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 September 30, 2006

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 incorporation or organization)		(I.R.S. Employer Identification No.)
100 Crescent Court, Suite 1600 Dallas, Texas		75201-6915
(Address of principal executive offices)		(Zip Code)
(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. Yes þ No o

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

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

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

56,144,479 shares of Common Stock, par value $.01 per share, were outstanding on October 31, 2006.

 

 

HOLLY CORPORATION
INDEX

		Page
PART I. FINANCIAL INFORMATION
Forward-Looking Statements			3
Definitions			4
Item 1. Financial Statements
Consolidated Balance Sheets September 30, 2006 (Unaudited) and December 31, 2005			6
Consolidated Statements of Income (Unaudited) Three Months and Nine Months Ended September 30, 2006 and 2005			7
Consolidated Statements of Cash Flows (Unaudited) Nine Months Ended September 30, 2006 and 2005			8
Consolidated Statements of Comprehensive Income (Unaudited) Three Months and Nine Months Ended September 30, 2006 and 2005			9
Notes to Consolidated Financial Statements (Unaudited)			10
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			26
Item 3. Quantitative and Qualitative Disclosures About Market Risk			45
Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles			45
Item 4. Controls and Procedures			51
PART II. OTHER INFORMATION
Item 1. Legal Proceedings			52
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			54
Item 6. Exhibits			55
Signatures			56
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 throughout this document 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 “Additional Factors that May Affect Future Results” (including “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 or pipeline or terminal 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, 2005 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 fractionated directly from crude oil to high octane gasoline blendstock and hydrogen. The hydrogen produced from the reforming process is used to desulfurize other refinery oils and is the main 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 the breaking down of large, complex hydrocarbon molecules into smaller, more useful ones by the application of heat, pressure and a chemical (catalyst) to speed the process.

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

     “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 converting C5/C6 gasoline compounds into their isomers, i.e., rearranging the structure of the molecules without changing their size or chemical composition.

     “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.

     “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.

     “Refining gross margin” or “refinery gross margin” means the difference between average net sales price and average costs of products per barrel of produced refined products. This margin does not include the effect of 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.

     “Solvent deasphalter / residuum oil supercritical extraction (“ROSE”)” means a refinery process 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 equal to or greater than 0.4 percent by weight, while “sweet crude oil” means crude oil containing quantities of sulfur 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

(In thousands, except share data)

		September 30,				December 31,
		2006				2005
		(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	194,628			$	49,064
Marketable securities			91,755				189,978
Accounts receivable: Product and transportation			175,042				145,736
Crude oil resales			222,209				254,734
Related party receivable			2,519				1,434
			399,770				401,904
Inventories:                Crude oil and refined products			90,584				91,257
Materials and supplies			13,713				12,082
			104,297				103,339
Income taxes receivable			725				—
Prepayments and other			28,715				14,639
Assets of discontinued operations			624				30,612
Total current assets			820,514				789,536
Properties, plants and equipment, at cost			611,902				532,641
Less accumulated depreciation, depletion and amortization			(229,010	)			(216,502	)
			382,892				316,139
Marketable securities (long-term)			4,074				15,800
Other assets:                   Turnaround costs (long-term)			6,351				7,309
Intangibles and other			14,961				14,116
			21,312				21,425
Total assets		$	1,228,792			$	1,142,900
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	516,810			$	518,584
Accrued liabilities			45,506				41,235
Income taxes payable			—				5,538
Liabilities of discontinued operations			4,237				14,076
Total current liabilities			566,553				579,433
Deferred income taxes			22,122				9,989
Other long-term liabilities			13,678				19,101
Commitments and contingencies			—				—
Distributions in excess of investment in Holly Energy Partners			163,701				157,026
Stockholders’ equity:
Preferred stock, $1.00 par value – 1,000,000 shares authorized; none issued			—				—
Common stock $.01 par value – 100,000,000 and 50,000,000 shares authorized; 71,747,560 and 35,378,646 shares issued as of September 30, 2006 and December 31, 2005, respectively			717				354
Additional capital			63,180				43,344
Retained earnings			702,760				495,819
Accumulated other comprehensive loss			(5,183	)			(4,802	)
Common stock held in treasury, at cost – 15,793,926 and 6,002,175 shares as of September 30, 2006 and December 31, 2005, respectively			(298,736	)			(157,364	)
Total stockholders’ equity			462,738				377,351
Total liabilities and stockholders’ equity		$	1,228,792			$	1,142,900

See accompanying notes.

HOLLY CORPORATION

(Unaudited)

(In thousands, except per share data)

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2006				2005				2006				2005
Sales and other revenues		$	1,172,693			$	880,520			$	3,085,127			$	2,233,895
Operating costs and expenses:
Cost of products sold (exclusive of depreciation, depletion and amortization)			979,309				725,286				2,562,803				1,828,632
Operating expenses (exclusive of depreciation, depletion and amortization)			54,146				42,287				155,705				132,031
General and administrative expenses (exclusive of depreciation, depletion and amortization)			12,566				12,619				44,813				35,527
Depreciation, depletion and amortization			9,480				8,549				28,187				31,896
Exploration expenses, including dry holes			102				69				329				310
Total operating costs and expenses			1,055,603				788,810				2,791,837				2,028,396
Income from operations			117,090				91,710				293,290				205,499
Other income (expense):
Equity in loss of joint ventures			—				—				—				(685	)
Equity in earnings of Holly Energy Partners			3,596				3,296				8,324				3,296
Minority interests in income of partnerships			—				—				—				(6,721	)
Interest income			2,747				1,202				6,890				4,455
Interest expense			(268	)			(501	)			(815	)			(4,706	)
			6,075				3,997				14,399				(4,361	)
Income from continuing operations before income taxes			123,165				95,707				307,689				201,138
Income tax provision:
Current			37,918				36,360				101,762				75,385
Deferred			6,046				(670	)			7,837				217
			43,964				35,690				109,599				75,602
Income from continuing operations before cumulative change in accounting principle			79,201				60,017				198,090				125,536
Cumulative effect of accounting change (net of income tax expense of $426)			—				669				—				669
Income from continuing operations			79,201				60,686				198,090				126,205
Discontinued operations
Income from discontinued operations			21				1,033				7,012				1,572
Gain (loss) on sale of discontinued operations			(220	)			—				13,805				—
Income (loss) from discontinued operations, net of taxes			(199	)			1,033				20,817				1,572
Net income		$	79,002			$	61,719			$	218,907			$	127,777
Basic earnings per share:
Continuing operations		$	1.40			$	0.99			$	3.45			$	2.02
Discontinued operations			—				0.02				0.36				0.02
Net income		$	1.40			$	1.01			$	3.81			$	2.04
Diluted earnings per share:
Continuing operations		$	1.37			$	0.97			$	3.38			$	1.97
Discontinued operations			—				0.01				0.35				0.03
Net income		$	1.37			$	0.98			$	3.73			$	2.00
Cash dividends declared per common share		$	0.08			$	0.05			$	0.21			$	0.14
Average number of common shares outstanding:
Basic			56,555				61,236				57,393				62,506
Diluted			57,783				62,772				58,643				63,960

See accompanying notes.

HOLLY CORPORATION

(Unaudited)

(In thousands)

		Nine Months Ended
		September 30,
		2006				2005
Cash flows from operating activities:
Net income		$	218,907			$	127,777
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization (includes discontinued operations)			28,737				34,336
Deferred income taxes (includes discontinued operations)			5,395				131
Minority interests in income of partnerships			—				6,721
Distributions in excess of equity in earnings of HEP and joint ventures			6,675				1,706
Equity based compensation expense			3,883				1,608
Gain on sale of assets, before income taxes			(22,004	)			—
(Increase) decrease in current assets:
Accounts receivable			13,531				(199,045	)
Inventories			(8,414	)			(1,336	)
Income taxes receivable			(725	)			10,735
Prepayments and other			(10,744	)			(10	)
Increase (decrease) in current liabilities:
Accounts payable			(17,295	)			166,589
Accrued liabilities			9,431				(1,026	)
Income taxes payable			(5,354	)			18,964
Turnaround expenditures			(7,122	)			(1,038	)
Other, net			(6,630	)			(3,236	)
Net cash provided by operating activities			208,271				162,876
Cash flows from investing activities:
Additions to properties, plants and equipment			(89,182	)			(58,062	)
Net cash proceeds from sale of Montana Refinery			48,872				—
Acquisition by HEP of pipeline and terminal assets			—				(121,853	)
Decrease in cash due to deconsolidation of HEP			—				(20,447	)
Purchase of additional interest in joint venture, net of cash			—				(18,506	)
Proceeds from sale of partial interest in joint venture			—				832
Purchases of marketable securities			(172,291	)			(254,801	)
Sales and maturities of marketable securities			285,943				209,371
Net cash provided by (used for) investing activities			73,342				(263,466	)
Cash flows from financing activities:
Proceeds from issuance of Holly Energy Partners’:
Senior notes, net of underwriter discount			—				181,955
Common units, net of offering costs			—				43,788
Net decrease in borrowings under revolving credit agreements			—				(25,000	)
Debt issuance costs			—				(948	)
Issuance of common stock upon exercise of options			2,424				2,736
Purchase of treasury stock			(138,369	)			(80,899	)
Cash dividends			(10,475	)			(8,232	)
Cash distributions to minority interests			—				(9,486	)
Excess tax benefit from equity based compensation			10,371				5,525
Net cash provided by (used for) financing activities			(136,049	)			109,439
Cash and cash equivalents:
Increase for the period			145,564				8,849
Beginning of period			49,064				67,460
End of period		$	194,628			$	76,309
Supplemental disclosure of cash flow information:
Cash paid during the period for
Interest		$	510			$	1,486
Income taxes		$	112,274			$	40,569

See accompanying notes.

HOLLY CORPORATION

(Unaudited)

(In thousands)

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2006				2005				2006				2005
Net income		$	79,002			$	61,719			$	218,907			$	127,777
Other comprehensive income (loss):
Securities available for sale:
Unrealized gain (loss) on available for sale securities			(332	)			131				(531	)			106
Reclassification adjustment to net income on sale of equity securities			(84	)			—				(94	)			—
Total unrealized gain (loss) on available for sale securities			(416	)			131				(625	)			106
Income tax expense (benefit)			(163	)			51				(244	)			41
Other comprehensive income (loss)			(253	)			80				(381	)			65
Total comprehensive income		$	78,749			$	61,799			$	218,526			$	127,842

See accompanying notes.

HOLLY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

     As of the close of business on September 30, 2006, 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;
	•		owned approximately 800 miles of crude oil pipelines located principally in West Texas and New Mexico;
	•		owned 100% of NK Asphalt Partners which manufactures and markets asphalt products from various terminals in Arizona and New Mexico; and
	•		owned a 45.0% interest in Holly Energy Partners, L.P. (“HEP”), which owns logistic assets including approximately 1,600 miles of petroleum product pipelines located in Texas, New Mexico and Oklahoma (including 340 miles of leased pipeline); eleven 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 March 31, 2006 we sold our petroleum refinery in Great Falls, Montana (the “Montana Refinery”) to a subsidiary of Connacher Oil and Gas Limited (“Connacher”). Accordingly, the results of operations of the Montana Refinery and a gain of $13.8 million on the sale are shown in discontinued operations (see Note 2).

On July 8, 2005, we closed on a transaction for HEP to acquire our two 65-mile parallel intermediate feedstock pipelines which connect our Lovington and Artesia, New Mexico facilities. Under the provision of the Financial Accounting Standards Board (“FASB”) Interpretation No. 46 (revised) (“FIN 46”) “Consolidation of Variable Interest Entities,” we have deconsolidated HEP effective July 1, 2005. The deconsolidation is being presented from July 1, 2005 forward (see Note 3).

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 September 30, 2006, the consolidated results of operations and comprehensive income for the three months and nine months ended September 30, 2006 and 2005 and consolidated cash flows for the nine months ended September 30, 2006 and 2005 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, 2005 filed with the SEC.

We use the last-in, first-out (“LIFO”) method of valuing inventory. An actual valuation of inventory under the LIFO method can be made only 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 nine months of 2006 are not necessarily indicative of the results to be expected for the full year. Certain reclassifications, which we determined to be immaterial, have been made to prior reported amounts to conform to current classifications. Due to the sale of the Montana Refinery, we reclassified certain amounts previously reported and now report such amounts as from discontinued operations.

HOLLY CORPORATION

Our operations are currently organized into one business division, Refining. The Refining business division includes the Navajo Refinery, Woods Cross Refinery and NK Asphalt Partners. We previously included the Montana Refinery in the Refining division, and the results from the Montana Refinery are now reported in discontinued operations. Prior to our deconsolidation of HEP on July 1, 2005 our operations were organized into two business divisions, which were Refining and HEP. Our operations that are not included in either the Refining or HEP (prior to its deconsolidation) business divisions include the operations of Holly Corporation, the parent company, a small-scale oil and gas exploration and production program, and prior to the deconsolidation of HEP, the elimination of the revenue and costs associated with HEP’s pipeline transportation services for us as well as the recognition of the minority interests’ income of HEP.

New Accounting Pronouncements

SFAS No. 151 “Inventory Costs, an amendment of ARB No. 43, Chapter 4”

In December 2004, the FASB issued SFAS No. 151, “Inventory Costs, an Amendment of ARB No. 43, Chapter 4.” This amendment requires abnormal amounts of idle facility expense, freight, handling costs and wasted materials (spoilage) to be recognized as current-period charges. This standard also requires that the allocation of fixed production overhead to the cost of conversion be based on the normal capacity of the production facilities. This standard is effective for fiscal years beginning after June 15, 2005. We adopted the standard effective January 1, 2006. The adoption of this standard did not have a material effect on our financial condition, results of operations or cash flows.

EITF No. 04-13 “Accounting for Purchases and Sales of Inventory with the Same Counterparty”

The Emerging Issues Task Force reached a consensus on Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty,” and the FASB ratified it in September 2005. This standard addresses accounting matters that arise when one company both sells inventory to and buys inventory from another company in the same line of business, specifically, when it is appropriate to measure purchases and sales of inventory at fair value and record them in cost of sales and revenues and when purchases and sales should be recorded as an exchange measured at the book value of the item sold. The consensus in this standard is to be applied to new arrangements entered into in reporting periods beginning after March 15, 2006. We adopted this standard effective April 1, 2006 and no longer account for certain crude oil transactions on a net basis.

With respect to supplying crude oil to our refineries, crude oil is often purchased in locations distant from our refineries and exchanged for crude oil that is transportable to our refineries. These buy/sell exchanges are done in contemplation of one another and allow us to receive the optimal crude blend and quantities at our refineries. All of the crude oil buy/sell transactions done in supplying crude oil to our refineries are recorded as exchanges with the net differential reflected in costs of sales. We also purchase crude oil from producers and other petroleum companies in excess of the needs of our refineries for resale to other purchasers or users of crude oil. With respect to these resales that are in the form of buy/sell exchanges with the same counterparty, the net differential of the exchanges is reflected in cost of products sold. Additionally, certain direct sales of this excess crude oil are made to purchasers or users of crude oil. Under the new accounting guidance, these direct sales and related purchases starting April 1, 2006 are being measured at fair value and accounted for as revenues with the related acquisition costs included in cost of products sold. Prior to our adoption of EITF 04-13, sales and cost of sales attributable to such excess crude oil direct sales were netted and presented in cost of products sold. During the quarter and nine months ended September 30, 2006, these crude oil sales amounted to $143.1 million and $274.4 million with corresponding costs of $142.9 million and $273.9 million, respectively, resulting in gains on these transactions of $0.2 million and $0.5 million, respectively.

In June 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes. This interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements by prescribing a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and

HOLLY CORPORATION

transition. This interpretation is effective for fiscal years beginning after December 15, 2006. We are currently evaluating the impact the adoption of this interpretation will have on our financial condition, results of operations and 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. This standard is effective for fiscal years beginning after November 15, 2007. We believe the adoption of this standard will not have a material effect on our financial condition, results of operations and cash flows.

SFAS No. 158 “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an Amendment of FASB Statements No. 87, 88, 106, and 132(R)”

In September 2006, the FASB issued SFAS No. 158, “Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans, an Amendment of FASB Statements no. 87, 88, 106 and 132(R). This amendment requires an employer to recognize the funded status of a defined benefit postretirement plan as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income. This standard also requires an employer to measure the funded status of a plan as of the date of its year-end financial statements. This standard is effective for fiscal years ending after December 15, 2006. We are currently evaluating the impact the adoption of this standard will have on our financial condition, results of operations and cash flows.

NOTE 2: Discontinued Operations

On March 31, 2006 we sold the Montana Refinery to Connacher. The net cash proceeds we received on the sale of the Montana Refinery amounted to $48.9 million, net of transaction fees and expenses. Additionally we received 1,000,000 shares of Connacher common stock valued at approximately $4.3 million at March 31, 2006. In accounting for the sale, we recorded a pre-tax gain of $22.4 million. The Montana Refinery assets disposed of had a net book value at March 31, 2006 of $13.7 million for property, plant and equipment, $15.4 million for inventories and $2.0 million for other assets, with current liabilities assumed amounting to $0.3 million.

We retained certain quantities of finished product inventories that were not included in the sale to Connacher. These inventories were liquidated during the second quarter of 2006.

The following tables provide summarized income statement information related to discontinued operations:

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2006				2005				2006				2005
						(In thousands)
Sales and other revenues from discontinued operations		$	51			$	54,759			$	53,912			$	124,405
Income from discontinued operations before income taxes		$	31			$	1,660			$	11,176			$	2,526
Income tax expense			(10	)			(627	)			(4,164	)			(954	)
Income from discontinued operations, net			21				1,033				7,012				1,572
Gain (loss) on sale of discontinued operations before income taxes			(354	)			—				22,004				—
Income tax (expense) benefit			134				—				(8,199	)			—
Gain (loss) on sale of discontinued operations, net			(220	)			—				13,805				—
Income (loss) from discontinued operations, net		$	(199	)		$	1,033			$	20,817			$	1,572

HOLLY CORPORATION

NOTE 3: Investment in 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. We currently have a 45.0% ownership interest in HEP, including our 2% general partner interest.

HEP serves our refineries in New Mexico and Utah under a 15-year pipelines and terminals agreement (“HEP PTA”) expiring in 2019 and a 15-year intermediate pipeline agreement expiring in 2020 (“HEP IPA”). Under the HEP PTA, we pay HEP fees to transport on their refined product pipelines or throughput in their terminals a volume of refined products that will result in a minimum level of revenue to HEP of $36.7 million annually. Under the HEP IPA, we agreed to transport volumes of intermediate products on the intermediate pipelines that will result in a minimum level of revenues to HEP of approximately $11.8 million annually. Minimum revenues for both agreements will adjust upward based on increases in the producer price index over the term of the agreements. Additionally, we agreed to indemnify HEP up to an aggregate amount of $17.5 million for any environmental noncompliance and remediation liabilities associated with the assets transferred to HEP and occurring or existing prior to the date of the transfers of ownership to HEP. Of this total, indemnification in excess of $15 million relates solely to the intermediate pipelines.

On February 28, 2005, HEP closed its acquisition from Alon of four refined products pipelines, an associated tank farm and two refined products terminals. These pipelines and terminals are located primarily in Texas and transport approximately 70% of the light refined products for Alon’s refinery in Big Spring, Texas. The total consideration paid by HEP for these pipeline and terminal assets was $120 million in cash and 937,500 Class B subordinated units which, subject to certain conditions, will convert into an equal number of HEP common units five years after the acquisition date. Following the closing of this transaction, we owned 47.9% of HEP including the 2% general partner interest. HEP financed the Alon transaction through a private offering of $150 million principal amount of 6.25% senior notes due 2015 (“HEP Senior Notes”). HEP 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 HEP’s credit agreement, including $5 million drawn shortly before the closing of the Alon transaction. The consideration paid for the Alon pipeline and terminal assets was allocated to the individual assets acquired based on their estimated fair values. The aggregate consideration amounted to $146.6 million, which consisted of $24.7 million fair value of HEP’s Class B subordinated units, $120 million in cash and $1.9 million of transaction costs. In accounting for this acquisition, HEP recorded pipeline and terminal assets of $86.9 million and an intangible asset of $59.7 million, representing the value of the 15-year pipelines and terminals agreement.

On July 8, 2005, we closed on the transaction in which HEP acquired our two parallel intermediate feedstock pipelines which connect our Lovington and Artesia, New Mexico facilities (our revenue commitments on the intermediate pipelines are discussed above under the HEP IPA). The total consideration was $81.5 million, which consisted of approximately $77.7 million in cash, 70,000 common units of HEP and a capital account credit to maintain our existing general partner interest in HEP. HEP financed the approximately $77.7 million cash portion of the consideration for the intermediate pipelines with the proceeds raised from the private sale, which closed simultaneously with the acquisition, of 1.1 million of its common units for $45.1 million to a limited number of institutional investors and the offering, completed in June 2005, of an additional $35 million in principal amount of HEP Senior Notes. As a result of this transaction, our ownership interest in HEP was reduced to the current 45%, including the 2% general partner interest.

HEP is a variable interest entity (“VIE”) as defined under FIN 46, and following HEP’s acquisition of the intermediate feedstock pipelines, we have determined that our beneficial variable interest in HEP was less than 50%; therefore, as required by FIN 46, we deconsolidated HEP effective as of July 1, 2005. The deconsolidation was presented from July 1, 2005 forward, and our share of the earnings of HEP, including any incentive distributions paid through our general partner interest, is now reported using the equity method of accounting. HEP has risk associated with its operations. HEP has three major customers, of which we are one. If any of the customers fails to meet the desired shipping levels or terminates its contracts, HEP could suffer substantial losses unless a new customer is found. If HEP does suffer losses, we would recognize our percentage of those losses based on our

HOLLY CORPORATION

ownership percentage in HEP at that time.

As of July 1, 2005, the impact of deconsolidation of HEP was an increase in the liability account of investments in HEP of $83.8 million, a decrease in property, plant and equipment of $157.8 million, a decrease in cash of $20.4 million, a decrease in other current assets of $3.6 million, a decrease in transportation agreements of $62.7 million, a decrease in other assets of $4.5 million, a decrease in minority interest of $179.5 million, a decrease in current liabilities of $3.9 million and a decrease in other long-term liabilities of $149.4 million.

The HEP Senior Notes are not recorded on our accompanying consolidated balance sheets due to the deconsolidation of HEP effective July 1, 2005. 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 million of the principal amount of the HEP Senior Notes.

We hold 7,000,000 subordinated units and 70,000 common units of HEP as of September 30, 2006. Our rights as holder of subordinated units to receive distributions of cash from HEP are subordinated to the rights of the common unitholders to receive such distributions.

In addition to the intermediate feedstock pipelines acquired by HEP in July 2005, we contributed all of the initial assets of HEP. As these transactions were among entities under common control, the assets were recorded at historical cost by HEP and we did not recognize a gain on the initial contribution or the intermediate pipelines transaction. The intermediate pipelines transaction resulted in a payment to us from HEP of $71.9 million in excess of our historical basis. Since the historical basis was less than the cash received on the transactions, our investment in HEP is a negative investment. The investment balance was eliminated in consolidation until the deconsolidation of HEP on July 1, 2005.

The following table sets forth the changes in our investment account balance with HEP for the nine months ended September 30, 2006 (In thousands):

Investment in HEP balance at December 31, 2005		$	(157,026	)
Equity in the earnings of HEP			8,324
Regular quarterly distributions from HEP			(14,999	)
Investment in HEP balance at September 30, 2006		$	(163,701	)

The following tables provide summary financial results for HEP.

		September 30,				December 31,
		2006				2005
		(In thousands)
Current assets		$	20,997			$	28,705
Properties and equipment, net			160,894				162,298
Transportation agreements and other			60,610				63,772
Total assets		$	242,501			$	254,775
Current liabilities		$	12,456			$	9,251
Long-term liabilities			181,801				181,711
Minority interest			10,638				11,753
Partners’ equity			37,606				52,060
Total liabilities and partners’ equity		$	242,501			$	254,775

HOLLY CORPORATION

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2006				2005				2006				2005
						(In thousands)
Revenues		$	22,899			$	21,517			$	63,864			$	57,551
Operating costs and expenses			12,098				11,332				36,723				31,347
Operating income			10,801				10,185				27,141				26,204
Other expenses, net			(3,050	)			(2,893	)			(9,257	)			(6,545	)
Net income		$	7,751			$	7,292			$	17,884			$	19,659

We have related party transactions with HEP for pipeline and terminal expenses, certain employee costs, insurance costs, and administrative costs under the Holly PTA, Holly IPA and an Omnibus Agreement.

	•		Pipeline and terminal expenses paid to HEP were $14.3 million and $12.5 million for the three months ended September 30, 2006 and 2005, respectively, and $37.3 million and $31.9 million for the nine months ended September 30, 2006 and 2005, respectively.
	•		We charged HEP $0.5 million for the three months ended September 30, 2006 and 2005 and $1.5 million for the nine months ended September 30, 2006 and 2005 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 $2.0 million and $1.8 million for the three months ended September 30, 2006 and 2005, respectively, and $5.7 million and $4.8 million for the nine months ended September 30, 2006 and 2005, respectively, which we recorded as a reduction in expenses.
	•		We reimbursed HEP $42,000 and $47,000 for certain costs paid on our behalf for the three months ended September 30, 2006 and 2005, respectively, and $138,000 and $161,000 for the nine months ended September 30, 2006 and 2005, respectively.
	•		We received as regular distributions on our subordinated units, common units and general partner interest, $5.2 million and $4.3 million for the three months ended September 30, 2006 and 2005, respectively, and $15.0 million and $12.0 million for the nine months ended September 30, 2006 and 2005, respectively. Our distributions for the three months ended September 30, 2006 and 2005 included $0.3 million and $0.1, respectively, in incentive distributions with respect to our general partner interest. General partner incentive distributions of $0.8 million and $0.1 were included in our distributions for the nine months ended September 30, 2006 and 2005, respectively.
	•		We had a net payable to HEP of $2.3 million and $3.6 million at September 30, 2006 and December 31, 2005, respectively.
	•		“Prepayments and other” includes $2.7 million and $1.0 million at September 30, 2006 and December 31, 2005, respectively, related to minimum revenue payments under the HEP IPA which may be applied as credits against future billings from HEP when our shipments exceed the minimum volume commitments on the intermediate pipelines.

NOTE 4: Earnings Per Share

Basic income per share is calculated as net income divided by average number of shares of common stock outstanding. Diluted income per share assumes, when dilutive, issuance of the net incremental shares from stock options and variable performance shares. The average number of shares of common stock and per share amounts have been adjusted to reflect the two-for-one stock split effective June 1, 2006. The following is a reconciliation of the numerators and denominators of the basic and diluted per share computations of income:

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		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2006				2005				2006				2005
		(In thousands, except per share data)
Net income		$	79,002			$	61,719			$	218,907			$	127,777
Average number of shares of common stock outstanding			56,555				61,236				57,393				62,506
Effect of dilutive stock options and variable restricted shares			1,228				1,536				1,250				1,454
Average number of shares of common stock outstanding assuming dilution			57,783				62,772				58,643				63,960
Income per share – basic		$	1.40			$	1.01			$	3.81			$	2.04
Income per share – diluted		$	1.37			$	0.98			$	3.73			$	2.00

NOTE 5: Stock-Based Compensation

On September 30, 2006 we had three principal share-based compensation plans, which are described below. The compensation cost that has been charged against income for these plans was $14.0 million and $5.6 million for the nine months ended September 30, 2006 and 2005, respectively. The total income tax benefit recognized in the income statements for share-based compensation arrangements was $5.4 million and $2.2 million for the nine months ended September 30, 2006 and 2005, 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 September 30, 2006, 2,642,174 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.

Previously awarded stock options and all other compensation arrangements based on the market value of our common stock have been adjusted to reflect the two-for-one stock split effective June 1, 2006.

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 on the date of grant of each option awarded has been estimated using the Black-Scholes option pricing model.

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

										Weighted-
						Weighted–				Average				Aggregate
						Average				Remaining				Intrinsic
						Exercise				Contractual				Value
Options		Shares				Price				Term				($000)
Outstanding at January 1, 2006			2,479,500			$	2.50
Exercised			(824,300	)		$	2.94
Forfeited or expired			—				—
Outstanding at September 30, 2006			1,655,200			$	2.28				3.5			$	67,950
Exercisable at September 30, 2006			1,615,200			$	2.21				3.5			$	66,415

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The total intrinsic value of options exercised during the nine months ended September 30, 2006 and 2005, was $27.1 million and $14.7 million, respectively.

A summary of the status of our nonvested options as of September 30, 2006 and changes during the nine months ended September 30, 2006, is presented below:

						Weighted-
						Average
						Grant-Date
Nonvested Options		Options				Fair Value
Nonvested at January 1, 2006			408,800			$	1.02
Vested			(368,800	)		$	0.91
Forfeited			—				—
Nonvested at September 30, 2006			40,000			$	1.99

As of September 30, 2006, there was $18,000 of total unrecognized compensation cost related to the stock options granted. That cost is expected to be recognized over a weighted-average period of two months. The total fair value of shares vested during the nine months ended September 30, 2006 and 2005, was $0.3 million and $0.4 million, respectively.

Cash received from option exercises under the stock option plans for the nine months ended September 30, 2006 and 2005, was $2.4 million and $2.7 million, respectively. The actual tax benefit realized for the tax deductions from option exercises under the stock option plans totaled $10.4 million and $5.5 million for the nine months ended September 30, 2006 and 2005, 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 vesting periods, as we assume all restricted shares will fully vest.

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

						Weighted–
						Average
						Grant-Date				Aggregate Intrinsic
Restricted Stock		Grants				Fair Value				Value ($000)
Outstanding at January 1, 2006 (not vested)			545,808			$	9.85
Vesting and transfer of ownership to recipients			(148,900	)		$	6.81
Granted			102,998			$	30.91
Forfeited			(4,984	)		$	17.06
Outstanding at September 30, 2006 (not vested)			494,922			$	15.07			$	23,855

The total intrinsic value of restricted stock vested and transferred to recipients during the nine months ended September 30, 2006 and 2005 was $5.5 million and $2.5 million, respectively. As of September 30, 2006, there was $3.6 million of total unrecognized compensation cost related to nonvested restricted stock grants. That cost is expected to be recognized over a weighted-average period of 1.5 years. The total fair value of shares vested during the nine months ended September 30, 2006 was $1.0 million.

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Performance Share Units

Under our Long-Term Incentive Compensation Plan, we grant certain officers and other key employees performance share units, some of which are payable in cash and some are payable in stock upon meeting certain criteria over the service period, and generally vest over a period of one to three years.

During the 2006 first quarter, certain grantees agreed to amend their outstanding performance share units to provide for the settlement in the form of our common stock instead of cash. The performance criteria of both the amended performance share units and the original performance share units not amended are based upon our share price and upon our total shareholder return during the requisite period as compared to the total shareholder return of our peer group of refining companies (referred to as “market performance” criteria). In addition, during the 2006 first quarter, we granted new performance share units that will be settled in our common stock based on certain measurements of our financial performance as compared to a select peer group of companies (referred to as “financial performance” criteria).

The fair value of each performance share unit award payable in cash is being revalued quarterly based on our valuation model and the corresponding expense is being amortized over the vesting periods. The fair value of each performance share unit award settled in stock is determined at the grant date (or the amendment date in the case of our amended agreements) and the corresponding expense is being amortized over the vesting periods.

The fair value of each performance share unit award based on financial performance criteria was measured based on the grant date stock price at February 16, 2006 of $29.50 (as adjusted for the two-for-one stock split effective June 1, 2006) and will apply to the number of shares ultimately issued for each award. The number of shares ultimately issued for each award will be based on our financial performance as compared to peer group companies and can range from zero to 200% of the number of performance share units issued. We currently have estimated the final payout of shares at 150%.

The fair value of each performance share unit award based on market performance criteria is computed based on an expected-cash-flow approach. The analysis utilizes the current stock price, dividend yield, historical total returns as of the measurement date, expected total returns based on a capital asset pricing model methodology, standard deviation of historical returns and comparison of expected total returns with the peer group. The expected total return and historical standard deviation 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.

For the nine months ended September 30, 2006, this valuation analysis was performed for the performance share units with market based performance on the February 10, 2006 effective date of the amendment of certain awards to provide for settlement in stock rather than cash, and at the end of the nine months, September 30, 2006.

At February 10, 2006, the price of our stock was $31.96 (as adjusted for the two-for-one stock split effective June 1, 2006), the latest quarterly dividend was $0.05 (as adjusted for the two-for-one stock split effective June 1, 2006), and the risk-free rates ranged from 4.68% to 4.70%, depending on the remaining performance period. The inputs affecting the range of expected total returns for us and the peer group are based on a capital asset pricing model utilizing information available at each measurement date. The monthly standard deviation of returns is based on the standard deviation of historical return information. The range of expected returns and standard deviation is presented below:

						Standard
Company		Expected Return on Equity				Deviation (Monthly)
Holly			12.25	%		10.9% to 12.1%
Peer group		10.0% to 13.5%				7.9% to 16.0%

At September 30, 2006, the price of our stock was $43.33, the latest quarterly dividend was $0.08, and the risk-free rates ranged from 4.38% to 4.86%, depending on the remaining performance period. The inputs affecting the range of expected total returns for us and the peer group are based on a capital asset pricing model utilizing information

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

						Standard
Company		Expected Return on Equity				Deviation (Monthly)
Holly			12.2	%		13.1% to 13.6%
Peer group		10.3% to 13.5%				10.1% to 16.0%

A summary of performance share units activity as of September 30, 2006, and changes during the nine months ended September 30, 2006 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, 2006 (nonvested)			356,524				—				—				356,524
Amended to settle in stock			(128,574	)			128,574				—				—
Vesting and payment of benefit to recipients			—				—				—				—
Granted			—				—				75,984				75,984
Forfeited			(4,456	)			—				—				(4,456	)
Outstanding at September 30, 2006 (nonvested)			223,494				128,574				75,984				428,052

There was no cash paid during the nine months ended September 30, 2006 related to vested performance share units, while $6.3 million was paid during the nine months ended September 30, 2005 related to vested performance share units. As of September 30, 2006, the cash liability associated with these awards was $13.8 million and is recorded in accrued liabilities on our consolidated balance sheets. Based on the weighted average fair value at September 30, 2006 of $57.21, there was $6.2 million of total unrecognized compensation cost related to nonvested performance share units. That cost is expected to be recognized over a weighted-average period of 0.9 years.

NOTE 6: 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, as part of the sale of the Montana Refinery, we received 1,000,000 shares of Connacher 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”) and auction rate securities (“ARS”). Although VRDN and ARS 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. Rates on ARS are reset through a Dutch auction process at intervals between 35 and 90 days, depending on the terms of the security. VRDN and ARS 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. Unrealized gains and losses, net of related income taxes, are temporary and reported as a component of accumulated other comprehensive income.

The following is a summary of our available-for-sale securities at September 30, 2006:

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		Available-for-Sale Securities
										Estimated
						Gross				Fair Value
						Unrealized				(Net Carrying
		Amortized Cost				Losses				Amount)
		(In thousands)
States and political subdivisions		$	92,619			$	(20	)		$	92,599
Equity securities			4,328				(1,098	)			3,230
Total marketable securities		$	96,947			$	(1,118	)		$	95,829

During the nine months ended September 30, 2006 and 2005, we recognized $94,000 in gains related to 232 sales and maturities and $0.3 million in losses related to 168 sales and maturities respectively, in which we received $285.9 million and $209.4 million in proceeds, respectively. The realized gains and losses represent the difference between the purchase price and market value on the maturity or sales dates.

NOTE 7: Investments in Joint Ventures

Prior to February 2005, NK Asphalt Partners was owned 49% by us and 51% by a subsidiary of Koch Materials Company (“Koch”), and did business under the name “Koch Asphalt Solutions – Southwest.” We accounted for this investment using the equity method. In February 2005, we purchased the 51% interest in NK Asphalt Partners owned by Koch for $16.9 million plus working capital. This purchase increased our ownership in NK Asphalt Partners from 49% to 100% and eliminated any further obligations we had with respect to additional contributions under the joint venture agreement. The partnership manufactures and markets asphalt and asphalt products from various terminals in Arizona and New Mexico and now does business under the name “Holly Asphalt Company.” From the date of acquisition of the additional 51%, we have consolidated the results of NK Asphalt Partners in our consolidated financial statements. All intercompany transactions have been eliminated in consolidation. The purchase price was allocated to the individual assets acquired and liabilities assumed based on their estimated fair values. The total purchase consideration for the 51% interest, including expenses, was $21.8 million, less cash of $3.4 million which was recorded due to the consolidation of NK Asphalt Partners at the time of the 51% acquisition. In addition to the cash, at the date of the acquisition, we recorded current assets of $11.7 million, net property, plant and equipment of $20.4 million, intangible assets of $5.2 million, goodwill of $1.0 million, and current liabilities of $8.5 million and eliminated our equity investment. Sales to the joint venture during 2005, prior to the acquisition, were $3.9 million.

Prior to February 28, 2005, we had a 49% interest in MRC Hi-Noon LLC, a joint venture operating retail service stations and convenience stores in Montana, and we accounted for our share of earnings from the joint venture using the equity method. At December 31, 2004, we had a reserve balance of approximately $0.8 million related to the collectability of advances to the joint venture and related accrued interest. On February 28, 2005, we sold our 49% interest to our joint venture partner and agreed to accept partial payment on the advances we previously made to the joint venture. In connection with this transaction, we received $0.8 million, which resulted in a book gain to us of $0.5 million.

NOTE 8: Environmental

Consistent with our accounting policy for environmental remediation and cleanup costs, we expensed $3.6 million during the nine months ended September 30, 2006 and $0.4 million during the nine months ended September 30, 2005 for environmental remediation and cleanup obligations and certain environmental obligations retained in connection with our sale of the Montana Refinery. The accrued environmental liability reflected in the consolidated balance sheets was $6.2 million and $3.1 million at September 30, 2006 and December 31, 2005, respectively, of which $4.5 million and $2.0 million was classified as other long-term liabilities, respectively. Costs of future expenditures for environmental obligations are not discounted to their present value.

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NOTE 9: Debt

Credit Facility

We have a $175 million secured revolving credit facility with Bank of America as administrative agent and lender, with a term of four years and an option to increase the facility to $225 million subject to certain conditions. This credit facility expires in 2008 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 September 30, 2006. At September 30, 2006, we had outstanding letters of credit totaling $2.3 million, and no outstanding borrowings under our credit facility. At that level of usage, the unused commitment under our credit facility was $172.7 million at September 30, 2006.

NOTE 10: Income taxes

The effective tax rate for continuing operations for the first nine months of 2006 was 35.6%, as compared to 37.6% for the first nine months of 2005. The reduction in the effective tax rate was principally due to income tax credits available to small business refiners incurring costs to produce ultra low sulfur diesel fuel.

NOTE 11: Stockholders’ Equity

Two-For-One Stock Split: On May 11, 2006, we announced that our Board of Directors approved a two-for-one stock split payable in the form of a stock dividend of one share of common stock for each issued and outstanding share of common stock. The stock dividend was paid on June 1, 2006 to all holders of record of common stock at the close of business on May 22, 2006. All references to the number of shares of common stock (other than authorized shares and other than issued shares and treasury shares at December 31, 2005 shown on our Consolidated Balance Sheets) and per share amounts have been adjusted to reflect the split on a retrospective basis.

Common Stock Repurchases: On November 7, 2005, we announced that our Board of Directors authorized the repurchase of up to $200.0 million of our 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 nine months ended September 30, 2006, we repurchased under this repurchase initiative 3,743,188 shares at a cost of approximately $140.0 million (of which $3.0 million of the cash settlement was after September 30, 2006) or an average of $37.40 per share. Since inception of this repurchase initiative through September 30, 2006, we have repurchased 4,730,788 shares at a cost of approximately $169.9 million or an average of $35.92 per share.

On October 30, 2006, we announced that our Board of Directors had authorized a $100 million increase in the $200 million common stock repurchase program. The increase raises the authorized repurchase limit under the common stock repurchase program from $200 million to $300 million.

In October 2005, we completed the purchase of $100 million of our common stock, pursuant to a repurchase program authorized by our Board of Directors which we had announced in May 2005. Repurchases were made from time to time in the open market or privately negotiated transactions based on market conditions, securities law limitations and other factors. During 2005, we repurchased 4,062,414 shares at a cost of approximately $100.0 million or an average of $24.62 per share under this repurchase initiative.

We have also made repurchases under the terms of restricted stock agreements to provide funds for the payment of payroll and income taxes due at the vesting of restricted shares in the case of executives who did not elect to satisfy such taxes by other means. During the nine months ended September 30, 2006, we repurchased at current market price from certain executives 46,388 shares of our common stock at a cost of approximately $1.4 million. During the nine months ended September 30, 2005, we repurchased at current market price from certain executives 49,580 shares of our common stock at a cost of approximately $0.8 million.

HOLLY CORPORATION

NOTE 12: Other Comprehensive Income

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

						Tax Expense
		Before-Tax				(Benefit)				After-Tax
		(In thousands)
For the three months ended September 30, 2006
Unrealized loss on securities available for sale		$	(416	)		$	(163	)		$	(253	)
Other comprehensive loss		$	(416	)		$	(163	)		$	(253	)
For the three months ended September 30, 2005
Unrealized gain on securities available for sale		$	131			$	51			$	80
Other comprehensive income		$	131			$	51			$	80
For the nine months ended September 30, 2006
Unrealized loss on securities available for sale		$	(625	)		$	(244	)		$	(381	)
Other comprehensive loss		$	(625	)		$	(244	)		$	(381	)
For the nine months ended September 30, 2005
Unrealized gain on securities available for sale		$	106			$	41			$	65
Other comprehensive income		$	106			$	41			$	65

The temporary unrealized loss or gain 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:

		September 30,				December 31,
		2006				2005
		(In thousands)
Pension obligation adjustment		$	(4,501	)		$	(4,501	)
Unrealized loss on securities available for sale			(682	)			(301	)
Accumulated other comprehensive loss		$	(5,183	)		$	(4,802	)

NOTE 13: Retirement Plan

We have a non-contributory defined benefit retirement plan that covers substantially all employees. Our policy is to make contributions annually of not less than the minimum funding requirements under the Employee Retirement Income Security Act of 1974. Benefits are based on the employees’ years of service and compensation.

The net periodic pension expense consisted of the following components:

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2006				2005				2006				2005
						(In thousands)
Service cost		$	1,022			$	862			$	3,248			$	2,585
Interest costs			1,018				941				3,115				2,824
Expected return on assets			(863	)			(791	)			(2,611	)			(2,372	)
Amortization of prior service cost			63				66				196				196
Amortization of net loss			217				241				825				724
One time cost incurred with sale of Montana Refinery			—				—				300				—
Net periodic benefit cost		$	1,457			$	1,319			$	5,073			$	3,957

HOLLY CORPORATION

The expected long-term annual rate of return on plan assets is 8.5%. This rate was used in measuring 2006 and 2005 net periodic benefit cost. We contributed $13.0 million to the retirement plan in the third quarter of 2006.

NOTE 14: Contingencies

We have pending proceedings in the United States Court of Appeals for the District of Columbia Circuit with respect to rulings by the Federal Energy Regulatory Commission (“FERC”) in proceedings brought by us and other parties against Kinder Morgan’s SFPP, L.P. (“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 an SFPP pipeline to ship refined products from El Paso, Texas to Tucson and Phoenix, Arizona. Rulings by the FERC relating principally to the period from 1993 through July 2000 resulted in reparations payments from SFPP to us in 2003 totaling approximately $15.3 million. In 2004 the appeals court issued its opinion relating principally to the period from 1993 through July 2000, ruling in favor of our positions on most of the disputed issues that concern us, and remanded the case to the FERC for additional consideration of several issues, some of which are involved in our claims. In May 2005, the FERC issued a general policy statement on an issue concerning the treatment of income taxes in the calculation of allowable rates for pipelines operated by partnerships. The FERC in a later order applied this general policy statement to SFPP and such application is contrary to our position in this case. We and certain other refining companies have pending before the court of appeals petitions challenging the FERC policy on income taxes, decisions by the FERC in 2005 and early 2006 on certain of the remanded issues, and rulings by the FERC on some issues relating to periods after July 2000. In March 2006, SFPP submitted computations asserted to be based on the most recent determinations of the FERC in the case. In April 2006, we filed a protest and comments concerning a number of elements of these computations. One element of the computations, which is based on the FERC’s disputed 2005 policy on treatment of income taxes, would if ultimately sustained result in a requirement for us to repay to SFPP approximately $3.0 million of the $15.3 million reparations amount received by us from SFPP in 2003. Because proceedings in the FERC on remand have not been completed and our petitions for review to the court of appeals with respect to the FERC’s orders are pending, it is not possible to determine whether the amount of reparations actually due to us for the period from 1993 through July 2000 will be found to be less than or more than the $15.3 million we received in 2003. Although it is not possible at the date of this report to predict the final outcome of these proceedings, we believe that future proceedings are not likely to result in an obligation for us to repay more than the amount now asserted in SFPP’s most recent computations (approximately $3.0 million) and that the more likely final result would be either a smaller repayment by us than is now asserted by SFPP or a payment to us of additional reparations. The ultimate amount of reparations payable to us will be determined only after further proceedings in the FERC on issues that have not been finally determined by the FERC, further proceedings in the appeals court with respect to determinations by the FERC, and possibly future petitions by one or more of the parties seeking United States Supreme Court review of issues in the case.

In discussions beginning in the last half of 2005, the Environmental Protection Agency (“EPA”) and the State of Utah have asserted that we have liabilities relating to the Federal Clean Air Act at 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 tentatively agreed with the EPA and the State of Utah to settle the issues presented by means of an agreement similar to the 2001 Consent Agreement we entered into for our Navajo and Montana refineries. The tentative settlement agreement, which has not yet been put into a final written agreement, includes proposed obligations for us to make specified additional capital investments expected to total up to approximately $10.0 million over several years and to make changes in operating procedures at the refinery. 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 tentative settlement.

HOLLY CORPORATION

Our Navajo Refining Company subsidiary is named as a defendant, along with approximately 40 other companies involved in oil refining and marketing and related businesses, in a lawsuit originally filed in May 2006 by the State of New Mexico in the U.S. District Court for the District of New Mexico. The lawsuit, as amended in late October through the filing of a second amended complaint in the U.S. District Court for the Southern District of New York under multidistrict procedures, alleges that the defendants are liable for contaminating the waters of New Mexico through producing and/or supplying methyl tertiary butyl ether (“MTBE”) or gasoline or other products containing MTBE. The claims made are for defective design or product, failure to warn, negligence, public nuisance, statutory public nuisance, private nuisance, trespass, and civil conspiracy. The second amended complaint also contains a claim, which is asserted in the complaint only against certain other defendants but which appears to be similar to a claim that has been threatened in a mailing to Navajo by law firms representing the plaintiff in this case, alleging violations of certain provisions of the Toxic Substances Control Act. The lawsuit seeks compensatory damages unspecified in amount, injunctive relief, exemplary and punitive damages, costs, attorney’s fees allowed by law, and interest allowed by law. As of the close of business on the day prior to the date of this report, Navajo has not been served in this case. At the date of this report, it is not possible to predict the likely course or outcome of this litigation.

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 have a materially adverse impact on our financial condition, results of operations or cash flows.

NOTE 15: Segment Information

Our operations are currently organized into one business division, Refining. The Refining business division includes the Navajo Refinery, Woods Cross Refinery and NK Asphalt Partners. Our operations that are not included in the Refining business division include the operations of Holly Corporation, the parent company, and a small-scale oil and gas exploration and production program. Although we previously included the Montana Refinery in the Refining division, the results from the Montana Refinery are now reported in discontinued operations and are not included in the table below.

Prior to our deconsolidation of HEP effective July 1, 2005, our operations were organized into two business divisions, which were Refining and HEP. These segments have been in effect since July 13, 2004, the closing of the initial public offering of HEP. Our operations that were not included in either the Refining or HEP business divisions included the operations of Holly Corporation, the parent company, a small-scale oil and gas exploration and production program and the elimination of the revenue and costs associated with HEP’s pipeline transportation services for us.

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 certain crude oil pipelines that we own and operate in conjunction with our refining operations as part of the supply networks of the refineries. The Refining segment also includes the equity in earnings from our 49% interest in NK Asphalt Partners prior to February 2005. In February 2005, we acquired the remaining 51% interest in the asphalt joint venture from the other partner; subsequent to the purchase, we include the operations of NK Asphalt Partners in our consolidated financial statements. NK Asphalt Partners, dba Holly Asphalt Company, manufactures and markets asphalt and asphalt products in Arizona, New Mexico, Texas and California. The cost of pipeline transportation and terminal services provided by HEP to us is also included in the Refining segment. The HEP segment involved all of the operations of HEP through June 30, 2005 (prior to the deconsolidation), including approximately 1,300 miles (780 miles prior to the Alon asset acquisition) of pipeline assets principally in Texas, New Mexico and Oklahoma and refined product terminals in several Southwest and Rocky Mountain states. The HEP segment also included a 70% interest in Rio Grande Pipeline Company (“Rio Grande”), which provides petroleum products transportation. Revenues from the HEP segment were earned through transactions with unaffiliated parties for pipeline transportation, rental and terminalling operations as well as revenues relating to pipeline transportation services

- 24 -

HOLLY CORPORATION

provided for our refining operations and from HEP’s interest in Rio Grande. Our operations not included in the reportable segment or segments were included in Corporate and Other, which included costs of Holly Corporation, the parent company, consisting primarily of general and administrative expenses as well as a small-scale oil and gas exploration and production program. The consolidations and eliminations column included the elimination of the revenue and costs associated with HEP’s pipeline transportation services for us. These items are no longer included after the deconsolidation of HEP effective July 1, 2005.

The accounting policies for the 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, 2005. Our reportable segments prior to July 1, 2005 were strategic business units that offered different products and services.

														Consolidations
										Corporate				and				Consolidated
		Refining				HEP				and Other				Eliminations				Total
		(In thousands)
Three Months Ended September 30, 2006
Sales and other revenues		$	1,172,409			$	—			$	404			$	(120	)		$	1,172,693
Depreciation, depletion and amortization		$	9,079			$	—			$	401			$	—			$	9,480
Income (loss) from operations		$	129,775			$	—			$	(12,685	)		$	—			$	117,090
Income (loss) from continuing operations before income taxes		$	133,439			$	—			$	(10,274	)		$	—			$	123,165
Three Months Ended September 30, 2005
Sales and other revenues		$	880,228			$	—			$	417			$	(125	)		$	880,520
Depreciation, depletion and amortization		$	8,255			$	—			$	294			$	—			$	8,549
Income (loss) from operations		$	104,262			$	—			$	(12,552	)		$	—			$	91,710
Income (loss) from continuing operations before income taxes		$	107,562			$	—			$	(11,855	)		$	—			$	95,707
Nine Months Ended September 30, 2006
Sales and other revenues		$	3,084,595			$	—			$	928			$	(396	)		$	3,085,127
Depreciation, depletion and amortization		$	27,046			$	—			$	1,141			$	—			$	28,187
Income (loss) from operations		$	338,670			$	—			$	(45,380	)		$	—			$	293,290
Income (loss) from continuing operations before income taxes		$	347,295			$	—			$	(39,606	)		$	—			$	307,689
Nine Months Ended September 30, 2005
Sales and other revenues		$	2,216,526			$	36,034			$	1,034			$	(19,699	)		$	2,233,895
Depreciation, depletion and amortization		$	24,778			$	6,212			$	906			$	—			$	31,896
Income (loss) from operations		$	223,182			$	16,019			$	(33,702	)		$	—			$	205,499
Income (loss) from continuing operations before income taxes		$	225,829			$	12,367			$	(30,739	)		$	(6,319	)		$	201,138

HOLLY CORPORATION

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 of 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 Woods Cross, Utah. Our profitability depends largely on the spread between market prices for refined petroleum products and crude oil prices. At September 30, 2006, we also owned a 45% interest in HEP, which owns and operates pipeline and terminalling assets and owns a 70% interest in 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. Additionally, starting April 1, 2006, we began recording direct sales of crude oil as revenues with the related acquisition costs included in cost of products, as required by recent accounting guidance (see” New Accounting Pronouncements” under “Critical Account Policies” below for additional discussion on this new accounting guidance). Prior to April 1, 2006, sales and cost of sales attributable to such crude oil direct sales were netted and presented in cost of products sold. During the nine months ended September 30, 2006, we recorded crude oil sales under this new guidance of $274.4 million with a corresponding cost of $273.9 million, resulting in a gain on these transactions of $0.5 million. Our total sales and other revenues for the nine months ended September 30, 2006 were $3,085.1 million and our net income for the nine months ended September 30, 2006 was $218.9 million. Our sales and other revenues and net income for the nine months ended September 30, 2005 were $2,233.9 million and $127.8 million, respectively. Our principal expenses are costs of products sold and operating expenses. Our total operating costs and expenses for the nine months ended September 30, 2006 were $2,791.8 million, an increase from $2,028.4 million for the nine months ended September 30, 2005.

On May 11, 2006, we announced that our Board of Directors had approved a two-for-one stock split payable in the form of a stock dividend of one share of common stock for each issued and outstanding share of common stock. The stock dividend was paid on June 1, 2006 to all holders of record of common stock at the close of business on May 22, 2006. All references to the number of shares of common stock (other than authorized shares and other than issued shares and treasury shares at December 31, 2005 shown on our Consolidated Balance Sheets) and per share amounts have been adjusted to reflect the split on a retrospective basis.

On March 31, 2006 we sold our petroleum refinery in Great Falls, Montana (the “Montana Refinery”) to a subsidiary of Connacher Oil and Gas Limited (“Connacher”). The net cash proceeds we received on the sale of the Montana Refinery amounted to $48.9 million, net of transaction fees and expenses. Additionally we received 1,000,000 shares of Connacher common stock valued at approximately $4.3 million at March 31, 2006. We have presented in discontinued operations the results of the Montana Refinery operations and a gain of $13.8 million on the sale.

On November 7, 2005, we announced that our Board of Directors had authorized the repurchase of up to $200.0 million of our 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 nine months ended September 30, 2006, we repurchased under this repurchase initiative 3,743,188 shares at a cost of approximately $140.0 million (of which $3.0 million of the cash settlement was after September 30, 2006) or an average of $37.40 per share. Since inception of this repurchase initiative through September 30, 2006, we have repurchased 4,730,788 shares at a cost of approximately $169.9 million or an average of $35.92 per share.

On October 30, 2006, we announced that our Board of Directors had authorized a $100 million increase in the $200 million common stock repurchase program. The increase raises the authorized repurchase limit under the common stock repurchase program from $200 million to $300 million.

HOLLY CORPORATION

RESULTS OF OPERATIONS

Financial Data (Unaudited)

		Three Months Ended
		September 30,								Change from 2005
		2006				2005 (1)				Change				Percent
		(In thousands, except per share data)
Sales and other revenues		$	1,172,693			$	880,520			$	292,173				33.2	%
Operating costs and expenses:
Cost of products sold (exclusive of depreciation, depletion and amortization)			979,309				725,286				254,023				35.0
Operating expenses (exclusive of depreciation, depletion and amortization)			54,146				42,287				11,859				28.0
General and administrative expenses (exclusive of depreciation, depletion and amortization)			12,566				12,619				(53	)			(0.4	)
Depreciation, depletion and amortization			9,480				8,549				931				10.9
Exploration expenses, including dry holes			102				69				33				47.8
Total operating costs and expenses			1,055,603				788,810				266,793				33.8
Income from operations			117,090				91,710				25,380				27.7
Other income (expense):
Equity in earnings of HEP			3,596				3,296				300				9.1
Interest income			2,747				1,202				1,545				128.5
Interest expense			(268	)			(501	)			233				(46.5	)
			6,075				3,997				2,078				52.0
Income from continuing operations before income taxes			123,165				95,707				27,458				28.7
Income tax provision			43,964				35,690				8,274				23.2
Income from continuing operations before cumulative change in accounting principle			79,201				60,017				19,184				32.0
Cumulative effect of accounting change (net of tax expense of $426)			—				669				(669	)			(100.0	)
Income from continuing operations			79,201				60,686				18,515				30.5
Income (loss) from discontinued operations, net of taxes			(199	)			1,033				(1,232	)			(119.3	)
Net income		$	79,002			$	61,719			$	17,283				28.0	%
Basic earnings per share:
Continuing operations		$	1.40			$	0.99			$	0.41				41.4	%
Discontinued operations			—				0.02				(0.02	)			(100.0	)
Net income		$	1.40			$	1.01			$	0.39				38.6	%
Diluted earnings per share:
Continuing operations		$	1.37			$	0.97			$	0.40				41.2	%
Discontinued operations			—				0.01				(0.01	)			(100.0	)
Net income		$	1.37			$	0.98			$	0.39				39.8	%
Cash dividends declared per common share		$	0.08			$	0.05			$	0.03				60.0	%
Average number of common shares outstanding:
Basic			56,555				61,236				(4,681	)			(7.6	)%
Diluted			57,783				62,772				(4,989	)			(7.9	)%