Holly Energy Partners (HEP) 8-K Holly Energy Partners, L.P. Reports Fourth Quarter Results

Exhibit 99.1

Press Release
February 3, 2009

Holly Energy Partners, L.P. Reports Fourth Quarter Results

Dallas, Texas — Holly Energy Partners, L.P. (NYSE-HEP) today reported its financial results for the fourth quarter of 2008. Distributable cash flow for the fourth quarter was $16.9 million, up $4.6 million or 37% from the same period last year. For the year ended December 31, 2008 distributable cash flow was $60.4 million, up $9.4 million or 18% from the same period last year.

Net income for the fourth quarter of 2008 was $7.1 million ($0.37 per basic and diluted limited partner unit) compared to $10.1 million ($0.58 per basic and diluted limited partner unit) for the same period of 2007. Net income includes $2.3 million of non-cash interest expense related to changes in fair value of certain interest rate swaps. For the year ended December 31, 2008, net income was $25.4 million ($1.34 per basic and diluted limited partner unit) compared to $39.3 million ($2.26 per basic and diluted limited partner unit) for the same period of 2007.

The strength of our distributable cash flow relative to our net income when comparing our 2008 results to 2007 is due to the contractual minimum commitments that we have in place with our shippers. Under our transportation agreements, Holly Corporation subsidiaries and Alon USA, Inc. are obligated to ship product volumes that generally result in a minimum level of billings. If these shippers do 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. At December 31, 2008, we had $15.7 million in deferred revenue as a result of such shortfall billings in 2008.

Commenting on the fourth quarter results for 2008, Matt Clifton, Chairman of the Board and Chief Executive Officer stated, “Our fourth quarter EBITDA and distributable cash flow were at record quarterly levels with each increasing $4.6 million or 27% and 37% over the same period in 2007, respectively. Additionally revenues improved for the quarter from those levels reported during the first nine months of 2008 as Alon’s Big Spring refinery returned to normal operating levels. Cash flows from our crude pipeline and tankage assets acquired in the first quarter contributed greatly to the increase in our distributable cash flow in the current year. I am pleased with our performance during the quarter that allowed us to increase our fourth quarter distribution to $0.765 per unit, representing our sixteenth consecutive quarterly increase and a 6% increase over our distribution for the fourth quarter of 2007. We believe this performance in turbulent times underscores both the stability of our fee-based income and the fiscally prudent nature of our past growth initiatives. Looking forward, the 85,000 bpd to 100,000 bpd capacity expansion upgrade to Holly’s Navajo Refinery will be completed and tied in during Holly’s first quarter 2009 planned maintenance turnaround. It is expected that increased crude oil deliveries to and increased production from the Navajo Refinery should have a positive impact on our transported crude oil and product volumes beginning in the second quarter of 2009. Higher revenues from increased movements on our existing pipelines will provide another opportunity to continue our growth trajectory in distributable cash flow.”

Total revenues for the fourth quarter of 2008 were $34.5 million, a $7.3 million increase compared to the three months ended December 31, 2007. This increase was due 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 and the effect of tariff increases on pipeline shipments. These increases were partially offset by a decrease in third party refined product shipments, a decrease in shipments on our intermediate pipeline system and a decrease in previously deferred revenue realized.

• Revenues from our refined product pipelines were $20.7 million, an increase of $1.1 million compared to the fourth quarter of 2007. This increase was due to an increase in affiliate shipments on our refined product system and the effect of the annual tariff increase on refined product shipments. These increases were partially offset by a decline in third party refined product pipeline shipments and a $0.7 million decrease in previously deferred revenue realized. Shipments on our refined product pipeline system increased to an average of 151.5 thousand barrels per day (“mbpd”) compared to 145.0 mbpd for the same period last year.

• Revenues from our intermediate pipelines were $2.9 million, a decrease of $0.4 million compared to the fourth quarter of 2007. This decrease was due to a decline in volumes shipped on our intermediate pipelines and a $0.2 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 61.4 mbpd compared to 70.0 mbpd for the same period last year.

• We acquired crude oil and product pipeline and tankage assets from subsidiaries of Holly Corporation on February 29, 2008 that service Holly’s Navajo Refinery in southeast New Mexico and Woods Cross Refinery in Woods Cross, Utah. Revenues from our crude pipelines were $6.9 million; fourth quarter shipments averaged 135.1 mbpd.

• Revenues from terminal, tankage and truck loading rack fees were $4.0 million, a decrease of $0.2 million compared to the fourth quarter of 2007.

Total revenues for the year ended December 31, 2008 were $118.1 million, a $12.7 million increase compared to the year ended December 31, 2007. This increase was due to revenues attributable to our crude pipeline and tankage assets acquired on February 29, 2008, an increase in affiliate refined product pipeline shipments and the effect of tariff increases. 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, a decrease in shipments on our intermediate pipeline system and a decrease in previously deferred revenue realized. (See discussion of Alon’s Big Spring Refinery below.) Also affecting our current year revenue comparison was other revenue of $2.7 million in 2007 that related to our sale of inventory of accumulated overages of refined products at our terminals. There was no comparable revenue for the year ended December 31, 2008.

• Revenues from our refined product pipelines were $69.0 million, a decrease of $3.5 million compared to the year ended December 31, 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 and a $0.5 million decrease in previously deferred revenue realized. These decreases were partially offset by an increase in affiliate shipments and the effect of the annual tariff increase on refined product shipments. Overall shipments on our refined product pipeline system decreased to an average of 121.5 mbpd compared to 140.2 mbpd for the same period last year.

• Revenues from our intermediate pipelines were $11.9 million, a decrease of $1.8 million compared to the year ended December 31, 2007. This decrease was due to the effects of downtime at Holly’s Navajo Refinery during the second quarter of 2008 and a $1.2 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 58.9 mbpd compared to 65.0 mbpd for the same period last year.

• Revenues from our crude pipelines were $22.4 million; shipments for the months of March through December 2008 averaged 133.3 mbpd.

• Revenues from terminal, tankage and truck loading rack fees were $14.8 million, a decrease of $1.6 million compared to the year ended December 31, 2007.

Operating costs and expenses were $19.3 million and $70.5 million for the three months and year ended December 31, 2008, respectively, an increase of $5.7 million and $18.2 million compared to same periods of 2007, respectively. The increase for the three months and year ended December 31, 2008 was due to costs and expenses related to the operations of our crude pipelines commencing March 1, 2008, increased depreciation attributable to our capital expansion projects, increased pipeline maintenance and payroll costs and an increase in professional fees. Additionally, interest expense for the three months and year ended

December 31, 2008 increased $4.4 million and $8.5 million over the same periods of 2007, respectively. This increase is due 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. Furthermore, interest expense for the three months and year ended December 31, 2008 includes $2.3 million in non-cash interest expense as a result of the application of fair value accounting to two of our interest rate swap agreements.

Other income of $1.0 million for the year ended December 31, 2008 represents a reimbursement for certain pipeline repair and maintenance costs that were incurred and expensed over a previous two year 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 refinery capacity until production was restored in late September. Shipments returned to normal levels during the fourth quarter of 2008. Lost production and reduced operations attributable to this incident resulted in a significant decrease in third party shipments and related revenues on our refined product pipelines during the first nine months of 2008. As a result of related shortfall billings, the incident did not materially affect our distributable cash flow.

We have scheduled a conference call today at 4:00 PM Eastern Time to discuss financial results. Listeners may access this call by dialing (888) 548-4639. The ID# for this call is #80734731. For those who would like to listen to this call via the internet, you may access the call at:http://www.videonewswire.com/event.asp?id=54926.

Additionally, listeners may replay this call approximately two hours after the call concludes by dialing (800) 642-1687. This audio archive will be available through February 17, 2009.

Holly Energy Partners, L.P., headquartered in Dallas, Texas, provides petroleum product and crude oil transportation, tankage and terminal services to the petroleum industry, including Holly Corporation subsidiaries. The Partnership owns and operates petroleum product and crude gathering pipelines, tankage and terminals in Texas, New Mexico, Arizona, Washington, Idaho, Oklahoma and Utah. In addition, the Partnership owns a 70% interest in Rio Grande Pipeline Company, a transporter of LPGs from West Texas to Northern Mexico.

Holly Corporation operates through its subsidiaries an 85,000 barrels-per-stream-day (“bpsd”) refinery located in Artesia, New Mexico and a 31,000 bpsd refinery in Woods Cross, Utah. A Holly Corporation subsidiary owns a 46% interest (including the general partner interest) in the Partnership.

The following is a “safe harbor” statement under the Private Securities Litigation Reform Act of 1995: The statements in this press release relating to matters that are not historical facts are “forward-looking statements” within the meaning of the federal securities laws. 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 and crude oil in the 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 or 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.

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.

RESULTS OF OPERATIONS (Unaudited)

Income, Distributable Cash Flow and Volumes

The following tables present income, distributable cash flow and volume information for the three months and years ended December 31, 2008 and 2007.

	Three Months Ended
	December 31,						Change from
	2008			2007			2007
	(In thousands, except per unit data)
Revenues
Pipelines:
Affiliates – refined product pipelines	$	11,452		$	9,817		$	1,635
Affiliates – intermediate pipelines		2,915			3,341			(426	)
Affiliates – crude pipelines		6,856			—			6,856
		21,223			13,158			8,065
Third parties – refined product pipelines		9,291			9,798			(507	)
		30,514			22,956			7,558
Terminals, refinery tankage and truck loading racks:
Affiliates		2,607			2,861			(254	)
Third parties		1,405			1,374			31
		4,012			4,235			(223	)
Total revenues		34,526			27,191			7,335
Operating costs and expenses
Operations		10,525			9,050			1,475
Depreciation and amortization		6,630			3,509			3,121
General and administrative		2,136			1,081			1,055
		19,291			13,640			5,651
Operating income		15,235			13,551			1,684
Interest income		13			102			(89	)
Interest expense, including amortization		(7,562	)		(3,177	)		(4,385	)
Other expense		(11	)		—			(11	)
Minority interest in Rio Grande		(444	)		(253	)		(191	)
Income before income taxes		7,231			10,223			(2,992	)
State income tax		(98	)		(82	)		(16	)
Net income		7,133			10,141			(3,008	)
Less general partner interest in net income, including incentive distributions(1)		1,018			832			186
Limited partners’ interest in net income	$	6,115		$	9,309		$	(3,194	)
Net income per unit applicable to limited partners(1)	$	0.37		$	0.58		$	(0.21	)
Weighted average limited partners’ units outstanding		16,328			16,108			220
EBITDA(2)	$	21,410		$	16,807		$	4,603
Distributable cash flow(3)	$	16,913		$	12,346		$	4,567
Volumes (bpd)(4)
Pipelines:
Affiliates – refined product pipelines		93,181			82,791			10,390
Affiliates – intermediate pipelines		61,359			69,957			(8,598	)
Affiliates – crude pipelines		135,138			—			135,138
		289,678			152,748			136,930
Third parties – refined product pipelines		58,270			62,253			(3,983	)
		347,948			215,001			132,947
Terminals and truck loading racks:
Affiliates		115,285			125,705			(10,420	)
Third parties		34,715			43,507			(8,792	)
		150,000			169,212			(19,212	)
Total for pipelines and terminal assets (bpd)		497,948			384,213			113,735

	Years Ended
	December 31,						Change from
	2008			2007			2007
	(In thousands, except per unit data)
Revenues
Pipelines:
Affiliates – refined product pipelines	$	40,446		$	36,281		$	4,165
Affiliates – intermediate pipelines		11,917			13,731			(1,814	)
Affiliates – crude pipelines		22,380			—			22,380
		74,743			50,012			24,731
Third parties – refined product pipelines		28,580			36,271			(7,691	)
		103,323			86,283			17,040
Terminals, refinery tankage and truck loading racks:
Affiliates		10,297			10,949			(652	)
Third parties		4,468			5,427			(959	)
		14,765			16,376			(1,611	)
Other — affiliates		—			2,748			(2,748	)
Total revenues		118,088			105,407			12,681
Operating costs and expenses
Operations		41,270			32,911			8,359
Depreciation and amortization		22,889			14,382			8,507
General and administrative		6,377			5,043			1,334
		70,536			52,336			18,200
Operating income		47,552			53,071			(5,519	)
Interest income		159			533			(374	)
Interest expense, including amortization		(21,763	)		(13,289	)		(8,474	)
Gain on sale of assets		36			298			(262	)
Other income, net		996			—			996
Minority interest in Rio Grande		(1,278	)		(1,067	)		(211	)
Income before income taxes		25,702			39,546			(13,844	)
State income tax		(335	)		(275	)		(60	)
Net income		25,367			39,271			(13,904	)
Less general partner interest in net income, including incentive distributions(1)		3,543			2,932			611
Limited partners’ interest in net income	$	21,824		$	36,339		$	(14,515	)
Net income per unit applicable to limited partners(1)	$	1.34		$	2.26		$	(0.92	)
Weighted average limited partners’ units outstanding		16,291			16,108			183
EBITDA(2)	$	70,195		$	66,684		$	3,511
Distributable cash flow(3)	$	60,365		$	51,012		$	9,353
Volumes (bpd)(4)
Pipelines:
Affiliates – refined product pipelines		83,203			77,441			5,762
Affiliates – intermediate pipelines		58,855			65,006			(6,151	)
Affiliates – crude pipelines		111,426			—			111,426
		253,484			142,447			111,037
Third parties – refined product pipelines		38,330			62,720			(24,390	)
		291,814			205,167			86,647
Terminals and truck loading racks:
Affiliates		109,539			119,910			(10,371	)
Third parties		32,737			45,457			(12,720	)
		142,276			165,367			(23,091	)
Total for pipelines and terminal assets (bpd)		434,090			370,534			63,556

(1)

Net income is allocated between limited partners and the general partner interest in accordance with the provisions of the partnership agreement. Incentive distributions of $0.9 million and $3.1 million were declared during the three months and year ended December 31, 2008, respectively, and $0.6 million and $2.2 million were declared during the three months and year ended December 31, 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 accepted 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						Years Ended
	December 31,						December 31,
	2008			2007			2008			2007
				(In thousands)
Net income	$	7,133		$	10,141		$	25,367		$	39,271
Add interest expense		5,017			3,068			18,479			12,281
Add amortization of discount and deferred debt issuance costs		263			109			1,002			1,008
Change in fair value – interest rate swaps		2,282			—			2,282			—
Subtract interest income		(13	)		(102	)		(159	)		(533	)
Add state income tax		98			82			335			275
Add depreciation and amortization		6,630			3,509			22,889			14,382
EBITDA	$	21,410		$	16,807		$	70,195		$	66,684

(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.

Set forth below is our calculation of distributable cash flow.

	Three Months Ended						Years Ended
	December 31,						December 31,
	2008			2007			2008			2007
	(In thousands)
Net income	$	7,133		$	10,141		$	25,367		$	39,271
Add amortization of discount and deferred debt issuance costs		263			109			1,002			1,008
Add change in fair value – interest rate swaps		2,282			—			2,282			—
Add depreciation and amortization		6,630			3,509			22,889			14,382
Add (subtract) increase (decrease) in deferred revenue		1,320			(916	)		11,958			(1,786	)
Subtract maintenance capital expenditures*		(715	)		(497	)		(3,133	)		(1,863	)
Distributable cash flow	$	16,913		$	12,346		$	60,365		$	51,012

* 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 year ended December 31, 2008 represent volumes transported on the crude pipelines for the months of March through December. Volumes shipped during the months of March through December 2008 averaged 133.3 mbpd. For the year ended December 31, 2008, volumes are based on volumes for the months of March though December, averaged over the 366 days in 2008. Under the pipelines and tankage agreement with Holly, 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.

	December 31,			December 31,
	2008			2007
	(In thousands)
Balance Sheet Data
Cash and cash equivalents	$	5,269		$	10,321
Working capital(5)	$	(37,832	)	$	5,446
Total assets(6)	$	439,688		$	238,904
Long-term debt	$	355,793		$	181,435
Partners’ equity (deficit)(6)	$	(2,098	)	$	27,816

(5) Reflects $29.0 million of short-term borrowings that were classified as current liabilities at December 31, 2008.

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

FOR FURTHER INFORMATION, Contact:

Bruce R. Shaw, Senior Vice President and
     Chief Financial Officer
M. Neale Hickerson, Vice President,
      Investor Relations
Holly Energy Partners, L.P.
214/871-3555