Holly Energy Partners 10Q 2005 Q1 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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


		FOR THE QUARTERLY PERIOD ENDED March 31, 2005


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


		FOR THE TRANSITION PERIOD FROM TO .

Commission File Number1-32225

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

(Address of principal executive offices)

(214) 871-3555

(Registrant’s telephone number, including area code)

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. Yesþ Noo

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).
Yeso Noþ

The number of the registrant’s outstanding common units at April 29, 2005 was 7,000,000.

HOLLY ENERGY PARTNERS, L.P.
INDEX


PART I. FINANCIAL INFORMATION			3

FORWARD-LOOKING STATEMENTS			3
Item 1. Financial Statements (Unaudited, except December 31, 2004 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			15
Item 3. Quantitative and Qualitative Disclosures About Market Risks			29
Item 4. Controls and Procedures			29

PART II. OTHER INFORMATION			30

Item 1. Legal proceedings			30
Item 6. Exhibits			30
SIGNATURES			32
1st Supplemental Indenture
2nd Supplemental Indenture
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

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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 refined petroleum products shipped on our pipelines and/or terminalled in our terminals;

	•	The future performance of the assets acquired from Alon USA, Inc.;

	•	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 acquire pipeline and terminal operations on acceptable terms and to integrate any future acquired operations;

	•	The availability and cost of our financing;

	•	The possibility of inefficiencies or shutdowns of refineries utilizing our pipeline and terminal facilities;

	•	The effects of current and future government regulations and policies;

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

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

	•	General economic conditions; and

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

Cautionary statements identifying important factors that could cause actual results to differ materially from our expectations are set forth in this Form 10-Q, including without limitation in conjunction with the forward-looking statements included in the 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, 2004 in “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” 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.

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Item 1. Financial Statements

Holly Energy Partners, L.P.

Consolidated Balance Sheets


	March 31, 2005			December 31,
	(Unaudited)			2004
	(In thousands, except unit data)
ASSETS
Current assets:
Cash and cash equivalents	$	18,416		$	19,104
Accounts receivable:
Trade		2,406			807
Affiliates		2,590			2,052

		4,996			2,859

Prepaid and other current assets		1,138			570

Total current assets		24,550			22,533

Properties and equipment, net		159,647			74,626
Transportation agreements, net		63,673			4,718
Other assets		2,293			1,881


Total assets	$	250,163		$	103,758


LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	1,639		$	1,716
Accrued liabilities		2,024			1,697

Total current liabilities		3,663			3,413

Commitments and contingencies		—			—
Long-term debt		147,055			25,000
Other long-term liabilities		831			585
Minority interest		12,612			13,232

Partners’ equity:
Common unitholders (7,000,000 units issued and outstanding as of March 31, 2005 and December 31, 2004)		143,851			144,318
Subordinated unitholders (7,000,000 units issued and outstanding as of March 31, 2005 and December 31, 2004)		(59,942	)		(59,470	)
Class B subordinated unitholders (937,500 units issued and outstanding as of March 31, 2005)		24,818			—
General partner equity (2% interest)		(22,725	)		(23,320	)


Total partners’ equity		86,002			61,528


Total liabilities and partners’ equity	$	250,163		$	103,758

See accompanying notes.

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Holly Energy Partners, L.P.

Consolidated Statements of Income
(Unaudited)


	Three Months Ended
	March 31,
	2005			2004
	(In thousands, except per unit data)
Revenues:
Affiliates	$	9,430		$	12,413
Third parties		7,083			6,358

		16,513			18,771


Operating costs and expenses:
Operations		5,388			6,452
Depreciation and amortization		2,363			2,046
General and administrative		977			—

		8,728			8,498


Operating income		7,785			10,273

Other income (expense):
Interest income		88			35
Interest expense		(1,118	)		—

		(1,030	)		35


Income before minority interest		6,755			10,308

Minority interest in Rio Grande Pipeline Company		(429	)		(688	)


Net income		6,326			9,620

Less:
Net income attributable to Predecessor		—			9,620
General partner interest in net income		126			—


Limited partners’ interest in net income	$	6,200		$	—


Net income per limited partner unit - Basic and diluted	$	0.43		$	—


Weighted average limited partners’ units outstanding		14,333			—

See accompanying notes.

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Holly Energy Partners, L.P.

Consolidated Statements of Cash Flows
(Unaudited)


	Three Months Ended March 31,
	2005			2004
	(In thousands)
Cash flows from operating activities
Net income	$	6,326		$	9,620
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		2,363			2,046
Minority interest in Rio Grande Pipeline Company		429			688
Equity based compensation expense		14			—
(Increase) decrease in current assets:
Accounts receivable — trade		(1,599	)		80
Accounts receivable — affiliates		(538	)		(9,928	)
Prepaid and other current assets		(567	)		(26	)
Increase (decrease) in current liabilities:
Accounts payable		(76	)		(1,539	)
Accounts payable — affiliates		—			(590	)
Accrued liabilities		327			(68	)
Other, net		83			—

Net cash provided by operating activities		6,762			283

Cash flows from investing activities
Acquisition of pipeline and terminal assets		(121,280	)		—
Additions to properties and equipment		(446	)		(1,549	)
Cash distribution to minority interest		(1,050	)		(1,050	)

Net cash used for investing activities		(122,776	)		(2,599	)

Cash flows from financing activities
Proceeds from issuance of senior notes, net of underwriter discount		147,375			—
Net decrease in borrowings under revolving credit agreement		(25,000	)		—
Distributions to partners		(7,143	)		—
Additional capital contribution from general partner		612			—
Deferred debt issuance costs		(509	)		—
Other		(9	)		—

Net cash provided by financing activities		115,326			—

Cash and cash equivalents
Decrease for period		(688	)		(2,316	)
Beginning of period		19,104			6,694


End of period	$	18,416		$	4,378

See accompanying notes.

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Holly Energy Partners, L.P.

Consolidated Statement of Partners’ Equity (Deficit)
(Unaudited)


							Class B		General
	Common			Subordinated			Subordinated		Partner
	Units			Units			Units		Interest			Total
							(In thousands)
Balance December 31, 2004	$	144,318		$	(59,470	)	$	—	$	(23,320	)	$	61,528

Issuance of Class B subordinated units		—			—			24,674		—			24,674
Capital contribution		—			—			—		612			612
Distributions		(3,500	)		(3,500	)		—		(143	)		(7,143	)
Amortization of restricted units		14			—			—		—			14
Other		(9	)		—			—		—			(9	)
Net income		3,028			3,028			144		126			6,326


Balance March 31, 2005	$	143,851		$	(59,942	)	$	24,818	$	(22,725	)	$	86,002

See accompanying notes.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 1: Organization, Basis of Presentation, and Principles of Consolidation

Holly Energy Partners, L.P. (“HEP”) together with its consolidated subsidiaries, is a publicly held master limited partnership, currently 47.9% owned by Holly Corporation (“Holly”). HEP commenced operations July 13, 2004. Concurrently with the completion of its initial public offering, Navajo Pipeline Co., L.P. (Predecessor) (“NPL”) and its affiliates, a wholly owned subsidiary of Holly, contributed a substantial portion of its assets to HEP. In this document, the words “we”, “our”, “ours” and “us” refer to HEP and NPL collectively unless the context otherwise indicates. See Note 2 for a further description of these transactions.

NPL constitutes HEP’s predecessor. The transfer of ownership of assets from NPL to HEP represented a reorganization of entities under common control and was recorded at historical cost. Accordingly, our financial statements include the historical results of operations of NPL prior to the transfer to HEP.

We operate in one business segment — the operation of common carrier and proprietary petroleum pipeline and terminal facilities.

The consolidated financial statements include our accounts and those of our subsidiaries. All significant inter-company transactions and balances have been eliminated. In addition, the consolidated financial statements also include financial data, at historical cost, related to the assets owned by Holly and its wholly-owned subsidiaries through July 12, 2004, other than HEP, that were not contributed to us upon completion of our initial public offering, all accounted for as entities under common control. The distributions paid to Holly upon formation of HEP were in excess of the historical cost of the assets contributed.

The consolidated financial statements for the three months ended March 31, 2005 and 2004 included herein have been prepared without audit, pursuant to the rules and regulations of the United States Securities and Exchange Commission (the “SEC”). The consolidated combined statements of income, cash flows and partners’ equity (deficit) include the accounts of NPL through July 12, 2004 and HEP thereafter. 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 2004 Form 10-K. Results of operations for the three months ended March 31, 2005 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2005. Certain reclassifications have been made to prior reported amounts to conform to current classifications.

Recent Accounting Pronouncement

In December 2004, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) 123 (revised), “Share-Based Payment.” This revision prescribes the accounting for a wide range of share-based compensation arrangements, including share options, restricted share plans, performance-based awards, share appreciation rights and employee share purchase plans, and generally requires the fair value of share-based awards to be expensed on the income statement. This standard was to become effective for us for the first interim period beginning after June 15, 2005, however in April 2005, the Securities and Exchange Commission allowed for the delay in the implementation of this standard, with the result that we are now required to adopt this standard for our 2006 year. SFAS 123 (revised) allows for either modified prospective recognition of compensation expense or modified retrospective recognition, which may be back to the original issuance of SFAS 123 or only to interim periods in the year of adoption. We are still evaluating the impact and method of adoption. However, we do not believe the adoption of this standard will have a material effect

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on our financial condition, results of operations or cash flows.

Note 2: Initial Public Offering of HEP

On March 15, 2004, a Registration Statement on Form S-1 was filed with the SEC relating to a proposed underwritten initial public offering of limited partnership interests in HEP. HEP was formed to acquire, own and operate substantially all of the refined product pipeline and terminalling assets that support Holly’s refining and marketing operations in West Texas, New Mexico, Utah and Arizona and a 70% interest in Rio Grande.

On July 7, 2004, we priced 6,100,000 common units for the initial public offering; and on July 8, 2004, our common units began trading on the New York Stock Exchange under the symbol “HEP.” On July 13, 2004, we closed our initial public offering of 7,000,000 common units at a price of $22.25 per unit, which included a 900,000 unit over-allotment option that was exercised by the underwriters. Total proceeds from the sale of the units were $145.5 million, net of $10.3 million underwriting commissions. After the offering, Holly, through a subsidiary, owned a 51% interest in HEP, including the general partner interest. The initial public offering represented the sale of a 49% interest in HEP.

All of our initial assets were contributed by Holly and its subsidiaries in exchange for: a) an aggregate of 7,000,000 subordinated units, representing 49% limited partner interests in HEP, b) incentive distribution rights (as set forth in HEP’s partnership agreement), c) the 2% general partner interest, and d) an aggregate cash distribution of $125.6 million.

The following table presents the assets and liabilities of our predecessor immediately prior to contributing assets to HEP, the assets and liabilities contributed to HEP, and the predecessor’s assets and liabilities that were not contributed to HEP:


	Navajo Pipeline		Contributed to
	Co., L.P.		Holly Energy
	(Predecessor)		Partners, L.P.		Not
	7/12/04		7/13/04		Contributed
	(In thousands)
Cash	$	2,268	$	2,268	$	—
Accounts receivable — trade		850		800		50
Accounts receivable — affiliates		51,934		—		51,934
Prepaid and other current assets		292		173		119
Properties and equipment, net		95,337		76,605		18,732
Transportation agreement, net		5,692		5,692		—

Total assets		156,373		85,538		70,835


Accounts payable — trade		1,452		339		1,113
Accounts payable — affiliates		18,819		—		18,819
Accrued liabilities		1,018		534		484
Short-term debt		30,082		30,082		—
Non-current liabilities		1,775		1,138		637
Minority interest		13,263		13,263		—

Total liabilities		66,409		45,356		21,053

Net Assets	$	89,964	$	40,182	$	49,782

We used the proceeds of the public offering and $25 million drawn under our credit facility agreement to: establish $9.9 million working capital for HEP, distribute $125.6 million to Holly, repay $30.1 million of short-term debt to Holly, pay $13.8 million underwriting commissions and other offering costs, and pay $1.4 million of deferred debt issuance costs related to the credit facility.

In connection with the offering, we entered into a 15-year pipelines and terminals agreement with Holly and several of its subsidiaries (the “Holly PTA”) under which they agreed generally to transport or terminal volumes on certain of our initial facilities that will result in revenues to HEP that will equal or exceed a

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specified minimum revenue amount annually (which is initially $35.4 million and will adjust upward based on the producer price index) over the term of the agreement.

We also entered into an omnibus agreement with Holly and certain of its subsidiaries that became effective July 13, 2004 (the “Omnibus Agreement”) and determines the services that Holly will provide to us. Under the Omnibus Agreement, Holly will charge us $2.0 million annually for general and administrative services that it provides, including but not limited to: executive, finance, legal, information technology and administrative services.

Note 3: Acquisition

On February 28, 2005, we closed on a contribution agreement with Alon USA, Inc. and several of its wholly-owned subsidiaries (collectively, “Alon”) that provided for our acquisition of four refined products pipelines aggregating approximately 500 miles, an associated tank farm and two refined products terminals with aggregate storage capacity of approximately 347,000 barrels. These pipelines and terminals are located primarily in Texas and transport approximately 70% of the light refined products for Alon’s 65,000 bpd capacity 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 in five years. We financed the Alon transaction through our private offering of $150 million principal amount of 6.25% senior notes due 2015. We used the proceeds of the offering to fund the $120 million cash portion of the consideration for the Alon transaction, and used the balance to repay $30 million of outstanding indebtedness under our revolving credit agreement, including $5 million drawn shortly before the closing of the Alon transaction. In connection with the Alon transaction, we entered into a 15-year pipelines and terminals agreement with Alon. Under this agreement, Alon agreed to transport on the pipelines and throughput volumes through the terminals, a volume of refined products that would result in minimum revenues to us of $20.2 million per year in the first year. The agreed upon tariffs at the minimum volume commitment will increase or decrease each year at a rate equal to the percentage change in the producer price index, but not below the initial tariffs. Alon’s minimum volume commitment was calculated based on 90% of Alon’s recent usage of these pipelines and terminals taking into account a 5,000 bpd expansion of Alon’s Big Spring Refinery completed in February 2005. At revenue levels above 105% of the base revenue amount, as adjusted for changes in the producer price index, Alon will receive an annual 50% discount on incremental revenues. Alon’s obligations under the pipelines and terminals agreement may be reduced or suspended under certain circumstances. We granted Alon a second mortgage on the pipelines and terminals to secure certain of Alon’s rights under the pipelines and terminals agreement. Alon will have 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, where 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 preliminarily allocated to the individual assets acquired based on their estimated fair values. The final allocation of the consideration is pending an independent appraisal, which is currently expected to be completed by year-end. The aggregate consideration amounted to $146.0 million, which consisted of $24.7 million fair value of our Class B subordinated units, $120 million in cash and $1.3 million of transaction costs. In accounting for this acquisition, we preliminarily recorded pipeline and terminal assets of $86.3 million and an intangible asset of $59.7 million, representing the value of the 15-year pipelines and terminals agreement for transportation.

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Note 4: Properties and Equipment


	March 31,		December 31,
	2005		2004
	(In thousands)
Pipelines and terminals	$	180,359	$	104,095
Land and right of way		14,929		4,865
Other		4,786		4,436
Construction in progress		353		201

		200,427		113,597
Less accumulated depreciation		40,780		38,971

	$	159,647	$	74,626

During the three-month periods ended March 31, 2005 and 2004, we did not capitalize any interest related to major construction projects.

Note 5: Employees, Retirement and Benefit Plans

Employees who provide direct services to us — other than Rio Grande employees — are employed by a Holly subsidiary. Their costs, including salaries, bonuses, payroll taxes, benefits, and other direct costs, are charged to us monthly in accordance with the Omnibus Agreement.

These employees participate in the retirement and benefit plans of Holly. Our share of retirement and benefits costs for the three months ended March 31, 2005 and 2004 was $0.3 million and $0.2 million, respectively.

We have 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. The Long-Term Incentive Plan currently permits the granting of awards covering an aggregate of 350,000 units.

In the last half of 2004, we granted 4,614 restricted common units to our outside directors and 1,875 restricted common units to an executive officer who also serves as a director, under the provisions of our Long-Term Incentive Plan. These common units were purchased in the open market in November 2004 and will vest in August 2007. During the first quarter of 2005, we authorized the grant of 11,735 restricted common units to officers and employees of Holly Logistic Services, L.L.C. These units vest 33.3% in January 2008, 33.3% in January 2009, and the final 33.3% in January 2010 (with later performance-based vesting in the case of one executive). These units will be purchased in the open market during the second quarter of 2005. Ownership in all restricted units is subject to restrictions until the vesting date, but recipients have distribution and voting rights from the date of grant. The cost of these grants is being expensed over their corresponding vesting periods and $26,000 has been expensed in the three months ended March 31, 2005.

During the first quarter of 2005, we authorized 1,515 performance units to employees of Holly Logistic Services, L.L.C. These units will vest and be settled in cash in January 2008, based on our unit price and shareholder return during the period as compared to the return of our peer group of pipeline companies. We are recording the cost of these units over the vesting period and have expensed $2,000 for the three months ended March 31, 2005.

Note 6: 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 a lender and serves as administrative agent under this agreement. Upon closing of our initial public offering, we drew $25 million under the Credit Agreement, which was outstanding at December 31, 2004.

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We amended the Credit Agreement effective February 28, 2005 to allow for the closing of the Alon transaction and the related senior notes offering as well as to amend certain of the restrictive covenants. With a portion of the proceeds from the senior note offering, we repaid $30 million of outstanding indebtedness under the Credit Agreement, including $5 million drawn shortly before the closing of the Alon transaction. As of March 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 unit holders.

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 (i) certain conditions specified in the Credit Agreement are met and (ii) 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 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. The initial $25 million borrowing was not a working capital borrowing under the Credit Agreement and was classified as a long-term liability at December 31, 2004.

Indebtedness under the Credit Agreement bears interest, at our option, at either (i) the base rate as announced by the administrative agent plus an applicable margin (ranging from 0.25% to 1.00%) or (ii) at a rate equal to 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. 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 certain levels of tangible net worth, 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 outstanding indebtedness under our Credit Agreement, including $5 million drawn shortly before the closing of the Alon transaction.

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.

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We have agreed to file a registration statement by July 28, 2005 enabling the holders of the Senior Notes to exchange the Senior Notes for exchange notes registered with the Securities and Exchange Commission with substantially identical terms. The exchange notes will generally be freely transferable but will be a new issue of securities for which there will not initially be a market.

The $150 million principal amount of Senior Notes is recorded at $147.1 on our accompanying consolidated balance sheet at March 31, 2005. The difference of $2.9 million from the principal balance is due to the accounting for the $2.6 million discount paid to the initial purchasers and for $0.3 million relating to 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 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 4.12% on $60 million of the debt during the first quarter of 2005. 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 accounted for them using the “shortcut” method 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 $0.3 million is included in “Other long-term liabilities” in our accompanying consolidated balance sheet at March 31, 2005. 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 accompanying consolidated balance sheet at March��31, 2005.

Other Debt Information

For the three months ended March 31, 2005, interest expense includes: $0.9 million of interest on the outstanding debt, net of the impact of the interest rate swap; $0.1 million of commitment fees on the unused portion of the Credit Agreement; and $0.1 million of amortization of the discount on the Senior Notes and deferred debt issuance costs. We made cash payments of $0.2 million for interest in the three months ended March 31, 2005.

The carrying amounts of our debt recorded on the balance sheet approximate fair value.

Note 7: Commitments and Contingencies

We lease certain facilities, pipelines and equipment under operating leases, most of which contain renewal options. As of March 31, 2005, the minimum future rental commitments under operating leases having non-cancelable lease terms in excess of one year total in the aggregate $12.3 million (not including a 10 year renewal option on a pipeline operating lease that is likely to be exercised), payable $5.5 million annually through June 2007. Rental expense charged to operations was $1.3 million in each of the three-month periods ended March 31, 2005 and 2004.

We are a party to various legal and regulatory proceedings, none of which we believe will have a material adverse impact on our financial condition, results of operations or cash flows.

Note 8: Significant Customers

All revenues are domestic revenues, of which over 90% are currently generated from our three largest customers: Holly and two third-party 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 for

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the three months ended March 31, 2005 and 2004.


	Three Months Ended
	March 31,
	2005			2004
Holly		57	%		66	%
Customer A		18	%		20	%
Customer B		21	%		9	%

Note 9: Related Party Transactions

We have related party transactions with Holly for pipeline and terminal revenues, certain employee costs, insurance costs, and administrative costs under the Holly PTA and Omnibus Agreement (see Note 2). Additionally, we received interest income from Holly during the year ended December 31, 2004, based on common treasury accounts prior to our initial public offering on July 13, 2004. Since that date, we maintain our own treasury accounts separate from Holly.

Pipeline and terminal revenues received from Holly were $9.4 million for the three months ended March 31, 2005 and $12.4 million for the three months ended March 31, 2004. Under the Omnibus Agreement, charges by Holly for the three months ended March 31, 2005 for general and administrative services were $0.5 million, and for reimbursement of employee costs supporting our operations were $1.4 million. In the three months ended March 31, 2005, we distributed $3.6 million to Holly as regular distributions on its subordinated units and general partner interest.

We have a 70% ownership interest in Rio Grande Pipeline Company. Due to the ownership interest and resulting consolidation, the other partner of Rio Grande is a related party to us. The other partner is the sole customer of Rio Grande, and we recorded revenues from the other partner of $3.0 million in the three months ended March 31, 2005 and $3.8 million in three months ended March 31, 2004. Distributions made to the other party were $1.1 million in the three months ended March 31, 2005 and 2004. Included in our accounts receivable — trade at March 31, 2005 and December 31, 2004 was $0.2 million and $0.5 million, respectively, which represented the receivable balance of Rio Grande from the other party.

Because Alon now owns all of our Class B subordinated units, they are considered to be our related party. Subsequent to the issuance of these units, we recognized $2.3 million of revenues for pipeline transportation, terminalling services, and a capacity lease. At March 31, 2005, $2.4 million receivable from them was included in our accounts receivable balance.

Note 10: Partners’ Equity and Cash Distributions

As partial consideration in the Alon transaction, 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. As a result of these transactions, Holly’s ownership interest has been reduced from 51% to 47.9%, including the 2% general partner interest.

In February 2005, we paid a regular cash distribution for the fourth quarter of 2004 of $0.50 on all units, an aggregate amount of $7.1 million. On April 29, 2005, we announced a cash distribution for the first quarter of 2005 of $0.55 per unit. The distribution is payable on all common, subordinated, and general partner units and will be paid May 16, 2005 to all unit holders of record on May 9, 2005. The aggregate amount of the distribution will be $8.4 million.

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HOLLY ENERGY PARTNERS, L.P.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

This Item 2, including but not limited to the sections on “Liquidity and Capital Resources”, contains forward-looking statements. See “Forward-Looking Statements” at the beginning of Part I.

OVERVIEW

Holly Energy Partners, L.P. (“HEP”) is a Delaware limited partnership formed by Holly Corporation (“Holly”) and is the successor to Navajo Pipeline Co., L.P. (Predecessor) (“NPL”). On March 15, 2004, we filed a Registration Statement on Form S-1 with the United States Securities and Exchange Commission (the “SEC”) relating to a proposed underwritten initial public offering of limited partnership units in HEP. HEP was formed to acquire, own and operate substantially all of the refined product pipeline and terminalling assets that support Holly’s refining and marketing operations in west Texas, New Mexico, Utah and Arizona and a 70% interest in Rio Grande Pipeline Company (“Rio Grande”). On July 7, 2004, we priced 6,100,000 common units for the initial public offering and on July 8, 2004, our common units began trading on the New York Stock Exchange under the symbol “HEP.” On July 13, 2004, we closed our initial public offering of 7,000,000 common units at a price of $22.25 per unit, which included a 900,000 unit over-allotment option that was exercised by the underwriters. Total proceeds from the sale of the units were $145.5 million, net of $10.3 million of underwriting commissions. All the initial assets of HEP were contributed by Holly and its subsidiaries in exchange for (A) 7,000,000 subordinated units, representing 49% limited partner interest in HEP, (B) incentive distribution rights (C) the 2% general partner interest and (D) an aggregate cash distribution of $125.6 million.

We operate a system of refined product pipelines in Texas, New Mexico and Oklahoma, and distribution terminals in Texas, New Mexico, Arizona, Utah, Idaho, and Washington. We generate revenues by charging tariffs for transporting refined products through our pipelines and by charging fees for terminalling refined products and other hydrocarbons, and storing and providing other services at our terminals. We do not take ownership of products that we transport or terminal and therefore we are not directly exposed to changes in commodity prices. We serve Holly’s refineries in New Mexico and Utah under a 15-year pipelines and terminals agreement with Holly (“Holly PTA”) expiring 2019.

Historical Results of Operations

In reviewing the historical results of operations that are discussed below, you should be aware of the following:

The historical financial data does not reflect any general and administrative expenses prior to July 13, 2004 as Holly did not historically allocate any of its general and administrative expenses to its pipelines and terminals. Our historical results of operations prior to July 13, 2004 includes revenues and costs associated with crude oil and intermediate product pipelines, which were not contributed to our partnership.

For periods after commencement of operations by HEP on July 13, 2004, our financial statements reflect:

•	net proceeds from our initial public offering which closed on July 13, 2004 (see “Liquidity and Capital Resources” below);

•	the transfer of certain of our predecessor’s operations to HEP, which

	-	includes our predecessor’s refined product pipeline and terminal assets and short-term debt due to Holly (which was repaid upon the closing of our initial public offering), and

	-	excludes our predecessor’s crude oil systems, intermediate product pipelines, accounts receivable from or payable to affiliates, and other miscellaneous assets and liabilities;

•	the execution of the Holly PTA and the recognition of revenues derived therefrom; and

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•	the execution of an omnibus agreement with Holly and several of its subsidiaries (the “Omnibus Agreement”) and the recognition of allocated general and administrative expenses in addition to direct general and administrative expense related to our operation as a publicly owned entity.

Agreements with Holly Corporation

Under the 15-year Holly PTA, Holly pays us fees to transport on our refined product pipelines or throughput in our terminals a volume of refined products that will produce at least $35.4 million of revenue in the first year. This minimum revenue commitment will increase each year at a rate equal to the percentage change in the producer price index, but will not decrease as a result of a decrease in the producer price index. Holly pays the published tariff rates on the pipelines and contractually agreed upon fees at the terminals. The tariffs will adjust annually at a rate equal to the percentage change in the producer price index. The terminal fees will adjust annually based upon an index comprised of comparable fees posted by third parties. Holly’s minimum revenue commitment applies only to the initial assets we acquired from Holly and may not be spread among assets we subsequently acquire. 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.

Furthermore, if new laws or regulations that affect terminals or pipelines generally are enacted that require us to make substantial and unanticipated capital expenditures at the pipelines or terminals, we will have the right to negotiate a monthly surcharge on Holly for the use of the terminals or to file for an increased tariff rate for use of the pipelines to cover Holly’s pro rata portion of the cost of complying with these laws or regulations, after we have made efforts to mitigate their effect. We and Holly will negotiate in good faith to agree on the level of the monthly surcharge or increased tariff rate.

Holly’s obligations under this agreement may be proportionately reduced or suspended if Holly shuts down or materially reconfigures one of its refineries. Holly will be required to give at least twelve months’ advance notice of any long-term shutdown or material reconfiguration. Holly’s obligations may also be temporarily suspended or terminated in certain circumstances.

Historically prior to July 13, 2004, Holly did not allocate any of its general and administrative expenses to its pipeline and terminalling operations. Under the Omnibus Agreement, we have agreed to pay Holly an annual administrative fee, initially in the amount of $2.0 million, for the provision by Holly or its affiliates of various general and administrative services to us for three years following the closing of our initial public offering. The fee may increase in the second and third years by the greater of 5% or the percentage increase in the consumer price index for the applicable year. In addition, our general partner has the right to agree to further increases in connection with expansions of our operations through the acquisition or construction of new assets or businesses. The $2.0 million fee includes expenses incurred by Holly and its affiliates to perform centralized corporate functions, such as executive management, legal, accounting, treasury, information technology and other corporate services, including the administration of employee benefit plans. This fee does not include the salaries of pipeline and terminal personnel or other employees of Holly Logistic Services, L.L.C. or the cost of their employee benefits, such as 401(k), pension and health insurance benefits, which are separately charged to us by Holly. We will also reimburse Holly and its affiliates for direct expenses they incur on our behalf. In addition, we anticipate incurring additional general and administrative costs, including costs relating to operating as a separate publicly held entity, such as costs for preparation of partners’ K-1 tax information, annual and quarterly reports to unitholders, investor relations, directors’ compensation, directors’ and officers’ insurance and registrar and transfer agent fees. Under the Omnibus Agreement, Holly also agreed to indemnify us in an aggregate amount not to exceed $15 million for ten years after the closing of our initial public offering for any environmental noncompliance and remediation liabilities associated with the assets transferred to us and occurring or existing prior to the closing date of our initial public offering.

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Alon Transaction; Senior Note Offering

On February 28, 2005, we closed on a contribution agreement with Alon USA, Inc. and several of its wholly-owned subsidiaries (collectively, “Alon”) that provided for our acquisition of four refined products pipelines, an associated tank farm and two refined products terminals located primarily in Texas. These pipelines and terminals transport approximately 70% of the light refined products for Alon’s 65,000 bpd capacity 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 valued at $24.7 million which, subject to certain conditions, will convert into an equal number of common units in five years. In connection with the Alon transaction, we entered into a 15-year pipelines and terminals agreement with Alon. Please read “Alon Transaction” under “Liquidity and Capital Resources” below for additional information.

We financed the $120 million cash portion of the Alon transaction through our private offering of $150 million principal amount of 6.25% senior notes due 2015. Please read “Senior Notes Due 2015” under “Liquidity and Capital Resources” below for additional information. We used the balance to repay $30 million of outstanding indebtedness under our revolving credit agreement, including $5 million drawn shortly before the closing of the Alon transaction.

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RESULTS OF OPERATIONS (Unaudited)

Income, Distributable Cash Flow and Volumes

The following tables present income, distributable cash flow and volume information for the three month periods ended March 31, 2005 and 2004.


	Three Months Ended
	March 31,
	2005			2004
	(In thousands)
Revenues
Pipelines:
Affiliates	$	7,068		$	6,984
Third parties		6,272			5,385

		13,340			12,369

Terminals & truck loading racks:
Affiliates		2,362			2,203
Third parties		811			843

		3,173			3,046
Other		—			5

Total for refined product pipeline and terminal assets		16,513			15,420

Crude system and intermediate pipelines not contributed to HEP⁽¹⁾:
Lovington crude oil pipelines		—			1,491
Intermediate pipelines		—			1,860


Total for crude system and intermediate pipeline assets		—			3,351

Total revenues		16,513			18,771

Operating costs and expenses
Costs related to refined product pipeline and terminal assets:
Operations		5,388			5,228
Depreciation and amortization		2,363			1,826
General and administrative		977			—

		8,728			7,054

Crude system and intermediate pipelines not contributed to HEP⁽¹⁾:
Operations		—			1,224
Depreciation and amortization		—			220

		—			1,444

Total operating costs and expenses		8,728			8,498


Operating income		7,785			10,273

Interest income		88			35
Interest expense, including amortization		(1,118	)		—
Minority interest in Rio Grande		(429	)		(688	)


Net income		6,326			9,620

Add interest expense		1,005			—
Add amortization of deferred debt issuance costs		113			—
Subtract interest income		(88	)		(35	)
Add depreciation and amortization		2,363			2,046


EBITDA⁽²⁾		9,719		$	11,631


Subtract interest expense		(1,005	)
Add interest income		88
Subtract maintenance capital expenditures⁽³⁾		(167	)


Distributable cash flow⁽⁴⁾	$	8,635

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	Three Months Ended
	March 31,
	2005		2004
Volumes (bpd)⁽⁵⁾
Pipelines:
Affiliates		68,018		65,313
Third parties — Rio Grande		17,897		20,542
Third parties — Other⁽⁵⁾		14,783		—
Third parties — Other (volumes transported under capacity lease agreement)		4,960		12,650

		105,658		98,505

Terminals & truck loading racks:
Affiliates		117,612		115,582
Third parties		31,451		25,798

		149,063		141,380

Total for refined product pipeline and terminal assets (bpd)		254,721		239,885

(1)		Revenue and expense items generated by the crude system and intermediate pipeline assets that were not contributed to HEP. Historically, these items were included in the income of NPL as predecessor, but are not included in the income of HEP beginning July 13, 2004.

(2)		Earnings before interest, taxes, depreciation and amortization (“EBITDA”) is calculated as net income plus (i) interest expense net of interest income and (ii) depreciation and amortization. EBITDA is not a calculation based upon U.S. generally accepted accounting principles (“U.S. GAAP”). However, the amounts included in the EBITDA calculation are derived from amounts included in our consolidated financial statements. EBITDA should not be considered as an alternative to net income or operating income, as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity. EBITDA is not necessarily comparable to similarly titled measures of other companies. EBITDA is presented here because it enhances an investor’s understanding of our ability to satisfy principal and interest obligations with respect to our indebtedness and for the use of cash for other purposes, including capital expenditures. EBITDA is also used by our management for internal analysis and as a basis for compliance with financial covenants.

(3)		Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and to extend their useful lives.

(4)		Distributable cash flow is not a calculation based upon U.S. GAAP. However, the amounts included in the calculation are derived from amounts separately presented in our consolidated financial statements, with the exception of maintenance capital expenditures. Distributable cash flow should not be considered in isolation or as an alternative to net income or operating income, as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity. Distributable cash flow is not necessarily comparable to similarly titled measures of other companies. Distributable cash flow is presented here because it is a widely accepted financial indicator used by investors to compare partnership performance. We believe that this measure provides investors an enhanced perspective of the operating performance of our assets and the cash our business is generating.

(5)		The amounts reported for the three months ended March 31, 2005 include volumes only for March 2005 related to the assets acquired from Alon, averaged over the full 90 days in the quarter. Pipeline movements shipped by Alon on the newly acquired pipelines in March 2005 were at 42.9 mbpd. Assuming the March 2005 volumes on the assets acquired from Alon would have been experienced for the entire 2005 first quarter, pro forma total volumes for the quarter would equal 133.8 mbpd pipeline volumes, 167.6 mbpd terminal and truck loading rack volumes and 301.4 mbpd total volumes.

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Balance Sheet Data


	March 31,		December 31,
	2005		2004
	(Dollars in thousands)
Cash and cash equivalents	$	18,416	$	19,104
Working capital	$	20,887	$	19,120
Total assets	$	250,163	$	103,758
Long-term debt	$	147,055	$	25,000
Partners’ equity	$	86,002	$	61,528

Results of Operations — Three Months Ended March 31, 2005 Compared with Three Months Ended March 31, 2004

Summary

Net income was $6.3 million for the three months ended March 31, 2005, a decrease of $3.3 from $9.6 million for the three months ended March 31, 2004. The decrease in income was principally due to the inclusion in earnings in the prior year’s quarter of the crude oil and intermediate product pipelines that were not contributed to the Partnership, reduced revenues from the Rio Grande Pipeline, general and administrative charges currently being incurred by the Partnership where no such charges were allocated prior to the initial public offering, and interest expense principally related to the senior notes issued in conjunction with the Alon transaction, offset by the addition of one month of income generated from the Alon acquired assets.

Revenues

Revenues of $16.5 million for the three months ended March 31, 2005 were $2.3 million less than the $18.8 million in the comparable period of 2004, primarily a result of $3.4 million revenues in the three months ended March 31, 2004 from assets not contributed to the Partnership. Favorably impacting revenues for the current year’s quarter was one month of pipeline and terminal revenues ($1.8 million) from the Alon assets following the February 28, 2005 acquisition.

Revenues from refined product pipelines increased by $0.9 million from $12.4 million for the three months ended March 31, 2004 to $13.3 million for the three months ended March 31, 2005. Pipeline movements shipped by Alon on the newly acquired pipelines in March 2005 were at 42.9 thousand barrels-per-day (“mbpd”) generating $1.6 million in revenues. Refined product shipments on the Partnership’s other pipelines, excluding barrels moved pursuant to a capacity lease agreement, averaged 85.9 mbpd for both the three month periods ended March 31, 2005 and 2004, with volumes shipped by Holly and its affiliates increasing 2.7 mbpd, while volumes shipped on the Rio Grande Pipeline decreasing 2.6 mbpd. As anticipated, during the first quarter of 2005 based on the aggregate volumes shipped by BP Plc (“BP”) on the Rio Grande Pipeline, BP is no longer required to pay the border crossing fee pursuant to its contract. For the three months ended March 31, 2005 and 2004, the border crossing fee was $0.8 million and $1.3 million, respectively. In addition, the volume decrease on the Rio Grande Pipeline resulted in reduced revenues of $0.3 million.

Revenues from terminal and truck loading rack service fees increased by $0.2 million from $3.0 million for the three months ended March 31, 2004 to $3.2 million for the three months ended March 31, 2005. Refined products terminalled in our facilities for the comparable quarters rose to 149.1 mbpd in the 2005 first quarter from 141.4 mbpd in the 2004 first quarter, due principally to the incremental March 2005 volumes from the terminals acquired from Alon.

Revenues from crude system and intermediate pipeline assets not contributed to HEP were $3.4 million for the three months ended March 31, 2004, as a result of including operations of the predecessor only until July 13, 2004, the commencement of operations of HEP.

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Operating Costs

Operating costs decreased $1.1 million from the first quarter of 2004 to the first quarter of 2005. Expenses for the crude system and intermediate pipelines that were not contributed to HEP were included in our results for the first quarter of 2004, resulting in $1.2 million of operating expenses in the 2004 first quarter. This decrease in expense was partially offset by an increase in operating expenses due to the assets acquired from Alon.

Depreciation and Amortization

Depreciation and amortization was $0.4 million higher in the quarter ended March 31, 2005 than in the quarter ended March 31, 2004, due to the increase in depreciation from the assets acquired from Alon, offset by the exclusion of the crude system and intermediate pipelines as of July 13, 2004, as these assets were not contributed to HEP.

General and Administrative

General and administrative costs were $1.0 million for the first quarter of 2005. No general and administrative costs were incurred in the first quarter of 2004, as prior to HEP’s formation date of July 13, 2004, Holly did not allocate any general and administrative costs to its subsidiaries.

Interest Expense

Interest expense for the three months ended March 31, 2005 totaled $1.1 million. The interest expense consisted of: $0.9 million of interest on our outstanding debt, net of the impact of the interest rate swap; $0.1 million of commitment fees on the unused portion of the credit facility; and $0.1 million of amortization of the discount on the senior notes and deferred debt issuance costs. No interest expense was incurred in the first quarter of 2004.

Minority Interest in Earnings of Rio Grande

The minority interest related to the 30% of Rio Grande that we do not own reduced our income by $0.4 million in the first quarter of 2005 compared to $0.7 million in the first quarter of 2004.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Prior to our initial public offering, Holly utilized a common treasury function for all of its subsidiaries, whereby all cash receipts were deposited in Holly bank accounts and all cash disbursements were made from these accounts. Cash receipts from customers and cash payments to vendors for NPL were recorded in these common accounts. Thus, prior to our initial public offering, no cash balances were reflected in the accounts of NPL other than the cash balances of Rio Grande. Cash transactions handled by Holly for NPL were reflected in accounts receivable from affiliates and accounts payable to affiliates. Holly did not contribute these affiliate payables and receivables balances to HEP.

We completed our initial public offering of 7,000,000 common units of HEP on July 13, 2004, realizing net proceeds of $145.5 million. Concurrent with the closing of the offering we entered into a four-year $100 million revolving credit facility agreement and borrowed $25 million under the agreement. The proceeds from the public offering and the borrowings were used to (1) pay offering costs of $3.5 million and deferred debt issuance costs of $1.4 million, (2) repay $30.1 million of debt we owed to Holly and (3) make a $125.6 million distribution to Holly. We retained $9.9 million to replenish working capital.

With a portion of the proceeds from the senior note offering used principally for the Alon transaction, we repaid $30 million of outstanding indebtedness under our revolving credit agreement, including $5 million drawn shortly before the closing of the Alon transaction. As of March 31, 2005, we have no amounts

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outstanding under the revolving credit agreement, and now have $100 million available and unused under our revolving credit agreement. We believe our current cash balances, future internally-generated funds and funds available under our revolving credit agreement will provide sufficient resources to meet our working capital liquidity needs for the foreseeable future. In February 2005, we paid a cash distribution for the fourth quarter of 2004 of $0.50 on all units and the general partner interest, and the aggregate amount of the distribution was $7.1 million.

Cash and cash equivalents decreased by $0.7 million during the three months ended March 31, 2005. The cash flow generated from operating activities of $6.8 million in addition to the cash provided by financing activities of $115.3 million was slightly less than the cash used for investing activities of $122.8 million. Working capital increased during the three months by $1.8 million to $20.9 million at March 31, 2005.

Cash Flows — Operating Activities

Cash flows from operating activities increased by $6.5 million from $0.3 million for the three months ended March 31, 2004 to $6.8 million for the three months ended March 31, 2005. Net income for the three months ended March 31, 2005 was $6.3 million, a decrease of $3.3 million from net income of $9.6 million for the three months ended March 31, 2004. The non-cash items of depreciation and amortization, minority interest, and equity-based compensation increased $0.1 million in the first three months of 2005 from the same period in 2004. Working capital items decreased cash flows by $2.5 million during the three months ended March 31, 2005, as compared to a decrease of $12.1 million for the three months ended March 31, 2004. The large decrease for the three months ended March 31, 2004 was primarily due to an increase in accounts receivable - affiliates.

Cash Flows — Investing Activities

Cash flows used for investing activities increased from $2.6 million for the three months ended March 31, 2004 to $122.8 million for the three months ended March 31, 2005. On February 28, 2005, we closed on the Alon transaction which required $120 million in cash plus transaction costs of $1.3 million. Additionally, we issued 937,500 Class B subordinated units valued at $24.7 million to Alon as part of the consideration. See “Alon Transaction” below for additional information. Investment in properties and equipment for the three months ended March 31, 2005 was $0.4 million, a decrease of $1.1 million from $1.5 million for the three months ended March 31, 2004. Distributions to the minority interest owner in Rio Grande were $1.1 million in both the three months ended March 31, 2005 and 2004.

Cash Flows — Financing Activities

Cash flows provided by financing activities amounted to $115.3 million for the three months ended March 31, 2005. In connection with the Alon asset acquisition, we received proceeds of $147.4 million from the issuance of senior notes. See “Senior Notes Due 2015” below for additional information. Additionally, we used proceeds from the senior note offering to repay $30 million of outstanding indebtedness under our credit agreement, including $5 million drawn shortly before the closing of the Alon transaction. In February 2005, we paid a cash distribution for the fourth quarter of 2004 of $0.50 on all units and the general partner interest, and the aggregate amount of the distribution was $7.1 million. Other cash flows from financing activities during the three months ended March 31, 2005 included an additional capital contribution from our general partner of $0.6 million and deferred debt issuance costs incurred of $0.5 million. During the three months ended March 31, 2004, we did not have any cash flows from financing activities.

Capital Requirements

Our pipeline and terminalling operations are capital intensive, requiring investments to maintain, expand, upgrade or enhance existing operations and to meet environmental and operations regulations. Our capital requirements have consisted of, and are expected to continue to consist primarily of, maintenance capital expenditures and expansion capital expenditures. Maintenance capital expenditures represent capital expenditures to replace partially or fully depreciated assets to maintain the operating capacity of existing assets. Maintenance capital expenditures include expenditures required to maintain equipment

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reliability, tankage and pipeline integrity, and safety and to address environmental regulations. Expansion capital expenditures represent capital expenditures to expand the operating capacity of existing or new assets, whether through construction or acquisition. Expansion capital expenditures include expenditures to acquire assets to grow our business and to expand existing facilities, such as projects that increase throughput capacity on our pipelines and in our terminals. Repair and maintenance expenses associated with existing assets that are minor in nature and do not extend the useful life of existing assets are charged to operating expenses as incurred.

Prior to our initial public offering, our capital requirements had historically been met with internally generated funds including short-term non-interest bearing funding from affiliates. We have budgeted average annual maintenance capital expenditures for our existing operations of $1.5 million in 2005 (excluding approximately $0.5 million of maintenance capital expenditures we anticipate with respect to assets acquired in the Alon transaction). We anticipate that these capital expenditures will be funded with cash generated by operations. However, we anticipate funding future expansion capital requirements through long-term borrowings or other debt financings and/or equity capital offerings.

Credit Agreement

Our obligations under the Credit Agreement are secured by substantially all of our assets, however such security related to the assets acquired from Alon is junior to Alon’s security interest. Indebtedness under the Credit Agreement is recourse to our general partner and guaranteed by our wholly-owned subsidiaries.

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Senior Notes Due 2015

We financed 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 proceeds of the offering to fund the $120 million cash portion of the consideration for the Alon transaction, and used the balance to repay $30 million of outstanding indebtedness under our Credit Agreement, including $5 million drawn shortly before the closing of the Alon transaction.

The $150 million principal amount of Senior Notes is recorded at $147.1 on our accompanying consolidated balance sheet at March 31, 2005. The difference is due to the accounting for the $2.6 million discount paid to the initial purchasers and for $0.3 million relating to the interest rate swap contract discussed below.

Alon Transaction

On February 28, 2005, we closed on a contribution agreement with Alon that provided for our acquisition of four refined products pipelines aggregating approximately 500 miles, an associated tank farm and two refined products terminals with aggregate storage capacity of approximately 347,000 barrels. These pipelines and terminals are located primarily in Texas and transport approximately 70% of the light refined products for Alon’s 65,000 bpd capacity refinery in Big Spring, Texas.

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Alon transaction. In connection with the Alon transaction, we entered into a 15-year pipelines and terminals agreement with Alon. Under this agreement, Alon agreed to transport on the pipelines and throughput volumes through the terminals, a volume of refined products that would result in minimum revenues to us of $20.2 million per year in the first year. The agreed upon tariffs at the minimum volume commitment will increase or decrease each year at a rate equal to the percentage change in the producer price index, but not below the initial tariffs. Alon’s minimum volume commitment was calculated based on 90% of Alon’s recent usage of these pipeline and terminals taking into account a 5,000 bpd expansion of Alon’s Big Spring Refinery completed in February 2005. At revenue levels above 105% of the base revenue amount, as adjusted for changes in the producer price index, Alon will receive an annual 50% discount on incremental revenues. Alon’s obligations under the pipelines and terminals agreement may be reduced or suspended under certain circumstances. We granted Alon a second mortgage on the pipelines and terminals to secure certain of Alon’s rights under the pipelines and terminals agreement. Alon will have 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, where Alon will indemnify us subject to a $100,000 deductible and a $20 million maximum liability cap.

Contractual Obligations and Contingencies

The following table presents our long-term contractual obligations as of March 31, 2005. Our pipeline operating lease contains one 10-year renewal option that is not reflected in the table below and that is likely to be exercised.


			Payments Due by Period
			Less than						Over 5
	Total		1 Year		2-3 Years		4-5 Years		Years
	(In thousands)
Long-term debt - principle	$	150,000	$	—	$	—	$	—	$	150,000
Long-term debt - interest		93,776		9,401		18,750		18,750		46,875
Pipeline operating lease		12,283		5,459		6,824		—		—
Other		6,010		2,450		3,465		95		—


Total	$	262,069	$	17,310	$	29,039	$	18,845	$	196,875

Impact of Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the three month periods ended March 31, 2005 and 2004.

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Environmental Matters

Our operation of pipelines, terminals, and associated facilities in connection with the storage and transportation of refined products is subject to stringent and complex federal, state, and local laws and regulations governing the discharge of materials into the environment, or otherwise relating to the protection of the environment. As with the industry generally, compliance with existing and anticipated laws and regulations increases our overall cost of business, including our capital costs to construct, maintain, and upgrade equipment and facilities. While these laws and regulations affect our maintenance capital expenditures and net income, we believe that they do not affect our competitive position in that the operations of our competitors are similarly affected. We believe that our operations are in substantial compliance with applicable environmental laws and regulations. These laws and regulations are subject to change by regulatory authorities, and we are unable to predict the ongoing cost to us of complying with these laws and regulations or the future impact of these laws and regulations on our operations. However, if new laws or regulations that affect terminals or pipelines are enacted that require us to make substantial and unanticipated capital expenditures, we will be able to recover a portion of the cost from Holly. See “Agreements with Holly Corporation” for further discussion. Violation of environmental laws, regulations, and permits can result in the imposition of significant administrative, civil and criminal penalties, injunctions, and construction bans or delays. A discharge of hydrocarbons or hazardous substances into the environment could, to the extent the event is not insured, subject us to substantial expense, including both the cost to comply with applicable laws and regulations and claims made by neighboring landowners and other third parties for personal injury and property damage.

We inspect our pipelines regularly using equipment rented from third party suppliers. Third parties also assist us in interpreting the results of the inspections.

Holly has agreed to indemnify us in an aggregate amount not to exceed $15 million for ten years after the closing of the initial public offering for environmental noncompliance and remediation liabilities associated with the assets transferred to us and occurring or existing before the closing date. 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, where Alon will indemnify us subject to a $100,000 deductible and a $20 million maximum liability cap.

Contamination resulting from spills of refined products and crude oil is not unusual within the petroleum pipeline industry. Historic spills along our pipelines and terminals as a result of past operations have resulted in contamination of the environment, including soils and groundwater. Site conditions, including soils and groundwater, are being evaluated at a few of our properties where operations may have resulted in releases of hydrocarbons and other wastes.

We may experience future releases of refined products into the environment from our pipelines and terminals, or discover historical releases that were previously unidentified or not assessed. While we maintain an extensive inspection and audit program designed, as applicable, to prevent and to detect and address these releases promptly, damages and liabilities incurred due to any future environmental releases from our assets nevertheless have the potential to substantially affect our business.

CRITICAL ACCOUNTING POLICIES

Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities as of the date of the financial statements. Actual results may differ from these estimates under different assumptions or conditions. We consider the following policies to be the most critical to understanding the judgments that are involved and the uncertainties that could impact our results of operations, financial condition and cash flows.

Our significant accounting policies are described in “Item 7. Management’s Discussion and Analysis of Financial Conditions and Operations – Critical Accounting Policies” in our Annual Report on Form 10-K for the year ended December 31, 2004. Certain critical accounting policies that materially affect the

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amounts recorded in our consolidated financial statements include revenue recognition, assessing the possible impairment of certain long-lived assets and assessing contingent liabilities for probable losses. There have been no changes to these policies in 2005.

Recent Accounting Pronouncement

In December 2004, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) 123 (revised), “Share-Based Payment.” This revision prescribes the accounting for a wide-range of share-based compensation arrangements, including share options, restricted share plans, performance-based awards, share appreciation rights and employee share purchase plans, and generally requires the fair value of share-based awards to be expensed on the income statement. This standard was to become effective for us for the first interim period beginning after June 15, 2005, however in April 2005, the Securities and Exchange Commission allowed for the delay in the implementation of this standard, with the result that we are now required to adopt this standard for our 2006 year. SFAS 123 (revised) allows for either modified prospective recognition of compensation expense or modified retrospective recognition, which may be back to the original issuance of SFAS 123 or only to interim periods in the year of adoption. We are still evaluating the impact and method of adoption. However, we do not believe the adoption of this standard will have a material effect on our financial condition, results of operations or cash flows.

ADDITIONAL FACTORS THAT MAY AFFECT FUTURE RESULTS

Additional factors that may affect future results are described in “Item 7. Management’s Discussion and Analysis of Financial Conditions and Operations – Additional Factors That May Affect Future Results” in our Annual Report on Form 10-K for the year ended December 31, 2004.

RISK MANAGEMENT

We have entered into an interest rate swap contract to effectively convert the interest expense associated with $60 million of our 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%. 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 accounted for them using the “shortcut” method prescribed for fair value hedges by SFAS No. 133. Accordingly, we adjust the carrying value of each 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 the interest rate swap agreement of $0.3 million is included in “Other long-term liabilities” in our accompanying consolidated balance sheet at March 31, 2005. 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 accompanying consolidated balance sheet at March 31, 2005.

The market risk inherent in our debt instruments and positions is the potential change arising from increases or decreases in interest rates as discussed below.

At March 31, 2005, we had an outstanding principal balance on our unsecured Senior Notes of $150.0 million. By means of our interest rate swap contract, we have effectively converted $60.0 million of the Senior Notes from a fixed rate to variable rate. For the fixed rate debt portion of $90.0 million, changes in interest rates would generally affect the fair value of the debt, but not our earnings or cash flows. Conversely, for the variable rate debt portion of $60.0 million, changes in interest rates would generally not impact the fair value of the debt, but may affect our future earnings and cash flows. We estimate a hypothetical 10% change in the interest rate applicable to our fixed rate debt portion of $90.0 million would result in a change of approximately $4 million in the fair value of the debt. A hypothetical 10% change in the interest rate applicable to our variable rate debt portion of $60.0 million would not have a material effect on our earnings or cash flows.

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At March 31, 2005, our cash and cash equivalents were made up of highly liquid investments with a maturity of three months or less at the time of purchase. Due to the short-term nature of our cash and cash equivalents, a hypothetical 10% increase in interest rates would not have a material effect on the fair market value of our portfolio. Since we have the ability to liquidate this portfolio, we do not expect our operating results or cash flows to be materially affected to any significant degree by the effect of a sudden change in market interest rates on our investment portfolio.

Our operations are subject to normal hazards of operations, including fire, explosion and weather-related perils. We maintain various insurance coverages, including business interruption insurance, subject to certain deductibles. We are not fully insured against certain risks because such risks are not fully insurable, coverage is unavailable, or premium costs, in our judgment, do not justify such expenditures.

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Item 3. Quantitative and Qualitative Disclosures About Market Risks

Market risk is the risk of loss arising from adverse changes in market rates and prices. See “Risk Management” under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a discussion of market risk exposures that we have with respect to our cash and cash equivalents and long-term debt. We utilize derivative instruments to hedge our interest rate exposure, also discussed under “Risk Management.”

Since we do not own products shipped on our pipelines or terminalled at our terminal facilities we do not have market risks associated with commodity prices.

Item 4. Controls and Procedures

(a) Evaluation of disclosure controls and procedures

Our principal executive officer and principal financial officer have evaluated, as required by Rule 13a-15(b) under the Securities Exchange Act of 1934 (the “Exchange Act”), our disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of the end of the period covered by this quarterly report on Form 10-Q. Based on that evaluation, the principal executive officer and principal financial officer concluded that the design and operation of our disclosure controls and procedures are effective in ensuring that information we are required to disclose in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission’s rules and forms.

(b) Changes in internal control over financial reporting

There have been no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during our last fiscal quarter that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

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HOLLY ENERGY PARTNERS, L.P.

PART II. OTHER INFORMATION

Item 1. Legal proceedings

We are a party to various legal and regulatory proceedings, none of which we believe will have a material adverse impact on our financial condition, results of operations or cash flows.

Item 6. Exhibits


			3.1			Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of Holly Energy Partners, L.P., dated February 28, 2005 (incorporated by reference to Exhibit 3.1 of Registrant’s Form 8-K Current Report dated February 28, 2005).

			4.1			Indenture, dated February 28, 2005, among the Issuers, the Guarantors and the Trustee (incorporated by reference to Exhibit 4.1 of Registrant’s Form 8-K Current Report dated February 28, 2005).

			4.2			Form of 6.25% Senior Note Due 2015 (included as Exhibit A to the Indenture filed as Exhibit 4.1 hereto) (incorporated by reference to Exhibit 4.2 of Registrant’s Form 8-K Current Report dated February 28, 2005).

			4.3			Form of Notation of Guarantee (included as Exhibit E to the Indenture filed as Exhibit 4.1 hereto) (incorporated by reference to Exhibit 4.3 of Registrant’s Form 8-K Current Report dated February 28, 2005).

			4.4			Registration Rights Agreement, dated February 28, 2005, among the Issuers and the Initial Purchasers (incorporated by reference to Exhibit 4.4 of Registrant’s Form 8-K Current Report dated February 28, 2005).

			4.5*			First Supplemental Indenture, dated March 10, 2005, among HEP Fin-Tex/Trust-River, L.P., Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors, and U.S. Bank National Association.

			4.6*			Second Supplemental Indenture, dated April 27, 2005, among Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors, and U.S. Bank National Association.

			10.1			Pipelines and Terminals Agreement, dated February 28, 2005, among the Partnership and Alon USA, LP2005 (incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K Current Report dated February 28, 2005).

			10.2			Form of Mortgage and Deed of Trust (Oklahoma) (incorporated by reference to Exhibit 10.2 of Registrant’s Form 8-K Current Report dated February 28, 2005).

			10.3			Form of Mortgage and Deed of Trust (Texas) (incorporated by reference to Exhibit 10.3 of Registrant’s Form 8-K Current Report dated February 28, 2005).

			10.4			Consent, Waiver and Amendment No. 2, dated February 28, 2005, among OLP, the existing guarantors identified therein, Union Bank of California, N.A., as administrative agent, and certain other lending institutions identified therein (incorporated by reference to Exhibit 10.4 of Registrant’s Form 8-K Current Report dated February 28, 2005).

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			31.1*			Certification of Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002.

			31.2*			Certification of Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002.

			32.1*			Certification of Chief Executive Officer under Section 906 of the Sarbanes-Oxley Act of 2002.

			32.2*			Certification of Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act of 2002.

Filed herewith.

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HOLLY ENERGY PARTNERS, L.P.

SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


		HOLLY ENERGY PARTNERS, L.P. (Registrant)

		By: HEP LOGISTICS HOLDINGS, L.P. its General Partner

		By: HOLLY LOGISTIC SERVICES, L.L.C. its General Partner

Date: May 5, 2005		/s/ P. Dean Ridenour

		P. Dean Ridenour
		Vice President and Chief Accounting Officer and Director (Principal Accounting Officer)

		/s/ Stephen J. McDonnell

		Stephen J. McDonnell Vice President and Chief Financial Officer (Principal Financial Officer)

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Positive
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Uncertain
Constraining
Legalese
Litigous
Readability	H.S. freshman Avg

Holly Energy Partners (HEP) 10-Q2005 Q1 Quarterly report

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