e10vq
Table of Contents

 
 
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 June 30, 2007
OR
     
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to                    
Commission File Number 1-3876
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)

Registrant’s telephone number, including area code
  (Zip 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, 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
54,984,932 shares of Common Stock, par value $.01 per share, were outstanding on July 31, 2007.
 
 

 


 

HOLLY CORPORATION
INDEX
             
        Page  
  FINANCIAL INFORMATION        
 
           
Forward-Looking Statements     3  
 
           
Definitions     4  
 
           
  Financial Statements        
 
           
 
  Consolidated Balance Sheets June 30, 2007 (Unaudited) and December 31, 2006     6  
 
           
 
  Consolidated Statements of Income (Unaudited) Three Months and Six Months Ended June 30, 2007 and 2006     7  
 
           
 
  Consolidated Statements of Cash Flows (Unaudited) Six Months Ended June 30, 2007 and 2006     8  
 
           
 
  Consolidated Statements of Comprehensive Income (Unaudited) Three Months and Six Months Ended June 30, 2007 and 2006     9  
 
           
 
  Notes to Consolidated Financial Statements (Unaudited)     10  
 
           
  Management’s Discussion and Analysis of Financial Condition and Results of Operations     22  
 
           
  Quantitative and Qualitative Disclosures About Market Risk     38  
 
           
    38  
 
           
  Controls and Procedures     44  
 
           
  OTHER INFORMATION        
 
           
  Legal Proceedings     45  
 
           
  Unregistered Sales of Equity Securities and Use of Proceeds     47  
 
           
  Submission of Matters to a Vote of Security Holders     47  
 
           
  Exhibits     49  
 
           
Signatures     50  
 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

 


Table of Contents

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 “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 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, 2006 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.

-3-


Table of Contents

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 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.
     “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.

-4-


Table of Contents

     “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.

-5-


Table of Contents

Item 1. Financial Statements
HOLLY CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
                 
    June 30,     December 31,  
    2007     2006  
    (Unaudited)          
ASSETS
               
Current assets:
               
Cash and cash equivalents
  $ 107,137     $ 154,117  
Marketable securities
    249,540       96,168  
 
               
Accounts receivable: Product and transportation
    208,640       199,083  
Crude oil resales
    193,595       196,842  
Related party receivable
    2,101       2,198  
 
           
 
    404,336       398,123  
 
               
Inventories: Crude oil and refined products
    128,464       115,100  
Materials and supplies
    15,233       14,575  
 
           
 
    143,697       129,675  
 
               
Income taxes receivable
          9,055  
Prepayments and other
    15,387       12,081  
Assets of discontinued operations
          355  
 
           
Total current assets
    920,097       799,574  
 
               
Properties, plants and equipment, at cost
    714,773       642,740  
Less accumulated depreciation, depletion and amortization
    (254,924 )     (237,270 )
 
           
 
    459,849       405,470  
 
               
Marketable securities (long-term)
    54,609       5,668  
 
               
Other assets:                   Turnaround costs
    9,150       12,061  
Intangibles and other
    13,772       15,096  
 
           
 
    22,922       27,157  
 
           
 
               
Total assets
  $ 1,457,477     $ 1,237,869  
 
           
 
               
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
Current liabilities:
               
Accounts payable
  $ 516,071     $ 507,566  
Accrued liabilities
    48,000       51,173  
Income taxes payable
    34,767        
Liabilities of discontinued operations
          654  
 
           
Total current liabilities
    598,838       559,393  
 
               
Deferred income taxes
    20,730       20,776  
Other long-term liabilities
    30,748       27,201  
Commitments and contingencies
           
Distributions in excess of investment in Holly Energy Partners
    167,161       164,405  
 
               
Stockholders’ equity:
               
Preferred stock, $1.00 par value – 1,000,000 shares authorized; none issued
           
Common stock $.01 par value – 160,000,000 and 100,000,000 shares authorized; 72,358,817 and 71,825,960 shares issued as of June 30, 2007 and December 31, 2006, respectively
    724       718  
Additional capital
    75,947       66,500  
Retained earnings
    959,990       745,994  
Accumulated other comprehensive loss
    (12,806 )     (11,358 )
Common stock held in treasury, at cost – 17,385,283 and 16,509,345 shares as of June 30, 2007 and December 31, 2006, respectively
    (383,855 )     (335,760 )
 
           
Total stockholders’ equity
    640,000       466,094  
 
           
 
               
Total liabilities and stockholders’ equity
  $ 1,457,477     $ 1,237,869  
 
           
See accompanying notes.

-6-


Table of Contents

HOLLY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
(In thousands, except per share data)
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2007     2006     2007     2006  
Sales and other revenues
  $ 1,216,997     $ 1,120,840     $ 2,142,864     $ 1,912,434  
 
                               
Operating costs and expenses:
                               
Cost of products sold (exclusive of depreciation, depletion, and amortization)
    897,237       908,009       1,648,951       1,583,494  
Operating expenses (exclusive of depreciation, depletion, and amortization)
    51,116       49,092       101,245       101,559  
General and administrative expenses (exclusive of depreciation, depletion, and amortization)
    21,348       18,731       37,195       32,247  
Depreciation, depletion and amortization
    10,641       10,683       22,092       18,707  
Exploration expenses, including dry holes
    105       100       257       227  
 
                       
Total operating costs and expenses
    980,447       986,615       1,809,740       1,736,234  
 
                       
Income from operations
    236,550       134,225       333,124       176,200  
 
                               
Other income (expense):
                               
Equity in earnings of Holly Energy Partners
    4,954       1,516       8,300       4,728  
Interest income
    3,550       2,408       6,110       4,143  
Interest expense
    (291 )     (272 )     (543 )     (547 )
 
                       
 
    8,213       3,652       13,867       8,324  
 
                       
 
                               
Income from continuing operations before income taxes
    244,763       137,877       346,991       184,524  
 
                               
Income tax provision:
                               
Current
    85,189       49,038       119,947       63,844  
Deferred
    947       1,110       875       1,791  
 
                       
 
    86,136       50,148       120,822       65,635  
 
                       
 
                               
Income from continuing operations
    158,627       87,729       226,169       118,889  
 
                               
Discontinued operations
                               
Income from discontinued operations
          5,604             6,991  
Gain on sale of discontinued operations
          (232 )           14,025  
 
                       
Income from discontinued operations, net of taxes
          5,372             21,016  
 
                       
 
                               
Net income
  $ 158,627     $ 93,101     $ 226,169     $ 139,905  
 
                       
 
                               
Basic earnings per share:
                               
Continuing operations
  $ 2.89     $ 1.53     $ 4.11     $ 2.06  
Discontinued operations
          0.09             0.36  
 
                       
Net income
  $ 2.89     $ 1.62     $ 4.11     $ 2.42  
 
                       
 
                               
Diluted earnings per share:
                               
Continuing operations
  $ 2.84     $ 1.51     $ 4.03     $ 2.01  
Discontinued operations
          0.09             0.36  
 
                       
Net income
  $ 2.84     $ 1.60     $ 4.03     $ 2.37  
 
                       
 
                               
Cash dividends declared per common share
  $ 0.12     $ 0.08     $ 0.22     $ 0.13  
 
                       
 
                               
Average number of common shares outstanding:
                               
Basic
    54,959       57,186       55,073       57,819  
Diluted
    55,953       58,363       56,079       59,072  
See accompanying notes.

-7-


Table of Contents

HOLLY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In thousands)
                 
    Six Months Ended  
    June 30,  
    2007     2006  
Cash flows from operating activities:
               
Net income
  $ 226,169     $ 139,905  
Adjustments to reconcile net income to net cash provided by operating activities:
               
Depreciation, depletion and amortization (includes discontinued operations)
    22,092       19,257  
Deferred income taxes (includes discontinued operations)
    875       (651 )
Equity based compensation expense
    1,446       2,442  
Distributions in excess of equity in earnings in HEP
    2,756       5,085  
Gain on sale of assets, before income taxes
          (22,358 )
(Increase) decrease in current assets:
               
Accounts receivable
    (5,862 )     (55,553 )
Inventories
    (14,022 )     (49,946 )
Income taxes receivable
    9,055        
Prepayments and other
    (3,306 )     (6,201 )
Increase (decrease) in current liabilities:
               
Accounts payable
    9,136       33,284  
Accrued liabilities
    (3,789 )     8,360  
Income taxes payable
    34,767       10,879  
Turnaround expenditures
    (202 )     (5,680 )
Other, net
    1,469       972  
 
           
Net cash provided by operating activities
    280,584       79,795  
Cash flows from investing activities:
               
Additions to properties, plants and equipment
    (72,531 )     (67,494 )
Net cash proceeds from sale of Montana Refinery
          48,872  
Purchases of marketable securities
    (360,040 )     (103,283 )
Sales and maturities of marketable securities
    158,150       198,033  
 
           
Net cash provided by (used for) investing activities
    (274,421 )     76,128  
Cash flows from financing activities:
               
Issuance of common stock upon exercise of options
    547       2,181  
Purchase of treasury stock
    (51,097 )     (92,333 )
Cash dividends
    (10,050 )     (5,866 )
Excess tax benefit from equity based compensation
    7,457       8,887  
 
           
Net cash used for financing activities
    (53,143 )     (87,131 )
Cash and cash equivalents:
Increase (decrease) for the period
    (46,980 )     68,792  
Beginning of period
    154,117       49,064  
 
           
End of period
  $ 107,137     $ 117,856  
 
           
 
               
Supplemental disclosure of cash flow information:
               
Cash paid during the period for
               
Interest
  $ 313     $ 349  
Income taxes
  $ 68,668     $ 59,007  
See accompanying notes.

-8-


Table of Contents

HOLLY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
(In thousands)
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2007     2006     2007     2006  
Net income
  $ 158,627     $ 93,101     $ 226,169     $ 139,905  
Other comprehensive income (loss):
                               
Securities available for sale:
                               
Unrealized gain (loss) on available for sale securities
    50       (428 )     428       (199 )
Reclassification adjustment to net income on sale of equity securities
    16       10       (5 )     (10 )
 
                       
Total unrealized gain (loss) on available for sale securities
    66       (418 )     423       (209 )
Retirement medical obligation adjustment
                (2,792 )      
 
                       
Other comprehensive income (loss) before income taxes
    66       (418 )     (2,369 )     (209 )
Income tax expense (benefit)
    28       (162 )     (921 )     (81 )
 
                       
Other comprehensive income (loss)
    38       (256 )     (1,448 )     (128 )
 
                       
Total comprehensive income
  $ 158,665     $ 92,845     $ 224,721     $ 139,777  
 
                       
See accompanying notes.

-9-


Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
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 June 30, 2007, 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 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 does business under the name of “Holly Asphalt Company;” and
 
    owned a 45.0% interest in Holly Energy Partners, L.P. (“HEP”) which includes our 2% general partner interest, which has logistic assets including approximately 1,700 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 net gain of $14.0 million on the sale are shown in discontinued operations (see Note 2).
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 June 30, 2007, the consolidated results of operations and comprehensive income for the three months and six months ended June 30, 2007 and 2006 and consolidated cash flows for the six months ended June 30, 2007 and 2006 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, 2006 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 six months ended June 30, 2007 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.
New Accounting Pronouncements
EITF No.06-11 “Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards”
In June 2007, the FASB ratified Emerging Issues Task Force (“EITF”) Issue 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

-10-


Table of Contents

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. While we are currently evaluating the impact of EITF No. 06-11, we do not expect the adoption of this standard to have a material impact on our financial condition, results of operations and cash flows.
SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115”
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 do not expect the adoption of this statement to have a material impact on our financial condition, results of operations and cash flows.
Interpretation No. 48 “Accounting for Uncertainty in Income Taxes”
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 transition. This interpretation is effective for fiscal years beginning after December 15, 2006. We adopted this standard effective January 1, 2007. As a result of the implementation of this standard, we recognized no material adjustment in the liability for unrecognized income tax benefits.
We are subject to U.S. federal income tax and to the income tax of multiple state jurisdictions. We have substantially concluded all U.S. federal, state and local income tax matters for fiscal years through July 31, 2002. In 2006, the Internal Revenue Service commenced examinations of our U.S. federal income tax returns for the tax years ended July 31, 2003 and December 31, 2003. To date, we do not anticipate that the resolution of this audit will result in a material change to our financial condition, results of operations or cash flows.
Our policy is to recognize potential interest and penalties related to income tax matters in income tax expense. We believe we have appropriate support for the income tax positions taken and to be taken on our income tax returns and that our accruals for tax liabilities are adequate for all open years based on an assessment of many factors, including past experience and interpretations of tax law applied to the facts of each matter.
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 do not anticipate that the adoption of this interpretation will have a material impact 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 $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.

-11-


Table of Contents

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     Six Months Ended  
    June 30,     June 30,  
    2007     2006     2007     2006  
            (In thousands)          
Sales and other revenues from discontinued operations
  $     $ 20,678     $     $ 53,861  
 
                       
                                 
Income from discontinued operations before income taxes
  $     $ 8,943     $     $ 11,145  
Income tax expense
          (3,339 )           (4,154 )
 
                       
Income from discontinued operations, net
          5,604             6,991  
                                 
Gain (loss) on sale of discontinued operations before income taxes
          (280 )           22,358  
Income tax (expense) benefit
          48             (8,333 )
 
                       
Gain (loss) on sale of discontinued operations, net
          (232 )           14,025  
 
                       
                                 
Income from discontinued operations, net
  $     $ 5,372     $     $ 21,016  
 
                       
In accordance with the Montana Refinery sale agreement, we retained certain financial liabilities, including certain environmental liabilities related to required remediation and corrective action for environmental conditions that existed at the time of sale and for financial penalties for infractions that occurred prior to the sale. Based on our estimates, we had accruals of $1.3 million as of June 30, 2007 and December 31, 2006 related to such environmental liabilities which is included in our environmental liability accrual as discussed in Note 7.
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% 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, volumes of refined products that will result in minimum annual payments to HEP. Following the July 1, 2007 producer price index (“PPI”) rate adjustment, minimum payments under the HEP PTA will be $39.6 million for the twelve months ending June 30, 2008. Under the HEP IPA, we agreed to transport minimum volumes of intermediate products on the intermediate pipelines that will result in minimum annual payments to HEP. Following the July 1, 2007 PPI rate adjustment, minimum payments under the HEP IPA will be $12.8 million for the twelve months ending June 30, 2008. Minimum payments 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 $15.0 million relates solely to the intermediate pipelines.
HEP is a variable interest entity (“VIE”) as defined under FIN 46, and following HEP’s acquisition of the intermediate feedstock pipelines in 2005, we determined that our beneficial variable interest in HEP was less than 50%. We report our share of the earnings of HEP, including any incentive distributions paid through our general partner interest, 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

-12-


Table of Contents

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 ownership percentage in HEP at that time.
We hold 7,000,000 subordinated units and 70,000 common units of HEP as of June 30, 2007. 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.
The following table sets forth the changes in our investment account balance with HEP for the six months ended June 30, 2007 (In thousands):
         
Investment in HEP balance at December 31, 2006
  $ (164,405 )
Equity in the earnings of HEP
    8,300  
Regular quarterly distributions from HEP
    (11,056 )
 
     
Investment in HEP balance at June 30, 2007
  $ (167,161 )
 
     
The following tables provide summary financial results for HEP.
                 
    June 30,     December 31,  
    2007     2006  
    (In thousands)  
Current assets
  $ 20,967     $ 23,624  
Properties and equipment, net
    156,671       160,484  
Transportation agreements and other
    57,551       59,465  
 
           
Total assets
  $ 235,189     $ 243,573  
 
           
 
               
Current liabilities
  $ 10,634     $ 14,174  
Long-term liabilities
    182,413       182,210  
Minority interest
    11,003       10,963  
Partners’ equity
    31,139       36,226  
 
           
Total liabilities and partners’ equity
  $ 235,189     $ 243,573  
 
           
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2007     2006     2007     2006  
            (In thousands)          
Revenues
  $ 27,131     $ 18,527     $ 51,003     $ 40,965  
Operating costs and expenses
    12,746       12,499       25,881       24,625  
 
                       
Operating income
    14,385       6,028       25,122       16,340  
Other expenses, net
    (3,379 )     (3,030 )     (6,682 )     (6,207 )
 
                       
Net income
  $ 11,006     $ 2,998     $ 18,440     $ 10,133  
 
                       
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 $16.4 million and $10.6 million for the three months ended June 30, 2007 and 2006, respectively, and $30.1 million and $23.1 million for the six months ended June 30, 2007 and 2006, respectively.
 
    We charged HEP $0.5 million for three months ended June 30, 2007 and 2006 and $1.0 million for the six months ended June 30, 2007 and 2006 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 $2.3 million and $1.8 million for the three months ended June 30, 2007 and 2006, respectively, and $4.6 million and $3.7 million for the six months ended June 30, 2007 and 2006, respectively, which we recorded as a reduction in expenses.

-13-


Table of Contents

    We reimbursed HEP $24,000 and $40,000 for the three months ended June 30, 2007 and 2006, respectively, and $98,000 and $96,000 for the six months ended June 30, 2007 and 2006, respectively, for certain costs paid on our behalf.
 
    We received as regular distributions on our subordinated units, common units and general partner interest, $5.6 million and $5.0 million for the three months ended June 30, 2007 and 2006, respectively, and $11.1 million and $9.8 million for the six months ended June 30, 2007 and 2006, respectively. Our distributions for the three months ended June 30, 2007 and 2006 included $0.5 million and $0.3 million, respectively, in incentive distributions with respect to our general partner interest. General partner incentive distributions of $1.0 million and $0.5 million were included in our distributions for the six months ended June 30, 2007 and 2006, respectively.
 
    We had a related party receivable from HEP of $2.1 million and $2.2 million at June 30, 2007 and December 31, 2006, respectively.
 
    We had accounts payable to HEP of $6.0 million and $5.7 million at June 30, 2007 and December 31, 2006, respectively.
 
    “Prepayments and other” includes $0.7 million and $0.2 million at June 30, 2007 and December 31, 2006, respectively, related to minimum payments under the HEP IPA which may be applied as credits against future billings from HEP if our shipments exceed the minimum volume commitments on the intermediate pipelines.
NOTE 4: Earnings Per Share
Basic earnings per share from continuing operations is calculated as income from continuing operations divided by the average number of shares of common stock outstanding. Diluted earnings per share from continuing operations 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 for income from continuing operations:
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2007     2006     2007     2006  
    (In thousands, except per share data)  
Income from continuing operations
  $ 158,627     $ 87,729     $ 226,169     $ 118,889  
Average number of shares of common stock outstanding
    54,959       57,186       55,073       57,819  
Effect of dilutive stock options, variable restricted shares and performance share units
    994       1,177       1,006       1,253  
 
                       
Average number of shares of common stock outstanding assuming dilution
    55,953       58,363       56,079       59,072  
 
                       
Basic earnings per share from continuing operations
  $ 2.89     $ 1.53     $ 4.11     $ 2.06  
 
                       
Diluted earnings per share from continuing operations
  $ 2.84     $ 1.51     $ 4.03     $ 2.01  
 
                       
NOTE 5: Stock-Based Compensation
On June 30, 2007 we had three principal share-based compensation plans, which are described below. The compensation cost recognized under these plans was $4.7 million and $7.1 million for the three months ended June 30, 2007 and 2006, respectively, and $9.1 million and $10.8 million for the six months ended June 30, 2007 and 2006, respectively. The total income tax benefit recognized in our consolidated statements of income for share-based compensation arrangements was $1.8 million and $2.8 million for the three months ended June 30, 2007 and 2006, respectively, and $3.2 million and $4.2 million for the six months ended June 30, 2007 and 2006, respectively. It is currently our practice to issue new shares for settlement of option exercises, restricted stock grants or performance

-14-


Table of Contents

share units settled in stock. Our current accounting policy for the recognition of compensation expense on 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 June 30, 2007, 2,550,411 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 following the grant date. There have been no options granted since December 2001. The fair value on the date of grant of each option awarded was estimated using the Black-Scholes option pricing model.
A summary of option activity as of June 30, 2007, and changes during the six months ended June 30, 2007 is presented below:
                                 
                    Weighted–        
            Weighted–     Average     Aggregate  
            Average     Remaining     Intrinsic  
            Exercise     Contractual     Value  
             Options   Shares     Price     Term     ($000)  
Outstanding at January 1, 2007
    1,576,800     $ 2.25                  
Exercised
    (177,600 )     3.07                  
Forfeited or expired
                           
 
                             
Outstanding at June 30, 2007
    1,399,200     $ 2.15       2.6     $ 100,805  
 
                       
Exercisable at June 30, 2007
    1,399,200     $ 2.15       2.6     $ 100,805  
 
                       
The total intrinsic value of options exercised during the six months ended June 30, 2007 and 2006, was $11.1 million and $23.2 million, respectively.
At June 30, 2007 and December 31, 2006, all stock options granted were fully vested. The total fair value of shares vested during the six months ended June 30, 2006 was $0.3 million.
Cash received from option exercises under the stock option plans for the six months ended June 30, 2007 and 2006, was $0.5 million and $2.2 million, respectively. The actual tax benefit realized for the tax deductions from option exercises under the stock option plans totaled $4.3 million and $8.9 million for the six months ended June 30, 2007 and 2006, 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.

-15-


Table of Contents

A summary of restricted stock grant activity and changes during the six months ended June 30, 2007 is presented below:
                         
            Weighted–        
            Average        
            Grant-Date     Aggregate Intrinsic  
                Restricted Stock   Grants     Fair Value     Value ($000)  
Outstanding at January 1, 2007 (nonvested)
    494,922     $ 15.07          
Vesting and transfer of ownership to recipients
    (253,802 )     13.35          
Granted
    65,304       58.01          
Forfeited
    (21,085 )     25.58          
 
                     
Outstanding at June 30, 2007 (nonvested)
    285,339     $ 25.64     $ 16,921  
 
                 
The total intrinsic value of restricted stock vested and transferred to recipients during the six months ended June 30, 2007 and 2006 was $15.1 million and $5.5 million, respectively. As of June 30, 2007, there was $3.9 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 1.2 years. The total fair value of shares vested during the six months ended June 30, 2007 and 2006 was $3.4 million and $1.0 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 2007 first quarter, we granted 42,813 performance share units with a fair value based on our grant date closing stock price of $55.47. 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 June 30, 2007, estimated share payouts for outstanding nonvested performance share unit awards ranged from 100% 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.
The fair value of each performance share unit award payable in cash is computed quarterly using 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.

-16-


Table of Contents

At June 30, 2007, the price of our stock was $74.19, the latest quarterly dividend was $0.12, and the risk-free rate was 5.21%. The inputs affecting the expected total return for us and the peer group are based on a capital asset pricing model utilizing information available at the measurement date. The monthly standard deviation of returns is based on the standard deviation of historical return information. The expected return and standard deviation are presented below:
                 
            Standard
       Company   Expected Return on Equity   Deviation (Monthly)
Holly
    12.7 %     7.3 %
Peer group
  11.2% to 13.7%   8.6% to 12.8%
A summary of performance share units’ activity and changes during the six months ended June 30, 2007 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, 2007 (nonvested)
    227,350       125,774       74,928       428,052  
Vesting and payment of benefit to recipients
    (145,900 )     (75,500 )           (221,400 )
Granted
                42,813       42,813  
Forfeited
          (7,550 )     (10,063 )     (17,613 )
 
                               
Outstanding at June 30, 2007 (nonvested)
    81,450       42,724       107,678       231,852  
 
                               
For the six months ended June 30, 2007 we paid $15.5 million in cash and issued 75,500 shares of our common stock having a fair value of $3.7 million related to vested performance share units. As of June 30, 2007, the cash liability associated with nonvested performance share units was $9.9 million and is recorded in “Accrued liabilities” in our consolidated balance sheets. At June 30, 2007, there was a total of $6.6 million of unrecognized compensation cost related to nonvested performance share units. This total consists of unrecognized compensation costs of $4.5 million related to stock-settled performance units having a weighted average grant date fair value of $36.68 and $2.1 million related to cash-settled performance units having a weighted average fair value of $74.19. These costs are expected to be recognized over a weighted-average period of 1.3 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. 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.

-17-


Table of Contents

The following is a summary of our available-for-sale securities at June 30, 2007:
                         
    Available-for-Sale Securities  
                    Estimated  
            Gross     Fair Value  
            Unrealized     (Net Carrying  
    Amortized Cost     Losses     Amount)  
    (In thousands)  
States and political subdivisions
  $ 300,799     $ (120 )   $ 300,679  
Equity securities
    4,328       (858 )     3,470  
 
                 
Total marketable securities
  $ 305,127     $ (978 )   $ 304,149  
 
                 
Interest income on our marketable debt securities for the six months ended June 30, 2007 and 2006 included $3.5 million and $3.3 million, respectively, of interest earned, $5,000 and $10,000, respectively, in realized gains and amortization of $0.4 million and $1.1 million, respectively, in net premiums paid related to our marketable debt securities. We had 85 and 152 sales and maturities during the six months ended June 30, 2007 and 2006, respectively, in which we received a total of $158.2 million and $198.0 million, respectively. The realized gains represent the difference between the purchase price, as amortized, and the market value on the maturity or sales date.
NOTE 7: Environmental
Consistent with our accounting policy for environmental remediation costs, we expensed $2.2 million and $0.8 million for the three months ended June 30, 2007 and 2006, respectively, and $2.3 million and $3.1 million for the six months ended June 30, 2007 and 2006, respectively, for environmental remediation obligations. The accrued environmental liability reflected in the consolidated balance sheets was $9.5 million and $7.6 million at June 30, 2007 and December 31, 2006, respectively, of which $7.3 million and $6.1 million, respectively, were classified as other long-term liabilities. Costs of future expenditures for environmental remediation are not discounted to their present value.
NOTE 8: Debt
Credit Facility
We have a $175.0 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 $225.0 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 June 30, 2007. At June 30, 2007, 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 June 30, 2007.
We made cash interest payments of $0.3 million for the six months ended June 30, 2007 and 2006.
NOTE 9: Income Taxes
The effective tax rate for continuing operations was 34.8% and 35.6% for the six months ending June 30, 2007 and 2006, respectively. The decrease in our effective tax rate was principally due to a statutory increase in the federal tax deduction for domestic manufacturing activities.

-18-


Table of Contents

NOTE 10: 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 and per share amounts for all periods presented have been adjusted to reflect the split on a retrospective basis.
Common Stock Repurchases: Under our $300.0 million 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 six months ended June 30, 2007, we repurchased 754,518 shares at a cost of $43.0 million or an average of $57.02 per share under this repurchase initiative. Since inception of this repurchase initiative in November 2005 through June 30, 2007, we have repurchased 6,200,725 shares at a cost of $250.0 million or an average of $40.32 per share.
During the six months ended June 30, 2007, we repurchased at current market price from certain officers and other key employees 121,420 shares of our common stock at a cost of $6.7 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.
On August 9, 2007, we announced that our Board of Directors had authorized a $100.0 million increase to our current common stock repurchase program. Before this increase, we had $50.0 million remaining under the repurchase program announced in November 2005 and subsequently increased to $300.0 million in October 2006. Repurchases under the expanded program will be made from time to time in the open market or privately negotiated transactions based on market conditions, securities law limitations and other factors.
NOTE 11: 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 June 30, 2007
                       
Unrealized gain on available-for-sale securities
  $ 66     $ 28     $ 38  
 
                 
Other comprehensive loss
  $ 66     $ 28     $ 38  
 
                 
 
                       
For the three months ended June 30, 2006
                       
Unrealized loss on available-for-sale securities
  $ (418 )   $ (162 )   $ (256 )
 
                 
Other comprehensive loss
  $ (418 )   $ (162 )   $ (256 )
 
                 
 
                       
For the six months ended June 30, 2007
                       
Retirement medical obligation adjustment
  $ (2,792 )   $ (1,086 )   $ (1,706 )
Unrealized gain on available-for-sale securities
    423       165       258  
 
                 
Other comprehensive loss
  $ (2,369 )   $ (921 )   $ (1,448 )
 
                 
 
                       
For the six months ended June 30, 2006
                       
Unrealized loss on available-for-sale securities
  $ (209 )   $ (81 )   $ (128 )
 
                 
Other comprehensive loss
  $ (209 )   $ (81 )   $ (128 )
 
                 
Unrealized gains and losses are due to changes in market values of our available-for-sale securities and are temporary in nature.

-19-


Table of Contents

Accumulated other comprehensive loss in the equity section of our consolidated balance sheets includes:
                 
    June 30,     December 31,  
    2007     2006  
    (In thousands)  
Pension obligation adjustment
  $ (1,115 )   $ (1,115 )
Unrealized loss on available-for-sale securities
    (598 )     (856 )
Adjustment to apply adoption of SFAS No. 158, net of income tax effect of $8,149 and $7,063, respectively
    (11,093 )     (9,387 )
 
           
Accumulated other comprehensive loss
  $ (12,806 )   $ (11,358 )
 
           
NOTE 12: 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.
The net periodic pension expense consisted of the following components:
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2007     2006     2007     2006  
            (In thousands)          
Service cost
  $ 465     $ 1,179     $ 2,055     $ 2,226  
Interest cost
    633       1,083       2,037       2,097  
Expected return on assets
    (473 )     (892 )     (2,039 )     (1,748 )
Amortization of prior service cost
    132       67       195       133  
Amortization of net loss
    171       288       454       608  
One time cost incurred with sale of Montana Refinery
          300             300  
 
                       
Net periodic benefit cost
  $ 928     $ 2,025     $ 2,702     $ 3,616  
 
                       
The expected long-term annual rate of return on plan assets is 8.5%. This rate was used in measuring 2007 and 2006 net periodic benefit cost. We will contribute $10.0 million to the retirement plan in 2007. No contributions were made during the six months ended June 30, 2007.
NOTE 13: Contingencies
On May 29, 2007, the United States Court of Appeals for the District of Columbia Circuit 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 an 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 years 1992 through 2006 in addition to the $15.3 million we received in 2003 from SFPP as reparations for the period from 1993 through July 2000. Because proceedings in the FERC following the court of appeals decision have not been completed and

-20-


Table of Contents

because the decision of the court of appeals could be the subject of petitions by one or more parties seeking United States Supreme Court review of issues addressed, it is not possible at this time to determine what will be the net amount payable to us at the conclusion of these proceedings.
In discussions beginning in the last half of 2005, the EPA and the State of Utah have asserted that we have Federal Clean Air Act 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 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 Refinery and previously-owned Montana Refinery. 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.
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.

-21-


Table of Contents

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 June 30, 2007, we also owned a 45% 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 six months ended June 30, 2007 were $2,142.9 million and our net income for the six months ended June 30, 2007 was $226.2 million. Our sales and other revenues and net income for the six months ended June 30, 2006 were $1,912.4 million and $139.9 million, respectively. Our principal expenses are costs of products sold and operating expenses. Our total operating costs and expenses for the six months ended June 30, 2007 were $1,809.7 million, as compared to $1,736.2 for the six months ended June 30, 2006.
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 operations and a net gain of $14.0 million on the sale.
Under our $300.0 million 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 six months ended June 30, 2007, we repurchased under this repurchase initiative 754,518 shares at a cost of $43.0 million or an average of $57.02 per share. Since inception of this repurchase initiative in November 2005 through June 30, 2007, we have repurchased 6,200,725 shares at a cost of $250.0 million or an average of $40.32 per share.
On August 9, 2007, we announced that our Board of Directors had authorized a $100.0 million increase to our current common stock repurchase program. Before this increase, we had $50.0 million remaining under the repurchase program initiated in November 2005 and subsequently increased to $300.0 million in October 2006. Repurchases under the expanded program will be made from time to time in the open market or privately negotiated transactions based on market conditions, securities law limitations and other factors.

-22-


Table of Contents

RESULTS OF OPERATIONS
Financial Data (Unaudited)
                                 
    Three Months Ended        
    June 30,     Change from 2006  
    2007     2006     Change     Percent  
    (In thousands, except per share data)  
Sales and other revenues
  $ 1,216,997     $ 1,120,840     $ 96,157       8.6 %
Operating costs and expenses:
                               
Cost of products sold (exclusive of depreciation, depletion and amortization)
    897,237       908,009       (10,772 )     (1.2 )
Operating expenses (exclusive of depreciation, depletion and amortization)
    51,116       49,092       2,024       4.1  
General and administrative expenses (exclusive of depreciation, depletion and amortization)
    21,348       18,731       2,617       14.0  
Depreciation, depletion and amortization
    10,641       10,683       (42 )     (0.4 )
Exploration expenses, including dry holes
    105       100       5       5.0  
 
                         
Total operating costs and expenses
    980,447       986,615       (6,168 )     (0.6 )
 
                         
 
Income from operations
    236,550       134,225       102,325       76.2  
Other income (expense):
                               
Equity in earnings of HEP
    4,954       1,516       3,438       226.8  
Interest income
    3,550       2,408       1,142       47.4  
Interest expense
    (291 )     (272 )     (19 )     7.0  
 
                         
 
    8,213       3,652       4,561       124.9  
 
                         
Income from continuing operations before income taxes
    244,763       137,877       106,886       77.5  
Income tax provision
    86,136       50,148       35,988       71.8  
 
                         
Income from continuing operations
    158,627       87,729       70,898       80.8  
Income from discontinued operations, net of taxes
          5,372       (5,372 )     (100.0 )
 
                         
Net income
  $ 158,627     $ 93,101     $ 65,526       70.4 %
 
                         
 
                               
Basic earnings per share:
                               
Continuing operations
  $ 2.89     $ 1.53     $ 1.36       88.9 %
Discontinued operations
          0.09       (0.09 )     (100.0 )
 
                         
Net income
  $ 2.89     $ 1.62     $ 1.27       78.4 %
 
                         
 
                               
Diluted earnings per share:
                               
Continuing operations
  $ 2.84     $ 1.51     $ 1.33       88.1 %
Discontinued operations
          0.09       (0.09 )     (100.0 )
 
                         
Net income
  $ 2.84     $ 1.60     $ 1.24       77.5 %
 
                         
 
                               
Cash dividends declared per common share
  $ 0.12     $ 0.08     $ 0.04       50.0 %
 
                               
Average number of common shares outstanding:
                               
Basic
    54,959       57,186       (2,227 )     (3.9 )%
Diluted
    55,953       58,363       (2,410 )     (4.1 )%

-23-


Table of Contents

                                 
    Six Months Ended        
    June 30,     Change from 2006  
    2007     2006     Change     Percent  
    (In thousands, except per share data)  
Sales and other revenues
  $ 2,142,864     $ 1,912,434     $ 230,430       12.0 %
Operating costs and expenses:
                               
Cost of products sold (exclusive of depreciation, depletion and amortization)
    1,648,951       1,583,494       65,457       4.1  
Operating expenses (exclusive of depreciation, depletion and amortization)
    101,245       101,559       (314 )     (0.3 )
General and administrative expenses (exclusive of depreciation, depletion and amortization)
    37,195       32,247       4,948       15.3  
Depreciation, depletion and amortization
    22,092       18,707       3,385       18.1  
Exploration expenses, including dry holes
    257       227       30       13.2  
 
                         
Total operating costs and expenses
    1,809,740       1,736,234       73,506       4.2  
 
                         
 
                               
Income from operations
    333,124       176,200       156,924       89.1  
Other income (expense):
                               
Equity in earnings of HEP
    8,300       4,728       3,572       75.6  
Interest income
    6,110       4,143       1,967       47.5  
Interest expense
    (543 )     (547 )     4       (0.7 )
 
                         
 
    13,867       8,324       5,543       66.6  
 
                         
Income from continuing operations before income taxes
    346,991       184,524       162,467       88.0  
Income tax provision
    120,822       65,635       55,187       84.1  
 
                         
Income from continuing operations
    226,169       118,889       107,280       90.2  
Income from discontinued operations, net of taxes
          21,016       (21,016 )     (100.0 )
 
                         
Net income
  $ 226,169     $ 139,905     $ 86,264       61.7 %
 
                         
 
                               
Basic earnings per share:
                               
Continuing operations
  $ 4.11     $ 2.06     $ 2.05       99.5 %
Discontinued operations
          0.36       (0.36 )     (100.0 )
 
                         
Net income
  $ 4.11     $ 2.42     $ 1.69       69.8 %
 
                         
 
                               
Diluted earnings per share:
                               
Continuing operations
  $ 4.03     $ 2.01     $ 2.02       100.5 %
Discontinued operations
          0.36       (0.36 )     (100.0 )
 
                         
Net income
  $ 4.03     $ 2.37     $ 1.66       70.0 %
 
                         
 
                               
Cash dividends declared per common share
  $ 0.22     $ 0.13     $ 0.09       69.2 %
 
                               
Average number of common shares outstanding:
                               
Basic
    55,073       57,819       (2,746 )     (4.7 )%
Diluted
    56,079       59,072       (2,993 )     (5.1 )%
Balance Sheet Data (Unaudited)
                 
    June 30,     December 31,  
    2007     2006  
    (In thousands)  
Cash, cash equivalents and investments in marketable securities
  $ 411,286     $ 255,953  
Working capital
  $ 321,259     $ 240,181  
Total assets
  $ 1,457,477     $ 1,237,869  
Stockholders’ equity
  $ 640,000     $ 466,094  

-24-


Table of Contents

Other Financial Data (Unaudited)
                                 
    Three Months Ended   Six Months Ended
    June 30,   June 30,
    2007   2006   2007   2006
    (In thousands)
Net cash provided by operating activities
  $ 194,283     $ 98,135     $ 280,584     $ 79,795  
Net cash provided by (used for) investing activities
  $ (220,646 )   $ (43,760 )   $ (274,421 )   $ 76,128  
Net cash used for financing activities
  $ (17,679 )   $ (31,130 )   $ (53,143 )   $ (87,131 )
Capital expenditures
  $ 45,781     $ 35,259     $ 72,531     $ 67,494  
EBITDA from continuing operations (1)
  $ 252,145     $ 146,424     $ 363,516     $ 199,635  
 
(1)   Earnings before interest, taxes, depreciation and amortization, which we refer to as EBITDA, is calculated as net income plus (i) interest expense net of interest income, (ii) income tax provision, and (iii) depreciation, depletion and amortization. EBITDA is not a calculation provided for under accounting principles generally accepted in the United States; however, the amounts included in the EBITDA calculation are derived from amounts included in our consolidated financial statements. EBITDA should not be considered as an alternative to net income or operating income as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity. EBITDA is not necessarily comparable to similarly titled measures of other companies. EBITDA is presented here because it is a widely used financial indicator used by investors and analysts to measure performance. EBITDA is also used by our management for internal analysis and as a basis for financial covenants. We are reporting EBITDA from continuing operations. EBITDA presented above is reconciled to net income under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 3 of Part I of this Form 10-Q.

-25-


Table of Contents

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     Six Months Ended  
    June 30,     June 30,  
    2007     2006     2007     2006  
Navajo Refinery
                               
Crude charge (BPD) (1)
    82,730       60,380       79,790       66,420  
Refinery production (BPD) (2)
    90,940       65,600       88,540       73,320  
Sales of produced refined products (BPD)
    90,660       66,320       88,040       73,000  
Sales of refined products (BPD) (3)
    100,840       83,940       98,610       87,340  
 
                               
Refinery utilization (4)
    99.7 %     80.5 %     96.1 %     88.6 %
 
                               
Average per produced barrel (5)
                               
Net sales
  $ 93.17     $ 90.76     $ 84.69     $ 82.49  
Cost of products (6)
    65.63       67.34       62.45       64.90  
 
                       
Refinery gross margin
    27.54       23.42       22.24       17.59  
Refinery operating expenses (7)
    4.26       5.37       4.22       5.07  
 
                       
Net operating margin
  $ 23.28     $ 18.05     $ 18.02     $ 12.52  
 
                       
 
                               
Feedstocks:
                               
Sour crude oil
    78 %     80 %     76 %     81 %
Sweet crude oil
    10 %     9 %     10 %     7 %
Other feedstocks and blends
    12 %     11 %     14 %     12 %
 
                       
Total
    100 %     100 %     100 %     100 %
 
                       
 
                               
Sales of produced refined products:
                               
Gasolines
    58 %     57 %     59 %     60 %
Diesel fuels
    30 %     27 %     29 %     26 %
Jet fuels
    3 %     5 %     3 %     5 %
Fuel oil
    3 %     %     3 %     %
Asphalt
    3 %     4 %     3 %     3 %
LPG and other
    3 %     7 %     3 %     6 %
 
                       
Total
    100 %     100 %     100 %     100 %
 
                       
Woods Cross Refinery
                               
Crude charge (BPD) (1)
    25,800       25,270       25,230       24,010  
Refinery production (BPD) (2)
    27,280       27,030       26,920       25,530  
Sales of produced refined products (BPD)
    26,130       27,500       27,120       25,410  
Sales of refined products (BPD) (3)
    26,230       28,800       27,390       26,640  
 
                               
Refinery utilization (4)
    99.2 %     97.2 %     97.0 %     92.3 %
 
                               
Average per produced barrel (5)
                               
Net sales
  $ 96.51     $ 89.63     $ 83.67     $ 80.52  
Cost of products (6)
    65.29       69.80       60.95       65.42  
 
                       
Refinery gross margin
    31.22       19.83       22.72       15.10  
Refinery operating expenses (7)
    4.22       4.36       4.50       4.99  
 
                       
Net operating margin
  $ 27.00     $ 15.47     $ 18.22     $ 10.11  
 
                       

-26-


Table of Contents

                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2007     2006     2007     2006  
Woods Cross Refinery
                               
Feedstocks:
                               
Sour crude oil
    2 %     3 %     1 %     4 %
Sweet crude oil
    90 %     89 %     90 %     87 %
Other feedstocks and blends
    8 %     8 %     9 %     9 %
 
                       
Total
    100 %     100 %     100 %     100 %
 
                       
 
                               
Sales of produced refined products:
                               
Gasolines
    58 %     64 %     61 %     63 %
Diesel fuels
    31 %     30 %     28 %     28 %
Jet fuels
    3 %     1 %     2 %     2 %
Fuel oil
    7 %     4 %     7 %     5 %
LPG and other
    1 %     1 %     2 %     2 %
 
                       
Total
    100 %     100 %     100 %     100 %
 
                       
 
                               
Consolidated
                               
Crude charge (BPD) (1)
    108,530       85,650       105,020       90,430  
Refinery production (BPD) (2)
    118,220       92,630       115,460       98,850  
Sales of produced refined products (BPD)
    116,790       93,820       115,160       98,410  
Sales of refined products (BPD) (3)
    127,070       112,740       126,000       113,980  
 
                               
Refinery utilization (4)
    99.6 %     84.8 %     96.3 %     89.5 %
 
                               
Average per produced barrel (5)
                               
Net sales
  $ 93.92     $ 90.43     $ 84.45     $ 81.98  
Cost of products (6)
    65.56       68.06       62.10       65.03  
 
                       
Refinery gross margin
    28.36       22.37       22.35       16.95  
Refinery operating expenses (7)
    4.25       5.08       4.29       5.05  
 
                       
Net operating margin
  $ 24.11     $ 17.29     $ 18.06     $ 11.90  
 
                       
 
                               
Feedstocks:
                               
Sour crude oil
    60 %     58 %     59 %     61 %
Sweet crude oil
    28 %     32 %     29 %     28 %
Other feedstocks and blends
    12 %     10 %     12 %     11 %
 
                       
Total
    100 %     100 %     100 %     100 %
 
                       
 
                               
Sales of produced refined products:
                               
Gasolines
    58 %     59 %     59 %     61 %
Diesel fuels
    30 %     27 %     29 %     27 %
Jet fuels
    3 %     4 %     3 %     4 %
Fuel oil
    4 %     1 %     4 %     1 %
Asphalt
    2 %     3 %     2 %     2 %
LPG and other
    3 %     6 %     3 %     5 %
 
                       
Total
    100 %     100 %     100 %     100 %
 
                       
 
(1)   Crude charge represents the barrels per day of crude oil processed at the crude units at our refineries.
 
(2)   Refinery production represents the barrels per day of refined products yielded from processing crude and other refinery feedstocks through the crude units and other conversion units at our refineries.
 
(3)   Includes refined products purchased for resale.
 
(4)   Represents crude charge divided by total crude capacity (BPSD).
 
(5)   Represents average per barrel amount for produced refined products sold, which is a non-GAAP measure. Reconciliations to amounts reported under GAAP are located under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 3 of Part I of this Form 10-Q.
 
(6)   Transportation costs billed from HEP are included in cost of products.
 
(7)   Represents operating expenses of our refinery, exclusive of depreciation, depletion and amortization, and excludes refining segment expenses of product pipelines and terminals.

-27-


Table of Contents

Results of Operations — Three Months Ended June 30, 2007 Compared to Three Months Ended June 30, 2006
Summary
Income from continuing operations was $158.6 million ($2.89 per basic and $2.84 per diluted share) in the second quarter of 2007, compared to income from continuing operations of $87.7 million ($1.53 per basic and $1.51 per diluted share) in the second quarter of 2006. Income from continuing operations increased $70.9 million for the second quarter of 2007, an increase of 81%, as compared to the second quarter of 2006, principally due to improved refined product margins experienced in the current year’s second quarter and an increase in volume of produced refined products sold. These favorable factors were partially offset by the effects of higher operating and general and administrative expenses incurred in the second quarter of 2007. Overall sales of produced refined products from continuing operations increased by 25% for the second quarter of 2007 as compared to the same period in 2006. Overall refinery gross margins from continuing operations were $28.36 per produced barrel for the second quarter of 2007 compared to refinery gross margins from continuing operations of $22.37 per produced barrel for the second quarter of 2006.
The large increase in volume of produced refined products sold is attributable to increased production levels for the three months ended June 30, 2007 as compared to the same period in 2006. Our production levels were lower for the three months ended June 30, 2006 due to planned downtime at our Navajo and Woods Cross Refineries during the second quarter of 2006. Diesel fuel produced at both of our refineries was required to meet certain nationwide ultra low sulfur diesel fuel (“ULSD”) requirements as of June 30, 2006. To meet this requirement, we completed certain ULSD projects at both refineries during the second quarter of 2006. In conjunction with these ULSD projects, we timed other refinery maintenance projects and an expansion of our Navajo Refinery. Downtime incurred from these capital projects was the principal factor in our reduced production levels during the second quarter 2006. Also contributing to our production increase for the three months ended June 30, 2007 is an increase in production levels following our 8,000 BPSD Navajo Refinery expansion in mid-year 2006.
Sales and Other Revenues
Sales and other revenues from continuing operations increased 9% from $1,120.8 million in the second quarter of 2006 to $1,217.0 million in the second quarter of 2007, due principally to higher refined product sales prices and an increase in volumes of produced refined products sold. The average sales price we received per produced barrel sold increased 4% from $90.43 in the second quarter of 2006 to $93.92 in the second quarter of 2007. The total volume of produced refined products sold increased 25% in the second quarter of 2007 as compared to the second quarter of 2006.
Cost of Products Sold
Cost of products sold decreased 1% from $908.0 million in the second quarter of 2006 to $897.2 million in the second quarter of 2007, due principally to a per unit decrease in the cost of produced refined products sold, partially offset by an increase in volumes of produced refined products sold. The total volume of produced refined products sold increased 25% in the second quarter of 2007 as compared to the second quarter of 2006. The average price we paid per barrel of crude oil and feedstocks purchased and the transportation costs of moving the finished products to the market place decreased 4% from $68.06 in the second quarter of 2006 to $65.56 in the second quarter of 2007.
Gross Refinery Margins
Gross refining margin per produced barrel increased 27% from $22.37 in the second quarter of 2006 to $28.36 in the second quarter of 2007 due to the combined effects of an increase in the average sales price we received per produced barrel sold and a decrease in the average price we paid per barrel of crude oil and feedstocks purchased. Gross refinery margin does not include the effects of depreciation, depletion and amortization. See “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 3 of Part 1 of this Form 10-Q for a reconciliation to the income statement of prices of refined products sold and cost of products purchased.
Operating Expenses
Operating expenses, exclusive of depreciation, depletion and amortization, increased 4% from $49.1 million in the second quarter of 2006 to $51.1 million in the second quarter of 2007, due principally to higher utility costs.

-28-


Table of Contents

General and Administrative Expenses
General and administrative expenses increased 14% from $18.7 million in the second quarter of 2006 to $21.3 million in the second quarter of 2007, due primarily to increased equity-based incentive compensation expense and software implementation costs. The increase in our equity-based compensation expense is due to an increase in our stock price.
Depreciation, Depletion and Amortization Expenses
Depreciation, depletion and amortization of $10.7 million in the second quarter of 2007 was comparable to the second quarter of 2006.
Equity in Earnings of HEP
Our equity in earnings of HEP was $5.0 million in the second quarter of 2007 as compared to $1.5 million in the second quarter of 2006. The increase in our equity in earnings of HEP was principally due to an increase in HEP’s earnings in the second quarter of 2007 as compared to the second quarter of 2006.
Interest Income
Interest income in the second quarter of 2007 was $3.6 million compared to $2.4 million in the second quarter of 2006. The increase in interest income was principally due to the effects of a higher interest rate environment combined with increased investments in marketable debt securities.
Interest Expense
Interest expense was $0.3 million for the second quarter of 2007 and 2006.
Income Taxes
Income taxes increased 72% from $50.1 million in the second quarter of 2006 to $86.1 million in the second quarter of 2007, due to significantly higher pre-tax earnings during the 2007 second quarter as compared to the 2006 second quarter. The effective tax rate for the second quarter of 2007 was 35.2%, as compared to 36.4% for the second quarter of 2006. The decrease in our effective tax rate was principally due to a statutory increase in the federal tax deduction for domestic manufacturing activities.
Discontinued Operations
We had no income from discontinued operations in the second quarter of 2007 as our Montana Refinery operations have ceased. Income from discontinued operations was $5.4 million in the second quarter of 2006, which was largely due to the liquidation of certain retained quantities of inventories not included in the sale of our Montana Refinery at March 31, 2006.
Results of Operations — Six Months Ended June 30, 2007 Compared to Six Months Ended June 30, 2006
Summary
Income from continuing operations was $226.2 million ($4.11 per basic and $4.03 per diluted share) for the six months ended June 30, 2007, compared to income from continuing operations of $118.9 million ($2.06 per basic and $2.01 per diluted share) for the six months ended June 30, 2006. Income from continuing operations increased $107.3 million for the six months ended June 30, 2007, an increase of 90%, as compared to the six months ended June 30, 2006, principally due to improved refined product margins experienced in the current year and an increase in volume of produced refined products sold. These favorable factors were partially offset by the effects of higher depreciation, depletion and amortization costs and general and administrative expenses incurred in the current year. Overall sales of produced refined products from continuing operations increased by 17% for the six months ended June 30, 2007 as compared to the same period in 2006. Overall refinery gross margins from continuing operations were $22.35 per produced barrel for the six months ended June 30, 2007 compared to refinery gross margins from continuing operations of $16.95 per produced barrel for the six months ended June 30, 2006.
The large increase in volume of produced refined products sold is attributable to increased production levels for the six months ended June 30, 2007 as compared to the same period in 2006. Our production levels were lower for the six months ended June 30, 2006 due to planned downtime at our Navajo and Woods Cross Refineries during the second quarter of 2006.

-29-


Table of Contents

Diesel fuel produced at both of our refineries was required to meet certain nationwide ultra low sulfur diesel fuel (“ULSD”) requirements as of June 30, 2006. To meet this requirement, we completed certain ULSD projects at both refineries during the second quarter of 2006. In conjunction with these ULSD projects, we timed other refinery maintenance projects and an expansion of our Navajo Refinery. Downtime incurred from these capital projects was the principal factor in our reduced production levels during the six months ended June 30, 2006. Also contributing to our production increase for the six months ended June 30, 2007, is an increase in production levels following our 8,000 BPSD Navajo Refinery expansion in mid-year 2006.
Sales and Other Revenues
Sales and other revenues from continuing operations increased 12% from $1,912.4 million for the six months ended June 30, 2006 to $2,142.9 million for the six months ended June 30, 2007, due principally to higher refined product sales prices and an increase in volumes of produced refined products sold. The average sales price we received per produced barrel sold increased 3% from $81.98 for the six months ended June 30, 2006 to $84.45 for the six months ended June 30, 2007. The total volume of produced refined products sold increased by 17% for the six months ended June 30, 2007 as compared to the six months ended June 30, 2006.
Cost of Products Sold
Cost of products sold increased 4% from $1,583.5 million in the six months ended June 30, 2006 to $1,649.0 million in the six months ended June 30, 2007, due principally to an increase in volumes of produced refined products sold, partially offset by a per unit decrease in the cost of produced refined products sold. The total volume of produced refined products sold increased 17% for the six months ended June 30, 2007 as compared to the six months ended June 30, 2006. The average price we paid per barrel of crude oil and feedstocks purchased and the transportation costs of moving the finished products to the market place decreased 5% from $65.03 in the six months ended June 30, 2006 to $62.10 in the six months ended June 30, 2007.
Gross Refinery Margins
Gross refining margin per produced barrel increased 32% from $16.95 in the six months ended June 30, 2006 to $22.35 in the six months ended June 30, 2007 due to the combined effects of an increase in the average sales price we received per produced barrel sold and a decrease in the average price we paid per barrel of crude oil and feedstocks purchased. Gross refinery margin does not include the effects of depreciation, depletion and amortization. See “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 3 of Part 1 of this Form 10-Q for a reconciliation to the income statement of prices of refined products sold and cost of products purchased.
Operating Expenses
Operating expenses, exclusive of depreciation, depletion and amortization of $101.2 million in the six months ended June 30, 2007 were comparable to $101.6 million in the six months ended June 30, 2006.
General and Administrative Expenses
General and administrative expenses increased 15% from $32.2 million in the six months ended June 30, 2006 to $37.2 million in the six months ended June 30, 2007, due primarily to increased equity-based incentive compensation expense and software implementation costs. The increase in our equity-based compensation expense is due to an increase in our stock price.
Depreciation, Depletion and Amortization Expenses
Depreciation, depletion and amortization increased 18% from $18.7 million in the six months ended June 30, 2006 to $22.1 million in the six months ended June 30, 2007 due to capitalized refinery improvement projects in 2006.
Equity in Earnings of HEP
Our equity in earnings of HEP was $8.3 million for the six months ended June 30, 2007 as compared to $4.7 million for the six months ended June 30, 2006. The increase in our equity in earnings of HEP was principally due to an increase in HEP’s earnings for the six months ended June 30, 2007 as compared to the six months ended June 30, 2006.

-30-


Table of Contents

Interest Income
Interest income for the six months ended June 30, 2007 was $6.1 million compared to $4.1 million for the six months ended June 30, 2006. The increase in interest income was principally due to the effects of a higher interest rate environment combined with increased investments in marketable debt securities.
Interest Expense
Interest expense was $0.5 million for the six months ended June 30, 2007 and 2006.
Income Taxes
Income taxes increased 84% from $65.6 million for the six months ended June 30, 2006 to $120.8 million for the six months ended June 30, 2007 due to significantly higher pre-tax earnings during the six months ended June 30, 2007 as compared to the six months ended June 30, 2006. The effective tax rate for the six months ended June 30, 2007 was 34.8%, as compared to 35.6% for the six months ended June 30, 2006. The decrease in our effective tax rate was principally due to a statutory increase in the federal tax deduction for domestic manufacturing activities.
Discontinued Operations
We had no income from discontinued operations for the six months ended June 30, 2007 as our Montana Refinery operations have ceased. Income from discontinued operations was $21.0 million for the six months ended June 30, 2006 which consisted of a $14.0 million gain on the sale of the Montana Refinery, net of $8.3 million in income taxes, and $7.0 million of earnings which was largely due to the liquidation of certain retained quantities of inventories that were not included in the sale of our Montana Refinery at March 31, 2006.
LIQUIDITY AND CAPITAL RESOURCES
We consider all highly-liquid instruments with a maturity of three months or less at the time of purchase to be cash equivalents. Cash equivalents are stated at cost, which approximates market value, and are invested primarily in conservative, highly-rated instruments issued by financial institutions or government entities with strong credit standings. We also invest available cash in highly-rated marketable debt securities primarily issued by government entities that have maturities 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 reported as a component of accumulated other comprehensive income or loss. As of June 30, 2007, we had cash and cash equivalents of $107.1 million, marketable securities with maturities under one year of $249.5 million and marketable securities with maturities greater than one year, but less than two years, of $54.6 million.
Cash and cash equivalents decreased by $47.0 million during the six months ended June 30, 2007. The combined cash used for investing activities of $274.4 million and for financing activities of $53.1 million exceeded cash provided by operating activities of $280.6 million. Working capital increased during the six months ended June 30, 2007 by $76.3 million.
We have a $175.0 million secured revolving credit facility with Bank of America as administrative agent and a lender, with a term of four years through 2008 and an option to increase the facility to $225.0 million subject to certain conditions. The credit facility may be used to fund working capital requirements, capital expenditures, acquisitions and other general corporate purposes. As of June 30, 2007, we had letters of credit outstanding under our revolving credit facility of $2.3 million and had no borrowings outstanding. We were in compliance with all covenants at June 30, 2007.

-31-


Table of Contents

Under our $300.0 million 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 six months ended June 30, 2007, we repurchased under this repurchase initiative 754,518 shares at a cost of approximately $43.0 million or an average of $57.02 per share. Since inception of this repurchase initiative in November 2005 through June 30, 2007, we have repurchased 6,200,725 shares at a cost of $250.0 million or an average of $40.32 per share.
On August 9, 2007, we announced that our Board of Directors had authorized a $100.0 million increase to our current common stock repurchase program. Before this increase, we had $50.0 million remaining under the repurchase program initiated in November 2005 and subsequently increased to $300.0 million in October 2006. Repurchases under the expanded program will be made from time to time in the open market or privately negotiated transactions based on market conditions, securities law limitations and other factors.
We believe our current cash, cash equivalents and marketable securities, along with future internally generated cash flow and funds available under our credit facility provide sufficient resources to fund currently planned capital projects and our liquidity needs for the foreseeable future as well as allow us to continue payment of quarterly dividends and the repurchase of additional common stock under our common stock repurchase program. In addition, components of our growth strategy may include construction of new refinery processing units and the expansion of existing units at our facilities and selective acquisition of complementary assets for our refining operations intended to increase earnings and cash flow. Our ability to acquire complementary assets will be dependent upon several factors, including our ability to identify attractive acquisition candidates, consummate acquisitions on favorable terms, successfully integrate acquired assets and obtain financing to fund acquisitions and to support our growth, and many other factors beyond our control.
Cash Flows — Operating Activities
Net cash flows provided by operating activities were $280.6 million for the six months ended June 30, 2007 compared to $79.8 million for the six months ended June 30, 2006, an increase of $200.8 million. Net income for the six months ended June 30, 2007 was $226.2 million, an increase of $86.3 million from net income of $139.9 million for the six months ended June 30, 2006. Additionally, the non-cash adjustments to net income of depreciation and amortization, deferred taxes, equity-based compensation and gain on sale of assets resulted in an increase to operating cash flows of $24.4 million for the six months ended June 30, 2007 as compared to a decrease of $1.3 million for the six months ended June 30, 2006. Distributions in excess of equity in earnings of HEP for the six months ended June 30, 2007 decreased to $2.8 million as compared to $5.1 million for the six months ended June 30, 2006. Changes in working capital items increased cash flows by $26.0 million for the six months ended June 30, 2007, as compared to a decrease of $59.2 million for the six months ended June 30, 2006, resulting mainly from an increase in inventories during the first six months of 2006. For the first six months of 2007, inventories increased by only $14.0 million, as compared to an increase of $49.9 million for the first six months of 2006. Also impacting the working capital items was a $22.6 decrease in net assets of discontinued operations during the six months ended June 30, 2006, due to the sale of the Montana Refinery assets on March 31, 2006. Additionally, for the first six months of 2007, turnaround expenditures amounted to $0.2 million, as opposed to $5.7 million for the first six months of 2006.
Cash Flows — Investing Activities and Capital Projects
Net cash flows used for investing activities were $274.4 million for the six months ended June 30, 2007, as compared to net cash flows provided by investing activities of $76.1 million for the six months ended June 30, 2006, a net change of $350.5 million. Cash expenditures for property, plant and equipment for the first six months of 2007 totaled $72.5 million as compared to $67.5 million for the same period in 2006. On March 31, 2006 we sold our Montana Refinery to Connacher. The cash proceeds we received on the sale of the Montana Refinery were $48.9 million, net of transaction fees and expenses. We also invested $360.0 million in marketable securities and received proceeds of $158.2 million from the sale or maturity of marketable securities during the six months ended June 30, 2007. For the six months ended June 30, 2006, we invested $103.3 million in marketable securities and received proceeds of $198.0 million from the sale or maturity of marketable securities.

-32-


Table of Contents

Planned Capital Expenditures
Each year our Board of Directors approves in our annual capital budget capital projects that our management is authorized to undertake. Additionally, at times when conditions warrant or as new opportunities arise, other special projects may be approved. The funds allocated for a particular capital project may be expended over a period of several years, depending on the time required to complete the project. Therefore, our planned capital expenditures for a given year consist of expenditures approved for capital projects included in the current year’s capital budget as well as, in certain cases, expenditures approved for capital projects in capital budgets for prior years. Our total capital budget for 2007 is approximately $42.1 million, not including the capital projects approved in prior years, our expansion and feedstock flexibility projects at the Navajo and Woods Cross refineries and pipeline projects as described below. The 2007 capital budget is comprised of $24.7 million for refining improvement projects for the Navajo Refinery, $9.7 million for projects at the Woods Cross Refinery, $3.2 million for transportation projects, $0.5 million for marketing-related projects, $2.8 million for asphalt plant projects and $1.2 million for information technology and other miscellaneous projects.
At the Navajo Refinery, we will be installing an additional 100 ton per day sulfur recovery unit at an estimated cost of $26.0 million that will permit Navajo to process 100% sour crude. The sulfur recovery unit is planned for start-up in the first quarter of 2009. Also, we will be installing a new 15,000 BPSD hydrocracker and a new 28 mmscf hydrogen plant at a budgeted cost of approximately $125.0 million. The addition of these units is expected to increase liquid volume recovery, increase the refinery’s capacity to process outside feedstocks, increase yields of high-valued products and enable the refinery to meet the EPA’s new low sulfur gasoline specifications.
As announced in February 2007, we will be revamping the Lovington crude unit at the Navajo Refinery which will increase crude capacity to approximately 100,000 BPSD. In addition, our Board of Directors has approved a revamp of the Artesia crude unit and the installation of a new 20,000 BPSD ROSE unit which combined with the hydrogen plant and the new hydrocracker and sulfur recovery units will allow the Navajo Refinery to process approximately 40,000 BPSD of heavy Canadian crude oil. The estimated cost of the combined crude expansion and heavy Canadian crude oil processing project is approximately $225.0 million. It is currently anticipated that the expansion portion of the overall project consisting of the initial crude unit revamp, the new hydrocracker and the new hydrogen plant will be completed and operational by the first quarter of 2009. The completion of the heavy crude oil processing portion of the overall project, including the second crude unit revamp and the installation of the new solvent de-asphalter, will be targeted to coincide with development of future pipeline access to the Navajo Refinery for heavy Canadian crude oil and other foreign heavy crude oils transported from the Cushing, Oklahoma area. We plan to explore with HEP the most economical manner to obtain this needed pipeline access.
At the Woods Cross Refinery, we will be adding a new 15,000 BPD hydrocracker along with sulfur recovery and desalting equipment. The budgeted cost of these additions is approximately $100.0 million. These additions will expand the Woods Cross Refinery’s crude processing capabilities from 26,000 BPD to 31,000 BPD while enabling the refinery to process up to 10,000 BPD of high-value low-priced black wax crude oil and up to 5,000 BPD of low-priced heavy Canadian crude oils. The Woods Cross Refinery expansion project as approved involves a higher capital investment than had originally been estimated, principally because of the substitution of a complex hydrocracker in place of certain desulfurization and expanded bottoms-processing modifications that had been included in preliminary planning. The substitution of the complex hydrocracker is expected to provide increased capabilities to process significantly more black wax crude oils, which have recently been priced at substantial discounts to West Texas Intermediate crude oil, while yielding substantially higher value products than the discounted heavy Canadian crudes that were a more significant part of the original plan. These additions would also increase the refinery’s capacity to process low-cost feedstocks and provide the necessary infrastructure for future expansions of crude oil refining capacity at the Woods Cross Refinery while enabling the refinery to meet the EPA’s new low sulfur gasoline specifications. The approved projects for the Woods Cross Refinery are expected to be completed during the fourth quarter of 2008.
In 2007, we expect to expend a total of approximately $179.0 million on currently approved refinery capital projects, which amount consists of certain carryovers of capital projects from previous years, less carryovers to subsequent years of certain of the currently approved capital projects.

-33-


Table of Contents

To fully take advantage of the economics on the Woods Cross expansion project, additional crude pipeline capacity will be required to move Canadian crude to the Woods Cross Refinery. In February 2007, HEP entered into a letter of intent with Plains All American Pipeline, L.P. (“Plains”) under which HEP will own a 25% interest in a new 95 mile intrastate pipeline system, now being constructed by Plains, capable of shipping up to 120,000 BPD of crude oil into the Salt Lake City area.
As previously announced, we have entered into a Memorandum of Understanding with Sinclair Transportation Company (‘Sinclair”) to jointly build a 12-inch pipeline from Salt Lake City, Utah to Las Vegas, Nevada, together with terminal facilities in the Cedar City, Utah and north Las Vegas areas (the “UNEV Pipeline”). Subject to the execution of definitive agreements, we will own a 75% interest and Sinclair will own a 25% interest in the project. We have an understanding with HEP that they will be the operator and will have an option to purchase our interest in the project, effective for a 180-day period commencing when the UNEV Pipeline becomes operational, at a purchase price equal to our share of actual costs, plus interest at 7% per annum. The initial capacity of the pipeline will be approximately 62,000 bpd, with the capacity for further expansion to approximately 120,000 bpd. The cost of the pipeline is expected to be approximately $225.0 million, and the total cost of the project including terminals is expected to be approximately $300.0 million. We have already begun certain preliminary work on this project. Construction of this project is currently expected to be completed by the end of 2008.
In October 2004, the American Jobs Creation Act of 2004 (“2004 Act”) was signed into law. Among other things, the 2004 Act creates tax incentives for small business refiners incurring costs to produce ULSD. The 2004 Act provides an immediate deduction of 75% of certain costs paid or incurred to comply with the ULSD standards, and a tax credit based on ULSD production of up to 25% of those costs. We estimate the tax savings that we derive from planned capital expenditures associated with the 2004 Act will result in a reduction in our income tax expense of approximately $8.4 million in 2007, representing the difference between the value of allowed credits under the 2004 Act as compared to the value of depreciating the investments. In August 2005, the Energy Policy Act of 2005 (“2005 Act”) was signed into law. Among other things, the 2005 Act creates tax incentives for refiners by providing for an immediate deduction of 50% of certain refinery capacity expansion costs when the expansion assets are placed in service. We believe the capacity expansion projects at the Navajo and Woods Cross refineries will qualify for this deduction.
The above mentioned regulatory compliance items, including the ULSD and LSG requirements, or other presently existing or future environmental regulations could cause us to make additional capital investments beyond those described above and incur additional operating costs to meet applicable requirements.
Cash Flows — Financing Activities
Net cash flows used for financing activities were $53.1 million for the six months ended June 30, 2007, as compared to $87.1 million for the six months ended June 30, 2006, a decrease of $34.0 million. Under our common stock repurchase program, we purchased treasury stock of $51.1 million during the six months ended June 30, 2007 and $92.3 million during the six months ended June 30, 2006. Our treasury stock purchases for the six months ended June 30, 2007 and 2006, include $6.7 million and $1.4 million, respectively, in common stock purchased from certain officers and other key employees, at market prices, made 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 six months ended June 30, 2007, we paid $10.1 million in dividends, received $0.5 million for common stock issued upon exercise of stock options, and recognized $7.5 million in excess tax benefits on our equity based compensation. During the six months ended June 30, 2006, we paid $5.9 million in dividends, received $2.2 million for common stock issued upon exercise of stock options and recognized $8.9 million in excess tax benefits on our equity based compensation.

-34-


Table of Contents

Contractual Obligations and Commitments
During the six months ended June 30, 2007, there were no significant changes to our contractual obligations for our agreements with HEP and operating leases, other than the regular payments made under the existing pipelines and terminals agreements with HEP and operating leases.
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 HEP’s refined product pipelines or throughput in HEP’s terminals a volume of refined products that will result in minimum annual payments to HEP. Following the July 1, 2007 producer price index (“PPI”) rate adjustment, minimum payments under the HEP PTA will be $39.6 million for the twelve months ending June 30, 2008. Under the HEP IPA, we agreed to transport volumes of intermediate products on the intermediate pipelines that will result in minimum annual payments to HEP. Following the July 1, 2007 PPI rate adjustment, minimum payments under the HEP IPA will be $12.8 million for the twelve months ending June 30, 2008. 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 $15.0 million relates solely to the intermediate pipelines.
HEP financed the Alon transaction through a private offering of $150.0 million principal amount of HEP Senior Notes. HEP increased these notes to $185.0 million as part of the purchase of our intermediate pipelines. The $185.0 million HEP Senior Notes are not recorded on our accompanying consolidated balance sheets at June 30, 2007 or December 31, 2006. Navajo Pipeline Co., L.P., one of our subsidiaries, has agreed to indemnify HEP’s general partner to the extent it makes any payment in satisfaction of $35.0 million of the principal amount of the HEP Senior Notes.
In discussions beginning in the last half of 2005, the EPA and the State of Utah have asserted that we have Federal Clean Air Act 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 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. With respect to the 2001 Consent Agreement we entered into for our Navajo and Montana refineries, following the sale of the Montana Refinery in March 2006 our remaining commitment relates to the Navajo Refinery and, with the investments made to date, our outstanding required investments are no longer significant.
CRITICAL ACCOUNTING POLICIES
Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities as of the date of the financial statements. Actual results may differ from these estimates under different assumptions or conditions.

-35-


Table of Contents

Our significant accounting policies are described in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies” in our Annual Report on Form 10-K for the year ended December 31, 2006. Certain critical accounting policies that materially affect the amounts recorded in our consolidated financial statements are the use of the LIFO method of valuing certain inventories, the amortization of deferred costs for regular major maintenance and repairs at our refineries, assessing the possible impairment of certain long-lived assets, and assessing contingent liabilities for probable losses. There have been no changes to these policies in 2007.
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 are subject to the final year-end LIFO inventory valuation.
New Accounting Pronouncements
EITF No.06-11 “Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards”

In June 2007, the FASB ratified Emerging Issues Task Force (“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. While we are currently evaluating the impact of EITF No. 06-11, we do not expect the adoption of this standard to have a material impact on our financial condition, results of operations and cash flows.
SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115”

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 do not expect the adoption of this statement to have a material impact on our financial condition, results of operations and cash flows.
Interpretation No. 48 “Accounting for Uncertainty in Income Taxes”

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 transition. This interpretation is effective for fiscal years beginning after December 15, 2006. We adopted this standard effective January 1, 2007. As a result of the implementation of this standard, we recognized no material adjustment in the liability for unrecognized income tax benefits.
We are subject to U.S. federal income tax and to the income tax of multiple state jurisdictions. We have substantially concluded all U.S. federal, state and local income tax matters for fiscal years through July 31, 2002. In 2006, the Internal Revenue Service commenced examinations of our U.S. federal income tax returns for the tax years ended July 31, 2003 and December 31, 2003. To date, we do not anticipate that the resolution of this audit will result in a material change to our financial condition, results of operations or cash flows.

-36-


Table of Contents

Our policy is to recognize potential interest and penalties related to income tax matters in income tax expense. We believe we have appropriate support for the income tax positions taken and to be taken on our income tax returns and that our accruals for tax liabilities are adequate for all open years based on an assessment of many factors, including past experience and interpretations of tax law applied to the facts of each matter.
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 do not anticipate that the adoption of this interpretation will have a material effect on our financial condition, results of operations and cash flows.
RISK MANAGEMENT
We use certain strategies to reduce some commodity price and operational risks. We do not attempt to eliminate all market risk exposures when we believe that the exposure relating to such risk would not be significant to our future earnings, financial position, capital resources or liquidity or that the cost of eliminating the exposure would outweigh the benefit. Our profitability depends largely on the spread between market prices for refined products and market prices for crude oil. A substantial or prolonged reduction in this spread could have a significant negative effect on our earnings, financial condition and cash flows.
We periodically utilize petroleum commodity futures contracts to reduce our exposure to price fluctuations associated with crude oil and refined products. Such contracts historically have been used principally to help manage the price risk inherent in purchasing crude oil in advance of the delivery date and as a hedge for fixed-price sales contracts of refined products. We have also utilized commodity price swaps and collar options to help manage the exposure to price volatility relating to forecasted purchases of natural gas. We have not had any open positions since 2005.
We regularly utilize contracts that provide for the purchase of crude oil and other feedstocks and for the sale of refined products. Certain of these contracts may meet the definition of a derivative instrument in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. We believe these contracts qualify for the normal purchases and normal sales exception under SFAS No. 133, because deliveries under the contracts will be in quantities expected to be used or sold over a reasonable period of time in the normal course of business. Accordingly, these contracts are designated as normal purchases and normal sales contracts and are not required to be recorded as derivative instruments under SFAS No. 133.
At June 30, 2007, we had no outstanding debt. As the interest rates on our bank borrowings are reset frequently based on either the bank’s daily effective prime rate or the LIBOR rate, interest rate market risk on any bank borrowings would be very low. At times, we have used borrowings under our credit facility to finance our working capital needs. There were no borrowings under the credit facilities at June 30, 2007. We invest a substantial portion of available cash in investment grade, highly liquid investments with maturities of three months or less and hence the interest rate market risk implicit in these cash investments is low. We also invest the remainder of available cash in portfolios of highly rated marketable debt securities, primarily issued by government entities, that have an average remaining duration (including any cash equivalents invested) of not greater than one year and hence the interest rate market risk implicit in these investments is also low. A hypothetical 10% change in the market interest rate over the next year would not materially impact our earnings, cash flow or financial condition since any borrowings under the credit facilities and our investments are at market rates and interest on borrowings and cash investments has historically not been significant as compared to our total operations.
Our operations are subject to normal hazards of operations, including fire, explosion and weather-related perils. We maintain various insurance coverages, including business interruption insurance, subject to certain deductibles. We are not fully insured against certain risks because such risks are not fully insurable, coverage is unavailable, or premium costs, in our judgment, do not justify such expenditures.

-37-


Table of Contents

Item 3. Quantitative and Qualitative Disclosures About Market Risk
See “Risk Management” under “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles
Reconciliations of earnings before interest, taxes, depreciation and amortization (“EBITDA”) to amounts reported under generally accepted accounting principles in financial statements.
Earnings before interest, taxes, depreciation and amortization, which we refer to as EBITDA, is calculated as net income plus (i) interest expense net of interest income, (ii) income tax provision, and (iii) depreciation, depletion and amortization. EBITDA is not a calculation provided for under accounting principles generally accepted in the United States; however, the amounts included in the EBITDA calculation are derived from amounts included in our consolidated financial statements. EBITDA should not be considered as an alternative to net income or operating income as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity. EBITDA is not necessarily comparable to similarly titled measures of other companies. EBITDA is presented here because it is a widely used financial indicator used by investors and analysts to measure performance. EBITDA is also used by our management for internal analysis and as a basis for financial covenants. We are reporting EBITDA from continuing operations.
Set forth below is our calculation of EBITDA from continuing operations.
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2007     2006     2007     2006  
            (In thousands)          
Income from continuing operations
  $ 158,627     $ 87,729     $ 226,169     $ 118,889  
Add provision for income tax
    86,136       50,148       120,822       65,635  
Add interest expense
    291       272       543       547  
Subtract interest income
    (3,550 )     (2,408 )     (6,110 )     (4,143 )
Add depreciation, depletion and amortization
    10,641       10,683       22,092       18,707  
 
                       
EBITDA from continuing operations
  $ 252,145     $ 146,424     $ 363,516     $ 199,635  
 
                       
Reconciliations of refinery operating information (non-GAAP performance measures) to amounts reported under generally accepted accounting principles in financial statements.
Refinery gross margin and net operating margin are non-GAAP performance measures that are used by our management and others to compare our refining performance to that of other companies in our industry. We believe these margin measures are helpful to investors in evaluating our refining performance on a relative and absolute basis.
We calculate refinery gross margin and net operating margin using net sales, cost of products and operating expenses, in each case averaged per produced barrel sold. These two margins do not include the effect of depreciation, depletion and amortization. Each of these component performance measures can be reconciled directly to our Consolidated Statements of Income.
Other companies in our industry may not calculate these performance measures in the same manner.

-38-


Table of Contents

Refinery Gross Margin
Refinery gross margin per barrel is the difference between average net sales price and average cost of products per barrel of produced refined products. Refinery gross margin for each of our refineries and for both of our refineries on a consolidated basis is calculated as shown below.
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2007     2006     2007     2006  
Average per produced barrel:
                               
 
                               
Navajo Refinery
                               
Net sales
  $ 93.17     $ 90.76     $ 84.69     $ 82.49  
Less cost of products
    65.63       67.34       62.45       64.90  
 
                       
Refinery gross margin
  $ 27.54     $ 23.42     $ 22.24     $ 17.59  
 
                       
 
                               
Woods Cross Refinery
                               
Net sales
  $ 96.51     $ 89.63     $ 83.67     $ 80.52  
Less cost of products
    65.29       69.80       60.95       65.42  
 
                       
Refinery gross margin
  $ 31.22     $ 19.83     $ 22.72     $ 15.10  
 
                       
 
                               
Consolidated
                               
Net sales
  $ 93.92     $ 90.43     $ 84.45     $ 81.98  
Less cost of products
    65.56       68.06       62.10       65.03  
 
                       
Refinery gross margin
  $ 28.36     $ 22.37     $ 22.35     $ 16.95  
 
                       
Net Operating Margin
Net operating margin per barrel is the difference between refinery gross margin and refinery operating expenses per barrel of produced refined products. Net operating margin for each of our refineries and for all of our refineries on a consolidated basis is calculated as shown below.
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2007     2006     2007     2006  
Average per produced barrel:
                               
 
                               
Navajo Refinery
                               
Refinery gross margin
  $ 27.54     $ 23.42     $ 22.24     $ 17.59  
Less refinery operating expenses
    4.26       5.37       4.22       5.07  
 
                       
Net operating margin
  $ 23.28     $ 18.05     $ 18.02     $ 12.52  
 
                       
 
                               
Woods Cross Refinery
                               
Refinery gross margin
  $ 31.22     $ 19.83     $ 22.72     $ 15.10  
Less refinery operating expenses
    4.22       4.36       4.50       4.99  
 
                       
Net operating margin
  $ 27.00     $ 15.47     $ 18.22     $ 10.11  
 
                       
 
                               
Consolidated
                               
Refinery gross margin
  $ 28.36     $ 22.37     $ 22.35     $ 16.95  
Less refinery operating expenses
    4.25       5.08       4.29       5.05  
 
                       
Net operating margin
  $ 24.11     $ 17.29     $ 18.06     $ 11.90  
 
                       

-39-


Table of Contents

Below are reconciliations to our Consolidated Statements of Income for (i) net sales, cost of products and operating expenses, in each case averaged per produced barrel sold, and (ii) net operating margin and refinery gross margin. Due to rounding of reported numbers, some amounts may not calculate exactly.
Reconciliations of refined product sales from produced products sold to total sales and other revenue
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2007     2006     2007     2006  
Navajo Refinery
                               
Average sales price per produced barrel sold
  $ 93.17     $ 90.76     $ 84.69     $ 82.49  
Times sales of produced refined products sold (BPD)
    90,660       66,320       88,040       73,000  
Times number of days in period
    91       91       181       181  
 
                       
Refined product sales from produced products sold
  $ 768,658     $ 547,747     $ 1,349,555     $ 1,089,940  
 
                       
 
                               
Woods Cross Refinery
                               
Average sales price per produced barrel sold
  $ 96.51     $ 89.63     $ 83.67     $ 80.52  
Times sales of produced refined products sold (BPD)
    26,130       27,500       27,120       25,410  
Times number of days in period
    91       91       181       181  
 
                       
Refined product sales from produced products sold
  $ 229,484     $ 224,299     $ 410,713     $ 370,328  
 
                       
Sum of refined products sales from produced products sold from our two refineries (4)
  $ 998,142     $ 772,046     $ 1,760,268     $ 1,460,268  
Add refined product sales from purchased products and rounding (1)
    91,747       168,064       171,093       252,343  
 
                       
Total refined products sales
    1,089,889       940,110       1,931,361       1,712,611  
Add direct sales of excess crude oil(2)
    91,843       131,275       153,523       131,275  
Add other refining segment revenue(3)
    35,045       49,453       57,475       68,300  
 
                       
Total refining segment revenue
    1,216,777       1,120,838       2,142,359       1,912,186  
Add corporate and other revenues
    114       143       505       524  
Add (subtract) consolidations and eliminations
    106       (141 )           (276 )
 
                       
Sales and other revenues
  $ 1,216,997     $ 1,120,840     $ 2,142,864     $ 1,912,434  
 
                       
 
(1)   We purchase finished products when opportunities arise that provide a profit on the sale of such products, or to meet delivery commitments.
 
(2)   We purchase crude oil and enter into buy/sell exchanges in excess of the needs to supply our refineries. Certain direct sales of this excess crude oil are made to purchasers or users of crude oil. Under new accounting guidance, these 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 as cost of products sold. Prior to April 1, 2006, sales and cost of sales attributable to such excess crude oil direct sales were netted and presented in cost of products sold.
 
(3)   Other refining segment revenue includes the revenues associated with NK Asphalt Partners and revenue derived from feedstock and sulfur credit sales.
 
(4)   The above calculations of refined product sales from produced products sold can also be computed on a consolidated basis. These amounts may not calculate exactly due to rounding of reported numbers.
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2007     2006     2007     2006  
Average sales price per produced barrel sold
  $ 93.92     $ 90.43     $ 84.45     $ 81.98  
Times sales of produced refined products sold (BPD)
    116,790       93,820       115,160       98,410  
Times number of days in period
    91       91       181       181  
 
                       
Refined product sales from produced products sold
  $ 998,142     $ 772,046     $ 1,760,268     $ 1,460,268  
 
                       

-40-


Table of Contents

Reconciliation of average cost of products per produced barrel sold to total costs of products sold
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2007     2006     2007     2006  
Navajo Refinery
                               
Average cost of products per produced barrel sold
  $ 65.63     $ 67.34     $ 62.45     $ 64.90  
Times sales of produced refined products sold (BPD)
    90,660       66,320       88,040       73,000  
Times number of days in period
    91       91       181       181  
 
                       
Cost of products for produced products sold
  $ 541,451     $ 406,405     $ 995,156     $ 857,524  
 
                       
 
                               
Woods Cross Refinery
                               
Average cost of products per produced barrel sold
  $ 65.29     $ 69.80     $ 60.95     $ 65.42  
Times sales of produced refined products sold (BPD)
    26,130       27,500       27,120       25,410  
Times number of days in period
    91       91       181       181  
 
                       
Cost of products for produced products sold
  $ 155,249     $ 174,675     $ 299,186     $ 300,880  
 
                       
Sum of cost of products for produced products sold from our two refineries (4)
  $ 696,700     $ 581,080     $ 1,294,342     $ 1,158,404  
Add refined product costs from purchased products sold and rounding (1)
    86,404       172,348       168,556       257,966  
 
                       
Total refined cost of products sold
    783,104       753,428       1,462,898       1,416,370  
Add crude oil cost of direct sales of excess crude oil(2)
    92,054       131,061       153,906       131,061  
Add other refining segment cost of products sold(3)
    21,973       23,661       32,147       36,339  
 
                       
Total refining segment cost of products sold
    897,131       908,150       1,648,951       1,583,770  
Add (subtract) consolidations and eliminations
    106       (141 )           (276 )
 
                       
Costs of products sold (exclusive of depreciation, depletion and amortization)
  $ 897,237     $ 908,009     $ 1,648,951     $ 1,583,494  
 
                       
 
(1)   We purchase finished products when opportunities arise that provide a profit on the sale of such products, or to meet delivery commitments.
 
(2)   We purchase crude oil and enter into buy/sell exchanges in excess of the needs to supply our refineries. Certain direct sales of this excess crude oil are made to purchasers or users of crude oil. Under new accounting guidance, these 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 as cost of products sold. Prior to April 1, 2006, sales and cost of sales attributable to such excess crude oil direct sales were netted and presented in cost of products sold.
 
(3)   Other refining segment cost of products sold includes the cost of products for NK Asphalt Partners and costs attributable to feedstock and sulfur credit sales.
 
(4)   The above calculations of refined product sales from produced products sold can also be computed on a consolidated basis. These amounts may not calculate exactly due to rounding of reported numbers.
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2007     2006     2007     2006  
Average cost of products per produced barrel sold
  $ 65.56     $ 68.06     $ 62.10     $ 65.03  
Times sales of produced refined products sold (BPD)
    116,790       93,820       115,160       98,410  
Times number of days in period
    91       91       181       181  
 
                       
Cost of products for produced products sold
  $ 696,700     $ 581,080     $ 1,294,342     $ 1,158,404  
 
                       

-41-


Table of Contents

Reconciliation of average refinery operating expenses per produced barrel sold to total operating expenses
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2007     2006     2007     2006  
Navajo Refinery
                               
Average refinery operating expenses per produced barrel sold
  $ 4.26     $ 5.37     $ 4.22     $ 5.07  
Times sales of produced refined products sold (BPD)
    90,660       66,320       88,040       73,000  
Times number of days in period
    91       91       181       181  
 
                       
Refinery operating expenses for produced products sold
  $ 35,145     $ 32,409     $ 67,247     $ 66,990  
 
                       
 
                               
Woods Cross Refinery
                               
Average refinery operating expenses per produced barrel sold
  $ 4.22     $ 4.36     $ 4.50     $ 4.99  
Times sales of produced refined products sold (BPD)
    26,130       27,500       27,120       25,410  
Times number of days in period
    91       91       181       181  
 
                       
Refinery operating expenses for produced products sold
  $ 10,034     $ 10,911     $ 22,089     $ 22,950  
 
                       
Sum of refinery operating expenses per produced products sold from our two refineries (2)
  $ 45,179     $ 43,320     $ 89,336     $ 89,940  
Add other refining segment operating expenses and rounding (1)
    5,934       5,790       11,895       11,603  
 
                       
Total refining segment operating expenses
    51,113       49,110       101,231       101,543  
Add corporate and other costs
    3       (18 )     14       16  
 
                       
Operating expenses (exclusive of depreciation, depletion and amortization)
  $ 51,116     $ 49,092     $ 101,245     $ 101,559  
 
                       
 
(1)   Other refining segment operating expenses include the marketing costs associated with our refining segment and the operating expenses of NK Asphalt Partners.
 
(2)   The above calculations of refinery operating expenses from produced products sold can also be computed on a consolidated basis. These amounts may not calculate exactly due to rounding of reported numbers.
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2007     2006     2007     2006  
Average refinery operating expenses per produced barrel sold
  $ 4.25     $ 5.08     $ 4.29     $ 5.05  
Times sales of produced refined products sold (BPD)
    116,790       93,820       115,160       98,410  
Times number of days in period
    91       91       181       181  
 
                       
Refinery operating expenses for produced products sold
  $ 45,179     $ 43,320     $ 89,336     $ 89,940  
 
                       
Reconciliation of net operating margin per barrel to refinery gross margin per barrel to total sales and other revenues
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2007     2006     2007     2006  
Navajo Refinery
                               
Net operating margin per barrel
  $ 23.28     $ 18.05     $ 18.02     $ 12.52  
Add average refinery operating expenses per produced barrel
    4.26       5.37       4.22       5.07  
 
                       
Refinery gross margin per barrel
    27.54       23.42       22.24       17.59  
Add average cost of products per produced barrel sold
    65.63       67.34       62.45       64.90  
 
                       
Average sales price per produced barrel sold
  $ 93.17     $ 90.76     $ 84.69     $ 82.49  
Times sales of produced refined products sold (BPD)
    90,660       66,320       88,040       73,000  
Times number of days in period
    91       91       181       181  
 
                       
Refined products sales from produced products sold
  $ 768,658     $ 547,747     $ 1,349,555     $ 1,089,940  
 
                       

-42-


Table of Contents

                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2007     2006     2007     2006  
Woods Cross Refinery
                               
Net operating margin per barrel
  $ 27.00     $ 15.47     $ 18.22     $ 10.11  
Add average refinery operating expenses per produced barrel
    4.22       4.36       4.50       4.99  
 
                       
Refinery gross margin per barrel
    31.22       19.83       22.72       15.10  
Add average cost of products per produced barrel sold
    65.29       69.80       60.95       65.42  
 
                       
Average sales price per produced barrel sold
  $ 96.51     $ 89.63     $ 83.67     $ 80.52  
Times sales of produced refined products sold (BPD)
    26,130       27,500       27,120       25,410  
Times number of days in period
    91       91       181       181  
 
                       
Refined products sales from produced products sold
  $ 229,484     $ 224,299     $ 410,713     $ 370,328  
 
                       
 
                               
Sum of refined products sales from produced products sold from our two refineries (4)
  $ 998,142     $ 772,046     $ 1,760,268     $ 1,460,268  
Add refined product sales from purchased products and rounding (1)
    91,747       168,064       171,093       252,343  
 
                       
Total refined products sales
    1,089,889       940,110       1,931,361       1,712,611  
Add direct sales of excess crude oil (2)
    91,843       131,275       153,523       131,275  
Add other refining segment revenue (3)
    35,045       49,453       57,475       68,300  
 
                       
Total refining segment revenue
    1,216,777       1,120,838       2,142,359       1,912,186  
Add corporate and other revenues
    114       143       505       524  
Add (subtract) consolidations and eliminations
    106       (141 )           (276 )
 
                       
Sales and other revenues
  $ 1,216,997     $ 1,120,840     $ 2,142,864     $ 1,912,434  
 
                       
 
(1)   We purchase finished products when opportunities arise that provide a profit on the sale of such products or to meet delivery commitments.
 
(2)   We purchase crude oil and enter into buy/sell exchanges in excess of the needs to supply our refineries. Certain direct sales of this excess crude oil are made to purchasers or users of crude oil. Under new accounting guidance, these 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 as cost of products sold. Prior to April 1, 2006, sales and cost of sales attributable to such excess crude oil direct sales were netted and presented in cost of products sold.
 
(3)   Other refining segment revenue includes the revenues associated with NK Asphalt Partners and revenue derived from feedstock and sulfur credit sales.
 
(4)   The above calculations of refined product sales from produced products sold can also be computed on a consolidated basis. These amounts may not calculate exactly due to rounding of reported numbers.
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2007     2006     2007     2006  
Net operating margin per barrel
  $ 24.11     $ 17.29     $ 18.06     $ 11.90  
Add average refinery operating expenses per produced barrel
    4.25       5.08       4.29       5.05  
 
                       
Refinery gross margin per barrel
    28.36       22.37       22.35       16.95  
Add average cost of products per produced barrel sold
    65.56       68.06       62.10       65.03  
 
                       
Average sales price per produced barrel sold
  $ 93.92     $ 90.43     $ 84.45     $ 81.98  
Times sales of produced refined products sold (BPD)
    116,790       93,820       115,160       98,410  
Times number of days in period
    91       91       181       181  
 
                       
Refined product sales from produced products sold
  $ 998,142     $ 772,046     $ 1,760,268     $ 1,460,268  
 
                       

-43-


Table of Contents

Item 4. Controls and Procedures
Evaluation of disclosure controls and procedures. Our principal executive officer and principal financial officer have evaluated, as required by Rule 13a-15(b) under the Securities Exchange Act of 1934 (the “Exchange Act”), our disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of the end of the period covered by this quarterly report on Form 10-Q. Based on that evaluation, the principal executive officer and principal financial officer concluded that the design and operation of our disclosure controls and procedures are effective in ensuring that information we are required to disclose in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.
Changes in internal control over financial reporting. During the quarter ended June 30, 2007, we implemented a new accounting software system, which required modifications to our existing system of internal control over financial reporting due to technical changes in the accounting software system. We have reviewed our modified internal controls and believe that they are appropriate and are functioning effectively.

-44-


Table of Contents

PART II. OTHER INFORMATION
Item 1. Legal Proceedings
On May 29, 2007, the United States Court of Appeals for the District of Columbia Circuit 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 an 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 years 1992 through 2006 in addition to the $15.3 million we received in 2003 from SFPP as reparations for the period from 1993 through July 2000. Because proceedings in the FERC following the court of appeals decision have not been completed and because the decision of the court of appeals could be the subject of petitions by one or more parties seeking United States Supreme Court review of issues addressed, 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 have pending in the United States Court of Federal Claims a lawsuit against the Department of Defense relating to claims totaling approximately $299.0 million with respect to jet fuel sales by two subsidiaries in the years 1982 through 1999. Our claims are similar to claims in a number of other cases that have also been pending in the United States Court of Federal Claims brought by other refining companies concerning military fuel sales. In response to our request, the judge in our case issued in February 2006 an order continuing the stay of our case originally ordered in March 2004. While the stay of our case is in effect we expect that further judicial proceedings in one or more other cases brought by other refining companies may clarify the legal standards that will apply to our case. In August and September 2006, three judges of the United States Court of Federal Claims issued rulings adverse to three other refining companies on issues that are also involved in our case. The refining companies that received these adverse rulings filed appeals of the adverse rulings to the United States Court of Appeals for the Federal Circuit in the fall of 2006, and in June 2007 the court of appeals heard oral arguments on the issues presented. At the date of this report, it is not possible to predict the outcome of further proceedings with respect to our case.
In discussions beginning in the last half of 2005, the EPA and the State of Utah have asserted that we have Federal Clean Air Act 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 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 Refinery and previously-owned Montana Refinery. 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.
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 October 2006 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 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,

-45-


Table of Contents

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.
On December 6, 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 on March 31, 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 seeks 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. While we do not agree with a number of the violations asserted in the Complaint, we and the current owner of the Great Falls refinery have been in negotiations with the MDEQ both before and after the filing of the Complaint to attempt to settle the issues raised on a compromise basis. At the date of this report, we are not able to predict the outcome of 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.

-46-


Table of Contents

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
     (c) Common Stock Repurchases Made in the Quarter
Under our $300 million common stock repurchase program (announced in November 2005 and increased from $200 million to $300 million in October 2006), 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. The following table includes repurchases made under this program during the second quarter of 2007.
                                 
                            Maximum Dollar
                            Value of Shares
                    Total Number of   Yet to be
                    Shares Purchased as   Purchased as Part
    Total Number of   Average price   Part of $300 Million   of the $300 Million
          Period   Shares Purchased   Paid Per Share   Program   Program(1)
April 2007
    96,592     $ 62.16       96,592     $ 57,813,809  
May 2007
    65,757     $ 68.48       65,757     $ 53,310,586  
June 2007
    46,730     $ 70.67       46,730     $ 50,008,332  
 
                               
Total for April to June 2007
    209,079     $ 66.05       209,079          
 
                               
 
(1)   Prior to $100 million increase in common stock repurchase program announced August 9, 2007.
Additionally, during the three months ended June 30, 2007, we repurchased at current market price from certain officers and other key employees 40,716 shares of our common stock at a cost of approximately $2.5 million. These repurchases were made 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.
Item 4. Submission of Matters to a Vote of Security Holders
At the annual meeting of stockholders on May 24, 2007, all nine of the nominees for directors as listed in the proxy statement were elected.
Election of Directors
                 
    Total Votes   Total Votes
    “For”   “Withheld”
Buford P. Berry
    46,794,144       3,114,028  
Matthew P. Clifton
    47,144,516       2,763,656  
W. John Glancy
    45,309,616       4,598,556  
William J. Gray
    44,997,437       4,910,735  
Marcus R. Hickerson
    16,391,391       33,516,781  
Thomas K. Matthews, II
    46,412,712       3,495,460  
Robert G. McKenzie
    38,417,718       11,490,454  
Jack P. Reid
    45,324,046       4,584,126  
Paul T. Stoffel
    46,708,292       3,199,880  

-47-


Table of Contents

Our stockholders approved an amendment to our Restated Certificate of Incorporation to increase the number of authorized shares of our common stock from 100,000,000 shares to 160,000,000.
             
Total Votes   Total Votes       Broker
“For”   “Withheld”   Abstentions   Non-Votes
43,758,490
  6,123,576   26,106  
Our stockholders re-approved the performance standards and eligibility provisions of our Long-Term Incentive Compensation Plan and approved an amendment to provide for the use of “net profit margin” as a business criterion for annual incentive awards.
             
Total Votes   Total Votes       Broker
“For”   “Withheld”   Abstentions   Non-Votes
48,225,668   1,638,285   44,219  

-48-


Table of Contents

Item 6. Exhibits
     (a) Exhibits
     
31.1+
  Certification of Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002.
 
   
31.2+
  Certification of Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002.
 
   
32.1+
  Certification of Chief Executive Officer under Section 906 of the Sarbanes-Oxley Act of 2002.
 
   
32.2+
  Certification of Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act of 2002.
 
+   Filed herewith.

-49-


Table of Contents

SIGNATURES
Pursuant to the requirements of the Securities and Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
             
    HOLLY CORPORATION    
         
    (Registrant)    
 
           
Date: August 9, 2007
      /s/ P. Dean Ridenour
 
P. Dean Ridenour
Vice President and Chief Accounting Officer
(Principal Accounting Officer)
   
 
           
 
      /s/ Stephen J. McDonnell
 
Stephen J. McDonnell
Vice President and Chief Financial Officer
(Principal Financial Officer)
   

-50-