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, 2008

OR

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

For the transition period from                     to                     

HOLLY CORPORATION

(Exact name of registrant as specified in its charter)

Delaware		75-1056913
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)
100 Crescent Court, Suite 1600
Dallas, Texas		75201-6915
(Address of principal executive offices)		(Zip Code)
Registrant’s telephone number, including area code (214) 871-3555

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, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

50,106,730 shares of Common Stock, par value $.01 per share, were outstanding on April 30, 2008.

 

 

HOLLY CORPORATION
INDEX

				Page
PART I.		FINANCIAL INFORMATION
Forward-Looking Statements				3
Definitions				4
Item 1.		Financial Statements
		Consolidated Balance Sheets March 31, 2008 (Unaudited) and December 31, 2007		6
		Consolidated Statements of Income (Unaudited) Three Months Ended March 31, 2008 and 2007		7
		Consolidated Statements of Cash Flows (Unaudited) Three Months Ended March 31, 2008 and 2007		8
		Consolidated Statements of Comprehensive Income (Unaudited) Three Months Ended March 31, 2008 and 2007		9
		Notes to Consolidated Financial Statements (Unaudited)		10
Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations		23
Item 3.		Quantitative and Qualitative Disclosures About Market Risk		38
Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles				38
Item 4.		Controls and Procedures		44
PART II.		OTHER INFORMATION
Item 1.		Legal Proceedings		45
Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds		46
Item 6.		Exhibits		47
Signatures				48
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

References herein to Holly Corporation include Holly Corporation and its consolidated subsidiaries. In accordance with the Securities and Exchange Commission’s (“SEC”) “Plain English” guidelines, this Quarterly Report on Form 10-Q has been written in the first person. In this document, the words “we”, “our”, “ours” and “us” refer only to Holly Corporation and its consolidated subsidiaries or to Holly Corporation or an individual subsidiary and not to any other person.

This Quarterly Report on Form 10-Q contains certain “forward-looking statements” within the meaning of the federal securities laws. All statements, other than statements of historical fact included in this Form 10-Q, including, but not limited to, those under “Results of Operations,” “Liquidity and Capital Resources” and “Risk Management” in Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part I and those in Item 1 “Legal Proceedings” in Part II, 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 to be 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 actions of actual or potential competitive suppliers of refined petroleum products in our markets;
	•		the demand for and supply of crude oil and refined products;
	•		the spread between market prices for refined products and market prices for crude oil;
	•		the possibility of constraints on the transportation of refined products;
	•		the possibility of inefficiencies, curtailments or shutdowns in refinery operations or pipelines;
	•		effects of governmental regulations and policies;
	•		the availability and cost of our financing;
	•		the effectiveness of our capital investments and marketing strategies;
	•		our efficiency in carrying out construction projects;
	•		our ability to acquire refined product operations on acceptable terms and to integrate any future acquired operations;
	•		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. This summary discussion should be read in conjunction with the discussion of risk factors and other cautionary statements under the heading “Risk Factors” included in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2007 and in conjunction with the discussion in this Form 10-Q in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the headings “Liquidity and Capital Resources.” 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.

DEFINITIONS

     Within this report, the following terms have these specific meanings:

     “Alkylation” means the reaction of propylene or butylene (olefins) with isobutane to form an iso-paraffinic gasoline (inverse of cracking).

     “BPD” means the number of barrels per day of crude oil or petroleum products.

     “BPSD” means the number of barrels per stream day (barrels of capacity in a 24 hour period) of crude oil or petroleum products.

     “Catalytic reforming” means a refinery process which uses a precious metal (such as platinum) based catalyst to convert low octane naphtha to high octane gasoline blendstock and hydrogen. The hydrogen produced from the reforming process is used to desulfurize other refinery oils and is the primary source of hydrogen for the refinery.

     “Cracking” means the process of breaking down larger, heavier and more complex hydrocarbon molecules into simpler and lighter molecules.

     “Crude distillation” means the process of distilling vapor from liquid crudes, usually by heating, and condensing slightly above atmospheric pressure the vapor back to liquid in order to purify, fractionate or form the desired products.

     “Ethanol” means a high octane gasoline blend stock that is used to make various grades of gasoline.

     “FCC,” or fluid catalytic cracking, means a refinery process that breaks down large complex hydrocarbon molecules into smaller more useful ones using a circulating bed of catalyst at relatively high temperatures.

     “Hydrocracker” means a refinery unit that breaks down large complex hydrocarbon molecules into smaller more useful ones using a fixed bed of catalyst at high pressure and temperature with hydrogen.

     “Hydrodesulfurization” means to remove sulfur and nitrogen compounds from oil or gas in the presence of hydrogen and a catalyst at relatively high temperatures.

     “Hydrogen plant” means a refinery unit that converts natural gas and steam to high purity hydrogen, which is then used in the hydrodesulfurization, hydrocracking and isomerization processes.

     “HF alkylation,” or hydrofluoric alkylation, means a refinery process which combines isobutane and C3/C4 olefins using HF acid as a catalyst to make high octane gasoline blend stock.

     “Isomerization” means a refinery process for rearranging the structure of C5/C6 molecules without changing their size or chemical composition and is used to improve the octane of C5/C6 gasoline blendstocks.

     “LPG” means liquid petroleum gases.

     “LSG,” or low sulfur gasoline, means gasoline that contains less than 30 PPM of total sulfur.

     “MMBtu” or one million British thermal units, means for each unit, the amount of heat required to raise one pound of water one degree Fahrenheit at one atmosphere pressure.

     “MMSCFD” means one million standard cubic feet per day.

     “MTBE” means methyl tertiary butyl ether, a high octane gasoline blend stock that is used to make various grades of gasoline.

     “Natural gasoline” means a low octane gasoline blend stock that is purchased and used to blend with other high octane stocks produced to make various grades of gasoline.

     “PPM” means parts-per-million.

     “Refinery gross margin” means the difference between average net sales price and average costs of products per barrel of produced refined products. This does not include the associated depreciation, depletion and amortization costs.

     “Reforming” means the process of converting gasoline type molecules into aromatic, higher octane gasoline blend stocks while producing hydrogen in the process.

     “ROSE”, or “Solvent deasphalter / residuum oil supercritical extraction,” means a refinery unit that uses a light hydrocarbon like propane or butane to extract non asphaltene heavy oils from asphalt or atmospheric reduced crude. These deasphalted oils are then further converted to gasoline and diesel in the FCC process. The remaining asphaltenes are either sold, blended to fuel oil or blended with other asphalt as a hardener.

     “Sour crude oil” means crude oil containing quantities of sulfur greater than 0.4 percent by weight, while “sweet crude oil” means crude oil containing quantities of sulfur equal to or less than 0.4 percent by weight.

     “ULSD,” or ultra low sulfur diesel, means diesel fuel that contains less than 15 PPM of total sulfur.

     “Vacuum distillation” means the process of distilling vapor from liquid crudes, usually by heating, and condensing below atmospheric pressure the vapor back to liquid in order to purify, fractionate or form the desired products.

Item 1. Financial Statements

HOLLY CORPORATION

CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)

		March 31,				December 31,
		2008				2007
		(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	180,551			$	94,369
Marketable securities			205,974				158,233
Accounts receivable:     Product and transportation			238,730				242,392
Crude oil resales			431,229				366,226
Related party receivable			—				6,151
			669,959				614,769
Inventories:                    Crude oil and refined products			118,850				118,308
Materials and supplies			16,265				22,322
			135,115				140,630
Income taxes receivable			13,451				16,356
Prepayments and other			8,707				10,264
Total current assets			1,213,757				1,034,621
Properties, plants and equipment, at cost			1,200,294				802,820
Less accumulated depreciation, depletion and amortization			(266,072	)			(271,970	)
			934,222				530,850
Marketable securities (long-term)			51,246				77,182
Other assets:                       Turnaround costs (long-term)			8,735				8,705
Intangibles and other			68,762				12,587
			77,497				21,292
Total assets		$	2,276,722			$	1,663,945
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	914,322			$	782,976
Accrued liabilities			34,176				35,104
Short-term debt — Holly Energy Partners			10,000				—
Total current liabilities			958,498				818,080
Long-term debt — Holly Corporation			—				—
Long-term debt — Holly Energy Partners			341,416				—
Deferred income taxes			36,425				38,933
Other long-term liabilities			42,334				36,712
Distributions in excess of investment in Holly Energy Partners			—				168,093
Minority interest			398,016				8,333
Stockholders’ equity:
Preferred stock, $1.00 par value — 1,000,000 shares authorized; none issued			—				—
Common stock $.01 par value — 160,000,000 shares authorized; 73,527,953 and 73,269,219 shares issued as of March 31, 2008 and December 31, 2007, respectively			735				733
Additional capital			112,781				109,125
Retained earnings			1,055,989				1,054,974
Accumulated other comprehensive loss			(20,662	)			(19,076	)
Common stock held in treasury, at cost — 22,818,361 and 20,653,050 shares as of March 31, 2008 and December 31, 2007, respectively			(648,810	)			(551,962	)
Total stockholders’ equity			500,033				593,794
Total liabilities and stockholders’ equity		$	2,276,722			$	1,663,945

See accompanying notes.

HOLLY CORPORATION

CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
(In thousands, except per share data)

		Three Months Ended
		March 31,
		2008				2007
Sales and other revenues		$	1,479,984			$	925,867
Operating costs and expenses:
Cost of products sold (exclusive of depreciation, depletion, and amortization)			1,383,437				751,714
Operating expenses (exclusive of depreciation, depletion, and amortization)			60,708				50,129
General and administrative expenses (exclusive of depreciation, depletion, and amortization)			12,832				15,847
Depreciation, depletion and amortization			13,309				11,451
Exploration expenses, including dry holes			105				152
Total operating costs and expenses			1,470,391				829,293
Income from operations			9,593				96,574
Other income (expense):
Equity in earnings of Holly Energy Partners			2,990				3,346
Minority interest in earnings of Holly Energy Partners			(802	)			—
Interest income			3,555				2,560
Interest expense			(1,992	)			(252	)
			3,751				5,654
Income from operations before income taxes			13,344				102,228
Income tax provision:
Current			6,318				34,758
Deferred			(1,623	)			(72	)
			4,695				34,686
Net income		$	8,649			$	67,542
Net income per share — basic		$	0.17			$	1.22
Net income per share — diluted		$	0.17			$	1.20
Cash dividends declared per common share		$	0.15			$	0.10
Average number of common shares outstanding:
Basic			51,165				55,189
Diluted		51,515					56,318

See accompanying notes.

HOLLY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In thousands)

		Three Months Ended
		March 31,
		2008				2007
Cash flows from operating activities:
Net income		$	8,649			$	67,542
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization			13,309				11,451
Deferred income taxes			(1,623	)			(72	)
Minority interest in earnings of Holly Energy Partners			802				—
Equity based compensation expense			178				1,231
Distributions in excess of equity in earnings in Holly Energy Partners			3,067				2,089
(Increase) decrease in current assets:
Accounts receivable			(49,717	)			35,682
Inventories			5,626				(15,758	)
Income taxes receivable			2,905				9,055
Prepayments and other			1,855				1,330
Increase (decrease) in current liabilities:
Accounts payable			125,125				(25,478	)
Accrued liabilities			(9,989	)			(16,552	)
Income taxes payable			—				16,109
Turnaround expenditures			(1,398	)			(198	)
Other, net			61				(130	)
Net cash provided by operating activities			98,850				86,301
Cash flows from investing activities:
Additions to properties, plants and equipment			(72,761	)			(26,750	)
Purchases of marketable securities			(207,557	)			(89,165	)
Investment in Holly Energy Partners			(290	)			—
Sales and maturities of marketable securities			185,772				62,140
Proceeds form sale of crude pipeline and tankage assets			171,000				—
Increase in cash due to consolidation of Holly Energy Partners			7,295				—
Net cash provided by (used for) investing activities			83,459				(53,775	)
Cash flows from financing activities:
Borrowings under credit agreement — Holly Energy Partners			10,000				—
Deferred financing costs			(365	)			—
Purchase of treasury stock			(102,850	)			(35,837	)
Cash dividends			(6,410	)			(4,477	)
Contribution from joint venture partner			19				—
Issuance of common stock upon exercise of options			254				263
Excess tax benefit from equity based compensation			3,225				4,587
Net cash used for financing activities			(96,127	)			(35,464	)
Cash and cash equivalents:
Increase (decrease) for the period			86,182				(2,938	)
Beginning of period			94,369				154,117
End of period		$	180,551			$	151,179
Supplemental disclosure of cash flow information:
Cash paid during the period for
Interest		$	5,080			$	14
Income taxes		$	298			$	5,006

See accompanying notes.

HOLLY CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
(In thousands)

		Three Months Ended
		March 31,
		2008				2007
		(In thousands)
Net income		$	8,649			$	67,542
Other comprehensive income (loss):
Securities available for sale:
Unrealized gain on available for sale securities			826				378
Reclassification adjustment to net income on sale of marketable securities			(1,307	)			(21	)
Total unrealized gain (loss) on available for sale securities			(481	)			357
Retirement medical obligation adjustment			—				(2,792	)
Other comprehensive loss of Holly Energy Partners
Change in fair value of cash flow hedge			(4,349	)			—
Less minority interest in other comprehensive loss			2,359				—
Other comprehensive loss of Holly Energy Partners, net of minority interest			(1,990	)			—
Other comprehensive loss before income taxes			(2,471	)			(2,435	)
Income tax benefit			(885	)			(949	)
Other comprehensive loss			(1,586	)			(1,486	)
Total comprehensive income		$	7,063			$	66,056

See accompanying notes.

HOLLY CORPORATION

NOTE 1: Description of Business and Presentation of Financial Statements

References herein to Holly Corporation include Holly Corporation and its consolidated subsidiaries. In accordance with the Securities and Exchange Commission’s (“SEC”) “Plain English” guidelines, this Quarterly Report on Form 10-Q has been written in the first person. In this document, the words “we”, “our”, “ours” and “us” refer only to Holly Corporation and its consolidated subsidiaries or to Holly Corporation or an individual subsidiary and not to any other person. For periods after the reconsolidation of HEP effective March 1, 2008, the words “we”, “our”, “ours”, and “us” normally include HEP and its subsidiaries as consolidated subsidiaries of Holly Corporation, except that such words generally do not include HEP and its subsidiaries when used in descriptions of agreements or transactions between HEP and its subsidiaries on the one hand and Holly Corporation and its other subsidiaries on the other hand.

     As of the close of business on March 31, 2008, we:

	•		owned and operated two refineries consisting of a petroleum refinery in Artesia, New Mexico that is operated in conjunction with crude oil distillation and vacuum distillation and other facilities situated 65 miles away in Lovington, New Mexico (collectively known as the “Navajo Refinery”), and a refinery in Woods Cross, Utah (“Woods Cross Refinery”);
	•		owned and operated Holly Asphalt Company (formerly, NK Asphalt Partners) which manufactures and markets asphalt products from various terminals in Arizona and New Mexico; and
	•		owned a 46% interest in Holly Energy Partners, L.P. (“HEP”) which includes our 2% general partner interest, which has logistic assets including approximately 2,500 miles of petroleum product pipelines located in Texas, New Mexico, Oklahoma and Utah (including 340 miles of leased pipeline); ten refined product terminals; two refinery truck rack facilities, a refined products tank farm facility, and a 70% interest in Rio Grande Pipeline Company (“Rio Grande”). On February 29, 2008, HEP acquired certain crude pipelines and tankage assets that also service our Navajo and Woods Cross Refineries.

We have prepared these consolidated financial statements without audit. In management’s opinion, these consolidated financial statements include all normal recurring adjustments necessary for a fair presentation of our consolidated financial position as of March 31, 2008, the consolidated results of operations and comprehensive income for the three months ended March 31, 2008 and 2007 and consolidated cash flows for the three months ended March 31, 2008 and 2007 in accordance with the rules and regulations of the SEC. Although certain notes and other information required by accounting principles generally accepted in the United States 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 Annual Report on Form 10-K for the year ended December 31, 2007 filed with the SEC.

We use the last-in, first-out (“LIFO”) method of valuing inventory. Under the LIFO method, an actual valuation of inventory can only be made at the end of each year based on the inventory levels and costs at that time. Accordingly, interim LIFO calculations are based on management’s estimates of expected year-end inventory levels and costs and are subject to the final year-end LIFO inventory valuation.

Our results of operations for the first three months of 2008 are not necessarily indicative of the results to be expected for the full year.

On February 29, 2008, we closed on the sale of certain crude pipelines and tankage assets (the “Crude Pipelines and Tankage Assets”) to HEP for $180.0 million. See Note 2 for a description of this transaction.

HEP is a variable interest entity (“VIE”) as defined under FIN No. 46. Under the provisions of FIN No. 46, HEP’s purchase of the Crude Pipelines and Tankage Assets qualifies as a reconsideration event whereby we reassessed our beneficial interest in HEP. Following this transaction, we determined that our beneficial interest in HEP exceeds 50%. Accordingly, we reconsolidated HEP effective March 1, 2008 and no longer account for our investment in HEP under the equity method of accounting.

New Accounting Pronouncements

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

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements — an Amendment of ARB No. 51. SFAS No. 160 changes the classification of non-controlling interests, also referred to as minority interests, in the consolidated financial statements. It also establishes a single method of accounting for changes in a parent company’s ownership interest that do not result in deconsolidation and requires a parent company to recognize a gain or loss when a subsidiary is deconsolidated. SFAS No. 160 is effective for fiscal years beginning on or after December 15, 2008. Earlier adoption is prohibited. We will adopt this standard effective January 1, 2009. We are currently evaluating the impact of this standard on our financial condition, results of operations and cash flows.

In June 2007, the FASB ratified EITF No. 06-11, Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards. EITF No. 06-11 requires that tax benefits generated by dividends paid during the vesting period on certain equity-classified share-based compensation awards be classified as additional paid-in capital and included in a pool of excess tax benefits available to absorb tax deficiencies from share-based payment awards. EITF No. 06-11 is effective for fiscal years beginning after December 15, 2007. We adopted this standard effective January 1, 2008. The adoption of this standard did not have a material effect on our financial condition, results of operations or cash flows.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No 115. SFAS No. 159, which amends SFAS No. 115, allows certain financial assets and liabilities to be recognized, at a company’s election, at fair market value, with any gains or losses for the period recorded in the statement of income. SFAS No. 159 includes available-for-sale securities in the assets eligible for this treatment. Currently, we record the gains or losses for the period as a component of comprehensive income and in the equity section of the balance sheet. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007, and interim periods in those fiscal years. We adopted this standard effective January 1, 2008. The adoption of this standard did not have a material effect on our financial condition, results of operations or cash flows.

SFAS No. 157 “Fair Value Measurements”

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

HEP has interest rate swaps that are measured at fair value on a recurring basis using level 2 inputs. See Note 7 for additional information on these swaps.

NOTE 2: Holly Energy Partners

HEP is a publicly held master limited partnership that commenced operations July 13, 2004 upon the completion of its initial public offering. At March 31, 2008, we held 7,000,000 subordinated units and 290,000 common units of HEP, representing a 46% ownership interest in HEP, including our 2% general partner interest.

On February 29, 2008, we closed on the sale of the Crude Pipelines and Tankage Assets to HEP for $180.0 million. The assets consisted of crude oil trunk lines that deliver crude oil to our Navajo Refinery in southeast New Mexico, gathering and connection pipelines located in west Texas and New Mexico, on-site crude tankage located within the Navajo and Woods Cross Refinery complexes, a jet fuel products pipeline and leased terminal between Artesia and

Roswell, New Mexico, and crude oil and product pipelines that support our Woods Cross Refinery. Consideration received consisted of $171.0 million in cash and 217,497 HEP common units having a value of $9.0 million.

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

HEP also serves our refineries in New Mexico and Utah under a 15-year pipelines and terminals agreement (the “HEP PTA”) expiring in 2019 and a 15-year intermediate pipeline agreement expiring in 2020 (the “HEP IPA”). Under the HEP PTA, we pay HEP fees to transport on their refined product pipelines or throughput in their terminals, volumes of refined products that will result in minimum annual payments to HEP. Under the HEP IPA, we agreed to transport minimum volumes of intermediate products on the intermediate pipelines that will also result in minimum annual payments to HEP. Minimum payments for both agreements are adjusted annually on July 1 based on increases in the PPI. Following the July 1, 2007 PPI rate adjustment, minimum payments under the HEP PTA and the HEP IPA are $39.6 million and $12.8 million, respectively, for the twelve months ended June 30, 2008.

HEP is a variable interest entity as defined under FIN No. 46. Under the provisions of FIN No. 46, this transaction qualifies as a reconsideration event whereby we reassessed our beneficial interest in HEP. Following HEP’s acquisition of our crude pipelines and tankage assets, we determined that our beneficial interest in HEP exceeds 50%. Accordingly, we reconsolidated HEP effective March 1, 2008 and no longer account for our investment in HEP under the equity method of accounting.

The following table sets forth the changes in our investment account in HEP for the period from January 1, 2008 through February 29, 2008, prior to our reconsolidation effective March 1, 2008:

		(In thousands)
Investment in HEP balance at December 31, 2007		$	(168,093	)
Equity in the earnings of HEP			2,990
Regular quarterly distributions from HEP			(6,057	)
Consideration received in excess of basis in Crude Pipeline and Tankage Assets			(153,355	)
HEP common units received			9,000
Purchase of additional HEP common units			104
Contribution made to maintain 2% general partner interest			186
Investment in HEP balance at February 29, 2008		$	(315,225	)

As of March 1, 2008, the impact of the reconsolidation of HEP was an increase in cash of $7.3 million, an increase in other current assets of $5.9 million, an increase in property, plant and equipment of $368.2 million, an increase in intangibles and other assets of $56.4 million, an increase in current liabilities of $19.6 million, an increase in long-term debt of $341.4 million, an increase in other long-term liabilities of $0.3 million, an increase in minority interest of $391.7 million and a decrease in distribution in excess of investment in HEP of $315.2 million. These amounts are based on management’s preliminary fair value estimates.

The following tables provide summary financial results for HEP through February 29, 2008, prior to our reconsolidation effective March 1, 2008.

		February 29,				December 31,
		2008				2007
		(In thousands)
Current assets		$	13,177			$	23,178
Properties and equipment, net			272,370				158,600
Transportation agreements and other			129,022				57,126
Total assets		$	414,569			$	238,904
Current liabilities		$	19,561			$	17,732
Long-term liabilities			353,684				182,616
Minority interest			11,055				10,740
Partners’ equity			30,269				27,816
Total liabilities and partners’ equity		$	414,569			$	238,904

		Period From
		January 1, 2008				Three Months
		Through				Ended
		February 29, 2008				March 31, 2007
		(In thousands)
Revenues		$	17,334			$	23,872
Operating costs and expenses			(9,172	)			(13,135	)
Operating income			8,162				10,737
Other expenses, net			(2,344	)			(3,303	)
Net income		$	5,818			$	7,434

We have related party transactions with HEP for pipeline and terminal expenses, certain employee costs, insurance costs and administrative costs under the HEP PTA, HEP IPA and an Omnibus Agreement. Related party transactions prior to our reconsolidation of HEP effective March 1, 2008 are as follows:

	•		Pipeline and terminal expenses paid to HEP were $10.6 million for the period from January 1, 2008 through February 29, 2008 and $13.8 million for the three months ended March 31, 2007.
	•		We charged HEP $0.4 million for the period from January 1, 2008 through February 29, 2008 and $0.5 million for the three months ended March 31, 2007 for general and administrative services under the Omnibus Agreement which we recorded as a reduction in expenses.
	•		HEP reimbursed us for costs of employees supporting their operations of $2.1 million for the period from January 1, 2008 through February 29, 2008 and $2.3 million for the three months ended March 31, 2007, which we recorded as a reduction in expenses.
	•		We reimbursed HEP zero for the period from January 1, 2008 through February 29, 2008 and $0.1 million for the three months ended March 31, 2007 for certain costs paid on our behalf.
	•		We received as regular distributions on our subordinated units, common units and general partner interest, $6.1 million for the period from January 1, 2008 through February 29, 2008 and $5.4 million for the three months ended March 31, 2007. Our distributions for the period from January 1, 2008 through February 29, 2008 and for the three months ended March 31, 2007 included $0.7 million and $0.4 million, respectively, in incentive distributions with respect to our general partner interest.
	•		We had a related party receivable from HEP of $6.0 million at February 29, 2008 and December 31, 2007, respectively.
	•		We had accounts payable to HEP of zero and $5.7 million at February 29, 2008 and December 31, 2007, respectively.

NOTE 3: Earnings Per Share

Basic earnings per share is calculated as income divided by the average number of shares of common stock outstanding. Diluted earnings per share assumes, when dilutive, the issuance of the net incremental shares from stock options, variable restricted shares and performance share units. The following is a reconciliation of the denominators of the basic and diluted per share computations:

		Three Months Ended
		March 31,
		2008				2007
		(In thousands, except per share data)
Net Income		$	8,649			$	67,542
Average number of shares of common stock outstanding			51,165				55,189
Effect of dilutive stock options, variable restricted shares and performance share units		350					1,129
Average number of shares of common stock outstanding assuming dilution		51,515					56,318
Net income per share — basic		$	0.17			$	1.22
Net income per share — diluted		$	0.17			$	1.20

NOTE 4: Stock-Based Compensation

On March 31, 2008 Holly had three principal share-based compensation plans, which are described below. The compensation cost that has been charged against income for those plans was $1.9 million and $4.4 million for the three months ended March 31, 2008 and 2007, respectively. The total income tax benefit recognized in the income statement for share-based compensation arrangements was $0.7 million and $1.5 million for the three months ended March 31, 2008 and 2007, respectively. It is currently our practice to issue new shares for settlement of option exercises, restricted stock grants or performance share units settled in stock. Our current accounting policy for the recognition of compensation expense for awards with pro-rata vesting (substantially all of our awards) is to expense the costs pro-rata over the vesting periods, which results in a higher expense in the earlier periods of the grants. At March 31, 2008, 2,422,269 shares of common stock were reserved for future grants under the current long-term incentive compensation plan, which reservation allows for awards of options, restricted stock, or other performance awards.

Stock Options

Under our Long-Term Incentive Compensation Plan and a previous stock option plan, we have granted stock options to certain officers and other key employees. All the options have been granted at prices equal to the market value of the shares at the time of the grant and normally expire on the tenth anniversary of the grant date. These awards generally vest 20% at the end of each of the five years after the grant date. There have been no options granted since December 2001. The fair value of each option awarded was estimated using the Black-Scholes option pricing model.

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

										Weighted-
						Weighted–				Average				Aggregate
						Average				Remaining				Intrinsic
						Exercise				Contractual				Value
Options		Shares				Price				Term				($000)
Outstanding at January 1, 2008			491,200			$	2.56
Exercised			(76,000	)			3.34
Outstanding at March 31, 2008			415,200			$	2.42				2.7			$	16,896
Exercisable at March 31, 2008			415,200			$	2.42				2.7			$	16,896

The total intrinsic value of options exercised during the three months ended March 31, 2008 and 2007, was $3.1 million and $3.6 million, respectively.

Cash received from option exercises under the stock option plans was $0.3 million for each of the three months ended March 31, 2008 and 2007. The actual tax benefit realized for the tax deductions from option exercises under the stock option plans totaled $1.2 million and $1.4 million for the three months ended March 31, 2008 and 2007, respectively.

Restricted Stock

Under our Long-Term Incentive Compensation Plan, we grant certain officers, other key employees and outside directors restricted stock awards with substantially all awards vesting generally over a period of one to five years. Although ownership of the shares does not transfer to the recipients until after the shares vest, recipients have dividend rights on these shares from the date of grant. The vesting for certain key executives is contingent upon certain earnings per share targets being realized. The fair value of each share of restricted stock awarded, including the shares issued to the key executives, was measured based on the market price as of the date of grant and is being amortized over the respective vesting period.

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

						Weighted–
						Average
						Grant-Date				Aggregate Intrinsic
Restricted Stock		Grants				Fair Value				Value ($000)
Outstanding at January 1, 2008 (non-vested)			298,565			$	27.22
Vesting and transfer of ownership to recipients			(113,196	)			23.53
Granted			68,710				47.19
Forfeited			(279	)			47.75
Outstanding at March 31, 2008 (non-vested)			253,800			$	34.25			$	11,017

The total intrinsic value of restricted stock vested and transferred to recipients during the three months ended March 31, 2008 and 2007 was $4.9 million and $6.4 million, respectively. As of March 31, 2008, there was $4.8 million of total unrecognized compensation cost related to non-vested restricted stock grants. That cost is expected to be recognized over a weighted-average period of 1.3 years. The total fair value of shares vested during the three months ended March 31, 2008 and 2007 was $2.7 million and $1.5 million, respectively.

Performance Share Units

Under our Long-Term Incentive Compensation Plan, we grant certain officers and other key employees performance share units, which are payable in either cash or stock upon meeting certain criteria over the service period, and generally vest over a period of one to three years. Under the terms of our performance share unit grants, awards are subject to either a “financial performance” or a “market performance” criteria.

During the 2008 first quarter, we granted 60,510 performance share units with a fair value based on our grant date closing stock price of $47.47. These units are payable in stock and are subject to certain financial performance criteria.

The fair value of each performance share unit award subject to the financial performance criteria and payable in stock is computed using the grant date closing stock price of each respective award grant and will apply to the number of units ultimately awarded. The number of shares ultimately issued for each award will be based on our

financial performance as compared to peer group companies over the performance period and can range from zero to 200%. As of March 31, 2008, estimated share payouts for outstanding non-vested performance share unit awards ranged from 150% to 200%.

The fair value of each performance share unit award based on market performance criteria and payable in stock is computed based on an expected-cash-flow approach. The analysis utilizes the grant date closing stock price, dividend yield, historical total returns, 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 are 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.

All outstanding performance share unit awards that were payable in cash vested in January 2008.

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

										Financial
		Market Performance								Performance
		Payable in				Stock				Stock				Total
		Cash				Settled				Settled				Performance
Performance Share Units		Grants				Grants				Grants				Share Units
Outstanding at January 1, 2008 (non-vested)			81,450				42,474				116,156				240,080
Vesting and payment of benefit to recipients			(81,450	)			(42,474	)			—				(123,924	)
Granted			—				—				60,510				60,510
Outstanding at March 31, 2008 (non-vested)			—				—				176,666				176,666

For the three months ended March 31, 2008 we paid $6.0 million and issued 84,948 shares of our common stock (representing a 200% share payout) having a fair value of $1.3 million related to vested performance share units. Based on the weighted average fair value at March 31, 2008 of $42.64, there was $0.8 million of total unrecognized compensation cost related to non-vested performance share units. That cost is expected to be recognized over a weighted-average period of 1.5 years.

HEP

On March 31, 2008, HEP had two types of equity-based compensation. The compensation cost charged against HEP’s income for these plans was $0.1 million for the period from March 1, 2008 through March 31, 2008.

Restricted Units

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

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

There were 11,486 restricted units having an intrinsic value of $0.4 million and a fair value of $0.5 million that were vested and transferred to recipients during the three months ended March 31, 2008. As of March 31, 2008, there was $1.1 million of total unrecognized compensation costs related to nonvested restricted unit grants. That cost is expected to be recognized over a weighted-average period of 1.5 years.

Performance Units

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

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

There were 1,514 performance units having an intrinsic value of $0.1 million and a fair value of $0.1 million that were vested and transferred to recipients during the three months ended March 31, 2008. Based on the weighted average fair value at March 31, 2008 of $42.10 there was $1.3 million of total unrecognized compensation cost related to nonvested performance units. That cost is expected to be recognized over a weighted-average period of 1.8 years.

NOTE 5: Cash and Cash Equivalents and Investments in Marketable Securities

Our investment portfolio consists of cash, cash equivalents, and investments in debt securities primarily issued by government entities. In addition, we own 1,000,000 shares of Connacher Oil and Gas Limited common stock.

We invest in highly-rated marketable debt securities, primarily issued by government entities that have maturities at the date of purchase of greater than three months. These securities include investments in variable rate demand notes (“VRDN”). Although VRDN may have long-term stated maturities, generally 15 to 30 years, we have designated these securities as available-for-sale and have classified them as current because we view them as available to support our current operations. Rates on VRDN are typically reset either daily or weekly. VRDN may be liquidated at par on the rate reset date. We also invest in other marketable debt securities with the maximum maturity of any individual issue not greater than two years from the date of purchase. All of these instruments are classified as available-for-sale, and as a result, are reported at fair value. Interest income is recorded as earned. Unrealized gains and losses, net of related income taxes, are temporary and reported as a component of accumulated other comprehensive income. Upon sale, realized gains and losses on the sale of marketable securities are computed based on the specific identification of the underlying cost of the securities sold and the unrealized gains and losses previously reported in other comprehensive income are reclassified to current earnings.

The following is a summary of our available-for-sale securities at March 31, 2008:

		Available-for-Sale Securities
										Estimated
						Gross				Fair Value
						Unrealized				(Net Carrying
		Amortized Cost				Gain (Loss)				Amount)
		(In thousands)
States and political subdivisions		$	252,994			$	1,236			$	254,230
Equity securities			4,328				(1,338	)			2,990
Total marketable securities		$	257,322			$	(102	)		$	257,220

Interest income on our marketable debt securities for the three months ended March 31, 2008 and 2007 included $1.9 million and $1.4 million, respectively, of interest earned, $1.3 million in realized gains and $21,000 in realized losses, respectively, and amortization of $0.9 million and $0.3 million, respectively, in net premiums paid related to our marketable debt securities. For the three months ended March 31, 2008 and 2007 we received a total of $185.8 million and $62.1 million, respectively, related to sales and maturities of our marketable debt securities. Realized gains and losses represent the difference between the purchase price, as amortized, and the market value on the maturity or sales date.

NOTE 6: Environmental Costs

Consistent with our accounting policy for environmental remediation costs, we expensed zero and $0.1 million for the three months ended March 31, 2008 and 2007, respectively, for environmental remediation obligations. The accrued environmental liability reflected in the consolidated balance sheets was $8.1 million and $8.6 million at March 31, 2008 and December 31, 2007, respectively, of which $4.6 million and $5.3 million, respectively, was classified as other long-term liabilities. Costs of future expenditures for environmental remediation are not discounted to their present value.

NOTE 7: Debt

Credit Facilities

In March 2008, we entered into an amended and restated $175.0 million senior secured revolving credit agreement (the “Credit Agreement”) that amends and restates our previous credit agreement in its entirety with Bank of America as administrative agent and lender. The Credit Agreement has a term of five years and an option to increase the facility to $300.0 million subject to certain conditions. This credit facility expires in 2013 and may be used to fund working capital requirements, capital expenditures, acquisitions or other general corporate purposes. We were in compliance with all covenants at March 31, 2008. At March 31, 2008, we had outstanding letters of credit totaling $2.5 million, and no outstanding borrowings under our credit facility. At that level of usage, the unused commitment under our credit facility was $172.5 million at March 31, 2008.

HEP has a $300.0 million senior secured revolving credit agreement (the “HEP Credit Agreement”) with Union Bank of California, N.A. as one of the lenders and as administrative agent and an option to increase the facility to $370.0 million subject to certain conditions. The HEP Credit Facility expires in August 2011 and may be used to fund working capital requirements, capital expenditures, acquisitions or other general partnership purposes.

HEP Senior Notes Due 2015

The HEP senior notes maturing March 1, 2015 are registered with the SEC and bear interest at 6.25% (“HEP Senior Notes”). The HEP 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 HEP Senior Notes are rated

investment grade by both Moody’s and Standard & Poor’s and no default or event of default exists, HEP will not be subject to many of the foregoing covenants. Additionally, HEP has certain redemption rights under the HEP Senior Notes. Navajo Pipeline Co., L.P., one of our subsidiaries, has agreed to indemnify HEP's controlling partner to the extent it makes any payment in satisfaction of $35.0 million of the principal amount of the HEP Senior Notes.

At March 31, 2008, the carrying amount of HEP’s long-term debt was as follows:

		(In thousands)
HEP Credit Agreement		$	181,000
HEP Senior Notes
Principal			185,000
Unamortized discount			(17,543	)
Fair value hedge – interest rate swap			2,959
			170,416
Total debt
Less short-term borrowings under HEP Credit Agreement			10,000
Total long-term debt		$	341,416

Interest Rate Risk Management

As of March 31, 2008, HEP had two interest rate swap contracts.

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

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

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

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

Additional information on HEP’s interest rate swaps are as follows:

Fair Value

Location of Offsetting

Interest Rate Swaps

Balance Sheet Location

(In thousands)

Balance

Cash flow hedge - $171 million LIBOR based debt

Other long-term liabilities

$

4,349

Accumulated other comprehensive loss

Fair value hedge – $60 million of 6.25% Senior Notes

Other assets

$

2,959

Long-term debt

NOTE 8: Income Taxes

Our effective tax rates for the first quarter of 2008 and 2007 were 35.2% and 33.9%, respectively. We realized a lower effective tax rate during the first quarter of 2007 due principally to the utilization of low sulfur diesel fuel production tax credits.

NOTE 9: Stockholders’ Equity

Common Stock Repurchases: Under our common stock repurchase program, common stock repurchases are being made from time to time in the open market or privately negotiated transactions based on market conditions, securities law limitations and other factors. During the three months ended March 31, 2008, we repurchased 2,125,627 shares at a cost of $94.9 million (of which $6.0 million of the cash settlement was after March 31, 2008) or an average of $44.64 per share. Since inception of our common stock repurchase initiative beginning in May 2005 through March 31, 2008, we have repurchased 15,656,533 shares at a cost of approximately $613.0 million or an average of $39.15 per share.

During the three months ended March 31, 2008, we repurchased at current market price from certain officers and key employees 39,684 shares of our common stock at a cost of approximately $2.0 million. These purchases were made under the terms of restricted stock and performance share unit agreements to provide funds for the payment of payroll and income taxes due at the vesting of restricted shares in the case of officers and employees who did not elect to satisfy such taxes by other means.

NOTE 10: Other Comprehensive Income

The components and allocated tax effects of other comprehensive loss are as follows:

						Tax Expense
		Before-Tax				(Benefit)				After-Tax
		(In thousands)
For the three months ended March 31, 2008
Unrealized loss on available-for-sale securities		$	(481	)		$	(187	)		$	(294	)
Unrealized loss on HEP cash flow hedge, net of minority interest			(1,990	)			(698	)			(1,292	)
Other comprehensive loss		$	(2,471	)		$	(885	)		$	(1,586	)
For the three months ended March 31, 2007
Retirement medical obligation adjustment		$	(2,792	)		$	(1,086	)		$	(1,706	)
Unrealized gain on available-for-sale securities			357				137				220
Other comprehensive loss		$	(2,435	)		$	(949	)		$	(1,486	)

The temporary unrealized gain (loss) on securities available for sale is due to changes in market prices of securities.

Accumulated other comprehensive loss in the equity section of our consolidated balance sheets includes:

		March 31,				December 31,
		2008				2007
		(In thousands)
Pension obligation adjustment		$	(16,228	)		$	(16,228	)
Retiree medical obligation adjustment			(3,078	)			(3,078	)
Unrealized gain (loss) on available-for-sale securities			(64	)			230
Unrealized loss on HEP cash flow hedge, net of minority interest			(1,292	)			—
Accumulated other comprehensive loss		$	(20,662	)		$	(19,076	)

NOTE 11: Retirement Plan

We have a non-contributory defined benefit retirement plan that covers most of our employees who were hired prior to January 1, 2007. Our policy is to make contributions annually of not less than the minimum funding requirements of the Employee Retirement Income Security Act of 1974. Benefits are based on the employee’s years of service and compensation.

Effective January 1, 2007, the retirement plan was frozen to new employees not covered by collective bargaining agreements with labor unions. To the extent an employee was hired prior to January 1, 2007, and elected to participate in automatic contributions features under our defined contribution plan, their participation in future benefits of the retirement plan was frozen.

The net periodic pension expense consisted of the following components:

		Three Months Ended
		March 31,
		2008				2007
		(In thousands)
Service cost		$	1,090			$	1,589
Interest cost			1,193				1,404
Expected return on assets			(1,144	)			(1,566	)
Amortization of prior service cost			98				63
Amortization of net loss			351				284
Net periodic benefit cost		$	1,588			$	1,774

The expected long-term annual rate of return on plan assets is 8.5%. This rate was used in measuring 2008 and 2007 net periodic benefit cost. We expect to contribute between zero and $10.0 million to the retirement plan during 2008. No contributions were made during the three months ended March 31, 2008.

NOTE 12: Contingencies

On May 29, 2007, the United States Court of Appeals for the District of Columbia Circuit (“Court of Appeals”) issued its decision on petitions for review, brought by us and other parties, concerning rulings by the Federal Energy Regulatory Commission (“FERC”) in proceedings brought by us and other parties against SFPP. These proceedings relate to tariffs of common carrier pipelines, which are owned and operated by SFPP, for shipments of refined products from El Paso, Texas to Tucson and Phoenix, Arizona and from points in California to points in Arizona. We are one of several refiners that regularly utilize the SFPP pipeline to ship refined products from El Paso, Texas to Tucson and Phoenix, Arizona. The Court of Appeals in its May 29, 2007 decision approved a FERC position, which is adverse to us, on the treatment of income taxes in the calculation of allowable rates for pipelines operated by partnerships and ruled in our favor on an issue relating to our rights to reparations when it is determined that certain tariffs we paid to SFPP in the past were too high. We currently estimate that, as a result of this decision and

prior rulings by the Court of Appeals and the FERC in these proceedings, a net amount will be due from SFPP to us for the period January 1992 through May 2006 in addition to the $15.3 million we received in 2003 from SFPP as reparations for the period from 1992 through July 2000. Because proceedings in the FERC following the Court of Appeals decision have not been completed and final action by the FERC could be subject to further court proceedings, it is not possible at this time to determine what will be the net amount payable to us at the conclusion of these proceedings. We and other shippers have been engaged in settlement discussions with SFPP on remaining issues in the FERC proceedings. These discussions resulted in a partial settlement, which became final in February 2008, providing for a payment to us of approximately $1.3 million with respect to our shipments from El Paso to Tucson and Phoenix for the period from June 1, 2006 through November 30, 2007. This amount was recorded in revenue for the quarter ended March 31, 2008 and was received in early April 2008. The partial settlement leaves for resolution in pending proceedings all remaining issues for other periods.

In discussions beginning in the last half of 2005, the EPA and the State of Utah have asserted that we have Federal CAA liabilities relating to our Woods Cross Refinery because of actions taken or not taken by prior owners of the Woods Cross Refinery, which we purchased from ConocoPhillips in June 2003. We have entered into an agreement, in the form of a Consent Decree, to settle this matter with the EPA and the State of Utah. The agreement, which has been signed by the parties and lodged with the federal district court in Utah, but which has not yet been entered by the court, includes obligations for us to make specified additional capital investments currently estimated to total approximately $17.0 million over several years and to make changes in operating procedures at the refinery. The agreement also requires expenditures by us totaling $250,000 for penalties and a supplemental environmental project of benefit of the community in which the Woods Cross Refinery is located. The agreements for the purchase of the Woods Cross Refinery provide that ConocoPhillips will indemnify us, subject to specified limitations, for environmental claims arising from circumstances prior to our purchase of the refinery. We believe that, in the present circumstances, the amount due to us from ConocoPhillips under the agreements for the purchase of the Woods Cross Refinery would be approximately $1.4 million with respect to the Consent Decree settlement.

In December 2006, the Montana Department of Environmental Quality (“MDEQ”) filed in state district court in Great Falls, Montana a Complaint and Application for Preliminary Injunction (the “Complaint”) naming as defendants Montana Refining Company (“MRC”), our subsidiary that owned the Great Falls, Montana refinery until it was sold to an unrelated purchaser in March 2006, and the unrelated company that purchased the refinery from MRC. The MDEQ asserts in the Complaint that the Great Falls refinery exceeded limitations on sulfur dioxide in the refinery’s air emission permit on certain dates in 2004 and 2005 and in 2006 both before and after the sale of the refinery, erroneously certified compliance with limitations on sulfur dioxide emissions, failed to promptly report emissions limit deviations, exceeded limits on sulfur in fuel gas on specified dates in 2005, failed in 2005 to conduct timely testing for certain emissions, submitted late a report required to be submitted in early 2006, failed to achieve a specified limitation on certain emissions in the first three quarters of 2006, and failed to timely submit a report on a 2005 emissions test. The Complaint sought penalties under applicable law of up to $10,000 per violation and an order enjoining MRC and the current owner of the refinery from further violations. We and the current owner of the Great Falls refinery have negotiated with MDEQ a settlement and an administrative order on consent (AOC) is being circulated for signatures. The agreement requires certain actions to be taken by the refinery and payment of a $105,000 penalty. MDEQ has agreed to dismiss the lawsuit within 10 days of execution of the AOC. We expect to pay to the current owner our appropriate share, which has not yet been finally agreed, of penalty and related amounts with respect to this matter.

We are a party to various other litigation and proceedings not mentioned in this report which we believe, based on advice of counsel, will not either individually or in the aggregate have a materially adverse impact on our financial condition, results of operations or cash flows.

NOTE 13: Segment Information

Our operations are currently organized into two reportable segments, Refining and HEP. Our operations that are not included in the Refining and HEP segments are included in Corporate and Other and includes the operations of Holly Corporation, our parent company, and a small-scale oil and gas exploration and production program.

The Refining segment includes the operations of our Navajo Refinery, Woods Cross Refinery and Holly Asphalt Company. The Refining segment involves the purchase and refining of crude oil and wholesale and branded marketing of refined products, such as gasoline, diesel fuel and jet fuel, and includes our Navajo Refinery and Woods Cross Refinery. The petroleum products produced by the Refining segment are marketed in Texas, New Mexico, Arizona, Utah, Wyoming, Idaho, Washington and northern Mexico. The Refining segment also includes Holly Asphalt Company which manufactures and markets asphalt and asphalt products in Arizona, New Mexico, Texas and northern Mexico.

HEP is a variable interest entity (“VIE”) as defined under FIN No. 46. Under the provisions of FIN No. 46, HEP’s purchase of the Crude Pipelines and Tankage Assets qualifies as a reconsideration event whereby we reassessed our beneficial interest in HEP. Following this transaction, we determined that our beneficial interest in HEP exceeds 50%. Accordingly, we reconsolidated HEP effective March 1, 2008 and no longer account for our investment in HEP under the equity method of accounting.

The HEP segment involves all of the operations of HEP effective March 1, 2008 (date of reconsolidation). HEP owns and operates a system of petroleum product and crude gathering pipelines in Texas, New Mexico, Oklahoma and Utah, distribution terminals in Texas, New Mexico, Arizona, Utah, Idaho, and Washington and refinery tankage in New Mexico and Utah. Revenues are generated by charging tariffs for transporting petroleum products and crude oil through their pipelines and by charging fees for terminalling petroleum products and other hydrocarbons, and storing and providing other services at their storage tanks and terminals. The HEP segment also included a 70% interest in Rio Grande which provides petroleum products transportation services. Revenues from the HEP segment are earned through transactions with unaffiliated parties for pipeline transportation, rental and terminalling operations as well as revenues relating to pipeline transportation services provided for our refining operations and from HEP’s interest in Rio Grande. Our preliminary revaluation of HEP’s assets and liabilities at March 31, 2008 (date of reconsolidation) resulted in basis adjustments to our consolidated HEP balances. Therefore, our reported amounts for the HEP segment may not agree to amounts reported in HEP’s periodic public filings.

The accounting policies for our segments are the same as those described in the summary of significant accounting policies in our Annual Report on Form 10-K for the year ended December 31, 2008.

														Consolidations
										Corporate				and				Consolidated
		Refining				HEP				and Other				Eliminations				Total
		(In thousands)
Three Months Ended March 31, 2008
Sales and other revenues		$	1,477,376			$	9,942			$	401			$	(7,735	)		$	1,479,984
Operating expenses		$	57,216			$	3,676			$	—			$	(184	)		$	60,708
General and administrative expenses		$	7			$	522			$	12,303			$	—			$	12,832
Depreciation and amortization		$	10,281			$	2,010			$	1,018			$	—			$	13,309
Income (loss) from operations		$	18,884			$	3,734			$	(13,025	)		$	—			$	9,593
Cash, cash equivalents and investments in marketable securities		$	—			$	8,237			$	429,534			$	—			$	437,771
Total assets		$	1,375,843			$	447,472			$	467,845			$	(14,438	)		$	2,276,722
Total debt		$	—			$	351,416			$	—			$	—			$	351,416
Three Months Ended March 31, 2007
Sales and other revenues		$	925,582			$	—			$	391			$	(106	)		$	925,867
Operating expenses		$	50,118			$	—			$	11			$	—			$	50,129
General and administrative expenses		$	3			$	—			$	15,844			$	—			$	15,847
Depreciation and amortization		$	11,026			$	—			$	425			$	—			$	11,451
Income (loss) from operations		$	112,615			$	—			$	(16,041	)		$	—			$	96,574
Cash, cash equivalents and investments in marketable securities		$	—			$	—			$	280,397			$	—			$	280,397
Total assets		$	922,003			$	—			$	325,039			$	—			$	1,247,042
Total debt		$	—			$	—			$	—			$	—			$	—

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

This Item 2 contains “forward-looking” statements. See “Forward-Looking Statements” at the beginning of Part I of this Quarterly Report on Form 10-Q. In this document, the words “we”, “our” and “us” refer only to Holly Corporation and its consolidated subsidiaries or to Holly Corporation or an individual subsidiary and not to any other person.

OVERVIEW

We are principally an independent petroleum refiner operating two refineries in Artesia and Lovington, New Mexico (operated as one refinery and collectively known as the “Navajo Refinery”) and Woods Cross, Utah (the “Woods Cross Refinery”). Our profitability depends largely on the spread between market prices for refined petroleum products and crude oil prices. At March 31, 2008, we also owned a 46% interest in Holly Energy Partners, L.P. (“HEP”), which owns and operates pipeline and terminalling assets and owns a 70% interest in Rio Grande Pipeline Company (“Rio Grande”).

Our principal source of revenue is from the sale of high value light products such as gasoline, diesel fuel and jet fuel in markets in the southwestern and western United States. Our sales and other revenues for the three months ended March 31, 2008 were $1,480.0 million and our net income for the three months ended March 31, 2008 was $8.6 million. Our sales and other revenues and net income for the three months ended March 31, 2007 were $925.9 million and $67.5 million, respectively. Our principal expenses are costs of products sold and operating expenses. Our total operating costs and expenses for the three months ended March 31, 2008 were $1,470.4 million, an increase from $829.3 million for the three months ended March 31, 2007.

On February 29, 2008, we closed on the sale of certain crude pipelines and tankage assets (the “Crude Pipelines and Tankage Assets”) to HEP for $180.0 million. The assets consisted of crude oil trunk lines that deliver crude oil to our Navajo Refinery in southeast New Mexico, gathering and connection pipelines located in west Texas and New Mexico, on-site crude tankage located within the Navajo and Woods Cross Refinery complexes, a jet fuel products pipeline and leased terminal between Artesia and Roswell, New Mexico, and crude oil and product pipelines that support our Woods Cross Refinery. Consideration received consisted of $171.0 million in cash and 217,497 HEP common units having a value of $9.0 million.

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

HEP is a variable interest entity (“VIE”) as defined under FIN No. 46. Under the provisions of FIN No. 46, HEP’s purchase of the Crude Pipelines and Tankage Assets qualifies as a reconsideration event whereby we reassessed our beneficial interest in HEP. Following this transaction, we determined that our beneficial interest in HEP exceeds 50%. Accordingly, we reconsolidated HEP effective March 1, 2008 and no longer account for our investment in HEP under the equity method of accounting.

Under our common stock repurchase program, common stock repurchases are being made from time to time in the open market or privately negotiated transactions based on market conditions, securities law limitations and other factors. During the three months ended March 31, 2008, we repurchased 2,125,627 shares at a cost of $94.9 million (of which $6.0 million of the cash settlement was after March 31, 2008) or an average of $44.64 per share. Since inception of our common stock repurchase initiative beginning in May 2005 through March 31, 2008, we have repurchased 15,656,533 shares at a cost of approximately $613.0 million or an average of $39.15 per share.

RESULTS OF OPERATIONS

Financial Data (Unaudited)

		Three Months Ended
		March 31,								Change from 2007
		2008				2007				Change				Percent
		(In thousands, except per share data)
Sales and other revenues		$	1,479,984			$	925,867			$	554,117				59.8	%
Operating costs and expenses:
Cost of products sold (exclusive of depreciation, depletion and amortization)			1,383,437				751,714				631,723				84.0
Operating expenses (exclusive of depreciation, depletion and amortization)			60,708				50,129				10,579				21.1
General and administrative expenses (exclusive of depreciation, depletion and amortization)			12,832				15,847				(3,015	)			(19.0	)
Depreciation, depletion and amortization			13,309				11,451				1,858				16.2
Exploration expenses, including dry holes			105				152				(47	)			(30.9	)
Total operating costs and expenses			1,470,391				829,293				641,098				77.3
Income from operations			9,593				96,574				(86,981	)			(90.1	)
Other income (expense):
Equity in earnings of HEP			2,990				3,346				(356	)			(10.6	)
Minority interest in earnings of HEP			(802	)			—				(802	)			(100.0	)
Interest income			3,555				2,560				995				38.9
Interest expense			(1,992	)			(252	)			(1,740	)			(690.5	)
			3,751				5,654				(1,903	)			(33.7	)
Income from operations before income taxes			13,344				102,228				(88,884	)			(86.9	)
Income tax provision			4,695				34,686				(29,991	)			(86.5	)
Net income		$	8,649			$	67,542			$	(58,893	)			(87.2	)
Net income per share — basic		$	0.17			$	1.22			$	(1.05	)			(86.1	)%
Net income per share — diluted		$	0.17			$	1.20			$	(1.03	)			(85.8	)%
Cash dividends declared per common share		$	0.15			$	0.10			$	0.05				50.0	%
Average number of common shares outstanding:
Basic			51,165				55,189				(4,024	)			(7.3	)%
Diluted			51,515				56,318			(4,803		)		(8.5		)%

Balance Sheet Data (Unaudited)

		March 31,				December 31,
		2008				2007
		(In thousands)
Cash, cash equivalents and investments in marketable securities		$	437,771			$	329,784
Working capital		$	255,259			$	216,541
Total assets		$	2,276,722			$	1,663,945
Long-term debt — HEP		$	341,416			$	—
Stockholders’ equity		$	500,033			$	593,794

Other Financial Data (Unaudited)

		Three Months Ended
		March 31,
		2008				2007
		(In thousands)
Net cash provided by operating activities		$	98,850			$	86,301
Net cash used for investing activities		$	83,459			$	(53,775	)
Net cash used for financing activities		$	(96,127	)		$	(35,464	)
Capital expenditures		$	72,761			$	26,750
EBITDA (1)		$	25,090			$	111,371

Our operations are currently organized into two reportable segments, Refining and HEP. Our operations that are not included in the Refining and HEP segment are included in Corporate and Other and includes the operations of Holly Corporation, our parent company, and a small-scale oil and gas exploration and production program.

		Three Months Ended
		March 31,
		2008				2007
		(In thousands)
Sales and other revenues
Refining(1)		$	1,477,376			$	925,582
HEP(2)			9,942				—
Corporate and Other			401				391
Consolidations and Eliminations			(7,735	)			(106	)
Consolidated		$	1,479,984			$	925,867
Operating Income (loss)
Refining(1)		$	18,884			$	112,615
HEP(2)			3,788				—
Corporate and Other			(13,025	)			(16,041	)
Consolidations and Eliminations			(54	)			—
Consolidated		$	9,593			$	96,574

Refining Operating Data (Unaudited)

Our refinery operations include the Navajo Refinery and the Woods Cross Refinery. The following tables set forth information, including non-GAAP performance measures about our consolidated refinery operations. The cost of products and refinery gross margin do not include the effect of depreciation, depletion and amortization. Reconciliations to amounts reported under GAAP are provided under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 3 of Part I of this Form 10-Q.

		Three Months Ended
		March 31,
		2008				2007
Navajo Refinery
Crude charge (BPD) (1)			83,200				76,820
Refinery production (BPD) (2)			94,640				86,100
Sales of produced refined products (BPD)			94,050				85,390
Sales of refined products (BPD) (3)			105,410				96,360
Refinery utilization (4)			97.9	%			92.6	%
Average per produced barrel (5)
Net sales		$	103.26			$	75.58
Cost of products(6)			96.83				59.04
Refinery gross margin			6.43				16.54
Refinery operating expenses (7)			4.39				4.18
Net operating margin		$	2.04			$	12.36
Feedstocks:
Sour crude oil			80	%			75	%
Sweet crude oil			8	%			10	%
Other feedstocks and blends			12	%			15	%
Total			100	%			100	%
Sales of produced refined products:
Gasolines			58	%			61	%
Diesel fuels			32	%			27	%
Jet fuels			1	%			3	%
Fuel oil			3	%			3	%
Asphalt			3	%			3	%
LPG and other			3	%			3	%
Total			100	%			100	%

		Three Months Ended
		March 31,
		2008				2007
Woods Cross Refinery
Crude charge (BPD) (1)			24,960				24,650
Refinery production (BPD) (2)			25,440				26,570
Sales of produced refined products (BPD)			25,300				28,120
Sales of refined products (BPD) (3)			27,530				28,550
Refinery utilization (4)			96.0	%			94.8	%
Average per produced barrel (5)
Net sales		$	102.96			$	71.61
Cost of products(6)			90.42				56.87
Refinery gross margin			12.54				14.74
Refinery operating expenses (7)			6.26				4.76
Net operating margin		$	6.28			$	9.98
Feedstocks:
Sour crude oil			3	%			—	%
Sweet crude oil			92	%			91	%
Other feedstocks and blends			5	%			9	%
Total			100	%			100	%
Sales of produced refined products:
Gasolines			68	%			63	%
Diesel fuels			23	%			25	%
Jet fuels			—	%			2	%
Fuel oil			5	%			6	%
LPG and other			4	%			4	%
Total			100	%			100	%
Consolidated
Crude charge (BPD) (1)			108,160				101,470
Refinery production (BPD) (2)			120,080				112,670
Sales of produced refined products (BPD)			119,350				113,510
Sales of refined products (BPD) (3)			132,940				124,910
Refinery utilization (4)			97.4	%			93.1	%
Average per produced barrel (5)
Net sales		$	103.20			$	74.59
Cost of products(6)			95.48				58.50
Refinery gross margin			7.72				16.09
Refinery operating expenses (7)			4.78				4.32
Net operating margin		$	2.94			$	11.77
Feedstocks:
Sour crude oil			64	%			58	%
Sweet crude oil			26	%			28	%
Other feedstocks and blends			10	%			14	%
Total			100	%			100	%