Holly Energy Partners (HEP) 10-Q 2008 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, 2008

OR

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

For the transition period from                    to                    .

Commission File Number:1-32225

HOLLY ENERGY PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

Delaware	20-0833098
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

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

(Address of principal executive offices)

(214) 871-3555

(Registrant’s telephone number, including area code)

None

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yesþ      Noo

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

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

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, 2008 was 8,390,000.

HOLLY ENERGY PARTNERS, L.P.
INDEX

PART I. FINANCIAL INFORMATION	3
FORWARD-LOOKING STATEMENTS	3
Item 1. Financial Statements (Unaudited, except December 31, 2007 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	26
Item 3. Quantitative and Qualitative Disclosures About Market Risks	43
Item 4. Controls and Procedures	43
PART II. OTHER INFORMATION	44
Item 1. Legal Proceedings	44
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	44
Item 6. Exhibits	44
SIGNATURES	45
EX-10.1
EX-12.1
EX-31.1
EX-31.2
EX-32.1
EX-32.2

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PART I. FINANCIAL INFORMATION

FORWARD-LOOKING STATEMENTS

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

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

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

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

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

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

• The availability and cost of additional debt and equity financing;

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

• The effects of current and future government regulations and policies;

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

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

• General economic conditions; and

• Other financial, operations and legal risks and uncertainties detailed from time to time in our Securities and Exchange Commission filings.

Cautionary statements identifying important factors that could cause actual results to differ materially from our expectations are set forth in this Form 10-Q, including without limitation, 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, 2007 in “Risk Factors,” and in this Form 10-Q in “Management’s Discussion and Analysis of Financial Condition and Results of Operations”. All forward-looking statements included in this Form 10-Q and all subsequent written or oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. The forward-looking statements speak only as of the date made and, other than as required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

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Item 1. Financial Statements

Holly Energy Partners, L.P.

Consolidated Balance Sheets

	September 30,
	2008			December 31,
	(Unaudited)			2007
	(In thousands, except unit data)
ASSETS
Current assets:
Cash and cash equivalents	$	2,118		$	10,321
Accounts receivable:
Trade		7,503			6,611
Affiliates		9,088			5,700
		16,591			12,311
Prepaid and other current assets		858			546
Total current assets		19,567			23,178
Properties and equipment, net		283,628			158,600
Transportation agreements, net		121,975			54,273
Other assets		4,916			2,853
Total assets	$	430,086		$	238,904
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	2,959		$	3,011
Accounts payable — affiliates		2,337			6,021
Accrued interest		1,011			2,996
Deferred revenue		14,338			3,700
Accrued property taxes		1,377			1,177
Other current liabilities		1,105			827
Short-term borrowings under credit agreement		24,000			—
Total current liabilities		47,127			17,732
Commitments and contingencies		—			—
Long-term debt		354,522			181,435
Other long-term liabilities		478			1,181
Minority interest		10,374			10,740
Partners’ equity (deficit):
Common unitholders (8,390,000 and 8,170,000 units issued and outstanding at September 30, 2008 and December 31, 2007, respectively)		171,852			172,807
Subordinated unitholders (7,000,000 units issued and outstanding)		(82,396	)		(73,725	)
Class B subordinated unitholders (937,500 units issued and outstanding)		21,812			22,973
General partner interest (2% interest)		(94,508	)		(94,239	)
Accumulated other comprehensive income		825			—
Total partners’ equity		17,585			27,816
Total liabilities and partners’ equity	$	430,086		$	238,904

See accompanying notes.

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Holly Energy Partners, L.P.

Consolidated Statements of Income

(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
	(In thousands, except per unit data)
Revenues:
Affiliates	$	22,737		$	14,827		$	61,210		$	44,942
Third parties		6,774			9,638			22,352			30,526
		29,511			24,465			83,562			75,468
Affiliates — other		—			2,748			—			2,748
		29,511			27,213			83,562			78,216
Operating costs and expenses:
Operations		11,033			7,939			30,745			23,861
Depreciation and amortization		5,884			3,594			16,259			10,873
General and administrative		1,596			1,406			4,241			3,962
		18,513			12,939			51,245			38,696
Operating income		10,998			14,274			32,317			39,520
Other income (expense):
Interest income		25			101			146			431
Interest expense		(5,161	)		(3,383	)		(14,201	)		(10,112	)
Gain on sale of assets		—			—			36			298
Other income		1,007			—			1,007			—
Minority interest in Rio Grande Pipeline Company		(164	)		(233	)		(834	)		(814	)
		(4,293	)		(3,515	)		(13,846	)		(10,197	)
Income before income taxes		6,705			10,759			18,471			29,323
State income tax		(84	)		(69	)		(237	)		(193	)
Net income		6,621			10,690			18,234			29,130
Less general partner interest in net income		905			794			2,526			2,100
Limited partners’ interest in net income	$	5,716		$	9,896		$	15,708		$	27,030
Net income per limited partner unit - basic and diluted	$	0.35		$	0.61		$	0.96		$	1.68
Weighted average limited partners’ units outstanding		16,328			16,108			16,279			16,108

See accompanying notes.

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Holly Energy Partners, L.P.

Consolidated Statements of Cash Flows

(Unaudited)

	Nine Months Ended
	September 30,
	2008			2007
	(In thousands)
Cash flows from operating activities
Net income	$	18,234		$	29,130
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		16,259			10,873
Minority interest in Rio Grande Pipeline Company		834			814
Amortization of restricted and performance units		1,194			1,087
Gain on sale of assets		(36	)		(298	)
(Increase) decrease in current assets:
Accounts receivable		(892	)		2,722
Accounts receivable — affiliates		(3,388	)		(2,670	)
Prepaid and other current assets		(312	)		439
Increase (decrease) in current liabilities:
Accounts payable		(52	)		(1,590	)
Accounts payable — affiliates		(3,684	)		59
Accrued interest		(1,985	)		(1,977	)
Deferred revenue		10,638			(870	)
Accrued property tax		200			68
Other current liabilities		278			(211	)
Other, net		802			551
Net cash provided by operating activities		38,090			38,127
Cash flows from investing activities
Additions to properties and equipment		(29,024	)		(3,119	)
Acquisition of crude pipelines and tankage assets		(171,000	)		—
Proceeds from sale of assets		36			325
Net cash used for investing activities		(199,988	)		(2,794	)
Cash flows from financing activities
Net borrowings under credit agreement		195,000			—
Proceeds from issuance of common units		104			—
Distributions to partners		(38,908	)		(35,565	)
Distributions to minority interest		(1,200	)		(1,290	)
Contribution from general partner		186			—
Purchase of units for restricted grants		(795	)		(1,082	)
Deferred financing costs		(692	)		(225	)
Other		—			(16	)
Net cash provided by (used for) financing activities		153,695			(38,178	)
Cash and cash equivalents
Decrease for period		(8,203	)		(2,845	)
Beginning of period		10,321			11,555
End of period	$	2,118		$	8,710

See accompanying notes.

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Holly Energy Partners, L.P.

Consolidated Statement of Partners’ Equity (Deficit)

(Unaudited)

													Accumulated
							Class B			General			Other
	Common			Subordinated			Subordinated			Partner			Comprehensive
	Units			Units			Units			Interest			Income		Total
	(In thousands)
Balance December 31, 2007	$	172,807		$	(73,725	)	$	22,973		$	(94,239	)	$	—	$	27,816
Net income		8,038			6,764			906			2,526			—		18,234
Change in fair value of cash flow hedge		—			—			—			—			825		825
Comprehensive income		8,038			6,764			906			2,526			825		19,059
Distributions to partners		(18,425	)		(15,435	)		(2,067	)		(2,981	)		—		(38,908	)
Issuance of common units		9,104			—			—			—			—		9,104
Cost of issuing common units		(71	)		—			—			—			—		(71	)
Capital contribution		—			—			—			186			—		186
Purchase of units for restricted grants		(795	)		—			—			—			—		(795	)
Amortization of restricted and performance units		1,194			—			—			—			—		1,194
Balance September 30, 2008	$	171,852		$	(82,396	)	$	21,812		$	(94,508	)	$	825	$	17,585

See accompanying notes.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 1: Description of Business and Presentation of Financial Statements

Holly Energy Partners, L.P. (“HEP”) together with its consolidated subsidiaries, is a publicly held master limited partnership, currently 46% 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.

Holly recognizes us as a variable interest entity. Our purchase of Holly’s crude pipelines and tankage assets on February 29, 2008 qualified as a reconsideration event whereby Holly reassessed their beneficial interest in us and determined that their beneficial interest in us exceeds 50%. Accordingly, Holly reconsolidated us effective March 1, 2008.

We operate in one business segment — the operation of petroleum product and crude oil pipelines, tankage and terminal facilities.

One of Holly’s wholly-owned subsidiaries owns a refinery in Artesia, New Mexico, which Holly operates in conjunction with crude, vacuum distillation and other facilities situated in Lovington, New Mexico (collectively, the “Navajo Refinery”). The Navajo Refinery produces high-value refined products such as gasoline, diesel fuel and jet fuel and serves markets in the southwestern United States and northern Mexico. We own and operate the two parallel intermediate feedstock pipelines (the “Intermediate Pipelines”), which connect the New Mexico refining facilities. Our refined product pipelines serve as part of the product distribution network that services the Navajo Refinery. Our terminal operations serving the Navajo Refinery include a truck rack at the Navajo Refinery and four integrated refined product terminals located in New Mexico, Texas and Arizona. On February 29, 2008, we acquired pipeline and tankage assets from Holly (the “Crude Pipelines and Tankage Assets”) that also service the Navajo Refinery. See Note 2 for a further description of these assets.

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 refinery, a refined product terminal in Spokane, Washington and a 50% non-operating interest in product terminals in Boise and Burley, Idaho. See Note 2 for a description of the Crude Pipelines and Tankage Assets that also service the Woods Cross Refinery.

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

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

The consolidated financial statements included herein have been prepared without audit, pursuant to the rules and regulations of the United States Securities and Exchange Commission (the “SEC”). The interim financial statements reflect all adjustments, which, in the opinion of management, are necessary for a fair presentation of our results for the interim periods. Such adjustments are considered to be of a normal recurring nature. Although certain notes and other information required by accounting principles generally accepted in the United States of America have been condensed or omitted, we believe that the disclosures in these consolidated financial statements are adequate to make the information presented not misleading. These consolidated financial statements should be read in conjunction with our Form 10-K for the year ended December 31, 2007. 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, 2008.

We have reclassified state income taxes for the three and nine months ended September 30, 2007 to conform to our current presentation. State income taxes were previously classified as operations and general and administrative expenses in our consolidated statement of income.

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Recent Accounting Pronouncements

Statement of Financial Accounting Standards (“SFAS”) No. 157 “Fair Value Measurements”
In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, Fair Value Measurements. This standard simplifies and codifies guidance on fair value measurements under generally accepted accounting principles. This standard defines fair value, establishes a framework for measuring fair value and prescribes expanded disclosures about fair value measurements. It also establishes a fair value hierarchy that categorizes inputs used in fair value measurements into three broad levels. Under this hierarchy, quoted prices in active markets for identical assets or liabilities are considered the most reliable evidence of fair value and are given the highest priority level (level 1). Unobservable inputs are considered the least reliable and are given the lowest priority level (level 3). We adopted this standard effective January 1, 2008.

We have interest rate swaps that we measure at fair value on a recurring basis using level 2 inputs. See Note 5 for additional information on these swaps.

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

In March 2008, the FASB ratified Emerging Issues Task Force (“EITF”) Issue No. 07-04, Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships (“MLP’s). This standard provides guidance in the application of the two-class method in computing earnings per unit to reflect an MLP’s contractual obligation to make distributions to the general partner, limited partners, and incentive distribution rights holder. EITF No. 07-04 is effective for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. We will adopt this standard effective January 1, 2009. We do not anticipate that the adoption of this standard will have a material effect on our financial condition, results of operations and cash flows.

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

In June 2006, the FASB issued FSP No. 03-6-1, Determining Whether Instruments Granted in Share-Based Transactions Are Participating Securities. This standard provides guidance in determining whether unvested instruments granted under share-based payment transactions are participating securities and, therefore, should be included in earnings per share calculations under the two-class method provided under FASB No. 128, Earnings per Share. FSP No. 03-6-1 is effective for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. We will adopt this standard effective January 1, 2009. We do not anticipate that the adoption of this standard will have a material effect on our financial condition, results of operations and cash flows.

Note 2: Acquisition

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

In connection with this transaction, we entered into a 15-year crude pipelines and tankage agreement with Holly (the “Holly CPTA”). Under this agreement, Holly agreed to transport and store volumes of crude oil on the crude pipelines and tankage facilities that at the agreed rates will result in minimum annual revenues to us of $26.7 million. The agreed upon tariffs on the crude pipelines will be adjusted each year at a rate equal to the percentage change in the producer price index (“PPI”) but will not decrease as a result of a decrease in the PPI. Additionally, Holly amended our omnibus agreement

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(the “Omnibus Agreement”) to provide $7.5 million of indemnification for a period of up to fifteen years for environmental noncompliance and remediation liabilities associated with the Crude Pipelines and Tankage Assets that occurred or existed prior to our acquisition for a period of up to fifteen years.

The consideration paid for the Crude Pipeline and Tankage Assets was allocated to the individual assets acquired based on management’s preliminary fair value estimates. In accounting for this acquisition, we recorded pipeline and terminal assets of $108.0 million and an intangible asset of $72.0 million, representing the allocated value of the Holly CPTA. This intangible asset is included in “Transportation agreements, net” in our consolidated balance sheets.

Note 3: Properties and Equipment

	September 30,		December 31,
	2008		2007
	(In thousands)
Pipelines and terminals	$	306,700	$	196,800
Land and right of way		24,319		22,825
Other		6,790		5,706
Construction in progress		33,766		9,103
		371,575		234,434
Less accumulated depreciation		87,947		75,834
	$	283,628	$	158,600

During the nine months ended September 30, 2008 we capitalized $0.7 million in interest related to major construction projects. We did not capitalize any interest during the nine months ended September 30, 2007.

Note 4: Transportation Agreements

Our transportation agreements consist of the following:

• The transportation agreement with Alon represents a portion of the total purchase price of assets purchased from Alon in 2005 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 Holly crude pipelines and tankage agreement represents a portion of the total purchase price of the Crude Pipelines and Tankage Assets that was allocated based on management’s preliminary estimate of its fair value. This asset is being amortized over 15 years ending 2023, the 15-year term of the Holly CPTA.

The carrying amounts of our transportation agreements are as follows:

	September 30,		December 31,
	2008		2007
	(In thousands)
Alon transportation agreement	$	59,933	$	59,933
Holly crude pipelines and tankage agreement		72,000		—
		131,933		59,933
Less accumulated amortization		9,958		5,660
	$	121,975	$	54,273

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Note 5: Debt

Credit Agreement

In February 2008, we amended our $100 million senior secured revolving credit agreement expiring in August 2011 to increase the size from $100 million to $300 million (the “Credit Agreement”), which we used to finance the $171.0 million cash portion of the consideration paid for the Crude Pipelines and Tankage Assets acquired from Holly. Union Bank of California, N.A. is one of the lenders and serves as administrative agent under this agreement. As of September 30, 2008 and December 31, 2007, we had $195.0 million and zero, respectively, outstanding under the Credit Agreement.

The Credit Agreement is available to fund capital expenditures, acquisitions, and working capital and for general partnership purposes. Advances under the Credit Agreement that are either designated for working capital or have been used as interim financing to fund capital expenditures are classified as 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 and to fund distributions to unitholders up to a $20.0 million sub-limit. During the nine months ended September 30, 2008, we received net advances totaling $24.0 million under the Credit Agreement that were used to fund capital expenditures.

We have the right to request an increase in the maximum amount of the Credit Agreement, up to $370.0 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. However, any recourse to HEP Logistics Holdings, L.P. would be limited to the extent of their assets, which other than their investment in HEP, are not significant.

We may prepay all loans at any time without penalty, except for payment of certain breakage and related costs. We are required to reduce all working capital borrowings under the Credit Agreement to zero for a period of at least 15 consecutive days in each twelve-month period prior to the maturity date of the agreement.

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, 2008, we are subject to the 0.375% rate on the $105.0 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 on us, including: a prohibition against distribution to unitholders if, before or after the distribution, a potential default or an event of default as defined in the agreement would occur; limitations on our ability to incur debt, make loans, acquire other companies, change the nature of our business, enter a merger or consolidation, or sell assets; and covenants that require maintenance of a specified EBITDA to interest expense ratio and debt to EBITDA ratio. If an event of default exists under the agreement, the lenders will be able to accelerate the maturity of the debt and exercise other rights and remedies.

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Senior Notes Due 2015

Our senior notes maturing March 1, 2015 are registered with the SEC and bear interest at 6.25% (the “Senior Notes”). The Senior Notes are unsecured and impose certain restrictive covenants, including limitations on our ability to incur additional indebtedness, make investments, sell assets, incur certain liens, pay distributions, enter into transactions with affiliates, and enter into mergers. At any time when the Senior Notes are rated investment grade by both Moody’s and Standard & Poor’s and no default or event of default exists, we will not be subject to many of the foregoing covenants. Additionally, we have certain redemption rights under the Senior Notes.

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

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

	September 30,			December 31,
	2008			2007
	(In thousands)
Credit Agreement	$	195,000		$	—
Senior Notes
Principal		185,000			185,000
Unamortized discount		(2,439	)		(2,724	)
Fair value hedge — interest rate swap		961			(841	)
		183,522			181,435
Total Debt		378,522			181,435
Less net short-term borrowing under credit agreement		24,000			—
Total long-term debt	$	354,522		$	181,435

Interest Rate Risk Management

As of September 30, 2008, we have two interest rate swap contracts.

We entered into an interest rate swap to hedge our exposure to the cash flow risk caused by the effects of LIBOR changes on the $171.0 million Credit Agreement advance that we used to finance our purchase of the Crude Pipelines and Tankage Assets from Holly. This interest rate swap effectively converts our $171.0 million LIBOR based debt to fixed rate debt having an interest rate of 3.74% plus an applicable margin, currently 2.0%, which equaled an effective interest rate of 5.74% as of September 30, 2008. The maturity date of this swap contract is February 28, 2013. We intend to renew our Credit Agreement prior to its expiration in August 2011 and continue to finance the $171.0 million balance until the swap matures.

We have designated this interest rate swap as a cash flow hedge. Based on our assessment of effectiveness using the change in variable cash flows method, we have determined that this interest rate swap is effective in offsetting the variability in interest payments on our $171.0 million variable rate debt resulting from changes in LIBOR. Under hedge accounting, we adjust our cash flow hedge on a quarterly basis to its fair value with a corresponding offset to accumulated other comprehensive income. Also on a quarterly basis, we measure hedge effectiveness by comparing the present value of the cumulative change in the expected future interest to be paid or received on the variable leg of our swap against the expected future interest payments on our $171.0 million variable rate debt. Any ineffectiveness is reclassified from accumulated other comprehensive income to interest expense. As of September 30, 2008, we had no ineffectiveness on our cash flow hedge.

We also have an interest rate swap contract that effectively converts interest expense associated with $60.0 million of our 6.25% Senior Notes from a fixed to a variable rate. Under this swap contract, interest on the $60.0 million notional amount is computed using the three-month LIBOR plus an applicable margin of 1.1575%, which equaled an effective interest rate of 3.97% as of September 30, 2008. The maturity date of this swap contract is March 1, 2015, matching the maturity of the Senior Notes.

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This interest rate swap has been designated as a fair value hedge and meets the requirements to assume no ineffectiveness. Accordingly, we use the “shortcut” method of accounting. Under this method, we adjust the carrying value of the swap to its fair value on a quarterly basis, with an offsetting entry to our Senior Notes, effectively adjusting the carrying value of $60.0 million of principal on the Senior Notes to its fair value.

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

Additional information on our interest rate swaps are as follows:

		Fair Value		Location of Offsetting
Interest Rate Swaps	Balance Sheet Location	(In thousands)		Balance
Cash flow hedge — $171 million LIBOR based debt	Other assets	$	825	Accumulated other comprehensive income
Fair value hedge – $60 million of 6.25% Senior Notes	Other assets	$	961	Long-term debt

Interest Expense and Other Debt Information

Interest expense consists of the following components:

	Nine Months Ended
	September 30,
	2008		2007
	(In thousands)
Interest on outstanding debt:
Senior Notes, net of interest rate swap	$	7,901	$	8,839
Credit Agreement, net of interest rate swap		5,320		—
Amortization of discount and deferred issuance costs		739		917
Commitment fees		241		356
Net interest expense	$	14,201	$	10,112
Cash paid for interest(1)	$	11,414	$	11,300

(1) Net of cash received under our interest rate swap agreements of $3.8 million for the nine months ended September 30, 2008 and 2007.

The estimated fair value of our Senior Notes was $148.0 million as of September 30, 2008.

Note 6: 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. These employees participate in the retirement and benefit plans of Holly. Our share of retirement and benefits costs was $0.6 million and $0.2 million for the three months ended September 30, 2008 and 2007, respectively, and $1.6 million and $1.0 million for the nine months ended September 30, 2008 and 2007, respectively.

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

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On September 30, 2008, we had two types of equity-based compensation, which are described below. The compensation cost charged against income for these plans was $0.6 million and $0.3 million for the three months ended September 30, 2008 and 2007, respectively, and $1.4 million and $1.0 million for the nine months ended September 30, 2008 and 2007, 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, 2008, 350,000 units were authorized to be granted under the equity-based compensation plans, of which 231,988 had not yet been granted.

Restricted Units

Under our Long-Term Incentive Plan, we grant restricted units to selected employees and directors who perform services for us, with vesting generally over a period of one to five years. Although full ownership of the units does not transfer to the recipients until the units vest, the recipients have distribution and voting rights on these units from the date of grant. The 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 and changes during the nine months ended September 30, 2008, is presented below:

						Weighted-
				Weighted-		Average	Aggregate
				Average		Remaining	Intrinsic
				Grant-Date		Contractual	Value
Restricted Units	Grants			Fair Value		Term	($000)
Outstanding January 1, 2008 (not vested)		44,711		$	44.77
Granted		27,088			38.43
Forfeited		(303	)		44.62
Vesting and transfer of full ownership to recipients		(18,025	)		45.60
Outstanding at September 30, 2008 (not vested)		53,471		$	41.28	1.0 year	$	1,606

There were 18,025 restricted units having an intrinsic value of $0.5 million and a fair value of $0.8 million that were vested and transferred to recipients during the nine months ended September 30, 2008. As of September 30, 2008, there was $0.9 million of total unrecognized compensation costs related to nonvested restricted unit grants. That cost is expected to be recognized over a weighted-average period of 1 year.

Performance Units

Under our Long-Term Incentive Plan, we grant performance units to selected executives 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. Our initial performance grant of 1,514 units in 2005 vested in the first quarter of 2008. Payment was 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 14,337 performance units to certain officers in March 2008. These units will vest over a three-year performance period ending December 31, 2010 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 $40.54 and will apply to the number of units ultimately awarded.

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A summary of performance unit activity and changes during the nine months ended September 30, 2008 is presented below:

	Payable
Performance Units	In Units
Outstanding at January 1, 2008 (not vested)		24,148
Granted		14,337
Forfeited		—
Vesting and payment of cash benefit to recipients		(1,514	)
Outstanding at September 30, 2008 (not vested)		36,971

There were 1,514 performance units having an intrinsic and fair value of $0.1 million that were vested and transferred to recipients during the nine months ended September 30, 2008. Based on the weighted average fair value of $42.10 at September 30, 2008 there was $0.8 million of total unrecognized compensation cost related to nonvested performance units. That cost is expected to be recognized over a weighted-average period of 1.3 years.

Note 7: Significant Customers

All revenues are domestic revenues, of which over 90% are currently generated from our three largest customers: Holly, Alon and BP Plc (“BP”). The major concentration of our 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,
	2008			2007			2008			2007
Holly		77	%		65	%		73	%		61	%
Alon		13	%		25	%		15	%		27	%
BP		6	%		7	%		8	%		9	%

Note 8: Related Party Transactions

Holly and Alon

As of September 30, 2008, we serve Holly’s refineries in New Mexico and Utah under three 15-year pipeline and terminal and tankage agreements. The substantial majority of our business is devoted to providing transportation, storage and terminalling services to Holly.

We have an agreement that relates to the pipelines and terminals contributed by Holly to us at the time of our initial public offering and expires in 2019 (the “Holly PTA”). Our second agreement with Holly relates to the Intermediate Pipelines acquired from Holly in July 2005 and expires in 2020 (the ���Holly IPA”). And third, we have the Holly CPTA that relates to the Crude Pipelines and Tankage Assets acquired from Holly and expires on February 29, 2023 (collectively the “agreements”).

Under these agreements, Holly agreed to transport and store volumes of refined product and crude oil on our pipelines and terminal and tankage facilities that result in minimum annual payments to us. The agreed upon tariffs are adjusted each year on the anniversary date of the agreement 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 our July 1, 2008 PPI rate adjustments, these agreements will result in minimum payments to us of $81.2 million for the twelve months ended June 30, 2009.

We also 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

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tariff rate. Following the March 1, 2008 PPI rate adjustment, Alon’s total minimum commitment for the twelve months ending February 28, 2009 is $22.0 million.

If Holly or Alon fail to meet their minimum volume commitments under the agreements in any quarter, it will be required to pay us in cash the amount of any shortfall by the last day of the month following the end of the quarter. With the exception of the Holly CPTA, a shortfall payment may be applied as a credit in the following four quarters after minimum obligations are met.

In October 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 includes replacing 85 miles of 8-inch pipe with 12-inch pipe, adding 150,000 barrels of refined product storage at our El Paso Terminal, improving existing pumps, adding a tie-in to the Kinder Morgan pipeline to Tucson and Phoenix, Arizona and making related modifications. The cost of this project is estimated to be $48.3 million. Currently, we are expecting to complete the majority of this project in early 2009.

Under certain provisions of the Omnibus Agreement that we entered with Holly in July 2004 and that expires in 2019, we pay Holly an annual administrative fee for the provision by Holly or its affiliates of various general and administrative services to us. Effective March 1, 2008, the annual fee was increased from $2.1 million to $2.3 million to cover additional general and administrative services attributable to the operations of our Crude Pipelines and Tankage Assets. This fee does not include the salaries of pipeline and terminal personnel or the cost of their employee benefits which are separately charged to us by Holly. We also reimburse Holly and its affiliates for direct expenses they incur on our behalf.

In consideration for Holly’s assistance in obtaining our joint venture opportunity in a new 95-mile intrastate pipeline system (the “SLC Pipeline”) now under construction by Plains All American Pipeline, L.P. (“Plains”), we will pay Holly a $2.5 million finder’s fee upon the closing of our investment in the joint venture with Plains. See Note 11 for further information on this proposed joint venture.

• Pipeline, terminal and tankage revenues received from Holly were $22.7 million and $14.8 million for the three months ended September 30, 2008 and 2007, respectively, and $61.2 million and $44.9 million for the nine months ended September 30, 2008 and 2007, respectively. These amounts include the revenues received under the Holly PTA, Holly IPA and Holly CPTA.

• 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. In the fourth quarter of 2007, we amended our pipelines and terminals agreement with Holly to provide that, on a go-forward basis, such terminal overages of refined product belong to Holly.

• Holly charged general and administrative services under the Omnibus Agreement of $0.6 million for each of the three months ended September 30, 2008 and 2007, and $1.6 million for each of the nine months ended September 30, 2008 and 2007.

• We reimbursed Holly for costs of employees supporting our operations of $3.7 million and $2.0 million for the three months ended September 30, 2008 and 2007, respectively, and $9.8 million and $6.6 million for the nine months ended September 30, 2008 and 2007, respectively.

• Holly reimbursed us zero and $80,000 for certain costs paid on their behalf for the three months ended September 30, 2008 and 2007, respectively, and zero and $179,000 for the nine months ended September 30, 2008 and 2007, respectively.

• We distributed $6.5 million and $5.8 million for the three months ended September 30, 2008 and 2007, respectively, to Holly as regular distributions on its subordinated units, common units and general partner interest. We distributed $18.9 million and $16.9 million to Holly for the nine months ended September 30, 2008 and 2007, respectively.

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• Our accounts receivable from Holly were $9.1 million and $5.7 million at September 30, 2008 and December 31, 2007, respectively.

• Holly has failed to meet its minimum volume commitment for each of the thirteen quarters since inception of the Holly IPA. We have charged Holly $6.5 million for these shortfalls to date, $0.8 million and zero million of which is included in affiliate accounts receivable at September 30, 2008 and December 31, 2007, respectively.

• For the three and nine months ended September 30, 2008, our revenues from Holly included $0.4 million and $1.2 million, respectively, of shortfalls billed under the Holly IPA in 2007 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, 2008 and December 31, 2007, includes $1.9 million and $1.1 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 $1.9 million deferred at September 30, 2008.

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’s agreement to ship on the Rio Grande pipeline expired on March 31, 2008. Rio Grande is currently serving multiple shippers on the pipeline. We recorded revenues from them of $1.7 million and $2.0 million for the three months ended September 30, 2008 and 2007, respectively, and $6.6 million and $6.8 million for the nine months ended September 30, 2008 and 2007, respectively.

• Rio Grande paid distributions to BP of $0.3 million and $0.8 million for the three months ended September 30, 2008 and 2007, respectively, and $1.2 million and $1.3 million for the nine months ended September 30, 2008 and 2007, respectively.

• Included in our accounts receivable – trade at September 30, 2008 and December 31, 2007 were $0.7 million and $1.5 million, respectively, which represented the receivable balance of Rio Grande from BP.

Alon

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

• We recognized $1.9 million and $5.0 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, 2008 and 2007, respectively. We recognized $6.8 million and $15.8 million of revenues for pipeline transportation and terminalling services under the Alon PTA and $5.3 million under pipeline capacity leases for the nine months ended September 30, 2008 and 2007.

• We paid $0.7 million to Alon for distributions on our Class B subordinated units for each of the three months ended September 30, 2008 and 2007 and $2.1 million and $1.9 million for the nine months ended September 30, 2008 and 2007, respectively.

• Included in our accounts receivable – trade at September 30, 2008 and December 31, 2007 were $6.7 million and $3.5 million, respectively, which represented the receivable balance from Alon.

• Our revenues from Alon for the three and nine months ended September 30, 2008 included $0.9 million and $2.2 million, respectively, of shortfalls billed under the Alon PTA in 2007 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, 2008 and December 31, 2007 includes $12.4 million and $2.6 million, respectively, relating to the Alon PTA. It is possible that Alon may not exceed

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its minimum obligations under the Alon PTA to allow Alon to receive credit for any of the $12.4 million deferred at September 30, 2008.

• Other income of $1.0 million for the three and nine months ended September 30, 2008 represents a reimbursement from Alon for certain pipeline repair and maintenance costs that were incurred and expensed over a two year period.

Note 9: Partners’ Equity, Allocations and Cash Distributions

Issuances of units

As partial consideration for our purchase of the Crude Pipelines and Tankage Assets, we issued 217,497 of our common units having a fair value of $9.0 million to Holly. Also, Holly purchased an additional 2,503 of our common units for $0.1 million and HEP Logistics Holdings, L.P., our general partner, contributed $0.2 million as an additional capital contribution in order to maintain its 2% general partner interest.

Holly currently holds 7,000,000 of our subordinated units and 290,000 of our common units, which constitutes a 46% ownership interest in us, including the 2% general partner interest. The subordination period applicable to Holly’s subordinated units extends until the first day of any quarter beginning after June 30, 2009 that certain tests based on our exceeding minimum quarterly distributions are met.

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 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.

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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,
	2008		2007		2008		2007
	(In thousands, except per unit data)
General partner interest	$	264	$	232	$	776	$	681
General partner incentive distribution		788		592		2,205		1,548
Total general partner distribution		1,052		824		2,981		2,229
Limited partner distribution		12,200		11,359		35,927		33,336
Total regular quarterly cash distribution	$	13,252	$	12,183	$	38,908	$	35,565
Cash distribution per unit applicable to limited partners	$	0.745	$	0.705	$	2.205	$	2.070

On October 24, 2008, we announced a cash distribution for the third quarter of 2008 of $0.755 per unit. The distribution is payable on all common, subordinated, and general partner units and will be paid November 14, 2008 to all unitholders of record on November 5, 2008. The aggregate amount of the distribution will be $13.5 million, including $0.9 million to be paid to the general partner as an incentive distribution.

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

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Note 10: Supplemental Guarantor/Non-Guarantor Financial Information

Obligations of Holly Energy Partners, L.P. (“Parent”) under the 6.25% Senior Notes have been jointly and severally guaranteed by each of its direct and indirect wholly-owned subsidiaries (“Guarantor Subsidiaries”). These guarantees are full and unconditional. Rio Grande (“Non-Guarantor”), in which we have a 70% ownership interest, is the only subsidiary that has not guaranteed these obligations.

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

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Condensed Consolidating Balance Sheet

				Guarantor			Non-
September 30, 2008	Parent			Subsidiaries			Guarantor			Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	2		$	106		$	2,010		$	—		$	2,118
Accounts receivable		—			15,931			660			—			16,591
Intercompany accounts receivable (payable)		(183,007	)		183,168			(161	)		—			—
Prepaid and other current assets		261			597			—			—			858
Total current assets		(182,744	)		199,802			2,509			—			19,567
Properties and equipment, net		��			250,915			32,713			—			283,628
Investment in subsidiaries		382,982			24,205			—			(407,187	)		—
Transportation agreements, net		—			121,975			—			—			121,975
Other assets		2,244			2,672			—			—			4,916
Total assets	$	202,482		$	599,569		$	35,222		$	(407,187	)	$	430,086
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	—		$	4,889		$	407		$	—		$	5,296
Accrued interest		(835	)		1,846			—			—			1,011
Deferred revenue		—			14,338			—			—			14,338
Accrued property taxes		—			1,229			148			—			1,377
Other current liabilities		2,210			(1,193	)		88			—			1,105
Short-term borrowings under credit agreement		—			24,000			—			—			24,000
Total current liabilities		1,375			45,109			643			—			47,127
Long-term debt		183,522			171,000			—			—			354,522
Other long-term liabilities		—			478			—			—			478
Minority interest		—			—			—			10,374			10,374
Partners’ equity		17,585			382,982			34,579			(417,561	)		17,585
Total liabilities and partners’ equity	$	202,482		$	599,569		$	35,222		$	(407,187	)	$	430,086

Condensed Consolidating Balance Sheet

				Guarantor			Non-
December 31, 2007	Parent			Subsidiaries			Guarantor			Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	2		$	8,060		$	2,259		$	—		$	10,321
Accounts receivable		—			10,820			1,491			—			12,311
Intercompany accounts receivable (payable)		(141,175	)		141,553			(378	)		—			—
Prepaid and other current assets		183			363			—			—			546
Total current assets		(140,990	)		160,796			3,372			—			23,178
Properties and equipment, net		—			125,383			33,217			—			158,600
Investment in subsidiaries		353,235			25,059			—			(378,294	)		—
Transportation agreements, net		—			54,273			—			—			54,273
Other assets		1,302			1,551			—			—			2,853
Total assets	$	213,547		$	367,062		$	36,589		$	(378,294	)	$	238,904
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	—		$	8,499		$	533		$	—		$	9,032
Accrued interest		(2,932	)		5,928			—			—			2,996
Deferred revenue		—			3,700			—			—			3,700
Accrued property taxes		—			1,021			156			—			1,177
Other current liabilities		6,387			(5,661	)		101			—			827
Total current liabilities		3,455			13,487			790			—			17,732
Long-term debt		181,435			—			—			—			181,435
Other long-term liabilities		841			340			—			—			1,181
Minority interest		—			—			—			10,740			10,740
Partners’ equity		27,816			353,235			35,799			(389,034	)		27,816
Total liabilities and partners’ equity	$	213,547		$	367,062		$	36,589		$	(378,294	)	$	238,904

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Condensed Consolidating Statement of Income

				Guarantor			Non-
Three months ended September 30, 2008	Parent			Subsidiaries			Guarantor			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	22,737		$	—		$	—		$	22,737
Third parties		—			5,437			1,663			(326	)		6,774
		—			28,174			1,663			(326	)		29,511
Operating costs and expenses:
Operations		—			10,593			766			(326	)		11,033
Depreciation and amortization		—			5,538			346			—			5,884
General and administrative		887			710			(1	)		—			1,596
		887			16,841			1,111			(326	)		18,513
Operating income (loss)		(887	)		11,333			552			—			10,998
Equity in earnings of subsidiaries		10,189			385			—			(10,574	)		—
Interest income (expense)		(2,681	)		(2,463	)		8			—			(5,136	)
Gain on sale of assets		—			—			—			—			—
Other Income		—			1,007			—			—			1,007
Minority interest		—			—			—			(164	)		(164	)
		7,508			(1,071	)		8			(10,738	)		(4,293	)
Income (loss) before income taxes		6,621			10,262			560			(10,738	)		6,705
State income tax		—			(73	)		(11	)		—			(84	)
Net income	$	6,621		$	10,189		$	549		$	(10,738	)	$	6,621

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		—			7,514			721			(296	)		7,939
Depreciation and amortization		—			3,267			327			—			3,594
General and administrative		707			586			113			—			1,406
		707			11,367			1,161			(296	)		12,939
Operating income (loss)		(707	)		14,184			797			—			14,274
Equity in earnings of subsidiaries		14,495			543			—			(15,038	)		—
Interest income (expense)		(3,098	)		(186	)		2			—			(3,282	)
Minority interest		—			—			—			(233	)		(233	)
		11,397			357			2			(15,271	)		(3,515	)
Income (loss) before income taxes		10,690			14,541			799			(15,271	)		10,759
State income tax		—			(46	)		(23	)		—			(69	)
Net income	$	10,690		$	14,495		$	776		$	(15,271	)	$	10,690

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Condensed Consolidating Statement of Income

				Guarantor			Non-
Nine months ended September 30, 2008	Parent			Subsidiaries			Guarantor			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	61,210		$	—		$	—		$	61,210
Third parties		—			16,735			6,584			(967	)		22,352
		—			77,945			6,584			(967	)		83,562
Operating costs and expenses:
Operations		—			28,908			2,804			(967	)		30,745
Depreciation and amortization		—			15,262			997			—			16,259
General and administrative		2,389			1,856			(4	)		—			4,241
		2,389			46,026			3,797			(967	)		51,245
Operating income (loss)		(2,389	)		31,919			2,787			—			32,317
Equity in earnings of subsidiaries		28,923			1,947			—			(30,870	)		—
Interest income (expense)		(8,300	)		(5,795	)		40			—			(14,055	)
Gain on sale of assets		—			36			—			—			36
Other income		—			1,007			—			—			1,007
Minority interest		—			—			—			(834	)		(834	)
		20,623			(2,805	)		40			(31,704	)		(13,846	)
Income (loss) before income taxes		18,234			29,114			2,827			(31,704	)		18,471
State income tax		—			(191	)		(46	)		—			(237	)
Net income	$	18,234		$	28,923		$	2,781		$	(31,704	)	$	18,234

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		—			22,300			2,450			(889	)		23,861
Depreciation and amortization		—			9,341			1,532			—			10,873
General and administrative		2,212			1,621			129			—			3,962
		2,212			33,262			4,111			(889	)		38,696
Operating income (loss)		(2,212	)		39,039			2,693			—			39,520
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	)
		31,342			1,678			72			(43,289	)		(10,197	)
Income (loss) before income taxes		29,130			40,717			2,765			(43,289	)		29,323
State income tax		—			(138	)		(55	)		—			(193	)
Net income	$	29,130		$	40,579		$	2,710		$	(43,289	)	$	29,130

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Condensed Consolidating Statement of Cash Flows

				Guarantor			Non-
Nine months ended September 30, 2008	Parent			Subsidiaries			Guarantor			Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities	$	(44,408	)	$	81,053		$	4,245		$	(2,800	)	$	38,090
Cash flows from investing activities
Additions to properties and equipment		—			(28,530	)		(494	)		—			(29,024	)
Acquisition of crude pipelines and tankage assets		—			(171,000	)		—			—			(171,000	)
Proceeds from sale of assets		—			36			—			—			36
		—			(199,494	)		(494	)		—			(199,988	)
Cash flows from financing activities
Net borrowings under credit agreement		9,000			186,000			—			—			195,000
Proceeds from issuance of common units		—			104			—			—			104
Distributions to partners		(38,908	)		—			(4,000	)		4,000			(38,908	)
Distributions to minority interest		—			—			—			(1,200	)		(1,200	)
Contribution from general partner		186			—			—			—			186
Purchase of units for restricted grants		(795	)		—			—			—			(795	)
Deferred financing costs		—			(692	)		—			—			(692	)
		(30,517	)		185,412			(4,000	)		2,800			153,695
Cash and cash equivalents
Increase (decrease) for the period		(74,925	)		66,971			(249	)		—			(8,203	)
Beginning of period		2			8,060			2,259			—			10,321
End of period	$	(74,923	)	$	75,031		$	2,010		$	—		$	2,118

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	$	36,647		$	(1,179	)	$	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	)
Distributions 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	)
		(36,647	)		(241	)		(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

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Note 11: Proposed Joint Ventures

In November 2007, we executed a definitive agreement with Plains to acquire a 25% joint venture interest in a new 95-mile intrastate pipeline system now under construction by Plains for the shipment of up to 120,000 bpd of crude oil into the Salt Lake City area. Under the agreement, the SLC Pipeline will be owned by a joint venture company that will be owned 75% by Plains and 25% by us. We expect to purchase our 25% interest in the joint venture in early 2009 when the SLC Pipeline is expected to become fully operational. The SLC 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 that is currently flowing on Plains’ Rocky Mountain Pipeline. The total cost of our investment in the SLC Pipeline is expected to be $28.0 million, including the $2.5 million finder’s fee that is payable to Holly upon the closing of our investment in the SLC Pipeline.

On January 31, 2008, we entered into an option agreement with Holly granting us an option to purchase all of Holly’s equity interests in a joint venture pipeline currently under construction. The pipeline will be capable of transporting refined petroleum products from Salt Lake City, Utah to Las Vegas, Nevada (the “UNEV Pipeline”). Holly currently owns 75% of the equity interests in the UNEV Pipeline. Under this agreement, we have an option to purchase Holly’s equity interests in the UNEV Pipeline, effective for a 180-day period commencing when the UNEV Pipeline becomes operational, at a purchase price equal to Holly’s investment in the joint venture pipeline plus interest at 7% per annum.

Holly is currently working on a project to delivery additional crude oils to its Navajo Refinery, including a pipeline from Slaughter, Texas to Lovington, New Mexico and pipeline from Lovington to Artesia, New Mexico. We have an understanding with Holly that we will be the operator and will have an option to purchase Holly’s investment in the projects at a purchase price to be negotiated with Holly.

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HOLLY ENERGY PARTNERS, L.P.

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

This Item 2, including but not limited to the sections on “Results of Operations” and “Liquidity and Capital Resources”, contains forward-looking statements. See “Forward-Looking Statements” at the beginning of Part I.

OVERVIEW

Holly Energy Partners, L.P. (“HEP”) is a Delaware limited partnership. We own and operate substantially all of the petroleum product and crude oil pipeline, tankage and terminalling assets that support the Holly Corporation (“Holly”) refining and marketing operations in west Texas, New Mexico, Utah, Idaho and Arizona and a 70% interest in Rio Grande Pipeline Company (“Rio Grande”). Holly currently owns a 46% interest in us.

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

On February 29, 2008, we acquired pipeline and tankage assets from Holly (the “Crude Pipelines and Tankage Assets”) for $180.0 million. The Crude Pipelines and Tankage Assets primarily consist of crude oil trunk lines and gathering lines, product and crude oil pipelines and tankage that service Holly’s Navajo and Woods Cross Refineries and a leased jet fuel terminal. Additional information on this transaction is provided under “Liquidity and Capital Resources.”

For the nine months ended September 30, 2008, our revenues were $83.6 million and our net income was $18.2 million. Our revenues and net income for the nine months ended September 30, 2007 were $78.2 million and $29.1 million, respectively. Our total operating costs and expenses for the nine months ended September 30, 2008 were $51.2 million compared to $38.7 million for the nine months ended September 30, 2007.

Agreements with Holly Corporation and Alon

As of September 30, 2008, we serve Holly’s refineries in New Mexico and Utah under three 15-year pipeline and terminal agreements. The substantial majority of our business is devoted to providing transportation, storage and terminalling services to Holly.

We have an agreement that relates to the pipelines and terminals contributed by Holly to us at the time of our initial public offering and expires in 2019 (the “Holly PTA”). Our second agreement with Holly relates to the Intermediate Pipelines acquired from Holly in July 2005 and expires in 2020 (the “Holly IPA”). Our third agreement, the Holly CPTA, relates to the Crude Pipelines and Tankage Assets acquired from Holly and expires on February 29, 2023 (collectively the “agreements”).

Under these agreements, Holly agreed to transport and store volumes of refined product and crude oil on our pipelines and terminal and tankage facilities that result in minimum annual payments to us. The agreed upon tariffs are adjusted each year on July 1 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.

We also have a 15-year pipelines and terminals agreement with Alon USA, Inc. (“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

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upon tariffs are increased or decreased annually at a rate equal to the percentage change in PPI, but not below the initial tariff rate.

Contractual minimums under our long-term service agreements are as follows:

	Minimum Annualized
	Commitment		Year of
Agreement	(In millions)		Maturity		Contract Type
Holly PTA	$	41.2		2019	Minimum revenue commitment
Holly IPA		13.3		2020	Minimum revenue commitment
Holly CPTA		26.7		2022	Minimum revenue commitment
Alon PTA		22.0		2020	Minimum volume commitment
Alon capacity lease		7.0	Various		Capacity lease
Total	$	110.2

We depend on our agreements with Holly and Alon for the majority of our revenues. A significant reduction in revenues under these agreements would have a material adverse effect on our results of operations.

In October 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 includes replacing 85 miles of 8-inch pipe with 12-inch pipe, adding 150,000 barrels of refined product storage at our El Paso Terminal, improving existing pumps, adding a tie-in to the Kinder Morgan pipeline to Tucson and Phoenix, Arizona and making related modifications. The cost of this project is estimated to be $48.3 million. Currently, we are expecting to complete this project by January 2009.

Under certain provisions of the Omnibus Agreement that we entered into with Holly in July 2004 and expires in 2019, we pay Holly an annual administrative fee for the provision by Holly or its affiliates of various general and administrative services to us. Effective March 1, 2008, the annual fee was increased from $2.1 million to $2.3 million to cover additional general and administrative services attributable to the operations of our Crude Pipelines and Tankage Assets. This fee does not include the salaries of pipeline and terminal personnel or the cost of their employee benefits which are separately charged to us by Holly. We also reimburse Holly and its affiliates for direct expenses they incur on our behalf.

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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, 2008 and 2007.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
	(In thousands, except per unit data)
Revenues
Pipelines:
Affiliates — refined product pipelines	$	10,553		$	8,815		$	28,994		$	26,464
Affiliates — intermediate pipelines		2,953			3,327			9,002			10,390
Affiliates — crude pipelines		6,776			—			15,524			—
		20,282			12,142			53,520			36,854
Third parties- refined product pipelines		5,773			8,300			19,289			26,473
		26,055			20,442			72,809			63,327
Terminals and truck loading racks:
Affiliates		2,455			2,685			7,690			8,088
Third parties		1,001			1,338			3,063			4,053
		3,456			4,023			10,753			12,141
Other — affiliates		—			2,748			—			2,748
Total revenues		29,511			27,213			83,562			78,216
Operating costs and expenses
Operations		11,033			7,939			30,745			23,861
Depreciation and amortization		5,884			3,594			16,259			10,873
General and administrative		1,596			1,406			4,241			3,962
		18,513			12,939			51,245			38,696
Operating income		10,998			14,274			32,317			39,520
Interest income		25			101			146			431
Interest expense, including amortization		(5,161	)		(3,383	)		(14,201	)		(10,112	)
Gain on sale of assets		—			—			36			298
Other income		1,007			—			1,007			—
Minority interest in Rio Grande		(164	)		(233	)		(834	)		(814	)
Income before income taxes		6,705			10,759			18,471			29,323
State income tax		(84	)		(69	)		(237	)		(193	)
Net income		6,621			10,690			18,234			29,130
Less general partner interest in net income, including incentive distributions(1)		905			794			2,526			2,100
Limited partners’ interest in net income	$	5,716		$	9,896		$	15,708		$	27,030
Net income per limited partner unit — basic and diluted(1)	$	0.35		$	0.61		$	0.96		$	1.68
Weighted average limited partners’ units outstanding		16,328			16,108			16,279			16,108
EBITDA(2)	$	17,725		$	17,635		$	48,785		$	49,877
Distributable cash flow(3)	$	15,749		$	13,683		$	43,452		$	38,666
Volumes (bpd)(4)
Pipelines:
Affiliates — refined product pipelines		79,192			71,987			79,852			75,638
Affiliates — intermediate pipelines		54,583			62,072			58,014			63,337
Affiliates — crude pipelines		132,120			—			103,465			—
		265,895			134,059			241,331			138,975
Third parties- refined product pipelines		25,046			59,024			31,635			62,877
		290,941			193,083			272,966			201,852
Terminals and truck loading racks:
Affiliates		102,128			110,545			107,611			117,957
Third parties		27,845			38,409			32,073			46,114
		129,973			148,954			139,684			164,071
Total for pipelines and terminal assets (bpd)		420,914			342,037			412,650			365,923

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(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 $0.8 million and $0.6 million were declared during the three months ended September 30, 2008 and 2007, respectively, and $2.2 million and $1.5 million during the nine months ended September 30, 2008 and 2007, 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, (ii) state income tax and (iii) depreciation and amortization. EBITDA is not a calculation based upon U.S. generally accepted accounting principles (“U.S. GAAP”). However, the amounts included in the EBITDA calculation are derived from amounts included in our consolidated financial statements. EBITDA should not be considered as an alternative to net income or operating income, as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity. EBITDA is not necessarily comparable to similarly titled measures of other companies. EBITDA is presented here because it is a widely used financial indicator used by investors and analysts to measure performance. EBITDA is also used by our management for internal analysis and as a basis for compliance with financial covenants.
	Set forth below is our calculation of EBITDA.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
	(In thousands)
Net income	$	6,621		$	10,690		$	18,234		$	29,130
Add interest expense		4,902			3,091			13,462			9,213
Add amortization of discount and deferred debt issuance costs		259			292			739			899
Subtract interest income		(25	)		(101	)		(146	)		(431	)
Add state income tax		84			69			237			193
Add depreciation and amortization		5,884			3,594			16,259			10,873
EBITDA	$	17,725		$	17,635		$	48,785		$	49,877

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

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Set forth below is our calculation of distributable cash flow.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
	(In thousands)
Net income	$	6,621		$	10,690		$	18,234		$	29,130
Add depreciation and amortization		5,884			3,594			16,259			10,873
Add amortization of discount and deferred debt issuance costs		259			292			739			899
Add (subtract) increase (decrease) in deferred revenue		3,857			120			10,638			(870	)
Subtract maintenance capital expenditures*		(872	)		(1,013	)		(2,418	)		(1,366	)
Distributable cash flow	$	15,749		$	13,683		$	43,452		$	38,666

*

Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and to extend their useful lives.

(4)

The amounts reported for the nine months ended September 30, 2008 include volumes transported on the crude pipelines for the period from March 1, 2008 through September 30, 2008 only. Volumes shipped during the months of March through September 2008 averaged 132.5 thousand barrels per day (“mbpd”). For the nine months ended September 30, 2008, crude pipeline volumes are based on volumes for the months of March through September, averaged over the 274 days in the first nine months of 2008. Under the Holly CPTA, fees are based on volumes transported on each pipeline component comprising the crude pipeline system (the crude oil gathering pipelines and the crude oil trunk lines). Accordingly, volumes transported on the crude pipelines represent the sum of volumes transported on both pipeline components. In cases where volumes are transported over both components of the crude pipeline system, such volumes are reflected twice in the total crude oil pipeline volumes.

	September 30,			December 31,
	2008			2007
	(In thousands)
Balance Sheet Data
Cash and cash equivalents	$	2,118		$	10,321
Working capital(5)	$	(27,560	)	$	5,446
Total assets	$	430,086		$	238,904
Long-term debt	$	354,522		$	181,435
Partners’ equity	$	17,585		$	27,816

(5) Reflects $24.0 million of short-term borrowings that were classified as current liabilities at September 30, 2008.

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

Results of Operations — Three Months Ended September 30, 2008 Compared with Three Months Ended September 30, 2007

Summary

Net income for the three months ended September 30, 2008 was $6.6 million, a $4.1 million decrease compared to the same period in 2007. This decrease was due principally the effects of limited production at Alon’s Big Spring Refinery resulting from an explosion and fire in February and an increase in operating costs and expenses and interest expense. These factors were partially offset by revenues

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attributable to our crude pipeline assets acquired in the first quarter of 2008 and an increase in previously deferred revenue realized. Revenue of $5.2 million relating to deficiency payments associated with certain guaranteed shipping contracts was deferred during the three months ended September 30, 2008. 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.

On February 18, 2008, Alon experienced an explosion and fire at its Big Spring refinery that resulted in the shutdown of production. In early April, Alon reopened its Big Spring refinery and resumed production at about one-half of refining capacity until late September when production was restored to full capacity. Lost production and reduced operations attributable to this incident resulted in a decrease in third party shipments on our refined product pipelines during the first nine months of 2008. Under our pipelines and terminals agreement with Alon, Alon has committed to a level of product shipments that generally results in a minimum level of annual revenue. If Alon does not meet their minimum commitments, we bill them quarterly an amount related to such shortfalls. Although these shortfall billings are required to be recorded as deferred revenues, such shortfall billings are included in our distributable cash flow as they occur. Deferred revenue amounts are later recognized as revenue and included in net income when no longer subject to recapture. This typically occurs within one year after the shortfall occurs and does not affect distributable cash flow.

Revenues

Total revenues for the three months ended September 30, 2008 were $29.5 million, a $2.3 million increase compared to the three months ended September 30, 2007. This increase was due principally to revenues attributable to our crude pipeline and tankage assets acquired in the first quarter of 2008, an increase in affiliate refined product pipeline shipments, the effect of tariff increases and a net increase in previously deferred revenue realized. These increases were partially offset by the effects of limited production at Alon’s Big Spring Refinery resulting from an explosion and fire in February and a decrease in shipments on our intermediate pipeline system. Also affecting our revenue comparison was 2007 third quarter revenue of $2.7 million related to our sale of inventory of accumulated overages of refined products at our terminals. There was no comparable revenue for the current year’s third quarter.

Revenues from our refined product pipelines were $16.3 million, a decrease of $0.8 million compared to the third quarter of 2007. This decrease was due principally to a decline in third party refined product pipeline shipments during the third quarter. This decrease was partially offset by an increase in affiliate refined product pipeline shipments, the effect of the annual tariff increase on refined product shipments and a $0.3 million increase in previously deferred revenue realized. Shipments on our refined product pipeline system decreased to an average of 104.2 mbpd compared to 131.0 mbpd for the same period last year.

Revenues from the intermediate pipelines were $3.0 million, a decrease of $0.4 million compared to the third quarter of 2007. This decrease was due to a decline in volumes shipped on our intermediate pipelines and a $0.1 million decrease in previously deferred revenue realized. These decreases were partially offset by the effect of the annual tariff increase on intermediate pipeline shipments. Shipments on our intermediate product pipeline system decreased to an average of 54.6 mbpd compared to 62.1 mbpd for the same period last year.

Revenues from our crude pipelines were $6.8 million; third quarter shipments averaged 132.1 mbpd.

Revenues from terminal, tankage and truck loading rack fees were $3.5 million, a decrease of $0.6 million compared to the third quarter of 2007. Refined products terminalled in our facilities decreased to an averaged 130.0 mbpd compared to 149.0 mbpd for the same period last year.

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. These overages arose from net product gains at our terminals from the beginning of 2005 through the third quarter of 2007. In the fourth quarter of 2007, we amended our pipelines and terminals agreement with Holly to provide that, on a go-forward basis, such terminal overages of refined product belong to Holly.

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Operating Costs

Operations expense for three months ended September 30, 2008 increased by $3.1 million compared to the three months ended September 30, 2007. This increase was due principally to the operations of our crude pipelines commencing March 1, 2008 and increased pipeline maintenance and payroll costs.

Depreciation and Amortization

Depreciation and amortization for the three months ended September 30, 2008 increased by $2.3 million compared to the three months ended September 30, 2007, due principally to depreciation and amortization attributable to our newly acquired crude pipelines, tankage assets and transportation agreement.

General and Administrative

General and administrative costs for the three months ended September 30, 2008 increased by $0.2 million compared to the three months ended September 30, 2007.

Interest Expense

Interest expense for the three months ended September 30, 2008 totaled $5.2 million, an increase of $1.8 million compared to the three months ended September 30, 2007. This increase is due principally to interest attributable to advances from our revolving credit agreement that were used to finance our crude pipeline asset purchase in the first quarter as well as capital projects. For the three months ended September 30, 2008, our aggregate effective interest rate was 5.5% compared to 7.3% for the same period last year.

Other Income

Other income of $1.0 million for the three months ended September 30, 2008 represents a reimbursement from Alon for certain pipeline repair and maintenance costs that were incurred and expensed over a two year period.

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 $0.2 million for each of the three months ended September 30, 2008 and 2007.

State Income Tax

State income taxes were $0.1 million for each of the three months ended September 30, 2008 and 2007.

Results of Operations — Nine Months Ended September 30, 2008 Compared with Nine Months Ended September 30, 2007

Summary

Net income for the nine months ended September 30, 2008 was $18.2 million, a $10.9 million decrease compared to the same period in 2007. This decrease was due principally to the effects of limited production at Alon’s Big Spring Refinery resulting from an explosion and fire in February, a decrease in intermediate pipeline revenue as a result of downtime at Holly’s Navajo Refinery in the second quarter, a net decrease in previously deferred revenue realized and an increase in operating costs and expenses and interest expense. These factors were partially offset by revenues attributable to our crude pipeline assets that were acquired in the first quarter of 2008. Revenue of $13.9 million relating to deficiency payments associated with certain transportation contracts was deferred during the nine months ended September 30, 2008. Such revenue will be recognized in future periods either as payment for shipments in excess of minimum required levels or when shipping rights expire unused after a twelve-month period.

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Revenues

Total revenues for the nine months ended September 30, 2008 were $83.6 million, a $5.3 million increase compared to the nine months ended September 30, 2007. This increase was due principally to revenues attributable to our crude pipeline assets acquired in the first quarter of 2008 and an increase in affiliate refined product shipments and the effect of tariff increases. These increases were partially offset by a decrease in third party shipments, a decrease in shipments on our intermediate pipeline system and a net decrease in previously deferred revenue realized. Also affecting our revenue comparison was 2007 third quarter revenue of $2.7 million related to our sale of inventory of accumulated overages of refined products at our terminals. There was no comparable revenue for the current year-to-date period.

Revenues from our refined product pipelines were $48.3 million, a decrease of $4.7 million compared to the nine months ended September 30, 2007. This decrease was due to a decline in third party shipments as a result of reduced production and downtime following an explosion at Alon’s Big Spring refinery during the first quarter. This decrease was partially offset by an increase in affiliate shipments, the effect of the annual tariff increase on refined product shipments and a $0.2 million increase in previously deferred revenue realized. Overall shipments on our refined product pipeline system decreased to an average of 111.5 mbpd compared to 138.5 mbpd for the same period last year.

Revenues from our intermediate pipelines were $9.0 million, a decrease of $1.4 million compared to the nine months ended September 30, 2007. This decrease was due to the effects of downtime at Holly’s Navajo Refinery during the second quarter of 2008 and a $1.0 million decrease in previously deferred revenue realized. These decreases were partially offset by the effect of the annual tariff increase on intermediate pipeline shipments. Shipments on our intermediate product pipeline system decreased to an average of 58.0 mbpd compared to 63.3 mbpd for the same period last year.

Revenues from our crude pipelines were $15.5 million; for the months of March through September 2008 shipments averaged 132.5 mbpd.

Revenues from terminal, tankage and truck loading rack fees were $10.8 million, a decrease of $1.4 million compared to the nine months ended September 30, 2007. Refined products terminalled in our facilities decreased to an average of 139.7 mbpd compared to 164.1 mbpd for the same period last year.

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 for the nine months ended September 30, 2008 increased by $6.9 million compared to the nine months ended September 30, 2007. This increase in expense was due principally to the operations of our crude pipelines commencing March 1, 2008 and increased pipeline maintenance and payroll costs.

Depreciation and Amortization

Depreciation and amortization for the nine months ended September 30, 2008 increased by $5.4 million compared to the nine months ended September 30, 2007, due principally to depreciation and amortization attributable to our newly acquired crude pipelines, tankage assets and transportation agreement.

General and Administrative

General and administrative costs for the nine months ended September 30, 2008 increased by $0.3 million compared to the nine months ended September 30, 2007.

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Interest Expense

Interest expense for the nine months ended September 30, 2008 totaled $14.2 million, an increase of $4.1 million compared to the nine months ended September 30, 2007. This increase is due principally to interest attributable to advances from our revolving credit agreement that were used to finance our crude pipeline asset purchase in the first quarter as well as capital projects. For the nine months ended September 30, 2008, our aggregate effective interest rate was 5.4% compared to 7.3% for the same period last year.

Other Income

Other income of $1.0 million for the nine months ended September 30, 2008 represents a reimbursement from Alon for certain pipeline repair and maintenance costs that were incurred and expensed over a two year period.

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 each of the nine months ended September 30, 2008 and 2007.

State Income Tax

State income taxes were $0.2 million for each of the nine months ended September 30, 2008 and 2007.

LIQUIDITY AND CAPITAL RESOURCES

Overview

In February 2008, we amended our $100 million senior secured revolving credit agreement expiring in August 2011 to increase the size from $100 million to $300 million (the “Credit Agreement”), which we used to finance the $171.0 million cash portion of the consideration paid for the Crude Pipelines and Tankage Assets acquired from Holly. As of September 30, 2008, we had $195.0 million outstanding under the Credit Agreement. The Credit Agreement is available to fund capital expenditures, acquisitions, and working capital and for general partnership purposes. Advances under the Credit Agreement that are either designated for working capital or have been used as interim financing to fund capital expenditures are classified as short-term liabilities. Other advances under the Credit Agreement are classified as long-term liabilities. During the nine months ended September 30, 2008, we received net advances totaling $24.0 million under the Credit Agreement that were used as interim financing for capital expenditures.

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

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. We intend to renew our registration statement prior to its expiration date of December 1, 2008.

We believe our current cash balances, future internally-generated funds and funds available under our Credit Agreement will provide sufficient resources to meet our working capital liquidity needs for the foreseeable future. With the current conditions in the credit and equity markets, there may be limits on

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our ability to issue new debt or equity financing. Additionally, due to pricing in the current debt and equity markets, we may not be able to issue new debt and equity at acceptable pricing. As a result, our ability to fund certain of our planned capital expenditures and other business opportunities may be limited.

In February, May and August 2008, we paid regular cash distributions of $0.725, $0.735 and $0.745, respectively, on all units, an aggregate amount of $38.9 million. Included in these distributions was an aggregate of $2.2 million paid to the general partner as incentive distributions.

Cash and cash equivalents decreased by $8.2 million during the nine months ended September 30, 2008. The cash flows used for investing activities of $200.0 million exceeded cash flows provided by operating and financing activities of $38.1 million and $153.7 million, respectively. Working capital for the nine months ended September 30, 2008 decreased by $33.0 million due principally to $24.0 million in interim financing of capital projects.

Cash Flows — Operating Activities

Cash flows from operating activities were $38.1 million for each of the nine months ended September 30, 2008 and 2007. Additional cash collections of $8.5 million from our major customers were offset by miscellaneous year-over-year changes in collections and payments including payments related to the operations of our crude pipeline system acquired in the first quarter of 2008.

As discussed above, our major shippers are obligated to make deficiency payments to us if they do not meet their minimum volume shipping obligations. Certain of these shippers then have the right to recapture these amounts if future volumes exceed minimum levels. During the first nine months of 2008, we received cash payments of $9.3 million under these commitments. We billed $3.4 million in the first nine months of 2007 related to shortfalls that occurred during this period that expired without recapture and was recognized as revenue during the nine months ended September 30, 2008. Another $5.2 million is included in our accounts receivable at September 30, 2008 related to shortfalls that occurred in the third quarter of 2008.

Cash Flows — Investing Activities

Cash flows used for investing activities increased by $197.2 million from $2.8 million for the nine months ended September 30, 2007 to $200.0 million for the nine months ended September 30, 2008. Additions to properties and equipment for the nine months ended September 30, 2008 were $29.0 million, an increase of $25.9 million from $3.1 million for the nine months ended September 30, 2007. Also during the nine months ended September 30, 2008, we acquired the Crude Pipelines and Tankage Assets from Holly. The cash consideration paid upon closing of this purchase was $171.0 million. During the nine months ended September 30, 2007, we received cash proceeds of $0.3 million upon the sale of certain assets.

Cash Flows — Financing Activities

Cash flows provided by financing activities were $153.7 million for the nine months ended September 30, 2008 compared to cash flows used for $38.2 million for the nine months ended September 30, 2007. During the nine months ended September 30, 2008, we had net borrowings of $195.0 million under the Credit Agreement of which $171.0 million was used to finance the cash portion of the consideration paid to acquire the Crude Pipelines and Tankage Assets on February 29, 2008. During the first nine months of 2008, we paid cash distributions on all units and the general partner interest in the aggregate amount of $38.9 million, an increase of $3.3 million from $35.6 million in distributions paid during the first nine months of 2007. We also paid $1.2 million in minority interest distributions, a decrease of $0.1 million compared to the nine months ended September 30, 2007. Cash paid for the purchases of units for restricted grants was $0.8 million for the nine months ended September 30, 2008, a decrease of $0.3 million from $1.1 million for the nine months ended September 30, 2007. Also for the nine months ended September 30, 2008, we paid $0.7 million in deferred financing costs that were attributable to our amended credit agreement.

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Capital Requirements

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

Each year the 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. Our total capital budget for 2008 is $53.7 million. This consists of budgeted costs for our South System expansion discussed below and other capital expansion and maintenance projects.

In October 2007, we entered into an agreement with Holly that amends the Holly PTA under which we have agreed to expand our South System between Artesia, New Mexico and El Paso, Texas. The expansion of the South System includes replacing 85 miles of 8-inch pipe with 12-inch pipe, adding 150,000 barrels of refined product storage at our El Paso Terminal, improving existing pumps, adding a tie-in to the Kinder Morgan pipeline to Tucson and Phoenix, Arizona, and making related modifications. The cost of this project is estimated to be $48.3 million. Currently, we are expecting to have the majority of this project complete in early 2009.

In November 2007, we executed a definitive agreement with Plains All American Pipeline, L.P. (“Plains”) to acquire a 25% joint venture interest in a new 95-mile intrastate pipeline system now under construction by Plains for the shipment of up to 120,000 bpd of crude oil into the Salt Lake City area (the “SLC Pipeline”). Under the agreement, the SLC Pipeline will be owned by a joint venture company that will be owned 75% by Plains and 25% by us. We expect to purchase our 25% interest in the joint venture in early 2009 when the SLC Pipeline is expected to become fully operational. The SLC 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 that is currently flowing on Plains’ Rocky Mountain Pipeline. The total cost of our investment in the SLC Pipeline is expected to be $28.0 million, including a $2.5 million finder’s fee that is payable to Holly upon the closing of our investment in the SLC Pipeline.

On January 31, 2008, we entered into an option agreement with Holly, granting us an option to purchase all of Holly’s equity interests in a joint venture pipeline currently under construction. The pipeline will be capable of transporting refined petroleum products from Salt Lake City, Utah to Las Vegas, Nevada (the “UNEV Pipeline”). Holly currently owns 75% of the equity interests in the UNEV Pipeline. Under this agreement, we have an option to purchase Holly’s equity interests in the UNEV Pipeline, effective for a 180-day period commencing when the UNEV Pipeline becomes operational, at a purchase price equal to Holly’s investment in the joint venture pipeline, plus interest at 7% per annum. The initial capacity of the pipeline will be 62,000 bpd, with the capacity for further expansion to 120,000 bpd. The total cost of the pipeline project including terminals is expected to be $300.0 million. Holly’s share of this cost is $225.0 million. Construction of this project is currently expected to be completed and the project to become operational in early 2010. On July 17, 2008, Holly announced the purchase of Musket Corporation’s Cedar City, Utah terminal and rail facilities that will serve as part of the UNEV Pipeline’s Cedar City Terminal.

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Holly is currently working on a project to delivery additional crude oils to its Navajo Refinery, including a 70-mile pipeline from Slaughter, Texas to Lovington, New Mexico, and a 65-mile pipeline from Lovington to Artesia, New Mexico. 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 at a purchase price to be negotiated with Holly. The projects will increase the pipeline capacity between Lovington and Artesia by 25,000 bpd. The cost of the projects is expected to be $83.0 million and construction is currently expected to be completed and the projects to become fully operational in the third quarter of 2009.

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

We expect that our currently planned expenditures for sustaining and maintenance capital as well as expenditures for acquisitions and capital development projects such as the UNEV Pipeline, SLC Pipeline, South System expansion and Holly crude oil projects described above will be funded with existing cash balances, cash generated by operations, the sale of additional limited partner units, the issuance of debt securities and advances under our $300 million senior secured revolving credit agreement maturing August 2011. With the current conditions in the credit and equity markets there may be limits on our ability to issue new debt or equity financing. Additionally, due to pricing in the current debt and equity markets, we may not be able to issue new debt and equity at acceptable pricing. Without additional capital beyond amounts available under the Credit Agreement, our ability to fund some of these capital projects may be limited, especially the UNEV Pipeline and Holly’s crude oil project. Although we are not obligated to purchase these assets, if we choose to exercise our purchase options, unfavorable market conditions may affect our decision to capitalize on these business opportunities.

Credit Agreement

In February 2008, we amended our $100 million senior secured revolving credit agreement expiring in August 2011 to increase the size from $100 million to $300 million, which we used to finance the $171.0 million cash portion of the consideration paid for the Crude Pipelines and Tankage Assets acquired from Holly. Union Bank of California, N.A. is one of the lenders and serves as administrative agent under this agreement. As of September 30, 2008 and December 31, 2007, we had $195.0 million and zero, respectively, outstanding under the Credit Agreement.

There are currently a total of thirteen lenders under the $300 million credit agreement with individual commitments ranging from $15 million to $40 million. If any particular lender could not honor its commitment, we believe the unused capacity under our credit agreement, which is $105.0 million as of September 30, 2008, would be available to meet our borrowing needs. Additionally, we have reviewed publicly available information on our lenders in order to review and monitor their financial stability and assess their ongoing ability to honor their commitments under the credit agreement. We have not, nor do we expect to, experience any difficulty in the lenders’ ability to honor their respective commitments, and if it were to become necessary, we believe there would be alternative lenders or options available.

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 either designated for working capital or have been used as interim financing to fund capital expenditures are classified as 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 and to fund distributions to unitholders up to a $20.0 million sub-limit. During the nine months ended September 30, 2008, we received net advances totaling $24.0 million under the Credit Agreement that were used as interim financing for capital expenditures.

We have the right to request an increase in the maximum amount of the Credit Agreement, up to $370.0 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

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guaranteed by our wholly-owned subsidiaries. However, any recourse to HEP Logistics Holdings, L.P. would be limited to the extent of their assets, which other than their investment in HEP, are not significant.

We may prepay all loans at any time without penalty, except for payment of certain breakage and related costs. We are required to reduce all working capital borrowings under the Credit Agreement to zero for a period of at least 15 consecutive days in each twelve-month period prior to the maturity date of the agreement.

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. At September 30, 2008, we are subject to the 0.375% rate on the $105.0 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 on us, including: a prohibition against distribution to unitholders if, before or after the distribution, a potential default or an event of default as defined in the agreement would occur; limitations on our ability to incur debt, make loans, acquire other companies, change the nature of our business, enter a merger or consolidation, or sell assets; and covenants that require maintenance of a specified EBITDA to interest expense ratio and debt to EBITDA ratio. If an event of default exists under the agreement, the lenders will be able to accelerate the maturity of the debt and exercise other rights and remedies.

Senior Notes Due 2015

Our 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.

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

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

	September 30,			December 31,
	2008			2007
	(In thousands)
Credit Agreement	$	195,000		$	—
Senior Notes
Principal		185,000			185,000
Unamortized discount		(2,439	)		(2,724	)
Fair value hedge — interest rate swap		961			(841	)
		183,522			181,435
Total Debt		378,522			181,435
Less short-term borrowing under credit agreement		24,000			—
Total long-term debt	$	354,522		$	181,435

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

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Holly Crude Pipelines and Tankage Transaction

On February 29, 2008, we acquired pipeline and tankage assets from Holly for $180.0 million. The Crude Pipelines and Tankage Assets consist of crude oil trunk lines that deliver crude to Holly’s Navajo Refinery in southeast New Mexico, gathering and connection pipelines located in west Texas and New Mexico, on-site crude tankage located within the Navajo and Woods Cross refinery complexes, a jet fuel products pipeline and leased terminal between Artesia and Roswell, New Mexico, and crude oil and product pipelines that support Holly’s Woods Cross Refinery.

The consideration paid for the Crude Pipelines and Tankage Assets consisted of $171.0 million in cash and 217,497 of our common units having a fair value of $9.0 million. We financed the $171.0 million cash portion of the consideration through borrowings under our Credit Agreement expiring August 2011.

The consideration paid for the Crude Pipeline and Tankage Assets was allocated to the individual assets acquired based on their estimated fair values. In accounting for this acquisition, we recorded pipeline and terminal assets of $108.0 million and an intangible asset of $72.0 million, representing the allocated value of the 15-year Holly CPTA. This intangible asset is included in “Transportation agreements, net” in our consolidated balance sheets.

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, 2008 and 2007.

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 and crude oil is subject to stringent and complex federal, state, and local laws and regulations governing the discharge of materials into the environment, or otherwise relating to the protection of the environment. As with the industry generally, compliance with existing and anticipated laws and regulations increases our overall cost of business, including our capital costs to construct, maintain, and upgrade equipment and facilities. While these laws and regulations affect our maintenance capital expenditures and net income, we believe that they do not affect our competitive position in that the operations of our competitors are similarly affected. We believe that our operations are in substantial compliance with applicable environmental laws and regulations. However, these laws and regulations, and the interpretation or enforcement thereof, are subject to frequent change by regulatory authorities, and we are unable to predict the ongoing cost to us of complying with these laws and regulations or the future impact of these laws and regulations on our operations. Violation of environmental laws, regulations, and permits can result in the imposition of significant administrative, civil and criminal penalties, injunctions, and construction bans or delays. A discharge of hydrocarbons or hazardous substances into the environment could, to the extent the event is not insured, subject us to substantial expense, including both the cost to comply with applicable laws and regulations and claims made by employees, neighboring landowners and other third parties for personal injury and property damage.

In connection with our acquisition of the Crude Pipelines and Tankage Assets on February 29, 2008, Holly amended the Omnibus Agreement to provide $7.5 million of indemnification for environmental noncompliance and remediation liabilities associated with the newly acquired assets for a period of up to fifteen years. The Omnibus Agreement also provides environmental indemnification for the assets transferred to us at the time of our initial public offering in 2004 of $15.0 million and the Intermediate Pipelines acquired in July 2005 of $2.5 million. The indemnification relates to environmental noncompliance and remediation liabilities associated with the assets acquired from Holly that occurred or existed prior to our acquisition. We also have an environmental agreement with Alon with respect to pre-closing environmental costs and liabilities relating to the pipelines and terminals acquired from Alon in February 2005.

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In the third quarter of 2008, we discovered a crude oil leak on a section of pipeline recently acquired from Holly. We have initiated clean-up activities and have accrued $0.2 million for estimated future remediation costs. Currently, we are evaluating the duration of the leak to determine whether this event occurred prior to our acquisition and therefore subject to indemnification from Holly.

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

CRITICAL ACCOUNTING POLICIES

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

Our significant accounting policies are described in “Item 7. Management’s Discussion and Analysis of Financial Condition and Operations — Critical Accounting Policies” in our Annual Report on Form 10-K for the year ended December 31, 2007. 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 2008.

Recent Accounting Pronouncements

Statement of Financial Accounting Standards (“SFAS”) No. 157 “Fair Value Measurements"
In September 2006, the Financial Accounting Standards Board issued SFAS No. 157, Fair Value Measurements. This standard simplifies and codifies guidance on fair value measurements under generally accepted accounting principles. This standard defines fair value, establishes a framework for measuring fair value and prescribes expanded disclosures about fair value measurements. It also establishes a fair value hierarchy that categorizes inputs used in fair value measurements into three broad levels. Under this hierarchy, quoted prices in active markets for identical assets or liabilities are considered the most reliable evidence of fair value and are given the highest priority level (level 1). Unobservable inputs are considered the least reliable and are given the lowest priority level (level 3). We adopted this standard effective January 1, 2008.

We have interest rate swaps that we measure at fair value on a recurring basis using level 2 inputs. See Risk Management below for additional information on these swaps.

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

In March 2008, the FASB ratified Emerging Issues Task Force (“EITF”) Issue No. 07-04, Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships (“MLP’s). This standard provides guidance in the application of the two-class method in computing earnings per unit to reflect an MLP’s contractual obligation to make distributions to the general partner, limited partners, and incentive distribution rights holder. EITF No. 07-04 is effective for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. We will adopt this standard effective January 1, 2009. We do not anticipate that the adoption of this standard will have a material effect on our financial condition, results of operations and cash flows.

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

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In June 2006, the FASB issued FSP No. 03-6-1, Determining Whether Instruments Granted in Share-Based Transactions Are Participating Securities. This standard provides guidance in determining whether unvested instruments granted under share-based payment transactions are participating securities and, therefore, should be included in earnings per share calculations under the two-class method provided under FASB No. 128, Earnings per Share. FSP No. 03-6-1 is effective for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. We will adopt this standard effective January 1, 2009. We do not anticipate that the adoption of this standard will have a material effect on our financial condition, results of operations and cash flows.

RISK MANAGEMENT

As of September 30, 2008, we have two interest rate swap contracts.

We entered into an interest rate swap to hedge our exposure to the cash flow risk caused by the effects of LIBOR changes on the $171.0 million Credit Agreement advance that we used to finance our purchase of the Crude Pipelines and Tankage Assets from Holly. This interest rate swap effectively converts our $171.0 million LIBOR based debt to fixed rate debt having an interest rate of 3.74% plus an applicable margin, currently 2.0%, which equaled an effective interest rate of 5.74% as of September 30, 2008. The maturity date of this swap contract is February 28, 2013. We intend to renew our Credit Agreement prior to its expiration in August 2011 and continue to finance the $171.0 million balance until the swap matures.

We have designated this interest rate swap as a cash flow hedge. Based on our assessment of effectiveness using the change in variable cash flows method, we have determined that this interest rate swap is effective in offsetting the variability in interest payments on our $171.0 million variable rate debt resulting from changes in LIBOR. Under hedge accounting, we adjust our cash flow hedge on a quarterly basis to its fair value with a corresponding offset to accumulated other comprehensive income. Also on a quarterly basis, we measure hedge effectiveness by comparing the present value of the cumulative change in the expected future interest to be paid or received on the variable leg of our swap against the expected future interest payments on our $171.0 million variable rate debt. Any ineffectiveness is reclassified from accumulated other comprehensive income to interest expense. As of September 30, 2008, we had no ineffectiveness on our cash flow hedge.

We also have an interest rate swap contract that effectively converts interest expense associated with $60.0 million of our 6.25% Senior Notes from a fixed to a variable rate. Under this swap contract, interest on the $60.0 million notional amount is computed using the three-month LIBOR plus an applicable margin of 1.1575%, which equaled an effective interest rate of 3.97% as of September 30, 2008. The maturity date of this 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 and meets the requirements to assume no ineffectiveness. Accordingly, we use the “shortcut” method of accounting. Under this method, we adjust the carrying value of the swap to its fair value on a quarterly basis, with an offsetting entry to our Senior Notes, effectively adjusting the carrying value of $60.0 million of principal on the Senior notes to its fair value.

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

Additional information on our interest rate swaps as of September 30, 2008 are as follows:

		Fair Value	Location of Offsetting
Interest Rate Swaps	Balance Sheet Location	(In thousands)	Balance
Cash flow hedge - $171 million LIBOR based debt	Other assets	$825	Accumulated other comprehensive income
Fair value hedge - $60 million of 6.25% Senior Notes	Other assets	$961	Long-term debt

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In October we entered into an additional interest rate swap contract to effectively convert our existing swap on $60.0 million of our Senior Notes as discussed above from variable rate debt back to fixed rate debt.

We have reviewed publicly available information on our counterparties in order to review and monitor their financial stability and assess their ongoing ability to honor their commitments under the interest rate swap contracts. We have not, nor do we expect to experience any difficulty in the counterparties honoring their respective commitments.

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, 2008, 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, 2008 would result in a change of approximately $5.2 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, 2008, our cash and cash equivalents included highly liquid investments with a maturity of three months or less at the time of purchase. Due to the short-term nature of our cash and cash equivalents, a hypothetical 10% increase in interest rates would not have a material effect on the fair market value of our portfolio. Since we have the ability to liquidate this portfolio, we do not expect our operating results or cash flows to be materially affected to any significant degree by the effect of a sudden change in market interest rates on our investment portfolio.

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

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

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Item 3.Quantitative and Qualitative Disclosures About Market Risks

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

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

Item 4.Controls and Procedures

(a)Evaluation of disclosure controls and procedures

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

(b) Changes in internal control over financial reporting

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

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PART II. OTHER INFORMATION

Item 1.Legal proceedings

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

Item 2.Unregistered Sales of Securities and Use of Proceeds

(c) Common unit repurchases made in the quarter

In the third quarter of 2008, we paid $0.3 million for the purchase of 8,186 of our common units in the open market for the recipients of our 2008 restricted unit grants.

							Maximum Number
					Total Number of		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 2008		—	$	—		—		—
August 2008		—	$	—		—		—
September 2008		8,186	$	34.34		—		—
Total		8,186	$	34.34		—

Item 6.Exhibits

10.1* Amendment No. 2 to Amended and Restated Credit Agreement, dated September 8, 2008, between Holly Energy Partners — Operating, L.P., certain of its subsidiaries acting as guarantors, Union Bank of California, N.A., as administrative agent, issuing bank and sole lead arranger and certain other lenders.

12.1*	Computation of Ratio of Earnings to Fixed Charges.
31.1*	Certification of Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Certification of Chief Executive Officer under Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*	Certification of Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act of 2002.

* Filed herewith

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HOLLY ENERGY PARTNERS, L.P.

SIGNATURES

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

HOLLY ENERGY PARTNERS, L.P.
(Registrant)
By:	HEP LOGISTICS HOLDINGS, L.P.
its General Partner
By:	HOLLY LOGISTIC SERVICES, L.L.C.
its General Partner

Date: October 31, 2008	/s/ Bruce R. Shaw
	Bruce R. Shaw
	Senior Vice President and Chief Financial Officer (Principal Financial Officer)
	/s/ Scott C. Surplus
	Scott C. Surplus
	Vice President and Controller (Principal Accounting Officer)

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