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		(I.R.S. Employer
incorporation or organization)		Identification No.)

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

(Address of principal executive offices)

(214) 871-3555

(Registrant’s telephone number, including area code)

None

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

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

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 definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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 October 23, 2009 was 17,582,400.

 

 

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			28
Item 3. Quantitative and Qualitative Disclosures About Market Risks			47
Item 4. Controls and Procedures			47
PART II. OTHER INFORMATION			48
Item 1. Legal Proceedings			48
Item 6. Exhibits			48
SIGNATURES			49
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.

		September 30,
		2009				December 31,
		(Unaudited)				2008
		(In thousands, except unit data)
ASSETS
Current assets:
Cash and cash equivalents		$	4,050			$	5,269
Accounts receivable:
Trade			4,965				5,082
Affiliates			11,176				9,395
			16,141				14,477
Prepaid and other current assets			1,070				593
Total current assets			21,261				20,339
Properties and equipment, net			349,062				290,284
Transportation agreements, net			117,173				122,383
Investment in SLC Pipeline			26,809				—
Other assets			4,660				6,682
Total assets		$	518,965			$	439,688
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade		$	3,001			$	5,816
Affiliates			1,965				2,202
			4,966				8,018
Accrued interest			916				2,845
Deferred revenue			7,582				15,658
Accrued property taxes			1,486				1,145
Other current liabilities			1,368				1,505
Short-term borrowings under credit agreement			—				29,000
Total current liabilities			16,318				58,171
Long-term debt			429,819				355,793
Other long-term liabilities			13,759				17,604
Equity:
Holly Energy Partners, L.P. partners’ equity (deficit):
Common unitholders (17,582,400 and 8,390,000 units issued and outstanding at September 30, 2009 and December 31, 2008, respectively)			136,746				169,126
Subordinated unitholders (7,000,000 units issued and outstanding at December 31, 2008)			—				(85,059	)
Class B subordinated unitholders (937,500 units issued and outstanding at September 30, 2009 and December 31, 2008)			21,054				21,455
General partner interest (2% interest)			(99,359	)			(94,653	)
Accumulated other comprehensive loss			(10,181	)			(12,967	)
Total Holly Energy Partners, L.P. partners’ equity (deficit)			48,260				(2,098	)
Noncontrolling interest			10,809				10,218
Total equity			59,069				8,120
Total liabilities and equity		$	518,965			$	439,688

See accompanying notes.

Holly Energy Partners, L.P.

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2009				2008				2009				2008
		(In thousands, except per unit data)
Revenues:
Affiliates		$	28,359			$	22,737			$	71,746			$	61,210
Third parties			14,385				6,774				43,724				22,352
			42,744				29,511				115,470				83,562
Operating costs and expenses:
Operations			11,450				11,033				33,332				30,745
Depreciation and amortization			6,820				5,884				19,929				16,259
General and administrative			1,848				1,596				4,990				4,241
			20,118				18,513				58,251				51,245
Operating income			22,626				10,998				57,219				32,317
Other income (expense):
Equity in earnings of SLC Pipeline			711				—				1,309				—
SLC Pipeline acquisition costs			—				—				(2,500	)			—
Interest income			2				25				10				146
Interest expense			(6,418	)			(5,161	)			(16,225	)			(14,201	)
Other			—				1,007				65				1,043
			(5,705	)			(4,129	)			(17,341	)			(13,012	)
Income before income taxes			16,921				6,869				39,878				19,305
State income tax			(113	)			(84	)			(317	)			(237	)
Net income			16,808				6,785				39,561				19,068
Less noncontrolling interest in net income			269				164				1,191				834
Net income attributable to Holly Energy Partners, L.P.		$	16,539			$	6,621			$	38,370			$	18,234
Less general partner interest in net income attributable to Holly Energy Partners, L.P.			2,022				1,008				5,163				2,736
Limited partners’ interest in net income attributable to Holly Energy Partners, L.P.		$	14,517			$	5,613			$	33,207			$	15,498
Limited partners’ per unit interest in net income attributable to Holly Energy Partners, L.P. — basic and diluted		$	0.78			$	0.34			$	1.89			$	0.95
Weighted average limited partners’ units outstanding			18,520				16,328				17,546				16,279

See accompanying notes.

Holly Energy Partners, L.P.

		Nine Months Ended
		September 30,
		2009				2008
		(In thousands)
Cash flows from operating activities
Net income		$	39,561			$	19,068
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization			19,929				16,259
Equity in earnings of SLC Pipeline			(1,309	)			—
Change in fair value — interest rate swaps			300				—
Amortization of restricted and performance units			631				1,194
Gain on sale of assets			—				(36	)
(Increase) decrease in current assets:
Accounts receivable — trade			117				(892	)
Accounts receivable — affiliates			(1,781	)			(3,388	)
Prepaid and other current assets			(477	)			(312	)
Increase (decrease) in current liabilities:
Accounts payable — trade			(2,815	)			(52	)
Accounts payable — affiliates			(237	)			(3,684	)
Accrued interest			(1,929	)			(1,985	)
Deferred revenue			(8,076	)			10,638
Accrued property taxes			341				200
Other current liabilities			(137	)			278
Other, net			670				802
Net cash provided by operating activities			44,788				38,090
Cash flows from investing activities
Additions to properties and equipment			(27,478	)			(29,024	)
Acquisition of 16-inch intermediate pipeline			(34,200	)			—
Investment in SLC Pipeline			(25,500	)			—
Acquisition of Tulsa loading racks			(11,800	)			—
Acquisition of crude pipelines and tankage assets			—				(171,000	)
Proceeds from sale of assets			—				36
Net cash used for investing activities			(98,978	)			(199,988	)
Cash flows from financing activities
Borrowings under credit agreement			197,000				221,000
Repayments under credit agreement			(152,000	)			(26,000	)
Proceeds from issuance of common units			58,355				104
Capital contribution from general partner			1,191				186
Distributions to HEP unitholders			(44,393	)			(38,908	)
Purchase price in excess of transferred basis in Tulsa loading racks			(5,700	)			—
Distributions to noncontrolling interest			(600	)			(1,200	)
Cost of issuing common units			(266	)			—
Purchase of units for restricted grants			(616	)			(795	)
Deferred financing costs			—				(692	)
Net cash provided by financing activities			52,971				153,695
Cash and cash equivalents
Decrease for period			(1,219	)			(8,203	)
Beginning of period			5,269				10,321
End of period		$	4,050			$	2,118

See accompanying notes.

Holly Energy Partners, L.P.

		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 in public offering			58,355				—				—				—				—				—				58,355
Conversion of subordinated units			(90,824	)			90,824				—				—				—				—				—
Cost of issuing common units			(266	)			—				—				—				—				—				(266	)
Capital contribution			—				—				—				1,191				—				—				1,191
Distributions — HEP unitholders			(21,253	)			(16,275	)			(2,180	)			(4,685	)			—				—				(44,393	)
Distributions — noncontrolling interest			—				—				—				—				—				(600	)			(600	)
Purchase price in excess of transferred basis in Tulsa loading racks			—				—				—				(5,700	)			—				—				(5,700	)
Purchase of units for restricted grants			(616	)			—				—				—				—				—				(616	)
Amortization of restricted and performance units			631				—				—				—				—				—				631
Comprehensive income:
Net income			21,593				10,510				1,779				4,488				—				1,191				39,561
Change in fair value of cash flow hedge			—				—				—				—				2,786				—				2,786
Comprehensive income			21,593				10,510				1,779				4,488				2,786				1,191				42,347
Balance September 30, 2009		$	136,746			$	—			$	21,054			$	(99,359	)		$	(10,181	)		$	10,809			$	59,069

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 and terminals, tankage and loading rack 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.

In June 2009, Holly acquired a petroleum refinery, including supporting infrastructure, located in Tulsa, Oklahoma (the “Tulsa Refinery”). On August 1, 2009, we acquired from Holly certain on-site truck and rail loading/unloading facilities that service the Tulsa Refinery. See Note 2 for additional information on this transaction.

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 of this quarterly report on October 30, 2009.

Recent Accounting Pronouncements

Accounting Standards Codification

In June 2009, the Financial Accounting Standards Board (“FASB”) issued its Accounting Standards Codification (“ASC”), codifying all previous sources of accounting principles into a single source of authoritative, nongovernmental U.S. generally accepted accounting principles (“U.S. GAAP”). Although the ASC supersedes all previous levels of authoritative accounting standards, it did not affect accounting principles under U.S. GAAP. We adopted the codification effective September 30, 2009.

Subsequent Events

In May 2009, the FASB issued accounting standards under ASC Topic “Subsequent Events” (previously Statement of Financial Accounting Standard (“SFAS”) No. 165) which establish 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 these standards effective June 30, 2009. Although these standards require 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.

Interim Disclosures about Fair Value of Financial Instruments

In April 2009, the FASB issued accounting standards under ASC Topic “Financial Instruments” (previously FASB Staff Position (“FSP”) SFAS No. 107-1 and Accounting Principles Board (“APB”) Opinion No. 28-1) which extend the annual financial statement disclosure requirements for financial instruments to interim reporting periods of publicly traded companies. We adopted these standards effective June 30, 2009. See Note 3 for disclosure of our financial instruments.

Noncontrolling Interests in Consolidated Financial Statements

Accounting standards under ASC Topic “Noncontrolling Interest in a Subsidiary” (previously SFAS No. 160) became effective January 1, 2009, which change 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 these standards, 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 these standards on a retrospective basis. While this presentation differs from previous U.S. GAAP requirements, it did not affect our net income and equity attributable to HEP.

Business Combinations

Accounting standards under ASC Topic “Business Combinations” (previously SFAS 141 No. (R)) became effective January 1, 2009, which establish 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.

Disclosures about Derivative Instruments and Hedging Activities

Accounting standards under ASC Topic “Derivatives and Hedging” (previously SFAS No. 161) became effective January 1, 2009, which amend and expand disclosure requirements 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.

Earnings per Share — Master Limited Partnerships

Accounting standards under ASC Topic “Earnings Per Share” (previously Emerging Issues Task Force (“EITF”) Issue No. 07-04) became effective January 1, 2009, which prescribe 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 these standards, our general partner earnings allocations included incentive distributions that were declared during each quarter. We have applied these standards on a retrospective basis. The adoption of these standards resulted in a decrease in our limited partners’ interest in net income attributable to Holly Energy Partners, L.P. for the three and nine months ended September 30, 2008, reducing earnings per limited partner unit by $.01 to $0.34 and $0.95 for the three and nine months ended September 30, 2008, respectively.

Participating Securities — Instruments Granted in Share-Based Transactions

Accounting standards under ASC Topic “Earnings Per Share” (previously FSP No. 03-6-1) became effective January 1, 2009, which provide 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. The adoption of these standards did not have a material impact on our financial condition, results of operations and cash flows.

Note 2: Acquisitions

Tulsa Loading Racks Transaction

On August 1, 2009, we acquired from Holly certain truck and rail loading/unloading facilities located at Holly’s Tulsa Refinery (the “Tulsa Loading Racks”) for $17.5 million. The racks load refined products produced at the Tulsa Refinery onto rail cars and/or tanker trucks for delivery to surrounding markets. In accounting for this transaction, we recorded property and equipment of $11.8 million representing Holly’s cost basis in the transferred assets since we are a controlled subsidiary of Holly and recorded the remaining $5.7 million as a decrease to our partners’ equity.

In connection with this transaction, we entered into a 15-year equipment and throughput agreement with Holly (the “Holly ETA”), whereby Holly has agreed to throughput a minimum volume of products via the Tulsa Loading Racks that will initially result in minimum annual revenues to us of $2.7 million.

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, and contributions to and distributions from the SLC Pipeline 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 based upon 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 principal under our revolving credit agreement (the “Credit Agreement”) and our 6.25% senior notes (the “Senior Notes”). The $245.0 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 $169.3 million at September 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

Fair value measurements are derived using inputs, assumptions that market participants would use in pricing an asset or liability, including assumptions about risk. GAAP 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

		September 30,				December 31,
		2009				2008
		(In thousands)
Pipelines and terminals		$	344,084			$	308,056
Land and right of way			26,978				24,991
Other			11,882				11,498
Construction in progress			75,088				38,589
			458,032				383,134
Less accumulated depreciation			108,970				92,850
		$	349,062			$	290,284

We capitalized $0.9 million and $0.7 million in interest related to major construction projects during the nine months ended September 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:

		September 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			16,991				11,781
		$	117,173			$	122,383

We have three 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”). We also have the Holly IPA that relates to the Intermediate Pipelines acquired from Holly in 2005 and in June 2009 and the Holly ETA that relates to the Tulsa Loading Racks acquired in August 2009. 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 $0.8 million and $0.6 million for the three months ended September 30, 2009 and 2008, respectively, and $2.0 million and $1.6 million for the nine months ended September 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 September 30, 2009, we have two types of equity-based compensation, which are described below. The compensation cost charged against income for these plans was $0.2 million and $0.6 million for the three months ended September 30, 2009 and 2008, respectively, and $1.1 million and $1.4 million for the nine months ended September 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 September 30, 2009, 350,000 units were authorized to be granted under the equity-based compensation plans, of which 203,684 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 nine months ended September 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			33,422				26.00
Forfeited			(2,152	)			42.53
Vesting and transfer of full ownership to recipients			(31,504	)			36.76
Outstanding at September 30, 2009 (not vested)			53,271			$	34.31			0.8 year				$	2,078

The fair value of restricted units that were vested and transferred to recipients during the nine months ended September 30, 2009 and 2008 were $1.2 million and $0.9 million, respectively. As of September 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 0.8 year.

During the nine months ended September 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 September 30, 2009, estimated share payouts for outstanding nonvested performance unit awards ranged from 110% to 120%.

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 nine months ended September 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 September 30, 2009 (not vested)			54,771

The fair value of performance units that were vested and transferred to recipients during the nine months ended September 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 September 30, 2009 there was $0.9 million of total unrecognized compensation cost related to nonvested performance units. That cost is expected to be recognized over a weighted-average period of 1.3 years.

Note 7: 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 nine months ended September 30, 2009, we received advances totaling $197.0 million that were used as interim financing for our acquisitions and for capital projects and repaid $152.0 million, resulting in $45.0 million in net advances received. As of September 30, 2009, we had $245.0 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 September 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). At September 30, 2009, we were subject to an applicable margin of 1.75%. We incur a commitment fee on the unused portion of the Credit Agreement at a rate ranging from 0.20% to 0.50% based upon the ratio of our funded debt to EBITDA for the four most recently completed fiscal quarters. At September 30, 2009, we are subject to a 0.30% commitment fee on the $55.0 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 become 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:

		September 30,				December 31,
		2009				2008
		(In thousands)
Credit Agreement		$	245,000			$	200,000
Senior Notes
Principal			185,000				185,000
Unamortized discount			(2,058	)			(2,344	)
Unamortized premium — dedesignated fair value hedge			1,877				2,137
			184,819				184,793
Total debt			429,819				384,793
Less net short-term borrowings under credit agreement(1)			—				29,000
Total long-term debt(1)		$	429,819			$	355,793

Interest Rate Risk Management

We use interest rate derivatives to manage our exposure to interest rate risk. As of September 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 1.75%, which equaled an effective interest rate of 5.49% as of September 30, 2009. The maturity date of this swap contract is February 28, 2013.

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 September 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 1.52% as of September 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 nine months ended September 30, 2009, we recognized an increase of $0.9 million and $0.3 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 September 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				$	2,658			Long-term debt				$	(1,877	)
- $60 million of 6.25% Senior Notes										HEP partners’ equity					(1,942	)(1)
										Interest expense					1,161	(2)
						$	2,658							$	(2,658	)
Liability
Cash flow hedge — $171 million		Other long-term								Accumulated other
LIBOR based debt		liabilities				$	(10,182	)		comprehensive loss				$	10,182
Variable-to-fixed interest rate swap		Other long-term								HEP partners’ equity					4,166	(1)
- $60 million		liabilities					(3,044	)		Interest expense					(1,122	)
						$	(13,226	)						$	13,226

Interest Expense and Other Debt Information

Interest expense consists of the following components:

		Nine Months Ended
		September 30,
		2009				2008
		(In thousands)
Interest on outstanding debt:
Senior Notes, net of interest rate swaps		$	8,320			$	7,901
Credit Agreement, net of interest rate swap			8,045				6,013
Net amortization of discount and deferred debt issuance costs			529				739
Commitment fees			202				241
Total interest incurred			17,096				14,894
Less capitalized interest			871				693
Net interest expense		$	16,225			$	14,201
Cash paid for interest(1)		$	18,307			$	11,414

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								Nine Months Ended
		September 30,								September 30,
		2009				2008				2009				2008
Holly			66	%			77	%			62	%			73	%
Alon			24	%			13	%			27	%			15	%
BP			3	%			6	%			5	%			8	%

Note 9: Related Party Transactions

Holly and Alon Agreements

As of September 30, 2009, we serve Holly’s refineries in New Mexico, Utah and Oklahoma under multiple long-term pipeline and terminal, tankage and throughput agreements. The substantial majority of our business is devoted to providing transportation, storage and terminalling services to Holly.

In connection with our August 2009 acquisition of the Tulsa Loading Racks from Holly, we entered into the Holly ETA, a 15-year equipment and throughput agreement that expires in 2024. Under this agreement, Holly has agreed to throughput a minimum volume of products via the Tulsa Loading Racks that will initially result in minimum annual revenues to us of $2.7 million.

We have three additional agreements that also relate to assets acquired from Holly. We have the Holly PTA (expiring in 2019) that relates to the pipelines and terminals contributed to us at the time of our initial public offering in 2004, the Holly IPA (expiring in 2024) that relates to the Intermediate Pipelines acquired in 2005 and in June 2009, and the Holly CPTA (expiring in 2023) that relates to the Crude Pipelines and Tankage Assets acquired in 2008.

Under the Holly PTA, Holly IPA, Holly CPTA and Holly ETA, Holly agreed to transport, store and throughput volumes of refined product and crude oil on our pipelines and terminals, tankage and loading rack facilities that result in minimum annual payments to us. These minimum annual payments or revenues will be adjusted each year at a percentage change based upon 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 based upon 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 $95.3 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 and the Holly ETA, 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 have with Holly, 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 $28.4 million and $22.7 million for the three months ended September 30, 2009 and 2008, respectively, and $71.7 million and $61.2 million for the nine months ended September 30, 2009 and 2008, respectively. These amounts include the revenues received under the Holly PTA, Holly IPA, Holly CPTA and Holly ETA.

•

Holly charged general and administrative services under the Omnibus Agreement of $0.6 million for the three months ended September 30, 2009 and 2008 and $1.7 million and $1.6 million for the nine months ended September 30, 2009 and 2008, respectively.

•

We reimbursed Holly for costs of employees supporting our operations of $4.2 million and $3.7 million for the three months ended September 30, 2009 and 2008, respectively, and $12.8 million and $9.8 million for the nine months ended September 30, 2009 and 2008, respectively.

•

We distributed $7.6 million and $6.5 million during the three months ended September 30, 2009 and 2008, respectively, to Holly as regular distributions on its common units, subordinated units and general partner interest, including general partner incentive distributions. We distributed $21.6 million and $18.9 million during the nine months ended September 30, 2009 and 2008, respectively.

•

Our accounts receivable from Holly was $11.2 million and $9.4 million at September 30, 2009 and December 31, 2008, respectively.

•

Holly has failed to meet its minimum volume commitment for each of the seventeen quarters since inception of the Holly IPA. Through September 30, 2009, we have charged Holly $9.8 million for these shortfalls to date, $0.6 million and $0.5 million of which is included in affiliate accounts receivable at September 30, 2009 and December 31, 2008, respectively.

•

Our revenues for the three and nine months ended September 30, 2009 include $0.8 million and $1.9 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 September 30, 2009 and December 31, 2008, includes $3.3 million and $2.4 million, respectively, relating to the Holly IPA. It is possible that Holly may not exceed its minimum obligations under the Holly IPA to allow Holly to receive credit for any of the $3.3 million deferred at September 30, 2009.

•

We acquired the Tulsa Loading Racks, our 16-inch intermediate pipeline and the Crude Pipelines and Tankage Assets from Holly in August 2009, June 2009 and February 2008, respectively. See Note 2 for a description of these transactions.

•

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 $8.8 million and $1.9 million for the three months ended September 30, 2009 and 2008, respectively, and $25.8 million and $6.8 million for the nine months ended September 30, 2009 and 2008, respectively, under the Alon PTA. Additionally, pipeline revenues received under a pipeline capacity lease agreement with Alon were $1.6 million and $1.8 million for the three months ended September 30, 2009 and 2008, respectively, and $5.0 million and $5.3 million for the nine months ended September 30, 2009 and 2008, respectively.

•

We distributed $0.7 million during the three months ended September 30, 2009 and 2008 and $2.2 million and $2.1 million during the nine months ended September 30, 2009 and 2008, respectively, to Alon as distributions on its Class B subordinated units.

•

Our accounts receivable — trade include receivable balances from Alon of $3.2 million and $2.5 million at September 30, 2009 and December 31, 2008, respectively.

•

Our revenues for the three and nine months ended September 30, 2009 include $4.3 million and $11.9 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 September 30, 2009 and December 31, 2008 includes $4.3 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 $4.3 million deferred at September 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 $1.4 million and $1.7 million for the three months ended September 30, 2009 and 2008, respectively, and $5.3 million and $6.6 million for the nine months ended September 30, 2009 and 2008, respectively.

•

Our accounts receivable — trade at September 30, 2009 and December 31, 2008 includes Rio Grande’s receivable balances from BP of $0.6 million and $0.8 million, respectively.

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

Issuances of units

As of September 30, 2009, Holly holds 7,290,000 of our common units and the 2% general partner interest, which together constitutes a 41% ownership interest in us. In August 2009, all of the conditions necessary to end the subordination period for the 7,000,000 subordinated units owned by Holly were met and the units were converted into our common units on a one-for-one basis.

Currently, Alon owns all 937,500 of our Class B subordinated units. The subordination period of these units extends until the first day of any quarter beginning after March 31, 2010 provided Alon is not in default with respect to payments due under its minimum volume commitments under the Alon PTA for each of the three consecutive, non-overlapping four-quarter periods immediately preceding such date. At the end of the subordination period, the Class B subordinated units will convert into our common units on a one-for-one basis.

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								Nine Months Ended
		September 30,								September 30,
		2009				2008				2009				2008
		(In thousands, except per unit data)
General partner interest in net income		$	300			$	115			$	691			$	316
General partner incentive distribution			1,722				893				4,472				2,420
Total general partner interest in net income attributable to HEP		$	2,022			$	1,008			$	5,163			$	2,736

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 October 22, 2009, we announced our cash distribution for the third quarter of 2009 of $0.795 per unit. The distribution is payable on all common, subordinated and general partner units and will be paid November 13, 2009 to all unitholders of record on November 2, 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								Nine Months Ended
		September 30,								September 30,
		2009				2008				2009				2008
		(In thousands, except per unit data)
General partner interest		$	336			$	268			$	947			$	792
General partner incentive distribution			1,722				893				4,472				2,420
Total general partner distribution			2,058				1,161				5,419				3,212
Limited partner distribution			14,723				12,357				41,938				36,591
Total regular quarterly cash distribution		$	16,781			$	13,518			$	47,357			$	39,803
Cash distribution per unit applicable to limited partners		$	0.795			$	0.755			$	2.355			$	2.235

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.

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								Nine Months Ended
		September 30,								September 30,
		2009				2008				2009				2008
						(In thousands)
Net income		$	16,808			$	6,785			$	39,561			$	19,068
Other comprehensive income:
Change in fair value of cash flow hedge			(1,482	)			(1,623	)			2,786				825
Comprehensive income			15,326				5,162				42,347				19,893
Less noncontrolling interest in comprehensive income			269				164				1,191				834
Comprehensive income attributable to HEP unitholders		$	15,057			$	4,998			$	41,156			$	19,059

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-
September 30, 2009		Parent				Subsidiaries				Guarantor				Eliminations				Consolidated
		(In thousands)
ASSETS
Current assets:
Cash and cash equivalents		$	2			$	303			$	3,745			$	—			$	4,050
Accounts receivable			—				14,589				1,552				—				16,141
Intercompany accounts receivable (payable)			(191,973	)			191,983				(10	)			—				—
Prepaid and other current assets			387				683				—				—				1,070
Total current assets			(191,584	)			207,558				5,287				—				21,261
Properties and equipment, net			—				317,612				31,450				—				349,062
Investment in subsidiaries			425,592				25,222				—				(450,814	)			—
Transportation agreements, net			—				117,173				—				—				117,173
Investment in SLC Pipeline			—				26,809				—				—				26,809
Other assets			3,669				991				—				—				4,660
Total assets		$	237,677			$	695,365			$	36,737			$	(450,814	)		$	518,965
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable		$	—			$	4,699			$	267			$	—			$	4,966
Accrued interest			(888	)			1,804				—				—				916
Deferred revenue			—				7,582				—				—				7,582
Accrued property taxes			—				1,348				138				—				1,486
Other current liabilities			2,442				(1,375	)			301				—				1,368
Total current liabilities			1,554				14,058				706				—				16,318
Long-term debt			184,819				245,000				—				—				429,819
Other long-term liabilities			3,044				10,715				—				—				13,759
Equity — HEP			48,260				425,592				36,031				(461,623	)			48,260
Equity — noncontrolling interest			—				—				—				10,809				10,809
Total liabilities and equity		$	237,677			$	695,365			$	36,737			$	(450,814	)		$	518,965

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 September 30, 2009		Parent				Subsidiaries				Guarantor				Eliminations				Consolidated
		(In thousands)
Revenues:
Affiliates		$	—			$	28,359			$	—			$	—			$	28,359
Third parties			—				12,791				1,939				(345	)			14,385
			—				41,150				1,939				(345	)			42,744
Operating costs and expenses:
Operations			—				11,105				690				(345	)			11,450
Depreciation and amortization			—				6,481				339				—				6,820
General and administrative			1,907				(59	)			—				—				1,848
			1,907				17,527				1,029				(345	)			20,118
Operating income (loss)			(1,907	)			23,623				910				—				22,626
Other income (expense):
Equity in earnings of subsidiaries			25,032				628				—				(25,660	)			—
Equity in earnings of SLC Pipeline			—				711				—				—				711
Interest income (expense)			(6,586	)			170				—				—				(6,416	)
			18,446				1,509				—				(25,660	)			(5,705	)
Income (loss) before income taxes			16,539				25,132				910				(25,660	)			16,921
State income tax			—				(100	)			(13	)			—				(113	)
Net income			16,539				25,032				897				(25,660	)			16,808
Less noncontrolling interest in net income			—				—				—				269				269
Net income attributable to HEP		$	16,539			$	25,032			$	897			$	(25,929	)		$	16,539