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

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

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

(214) 871-3555

None

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.

Yes þ      No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes o      No o

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 filer o		Accelerated filer þ		Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Exchange Act).

Yes o No þ

The number of the registrant’s outstanding common units at July 25, 2009 was 10,582,400.

 

 

HOLLY ENERGY PARTNERS, L.P.
INDEX

PART I. FINANCIAL INFORMATION			3
FORWARD-LOOKING STATEMENTS			3
Item 1. Financial Statements (Unaudited, except December 31, 2008 Balance Sheet)			4
Consolidated Balance Sheets			4
Consolidated Statements of Income			5
Consolidated Statements of Cash Flows			6
Consolidated Statement of Equity			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			44
Item 4. Controls and Procedures			44
PART II. OTHER INFORMATION			45
Item 1. Legal Proceedings			45
Item 6. Exhibits			45
SIGNATURES			46
EX-4.1
EX-4.2
EX-4.3
EX-12.1
EX-31.1
EX-31.2
EX-32.1
EX-32.2

PART I. FINANCIAL INFORMATION

FORWARD-LOOKING STATEMENTS

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

•

Risks and uncertainties with respect to the actual quantities of petroleum products 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, the forward-looking statements 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, 2008 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.

Item 1. Financial Statements

Holly Energy Partners, L.P.
Consolidated Balance Sheets

		June 30, 2009				December 31,
		(Unaudited)				2008
		(In thousands, except unit data)
ASSETS
Current assets:
Cash and cash equivalents		$	4,195			$	5,269
Accounts receivable:
Trade			4,804				5,082
Affiliates			8,676				9,395
			13,480				14,477
Prepaid and other current assets			827				593
Total current assets			18,502				20,339
Properties and equipment, net			336,685				290,284
Transportation agreements, net			118,909				122,383
Investment in SLC Pipeline			26,098				—
Other assets			4,921				6,682
Total assets		$	505,115			$	439,688
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable		$	7,074			$	5,816
Accounts payable — affiliates			2,046				2,202
Accrued interest			2,871				2,845
Deferred revenue			10,989				15,658
Accrued property taxes			1,026				1,145
Other current liabilities			1,058				1,505
Short-term borrowings under credit agreement			—				29,000
Total current liabilities			25,064				58,171
Long-term debt			402,810				355,793
Other long-term liabilities			11,482				17,604
Equity:
Holly Energy Partners, L.P. partners’ equity (deficit):
Common unitholders (10,582,400 and 8,390,000 units issued and outstanding at June 30, 2009 and December 31, 2008, respectively)			224,609				169,126
Subordinated unitholders (7,000,000 units issued and outstanding at June 30, 2009 and December 31, 2008)			(88,106	)			(85,059	)
Class B subordinated unitholders (937,500 units issued and outstanding at June 30, 2009 and December 31, 2008)			21,046				21,455
General partner interest (2% interest)			(93,630	)			(94,653	)
Accumulated other comprehensive loss			(8,700	)			(12,967	)
Total Holly Energy Partners, L.P. partners’ equity (deficit)			55,219				(2,098	)
Noncontrolling interest			10,540				10,218
Total equity			65,759				8,120
Total liabilities and equity		$	505,115			$	439,688

See accompanying notes.

Holly Energy Partners, L.P.
Consolidated Statements of Income
(Unaudited)

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2009				2008				2009				2008
						(In thousands, except per unit data)
Revenues:
Affiliates		$	25,064			$	20,146			$	43,387			$	38,473
Third parties			15,538				6,629				29,339				15,578
			40,602				26,775				72,726				54,051
Operating costs and expenses:
Operations			11,086				9,985				21,882				19,712
Depreciation and amortization			6,853				6,062				13,109				10,375
General and administrative			1,818				1,359				3,142				2,645
			19,757				17,406				38,133				32,732
Operating income			20,845				9,369				34,593				21,319
Other income (expense):
Equity in earnings of SLC Pipeline			423				—				598				—
SLC Pipeline acquisition costs			—				—				(2,500	)			—
Interest income			2				28				8				121
Interest expense			(4,404	)			(5,233	)			(9,807	)			(9,040	)
Other			65				—				65				36
			(3,914	)			(5,205	)			(11,636	)			(8,883	)
Income before income taxes			16,931				4,164				22,957				12,436
State income tax			(112	)			(85	)			(204	)			(153	)
Net income			16,819				4,079				22,753				12,283
Less noncontrolling interest in net income			427				264				922				670
Net income attributable to Holly Energy Partners, L.P.		$	16,392			$	3,815			$	21,831			$	11,613
Less general partner interest in net income attributable to Holly Energy Partners, L.P.			1,849				849				3,142				1,728
Limited partners’ interest in net income attributable to Holly Energy Partners, L.P.		$	14,543			$	2,966			$	18,689			$	9,885
Limited partners’ per unit interest in net income attributable to Holly Energy Partners, L.P. — basic and diluted		$	0.82			$	0.18			$	1.10			$	0.61
Weighted average limited partners’ units outstanding			17,789				16,328				17,058				16,254

See accompanying notes.

Holly Energy Partners, L.P.
Consolidated Statements of Cash Flows
(Unaudited)

		Six Months Ended
		June 30,
		2009				2008
		(In thousands)
Cash flows from operating activities
Net income		$	22,753			$	12,283
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization			13,109				10,375
Equity in earnings of SLC Pipeline			(598	)			—
Change in fair value – interest rate swaps			(628	)			—
Amortization of restricted and performance units			417				548
Gain on sale of assets			—				(36	)
(Increase) decrease in current assets:
Accounts receivable			278				(720	)
Accounts receivable – affiliates			719				(2,892	)
Prepaid and other current assets			(234	)			(137	)
Increase (decrease) in current liabilities:
Accounts payable			1,258				1,468
Accounts payable – affiliates			(156	)			(4,229	)
Accrued interest			26				(97	)
Deferred revenue			(4,669	)			6,781
Accrued property taxes			(119	)			(427	)
Other current liabilities			(447	)			216
Other, net			541				288
Net cash provided by operating activities			32,250				23,421
Cash flows from investing activities
Additions to properties and equipment			(21,826	)			(20,036	)
Acquisition of 16-inch intermediate pipeline			(34,200	)			—
Investment in SLC Pipeline			(25,500	)			—
Acquisition of crude pipelines and tankage assets			—				(171,000	)
Proceeds from sale of assets			—				36
Net cash used for investing activities			(81,526	)			(191,000	)
Cash flows from financing activities
Borrowings under credit agreement			99,000				211,000
Repayments under credit agreement			(81,000	)			(20,000	)
Proceeds from issuance of common units			58,355				104
Capital contribution from general partner			1,191				186
Distributions to HEP unitholders			(27,968	)			(25,656	)
Distributions to noncontrolling interest			(600	)			(900	)
Cost of issuing common units			(160	)			—
Purchase of units for restricted grants			(616	)			(514	)
Deferred financing costs			—				(591	)
Net cash provided by financing activities			48,202				163,629
Cash and cash equivalents
Decrease for period			(1,074	)			(3,950	)
Beginning of period			5,269				10,321
End of period		$	4,195			$	6,371

See accompanying notes.

Holly Energy Partners, L.P.
Consolidated Statement of Equity
(Unaudited)

		Holly Energy Partners, L.P. Partners’ Equity (Deficit):
																		Accumulated
										Class B				General				Other				Non-
		Common				Subordinated				Subordinated				Partner				Comprehensive				Controlling
		Units				Units				Units				Interest				Loss				Interest				Total
		(In thousands)
Balance December 31, 2008		$	169,126			$	(85,059	)		$	21,455			$	(94,653	)		$	(12,967	)		$	10,218			$	8,120
Issuance of common units			58,355				—				—				—				—				—				58,355
Cost of issuing common units			(160	)			—				—				—				—				—				(160	)
Capital contribution			—				—				—				1,191				—				—				1,191
Distributions — HEP unitholders			(12,931	)			(10,780	)			(1,444	)			(2,813	)			—				—				(27,968	)
Distributions — noncontrolling interest			—				—				—				—				—				(600	)			(600	)
Purchase of units for restricted grants			(616	)			—				—				—				—				—				(616	)
Amortization of restricted and performance units			417				—				—				—				—				—				417
Comprehensive income:
Net income			10,418				7,733				1,035				2,645				—				922				22,753
Change in fair value of cash flow hedge			—				—				—				—				4,267				—				4,267
Comprehensive income			10,418				7,733				1,035				2,645				4,267				922				27,020
Balance June 30, 2009		$	224,609			$	(88,106	)		$	21,046			$	(93,630	)		$	(8,700	)		$	10,540			$	65,759

See accompanying notes.

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 41% owned by Holly Corporation and its subsidiaries (collectively “Holly”). We commenced operations July 13, 2004 upon the completion of our initial public offering. In this document, the words “we,” “our,” “ours” and “us” refer to HEP unless the context otherwise indicates.

We operate in one business segment — the operation of petroleum 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 intermediate feedstock pipelines (the “Intermediate Pipelines”), which connect the New Mexico refining facilities. Our operations serving the Navajo Refinery include refined product pipelines that serve as part of the refinery’s product distribution network. We also own and operate crude oil pipelines and on-site crude oil tankage that supply and support the refinery. Our terminal operations serving the Navajo Refinery include an on-site truck rack at the refinery and five integrated refined product terminals located in New Mexico, Texas and Arizona.

Another of Holly’s wholly-owned subsidiaries owns a refinery located near Salt Lake City, Utah (the “Woods Cross Refinery”). Our operations serving the Woods Cross Refinery include crude oil and refined product pipelines, crude oil tankage and 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.

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 liquefied petroleum gases to northern Mexico.

In March 2009, we acquired a 25% joint venture interest in a new 95-mile intrastate pipeline system (the “SLC Pipeline”) jointly owned by Plains All American Pipeline, L.P. (“Plains”) and us. See Note 2 for additional information on the SLC Pipeline joint venture.

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, 2008. 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, 2009.

These consolidated financial statements reflect management’s evaluation of subsequent events through the time of our filing on July 31, 2009.

Recent Accounting Pronouncements

Statement of Financial Accounting Standard (“SFAS”) No. 160 “Noncontrolling Interests in Consolidated Financial Statements — an Amendment of Accounting Research Bulletin (“ARB”) No. 51”

SFAS No. 160 became effective January 1, 2009, which changes the classification of noncontrolling interests, also referred to as minority interests, in the consolidated financial statements. As a result, all previous references to “minority interest” within this document have been replaced with “noncontrolling interest.” Additionally, net income attributable to the noncontrolling interest in our Rio Grande subsidiary is now presented as an adjustment to net income to arrive at “Net income attributable to Holly Energy Partners, L.P.” in our Consolidated Statements of Income. Prior to our adoption of this standard, this amount was presented as “Minority interest in Rio Grande,” a non-operating expense item before “Income before income taxes.” Furthermore, equity attributable to noncontrolling interests in our Rio Grande subsidiary is now presented as a separate component of total equity in our Consolidated Financial Statements. We have applied this standard on a retrospective basis. While this presentation differs from previous GAAP requirements, this standard did not affect our net income and equity attributable to HEP.

SFAS 141(R) “Business Combinations”

SFAS No. 141(R) became effective January 1, 2009, which establishes principles and requirements for how an acquirer accounts for a business combination. It also requires that acquisition-related transaction and restructuring costs be expensed rather than be capitalized as part of the cost of an acquired business. Accordingly, we were required to expense the $2.5 million finder’s fee related to the acquisition of our SLC Pipeline joint venture interest.

SFAS No. 161 “Disclosures about Derivative Instruments and Hedging Activities, an Amendment of SFAS No. 133”

SFAS No. 161 became effective January 1, 2009, which amends and expands the disclosure requirements of SFAS 133 to include disclosure of the objectives and strategies related to an entity’s use of derivative instruments, disclosure of how an entity accounts for its derivative instruments and disclosure of the financial impact, including the effect on cash flows associated with derivative activity. See Note 7 for disclosure of our derivative instruments and hedging activity.

Emerging Issues Task Force (“EITF”) Issue No. 07-04 “Application of the Two-Class Method under SFAS Statement No. 128, ‘Earnings per Share,’ to Master Limited Partnerships”

EITF Issue No. 07-04 became effective January 1, 2009, which prescribes the application of the two-class method in computing earnings per unit to reflect a master limited partnership’s contractual obligation to make distributions to the general partner, limited partners and incentive distribution rights holders. As a result, quarterly earnings allocations to the general partner now include incentive distributions that were declared subsequent to quarter end. Prior to our adoption of this standard, our general partner earnings allocations included incentive distributions that were declared during each quarter. We have applied this standard on a retrospective basis. Although this standard resulted in a decrease in our limited partners’ interest in net income attributable to Holly Energy Partners, L.P. for the three and six months ended June 30, 2008, it did not affect earnings of $0.18 and $0.61 per limited partner unit for the three and six months ended June 30, 2008, respectively.

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

FSP No. 03-6-1 became effective January 1, 2009, which 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 SFAS No. 128, Earnings per Share. The adoption of this standard did not have a material impact on our financial condition, results of operations and cash flows.

SFAS No. 165 “Subsequent Events”

In May 2009, the FASB issued SFAS No. 165, which establishes general standards for accounting and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. We adopted this standard effective June 30, 2009. Although this standard requires disclosure of the date through which we have evaluated subsequent events, it did not affect our accounting and disclosure policies with respect to subsequent events.

FSP SFAS No. 107-1 and Accounting Principles Board (“APB”) No. 28-1 “Interim Disclosures about Fair Value of Financial Instruments”

In April 2009, the FASB issued FSP SFAS No, 107-1 and APB No. 28-1, which extends the annual financial statement disclosure requirements for financial instruments to interim reporting periods of publicly traded companies. We adopted this standard effective June 30, 2009. See Note 3 for disclosure of our financial instruments.

Note 2: Acquisitions

Lovington-Artesia Pipeline Transaction

On June 1, 2009, we acquired a newly constructed 16-inch intermediate pipeline from Holly for $34.2 million. The pipeline runs 65 miles from the Navajo Refinery’s crude oil distillation and vacuum facilities in Lovington, New Mexico to its petroleum refinery located in Artesia, New Mexico. This pipeline was placed in service effective June 1, 2009 and operates as a component of our Intermediate Pipeline system that services Holly’s Navajo Refinery.

In connection with this transaction, Holly agreed to amend our transportation agreement that relates to the Intermediate Pipelines acquired in 2005 (the “Holly IPA”). As a result, the term of the Holly IPA was extended by an additional 4 years and now expires in June 2024. Additionally, Holly’s minimum commitment under the Holly IPA was increased and the Holly IPA now results in minimum annual payments to us of $20.7 million.

SLC Pipeline Joint Venture Interest

On March 1, 2009, we acquired a 25% joint venture interest in the SLC Pipeline, a new 95-mile intrastate pipeline system jointly owned by Plains and us. The SLC Pipeline commenced operations effective March 2009 and allows 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 flowing from Wyoming and Utah via Plains’ Rocky Mountain Pipeline. The total cost of our investment in the SLC Pipeline was $28.0 million, consisting of the capitalized $25.5 million joint venture contribution and the $2.5 million finder’s fee paid to Holly that was expensed as acquisition costs.

We account for our investment using the equity method of accounting. Under the equity method of accounting, we record our pro-rata share of earnings of the SLC Pipeline. Contributions to and distributions from the SLC Pipeline are recorded as adjustments to our investment balance.

Crude Pipelines and Tankage Transaction

On February 29, 2008, we acquired crude pipeline and tankage assets from Holly (the “Crude Pipelines and Tankage Assets”) 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 between Artesia and Roswell, New Mexico, a leased jet fuel terminal in 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 the Holly CPTA, Holly agreed to transport and store volumes of crude oil on the crude pipelines and tankage facilities that result in minimum annual payments to us. These minimum annual payments or revenues 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. Under the agreement, the tariff rates will generally be increased annually by the percentage

change in the Federal Energy Regulatory Commission (“FERC”) Oil Pipeline Index. The FERC index is the change in the PPI plus a FERC adjustment factor that is reviewed periodically.

Note 3: Financial Instruments

Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, debt and interest rate swaps. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the short-tem maturity of these instruments.

Our debt consists of outstanding principle under our revolving credit agreement (the “Credit Agreement”) and our 6.25% senior notes (the “Senior Notes”). The $218.0 million carrying amount of outstanding debt under our Credit Agreement approximates fair value as interest rates are reset frequently using current rates. The estimated fair value of our Senior Notes was $161.0 million at June 30, 2009. This fair value estimate is based on market quotes provided from a third-party bank. See Note 7 for additional information on these instruments.

Fair Value Measurements

We adopted SFAS No. 157 “Fair Value Measurements” effective January 1, 2008. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. It also establishes a fair value hierarchy that categorizes inputs used in fair value measurements into three broad levels as follows:

•

(Level 1) Quoted prices in active markets for identical assets or liabilities.

•

(Level 2) Observable inputs other than quoted prices included in Level 1, such as quoted prices for similar assets and liabilities in active markets, similar assets and liabilities in markets that are not active or can be corroborated by observable market data.

•

(Level 3) Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. This includes valuation techniques that involve significant unobservable inputs.

We have interest rate swaps that are measured at fair value on a recurring basis using Level 2 inputs. With respect to these instruments, fair value is based on the net present value of expected future cash flows related to both variable and fixed rate legs of our interest rate swap agreements. Our measurements are computed using the forward London Interbank Offered Rate (“LIBOR”) yield curve, a market-based observable input. See Note 7 for additional information on our interest rate swaps, including fair value measurements.

Note 4: Properties and Equipment

		June 30,				December 31,
		2009				2008
		(In thousands)
Pipelines and terminals		$	345,582			$	308,056
Land and right of way			25,042				24,991
Other			11,761				11,498
Construction in progress			58,050				38,589
			440,435				383,134
Less accumulated depreciation			103,750				92,850
		$	336,685			$	290,284

We capitalized $0.7 million and $0.2 million in interest related to major construction projects during the six months ended June 30, 2009 and 2008, respectively.

Note 5: Transportation Agreements

Our transportation agreements consist of the following:

•

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

•

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 using a fair value based on the agreement’s expected contribution to our future earnings under an income approach. 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:

		June 30,				December 31,
		2009				2008
		(In thousands)
Alon transportation agreement		$	59,933			$	59,933
Holly crude pipelines and tankage agreement			74,231				74,231
			134,164				134,164
Less accumulated amortization			15,255				11,781
		$	118,909			$	122,383

We have two additional transportation agreements with Holly. One of the agreements relates to the pipelines and terminals contributed to us from Holly at the time of our initial public offering in 2004 (the “Holly PTA”). The second agreement relates to the Intermediate Pipelines acquired from Holly in 2005 and in June 2009, the Holly IPA. Our basis in the assets acquired under these transfers reflects Holly’s historical cost and does not reflect a step-up in basis to fair value. Therefore, these agreements have a recorded value of zero.

Note 6: Employees, Retirement and Incentive Plans

Employees who provide direct services to us are employed by Holly Logistic Services, L.L.C., a Holly subsidiary. Their costs, including salaries, bonuses, payroll taxes, benefits and other direct costs, are charged to us monthly in accordance with an omnibus agreement that we have with Holly (the “Omnibus Agreement”). These employees participate in the retirement and benefit plans of Holly. Our share of retirement and benefit plan costs was $0.6 million for the three months ended June 30, 2009 and 2008 and $1.2 million and $1.0 million for the six months ended June 30, 2009 and 2008, 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.

As of June 30, 2009, we have two types of equity-based compensation, which are described below. The compensation cost charged against income for these plans was $0.4 million and $0.5 million for the three months ended June 30, 2009 and 2008, respectively, and $0.9 million and $0.8 million for the six months ended June 30, 2009 and 2008, respectively. It is currently our policy to purchase units in the open market instead of issuing new units for settlement of restricted unit grants. At June 30, 2009, 350,000 units were authorized to be granted under the equity-based compensation plans, of which 200,541 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 restricted unit grant 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 six months ended June 30, 2009 is presented below:

										Weighted-
						Weighted-				Average				Aggregate
						Average				Remaining				Intrinsic
						Grant-Date				Contractual				Value
Restricted Units		Grants				Fair Value				Term				($000)
Outstanding January 1, 2009 (not vested)			53,505			$	41.28
Granted			26,562				23.30
Forfeited			(2,152	)			42.53
Vesting and transfer of full ownership to recipients			(23,318	)			37.70
Outstanding at June 30, 2009 (not vested)			54,597			$	34.01			1.0 year				$	1,733

The fair value of restricted units that were vested and transferred to recipients during the six months ended June 30, 2009 and 2008 were $0.9 million and $0.5 million, respectively. As of June 30, 2009, there was $0.7 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 1.0 year.

During the six months ended June 30, 2009, we paid $0.6 million for the purchase of 26,431 of our common units in the open market for the recipients of our 2009 restricted unit grants.

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 based upon the growth in distributions on our common units during the requisite period, and generally vest over a period of three years. As of June 30, 2009, estimated share payouts for outstanding nonvested performance unit awards ranged from 125% to 150%.

We granted 28,113 performance units to certain officers in March 2009. These units will vest over a three-year performance period ending December 31, 2011 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 $23.30 and will apply to the number of units ultimately awarded.

A summary of performance unit activity and changes during the six months ended June 30, 2009 is presented below:

		Payable
Performance Units		In Units
Outstanding at January 1, 2009 (not vested)			36,971
Granted			28,113
Forfeited			—
Vesting and transfer of common units to recipients			(10,313	)
Outstanding at June 30, 2009 (not vested)			54,771

The fair value of performance units that were vested and transferred to recipients during the six months ended June 30, 2009 and 2008 were $0.4 million and $0.1 million, respectively. Based on the weighted average grant date fair value of $32.95 at June 30, 2009 there was $1.3 million of total unrecognized compensation cost related to nonvested performance units. That cost is expected to be recognized over a weighted-average period of 1.5 years.

Note 7: Debt

Credit Agreement

We have a $300.0 million senior secured revolving credit agreement expiring in August 2011, the Credit Agreement. The Credit Agreement is available to fund capital expenditures, acquisitions, and working capital and for general partnership purposes. 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. Advances under the Credit Agreement that are designated for working capital are classified as short-term liabilities. Other advances under the Credit Agreement, including advances used for the financing of capital projects, are classified as long-term liabilities. During the six months ended June 30, 2009, we received advances totaling $99.0 million that were used as interim financing for capital projects and acquisitions and repaid $81.0 million, resulting in $18.0 million in net advances received. As of June 30, 2009, we had $218.0 million outstanding under the Credit Agreement.

Our obligations under the Credit Agreement are collateralized 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. Any recourse to HEP Logistics Holdings, L.P. would be limited to the extent of its assets, which other than its investment in us, 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. As of June 30, 2009, we had no working capital borrowings.

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 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 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 June 30, 2009, we are subject to a 0.375% commitment fee on the $82.0 million unused portion of the Credit Agreement. The agreement expires 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.

Additionally, the Credit Agreement contains certain provisions whereby the lenders may accelerate payment of outstanding debt under certain circumstances.

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 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. Any recourse to HEP Logistics Holdings, L.P. would be limited to the extent of its assets, which other than its investment in us, are not significant.

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

		June 30,				December 31,
		2009				2008
		(In thousands)
Credit Agreement		$	218,000			$	200,000
Senior Notes
Principal			185,000				185,000
Unamortized discount			(2,154	)			(2,344	)
Unamortized premium – dedesignated fair value hedge			1,964				2,137
			184,810				184,793
Total debt			402,810				384,793
Less net short-term borrowings under credit agreement(1)			—				29,000
Total long-term debt(1)		$	402,810			$	355,793

Interest Rate Risk Management

We use interest rate derivatives to manage our exposure to interest rate risk. As of June 30, 2009, we have three interest rate swap contracts.

We have an interest rate swap that hedges 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 in February 2008. 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 2.00%, which equaled an effective interest rate of 5.74% as of June 30, 2009. 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.

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 the offsetting fair value adjustment 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 June 30, 2009, 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 (“Variable Rate Swap”). Under this swap contract, interest on the $60.0 million notional amount is computed using the three-month LIBOR plus a spread of 1.1575%, which equaled an effective interest rate of 1.83% as of June 30, 2009. The maturity date of this swap contract is March 1, 2015, matching the maturity of the Senior Notes.

In October 2008, we entered into an additional interest rate swap contract, effective December 1, 2008, that effectively unwinds the effects of the Variable Rate Swap discussed above, converting $60.0 million of our hedged long-term debt back to fixed rate debt (“Fixed Rate Swap”). Under the Fixed Rate Swap, interest on a notional amount of $60.0 million is computed at a fixed rate of 3.59% versus three-month LIBOR which when added to the 1.1575% spread on the Variable Rate Swap results in an effective fixed interest rate of 4.75%. The maturity date of this swap contract is December 1, 2013.

Prior to the execution of our Fixed Rate Swap, the Variable Rate Swap was designated as a fair value hedge of $60.0 million in outstanding principal under the Senior Notes. We dedesignated this hedge in October 2008. At this time, the carrying balance of our Senior Notes included a $2.2 million premium due to the application of hedge accounting until the dedesignation date. This premium is being amortized as a reduction to interest expense over the remaining term of the Variable Rate Swap.

Our interest rate swaps not having a “hedge” designation are measured quarterly at fair value either as an asset or a liability in our consolidated balance sheets with the offsetting fair value adjustment to interest expense. For the three and six months ended June 30, 2009, we recognized a reduction of $0.8 million and $0.6 million, respectively, in interest expense as a result of fair value adjustments to our interest rate swaps.

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 June 30, 2009 is as follows:

		Balance Sheet						Location of Offsetting		Offsetting
Interest Rate Swaps		Location		Fair Value				Balance		Amount
		(In thousands)
Asset
Fixed-to-variable interest rate swap		Other assets		$	2,751			Long-term debt		$	(1,964	)
- $60 million of 6.25% Senior Notes								HEP partners’ equity			(1,942	)(1)
								Interest expense			1,155	(2)
				$	2,751					$	(2,751	)
Liability
Cash flow hedge — $171 million LIBOR		Other long-term						Accumulated other
based debt		liabilities		$	(8,700	)		comprehensive loss		$	8,700
Variable-to-fixed interest rate swap		Other long-term						HEP partners’ equity			4,166	(1)
- $60 million		liabilities			(2,209	)		Interest expense			(1,957	)
				$	(10,909	)				$	10,909

Interest Expense and Other Debt Information

Interest expense consists of the following components:

		Six Months Ended
		June 30,
		2009				2008
		(In thousands)
Interest on outstanding debt:
Senior Notes, net of interest rate swaps		$	4,710			$	5,353
Credit Agreement, net of interest rate swap			5,260				3,278
Net amortization of discount and deferred debt issuance costs			353				480
Commitment fees			145				149
Total interest incurred			10,468				9,260
Less capitalized interest			661				220
Net interest expense		$	9,807			$	9,040
Cash paid for interest(1)		$	11,836			$	6,200

Note 8: 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 pipeline system revenues are derived from activities conducted in the southwest United States. The following table presents the percentage of total revenues generated by each of these three customers:

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2009				2008				2009				2008
Holly			62	%			75	%			60	%			71	%
Alon			27	%			12	%			28	%			16	%
BP			5	%			8	%			5	%			9	%

Note 9: Related Party Transactions

Holly and Alon Agreements

As of June 30, 2009, we serve Holly’s refineries in New Mexico and Utah under three long-term 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 2005 and in June 2009 and expires in 2024, the Holly IPA. Third, we have the Holly CPTA that relates to the Crude Pipelines and Tankage Assets acquired from Holly in 2008 and expires in February 2023.

Under the Holly PTA, Holly IPA and Holly CPTA, 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. These minimum annual payments or revenues will be adjusted each year at a percentage change equal to the change in the PPI but will not decrease as a result of a decrease in the PPI. Under these agreements, the agreed upon tariff rates are adjusted each year on July 1 at a rate equal to the percentage change in the PPI or FERC index, but generally will not decrease as a result of a decrease in the PPI or FERC index. The FERC index is the change in the PPI plus a FERC adjustment factor that is reviewed periodically. Following the July 1, 2009 PPI rate adjustments, these agreements will result in minimum payments to us of $92.8 million for the twelve months ended June 30, 2010.

We also have a pipelines and terminals agreement with Alon 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 the PPI, but not below the initial tariff rate. Following the March 1, 2009 PPI rate adjustment, Alon’s total minimum commitment for the twelve months ending February 28, 2010 decreased to $21.7 million.

If either Holly or Alon fails to meet its minimum volume commitment 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.

Under certain provisions of the Omnibus Agreement that we entered into with Holly in July 2004 and that expires in 2019, we pay Holly an annual administrative fee, currently $2.3 million, for the provision by Holly or its affiliates of various general and administrative services to us. 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.

•

Pipeline, terminal and tankage revenues received from Holly were $25.1 million and $20.1 million for the three months ended June 30, 2009 and 2008, respectively, and $43.4 million and $38.5 million for the six months ended June 30, 2009 and 2008, respectively. These amounts include the revenues received under the Holly PTA, Holly IPA and Holly CPTA.

•

Holly charged general and administrative services under the Omnibus Agreement of $0.6 million for the three months ended June 30, 2009 and 2008 and $1.2 million and $1.1 million for the six months ended June 30, 2009 and 2008, respectively.

•

We reimbursed Holly for costs of employees supporting our operations of $4.0 million and $3.5 million for the three months ended June 30, 2009 and 2008, respectively, and $8.6 million and $6.1 million for the six months ended June 30, 2009 and 2008, respectively.

•

We distributed $7.1 million and $6.4 million during the three months ended June 30, 2009 and 2008, respectively, to Holly as regular distributions on its subordinated units, common units and general partner interest. We distributed $14.0 million and $12.4 million during the six months ended June 30, 2009 and 2008, respectively.

•

Our accounts receivable from Holly was $8.7 million and $9.4 million at June 30, 2009 and December 31, 2008, respectively.

•

Holly has failed to meet its minimum volume commitment for each of the sixteen quarters since inception of the Holly IPA. Through June 30, 2009, we have charged Holly $9.3 million for these shortfalls to date, $0.5 million of which is included in affiliate accounts receivable at June 30, 2009 and December 31, 2008.

•

Our revenues for the three and six months ended June 30, 2009 include $0.9 million and $1.1 million, respectively, of shortfalls billed under the Holly IPA in 2008 as Holly did not exceed its minimum volume commitment in any of the subsequent four quarters. Deferred revenue in the consolidated balance sheets at June 30, 2009 and December 31, 2008, includes $3.5 million and $2.4 million, respectively, relating to the Holly IPA. It is possible that Holly may not exceed its minimum obligations under the Holly IPA to allow Holly to receive credit for any of the $3.5 million deferred at June 30, 2009.

•

See Note 2 for information on our 16-inch intermediate pipeline and the Crude Pipelines and Tankage Assets acquired from Holly in June 2009 and February 2008, respectively.

•

We paid Holly a $2.5 million finder’s fee in the first quarter of 2009 in consideration for its assistance in obtaining our joint venture interest in the SLC Pipeline.

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

•

Pipeline and terminal revenues received from Alon were $9.2 million and $1.5 million for the three months ended June 30, 2009 and 2008, respectively, and $17.0 million and $4.9 million for the six months ended June 30, 2009 and 2008, respectively, under the Alon PTA. Additionally, pipeline revenues received under a pipeline capacity lease agreement with Alon were $1.7 million and $1.8 million for the three months ended June 30, 2009 and 2008, respectively, and $3.4 million and $3.6 million for the six months ended June 30, 2009 and 2008, respectively.

•

We distributed $0.7 million during the three months ended June 30, 2009 and 2008 and $1.4 million during the six months ended June 30, 2009 and 2008, to Alon for distributions on its Class B subordinated units.

•

Included in our accounts receivable – trade were $3.5 million and $2.5 million at June 30, 2009 and December 31, 2008, respectively, which represented receivable balances from Alon.

•

Our revenues for the three and six months ended June 30, 2009 include $4.8 million and $7.7 million, respectively, of shortfalls billed under the Alon PTA in 2008 as Alon did not exceed its minimum revenue obligation in any of the subsequent four quarters. Deferred revenue in the consolidated balance sheets at June 30, 2009 and December 31, 2008 includes $7.5 million and $13.3 million, respectively, relating to the Alon PTA. It is possible that Alon may not exceed its minimum obligations under the Alon PTA to allow Alon to receive credit for any of the $7.5 million deferred at June 30, 2009.

BP

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

•

BP is one of multiple shippers on the Rio Grande pipeline. We recorded revenues from BP of $2.2 million for the three months ended June 30, 2009 and 2008 and $3.8 million and $4.9 million for the six months ended June 30, 2009 and 2008, respectively.

•

Included in our accounts receivable – trade at June 30, 2009 and December 31, 2008 were $1.1 million and $0.8 million, respectively, which represented the receivable balance of Rio Grande from BP.

Note 10: HEP Partners’ Equity, Income Allocations, Cash Distributions and Comprehensive Income

Issuances of units

As of June 30, 2009, Holly holds 7,000,000 of our subordinated units and 290,000 of our common units, which constitutes a 41% ownership interest in us, including the 2% general partner interest. The subordination period of Holly’s subordinated units extends until the first day of any quarter beginning after June 30, 2009 that certain conditions are met. After giving effect to the payment of our quarterly distribution for the quarter ended June 30, 2009, we expect that all of the conditions necessary to end the subordination period will be satisfied and the Holly owned subordinated units will convert into 7,000,000 common units two business days after the distribution is paid.

In May 2009, we closed a public offering of 2,192,400 of our common units priced at $27.80 per unit including 192,400 common units issued pursuant to the underwriters’ exercise of their over-allotment option. Net proceeds of $58.4 million were used to repay bank debt and for general partnership purposes. In addition, we received a $1.2 million capital contribution from our general partner to maintain its 2% general partner interest.

Under our registration statement filed with the SEC using a “shelf” registration process, we currently have the ability to raise approximately $940.0 million through security offerings, 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 attributable to Holly Energy Partners, L.P. is allocated between limited partners and the general partner interest in accordance with the provisions of the partnership agreement. HEP net income allocated to the general partner includes incentive distributions that are declared subsequent to quarter end. After the amount of incentive distributions is allocated to the general partner, the remaining net income attributable to HEP is generally allocated to the partners based on their weighted average ownership percentage during the period.

The following table presents the allocation of the general partner interest in net income attributable to HEP:

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2009				2008				2009				2008
		(In thousands, except per unit data)
General partner interest in net income		$	304			$	61			$	392			$	202
General partner incentive distribution			1,545				788				2,750				1,526
Total general partner interest in net income attributable to HEP		$	1,849			$	849			$	3,142			$	1,728

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 agreement, occurs or would result from the cash distribution.

Our 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.

On July 23, 2009, we announced our cash distribution for the second quarter of 2009 of $0.785 per unit. The distribution is payable on all common, subordinated and general partner units and will be paid August 14, 2009 to all unitholders of record on August 3, 2009.

The following table presents the allocation of our regular quarterly cash distributions to the general and limited partners for the periods to which they apply. Our distributions are declared subsequent to quarter end, therefore the amounts presented do not reflect distributions paid in the periods presented below.

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2009				2008				2009				2008
		(In thousands, except per unit data)
General partner interest		$	328			$	264			$	611			$	524
General partner incentive distribution			1,545				788				2,750				1,526
Total general partner distribution			1,873				1,052				3,361				2,050
Limited partner distribution			14,538				12,200				27,200				24,234
Total regular quarterly cash distribution		$	16,411			$	13,252			$	30,561			$	26,284
Cash distribution per unit applicable to limited partners		$	0.785			$	0.745			$	1.560			$	1.480

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 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 and equipment and intangible assets instead of reductions to equity.

Comprehensive Income

We have other comprehensive income resulting from fair value adjustments to our cash flow hedge. Our comprehensive income is as follows:

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2009				2008				2009				2008
		(In thousands)
Net income		$	16,819			$	4,079			$	22,753			$	12,283
Other comprehensive income:
Change in fair value of cash flow hedge			4,417				6,797				4,267				2,448
Comprehensive income			21,236				10,876				27,020				14,731
Less noncontrolling interest in comprehensive income			427				264				922				670
Comprehensive income attributable to HEP unitholders		$	20,809			$	10,612			$	26,098			$	14,061

Note 11: 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.

Condensed Consolidating Balance Sheet

						Guarantor				Non-
June 30, 2009		Parent				Subsidiaries				Guarantor				Eliminations				Consolidated
		(In thousands)
ASSETS
Current assets:
Cash and cash equivalents		$	2			$	1,304			$	2,889			$	—			$	4,195
Accounts receivable			—				12,325				1,155				—				13,480
Intercompany accounts receivable (payable)			(169,661	)			169,846				(185	)			—				—
Prepaid and other current assets			6				821				—				—				827
Total current assets			(169,653	)			184,296				3,859				—				18,502
Properties and equipment, net			—				304,904				31,781				—				336,685
Investment in subsidiaries			411,367				24,594				—				(435,961	)			—
Transportation agreements, net			—				118,909				—				—				118,909
Investment in SLC Pipeline			—				26,098				—				—				26,098
Other assets			3,799				1,122				—				—				4,921
Total assets		$	245,513			$	659,923			$	35,640			$	(435,961	)		$	505,115
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable		$	—			$	8,992			$	128			$	—			$	9,120
Accrued interest			(2,842	)			5,713				—				—				2,871
Deferred revenue			—				10,989				—				—				10,989
Accrued property taxes			—				934				92				—				1,026
Other current liabilities			6,117				(5,345	)			286				—				1,058
Total current liabilities			3,275				21,283				506				—				25,064
Long-term debt			184,810				218,000				—				—				402,810
Other long-term liabilities			2.209				9,273				—				—				11,482
Equity — HEP			55,219				411,367				35,134				(446,501	)			55,219
Equity – noncontrolling interest			—				—				—				10,540				10,540
Total liabilities and equity		$	245,513			$	659,923			$	35,640			$	(435,961	)		$	505,115

Condensed Consolidating Balance Sheet

						Guarantor				Non-
December 31, 2008		Parent				Subsidiaries				Guarantor				Eliminations				Consolidated
		(In thousands)
ASSETS
Current assets:
Cash and cash equivalents		$	2			$	3,706			$	1,561			$	—			$	5,269
Accounts receivable			—				13,332				1,145				—				14,477
Intercompany accounts receivable (payable)			(197,828	)			197,979				(151	)			—				—
Prepaid and other current assets			176				417				—				—				593
Total current assets			(197,650	)			215,434				2,555				—				20,339
Properties and equipment, net			—				257,886				32,398				—				290,284
Investment in subsidiaries			378,481				23,842				—				(402,323	)			—
Transportation agreements, net			—				122,383				—				—				122,383
Other assets			5,300				1,382				—				—				6,682
Total assets		$	186,131			$	620,927			$	34,953			$	(402,323	)		$	439,688
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable		$	—			$	7,357			$	661			$	—			$	8,018
Accrued interest			(27,778	)			30,623				—				—				2,845
Deferred revenue			—				15,658				—				—				15,658
Accrued property taxes			—				1,015				130				—				1,145
Other current liabilities			31,214				(29,811	)			102				—				1,505
Short-term borrowings under credit agreement			—				29,000				—				—				29,000
Total current liabilities			3,436				53,842				893				—				58,171
Long-term debt			184,793				171,000				—				—				355,793
Other long-term liabilities			—				17,604				—				—				17,604
Equity — HEP			(2,098	)			378,481				34,060				(412,541	)			(2,098	)
Equity – noncontrolling interest			—				—				—				10,218				10,218
Total liabilities and equity		$	186,131			$	620,927			$	34,953			$	(402,323	)		$	439,688

Condensed Consolidating Statement of Income

						Guarantor				Non-
Three months ended June 30, 2009		Parent				Subsidiaries				Guarantor				Eliminations				Consolidated
		(In thousands)
Revenues:
Affiliates		$	—			$	25,064			$	—			$	—			$	25,064
Third parties			—				13,286				2,603				(351	)			15,538
			—				38,350				2,603				(351	)			40,602
Operating costs and expenses:
Operations			—				10,637				800				(351	)			11,086
Depreciation and amortization			—				6,512				341				—				6,853
General and administrative			590				1,207				21				—				1,818
			590				18,356				1,162				(351	)			19,757
Operating income (loss)			(590	)			19,994				1,441				—				20,845
Other income (expense):
Equity in earnings of subsidiaries			15,930				996				—				(16,926	)			—
Equity in earnings of SLC Pipeline			—				423				—				—				423
Interest income (expense)			1,052				(5,454	)			—				—				(4,402	)
Other			—				65				—				—				65
			16,982				(3,970	)			—				(16,926	)			(3,914	)
Income (loss) before income taxes			16,392				16,024				1,441				(16,926	)			16,931
State income tax			—				(94	)			(18	)			—				(112	)
Net income			16,392				15,930				1,423				(16,926	)			16,819
Less noncontrolling interest in net income			—				—				—				427				427
Net income attributable to HEP		$	16,392			$	15,930			$	1,423			$	(17,353	)		$	16,392