UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2008

OR

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

For the transition period from                       to                      .

Commission File Number: 1-32225

HOLLY ENERGY PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

Delaware		20-0833098
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		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 is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

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

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

Yes o      No þ

The number of the registrant’s outstanding common units at April 30, 2008 was 8,390,000.

 

 

HOLLY ENERGY PARTNERS, L.P.
INDEX

PART I. FINANCIAL INFORMATION			3
FORWARD-LOOKING STATEMENTS			3
Item 1. Financial Statements (Unaudited, except December 31, 2007 Balance Sheet)			4
Consolidated Balance Sheets			4
Consolidated Statements of Income			5
Consolidated Statements of Cash Flows			6
Consolidated Statement of Partners’ Equity (Deficit) and Comprehensive Income			7
Notes to Consolidated Financial Statements			8
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			25
Item 3. Quantitative and Qualitative Disclosures About Market Risks			40
Item 4. Controls and Procedures			40
PART II. OTHER INFORMATION			41
Item 1. Legal Proceedings			41
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			41
Item 6. Exhibits			41
SIGNATURES			43
Computation of Ratio of Earnings to Fixed Charges
Certification of Chief Executive Officer Pursuant to Section 302
Certification of Chief Financial Officer Pursuant to Section 302
Certification of Chief Executive Officer Pursuant to Section 906
Certification of Chief Financial Officer Pursuant to Section 906

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 and crude oil 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 our financing;
	•		The possibility of reductions in production or shutdowns at refineries utilizing our pipeline and terminal facilities;
	•		The effects of current and future government regulations and policies;
	•		Our operational efficiency in carrying out routine operations and capital construction projects;
	•		The possibility of terrorist attacks and the consequences of any such attacks;
	•		General economic conditions; and
	•		Other financial, operations and legal risks and uncertainties detailed from time to time in our Securities and Exchange Commission filings.

Cautionary statements identifying important factors that could cause actual results to differ materially from our expectations are set forth in this Form 10-Q, including without limitation, in conjunction with the forward-looking statements included in this Form 10-Q that are referred to above. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements set forth in our Annual Report on Form 10-K for the year ended December 31, 2007 in “Risk Factors,” and in this Form 10-Q in “Management’s Discussion and Analysis of Financial Condition and Results of Operations”. All forward-looking statements included in this Form 10-Q and all subsequent written or oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. The forward-looking statements speak only as of the date made and, other than as required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Item 1. Financial Statements

Holly Energy Partners, L.P.

		March 31, 2008				December 31,
		(Unaudited)				2007
		(In thousands, except unit data)
ASSETS
Current assets:
Cash and cash equivalents		$	8,237			$	10,321
Accounts receivable:
Trade			5,184				6,611
Affiliates			7,773				5,700
			12,957				12,311
Prepaid and other current assets			342				546
Total current assets			21,536				23,178
Properties and equipment, net			274,187				158,600
Transportation agreements, net			125,374				54,273
Other assets			6,209				2,853
Total assets		$	427,306			$	238,904
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable		$	4,773			$	3,011
Accounts payable — affiliates			5,068				6,021
Accrued interest			1,027				2,996
Deferred revenue			5,551				3,700
Accrued property taxes			626				1,177
Other current liabilities			651				827
Short-term borrowings under credit agreement			10,000				—
Total current liabilities			27,696				17,732
Commitments and contingencies			—				—
Long-term debt			356,330				181,435
Other long-term liabilities			4,695				1,181
Minority interest			11,145				10,740
Partners’ equity (deficit):
Common unitholders (8,390,000 and 8,170,000 units issued and outstanding at March 31, 2008 and December 31, 2007, respectively)			179,034				172,807
Subordinated unitholders (7,000,000 units issued and outstanding)			(75,779	)			(73,725	)
Class B subordinated unitholders (937,500 units issued and outstanding)			22,697				22,973
General partner interest (2% interest)			(94,163	)			(94,239	)
Accumulated other comprehensive loss			(4,349	)			—
Total partners’ equity			27,440				27,816
Total liabilities and partners’ equity		$	427,306			$	238,904

See accompanying notes.

Holly Energy Partners, L.P.

		Three Months Ended
		March 31,
		2008				2007
		(In thousands, except per unit data)
Revenues:
Affiliates		$	18,318			$	13,790
Third parties			8,958				10,082
			27,276				23,872
Operating costs and expenses:
Operations			9,727				7,733
Depreciation and amortization			4,313				4,071
General and administrative			1,286				1,272
			15,326				13,076
Operating income			11,950				10,796
Other income (expense):
Interest income			93				185
Interest expense			(3,807	)			(3,358	)
Gain on sale of assets			36				297
Minority interest in Rio Grande Pipeline Company			(406	)			(427	)
			(4,084	)			(3,303	)
Income before income taxes			7,866				7,493
State income tax			(68	)			(59	)
Net income			7,798				7,434
Less general partner interest in net income			821				580
Limited partners’ interest in net income		$	6,977			$	6,854
Net income per limited partner unit - basic and diluted		$	0.43			$	0.43
Weighted average limited partners’ units outstanding			16,181				16,108

See accompanying notes.

Holly Energy Partners, L.P.

		Three Months Ended March 31,
		2008				2007
		(In thousands)
Cash flows from operating activities
Net income		$	7,798			$	7,434
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization			4,313				4,071
Minority interest in Rio Grande Pipeline Company			405				427
Amortization of restricted and performance units			94				302
Gain on sale of assets			(36	)			(297	)
(Increase) decrease in current assets:
Accounts receivable			1,427				1,768
Accounts receivable — affiliates			(2,073	)			1,652
Prepaid and other current assets			204				391
Increase (decrease) in current liabilities:
Accounts payable			1,762				(1,664	)
Accounts payable — affiliates			(953	)
Accrued interest			(1,969	)			(1,953	)
Deferred revenue			1,851				906
Accrued property tax			(551	)			(360	)
Other current liabilities			(177	)			(368	)
Other, net			309				284
Net cash provided by operating activities			12,404				12,593
Cash flows from investing activities
Additions to properties and equipment			(11,086	)			(912	)
Acquisition of crude pipelines and tankage assets			(171,000	)			—
Proceeds from sale of assets			36				325
Net cash used for investing activities			(182,050	)			(587	)
Cash flows from financing activities
Borrowings under credit agreement			181,000				—
Proceeds from issuance of common units			104				—
Distributions to partners			(12,623	)			(11,538	)
Cash contribution from general partner			186				—
Purchase of units for restricted grants			(514	)			(908	)
Deferred financing costs			(591	)			—
Other			—				(15	)
Net cash provided by (used for) financing activities			167,562				(12,461	)
Cash and cash equivalents
Decrease for period			(2,084	)			(455	)
Beginning of period			10,321				11,555
End of period		$	8,237			$	11,100

See accompanying notes.

Holly Energy Partners, L.P.

																		Accumulated
										Class B				General				Other
		Common				Subordinated				Subordinated				Partner				Comprehensive
		Units				Units				Units				Interest				Loss				Total
										(In thousands)
Balance December 31, 2007		$	172,807			$	(73,725	)		$	22,973			$	(94,239	)		$	—			$	27,816
Net income			3,552				3,021				404				821				—				7,798
Change in fair value of cash flow hedge			—				—				—				—				(4,349	)			(4,349	)
Comprehensive income			3,552				3,021				404				821				(4,349	)			3,449
Distributions to partners			(5,938	)			(5,075	)			(680	)			(931	)			—				(12,624	)
Issuance of common units			9,104				—				—				—				—				9,104
Cost of issuing common units			(71	)			—				—				—				—				(71	)
Capital contribution			—				—				—				186				—				186
Purchase of units for restricted grants			(514	)			—				—				—				—				(514	)
Amortization of restricted and performance units			94				—				—				—				—				94
Balance March 31, 2008		$	179,034			$	(75,779	)		$	22,697			$	(94,163	)		$	(4,349	)		$	27,440

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 46% owned by Holly Corporation and its subsidiaries (collectively “Holly”). HEP commenced operations July 13, 2004 upon the completion of its initial public offering. In this document, the words “we”, “our”, “ours” and “us” refer to HEP unless the context otherwise indicates.

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

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

Another of Holly’s wholly-owned subsidiaries owns a refinery located near Salt Lake City, Utah (the “Woods Cross Refinery”). Our operations serving the Woods Cross Refinery include a truck rack at the Woods Cross Refinery, a refined product terminal in Spokane, Washington and a 50% non-operating interest in product terminals in Boise and Burley, Idaho. See Note 2 for a description of the Crude Pipelines and Tankage Assets that also service the Woods Cross refinery.

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

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

The consolidated financial statements for the three months ended March 31, 2008 and 2007 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, that, in the opinion of management, are necessary for a fair presentation of our results for the interim periods. Such adjustments are considered to be of a normal recurring nature. Although certain notes and other information required by accounting principles generally accepted in the United States of America have been condensed or omitted, we believe that the disclosures in these consolidated financial statements are adequate to make the information presented not misleading. These consolidated financial statements should be read in conjunction with our Form 10-K for the year ended December 31, 2007. Results of operations for interim periods are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2008.

We have reclassified state income taxes for the three months ended March 31, 2007 to conform to our current presentation at March 31, 2008. State income taxes were previously classified as operations and general and administrative expenses in our consolidated statement of income for the three months ended March 31, 2007.

Recent Accounting Pronouncements

Statement of Financial Accounting Standards (“SFAS”) No. 157 “Fair Value Measurements”

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

We have interest rate swaps that we measure at fair value on a recurring basis using level 2 inputs. See Note 5 in the “Notes to the Consolidated Financial Statements” for additional information on these swaps.

SFAS No. 133 Implementation Issue No. E23 “Issues Involving the Application of the Shortcut Method under Paragraph 68”

In January 2008, the FASB posted SFAS No. 133 Implementation Issue No. E23, Issues Involving the Application of the Shortcut Method under Paragraph 68. This standard addresses issues pertaining to the application of the shortcut method in accounting for hedges when the settlement of a hedged item occurs subsequent to the interest rate swap trade date. It also addresses hedging relationships when the transaction price of an interest rate swap is zero. This standard is effective for hedging relationships designated on or after January 1, 2008 and requires the reassessment of preexisting hedges utilizing the shortcut method under this new guidance. We adopted this standard effective January 1, 2008. The adoption of this standard did not have a material impact on our financial condition, results of operations and cash flows.

Note 2: Acquisition

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

In connection with this transaction, we entered into a 15-year crude pipelines and tankage agreement with Holly (the “Holly CPTA”). Under this agreement, Holly agreed to transport and store volumes of crude oil on the crude pipelines and tankage facilities, respectively that, at the agreed rates, will initially result in minimum annual revenues to us of $25.3 million. The agreed upon tariffs on the crude pipelines will be adjusted each year at a rate equal to the percentage change in the producer price index (“PPI”) but will not decrease as a result of a decrease in the PPI. Additionally, Holly amended our omnibus agreement (the “Omnibus Agreement”) to provide $7.5 million of indemnification for environmental noncompliance and remediation liabilities associated with the Crude Pipelines and Tankage Assets that occurred or existed prior to our acquisition for a period of up to fifteen years.

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

In accordance with the provisions of FASB Interpretation (“FIN”) No. 46, Holly recognizes us as a variable interest entity (“VIE”). Under this standard, our purchase of Holly’s Crude Pipelines and Tankage Assets qualifies as a reconsideration event whereby Holly reassessed their beneficial interest in us. Following our acquisition of these assets, Holly determined that their beneficial interest in us now exceeds 50%. Accordingly, Holly reconsolidated us effective March 1, 2008.

Note 3: Properties and Equipment

		March 31,				December 31,
		2008				2007
		(In thousands)
Pipelines and terminals		$	305,088			$	196,800
Land and right of way			23,977				22,825
Other			6,394				5,706
Construction in progress			18,061				9,103
			353,520				234,434
Less accumulated depreciation			79,333				75,834
		$	274,187			$	158,600

During the three months ended March 31, 2008 we capitalized $0.2 million in interest related to major construction projects. We did not capitalize any interest during the three months ended March 31, 2007.

Note 4: Transportation Agreements

Our transportation recorded agreements consist of the following:

	•		The transportation agreement with Alon USA, Inc (“Alon”) represents a portion of the total purchase price of assets purchased from Alon in 2005 that was allocated based on an estimated fair value derived under the income approach. This asset is being amortized over 30 years ending 2035, the 15-year initial term of the pipelines and terminals agreement with Alon plus the expected 15-year extension period.
	•		The Holly crude pipelines and tankage agreement represents a portion of the total purchase price of the Crude Pipelines and Tankage Assets that was allocated based on management’s preliminary estimate of its fair value. This asset is being amortized over 15 years ending 2023, the 15-year term of the Holly CPTA.

The carrying amounts of our transportation agreements are as follows:

		March 31,				December 31,
		2008				2007
		(In thousands)
Alon transportation agreement		$	59,933			$	59,933
Holly crude pipelines and tankage agreement			72,000				—
			131,933				59,933
Less accumulated amortization			6,559				5,660
		$	125,374			$	54,273

Note 5: Debt

Credit Agreement

In February 2008, we amended our $100 million senior secured revolving credit agreement expiring in August 2011 to increase the size from $100 million to $300 million (the “Credit Agreement’), which we used to finance the $171.0 million cash portion of the consideration paid for the Crude Pipelines and Tankage Assets acquired from Holly. Union Bank of California, N.A. is one of the lenders and serves as administrative agent under this agreement. As of March 31, 2008 and December 31, 2007, we had $181.0 million and zero, respectively, outstanding under the Credit Agreement.

The Credit Agreement is available to fund capital expenditures, acquisitions, and working capital and for general partnership purposes. Advances under the Credit Agreement that are either designated for working capital or have been used as interim financing to fund capital expenditures are classified as

short-term liabilities. Other advances under the Credit Agreement are classified as long-term liabilities. In addition, the Credit Agreement is available to fund letters of credit up to a $50.0 million sub-limit and to fund distributions to unitholders up to a $20.0 million sub-limit. During the three months ended March 31, 2008, we received advances totaling $10.0 million under the Credit Agreement that were used to fund capital expenditures.

We have the right to request an increase in the maximum amount of the Credit Agreement, up to $370.0 million. Such request will become effective if (a) certain conditions specified in the Credit Agreement are met and (b) existing lenders under the Credit Agreement or other financial institutions reasonably acceptable to the administrative agent commit to lend such increased amounts under the agreement.

Our obligations under the Credit Agreement are secured by substantially all of our assets. Indebtedness under the Credit Agreement is recourse to HEP Logistics Holdings, L.P., our general partner, and guaranteed by our wholly-owned subsidiaries.

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 once each twelve-month period prior to the maturity date of the agreement.

Indebtedness under the Credit Agreement bears interest, at our option, at either (a) the reference rate as announced by the administrative agent plus an applicable margin (ranging from 0.25% to 1.50%) or (b) at a rate equal to the London Interbank Offered Rate (“LIBOR”) plus an applicable margin (ranging from 1.00% to 2.50%). In each case, the applicable margin is based upon the ratio of our funded debt (as defined in the agreement) to EBITDA (earnings before interest, taxes, depreciation and amortization, as defined in the Credit Agreement). We incur a commitment fee on the unused portion of the Credit Agreement at a rate ranging from 0.20% to 0.50% based upon the ratio of our funded debt to EBITDA for the four most recently completed fiscal quarters. At March 31, 2008, we are subject to the 0.25% rate on the $119.0 million of the unused commitment on the Credit Agreement. The agreement matures in August 2011. At that time, the agreement will terminate and all outstanding amounts thereunder will be due and payable.

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

Senior Notes Due 2015

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

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

		March 31,				December 31,
		2008				2007
		(In thousands)
Credit Agreement		$	181,000			$	—
Senior Notes
Principal			185,000				185,000
Unamortized discount			(2,629	)			(2,724	)
Fair value hedge — interest rate swap			2,959				(841	)
			185,330				181,435
Total Debt			366,330				181,435
Less short-term borrowing under credit agreement			10,000				—
Total long-term debt		$	356,330			$	181,435

Interest Rate Risk Management

As of March 31, 2008, we have two interest rate swap contracts.

We entered into an interest rate swap to hedge our exposure to the cash flow risk caused by the effects of LIBOR changes on the $171.0 million Credit Agreement advance that we used to finance our purchase of the Crude Pipelines and Tankage Assets from Holly. This interest rate swap effectively converts our $171.0 million LIBOR based debt to fixed rate debt having an interest rate of 3.74% plus an applicable margin, currently 1.50%, that results in a March 31, 2008 effective interest rate of 5.24%.

Under the provisions of SFAS No. 133, we have designated this interest rate swap as a cash flow hedge. Based on our assessment of effectiveness using the change in variable cash flows method, we have determined that this interest rate swap is effective in offsetting the variability in interest payments on our $171.0 million variable rate debt resulting from changes in LIBOR. Under hedge accounting, we adjust our cash flow hedge on a quarterly basis to its fair value with a corresponding offset to accumulated other comprehensive income. Also on a quarterly basis, we measure hedge effectiveness by comparing the present value of the cumulative change in the expected future interest payments 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 March 31, 2008, we had no ineffectiveness on our cash flow hedge.

We also have an interest rate swap contract that effectively converts interest expense associated with $60.0 million of our 6.25% Senior Notes from a fixed to a variable rate. Under this swap contract, interest on the $60.0 million notional amount is computed using the three-month LIBOR plus an applicable margin of 1.1575%, which equaled an effective interest rate of 4.23% at March 31, 2008. The maturity of the swap contract is March 1, 2015, matching the maturity of the Senior Notes.

This interest rate swap has been designated as a fair value hedge and meets the requirements to assume no ineffectiveness under the provisions of SFAS No. 133. Accordingly, we use the “shortcut” method of accounting as prescribed under SFAS No. 133. Under this method, we adjust the carrying value of the swap to its fair value on a quarterly basis, with an offsetting entry to our Senior Notes, effectively adjusting the carrying value of $60.0 million of principal on the Senior notes to its fair value.

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

Additional information on our interest rate swaps are as follows:

				Fair Value				Location of Offsetting
Interest Rate Swaps		Balance Sheet Location		(In thousands)				Balance
Cash flow hedge - $171 million LIBOR based debt		Other long-term liabilities		$	4,349			Accumulated other comprehensive loss
Fair value hedge - $60 million of 6.25% Senior Notes		Other assets		$	2,959			Long-term debt

Other Debt Information

		Three Months Ended
		March 31,
		2008				2007
		(In thousands)
Interest on outstanding debt:
Senior Notes, net of interest rate swap		$	2,710			$	2,932
Credit Agreement, net of interest rate swap			803				—
Amortization of discount and deferred issuance costs			223				303
Commitment fees			71				123
Net interest expense		$	3,807			$	3,358
Cash paid for interest(1)		$	5,013			$	5,135

The estimated fair value of our Senior Notes was $167.9 million at March 31, 2008.

Note 6: Employees, Retirement and Benefit Plans

Employees who provide direct services to us are employed by Holly Logistic Services, L.L.C., a Holly subsidiary. Their costs, including salaries, bonuses, payroll taxes, benefits, and other direct costs, are charged to us monthly under certain provisions of the Omnibus Agreement that we entered into with Holly in July 2004.

These employees participate in the retirement and benefit plans of Holly. Our share of retirement and benefits costs was $0.2 million and $0.4 million for the three months ended March 31, 2008 and 2007, respectively.

We have adopted a 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.

On March 31, 2008, we had two types of equity-based compensation, which are described below. The compensation cost charged against income for these plans was $0.3 million for the three months ended March 31, 2008 and 2007. It is currently our policy to purchase units in the open market instead of issuing new units for settlement of restricted unit grants. At March 31, 2008, 350,000 units were authorized to be granted under the equity-based compensation plans, of which 243,486 had not yet been granted.

Restricted Units

Under our Long-Term Incentive Plan, we grant restricted units to selected employees, consultants and directors who perform services for us, with vesting generally over a period of one to five years. Certain restricted units granted to our directors vest quarterly. Although full ownership of the units does not transfer to the recipients until the units vest, the recipients have distribution and voting rights on these units from the date of grant. The vesting for certain key executives is contingent upon certain earnings per unit targets being realized. The fair value of each unit of restricted unit awards was measured at the market price as of the date of grant and is being amortized over the vesting period, including the units issued to the key executives, as we expect those units to fully vest.

A summary of restricted unit activity and changes during the three months ended March 31, 2008, is presented below:

										Weighted-
						Weighted-				Average				Aggregate
						Average				Remaining				Intrinsic
						Grant-Date				Contractual				Value
Restricted Units		Grants				Fair Value				Term				($000)
Outstanding January 1, 2008 (not vested)			44,711			$	44.77
Granted			15,902				40.54
Forfeited			(303	)			44.62
Vesting and transfer of full ownership to recipients			(11,486	)			43.53
Outstanding at March 31, 2008 (not vested)			48,824			$	43.69				1.5			$	1,874

There were 11,486 restricted units having an intrinsic value of $0.4 million and a fair value of $0.5 million that were vested and transferred to recipients during the three months ended March 31, 2008. As of March 31, 2008, there was $1.1 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 1.5 years.

Performance Units

Under our Long-Term Incentive Plan, we grant performance units to selected executives and employees who perform services for us. These performance units are payable upon meeting the performance criteria over a service period, and generally vest over a period of three years. The amount payable under the initial performance grant of 1,514 units in 2005 is based upon our unit price and upon our total unitholder return during the requisite period as compared to the total unitholder return of a selected peer group of partnerships. The amount payable under all other performance unit grants is based upon the growth in distributions per limited partner unit during the requisite period.

We granted 14,337 performance units to certain officers in March 2008. These units will vest over a three-year performance period ending December 31, 2010, and are payable in HEP common units. The number of units actually earned will be based on the growth of distributions to limited partners over the performance period, and can range from 50% to 150% of the number of performance units issued. The fair value of these performance units is based on the grant date closing unit price of $40.54 and will apply to the number of units ultimately awarded.

A summary of performance units activity and changes during the three months ended March 31, 2008 is presented below:

		Payable
Performance Units		In Units
Outstanding at January 1, 2008 (not vested)			24,148
Granted			14,337
Forfeited			—
Vesting and transfer of full ownership to recipients			(1,514	)
Outstanding at March 31, 2008 (not vested)			36,971

There were 1,514 performance units having an intrinsic value of $0.1 million and a fair value of $0.1 million that were vested and transferred to recipients during the three months ended March 31, 2008. Based on the weighted average fair value at March 31, 2008 of $42.10 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 1.8 years.

Note 7: Significant Customers

All revenues are domestic revenues, of which over 90% are currently generated from our three largest customers: Holly, Alon and BP Plc (“BP”). The major concentration of our petroleum products pipeline system’s revenue is derived from activities conducted in the southwest United States. The following table presents the percentage of total revenues generated by each of these three customers:

		Three Months Ended
		March 31,
		2008				2007
Holly			67	%			58	%
Alon			19	%			26	%
BP			10	%			13	%

Note 8: Related Party Transactions

Holly

As of March 31, 2008, we serve Holly’s refineries in New Mexico and Utah under three 15-year pipeline and terminal agreements.

In connection with our purchase of the Crude Pipelines and Tankage Assets from Holly on February 29, 2008, we entered into the 15-year Holly CPTA. Under the Holly CPTA, Holly agreed to transport and store volumes of crude oil on the crude pipelines and tankage facilities, respectively that, at the agreed rates, will initially result in minimum annual revenues to us of $25.3 million. The agreed upon tariffs on the crude pipelines will be adjusted each year at a rate equal to the percentage change in the PPI but will not decrease as a result of a decrease in the PPI. Additionally, Holly amended the Omnibus Agreement to provide $7.5 million of indemnification for environmental noncompliance and remediation liabilities associated with the Crude Pipelines and Tankage Assets that occurred or existed prior to our acquisition for a period of up to fifteen years.

We also 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 third agreement with Holly relates to the Intermediate Pipelines acquired from Holly in July 2005 and expires in 2020 (the “Holly IPA”). The substantial majority of our business is devoted to providing transportation and terminalling services to Holly. The minimum revenue commitments under the Holly PTA and the Holly IPA increase each year at a rate equal to the percentage change in PPI, but will not decrease as a result of a decrease in the PPI.

Following the July 1, 2007 PPI rate adjustment, the volume commitment by Holly under the Holly PTA will produce at least $39.6 million of revenue for the twelve months ending June 30, 2008. Under the Holly IPA, Holly agreed to transport volumes of intermediate products on the Intermediate Pipelines that following the July 1, 2007 PPI rate adjustment, will result in minimum funds to us of $12.8 million for the twelve months ending June 30, 2008.

If Holly fails to meet its minimum volume commitments in any quarter, it is required to pay us in cash the amount of any shortfall by the last day of the month following the end of the quarter. A shortfall payment may be applied as a credit in the following four quarters after Holly’s minimum obligations are met.

In October 2007, we entered into an agreement with Holly that amends the Holly PTA under which we have agreed to expand our refined products pipeline system between Artesia, New Mexico and El Paso, Texas (the “South System”). The expansion of the South System will include replacing 85 miles of 8-inch pipe with 12-inch pipe, adding 150,000 barrels of refined product storage at our El Paso Terminal, improving existing pumps, adding a tie-in to the Kinder Morgan pipeline to Tucson and Phoenix, Arizona, and making related modifications. The cost of this project is estimated to be $48.3 million. Currently, we are expecting to complete this project by January 2009. The agreement also provides for a tariff increase, expected to be effective May 1, 2008, on Holly shipments on our refined product pipelines.

Under certain provisions of the Omnibus Agreement that we entered with Holly in July 2004 and that expires in 2019, we pay Holly an annual administrative fee for the provision by Holly or its affiliates of various general and administrative services to us. Effective March 1, 2008, the annual fee was increased from $2.1 million to $2.3 million to cover additional general and administrative services attributable to the operations of our Crude Pipelines and Tankage Assets. This fee does not include the salaries of pipeline and terminal personnel or the cost of their employee benefits, such as 401(k), pension and health insurance benefits, which are separately charged to us by Holly. We also reimburse Holly and its affiliates for direct expenses they incur on our behalf.

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

•		Pipeline, terminal and tankage revenues received from Holly were $18.3 million and $13.8 million for the three months ended March 31, 2008 and 2007, 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 $0.5 million for the three months ended March 31, 2008 and 2007.
•		We reimbursed Holly for costs of employees supporting our operations of $2.6 million and $2.3 million for the three months ended March 30, 2008 and 2007, respectively.
•		Holly reimbursed us zero and $74,000 for the three months ended March 31, 2008 and 2007, respectively, for certain costs paid on their behalf.
•		We distributed $6.1 million and $5.4 million for the three months ended March 31, 2008 and 2007, respectively, to Holly as regular distributions on its subordinated units, common units and general partner interest.
•		Our accounts receivable from Holly were $7.8 million and $5.7 million at March 31, 2008 and December 31, 2007, respectively.
•		Holly failed to meet its minimum volume commitment for each of the eleven quarters since inception of the Holly IPA. We have charged Holly $4.8 million for these shortfalls to date, $0.2 million and zero of which is included in affiliate accounts receivable at March 31, 2008 and December 31, 2007, respectively.

•

For the three months ended March 31, 2008, our revenues from Holly included $0.6 million of shortfalls billed under the Holly IPA in 2007 as Holly did not exceed its minimum volume commitment in any of the subsequent four quarters. Deferred revenue in the consolidated balance sheets at March 30, 2008 and December 31, 2007, includes $0.8 million and $1.1 million, respectively, relating to the Holly IPA. It is possible that Holly may not exceed its minimum obligations under the Holly IPA to allow Holly to receive credit for any of the $0.8 million deferred at March 31, 2008.

BP

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

•		BP’s agreement to ship on the Rio Grande pipeline expired on March 31, 2008. Rio Grande is currently serving multiple shippers on the pipeline. We recorded revenues from them of $2.7 million and $3.0 million for the three months ended March 31, 2008 and 2007, respectively.
•		Rio Grande did not pay any distributions for the three months ended March 31, 2008 and 2007.
•		Included in our accounts receivable — trade at March 31, 2008 and December 31, 2007 were $0.6 million and $1.5 million, respectively, which represented the receivable balance of Rio Grande from BP.

Alon

We have a 15-year pipelines and terminals agreement with Alon (the “Alon PTA”), expiring in 2020, under which Alon has agreed to transport on our pipelines and throughput through our terminals volumes of refined products that results in a minimum level of annual revenue. The agreed upon tariffs are increased or decreased annually at a rate equal to the percentage change in PPI, but not below the initial tariff rate. Following the March 1, 2008 PPI rate adjustment, Alon’s total minimum commitment for the twelve months ending February 28, 2009 is $21.9 million.

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

•		We recognized $3.4 million and $4.4 million of revenues for pipeline transportation and terminalling services under the Alon PTA and $1.8 million under a pipeline capacity lease for the three months ended March 31, 2008 and 2007. The pipeline lease agreement with Alon was amended effective August 31, 2007 to extend two capacity leases for 10 years to August 31, 2018 and July 31, 2020, respectively, to reduce the total leased capacity from 20,000 to 17,500 barrels per day (“bpd”) effective September 1, 2008, and to allow Alon an option, effective from September 1, 2008, to increase the leased capacity by 2,500 bpd for a term of 10 years.
•		We paid $0.7 million and $0.6 million to Alon for distributions on our Class B subordinated units for the three months ended March 31, 2008 and 2007, respectively.
•		Included in our accounts receivable — trade at March 31, 2008 and December 31, 2007 were $4.0 million and $3.5 million, respectively, which represented the receivable balance from Alon.
•		For the three months ended March 31, 2008, our revenues from Alon included $0.8 million of shortfalls billed under the Alon PTA in 2007 as Alon did not exceed its minimum revenue obligation in any of the subsequent four quarters. Deferred revenue in the consolidated balance sheets at March 31, 2008 and December 31, 2007 includes $4.7 million and $2.6 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 $4.7 million deferred at March 31, 2008.

Note 9: Partners’ Equity, Allocations and Cash Distributions

Issuances of units

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

Holly currently holds 7,000,000 of our subordinated units and 290,000 of our common units, which constitutes a 46% ownership interest in us, including the 2% general partner interest.

The Holly-owned subordinated units have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.50 per quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. The purpose of the subordinated units is to increase the likelihood that cash is available for common unit distributions during the subordination period. The subordination period will extend until the first day of any quarter beginning after June 30, 2009 that each of the following tests are met: distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date; the “adjusted operating surplus” (as defined in its partnership agreement) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units during those periods on a fully diluted basis and the related distribution on the 2% general partner interest during those periods; and there are no arrearages in payment of the minimum quarterly distribution on the common units. If the unitholders remove the general partner without cause, the subordination period may end before June 30, 2009. The Holly-owned subordinated units may convert to common units on a one-for-one basis when certain conditions are met. The partnership agreement sets forth the calculation to be used to determine the amount and priority of cash distributions that the common unitholders, subordinated unitholders and general partner will receive.

Under our registration statement filed with the SEC using a “shelf” registration process, we may offer from time to time up to $800.0 million of our securities through one or more prospectus supplements that would describe, among other things, the specific amounts, prices and terms of any securities offered and how the proceeds would be used. Any proceeds from the sale of securities would be used for general business purposes, which may include, among other things, funding acquisitions of assets or businesses, working capital, capital expenditures, investments in subsidiaries, the retirement of existing debt and/or the repurchase of common units or other securities.

Allocations of Net Income

Net income is allocated between limited partners and the general partner interest in accordance with the provisions of the partnership agreement. Net income allocated to the general partner includes any incentive distributions declared in the period. After the amount of incentive distributions is allocated to the general partner, the remaining net income for the period is generally allocated to the partners based on their weighted average ownership percentage during the period.

Cash Distributions

We consider regular cash distributions to unitholders on a quarterly basis, although there is no assurance as to the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors. Our Credit Agreement prohibits us from making cash

distributions if any potential default or event of default, as defined in the Credit Agreement, occurs or would result from the cash distribution.

Within 45 days after the end of each quarter, we will distribute all of our available cash (as defined in our partnership agreement) to unitholders of record on the applicable record date. The amount of available cash generally is all cash on hand at the end of the quarter; less the amount of cash reserves established by our general partner to provide for the proper conduct of our business, comply with applicable law, any of our debt instruments, or other agreements; or provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters; plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are generally borrowings that are made under our revolving Credit Agreement and in all cases are used solely for working capital purposes or to pay distributions to partners.

We make distributions of available cash from operating surplus for any quarter during any subordination period in the following manner: firstly, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter; secondly, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period; thirdly, 98% to the subordinated unitholders, pro rata, and 2% to the general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and thereafter, cash in excess of the minimum quarterly distributions is distributed to the unitholders and the general partner based on the percentages below.

The general partner, HEP Logistics Holdings, L.P., is entitled to incentive distributions if the amount we distribute with respect to any quarter exceeds specified target levels shown below:

						Marginal Percentage Interest in
		Total Quarterly Distribution				Distributions
		Target Amount				Unitholders				General Partner
Minimum Quarterly Distribution		$	0.50				98	%			2	%
First Target Distribution		Up to $0.55					98	%			2	%
Second Target Distribution		above $0.55 up to $0.625					85	%			15	%
Third Target distribution		above $0.625 up to $0.75					75	%			25	%
Thereafter		Above $0.75					50	%			50	%

The following table presents the allocation of our regular quarterly cash distributions to the general and limited partners for each period in which declared.

		Three Months Ended
		March 31,
		2008				2007
		(In thousands, except per unit data)
General partner interest		$	252			$	222
General partner incentive distribution			679				440
Total general partner distribution			931				662
Limited partner distribution			11,678				10,876
Total regular quarterly cash distribution		$	12,609			$	11,538
Cash distribution per unit applicable to limited partners		$	0.725			$	0.675

On April 25, 2008, we announced a cash distribution for the first quarter of 2008 of $0.735 per unit. The distribution is payable on all common, subordinated, and general partner units and will be paid May 14, 2008 to all unitholders of record on May 5, 2008. The aggregate amount of the distribution will be $13.0 million, including $0.7 million paid to the general partner as an incentive distribution.

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

Note 10: Supplemental Guarantor/Non-Guarantor Financial Information

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

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

Condensed Consolidating Balance Sheet

						Guarantor				Non-
March 31, 2008		Parent				Subsidiaries				Guarantor				Eliminations				Consolidated
		(in thousands)
ASSETS
Current assets:
Cash and cash equivalents		$	2			$	3,679			$	4,556			$	—			$	8,237
Accounts receivable			—				12,337				620				—				12,957
Intercompany accounts receivable (payable)			(150,588	)			150,994				(406	)			—				—
Prepaid and other current assets			94				248				—				—				342
Total current assets			(150,492	)			167,258				4,770				—				21,536
Properties and equipment, net			—				241,251				32,936				—				274,187
Investment in subsidiaries			360,440				26,006				—				(386,446	)			—
Transportation agreements, net			—				125,374				—				—				125,374
Other assets			4,212				1,997				—				—				6,209
Total assets		$	214,160			$	561,886			$	37,706			$	(386,446	)		$	427,306
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable		$	—			$	9,453			$	388			$	—			$	9,841
Accrued interest			(955	)			1,982				—				—				1,027
Deferred revenue			—				5,551				—				—				5,551
Accrued property taxes			—				580				46				—				626
Other current liabilities			2,345				(1,815	)			121				—				651
Short-term borrowings under credit agreement			—				10,000				—				—				10,000
Total current liabilities			1,390				25,751				555				—				27,696
Long-term debt			185,330				171,000				—				—				356,330
Other long-term liabilities			—				4,695				—				—				4,695
Minority interest			—				—				—				11,145				11,145
Partners’ equity			27,440				360,440				37,151				(397,591	)			27,440
Total liabilities and partners’ equity		$	214,160			$	561,886			$	37,706			$	(386,446	)		$	427,306

Condensed Consolidating Balance Sheet

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

Condensed Consolidating Statement of Income

						Guarantor				Non-
Three months ended March 31, 2008		Parent				Subsidiaries				Guarantor				Eliminations				Consolidated
		(in thousands)
Revenues:
Affiliates		$	—			$	18,327			$	—			$	—			$	18,327
Third parties			—				6,516				2,750				(317	)			8,949
			—				24,843				2,750				(317	)			27,276
Operating costs and expenses:
Operations			—				8,973				1,071				(317	)			9,727
Depreciation and amortization			—				3,988				325				—				4,313
General and administrative			742				543				1				—				1,286
			742				13,504				1,397				(317	)			15,326
Operating income (loss)			(742	)			11,339				1,353				—				11,950
Equity in earnings of subsidiaries			11,554				947				—				(12,501	)			—
Interest income (expense)			(3,014	)			(719	)			19				—				(3,714	)
Gain on sale of assets			—				36				—				—				36
Minority interest			—				—				—				(406	)			(406	)
			8,540				264				19				(12,907	)			(4,084	)
Income before income taxes			7,798				11,603				1,372				(12,907	)			7,866
State income tax			—				(49	)			(19	)			—				(68	)
Net income		$	7,798			$	11,554			$	1,353			$	(12,907	)		$	7,798

Condensed Consolidating Statement of Income

						Guarantor				Non-
Three months ended March 31, 2007		Parent				Subsidiaries				Guarantor				Eliminations				Consolidated
		(in thousands)
Revenues:
Affiliates		$	—			$	13,790			$	—			$	—			$	13,790
Third parties			—				7,349				3,026				(293	)			10,082
			—				21,139				3,026				(293	)			23,872
Operating costs and expenses:
Operations			—				7,233				793				(293	)			7,733
Depreciation and amortization			—				3,223				848				—				4,071
General and administrative			766				505				1				—				1,272
			766				10,961				1,642				(293	)			13,076
Operating income (loss)			(766	)			10,178				1,384				—				10,796
Equity in earnings of subsidiaries			11,264				997				—				(12,261	)			—
Interest income (expense)			(3,064	)			(149	)			40				—				(3,173	)
Gain on sale of assets			—				297				—				—				297
Minority interest			—				—				—				(427	)			(427	)
			8,200				1,145				40				(12,688	)			(3,303	)
Income before income taxes			7,434				11,323				1,424				(12,688	)			7,493
State income tax			—				(59	)			—				—				(59	)
Net income		$	7,434			$	11,264			$	1,424			$	(12,688	)		$	7,434

Condensed Consolidating Statement of Cash Flows

						Guarantor				Non-
Three months ended March 31, 2008		Parent				Subsidiaries				Guarantor				Eliminations				Consolidated
		(in thousands)
Cash flows from operating activities		$	3,908			$	6,154			$	2,342			$	—			$	12,404
Cash flows from investing activities
Additions to properties and equipment			—				(11,041	)			(45	)			—				(11,086	)
Acquisition of crude pipelines and tankage assets			—				(171,000	)			—				—				(171,000	)
Proceeds from sale of assets			—				36				—				—				36
			—				(182,005	)			(45	)			—				(182,050	)
Cash flows from financing activities
Borrowings under credit agreement			—				181,000				—				—				181,000
Proceeds from issuance of common units			—				104				—				—				104
Distributions to partners			(12,437	)			—				—				—				(12,437	)
Cash distribution to minority interest			—				—				—				—				—
Purchase of units for restricted grants			(514	)			—				—				—				(514	)
Deferred financing costs			—				(591	)			—				—				(591	)
			(12,951	)			180,513				—				—				167,562
Cash and cash equivalents
Increase (decrease) for the period			(9,043	)			4,662				2,297				—				(2,084	)
Beginning of period			2				8,060				2,259				—				10,321
End of period		$	(9,041	)		$	12,722			$	4,556			$	—			$	8,237