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 September 30, 2006

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

For the transition period from                      to                     .

HOLLY ENERGY PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

Delaware		20-0833098
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

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

(Address of principal executive offices)

(214) 871-3555

(Registrant’s telephone number, including area code)

None

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

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

Yes þ           No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o            Accelerated filer þ           Non-accelerated filer o

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

Yes o           No þ

The number of the registrant’s outstanding common units at October 20, 2006 was 8,170,000.

 

 

HOLLY ENERGY PARTNERS, L.P.
INDEX

PART I. FINANCIAL INFORMATION			3
FORWARD-LOOKING STATEMENTS			3
Item 1. Financial Statements (Unaudited, except December 31, 2005 Balance Sheet)			4
Consolidated Balance Sheets			4
Consolidated Statements of Income			5
Consolidated Statements of Cash Flows			6
Consolidated Statement of Partners’ Equity (Deficit)			7
Notes to Consolidated Financial Statements			8
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			25
Item 3. Quantitative and Qualitative Disclosures About Market Risks			40
Item 4. Controls and Procedures			40
PART II. OTHER INFORMATION			41
Item 1. Legal Proceedings			41
Item 2. Unregistered Sales of Securities and Use of Proceeds			41
Item 6. Exhibits			41
SIGNATURES			42
Computation of Ratio of Earnings to Fixed Charges
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906

PART I. FINANCIAL INFORMATION

FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains certain “forward-looking statements” within the meaning of the federal securities laws. All statements, other than statements of historical fact included in the 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 materially differ 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 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 any future acquired operations;
	•		The availability and cost of our financing;
	•		The possibility of reductions in production or shutdowns at refineries utilizing our pipeline and terminal facilities;
	•		The effects of current and future government regulations and policies;
	•		Our operational efficiency in carrying out routine operations and capital construction projects;
	•		The possibility of terrorist attacks and the consequences of any such attacks;
	•		General economic conditions; and
	•		Other financial, operational 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, 2005 in “Risk Factors,” and in this Form 10-Q in “Management’s Discussion and Analysis of Financial Condition and Results of Operations”. All forward-looking statements included in this Form 10-Q and all subsequent written or oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. The forward-looking statements speak only as of the date made and, other than as required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Item 1. Financial Statements

Holly Energy Partners, L.P.

		September 30,
		2006				December 31,
		(Unaudited)				2005
		(In thousands, except unit data)
ASSETS
Current assets:
Cash and cash equivalents		$	12,408			$	20,583
Accounts receivable:
Trade			4,659				3,076
Affiliates			2,286				3,645
			6,945				6,721
Prepaid and other current assets			1,644				1,401
Total current assets			20,997				28,705
Properties and equipment, net			160,894				162,298
Transportation agreements, net			57,842				60,903
Other assets			2,768				2,869
Total assets		$	242,501			$	254,775
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable		$	3,951			$	3,020
Accrued interest			970				2,892
Deferred revenue			4,695				1,013
Accrued property taxes			1,273				1,013
Other current liabilities			1,567				1,313
Total current liabilities			12,456				9,251
Commitments and contingencies			—				—
Long-term debt			180,466				180,737
Other long-term liabilities			1,335				974
Minority interest			10,638				11,753
Partners’ equity (deficit):
Common unitholders (8,170,000 units issued and outstanding)			177,472				184,650
Subordinated unitholder (7,000,000 units issued and outstanding)			(69,396	)			(63,235	)
Class B subordinated unitholder (937,500 units issued and outstanding)			23,563				24,388
General partner (2% interest)			(94,033	)			(93,743	)
Total partners’ equity			37,606				52,060
Total liabilities and partners’ equity		$	242,501			$	254,775

See accompanying notes.

Holly Energy Partners, L.P.

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2006				2005				2006				2005
		(In thousands, except per unit data)
Revenues:
Affiliates		$	14,272			$	12,507			$	37,338			$	31,878
Third parties			8,627				9,010				26,526				25,673
			22,899				21,517				63,864				57,551
Operating costs and expenses:
Operations			7,082				6,333				21,620				18,169
Depreciation and amortization			3,839				3,924				11,413				10,136
General and administrative			1,177				1,075				3,690				3,042
			12,098				11,332				36,723				31,347
Operating income			10,801				10,185				27,141				26,204
Other income (expense):
Interest income			214				201				702				434
Interest expense			(3,302	)			(3,038	)			(9,724	)			(6,521	)
			(3,088	)			(2,837	)			(9,022	)			(6,087	)
Income before minority interest			7,713				7,348				18,119				20,117
Minority interest in Rio Grande Pipeline Company			38				(56	)			(235	)			(458	)
Net income			7,751				7,292				17,884				19,659
Less general partner interest in net income			488				208				1,134				455
Limited partners’ interest in net income		$	7,263			$	7,084			$	16,750			$	19,204
Net income per limited partner unit - Basic and diluted		$	0.45			$	0.44			$	1.04			$	1.27
Weighted average limited partner units outstanding			16,108				16,018				16,108				15,103

See accompanying notes.

Holly Energy Partners, L.P.

		Nine Months Ended September 30,
		2006				2005
		(In thousands)
Cash flows from operating activities
Net income		$	17,884			$	19,659
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization			11,413				10,136
Minority interest in Rio Grande Pipeline Company			235				458
Amortization of restricted and performance units			646				144
(Increase) decrease in current assets:
Accounts receivable – trade			(1,583	)			(2,624	)
Accounts receivable – affiliates			1,359				1,124
Prepaid and other current assets			(317	)			(986	)
Increase (decrease) in current liabilities:
Accounts payable			931				691
Accrued interest			(1,922	)			860
Deferred revenue			3,682				475
Accrued property taxes			260				815
Other current liabilities			254				(217	)
Other, net			258				203
Net cash provided by operating activities			33,100				30,738
Cash flows from investing activities
Acquisition of pipeline and terminal assets			—				(127,791	)
Additions to properties and equipment			(6,941	)			(2,394	)
Net cash used for investing activities			(6,941	)			(130,185	)
Cash flows from financing activities
Proceeds from issuance of senior notes, net of discount			—				181,238
Proceeds from issuance of common units, net of underwriter discount			—				45,100
Distributions to partners			(32,350	)			(25,035	)
Excess purchase price over contributed basis of intermediate pipelines			—				(71,850	)
Borrowings (payback) under revolving credit agreement			—				(25,000	)
Purchase of units for restricted grants			(634	)			(635	)
Cash contribution from general partner			—				612
Deferred debt issuance costs			—				(1,208	)
Cash distributions to minority interest			(1,350	)			(2,010	)
Costs of issuing common units			—				(345	)
Net cash provided by (used for) financing activities			(34,334	)			100,867
Cash and cash equivalents Increase/(decrease) for period			(8,175	)			1,420
Beginning of period			20,583				19,104
End of period		$	12,408			$	20,524

See accompanying notes.

Holly Energy Partners, L.P.

										Class B
		Common				Subordinated				Subordinated				General Partner
		Units				Units				Units				Interest				Total
		(In thousands)
Balance December 31, 2005		$	184,650			$	(63,235	)		$	24,388			$	(93,743	)		$	52,060
Distributions			(15,686	)			(13,440	)			(1,800	)			(1,424	)			(32,350	)
Purchase of units for restricted grants			(634	)			—				—				—				(634	)
Amortization of restricted and performance units			646				—				—				—				646
Net income			8,496				7,279				975				1,134				17,884
Balance September 30, 2006		$	177,472			$	(69,396	)		$	23,563			$	(94,033	)		$	37,606

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 45% owned by Holly Corporation (“Holly”). HEP commenced operations July 13, 2004 upon the completion of its initial public offering. In this document, the words “we”, “our”, “ours” and “us” refer to HEP unless the context otherwise indicates.

We operate in one business segment — the operation of petroleum pipelines 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”). In July 2005, we acquired the two parallel intermediate feedstock pipelines, which connect the New Mexico refining facilities. 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. In conjunction with Holly’s operation of the Navajo Refinery, we operate refined product pipelines as part of the product distribution network of the Navajo Refinery. Our terminal operations serving the Navajo Refinery include a truck rack at the Navajo 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 a truck rack at the Woods Cross Refinery, a refined product terminal in Spokane, Washington and a 50% non-operating interest in product terminals in Boise and Burley, Idaho.

In February 2005, we acquired from Alon USA, Inc. and several of its wholly-owned subsidiaries (collectively, “Alon”) four refined products pipelines, an associated tank farm and two refined products terminals. These pipelines and terminals are located primarily in Texas and transport and terminal light refined products for Alon’s refinery in Big Spring, Texas.

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

The consolidated financial statements for the three and nine months ended September 30, 2006 and 2005 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 are, in the opinion of management, 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, 2005. Results of operations for the three and nine months ended September 30, 2006 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2006. Certain reclassifications have been made to prior reported amounts to conform to current classifications.

Note 2: Acquisitions

Alon Transaction

On February 28, 2005, we acquired from Alon four refined products pipelines, an associated tank farm and two refined products terminals. These pipelines and terminals are located primarily in Texas and transport and terminal light refined products for Alon’s refinery in Big Spring, Texas.

The total consideration paid for these pipeline and terminal assets was $120 million in cash and 937,500 of our Class B subordinated units which, subject to certain conditions, will convert into an equal number of common units on February 28, 2010. We financed the Alon transaction with a portion of the proceeds of our private offering of $150 million principal amount of 6.25% senior notes due 2015 (see Note 5 for further information on the senior notes). In connection with the Alon transaction, we entered into a 15-year pipelines and terminals agreement with Alon (the “Alon PTA”). Under this agreement, Alon agreed to transport on the pipelines and throughput through the terminals a volume of refined products that would result in minimum revenue levels each year that will change annually based on changes in the producer price index (“PPI”), but will not decrease below the initial $20.2 million annual amount. The total commitment for 2006, including the effect of the March 1, 2006 PPI adjustment, is $20.5 million. The agreed upon tariffs will increase or decrease each year at a rate equal to the percentage change in the PPI, but not below the initial tariffs. Alon’s minimum volume commitment was calculated based on 90% of Alon’s then recent usage of these pipelines and terminals taking into account an expansion of Alon’s Big Spring Refinery completed in February 2005. At revenue levels above 105% of the base revenue amount, as adjusted each year for changes in the PPI, Alon will receive an annual 50% discount on incremental revenues. Alon’s obligations under the Alon PTA may be reduced or suspended under certain circumstances. We granted Alon a second mortgage on the pipelines and terminals acquired from Alon to secure certain of Alon’s rights under the Alon PTA. Alon has a right of first refusal to purchase the pipelines and terminals if we decide to sell them in the future. Additionally, we entered into an environmental agreement with Alon with respect to pre-closing environmental costs and liabilities relating to the pipelines and terminals acquired from Alon, whereby Alon will indemnify us subject to a $100,000 deductible and a $20 million maximum liability cap.

The consideration for the Alon pipeline and terminal assets was allocated to the individual assets acquired based on their estimated fair values. The allocation of the consideration is based on an independent appraisal. The aggregate consideration amounted to $146.7 million, which consisted of $24.7 million fair value of our Class B subordinated units, $120 million in cash and $2.0 million of transaction costs. In accounting for this acquisition, we recorded pipeline and terminal assets of $86.7 million and an intangible asset of $60.0 million, representing the allocated value of the 15-year Alon PTA. This intangible asset is included in “Transportation agreements, net” in our consolidated balance sheets.

Holly Intermediate Pipelines Transaction

On July 6, 2005, we entered into a definitive purchase agreement (the “Purchase Agreement”) with Holly to acquire Holly’s two parallel intermediate feedstock pipelines (the “Intermediate Pipelines”) which connect its Lovington, New Mexico and Artesia, New Mexico refining facilities. On July 8, 2005, we closed on the acquisition for $81.5 million, which consisted of $77.7 million in cash, 70,000 common units of HEP and a capital account credit of $1.0 million to maintain Holly’s existing general partner interest in the Partnership. We financed the cash portion of the consideration for the Intermediate Pipelines with the proceeds raised from (a) the private sale of 1,100,000 of our common units for $45.1 million to a limited number of institutional investors which closed simultaneously with the acquisition and (b) an additional $35.0 million in principal amount of our 6.25% senior notes due 2015. This acquisition was made pursuant to an option to purchase these pipelines granted by Holly to us at the time of our initial public offering in July 2004.

In connection with this transaction, we entered into a 15-year pipelines agreement with Holly (the “Holly IPA”), which expires in 2020. Under this agreement, Holly agreed to transport volumes of intermediate products on the Intermediate Pipelines that, at the agreed tariff rates, will result in minimum funds to us of $11.8 million per calendar year. The minimum commitment and the full base tariff will be adjusted each year at a rate equal to the percentage change in the PPI, but the minimum commitment will not decrease

as a result of a decrease in the PPI. Holly’s minimum revenue commitment applies only to the Intermediate Pipelines, and Holly will not be able to spread its minimum revenue commitment among pipeline assets HEP already owns or subsequently acquires. If Holly fails to meet its minimum revenue commitment 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 may be applied as a credit in the following four quarters after Holly’s minimum obligations are met. The Holly IPA may be extended by the mutual agreement of the parties.

We agreed to expend up to $3.5 million to expand the capacity of the Intermediate Pipelines to meet the needs of Holly’s expansion of their Navajo Refinery, of which we had spent $2.8 million as of September 30, 2006. If new laws or regulations are enacted that require us to make substantial and unanticipated capital expenditures with regard to the Intermediate Pipelines, we have the right to amend the tariff rates to recover our costs of complying with these new laws or regulations (including a reasonable rate of return). Under certain circumstances, either party may temporarily suspend its obligations under the Holly IPA. We granted Holly a second mortgage on the Intermediate Pipelines to secure certain of Holly’s rights under the Holly IPA. Holly agreed to provide $2.5 million of additional indemnification above that previously provided for environmental noncompliance and remediation liabilities occurring or existing before the closing date of the Purchase Agreement, bringing the total indemnification provided to us from Holly to $17.5 million. Of this total, indemnification above $15 million relates solely to the Intermediate Pipelines.

As this transaction was among entities under common control, we recorded the acquired assets at Holly’s historic book value of $6.8 million. The $71.9 million excess of the purchase price over the historic book value is recorded as a reduction to partners’ equity for financial accounting purposes.

Note 3: Properties and Equipment

		September 30,				December 31,
		2006				2005
		(In thousands)
Pipelines and terminals		$	187,738			$	184,464
Land and right of way			22,445				22,163
Other			6,312				5,728
Construction in progress			5,905				2,792
			222,400				215,147
Less accumulated depreciation			61,506				52,849
		$	160,894			$	162,298

During the three and nine months ended September 30, 2006 and 2005, we did not capitalize any interest related to major construction projects.

Note 4: Transportation Agreements

The costs of two transportation agreements are recorded on our consolidated balance sheets at September 30, 2006:

•		Costs incurred by Rio Grande in constructing certain pipeline and terminal facilities located in Mexico, which were then contributed to an affiliate of Pemex, the national oil company of Mexico. In exchange, Rio Grande received a 10-year transportation agreement from BP plc expiring in 2007. This asset is being amortized over the 10-year term of the agreement.
•		A portion of the total purchase price of the Alon assets was allocated to the transportation agreement asset based on the fair value appraisal provided by an independent firm. 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 carrying amounts of the transportation agreements are as follows:

		September 30,				December 31,
		2006				2005
		(In thousands)
Rio Grande transportation agreement		$	20,836			$	20,836
Alon transportation agreement			59,933				59,933
			80,769				80,769
Less accumulated amortization			22,927				19,866
		$	57,842			$	60,903

Note 5: Debt

Credit Agreement

In conjunction with our initial public offering on July 13, 2004, we entered into a four-year, $100 million senior secured revolving credit agreement (the “Credit Agreement”). Union Bank of California, N.A. is one of the lenders and serves as administrative agent under this agreement. During 2005, amendments were made to the Credit Agreement to allow for the closing of the Alon transaction and the related senior notes offering, the closing of the Holly Intermediate Pipelines transaction and to amend certain of the restrictive covenants. As of September 30, 2006 and December 31, 2005, we had no amounts outstanding under the Credit Agreement.

The Credit Agreement is available to fund capital expenditures, acquisitions, and working capital and for general partnership purposes. Advances under the Credit Agreement that are designated for working capital are short-term liabilities. Other advances under the Credit Agreement are classified as long-term liabilities. In addition, the Credit Agreement is available to fund letters of credit up to a $50 million sub-limit. Up to $5 million is available to fund distributions to unitholders.

We have the right to request an increase in the maximum amount of the Credit Agreement, up to $175 million. Such request will become effective if (a) certain conditions specified in the Credit Agreement are met and (b) existing lenders under the Credit Agreement or other financial institutions reasonably acceptable to the administrative agent commit to lend such increased amounts under the agreement.

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

We may prepay all loans at any time without penalty. We are required to reduce all working capital borrowings under the Credit Agreement to zero for a period of at least 15 consecutive days once each twelve-month period prior to the maturity date of the agreement.

Indebtedness under the Credit Agreement bears interest, at our option, at either (a) the base rate as announced by the administrative agent plus an applicable margin (ranging from 0.25% to 1.00%) or (b) at a rate equal to the London Interbank Offered Rate (“LIBOR”) plus an applicable margin (ranging from 1.50% to 2.25%). In each case, the applicable margin is based upon the ratio of our funded debt (as defined in the agreement) to EBITDA (earnings before interest, taxes, depreciation and amortization, as defined in the Credit Agreement). We incur a commitment fee on the unused portion of the Credit Agreement at a rate of 0.375% or 0.500% based upon the ratio of our funded debt to EBITDA for the four most recently completed fiscal quarters. At September 30, 2006, we are subject to the 0.500% rate on the $100 million of the unused commitment on the Credit Agreement. The agreement matures in July 2008. At that time, the agreement will terminate and all outstanding amounts thereunder will be due and payable.

The Credit Agreement imposes certain requirements, including: a prohibition against distribution to unitholders if, before or after the distribution, a potential default or an event of default as defined in the agreement would occur; limitations on our ability to incur debt, make loans, acquire other companies,

change the nature of our business, enter a merger or consolidation, or sell assets; and covenants that require maintenance of EBITDA to interest expense ratio and debt to EBITDA ratio. If an event of default exists under the agreement, the lenders will be able to accelerate the maturity of the debt and exercise other rights and remedies.

Senior Notes Due 2015

We financed the $120 million cash portion of the Alon transaction through our private offering on February 28, 2005 of $150 million principal amount of 6.25% senior notes due 2015 (“Senior Notes”). We used the balance to repay $30 million of then outstanding indebtedness under our Credit Agreement, including $5 million drawn shortly before the closing of the Alon transaction.

We financed a portion of the cash consideration for the Intermediate Pipelines transaction with the private offering in June 2005 of an additional $35.0 million in principal amount of the Senior Notes.

On July 28, 2005, we filed a registration statement to allow the holders of the Senior Notes to exchange the Senior Notes for exchange notes registered with the SEC with substantially identical terms, which exchange was completed in October 2005.

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

The $185 million principal amount of Senior Notes is recorded at $180.5 million on our consolidated balance sheet at September 30, 2006. The difference of $4.5 million is due to $3.2 million of unamortized discount and $1.3 million relating to the fair value of the interest rate swap contract discussed below.

Interest Rate Risk Management

We have entered into an interest rate swap contract to effectively convert the interest expense associated with $60 million of our 6.25% Senior Notes from a fixed rate to variable rates. The interest rate on the $60 million notional amount is equal to three month LIBOR plus an applicable margin of 1.1575%, which equaled an effective interest rate of 6.14% on $60 million of the debt during the nine months ended September 30, 2006. The maturity of the swap contract is March 1, 2015, matching the maturity of the Senior Notes.

This interest rate swap has been designated as a fair value hedge as defined by SFAS No. 133. Our interest rate swap meets the conditions required to assume no ineffectiveness under SFAS No. 133 and, therefore, we have used the “shortcut” method of accounting prescribed for fair value hedges by SFAS No. 133. Accordingly, we adjust the carrying value of the swap to its fair value each quarter, with an offsetting entry to adjust the carrying value of the debt securities whose fair value is being hedged. We record interest expense equal to the variable rate payments under the swaps.

The fair value of our interest rate swap of $1.3 million and $0.8 million is included in “Other long-term liabilities” in our consolidated balance sheets at September 30, 2006 and December 31, 2005, respectively. The offsetting entry to adjust the carrying value of the debt securities whose fair value is being hedged is recognized as a reduction of “Long-term debt” on our consolidated balance sheets at September 30, 2006 and December 31, 2005.

Other Debt Information

		Nine Months Ended
		September 30,
		2006				2005
		(In thousands)
Interest on outstanding debt:
Senior Notes, net of interest rate swap		$	8,622			$	5,502
Credit Agreement			—				164
Amortization of discount and deferred issuance costs			726				543
Commitment fees			376				312
Net interest expense		$	9,724			$	6,521
Cash paid for interest		$	14,521			$	6,761

We estimate that the fair value of our Senior Notes was $171.1 million at September 30, 2006, based on a determination by a third-party investment firm.

Note 6: Commitments and Contingencies

In June 2006, we exercised the first of three 10-year renewal options on our lease agreement for the refined products pipeline between White Lakes Junction and Kutz Station in New Mexico. This extension will become effective July 2007, immediately upon expiration of the original lease term. The minimum annual commitments under this new operating lease extension are as follows (excluding the second and third 10-year lease extensions, which are likely to be exercised):

Year Ending
December 31,		$000’s
2007		$	3,041
2008			6,082
2009			6,082
2010			6,082
Thereafter			39,529
Total		$	60,816

Note 7: Earnings per Unit

Basic income per limited partner unit is calculated as net income available to common unitholders divided by the weighted average number of limited partner units outstanding during the period. Diluted income per limited partner unit gives effect to all potentially dilutive common units during the period, including variable performance units, using the treasury stock method. The issuance of potentially dilutive performance units was excluded from the calculation of diluted income per limited partner unit, as the effect would have been anti-dilutive.

Note 8: 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 a three-year omnibus agreement we entered into with Holly in July 2004 (the “Omnibus Agreement”).

These employees participate in the retirement and benefit plans of Holly. Our share of retirement and benefits costs was $0.4 million and $0.3 million for the three months ended September 30, 2006 and 2005, respectively, and $0.9 million and $0.7 million for the nine months ended September 30, 2006 and 2005, respectively.

We have adopted a Long-Term Incentive Plan for employees, consultants and 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 September 30, 2006, we had two types of equity-based compensation, which are described below. The compensation cost charged against income for these plans was $0.2 million and $0.1 million for the three months ended September 30, 2006 and 2005, respectively, and $0.6 million and $0.2 million for the nine months ended September 30, 2006 and 2005, respectively. It is currently our policy to purchase units in the open market instead of issuing new units for settlement of restricted unit grants. At September 30, 2006, 350,000 units were authorized to be granted under the equity-based compensation plans, of which 291,419 had not yet been granted.

We elected early adoption of SFAS 123 (revised) on July 1, 2005, based on modified prospective application. The effect of this change in accounting principle was immaterial to our financial condition and results of operations.

Restricted Units

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

A summary of restricted unit activity as of September 30, 2006, and changes during the nine months ended September 30, 2006, is presented below:

										Weighted-
						Weighted-				Average				Aggregate
						Average				Remaining				Intrinsic
						Grant-Date				Contractual				Value
Restricted Units		Grants				Fair Value				Term				($000)
Outstanding January 1, 2006 (not vested)			20,926			$	40.98
Granted			15,871			$	39.19
Forfeited			(200	)		$	40.08
Vesting and transfer of full ownership to recipients			—				—
Outstanding at September 30, 2006 (not vested)			36,597			$	40.21			1.5 years				$	1,382

There were no restricted units vested or transferred to recipients during the nine months ended September 30, 2006. As of September 30, 2006, there was $0.8 million of total unrecognized compensation costs related to nonvested restricted unit grants. That cost is expected to be recognized over a weighted-average period of 1.5 years.

In September 2006, we paid $0.1 million for the purchase of 3,210 of our common units in the open market for the recipients of the August 2006 restricted units grant.

Performance Units

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

The initial performance unit grant was payable in cash. As of February 10, 2006, we amended the existing performance unit agreements to provide payment of these awards in HEP common units rather than payment in cash. The performance criteria were not amended. Until this conversion to equity payment, the fair value of each performance unit award was revalued quarterly based on our valuation model and the corresponding expense was amortized over the vesting periods. Upon conversion to equity payment, we established the fair value of each performance unit and are now amortizing that amount over the vesting period.

In addition to revising the existing performance unit agreements, we granted 12,501 performance units to certain officers in February 2006. These units will vest over a three-year performance period ending December 31, 2008, 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.

The fair value of the performance units is based on an expected cash flow approach at the grant date. The analysis utilizes the unit price, distribution yield, historical total returns as of the measurement date, expected total returns based on a capital asset pricing model methodology, standard deviation of historical returns, and comparison of expected total returns with the peer group. The expected total return and historical standard deviation is applied to a lognormal expected return distribution in a Monte Carlo simulation model to identify the expected range of potential returns and probabilities of expected returns. The range of inputs reflects changes in the remaining life of the performance units and changes in market conditions between measurement dates. The inputs affecting the range of expected total returns for HEP and the peer group are based on a capital asset pricing model utilizing information available at each measurement date.

Data Elements Used in Analysis
Closing price of HEP common units February 10, 2006		$	39.55
Latest quarterly distribution per limited unit		$	0.64
Risk-free rate			4.86	%

The monthly standard deviation of returns is based on the standard deviation of historical return information. The range of expected returns and standard deviation is presented below:

						Standard
		Expected Return on				Deviation
Company		Equity				(Monthly)
HEP			14.0	%			7.6	%
Peer group		9.8% to 11.0%				3.8% to 4.9%

A summary of performance units activity as of September 30, 2006, and changes during the nine months ended September 30, 2006 is presented below:

		Payable				Payable
Performance Units		In Cash				In Units
Outstanding at January 1, 2006 (not vested)			1,515				—
Conversion to unit payment			(1,515	)			1,515
Vesting and payment of units to recipients			—				—
Granted			—				12,501
Forfeited			—				—
Outstanding at September 30, 2006 (not vested)			—				14,016

There were no payments for performance units vesting during the nine months ended September 30, 2006. Based on the weighted average fair value at September 30, 2006 of $48.93, there was $0.4 million of total unrecognized compensation cost related to nonvested performance units. That cost is expected to be recognized over a weighted-average period of 1.2 years.

Note 9: Significant Customers

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

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2006				2005				2006				2005
Holly			62	%			58	%			59	%			55	%
BP plc			6	%			8	%			9	%			11	%
Alon			29	%			31	%			30	%			30	%

Note 10: Related Party Transactions

Holly

We have related party transactions with Holly for pipeline and terminal revenues, certain employee costs, insurance costs, and administrative costs under the 15-year pipelines and terminals agreement expiring in 2019 that we entered with Holly in July 2004 (the “Holly PTA”), the Holly IPA and the Omnibus Agreement.

•		Pipeline and terminal revenues received from Holly were $14.3 million and $12.5 million for the three months ended September 30, 2006 and 2005, respectively, and $37.3 million and $31.9 million for the nine months ended September 30, 2006 and 2005, respectively. These amounts include the revenues received under the Holly PTA and Holly IPA.
•		Holly charged general and administrative services under the Omnibus Agreement of $0.5 million in the three months ended September 30, 2006 and 2005, and $1.5 million for the nine months ended September 30, 2006 and 2005.
•		We reimbursed Holly for costs of employees supporting our operations of $2.0 million and $1.8 million for the three months ended September 30, 2006 and 2005, respectively, and $5.7 million and $4.8 million for the nine months ended September 30, 2006 and 2005, respectively.
•		Holly reimbursed $42,000 and $47,000 to us for certain costs paid on their behalf in the three months ended September 30, 2006 and 2005, respectively. Holly reimbursed $138,000 and $161,000 in the nine months ended September 30, 2006 and 2005, respectively.
•		In the three months ended September 30, 2006 and 2005, we distributed $5.2 million and $4.3 million, respectively, to Holly as regular distributions on its subordinated units, common units and general partner interest. We distributed $15.0 million and $12.0 million to Holly in the nine months ended September 30, 2006 and 2005, respectively.
•		Our net accounts receivable from Holly were $2.3 million and $3.6 million at September 30, 2006 and December 31, 2005, respectively.
•		As described under “Holly Intermediate Pipelines Transaction” in Note 2 above, under the Holly IPA, Holly agreed to transport volumes of products on the Intermediate Pipelines that will result in minimum funds to us of $11.8 million per year initially, adjusted annually for increases in PPI. If Holly fails to meet its minimum revenue commitment in any quarter, Holly is required to pay cash for the shortfall. A shortfall payment may be applied as a credit in the following four quarters after Holly’s minimum obligation for that quarter is met.
		Holly has failed to meet its minimum revenue commitment for each of the first five quarters of the Holly IPA. We have charged Holly $3.2 million for these shortfalls to date, $0.6 million and $0.5 million of which are included in affiliate accounts receivable at September 30, 2006 and December 31, 2005, respectively.

We recognized the $0.5 million shortfall for the quarter ended September 30, 2005 as additional revenues in the consolidated statements of income for the three and nine months ended September 30, 2006, as Holly did not exceed its minimum revenue obligation in any of the subsequent four quarters. Deferred revenue on the consolidated balance sheets at September 30, 2006 and December 31, 2005 includes $2.7 million and $1.0 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 $2.7 million deferred at September 30, 2006.

BP plc

We have a 70% ownership interest in Rio Grande. Due to the ownership interest and resulting consolidation, the other partner of Rio Grande – BP plc (“BP”) — is a related party to us.

•		BP is the sole customer of Rio Grande, and we recorded revenues of $1.4 million and $1.7 million for the three months ended September 30, 2006 and 2005, and $5.4 million and $6.3 million for the nine months ended September 30, 2006 and 2005, respectively.
•		Rio Grande paid distributions to BP of $0.2 million and $0.4 million for the three months ended September 30, 2006 and 2005, and $1.4 million and $2.0 million for the nine months ended September 30, 2006 and 2005, respectively.
•		Included in our accounts receivable – trade at September 30, 2006 and December 31, 2005 were $0.3 million and $0.5 million, respectively, which represented the receivable balance of Rio Grande from BP.

Alon

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

•		We recognized $6.6 million and $6.7 million of revenues for pipeline transportation and terminalling services under the Alon PTA and under a pipeline capacity lease in the three months ended September 30, 2006 and 2005, respectively. We recognized $19.0 million and $16.1 million in the nine months ended September 30, 2006 and the period from February 28 to September 30, 2005, respectively.
•		We paid $0.6 million and $0.5 million to Alon for distributions on our Class B subordinated units in the three months ended September 30, 2006 and 2005, respectively. We paid $1.8 million and $1.1 million in the nine months ended September 30, 2006 and the period from February 28 to September 30, 2005, respectively.
•		Our net accounts receivable from Alon were $3.6 million at September 30, 2006 and $2.4 million at December 31, 2005.
•		“Deferred revenue” includes $2.0 million of minimum revenue commitments under the Alon PTA at September 30, 2006.

Note 11: Partners’ Equity and Cash Distributions

Issuances of units

Upon the closing of our initial public offering on July 13, 2004, Holly received 7,000,000 subordinated units, which constituted 49% ownership of us at that time, and a 2% general partner interest. During the subordination period, the common units have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.50 per quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. The purpose of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units. The subordination period will extend until the first day of any quarter beginning after June 30, 2009 that each of the following tests are met: distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date; the “adjusted operating surplus” (as defined in the partnership agreement) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units during those periods on a fully diluted basis and the related distribution on the 2% general partner interest during those periods; and there are no arrearages in payment of the minimum quarterly distribution on the common units. If the unitholders remove the general partner without cause, the subordination period may end before June 30, 2009.

The Holly subordinated units may convert to common units on a one-for-one basis when certain conditions are met. The partnership agreement sets forth the calculation to be used to determine the amount and priority of cash distributions that the common unitholders, subordinated unitholders and general partner will receive.

As partial consideration in the Alon transaction in the first quarter of 2005, we issued 937,500 of our Class B subordinated units at a fair value of $24.7 million. Additionally, our general partner contributed $0.6 million as an additional capital contribution to maintain its 2% general partner interest.

We financed a portion of the cash consideration paid for the Intermediate Pipelines with $45.1 million of proceeds raised from the private sale of 1,100,000 of our common units to a limited number of institutional investors which closed on July 8, 2005. On September 2, 2005, we filed a registration statement with the SEC using a “shelf” registration process which allows the institutional investors to freely transfer their units. Additionally under this shelf process, we may offer from time to time up to $800 million of our securities, through one or more prospectus supplements that would describe, among other things, the specific amounts, prices and terms of any securities offered and how the proceeds would be used. Any proceeds from the sale of securities would be used for general business purposes, which may include, among other things, funding acquisitions of assets or businesses, working capital, capital expenditures, investments in subsidiaries, the retirement of existing debt and/or the repurchase of common units or other securities.

In connection with the Intermediate Pipelines transaction, we issued 70,000 common units to Holly. We also received a portion of the Intermediate Pipelines assets with $1.0 million book value as a capital contribution from HEP Logistics Holdings, L.P. in order to maintain its 2% general partner interest.

As a result of these transactions, Holly’s total ownership interest was reduced from 51% at the time of our initial public offering to 45% in July 2005 following the Intermediate Pipelines transaction.

Allocations of Net Income

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

Cash Distributions

In July 2005, our cash payment to Holly in excess of the basis of the assets received in the acquisition of the Intermediate Pipelines was recorded as a distribution to our general partner in the amount of $71.9 million. See Note 2 for further discussion of this transaction.

We intend to consider regular cash distributions to unitholders on a quarterly basis, although there is no assurance as to the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors. Our Credit Agreement prohibits us from making cash distributions if any potential default or event of default, as defined in the Credit Agreement, occurs or would result from the cash distribution.

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

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

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

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

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

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2006				2005				2006				2005
		(In thousands, except per unit data)
General partner interest		$	215			$	189			$	631			$	499
General partner incentive distribution			340				63				793				63
Total general partner distribution			555				252				1,424				562
Limited partner distribution			10,550				9,256				30,926				24,473
Total regular quarterly cash distribution		$	11,105			$	9,508			$	32,350			$	25,035
Cash distribution per unit applicable to limited partners		$	0.655			$	0.575			$	1.920			$	1.625

On October 23, 2006, we announced a cash distribution for the third quarter of 2006 of $0.665 per unit. The distribution is payable on all common, subordinated, and general partner units and will be paid November 14, 2006 to all unitholders of record on November 3, 2006. The aggregate amount of the distribution will be $11.3 million, including $0.4 million paid to the general partner as an incentive distribution.

Note 12: 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 Pipeline Company (“Non-Guarantor”), in which we have a 70% ownership interest, is the only subsidiary which has not guaranteed these obligations.

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

Condensed Consolidating Balance Sheet

						Guarantor				Non-
September 30, 2006		Parent				Subsidiaries				Guarantor				Eliminations				Consolidated
		(In thousands)
ASSETS
Current assets:
Cash and cash equivalents		$	2			$	10,979			$	1,427			$	—			$	12,408
Accounts receivable			—				6,592				353				—				6,945
Intercompany accounts receivable (payable)			(66,150	)			66,348				(198	)			—				—
Prepaid and other current assets			311				1,333				—				—				1,644
Total current assets			(65,837	)			85,252				1,582				—				20,997
Properties and equipment, net			—				127,442				33,452				—				160,894
Investment in subsidiaries			285,470				24,823				—				(310,293	)			—
Transportation agreements, net			—				56,771				1,071				—				57,842
Other assets			1,491				1,277				—				—				2,768
Total assets		$	221,124			$	295,565			$	36,105			$	(310,293	)		$	242,501
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable		$	—			$	3,681			$	270			$	—			$	3,951
Accrued interest			970				—				—				—				970
Deferred revenue			—				4,695				—				—				4,695
Accrued property taxes			—				1,097				176				—				1,273
Other current liabilities			747				622				198				—				1,567
Total current liabilities			1,717				10,095				644				—				12,456
Long-term debt			180,466				—				—				—				180,466
Other long-term liabilities			1,335				—				—				—				1,335
Minority interest			—				—				—				10,638				10,638
Partners’ equity			37,606				285,470				35,461				(320,931	)			37,606
Total liabilities and partners’ equity		$	221,124			$	295,565			$	36,105			$	(310,293	)		$	242,501

 

Condensed Consolidating Balance Sheet

						Guarantor				Non-
December 31, 2005		Parent				Subsidiaries				Guarantor				Eliminations				Consolidated
		(In thousands)
ASSETS
Current assets:
Cash and cash equivalents		$	2			$	17,770			$	2,811			$	—			$	20,583
Accounts receivable			—				6,206				515				—				6,721
Intercompany accounts receivable (payable)			(21,182	)			21,458				(276	)			—				—
Prepaid and other current assets			232				1,169				—				—				1,401
Total current assets			(20,948	)			46,603				3,050				—				28,705
Properties and equipment, net			—				128,077				34,221				—				162,298
Investment in subsidiaries			256,416				27,423				—				(283,839	)			—
Transportation agreements, net			—				58,269				2,634				—				60,903
Other assets			1,594				1,275				—				—				2,869
Total assets		$	237,062			$	261,647			$	39,905			$	(283,839	)		$	254,775
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable		$	—			$	2,666			$	354			$	—			$	3,020
Accrued interest			2,892				—				—				—				2,892
Deferred revenue			—				1,013				—				—				1,013
Accrued property taxes			—				837				176				—				1,013
Other current liabilities			594				520				199				—				1,313
Total current liabilities			3,486				5,036				729				—				9,251
Long-term debt			180,737				—				—				—				180,737
Other long-term liabilities			779				195				—				—				974
Minority interest			—				—				—				11,753				11,753
Partners’ equity			52,060				256,416				39,176				(295,592	)			52,060
Total liabilities and partners’ equity		$	237,062			$	261,647			$	39,905			$	(283,839	)		$	254,775

Condensed Consolidating Statement of Income

						Guarantor				Non-
Three months ended September 30, 2006		Parent				Subsidiaries				Guarantor				Eliminations				Consolidated
		(In thousands)
Revenues:
Affiliates		$	—			$	14,272			$	—			$	—			$	14,272
Third parties			—				7,526				1,403				(302	)			8,627
			—				21,798				1,403				(302	)			22,899
Operating costs and expenses:
Operations			—				6,697				687				(302	)			7,082
Depreciation and amortization			—				2,981				858				—				3,839
General and administrative			660				516				1				—				1,177
			660				10,194				1,546				(302	)			12,098
Operating income (loss)			(660	)			11,604				(143	)			—				10,801
Equity in earnings of subsidiaries			11,476				(87	)			—				(11,389	)			—
Interest income (expense)			(3,065	)			(41	)			18				—				(3,088	)
Minority interest			—				—				—				38				38
Net income (loss)		$	7,751			$	11,476			$	(125	)		$	(11,351	)		$	7,751

 

Condensed Consolidating Statement of Income

						Guarantor				Non-
Three months ended September 30, 2005		Parent				Subsidiaries				Guarantor				Eliminations				Consolidated
		(In thousands)
Revenues:
Affiliates		$	—			$	12,507			$	—			$	—			$	12,507
Third parties			—				7,627				1,662				(279	)			9,010
			—				20,134				1,662				(279	)			21,517
Operating costs and expenses:
Operations			—				5,969				643				(279	)			6,333
Depreciation and amortization			—				3,080				844				—				3,924
General and administrative			557				517				1				—				1,075
			557				9,566				1,488				(279	)			11,332
Operating income (loss)			(557	)			10,568				174				—				10,185
Equity in earnings of subsidiaries			10,655				130				—				(10,785	)			—
Interest income (expense)			(2,806	)			(43	)			12				—				(2,837	)
Minority interest			—				—				—				(56	)			(56	)
Net income		$	7,292			$	10,655			$	186			$	(10,841	)		$	7,292

Condensed Consolidating Statement of Income

						Guarantor				Non-
Nine months ended September 30, 2006		Parent				Subsidiaries				Guarantor				Eliminations				Consolidated
		(In thousands)
Revenues:
Affiliates		$	—			$	37,338			$	—			$	—			$	37,338
Third parties			—				22,014				5,409				(897	)			26,526
			—				59,352				5,409				(897	)			63,864
Operating costs and expenses:
Operations			—				20,373				2,144				(897	)			21,620
Depreciation and amortization			—				8,864				2,549				—				11,413
General and administrative			2,149				1,537				4				—				3,690
			2,149				30,774				4,697				(897	)			36,723
Operating income (loss)			(2,149	)			28,578				712				—				27,141
Equity in earnings of subsidiaries			29,053				550				—				(29,603	)			—
Interest income (expense)			(9,020	)			(75	)			73				—				(9,022	)
Minority interest			—				—				—				(235	)			(235	)
Net income		$	17,884			$	29,053			$	785			$	(29,838	)		$	17,884

 

Condensed Consolidating Statement of Income

						Guarantor				Non-
Nine months ended September 30, 2005		Parent				Subsidiaries				Guarantor				Eliminations				Consolidated
		(In thousands)
Revenues:
Affiliates		$	—			$	31,878			$	—			$	—			$	31,878
Third parties			—				19,941				6,290				(558	)			25,673
			—				51,819				6,290				(558	)			57,551
Operating costs and expenses:
Operations			—				16,484				2,243				(558	)			18,169
Depreciation and amortization			—				7,603				2,533				—				10,136
General and administrative			1,477				1,549				16				—				3,042
			1,477				25,636				4,792				(558	)			31,347
Operating income (loss)			(1,477	)			26,183				1,498				—				26,204
Equity in earnings of subsidiaries			26,888				1,070				—				(27,958	)			—
Interest income (expense)			(5,752	)			(365	)			30				—				(6,087	)
Minority interest			—				—				—				(458	)			(458	)
Net income		$	19,659			$	26,888			$	1,528			$	(28,416	)		$	19,659