HOLLY ENERGY PARTNERS LP - Quarter Report: 2011 June (Form 10-Q)

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2011

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

For the transition period from to .

Commission File Number: 1-32225

HOLLY ENERGY PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

Delaware

20-0833098

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

2828 N. Harwood, Suite 1300

Dallas, Texas 75201

(Address of principal executive offices)

(214) 871-3555

(Registrant’s telephone number, including area code)

100 Crescent Court, Suite 1600, Dallas, Texas 75201-6915

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Exchange Act). Yes ¨ No x

The number of the registrant’s outstanding common units at July 22, 2011 was 22,078,509.

HOLLY ENERGY PARTNERS, L.P.

INDEX


PART I. FINANCIAL INFORMATION			3

	FORWARD-LOOKING STATEMENTS		3

	Item 1.	Financial Statements (Unaudited, except December 31, 2010 Balance Sheet)	4

	Consolidated Balance Sheets		4

	Consolidated Statements of Income		5

	Consolidated Statements of Cash Flows		6

	Consolidated Statement of Partners’ Equity		7

	Notes to Consolidated Financial Statements		8

	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23

	Item 3.	Quantitative and Qualitative Disclosures About Market Risks	39

	Item 4.	Controls and Procedures	39

PART II. OTHER INFORMATION			40

	Item 1.	Legal Proceedings	40

	Item 6.	Exhibits	40

	SIGNATURES		41

	Index to Exhibits		42

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PART I. FINANCIAL INFORMATION

FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains certain “forward-looking statements” within the meaning of the federal securities laws. All statements, other than statements of historical fact included in this Form 10-Q, including, but not limited to, those under “Results of Operations” and “Liquidity and Capital Resources” in Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part I are forward-looking statements. Forward looking statements use words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “intend,” “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. Such 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 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 successfully purchase and integrate additional operations in the future;

•

our ability to complete previously announced or contemplated acquisitions;

•

the availability and cost of additional debt and equity financing;

•

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

•

the effects of current and future government regulations and policies;

•

our operational efficiency in carrying out routine operations and capital construction projects;

•

the possibility of terrorist attacks and the consequences of any such attacks;

•

general economic conditions; and

•

other financial, operational and legal risks and uncertainties detailed from time to time in our Securities and Exchange Commission filings.

Cautionary statements identifying important factors that could cause actual results to differ materially from our expectations are set forth in this Form 10-Q, including without limitation, the forward-looking statements that are referred to above. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements set forth in our Annual Report on Form 10-K for the year ended December 31, 2010 in “Risk Factors” and in this Form 10-Q in “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” All forward-looking statements included in this Form 10-Q and all subsequent written or oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. The forward-looking statements speak only as of the date made and, other than as required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

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Item 1.

Financial Statements

Holly Energy Partners, L.P.

Consolidated Balance Sheets


	June 30, 2011 (Unaudited)			December 31, 2010
	(In thousands, except unit data)
ASSETS
Current assets:
Cash and cash equivalents	$	1,402		$	403
Accounts receivable:
Trade		2,600			3,544
Affiliates		16,156			18,964

		18,756			22,508

Prepaid and other current assets		1,038			775

Total current assets		21,196			23,686

Properties and equipment, net		445,986			434,950
Transportation agreements, net		105,016			108,489
Goodwill		49,109			49,109
Investment in SLC Pipeline		25,519			25,437
Other assets		4,325			1,602


Total assets	$	651,151		$	643,273


LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	3,924		$	6,347
Affiliates		3,191			3,891

		7,115			10,238

Accrued interest		7,521			7,517
Deferred revenue		5,319			10,437
Accrued property taxes		2,311			1,990
Other current liabilities		956			1,262

Total current liabilities		23,222			31,444

Long-term debt		518,818			491,648
Other long-term liabilities		9,164			10,809

Partners’ equity:
Common unitholders (22,078,509 units issued and outstanding at June 30, 2011 and December 31, 2010)		261,014			271,649
General partner interest (2% interest)		(152,595	)		(152,251	)
Accumulated other comprehensive loss		(8,472	)		(10,026	)

Total partners’ equity		99,947			109,372


Total liabilities and partners’ equity	$	651,151		$	643,273

See accompanying notes.

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Holly Energy Partners, L.P.

Consolidated Statements of Income

(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(In thousands, except per unit data)
Revenues:
Affiliates	$	37,139		$	37,079		$	71,246		$	70,676
Third parties		13,801			8,404			24,711			15,503

		50,940			45,483			95,957			86,179


Operating costs and expenses:
Operations		14,366			13,495			27,162			26,555
Depreciation and amortization		7,713			7,591			15,353			14,801
General and administrative		1,573			1,913			2,936			4,476

		23,652			22,999			45,451			45,832


Operating income		27,288			22,484			50,506			40,347

Other income (expense):
Equity in earnings of SLC Pipeline		467			544			1,207			1,025
Interest income		—			2			—			5
Interest expense		(8,724	)		(9,549	)		(17,273	)		(17,093	)
Other expense		—			—			(12	)		(7	)

		(8,257	)		(9,003	)		(16,078	)		(16,070	)


Income before income taxes		19,031			13,481			34,428			24,277

State income tax		(18	)		(46	)		(246	)		(140	)


Net income		19,013			13,435			34,182			24,137

Less general partner interest in net income, Including incentive distributions		3,847			2,909			7,409			5,555


Limited partners’ interest in net income	$	15,166		$	10,526		$	26,773		$	18,582


Limited partners’ per unit interest in earnings – basic and diluted:	$	0.69		$	0.48		$	1.21		$	0.84


Weighted average limited partners’ units outstanding		22,079			22,079			22,079			22,079

See accompanying notes.

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Holly Energy Partners, L.P.

Consolidated Statements of Cash Flows

(Unaudited)


	Six Months Ended June 30,
	2011			2010
	(In thousands)
Cash flows from operating activities
Net income	$	34,182		$	24,137
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		15,353			14,801
Equity in earnings of SLC Pipeline, net of distributions		(82	)		100
Change in fair value – interest rate swaps		—			1,464
Amortization of restricted and performance units		1,080			1,339
(Increase) decrease in current assets:
Accounts receivable – trade		944			(1,696	)
Accounts receivable – affiliates		2,808			(2,625	)
Prepaid and other current assets		(263	)		(200	)
Current assets of discontinued operations		—			2,195
Increase (decrease) in current liabilities:
Accounts payable – trade		(2,423	)		(372	)
Accounts payable – affiliates		(700	)		501
Accrued interest		4			4,825
Deferred revenue		(5,118	)		2,521
Accrued property taxes		321			(82	)
Other current liabilities		(306	)		(656	)
Other, net		489			(1,066	)

Net cash provided by operating activities		46,289			45,186


Cash flows from investing activities
Additions to properties and equipment		(22,900	)		(4,487	)
Acquisition of assets from HollyFrontier Corporation		—			(39,040	)

Net cash used for investing activities		(22,900	)		(43,527	)


Cash flows from financing activities
Borrowings under credit agreement		64,000			39,000
Repayments of credit agreement borrowings		(37,000	)		(90,000	)
Proceeds from issuance of senior notes		—			147,540
Distributions to HEP unitholders		(44,862	)		(41,312	)
Purchase price in excess of transferred basis in assets acquired from HollyFrontier Corporation		—			(53,960	)
Purchase of units for incentive grants		(1,379	)		(2,276	)
Deferred financing costs		(3,149	)		(353	)

Net cash used for financing activities		(22,390	)		(1,361	)


Cash and cash equivalents
Increase for the period		999			298
Beginning of period		403			2,508

End of period	$	1,402		$	2,806

See accompanying notes.

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Holly Energy Partners, L.P.

Consolidated Statement of Partners’ Equity

(Unaudited)


	Common Units			General Partner Interest			Accumulated Other Comprehensive Loss			Total

Balance December 31, 2010	$	271,649		$	(152,251	)	$	(10,026	)	$	109,372

Distributions to HEP unitholders		(37,525	)		(7,337	)		—			(44,862	)
Purchase of units for restricted grants		(1,379	)		—			—			(1,379	)
Amortization of restricted and performance units		1,080			—			—			1,080
Comprehensive income:
Net income		27,189			6,993			—			34,182
Other comprehensive income		—			—			1,554			1,554

Comprehensive income		27,189			6,993			1,554			35,736


Balance June 30, 2011	$	261,014		$	(152,595	)	$	(8,472	)	$	99,947

See accompanying notes.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1: Description of Business and Presentation of Financial Statements

Holly Energy Partners, L.P. (“HEP”) together with its consolidated subsidiaries, is a publicly held master limited partnership, currently 34% owned (including the 2% general partner interest) by HollyFrontier Corporation (formerly known as Holly Corporation) (“HFC”) and its subsidiaries. HFC changed its name in connection with the consummation of its merger of equals with Frontier Oil Corporation effective July 1, 2011. All previous references to “Holly” within these financial statements have been replaced with “HFC.”

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 business segment - the operation of petroleum product and crude oil pipelines and terminals, tankage and loading rack facilities.

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 west Texas, New Mexico, Utah, Oklahoma, Idaho and Arizona. We also own and operate refined product pipelines and terminals, located primarily in Texas, that service Alon USA, Inc.’s (“Alon”) refinery in Big Spring, Texas. Additionally, we own 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 area.

We generate revenues by charging tariffs for transporting petroleum products and crude oil through our pipelines, by charging fees for terminalling refined products and other hydrocarbons and storing and providing other services at our storage tanks and terminals. We do not take ownership of products that we transport, terminal or store, and therefore, we are not directly exposed to changes in commodity prices.

The consolidated financial statements included herein have been prepared without audit, pursuant to the rules and regulations of the United States Securities and Exchange Commission (the “SEC”). The interim financial statements reflect all adjustments, which, in the opinion of management, are necessary for a fair presentation of our results for the interim periods. Such adjustments are considered to be of a normal recurring nature. Although certain notes and other information required by U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted, we believe that the disclosures in these consolidated financial statements are adequate to make the information presented not misleading. These consolidated financial statements should be read in conjunction with our Form 10-K for the year ended December 31, 2010. Results of operations for interim periods are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2011.

Note 2: Acquisitions

2010 Acquisitions

Tulsa East / Lovington Storage Asset Transaction

On March 31, 2010, we acquired from HFC certain storage assets for $88.6 million consisting of hydrocarbon storage tanks having approximately 2 million barrels of storage capacity, a rail loading rack and a truck unloading rack located at HFC’s Tulsa refinery east facility.

Also, as part of this same transaction, we acquired HFC’s asphalt loading rack facility located at its Navajo refinery facility in Lovington, New Mexico for $4.4 million.

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We are a consolidated variable interest entity of HFC. In accounting for these acquisitions from HFC, we recorded total property and equipment at HFC’s cost basis of $39 million and the purchase price in excess of HFC’s basis in the assets of $54 million as a decrease to our partners’ equity.

Note 3: Financial Instruments

Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, debt and an interest rate swap. 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.

Our debt consists of borrowings outstanding under our $275 million revolving credit agreement (the “Credit Agreement”), our 6.25% senior notes due 2015 (the “6.25% Senior Notes”) and our 8.25% senior notes due 2018 (the “8.25% Senior Notes”). The $186 million carrying amount of borrowings outstanding under the Credit Agreement approximates fair value as interest rates are reset frequently using current rates. The estimated fair values of our 6.25% Senior Notes and 8.25% Senior Notes were $184.1 million and $159.4 million, respectively, at June 30, 2011. These fair value estimates are based on market quotes provided from a third-party bank. See Note 7 for additional information on these instruments.

Fair Value Measurements

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.

We have an interest rate swap that is measured at fair value on a recurring basis using Level 2 inputs that as of June 30, 2011 represented a liability having a fair value of $8.5 million. With respect to this instrument, fair value is based on the net present value of expected future cash flows related to both variable and fixed rate legs of our interest rate swap agreement. Our 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 our interest rate swap.

Note 4: Properties and Equipment


	June 30,		December 31,
	2011		2010
	(In thousands)

Pipelines and terminals	$	510,488	$	507,260
Land and right of way		25,271		25,264
Other		15,427		14,591
Construction in progress		35,391		16,601

		586,577		563,716
Less accumulated depreciation		140,591		128,766

	$	445,986	$	434,950

We capitalized $0.5 million and $0.2 million in interest related to major construction projects during the six months ended June 30, 2011 and 2010, respectively.

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Note 5: Transportation Agreements

Our transportation agreements consist of the following:

•

The Alon pipelines and terminals agreement (the “Alon PTA”) represents a portion of the total purchase price of the Alon assets acquired in 2005 that was allocated based on an estimated fair value derived under an income approach. This asset is being amortized over 30 years ending 2035, the 15-year initial term of the Alon PTA plus the expected 15-year extension period.

•

The HFC crude pipelines and tankage agreement (the “HFC CPTA”) represents a portion of the total purchase price of certain crude pipelines and tankage assets acquired from HFC in 2008 (at which time we were not a consolidated variable interest entity of HFC) that was allocated using a fair value based on the agreement’s expected contribution to our future earnings under an income approach. This asset is being amortized over 15 years ending 2023, the 15-year term of the HFC CPTA.

The carrying amounts of our transportation agreements are as follows:


	June 30, 2011		December 31, 2010
	(In thousands)

Alon transportation agreement	$	59,933	$	59,933
HFC crude pipelines and tankage agreement		74,231		74,231

		134,164		134,164
Less accumulated amortization		29,148		25,675

	$	105,016	$	108,489

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

In addition, we have an agreement to provide transportation and storage services to HFC via our Tulsa logistics and storage assets acquired from Sinclair. Since this agreement is with HFC and not between Sinclair and us, there is no purchase price allocation attributable to this agreement.

Note 6: Employees, Retirement and Incentive Plans

Employees who provide direct services to us are employed by Holly Logistic Services, L.L.C., a 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 $0.7 million and $0.6 million for the three months ended June 30, 2011 and 2010, respectively, and $1.4 million and $1.3 million for the six months ended June 30, 2011 and June 30, 2010, respectively.

We have adopted an incentive plan (“Long-Term Incentive Plan”) for employees, consultants and non-employee directors who perform services for us. The Long-Term Incentive Plan consists of four components: restricted units, performance units, unit options and unit appreciation rights.

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As of June 30, 2011, we have two types of equity-based compensation, which are described below. The compensation cost charged against income for these plans was $0.4 million and $0.3 million for the three months ended June 30, 2011 and 2010, respectively, and $1.1 million and $1.3 million for the six months ended June 30, 2011 and 2010, respectively. We currently purchase units in the open market instead of issuing new units for the settlement of all unit awards under our Long-Term Incentive Plan. At June 30, 2011, 350,000 units were authorized to be granted under the equity-based compensation plans, of which 83,254 had not yet been granted, assuming no forfeitures of the unvested units and full achievement of goals for the performance units already granted.

Restricted Units

Under our Long-Term Incentive Plan, we grant restricted units to selected employees and directors who perform services for us, with vesting generally over a period of one to five years. Although full ownership of the units does not transfer to the recipients until the units vest, the recipients have distribution and voting rights on these units from the date of grant. The fair value of each restricted unit award is measured at the market price as of the date of grant and is amortized over the vesting period.

A summary of restricted unit activity and changes during the six months ended June 30, 2011 is presented below:


Restricted Units	Grants			Weighted- Average Grant-Date Fair Value		Weighted- Average Remaining Contractual Term		Aggregate Intrinsic Value ($000)

Outstanding at January 1, 2011 (nonvested)		47,295		$	37.47
Granted		17,780			59.65
Vesting and transfer of full ownership to recipients		(24,055	)		41.48
Forfeited		(7,802	)		48.29

Outstanding at June 30, 2011 (nonvested)		33,218		$	44.97		1 year	$	1,803

The fair value of restricted units that were vested and transferred to recipients during the six months ended June 30, 2011 and 2010 were $1 million and $1.5 million, respectively. As of June 30, 2011, there was $0.7 million of total unrecognized compensation costs related to nonvested restricted unit grants. That cost is expected to be recognized over a weighted-average period of 1 year.

Performance Units

Under our Long-Term Incentive Plan, we grant performance units to selected executives who perform services for us. Performance units granted in 2011 and 2010 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. Performance units granted in 2009 are payable based upon the growth in distributions on our common units during the requisite period, and vest over a period of three years. As of June 30, 2011, estimated share payouts for outstanding nonvested performance unit awards ranged from 110% to 120%.

We granted 8,969 performance units to certain officers in March 2011. These units will vest over a three-year performance period ending December 31, 2013 and are payable in HEP common units. The number of units actually earned will be based on the growth of our distributable cash flow per common unit over the performance period, and can range from 50% to 150% of the number of performance units granted. The fair value of these performance units is based on the grant date closing unit price of $59.65 and will apply to the number of units ultimately awarded.

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A summary of performance unit activity and changes during the six months ended June 30, 2011 is presented below:


Performance Units	Payable In Units

Outstanding at January 1, 2011 (nonvested)		59,415
Granted		8,969
Vesting and transfer of common units to recipients		(14,337	)
Forfeited		—

Outstanding at June 30, 2011 (nonvested)		54,047

The fair value of performance units vested and transferred to recipients during the six months ended June 30, 2011 and 2010 was $0.6 million and $0.5 million, respectively. Based on the weighted average grant-date fair value, there were $1 million of total unrecognized compensation costs related to nonvested performance units at June 30, 2011. That cost is expected to be recognized over a weighted-average period of 1.1 years.

During the six months ended June 30, 2011, we paid $1.4 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.

Note 7: Debt

Credit Agreement

We have a $275 million Credit Agreement that is available to fund capital expenditures, investments, acquisitions, distribution payments and working capital and for general partnership purposes. It is also available to fund letters of credit up to a $50 million sub-limit and to fund distributions to unitholders up to a $30 million sub-limit. In February 2011, we amended our previous credit agreement (expiring in August 2011), extending the expiration date and slightly reducing the size of the credit facility from $300 million to $275 million. The size was reduced based on management’s review of past and forecasted utilization of the facility. The Credit Agreement expires in February 2016; however, in the event that the 6.25% Senior Notes are not repurchased, refinanced, extended or repaid prior to September 1, 2014, the Credit Agreement shall expire on that date.

During the six months ended June 30, 2011, we received advances totaling $64 million and repaid $37 million, resulting in net borrowings of $27 million under the Credit Agreement and an outstanding balance of $186 million at June 30, 2011.

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., our general partner, and guaranteed by our material, wholly-owned subsidiaries. Any recourse to HEP Logistics Holdings, L.P. 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 1.00% to 2.00%) or (b) at a rate equal to LIBOR plus an applicable margin (ranging from 2.00% to 3.00%). 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 0.375% to 0.50% based upon the ratio of our funded debt to EBITDA for the four most recently completed fiscal quarters.

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The Credit Agreement imposes certain requirements on us which we are subject to and 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 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 2010, we issued $150 million in aggregate principal amount outstanding of 8.25% Senior Notes maturing March 15, 2018. A portion of the $147.5 million in net proceeds received was used to fund our $93 million purchase of the Tulsa and Lovington storage assets from HFC on March 31, 2010. Additionally, we used a portion to repay $42 million in outstanding Credit Agreement borrowings, with the remaining proceeds available for general partnership purposes, including working capital and capital expenditures.

Our 6.25% Senior Notes having an aggregate principal amount outstanding of $185 million mature March 1, 2015 and are registered with the SEC. The 6.25% Senior Notes and 8.25% Senior Notes (collectively, the “Senior Notes”) are unsecured and have certain restrictive covenants, which we are subject to and currently in compliance with, including limitations on our ability to incur additional indebtedness, make investments, sell assets, incur certain liens, pay distributions, enter into transactions with affiliates, and enter into mergers. At any time when the Senior Notes are rated investment grade by both Moody’s and Standard & Poor’s and no default or event of default exists, we will not be subject to many of the foregoing covenants. Additionally, we have certain redemption rights under the Senior Notes.

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

The carrying amounts of our debt are as follows:


	June 30, 2011			December 31, 2010
	(In thousands)
Credit Agreement	$	186,000		$	159,000

6.25% Senior Notes
Principal		185,000			185,000
Unamortized discount		(1,394	)		(1,584	)
Unamortized premium – dedesignated fair value hedge		1,271			1,444

		184,877			184,860


8.25% Senior Notes
Principal		150,000			150,000
Unamortized discount		(2,059	)		(2,212	)

		147,941			147,788


Total long-term debt	$	518,818		$	491,648

Interest Rate Risk Management

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

As of June 30, 2011, we have an interest rate swap that hedges our exposure to the cash flow risk caused by the effects of LIBOR changes on a $155 million Credit Agreement advance. This interest rate swap effectively converts $155 million of LIBOR based debt to fixed rate debt having an interest rate of 3.74% plus an applicable margin, currently 2.50%, which equals an effective interest rate of 6.24% as of June 30, 2011. This swap contract matures in February 2013.

- 13 -

We have designated this interest rate swap as a cash flow hedge. Based on our assessment of effectiveness using the change in variable cash flows method, we have determined that this interest rate swap is effective in offsetting the variability in interest payments on $155 million of our variable rate debt resulting from changes in LIBOR. Under hedge accounting, we adjust our cash flow hedge on a quarterly basis to its fair value with the offsetting fair value adjustment to accumulated other comprehensive 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 swap against the expected future interest payments on $155 million of our variable rate debt. Any ineffectiveness is reclassified from accumulated other comprehensive loss to interest expense. To date, we have had no ineffectiveness on our cash flow hedge.

Additional information on our interest rate swap is as follows:

Derivative Instrument

Balance Sheet

Location

Fair Value

Location of Offsetting
Balance

Offsetting
Amount

(In thousands)

June 30, 2011

Interest rate swap designated as cash flow hedging instrument:

Variable-to-fixed interest rate swap contract ($155 million of LIBOR based debt interest)

Other long-term liabilities

8,472

Accumulated other comprehensive loss

8,472

December 31, 2010

Interest rate swap designated as cash flow hedging instrument:

Variable-to-fixed interest rate swap contract ($155 million of LIBOR based debt interest)

Other long-term liabilities

10,026

Accumulated other comprehensive loss

10,026

Interest Expense and Other Debt Information

Interest expense consists of the following components:


	Six Months Ended June 30,
	2011		2010
	(In thousands)
Interest on outstanding debt:
Credit Agreement, net of interest on interest rate swap	$	5,013	$	4,726
6.25% Senior Notes, net of interest on interest rate swaps		5,781		5,623
8.25% Senior Notes		6,187		3,816
Partial settlement of interest rate swap – cash flow hedge		—		1,076
Net fair value adjustments to interest rate swaps ⁽¹⁾		—		1,464
Net amortization of discount and deferred debt issuance costs		595		458
Commitment fees		227		177

Total interest incurred		17,803		17,340
Less capitalized interest		530		247

Net interest expense	$	17,273	$	17,093


Cash paid for interest ⁽²⁾	$	17,204	$	14,192

(1)	Represents fair value adjustments to interest rate swap agreements settled during the first quarter of 2010.

(2)	Net of cash received under previous interest rate swap agreements of $1.9 million for the six months ended June 30, 2010.

Note 8: Significant Customers

All revenues are domestic revenues, of which 96% 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.

- 14 -

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
HFC		73	%		82	%		74	%		82	%
Alon		23	%		14	%		22	%		14	%

(1)

The Alon PTA was amended in June 2011, limiting the carryover term of credits attributable to Alon’s shortfall payments to the calendar year end in which the shortfalls occur. As a result, we recognized an additional $2.4 million of previously deferred revenues during the three months ended June 30, 2011 that relate to shortfall billings for the third and fourth quarters of 2010.

Note 9: Related Party Transactions

HFC Agreements

We serve HFC’s refineries in New Mexico, Utah and Oklahoma under the following long-term pipeline and terminal, tankage and throughput agreements:

•

HFC PTA (pipelines and terminals throughput agreement expiring in 2019 that relates to assets contributed to us by HFC upon our initial public offering in 2004);

•

HFC IPA (intermediate pipelines throughput agreement expiring in 2024 that relates to assets acquired from HFC in 2005 and 2009);

•

HFC CPTA (crude pipelines and tankage throughput agreement expiring in 2023 that relates to assets acquired from HFC in 2008);

•

HFC PTTA (pipeline, tankage and loading rack throughput agreement expiring in 2024 that relates to the Tulsa east facilities acquired from Sinclair in 2009 and from HFC in March 2010);

•

HFC RPA (pipeline throughput agreement expiring in 2024 that relates to the Roadrunner Pipeline acquired from HFC in 2009);

•

HFC ETA (equipment and throughput agreement expiring in 2024 that relates to the Tulsa west facilities acquired from HFC in 2009);

•

HFC NPA (natural gas pipeline throughput agreement expiring in 2024); and

•

HFC ATA (asphalt loading rack throughput agreement expiring in 2025 that relates to the Lovington rack facility acquired from HFC in March 2010).

Under these agreements, HFC agreed to transport, store and throughput volumes of refined product and crude oil on our pipelines and terminal, tankage and loading rack facilities that result in minimum annual payments to us. These minimum annual payments or revenues are subject to annual tariff rate adjustments on July 1, based on the Producer Price Index (“PPI”) or Federal Energy Regulatory Commission (“FERC”) index. As of July 1, 2011, these agreements with HFC will result in minimum annualized payments to us of $140 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. A shortfall payment under the HFC PTA and HFC IPA may be applied as a credit in the following four quarters after minimum obligations are met.

Under certain provisions of an omnibus agreement we have with HFC (the “Omnibus Agreement”) we pay HFC an annual administrative fee for the provision by HFC or its affiliates of various general and administrative services to us, currently $2.3 million. This fee does not include the salaries of pipeline and terminal personnel 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.

- 15 -

Related party transactions with HFC are as follows:

•

Revenues received from HFC were $37.1 million for the three months ended June 30, 2011 and 2010, and $71.2 million and $70.7 million for the six months ended June 30, 2011 and 2010, respectively.

•

HFC charged general and administrative services under the Omnibus Agreement of $0.6 million for the three months ended June 30, 2011 and 2010 and $1.2 million for the six months ended June 30, 2011 and 2010.

•

We reimbursed HFC for costs of employees supporting our operations of $4.7 million and $4.6 million for the three months ended June 30, 2011 and 2010, respectively, and $9.7 million and $8.8 million for the six months ended June 30, 2011 and 2010, respectively.

•

We distributed $10 million and $8.8 million for the three months ended June 30, 2011 and 2010, respectively, to HFC as regular distributions on its common units, and general partner interest, including general partner incentive distributions. We distributed $19.7 million and $17.4 million for the six months ended June 30, 2011 and 2010, respectively.

•

Accounts receivable from HFC were $16.2 million and $19 million at June 30, 2011 and December 31, 2010, respectively.

•

Accounts payable to HFC were $3.2 million and $3.9 million at June 30, 2011 and December 31, 2010, respectively.

•

Revenues for the three and the six months ended June 30, 2011 include $0.7 million and $1.9 million, respectively, of shortfalls billed under the HFC IPA in 2010, as HFC did not exceed its minimum volume commitment in any of the subsequent four quarters. Deferred revenue in the consolidated balance sheets at June 30, 2011 and December 31, 2010, includes $3.9 million and $3.3 million, respectively, relating to the HFC IPA. It is possible that HFC may not exceed its minimum obligations under the HFC IPA to allow HFC to receive credit for any of the $3.9 million deferred at June 30, 2011.

•

We acquired certain storage assets and an asphalt loading rack facility from HFC in March 2010. See Note 2 for a description of this transaction.

Note 10: Partners’ Equity

HFC currently holds 7,290,000 of our common units and the 2% general partner interest, which together constitutes a 34% ownership interest in us.

In May 2010, all of the conditions necessary to end the subordination period for the 937,500 Class B subordinated units originally issued to Alon in connection with our acquisition of assets from Alon in 2005 were met and the units were converted into our common units on a one-for-one basis. These subordinated units were not publicly traded.

Under our registration statement filed with the SEC using a “shelf” registration process, we currently have the ability to raise $860 million through security offerings, 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.

- 16 -

Allocations of Net Income

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

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
	(In thousands, except per unit data)
General partner interest in net income	$	310	$	220	$	547	$	388
General partner incentive distribution		3,537		2,689		6,862		5,167

Total general partner interest in net income attributable to HEP	$	3,847	$	2,909	$	7,409	$	5,555

Cash Distributions

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

On July 27, 2011, we announced our cash distribution for the second quarter of 2011 of $0.865 per unit. The distribution is payable on all common and general partner units and will be paid August 12, 2011 to all unitholders of record on August 8, 2011.

The following table presents the allocation of our regular quarterly cash distributions to the general and limited partners for the periods in which they apply. Our distributions are declared subsequent to quarter end; therefore, the amounts presented do not reflect distributions paid during the periods presented below.


	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
	(In thousands, except per unit data)
General partner interest	$	462	$	427	$	915	$	844
General partner incentive distribution		3,537		2,689		6,862		5,167

Total general partner distribution		3,999		3,116		7,777		6,011
Limited partner distribution		19,098		18,215		37,975		36,209

Total regular quarterly cash distribution	$	23,097	$	21,331	$	45,752	$	42,220

Cash distribution per unit applicable to limited partners	$	0.865	$	0.825	$	1.720	$	1.640

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 our equity since our regular quarterly distributions have exceeded our quarterly net income. Additionally, if the assets contributed and acquired 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 $218 million would have been recorded in our financial statements as increases to our properties and equipment and intangible assets instead of decreases to our partners’ equity.

- 17 -

Comprehensive Income

We have other comprehensive income resulting from fair value adjustments to our cash flow hedge. Our comprehensive income is as follows:


	Three Months Ended June 30,					Six Months Ended June 30,
	2011		2010			2011		2010
	(In thousands)

Net income	$	19,013	$	13,435		$	34,182	$	24,137
Other comprehensive income (loss):
Change in fair value of cash flow hedge		271		(1,696	)		1,554		(3,057	)
Reclassification adjustment to net income on partial settlement of cash flow hedge		—		1,076			—		1,076


Other comprehensive income (loss)		271		(620	)		1,554		(1,981	)


Comprehensive income	$	19,284	$	12,815		$	35,736	$	22,156

Note 11: Supplemental Guarantor/Non-Guarantor Financial Information

Obligations of Holly Energy Partners, L.P. (“Parent“) under the 6.25% Senior Notes and 8.25% Senior Notes have been jointly and severally guaranteed by each of its direct and indirect wholly-owned subsidiaries (“Guarantor Subsidiaries“). These guarantees are full and unconditional.

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

- 18 -

Condensed Consolidating Balance Sheet


June 30, 2011	Parent			Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	2		$	1,400	$	—		$	1,402
Accounts receivable		—			18,756		—			18,756
Intercompany accounts receivable (payable)		(151,277	)		151,277		—			—
Prepaid and other current assets		73			965		—			1,038

Total current assets		(151,202	)		172,398		—			21,196

Properties and equipment, net		—			445,986		—			445,986
Investment in subsidiaries		590,944			—		(590,944	)		—
Transportation agreements, net		—			105,016		—			105,016
Goodwill		—			49,109		—			49,109
Investment in SLC Pipeline		—			25,519		—			25,519
Other assets		1,156			3,169		—			4,325

Total assets	$	440,898		$	801,197	$	(590,944	)	$	651,151


LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	—		$	7,115	$	—		$	7,115
Accrued interest		7,498			23		—			7,521
Deferred revenue		—			5,319		—			5,319
Accrued property taxes		—			2,311		—			2,311
Other current liabilities		635			321		—			956

Total current liabilities		8,133			15,089		—			23,222

Long-term debt		332,818			186,000		—			518,818
Other long-term liabilities		—			9,164		—			9,164
Partners’ equity		99,947			590,944		(590,944	)		99,947

Total liabilities and partners’ equity	$	440,898		$	801,197	$	(590,944	)	$	651,151

Condensed Consolidating Balance Sheet
December 31, 2010	Parent			Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	2		$	401	$	—		$	403
Accounts receivable		—			22,508		—			22,508
Intercompany accounts receivable (payable)		(92,230	)		92,230		—			—
Prepaid and other current assets		235			540		—			775

Total current assets		(91,993	)		115,679		—			23,686

Properties and equipment, net		—			434,950		—			434,950
Investment in subsidiaries		541,262			—		(541,262	)		—
Transportation agreements, net		—			108,489		—			108,489
Goodwill		—			49,109		—			49,109
Investment in SLC Pipeline		—			25,437		—			25,437
Other assets		1,261			341		—			1,602

Total assets	$	450,530		$	734,005	$	(541,262	)	$	643,273


LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	—		$	10,238	$	—		$	10,238
Accrued interest		7,498			19		—			7,517
Deferred revenue		—			10,437		—			10,437
Accrued property taxes		—			1,990		—			1,990
Other current liabilities		1,011			251		—			1,262

Total current liabilities		8,509			22,935		—			31,444

Long-term debt		332,649			158,999		—			491,648
Other long-term liabilities		—			10,809		—			10,809
Partners’ equity		109,372			541,262		(541,262	)		109,372

Total liabilities and partners’ equity	$	450,530		$	734,005	$	(541,262	)	$	643,273

- 19 -

Condensed Consolidating Statement of Income


Three Months Ended June 30, 2011	Parent			Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	37,139		$	—		$	37,139
Third parties		—			13,801			—			13,801

		—			50,940			—			50,940

Operating costs and expenses:
Operations		—			14,366			—			14,366
Depreciation and amortization		—			7,713			—			7,713
General and administrative		952			621			—			1,573

		952			22,700			—			23,652

Operating income (loss)		(952	)		28,240			—			27,288

Equity in earnings of subsidiaries		26,086			—			(26,086	)		—
Equity in earnings of SLC Pipeline		—			467			—			467
Interest income (expense)		(6,121	)		(2,603	)		—			(8,724	)


		19,965			(2,136	)		(26,086	)		(8,257	)


Income before income taxes		19,013			26,104			(26,086	)		19,031

State income tax		—			(18	)		—			(18	)


Net income	$	19,013		$	26,086		$	(26,086	)	$	19,013


Condensed Consolidating Statement of Income
Three Months Ended June 30, 2010	Parent			Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	37,079		$	—		$	37,079
Third parties		—			8,404			—			8,404

		—			45,483			—			45,483

Operating costs and expenses:
Operations		—			13,495			—			13,495
Depreciation and amortization		—			7,591			—			7,591
General and administrative		1,281			632			—			1,913

		1,281			21,718			—			22,999

Operating income (loss)		(1,281	)		23,765			—			22,484

Equity in earnings of subsidiaries		20,833			—			(20,833	)		—
Equity in earnings of SLC Pipeline		—			544			—			544
Interest income (expense)		(6,117	)		(3,430	)		—			(9,547	)


		14,716			(2,886	)		(20,833	)		(9,003	)


Income before income taxes		13,435			20,879			(20,833	)		13,481

State income tax		—			(46	)		—			(46	)


Net income	$	13,435		$	20,833		$	(20,833	)	$	13,435

- 20 -

Condensed Consolidating Statement of Income


Six Months Ended June 30, 2011	Parent			Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	71,246		$	—		$	71,246
Third parties		—			24,711			—			24,711

		—			95,957			—			95,957

Operating costs and expenses:
Operations		—			27,162			—			27,162
Depreciation and amortization		—			15,353			—			15,353
General and administrative		1,703			1,233			—			2,936

		1,703			43,748			—			45,451

Operating income (loss)		(1,703	)		52,209			—			50,506

Equity in earnings of subsidiaries		48,128			—			(48,128	)		—
Equity in earnings of SLC Pipeline		—			1,207			—			1,207
Interest income (expense)		(12,243	)		(5,030	)		—			(17,273	)
Other		—			(12	)		—			(12	)


		35,885			(3,835	)		(48,128	)		(16,078	)


Income before income taxes		34,182			48,374			(48,128	)		34,428

State income tax		—			(246	)		—			(246	)


Net income	$	34,182		$	48,128		$	(48,128	)	$	34,182


Condensed Consolidating Statement of Income
Six Months Ended June 30, 2010	Parent			Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	70,676		$	—		$	70,676
Third parties		—			15,503			—			15,503

		—			86,179			—			86,179

Operating costs and expenses:
Operations		—			26,555			—			26,555
Depreciation and amortization		—			14,801			—			14,801
General and administrative		3,082			1,394			—			4,476

		3,082			42,750			—			45,832

Operating income (loss)		(3,082	)		43,429			—			40,347

Equity in earnings of subsidiaries		38,318			—			(38,318	)		—
Equity in earnings of SLC Pipeline		—			1,025			—			1,025
Interest income (expense)		(11,099	)		(5,989	)		—			(17,088	)
Other		—			(7	)		—			(7	)


		27,219			(4,971	)		(38,318	)		(16,070	)


Income before income taxes		24,137			38,458			(38,318	)		24,277

State income tax		—			(140	)		—			(140	)


Net income	$	24,137		$	38,318		$	(38,318	)	$	24,137

- 21 -

Condensed Consolidating Statement of Cash Flows


Six Months Ended June 30, 2011	Parent			Guarantor Subsidiaries			Eliminations		Consolidated
	(In thousands)

Cash flows from operating activities	$	46,241		$	48		$	—	$	46,289

Cash flows from investing activities
Additions to properties and equipment		—			(22,900	)		—		(22,900	)

Cash flows from financing activities
Net borrowings under credit agreement		—			27,000			—		27,000
Distributions to HEP unitholders		(44,862	)		—			—		(44,862	)
Purchase of units for restricted grants		(1,379	)		—			—		(1,379	)
Deferred financing costs		—			(3,149	)		—		(3,149	)


		(46,241	)		23,851			—		(22,390	)


Cash and cash equivalents
Increase for the period		—			999			—		999
Beginning of period		2			401			—		403


End of period	$	2		$	1,400		$	—	$	1,402


Condensed Consolidating Statement of Cash Flows
Six Months Ended June 30, 2010	Parent			Guarantor Subsidiaries			Eliminations		Consolidated
	(in thousands)

Cash flows from operating activities	$	(103,599	)	$	148,785		$	—	$	45,186

Cash flows from investing activities
Additions to properties and equipment		—			(4,487	)		—		(4,487	)
Acquisition of assets from HFC		—			(39,040	)		—		(39,040	)


		—			(43,527	)		—		(43,527	)

Cash flows from financing activities
Net repayments under credit agreement		—			(51,000	)		—		(51,000	)
Net proceeds from issuance of senior notes		147,540			—			—		147,540
Distributions to HEP unitholders		(41,312	)		—			—		(41,312	)
Purchase price in excess of transferred basis in assets acquired from HFC		—			(53,960	)		—		(53,960	)
Purchase of units for restricted grants		(2,276	)		—			—		(2,276	)
Deferred financing costs		(353	)		—			—		(353	)


		103,599			(104,960	)		—		(1,361	)


Cash and cash equivalents
Increase for the period		—			298			—		298
Beginning of period		2			2,506			—		2,508


End of period	$	2		$	2,804		$	—	$	2,806

- 22 -

HOLLY ENERGY PARTNERS, L.P.

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

This Item 2, including but not limited to the sections on “Results of Operations” and “Liquidity and Capital Resources,” contains forward-looking statements. See “Forward-Looking Statements” at the beginning of Part I of this Quarterly Report on Form 10-Q. In this document, the words “we,” “our,” “ours” and “us” refer to Holly Energy Partners, L.P. (“HEP”) and its consolidated subsidiaries or to HEP or an individual subsidiary and not to any other person.

OVERVIEW

HEP is a Delaware limited partnership. We own and operate petroleum product and crude oil pipeline and terminal, tankage and loading rack facilities that support the refining and marketing operations of HollyFrontier Corporation (formerly known as Holly Corporation) (“HFC”) in west Texas, New Mexico, Utah, Oklahoma, Idaho and Arizona. HFC and its subsidiaries currently own a 34% interest in us including the 2% general partnership interest. HFC changed its name in connection with the consummation of its merger of equals with Frontier Oil Corporation effective July 1, 2011. All previous references to “Holly” within this document have been replaced with “HFC.”

We also own and operate refined product pipelines and terminals, located primarily in Texas, that service Alon’s (“Alon”) Big Spring refinery in Big Spring, Texas. Additionally, we own a 25% joint venture interest in the SLC Pipeline (the “SLC Pipeline”), a 95-mile intrastate crude oil pipeline system that serves refineries in the Salt Lake City area.

2010 Acquisitions

Tulsa East / Lovington Storage Asset Transaction

On March 31, 2010, we acquired from HFC certain storage assets for $93 million, consisting of hydrocarbon storage tanks having approximately 2 million barrels of storage capacity, a rail loading rack and a truck unloading rack located at HFC’s Tulsa refinery east facility and an asphalt loading rack facility located at HFC’s Navajo refinery facility in Lovington, New Mexico.

Agreements with HFC and Alon

We serve HFC’s refineries in New Mexico, Utah and Oklahoma under the following long-term pipeline and terminal, tankage and throughput agreements:

•

HFC PTA (pipelines and terminals throughput agreement expiring in 2019 that relates to assets contributed to us by HFC upon our initial public offering in 2004);

•

HFC IPA (intermediate pipelines throughput agreement expiring in 2024 that relates to assets acquired from HFC in 2005 and 2009);

•

HFC CPTA (crude pipelines and tankage throughput agreement expiring in 2023 that relates to assets acquired from HFC in 2008);

•

HFC PTTA (pipeline, tankage and loading rack throughput agreement expiring in 2024 that relates to the Tulsa east facilities acquired from Sinclair in 2009 and from HFC in March 2010);

•

HFC RPA (pipeline throughput agreement expiring in 2024 that relates to the Roadrunner Pipeline acquired from HFC in 2009);

•

HFC ETA (equipment and throughput agreement expiring in 2024 that relates to the Tulsa west facilities acquired from HFC in 2009);

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•

HFC NPA (natural gas pipeline throughput agreement expiring in 2024); and

•

HFC ATA (asphalt loading rack throughput agreement expiring in 2025 that relates to the Lovington rack facility acquired from HFC in March 2010).

We also have a pipelines and terminals agreement with Alon expiring in 2020 under which Alon has agreed to transport on our pipelines and throughput through our terminals volumes of refined products that result in a minimum level of annual revenue that is also subject to annual tariff rate adjustments.

We have a capacity lease agreement with Alon under which we lease Alon space on our Orla to El Paso pipeline for the shipment of up to 17,500 barrels of refined product per day. The terms under this agreement expire beginning in 2012 through 2018.

As of July 1, 2011, contractual minimums under our long-term service agreements are as follows:


Agreement	Minimum Annualized Commitment (In millions)		Year of Maturity	Contract Type

HFC PTA	$	45.6	2019	Minimum revenue commitment
HFC IPA		21.6	2024	Minimum revenue commitment
HFC CPTA		29.6	2023	Minimum revenue commitment
HFC PTTA		29.8	2024	Minimum revenue commitment
HFC RPA		9.5	2024	Minimum revenue commitment
HFC ETA		2.8	2024	Minimum revenue commitment
HFC ATA		0.5	2025	Minimum revenue commitment
HFC NPA		0.6	2024	Minimum revenue commitment
Alon PTA		23.4	2020	Minimum volume commitment
Alon capacity lease		6.6	Various	Capacity lease


Total	$	170.0

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

Under certain provisions of an omnibus agreement (“Omnibus Agreement”) that we have with HFC, we pay HFC an annual administrative fee, currently $2.3 million, for the provision by HFC or its affiliates of various general and administrative services to us. This fee does not include the salaries of pipeline and terminal personnel or the cost of their employee benefits, which are separately charged to us by HFC. We also reimburse HFC and its affiliates for direct expenses they incur on our behalf.

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RESULTS OF OPERATIONS (Unaudited)

Income, Distributable Cash Flow and Volumes

The following tables present income, distributable cash flow and volume information for the three and the six months ended June 30, 2011 and 2010.


	Three Months Ended June 30,						Change from 2010
	2011			2010			Change from 2010
	(In thousands, except per unit data)
Revenues
Pipelines:
Affiliates – refined product pipelines	$	11,689		$	12,067		$	(378	)
Affiliates – intermediate pipelines		5,069			4,964			105
Affiliates – crude pipelines		9,624			9,728			(104	)

		26,382			26,759			(377	)
Third parties – refined product pipelines		11,906			6,455			5,451

		38,288			33,214			5,074
Terminals and loading racks:
Affiliates		10,757			10,320			437
Third parties		1,895			1,949			(54	)

		12,652			12,269			383

Total revenues		50,940			45,483			5,457

Operating costs and expenses
Operations		14,366			13,495			871
Depreciation and amortization		7,713			7,591			122
General and administrative		1,573			1,913			(340	)

		23,652			22,999			653


Operating income		27,288			22,484			4,804

Equity in earnings of SLC Pipeline		467			544			(77	)
Interest income		—			2			(2	)
Interest expense, including amortization		(8,724	)		(9,549	)		825

		(8,257	)		(9,003	)		746


Income before income taxes		19,031			13,481			5,550

State income tax		(18	)		(46	)		28


Net income		19,013			13,435			5,578

Less general partner interest in net income, including incentive distributions ⁽¹⁾		3,847			2,909			938


Limited partners’ interest in net income	$	15,166		$	10,526		$	4,640


Limited partners’ earnings per unit – basic and diluted ⁽¹⁾	$	0.69		$	0.48		$	0.21


Weighted average limited partners’ units outstanding		22,079			22,079			—

EBITDA ⁽²⁾	$	35,468		$	30,619		$	4,849

Distributable cash flow ⁽³⁾	$	21,421		$	22,673		$	(1,252	)


Volumes (bpd)
Pipelines:
Affiliates – refined product pipelines		90,984			98,464			(7,480	)
Affiliates – intermediate pipelines		84,201			86,140			(1,939	)
Affiliates – crude pipelines		160,648			141,263			19,385

		335,833			325,867			9,966
Third parties – refined product pipelines		51,627			34,844			16,783

		387,460			360,711			26,749
Terminals and loading racks:
Affiliates		182,394			186,515			(4,121	)
Third parties		42,694			37,902			4,792

		225,088			224,417			671

Total for pipelines and terminal assets (bpd)		612,548			585,128			27,420

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	Six Months Ended June 30,						Change from 2010
	2011			2010			Change from 2010
	(In thousands, except per unit data)
Revenues
Pipelines:
Affiliates – refined product pipelines	$	21,547		$	23,547		$	(2,000	)
Affiliates – intermediate pipelines		9,702			10,756			(1,054	)
Affiliates – crude pipelines		18,945			19,133			(188	)

		50,194			53,436			(3,242	)
Third parties – refined product pipelines		21,061			11,859			9,202

		71,255			65,295			5,960
Terminals and loading racks:
Affiliates		21,052			17,240			3,812
Third parties		3,650			3,644			6

		24,702			20,884			3,818

Total revenues		95,957			86,179			9,778

Operating costs and expenses
Operations		27,162			26,555			607
Depreciation and amortization		15,353			14,801			552
General and administrative		2,936			4,476			(1,540	)

		45,451			45,832			(381	)


Operating income		50,506			40,347			10,159

Equity in earnings of SLC Pipeline		1,207			1,025			182
Interest income		—			5			(5	)
Interest expense, including amortization		(17,273	)		(17,093	)		(180	)
Other		(12	)		(7	)		(5	)

		(16,078	)		(16,070	)		(8	)


Income before income taxes		34,428			24,277			10,151

State income tax		(246	)		(140	)		(106	)


Net income		34,182			24,137			10,045

Less general partner interest in net income, including incentive distributions ⁽¹⁾		7,409			5,555			1,854


Limited partners’ interest in net income	$	26,773		$	18,582		$	8,191


Limited partners’ earnings per unit – basic and diluted ⁽¹⁾	$	1.21		$	0.84		$	0.37


Weighted average limited partners’ units outstanding		22,079			22,079			—

EBITDA ⁽²⁾	$	67,054		$	56,166		$	10,888

Distributable cash flow ⁽³⁾	$	42,193		$	42,831		$	(638	)


Volumes (bpd)
Pipelines:
Affiliates – refined product pipelines		84,139			95,937			(11,798	)
Affiliates – intermediate pipelines		76,452			82,649			(6,197	)
Affiliates – crude pipelines		148,520			138,094			10,426

		309,111			316,680			(7,569	)
Third parties – refined product pipelines		50,086			32,850			17,236

		359,197			349,530			9,667
Terminals and loading racks:
Affiliates		170,230			175,218			(4,988	)
Third parties		41,532			36,381			5,151

		211,762			211,599			163

Total for pipelines and terminal assets (bpd)		570,959			561,129			9,830

(1)

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

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(2)

EBITDA is calculated as net income plus (i) interest expense, net of interest income, (ii) state income tax and (iii) depreciation and amortization. EBITDA is not a calculation based upon U.S. generally accepted accounting principles (“GAAP”). However, the amounts included in the EBITDA calculation are derived from amounts included in our consolidated financial statements. EBITDA should not be considered as an alternative to net income or operating income, as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity. EBITDA is not necessarily comparable to similarly titled measures of other companies. EBITDA is presented here because it is a widely used financial indicator used by investors and analysts to measure performance. EBITDA also is used by our management for internal analysis and as a basis for compliance with financial covenants.

Set forth below is our calculation of EBITDA.


	Three Months Ended June 30,					Six Months Ended June 30,
	2011		2010			2011		2010
	(In thousands)

Net income	$	19,013	$	13,435		$	34,182	$	24,137

Add (subtract):
Interest expense		8,419		8,209			16,678		14,095
Amortization of discount and deferred debt issuance costs		305		264			595		458
Increase in interest expense – change in fair value of interest rate swaps and swap settlement costs		—		1,076			—		2,540
Interest income		—		(2	)		—		(5	)
State income tax		18		46			246		140
Depreciation and amortization		7,713		7,591			15,353		14,801


EBITDA	$	35,468	$	30,619		$	67,054	$	56,166

(3)

Distributable cash flow is not a calculation based upon GAAP. However, the amounts included in the calculation are derived from amounts separately presented in our consolidated financial statements, with the exception of equity in excess cash flows over earnings of SLC Pipeline, and maintenance capital expenditures. Distributable cash flow should not be considered in isolation or as an alternative to net income or operating income as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity. Distributable cash flow is not necessarily comparable to similarly titled measures of other companies. Distributable cash flow is presented here because it is a widely accepted financial indicator used by investors to compare partnership performance. It is also 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.

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Set forth below is our calculation of distributable cash flow.


	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(In thousands)

Net income	$	19,013		$	13,435		$	34,182		$	24,137

Add (subtract):
Depreciation and amortization		7,713			7,591			15,353			14,801
Amortization of discount and deferred debt issuance costs		305			264			595			458
Increase in interest expense – change in fair value of interest rate swaps and swap settlement costs		—			1,076			—			2,540
Equity in excess cash flows over earnings of SLC Pipeline		308			174			314			352
Increase (decrease) in deferred revenue		(4,014	)		1,414			(5,118	)		2,521
Maintenance capital expenditures*		(1,904	)		(1,281	)		(3,133	)		(1,978	)


Distributable cash flow	$	21,421		$	22,673		$	42,193		$	42,831

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.


	June 30,			December 31,
	2011			2010
Balance Sheet Data	(In thousands)

Cash and cash equivalents	$	1,402		$	403
Working capital deficit	$	(2,026	)	$	(7,758	)
Total assets	$	651,151		$	643,273
Long-term debt	$	518,818		$	491,648
Partners’ equity ⁽⁴⁾	$	99,947		$	109,372

(4)

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 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 $218 million would have been recorded in our financial statements as increases to our properties and equipment and intangible assets instead of decreases to our partners’ equity.

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Results of Operations – Three Months Ended June 30, 2011 Compared with Three Months Ended June 30, 2010

Summary

Net income for the three months ended June 30, 2011 was $19 million, a $5.6 million increase compared to the three months ended June 30, 2010. This increase in overall earnings is due principally to an increase in deferred revenue realized and increased third-party refined product pipeline shipments.

Revenues for the three months ended June 30, 2011 include the recognition of $5.5 million of prior shortfalls billed to shippers in 2010 as they did not meet their minimum volume commitments within the contractual make-up period. This includes the recognition of $2.4 million of shortfalls billed in the third and fourth quarters of 2010 as a result of an amendment to the Alon PTA in June 2011 that limits the carryover term of shortfall credits to the calendar year in which the shortfalls occurred. Revenues of $1.5 million relating to deficiency payments associated with certain guaranteed shipping contracts were deferred during the three months ended June 30, 2011. Such deferred revenue will be recognized in earnings either as payment for shipments in excess of guaranteed levels, or when shipping rights expire unused.

Revenues

Total revenues for the three months ended June 30, 2011 were $50.9 million, a $5.5 million increase compared to the three months ended June 30, 2010. This is due principally to a $3.8 million increase in previously deferred revenue realized. Overall pipeline shipments were up 7% from the second quarter of 2010, due mainly to an increase in third-party refined product pipeline shipments.

Revenues from our refined product pipelines were $23.6 million, an increase of $5.1 million compared to the three months ended June 30, 2010. This increase is due principally to a $3.6 million increase in previously deferred revenue realized. Volumes shipped on our refined product pipelines averaged 142.6 thousand barrels per day (“mbpd“) compared to 133.3 mbpd for the same period last year.

Revenues from our intermediate pipelines were $5.1 million, an increase of $0.1 million compared to the three months ended June 30, 2010. This reflects a $0.2 million increase in previously deferred revenue realized, partially offset by a decrease in intermediate pipeline shipments. Volumes shipped on our intermediate pipelines averaged 84.2 mbpd compared to 86.1 mbpd for the same period last year.

Revenues from our crude pipelines were $9.6 million, a decrease of $0.1 million compared to the three months ended June 30, 2010. Volumes shipped on our crude pipelines averaged 160.6 mbpd compared to 141.3 mbpd for the same period last year. Although shipments were up, we did not realize higher revenues in the current year due to the receipt of higher minimum revenue commitment fees from HFC in 2010.

Revenues from terminal, tankage and loading rack fees were $12.7 million, an increase of $0.4 million compared to the three months ended June 30, 2010. Refined products terminalled in our facilities increased to an average of 225.1 mbpd compared to 224.4 mbpd for the same period last year.

Operations Expense

Operations expense for the three months ended June 30, 2011 increased by $0.9 million compared to the three months ended June 30, 2010. This increase is due principally to increased maintenance costs during the current year second quarter.

Depreciation and Amortization

Depreciation and amortization for the three months ended June 30, 2011 increased by $0.1 million compared to the three months ended June 30, 2010.

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General and Administrative

General and administrative costs for the three months ended June 30, 2011 decreased by $0.3 million compared to the three months ended June 30, 2010 due to lower professional fees during the current year.

Equity in Earnings of SLC Pipeline

Our equity in earnings of the SLC Pipeline was $0.5 million for the three months ended June 30, 2011 and 2010.

Interest Expense

Interest expense for the three months ended June 30, 2011 totaled $8.7 million, a decrease of $0.8 million compared to the three months ended June 30, 2010. Interest costs for the three months ended June 30, 2010 include $1.1 million in costs attributable to the partial settlement of an interest rate swap. This was partially offset by interest on increased credit agreement borrowings during the current year. Our aggregate effective interest rate was 6.7% for the three months ended June 30, 2011 compared to 7.7% for the same period of 2010.

State Income Tax

We recorded state income taxes of $18,000 and $46,000 for the three months ended June 30, 2011 and 2010, respectively, which are solely attributable to the Texas margin tax.

Results of Operations – Six Months Ended June 30, 2011 Compared with Six Months Ended June 30, 2010

Summary

Net income for the six months ended June 30, 2011 was $34.2 million, a $10 million increase compared to the six months ended June 30, 2010. This increase in overall earnings is due principally to an overall increase in pipeline shipments, earnings attributable to our March 2010 asset acquisitions and an increase in previously deferred revenue realized.

Revenues for the six months ended June 30, 2011 include the recognition of $9.1 million of prior shortfalls billed to shippers in 2010. Revenues of $3.9 million relating to deficiency payments associated with certain guaranteed shipping contracts were deferred during the six months ended June 30, 2011. Such deferred revenue will be recognized in earnings either as payment for shipments in excess of guaranteed levels, or when shipping rights expire unused.

Revenues

Total revenues for the six months ended June 30, 2011 were $96 million, a $9.8 million increase compared to the six months ended June 30, 2010. This is due principally to increased pipeline shipments, revenues attributable to our March 2010 asset acquisitions and a $4.9 million increase in previously deferred revenue realized. Overall pipeline shipments were up 3% from the six months ended June 30, 2010, due to an increase in third-party refined product pipeline shipments that was partially offset by decreased affiliate pipeline shipments.

Related-party pipeline and throughput volumes were down during the current year-to-date period as a result of downtime at HFC’s Navajo refinery following a plant-wide power outage in late January 2011 and the subsequent delay in restoring production to planned levels.

Revenues from our refined product pipelines were $42.6 million, an increase of $7.2 million compared to the six months ended June 30, 2010. This is due to a $5.3 million increase in previously deferred revenue realized and an increase in third-party refined product pipeline shipments. Volumes shipped on our refined product pipelines averaged 134.2 mbpd compared to 128.8 mbpd for the same period last year.

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Revenues from our intermediate pipelines were $9.7 million, a decrease of $1.1 million compared to the six months ended June 30, 2010. This reflects a $0.4 million decrease in previously deferred revenue realized and a decrease in intermediate pipeline shipments. Shipments on our intermediate pipelines decreased to an average of 76.5 mbpd compared to 82.6 mbpd for the same period last year.

Revenues from our crude pipelines were $18.9 million, a decrease of $0.2 million compared to the six months ended June 30, 2010. Volumes on our crude pipelines averaged 148.5 mbpd compared to 138.1 mbpd for the same period last year. Although shipments were up, we did not realize higher revenues in the current year due to the receipt of higher minimum revenue commitment fees from HFC in 2010.

Revenues from terminal, tankage and loading rack fees were $24.7 million, an increase of $3.8 million compared to the six months ended June 30, 2010. This increase is due primarily to revenues attributable to our Tulsa storage and rack facilities acquired from HFC in March 2010. Refined products terminalled in our facilities increased to an average of 211.8 mbpd compared to 211.6 mbpd for the same period last year.

Operations Expense

Operations expense for the six months ended June 30, 2011 increased by $0.6 million compared to the six months ended June 30, 2010. This increase is due principally to increased maintenance costs during the current year-to-date period.

Depreciation and Amortization

Depreciation and amortization for the six months ended June 30, 2011 increased by $0.6 million compared to the six months ended June 30, 2010. This was due to increased depreciation attributable to our March 2010 asset acquisitions from HFC and capital projects.

General and Administrative

General and administrative costs for the six months ended June 30, 2011 decreased by $1.5 million compared to the six months ended June 30, 2010, which included higher professional fees and costs as a result of our March 2010 asset acquisitions from HFC.

Equity in Earnings of SLC Pipeline

Our equity in earnings of the SLC Pipeline was $1.2 million and $1 million for the six months ended June 30, 2011 and 2010, respectively.

Interest Expense

Interest expense for the six months ended June 30, 2011 totaled $17.3 million, an increase of $0.2 million compared to the six months ended June 30, 2010. This increase reflects interest on increased debt levels during the current year, partially offset by prior year costs of $1.1 million that relate to the partial settlement of an interest rate swap. Excluding the effects of fair value adjustments to this swap in 2010, our aggregate effective interest rate was 6.7% for the six months ended June 30, 2011 compared to 6.8% for 2010.

State Income Tax

We recorded state income taxes of $246,000 and $140,000 for the six months ended June 30, 2011 and 2010, respectively, which are solely attributable to the Texas margin tax.

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LIQUIDITY AND CAPITAL RESOURCES

Overview

During the six months ended June 30, 2011, we received advances totaling $64 million and repaid $37 million, resulting in net borrowings of $27 million under our $275 million senior secured revolving credit facility (the “Credit Agreement”) and an outstanding balance of $186 million at June 30, 2011.

The Credit Agreement 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 and to fund distributions to unitholders up to a $30 million sub-limit.

In March 2010, we issued $150 million in aggregate principal amount of 8.25% senior notes maturing March 15, 2018 (the “8.25% Senior Notes”). A portion of the $147.5 million in net proceeds received was used to fund our $93 million purchase of the Tulsa and Lovington storage assets from HFC on March 31, 2010. Additionally, we used a portion to repay $42 million in outstanding Credit Agreement borrowings, with the remaining proceeds available for general partnership purposes, including working capital and capital expenditures. In addition, we have outstanding $185 million in aggregate principal amount of 6.25% senior notes maturing March 1, 2015 (the “6.25% Senior Notes”) that are registered with the SEC.

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 and May 2011 we paid regular quarterly cash distributions of $0.845 and $0.855, respectively, on all units in an aggregate amount of $44.9 million. Included in these distributions were $6.4 million of incentive distribution payments to the general partner.

Cash and cash equivalents increased by $1 million during the six months ended June 30, 2011. The cash flows provided by operating activities of $46.3 million exceeded the combined cash flows used for investing and financing activities of $22.9 million and $22.4 million, respectively. Working capital increased by $5.7 million to $(2.0) million during the six months ended June 30, 2011.

Cash Flows - Operating Activities

Cash flows from operating activities increased by $1.1 million from $45.2 million for the six months ended June 30, 2010 to $46.3 million for the six months ended June 30, 2011. This increase is due principally to $3.1 million in additional cash collections from our customers combined with a decrease in payments related to operating expenses. These factors were partially offset by increased interest payments.

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 $6.6 million during the six months ended June 30, 2010 related to shortfalls that subsequently expired without recapture and were recognized as revenue during the six months ended June 30, 2011. We recognized an additional $2.4 million related to shortfalls billed in the third and fourth quarters of 2010 as a result of an amendment to the Alon PTA in June 2011 that limits the carryover term of credits attributable to such shortfall billings to the calendar year end in which the shortfalls occurred. Another $1.5 million is included in our accounts receivable at June 30, 2011 related to shortfalls that occurred during the second quarter of 2011.

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Cash Flows - Investing Activities

Cash flows used for investing activities decreased by $20.6 million from $43.5 million for the six months ended June 30, 2010 to $22.9 million for the six months ended June 30, 2011. During the six months ended June 30, 2011 and 2010, we invested $22.9 million and $4.5 million in additions to properties and equipment, respectively. Additionally in March 2010, we acquired storage assets from HFC for $39 million.

Cash Flows - Financing Activities

Cash flows used for financing activities were $22.4 million compared to $1.4 million for the six months ended June 30, 2010, an increase of $21 million. During the six months ended June 30, 2011, we received $64 million and repaid $37 million in advances under the Credit Agreement, we paid $44.9 million in regular quarterly cash distributions to our general and limited partners, paid $3.1 million in financing costs to amend our previous credit agreement and paid $1.4 million for the purchase of common units for recipients of our incentive grants. During the six months ended June 30, 2010, we received $39 million and repaid $90 million in advances under the Credit Agreement. Additionally, we received $147.5 million in net proceeds and incurred $0.4 million in financing costs upon the issuance of the 8.25% Senior Notes. For the six months ended June 30, 2010, we paid $41.3 million in regular quarterly cash distributions to our general and limited partners, paid $54 million in excess of HFC’s transferred basis in the storage assets acquired in March 2010 and paid $2.3 million for the purchase of common units for recipients of our incentive grants.

Capital Requirements

Our pipeline and terminalling operations are capital intensive, requiring investments to maintain, expand, upgrade or enhance existing operations and to meet environmental and operational regulations. Our capital requirements consist of maintenance capital expenditures and expansion capital expenditures. 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, special 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 2011 capital budget is comprised of $5.8 million for maintenance capital expenditures and $20.1 million for expansion capital expenditures.

We are currently constructing five interconnecting pipelines between HFC’s Tulsa east and west refining facilities. The project is expected to cost approximately $35 million with completion in the late summer of 2011. We are finalizing terms under a long-term agreement with HFC to transfer intermediate products via these pipelines that will commence upon completion of the project. In the event that we are unable to obtain such an agreement, HFC will reimburse us for the cost of the pipelines.

Additionally, we have two expansion projects to provide 60,000 bpd of additional crude pipeline take-away capacity resulting from increased Delaware Basin drilling activity in southeast New Mexico.

The first project will increase one of our existing crude oil trunk lines from 35,000 bpd to 60,000 bpd. This 35-mile pipeline transports crude oil from our gathering system in southeast New Mexico to HFC’s New Mexico refining facilities. The scope of the project includes the replacement of 5 miles of existing pipe with larger diameter pipe and the addition of a higher horsepower pump. Work will commence shortly and is expected to be completed during the first half of 2012.

The second project will consist of the reactivation and conversion to crude oil service a 70-mile, 8-inch petroleum products pipeline owned by us. Once in service, this pipeline would be capable of transporting

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up to 35,000 bpd of crude oil from rapidly developing Delaware Basin production in the Carlsbad, New Mexico area to either a third party common carrier pipeline station for transport to major crude oil markets or to HFC’s New Mexico refining facilities. The scope of this project is in the process of being finalized. It is anticipated that this project, subject to receipt of acceptable shipper support and board approval, could also be completed during the first half of 2012.

We have an option agreement with HFC, granting us an option to purchase HFC’s 75% equity interest in UNEV Pipeline, LLC (“UNEV Pipeline”), a joint venture pipeline currently under construction that will be capable of transporting refined petroleum products from Salt Lake City, Utah to Las Vegas, Nevada. Under this agreement, we have an option to purchase HFC’s equity interest in the UNEV Pipeline, effective for a 180-day period commencing when the UNEV Pipeline becomes operational, at a purchase price equal to HFC’s investment in the joint venture pipeline, plus interest at 7% per annum. The initial capacity of the pipeline will be 62,000 bpd, with the capacity for further expansion to 120,000 bpd. The current total construction cost of the pipeline project including terminals is expected to be approximately $385 million. This includes the construction of ethanol blending and storage facilities at the Cedar City terminal. HFC’s share of this estimated cost is $289 million and is exclusive of the 7% per annum interest cost under our option to purchase HFC’s 75% interest in the UNEV Pipeline. The pipeline is in the final construction phase and is expected to be mechanically complete later this year.

We expect that our currently planned sustaining and maintenance capital expenditures as well as expenditures for acquisitions and capital development projects such as the UNEV Pipeline described above, 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 fund some of these capital projects may be limited, especially the UNEV Pipeline. We are not obligated to purchase the UNEV Pipeline nor are we subject to any fees or penalties if HLS’ board of directors decides not to proceed with this opportunity.

Credit Agreement

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 1.00% to 2.00%) or (b) at a rate equal to the London Interbank Offered Rate (“LIBOR“) plus an applicable margin (ranging from 2.00% to 3.00%). 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 0.375% to 0.50% based upon the ratio of our funded debt to EBITDA for the four most recently completed fiscal quarters.

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The Credit Agreement imposes certain requirements on us 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 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 agreement, the lenders will be able to accelerate the maturity of the debt and exercise other rights and remedies.

Senior Notes

The 6.25% Senior Notes and 8.25% Senior Notes (collectively, the “Senior Notes”) are unsecured and impose certain restrictive covenants which we are subject to and currently in compliance with, including limitations on our ability to incur additional indebtedness, make investments, sell assets, incur certain liens, pay distributions, enter into transactions with affiliates, and enter into mergers. At any time when the Senior Notes are rated investment grade by both Moody’s and Standard & Poor’s and no default or event of default exists, we will not be subject to many of the foregoing covenants. Additionally, we have certain redemption rights under the Senior Notes.

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


	June 30, 2011			December 31, 2010
	(In thousands)
Credit Agreement	$	186,000		$	159,000

6.25% Senior Notes
Principal		185,000			185,000
Unamortized discount		(1,394	)		(1,584	)
Unamortized premium – dedesignated fair value hedge		1,271			1,444

		184,877			184,860


8.25% Senior Notes
Principal		150,000			150,000
Unamortized discount		(2,059	)		(2,212	)

		147,941			147,788


Total long-term debt	$	518,818		$	491,648

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

Contractual Obligations

During the six months ended June 30, 2011, we had net borrowings of $27 million resulting in $186 million of borrowings outstanding under the Credit Agreement at June 30, 2011.

There were no other significant changes to our long-term contractual obligations during this period.

Impact of Inflation

Inflation in the United States has been relatively moderate in recent years and did not have a material impact on our results of operations for the six months ended June 30, 2011 and 2010. Historically, the PPI has increased an average of 3% annually over the past 5 calendar years. However, the June 30, 2011 PPI increased at a rate of 7% on a year-over-year basis.

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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 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 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, HFC agreed to indemnify us up to certain aggregate amounts for any environmental noncompliance and remediation liabilities associated with assets transferred to us and occurring or existing prior to the date of such transfers. The transfers that are covered by the agreement include the refined product pipelines, terminals and tanks transferred by HFC’s subsidiaries in connection with our initial public offering in July 2004, the intermediate pipelines acquired in July 2005, the crude pipelines and tankage assets acquired in 2008, and the asphalt loading rack facility acquired in March 2010. The Omnibus Agreement provides environmental indemnification of up to $15 million for the assets transferred to us, other than the crude pipelines and tankage assets, plus an additional $2.5 million for the intermediate pipelines acquired in July 2005. Except as described below, HFC’s indemnification obligations described above will remain in effect for an asset for ten years following the date it is transferred to us. The Omnibus Agreement also provides an additional $7.5 million of indemnification through 2023 for environmental noncompliance and remediation liabilities specific to the crude pipelines and tankage assets. HFC’s indemnification obligations described above 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, or (vi) the Tulsa east storage tanks and loading racks acquired in March 2010.

Under provisions of the HFC ETA and HFC PTTA, HFC will indemnify us for environmental liabilities arising from our pre-ownership operations of the Tulsa west loading rack facilities acquired from HFC in August 2009, the Tulsa logistics and storage assets acquired from Sinclair in December 2009 and the Tulsa east storage tanks and loading racks acquired from HFC in March 2010. Additionally, HFC agreed to indemnify us for any liabilities arising from HFC’s operation of the loading racks under the HFC ETA.

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 through 2015, subject to a $100,000 deductible and a $20 million maximum liability cap.

There are environmental remediation projects that are currently in progress that relate to certain assets acquired from HFC. Certain of these projects were underway prior to our purchase and represent liabilities of HFC as the obligation for future remediation activities was retained by HFC. At June 30,

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2011, we have an accrual of $0.2 million that relates to environmental clean-up projects for which we have assumed liability. 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. 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.

Our significant accounting policies are described in “Item 7. Management’s Discussion and Analysis of Financial Condition and Operations – Critical Accounting Policies” in our Annual Report on Form 10-K for the year ended December 31, 2010. Certain critical accounting policies that materially affect the amounts recorded in our consolidated financial statements include revenue recognition, assessing the possible impairment of certain long-lived assets and assessing contingent liabilities for probable losses. There have been no changes to these policies in 2011. We consider these policies to be the most critical to understanding the judgments that are involved and the uncertainties that could impact our results of operations, financial condition and cash flows.

RISK MANAGEMENT

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

As of June 30, 2011, we have an interest rate swap that hedges our exposure to the cash flow risk caused by the effects of LIBOR changes on a $155 million Credit Agreement advance. This interest rate swap effectively converts $155 million of LIBOR based debt to fixed rate debt having an interest rate of 3.74% plus an applicable margin currently 2.50%, which equals an effective interest rate of 6.24% as of June 30, 2011. This swap contract matures in February 2013.

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Additional information on our interest rate swap is as follows:

Derivative Instrument

Balance Sheet

Location

Fair Value

Location of Offsetting
Balance

Offsetting
Amount

(In thousands)

June 30, 2011

Interest rate swap designated as cash flow hedging instrument:

Variable-to-fixed interest rate swap contract ($155 million of LIBOR based debt interest)

Other long-term liabilities

8,472

Accumulated other comprehensive loss

8,472

December 31, 2010

Interest rate swap designated as cash flow hedging instrument:

Variable-to-fixed interest rate swap contract ($155 million of LIBOR based debt interest)

Other long-term liabilities

10,026

Accumulated other comprehensive loss

10,026

We review publicly available information on our counterparty in order to review and monitor its financial stability and assess its ongoing ability to honor its commitments under the interest rate swap contract. This counterparty is a large financial institution. Furthermore, we have not experienced, nor do we expect to experience, any difficulty in the counterparty honoring its respective commitment.

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

At June 30, 2011, we had an outstanding principal balance on our 6.25% Senior Notes and 8.25% Senior Notes of $185 million and $150 million, respectively. A change in interest rates would generally affect the fair value of the Senior Notes, but not our earnings or cash flows. At June 30, 2011, the fair value of our 6.25% Senior Notes and 8.25% Senior Notes were $184.1 million and $159.4 million, respectively. We estimate a hypothetical 10% change in the yield-to-maturity applicable to the 6.25% Senior Notes and 8.25% Senior Notes at June 30, 2011 would result in a change of approximately $4 million and $6 million, respectively, in the fair value of the underlying notes.

For the variable rate Credit Agreement, changes in interest rates would affect cash flows, but not the fair value. At June 30, 2011, borrowings outstanding under the Credit Agreement were $186 million. By means of our cash flow hedge, we have effectively converted the variable rate on $155 million of outstanding borrowings to a fixed rate of 6.24%.

At June 30, 2011, our cash and cash equivalents included highly liquid investments with a maturity of three months or less at the time of purchase. Due to the short-term nature of our cash and cash equivalents, a hypothetical 10% increase in interest rates would not have a material effect on the fair market value of our portfolio. Since we have the ability to liquidate this portfolio, we do not expect our operating results or cash flows to be materially affected by the effect of a sudden change in market interest rates on our investment portfolio.

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

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

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Item 3.

Quantitative and Qualitative Disclosures About Market Risks

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 cash and cash equivalents and long-term debt. We utilize derivative instruments to hedge our interest rate exposure, also discussed under “Risk Management.”

Since we do not own products shipped on our pipelines or terminalled at our terminal facilities, we do not have market risks associated with commodity prices.

Item 4.

Controls and Procedures

(a) Evaluation of disclosure controls and procedures

Our principal executive officer and principal financial officer have evaluated, as required by Rule 13a-15(b) under the Securities Exchange Act of 1934 (the “Exchange Act”), our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this quarterly report on Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information we are required to disclose in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of June 30, 2011.

(b) Changes in internal control over financial reporting

There have been no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during our last fiscal quarter that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1.

Legal Proceedings

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

Item 6.

Exhibits

The Exhibit Index on page 42 of this Quarterly Report on Form 10-Q lists the exhibits that are filed or furnished, as applicable, as part of the Quarterly Report on Form 10-Q.

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HOLLY ENERGY PARTNERS, L.P.

SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


		HOLLY ENERGY PARTNERS, L.P.
		(Registrant)

		By: HEP LOGISTICS HOLDINGS, L.P. its General Partner

		By: HOLLY LOGISTIC SERVICES, L.L.C. its General Partner

Date:	August 1, 2011	/s/ Douglas S. Aron
		Douglas S. Aron
		Executive Vice President and
		Chief Financial Officer
		(Principal Financial Officer)

		/s/ Scott C. Surplus
		Scott C. Surplus
		Vice President and Controller
		(Principal Accounting Officer)

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Exhibit Index


Exhibit Number		Description

3.1		Amendment No. 1 to the First Amended and Restated Limited Liability Company Agreement of Holly Logistic Services, L.L.C., dated April 27, 2011 (incorporated by reference to Exhibit 3.1 of Registrant’s Form 8-K Current Report dated May 3, 2011, File No. 1-32225).

10.1+		First Letter Agreement with respect to Pipelines and Terminals Agreement between Holly Energy Partners, L.P. and ALON USA, LP, dated January 25, 2005

10.2+		Second Letter Agreement with respect to Pipelines and Terminals Agreement between Holly Energy Partners, L.P. and ALON USA, LP, dated June 29, 2007

10.3+		Third Letter Agreement with respect to Pipelines and Terminals Agreement between Holly Energy Partners, L.P. and ALON USA, LP, dated April 1, 2011

10.4+		First Amendment of Pipelines and Terminals Agreement between Holly Energy Partners, L.P. and ALON USA, LP, dated September 1, 2008

10.5+		Second Amendment to Pipelines and Terminals Agreement between Holly Energy Partners, L.P. and ALON USA, LP, dated March 1, 2011

10.6+		Third Amendment to Pipelines and Terminals Agreement between Holly Energy Partners, L.P. and ALON USA, LP, dated June 6, 2011

12.1+		Computation of Ratio of Earnings to Fixed Charges.

31.1+		Certification of Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002.

31.2+		Certification of Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002.

32.1++		Certification of Chief Executive Officer under Section 906 of the Sarbanes-Oxley Act of 2002.

32.2++		Certification of Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act of 2002.

101**		The following financial information from Holly Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Income, (iii) Consolidated Statements of Cash Flows, (iv) Consolidated Statements of Partners’ Equity, and (v) Notes to Consolidated Financial Statements (tagged as blocks of text).

+	Filed herewith.

++	Furnished herewith.

**	Furnished electronically herewith.

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