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 SEPTEMBER 30, 2004 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 October 29, 2004: 26,954,157 |
FRONTIER OIL CORPORATION
QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTER ENDED SEPTEMBER 30, 2004
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;
|
| • |
statements relating to future financial performance, future capital sources and other matters; and
|
| • | 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. |
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.
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
FRONTIER OIL CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited, in thousands except per share amounts)
Nine Months Ended Three Months Ended
September 30 September 30
2004 2003 2004 2003
------------ ----------- ----------- ----------
Revenues:
Refined products $ 2,069,785 $ 1,625,441 $ 791,613 $ 594,292
Other (11,473) 2,119 (6,537) 471
------------ ----------- ----------- ----------
2,058,312 1,627,560 785,076 594,763
------------ ----------- ----------- ----------
Costs and Expenses:
Raw material, freight and other costs 1,719,851 1,401,401 671,400 502,723
Refinery operating expenses, excluding
depreciation 162,124 149,059 55,721 48,495
Selling and general expenses, excluding
depreciation 20,921 14,926 7,075 5,132
Merger termination and legal costs 3,820 3,953 157 3,953
Depreciation and amortization 23,928 21,187 8,166 7,156
------------ ----------- ----------- ----------
1,930,644 1,590,526 742,519 567,459
------------ ----------- ----------- ----------
Operating Income 127,668 37,034 42,557 27,304
------------ ----------- ----------- ----------
Interest expense and other financing costs 17,618 20,749 5,813 6,590
Interest income (890) (907) (485) (260)
Gain on involuntary conversion of assets (594) - - -
Merger financing termination costs, net - 17,632 - 14,212
------------ ----------- ----------- ----------
16,134 37,474 5,328 20,542
------------ ----------- ----------- ----------
Income (Loss) Before Income Taxes 111,534 (440) 37,229 6,762
Provision for Income Taxes 42,009 430 13,437 2,940
------------ ----------- ----------- ----------
Net Income (Loss) $ 69,525 $ (870) $ 23,792 $ 3,822
============ =========== =========== ==========
Basic Income (Loss) Per Share
of Common Stock $ 2.61 $ (.03) $ .89 $ .15
============ =========== =========== ==========
Diluted Income (Loss) Per Share
of Common Stock $ 2.55 $ (.03) $ .87 $ .14
============ =========== =========== ==========
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)
Nine Months Ended Three Months Ended
September 30 September 30
2004 2003 2004 2003
------------ ----------- ----------- ----------
Net Income (Loss) $ 69,525 $ (870) $ 23,792 $ 3,822
Other Comprehensive Income, Net of Income Tax - - - -
------------ ----------- ----------- ----------
Comprehensive Income (Loss) $ 69,525 $ (870) $ 23,792 $ 3,822
============ =========== =========== ==========
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)
September 30, 2004 and December 31, 2003 2004 2003
----------- ----------
ASSETS
Current Assets:
Cash, including cash equivalents of
$115,159 in 2004 and $56,811 in 2003 $ 122,741 $ 64,520
Trade receivables, net of allowance of $500 in both years 132,226 86,519
Other receivables 6,182 1,834
Inventory of crude oil, products and other 192,550 123,999
Deferred tax assets 7,165 5,967
Other current assets 985 1,974
----------- ----------
Total current assets 461,849 284,813
----------- ----------
Property, Plant and Equipment, at cost:
Refineries, terminal equipment and pipeline 515,755 489,502
Furniture, fixtures and other equipment 8,033 6,142
----------- ----------
523,788 495,644
Less - Accumulated depreciation 196,142 173,196
----------- ----------
327,646 322,448
Deferred Financing Costs, net 3,564 4,009
Commutation Account 17,334 19,550
Prepaid Insurance 4,845 6,593
Other Assets 4,811 4,884
Other Intangible Assets, net 1,553 -
----------- ----------
TOTAL ASSETS $ 821,602 $ 642,297
=========== ==========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Accounts payable $ 249,751 $ 177,235
Revolving credit facility 36,250 45,750
Accrued turnaround cost 15,996 10,412
Accrued liabilities and other 23,025 10,282
Accrued interest 7,512 2,513
----------- ----------
Total current liabilities 332,534 246,192
----------- ----------
Long-Term Debt 168,853 168,689
Long-Term Accrued and Other Liabilities 36,317 36,954
Deferred Credits and Other 4,404 4,255
Deferred Income Taxes 39,617 16,930
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,
31,588,624 and 30,643,549 shares issued in 2004 and 2003 57,599 57,504
Paid-in capital 117,907 106,443
Retained earnings 112,850 47,614
Accumulated other comprehensive loss (924) (924)
Treasury stock, 4,638,467 shares and 4,264,673 shares
in 2004 and 2003 (47,024) (39,914)
Deferred employee compensation (531) (1,446)
----------- ----------
Total Shareholders' Equity 239,877 169,277
----------- ----------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 821,602 $ 642,297
=========== ==========
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 nine months ended September 30, 2004 2003
----------- ----------
OPERATING ACTIVITIES
Net income (loss) $ 69,525 $ (870)
Depreciation and amortization 23,928 21,187
Deferred income taxes 26,363 131
Merger finance costs and discount on 8% Senior Notes - 8,114
Amortization of deferred finance costs and discount 802 1,833
Deferred employee compensation amortization 915 1,009
Amortization of long-term prepaid insurance 1,148 -
Decrease in commutation account 2,216 -
Change in deferred credits and other (81) (604)
Net assets written-off in involuntary conversion of assets 1,126 -
Net loss on sale of assets - 189
Change in working capital from operations (18,766) (1,672)
----------- ----------
Net cash provided by operating activities 107,176 29,317
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INVESTING ACTIVITIES
Additions to property, plant and equipment and other (34,840) (27,026)
Proceeds from sale of assets - 304
Other investments - (34)
----------- ----------
Net cash used in investing activities (34,840) (26,756)
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FINANCING ACTIVITIES
Revolving credit facility (repayments) borrowings, net (9,500) 16,750
Deferred finance costs (193) (877)
Issuance of common stock 2,591 316
Purchase of treasury stock (3,029) (428)
Dividends (4,051) (3,890)
Other 67 -
Proceeds from issuance of 8% Senior Notes - 218,143
Fund restricted cash (escrow account) - (232,066)
Merger finance costs on 8% Senior Notes - (6,257)
----------- ----------
Net cash used by financing activities (14,115) (8,309)
----------- ----------
Increase (Decrease) in cash and cash equivalents 58,221 (5,748)
Cash and cash equivalents, beginning of period 64,520 112,364
----------- ----------
Cash and cash equivalents, end of period $ 122,741 $ 106,616
=========== ==========
- -----------------------------------------------------------------------------------------------------------------
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for interest, excluding capitalized interest $ 10,742 $ 13,803
Cash paid during the period for income taxes 11,474 624
The accompanying notes are an integral part of these consolidated financial statements.
FRONTIER OIL CORPORATION AND SUBSIDIARIES
NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2004
(Unaudited)
1. Financial statement presentation
Financial statement presentation
The 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 (the “Cheyenne Refinery”) and El Dorado, Kansas (the “El Dorado Refinery”). The Company also owns FGI, LLC, an asphalt terminal and storage facility in Grand Island, Nebraska, whose activities are included in the consolidated financial statements since December 1, 2003 when the Company increased its ownership from 50% to 100%. Previously, the Company’s 50% interest in FGI, LLC was accounted for using the equity method of accounting. The Company also owns a 34.72% interest in a crude oil pipeline in Wyoming and a 50% interest in two crude oil tanks in Guernsey, Wyoming, both of which are accounted for as undivided interests. Each asset, liability, revenue and expense is reported on a proportionate gross basis. In addition, the equity method of accounting is utilized for the Company’s 25% interest in 8901 Hangar, Inc., a company which leases and operates a private airplane hangar. All of the operations of the Company are in the United States, with its marketing efforts focused in the Rocky Mountain region and the Plains States. The term “Rocky Mountain region,” refers to the states of Colorado, Wyoming, Montana and Utah, and the term “Plains States,” refers to the states of Kansas, Nebraska, Iowa, Missouri, North Dakota and South Dakota. The Company purchases 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. The Company believes that the disclosures contained herein 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/A for the year ended December 31, 2003 and the Company’s quarterly reports on Form 10-Q for the quarters ended March 31, 2004 and June 30, 2004.
Earnings per share
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 nine months ended September 30, 2003 because a loss was incurred. No adjustments to income are used in the calculation of earnings per share. The basic and diluted average shares outstanding are as follows:
Nine Months Ended Three Months Ended
September 30 September 30
2004 2003 2004 2003
---------- ---------- ---------- ----------
Basic 26,594,720 25,910,470 26,874,084 25,937,842
Diluted 27,298,715 25,910,470 27,444,618 26,956,658
The number of outstanding stock options that could potentially dilute EPS in future years but were not included in the computation of diluted EPS (because the exercise prices exceeded the average market prices for the periods) were 690,600 shares for the nine months and three months ended September 30, 2004 and 1,546,700 shares for the three months ended September 30, 2003.
New accounting pronouncements
In March 2004, the Financial Accounting Standards Board (“FASB”) issued an Exposure Draft for a Proposed Statement of Financial Accounting Standards, “Share Based Payment”, an amendment of FASB Statements No. 123 and 95. This statement originally would have required companies to recognize the fair value of stock options and other stock-based compensation to employees prospectively beginning with fiscal years ending after December 15, 2004; however, the FASB has recently amended the Exposure Draft to defer the effective date to fiscal periods beginning after June 15, 2005. This means that Frontier would be required to implement the proposed standard no later than the quarter beginning July 1, 2005. The Company currently measures stock-based compensation in accordance with Accounting Principles Board (“APB”) 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. No compensation cost for stock options was recognized in the consolidated statements of operations for the nine months or the three months ended September 30, 2004 and 2003. The Company is currently evaluating the various provisions of the Exposure Draft. If adopted by the FASB as proposed, the impact on the Company’s financial condition or results of operations will depend on the number and terms of stock options outstanding on the date of change, as well as future options granted. See Note 3 for the pro forma impact the fair value method would have had on the Company’s results of operations for the nine months and three months ended September 30, 2004 and 2003.
2. Schedule of major components of inventory
September 30, December 31,
2004 2003
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(in thousands)
Crude oil $ 63,501 $ 39,374
Unfinished products 70,801 31,240
Finished products 40,505 34,712
Process chemicals 3,717 5,175
Repairs and maintenance supplies and other 14,026 13,498
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$ 192,550 $ 123,999
============= =============
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 cost and associated freight and other costs. 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 (i) components of raw material, the associated raw material freight, and other costs and (ii) 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, supplies and process chemicals are recorded at the lower of average cost or market.
3. Stock-based compensation
Stock-based compensation is measured in accordance with 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 $915,000 and $1.0 million related to restricted stock awards were recognized for the nine months ended September 30, 2004 and 2003, respectively. Compensation costs of $266,000 and $377,000 related to restricted stock awards were recognized for the three months ended September 30, 2004 and 2003, respectively. As of September 30, 2004, there were 54,698 shares of unvested restricted stock outstanding, which represents the remaining shares from the 2002 grants, which will vest in March 2005. No grants were made under the Plan in 2003 or during the first nine months of 2004. During the nine months ended September 30, 2004, the Company received 48,443 shares ($901,000) of treasury stock from stock surrendered by employees to pay their withholding taxes on shares of restricted stock which vested during the first quarter.
The Company has a stock option plan which authorizes the granting of options to employees to purchase shares of the Company’s common stock. The plan through September 30, 2004 had reserved for issuance a total of 3,600,000 shares of common stock, of which 3,501,250 shares have been granted (2,169,350 shares remain outstanding) and 98,750 shares were available to be granted. Of the $6.7 million (945,075 shares) of common stock issued during the nine months ended September 30, 2004 under stock option plans, $4.1 million was funded by the Company receiving 215,599 shares of stock (now held as treasury stock) directly from employees in cashless stock option exercises. The Company also increased its treasury shares when it received 112,752 shares ($2.1 million) of stock surrendered by employees to pay their withholding taxes related to these stock option exercises. Options under the plan are granted at fair market value on the date of grant. No entries are made in the Company’s equity 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 and amortized over the vesting period pursuant to FASB Statement No. 123, the Company’s income or loss and EPS would have been the pro forma amounts listed in the following table for the nine months and three months ended September 30, 2004 and 2003:
Nine Months Ended Three Months Ended
September 30 September 30
2004 2003 2004 2003
---------- ---------- ----------- ----------
(in thousands, except per share amounts)
Net income (loss) as reported $ 69,525 $ (870) $ 23,792 $ 3,822
Deduct: Pro forma compensation
expense, net of tax 1,550 2,509 482 563
---------- ---------- ----------- ----------
Pro forma net income (loss) $ 67,975 $ (3,379) $ 23,310 $ 3,259
========== ========== =========== ==========
Basic Income (Loss) per Share:
As reported $ 2.61 $ (.03) $ .89 $ .15
Pro forma 2.56 (.13) .87 .13
Diluted Income (Loss) per Share:
As reported $ 2.55 $ (.03) $ .87 $ .14
Pro forma 2.49 (.13) .85 .12
The fair value of grants was estimated as of the date of grant using the Black-Scholes option pricing model. The pro forma compensation expense for the nine months and three months ended September 30, 2004 includes amortization for options granted in the years of 2001, 2002, 2003 and 2004. The pro forma compensation expense for the nine months and three months ended September 30, 2003 includes amortization for options granted in the years of 2000, 2001, 2002 and 2003. For the weighted-average assumptions used in the Black-Scholes option pricing model for grants made in 2003, 2002, 2001 and 2000, please refer to the Company’s annual reports on Form 10-K/A for the years ended December 31, 2003 and 2002. The weighted-average assumptions used in the Black-Scholes option pricing model for grants issued in 2004 are: risk-free interest rate of 2.97%, expected volatility of 47.80%, expected life of 5.0 years and 1.10% dividend yield.
4. Price risk management activities
The Company at times enters into commodity derivative contracts to manage its price exposure to inventory positions that are in excess of its base level of operating inventories, purchases of foreign crude oil, consumption of natural gas in the refining process, to fix margins on certain future production, or to fix differentials on crude oil. 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 whom the Company believes are creditworthy. The Company accounts for its commodity derivative contracts under the hedge (or deferral) method of accounting when the derivative contracts are designated as hedges for accounting purposes, or 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 “Raw material, freight and other costs” or “Refinery operating expenses, excluding depreciation” when the associated transactions are consummated. Gains and losses on transactions accounted for using mark-to-market accounting are reflected in “Other revenues” in each period.
Other revenues for the nine months ended September 30, 2004 included $11.9 million realized and unrealized net losses on derivative contracts accounted for using mark-to-market accounting. Other revenues for the three months ended September 30, 2004 included $6.6 million realized and unrealized net losses on derivative contracts accounted for using mark-to-market accounting.
At September 30, 2004, 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 included in “Other revenues” in the consolidated statements of operations:
| • |
Derivative contracts on 91,000 barrels of crude oil to hedge crude oil and
intermediate product inventory builds for both the Cheyenne and El Dorado
Refineries expected to be drawn down during the months of October and November
2004. These open contracts had total unrealized net losses at September 30, 2004
of approximately $293,000. During the nine months ended September 30, 2004, the
Company reported net losses of approximately $5.5 million on closed out
contracts to hedge crude oil and intermediate inventories.
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| • |
Derivative contracts on 336,000 barrels of crude oil to hedge normal butane
inventory for the El Dorado Refinery expected to be drawn down during the months
of October 2004 through early January 2005. These open contracts had total
unrealized net losses at September 30, 2004 of approximately $1.2 million.
During the nine months ended September 30, 2004, the Company reported net losses
of approximately $2.0 million on closed out contracts to hedge normal butane
inventory for the El Dorado Refinery.
|
During the nine months ended September 30, 2004, the Company utilized derivative contracts on barrels of crude oil to fix the heavy crude differential to the New York Mercantile Exchange light crude oil contract price for a portion of the committed purchases under the Company’s crude oil supply agreement with Baytex. During the nine months ended September 30, 2004, the Company recorded losses of nearly $2.6 million (included in “Other revenues”) on these contracts. No open positions remain at September 30, 2004 related to these contracts. The Company also utilized derivative contracts on barrels of crude oil to hedge crude oil inventories at the El Dorado Refinery and realized $327,000 in losses on these positions during the first quarter of 2004.
The Company had no open derivative contracts at September 30, 2004 that were being accounted for as hedges. The Company also had no derivative contracts, during the nine months ended September 30, 2004, that were designated and accounted for as hedges.
5. Environmental
The Company’s operations and many of its manufactured products 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 the Refineries during the next several years. The Environmental Protection Agency (“EPA”) recently embarked on a Petroleum Refining Initiative (“Initiative”) alleging industry-wide noncompliance with certain longstanding 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, Frontier does not know how or if the Initiative will affect the Company. The Company has, however, in recognition of the EPA’s reinterpretation of certain regulatory requirements associated with the Initiative, determined that over the next three years, expenditures totaling approximately $10 million may be necessary to further reduce emissions from the Refineries’ flare systems. Both the Kansas Department of Health and Environment (“KDHE”) and the Wyoming Department of Environmental Quality (“WDEQ”) have expressed their preference to enter into consent decrees with the Company to settle these and certain other compliance matters. The provisions of a KDHE Order have not yet been proposed; however, Region VII of the EPA has informed the State of Kansas (“State”) and the Company that requirements for reductions in emissions from the El Dorado Refinery Fluid Catalytic Cracking Unit (“FCCU”) must also be included in any settlement with the State if the Company wants protection from a subsequent EPA enforcement action under the Initiative. The Company is currently evaluating interim and final FCCU emission control options. The WDEQ has indicated its willingness to accept a monetary penalty of $120,000 along with the completion of an agreed upon Capital Supplemental Environmental Project estimated to cost $535,000 to satisfy the reduction of flare system emissions, an earlier notice of violation regarding excess emissions from the Cheyenne Refinery’s crude unit heaters, resolution of the 1992 Odor Consent Decree and two recent odor violations associated with the startup of the Cheyenne Refinery’s new gasoline desulfurization equipment. The WDEQ Consent Decree formalizing this agreement is now being prepared. During the first quarter of 2004, the Company decreased the previously estimated penalty accrual of $317,000 recorded as of December 31, 2003 down to $120,000. This $197,000 reduction is reflected as a reduction of “Refinery operating expenses, excluding depreciation” on the consolidated statement of operations for the nine months ended September 30, 2004.
On December 21, 1999, the EPA promulgated national regulations limiting the amount of sulfur that will be allowed in gasoline. The new regulations require the phase-in of gasoline sulfur standards, which began January 1, 2004 and continues through 2008, with special provisions for small business refiners. Because the Company qualifies as a small business refiner, Frontier has elected to extend Frontier’s small refinery interim gasoline sulfur standards at each of the Refineries until 2011 and to comply with the highway diesel sulfur standard by June 2006 (see discussion below). The Cheyenne Refinery has spent approximately $28.2 million to complete the project to meet the interim gasoline sulfur standard, which was required by January 1, 2004. The remaining $7.0 million estimated cost to meet the additional standard for the Cheyenne Refinery is expected to be incurred in 2009 and 2010. The total capital expenditures estimated as of September 30, 2004 for the El Dorado Refinery to achieve the final gasoline sulfur standard are approximately $15 million, which are expected to be incurred between 2006 and 2009. The Company’s approach to achieve the gasoline sulfur standard at the El Dorado Refinery has been revised from building a new unit to the modification of existing equipment, thus reducing the cost from the original estimate of $44 million.
The EPA has promulgated regulations that will limit the sulfur content of highway diesel fuel beginning in 2006. As a small business refiner, Frontier has elected to comply with the highway diesel sulfur standard by June 2006 and extend Frontier’s small refiner interim gasoline sulfur standards at each of the Refineries until 2011. As of September 30, 2004, capital costs for diesel desulfurization are estimated to be approximately $13.5 million for the Cheyenne Refinery and approximately $100 million for the El Dorado Refinery. Approximately $500,000 of the Cheyenne Refinery expenditures are expected to be incurred in 2004, with none incurred as of September 30, 2004. The remaining expenditures will be incurred in 2005 and 2006. Approximately $11.0 million of the El Dorado Refinery expenditures are expected to be incurred by the end of 2004, with only $933,000 incurred through September 30, 2004. The remaining expenditures will be incurred in 2005 and 2006. The precise timing and amount of these expenditures will likely vary as detailed engineering to achieve the desulfurization is developed. It may be necessary for the Company to pursue external financing to fund a portion of these capital expenditures beginning in 2005 or 2006. Certain provisions of recent federal legislation (HR 4520 – “The American Jobs Creation Act of 2004”) should benefit Frontier by allowing the Company an accelerated depreciation deduction of 75% of these qualified capital costs in the years incurred and by providing a $0.05 per gallon credit on compliant diesel fuel up to an amount equal to the remaining 25% of these qualified capital costs for federal income tax purposes.
On June 29, 2004, the EPA promulgated regulations designed to reduce emissions from the combustion of diesel fuel in non-road applications such as mining, agriculture, locomotives and marine vessels. The Company currently participates in this market through the manufacture and sale of approximately 6,000 barrels per day of non-road diesel fuel from our El Dorado Refinery. The new regulations will, in part, require refiners to reduce the sulfur content of non-road diesel fuel from 5,000 parts per million (“ppm”) to 500 ppm in 2007 and further to 15 ppm in 2010 for all uses but locomotive and marine. Diesel fuel used in locomotives and marine operations will be required to meet the 15 ppm sulfur standard in 2012. Small refiners, such as Frontier, will be allowed to either postpone the new sulfur limits or, if the small refiner chooses to meet the new limit on the national schedule, to increase their gasoline sulfur limits by 20%. Frontier intends to desulfurize all of its diesel fuel, including non-road, to the 15 ppm sulfur standard by 2006. The new regulation also clarifies that EPA-approved small business refiners will be allowed to exceed both the small refiner maximum capacity and/or employee criteria through merger with or acquisition of another approved small business refiner without loss of small refiner regulatory status.
As is the case with all companies engaged in similar industries, the Company faces potential exposure from future claims and lawsuits involving environmental matters. The matters include soil and water contamination, air pollution, personal injury and property damage allegedly caused by substances that the Company may have manufactured, handled, used, released or disposed.
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 that may have been impacted by past operational activities. Prior to this agreement, the Company addressed tasks required under a consent decree entered by the Wyoming State District Court on November 28, 1984 and involving the State of Wyoming, the WDEQ and the predecessor owners of the Cheyenne Refinery. This action primarily addressed the threat of groundwater and surface water contamination at the Cheyenne Refinery. As a result of these investigative efforts, 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. In addition, the Company estimates that an ongoing groundwater remediation program averaging $150,000 to $200,000 in annual operating and maintenance costs will be required for approximately ten more years. As of September 30, 2004, the Company has a reserve of $1.5 million in environmental liabilities reflecting the estimated present value of these expenditures. The EPA also issued an administrative consent order with respect to the Cheyenne Refinery on September 24, 1990 pursuant to the Resource Conservation and Recovery Act. Among other things, this order required a technical investigation of the Cheyenne Refinery to determine if certain areas had been adversely impacted by past operational activities. Based upon the results of the investigation, additional remedial action could be required by a subsequent administrative order or permit.
In accordance with permits issued by the State of Wyoming under the federal National Pollutant Discharge Elimination System (“NPDES”), the Cheyenne Refinery is permitted to discharge its treated wastewater to either of two receiving waterways: a creek adjacent to the Refinery or a normally dry ravine called “Porter Draw”. Certain landowners downstream of the Refinery’s permitted discharge to Porter Draw expressed their unwillingness to continue to accommodate this wastewater flow by appealing the Company’s discharge permit and by giving notice of possible legal action. In response, the Company arranged to deliver its treated wastewater to the City of Cheyenne (“City”) municipal treatment plant for additional treatment and release as an alternative to continuing discharge to the ravine and has entered into settlements with the landowners. To initiate this wastewater treatment service, Frontier will pay the City a $1.6 million development fee (reflected in “Other Intangible Assets”), which will be paid in equal installments over five years, with the first payment having been made in July 2004. In addition, the Refinery will pay the City $2.00 per 1,000 gallons of wastewater treated.
El Dorado Refinery. The El Dorado Refinery is subject to a 1988 consent order with the 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. More specifically, the Refinery must continue to operate the hydrocarbon recovery well systems and containment barriers at the site and conduct sampling from monitoring wells and surface water stations. Quarterly and annual reports must also be submitted to the KDHE. 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. Subject to the terms of the purchase and sale agreement for the El Dorado Refinery entered into between the Company and Equilon Enterprises LLC (now known as Shell Oil Products (“Shell”)), Shell is responsible for the costs of continued compliance with this order.
The most recent NPDES permit issued to the El Dorado Refinery requires, in part, the preparation and submission 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 is responsible for the first $2 million of any required wastewater treatment system upgrades. If required system upgrade costs exceed this amount, Shell and Frontier share, based on a sliding scale percentage, up to another $3 million in upgrade costs. In addition to Shell’s obligation for the wastewater treatment system upgrade, subject to the terms of the purchase and sale agreement, Shell is also responsible for up to $5 million in costs relating to safety, health and environmental conditions that arise after the sales transaction closed in November 1999 because of Shell’s prior operation of the El Dorado Refinery that are not covered under a ten-year insurance policy. This insurance policy has $25 million of coverage through November 17, 2009 for environmental liabilities with a $500,000 deductible and will reimburse Frontier for losses related to certain conditions existing prior to the Company’s 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. In accordance with the purchase and sale agreement, Shell agreed during the third quarter of 2004 to reimburse the Company for its share (approximately $450,000) of the approximately $750,000 of costs incurred by the Company during work done between 2001 and 2003 to identify and remedy wastewater effluent toxicity concerns.
6. Litigation
Beverly Hills Lawsuits. 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 Unified School District and the City of Beverly Hills on behalf of former students, school employees, area residents and others alleging that emissions from the oil field or the production facilities caused cancers or various other health problems in those individuals. Wainoco Oil & Gas Company and Frontier have been named in six such suits: Moss et al. v. Veneco, Inc. et al., filed in June 2003; Ibraham et al. v. City of Beverly Hills et al., filed in July 2003; Yeshoua et al. v. Veneco, Inc. et al., filed in August 2003; Jacobs v. Wainoco Oil & Gas Company et al., filed in December 2003; Bussel et al. v. Veneco, Inc. et al., filed in January 2004; and Steiner et al. v. Venoco Inc. et al, filed in May 2004. Other defendants in these lawsuits include the Beverly Hills Unified School District, the City of Beverly Hills, ten other oil and gas companies, two additional companies involved in owning or operating a power plant adjacent to the Beverly Hills High School and three of their related parent companies. The lawsuits include claims for personal injury, wrongful death, loss of consortium and/or fear of contracting diseases, and also ask for punitive damages. No dollar amounts of damages have been specified in any of the lawsuits. The six pending lawsuits have been related to one another and have been transferred to a judge on the complex civil litigation panel in the Superior Court of the State of California for the County of Los Angeles. A case management order has been entered in the case pursuant to which 12 plaintiffs have been selected as the initial group of plaintiffs to go to trial, discovery has commenced and a preliminary trial date has been set for July 25, 2005.
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 anyone, including former Beverly Hills high school students, school employees or area residents. Nevertheless, as a matter of prudent risk management, Frontier purchased insurance in 2003 from an insurance company with an A.M. Best rating of A++ (Superior) covering the existing claims described above and any similar claims for bodily injury or property damage asserted during the five-year period following the policy’s September 30, 2003 commencement date. The claims are covered, whether asserted directly against the insured parties or as a result of contractual indemnity. The policy covers defense costs and any payments made to claimants, up to an aggregate limit of $120 million, including coinsurance by Frontier of up to $3.9 million of the coverage between $40 million and $120 million. In October 2003, the Company paid $6.25 million to the insurance company (which included an indemnity premium of $5.75 million and a $500,000 administration fee) and also funded with the insurance company a commutation account of approximately $19.5 million, from which the insurance company is funding the first costs under the policy including, but not limited to, the costs of defense of the claims. As of September 30, 2004, the commutation account balance was approximately $17.3 million. The Company also paid $772,500 to the State of California for surplus line tax on the premium in 2003, of which $600,000 was refunded. Frontier has the right to terminate the policy at any time after the first year and, prior to September 30, 2008, receive a refund of up to $4.3 million of the premium (which dollar amount declines over time) plus any unspent balance in the commutation account plus accumulated interest. While the policy is in effect, the insurance company will manage the defense of the claims. The Company is also seeking coverage with respect to the Beverly Hills, California claims from the insurance companies that provided policies to Frontier during the 1985 to 1995 period.
Frontier believes that neither the claims that have been made, the six pending lawsuits, nor other 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 material adverse effect upon Frontier.
Holly Lawsuit. On August 20, 2003, Frontier announced that Holly Corporation (“Holly”) had advised the Company that Holly was not willing to proceed with the merger agreement previously announced on March 31, 2003 on the agreed terms. As a result, Frontier filed suit for damages in the Delaware Court of Chancery. On September 2, 2003, Holly filed an answer and counterclaims, denying the Company’s claims, asserting that Frontier repudiated the merger agreement by filing the Delaware lawsuit, and claiming among other things that the Beverly Hills, California litigation caused the Company to be in breach of its representations and warranties in the merger agreement. Frontier has denied all of Holly’s counterclaims. Trial on the suit and Holly’s counterclaims concluded on March 5, 2004. Oral arguments were held on May 4, 2004, and the Company is awaiting a decision. Frontier believes that the counterclaims filed against it by Holly will not result in any material liability or have any material adverse effect upon Frontier.
MTBE Concentration Lawsuits. Although Frontier has never manufactured MTBE nor provided MTBE blended product to the Kansas marketplace, the El Dorado Refinery (Frontier El Dorado Refining Company) has recently been named as one of fifty-two defendants in four lawsuits brought on behalf of the City of Dodge City, Kansas, the Chisholm Creek Utility Authority, the City of Bel Aire, Kansas, the County of Sedgwick Water Authority and the City of Park City, Kansas alleging unspecified damages for contamination of groundwater/public water wells by MTBE and tertiary butyl alcohol (“TBA”), a degradation product of MTBE. One element of the damage claims entails the alleged need for a wellfield vulnerability study at a cost in excess of $75,000. Plaintiffs contend that the defendants manufactured or otherwise put MTBE into the stream of interstate commerce. The causes of action stated include strict liability for a defective product or design, strict liability for failure to warn, negligence, public nuisance, private nuisance, trespass, and civil conspiracy. Because Frontier has neither manufactured MTBE nor provided MTBE blended product to the Kansas marketplace, the Company believes that any potential liability in this matter is negligible.
Other. We are also involved in various lawsuits which are incidental to our business. In management's opinion, the adverse determination of such lawsuits would not have a material adverse effect on our liquidity, financial position or results of operations.
7. Other Contingencies - El Dorado Earn-out Payments
On November 16, 1999, Frontier acquired the 110,000 barrels per day El Dorado Refinery from Equilon Enterprises LLC, now known as Shell. Under the provisions of the purchase and sale agreement, the Company is required to make contingent earn-out payments for each of the years 2000 through 2007 equal to one-half of the excess over $60 million per year, up to $7.5 million, of the El Dorado Refinery’s annual revenues less its material costs and operating costs, other than depreciation. The total amount of these contingent payments is capped at $40 million. Any contingency payment will be recorded when determinable at each year-end as an additional acquisition cost. No contingent earn-out payment was required based on 2003, 2002 or 2000 results. A contingent earn-out payment of $7.5 million was required based on 2001 results and was accrued as of December 31, 2001 and paid in early 2002. It will not be known until year end if a contingent earn-out payment, based on 2004 results, will be required in early 2005. However, based on the results of operations for the nine months ended September 30, 2004, it is probable, but not estimatable, that a payment may be required.
8. Cheyenne Refinery Fire
On January 19, 2004, a fire occurred in the furnaces of the coking unit at the Cheyenne Refinery. The coker was out of service for approximately one month. Although the coker has been returned to service, some capital work is still ongoing; thus, final capital costs resulting from the fire are not yet known. As of September 30, 2004, the Company had received $3.5 million under its insurance policy, which represents a partial settlement. This amount exceeds expenses recorded to date by $594,000, resulting in the “Gain from involuntary conversion of assets” (recorded in June 2004) and included in the consolidated statement of operations for the nine months ended September 30, 2004. Expenses recorded to date include $1.8 million in clean-up costs and $1.1 million of net property, plant and equipment written-off ($2.1 million, net of $945,000 accumulated depreciation) due to the fire. The Company has incurred $7.8 million in capital work through September 30, 2004 to replace the coker furnaces. Once final capital costs are determined, additional amounts are expected to be recovered through the Company’s insurance coverage.
9. Subsequent Events - Tender Offer and Redemption of 11¾% Senior Notes and Issuance of 6.625% Senior Notes
On October 1, 2004, Frontier Oil Corporation (“FOC”) issued $150 million principal amount of 6.625% Senior Notes (the “Notes”) due 2011. The Notes, which mature on October 1, 2011, were issued at par, and FOC received net proceeds (after underwriting fees) of $147.2 million. Interest is paid semi-annually. The Notes are redeemable, at the option of FOC, at 103.313% after October 1, 2007, declining to 100% in 2010. Prior to October 1, 2007, FOC may at its option redeem the Notes at a defined make-whole amount, plus accrued and unpaid interest. FOC used a portion of the net proceeds from this offering to fund a tender offer and consent solicitation for $64.9 million principal of its 11¾% Senior Notes in October 2004 and included payment of a premium of $4.2 million and payment of accrued interest to date of $2.9 million. FOC intends to redeem in November 2004 the remaining $105.6 million outstanding principal of its 11¾% Senior Notes, including payment of a $6.2 million premium and payment of accrued interest to date of another $6.2 million, with the remaining proceeds of the offering, together with other available funds.
Frontier Holdings Inc. and its subsidiaries (“FHI”) are full and unconditional guarantors of FOC’s 6.625% Senior Notes. Presented on the following pages are the Company’s consolidating balance sheets, statements of operations, and cash flows as required by Rule 3-10 of Regulation S-X of the Securities Exchange Act of 1934, as amended. As specified in Rule 3-10, the condensed consolidating balance sheets, statement of operations, and cash flows presented below meet the requirements for financial statements of the issuer and each guarantor of the notes since guarantors are all direct or indirect wholly-owned subsidiaries of Frontier, and all of the guarantees are full and unconditional on a joint and several basis. The Company files a consolidated U.S. federal income tax return and consolidated state income tax returns in the majority of states in which it does business. Each subsidiary calculates its income tax provisions on a separate company basis, which are eliminated in the consolidation process.
FRONTIER OIL CORPORATION
Consolidating Statement of Operations
For the Nine Months Ended September 30, 2004
(unaudited, in thousands)
FHI Other
FOC (Guarantor Non-Guarantor
(Parent) Subsidiaries) Subsidiaries Eliminations Consolidated
--------------------------------------------------------------------------
REVENUE:
Refined products $ - $ 2,069,785 $ - $ - $ 2,069,785
Other - (11,516) 43 - (11,473)
Equity in earnings of subsidiaries 141,563 - - (141,563) -
------------ -------------- --------------- --------------- -------------
TOTAL REVENUES 141,563 2,058,269 43 (141,563) 2,058,312
------------ -------------- --------------- --------------- -------------
COSTS AND EXPENSES:
Raw material, freight and other costs - 1,719,851 - - 1,719,851
Refinery operating expenses, excluding
depreciation - 162,124 - - 162,124
Selling and general expenses, excluding
depreciation 11,335 9,586 - - 20,921
Merger termination and legal costs 3,820 - - - 3,820
Depreciation and amortization 59 24,285 - (416) 23,928
------------ -------------- --------------- --------------- -------------
15,214 1,915,846 - (416) 1,930,644
------------ -------------- --------------- --------------- -------------
OPERATING INCOME 126,349 142,423 43 (141,147) 127,668
------------ -------------- --------------- --------------- -------------
Interest expense and other financing costs 15,619 1,999 - - 17,618
Interest income (805) (85) - - (890)
Gain on involuntary conversion of assets - (594) - - (594)
------------ -------------- --------------- --------------- -------------
14,814 1,320 - - 16,134
------------ -------------- --------------- --------------- -------------
INCOME BEFORE INCOME TAXES 111,535 141,103 43 (141,147) 111,534
Provision for income taxes 42,010 53,693 - (53,694) 42,009
------------ -------------- --------------- --------------- -------------
NET INCOME $ 69,525 $ 87,410 $ 43 $ (87,453) $ 69,525
============ ============== =============== =============== =============
FRONTIER OIL CORPORATION
Consolidating Statement of Operations
For the Three Months Ended September 30, 2004
(unaudited, in thousands)
FHI Other
FOC (Guarantor Non-Guarantor
(Parent) Subsidiaries) Subsidiaries Eliminations Consolidated
-------------------------------------------------------------------------
REVENUE:
Refined products $ - $ 791,613 $ - $ - $ 791,613
Other 2 (6,558) 19 - (6,537)
Equity in earnings of subsidiaries 45,774 - - (45,774) -
------------- ------------- ------------ ------------- ------------
TOTAL REVENUES 45,776 785,055 19 (45,774) 785,076
------------- ------------- ------------ ------------- ------------
COSTS AND EXPENSES:
Raw material, freight and other costs - 671,400 - - 671,400
Refinery operating expenses, excluding
depreciation - 55,721 - - 55,721
Selling and general expenses, excluding
depreciation 3,588 3,487 - - 7,075
Merger termination and legal costs 157 - - - 157
Depreciation and amortization 19 8,285 - (138) 8,166
------------- ------------- ------------ ------------- ------------
3,764 738,893 - (138) 742,519
------------- ------------- ------------ ------------- ------------
OPERATING INCOME 42,012 46,162 19 (45,636) 42,557
------------- ------------- ------------ ------------- ------------
Interest expense and other financing costs 5,213 600 - - 5,813
Interest income (430) (55) - - (485)
------------- ------------- ------------ ------------- ------------
4,783 545 - - 5,328
------------- ------------- ------------ ------------- ------------
INCOME BEFORE INCOME TAXES 37,229 45,617 19 (45,636) 37,229
Provision for income taxes 13,437 17,113 - (17,113) 13,437
------------- ------------- ------------ ------------- ------------
NET INCOME $ 23,792 $ 28,504 $ 19 $ (28,523) $ 23,792
============= ============= ============ ============= ============
FRONTIER OIL CORPORATION
Consolidating Balance Sheet
As of September 30, 2004
(unaudited, in thousands)
FHI Other
FOC (Guarantor Non-Guarantor
(Parent) Subsidiaries) Subsidiaries Eliminations Consolidated
--------------------------------------------------------------------------
ASSETS
Current Assets:
Cash and cash equivalents $ 116,688 $ 6,053 $ - $ - $ 122,741
Trade receivables - 132,226 - - 132,226
Other receivables 5,310 872 - - 6,182
Receivable from affiliated companies - 383 80 (463) -
Inventory of crude oil, products and other - 192,550 - - 192,550
Deferred tax assets 7,165 7,081 - (7,081) 7,165
Other current assets 134 851 - - 985
------------- ------------- ------------- ------------- -------------
TOTAL CURRENT ASSETS 129,297 340,016 80 (7,544) 461,849
------------- ------------- ------------- ------------- -------------
Property, Plant and Equipment, at cost:
Refineries, terminal equipment and pipeline - 526,808 - (11,053) 515,755
Furniture, fixtures and other equipment 1,112 6,921 - - 8,033
------------- ------------- ------------- ------------- -------------
1,112 533,729 - (11,053) 523,788
Less - Accumulated Depreciation 925 202,483 - (7,266) 196,142
------------- ------------- ------------- ------------- -------------
187 331,246 - (3,787) 327,646
Deferred Financing Costs, net 3,070 494 - - 3,564
Commutation Account 17,334 - - - 17,334
Prepaid Insurance 4,845 - - - 4,845
Other Assets 4,811 - - - 4,811
Other Intangible Assets, net - 1,553 - - 1,553
Investment in Subsidiaries 312,979 - - (312,979) -
------------- ------------- ------------- ------------- -------------
TOTAL ASSETS $ 472,523 $ 673,309 $ 80 $ (324,310) $ 821,602
============= ============= ============= ============= =============
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Accounts payable $ 1,552 $ 248,199 $ - $ - $ 249,751
Revolving credit facility - 36,250 - - 36,250
Accrued turnaround cost - 15,996 - - 15,996
Accrued liabilities and other 10,450 12,306 269 - 23,025
Accrued interest 7,510 2 - - 7,512
------------- ------------- ------------- ------------- -------------
TOTAL CURRENT LIABILITIES 19,512 312,753 269 - 332,534
------------- ------------- ------------- ------------- -------------
Long-Term Debt 168,853 - - - 168,853
Long-Term Accrued and Other Liabilities - 36,317 - - 36,317
Deferred Credits and Other 4,201 203 - - 4,404
Deferred Income Taxes 39,617 47,027 - (47,027) 39,617
Payable to Affiliated Companies 463 4,944 - (5,407) -
Shareholders' Equity:
Common stock 57,599 1 12,251 (12,252) 57,599
Paid-in capital 117,907 311,085 262,793 (573,878) 117,907
Retained earnings 111,353 (38,097) (275,233) 314,827 112,850
Accumulated other comprehensive income (loss) 573 (924) - (573) (924)
Treasury stock (47,024) - - - (47,024)
Deferred employee compensation (531) - - - (531)
------------- ------------- ------------- ------------- -------------
TOTAL SHAREHOLDERS' EQUITY 239,877 272,065 (189) (271,876) 239,877
------------- ------------- ------------- ------------- -------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 472,523 $ 673,309 $ 80 $ (324,310) $ 821,602
============= ============= ============= ============= =============
FRONTIER OIL CORPORATION
Consolidating Statement of Cash Flows
For the Nine Months Ended September 30, 2004
(unaudited, in thousands)
FHI Other
FOC (Guarantor Non-Guarantor
(Parent) Subsidiaries) Subsidiaries Eliminations Consolidated
------------------------------------------------------------------------
OPERATING ACTIVITIES
Net income $ 69,525 $ 87,410 $ 43 $ (87,453) $ 69,525
Equity in earnings of subsidiaries (141,563) - - 141,563 -
Depreciation and amortization 59 24,285 - (416) 23,928
Deferred income taxes 26,363 53,694 - (53,694) 26,363
Amortization of deferred finance costs and discount 586 216 - - 802
Deferred employee compensation amortization 915 - - - 915
Amortization of long-term prepaid insurance 1,148 - - - 1,148
Decrease in commutation account 2,216 - - - 2,216
Change in deferred credits and other 564 (645) - - (81)
Net assets written-off in involuntary conversion
of assets - 1,126 - - 1,126
Changes in working capital from operations 9,381 (28,144) (3) - (18,766)
------------- ------------- --------------- ------------ ---------------
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES (30,806) 137,942 40 - 107,176
------------- ------------- --------------- ------------ ---------------
INVESTING ACTIVITIES
Additions to property, plant and equipment and
other (1) (34,839) - - (34,840)
------------- ------------- --------------- ------------ ---------------
NET CASH USED IN INVESTING ACTIVITIES (1) (34,839) - - (34,840)
------------- ------------- --------------- ------------ ---------------
FINANCING ACTIVITIES
Revolving credit facility repayments, net - (9,500) - - (9,500)
Deferred finance costs (193) - - - (193)
Issuance of common stock 2,591 - - - 2,591
Purchase of treasury stock (3,029) - - - (3,029)
Dividends (4,051) - - - (4,051)
Other - 67 - - 67
Intercompany transactions 92,331 (92,291) (40) - -
------------- ------------- --------------- ------------ ---------------
NET CASH PROVIDED BY (USED IN)
FINANCING ACTIVITIES 87,649 (101,724) (40) - (14,115)
------------- ------------- --------------- ------------ ---------------
Increase in cash and cash equivalents 56,842 1,379 - - 58,221
Cash and cash equivalents, beginning of period 59,846 4,674 - - 64,520
------------- ------------- --------------- ------------ ---------------
Cash and cash equivalents, end of period $ 116,688 $ 6,053 $ - $ - $ 122,741
============= ============= =============== ============ ===============
FRONTIER OIL CORPORATION
Consolidating Statement of Operations
For the Nine Months Ended September 30, 2003
(unaudited, in thousands)
FHI Other
FOC (Guarantor Non-Guarantor
(Parent) Subsidiaries) Subsidiaries Eliminations Consolidated
------------------------------------------------------------------------
REVENUE:
Refined products $ - $1,625,441 $ - $ - $1,625,441
Other (19) 2,099 39 - 2,119
Equity in earnings of subsidiaries 27,914 - - (27,914) -
------------- ------------- ------------- ------------- ------------
TOTAL REVENUES 27,895 1,627,540 39 (27,914) 1,627,560
------------- ------------- ------------- ------------- ------------
COSTS AND EXPENSES:
Raw material, freight and other costs - 1,401,401 - - 1,401,401
Refinery operating expenses, excluding
depreciation - 149,059 - - 149,059
Selling and general expenses, excluding
depreciation 5,748 9,178 - - 14,926
Merger termination and legal costs 3,953 - - - 3,953
Depreciation and amortization 88 21,515 - (416) 21,187
------------- ------------- ------------- ------------- ------------
9,789 1,581,153 - (416) 1,590,526
------------- ------------- ------------- ------------- ------------
OPERATING INCOME 18,106 46,387 39 (27,498) 37,034
------------- ------------- ------------- ------------- ------------
Interest expense and other financing costs 19,326 1,423 - - 20,749
Interest income (761) (146) - - (907)
Merger financing termination costs, net - - 17,632 - 17,632
------------- ------------- ------------- ------------- ------------
18,565 1,277 17,632 - 37,474
------------- ------------- ------------- ------------- ------------
INCOME (LOSS) BEFORE INCOME TAXES (459) 45,110 (17,593) (27,498) (440)
Provision for income taxes 411 17,283 - (17,264) 430
------------- ------------- ------------- ------------- ------------
NET INCOME (LOSS) $ (870) $ 27,827 $ (17,593) $ (10,234) $ (870)
============= ============= ============= ============= ============
FRONTIER OIL CORPORATION
Consolidating Statement of Operations
For the Three Months Ended September 30, 2003
(unaudited, in thousands)
FHI Other
FOC (Guarantor Non-Guarantor
(Parent) Subsidiaries) Subsidiaries Eliminations Consolidated
--------------------------------------------------------------------------
REVENUE:
Refined products $ - $ 594,292 $ - $ - $ 594,292
Other (32) 489 14 - 471
Equity in earnings of subsidiaries 18,734 - - (18,734) -
------------- ------------- ------------- ------------- -------------
TOTAL REVENUES 18,702 594,781 14 (18,734) 594,763
------------- ------------- ------------- ------------- -------------
COSTS AND EXPENSES:
Raw material, freight and other costs - 502,723 - - 502,723
Refinery operating expenses, excluding
depreciation - 48,495 - - 48,495
Selling and general expenses, excluding
depreciation 2,041 3,091 - - 5,132
Merger termination and legal costs 3,953 - - 3,953
Depreciation and amortization 26 7,268 - (138) 7,156
------------- ------------- ------------- ------------- -------------
6,020 561,577 - (138) 567,459
------------- ------------- ------------- ------------- -------------
OPERATING INCOME 12,682 33,204 14 (18,596) 27,304
------------- ------------- ------------- ------------- -------------
Interest expense and other financing costs 6,150 440 - - 6,590
Interest income (230) (30) - - (260)
Merger financing termination costs, net - - 14,212 - 14,212
------------- ------------- ------------- ------------- -------------
5,920 410 14,212 - 20,542
------------- ------------- ------------- ------------- -------------
INCOME (LOSS) BEFORE INCOME TAXES 6,762 32,794 (14,198) (18,596) 6,762
Provision for income taxes 2,940 12,522 - (12,522) 2,940
------------- ------------- ------------- ------------- -------------
NET INCOME (LOSS) $ 3,822 $ 20,272 $ (14,198) $ (6,074) $ 3,822
============= ============= ============= ============= =============
FRONTIER OIL CORPORATION
Consolidating Balance Sheet
As of December 31, 2003
(unaudited, in thousands)
FHI Other
FOC (Guarantor Non-Guarantor
(Parent) Subsidiaries) Subsidiaries Eliminations Consolidated
-------------------------------------------------------------------------
ASSETS
Current Assets:
Cash and cash equivalents $ 59,846 $ 4,674 $ - $ - $ 64,520
Trade receivables - 86,519 - - 86,519
Other receivables 710 1,124 - - 1,834
Receivable from affiliated companies - 692 40 (732) -
Inventory of crude oil, products and other - 123,999 - - 123,999
Deferred tax assets 5,967 5,201 - (5,201) 5,967
Other current assets 68 1,906 - - 1,974
------------- ------------- ------------- ------------- -------------
TOTAL CURRENT ASSETS 66,591 224,115 40 (5,933) 284,813
------------- ------------- ------------- ------------- -------------
Property, Plant and Equipment, at cost:
Refineries, terminal equipment and pipeline - 500,555 - (11,053) 489,502
Furniture, fixtures and other equipment 1,111 5,031 - - 6,142
------------- ------------- ------------- ------------- -------------
1,111 505,586 - (11,053) 495,644
Less - Accumulated Depreciation 866 179,180 (6,850) 173,196
------------- ------------- ------------- ------------- -------------
245 326,406 - (4,203) 322,448
Deferred Financing Costs, net 3,299 710 - - 4,009
Commutation Account 19,550 - - - 19,550
Prepaid Insurance 6,593 - - - 6,593
Other Assets 4,884 - - - 4,884
Investment in Subsidiaries 264,016 - - (264,016) -
------------- ------------- ------------- ------------- -------------
TOTAL ASSETS $ 365,178 $ 551,231 $ 40 $ (274,152) $ 642,297
============= ============= ============= ============= =============
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Accounts payable $ 1,736 $ 175,496 $ 3 $ - $ 177,235
Revolving credit facility - 45,750 - - 45,750
Accrued turnaround cost - 10,412 - - 10,412
Accrued liabilities and other 1,587 8,426 269 - 10,282
Accrued interest 2,504 9 - - 2,513
------------- ------------- ------------- ------------- -------------
TOTAL CURRENT LIABILITIES 5,827 240,093 272 - 246,192
------------- ------------- ------------- ------------- -------------
Long-Term Debt 168,689 - - - 168,689
Long-Term Accrued and Other Liabilities - 36,954 - - 36,954
Deferred Credits and Other 3,723 532 - - 4,255
Deferred Income Taxes 16,930 38,183 - (38,183) 16,930
Payable to Affiliated Companies 732 3,271 - (4,003) -
Shareholders' Equity:
Common stock 57,504 1 12,251 (12,252) 57,504
Paid-in capital 106,443 310,828 280,832 (591,660) 106,443
Retained earnings 46,117 (77,707) (293,315) 372,519 47,614
Accumulated other comprehensive income (loss) 573 (924) - (573) (924)
Treasury stock (39,914) - - - (39,914)
Deferred employee compensation (1,446) - - - (1,446)
------------- ------------- ------------- ------------- -------------
TOTAL SHAREHOLDERS' EQUITY 169,277 232,198 (232) (231,966) 169,277
------------- ------------- ------------- ------------- -------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 365,178 $ 551,231 $ 40 $ (274,152) $ 642,297
============= ============= ============= ============= =============
FRONTIER OIL CORPORATION
Consolidating Statement of Cash Flows
For the Nine Months Ended September 30, 2003
(unaudited, in thousands)
FHI Other
FOC (Guarantor Non-Guarantor
(Parent) Subsidiaries)Subsidiaries Eliminations Consolidated
----------------------------------------------------------------------
OPERATING ACTIVITIES
Net income (loss) $ (870) $ 27,827 $ (17,593) $ (10,234) $ (870)
Equity in earnings of subsidiaries 27,914 - - (27,914) -
Depreciation and amortization 88 21,515 - (416) 21,187
Deferred income taxes 131 17,264 - (17,264) 131
Merger finance costs and discount on 8% Senior Notes - - 8,114 - 8,114
Amortization of deferred finance costs and discount 1,584 249 - - 1,833
Deferred employee compensation amortization 1,009 - - - 1,009
Net loss on sale of assets 232 (43) - - 189
Change in deferred credits and other 48 (652) - - (604)
Changes in working capital from operations 5,569 (17,323) 10,082 - (1,672)
--------------- ------------ ------------ ------------- ------------
NET CASH PROVIDED BY OPERATING ACTIVITIES 35,705 48,837 603 (55,828) 29,317
--------------- ------------ ------------ ------------- ------------
INVESTING ACTIVITIES
Additions to property, plant and equipment and other (45) (26,981) - - (27,026)
Proceeds from sale of assets 240 64 - - 304
Other investments (34) - - - (34)
--------------- ------------ ------------ ------------- ------------
NET CASH PROVIDED BY (USED IN)
INVESTING ACTIVITIES 161 (26,917) - - (26,756)
--------------- ------------ ------------ ------------- ------------
FINANCING ACTIVITIES
Revolving credit facility borrowings, net - 16,750 - - 16,750
Deferred finance costs - (877) - - (877)
Issuance of common stock 316 - - - 316
Purchase of treasury stock (428) - - - (428)
Dividends (3,890) - - - (3,890)
Proceeds from issuance of 8% Senior Notes - - 218,143 - 218,143
Fund restricted cash (escrow account) - - (232,066) - (232,066)
Merger finance costs on 8% Senior Notes - - (6,257) - (6,257)
Intercompany transactions 20,789 (40,367) 19,578 - -
--------------- ------------ ------------ ------------- ------------
NET CASH PROVIDED BY (USED IN)
FINANCING ACTIVITIES 16,787 (24,494) (602) - (8,309)
--------------- ------------ ------------ ------------- ------------
Increase in cash and cash equivalents 52,653 (2,574) 1 (55,828) (5,748)
Cash and cash equivalents, beginning of period 106,118 6,246 - - 112,364
--------------- ------------ ------------ ------------- ------------
Cash and cash equivalents, end of period $ 158,771 $ 3,672 $ 1 $ (55,828) $ 106,616
=============== ============ ============ ============= ============
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
To assist in understanding our operating results, please refer to the operating data at the end of this analysis, which provides key operating information for our combined Refineries. Data for each Refinery is included in our annual report on Form 10-K/A, our quarterly reports on Form 10-Q and on our web site at http://www.frontieroil.com. We make our web site content available for informational purposes only. The web site should not be relied upon for investment purposes. We make available on this web site under “Investor Relations”, free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, proxy statements, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC.
The following are three significant indicators of our profitability reflected in the operating data included in this report:
1) gasoline and diesel crack spreads: the average non-oxygenated gasoline and diesel net sales prices we receive for each product less the average West Texas Intermediate ("WTI") crude oil priced at Cushing, Oklahoma;
2) light/heavy crude oil differential: the average differential between the benchmark WTI crude oil priced at Cushing, Oklahoma and the heavy crude oil priced delivered to the Cheyenne Refinery; and
3) WTI/WTS crude oil differential: the average differential between benchmark WTI crude oil priced at Cushing, Oklahoma and West Texas sour crude oil priced at Midland, Texas.
Other significant factors that influence our results are refinery utilization, crude oil price trends, asphalt and by-product margins and refinery operating expenses (including natural gas prices and turnaround, or planned maintenance, activity). Frontier typically does not use derivative instruments to offset price risk on its base level of operating inventories. We use the first-in, first-out (“FIFO”) inventory accounting method. As such, crude oil price trends can cause significant fluctuation in the inventory valuation of our crude oil, unfinished products and finished products resulting in FIFO inventory gains when crude oil prices increase and FIFO inventory losses when crude oil prices decrease during the reporting period. See Price Risk Management Activities under Item 3 for a discussion of our utilization of futures trading.
The terms “Frontier”, “we” and “our” refer to Frontier Oil Corporation and its subsidiaries.
Nine months ended September 30, 2004 compared with the same period in 2003
Overview of Results
We had net income for the nine months ended September 30, 2004 of $69.5 million, or $2.55 per diluted share, compared to a net loss of $870,000, or ($0.03) per share, in the same period in 2003. Our operating income of $127.7 million for the nine months ended September 30, 2004 was an increase of $90.6 million from the $37.0 million operating income for the comparable period in 2003. The average gasoline crack spread was significantly higher during 2004 ($10.24 per barrel) than in 2003 ($7.60 per barrel), and both the light/heavy and WTI/WTS crude oil differentials improved. The average diesel crack spread was also higher during 2004 ($6.51 per barrel) than in 2003 ($4.87 per barrel).
Our net income for the first nine months of 2004 was reduced by the legal costs associated with the termination of the Holly Corporation (“Holly”) merger and the Beverly Hills litigation. On March 31, 2003, we announced that we had entered into an agreement with Holly pursuant to which the two companies would merge. On August 20, 2003, we announced that Holly had advised us that it was not willing to proceed with our merger agreement on the agreed terms. As a result, we filed suit against Holly for damages in Delaware. Merger termination legal costs reduced earnings in the first nine months of 2004 by $3.8 million pretax ($2.3 million after tax) and costs related to the Beverly Hills litigation reduced earnings in the first nine months of 2004 by an additional $4.8 million pretax ($2.9 million after tax).
Specific Variances
Refined product revenues increased $444.3 million, or 27%, from $1.6 billion to $2.1 billion for the nine months ended September 30, 2004 compared to the same period in 2003. This increase was due to increased sales prices ($9.64 higher average per sales barrel), largely the result of higher crude oil prices and further increased by slightly higher sales volumes in 2004 (335 more barrels per day (“bpd”)). Our gasoline and diesel crack spreads averaged $10.24 per barrel and $6.51 per barrel, respectively, during the nine months ended September 30, 2004 compared to $7.60 per barrel and $4.87 per barrel, respectively, in the same period in 2003. Average gasoline prices increased from $40.46 per sales barrel in 2003 to $51.23 per sales barrel in 2004. Sales volumes of gasoline increased from 88,313 bpd in 2003 to 90,019 bpd in 2004. Average diesel and jet fuel prices increased from $36.72 per sales barrel in 2003 to $46.68 per sales barrel during 2004. However, sales volumes of diesel and jet fuel decreased 1,215 bpd from 53,702 bpd during the nine months ended September 30, 2003 to 52,487 bpd in the same period in 2004. Total product sales volumes overall increased only slightly from 164,468 bpd in the nine months ended September 30, 2003 to 164,803 bpd in the same period in 2004.
Manufactured product yields (“yields”) are the volumes of specific materials that are obtained through the distilling of crude oil and the operations of other refinery process units. Yields of gasoline were nearly flat year to year decreasing only 18 bpd, from 81,936 bpd in the nine months ended September 30, 2003 to 81,918 bpd in the same period in 2004. Yields of diesel and jet fuel decreased 701 bpd, or approximately 1%, from 53,188 bpd in the nine months ended September 30, 2003 to 52,487 bpd in the same period in 2004. Sales and yields for the nine months ended September 30, 2004 for the El Dorado Refinery were higher than during the same period in 2003 primarily because of the crude unit turnaround at the El Dorado Refinery, which commenced on March 18, 2003 and was completed on March 30, 2003. Yields for the nine months ended September 30, 2004 for the Cheyenne Refinery were lower than in the same period in 2003 primarily because of the coker furnace fire. The Cheyenne Refinery coking unit (see Note 8 in the “Notes to Interim Consolidated Financial Statements”) was out of service for one month in the first quarter of 2004.
Other revenues decreased $13.6 million to a $11.5 million loss for the nine months ended September 30, 2004 compared to income of $2.1 million for the same period in 2003 due to $11.9 million in net losses from derivative contracts accounted for using mark-to-market accounting in the nine months ended September 30, 2004 compared to net gains of $1.2 million for the same period in 2003. See Price Risk Management Activities under Item 3 for a discussion of our utilization of commodity derivative contracts. Processing income from our Cheyenne Refinery coker was $538,000 less during the nine months ended September 30, 2004, compared to the same period in 2003 due to the coker being out of service for a portion of 2004 from the previously mentioned fire and the July 2004 conclusion of the long-term resid processing agreement with Suncor Energy (USA) Inc. (“Suncor”), which was replaced with a new arrangement. The processing agreement entitled Suncor to process in the Cheyenne Refinery coker unit up to 3,300 bpd of resid, a heavy end by-product of the refining process. Under the new arrangement, Frontier purchases resid from Suncor and processes it through our coker unit, and Suncor purchases the resulting coker gas oil.
Raw material, freight and other costs include crude oil and other raw materials used in the refining process, purchased products and blendstocks, freight costs for FOB destination sales, as well as the impact of changes in inventory under the FIFO inventory accounting method. The average price of crude oil was higher in the nine months ended September 30, 2004 than in the same period in 2003. The average price of WTI crude oil priced at Cushing, Oklahoma was $39.61 per barrel in the first nine months of 2004 compared to $32.04 per barrel in the same period in 2003. Raw material, freight and other costs increased by $318.5 million, or $6.88 per sales barrel, during the nine months ended September 30, 2004 when compared to the same period in 2003. The increase in raw material, freight and other costs was due to higher average crude prices and more crude oil charges, offset by inventory gains from rising prices in the nine months ended September 30, 2004 compared to inventory losses in the comparable period in 2003. We also benefited from improved crude oil differentials during the nine months ended September 30, 2004 when compared to the same period in 2003. For the nine months ended September 30, 2004, we realized a reduction in raw material, freight and other costs as a result of inventory gains of approximately $27.9 million after tax ($45.1 million pretax, comprised of $11.7 million at the Cheyenne Refinery and $33.4 million at the El Dorado Refinery) because of increasing crude oil and refined product prices. The price of crude oil on the New York Mercantile Exchange was very volatile during the first nine months of 2004: it began the year at $32.52 per barrel, ended the first quarter at $35.76 per barrel, reached a second quarter high of $42.33 per barrel on June 1, dropped to $37.05 per barrel by June 30, and then increased during the third quarter to $49.64 per barrel on September 30, 2004. For the nine months ended September 30, 2003, we realized an increase in raw material, freight and other costs as a result of inventory losses of approximately $2.3 million after tax ($3.6 million pretax, comprised of a $4.6 million loss for the El Dorado Refinery, offset by a $1.0 million gain for the Cheyenne Refinery).
The Cheyenne Refinery raw material, freight and other costs of $36.45 per sales barrel for the nine months ended September 30, 2004 increased from $29.68 per sales barrel in the same period in 2003 due to higher crude oil prices offset by higher inventory gains and an improved light/heavy crude oil differential. The heavy crude oil utilization rate at the Cheyenne Refinery expressed as a percentage of the total crude oil charge decreased to 85% in the nine month period ending September 30, 2004 from 89% in 2003, as we processed more light crude oil due to the coker being out of service for approximately one month. The light/heavy crude oil differential for the Cheyenne Refinery averaged $8.75 per barrel in the nine months ended September 30, 2004 compared to $6.91 per barrel in the same period in 2003.
The El Dorado Refinery raw material, freight and other costs of $38.87 per sales barrel for the nine months ended September 30, 2004 increased from $31.96 per sales barrel in the same period in 2003 due to higher average crude oil prices offset by higher inventory gains and an improved WTI/WTS crude oil differential. The WTI/WTS crude oil differential increased from an average of $2.67 per barrel in the nine-month period ending September 30, 2003, to $3.04 per barrel in the same period in 2004.
Refinery operating expenses, excluding depreciation, includes both the variable costs (including energy and utilities) and the fixed costs (salaries, taxes, maintenance costs and other) of operating the Refineries. Refinery operating expenses, excluding depreciation, were $162.1 million, or $3.59 per sales barrel, in the nine months ended September 30, 2004 compared to $149.1 million, or $3.32 per sales barrel, in the comparable period of 2003.
The Cheyenne Refinery operating expenses, excluding depreciation, were $55.4 million, or $3.81 per sales barrel, in the nine months ended September 30, 2004 compared to $44.1 million, or $2.99 per sales barrel, in the comparable period of 2003. The increase resulted from higher costs of natural gas ($2.5 million), maintenance ($2.9 million), salaries ($1.9 million), excess turnaround costs and accruals ($834,000), consulting and legal ($1.1 million) and environmental ($1.7 million).
The El Dorado Refinery operating expenses, excluding depreciation, were $106.7 million, or $3.49 per sales barrel, in the nine months ended September 30, 2004, increasing from $104.9 million, or $3.48 per sales barrel, in the same nine-month period of 2003 primarily due to higher costs in salaries and benefits ($2.0 million), electricity ($785,000), natural gas ($658,000) and excess turnaround costs and accruals ($306,000), offset by reduced costs in maintenance ($832,000), consulting and legal ($777,000) and insurance ($305,000). Although natural gas costs overall were higher, reduced volumes dramatically decreased the impact of the higher natural gas prices.
Selling and general expenses, excluding depreciation, increased $6.0 million, or 40%, from $14.9 million for the nine months ended September 30, 2003 to $20.9 million for the nine months ended September 30, 2004 because of $4.8 million in costs related to the Beverly Hills litigation ($3.6 million in legal costs, substantially all of which have been paid or will be paid from the Commutation Account, and $1.1 million amortization of the previously purchased loss mitigation insurance premium) as opposed to $886,000 in legal costs in the same period in 2003, and increases in salaries ($2.2 million).
Merger termination and legal costs of $3.8 million for the nine months ended September 30, 2004 include ongoing legal costs associated with the termination of the anticipated 2003 Holly merger and resulting lawsuit, compared to $4.0 million in merger termination and legal costs for the comparable period in 2003.
Depreciation and amortization increased $2.7 million, or 13%, for the nine months ended September 30, 2004 compared to the same period in 2003 because of increased capital investment in our Refineries.
Interest expense and other financing costs of $17.6 million for the nine months ended September 30, 2004 decreased $3.1 million, or 15%, from $20.7 million in the comparable period in 2003 due to redemption of the 9-1/8% Senior Notes in December 2003 and the write-off in the 2003 period of deferred finance costs related to previous repurchases of 9-1/8% and 11¾% Senior Notes, offset by less capitalized interest and higher interest expense and fees on the revolving credit facility in 2004. Average debt outstanding decreased to $215 million during the nine months ended September 30, 2004 from $241 million (excluding merger debt) for the same period in 2003. Although the 9-1/8% Senior Notes were not outstanding during the nine months ended September 30, 2004, more revolving credit facility borrowings were utilized in the nine-month period of 2004 than in the comparable period in 2003 due to higher crude and product prices.
Interest income decreased $17,000 from $907,000 in the nine months ended September 30, 2003 to $890,000 in the nine months ended September 30, 2004.
The gain on involuntary conversion of assets relates to the fire that occurred on January 19, 2004 in the furnaces of the coking unit at the Cheyenne Refinery. For the nine months ended September 30, 2004, the gain represents the partial settlement proceeds of $3.5 million from our insurers less $1.8 million of expenses related to clean-up costs and $1.1 million of net property, plant and equipment written-off due to the fire.
The merger financing termination costs, net, during the nine months ended September 30, 2003 were $17.6 million, which related to the 8% Senior Notes issued to finance the contemplated Holly merger and included interest expense, issue discount, financing issue costs and redemption premium, net of $718,000 interest income earned on the escrow account.
The income tax provision for the nine months ended September 30, 2004 was $42.0 million on pretax income of $111.5 million (or 37.7%) reflecting the net benefit of releasing our deferred tax valuation allowance offset by the effect of the permanent book versus tax differences and prior year adjustments from our current estimated effective tax rate of 38.2%. The income tax provision for the nine months ended September 30, 2003 was $430,000 on a pretax net loss of $440,000 due to one-time adjustments for permanent book versus tax differences related to 2002 and 2003 expenses and an increase of $280,000 in the income tax provision for the nine months ended September 30, 2003 resulting from an adjustment to the 2002 tax provision. The new “American Jobs Creation Act of 2004” provision providing tax relief for manufacturers should result in reduced effective federal income tax rates beginning in 2005. The FASB has not yet determined whether the tax effect of this special deduction will be recognized only as amounts are deducted on the tax returns or if this effect may be treated as a change in tax rates with adjustments to deferred tax assets and liabilities.
Three months ended September 30, 2004 compared with the same period in 2003
Overview of Results
We had net income for the three months ended September 30, 2004 of $23.8 million, or $0.87 per diluted share, compared to net income of $3.8 million, or $0.14 per diluted share, in the same period in 2003. Our operating income of $42.6 million for the three months ended September 30, 2004 was an increase of $15.3 million from the $27.3 million operating income for the comparable period in 2003. The average diesel crack spread was significantly higher during the three months ended September 30, 2004 ($8.10 per barrel) than in the same period in 2003 ($4.75 per barrel), and both the light/heavy and WTI/WTS crude oil differentials improved. The average gasoline crack spread was less during the three months ended September 30, 2004 ($8.88 per barrel) than in the same period in 2003 ($9.70 per barrel). As crude oil prices reached record highs during the third quarter of 2004, our profitability was adversely impacted by the resulting negative margins on certain of our heavy end products.
Specific Variances
Refined product revenues increased $197.3 million, or 33%, from $594.3 million to $791.6 million for the three months ended September 30, 2004 compared to the same period in 2003. The increase was due to increased sales prices ($12.88 average per sales barrel) which were reflective of higher crude oil prices, offset by lower sales volumes. Our gasoline and diesel crack spreads averaged $8.88 per barrel and $8.10 per barrel, respectively, during the three months ended September 30, 2004, compared to $9.70 per barrel and $4.75 per barrel, respectively, in the same period in 2003. Average gasoline prices increased from $41.67 per sales barrel in 2003 to $54.07 per sales barrel in 2004. Sales volumes of gasoline increased 1,738 bpd from 92,383 bpd during the three months ended September 30, 2003 to 94,121 bpd in the same period in 2004. Average diesel and jet fuel prices increased from $36.10 per sales barrel in the three months ended 2003 to $52.31 per sales barrel during the same period in 2004. Sales volumes of diesel and jet fuel decreased 4,145 bpd from 58,963 bpd during the three months ended September 30, 2003 to 54,818 bpd in the same period in 2004. Total product sales volumes overall decreased 2,710 bpd from 176,914 bpd in the three months ended September 30, 2003 to 174,204 bpd in the same period in 2004.
Yields of gasoline decreased 1,537 bpd, or 2%, from 86,014 bpd in the three months ended September 30, 2003 to 84,477 bpd in the same period in 2004. Yields of diesel and jet fuel decreased 2,264 bpd, or 4%, from 57,321 bpd in the three months ended September 30, 2003 compared to 55,057 bpd in the same period in 2004.
Other revenues decreased to a $6.5 million loss for the three months ended September 30, 2004 compared to income of $471,000 for the same period in 2003. This was due to $6.6 million in net losses on derivative contracts accounted for using mark-to-market accounting in the three months ended September 30, 2004 compared to net gains of $186,000 for the same period in 2003. See Price Risk Management Activities under Item 3 for a discussion of our utilization of commodity derivative contracts. We also had a decrease of $292,000 in processing income from our Cheyenne Refinery coker, as July 2004 was the last month to reflect processing income as the resid processing agreement was concluded and replaced with a new arrangement as discussed above.
Raw material, freight and other costs include crude oil and other raw materials used in the refining process, purchased products and blendstocks, freight costs for FOB destination sales, as well as the impact of changes in inventory under the FIFO inventory accounting method. The average price of crude oil was significantly higher in the three months ended September 30, 2004 than in the same period in 2003. The average price of WTI crude oil priced at Cushing, Oklahoma was $44.12 per barrel in the three months ended September 30, 2004 compared to $31.03 per barrel in the same period in 2003. Raw material, freight and other costs increased by $168.7 million, or $11.00 per sales barrel, during the three months ended September 30, 2004, when compared to the same period in 2003, due to the higher average crude oil prices offset by fewer crude oil charges and inventory gains from rising prices for the three months ended September 30, 2004 compared to inventory losses during the same period in 2003. For the three months ended September 30, 2004, we realized a reduction in raw material, freight and other costs as a result of inventory gains of approximately $13.1 million after tax ($21.3 million pretax, comprised of $6.0 million at the Cheyenne Refinery and $15.3 million at the El Dorado Refinery) because of the increasing crude oil and refined product prices. The price of crude oil on the New York Mercantile Exchange increased sharply during the third quarter of 2004, beginning at $37.05 per barrel at June 30, 2004 and ending the quarter at $49.64 per barrel on September 30, 2004. For the three months ended September 30, 2003, we realized an increase in raw material, freight and other costs as a result of inventory losses of approximately $3.9 million after tax ($6.3 million pretax, comprised of a $4.5 million loss for the El Dorado Refinery and a $1.8 million loss for the Cheyenne Refinery).
The Cheyenne Refinery raw material, freight and other costs of $39.20 per sales barrel, for the three months ended September 30, 2004, increased from $28.93 per sales barrel in the same period in 2003 due to higher crude oil prices offset by inventory gains and an improved light/heavy crude oil differential. The heavy crude oil utilization rate at the Cheyenne Refinery expressed as a percentage of the total crude oil charge, decreased to 85% in the three-month period ending September 30, 2004 from 87% in the same period in 2003. The light/heavy crude oil differential for the Cheyenne Refinery averaged $9.28 per barrel in the three months ended September 30, 2004, compared to $6.81 per barrel in the same period in 2003.
The El Dorado Refinery raw material, freight and other costs of $43.16 per sales barrel, for the three months ended September 30, 2004, increased from $31.85 per sales barrel in the same period in 2003 due to higher average crude oil prices offset by fewer crude oil charges and inventory gains. The WTI/WTS crude oil differential increased from an average of $2.44 per barrel in the three-month period ending September 30, 2003 to $2.95 per barrel in this same period in 2004.
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 expenses, excluding depreciation, were $55.7 million, or $3.48 per sales barrel, in the three months ended September 30, 2004, compared to $48.5 million, or $2.98 per sales barrel, in the comparable period of 2003.
The Cheyenne Refinery operating expenses, excluding depreciation, were $20.8 million, or $4.06 per sales barrel, in the three months ended September 30, 2004 compared to $14.8 million, or $2.76 per sales barrel, in the comparable period of 2003. The increase was primarily due to higher maintenance costs ($1.8 million), higher natural gas prices ($840,000), higher salaries ($627,000), the elimination in July 2004 of the processing cost reimbursement related to the resid processing agreement as discussed above ($732,000) and an increase in environmental costs ($1.8 million).
The El Dorado Refinery operating expenses, excluding depreciation, were $34.9 million, or $3.20 per sales barrel, in the three-month period ended September 30, 2004 compared to $33.7 million, or $3.09 per sales barrel, in the comparable period of 2003. The increase was primarily due to higher natural gas costs ($1.2 million) and salaries and benefits ($1.2 million) offset by positive variances in consulting and legal ($715,000), additive and chemical costs ($229,000) and maintenance ($181,000).
Selling and general expenses, excluding depreciation, increased $1.9 million, or 38%, for the three months ended September 30, 2004 because of increases in salaries $998,000 and $1.3 million in costs related to the Beverly Hills litigation (nearly $1.0 million in legal costs, substantially all of which have been paid or will be paid from the Commutation Account, and $302,000 amortization of the loss mitigation insurance premium purchased in October 2003), as opposed to $610,000 in legal costs in the same period in 2003.
Merger termination and legal costs of $157,000, for the three months ended September 30, 2004, include ongoing legal costs associated with the termination of the anticipated 2003 Holly merger and resulting lawsuit, which compares to $4.0 million in merger termination and legal costs for the comparable period in 2003.
Depreciation increased $1.0 million, or 14%, for the three months ended September 30, 2004 as compared to the same period in 2003 because of increased capital investment in our Refineries.
Interest expense and other financing costs of $5.8 million, for the three months ended September 30, 2004, decreased $777,000, or 12%, from $6.6 million in the comparable period in 2003 due to redemption of the 9-1/8% Senior Notes in December 2003 offset by no capitalized interest during 2004. Average debt outstanding decreased to $191 million during the three months ended September 30, 2004 from $239 million (excluding merger debt) for the same period in 2003. Although the 9-1/8% Senior Notes were not outstanding during the three months ending September 30, 2004, more revolving credit facility borrowings were utilized in the third quarter of 2004 than in the comparable period in 2003 due to higher crude oil and product prices.
Interest income increased $225,000 from $260,000, in the three months ended September 30, 2003, to $485,000 in the three months ended September 30, 2004 due to more cash available to invest.
The merger financing termination costs, net, during the three months ended September 30, 2003 were $14.2 million, and included interest expense, issue discount, financing issue costs and redemption premium, net of $351,000 interest income earned on the escrow account related to the 8% Senior Notes issued to finance the contemplated Holly merger.
The income tax expense for the three months ended September 30, 2004 was $13.4 million on pretax income of $37.2 million (or 36.1%) reflecting the effect of the net benefit of releasing our deferred tax valuation allowance offset by the permanent book versus tax differences and prior year adjustments from our current estimated effective tax rate of 38.2%. The income tax provision for the three months ended September 30, 2003 was $2.9 million on pretax net income of $6.8 million (43.4% effective rate) due to one-time adjustments for permanent book versus tax differences related to 2002 and 2003 expenses and an increase in the income tax provision for the three months ended September 30, 2003 resulting from an adjustment to the 2002 tax provision.
LIQUIDITY AND CAPITAL RESOURCES
Net cash provided by operating activities was $107.2 million for the nine months ended September 30, 2004 compared to net cash provided by operating activities of $29.3 million during the nine months ended September 30, 2003. Improved results of operations were the largest contributor to improved cash flow offset by higher uses of cash by working capital changes.
Working capital changes used a total of $19.1 million of cash flows in the nine months ended September 30, 2004 while using only $1.7 million of cash flows in the comparable period in 2003. The most significant use of cash for working capital changes during the nine-month period of 2004 was the increase in receivables of $49.5 million and the increase in inventories of $68.6 million compared to a decrease in receivables of $4.7 million and an increase in inventory of only $19.9 million in the 2003 comparable period. The increase in inventories and receivables was due to the sharp increase in crude oil and product prices during 2004.
The most significant working capital item offsetting the negative cash impacts during the nine months ended September 30, 2004 was an increase in trade and crude payables (providing cash) of $77.1 million in the 2004 period. This was primarily due to increases in the crude payable as a result of the higher crude oil prices.
During the nine months ended September 30, 2004, we made estimated federal and state income tax payments of approximately $11.5 million.
At September 30, 2004, we had $122.7 million of cash and cash equivalents, working capital of $129.3 million and $75.6 million of borrowing base availability for additional borrowings under our revolving credit facility.
During the nine months ended September 30, 2004, we increased our treasury stock by 215,599 shares ($4.1 million) which were obtained directly from employees in cashless stock option exercises, and we received another 112,752 shares ($2.1 million) of treasury stock from stock surrendered by employees to pay their withholding taxes related to the stock option exercises. We also acquired 48,443 shares ($901,000) of treasury stock from stock surrendered by employees to pay their withholding taxes on shares of restricted stock which vested during the first quarter.
Capital expenditures during the first nine months of 2004 were $34.8 million, which included payments of approximately $6 million for the Cheyenne Refinery low sulfur gasoline project (completed in December 2003) and approximately $7.8 million in unplanned capital work due to the Cheyenne Refinery coker fire. Capital expenditures aggregating approximately $60 million are currently planned for 2004. These 2004 capital expenditures include approximately $28 million for the El Dorado Refinery, $31 million for the Cheyenne Refinery, and $1 million of capital for expenditures in our Denver and Houston offices, our asphalt terminal in Nebraska and for our share of crude pipeline projects. The approximately $28 million of capital expenditures for our El Dorado Refinery includes approximately $11 million to begin the ultra low sulfur diesel compliance project, as well as operational, payout, safety, administrative, environmental and optimization projects. The approximately $31 million of capital expenditures for our Cheyenne Refinery includes the $7.8 million of capital incurred due to the Cheyenne Refinery coker fire, the $6 million incurred on the low sulfur gasoline project, as well as environmental, ultra low sulfur diesel, operational, safety, administrative and payout projects. Compliance with the upcoming ultra low sulfur diesel requirements at our Refineries will require additional capital expenditures through 2006. The total capital we will utilize to comply with the regulations is estimated to be $13.5 million at the Cheyenne Refinery and approximately $100 million at the El Dorado Refinery. The expenditures for the ultra low sulfur diesel projects for 2004 are estimated at $550,000 at the Cheyenne Refinery and $11.0 million at the El Dorado Refinery, which are included in the capital expenditures discussed above. The remaining costs for the ultra low sulfur diesel projects at both Refineries are expected to be spent in 2005 and 2006. It may be necessary for us to obtain external financing in 2005 or 2006 to fund these required expenditures. The recently enacted “American Jobs Creation Act of 2004” should allow us, as a small business refiner, to deduct for federal income tax purposes 75% of the qualified costs related to these low sulfur diesel expenditures in the years incurred as well as provide tax credits based on the resulting production of ultra low sulfur diesel up to 25% of the remaining qualified costs.
As of September 30, 2004, we had received payments of $3.5 million from our insurance company for reimbursement of costs related to the coker fire. Additional proceeds from our insurance company are expected to be received during the fourth quarter of 2004.
As of September 30, 2004, we had $206.7 million principal ($205.2 million, net of discount) of total consolidated debt, of which $170.4 million was long-term debt ($168.9 million, net of discount) and $36.3 million was under our revolving credit facility. We also had $63.2 million outstanding letters of credit under our revolving credit facility. We were in compliance with the financial covenants of our revolving credit facility as of September 30, 2004. We had shareholders’ equity of $238.2 million as of September 30, 2004. Operating cash flows are affected by crude oil and refined product prices and other risks as discussed in “Item 3. Quantitative and Qualitative Disclosures About Market Risks”.
Under the provisions of the purchase agreement with Shell for our El Dorado Refinery, we have made, or may be required to make, contingent earn-out payments for each of the years 2000 through 2007 equal to one-half of the excess over $60 million per year of the El Dorado Refinery’s annual revenues less material costs and operating costs, other than depreciation. The total amount of these contingent payments is capped at $40 million, with an annual cap of $7.5 million. No payment was necessary in 2004, based on 2003 results. It will not be determinable until year-end if a contingent earn-out payment, based on 2004 results, will be required in early 2005. However, based on the results of operations for the nine months ended September 30, 2004, it is probable, but not estimatable, that a payment may be required. Such contingency payments, if any, will be recorded as additional acquisition costs.
Our Board of Directors declared quarterly cash dividends of $.05 per share in December 2003, March 2004, and June 2004 which were paid in January 2004, April 2004, and July 2004, respectively. Our Board of Directors declared a quarterly cash dividend of $.06 per share in September 2004, which was paid on October 12, 2004 to shareholders of record on September 24, 2004. The total cash required for the dividend declared in September 2004 was approximately $1.6 million and was accrued at quarter end.
On October 1, 2004, we issued $150 million principal amount of 6.625% Senior Notes (the “Notes”) due 2011. The Notes, which mature on October 1, 2011, were issued at par and we received net proceeds (after underwriting fees) of $147.2 million. Interest is paid semi-annually. The Notes are redeemable, at our option, at 103.313% after October 1, 2007, declining to 100% in 2010. Prior to October 1, 2007, we may, at our option redeem the Notes at a defined make-whole amount, plus accrued and unpaid interest. We used part of the net proceeds of this offering to fund a tender offer and consent solicitation for $64.9 million principal of our 11¾% Senior Notes in October 2004 and included payment of a premium of $4.2 million and payment of accrued interest to date of $2.9 million. We intend to redeem in November 2004 the remaining $105.6 million outstanding principal of our 11¾% Senior Notes, including payment of a $6.2 million premium and payment of accrued interest to date of another $6.2 million, with the remaining proceeds of the offering, together with other available funds. These actions should significantly reduce our interest expense in future years.
REFINING OPERATING STATISTICAL INFORMATION
Consolidated: Nine Months Ended Three Months Ended
September 30, September 30,
2004 2003 2004 2003
------- ------- ------- -------
Charges (bpd) (1)
Light crude 38,760 30,451 43,099 31,295
Heavy and intermediate crude 110,054 116,128 109,625 127,589
Other feed and blend stocks 16,004 18,806 16,712 18,480
------- ------- ------- -------
Total 164,818 165,385 169,436 177,364
Manufactured product yields (bpd) (2)
Gasoline 81,918 81,936 84,477 86,014
Diesel and jet fuel 52,487 53,188 55,057 57,321
Asphalt 7,520 7,534 7,975 9,202
Chemicals 959 811 1,034 835
Other 17,511 17,661 15,936 18,091
------- ------- ------- -------
Total 160,395 161,130 164,479 171,463
Total product sales (bpd)
Gasoline 90,019 88,313 94,121 92,383
Diesel and jet fuel 52,487 53,702 54,818 58,963
Asphalt 7,725 7,807 8,325 10,557
Chemicals 817 811 942 835
Other 13,755 13,835 15,998 14,176
------- ------- ------- -------
Total 164,803 164,468 174,204 176,914
Refinery operating margin information (per sales bbl)
Refined products revenue $ 45.84 $ 36.20 $ 49.39 $ 36.51
Raw material, freight and other costs
(FIFO inventory accounting) 38.09 31.21 41.89 30.89
Refinery operating expenses, excluding depreciation 3.59 3.32 3.48 2.98
Refinery depreciation .51 .47 .49 .42
Average WTI crude oil priced at Cushing, OK $ 39.58 $ 32.04 $ 44.02 $ 31.03
Average gasoline crack spreads (per barrel) (3) $ 10.24 $ 7.60 $ 8.88 $ 9.70
Average diesel crack spreads (per barrel) (3) $ 6.51 $ 4.87 $ 8.10 $ 4.75
Average sales price (per sales bbl)
Gasoline $ 51.23 $ 40.46 $ 54.07 $ 41.67
Diesel and jet fuel 46.68 36.72 52.31 36.10
Asphalt 23.75 24.64 26.39 25.53
Chemicals 105.27 53.97 142.63 48.05
Other 16.21 12.47 18.32 12.15
| (1) | Charges are the quantity of crude oil and other feedstocks processed through refinery units. |
| (2) | Manufactured product yields are the volumes of specific materials that are obtained through the distilling of crude oil and the operations of other refinery process units. |
| (3) | The average non-oxygenated gasoline and diesel net sales prices we receive for each product less the average WTI crude priced at Cushing, Oklahoma. |
REFINING OPERATING STATISTICAL INFORMATION
Cheyenne Refinery: Nine Months Ended Three Months Ended
September 30, September 30,
2004 2003 2004 2003
------- ------- ------- -------
Charges (bpd) (1)
Light crude 6,795 5,226 7,376 6,235
Heavy crude 37,872 40,299 40,752 41,902
Other feed and blend stocks 3,981 5,688 3,852 5,703
------- ------- ------- -------
Total 48,648 51,213 51,980 53,840
Manufactured product yields (bpd) (2)
Gasoline 19,551 20,226 19,182 20,588
Diesel 13,981 15,159 15,401 15,797
Asphalt 7,520 7,534 7,975 9,202
Other 5,803 6,658 7,451 6,263
------- ------- ------- -------
Total 46,855 49,577 50,009 51,850
Total product sales (bpd)
Gasoline 26,633 26,381 26,217 27,143
Diesel 14,283 15,228 15,473 15,847
Asphalt 7,725 7,807 8,325 10,557
Other 4,502 4,613 5,774 4,901
------- ------- ------- -------
Total 53,143 54,029 55,789 58,448
Refinery operating margin information (per sales bbl)
Refined products revenue $ 44.23 $ 35.88 $ 47.49 $ 35.80
Raw material, freight and other costs
(FIFO inventory accounting) 36.45 29.68 39.20 28.93
Refinery operating expenses, excluding depreciation 3.81 2.99 4.06 2.76
Refinery depreciation .86 .79 .83 .72
Average light/heavy crude oil differential (per barrel) (3) $ 8.75 $ 6.91 $ 9.28 $ 6.81
Average gasoline crack spreads (per barrel) (4) $ 10.90 $ 8.07 $ 10.63 $ 10.38
Average diesel crack spreads (per barrel) (4) $ 8.73 $ 6.31 $ 8.99 $ 6.55
Average sales price (per sales bbl)
Gasoline $ 52.63 $ 42.31 $ 56.96 $ 43.38
Diesel 49.46 38.81 53.33 38.19
Asphalt 23.75 24.64 26.39 25.53
Other 13.06 8.51 19.24 8.15
| (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 crude oil differential is the differential between the benchmark average WTI crude priced at Cushing, Oklahoma and the heavy crude oil priced delivered to the Cheyenne Refinery. The light/heavy crude oil differential for prior periods has been restated to conform to the current presentation using WTI as the light crude oil in order to be comparable with WTI/WTS crude oil differential reported for the El Dorado Refinery. |
| (4) | The average non-oxygenated gasoline and diesel net sales prices we receive for each product less the average WTI crude priced at Cushing, Oklahoma. |
REFINING OPERATING STATISTICAL INFORMATION
El Dorado Refinery: Nine Months Ended Three Months Ended
September 30, September 30,
2004 2003 2004 2003
------- ------- ------- -------
Charges (bpd) (1)
Light crude 31,966 25,225 35,723 25,061
Heavy and intermediate crude 72,182 75,829 68,873 85,687
Other feed and blend stocks 12,023 13,118 12,860 12,777
------- ------- ------- -------
Total 116,171 114,172 117,456 123,525
Manufactured product yields (bpd) (2)
Gasoline 62,367 61,710 65,295 65,426
Diesel and jet fuel 38,506 38,029 39,656 41,524
Chemicals 959 811 1,034 835
Other 11,708 11,003 8,485 11,828
------- ------- ------- -------
Total 113,540 111,553 114,470 119,613
Total product sales (bpd)
Gasoline 63,386 61,932 67,904 65,240
Diesel and jet fuel 38,204 38,473 39,345 43,115
Chemicals 817 811 942 835
Other 9,253 9,222 10,224 9,276
------- ------- ------- -------
Total 111,660 110,438 118,415 118,466
Refinery operating margin information (per sales bbl)
Refined products revenue $ 46.60 $ 36.36 $ 50.29 $ 36.87
Raw material, freight and other costs
(FIFO inventory accounting) 38.87 31.96 43.16 31.85
Refinery operating expenses, excluding depreciation 3.49 3.48 3.20 3.09
Refinery depreciation .34 .31 .33 .28
WTI/WTS crude oil differential (per bbl) (3) $ 3.04 $ 2.67 $ 2.95 $ 2.44
Average gasoline crack spreads (per barrel) (4) $ 9.96 $ 7.40 $ 8.20 $ 9.42
Average diesel crack spreads (per barrel) (4) $ 5.68 $ 4.30 $ 7.75 $ 4.09
Average sales price (per sales bbl)
Gasoline $ 50.63 $ 39.68 $ 52.95 $ 40.96
Diesel and jet fuel 45.64 35.90 51.91 35.33
Chemicals 105.27 53.97 142.63 48.05
Other 17.74 14.45 17.81 14.26
| (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 differential between benchmark West Texas intermediate (sweet) crude oil priced at Cushing, Oklahoma and West Texas sour crude oil priced at Midland, Texas. |
| (4) | The average non-oxygenated gasoline and diesel net prices we receive for each product less the average WTI crude priced at Cushing, Oklahoma. |
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 that are in excess of our base level of operating inventories, our purchases of foreign crude oil, our consumption of natural gas in the refining process, to fix margins on certain future production and fix differentials on crude oil. 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 the date of purchase. 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. When we make the decision to manage our price exposure, we neither incur losses from negative price changes nor do we obtain the benefit of positive price changes. 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 “Raw material, freight and other costs” or “Refinery operating expenses, excluding depreciation” when the associated transactions are consummated. 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 nine months ended September 30, 2004, included $11.9 million realized and unrealized net losses on derivative contracts accounted for using mark-to-market accounting. Other revenues for the three months ended September 30, 2004, included $6.6 million realized and unrealized net losses on derivative contracts accounted for using mark-to-market accounting.
At September 30, 2004, 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 included in “Other revenues” in the consolidated statements of operations:
| • |
Derivative contracts on 91,000 barrels of crude oil to hedge crude oil and
intermediate product inventory builds for both the Cheyenne and El Dorado
Refineries expected to be drawn down during the months of October and November
2004. These open contracts had total unrealized net losses at September 30, 2004
of approximately $293,000. During the nine months ended September 30, 2004 we
reported net losses of approximately $5.5 million on closed out contracts to
hedge crude oil and intermediate inventories.
|
| • |
Derivative contracts on 336,000 barrels of crude oil to hedge normal butane
inventory for the El Dorado Refinery expected to be drawn down during the months
of October 2004 through early January 2005. These open contracts had total
unrealized net losses at September 30, 2004 of approximately $1.2 million.
During the nine months ended September 30, 2004 we reported net losses of
approximately $2.0 million on closed out contracts to hedge normal butane
inventory for the El Dorado Refinery.
|
During the nine months ended September 30, 2004 we utilized derivative contracts on barrels of crude oil to fix the heavy crude differential to the New York Mercantile Exchange light crude oil contract price for a portion of the committed purchases under our crude oil supply agreement with Baytex. During the nine months ended September 30, 2004, we recorded losses of nearly $2.6 million (included in “Other revenues”) on these contracts. No open positions remain at September 30, 2004 related to these contracts. We also utilized derivative contracts on barrels of crude oil to hedge crude oil inventories at the El Dorado Refinery and realized $327,000 in losses on these positions during the first quarter of 2004.
We had no open derivative contracts at September 30, 2004 that were being accounted for as hedges, nor did we have any derivative contracts during the nine months ended September 30, 2004, that were designated and accounted for as hedges.
Interest Rate Risk. Borrowings under our revolving credit facility bear a current market rate of interest. Our approximately $170.5 million principal of 11¾% Senior Notes that were outstanding at September 30, 2004 and due 2009 have a fixed interest rate. Thus, our long-term debt is not exposed to cash flow risk from interest rate changes. Our long-term debt, however, is exposed to fair value risk. The estimated fair value of our 11¾% Senior Notes at September 30, 2004 was $181.5 million. As stated above, we consummated a tender for $64.9 million principal of our 11¾% Senior Notes in October 2004, and we intend to redeem in November 2004 the remaining $105.6 million outstanding principal of our 11¾% Senior Notes.
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 evaluated, 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, the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 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.
During the most recent fiscal quarter, there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II - OTHER INFORMATION
| ITEM 1. |
Legal Proceedings - See Note 6 in the Notes to Interim Consolidated Financial Statements. |
| ITEM 2. |
Unregistered Sales of Equity Securities and Use of Proceeds - None. |
| 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 - 4.1 – Indenture, dated as of October 1, 2004, among Frontier Oil Corporation, as issuer, the guarantors party thereto and Wells Fargo Bank, N.A., as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K, filed on October 4, 2004 (SEC File No. 001-07627)). 4.2 – Registration Rights Agreement, dated as of October 1, 2004, among Frontier Oil Corporation, each of the guarantors party thereto and Bear, Stearns & Co. Inc., BNP Paribas Securities Corp. and TD Securities (USA) Inc. (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K, filed on October 4, 2004 (SEC File No. 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. 32.2 – 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. |
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: November 4, 2004