HOLLY ENERGY PARTNERS LP - Quarter Report: 2010 March (Form 10-Q)

HOLLY ENERGY PARTNERS, L.P.
INDEX

PART I. FINANCIAL INFORMATION			3
FORWARD-LOOKING STATEMENTS			3
Item 1. Financial Statements (Unaudited, except December 31, 2009 Balance Sheet)			4
Consolidated Balance Sheets			4
Consolidated Statements of Income			5
Consolidated Statements of Cash Flows			6
Consolidated Statement of Partners’ 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			39
Item 4. Controls and Procedures			39
PART II. OTHER INFORMATION			40
Item 1. Legal Proceedings			40
Item 6. Exhibits			40
SIGNATURES			41
Exhibit 12.1
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 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. Forward looking statements use words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “intend,” “could,” “believe,” “may,” and similar expressions and statements regarding our plans and objectives for future operations. These statements are based on our beliefs and assumptions and those of our general partner using currently available information and expectations as of the date hereof, are not guarantees of future performance and involve certain risks and uncertainties. Although we and our general partner believe that such expectations reflected in such forward-looking statements are reasonable, neither we nor our general partner can give assurance that our expectations will prove to be correct. Such statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Certain factors could cause actual results to differ materially from results anticipated in the forward-looking statements. These factors include, but are not limited to:

•

risks and uncertainties with respect to the actual quantities of petroleum products and crude oil shipped on our pipelines and/or terminalled in our terminals;

•

the economic viability of Holly Corporation, Alon USA, Inc. and our other customers;

•

the demand for refined petroleum products in markets we serve;

•

our ability to successfully purchase and integrate additional operations in the future;

•

our ability to complete previously announced or contemplated acquisitions;

•

the availability and cost of additional debt and equity financing;

•

the possibility of reductions in production or shutdowns at refineries utilizing our pipeline and terminal facilities;

•

the effects of current and future government regulations and policies;

•

our operational efficiency in carrying out routine operations and capital construction projects;

•

the possibility of terrorist attacks and the consequences of any such attacks;

•

general economic conditions; and

•

other financial, operations and legal risks and uncertainties detailed from time to time in our Securities and Exchange Commission filings.

Cautionary statements identifying important factors that could cause actual results to differ materially from our expectations are set forth in this Form 10-Q, including without limitation, the forward-looking statements that are referred to above. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements set forth in our Annual Report on Form 10-K for the year ended December 31, 2009 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, 2010				December 31,
		(Unaudited)				2009
		(In thousands, except unit data)
ASSETS
Current assets:
Cash and cash equivalents		$	16,609			$	2,508
Accounts receivable:
Trade			4,301				4,693
Affiliates			16,155				14,074
			20,456				18,767
Prepaid and other current assets			514				739
Current assets of discontinued operations			—				2,195
Total current assets			37,579				24,209
Properties and equipment, net			432,057				398,044
Transportation agreements, net			113,699				115,436
Goodwill			49,109				49,109
Investment in SLC Pipeline			26,400				25,919
Other assets			1,845				4,128
Total assets		$	660,689			$	616,845
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable:
Trade		$	3,361			$	3,860
Affiliates			2,855				2,351
			6,216				6,211
Accrued interest			1,706				2,863
Deferred revenue			9,510				8,402
Accrued property taxes			858				1,072
Other current liabilities			1,148				1,257
Total current liabilities			19,438				19,805
Long-term debt			503,393				390,827
Other long-term liabilities			11,366				12,349
Partners’ equity:
Common unitholders (21,141,009 units issued and outstanding)			262,941				275,553
Class B subordinated unitholders (937,500 units issued and outstanding)			21,022				21,426
General partner interest (2% interest)			(146,969	)			(93,974	)
Accumulated other comprehensive loss			(10,502	)			(9,141	)
Total partners’ equity			126,492				193,864
Total liabilities and partners’ equity		$	660,689			$	616,845

See accompanying notes.

Holly Energy Partners, L.P.

		Three Months Ended
		March 31,
		2010				2009
		(In thousands, except per unit data)
Revenues:
Affiliates		$	33,597			$	18,323
Third parties			7,099				11,009
			40,696				29,332
Operating costs and expenses:
Operations			13,060				10,342
Depreciation and amortization			7,210				6,016
General and administrative			2,563				1,334
			22,833				17,692
Operating income			17,863				11,640
Other income (expense):
Equity in earnings of SLC Pipeline			481				175
Interest income			3				6
Interest expense			(7,544	)			(5,403	)
Other expense			(7	)			—
SLC Pipeline acquisition costs			—				(2,500	)
			(7,067	)			(7,722	)
Income from continuing operations before income taxes			10,796				3,918
State income tax			(94	)			(73	)
Income from continuing operations			10,702				3,845
Income from discontinued operations, net of noncontrolling interest of $495			—				1,594
Net income			10,702				5,439
Less general partner interest in net income, including incentive distributions			2,646				1,293
Limited partners’ interest in net income		$	8,056			$	4,146
Limited partners’ per unit interest in earnings – basic and diluted:
Income from continuing operations		$	0.36			$	0.16
Income from discontinued operations			—				0.09
Net income		$	0.36			$	0.25
Weighted average limited partners’ units outstanding			22,079				16,328

See accompanying notes.

Holly Energy Partners, L.P.

		Three Months Ended
		March 31,
		2010				2009 (1)
		(In thousands)
Cash flows from operating activities
Net income		$	10,702			$	5,439
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization			7,210				6,256
SLC Pipeline earnings in excess of distributions			(481	)			(175	)
Change in fair value – interest rate swaps			1,464				216
Noncontrolling interest in earnings of Rio Grande Pipeline Company			—				495
Amortization of restricted and performance units			966				(52	)
(Increase) decrease in current assets:
Accounts receivable – trade			392				923
Accounts receivable – affiliates			(2,081	)			(2,336	)
Prepaid and other current assets			225				242
Current assets of discontinued operations			2,195				—
Increase (decrease) in current liabilities:
Accounts payable – trade			(499	)			(124	)
Accounts payable – affiliates			504				940
Accrued interest			(1,157	)			(1,923	)
Deferred revenue			1,108				362
Accrued property taxes			(214	)			(335	)
Other current liabilities			(109	)			(540	)
Other, net			(1,502	)			168
Net cash provided by operating activities			18,723				9,556
Cash flows from investing activities
Additions to properties and equipment			(1,911	)			(10,570	)
Acquisition of assets from Holly Corporation			(37,234	)			—
Investment in SLC Pipeline			—				(25,500	)
Net cash used for investing activities			(39,145	)			(36,070	)
Cash flows from financing activities
Borrowings under credit agreement			33,000				53,000
Repayments under credit agreement			(68,000	)			(13,000	)
Proceeds from issuance of senior notes			147,540				—
Distributions to HEP unitholders			(20,506	)			(13,818	)
Purchase price in excess of transferred basis in assets acquired from Holly Corporation			(55,766	)			—
Purchase of units for restricted grants			(1,745	)			(616	)
Net cash provided by financing activities			34,523				25,566
Cash and cash equivalents
Increase (decrease) for the period			14,101				(948	)
Beginning of period			2,508				5,269
End of period		$	16,609			$	4,321

See accompanying notes.

Holly Energy Partners, L.P.

														Accumulated
						Class B				General				Other
		Common				Subordinated				Partner				Comprehensive
		Units				Units				Interest				Loss				Total
		(In thousands)
Balance December 31, 2009		$	275,553			$	21,426			$	(93,974	)		$	(9,141	)		$	193,864
Distributions to partners			(19,751	)			(755	)			—				—				(20,506	)
Purchase price in excess of transferred basis in assets acquired from Holly Corporation			—				—				(55,428	)			—				(55,428	)
Purchase of units for restricted grants			(1,745	)			—				—				—				(1,745	)
Amortization of restricted and performance units			966				—				—				—				966
Comprehensive income:
Net income			7,918				351				2,433				—				10,702
Change in fair value of cash flow hedge			—				—				—				(1,361	)			(1,361	)
Comprehensive income			7,918				351				2,433				(1,361	)			9,341
Balance March 31, 2010		$	262,941			$	21,022			$	(146,969	)		$	(10,502	)		$	126,492

See accompanying notes.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 34% owned by Holly Corporation and its subsidiaries (collectively “Holly”). We commenced operations on July 13, 2004 upon the completion of our initial public offering. In these consolidated financial statements, the words “we,” “our,” “ours” and “us” refer to HEP unless the context otherwise indicates.

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

We own and operate petroleum product and crude oil pipeline and terminal, tankage and loading rack facilities that support Holly’s refining and marketing operations in west Texas, New Mexico, Utah, Oklahoma, Idaho and Arizona. We also own and operate refined product pipelines and terminals, located primarily in Texas, that service Alon USA, Inc.’s (“Alon”) refinery in Big Spring, Texas. Additionally, we own a 25% joint venture interest in a 95-mile intrastate crude oil pipeline system (the “SLC Pipeline”) that serves refineries in the Salt Lake City area.

We generate revenues by charging tariffs for transporting petroleum products and crude oil through our pipelines, by charging fees for terminalling refined products and other hydrocarbons and storing and providing other services at our storage tanks and terminals. We do not take ownership of products that we transport, terminal or store, and therefore, we are not directly exposed to changes in commodity prices.

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, 2009. 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, 2010.

Note 2: Discontinued Operations

On December 1, 2009, we sold our 70% interest in Rio Grande Pipeline Company (“Rio Grande”) to a subsidiary of Enterprise Products Partners LP for $35 million. Accordingly, results of operations of Rio Grande are presented in discontinued operations.

In accounting for the sale, we recorded a gain of $14.5 million and a receivable of $2.2 million, representing our final distribution from Rio Grande. Our recorded net asset balance of Rio Grande at December 1, 2009, was $22.7 million, consisting of cash of $3.1 million, $29.9 million in properties and equipment, net and $10.3 million in equity, representing BP, Plc’s 30% noncontrolling interest.

Cash flows from continuing and discontinued operations have been combined for presentation purposes in the Consolidated Statements of Cash Flows. For the three months ended March 31, 2009, net cash flows from our discontinued Rio Grande operations were $2 million.

Note 3: Acquisitions

2010 Acquisitions

Tulsa East / Lovington Storage Asset Transaction

On March 31, 2010, we acquired from Holly certain storage assets for $88.6 million consisting of hydrocarbon storage tanks having approximately 2 million barrels of storage capacity, a rail loading rack and a truck unloading rack located at Holly’s Tulsa refinery east facility.

In connection with this purchase, we amended our 15-year pipeline, tankage and loading rack throughput agreement with Holly (the “Holly PTTA”) that initially pertained to the logistics and storage assets acquired from an affiliate of Sinclair Oil Company (“Sinclair”) in December 2009. Under the amended Holly PTTA, Holly has agreed to transport, throughput and load volumes of product through our Tulsa east facility logistics and storage assets that will result in minimum annualized revenues to us of $27.2 million.

Also, as part of this same transaction, we acquired Holly’s asphalt loading rack facility located at Holly’s Navajo refinery Lovington facility for $4.4 million and entered into 15-year asphalt facility throughput agreement (the “Holly ATA”). Under the Holly ATA, Holly has agreed to throughput a minimum volume of products via our Lovington asphalt loading rack facility that will result in minimum annualized revenues to us of $0.5 million.

We are a controlled subsidiary of Holly. In accounting for these March 2010 acquisitions from Holly, we recorded total property and equipment at Holly’s cost basis of $37.2 million and the purchase price in excess of Holly’s basis in the assets of $55.8 million as a decrease to our partners’ equity.

2009 Acquisitions

Sinclair Logistics and Storage Assets Transaction

On December 1, 2009, we acquired from Sinclair storage tanks having approximately 1.4 million barrels of storage capacity and loading racks at its refinery located in Tulsa, Oklahoma for $79.2 million. The purchase price consisted of $25.7 million in cash, including $4.2 million in taxes and 1,373,609 of our common units having a fair value of $53.5 million. Separately, Holly, also a party to the transaction, acquired Sinclair’s Tulsa refinery.

With respect to this purchase, we recorded $30.2 million in properties and equipment, $49.1 million in goodwill and $0.2 million in other long-term liabilities. The value of the acquired assets, which does not include goodwill, is based on management’s fair value estimates using a cost approach methodology.

Roadrunner / Beeson Pipelines Transaction

Also on December 1, 2009, we acquired from Holly two newly constructed pipelines for $46.5 million, consisting of a 65-mile, 16-inch crude oil pipeline (the “Roadrunner Pipeline”) that connects the Navajo refinery facility located in Lovington, New Mexico to a terminus of Centurion Pipeline L.P.’s pipeline extending between west Texas and Cushing, Oklahoma and a 37-mile, 8-inch crude oil pipeline that connects our New Mexico crude oil gathering system to the Navajo refinery Lovington facility (the “Beeson Pipeline”).

Tulsa West Loading Racks Transaction

On August 1, 2009, we acquired from Holly certain truck and rail loading/unloading facilities located at Holly’s Tulsa refinery west facility for $17.5 million. The racks load refined products and lube oils produced at the Tulsa refinery onto rail cars and/or tanker trucks.

Lovington-Artesia Pipeline Transaction

On June 1, 2009, we acquired from Holly a newly constructed 16-inch intermediate pipeline for $34.2 million that runs 65 miles from the Navajo refinery’s crude oil distillation and vacuum facilities in Lovington, New Mexico to its petroleum refinery located in Artesia, New Mexico.

The Roadrunner and Beeson Pipelines, loading rack facilities and 16-inch intermediate pipeline discussed above were recorded at $95.1 million, representing Holly’s cost basis in the transferred assets. The $3.1 million purchase price in excess of Holly’s basis in the assets was recorded as a decrease to our partners’ equity.

SLC Pipeline Joint Venture Interest

On March 1, 2009, we acquired a 25% joint venture interest in the SLC Pipeline, a new 95-mile intrastate pipeline system that we jointly own with Plains All American Pipeline, L.P. (“Plains”). The total cost of our investment in the SLC Pipeline was $28 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.

Note 4: Financial Instruments

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

Our debt consists of outstanding principal under our revolving credit agreement (the “Credit Agreement”), our 6.25% senior notes due 2015 (the “6.25% Senior Notes”) and our 8.25% senior notes due 2018 (the “8.25% Senior Notes”). The $171 million carrying amount of outstanding debt under our Credit Agreement approximates fair value as interest rates are reset frequently using current rates. The estimated fair values of our 6.25% Senior Notes and 8.25% Senior Notes were $175.8 million and $151.5 million, respectively, at March 31, 2010. These fair value estimates are based on market quotes provided from a third-party bank. See Note 8 for additional information on these instruments.

Fair Value Measurements

Fair value measurements are derived using inputs, assumptions that market participants would use in pricing an asset or liability, including assumptions about risk. GAAP categorizes inputs used in fair value measurements into three broad levels as follows:

•

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

•

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

•

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

We have an interest rate swap that is measured at fair value on a recurring basis using Level 2 inputs that as of March 31, 2010 had a fair value of $10.5 million. With respect to this instrument, fair value is based on the net present value of expected future cash flows related to both variable and fixed rate legs of our interest rate swap agreement. Our measurement is computed using the forward London Interbank Offered Rate (“LIBOR”) yield curve, a market-based observable input. See Note 8 for additional information on our interest rate swap.

Note 5: Properties and Equipment

		March 31,				December 31,
		2010				2009
		(In thousands)
Pipelines and terminals (1)		$	492,931			$	455,075
Land and right of way			25,247				25,230
Other			13,071				12,528
Construction in progress			11,496				10,484
			542,745				503,317
Less accumulated depreciation			110,688				105,273
		$	432,057			$	398,044

We capitalized $0.1 million and $0.3 million in interest related to major construction projects during the three months ended March 31, 2010 and 2009, respectively.

Note 6: Transportation Agreements

Our transportation agreements consist of the following:

•

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

•

The Holly crude pipelines and tankage agreement (the “Holly CPTA”) represents a portion of the total purchase price of certain crude pipelines and tankage assets acquired from Holly in 2008 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,
		2010				2009
		(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			20,465				18,728
		$	113,699			$	115,436

We have additional transportation agreements with Holly that relate to pipeline, terminal and tankage assets contributed to us or acquired from Holly. These transfers occurred while under common control of Holly, therefore, our basis in these assets reflect Holly’s historical cost and does not reflect a step-up in basis to fair value. These agreements have a recorded value of zero.

In addition, we have an agreement to provide transportation and storage services to Holly via our Tulsa logistics and storage assets acquired from Sinclair. Since this agreement is with Holly and not between Sinclair and us, there is no cost attributable to this agreement.

Note 7: Employees, Retirement and Incentive Plans

Employees who provide direct services to us are employed by Holly Logistic Services, L.L.C., a Holly subsidiary. Their costs, including salaries, bonuses, payroll taxes, benefits and other direct costs are charged to us monthly in accordance with an omnibus agreement that we have with Holly. These employees participate in the retirement and benefit plans of Holly. Our share of retirement and benefit plan costs was $0.7 million and $0.6 million for the three months ended March 31, 2010 and 2009, respectively. These amounts include retirement costs of $0.4 million and $0.3 million for the three months ended March 31, 2010 and 2009, respectively.

We have adopted an incentive plan (“Long-Term Incentive Plan”) for employees, consultants and non-employee directors who perform services for us. The Long-Term Incentive Plan consists of four components: restricted units, performance units, unit options and unit appreciation rights.

As of March 31, 2010, we have two types of equity-based compensation, which are described below. The compensation cost charged against income for these plans was $1 million and $0.4 million for the three months ended March 31, 2010 and 2009, respectively. We currently purchase units in the open market instead of issuing new units for settlement of restricted unit grants. At March 31, 2010, 350,000 units were authorized to be granted under the equity-based compensation plans, of which 174,857 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 fair value of each restricted unit award is measured at the market price as of the date of grant and is amortized over the vesting period.

A summary of restricted unit activity and changes during the three months ended March 31, 2010 is presented below:

										Weighted-
						Weighted-				Average				Aggregate
						Average				Remaining				Intrinsic
						Grant-Date				Contractual				Value
Restricted Units		Grants				Fair Value				Term				($000)
Outstanding at January 1, 2010 (nonvested)			53,271			$	34.31
Granted			31,355				42.59
Vesting and transfer of full ownership to recipients			(34,645	)			38.94
Outstanding at March 31, 2010 (nonvested)			49,981			$	36.30				1 year			$	2,124

The fair value of restricted units that were vested and transferred to recipients during the three months ended March 31, 2010 and 2009 were $1.3 million and $0.9 million, respectively. As of March 31, 2010, there was $0.9 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 year.

During the three months ended March 31, 2010, we paid $1.7 million for the purchase of 40,681 of our common units in the open market for the recipients of our restricted unit grants.

Performance Units

Under our Long-Term Incentive Plan, we grant performance units to selected executives who perform services for us. Performance units granted in 2010 are payable based upon the growth in our distributable cash flow per common unit over the performance period, and vest over a period of three years. Performance units granted in 2009 and 2008 are payable based upon the growth in distributions on our common units during the requisite period, and vest over a period of three years. As of March 31, 2010, estimated share payouts for outstanding nonvested performance unit awards ranged from 110 to 120%.

We granted 16,965 performance units to certain officers in March 2010. These units will vest over a three-year performance period ending December 31, 2012 and are payable in HEP common units. The number of units actually earned will be based on the growth of our distributable cash flow per common unit 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 $42.59 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, 2010 is presented below:

		Payable
Performance Units		In Units
Outstanding at January 1, 2010 (nonvested)			54,771
Vesting and transfer of common units to recipients			(11,785	)
Granted			16,965
Outstanding at March 31, 2010 (nonvested)			59,951

The fair value of performance units vested and transferred to recipients during the three months ended March 31, 2010 and 2009 was $0.5 million and $0.4 million, respectively. Based on the weighted average fair value at March 31, 2010 of $33.09, 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 8: Debt

Credit Agreement

We have a $300 million senior secured revolving Credit Agreement expiring in August 2011. 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 million sub-limit and to fund distributions to unitholders up to a $20 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, 2010, we received advances totaling $33 million and repaid $68 million, resulting in the net repayment of $35 million in advances. As of March 31, 2010, we had $171 million outstanding under the Credit Agreement.

Our obligations under the Credit Agreement are collateralized by substantially all of our assets. Indebtedness under the Credit Agreement is recourse to HEP Logistics Holdings, L.P., our general partner, and guaranteed by our wholly-owned subsidiaries. Any recourse to HEP Logistics Holdings, L.P. would be limited to the extent of its assets, which other than its investment in us, are not significant.

We may prepay all loans at any time without penalty, except for payment of certain breakage and related costs. We are required to reduce all working capital borrowings under the Credit Agreement to zero for a period of at least 15 consecutive days in each twelve-month period prior to the maturity date of the agreement. As of March 31, 2010, we had no working capital borrowings.

Indebtedness under the Credit Agreement bears interest, at our option, at either (a) the reference rate as announced by the administrative agent plus an applicable margin (ranging from 0.25% to 1.50%) or (b) at a rate equal to LIBOR plus an applicable margin (ranging from 1.00% to 2.50%). In each case, the applicable margin is based upon the ratio of our funded debt (as defined in the Credit Agreement) to EBITDA (earnings before interest, taxes, depreciation and amortization, as defined in the Credit Agreement). At March 31, 2010, we were subject to an applicable margin of 1.75%. We incur a commitment fee on the unused portion of the Credit Agreement at a rate ranging from 0.20% to 0.50% based upon the ratio of our funded debt to EBITDA for the four most recently completed fiscal quarters. At March 31, 2010, we are subject to a .30% commitment fee on the $129 million unused portion of the Credit Agreement. The agreement expires in August 2011. At that time, the agreement will terminate and all outstanding amounts thereunder will become due and payable.

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

In March 2010, we issued $150 million in aggregate principal amount of 8.25% Senior Notes maturing March 15, 2018. A portion of the $147.5 million in net proceeds received was used to fund our $93 million purchase of the Tulsa and Lovington storage assets from Holly on March 31, 2010. Additionally, we used a portion to repay $42 million in outstanding Credit Agreement borrowings, with the remaining proceeds available for general partnership purposes, including working capital, capital expenditures and possible future acquisitions.

Our 6.25% Senior Notes having an aggregate principal amount of $185 million mature March 1, 2015 and are registered with the SEC. The 6.25% Senior Notes and 8.25% Senior Notes (collectively, the “Senior Notes”) are unsecured and impose certain restrictive covenants, which we are subject to and currently in compliance with, 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. However, any recourse to HEP Logistics Holdings, L.P. would be limited to the extent of its assets, which other than its investment in us, are not significant.

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

		March 31,				December 31,
		2010				2009
		(In thousands)
Credit Agreement		$	171,000			$	206,000
6.25% Senior Notes
Principal			185,000				185,000
Unamortized discount			(1,868	)			(1,964	)
Unamortized premium — dedesignated fair value hedge			1,704				1,791
			184,836				184,827
8.25% Senior Notes
Principal			150,000				—
Unamortized discount			(2,443	)			—
			147,557				—
Total long-term debt		$	503,393			$	390,827

Interest Rate Risk Management

We use interest rate swaps (derivative instruments) to manage our exposure to interest rate risk.

As of March 31, 2010, we have an interest rate swap that hedges our exposure to the cash flow risk caused by the effects of LIBOR changes on a $171 million Credit Agreement advance. This interest rate swap effectively converts our $171 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, 2010. The maturity date of this swap contract is February 28, 2013.

We have designated this interest rate swap as a cash flow hedge. Based on our assessment of effectiveness using the change in variable cash flows method, we have determined that this interest rate swap is effective in offsetting the variability in interest payments on our $171 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 million variable rate debt. Any ineffectiveness is reclassified from accumulated other comprehensive income to interest expense. To date, we have had no ineffectiveness on our cash flow hedge.

Additional information on our interest rate swap as of March 31, 2010 is as follows:

Balance Sheet

Location of Offsetting

Offsetting

Interest Rate Swap

Location

Fair Value

Balance

Amount

(In thousands)

Liability

Cash flow hedge — $171 million LIBOR based debt

Other long-term liabilities

$

(10,502

)

Accumulated other comprehensive loss

$

10,502

In the first quarter of 2010, we settled two interest rate swaps. We had an interest rate swap contract that effectively converted interest expense associated with $60 million of our 6.25% Senior Notes from fixed to variable rate debt (“Variable Rate Swap”). We had an additional interest rate swap contract that effectively unwound the effects of the Variable Rate Swap, converting $60 million of the previously hedged long-term debt back to fixed rate debt (“Fixed Rate Swap”), effectively fixing interest at a 4.75% rate. Upon settlement of the Variable Rate and Fixed Rate Swaps, we received $1.9 million and paid $3.6 million, respectively.

For the three months ended March 31, 2010 and 2009, we recognized $1.5 million and $0.2 million, respectively, in interest expense attributable to fair value adjustments to these interest rate swaps.

We have a deferred hedge premium that relates to the application of hedge accounting to the Variable Rate Swap prior to its hedge dedesignation in 2008. This deferred hedge premium having a balance of $1.7 million at March 31, 2010, is being amortized as a reduction to interest expense over the remaining term of the 6.25% Senior Notes.

Interest Expense and Other Debt Information

Interest expense consists of the following components:

		March 31,				March 31,
		2010				2009
		(In thousands)
Interest on outstanding debt:
Credit Agreement, net of interest on interest rate swap		$	2,472			$	2,570
6.25% Senior Notes, net of interest on interest rate swaps			2,732				2,665
8.25% Senior Notes			722				—
Net fair value adjustments to interest rate swaps			1,464				216
Net amortization of discount and deferred debt issuance costs			194				176
Commitment fees			77				65
Total interest incurred			7,661				5,692
Less capitalized interest			117				289
Net interest expense		$	7,544			$	5,403
Cash paid for interest (1)		$	10,587			$	8,501

Note 9: Significant Customers

All revenues are domestic revenues, of which over 95% are currently generated from our two largest customers: Holly and Alon. The major concentration of our petroleum product and crude oil pipeline system’s revenues is derived from activities conducted in the southwest United States.

The following table presents the percentage of total revenues from continuing operations generated by each of these customers:

		Three Months Ended
		March 31,
		2010				2009
Holly			83	%			63	%
Alon			13	%			32	%

Note 10: Related Party Transactions

Holly and Alon Agreements

We serve Holly’s refineries in New Mexico, Utah and Oklahoma under the following long-term pipeline and terminal, tankage and throughput agreements:

•

Holly PTA (pipelines and terminals throughput agreement expiring in 2019 that relates to the pipelines and terminal assets contributed to us by Holly upon our initial public offering in 2004);

•

Holly IPA (intermediate pipelines throughput agreement expiring in 2024 that relates to the intermediate pipelines acquired from Holly in 2005 and 2009);

•

Holly CPTA (crude pipelines and tankage throughput agreement expiring in 2023 that relates to the crude pipelines and tankage assets acquired from Holly in 2008);

•

Holly PTTA (pipeline, tankage and loading rack throughput agreement expiring in 2024 that relates to the Tulsa east storage tank and loading rack facilities acquired from Sinclair in 2009 and from Holly in March 2010);

•

Holly RPA (pipeline throughput agreement expiring in 2024 that relates to the Roadrunner Pipeline acquired from Holly in 2009);

•

Holly ETA (equipment and throughput agreement expiring in 2024 that relates to the Tulsa west loading rack facilities acquired from Holly in 2009); and

•

Holly ATA (loading rack throughput agreement expiring in 2025 that relates to the Lovington asphalt loading rack facility acquired from Holly in March 2010).

Under these agreements, Holly agreed to transport, store and throughput volumes of refined product and crude oil on our pipelines and terminal, tankage and loading rack facilities that result in minimum annual payments to us. These minimum annual payments or revenues will be adjusted each year at a percentage change based upon the change in the Producer Price Index (“PPI”) but will not decrease as a result of a decrease in the PPI. Under these agreements, the agreed upon tariff rates are adjusted each year on July 1 at a rate based upon the percentage change in the PPI or the Federal Energy Regulatory Commission (“FERC”) index, but with the exception of the Holly IPA, generally will not decrease as a result of a decrease in the PPI or FERC index. The FERC index is the change in the PPI plus a FERC adjustment factor that is reviewed periodically. As of March 31, 2010, these agreements with Holly will result in minimum annualized payments to us of $132.4 million.

We also have a pipelines and terminals agreement with Alon expiring in 2020 under which Alon has agreed to transport on our pipelines and throughput through our terminals volumes of refined products that result in a minimum level of annual revenue. The agreed upon tariff rates 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, 2010 PPI adjustment, Alon’s minimum annualized commitment to us is $22.7 million.

If Holly or Alon fails 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. A shortfall payment under the Holly PTA, Holly IPA and Alon PTA may be applied as a credit in the following four quarters after minimum obligations are met.

We entered into an omnibus agreement with Holly in 2004 that Holly and we have amended and restated several times in connection with our past acquisitions from Holly with the last amendment and restatement occurring on March 31, 2010 (the “Omnibus Agreement”). Under certain provisions of the Omnibus Agreement, we pay Holly an annual administrative fee for the provision by Holly or its affiliates of various general and administrative services to us, 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. Also, we reimburse Holly and its affiliates for direct expenses they incur on our behalf.

Related party transactions with Holly are as follows:

•

Pipeline, terminal and tankage revenues received from Holly were $33.6 million and $18.3 million for the three months ended March 31, 2010 and 2009, respectively. These amounts include revenues received under our long-term transportation and throughput agreements with Holly.

•

Holly charged general and administrative services under the Omnibus Agreement of $0.6 million for the three months ended March 31, 2010 and 2009.

•

We reimbursed Holly for costs of employees supporting our operations of $4.2 million and $4.7 million for the three months ended March 31, 2010 and 2009, respectively.

•

We paid Holly a $2.5 million finder’s fee in connection the acquisition of our 25% joint venture interest in the SLC Pipeline in the first quarter of 2009.

•

We distributed $8.5 million and $6.9 million for the three months ended March 31, 2010 and 2009, respectively, to Holly as regular distributions on its common units, subordinated units and general partner interest, including general partner incentive distributions.

•

Our accounts receivable from Holly was $16.2 million and $14.1 million at March 31, 2010 and December 31, 2009, respectively.

•

Our accounts payable to Holly were $2.9 million and $2.4 million at March 31, 2010 and December 31, 2009, respectively.

•

Holly failed to meet its minimum volume commitment for each of the nineteen quarters since inception of the Holly IPA. Through March 31, 2010, we have charged Holly $11.7 million for these shortfalls of which $1.1 million and $0.7 million is included in affiliate accounts receivable at March 31, 2010 and December 31, 2009, respectively.

•

Our revenues for the three months ended March 31, 2010 include $1.8 million of shortfalls billed under the Holly IPA in 2009 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, 2010 and December 31, 2009, includes $3 million and $3.6 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 million deferred at March 31, 2010.

•

We acquired the Tulsa east and Lovington storage assets, Roadrunner and Beeson Pipelines, Tulsa loading racks and a 16-inch intermediate pipeline from Holly in March 2010, December 2009, August 2009 and June 2009, respectively. See Note 3 for a description of these transactions.

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

Related party transactions with Alon are as follows:

•

Pipeline and terminal revenues received from Alon were $4.1 million and $7.7 million for the three months ended March 31, 2010 and 2009, respectively, under the Alon PTA. Additionally, pipeline revenues received under a pipeline capacity lease agreement with Alon were $1.3 million and $1.7 million for three months ended March 31, 2010 and 2009, respectively.

•

We distributed $0.8 million and $0.7 million for the three months ended March 31, 2010 and 2009, respectively, to Alon for distributions on its Class B subordinated units.

•

Our accounts receivable – trade include receivable balances from Alon of $4 million at March 31, 2010 and December 31, 2009.

•

Our revenues for the three months ended March 31, 2010 include $0.7 million of shortfalls billed under the Alon PTA in 2009, 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, 2010 and December 31, 2009 includes $6.6 million and $4.8 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 $6.6 million deferred at March 31, 2010.

Note 11: Partners’ Equity, Income Allocations, Cash Distributions and Comprehensive Income

Holly currently holds 7,290,000 of our common units and the 2% general partner interest, which together constitutes a 34% ownership interest in us.

Currently we have outstanding, 937,500 Class B subordinated units that were originally issued to Alon. As of March 31, 2010, all of the conditions necessary to end the subordination period for these units have been met, and we anticipate that in May 2010, following our next declared distribution, these units will convert into our common units on a one-for-one basis.

Issuances of units

In connection with our December 1, 2009 acquisition of Sinclair’s Tulsa logistics assets, we issued 1,373,609 of our common units having a value of $53.5 million to Sinclair as partial consideration of our total $79.2 million purchase price.

In November 2009, we issued in a public offering 2,185,000 of our common units priced at $35.78 per unit. Aggregate net proceeds of $74.9 million were used to fund the cash portion of our December 1, 2009 asset acquisitions, to repay outstanding borrowings under the Credit Agreement and for general partnership purposes.

Additionally in May 2009, we issued in a public offering 2,192,400 of our common units priced at $27.80 per unit. Net proceeds of $58.4 million were used to repay outstanding borrowings under the Credit Agreement and for general partnership purposes.

Concurrent with the 2009 common unit issuances described above, we received aggregate capital contributions of $3.8 million from our general partner to maintain its 2% general partner interest.

Under our registration statement filed with the SEC using a “shelf” registration process, we currently have the ability to raise $860 million through security offerings, through one or more prospectus supplements that would describe, among other things, the specific amounts, prices and terms of any securities offered and how the proceeds would be used. Any proceeds from the sale of securities would be used for general business purposes, which may include, among other things, funding acquisitions of assets or businesses, working capital, capital expenditures, investments in subsidiaries, the retirement of existing debt and/or the repurchase of common units or other securities.

Allocations of Net Income

Net income attributable to Holly Energy Partners, L.P. is allocated between limited partners and the general partner interest in accordance with the provisions of the partnership agreement. HEP net income allocated to the general partner includes incentive distributions that are declared subsequent to quarter end. After the amount of incentive distributions is allocated to the general partner, the remaining net income attributable to HEP is generally allocated to the partners based on their weighted-average ownership percentage during the period.

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

		Three Months Ended
		March 31,
		2010				2009
		(In thousands)
General partner interest in net income		$	169			$	88
General partner incentive distribution			2,477				1,205
Total general partner interest in net income		$	2,646			$	1,293

Cash Distributions

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

On April 23, 2010, we announced our cash distribution for the first quarter of 2010 of $0.815 per unit. The distribution is payable on all common, subordinated, and general partner units and will be paid May 14, 2010 to all unitholders of record on May 4, 2010.

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

		Three Months Ended
		March 31,
		2010				2009
		(In thousands, except per unit data)
General partner regular distribution		$	418			$	283
General partner incentive distribution			2,477				1,205
Total general partner distribution			2,895				1,488
Limited partner distribution			17,994				12,654
Total regular quarterly cash distribution		$	20,889			$	14,142
Cash distribution per unit applicable to limited partners		$	0.815			$	0.775

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 our equity since our regular quarterly distributions have exceeded our quarterly net income. Additionally, if the assets transferred to us upon our initial public offering in 2004, the intermediate pipelines purchased from Holly in 2005 and the assets purchased from Holly in 2009 and March 2010 had been acquired from third parties, our acquisition cost in excess of Holly’s basis in the transferred assets of $216.2 million would have been recorded as increases to our properties and equipment and intangible assets instead of decreases to partners’ 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,
		2010				2009
		(In thousands)
Net income		$	10,702			$	5,934
Other comprehensive loss:
Change in fair value of cash flow hedge			(1,361	)			(150	)
Comprehensive income			9,341				5,784
Less noncontrolling interest in comprehensive income			—				(495	)
Comprehensive income attributable to HEP unitholders		$	9,341			$	5,289

Note 12: Supplemental Guarantor/Non-Guarantor Financial Information

Obligations of Holly Energy Partners, L.P. (“Parent”) under the 6.25% Senior Notes and 8.25% 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.

We sold our 70% interest in Rio Grande on December 1, 2009; therefore, Rio Grande is no longer a subsidiary of HEP. Rio Grande (“Non-Guarantor”) was the only subsidiary that did not guarantee these obligations. Amounts attributable to Rio Grande prior to our sale are presented in discontinued operations.

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
March 31, 2010		Parent				Subsidiaries				Eliminations				Consolidated
		(In thousands)
ASSETS
Current assets:
Cash and cash equivalents		$	2			$	16,607			$	—			$	16,609
Accounts receivable			—				20,456				—				20,456
Intercompany accounts receivable (payable)			(14,523	)			14,523				—				—
Prepaid and other current assets			227				287				—				514
Total current assets			(14,294	)			51,873				—				37,579
Properties and equipment, net			—				432,057				—				432,057
Investment in subsidiaries			474,504				—				(474,504	)			—
Transportation agreements, net			—				113,699				—				113,699
Goodwill			—				49,109				—				49,109
Investment in SLC Pipeline			—				26,400				—				26,400
Other assets			1,115				730				—				1,845
Total assets		$	461,325			$	673,868			$	(474,504	)		$	660,689
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable		$	—			$	6,216			$	—			$	6,216
Accrued interest			1,685				21				—				1,706
Deferred revenue			—				9,510				—				9,510
Accrued property taxes			—				858				—				858
Other current liabilities			755				393				—				1,148
Total current liabilities			2,440				16,998				—				19,438
Long-term debt			332,393				171,000				—				503,393
Other long-term liabilities			—				11,366				—				11,366
Partners’ equity			126,492				474,504				(474,504	)			126,492
Total liabilities and partners’ equity		$	461,325			$	673,868			$	(474,504	)		$	660,689

Condensed Consolidating Balance Sheet

						Guarantor
December 31, 2009		Parent				Subsidiaries				Eliminations				Consolidated
		(In thousands)
ASSETS
Current assets:
Cash and cash equivalents		$	2			$	2,506			$	—			$	2,508
Accounts receivable			—				18,767				—				18,767
Intercompany accounts receivable (payable)			(76,855	)			76,855				—				—
Prepaid and other current assets			261				478				—				739
Current assets of discontinued operations			—				2,195				—				2,195
Total current assets			(76,592	)			100,801				—				24,209
Properties and equipment, net			—				398,044				—				398,044
Investment in subsidiaries			458,381				—				(458,381	)			—
Transportation agreements, net			—				115,436				—				115,436
Goodwill			—				49,109				—				49,109
Investment in SLC Pipeline			—				25,919				—				25,919
Other assets			3,267				861				—				4,128
Total assets		$	385,056			$	690,170			$	(458,381	)		$	616,845
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable		$	—			$	6,211			$	—			$	6,211
Accrued interest			2,849				14				—				2,863
Deferred revenue			—				8,402				—				8,402
Accrued property taxes			—				1,072				—				1,072
Other current liabilities			961				296				—				1,257
Total current liabilities			3,810				15,995				—				19,805
Long-term debt			184,827				206,000				—				390,827
Other long-term liabilities			2,555				9,794				—				12,349
Partners’ equity			193,864				458,381				(458,381	)			193,864
Total liabilities and partners’ equity		$	385,056			$	690,170			$	(458,381	)		$	616,845

Condensed Consolidating Statement of Income

						Guarantor
Three months ended March 31, 2010		Parent				Subsidiaries				Eliminations				Consolidated
		(In thousands)
Revenues:
Affiliates		$	—			$	33,597			$	—			$	33,597
Third parties			—				7,099				—				7,099
			—				40,696				—				40,696
Operating costs and expenses:
Operations			—				13,060				—				13,060
Depreciation and amortization			—				7,210				—				7,210
General and administrative			1,801				762				—				2,563
			1,801				21,032								22,833
Operating income (loss)			(1,801	)			19,664				—				17,863
Equity in earnings of subsidiaries			17,485				—				(17,485	)			—
Equity in earnings of SLC Pipeline			—				481				—				481
Interest income (expense)			(4,982	)			(2,559	)			—				(7,541	)
Other			—				(7	)			—				(7	)
			12,503				(2,085	)			(17,485	)			(7,067	)
Income (loss) before income taxes			10,702				17,579				(17,485	)			10,796
State income tax			—				(94	)			—				(94	)
Net income		$	10,702			$	17,485			$	(17,485	)		$	10,702

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			—				11,009				—				—				11,009
			—				29,332				—				—				29,332
Operating costs and expenses:
Operations			—				10,342				—				—				10,342
Depreciation and amortization			—				6,016				—				—				6,016
General and administrative			698				636				—				—				1,334
			698				16,994				—				—				17,692
Operating income (loss)			(698	)			12,338				—				—				11,640
Equity in earnings of subsidiaries			9,064				1,156				—				(10,220	)			—
Equity in earnings of SLC Pipeline			—				175				—				—				175
Interest income (expense)			(2,927	)			(2,470	)			—				—				(5,397	)
SLC Pipeline acquisition costs			—				(2,500	)			—				—				(2,500	)
			6,137				(3,639	)			—				(10,220	)			(7,722	)
Income (loss) from continuing operations before income taxes			5,439				8,699				—				(10,220	)			3,918
State income tax			—				(73	)			—				—				(73	)
Income from continuing operations			5,439				8,626				—				(10,220	)			3,845
Income from discontinued operations			—				438				1,651				(495	)			1,594
Net income		$	5,439			$	9,064			$	1,651			$	(10,715	)		$	5,439