10-K 1 hep12-31x201310k.htm 10-K HEP 12-31-2013 10K
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, 2013
OR

¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from    __________   to   ____________         
Commission File Number 1-32225
 _________________________________________________________________
HOLLY ENERGY PARTNERS, L.P.
(Exact name of registrant as specified in its charter)
_________________________________________________________________
Delaware
 
20-0833098
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer Identification No.)
 
 
 
2828 N. Harwood, Suite 1300
Dallas, Texas
 
75201-1507
(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.
_________________________________________________________________
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 $1.3 billion on June 28, 2013, 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 14, 2014 was 58,657,048.
 __________________________________________________________________________________________
DOCUMENTS INCORPORATED BY REFERENCE: None



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TABLE OF CONTENTS

 
 
 
Item
 
Page
 
PART I
 
 
 
 
 
 
 
1.
1A.
1B.
2.
3.
4.
 
 
 
 
PART II
 
 
 
 
5.
6.
7.
7A.
8.
9.
9A.
9B.
 
 
 
 
PART III
 
 
 
 
10.
11.
12.
13.
14.
 
 
 
 
PART IV
 
 
 
 
15.
 
 
 
 
 
 



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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 additional operations in the future successfully;
•
our ability to complete previously announced or contemplated acquisitions;
•
the availability and cost of additional debt and equity financing;
•
the possibility of reductions in production or shutdowns at refineries utilizing our pipeline and terminal facilities;
•
the effects of current and future government regulations and policies;
•
our operational efficiency in carrying out routine operations and capital construction projects;
•
the possibility of terrorist attacks and the consequences of any such attacks;
•
general economic conditions; and
•
other financial, operational and legal risks and uncertainties detailed from time to time in our Securities and Exchange Commission filings.

Cautionary statements identifying important factors that could cause actual results to differ materially from our expectations are set forth in this Form 10-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:
 
 
 
 
 
Alon
5
 
 
Beeson Pipeline
27
 
 
bpd
8
 
 
CFR
9
 
 
Credit Agreement
8
 
 
DOT
9
 
 
EBITDA
37
 
 
Expansion capital expenditures
8
 
 
FERC
7
 
 
GAAP
37
 
 
Guarantor subsidiaries
79
 
 
HEP
5
 
 
HEP Logistics
20
 
 
HLS
5
 
 
HFC
5
 
 
LACT
6
 
 
LIBOR
49
 
 
Long-term Incentive Plan
69
 
 
LPG
6
 
 
Maintenance capital expenditures
8
 
 
mbbls
26
 
 
mbpd
43
 
 
MMSCFD
27
 
 
Mid-America
27
 
 
Non-Guarantor
79
 
 
NuStar
30
 
 
Omnibus Agreement
7
 
 
OSHA
16
 
 
Parent
79
 
 
Plains
5
 
 
PPI
7
 
 
Predecessor
37
 
 
SEC
5
 
 
Senior Notes
13
 
 
SLC Pipeline
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 417-mile, 12-inch refined products pipeline running from Woods Cross, Utah to Las Vegas, Nevada (the “UNEV Pipeline”), product terminals near Cedar City, Utah and Las Vegas, Nevada and related assets; and a 25% 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 970 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 417-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 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 1,200,000 barrels;
•
on-site refined and intermediate product tankage at HFC’s Tulsa, Cheyenne and El Dorado refineries having an aggregate storage capacity of approximately 8,400,000 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 490,000 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.

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.
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 $25 million.

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2011 Acquisition
Legacy Frontier Tankage and Terminal Transaction
On November 9, 2011, we acquired from HFC certain tankage, loading rack and crude receiving assets located at HFC’s El Dorado and Cheyenne refineries. We paid non-cash consideration consisting of promissory notes with an aggregate principal amount of $150 million and 7,615,230 of our common units. In connection with the transaction, we entered into 15-year throughput agreements with HFC containing minimum annual revenue commitments to us of $48.3 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. Following the July 1, 2013 PPI adjustment, HFC's minimum annualized payments to us under these agreements increased by $4.7 million to $225.5 million.
If HFC fails to meet its minimum volume commitments under the agreements in any quarter, it will be required to pay us in cash the amount of any shortfall by the last day of the month following the end of the quarter. Under certain of the agreements, a shortfall payment may be applied as a credit in the following four quarters after minimum obligations are met.
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, 2013, these agreements with Alon will result in minimum annualized payments to us of $31.8 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, currently $2.3 million, for the provision by HFC or its affiliates of various general and administrative services to us. This fee includes expenses incurred by HFC and its affiliates 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 and its affiliates 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.

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CAPITAL REQUIREMENTS

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

Each year the HLS board of directors approves our annual capital budget, which specifies capital projects that our management is authorized to undertake. Additionally, at times when conditions warrant or as new opportunities arise, additional projects may be approved. The funds allocated for a particular capital project may be expended over a period in excess of a year, depending on the time required to complete the project. Therefore, our planned capital expenditures for a given year consist of expenditures approved for capital projects included in the current year's capital budget as well as, in certain cases, expenditures approved for capital projects in capital budgets for prior years. The 2014 capital budget is comprised of $7.3 million for maintenance capital expenditures and $26.2 million for expansion capital expenditures. We expect to spend approximately $52 million in cash for capital projects approved in 2014 plus those approved in prior years but not yet completed, including the expansion of our crude oil transportation system in southeastern New Mexico and the UNEV project discussed below. In addition to our capital budget, we may spend funds periodically to perform capital upgrades to our assets where a customer reimburses us for such costs. These reimbursements would be required under contractual agreements, and the upgrades would generally benefit the customer over the remaining life of such agreements.

We are proceeding with the expansion of our crude oil transportation system in southeastern New Mexico in response to increased crude oil production in the area.  The expansion should provide shippers with additional pipeline takeaway capacity to either common carrier pipeline stations for transportation to major crude oil markets or to HFC's New Mexico refining facilities. To complete the project, we are converting an existing refined products pipeline to crude oil service, constructing several new pipeline segments, expanding an existing pipeline, and building new truck unloading stations and crude storage capacity.  Excluding the value of the existing pipeline to be converted, total capital expenditures are expected to be between $45 million and $50 million.  We expect that the increase over the original budget range of $35 million to $40 million will be recovered from HFC over a five year period through an additional fee on shipped volumes. We estimate the project will provide increased capacity of up to 100,000 barrels per day ("bpd") across the system and anticipate it will be in full service no later than August 2014.  

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

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

We expect that our currently planned sustaining and maintenance capital expenditures, as well as expenditures for acquisitions and capital development projects will be funded with existing cash generated by operations, the sale of additional limited partner common units, the issuance of debt securities and advances under our $650 million senior secured revolving credit facility expiring in November 2018 (the "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.

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SAFETY AND MAINTENANCE
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 code or regulation. 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 conduct all cathodic protection work in accordance with National Association of Corrosion Engineers standards. We regularly monitor, test and record the effectiveness of these corrosion-inhibiting systems.
We monitor the structural integrity of selected 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 ensure that the pipelines that have the greatest risk potential receive the highest priority in being scheduled for inspections or pressure tests for integrity. Our inspection process complies with all Department of Transportation (“DOT”) and Code of Federal Regulations (“CFR”) 49 CFR Part 195 requirements.
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, state, and local laws; the regulations and standards prescribed by the American Petroleum Institute, the DOT; 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.

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

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, 2013, we have an accrual of $3.6 million that relates to environmental clean-up projects

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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.
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, nevertheless, 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 257 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.


Item 1A.
Risk Factors
Investing in us involves a degree of risk, including the risks described below. 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 be affected also by economic, financial, competitive, and regulatory factors that are beyond our control. Because the cash we generate from operations will fluctuate from quarter to quarter, we may not be able to pay quarterly distributions at the current level for each quarter or to increase our quarterly distributions in the future.

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, 2013, HFC accounted for 77% of the revenues of our petroleum product and crude pipelines and 91% 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 curtailing of production at the Navajo refinery could, by reducing throughput in our pipelines and terminals, result in our realizing materially lower levels of revenues and cash flow for the duration of the shutdown. For the year ended December 31, 2013, production from the Navajo refinery accounted for 81% of the throughput volumes transported by our refined product and crude pipelines. The Navajo refinery also received 100% 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;

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•
operational problems such as catastrophic events at the refinery, labor difficulties or environmental proceedings or other litigation that compel the cessation 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 magnitude of 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, 2013, Alon accounted for 11% 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.
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 magnitude of 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.
 
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.

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As of December 31, 2013, the principal amount of our total outstanding debt was $813.0 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 indentures for our 8.25% senior notes due 2018 and our 6.50% senior notes due 2020 (collectively, the “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 prevailing 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 impair materially 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 assure you 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 2015 and $171 million prior to 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. Moreover, without adequate funding, we may be unable to execute our growth strategy, complete future acquisitions or construction projects, take advantage of other business opportunities or respond to competitive pressures, any of which 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 or if our assumptions concerning population growth are inaccurate.

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

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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. Our inability to execute our growth strategy may materially, adversely affect our ability to maintain or pay higher distributions in the future.

Our growth strategy is also dependent 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 and the willingness and ability of HFC to capture a share of additional demand in its existing markets and to identify and penetrate new markets in the Southwestern, Rocky Mountain and Mid-Continent regions of the United States. If our assumptions about growth in 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.

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.

Mergers among our existing customers could provide strong economic incentives for the combined entities to utilize 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 have agreed to indemnify us, subject to certain limitations, for (1) certain pre-closing environmental liabilities discovered within specified time periods after the date of the applicable acquisition, (2) certain matters arising from the pre-closing ownership and operation of assets, and (3) ongoing remediation related to the assets. Our 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

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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 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 current 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.

Meeting the requirements of evolving environmental, health and safety laws and regulations, including those related to climate change, could 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, HFC and Alon 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. Future developments in federal laws and regulations governing environmental, health and safety and energy matters are especially difficult to predict.


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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. 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.

The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 increases maximum penalties for safety violations, establishes additional safety requirements for newly constructed pipelines, and requires studies of certain safety issues and potentially the adoption of new regulatory requirements for existing pipelines. In addition, the Pipeline and Hazardous Materials Safety Administration of the U.S. Department of Transportation has published an advanced notice of proposed rulemaking to solicit comments on the need for changes to its safety regulations, including whether to revise the integrity management requirements and add new regulations governing the safety of gathering lines. In addition, states have adopted regulations, similar to existing PHMSA regulations, for intrastate gathering and transmission lines. Such legislative and regulatory changes could have a material effect on our operations through more stringent and comprehensive safety regulations and higher penalties for the violation of those regulations.

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, there can be no assurance that a system failure or data security breach will not 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 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.

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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 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 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 equipment or life 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. With 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 those considered to be sudden and accidental. Our business interruption insurance covers only certain lost revenues arising from physical damage to our facilities and HFC and Alon 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 insure the quality and purity of the products loaded at our loading racks. If our quality control measures were to 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.

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

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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. If the FERC's petroleum pipeline rate-making methodology changes, the new methodology could result in tariffs that generate lower revenues and cash flow. 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. In addition, changes in the index might not be large enough to fully reflect actual increases in our costs. The FERC's 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 as far back as 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. These agreements do not prevent other current or future shippers from challenging 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 not known at this time. 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 may affect our operations in unpredictable ways, including disruptions of crude oil supplies and markets for refined products, and the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror.

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 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 credit ratings and risk profile, and that of our general partner, 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

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access capital markets at attractive rates, and could result in an increase in our borrowing costs, a reduced level of capital expenditures and an impact on 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 of any future acquisitions 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 the acquisitions we recently completed or as a result of 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 affected materially and adversely.

Delays or cost increases related to capital spending programs involving construction of new facilities (or improvements and repairs to our existing facilities) could affect adversely 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.

We do not own all of the land on which our pipeline systems and facilities are located. Our operations could be disrupted if we were to lose or were unable to renew existing rights-of-way.

We do not own all of the land on which our pipeline systems and facilities are located, and we are, therefore, subject to the risk of increased costs to maintain necessary land use. We obtain the right to construct and operate pipelines on land owned by third parties and government agencies for specified periods. If we were to lose these rights through an inability to renew right-of-way contracts or otherwise, we may be required to relocate our pipelines and our business could be adversely affected. Additionally, it may become more expensive for us to obtain new rights-of-way or to renew existing rights-of-way. If the cost of obtaining new

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rights-of-way or renewing existing rights-of-way increases, it may adversely affect our operations and 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 on behalf of HLS discontinue employment with HFC, 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 HLS's labor force 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, 2013, approximately 16% of HFC's employees dedicated to providing services for us on behalf of HLS were represented by labor unions under collective bargaining agreements with various expiration dates. We 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 strike or work stoppage in the future, 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 Holly Logistic Services, L.L.C., 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;
•
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.


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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 currently obligated to pay HFC an administrative fee of $2.3 million per year for the provision by HFC or its affiliates of various general and administrative services for our benefit. We can provide no 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 properly 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 Holly Logistic Services, L.L.C. 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, for 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, for 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 our general partner's general partner and have no right to elect our general partner or the board of directors of our general partner's general partner on an annual or other continuing basis. The board of directors of our general partner's general partner is chosen by the sole member of our general partner's general partner. Furthermore, 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 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 or to acquire information about our operations, as well as other provisions limiting the unitholders' ability to 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 taken by the board of directors and officers.


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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;
•
because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;
•
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 among us, HFC and our general partner, 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.

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, but not the obligation, which it may assign to any of its affiliates or to us, 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.


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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, as a result of legislative changes, 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. Based upon our current operations, we believe we satisfy the qualifying income requirement. Failing to meet the qualifying income requirement 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%. 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.

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, 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

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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.

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

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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 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.

- 25 -

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 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.
 
 
Years Ended December 31,
 
 
2013
 
2012
 
2011
 
2010
 
2009
Volumes transported for (bpd):
 
 
 
 
 
 
 
 
 
 
HFC
 
397,359

 
405,718

 
345,990

 
324,382

 
295,039

Third parties(1)
 
63,337

 
63,152

 
52,361

 
38,910

 
43,709

Total
 
460,696

 
468,870

 
398,351

 
363,292

 
338,748

Total barrels in thousands (“mbbls”)(1)
 
168,154

 
171,606

 
145,398

 
132,602

 
123,643

 
(1)
We sold our 70% interest in Rio Grande on December 1, 2009, therefore the Rio Grande volumes have been excluded.

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. 

- 26 -

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

 
417

 
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

 
96,000

 
Tulsa, OK(5)
 
8/10/12

 
7

 
    

(5) 
Crude Pipelines:
 
 
 
 
 
 
 
Lovington / Artesia, New Mexico
 
Various

 
861

 
31,000

 
Roadrunner Pipeline
 
16

 
69

 
62,400

 
Beeson Pipeline
 
8

 
41

 
35,000

 
 
(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.

HFC shipped an aggregate of 63% of the petroleum products transported on our refined product pipelines and 100% of the petroleum products transported on our intermediate pipelines and crude oil pipelines in 2013. These pipelines transported 84% of the light refined products produced by HFC’s Navajo refinery in 2013.

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.


- 27 -

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 $558,000 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. Our Bloomfield terminal 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.

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 417-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.


- 28 -

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. 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 850 miles of 4-inch, 6-inch and 8-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.

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.

Beeson Pipeline
The Beeson crude oil pipeline delivers crude oil to the Navajo refinery Lovington facility. 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

- 29 -

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,
 
 
2013
 
2012
 
2011
 
2010
 
2009
Refined products terminalled for (bpd):
 
 
 
 
 
 
 
 
 
 
HFC
 
255,108

 
271,549

 
193,645

 
178,903

 
114,431

Third parties
 
63,791

 
53,456

 
44,454

 
39,568

 
42,206

Total
 
318,899

 
325,005

 
238,099

 
218,471

 
156,637

Total (mbbls)
 
116,398

 
118,952

 
86,906

 
79,742

 
57,173


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
 
251,000

 
9
 
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
 
2,734,000

 
 
 
 
 
 
 
(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 87% of the volumes at this terminal. We also receive product from the Big Spring refinery that accounted for 13% of the volumes at this terminal in 2013. 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”).


- 30 -

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.

Mountain Home Terminal
We receive jet fuel from third parties at this terminal that is transported on Chevron’s 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 Chevron common carrier pipeline. The Spokane terminal also is supplied by Chevron and Yellowstone pipelines and 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 2013. 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 2013. 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 only 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 2013. 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.


- 31 -

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 racks that load refined products and lube oil produced at the refinery onto rail car and a truck rack that loads lube oil onto 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.

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 9,600,000 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
 
3,412,000

 
Crude oil and refined product
 
55
Cheyenne, WY
 
1,850,000

 
Refined and intermediate product
 
56
El Dorado, KS
 
3,639,000

 
Refined and intermediate product
 
84
Total
 
9,580,000

 
 
 
 


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.



- 32 -

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.




- 33 -

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
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

2012
 
 
 
 
 
 
 
 
Fourth quarter
 
$
34.41

 
$
30.19

 
$
0.4700

 
6,938,000

Third quarter
 
$
36.98

 
$
28.56

 
$
0.4630

 
6,420,200

Second quarter
 
$
31.44

 
$
26.12

 
$
0.4550

 
5,298,000

First quarter
 
$
31.88

 
$
26.64

 
$
0.4480

 
6,704,400

 
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.
The cash distribution for the fourth quarter of 2013 was declared on January 23, 2014 and is payable on February 14, 2014 to all unitholders of record on February 4, 2014.

As of February 11, 2014, we had approximately 16,982 common unitholders, including beneficial owners of common units held in street name.

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.

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:

- 34 -

 
 
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%


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 2013
 
—

 
$
—

 
—

 
$
—

November 2013
 
—

 
$
—

 
—

 
$
—

December 2013
 
61,532

 
$
31.43

 
—

 
$
—

Total for October to December 2013
 
61,532

 
 
 
—

 
 

The units reported represent (a) purchases of 50,000 common units in the open market for delivery to the 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; and (b) the delivery of 11,532 common units (which units were previously issued to certain officers and other employees pursuant to restricted unit awards at the time of grant) by such officers and employees to provide funds for the payment of payroll and income taxes due at vesting in the case of officers and employees who did not elect to satisfy such taxes by other means.


- 35 -

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,
 
 
2013
 
2012
 
2011
 
2010
 
2009
 
 
(In thousands, except per unit data)
Statement of Income Data:
 
 
 
 
 
 
 
 
 
 
Revenues
 
$
305,182

 
$
292,560

 
$
214,268

 
$
182,137

 
$
146,612

Operating costs and expenses
 
 
 
 
 
 
 
 
 
 
Operations (exclusive of depreciation and amortization)
 
99,444

 
89,242

 
64,521

 
54,946

 
44,668

Depreciation and amortization
 
65,423

 
57,461

 
36,958

 
31,363

 
27,982

General and administrative
 
11,749

 
7,594

 
6,576

 
7,719

 
7,586

 
 
176,616

 
154,297

 
108,055

 
94,028

 
80,236

Operating income
 
128,566

 
138,263

 
106,213

 
88,109

 
66,376

Equity in earnings of SLC Pipeline
 
2,826

 
3,364

 
2,552

 
2,393

 
1,919

SLC Pipeline acquisition costs
 
—

 
—

 
—

 
—

 
(2,500
)
Interest income
 
161

 
—

 
—

 
7

 
11

Interest expense
 
(47,010
)
 
(47,182
)
 
(35,959
)
 
(34,001
)
 
(21,501
)
Loss on early extinguishment of debt
 
—

 
(2,979
)
 
—

 
—

 
—

Gain on sale of assets
 
1,810

 
—

 
—

 
—

 
—

Other income
 
61

 
10

 
17

 
17

 
67

 
 
(42,152
)
 
(46,787
)
 
(33,390
)
 
(31,584
)
 
(22,004
)
Income from continuing operations before income taxes
 
86,414

 
91,476

 
72,823

 
56,525

 
44,372

State income tax
 
(333
)
 
(371
)
 
(234
)
 
(296
)
 
(20
)
Income from continuing operations
 
86,081

 
91,105

 
72,589

 
56,229

 
44,352

Add net loss attributable to Predecessor
 
—

 
4,200

 
6,351

 
70

 
1,411

Noncontrolling interest
 
(6,632
)
 
(1,153
)
 
859

 
24

 
471

Income from continuing operations attributable to Holly Energy Partners
 
79,449

 
94,152

 
79,799

 
56,323

 
46,234

Income from discontinued operations, net of noncontrolling interest(1)
 
—

 
—

 
—

 
—

 
19,780

Net income attributable to Holly Energy Partners
 
79,449

 
94,152

 
79,799

 
56,323

 
66,014

Less general partner interest in net income, including incentive distributions(2)
 
27,523

 
22,450

 
16,806

 
12,084

 
7,947

Limited partners’ interest in net income
 
$
51,926

 
$
71,702

 
$
62,993

 
$
44,239

 
$
58,067

Limited partners’ per unit interest in net income – basic and diluted(2)
 
$
0.88

 
$
1.29

 
$
1.38

 
$
1.00

 
$
1.59

Distributions per limited partner unit
 
$
1.96

 
$
1.84

 
$
1.74

 
$
1.66

 
$
1.58

 
 
 
 
 
 
 
 
 
 
 
Other Financial Data:
 
 
 
 
 
 
 
 
 
 
Cash flows from operating activities
 
$
183,080

 
$
161,149

 
$
98,907

 
$
104,736

 
$
68,503

Cash flows from investing activities
 
$
(49,070
)
 
$
(42,599
)
 
$
(206,174
)
 
$
(142,051
)
 
$
(198,684
)
Cash flows from financing activities
 
$
(132,895
)
 
$
(119,682
)
 
$
105,584

 
$
35,856

 
$
131,023

EBITDA(3)
 
$
192,054

 
$
194,242

 
$
149,766

 
$
122,089

 
$
100,707

Distributable cash flow(4)
 
$
146,579

 
$
153,125

 
$
100,295

 
$
91,054

 
$
72,213

Maintenance capital expenditures(5)
 
$
8,683

 
$
5,649

 
$
5,415

 
$
4,487

 
$
3,595

Expansion capital expenditures
 
43,418

 
37,212

 
200,894

 
137,442

 
201,454

Total capital expenditures
 
$
52,101

 
$
42,861

 
$
206,309

 
$
141,929

 
$
205,049

 
 
 
 
 
 
 
 
 
 
 
Balance Sheet Data (at period end):
 
 
 
 
 
 
 
 
 
 
Net property, plant and equipment
 
$
957,814

 
$
960,535

 
$
960,499

 
$
683,793

 
$
553,233

Total assets
 
$
1,382,508

 
$
1,394,110

 
$
1,399,196

 
$
913,263

 
$
779,035

Long-term debt(6)
 
$
807,630

 
$
864,674

 
$
605,888

 
$
491,648

 
$
390,827

Total liabilities
 
$
915,574

 
$
941,254

 
$
661,518

 
$
548,402

 
$
425,633

Total equity(7)
 
$
466,934

 
$
452,856

 
$
737,678

 
$
364,861

 
$
353,402

 


- 36 -

(1)
On December 1, 2009, we sold our 70% interest in Rio Grande. Results of operations of Rio Grande and the $14.5 million gain on the sale are presented in discontinued operations.

(2)
Net income is allocated between limited partners and the general partner interest in accordance with the provisions of the partnership agreement. Net income allocated to the general partner includes incentive distributions declared subsequent to quarter end. Net income attributable to the limited partners is divided by the weighted average limited partner units outstanding in computing the limited partners’ per unit interest in net income.

(3)
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,
 
 
2013
 
2012
 
2011
 
2010
 
2009
 
 
(In thousands)
Income from continuing operations attributable to HEP
 
$
79,449

 
$
94,152

 
$
79,799

 
$
56,323

 
$
46,234

Add (subtract):
 
 
 
 
 
 
 
 
 
 
Interest expense
 
44,041

 
40,141

 
34,706

 
30,453

 
20,620

Interest income
 
(161
)
 
—

 
 
 
(7
)
 
(11
)
Amortization of discount and deferred debt issuance costs
 
2,120

 
1,946

 
1,212

 
1,008

 
706

Loss on early extinguishment of debt
 
—

 
2,979

 
 
 
—

 
—

Increase in interest expense – non-cash charges attributable to interest rate swaps and swap settlement amortization
 
849

 
5,095

 
41

 
2,540

 
175

State income tax
 
333

 
371

 
234

 
296

 
20

Depreciation and amortization
 
65,423

 
57,461

 
36,958

 
31,363

 
27,982

Predecessor depreciation and amortization
 
—

 
(7,903
)
 
(3,184
)
 
113

 
(1,268
)
EBITDA from discontinued operations (excludes gain on sale of Rio Grande in 2009)
 
—

 
—

 
—

 
—

 
6,249

EBITDA
 
$
192,054

 
$
194,242

 
$
149,766

 
$
122,089

 
$
100,707



(4)
Distributable cash flow is not a calculation based upon GAAP. However, the amounts included in the calculation are derived from amounts presented in our consolidated financial statements, with the general exceptions of a billed crude revenue settlement, 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.


- 37 -

Set forth below is our calculation of distributable cash flow. 
 
 
Years Ended December 31,
 
 
2013
 
2012
 
2011
 
2010
 
2009
 
 
(In thousands)
Income from continuing operations attributable to HEP
 
$
79,449

 
$
94,152

 
$
79,799

 
$
56,323

 
$
46,234

Add (subtract):
 
 
 
 
 
 
 
 
 
 
Depreciation and amortization
 
65,423

 
57,461

 
36,958

 
31,363

 
27,982

Predecessor depreciation and amortization
 
—

 
(7,903
)
 
(3,184
)
 
113

 
(1,268
)
Amortization of discount and deferred debt issuance costs
 
2,120

 
1,946

 
1,212

 
1,008

 
706

Increase in interest expense – non-cash charges attributable to interest rate swaps and swap settlement amortization
 
849

 
5,095

 
41

 
2,540

 
175

Loss on early extinguishment of debt
 
—

 
2,979

 
—

 
—

 
—

Increase (decrease) in deferred revenue related to minimum revenue commitments
 
3,686

 
462

 
(6,405
)
 
2,035

 
(7,256
)
Maintenance capital expenditures (5)
 
(8,683
)
 
(5,649
)
 
(5,415
)
 
(4,487
)
 
(3,595
)
Crude revenue settlement
 
918

 
3,670

 
(4,588
)
 
—

 
—

Distributable cash flow from discontinued operations (excludes gain on sale of Rio Grande in 2009)
 
—

 
—

 
 
 
—

 
6,183

SLC Pipeline acquisition costs (8)
 
—

 
—

 
 
 
—

 
2,500

Other non-cash adjustments
 
2,817

 
912

 
1,877

 
2,159

 
552

Distributable cash flow
 
$
146,579

 
$
153,125

 
$
100,295

 
$
91,054

 
$
72,213

 

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

(6)
Includes $363 million, $421 million, $200 million, $159 million and $206 million in Credit Agreement advances that were classified as long-term debt at December 31, 2013, 2012, 2011, 2010 and 2009, respectively.

(7)
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.

(8)
Under accounting standards, we were required to expense rather than capitalize certain acquisition costs of $2.5 million associated with our joint venture agreement with Plains that closed in March 2009. These costs directly relate to our interest in the new joint venture pipeline and are similar to expansion capital expenditures; accordingly, we have added back these costs to arrive at distributable cash flow.


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.


- 38 -

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, 2013, 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.

We believe the continuing growth of crude production in the Permian Basin and throughout the Mid-Continent and favorable refining economics should support high utilization rates for the refineries we serve, which in turn will support volumes in our product pipelines, crude gathering system and terminals.

UNEV Pipeline Interest Acquisition
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. Also under the terms of the transaction, we issued to HFC a Class B unit comprising a noncontrolling equity interest in a wholly-owned subsidiary subject to redemption to the extent that HFC is entitled to a 50% interest in our share of annual UNEV earnings before interest, income taxes, depreciation, and amortization above $30 million beginning July 1, 2016 and ending in June 2032, subject to certain limitations. 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 $25 million.

Legacy Frontier Pipeline and Tankage Asset Transaction
On November 9, 2011, we acquired from HFC certain tankage, loading rack and crude receiving assets located at HFC’s El Dorado and Cheyenne refineries. We paid non-cash consideration consisting of promissory notes with an aggregate principal amount of $150 million and 7,615,230 of our common units. In connection with the transaction, we entered into 15-year throughput agreements with HFC containing minimum annual revenue commitments to us of $48.3 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, 2013, these agreements with HFC will result in minimum annualized payments to us of $225.5 million.

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

- 39 -

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, 2013, these agreements with Alon will result in minimum annualized payments to us of $31.8 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, currently $2.3 million, for the provision by HFC or its affiliates 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 and its affiliates for direct expenses they incur on our behalf.



- 40 -

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, 2013, 2012 and 2011.
 
 
Year 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
 
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 loss (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
)

- 41 -

 
 
Years Ended December 31,
 
Change from
 
 
2012
 
2011
 
2011
 
 
(In thousands, except per unit data)
Revenues
 
 
 
 
 
 
Pipelines:
 
 
 
 
 
 
Affiliates—refined product pipelines
 
$
67,682

 
$
46,649

 
$
21,033

Affiliates—intermediate pipelines
 
28,540

 
21,948

 
6,592

Affiliates—crude pipelines
 
45,888

 
47,542

 
(1,654
)
 
 
142,110

 
116,139

 
25,971

Third parties—refined product pipelines
 
37,521

 
38,216

 
(695
)
 
 
179,631

 
154,355

 
25,276

Terminals, tanks and loading racks:
 
 
 
 
 
 
Affiliates
 
103,472

 
52,122

 
51,350

Third parties
 
9,457

 
7,791

 
1,666

 
 
112,929

 
59,913

 
53,016

Total revenues
 
292,560

 
214,268

 
78,292

Operating costs and expenses
 
 
 
 
 
 
Operations (exclusive of depreciation and amortization)
 
89,242

 
64,521

 
24,721

Depreciation and amortization
 
57,461

 
36,958

 
20,503

General and administrative
 
7,594

 
6,576

 
1,018

 
 
154,297

 
108,055

 
46,242

Operating income
 
138,263

 
106,213

 
32,050

Equity in earnings of SLC Pipeline
 
3,364

 
2,552

 
812

Interest expense, including amortization
 
(47,182
)
 
(35,959
)
 
(11,223
)
Other expense
 
10

 
17

 
(7
)
 
 
(46,787
)
 
(33,390
)
 
(13,397
)
Income before income taxes
 
91,476

 
72,823

 
18,653

State income tax
 
(371
)
 
(234
)
 
(137
)
Net income
 
91,105

 
72,589

 
18,516

Allocation of net loss attributable to Predecessors
 
4,200

 
6,351

 
(2,151
)
Allocation of net loss attributable to noncontrolling interests
 
(1,153
)
 
859

 
(2,012
)
Net income attributable to Holly Energy Partners
 
94,152

 
79,799

 
14,353

General partner interest in net income, including incentive distributions (1)
 
(22,450
)
 
(16,806
)
 
(5,644
)
Limited partners’ interest in net income
 
$
71,702

 
$
62,993

 
$
8,709

Limited partners’ earnings per unit—basic and diluted (1)
 
$
1.29

 
$
1.38

 
$
(0.09
)
Weighted average limited partners’ units outstanding
 
55,696

 
45,672

 
10,024

EBITDA (2)
 
$
194,242

 
$
149,766

 
$
44,476

Distributable cash flow (3)
 
$
153,125

 
$
100,295

 
$
52,830

 
 
 
 
 
 
 
Volumes (bpd)
 
 
 
 
 
 
Pipelines:
 
 
 
 
 
 
Affiliates—refined product pipelines
 
107,509

 
90,782

 
16,727

Affiliates—intermediate pipelines
 
127,169

 
93,419

 
33,750

Affiliates—crude pipelines
 
171,040

 
161,789

 
9,251

 
 
405,718

 
345,990

 
59,728

Third parties—refined product pipelines
 
63,152

 
52,361

 
10,791

 
 
468,870

 
398,351

 
70,519

Terminals and loading racks:
 
 
 
 
 

Affiliates
 
271,549

 
193,645

 
77,904

Third parties
 
53,456

 
44,454

 
9,002

 
 
325,005

 
238,099

 
86,906

Total for pipelines and terminal assets (bpd)
 
793,875

 
636,450

 
157,425



- 42 -

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

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 thousand barrels per day (“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.

- 43 -


Revenues from our crude pipelines were $48.7 million, an increase of $2.9 million on shipments averaging of 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 increased 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.

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 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.

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


Results of Operations—Year Ended December 31, 2012 Compared with Year Ended December 31, 2011

Summary
Net income attributable to HEP for the year ended December 31, 2012 was $94.2 million, a $14.4 million increase compared to the year ended December 31, 2011. This increase in earnings was due principally to increased pipeline shipments, earnings attributable to our November 2011 acquisition and annual tariff increases. These factors were offset partially by increased operating costs and expenses, higher interest expense and a loss on the early extinguishment of debt. Although net income attributable to HEP increased, limited partners' per unit interest in earnings decreased from $1.38 per unit in 2011 to $1.29 per unit in 2012. The principal factors that caused the decrease in limited partners' per unit interest, relative to the overall net income attributable to HEP increase, were higher incentive distributions to the general partner and the UNEV acquisition not yet being accretive to earnings, although it was accretive to distributable cash flow.


- 44 -

Revenues for the year ended December 31, 2012 include the recognition of $4.0 million of prior shortfalls billed to shippers in 2011. Deficiency payments of $7.8 million associated with certain guaranteed shipping contracts were deferred during the year ended December 31, 2012.

Revenues
Total revenues for the year ended December 31, 2012 were $292.6 million, a $78.3 million increase compared to the year ended December 31, 2011. This was due principally to increased pipeline shipments, revenues attributable to our recent acquisitions and the effect of annual tariff increases partially offset by a $4.6 million decrease in previously deferred revenue realized under our guaranteed shipping contracts. Overall pipeline volumes were up 18% compared to the year ended December 31, 2011.

Revenues from our refined product pipelines were $105.2 million, an increase of $20.3 million compared to the year ended December 31, 2011. This included $15.0 million in revenues attributable to UNEV pipeline throughputs which commenced initial start-up activities in December 2011 partially offset by a $5.4 million decrease in previously deferred revenue realized under our guaranteed shipping contracts. Volumes shipped on our refined product pipelines averaged 170.7 thousand barrels per day compared to 143.1 mbpd for 2011.

Revenues from our intermediate pipelines were $28.5 million, an increase of $6.6 million compared to the year ended December 31, 2011. This included $3.4 million of increased revenues attributable to the Tulsa interconnect pipelines, which were placed in service in September 2011, and a $0.8 million increase in previously deferred revenue realized under our guaranteed shipping contracts. Volumes shipped on our intermediate pipelines averaged 127.2 mbpd compared to 93.4 mbpd for 2011.

Revenues from our crude pipelines were $45.9 million, a decrease of $1.7 million compared to the year ended December 31, 2011. Revenues for the year ended December 31, 2011 included $5.5 million attributable to a crude pipeline revenue settlement with HFC. Volumes shipped on our crude pipelines increased to an average of 171.0 mbpd compared to 161.8 mbpd for 2011.

Revenues from terminal, tankage and loading rack fees were $112.9 million, an increase of $53.0 million compared to year ended December 31, 2011. This increase was due principally to $45.4 million of increased revenues attributable to our terminal, tankage and loading racks serving HFC's El Dorado and Cheyenne refineries. Refined products terminalled in our facilities increased to an average of 325.0 mbpd compared to 238.1 mbpd for 2011.

Operations Expense
Operations expense for the year ended December 31, 2012 increased by $24.7 million compared to the year ended December 31, 2011. This increase was due principally to increased operating costs of $9.6 million and $5.2 million attributable to the 2012 acquired UNEV pipeline and assets serving HFC's El Dorado and Cheyenne refineries, respectively, higher throughput levels as well as year-over-year increases in property taxes, maintenance service and payroll costs.

Depreciation and Amortization
Depreciation and amortization for the year ended December 31, 2012 increased by $20.5 million compared to the year ended December 31, 2011. This increase was due principally to depreciation attributable to our recent acquisitions from HFC and capital projects. Also contributing were increases in asset abandonment charges related to tankage no longer in service.

General and Administrative
General and administrative costs for the year ended December 31, 2012 increased by $1.0 million compared to the year ended December 31, 2011 due to timing of professional fees related to recent acquisitions.

Equity in Earnings of SLC Pipeline
Our equity in earnings of the SLC Pipeline was $3.4 million and $2.6 million for the years ended December 31, 2012 and 2011.

Interest Expense
Interest expense for the year ended December 31, 2012 totaled $47.2 million, an increase of $11.2 million compared to the year ended December 31, 2011. This increase reflected interest on a year-over-year increase in debt levels. Our aggregate effective interest rate was 6.5% and 6.7% for the years ended December 31, 2012 and 2011, respectively.

Loss on Early Extinguishment of Debt
We recognized a charge of $3.0 million upon the early extinguishment of our 6.25% senior notes for the 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.



- 45 -

State Income Tax
We recorded state income tax expense of $371,000 and $234,000 for the years ended December 31, 2012 and 2011 which was solely attributable to the Texas margin tax.


LIQUIDITY AND CAPITAL RESOURCES

Overview
In November 2013, we amended the Credit Agreement increasing the size of the credit facility from $550 million to $650 million. Our $650 million senior secured revolving credit facility 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, 2013, we received advances totaling $310.6 million and repaid $368.6 million, resulting in net reduction of $58.0 million under the Credit Agreement and an outstanding balance of $363.0 million at December 31, 2013.
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 2013, we paid regular quarterly cash distributions of $0.4700, $0.4775, $0.4850 and $0.4925, respectively, on all units in an aggregate amount of $139.5 million. Included in this aggregate amount were $24.6 million of incentive distribution payments to the general partner.

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

Cash and cash equivalents increased by $1.1 million during the year ended December 31, 2013. The cash flows provided by operating activities of $183.1 million were greater than the cash flows used for financing and investing activities of $132.9 million and $49.1 million, respectively. Working capital decreased by $18.4 million to a deficit of $6.6 million at December 31, 2013 from $11.8 million at December 31, 2012.

Cash Flows—Operating Activities
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.

Our major shippers are obligated to make deficiency payments to us if they do not meet their minimum volume shipping obligations. Under certain agreements with these shippers, they have the right to recapture these amounts if future volumes exceed minimum levels. We billed $7.8 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 is included as deferred revenue on our balance sheet at December 31, 2013 related to shortfalls billed during the year ended December 31, 2013.


- 46 -

Year Ended December 31, 2012 Compared with Year Ended December 31, 2011
Cash flows from operating activities increased by $62.4 million from $99.0 million for the year ended December 31, 2011 to $161.4 million for the year ended December 31, 2012. This increase is due principally to $63.0 million in additional cash collections from our customers, partially offset by payments attributable to increased operating expenses.

We billed $4.6 million during the year ended December 31, 2011 related to shortfalls that subsequently expired without recapture and were recognized as revenue during the year ended December 31, 2012. Another $7.8 million was included in our accounts receivable at December 31, 2012 related to shortfalls that occurred during the year ended December 31, 2012.

Cash Flows—Investing Activities
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 $42.6 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.

Year Ended December 31, 2012 Compared with Year Ended December 31, 2011
Cash flows used for investing activities decreased by $163.4 million from $206.3 million for the year ended December 31, 2011 to $42.9 million for the year ended December 31, 2012. During the years ended December 31, 2012 and 2011, we invested $42.9 million and $206.3 million in additions to properties and equipment, respectively. The decrease is attributable to lower expenditures in 2012 as a result of the completion of the UNEV pipeline in 2011. Distributions in excess of equity in earnings of the SLC Pipeline was $0.3 million and $0.1 million for the years ended December 31, 2012 and 2011.

Cash Flows—Financing Activities
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 distributed $3.1 million to the UNEV noncontrolling interest joint venture partner 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 UNEV's joint venture partners, 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.

Year Ended December 31, 2012 Compared with Year Ended December 31, 2011
Cash flows used for financing activities were $119.7 million for the year ended December 31, 2012, as discussed above, compared to cash provided of $105.6 million for the year ended December 31, 2011, a decrease of $225.3 million. During the year ended December 31, 2011, we received $118.0 million and repaid $77.0 million in advances under the Credit Agreement, received proceeds of $75.8 million from the issuance of our common units, and repaid $77.1 million of our promissory notes. Additionally, we paid $91.5 million in regular quarterly cash distributions to our general and limited partners, we received $156.5 million from UNEV's joint venture partners, received $5.9 million from our general partner, incurred $3.2 million in financing costs upon the issuance of the 8.25% senior notes, and paid $1.6 million for the purchase of common units for recipients of our incentive grants.


- 47 -

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

Each year the HLS board of directors approves our annual capital budget, which specifies capital projects that our management is authorized to undertake. Additionally, at times when conditions warrant or as new opportunities arise, additional projects may be approved. The funds allocated for a particular capital project may be expended over a period in excess of a year, depending on the time required to complete the project. Therefore, our planned capital expenditures for a given year consist of expenditures approved for capital projects included in the current year's capital budget as well as, in certain cases, expenditures approved for capital projects in capital budgets for prior years. The 2014 capital budget is comprised of $7.3 million for maintenance capital expenditures and $26.2 million for expansion capital expenditures. We expect to spend approximately $52 million in cash for capital projects approved in 2014 plus those approved in prior years but not yet completed, including the expansion of our crude oil transportation system in southeastern New Mexico and the UNEV project discussed below. In addition to our capital budget, we may spend funds periodically to perform capital upgrades to our assets where a customer reimburses us for such costs. These reimbursements would be required under contractual agreements, and the upgrades would generally benefit the customer over the remaining life of such agreements.

We are proceeding with the expansion of our crude oil transportation system in southeastern New Mexico in response to increased crude oil production in the area.  The expansion should provide shippers with additional pipeline takeaway capacity to either common carrier pipeline stations for transportation to major crude oil markets or to HFC's New Mexico refining facilities. To complete the project, we are converting an existing refined products pipeline to crude oil service, constructing several new pipeline segments, expanding an existing pipeline, and building new truck unloading stations and crude storage capacity.  Excluding the value of the existing pipeline to be converted, total capital expenditures are expected to be between $45 million and $50 million.  We expect that the increase over the original budget range of $35 million to $40 million will be recovered from HFC over a five year period through an additional fee on shipped volumes. We estimate the project will provide increased capacity of up to 100,000 barrels per day across the system and anticipate it will be in full service no later than August 2014.  

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

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

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


- 48 -

On July 12, 2012, we acquired HFC's 75% interest in UNEV. We paid consideration consisting of $260.0 million in cash and 2,059,800 of our common units. We paid an additional $0.9 million to HFC for a post-closing working capital adjustment. Also under the terms of the transaction, we issued to HFC a Class B unit comprising a noncontrolling equity interest in a wholly-owned subsidiary subject to redemption to the extent that HFC is entitled to a 50% interest in our share of annual UNEV earnings before interest, income taxes, depreciation, and amortization above $30 million beginning July 1, 2016 and ending in June 2032, subject to certain limitations.

Credit Agreement
On November 22, 2013, we amended our credit agreement increasing the size of the credit facility from $550.0 million to $650.0 million. 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 Holdings, L.P. (“HEP Logistics”), our general partner, and guaranteed by our material wholly-owned subsidiaries. Any recourse to HEP Logistics would be limited to the extent of its assets, which other than its investment in us, are not significant. We may prepay all loans at any time without penalty, except for payment of certain breakage and related costs.

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

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

We also have $150 million in aggregate principal amount outstanding of 8.25% senior notes maturing March 15, 2018 (the “8.25% Senior Notes”). On February 12, 2014, we announced that we will redeem all of our outstanding 8.25% Senior Notes. The redemption price will be equal to 104.125% of the principal amount for a total payment to the holders of the notes of approximately $156.2 million plus accrued interest. The redemption of the 8.25% Senior Notes is scheduled to occur on March 15, 2014. We plan to fund the redemption with borrowings under our Credit Agreement.

Our 6.5% Senior Notes and 8.25% Senior Notes (collectively, the “Senior Notes”) are unsecured and impose certain restrictive covenants which we are in compliance with currently, including limitations on our ability to incur additional indebtedness, make investments, sell assets, incur certain liens, pay distributions, enter into transactions with affiliates, and enter into mergers. At any time when the Senior Notes are rated investment grade by both Moody’s and Standard & Poor’s and no default or event of default exists, we will not be subject to many of the foregoing covenants. Additionally, we have certain redemption rights at varying premiums over face value under the Senior Notes.

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

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

- 49 -

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.

Promissory Notes
In November 2011, we issued senior unsecured promissory notes to HFC (the “Promissory Notes”) having an aggregate principal amount of $150.0 million to finance a portion of our November 9, 2011 acquisition of assets located at HFC's El Dorado and Cheyenne refineries. In December 2011, we repaid $77.1 million of outstanding principal using proceeds received in our December 2011 common unit offering and existing cash. We repaid the remaining $72.9 million balance in March 2012.

Long-term Debt
The carrying amounts of our long-term debt are as follows:
 
 
December 31,
2013
 
December 31,
2012
 
 
(In thousands)
Credit Agreement
 
$
363,000

 
$
421,000

 
 
 
 
 
6.5% Senior Notes
 
 
 
 
Principal
 
300,000

 
300,000

Unamortized discount
 
(4,073
)
 
(4,725
)
 
 
295,927

 
295,275

8.25% Senior Notes
 
 
 
 
Principal
 
150,000

 
150,000

Unamortized discount
 
(1,297
)
 
(1,601
)
 
 
148,703

 
148,399

 
 
 
 
 
Total long-term debt
 
$
807,630

 
$
864,674


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

Long-term Contractual Obligations
The following table presents our long-term contractual obligations as of December 31, 2013.
 
 
 
 
Payments Due by Period
 
 
Total
 
Less than
1 Year
 
1-3 Years
 
3-5 Years
 
Over 5
Years
 
 
(In thousands)
Long-term debt – principal
 
$
813,000

 
$
—

 
$
—

 
$
513,000

 
$
300,000

Long-term debt - interest
 
221,804

 
39,748

 
79,497

 
73,309

 
29,250

Pipeline operating lease
 
23,423

 
6,692

 
13,385

 
3,346

 
—

Right-of-way leases
 
1,184

 
182

 
344

 
296

 
362

Other
 
17,034

 
1,987

 
3,904

 
3,904

 
7,239

Total
 
$
1,076,445

 
$
48,609

 
$
97,130

 
$
593,855

 
$
336,851

Long-term debt consists of outstanding principal under the Credit Agreement and Senior Notes. Interest on the credit agreement is calculated using the rate in effect at December 31, 2013. The above table does not reflect the pending redemption of the 8.25% Senior Notes scheduled for March 2014.
The pipeline operating lease amounts above reflect the exercise of the first of three 10-year extensions, 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, 2013. 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 maintenance and utility costs that relate to our assets located at HFC’s refinery facilities.


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Impact of Inflation
Inflation in the United States has been relatively moderate in recent years and did not have a material impact on our results of operations for the years ended December 31, 2013, 2012 and 2011. Historically, the PPI has increased an average of 2.2% annually over the past 5 calendar years.

The substantial majority of our revenues are generated under long-term contracts that provide for increases in our rates and minimum revenue guarantees annually for increases in the PPI. Certain of these contracts have provisions that limit the level of annual PPI percentage rate increases. Although the recent PPI increase may not be indicative of additional increases to be realized in the future, a significant and prolonged period of high inflation could adversely affect our cash flows and results of operations if costs increase at a rate greater than the fees we charge our shippers.

Environmental Matters
Our operation of pipelines, terminals, and associated facilities in connection with the transportation and storage of refined products and crude oil is subject to stringent and complex federal, state, and local laws and regulations governing the discharge of materials into the environment, or otherwise relating to the protection of the environment. As with the industry generally, compliance with existing and anticipated laws and regulations increases our overall cost of business, including our capital costs to construct, maintain, and upgrade equipment and facilities. While these laws and regulations affect our maintenance capital expenditures and net income, we believe that they do not affect our competitive position given that the operations of our competitors are similarly affected. We believe that our operations are in substantial compliance with applicable environmental laws and regulations. However, these laws and regulations, and the interpretation or enforcement thereof, are subject to frequent change by regulatory authorities, and we are unable to predict the ongoing cost to us of complying with these laws and regulations or the future impact of these laws and regulations on our operations. Violation of environmental laws, regulations, and permits can result in the imposition of significant administrative, civil and criminal penalties, injunctions, and construction bans or delays. A major discharge of hydrocarbons or hazardous substances into the environment could, to the extent the event is not insured, subject us to substantial expense, including both the cost to comply with applicable laws and regulations and claims made by employees, neighboring landowners and other third parties for personal injury and property damage.
Under the Omnibus Agreement and certain transportation agreements and purchase agreements with HFC, HFC has agreed to indemnify us, subject to certain monetary and time limitations, for environmental noncompliance and remediation liabilities associated with certain assets transferred to us from HFC and occurring or existing prior to the date of such transfers.
We have an environmental agreement with Alon with respect to pre-closing environmental costs and liabilities relating to the pipelines and terminals acquired from Alon in 2005, under which Alon will indemnify us subject to certain monetary and time limitations.

There are environmental remediation projects that are currently in progress that relate to certain assets acquired from HFC. Certain of these projects were underway prior to our purchase and represent liabilities of HFC as the obligation for future remediation activities was retained by HFC. At December 31, 2013, we have an accrual of $3.6 million that relates to environmental clean-up projects for which we have assumed liability or for which the indemnity provided for by HFC has expired or will expire. The remaining projects, including assessment and monitoring activities, are covered under the HFC environmental indemnification discussed above and represent liabilities of HFC.


CRITICAL ACCOUNTING POLICIES

Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities as of the date of the financial statements. Actual results may differ from these estimates under different assumptions or conditions. 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 definite-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, 2013.

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.


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RISK MANAGEMENT

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

As of December 31, 2013, we have three interest rate swaps, designated as a cash flow hedge, that hedge our exposure to the cash flow risk caused by the effects of LIBOR changes on $305.0 million of Credit Agreement advances. Our first interest rate swap effectively converts $155.0 million of our LIBOR based debt to fixed rate debt having an interest rate of 0.99% plus an applicable margin of 2.00% as of December 31, 2013, which equaled an effective interest rate of 2.99%. This swap contract matures in February 2016. In August 2012, we entered into two similar interest rate swaps with identical terms which effectively convert $150.0 million of our LIBOR based debt to fixed rate debt having an interest rate of 0.74% plus an applicable margin of 2.00% as of December 31, 2013, 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, 2013, we had an outstanding principal balance on our 6.5% Senior Notes and 8.25% Senior Notes of $300 million and $150 million, respectively. A change in interest rates generally would affect the fair value of the Senior Notes, but not our earnings or cash flows. At December 31, 2013, the fair values of our 6.5% Senior Notes and 8.25% Senior Notes were $313.5 million and $158.3 million, respectively. We estimate a hypothetical 10% change in the yield-to-maturity applicable to the 6.5% Senior Notes and 8.25% Senior Notes at December 31, 2013 would result in a change of approximately $9.1 million and $3.8 million, respectively, in the fair value of the underlying notes.

For the variable rate Credit Agreement, changes in interest rates would affect cash flows, but not the fair value. At December 31, 2013, borrowings outstanding under the Credit Agreement were $363.0 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 $58.0 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.


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, 2013 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 (1992 framework). Based on this assessment, management concluded that, as of December 31, 2013, 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, 2013. That report appears on page 55.


- 53 -


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, 2013, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 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, 2013, 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, 2013 and 2012, 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, 2013, and our report dated February 24, 2014, expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Dallas, Texas
February 24, 2014



- 54 -


Index to Consolidated Financial Statements
 


- 55 -



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, 2013 and 2012, 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, 2013. 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, 2013 and 2012, and the consolidated results of its operations and its cash flows, for each of the three years in the period ended December 31, 2013, 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, 2013, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) and our report dated February 24, 2014 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Dallas, Texas
February 24, 2014



- 56 -

HOLLY ENERGY PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS  

 
 
December 31, 2013
 
December 31, 2012
 
 
(In thousands, except unit data)
ASSETS
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents
 
$
6,352

 
$
5,237

Accounts receivable:
 
 
 
 
Trade
 
5,061

 
7,126

Affiliates
 
29,675

 
31,594

 
 
34,736

 
38,720

Prepaid and other current assets
 
3,874

 
3,619

Total current assets
 
44,962

 
47,576

 
 
 
 
 
Properties and equipment, net
 
957,814

 
960,535

Transportation agreements, net
 
87,650

 
94,596

Goodwill
 
256,498

 
256,498

Investment in SLC Pipeline
 
24,741

 
25,041

Other assets
 
10,843

 
9,864

Total assets
 
$
1,382,508

 
$
1,394,110

 
 
 
 
 
LIABILITIES AND PARTNERS’ EQUITY
 
 
 
 
Current liabilities:
 
 
 
 
Accounts payable:
 
 
 
 
Trade
 
$
14,414

 
$
7,045

Affiliates
 
8,484

 
4,985

 
 
22,898

 
12,030

 
 
 
 
 
Accrued interest
 
10,239

 
10,226

Deferred revenue
 
13,981

 
8,901

Accrued property taxes
 
2,603

 
2,688

Other current liabilities
 
1,845

 
1,905

Total current liabilities
 
51,566

 
35,750

 
 
 
 
 
Long-term debt
 
807,630

 
864,674

Other long-term liabilities
 
14,585

 
15,433

Deferred revenue
 
21,669

 
11,494

 
 
 
 
 
Class B unit
 
20,124

 
13,903

 
 
 
 
 
Equity:
 
 
 
 
Partners’ equity:
 
 
 
 
Common unitholders (58,657,048 and 56,782,048 units issued and outstanding
    at December 31, 2013 and 2012, respectively)
 
516,147

 
502,809

General partner interest (2% interest)
 
(146,557
)
 
(145,877
)
Accumulated other comprehensive loss
 
(144
)
 
(4,279
)
Total partners’ equity
 
369,446

 
352,653

Noncontrolling interest
 
97,488

 
100,203

Total equity
 
466,934

 
452,856

Total liabilities and equity
 
$
1,382,508

 
$
1,394,110



See accompanying notes.

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HOLLY ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF INCOME
 
 
 
Years Ended December 31,
 
 
2013
 
2012
 
2011
 
 
(In thousands, except per unit data)
Revenues:
 
 
 
 
 
 
Affiliates
 
$
252,368

 
$
245,582

 
$
168,261

Third parties
 
52,814

 
46,978

 
46,007

 
 
305,182

 
292,560

 
214,268

Operating costs and expenses:
 
 
 
 
 
 
Operations (exclusive of depreciation and amortization)
 
99,444

 
89,242

 
64,521

Depreciation and amortization
 
65,423

 
57,461

 
36,958

General and administrative
 
11,749

 
7,594

 
6,576

 
 
176,616

 
154,297

 
108,055

Operating income
 
128,566

 
138,263

 
106,213

 
 
 
 
 
 
 
Other income (expense):
 
 
 
 
 
 
Equity in earnings of SLC Pipeline
 
2,826

 
3,364

 
2,552

Interest expense
 
(47,010
)
 
(47,182
)
 
(35,959
)
Interest income
 
161

 
—

 
—

Loss on early extinguishment of debt
 
—

 
(2,979
)
 
—

Gain on sale of assets
 
1,810

 
—

 
—

Other (income) expense
 
61

 
10

 
17

 
 
(42,152
)
 
(46,787
)
 
(33,390
)
Income before income taxes
 
86,414

 
91,476

 
72,823

State income tax expense
 
(333
)
 
(371
)
 
(234
)
Net income
 
86,081

 
91,105

 
72,589

Allocation of net loss attributable to Predecessors
 
—

 
4,200

 
6,351

Allocation of net loss (income) attributable to noncontrolling interests
 
(6,632
)
 
(1,153
)
 
859

Net income attributable to Holly Energy Partners
 
79,449

 
94,152

 
79,799

General partner interest in net income, including incentive distributions
 
(27,523
)
 
(22,450
)
 
(16,806
)
Limited partners’ interest in net income
 
$
51,926

 
$
71,702

 
$
62,993

Limited partners’ per unit interest in earnings—basic and diluted
 
$
0.88

 
$
1.29

 
$
1.38

Weighted average limited partners’ units outstanding
 
58,246

 
55,696

 
45,672



See accompanying notes.


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HOLLY ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


 
 
Years Ended December 31,
 
 
2013
 
2012
 
2011
 
 
(In thousands)
Net income
 
$
86,081

 
$
91,105

 
$
72,589

 
 
 
 
 
 
 
Other comprehensive income:
 
 
 
 
 
 
Change in fair value of cash flow hedging instruments
 
1,194

 
(4,418
)
 
(1,956
)
Amortization of unrealized loss attributable to discontinued cash flow hedge
 
849

 
5,095

 
41

Reclassification adjustment to net income on partial settlement of cash flow hedge
 
2,092

 
1,508

 
5,477

Other comprehensive income
 
4,135

 
2,185

 
3,562

Comprehensive income before noncontrolling interest
 
90,216

 
93,290

 
76,151

Allocation of comprehensive (income) loss to noncontrolling interests
 
(6,632
)
 
(1,153
)
 
859

Allocation of net loss attributable to Predecessors
 
—

 
4,200

 
6,351

Comprehensive income attributable to Holly Energy Partners
 
$
83,584

 
$
96,337

 
$
83,361


    
See accompanying notes.


- 59 -

HOLLY ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
 
 
Years Ended December 31,
 
 
2013
 
2012
 
2011
 
 
(In thousands)
Cash flows from operating activities
 
 
 
 
 
 
Net income
 
$
86,081

 
$
91,105

 
$
72,589

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
 
 
Depreciation and amortization
 
65,423

 
57,461

 
36,958

Gain on sale of assets
 
(1,810
)
 
—

 
—

Amortization of deferred charges
 
2,970

 
7,556

 
1,253

Amortization of restricted and performance units
 
3,575

 
2,858

 
2,046

(Increase) decrease in operating assets:
 
 
 
 
 
 
Accounts receivable—trade
 
2,065

 
(3,997
)
 
489

Accounts receivable—affiliates
 
1,919

 
(135
)
 
(13,032
)
Prepaid and other current assets
 
(255
)
 
110

 
(2,491
)
Increase (decrease) in operating liabilities:
 
 
 
 
 
 
Accounts payable—trade
 
3,365

 
(9,003
)
 
3,894

Accounts payable—affiliates
 
3,821

 
(1,811
)
 
2,137

Accrued interest
 
13

 
1,945

 
763

Deferred revenue
 
15,255

 
11,333

 
(2,127
)
Accrued property taxes
 
(85
)
 
492

 
206

Other current liabilities
 
(45
)
 
113

 
515

Other, net
 
788

 
3,122

 
(4,293
)
Net cash provided by operating activities
 
183,080

 
161,149

 
98,907

 
 
 
 
 
 
 
Cash flows from investing activities
 
 
 
 
 
 
Additions to properties and equipment
 
(52,101
)
 
(42,861
)
 
(206,309
)
Proceeds from sale of assets
 
2,731

 
—

 
—

Distributions in excess of equity in earnings in SLC pipeline
 
300

 
262

 
135

Net cash used for investing activities
 
(49,070
)
 
(42,599
)
 
(206,174
)
 
 
 
 
 
 
 
Cash flows from financing activities
 
 
 
 
 
 
Borrowings under credit agreement
 
310,600

 
587,000

 
118,000

Repayments of credit agreement borrowings
 
(368,600
)
 
(366,000
)
 
(77,000
)
Proceeds from issuance of senior notes
 
—

 
294,750

 
—

Proceeds from issuance of common units
 
73,444

 
—

 
75,815

Cash distribution to HFC for UNEV acquisition
 
—

 
(260,922
)
 
—

Repayment of notes
 
—

 
(260,235
)
 
(77,100
)
Contributions from UNEV joint venture partners
 
—

 
15,000

 
156,500

Contributions from general partner
 
1,499

 
1,748

 
5,887

Distributions to HEP unitholders
 
(139,486
)
 
(122,777
)
 
(91,506
)
Distributions to noncontrolling interest
 
(3,125
)
 
—

 
—

Purchase of units for incentive grants
 
(5,634
)
 
(4,919
)
 
(1,641
)
Deferred financing costs
 
(1,344
)
 
(3,238
)
 
(3,150
)
Other
 
(249
)
 
(89
)
 
(221
)
Net cash provided (used) by financing activities
 
(132,895
)
 
(119,682
)
 
105,584

 
 
 
 
 
 
 
Cash and cash equivalents
 
 
 
 
 
 
Increase (decrease) for the year
 
1,115

 
(1,132
)
 
(1,683
)
Beginning of year
 
5,237

 
6,369

 
8,052

End of year
 
$
6,352

 
$
5,237

 
$
6,369



See accompanying notes.

- 60 -

HOLLY ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF PARTNERS' EQUITY
 
 
Holly Energy Partners, L.P. Partners’ Equity (Deficit):
 
 
 
 
 
 
Common
Units
 
General
Partner
Interest
 
Accumulated
Other
Comprehensive
Loss
 
Noncontrolling
Interest
 
Total
 
 
(In thousands)
Balance December 31, 2010
 
$
269,153

 
$
42,372

 
$
(10,026
)
 
$
63,362

 
$
364,861

Issuance of common units
 
75,815

 
—

 
—

 
—

 
75,815

Capital contribution
 
—

 
127,947

 
—

 
36,500

 
164,447

Distributions to HEP unitholders
 
(75,951
)
 
(15,555
)
 
—

 
—

 
(91,506
)
Tankage and terminal assets acquired from HFC:
 
 
 
 
 
 
 
 
 
 
Transferred basis in properties and goodwill
 
295,110

 
—

 
—

 
—

 
295,110

Operating costs prior to acquisition
 
2,348

 
—

 
—

 
—

 
2,348

Promissory notes issued
 
(150,000
)
 
—

 
—

 
—

 
(150,000
)
Purchase of units for incentive grants
 
(2,168
)
 
—

 
—

 
—

 
(2,168
)
Amortization of restricted and performance units
 
2,046

 
—

 
—

 
—

 
2,046

Other
 
332

 
242

 
—

 
—

 
574

 Net income
 
64,754

 
8,695

 
—

 
(860
)
 
72,589

 Other comprehensive income
 
—

 
—

 
3,562

 
—

 
3,562

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 UNEV joint venture partners
 
—

 
—

 
—

 
(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

 
See accompanying notes.

- 61 -

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2013

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 417-mile, 12-inch refined products pipeline running from Woods Cross, Utah to Las Vegas, Nevada (the “UNEV Pipeline”), product terminals near Cedar City, Utah and Las Vegas, Nevada and related assets, and a 25% interest in SLC Pipeline L.L.C., 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.

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.

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. If these assets 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 as increases to our properties and equipment and intangible assets at the time of acquisition instead of reductions to our partners' equity.

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.


- 62 -

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.

Materials and Supplies
Materials and supplies consisting of materials and supplies used for operations are stated at the lower of cost, using the average cost method, or market and are shown under “Prepaid and other current assets” in our consolidated balance sheets.

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. 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, 2013.

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, 2013, our underlying equity in the SLC Pipeline was $59.6 million compared to our recorded investment balance of $24.7 million, a difference of $34.9 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, 2013 and 2012, we have asset retirement obligations of $6.5 million and $5.6 million, respectively, that are recorded under “Other long-term liabilities” in

- 63 -

our consolidated balance sheets. During 2013, we increased our asset retirement obligations by an additional $0.6 million as a result of a change in our previous estimates.

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, 2013, 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 $2.7 billion including $265.6 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, 2013 and 2012, we had accruals net of expected recoveries from indemnifying parties for environmental remediation obligations of $3.6 million and $3.0 million, respectively, measured on an undiscounted basis.
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. Due to a statutory change that was enacted in June 2013, we are now able to deduct additional expenses which is anticipated to result in lower cash taxes to HEP in the current and future years. 
 
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.

- 64 -


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

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


Note 2:
Acquisitions

2012 UNEV Acquisition
On July 12, 2012, we acquired HFC's 75% interest in UNEV. We paid consideration consisting of $260.0 million in cash and 2,059,800 of our common units. We paid an additional $0.9 million to HFC for a post-closing working capital adjustment. Also under the terms of the transaction, we issued to HFC a Class B unit comprising a noncontrolling equity interest in a wholly-owned subsidiary subject to redemption to the extent that HFC is entitled to a 50% interest in our share of annual UNEV earnings before interest, income taxes, depreciation, and amortization above $30 million beginning July 1, 2016 and ending in June 2032, subject to certain limitations. Such contingent redemption payments are limited to a maximum payment amount calculated as described below. However, to the extent earnings thresholds are not achieved, no redemption payments are required. Contemporaneously with this transaction, HFC (our general partner) agreed to forego its right to incentive distributions of up to $1.25 million per quarter over twelve consecutive quarterly periods following the closing of the transaction and up to an additional four quarters in certain circumstances. The Class B unit increases with each foregone incentive distribution as described above and by a 7% factor compounded annually on the outstanding unredeemed balance through its expiration date. At our option, we may redeem, in whole or in part, the Class B unit at the current unredeemed value based on the calculation described. The class B unit had a carrying value of $20.1 million at December 31, 2013 and $13.9 million at December 31, 2012 .

Noncontrolling interests reported in the Consolidated Statements of Income include the minority partner's 25% interest in UNEV and income attributable to the Class B unit representing foregone incentive distribution rights and the 7% accretion factor, which collectively amounted to $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 years ended December 31, 2012 and 2011, our consolidated statement of income includes revenues from UNEV of $18.7 million and $0.3 million, respectively, and net losses of $7.2 million and $3.4 million, respectively. Predecessor revenues for the years ended December 31, 2012 and 2011 are $8.1 million and $0.3 million, respectively, and Predecessor net losses are $4.2 million and $2.6 million, respectively. At December 31, 2013, UNEV had transportation agreements with shippers that provide minimum annualized revenues of $25.0 million, of which $16.9 million relates to a transportation agreement with HFC.

The following table provides HFC's carrying basis related to UNEV on July 12, 2012, immediately prior to the acquisition.

- 65 -

 
 
July 12, 2012
 
 
(In thousands)
Current assets
 
$
7,083

Properties and equipment, net
 
418,764

Total assets
 
$
425,847

 
 
 
Current liabilities
 
$
7,040

General partner interest related to Predecessor
 
318,310

Noncontrolling interest
 
100,497

Total liabilities and equity
 
$
425,847


            
2011 Legacy Frontier Pipeline and Tankage Asset Transaction
On November 9, 2011, we acquired from HFC certain tankage, loading rack and crude receiving assets located at HFC’s El Dorado and Cheyenne refineries. We paid non-cash consideration consisting of promissory notes with an aggregate principal amount of $150.0 million and 7,615,230 of our common units. As an entity under common control with HFC, we recorded this transfer at HFC's carrying basis. We recorded properties and equipment of $88.1 million, goodwill of $207.4 million and a non-cash capital contribution of $295.5 million, representing HFC's cost basis in the acquired assets. On November 9, 2011, we recorded a $150.0 million liability representing the promissory notes issued to HFC at the time of the closing of this transaction. In 2012, we recorded additional properties and equipment of $7.6 million, and a related non-cash capital contribution of $7.6 million for newly constructed tankage conveyed in 2012 as part of the November 9, 2011 transaction.

Summary Pro Forma Information
Assuming both acquisitions had occurred on January 1, 2011 and our throughput agreements with HFC were in effect at that time, the pro forma revenues, net income and earnings per unit are presented below:
 
 
Year Ended
 December 31, 2011
 
 
(In thousands, except per share amounts)
 
 
(unaudited)
Revenues
 
$
214,268

Net income
 
$
71,145

Earnings per unit
 
$
1.19



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.


- 66 -

The carrying amounts and estimated fair values of our senior notes and interest rate swaps were as follows:
 
 
 
 
December 31, 2013
 
December 31, 2012
Financial Instrument
 
Fair Value Input Level
 
Carrying
Value
 
Fair Value
 
Carrying
Value
 
Fair Value
 
 
 
 
(In thousands)
Liabilities:
 
 
 
 
 
 
 
 
 
 
Senior notes:
 
 
 
 
 
 
 
 
 
 
6.5% senior notes
 
Level 2
 
$
295,927

 
$
313,500

 
$
295,275

 
$
321,000

8.25% senior notes
 
Level 2
 
148,703

 
158,250

 
148,398

 
163,125

 
 
 
 
444,630

 
471,750

 
443,673

 
484,125

 
 
 
 
 
 
 
 
 
 
 
Interest rate swaps
 
Level 2
 
144

 
144

 
3,430

 
3,430

 
 
 
 
$
444,774

 
$
471,894

 
$
447,103

 
$
487,555


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

See Note 7 for additional information on these instruments.


Note 4:
Properties and Equipment 

The carrying amounts of our properties and equipment are as follows:
 
 
December 31,
2013
 
December 31,
2012
 
 
(In thousands)
Pipelines, terminals and tankage
 
$
1,077,037

 
$
1,049,531

Land and right of way
 
63,425

 
63,248

Construction in progress
 
50,454

 
27,150

Other
 
19,997

 
24,462

 
 
1,210,913

 
1,164,391

Less accumulated depreciation
 
253,099

 
203,856

 
 
$
957,814

 
$
960,535


We capitalized $0.6 million and $0.3 million in interest related to construction projects during the years ended December 31, 2013 and 2012, respectively.

Depreciation expense was $58.1 million, $50.1 million, and $30.0 million for the years ended December 31, 2013, 2012 and 2011, respectively. Included in depreciation expense were asset abandonment charges of $6.2 million, $4.8 million and $1.2 million for the years ended December 31, 2013, 2012 and 2011, respectively, for assets permanently removed from service.



- 67 -

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,
2013
 
December 31,
2012
 
 
(In thousands)
Alon transportation agreement
 
$
59,933

 
$
59,933

HFC transportation agreement
 
74,231

 
74,231

 
 
134,164

 
134,164

Less accumulated amortization
 
46,514

 
39,568

 
 
$
87,650

 
$
94,596


Amortization expense was $6.9 million for each of the years ended December 31, 2013, 2012 and 2011, 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

Employees who provide direct services to us are employed by Holly Logistic Services, L.L.C., an HFC subsidiary. Their costs, including salaries, bonuses, payroll taxes, benefits and other direct costs, are charged to us monthly in accordance with an omnibus agreement that we have with HFC. These employees participate in the retirement and benefit plans of HFC. Our share of retirement and benefit plan costs was $7.4 million, $6.9 million and $3.6 million for the years ended December 31, 2013, 2012 and 2011, respectively. These costs include retirement costs of $5.0 million, $4.3 million and $2.2 million for the years ended December 31, 2013, 2012 and 2011, 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, 2013, we have three types of incentive-based awards which are described below. The compensation cost charged against income was $3.6 million, $2.7 million and $2.1 million for the years ended December 31, 2013, 2012 and 2011, 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, 2013, 2,500,000 units were authorized to be granted under our Long-Term Incentive Plan, of which 1,634,211 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 selected employees and non-employee directors who perform services for us, with most awards vesting over a period of one to three years. Although full ownership of the units does not transfer to the recipients until the units vest, the recipients have distribution and voting rights on these units from the date of grant.

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, 2013 is presented below: 
Restricted and Phantom Units
 
Units
 
Weighted-
Average
Grant-Date
Fair Value
Outstanding at January 1, 2013 (nonvested)
 
58,472

 
$
31.21

Granted
 
116,606

 
34.66

Vesting and transfer of full ownership to recipients
 
(39,522
)
 
31.39

Forfeited
 
(12,605
)
 
41.18

Outstanding at December 31, 2013 (nonvested)
 
122,951

 
$
33.36


The fair values of restricted units that were vested and transferred to recipients during the years ended December 31, 2013, 2012 and 2011 were $1.2 million, $2.4 million and $1.4 million respectively. No phantom units vested during the years ended December 31, 2013, 2012 and 2011, respectively. As of December 31, 2013, there was $2.8 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 1.4 years. For the years ended December 31, 2012 and 2011, the grant date closing unit price applied to the number of restricted units ultimately awarded was $31.01 and $29.05 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. As of December 31, 2013, estimated unit payouts for outstanding nonvested performance unit awards were at 100% to 150%.

We granted 32,888 target performance units to certain officers in March 2013 and 12,954 target performance units to certain officers in November 2013 (as a result of a change in the timing of long-term incentive award grants). These units will vest over a three-year performance period ending December 31, 2015 and December 31, 2016, respectively, and are payable in HEP common units. The number of units actually earned will be based on the growth of our distributable cash flow per common unit over the performance period, and can range from 0% to 200% of the target number of performance units granted (in the case of our Chairman) or from 50% to 150% of the target number of performance units granted (in the case of other officers granted performance units). Although common units are not transferred to the recipients until the performance units vest, the recipients have distribution rights with respect to the common units from the date of grant. The fair value of these performance units is based on the grant date closing unit price of $40.86 for the performance units granted in March 2013 and $30.40 for the performance units granted in November 2013 and will apply to the number of units ultimately awarded. For the years ended December 31, 2012 and 2011, the grant date closing unit price applied to the number of units ultimately awarded was $30.61 and $29.83 respectively.

A summary of performance unit activity and changes during the twelve months ended December 31, 2013 is presented below:
Performance Units
 
Units
Outstanding at January 1, 2013 (nonvested)
 
54,498

Granted
 
45,842

Vesting and transfer of common units to recipients
 
(25,124
)
Outstanding at December 31, 2013 (nonvested)
 
75,216


The grant date fair value of performance units vested and transferred to recipients during the years ended December 31, 2013, 2012 and 2011 was $0.5 million, $0.5 million and $0.9 million, respectively. Based on the weighted average fair value at December 31, 2013 of $2.6 million, there was $1.4 million of total unrecognized compensation expense related to nonvested performance units, which is expected to be recognized over a weighted-average period of 1.5 years.

During the year ended December 31, 2013, we paid $5.6 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
On November 22, 2013, we amended our credit agreement increasing the size of the credit facility from $550 million to $650 million. Our $650 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 available also to fund letters of credit up to a $50 million sub-limit. During the year ended December 31, 2013, we received advances totaling $310.6 million and repaid $368.6 million, resulting in net reductions of $58.0 million under the Credit Agreement and an outstanding balance of $363 million at December 31, 2013.

Our obligations under the Credit Agreement are collateralized by substantially all of our assets. Indebtedness under the Credit Agreement is recourse to HEP Logistics Holdings, L.P. (“HEP Logistics”), our general partner, and guaranteed by our material wholly-owned subsidiaries. Any recourse to HEP Logistics would be limited to the extent of its assets, which other than its investment in us, are not significant. We may prepay all loans at any time without penalty, except for payment of certain breakage and related costs.

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 interest rates on our Credit Agreement borrowings in effect at December 31, 2013 and 2012 were 2.163% and 2.456%, 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 which we are currently in compliance with, including: a prohibition against distribution to unitholders if, before or after the distribution, a potential default or an event of default as defined in the agreement would occur; limitations on our ability to incur debt, make loans, acquire other companies, change the nature of our business, enter into a merger or consolidation, or sell assets; and covenants that require maintenance of a specified EBITDA to interest expense ratio, total debt to EBITDA ratio and senior debt to EBITDA ratio. If an event of default exists under the Credit Agreement, the lenders will be able to accelerate the maturity of the debt and exercise other rights and remedies.

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

Also, we have $150 million in aggregate principal amount outstanding of 8.25% senior notes maturing March 15, 2018 (the “8.25% Senior Notes”). On February 12, 2014, we announced that we will redeem all of our outstanding 8.25% Senior Notes. The redemption price will be equal to 104.125% of the principal amount for a total payment to the holders of the notes of approximately $156.2 million plus accrued interest. The redemption of the 8.25% Senior Notes is scheduled to occur on March 15, 2014. We plan to fund the redemption with borrowings under our Credit Agreement.

The 6.5% Senior Notes and 8.25% Senior Notes (collectively, the “Senior Notes”) are unsecured and impose certain restrictive covenants, which we are currently in compliance with, including limitations on our ability to incur additional indebtedness, make investments, sell assets, incur certain liens, pay distributions, enter into transactions with affiliates, and enter into mergers. At any time when the Senior Notes are rated investment grade by both Moody’s and Standard & Poor’s and no default or event of default exists, we will not be subject to many of the foregoing covenants. Additionally, we have certain redemption rights at varying premiums over face value under the Senior Notes.

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


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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.

Promissory Notes
In November 2011, we issued senior unsecured promissory notes to HFC (the “Promissory Notes”) having an aggregate principal amount of $150 million to finance a portion of our November 9, 2011 acquisition of assets located at HFC's El Dorado and Cheyenne refineries (see Note 2). In December 2011, we repaid $77.1 million of outstanding principal using proceeds received in our December 2011 common unit offering and existing cash. We repaid the remaining $72.9 million balance in March 2012.

Long-term Debt
The carrying amounts of our long-term debt are as follows:
 
 
December 31,
2013
 
December 31,
2012
 
 
(In thousands)
Credit Agreement
 
$
363,000

 
$
421,000

6.5% Senior Notes
 
 
 
 
Principal
 
300,000

 
300,000

Unamortized discount
 
(4,073
)
 
(4,725
)
 
 
295,927

 
295,275

8.25% Senior Notes
 
 
 
 
Principal
 
150,000

 
150,000

Unamortized discount
 
(1,297
)
 
(1,601
)
 
 
148,703

 
148,399

 
 
 
 
 
Total long-term debt
 
$
807,630

 
$
864,674


Maturities of our long-term debt are as follows:
Years Ending December 31,
 
(In thousands)
2014
 
$
—

2015
 
—

2016
 
—

2017
 
—

2018
 
513,000

Thereafter
 
300,000

Total
 
$
813,000


Interest Rate Risk Management
We use interest rate swaps (derivative instruments) to manage our exposure to interest rate risk.

As of December 31, 2013, we have three interest rate swaps that hedge our exposure to the cash flow risk caused by the effects of LIBOR changes on $305 million of Credit Agreement advances. Our first interest rate swap entered into in December 2011, 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, 2013, which equaled an effective interest rate of 2.99%. This swap contract matures in February 2016. In August 2012, we entered into two similar interest rate swaps with identical terms which effectively convert $150 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, 2013, 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

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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, 2013, we had no ineffectiveness on our cash flow hedges.

Prior to entering into our swap contract in December 2011 (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, 2013, we have accumulated other comprehensive loss of $0.1 million that relates to our current cash flow hedging instruments. Approximately $0.4 million will be transferred from accumulated other comprehensive loss into interest expense as interest is paid on the underlying swap agreement over the next twelve-month period, assuming interest rates remain unchanged.

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, 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 assets
 
1,670

 
Accumulated other
    comprehensive gain
 
1,670

 
 
 
 
$
144

 
 
 
$
144

 
 
 
 
 
 
 
 
 
December 31, 2012
 
 
 
 
 
 
 
 
Interest rate swaps designated as cash flow hedging instrument:
 
 
 
 
 
 
Variable-to-fixed interest rate swap contract ($305 million of LIBOR based debt interest)
 
Other long-term
    liabilities
 
$
3,430

 
Accumulated other
    comprehensive loss
 
$
3,430


We have a deferred hedge premium that relates to the application of hedge accounting to a variable-rate swap associated with our 6.25% senior notes prior to its hedge dedesignation in 2008. This deferred hedge premium having a balance of $1.1 million at December 31, 2011 was amortized in 2012 and the unamortized balance was taken as a reduction to interest expense during the cash tender offer and consent solicitation of our 6.25% Senior Notes.


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Interest Expense and Other Debt Information
Interest expense consists of the following components:
 
 
Years Ended December 31,
 
 
2013
 
2012
 
2011
 
 
(In thousands)
Interest on outstanding debt:
 
 
 
 
 
 
Credit Agreement, net of interest on interest rate swaps
 
$
11,961

 
$
8,736

 
$
10,477

6.5% Senior Notes
 
19,506

 
15,716

 
—

6.25% Senior Notes
 
—

 
2,422

 
11,565

8.25% Senior Notes
 
12,380

 
12,380

 
12,380

Promissory Notes
 
—

 
543

 
745

Amortization of discount and deferred debt issuance costs
 
2,123

 
1,946

 
1,212

Amortization of unrecognized loss attributable to terminated cash flow hedge
 
849

 
5,095

 
41

Commitment fees
 
832

 
621

 
430

Total interest incurred
 
47,651

 
47,459

 
36,850

Less capitalized interest
 
641

 
277

 
891

Net interest expense
 
$
47,010

 
$
47,182

 
$
35,959

Cash paid for interest
 
$
44,655

 
$
38,476

 
$
34,825


We recognized a charge of $3.0 million upon the early extinguishment of debt 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.


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, 2013, 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)
2014
$
6,874

2015
6,871

2016
6,857

2017
3,495

2018
148

Thereafter
362

Total
$
24,607

Rental expense charged to operations was $8.3 million, $8.1 million and $7.5 million for the years ended December 31, 2013, 2012 and 2011, respectively.
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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Note 9:
Significant Customers

All revenues are domestic revenues, of which 94% 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:
 
2013
 
2012
 
2011
HFC
83
%
 
84
%
 
79
%
Alon
11
%
 
11
%
 
18
%


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

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

In November 2011, we reached an agreement with HFC that clarifies certain terms of a crude pipelines and tankage throughput agreement, whereby HFC agreed to pay us $5.5 million for certain past deliveries on our crude pipeline system. We recognized this settlement as revenue in the fourth quarter of 2011 that was billed in six equal quarterly installments through March 2013.

Under certain provisions of an omnibus agreement we have with HFC (the “Omnibus Agreement”), we pay HFC an annual administrative fee for the provision by HFC or its affiliates of various general and administrative services to us, currently $2.3 million. This fee does not include the salaries of personnel employed by 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 from HFC were $252.4 million, $245.6 million and $168.3 million for the years ended December 31, 2013, 2012 and 2011, respectively.
•
HFC charged us general and administrative services under the Omnibus Agreement of $2.3 million for each of the three years ended December 31, 2013, 2012 and 2011.
•
We reimbursed HFC for costs of employees supporting our operations of $34.6 million, $31.1 million and $21.4 million for the years ended December 31, 2013, 2012 and 2011, respectively. Netted against the cost of employees for the year ended December 31, 2013 is a $3.5 million refund received from HFC for net tax refunds related to payroll costs covering a multi-year period.
•
HFC reimbursed us $21.6 million, $13.4 million and $11.9 million for the years ended December 31, 2013, 2012 and 2011, respectively, for certain reimbursable costs and capital projects.
•
We distributed $71.4 million, $64.0 million and $40.6 million, for the years ended December 31, 2013, 2012 and 2011, respectively, to HFC as regular distributions on its common units and general partner interest, including general partner incentive distributions.
•
Accounts receivable from HFC were $29.7 million and $31.6 million at December 31, 2013 and 2012, respectively.
•
Accounts payable to HFC were $8.5 million and $5.0 million at December 31, 2013 and 2012, respectively.

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•
Revenues for the years ended December 31, 2013, 2012 and 2011 include $5.1 million, $7.8 million and $3.3 million of shortfall payments billed in 2012, 2011 and 2010, respectively, as HFC did not exceed its minimum volume commitment in any of the subsequent four quarters in 2013, 2012 and 2011. Additionally, revenues for the year ended December 31, 2012 include $3.8 million due to capacity constraints on our UNEV pipeline system. Deferred revenue in the consolidated balance sheets at December 31, 2013 and 2012, includes $10.1 million and $5.1 million, respectively, relating to certain shortfall billings. It is possible that HFC may not exceed its minimum obligations to receive credit for any of the $10.1 million deferred at December 31, 2013.
•
We acquired from HFC a 75% interest in the UNEV Pipeline in July 2012 and certain tankage and terminal assets in November 2011. See Note 2 for a description of these transactions.


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

As of December 31, 2013, HFC held 22,380,030 of our common units and the 2% general partner interest, which together constituted a 39% ownership interest in us.

On January 16, 2013, a two-for-one unit split was paid in the form of a common unit distribution for each issued and outstanding common unit to all unitholders of record on January 7, 2013. All references to unit and per unit amounts in this document and related disclosures have been adjusted to reflect the effect of the unit split 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. Amounts repaid under our credit facility may be reborrowed from time to time, and we intend to reborrow certain amounts to fund capital expenditures.

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.

2011 Issuances
We issued in a public offering 2,950,000 of our common units priced at $26.75 per unit in December 2011. Aggregate net proceeds of $75.8 million were used to pay a portion of outstanding principal of the Promissory Notes.

We issued 7,615,230 of our common units to HFC in November 2011 as partial consideration for the purchase of certain tankage, loading rack and crude receiving assets located at HFC's El Dorado and Cheyenne refineries.

We received aggregate capital contributions of $5.9 million from our general partner to maintain its 2% general partner interest concurrent with the 2011 common unit issuances described above.

Under our registration statement filed with the SEC using a “shelf” registration process, we currently have the ability to raise up to $2 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.

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

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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,
 
 
2013
 
2012
 
2011
 
 
(in thousands)
General partner interest in net income
 
$
1,059

 
$
1,464

 
$
1,287

General partner incentive distribution
 
26,464

 
20,986

 
15,519

Total general partner interest in net income
 
$
27,523

 
$
22,450

 
$
16,806


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 23, 2014, we announced our cash distribution for the fourth quarter of 2013 of $0.50 per unit. The distribution is payable on all common and general partner units and will be paid February 14, 2014 to all unitholders of record on February 4, 2014.


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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,
 
 
2013
 
2012
 
2011
 
 
(In thousands, except per unit data)
General partner interest in distribution
 
$
2,982

 
$
2,566

 
$
1,981

General partner incentive distribution
 
26,464

 
20,986

 
15,519

Total general partner distribution
 
29,446

 
23,552

 
17,500

Limited partner distribution
 
114,675

 
102,222

 
81,508

Total regular quarterly cash distribution
 
$
144,121

 
$
125,774

 
$
99,008

Cash distribution per unit applicable to limited partners
 
$
1.955

 
$
1.835

 
$
1.740


As a master limited partnership, we distribute our available cash, which historically has exceeded our net income attributable to HEP because depreciation and amortization expense represents a non-cash charge against income. The result is a decline in our partners’ equity since our regular quarterly distributions have exceeded our quarterly net income attributable to HEP. Additionally, if the asset contributions and acquisitions from HFC had occurred while we were not a consolidated variable interest entity of HFC, our acquisition cost, in excess of HFC’s historical basis in the transferred assets of $305.3 million, would have been recorded in our financial statements at the time of acquisition, as increases to our properties and equipment and intangible assets instead of decreases to our partners’ equity.


Note 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, 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

Year Ended December 31, 2012
 
 
 
 
 
 
 
 
 
 
Revenues
 
$
68,415

 
$
68,660

 
$
74,054

 
$
81,431

 
$
292,560

Operating income
 
$
31,602

 
$
30,116

 
$
35,572

 
$
40,973

 
$
138,263

Income before income taxes
 
$
19,431

 
$
19,204

 
$
23,909

 
$
28,932

 
$
91,476

Net income
 
$
19,356

 
$
19,128

 
$
23,773

 
$
28,848

 
$
91,105

Net income attributable to Holly Energy Partners
 
$
21,774

 
$
22,003

 
$
23,336

 
$
27,039

 
$
94,152

Limited partners’ per unit interest in net income – basic and diluted
 
$
0.30

 
$
0.30

 
$
0.32

 
$
0.37

 
$
1.29

Distributions per limited partner unit
 
$
0.448

 
$
0.455

 
$
0.463

 
$
0.470

 
$
1.835

 



- 77 -

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.

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




- 78 -

Condensed Consolidating Balance Sheet
December 31, 2012
 
Parent
 
Guarantor
Restricted Subsidiaries
 
Non-Guarantor Non-Restricted Subsidiaries
 
Eliminations
 
Consolidated
 
 
(In thousands)
ASSETS
 
 
 
 
 
 
 
 
 
 
Current assets:
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
2

 
$
823

 
$
4,412

 
$
—

 
$
5,237

Accounts receivable
 
—

 
32,319

 
6,401

 
—

 
38,720

Intercompany accounts receivable
 
42,194

 
—

 
—

 
(42,194
)
 
—

Prepaid and other current assets
 
224

 
2,395

 
1,000

 
—

 
3,619

Total current assets
 
42,420

 
35,537

 
11,813

 
(42,194
)
 
47,576

Properties and equipment, net
 
—

 
563,701

 
396,834

 
—

 
960,535

Investment in subsidiaries
 
763,569

 
300,607

 
—

 
(1,064,176
)
 
—

Transportation agreements, net
 
—

 
94,596

 
—

 
—

 
94,596

Goodwill
 
—

 
256,498

 
—

 
—

 
256,498

Investment in SLC Pipeline
 
—

 
25,041

 
—

 
—

 
25,041

Other assets
 
1,154

 
8,710

 
—

 
—

 
9,864

Total assets
 
$
807,143

 
$
1,284,690

 
$
408,647

 
$
(1,106,370
)
 
$
1,394,110

 
 
 
 
 
 
 
 
 
 
 
LIABILITIES AND PARTNERS’ EQUITY
 
 
 
 
 
 
 
 
 
 
Current liabilities:
 
 
 
 
 
 
 
 
 
 
Accounts payable
 
$
—

 
$
10,745

 
$
1,285

 
$
—

 
$
12,030

Intercompany accounts payable
 
—

 
42,194

 
—

 
(42,194
)
 
—

Accrued interest
 
10,198

 
28

 
—

 
—

 
10,226

Deferred revenue
 
—

 
3,319

 
5,582

 
—

 
8,901

Accrued property taxes
 
—

 
1,923

 
765

 
—

 
2,688

Other current liabilities
 
563

 
1,274

 
68

 
—

 
1,905

Total current liabilities
 
10,761

 
59,483

 
7,700

 
(42,194
)
 
35,750

 
 
 
 
 
 
 
 
 
 
 
Long-term debt
 
443,674

 
421,000

 
—

 
—

 
864,674

Other long-term liabilities
 
55

 
15,241

 
137

 
—

 
15,433

Deferred revenue
 
—

 
11,494

 
—

 
—

 
11,494

Class B unit
 
—

 
13,903

 
—

 
—

 
13,903

Equity - partners
 
352,653

 
763,569

 
400,810

 
(1,164,379
)
 
352,653

Equity - noncontrolling interest
 
—

 
—

 
—

 
100,203

 
100,203

Total liabilities and partners’ equity
 
$
807,143

 
$
1,284,690

 
$
408,647

 
$
(1,106,370
)
 
$
1,394,110



- 79 -



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 Predecessors
 
—

 
—

 
—

 
—

 
—

Allocation of net (income) 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 (loss)
 
4,135

 
4,135

 
—

 
(4,135
)
 
4,135

Comprehensive income (loss)
 
$
83,584

 
$
126,207

 
$
1,641

 
$
(127,848
)
 
$
83,584



- 80 -


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 of subsidiaries
 
130,743

 
(5,400
)
 
—

 
(125,343
)
 
—

Equity in earnings of SLC Pipeline
 
—

 
3,364

 
—

 
—

 
3,364

Interest (expense) income
 
(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 income
 
2,185

 
2,185

 
—

 
(2,185
)
 
2,185

Comprehensive income (loss)
 
$
96,337

 
$
132,928

 
$
(7,200
)
 
$
(125,728
)
 
$
96,337




- 81 -

Condensed Consolidating Statement of Comprehensive Income
Year Ended December 31, 2011
 
Parent
 
Guarantor
Restricted Subsidiaries
 
Non-Guarantor Non-Restricted Subsidiaries
 
Eliminations
 
Consolidated
 
 
(In thousands)
Revenues:
 
 
 
 
 
 
 
 
 
 
Affiliates
 
$
—

 
$
168,519

 
$
313

 
$
(571
)
 
$
168,261

Third parties
 
—

 
46,005

 
2

 
—

 
46,007

 
 
—

 
214,524

 
315

 
(571
)
 
214,268

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

 
63,100

 
1,992

 
(571
)
 
64,521

Depreciation and amortization
 
—

 
35,200

 
1,758

 
—

 
36,958

General and administrative
 
3,902

 
2,674

 
—

 
—

 
6,576

 
 
3,902

 
100,974

 
3,750

 
(571
)
 
108,055

Operating income (loss)
 
(3,902
)
 
113,550

 
(3,435
)
 
—

 
106,213

Equity in earnings (loss) of subsidiaries
 
101,844

 
(2,576
)
 
—

 
(99,268
)
 
—

Equity in earnings of SLC Pipeline
 
—

 
2,552

 
—

 
—

 
2,552

Interest (expense) income
 
(24,494
)
 
(11,465
)
 
—

 
—

 
(35,959
)
Other
 
—

 
17

 
—

 
—

 
17

 
 
77,350

 
(11,472
)
 
—

 
(99,268
)
 
(33,390
)
Income (loss) before income taxes
 
73,448

 
102,078

 
(3,435
)
 
(99,268
)
 
72,823

State income tax expense
 
—

 
(234
)
 
—

 
—

 
(234
)
Net income (loss)
 
73,448

 
101,844

 
(3,435
)
 
(99,268
)
 
72,589

Allocation of net loss attributable to Predecessors
 
6,351

 
—

 
—

 
—

 
6,351

Allocation of net loss attributable to noncontrolling interests
 
—

 
—

 
—

 
859

 
859

Net income (loss) attributable to Holly Energy Partners
 
79,799

 
101,844

 
(3,435
)
 
(98,409
)
 
79,799

Other comprehensive (loss)
 
3,562

 
3,562

 
—

 
(3,562
)
 
3,562

Comprehensive income (loss)
 
$
83,361

 
$
105,406

 
$
(3,435
)
 
$
(101,971
)
 
$
83,361


- 82 -


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 (1)
 
$
(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
)
 
—

Distributions in excess of 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 (1)
 
105,031

 
(105,031
)
 
—

 
—

 
—

Proceeds from the issuance of common units
 
73,444

 
—

 
—

 
—

 
73,444

Contributions from general partners
 
1,499

 
—

 
—

 
—

 
1,499

Distributions to HEP unitholders
 
(139,486
)
 
—

 
—

 
—

 
(139,486
)
Distributions to noncontrolling interests
 
—

 
—

 
(12,500
)
 
9,375

 
(3,125
)
Purchase of units for incentive 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


(1) Effective with fiscal year 2013, we changed the 2012 and 2011 cash flow presentation of transactions associated with the partnerships intercompany lending activities by reclassifying certain amounts from operating cash flows to financing cash flows.


- 83 -

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 (1)
 
$
(34,557
)
 
$
194,667

 
$
1,039

 
$
—

 
$
161,149

 
 
 
 
 
 
 
 
 
 
 
Cash flows from investing activities
 
 
 
 
 
 
 
 
 
 
Additions to properties and equipment
 
—

 
(28,134
)
 
(14,727
)
 
—

 
(42,861
)
Distribution in excess of 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 (1)
 
51,989

 
(51,989
)
 
—

 
—

 
—

Cash distribution to HFC for UNEV acquisition
 
—

 
(260,922
)
 
—

 
—

 
(260,922
)
Repayments of 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



- 84 -

Condensed Consolidating Statement of Cash Flows

Year Ended December 31, 2011
 
Parent
 
Guarantor
Restricted Subsidiaries
 
Non-Guarantor Non-Restricted Subsidiaries
 
Eliminations
 
Consolidated
 
 
(In thousands)
Cash flows from operating activities (1)
 
$
(24,515
)
 
$
121,776

 
$
1,646

 
$
—

 
$
98,907

 
 
 
 
 
 
 
 
 
 
 
Cash flows from investing activities
 
 
 
 
 
 
 
 
 
 
Additions to properties and equipment
 
—

 
(43,614
)
 
(162,695
)
 
—

 
(206,309
)
Distributions in excess of earnings in SLC pipeline
 
—

 
135

 
—

 
—

 
135

 
 
—

 
(43,479
)
 
(162,695
)
 
—

 
(206,174
)
 
 
 
 
 
 
 
 
 
 
 
Cash flows from financing activities
 
 
 
 
 
 
 
 
 
 
Net borrowings under credit agreement
 
—

 
41,000

 
—

 
—

 
41,000

Net intercompany financing activities (1)
 
36,181

 
(36,181
)
 
—

 
—

 
—

Repayments of promissory notes
 
—

 
(77,100
)
 
—

 
—

 
(77,100
)
Proceeds from issuance of common units
 
75,815

 
—

 
—

 
—

 
75,815

Contributions from UNEV joint venture partners
 
—

 
—

 
156,500

 
—

 
156,500

Contributions from general partner
 
5,887

 
—

 
—

 
—

 
5,887

Distributions to HEP unitholders
 
(91,506
)
 
—

 
—

 
—

 
(91,506
)
Purchase of units for restricted grants
 
(1,641
)
 
—

 
—

 
—

 
(1,641
)
Deferred financing costs
 
—

 
(3,150
)
 
—

 
—

 
(3,150
)
Other
 
(221
)
 
—

 
—

 
—

 
(221
)
 
 
24,515

 
(75,431
)
 
156,500

 
—

 
105,584

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

 
2,866

 
(4,549
)
 
—

 
(1,683
)
Beginning of period
 
2

 
401

 
7,649

 
—

 
8,052

End of period
 
$
2

 
$
3,267

 
$
3,100

 
$
—

 
$
6,369



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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 Securities and Exchange Commission’s rules and forms. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of December 31, 2013 at a reasonable level of assurance.
(b) Changes in internal control over financial reporting
There have been no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during our last fiscal quarter that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.
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 2013 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.

Certain executive officers of HLS are also officers of HFC or provide services to HFC. During 2013, the following HLS executive officers were the only executive officers who spent all of their professional time managing our business and affairs:

Name
Title
Matthew P. Clifton
Chairman of the Board and Chief Executive Officer (1)
Bruce R. Shaw
President
Mark T. Cunningham
Senior Vice President, Operations

(1)
Mr. Clifton served in these capacities through the end of day on December 31, 2013.

Scott C. Surplus, Vice President and Controller, devoted a portion of his professional time to overseeing the risk management and insurance practices of HFC. Douglas S. Aron, Executive Vice President and Chief Financial Officer, and Denise C. McWatters, Senior Vice President, General Counsel and Secretary, are also officers of HFC and devoted as much of their professional time as was necessary to oversee the management of our business and affairs. Effective at the end of day on December 31, 2013, Mr. Clifton retired as Chief Executive Officer. Effective January 1, 2014, Mr. Clifton was appointed as Executive Chairman of HLS and Michael C. Jennings was appointed as Chief Executive Officer of HLS. Mr. Jennings is also an officer of HFC and devotes as much of his professional time as is necessary to oversee the management of our business and affairs. Effective February 28, 2014, Mr. Clifton will retire as Executive Chairman of HLS, and as an employee of HLS, and will serve as Chairman of the Board in a non-employee capacity.

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.

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 the Executive Chairman of HLS (and, effective February 28, 2014, 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 both 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 Executive Chairman (and, effective February 28, 2014, 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-management 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-management 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-management directors, including advising the Chairman and Chief Executive Officer on the efficiency of the Board meetings; and

- 87 -


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

Persons wishing to communicate with the non-management 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 review the communication and 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.

•
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 and William P. Stengel 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”).


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Conflicts Committee. The Conflicts Committee of HLS is composed of three directors, Messrs. Stengel, Pinkerton and Gray. 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 and Stengel 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. The Board has determined that these historical relationships do not impair Mr. Ridenour’s independence.

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 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, TX, 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 62.

Principal Occupation:
Executive Chairman of HLS

Business Experience:
Mr. Clifton was appointed as Executive Chairman of HLS in January 2014 and, effective February 28, 2014, will serve as Chairman of the Board in a non-employee capacity. Mr. Clifton served as Chairman of the Board and Chief Executive Officer of HLS from March 2004 through December 2013. Mr. Clifton served 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.
_________________________________________________________________________________________




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Charles M. Darling, IV    Director since July 2004. Age 65.

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 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 73.

Principal Occupation:
Private Consultant and Member of the New Mexico House of Representatives

Business Experience:
Mr. Gray is a private consultant and has served as a member of the New Mexico House of Representatives since November 2006. 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 48.

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 73.

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 72.

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 65.

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 59.

Principal Occupation:
Retired

Business Experience:
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 2004 to 2014 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 2013, 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 2013, the Audit Committee held five meetings, the Conflicts Committee held five meetings and the Compensation Committee held five meetings.

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
 
 

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

Audit Committee

The functions of the Audit Committee include the following:

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•
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 three directors, Messrs. Darling, Gray and Stengel, 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 Committee requiring approval solely by independent members of the Board. During 2013, the subcommittee of the Compensation Committee held three meetings.
The Compensation Committee has engaged Frederic W. Cook & Co. (the “Compensation Consultant” or “FWC”), an outside 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, 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.

- 93 -


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, 2013
 
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, 2013. 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, 2013 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, 2013 be included in Holly Energy Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2013 for filing with the SEC.
 
Members of the Audit Committee:
Jerry W. Pinkerton, Chairman
Charles M. Darling, IV
P. Dean Ridenour

Director Compensation

Members of the Board who also serve as officers or employees of HLS or HFC do not receive additional compensation in their capacity as directors or chairmen of committees.

For the year ended December 31, 2013, directors who were not officers or employees of HLS or HFC (“non-employee directors”) were compensated as follows:

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Annual cash retainer (payable in four quarterly installments)
$
50,000

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

Telephonic special board or committee meeting (2)
$
1,000

Each attended strategy meeting with HLS management
$
1,500

Annual grant of restricted units under the Long-Term Incentive Plan
$
75,000

Special cash retainer for chairmen of committees and subcommittees (payable in four quarterly installments)
$
10,000


(1)
Upon submission of appropriate documentation, non-employee directors also are reimbursed for reasonable out-of-pocket expenses in connection with attending Board or committee meetings.
 
 
(2)
Non-employee directors receive $1,000 for telephonic special meetings that last over 30 minutes. The Chairman of the Board and the chairman of each committee has authority to exercise his discretion as to whether the topics discussed at a telephonic special meeting of the Board or committee, as applicable, that lasts 30 minutes or less warrants a fee of $1,000.

Equity Awards

Each August 1, non-employee directors receive an annual grant under the Holly Energy Partners, L.P. Amended and Restated Long-Term Incentive Plan (“Long-Term Incentive Plan”) 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 restricted unit grants is calculated based upon the market closing price of our common units on the day of grant (or the last business day prior to August 1 if August 1 occurs on a Saturday or Sunday). The restricted units fully vest one year following the date of grant, subject to the director’s continued service on the Board. Accelerated vesting of all unvested units will occur upon a change in control of HFC, HLS, HEP or HEP Logistics. In addition, accelerated vesting of unvested units will occur 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.

Non-Qualified Deferred Compensation

The non-employee directors of HLS are eligible to participate in the HollyFrontier Corporation Executive Nonqualified Deferred Compensation Plan, which plan is not tax-qualified under Section 401 of the Internal Revenue Code and allows participants to defer receipt of certain compensation (the “NQDC Plan”). For 2013, the NQDC Plan provided non-employee director participants with the potential to defer up to 50% of their cash retainers and meeting fees for the calendar year. Mr. Pinkerton was the only non-employee director that participated in the NQDC Plan in 2013. Participating directors 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 directly or indirectly a participant’s earnings under the NQDC Plan. During 2013, earnings on Mr. Pinkerton’s account under the NQDC Plan did not exceed 120% of the applicable long-term federal rate (2.60%). As a result, 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 2013 are included in the Director Compensation Table below. For additional information on the NQDC Plan, see “Compensation Discussion and Analysis--Overview of 2013 Executive Compensation Components and Decisions-Retirement and Benefit Plans-Deferred Compensation Plan” and the narrative preceding the “Nonqualified Deferred Compensation Table.”

Unit Ownership and Retention Policy for Directors

Effective October 2013, our non-employee directors and Mr. Jennings became subject to a new unit ownership and retention policy. Pursuant to the unit ownership and retention policy, each subject 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. Each subject director is required to meet the applicable requirements within five years of first being subject to the policy.

Subject directors are also required to continuously own sufficient units to meet the unit ownership and retention requirements once attained. Until directors attain compliance with the unit ownership and retention policy, the directors will be required to hold 25% of the units received from any equity award. If a director attains compliance with the unit ownership and retention policy and

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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, 2013, all of our subject directors were in compliance with the unit ownership and retention policy.

Anti-Hedging and Anti-Pledging Policy

The directors of HLS 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 2013 by each of the non-employee directors of HLS.

Name (1)
 
Fees Earned or Paid in Cash
 
Unit Awards (2)
 
All Other Compensation
 
Total
Charles M. Darling, IV
 
$
93,000

 
$
75,020

 
$
—

 
$
168,020

William J. Gray
 
$
83,000

 
$
75,020

 
$ 32,231 (3)

 
$
190,251

Jerry W. Pinkerton
 
$
88,000

 
$
75,020

 
$
—

 
$
163,020

P. Dean Ridenour
 
$
71,000

 
$
75,020

 
$
—

 
$
146,020

William P. Stengel
 
$
93,000

 
$
75,020

 
$
—

 
$
168,020

James G. Townsend
 
$
76,000

 
$
75,020

 
$
—

 
$
151,020


(1)
Messrs. Clifton and Jennings are not included in this table because they received no additional compensation for their services as directors of HLS since, during 2013, Mr. Clifton was an officer of HLS and Mr. Jennings was an officer of HFC. The compensation paid by us to Mr. Clifton in 2013 is shown under “Summary Compensation Table” below and the compensation paid by HFC to Mr. Jennings in 2013 will be shown in HFC’s 2014 Proxy Statement.
    
(2)
Reflects the aggregate grant date fair value of restricted units granted to the non-employee directors on August 1, 2013, 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, 2013, for a discussion of the assumptions used in determining the FASB ASC Topic 718 grant date fair value of these awards. Each of the non-employee directors received an award of 1,981 restricted units under the Long-Term Incentive Plan on August 1, 2013 that will vest on August 1, 2014. As of December 31, 2013, these are the only restricted units held by our non-employee directors.

(3)
Represents fees for consulting services provided by Mr. Gray to HFC during 2013. 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, 2013. In January 2014, the Partnership became aware that, due to an administrative error, a Form 4 that was timely filed on January 2, 2009 by Mr. Shaw incorrectly reported that Mr. Shaw had forfeited 535 units (prior to the adjustment for the unit split that occurred on January 16, 2013) in connection with the vesting of a portion of his restricted units. The Form 4 should have reported that Mr. Shaw forfeited 433 units (prior to the adjustment for the unit split that occurred on January 16, 2013) in connection with the vesting of a portion of his restricted units.



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Item 11.
Executive Compensation

Executive Officers

The following sets forth information regarding the executive officers of HLS as of February 14, 2014:

Name
Age
Position with HLS
Matthew P. Clifton
62
Executive Chairman
Michael C. Jennings
48
Chief Executive Officer
Bruce R. Shaw
46
President
Douglas S. Aron
40
Executive Vice President and Chief Financial Officer
Denise C. McWatters
54
Senior Vice President, General Counsel and Secretary
Mark T. Cunningham
54
Senior Vice President, Operations
Scott C. Surplus
54
Vice President and Controller

Information regarding Messrs. Clifton and Jennings is included above under “Directors.” Effective February 28, 2014, Mr. Clifton will serve as Chairman of the Board in a non-employee capacity.

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 and 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.

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 until April 2008 and as Vice President, General Counsel and Secretary 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.

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.


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Scott C. Surplus was appointed Vice President and Controller in June 2008. Mr. Surplus also served in a similar capacity for HFC through June 2012. He served Holly Corporation and HLS as Vice President, Risk Management from 2007 to 2008, Vice President, Financial Reporting from 2005 to 2007 and Vice President and Controller from 2004 to 2005. Prior to this, he served in many areas of accounting and finance during his 29 years at Holly Corporation (and HFC), including SEC and financial reporting, tax, treasury, and risk management.

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 2013, to the extent the Compensation Committee of the Board (the “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 for compensation expenses.

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, 2013, HLS utilized 257 people employed by HFC to provide general, administrative and operational services to us. Certain executive officers of HLS are also officers of HFC or provide services to HFC.

For 2013, the “Named Executive Officers” of HLS were as follows:

Name
Position with HLS
Matthew P. Clifton
Chairman of the Board and Chief Executive Officer (1)
Douglas S. Aron
Executive Vice President and Chief Financial Officer
Bruce R. Shaw
President
Mark T. Cunningham
Senior Vice President, Operations
Scott C. Surplus
Vice President and Controller

(1)
Mr. Clifton served in this position through the end of day on December 31, 2013. Effective January 1, 2014, Mr. Clifton was appointed Executive Chairman of HLS and Mr. Jennings was appointed Chief Executive Officer of HLS. Effective February 28, 2014, Mr. Clifton will serve as Chairman of the Board of HLS in a non-employee capacity.

Effective January 1, 2013, Mr. Clifton retired from HFC, and Mr. Shaw resigned from HFC. During 2013, Messrs. Clifton, Shaw and Cunningham spent all of their professional time managing our business and affairs. Mr. Surplus devoted a portion of his professional time to overseeing the risk management and insurance practices of HFC. Mr. Aron also served as an executive officer of HFC and devoted only as much of his professional time as was necessary to oversee the management of our business and affairs.

Under the terms of the Omnibus Agreement, we currently pay an annual administrative fee to HFC of $2,300,000 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 the personnel employed by HFC who perform services for us on behalf of HLS. 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.

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In 2013, compensation decisions for Messrs. Clifton, Shaw, Cunningham and Surplus were made by the 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. Clifton, Shaw, Cunningham and Surplus with awards under our Long-Term Incentive Plan. All compensation provided to Messrs. Clifton, Shaw, Cunningham and Surplus for 2013 is discussed and reported, in accordance with SEC rules, in the narratives and tables that follow.

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

The compensation for the services performed for us by Mr. Aron 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 Mr. Aron for 2013 is allocated to the services he performed for us during 2013. The allocation was made based on the assumption that Mr. Aron spent, in the aggregate, approximately 20% of his professional time in 2013 on our business and affairs. As a result, for Mr. Aron, only 20% of the total amount of compensation he received from HFC for 2013 is disclosed in the tables that follow. Because HFC made all decisions regarding the compensation paid to Mr. Aron, those decisions are not discussed in this compensation discussion and analysis. The total compensation paid by HFC to Mr. Aron in 2013 will be disclosed in HFC’s 2014 Proxy Statement.

The 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 HFC’s employees generally, and such benefits are sponsored and administered entirely by HFC without input from HLS or the Committee. The pension and retirement benefits provided to Messrs. Clifton, Shaw, Cunningham and Surplus are described below. The costs of these benefits for the Named Executive Officers (other than Mr. Aron) 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 Committee balances the use of both cash and equity compensation in the total direct compensation package provided to Messrs. Clifton, Shaw, Cunningham and Surplus; however, the Committee has not adopted any formal policies for allocating their compensation among salary, bonus and long-term equity compensation.

In the fourth quarter of 2012 and the first quarter of 2013, the Committee, with the assistance of the Chief Executive Officer (other than with respect to his own compensation), reviewed the mix and level of cash and long-term equity incentive compensation for the Named Executive Officers (other than Mr. Aron) with a goal of providing sufficient current, competitive compensation to retain each of them, while at the same time providing each of 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 Committee believes that the 2013 compensation paid to Messrs. Clifton, Shaw, Cunningham and Surplus reflects an appropriate allocation of compensation between salary, bonus and equity compensation.

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

The Committee has engaged Frederic W. Cook & Co. (the “Compensation Consultant” or “FWC”), an outside consulting firm specializing in executive compensation, to advise the Committee on matters related to executive and non-employee director compensation and long-term equity incentive awards. The Compensation Consultant provides the 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 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 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 Committee

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prior to the Committee meetings at which salaries and fees are approved, bonuses are awarded and equity compensation or awards are established for the upcoming year.

Review of Market Data

Market pay levels are one of many factors considered by the Committee in setting compensation for the Named Executive Officers. The 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 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 as the Liquid Pipeline Roundtable Compensation Survey) and SEC filings of publicly traded companies that the Compensation Consultant and we 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 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 2013 compensation was unchanged from 2012 and 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.
Magellan Midstream Partners, L.P.
Buckeye Partners, L.P.
MarkWest Energy Partners, L.P.
Copano Energy, L.L.C.
NuStar Energy L.P.
Crosstex Energy, L.P.
Regency Energy Partners, L.P.
DCP Midstream Partners L.P.
Sunoco Logistics Partners L.P.
Genesis Energy, L.P.
Targa Resources Partners, L.P.
Inergy L.P.
 

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. We, following advice from the Compensation Consultant, consider our salary and non-salary compensation components in comparison to the median compensation levels 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 2013, the total direct compensation (including both cash and equity components) paid to Messrs. Clifton, Shaw, Cunningham and Surplus 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.

The market range of various compensation elements paid by HFC to Mr. Aron in 2013 will be discussed in further detail within the “Compensation Discussion and Analysis” section of HFC’s 2014 Proxy Statement.

Role of Named Executive Officers in Determining Executive Compensation

In making executive compensation decisions, the 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 Committee also considered recommendations by the Chief Executive Officer (other than as to himself) and other factors in determining the appropriate final compensation factors.

Various members of management facilitate the Committee’s consideration of compensation for Named Executive Officers by providing data for the 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 Committee with guidance as to how such data impacts performance goals set by the Committee during the previous year. When management considers a discretionary bonus to be appropriate, it will suggest an amount and provide the Committee with management’s rationale for such bonus. Given the day-to-day familiarity that management has with the work performed, the Committee values management’s recommendations, although no Named Executive Officer has authority to determine or comment on compensation decisions directly related to himself. The Committee makes the final decision as to the compensation of the Named Executive Officers (other than Mr. Aron).

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Overview of 2013 Executive Compensation Components and Decisions

In 2013, all compensation decisions for Messrs. Clifton, Shaw, Cunningham, and Surplus were made by the Committee. The components of compensation actually received by our Named Executive Officers (other than Mr. Aron, whose compensation was determined by HFC and not by the Committee) in 2013 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
Perquisites
Matthew P. Clifton
x
 
x
x
x
x
Bruce R. Shaw
x
x
x
x
x
x
Mark T. Cunningham
x
x
x
x
x
 
Scott C. Surplus
x
x
x
x
x
 

Each of these components is described in further detail in the narrative that follows. The Committee determined that the amount of, and the special terms regarding performance objectives and levels included in, the performance unit awards granted to Mr. Clifton in March 2013, fully compensated Mr. Clifton for exceptional performance during 2013 and hence that no bonus would be paid to him for 2013 services under our Annual Incentive Plan.

Base Salary

In the fourth quarter of 2012 and the first quarter of 2013, the Committee conducted its annual review of base salaries for the Named Executive Officers (other than Mr. Aron, whose base salary determinations will be discussed in further detail within the “Compensation Discussion and Analysis” section of HFC’s 2014 Proxy Statement.). For Messrs. Clifton, Shaw, Cunningham and Surplus, the Committee considered each of their respective positions, level of responsibility and performance in 2012. The Committee also reviewed competitive market data relevant to each individual’s position provided by the Compensation Consultant. Prior to 2013, the Committee did not make base salary decisions for Messrs. Clifton, Shaw or Surplus but, following a review of the various factors listed above, the Committee set 2013 base salaries for Messrs. Clifton, Shaw, and Surplus at the level it determined to be appropriate to retain the services of these officers. In addition, the Committee determined that an increase in Mr. Cunningham’s base salary was warranted for 2013 based on his performance in 2012, his increasing level of responsibility resulting from the growth of HEP and the compensation being paid by our peers for comparable positions. The following table sets forth the 2013 base salaries for Messrs. Clifton, Shaw, Cunningham and Surplus:

Name and Title
2013
Base Salary (1)
Percentage Increase from 2012 (2)
Matthew P. Clifton
$250,000
—

Bruce R. Shaw
$450,000
—

Mark T. Cunningham
$270,000
12.5%

Scott C. Surplus
$250,000
—

  
(1)
Represents salaries effective January 1, 2013, except for Mr. Surplus. Mr. Surplus’s salary was effective as of February 4, 2013.

(2)
Mr. Cunningham’s 2012 annual base salary rate was $240,000. Salaries paid to Messrs. Clifton, Shaw and Surplus in 2012 were determined and paid by HFC.

Annual Incentive Cash Bonus Compensation

The Board adopted the HLS Annual Incentive Plan (the “Annual Incentive Plan”) in August 2004 to motivate employees of HLS and its affiliates who perform services for HLS and us to produce outstanding results, encourage superior performance, increase productivity, contribute to our and HLS’s health and safety goals, and aid in attracting and retaining key employees. The 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 Committee of achievement of the performance metrics for the applicable performance periods.


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In the fourth quarter of 2012, the Committee approved target awards under the Annual Incentive Plan for 2013. In the first quarter of 2013, the Committee determined that the applicable performance period for the Annual Incentive Plan awards would be the 12-month period beginning October 1, 2012 and ending September 30, 2013, with determination and payment of the cash bonus amounts occurring in the fourth quarter of 2013.

The 2013 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.

•
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 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 Committee, result in a decrease in a bonus. The 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 Committee believes additional compensation is warranted to reward an executive for outstanding performance, the 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 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, Cunningham and Surplus for 2013, and the portion of their target award opportunity allocated to each performance metric. In determining the annual bonus award opportunities for 2013, the Committee considered the amount of, and the special terms regarding performance objectives and levels included in, the performance unit awards granted to Mr. Clifton in March 2013, and determined that this award fully compensated Mr. Clifton for exceptional performance during 2013. For this reason, the Committee determined that Mr. Clifton would not receive a cash bonus in 2013. Mr. Aron receives his annual cash incentive compensation from HFC, which will be discussed in further detail within the “Compensation Discussion and Analysis” section of HFC’s 2014 Proxy Statement.


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Allocation Between Performance Metric
               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%
Scott C. Surplus
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 (other than as to himself) to the Committee. The 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 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 2013 performance period, the actual distributable cash flow ($153.93 million) exceeded the budgeted distributable cash flow ($143.09 million) by 7.6%. As a result, the payout on this metric was 122.8%. The following table sets forth the actual payouts to Messrs. Shaw, Cunningham and Surplus for 2013 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
33.8%
34.7%
68.5%
Mark T. Cunningham
24.6%
25.0%
49.6%
Scott C. Surplus
24.6%
20.0%
44.6%
   
Long-Term Incentive Equity Compensation

The Long-Term Incentive Plan was adopted by the Board in August 2004 with the objective of promoting our interests by providing to management, employees and consultants of HLS and its affiliates who perform services for us and our subsidiaries equity incentive compensation awards. 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 amended and restated effective February 10, 2012.

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 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”). Historically, awards were granted annually during the first quarter of each year. Beginning in the fourth quarter of 2013, annual awards will typically be made in the fourth quarter of the year preceding the year to which the award relates. The 2013 annual awards were made in March 2013 and are described immediately below. The 2014 annual awards were made in November 2013 and are described under “-2014 Compensation Decisions-Long-Term Incentive Equity Compensation.”

In determining the appropriate amount and type of long-term equity incentive awards to be granted to the Named Executive Officers each year, the 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 high performance with variable compensation dependent on that performance. The Committee believes this analysis verifies that total equity compensation to Messrs. Clifton, Shaw, Cunningham and Surplus for 2013 is appropriate for the level of responsibility that each of these officers hold. In March 2013, Mr. Clifton received performance units, Messrs. Shaw and Cunningham received both restricted units and performance units and Mr. Surplus received restricted units under our Long-Term Incentive Plan.


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Restricted Unit Awards

A restricted unit award is an award of common units that are subject to a risk of forfeiture. In March 2013, Messrs. Shaw, Cunningham and Surplus were the only executive officers who were granted restricted units. The following table sets forth the number of restricted units awarded in March 2013 to Messrs. Shaw, Cunningham and Surplus:

Name
Number of Restricted Units
Bruce R. Shaw
6,732
Mark T. Cunningham
5,049
Scott C. Surplus
6,732

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 March 2013 vest in three equal annual installments as noted in the following table and will be fully vested and nonforfeitable after December 15, 2015:

Restricted Unit Vesting Criteria
Vesting Date (1)
Cumulative Amount of Restricted Units Vested
Immediately following December 15, 2013
1/3
Immediately following December 15, 2014
2/3
Immediately following December 15, 2015
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.”

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. In March 2013, Messrs. Clifton, Shaw and Cunningham were the only executive officers who were granted performance units. Performance units are settled only upon the attainment of pre-established performance targets, which may include the achievement of specified financial objectives determined by the Committee. The Committee also approves the period over which the performance targets must be attained in order for performance units to vest. The performance period for the awards began on January 1, 2013 and ends on December 31, 2015. 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.”

Each executive officer that received performance units is granted a target number of performance share units. The target number is initially approved by the 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 performance units granted to Messrs. Clifton, Shaw and Cunningham in March 2013:

Name
Target Number of Performance Units
Matthew P. Clifton
24,474
Bruce R. Shaw
6,731
Mark T. Cunningham
1,683
    
The 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 March 2013. For Mr. Clifton, 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

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“Base Distributable Cash Flow/Unit” and “Incentive Distributable Cash Flow/Unit.” For Messrs. Shaw and Cunningham, 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.”

For Mr. Clifton, 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
0%
Incentive Distributable Cash Flow/Unit
200%

(1)
The percentages above are interpolated between points up to a maximum of 200%. The result is rounded to the nearest whole percentage, but not to a number in excess of 200%.

For Messrs. Shaw and Cunningham, 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%.

We adopted different performance objectives and different performance percentage levels for the performance units awarded to Mr. Clifton as compared to the performance units awarded to Messrs. Shaw and Cunningham because, in his role as Chief Executive Officer, Mr. Clifton is responsible for the entirety of our operations and organizational-wide performance. As a result, we believe it is appropriate for his performance units to be subject to greater performance risk and greater performance reward.


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For the performance units:

Term
What It Means
Achieved Distributable Cash Flow/Unit
Actual Distributable Cash Flow in 2015 adjusted, on an annualized basis, to the extent such adjustment is not reflected in Actual Distributable Cash Flow in 2015, 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 Committee, divided by the number of common units outstanding as of year-end 2015
Base Distributable Cash Flow/Unit
Distributable Cash Flow for 2012 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 Committee, divided by the number of common units outstanding as of year-end 2012
Target Distributable Cash Flow/Unit
Base Distributable Cash Flow/Unit x (100% + WAIA1) x (100% + WAIA2) x (100% + WAIA3)
Incentive Distributable Cash Flow/Unit
For Mr. Clifton: (Base Distributable Cash Flow/Unit) x (100% + (WAIA1 + 5%)) x (100% + (WAIA2 + 5%)) x (100% + (WAIA3 + 5%))

For Messrs. Shaw and Cunningham: (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 incentive equity 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 of long-term incentive equity awards.

Retirement 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 employees of HLS are charged monthly to us in accordance with the terms of the Omnibus Agreement. The terms of these benefit arrangements are described below. Mr. Aron generally participates in the same retirement and welfare benefit arrangements, and information regarding his participation in these arrangements will be described in HFC’s 2014 Proxy Statement.

Defined Contribution Plan

For 2013, all employees of HLS were eligible to participate in the HollyFrontier Corporation 401(k) Retirement Savings Plan, a tax qualified defined contribution plan (the “401(k) Plan”). Employees may contribute amounts from 0% up to a maximum of 75% of their eligible compensation to the 401(k) Plan. Employee contributions that were made on a tax-deferred basis were

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generally limited to $17,500 for 2013, with employees 50 years of age or over able to make additional tax-deferred contributions of $5,500.

In 2013, 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. These employer matching contributions vest immediately. In addition, for 2013, all non-union employees received an employer retirement contribution to the 401(k) Plan ranging from 3% to 8% of the participating employee’s eligible compensation, subject to applicable Internal Revenue Code limits, based on years of service. Employer retirement contributions are subject to a three-year cliff-vesting period.

Except for Mr. Aron, 401(k) Plan benefits for all of the Named Executive Officers were charged to us in 2013 pursuant to the Omnibus Agreement.

Deferred Compensation Plan

In 2013, certain employees of HLS and HFC, including the Named Executive Officers, were eligible to participate in the NQDC Plan. The NQDC Plan provides certain management and other highly compensated employees of HFC and HLS 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.

Eligible employees may 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.

Except for Mr. Aron, NQDC Plan benefits for all of the Named Executive Officers who participate in the NQDC Plan were charged to us in 2013 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”). No additional benefits accrued under the Retirement Plan and Restoration Plan for any participants effective May 1, 2012, and the retirement benefits offered to employees on and after that date are solely provided through defined contribution retirement plans, such as the 401(k) 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, Mr. Clifton participated in the Retirement Plan and the Restoration Plan, and Messrs. Cunningham and Surplus participated in the Retirement Plan. Mr. Shaw formerly was a participant in the Retirement Plan and the Restoration Plan and has a retirement benefit that was frozen in 2007. 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.”


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Messrs. Clifton, Shaw, Cunningham, and Surplus were the only Named Executive Officers whose Retirement Plan and/or Restoration Plan benefits were charged to us in 2013 pursuant to the Omnibus Agreement.

Other Benefits and Perquisites

All full-time employees of HLS, including our executive officers employed by HLS, are eligible to participate in various health and welfare benefit plans, including medical, dental, life insurance, and disability programs, that are sponsored and maintained by HFC. Health and welfare benefits for all of the Named Executive Officers, other than Mr. Aron, were charged to us in 2013 pursuant to the Omnibus Agreement.

It is the Committee’s policy to provide only limited perquisites to our Named Executive Officers. For 2013, the Committee approved a reimbursement by HLS to Mr. Clifton for travel expenses he incurred in his travel to and from Dallas, Texas for business purposes, including attendance at Board and committee meetings. In addition, for security reasons as a result of our increased size and value, we reimburse Messrs. Clifton and Shaw up to $9,500 per year for any out-of-pocket expenses related to security training, consulting or technology. Neither Mr. Clifton nor Mr. Shaw elected to utilize the security perquisite in 2013.

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. The material terms of, and the quantification of, the potential amounts payable under the Change in Control Agreements currently in effect with the 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 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 Messrs. Clifton, Shaw and Surplus, 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 a Change in Control Agreement with Mr. Aron, the costs of which are fully borne by HFC. Mr. Aron’s Change in Control Agreement was in effect during 2013. The HFC Change in Control Agreement is triggered only upon a change in control of HFC, and the terms of the HFC Change in Control Agreement will be described in HFC’s 2014 Proxy Statement.

Unit Ownership and Retention Policy for Executives

The Board, the 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 Committee recommended, and the Board approved, a new unit ownership and retention policy, which increased the retention requirements for Messrs. Clifton and Shaw and subjected Messrs. Cunningham and Surplus to retention requirements.

Pursuant to the unit ownership and retention policy, each Named Executive Officer specified below is required to hold common units equal in value to the following:

Executive Officer
Value of Units
Matthew P. Clifton (1)
3x Base Salary
Bruce R. Shaw
2x Base Salary
Mark T. Cunningham
1x Base Salary
Scott C. Surplus
1x Base Salary

(1) Effective February 28, 2014, Mr. Clifton will be subject to the unit retention requirement for directors set forth under "Directors Compensation - Unit Ownership and Retention Policy for Directors."


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Each 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, 2013, all of our Named Executive Officers listed above were in compliance with the unit ownership and retention policy.

Anti-Hedging and Anti-Pledging Policy

The employees of HLS, including our Named Executive Officers, are subject to the HEP Insider Trading Policy, which, among other things, prohibits such employees from entering into short sales or hedging or pledging our common units and HFC common stock.

Tax and Accounting Implications

We account for the equity compensation expense for our employees and executive officers, including the Named Executive Officers, 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 the Named Executive Officers. Accordingly, the Committee does not consider its impact in determining compensation levels. The Committee has taken into account the tax implications to us in its decision to grant long-term 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 canceled, repurchased and/or recouped to the extent required by applicable law or any clawback policy that we adopt. The Committee will evaluate the practical, administrative and other implications of adopting, implementing and enforcing a clawback policy.

2014 Compensation Decisions

Mr. Clifton retired from his position as Chief Executive Officer of HLS effective at the end of day on December 31, 2013, and was appointed as Executive Chairman of HLS, effective January 1, 2014. Mr. Jennings was appointed as Chief Executive Officer of HLS, also effective January 1, 2014. Effective February 28, 2014, Mr. Clifton will serve as Chairman of the Board of HLS in a non-employee capacity. In his capacity as Executive Chairman (and, effective February 28, 2014, as Chairman of the Board), Mr. Clifton receives compensation for his 2014 service as a member of the Board that is in the same amount as the compensation paid to non-employee directors generally and also for 2014 receives an aggregate annual amount equal to $125,000 (paid in the form of salary during the period he serves as Executive Chairman and in the form of a quarterly cash retainer during the period he serves as Chairman of the Board). Mr. Jennings also serves as an executive officer of HFC, and HFC makes all decisions regarding the compensation paid to Mr. Jennings. Additional information regarding his compensation will be disclosed in HFC’s 2014 Proxy Statement.

Long-Term Incentive Equity Compensation

In the fourth quarter of 2013, the Committee decided to change the timing of its annual grants of long-term equity awards. Specifically, the 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 preceding year, rather than in the first quarter of 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 executive officers who are compensated by us. As a result of the change in timing of the award grants, Messrs. Clifton, Shaw and Cunningham received two long-term equity incentive award grants during 2013: (i) the March 2013 grants, which are the annual grants for the 2013 year, and (ii) the November 2013 grants, which are the annual grants for the 2014 year. The amount of the long-term equity incentive awards Messrs. Shaw and Cunningham received in November 2013 was determined using the same considerations the Committee would have used had the awards been granted in the first quarter of 2014 pursuant to our historic practice. The amount of restricted units Mr. Clifton received in November 2013 was equal to $75,000 on the date of grant, with

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the number of restricted units rounded up to the nearest whole unit in the case of fractional units, which is the same as the annual equity award received by non-employee directors. Further, while the Committee determined to accelerate the time when it would grant annual awards for each fiscal year to November of the prior year, the vesting dates for annual awards will remain the same as if the awards had been granted in March of the year to which such awards relate (except as described below for Mr. Clifton).

Restricted Unit Awards

In November 2013, Messrs. Clifton, Shaw and Cunningham were the only executive officers who were granted restricted units. The following table sets forth the number of restricted units awarded to each of them in November 2013:

Name
Number of Restricted Units
Matthew P. Clifton
2,468

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 to Mr. Clifton in November 2013 contain special vesting provisions similar to those that apply to the restricted units awarded to HLS’s non-employee directors. These restricted units will fully vest on December 15, 2014.

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.”

Performance Unit Awards

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. The target number of performance units granted to each executive officer that received performance units in November 2013 was determined in the same manner as the March 2013 performance unit awards described above. The following table sets forth the target performance units granted to Messrs. Shaw and Cunningham in November 2013:

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

The 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. For Messrs. Shaw and Cunningham, the actual number of units earned at the end of the performance period is based on the Achieved Distributable Cash Flow/Unit as

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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 by Messrs. Shaw and Cunningham will be calculated in the same manner as the performance unit awards granted in March 2013, as adjusted to reflect the applicable performance period for the 2014 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 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

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
Matthew P. Clifton Chairman of the Board and Chief Executive Officer (7)
2013
$
250,000

-

$
1,075,035

-

-

$
209,007

$
1,534,042

2012
-

-

$
1,434,995

-

-

-

$
1,434,995

2011
-

-

$
588,501

-

-

-

$
588,501

Douglas S. Aron
Executive Vice President and Chief Financial Officer (8)
2013
$
530,000

-

-

$
124,850

-

-

$
654,850

2012
$
261,350

-

-

-

-

-

$
261,350

2011
-

-

-

-

-

-

-

Bruce R. Shaw
President
2013
$
450,000

$
156,335

$
1,200,172

$
151,965

-

$
96,069

$
2,054,541

2012
$
400,707

-

-

-

-

-

$
400,707

2011
-

-

$
93,770

-

-

-

$
93,770

Mark T. Cunningham
Senior Vice President - Operations
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

2011
$
210,344

$
71,250

$
180,024

$
58,750

$
64,673

$
12,600

$
597,641

Scott C. Surplus
Vice President and Controller (9)
2013
$
249,217

$
50,000

$
275,070

$
61,400

-

$
139,803

$
775,490



(1)
As a result of certain changes to our grant timing practices adopted by the Committee during the fourth quarter of 2013, Messrs. Clifton, Shaw and Cunningham received two grants of long-term equity incentive awards during 2013-(a) one for

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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. Clifton, Shaw and Cunningham for 2013 is overstated. See note 3 to the Summary Compensation Table for additional information.

(2)
Amounts in this column reflect 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 2013, includes a special one-time true-up amount paid to Mr. Shaw ($39) and Mr. Cunningham ($88) in order that the total amount received by each of them in 2013 under our Annual Incentive Plan (including the amounts reported in the “Non-Equity Incentive Plan Compensation” column) would be rounded to the nearest hundred dollar amount.
(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, 2013 for a discussion of the assumptions used in determining the FASB ASC Topic 718 grant date fair value of these awards.

As described in greater detail above under “Compensation Discussion and Analysis - 2014 Compensation Decisions - Long-Term Incentive Equity Compensation,” as a result of certain changes to our grant timing practices adopted by the Committee during the fourth quarter of 2013, Messrs. Clifton, Shaw and Cunningham received two grants of long-term equity incentive awards during 2013-(a) one for the 2013 year, granted in March 2013 (the “2013 Award”), and (b) one for the 2014 year, granted in November 2013 (the “2014 Award”). Because the 2014 Award was granted during 2013, it is reported in the “Unit Awards” column of the Summary Compensation Table for 2013 rather than 2014, in accordance with SEC rules. However, this reporting requirement overstates the amount of compensation awarded to Messrs. Clifton, Shaw and Cunningham for the 2013 service period. The chart below shows the portion of the dollar amounts reported in the “Unit Awards” column above for 2013 that are attributable to the 2013 Awards only, and the total aggregate annual compensation received by each Named Executive Officer that would have been reported in the “Total” column of the Summary Compensation Table above if the 2014 Awards were not required to be included as 2013 compensation:
 
2013 Award (March 2013)
 
Name
Restricted Stock
Performance Share Units (1)
Aggregate Total Compensation
Matthew P. Clifton
-

$
1,000,008

$
1,459,015

Bruce R. Shaw
$
275,070

$
275,029

$
1,404,468

Mark T. Cunningham
$
206,302

$
68,767

$
776,869


(1) The amounts listed are based on a probable payout percentage of 100%.

With respect to performance units awarded in March 2013, the amounts in the Summary Compensation Table are based on a probable payout percentage of 100%. If the performance units granted in March 2013 are paid out at the maximum payout level of 200% for Mr. Clifton, the grant date fair value of Mr. Clifton’s 2013 award of performance units would be $2,000,015. If the performance units granted in March 2013 are paid out at the maximum payout level of 150% for Messrs. Shaw and Cunningham, the grant date fair value of their 2013 award of performance units would be as follows: Mr. Shaw, $412,543 and Mr. Cunningham, $103,151.

With respect to performance units awarded in November 2013, the amounts in the Summary Compensation Table are based on a probable payout percentage of 100%. If the performance units granted in November 2013 are paid out at the maximum payout level of 150% for Messrs. Shaw and Cunningham, the grant date fair value of their 2014 award of performance units would be as follows: Mr. Shaw, $487,555 and Mr. Cunningham, $103,147.

The terms of the March 2013 performance unit awards and the March 2013 restricted unit awards are described above under “Compensation Discussion and Analysis - Overview of 2013 Executive Compensation Components and Decisions - Long-Term Incentive Equity Compensation.” The terms of the November 2013 performance unit awards and the November 2013 restricted unit awards are described under “Compensation Discussion and Analysis - 2014 Compensation Decisions - Long-Term Incentive Equity Compensation.” For additional information on outstanding restricted unit and performance unit awards,

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see below under “Outstanding Equity Awards at Fiscal Year End.” No forfeitures of equity awards held by the Named Executive Officers occurred in 2013.

On a going forward basis, annual equity awards will be made once each year in the fourth quarter of the year preceding the year to which the annual 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.
 
(4) Amounts in this column reflect 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 2013 bonus amounts under our Annual Incentive Plan are described above in greater detail under “Compensation Discussion and Analysis-Overview of 2013 Executive Compensation Components and Decisions-Annual Incentive Cash Bonus Compensation.” See note 8 to the Summary Compensation Table for a discussion of the amounts reported as "Non-Equity Incentive Plan Compensation" for Mr. Aron.
(5) For 2013, no amounts are reported with respect to the Retirement Plan, which was liquidated in June 2013. In addition, no amounts are reported with respect to the Restoration Plan, since the aggregate change in the actuarial present value of Mr. Clifton’s and Mr. Shaw’s accumulated benefits under the Restoration Plan was negative. Specifically, the change in the actuarial present value of Mr. Clifton’s accumulated benefit in the Restoration Plan was $(44,587) and the change in the actuarial present value of Mr. Shaw’s accumulated benefit in the Restoration Plan was $(630).

During 2013, earnings on the Named Executive Officers’ NQDC Plan accounts did not exceed 120% of the applicable long-term federal rate (2.60%). As a result, no above market or preferential earnings were paid to the Named Executive Officers and, therefore, none of the earnings received by the Named Executive Officers under the NQDC Plan during 2013 are included in this table.

(6)
For 2013, includes the compensation as described under “All Other Compensation” below.

(7)
Mr. Clifton retired as Chief Executive Officer effective at the end of day on December 31, 2013 and was appointed to serve as Executive Chairman of HLS effective January 1, 2014. Effective February 28, 2014, Mr. Clifton will serve as Chairman of the Board of HLS in a non-employee capacity.

(8)
During 2013, Mr. Aron split his professional time between HFC and us, and all compensation paid to him for 2013 was determined and paid by HFC. In accordance with SEC rules, a portion of the total compensation paid by HFC to Mr. Aron for 2013 is allocated to the services he performed for us during 2013. The allocation was made based on the assumption that Mr. Aron spent, in the aggregate, approximately 20% of his professional time in 2013 on our business and affairs. As a result, for Mr. Aron, only 20% of the total amount of compensation he received from HFC for 2013 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 2013 (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 2014 Proxy Statement.

(9)
Although Mr. Surplus devoted a portion of his professional time in 2013 to overseeing the risk management and insurance practices of HFC, all 2013 compensation decisions for Mr. Surplus were made by the Committee and we reimbursed HFC for 100% of the compensation expenses incurred by HFC for salary, bonus, retirement and other benefits provided to Mr. Surplus. As a result, all compensation provided to Mr. Surplus for 2013 is discussed and reported, in accordance with SEC rules, in the Summary Compensation Table above and in the narratives and tables that follow.
    
All Other Compensation
The table below describes the components of the compensation included in the “All Other Compensation” column for 2013 in the Summary Compensation Table above.

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Name
401(k) Plan Company Matching Contributions
401(k) Plan Retirement Contribution
NQDC Plan Company Matching Contribution
NQDC Plan Retirement Contributions
Transition Benefit Contribution
Perquisites (1)
Tax Reimbursements (2)
Total
Matthew P. Clifton
$
15,300

$
18,200

$
6,164

$
10,418

$
125,206

$
33,663

$
56

$
209,007

Douglas S. Aron
-

-

-

-

-

-

-

-

Bruce R. Shaw
$
15,300

$
16,575

$
30,150

$
32,662

-

-

$
1,382

$
96,069

Mark T. Cunningham
$
15,300

$
13,388

$
8,893

$
7,781

$
51,000

-

$
1,538

$
97,900

Scott C. Surplus
$
15,300

$
18,200

$
6,343

$
10,657

$
89,250

-

$
53

$
139,803


(1)
For Mr. Clifton, includes reimbursement of travel expenses to and from Dallas, Texas for business purposes.

(2)
For Messrs. Clifton and Surplus, represents reimbursements for taxes owed on the portion of the retirement contributions made on behalf of Messrs. Clifton and Surplus to the NQDC Plan and that would have otherwise been made to the 401(k) Plan had Messrs. Clifton and Surplus not exceeded the Internal Revenue Service limits on contributions to the 401(k) Plan.

For Mr. Shaw, represents tax payments made for business travel on HFC’s aircraft that had a personal element.
For Mr. Cunningham, represents tax payments made on family travel on HFC’s aircraft for business purposes.

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 2013. In this table, awards are abbreviated as “AICP” for the annual incentive cash awards under our Annual Incentive Plan, as “RUA” for restricted unit awards, and as “PUA” for performance unit awards. In 2013, awards of performance units and restricted units were issued under our Long-Term Incentive Plan. Mr. Aron did not receive any plan-based awards from us during 2013.

As described in greater detail above under “Compensation Discussion and Analysis - 2014 Compensation Decisions - Long-Term Incentive Equity Compensation,” as a result of certain changes to our grant timing practices adopted by the Committee in the fourth quarter of 2013, Messrs. Clifton, 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. On a going forward basis, annual equity awards will be made once each year in the fourth quarter of the year preceding the year to which the annual 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.


 
Type
Committee Action Date
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)
Matthew P. Clifton
PUA
02/05/2013
03/01/2013
 
 
 
-
$24,474
$48,948
 
$1,000,008
 
RUA
11/22/2013
11/22/2013
 
 
 
 
 
 
$2,468
$75,027 (5)
Douglas S. Aron
-
 
 
 
 
 
 
 
 
 
 
Bruce R. Shaw
AICP
 
 
-
$123,750
$247,500
 
 
 
 
 
 
PUA
02/05/2013
03/01/2013
 
 
 
$3,366
$6,731
$10,097
 
$275,029
 
 
11/22/2013
11/22/2013
 
 
 
$5,346
$10,692
$16,038
 
$325,037 (5)
 
RUA
02/05/2013
03/01/2013
 
 
 
 
 
 
$6,732
$275,070
 
 
11/22/2013
11/22/2013
 
 
 
 
 
 
$10,692
$325,037 (5)
Mark T. Cunningham
AICP
 
 
-
$54,000
$108,000
 
 
 
 
 
 
PUA
02/05/2013
03/01/2013
 
 
 
$842
$1,683
$2,525
 
$68,767
 
 
11/22/2013
11/22/2013
 
 
 
$1,131
$2,262
$3,393
 
$68,765 (5)
 
RUA
02/05/2013
03/01/2013
 
 
 
 
 
 
$5,049
$206,302
 
 
11/22/2013
11/22/2013
 
 
 
 
 
 
$6,786
$206,294 (5)
Scott C. Surplus
AICP
 
 
-
$50,000
$100,000
 
 
 
 
 
 
RUA
02/05/2013
03/01/2013
 
 
 
 
 
 
$6,732
$275,070

(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 2013 Executive Compensation Components and Decisions - Annual Incentive Cash Bonus Compensation.” Amounts reported do not include amounts potentially payable pursuant to the discretionary individual

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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 2013, and the amount actually paid with respect 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 2013.
(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 are described above under “Compensation Discussion and Analysis - Overview of 2013 Executive Compensation Components and Decisions - Long-Term Incentive Equity Compensation - Performance Unit Awards” and “Compensation Discussion and Analysis - 2014 Compensation Decisions - Long-Term Incentive Equity Compensation - Performance Unit Awards.”
(3)
Represents awards of restricted units. The terms of the restricted unit awards are described above under “Compensation Discussion and Analysis - Overview of 2013 Executive Compensation Components and Decisions - Long-Term Incentive Equity Compensation - Restricted Unit Awards” and “Compensation Discussion and Analysis - 2014 Compensation Decisions - Long-Term Incentive Equity Compensation - Restricted Unit Awards.”
(4)
Represents the grant date fair value determined pursuant to FASB ACS Topic 718, based on a closing price of our common units of $40.86 on March 1, 2013 and $30.40 on November 22, 2013. The value of performance units granted on March 1, 2013 and November 22, 2013 each reflect a probable payout percentage of 100%.
(5)
The awards reported on these lines are awards for the 2014 service period and result from the Committee’s decision to change its grant timing practices, as described in greater detail above under “Compensation Discussion and Analysis - 2014 Compensation Decisions - Long-Term Incentive Equity Compensation.” If the Committee had not decided to change the time it makes annual grants to the prior year, these awards would have been granted in 2014 and been reflected as 2014 compensation.

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, 2013, including awards that were granted prior to 2013. The value of these awards was calculated based on a price of $32.33 per unit, the closing price of our common units on December 31, 2013. Mr. Aron does 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 (2)
Equity Incentive Plan Awards: Market or Payout Value of Unearned Units or Other Rights That Have Not Vested
Matthew P. Clifton
RUA
13,904

$
449,516

 
 
PUA
 
 
66,102
$
2,137,078

Douglas S. Aron
-
-

-

-
-

Bruce R. Shaw
RUA
15,180

$
490,769

 
 
PUA
 
 
26,135
$
844,945

Mark T. Cunningham
RUA
12,875

$
416,249

 
 
PUA
 
 
5,918
$
191,329

Scott C. Surplus
RUA
4,488

$
145,097

-
-


(1)
Includes the following restricted unit awards granted by us:
•
in March 2012 to Mr. Clifton (34,308) and Mr. Cunningham (8,170), of which one third vested on December 15, 2012, one third vested on December 15, 2013 and the remaining one third vests on December 15, 2014;

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•
in March 2013 to Mr. Shaw (6,732), Mr. Cunningham (5,049) and Mr. Surplus (6,732), of which one third vested on December 15, 2013, one third vests on December 15, 2014 and the remaining one third vests on December 15, 2015; and
•
in November 2013 to Mr. Clifton (2,468), all of which vest on December 15, 2014; and
•
in November 2013 to Mr. Shaw (10,692) and Mr. Cunningham (6,786), of which one third vests on December 15, 2014, one third vests on December 15, 2015 and the remaining one third vests on December 15, 2016.

(2)
Includes the following performance unit awards granted by us (the amounts included in the parentheticals reflect the target number of performance share units subject to each award):
•
in March 2012 to Mr. Clifton (11,436), with a performance period that ends on December 31, 2014;
•
in March 2013 to Mr. Clifton (24,474), Mr. Shaw (6,731) and Mr. Cunningham (1,683), in each case, with a performance period that ends on December 31, 2015; and
•
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.

For the performance units granted in March 2012 to Mr. Clifton, the number of common units payable is determined based on the total increase in our distributable cash flow per common unit for the performance period compared to the baseline distributable cash flow per common unit. Under the terms of the grant, Mr. Clifton may earn from 50% to 150% of the target number of performance units granted to him.
For the performance units granted in March 2013 to Mr. Clifton, the number of common units payable is based on the Achieved Distributable Cash Flow/Unit as compared to the Base Distributable Cash Flow/Unit and Incentive Distributable Cash Flow/Unit. Under the terms of the grant, Mr. Clifton may earn from 0% to 200% of the target number of performance units granted to him.
For the performance units granted in March 2013 and November 2013 to Messrs. Shaw and Cunningham, 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.
See “Overview of 2013 Executive Compensation Components and Decisions - Long-Term Incentive Equity Compensation - Performance Unit Awards” and “Compensation Discussion and Analysis - 2014 Compensation Decisions - Long-Term Incentive Equity Compensation - Performance Unit Awards” for further details.

Option Exercises and Units Vested
The following table provides information regarding the vesting in 2013 of restricted unit and performance unit awards held by the Named Executive Officers. To date, we have not granted any unit options.

The value realized from the vesting of restricted unit and/or performance 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
Matthew P. Clifton
   67,739 (1)
$
2,273,974

Douglas S. Aron
-
-

Bruce R. Shaw
3,292
$
102,809

Mark T. Cunningham
6,418
$
200,434

Scott C. Surplus
2,746
$
85,758



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(1)
Includes (a) 30,149 performance units that became payable to Mr. Clifton on February 5, 2013 upon the determination by the Subcommittee of the Committee that the performance percentage applicable to the target number of 25,124 performance units granted to Mr. Clifton in March 2010 was 120%, (b) an additional 502 performance units that became payable to Mr. Clifton on April 12, 2013 as a result of the finalization of HEP’s 2012 financial statements and a revision to the performance percentage applicable to the target number of performance units granted to Mr. Clifton in March 2010, which increased the performance percentage to 122% from 120%, and (c) 25,652 performance units that became payable to Mr. Clifton on February 5, 2014 upon the determination by the Subcommittee of the Committee that the performance percentage applicable to the target number of 17,938 performance units granted to Mr. Clifton in March 2011 with a performance period that ended on December 31, 2013 was 143%, which performance units are treated, in accordance with SEC rules, as vesting during 2013; the value realized with respect to each of the awards described in clause (a), (b) and (c) above is calculated based on the closing price of our common units on the date of payment.    
   
Pension Benefits Table
Certain of the Named Executive Officers are participants in the Retirement Plan and the Restoration Plan. As of January 1, 2012, participants in the Retirement Plan and the Restoration Plan who are not subject to a collective bargaining agreement, including Named Executive Officers, ceased accruing additional benefits under the plans, and as of May 1, 2012, all participants in these plans ceased accruing additional benefits. Mr. Shaw formerly was an active participant in both plans and has a retirement benefit that was frozen in 2007. 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 in the Retirement Plan 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.”

Retirement Plan
As of June 2013, the Retirement Plan has been liquidated. The amounts set forth in the “Payments During Last Fiscal Year” column in the table below show the amount of retirement benefits paid to each Named Executive Officer (other than Mr. Aron) pursuant to the Retirement Plan liquidation. These amounts were paid in the form of a lump sum distribution, and no Named Executive Officer is owed any additional benefits under the Retirement Plan.
The Retirement Plan was a tax-qualified defined benefit retirement plan. The dollar amount of benefits accrued under the Retirement Plan was based upon a participant’s compensation, age and length of service. An employee’s benefit service was not deemed interrupted if the employee performed services for HFC and later transitioned to work as an HLS employee. Under the Retirement Plan, a participant’s highest average monthly compensation, including base salary or base pay and any quarterly bonuses, during a consecutive 36-month period of employment, is the participant’s “Plan Compensation.” Upon normal retirement following a participant’s attainment of age 65, a participant was entitled under the Retirement Plan to a life annuity with monthly pension payments equal to (i) 1.6% of the participant’s Plan Compensation, multiplied by the participant’s total years of credited benefit service, minus (ii) 1.5% of the participant’s primary Social Security benefit, multiplied by the participant’s total years of credited service (but not to exceed 45% of such Social Security benefits). Accrued benefits under the Retirement Plan were frozen based on pay and service at the close of business on December 31, 2011. The Retirement Plan also provided for benefits upon early retirement (age 50 and at least 10 years of service or age 55 and at least 3 years of service) and late retirement, as well as providing accelerated deferred vested benefits, disability benefits and death benefits. Instead of the normal form of payment, participants could also elect to receive their accrued benefits in the form of a life annuity with a period certain, a contingent annuity or a lump sum.

Benefits up to the limits set by the Internal Revenue Code were funded by contributions to the Retirement Plan, with the annual contribution amounts determined on an actuarial basis. The Internal Revenue Code limits the annual benefits that can be paid from, as well as the compensation that can be taken into account in computing benefits under, pension plans such as the Retirement Plan.

Restoration Plan

The Restoration Plan is an unfunded non-qualified plan that provides supplemental retirement benefits. As of January 1, 2012, participants in the Restoration Plan are no longer accruing additional benefits. Messrs. Clifton and Shaw are the only Named Executive Officers who have accumulated benefits under the Restoration Plan.


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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 our 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). Because Mr. Clifton is over age 50 and has more than 10 years of service, he was eligible for early retirement as of December 31, 2013. His early retirement benefits under the Restoration Plan, potentially payable beginning January 1, 2014, are estimated to be $24,703 per month payable for his lifetime or $3,990,745 payable as a lump sum. A portion of the $24,703 monthly benefit payable to Mr. Clifton under the Restoration Plan is attributable to post-409A benefits and, therefore, will be paid in a lump sum and not as a monthly benefit.

Name
Plan Name
Number of Years Credited Service
Present Value of
Accumulated Benefit
Payments During Last Fiscal Year
Matthew P. Clifton
Retirement Plan
31.17
-

$
1,110,389

Restoration Plan
31.17
$
3,981,242

-

Douglas S. Aron
Retirement Plan
-
-

-

Restoration Plan
-
-

-

Bruce R. Shaw
Retirement Plan
8.25
-

$
126,053

Restoration Plan
8.25
$
8,756

-

Mark T. Cunningham
Retirement Plan
           7.5
-

$
166,032

Restoration Plan
-
-

-

Scott C. Surplus
Retirement Plan
27.08
-

$
943,390

Restoration Plan
-
-

-


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 17 to HFC’s consolidated financial statements for the fiscal year ended December 31, 2013), 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
4.40%

Mortality Table
2013 IRS Prescribed Mortality-Static Annuitant, male and female

Nonqualified Deferred Compensation

In 2013, all of the Named Executive Officers participated in the NQDC Plan. The NQDC Plan functions as a spill-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 2013, the annual deferral contribution limit under the 401(k) Plan was $17,500, and the annual compensation limit was $255,000. 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 2013, 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

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limits under Section 401(k) of the Internal Revenue Code, based on years of service. 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.

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 ($255,000 in 2013), 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. In February 2014, the Transition Benefit Plan was amended to exclude the 2014 annual incentive bonus, if any, for Mr. Clifton in determining the 2014 transition benefit payment since, due to the change in HFC’s timing of annual bonus payments in 2012, Mr. Clifton received two annual incentive bonuses from HFC in 2012, which were taken into account in determining the 2012 transition benefit payment.

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 directly or indirectly a participant’s earnings under the NQDC Plan. During 2013, 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 2013 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 2013. The following table lists the investment options for the NQDC Plan in 2013 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
       32.06%
American Century Mid-Cap Value Instl Fund
30.26%
Buffalo Small Cap Fund
44.15%
Columbia Acorn International Z Fund
22.33%
Columbia Acorn Z Fund
30.90%
Fidelity Contrafund Fund
34.15%
Fidelity Low-Priced Stock Fund
34.31%
Harbor Capital Appreciation Instl Fund
37.66%
LargeCap S&P 500 Index Instl Fund
32.06%
MidCap S&P 400 Index Instl Fund
33.13%
Money Market Inst Fund
-
Oppenheimer Developing Markets Institutional Fund
8.85%
PIMCO Total Return Instl Fund
-1.92%
PIMCO All Asset All Authority Instl Fund
-5.47%
SmallCap S&P 600 Index Instl Fund
40.90%
T. Rowe Price Retirement Income Fund
9.15%
T. Rowe Price Retirement 2005 Fund
9.74%
T. Rowe Price Retirement 2010 Fund
11.93%
T. Rowe Price Retirement 2015 Fund
15.18%
T. Rowe Price Retirement 2020 Fund
18.05%
T. Rowe Price Retirement 2025 Fund
20.78%
T. Rowe Price Retirement 2030 Fund
23.09%
T. Rowe Price Retirement 2035 Fund
24.86%
T. Rowe Price Retirement 2040 Fund
25.93%
T. Rowe Price Retirement 2045 Fund
25.93%
T. Rowe Price Retirement 2050 Fund
25.90%
T. Rowe Price Retirement 2055 Fund
25.86%
Thornburg International Value R6 Fund
15.86%
Vanguard Equity-Income Adm. Fund
30.19%
Vanguard Total Bond Market Index Signal Fund
-2.15%
Vanguard Total Intl Stock Index Signal Fund
15.14%

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.

Non-Qualified Deferred Compensation Table
The NQDC Plan benefits for all the Named Executive Officers (other than Mr. Aron) were charged to us in 2013 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 Mr. Aron) in 2013. Even though Mr. Aron is also a participant in the NQDC Plan, we have not provided any disclosure with respect to his NQDC Plan benefits since those benefits are paid for by HFC. Additional information regarding the NQDC Plan will be provided in HFC’s 2014 Proxy Statement.


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Name
Executive Contributions (1)
Company
Contributions (2)
Aggregate
Earnings
Aggregate
Withdrawals/
Distributions

Aggregate Balance
at December 31, 2013 (3)
Matthew P. Clifton
$
12,981

$
141,788

$
273,422

-
$
3,733,643

Douglas S. Aron
-

-

-

-
-

Bruce R. Shaw
$
27,950

$
62,812

$
61,889

-
$
254,972

Mark T. Cunningham
$
45,472

$
67,673

$
(36,692
)
-
$
193,888

Scott C. Surplus
$
17,871

$
106,251

$
50,378

-
$
227,376


(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 2013.

(2)
These amounts are also included in the “All Other Compensation” column of the “Summary Compensation Table” for 2013.

(3)
The aggregate balance for each Named Executive Officer reflects the cumulative value, as of December 31, 2013, 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. Of the total aggregate balance reported above for Mr. Cunningham, we previously reported (a) $43,840 of employee contributions in the “Salary” column of the Summary Compensation Table for 2012, and (b) $72,280 of employer-provided contributions in the “All Other Compensation” column of the Summary Compensation Table for 2012.

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 2013, all of the Named Executive Officers, other than Mr. Aron, had in effect a Change in Control Agreement with us, in accordance with our Change in Control Policy. We entered into a Change in Control Agreement with Messrs. Clifton, Shaw and Surplus, 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 a Change in Control Agreement with Mr. Aron, which was in effect during 2013. The HFC Change in Control Agreement triggers only upon a change in control of HFC. The terms of the HFC Change in Control Agreement, and a quantification of potential benefits under the Change in Control Agreement with HFC and its named executive officers, including Mr. Aron, will be disclosed in HFC’s 2014 Proxy Statement. Messrs. Clifton, Shaw and Surplus had previously entered into Change in Control Agreements with HFC. In connection with Messrs. Clifton, Shaw and Surplus becoming employees of HLS, their respective Change in Control Agreements with HFC terminated automatically pursuant to its terms.

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 is terminated without “Cause,” leaves voluntarily for “Good Reason,” or is terminated 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 with HLS within 30 days after the termination, then the executive will receive the following cash severance amounts paid by us:

•
a cash payment 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 his 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) 3.0 for Mr. Clifton, (b) 2.0 for Mr. Shaw, and (c) 1.0 for Mr. Cunningham and Mr. Surplus.


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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.

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

Except for the restricted units granted to Mr. Clifton in November 2013, the outstanding long-term equity incentive awards granted under the Long-Term Incentive Plan vest upon a “Special Involuntary Termination”, which occurs when, within 60 days prior to or at any time after a “Change in Control”:


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•
the executive is terminated, other than for “Cause,” or

•
the executive resigns within 90 days following an “Adverse Change.”

All outstanding performance units will vest at 150% in the event of a Special Involuntary Termination, except for the performance units granted to Mr. Clifton in 2013, which will vest at 200% in the event of a Special Involuntary Termination. The restricted units granted to Mr. Clifton in November 2013 vest upon a “Change in Control.”

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 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, except with respect to the performance units granted to Mr. Clifton in 2013, executives will earn and receive payment with respect to no less than 50% of the performance units awarded in 2013). 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 (other than the award agreement for Mr. Clifton’s restricted unit awards granted in November 2013, which does not contain such definition), “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 (in the case of the 2012 and 2013 performance unit awards) or executives (in the case of the 2011 performance unit award).

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For purposes of the long-term equity incentive awards (other than the award agreement for Mr. Clifton’s restricted unit awards granted in November 2013, which does not contain such definition), “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.

Holly Retirement Restoration Plan
The Restoration Plan provides benefits to participants (including Messrs. Clifton and Shaw) in the event of a change in control of HFC. 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 they are 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. Mr. Clifton is a participant in the Restoration Plan, and Mr. Shaw formerly was a participant in the Restoration Plan and has a retirement benefit that was frozen in 2007. 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, 2013. For these purposes, our common unit price was assumed to be $32.33, which was the closing price per unit on December 31, 2013.
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 2013 year was taken prior to December 31, 2013. Because we accrue vacation in any given year for the following year, amounts reported as “Cash Payments” include accrued vacation amounts accrued in 2013 for the 2014 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 settled at the maximum level based on performance through December 31, 2013. 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 2013 vested on December 15, 2013.

•
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) 36 months for Mr. Clifton, (b) 24 months for Mr. Shaw, and (c) 12 months for Mr. Cunningham and Mr. Surplus.

•
In calculating whether any tax reimbursements were owed to the Named Executive Officers, we used the following assumptions: (a)  the excise tax rate under Section 4999 of the Tax Code is 20%, the federal income tax rate is 39.6%, the Medicare rate is 2.35%, the adjustment to reflect the phase-out of itemized deductions is 1.19%, and there are no state or local income taxes, (b) no amounts will be discounted as attributable to reasonable compensation, (c) all cash severance payments are contingent upon a change in control, and (d) the presumption required under applicable regulations that

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the equity awards granted in 2013 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 or 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.
Named Executive Officer

Cash Payments (1)
Value of
Welfare Benefits
Vesting
of Equity Awards 
Total
Matthew P. Clifton    
Termination in connection with or following a Change in Control
$
11,925,088

$
55,477

$
2,586,594

$
14,567,159

Termination due to Death, Disability, Retirement or without Cause
$
—

$
—

$
897,222

$
897,222


Douglas S. Aron

Termination in connection with or following a Change in Control
$
—

$
—

$
—

$
—

Termination due to Death, Disability, Retirement or without Cause
$
—

$
—

$
—

$
—


Bruce R. Shaw

Termination in connection with or following a Change in Control
$
1,669,371

$
36,985

$
1,335,714

$
3,042,070

Termination due to Death, Disability, Retirement or without Cause
$
—

$
—

$
108,790

$
108,790


Mark T. Cunningham

Termination in connection with or following a Change in Control
$
396,410

$
18,492

$
607,610

$
1,022,512

Termination due to Death, Disability, Retirement or without Cause
$
—

$
—

$
27,222

$
27,222


Scott C. Surplus

Termination in connection with or following a Change in Control
$
444,846

$
18,492

$
145,097

$
608,435

Termination due to Death, Disability, Retirement or without Cause
$
—

$
—

$
—

$
—


(1)
For Mr. Clifton, includes (a) $2,404,670, the amount of the Restoration Plan annuity contract (which is equal to benefits otherwise due to Mr. Clifton under the Restoration Plan, reduced by the amount of the Restoration Plan cash payment), and (b) $1,576,572, 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 2013 marginal federal income tax rate of 39.6%).

For Mr. Shaw, includes (a) $5,289, 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) $3,467, 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 2013 marginal federal income tax rate of 39.6%).


- 125 -

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 Committee believes that payment should be 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, which 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-based equity incentives, 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 certain levels 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 14, 2014 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 14, 2014. 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.

Name of Beneficial Owner
Common Units
Percentage of Outstanding Common Units
HollyFrontier Corporation (1)
22,380,030

39.39%
Oppenheimer Funds, Inc. (2)
7,304,915
12.45%
Oppenheimer SteelPath MLP Income Fund (3)
3,241,053

5.53%
Tortoise Capital Advisors, L.L.C. (4)
3,087,132

5.26%
Matthew P. Clifton (5)
248,556

*
Bruce R. Shaw (5)
42,967

*
Douglas S. Aron(6)
2,840

*
Mark T. Cunningham (5)
32,963

*
Scott C. Surplus (5)
17,748

*
Michael C. Jennings
6,000

*
P. Dean Ridenour (7)
63,125

*
Charles M. Darling, IV (7)(8)
42,053

*
William J. Gray (7)
20,551

*
Jerry W. Pinkerton (7)
23,753

*
William P. Stengel (7)(9)
13,537

*
James G. Townsend (7)
17,737

*
All directors and executive officers as group (13 persons) (10)
536,711

*

* 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 2828 N. Harwood, Suite 1300, Dallas, Texas 75201-1507.
(2)
Oppenheimer Funds, Inc. filed with the SEC a Schedule 13G/A, dated February 6, 2014. Based on this Schedule 13G/A, Oppenheimer Funds, Inc. has shared voting power and shared dispositive power with respect to 7,304,915 units. The address of Oppenheimer Funds, Inc. is Two World Financial Center, 225 Liberty Street, New York, NY 10281.
(3)
Oppenheimer SteelPath MLP Income Fund filed with the SEC a Schedule 13G/A, dated February 6, 2014. Based on this Schedule 13G/A, Oppenheimer SteelPath MLP Income Fund has sole voting power and shared dispositive power with

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respect to 3,241,053 units. The address of Oppenheimer SteelPath MLP Income Fund is 2100 McKinney Avenue, Suite 1401, Dallas, TX 75201.
(4)
Tortoise Capital Advisors, L.L.C. filed with the SEC a Schedule 13G on February 11, 2014. Based on this Schedule 13G, Tortoise Capital Advisors, L.L.C. reported that it had sole voting power and sole dispositive power with respect to zero units, and shared voting power and shared dispositive power with respect to 3,087,132 units. The address of Tortoise Capital Advisors, L.L.C. is 11550 Ash St., Suite 300, Leawood, KS 66211.
(5)
The number reported includes restricted units for which the executive has sole voting power but no dispositive power, as follows: Mr. Clifton (13,904 units), Mr. Shaw (15,180 units), Mr. Cunningham (12,875 units) and Mr. Surplus (4,488 units). The number does not include performance units held by Mr. Clifton, Mr. Shaw and Mr. Cunningham.
(6)
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.
(7)
The number reported includes 1,981 restricted units for which the non-management director has sole voting power but no dispositive power.
(8)
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.
(9)
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.
(10)
The number reported includes 46,448 restricted units held by executive officers for which they have sole voting power but no dispositive power and 11,886 restricted units held by non-management 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, 2013:
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)
98,154 (3)
—
1,635,469
 
 
 
 
Equity compensation plans not approved by security holders
—
—
—
 
 
 
 
Total
98,154
 
1,635,469

(1)
All stock-based compensation plans are described in Note 6 to our consolidated financial statements for the fiscal year ended December 31, 2013.

(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 remaining available for future issuance 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 unitholders.

(3)
Represents units subject to performance units granted to (a) Mr. Clifton under the Long-Term Incentive Plan in March 2012 assuming a maximum payout level of 150% at the time of vesting and in March 2013 assuming a maximum payout level of 200% at the time of vesting, and (b) Messrs. Shaw and Cunningham in March 2013 and November 2013 assuming

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a maximum payout level of 150% at the time of vesting. If the performance units granted to Mr. Clifton in 2012 and 2013 and to Messrs. Shaw and Cunningham in 2013 are paid at target, 57,278 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 2013 Executive Compensation Components and Decisions - Long-Term Incentive Equity Compensation.”


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, currently $2.3 million per year, 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. Please read “Omnibus Agreement” 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, currently in the amount of $2.3 million, 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;

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•
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.

Payment of general and administrative services fee
Under the Omnibus Agreement we pay HFC an annual administrative fee, currently in the amount of $2.3 million, 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 or (vii) the UNEV Pipeline. 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.

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.


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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. Following the July 1, 2013 PPI adjustment, HFC's minimum annualized payments to us under these agreements increased by $4.7 million to $225.5 million.

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.

•
Legacy Frontier Tankage and Terminal Transaction – On November 9, 2011, we acquired from HFC certain tankage, loading rack and crude receiving assets located at HFC’s El Dorado and Cheyenne refineries. We paid non-cash consideration consisting of Promissory Notes with an aggregate principal amount of $150 million and 7,615,230 of our common units. We repaid $77.1 million of outstanding principal using proceeds received in our December 2011 common unit offering and existing cash. We repaid the remaining $72.9 million balance in March 2012.

•
See “2012 Acquisition” and “2011 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 $252.4 million, $245.6 million and $168.3 million for the years ended December 31, 2013, 2012 and 2011, 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, 2013, 2012 and 2011, respectively.

•
We reimbursed HFC for costs of employees supporting our operations of $34.6 million, $31.1 million and $21.4 million for the years ended December 31, 2013, 2012 and 2011, respectively.

•
HFC reimbursed us $21.6 million, $13.4 million and $11.9 million for certain reimbursable costs and capital projects for the years ended December 31, 2013, 2012 and 2011, respectively.

•
We distributed $71.4 million, $64.0 million and $40.6 million for the years ended December 31, 2013, 2012 and 2011, respectively, to HFC as regular distributions on its common units, subordinated units and general partner interest, including general partner incentive distributions.


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, 2013 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.


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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 2013 calendar year.
Fees paid to Ernst & Young LLP for 2013 and 2012 are as follows:
 
 
2013
 
2012
 
 
 
 
 
Audit Fees (1)
 
$
669,000

 
$
762,000

Tax Fees
 
287,000

 
117,000

Total
 
$
956,000

 
$
879,000

 
(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
 
(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 135 to 141.



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 24, 2014
 
/s/ Michael C. Jennings
 
 
Michael C. Jennings
 
 
Chief Executive Officer
 
 
 


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 24, 2014
 
/s/ Michael C. Jennings
 
 
Michael C. Jennings
 
 
Chief Executive Officer and Director
 
 
 
Date: February 24, 2014
 
/s/ Bruce R. Shaw
 
 
Bruce R. Shaw
 
 
President
 
 
 
Date: February 24, 2014
 
/s/ Douglas S. Aron
 
 
Douglas S. Aron
 
 
Executive Vice President and Chief Financial Officer
 
 
(Principal Financial Officer)
 
 
 
Date: February 24, 2014
 
/s/ Scott C. Surplus
 
 
Scott C. Surplus
 
 
Vice President and Controller
 
 
(Principal Accounting Officer)
 
 
 
Date: February 24, 2014
 
/s/ Matthew P. Clifton
 
 
Matthew P. Clifton
 
 
Executive Chairman
 
 
 
 
 
/s/ Charles M. Darling, IV
 
 
Charles M. Darling, IV
 
 
Director
 
 
 
Date: February 24, 2014
 
/s/ William J. Gray
 
 
William J. Gray
 
 
Director
 
 
 

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Date: February 24, 2014
 
/s/ Jerry W. Pinkerton
 
 
Jerry W. Pinkerton
 
 
Director
 
 
 
Date: February 24, 2014
 
/s/ P. Dean Ridenour
 
 
P. Dean Ridenour
 
 
Director
 
 
 
Date: February 24, 2014
 
/s/ William P. Stengel
 
 
William P. Stengel
 
 
Director
 
 
 
Date: February 24, 2014
 
/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. 00001-32225).
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. 00001-32225).
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. 00001-32225).

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10.15
 
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. 00001-32225).
10.16
 
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. 00001-32225).
10.17
 
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. 00001-32225).
10.18
 
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)
10.19
 
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).
10.20
 
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).
10.21
 
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).
10.22
 
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).
10.23
 
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).
10.24
 
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).
10.25
 
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).
10.26
 
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).
10.27
 
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).
10.28
 
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).
10.29
 
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).
10.30
 
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).
10.31
 
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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10.32
 
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).
10.33
 
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).
10.34
 
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).
10.35
 
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).
10.36
 
Amended and Restated Crude Pipelines and Tankage Agreement, entered into on December 1, 2009, effective January 1, 2009, among Navajo Refining Company, L.L.C., Holly Refining & Marketing Company - Woods Cross, Holly Refining & Marketing Company, Holly Energy Partners - Operating, L.P., HEP Pipeline, LLC and HEP Woods Cross, L.L.C. (incorporated by reference to Exhibit 10.8 of Registrant's Form 8-K Current Report dated December 7, 2009, File No. 001-32225).
10.37
 
Letter Agreement, dated October 14, 2011, regarding the Amended and Restated Crude Pipelines and Tankage Agreement, dated December 1, 2009 (incorporated by reference to Exhibit 10.3 of Registrant's Quarterly Report on Form 10-Q for its quarterly period ended September 30, 2011, File No. 001-32225)
10.38
 
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. 0001-32225).
10.39
 
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).
10.40
 
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).
10.41
 
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*
 
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.
10.43
 
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).
10.44
 
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).
10.45
 
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).
10.46
 
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).
10.47
 
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).

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10.48
 
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).
10.49
 
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).
10.50
 
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).
10.51
 
Tulsa Refinery Interconnects Term Sheet dated August 9, 2010 (incorporated by reference to Exhibit 10.1 of Registrant's Form 8-K Current Report dated August 11, 2010, File No. 001-32225).
10.52
 
Amendment to Tulsa Refinery Interconnects Term Sheet dated December 31, 2010 (incorporated by reference to Exhibit 10.1 of Registrant's Form 8-K Current Report dated January 6, 2011, File No. 001-32225).
10.53
 
Second Amendment to Tulsa Refinery Interconnects Term Sheet dated March 31, 2011 (incorporated by reference to Exhibit 10.1 of Registrant's Form 8-K Current Report dated March 31, 2011, File No. 001-32225).
10.54
 
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).
10.55
 
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).
10.56
 
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).
10.57
 
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).
10.58
 
Seventh Amended and Restated Omnibus Agreement, dated July 12, 2012, among HollyFrontier Corporation, Holly Energy Partners, L.P. and certain of their respective subsidiaries (incorporated by reference to Exhibit 10.6 of Registrant's Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2012, File No. 001-32225).
10.59
 
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).
10.60
 
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).
10.61
 
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).
10.62*
 
First Amendment to Lease and Access Agreement (Cheyenne), effective June 5, 2012, between Frontier Refining LLC and Cheyenne Logistics LLC.
10.63
 
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).
10.64*
 
First Amendment to Lease and Access Agreement (El Dorado), effective August 15, 2012, between Frontier El Dorado Refining LLC and El Dorado Logistics LLC.
10.65*
 
Second Amendment to Lease and Access Agreement (El Dorado), effective December 5, 2012, between Frontier El Dorado Refining LLC and El Dorado Logistics LLC.
10.66*
 
Third Amendment to Lease and Access Agreement (El Dorado), dated January 7, 2014, between Frontier El Dorado Refining LLC and El Dorado Logistics LLC.
10.67
 
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).

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10.68
 
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).
10.69
 
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).
10.70
 
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).
10.71
 
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).
10.72
 
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).
10.73+
 
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).
10.74+
 
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).
10.75+
 
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).
10.76+
 
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).
10.77+
 
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).
10.78+
 
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).
10.79+
 
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).
10.80+
 
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).
10.81+
 
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).
10.82+
 
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).
10.83+
 
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).
10.84+
 
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).
10.85+
 
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).
10.86+*
 
Form of Restricted Unit Agreement (Executive Chairman)
10.87+*
 
Form of Notice of Grant of Restricted Units (Executive Chairman)
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 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).
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.

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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, 2013, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Income, (iii) Consolidated Statements of Comprehensive Income, (iv) Consolidated Statements of Cash Flows, (v) Consolidated Statement of Partners’ Equity, and (vi) Notes to Consolidated Financial Statements.


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


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