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

Exhibit 99.1

Press Release
October 28, 2010

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

Dallas, Texas — Holly Energy Partners, L.P. (“HEP” or the “Partnership”) (NYSE-HEP) today reported financial results for the third quarter of 2010. For the quarter, distributable cash flow was $24 million, up $3.3 million, or 16% compared to third quarter of 2009. For the nine months ended September 30, 2010, distributable cash flow was $66.8 million, up $15.1 million or 29% compared to the same period of 2009. Based on these results, HEP announced a distribution increase on October 26, 2010, raising the quarterly distribution from $0.825 to $0.835 per unit, representing a 5% increase over the distribution for the third quarter of 2009.

For the quarter, income from continuing operations was $16.3 million ($0.59 per basic and diluted limited partner unit) compared to $15.5 million ($0.73 per basic and diluted limited partner unit) for the third quarter of 2009. Net income was $16.3 million ($0.59 per basic and diluted limited partner unit) versus $16.5 million ($0.78 per basic and diluted limited partner unit) for the third quarter of 2009, which included Rio Grande discontinued operations. Excluding discontinued operations, the slight increase in overall earnings is due principally to contributions from our December 2009 and March 2010 asset acquisitions, partially offset by a decrease in realized deferred revenue, lower shipment volumes and increased interest costs.

For the current nine month period, income from continuing operations was $40.4 million ($1.43 per basic and diluted limited partner unit) compared to $34.3 million ($1.66 per basic and diluted limited partner unit) for the same nine month period of 2009. Net income was $40.4 million ($1.43 per basic and diluted limited partner unit) versus $38.4 million ($1.89 per basic and diluted limited partner unit) for the first nine months of 2009.

Commenting on the third quarter of 2010, Matt Clifton, Chairman of the Board and Chief Executive Officer stated, “The third quarter generated solid financial results as distributable cash flow and EBITDA again reached new quarterly highs. For the quarter, increased distributable cash flow over the same period of 2009 allowed us to declare our 24^th consecutive distribution increase. EBITDA was $32 million, an increase of $2.1 million or 7% over last year’s third quarter, and for the current nine month period, EBITDA was $88.2 million, an increase of $13.3 million or 18% over last year’s respective period, reflecting earnings contributions from our 2009 and March 2010 asset acquisitions. Although shipments on our pipelines did not meet targeted levels, we are pleased with these operating results.”

“Looking forward, we will continue to explore opportunities that should provide further growth in our distributable cash flow, asset base and geographic footprint,” Clifton said.

Third Quarter 2010 Revenue Highlights

Total revenues from continuing operations for the quarter were $46.5 million, a $5.7 million increase compared to the third quarter of 2009. This was due to revenues attributable to our December 2009 and March 2010 asset acquisitions, partially offset by a $3.4 million decrease in previously deferred revenue realized and a decrease in pipeline shipments. The small decrease in affiliate pipeline shipments reflects slightly lower run rates at Holly’s Navajo refinery during the third quarter due to the impact of unscheduled downtime of certain operating units.

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• Revenues from ourrefined product pipelineswere $19.6 million, a decrease of $3.2 million. This decrease is primarily due to a $3.2 million decrease in previously deferred revenue realized. Volumes shipped on our refined product pipelines averaged 135.2 thousand barrels per day (“mbpd”) compared to 142.8 mbpd for the third quarter of 2009.

• Revenues from ourintermediate pipelineswere $4.9 million, a decrease of $0.5 million, on shipments averaging 83.2 mbpd compared to 88.1 mbpd for the third quarter of 2009. This includes a $0.2 million decrease in previously deferred revenue realized.

• Revenues from ourcrude pipelineswere $9.8 million, an increase of $2.2 million. This increase is primarily due to $2.3 million in revenues attributable to our Roadrunner Pipeline agreement entered into in December 2009. Volumes shipped on our crude pipelines averaged 143.6 mbpd compared to 143.9 mbpd for the third quarter of 2009.

• Revenues fromterminal, tankage and loading rackfees were $12.2 million, an increase of $7.2 million compared to the third quarter of 2009. This increase includes $7.1 million in revenues attributable to volumes transferred and stored at our Tulsa storage and rack facilities.

Revenues from continuing operations for the three months ended September 30, 2010 include the recognition of $1.6 million of prior shortfalls billed to shippers in 2009, as they did not meet their minimum volume commitments in any of the subsequent four quarters. As of September 30, 2010, deferred revenue in our consolidated balance sheet was $11.7 million. Such deferred revenue will be recognized in earnings either as payment for shipments in excess of guaranteed levels or when shipping rights expire unused over the next four quarters.

Nine Months Ended September 30, 2010 Revenue Highlights

Total revenues from continuing operations for the nine months were $132.7 million, a $24.6 million increase compared to the same period of 2009. This was due to our recent asset acquisitions and higher tariffs on affiliate shipments, partially offset by an $8.1 million decrease in previously deferred revenue realized. On a year-to-date basis, overall pipeline shipments were up 7%, reflecting increased affiliate volumes attributable to Holly Corporation’s (“Holly”) first quarter of 2009 Navajo refinery expansion, including volumes shipped on our new 16” intermediate and Beeson pipelines, partially offset by a decrease in third-party shipments. Additionally, prior year affiliate shipments reflect lower first quarter volumes as a result of production downtime during a major maintenance turnaround of the Navajo refinery during the first quarter of 2009.

• Revenues from ourrefined product pipelineswere $55 million, a decrease of $7.3 million. This decrease is primarily due to a $9.1 million decrease in previously deferred revenue realized. Volumes shipped on our refined product pipelines averaged 130.9 mbpd compared to 131.1 mbpd for the first nine months of 2009, reflecting a decline in third-party shipments, offset by an increase in affiliate shipments.

• Revenues from ourintermediate pipelineswere $15.7 million, an increase of $4.2 million, on shipments averaging 82.8 mbpd compared to 64.5 mbpd for the nine months ended September 30, 2009. This increase is primarily due to volumes shipped on our 16-inch intermediate pipeline combined with a $1 million increase in previously deferred revenue realized.

• Revenues from ourcrude pipelineswere $28.9 million, an increase of $7.7 million, on shipments averaging 140 mbpd compared to 136.3 mbpd for the nine months ended September 30, 2009. This increase is primarily due to $6.9 million in revenues attributable to our Roadrunner Pipeline agreement.

• Revenues fromterminal, tankage and loading rackfees were $33.1 million, an increase of $20 million compared to the nine months ended September 30, 2009. This increase includes $19 million in revenues attributable to volumes transferred and stored at our Tulsa storage and rack facilities.

Our revenues from continuing operations for the nine months ended September 30, 2010 include the recognition of $5.7 million of prior shortfalls billed to shippers in 2009, as they did not meet their minimum volume commitments in any of the subsequent four quarters.

Cost and Expense Highlights

Operating costs and expenses were $22.4 million and $68.2 million for the three and nine months ended September 30, 2010, respectively, representing increases of $2.8 million and $11.9 million compared to the same periods of 2009. These increases were due to costs attributable to our recent asset acquisitions, higher year-to-date throughput volumes on our heritage pipelines, early 2010 transaction related expenses, and higher depreciation, maintenance and payroll expense.

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Additionally, interest expense was $8.4 million and $25.5 million for the three and nine months ended September 30, 2010, respectively, representing increases of $2 million and $9.3 million compared to the same periods of 2009. These increases reflect interest on our 8.25% senior notes issued in March 2010 and costs of $1.1 million from a partial settlement of an interest rate swap in the second quarter of 2010.

We have scheduled a webcast conference call today at 4:00 PM Eastern Time to discuss financial results. This webcast may be accessed at:http://www.videonewswire.com/event.asp?id=73286.

An audio archive of this webcast will be available using the above noted link through November 11, 2010.

About Holly Energy Partners, L.P.

Holly Energy Partners, L.P., headquartered in Dallas, Texas, provides petroleum product and crude oil transportation, terminalling, storage and throughput 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 25% interest in SLC Pipeline LLC, a 95-mile intrastate pipeline system serving refineries in the Salt Lake City, Utah area.

Holly Corporation operates through its subsidiaries a 100,000 barrels-per-stream-day (“bpsd”) refinery located in Artesia, New Mexico, a 31,000 bpsd refinery in Woods Cross, Utah and a 125,000 bpsd refinery in Tulsa, Oklahoma. A Holly Corporation subsidiary owns a 34% 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. Forward looking statements use words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “intend,” “could,” “believe,” “may,” and similar expressions and statements regarding our plans and objectives for future operations. These statements are based on our beliefs and assumptions and those of our general partner 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 and our general partner believe that such expectations reflected in such forward-looking statements are reasonable, neither we nor our general partner can give assurance that our expectations will prove to be correct. Such statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Certain factors could cause actual results to differ materially from results anticipated in the forward-looking statements. These factors include, but are 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 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.

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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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 the nine months ended September 30, 2010 and 2009.

	Three Months Ended
	September 30,						Change from
	2010			2009			2009
	(In thousands, except per unit data)
Revenues
Pipelines:
Affiliates — refined product pipelines	$	12,340		$	12,267		$	73
Affiliates — intermediate pipelines		4,917			5,370			(453	)
Affiliates — crude pipelines		9,774			7,563			2,211
		27,031			25,200			1,831
Third parties — refined product pipelines		7,277			10,552			(3,275	)
		34,308			35,752			(1,444	)
Terminals and loading racks:
Affiliates		10,282			3,159			7,123
Third parties		1,959			1,894			65
		12,241			5,053			7,188
Total revenues		46,549			40,805			5,744
Operating costs and expenses:
Operations		13,632			11,103			2,529
Depreciation and amortization		7,237			6,580			657
General and administrative		1,508			1,848			(340	)
		22,377			19,531			2,846
Operating income		24,172			21,274			2,898
Equity in earnings of SLC Pipeline		570			711			(141	)
Interest income		1			2			(1	)
Interest expense, including amortization		(8,417	)		(6,418	)		(1,999	)
Other income		9			—			9
		(7,837	)		(5,705	)		(2,132	)
Income from continuing operations before income taxes		16,335			15,569			766
State income tax		(76	)		(100	)		24
Income from continuing operations		16,259			15,469			790
Income from discontinued operations, net of noncontrolling interest of $269(1)		—			1,070			(1,070	)
Net income		16,259			16,539			(280	)
Less general partner interest in net income, including incentive distributions(2)		3,172			2,022			1,150
Limited partners’ interest in net income	$	13,087		$	14,517		$	(1,430	)
Limited partners’ earnings per unit — basic and diluted:(2)
Income from continuing operations	$	0.59		$	0.73		$	(0.14	)
Income from discontinued operations		—			0.05			(0.05	)
Net income	$	0.59		$	0.78		$	(0.19	)
Weighted average limited partners’ units outstanding		22,079			18,520			3,559
EBITDA(3)	$	31,988		$	29,888		$	2,100
Distributable cash flow(4)	$	23,969		$	20,678		$	3,291
Volumes from continuing operations (bpd)(1)
Pipelines:
Affiliates — refined product pipelines		93,194			98,987			(5,793	)
Affiliates — intermediate pipelines		83,227			88,053			(4,826	)
Affiliates — crude pipelines		143,617			143,902			(285	)
		320,038			330,942			(10,904	)
Third parties — refined product pipelines		41,967			43,858			(1,891	)
		362,005			374,800			(12,795	)
Terminals and loading racks:
Affiliates		183,312			122,413			60,899
Third parties		43,633			44,459			(826	)
		226,945			166,872			60,073
Total for pipelines and terminal assets (bpd)		588,950			541,672			47,278

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	Nine Months Ended
	September 30,						Change from
	2010			2009			2009
	(In thousands, except per unit data)
Revenues
Pipelines:
Affiliates — refined product pipelines	$	35,887		$	31,186		$	4,701
Affiliates — intermediate pipelines		15,673			11,438			4,235
Affiliates — crude pipelines		28,907			21,215			7,692
		80,467			63,839			16,628
Third parties — refined product pipelines		19,136			31,125			(11,989	)
		99,603			94,964			4,639
Terminals and loading racks:
Affiliates		27,522			7,907			19,615
Third parties		5,603			5,265			338
		33,125			13,172			19,953
Total revenues		132,728			108,136			24,592
Operating costs and expenses:
Operations		40,187			32,076			8,111
Depreciation and amortization		22,038			19,209			2,829
General and administrative		5,984			4,979			1,005
		68,209			56,264			11,945
Operating income		64,519			51,872			12,647
Equity in earnings of SLC Pipeline		1,595			1,309			286
Interest income		6			10			(4	)
Interest expense, including amortization		(25,510	)		(16,225	)		(9,285	)
Other income		2			65			(63	)
SLC Pipeline acquisition costs		—			(2,500	)		2,500
		(23,907	)		(17,341	)		(6,566	)
Income from continuing operations before income taxes		40,612			34,531			6,081
State income tax		(216	)		(266	)		50
Income from continuing operations		40,396			34,265			6,131
Income from discontinued operations, net of noncontrolling interest of 1,191(1)		—			4,105			(4,105	)
Net income		40,396			38,370			2,026
Less general partner interest in net income, including incentive distributions(2)		8,727			5,163			3,564
Limited partners’ interest in net income	$	31,669		$	33,207		$	(1,538	)
Limited partners’ earnings per unit — basic and diluted:(2)
Income from continuing operations	$	1.43		$	1.66		$	(0.23	)
Income from discontinued operations		—			0.23			(0.23	)
Net income	$	1.43		$	1.89		$	(0.46	)
Weighted average limited partners’ units outstanding		22,079			17,546			4,533
EBITDA(3)	$	88,154		$	74,831		$	13,323
Distributable cash flow(4)	$	66,800		$	51,677		$	15,123
Volumes from continuing operations (bpd)(1)
Pipelines:
Affiliates — refined product pipelines		95,013			85,489			9,524
Affiliates — intermediate pipelines		82,844			64,494			18,350
Affiliates — crude pipelines		139,955			136,315			3,640
		317,812			286,298			31,514
Third parties — refined product pipelines		35,923			45,647			(9,724	)
		353,735			331,945			21,790
Terminals and loading racks:
Affiliates		177,946			106,969			70,977
Third parties		38,825			42,873			(4,048	)
		216,771			149,842			66,929
Total for pipelines and terminal assets (bpd)		570,506			481,787			88,719

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(1)	On December 1, 2009, we sold our 70% interest in Rio Grande. Results of operations of Rio Grande are presented in discontinued operations. Pipeline volume information excludes volumes attributable to Rio Grande.
(2)	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 incentive distributions declared subsequent to quarter end. General partner incentive distributions for the three and the nine months ended September 30, 2010 were $2.9 million and $8.1 million. For the three and the nine months ended September 30, 2009 the distributions were $1.7 million and $4.5 million, respectively. Net income attributable to the limited partners is divided by the weighted average limited partner units outstanding in computing the limited partners’ per unit interest in net income.
(3)	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 (“GAAP”). However, the amounts included in the EBITDA calculation are derived from amounts included in our consolidated financial statements, with the exception of EBITDA from discontinued operations. 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 also is 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,
	2010			2009			2010			2009
	(In thousands)
Income from continuing operations	$	16,259		$	15,469		$	40,396		$	34,265
Add (subtract):
Interest expense		8,135			5,314			22,230			15,396
Amortization of discount and deferred debt issuance costs		282			176			740			529
Increase in interest expense — change in fair value of interest rate swaps and swap settlement costs		—			928			2,540			300
Interest income		(1	)		(2	)		(6	)		(10	)
State income tax		76			100			216			266
Depreciation and amortization		7,237			6,580			22,038			19,209
EBITDA from discontinued operations		—			1,323			—			4,876
EBITDA	$	31,988		$	29,888		$	88,154		$	74,831

(4) Distributable cash flow is not a calculation based upon GAAP. However, the amounts included in the calculation are derived from amounts separately presented in our consolidated financial statements, with the exception of equity in excess cash flows over earnings of SLC Pipeline, maintenance capital expenditures and distributable cash flow from discontinued operations. 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. It also is used by management for internal analysis and our performance units. 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,
	2010			2009			2010			2009
	(In thousands)
Income from continuing operations	$	16,259		$	15,469		$	40,396		$	34,265
Add (subtract):
Depreciation and amortization		7,237			6,580			22,038			19,209
Amortization of discount and deferred debt issuance costs		282			176			740			529
Increase in interest expense — change in fair value of interest rate swaps and swap settlement costs		—			928			2,540			300
Equity in excess cash flows over		173			167			525			387
earnings of SLC Pipeline
Increase (decrease) in deferred revenue		758			(3,407	)		3,279			(8,076	)
SLC Pipeline acquisition costs*		—			—			—			2,500
Maintenance capital expenditures**		(740	)		(545	)		(2,718	)		(2,262	)
Distributable cash flow from discontinued operations		—			1,310			—			4,825
Distributable cash flow	$	23,969		$	20,678		$	66,800		$	51,677

*	We expensed the $2.5 million finder’s fee associated with our joint venture agreement with Plains that closed in March 2009. These costs directly relate to our interest in the new joint venture pipeline and are similar to expansion capital expenditures; accordingly, we have added back these costs to arrive at distributable cash flow.
**	Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and to extend their useful lives. Maintenance capital expenditures include expenditures required to maintain equipment reliability, tankage and pipeline integrity, and safety and to address environmental regulations.

	September 30,			December 31,
	2010			2009
	(In thousands)
Balance Sheet Data
Cash and cash equivalents	$	706		$	2,508
Working capital(5)	$	(155,392	)	$	4,404
Total assets	$	634,584		$	616,845
Long-term debt(6)	$	332,564		$	390,827
Total equity(7)	$	110,948		$	193,864

(5)	Our credit agreement expires in August 2011; therefore, working capital at September 30, 2010 reflects $157 million of credit agreement borrowings that are classified as current liabilities. We intend to renew the credit agreement prior to expiration and to continue to finance the outstanding credit agreement balance, which we will then reclassify as long-term debt. Excluding the $157 million credit agreement borrowings, working capital was $1.6 million at September 30, 2010.
(6)	Includes $206 million of credit agreement advances at December 31, 2009.
(7)	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, the intermediate pipelines purchased from Holly in 2005 and the assets purchased from Holly in 2009 and March 2010 had been acquired from third parties, our acquisition cost in excess of Holly’s basis in the transferred assets of $217.9 million would have been recorded as increases to our properties and equipment and intangible assets instead of decreases to 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

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