Holly Energy Partners (HEP) 10-Q 2009 Q2 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2009

OR

o 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.)

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

(Address of principal executive offices)

(214) 871-3555

(Registrant’s telephone number, including area code)

None

(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.

Yesþ      Noo

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).

Yeso      Noo

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. (Check one):

Large accelerated filero  Accelerated filerþ  Non-accelerated filero
(Do not check if a smaller reporting company) Smaller reporting companyo 

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Exchange Act).

Yeso Noþ

The number of the registrant’s outstanding common units at July 25, 2009 was 10,582,400.

HOLLY ENERGY PARTNERS, L.P.
INDEX

PART I. FINANCIAL INFORMATION	3
FORWARD-LOOKING STATEMENTS	3
Item 1. Financial Statements (Unaudited, except December 31, 2008 Balance Sheet)	4
Consolidated Balance Sheets	4
Consolidated Statements of Income	5
Consolidated Statements of Cash Flows	6
Consolidated Statement of Equity	7
Notes to Consolidated Financial Statements	8
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 3. Quantitative and Qualitative Disclosures About Market Risks	44
Item 4. Controls and Procedures	44
PART II. OTHER INFORMATION	45
Item 1. Legal Proceedings	45
Item 6. Exhibits	45
SIGNATURES	46
EX-4.1
EX-4.2
EX-4.3
EX-12.1
EX-31.1
EX-31.2
EX-32.1
EX-32.2

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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. These statements are based on management’s beliefs and assumptions 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 believe that the expectations reflected in these forward-looking statements are reasonable, we cannot assure you that our expectations will prove correct. Therefore, actual outcomes and results could differ materially from what is expressed, implied or forecast in these statements. Any differences could be caused by a number of factors, including, but 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 Holly 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 pending 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, operations 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, 2008 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, 2009			December 31,
	(Unaudited)			2008
	(In thousands, except unit data)
ASSETS
Current assets:
Cash and cash equivalents	$	4,195		$	5,269
Accounts receivable:
Trade		4,804			5,082
Affiliates		8,676			9,395
		13,480			14,477
Prepaid and other current assets		827			593
Total current assets		18,502			20,339
Properties and equipment, net		336,685			290,284
Transportation agreements, net		118,909			122,383
Investment in SLC Pipeline		26,098			—
Other assets		4,921			6,682
Total assets	$	505,115		$	439,688
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	7,074		$	5,816
Accounts payable — affiliates		2,046			2,202
Accrued interest		2,871			2,845
Deferred revenue		10,989			15,658
Accrued property taxes		1,026			1,145
Other current liabilities		1,058			1,505
Short-term borrowings under credit agreement		—			29,000
Total current liabilities		25,064			58,171
Long-term debt		402,810			355,793
Other long-term liabilities		11,482			17,604
Equity:
Holly Energy Partners, L.P. partners’ equity (deficit):
Common unitholders (10,582,400 and 8,390,000 units issued and outstanding at June 30, 2009 and December 31, 2008, respectively)		224,609			169,126
Subordinated unitholders (7,000,000 units issued and outstanding at June 30, 2009 and December 31, 2008)		(88,106	)		(85,059	)
Class B subordinated unitholders (937,500 units issued and outstanding at June 30, 2009 and December 31, 2008)		21,046			21,455
General partner interest (2% interest)		(93,630	)		(94,653	)
Accumulated other comprehensive loss		(8,700	)		(12,967	)
Total Holly Energy Partners, L.P. partners’ equity (deficit)		55,219			(2,098	)
Noncontrolling interest		10,540			10,218
Total equity		65,759			8,120
Total liabilities and equity	$	505,115		$	439,688

See accompanying notes.

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Holly Energy Partners, L.P.
Consolidated Statements of Income
(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
				(In thousands, except per unit data)
Revenues:
Affiliates	$	25,064		$	20,146		$	43,387		$	38,473
Third parties		15,538			6,629			29,339			15,578
		40,602			26,775			72,726			54,051
Operating costs and expenses:
Operations		11,086			9,985			21,882			19,712
Depreciation and amortization		6,853			6,062			13,109			10,375
General and administrative		1,818			1,359			3,142			2,645
		19,757			17,406			38,133			32,732
Operating income		20,845			9,369			34,593			21,319
Other income (expense):
Equity in earnings of SLC Pipeline		423			—			598			—
SLC Pipeline acquisition costs		—			—			(2,500	)		—
Interest income		2			28			8			121
Interest expense		(4,404	)		(5,233	)		(9,807	)		(9,040	)
Other		65			—			65			36
		(3,914	)		(5,205	)		(11,636	)		(8,883	)
Income before income taxes		16,931			4,164			22,957			12,436
State income tax		(112	)		(85	)		(204	)		(153	)
Net income		16,819			4,079			22,753			12,283
Less noncontrolling interest in net income		427			264			922			670
Net income attributable to Holly Energy Partners, L.P.	$	16,392		$	3,815		$	21,831		$	11,613
Less general partner interest in net income attributable to Holly Energy Partners, L.P.		1,849			849			3,142			1,728
Limited partners’ interest in net income attributable to Holly Energy Partners, L.P.	$	14,543		$	2,966		$	18,689		$	9,885
Limited partners’ per unit interest in net income attributable to Holly Energy Partners, L.P. — basic and diluted	$	0.82		$	0.18		$	1.10		$	0.61
Weighted average limited partners’ units outstanding		17,789			16,328			17,058			16,254

See accompanying notes.

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Holly Energy Partners, L.P.
Consolidated Statements of Cash Flows
(Unaudited)

	Six Months Ended
	June 30,
	2009			2008
	(In thousands)
Cash flows from operating activities
Net income	$	22,753		$	12,283
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		13,109			10,375
Equity in earnings of SLC Pipeline		(598	)		—
Change in fair value – interest rate swaps		(628	)		—
Amortization of restricted and performance units		417			548
Gain on sale of assets		—			(36	)
(Increase) decrease in current assets:
Accounts receivable		278			(720	)
Accounts receivable – affiliates		719			(2,892	)
Prepaid and other current assets		(234	)		(137	)
Increase (decrease) in current liabilities:
Accounts payable		1,258			1,468
Accounts payable – affiliates		(156	)		(4,229	)
Accrued interest		26			(97	)
Deferred revenue		(4,669	)		6,781
Accrued property taxes		(119	)		(427	)
Other current liabilities		(447	)		216
Other, net		541			288
Net cash provided by operating activities		32,250			23,421
Cash flows from investing activities
Additions to properties and equipment		(21,826	)		(20,036	)
Acquisition of 16-inch intermediate pipeline		(34,200	)		—
Investment in SLC Pipeline		(25,500	)		—
Acquisition of crude pipelines and tankage assets		—			(171,000	)
Proceeds from sale of assets		—			36
Net cash used for investing activities		(81,526	)		(191,000	)
Cash flows from financing activities
Borrowings under credit agreement		99,000			211,000
Repayments under credit agreement		(81,000	)		(20,000	)
Proceeds from issuance of common units		58,355			104
Capital contribution from general partner		1,191			186
Distributions to HEP unitholders		(27,968	)		(25,656	)
Distributions to noncontrolling interest		(600	)		(900	)
Cost of issuing common units		(160	)		—
Purchase of units for restricted grants		(616	)		(514	)
Deferred financing costs		—			(591	)
Net cash provided by financing activities		48,202			163,629
Cash and cash equivalents
Decrease for period		(1,074	)		(3,950	)
Beginning of period		5,269			10,321
End of period	$	4,195		$	6,371

See accompanying notes.

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Holly Energy Partners, L.P.
Consolidated Statement of Equity
(Unaudited)

	Holly Energy Partners, L.P. Partners’ Equity (Deficit):
													Accumulated
							Class B			General			Other			Non-
	Common			Subordinated			Subordinated			Partner			Comprehensive			Controlling
	Units			Units			Units			Interest			Loss			Interest			Total
	(In thousands)
Balance December 31, 2008	$	169,126		$	(85,059	)	$	21,455		$	(94,653	)	$	(12,967	)	$	10,218		$	8,120
Issuance of common units		58,355			—			—			—			—			—			58,355
Cost of issuing common units		(160	)		—			—			—			—			—			(160	)
Capital contribution		—			—			—			1,191			—			—			1,191
Distributions — HEP unitholders		(12,931	)		(10,780	)		(1,444	)		(2,813	)		—			—			(27,968	)
Distributions — noncontrolling interest		—			—			—			—			—			(600	)		(600	)
Purchase of units for restricted grants		(616	)		—			—			—			—			—			(616	)
Amortization of restricted and performance units		417			—			—			—			—			—			417
Comprehensive income:
Net income		10,418			7,733			1,035			2,645			—			922			22,753
Change in fair value of cash flow hedge		—			—			—			—			4,267			—			4,267
Comprehensive income		10,418			7,733			1,035			2,645			4,267			922			27,020
Balance June 30, 2009	$	224,609		$	(88,106	)	$	21,046		$	(93,630	)	$	(8,700	)	$	10,540		$	65,759

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 41% owned by Holly Corporation and its subsidiaries (collectively “Holly”). We commenced operations July 13, 2004 upon the completion of our initial public offering. In this document, 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, tankage and terminal facilities.

One of Holly’s wholly-owned subsidiaries owns a refinery in Artesia, New Mexico, which Holly operates in conjunction with crude, vacuum distillation and other facilities situated in Lovington, New Mexico (collectively, the “Navajo Refinery”). The Navajo Refinery produces high-value refined products such as gasoline, diesel fuel and jet fuel and serves markets in the southwestern United States and northern Mexico. We own and operate intermediate feedstock pipelines (the “Intermediate Pipelines”), which connect the New Mexico refining facilities. Our operations serving the Navajo Refinery include refined product pipelines that serve as part of the refinery’s product distribution network. We also own and operate crude oil pipelines and on-site crude oil tankage that supply and support the refinery. Our terminal operations serving the Navajo Refinery include an on-site truck rack at the refinery and five integrated refined product terminals located in New Mexico, Texas and Arizona.

Another of Holly’s wholly-owned subsidiaries owns a refinery located near Salt Lake City, Utah (the “Woods Cross Refinery”). Our operations serving the Woods Cross Refinery include crude oil and refined product pipelines, crude oil tankage and a truck rack at the refinery, a refined product terminal in Spokane, Washington and a 50% non-operating interest in product terminals in Boise and Burley, Idaho.

We also own and operate refined products pipelines and terminals, located primarily in Texas, that service Alon USA, Inc.’s (“Alon”) refinery in Big Spring, Texas.

Additionally, we own a refined product terminal in Mountain Home, Idaho, and a 70% interest in Rio Grande Pipeline Company (“Rio Grande”), which provides transportation of liquefied petroleum gases to northern Mexico.

In March 2009, we acquired a 25% joint venture interest in a new 95-mile intrastate pipeline system (the “SLC Pipeline”) jointly owned by Plains All American Pipeline, L.P. (“Plains”) and us. See Note 2 for additional information on the SLC Pipeline joint venture.

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 accounting principles generally accepted in the United States of America 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, 2008. 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, 2009.

These consolidated financial statements reflect management’s evaluation of subsequent events through the time of our filing on July 31, 2009.

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Recent Accounting Pronouncements

Statement of Financial Accounting Standard (“SFAS”) No. 160 “Noncontrolling Interests in Consolidated Financial Statements — an Amendment of Accounting Research Bulletin (“ARB”) No. 51”

SFAS No. 160 became effective January 1, 2009, which changes the classification of noncontrolling interests, also referred to as minority interests, in the consolidated financial statements. As a result, all previous references to “minority interest” within this document have been replaced with “noncontrolling interest.” Additionally, net income attributable to the noncontrolling interest in our Rio Grande subsidiary is now presented as an adjustment to net income to arrive at “Net income attributable to Holly Energy Partners, L.P.” in our Consolidated Statements of Income. Prior to our adoption of this standard, this amount was presented as “Minority interest in Rio Grande,” a non-operating expense item before “Income before income taxes.” Furthermore, equity attributable to noncontrolling interests in our Rio Grande subsidiary is now presented as a separate component of total equity in our Consolidated Financial Statements. We have applied this standard on a retrospective basis. While this presentation differs from previous GAAP requirements, this standard did not affect our net income and equity attributable to HEP.

SFAS 141(R) “Business Combinations”

SFAS No. 141(R) became effective January 1, 2009, which establishes principles and requirements for how an acquirer accounts for a business combination. It also requires that acquisition-related transaction and restructuring costs be expensed rather than be capitalized as part of the cost of an acquired business. Accordingly, we were required to expense the $2.5 million finder’s fee related to the acquisition of our SLC Pipeline joint venture interest.

SFAS No. 161 “Disclosures about Derivative Instruments and Hedging Activities, an Amendment of SFAS No. 133”

SFAS No. 161 became effective January 1, 2009, which amends and expands the disclosure requirements of SFAS 133 to include disclosure of the objectives and strategies related to an entity’s use of derivative instruments, disclosure of how an entity accounts for its derivative instruments and disclosure of the financial impact, including the effect on cash flows associated with derivative activity. See Note 7 for disclosure of our derivative instruments and hedging activity.

Emerging Issues Task Force(“EITF”) Issue No. 07-04 “Application of the Two-Class Method under SFAS Statement No. 128, ‘Earnings per Share,’ to Master Limited Partnerships”

EITF Issue No. 07-04 became effective January 1, 2009, which prescribes the application of the two-class method in computing earnings per unit to reflect a master limited partnership’s contractual obligation to make distributions to the general partner, limited partners and incentive distribution rights holders. As a result, quarterly earnings allocations to the general partner now include incentive distributions that were declared subsequent to quarter end. Prior to our adoption of this standard, our general partner earnings allocations included incentive distributions that were declared during each quarter. We have applied this standard on a retrospective basis. Although this standard resulted in a decrease in our limited partners’ interest in net income attributable to Holly Energy Partners, L.P. for the three and six months ended June 30, 2008, it did not affect earnings of $0.18 and $0.61 per limited partner unit for the three and six months ended June 30, 2008, respectively.

Financial Accounting Standards Board (“FASB”) Staff Position (“FSP”) No. EITF 03-6-1 “Determining Whether Instruments Granted in Share-Based Transactions Are Participating Securities”

FSP No. 03-6-1 became effective January 1, 2009, which provides guidance in determining whether unvested instruments granted under share-based payment transactions are participating securities and, therefore, should be included in earnings per share calculations under the two-class method provided under SFAS No. 128, Earnings per Share. The adoption of this standard did not have a material impact on our financial condition, results of operations and cash flows.

SFAS No. 165 “Subsequent Events”

In May 2009, the FASB issued SFAS No. 165, which establishes general standards for accounting and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. We adopted this standard effective June 30, 2009. Although this standard requires disclosure of the date through which we have evaluated subsequent events, it did not affect our accounting and disclosure policies with respect to subsequent events.

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FSP SFAS No. 107-1 and Accounting Principles Board (“APB”) No. 28-1 “Interim Disclosures about Fair Value of Financial Instruments”

In April 2009, the FASB issued FSP SFAS No, 107-1 and APB No. 28-1, which extends the annual financial statement disclosure requirements for financial instruments to interim reporting periods of publicly traded companies. We adopted this standard effective June 30, 2009. See Note 3 for disclosure of our financial instruments.

Note 2: Acquisitions

Lovington-Artesia Pipeline Transaction

On June 1, 2009, we acquired a newly constructed 16-inch intermediate pipeline from Holly for $34.2 million. The pipeline runs 65 miles from the Navajo Refinery’s crude oil distillation and vacuum facilities in Lovington, New Mexico to its petroleum refinery located in Artesia, New Mexico. This pipeline was placed in service effective June 1, 2009 and operates as a component of our Intermediate Pipeline system that services Holly’s Navajo Refinery.

In connection with this transaction, Holly agreed to amend our transportation agreement that relates to the Intermediate Pipelines acquired in 2005 (the “Holly IPA”). As a result, the term of the Holly IPA was extended by an additional 4 years and now expires in June 2024. Additionally, Holly’s minimum commitment under the Holly IPA was increased and the Holly IPA now results in minimum annual payments to us of $20.7 million.

SLC Pipeline Joint Venture Interest

On March 1, 2009, we acquired a 25% joint venture interest in the SLC Pipeline, a new 95-mile intrastate pipeline system jointly owned by Plains and us. The SLC Pipeline commenced operations effective March 2009 and allows various refiners in the Salt Lake City area, including Holly’s Woods Cross Refinery, to ship crude oil into the Salt Lake City area from the Utah terminus of the Frontier Pipeline as well as crude oil flowing from Wyoming and Utah via Plains’ Rocky Mountain Pipeline. The total cost of our investment in the SLC Pipeline was $28.0 million, consisting of the capitalized $25.5 million joint venture contribution and the $2.5 million finder’s fee paid to Holly that was expensed as acquisition costs.

We account for our investment using the equity method of accounting. Under the equity method of accounting, we record our pro-rata share of earnings of the SLC Pipeline. Contributions to and distributions from the SLC Pipeline are recorded as adjustments to our investment balance.

Crude Pipelines and Tankage Transaction

On February 29, 2008, we acquired crude pipeline and tankage assets from Holly (the “Crude Pipelines and Tankage Assets”) for $180.0 million that consist of crude oil trunk lines that deliver crude oil to Holly’s Navajo Refinery in southeast New Mexico, gathering and connection pipelines located in west Texas and New Mexico, on-site crude tankage located within the Navajo and Woods Cross Refinery complexes, a jet fuel products pipeline between Artesia and Roswell, New Mexico, a leased jet fuel terminal in Roswell, New Mexico and crude oil and product pipelines that support Holly’s Woods Cross Refinery. The consideration paid consisted of $171.0 million in cash and 217,497 of our common units having a fair value of $9.0 million. We financed the $171.0 million cash portion of the consideration through borrowings under our senior secured revolving credit agreement expiring August 2011.

In connection with this transaction, we entered into a 15-year crude pipelines and tankage agreement with Holly (the “Holly CPTA”). Under the Holly CPTA, Holly agreed to transport and store volumes of crude oil on the crude pipelines and tankage facilities that result in minimum annual payments to us. These minimum annual payments or revenues will be adjusted each year at a rate equal to the percentage change in the Producer Price Index (“PPI”) but will not decrease as a result of a decrease in the PPI. Under the agreement, the tariff rates will generally be increased annually by the percentage

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change in the Federal Energy Regulatory Commission (“FERC”) Oil Pipeline Index. The FERC index is the change in the PPI plus a FERC adjustment factor that is reviewed periodically.

Note 3: Financial Instruments

Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, debt and interest rate swaps. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the short-tem maturity of these instruments.

Our debt consists of outstanding principle under our revolving credit agreement (the “Credit Agreement”) and our 6.25% senior notes (the “Senior Notes”). The $218.0 million carrying amount of outstanding debt under our Credit Agreement approximates fair value as interest rates are reset frequently using current rates. The estimated fair value of our Senior Notes was $161.0 million at June 30, 2009. This fair value estimate is based on market quotes provided from a third-party bank. See Note 7 for additional information on these instruments.

Fair Value Measurements

We adopted SFAS No. 157 “Fair Value Measurements” effective January 1, 2008. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. It also establishes a fair value hierarchy that 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 interest rate swaps that are measured at fair value on a recurring basis using Level 2 inputs. With respect to these instruments, 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 agreements. Our measurements are 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 swaps, including fair value measurements.

Note 4: Properties and Equipment

	June 30,		December 31,
	2009		2008
	(In thousands)
Pipelines and terminals	$	345,582	$	308,056
Land and right of way		25,042		24,991
Other		11,761		11,498
Construction in progress		58,050		38,589
		440,435		383,134
Less accumulated depreciation		103,750		92,850
	$	336,685	$	290,284

We capitalized $0.7 million and $0.2 million in interest related to major construction projects during the six months ended June 30, 2009 and 2008, 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 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 Holly crude pipelines and tankage agreement represents a portion of the total purchase price of the Crude Pipelines and Tankage Assets 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 Holly CPTA.

The carrying amounts of our transportation agreements are as follows:

	June 30,		December 31,
	2009		2008
	(In thousands)
Alon transportation agreement	$	59,933	$	59,933
Holly crude pipelines and tankage agreement		74,231		74,231
		134,164		134,164
Less accumulated amortization		15,255		11,781
	$	118,909	$	122,383

We have two additional transportation agreements with Holly. One of the agreements relates to the pipelines and terminals contributed to us from Holly at the time of our initial public offering in 2004 (the “Holly PTA”). The second agreement relates to the Intermediate Pipelines acquired from Holly in 2005 and in June 2009, the Holly IPA. Our basis in the assets acquired under these transfers reflects Holly’s historical cost and does not reflect a step-up in basis to fair value. Therefore, these agreements have a recorded value of zero.

Note 6: Employees, Retirement and Incentive Plans

Employees who provide direct services to us are employed by Holly Logistic Services, L.L.C., a Holly 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 Holly (the “Omnibus Agreement”). These employees participate in the retirement and benefit plans of Holly. Our share of retirement and benefit plan costs was $0.6 million for the three months ended June 30, 2009 and 2008 and $1.2 million and $1.0 million for the six months ended June 30, 2009 and 2008, 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.

As of June 30, 2009, 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 $0.5 million for the three months ended June 30, 2009 and 2008, respectively, and $0.9 million and $0.8 million for the six months ended June 30, 2009 and 2008, respectively. It is currently our policy to purchase units in the open market instead of issuing new units for settlement of restricted unit grants. At June 30, 2009, 350,000 units were authorized to be granted under the equity-based compensation plans, of which 200,541 had not yet been granted.

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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 vesting for certain key executives is contingent upon certain earnings per unit targets being realized. The fair value of each restricted unit grant was measured at the market price as of the date of grant and is being amortized over the vesting period, including the units issued to the key executives, as we expect those units to fully vest.

A summary of restricted unit activity and changes during the six months ended June 30, 2009 is presented below:

						Weighted-
				Weighted-		Average	Aggregate
				Average		Remaining	Intrinsic
				Grant-Date		Contractual	Value
Restricted Units	Grants			Fair Value		Term	($000)
Outstanding January 1, 2009 (not vested)		53,505		$	41.28
Granted		26,562			23.30
Forfeited		(2,152	)		42.53
Vesting and transfer of full ownership to recipients		(23,318	)		37.70
Outstanding at June 30, 2009 (not vested)		54,597		$	34.01	1.0 year	$	1,733

The fair value of restricted units that were vested and transferred to recipients during the six months ended June 30, 2009 and 2008 were $0.9 million and $0.5 million, respectively. As of June 30, 2009, 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 1.0 year.

During the six months ended June 30, 2009, we paid $0.6 million for the purchase of 26,431 of our common units in the open market for the recipients of our 2009 restricted unit grants.

Performance Units

Under our Long-Term Incentive Plan, we grant performance units to selected executives and employees who perform services for us. These performance units are payable based upon the growth in distributions on our common units during the requisite period, and generally vest over a period of three years. As of June 30, 2009, estimated share payouts for outstanding nonvested performance unit awards ranged from 125% to 150%.

We granted 28,113 performance units to certain officers in March 2009. These units will vest over a three-year performance period ending December 31, 2011 and are payable in HEP common units. The number of units actually earned will be based on the growth of distributions to limited partners over the performance period and can range from 50% to 150% of the number of performance units issued. The fair value of these performance units is based on the grant date closing unit price of $23.30 and will apply to the number of units ultimately awarded.

A summary of performance unit activity and changes during the six months ended June 30, 2009 is presented below:

	Payable
Performance Units	In Units
Outstanding at January 1, 2009 (not vested)		36,971
Granted		28,113
Forfeited		—
Vesting and transfer of common units to recipients		(10,313	)
Outstanding at June 30, 2009 (not vested)		54,771

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The fair value of performance units that were vested and transferred to recipients during the six months ended June 30, 2009 and 2008 were $0.4 million and $0.1 million, respectively. Based on the weighted average grant date fair value of $32.95 at June 30, 2009 there was $1.3 million of total unrecognized compensation cost related to nonvested performance units. That cost is expected to be recognized over a weighted-average period of 1.5 years.

Note 7: Debt

Credit Agreement

We have a $300.0 million senior secured revolving credit agreement expiring in August 2011, the Credit Agreement. The Credit Agreement is available to fund capital expenditures, acquisitions, and working capital and for general partnership purposes. In addition, the Credit Agreement is available to fund letters of credit up to a $50.0 million sub-limit and to fund distributions to unitholders up to a $20.0 million sub-limit. Advances under the Credit Agreement that are designated for working capital are classified as short-term liabilities. Other advances under the Credit Agreement, including advances used for the financing of capital projects, are classified as long-term liabilities. During the six months ended June 30, 2009, we received advances totaling $99.0 million that were used as interim financing for capital projects and acquisitions and repaid $81.0 million, resulting in $18.0 million in net advances received. As of June 30, 2009, we had $218.0 million outstanding under the Credit Agreement.

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 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. We are required to reduce all working capital borrowings under the Credit Agreement to zero for a period of at least 15 consecutive days in each twelve-month period prior to the maturity date of the agreement. As of June 30, 2009, we had no working capital borrowings.

Indebtedness under the Credit Agreement bears interest, at our option, at either (a) the reference rate as announced by the administrative agent plus an applicable margin (ranging from 0.25% to 1.50%) or (b) at a rate equal to LIBOR plus an applicable margin (ranging from 1.00% to 2.50%). In each case, the applicable margin is based upon the ratio of our funded debt (as defined in the agreement) to EBITDA (earnings before interest, taxes, depreciation and amortization, as defined in the agreement). We incur a commitment fee on the unused portion of the Credit Agreement at a rate ranging from 0.20% to 0.50% based upon the ratio of our funded debt to EBITDA for the four most recently completed fiscal quarters. At June 30, 2009, we are subject to a 0.375% commitment fee on the $82.0 million unused portion of the Credit Agreement. The agreement expires in August 2011. At that time, the agreement will terminate and all outstanding amounts thereunder will be due and payable.

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 and 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.

Additionally, the Credit Agreement contains certain provisions whereby the lenders may accelerate payment of outstanding debt under certain circumstances.

Senior Notes Due 2015

Our Senior Notes maturing March 1, 2015 are registered with the SEC and bear interest at 6.25%. The Senior Notes are unsecured and impose certain restrictive covenants, including limitations on our ability

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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. 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 long-term debt are as follows:

	June 30,			December 31,
	2009			2008
	(In thousands)
Credit Agreement	$	218,000		$	200,000
Senior Notes
Principal		185,000			185,000
Unamortized discount		(2,154	)		(2,344	)
Unamortized premium – dedesignated fair value hedge		1,964			2,137
		184,810			184,793
Total debt		402,810			384,793
Less net short-term borrowings under credit agreement(1)		—			29,000
Total long-term debt(1)	$	402,810		$	355,793

(1) We are currently classifying all borrowings under the Credit Agreement as long-term. At December 31, 2008, we classified certain of our Credit Agreement borrowings as short-term.

Interest Rate Risk Management

We use interest rate derivatives to manage our exposure to interest rate risk. As of June 30, 2009, we have three interest rate swap contracts.

We have an interest rate swap that hedges our exposure to the cash flow risk caused by the effects of LIBOR changes on the $171.0 million Credit Agreement advance that we used to finance our purchase of the Crude Pipelines and Tankage Assets in February 2008. This interest rate swap effectively converts our $171.0 million LIBOR based debt to fixed rate debt having an interest rate of 3.74% plus an applicable margin, currently 2.00%, which equaled an effective interest rate of 5.74% as of June 30, 2009. The maturity date of this swap contract is February 28, 2013. We intend to renew our Credit Agreement prior to its expiration in August 2011.

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 our $171.0 million 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 income. 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 our $171.0 million variable rate debt. Any ineffectiveness is reclassified from accumulated other comprehensive income to interest expense. As of June 30, 2009, we had no ineffectiveness on our cash flow hedge.

We also have an interest rate swap contract that effectively converts interest expense associated with $60.0 million of our 6.25% Senior Notes from a fixed to a variable rate (“Variable Rate Swap”). Under this swap contract, interest on the $60.0 million notional amount is computed using the three-month LIBOR plus a spread of 1.1575%, which equaled an effective interest rate of 1.83% as of June 30, 2009. The maturity date of this swap contract is March 1, 2015, matching the maturity of the Senior Notes.

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In October 2008, we entered into an additional interest rate swap contract, effective December 1, 2008, that effectively unwinds the effects of the Variable Rate Swap discussed above, converting $60.0 million of our hedged long-term debt back to fixed rate debt (“Fixed Rate Swap”). Under the Fixed Rate Swap, interest on a notional amount of $60.0 million is computed at a fixed rate of 3.59% versus three-month LIBOR which when added to the 1.1575% spread on the Variable Rate Swap results in an effective fixed interest rate of 4.75%. The maturity date of this swap contract is December 1, 2013.

Prior to the execution of our Fixed Rate Swap, the Variable Rate Swap was designated as a fair value hedge of $60.0 million in outstanding principal under the Senior Notes. We dedesignated this hedge in October 2008. At this time, the carrying balance of our Senior Notes included a $2.2 million premium due to the application of hedge accounting until the dedesignation date. This premium is being amortized as a reduction to interest expense over the remaining term of the Variable Rate Swap.

Our interest rate swaps not having a “hedge” designation are measured quarterly at fair value either as an asset or a liability in our consolidated balance sheets with the offsetting fair value adjustment to interest expense. For the three and six months ended June 30, 2009, we recognized a reduction of $0.8 million and $0.6 million, respectively, in interest expense as a result of fair value adjustments to our interest rate swaps.

We record interest expense equal to the variable rate payments under the swaps. Receipts under the swap agreements are recorded as a reduction of interest expense.

Additional information on our interest rate swaps as of June 30, 2009 is as follows:

	Balance Sheet				Location of Offsetting	Offsetting
Interest Rate Swaps	Location	Fair Value			Balance	Amount
	(In thousands)
Asset
Fixed-to-variable interest rate swap	Other assets	$	2,751		Long-term debt	$	(1,964	)
- $60 million of 6.25% Senior Notes					HEP partners’ equity		(1,942	)(1)
					Interest expense		1,155	(2)
		$	2,751			$	(2,751	)
Liability
Cash flow hedge — $171 million LIBOR	Other long-term				Accumulated other
based debt	liabilities	$	(8,700	)	comprehensive loss	$	8,700
Variable-to-fixed interest rate swap	Other long-term				HEP partners’ equity		4,166	(1)
- $60 million	liabilities		(2,209	)	Interest expense		(1,957	)
		$	(10,909	)		$	10,909

(1)	Represents prior year charges to interest expense.
(2)	Net of amortization of premium attributable to dedesignated hedge.

Interest Expense and Other Debt Information

Interest expense consists of the following components:

	Six Months Ended
	June 30,
	2009		2008
	(In thousands)
Interest on outstanding debt:
Senior Notes, net of interest rate swaps	$	4,710	$	5,353
Credit Agreement, net of interest rate swap		5,260		3,278
Net amortization of discount and deferred debt issuance costs		353		480
Commitment fees		145		149
Total interest incurred		10,468		9,260
Less capitalized interest		661		220
Net interest expense	$	9,807	$	9,040
Cash paid for interest(1)	$	11,836	$	6,200

(1) Net of cash received under our interest rate swap agreements of $1.9 million and $2.1 million for the six months ended June 30, 2009 and 2008, respectively.

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Note 8: Significant Customers

All revenues are domestic revenues, of which over 90% are currently generated from our three largest customers: Holly, Alon and BP Plc (“BP”). The major concentration of our pipeline system revenues are derived from activities conducted in the southwest United States. The following table presents the percentage of total revenues generated by each of these three customers:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
Holly		62	%		75	%		60	%		71	%
Alon		27	%		12	%		28	%		16	%
BP		5	%		8	%		5	%		9	%

Note 9: Related Party Transactions

Holly and Alon Agreements

As of June 30, 2009, we serve Holly’s refineries in New Mexico and Utah under three long-term pipeline and terminal and tankage agreements. The substantial majority of our business is devoted to providing transportation, storage and terminalling services to Holly.

We have an agreement that relates to the pipelines and terminals contributed by Holly to us at the time of our initial public offering and expires in 2019, the Holly PTA. Our second agreement with Holly relates to the Intermediate Pipelines acquired from Holly in 2005 and in June 2009 and expires in 2024, the Holly IPA. Third, we have the Holly CPTA that relates to the Crude Pipelines and Tankage Assets acquired from Holly in 2008 and expires in February 2023.

Under the Holly PTA, Holly IPA and Holly CPTA, Holly agreed to transport and store volumes of refined product and crude oil on our pipelines and terminal and tankage facilities that result in minimum annual payments to us. These minimum annual payments or revenues will be adjusted each year at a percentage change equal to the change in the PPI but will not decrease as a result of a decrease in the PPI. Under these agreements, the agreed upon tariff rates are adjusted each year on July 1 at a rate equal to the percentage change in the PPI or FERC index, but generally will not decrease as a result of a decrease in the PPI or FERC index. The FERC index is the change in the PPI plus a FERC adjustment factor that is reviewed periodically. Following the July 1, 2009 PPI rate adjustments, these agreements will result in minimum payments to us of $92.8 million for the twelve months ended June 30, 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 results in a minimum level of annual revenue. The agreed upon tariffs are increased or decreased annually at a rate equal to the percentage change in the PPI, but not below the initial tariff rate. Following the March 1, 2009 PPI rate adjustment, Alon’s total minimum commitment for the twelve months ending February 28, 2010 decreased to $21.7 million.

If either Holly or Alon fails to meet its minimum volume commitment 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. With the exception of the Holly CPTA, a shortfall payment may be applied as a credit in the following four quarters after minimum obligations are met.

Under certain provisions of the Omnibus Agreement that we entered into with Holly in July 2004 and that expires in 2019, we pay Holly an annual administrative fee, currently $2.3 million, for the provision by Holly 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 Holly. We also reimburse Holly and its affiliates for direct expenses they incur on our behalf.

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• Pipeline, terminal and tankage revenues received from Holly were $25.1 million and $20.1 million for the three months ended June 30, 2009 and 2008, respectively, and $43.4 million and $38.5 million for the six months ended June 30, 2009 and 2008, respectively. These amounts include the revenues received under the Holly PTA, Holly IPA and Holly CPTA.

• Holly charged general and administrative services under the Omnibus Agreement of $0.6 million for the three months ended June 30, 2009 and 2008 and $1.2 million and $1.1 million for the six months ended June 30, 2009 and 2008, respectively.

• We reimbursed Holly for costs of employees supporting our operations of $4.0 million and $3.5 million for the three months ended June 30, 2009 and 2008, respectively, and $8.6 million and $6.1 million for the six months ended June 30, 2009 and 2008, respectively.

• We distributed $7.1 million and $6.4 million during the three months ended June 30, 2009 and 2008, respectively, to Holly as regular distributions on its subordinated units, common units and general partner interest. We distributed $14.0 million and $12.4 million during the six months ended June 30, 2009 and 2008, respectively.

• Our accounts receivable from Holly was $8.7 million and $9.4 million at June 30, 2009 and December 31, 2008, respectively.

• Holly has failed to meet its minimum volume commitment for each of the sixteen quarters since inception of the Holly IPA. Through June 30, 2009, we have charged Holly $9.3 million for these shortfalls to date, $0.5 million of which is included in affiliate accounts receivable at June 30, 2009 and December 31, 2008.

• Our revenues for the three and six months ended June 30, 2009 include $0.9 million and $1.1 million, respectively, of shortfalls billed under the Holly IPA in 2008 as Holly did not exceed its minimum volume commitment in any of the subsequent four quarters. Deferred revenue in the consolidated balance sheets at June 30, 2009 and December 31, 2008, includes $3.5 million and $2.4 million, respectively, relating to the Holly IPA. It is possible that Holly may not exceed its minimum obligations under the Holly IPA to allow Holly to receive credit for any of the $3.5 million deferred at June 30, 2009.

• See Note 2 for information on our 16-inch intermediate pipeline and the Crude Pipelines and Tankage Assets acquired from Holly in June 2009 and February 2008, respectively.

• We paid Holly a $2.5 million finder’s fee in the first quarter of 2009 in consideration for its assistance in obtaining our joint venture interest in the SLC Pipeline.

Alon became a related party when it acquired all of our Class B subordinated units in connection with our acquisition of assets from it in February 2005.

• Pipeline and terminal revenues received from Alon were $9.2 million and $1.5 million for the three months ended June 30, 2009 and 2008, respectively, and $17.0 million and $4.9 million for the six months ended June 30, 2009 and 2008, respectively, under the Alon PTA. Additionally, pipeline revenues received under a pipeline capacity lease agreement with Alon were $1.7 million and $1.8 million for the three months ended June 30, 2009 and 2008, respectively, and $3.4 million and $3.6 million for the six months ended June 30, 2009 and 2008, respectively.

• We distributed $0.7 million during the three months ended June 30, 2009 and 2008 and $1.4 million during the six months ended June 30, 2009 and 2008, to Alon for distributions on its Class B subordinated units.

• Included in our accounts receivable – trade were $3.5 million and $2.5 million at June 30, 2009 and December 31, 2008, respectively, which represented receivable balances from Alon.

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• Our revenues for the three and six months ended June 30, 2009 include $4.8 million and $7.7 million, respectively, of shortfalls billed under the Alon PTA in 2008 as Alon did not exceed its minimum revenue obligation in any of the subsequent four quarters. Deferred revenue in the consolidated balance sheets at June 30, 2009 and December 31, 2008 includes $7.5 million and $13.3 million, respectively, relating to the Alon PTA. It is possible that Alon may not exceed its minimum obligations under the Alon PTA to allow Alon to receive credit for any of the $7.5 million deferred at June 30, 2009.

BP

We have a 70% ownership interest in Rio Grande and BP owns the other 30%. Due to the ownership interest and resulting consolidation, BP is a related party to us.

• BP is one of multiple shippers on the Rio Grande pipeline. We recorded revenues from BP of $2.2 million for the three months ended June 30, 2009 and 2008 and $3.8 million and $4.9 million for the six months ended June 30, 2009 and 2008, respectively.

• Included in our accounts receivable – trade at June 30, 2009 and December 31, 2008 were $1.1 million and $0.8 million, respectively, which represented the receivable balance of Rio Grande from BP.

Note 10: HEP Partners’ Equity, Income Allocations, Cash Distributions and Comprehensive Income

Issuances of units

As of June 30, 2009, Holly holds 7,000,000 of our subordinated units and 290,000 of our common units, which constitutes a 41% ownership interest in us, including the 2% general partner interest. The subordination period of Holly’s subordinated units extends until the first day of any quarter beginning after June 30, 2009 that certain conditions are met. After giving effect to the payment of our quarterly distribution for the quarter ended June 30, 2009, we expect that all of the conditions necessary to end the subordination period will be satisfied and the Holly owned subordinated units will convert into 7,000,000 common units two business days after the distribution is paid.

In May 2009, we closed a public offering of 2,192,400 of our common units priced at $27.80 per unit including 192,400 common units issued pursuant to the underwriters’ exercise of their over-allotment option. Net proceeds of $58.4 million were used to repay bank debt and for general partnership purposes. In addition, we received a $1.2 million capital contribution from our general partner to maintain its 2% general partner interest.

Under our registration statement filed with the SEC using a “shelf” registration process, we currently have the ability to raise approximately $940.0 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.

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 generally allocated to the partners based on their weighted average ownership percentage during the period.

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The following table presents the allocation of the general partner interest in net income attributable to HEP:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
	(In thousands, except per unit data)
General partner interest in net income	$	304	$	61	$	392	$	202
General partner incentive distribution		1,545		788		2,750		1,526
Total general partner interest in net income attributable to HEP	$	1,849	$	849	$	3,142	$	1,728

Cash Distributions

We consider regular cash distributions to unitholders on a quarterly basis, although there is no assurance as to the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors. Our Credit Agreement prohibits us from making cash distributions if any potential default or event of default, as defined in the agreement, occurs or would result from the cash distribution.

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 23, 2009, we announced our cash distribution for the second quarter of 2009 of $0.785 per unit. The distribution is payable on all common, subordinated and general partner units and will be paid August 14, 2009 to all unitholders of record on August 3, 2009.

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
	(In thousands, except per unit data)
General partner interest	$	328	$	264	$	611	$	524
General partner incentive distribution		1,545		788		2,750		1,526
Total general partner distribution		1,873		1,052		3,361		2,050
Limited partner distribution		14,538		12,200		27,200		24,234
Total regular quarterly cash distribution	$	16,411	$	13,252	$	30,561	$	26,284
Cash distribution per unit applicable to limited partners	$	0.785	$	0.745	$	1.560	$	1.480

As a master limited partnership, we distribute our available cash, which has historically exceeded our net income because depreciation and amortization expense represents a non-cash charge against income. The result is a decline in equity since our regular quarterly distributions have exceeded our quarterly net income. Additionally, if the assets transferred to us upon our initial public offering in 2004 and the intermediate pipelines purchased from Holly in 2005 had been acquired from third parties, our acquisition cost in excess of Holly’s basis in the transferred assets of $157.3 million would have been recorded as increases to our properties and equipment and intangible assets instead of reductions to equity.

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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				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
	(In thousands)
Net income	$	16,819	$	4,079	$	22,753	$	12,283
Other comprehensive income:
Change in fair value of cash flow hedge		4,417		6,797		4,267		2,448
Comprehensive income		21,236		10,876		27,020		14,731
Less noncontrolling interest in comprehensive income		427		264		922		670
Comprehensive income attributable to HEP unitholders	$	20,809	$	10,612	$	26,098	$	14,061

Note 11: Supplemental Guarantor/Non-Guarantor Financial Information

Obligations of Holly Energy Partners, L.P. (“Parent”) under the 6.25% 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. Rio Grande (“Non-Guarantor”), in which we have a 70% ownership interest, is the only subsidiary that has not guaranteed these obligations.

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

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Condensed Consolidating Balance Sheet

				Guarantor			Non-
June 30, 2009	Parent			Subsidiaries			Guarantor			Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	2		$	1,304		$	2,889		$	—		$	4,195
Accounts receivable		—			12,325			1,155			—			13,480
Intercompany accounts receivable (payable)		(169,661	)		169,846			(185	)		—			—
Prepaid and other current assets		6			821			—			—			827
Total current assets		(169,653	)		184,296			3,859			—			18,502
Properties and equipment, net		—			304,904			31,781			—			336,685
Investment in subsidiaries		411,367			24,594			—			(435,961	)		—
Transportation agreements, net		—			118,909			—			—			118,909
Investment in SLC Pipeline		—			26,098			—			—			26,098
Other assets		3,799			1,122			—			—			4,921
Total assets	$	245,513		$	659,923		$	35,640		$	(435,961	)	$	505,115
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	—		$	8,992		$	128		$	—		$	9,120
Accrued interest		(2,842	)		5,713			—			—			2,871
Deferred revenue		—			10,989			—			—			10,989
Accrued property taxes		—			934			92			—			1,026
Other current liabilities		6,117			(5,345	)		286			—			1,058
Total current liabilities		3,275			21,283			506			—			25,064
Long-term debt		184,810			218,000			—			—			402,810
Other long-term liabilities		2.209			9,273			—			—			11,482
Equity — HEP		55,219			411,367			35,134			(446,501	)		55,219
Equity – noncontrolling interest		—			—			—			10,540			10,540
Total liabilities and equity	$	245,513		$	659,923		$	35,640		$	(435,961	)	$	505,115

Condensed Consolidating Balance Sheet

				Guarantor			Non-
December 31, 2008	Parent			Subsidiaries			Guarantor			Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	2		$	3,706		$	1,561		$	—		$	5,269
Accounts receivable		—			13,332			1,145			—			14,477
Intercompany accounts receivable (payable)		(197,828	)		197,979			(151	)		—			—
Prepaid and other current assets		176			417			—			—			593
Total current assets		(197,650	)		215,434			2,555			—			20,339
Properties and equipment, net		—			257,886			32,398			—			290,284
Investment in subsidiaries		378,481			23,842			—			(402,323	)		—
Transportation agreements, net		—			122,383			—			—			122,383
Other assets		5,300			1,382			—			—			6,682
Total assets	$	186,131		$	620,927		$	34,953		$	(402,323	)	$	439,688
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	—		$	7,357		$	661		$	—		$	8,018
Accrued interest		(27,778	)		30,623			—			—			2,845
Deferred revenue		—			15,658			—			—			15,658
Accrued property taxes		—			1,015			130			—			1,145
Other current liabilities		31,214			(29,811	)		102			—			1,505
Short-term borrowings under credit agreement		—			29,000			—			—			29,000
Total current liabilities		3,436			53,842			893			—			58,171
Long-term debt		184,793			171,000			—			—			355,793
Other long-term liabilities		—			17,604			—			—			17,604
Equity — HEP		(2,098	)		378,481			34,060			(412,541	)		(2,098	)
Equity – noncontrolling interest		—			—			—			10,218			10,218
Total liabilities and equity	$	186,131		$	620,927		$	34,953		$	(402,323	)	$	439,688

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Condensed Consolidating Statement of Income

				Guarantor			Non-
Three months ended June 30, 2009	Parent			Subsidiaries			Guarantor			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	25,064		$	—		$	—		$	25,064
Third parties		—			13,286			2,603			(351	)		15,538
		—			38,350			2,603			(351	)		40,602
Operating costs and expenses:
Operations		—			10,637			800			(351	)		11,086
Depreciation and amortization		—			6,512			341			—			6,853
General and administrative		590			1,207			21			—			1,818
		590			18,356			1,162			(351	)		19,757
Operating income (loss)		(590	)		19,994			1,441			—			20,845
Other income (expense):
Equity in earnings of subsidiaries		15,930			996			—			(16,926	)		—
Equity in earnings of SLC Pipeline		—			423			—			—			423
Interest income (expense)		1,052			(5,454	)		—			—			(4,402	)
Other		—			65			—			—			65
		16,982			(3,970	)		—			(16,926	)		(3,914	)
Income (loss) before income taxes		16,392			16,024			1,441			(16,926	)		16,931
State income tax		—			(94	)		(18	)		—			(112	)
Net income		16,392			15,930			1,423			(16,926	)		16,819
Less noncontrolling interest in net income		—			—			—			427			427
Net income attributable to HEP	$	16,392		$	15,930		$	1,423		$	(17,353	)	$	16,392

Condensed Consolidating Statement of Income

				Guarantor			Non-
Three months ended June 30, 2008	Parent			Subsidiaries			Guarantor			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	20,146		$	—		$	—		$	20,146
Third parties		—			4,482			2,171			(324	)		6,629
		—			24,928			2,171			(324	)		26,775
Operating costs and expenses:
Operations		—			9,342			967			(324	)		9,985
Depreciation and amortization		—			5,736			326			—			6,062
General and administrative		760			603			(4	)		—			1,359
		760			15,681			1,289			(324	)		17,406
Operating income (loss)		(760	)		9,247			882			—			9,369
Other income (expense):
Equity in earnings of subsidiaries		7,180			615			—			(7,795	)		—
Interest income (expense)		(2,605	)		(2,613	)		13			—			(5,205	)
		4,575			(1,998	)		13			(7,795	)		(5,205	)
Income (loss) before income taxes		3,815			7,249			895			(7,795	)		4,164
State income tax		—			(69	)		(16	)		—			(85	)
Net income		3,815			7,180			879			(7,795	)		4,079
Less noncontrolling interest in net income		—			—			—			264			264
Net income attributable to HEP	$	3,815		$	7,180		$	879		$	(8,059	)	$	3,815

- 23 -

Condensed Consolidating Statement of Income

				Guarantor			Non-
Six months ended June 30, 2009	Parent			Subsidiaries			Guarantor			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	43,387		$	—		$	—		$	43,387
Third parties		—			24,639			5,395			(695	)		29,339
		—			68,026			5,395			(695	)		72,726
Operating costs and expenses:
Operations		—			20,986			1,591			(695	)		21,882
Depreciation and amortization		—			12,428			681			—			13,109
General and administrative		1,288			1,843			11			—			3,142
		1,288			35,257			2,283			(695	)		38,133
Operating income (loss)		(1,288	)		32,769			3,112			—			34,593
Other income (expense):
Equity in earnings of subsidiaries		24,994			2,152			—			(27,146	)		—
Equity in earnings of SLC Pipeline		—			598			—			—			598
SLC Pipeline acquisition costs		—			(2,500	)		—			—			(2,500	)
Interest income (expense)		(1,875	)		(7,924	)		—			—			(9,799	)
Other		—			65			—			—			65
		23,119			(7,609	)		—			(27,146	)		(11,636	)
Income (loss) before income taxes		21,831			25,160			3,112			(27,146	)		22,957
State income tax		—			(166	)		(38	)		—			(204	)
Net income		21,831			24,994			3,074			(27,146	)		22,753
Less noncontrolling interest in net income		—			—			—			922			922
Net income attributable to HEP	$	21,831		$	24,994		$	3,074		$	(28,068	)	$	21,831

Condensed Consolidating Statement of Income

				Guarantor			Non-
Six months ended June 30, 2008	Parent			Subsidiaries			Guarantor			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	38,473		$	—		$	—		$	38,473
Third parties		—			11,298			4,921			(641	)		15,578
		—			49,771			4,921			(641	)		54,051
Operating costs and expenses:
Operations		—			18,315			2,038			(641	)		19,712
Depreciation and amortization		—			9,724			651			—			10,375
General and administrative		1,502			1,146			(3	)		—			2,645
		1,502			29,185			2,686			(641	)		32,732
Operating income (loss)		(1,502	)		20,586			2,235			—			21,319
Other income (expense):
Equity in earnings of subsidiaries		18,734			1,562			—			(20,296	)		—
Interest income (expense)		(5,619	)		(3,332	)		32			—			(8,919	)
Gain on sale of assets		—			36			—			—			36
		13,115			(1,734	)		32			(20,296	)		(8,883	)
Income (loss) before income taxes		11,613			18,852			2,267			(20,296	)		12,436
State income tax		—			(118	)		(35	)		—			(153	)
Net income		11,613			18,734			2,232			(20,296	)		12,283
Less noncontrolling interest in net income		—			—			—			670			670
Net income attributable to HEP	$	11,613		$	18,734		$	2,232		$	(20,966	)	$	11,613

- 24 -

Condensed Consolidating Statement of Cash Flows

				Guarantor			Non-
Six months ended June 30, 2009	Parent			Subsidiaries			Guarantor			Eliminations			Consolidated
	(in thousands)
Cash flows from operating activities	$	(31,418	)	$	61,676		$	3,392		$	(1,400	)	$	32,250
Cash flows from investing activities
Investment in SLC Pipeline		—			(25,500	)		—			—			(25,500	)
Additions to properties and equipment		—			(55,962	)		(64	)		—			(56,026	)
		—			(81,462	)		(64	)		—			(81,526	)
Cash flows from financing activities
Net borrowings under credit agreement		—			18,000			—			—			18,000
Proceeds from issuance of common units		58,355			—			—			—			58,355
Capital contribution from general partner		1,191			—			—			—			1,191
Distributions to HEP unitholders		(27,968	)		—			(2,000	)		2,000			(27,968	)
Distributions to noncontrolling interest		—			—			—			(600	)		(600	)
Other financing activities, net		(160	)		(616	)		—			—			(776	)
		31,418			17,384			(2,000	)		1,400			48,202
Cash and cash equivalents
Increase (decrease) for the period		—			(2,402	)		1,328			—			(1,074	)
Beginning of period		2			3,706			1,561			—			5,269
End of period	$	2		$	1,304		$	2,889		$	—		$	4,195

Condensed Consolidating Statement of Cash Flows

				Guarantor			Non-
Six months ended June 30, 2008	Parent			Subsidiaries			Guarantor			Eliminations			Consolidated
	(in thousands)
Cash flows from operating activities	$	16,984		$	4,866		$	3,671		$	(2,100	)	$	23,421
Cash flows from investing activities
Additions to properties and equipment		—			(19,567	)		(469	)		—			(20,036	)
Acquisition of crude pipelines and tankage assets		—			(171,000	)		—			—			(171,000	)
Proceeds from sale of assets		—			36			—			—			36
		—			(190,531	)		(469	)		—			(191,000	)
Cash flows from financing activities
Net borrowings under credit agreement		9,000			182,000			—			—			191,000
Proceeds from issuance of common units		—			104			—			—			104
Capital contribution from general partner		186			—			—			—			186
Distributions to HEP unitholders		(25,656	)		—			(3,000	)		3,000			(25,656	)
Distributions to noncontrolling interest		—			—			—			(900	)		(900	)
Other financing activities, net		(514	)		(591	)		—			—			(1,105	)
		(16,984	)		181,513			(3,000	)		2,100			163,629
Cash and cash equivalents
Increase (decrease) for the period		—			(4,152	)		202			—			(3,950	)
Beginning of period		2			8,060			2,259			—			10,321
End of period	$	2		$	3,908		$	2,461		$	—		$	6,371

- 25 -

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. In this document, the words “we,” “our,” “ours” and “us” refer to HEP and its consolidated subsidiaries or to HEP or an individual subsidiary and not to any other person.

OVERVIEW

Holly Energy Partners, L.P. (“HEP”) is a Delaware limited partnership. We own and operate substantially all of the petroleum product and crude oil pipeline, tankage and terminalling assets that support the Holly Corporation (“Holly”) refining and marketing operations in west Texas, New Mexico, Utah, Idaho and Arizona and a 70% interest in Rio Grande Pipeline Company (“Rio Grande”). Holly currently owns a 41% interest in us. 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.

We operate a system of petroleum product and crude oil pipelines in Texas, New Mexico, Oklahoma and Utah and distribution terminals in Texas, New Mexico, Arizona, Utah, Idaho and Washington. 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 or terminal; therefore, we are not directly exposed to changes in commodity prices.

On June 1, 2009, we acquired a newly constructed 16-inch intermediate pipeline from Holly for $34.2 million. The pipeline runs 65 miles from Holly’s crude oil distillation and vacuum facilities in Lovington, New Mexico to its petroleum refinery located in Artesia, New Mexico (collectively, the “Navajo Refinery”). This pipeline operates as a component of our intermediate pipeline system that services Holly’s Navajo Refinery.

Additionally in March 2009, we acquired a 25% joint venture interest in a new 95-mile intrastate pipeline system (the “SLC Pipeline”) jointly owned by Plains All American Pipeline, L.P. (“Plains”) and us. The SLC Pipeline allows various refiners in the Salt Lake City area, including Holly’s Woods Cross refinery, to ship crude oil into the Salt Lake City area from the Utah terminus of the Frontier Pipeline as well as crude oil flowing from Wyoming and Utah via Plains’ Rocky Mountain Pipeline. The SLC Pipeline commenced pipeline operations effective March 2009.

In May 2009, we closed a public offering of 2,192,400 of our common units priced at $27.80 per unit including 192,400 common units issued pursuant to the underwriters’ exercise of their over-allotment option. Net proceeds of $58.4 million were used to repay bank debt and for general partnership purposes. In addition, we received a $1.2 million capital contribution from our general partner to maintain its 2% general partner interest.

In March 2009 Holly, our largest customer, completed a 15,000 barrels per day (“bpd”) capacity expansion of its Navajo Refinery increasing refining capacity to 100,000 bpd, or by 18%.

For the six months ended June 30, 2009, our revenues were $72.7 million compared to $54.1 million for the six months ended June 30, 2008. Our total operating costs and expenses for the six months ended June 30, 2009 were $38.1 million compared to $32.7 million for the same period of 2008.

Net income attributable to HEP was $18.7 million ($1.10 per basic and diluted limited partner unit) for the six months ended June 30, 2009 compared to $9.9 million ($0.61 per basic and diluted limited partner unit) for the same period of 2008.

- 26 -

Agreements with Holly Corporation and Alon

As of June 30, 2009, we serve Holly’s refineries in New Mexico and Utah under three long-term pipeline and terminal and tankage agreements. The substantial majority of our business is devoted to providing transportation, storage and terminalling services to Holly.

We have an agreement that relates to the pipelines and terminals contributed by Holly to us at the time of our initial public offering in 2004 and expires in 2019 (the “Holly PTA”). Our second agreement relates to the intermediate pipelines acquired from Holly in 2005 and in June 2009 (the “Holly IPA”). In connection with our purchase of Holly’s 16-inch intermediate pipeline in June 2009, we amended the Holly IPA. As a result, the term of the Holly IPA was extended by an additional 5 years and now expires in June 2024 and Holly’s minimum commitment under the Holly IPA was increased. Our third agreement relates to the crude pipelines and tankage assets acquired from Holly in 2008 and expires in 2023 (the “Holly CPTA”).

Under these agreements, Holly agreed to transport and store volumes of refined product and crude oil on our pipelines and terminal and tankage facilities that result in minimum annual payments to us. These minimum annual payments or revenues will be adjusted each year at a percentage change equal to the change in the Producer Price Index (“PPI”) but will not decrease as a result of a decrease in the PPI. Under these agreements, the agreed upon tariff rates are adjusted each year on July 1 at a rate equal to the percentage change in the PPI or the Federal Energy Regulatory Commission (“FERC”) Oil Pipeline Index, but generally will not decrease as a result of a decrease in the PPI or FERC index. The FERC index is the change in the PPI plus a FERC adjustment factor that is reviewed periodically.

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 results in a minimum level of annual revenue. The agreed upon tariffs are increased or decreased annually at a rate equal to the percentage change in the PPI, but not below the initial tariff rate.

At July 1, 2009, contractual minimums under our long-term service agreements are as follows:

	Minimum Annualized
	Commitment		Year of
Agreement	(In millions)		Maturity	Contract Type
Holly PTA	$	43.7	2019	Minimum revenue commitment
Holly IPA*		20.7	2024	Minimum revenue commitment
Holly CPTA		28.4	2023	Minimum revenue commitment
Alon PTA		21.7	2020	Minimum volume commitment
Alon capacity lease		6.8	Various	Capacity lease
Total	$	121.3

* Reflects amended terms of the Holly IPA effective June 2009.

We depend on our agreements with Holly and Alon for the majority of our revenues. 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 that we entered into with Holly in July 2004 and expires in 2019 (the “Omnibus Agreement”), we pay Holly an annual administrative fee, currently $2.3 million, for the provision by Holly 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 Holly. We also reimburse Holly and its affiliates for direct expenses they incur on our behalf.

- 27 -

RESULTS OF OPERATIONS (Unaudited)

Income, Distributable Cash Flow and Volumes

The following tables present income, distributable cash flow and volume information for the three and six months ended June 30, 2009 and 2008.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
	(In thousands, except per unit data)
Revenues
Pipelines:
Affiliates — refined product pipelines	$	11,366		$	8,873		$	18,919		$	18,441
Affiliates — intermediate pipelines		4,302			2,456			6,068			6,049
Affiliates — crude pipelines		6,751			6,553			13,652			8,748
		22,419			17,882			38,639			33,238
Third parties — refined product pipelines		13,701			5,681			25,968			13,516
		36,120			23,563			64,607			46,754
Terminals, refinery tankage and truck loading racks:
Affiliates		2,645			2,264			4,748			5,235
Third parties		1,837			948			3,371			2,062
		4,482			3,212			8,119			7,297
Total revenues		40,602			26,775			72,726			54,051
Operating costs and expenses:
Operations		11,086			9,985			21,882			19,712
Depreciation and amortization		6,853			6,062			13,109			10,375
General and administrative		1,818			1,359			3,142			2,645
		19,757			17,406			38,133			32,732
Operating income		20,845			9,369			34,593			21,319
Other income (expense):
Equity in earnings of SLC Pipeline		423			—			598			—
SLC Pipeline acquisition costs		—			—			(2,500	)		—
Interest income		2			28			8			121
Interest expense, including amortization		(4,404	)		(5,233	)		(9,807	)		(9,040	)
Other		65			—			65			36
		(3,914	)		(5,205	)		(11,636	)		(8,883	)
Income before income taxes		16,931			4,164			22,957			12,436
State income tax		(112	)		(85	)		(204	)		(153	)
Net income(8)		16,819			4,079			22,753			12,283
Less noncontrolling interest in net income(8)		427			264			922			670
Net income attributable to HEP(8)		16,392			3,815			21,831			11,613
Less general partner interest in net income attributable to HEP, including incentive distributions(1)		1,849			849			3,142			1,728
Limited partners’ interest in net income attributable to HEP	$	14,543		$	2,966		$	18,689		$	9,885
Limited partners’ per unit interest in net income attributable to HEP — basic and diluted(1)(9)	$	0.82		$	0.18		$	1.10		$	0.61
Weighted average limited partners’ units outstanding		17,789			16,328			17,058			16,254
EBITDA(2)	$	27,759		$	15,167		$	44,943		$	31,060
Distributable cash flow(3)	$	16,415		$	13,995		$	30,999		$	27,703
Volumes — barrels per day (“bpd”)(4)
Pipelines:
Affiliates — refined product pipelines		94,738			75,812			78,628			80,186
Affiliates — intermediate pipelines		70,543			51,886			52,520			59,748
Affiliates — crude pipelines		142,598			130,559			132,459			88,979
		307,879			258,257			263,607			228,913
Third parties — refined product pipelines		56,851			24,423			61,549			34,966
		364,730			282,680			325,156			263,879
Terminals and truck loading racks:
Affiliates		115,221			93,328			99,118			110,381
Third parties		40,742			31,178			42,067			34,210
		155,963			124,506			141,185			144,591
Total for pipelines and terminal assets (bpd)		520,693			407,186			466,341			408,470

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(1)	Net income attributable to HEP is allocated between limited partners and the general partner interest in accordance with the provisions of the partnership agreement. HEP net income allocated to the general partner includes incentive distributions declared subsequent to quarter end. General partner incentive distributions for the three months ended June 30, 2009 and 2008 were $1.5 million and $0.8 million, respectively, and for the six months ended June 30, 2009 and 2008 were $2.8 million and $1.5 million, respectively. HEP 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 HEP net income.
(2)	Earnings before interest, taxes, depreciation and amortization (“EBITDA”) is calculated as net income attributable to HEP 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 (“U.S. GAAP”). However, the amounts included in the EBITDA calculation are derived from amounts included in our consolidated financial statements. EBITDA should not be considered as an alternative to net income or operating income, as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity. EBITDA is not necessarily comparable to similarly titled measures of other companies. EBITDA is presented here because it is a widely used financial indicator used by investors and analysts to measure performance. EBITDA is also used by our management for internal analysis and as a basis for compliance with financial covenants.
	Set forth below is our calculation of EBITDA.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
	(In thousands)
Net income attributable to HEP	$	16,392		$	3,815		$	21,831		$	11,613
Add interest expense		5,071			4,976			10,082			8,560
Add amortization of discount and deferred debt issuance costs		177			257			353			480
Add increase in interest expense — change in fair value of interest rate swaps		(844	)		—			(628	)		—
Subtract interest income		(2	)		(28	)		(8	)		(121	)
Add state income tax		112			85			204			153
Add depreciation and amortization		6,853			6,062			13,109			10,375
EBITDA	$	27,759		$	15,167		$	44,943		$	31,060

(3) Distributable cash flow is not a calculation based upon U.S. GAAP. However, the amounts included in the calculation are derived from amounts separately presented in our consolidated financial statements, with the exception of 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. 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						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
	(In thousands)
Net income attributable to HEP	$	16,392		$	3,815		$	21,831		$	11,613
Add depreciation and amortization		6,853			6,062			13,109			10,375
Add amortization of discount and deferred debt issuance costs		177			257			353			480
Subtract decrease in interest expense — change in fair value of interest rate swaps		(844	)		—			(628	)		—
Add equity in excess cash flows over earnings of SLC Pipeline		167			—			220			—
Add (subtract) increase (decrease) in deferred revenue		(5,031	)		4,930			(4,669	)		6,781
Add SLC Pipeline acquisition costs*		—			—			2,500			—
Subtract maintenance capital expenditures**		(1,299	)		(1,069	)		(1,717	)		(1,546	)
Distributable cash flow	$	16,415		$	13,995		$	30,999		$	27,703

*	Under new accounting guidance, Statement of Financial Accounting Standards (“SFAS”) No. 141(R) effective January 1, 2009, we were required to expense rather than capitalize certain acquisition costs of $2.5 million associated with our joint venture agreement with Plains that closed in March 2009. As these costs directly relate to our interest in the new joint venture pipeline and are similar to expansion capital expenditures, we have added back these costs to arrive at distributable cash flow.
**	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.
(4)	The amount reported for the six months ended June 30, 2008 include volumes transported on the crude pipelines for the period from March 1, 2008 through June 30, 2008 only. Volumes shipped during the months of March through June 2008 averaged 133.1 thousand barrels per day (“mbpd”). For the six months ended June 30, 2008, crude pipeline volumes are based on volumes for the months of March through June, averaged over the 182 days in the first six months of 2008. Under the Holly CPTA, fees are based on volumes transported on each pipeline component comprising the crude pipeline system (the crude oil gathering pipelines and the crude oil trunk lines). Accordingly, volumes transported on the crude pipelines represent the sum of volumes transported on both pipeline components. In cases where volumes are transported over both components of the crude pipeline system, such volumes are reflected twice in the total crude oil pipeline volumes.

	June 30,			December 31,
	2009			2008
	(In thousands)
Balance Sheet Data
Cash and cash equivalents	$	4,195		$	5,269
Working capital(5)	$	(6,562	)	$	(37,832	)
Total assets(6)	$	505,115		$	439,688
Long-term debt(7)	$	402,810		$	355,793
Total equity(6)(8)	$	65,759		$	8,120

(5)

Working capital at December 31, 2008 reflects $29.0 million of credit agreement advances that were classified as short-term borrowings.

(6)

As a master limited partnership, we distribute our available cash, which historically has exceeded net income because depreciation and amortization expense represents a non-cash charge against income. The result is a decline in equity since our regular quarterly distributions have exceeded our quarterly net income. Additionally, if the assets transferred to us upon our initial public offering in 2004 and the intermediate pipelines purchased from Holly in 2005 had been acquired from third parties, our acquisition cost in excess of Holly’s basis in the transferred assets of $157.3 million would have been recorded as increases to our properties and equipment and intangible assets instead of reductions to equity.

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(7)	Includes $218.0 million of credit agreement advances that were classified long-term debt at June 30, 2009.
(8)	On January 1, 2009, we adopted Statement of Financial Accounting Standard (“SFAS”) No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an amendment of Accounting Research Bulletin (“ARB”) No. 51.” As a result, net income attributable to the noncontrolling interest in our Rio Grande subsidiary is now presented as an adjustment to net income to arrive at “Net income attributable to Holly Energy Partners, L.P.” in our Consolidated Statements of Income. Prior to our adoption of this standard, this amount was presented as “Minority interest in Rio Grande,” a non-operating expense item before “Income before income taxes.” Additionally, equity attributable to noncontrolling interests in our Rio Grande subsidiary is now presented as a separate component of total equity in our Consolidated Financial Statements. We have applied this standard on a retrospective basis. While this presentation differs from previous GAAP requirements, this standard did not affect our net income and equity attributable to HEP.
(9)	On January 1, 2009, we also adopted Emerging Issues Task Force (“EITF”) No. 07-4, “Application of the Two-Class Method under SFAS No. 128, ‘Earnings per Share,’ to Master Limited Partnerships,” which prescribes the application of the two-class method in computing earnings per unit to reflect a master limited partnership’s contractual obligation to make distributions to the general partner, limited partners and incentive distribution rights holders. As a result, our quarterly earnings allocations to the general partner now include incentive distributions that were declared subsequent to quarter end. Prior to our adoption of this standard, our general partner earnings allocations included incentive distributions that were declared during each quarter. We have applied this standard on a retrospective basis. Although this standard resulted in a decrease in our limited partners’ interest in net income attributable to Holly Energy Partners, L.P. for the three and six month ended June 30, 2008, it did not affect earnings of $0.18 and $0.61 per limited partner unit for the three and six months ended June 30, 2008, respectively.

Results of Operations — Three Months Ended June 30, 2009 Compared with Three Months Ended June 30, 2008

Summary

Net income attributable to HEP for the three months ended June 30, 2009 was $16.4 million, a $12.6 million increase compared to the same period in 2008. This increase was due principally to increased shipments on our pipeline systems, the effect of the July 2008 annual tariff increases on affiliate pipeline shipments and an increase in previously deferred revenue realized. These factors were partially offset by an increase in operating costs and expenses. Revenue of $1.6 million relating to deficiency payments associated with certain guaranteed shipping contracts was deferred during the three months ended June 30, 2009. Such revenue will be recognized in future periods either as payment for shipments in excess of guaranteed levels or when shipping rights expire unused after a twelve-month period.

Revenues

Total revenues for the three months ended June 30, 2009 were $40.6 million, a $13.8 million increase compared to the three months ended June 30, 2008. This increase was due principally to overall increased shipments on our pipeline systems, the effect of the July 2008 annual tariff increase on affiliate pipeline shipments and an increase in previously deferred revenue realized. Increased volumes attributable to Holly’s 15,000 bpsd expansion of the Navajo Refinery, including volumes shipped on our new 16-inch pipeline, contributed to a 19% increase in affiliate pipeline shipments. Additionally, last year’s third-party refined product shipments were down as a result of limited production resulting from an explosion and fire at Alon’s Big Spring refinery in the first quarter of 2008. Furthermore, affiliate shipments were also down during the second quarter of 2008 as a result of unplanned downtime at Holly’s Navajo Refinery in May 2008.

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Revenues from our refined product pipelines were $25.1 million, an increase of $10.5 million compared to the second quarter of 2008. This increase was due to increased shipments on our refined product pipeline system, the effect of the July 2008 annual tariff increase on affiliate refined product shipments and a $4.3 million increase in previously deferred revenue realized. Shipments on our refined product pipeline system increased to an average of 151.6 mbpd compared to 100.2 mbpd for the same period last year.

Revenues from our intermediate pipelines were $4.3 million, an increase of $1.8 million compared to the second quarter of 2008. This increase was due to increased shipments on our intermediate pipeline system, the effect of the July 2008 annual tariff increase on intermediate pipeline shipments and a $0.7 million increase in previously deferred revenue realized. Shipments on our intermediate product pipeline system increased to an average of 70.5 mbpd compared to 51.9 mbpd for the same period last year.

Revenues from our crude pipelines were $6.8 million, an increase of $0.2 million compared to the second quarter of 2008. Shipments on our crude pipeline system increased to an average of 142.6 mbpd compared to 130.6 mbpd for the same period last year.

Revenues from terminal, tankage and truck loading rack fees were $4.5 million, an increase of $1.3 million compared to the second quarter of 2008. Refined products terminalled in our facilities increased to an average of 156.0 mbpd compared to 124.5 mbpd for the same period last year.

Operating Costs

Operations expense for three months ended June 30, 2009 increased by $1.1 million compared to the three months ended June 30, 2008. This increase was due principally to costs attributable to higher throughput volumes.

Depreciation and Amortization

Depreciation and amortization for the three months ended June 30, 2009 increased by $0.8 million compared to the three months ended June 30, 2008. This increase was due principally to increased depreciation attributable to asset acquisitions and capital projects.

General and Administrative

General and administrative costs for the three months ended June 30, 2009 increased by $0.5 million compared to the three months ended June 30, 2008. This increase was due principally to increased professional fees.

Equity in earnings of SLC Pipeline

The SLC Pipeline commenced pipeline operations effective March 2009. Our equity in earnings of the SLC Pipeline was $0.4 million for the three months ended June 30, 2009.

Interest Expense

Interest expense for the three months ended June 30, 2009 totaled $4.4 million, a decrease of $0.8 million compared to the three months ended June 30, 2008. This was due to the effects of interest attributable to advances from our revolving credit agreement that were used to finance asset acquisitions as well as capital projects, offset by the effects of a lower effective interest rate. Additionally for the three months ended June 30, 2009, fair value adjustments to our interest rate swaps resulted in a $0.8 million non-cash reduction in interest expense. Excluding the effects of these fair value adjustments, our aggregate effective interest rate was 5.3% for the three months ended June 30, 2009 compared to 5.6% for the same period last year.

State Income Tax

State income taxes were $0.1 million for each of the three months ended June 30, 2009 and 2008.

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Results of Operations — Six Months Ended June 30, 2009 Compared with Six Months Ended June 30, 2008

Summary

Net income attributable to HEP for the six months ended June 30, 2009 was $21.8 million, a $10.2 million increase compared to the same period in 2008. This increase was due principally to increased third-party refined product shipments, increased revenues attributable to our crude pipeline and tankage assets, the effect of the July 2008 annual tariff increase on affiliate pipeline shipments and an increase in previously deferred revenue realized. Additionally, we incurred acquisition costs of $2.5 million that relate to the acquisition of our SLC Pipeline joint venture interest in March 2009. Revenue of $5.1 million relating to deficiency payments associated with certain guaranteed shipping contracts was deferred during the six months ended June 30, 2009. Such revenue will be recognized in future periods either as payment for shipments in excess of guaranteed levels, or when shipping rights expire unused after a twelve-month period.

In February 2008, we acquired certain crude pipeline and tankage assets from Holly (the “Crude Pipelines and Tankage Assets”) that service Holly’s Navajo and Woods Cross Refineries. For the six months ended June 30, 2008, our results of operations reflect only four months of crude pipeline and tankage operating activity due to our crude pipeline and tankage operations commencing March 1, 2008.

Revenues

Total revenues for the six months ended June 30, 2009 were $72.7 million, an $18.7 million increase compared to the six months ended June 30, 2008. This increase was due principally to increased third-party refined product shipments, increased revenues attributable to our crude pipeline assets acquired in the first quarter of 2008, the effect of the July 2008 annual tariff increases on affiliate pipeline shipments and an increase in previously deferred revenue realized. With respect to affiliate shipments, the second quarter increases were offset by the effects of reduced production during Holly’s planned maintenance turnaround of its Navajo Refinery in the first quarter of 2009. Additionally, last year’s third-party refined product shipments were down as a result of limited production resulting from an explosion and fire at Alon’s Big Spring refinery in the first quarter of 2008.

Revenues from our refined product pipelines were $44.9 million, an increase of $12.9 million compared to the six months ended June 30, 2008. This increase was due to increased third-party shipments on our refined product pipeline system, the effect of the July 2008 annual tariff increase on affiliate refined product shipments and a $6.4 million increase in previously deferred revenue realized. These increases were partially offset by the effects of a slight decline in affiliate refined product pipeline shipments resulting from production downtime during the Navajo Refinery turnaround in the first quarter of 2009. Shipments on our refined product pipeline system increased to an average of 140.2 mbpd compared to 115.2 mbpd for the same period last year.

Revenues from our intermediate pipelines of $6.1 million were relatively flat compared to the six months ended June 30, 2008. This was due to the effect of the July 2008 annual tariff increase on intermediate pipeline shipments, a $0.4 million increase in previously deferred revenue realized and shipments on our new 16-inch intermediate pipeline, offset by the effects of a decrease in intermediate pipeline shipments resulting from production downtime during the Navajo Refinery turnaround in the first quarter of 2009. Shipments on our intermediate product pipeline system decreased to an average of 52.5 mbpd compared to 59.7 mbpd for the same period last year.

Revenues from our crude pipelines were $13.7 million, an increase of $4.9 million compared to six months ended June 30, 2008. This increase was due to the realization of revenues from crude oil shipments for a full six-month period during the six months ended June 30, 2009 compared to four months of shipments during the same period last year due to the commencement of our crude pipeline operations effective March 1, 2008. This was partially offset by the effects of a slight decrease in crude pipeline shipments resulting from production downtime during the Navajo Refinery turnaround in the first quarter of 2009. Shipments on our crude pipeline system decreased to an average of 132.5 mbpd during the six months ended June 30, 2009 compared to 133.1 mbpd for the months of March through June 2008.

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Revenues from terminal, tankage and truck loading rack fees were $8.1 million, an increase of $0.8 million compared to the same period last year. Refined products terminalled in our facilities decreased to an average of 141.2 mbpd compared to 144.6 mbpd for the same period last year.

Operating Costs

Operations expense for the six months ended June 30, 2009 increased by $2.2 million compared to the six months ended June 30, 2008. This increase was due principally to costs attributable to higher throughput volumes as well as costs associated with our crude pipelines acquired in February 2008. For the six months ended June 30, 2009, operating costs reflect costs attributable to our crude pipeline operations for a full six-month period compared to four months during the same period of 2008 due to the commencement of our crude pipeline operations effective March 1, 2008.

Depreciation and Amortization

Depreciation and amortization for the six months ended June 30, 2009 increased by $2.7 million compared to the six months ended June 30, 2008. This increase was due principally to increased depreciation attributable to asset acquisitions and capital projects.

General and Administrative

General and administrative costs for the six months ended June 30, 2009 increased by $0.5 million compared to the six months ended June 30, 2008. This increase was due principally to increased professional fees.

Equity in earnings of SLC Pipeline

The SLC Pipeline commenced pipeline operations effective March 2009. Our equity in earnings of the SLC Pipeline was $0.6 million for the six months ended June 30, 2009.

SLC Pipeline Acquisition Costs

We incurred a $2.5 million finder’s fee in connection with the acquisition our SLC Pipeline joint venture interest. As a result of SFAS 141(R) effective January 1, 2009, we were required to expense rather than capitalize these direct acquisition costs.

Interest Expense

Interest expense for the six months ended June 30, 2009 totaled $9.8 million, an increase of $0.8 million compared to the six months ended June 30, 2008. This increase was due principally to interest attributable to advances from our revolving credit agreement that were used to finance asset acquisitions as well as capital projects. Additionally for the six months ended June 30, 2009, fair value adjustments to our interest rate swaps resulted in a $0.6 million non-cash reduction in interest expense. Excluding the effects of these fair value adjustments, our aggregate effective interest rate was 5.3% for the six months ended June 30, 2009 compared to 5.4% for the same period last year.

State Income Tax

State income taxes were $0.2 million for each of the six months ended June 30, 2009 and 2008.

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LIQUIDITY AND CAPITAL RESOURCES

Overview

We have a $300.0 million senior secured revolving credit agreement expiring in August 2011 (the “Credit Agreement”). The Credit Agreement is available to fund capital expenditures, acquisitions, and working capital and for general partnership purposes. In addition, the Credit Agreement is available to fund letters of credit up to a $50.0 million sub-limit and to fund distributions to unitholders up to a $20.0 million sub-limit. During the six months ended June 30, 2009, we received advances totaling $99.0 million that were used as interim financing for capital projects and acquisitions and repaid $81.0 million, resulting in $18.0 million in net advances received. As of June 30, 2009, we had $218.0 million outstanding under the Credit Agreement.

Our senior notes maturing March 1, 2015 are registered with the U.S. Securities and Exchange Commission (“SEC”) and bear interest at 6.25% (the “Senior Notes”). The Senior Notes are unsecured and impose certain restrictive covenants, 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.

In May 2009, we closed a public offering of 2,192,400 of our common units priced at $27.80 per unit including 192,400 common units issued pursuant to the underwriters’ exercise of their over-allotment option. Net proceeds of $58.4 million were used to repay bank debt and for general partnership purposes. In addition, we received a $1.2 million capital contribution from our general partner to maintain its 2% general partner interest.

Under our registration statement filed with the SEC using a “shelf” registration process, we currently have the ability to raise approximately $940.0 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.

We believe our current cash balances, future internally-generated funds and funds available under our Credit Agreement will provide sufficient resources to meet our working capital liquidity needs for the foreseeable future. With the current conditions in the credit and equity markets, there may be limits on our ability to issue new debt or equity financing. Additionally, due to pricing in the current debt and equity markets, we may not be able to issue new debt and equity at acceptable pricing. As a result, our ability to fund certain of our planned capital projects and other business opportunities may be limited.

In February and May 2009, we paid regular cash distributions of $0.765 and $0.775 on all units, an aggregate amount of $28.0 million. Included in these distributions was $2.3 million paid to the general partner as an incentive distribution.

Cash and cash equivalents decreased by $1.1 million during the six months ended June 30, 2009. The cash flows used for investing activities of $81.5 million exceeded cash flows provided by operating and financing activities of $32.3 million and $48.2 million, respectively. Working capital for the six months ended June 30, 2009 increased by $31.3 million due principally to the reclassification of $29.0 million in Credit Agreement advances to long-term debt. These advances were classified as short-term borrowings at December 31, 2008 and have been reclassified to long-term debt since our Credit Agreement expires in 2011.

Cash Flows — Operating Activities

Cash flows from operating activities increased by $8.8 million from $23.4 million for the six months ended June 30, 2008 to $32.2 million for the six months ended June 30, 2009. Additional cash collections of $11.3 million from our major customers were offset by miscellaneous year-over-year changes in collections and payments.

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Our major shippers are obligated to make deficiency payments to us if they do not meet their minimum volume shipping obligations. Certain of these shippers then have the right to recapture these amounts if future volumes exceed minimum levels. For the six months ended June 30, 2009, we received cash payments of $5.3 million under these commitments. We billed $8.8 million during the six months ended June 30, 2008 related to shortfalls that subsequently expired without recapture and was recognized as revenue during the six months ended June 30, 2009. Another $1.7 million is included in our accounts receivable at June 30, 2009 related to shortfalls that occurred in the second quarter of 2009.

Cash Flows — Investing Activities

Cash flows used for investing activities decreased by $109.5 million from $191.0 million for the six months ended June 30, 2008 to $81.5 million for the six months ended June 30, 2009. During the six months ended June 30, 2009, we acquired Holly’s 16-inch intermediate pipeline and our SLC Pipeline joint venture interest costing $34.2 million and $25.5 million, respectively. Additionally, additions to properties and equipment for the six months ended June 30, 2009 were $21.8 million, an increase of $1.8 million compared to $20.0 million for same period last year. For the six months ended June 30, 2008, we paid $171.0 million in connection with our purchase of the Crude Pipelines and Tankage Assets from Holly in February 2008.

Cash Flows — Financing Activities

Cash flows provided by financing activities decreased by $115.4 million from $163.6 million for the six months ended June 30, 2008 to $48.2 million for the six months ended June 30, 2009. During the six months ended June 30, 2009, we received $99.0 million and repaid $81.0 million in advances under the Credit Agreement. We also received $58.4 million in proceeds and incurred $0.2 million in costs with respect to our May 2009 equity offering. During the six months ended June 30, 2009, we paid $28.0 million in regular quarterly cash distributions to our general and limited partners and paid $0.6 million in distributions to noncontrolling interest holders in Rio Grande. Additionally during 2009, we received a $1.2 million capital contribution from our general partner and paid $0.6 million for the purchase of common units for recipients of our restricted unit incentive grants. During the six months ended June 30, 2008, we received $211.0 million and repaid $20.0 million in advances under the Credit Agreement, received $0.1 million from the issuance of our common units and incurred $0.6 million in deferred financing costs with respect to the amendment to the Credit Agreement. We also paid $25.7 million in regular quarterly cash distributions to our general partner and limited partners and paid $0.9 million in distributions to noncontrolling interest holders in Rio Grande. Additionally during 2008, we received a $0.2 million capital contribution from our general partner and paid $0.5 million for the purchase of common units for recipients of our restricted unit 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 Holly Logistic Services, L.L.C. (“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 2009 capital budget is comprised of $3.7 million for maintenance capital expenditures and $2.2 million for expansion capital expenditures. Additionally, capital expenditures planned in 2009 include approximately $43.0 million for capital projects approved in prior years, most of which relate to the expansion of our pipeline between Artesia, New Mexico and El Paso, Texas (the “South System”) and the joint venture with Plains All American Pipeline, L.P. discussed below.

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In October 2007, we entered into an agreement with Holly that amends the Holly PTA under which we have agreed to expand the South System. The expansion of the South System includes replacing 85 miles of 8-inch pipe with 12-inch pipe, adding 150,000 barrels of refined product storage at our El Paso Terminal, improving existing pumps, adding a tie-in to the Kinder Morgan pipeline to Tucson and Phoenix, Arizona, and making related modifications. The cost of this project is estimated to be $51.0 million. Construction of the South System pipe replacement and storage tankage is complete and improvements to Kinder Morgan’s El Paso pump station are expected to be completed by August 2009.

In March 2009, we acquired a 25% joint venture interest in a new 95-mile intrastate pipeline system, the SLC Pipeline, jointly owned by Plains and us. The SLC Pipeline allows various refiners in the Salt Lake City area, including Holly’s Woods Cross Refinery, to ship crude oil into the Salt Lake City area from the Utah terminus of the Frontier Pipeline as well as crude oil flowing from Wyoming and Utah via Plains’ Rocky Mountain Pipeline. The total cost of our investment in the SLC Pipeline was $28.0 million, consisting of the capitalized $25.5 million joint venture contribution and the $2.5 million finder’s fee paid to Holly that was expensed as acquisition costs.

We have an option agreement with Holly, granting us an option to purchase Holly’s 75% equity interest in a joint venture pipeline currently under construction. The pipeline will be capable of transporting refined petroleum products from Salt Lake City, Utah to Las Vegas, Nevada (the “UNEV Pipeline”). Under this agreement, we have an option to purchase Holly’s equity interests in the UNEV Pipeline, effective for a 180-day period commencing when the UNEV Pipeline becomes operational, at a purchase price equal to Holly’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 total cost of the pipeline project including terminals is expected to be $300.0 million. Holly’s share of this cost is $225.0 million. Holly has decided to delay completion of the UNEV project until the fall of 2010.

Holly is currently working on a project to deliver additional crude oils to its Navajo Refinery, including a 70-mile pipeline from Centurion Pipeline L.P.’s Slaughter Station in west Texas to Lovington, New Mexico. Under provisions of the Omnibus Agreement, we will have an option to purchase Holly’s investment in the project at a purchase price to be negotiated with Holly. The cost of the project is expected to be $35.5 million and construction is currently expected to be completed and the project to become fully operational in the fourth quarter of 2009.

We are currently working on a capital improvement project that will provide increased flexibility and capacity to our intermediate pipelines enabling us to accommodate increased volumes following Holly’s Navajo Refinery capacity expansion. This project is expected to be completed in the third quarter of 2009 at an estimated cost of $7.0 million.

During the first quarter of 2009, we completed the conversion of an existing 12-mile crude oil pipeline to a natural gas pipeline at a cost of $1.1 million. This pipeline is operational and delivering natural gas to Holly’s Navajo Refinery.

We expect that our currently planned expenditures for sustaining and maintenance capital as well as expenditures for acquisitions and capital development projects such as the UNEV Pipeline, South System expansion and Holly crude oil projects described above, will be funded with existing cash generated by operations, the sale of additional limited partner units, the issuance of debt securities and advances under our $300 million Credit Agreement maturing August 2011, or a combination thereof. With the current conditions in the credit and equity markets, there may be limits on our ability to issue new debt or equity financing. Additionally, due to pricing in the current 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 and Holly’s crude oil project. We are not obligated to purchase these assets nor are we subject to any fees or penalties if HLS’ board of directors decide not to proceed with any of these opportunities.

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Credit Agreement

We have a $300.0 million senior secured revolving credit agreement expiring in August 2011. The Credit Agreement is available to fund capital expenditures, acquisitions, and working capital and for general partnership purposes. In addition, the Credit Agreement is available to fund letters of credit up to a $50.0 million sub-limit and to fund distributions to unitholders up to a $20.0 million sub-limit. Advances under the Credit Agreement that are designated for working capital are classified as short-term liabilities. Other advances under the Credit Agreement, including advances used for the interim financing of capital projects, are classified as long-term liabilities. During the six months ended June 30, 2009, we received advances totaling $99.0 million that were used as interim financing for capital projects and acquisitions and repaid $81.0 million, resulting in $18.0 million in net advances received. As of June 30, 2009, we had $218.0 million outstanding under the Credit Agreement.

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 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. We are required to reduce all working capital borrowings under the Credit Agreement to zero for a period of at least 15 consecutive days in each twelve-month period prior to the maturity date of the agreement. As of June 30, 2009, we had no working capital borrowings.

Indebtedness under the Credit Agreement bears interest, at our option, at either (a) the reference rate as announced by the administrative agent plus an applicable margin (ranging from 0.25% to 1.50%) or (b) at a rate equal to the London Interbank Offered Rate (“LIBOR”) plus an applicable margin (ranging from 1.00% to 2.50%). In each case, the applicable margin is based upon the ratio of our funded debt (as defined in the agreement) to EBITDA (earnings before interest, taxes, depreciation and amortization, as defined in the agreement). We incur a commitment fee on the unused portion of the Credit Agreement at a rate ranging from 0.20% to 0.50% based upon the ratio of our funded debt to EBITDA for the four most recently completed fiscal quarters. At June 30, 2009, we are subject to a 0.375% commitment fee on the $82.0 million unused portion of the Credit Agreement. The agreement expires in August 2011. At that time, the agreement will terminate and all outstanding amounts thereunder will be due and payable.

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 and 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.

Additionally, the Credit Agreement contains certain provisions whereby the lenders may accelerate payment of outstanding debt under certain circumstances.

Senior Notes Due 2015

Our Senior Notes maturing March 1, 2015 are registered with the SEC and bear interest at 6.25%. The Senior Notes are unsecured and impose certain restrictive covenants, 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. 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.

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

	June 30,			December 31,
	2009			2008
	(In thousands)
Credit Agreement	$	218,000		$	200,000
Senior Notes
Principal		185,000			185,000
Unamortized discount		(2,154	)		(2,344	)
Unamortized premium — de-designated fair value hedge		1,964			2,137
		184,810			184,793
Total debt		402,810			384,793
Less net short-term borrowings under credit agreement(1)		—			29,000
Total long-term debt(1)	$	402,810		$	355,793

(1) We are currently classifying all borrowings under the Credit Agreement as long-term. At December 31, 2008, we classified certain of our Credit Agreement borrowings as short-term.

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

Contractual Obligations

During the six months ended June 30, 2009, we received net advances of $18.0 million resulting in $218.0 million of outstanding principal under the Credit Agreement at June 30, 2009. 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 low in recent years and did not have a material impact on our results of operations for the six months ended June 30, 2009 and 2008.

A substantial majority of our revenues are generated under long-term contracts that include the right to increase our rates and minimum revenue guarantees annually for increases in the PPI. Historically, the PPI has increased an average of 4.3% annually over the past 5 calendar years.

Environmental Matters

Our operation of pipelines, terminals, and associated facilities in connection with the storage and transportation 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, Holly has also 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 Omnibus Agreement provides

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environmental indemnification of up to $15.0 million through 2014 for the assets transferred to us at the time of our initial public offering in 2004, plus an additional $2.5 million through 2015 for the intermediate pipelines acquired in July 2005 and up to $7.5 million through 2023 for the Crude Pipelines and Tankage Assets acquired in February 2008.

Additionally, 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 $20.0 million maximum liability cap.

There are environmental remediation projects that are currently underway relating to certain assets purchased from Holly Corporation. These remediation projects, including assessment and monitoring activities are covered by the environmental indemnification discussed above and represent liabilities of Holly Corporation.

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 U.S. GAAP. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities as of the date of the financial statements. Actual results may differ from these estimates under different assumptions or conditions. We consider the following policies to be the most critical to understanding the judgments that are involved and the uncertainties that could impact our results of operations, financial condition and cash flows.

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, 2008. 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 2009.

Recent Accounting Pronouncements

SFAS No. 160 “Noncontrolling Interests in Consolidated Financial Statements — an Amendment of ARB No. 51”

SFAS No. 160 became effective January 1, 2009, which changes the classification of noncontrolling interests, also referred to as minority interests, in the consolidated financial statements. As a result, all previous references to “minority interest” within this document have been replaced with “noncontrolling interest.” Additionally, net income attributable to the noncontrolling interest in our Rio Grande subsidiary is now presented as an adjustment to net income to arrive at “Net income attributable to Holly Energy Partners, L.P.” in our Consolidated Statements of Income. Prior to our adoption of this standard, this amount was presented as “Minority interest in Rio Grande,” a non-operating expense item before “Income before income taxes.” Furthermore, equity attributable to noncontrolling interests in our Rio Grande subsidiary is now presented as a separate component of total equity in our Consolidated Financial Statements. We have applied this standard on a retrospective basis. While this presentation differs from previous GAAP requirements, this standard did not affect our net income and equity attributable to HEP.

SFAS 141(R) “Business Combinations”

SFAS No. 141(R) became effective January 1, 2009, which establishes principles and requirements for how an acquirer accounts for a business combination. It also requires that acquisition-related transaction and restructuring costs be expensed rather than be capitalized as part of the cost of an acquired business. Accordingly, we were required to expense the $2.5 million finder’s fee related to the acquisition of our SLC Pipeline joint venture interest.

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SFAS No. 161 “Disclosures about Derivative Instruments and Hedging Activities, an Amendment of SFAS No. 133”

SFAS No. 161 became effective January 1, 2009, which amends and expands the disclosure requirements of SFAS 133 to include disclosure of the objectives and strategies related to an entity’s use of derivative instruments, disclosure of how an entity accounts for its derivative instruments and disclosure of the financial impact, including the effect on cash flows associated with derivative activity. See risk management below for disclosure of our derivative instruments and hedging activity.

EITF Issue No. 07-04 “Application of the Two-Class Method under SFAS No. 128, ‘Earnings per Share,’ to Master Limited Partnerships”

EITF No. 07-04 became effective January 1, 2009, which prescribes the application of the two-class method in computing earnings per unit to reflect a master limited partnership’s contractual obligation to make distributions to the general partner, limited partners and incentive distribution rights holders. As a result, our quarterly earnings allocations to the general partner now include incentive distributions that were declared subsequent to quarter end. Prior to our adoption of this standard, our general partner earnings allocations included incentive distributions that were declared during each quarter. We have applied this standard on a retrospective basis. Although this standard resulted in a decrease in our limited partners’ interest in net income attributable to Holly Energy Partners, L.P. for the three and six months ended June 30, 2008, it did not affect earnings of $0.18 and $0.61 per limited partner unit for the three and six months ended June 30, 2008, respectively.

Financial Accounting Standards Board (“FASB”) Staff Position (“FSP”) No. EITF 03-6-1 “Determining Whether Instruments Granted in Share-Based Transactions Are Participating Securities”

FSP No. 03-6-1 became effective January 1, 2009, which provides guidance in determining whether unvested instruments granted under share-based payment transactions are participating securities and, therefore, should be included in earnings per share calculations under the two-class method provided under SFAS No. 128, Earnings per Share. The adoption of this standard did not have a material effect on our financial condition, results of operations and cash flows.

SFAS No. 165 “Subsequent Events”

In May 2009, the FASB issued SFAS No. 165, which establishes general standards for accounting and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. We adopted this standard effective June 30, 2009. Although this standard requires disclosure of the date through which we have evaluated subsequent events, it did not affect our accounting and disclosure policies with respect to subsequent events.

FSP SFAS No. 107-1 and Accounting Principles Board (“APB”) No. 28-1 “Interim Disclosures about Fair Value of Financial Instruments”

In April 2009, the FASB issued FSP SFAS No, 107-1 and APB No. 28-1, which extends the annual financial statement disclosure requirements for financial instruments to interim reporting periods of publicly traded companies. We adopted this standard effective June 30, 2009.

RISK MANAGEMENT

We use interest rate derivatives to manage our exposure to interest rate risk. As of June 30, 2009, we have three interest rate swap contracts.

We have an interest rate swap that hedges our exposure to the cash flow risk caused by the effects of LIBOR changes on the $171.0 million Credit Agreement advance that we used to finance our purchase of the Crude Pipelines and Tankage Assets in February 2008. This interest rate swap effectively converts our $171.0 million LIBOR based debt to fixed rate debt having an interest rate of 3.74% plus an applicable margin, currently 2.00%, which equaled an effective interest rate of 5.74% as of June 30, 2009. The maturity date of this swap contract is February 28, 2013. We intend to renew our Credit Agreement prior to its expiration in August 2011.

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 our $171.0 million variable rate debt

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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 income. 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 our $171.0 million variable rate debt. Any ineffectiveness is reclassified from accumulated other comprehensive income to interest expense. As of June 30, 2009, we had no ineffectiveness on our cash flow hedge.

We also have an interest rate swap contract that effectively converts interest expense associated with $60.0 million of our 6.25% Senior Notes from a fixed to a variable rate (“Variable Rate Swap”). Under this swap contract, interest on the $60.0 million notional amount is computed using the three-month LIBOR plus a spread of 1.1575%, which equaled an effective interest rate of 1.83% as of June 30, 2009. The maturity date of this swap contract is March 1, 2015, matching the maturity of the Senior Notes.

In October 2008, we entered into an additional interest rate swap contract, effective December 1, 2008, that effectively unwinds the effects of the Variable Rate Swap discussed above, converting $60.0 million of our hedged long-term debt back to fixed rate debt (“Fixed Rate Swap”). Under the Fixed Rate Swap, interest on a notional amount of $60.0 million is computed at a fixed rate of 3.59% versus three-month LIBOR which when added to the 1.1575% spread on the Variable Rate Swap results in an effective fixed interest rate of 4.75%. The maturity date of this swap contract is December 1, 2013.

Prior to the execution of our Fixed Rate Swap, the Variable Rate Swap was designated as a fair value hedge of $60.0 million in outstanding principal under the Senior Notes. We dedesignated this hedge in October 2008. At this time, the carrying balance of our Senior Notes included a $2.2 million premium due to the application of hedge accounting until the dedesignation date. This premium is being amortized as a reduction to interest expense over the remaining term of the Variable Rate Swap.

Our interest rate swaps not having a “hedge” designation are measured quarterly at fair value either as an asset or a liability in our consolidated balance sheets with the offsetting fair value adjustment to interest expense. For the three and six months ended June 30, 2009, we recognized a reduction of $0.8 million and $0.6 million, respectively, in interest expense as a result of fair value adjustments to our interest rate swaps.

We record interest expense equal to the variable rate payments under the swaps. Receipts under the swap agreements are recorded as a reduction of interest expense.

Additional information on our interest rate swaps as of June 30, 2009 are as follows:

	Balance Sheet				Location of Offsetting	Offsetting
Interest Rate Swaps	Location	Fair Value			Balance	Amount
	(In thousands)
Asset
Fixed-to-variable interest rate swap	Other assets	$	2,751		Long-term debt	$	(1,964	)
- $60 million of 6.25% Senior Notes					HEP partners’ equity		(1,942	)(1)
					Interest expense		1,155	(2)
		$	2,751			$	(2,751	)
Liability
Cash flow hedge — $171 million LIBOR based debt	Other long-term liabilities	$	(8,700	)	Accumulated other comprehensive loss	$	8,700
Variable-to-fixed interest rate swap	Other long-term				HEP partners’ equity		4,166	(1)
- $60 million	liabilities		(2,209	)	Interest expense		(1,957	)
		$	(10,909	)		$	10,909

(1)	Represents prior year charges to interest expense.
(2)	Net of amortization of premium attributable to dedesignated hedge.

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

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At June 30, 2009, we had an outstanding principal balance on our 6.25% Senior Notes of $185.0 million. By means of our interest rate swap contracts, we have effectively converted the 6.25% fixed rate on $60.0 million of the Senior Notes to a fixed rate of 4.75%. A change in interest rates would generally affect the fair value of the debt, but not our earnings or cash flows. At June 30, 2009, the fair value of our Senior Notes was $161.0 million. We estimate a hypothetical 10% change in the yield-to-maturity applicable to the Senior Notes at June 30, 2009 would result in a change of approximately $9.6 million in the fair value of the debt.

At June 30, 2009, 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 to any significant degree 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 Exchange Act Rule 13a-15(e)) as of the end of the period covered by this quarterly report on Form 10-Q. Based on that evaluation, the principal executive officer and principal financial officer concluded that the design and operation of our disclosure controls and procedures are effective in ensuring that information we are required to disclose in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission’s rules and forms.

(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 been 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

4.1*	Third Supplemental Indenture, dated June 11, 2009, among Lovington-Artesia, L.L.C., Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors, and U.S. Bank National Association.
4.2*	Fourth Supplemental Indenture, dated June 29, 2009, among HEP SLC, LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors, and U.S. Bank National Association.
4.3*	Fifth Supplemental Indenture, dated July 13, 2009, among HEP Tulsa LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors, and U.S. Bank National Association.
10.1	LLC Interest Purchase Agreement, dated as of June 1, 2009, by and among Holly Corporation, Navajo Pipeline Co., L.P. and Holly Energy Partners — Operating, L.P. (incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K Current Report dated June 5, 2009, File No. 1-32225).
10.2	Amended and Restated Intermediate Pipelines Agreement, dated as of June 1, 2009, by and among Holly Corporation, Navajo Refining Company, L.L.C., Holly Energy Partners, L.P., Holly Energy Partners — Operating, L.P., HEP Pipeline, L.L.C., Lovington-Artesia, L.L.C., HEP Logistics Holdings, L.P., Holly Logistic Services, L.L.C. and HEP Logistics GP, L.L.C. (incorporated by reference to Exhibit 10.2 of Registrant’s Form 8-K Current Report dated June 5, 2009, File No. 1-32225).
10.3	Amended and Restated Omnibus Agreement, dated as of June 1, 2009, by and among Holly Corporation, Navajo Pipeline Co., L.P., Holly Logistic Services, L.L.C., HEP Logistics Holdings, L.P., Holly Energy Partners, L.P., HEP Logistics GP, L.L.C. and Holly Energy Partners — Operating, L.P. (incorporated by reference to Exhibit 10.3 of Registrant’s Form 8-K Current Report dated June 5, 2009, File No. 1-32225).
10.4	Mortgage, Line of Credit Mortgage and Deed of Trust, dated June 1, 2009, by Lovington-Artesia, L.L.C. for the benefit of Holly Corporation (incorporated by reference to Exhibit 10.4 of Registrant’s Form 8-K Current Report dated June 5, 2009, File No. 1-32225).
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.

*	Filed herewith
**	Furnished herewith

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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: July 31, 2009	/s/ Bruce R. Shaw
	Bruce R. Shaw
	Senior 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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