UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
| [X] |
Quarterly Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2003 OR |
| [ ] |
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 1-7627 |
FRONTIER OIL CORPORATION
(Exact name of registrant as specified in its charter)
|
Wyoming (State or other jurisdiction of incorporation or organization) 10000 Memorial Drive, Suite 600 Houston, Texas (Address of principal executive offices) |
74-1895085 (I.R.S. Employer Identification No.) 77024-3411 (Zip Code) |
Registrant’s telephone number, including area code: (713) 688-9600
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 [x] No . . . |
| Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act) |
|
Yes [x] No . . . Registrant’s number of common shares outstanding as of August 4, 2003: 26,140,517 |
FRONTIER OIL CORPORATION
QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTER ENDED JUNE 30, 2003
INDEX
Part I - Financial Information
| Item 1. |
Financial Statements |
| Item 2. |
Management’s Discussion and Analysis of Financial
Condition and Results of Operations |
| Item 3. |
Quantitative and Qualitative Disclosures About Market Risk |
| Item 4. | Controls and Procedures |
Part II - Other Information
This Form 10-Q contains “forward-looking statements,” as defined by the Securities and Exchange Commission. Such statements are those concerning contemplated transactions and strategic plans, expectations and objectives for future operations. These include, without limitation:
| • |
statements, other than statements of historical facts, that address activities,
events or developments that we expect, believe or anticipate will or may occur
in the future;
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| • |
statements relating to future financial performance, future equity issuances and other matters; and
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| • |
any other statements preceded by, followed by or that include the words
“anticipates,” “believes,” “expects,”
“plans,” “intends,” “estimates,”
“projects,” “could,” “should,” “may,” or
similar expressions.
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Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Form 10-Q are reasonable, we can give no assurance that such plans, intentions or expectations will be achieved. These statements are based on assumptions made by us based on our experience and perception of historical trends, current conditions, expected future developments and other factors that we believe are appropriate in the circumstances. Such statements are subject to a number of risks and uncertainties, many of which are beyond our control. You are cautioned that any such statements are not guarantees of future performance and that actual results or developments may differ materially from those projected in the forward-looking statements.
We undertake no obligation to update or revise publicly any forward-looking statements, whether as a result of new information, future events or otherwise.
Definitions of Terms
bbl(s) = barrel(s)
bpd = barrel(s) per day
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
FRONTIER OIL CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited, in thousands except per share amounts)
Six Months Ended Three Months Ended
June 30 June 30
2003 2002 2003 2002
---------- ---------- ----------- ----------
Revenues:
Refined products $1,031,149 $ 794,342 $ 533,428 $ 459,357
Other 1,648 1,170 (15) (195)
---------- ---------- ----------- ----------
1,032,797 795,512 533,413 459,162
---------- ---------- ----------- ----------
Costs and Expenses:
Raw material, freight and other costs 898,678 677,144 463,374 400,905
Refining operating expenses, excluding
depreciation 100,564 88,688 49,253 45,649
Selling and general expenses, excluding
depreciation 9,794 8,004 5,116 4,201
Depreciation 14,031 13,374 7,071 6,776
---------- ---------- ----------- ----------
1,023,067 787,210 524,814 457,531
---------- ---------- ----------- ----------
Operating Income 9,730 8,302 8,599 1,631
---------- ---------- ----------- ----------
Interest Expense and other financing costs 17,946 13,730 10,520 6,953
Interest income (1,014) (916) (641) (451)
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16,932 12,814 9,879 6,502
---------- ---------- ----------- ----------
Loss Before Income Taxes (7,202) (4,512) (1,280) (4,871)
Benefit for Income Taxes (2,510) (1,766) (288) (1,864)
---------- ---------- ----------- ----------
Net Loss $ (4,692) $ (2,746) $ (992) $ (3,007)
========== ========== =========== ==========
Basic Loss Per Share
of Common Stock: $ (.18) $ (.11) $ (.04) $ (.12)
========== ========== ===========- ==========
Diluted Loss Per Share
of Common Stock: $ (.18) $ (.11) $ (.04) $ (.12)
========== ========== ===========- ==========
The accompanying notes are an integral part of these consolidated financial statements.
FRONTIER OIL CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Unaudited, in thousands)
Six Months Ended Three Months Ended
June 30 June 30
2003 2002 2003 2002
---------- ----------- ----------- ----------
Net Loss $ (4,692) $ (2,746) $ (992) $ (3,007)
Other Comprehensive Income, Net of Income Tax:
Change in fair value of cash flow hedges - 263 - 296
Derivative value reclassed to income - (39) - (39)
---------- ----------- ----------- ----------
Comprehensive Loss $ (4,692) $ (2,522) $ (992) $ (2,750)
========== ========== =========== ==========
The accompanying notes are an integral part of these consolidated financial statements.
FRONTIER OIL CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited, in thousands except shares)
June 30, 2003 and December 31, 2002 2003 2002
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ASSETS
Current Assets:
Cash, including cash equivalents of
$72,441 in 2003 and $109,825 in 2002 $ 77,822 $ 112,364
Restricted cash 3,617 -
Trade receivables, net of allowance of $500 in both years 78,434 81,154
Note receivable, net of allowance of $800 1,449 1,449
Other receivables 2,815 987
Inventory of crude oil, products and other 136,550 105,160
Deferred tax current assets 4,599 5,346
Other current assets 1,540 2,510
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Total current assets 306,826 308,970
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Restricted Cash 228,067 -
Property, Plant and Equipment, at cost:
Refineries and pipeline 465,940 447,948
Furniture, fixtures and other equipment 5,206 5,119
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471,146 453,067
Less - Accumulated depreciation 158,158 144,127
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315,008 308,940
Asset Held for Sale - 472
Deferred Financing Costs, Net 11,063 5,460
Other Assets 7,321 5,035
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TOTAL ASSETS $ 866,265 $ 628,877
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LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Accounts payable $ 197,165 $ 174,917
Revolving credit facility 8,000 -
Accrued turnaround cost 5,266 12,849
Accrued liabilities and other 9,289 9,095
Accrued interest 7,476 3,856
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Total current liabilities 227,196 200,717
Long-Term Debt 426,231 207,966
Long-Term Accrued Turnaround Cost 16,499 14,013
Post-Retirement Employee Liabilities 19,198 18,784
Deferred Credits and Other 3,892 3,963
Deferred Income Taxes 11,808 15,176
Commitments and Contingencies
Shareholders' Equity:
Preferred stock, $100 par value, 500,000 shares authorized,
no shares issued - -
Common stock, no par, 50,000,000 shares authorized,
30,316,549 and 30,290,324 shares issued in 2003 and 2002 57,472 57,469
Paid-in capital 102,838 102,557
Retained earnings 42,316 49,621
Accumulated other comprehensive income (loss) (598) (598)
Treasury stock, 4,176,035 shares and 4,151,210 shares
in 2003 and 2002 (38,387) (37,959)
Deferred employee compensation (2,200) (2,832)
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Total Shareholders' Equity 161,441 168,258
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TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 866,265 $ 628,877
=========== ==========
The accompanying notes are an integral part of these consolidated financial statements.
FRONTIER OIL CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited, in thousands)
For the six months ended June 30, 2003 2002
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OPERATING ACTIVITIES
Net loss $ (4,692) $ (2,746)
Depreciation 14,031 13,374
Deferred income taxes (2,529) (1,849)
Amortization of deferred finance costs and senior note discount 1,675 1,073
Deferred employee compensation amortization 632 400
Net loss on sales of assets 189 -
Deferred credits and other (303) (312)
Change in working capital from operations (9,027) (23,104)
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Net cash used in operating activities (24) (13,164)
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INVESTING ACTIVITIES
Additions to property, plant and equipment and other (17,813) (18,695)
Proceeds from sale of assets 304 -
Holly merger acquisition costs (2,020) -
Other investments (34) -
El Dorado refinery acquisition - contingent earn-out payment - (7,500)
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Net cash used in investing activities (19,563) (26,195)
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FINANCING ACTIVITIES
Revolving credit facility borrowings 8,000 46,800
Proceeds from issuance of 8% Senior Notes (Note 7) 218,143 -
Fund restricted cash (escrow account) (Note 7) (231,684) -
Deferred finance costs (6,585) -
Issuance of common stock 192 1,650
Purchase of treasury stock (428) (787)
Dividends (2,593) (2,578)
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Net cash (used in) provided by financing activities (14,955) 45,085
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(Decrease) Increase in cash and cash equivalents (34,542) 5,726
Cash and cash equivalents, beginning of period 112,364 103,995
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Cash and cash equivalents, end of period $ 77,822 $ 109,721
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The accompanying notes are an integral part of these consolidated financial statements.
FRONTIER OIL
CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2003
(Unaudited)
The consolidated financial statements include the accounts of Frontier Oil Corporation, a Wyoming corporation, and its wholly owned subsidiaries, including Frontier Holdings Inc., collectively referred to as Frontier or the Company. The Company is an energy company engaged in crude oil refining and wholesale marketing of refined petroleum products (the “refining operations”). The Company operates refineries (“the Refineries”) in Cheyenne, Wyoming and El Dorado, Kansas with a combined crude oil capacity of over 156,000 barrels per day. All of the operations of the Company are in the United States with its marketing efforts focused in the Rocky Mountain and Plains States regions of the United States. The Company purchases the crude oil to be refined and markets the refined petroleum products produced, including various grades of gasoline, diesel fuel, jet fuel, asphalt, chemicals and petroleum coke. The operations of refining and marketing of petroleum products are considered part of one reporting segment.
These financial statements have been prepared by the Company without audit, pursuant to the rules and regulations of the Securities and Exchange Commission and include all adjustments (comprised of only normal recurring adjustments) which are, in the opinion of management, necessary for a fair presentation. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to make the information presented not misleading. It is suggested that the financial statements included herein be read in conjunction with the financial statements and the notes thereto included in the Company’s annual report on Form 10-K for the year ended December 31, 2002.
Basic earnings per share (“EPS”) has been computed based on the weighted average number of common shares outstanding. Basic and diluted shares were the same for the six months and three months ended June 30, 2003 and 2002 because losses were incurred. No adjustments to income are used in the calculation of earnings per share. The basic and diluted average shares outstanding are as follows:
Six Months Ended Three Months Ended
June 30 June 30,
2003 2002 2003 2002
------------ ----------- ------------ -----------
Basic 25,896,557 25,720,686 25,928,910 25,813,886
Diluted 25,896,557 25,720,686 25,928,910 25,813,886
The number of shares of the Company’s restricted stock that could potentially dilute basic EPS in the future but were not included in the computation of diluted EPS for the six months ended June 30, 2003 and 2002 were 30,326 and 83,384 shares, respectively, because to do so would have been antidilutive for the periods presented. The number of shares of the Company’s restricted stock that could potentially dilute basic EPS in the future but were not included in the computation of diluted EPS for the three months ended June 30, 2003 and 2002 were 37,299 and 68,759 shares, respectively, because to do so would have been antidilutive for the periods presented.
In June 2001, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standard (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations”. This statement provides accounting and disclosure requirements for retirement obligations associated with long-lived assets and became effective January 1, 2003. SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred with the associated asset retirement costs being capitalized as a part of the carrying amount of the long-lived asset. SFAS No. 143 also includes disclosure requirements that provide a description of asset retirement obligations and reconciliation of changes in the components of those obligations. The Company has potential asset retirement obligation (“ARO”) liabilities related to its Refineries as a result of environmental and other legal requirements. Any ARO liability is not currently estimatable as to amount and timing, but the Company will continue to monitor and evaluate its potential AROs. In the event that the Company decides to cease the use of a particular refinery, an ARO liability would be recorded at that time. The adoption of SFAS No. 143 on January 1, 2003 did not have any impact on the Company’s current financial condition or results of operations.
In 2001, the American Institute of Certified Public Accountants (“AICPA”) issued an Exposure Draft for a Proposed Statement of Position, “Accounting for Certain Costs and Activities Related to Property, Plant and Equipment”. The proposed Statement of Position (“SOP”), as originally written, would require major maintenance activities, such as refinery turnarounds, to be expensed as costs are incurred. In the fourth quarter of 2002, the AICPA announced it would be transitioning this project to the FASB, although the AICPA may retain and address certain components of the proposed SOP. The FASB and the AICPA have not determined which components, if any, will be retained by the AICPA for potential issuance in a future SOP. In addition, the FASB has not set a timetable for addressing the issues raised by the proposed SOP. Adoption of the proposed SOP would require that any existing turnaround accruals be reversed to income immediately and the costs of future turnarounds expensed as incurred. If this proposed change were in effect at June 30, 2003, the Company would have been required to reverse the turnaround accruals and recognize pretax income totaling $21.2 million. The total accrued turnaround costs will change throughout the year as turnarounds are incurred and accruals are made for future turnarounds. If adopted in its present form, income related to this proposed change would be reported as a cumulative effect of an accounting change, net of tax, in the consolidated statements of operations.
In April 2002, the FASB issued SFAS No. 145, “Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections.” The rescission of SFAS No. 4 is the only portion of SFAS No. 145 that may have an impact on the Company in the future. Under SFAS No. 4, all gains and losses from extinguishment of debt were required to be aggregated and, if material, classified as an extraordinary item, net of related income tax effect. SFAS No. 145 eliminates SFAS No. 4. As a result, gains and losses from extinguishment of debt should be classified as extraordinary items only if they meet the criteria in Accounting Principles Board Opinion No. 30. The Company adopted SFAS No. 145 effective January 1, 2003, and it did not have any impact on the Company’s financial condition or results of operations.
In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities”. This statement amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other activities. SFAS No. 149 is to be applied prospectively for contracts entered into or modified after June 30, 2003 and is not expected to have any impact on the Company’s financial condition or results of operations.
In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity”. This statement established standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument within its scope as a liability (or asset in some circumstances). This statement was effective for financial instruments entered into or modified after May 31, 2003 and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The Company adopted SFAS No. 150 on July 1, 2003 and it did not have any impact on our financial condition or results of operations.
2. Schedule of major components of inventory
June 30, December 31,
2003 2002
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(in thousands)
Crude oil $ 42,708 $ 33,765
Unfinished products 38,254 24,806
Finished products 36,839 29,836
Process chemicals 5,386 3,308
Repairs and maintenance supplies and other 13,363 13,445
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$ 136,550 $ 105,160
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Inventories of crude oil, unfinished products and all finished products are recorded at the lower of cost on a first in, first out (“FIFO”) basis or market. Crude oil includes both domestic and foreign crude oil volumes at its cost and associated freight and other cost. Unfinished products (work in process) include any crude oil which has entered into the refining process, and other feedstocks that are not finished as far as refining operations are concerned. These include unfinished gasoline and diesel, blendstocks and other feedstocks. Finished product inventory includes saleable gasoline, diesel, jet fuel, chemicals, asphalt and other finished products. Unfinished and finished products inventory values have both components of raw material, the associated raw material freight and other costs, and direct refinery operating expense allocated when refining begins relative to their proportionate market values. Refined product exchange transactions are considered asset exchanges with deliveries offset against receipts. The net exchange balance is included in inventory. Inventories of materials and supplies and process chemicals are recorded at the lower of average cost or market.
Stock-based compensation is measured in accordance with Accounting Principles Board (“APB”) Opinion No. 25. Under this intrinsic value method, compensation cost is the excess, if any, of the quoted market value of the Company’s common stock at the grant date over the amount the employee must pay to acquire the stock.
On March 13, 2001 the Company established the Frontier Oil Corporation Restricted Stock Plan (the “Plan”) which reserved 1,000,000 shares of common stock held as treasury stock by the Company for restricted stock grants to be made under an incentive compensation program. Restricted shares, when granted, are recorded at the market value on the date of issuance as deferred employee compensation (equity account) and amortized to compensation expense over the respective vesting periods of the stock. Compensation costs of $632,000 and $400,000 related to restricted stock awards were recognized for the six months ended June 30, 2003 and 2002, respectively. Compensation costs of $377,000 and $275,000 related to restricted stock awards were recognized for the three months ended June 30, 2003 and 2002, respectively. As of June 30, 2003, there were 205,629 shares of unvested restricted stock, which represents the total of grants made in 2001 and 2002 less the vested portion of the grants and shares forfeited from employee departures prior to vesting. The remaining 123,054 shares from the 2001 grants vest in March 2004. Of the remaining 82,575 shares from the 2002 grants, approximately 27,527 shares will vest in March 2004 with the remaining vesting in March 2005. No grants were made in 2003 through June 30.
The Company has stock option plans which authorize the granting of options to employees to purchase shares of the Company’s common stock. The plans through June 30, 2003 had reserved for issuance a total of 8,001,575 shares of common stock of which 4,461,400 shares were granted and exercised, 3,398,525 shares were granted and were outstanding and 141,650 shares were available to be granted. Options under the plans are granted at fair market value on the date of grant. No entries are made in the accounts until the options are exercised, at which time the proceeds are credited to common stock and paid-in capital. Generally, the options vest ratably throughout their one- to five-year terms.
Had compensation costs been determined based on the fair value at the grant dates for awards, the Company’s net income (loss) and EPS would have been the pro forma amounts indicated in the following table for the six months and three months ended June 30, 2003 and 2002:
Six Months Ended Three Months Ended
June 30 June 30,
2003 2002 2003 2002
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(in thousands, except per share amounts)
Net loss as reported $ (4,692) $ (2,746) $ (992) $ (3,007)
Deduct: Pro forma compensation
expense, net of tax 3,609 4,002 - 4,002
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Pro forma net loss $ (8,301) $ (6,748) $ (992) $ (7,009)
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Basic Loss per Share:
As reported $ (.18) $ (.11) $ (.04) $ (.12)
Pro forma (.32) (.26) (.04) (.27)
Diluted Loss per Share:
As reported $ (.18) $ (.11) $ (.04) $ (.12)
Pro forma (.32) (.26) (.04) (.27)
The Company, at times, enters into commodity derivative contracts to manage its price exposure to its inventory positions, purchases of foreign crude oil and consumption of natural gas in the refining process or to fix margins on certain future production. The commodity derivative contracts used by the Company may take the form of futures contracts, collars or price swaps and are entered into with counterparties believed to be credit-worthy. The Company uses futures transactions to price foreign crude oil cargos at the price at the time the crude oil is processed by the El Dorado refinery instead of the price when purchased. Foreign crude oil delivery times can exceed one month from when the purchase is made. The Company accounts for its commodity derivative contracts under 1) the hedge (or deferral) method of accounting when the derivative contracts are designated as hedges for accounting purposes, or 2) mark-to-market accounting if the Company elects not to designate derivative contracts as accounting hedges or if such derivative contracts do not qualify for hedge accounting. As such, gains or losses on commodity derivative contracts accounted for as hedges are recognized in refining operating expenses when the associated transactions are consummated while gains and losses on transactions accounted for using mark–to-market accounting are reflected in other revenues at each period end.
Other revenues for the six months ended June 30, 2003 includes $999,000 realized and unrealized net gains on derivative contracts accounted for using mark-to-market accounting and $20,000 net realized gains for the ineffective portion of crude oil hedges. Other revenues for the six months ended June 30, 2002 included $1.2 million realized and unrealized net gains on the ineffective portion of fair value hedges on crude oil cargos and $499,000 realized and unrealized net losses on derivative contracts accounted for using mark-to-market accounting. Other revenues for the three months ended June 30, 2003 includes $359,000 realized and unrealized net losses on derivative contracts accounted for using mark-to-market accounting and $2,000 net realized gains for the ineffective portion of crude oil hedges. Other revenues for the three months ended June 30, 2002 includes $88,000 realized and unrealized net gains on the ineffective portion of fair value hedges on crude oil cargos and $499,000 realized and unrealized net losses on derivative contracts accounted for using mark-to-market accounting. The ineffective portion of foreign crude oil hedges arises primarily from changes in the shape of the forward futures price curve.
At June 30, 2003 the Company had the following open commodity derivative contracts which, while economic hedges, did not qualify for hedge accounting treatment and whose gains or losses are being reflected in other revenues:
| • | Derivative contracts on 239,000 barrels of crude oil to hedge gas oil inventory builds at the El Dorado refinery. These open contracts have total unrealized losses at June 30, 2003 of approximately $249,000. During the six months ended June 30, 2003 the Company realized net gains of approximately $1.2 million on closed out contracts to hedge the gas oil inventory. |
The Company had no open derivative contracts at June 30, 2003 being accounted for as hedges. During the six months ended June 30, 2003, the Company had the following derivatives that were appropriately designated and accounted for as hedges:
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Natural Gas Collars. Price swaps on natural gas for the purpose of
hedging against natural gas price increases for February and March 2003 for
approximately 100% of the El Dorado refinery’s anticipated usage and which
are accounted for as cash flow hedges. The February group of contracts to hedge
natural gas costs were for 700,000 MMBTU and expired with no gain or loss. The
March group of contracts to hedge natural gas totaled 720,000 MMBTU and the
Company realized a $1.7 million gain which reduced refining operating expenses
in March.
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| • | Crude Contracts. In January 2003, the Company had derivative contracts on 200,000 barrels of crude oil to hedge Canadian crude costs for the Cheyenne refinery which were accounted as fair value hedges. A $13,000 loss was realized on these positions of which $31,000 increased crude costs and $18,000 income was reflected in other revenues for the ineffective portion of this hedge. In May 2003, the Company closed out derivative contracts it had purchased in April 2003 on 675,000 barrels of crude oil to hedge two foreign crude cargos purchased for the El Dorado refinery. A $13,000 gain was realized on these positions of which $11,000 reduced crude costs and $2,000 was reflected in other revenues for the ineffective portion of these hedges. |
The Company’s refining and marketing operations are subject to a variety of federal, state and local health and environmental laws and regulations governing product specifications, the discharge of materials into the environment, and the generation, treatment, storage, transportation and disposal of solid and hazardous waste and materials. Numerous permits with varying terms of duration are required for the operation of the Refineries, and these permits are subject to revocation, expiration, modification and renewal. Timely application for new permits and/or renewal of existing permits is undertaken as necessary to maintain compliance with applicable permitting requirements. Governmental authorities have the power to enforce compliance with these regulations and permits, and violators are subject to injunctions, civil fines and even criminal penalties. The Company believes that each of our Refineries has obtained all necessary permits and is in substantial compliance with such permits, and other applicable existing environmental laws and regulations.
The Company’s operations and many of the products manufactured are specifically subject to certain requirements of the Clean Air Act (“CAA”) and related state and local regulations. The 1990 amendments to the CAA contain provisions that will require capital expenditures for the installation of certain air pollution control devices at our refineries during the next several years. The EPA recently embarked on a Petroleum Refining Initiative (“Initiative”) alleging industry-wide noncompliance with certain CAA rules. The Initiative has resulted in many refiners entering into consent decrees typically requiring substantial expenditures for penalties and additional pollution control equipment. Frontier has been contacted by the EPA and invited to meet with them to hear more about the Initiative. At this time, the Company does not know how or if the Initiative will affect Frontier. The Company has, however, recently determined through the Company’s practice of routine self audits, that over the next three years, expenditures totaling approximately $10 million will likely be necessary to further reduce emissions from the Refineries’ flare systems. The results of these self audits have been shared with the state regulatory agencies in Wyoming and Kansas and, although Kansas has not yet responded, a violation notice has been issued by the State of Wyoming. The Company anticipates entering into a consent decree with the State of Wyoming which will likely contain an as yet to be determined penalty and compliance schedule to address this issue. Because other refineries will be required to make similar expenditures, Frontier does not expect such expenditures to materially adversely impact the Company’s competitive position.
On December 21, 1999, the EPA promulgated national regulations limiting the amount of sulfur that is to be allowed in gasoline. The total capital expenditures estimated, as of June 30, 2003, to achieve the final gasoline sulfur standard, are approximately $35 million at the Cheyenne Refinery and approximately $44 million at the El Dorado Refinery. Approximately $15.2 million of the Cheyenne Refinery expenditures had been incurred as of June 30, 2003, an additional $12.8 million is expected to be incurred by early 2004 with the remaining $7 million in 2009 and 2010. The expenditures for the El Dorado Refinery are expected to be incurred beginning in 2008 and completed in 2010.
The EPA recently promulgated regulations that will limit the sulfur content of highway diesel fuel beginning in 2006 to 15 parts-per-million from the current standard of 500 parts-per-million. As of June 30, 2003, capital costs for diesel desulfurization are estimated to be approximately $5 million for Cheyenne and $56 million for El Dorado. The Cheyenne Refinery expenditures are currently expected to be committed beginning in 2005, with the majority to be committed in 2006. Approximately $6 million of the El Dorado Refinery expenditures are currently expected to be committed in 2004 with the remaining $50 million in 2005 and 2006.
On April 15, 2003, the EPA proposed regulations to reduce emissions from diesel engines used in off-road activities such as agriculture, mining and railroads and also to limit the allowable amount of sulfur in the diesel fuel used in those engines. If promulgated, the EPA’s proposal would require a reduction in off-road diesel fuel sulfur by June 1, 2007 from the currently allowable 5,000 parts per million to 500 parts per million and by June 1, 2010 further limit the concentration of diesel fuel used in off-road applications other than railroads and marine engines to 15 parts per million of sulfur. The EPA is also proposing to allow small business refiners, such as Frontier, to continue to produce off-road diesel at the current sulfur limit of 5,000 parts per million through May 31, 2010 and to meet a limit of 500 parts per million sulfur from June 1, 2010 until May 31, 2014. Frontier has historically provided a minor amount of diesel fuel to the off-road markets from both of the Company’s refineries. The Company is monitoring these regulatory developments and is evaluating its compliance options. The costs that the Company will eventually incur to comply with these regulations, when final, are currently unknown.
As is the case with all companies engaged in similar industries, the Company faces potential exposure from claims and lawsuits involving environmental matters. The matters include soil and water contamination, air pollution, personal injury and property damage allegedly caused by substances which the Company manufactured, handled, used, released or disposed of.
A Frontier subsidiary, Wainoco Oil & Gas Company, owned and operated an interest in an oil field in the Los Angeles, California metropolitan area from 1985 to 1995. The production facilities for that interest in the oil field are located at the campus of the Beverly Hills High School. In April 2003, a law firm began filing claims with the Beverly Hills school district and city on behalf of former students, school employees and area residents alleging that emissions from the oil field or the production facilities caused cancers or various other health problems in those individuals. On June 9, 2003, the law firm filed a lawsuit related to some of these claims, styled Moss, et al. vs. Venoco, Inc. et al., in Superior Court for the State of California for the County of Los Angeles, Central District, asserting claims relating to 21 persons who allegedly developed cancer as a result of alleged emissions from the oil field, the production facilities at the Beverly Hills High School, from other nearby production facilities that were never operated by Frontier or any of its subsidiaries, and/or from the Century City District Energy Plant, an electric power plant located adjacent to the Beverly Hills High School. The lawsuit, which was amended on July 2, 2003, named 19 defendants, including the Beverly Hills Unified School District, the City of Beverly Hills, 12 oil and gas companies, including Wainoco Oil & Gas Company and Frontier, involved in owning and operating production facilities and 5 additional companies involved in owning or operating the power plant. On August 1, 2003, the law firm filed a second lawsuit against the same defendants, styled Yeshoua, et al. vs. Venoco, Inc. et al., in Superior Court of the State of California for the County of Los Angeles, Central District. The second lawsuit asserts claims relating to 208 persons who allegedly developed various kinds of cancer and 199 additional persons who allegedly developed unspecified personal injuries and fears of diseases as a result of the alleged emissions. Both lawsuits include claims for personal injury, wrongful death, loss of consortium and fear of contracting diseases, and also ask for punitive damages. No dollar amounts of damages have been specified in any of the lawsuits. The oil production site operated by Frontier’s subsidiary was a modern facility and was operated with a high level of safety and responsibility. Frontier believes that its subsidiary’s activities did not cause any health problems for former Beverly Hills high school students, school employees or area residents. Frontier believes that neither the claims that have been made against the Beverly Hills school district and the city, the two lawsuits, nor other pending or potential future litigation by which similar or related claims may be asserted against Frontier or its subsidiary will result in any material liability or have any other material adverse effect upon Frontier.
Cheyenne Refinery. The Company is party to an agreement with the State of Wyoming requiring the investigation and possible eventual remediation of certain areas of the Cheyenne Refinery’s property which may have been impacted by past operational activities. This action primarily addressed the threat of groundwater and surface water contamination. Based upon the results of the investigation, substantial capital expenditures and remediation of conditions found to exist have already taken place or are in progress, including the completion of surface impoundment closures, waste stabilization activities and other site remediation projects totaling approximately $4 million and an ongoing groundwater remediation program averaging $150,000 in annual operation and maintenance costs. Additional remedial action could be required by a subsequent administrative order or permit.
El Dorado Refinery. The El Dorado Refinery is subject to a 1988 consent order with the Kansas Department of Health and the Environment (“KDHE”). This order, including various subsequent modifications, requires the Refinery to continue the implementation of a groundwater management program with oversight provided by the KDHE Bureau of Environmental Remediation. The order requires that remediation activities continue until KDHE-established groundwater criteria or other criteria agreed to by the KDHE and the Refinery are met. Frontier acquired the El Dorado refinery in November 1999 from Equilon Enterprises LLC, now known as Shell Oil Products US (“Shell”). Subject to the terms of the purchase and sale agreement, Shell will be responsible for the costs of continued compliance with this order.
The most recent National Pollutant Discharge Elimination System permit issued to the El Dorado Refinery requires, in part, the preparation and submittal of an engineering report identifying certain refinery wastewater treatment plant upgrades necessary to allow routine compliance with applicable discharge permit limits. In accordance with the provisions of the purchase and sale agreement, Shell will be responsible for the first $2 million of any required wastewater treatment system upgrades. If required system upgrade costs exceed this amount, Shell and Frontier will share, based on a sliding scale percentage, up to another $3 million in upgrade costs. Subject to the terms of the purchase and sale agreement, Shell will be responsible for up to $5 million in costs, in addition to Shell’s obligation for the wastewater treatment system upgrade, relating to safety, health and environmental conditions after closing arising from Shell’s operation of the El Dorado Refinery that are not covered under a ten-year insurance policy. This insurance policy has $25 million coverage through November 17, 2009 for environmental liabilities, with a $500,000 deductible, and will reimburse the Company for losses related to all known and some unknown conditions existing prior to our acquisition of the El Dorado Refinery. The first phase of wastewater treatment system upgrades was completed in 2001 at a cost of $2.6 million with payment apportioned as described above.
On August 18, 2000, the Company entered into a Consent Agreement and Final Order of the Secretary (“Agreement”) with the KDHE that required the initiation of a wastewater toxicity testing program to commence upon the completion of the wastewater treatment upgrades described above. Progress has been made toward satisfying the provisions of the Agreement, and Frontier expects to meet all applicable requirements.
On March 31, 2003 the Company announced that it had entered into an agreement with Holly Corporation (“Holly”) pursuant to which the two companies will merge. Following the merger, the combined entity will own five refineries with refining capacity in excess of 260,000 barrels per day by the end of 2003. Pursuant to the merger agreement, Holly stockholders will receive in the merger transaction approximately 37% of the outstanding shares of the combined company, $172.5 million in cash, and contingent value rights representing non-transferable interests in potential future net recoveries from litigation related to past sales of jet fuel by Holly to the United States government. Frontier shareholders will receive in the merger transaction approximately 63% of the outstanding shares of the combined company, which will be named Frontier Oil Corporation. The combined company’s shares are expected to be listed on the New York Stock Exchange under the symbol “FTO”. The boards of directors of both companies have unanimously approved the merger and Frontier and Holly will each hold a special meeting of stockholders to consider and vote on the merger agreement. An amended registration statement on Form S-4 relating to the merger was filed on August 7, 2003. Consummation of the transaction is expected in the third quarter or early in the fourth quarter of 2003.
On April 17, 2003, the Company received the net proceeds from a private placement of $220 million of 8% senior notes (“Senior Notes”) due April 15, 2013. The net proceeds of the Senior Notes will be used, together with other available funds, to finance the cash portion of the merger with Holly, to pay related fees and expenses and to refinance or pay off existing Holly indebtedness. Any remaining net proceeds will be used for other general corporate purposes, which may include capital expenditures, potential future acquisitions or the repayment of our existing indebtedness. The Senior Notes were issued at 99.156% of principal amount, and were issued by Frontier Escrow Corporation, a newly formed, wholly-owned, direct subsidiary of Frontier Oil Corporation that was created solely to issue the Senior Notes and to merge with and into Frontier Oil Corporation upon consummation of the Holly merger. Pending consummation of the merger with Holly, the net proceeds of the notes offering, along with other amounts contributed by the Company, have been placed in an escrow account. If the merger with Holly does not occur by October 31, 2003, the notes will be redeemed by Frontier Escrow Corporation at a price equal to 101% of the aggregate principal amount of the notes plus accrued interest.
Effective June 1, 2003, one of the Company’s subsidiaries, Frontier Oil and Refining Company, entered into a new three year transportation agreement with a pipeline operator to transport up to 50,000 barrels per day of either West Texas Sour crude oil and/or West Texas Intermediate crude oil from Midland, Texas to Cushing, Oklahoma. If Frontier transports less than an average of 50,000 barrels per day over a contract year, Frontier is obligated to pay the pipeline operator a deficiency fee per barrel between the actual average barrels transported and 50,000 barrels. This agreement replaces previous similar agreements with pipeline operators.
| ITEM 2. |
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
RESULTS OF OPERATIONS
The terms “Frontier” and “we” refer to Frontier Oil Corporation and its subsidiaries.
Six months ended June 30, 2003 compared with the same period in 2002
We had a net loss for the six months ended June 30, 2003 of $4.7 million, or ($.18) per share, compared to a net loss of $2.7 million, or ($.11) per share, for the same period in 2002. The most significant factor causing the $2.0 million decrease in the results of operations in 2003 from 2002 was higher interest expense due to the issuance of the 8% Senior Notes in mid April 2003 to finance the pending Holly merger discussed in Notes 6 and 7 to the Consolidated Financial Statements.
Operating income increased $1.4 million in 2003 versus 2002 due to an increase in the refined product spread (refined product revenues less raw material, freight and other costs) of $15.3 million and an increase in other revenues of $478,000 offset by an increase in refinery operating expenses, excluding depreciation, of $11.9 million (which included $7.5 million of higher natural gas costs) and increases in selling and general costs, excluding depreciation, of $1.8 million and depreciation of $657,000.
Refined product spread is the difference between our refined product revenues and our raw material, freight and other costs. Raw material, freight and other costs include crude oil and other raw materials utilized in the refining process, purchased products and blendstocks, freight costs on free-on-board (“FOB”) destination sales, as well as the impact of changes in inventory under FIFO inventory accounting. Another term for refined product spread is gross margin. This is a useful number for management to gauge the profitability of the refined product market (i.e. the difference between what we sell the product for and the cost of the raw materials which are utilized to refine the product). The following table calculates the Company’s refined product spread per sales barrel for the six months ended June 30, 2003 and 2002.
Refined Product Spread Per Sales Barrel
(in thousands, except per sales barrel amounts)
Cheyenne El Dorado Consolidated
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Six Months Ended June 30, 2003
Refined Products Revenue (a) $ 336,797 $ 694,352 $ 1,031,149
Raw Material, Freight & Other Costs (b) $ 282,259 $ 616,419 $ 898,678
Total Product Sales (Mbbls) (c) 9,373 19,250 28,623
Refined Products Revenue Per Sales Barrel (a)/(c) = (d) $ 35.93 $ 36.07 $ 36.03
Raw Material, Freight & Other Costs Per Sales Barrel (b)/(c) = (e) $ 30.11 $ 32.02 $ 31.40
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Refined Product Spread Per Sales Barrel (d)-(e) $ 5.82 $ 4.05 $ 4.63
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Six Months Ended June 30, 2002
Refined Products Revenue (a) $ 224,590 $ 569,752 $ 794,342
Raw Material, Freight & Other Costs (b) $ 188,584 $ 488,560 $ 677,144
Total Product Sales (Mbbls) (c) 8,234 21,026 29,260
Refined Products Revenue Per Sales Barrel (a)/(c) = (d) $ 27.28 $ 27.10 $ 27.15
Raw Material, Freight & Other Costs Per Sales Barrel (b)/(c) = (e) $ 22.90 $ 23.24 $ 23.14
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Refined Product Spread Per Sales Barrel (d)-(e) $ 4.38 $ 3.86 $ 4.01
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Refined product revenues and raw material costs are impacted by changes in the price of crude oil. The average price of crude oil was substantially higher in 2003 than in 2002. Our profitability at our Cheyenne refinery is linked to the light/heavy crude spread (the discount at which heavy crude oil sells compared to the sales price of light crude oil) and our profitability at our El Dorado refinery is linked to the WTI/WTS crude spread (the difference between West Texas Intermediate and West Texas Sour crude oil prices). The refined product spread was $4.63 per sales barrel in 2003 compared to $4.01 per sales barrel in 2002 due to higher light product margins, increases in both the light/heavy crude spread and WTI/WTS crude spread, offset by the negative impacts of the 18 day planned major turnaround in March 2003 at our El Dorado refinery and a lower positive inventory valuation impact during the six months ended June 30, 2003 compared to the same period in 2002. For the six months ended June 30, 2003, we realized an increase to the refined product spread from inventory gains of approximately $2.7 million pretax ($1.7 million after tax), which was the net result of inventory gains in January and February and June because of increasing crude and product prices, partially offset by inventory losses (including lower of cost or market adjustments to inventory of $11.6 million during March) in March and April because of decreasing crude and product prices. The $11.6 million lower of cost or market adjustment at El Dorado at March 31, 2003 was exacerbated due to the turnaround and rapid price declines at the end of March. For the six months ended June 30, 2002 we realized an increase to the refined product spread from inventory gains of approximately $26.1 million pretax ($15.9 million after tax) because of increasing crude prices during the period.
The Cheyenne refinery refined product spread was $5.82 per sales barrel in the first six months of 2003 compared to $4.38 per sales barrel in the first six months of 2002 due to higher light product margins and an increase in the light/heavy spread offset by a lower positive inventory valuation impact during the six months ended June 30, 2003 compared to the same period in 2002. The light/heavy spread increased from an average $2.24 per barrel in the six months ended June 30, 2002 to $5.88 per barrel for the same period this year. For the six months ended June 30, 2003 at the Cheyenne refinery we realized an increase to the refined product spread from inventory gains of approximately $2.8 million pretax compared to an increase in the refined product spread from inventory gains of $8.9 million pretax for the six months ended June 30, 2002.
The El Dorado refinery refined product spread was $4.05 per sales barrel in 2003 compared to $3.86 per sales barrel in 2002 due to higher light product margins and an increase in the WTI/WTS crude spread offset by reduced charges, yields and sales resulting from the 18 day turnaround in March 2003 and a lower positive inventory valuation impact. The WTI/WTS spread increased from an average $1.38 per barrel in the six months ended June 30, 2002 to $2.78 per barrel for the same period this year. For the six months ended June 30, 2003 at the El Dorado refinery, we realized a decrease to the refined product spread from inventory losses of approximately $0.1 million pretax, compared to an increase in the refined product spread from inventory gains of $17.2 million pretax for the six months ended June 30, 2002.
Refined product revenues increased by $236.8 million or 30% from $794.3 million to $1.0 billion due to increased sales prices offset by decreased overall sales volumes. Average gasoline prices increased from $30.64 per sales barrel for the first six months of 2002 to $39.81 per sales barrel during the first six months of 2003. Gasoline sales volumes decreased 2,783 barrels per day during the six months ended June 30, 2003 compared to the comparable six months in 2002. Average diesel and jet fuel prices for the first six months of 2003 increased from $26.94 per sales barrel for the first six months of 2002 to $37.09 per sales barrel for the first six months of 2003. Diesel sales volumes decreased 1,995 barrels per day during the six months ended June 30, 2003 compared to the comparable six months in 2002. Manufactured product yields (“yields”) are the volumes of specification materials that are obtained through the distilling of crude oil and operations of other refinery process units. Yields of gasoline decreased 2,214 barrels per day or 3%, from 82,077 barrels per day during the six months ended June 30, 2002 to 79,863 barrels per day during the 2003 comparable period. Yields of diesel and jet fuel decreased 1,652 barrels per day or 3%, from 52,739 barrels per day during the six months ended June 30, 2002 to 51,087 barrels per day during the 2003 comparable period. The primary reason for the lower volumes in sales and yields in 2003 was the turnaround at the El Dorado refinery which commenced on March 18, 2003 and was completed on March 30.
Other revenues increased $478,000 to $1.6 million in the six months ended June 30, 2003 due to $1.0 million income from realized and unrealized futures trading net gains, primarily on positions purchased to hedge inventories, compared to a $678,000 gain in 2002 primarily from the ineffective portion of foreign crude oil hedges in 2002.
Raw material, freight and other costs include crude oil and other raw materials utilized in the refining process, purchased products and blendstocks, freight costs for FOB destination sales, as well as the impact of changes in inventory under FIFO inventory accounting. Raw material, freight and other costs of $898.7 million ($31.40 per sales barrel) during the six months ending June 30 2003 increased 33% (36% on a per sales barrel basis) or $221.5 million ($8.26 per sales barrel) when compared to the same period in 2002 primarily due to higher crude oil prices. The Cheyenne refinery raw material, freight and other costs of $30.11 per sales barrel increased 31% from $22.90 per sales barrel in 2002 due to higher crude oil prices. We benefited from the light/heavy spread averaging $5.88 per barrel in the first six months of 2003 compared to only $3.64 per barrel in the first six months of 2002. The heavy crude oil utilization rate for the six month period at the Cheyenne refinery expressed as a percentage of total crude oil was 89% in 2003 compared to 90% in 2002. The El Dorado refinery raw material, freight and other costs of $32.02 per sales barrel increased 38% from $23.24 per sales barrel in 2002 due to higher crude oil prices.
Refinery operating expenses, excluding depreciation, include both the variable costs (including energy and utilities) and the fixed costs (salaries, taxes, maintenance costs and other) of operating the refineries. Refinery operating expense, excluding depreciation, increased by $11.9 million (to $4.63 per sales barrel from $4.01 per sales barrel) during the six months ended June 30, 2003, when compared to the same period in 2002. Higher natural gas costs comprised approximately 42% of the per sales barrel refinery operating expense increase with the remainder being primarily due to decreased yields and sales volumes. The Cheyenne refinery operating expense, excluding depreciation, for the six months ended June 30, 2003 increased $797,000 from the same period in 2002, due to a $1.4 million increase in natural gas costs; however, refinery operating expense on a per sales barrel basis at Cheyenne decreased $.33 to $3.13 per sales barrel in 2003 due to increased sales volumes. The El Dorado refinery operating expense, excluding depreciation, increased $11.1 million for the six months ended June 30, 2003 from the same period in 2002 due primarily to a $6.0 million increase in natural gas cost, an increase of $2.1 million in salaries resulting from overtime incurred in connection with the turnaround and overall increased benefit costs, and the $2.4 million turnaround expense in excess of accrual. Refinery operating expense on a per sales barrel basis at El Dorado increased to $3.70 per sales barrel for the six months ended June 30, 2003, compared to $2.86 per sales barrel in 2002, a combination effect of both the higher refinery operating expenses and decreased sales volumes in 2003 due to the turnaround.
Selling and general expenses, excluding depreciation, increased $1.8 million or 22% for the six months ended June 30, 2003 compared to the same period in 2002 because of increased salaries, travel costs and engineering, legal and other consulting services relating to evaluating potential acquisitions. We also incurred an additional loss of $232,000 on the sale of an airplane which previously had been identified as being held for sale.
Depreciation increased $657,000 or 5% in the 2003 three-month period as compared to the same period in 2002 because of increases in capital investments.
The interest expense increase of $4.2 million or 31% for the six months ended June 30, 2003 was attributable to $3.6 million in interest expense on the $220,000,000 principal amount of 8% Senior Notes issued in mid April 2003 to facilitate the financing of our pending merger with Holly, the write-off of deferred finance costs related to previous repurchases of Senior Notes offset by less interest expense on the revolving credit facility from both lower average borrowings and lower market interest rates this year. Average debt outstanding during the six months ended June 30, increased from $256 million in 2002 to $333 million in 2003.
Three months ended June 30, 2003 compared with the same period in 2002
We had a net loss for the three months ended June 30, 2003 of $992,000, or ($.04) per share, compared to a net loss of $3.0 million, or ($.12) per share, for the same period in 2002. The most significant factors contributing to the $2.0 million increase in the results of operations in 2003 from 2002 were higher light product margins offset by higher crude oil prices and negative FIFO inventory valuation impacts.
Operating income increased $7.0 million in 2003 versus 2002 due to an increase in the refined product spread (refined product revenues less raw material, freight and other costs) of $11.6 million and an increase in other revenues of $180,000 being more than offset by an increase in refinery operating expenses, excluding depreciation, of $3.6 million (which included $2.9 million in higher natural gas costs) and increases in selling and general costs, excluding depreciation of $915,000 and depreciation of $295,000.
The following table calculates the Company’s refined product spread per sales barrel for the three months ended June 30, 2003 and 2002.
Refined Product Spread Per Sales Barrel
(in thousands, except per sales barrel amounts)
Cheyenne El Dorado Consolidated
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Three Months Ended June 30, 2003
Refined Products Revenue (a) $ 164,851 $ 368,577 $ 533,428
Raw Material, Freight & Other Costs (b) $ 138,251 $ 325,123 $ 463,374
Total Product Sales (Mbbls) (c) 4,885 10,696 15,581
Refined Products Revenue Per Sales Barrel (a)/(c) = (d) $ 33.75 $ 34.46 $ 34.24
Raw Material, Freight & Other Costs Per Sales Barrel (b)/(c) = (e) $ 28.30 $ 30.40 $ 29.74
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Refined Product Spread Per Sales Barrel (d)-(e) $ 5.45 $ 4.06 $ 4.50
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Three Months Ended June 30, 2002
Refined Products Revenue (a) $ 136,563 $ 322,794 $ 459,357
Raw Material, Freight & Other Costs (b) $ 117,524 $ 283,381 $ 400,905
Total Product Sales (Mbbls) (c) 4,587 10,824 15,411
Refined Products Revenue Per Sales Barrel (a)/(c) = (d) $ 29.77 $ 29.82 $ 29.81
Raw Material, Freight & Other Costs Per Sales Barrel (b)/(c) = (e) $ 25.62 $ 26.18 $ 26.01
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Refined Product Spread Per Sales Barrel (d)-(e) $ 4.15 $ 3.64 $ 3.80
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Refined product revenues and raw material costs are impacted by changes in the price of crude oil. The average price of crude oil was substantially higher in 2003 than in 2002. Our profitability at our Cheyenne refinery is also linked to the light/heavy crude spread (the discount at which heavy crude oil sells compared to the sales price of light crude oil) and our profitability at our El Dorado refinery is linked to the WTI/WTS crude spread (the difference between West Texas Intermediate and West Texas Sour crude oil prices). The refined product spread was $4.50 per sales barrel in 2003 compared to $3.80 per sales barrel in 2002 due to higher light product margins, increases in both the light/heavy crude spread and WTI/WTS crude spread, offset by a negative inventory valuation impact during the three months ended June 30, 2003 compared to a positive inventory valuation impact in the same period in 2002. For the three months ended June 30, 2003, we realized losses to the refined product spread from inventory losses of approximately $5.7 million pretax ($3.5 million after tax), which was the net result of inventory losses in April and May because of decreasing crude and product prices, partially offset by inventory gains in June. For the three months ended June 30, 2002 we realized an increase to the refined product spread from inventory gains of approximately $12.2 million pretax ($7.6 million after tax) because of increasing crude prices during the six months.
The Cheyenne refinery refined product spread was $4.06 per sales barrel in the second quarter of 2003 compared to $3.64 per sales barrel in the second quarter of 2002 due to higher light product margins and an increase in the light/heavy spread offset by a slightly negative inventory valuation impact during the three months ended June 30, 2003 compared to a positive inventory valuation impact for the same period in 2002. The light/heavy spread increased from an average $3.52 per barrel in the three months ended June 30, 2002 to $5.48 per barrel for the same period this year. For the three months ended June 30, 2003 at the Cheyenne refinery we realized a decrease to the refined product spread from inventory losses of approximately $201,000 pretax compared to an increase in the refined product spread from inventory gains of $4.1 million pretax for the three months ended June 30, 2002.
The El Dorado refinery refined product spread was $4.06 per sales barrel in 2003 compared to $3.64 per sales barrel in 2002 due to higher light product margins, an increase in the WTI/WTS crude spread offset by a negative inventory valuation impact. The WTI/WTS spread increased from an average $1.22 per barrel in the three months ended June 30, 2002 to $3.19 per barrel for the same period this year. For the three months ended June 30, 2003 at the El Dorado refinery, we realized a decrease to the refined product spread from inventory losses of approximately $5.5 million pretax, compared to an increase in the refined product spread from inventory gains of $8.1 million pretax for the three months ended June 30, 2002.
Refined product revenues increased by $74.1 million or 16% from $459.4 million to $533.4 million due to increased sales prices and increased overall sales volumes. Average gasoline prices increased from $33.96 per sales barrel for the second quarter of 2002 to $38.61 per sales barrel during the same period of 2003. Gasoline sales volumes decreased 2,240 barrels per day during the three months ended June 30, 2003 compared to the comparable three months in 2002. Average diesel and jet fuel prices increased from $29.37 per sales barrel for the three months ended June 30, 2002 to $34.22 per sales barrel for the comparable period of 2003. Diesel sales volumes increased 2,659 barrels per day during the three months ended June 30, 2003 compared to the comparable three months in 2002. Yields of gasoline increased 3,006 barrels per day or 4%, from 82,050 barrels per day during the three months ended June 30, 2002 to 85,056 barrels per day during the 2003 comparable period. Yields of diesel and jet fuel increased 5,134 barrels per day or 9%,from 54,190 barrels per day during the three months ended June 30, 2002 to 59,324 barrels per day during the 2003 comparable period.
Other revenues increased $180,000 to a $15,000 loss in 2003 from a $195,000 loss in 2002 due to a $357,000 loss from realized and unrealized futures trading net gains from positions to hedge inventory and the ineffective portion of foreign crude oil hedges in 2003 compared to a $411,000 loss in 2002. We also realized a $43,000 gain from the sale of assets, and 2003 processing income was $63,000 more than in 2002.
Raw material, freight and other costs include crude oil and other raw materials utilized in the refining process, purchased products and blendstocks, freight costs for free-on-board (“FOB”) destination sales, as well as the impact of changes in inventory under FIFO inventory accounting. Raw material, freight and other costs of $463.4 million during the three months ending June 30, 2003 increased 16% (14% on a per sales barrel basis) or $62.5 million ($3.73 per sales barrel) when compared to the same period in 2002 primarily due to higher crude oil prices. The Cheyenne refinery raw material, freight and other costs of $28.30 per sales barrel increased 10% from $25.62 per sales barrel in 2002 due to higher crude oil prices. We benefited from the light/heavy spread averaging $5.48 per barrel in the second quarter of 2003 compared to only $3.52 per barrel in the comparable quarter of 2002. The heavy crude oil utilization rate at the Cheyenne refinery expressed as a percentage of total crude oil was 88% in 2003 compared to 90% in 2002. The El Dorado refinery raw material, freight and other costs of $30.40 per sales barrel increased 16% from $26.18 per sales barrel in 2002 due to higher crude oil prices.
Refinery operating expenses, excluding depreciation, include both the variable costs (including energy and utilities) and the fixed costs (salaries, taxes, maintenance costs and other) of operating the refineries. Refinery operating expense, excluding depreciation, increased by $3.6 million (to $3.16 per sales barrel from $2.96 per sales barrel) during the three months ended June 30, 2003, when compared to the same period in 2002. Higher natural gas costs comprised approximately 95% of the per sales barrel refinery operating expense increase. The Cheyenne refinery operating expense, excluding depreciation, for the three months ended June 30, 2003 decreased $518,000 from the same period in 2002, due to $940,000 in excess turnaround costs in 2002, with none in 2003, offset by a $342,000 increase in natural gas costs from 2002 to 2003. The refinery operating expense on a per sales barrel basis at Cheyenne decreased $.31 to $3.01 per sales barrel in 2003 due to the lower expense and increased sales volumes. The El Dorado refinery operating expense, excluding depreciation, increased $4.1 million for the three months ended June 30, 2003 from the same period in 2002 due primarily to a $2.6 million increase in natural gas cost and a $1.1 million negative variance in additives and chemicals. Refinery operating expense at El Dorado increased to $3.23 per sales barrel for the three months ended June 30, 2003, compared to $2.81 per sales barrel in 2002, a combination effect of both the higher refinery operating expenses and decreased sales volumes in 2003.
Selling and general expenses, excluding depreciation, increased $915,000 or 22% for the three months ended June 30, 2003 compared to the same period in 2002 because of increased salaries, travel costs and engineering, legal and other consulting services relating to evaluating potential acquisitions. We also incurred an additional loss of $232,000 on the sale of an airplane which previously had been identified as being held for sale.
Depreciation increased $295,000 or 4% in the 2003 three-month period as compared to the same period in 2002 because of increases in capital investments.
The interest expense increase of $3.6 million or 51% for the three months ended June 30, 2003 was attributable to $3.6 million in interest expense on the $220,000,000 principal amount of 8% Senior Notes issued in mid April 2003 to facilitate the financing of our pending merger with Holly. Average debt outstanding during the three months ended June 30, increased from $261 million in 2002 to $413 million in 2003.
LIQUIDITY AND CAPITAL RESOURCES
Net cash used by operating activities for the six months ended June 30, 2003 was $24,000 compared to $13.2 million cash used by operating activities for the six months ended June 30, 2002. Working capital changes required $9.0 million and $23.1 million of cash flows for the first six months of 2003 and 2002, respectively. The major use of working capital during the six months ended June 30, 2003 was an increase in inventory of $31.4 million due to higher crude and other prices. The major source of working capital during the six months ended June 30, 2003 was a decrease in trade and crude payables of $21.4 million also due to higher crude oil prices resulting in an increase in crude payables.
Additions to property and equipment in the first six months of 2003 of $17.8 million decreased $0.9 million from the first six months in 2002. Capital expenditures of approximately $40 million are planned in 2003, which includes nearly $15.0 million for the low sulfur gasoline project at Cheyenne. The additional $25 million of capital expenditures consists of $14.0 million of sustaining capital (including safety, environmental and operational projects), $4.1 million of growth, strategic and profitability projects, $3.2 million of information technology projects and $3.7 million of small capital and other projects at both the Cheyenne and El Dorado refineries. During the first six months of 2002, we also paid out the $7.5 million El Dorado earn-out payment based on 2001 results of operations. No El Dorado earn-out payment will be made in 2003, as none was earned based on the 2002 results of operations. During the first six months of 2003 we have incurred $2.0 million of Holly acquisition-related costs, primarily legal and accounting, which are included in Other Assets on the June 30, 2003, balance sheet and will become part of the purchase price allocation when the transaction is consummated.
On May 29, 2003 we announced that we had entered into an amended and restated revolving credit facility with a group of banks led by Union Bank of California and BNP Paribas. Commitments under the new working capital facility are $175 million and will increase to $250 million upon closing of the merger with Holly Corporation, which is expected to close in the third quarter of this year. Cash advances under the revolving credit facility are currently limited to a maximum of $125 million, increasing to $200 million upon closing of the merger. The facility includes reduced interest rate spreads and letter of credit fees. In addition, a new financial covenant package is reflective of the revised capital structure and facilitates intra-company funds flows. We are in compliance at June 30, 2003 with the financial covenants of our new revolving credit facility.
At June 30, 2003, we had borrowings under our revolving credit facility of $8.0 million, $77.8 million of cash and cash equivalents, working capital of $79.6 million, and an approximate $101.2 million borrowing base availability for additional borrowings under our revolving credit facility.
During the first six months of 2003 we have not purchased any additional common stock under our previously announced stock repurchase programs authorized by our Board of Directors to purchase up to six million shares; however, we did acquire 24,825 shares of stock from employees to cover their withholding taxes on shares of restricted stock which vested in March. Through December 2002, 4,367,366 shares of common stock had been purchased under the stock repurchase programs.
Dividends of $2.6 million were paid to shareholders during the first six months of 2003. These dividends of $.05 per share were declared in December 2002 and March 2003 and were paid on January 13, 2003 and April 14, 2003, respectively. Our Board of Directors also declared dividends in June 2003 of $.05 per share, which were paid on July 14, 2003 to shareholders of record on June 27, 2003. The cash required for this dividend was approximately $1.3 million and was accrued as of June 30, 2003.
On April 17, 2003, we received the net proceeds from a private placement of $220 million of 8% senior notes (“Senior Notes”) due April 15, 2013. The net proceeds of the Senior Notes will be used, together with other available funds, to finance the cash portion of the previously discussed Holly merger, to pay related fees and expenses and to refinance or pay off existing Holly indebtedness. Any remaining net proceeds will be used for other general corporate purposes which may include capital expenditures, potential future acquisitions or the repayment of our existing indebtedness. The Senior Notes were issued at 99.156% of principal amount and were issued by Frontier Escrow Corporation, a newly formed, wholly-owned, direct subsidiary of Frontier that was created solely to issue the Senior Notes and to merge with and into Frontier Oil Corporation upon consummation of the Holly merger. Pending consummation of the Holly merger, the net proceeds of the offering, along with other amounts contributed by us, have been placed in an escrow account. The amounts in this escrow account are reflected as restricted cash on our June 30, 2003 balance sheet. If the Holly merger does not occur by October 31, 2003, Frontier Escrow Corporation will redeem the Senior Notes at a price equal to 101% of the aggregate principal amount of the notes plus accrued interest.
REFINING OPERATING STATISTICAL INFORMATION
Consolidated:
Six Months Ended Three Months Ended
June 30, June 30,
--------------------- ----------------------
2003 2002 2003 2002
--------- --------- --------- ---------
Charges (bpd) (1)
Light crude 30,021 31,423 33,428 31,457
Heavy and intermediate crude 110,304 112,848 122,769 117,044
Other feed and blend stocks 18,972 16,942 17,413 16,573
--------- --------- --------- ---------
Total 159,297 161,213 173,610 165,074
Manufactured product yields (bpd) (2)
Gasoline 79,863 82,077 85,056 82,050
Diesel and jet fuel 51,087 52,739 59,324 54,190
Asphalt 6,686 6,635 7,976 8,764
Chemicals (3) 798 (19) 749 14
Other 17,442 16,003 17,095 15,101
--------- --------- --------- ---------
Total 155,876 157,435 170,200 160,119
Total product sales (bpd)
Gasoline 86,244 89,027 89,420 91,660
Diesel and jet fuel 51,028 53,023 57,724 55,065
Asphalt 6,410 6,229 8,846 9,029
Chemicals (3) 798 234 749 150
Other 13,661 13,151 14,476 13,462
--------- --------- --------- ---------
Total 158,141 161,664 171,215 169,366
Operating margin information (per sales bbl)
Average sales price $ 36.03 $ 27.15 $ 34.24 $ 29.81
Raw material, freight and other costs
(FIFO inventory accounting) 31.40 23.14 29.74 26.01
-------- --------- --------- ---------
Product spread 4.63 4.01 4.50 3.80
Refinery operating expenses, excl depreciation 3.51 3.03 3.16 2.96
Depreciation .49 .45 .45 .43
-------- --------- --------- ---------
Operating margin $ .63 $ .53 $ .89 $ .41
Average West Texas Intermediate
crude oil price at Cushing, OK $ 32.54 $ 23.82 $ 30.30 $ 26.36
Average sales price (per sales bbl)
Gasoline $ 39.81 $ 30.64 $ 38.61 $ 33.96
Diesel and jet fuel 37.09 26.94 34.22 29.37
Asphalt 23.90 19.62 24.03 21.37
Chemicals (3) 57.13 36.71 48.54 40.21
Other 12.64 7.74 12.77 8.83
(1) Charges are the quantity of crude oil and other feedstocks processed through refinery units.
(2) Manufactured product yields are the volumes of specification materials that are obtained through the
distilling of crude oil and operations of other refinery process units.
(3) During the first quarter of 2002, the process of shutting down the petro-chemical complex at El Dorado
began and we discontinued the production of phenol and acetone and began producing and selling benzene.
REFINING OPERATING STATISTICAL INFORMATION
Cheyenne Refinery:
Six Months Ended Three Months Ended
June 30, June 30,
--------------------- ---------------------
2003 2002 2003 2002
--------- --------- --------- ---------
Charges (bpd) (1)
Light crude 4,713 3,791 5,650 4,349
Heavy crude 39,485 35,092 40,500 37,541
Other feed and blend stocks 5,681 4,108 4,692 3,358
--------- --------- --------- ---------
Total 49,879 42,991 50,842 45,248
Manufactured product yields (bpd) (2)
Gasoline 20,042 16,122 19,226 15,737
Diesel 14,834 12,762 15,568 12,882
Asphalt 6,686 6,635 7,976 8,764
Other 6,858 5,984 6,474 5,852
--------- --------- --------- ---------
Total 48,420 41,503 49,244 43,235
Total product sales (bpd)
Gasoline 25,993 22,465 24,385 23,889
Diesel 14,914 12,758 15,939 13,703
Asphalt 6,410 6,229 8,846 9,029
Other 4,467 4,045 4,512 3,788
--------- --------- --------- ---------
Total 51,784 45,497 53,682 50,409
Operating margin information (per sales bbl)
Average sales price $ 35.93 27.28 $ 33.75 $ 29.77
Raw material, freight and other costs
(FIFO inventory accounting) 30.11 22.90 28.30 25.62
-------- --------- --------- ---------
Product spread 5.82 4.38 5.45 4.15
Refinery operating expenses, excl depreciation 3.13 3.46 3.01 3.32
Depreciation .82 .87 .79 .81
-------- --------- --------- ---------
Operating margin $ 1.87 $ .05 $ 1.65 $ .02
Average light/heavy crude spread based on
delivered crude costs (per bbl) (3) $ 5.88 $ 3.64 $ 5.48 $ 3.52
Average sales price (per sales bbl)
Gasoline $ 41.74 $ 32.49 $ 40.34 $ 35.64
Diesel 39.15 28.67 36.17 31.50
Asphalt 23.90 19.62 24.03 21.37
Other 8.71 5.71 8.64 6.53
(1) Charges are the quantity of crude oil and other feedstocks processed through refinery units.
(2) Manufactured product yields are the volumes of specification materials that are obtained through the
distilling of crude oil and operations of other refinery process units.
(3) Average light/heavy spread is the discount at which heavy crude oil (gravity is low) sells compared to
the sales price of light crude oil (gravity is high).
REFINING OPERATING STATISTICAL INFORMATION
El Dorado Refinery:
Six Months Ended Three Months Ended
June 30, June 30,
---------------------- ----------------------
2003 2002 2003 2002
--------- --------- --------- ---------
Charges (bpd) (1)
Light crude 25,308 27,631 27,778 27,108
Heavy and intermediate crude 70,819 77,756 82,269 79,503
Other feed and blend stocks 13,291 12,834 12,721 13,215
--------- --------- --------- ---------
Total 109,418 118,221 122,768 119,826
Manufactured product yields (bpd) (2)
Gasoline 59,822 65,955 65,829 66,313
Diesel and jet fuel 36,253 39,978 43,756 41,308
Chemicals (3) 798 (19) 749 14
Other 10,584 10,019 10,621 9,249
--------- --------- --------- ---------
Total 107,457 115,933 120,955 116,884
Total product sales (bpd)
Gasoline 60,250 66,562 65,036 67,771
Diesel and jet fuel 36,114 40,265 41,785 41,362
Chemicals (3) 798 234 749 150
Other 9,195 9,107 9,963 9,673
--------- --------- --------- ---------
Total 106,357 116,168 117,533 118,956
Operating margin information (per sales bbl)
Average sales price $ 36.07 $ 27.10 $ 34.46 $ 29.82
Raw material, freight and other costs
(FIFO inventory accounting) 32.02 23.24 30.40 26.18
-------- --------- --------- ---------
Product spread 4.05 3.86 4.06 3.64
Refinery operating expenses, excl depreciation 3.70 2.86 3.23 2.81
Depreciation .33 .28 .29 .28
-------- --------- --------- ---------
Operating margin $ .02 $ .72 $ .54 $ .55
WTI/WTS crude spread (per bbl) (4) $ 2.78 $ 1.38 $ 3.19 $ 1.22
Average sales price (per sales bbl)
Gasoline $ 38.97 $ 30.01 $ 37.96 $ 33.37
Diesel and jet fuel 36.25 26.39 33.48 28.66
Chemicals (3) 57.13 36.71 48.54 40.21
Other 14.54 8.64 14.64 9.73
(1) Charges are the quantity of crude oil and other feedstocks processed through refinery units.
(2) Manufactured product yields are the volumes of specification materials that are obtained through the
distilling of crude oil and operations of other refinery process units.
(3) During the first quarter of 2002, the process of shutting down the petro-chemical complex at El Dorado
began and we discontinued the production of phenol and acetone and began producing and selling benzene.
(4) Average differential between benchmark West Texas intermediate (sweet) crude oil priced at Cushing,
Oklahoma and West Texas sour crude oil priced at Midland, Texas.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Impact of Changing Prices. Our revenues and cash flows, as well as estimates of future cash flows, are very sensitive to changes in energy prices. Major shifts in the cost of crude oil and the price of refined products and natural gas can result in large changes in the operating margin from refining operations. These prices also determine the carrying value of the refineries’ inventories.
Price Risk Management Activities. At times, we enter into commodity derivative contracts to manage our price exposure to our inventory positions, our purchases of foreign crude oil and consumption of natural gas in the refining process as well as fix margins on certain future production. The commodity derivative contracts we use may take the form of futures contracts or price swaps and are entered into with reputable counterparties. We use futures transactions to price foreign crude oil cargos at the time when the crude oil is processed by the El Dorado Refinery instead of the price when purchased. Foreign crude oil delivery times can exceed one month from when the purchase is made. In addition, we may engage in futures transactions for the purchase of natural gas at fixed prices. The El Dorado and Cheyenne refineries consume natural gas for energy and feedstock purposes. We account for our commodity derivative contracts under 1) the hedge (or deferral) method of accounting when the derivative contracts qualify and are designated as hedges for accounting purposes, or 2) mark-to-market accounting if we elect not to designate derivative contracts as accounting hedges or if such derivative contracts do not qualify for hedge accounting. As such, gains or losses on commodity derivative contracts accounted for as hedges are recognized in refining operating expenses when the associated transactions are consummated while gains and losses on transactions accounted for using mark-to-market accounting are reflected in other revenues at each period end.
Other revenues for the six months ended June 30, 2003 includes $999,000 realized and unrealized net gains on derivative contracts accounted for using mark-to-market accounting and $20,000 net realized gains for the ineffective portion of crude oil hedges. Other revenues for the six months ended June 30, 2002 included $1.2 million realized and unrealized net gains on the ineffective portion of fair value hedges on crude oil cargos and $499,000 realized and unrealized net losses on derivative contracts accounted for using mark-to-market accounting. Other revenues for the three months ended June 30, 2003 includes $359,000 realized and unrealized net losses on derivative contracts accounted for using mark-to-market accounting and $2,000 net realized gains for the ineffective portion of crude oil hedges. Other revenues for the three months ended June 30, 2002 includes $88,000 realized and unrealized net gains on the ineffective portion of fair value hedges on crude oil cargos and $499,000 realized and unrealized net losses on derivative contracts accounted for using mark-to-market accounting. The ineffective portion of foreign crude oil hedges arises primarily from changes in the shape of the forward futures price curve.
At June 30, 2003 we had the following open commodity derivative contracts which, while economic hedges, did not qualify for hedge accounting treatment and whose gains or losses are being reflected in other revenues:
| • | Derivative contracts on 239,000 barrels of crude oil to hedge gas oil inventory builds at the El Dorado refinery. These open contracts have total unrealized losses at June 30, 2003 of approximately $249,000. During the six months ended June 30, 2003 we realized net gains of approximately $1.2 million on closed out contracts to hedge the gas oil inventory. |
We had no open derivative contracts at June 30, 2003 being accounted for as hedges. During the six months ended June 30, 2003, we had the following derivatives that were appropriately designated and accounted for as hedges:
| • |
Natural Gas Collars. Price swaps on natural gas for the purpose of
hedging against natural gas price increases for February and March 2003 for
approximately 100% of the El Dorado refinery’s anticipated usage and which
are accounted for as cash flow hedges. The February group of contracts to hedge
natural gas costs were for 700,000 MMBTU and expired with no gain or loss. The
March group of contracts to hedge natural gas totaled 720,000 MMBTU and the
Company realized a $1.7 million gain which reduced our refining operating
expenses in March.
|
|
| • | Crude Contracts. In January 2003, we had derivative contracts on 200,000 barrels of crude oil to hedge Canadian crude costs for the Cheyenne refinery which were accounted as fair value hedges. A $13,000 loss was realized on these positions of which $31,000 increased crude costs and $18,000 income was reflected in other revenues for the ineffective portion of this hedge. In May 2003, we closed out derivative contracts we had purchased in April 2003 on 675,000 barrels of crude oil to hedge two foreign crude cargos purchased for the El Dorado refinery. A $13,000 gain was realized on these positions of which $11,000 reduced crude costs and $2,000 was reflected in other revenues for the ineffective portion of these hedges. |
Interest Rate Risk. Borrowings under our revolving credit facility bear a current market rate of interest. Our approximately $39.5 million principal of outstanding 9-1/8% Senior Notes, due 2006, have a fixed interest rate. Our approximately $170.5 million principal of 11¾% Senior Notes outstanding, due 2009, and our $220.0 million principal of 8% Senior Notes, due 2013, also have fixed interest rates. Accordingly, our long-term debt is not exposed to cash flow risk from interest rate changes; however, our long-term debt is exposed to fair value risk. The estimated fair value of the 9-1/8% Senior Notes at June 30, 2003 was $40.3 million, the estimated fair value of the 11¾% Senior Notes was $185.8 million and the estimated fair value of the 8% Senior Notes was $226.6 million.
ITEM 4. CONTROLS AND PROCEDURES
We maintain a set of disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports filed by us under the Securities Exchange Act of 1934, as amended (“Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our management, including our Chairman of the Board, President and Chief Executive Officer and our Executive Vice President - Finance & Administration, Chief Financial Officer of the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-14 of the Exchange Act. Based on that evaluation, our Chairman of the Board, President and Chief Executive Officer and our Executive Vice President - Finance & Administration, Chief Financial Officer, concluded that our disclosure controls and procedures are effective.
There have been no significant changes in our internal controls or other factors that could significantly affect those controls subsequent to the date of their evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
PART II - OTHER INFORMATION
| ITEM 1. |
Legal Proceedings - None that in the opinion of management would have a material impact on the registrant. |
| ITEM 2. |
Changes in Securities - There have been no changes in the constituent instruments defining the rights of the holders of any class of registered securities during the current quarter. |
| ITEM 3. |
Defaults Upon Senior Securities - None. |
| ITEM 4. |
Submission of Matters to a Vote of Security Holders - None. |
| ITEM 5. |
Other Information - None. |
| ITEM 6. |
Exhibits and Reports on Form 8-K - (a) Exhibits 10.1 – Amended and Restated Revolving Credit Agreement dated May 27, 2003 among Frontier Oil Corporation, one of its wholly owned subsidiaries, Frontier Oil and Refining Company, as borrower, the lenders named therein, Union Bank of California, N.A., as administrative agent, documentation agent and lead arranger, and PNB Paribas, as syndication agent (incorporated by reference and filed as Exhibit 99.2 to Form 8-K dated and filed May 29, 2003, File Number 001-07627). 31.1 – Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31.2 – Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 32.1 - - Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 32.2 - Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (b) Reports on Form 8-K A report on Form 8-K dated March 30, 2003 and filed April 2, 2003, File Number 001-07627 regarding the Agreement and Plan of Merger between Frontier Oil Corporation and Holly Corporation. A report on Form 8-K dated and filed April 2, 2003, File Number 001-07627 regarding the Company’s proposal to make a private placement of senior notes. A report on Form 8-K dated May 1, 2003 and filed May 2, 2003, File Number 001-07627 regarding the news release announcing the Company’s first quarter financial results. A report on Form 8-K dated April 17, 2003 and filed May 9, 2003, File Number 001-07627 regarding the amended Registration Rights Agreement. A report on Form 8-K dated May 12, 2003 and filed May 14, 2003, File Number 001-07627 regarding an amendment to the merger agreement with Holly Corporation. A report on Form 8-K dated and filed May 29, 2003, File Number 001-07627 regarding the execution of the Amended and Restated Revolving Credit Agreement. A report on Form 8-K dated June 10, 2003 and filed June 12, 2003, File Number 001-07627 regarding a press release announcing that a lawsuit had been filed in California naming a number of oil companies, including, Frontier Oil Corporation and its subsidiary Wainoco Oil & Gas Company, as defendants. A report on Form 8-K dated July 30, 2003 and filed July 31, 2003, File Number 001-07627 regarding a press release announcing the Company’s second quarter results. |
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
| FRONTIER OIL CORPORATION |
| By: |
/s/ Nancy J. Zupan –––––––––––––––––––– Nancy J. Zupan Vice President - Controller (principal accounting officer) |
Date: August 11, 2003