Holly Energy Partners (HEP) 10-Q 2006 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 endedJune 30, 2006

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	(I.R.S. Employer
incorporation or organization)	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 is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filero Accelerated filerþ Non-accelerated filero

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 21, 2006 was 8,170,000.

HOLLY ENERGY PARTNERS, L.P.
INDEX

PART I. FINANCIAL INFORMATION	3
FORWARD-LOOKING STATEMENTS	3
Item 1. Financial Statements (Unaudited, except December 31, 2005 Balance Sheet)	4
Consolidated Balance Sheets	4
Consolidated Statements of Income	5
Consolidated Statements of Cash Flows	6
Consolidated Statement of Partners’ Equity (Deficit)	7
Notes to Consolidated Financial Statements	8
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Item 3. Quantitative and Qualitative Disclosures About Market Risks	38
Item 4. Controls and Procedures	38
PART II. OTHER INFORMATION	39
Item 1. Legal proceedings	39
Item 2. Unregistered sales of securities and use of proceeds	39
Item 6. Exhibits	39
SIGNATURES	40
Computation of Ratio of Earnings to Fixed Charges
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906

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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 the 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 materially differ 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 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 any future acquired operations;

• The availability and cost of our 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, in conjunction with the forward-looking statements included in this Form 10-Q 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, 2005 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, 2006			December 31,
	(Unaudited)			2005
	(In thousands, except unit data)
ASSETS
Current assets:
Cash and cash equivalents	$	16,414		$	20,583
Accounts receivable:
Trade		3,835			3,076
Affiliates		3,312			3,645
		7,147			6,721
Prepaid and other current assets		1,154			1,401
Total current assets		24,715			28,705
Properties and equipment, net		160,538			162,298
Transportation agreements, net		58,862			60,903
Other assets		2,659			2,869
Total assets	$	246,774		$	254,775
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	3,418		$	3,020
Accrued interest		2,924			2,892
Deferred revenue		4,929			1,013
Other current liabilities		2,125			2,326
Total current liabilities		13,396			9,251
Commitments and contingencies		—			—
Long-term debt		178,435			180,737
Other long-term liabilities		3,271			974
Minority interest		10,826			11,753
Partners’ equity (deficit):
Common unitholders (8,170,000 units issued and outstanding)		179,024			184,650
Subordinated unitholder (7,000,000 units issued and outstanding)		(67,966	)		(63,235	)
Class B subordinated unitholder (937,500 units issued and outstanding)		23,754			24,388
General partner (2% interest)		(93,966	)		(93,743	)
Total partners’ equity		40,846			52,060
Total liabilities and partners’ equity	$	246,774		$	254,775

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,
	2006			2005			2006			2005
	(In thousands, except per unit data)
Revenues:
Affiliates	$	10,584		$	9,941		$	23,066		$	19,371
Third parties		7,943			9,580			17,899			16,663
		18,527			19,521			40,965			36,034
Operating costs and expenses:
Operations		7,429			6,448			14,538			11,836
Depreciation and amortization		3,781			3,849			7,574			6,212
General and administrative		1,289			990			2,513			1,967
		12,499			11,287			24,625			20,015
Operating income		6,028			8,234			16,340			16,019
Other income (expense):
Interest income		245			145			488			233
Interest expense		(3,247	)		(2,365	)		(6,422	)		(3,483	)
		(3,002	)		(2,220	)		(5,934	)		(3,250	)
Income before minority interest		3,026			6,014			10,406			12,769
Minority interest in Rio Grande Pipeline Company		(28	)		27			(273	)		(402	)
Net income		2,998			6,041			10,133			12,367
Less general partner interest in net income		319			121			646			247
Limited partners’ interest in net income	$	2,679		$	5,920		$	9,487		$	12,120
Net income per limited partner unit — Basic and diluted	$	0.17		$	0.40		$	0.59		$	0.83
Weighted average limited partners’ units outstanding		16,108			14,938			16,108			14,637

See accompanying notes.

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Holly Energy Partners, L.P.

Consolidated Statements of Cash Flows

(Unaudited)

	Six Months Ended June 30,
	2006			2005
	(In thousands)
Cash flows from operating activities
Net income	$	10,133		$	12,367
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		7,574			6,212
Minority interest in Rio Grande Pipeline Company		273			402
Amortization of restricted and performance units		409			33
(Increase) decrease in current assets:
Accounts receivable – trade		(759	)		(3,587	)
Accounts receivable – affiliates		333			(140	)
Prepaid and other current assets		172			(388	)
Increase (decrease) in current liabilities:
Accounts payable		398			1,050
Accrued interest		32			2,955
Deferred revenue		3,916			—
Other current liabilities		(200	)		125
Other, net		205			223
Net cash provided by operating activities		22,486			19,252
Cash flows from investing activities
Acquisition of pipeline and terminal assets		—			(121,853	)
Additions to properties and equipment		(3,699	)		(710	)
Other		—			(211	)
Net cash used for investing activities		(3,699	)		(122,774	)
Cash flows from financing activities
Proceeds from issuance of senior notes, net of discount		—			181,238
Net decrease in borrowings under revolving credit agreement		—			(25,000	)
Distributions to partners		(21,244	)		(15,526	)
Purchase of units for restricted grants		(512	)		—
Cash contribution from general partner		—			612
Deferred debt issuance costs		—			(967	)
Cash distributions to minority interest		(1,200	)		(1,620	)
Other		—			(9	)
Net cash provided by (used for) financing activities		(22,956	)		138,728
Cash and cash equivalents
Increase/(decrease) for period		(4,169	)		35,206
Beginning of period		20,583			19,104
End of period	$	16,414		$	54,310

See accompanying notes.

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Holly Energy Partners, L.P.

Consolidated Statement of Partners’ Equity (Deficit)

(Unaudited)

							Class B
	Common			Subordinated			Subordinated			General Partner
	Units			Units			Units			Interest			Total
	(In thousands)
Balance December 31, 2005	$	184,650		$	(63,235	)	$	24,388		$	(93,743	)	$	52,060
Distributions		(10,335	)		(8,854	)		(1,186	)		(869	)		(21,244	)
Purchase of units for restricted grants		(512	)		—			—			—			(512	)
Amortization of restricted and performance units		409			—			—			—			409
Net income		4,812			4,123			552			646			10,133
Balance June 30, 2006	$	179,024		$	(67,966	)	$	23,754		$	(93,966	)	$	40,846

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 45% owned by Holly Corporation (“Holly”). HEP commenced operations July 13, 2004 upon the completion of its 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 pipelines 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”). In July 2005, we acquired the two parallel intermediate feedstock pipelines, which connect the Lovington, New Mexico and Artesia, New Mexico refining facilities. 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. In conjunction with Holly’s operation of the Navajo Refinery, we operate refined product pipelines as part of the product distribution network of the Navajo Refinery. Our terminal operations serving the Navajo Refinery include a truck rack at the Navajo 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 a truck rack at the Woods Cross Refinery, a refined product terminal in Spokane, Washington and a 50% non-operating interest in product terminals in Boise and Burley, Idaho.

In February 2005, we acquired from Alon USA, Inc. and several of its wholly-owned subsidiaries (collectively, “Alon”) four refined products pipelines, an associated tank farm and two refined products terminals. These pipelines and terminals are located primarily in Texas and transport and terminal light refined products for Alon’s 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 liquid petroleum gases to northern Mexico.

The consolidated financial statements for the three and six months ended June 30, 2006 and 2005 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 are, in the opinion of management, 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, 2005. Results of operations for the three and six months ended June 30, 2006 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2006. Certain reclassifications have been made to prior reported amounts to conform to current classifications.

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Note 2: Acquisitions

Alon Transaction

On February 28, 2005, we acquired from Alon four refined products pipelines, an associated tank farm and two refined products terminals. These pipelines and terminals are located primarily in Texas and transport and terminal light refined products for Alon’s refinery in Big Spring, Texas.

The total consideration paid for these pipeline and terminal assets was $120 million in cash and 937,500 of our Class B subordinated units which, subject to certain conditions, will convert into an equal number of common units on February 28, 2010. We financed the Alon transaction with a portion of the proceeds of our private offering of $150 million principal amount of 6.25% senior notes due 2015 (see Note 5 for further information on the senior notes). In connection with the Alon transaction, we entered into a 15-year pipelines and terminals agreement with Alon (the “Alon PTA”). Under this agreement, Alon agreed to transport on the pipelines and throughput through the terminals a volume of refined products that would result in minimum revenue levels each year that will change annually based on changes in the producer price index (“PPI”), but will not decrease below the initial $20.2 million annual amount. The total commitment for 2006, including the effect of the March 1, 2006 PPI adjustment, is $20.5 million. The agreed upon tariffs will increase or decrease each year at a rate equal to the percentage change in the PPI, but not below the initial tariffs. Alon’s minimum volume commitment was calculated based on 90% of Alon’s then recent usage of these pipelines and terminals taking into account an expansion of Alon’s Big Spring Refinery completed in February 2005. At revenue levels above 105% of the base revenue amount, as adjusted each year for changes in the PPI, Alon will receive an annual 50% discount on incremental revenues. Alon’s obligations under the Alon PTA may be reduced or suspended under certain circumstances. We granted Alon a second mortgage on the pipelines and terminals acquired from Alon to secure certain of Alon’s rights under the Alon PTA. Alon has a right of first refusal to purchase the pipelines and terminals if we decide to sell them in the future. Additionally, we entered into an environmental agreement with Alon with respect to pre-closing environmental costs and liabilities relating to the pipelines and terminals acquired from Alon, whereby Alon will indemnify us subject to a $100,000 deductible and a $20 million maximum liability cap.

The consideration for the Alon pipeline and terminal assets was allocated to the individual assets acquired based on their estimated fair values. The allocation of the consideration is based on an independent appraisal. The aggregate consideration amounted to $146.7 million, which consisted of $24.7 million fair value of our Class B subordinated units, $120 million in cash and $2.0 million of transaction costs. In accounting for this acquisition, we recorded pipeline and terminal assets of $86.7 million and an intangible asset of $60.0 million, representing the allocated value of the 15-year Alon PTA. This intangible asset is included in “Transportation agreements, net” in our consolidated balance sheets.

Holly Intermediate Pipelines Transaction

On July 6, 2005, we entered into a definitive purchase agreement (the “Purchase Agreement”) with Holly to acquire Holly’s two parallel intermediate feedstock pipelines (the “Intermediate Pipelines”) which connect its Lovington, New Mexico and Artesia, New Mexico refining facilities. On July 8, 2005, we closed on the acquisition for $81.5 million, which consisted of $77.7 million in cash, 70,000 common units of HEP and a capital account credit of $1.0 million to maintain Holly’s existing general partner interest in the Partnership. We financed the cash portion of the consideration for the Intermediate Pipelines with the proceeds raised from (a) the private sale of 1,100,000 of our common units for $45.1 million to a limited number of institutional investors which closed simultaneously with the acquisition and (b) an additional $35.0 million in principal amount of our 6.25% senior notes due 2015. This acquisition was made pursuant to an option to purchase these pipelines granted by Holly to us at the time of our initial public offering in July 2004.

In connection with this transaction, we entered into a 15-year pipelines agreement with Holly (the “Holly IPA”), which expires in 2020. Under this agreement, Holly agreed to transport volumes of intermediate products on the Intermediate Pipelines that, at the agreed tariff rates, will result in minimum funds to us of $11.8 million per calendar year. The minimum commitment and the full base tariff will be adjusted each year at a rate equal to the percentage change in the PPI, but the minimum commitment will not decrease

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as a result of a decrease in the PPI. Holly’s minimum revenue commitment applies only to the Intermediate Pipelines, and Holly will not be able to spread its minimum revenue commitment among pipeline assets HEP already owns or subsequently acquires. If Holly fails to meet its minimum revenue commitment in any quarter, it will be required to pay us in cash the amount of any shortfall by the last day of the month following the end of the quarter. A shortfall payment may be applied as a credit in the following four quarters after Holly’s minimum obligations are met. As of June 30, 2006, $2.6 million of shortfalls had been billed to Holly under the Holly IPA and is available to be applied as credits to billings in 2006 and 2007 for shipments on the Intermediate Pipelines that exceed the minimum commitment. The Holly IPA may be extended by the mutual agreement of the parties.

We agreed to expend up to $3.5 million to expand the capacity of the Intermediate Pipelines to meet the needs of Holly’s expansion of their Navajo Refinery, of which we had spent $2.8 million as of June 30, 2006. If new laws or regulations are enacted that require us to make substantial and unanticipated capital expenditures with regard to the Intermediate Pipelines, we have the right to amend the tariff rates to recover our costs of complying with these new laws or regulations (including a reasonable rate of return). Under certain circumstances, either party may temporarily suspend its obligations under the Holly IPA. We granted Holly a second mortgage on the Intermediate Pipelines to secure certain of Holly’s rights under the Holly IPA. Holly agreed to provide $2.5 million of additional indemnification above that previously provided for environmental noncompliance and remediation liabilities occurring or existing before the closing date of the Purchase Agreement, bringing the total indemnification provided to us from Holly to $17.5 million. Of this total, indemnification above $15 million relates solely to the Intermediate Pipelines.

As this transaction was among entities under common control, we recorded the acquired assets at Holly’s historic book value of $6.8 million. The $71.9 million excess of the purchase price over the historic book value is recorded as a reduction to partners’ equity for financial accounting purposes.

Note 3: Properties and Equipment

	June 30,		December 31,
	2006		2005
	(In thousands)
Pipelines and terminals	$	186,458	$	184,464
Land and right of way		22,512		22,163
Other		6,294		5,728
Construction in progress		3,870		2,792
		219,134		215,147
Less accumulated depreciation		58,596		52,849
	$	160,538	$	162,298

During the three and six months ended June 30, 2006 and 2005, we did not capitalize any interest related to major construction projects.

Note 4: Transportation Agreements

The costs of two transportation agreements are recorded on our consolidated balance sheets at June 30, 2006:

• Costs incurred by Rio Grande in constructing certain pipeline and terminal facilities located in Mexico, which were then contributed to an affiliate of Pemex, the national oil company of Mexico. In exchange, Rio Grande received a 10-year transportation agreement from BP plc expiring in 2007. This asset is being amortized over the 10-year term of the agreement.

• A portion of the total purchase price of the Alon assets was allocated to the transportation agreement asset based on the fair value appraisal provided by an independent firm. 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.

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The carrying amounts of the transportation agreements are as follows:

	June 30,		December 31,
	2006		2005
	(In thousands)
Rio Grande transportation agreement	$	20,836	$	20,836
Alon transportation agreement		59,933		59,933
		80,769		80,769
Less accumulated amortization		21,907		19,866
	$	58,862	$	60,903

Note 5: Debt

Credit Agreement

In conjunction with our initial public offering on July 13, 2004, we entered into a four-year, $100 million senior secured revolving credit agreement (the “Credit Agreement”). Union Bank of California, N.A. is one of the lenders and serves as administrative agent under this agreement. During 2005, amendments were made to the Credit Agreement to allow for the closing of the Alon transaction and the related senior notes offering, the closing of the Holly Intermediate Pipelines transaction and to amend certain of the restrictive covenants. As of June 30, 2006 and December 31, 2005, we had no amounts outstanding under the Credit Agreement.

The Credit Agreement is available to fund capital expenditures, acquisitions, and working capital and for general partnership purposes. Advances under the Credit Agreement that are designated for working capital are short-term liabilities. Other advances under the Credit Agreement are classified as long-term liabilities. In addition, the Credit Agreement is available to fund letters of credit up to a $50 million sub-limit. Up to $5 million is available to fund distributions to unitholders.

We have the right to request an increase in the maximum amount of the Credit Agreement, up to $175 million. Such request will become effective if (a) certain conditions specified in the Credit Agreement are met and (b) existing lenders under the Credit Agreement or other financial institutions reasonably acceptable to the administrative agent commit to lend such increased amounts under the agreement.

Our obligations under the Credit Agreement are secured by substantially all of our assets. Indebtedness under the Credit Agreement is recourse to our general partner and guaranteed by our wholly-owned subsidiaries.

We may prepay all loans at any time without penalty. We are required to reduce all working capital borrowings under the Credit Agreement to zero for a period of at least 15 consecutive days once each twelve-month period prior to the maturity date of the agreement.

Indebtedness under the Credit Agreement bears interest, at our option, at either (a) the base rate as announced by the administrative agent plus an applicable margin (ranging from 0.25% to 1.00%) or (b) at a rate equal to the London Interbank Offered Rate (“LIBOR”) plus an applicable margin (ranging from 1.50% to 2.25%). 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 Credit Agreement). We incur a commitment fee on the unused portion of the Credit Agreement at a rate of 0.375% or 0.500% based upon the ratio of our funded debt to EBITDA for the four most recently completed fiscal quarters. At June 30, 2006, we are subject to the 0.500% rate on the $100 million of the unused commitment on the Credit Agreement. The agreement matures in July 2008. At that time, the agreement will terminate and all outstanding amounts thereunder will be due and payable.

The Credit Agreement imposes certain requirements, 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,

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change the nature of our business, enter a merger or consolidation, or sell assets; and covenants that require maintenance of 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.

Senior Notes Due 2015

We financed the $120 million cash portion of the Alon transaction through our private offering on February 28, 2005 of $150 million principal amount of 6.25% senior notes due 2015 (“Senior Notes”). We used the balance to repay $30 million of then outstanding indebtedness under our Credit Agreement, including $5 million drawn shortly before the closing of the Alon transaction.

We financed a portion of the cash consideration for the Intermediate Pipelines transaction with the private offering in June 2005 of an additional $35.0 million in principal amount of the Senior Notes.

On July 28, 2005, we filed a registration statement to allow the holders of the Senior Notes to exchange the Senior Notes for exchange notes registered with the SEC with substantially identical terms, which exchange was completed in October 2005.

The Senior Notes mature on March 1, 2015 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.

The $185 million principal amount of Senior Notes is recorded at $178.4 million on our consolidated balance sheet at June 30, 2006. The difference of $6.6 million is due to $3.3 million of unamortized discount and $3.3 million relating to the fair value of the interest rate swap contract discussed below.

Interest Rate Risk Management

We have entered into an interest rate swap contract to effectively convert the interest expense associated with $60 million of our 6.25% Senior Notes from a fixed rate to a variable rate. The interest rate on the $60 million notional amount is equal to three month LIBOR plus an applicable margin of 1.1575%, which equaled an effective interest rate of 5.94% on $60 million of the debt during the six months ended June 30, 2006. The maturity of the swap contract is March 1, 2015, matching the maturity of the Senior Notes.

This interest rate swap has been designated as a fair value hedge as defined by SFAS No. 133. Our interest rate swap meets the conditions required to assume no ineffectiveness under SFAS No. 133 and, therefore, we have used the “shortcut” method of accounting prescribed for fair value hedges by SFAS No. 133. Accordingly, we adjust the carrying value of the swap to its fair value each quarter, with an offsetting entry to adjust the carrying value of the debt securities whose fair value is being hedged. We record interest expense equal to the variable rate payments under the swaps.

The fair value of our interest rate swap of $3.3 million and $0.8 million is included in “Other long-term liabilities” in our consolidated balance sheets at June 30, 2006 and December 31, 2005, respectively. The offsetting entry to adjust the carrying value of the debt securities whose fair value is being hedged is recognized as a reduction of “Long-term debt” on our consolidated balance sheets at June 30, 2006 and December 31, 2005.

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Other Debt Information

	Six Months Ended
	June 30,
	2006		2005
	(In thousands)
Interest on outstanding debt:
Senior Notes, net of interest rate swap	$	5,690	$	2,825
Credit Agreement		—		164
Amortization of discount and deferred issuance costs		484		308
Commitment fees		248		186
Net interest expense	$	6,422	$	3,483
Cash paid for interest	$	7,781	$	937

We estimate that the fair value of our Senior Notes was $169.3 million at June 30, 2006, based on a determination by a third-party investment firm.

Note 6: Commitments and Contingencies

In June 2006, we exercised the first of two 10-year renewal options on our lease agreement for the refined products pipeline between White Lakes Junction and Kutz Station in New Mexico. This extension will become effective July 2007, immediately upon expiration of the original lease term. The minimum annual commitments under this new operating lease extension are as follows (excluding the second 10-year lease extension, which is likely to be exercised):

Year Ending
December 31,	$000’s
2007	$	3,041
2008		6,082
2009		6,082
2010		6,082
Thereafter		39,529
Total	$	60,816

Note 7: Earnings per Unit

Basic income per limited partner unit is calculated as net income available to common unitholders divided by the weighted average number of limited partner units outstanding during the period. Diluted income per limited partner unit gives effect to all potentially dilutive common units during the period, including variable performance units, using the treasury stock method. The issuance of potentially dilutive performance units was excluded from the calculation of diluted income per limited partner unit, as the effect would have been anti-dilutive.

Note 8: Employees, Retirement and Benefit 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 a three-year omnibus agreement we entered into with Holly in July 2004 (the “Omnibus Agreement”).

These employees participate in the retirement and benefit plans of Holly. Our share of retirement and benefits costs was $0.3 million and $0.2 million for the three months ended June 30, 2006 and 2005, respectively, and $0.6 million and $0.4 million for the six months ended June 30, 2006 and 2005, respectively.

- 13 -

We have adopted a Long-Term Incentive Plan for employees, consultants and 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.

On June 30, 2006, we had two types of equity-based compensation, which are described below. The compensation cost charged against income for these plans was $0.2 million and $0.1 million for the three months ended June 30, 2006 and 2005, respectively, and $0.4 million and $0.1 million for the six months ended June 30, 2006 and 2005, 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, 2006, 350,000 units were authorized to be granted under the equity-based compensation plans, of which 294,631 had not yet been granted.

We elected early adoption of SFAS 123 (revised) on July 1, 2005, based on modified prospective application. The effect of this change in accounting principle was immaterial to our financial condition and results of operations.

Restricted Units

Under our Long-Term Incentive Plan, we grant restricted units to selected employees, consultants and directors who perform services for us, with vesting generally over a period of two 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 unit of restricted unit awards 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 as of June 30, 2006, and changes during the six months ended June 30, 2006, is presented below:

						Weighted-
				Weighted-		Average	Aggregate
				Average		Remaining	Intrinsic
				Grant-Date		Contractual	Value
Restricted Units	Grants			Fair Value		Term	($000)
Outstanding January 1, 2006 (not vested)		20,926		$	40.98
Granted		12,661		$	39.45
Forfeited		(200	)	$	39.45
Vesting and transfer of full ownership to recipients		—			—
Outstanding at June 30, 2006 (not vested)		33,387		$	40.40	1.8 years	$	1,347

There were no restricted units vested or transferred to recipients during the six months ended June 30, 2006. As of June 30, 2006, there was $0.8 million of total unrecognized compensation costs related to nonvested restricted unit grants. That cost is expected to be recognized over a weighted-average period 1.8 years.

In June 2006, we paid $0.5 million for the purchase of 12,461 of our common units in the open market for the recipients of the February 2006 restricted units grant.

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 upon meeting the performance criteria over a service period, and generally vest over a period of three years. The amount payable under these grants is based upon our unit price and upon our total unitholder return during the requisite period as compared to the total unitholder return of a selected peer group of partnerships.

- 14 -

The initial performance unit grant was payable in cash. As of February 10, 2006, we amended the existing performance unit agreements to provide payment of these awards in HEP common units rather than payment in cash. The performance criteria were not amended. Until this conversion to equity payment, the fair value of each performance unit award was revalued quarterly based on our valuation model and the corresponding expense was amortized over the vesting periods. Upon conversion to equity payment, we established the fair value of each performance unit and are now amortizing that amount over the vesting period.

In addition to revising the existing performance unit agreements, we granted 12,501 performance units to certain officers in February 2006. These units will vest over a three-year performance period ending December 31, 2008, 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.

The fair value of the performance units is based on an expected cash flow approach at the grant date. The analysis utilizes the unit price, distribution yield, historical total returns as of the measurement date, expected total returns based on a capital asset pricing model methodology, standard deviation of historical returns, and comparison of expected total returns with the peer group. The expected total return and historical standard deviation is applied to a lognormal expected return distribution in a Monte Carlo simulation model to identify the expected range of potential returns and probabilities of expected returns. The range of inputs reflects changes in the remaining life of the performance units and changes in market conditions between measurement dates. The inputs affecting the range of expected total returns for HEP and the peer group are based on a capital asset pricing model utilizing information available at each measurement date.

Data Elements Used in Analysis
Closing price of HEP common units February 10, 2006	$	39.55
Latest quarterly distribution per limited unit	$	0.64
Risk-free rate		4.86	%

The monthly standard deviation of returns is based on the standard deviation of historical return information. The range of expected returns and standard deviation is presented below:

				Standard
	Expected Return on			Deviation
Company	Equity			(Monthly)
HEP		14.0	%		7.6	%
Peer group	9.8% to 11.0%			3.8% to 4.9%

A summary of performance units activity as of June 30, 2006, and changes during the six months ended June 30, 2006 is presented below:

	Payable			Payable
Performance Units	In Cash			In Units
Outstanding at January 1, 2006 (not vested)		1,515			—
Conversion to unit payment		(1,515	)		1,515
Vesting and payment of units to recipients		—			—
Granted		—			12,501
Forfeited		—			—
Outstanding at June 30, 2006 (not vested)		—			14,016

There were no payments for performance units vesting during the six months ended June 30, 2006. Based on the weighted average fair value at June 30, 2006 of $48.93, there was $0.5 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.

- 15 -

Note 9: Significant Customers

All revenues are domestic revenues, of which over 90% are currently generated from our three largest customers: Holly and two unaffiliated customers. The major concentration of our petroleum products pipeline system’s revenues is 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,
	2006			2005			2006			2005
Holly		57	%		51	%		56	%		54	%
BP plc		9	%		8	%		10	%		13	%
Alon		30	%		37	%		30	%		29	%

Note 10: Related Party Transactions

Holly

We have related party transactions with Holly for pipeline and terminal revenues, certain employee costs, insurance costs, and administrative costs under the 15-year pipelines and terminals agreement expiring in 2019 that we entered with Holly in July 2004 (the “Holly PTA”), the Holly IPA and the Omnibus Agreement.

• Pipeline and terminal revenues received from Holly were $10.6 million and $9.9 million for the three months ended June 30, 2006 and 2005, respectively, and $23.1 million and $19.4 million for the six months ended June 30, 2006 and 2005, respectively. These amounts include the revenues received under the Holly PTA and Holly IPA.

• Holly charged general and administrative services under the Omnibus Agreement of $0.5 million in the three months ended June 30, 2006 and 2005, and $1.0 million for the six months ended June 30, 2006 and 2005.

• We reimbursed Holly for costs of employees supporting our operations of $1.8 million and $1.6 million for the three months ended June 30, 2006 and 2005, respectively, and $3.7 million and $3.0 million for the six months ended June 30, 2006 and 2005, respectively.

• Holly reimbursed $40,000 and $66,000 to us for certain costs paid on their behalf in the three months ended June 30, 2006 and 2005, respectively. They reimbursed $96,000 and $114,000 in the six months ended June 30, 2006 and 2005, respectively.

• In the three months ended June 30, 2006 and 2005, we distributed $5.0 million and $4.0 million, respectively, to Holly as regular distributions on its subordinated units, common units and general partner interest. We distributed $9.8 million and $7.7 million to Holly in the six months ended June 30, 2006 and 2005, respectively.

• Our net accounts receivable from Holly were $3.3 million and $3.6 million at June 30, 2006 and December 31, 2005, respectively.

• “Deferred revenue” includes $3.5 million and $1.0 million of minimum revenue commitments under the Holly IPA and Holly PTA at June 30, 2006 and December 31, 2005, respectively.

BP plc

We have a 70% ownership interest in Rio Grande. Due to the ownership interest and resulting consolidation, the other partner of Rio Grande – BP plc (“BP”) — is a related party to us.

- 16 -

• BP is the sole customer of Rio Grande, and we recorded revenues from them of $1.6 million for the three months ended June 30, 2006 and 2005, and $4.0 million and $4.6 million for the six months ended June 30, 2006 and 2005, respectively.

• Rio Grande paid distributions to BP of $0.6 million for the three months ended June 30, 2006 and 2005, and $1.2 million and $1.6 million for the six months ended June 30, 2006 and 2005, respectively.

• Included in our accounts receivable – trade at June 30, 2006 and December 31, 2005 were $0.2 million and $0.5 million, respectively, which represented the receivable balance of Rio Grande from BP.

Alon

Alon became a related party when it acquired all of our Class B subordinated units in connection with our acquisition of assets from them on February 28, 2005.

• We recognized $5.6 million and $7.1 million of revenues for pipeline transportation and terminalling services under the Alon PTA and under a pipeline capacity lease in the three months ended June 30, 2006 and 2005, respectively. We recognized $12.4 million and $9.4 million in the six months ended June 30, 2006 and the period from February 28 to June 30, 2005, respectively.

• We paid $0.6 million and $0.5 million to Alon for distributions on our Class B subordinated units in the three months ended June 30, 2006 and 2005, respectively. We paid $1.2 million and $0.5 million in the six months ended June 30, 2006 and the period from February 28 to June 30, 2005, respectively.

• Our net accounts receivable from Alon were $3.4 million at June 30, 2006 and $2.4 million at December 31, 2005.

• “Deferred revenue” includes $1.4 million of minimum revenue commitments under the Alon PTA at June 30, 2006.

Note 11: Partners’ Equity and Cash Distributions

Issuances of units

Upon the closing of our initial public offering on July 13, 2004, Holly received 7,000,000 subordinated units, which constituted 49% ownership of us at that time, and a 2% general partner interest. During the subordination period, the common units have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.50 per quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. The purpose of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units. The subordination period will extend until the first day of any quarter beginning after June 30, 2009 that each of the following tests are met: distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date; the “adjusted operating surplus” (as defined in the partnership agreement) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units during those periods on a fully diluted basis and the related distribution on the 2% general partner interest during those periods; and there are no arrearages in payment of the minimum quarterly distribution on the common units. If the unitholders remove the general partner without cause, the subordination period may end before June 30, 2009.

- 17 -

The Holly subordinated units may convert to common units on a one-for-one basis when certain conditions are met. The partnership agreement sets forth the calculation to be used to determine the amount and priority of cash distributions that the common unitholders, subordinated unitholders and general partner will receive.

As partial consideration in the Alon transaction in the first quarter of 2005, we issued 937,500 of our Class B subordinated units at a fair value of $24.7 million. Additionally, our general partner contributed $0.6 million as an additional capital contribution to maintain its 2% general partner interest.

We financed a portion of the cash consideration paid for the Intermediate Pipelines with $45.1 million of proceeds raised from the private sale of 1,100,000 of our common units to a limited number of institutional investors which closed on July 8, 2005. On September 2, 2005, we filed a registration statement with the SEC using a “shelf” registration process which allows the institutional investors to freely transfer their units. Additionally under this shelf process, we may offer from time to time up to $800 million of our securities, through one or more prospectus supplements that would describe, among other things, the specific amounts, prices and terms of any securities offered and how the proceeds would be used. Any proceeds from the sale of securities would be used for general business purposes, which may include, among other things, funding acquisitions of assets or businesses, working capital, capital expenditures, investments in subsidiaries, the retirement of existing debt and/or the repurchase of common units or other securities.

In connection with the Intermediate Pipelines transaction, we issued 70,000 common units to Holly. We also received a portion of the Intermediate Pipelines assets with $1.0 million book value as a capital contribution from HEP Logistics Holdings, L.P. in order to maintain its 2% general partner interest.

As a result of these transactions, Holly’s total ownership interest was reduced from 51% at the time of our initial public offering to 45% in July 2005 following the Intermediate Pipelines transaction.

Allocations of Net Income

Net income is allocated between limited partners and the general partner interest in accordance with the provisions of the partnership agreement. Net income allocated to the general partner includes any incentive distributions declared in the period. After the amount of incentive distributions is allocated to the general partner, the remaining net income for the period is generally allocated to the partners based on their weighted average ownership percentage during the period.

Cash Distributions

In July 2005, our cash payment to Holly in excess of the basis of the assets received in the acquisition of the Intermediate Pipelines was recorded as a distribution to our general partner in the amount of $71.9 million. See Note 2 for further discussion of this transaction.

We intend to 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 Credit Agreement, occurs or would result from the cash distribution.

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

- 18 -

We will make distributions of available cash from operating surplus for any quarter during any subordination period in the following manner: firstly, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter; secondly, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period; thirdly, 98% to the subordinated unitholders, pro rata, and 2% to the general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and thereafter, cash in excess of the minimum quarterly distributions is distributed to the unitholders and the general partner based on the percentages below.

The 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 shown below:

			Marginal Percentage Interest in
	Total Quarterly Distribution		Distributions
	Target Amount		Unitholders			General Partner
Minimum Quarterly Distribution	$	0.50		98	%		2	%
First Target Distribution	Up to $0.55			98	%		2	%
Second Target Distribution	above $0.55 up to $0.625			85	%		15	%
Third Target Distribution	above $0.625 up to $0.75			75	%		25	%
Thereafter	Above $0.75			50	%		50	%

The following table presents the allocation of our regular quarterly cash distributions to the general and limited partners for each period in which declared.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2006		2005		2006		2005
	(In thousands, except per unit data)
General partner interest	$	210	$	168	$	416	$	310
General partner incentive distribution		264		—		453		—
Total general partner distribution		474		168		869		310
Limited partner distribution		10,309		8,215		20,375		15,216
Total regular quarterly cash distribution	$	10,783	$	8,383	$	21,244	$	15,526
Cash distribution per unit applicable to limited partners	$	0.64	$	0.55	$	1.265	$	1.05

On July 21, 2006, we announced a cash distribution for the second quarter of 2006 of $0.655 per unit. The distribution is payable on all common, subordinated, and general partner units and will be paid August 9, 2006 to all unitholders of record on August 1, 2006. The aggregate amount of the distribution will be $11.1 million, including $0.3 million paid to the general partner as an incentive distribution.

Note 12: 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 Pipeline Company (“Non-Guarantor”), in which we have a 70% ownership interest, is the only subsidiary which 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.

- 19 -

Condensed Consolidating Balance Sheet

				Guarantor		Non-
June 30, 2006	Parent			Subsidiaries		Guarantor			Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	2		$	14,897	$	1,515		$	—		$	16,414
Accounts receivable		—			6,901		246			—			7,147
Intercompany accounts receivable (payable)		(49,418	)		49,827		(409	)		—			—
Prepaid and other current assets		26			1,128		—			—			1,154
Total current assets		(49,390	)		72,753		1,352			—			24,715
Properties and equipment, net		—			126,810		33,728			—			160,538
Investment in subsidiaries		273,993			25,260		—			(299,253	)		—
Transportation agreements, net		—			57,270		1,592			—			58,862
Other assets		1,520			1,139		—			—			2,659
Total assets	$	226,123		$	283,232	$	36,672		$	(299,253	)	$	246,774
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	—		$	3,143	$	275		$	—		$	3,418
Accrued interest		2,924			—		—			—			2,924
Deferred revenue		—			4,929		—			—			4,929
Other current liabilities		647			1,167		311			—			2,125
Total current liabilities		3,571			9,239		586			—			13,396
Long-term debt		178,435			—		—			—			178,435
Other long-term liabilities		3,271			—		—			—			3,271
Minority interest		—			—		—			10,826			10,826
Partners’ equity		40,846			273,993		36,086			(310,079	)		40,846
Total liabilities and partners’ equity	$	226,123		$	283,232	$	36,672		$	(299,253	)	$	246,774

Condensed Consolidating Balance Sheet

				Guarantor		Non-
December 31, 2005	Parent			Subsidiaries		Guarantor			Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	2		$	17,770	$	2,811		$	—		$	20,583
Accounts receivable		—			6,206		515			—			6,721
Intercompany accounts receivable (payable)		(21,182	)		21,458		(276	)		—			—
Prepaid and other current assets		232			1,169		—			—			1,401
Total current assets		(20,948	)		46,603		3,050			—			28,705
Properties and equipment, net		—			128,077		34,221			—			162,298
Investment in subsidiaries		256,416			27,423		—			(283,839	)		—
Transportation agreements, net		—			58,269		2,634			—			60,903
Other assets		1,594			1,275		—			—			2,869
Total assets	$	237,062		$	261,647	$	39,905		$	(283,839	)	$	254,775
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	—		$	2,666	$	354		$	—		$	3,020
Accrued interest		2,892			—		—			—			2,892
Deferred revenue		—			1,013		—			—			1,013
Other current liabilities		594			1,357		375			—			2,326
Total current liabilities		3,486			5,036		729			—			9,251
Long-term debt		180,737			—		—			—			180,737
Other long-term liabilities		779			195		—			—			974
Minority interest		—			—		—			11,753			11,753
Partners’ equity		52,060			256,416		39,176			(295,592	)		52,060
Total liabilities and partners’ equity	$	237,062		$	261,647	$	39,905		$	(283,839	)	$	254,775

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Condensed Consolidating Statement of Income

				Guarantor			Non-
Three months ended June 30, 2006	Parent			Subsidiaries			Guarantor		Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	10,584		$	—	$	—		$	10,584
Third parties		—			6,607			1,637		(301	)		7,943
		—			17,191			1,637		(301	)		18,527
Operating costs and expenses:
Operations		—			7,006			724		(301	)		7,429
Depreciation and amortization		—			2,934			847		—			3,781
General and administrative		777			510			2		—			1,289
		777			10,450			1,573		(301	)		12,499
Operating income (loss)		(777	)		6,741			64		—			6,028
Equity in earnings of subsidiaries		6,788			65			—		(6,853	)		—
Interest income (expense)		(3,013	)		(18	)		29		—			(3,002	)
Minority interest		—			—			—		(28	)		(28	)
Net income	$	2,998		$	6,788		$	93	$	(6,881	)	$	2,998

Condensed Consolidating Statement of Income

				Guarantor			Non-
Three months ended June 30, 2005	Parent			Subsidiaries			Guarantor			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	9,941		$	—		$	—		$	9,941
Third parties		—			8,213			1,646			(279	)		9,580
		—			18,154			1,646			(279	)		19,521
Operating costs and expenses:
Operations		—			5,819			908			(279	)		6,448
Depreciation and amortization		—			3,007			842			—			3,849
General and administrative		465			523			2			—			990
		465			9,349			1,752			(279	)		11,287
Operating income (loss)		(465	)		8,805			(106	)		—			8,234
Equity in earnings of subsidiaries		8,665			(61	)		—			(8,604	)		—
Interest income (expense)		(2,159	)		(79	)		18			—			(2,220	)
Minority interest		—			—			—			27			27
Net income	$	6,041		$	8,665		$	(88	)	$	(8,577	)	$	6,041

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Condensed Consolidating Statement of Income

				Guarantor			Non-
Six months ended June 30, 2006	Parent			Subsidiaries			Guarantor		Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	23,066		$	—	$	—		$	23,066
Third parties		—			14,488			4,006		(595	)		17,899
		—			37,554			4,006		(595	)		40,965
Operating costs and expenses:
Operations		—			13,676			1,457		(595	)		14,538
Depreciation and amortization		—			5,883			1,691		—			7,574
General and administrative		1,489			1,021			3		—			2,513
		1,489			20,580			3,151		(595	)		24,625
Operating income (loss)		(1,489	)		16,974			855		—			16,340
Equity in earnings of subsidiaries		17,577			637			—		(18,214	)		—
Interest income (expense)		(5,955	)		(34	)		55		—			(5,934	)
Minority interest		—			—			—		(273	)		(273	)
Net income	$	10,133		$	17,577		$	910	$	(18,487	)	$	10,133

Condensed Consolidating Statement of Income

				Guarantor			Non-
Six months ended June 30, 2005	Parent			Subsidiaries			Guarantor		Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	19,371		$	—	$	—		$	19,371
Third parties		—			12,314			4,628		(279	)		16,663
		—			31,685			4,628		(279	)		36,034
Operating costs and expenses:
Operations		—			10,515			1,600		(279	)		11,836
Depreciation and amortization		—			4,523			1,689		—			6,212
General and administrative		920			1,032			15		—			1,967
		920			16,070			3,304		(279	)		20,015
Operating income (loss)		(920	)		15,615			1,324		—			16,019
Equity in earnings of subsidiaries		16,233			940			—		(17,173	)		—
Interest income (expense)		(2,946	)		(322	)		18		—			(3,250	)
Minority interest		—			—			—		(402	)		(402	)
Net income	$	12,367		$	16,233		$	1,342	$	(17,575	)	$	12,367

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Condensed Consolidating Statement of Cash Flows

				Guarantor			Non-
Six months ended June 30, 2006	Parent			Subsidiaries			Guarantor			Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities	$	21,756		$	670		$	2,860		$	(2,800	)	$	22,486
Cash flows from investing activities – Additions to properties and equipment		—			(3,543	)		(156	)		—			(3,699	)
Cash flows from financing activities
Contributions from (distributions to) partners		(21,244	)		—			(4,000	)		4,000			(21,244	)
Cash distributions to minority interest		—			—			—			(1,200	)		(1,200	)
Other financing activities, net		(512	)		—			—			—			(512	)
		(21,756	)		—			(4,000	)		2,800			(22,956	)
Cash and cash equivalents
Increase (decrease) for the year		—			(2,873	)		(1,296	)		—			(4,169	)
Beginning of year		2			17,770			2,811			—			20,583
End of year	$	2		$	14,897		$	1,515		$	—		$	16,414

Condensed Consolidating Statement of Cash Flows

				Guarantor			Non-
Six months ended June 30, 2005	Parent			Subsidiaries			Guarantor			Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities	$	(45,611	)	$	65,245		$	3,398		$	(3,780	)	$	19,252
Cash flows from investing activities
Acquisitions of pipeline and terminal assets		(120,000	)		(1,853	)		—			—			(121,853	)
Additions to properties and equipment		—			(710	)		—			—			(710	)
Investments in subsidiaries, net		(1	)		—			—			1			—
Other		—			(211	)		—			—			(211	)
		(120,001	)		(2,774	)		—			1			(122,774	)
Cash flows from financing activities
Proceeds from issuance of senior notes, net of discounts		181,238			—			—			—			181,238
Contributions from (distributions to) partners		(14,914	)		1			(5,400	)		5,399			(14,914	)
Borrowings (paydowns) of debt, net		—			(25,000	)		—			—			(25,000	)
Cash distributions to minority interest		—			—			—			(1,620	)		(1,620	)
Other financing activities, net		(712	)		(264	)		—			—			(976	)
		165,612			(25,263	)		(5,400	)		3,779			138,728
Cash and cash equivalents
Increase (decrease) for the year		—			37,208			(2,002	)		—			35,206
Beginning of year		2			15,143			3,959			—			19,104
End of year	$	2		$	52,351		$	1,957		$	—		$	54,310

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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.

OVERVIEW

Holly Energy Partners, L.P. (“HEP”) is a Delaware limited partnership formed by Holly Corporation (“Holly”) and was initially formed to acquire, own and operate substantially all of the refined product pipeline and terminalling assets that support Holly’s refining and marketing operations in west Texas, New Mexico, Utah and Arizona and a 70% interest in Rio Grande Pipeline Company (“Rio Grande”). HEP commenced operations July 13, 2004 upon the completion of its initial public offering and is currently 45% owned by Holly.

In 2005, we completed two significant acquisitions. On February 28, 2005, we acquired from Alon USA, Inc. and several of its wholly-owned subsidiaries (collectively, “Alon”) four refined products pipelines, an associated tank farm and two refined products terminals located primarily in Texas that serve Alon’s Big Spring, Texas refinery. On July 8, 2005, we acquired Holly’s two 65-mile parallel intermediate feedstock pipelines (the “Intermediate Pipelines”) which connect its Lovington, New Mexico and Artesia, New Mexico refining facilities. Additional information on these transactions can be found under “Liquidity and Capital Resources” below.

We currently operate a system of petroleum product pipelines in Texas, New Mexico and Oklahoma, and distribution terminals in Texas, New Mexico, Arizona, Utah, Idaho, and Washington. We generate revenues by charging tariffs for transporting petroleum products through our pipelines and by charging fees for terminalling refined products and other hydrocarbons, and storing and providing other services at our terminals. We do not take ownership of products that we transport or terminal; therefore, we are not directly exposed to changes in commodity prices.

Our revenues for the six months ended June 30, 2006 were $41.0 million and our net income for the six months ended June 30, 2006 was $10.1 million. Our revenues and net income for the six months ended June 30, 2005 were $36.0 million and $12.4 million, respectively. Our total operating costs and expenses for the six months ended June 30, 2006 were $24.6 million, as compared to $20.0 million for the six months ended June 30, 2005.

Agreements with Holly Corporation

We serve Holly’s refineries in New Mexico and Utah under the 15-year pipelines and terminals agreement with Holly (“Holly PTA”) expiring 2019 and the 15-year Holly Intermediate Pipeline Agreement expiring 2020 (“Holly IPA”). The majority of our business is devoted to providing transportation and terminalling services to Holly. Under the Holly PTA, Holly pays us fees to transport on our refined product pipelines or throughput in our terminals a volume of refined products that will produce a minimum level of revenue. Following the July 1, 2006 producer price index adjustment, the volume commitments by Holly under the Holly PTA will produce at least $37.6 million of revenue in 2006; and the volume commitments under the Holly IPA will produce at least $12.1 million of revenue in 2006. If Holly fails to meet its minimum revenue commitments in any quarter, it is required to pay us in cash the amount of any shortfall by the last day of the month following the end of the quarter. A shortfall payment may be applied as a credit in the following four quarters after Holly’s minimum obligations are met.

In 2006, the Holly PTA was amended to reflect certain rate changes, most significantly a re-negotiation of the tariffs on our refined product pipelines that serve Holly’s Navajo refinery. These new tariffs went into effect as of April 1, 2006, but had little impact on our revenues due to reduced volumes shipped from the refinery during the second quarter 2006.

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Under an omnibus agreement expiring in 2019 that we entered into with Holly in July 2004 (the “Omnibus Agreement”), we have agreed to pay Holly an annual administrative fee, currently in the amount of $2.0 million, for the provision by Holly or its affiliates of various general and administrative services to us for three years following the closing of our initial public offering. This fee does not include the salaries of pipeline and terminal personnel or the cost of their employee benefits, such as 401(k), pension and health insurance benefits, which are separately charged to us by Holly. We also reimburse Holly and its affiliates for direct expenses they incur on our behalf.

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, 2006 and 2005.

	Three Months Ended						Six Months Ended
	June 30						June 30,
	2006			2005			2006			2005
	(In thousands, except per unit data)
Revenues
Pipelines:
Affiliates — refined product pipelines	$	6,374		$	7,121		$	13,697		$	14,189
Affiliates — intermediate pipelines		1,841			—			4,314			—
Third parties		6,821			8,226			15,598			14,498
		15,036			15,347			33,609			28,687
Terminals & truck loading racks:
Affiliates		2,369			2,820			5,055			5,182
Third parties		1,122			1,354			2,301			2,165
		3,491			4,174			7,356			7,347
Total revenues		18,527			19,521			40,965			36,034
Operating costs and expenses
Operations		7,429			6,448			14,538			11,836
Depreciation and amortization		3,781			3,849			7,574			6,212
General and administrative		1,289			990			2,513			1,967
		12,499			11,287			24,625			20,015
Operating income		6,028			8,234			16,340			16,019
Interest income		245			145			488			233
Interest expense, including amortization		(3,247	)		(2,365	)		(6,422	)		(3,483	)
Minority interest in Rio Grande		(28	)		27			(273	)		(402	)
Net income		2,998			6,041			10,133			12,367
Less general partner interest in net income, including incentive distributions(1)		319			121			646			247
Limited partners’ interest in net income	$	2,679		$	5,920		$	9,487		$	12,120
Net income per limited partner unit — basic and diluted(1)	$	0.17		$	0.40		$	0.59		$	0.83
Weighted average limited partners’ units outstanding		16,108			14,938			16,108			14,637
EBITDA(2)	$	9,781		$	12,110		$	23,641		$	21,829
Distributable cash flow(3)	$	10,293		$	10,055		$	21,507		$	18,690

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	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2006		2005		2006		2005
Volumes (bpd)(4)
Pipelines:
Affiliates — refined product pipelines		55,793		64,969		61,151		66,485
Affiliates — intermediate pipelines		44,955		—		52,959		—
Third parties		52,134		75,478		64,666		56,664
		152,882		140,447		178,776		123,149
Terminals & truck loading racks:
Affiliates		107,302		128,827		113,202		122,778
Third parties		41,266		50,380		44,145		39,152
		148,568		179,207		157,347		161,930
Total for pipelines and terminal assets (bpd)		301,450		319,654		336,123		285,079

(1)	Net income is allocated between limited partners and the general partner interest in accordance with the provisions of the partnership agreement. Net income allocated to the general partner includes any incentive distributions declared in the period. Incentive distributions of $0.3 million and $0.5 million were declared during the three and six months ended June 30, 2006, respectively. No incentive distributions were declared during the six months ended June 30, 2005. The net income applicable to the limited partners is divided by the weighted average limited partner units outstanding in computing the net income per unit applicable to limited partners.
(2)	Earnings before interest, taxes, depreciation and amortization (“EBITDA”) is calculated as net income plus (i) interest expense net of interest income and (ii) 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,
	2006			2005			2006			2005
	(In thousands)
Net income	$	2,998		$	6,041		$	10,133		$	12,367
Add interest expense		3,005			2,170			5,938			3,175
Add amortization of discount and deferred debt issuance costs		242			195			484			308
Subtract interest income		(245	)		(145	)		(488	)		(233	)
Add depreciation and amortization		3,781			3,849			7,574			6,212
EBITDA	$	9,781		$	12,110		$	23,641		$	21,829

(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

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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.

Set forth below is our calculation of distributable cash flow.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
	(In thousands)
Net income	$	2,998		$	6,041		$	10,133		$	12,367
Add depreciation and amortization		3,781			3,849			7,574			6,212
Add amortization of discount and deferred debt issuance costs		242			195			484			308
Add increase in deferred revenue		3,432			—			3,916			—
Subtract maintenance capital expenditures*		(160	)		(30	)		(600	)		(197	)
Distributable cash flow	$	10,293		$	10,055		$	21,507		$	18,690

	*	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 amounts reported represent volumes from the initial assets contributed to HEP at inception in July 2004 and additional volumes from the assets acquired from Alon starting in March 2005 and the Intermediate Pipelines acquired from Holly starting in July 2005. The amounts reported in the 2005 periods include volumes on the acquired assets from their respective acquisition dates averaged over the full reported periods.

Balance Sheet Data

	June 30,		December 31,
	2006		2005
	(In thousands)
Cash and cash equivalents	$	16,414	$	20,583
Working capital	$	11,319	$	19,454
Total assets	$	246,774	$	254,775
Long-term debt	$	178,435	$	180,737
Partners’ equity	$	40,846	$	52,060

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Results of Operations — Three Months Ended June 30, 2006 Compared with Three Months Ended June 30, 2005

Summary

Net income was $3.0 million for the three months ended June 30, 2006, a decrease of $3.0 million from $6.0 million for the three months ended June 30, 2005. The decrease in overall earnings was principally due to the reduction in volumes transported by affiliates and third parties on our product pipeline systems, combined with higher interest expense principally related to the senior notes issued in connection with the Intermediate Pipelines acquired from Holly on July 8, 2005, partially offset by the income generated from the Intermediate Pipelines acquired.

Revenues

Revenues were $1.0 million less in the second quarter of 2006 than in the second quarter of 2005. This decrease is principally due to a reduction in volumes shipped on our refined product pipelines and terminalled in our facilities, partially offset by an increase of revenues from the Intermediate Pipelines assets acquired from Holly on July 8, 2005.

All of the refineries utilizing our refined product distribution network, including Holly’s Navajo and Woods Cross refineries and Alon’s Big Spring refinery, were required to produce ultra low sulfur diesel fuel (“ULSD”) by June 2006. To meet this requirement, significant downtime at the refineries was required during the quarter ended June 30, 2006, so that ULSD-associated projects could be brought on line. Additionally, Holly completed an expansion of the Navajo refinery, which required additional unit downtime. The tie-in of these new projects coming on line, combined with other refinery maintenance, much of which was timed in conjunction with the capital projects, resulted in reduced refinery production, which was the principal factor contributing to our significant volume decreases during the quarter.

A substantial majority of our gross revenues are derived from long-term contracts that contain minimum revenue commitments or fixed lease payments designed to protect us during downtimes at refineries we serve with our distribution system. Under these contracts, our major shippers are obligated to make deficiency payments to us if we do not receive certain minimum revenue amounts. The shippers then have the right to recapture these amounts if future revenues exceed certain levels. During the second quarter of 2006, we benefited from approximately $3.4 million of minimum revenue commitments which are not included in net income calculations but are accounted for as deferred revenues. Such amounts will be reflected as revenue when the shippers utilize the services or the contractual period to shippers for such guaranteed payments expires.

Revenues from refined product pipelines decreased by $2.1 million from $15.3 million for the quarter ended June 30, 2005 to $13.2 million for the quarter ended June 30, 2006. Shipments on our refined product pipelines averaged 107.9 thousand barrels per day (“mbpd”) for the three months ended June 30, 2006 as compared to 140.4 mbpd for the three months ended June 30, 2005. The decrease in refined products shipped on our pipelines was due to the reduction in refinery production volumes as discussed above.

Revenues from the Intermediate Pipelines purchased from Holly in July 2005 contributed $1.8 million to revenue in the three months ended June 30, 2006. Shipments on the intermediate product pipelines averaged 45.0 mbpd for the three months ended June 30, 2006. Shipments on the Intermediate Pipelines were also substantially reduced during the three months ended June 30, 2006 primarily due to the capital projects at the Navajo refinery.

Revenues from terminal and truck loading rack service fees decreased by $0.7 million from $4.2 million for the quarter ended June 30, 2005 to $3.5 million for the quarter ended June 30, 2006. Refined products terminalled in our facilities decreased to 148.6 mbpd in the 2006 second quarter from 179.2 mbpd in the 2005 second quarter, due to the reduction in refinery production volumes.

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Operations Expense

Operations expense increased $1.0 million from the second quarter of 2005 to the second quarter of 2006. This increase is principally due to pipeline maintenance performed during the 2006 second quarter. Additionally impacting operations expenses was an increase of $0.3 million of direct operating costs relating to the Intermediate Pipelines acquired in July 2005.

Depreciation and Amortization

Depreciation and amortization for the second quarter of 2006 was not significantly different than the amount reported in the quarter ended June 30, 2005.

General and Administrative

General and administrative costs increased $0.3 million from the second quarter of 2005 to the second quarter of 2006 due mainly to business development costs and equity-based compensation expense.

Interest Expense

Interest expense for the three months ended June 30, 2006 totaled $3.2 million, an increase of $0.8 million from $2.4 million for the three months ended June 30, 2005. The increase is principally due to the debt issued in connection with the Intermediate Pipelines acquisition. In the three months ended June 30, 2006, interest expense consisted of: $2.9 million of interest on our outstanding debt, net of the impact of the interest rate swap; $0.1 million of commitment fees on the unused portion of the credit facility; and $0.2 million of amortization of the discount on the senior notes and deferred debt issuance costs. In the three months ended June 30, 2005, interest expense consisted of: $2.1 million of interest on our then outstanding debt, net of the impact of the interest rate swap; $0.1 million of commitment fees on the unused portion of the credit facility; and $0.2 million of amortization of the discount on the senior notes and deferred debt issuance costs.

Minority Interest in Earnings of Rio Grande

The minority interest related to the 30% of Rio Grande that we do not own did not significantly affect income in the second quarter of 2006 or in the second quarter of 2005.

Results of Operations — Six Months Ended June 30, 2006 Compared with Six Months Ended June 30, 2005

Summary

Net income was $10.1 million for the six months ended June 30, 2006, a decrease of $2.3 million from $12.4 million for the six months ended June 30, 2005. The decrease in overall earnings was principally due to increased interest expense related to the senior notes issued in connection with the Alon and Intermediate Pipelines transactions, combined with reduced revenues from our original pipelines and terminals and from the Rio Grande Pipeline, partially offset by the income generated from the Intermediate Pipelines acquired from Holly on July 8, 2005 and from the pipeline and terminal assets acquired from Alon on February 28, 2005, from which we realized benefits for only four months in the first six months of 2005.

Revenues

Revenues were $5.0 million higher in the six months ended June 30, 2006 as compared to the six months ended June 30, 2005. This increase was principally due to an increase in the revenues from the pipeline and terminal assets acquired from Alon following the February 28, 2005 acquisition, for which we only realized revenues for four months of the first six months of 2005, and revenues from the Intermediate Pipelines assets acquired from Holly on July 8, 2005. Partially offsetting the increased revenues from the Alon and Intermediate Pipelines transactions, as discussed above, refinery production was reduced in the

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second quarter of 2006 at the refineries that utilize our pipelines and terminals systems, which resulted in a significant decrease in our volumes for such period.

Revenues from refined product pipelines increased by $0.6 million from $28.7 million for the six months ended June 30, 2005 to $29.3 million for the six months ended June 30, 2006. Shipments on our refined product pipelines averaged 125.8 mbpd for the six months ended June 30, 2006 as compared to 123.1 mbpd for the six months ended June 30, 2005. The small increase in volumes was due to having a full six months of volumes from the pipelines acquired from Alon, which we realized revenues for only four months of the first six months of 2005, partially offset by the reduction in refinery production volumes in the 2006 second quarter. Additionally impacting revenue in the first six months of 2005, BP Plc (“BP”) completed its obligation to pay the border crossing fee under BP’s Rio Grande Pipeline contract. For the six months ended June 30, 2005, the border crossing fee was $0.9 million.

Revenues from the Intermediate Pipelines purchased from Holly in July 2005 contributed $4.3 million to revenue in the six months ended June 30, 2006. Shipments on the Intermediate Pipelines averaged 53.0 mbpd for the six months ended June 30, 2006.

Revenues from terminal and truck loading rack service fees slightly increased from $7.3 million for the six months ended June 30, 2005 to $7.4 million for the six months ended June 30, 2006. Refined products terminalled in our facilities for the comparable periods decreased to 157.3 mbpd in the first six months of 2006 from 161.9 mbpd in the first six months of 2005, however such volume decrease was offset by increases in terminalling rates charged. The decrease in volumes was due to the reduction in refinery production volumes in the 2006 second quarter, partially offset by having a full six months of volumes from the terminals acquired from Alon, for which we realized revenues in only four months of the first six months of 2005.

Operations Expense

Operations expense increased $2.7 million from the first six months of 2005 to the first six months of 2006. This increase in expense was principally due to $1.8 million of increased direct operating costs relating to the assets acquired from Alon and direct operating costs of $0.6 million for the Intermediate Pipelines that were acquired in July 2005. Additionally impacting operations expense were other period-over-period increases in pipeline maintenance performed during the 2006 second quarter.

Depreciation and Amortization

Depreciation and amortization was $1.4 million higher in the six months ended June 30, 2006 than in the six months ended June 30, 2005, due principally to the depreciation and amortization on the assets acquired from Alon.

General and Administrative

General and administrative costs increased $0.5 million from the first six months of 2005 to the first six months of 2006 due mainly to business development costs and equity-based compensation expense.

Interest Expense

Interest expense for the six months ended June 30, 2006 totaled $6.4 million, an increase of $2.9 million from $3.5 million for the six months ended June 30, 2005. The increase is due to the debt issued in connection with the Alon and Intermediate Pipelines acquisitions. In the six months ended June 30, 2006, interest expense consisted of: $5.7 million of interest on our outstanding debt, net of the impact of the interest rate swap; $0.2 million of commitment fees on the unused portion of the credit facility; and $0.5 million of amortization of the discount on the senior notes and deferred debt issuance costs. In the six months ended June 30, 2005, interest expense consisted of: $3.0 million of interest on our then outstanding debt, net of the impact of the interest rate swap; $0.2 million of commitment fees on the unused portion of the credit facility; and $0.3 million of amortization of the discount on the senior notes and deferred debt issuance costs.

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Minority Interest in Earnings of Rio Grande

The minority interest related to the 30% of Rio Grande that we do not own reduced our income in the first six months of 2006 by $0.3 million as compared to $0.4 million in the first six months of 2005.

LIQUIDITY AND CAPITAL RESOURCES

Overview

In conjunction with our initial public offering on July 13, 2004, we entered into a four-year, $100 million senior secured revolving credit agreement (the “Credit Agreement”). During 2005, amendments were made to the Credit Agreement to allow for the closing of the Alon transaction and the related senior notes offering, the closing of the Holly Intermediate Pipelines transaction and to amend certain of the restrictive covenants. As of June 30, 2006, we had no amounts outstanding under the Credit Agreement. The Credit Agreement is available to fund capital expenditures, acquisitions, and working capital and for general partnership purposes.

We financed the $120 million cash portion of the consideration for the Alon transaction through our private offering on February 28, 2005 of $150 million of 6.25% senior notes due 2015 (“Senior Notes”). We used the balance to repay $30 million of outstanding indebtedness under our Credit Agreement, including $5 million drawn shortly before the closing of the Alon transaction. We financed a portion of the cash consideration for the Intermediate Pipelines transaction with the private offering in June 2005 of an additional $35 million in principal amount of the Senior Notes.

On July 28, 2005, we filed a registration statement to allow the holders of the Senior Notes to exchange the Senior Notes for exchange notes registered with the SEC with substantially identical terms, which exchange was completed in October 2005. Additionally under this shelf process, we may offer from time to time up to $800 million of our securities, through one or more prospectus supplements that would describe, among other things, the specific amounts, prices and terms of any securities offered and how the proceeds would be used. Any proceeds from the sale of securities would be used for general business purposes, which may include, among other things, funding acquisitions of assets or businesses, working capital, capital expenditures, investments in subsidiaries, the retirement of existing debt and/or the repurchase of common units or other securities.

We believe our current cash balances, future internally-generated funds and funds available under our Credit Agreement will provide sufficient resources to meet our working capital liquidity needs for the foreseeable future. In February and May 2006, we paid regular cash distributions of $0.625 and $0.64, respectively, on all units, an aggregate amount of $21.2 million. Included in these distributions was an aggregate of $0.5 million paid to the general partner as incentive distributions, as the distributions per unit exceeded $0.55.

Cash and cash equivalents decreased by $4.2 million during the six months ended June 30, 2006. The cash flows used for financing activities of $23.0 million, in addition to cash flows used for investing activities of $3.7 million, exceeded cash flows generated from operating activities of $22.5 million. Working capital decreased during the quarter by $8.1 million to $11.3 million at June 30, 2006.

Cash Flows — Operating Activities

Cash flows from operating activities increased by $3.2 million from $19.3 million for the six months ended June 30, 2005 to $22.5 million for the six months ended June 30, 2006. This increase is mainly due to $11.8 million additional cash collections from customers on the Alon assets and Intermediate Pipelines purchased in 2005. This increase of cash collections is partially offset by increased operations expense of $2.4 million on these new assets and increased cash payments for interest of $6.8 million, principally on the debt issued for these acquisitions. The remaining increase in cash flows from operating activities is due to lower pre-payments in 2006 and to miscellaneous year-over-year changes in collections and payments.

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Cash Flows — Investing Activities

Cash flows used for investing activities decreased by $119.1 million from $122.8 million for the first six months of 2005 to $3.7 million for first six months of 2006. On February 28, 2005, we closed on the Alon transaction which required $120.0 million in cash plus transaction costs of $2.0 million. Additionally, we issued 937,500 Class B subordinated units valued at $24.7 million to Alon as part of the consideration. See “Alon Transaction” below for additional information. Additions to properties and equipment for the six months ended June 30, 2006 was $3.7 million, an increase of $3.0 million from $0.7 million for the six months ended June 30, 2005.

Cash Flows — Financing Activities

Cash flows used for financing activities amounted to $23.0 million for the six months ended June 30, 2006. This compared to cash flows provided by financing activities of $138.7 million in the six months ended June 30, 2005. In February 2005, we received proceeds of $147.4 million from the issuance of Senior Notes in connection with the Alon asset acquisition. Additionally, we used proceeds from the original Senior Notes offering to repay $30.0 million of outstanding indebtedness under our Credit Agreement, including $5.0 million drawn shortly before the closing of the Alon transaction. In June 2005, in anticipation of the July Intermediate Pipelines transaction, we received additional proceeds from Senior Notes issued of $33.8 million. See “Senior Notes Due 2015” below for additional information. In the first six months of 2006, we paid cash distributions on all units and the general partner interest in the aggregate amount of $21.2 million, an increase of $5.7 million from $15.5 million in distributions paid in the first six months of 2005. Distributions to the minority interest owner in Rio Grande were $1.2 million for the six months ended June 30, 2006, a decrease of $0.4 million from $1.6 million for the six months ended June 30, 2005. Other cash flows from financing activities during the six months ended June 30, 2005 included an additional capital contribution from our general partner of $0.6 million and deferred debt issuance costs incurred of $1.0 million.

Capital Requirements

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

Each year our general partner’s board of directors approves capital projects that our management is authorized to undertake in our annual capital budget. 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 of years, 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. Our total approved capital budget for 2006 is $8.8 million, which does not include amounts for possible acquisition transactions.

We anticipate that the currently budgeted capital expenditures will be funded with existing cash balances and cash generated by operations. However, we may fund future expansion capital requirements or acquisitions through long-term debt and/or equity capital offerings.

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Credit Agreement

In conjunction with our initial public offering on July 13, 2004, we entered into a four-year, $100 million senior secured revolving Credit Agreement. Union Bank of California, N.A. is a lender and serves as administrative agent under this agreement. Upon closing of our initial public offering, we drew $25 million under the Credit Agreement, which was outstanding at December 31, 2004.

We amended the Credit Agreement effective February 28, 2005 to allow for the closing of the Alon transaction and the related Senior Notes offering as well as to amend certain of the restrictive covenants. With a portion of the proceeds from the Senior Notes offering, we repaid $30 million of outstanding indebtedness under the Credit Agreement, including $5 million drawn shortly before the closing of the Alon transaction. As of June 17, 2005, we amended the Credit Agreement to restate the definition of certain terms used in the restrictive covenants. Additionally, we amended the Credit Agreement effective July 8, 2005 to allow for the closing of the Holly Intermediate Pipelines transaction as well as to amend certain of the restrictive covenants. As of June 30, 2006, we had no amounts outstanding under the Credit Agreement.

The Credit Agreement is available to fund capital expenditures, acquisitions, and working capital and for general partnership purposes. Advances under the Credit Agreement that are designated for working capital are short-term liabilities. Other advances under the Credit Agreement are classified as long-term liabilities. In addition, the Credit Agreement is available to fund letters of credit up to a $50 million sub-limit. Up to $5 million is available to fund distributions to unitholders.

We have the right to request an increase in the maximum amount of the Credit Agreement, up to $175 million. Such request will become effective if (a) certain conditions specified in the Credit Agreement are met and (b) existing lenders under the Credit Agreement or other financial institutions reasonably acceptable to the administrative agent commit to lend such increased amounts under the agreement.

Our obligations under the Credit Agreement are secured by substantially all of our assets. Indebtedness under the Credit Agreement is recourse to our general partner and guaranteed by our wholly-owned subsidiaries.

We may prepay all loans at any time without penalty. We are required to reduce all working capital borrowings under the Credit Agreement to zero for a period of at least 15 consecutive days once each twelve-month period prior to the maturity date of the agreement.

Indebtedness under the Credit Agreement bears interest, at our option, at either (a) the base rate as announced by the administrative agent plus an applicable margin (ranging from 0.25% to 1.00%) or (b) at a rate equal to the London Interbank Offered Rate (“LIBOR”) plus an applicable margin (ranging from 1.50% to 2.25%). 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 Credit Agreement). We incur a commitment fee on the unused portion of the Credit Agreement at a rate of 0.375% or 0.500% based upon the ratio of our funded debt to EBITDA for the four most recently completed fiscal quarters. At June 30, 2006, we are subject to the 0.500% rate on the $100 million of the unused commitment on the Credit Agreement. The agreement matures in July 2008. At that time, the agreement will terminate and all outstanding amounts thereunder will be due and payable.

The Credit Agreement imposes certain requirements, 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 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.

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Senior Notes Due 2015

We financed the $120 million cash portion of the consideration for the Alon transaction through our private offering on February 28, 2005 of $150 million principal amount of 6.25% Senior Notes due 2015. We used the balance to repay $30 million of outstanding indebtedness under our Credit Agreement, including $5 million drawn shortly before the closing of the Alon transaction. We financed a portion of the cash consideration for the Intermediate Pipelines transaction with the private offering in June 2005 of an additional $35 million in principal amount of the Senior Notes.

The Senior Notes mature on March 1, 2015 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.

The $185.0 million principal amount of Senior Notes is recorded at $178.4 million on our accompanying consolidated balance sheet at June 30, 2006. The difference is due to the $3.3 million unamortized discount and $3.3 million relating to the fair value of the interest rate swap contract discussed below.

Alon Transaction

The total consideration paid for the Alon pipeline and terminal assets was $120.0 million in cash and 937,500 of our Class B subordinated units which, subject to certain conditions, will convert into an equal number of common units in five years. We financed the cash portion of the Alon transaction through our private offering of the $150 million Senior Notes. We used the proceeds of the offering to fund the $120 million cash portion of the consideration for the Alon transaction, and used the balance to repay $30 million of outstanding indebtedness under our Credit Agreement, including $5 million drawn shortly before the closing of the Alon transaction. In connection with the Alon transaction, we entered into the 15-year Alon PTA. Under the 15-year Alon PTA, Alon agreed to transport on the pipelines and throughput through the terminals a volume of refined products that would result in minimum revenue levels each year that will change annually based on changes in the Producer’s Price Index (the “PPI”), but will not decrease below the initial $20.2 million annual amount. The total commitment for 2006, after the March 1, 2006 PPI adjustment, is $20.5 million.

The consideration for the Alon pipeline and terminal assets was allocated to the individual assets acquired based on their estimated fair values as determined by an independent appraisal. The aggregate consideration amounted to $146.7 million, which consisted of $24.7 million fair value of our Class B subordinated units, $120.0 million in cash and $2.0 million of transaction costs. In accounting for this acquisition, we recorded pipeline and terminal assets of $86.7 million and an intangible asset of $60.0 million, representing the value of the 15-year pipelines and terminals agreement for transportation.

Holly Intermediate Pipelines Transaction

On July 6, 2005, we entered into the Purchase Agreement with Holly to acquire Holly’s two 65-mile parallel Intermediate Pipelines which connect its Lovington, New Mexico and Artesia, New Mexico refining facilities. On July 8, 2005, we closed on the acquisition for $81.5 million, which consisted of $77.7 million in cash, 70,000 common units of HEP and a capital account credit of $1.0 million to maintain Holly’s existing general partner interest in the Partnership. We financed the cash portion of the consideration for the Intermediate Pipelines with the proceeds raised from (a) the private sale of 1,100,000 of our common units for $45.1 million to a limited number of institutional investors which closed simultaneously with the acquisition and (b) an additional $35.0 million in principal amount of our 6.25% Senior Notes due 2015. This acquisition was made pursuant to an option to purchase these pipelines granted by Holly to us at the time of our initial public offering in July 2004.

In connection with this transaction, we entered into a 15-year pipelines agreement with Holly. Under this agreement, Holly agreed to transport volumes of intermediate products on the Intermediate Pipelines that,

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at the agreed tariff rates, will result in minimum revenues to us of $11.8 million in the initial contract year. The total commitment for 2006, after the July 1, 2006 PPI adjustment, is $12.1 million.

As this transaction is among entities under common control, we recorded the acquired assets at Holly’s historic book value of $6.8 million. This resulted in payment to Holly of a purchase price of $71.9 million in excess of the basis of the assets received and a $71.9 million reduction of our net partners’ equity.

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, 2006 and 2005.

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 2.5% 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 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.

We inspect our pipelines regularly using equipment rented from third-party suppliers. Third parties also assist us in interpreting the results of the inspections.

Holly has agreed to indemnify us in an aggregate amount not to exceed $15 million for ten years after the closing of our initial public offering on July 13, 2004 for environmental noncompliance and remediation liabilities associated with the assets initially transferred to us and occurring or existing before that date, and provide $2.5 million of additional indemnification for the Intermediate Pipelines acquired in July 2005. Additionally, we entered into an environmental agreement with Alon with respect to pre-closing environmental costs and liabilities relating to the pipelines and terminals acquired from Alon in February 2005, where Alon will indemnify us for ten years subject to a $100,000 deductible and a $20 million maximum liability cap.

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

An environmental remediation project is in progress currently at our El Paso terminal, the remaining costs of which are projected to be approximately $1.3 million over the next five years. Other parties are

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undertaking remediation projects at our Boise, Burley and Albuquerque terminals, and we are obligated to pay a portion of these costs at the Albuquerque terminal, but not at the Boise or Burley terminals. The estimated cost for our share of the environmental remediation at the Albuquerque terminal is approximately $0.2 million, to be incurred over the next five years. A remediation project is also under way in New Mexico for a leak on our refined product pipeline from Artesia, New Mexico to Orla, Texas. At June 30, 2006, we estimate the remaining cost on this project to be $0.2 million, half of which will be incurred within the next year. Holly has agreed, subject to a $15 million limit, to indemnify us for environmental liabilities related to the assets transferred to us to the extent such liabilities exist or arise from operation of these assets prior to the closing of our initial public offering on July 13, 2004 and are asserted within 10 years after that date. The Holly indemnification will cover the costs associated with the three remediation projects mentioned above, including assessment, monitoring, and remediation programs.

In the fourth quarter of 2005, we experienced a refined product release in Jones County, Texas on one of the pipelines recently acquired from Alon. This event is not subject to indemnification from Alon. As of June 30, 2006, we estimate that the total remaining remediation cost for this incident to be insignificant.

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

CRITICAL ACCOUNTING POLICIES

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

Our significant accounting policies are described in “Item 7. Management’s Discussion and Analysis of Financial Conditions and Operations — Critical Accounting Policies” in our Annual Report on Form 10-K for the year ended December 31, 2005. 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 2006.

RISK MANAGEMENT

We have entered into an interest rate swap contract to effectively convert the interest expense associated with $60 million of our 6.25% Senior Notes from a fixed rate to variable rates. Under the swap agreement, we receive 6.25% fixed rate on the notional amount and pay a variable rate equal to three month LIBOR plus an applicable margin of 1.1575%. The variable rate being paid on the notional amount at June 30, 2006 was 6.39%, including the applicable margin. The maturity of the swap contract is March 1, 2015, matching the maturity of the Senior Notes.

This interest rate swap has been designated as a fair value hedge as defined by SFAS No. 133. Our interest rate swap meets the conditions required to assume no ineffectiveness under SFAS No. 133 and, therefore, we have used the “shortcut” method of accounting prescribed for fair value hedges by SFAS No. 133. Accordingly, we adjust the carrying value of the swap to its fair value each quarter, with an offsetting entry to adjust the carrying value of the debt securities whose fair value is being hedged. We record interest expense equal to the variable rate payments under the swaps.

The fair value of the interest rate swap agreement of $3.3 million is included in “Other long-term liabilities” in our accompanying consolidated balance sheet at June 30, 2006. The offsetting entry to adjust the carrying value of the debt securities whose fair value is being hedged is recognized as a reduction of “Long-term debt” on our accompanying consolidated balance sheet at June 30, 2006.

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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.

At June 30, 2006, we had an outstanding principal balance on our unsecured Senior Notes of $185.0 million. By means of our interest rate swap contract, we have effectively converted $60.0 million of the Senior Notes from a fixed rate to variable rate. For the fixed rate debt portion of $125.0 million, changes in interest rates would generally affect the fair value of the debt, but not our earnings or cash flows. Conversely, for the variable rate debt portion of $60.0 million, changes in interest rates would generally not impact the fair value of the debt, but may affect our future earnings and cash flows. We estimate a hypothetical 10% change in the yield-to-maturity applicable to our fixed rate debt portion of $125.0 million as of June 30, 2006 would result in a change of approximately $5.5 million in the fair value of the debt. A hypothetical 10% change in the interest rate applicable to our variable rate debt portion of $60.0 million would not have a material effect on our earnings or cash flows.

At June 30, 2006, 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.

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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 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 2. Unregistered sales of securities and use of proceeds

(c) Common unit repurchases made in the quarter

On February 16, 2006, we granted restricted units to selected officers and other employees. In June 2006, we funded the purchase of 12,461 common units in the open market for these recipients. These units will vest no later than January 1, 2009.

							Maximum Number
					Total Number of		of Units that May
					Units Purchased		Yet Be Purchased
	Total Number of				as Part of Publicly		Under a Publicly
	Units		Average Price		Announced Plan		Announced Plan
Period	Purchased		Paid Per Unit		or Program		or Program
April 2006		—	$	—		—		—
May 2006		—	$	—		—		—
June 2006		12,461	$	41.05		—		—
Total for April to June 2006		12,461				—

Item 6. Exhibits

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.

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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 28, 2006	/s/ P. Dean Ridenour
	P. Dean Ridenour
	Vice President and Chief Accounting Officer
	and Director
	(Principal Accounting Officer)
	/s/ Stephen J. McDonnell
	Stephen J. McDonnell
	Vice President and Chief Financial
	Officer
	(Principal Financial Officer)

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