Holly Energy Partners (HEP) 10-Q 2007 Q3 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 endedSeptember 30, 2007

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 October 26, 2007 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, 2006 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	39
Item 4. Controls and Procedures	39
PART II. OTHER INFORMATION	40
Item 1. Legal Proceedings	40
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	40
Item 6. Exhibits	40
SIGNATURES	41
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

- 2 -

PART I. FINANCIAL INFORMATION

FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains certain “forward-looking statements” within the meaning of the federal securities laws. All statements, other than statements of historical fact included in this Form 10-Q, including, but not limited to, those under “Results of Operations” and “Liquidity and Capital Resources” in Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part I are forward-looking statements. These statements are based on management’s beliefs and assumptions using currently available information and expectations as of the date hereof, are not guarantees of future performance, and involve certain risks and uncertainties. Although we believe that the expectations reflected in these forward-looking statements are reasonable, we cannot assure you that our expectations will prove correct. Therefore, actual outcomes and results could differ materially from what is expressed, implied or forecast in these statements. Any differences could be caused by a number of factors, including, but not limited to:

• Risks and uncertainties with respect to the actual quantities of petroleum products shipped on our pipelines and/or terminalled in our terminals;

• The economic viability of Holly Corporation, Alon USA, Inc. and our other customers;

• The demand for refined petroleum products in markets we serve;

• Our ability to successfully purchase and integrate additional operations in the future;

• Our ability to complete previously announced pending or contemplated acquisitions;

• The availability and cost of 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, 2006 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.

- 3 -

Item 1.Financial Statements

Holly Energy Partners, L.P.

Consolidated Balance Sheets

	September 30,
	2007			December 31,
	(Unaudited)			2006
	(In thousands, except unit data)
ASSETS
Current assets:
Cash and cash equivalents	$	8,710		$	11,555
Accounts receivable:
Trade		4,617			7,339
Affiliates		6,129			3,518
		10,746			10,857
Prepaid and other current assets		773			1,212
Total current assets		20,229			23,624
Properties and equipment, net		154,770			160,484
Transportation agreements, net		54,773			56,821
Other assets		2,619			2,644
Total assets	$	232,391		$	243,573
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	2,191		$	3,781
Accrued interest		964			2,941
Deferred revenue		4,616			5,486
Accrued property taxes		936			868
Other current liabilities		887			1,098
Total current liabilities		9,594			14,174
Commitments and contingencies		—			—
Long-term debt		181,347			180,660
Other long-term liabilities		1,168			1,550
Minority interest		10,486			10,963
Partners’ equity (deficit):
Common unitholders (8,170,000 units issued and outstanding)		173,654			176,844
Subordinated unitholders (7,000,000 units issued and outstanding)		(72,765	)		(70,022	)
Class B subordinated unitholders (937,500 units issued and outstanding)		23,101			23,469
General partner interest (2% interest)		(94,194	)		(94,065	)
Total partners’ equity		29,796			36,226
Total liabilities and partners’ equity	$	232,391		$	243,573

See accompanying notes.

- 4 -

Holly Energy Partners, L.P.

Consolidated Statements of Income
(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
				(In thousands, except per unit data)
Revenues:
Affiliates	$	14,827		$	14,272		$	44,942		$	37,338
Third parties		9,638			8,627			30,526			26,526
		24,465			22,899			75,468			63,864
Affiliates - other		2,748			—			2,748			—
		27,213			22,899			78,216			63,864
Operating costs and expenses:
Operations		7,985			7,082			24,025			21,620
Depreciation and amortization		3,594			3,839			10,873			11,413
General and administrative		1,429			1,177			3,991			3,690
		13,008			12,098			38,889			36,723
Operating income		14,205			10,801			39,327			27,141
Other income (expense):
Interest income		101			214			431			702
Interest expense		(3,383	)		(3,302	)		(10,112	)		(9,724	)
Gain on sale of assets		—			—			298			—
		(3,282	)		(3,088	)		(9,383	)		(9,022	)
Income before minority interest		10,923			7,713			29,944			18,119
Minority interest in Rio Grande Pipeline Company		(233	)		38			(814	)		(235	)
Net income		10,690			7,751			29,130			17,884
Less general partner interest in net income		794			488			2,100			1,134
Limited partners’ interest in net income	$	9,896		$	7,263		$	27,030		$	16,750
Net income per limited partner unit - basic and diluted	$	0.61		$	0.45		$	1.68		$	1.04
Weighted average limited partners’ units outstanding		16,108			16,108			16,108			16,108

See accompanying notes.

- 5 -

Holly Energy Partners, L.P.

Consolidated Statements of Cash Flows
(Unaudited)

	Nine Months Ended September 30,
	2007			2006
	(In thousands)
Cash flows from operating activities
Net income	$	29,130		$	17,884
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		10,873			11,413
Minority interest in Rio Grande Pipeline Company		814			235
Amortization of restricted and performance units		1,087			646
Gain on sale of assets		(298	)		—
(Increase) decrease in current assets:
Accounts receivable – trade		2,722			(1,583	)
Accounts receivable – affiliates		(2,611	)		1,359
Prepaid and other current assets		439			(317	)
Increase (decrease) in current liabilities:
Accounts payable		(1,590	)		931
Accrued interest		(1,977	)		(1,922	)
Deferred revenue		(870	)		3,682
Accrued property tax		68			260
Other current liabilities		(211	)		254
Other, net		551			258
Net cash provided by operating activities		38,127			33,100
Cash flows from investing activities
Additions to properties and equipment		(3,119	)		(6,941	)
Proceeds from sale of assets		325			—
Net cash used for investing activities		(2,794	)		(6,941	)
Cash flows from financing activities
Distributions to partners		(35,565	)		(32,350	)
Purchase of units for restricted grants		(1,082	)		(634	)
Cash distributions to minority interest		(1,290	)		(1,350	)
Deferred financing costs		(225	)		—
Other		(16	)		—
Net cash used for financing activities		(38,178	)		(34,334	)
Cash and cash equivalents
Decrease for period		(2,845	)		(8,175	)
Beginning of period		11,555			20,583
End of period	$	8,710		$	12,408

See accompanying notes.

- 6 -

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, 2006	$	176,844		$	(70,022	)	$	23,469		$	(94,065	)	$	36,226
Distributions to partners		(16,905	)		(14,490	)		(1,941	)		(2,229	)		(35,565	)
Purchase of units for restricted grants		(1,082	)		—			—			—			(1,082	)
Amortization of restricted and performance units		1,087			—			—			—			1,087
Net income		13,710			11,747			1,573			2,100			29,130
Balance September 30, 2007	$	173,654		$	(72,765	)	$	23,101		$	(94,194	)	$	29,796

See accompanying notes.

- 7 -

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 and its subsidiaries (collectively “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. 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 nine months ended September 30, 2007 and 2006 included herein have been prepared without audit, pursuant to the rules and regulations of the United States Securities and Exchange Commission (the “SEC”). The interim financial statements reflect all adjustments, which, in the opinion of management, are necessary for a fair presentation of our results for the interim periods. Such adjustments are considered to be of a normal recurring nature. Although certain notes and other information required by accounting principles generally accepted in the United States of America have been condensed or omitted, we believe that the disclosures in these consolidated financial statements are adequate to make the information presented not misleading. These consolidated financial statements should be read in conjunction with our Form 10-K for the year ended December 31, 2006. Results of operations for interim periods are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2007. Certain reclassifications have been made to prior reported amounts to conform to current classifications.

Recent Accounting Pronouncements

Interpretation No. 48 “Accounting for Uncertainty in Income Taxes”
In June 2006, the Financial Accounting Standards Board (“FASB”) issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes. This interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements by prescribing a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This interpretation also provides guidance on

- 8 -

derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. We adopted this standard effective January 1, 2007. The adoption of this standard did not have a material impact on our financial condition, results of operations and cash flows.

Note 2: Properties and Equipment

	September 30,		December 31,
	2007		2006
	(In thousands)
Pipelines and terminals	$	196,452	$	195,688
Land and right of way		22,825		22,486
Other		5,315		5,267
Construction in progress		3,910		1,539
		228,502		224,980
Less accumulated depreciation		73,732		64,496
	$	154,770	$	160,484

During the three and nine months ended September 30, 2007 and 2006, we did not capitalize any interest related to major construction projects.

Note 3: Transportation Agreements

Our transportation agreements consist of the following:

• The Rio Grande transportation agreement represents 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 (“BP”). The initial 10-year term of this agreement expired in April 2007 and was extended for an additional year. This agreement will continue on a year-to-year basis unless cancelled by either party prior to the end of the previous contract year. The carrying amount of this asset was fully amortized and retired in April 2007.

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

The carrying amounts of our transportation agreements are as follows:

	September 30,		December 31,
	2007		2006
	(In thousands)
Rio Grande transportation agreement	$	—	$	20,836
Alon transportation agreement		59,933		59,933
		59,933		80,769
Less accumulated amortization		5,160		23,948
	$	54,773	$	56,821

Note 4: Debt

Credit Agreement

In August 2007, we entered into an amended and restated four-year, $100.0 million senior secured revolving credit agreement expiring in August 2011 (the “Credit Agreement”) that amends and restates our previous senior credit agreement in its entirety. Union Bank of California, N.A. is one of the lenders and serves as administrative agent under this agreement. As of September 30, 2007 and December 31, 2006, we had no amounts outstanding under the Credit Agreement.

- 9 -

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 $50.0 million sub-limit. Up to $20.0 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 $200.0 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 HEP Logistics Holdings, L.P., our general partner, and guaranteed by our wholly-owned subsidiaries.

We may prepay all loans at any time without penalty, except for payment of certain breakage and related costs. We are required to reduce all working capital borrowings under the Credit Agreement to zero for a period of at least 15 consecutive days 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 reference rate as announced by the administrative agent plus an applicable margin (ranging from 0.25% to 1.50%) or (b) at a rate equal to the London Interbank Offered Rate (“LIBOR”) plus an applicable margin (ranging from 1.00% to 2.50%). In each case, the applicable margin is based upon the ratio of our funded debt (as defined in the agreement) to EBITDA (earnings before interest, taxes, depreciation and amortization, as defined in the Credit Agreement). We incur a commitment fee on the unused portion of the Credit Agreement at a rate ranging from 0.20% to 0.50% based upon the ratio of our funded debt to EBITDA for the four most recently completed fiscal quarters. At September 30, 2007, we are subject to the 0.25% rate on the $100.0 million of the unused commitment on the Credit Agreement. The agreement matures in August 2011. At that time, the agreement will terminate and all outstanding amounts thereunder will be due and payable.

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

Senior Notes Due 2015

Our senior notes maturing March 1, 2015 are registered with the SEC and bear interest at 6.25% (“Senior Notes”). The Senior Notes are unsecured and impose certain restrictive covenants, including limitations on our ability to incur additional indebtedness, make investments, sell assets, incur certain liens, pay distributions, enter into transactions with affiliates, and enter into mergers. 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 $181.3 million on our consolidated balance sheets at September 30, 2007. The difference of $3.7 million is due to $2.9 million of unamortized discount and $0.8 million relating to the fair value of the interest rate swap contract discussed below.

- 10 -

Interest Rate Risk Management

We have entered into an interest rate swap contract to effectively convert the interest expense associated with $60.0 million of our 6.25% Senior Notes from a fixed rate to a variable rate. The interest rate on the $60.0 million notional amount is equal to three-month LIBOR plus an applicable margin of 1.1575%, which equaled an effective interest rate of 6.62% on $60.0 million of the debt during the nine months ended September 30, 2007. 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 Statement of Financial Accounting Standard (“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 swap.

The fair value of our interest rate swap of $0.8 million and $1.2 million is included in “Other long-term liabilities” in our consolidated balance sheets at September 30, 2007 and December 31, 2006, 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 September 30, 2007 and December 31, 2006.

Other Debt Information

	Nine Months Ended
	September 30,
	2007		2006
	(In thousands)
Interest on outstanding debt:
Senior Notes, net of interest rate swap	$	8,839	$	8,622
Amortization of discount and deferred issuance costs		917		726
Commitment fees		356		376
Net interest expense	$	10,112	$	9,724
Cash paid for interest(1)	$	11,300	$	10,792

(1) Net of cash received under our interest rate swap agreement of $3.8 million for the nine months ended September 30, 2007 and 2006.

The estimated fair value of our Senior Notes was $172.1 million at September 30, 2007.

Note 5: 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 under certain provisions of an 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 $0.2 million and $0.4 million for the three months ended September 30, 2007 and 2006, respectively, and $1.0 million and $0.9 million for the nine months ended September 30, 2007 and 2006, respectively.

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

- 11 -

On September 30, 2007, we had two types of equity-based compensation, which are described below. The compensation cost charged against income for these plans was $0.3 million and $0.2 million for the three months ended September 30, 2007 and 2006, respectively, and $1.0 million and $0.6 million for the nine months ended September 30, 2007 and 2006, 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 September 30, 2007, 350,000 units were authorized to be granted under the equity-based compensation plans, of which 250,974 had not yet been granted.

Restricted Units

Under our Long-Term Incentive Plan, we grant restricted units to selected employees, consultants and non-employee directors who perform services for us, with vesting generally over a period of one to five years. Although full ownership of the units does not transfer to the recipients until the units vest, the recipients have distribution and voting rights on these units from the date of grant. The vesting for certain key executives is contingent upon certain earnings per unit targets being realized. The fair value of each 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 September 30, 2007, and changes during the nine months ended September 30, 2007, is presented below:

						Weighted-
				Weighted-		Average	Aggregate
				Average		Remaining	Intrinsic
				Grant-Date		Contractual	Value
Restricted Units	Grants			Fair Value		Term	($000)
Outstanding January 1, 2007 (not vested)		36,597		$	40.21
Granted		23,523			47.10
Forfeited		(1,555	)		44.32
Vesting and transfer of full ownership to recipients		(13,869	)		36.90
Outstanding at September 30, 2007 (not vested)		44,696		$	44.77	0.9 years	$	2,058

There were 13,869 units vested and transferred to recipients during the nine months ended September 30, 2007. As of September 30, 2007, there was $1.0 million of total unrecognized compensation costs related to nonvested restricted unit grants. That cost is expected to be recognized over a weighted-average period of 0.9 years.

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 the initial performance grant of 1,514 units in 2005 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. The amount payable under all other performance unit grants is based upon the growth in distributions per limited partner unit during the requisite period.

We granted 12,321 performance units to certain officers in February 2007. These units will vest over a three-year performance period ending December 31, 2009, and are payable in HEP common units. The number of units actually earned will be based on the growth of distributions to limited partners over the performance period, and can range from 50% to 150% of the number of performance units issued. The fair value of these performance units is based on the grant date closing unit price of $46.12 and will apply to the number of units ultimately awarded.

- 12 -

A summary of performance units activity as of September 30, 2007 and changes during the nine months ended September 30, 2007 is presented below:

	Payable
Performance Units	In Units
Outstanding at January 1, 2007 (not vested)		14,015
Vesting and payment of cash benefit to recipients		—
Granted		12,321
Forfeited		(2,188	)
Outstanding at September 30, 2007 (not vested)		24,148

There were no payments for performance units vesting during the nine months ended September 30, 2007. Based on the weighted average fair value at September 30, 2007 of $53.35, there was $0.6 million of total unrecognized compensation cost related to nonvested performance units. That cost is expected to be recognized over a weighted-average period of 1.7 years.

Note 6: Significant Customers

All revenues are domestic revenues, of which over 90% are currently generated from our three largest customers: Holly, Alon and BP. The major concentration of our petroleum products pipeline system’s revenue 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						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
Holly		65	%		62	%		61	%		59	%
Alon		25	%		29	%		27	%		30	%
BP		7	%		6	%		9	%		9	%

Note 7: Related Party Transactions

Holly

We serve Holly’s refineries in New Mexico and Utah under two 15-year pipeline and terminal agreements. One of these agreements relates to the pipelines and terminals contributed by Holly to us at the time of our initial public offering and expires in 2019 (“Holly PTA”). Our other agreement with Holly relates to the Intermediate Pipelines acquired from Holly in July 2005 and expires in 2020 (“Holly IPA”). The substantial majority of our business is devoted to providing transportation and terminalling services to Holly. The minimum revenue commitments under the Holly PTA and the Holly IPA increase each year at a rate equal to the percentage change in the producer price index (“PPI”), but will not decrease as a result of a decrease in the PPI.

Following the July 1, 2007 PPI rate adjustment, the volume commitment by Holly under the Holly PTA will produce at least $39.6 million of revenue for the twelve months ending June 30, 2008. Under the Holly IPA, Holly agreed to transport volumes of intermediate products on the Intermediate Pipelines that following the July 1, 2007 PPI rate adjustment, will result in minimum funds to us of $12.8 million for the twelve months ending June 30, 2008.

If Holly fails to meet its minimum volume 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.

Under certain provisions of the Omnibus Agreement that we entered with Holly in July 2004 and expires in 2019, we pay Holly an annual administrative fee, initially $2.0 million for each of the three years following the closing of our initial public offering, for the provision by Holly or its affiliates of various

- 13 -

general and administrative services to us. Effective July 1, 2007, the annual fee increased to $2.1 million in accordance with provisions under the agreement. 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.

• Pipeline and terminal revenues received from Holly were $14.8 million and $14.3 million for the three months ended September 30, 2007 and 2006, respectively, and $44.9 million and $37.3 million for the nine months ended September 30, 2007 and 2006, respectively. These amounts include the revenues received under the Holly PTA and Holly IPA.

• Other revenues received from Holly were $2.7 million for the three and nine months ended September 30, 2007 related to our sale of inventory of accumulated terminal overages of refined product. These overages arose from net product gains at our terminals from the beginning of 2005 through the third quarter of 2007. We are currently negotiating an amendment to our pipelines and terminals agreement with Holly that provides that such terminal overages of refined product shall belong to Holly in the future.

• Holly charged general and administrative services under the Omnibus Agreement of $0.6 million and $0.5 million for the three months ended September 30, 2007 and 2006, respectively, and $1.6 million and $1.5 million for the nine months ended September 30, 2007 and 2006, respectively.

• We reimbursed Holly for costs of employees supporting our operations of $2.0 million for the three months ended September 30, 2007 and 2006, and $6.6 million and $5.7 million for the nine months ended September 30, 2007 and 2006, respectively.

• Holly reimbursed us $80,000 and $42,000 for certain costs paid on their behalf for the three months ended September 30, 2007 and 2006, respectively, and $179,000 and $138,000 for the nine months ended September 30, 2007 and 2006, respectively.

• In the three months ended September 30, 2007 and 2006, we distributed $5.8 million and $5.2 million, respectively, to Holly as regular distributions on its subordinated units, common units and general partner interest. We distributed $16.9 million and $15.0 million to Holly in the nine months ended September 30, 2007 and 2006, respectively.

• Our net accounts receivable from Holly were $6.1 million and $3.5 million at September 30, 2007 and December 31, 2006, respectively.

• Holly has failed to meet its minimum volume commitment for each of the first nine quarters of the Holly IPA. We have charged Holly $4.5 million for these shortfalls to date, $0.3 million and $0.2 million of which is included in affiliate accounts receivable at September 30, 2007 and December 31, 2006, respectively.

• For the three and nine months ended September 30, 2007, our revenues from Holly included $0.6 million and $2.2 million, respectively, of shortfalls billed under the Holly IPA in 2006 as Holly did not exceed its minimum volume commitment in any of the subsequent four quarters. Deferred revenue in the consolidated balance sheets at September 30, 2007 and December 31, 2006, includes $1.3 million and $2.4 million, respectively, relating to the Holly IPA. It is possible that Holly may not exceed its minimum obligations under the Holly IPA to allow Holly to receive credit for any of the $1.3 million deferred at September 30, 2007.

BP

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

• BP is the sole customer of Rio Grande. BP’s agreement to ship on the Rio Grande pipeline expired in April 2007 and was extended for an additional year. This agreement will continue on a year-to-year

- 14 -

	basis unless cancelled by either party prior to the end of the previous contract year. We recorded revenues from them of $2.0 million and $1.4 million for the three months ended September 30, 2007 and 2006, respectively, and $6.8 million and $5.4 million for the nine months ended September 30, 2007 and 2006, respectively.
•	Rio Grande paid distributions to BP of $0.8 million and $0.2 million for the three months ended September 30, 2007 and 2006, respectively, and $1.3 million and $1.4 million for the nine months ended September 30, 2007 and 2006, respectively.
•	Included in our accounts receivable – trade at September 30, 2007 and December 31, 2006 were $0.8 million and $2.1 million, respectively, which represented the receivable balance of Rio Grande from BP.

Alon

We have a 15-year pipelines and terminals agreement with Alon (the “Alon PTA”), expiring in 2020, under which Alon has agreed to transport on our pipelines and throughput through our terminals volumes of refined products that results in a minimum level of annual revenue. The agreed upon tariffs are increased or decreased annually at a rate equal to the percentage change in PPI, but not below the initial tariff rate. Following the March 1, 2007 PPI rate adjustment, Alon’s total minimum commitment for the twelve months ending December 31, 2007 is $20.8 million.

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 $5.0 million and $4.8 million of revenues for pipeline transportation and terminalling services under the Alon PTA and $1.8 million and $1.8 million under a pipeline capacity lease for the three months ended September 30, 2007 and 2006, respectively. We recognized $15.8 million and $13.8 million of revenues for pipeline transportation and terminalling services under the Alon PTA and $5.3 million and $5.2 million under pipeline capacity leases for the nine months ended September 30, 2007 and 2006, respectively. The pipeline lease agreement with Alon was amended effective August 31, 2007 to extend two capacity leases for 10 years to August 31, 2018 and July 31, 2020, respectively, to reduce the total leased capacity from 20,000 to 17,500 barrels per day (“bpd”) effective September 1, 2008, and to allow Alon an option, effective from September 1, 2008, to increase the leased capacity by 2,500 bpd for a term of 10 years.

• We paid $0.7 million and $0.6 million to Alon for distributions on our Class B subordinated units for the three months ended September 30, 2007 and 2006, respectively, and $1.9 million and $1.8 million for the nine months ended September 30, 2007 and 2006, respectively.

• Included in our accounts receivable – trade at September 30, 2007 and December 31, 2006 were $3.7 million and $5.0 million, respectively, which represented the receivable balance from Alon.

• For the three and nine months ended September 30, 2007, our revenues from Alon included $0.6 million of shortfalls billed under the Alon PTA in 2006 as Alon did not exceed its minimum revenue obligation in any of the subsequent four quarters. Deferred revenue in the consolidated balance sheets at September 30, 2007 and December 31, 2006 includes $3.3 million and $3.1 million, respectively, relating to the Alon PTA. It is possible that Alon may not exceed its minimum obligations under the Alon PTA to allow Alon to receive credit for any of the $3.3 million deferred at September 30, 2007.

- 15 -

Note 8: Partners’ Equity and Cash Distributions

Issuances of units

Holly currently holds 7,000,000 of our subordinated units and 70,000 of our common units, which constitutes a 45% ownership interest in us, including the 2% general partner interest.

Holly’s subordinated 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 cash is available for common unit distributions during the subordination period. 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 its 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. The Holly owned 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.

Under our registration statement filed with the SEC using a “shelf” registration process, we may offer from time to time up to $800.0 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.

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

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

- 16 -

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.

We 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				Nine Months Ended
	September 30,				September 30,
	2007		2006		2007		2006
	(In thousands, except per unit data)
General partner interest	$	232	$	215	$	681	$	631
General partner incentive distribution		592		340		1,548		793
Total general partner distribution		824		555		2,229		1,424
Limited partner distribution		11,359		10,550		33,336		30,926
Total regular quarterly cash distribution	$	12,183	$	11,105	$	35,565	$	32,350
Cash distribution per unit applicable to limited partners	$	0.705	$	0.655	$	2.070	$	1.920

On October 26, 2007, we announced a cash distribution for the third quarter of 2007 of $0.715 per unit. The distribution is payable on all common, subordinated, and general partner units and will be paid November 14, 2007 to all unitholders of record on November 6, 2007. The aggregate amount of the distribution will be $12.4 million, including $0.6 million paid to the general partner as an incentive distribution.

As a master limited partnership, we distribute our available cash, which exceeds our net income because depreciation and amortization expense represents a non-cash charge against income. The result is a decline in partners’ equity since our regular quarterly distributions exceed our quarterly net income.

- 17 -

Note 9: Supplemental Guarantor/Non-Guarantor Financial Information

Obligations of Holly Energy Partners, L.P. (“Parent”) under the 6.25% Senior Notes have been jointly and severally guaranteed by each of its direct and indirect wholly-owned subsidiaries (“Guarantor Subsidiaries”). These guarantees are full and unconditional. Rio Grande (“Non-Guarantor”), in which we have a 70% ownership interest, is the only subsidiary, 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.

- 18 -

Condensed Consolidating Balance Sheet

				Guarantor		Non-
September 30, 2007	Parent			Subsidiaries		Guarantor			Eliminations			Consolidated
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	2		$	6,144	$	2,564		$	—		$	8,710
Accounts receivable		—			9,962		784			—			10,746
Intercompany accounts receivable (payable)		(127,480	)		127,847		(367	)		—			—
Prepaid and other current assets		271			502		—			—			773
Total current assets		(127,207	)		144,455		2,981			—			20,229
Properties and equipment, net		—			122,085		32,685			—			154,770
Investment in subsidiaries		339,451			24,469		—			(363,920	)		—
Transportation agreements, net		—			54,773		—			—			54,773
Other assets		1,340			1,279		—			—			2,619
Total assets	$	213,584		$	347,061	$	35,666		$	(363,920	)	$	232,391
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	—		$	1,692	$	499		$	—		$	2,191
Accrued interest		957			7		—			—			964
Deferred revenue		—			4,616		—			—			4,616
Accrued property taxes		—			805		131			—			936
Other current liabilities		650			156		81			—			887
Total current liabilities		1,607			7,276		711			—			9,594
Long-term debt		181,347			—		—			—			181,347
Other long-term liabilities		834			334		—			—			1,168
Minority interest		—			—		—			10,486			10,486
Partners’ equity		29,796			339,451		34,955			(374,406	)		29,796
Total liabilities and partners’ equity	$	213,584		$	347,061	$	35,666		$	(363,920	)	$	232,391

Condensed Consolidating Balance Sheet

				Guarantor		Non-
December 31, 2006	Parent			Subsidiaries		Guarantor			Eliminations			Consolidated
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	2		$	9,819	$	1,734		$	—		$	11,555
Accounts receivable		—			8,772		2,085			—			10,857
Intercompany accounts receivable (payable)		(78,952	)		79,144		(192	)		—			—
Prepaid and other current assets		203			1,009		—			—			1,212
Total current assets		(78,747	)		98,744		3,627			—			23,624
Properties and equipment, net		—			127,357		33,127			—			160,484
Investment in subsidiaries		298,872			25,581		—			(324,453	)		—
Transportation agreements, net		—			56,271		550			—			56,821
Other assets		1,453			1,191		—			—			2,644
Total assets	$	221,578		$	309,144	$	37,304		$	(324,453	)	$	243,573
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	—		$	3,356	$	425		$	—		$	3,781
Accrued interest		2,941			—		—			—			2,941
Deferred revenue		—			5,486		—			—			5,486
Accrued property taxes		—			726		142			—			868
Other current liabilities		516			389		193			—			1,098
Total current liabilities		3,457			9,957		760			—			14,174
Long-term debt		180,660			—		—			—			180,660
Other long-term liabilities		1,235			315		—			—			1,550
Minority interest		—			—		—			10,963			10,963
Partners’ equity		36,226			298,872		36,544			(335,416	)		36,226
Total liabilities and partners’ equity	$	221,578		$	309,144	$	37,304		$	(324,453	)	$	243,573

- 19 -

Condensed Consolidating Statement of Income

				Guarantor			Non-
Three months ended September 30, 2007	Parent			Subsidiaries			Guarantor		Eliminations			Consolidated
	(in thousands)
Revenues:
Affiliates	$	—		$	14,827		$	—	$	—		$	14,827
Third parties		—			7,976			1,958		(296	)		9,638
		—			22,803			1,958		(296	)		24,465
Affiliates - other		—			2,748			—		—			2,748
		—			25,551			1,958		(296	)		27,213
Operating costs and expenses:
Operations		—			7,560			721		(296	)		7,985
Depreciation and amortization		—			3,267			327		—			3,594
General and administrative		707			586			136		—			1,429
		707			11,413			1,184		(296	)		13,008
Operating income (loss)		(707	)		14,138			774		—			14,205
Equity in earnings of subsidiaries		14,495			543			—		(15,038	)		—
Interest income (expense)		(3,098	)		(186	)		2		—			(3,282	)
Minority interest		—			—			—		(233	)		(233	)
Net income	$	10,690		$	14,495		$	776	$	(15,271	)	$	10,690

Condensed Consolidating Statement of Income

				Guarantor			Non-
Three months ended September 30, 2006	Parent			Subsidiaries			Guarantor			Eliminations			Consolidated
	(in thousands)
Revenues:
Affiliates	$	—		$	14,272		$	—		$	—		$	14,272
Third parties		—			7,526			1,403			(302	)		8,627
		—			21,798			1,403			(302	)		22,899
Operating costs and expenses:
Operations		—			6,697			687			(302	)		7,082
Depreciation and amortization		—			2,981			858			—			3,839
General and administrative		660			516			1			—			1,177
		660			10,194			1,546			(302	)		12,098
Operating income (loss)		(660	)		11,604			(143	)		—			10,801
Equity in earnings of subsidiaries		11,476			(87	)		—			(11,389	)		—
Interest income (expense)		(3,065	)		(41	)		18			—			(3,088	)
Minority interest		—			—			—			38			38
Net income	$	7,751		$	11,476		$	(125	)	$	(11,351	)	$	7,751

- 20 -

Condensed Consolidating Statement of Income

				Guarantor			Non-
Nine months ended September 30, 2007	Parent			Subsidiaries			Guarantor		Eliminations			Consolidated
	(in thousands)
Revenues:
Affiliates	$	—		$	44,942		$	—	$	—		$	44,942
Third parties		—			24,611			6,804		(889	)		30,526
		—			69,553			6,804		(889	)		75,468
Affiliates - other		—			2,748			—		—			2,748
		—			72,301			6,804		(889	)		78,216
Operating costs and expenses:
Operations		—			22,438			2,476		(889	)		24,025
Depreciation and amortization		—			9,341			1,532		—			10,873
General and administrative		2,212			1,621			158		—			3,991
		2,212			33,400			4,166		(889	)		38,889
Operating income (loss)		(2,212	)		38,901			2,638		—			39,327
Equity in earnings of subsidiaries		40,579			1,896			—		(42,475	)		—
Interest income (expense)		(9,237	)		(516	)		72		—			(9,681	)
Gain on sale of assets		—			298			—		—			298
Minority interest		—			—			—		(814	)		(814	)
Net income	$	29,130		$	40,579		$	2,710	$	(43,289	)	$	29,130

Condensed Consolidating Statement of Income

				Guarantor			Non-
Nine months ended September 30, 2006	Parent			Subsidiaries			Guarantor		Eliminations			Consolidated
	(in thousands)
Revenues:
Affiliates	$	—		$	37,338		$	—	$	—		$	37,338
Third parties		—			22,014			5,409		(897	)		26,526
		—			59,352			5,409		(897	)		63,864
Operating costs and expenses:
Operations		—			20,373			2,144		(897	)		21,620
Depreciation and amortization		—			8,864			2,549		—			11,413
General and administrative		2,149			1,537			4		—			3,690
		2,149			30,774			4,697		(897	)		36,723
Operating income (loss)		(2,149	)		28,578			712		—			27,141
Equity in earnings of subsidiaries		29,053			550			—		(29,603	)		—
Interest income (expense)		(9,020	)		(75	)		73		—			(9,022	)
Minority interest		—			—			—		(235	)		(235	)
Net income	$	17,884		$	29,053		$	785	$	(29,838	)	$	17,884

- 21 -

Condensed Consolidating Statement of Cash Flows

				Guarantor			Non-
Nine months ended September 30, 2007	Parent			Subsidiaries			Guarantor			Eliminations			Consolidated
	(in thousands)
Cash flows from operating activities	$	36,872		$	(1,404	)	$	5,669		$	(3,010	)	$	38,127
Cash flows from investing activities
Additions to properties and equipment		—			(2,580	)		(539	)		—			(3,119	)
Proceeds from sale of assets		—			325			—			—			325
		—			(2,255	)		(539	)		—			(2,794	)
Cash flows from financing activities
Distributions to partners		(35,565	)		—			(4,300	)		4,300			(35,565	)
Cash distribution to minority interest		—			—			—			(1,290	)		(1,290	)
Purchase of units for restricted grants		(1,082	)		—			—			—			(1,082	)
Deferred financing costs		(225	)		—			—			—			(225	)
Other		—			(16	)		—			—			(16	)
		(36,872	)		(16	)		(4,300	)		3,010			(38,178	)
Cash and cash equivalents
Increase (decrease) for the period		—			(3,675	)		830			—			(2,845	)
Beginning of period		2			9,819			1,734			—			11,555
End of period	$	2		$	6,144		$	2,564		$	—		$	8,710

Condensed Consolidating Statement of Cash Flows

				Guarantor			Non-
Nine months ended September 30, 2006	Parent			Subsidiaries			Guarantor			Eliminations			Consolidated
	(in thousands)
Cash flows from operating activities	$	32,984		$	(67	)	$	3,333		$	(3,150	)	$	33,100
Cash flows from investing activities – additions to properties and equipment		—			(6,724	)		(217	)		—			(6,941	)
Cash flows from financing activities
Distributions to partners		(32,350	)		—			(4,500	)		4,500			(32,350	)
Cash distribution to minority interest		—			—			—			(1,350	)		(1,350	)
Purchase of units for restricted grants		(634	)		—			—			—			(634	)
		(32,984	)		—			(4,500	)		3,150			(34,334	)
Cash and cash equivalents
Decrease for the period		—			(6,791	)		(1,384	)		—			(8,175	)
Beginning of period		2			17,770			2,811			—			20,583
End of period	$	2		$	10,979		$	1,427		$	—		$	12,408

Note 10: Proposed Joint Ventures

In February 2007, the HLS board of directors authorized a letter of intent with Plains All American Pipeline, L.P. (“Plains”) for HEP to acquire a 25% joint venture interest in a new 95-mile intrastate pipeline system, now being constructed by Plains, for the shipment of up to 120,000 bpd of crude oil into the Salt Lake City area. The pipeline would be owned by a new joint venture company which would be owned 75% by Plains and 25% by HEP. Subject to the actual construction cost, HEP would purchase its interest for between $22.0 and $25.5 million in the first quarter of 2008, when the new pipeline system is expected to become fully operational.

As previously announced, Holly has entered into a Memorandum of Understanding with Sinclair Transportation Company (‘Sinclair”) to jointly build a 12-inch pipeline from Salt Lake City, Utah to Las Vegas, Nevada, together with terminal facilities in the Cedar City, Utah and north Las Vegas areas (the

- 22 -

“UNEV Pipeline”). Subject to the execution of definitive agreements, Holly will own a 75% interest and Sinclair will own a 25% interest in the project. We have an understanding with Holly that we will be the operator and will have an option to purchase Holly’s investment in the project, effective for a 180-day period commencing when the UNEV Pipeline becomes operational, at a purchase price equal to Holly’s share of actual costs, plus interest at 7% per annum. The initial capacity of the pipeline will be approximately 62,000 bpd, with the capacity for further expansion to approximately 120,000 bpd. The cost of the pipeline is expected to be approximately $235.0 million, and the total cost of the project including terminals is expected to be approximately $300.0 million. Construction of this project is currently expected to be completed and operational in early 2009.

Note 11: Subsequent Events

On October 15, 2007, we entered into an agreement with Holly that amends the Holly PTA under which we have agreed to expand our refined products pipeline system between Artesia, New Mexico and El Paso, Texas (the “South System”). The expansion of the South System will include replacing approximately 85 miles of eight-inch pipe with twelve-inch pipe, adding 150,000 barrels of refined product storage at our El Paso Terminal, improving existing pumps, adding a tie-in to the Kinder Morgan pipeline to Tucson and Phoenix, Arizona, and making related modifications. The Amendment also provides for a tariff increase, effective May 1, 2008, on Holly shipments on our refined product pipelines and monetary incentives for the early completion of the South System expansion, currently targeted for January 31, 2009.

- 23 -

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. We own and operate substantially all of the refined product pipeline and terminalling assets that support the Holly Corporation (“Holly”) refining and marketing operations in west Texas, New Mexico, Utah, Idaho and Arizona and a 70% interest in Rio Grande Pipeline Company (“Rio Grande”). HEP is currently 45% owned by Holly.

We 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 except for terminal overages; therefore, we are not directly exposed to changes in commodity prices.

Our revenues for the nine months ended September 30, 2007 were $78.2 million and our net income for the nine months ended September 30, 2007 was $29.1 million. Our revenues and net income for the nine months ended September 30, 2006 were $63.9 million and $17.9 million, respectively. Our total operating costs and expenses for the nine months ended September 30, 2007 were $38.9 million, as compared to $36.7 million for the nine months ended September 30, 2006.

Agreements with Holly Corporation

We serve Holly’s refineries in New Mexico and Utah under two 15-year pipeline and terminal agreements. One of these agreements relates to the pipelines and terminals contributed by Holly to us at the time of our initial public offering and expires in 2019 (“Holly PTA”). Our other agreement with Holly relates to the Intermediate Pipelines acquired from Holly in July 2005 and expires in 2020 (“Holly IPA”). The substantial majority of our business is devoted to providing transportation and terminalling services to Holly. Following the July 1, 2007 rate adjustment for the increased producer price index (“PPI”), the volume commitment by Holly under the Holly PTA will produce at least $39.6 million of revenue for the twelve months ending June 30, 2008. Under the Holly IPA, Holly agreed to transport volumes of intermediate products on the intermediate pipelines that following the July 1, 2007 PPI adjustment will result in minimum funds to us of $12.8 million for the twelve months ended June 30, 2008. If Holly fails to meet its minimum volume commitments 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.

Under certain provisions of an omnibus agreement that we entered with Holly in July 2004 and expires in 2019 (the “Omnibus Agreement”), we pay Holly an annual administrative fee, initially $2.0 million for each of the three years following the closing of our initial public offering, for the provision by Holly or its affiliates of various general and administrative services to us. Effective July 1, 2007, the annual fee increased to $2.1 million in accordance with provisions under the agreement. 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.

- 24 -

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 nine months ended September 30, 2007 and 2006.

	Three Months Ended
	September 30,						Change from
	2007			2006			2006
	(In thousands, except per unit data)
Revenues
Pipelines:
Affiliates – refined product pipelines	$	8,815		$	8,707		$	108
Third parties – refined product pipelines		8,300			7,504			796
		17,115			16,211			904
Affiliates – intermediate pipelines		3,327			3,023			304
		20,442			19,234			1,208
Terminals and truck loading racks:
Affiliates		2,685			2,542			143
Third parties		1,338			1,123			215
		4,023			3,665			358
Other - affiliates		2,748			—			2,748
Total revenues		27,213			22,899			4,314
Operating costs and expenses
Operations		7,985			7,082			903
Depreciation and amortization		3,594			3,839			(245	)
General and administrative		1,429			1,177			252
		13,008			12,098			910
Operating income		14,205			10,801			3,404
Interest income		101			214			(113	)
Interest expense, including amortization		(3,383	)		(3,302	)		(81	)
Gain on sale of assets		—			—			—
Minority interest in Rio Grande		(233	)		38			(271	)
Net income		10,690			7,751			2,939
Less general partner interest in net income, including incentive distributions(1)		794			488			306
Limited partners’ interest in net income	$	9,896		$	7,263		$	2,633
Net income per limited partner unit - basic and diluted(1)	$	0.61		$	0.45		$	0.16
Weighted average limited partners’ units outstanding		16,108			16,108			—
EBITDA(2)	$	17,566		$	14,678		$	2,888
Distributable cash flow(3)	$	13,683		$	11,338		$	2,345
Volumes (bpd)(4)
Pipelines:
Affiliates – refined product pipelines		71,987			73,525			(1,538	)
Third parties – refined product pipelines		59,024			58,744			280
		131,011			132,269			(1,258	)
Affiliates – intermediate pipelines		62,072			58,711			3,361
		193,083			190,980			2,103
Terminals and truck loading racks:
Affiliates		110,545			118,350			(7,805	)
Third parties		38,409			41,656			(3,247	)
		148,954			160,006			(11,052	)
Total for pipelines and terminal assets (bpd)		342,037			350,986			(8,949	)

- 25 -

	Nine Months Ended
	September 30,						Change from
	2007			2006			2006
	(In thousands, except per unit data)
Revenues
Pipelines:
Affiliates – refined product pipelines	$	26,464		$	22,404		$	4,060
Third parties – refined product pipelines		26,473			23,102			3,371
		52,937			45,506			7,431
Affiliates – intermediate pipelines		10,390			7,337			3,053
		63,327			52,843			10,484
Terminals and truck loading racks:
Affiliates		8,088			7,597			491
Third parties		4,053			3,424			629
		12,141			11,021			1,120
Other - affiliates		2,748			—			2,748
Total revenues		78,216			63,864			14,352
Operating costs and expenses
Operations		24,025			21,620			2,405
Depreciation and amortization		10,873			11,413			(540	)
General and administrative		3,991			3,690			301
		38,889			36,723			2,166
Operating income		39,327			27,141			12,186
Interest income		431			702			(271	)
Interest expense, including amortization		(10,112	)		(9,724	)		(388	)
Gain on sale of assets		298			—			298
Minority interest in Rio Grande		(814	)		(235	)		(579	)
Net income		29,130			17,884			11,246
Less general partner interest in net income, including incentive distributions(1)		2,100			1,134			966
Limited partners’ interest in net income	$	27,030		$	16,750		$	10,280
Net income per limited partner unit - basic and diluted(1)	$	1.68		$	1.04		$	0.64
Weighted average limited partners’ units outstanding		16,108			16,108			—
EBITDA(2)	$	49,684		$	38,319		$	11,365
Distributable cash flow(3)	$	38,666		$	32,845		$	5,821
Volumes (bpd)
Pipelines:
Affiliates – refined product pipelines		75,638			65,321			10,317
Third parties – refined product pipelines		62,877			62,671			206
		138,515			127,992			10,523
Affiliates – intermediate pipelines		63,337			54,898			8,439
		201,852			182,890			18,962
Terminals and truck loading racks:
Affiliates		117,957			114,937			3,020
Third parties		46,114			43,306			2,808
		164,071			158,243			5,828
Total for pipelines and terminal assets (bpd)		365,923			341,133			24,790

- 26 -

(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 $0.6 million and $0.3 million were declared during the three months ended September 30, 2007 and 2006, respectively, and $1.5 million and $0.8 million during the nine months ended September 30, 2007 and 2006, respectively. 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						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
	(In thousands)
Net income	$	10,690		$	7,751		$	29,130		$	17,884
Add interest expense		3,091			3,060			9,213			8,998
Add amortization of discount and deferred debt issuance costs		292			242			899			726
Subtract interest income		(101	)		(214	)		(431	)		(702	)
Add depreciation and amortization		3,594			3,839			10,873			11,413
EBITDA	$	17,566		$	14,678		$	49,684		$	38,319

(3) Distributable cash flow is not a calculation based upon U.S. GAAP. However, the amounts included in the calculation are derived from amounts separately presented in our consolidated financial statements, with the exception of maintenance capital expenditures. Distributable cash flow should not be considered in isolation or as an alternative to net income or operating income, as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity. Distributable cash flow is not necessarily comparable to similarly titled measures of other companies. Distributable cash flow is presented here because it is a widely accepted financial indicator used by investors to compare partnership performance. We believe that this measure provides investors an enhanced perspective of the operating performance of our assets and the cash our business is generating.

- 27 -

Set forth below is our calculation of distributable cash flow.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
				(In thousands)
Net income	$	10,690		$	7,751		$	29,130		$	17,884
Add depreciation and amortization		3,594			3,839			10,873			11,413
Add amortization of discount and deferred debt issuance costs		292			242			899			726
Add (subtract) increase (decrease) in deferred revenue		120			(234	)		(870	)		3,682
Subtract maintenance capital expenditures*		(1,013	)		(260	)		(1,366	)		(860	)
Distributable cash flow	$	13,683		$	11,338		$	38,666		$	32,845

* 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.

	September 30,		December 31,
	2007		2006
Balance Sheet Data	(In thousands)
Cash and cash equivalents	$	8,710	$	11,555
Working capital	$	10,635	$	9,450
Total assets	$	232,391	$	243,573
Long-term debt	$	181,347	$	180,660
Partners’ equity	$	29,796	$	36,226

As a master limited partnership, we distribute our available cash, which exceeds our net income because depreciation and amortization expense represents a non-cash charge against income. The result is a decline in partners’ equity since our regular quarterly distributions exceed our quarterly net income.

Results of Operations – Three Months Ended September 30, 2007 Compared with Three Months Ended September 30, 2006

Summary

Net income increased by $2.9 million from $7.8 million for the three months ended September 30, 2006 to $10.7 million for the three months ended September 30, 2007. The increase in overall earnings was principally due to an increase in volumes transported on our intermediate pipelines, the effects of annual tariff increases on product shipments, the realization of certain previously deferred revenue and revenue related to the sale of inventory of accumulated terminal overages of refined product to Holly. These factors were partially offset by a net decrease in volumes transported on our refined product pipelines and an increase in our operating costs and expenses. Approximately $1.1 million of revenue relating to deficiency payments associated with certain guaranteed shipping contracts was deferred during the three months ended September 30, 2007. Such revenue will be recognized in future periods either as payment for shipments in excess of guaranteed levels or when shipping rights expire unused after a twelve-month period.

Revenues

Revenues increased by $4.3 million from $22.9 million for the three months ended September 30, 2006 to $27.2 million for the three months ended September 30, 2007. This increase in revenue was principally

- 28 -

due to an increase in volumes transported on our intermediate pipelines, the effects of annual tariff increases on product shipments, an increase in previously deferred revenue realized and revenue related to the sale of inventory of accumulated terminal overages of refined product to Holly, partially offset by a net decrease in volumes transported on our refined product pipelines.

Revenues for the three months ended September 30, 2007 include $2.7 million of revenue related to our sale to Holly of inventory of accumulated overages of refined products at our terminals. These overages arose from net product gains at our terminals from the beginning of 2005 through the third quarter of 2007. We are currently negotiating an amendment to our pipelines and terminals agreement with Holly that provides that such terminal overages of refined product shall belong to Holly in the future.

Volumes of product transported on our refined product pipelines decreased for the three months ended September 30, 2007 as compared to the same period in 2006 due to a decline in affiliate shipments. During the third quarter of 2007, certain units of Holly’s Navajo refinery were down for 10 days of unscheduled repairs as a result of damage incurred from a power outage. During this period, refinery production was reduced significantly.

Revenues from the refined product pipelines increased by $0.9 million from $16.2 million for the three months ended September 30, 2006 to $17.1 million for the three months ended September 30, 2007. This increase in refined product pipeline revenue is principally due to the effect of the annual tariff increase on refined product shipments and the realization of $0.5 million of previously deferred revenue. These factors were partially offset by a net decrease in volumes shipped on our refined product pipelines. The decrease in refined product pipeline shipments was principally due to a decrease in affiliate shipments attributable to downtime at Holly’s Navajo Refinery as discussed above. Shipments on our refined product pipelines decreased to an average of 131.0 thousand barrels per day (“mbpd”) for the three months ended September 30, 2007 as compared to 132.3 mbpd for the three months ended September 30, 2006.

Revenues from the intermediate product pipelines increased by $0.3 million from $3.0 million for the three months ended September 30, 2006 to $3.3 million for the three months ended September 30, 2007. This increase in intermediate pipeline revenue was principally due to an increase in volumes shipped on our intermediate pipelines, the effect of the annual tariff increase on intermediate pipeline shipments and an increase in previously deferred revenue realized. Intermediate pipeline revenue for the three months ended September 30, 2007 included $0.6 million, as compared to $0.5 million for the three months ended September 30, 2006, of previously deferred revenue. Shipments on our intermediate product pipelines increased to an average of 62.1 mbpd for the three months ended September 30, 2007 as compared to 58.7 mbpd for the three months ended September 30, 2006.

Revenues from terminal and truck loading rack service fees increased by $0.3 million from $3.7 million for the three months ended September 30, 2006 to $4.0 million for the three months ended September 30, 2007. Refined products terminalled in our facilities averaged 149.0 mbpd for the three months ended September 30, 2007 as compared to 160.0 mbpd for the three months ended September 30, 2006.

Other revenues for the three months ended September 30, 2007 consisted of $2.7 million related to the sale of inventory of accumulated terminal overages of refined product to Holly.

Operating Costs

Operations expense increased by $0.9 million from the three months ended September 30, 2006 to the three months ended September 30, 2007. This increase in expense was principally due to an increase in pipeline and terminal maintenance expense and an increase in the cost of employees who perform services for us, including the addition of two new senior level executives.

Depreciation and Amortization

Depreciation and amortization decreased by $0.2 million from the three months ended September 30, 2006 to the three months ended September 30, 2007, due principally to a reduction in amortization

- 29 -

expense, as a transportation agreement became fully amortized in April 2007, partially offset by depreciation and amortization on fixed asset additions.

General and Administrative

General and administrative costs increased by $0.3 million from the three months ended September 30, 2006 to the three months ended September 30, 2007, due principally to an increase in equity-based incentive compensation expense.

Interest Expense

Interest expense for the three months ended September 30, 2007 totaled $3.4 million, an increase of $0.1 million from $3.3 million for the three months ended September 30, 2006. For the three months ended September 30, 2007, interest expense consisted of: $3.0 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 $0.3 million of amortization of the discount on the senior notes and deferred debt issuance costs. For the three months ended September 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 $0.3 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 reduced our income by $233,000 for the three months ended September 30, 2007 as compared to an increase of $38,000 for the three months ended September 30, 2006.

Results of Operations – Nine Months Ended September 30, 2007 Compared with Nine Months Ended September 30, 2006

Summary

Net income increased by $11.2 million from $17.9 million for the nine months ended September 30, 2006 to $29.1 million for the nine months ended September 30, 2007. The increase in overall earnings was principally due to an increase in volumes transported on our pipeline systems, the effects of annual tariff increases on product shipments, the realization of certain previously deferred revenue and revenue related to the sale of inventory of accumulated terminal overages of refined product to Holly, partially offset by an increase in our operating costs and expenses. Approximately $3.3 million of revenue relating to deficiency payments associated with certain guaranteed shipping contracts was deferred during the nine months ended September 30, 2007. Such revenue will be recognized in future periods either as payment for shipments in excess of guaranteed levels or when shipping rights expire unused after a twelve-month period.

Revenues

Revenues increased by $14.3 million from $63.9 million for the nine months ended September 30, 2006 to $78.2 million for the nine months ended September 30, 2007. This increase was principally due to an increase in volumes transported on our pipeline systems, the effects of annual tariff increases on product shipments, an increase in previously deferred revenue realized and revenue related to the sale of inventory of accumulated terminal overages of refined product to Holly.

Revenues for the nine months ended September 30, 2007 include $2.7 million of revenue related to our sale to Holly of inventory of accumulated overages of refined products at our terminals. These overages arose from net product gains at our terminals from the beginning of 2005 through the third quarter of 2007. We are currently negotiating an amendment to our pipelines and terminals agreement with Holly that provides that such terminal overages of refined product shall belong to Holly in the future.

- 30 -

Volumes of product transported on our refined product pipelines decreased in August 2007 due to a decline in affiliate shipments. During August 2007, certain units of Holly’s Navajo refinery were down for 10 days of unscheduled repairs as a result of damage incurred from a power outage. During this period, refinery production was reduced significantly.

The large increase in revenues and net income for the nine months ended September 30, 2007 as compared to the same period in 2006 was principally due to significant downtime at all of the refineries served by our product distribution network in the second quarter of 2006. These refineries, including Holly’s Navajo and Woods Cross refineries and Alon’s Big Spring refinery, were required to produce ULSD fuel by June 2006. To meet this requirement, downtime at the refineries was required so that ULSD-associated projects could be brought on line. Additionally, Holly completed an expansion of the Navajo refinery. 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 a significant volume decrease during the second quarter of 2006. Since the expansion of Holly’s Navajo refinery in mid-year 2006, increased production has contributed to increased volume shipments on our pipeline systems. The increase in volume shipments on our pipeline systems for the nine months ended September 30, 2007 was partially offset by a decrease in affiliate refined product shipments during August 2007 due to downtime at Holly’s Navajo refinery as discussed above.

Revenues from the refined product pipelines increased by $7.4 million from $45.5 million for the nine months ended September 30, 2006 to $52.9 million for the nine months ended September 30, 2007. This increase in refined product pipeline revenue was principally due to an increase in volumes shipped on our refined product pipelines, the effect of the annual tariff increase on refined product shipments, and the realization of 2.0 million of previously deferred revenue. Shipments on our refined product pipelines increased to an average of 138.5 mbpd for the nine months ended September 30, 2007 as compared to 128.0 mbpd for the nine months ended September 30, 2006.

Revenues from the intermediate product pipelines increased by $3.1 million from $7.3 million for the nine months ended September 30, 2006 to $10.4 million for the nine months ended September 30, 2007. This increase in intermediate pipeline revenue was principally due to an increase in volumes shipped on our intermediate pipelines, the effect of the annual tariff increase on intermediate pipeline shipments and an increase in previously deferred revenue realized. Intermediate pipeline revenue for the nine months ended September 30, 2007 included $2.2 million, as compared to $0.5 million for the nine months ended September 30, 2006, of previously deferred revenue. Shipments on our intermediate product pipelines increased to an average of 63.3 mbpd for the nine months ended September 30, 2007 as compared to 54.9 mbpd for the nine months ended September 30, 2006.

Revenues from terminal and truck loading rack service fees increased by $1.1 million from $11.0 million for the nine months ended September 30, 2006 to $12.1 million for the nine months ended September 30, 2007. This increase was principally due to an increase in refined products terminalled in our facilities. Refined products terminalled in our facilities increased to an average of 164.1 mbpd for the nine months ended September 30, 2007 as compared to 158.2 mbpd for the nine months ended September 30, 2006.

Other revenues for the nine months ended September 30, 2007 consisted of $2.7 million related to the sale of inventory of accumulated terminal overages of refined product to Holly.

Operating Costs

Operations expense increased by $2.4 million from the nine months ended September 30, 2006 to the nine months ended September 30, 2007. This increase in expense was principally due to an increase in pipeline and terminal maintenance expense and an increase in the cost of employees who perform services for us, including the addition of two new senior level executives.

- 31 -

Depreciation and Amortization

Depreciation and amortization decreased by $0.5 million from the nine months ended September 30, 2006 to the nine months ended September 30, 2007, due principally to a reduction in amortization expense, as a transportation agreement became fully amortized in April 2007, partially offset by depreciation and amortization on fixed asset additions.

General and Administrative

General and administrative costs increased by $0.3 million from the nine months ended September 30, 2006 to the nine months ended September 30, 2007, due principally to an increase in equity-based incentive compensation expense.

Interest Expense

Interest expense for the nine months ended September 30, 2007 totaled $10.1 million, an increase of $0.4 million from $9.7 million for the nine months ended September 30, 2006. For the nine months ended September 30, 2007, interest expense consisted of: $8.8 million of interest on our outstanding debt, net of the impact of the interest rate swap; $0.4 million of commitment fees on the unused portion of the credit facility; and $0.9 million of amortization of the discount on the senior notes and deferred debt issuance costs. For the nine months ended September 30, 2006, interest expense consisted of: $8.6 million of interest on our outstanding debt, net of the impact of the interest rate swap; $0.4 million of commitment fees on the unused portion of the credit facility; and $0.7 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 reduced our income by $0.8 million for the nine months ended September 30, 2007 as compared to $0.2 million for the nine months ended September 30, 2006.

LIQUIDITY AND CAPITAL RESOURCES

Overview

In August 2007, we entered into an amended and restated four-year, $100.0 million senior secured revolving credit agreement expiring in August 2011 (the “Credit Agreement”) that amends and restates our previous senior credit agreement in its entirety. The Credit Agreement is available to fund capital expenditures, acquisitions, and working capital and for general partnership purposes. As of September 30, 2007, we had no amounts outstanding under the Credit Agreement.

Our senior notes maturing March 1, 2015 are registered with the SEC and bear interest at 6.25% (“Senior Notes”). The Senior Notes are unsecured and impose certain restrictive covenants, including limitations on our ability to incur additional indebtedness, make investments, sell assets, incur certain liens, pay distributions, enter into transactions with affiliates, and enter into mergers. 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.

Under our “shelf” registration statement, filed September 2, 2005, we may offer from time to time up to $800.0 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.

- 32 -

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, May and August 2007, we paid regular cash distributions of $0.675, $0.69 and $0.705, respectively, on all units, an aggregate amount of $35.6 million. Included in these distributions was an aggregate of $1.5 million paid to the general partner as incentive distributions, as the distributions per unit exceeded $0.55.

Cash and cash equivalents decreased by $2.9 million during the nine months ended September 30, 2007. The cash flows used for financing activities of $38.2 million, in addition to cash flows used for investing activities of $2.8 million, exceeded cash flows generated from operating activities of $38.1 million. Working capital increased by $1.2 million to $10.6 million during the nine months ended September 30, 2007.

Cash Flows — Operating Activities

Cash flows from operating activities increased by $5.0 million from $33.1 million for the nine months ended September 30, 2006 to $38.1 million for the nine months ended September 30, 2007. This increase is mainly due to $5.7 million in additional cash collections from our major customers, resulting principally from increased revenues and shortfall billings, partially offset by miscellaneous year-over-year changes in collections and payments.

As discussed above, our major shippers are obligated to make deficiency payments to us if we do not receive certain minimum revenue payments. Certain of these shippers then have the right to recapture these amounts if future volumes exceed minimum levels. During the first nine months of 2007, we received cash payments of $3.4 million under these commitments. We billed $3.3 million in the first nine months of 2006 related to shortfalls that occurred during the nine months ended September 30, 2006, which expired without recapture and was recognized as revenue in the first nine months of 2007. Another $1.2 million is included in our accounts receivable at September 30, 2007 related to shortfalls that occurred in the third quarter of 2007.

Cash Flows — Investing Activities

Cash flows used for investing activities decreased by $4.1 million from $6.9 million for the nine months ended September 30, 2006 to $2.8 million for the nine months ended September 30, 2007. Additions to properties and equipment for the nine months ended September 30, 2007 were $3.1 million, a decrease of $3.8 million from $6.9 million for the nine months ended September 30, 2006. During the nine months ended September 30, 2007, we also received cash proceeds of $0.3 million on the sale of certain assets.

Cash Flows — Financing Activities

Cash flows used for financing activities were $38.2 million for the nine months ended September 30, 2007 as compared to $34.3 million for the nine months ended September 30, 2006. During the first nine months of 2007, we paid cash distributions on all units and the general partner interest in the aggregate amount of $35.6 million, an increase of $3.2 million from $32.4 million in distributions paid during the first nine months of 2006. Cash paid for the purchases of units for restricted grants was $1.1 million for the nine months ended September 30, 2007, an increase of $0.5 million from $0.6 million for the nine months ended September 30, 2006. Cash distributions paid to the minority interest owner in Rio Grande was $1.3 million for the nine months ended September 30, 2007, as compared to $1.4 million for the nine months ended September 30, 2006. Also for the nine months ended September 30, 2007, we paid $0.2 million in deferred financing costs that were attributable to our amended credit agreement.

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

- 33 -

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 the Holly Logistic Services, L.L.C. (“HLS”) board of directors approves our annual capital budget, which specifies capital projects that our management is authorized to undertake. Additionally, at times when conditions warrant or as new opportunities arise, special projects may be approved. The funds allocated for a particular capital project may be expended over a period 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.

In February 2007, the HLS board of directors authorized a letter of intent with Plains All American Pipeline, L.P. (“Plains��) for HEP to acquire a 25% joint venture interest in a new 95-mile intrastate pipeline system, now being constructed by Plains, for the shipment of up to 120,000 bpd of crude oil into the Salt Lake City area. The pipeline would be owned by a new joint venture company which would be owned 75% by Plains and 25% by HEP. Subject to the actual construction cost, HEP would purchase its interest for between $22.0 and $25.5 million in the first quarter of 2008, when the new pipeline system is expected to become fully operational. The pipeline will allow various refiners in the Salt Lake City area, including Holly’s Woods Cross refinery, to ship crude oil into the Salt Lake City area from the Utah terminus of the Frontier Pipeline as well as crude oil from Wyoming and Utah, which is currently flowing on Plains’ Rocky Mountain Pipeline. Our investment in the project is subject to various conditions, including the negotiation and execution of mutually satisfactory definitive agreements.

We anticipate that our currently planned expenditures for sustaining and maintenance capital as well as expenditures for smaller capital development projects (including the investment in the Utah crude oil pipeline project as described in the preceding paragraph) will be funded with existing cash balances, cash generated by operations and advances under our Credit Agreement.

As previously announced, Holly has entered into a Memorandum of Understanding with Sinclair Transportation Company (“Sinclair”) to jointly build a 12-inch pipeline from Salt Lake City, Utah to Las Vegas, Nevada, together with terminal facilities in the Cedar City, Utah and north Las Vegas areas (the “UNEV Pipeline”). Subject to the execution of definitive agreements, Holly will own a 75% interest and Sinclair will own a 25% interest in the project. We have an understanding with Holly that we will be the operator and will have an option to purchase Holly’s investment in the project, effective for a 180-day period commencing when the UNEV Pipeline becomes operational, at a purchase price equal to Holly’s share of actual costs, plus interest at 7% per annum. The initial capacity of the pipeline will be 62,000 bpd, with the capacity for further expansion to 120,000 bpd. The cost of the pipeline is expected to be $235.0 million, and the total cost of the project including terminals is expected to be approximately $300.0 million. Construction of this project is currently expected to be completed and operational in early 2009.

On October 15, 2007, we entered into an agreement with Holly that amends the Holly PTA under which we have agreed to expand our refined products pipeline system between Artesia, New Mexico and El Paso, Texas (the “South System”). The expansion of the South System will include replacing 85 miles of eight-inch pipe with twelve-inch pipe, adding 150,000 barrels of refined product storage at our El Paso Terminal, improving existing pumps, adding a tie-in to the Kinder Morgan pipeline to Tucson and Phoenix, Arizona, and making related modifications. The estimated cost of this project is expected to be $48.3 million. Currently, we are expecting to complete this project in January 2009.

We are also studying several other projects, which are in various stages of analysis.

- 34 -

We expect to use the issuance of debt securities and/or common units as well as borrowing under our Credit Agreement as the principal means of financing large investments in major capital projects such as the UNEV Pipeline project described in the paragraph above.

Credit Agreement

In August 2007, we entered into an amended and restated four-year, $100.0 million senior secured revolving credit agreement expiring in August 2011 (the “Credit Agreement”) that amends and restates our previous senior credit agreement in its entirety. Union Bank of California, N.A. is a lender and serves as administrative agent under this 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 $50.0 million sub-limit. Up to $20.0 million is available to fund distributions to unitholders. As of September 30, 2007, we had no amounts outstanding under the Credit Agreement.

We have the right to request an increase in the maximum amount of the Credit Agreement, up to $200.0 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, except for payment of certain breakage and related costs. We are required to reduce all working capital borrowings under the Credit Agreement to zero for a period of at least 15 consecutive days 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 reference rate as announced by the administrative agent plus an applicable margin (ranging from 0.25% to 1.50%) or (b) at a rate equal to the London Interbank Offered Rate (“LIBOR”) plus an applicable margin (ranging from 1.00% to 2.50%). In each case, the applicable margin is based upon the ratio of our funded debt (as defined in the agreement) to EBITDA (earnings before interest, taxes, depreciation and amortization, as defined in the Credit Agreement). We incur a commitment fee on the unused portion of the Credit Agreement at a rate ranging from 0.20% or 0.50% based upon the ratio of our funded debt to EBITDA for the four most recently completed fiscal quarters. The agreement matures in August 2011. At that time, the agreement will terminate and all outstanding amounts thereunder will be due and payable.

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

Senior Notes Due 2015

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.

- 35 -

The $185.0 million principal amount of Senior Notes is recorded at $181.3 million on our accompanying consolidated balance sheet at September 30, 2007. The difference of $3.7 million is due to the $2.9 million unamortized discount and $0.8 million relating to the fair value of the interest rate swap contract as further discussed under “Risk Management.”

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 nine months ended September 30, 2007 and 2006.

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 3.9% annually over the past 3 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 $15.0 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 $20.0 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 $2.0 million over the next five years. Other parties are undertaking remediation projects at our Boise, Burley and Albuquerque terminals, and we are obligated to pay a

- 36 -

portion of these costs at the Albuquerque terminal, but not at the Boise or Burley terminals. As of September 30, 2007, we estimate the total remaining remediation cost for the Albuquerque terminal to be insignificant. A remediation project is also under way in New Mexico concerning a leak at a point along our refined product pipeline from Artesia, New Mexico to Orla, Texas. As of September 30, 2007, we estimate the remaining cost on this project to be $0.3 million, half of which will be incurred within the next year. Holly has agreed, subject to a $15.0 million limit, to indemnify us for environmental liabilities related to the assets transferred to us by Holly to the extent such liabilities existed or arose 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 remediation projects mentioned above, including assessment, monitoring, and remediation programs.

In the fourth quarter of 2005, we experienced a refined product release near Sweetwater, Texas. As of September 30, 2007, we estimate that the total remaining remediation cost for this incident to be insignificant. This occurrence is not subject to indemnification from Alon.

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 are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities as of the date of the financial statements. Actual results may differ from these estimates under different assumptions or conditions. We consider the following policies to be the most critical to understanding the judgments that are involved and the uncertainties that could impact our results of operations, financial condition and cash flows.

Our significant accounting policies are described in “Item 7. Management’s Discussion and Analysis of Financial Condition and Operations – Critical Accounting Policies” in our Annual Report on Form 10-K for the year ended December 31, 2006. 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 2007.

Recent Accounting Pronouncements

Interpretation No. 48 “Accounting for Uncertainty in Income Taxes”
In June 2006, the Financial Accounting Standards Board (“FASB”) issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes. This interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements by prescribing a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. We adopted this standard effective January 1, 2007. The adoption of this standard did not have a material impact on our financial condition, results of operations and cash flows.

- 37 -

RISK MANAGEMENT

We have entered into an interest rate swap contract to effectively convert the interest expense associated with $60.0 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 September 30, 2007 was 6.7788%, 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 $0.8 million is included in “Other long-term liabilities” in our accompanying consolidated balance sheet at September 30, 2007. 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 September 30, 2007.

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 September 30, 2007, 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 September 30, 2007 would result in a change of approximately $5.1 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 September 30, 2007, 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.

- 38 -

Item 3.Quantitative and Qualitative Disclosures About Market Risks

Market risk is the risk of loss arising from adverse changes in market rates and prices. See “Risk Management” under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a discussion of market risk exposures that we have with respect to our cash and cash equivalents and long-term debt. We utilize derivative instruments to hedge our interest rate exposure, also discussed under “Risk Management.”

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

Item 4.Controls and Procedures

(a) Evaluation of disclosure controls and procedures

Our principal executive officer and principal financial officer have evaluated, as required by Rule 13a-15(b) under the Securities Exchange Act of 1934 (the “Exchange Act”), our disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of the end of the period covered by this quarterly report on Form 10-Q. Based on that evaluation, the principal executive officer and principal financial officer concluded that the design and operation of our disclosure controls and procedures are effective in ensuring that information we are required to disclose in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission’s rules and forms.

(b) Changes in internal control over financial reporting

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

- 39 -

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

In the third quarter of 2007, we paid $0.2 million for the purchase of 3,836 of our common units in the open market for the recipients of our 2007 restricted unit grants.

							Maximum Number of
					Total Number of		Units that May
					Units Purchased as		Yet Be Purchased
					Part of Publicly		Under a Publicly
	Total Number of		Average Price		Announced Plan or		Announced Plan or
Period	Units Purchased		Paid Per Unit		Program		Program
July 2007		—	$	—		—		—
August 2007		—	$	—		—		—
September 2007		3,836	$	45.29		—		—
Total		3,836	$	45.29		—

Item 6.Exhibits

10.1	Amendment and Supplement to Pipeline Lease Agreement, dated February 21, 1997, between American Petrofina Pipeline Company (predecessor in interest to Alon USA, L.P.) and Navajo Pipeline Company (predecessor in interest to HEP Pipeline Assets, L.P.) (incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K Current Report dated October 16, 2007).
10.2	Amendment to Pipelines and Terminals Agreement, dated July 13, 2004, by and among Holly Corporation, Navajo Refining Company, L.P., Holly Refining and Marketing Company, Holly Energy Partners – Operating, L.P., HEP Logistics Holdings, L.P., Holly Logistic Services, L.L.C. and HEP Logistics GP, L.L.C. (incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K Current Report dated October 19, 2007).
10.3	Amended and Restated Credit Agreement, dated August 27, 2007, between Holly Energy Partners — Operating, L.P., Union Bank of California, N.A., Bank of America, N.A., Guaranty Bank, and certain other lenders (incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K Current Report dated October 31, 2007).
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

- 40 -

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: November 2, 2007	/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)

- 41 -