounting Policies [Abstract]

Description of Business and Summary of Significant Accounting Policies

Description of Business and Summary of Significant Accounting Policies

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 operate in one reportable segment which represents the aggregation of our petroleum product and crude pipelines business and terminals, tankage and loading rack facilities operations.

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 the UNEV Pipeline, LLC (“UNEV”), which owns a 427-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.

Principles of Consolidation and Common Control Transactions

The consolidated financial statements include our accounts and those of subsidiaries and joint ventures that we control through a 50% or more ownership interest. All significant inter-company transactions and balances have been eliminated.

Most of our asset acquisitions from HFC occurred while we were a consolidated variable interest entity of HFC. Therefore, as an entity under common control with HFC, we recorded these assets on our balance sheets at HFC's historical basis instead of our purchase price or fair value.

Use of Estimates

The preparation of financial statements in accordance with U.S. generally accepted accounting principles (“GAAP”) requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates.

Cash and Cash Equivalents

For purposes of the statements of cash flows, we consider all highly liquid investments with maturities of three months or less at the time of purchase to be cash equivalents. The carrying amounts reported on the balance sheets approximate fair value due to the short-term maturity of these instruments.

Accounts Receivable

The majority of the accounts receivable are due from affiliates of HFC, Alon or independent companies in the petroleum industry. Credit is extended based on evaluation of the customer's financial condition and, in certain circumstances, collateral such as letters of credit or guarantees, may be required. Credit losses are charged to income when accounts are deemed uncollectible and historically have been minimal.

Properties and Equipment

Properties and equipment are stated at cost. Properties and equipment acquired from HFC while under common control of HFC are stated at HFC's historical basis. Depreciation is provided by the straight-line method over the estimated useful lives of the assets, primarily 15 to 25 years for terminal facilities and tankage, 25 to 32 years for pipelines and 5 to 10 years for corporate and other assets. We depreciate assets acquired under capital leases over the lesser of the lease term or the economic life of the assets. Maintenance, repairs and minor replacements are expensed as incurred. Costs of replacements constituting improvements are capitalized.

Transportation Agreements

The transportation agreement assets are stated at acquisition date fair value and are being amortized over the periods of the agreements using the straight-line method. See Note 5 for additional information on our transportation agreements.

Goodwill and Long-Lived Assets

Goodwill represents the excess of our cost of an acquired business over the fair value of the assets acquired, less liabilities assumed. Goodwill is not amortized and is tested for impairment annually or more frequently if events or changes in circumstances indicate goodwill may be impaired. We test goodwill at the reporting unit level for impairment annually and between annual tests if events or changes in circumstances indicate the carrying amount may exceed fair value. Recoverability is determined by comparing the estimated fair value of a reporting unit to the carrying value, including the related goodwill, of that reporting unit. We use the present value of the expected future net cash flows and market multiple analyses to determine the estimated fair values of the reporting units. The impairment test requires the use of projections, estimates and assumptions as to the future performance of our operations. Actual results could differ from projections resulting in revisions to our assumptions, and if required, recognizing an impairment loss.

We evaluate long-lived assets, including finite intangible assets, for potential impairment by identifying whether indicators of impairment exist and, if so, assessing whether the long-lived assets are recoverable from estimated future undiscounted cash flows. The actual amount of impairment loss, if any, to be recorded is equal to the amount by which a long-lived asset's carrying value exceeds its fair value.

There have been no impairments to goodwill or our long-lived assets as of December 31, 2014.

Investment in SLC Pipeline

We account for our 25% SLC Pipeline joint venture interest using the equity method of accounting, whereby we record our pro-rata share of earnings of the SLC Pipeline, and contributions to and distributions from the SLC Pipeline as adjustments to our investment balance. As of December 31, 2014, our underlying equity in the SLC Pipeline was $58.9 million compared to our recorded investment balance of $24.5 million, a difference of $34.4 million. We are amortizing this difference as an adjustment to our pro-rata share of earnings over the useful lives of the underlying assets of SLC Pipeline.

Asset Retirement Obligations

We record legal obligations associated with the retirement of certain of our long-lived assets that result from the acquisition, construction, development and/or the normal operation of our long-lived assets. The fair value of the estimated cost to retire a tangible long-lived asset is recorded in the period in which the liability is incurred and when a reasonable estimate of the fair value of the liability can be made. For our pipeline assets, the right-of-way agreements typically do not require the dismantling, removal and reclamation of the right-of-way upon cessation of the pipeline service. Additionally, management is unable to predict when, or if, our pipelines and related facilities would become obsolete and require decommissioning. Accordingly, we have recorded no liability or corresponding asset related to an asset retirement obligation for the majority of our pipelines as both the amounts and timing of such potential future costs are indeterminable. For our remaining assets, at December 31, 2014 and 2013, we have asset retirement obligations of $6.8 million and $6.5 million, respectively, that are recorded under “Other long-term liabilities” in our consolidated balance sheets.

Revenue Recognition

Revenues are recognized as products are shipped through our pipelines and terminals or other services are rendered. Billings to customers for their obligations under their quarterly minimum revenue commitments are recorded as deferred revenue liabilities if the customer has the right to receive future services for these billings. The revenue is recognized at the earlier of:

• the customer receiving the future services provided by these billings,

• the period in which the customer is contractually allowed to receive the services expires, or

• our determination that we will not be required to provide services within the allowed period.

We determine that we will not be required to provide services within the allowed period when, based on current and projected shipping levels, our pipeline systems will not have the necessary capacity to enable a customer to exceed its minimum volume levels to such a degree as to utilize the shortfall credit within its respective contractual shortfall make-up period.

We have additional revenues under an operating lease to a third party of an interest in the capacity of one of our pipelines.

As of December 31, 2014, billings to customers under their minimum revenue commitments per the terms of long-term throughput agreements expiring in 2019 through 2026 and the third party operating lease will result in minimum annualized payments to us in the aggregate of $2.5 billion including $272.4 million for each of the next five years. These agreements provide for increases in the minimum revenue guarantees annually for increases in the Producer Price Index ("PPI") or the Federal Energy Regulatory Commission ("FERC") index, with certain contracts having provisions that limit the level of the rate increases.

We have other cost reimbursement provisions in our throughput / storage agreements providing that customers (including HFC) reimburse us for certain costs. Such reimbursement receipts are recorded as revenue or deferred revenue depending on the nature of the cost. Deferred revenue is recognized over the remaining contractual term of the related throughput agreement.

Taxes billed and collected from our pipeline and terminal customers are recorded on a net basis with no effect on net income.

Environmental Costs

Environmental costs are expensed if they relate to an existing condition caused by past operations and do not contribute to current or future revenue generation. Liabilities are recorded when site restoration and environmental remediation, cleanup and other obligations are either known or considered probable and can be reasonably estimated. Such estimates require judgment with respect to costs, time frame and extent of required remedial and clean-up activities and are subject to periodic adjustments based on currently available information. At December 31, 2014 and 2013, we had accrued liabilities, measured on an undiscounted basis, net of expected recoveries from indemnifying parties, for environmental remediation obligations of $5.2 million and $3.6 million respectively, of which $2.3 million and $0.4 million, respectively, were classified as other current liabilities.

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 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. Environmental costs recoverable through insurance, indemnification agreements or other sources are included in other assets to the extent such recoveries are considered probable.

Income Tax

We are subject to the Texas margin tax that is based on our Texas sourced taxable margin. The tax is calculated by applying a tax rate to a base that considers both revenues and expenses and therefore has the characteristics of an income tax.

We are organized as a pass-through entity for federal income tax purposes. As a result, our partners are responsible for federal income taxes based on their respective share of taxable income.

Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under the partnership agreement.

Net Income per Limited Partners' Unit

We use the two-class method when calculating the net income per unit applicable to limited partners, which is based on the weighted-average number of common and subordinated units outstanding during the year. Net income per unit applicable to limited partners is computed by dividing limited partners' interest in net income, after adjusting for the allocation of net income or loss attributable to previous owners ("Predecessor"), the allocation of net income or loss attributable to noncontrolling interests and the general partner's 2% interest and incentive distributions and other participating securities, by the weighted-average number of outstanding common, subordinated units and other dilutive securities. Other participating securities and dilutive securities are not significant.

New Accounting Pronouncements

Revenue Recognition

In May 2014, an accounting standard update was issued requiring revenue to be recognized when promised goods or services are transferred to customers in an amount that reflects the expected consideration for these goods or services. This standard is effective January 1, 2017, and we are evaluating the impact of this standard.

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Description of Business and Presentation of Financial Statements (Details) (USD $)	3 Months Ended									12 Months Ended			0 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jan. 16, 2013	Jul. 12, 2012
Other Ownership Interests [Line Items]
Minimum Annualized Payments Receivable Aggregate	$ 2,500,000,000									$ 2,500,000,000
Partners' Capital Account, Sale of Units								73,400,000
Ownership percentage, controlling interest	39.00%									39.00%
General partner interest									2.00%	2.00%
Equity method investment, ownership percentage	50.00%									50.00%
Equity Method Investment, Underlying Equity in Net Assets	58,900,000									58,900,000
Sale of Stock, Number of Shares Issued in Transaction								1,875,000
Business Acquisitions, Limited partners interest in net income										70,858,000	51,926,000	71,702,000
Limited partners’ per unit interest in earnings—basic and diluted:	$ 0.33	$ 0.35	$ 0.25	$ 0.27	$ 0.19	$ 0.25	$ 0.23	$ 0.21		$ 1.20	$ 0.88	$ 1.29
Equity Method Investments	24,478,000				24,741,000					24,478,000	24,741,000
Asset Retirement Obligation	6,800,000				6,500,000					6,800,000	6,500,000
Minimum Annualized Payments Receivable	272,400,000									272,400,000
Accrual for Environmental Loss Contingencies	5,200,000				3,600,000					5,200,000	3,600,000
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	34,400,000									34,400,000
Loss on early extinguishment of debt										(7,677,000)	0	(2,979,000)
Common Units
Other Ownership Interests [Line Items]
Common unit split, conversion ratio													2
SLC Pipeline [Member]
Other Ownership Interests [Line Items]
Equity method investment, ownership percentage	25.00%									25.00%
Pipeline, length (miles)	95									95
UNEV Pipeline [Member]
Other Ownership Interests [Line Items]
Equity method investment, ownership percentage	75.00%									75.00%				75.00%
Pipeline, length (miles)	427									427
Pipeline, size (inches)	12									12
Other Fixed Assets [Member] | Minimum [Member]
Other Ownership Interests [Line Items]
Property, Plant and Equipment, Useful Life										5 years
Other Fixed Assets [Member] | Maximum [Member]
Other Ownership Interests [Line Items]
Property, Plant and Equipment, Useful Life										10 years
Pipelines and terminals [Member] | Minimum [Member]
Other Ownership Interests [Line Items]
Property, Plant and Equipment, Useful Life										25 years
Pipelines and terminals [Member] | Maximum [Member]
Other Ownership Interests [Line Items]
Property, Plant and Equipment, Useful Life										32 years
Terminal Facilities and Tankage [Member] [Member] | Minimum [Member]
Other Ownership Interests [Line Items]
Property, Plant and Equipment, Useful Life										15 years
Terminal Facilities and Tankage [Member] [Member] | Maximum [Member]
Other Ownership Interests [Line Items]
Property, Plant and Equipment, Useful Life										25 years
General Partner HFC [Member]
Other Ownership Interests [Line Items]
Sale of Stock, Number of Shares Issued in Transaction								1,875,000
Other Current Liabilities [Member]
Other Ownership Interests [Line Items]
Accrual for Environmental Loss Contingencies	$ 2,300,000				$ 400,000					$ 2,300,000	$ 400,000

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Debt Credit Agreement (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Debt Instrument, Interest Rate at Period End	2.152%	2.163%
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Letters of Credit Maximum Capacity	50
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Credit agreement, maximum borrowing capacity	650
Minimum [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.30%
Minimum [Member] | Option AA [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.625%
Minimum [Member] | Option (b) [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.625%
Maximum [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.45%
Maximum [Member] | Option AA [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.50%
Maximum [Member] | Option (b) [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.50%

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Supplemental Guarantor / Non-Guarantor Financial Information Condensed Consolidated Balance Sheet (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Current assets:
Cash and cash equivalents	$ 2,830	$ 6,352	$ 5,237	$ 6,369
Accounts receivable	40,129	34,736
Accounts Receivable, Related Parties, Current	0	0
Prepaid and other current assets	4,383	3,874
Total current assets	47,342	44,962
Properties and equipment, net	980,479	957,814
Investments in subsidiaries	0	0
Transportation agreements, net	80,703	87,650
Goodwill	256,498	256,498
Investment in SLC Pipeline	24,478	24,741
Other assets	12,055	10,843
Total assets	1,401,555	1,382,508
Current liabilities:
Accounts payable	17,881	22,898
Accounts Payable, Related Parties, Current	0	0
Accrued interest	6,615	10,239
Deferred revenue	12,432	13,981
Accrued property taxes	2,703	2,603
Other current liabilities	4,571	1,845
Total current liabilities	44,202	51,566
Long-term debt	867,579	807,630
Other long-term liabilities	18,145	14,585
Deferred Revenue	29,392	21,669
Class B unit	26,793	20,124
Equity - partners	320,362	369,446
Equity - noncontrolling interest	95,082	97,488
Total liabilities and equity	1,401,555	1,382,508
Parent [Member]
Current assets:
Cash and cash equivalents	2	2	2	2
Accounts receivable	0	0
Accounts Receivable, Related Parties, Current	0	0
Prepaid and other current assets	212	234
Total current assets	214	236
Properties and equipment, net	0	0
Investments in subsidiaries	622,100	885,598
Transportation agreements, net	0	0
Goodwill	0	0
Investment in SLC Pipeline	0	0
Other assets	1,319	1,684
Total assets	623,633	887,518
Current liabilities:
Accounts payable	0	0
Accounts Payable, Related Parties, Current	0	62,516
Accrued interest	6,500	10,198
Deferred revenue	0	0
Accrued property taxes	0	0
Other current liabilities	45	629
Total current liabilities	6,545	73,343
Long-term debt	296,579	444,630
Other long-term liabilities	147	99
Deferred Revenue	0	0
Class B unit	0	0
Equity - partners	320,362	369,446
Equity - noncontrolling interest	0	0
Total liabilities and equity	623,633	887,518
Guarantor Subsidiaries [Member]
Current assets:
Cash and cash equivalents	2,828	1,447	823	3,267
Accounts receivable	34,274	31,107
Accounts Receivable, Related Parties, Current	0	62,516
Prepaid and other current assets	2,856	2,590
Total current assets	39,958	97,660
Properties and equipment, net	596,988	564,847
Investments in subsidiaries	285,247	292,464
Transportation agreements, net	80,703	87,650
Goodwill	256,498	256,498
Investment in SLC Pipeline	24,478	24,741
Other assets	10,736	9,159
Total assets	1,294,608	1,333,019
Current liabilities:
Accounts payable	15,495	18,966
Accounts Payable, Related Parties, Current	0	0
Accrued interest	115	41
Deferred revenue	5,672	6,406
Accrued property taxes	1,902	1,661
Other current liabilities	4,408	1,216
Total current liabilities	27,592	28,290
Long-term debt	571,000	363,000
Other long-term liabilities	17,731	14,338
Deferred Revenue	29,392	21,669
Class B unit	26,793	20,124
Equity - partners	622,100	885,598
Equity - noncontrolling interest	0	0
Total liabilities and equity	1,294,608	1,333,019
Non-Guarantor Subsidiaries [Member]
Current assets:
Cash and cash equivalents	0	4,903	4,412	3,100
Accounts receivable	6,044	4,543
Accounts Receivable, Related Parties, Current	0	0
Prepaid and other current assets	1,315	1,050
Total current assets	7,359	10,496
Properties and equipment, net	383,491	392,967
Investments in subsidiaries	0	0
Transportation agreements, net	0	0
Goodwill	0	0
Investment in SLC Pipeline	0	0
Other assets	0	0
Total assets	390,850	403,463
Current liabilities:
Accounts payable	2,575	4,846
Accounts Payable, Related Parties, Current	0	0
Accrued interest	0	0
Deferred revenue	6,760	7,575
Accrued property taxes	801	942
Other current liabilities	118	0
Total current liabilities	10,254	13,363
Long-term debt	0	0
Other long-term liabilities	267	148
Deferred Revenue	0	0
Class B unit	0	0
Equity - partners	380,329	389,952
Equity - noncontrolling interest	0	0
Total liabilities and equity	390,850	403,463
Eliminations [Member]
Current assets:
Cash and cash equivalents	0	0	0	0
Accounts receivable	(189)	(914)
Accounts Receivable, Related Parties, Current	0	(62,516)
Prepaid and other current assets	0	0
Total current assets	(189)	(63,430)
Properties and equipment, net	0	0
Investments in subsidiaries	(907,347)	(1,178,062)
Transportation agreements, net	0	0
Goodwill	0	0
Investment in SLC Pipeline	0	0
Other assets	0	0
Total assets	(907,536)	(1,241,492)
Current liabilities:
Accounts payable	(189)	(914)
Accounts Payable, Related Parties, Current	0	(62,516)
Accrued interest	0	0
Deferred revenue	0	0
Accrued property taxes	0	0
Other current liabilities	0	0
Total current liabilities	(189)	(63,430)
Long-term debt	0	0
Other long-term liabilities	0	0
Deferred Revenue	0	0
Class B unit	0	0
Equity - partners	(1,002,429)	(1,275,550)
Equity - noncontrolling interest	95,082	97,488
Total liabilities and equity	$ (907,536)	$ (1,241,492)

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Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Current assets:
Cash and cash equivalents	$ 2,830	$ 6,352
Accounts receivable:
Trade	6,737	5,061
Affiliates	33,392	29,675
Total accounts receivable	40,129	34,736
Prepaid and other current assets	4,383	3,874
Total current assets	47,342	44,962
Properties and equipment, net	980,479	957,814
Transportation agreements, net	80,703	87,650
Goodwill	256,498	256,498
Investment in SLC Pipeline	24,478	24,741
Other assets	12,055	10,843
Total assets	1,401,555	1,382,508
Accounts payable:
Trade	12,642	14,414
Affiliates	5,239	8,484
Total accounts payable	17,881	22,898
Accrued interest	6,615	10,239
Deferred revenue	12,432	13,981
Accrued property taxes	2,703	2,603
Other current liabilities	4,571	1,845
Total current liabilities	44,202	51,566
Long-term debt	867,579	807,630
Other long-term liabilities	18,145	14,585
Deferred Revenue	29,392	21,669
Class B unit	26,793	20,124
Partners’ equity:
Common unitholders (58,657,048 units issued and outstanding at December 31, 2014 and 2013)	468,813	516,147
General partner interest (2% interest)	(148,405)	(146,557)
Accumulated other comprehensive loss	(46)	(144)
Total partners’ equity	320,362	369,446
Noncontrolling interest	95,082	97,488
Total Equity	415,444	466,934
Total liabilities and equity	$ 1,401,555	$ 1,382,508

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Debt Debt Maturities by Year (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2014
Long-term Debt, Fiscal Year Maturity [Abstract]
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	$ 0
Long-term Debt, Maturities, Repayments of Principal in Year Two	0
Long-term Debt, Maturities, Repayments of Principal in Year Three	0
Long-term Debt, Maturities, Repayments of Principal in Year Four	571,000
Long-term Debt, Maturities, Repayments of Principal in Year Five	0
Long-term Debt, Maturities, Repayments of Principal after Year Five	300,000
Long-term Debt	$ 871,000

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Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash flows from operating activities
Net income	$ 113,813	$ 86,081	$ 91,105
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	62,166	65,423	57,461
Gain on sale of assets	0	(1,810)	0
Amortization of deferred charges	1,820	2,970	7,556
Amortization of restricted and performance units	3,539	3,575	2,858
Loss on early extinguishment of debt	7,677	0	2,979
(Increase) decrease in operating assets:
Accounts receivable – trade	(1,676)	2,065	(3,997)
Accounts receivable – affiliates	(3,717)	1,919	(135)
Prepaid and other current assets	(510)	(255)	110
Increase (decrease) in operating liabilities:
Accounts payable – trade	2,469	3,365	(9,003)
Accounts payable – affiliates	(3,245)	3,821	(1,811)
Accrued interest	(3,624)	13	1,945
Deferred revenue	6,173	15,255	11,333
Accrued property taxes	100	(85)	492
Other current liabilities	1,819	(45)	113
Other, net	(164)	788	143
Net cash provided by operating activities	186,640	183,080	161,149
Cash flows from investing activities
Additions to properties and equipment	(79,959)	(52,101)	(42,861)
Proceeds from sale of assets	0	2,731	0
Distributions in Excess of Equity in Earnings in SLC Pipeline	263	300	262
Net cash used for investing activities	(79,696)	(49,070)	(42,599)
Cash flows from financing activities
Borrowings under credit agreement	642,300	310,600	587,000
Repayments of credit agreement borrowings	(434,300)	(368,600)	(366,000)
Proceeds from issuance of senior notes	0	0	294,750
Proceeds from issuance of common units	0	73,444	0
Cash distribution to HFC for UNEV acquisition	0	0	(260,922)
Repayments of senior notes	(156,188)	0	(260,235)
Contributions from noncontrolling interests	0	0	15,000
Contribution from general partner		1,499	1,748
Distributions to HEP unitholders	(154,670)	(139,486)	(122,777)
Distributions to noncontrolling interest	(4,025)	(3,125)	0
Purchase of units for incentive grants	(3,577)	(5,634)	(4,919)
Deferred financing costs	0	(1,344)	(3,238)
Other	(6)	(249)	(89)
Net cash used by financing activities	(110,466)	(132,895)	(119,682)
Cash and cash equivalents
Increase (decrease) for the year	(3,522)	1,115	(1,132)
Beginning of period	6,352	5,237	6,369
End of period	$ 2,830	$ 6,352	$ 5,237

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Properties and Equipment (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Property, Plant and Equipment [Line Items]
Properties and equipment, gross	$ 1,280,479,000	$ 1,210,913,000
Less accumulated depreciation	300,000,000	253,099,000
Properties and equipment, net	980,479,000	957,814,000
Interest costs, capitalized during period	(1,510,000)	(641,000)	(277,000)
Depreciation	54,700,000	58,100,000	50,100,000
Noncash Project Abandonment Costs	1,900,000	6,200,000	4,800,000
Pipelines and terminals [Member]
Property, Plant and Equipment [Line Items]
Properties and equipment, gross	1,137,157,000	1,077,037,000
Land and right of way [Member]
Property, Plant and Equipment [Line Items]
Properties and equipment, gross	64,458,000	63,425,000
Construction in progress [Member]
Property, Plant and Equipment [Line Items]
Properties and equipment, gross	56,228,000	50,454,000
Property, Plant and Equipment, Other Types [Member]
Property, Plant and Equipment [Line Items]
Properties and equipment, gross	$ 22,636,000	$ 19,997,000

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Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2014

Fair Value Disclosures [Abstract]

Schedule of Fair Value, Financial Instruments Measured on Recurring Basis

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

		December 31, 2014				December 31, 2013
Financial Instrument	Fair Value Input Level	Carrying Value		Fair Value		Carrying Value		Fair Value
		(In thousands)
Assets:
Interest rate swaps	Level 2	$	1,019	$	1,019	$	1,670	$	1,670
Liabilities:
Senior notes:
6.5% Senior Notes	Level 2	$	296,579	$	291,000	$	295,927	$	313,500
8.25% Senior Notes	Level 2	—		—		148,703		158,250
		296,579		291,000		444,630		471,750
Interest rate swaps	Level 2	1,065		1,065		1,814		1,814
		$	297,644	$	292,065	$	446,444	$	473,564

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Transportation Agreements (Details) (USD $)	12 Months Ended
	Dec. 31, 2014 Components	Dec. 31, 2013
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Amortization Expense	$ 6,900,000
Transportation Agreements [Abstract]
Transportation agreements, gross	134,164,000	134,164,000
Less accumulated amortization	53,461,000	46,514,000
Transportation agreements, net	80,703,000	87,650,000
Basis in Transportation Agreements	0
HFC transportation agreement
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Useful Life (years)	15 years
Transportation Agreements [Abstract]
Transportation agreements, gross	74,231,000	74,231,000
Alon transportation agreement
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Useful Life (years)	30 years
Finite-Lived Intangible Assets, Inital Term of Useful Life	15 years
Finite-Lived Intangible Assets, Useful Life, Initial Term	15 years
Transportation Agreements [Abstract]
Transportation agreements, gross	$ 59,933,000	$ 59,933,000

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Transportation Agreements (Tables)

12 Months Ended

Dec. 31, 2014

Finite-Lived Intangible Assets, Gross [Abstract]

Transportation Agreements by Major Class

The carrying amounts of our transportation agreements are as follows:

	December 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	53,461		46,514
	$	80,703	$	87,650

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Consolidated Statement of Partners' Equity (USD $) In Thousands, unless otherwise specified	Total	Common Units	General Partner Interest	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interest
Beginning balance at Dec. 31, 2011	$ 737,678	$ 481,439	$ 163,701	$ (6,464)	$ 99,002
Increase (Decrease) in Partners' Equity [Roll Forward]
Capital contribution	13,286		10,286		3,000
Distributions to HEP unitholders	(122,777)	(99,744)	(23,033)
Cash distribution	(260,922)		(260,922)
Issuance of common units		45,839	(45,839)
Issuance of Class B unit	(12,200)		(12,200)
Purchase of Units for Incentive Grants	(4,713)	(4,713)
Amortization of restricted and performance units	2,858	2,858
Class B unit accretion	(1,703)	(1,694)	(9)
Partners' Capital Account, Acquisitions	7,947	7,947
Other	112		112
Net income	91,105	70,877	22,027
Net Income (Loss) Attributable to Redeemable Noncontrolling Interest					(1,799)
Other comprehensive income	2,185			2,185
Ending balance at Dec. 31, 2012	452,856	502,809	(145,877)	(4,279)	100,203
Increase (Decrease) in Partners' Equity [Roll Forward]
Capital contribution	1,499		1,499
Stock Issued During Period, Value, Other	73,444	73,444
Distributions to HEP unitholders	(139,486)	(112,039)	(27,447)
Cash distribution	0
Purchase of Units for Incentive Grants	(5,313)	(5,313)
Amortization of restricted and performance units	3,575	3,575
Class B unit accretion	(6,221)	(6,097)	(124)
Distributions to noncontrolling interests	(3,125)				(3,125)
Other	(511)	(248)	(263)
Net income	86,081	60,016	25,655
Net Income (Loss) Attributable to Redeemable Noncontrolling Interest					410
Other comprehensive income	4,135			4,135
Ending balance at Dec. 31, 2013	466,934	516,147	(146,557)	(144)	97,488
Increase (Decrease) in Partners' Equity [Roll Forward]
Distributions to HEP unitholders	(154,670)	(119,944)	(34,726)
Cash distribution	0
Purchase of Units for Incentive Grants	(3,577)	(3,577)
Amortization of restricted and performance units	3,539	3,539
Class B unit accretion	(6,668)	(6,534)	(134)
Distributions to noncontrolling interests	(4,025)				(4,025)
Net income	113,813	79,182	33,012
Net Income (Loss) Attributable to Redeemable Noncontrolling Interest					1,619
Other comprehensive income	98			98
Ending balance at Dec. 31, 2014	$ 415,444	$ 468,813	$ (148,405)	$ (46)	$ 95,082

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Consolidated Balance Sheets (Parenthetical)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Partners' Equity:
Common units issued	58,657,048	58,657,048
Common units outstanding	58,657,048	58,657,048
General partner interest	2.00%

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Related Party Transactions

12 Months Ended

Dec. 31, 2014

Related Party Transactions [Abstract]

Related Party Transactions

Related Party Transactions

We serve HFC's refineries under long-term pipeline and terminal, tankage and throughput agreements expiring from 2019 to 2026. Under these agreements, HFC 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 1st each year based on the Producer Price Index (“PPI”) or Federal Energy Regulatory Commission (“FERC”) index. As of December 31, 2014, these agreements with HFC will result in minimum payments to us of $231.6 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 ($2.3 million in 2014 and currently $2.4 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 $275.2 million, $252.4 million and $245.6 million for the years ended December 31, 2014, 2013 and 2012, respectively.

• HFC charged us general and administrative services under the Omnibus Agreement of $2.3 million for each of the years ended December 31, 2014, 2013 and 2012.

• We reimbursed HFC for costs of employees supporting our operations of $38.9 million, $34.6 million and $31.1 million for the years ended December 31, 2014, 2013 and 2012, respectively. Netted against the cost of employees for the year ended December 31, 2013, is a $3.5 million refund from HFC related to refunds of taxes covering a multi-year period.

• HFC reimbursed us $16.8 million, $21.6 million and $13.4 million for the years ended December 31, 2014, 2013 and 2012, respectively, for certain reimbursable costs and capital projects.

• We distributed $80.5 million, $71.4 million and $64.0 million, for the years ended December 31, 2014, 2013 and 2012, respectively, to HFC as regular distributions on its common units and general partner interest, including general partner incentive distributions.

• Accounts receivable from HFC were $33.4 million and $29.7 million at December 31, 2014 and 2013, respectively.

• Accounts payable to HFC were $5.2 million and $8.5 million at December 31, 2014 and 2013, respectively.

• Revenues for the years ended December 31, 2014, 2013 and 2012 include $10.1 million, $5.1 million and $7.8 million, respectively, of shortfall payments billed in 2013, 2012 and 2011, respectively, as HFC did not exceed its minimum volume commitment in any of the subsequent four quarters in 2014, 2013 and 2012. Deferred revenue in the consolidated balance sheets at December 31, 2014 and 2013, includes $7.3 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 $7.3 million deferred at December 31, 2014.

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

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Document Entity Information (USD $)	12 Months Ended
	Dec. 31, 2014	Feb. 20, 2015	Jun. 30, 2014
Entity Information [Line Items]
Entity Registrant Name	HOLLY ENERGY PARTNERS LP
Entity Central Index Key	0001283140
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2014
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding		58,657,048
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 1,200,000,000

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Partners' Equity, Income Allocations and Cash Distributions

12 Months Ended

Dec. 31, 2014

Partners' Capital [Abstract]

Partners' Equity, Income Allocations and Cash Distributions

Partners’ Equity, Income Allocations and Cash Distributions

As of December 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.

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

Common Unit Issuances

2013 Issuances

In March 2013, we closed on a public offering of 1,875,000 of our common units. Additionally, an affiliate of HFC, as a selling unitholder, closed on a public sale of 1,875,000 of its HEP common units for which we did not receive any proceeds. We used our net proceeds of $73.4 million to repay indebtedness incurred under our credit facility and for general partnership purposes.

2012 Issuances

On July 12, 2012, we issued HFC 2,059,800 of our common units as partial consideration for our acquisition of its 75% interest in UNEV.

We received aggregate capital contributions of $1.7 million from our general partner to maintain its 2% general partner interest concurrent with the 2012 common unit issuance described above.

Under our registration statement filed with the SEC using a “shelf” registration process, $2.0 billion of securities have been registered. Any potential sale of such securities, through one or more prospectus supplements, 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.

Allocations of Net Income

Net income attributable to HEP is allocated between limited partners and the general partner interest in accordance with the provisions of the partnership agreement. HEP net income allocated to the general partner includes incentive distributions that are declared subsequent to quarter end. After the amount of incentive distributions is allocated to the general partner, the remaining net income attributable to HEP is allocated to the partners based on their weighted-average ownership percentage during the period.

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

	Years Ended December 31,
	2014		2013		2012
	(in thousands)
General partner interest in net income	$	1,446	$	1,059	$	1,464
General partner incentive distribution	33,221		26,464		20,986
Total general partner interest in net income	$	34,667	$	27,523	$	22,450

Cash Distributions

We consider regular cash distributions to unitholders on a quarterly basis, although there is no assurance as to the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors.

Within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement) to unitholders of record on the applicable record date. The amount of available cash generally is all cash on hand at the end of the quarter; less the amount of cash reserves established by our general partner to provide for the proper conduct of our business, comply with applicable laws, any of our debt instruments, or other agreements; or provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters; plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter.

We make distributions in the following manner: 98% to our common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter and any arrearages in payment of the minimum quarterly distributions for any prior quarters, thereafter. Cash in excess of the minimum quarterly distributions is distributed to the unitholders and the general partner based on certain percentages presented below.

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

	Total Quarterly Distribution	Marginal Percentage Interest in Distributions
	Target Amount	Unitholders	General Partner
Minimum quarterly distribution	$0.25	98%	2%
First target distribution	Up to $0.275	98%	2%
Second target distribution	above $0.275 up to $0.3125	85%	15%
Third target distribution	above $0.3125 up to $0.375	75%	25%
Thereafter	Above $0.375	50%	50%

On January 22, 2015, we announced our cash distribution for the fourth quarter of 2014 of $0.53 per unit. The distribution is payable on all common and general partner units and was paid February 13, 2015, to all unitholders of record on February 2, 2015.

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.

	Years Ended December 31,
	2014		2013		2012
	(In thousands, except per unit data)
General partner interest in distribution	$	3,264	$	2,982	$	2,566
General partner incentive distribution	33,221		26,464		20,986
Total general partner distribution	36,485		29,446		23,552
Limited partner distribution	121,714		114,675		102,222
Total regular quarterly cash distribution	$	158,199	$	144,121	$	125,774
Cash distribution per unit applicable to limited partners	$	2.075	$	1.955	$	1.835

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

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Consolidated Statements of Income (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues:
Affiliates	$ 275,196	$ 252,368	$ 245,582
Third parties	57,349	52,814	46,978
Total revenues	332,545	305,182	292,560
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	104,801	99,444	89,242
Depreciation and amortization	62,166	65,423	57,461
General and administrative	10,824	11,749	7,594
Total operating costs and expenses	177,791	176,616	154,297
Operating income	154,754	128,566	138,263
Other income (expense):
Equity in earnings of SLC Pipeline	0	0	0
Interest expense	(36,101)	(47,010)	(47,182)
Interest Income	3	161	0
Loss on early extinguishment of debt	(7,677)	0	(2,979)
Gain on sale of assets	0	1,810	0
Other Income	82	61	10
Total other income (expense)	(40,706)	(42,152)	(46,787)
Income before Income Taxes	114,048	86,414	91,476
State income tax expense	(235)	(333)	(371)
Net Income	113,813	86,081	91,105
Allocation of net loss attributable to Predecessors	0	0	4,200
Allocation of net income (loss) attributable to noncontrolling interest	(8,288)	(6,632)	(1,153)
Net income attributable to Holly Energy Partners	105,525	79,449	94,152
General partner interest in net income, including incentive distributions	(34,667)	(27,523)	(22,450)
Limited partners’ interest in net income	70,858	51,926	71,702
Limited partners’ per unit interest in earnings—basic and diluted:	$ 1.20	$ 0.88	$ 1.29
Weighted average limited partners’ units outstanding	58,657	58,246	55,696
SLC Pipeline [Member]
Other income (expense):
Equity in earnings of SLC Pipeline	$ 2,987	$ 2,826	$ 3,364

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Transportation Agreements

12 Months Ended

Dec. 31, 2014

Finite-Lived Intangible Assets, Gross [Abstract]

Transportation Agreements

Transportation Agreements

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

The carrying amounts of our transportation agreements are as follows:

	December 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	53,461		46,514
	$	80,703	$	87,650

Amortization expense was $6.9 million for each of the years ended December 31, 2014, 2013 and 2012, respectively.

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.

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Properties and Equipment

12 Months Ended

Dec. 31, 2014

Property, Plant and Equipment [Abstract]

Properties and Equipment

Properties and Equipment

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

	December 31, 2014		December 31, 2013
	(In thousands)
Pipelines, terminals and tankage	$	1,137,157	$	1,077,037
Land and right of way	64,458		63,425
Construction in progress	56,228		50,454
Other	22,636		19,997
	1,280,479		1,210,913
Less accumulated depreciation	300,000		253,099
	$	980,479	$	957,814

We capitalized $1.5 million and $0.6 million in interest related to construction projects during the years ended December 31, 2014 and 2013, respectively.

Depreciation expense was $54.7 million, $58.1 million, and $50.1 million for the years ended December 31, 2014, 2013 and 2012, respectively, and includes depreciation of assets acquired under capital leases. Asset abandonment charges of $1.9 million, $6.2 million and $4.8 million for assets permanently removed from service were included in depreciation expense for the years ended December 31, 2014, 2013 and 2012, respectively.

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Properties and Equipment (Tables)

12 Months Ended

Dec. 31, 2014

Property, Plant and Equipment [Abstract]

Properties and Equipment

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

	December 31, 2014		December 31, 2013
	(In thousands)
Pipelines, terminals and tankage	$	1,137,157	$	1,077,037
Land and right of way	64,458		63,425
Construction in progress	56,228		50,454
Other	22,636		19,997
	1,280,479		1,210,913
Less accumulated depreciation	300,000		253,099
	$	980,479	$	957,814

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Quarterly Financial Data

12 Months Ended

Dec. 31, 2014

Quarterly Financial Data [Abstract]

Quarterly Financial Information

Quarterly Financial Data (Unaudited)

Summarized quarterly financial data is as follows:

	First		Second		Third		Fourth		Total
	(In thousands, except per unit data)
Year Ended December 31, 2014
Revenues	$	87,004	$	74,998	$	82,130	$	88,413	$	332,545
Operating income	$	45,453	$	32,033	$	38,925	$	38,343	$	154,754
Income before income taxes	$	27,855	$	24,478	$	31,231	$	30,484	$	114,048
Net income	$	27,780	$	24,450	$	31,189	$	30,394	$	113,813
Net income attributable to Holly Energy Partners	$	24,143	$	23,034	$	29,680	$	28,668	$	105,525
Limited partners’ per unit interest in net income – basic and diluted	$	0.27	$	0.25	$	0.35	$	0.33	$	1.20
Distributions per limited partner unit	$	0.508	$	0.515	$	0.523	$	0.530	$	2.075
Year Ended December 31, 2013
Revenues	$	74,298	$	75,285	$	77,723	$	77,876	$	305,182
Operating income	$	31,047	$	32,520	$	34,173	$	30,826	$	128,566
Income before income taxes	$	21,345	$	21,641	$	23,097	$	20,331	$	86,414
Net income	$	21,289	$	21,297	$	23,057	$	20,438	$	86,081
Net income attributable to Holly Energy Partners	$	18,399	$	20,167	$	21,885	$	18,998	$	79,449
Limited partners’ per unit interest in net income – basic and diluted	$	0.21	$	0.23	$	0.25	$	0.19	$	0.88
Distributions per limited partner unit	$	0.478	$	0.485	$	0.493	$	0.500	$	1.955

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2014

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

We lease certain facilities, pipelines and rights of way under operating leases, most of which contain renewal options. The right of way agreements have various termination dates through 2053.

As of December 31, 2014, the minimum future rental commitments under operating leases having non-cancelable lease terms in excess of one year are as follows:

Years Ending December 31,	(In thousands)
2015	$	6,928
2016	6,913
2017	3,549
2018	192
2019	124
Thereafter	266
Total	$	17,972

Rental expense charged to operations was $8.0 million, $8.3 million and $8.1 million for the years ended December 31, 2014, 2013 and 2012, respectively.

We also have other long-term contractual obligations primarily consisting of long-term site service agreements with HFC, expiring in 2024 through 2026, for the provision of certain facility services and utility costs that relate to our assets located at HFC’s refinery facilities. At December 31, 2014, these minimum future contractual obligations having terms in excess of one year are as follows:

Years Ending December 31,	(In thousands)
2015	$	1,067
2016	1,067
2017	1,067
2018	1,067
2019	1,032
Thereafter	6,294
Total	$	11,594

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

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Employees, Retirement and Incentive Plans

12 Months Ended

Dec. 31, 2014

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

Employees, Retirement and Incentive Plans

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 $7.4 million, $7.4 million and $6.9 million for the years ended December 31, 2014, 2013 and 2012, respectively. These costs include retirement costs of $4.4 million, $5.0 million and $4.3 million for the years ended December 31, 2014, 2013 and 2012, respectively.

We have an incentive plan (“Long-Term Incentive Plan”) for employees and non-employee directors who perform services for us. The Long-Term Incentive Plan consists of four components: restricted 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 December 31, 2014, we have three types of incentive-based awards which are described below. The compensation cost charged against income was $3.5 million, $3.6 million and $2.9 million for the years ended December 31, 2014, 2013 and 2012, respectively. We currently purchase units in the open market instead of issuing new units for settlement of all unit awards under our Long-Term Incentive Plan. As of December 31, 2014, 2,500,000 units were authorized to be granted under our Long-Term Incentive Plan, of which 1,530,748 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.

A summary of restricted unit and phantom unit activity and changes during the year ended December 31, 2014, is presented below:

Restricted and Phantom Units	Units		Weighted- Average Grant-Date Fair Value
Outstanding at January 1, 2014 (nonvested)	122,951		$	33.36
Granted	91,852		33.49
Vesting and transfer of full ownership to recipients	(80,645	)	33.22
Forfeited	(8,081	)	35.28
Outstanding at December 31, 2014 (nonvested)	126,077		$	33.43

The fair values of restricted and phantom units that were vested and transferred to recipients during the years ended December 31, 2014, 2013 and 2012 were $2.7 million, $1.2 million and $2.4 million respectively. As of December 31, 2014, there was $3.0 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 1.5 years. For the years ended December 31, 2013 and 2012, the grant date closing unit price applied to the number of restricted units and phantom units ultimately awarded was $34.66 and $31.01 respectively.

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.

We granted 13,967 target performance units to certain officers in October 2014. These units will vest over a three year period ending December 31, 2017. The performance units granted 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 50% to 150% of the target number of performance units granted. Although common units are not transferred to the recipients until the performance units vest, the recipients have distribution rights with respect to the common units from the date of grant. The fair value of these performance units is based on the grant date closing unit price of $33.57 for the performance units granted in October 2014 and will apply to the number of units ultimately awarded. For the years ended December 31, 2013 and 2012, the weighted average grant date closing unit price applied to the number of units awarded was $37.90 and $30.61 respectively.

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

Performance Units	Units
Outstanding at January 1, 2014 (nonvested)	75,216
Granted	13,967
Vesting and transfer of common units to recipients	(17,938	)
Outstanding at December 31, 2014 (nonvested)	71,245

The grant date fair value of performance units vested and transferred to recipients was $0.5 million during each of the three years ended December 31, 2014, 2013 and 2012. Based on the weighted average fair value of performance units outstanding at December 31, 2014, of $2.6 million, there was $1.1 million of total unrecognized compensation expense related to nonvested performance units, which is expected to be recognized over a weighted-average period of 1.2 years.

During the year ended December 31, 2014, we paid $3.6 million for the purchase of our common units in the open market for the issuance and settlement of all unit awards under our Long-Term Incentive Plan.

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Debt

12 Months Ended

Dec. 31, 2014

Debt Instruments [Abstract]

Debt

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 is 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.

Indebtedness under the Credit Agreement bears interest, at our option, at either (a) the reference rate as announced by the administrative agent plus an applicable margin (ranging from 0.625% to 1.50%) or (b) at a rate equal to LIBOR plus an applicable margin (ranging from 1.625% to 2.50%). In each case, the applicable margin is based upon the ratio of our funded debt (as defined in the Credit Agreement) to EBITDA (earnings before interest, taxes, depreciation and amortization, as defined in the Credit Agreement). The weighted-average interest rates on our Credit Agreement borrowings in effect at December 31, 2014 and 2013, were 2.152% and 2.163%, respectively. We incur a commitment fee on the unused portion of the Credit Agreement at an annual rate ranging from 0.30% to 0.45% based upon the ratio of our funded debt to EBITDA for the four most recently completed fiscal quarters.

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

Senior Notes

In March 2012, we issued $300 million in aggregate principal amount outstanding of 6.5% Senior Notes maturing March 2020. Net proceeds of $294.8 million were used in March and April 2012 to redeem $185.0 million aggregate principal amount of our 6.25% Senior Notes maturing March 1, 2015, tendered pursuant to a cash tender offer and consent solicitation, to repay $72.9 million in promissory notes related to our November 2011 acquisition of assets located at HFC's El Dorado and Cheyenne refineries, to pay related fees, expenses and accrued interest in connection with these transactions and to repay borrowings under the Credit Agreement. We recognized a charge of $3.0 million upon the early extinguishment of our 6.25% Senior Notes for the year ended December 31, 2012. This charge represents the premium paid to our 6.25% Senior Note holders upon their tender of an aggregate principal amount of $185.0 million and related net discount.

In March 2014, we redeemed the $150 million aggregate principal amount of 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.

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 is recourse to HEP Logistics, our general partner, and is guaranteed by our material, 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.

Our purchase and contribution agreements with HFC with respect to the intermediate pipelines acquired in 2005 and the crude pipelines and tankage assets acquired in 2008, restrict us from selling these pipelines and terminals acquired from HFC. Under these agreements, we are restricted from prepaying borrowings and long-term debt to outstanding balances below $206 million prior to 2015 and $171 million prior to 2018, subject to certain limited exceptions.

Long-term Debt

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

	December 31, 2014			December 31, 2013
	(In thousands)
Credit Agreement	$	571,000		$	363,000
6.5% Senior Notes
Principal	300,000			300,000
Unamortized discount	(3,421		)	(4,073		)
	296,579			295,927
8.25% Senior Notes
Principal	—			150,000
Unamortized discount	—			(1,297		)
	—			148,703
Total long-term debt	$	867,579		$	807,630

Maturities of our long-term debt are as follows:

Years Ending December 31,	(In thousands)
2015	$	—
2016	—
2017	—
2018	571,000
2019	—
Thereafter	300,000
Total	$	871,000

Interest Rate Risk Management

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

As of December 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 December 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 December 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 December 31, 2014, we had no ineffectiveness on our cash flow hedges.

Prior to entering into our first swap contract (discussed above), we terminated our previous interest rate swap that prior to settlement also served to hedge our exposure to the effects of LIBOR changes on the same $155 million Credit Agreement advance. We terminated this swap at a cost of $6 million, to lock in a lower effective interest rate on this $155 million advance, which by means of the previous swap contract was effectively fixed at 6.24% at the time of termination. This cost of terminating the swap was amortized as a charge to interest expense through February 2013, the remaining term of the terminated swap contract.

At December 31, 2014, we have accumulated other comprehensive loss of $46,000 that relates to our current cash flow hedging instruments. Approximately $0.5 million will be transferred from accumulated other comprehensive loss into interest expense as interest is paid on the underlying swap agreement over the next twelve-month period, assuming interest rates remain unchanged.

Additional information on our interest rate swaps is as follows:

Derivative Instrument	Balance Sheet Location	Fair Value			Location of Offsetting Balance	Offsetting Amount
	(In thousands)
December 31, 2014
Interest rate swaps designated as cash flow hedging instrument:
Variable-to-fixed interest rate swap contract ($155 million of LIBOR based debt interest)	Other long-term     liabilities	$	(1,065	)	Accumulated other     comprehensive loss	$	(1,065	)
Variable-to-fixed interest rate swap contract ($150 million of LIBOR based debt interest)	Other long-term assets	1,019			Accumulated other     comprehensive income	1,019
		$	(46	)		$	(46	)
December 31, 2013
Interest rate swaps designated as cash flow hedging instrument:
Variable-to-fixed interest rate swap contract ($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 contract ($150 million of LIBOR based debt interest)	Other long-term assets	1,670			Accumulated other     comprehensive income	1,670
		$	(144	)		$	(144	)

Interest Expense and Other Debt Information

Interest expense consists of the following components:

	Years Ended December 31,
	2014		2013		2012
	(In thousands)
Interest on outstanding debt:
Credit Agreement, net of interest on interest rate swaps	$	13,350	$	11,961	$	8,736
6.5% Senior Notes	19,446		19,506		15,716
6.25% Senior Notes	—		—		2,422
8.25% Senior Notes	2,544		12,380		12,380
Promissory Notes	—		—		543
Amortization of discount and deferred debt issuance costs	1,821		2,120		1,946
Amortization of unrecognized loss attributable to terminated cash flow hedge	—		849		5,095
Commitment fees	450		835		621
Total interest incurred	37,611		47,651		47,459
Less capitalized interest	1,510		641		277
Net interest expense	$	36,101	$	47,010	$	47,182
Cash paid for interest	$	39,414	$	44,655	$	38,476

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Significant Customers

12 Months Ended

Dec. 31, 2014

Risks and Uncertainties [Abstract]

Significant Customers

Significant Customers

All revenues are domestic revenues, of which 93% are currently generated 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:

	Years Ended December 31,
	2014		2013		2012
HFC	83	%	83	%	84	%
Alon	10	%	11	%	11	%

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Financial Instruments (Narrative) (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Fair value inputs, Level 2 [Member]
Debt Instrument [Line Items]
Financial Liabilities Fair Value Disclosure	$ 292,065	$ 473,564
6.5% Senior Notes [Member]
Debt Instrument [Line Items]
Financial Liabilities Fair Value Disclosure	296,579	295,927
6.5% Senior Notes [Member] | Fair value inputs, Level 2 [Member]
Debt Instrument [Line Items]
Financial Liabilities Fair Value Disclosure	291,000	313,500
8.25% Senior Notes [Member]
Debt Instrument [Line Items]
Financial Liabilities Fair Value Disclosure	0	148,703
8.25% Senior Notes [Member] | Fair value inputs, Level 2 [Member]
Debt Instrument [Line Items]
Financial Liabilities Fair Value Disclosure	0	158,250
Carrying Amount [Member]
Debt Instrument [Line Items]
Financial Liabilities Fair Value Disclosure	297,644	446,444
Interest Rate Swap [Member]
Debt Instrument [Line Items]
Derivative Asset	1,019	1,670
Financial Liabilities Fair Value Disclosure	1,065	1,814
Interest Rate Swap [Member] | Fair value inputs, Level 2 [Member]
Debt Instrument [Line Items]
Derivative Asset	1,019	1,670
Financial Liabilities Fair Value Disclosure	1,065	1,814
Senior Debt Obligations [Member]
Debt Instrument [Line Items]
Financial Liabilities Fair Value Disclosure	296,579	444,630
Senior Debt Obligations [Member] | Fair value inputs, Level 2 [Member]
Debt Instrument [Line Items]
Financial Liabilities Fair Value Disclosure	$ 291,000	$ 471,750

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Partners' Equity, Cash Distributions (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Partners Capital, Distribution Amount per share Minimum									$ 0.250
Partners' Capital, Distribution Amount Per Share	$ 0								$ 0
Distribution of Available Cash to Unitholders, Period									45 days
Partner Distributions
General partner interest in distribution									$ 3,264	$ 2,982	$ 2,566
General partner incentive distribution									33,221	26,464	20,986
Total general partner distribution									36,485	29,446	23,552
Limited partner distribution									121,714	114,675	102,222
Total regular quarterly cash distribution									$ 158,199	$ 144,121	$ 125,774
Cash distribution per unit applicable to limited partners	$ 0.530	$ 0.523	$ 0.515	$ 0.5075	$ 0.500	$ 0.493	$ 0.485	$ 0.478	$ 2.075	$ 1.955	$ 1.835
Minimum Quarterly Distribution Percentage [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
General Partners Capital, Distribution Amount per share									2.00%
Partners Capital Distribution percentage									98.00%
Partner Distributions
General Partners Capital, Distribution Amount per share	0.00%								0.00%
First Target Distribution [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Partners Capital, Distribution Amount per share Maximum									$ 0.275
General Partners Capital, Distribution Amount per share									2.00%
Partners Capital Distribution percentage									98.00%
Second Distribution Target [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Partners Capital, Distribution Amount per share Minimum									$ 0.275
Partners Capital, Distribution Amount per share Maximum									$ 0.3125
General Partners Capital, Distribution Amount per share									15.00%
Partners Capital Distribution percentage									85.00%
Third Target Distribution [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Partners Capital, Distribution Amount per share Minimum									$ 0.3125
Partners Capital, Distribution Amount per share Maximum									$ 0.375
General Partners Capital, Distribution Amount per share									25.00%
Partners Capital Distribution percentage									75.00%
Thereafter Target Distribution [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Partners Capital, Distribution Amount per share Minimum									$ 0.375
General Partners Capital, Distribution Amount per share									50.00%
Partners Capital Distribution percentage									50.00%

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Description of Business and Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2014

Accounting Policies [Abstract]

Consolidation and Common Control Transactions, Policy

Principles of Consolidation and Common Control Transactions

The consolidated financial statements include our accounts and those of subsidiaries and joint ventures that we control through a 50% or more ownership interest. All significant inter-company transactions and balances have been eliminated.

Most of our asset acquisitions from HFC occurred while we were a consolidated variable interest entity of HFC. Therefore, as an entity under common control with HFC, we recorded these assets on our balance sheets at HFC's historical basis instead of our purchase price or fair value.

Use of Estimates, Policy

Use of Estimates

The preparation of financial statements in accordance with U.S. generally accepted accounting principles (“GAAP”) requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates.

Cash and Cash Equivalents, Policy

Cash and Cash Equivalents

For purposes of the statements of cash flows, we consider all highly liquid investments with maturities of three months or less at the time of purchase to be cash equivalents. The carrying amounts reported on the balance sheets approximate fair value due to the short-term maturity of these instruments.

Accounts Receivable, Policy

Accounts Receivable

The majority of the accounts receivable are due from affiliates of HFC, Alon or independent companies in the petroleum industry. Credit is extended based on evaluation of the customer's financial condition and, in certain circumstances, collateral such as letters of credit or guarantees, may be required. Credit losses are charged to income when accounts are deemed uncollectible and historically have been minimal.

Properties and Equipment, Policy

Properties and Equipment

Properties and equipment are stated at cost. Properties and equipment acquired from HFC while under common control of HFC are stated at HFC's historical basis. Depreciation is provided by the straight-line method over the estimated useful lives of the assets, primarily 15 to 25 years for terminal facilities and tankage, 25 to 32 years for pipelines and 5 to 10 years for corporate and other assets. We depreciate assets acquired under capital leases over the lesser of the lease term or the economic life of the assets. Maintenance, repairs and minor replacements are expensed as incurred. Costs of replacements constituting improvements are capitalized.

Transportation Agreements, Policy

Transportation Agreements

The transportation agreement assets are stated at acquisition date fair value and are being amortized over the periods of the agreements using the straight-line method. See Note 5 for additional information on our transportation agreements.

Goodwill and Long-Lived Assets, Policy

Goodwill and Long-Lived Assets

Goodwill represents the excess of our cost of an acquired business over the fair value of the assets acquired, less liabilities assumed. Goodwill is not amortized and is tested for impairment annually or more frequently if events or changes in circumstances indicate goodwill may be impaired. We test goodwill at the reporting unit level for impairment annually and between annual tests if events or changes in circumstances indicate the carrying amount may exceed fair value. Recoverability is determined by comparing the estimated fair value of a reporting unit to the carrying value, including the related goodwill, of that reporting unit. We use the present value of the expected future net cash flows and market multiple analyses to determine the estimated fair values of the reporting units. The impairment test requires the use of projections, estimates and assumptions as to the future performance of our operations. Actual results could differ from projections resulting in revisions to our assumptions, and if required, recognizing an impairment loss.

We evaluate long-lived assets, including finite intangible assets, for potential impairment by identifying whether indicators of impairment exist and, if so, assessing whether the long-lived assets are recoverable from estimated future undiscounted cash flows. The actual amount of impairment loss, if any, to be recorded is equal to the amount by which a long-lived asset's carrying value exceeds its fair value.

There have been no impairments to goodwill or our long-lived assets as of December 31, 2014.

Investment in SLC Pipeline, Policy

Investment in SLC Pipeline

We account for our 25% SLC Pipeline joint venture interest using the equity method of accounting, whereby we record our pro-rata share of earnings of the SLC Pipeline, and contributions to and distributions from the SLC Pipeline as adjustments to our investment balance. As of December 31, 2014, our underlying equity in the SLC Pipeline was $58.9 million compared to our recorded investment balance of $24.5 million, a difference of $34.4 million. We are amortizing this difference as an adjustment to our pro-rata share of earnings over the useful lives of the underlying assets of SLC Pipeline.

Asset Retirement Obligations, Policy

Asset Retirement Obligations

We record legal obligations associated with the retirement of certain of our long-lived assets that result from the acquisition, construction, development and/or the normal operation of our long-lived assets. The fair value of the estimated cost to retire a tangible long-lived asset is recorded in the period in which the liability is incurred and when a reasonable estimate of the fair value of the liability can be made. For our pipeline assets, the right-of-way agreements typically do not require the dismantling, removal and reclamation of the right-of-way upon cessation of the pipeline service. Additionally, management is unable to predict when, or if, our pipelines and related facilities would become obsolete and require decommissioning. Accordingly, we have recorded no liability or corresponding asset related to an asset retirement obligation for the majority of our pipelines as both the amounts and timing of such potential future costs are indeterminable. For our remaining assets, at December 31, 2014 and 2013, we have asset retirement obligations of $6.8 million and $6.5 million, respectively, that are recorded under “Other long-term liabilities” in our consolidated balance sheets.

Revenue Recognition, Policy

Revenue Recognition

Revenues are recognized as products are shipped through our pipelines and terminals or other services are rendered. Billings to customers for their obligations under their quarterly minimum revenue commitments are recorded as deferred revenue liabilities if the customer has the right to receive future services for these billings. The revenue is recognized at the earlier of:

• the customer receiving the future services provided by these billings,

• the period in which the customer is contractually allowed to receive the services expires, or

• our determination that we will not be required to provide services within the allowed period.

We determine that we will not be required to provide services within the allowed period when, based on current and projected shipping levels, our pipeline systems will not have the necessary capacity to enable a customer to exceed its minimum volume levels to such a degree as to utilize the shortfall credit within its respective contractual shortfall make-up period.

We have additional revenues under an operating lease to a third party of an interest in the capacity of one of our pipelines.

As of December 31, 2014, billings to customers under their minimum revenue commitments per the terms of long-term throughput agreements expiring in 2019 through 2026 and the third party operating lease will result in minimum annualized payments to us in the aggregate of $2.5 billion including $272.4 million for each of the next five years. These agreements provide for increases in the minimum revenue guarantees annually for increases in the Producer Price Index ("PPI") or the Federal Energy Regulatory Commission ("FERC") index, with certain contracts having provisions that limit the level of the rate increases.

We have other cost reimbursement provisions in our throughput / storage agreements providing that customers (including HFC) reimburse us for certain costs. Such reimbursement receipts are recorded as revenue or deferred revenue depending on the nature of the cost. Deferred revenue is recognized over the remaining contractual term of the related throughput agreement.

Taxes billed and collected from our pipeline and terminal customers are recorded on a net basis with no effect on net income.

Environmental Costs, Policy

Environmental Costs

Environmental costs are expensed if they relate to an existing condition caused by past operations and do not contribute to current or future revenue generation. Liabilities are recorded when site restoration and environmental remediation, cleanup and other obligations are either known or considered probable and can be reasonably estimated. Such estimates require judgment with respect to costs, time frame and extent of required remedial and clean-up activities and are subject to periodic adjustments based on currently available information. At December 31, 2014 and 2013, we had accrued liabilities, measured on an undiscounted basis, net of expected recoveries from indemnifying parties, for environmental remediation obligations of $5.2 million and $3.6 million respectively, of which $2.3 million and $0.4 million, respectively, were classified as other current liabilities.

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 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. Environmental costs recoverable through insurance, indemnification agreements or other sources are included in other assets to the extent such recoveries are considered probable.

Income Tax, Policy

Income Tax

We are subject to the Texas margin tax that is based on our Texas sourced taxable margin. The tax is calculated by applying a tax rate to a base that considers both revenues and expenses and therefore has the characteristics of an income tax.

We are organized as a pass-through entity for federal income tax purposes. As a result, our partners are responsible for federal income taxes based on their respective share of taxable income.

Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under the partnership agreement.

Net Income per Limited Partners' Unit, Policy

Net Income per Limited Partners' Unit

We use the two-class method when calculating the net income per unit applicable to limited partners, which is based on the weighted-average number of common and subordinated units outstanding during the year. Net income per unit applicable to limited partners is computed by dividing limited partners' interest in net income, after adjusting for the allocation of net income or loss attributable to previous owners ("Predecessor"), the allocation of net income or loss attributable to noncontrolling interests and the general partner's 2% interest and incentive distributions and other participating securities, by the weighted-average number of outstanding common, subordinated units and other dilutive securities. Other participating securities and dilutive securities are not significant.

New Accounting Pronouncements, Policy

New Accounting Pronouncements

Revenue Recognition

In May 2014, an accounting standard update was issued requiring revenue to be recognized when promised goods or services are transferred to customers in an amount that reflects the expected consideration for these goods or services. This standard is effective January 1, 2017, and we are evaluating the impact of this standard.

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Debt (Tables)

12 Months Ended

Dec. 31, 2014

Debt Instruments [Abstract]

Schedule of Long-term Debt Instruments

Long-term Debt

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

	December 31, 2014			December 31, 2013
	(In thousands)
Credit Agreement	$	571,000		$	363,000
6.5% Senior Notes
Principal	300,000			300,000
Unamortized discount	(3,421		)	(4,073		)
	296,579			295,927
8.25% Senior Notes
Principal	—			150,000
Unamortized discount	—			(1,297		)
	—			148,703
Total long-term debt	$	867,579		$	807,630

Schedule of Maturities of Long-term Debt

Maturities of our long-term debt are as follows:

Years Ending December 31,	(In thousands)
2015	$	—
2016	—
2017	—
2018	571,000
2019	—
Thereafter	300,000
Total	$	871,000

Schedule of Derivative Instruments

Additional information on our interest rate swaps is as follows:

Derivative Instrument	Balance Sheet Location	Fair Value			Location of Offsetting Balance	Offsetting Amount
	(In thousands)
December 31, 2014
Interest rate swaps designated as cash flow hedging instrument:
Variable-to-fixed interest rate swap contract ($155 million of LIBOR based debt interest)	Other long-term     liabilities	$	(1,065	)	Accumulated other     comprehensive loss	$	(1,065	)
Variable-to-fixed interest rate swap contract ($150 million of LIBOR based debt interest)	Other long-term assets	1,019			Accumulated other     comprehensive income	1,019
		$	(46	)		$	(46	)
December 31, 2013
Interest rate swaps designated as cash flow hedging instrument:
Variable-to-fixed interest rate swap contract ($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 contract ($150 million of LIBOR based debt interest)	Other long-term assets	1,670			Accumulated other     comprehensive income	1,670
		$	(144	)		$	(144	)

Schedule of Interest Expense and Other Debt Information

Interest expense consists of the following components:

	Years Ended December 31,
	2014		2013		2012
	(In thousands)
Interest on outstanding debt:
Credit Agreement, net of interest on interest rate swaps	$	13,350	$	11,961	$	8,736
6.5% Senior Notes	19,446		19,506		15,716
6.25% Senior Notes	—		—		2,422
8.25% Senior Notes	2,544		12,380		12,380
Promissory Notes	—		—		543
Amortization of discount and deferred debt issuance costs	1,821		2,120		1,946
Amortization of unrecognized loss attributable to terminated cash flow hedge	—		849		5,095
Commitment fees	450		835		621
Total interest incurred	37,611		47,651		47,459
Less capitalized interest	1,510		641		277
Net interest expense	$	36,101	$	47,010	$	47,182
Cash paid for interest	$	39,414	$	44,655	$	38,476

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Partners' Equity (Details) (USD $)	3 Months Ended		12 Months Ended	0 Months Ended
	Mar. 31, 2013	Dec. 31, 2012	Dec. 31, 2014	Jul. 12, 2012	Jan. 16, 2013
Capital Unit [Line Items]
Partners' capital account, units held by controlling interest			22,380,030
General partner ownership interest		2.00%	2.00%
Ownership percentage, controlling interest			39.00%
Sale of Stock, Number of Shares Issued in Transaction	1,875,000
Partners' Capital Account, Sale of Units	$ 73,400,000
Equity method investment, ownership percentage			50.00%
General Partners' Contributed Capital		1,700,000
Public Offering of Securities, Maximum Proceeds Authorized			$ 2,000,000,000
UNEV Pipeline [Member]
Capital Unit [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares				2,059,800
Equity method investment, ownership percentage			75.00%	75.00%
General Partner HFC [Member]
Capital Unit [Line Items]
Sale of Stock, Number of Shares Issued in Transaction	1,875,000
Common Units
Capital Unit [Line Items]
Common unit split, conversion ratio					2

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Debt Senior Notes (Details) (USD $)	12 Months Ended			3 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Mar. 31, 2014	Mar. 31, 2012
Debt Instrument [Line Items]
Proceeds from senior notes	$ 0	$ 0	$ 294,750,000
Loss on early extinguishment of debt	(7,677,000)	0	(2,979,000)
Credit agreement restrictions before 2015	206,000,000
Credit agreement restrictions 2015 to 2018	171,000,000
8.25% Interest Rate [Member]
Debt Instrument [Line Items]
Principal				150,000,000
Stated interest rate, senior notes				8.25%
Senior Notes Aggregate Redemption Amount				156,200,000
Loss on early extinguishment of debt				7,700,000
Debt Instrument, Unamortized Premium				6,200,000
Amortization of Financing Costs				1,500,000
6.5% Interest Rate [Member]
Debt Instrument [Line Items]
Principal					300,000,000
Proceeds from senior notes					294,800,000
Stated interest rate, senior notes	6.50%				6.50%
6.25% Interest Rate [Member]
Debt Instrument [Line Items]
Repayment of senior notes					185,000,000
Stated interest rate, senior notes					6.25%
Promissory Notes [Member]
Debt Instrument [Line Items]
Repayment of notes					$ (72,900,000)

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Consolidated Statement of Comprehensive Income (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Net income	$ 113,813	$ 86,081	$ 91,105
Change in fair value of cash flow hedging instruments	(2,104)	1,194	(4,418)
Amortization of unrealized loss attributable to discontinued cash flow hedge	0	849	5,095
Reclassification adjustment to net income on partial settlement of cash flow hedge	2,202	2,092	1,508
Other comprehensive income	98	4,135	2,185
Comprehensive income before noncontrolling interest	113,911	90,216	93,290
Allocation of comprehensive (income) loss to noncontrolling interests	(8,288)	(6,632)	(1,153)
Allocation of net loss attributable to Predecessors	0	0	4,200
Comprehensive income attributable to Holly Energy Partners	$ 105,623	$ 83,584	$ 96,337

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Financial Instruments

12 Months Ended

Dec. 31, 2014

Fair Value Disclosures [Abstract]

Financial Instruments

Financial Instruments

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

Fair value measurements are derived using inputs (assumptions that market participants would use in pricing an asset or liability) including assumptions about risk. GAAP categorizes inputs used in fair value measurements into three broad levels as follows:

• (Level 1) Quoted prices in active markets for identical assets or liabilities.

• (Level 2) Observable inputs other than quoted prices included in Level 1, such as quoted prices for similar assets and liabilities in active markets, similar assets and liabilities in markets that are not active or can be corroborated by observable market data.

• (Level 3) Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. This includes valuation techniques that involve significant unobservable inputs.

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

		December 31, 2014				December 31, 2013
Financial Instrument	Fair Value Input Level	Carrying Value		Fair Value		Carrying Value		Fair Value
		(In thousands)
Assets:
Interest rate swaps	Level 2	$	1,019	$	1,019	$	1,670	$	1,670
Liabilities:
Senior notes:
6.5% Senior Notes	Level 2	$	296,579	$	291,000	$	295,927	$	313,500
8.25% Senior Notes	Level 2	—		—		148,703		158,250
		296,579		291,000		444,630		471,750
Interest rate swaps	Level 2	1,065		1,065		1,814		1,814
		$	297,644	$	292,065	$	446,444	$	473,564

Level 2 Financial Instruments

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

See Note 7 for additional information on these instruments.

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2014

Commitments and Contingencies Disclosure [Abstract]

Commitments Disclosure Site Service Agreements [Table Text Block]

At December 31, 2014, these minimum future contractual obligations having terms in excess of one year are as follows:

Years Ending December 31,	(In thousands)
2015	$	1,067
2016	1,067
2017	1,067
2018	1,067
2019	1,032
Thereafter	6,294
Total	$	11,594

Schedule of Future Minimum Rental Payments for Operating Leases

As of December 31, 2014, the minimum future rental commitments under operating leases having non-cancelable lease terms in excess of one year are as follows:

Years Ending December 31,	(In thousands)
2015	$	6,928
2016	6,913
2017	3,549
2018	192
2019	124
Thereafter	266
Total	$	17,972

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Employees, Retirement and Incentive Plans Restricted Units (Details) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Phantom Share Units (PSUs) [Member]
Weighted Average Grant-Date Fair Value
Award vesting period	1 year
Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding at January 1, 2014 (nonvested)	122,951
Granted	91,852
Vesting and transfer of full ownership to recipients	80,645
Forfeited	(8,081)
Outstanding at December 31, 2014 (nonvested)	126,077	122,951
Weighted Average Grant-Date Fair Value
Outstanding at January 1, 2014 (nonvested)	$ 33.36
Granted	$ 33.49
Vesting and transfer of full ownership to recipients	$ 33.22	$ 34.66	$ 31.01
Forfeited	$ 35.28
Outstanding at December 31, 2014 (nonvested)	$ 33.43	$ 33.36
Weighted average remaining contractual term (years)	1 year 6 months
Fair value of vested units transferred to recipients	$ 2.7	$ 1.2	$ 2.4
Total unrecognized compensation related to nonvested units	$ 3.0
Minimum [Member] | Restricted Stock [Member]
Weighted Average Grant-Date Fair Value
Award vesting period	1 year
Minimum [Member] | Restricted Stock Units (RSUs) [Member]
Weighted Average Grant-Date Fair Value
Award vesting period	1 year
Maximum [Member] | Restricted Stock [Member]
Weighted Average Grant-Date Fair Value
Award vesting period	3 years
Maximum [Member] | Restricted Stock Units (RSUs) [Member]
Weighted Average Grant-Date Fair Value
Award vesting period	3 years

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Supplemental Guarantor / Non-Guarantor Financial Information

12 Months Ended

Dec. 31, 2014

Supplemental Guarantor / Non-Guarantor Financial Information [Abstract]

Supplemental Guarantor / Non-Guarantor Financial Information

Supplemental Guarantor/Non-Guarantor Financial Information

Obligations of HEP (“Parent”) under the Senior Notes have been jointly and severally guaranteed by each of its direct and indirect 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.

Condensed Consolidating Balance Sheet

December 31, 2014	Parent		Guarantor Restricted Subsidiaries		Non-Guarantor Non-Restricted Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	2	$	2,828	$	—	$	—		$	2,830
Accounts receivable	—		34,274		6,044		(189		)	40,129
Prepaid and other current assets	212		2,856		1,315		—			4,383
Total current assets	214		39,958		7,359		(189		)	47,342
Properties and equipment, net	—		596,988		383,491		—			980,479
Investment in subsidiaries	622,100		285,247		—		(907,347		)	—
Transportation agreements, net	—		80,703		—		—			80,703
Goodwill	—		256,498		—		—			256,498
Investment in SLC Pipeline	—		24,478		—		—			24,478
Other assets	1,319		10,736		—		—			12,055
Total assets	$	623,633	$	1,294,608	$	390,850	$	(907,536	)	$	1,401,555
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	—	$	15,495	$	2,575	$	(189	)	$	17,881
Accrued interest	6,500		115		—		—			6,615
Deferred revenue	—		5,672		6,760		—			12,432
Accrued property taxes	—		1,902		801		—			2,703
Other current liabilities	45		4,408		118		—			4,571
Total current liabilities	6,545		27,592		10,254		(189		)	44,202
Long-term debt	296,579		571,000		—		—			867,579
Other long-term liabilities	147		17,731		267		—			18,145
Deferred revenue	—		29,392		—		—			29,392
Class B unit	—		26,793		—		—			26,793
Equity - partners	320,362		622,100		380,329		(1,002,429		)	320,362
Equity - noncontrolling interest	—		—		—		95,082			95,082
Total liabilities and partners’ equity	$	623,633	$	1,294,608	$	390,850	$	(907,536	)	$	1,401,555

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

Condensed Consolidating Statement of Comprehensive Income

Year Ended December 31, 2014	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries		Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	254,364		$	22,073	$	(1,241	)	$	275,196
Third parties	—			45,711			11,638		—			57,349
	—			300,075			33,711		(1,241		)	332,545
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	—			93,382			12,660		(1,241		)	104,801
Depreciation and amortization	—			47,592			14,574		—			62,166
General and administrative	2,658			8,166			—		—			10,824
	2,658			149,140			27,234		(1,241		)	177,791
Operating income (loss)	(2,658		)	150,935			6,477		—			154,754
Equity in earnings of subsidiaries	138,691			4,858			—		(143,549		)	—
Equity in earnings of SLC Pipeline	—			2,987			—		—			2,987
Interest income	—			3			—		—			3
Interest expense	(22,831		)	(13,270		)	—		—			(36,101		)
Loss on early extinguishment of debt	(7,677		)	—			—		—			(7,677		)
Other	—			82			—		—			82
	108,183			(5,340		)	—		(143,549		)	(40,706		)
Income (loss) before income taxes	105,525			145,595			6,477		(143,549		)	114,048
State income tax expense	—			(235		)	—		—			(235		)
Net income (loss)	105,525			145,360			6,477		(143,549		)	113,813
Allocation of net (income) attributable to noncontrolling interests	—			—			—		(8,288		)	(8,288		)
Net income (loss) attributable to Holly Energy Partners	105,525			145,360			6,477		(151,837		)	105,525
Other comprehensive (loss)	98			98			—		(98		)	98
Comprehensive income (loss)	$	105,623		$	145,458		$	6,477	$	(151,935	)	$	105,623

Condensed Consolidating Statement of Comprehensive Income

Year Ended December 31, 2013	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries		Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	236,336		$	17,258	$	(1,226	)	$	252,368
Third parties	—			42,139			10,675		—			52,814
	—			278,475			27,933		(1,226		)	305,182
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	—			88,614			12,056		(1,226		)	99,444
Depreciation and amortization	—			51,082			14,341		—			65,423
General and administrative	3,381			8,368			—		—			11,749
	3,381			148,064			26,397		(1,226		)	176,616
Operating income (loss)	(3,381		)	130,411			1,536		—			128,566
Equity in earnings of subsidiaries	115,850			1,231			—		(117,081		)	—
Equity in earnings of SLC Pipeline	—			2,826			—		—			2,826
Interest income	—			56			105		—			161
Interest expense	(33,020		)	(13,990		)	—		—			(47,010		)
Gain on sale of assets	—			1,810			—		—			1,810
Other	—			61			—		—			61
	82,830			(8,006		)	105		(117,081		)	(42,152		)
Income (loss) before income taxes	79,449			122,405			1,641		(117,081		)	86,414
State income tax expense	—			(333		)	—		—			(333		)
Net income (loss)	79,449			122,072			1,641		(117,081		)	86,081
Allocation of net loss attributable to noncontrolling interests	—			—			—		(6,632		)	(6,632		)
Net income (loss) attributable to Holly Energy Partners	79,449			122,072			1,641		(123,713		)	79,449
Other comprehensive income	4,135			4,135			—		(4,135		)	4,135
Comprehensive income (loss)	$	83,584		$	126,207		$	1,641	$	(127,848	)	$	83,584

Condensed Consolidating Statement of Comprehensive Income

Year Ended December 31, 2012	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	232,986		$	13,754		$	(1,158	)	$	245,582
Third parties	—			41,984			4,994			—			46,978
	—			274,970			18,748			(1,158		)	292,560
Operating costs and expenses:
Operations (exclusive of depreciation and amortization)	—			78,766			11,634			(1,158		)	89,242
Depreciation and amortization	—			43,147			14,314			—			57,461
General and administrative	3,336			4,258			—			—			7,594
	3,336			126,171			25,948			(1,158		)	154,297
Operating income (loss)	(3,336		)	148,799			(7,200		)	—			138,263
Equity in earnings (loss) of subsidiaries	130,743			(5,400		)	—			(125,343		)	—
Equity in earnings of SLC Pipeline	—			3,364			—			—			3,364
Interest expense	(31,523		)	(15,659		)	—			—			(47,182		)
Loss on early extinguishment of debt	(2,979		)	—			—			—			(2,979		)
Other	—			10			—			—			10
	96,241			(17,685		)	—			(125,343		)	(46,787		)
Income (loss) before income taxes	92,905			131,114			(7,200		)	(125,343		)	91,476
State income tax expense	—			(371		)	—			—			(371		)
Net income (loss)	92,905			130,743			(7,200		)	(125,343		)	91,105
Allocation of net loss attributable to Predecessors	4,200			—			—			—			4,200
Allocation of net loss attributable to noncontrolling interests	(2,953		)	—			—			1,800			(1,153		)
Net income (loss) attributable to Holly Energy Partners	94,152			130,743			(7,200		)	(123,543		)	94,152
Other comprehensive (loss)	2,185			2,185			—			(2,185		)	2,185
Comprehensive income (loss)	$	96,337		$	132,928		$	(7,200	)	$	(125,728	)	$	96,337

Condensed Consolidating Statement of Cash Flows

Year Ended December 31, 2014	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities	$	(25,339	)	$	193,273		$	19,398		$	(692	)	$	186,640
Cash flows from investing activities
Additions to properties and equipment	—			(71,758		)	(8,201		)	—			(79,959		)
Distributions from UNEV	—			11,383			—			(11,383		)	—
Distributions in excess of equity in earnings in SLC Pipeline	—			263			—			—			263
	—			(60,112		)	(8,201		)	(11,383		)	(79,696		)
Cash flows from financing activities
Net borrowings under credit agreement	—			208,000			—			—			208,000
Net intercompany financing activities	339,771			(339,771		)	—			—			—
Repayments of senior notes	(156,188		)	—			—			—			(156,188		)
Distributions to HEP unitholders	(154,670		)	—			—			—			(154,670		)
Distributions to noncontrolling interests	—			—			(16,100		)	12,075			(4,025		)
Purchase of units for incentive grants	(3,577		)	—			—			—			(3,577		)
Other	3			(9		)	—			—			(6		)
	25,339			(131,780		)	(16,100		)	12,075			(110,466		)
Cash and cash equivalents
Increase (decrease) for the period	—			1,381			(4,903		)	—			(3,522		)
Beginning of period	2			1,447			4,903			—			6,352
End of period	$	2		$	2,828		$	—		$	—		$	2,830

Condensed Consolidating Statement of Cash Flows

Year Ended December 31, 2013	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities	$	(34,605	)	$	197,678		$	20,007		$	—		$	183,080
Cash flows from investing activities
Additions to properties and equipment	—			(45,085		)	(7,016		)	—			(52,101		)
Proceeds from the sale of assets	—			2,731			—			—			2,731
Distributions from UNEV	—			9,375			—			(9,375		)	—
Distribution in excess of equity in earnings in SLC Pipeline	—			300			—			—			300
	—			(32,679		)	(7,016		)	(9,375		)	(49,070		)
Cash flows from financing activities
Net repayments under credit agreement	—			(58,000		)	—			—			(58,000		)
Net intercompany financing activities	105,031			(105,031		)	—			—			—
Proceeds from issuance of common units	73,444			—			—			—			73,444
Distributions to noncontrolling interests	—			—			(12,500		)	9,375			(3,125		)
Contributions from general partner	1,499			—			—			—			1,499
Distributions to HEP unitholders	(139,486		)	—			—			—			(139,486		)
Purchase of units for restricted grants	(5,634		)	—			—			—			(5,634		)
Deferred financing costs	—			(1,344		)	—			—			(1,344		)
Other	(249		)	—			—			—			(249		)
	34,605			(164,375		)	(12,500		)	9,375			(132,895		)
Cash and cash equivalents
Increase for the period	—			624			491			—			1,115
Beginning of period	2			823			4,412			—			5,237
End of period	$	2		$	1,447		$	4,903		$	—		$	6,352

Condensed Consolidating Statement of Cash Flows

Year Ended December 31, 2012	Parent			Guarantor Restricted Subsidiaries			Non-Guarantor Non-Restricted Subsidiaries			Eliminations		Consolidated
	(In thousands)
Cash flows from operating activities	$	(34,557	)	$	194,667		$	1,039		$	—	$	161,149
Cash flows from investing activities
Additions to properties and equipment	—			(28,134		)	(14,727		)	—		(42,861		)
Distributions in excess of equity in earnings in SLC Pipeline	—			262			—			—		262
	—			(27,872		)	(14,727		)	—		(42,599		)
Cash flows from financing activities
Net borrowings under credit agreement	—			221,000			—			—		221,000
Proceeds from issuance of senior notes	294,750			—			—			—		294,750
Net intercompany financing activities	51,989			(51,989		)	—			—		—
Cash distribution to HFC for UNEV acquisition	—			(260,922		)	—			—		(260,922		)
Redemption of senior notes	(185,000		)	(75,235		)	—			—		(260,235		)
Contributions from UNEV joint venture partners	—			—			15,000			—		15,000
Contributions from general partner	1,748			—			—			—		1,748
Distributions to HEP unitholders	(122,777		)	—			—			—		(122,777		)
Purchase of units for restricted grants	(5,240		)	321			—			—		(4,919		)
Deferred financing costs	(913		)	(2,325		)	—			—		(3,238		)
Other	—			(89		)	—			—		(89		)
	34,557			(169,239		)	15,000			—		(119,682		)
Cash and cash equivalents
Increase (decrease) for the period	—			(2,444		)	1,312			—		(1,132		)
Beginning of period	2			3,267			3,100			—		6,369
End of period	$	2		$	823		$	4,412		$	—	$	5,237