HOLLY ENERGY PARTNERS LP - Quarter Report: 2009 March (Form 10-Q)

 

 

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, 2009

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

(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

The registrant has not yet been phased in to the Interactive Data File requirements.

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o		Accelerated filer þ		Non-accelerated filer o		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 24, 2009 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, 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			24
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			42
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, 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, 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.

		March 31, 2009				December 31,
		(Unaudited)				2008
		(In thousands, except unit data)
ASSETS
Current assets:
Cash and cash equivalents		$	4,321			$	5,269
Accounts receivable:
Trade			4,159				5,082
Affiliates			11,731				9,395
			15,890				14,477
Prepaid and other current assets			351				593
Total current assets			20,562				20,339
Properties and equipment, net			296,343				290,284
Transportation agreements, net			120,646				122,383
Investment in SLC Pipeline			25,675				—
Other assets			6,319				6,682
Total assets		$	469,545			$	439,688
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable		$	5,692			$	5,816
Accounts payable — affiliates			3,142				2,202
Accrued interest			922				2,845
Deferred revenue			16,020				15,658
Accrued property taxes			810				1,145
Other current liabilities			965				1,505
Short-term borrowings under credit agreement			—				29,000
Total current liabilities			27,551				58,171
Commitments and contingencies			—				—
Long-term debt			424,802				355,793
Other long-term liabilities			17,774				17,604
Equity:
Holly Energy Partners, L.P. partners’ equity (deficit):
Common unitholders (8,390,000 units issued and outstanding at March 31, 2009 and December 31, 2008)			164,248				169,126
Subordinated unitholders (7,000,000 units issued and outstanding at March 31, 2009 and December 31, 2008)			(88,568	)			(85,059	)
Class B subordinated unitholders (937,500 units issued and outstanding at March 31, 2009 and December 31, 2008)			20,984				21,455
General partner interest (2% interest)			(94,842	)			(94,653	)
Accumulated other comprehensive loss			(13,117	)			(12,967	)
Total Holly Energy Partners, L.P. partners’ deficit			(11,295	)			(2,098	)
Noncontrolling interest			10,713				10,218
Total equity (deficit)			(582	)			8,120
Total liabilities and equity		$	469,545			$	439,688

See accompanying notes.

Holly Energy Partners, L.P.

		Three Months Ended
		March 31,
		2009				2008
		(In thousands, except per unit data)
Revenues:
Affiliates		$	18,323			$	18,327
Third parties			13,801				8,949
			32,124				27,276
Operating costs and expenses:
Operations			10,796				9,727
Depreciation and amortization			6,256				4,313
General and administrative			1,324				1,286
			18,376				15,326
Operating income			13,748				11,950
Other income (expense):
Equity in earnings of SLC Pipeline			175				—
SLC Pipeline acquisition costs			(2,500	)			—
Interest income			6				93
Interest expense			(5,403	)			(3,807	)
Gain on sale of assets			—				36
			(7,722	)			(3,678	)
Income before income taxes			6,026				8,272
State income tax			(92	)			(68	)
Net income			5,934				8,204
Less noncontrolling interest in net income			495				406
Net income attributable to Holly Energy Partners, L.P.			5,439				7,798
Less general partner interest in net income attributable to Holly Energy Partners, L.P.			1,293				880
Limited partners’ interest in net income attributable to Holly Energy Partners, L.P.		$	4,146			$	6,918
Limited partners’ per unit interest in net income attributable to Holly Energy Partners, L.P. – basic and diluted		$	0.25			$	0.43
Weighted average limited partners’ units outstanding			16,328				16,181

     See accompanying notes.

Holly Energy Partners, L.P.

		Three Months Ended
		March 31,
		2009				2008
		(In thousands)
Cash flows from operating activities
Net income		$	5,934			$	8,204
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization			6,256				4,313
Equity in earnings of SLC Pipeline			(175	)			—
Change in fair value — interest rate swaps			216				—
Amortization of restricted and performance units			(52	)			94
Gain on sale of assets			—				(36	)
(Increase) decrease in current assets:
Accounts receivable			923				1,427
Accounts receivable — affiliates			(2,336	)			(2,073	)
Prepaid and other current assets			242				204
Increase (decrease) in current liabilities:
Accounts payable			(124	)			1,762
Accounts payable — affiliates			940				(953	)
Accrued interest			(1,923	)			(1,969	)
Deferred revenue			362				1,851
Accrued property taxes			(335	)			(551	)
Other current liabilities			(540	)			(177	)
Other, net			168				308
Net cash provided by operating activities			9,556				12,404
Cash flows from investing activities
Additions to properties and equipment			(10,570	)			(11,086	)
Investment in SLC Pipeline			(25,500	)			—
Acquisition of crude pipelines and tankage assets			—				(171,000	)
Proceeds from sale of assets			—				36
Net cash used for investing activities			(36,070	)			(182,050	)
Cash flows from financing activities
Net borrowings under credit agreement			40,000				181,000
Distributions to HEP partners			(13,818	)			(12,623	)
Purchase of units for restricted grants			(616	)			(514	)
Proceeds from issuance of common units			—				104
Contribution from general partner			—				186
Deferred financing costs			—				(591	)
Net cash provided by financing activities			25,566				167,562
Cash and cash equivalents
Decrease for period			(948	)			(2,084	)
Beginning of period			5,269				10,321
End of period		$	4,321			$	8,237

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
Distributions			(6,421	)			(5,354	)			(718	)			(1,325	)			—				—				(13,818	)
Purchase of units for restricted grants			(616	)			—				—				—				—				—				(616	)
Amortization of restricted and performance units			(52	)			—				—				—				—				—				(52	)
Comprehensive income:
Net income			2,211				1,845				247				1,136				—				495				5,934
Change in fair value of cash flow hedge			—				—				—				—				(150	)			—				(150	)
Comprehensive income			2,211				1,845				247				1,136				(150	)			495				5,784
Balance March 31, 2009		$	164,248			$	(88,568	)		$	20,984			$	(94,842	)		$	(13,117	)		$	10,713			$	(582	)

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”). We commenced operations July 13, 2004 upon the completion of our initial public offering. In this document, the words “we,” “our,” “ours” and “us” refer to HEP unless the context otherwise indicates.

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

One of Holly’s wholly-owned subsidiaries owns a refinery in Artesia, New Mexico, which Holly operates in conjunction with crude, vacuum distillation and other facilities situated in Lovington, New Mexico (collectively, the “Navajo Refinery”). The Navajo Refinery produces high-value refined products such as gasoline, diesel fuel and jet fuel and serves markets in the southwestern United States and northern Mexico. We own and operate the two parallel 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 February 2008, we acquired crude pipeline and tankage assets from Holly (the “Crude Pipelines and Tankage Assets”), that service Holly’s Navajo and Woods Cross Refineries. Our pipeline, tankage and terminalling operations reflect the operations of our crude pipeline and tankage assets commencing March 1, 2008. See Note 2 for additional information.

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 10 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.

Recent Accounting Pronouncements

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

In December 2007, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 160, which changes the classification of non-controlling interests, also referred to as minority interests, in the consolidated financial statements. We adopted this standard effective January 1, 2009. As a result, all previous references to “minority interest” within this document have been replaced with “noncontrolling interest.” Additionally, net income attributable to the non-controlling interest in our Rio Grande subsidiary is now presented as an adjustment to net income to arrive at “Net income attributable to Holly Energy Partners, L.P.” in our Consolidated Statements of Income. Prior to our adoption of this standard, this amount was presented as “Minority interest in Rio Grande,” a non-operating expense item before “Income before income taxes.” Furthermore, equity attributable to noncontrolling interests in our Rio Grande subsidiary is now presented as a separate component of total equity in our Consolidated Financial Statements. We have adopted this standard on a retroactive basis. While this presentation differs from previous GAAP requirements, this standard did not affect our net income and equity attributable to HEP partners.

SFAS 141(R) Business Combinations

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

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

In March 2008, the FASB issued SFAS No. 161, which amends and expands the disclosure requirements of SFAS 133 to include disclosure of the objectives and strategies related to an entity’s use of derivative instruments, disclosure of how an entity accounts for its derivative instruments and disclosure of the financial impact, including the effect on cash flows associated with derivative activity. We adopted this standard effective January 1, 2009. See Note 6 for disclosure of our derivative instruments and hedging activity.

EITF No. 07-04 “Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships”

In March 2008, the FASB ratified Emerging Issues Task Force (“EITF”) Issue No. 07-04, which prescribes the application of the two-class method in computing earnings per unit to reflect a master limited partnership’s contractual obligation to make distributions to the general partner, limited partners and incentive distribution rights holder. We adopted this standard effective January 1, 2009. As a result, quarterly earnings allocations to the general partner now include incentive distributions that were declared subsequent to quarter end. Prior to our adoption of this standard, our general partner earnings allocations included incentive distributions that were declared during each quarter. We have adopted this standard on a retroactive basis. Although this standard resulted in a decrease in our limited partners’ interest in net income attributable to Holly Energy Partners, L.P. for the first quarter of 2008, it did not affect last year’s first quarter earnings of $0.43 per limited partner unit.

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

In June 2006, the FASB issued FSP No. 03-6-1 which provides guidance in determining whether unvested instruments granted under share-based payment transactions are participating securities and, therefore, should be included in earnings per share calculations under the two-class method provided under FASB No. 128, Earnings per Share. We adopted this standard effective January 1, 2009. The adoption of this standard did not have a material impact on our financial condition, results of operations and cash flows.

Note 2: Holly Crude Pipelines and Tankage Transaction

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 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 at the agreed rates will result in minimum annual payments to us of $26.8 million. These minimum annual payments or revenue will be adjusted each year at a rate equal to the percentage change in the Producer Price Index (“PPI”) but will not decrease as a result of a decrease in the PPI. Under the agreement, the tariff rates will generally be increased annually by the percentage change in the Federal Energy Regulatory Commission (“FERC”) Oil Pipeline Index. The FERC index is the change in the PPI plus a FERC adjustment factor which is reviewed periodically.

Note 3: Properties and Equipment

		March 31,				December 31,
		2009				2008
		(In thousands)
Pipelines and terminals		$	309,326			$	308,056
Land and right of way			24,991				24,991
Other			11,660				11,498
Construction in progress			48,889				38,589
			394,866				383,134
Less accumulated depreciation			98,523				92,850
		$	296,343			$	290,284

We capitalized $0.3 million and $0.2 million in interest related to major construction projects during the three months ended March 31, 2009 and 2008, respectively.

Note 4: Transportation Agreements

Our transportation agreements consist of the following:

	•		The Alon transportation 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:

		March 31,				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			13,518				11,781
		$	120,646			$	122,383

We have two additional 15-year transportation agreements with Holly. One of the agreements relates to the pipelines and terminals contributed to us from Holly at the time of our initial public offering in 2004 (the “Holly PTA”). The second agreement relates to the Intermediate Pipelines acquired from Holly in 2005 (the “Holly IPA”). Our basis in the assets acquired under these transfers reflect Holly’s historical cost and do not reflect a step-up in basis to fair value. Therefore, these agreements have a recorded value of zero.

Note 5: 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 in accordance with an omnibus agreement that we have with Holly (the “Omnibus Agreement”). These employees participate in the retirement and benefit plans of Holly. Our share of retirement and benefit plan costs was $0.6 million and $0.2 million for the three months ended March 31, 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.

On March 31, 2009, we had two types of equity-based compensation, which are described below. The compensation cost charged against income for these plans was $0.4 million and $0.3 million for the three months ended March 31, 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 March 31, 2009, 350,000 units were authorized to be granted under the equity-based compensation plans, of which 200,541 had not yet been granted.

Restricted Units

Under our Long-Term Incentive Plan, we grant restricted units to selected employees and directors who perform services for us, with vesting generally over a period of one to five years. Although full ownership of the units does not transfer to the recipients until the units vest, the recipients have distribution and voting rights on these units from the date of grant. The vesting for certain key executives is contingent upon certain earnings per unit targets being realized. The fair value of each unit of 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 three months ended March 31, 2009 is presented below:

										Weighted-
						Weighted-				Average				Aggregate
						Average				Remaining				Intrinsic
						Grant-Date				Contractual				Value
Restricted Units		Grants				Fair Value				Term				($000)
Outstanding January 1, 2009 (not vested)			53,505			$	41.28
Granted			26,562				23.30
Forfeited			(2,152	)			42.53
Vesting and transfer of full ownership to recipients			(23,318	)			37.70
Outstanding at March 31, 2009 (not vested)			54,597			$	34.01			1.2 years				$	1,268

The fair value of restricted units that were vested and transferred to recipients during the three months ended March 31, 2009 and 2008 were $0.9 million and $0.5 million, respectively. As of March 31, 2009, there was $1.0 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 1.2 years.

During the three months ended March 31, 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 March 31, 2009, estimated share payouts for outstanding nonvested performance unit awards ranged from 0% to 150%.

We granted 28,113 performance units to certain officers in March 2009. These units will vest over a three-year performance period ending December 31, 2011 and are payable in HEP common units. The number of units actually earned will be based on the growth of distributions to limited partners over the performance period, and can range from 50% to 150% of the number of performance units issued. The fair value of these performance units is based on the grant date closing unit price of $23.30 and will apply to the number of units ultimately awarded.

A summary of performance unit activity and changes during the three months ended March 31, 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 March 31, 2009 (not vested)			54,771

The fair value of performance units that were vested and transferred to recipients during the three months ended March 31, 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 March 31, 2009 there was $1.5 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 6: 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 three months ended March 31, 2009, we received net advances totaling $40.0 million that were used as interim financing for capital projects and the purchase of our SLC Pipeline joint venture interest. As of March 31, 2009, we had $240.0 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 their assets, which other than their 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 March 31, 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 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 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, 2009, we are subject to a 0.30% commitment fee on the $60.0 million unused portion of the Credit Agreement. The agreement expires in August 2011. At that time, the agreement will terminate and all outstanding amounts thereunder will be due and payable.

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

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

Senior Notes Due 2015

Our senior notes maturing March 1, 2015 are registered with the U.S. Securities and Exchange Commission (“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.

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 their assets, which other than their investment in us, are not significant.

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

		March 31,				December 31,
		2009				2008
		(In thousands)
Credit Agreement		$	240,000			$	200,000
Senior Notes
Principal			185,000				185,000
Unamortized discount			(2,249	)			(2,344	)
Unamortized premium — de-designated fair value hedge			2,051				2,137
			184,802				184,793
Total debt			424,802				384,793
Less net short-term borrowings under credit agreement (1)			—				29,000
Total long-term debt (1)		$	424,802			$	355,793

Interest Rate Risk Management

We use interest rate derivatives to manage our exposure to interest rate risk. As of March 31, 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 March 31, 2009. The maturity date of this swap contract is February 28, 2013. We intend to renew our Credit Agreement prior to its expiration in August 2011 and continue to finance the $171.0 million balance until the swap matures.

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 March 31, 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 2.42% as of March 31, 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 months ended March 31, 2009, we recognized $0.2 million in interest expense attributable to 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.

Our interest rate swaps are valued using Level 2 inputs. Additional information on our interest rate swaps as of March 31, 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		$	3,762			Long-term debt		$	(2,051	)
- $60 million of 6.25% Senior Notes								HEP partners’ deficit			(1,942	)(1)
								Interest expense			231	(2)
				$	3,762					$	(3,762	)
Liability
Cash flow hedge — $171 million LIBOR based debt		Other long-term liabilities		$	(13,117	)		Accumulated other comprehensive loss		$	13,117
Variable-to-fixed interest rate swap		Other long-term						HEP partners' deficit			4,166	(1)
- $60 million		liabilities			(4,064	)		Interest expense			(102	)
				$	(17,181	)				$	17,181

Interest Expense and Other Debt Information

Interest expense consists of the following components:

		Three Months Ended
		March 31,
		2009				2008
		(In thousands)
Interest on outstanding debt:
Senior Notes, net of interest rate swaps		$	2,881			$	2,710
Credit Agreement, net of interest rate swap			2,570				984
Net amortization of discount and deferred debt issuance costs			176				223
Commitment fees			65				71
Total interest incurred			5,692				3,988
Less capitalized interest			289				181
Net interest expense		$	5,403			$	3,807
Cash paid for interest(1)		$	8,501			$	5,013

The estimated fair value of our Senior Notes was $136.9 million at March 31, 2009.

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 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
		March 31,
		2009				2008
Holly			57	%			67	%
Alon			29	%			19	%
BP			5	%			10	%

Note 8: Related Party Transactions

Holly and Alon Agreements

As of March 31, 2009, we serve Holly’s refineries in New Mexico and Utah under three 15-year pipeline and terminal and tankage agreements. The substantial majority of our business is devoted to providing transportation, storage and terminalling services to Holly.

We have an agreement that relates to the pipelines and terminals contributed by Holly to us at the time of our initial public offering and expires in 2019, the Holly PTA. Our second agreement with Holly relates to the Intermediate Pipelines acquired from Holly in July 2005 and expires in 2020, the Holly IPA. And third, we have the Holly CPTA that relates to the Crude Pipelines and Tankage Assets acquired from Holly in 2008 and expires on February 29, 2023.

Under the Holly PTA, Holly IPA and Holly CPTA, Holly agreed to transport and store volumes of refined product and crude oil on our pipelines and terminal and tankage facilities that result in minimum annual payments to us. These minimum annual payments or revenues will be adjusted each year at a percentage change equal to the change in the PPI but will not decrease as a result of a decrease in the PPI. Under these agreements, the agreed upon tariff rates are adjusted each year on July 1 at a rate equal to the percentage change in the PPI or FERC index, but generally will not decrease as a result of a decrease in the PPI or FERC index. The FERC index is the change in the PPI plus a FERC adjustment factor which is reviewed periodically. Following the July 1, 2008 PPI rate adjustments, these agreements will result in minimum payments to us of $81.3 million for the twelve months ended June 30, 2009.

We also have a 15-year 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 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 Holly or Alon fail to meet their minimum volume commitments under the agreements in any quarter, it will be required to pay us in cash the amount of any shortfall by the last day of the month following the end of the quarter. With the exception of the Holly CPTA, a shortfall payment may be applied as a credit in the following four quarters after minimum obligations are met.

Under certain provisions of the Omnibus Agreement that we entered with Holly in July 2004 and that expires in 2019, we pay Holly an annual administrative fee, currently $2.3 million, for the provision by Holly or its affiliates of various general and administrative services to us. This fee does not include the salaries of pipeline and terminal personnel or the cost of their employee benefits, which are separately charged to us by Holly. We also reimburse Holly and its affiliates for direct expenses they incur on our behalf.

•

Pipeline, terminal and tankage revenues received from Holly were $18.3 million for each of the three months ended March 31, 2009 and 2008. These amounts include the revenues received under the Holly PTA, Holly IPA and Holly CPTA.

•

Holly charged general and administrative services under the Omnibus Agreement of $0.6 million and $0.5 million for the three months ended March 31, 2009 and 2008, respectively.

•

We reimbursed Holly for costs of employees supporting our operations of $4.7 million and $2.6 million for the three months ended March 31, 2009 and 2008, respectively.

•

During the three months ended March 31, 2009, we paid Holly a $2.5 million finder’s fee in consideration for their assistance in obtaining our joint venture interest in the SLC Pipeline.

•

We distributed $6.9 million and $6.1 million during the three months ended March 31, 2009 and 2008, respectively, to Holly as regular distributions on its subordinated units, common units and general partner interest.

•

Our accounts receivable from Holly was $11.7 million and $9.4 million at March 31, 2009 and December 31, 2008, respectively.

•

Holly has failed to meet its minimum volume commitment for each of the fifteen quarters since inception of the Holly IPA. Through March 31, 2009, we have charged Holly $8.7 million for these shortfalls to date, $1.8 million and $0.5 million of which is included in affiliate accounts receivable at March 31, 2009 and December 31, 2008, respectively.

•

Our revenues for the three months ended March 31, 2009 include $0.2 million 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 March 31, 2009 and December 31, 2008, includes $3.9 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 $3.9 million deferred at March 31, 2009.

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.

•

Pipeline and terminal revenues received from Alon were $7.7 million and $3.4 million for the three months ended March 31, 2009 and 2008, respectively, under the Alon PTA. Additionally, pipeline revenues received under a pipeline capacity lease agreement with Alon were $1.7 million and $1.8 million for the three months ended March 31, 2009 and 2008, respectively.

•

We distributed $0.7 million during each of the three months ended March 31, 2009 and 2008 to Alon for distributions on its Class B subordinated units.

•

Included in our accounts receivable — trade were $3.3 million and $2.5 million at March 31, 2009 and December 31, 2008, respectively, which represented receivable balances from Alon.

•

Our revenues for the three months ended March 31, 2009 include $2.9 million 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 March 31, 2009 and December 31, 2008 includes $11.1 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 $11.1 million deferred at March 31, 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 $1.7 million and $2.7 million for the three months ended March 31, 2009 and 2008, respectively.

•

Included in our accounts receivable — trade at March 31, 2009 and December 31, 2008 were $0.5 million and $1.1 million, respectively, which represented the receivable balance of Rio Grande from BP.

Note 9: HEP Partners’ Equity, Income Allocations, Cash Distributions and Comprehensive Income

Issuances of units

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 subordination period of Holly’s subordinated units 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. The Holly subordinated units will convert to common units (on a one-for-one basis) on July 1, 2009 if these conditions are met.

Under our registration statement filed with the SEC using a “shelf” registration process, we may offer from time to time up to $1.0 billion 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 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.

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.

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

		Three Months Ended
		March 31,
		2009				2008
		(In thousands, except per unit data)
General partner interest		$	283			$	260
General partner incentive distribution			1,205				738
Total general partner distribution			1,488				998
Limited partner distribution			12,654				12,035
Total regular quarterly cash distribution		$	14,142			$	13,033
Cash distribution per unit applicable to limited partners		$	0.775			$	0.735

On April 23, 2009, we announced our cash distribution for the first quarter of 2009 of $0.775 per unit. The distribution is payable on all common, subordinated, and general partner units and will be paid May 14, 2009 to all unitholders of record on May 5, 2009.

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

Comprehensive Income

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

		Three Months Ended
		March 31,
		2009				2008
		(In thousands)
Net income		$	5,934			$	8,204
Other comprehensive loss:
Change in fair value of cash flow hedge			(150	)			(4,349	)
Comprehensive income			5,784				3,855
Less noncontrolling interest in comprehensive income			(495	)			(406	)
Comprehensive income attributable to HEP unitholders		$	5,289			$	3,449

Note 10: SLC Pipeline Joint Venture

In March 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 allows various refiners in the Salt Lake City area, including Holly’s Woods Cross Refinery, to ship crude oil into the Salt Lake City area from the Utah terminus of the Frontier Pipeline as well as crude oil flowing from Wyoming and Utah via Plains’ Rocky Mountain Pipeline. The total cost of our investment in the SLC Pipeline was $28.0 million, consisting of the capitalized $25.5 million joint venture contribution and the $2.5 million finder’s fee paid to Holly that was expensed as acquisition costs.

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

The SLC Pipeline commenced pipeline operations effective March 2009. Our equity in earnings of the SLC Pipeline was $0.2 million for the three months ended March 31, 2009.

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-
March 31, 2009		Parent				Subsidiaries				Guarantor				Eliminations				Consolidated
		(In thousands)
ASSETS
Current assets:
Cash and cash equivalents		$	2			$	1,105			$	3,214			$	—			$	4,321
Accounts receivable			—				15,104				786				—				15,890
Intercompany accounts receivable (payable)			(213,794	)			213,980				(186	)			—				—
Prepaid and other current assets			91				260				—				—				351
Total current assets			(213,701	)			230,449				3,814				—				20,562
Properties and equipment, net			—				264,234				32,109				—				296,343
Investment in subsidiaries			385,831				24,998				—				(410,829	)			—
Transportation agreements, net			—				120,646				—				—				120,646
Investment in SLC Pipeline			—				25,675				—				—				25,675
Other assets			5,067				1,252				—				—				6,319
Total assets		$	177,197			$	667,254			$	35,923			$	(410,829	)		$	469,545
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable		$	—			$	8,764			$	70			$	—			$	8,834
Accrued interest			(888	)			1,810				—				—				922
Deferred revenue			—				16,020				—				—				16,020
Accrued property taxes			—				763				47				—				810
Other current liabilities			2,078				(1,208	)			95				—				965
Total current liabilities			1,190				26,149				212				—				27,551
Long-term debt			184,802				240,000				—				—				424,802
Other long-term liabilities			—				17,774				—				—				17,774
Equity			(8,795	)			383,331				35,711				(410,829	)			(582	)
Total liabilities and equity		$	177,197			$	667,254			$	35,923			$	(410,829	)		$	469,545

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			(2,098	)			378,481				34,060				(402,323	)			8,120
Total liabilities and equity		$	186,131			$	620,927			$	34,953			$	(402,323	)		$	439,688

Condensed Consolidating Statement of Income

						Guarantor				Non-
Three months ended March 31, 2009		Parent				Subsidiaries				Guarantor				Eliminations				Consolidated
		(In thousands)
Revenues:
Affiliates		$	—			$	18,323			$	—			$	—			$	18,323
Third parties			—				11,353				2,792				(344	)			13,801
			—				29,676				2,792				(344	)			32,124
Operating costs and expenses:
Operations			—				10,349				791				(344	)			10,796
Depreciation and amortization			—				5,916				340				—				6,256
General and administrative			698				636				(10	)			—				1,324
			698				16,901				1,121				(344	)			18,376
Operating income (loss)			(698	)			12,775				1,671				—				13,748
Other income (expense):
Equity in earnings of subsidiaries			11,564				1,156				—				(12,720	)			—
Equity in earnings of SLC Pipeline			—				175				—				—				175
SLC Pipeline acquisition costs			—				(2,500	)			—				—				(2,500	)
Interest income (expense)			(2,927	)			(2,470	)			—				—				(5,397	)
			8,637				(3,639	)			—				(12,720	)			(7,722	)
Income (loss) before income taxes			7,939				9,136				1,671				(12,720	)			6,026
State income tax			—				(72	)			(20	)			—				(92	)
Net income			7,939				9,064				1,651				(12,720	)			5,934
Less noncontrolling interest in net income			—				—				—				495				495
Net income attributable to HEP partners		$	7,939			$	9,064			$	1,651			$	(13,215	)		$	5,439

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
Other income (expense):
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
			8,540				264				19				(12,501	)			(3,678	)
Income (loss) before income taxes			7,798				11,603				1,372				(12,501	)			8,272
State income tax			—				(49	)			(19	)			—				(68	)
Net income			7,798				11,554				1,353				(12,501	)			8,204
Less noncontrolling interest in net income			—				—				—				406				406
Net income attributable to HEP partners		$	7,798			$	11,554			$	1,353			$	(12,907	)		$	7,798